-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, CHF9Db7t1WRSF8U2lrV9M7/AeZ61AXv0/qvxFOodYEN3426amdkrEKIOaVHwLbdU bkLbacGV7uPQ0LE6AfnQqg== 0000950172-99-000997.txt : 19990810 0000950172-99-000997.hdr.sgml : 19990810 ACCESSION NUMBER: 0000950172-99-000997 CONFORMED SUBMISSION TYPE: U-1 PUBLIC DOCUMENT COUNT: 9 FILED AS OF DATE: 19990806 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NEW ENGLAND ELECTRIC SYSTEM CENTRAL INDEX KEY: 0000071297 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041663060 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: U-1 SEC ACT: SEC FILE NUMBER: 070-09537 FILM NUMBER: 99680490 BUSINESS ADDRESS: STREET 1: 25 RESEARCH DR CITY: WESTBOROUGH STATE: MA ZIP: 01582 BUSINESS PHONE: 5083892000 MAIL ADDRESS: STREET 1: 25 RESEARCH DR CITY: WESTBOROUGH STATE: MA ZIP: 01582 U-1 1 FORM U-1 File No. 70-______ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM U-1 ----------------------------------------- APPLICATION OR DECLARATION UNDER THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 ---------------------------------------------------- New England Electric System Eastern Utilities Associates 25 Research Drive One Liberty Square, P.O. Box 2333 Westborough, MA 01582 Boston, MA 02109 (Name of companies and top registered holding company parents filing this statement and addresses of principal executive offices) ------------------------------------------------------------------ Michael E. Jesanis Donald G. Pardus Kirk L. Ramsauer Clifford J. Hebert, Jr. New England Electric System Eastern Utilities Associates 25 Research Drive One Liberty Square, P.O. Box 2333 Westborough, MA 01582 Boston, MA 02109 (Name and addresses of agents for service) ---------------------------------- The Commission also is requested to send copies of any communications in connection with this matter to: Clifford M. Naeve, Esq. Arthur I. Anderson, P.C. Judith A. Center, Esq. David A. Fazzone, P.C. Kathleen A. Foudy, Esq. Amy J. Gould, Esq. William C. Weeden McDermott, Will & Emery Skadden, Arps, Slate, Meagher & Flom LLP 28 State Street 1440 New York Avenue, N.W. Boston, MA 02109-1775 Washington, D.C. 20005 TABLE OF CONTENTS Page ITEM I: DESCRIPTION OF PROPOSED TRANSACTION....................................1 A. Description of the Parties to the Transaction........................1 1. General Request.................................................2 2. Overview of the Transaction.....................................5 B. Description of the Parties to the Transaction........................6 1. General Description.............................................6 a. NEES.......................................................6 b. EUA........................................................9 2. Description of Facilities......................................11 a. NEES......................................................11 i. General..............................................11 ii. Electric Generating Facilities and Resources.........11 iii. Electric Transmission Facilities.....................12 b. EUA.......................................................13 i. General..............................................13 ii. Electric Generating Facilities and Resources.........13 iii. Electric Transmission Facilities.....................14 3. Non-Utility Businesses.........................................14 a. NEES......................................................14 i. New England Hydro Finance Company, Inc...............14 ii. NEES Communications, Inc.............................14 iii. NEES Global..........................................15 iv. NEES Energy, Inc.....................................15 v. AllEnergy Marketing Company, L.L.C...................15 vi. Granite State Energy, Inc............................15 vii. Service Company..................................16 viii. New England Energy Incorporated..................16 ix. Metrowest Realty, LLC................................16 b. EUA.......................................................16 i. EUA Cogenex..........................................17 ii. EUA Energy...........................................18 iii. EUA Ocean State......................................19 iv. EUA Energy Services..................................19 v. EUA Telecommunications...............................19 vi. EUA Service..........................................19 vii. Eastern Edison Electric Company..................19 C. Description of Transaction..........................................19 1. Background.....................................................19 2. Merger Agreement...............................................20 D. Management and Operations Following the Transaction.................21 ITEM II. FEES, COMMISSIONS AND EXPENSES......................................21 ITEM III. APPLICABLE STATUTORY PROVISIONS....................................22 A. Section 10(b).......................................................24 1. Section 10(b)(1)...............................................24 a. Interlocking Relations....................................25 b. Concentration of Control..................................25 i. Size ...............................25 ii. Competition and Antitrust Considerations.............27 2. Section 10(b)(2)...............................................28 a. Fairness of Consideration.................................28 b. Fairness of Fees..........................................30 3. Section 10(b)(3)...............................................30 a. Capital Structure.........................................31 b. Public Interest, Interest of Investors and Consumers, and Proper Functioning of Holding Company System..........33 B. Section 10(c).......................................................33 1. Section 10(c)(1)...............................................33 a. Section 11(a) and Section 11(b)(2)........................34 b. Section 11(b)(1) (single integrated public utility system)...................................................34 i. Interconnection......................................35 ii. Single Interconnected and Coordinated System.........35 iii. Single Area or Region ...............................37 iv. Localized Management, Efficient Operation and Effective Regulation.................................37 c. Section 11(b)(1) (Acquisition of Non-Utility Interests)...37 2. Section 10(c)(2)...............................................38 C. Section 10(f).......................................................39 D. Service Agreement...................................................39 E. Organization of LLC; Acquisition of Merger LLC Interests............40 F. Financing and Other Commission Authorizations.......................40 1. Payment of Dividends Out of Capital or Unearned Surplus........40 2. Financing Arrangements.........................................44 a. Borrowings from Banks - Credit Agreement..................45 b. Cost of Funds.............................................45 c. Borrowings from Banks - Short-term........................45 d. Sale of Commercial Paper to Dealers.......................46 e. Filing of Certificates of Notification....................47 3. Rule 53 ...........................................................47 ITEM IV. REGULATORY APPROVAL.................................................47 ITEM V. PROCEDURE............................................................48 ITEM VI. EXHIBITS AND FINANCIAL STATEMENTS...................................48 A. Exhibits............................................................48 B. Financial Statements................................................49 ITEM VII. INFORMATION AS TO ENVIRONMENTAL EFFECTS............................50 ITEM I: DESCRIPTION OF PROPOSED TRANSACTION A. Description of the Parties to the Transaction This Form U-1 Application/Declaration ("Application/Declaration") seeks approvals relating to the proposed combination of New England Electric System ("NEES"), Eastern Utilities Associates ("EUA"), and Research Drive LLC ("LLC"), a Massachusetts limited liability company1 (the "Merger"). Pursuant to the merger, LLC will merge with and into EUA, with EUA as the surviving entity, and, therefore, a wholly-owned subsidiary of NEES. EUA subsequently will be merged with and into NEES, with NEES as the surviving entity (together with the Merger, the "Transaction"). Subsequent to the Transaction, NEES will remain a registered holding company pursuant to the Public Utility Holding Company Act of 1935 (the "Act"). The Transaction will yield substantial benefits to investors, consumers and the general public. It will create a merged company that will be strong financially and well-equipped to meet increasing competition in wholesale and retail power markets. In addition, NEES and EUA (collectively, the "Applicants") consistently have been the two lowest-cost, major electric companies in New England. The Transaction will generate efficiencies and cost savings which will maintain low rates for customers of the merged companies. The benefits of the Transaction are discussed in detail in Item III.B.2 below. Pursuant to an Agreement and Plan of Merger, dated as of December 11, 1998, by and among The National Grid Group plc ("NGG"), NGG Holdings LLC, a Massachusetts limited liability company and a wholly-owned subsidiary of NGG, and NEES (the "NEES/NGG Merger Agreement"), NGG Holdings LLC will be merged with and into NEES with NEES as the surviving entity (the "NEES/NGG Merger"). NGG, a public limited company incorporated under the laws of England and Wales, owns and operates the England and Wales high-voltage transmission network, including interconnections with Scotland and France. Under the terms of the NEES/NGG Merger Agreement (attached as Exhibit B-1), NEES will become an indirect, wholly-owned subsidiary of NGG, which will become a registered holding company under the Act. On March 25, 1999, as amended - -------- 1 NEES owns ninety-nine percent of the voting securities of LLC and NEES Global, Inc. ("NEES Global") owns the remaining one percent. NEES Global is wholly-owned by NEES. on July 12, 1999, NEES and NGG filed an application/declaration with the Commission requesting authority to undertake their merger.2 On May 3, 1999, NEES shareholders approved the NEES/NGG Merger with 94 percent of the stock cast in favor of the NEES/NGG Merger. The Transaction which is the subject of this Application/Declaration is not contingent upon consummation of the NEES/NGG Merger. However, the instant Transaction has the full support of NGG. It is expected that the joint effect of this Transaction and the NEES/NGG Merger will be the creation of a new registered holding company, NGG, which will own a stronger, more efficient U.S. electric utility business formed through the consolidation of NEES and EUA.3 1. General Request In connection with the Transaction, Applicants, pursuant to Sections 6, 7, 9(a)(1), 10, 11, 12, and 13 of the Act and the rules thereunder, hereby request authorizations and approvals from the Commission with respect to the following: o The acquisition by LLC of all of the issued and outstanding EUA common shares, and the indirect acquisition of EUA common shares by NEES through its wholly-owned subsidiary, LLC; o The merger of NEES and EUA, with NEES being the surviving entity; o The acquisition of common shares related to the mergers of Eastern Edison Company ("Eastern Edison") and Massachusetts Electric Company ("Mass. Electric"), with Mass. Electric being the surviving entity; New England Power Company ("NEP") and Montaup Electric Company ("Montaup")4, with NEP being the surviving entity; and Blackstone Valley Electric Company ("Blackstone"), Newport Electric Corporation ("Newport"), and The Narragansett Electric Company ("Narragansett"), with Narragansett being the surviving entity; - -------- 2 See Holding Co. Act Release No. 26994 (Mar. 31, 1999). 3 The effects of the merger of NEES and NGG in conjunction with the Trans action are addressed at various points in this Application/Declaration. 4 See note 9, infra. o The indirect acquisition by NEES of EUA's non-utility businesses through NEES' ownership of common shares or equity in those non-utility businesses; o The merger of EUA Service Corporation ("EUA Service") into New England Power Service Company ("Service Company"), with Service Company being the surviving service company, and the former EUA companies entering into service agreements with Service Company in the authorized form; o The issuance of securities related to the mergers of Mass. Electric and Eastern Edison; NEP and Montaup; and Narragansett, Blackstone and Newport. The assumption by Mass. Electric of Eastern Edison's pollution control revenue bonds and preferred stock; o If the NEES/NGG Merger has not been consummated prior to the consummation of the Merger, approval of NEES' financing arrangements with a syndicate of banks, and authority for NEES to issue commercial paper or to engage in short term borrowing, pursuant to which NEES may borrow up to $650.0 million aggregate amount of debt outstanding at any one time, in addition to debt borrowings currently authorized, for the purpose of consummating the Transaction; o The assumption by NEES of certain guarantees under various debt instruments of EUA and its subsidiary companies (the "EUA System"), including EUA's guaranty of the long-term debt of EUA Cogenex Corporation ("EUA Cogenex"), EUA Cogenex's equity maintenance agreement and EUA Cogenex's short-term debt under the EUA System revolving credit line, and including EUA's guaranty of the debt of EUA Ocean State Corporation ("EUA Ocean State"); o Following the merger of EUA into NEES, there will be a time period before merger of EUA subsidiaries into NEES subsidiaries, and during such time period, the participation of EUA subsidiaries in the NEES money pool; and o Payment of dividends out of capital surplus. Applicants further request that the Commission grant such other authority as may be necessary in connection with the Transaction. The Merger is subject to certain customary closing conditions, including the receipt of the approval of EUA's shareholders by an affirmative vote of two-thirds of the outstanding EUA shares. At a meeting of EUA's shareholders on May 17, 1999, the Merger was approved by 76.2 percent of the outstanding EUA shares authorized to vote, and by a total of 97 percent of the votes cast at the meeting. The Merger also requires receipt of the approval of: (i) the Commission under the Act; (ii) the Federal Energy Regulatory Commission ("FERC"); (iii) the Nuclear Regulatory Commission ("NRC"); (iv) the Federal Communications Commission ("FCC"); (v) the Vermont Public Service Board (the "VPSB"); (vi) the Connecticut Department of Public Utility Control (the "CDPUC"); and (vii) possibly the New Hampshire Public Utilities Commission ("NHPUC").5 Additionally, pursuant to Chapter 247 of the Acts of 1999 of the General Assembly of State of Rhode Island and the Providence Plantations (99-H 6374 am), enacted July 1, 1999, the Rhode Island Division of Public Utilities and Carriers ("RIDIV") must approve a merger of public utilities. Therefore, the RIDIV has jurisdiction to approve the merger of Blackstone and Newport into Narragansett. Although the approval of the Massachusetts Department of Telecommunications and Energy ("MDTE") is not required for the Transaction, the MDTE has jurisdiction over the consolidation of the Massachusetts operating companies and the rate plan for the combined operating companies. Although the merger of the parent companies is not subject to the jurisdiction of the Rhode Island Public Utilities Commission ("RIPUC"), the RIPUC has jurisdiction over the retail rate plan associated with the combination of Blackstone and Newport into Narragansett.6 Applicants also filed the requisite notification with the Federal Trade Commission ("FTC") and the Department of Justice ("DOJ") under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"), and received clearance under the HSR Act on April 30, 1999. - -------- 5 Montaup is a joint owner of the Seabrook Nuclear Plant in New Hampshire, but has a contract to sell such ownership interest. Upon completion of that sale, Montaup no longer would be regulated by the NHPUC, and, therefore, NHPUC approval of the Transaction would not be required. 6 Copies of applications for the above-mentioned FERC, NRC and state approvals are attached as Exhibits D-1 to D-7. 2. Overview of the Transaction Pursuant to an Agreement and Plan of Merger, dated as of February 1, 1999 (the "Merger Agreement"), LLC will be merged with and into EUA in accordance with Section 2 of Chapter 182 and Sections 59 and 62 of Chapter 156C of the Massachusetts General Laws. Upon the execution and filing of a certificate of merger with the Secretary of the Commonwealth of Massachusetts by EUA and LLC, or any later date specified by such certificate (the "Effective Date"), the separate existence of LLC shall cease and EUA will be the surviving entity. Each one percent of the issued and outstanding membership interests in LLC will be converted into one transferable certificate of participation or share in EUA. All EUA shares that are owned by EUA as treasury shares and any EUA shares owned by NEES or any other wholly-owned subsidiary of NEES will be cancelled and retired and shall cease to exist, and no cash or other consideration shall be delivered in exchange therefor. The remaining EUA shares issued and outstanding immediately prior to the Effective Date will be cancelled and converted into the right to receive cash in the amount of $31.00 per share (the "Per Share Amount"), as such amount may be adjusted. If the closing of the Merger and the transactions contemplated by the Merger Agreement (the "Closing") have not taken place on or prior to November 17, 1999, the six month anniversary of May 17, 1999, the date on which EUA shareholders' approval was obtained, (the "Adjustment Date"), the Per Share Amount will be increased, for each day after the Adjustment Date up to and including the day which is one day prior to the earlier of the Closing and April 30, 2000, by an amount equal to $0.003. If the NEES/NGG Merger has not been consummated prior to the consummation of the Transaction, NEES intends to use available cash and funds from borrowings as described hereinafter to consummate the Transaction. If the NEES/NGG Merger has been consummated, NEES intends to use available cash and funds received from capital contributions from, or issuance of equity to, NGG to consummate the Transaction. As soon as practicable after the Merger, NEES and EUA plan to merge the NEES and EUA holding companies (with NEES becoming the surviving holding company). In order to consolidate the underlying operating companies in each state and the two service companies, Narragansett will merge with Blackstone and Newport, with Narragansett the surviving company. Mass. Electric will merge with Eastern Edison, with Mass. Electric the surviving company. NEP will merge with Montaup, with NEP the surviving company. EUA Service and Service Company also will be merged, with Service Company the surviving company. B. Description of the Parties to the Transaction 1. General Description a. NEES NEES was organized and exists as a voluntary association created under the laws of the Commonwealth of Massachusetts on January 2, 1926. A copy of NEES' Agreement and Declaration of Trust is incorporated by reference as Exhibit A-1. NEES' principal executive office is located at 25 Research Drive, Westborough, Massachusetts 01582. NEES is a registered public utility holding company, and NEES and its subsidiaries are subject to the broad regulatory provisions of the Act administered by the Commission. Various NEES subsidiaries also are subject to regulation by (i) the FERC under the Federal Power Act (the "FPA"), with respect to wholesale sales and transmission of electric power, construction and operation of hydroelectric projects, and accounting and other matters, and (ii) various state regulatory commissions (as discussed below). In addition, the activities of nuclear facilities in which NEES and its subsidiaries have ownership interests are regulated by the NRC. The common stock, par value of $1.00 per share, of NEES is listed on the New York Stock Exchange and the Boston Stock Exchange. As of June 30, 1999, there were 59,120,059 shares of NEES common stock outstanding. On a consolidated basis at the end of 1998, NEES had total assets of $5.07 billion, net utility assets of $2.5 billion, total operating revenues of $2.42 billion, utility operating revenues of $2.24 billion, and net income of $190.0 million. NEES owns all of the voting securities of the following four distribution subsidiaries: Mass. Electric, Narragansett, Granite State Electric Company ("Granite State"), and Nantucket Electric Company ("Nantucket") (collectively, the "Electricity Delivery Companies"). NEES also owns 99.97 percent of the outstanding voting securities of its principal transmission subsidiary, NEP. Together, the Electricity Delivery Companies and NEP constitute a single integrated electric utility system (the "NEES System") that is directly interconnected with other utilities in New England and New York State, including EUA, and indirectly interconnected with utilities in Canada. The NEES System covers more than 4,500 square miles with a population of approximately 3,000,000. At December 31, 1998, NEES and its subsidiaries had approximately 3,540 employees. A map marking the entire NEES service area is attached as Exhibit E-4. Mass. Electric is a public utility company engaged in the delivery of electricity to approximately 980,000 customers in an area comprising approximately 43 percent of Massachusetts. The Mass. Electric service area consists of 146 cities and towns, including the highly diversified commercial and industrial cities of Worcester, Lowell and Quincy. The population of the service area is approximately 2,160,000, or 36 percent of the total population of the state. During 1998, 39 percent of Mass. Electric's revenues from the sale of electricity was derived from residential customers, 39 percent from commercial customers, 21 percent from industrial customers, and 1 percent from others. In 1998, the utility's 20 largest customers accounted for approximately 7 percent of its electric revenues. At the end of 1998, Mass. Electric had total assets of $1.45 billion, operating revenues of $1.5 billion and net income of $49.4 million. Mass. Electric is subject to regulation by the FERC and the MDTE. Narragansett is a public utility company engaged in the delivery of electricity to approximately 335,000 customers in Rhode Island. Narragansett's service territory, which includes urban, suburban and rural areas, covers approximately 839 square miles, or 80 percent of the area of the state, and encompasses 27 cities and towns, including Providence, East Providence, Cranston, and Warwick. The population of the service area is approximately 725,000, which represents approximately 72 percent of the total population of the state. During 1998, 44 percent of Narragansett's revenues from the sale of electricity was derived from residential customers, 40 percent from commercial customers, 14 percent from industrial customers, and 2 percent from others. In 1998, the 20 largest customers of Narragansett accounted for approximately 10 percent of its electric revenues. At the end of 1998, Narragansett had total assets of $664.1 million, operating revenues of $475.7 million, and net income of $30.5 million. Narragansett is subject to the regulation of the FERC, the RIPUC and the RIDIV. Granite State is a public utility company engaged in the delivery of electricity to approximately 37,000 customers in 21 New Hampshire communities. The Granite State service territory has a population of approximately 73,000 and includes the Salem area of southern New Hampshire and several communities along the Connecticut River. During 1998, 49 percent of Granite State's revenues from the sale of electricity was derived from commercial customers, 36 percent from residential customers, 14 percent from industrial customers, and 1 percent from others. In 1998, the 10 largest customers of Granite State accounted for approximately 18 percent of its electric revenues. At the end of 1998, Granite State had total assets of $61.8 million, operating revenues of $65.7 million, and net income of $3.2 million. Granite State is subject to the regulation of the FERC and the NHPUC. Nantucket provides electric delivery service to approximately 10,000 customers on Nantucket Island, which has a year-round population of approximately 6,000 and a seasonal tourist population that peaks at approximately 40,000 during the summer. Nantucket's service area covers the entire island. During 1998, 62 percent of Nantucket's revenues from the sale of electricity was derived from residential customers, 37 percent from commercial customers and 1 percent from others. At the end of 1998, Nantucket had total assets of $44.0 million, operating revenues of $15.1 million, and net income of $500,000. Nantucket is subject to the regulation of the FERC and the MDTE. NEP is engaged in purchasing, transmitting and selling electric energy at wholesale. In 1998, 98 percent of NEP's revenues from the sale of electricity was derived from sales for resale to affiliated companies and 2 percent from sales for resale to municipal and other utilities. NEP recently has completed the sale of substantially all of its non-nuclear generating business and currently is attempting to sell its minority interests in three operating nuclear power plants and one fossil-fueled generating station in Maine.7 With the sale of its non-nuclear generating business, NEP is principally an electric transmission company. At the end of 1998, NEP had total assets of $2.41 billion, operating revenues of $1.2 billion and net income of $121.5 million. NEP is subject, for certain purposes, to regulation by the Commission, the FERC, the NRC, the MDTE, the NHPUC, the VPSB, the CDPUC, and the Maine Public Utilities Commission (the "MPUC"). New England Electric Transmission Corporation ("NEET") is a wholly-owned subsidiary of NEES. NEET owns and operates a direct current/alternating current converter terminal facility for the first phase of the Hydro-Quebec and New England interconnection (the "Interconnection") and six miles of high voltage direct current transmission line in New Hampshire. NEET, Mass. Hydro (described below) and N.H. Hydro (described below) together own and operate, on behalf of New England Power Pool ("NEPOOL") participants in the second phase of the Interconnection, a 450 kV direct current transmission line - -------- 7 NEP also is a holding company because it owns more than 10 percent of the outstanding voting securities of Vermont Yankee Nuclear Power Corporation ("Vermont Yankee"), the licensed operator of the Vermont Yankee nuclear facility. NEP also has minority interests in Yankee Atomic Electric Com pany ("Yankee Atomic"), Maine Yankee Atomic Power Company ("Maine Yankee") and Connecticut Yankee Atomic Power Company ("Connecticut Yankee"), all of which permanently have ceased operations. NEP is an exempt holding company under the Act. Yankee Atomic Electric Company, Holding Co. Act Release No. 13048 (Nov. 25, 1955). and related terminals. As of December 31, 1998, NEET had total assets of $35.2 million, operating revenues of $9.6 million and net income of $813,000. New England Hydro-Transmission Corporation ("N.H. Hydro"), in which NEES holds 53.97 percent of the common stock, operates 121 miles of high-voltage direct current transmission lines in New Hampshire for the second phase of the Interconnection, extending to the Massachusetts border. At the end of 1998, N.H. Hydro had total assets of $131.0 million, operating revenues of $31.7 million and net income of $4.8 million. New England Hydro-Transmission Electric Company, Inc. ("Mass. Hydro"), 53.97 percent of the voting stock of which is held by NEES, operates a direct current/alternating current terminal and related facilities for the second phase of the Interconnection and 12 miles of high-voltage direct current transmission lines in Massachusetts. At the end of 1998, Mass. Hydro had total assets of $160.0 million, operating revenues of $37.0 million and net income of $7.9 million. LLC, a Massachusetts limited liability company, exists solely for the purpose of effecting this Transaction by merging with and into EUA. Narragansett, Mass. Electric , Granite State, and NEP (and a NEES non-utility subsidiary, AllEnergy (described below)) are members of NEPOOL. The FERC recently has approved a restructuring of NEPOOL involving (i) the formation of an Independent System Operator ("ISO") that will control the transmission facilities owned by the NEPOOL public utility members and administer the NEPOOL open-access transmission tariff and (ii) the operation of a power exchange that will embody a competitive power wholesale market. New England Power Pool, 85 FERC P. 61,379 (December 17, 1998). b. EUA EUA was organized and exists under a Declaration of Trust dated April 2, 1928, as amended, in the Commonwealth of Massachusetts. A copy of the EUA Declaration of Trust, as amended, is incorporated by reference as Exhibit A-2. EUA's principal executive office is located at One Liberty Square, P.O. Box 2333, Boston, Massachusetts 02109. EUA operates as a registered holding company pursuant to the Act. At the end of 1998, the EUA System served approximately 305,000 retail customers in Massachusetts and Rhode Island. As a registered public utility holding company, EUA and its subsidiaries are subject to the broad regulatory provisions of the Act administered by the Commission. Various EUA subsidiaries also are subject to regulation by (i) the FERC under the FPA with respect to wholesale sales and transmission of electric power, accounting and other matters and (ii) various state regulatory commissions (as discussed below). In addition, the activities of nuclear facilities in which EUA has ownership interests are regulated by the NRC. The common shares, par value of $5 per share, of EUA are listed on the New York and Pacific Exchanges. As of July 31, 1999, there were 20,435,997 EUA common shares outstanding. On a consolidated basis at the end of 1998, EUA had total assets of $1.3 billion, net utility assets of $651.6 million, operating revenues of $538.8 million, utility operating revenues of $480.1 million, net income of $37.0 million, and utility net income of $37.4 million EUA directly owns all of the common stock of the following electric public utility companies: Blackstone, Eastern Edison and Newport. Eastern Edison owns all of the outstanding securities of Montaup.8 As of December 31, 1998, Blackstone, Eastern Edison, Newport, and Montaup together had 399 employees; EUA Service had an additional 551 employees. A map marking the entire EUA service area is attached as Exhibit E-4. Blackstone was organized in 1912 under the laws of the State of Rhode Island. Blackstone serves a territory of approximately 150 square miles in portions of northern Rhode Island with a population of approximately 207,000. As of December 31, 1998, Blackstone furnished retail electric service to approximately 86,000 customers. At the end of 1998, Blackstone had total assets of $134.1 million, operating revenues of $130.2 and net income of $4.9 million. Blackstone is subject to the regulation of the FERC, the RIDIV and the RIPUC. Eastern Edison was organized in 1883 under the laws of the Commonwealth of Massachusetts. Eastern Edison supplies electric service in 22 cities and towns in southeastern Massachusetts. Eastern Edison's retail electric service territory covers approximately 392 square miles and has an estimated population of approximately 463,000. As of December 31, 1998, Eastern Edison served approximately 186,000 retail customers. On a consolidated basis at the end of 1998, Eastern Edison had total assets of $831.6 million, operating revenues of $408.2 million and net income of $29.7 million. Eastern Edison is subject to the regulation of the FERC and the MDTE. Newport serves a territory of approximately 55 square miles and an estimated population of approximately 70,000 in south coastal Rhode Island. - -------- 8 See note 9, infra. Newport supplies retail electric service to approximately 33,000 customers. At the end of 1998, Newport had total assets of $71.9 million, operating revenues of $59.5 million and net income of $2.9 million. Newport is subject to the regulation of the FERC, the RIDIV and the RIPUC. Montaup, a subsidiary of Eastern Edison9, is a generation and transmission company that supplies electricity at wholesale to Eastern Edison, Blackstone, Newport, and two unaffiliated utilities. Consistent with the electric utility industry restructuring legislation passed in Massachusetts and Rhode Island and settlement agreements approved by regulators in those states and at the FERC, Montaup has agreed to sell all of its generating assets and transfer its non-nuclear power purchase contracts. Montaup has minority ownership interests in Vermont Yankee, Connecticut Yankee, Maine Yankee, and Yankee Atomic. Montaup also owns minority interests in Millstone 3 and Seabrook. As noted above, Yankee Atomic, Connecticut Yankee and Maine Yankee permanently have shut down operations. In addition, Montaup has agreed to sell its interests in Seabrook and continues to attempt to sell its interests in Vermont Yankee and Millstone 3. At the end of 1998 Montaup had total assets of $641.0 million, operating revenues of $324.7 million and net income of $15.5 million. Montaup is subject to the regulation of the FERC, and the NRC, and to limited regulation by the MPUC, the CDPUC, the VPSB, the NHPUC and the MDTE. 2. Description of Facilities a. NEES i. General For the year ending December 31, 1998, NEES and its utility subsidiaries sold 25,413 million kWh of electric energy (at retail or wholesale). ii. Electric Generating Facilities and Resources Pursuant to a settlement agreement with the RIPUC and a settlement agreement approved by the MDTE in connection with the electric utility - -------- 9 Montaup currently is a subsidiary of Eastern Edison. However, on July 14 1999, EUA filed an application (File No. 70-9527) with the Commission seeking authority for Eastern Edison to transfer to EUA, and for EUA to acquire from Eastern Edison, all of Eastern Edison's investment in Montaup's capitalization, so that EUA will become the direct parent of Montaup. restructuring undertaken in their respective states, NEP and Narragansett entered into an agreement to sell all their generating assets. On September 1, 1998, NEP and Narragansett completed the sale of substantially all of their non-nuclear generating business to USGen New England, Inc. ("USGen"), an indirect wholly-owned subsidiary of PG&E Corporation. The non-nuclear generating business included three fossil-fueled and 15 hydroelectric generating stations, totaling approximately 4,000 megawatts ("MW") of capacity, as well as NEES' 100 percent interest in Narragansett Energy Resources Company, a 20 percent general partner in the Ocean State Power project, all of which had a book value of $1.1 billion at the time of sale. USGen also purchased NEP's entitlement to approximately 1,100 MW of power procured under long-term contracts. NEP currently owns interests in six nuclear generating facilities. As noted above, the nuclear plants owned by Yankee Atomic, Maine Yankee and Connecticut Yankee have been shut down permanently. NEP currently is attempting to sell its minority ownership interests in three other nuclear power plants, Vermont Yankee, Millstone 3 and Seabrook 1, and a 60 MW interest in a fossil-fueled generating station in Maine. In February 1999, Vermont Yankee entered into a letter of intent to sell its assets. Although the term of this letter of intent has expired, Vermont Yankee is holding negotiations with two parties regarding possible sale. iii. Electric Transmission Facilities As of December 31, 1998, NEP's integrated transmission system consisted of 2,233 circuit miles of transmission lines, 110 substations with an aggregate capacity of 12,535,789 kVA and 7 pole or conduit miles of distribution lines. As of December 31, 1998, Narragansett owned 327 circuit miles of transmission lines, 224 substations with an aggregate capacity of 4,003,695 kVA, 49,475 line transformers with the capacity of 2,133,156 kVA, and 4,644 pole or conduit miles of distribution lines. As of December 31, 1998, Mass. Electric owned 83 circuit miles of transmission lines, 247 substations with an aggregate capacity of 2,951,270 kVA, 147,571 line transformers with the capacity of 8,318,059 kVA, and 17,204 pole or conduit miles of distribution lines. b. EUA i. General For the year ending December 31, 1998, EUA and its utility subsidiaries sold 5,974 million kWh of electric energy (at retail or wholesale). ii. Electric Generating Facilities and Resources By the end of 1998, pursuant to settlement agreements approved by federal and state regulators, EUA's utility affiliates signed agreements to sell all of their non-nuclear power generation assets and power purchase agreements to various non-affiliated parties in connection with electric utility restructuring undertaken in Massachusetts and Rhode Island. At the end of 1998, Montaup sold several diesel-powered generating units (totaling approximately 16 MW) owned by Newport to Illinois-based Wabash Power Equipment Company and its 50 percent share (approximately 280 MW) of Unit 2 of the Canal generating station in Sandwich, Massachusetts to Southern Energy Canal, LLC, an indirect subsidiary of The Southern Company. On April 7, 1998, Montaup entered into an agreement to transfer power purchase contracts for approximately 170 MW of output from Ocean State Power I and Ocean State Power II to TransCanada Power Marketing Ltd., an indirect subsidiary of TransCanada Pipelines Limited; the transfer was effective June 1, 1999. On December 21, 1998, Montaup entered into an agreement to transfer purchase power contracts totaling approximately 177 MW to Constellation Power Source, Inc., a wholly owned affiliate of the Baltimore Gas and Electric Company; the transfer will become effective on September 1, 1999. On April 26, 1999, Montaup completed the sale of its 170 MW Somerset Generating Station, located in Somerset, Massachusetts, to Somerset Power, LLC, an indirect subsidiary of Northern States Power Company. In June of 1999, Montaup completed the sale of its and Newport's combined 2.6 percent (approximately 16 MW) share of the W.F. Wyman Unit 4 in Yarmouth, Maine to FPL Energy Wyman IV LLC, an indirect subsidiary of the Florida-based FPL Group, Inc. Also in June of 1999, Blackstone sold its hydroelectric facility in Pawtucket, Rhode Island (approximately 1 MW) to Pawtucket Hydropower LLC, an affiliate of Putnam Hydropower Inc. In July 1999, in connection with Entergy Nuclear Generation Company's acquisition of Pilgrim Station from Boston Edison, the power purchase agreement (approximately 73 MW) between Montaup and Boston Edison was terminated. As a condition of the termination, Montaup entered into a reduced term power purchase contract for Pilgrim Station power with Entergy Nuclear Generation Company. Montaup also has agreed to sell its ownership interest in the Seabrook Station nuclear power plant to Little Bay Power Corporation, a subsidiary of BayCorp Holdings, Ltd., with an expected closing later in 1999. EUA's remaining generating capacity comprises 58 MW from its ownership shares of the Millstone 3 and Vermont Yankee nuclear facilities. EUA actively is attempting to sell and/or transfer its interests in the Vermont Yankee facility, and ultimately intends to sell and/or transfer its interests in Millstone 3 as well. All of the sale and contract transfer agreements are subject to federal and/or state regulatory approvals, including that of the NRC with respect to the Seabrook sale. iii. Electric Transmission Facilities The EUA transmission system consists of approximately 7,100 miles of transmission and distribution lines and 84 substations located in the cities and towns served. Blackstone owns approximately 1,700 miles of transmission and distribution lines and 26 substations. Eastern Edison and Montaup own approximately 4,600 miles of transmission and distribution lines and 44 substations. Newport owns approximately 800 miles of transmission and distribution lines and 14 substations. 3. Non-Utility Businesses a. NEES The following provides a summary of each of the non-utility companies in which NEES has an ownership interest: i. New England Hydro Finance Company, Inc. New England Hydro Finance Company, Inc. ("N.E. Hydro Finance"), owned in equal shares by Mass. Hydro and N.H. Hydro, provides the debt financing required by Mass. Hydro and N.H. Hydro to fund the capital costs of their participation in the Interconnection. ii. NEES Communications, Inc. NEES Communications, Inc. ("NEESCom") is a wholly-owned subsidiary of NEES that provides telecommunications and information-related products and services. NEESCom was established to allow NEES to participate in the growing telecommunications industry. NEESCom, an exempt telecommunications company, is not regulated under the Act and has a license issued by and is subject to regulation by the FCC. NEESCom plans to focus on the fiber optics cable and infrastructure sectors of the telecommunications industry. At the end of 1998, NEESCom had total assets of $12.6 million, operating revenues of $100,000 and a net loss of $1.2 million. iii. NEES Global NEES Global is a wholly-owned non-utility subsidiary of NEES which provides consulting services and product licenses to unaffiliated utilities in the areas of electric utility restructuring and customer choice. NEES Global also sells and leases water heaters through its wholly-owned subsidiary, New England Water Heater Co., Inc. At the end of 1998, NEES Global had total assets of $23.3 million, operating revenues of $5.0 million and a net loss of $1.1 million. iv. NEES Energy, Inc. NEES Energy, Inc. ("NEES Energy") is a wholly-owned marketing subsidiary of NEES. At December 31, 1998, NEES Energy had total assets of $86.5 million, operating revenues of $171.4 million and a net loss of $13.0 million. v. AllEnergy Marketing Company, L.L.C. AllEnergy Marketing Company, L.L.C. ("AllEnergy") is an indirect, wholly-owned subsidiary of NEES. NEES Energy owns 100 percent of the voting securities of AllEnergy. AllEnergy, a member of NEPOOL, markets energy commodities (natural gas, propane, and oil) and provides a wide range of energy-related services, including but not limited to, marketing, brokering and sales of energy, audits, fuel supply, repair, maintenance, construction, operation, design, engineering, and consulting to customers in the competitive power markets of New England and New York. AllEnergy also owns Texas Liquids LLC, which is principally a propane and natural gas marketer with its home office in New Jersey. On February 12, 1999, NEES and AllEnergy acquired Griffith Consumers Company, a full service distributor of residential and commercial heating oil in Washington, D.C., and in parts of Maryland, Delaware, Virginia, and West Virginia. On June 14, 1999, AllEnergy agreed to buy Texas-Ohio Gas, Inc., a unit of Denver-based New Century Energies that sells gas to about 3,000 commercial and industrial customers in the Northeast of the United States. vi. Granite State Energy, Inc. Granite State Energy, Inc. ("Granite State Energy") is a wholly-owned, non-utility marketing subsidiary of NEES. Granite State Energy provides a range of energy and energy-related services, including: sales of electric energy, audits, power quality, fuel supply, repair, maintenance, construction, design, engineering, and consulting. At the end of 1998, Granite State Energy had total assets of $300,000, operating revenues of $700,000, and no net income. vii. Service Company Service Company, wholly-owned by NEES, is a service company pursuant to Section 13 of the Act. Service Company has contracted with NEES and its subsidiaries to provide, at cost, such administrative, engineering, construction, legal, and financial services as NEES and its subsidiaries request pursuant to a service agreement approved by the Commission in accordance with the requirements of Rule 90. At the end of 1998, Service Company had total assets of $123.2 million and net income of $1.8 million. viii. New England Energy Incorporated As part of NEES' plan to divest its generating business, New England Energy Incorporated ("NEEI"), wholly-owned by NEES, sold its oil and gas properties in February 1998. NEEI primarily participated (principally through a partnership with a non-affiliated oil company) in domestic oil and gas exploration, development and production. NEEI also sold fuel purchased in the open market to NEP. At the end of 1998, NEEI had total assets of $7.6 million and a net loss of $100,000. ix. Metrowest Realty, LLC Metrowest Realty, LLC, wholly-owned by NEES, owns the headquarters complex of NEES and its subsidiaries. The complex is located in Westborough, Massachusetts. Metrowest Realty, LLC also owns the North Andover, Massachusetts service center occupied by Mass. Electric. b. EUA EUA directly owns all of the common stock of the following non-utility companies: EUA Cogenex, EUA Energy Investment Corporation ("EUA Energy"), EUA Ocean State, EUA Energy Services, Inc. ("EUA Energy Services"), EUA Telecommunications Corporation ("EUA Telecommunications"), and Eastern Edison Electric Company. In addition, EUA directly owns all of the common stock of EUA Service, a service company pursuant to Section 13 of the Act. i. EUA Cogenex EUA Cogenex is an energy services company that employs energy efficient technology and equipment intended to reduce the energy consumption and costs of its customers. Such technology and equipment include: building automation systems, lighting modifications, boiler and chiller replacements, and other mechanical measures such as motors and drives. EUA Cogenex also serves public and private multi-family housing through its subsidiary, EUA Citizens Conservation Services, Inc., of which EUA Cogenex holds all voting control. In addition, EUA Cogenex owns 100 percent of the voting stock of EUA Cogenex West (formerly EUA Highland Corporation), an energy services company that provides energy conservation services in Colorado, Texas, Ohio, North Carolina, and certain mid-western states. EUA Cogenex also holds all voting control of Northeast Energy Management, Inc., a demand side management company, and EUA Cogenex-Canada, Inc. (which holds 100 percent voting control of EUA Cogenex-Canada Energy Services, Inc., a company formed to participate in a marketing and development joint venture with Monenco Agra, an Ontario-based engineering firm). As of December 31, 1998, EUA Cogenex held 50 percent of the voting control and acted as managing general partner of the following partnerships which operate and monitor existing demand side management and/or energy management services contractual obligations, but do not develop new business: EUA WestCoast L.P., EUA Energy Capital and Services I, EUA Energy Capital and Services II, EUA FRC II Energy Associates, and Micro Utility Partners of America. As of December 31, 1998, EUA Cogenex also held 50 percent of the voting power in APS Cogenex L.L.C., a limited liability company formed to develop, engineer and construct projects at the National Cancer Institute in Army Garrison at Fort Detrick, Maryland. As of December 31, 1998, EUA Cogenex employed 187 persons in its operations and had total consolidated assets of $157.2 million, operating revenues of $54.8 million, and a net loss of $1.3 million. As of June 28, 1999, the management of EUA Cogenex decided to divest certain of the non-core businesses and activities of EUA Cogenex including EUA Citizens Conservation Services, Inc. and the EUA/DAY and DAYMetrix divisions of EUA Cogenex. EUA Cogenex has received an offer from the management of the EUA/DAY division to purchase the business and assets of such division from EUA Cogenex. As a result of this pending sale and the corresponding cessation of continued development of DAYMetrix, its energy control software application and related technologies division, EUA Cogenex recorded an after tax charge of $2.9 million in the second quarter of 1999. ii. EUA Energy EUA Energy invests in energy-related projects. EUA Energy wholly owns Renova LLC ("Renova"), which was transferred from EUA Cogenex in May 1998. Renova manufactures energy efficient fluorescent lighting products that maximize lighting output and reduce energy consumption. EUA Energy also retains 100 percent voting power in: EUA BIOTEN, Inc. ("EUA BIOTEN"), which was formed to develop biomass-fueled generating units and which owns 100 percent of the common stock of BIOTEN Operations, Inc., a Tennessee corporation that owns a demonstration facility in Red Boiling Springs, Tennessee; Eastern Unicord Corporation, which was formed to invest in the construction of a wood burning energy plant in Pembroke, New Hampshire; EUA Compression Services, Inc., which was formed to provide compression stations along transmission lines; and EUA TransCapacity, Inc., which was formed to develop and market services and computer software enabling natural gas industry clients to connect, communicate and coordinate with their trading partners via electronic data interchange. EUA Energy also holds 9.9 percent of the voting power of Separation Technologies, Inc., which markets and installs its own proprietary equipment for separating unburned carbon from coal fly-ash. At the end of 1998, EUA Energy had total assets of $30.4 million, operating revenues of $3.9 million and a net loss of $5.3 million. EUA Energy is attempting to negotiate strategic alliances with, or the sale of, its energy-related investments, including EUA BIOTEN, Renova, and TransCapacity, L.P., prior to the Merger. EUA BIOTEN has reached an agreement with the management of BIOTEN Corp., a newly formed Delaware corporation that is not affiliated with EUA BIOTEN, pursuant to which BIOTEN Corp.'s management will have the option, through December 31, 1999, to purchase all the assets of EUA BIOTEN. EUA BIOTEN recently received a letter of intent from a third party which, among other things, would finance the purchase of EUA BIOTEN's assets by BIOTEN Corp.'s management. As a result, EUA Energy recorded an after tax charge to its earnings of approximately $9.4 million in the second quarter of 1999. Similarly, EUA Energy recently received a letter of intent from the management of Renova to purchase certain of its assets. As a result of this pending sale, EUA Energy recorded an after tax charge to its earnings of approximately $3.5 million in the second quarter of 1999. EUA Energy plans to dissolve Eastern Unicord Corporation and EUA Compression Services, Inc. prior to the Merger. TransCapacity, L.P. ceased normal operations effective July 31, 1999. iii. EUA Ocean State EUA Ocean State owns a 29.9 percent partnership interest in the northern Rhode Island-based Ocean State generating station's two gas-fired generating units, Ocean State Power I and Ocean State Power II. At the end of 1998, EUA Ocean State had total assets of $49.2 million and net income of $4.1 million. iv. EUA Energy Services EUA Energy Services markets energy and energy-related services. At the end of 1998, EUA Energy Services had total assets of $500,000 and a net loss of $200,000. EUA plans to dissolve EUA Energy Services prior to the Merger. v. EUA Telecommunications EUA Telecommunications was formed to provide telecommunications and information services. At the end of 1998, EUA Telecommunications had total assets of $70,000 and a net loss of $100,000. EUA plans to dissolve EUA Telecommunications prior to the Merger. vi. EUA Service EUA Service is a service company pursuant to Section 13 of the Act. EUA Service provides various accounting, financial, engineering, planning, data processing, and other services to all EUA System companies in accordance with the requirements of Rule 90. At the end of 1998, EUA Service had total assets of $35.3 million and net income of $260,000. vii. Eastern Edison Electric Company Eastern Edison Electric Company was originally formed as part of EUA's efforts to consolidate its subsidiaries. Eastern Edison Electric Company, however, has been inactive for over six years and EUA plans to dissolve the company prior to the Merger. C. Description of Transaction 1. Background In late May, 1998, the EUA board of trustees (the "EUA Board") met to review EUA's strategic options for future operations. The EUA Board decided to open communications with selected electric utilities in the region in an attempt to determine their interest in discussing some type of business combination. In December 1998, EUA contacted NEES to explore NEES' interest in discussing a possible business combination. After intensive negotiations between NEES and EUA, the EUA Board held special meetings on January 31, 1999 and February 1, 1999, to review and consider the proposals received from NEES. After presentations by the EUA Board's legal and financial advisors, and a full discussion and analysis by the EUA Board, the EUA Board (1) determined that it was in the best interests of EUA's shareholders, employees and customers for EUA to enter into a business combination with NEES; (2) determined that the terms of the Merger were fair to, and in the best interests of, EUA shareholders; and (3) authorized, approved and adopted the proposed agreement and plan of merger and the transaction contemplated by the Merger Agreement, and the execution and delivery of the Merger Agreement. EUA was advised that NEES obtained the consent of NGG to enter into the Merger Agreement, and on the morning of February 1, 1999, at the conclusion of the EUA Board meeting and prior to the opening of markets, EUA and NEES executed and delivered the Merger Agreement. 2. Merger Agreement The Merger Agreement provides for the merger of LLC with and into EUA, with EUA as the surviving entity. The Merger Agreement is incorporated by reference as Exhibit B-4. Under the terms of the Merger Agreement, each outstanding common share of EUA (and collectively, the "EUA Common Shares"), other than shares, if any, owned by EUA as treasury shares, or by NEES, LLC or any other wholly-owned subsidiary of NEES, will be converted into the right to receive cash in the amount of $31.00 per share. If the Closing does not occur on or prior to the Adjustment Date, then the per share amount will be increased by an amount equal to $0.003 for each day after the Adjustment Date, up to and including the day which is one day prior to the earlier of the Closing and April 30, 2000. The Merger Agreement may be terminated under certain circumstances, some of which provide for the payment of termination fees. The Transaction is subject to customary closing conditions, including the approval of the holders of two-thirds of the outstanding EUA Common Shares and all necessary governmental approvals, including that of the Commission. The Transaction has been approved by the NEES Board of Directors, the EUA Board and the Members of LLC. On May 17, 1999, EUA shareholders approved the Merger, with 97 percent of the shareholders that voted casting ballots in favor of the Merger. Because the acquisition of EUA is for cash, the conditions for pooling of interest accounting are not met with regard to the Transaction. The Transaction will be accounted for as a purchase in accordance with generally accepted accounting principles. The conversion of EUA Common Shares into the right to receive the Merger consideration pursuant to the Merger Agreement will be treated as a taxable sale of such shares for United States federal income tax purposes (and also may be a taxable transaction under applicable state, local, foreign, and other tax laws). D. Management and Operations Following the Transaction As noted above, as soon as practicable after the Merger, NEES and EUA plan to merge the NEES and EUA holding companies, with NEES as the surviving holding company. Subject to the receipt of state regulatory approvals, as necessary, Narragansett will merge with Blackstone and Newport, with Narragansett the surviving company; Eastern Edison will merge with Mass. Electric, with Mass. Electric the surviving company; and Montaup will merge with NEP, with NEP the surviving company. Finally, to lower administrative costs, EUA Service and Service Company will be consolidated, with Service Company the surviving company. After the Merger, the surviving companies will be managed and operated in a manner similar to the current operations. ITEM II. FEES, COMMISSIONS AND EXPENSES The fees, commissions and expenses that shall be paid or incurred, directly or indirectly, in connection with the Transaction are estimated as follows: Thousands Accountants' fees................................................. * Legal fees and expenses........................................... * Shareholder communication and proxy solicitation expenses......... * NYSE listing fee.................................................. * Pacific Stock Exchange listing fee................................ * Exchanging, printing and engraving stock certificates expenses.... * Investment bankers' fees and expenses............................. * Consulting fees................................................... * Miscellaneous .................................................... * Total........................................................ * (*) To be filed by amendment The total fees, commissions and expenses expected to be incurred for transaction and regulatory processing costs will be filed by amendment. ITEM III. APPLICABLE STATUTORY PROVISIONS The following Sections of the Act and Commission rules relate to the Transaction: Section or Rule Under the Act Action to Which Section or Rule Relates 6, 7 and rules thereunder Issuance of securities related to the mergers of Eastern Edison with Mass. Electric, Montaup with NEP, and Blackstone and Newport with Narragansett. Assumption by Mass. Electric of Eastern Edison's pollution control revenue bonds, and preferred stock. Borrowing by NEES of up to $650.0 million under certain circumstances. NEES assumption of guarantees under various debt instruments of EUA System companies. Participation of EUA subsidiaries in NEES money pool. 9, 10, 11, 12 and rules Acquisition by NEES of LLC and of EUA thereunder Common Shares; indirect acquisition by NEES of securities and interests in the business of EUA's subsidiary companies, including the non-utility subsidiaries; payments of dividends out of capital surplus. 13 and rules thereunder Merger of EUA Service into Service Company with Service Company as the surviving service company. Section 9(a)(1) of the Act provides that unless the acquisition has been approved by the Commission under Section 10, it shall be unlawful for any registered holding company or any subsidiary company thereof "to acquire, directly or indirectly, any securities or utility assets or any other interest in any business." Section 9(a)(1) is applicable to the proposed Transaction because it involves the acquisition by NEES of EUA Common Shares, the indirect acquisition by NEES of the securities of and interests in the businesses of EUA's subsidiary companies, and the merger of EUA's utility subsidiaries into NEES' utility subsidiaries. For the reasons set forth in detail below, the Transaction fully complies with Section 10 of the Act: o The Transaction will not create detrimental interlocking relations or a detrimental concentration of control; o The consideration and fees to be paid in connection with the Transaction are fair and reasonable; o The Transaction will not result in an unduly complicated capital structure for the merged company; o The Transaction is in the interests of the public, investors and consumers; o The merged company will be a single integrated public utility system; o The Transaction will result in an equitable distribution of voting power among NEES' investors and does not unduly complicate the structure of the holding company system; o The Transaction tends toward the economical and efficient development of an integrated electric utility system; and o The Transaction will comply with all applicable state laws. Pursuant to Sections 9 and 10, Congress entrusted the Commission with the responsibility for "supervision over the future development of utility-holding company systems." The Southern Co., Holding Co. Act Release No. 25639 (Sept. 23, 1992) ("Southern"). In Section 1(c), the Act directs the Commission to interpret all provisions of the Act to address certain enumerated problems and evils in order to protect the interests of the general public, investors and consumers. As a result, the Commission's mandate under the Act is "to prevent acquisitions which would be 'attended by the evils which have featured the past growth of holding companies.'" American Elec. Power Co., Holding Co. Act Release No. 20633 (July 21, 1978) (quoting H.R. Rep. No. 1318, 74th Cong., 1st Sess. 16 (1935)). Such evils include the "growth and extension of holding companies [that] bears no relation to economy of management and operation or the integration and coordination of related operating properties." Section 1(b)(4) of the Act. The Transaction fully complies with the Act and does not prompt any of the concerns that the Act was intended to address. In fact, the Transaction clearly promotes the goals of the Act by creating an integrated merged entity that will benefit the interests of the general public, investors and consumers. Both state and federal regulation will ensure that the interests of the public, investors and consumers continue to be protected. Set forth below are discussions of each of the subsections of Section 10 of the Act as they relate to the Transaction. A. Section 10(b) Section 10(b) of the Act provides that if the requirements of Section 10(f) are satisfied, the Commission must approve an acquisition under Section 9(a) unless the Commission finds that: (1) such acquisition will tend towards interlocking relations or the concentration of control of public-utility companies, of a kind or to an extent detrimental to the public interest or the interest of investors or consumers; (2) in case of the acquisition of securities or utility assets, the consideration, including all fees, commissions, and other remuneration, to whomsoever paid, to be given, directly or indirectly, in connection with such acquisition is not reasonable or does not bear a fair relation to the sums invested in or the earning capacity of the utility assets to be acquired or the utility assets underlying the securities to be acquired; or (3) such acquisition will unduly complicate the capital structure of the holding-company system of the applicant or will be detrimental to the public interest or the interest of investors or consumers or the proper functioning of such holding-company system. 1. Section 10(b)(1) Under Section 10(b)(1) of the Act, the Commission shall approve a proposed acquisition unless it finds that the proposed acquisition shall "tend towards interlocking relations or the concentration of control of public utility companies of a kind or to an extent detrimental to the public interest or the interest of investors or consumers." Thus, Section 10(b)(1) does not prohibit a merger merely because it causes interlocking relations or increases concentration of control to some degree. Rather, a merger fails the balancing test set forth in Section 10 only when any detrimental effects from any interlocking relations or concentration of control caused by the merger outweigh the merger benefits. a. Interlocking Relations Any merger creates interlocking relations between previously unrelated companies. As previously noted by the Commission: "[W]ith any addition of a new subsidiary to a holding company system, the Acquisition will result in certain interlocking relationships between [the two merging entities]." Northeast Utilities, Holding Co. Act Release No. 25221 (Dec. 21, 1990), modified on other grounds, Holding Co. Act Release No. 25273 (Mar. 15, 1991), aff'd sub nom. City of Holyoke Gas & Elec. Dep't v. SEC, 972 F.2d 358 (D.C. Cir. 1992) ("Northeast I"). Such "interlocking relationships are necessary to integrate [the two merging entities.]" Id. As noted above, immediately or shortly after consummation of the Transaction, EUA will cease its corporate existence and its utility subsidiaries will be merged into NEES' utility subsidiaries. Because EUA thus will be completely merged into NEES and will end its independent existence, no concern about interlocking relations is presented by the Transaction. b. Concentration of Control When considering the issue of concentration of control pursuant to Section 10(b)(1), the Commission "considers various factors, including the size of the resulting system and the competitive effects of the acquisition." Entergy Corp., Holding Co. Act Release No. 25952 (Dec. 17, 1993), request for reconsideration denied, Holding Co. Act Release No. 26037 (Apr. 28, 1994), remanded sub nom. Cajun Elec. Power Coop. Inc. v. SEC, 1994 WL 704047 (D.C. Cir. Nov. 16, 1994) ("Entergy"). i. Size The NEES system following the acquisition of EUA's assets and operations will serve approximately 1.67 million retail electric customers in New England. Based on year-end 1998 figures, the system's annual operating revenues will be approximately $2.96 billion (operating utility revenues of approximately $2.72 billion); and its total assets will be approximately $6.37 billion (utility assets of approximately $3.14 billion). The Commission has approved a number of mergers and acquisitions involving utilities with combined assets and operations exceeding or approximately those of the NEES/EUA merged company. See, e.g., New Century Energies, Inc., Holding Co. Act Release No. 26748 (Aug. 1, 1997) (merged company assets of approximately $7 billion); Ameren Corp., Holding Co. Act Release No. 26809 (Dec. 30, 1997) (assets of $8.8 billion, utility assets of approximately $6.6 billion); CINergy Corp., Holding Co. Act Release No. 26146 (Oct. 21, 1994) (assets of approximately $8 billion, utility assets of approximately $6 billion) ("Cinergy"). Following the Transaction, NEES will be smaller than Northeast Utilities, another registered holding company operating in New England, and, as illustrated by the following table, will be among the smaller of the registered holding companies. Registered Holding Company Statistics (as of December 31, 1998) ($MM)
12 Months' Consolidated Consolidated Holding Company System Assets Rank Operating Earnings Rank - ---------------------- ------ ---- ------------------ ---- Southern Co. (E) 36,192.0 1 11,403.0 2 Entergy Corp. (E) 22,848.0 2 11,494.8 1 American Electric Power Co. (E) 19,483.2 3 6,345.9 3 GPU Corp. (E) 16,288.1 4 4,248.8 7 Central and South West Corp. (E) 13,744.0 5 5,482.0 6 Northeast Utilities (E) 10,387.4 6 3,767.7 8 Cinergy Corp. (E)(G) 10,298.8 7 5,876.3 4 Ameren (E)(G) 8,847.4 8 3,318.2 10 New Century Energies (E)(G) 7,672.0 9 3,610.9 9 Columbia Energy Group (G) 6,968.7 10 5,731.8 5 Allegheny Energy, Inc. (E) 6,747.8 11 2,576.4 14 NEES/EUA (E) 6,373.2 12 2,959.3 12 Consolidated Natural Gas Co. (G) 6,361.9 13 2,760.4 13 Conectiv (E)(G) 6,100.0 14 3,100.0 11 Alliant Energy Corp. (E)(G) 4,959.0 15 2,131.0 15 National Fuel Gas Co. (G) 2,684.5 16 1,248.0 16 Unitil Co. (E)(G) 376.9 17 149.6 17 PECO Energy Power Co. (E) 118.0 18 18.5 18 Source: Holding Companies Registered Under the Public Utility Holding Company Act of 1935 As of July 1, 1999, Report of the Division of Investment Management, United States Securities and Exchange Commission. Legend (E): Electric Utility (G): Gas Utility
ii. Competition and Antitrust Considerations The Commission's Section 10(b)(1) analysis also must include consideration of federal antitrust policies.10 Were the Commission to determine that an acquisition tends toward the concentration of control of public utility companies, the Commission balances this effect against the benefits of the acquisition to determine whether the acquisition meets the Section 10(b)(1) standards. In the past, the Commission "has approved acquisitions that decrease competition when it concludes that the acquisitions would result in benefits such as possible economies of scale, elimination of the duplication of facilities and activities, sharing of production capacity and reserves, and generally more efficient operations." Northeast I, supra. The Commission also has stated that the "antitrust ramifications of an acquisition must be considered in light of the fact that public utilities are regulated monopolies and that federal and state administrative agencies regulate the rates charged consumers." Id. The Commission has concurrent jurisdiction in assessing the competitive impacts of the Transaction with the DOJ, the FTC, and the FERC. Additionally, the MDTE may inquire into the effects of competition. Applicants filed Notification and Report Forms with the DOJ and the FTC, which contain a description of the Transaction's effects on competition, as required by the HSR Act, and received clearance under the HSR Act on April 30, 1999. In addition, on May 5, 1999, as amended on July 1, 1999, Applicants filed with the FERC a request for approval of the Transaction pursuant to Section 203 of the Federal Power Act. The FERC will evaluate the Transaction's competitive effects and will approve the Transaction only upon finding that it is in the public interest and will not adversely affect competition. Attached as Exhibit D-1 is Applicants' FERC Application, which contains detailed discussions and testimony explaining that the Transaction will not have any adverse effect on competition. Specifically, in the FERC Application, and the testimony of Dr. Henry J. Kahwaty attached hereto, Applicants explained that the Transaction does not create any issues with respect to generation or transmission market power, or vertical effects. In accordance with state electric restructuring legislation and settlement agreements approved by the FERC and state regulators, both NEES and EUA have divested nearly all of their generation assets and power purchase contracts, and, therefore, neither NEES nor EUA has operational control over any generation resources or the ability to increase generation prices. Because transmission is provided under FERC regulated open-access tariffs, the Transaction will not create any limitations on access to NEES or EUA transmission facilities. In addition, no vertical issues are presented because - -------- 10 See, e.g., Conectiv, Inc., Holding Co. Act Release No. 26832 (Feb. 25, 1998) ("Conectiv"). both NEES and EUA provide retail access to power suppliers under open delivery tariffs. The benefits accompanying the Transaction are outlined below in Item III.B.2 and are benefits which the Commission has in other transactions weighed against any concerns about concentration of control. See American Electric Power Co., 46 S.E.C. Docket 1299 (1978). For all of these reasons, Applicants believe that the Transaction will not result in a concentration of control which will be detrimental to the public interest, but instead will offer the potential to facilitate an actual increase in competition in regional electricity markets. 2. Section 10(b)(2) Pursuant to Section 10(b)(2) of the Act, the Commission will approve the Transaction unless it finds that "the consideration, including all fees, commissions and other remuneration, ... is not reasonable or does not bear a fair relation to the sums invested in or the earning capacity of the utility assets to be acquired or the utility assets underlying the securities to be acquired." a. Fairness of Consideration When determining whether consideration for an acquisition meets the fair and reasonable test of Section 10(b)(2), the Commission considers various factors. The Commission has considered: (i) the market price at which securities have traded; (ii) whether the purchase price was decided as the result of arm's-length negotiations; and (iii) whether each party's board of directors has approved the purchase price. Finally, the Commission considers the opinions of investment bankers, and the earnings, dividends and book and market value of the shares of the company to be acquired. See American National Gas Co., 43 S.E.C. 203 (1966), Consolidated Natural Gas Co., Holding Co. Act Release No. 25040 (Feb. 14, 1990). Under the standards applied by the Commission in previous utility mergers, the consideration to be paid by NEES in the Transaction is reasonable and bears a fair relation to the earnings capacity of the utility assets underlying the EUA Common Shares to be acquired, in compliance with Section 10(b)(2). Each of the EUA Common Shares will be converted into the right to receive $31.00 per share in cash, plus the possible application of an upward adjustment factor more fully discussed in the Merger Agreement. As shown in the table below, the quarterly data, high and low, for EUA Common Shares provide support for the consideration for each EUA Common Share.
Dividends Paid Per EUA High Low Common Share 1996 First Quarter 24 1/4 20 5/8 $ 0.400 Second Quarter 21 7/8 18 1/2 0.415 Third Quarter 191/2 14 3/4 0.415 Fourth Quarter 171/2 16 0.415 1997 First Quarter 19 5/8 17 1/4 $ 0.415 Second Quarter 181/2 16 3/8 0.415 Third Quarter 19 15/16 18 7/16 0.415 Fourth Quarter 26 5/8 20 1/8 0.415 1998 First Quarter 27 11/16 23 11/16 $ 0.415 Second Quarter 27 3/8 24 7/16 0.415 Third Quarter 26 15/16 24 5/16 0.415 Fourth Quarter 28 1/4 24 5/8 0.415
The $31.00 purchase price represents a 5 percent premium above EUA's closing share price of $29.56 on January 29, 1999, the last trading day before the Transaction was announced. The purchase price also represents a 23 percent premium above the price of EUA's closing share price on December 4, 1998, the last trading day before other regional merger announcements affected EUA's share price. Furthermore, Applicants' belief that the consideration is fair and reasonable is based on the following additional considerations: o The consideration is the product of extensive and vigorous arm's length negotiations between NEES and EUA conducted in a competitive context (see discussion of negotiations in Exhibit K-1); o The Merger has been approved by (i) the NEES Board of Directors, the EUA Board, and the Members of LLC and (ii) 97 percent of the EUA shareholders casting votes regarding the Merger. o Internationally-recognized financial advisers for both NEES and EUA have reviewed extensive information concerning the companies and analyzed a variety of valuation methodologies. An opinion from NEES' financial adviser, Merrill Lynch & Co. (see Exhibit F-1), states that the consideration to be paid by NEES with respect to the Merger is fair, from a financial point of view, to NEES. An opinion from EUA's financial adviser, Salomon Smith Barney (see Exhibit F-2), states that the consideration to be received by EUA's shareholders with respect to the Merger is fair, from a financial point of view, to EUA's shareholders; o The inclusion of required closing conditions in the Merger Agreement serves to assure that the Merger will be consummated on terms that are fair to Applicants and their shareholders. b. Fairness of Fees The various categories of fees, commissions and expenses in connection with the transaction and regulatory processing costs for the Transaction are set forth in Item II of this Application/Declaration. Applicants will file by amendment the total amount of transaction and regulatory processing costs they together expect to incur, and also will file by amendment the amount of financial advisory fees they expect to incur. Applicants believe that the estimated fees and expenses they will incur will bear fair relation to EUA's value and the Transaction savings, and will be fair and reasonable. See Northeast Utilities, Holding Co. Act Release No. 25548 (June 3, 1992), modified on other grounds, Holding Co. Act Release No. 25550 (June 4, 1992) ("Northeast II") (Commission considers whether fees and expenses bear a fair relation to the value of the company to be acquired and the savings to be achieved by the acquisition). As discussed below at Item III.B.2, the expected savings that will be achieved by the Transaction substantially will outweigh the estimated fees. Furthermore, the estimated overall fees will be reasonable as compared to the fees approved by the Commission in other merger transactions. For all of the above reasons, the consideration and fees to be paid will be fair and reasonable in compliance with Section 10(b)(2). 3. Section 10(b)(3) Section 10(b)(3) of the Act requires that the Commission approve an acquisition unless "such acquisition will unduly complicate the capital structure of the holding-company system ... or will be detrimental to the public interest or the interest of investors or consumers or the proper functioning of such holding-company system." a. Capital Structure Acquisitions do not unduly complicate the capital structure of the holding company system where the purchaser's capital structure negligibly is affected and the debt-to-equity ratio of the merged holding company following the acquisition falls within the seventy-to-thirty percent of debt-to-common equity generally prescribed by the Commission. Entergy, supra (citing Northeast I); Georgia Power Company, 45 S.E.C. 610, 615 (1974). Furthermore, the Commission has approved common equity to total capitalization ratios as low as 27.6 percent. See Northeast I, supra. The proposed combination of NEES and EUA will not unduly complicate the capital structure of the merged company. NEES will finance the Transaction with cash and funds received from capital contributions from, or issuance of equity to, NGG, in the event the NEES/NGG Merger is consummated prior to the Transaction, or cash received from the issuance of up to $650.0 million of debt in the event the Transaction is consummated prior to the NEES/NGG Merger. The historical capital structures of NEES and EUA, as well as of NGG, as of March 31, 1999 are set forth below: NEES, EUA and NGG Historical Capital Structures (In Millions)
NEES EUA NGG (c) $ % $ % (pound) $ % Long-term Debt (a) $1,089.1 40.0% $330.3 44.9% (pound)2,029.9 $3,247.8 53.8% Preferred 19.5 0.7% 35.0 4.7% 0.0 0.0 0.0% Common Equity 1,616.2 59.3% 371.1 50.4% 1,744.0 2,790.4 46.2% ------- ----- ----- ----- ------- ------- ----- Total Capitalization (b) $2,724.8 100.0% $736.4 100.0% (pound)3,773.9 $6,038.2 100.0% ======== ====== ====== ====== ======== ======== ======
The pro forma consolidated capital structures of (i) NEES and EUA and (ii) NEES, EUA and NGG following the two acquisitions as of March 31, 1999 would have been as follows:
NEES/EUA Pro Forma Consolidated Capital Structure (in Millions) $ % Long-term Debt (a) 1419.42 41.0% Preferred 54.5 1.6% Common Equity 1,987.3 57.4% ------- ----- Total Capitalization (b) 3,461.2 100.0% ======= ======
NGG/NEES/EUA Pro Forma Consolidated Capital Structure (in Millions) $ % Long-term Debt (a) 4,667.2 49.1% Preferred and preference equity 54.5 0.6% Common Equity 4,777.7 50.3% ------- ----- Total Capitalization (b) 9,499.4 100.0% ======= ======
(a) NEES: Long-term debt includes long-term debt of $1,046.8 million and long-term debt due within one year of $42.3 million for a total of $1,089.1 million. EUA: Long-term debt includes long-term debt of $308.4 million and long-term debt due within one year of $21.9 million for a total of $330.3 million. NGG: Long-term debt includes long-term debt of (pound)1,637.3 million ($2,619.7 million) and long-term debt due within one year of (pound)392.6 million ($628.2 million) for a total of (pound)2,029.9 million ($3,247.8 million). (b) NEES: Capitalization includes capitalization per B.S. of $2,682.5 million and long-term debt due within one year of $42.3 million for a total of $2,724.8 million. EUA: Capitalization includes capitalization per B.S. of $714.5 million and long-term debt due within one year of $21.9 million for a total of $736.4 million. (c) Exchange rate of (pound)/$1.60. As the above tables reveal, NEES' debt-to-equity ratio is not affected by any material degree by the Transaction. The merged company's common equity to total capitalization ratio significantly exceeds the Commission's traditionally acceptable 30 to 35 percent level. Since EUA will cease to exist shortly after consummation of the Transaction and EUA's assets and operations will be merged into those of NEES, there is no issue regarding minority ownership of common shares. b. Public Interest, Interest of Investors and Consumers, and Proper Functioning of Holding Company System Section 10(b)(3) also requires the Commission to determine whether the proposed Transaction will be detrimental to the interests of the general public, investors or consumers, or the proper functioning of the combined system. As set forth more fully below, the Transaction is expected to result in substantial cost savings and synergies, and will integrate and improve the efficiency of the combined utility systems. The Transaction, therefore, will be in the public interest and the interests of investors and consumers, and will not be detrimental to the proper functioning of the resulting holding company system. B. Section 10(c) Section 10(c) of the Act establishes additional standards for approval of the Transaction. Under Section 10(c), "the Commission shall not approve: (1) an acquisition of securities or utility assets, or of any other interest, which is unlawful under the provisions of Section 8 or is detrimental to the carrying out of the provisions of Section 11; or (2) the acquisition of securities or utility assets of a public-utility or holding company unless the Commission finds that such acquisition will serve the public interest by tending towards the economical and efficient development of an integrated public utility system." 1. Section 10(c)(1) Section 10(c)(1) requires that an acquisition be lawful under the provisions of Section 8 of the Act. Section 8 prohibits an acquisition by a registered holding company of an interest in an electric and gas utility serving substantially the same area without the express approval of the state commission when that state's law prohibits or requires approval of the acquisition. As neither NEES nor EUA owns any interest in a gas utility, the provisions of Section 8 are not applicable to the Transaction. Section 10(c)(1) also requires that the Transaction not be detrimental to the carrying out of the provisions of Section 11, specifically those prohibiting unduly complex corporate structures and mandating integrated public utility systems. The following analysis demonstrates that the Transaction fully meets the standards of Section 11. a. Section 11(a) and Section 11(b)(2) Section 11(a) requires the Commission to examine the corporate structure of registered holding companies to ensure that unnecessary complexities are eliminated and voting powers are fairly and equitably distributed. Similarly, Section 11(b)(2) of the Act requires that the Commission "ensure that the corporate structure or continued existence of any company in the holding-company system does not unduly or unnecessarily complicate the structure, or unfairly or inequitably distribute voting power among security holders, of such holding-company system." The Transaction fulfills the standard imposed by Section 11(b)(2). The resulting capital structure will not be unduly complicated, as discussed above. See, e.g., Sierra Pacific Resources, Holding Co. Act Release No. 24566 (Jan. 28, 1988), aff'd, Environmental Action, Inc., 895 F.2d 1255 (D.C. Cir. 1990) (Commission incorporates its Section 10(b)(3) capital structure analysis into its Section 11(b)(2) corporate structure analysis). b. Section 11(b)(1) (single integrated public utility system) An integrated public utility system, as applied to electric utility companies, is defined in Section 2(a)(29)(A) of the Act as: "a system consisting of one or more units of generating plants and/or transmission lines and/or distributing facilities, whose utility assets, whether owned by one or more electric utility companies, are physically interconnected or capable of physical interconnection and which under normal conditions may be economically operated as a single interconnected and coordinated system confined in its operations to a single area or region, in one or more States, not so large as to impair (considering the state of the art and the area or region affected) the advantages of localized management, efficient operation, and the effectiveness of regulation;" Pursuant to the above definition, the Commission has established four criteria that must be satisfied before the Commission finds that an integrated electric public utility system will result from a proposed merger of two separate systems: (i) the utility assets of the systems are physically interconnected or capable of physical interconnection; (ii) the utility assets, under normal conditions, must be economically operated as a single interconnected and coordinated system; (iii) the system must be confined in its operations to a single area or region; and (iv) the system must not be so large as to impair (considering the state of the art and the area or region affected) the advantages of localized management, efficient operation, and the effectiveness of regulation. See, e.g., Environmental Action, Inc. v. SEC, supra (citing In re Electric Energy Inc., 38 S.E.C. 658, 668 (1958)). As demonstrated below, the Transaction meets each of these standards. i. Interconnection The NEES and EUA systems are adjacent to each other and their transmission lines are directly physically interconnected; power is exchanged presently between EUA and NEES. See Exhibit E-4. In addition, NEES and EUA are interconnected via the NEPOOL transmission network, which is administered by an ISO that assures open-access transmission services for the New England marketplace at a uniform flat rate. The Commission has recognized that power pools and ISOs can provide a mechanism for satisfying the physical interconnection requirement of the Act. See, e.g., Conectiv; Unitil Corp., Holding Co. Act Release No. 25524 (Apr. 24, 1992). ii. Single Interconnected and Coordinated System The merged company will operate as a single interconnected and coordinated system, pursuant to the requirements of Section 2(a)(29)(A). The Commission has "interpreted this language to refer to the physical operation of utility assets as a system in which, among other things, the generation and/or flow of current within the system may be centrally controlled and allocated as need or economy directs." Conectiv, supra (citing North American Co., 11 S.E.C. 194, 242 (1942), aff'd, SEC v. North American Co., 133 F.2d 148 (2d Cir. 1943), aff'd on constitutional issues, 327 U.S. 686 (1946)). In enacting this standard, Congress "intended that the utility properties be so connected and operated that there is coordination among all parts, and that those parts bear an integral operating relationship to one another." Id. (citing Cities Services Co., 14 S.E.C. 28, 55 (1943)). NEES' and EUA's utility operations will be consolidated fully into existing NEES utility subsidiaries, which will continue to operate on a fully integrated basis. In addition, NEES' operations will be coordinated via NEPOOL and the new ISO-managed bulk power system, which will administer a market-driven dispatch framework that matches loads with resources bid into the system by generators and suppliers. The NEES system will continue to be coordinated in a variety of other ways, e.g. by way of centralized accounting and financial systems, information system networks, strategic planning, etc. The Commission, in applying the integration standard, looks beyond simply the coordination of day-to-day utility operations to a broader range of corporate functions and activities. See, e.g., General Public Utilities Corp., Holding Co. Act Release No. 13116 (Mar. 2, 1956) (integration is accomplished through power dispatching by a central load dispatcher as well as through coordination of maintenance and construction requirements); Middle South Utilities, Holding Co. Act Release No. 11782 (March 20, 1953), petition to reopen denied, Holding Co. Act Release No. 12978 (Sept. 13, 1955), rev'd sub nom. Louisiana Public Service Comm'n v. SEC, 235 F.2d 167 (5th Cir. 1956), rev'd, 353 U.S. 368 (1957), reh'g denied, 354 U.S. 928 (1957) (integration is accomplished through an operating committee which coordinates not only the scheduling of generation and system dispatch, but also makes and keeps records and necessary reports, coordinates construction programs and provides for all other interrelated operations involved in the coordination of generation and transmission); The North American Co., Holding Co. Act Release No. 10320 (Dec. 28, 1950) (economic integration is demonstrated by the exchange of power, the coordination of future power demand, the sharing of extensive experience with regard to engineering and other operating problems, and the furnishing of financial aid to the company being acquired). As required under Section 2(a)(29)(A), the coordinated system must be "economically operated." Thus, the Commission analyzes whether the coordinated system achieves economies and efficiencies. See, e.g., City of New Orleans v. SEC, 969 F.2d 1163, 1168 (D.C. Cir. 1992) (the term "economically" means "that facilities, in addition to their physical interconnection, be consolidated so as to take advantage of efficiencies"). Applicants expect to realize significant economies and efficiencies as a result of the Transaction. As described in Item III.B.2 below, Applicants estimate the present value of the net savings from the Transaction, after reflecting recovery rates of the acquisition premium and transaction costs, to be approximately $356.0 million following the Transaction. iii. Single Area or Region The merged company's operations will be confined to a "single area or region in one or more States." Following the Transaction, NEES will continue to operate in the same New England states in which it currently conducts public utility operations. iv. Localized Management, Efficient Operation and Effective Regulation Section 2(a)(29)(A) also provides for the Commission's consideration of the size of the combined system, requiring that the combined system not be so large as to impair the advantages of localized management, efficient operation, and the effectiveness of regulation. Following the Transaction, NEES and its subsidiaries will maintain their current management and local operating headquarters. EUA's utility assets and operations will be combined fully into NEES' existing utility subsidiaries. This structure will preserve all the benefits of localized management which NEES and its subsidiaries currently enjoy, while promoting maximum efficiencies and economies. The Transaction will not impair the effectiveness of state regulation. Following the Transaction, NEES and its subsidiaries will continue to be regulated by the same state commissions which currently regulate them, including those of Massachusetts and Rhode Island, which now regulate EUA's utility activities. The Transaction is subject to the approval of the VPSB, the CDPUC, the RIDIV and possibly the NHPUC. In addition, Applicants are seeking rate plan approval from the MDTE and the RIPUC. c. Section 11(b)(1) (Acquisition of Non-Utility Interests) Section 11(b)(1) of the Act also requires that a registered holding company limit its operations to a single integrated public utility system and "such other businesses as are reasonably incidental, or economically necessary or appropriate to the operations of such integrated public-utility system." Each of EUA's non-utility business interests conforms to the "other business" standards of the Act as previously determined by the Commission. The indirect acquisition by NEES of EUA's non-utility businesses in no way affects the functional relationship of those businesses to NEES' core electric business following the Transaction. See Item I.B.3(b) above for a detailed description of EUA's non-utility businesses. Based on the foregoing, the Transaction is not detrimental to the carrying out of the provisions of Section 11. 2. Section 10(c)(2) Section 10(c)(2) requires that the Commission approve a transaction that serves the public interest through economical and efficient development of an integrated public utility system. As described above, the NEES System will be fully integrated following the Transaction. Further, the Transaction will promote the economic and efficient development of the NEES utility system. Economic efficiency is the driving force behind the Transaction; its purpose is to create an entity well situated to compete effectively in an increasingly active market. The Transaction will allow NEES to realize the "opportunities for economies of scale, the elimination of duplicate facilities and activities, the sharing of production capacity and reserves and generally more efficient operations" described by the Commission in American Electric Power, supra. Applicants expect to achieve at least $356.0 million in present value net savings (after amortization of the EUA acquisition premium and transaction costs) following consummation of the Transaction. (See, e.g., Testimony of Michael E. Jesanis, The Narragansett Electric Company, Blackstone Valley Electric Company, and Newport Electric Corporation: Rate Plan Filing in Support of Merger, Vol. 1, Rhode Island Public Utilities Commission (May, 1999)). The merger of NEES and EUA will result in cost savings in a number of areas. Approximately 70 percent of the projected savings will arise from personnel reductions in administrative areas such as accounting and finance. In addition, NEES and EUA customer service operations will be integrated to handle increased volumes with greater efficiency. Other operating savings will result from the disposition of duplicate facilities, realization of greater purchasing power, and elimination of redundant administrative costs such as corporate governance expense. NEES' and EUA's utility customers will receive substantial benefits from the Transaction and its resulting cost savings. NEES has filed rate consolidation plans with the MDTE and the RIPUC that extend an agreed-upon distribution rate freeze from December 31, 2000 to December 31, 2002. On the later of April 1, 2000 or 120 days after the Merger is completed, the rates of Blackstone and Newport will be partially consolidated with Narragansett's lower rates, thereby saving Blackstone and Newport customers $2.1 million and $3.4 million annually. In addition, all of Eastern Edison's customers will be moved to Mass. Electric's lower rates on January 1, 2001. The movement to Mass. Electric's rates will save Eastern Edison's customers approximately $23.0 million in the first year of rate consolidation. NEES also has proposed a further two year freeze in distribution rates related to the NEES/NGG Merger through December 31, 2004 (contingent upon consummation of the NEES/NGG Merger). The rate plans will save Rhode Island and Massachusetts customers $79.0 million and $105.0 million, respectively, over a four year period. Because EUA has no retail operations in New Hampshire, no rate plan for New Hampshire customers has been proposed. As the Commission has observed with reference to Section 10(c)(2), "specific dollar forecasts of future savings are not necessarily required; a demonstrated potential for economies will suffice even when these are not precisely quantifiable." Centerior Energy Corp., Holding Co. Act Release No. 24073 (Apr. 29, 1986). In this regard, the Transaction will result in additional benefits which, although not precisely quantifiable, are nonetheless significant. For example, the merged company will be better situated to provide more reliable electric service than is possible for NEES and EUA on a stand-alone basis. It also will be better equipped and positioned to provide the transmission and distribution infrastructure that is essential to the creation of a robust power supply competitive market in restructured wholesale and retail electric markets. C. Section 10(f) Section 10(f) provides that: "The Commission shall not approve any acquisition as to which an application is made under this section unless it appears to the satisfaction of the Commission that such State laws as may apply in respect of such acquisition have been complied with, except where the Commission finds that compliance with such State laws would be detrimental to the carrying out of the provisions of section 11." As described above, and as evidenced by the various applications seeking authorization of the Transaction and rate plan approvals and orders approving such, NEES and EUA will comply with all applicable state laws related to the Transaction. D. Service Agreement As described in Item I.B.3(a) above, Service Company is a service company that, pursuant to service agreements with each of the subsidiary companies of NEES, provides various technical, engineering, accounting, administrative, financial, purchasing, computing, managerial, operational, and legal services to each of the NEES subsidiary companies. Pursuant to the service agreements, these services are provided at cost. The Commission previously has determined that Service Company is so organized and its business is so conducted as to meet the requirements of Section 13(b) of the Act and Rule 88 thereunder. New England Power Service Co., 1 SEC 615 (1936), continued by, 10 SEC 562 (1941), modified by, Holding Co. Act Release No. 14128 (Dec. 30, 1959). Similarly, EUA Service is a service company which, pursuant to service agreements signed with each of the subsidiary companies of EUA, provides various technical, engineering, accounting, administrative, financial, purchasing, computing, managerial, and operational services to each of the EUA subsidiary companies. Pursuant to the service agreements, these services are provided at cost. The Commission also previously has determined that EUA Service is so organized and its business is so conducted as to meet the requirements of Section 13(b) of the Act and Rule 88 thereunder. Eastern Utilities Associates, Holding Co. Act Release No. 17029 (Mar. 5, 1971). Upon consummation of the Transaction, EUA Service will be merged with Service Company, and Service Company will be the surviving service company for the NEES system. E. Organization of LLC; Acquisition of Merger LLC Interests LLC was organized solely for the purpose of effecting the Transaction and has not conducted any activities other than in connection with the Transaction. LLC has no subsidiaries. Each membership certificate of LLC to be issued to LLC and outstanding immediately before the consummation of the Merger will be converted into one share of the surviving entity upon consummation of the Transaction. Thus, the sole purpose for LLC is to serve as an acquisition subsidiary of NEES for purposes of effecting the Transaction. Approval of this Application/Declaration will constitute approval of the acquisition by NEES of the membership certificates of LLC. F. Financing and Other Commission Authorizations 1. Payment of Dividends Out of Capital or Unearned Surplus. As a result of the application of the purchase method of accounting to the Transaction, the current retained earnings of EUA and its subsidiary companies (the "EUA Subsidiary Companies") will be recharacterized as additional paid-in-capital. In addition, the Transaction will give rise to a substantial level of goodwill, the difference between the aggregate fair values of all identifiable tangible and intangible (non-goodwill) assets on the one hand, and the total consideration to be paid for EUA and the fair value of the liabilities assumed, on the other. In accordance with the Commission's Staff Accounting Bulletin No. 54, Topic 5J ("Staff Accounting Bulletin"), the goodwill will be "pushed down" to the EUA Subsidiary Companies and reflected as additional paid-in-capital in their financial statements. The effect of these accounting conventions would be to leave the EUA Subsidiary Companies with no retained earnings, the traditional source of dividend payment, but, nevertheless, strong balance sheets showing significant equity levels. Applicants request authorization to pay dividends out of the additional paid-in-capital account up to the amount of the EUA Subsidiary Companies' aggregate retained earnings just prior to the Transaction and out of earnings before the amortization of the goodwill thereafter. As indicated in the Staff Accounting Bulletin, registrants that have substantially all (generally defined as in excess of 95 percent) of their common stock acquired by a third party, in a business combination accounted for under the purchase method, should reflect the push-down of goodwill in the registrant's post-acquisition financial statements. For any post-acquisition reporting of the consolidated NEES financial statements, push down accounting will be reflected in those statements and the full amount of goodwill associated with the EUA acquisition will be reflected. Push down accounting also will be applied to the EUA Subsidiary Companies. NEES currently intends to amortize the goodwill resulting from the acquisition of EUA over a 20-year period. Generally accepted accounting principles ("GAAP") at present allow a goodwill life of up to 40 years. The Commission, however, has been challenging registrants that adopt the maximum period. Additionally, the FASB draft proposal relating to accounting for business combinations would limit the maximum goodwill life to 20 years. Applicants, therefore currently intend to adopt a 20-year goodwill amortization period. The application of "push down" accounting represents the termination of the old accounting entity and the creation of a new one. For FERC and state commission reporting purposes, goodwill will be recorded in the "Acquisition adjustments" account. The original historical basis of the plant accounts will not be disturbed. As a result of the push down of the goodwill, the common equity balances of EUA and the EUA Subsidiary Companies effectively are reset as if they were new companies, because a new basis of accounting has been pushed down to the entities. As a result, retained earnings are eliminated. Immediately following this accounting treatment, the only components with a recorded value would be: o Common shares - which would continue to reflect the par value of the common shares issued. o Additional paid in capital - which would reflect a value consistent with total common stockholders equity minus the par value recorded in the common stock line. In other words, the resulting common stockholders' equity will equal the total consideration paid for the entity. Based on 1998 financial information, the application of these accounting principles to the NEES/EUA merger will result in following adjustments to EUA's accounts:
$'000 1998 Adjustments 1 Adjustments 2 Restated Common Shares $102,180 -- -- $102,180 Paid in capital $218,959 $52,535 $259,842 $531,336 Retained earnings $56,466 ($56,466) -- 0 Common Share ($3,931) $3,931 -- 0 Expense Total equity $373,674 $0 $259,842 $633,516
Adjustments 1 - capital accounts are restated as Paid in Capital. Adjustments 2 - goodwill is added to Paid in Capital. The push down of the goodwill also has an impact on the net income of EUA. Since the goodwill will be amortized over 20 years, EUA's net income will be reduced by the amount of the amortization. The premium to be paid to acquire EUA will result in goodwill and the elimination of EUA's retained earnings. EUA's consolidation with NEES will further increase NEES' additional paid in capital account. The amortization of the EUA goodwill also will reduce net income. The required accounting adjustments put EUA in the anomalous position of having greater stockholders' equity following the Transaction, but projected net income below EUA's current dividend payment levels and no retained earnings from which to pay dividends. As discussed further below, these merger-related accounting adjustments do not affect the cash flow associated with the utility subsidiaries. Section 12 of the 1935 Act, and Rule 46 thereunder, generally prohibit the payment of dividends out of "capital or unearned surplus" except pursuant to an order of the Commission. The legislative history explains that this provision was intended to "prevent the milking of operating companies in the interest of the controlling holding company groups." S. Rep. No. 621, 74th Cong., 1st Sess. 34 (1935).11 In determining whether to permit a registered holding company to pay dividends out of capital surplus, the Commission considers various factors, including: (i) the asset value of the company in relation to its capitalization, (ii) the company's prior earnings, (iii) the company's current earnings in - -------- 11 Compare Section 305(a) of the Federal Power Act. relation to the proposed dividend, and (iv) the company's projected cash position after payment of a dividend. See Eastern Utilities Associates, Holding Co. Act Release No. 25330 (June 13, 1991), and cases cited therein. Further, the payment of the dividend must be "appropriate in the public interest." Id., citing Commonwealth & Southern Corporation, 13 S.E.C. 489, 492 (1943). NEES and its subsidiaries request authority to pay dividends out of additional paid-in-capital up to the amount of EUA's consolidated retained earnings and EUA's subsidiaries' retained earnings, just prior to the Transaction and out of earnings before the amortization of goodwill thereafter. In no case would dividends be paid if it would result in the consolidated equity of NEES dropping below 30 percent on a consolidated basis. This restriction is intended to protect both investors and consumers. In support of their request, Applicants assert that each of the standards of Section 12(c) of the 1935 Act enunciated in Eastern Utilities Associates are satisfied: (i) After the Transaction, and giving effect to the pushdown of goodwill, NEES' equity as a percentage of total capitalization will be 60.4% percent, substantially in excess of the traditional levels of equity capitalization that the Commission has authorized for other registered holding company systems. Applicants' commitment to maintain the capitalization of NEES at or above 30 percent equity on a consolidated basis should result in a capital structure consistent with industry norms. (ii) NEES has a favorable history of prior earnings and it has a long record of consistent dividend payments.12 - -------- 12 In recent years, NEES' net income and dividends have been: Year Net Income ($ millions) Dividends Paid ($ millions) 1994 199 149 1995 205 152 1996 209 153 1997 220 152 1998 190 146 (iii) Applicants anticipate that NEES' cash flow after the Transaction will not differ significantly from its pre-Transaction cash flow and that earnings before the amortization of goodwill ("Gross Earnings"), therefore, should remain stable post-Transaction. Applicants intend that dividends paid out of future earnings will continue to reflect a dividend payout ratio of between 60 percent and 100 percent of Gross Earnings, based on a rolling 5-year average. (iv) The projected cash position of NEES and its utility subsidiaries after the Transaction will be adequate to meet the obligations of each company. As of March 31, 1999, NEES had cash balances of $62.9 million and marketable securities of $93.9 million on a consolidated basis. The amortization of goodwill is a non-cash expense that will not affect the cash flow of NEES or its subsidiaries. Each of NEES and its subsidiary companies is forecast to have sufficient cash to pay dividends in the amounts contemplated. (v) The proposed dividend payments are in the public interest. NEES and its subsidiary companies are in sound financial condition as indicated by their credit ratings. NEES' commercial paper is rated A-1 by Standard & Poor's ("S&P") and Prime-1 by Moody's Investor Service ("Moody's"). The long-term debt of Mass. Electric, Narragansett, and NEP is rated AA-, A1; AA-, A1; and A+, A1 by S&P and Moody's, respectively. Indeed, S&P has placed the credit ratings of NEES, Mass. Electric, Narragansett, and NEP on "creditwatch with positive implications."13 The expectations of continued strong credit ratings by NEES' utility subsidiaries should allow them to continue to access the capital markets to finance their operations and growth. In addition, the dividend payments are consistent with investor interests because they allow the capital structure of NEES and its subsidiaries to be adjusted to more appropriate levels of debt and equity. 2. Financing Arrangements By this Application/Declaration, NEES seeks Commission authorization to enter into financing arrangements pursuant to which NEES may borrow up to $650.0 million in the event the Transaction is consummated prior to the NEES/NGG Merger. NEES also seeks authority to issue commercial paper or otherwise to engage in short-term borrowing up to $650.0 million. The maximum aggregate - -------- 13 S&P's Credit Wire (Dec. 14, 1998). amount of debt outstanding hereunder, whether commercial paper or bank debt would not exceed $650.0 million at any one time. NEES requests that the authority requested herein be granted through December 31, 2005.14 a. Borrowings from Banks - Credit Agreement NEES proposes to enter into a Credit Agreement. A draft of the Credit Agreement, Exhibit B-3 to this filing, will be filed by amendment. The Credit Agreement will provide for a revolving facility of up to $650.0 million. The term would not be in excess of five years. NEES will propose having interest rate options to permit LIBOR borrowings, Base Rate borrowings, and Competitive Bid borrowings. The Credit Agreement also will include provisions for various fees which may include a facility fee, an arrangement and syndication fee, and an annual administration fee. The Credit Agreement will be unsecured. NEES intends to have the option of reducing the commitments under the Credit Agreement, or making prepayments at any time without penalty. b. Cost of Funds Pricing for the Credit Agreement has not yet been negotiated. Final pricing will be supplied by amendment. c. Borrowings from Banks - Short-term NEES also may make arrangements with certain banks for short-term lines of credit, for various purposes, including support of commercial paper. The proposed borrowings will be evidenced by notes payable, maturing in less than one year from the date of issuance. NEES will negotiate with the banks the interest costs of such borrowings, and will pay fees to the banks in lieu of compensating balance arrangements. The effective interest cost of borrowings, on a daily basis, from a bank will not exceed the greater of the bank's base or prime lending rate, or the rate published daily in the Wall Street Journal as the high federal funds rate, plus, in either case, one percent. Certain of such borrowings may be without prepayment privileges. Based on the current base lending rate of 8 percent and an equivalent or lower high federal funds rate, the effective interest costs of such borrowing would not exceed 12 percent per annum. - ---------- 14 This request is in addition to NEES' existing authority, through December 31, 2002, to issue short-term notes to banks and/or commercial paper to dealers up to an aggregate amount of $500.0 million outstanding at any one time. Payment of any short-term promissory notes prior to maturity will be made on the basis most favorable to NEES, taking into account fixed maturities, interest rates, and any other relevant financial consideration. d. Sale of Commercial Paper to Dealers NEES also proposes to issue and sell commercial paper directly to one or more nationally recognized commercial paper dealers ("CP Dealer"). Initially the CP Dealer will be CS First Boston Corporation and/or Merrill Lynch Money Markets Incorporated, but this may change as warranted. The commercial paper so issued and sold will satisfy the requirements of Section 3(a)(3) of the Securities Act of 1933 and be in the form of unsecured promissory notes having varying maturities of not in excess of 270 days. Actual maturities will be determined by market conditions, the effective interest cost to NEES, and NEES' cash requirements at the time of issuance. The commercial paper will be in denominations of not less than $50,000. The terms of the commercial paper will not provide for prepayment prior to maturity. The commercial paper will be purchased by the CP Dealer from the issuer at a discount which will not be in excess of the discount then prevailing for commercial paper of comparable quality and maturity which is sold to commercial paper dealers. The CP Dealer initially will reoffer the commercial paper at a discount rate not more than 1/8 of one percent per annum less than the prevailing discount rate to NEES. The effective interest cost to NEES of commercial paper generally will not exceed the effective interest cost of the base lending rate at BankBoston (formerly the First National Bank of Boston). However, the effective interest cost of such paper is based on the supply of, and demand for, that and similar paper at the time of sale. Specifically, on several previous occasions, short-term money markets have become very volatile during brief periods of extraordinary demand, and the interest costs of commercial paper have exceeded bank base rates. Because such volatile market conditions usually exist for brief periods, it is not anticipated that any sale of commercial paper with interest costs in excess of bank base rates would have a significant marginal impact on the annual interest cost of NEES. Therefore, while it is not anticipated that the effective annual cost of borrowing through commercial paper will exceed the annual base rate borrowing from BankBoston, in order to obtain maximum flexibility during the periods described above, commercial paper may be issued with a maturity of not more than 90 days with an effective cost in excess of the then-existing lending rate. The decision to borrow from banks or issue commercial paper will be based on the cost of such funds and their availability for the anticipated borrowing period. e. Filing of Certificates of Notification Within 45 days after the end of each calendar quarter, NEES will file a certificate of notification covering the transactions effected pursuant to the authority requested herein during such quarter. Such certificate will show the dates and amounts of all new money borrowings, whether by issuance of notes to banks or by sale of commercial paper, the names of the lenders, the maximum concurrent amount of notes outstanding to banks and CP Dealers, the aggregate total outstanding at any one time, and the aggregate total outstanding at the end of such quarter. Each certificate will include, with respect to the issue and sale of commercial paper, the effective interest cost for such promissory note issued as commercial paper. The final certificate of notification will be accompanied by the required past tense opinion of counsel. 3. Rule 53 Neither NEES nor EUA has an ownership interest in an exempt wholesale generator ("EWG") or a foreign utility company ("FUCO") as defined in Sections 32 and 33 of the Act. Additionally, neither NEES nor EUA is a party to, nor does NEES or EUA have any rights under, a service, sales, or construction agreement with an EWG or a FUCO. NEES shall comply with the requirements of Rule 53 of the Act in connection with any future EWG and FUCO acquisitions and financings. To the extent that any monies from the borrowings hereunder are used to invest in, or otherwise acquire an interest in the business of, any EWGs or FUCOs, NEES will comply with the Commission's orders in File No. 70-8783 (Release No. 35-26504 dated April 15, 1996, as supplemented by Release No. 35-26729 dated June 10, 1997). ITEM IV. REGULATORY APPROVAL In addition to required Commission approvals, the following have jurisdiction over various aspects of the Transaction (and related subsidiary company consolidations): the FERC, the NRC, the FCC, the VPSB, the CDPUC, possibly the NHPUC, the MDTE, and the RIDIV. In addition, Applicants are seeking approval from the MDTE and the RIPUC for a rate plan that allows recovery of the costs of the acquisition and the acquisition premium. In addition, Applicants filed notification and report forms under the HSR Act with the DOJ and the FTC with respect to the Merger. On April 30, 1999, Applicants received clearance for the Merger under the HSR Act. ITEM V. PROCEDURE The Commission is respectfully requested to issue and publish not later than August 20, 1999, the requisite notice under Rule 23 with respect to the filing of this Application/Declaration, such notice to specify a date not later than 25 days, by which comments may be entered and a date not later than October 15, 1999, as the date after which an order of the Commission granting and permitting this Application/Declaration to become effective may be entered by the Commission. It is submitted that a recommended decision by a hearing or other responsible officer of the Commission is not needed for approval of the Transaction. The Division may assist in the preparation of the Commission's decision. There should be no waiting period between the issuance of the Commission's order and the date on which it is to become effective. ITEM VI. EXHIBITS AND FINANCIAL STATEMENTS A. Exhibits A-1 Agreement and Declaration of Trust dated January 2, 1926, as amended through April 28, 1992 (Exhibit 3 to 1994 NEES Form 10-K, File No. 1-3446, and incorporated herein by reference) A-2 Declaration of Trust, dated April 2, 1928, as amended (Exhibit A-3, File No. 70- 3188; Exhibit 1 to 8-K Reports for April in each of the years 1957, 1962, 1966, 1968, 1972 and 1973, File No. 1-5366; Exhibit A-1(a), Amendment No. 2 to Form U-1, File No. 70-5997; Exhibit 4-3, Registration No. 2-72589; Exhibit 1 to Certificate of Notification; File No. 70-6713; Exhibit 1 to Certificate of Notification; File No. 70-7084; Exhibit 3-2, Form 10-K for 1987, File No. 1- 5366, and incorporated herein by reference) A-3 Amended and Restated Certificate of Organization of LLC B-1 NEES/NGG Merger Agreement (Exhibit 10(mm) to NEES Form 8-K, File No. 1-3446, dated December 16, 1998, and incorporated herein by reference) B-2 Term Sheet to Credit Agreement (to be filed by amendment) B-3 Draft Credit Agreement (to be filed by amendment) B-4 Merger Agreement D-1 Application to the FERC, filed on May 5, 1999, as supplemented on July 1, 1999, together with testimony and exhibits (pursuant to Exhibit G, state filings provided separately) D-2 Application to the MDTE, together with testimony and exhibits D-3 Application to the RIPUC, together with testimony and exhibits D-4 Application to the VPSB, together with testimony and exhibits D-5 Application to the CDPUC, together with testimony and exhibits (to be filed by amendment) D-6 Application to the NHPUC, together with testimony and exhibits (to be filed by amendment) D-7 Application to the NRC (to be filed by amendment) E-1 NEES organization chart (to be filed by amendment) E-2 EUA organization chart (to be filed by amendment) E-3 Combined company organization chart after the Transaction (to be filed by amendment) E-4 Map of NEES and EUA service areas and transmission systems (Exhibit I to Exhibit D-1 hereto) F-1 Opinion of Merrill Lynch & Co. (to be filed by amendment) F-2 Opinion of Salomon Smith Barney (to be filed by amendment) F-3 Opinion of Counsel (to be filed by amendment) F-4 Past Tense Opinion of Counsel (to be filed by amendment with Rule 24 certificate G-1 NEES' Annual Report on Form 10-K for the fiscal year ended December 31, 1998 (File No. 1-3446, filed March 31, 1999, and incorporated herein by reference) G-2 NEES' Quarterly Report on Form 10-Q for the quarter ended March 31, 1999 (File No. 1-3446, filed May 17, 1999, and incorporated herein by reference) G-3 EUA's Annual Report on Form 10-K for the fiscal year ended December 31, 1998 (File No. 1-5366, filed March 31, 1999, and incorporated herein by reference) G-4 EUA's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999 (File No. 1-5366, filed May 14, 1999, and incorporated herein by reference) H-1 Proposed Form of Notice K-1 Discussion of negotiations between NEES and EUA B. Financial Statements FS-1 NEES' Consolidated Balance Sheet as of December 31, 1998 (previously filed with the Commission in NEES' Annual Report on Form 10-K for the year ended December 31, 1998 (Exhibit G-1 hereto), filed March 31, 1999, File No. 1-3446, and incorporated herein by reference) FS-2 NEES' Consolidated Statement of Income for the 12 months ended December 31, 1998 (previously filed with the Commission in NEES' Annual Report on Form 10-K for the year ended December 31, 1998 (Exhibit G-1 hereto), filed March 31, 1999, File No. 1-3446, and incorporated herein by reference) FS-3 EUA's Consolidated Balance Sheet as of December 31, 1998 (previously filed with the Commission in NEES' Annual Report on Form 10-K for the year ended December 31, 1998 (Exhibit G-3 hereto), filed March 31, 1999, File No. 1-5366, and incorporated herein by reference) FS-4 EUA's Consolidated Statement of Income for the 12 months ended December 31, 1998 (previously filed with the Commission in NEES' Annual Report on Form 10-K for the year ended December 31, 1998 (Exhibit G-3 hereto), filed March 31, 1999, File No. 1-5366, and incorporated herein by reference) ITEM VII. INFORMATION AS TO ENVIRONMENTAL EFFECTS The Transaction neither involves "major federal actions" nor "significantly [affects] the quality of the human environment" as those terms are used in Section 102(2)(C) of the National Environmental Policy Act, 42 U.S.C. Sec. 4332. The only federal actions related to the Transaction pertain to the required approvals and actions summarized in Item IV, and Commission approval of this Application/Declaration. Consummation of the Transaction will not result in significant changes in the operations of the public utilities involved in the Transaction that would have any impact on the environment. No federal agency is preparing an environmental impact statement with respect to this matter. [REMAINDER OF PAGE INTENTIONALLY LEFT BLANK] SIGNATURE Pursuant to the requirements of the Public Utility Holding Company Act of 1935, the undersigned companies have duly caused this statement to be signed on their behalf by the undersigned thereunto duly authorized. NEW ENGLAND ELECTRIC SYSTEM* By: /s/ Kirk L. Ramsauer ---------------------- Name: Kirk L. Ramsauer Title: Deputy General Counsel * The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer, or agent thereof assumes or shall be held to any liability therefor. EASTERN UTILITIES ASSOCIATES** By: /s/ Donald G. Pardus --------------------- Name: Donald G. Pardus Title: Chairman/CEO ** The name "Eastern Utilities Associates" is the designation of the Trustees of EUA for the time being in their collective capacity but not personally, under a Declaration of Trust dated April 2, 1928, as amended, a copy of which amended Declaration of Trust has been filed in the office of the Secretary of The Commonwealth of Massachusetts and elsewhere as required by law; and all persons dealing with EUA must look solely to the trust property for the enforcement of any claim against EUA, as neither the Trustees nor the officers or shareholders of EUA assume any personal liability for obligations entered into on behalf of EUA. Dated: EX-99 2 EXHIBIT A-3 Exhibit A-3 RESEARCH DRIVE LLC AMENDED AND RESTATED CERTIFICATE OF ORGANIZATION Pursuant to the provisions of the Massachusetts Limited Liability Company Act, M.G.L. c. 156C (the "Act"), the undersigned hereby certifies as follows: 1. Tax Identification Number. The federal employer identification number of the limited liability company (the "LLC") has been applied for. 2. Name of the Limited Liability Company. The name of the LLC is Research Drive LLC. 3. Original Filing Date. The LLC's original Certificate of Organization was filed on January 29, 1999. 4. Office of the LLC. The address of the office of the LLC for purposes of Section 5 of the Act is 25 Research Drive, Westborough, MA 01582. 5. Business of the LLC. The general character of the business of the LLC is to engage in any manufacturing, management, service or other business, operation or activity related to energy generation, transmission or distribution, utilization, conservation or transportation, construction or telecommunications, directly or indirectly through joint ventures, partnership or other entities; to engage in any activities directly or indirectly related or incidental thereto, and to engage in any other activity in which limited liability companies organized under the laws of the Commonwealth of Massachusetts may lawfully engage. 6. Date of Dissolution. The LLC has no specified date of dissolution. 7. Agent for Service of Process. The name and business address of the resident agent for service of process required to be maintained by Section 5 of the Act is CT Corporation System, 2 Oliver Street, Boston, MA 02109. 8. Managers. The following persons are managers of the LLC: Name Address Richard P. Sergel 25 Research Drive, Westborough, MA 01582 John G. Cochrane 25 Research Drive, Westborough, MA 01582 9. Amendments. The LLC's Certificate of Organization is hereby amended by indicating that a federal employer identification number has been applied for, changing the address of the office of the LLC, deleting Louis A. Goodman as an authorized person and adding Richard P. Sergel and John G. Cochrane as Managers. IN WITNESS WHEREOF, the undersigned hereby affirms under the penalties of perjury that the facts stated herein are true, as of February 25, 1999. RESEARCH DRIVE LLC /s/ John G. Cochrane ---------------------------------------- John G. Cochrane, Manager EX-99 3 EXHIBIT B-4 Tab 1 AGREEMENT AND PLAN OF MERGER dated as of February 1, 1999 by and among NEW ENGLAND ELECTRIC SYSTEM, RESEARCH DRIVE LLC and EASTERN UTILITIES ASSOCIATES TABLE OF CONTENTS Page No. ARTICLE I THE MERGER......................................................... 1 1.01 The Merger......................................................... 1 1.02 Effective Time..................................................... 1 1.03 Effects of the Merger.............................................. 2 ARTICLE II CONVERSION OF SHARES............................................... 2 2.01 Conversion of Capital Stock........................................ 2 2.02 Surrender of Shares................................................ 3 2.03 Withholding Rights................................................. 4 ARTICLE III THE CLOSING........................................................ 4 ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EUA.............................. 5 4.01 Organization and Qualification..................................... 5 4.02 Capital Stock...................................................... 6 4.03 Authority.......................................................... 7 4.04 Non-Contravention; Approvals and Consents.......................... 7 4.05 SEC Reports, Financial Statements and Utility Reports.............. 8 4.06 Absence of Certain Changes or Events............................... 9 4.07 Legal Proceedings.................................................. 9 4.08 Information Supplied............................................... 9 4.09 Compliance......................................................... 10 4.10 Taxes.............................................................. 10 4.11 Employee Benefit Plans; ERISA...................................... 12 4.12 Labor Matters...................................................... 14 4.13 Environmental Matters.............................................. 15 4.14 Regulation as a Utility............................................ 17 4.15 Insurance.......................................................... 17 4.16 Nuclear Facilities................................................. 18 4.17 Vote Required...................................................... 18 4.18 Opinion of Financial Advisor....................................... 18 -i- Page No. 4.19 Ownership of NEES Common Shares.................................... 18 4.20 State Anti-Takeover Statutes....................................... 18 4.21 Year 2000.......................................................... 19 4.22 EUA Associates..................................................... 19 ARTICLE V REPRESENTATIONS AND WARRANTIES OF NEES............................. 19 5.01 Organization and Qualification..................................... 19 5.02 Authority.......................................................... 20 5.03 Capital Stock...................................................... 20 5.04 Non-Contravention; Approvals and Consents.......................... 20 5.05 Information Supplied............................................... 21 5.06 Compliance......................................................... 21 5.07 Financing.......................................................... 22 5.08 No Vote Required................................................... 22 5.09 Ownership of EUA Shares............................................ 22 5.10 Merger with The National Grid Group plc............................ 22 ARTICLE VI COVENANTS................................................ 22 6.01 Covenants of EUA................................................... 22 6.02 Covenants of NEES.................................................. 28 6.03 Additional Covenants by NEES and EUA............................... 29 ARTICLE VII ADDITIONAL AGREEMENTS.................................... 30 7.01 Access to Information.............................................. 30 7.02 Proxy Statement.................................................... 31 7.03 Approval of Shareholders........................................... 31 7.04 Regulatory and Other Approvals..................................... 31 7.05 Employee Benefit Plans............................................. 32 7.06 Labor Agreements and Workforce Matters............................. 34 7.07 Post Merger Operations............................................. 34 7.08 No Solicitations................................................... 35 7.09 Directors' and Officers' Indemnification and Insurance............. 36 7.10 Expenses........................................................... 37 7.11 Brokers or Finders................................................. 37 7.12 Anti-Takeover Statutes............................................. 38 7.13 Public Announcements............................................... 38 -ii- Page No. 7.14 Restructuring of the Merger........................................ 38 ARTICLE VIII CONDITIONS......................................................... 39 8.01 Conditions to Each Party's Obligation to Effect the Merger......... 39 8.02 Conditions to Obligation of NEES and LLC to Effect the Merger...... 39 8.03 Conditions to Obligation of EUA to Effect the Merger............... 40 ARTICLE IX TERMINATION, AMENDMENT AND WAIVER.................................. 41 9.01 Termination........................................................ 41 9.02 Effect of Termination.............................................. 43 9.03 Termination Fees................................................... 43 9.04 Amendment.......................................................... 44 9.05 Waiver............................................................. 44 ARTICLE X GENERAL PROVISIONS................................................. 44 10.01 Non-Survival of Representations, Warranties, Covenants and Agreements......................................................... 44 10.02 Notices............................................................ 44 10.03 Entire Agreement; Incorporation of Exhibits........................ 46 10.04 No Third Party Beneficiary......................................... 46 10.05 No Assignment; Binding Effect...................................... 46 10.06 Headings........................................................... 47 10.07 Invalid Provisions................................................. 47 10.08 Governing Law...................................................... 47 10.09 Enforcement of Agreement........................................... 47 10.10 Certain Definitions................................................ 47 10.11 Counterparts....................................................... 48 10.12 WAIVER OF JURY TRIAL............................................... 48 -iii- GLOSSARY OF DEFINED TERMS The following terms, when used in this Agreement, have the meanings ascribed to them in the corresponding Sections of this Agreement listed below: "1935 Act" -- Section 4.05(b) "Adjustment Date" -- Section 2.01(c) "Affected Employees" -- Section 7.05(a) "affiliate" -- Section 10.11(a) "Agreement" -- Preamble "Alternative Proposal" -- Section 7.08 "beneficially" -- Section 10.10(b) "business day" -- Section 10.10(c) "Canceled Shares" -- Section 2.02(b) "Certificates" -- Section 2.02(b) "Closing" -- Article III "Closing Agreement" -- Section 4.10(j) "Closing Date" -- Article III "Code" -- Section 2.03 "Confidentiality Agreement" -- Section 7.01 "Constituent Entities" -- Section 1.01 "Contracts" -- Section 4.04(a) "control," "controlling," "controlled by" and "under common control with" -- Section 10.10(a) "DOE" -- Section 4.05(b) "Effective Time" -- Section 1.02 "Environmental Claim" -- Section 4.13(f)(i) "Environmental Laws" -- Section 4.13(f)(ii) "Environmental Permits" -- Section 4.13(b) "ERISA" -- Section 4.11(a) "ERISA Affiliate" -- Section 4.11(c) "EUA" -- Preamble "EUA Associates" -- Section 4.01(b) "EUA Employee Agreements" -- Section 7.05(d)(ii) "EUA Executives" -- Section 7.05(d)(ii) "EUA Shares" -- Preamble "EUA Disclosure Letter" -- Section 4.01(a) "EUA Employee Benefit Plans" -- Section 4.11(a) "EUA Financial Statements" -- Section 4.05(a) "EUA Nuclear Facilities" -- Section 4.16 "EUA Material Adverse Effect" -- Section 4.01(a) "EUA Required Consents" -- Section 4.04(a) "EUA Required Statutory Approvals" -- Section 4.04(b) "EUA SEC Reports" -- Section 4.05(a) -iv- "EUA Shareholders' Approval" -- Section 7.03 "EUA Shareholders' Meeting" -- Section 7.03 "EUA Significant Subsidiary" -- Section 7.08 "EUA Shares" -- Preamble "EUA Trust Agreement" -- Section 1.03 "EUA Voting Debt -- Section 4.02(d) "Evaluation Material" -- Section 7.01(a) "Exchange Act" -- Section 4.05(a) "Exchange Fund" -- Section 2.02(a) "Extended Termination Date" -- Section 9.01(b) "FCC" -- Section 4.05(b) "FERC" -- Section 4.05(b) "Final Order" -- Section 8.01(d) "Governmental Authority" -- Section 4.04(a) "Hazardous Materials" -- Section 4.13(f)(iii) "HSR Act" -- Section 7.04(a) "Indemnified Liabilities" -- Section 7.09(a) "Indemnified Party" -- Section 7.09(a) "Indemnified Parties" -- Section 7.09(a) "Information Systems" -- Section 4.21 "Initial Termination Date" -- Section 9.01(b) "IRS" -- Section 4.10(m) "knowledge" -- Section 10.11(d) "laws" -- Section 4.04(a) "Lien" -- Section 4.02(b) "LLC" -- Preamble "Massachusetts Secretary" -- Section 1.02 "Merger" -- Preamble "Merger Consideration" -- Section 2.01(b)(ii) "MGL" -- Section 1.01 "National Grid Group" -- Section 5.10 "National Grid Merger Agreement" -- Section 5.10 "NEES" -- Preamble "NEES Disclosure Letter" -- Section 5.03 "NEES Material Adverse Effect" -- Section 5.01 "NEES-EUA Regulatory Approvals" -- Section 7.04(b) "NEES-EUA Regulatory Proceedings" -- Section 7.04(c) "NEES Required Consents" -- Section 5.04(a) "NEES Required Statutory Approvals" -- Section 5.04(b) "NEES-NGG Regulatory Approvals" -- Section 7.04(c) "NEES-NGG Regulatory Proceedings" -- Section 7.04(c) "NEES-NGG Required Statutory Approvals"-- Section 7.04 "NEES-NGG Transactions" -- Section 7.04 "NEES Shares" -- Section 5.03 -v- "NEES Trust Agreement" -- Section 5.01 "NGG Circular" -- Section 7.02 "NRC" -- Section 4.05(b) "Options" -- Section 4.02(a) "orders" -- Section 4.04(a) "Out-of-Pocket Expenses" -- Section 9.03(a) "Paying Agent" -- Section 2.02(a) "PBGC" -- Section 4.11(g) "person" -- Section 10.11(e) "Per Share Amount" -- Section 2.01(b)(ii) "Post Closing Plans" -- Section 7.05(b) "Proxy Statement" -- Section 4.08(a) "Release" -- Section 4.13(f)(iv) "Representatives" -- Section 10.11(f) "SEC" -- Section 4.05(a) "Securities Act" -- Section 4.05(a) "Subsidiary" -- Section 10.11(g) "Surviving Entity" -- Section 1.01 "Tax Ruling" -- Section 4.10(j) "Taxes" -- Section 4.10 "Tax Return" -- Section 4.10 "US GAAP" -- Section 4.05(a) "Yankee Companies" -- Section 4.16 "Y2K Consultant" -- Section 6.01(o) -vi- This AGREEMENT AND PLAN OF MERGER, dated as of February 1, 1999 (this "Agreement"), is made and entered into by and among NEW ENGLAND ELECTRIC SYSTEM, a Massachusetts business trust ("NEES"), RESEARCH DRIVE LLC ("LLC"), a Massachusetts limited liability company which is directly and indirectly wholly owned by NEES, and EASTERN UTILITIES ASSOCIATES, a Massachusetts business trust ("EUA"). WHEREAS, the Board of Directors of NEES, the Board of Trustees of EUA and the members of LLC have each determined that it is advisable and in the best interests of their respective shareholders and members to consummate, and have approved, the business combination transaction provided for herein in which LLC would merge with and into EUA, with EUA being the surviving entity (the "Merger"), pursuant to the terms and conditions of this Agreement, as a result of which NEES will own, directly or indirectly, all of the issued and outstanding common shares of EUA (the "EUA Shares"); WHEREAS, NEES, LLC and EUA desire to make certain representations, warranties and agreements in connection with the Merger and also to prescribe various conditions to the Merger; NOW, THEREFORE, in consideration of the mutual covenants and agreements set forth in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows: ARTICLE I THE MERGER 1.01 The Merger. Upon the terms and subject to the conditions of this Agreement, at the Effective Time (as defined in Section 1.02), LLC shall be merged with and into EUA in accordance with Section 2 of Chapter 182 and Section 59 of Chapter 156C of the Massachusetts General Laws ("MGL"). At the Effective Time, the separate existence of LLC shall cease and EUA shall continue as the surviving entity in the Merger. EUA, after the Effective Time, is sometimes referred to herein as the "Surviving Entity" and EUA and LLC are sometimes referred to herein as the "Constituent Entities". The effect and consequences of the Merger shall be as set forth in Article II. 1.02 Effective Time. Subject to the provisions of this Agreement, on the Closing Date (as defined in Article III), a certificate of merger shall be executed and filed by EUA and LLC with the Secretary of the Commonwealth of Massachusetts (the "Massachusetts Secretary"). The Merger shall become effective at the time of the filing of the certificate of merger relating to the Merger with the Massachusetts Secretary, or at such later time as is specified in the certificate of merger (such date and time being referred to herein as the "Effective Time"). 1.03 Effects of the Merger. At the Effective Time, the Agreement and Declaration of Trust of EUA (the "EUA Trust Agreement") as in effect immediately prior to the Effective Time shall be the agreement and declaration of trust of the Surviving Entity, until thereafter amended as provided by law and such agreement and declaration of trust. Subject to the foregoing, the additional effects of the Merger shall be as provided in the applicable provisions of Section 2 of Chapter 182 of the MGL and Section 62 of the Limited Liability Company Act of Massachusetts. ARTICLE II CONVERSION OF SHARES 2.01 Conversion of Capital Stock. At the Effective Time, by virtue of the Merger and without any action on the part of the holder thereof: (a) Membership Interests of LLC. Each one percent of the issued and outstanding membership interests in LLC shall be converted into one transferable certificate of participation or share of the Surviving Entity. (b) Conversion of EUA Shares. (i) Cancellation of Treasury Shares and Shares Owned by NEES and Subsidiaries. All EUA Shares that are owned by EUA as treasury shares and any EUA Shares owned by NEES or any other wholly owned Subsidiary (as defined in Section 10.11) of NEES shall be canceled and retired and shall cease to exist and no cash or other consideration shall be delivered in exchange therefor. (ii) Conversion of EUA Shares. Each EUA Share issued and outstanding immediately prior to the Effective Time (other than shares to be canceled in accordance with Section 2.01(b)(i)) shall be canceled and converted in accordance with the provisions of this Section 2.01 into the right to receive cash in the amount (the "Per Share Amount") of $31.00 as such amount may hereafter be adjusted in accordance with Section 2.01(c) hereof (the "Merger Consideration"), payable, without interest, to the holder of such EUA Share, upon surrender, in the manner provided in Section 2.02 hereof, of the certificate formerly evidencing such share. (c) Adjustment in Amount of Merger Consideration. In the event that the Closing Date shall not have occurred on or prior to the date that is the six (6) month anniversary of the date on which EUA Shareholders' Approval is obtained (the "Adjustment Date"), the Per Share Amount shall be increased, for each day after the Adjustment Date up to and including the day which is one day prior to the earlier of the Closing Date and the Extended Termination Date, by an amount equal to $0.003. -2- 2.02 Surrender of Shares. (a) Deposit with Paying Agent. Prior to the Effective Time, NEES shall designate a bank or trust company reasonably acceptable to EUA to act as agent (the "Paying Agent") for the benefit of the holders of EUA Shares in connection with the Merger to receive the funds to which holders of EUA Shares shall become entitled pursuant to Section 2.01(b)(ii) (the "Exchange Fund"). From time to time at, immediately prior to or after the Effective Time, NEES or LLC shall make or cause to be made available to the Paying Agent immediately available funds in amounts and at the times necessary for the payment of the Merger Consideration upon surrender of Certificates (as defined in Section 2.02(b)) in accordance with Section 2.02(b), it being understood that any and all interest or other income earned on funds made available to the Paying Agent pursuant to this Section 2.02(a) shall belong to and shall be paid (at the time provided for in Section 2.02(e)) as directed by NEES or LLC. Any such funds deposited with the Paying Agent by NEES shall be invested by the Paying Agent as directed by NEES or LLC. (b) Exchange Procedure. As soon as practicable after the Effective Time, the Paying Agent shall mail to each holder of record of a certificate or certificates (the "Certificates") which immediately prior to the Effective Time represented outstanding EUA Shares (the "Canceled Shares") that were canceled and became instead the right to receive the Merger Consideration pursuant to Section 2.01(b)(ii): (i) a letter of transmittal in such form as NEES and EUA may reasonably agree (which shall specify that delivery shall be effected, and risk of loss and title to the Certificates shall pass, only upon actual delivery of the Certificates to the Paying Agent) and (ii) instructions for effecting the surrender of the Certificates in exchange for the Merger Consideration. Upon surrender of a Certificate or Certificates to the Paying Agent for cancellation (or to such other agent or agents as may be appointed by NEES and are reasonably acceptable to EUA), together with a duly executed letter of transmittal and such other documents as the Paying Agent shall require, the holder of such Certificate shall be entitled to receive the Merger Consideration in exchange for each EUA Share formerly evidenced by such Certificate which such holder has the right to receive pursuant to Section 2.01(b)(ii). In the event of a transfer of ownership of Canceled Shares which is not registered in the transfer records of EUA, the Merger Consideration in respect of such Canceled Shares may be given to the transferee thereof if the Certificate or Certificates representing such Canceled Shares is presented to the Paying Agent, accompanied by all documents required to evidence and effect such transfer and by evidence satisfactory to the Paying Agent that any applicable stock transfer taxes have been paid. At any time after the Effective Time, each Certificate shall be deemed to represent only the right to receive the Merger Consideration subject to and upon the surrender of such Certificate as contemplated by this Section 2.02. No interest shall be paid or will accrue on the Merger Consideration payable to holders of Certificates pursuant to Section 2.01(b)(ii). (c) No Further Ownership Rights in EUA Shares. The Merger Consideration paid upon the surrender of Certificates in accordance with the terms of Section 2.01(b)(ii) shall be deemed to have been paid at the Effective Time in full satisfaction of all rights pertaining to EUA Shares represented thereby. From and after the Effective Time, the share transfer books of EUA shall be closed and there shall be no further registration of transfers thereon of EUA Shares which were outstanding immediately prior to the Effective Time. -3- If, after the Effective Time, Certificates are presented to NEES for any reason, they shall be canceled and exchanged as provided in this Section 2.02. (d) Lost, Stolen or Destroyed Certificates. In the event any owner of any Certificate shall claim that such Certificate shall have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the owner of such Certificate and delivery of that affidavit to the Paying Agent and, if required by NEES or LLC, the posting by such person of a bond in customary amount as indemnity against any claim that may be made against NEES, EUA or the Surviving Entity with respect to such Certificate, the Paying Agent will issue in exchange for such lost, stolen or destroyed Certificate the Merger Consideration payable upon due surrender of, and deliverable pursuant to this Section 2.02 in respect of, EUA Shares to which such Certificate relates. (e) Termination of Exchange Fund. Any portion of the Exchange Fund which remains undistributed to the shareholders of EUA for one (1) year after the Effective Time shall be delivered to the Surviving Entity, upon demand, and any Shareholders of EUA who have not theretofore complied with this Article II shall thereafter look only to the Surviving Entity (subject to abandoned property, escheat and other similar laws) as general creditors for payment of their claim for the Merger Consideration payable upon due surrender of the Certificates held by them. None of NEES, LLC or the Surviving Entity shall be liable to any former holder of EUA Shares for the Merger Consideration delivered to a public official pursuant to any applicable abandoned property, escheat or similar law. 2.03 Withholding Rights. Each of the Surviving Entity and NEES shall be entitled to deduct and withhold from the consideration otherwise payable pursuant to this Agreement to any holder of EUA Shares such amounts as it is required to deduct and withhold with respect to the making of such payment under the Internal Revenue Code of 1986, as amended (the "Code"), or any other provision of state, local or foreign tax law. To the extent that amounts are so withheld by the Surviving Entity or NEES, as the case may be, such withheld amounts shall be treated for all purposes of this Agreement as having been paid to the holder of EUA Shares in respect of which such deduction and withholding was made by the Surviving Entity or NEES, as the case may be. ARTICLE III THE CLOSING The closing of the Merger and other transactions contemplated hereby (the "Closing") will take place at the offices of Skadden, Arps, Slate, Meagher & Flom LLP, 919 Third Avenue, New York, New York 10022, at 10:00 a.m., local time, on the second business day following satisfaction or waiver (where applicable) of the conditions set forth in Article VIII (other than those conditions that by their nature are to be fulfilled at the Closing, but subject to the fulfillment or waiver of such conditions), unless another date, time or place is agreed to in writing by the parties hereto (the "Closing Date"). -4- ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EUA EUA represents and warrants to NEES and LLC as follows: 4.01 Organization and Qualification. (a) EUA is a voluntary association duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has full power, authority and legal right to own its property and assets and to transact the business in which it is engaged. Each of EUA's Subsidiaries is a corporation duly organized or incorporated, validly existing and in good standing under the laws of its jurisdiction of organization or incorporation and has full corporate power and authority to conduct its business as and to the extent now conducted and to own, use and lease its assets and properties, except where failure to be so organized or incorporated, existing and in good standing or to have such power and authority, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. As used in this Agreement, the term "EUA Material Adverse Effect" means a material adverse effect on the business, assets, results of operations, condition (financial or otherwise) or prospects of EUA and its Subsidiaries taken as a whole. Each of EUA and its Subsidiaries is duly qualified, licensed or admitted to do business and is in good standing in each jurisdiction in which the ownership, use or leasing of its assets and properties, or the conduct or nature of its business, makes such qualification, licensing or admission necessary, except where failure to be so qualified, licensed or admitted and in good standing, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. Section 4.01 of the letter dated the date hereof and delivered to NEES and LLC by EUA concurrently with the execution and delivery of this Agreement (the "EUA Disclosure Letter") sets forth (i) the name and jurisdiction of incorporation or organization of each Subsidiary of EUA, (ii) such Subsidiary's authorized capital stock, (iii) the number of issued and outstanding shares of capital stock of such Subsidiary and (iv) the number of shares of such Subsidiary held of record by EUA. EUA has previously delivered to NEES correct and complete copies of the EUA Trust Agreement and the certificate or articles of organization or incorporation and bylaws (or other comparable charter documents) of its Subsidiaries. (b) Section 4.01 of the EUA Disclosure Letter sets forth a description as of the date hereof, of all EUA Associates, including (i) the name of each such entity and EUA's interest therein and (ii) a brief description of the principal line or lines of business conducted by each such entity. For purposes of this Agreement "EUA Associates" shall mean any corporation or other entity (including partnerships and other business associations) that is not a Subsidiary of EUA in which EUA and/or one or more of its Subsidiaries, directly or indirectly, owns an equity interest (other than short-term investments in the ordinary course of business) if such corporation or other entity (including partnerships and other business associations) contributes five percent or more of EUA's consolidated revenues, assets, income or costs. -5- 4.02 Capital Stock. (a) The authorized equity securities of EUA consists of 36,000,000 EUA Shares, of which 20,435,997 shares were issued and outstanding as of the close of business on January 29, 1999. As of the close of business on January 29, 1999, no EUA Shares were held in the treasury of EUA. Since such date there has been no change in the sum of the issued and outstanding EUA Shares. All of the issued and outstanding EUA Shares are duly authorized, validly issued, fully paid and nonassessable. Except pursuant to this Agreement and except as described in Section 4.02 of the EUA Disclosure Letter, on the date hereof there are no outstanding subscriptions, options, warrants, rights (including share appreciation rights), preemptive rights or other contracts, commitments, understandings or arrangements, including any right of conversion or exchange under any outstanding security, instrument or agreement (together, "Options"), obligating EUA or any of its Subsidiaries to issue or sell any shares of equity securities of EUA or to grant, extend or enter into any Option with respect thereto. The EUA Disclosure Letter sets forth all capital stock authorized, issued and outstanding at subsidiary levels as of the close of business on January 29, 1999. (b) Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, all of the outstanding shares of capital stock of each Subsidiary of EUA are duly authorized, validly issued, fully paid and nonassessable and are owned, beneficially and of record, by EUA or a Subsidiary, which is wholly owned, directly or indirectly, by EUA, free and clear of any liens, claims, mortgages, encumbrances, pledges, security interests, equities and charges of any kind (each a "Lien"). Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no (i) outstanding Options obligating EUA or any of its Subsidiaries to issue or sell any shares of capital stock of any Subsidiary of EUA or to grant, extend or enter into any such Option or (ii) voting trusts, proxies or other commitments, understandings, restrictions or arrangements in favor of any person other than EUA or a Subsidiary which is wholly owned, directly or indirectly, by EUA with respect to the voting of, or the right to participate in, dividends or other earnings on any capital stock of any Subsidiary of EUA. (c) Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no outstanding contractual obligations of EUA or any Subsidiary of EUA to repurchase, redeem or otherwise acquire any EUA Shares or any capital stock of any Subsidiary of EUA or to provide funds to, or make any investment (in the form of a loan, capital contribution or otherwise) in, any Subsidiary of EUA or any other person. (d) As of the date of this Agreement, no bonds, debentures, notes or other indebtedness of EUA or any Subsidiary of EUA having the right to vote (or which are convertible into or exercisable for securities having the right to vote) (together "EUA Voting Debt") on any matters on which Shareholders may vote are issued or outstanding nor are there any outstanding Options obligating EUA or any of its Subsidiaries to issue or sell any EUA Voting Debt or to grant, extend or enter into any Option with respect thereto. -6- 4.03 Authority. EUA has full power and authority to enter into this Agreement, to perform its obligations hereunder and, subject to obtaining EUA Shareholders' Approval (as defined in Section 7.03(b)) and EUA Required Statutory Approvals (as defined in Section 4.04(b)), to consummate the Merger and other transactions contemplated hereby. The execution, delivery and performance of this Agreement by EUA and the consummation by EUA of the Merger and other transactions contemplated hereby have been duly authorized by all necessary action on the part of EUA, subject to obtaining EUA Shareholders' Approval with respect to the consummation of the Merger and the other transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by EUA and constitutes a legal, valid and binding obligation of EUA enforceable against EUA in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). 4.04 Non-Contravention; Approvals and Consents. (a) The execution and delivery of this Agreement by EUA do not, and the performance by EUA of its obligations hereunder and the consummation of the Merger and other transactions contemplated hereby will not, conflict with, result in a violation or breach of, constitute (with or without notice or lapse of time or both) a default under, result in or give to any person any right of payment or reimbursement, termination, cancellation, modification or acceleration of, or result in the creation or imposition of any Lien upon any of the assets or properties of EUA or any of its Subsidiaries or any of the terms, conditions or provisions of (i) the EUA Trust Agreement or the certificates or articles of incorporation or organization or bylaws (or other comparable charter documents) of EUA's Subsidiaries, or (ii) subject to the obtaining of EUA Shareholders' Approval, EUA Required Consents, EUA Required Statutory Approvals and the taking of any other actions described in this Section 4.04, (x) any statute, law, rule, regulation or ordinance (together, "laws"), or any judgment, decree, order, writ, permit or license (together, "orders"), of any court, tribunal, arbitrator, authority, agency, commission, official or other instrumentality of the United States, any foreign country or any domestic or foreign state, county, city or other political subdivision (a "Governmental Authority") applicable to EUA or any of its Subsidiaries or any of their respective assets or properties, or (y) subject to obtaining the third-party consents set forth in Section 4.04 of the EUA Disclosure Letter (the "EUA Required Consents"), any note, bond, mortgage, security agreement, indenture, license, franchise, permit, concession, contract, lease or other instrument, obligation or agreement of any kind (together, "Contracts") to which EUA or any of its Subsidiaries is a party or by which EUA or any of its Subsidiaries or any of their respective assets or properties is bound, excluding from the foregoing clauses (x) and (y) such conflicts, violations, breaches, defaults, payments or reimbursements, terminations, cancellations, modifications, accelerations and creations and impositions of Liens which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. -7- (b) No declaration, filing or registration with, or notice to or authorization, consent or approval of, any Governmental Authority is necessary for the execution and delivery of this Agreement by EUA or the consummation by EUA of the Merger and other transactions contemplated hereby except as described in Section 4.04 of the EUA Disclosure Letter or the failure of which to obtain could not reasonably be expected to result in an EUA Material Adverse Effect (the "EUA Required Statutory Approvals," it being understood that references in this Agreement to "obtaining" such EUA Required Statutory Approvals shall mean making such declarations, filings or registrations; giving such notices; obtaining such authorizations, consents or approvals; and having such waiting periods expire as are necessary to avoid a violation of law). 4.05 SEC Reports, Financial Statements and Utility Reports. (a) EUA delivered to NEES prior to the execution of this Agreement a true and complete copy of each form, report, schedule, registration statement, registration exemption, if applicable, definitive proxy statement and other document (together with all amendments thereof and supplements thereto) filed by EUA or any of its Subsidiaries with the Securities and Exchange Commission (the "SEC") under the Securities Act of 1933, as amended, and the rules and regulations thereunder (the "Securities Act") and the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder (the "Exchange Act") since December 31, 1995 (as such documents have since the time of their filing been amended or supplemented, the "EUA SEC Reports"), which are all the documents (other than preliminary materials) that EUA and its Subsidiaries were required to file with the SEC under the Securities Act and the Exchange Act since such date. As of their respective dates, EUA SEC Reports (i) complied as to form in all material respects with the requirements of the Securities Act or the Exchange Act, as the case may be, and (ii) did not contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. Each of the audited consolidated financial statements and unaudited interim consolidated financial statements (including, in each case, the notes, if any, thereto) included in EUA SEC Reports (the "EUA Financial Statements") complied as to form in all material respects with the published rules and regulations of the SEC with respect thereto, were prepared in accordance with U.S. generally accepted accounting principles ("US GAAP") applied on a consistent basis during the periods involved (except as may be indicated therein or in the notes thereto and except with respect to unaudited statements as permitted by Form 10-Q of the SEC) and fairly present (subject, in the case of the unaudited interim financial statements, to normal, recurring year-end audit adjustments (which are not expected to be, individually or in the aggregate, materially adverse to EUA and its Subsidiaries taken as a whole)) the consolidated financial position of EUA and its consolidated subsidiaries as at the respective dates thereof and the consolidated results of their operations and cash flows for the respective periods then ended. Except as set forth in Section 4.05 of the EUA Disclosure Letter, each Subsidiary of EUA is treated as a consolidated subsidiary of EUA in EUA Financial Statements for all periods covered thereby. (b) All filings (other than immaterial filings) required to be made by EUA or any of its Subsidiaries since December 31, 1995, under the Public -8- Utility Holding Company Act of 1935 (the "1935 Act"), the Federal Power Act, the Atomic Energy Act of 1954, the Communications Act of 1934, and applicable state laws and regulations, have been filed with the SEC, the Federal Energy Regulatory Commission (the "FERC"), the Department of Energy (the "DOE"), the Nuclear Regulatory Commission (the "NRC"), the Federal Communications Commission (the "FCC") or any appropriate state public utility commissions (including, without limitation, to the extent required, the state public utility regulatory agencies of Massachusetts, Rhode Island, New Hampshire, Maine, Vermont and Connecticut as the case may be, including all forms, statements, reports, agreements (oral or written) and all documents, exhibits, amendments and supplements appertaining thereto, including but not limited to all rates, tariffs, franchises, service agreements and related documents and all such filings complied, as of their respective dates, in all material respects with all applicable requirements of the appropriate statutes and the rules and regulations thereunder. 4.06 Absence of Certain Changes or Events. Except as set forth in Section 4.06 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date of this Agreement since December 31, 1997, EUA and each of EUA's Subsidiaries have conducted its business only in the ordinary course of business consistent with past practice and there has not been, and no fact or condition exists which, individually or in the aggregate, has or could reasonably be expected to have an EUA Material Adverse Effect. 4.07 Legal Proceedings. Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or in Section 4.07 of the EUA Disclosure Letter and except for environmental matters which are governed by Section 4.13, (i) there are no actions, claims, hearings, suits, arbitrations or proceedings pending or, to the knowledge of EUA or any of its Subsidiaries, threatened against, specifically relating to or affecting, and, to the knowledge of EUA or any of its Subsidiaries, there are no Governmental Authority investigations or audits pending or threatened against, specifically relating to or affecting, EUA or any of its Subsidiaries or any of their respective assets and properties which, individually or in the aggregate, could reasonably be expected to have an EUA Material Adverse Effect and (ii) neither EUA nor any of its Subsidiaries is subject to any order of any Governmental Authority which, individually or in the aggregate, could reasonably be expected to have an EUA Material Adverse Effect. 4.08 Information Supplied. (a) The proxy statement relating to EUA Shareholders' Meeting, as amended or supplemented from time to time (as so amended and supplemented, the "Proxy Statement"), and any other documents to be filed by EUA with the SEC (including, without limitation, under the 1935 Act) or any other Governmental Authority in connection with the Merger and other transactions contemplated hereby will comply as to form in all material respects with the requirements of the Exchange Act, the Securities Act and the 1935 Act, as applicable, and will not, on the date of their respective filings or, in the case of the Proxy Statement, at the date it is mailed to Shareholders of EUA and at the time of EUA Shareholders' Meeting (as defined in Section 7.03), contain any untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in light of the circumstances under which they are made, not misleading. -9- (b) Notwithstanding the foregoing provisions of this Section 4.08, no representation or warranty is made by EUA with respect to statements made or incorporated by reference in the Proxy Statement based on information supplied by NEES or LLC for inclusion or incorporation by reference therein. 4.09 Compliance. Except as set forth in Section 4.09 of the EUA Disclosure Letter, or as disclosed in EUA SEC Reports filed prior to the date hereof, neither EUA nor any of EUA's Subsidiaries is in violation of, is, to the knowledge of EUA, under investigation with respect to any violation of, or has been given notice or been charged with any violation of, any law, statute, order, rule, regulation, ordinance or judgment (including, without limitation, any applicable environmental law, ordinance or regulation) of any Governmental Authority, except for possible violations which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. Except as set forth in Section 4.09 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date hereof, EUA and EUA's Subsidiaries have all permits, licenses, franchises and other governmental authorizations, consents and approvals necessary to conduct their businesses as presently conducted except for such failures which could not reasonably be expected to have an EUA Material Adverse Effect. Neither EUA nor any of EUA's Subsidiaries is in breach or violation of, or in default in the performance or observance of any term or provision of, (i) the EUA Trust Agreement, in the case of EUA, or articles of incorporation or organization or by-laws, in the case of EUA's Subsidiaries, or (ii) any contract, commitment, agreement, indenture, mortgage, loan agreement, note, lease, bond, license, approval or other instrument to which it is a party or by which EUA or any Subsidiary of EUA is bound or to which any of their respective property is subject, except for possible violations, breaches or defaults which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. 4.10 Taxes. Except as disclosed in Section 4.10 of the EUA Disclosure Letter: (a) Filing of Timely Tax Returns. EUA and each of its Subsidiaries have timely filed all Tax Returns required to be filed by each of them under applicable law. All Tax Returns were (and, as to Tax Returns not filed as of the date hereof, will be) true, complete and correct; (b) Payment of Taxes. EUA and each of its Subsidiaries have, within the time and in the manner prescribed by law, paid (and until the Closing Date will pay within the time and in the manner prescribed by law) all Taxes that are currently due and payable except for those contested in good faith and for which adequate reserves have been taken; (c) Tax Reserves. EUA and its Subsidiaries have established (and until the Closing Date will maintain) on their books and records adequate reserves for all Taxes and for any liability for deferred income taxes in accordance with GAAP; -10- (d) Extensions of Time for Filing Tax Returns. Neither EUA nor any of its Subsidiaries has requested any extension of time within which to file any Tax Return, which Tax Return has not since been filed; (e) Waivers of Statute of Limitations. Neither EUA nor any of its Subsidiaries has in effect any extension, outstanding waivers or comparable consents regarding the application of the statute of limitations with respect to any Taxes or Tax Returns; (f) Expiration of Statute of Limitations. The Tax Returns of EUA, each of its Subsidiaries and any affiliated, consolidated, combined or unitary group that includes EUA or any of its Subsidiaries either have been examined and settled with the appropriate Tax authority or closed by virtue of the expiration of the applicable statute of limitations for all years through and including 1993; (g) Audit, Administrative and Court Proceedings. No audits or other administrative proceedings or court proceedings are presently pending or threatened with regard to any Taxes or Tax Returns of EUA or any of its Subsidiaries (other than those being contested in good faith and for which adequate reserves have been established) and no issues have been raised in writing by any Tax authority in connection with any Tax or Tax Return; (h) Tax Liens. There are no Tax liens upon any asset of EUA or any of its Subsidiaries except liens for Taxes not yet due. (i) Powers of Attorney. No power of attorney currently in force has been granted by EUA or any of its Subsidiaries concerning any Tax matter; (j) Tax Rulings. Neither EUA nor any of its Subsidiaries has, during the five year period prior to the date of this Agreement, received a Tax Ruling (as defined below) or entered into a Closing Agreement (as defined below) with any taxing authority. "Tax Ruling", as used in this Agreement, shall mean a written ruling of a taxing authority relating to Taxes. "Closing Agreement", as used in this Agreement, shall mean a written and legally binding agreement with a taxing authority relating to Taxes; (k) Availability of Tax Returns. EUA and its Subsidiaries have made available to NEES complete and accurate copies, covering all years ending on or after December 31, 1993, of (i) all Tax Returns, and any amendments thereto, filed by EUA or any of its Subsidiaries, (ii) all audit reports received from any taxing authority relating to any Tax Return filed by EUA or any of its Subsidiaries and (iii) any Closing Agreements entered into by EUA or any of its Subsidiaries with any taxing authority. (l) Tax Sharing Agreements. No agreements relating to the allocation or sharing of Taxes exist between or among EUA and any of its Subsidiaries and neither EUA nor any of its Subsidiaries (i) has been a member of an affiliated group filing a consolidated federal income tax return (other -11- than a group the common parent of which was EUA) or (ii) has any liability for Taxes of any Person (other than EUA or its Subsidiaries) under United States Treasury Regulation Section 1.1502-6 (or any provision of state, local), or foreign law, as a transferee or successor, by contract or otherwise; (m) Code Section 481 Adjustments. Neither EUA nor any of its Subsidiaries is required to include in income any adjustment pursuant to Code Section 481(a) by reason of a voluntary change in accounting method initiated by EUA or any of its Subsidiaries, and, the Internal Revenue Service ("IRS") has not proposed any such adjustment or change in accounting method; (n) Code Sections 6661 and 6662. All transactions that could give rise to an understatement of federal income tax, and within the meaning of Code Section 6662 have been adequately disclosed (or, with respect to Tax Returns filed following the Closing, will be adequately disclosed) on the Tax Returns of EUA and its Subsidiaries in accordance with Code Section 6662(d)(2)(B); (o) Intercompany Transactions. Neither EUA nor any of its Subsidiaries has engaged in any intercompany transactions within the meaning of Treasury Regulations ss. 1.1502-13 for which any income or gain will remain unrecognized as of the close of the last taxable year prior to the Closing Date; and (p) Foreign Tax Returns. Neither EUA nor any of its Subsidiaries is required to file a foreign tax return. "Taxes" as used in this Agreement, shall mean any federal, state, county, local or foreign taxes, charges, fees, levies, or other assessments, including all net income, gross income, premiums, sales and use, ad valorem, transfer, gains, profits, windfall profits, excise, franchise, real and personal property, gross receipts, capital stock, production, business and occupation, employment, disability, payroll, license, estimated, stamp, custom duties, severance or withholding taxes, other taxes or similar charges of any kind whatsoever imposed by any governmental entity, whether imposed directly on a Person or resulting under Treasury Regulation Section 1.1502-6 (or any similar provision of state, local or foreign law), as a transferee or successor, by contract or otherwise and includes any interest and penalties on or additions to any such taxes or in respect of a failure to comply with any requirement relating to any Tax Return. "Tax Return" as used in this Agreement, shall mean a report, return or other information required to be supplied to a governmental entity with respect to Taxes including, where permitted or required, combined, unitary or consolidated returns for any group of entities. 4.11 Employee Benefit Plans; ERISA. (a) Each "employee benefit plan" (as defined in Section 3(3) of the Employee Retirement Income Security Act of 1974, as amended ("ERISA")), bonus, deferred compensation, share option or other written agreement relating to employment or fringe benefits for employees, former employees, officers, trustees or directors of EUA or any of its Subsidiaries effective as of the date hereof or providing benefits as of the date hereof to current employees, former employees, officers, trustees or -12- directors of EUA or pursuant to which EUA or any of its subsidiaries has or could reasonably be expected to have any liability (collectively, the "EUA Employee Benefit Plans") is listed in Section 4.11(a) of the EUA Disclosure Letter, is in material compliance with applicable law, and has been administered and operated in all material respects in accordance with its terms. Each EUA Employee Benefit Plan which is intended to be qualified within the meaning of Section 401(a) of the Code has received a favorable determination letter from the IRS as to such qualification and, to the knowledge of EUA, no event has occurred and no condition exists which could reasonably be expected to result in the revocation of, or have any adverse effect on, any such determination. (b) Complete and correct copies of the following documents have been made available to NEES as of the date of this Agreement: (i) all EUA Employee Benefit Plans and any related trust agreements or insurance contracts, (ii) the most current summary descriptions of each EUA Employee Benefit Plan subject to ERISA, (iii) the three most recent Form 5500s and Schedules thereto for each EUA Employee Benefit Plan subject to such reporting, (iv) the most recent determination of the IRS with respect to the qualified status of each EUA Employee Benefit Plan that is intended to qualify under Section 401(a) of the Code, (v) the most recent accountings with respect to each EUA Employee Benefit Plan funded through a trust and (vi) the most recent actuarial report of the qualified actuary of each EUA Employee Benefit Plan with respect to which actuarial valuations are conducted. (c) Except as set forth in Section 4.11(c) of the EUA Disclosure Letter, neither EUA nor any Subsidiary maintains or is obligated to provide benefits under any EUA Employee Benefit Plan (other than as an incidental benefit under a Plan qualified under Section 401(a) of the Code) which provides health or welfare benefits to retirees or other terminated employees other than benefit continuations as required pursuant to Section 601 of ERISA. Each EUA Employee Benefit Plan subject to the requirements of Section 601 of ERISA has been operated in material compliance therewith. EUA has not contributed to a nonconforming group health plan (as defined in Code Section 5000(c)) and no person under common control with EUA within the meaning of Section 414 of the Code ("ERISA Affiliate") has incurred a tax liability under Code Section 5000(a) that is or could reasonably be expected to be a liability of EUA's. (d) Except as set forth in Section 4.11(d) of the EUA Disclosure Letter, each EUA Employee Benefit Plan covers only employees who are employed by EUA or a Subsidiary (or former employees or beneficiaries with respect to service with EUA or a Subsidiary). (e) Except as set forth in Section 4.11(e) of the EUA Disclosure Letter, neither EUA, any Subsidiary, any ERISA Affiliate nor any other corporation or organization controlled by or under common control with any of the foregoing within the meaning of Section 4001 of ERISA has, within the five-year period preceding the date of this Agreement, at any time contributed to any "multiemployer plan," as that term is defined in Section 4001 of ERISA. -13- (f) No event has occurred, and there exists no condition or set of circumstances in connection with any EUA Employee Benefit Plan, under which EUA or any Subsidiary, directly or indirectly (through any indemnification agreement or otherwise), could be subject to any liability under Section 409 of ERISA, Section 502(i) of ERISA, Title IV of ERISA or Section 4975 of the Code except for instances of non-compliance which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. (g) Neither EUA nor any ERISA Affiliate has incurred any liability to the Pension Benefit Guaranty Corporation (the "PBGC") under Section 302(c)(ii), 4062, 4063, 4064 or 4069 of ERISA, or otherwise that has not been satisfied in full and no event or condition exists or has existed which could reasonably be expected to result in any such material liability. As of the date of this Agreement, no "reportable event" within the meaning of Section 4043 of ERISA has occurred with respect to any EUA Employee Benefit Plan that is a defined benefit plan under Section 3(35) of ERISA. (h) Except as set forth in Section 4.11(h) of the EUA Disclosure Letter, no employer securities, employer real property or other employer property is included in the assets of any EUA Employee Benefit Plan. (i) Full payment has been made of all material amounts which EUA or any affiliate thereof was required under the terms of EUA Employee Benefit Plans to have paid as contributions to such plans on or prior to the Effective Time (excluding any amounts not yet due) and no EUA Employee Benefit Plan which is subject to Part III of Subtitle B of Title I of ERISA has incurred any "accumulated funding deficiency" within the meaning of Section 302 of ERISA or Section 412 of the Code, whether or not waived. (j) Except as set forth in Section 4.11(j) of the EUA Disclosure Letter, no amounts payable under any EUA Employee Benefit Plan or other agreement, contract, or arrangement will fail to be deductible for federal income tax purposes by virtue of Section 280G or Section 162(m) of the Code. 4.12 Labor Matters. As of the date hereof, except as set forth in Section 4.12 of the EUA Disclosure Letter, neither EUA nor any of its Subsidiaries is a party to any material collective bargaining agreement or other labor agreement with any union or labor organization. To the knowledge of EUA, as of the date hereof, there is no current union representation question involving employees of EUA or any of its Subsidiaries, nor does EUA know of any activity or proceeding of any labor organization (or representative thereof) or employee group to organize any such employees. Except as set forth in Section 4.12 of the EUA Disclosure Letter, (i) there is no unfair labor practice, employment discrimination or other employment-related complaint or proceeding against EUA or any of its Subsidiaries pending or, to the knowledge of EUA, threatened, which has or could reasonably be expected to have an EUA Material Adverse Effect, (ii) there is no strike, dispute, slowdown, work stoppage or lockout pending, or, to the knowledge of EUA, threatened, against or involving EUA or any of its Subsidiaries which has or could reasonably be expected to have, an EUA Material Adverse Effect and (iii) there is no proceeding, claim, -14- suit, or action pending or, to the knowledge of EUA or any of its Subsidiaries, threatened, nor, to the knowledge of EUA or any of its Subsidiaries is there any Governmental Authority investigation pending or threatened, in respect of which any trustee, director, officer, employee or agent of EUA or any of its Subsidiaries is or may be entitled to claim indemnification from EUA or any of its Subsidiaries pursuant to the EUA Trust Agreement, in the case of EUA, and their respective articles of incorporation and by-laws, in the case of EUA's Subsidiaries, or as provided in the indemnification agreements listed in Section 4.12 of the EUA Disclosure Letter. Except as set forth in Section 4.12 of the EUA Disclosure Letter, EUA and its Subsidiaries are in compliance with all federal, state and local laws with respect to employment practices and labor relations, including, without limitation, any provisions relating to affirmative action, employment discrimination, wages, hours, collective bargaining, and the payment of social security and similar taxes, safety and health regulations and mass layoffs and plant closings except for such instances of noncompliance which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. 4.13 Environmental Matters. Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or in Section 4.13 of the EUA Disclosure Letter: (a) (i) Each of EUA and its Subsidiaries is in compliance with all applicable Environmental Laws (as hereinafter defined), except where the failure to be in compliance, in the aggregate could not reasonably be expected to result in an EUA Material Adverse Effect; and (ii) Neither EUA nor any of its Subsidiaries has received any written communication from any person or Governmental Authority that alleges that EUA or any of its Subsidiaries is not in such compliance (including the materiality qualifier set forth in clause (i) above) with applicable Environmental Laws. (b) Each of EUA and its Subsidiaries has obtained all environmental, health and safety permits and governmental authorizations (collectively, the "Environmental Permits") necessary for the construction of their facilities and the conduct of their operations, as applicable, and all such Environmental Permits are in good standing or, where applicable, a renewal application has been timely filed and agency approval is expected in the ordinary course of business, and EUA and its Subsidiaries are in compliance with all terms and conditions of the Environmental Permits, except where the failure have such Environmental Permits, file a renewal application for such Environmental Permits, or to be in compliance with such Environmental Permits, in the aggregate could not reasonably be expected to result in an EUA Material Adverse Effect. (c) There is no Environmental Claim (as hereinafter defined) that could, individually or in the aggregate, reasonably be expected to have an EUA Material Adverse Effect pending (i) against EUA or any of its Subsidiaries; (ii) against any person or entity whose liability for any Environmental Claim EUA or any of its Subsidiaries has or may have retained or assumed either contractually or by operation of law; or (iii) against any real or personal -15- property or operations which EUA or any of its Subsidiaries owns, leases or manages, in whole or in part. (d) To the knowledge of EUA there have not been any material Releases (as hereinafter defined) of any Hazardous Material (as hereinafter defined) that would be reasonably likely to form the basis of any material Environmental Claim against EUA or any of its Subsidiaries, or against any person or entity whose liability for any material Environmental Claim EUA or any of its Subsidiaries has or may have retained or assumed either contractually or by operation of law, except for any Environmental Claim that, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. (e) To the knowledge of EUA with respect to any predecessor of EUA or any of its Subsidiaries, there is no material Environmental Claim pending or threatened, and there has been no Release of Hazardous Materials that could reasonably be expected to form the basis of any material Environmental Claim except for any Environmental Claim that, individually or in the aggregate, could not be reasonably be expected to have an EUA Material Adverse Effect. (f) As used in this Section 4.13: (i) "Environmental Claim" means any and all written administrative, regulatory or judicial actions, suits, demands, demand letters, directives, claims, liens, investigations, proceedings or notices or noncompliance, liability or violation by any person or entity (including any Governmental Authority) alleging potential liability (including, without limitation, potential responsibility or liability for enforcement, investigatory costs, cleanup costs, governmental response costs, removal costs, remedial costs, natural resources damages, property damages, personal injuries or penalties) arising out of, based on or resulting from (A) the presence, or Release or threatened Release into the environment, of any Hazardous Materials at any location, whether or not owned, operated, leased or managed by EUA or any of its Subsidiaries; or (B) circumstances forming the basis of any violation, or alleged violation, of any Environmental Law; or (C) any and all claims by any third party seeking damages, contribution, indemnification, cost recovery, compensation or injunctive relief resulting from the presence or Release of any Hazardous Materials; (ii) "Environmental Laws" means all federal, state and local laws, rules and regulations and binding interpretation thereof, relating to pollution, the environment (including, without limitation, ambient air, surface water, groundwater, land surface or subsurface strata) or protection of human health as it relates to the environment including, without limitation, laws and -16- regulations relating to Releases or threatened Releases of Hazardous Materials, or otherwise relating to the manufacture, generation, processing, distribution, use, treatment, storage, disposal, transport or handling of Hazardous Materials; (iii) "Hazardous Materials" means (A) any petroleum or petroleum products, radioactive materials, asbestos in any form that is or could become friable, urea formaldehyde foam insulation, and transformers or other equipment that contain dielectric fluid containing polychlorinated biphenyls; and (B) any chemicals, materials or substances which are now defined as or included in the definition of "hazardous substances", "hazardous wastes", "hazardous materials", "extremely hazardous wastes", "restricted hazardous wastes", "toxic substances", "toxic pollutants", or words of similar import, under any Environmental Law; and (c) any other chemical, material, substance or waste, exposure to which is now prohibited, limited or regulated under any Environmental Law in a jurisdiction in which EUA or any of its Subsidiaries (x) operates or (y) stores, treats or disposes of Hazardous Materials; and (iv) "Release" means any release, spill, emission, leaking, injection, deposit, disposal, discharge, dispersal, leaching or migration into the atmosphere, soil, surface water, groundwater or property. 4.14 Regulation as a Utility. (a) EUA is a public utility holding company registered under Section 5, and subject to the provisions, of the 1935 Act. Section 4.14 of the EUA Disclosure Letter lists the subsidiaries of EUA that are "public utility companies" within the meaning of Section 2(a)(5) of the 1935 Act and lists the jurisdictions where each such Subsidiary is subject to regulation as a public utility company or public service company. Except as set forth above and as set forth in Section 4.14 of the EUA Disclosure Letter, neither EUA nor any "subsidiary company" or "affiliate" of EUA is subject to regulation as a public utility or public service company (or similar designation) by the federal government of the United States, any state in the United States or any political subdivision thereof, or any foreign country. (b) As used in this Section 4.14, the terms "subsidiary company" and "affiliate" shall have the respective meanings ascribed to them in Section 2(a)(8) and Section 2(a)(11), respectively, of the 1935 Act. 4.15 Insurance. Except as set forth in Section 4.15 of the EUA Disclosure Letter, each of EUA and its Subsidiaries is, and has been continuously since January 1, 1994, insured with financially responsible insurers in such amounts and against such risks and losses as are customary in all material respects for companies in the United States conducting the business conducted by EUA and its Subsidiaries during such time period. Except as set forth in Section 4.15 of the EUA Disclosure Letter, neither EUA nor any of its Subsidiaries has received any notice of cancellation or termination with respect to any material insurance policy of EUA or any of its Subsidiaries. The insurance policies of EUA and each of its Subsidiaries are valid and enforceable policies. -17- 4.16 Nuclear Facilities. Montaup Electric Company, a Subsidiary of EUA, is a minority common stockholder of each of Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power Corporation and Yankee Atomic Electric Company (the "Yankee Companies") and a minority joint owner in Millstone 3 and Seabrook 1 (collectively, as described in Section 4.16 of the EUA Disclosure Letter, the "EUA Nuclear Facilities"). With respect to its ownership of Millstone 3 and Seabrook 1, Montaup Electric Company holds the required operating licenses from the NRC. With respect to the Yankee Companies, each Yankee Company holds its own operating license from the NRC. Because it is a minority stockholder or a minority joint owner, Montaup Electric Company does not have responsibility for the operation of EUA Nuclear Facilities. Except as set forth in Section 4.16 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date hereof, to the knowledge of EUA, neither EUA nor any of its Subsidiaries is in violation of any applicable health, safety, regulatory and other legal requirement, including NRC laws and regulations and Environmental Laws, applicable to EUA Nuclear Facilities except for such failure to comply as could not reasonably be expected to have a material adverse effect with respect to EUA Nuclear Facilities and the ownership interest of EUA therein. To the knowledge of EUA, each of EUA Nuclear Facilities maintains emergency plans designed to respond to an unplanned release therefrom of radioactive materials into the environment and insurance coverages consistent with industry practice. EUA has funded, or has caused the funding of, its portion of the decommissioning cost of each of the EUA Nuclear Facilities and the storage of spent nuclear fuel consistent with the most recently approved plan for each of the EUA Nuclear Facilities and FERC authorized rates. Except as set forth in Section 4.16 of the EUA Disclosure Letter, to the knowledge of EUA, no EUA Nuclear Facility is as of the date of this Agreement on the List of Nuclear Power Plants Warranting Increased Regulatory Attention maintained by the NRC. 4.17 Vote Required. The affirmative vote of two-thirds of the outstanding EUA Shares voting as a single class (with each EUA Share having one vote per share) with respect to the approval of the Merger and other transactions contemplated hereby is the only vote of the holders of any class or series of equity securities of EUA or its Subsidiaries required to approve this Agreement and approve the Merger and other transactions contemplated hereby. 4.18 Opinion of Financial Advisor. EUA has received the opinion of Salomon Smith Barney Inc., dated the date of this Agreement, to the effect that, as of such date, the Merger Consideration is fair from a financial point of view to the holders of EUA Shares. A true and complete copy of the written opinion will be delivered to NEES promptly after receipt thereof by EUA. 4.19 Ownership of NEES Common Shares. Neither EUA nor any of its Subsidiaries or other affiliates beneficially owns any NEES Common Shares. 4.20 State Anti-Takeover Statutes. EUA has taken all necessary actions so that the provisions of Chapters 110C, 110D or 110F of the MGL will not apply to this Agreement, the Merger or other transactions contemplated hereby or thereby. -18- 4.21 Year 2000. The Information Systems operated by EUA and its Subsidiaries which is used in the conduct of their business is capable of providing or being adapted to provide uninterrupted millennium functionality to record, store, process and present calendar dates falling on or after January 1, 2000 in substantially the same manner and with the same functionality as such Information Systems record, store, process and present such calendar dates falling on or before December 31, 1999 other than such interruptions in millennium functionality that could not, individually or in the aggregate, reasonably be expected to result in a EUA Material Adverse Effect. EUA reasonably believes as of the date hereof that the remaining cost of adaptations referred to in the foregoing sentence will not exceed the amounts reflected in the Form 10-Q filed by EUA for the quarter ended September 30, 1998 (excluding the fees and costs of any Y2K Consultant retained pursuant to Section 6.01(o) hereof and of the implementation of any recommendations by such Y2K Consultant actually made by EUA that are not already part of EUA's compliance plan as of the date hereof). "Information Systems" means mainframe and midrange hardware, operating system software and applications programs; network and desktop (PC) hardware, operating system software and applications programs; EDI (Electronic Date Interchange) and FTP (File Transfer Protocol) software; and embedded systems hardware and applications software. 4.22 EUA Associates. The representations and warranties set forth in Sections 4.04(a), 4.06, 4.07, 4.09, 4.12 and 4.13 are true and correct in all material respects with regard to EUA Associates. ARTICLE V REPRESENTATIONS AND WARRANTIES OF NEES NEES represents and warrants to EUA as follows: 5.01 Organization and Qualification. NEES is a voluntary association duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has full power, authority and legal right to own its property and assets and to transact the business in which it is engaged. Each of the NEES Subsidiaries is a corporation duly organized or incorporated, validly existing and in good standing under the laws of its jurisdiction of organization or incorporation and has full corporate power and authority to conduct its business as and to the extent now conducted and to own, use and lease its assets and properties, except where failure to be so organized or incorporated, existing and in good standing or to have such power and authority, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. As used in this Agreement, the term "NEES Material Adverse Effect" means a material adverse effect on the business, assets, results of operations, condition (financial or otherwise) or prospects of NEES and its Subsidiaries taken as a whole. LLC is a limited liability company validly existing under the laws of the Commonwealth of Massachusetts. LLC was formed solely for the purpose of engaging in the Merger and other transactions contemplated hereby, has engaged in no other business activities (other than in connection with the formation and capitalization of LLC pursuant to or in -19- accordance with the LLC Agreement (as defined below)) and has conducted its operations only as contemplated hereby and by the LLC Agreement. Each of NEES and its Subsidiaries is duly qualified, licensed or admitted to do business and is in good standing in each jurisdiction in which the ownership, use or leasing of its assets and properties, or the conduct or nature of its business, makes such qualification, licensing or admission necessary, except where failure to be so qualified, licensed or admitted and in good standing, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. NEES has previously delivered to EUA correct and complete copies of its Agreement and Declaration of Trust (the "NEES Trust Agreement") and the articles of association of LLC. 5.02 Authority. Each of NEES and LLC has full power and authority to enter into this Agreement, and to perform its obligations hereunder, and to consummate the Merger and other transactions contemplated hereby. The execution, delivery and performance of this Agreement by each of NEES and LLC and the consummation by each of NEES and LLC of the Merger and other transactions contemplated hereby have been duly authorized by all necessary corporate action on the part of NEES and all necessary action on the part of LLC. This Agreement has been duly and validly executed and delivered by each of NEES and LLC and constitutes a legal, valid and binding obligation of each of NEES and LLC enforceable against each of NEES and LLC in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). 5.03 Capital Stock. The authorized equity securities of NEES consists of 150,000,000 common shares of NEES (the "NEES Shares"), of which 59,170,986 shares were issued and outstanding as of the close of business on January 29, 1999. As of the close of business on January 29, 1999, 5,798,666 NEES Shares were held in the treasury of NEES. All of the issued and outstanding NEES Shares are duly authorized, validly issued, fully paid and nonassessable. Except as may be provided by the New England Electric System Companies' Incentive Share Plan, the New England Electric System Companies Incentive Thrift Plan I, the New England Electric System Companies Incentive Thrift Plan II, the New England Electric Companies Long-Term Performance Share Award Plan, and the New England Electric System Directors' annual retainer shares, and except as set forth in Section 5.03 of the letter dated the date hereof and delivered to EUA by NEES and LLC concurrently with the execution and delivery of this Agreement (the "NEES Disclosure Letter"), on the date hereof there are no outstanding Options obligating NEES or any of its Subsidiaries to issue or sell any shares of equity securities of NEES or to grant, extend or enter into any Option with respect thereto. 5.04 Non-Contravention; Approvals and Consents. (a) The execution and delivery of this Agreement by each of NEES and LLC do not, and the performance by each of NEES and LLC of its obligations hereunder and the consummation of the Merger and other transactions contemplated hereby will not, conflict with, result in a violation or breach of, constitute (with or without notice or lapse of time or both) a default under, result in or give to any person any right of payment or reimbursement, termination, cancellation, modification or -20- acceleration of, or result in the creation or imposition of any Lien upon any of the assets or properties of NEES, or LLC under, any of the terms, conditions or provisions of (i) the NEES Agreement and Declaration of Trust or the articles of organization of LLC, (ii) subject to the actions described in paragraph (b) of this Section, (x) any laws or orders of any Governmental Authority applicable to NEES or LLC or any of their respective assets or properties, or (y) subject to obtaining the third-party consents (the "NEES Required Consents") set forth in Section 5.04 of the NEES Disclosure Letter any Contracts to which NEES is a party or by which NEES or any of its Subsidiaries or any of their respective assets or properties is bound, excluding from the foregoing clauses (x) and (y) conflicts, violations, breaches, defaults, terminations, modifications, accelerations and creations and impositions of Liens which, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. (b) No declaration, filing or registration with, or notice to or authorization, consent or approval of, any Governmental Authority is necessary for the execution and delivery of this Agreement by NEES or LLC or the consummation by NEES or LLC of the Merger and other transactions contemplated hereby except as described in Section 5.04 of the NEES Disclosure Letter or the failure of which to obtain could not reasonably be expected to result in a NEES Material Adverse Effect (the "NEES Required Statutory Approvals," it being understood that references in this Agreement to "obtaining" such NEES Required Statutory Approvals shall mean making such declarations, filings or registrations; giving such notices; obtaining such authorizations, consents or approvals; and having such waiting periods expire as are necessary to avoid a violation of law). 5.05 Information Supplied. (a) The information supplied by NEES or LLC and included in the Proxy Statement with the written consent of NEES or LLC, as the case may be, will not, at the date mailed to EUA's Shareholders or at the time of EUA Shareholder's Meeting, contain any untrue statements of a material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. (b) Notwithstanding the foregoing provisions of this Section 5.05, no representation or warranty is made by NEES with respect to statements made or incorporated by reference in the Proxy Statement based on information supplied by EUA for inclusion or incorporation by reference therein or based on information which is not made in or incorporated by reference in such documents but which should have been disclosed pursuant to this Section 5.05. 5.06 Compliance. Except as set forth in Section 5.06 of the NEES Disclosure Letter, or as disclosed in the NEES Reports filed prior to the date hereof, NEES is not in violation of, is, to the knowledge of NEES, under investigation with respect to any violation of, or has been given notice or been charged with any violation of, any law, statute, order, rule, regulation, ordinance or judgment (including, without limitation, any applicable environmental law, ordinance or regulation) of any Governmental Authority, except for possible violations which, individually or in the aggregate, could -21- not reasonably be expected to have a NEES Material Adverse Effect. Except as set forth in Section 5.06 of the NEES Disclosure Letter or as disclosed in the NEES Reports filed prior to the date hereof, NEES and its Subsidiaries have all material permits, licenses and other governmental authorizations, consents and approvals necessary to conduct their businesses as presently conducted which are material to the operation of the businesses of NEES. NEES is not in breach or violation of, or in default in the performance or observance of, any term or provision of, and no event has occurred which, with lapse of time or action by a third party, could result in a default by NEES under (i) the NEES Agreement and Declaration of Trust or by-laws or (ii) any contract, commitment, agreement, indenture, mortgage, loan agreement, note, lease, bond, license, approval or other instrument to which it is a party or by which NEES is bound or to which any of their respective property is subject, except for possible violations, breaches or defaults which, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. 5.07 Financing. NEES has or will have available, prior to the Effective Time, sufficient cash in immediately available funds to pay or to cause LLC to pay the Merger Consideration pursuant to Article II hereof and to consummate the Merger and other transactions contemplated hereby. 5.08 No Vote Required. No vote of the NEES Shares or of any class or series of equity securities of NEES or its Subsidiaries is necessary for the approval of the Merger and other transactions contemplated hereby. 5.09 Ownership of EUA Shares. Neither NEES nor any of its Subsidiaries or other affiliates beneficially owns any EUA Shares. 5.10 Merger with The National Grid Group plc. NEES has entered into an Agreement and Plan of Merger dated as of December 11, 1998 by and among The National Grid Group plc ("National Grid Group"), NGG Holdings LLC (formerly known as Iosta LLC) and NEES (the "National Grid Merger Agreement"). Pursuant to Section 6.01 of the National Grid Merger Agreement, NEES has provided a copy of this Agreement to National Grid Group, and National Grid Group has given NEES its written consent to enter into this Agreement and consummate the Merger on the terms set forth in this Agreement. Prior to the execution of this Agreement, NEES has provided EUA with a copy of such written consent. ARTICLE VI COVENANTS 6.01 Covenants of EUA. At all times from and after the date hereof until the Effective Time, EUA covenants and agrees as to itself and its Subsidiaries that (except as expressly contemplated or permitted by this Agreement or as set forth in Section 6.01 of the EUA Disclosure Letter, or to the extent that NEES shall otherwise previously consent in writing): -22- (a) Ordinary Course. EUA and each of its Subsidiaries shall conduct their businesses only in, and EUA and each of its Subsidiaries shall not take any action except in, the ordinary course consistent with good utility practice. Without limiting the generality of the foregoing, EUA and its Subsidiaries shall use all commercially reasonable efforts to preserve intact in all material respects their present business organizations and reputation, to maintain in effect all existing permits, to keep available the services of their key officers and employees, to maintain their assets and properties in good working order and condition, ordinary wear and tear excepted, to maintain insurance on their tangible assets and businesses in such amounts and against such risks and losses as are currently in effect, to preserve their relationships with customers and suppliers and others having significant business dealings with them and to comply in all material respects with all laws and orders of all Governmental Authorities applicable to them. (b) Charter Documents. EUA shall not, nor shall it permit any of its Subsidiaries to, amend or propose to amend the EUA Trust Agreement, in the case of EUA, and its certificate or articles of incorporation or organization or bylaws (or other comparable charter documents), in the case of EUA's Subsidiaries. (c) Dividends. EUA shall not, nor shall it permit any of its Subsidiaries to, (i) declare, set aside or pay any dividends on, or make other distributions in respect of, any of its capital stock or share capital, except: (A) that EUA may continue the declaration and payment of regular quarterly dividends on EUA Shares with usual record and payment dates not, in any fiscal year, in excess of the dividend for the comparable period in the prior fiscal year; (B) that the Subsidiaries of EUA set forth in Section 6.01(c) of the EUA Disclosure Letter may continue the declaration and payment of dividends on preferred stock in accordance with the terms of such stock, with the record and payment dates and in the amounts set forth in Section 6.01(c) of the EUA Disclosure Letter; (C) if the Effective Time does not occur between a record date and payment date of a regular quarterly dividend, for a special dividend on EUA Shares with respect to the quarter in which the Effective Time occurs with a record date on or prior to the date on which the Effective Time occurs, which does not exceed an amount equal to the product of (x) the number of days between the last payment date of a regular quarterly dividend and the record date of such special dividend, multiplied by (y) $.0045; and (D) for dividends and distributions (including liquidating distributions) by a direct or indirect Subsidiary of EUA to its parent. -23- (ii) split, combine, subdivide, reclassify or take similar action with respect to any of its capital stock or share capital or issue or authorize or propose the issuance of any other securities in respect of, in lieu of or in substitution for shares of its capital stock or comprised in its share capital, (iii) adopt a plan of complete or partial liquidation or resolutions providing for or authorizing such liquidation or a dissolution, merger, consolidation, restructuring, recapitalization or other reorganization or (iv) directly or indirectly redeem, repurchase or otherwise acquire any shares of its capital stock or any Option with respect thereto except: (A) in connection with intercompany purchases of capital stock or share capital, (B) for the purpose of funding EUA's dividend reinvestment and share purchase plan in accordance with past practice, or (C) subject to EUA's obligations under the Securities Act and the Exchange Act, pursuant to EUA's previously announced share repurchase program provided that the number of EUA Shares repurchased does not exceed 3,000,000 and the price paid per share does not exceed 95% of the Per Share Amount. (d) Share Issuances. EUA shall not, nor shall it permit any of its Subsidiaries to, issue, deliver or sell, or authorize or propose the issuance, delivery or sale of, any shares of its capital stock or any Option with respect thereto (other than the issuance by a wholly owned Subsidiary of its capital stock to its direct or indirect parent corporation, or modify or amend any right of any holder of outstanding shares of capital stock or Options with respect thereto). (e) Acquisitions. EUA shall not, nor shall it permit any of its Subsidiaries to acquire or agree to acquire (by merging or consolidating with, or by purchasing a substantial equity interest in or substantial portion of the assets of, or by any other manner) any business or any corporation, partnership, association or other business organization or division thereof. (f) Dispositions. EUA shall not, nor shall it permit any of its Subsidiaries to sell, lease, securitize, grant any security interest in or otherwise dispose of or encumber any of its assets or properties, other than dispositions in the ordinary course of its business consistent with past practice and having an aggregate value of less than $1,000,000 for each disposition and $5,000,000 in the aggregate. (g) Indebtedness. EUA shall not, nor shall it permit any of its Subsidiaries to incur or guarantee any indebtedness (including any debt borrowed or guaranteed or otherwise assumed, including, without limitation, the issuance of debt securities or warrants or rights to acquire debt) or enter into any "keep well" or other agreement to maintain any financial condition of another Person or enter into any arrangement having the economic effect of any of the foregoing other than (i) short-term indebtedness in the ordinary course of business consistent with past practice (such as the issuance of commercial paper -24- or the use of existing credit facilities) in amounts not exceeding the amounts set forth in Section 6.01(g) of the EUA Disclosure Letter, (ii) long-term indebtedness in connection with the refinancing of existing indebtedness either at its stated maturity or at a lower cost of funds (calculating such cost on an aggregate after-tax basis) or (iii) guarantees or "keep well" agreements in favor of wholly owned Subsidiaries of EUA in connection with the conduct of the business of such wholly owned Subsidiaries of EUA not aggregating more than $1,000,000. (h) Capital Expenditures. Except (i) as required by law or (ii) as reasonably deemed necessary by EUA after consulting with NEES following a catastrophic event, such as a major storm, EUA shall not, nor shall it permit any of its Subsidiaries to make any capital expenditures or commitments during any fiscal year that is in excess of 110% of (i) the aggregate amount set forth in Section 6.01(h) of the EUA Disclosure Letter with respect to EUA and its Subsidiaries that are public utility companies within the meaning of Section 2(a)(5) of the 1935 Act or (ii) the amount set forth in Section 6.01(h) of the EUA Disclosure Letter with respect to each of EUA's other Subsidiaries. (i) Employee Benefits. EUA shall not, nor shall it permit any of its Subsidiaries to enter into, adopt, amend (except as may be required by applicable law) or terminate any EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy between EUA or one of its Subsidiaries and one or more of its trustees, directors, officers, employees or former employees, or, except for normal increases in the ordinary course of business, (a) increase in any manner the compensation or fringe benefits of any trustee, director or executive officer, (b) increase in any manner the compensation or fringe benefits of any employee, (c) pay any benefit not required by any plan or arrangement in effect as of the date hereof or, (d) cause any trustee, director, officer, employee or former employee of EUA to accrue or receive additional benefits, accelerate vesting or accelerate the payment of any benefits under any EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy. EUA, prior to the Closing Date, shall take all necessary action and make all necessary amendments to its stock-based plans so that all such plans will be in a form that allows the plans to function after the Effective Time and after any merger of EUA and its Subsidiaries into NEES or its Subsidiaries. EUA, prior to the Closing Date, shall take all necessary actions, in a manner satisfactory to NEES, so that on or after the Closing Date, neither EUA, the Surviving Entity nor their affiliates' stock or securities will be required to be held in, or distributed pursuant to, any EUA Employee Benefit Plan. (j) Labor Matters. Notwithstanding any other provision of this Agreement to the contrary, EUA or its Subsidiaries may negotiate successor collective bargaining agreements to those referenced in Section 4.12 hereof, and may negotiate other collective bargaining agreements or arrangements as required by law or for the purpose of implementing the agreements referenced in Section 4.12 hereof. EUA will keep NEES informed as to the status of, and will consult with NEES as to the strategy for, all negotiations with collective bargaining representatives. EUA and its Subsidiaries shall act prudently and reasonably and consistent with their obligation under applicable law in such negotiations. -25- (k) Discharge of Liabilities. EUA shall not, nor shall it permit its Subsidiaries to, pay, discharge or satisfy any material claims, liabilities or obligations (absolute, accrued, asserted or unasserted, contingent or otherwise), other than the payment, discharge or satisfaction, in the ordinary course of business consistent with past practice (which includes the payment of final and unappealable judgments) or in accordance with their terms, of liabilities reflected or reserved against in, or contemplated by, the most recent consolidated financial statements (or the notes thereto) of such party included in EUA SEC Reports, or incurred in the ordinary course of business consistent with past practice. (l) Contracts. EUA shall not, nor shall it permit its Subsidiaries, except in the ordinary course of business consistent with past practice or as set forth in Section 6.01(l) of the EUA Disclosure Letter, (i) to modify, amend, terminate or fail to use commercially reasonable efforts to renew any material Contract to which EUA or any of its Subsidiaries is a party or waive, release or assign any material rights or claims or (ii) to enter into any new material Contracts except as expressly permitted by Sections 6.01 (f), (g) or (i) and 7.06 hereof. (m) Equity Investments. EUA shall not, nor shall it permit its Subsidiaries or affiliates to, make equity contributions to non-affiliates or to its non-utility Subsidiaries. (n) Loans. EUA shall not, nor shall it permit its Subsidiaries or affiliates to, loan money to non-affiliates or to its non-utility Subsidiaries. (o) Year 2000. EUA, within 15 days of the date of this Agreement, shall engage a qualified third party ("Y2K Consultant") to conduct a detailed assessment of the adequacy and state of completion of its Year 2000 Program, including but not limited to assessment and testing of its customer, accounting, and operational systems. The Y2K Consultant and scope of work of the Y2K Consultant shall be acceptable to NEES. Such assessment and testing shall be completed as soon thereafter as practicable. EUA shall have such assessment updated by the Y2K Consultant at the end of each fiscal quarter of 1999. EUA shall allow designated NEES personnel and representatives access to the Y2K Consultant's personnel, reports and recommendations and access to EUA's personnel, documents, and information related to the Y2K issue. EUA and the third party shall meet with such designated NEES personnel and representatives on a periodic basis (but not less frequently than monthly) to update NEES on EUA's Year 2000 Program. If this Agreement is terminated pursuant to Section 9.01 hereof, NEES shall reimburse EUA for the costs and expenses of the Y2K Consultant. (p) Insurance. EUA shall, and shall cause its Subsidiaries to, maintain with financially responsible insurance companies (or through self-insurance, consistent with past practice) insurance in such amounts and against such risks and losses as are customary for companies engaged in their respective businesses. (q) 1935 Act. EUA shall not, nor shall it permit any of its Subsidiaries to, engage in any activities which would cause a change in its status, or that of its Subsidiaries, under the 1935 Act. -26- (r) Regulatory Matters. Subject to applicable law and except for non-material filings in the ordinary course of business consistent with past practice, EUA shall consult with NEES prior to implementing any changes in its or any of its Subsidiaries' rates or charges, standards of service or accounting or executing any agreement with respect thereto that is otherwise permitted under this Agreement and shall, and shall cause its Subsidiaries to, deliver to NEES a copy of each such filing or agreement at least four (4) business days prior to the filing or execution thereof so that NEES may comment thereon. EUA shall, and shall cause its Subsidiaries to, make all such filings (i) only in the ordinary course of business consistent with past practice or (ii) as required by a Governmental Authority or regulatory agency with appropriate jurisdiction. (s) Accounting. EUA shall not, nor shall it permit any of its Subsidiaries to make any changes in their accounting methods, policies or procedures, except as required by law, rule, regulation or applicable generally accepted accounting principles; (t) Tax Status. Neither EUA nor any of its Subsidiaries shall (i) make or rescind any material express or deemed election relating to Taxes, (ii) make a request for a Tax Ruling or enter into a Closing Agreement, (iii) settle or compromise any material claim, action, suit, litigation, proceeding, arbitration, investigation, audit, or controversy relating to Taxes or (iv) change in any material respect any of its methods of reporting income, deductions or accounting for federal income tax purposes from those employed in the preparation of its federal income Tax Return for the taxable year ending December 31, 1997, except as may be required by applicable law. (u) No Breach. EUA shall not, nor shall it permit any of its Subsidiaries to willfully take or fail to take any action that would or is reasonably likely to result in (i) a material breach of any provision of this Agreement or (ii) its representations and warranties set forth in this Agreement being untrue in any material respect on and as of the Closing Date. (v) Advice of Changes. EUA shall confer with NEES on a regular and frequent basis with respect to EUA's business and operations and other matters relevant to the Merger to the extent permitted by law, and shall promptly advise NEES, orally and in writing, of any material change or event, including, without limitation, any complaint, investigation or hearing by any Governmental Authority (or communication indicating the same may be contemplated) or the institution or threat of material litigation; provided that EUA shall not be required to make any disclosure to the extent such disclosure would constitute a violation of any applicable law or regulation. (w) Notice and Cure. EUA will notify NEES in writing of, and will use all commercially reasonable efforts to cure before the Closing, any event, transaction or circumstance, as soon as practical after it becomes known to EUA, that causes or will or may be likely to cause any covenant or agreement of EUA under this Agreement to be breached or that renders or will render untrue in any material respect any representation or warranty of EUA contained in this Agreement. EUA also will notify NEES in writing of, and will use all -27- commercially reasonable efforts to cure, before the Closing, any material violation or breach, as soon as practical after it becomes known to EUA, of any representation, warranty, covenant or agreement made by EUA. No notice given pursuant to this paragraph shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein. (x) Fulfillment of Conditions. Subject to the terms and conditions of this Agreement, EUA will take or cause to be taken all commercially reasonable steps necessary or desirable and proceed diligently and in good faith to satisfy each condition to the other's obligations contained in this Agreement and to consummate and make effective the Merger and other transactions contemplated by this Agreement, and EUA will not, nor will it permit any of its Subsidiaries to, take or fail to take any action that could be reasonably expected to result in the nonfulfillment of any such condition. (y) Third Party Standstill Agreements. Except as provided in Section 7.08 hereto, during the period from the date of this Agreement through the Effective Time, neither EUA nor any of its Subsidiaries shall terminate, amend, modify or waive any provision of any confidentiality or standstill agreement to which it is a party. During such period, EUA shall take all steps necessary to enforce, to the fullest extent permitted under applicable law, the provisions of any such agreement. 6.02 Covenants of NEES. At all times from and after the date hereof until the Effective Time, NEES covenants and agrees that (except as expressly contemplated or permitted by this Agreement or to the extent that EUA shall otherwise previously consent in writing): (a) No Breach. NEES shall not, nor shall it permit any of its Subsidiaries to, except as otherwise expressly provided for in this Agreement, willfully take or fail to take any action that would or is reasonably likely to result in (i) a material breach of any of its covenants or agreements contained in this Agreement or (ii) any of its representations and warranties set forth in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.06, 5.07, 5.08 and 5.09 of this Agreement being untrue in any material respect on and as of the Closing Date. (b) Advice of Changes. NEES shall confer with EUA on a regular and frequent basis with respect to any matter having, or which, insofar as can be reasonably foreseen, could reasonably be expected to have, a NEES Material Adverse Effect or materially impair the ability of NEES to consummate the Merger and other transactions contemplated hereby; provided that NEES shall not be required to make any disclosure to the extent such disclosure would constitute a violation of any applicable law or regulation. (c) Notice and Cure. NEES will notify EUA in writing of, and will use all commercially reasonable efforts to cure before the Closing, any event, transaction or circumstance, as soon as practical after it becomes known to NEES, that causes or will or may be likely to cause any covenant or agreement of NEES under this Agreement to be breached or that renders or will render -28- untrue in any material respect any representation or warranty of NEES contained in this Agreement. NEES also will notify EUA in writing of, and will use all commercially reasonable efforts to cure before the Closing, any material violation or breach, as soon as practical after it becomes known to such party, of any representation, warranty, covenant or agreement made by NEES. No notice given pursuant to this paragraph shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein. (d) Fulfillment of Conditions. Subject to the terms and conditions of this Agreement, NEES will take or cause to be taken all commercially reasonable steps necessary or desirable and proceed diligently and in good faith to satisfy each condition to its obligations contained in this Agreement and to consummate and make effective the Merger and other transactions contemplated by this Agreement, and NEES will not, nor will it permit any of its Subsidiaries to, take or fail to take any action that could be reasonably expected to result in the nonfulfillment of any such condition. (e) Conduct of Business of LLC. Prior to the Effective Time, except as may be required by applicable law and subject to the other provisions of this Agreement, NEES shall cause LLC to (i) perform its obligations under this Agreement in accordance with its terms, and (ii) not engage directly or indirectly in any business or activities of any type or kind and not enter into any agreements or arrangements with any person, or be subject to or bound by any obligation or undertaking, which is inconsistent with this Agreement. (f) Certain Mergers. NEES shall not, and shall not permit any of its Subsidiaries to, acquire or agree to acquire by merging or consolidating with, or by purchasing a substantial portion of the assets of or equity in, or by any other manner, any business or any corporation, partnership, association or other business organization or division thereof, or otherwise acquire or agree to acquire any assets if the entering into of a definitive agreement relating to or the consummation of such acquisition, merger or consolidation could reasonably be expected to (i) impose any material delay in the obtaining of, or significantly increase the risk of not obtaining, any authorizations, consents, orders, declarations or approvals of any Governmental Authority necessary to consummate the Merger or the expiration or termination of any applicable waiting period, (ii) significantly increase the risk of any Governmental Authority entering an order prohibiting the consummation of the Merger, (iii) significantly increase the risk of not being able to remove any such order on appeal or otherwise or (iv) materially delay the consummation of the Merger. 6.03 Additional Covenants by NEES and EUA. (a) Control of Other Party's Business. Nothing contained in this Agreement shall give NEES, directly or indirectly, the right to control or direct EUA's operations prior to the Effective Time. Nothing contained in this Agreement shall give EUA, directly or indirectly, the right to control or direct NEES' operations prior to the Effective Time. Prior to the Effective Time, each of EUA and NEES shall exercise, consistent with the terms and conditions of this Agreement, complete control and supervision over its respective operations. -29- (b) Transition Steering Team. As soon as reasonably practicable after the date hereof, NEES and EUA shall create a special transition steering team, with representation from EUA and NEES, that will develop recommendations concerning the future structure and operations of EUA after the Effective Time, subject to applicable law. The members of the transition steering team shall be appointed by the Chief Executive Officers of NEES and EUA. The functions of the transition steering team shall include (i) to direct the exchange of information and documents between the parties and their Subsidiaries as contemplated by Section 7.01 and (ii) the development of regulatory plans and proposals, corporate organizational and management plans, workforce combination proposals, and such other matters as they deem appropriate. ARTICLE VII ADDITIONAL AGREEMENTS 7.01 Access to Information. EUA shall, and shall cause each of its Subsidiaries to, and shall use commercially reasonable efforts to cause EUA Associates to, throughout the period from the date hereof to the Effective Time to the extent permitted by law, (i) provide NEES and its Representatives with full access, upon reasonable prior notice and during normal business hours, to all facilities, operations, officers (including EUA's environmental, health and safety personnel), employees, agents and accountants of EUA and its Subsidiaries and Associates and their respective assets, properties, books and records, to the extent EUA or any Subsidiary of EUA or EUA Associate is not under a legal obligation not to provide access or to the extent that such access would not constitute a waiver of the attorney client privilege and does not unreasonably interfere with the business and operations of EUA and its Subsidiaries and Associates and (ii) furnish promptly to such persons (x) a copy of each report, statement, schedule and other document filed or received by EUA or any of its Subsidiaries pursuant to the requirements of federal or state securities laws and each material report, statement, schedule and other document filed with any other Governmental Authority, and (y) all other information and data (including, without limitation, copies of Contracts, EUA Employee Benefit Plans, and other books and records) concerning the business and operations of EUA and its Subsidiaries as NEES or any of its Representatives reasonably may request. No review pursuant to this Section 7.01 or otherwise shall affect any representation or warranty contained in this Agreement or any condition to the obligations of the parties hereto. Any such information or material obtained pursuant to this Section 7.01 that constitutes "Evaluation Material" (as such term is defined in the letter agreement dated as of December 18, 1998 between EUA and NEES (the "Confidentiality Agreement")) shall be governed by the terms of the Confidentiality Agreement. NEES may provide information or materials that it obtains relating to EUA or any EUA Subsidiary pursuant to this Section 7.01 to National Grid Group; the treatment by National Grid Group of such information or material shall be governed by the terms of the letter agreement dated as of December 21, 1998 between EUA and National Grid Group. 7.02 Proxy Statement. As soon as reasonably practicable after the date of this Agreement, EUA shall prepare and file the Proxy Statement with the -30- SEC. NEES and EUA shall cooperate with each other in the preparation of the Proxy Statement and any amendment or supplement thereto, and EUA shall promptly notify NEES of the receipt of any comments of the SEC with respect to the Proxy Statement and of any requests by the SEC for any amendment or supplement thereto or for additional information, and shall promptly provide to NEES copies of all correspondence between EUA or any of its Representatives and the SEC with respect to the Proxy Statement (except reports from financial advisors other than with the consent of such financial advisors). Each of the parties hereto shall furnish all information concerning itself which is required or customary for inclusion in the Proxy Statement. EUA shall consult with NEES regarding the Proxy Statement and have due regard to any comments NEES may make in relation to the Proxy Statement. EUA shall give NEES and its counsel the opportunity to review the Proxy Statement and all responses to requests for additional information by and replies to comments of the SEC before their being filed with, or sent to, the SEC. Each of EUA and NEES agrees to use its reasonable best efforts, after consultation with the other parties hereto, to respond promptly to all such comments of and requests by the SEC. After obtaining the consent of EUA, which consent shall not be unreasonably withheld, NEES may provide information supplied to NEES by EUA to National Grid Group for inclusion of such information in the Super Class 1 circular ("NGG Circular") to be issued to shareholders of National Grid Group in connection with approval by such shareholders of the National Grid Merger Agreement. NEES shall use its best efforts to provide EUA with a draft of any portion of the NGG Circular with information relating to EUA prior to the issuance of the NGG Circular. 7.03 Approval of Shareholders. EUA shall, through its Board of Trustees, duly call, give notice of, convene and hold a meeting of its shareholders (the "EUA Shareholders' Meeting") for the purpose of voting on the approval of the Merger and other transactions contemplated hereby (the "EUA Shareholders' Approval") as soon as reasonably practicable after the date hereof; provided, however, subject to the fiduciary duties of its Board of Trustees and the requirements of applicable law, EUA shall include in the Proxy Statement the recommendation of the Board of Trustees of EUA that the Shareholders of EUA approve the Merger and the other transactions contemplated hereby, and shall use its reasonable best efforts to obtain such approval. 7.04 Regulatory and Other Approvals. (a) HSR Filings. Each party hereto shall file or cause to be filed with the Federal Trade Commission and the Department of Justice any notifications required to be filed by its respective "ultimate parent" company under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"), and the rules and regulations promulgated thereunder with respect to the Merger and other transactions contemplated hereby. Such parties will use all commercially reasonable efforts to make such filings in a timely manner and to respond on a timely basis to any requests for additional information made by either of such agencies. (b) Other Regulatory Approvals. Each party shall cooperate and use its best efforts to promptly prepare and file all necessary applications, notices, petitions, filings and other documents with, and to use all commercially reasonable efforts to obtain all necessary permits, consents, approvals and authorizations of, all Governmental Authorities necessary or -31- advisable to obtain the EUA Required Statutory Approvals, the NEES Required Statutory Approvals and the approvals of the state utility commissions referred to in Section 8.01(d) (collectively, the "NEES-EUA Regulatory Approvals"). The parties agree that they will consult with each other with respect to obtaining the NEES-EUA Regulatory Approvals; provided, however, that NEES shall have primary responsibility for the preparation and filing of any related applications, filings or other material with the SEC, the FERC, the NRC and state utility commissions. EUA shall have the right to review and approve in advance drafts of and final applications, filings and other material (including material with respect to proposed settlements) submitted to or filed with the SEC, the FERC, the NRC and state utility commissions or parties to such proceedings before such Governmental Authority, which approval shall not be unreasonably withheld or delayed. (c) NEES-NGG Regulatory Proceedings. EUA and NEES acknowledge that, at the same time EUA and NEES will be seeking to obtain the NEES-EUA Regulatory Approvals, National Grid Group and NEES will be seeking to obtain the regulatory approvals (the "NEES-NGG Regulatory Approvals") required to consummate the transactions contemplated by the National Grid Merger Agreement. NEES and EUA agree to seek to prosecute the proceedings relating to the NEES-EUA Regulatory Approvals (the "NEES-EUA Regulatory Proceedings") separately from the prosecution by National Grid Group and NEES of the proceedings relating to the NEES-NGG Regulatory Approvals (the "NEES-NGG Regulatory Proceedings"), but recognize that one or more of the NEES-EUA Regulatory Proceedings may be consolidated with one or more of the NEES-NGG Regulatory Proceedings by the relevant Governmental Authority. Upon the request of EUA, NEES will keep EUA reasonably apprised of the status of the NEES-NGG Regulatory Proceedings. 7.05 Employee Benefit Plans. (a) For a period of twelve (12) months immediately following the Closing Date, the compensation, benefits and coverage provided to those non-union individuals who continue to be employees of the Surviving Entity (the "Affected Employees") pursuant to employee benefit plans or arrangements maintained by NEES or the Surviving Entity shall be, in the aggregate, not less favorable (as determined by NEES and the Surviving Entity using reasonable assumptions and benefit valuation methods) than those provided, in the aggregate, to such Affected Employees immediately prior to the Closing Date. In addition to the foregoing, NEES shall, or shall cause the Surviving Entity to, pay any Affected Employee whose employment is terminated by NEES or the Surviving Entity within twelve (12) months of the Closing Date a severance benefit package equivalent to the severance benefit package that would be provided under the NEES Standard Severance Plan as in effect on the date hereof. (b) NEES shall, or shall cause the Surviving Entity to, give the Affected Employees full credit for purposes of eligibility, vesting, benefit accrual (including, without limitation, benefit accrual under any defined benefit pension plans) and determination of the level of benefits under any employee benefit plans or arrangements maintained by NEES or the Surviving Entity in effect as of the Closing Date for such Affected Employees' service with EUA or any Subsidiary of EUA (or any prior employer) to the same extent -32- recognized by EUA or such Subsidiary immediately prior to the Closing Date. With respect to any employee benefit plan or arrangement established by NEES, EUA or the Surviving Entity after the Closing Date (the "Post Closing Plans"), service shall be credited in accordance with the terms of such Post Closing Plans. (c) NEES shall, or shall cause the Surviving Entity to, (i) waive all limitations as to preexisting conditions, exclusions and waiting periods with respect to participation and coverage requirements applicable to the Affected Employees under any welfare benefit plan established to replace any EUA welfare benefit plans in which such Affected Employees may be eligible to participate after the Closing Date, other than limitations or waiting periods that are already in effect with respect to such Affected Employees and that have not been satisfied as of the Closing Date under any welfare plan maintained for the Affected Employees immediately prior to the Closing Date, and (ii) provide each Affected Employee with credit for any co-payments and deductibles paid prior to the Closing Date in satisfying any applicable deductible or out-of-pocket requirements under any welfare plans that such Affected Employees are eligible to participate in after the Closing Date. (d)(i) NEES shall, or shall cause the Surviving Entity and its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving Entity and its Subsidiaries under, all EUA Employee Benefit Plans as in effect on the date hereof; provided, however, that this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity from exercising their rights with respect to all EUA Employee Benefit Plans solely in accordance with their terms, including but not limited to the right to alter, terminate or otherwise amend such EUA Employee Benefit Plans. (ii) NEES shall, or shall cause the Surviving Entity and its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving Entity and its Subsidiaries under, (A) all employment severance, consulting and retention agreements or arrangements as in effect on the date hereof, as set forth in Section 7.05(d)(ii) of the EUA Disclosure Letter, or as modified in accordance with Section 6.01(i) of the EUA Disclosure Letter (such agreements or arrangements, the "EUA Employee Agreements" and the individuals who are parties to such EUA Employee Agreements, the "EUA Executives") and (B) all EUA Employee Benefit Plans in which such EUA Executives participate; provided, however, that this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity from exercising their rights with respect to the EUA Employee Agreements and the EUA Employee Benefit Plans in which such EUA Executives participate, in each case solely in accordance with their terms, including but not limited to the right to alter, terminate or otherwise amend such EUA Employee Agreements and EUA Employee Benefit Plans. (e) Notwithstanding the foregoing, NEES and the Surviving Entity and its subsidiaries shall neither be required to or prevented from merging EUA's benefit plans, agreements, or arrangements into NEES or the Surviving Entity and its subsidiaries benefit plans, agreements, or arrangements or from -33- replacing EUA's benefit plans, agreements or arrangements with NEES or the Surviving Entity and its subsidiaries benefit plans, agreements or arrangements. 7.06 Labor Agreements and Workforce Matters. (a) Labor Agreements. NEES shall honor, or shall cause the appropriate subsidiaries of the Surviving Entity to honor, all collective bargaining agreements of EUA or its subsidiaries in effect as of the Effective Time until their expiration; provided, however, that this undertaking is not intended to prevent NEES or the Surviving Entity and its subsidiaries from exercising their rights with respect to such collective bargaining agreements and in accordance with their terms, including any right to amend, modify, suspend, revoke or terminate any such contract, agreement, collective bargaining agreement or commitment or portion thereof. (b) Workforce Matters. Subject to applicable law and obligations under applicable collective bargaining agreements, for a period of 2 years following the Effective Time, any reductions in workforce in respect of employees of the Surviving Entity and its Subsidiaries shall be made on a fair and equitable basis as determined by the Surviving Entity, with due consideration to prior experience and skills, and any employee whose employment is terminated or job is eliminated during such period shall be entitled to participate on a fair and equitable basis as determined by NEES or the Surviving Entity in the job opportunity and employment placement programs offered by NEES or the Surviving Entity or any of their Subsidiaries for which they are eligible. Any workforce reductions carried out following the Effective Time by the Surviving Entity and its Subsidiaries shall be done in accordance with all applicable collective bargaining agreements and all laws and regulations governing the employment relationship and termination thereof including, without limitation, the Worker Adjustment and Retraining Notification Act, and the regulations promulgated thereunder, and any comparable state or local law. 7.07 Post Merger Operations. (a) NEES Advisory Board. If the Merger is consummated, then, promptly following the closing of the merger contemplated by the National Grid Merger Agreement, NEES shall take such action as is necessary to cause all of the members of the Board of Directors of EUA to be appointed to serve on the advisory board to be formed pursuant to Section 7.07(e) of the National Grid Merger Agreement. (b) Charities. The parties agree that provision of charitable contribution and community support within the New England region serves a number of important goals. After the Effective Time, NEES intends to cause the Surviving Entity to provide charitable contributions and community support within the New England region at annual levels substantially comparable to the annual level of charitable contributions and community support provided, directly or indirectly, by EUA and its public utility subsidiaries within the New England region during 1998. -34- 7.08 No Solicitations. Prior to the Effective Time, EUA agrees: (a) that neither it nor any of its Subsidiaries shall, and it shall use its best efforts to cause its Representatives (as defined in Section 10.10) not to, knowingly initiate, solicit or encourage, directly or indirectly, any inquiries or any proposal or offer (including, without limitation, any proposal or offer to its Shareholders) with respect to a merger, consolidation or other business combination including EUA or any of its significant Subsidiaries (as defined in Rule 1-02(W) of Regulation S-X promulgated under the Exchange Act) other than EUA Cogenex Corporation (an "EUA Significant Subsidiary"), or any acquisition or similar transaction (including, without limitation, a tender or exchange offer) involving the purchase of (i) all or any significant portion of the assets of EUA and its Subsidiaries taken as a whole, (ii) ten percent or more of the outstanding EUA Shares or (iii) 50% or more of the outstanding shares of the capital stock of any EUA Significant Subsidiary (any such proposal or offer being hereinafter referred to as an "Alternative Proposal"), or engage in any negotiations concerning, or provide any confidential information or data to, or have any other discussions with, any person or group relating to an Alternative Proposal, or otherwise knowingly facilitate any effort or attempt to make or implement an Alternative Proposal other than from NEES and its affiliates; (b) that it will immediately cease and cause to be terminated any existing activities, discussions or negotiations with any parties with respect to any Alternative Proposal; and (c) that it will notify NEES immediately if any such inquiries, proposals or offers are received by, any such information is requested from, or any such negotiations or discussions are sought to be initiated or continued with, it or any of such persons; provided, however, that, prior to receipt of the EUA Shareholders' Approval, nothing contained in this Section 7.08 shall prohibit the Board of Trustees of EUA from (i) furnishing information to (but only pursuant to a confidentiality agreement in customary form and having terms and conditions no less favorable to EUA than the Confidentiality Agreement (as defined in Section 7.01)) or entering into discussions or negotiations with any person or group that makes an unsolicited Alternative Proposal, if, and only to the extent that, (A) the Board of Trustees of EUA, based upon advice of outside counsel with respect to fiduciary duties, determines in good faith that such action is necessary for the Board of Trustees to act in a manner consistent with its fiduciary duties to Shareholders under applicable law, (B) the Board of Trustees of EUA has reasonably concluded in good faith (after consultation with its financial advisors) that the person or group making such Alternative Proposal will have adequate sources of financing to consummate such Alternative Proposal and that such Alternative Proposal is likely to be more favorable to EUA's shareholders than the Merger, (C) prior to furnishing such information to, or entering into discussions or negotiations with, such person or group, EUA provides written notice to NEES to the effect that it is furnishing information to, or entering into discussions or negotiations with, such person or group, which notice shall identify such person or group and the material terms of the Alternative Proposal in reasonable detail, and (D) EUA keeps NEES promptly informed of the status and all material information with respect to any such discussions or negotiations; and (ii) to the extent required, complying with Rule 14e-2 promulgated under the Exchange Act with regard to an Alternative Proposal. Nothing in this Section 7.08 shall (x) permit EUA to terminate this Agreement (except as specifically provided in Article IX), (y) permit EUA to enter into any agreement with respect to an Alternative Proposal for so long as this Agreement remains in effect (it being agreed that for so long as this Agreement remains in effect, EUA shall not enter -35- into any agreement with any person or group that provides for, or in any way knowingly facilitates, an Alternative Proposal (other than a confidentiality agreement under the circumstances described above)), or (z) affect any other obligation of EUA under this Agreement. 7.09 Directors' and Officers' Indemnification and Insurance. (a) Indemnification. To the extent, if any, not provided by an existing right of indemnification or other agreement or policy, from and after the Effective Time, NEES shall, or shall cause the Surviving Entity to, to the fullest extent permitted by applicable law, indemnify, defend and hold harmless each person who is now, or has been at any time prior to the date hereof, or who becomes prior to the Effective Time, (x) an officer, trustee or director or (y) an employee covered as of the date hereof (to the extent of the coverage extended as of the date hereof) of EUA or any Subsidiary of EUA (each an "Indemnified Party," and collectively, the "Indemnified Parties") against (i) all losses, expenses (including reasonable attorney's fees and expenses), claims, damages or liabilities or, subject to the first proviso of the next succeeding sentence, amounts paid in settlement, arising out of actions or omissions occurring at or prior to the Effective Time (and whether asserted or claimed prior to, at or after the Effective Time) that are, in whole or in part, based on or arising out of the fact that such person is or was a director, trustee, officer or employee of EUA or any Subsidiary of EUA (the "Indemnified Liabilities"), and (ii) all Indemnified Liabilities to the extent they are based on or arise out of or pertain to the transactions contemplated by this Agreement, in each case, to the extent permitted by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter. In the event of any such loss, expense, claim, damage or liability (whether or not arising before the Effective Time), (i) NEES shall, or shall cause the Surviving Entity to, pay the reasonable fees and expenses of counsel selected by the Indemnified Parties, which counsel shall be reasonably satisfactory to NEES or the Surviving Entity, as appropriate, promptly after statements therefor are received and otherwise advance to such Indemnified Party upon request, reimbursement of documented expenses reasonably incurred, in either case to the extent not prohibited by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter upon receipt of an undertaking by or on behalf of such director, trustee or officer to repay such amounts as and to the extent required by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter, (ii) the Surviving Entity shall cooperate in the defense of any such matter and (iii) any determination required to be made with respect to whether an Indemnified Party's conduct complies with the standards set forth under the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter and the certificate of incorporation or by-laws or similar governing documents of the Surviving Entity shall be made by independent counsel mutually acceptable to the Surviving Entity and the Indemnified Party; provided, however, that the Surviving Entity shall not be liable for any settlement effected without its written consent (which consent shall not be unreasonably withheld) and provided further that no indemnification shall be made if such indemnification is prohibited by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter. -36- (b) Insurance. For a period of six years after the Effective Time, NEES and the Surviving Entity at NEES's election, (i) shall cause to be maintained in effect an extended reporting period for current policies of directors' and officers' liability insurance for the benefit of such persons who are currently covered by such policies of EUA on terms no less favorable than the terms of such current insurance coverage or (ii) shall provide tail coverage for such persons which provides such persons with coverage for a period of six years for acts prior to the Effective Time on terms no less favorable than the terms of such current insurance coverage. (c) Successors. In the event the Surviving Entity or any of its successors or assigns (i) consolidates with or merges into any other person or entity and shall not be the continuing or surviving corporation or entity of such consolidation or merger or (ii) transfers all or substantially all of its properties and assets to any person or entity, then and in either such case, proper provisions shall be made so that the successors and assigns of the Surviving Entity, as applicable, shall assume the obligations set forth in this Section 7.09. (d) Survival of Indemnification. To the fullest extent permitted by law, from and after the Effective Time, all rights to indemnification as of the date hereof in favor of the employees, agents, directors, trustees and officers of EUA and EUA's Subsidiaries with respect to their activities as such prior to the Effective Time, as provided in the EUA Trust Agreement or the respective certificates of incorporation and by-laws or similar governing documents in effect on the date hereof, or otherwise in effect on the date hereof, shall survive the Merger and shall continue in full force and effect for a period of not less than six years from the Effective Time. (e) Benefit. The provisions of this Section 7.09 are intended to be for the benefit of, and shall be enforceable by, each Indemnified Party, his or her heirs and his or her representatives. (f) Amendment of the EUA Trust Agreement. NEES shall not, and shall ensure that the Surviving Entity shall not, amend the EUA Trust Agreement to in any way limit the indemnification provided to the Indemnified Parties under this Section 7.09. 7.10 Expenses. Except as set forth in Section 9.03, whether or not the Merger is consummated, all costs and expenses incurred in connection with the Merger and other transactions contemplated hereby shall be paid by the party incurring such cost or expense, except that the filing fees in connection with the filings required under the HSR Act and the 1935 Act shall be paid by NEES. 7.11 Brokers or Finders. EUA represents, as to itself and its affiliates, that no agent, broker, investment banker, financial advisor or other firm or person is or will be entitled to any broker's, finder's or investment banker's fee or any other commission or similar fee in connection with the Merger and other transactions contemplated by this Agreement except Salomon Smith Barney Inc., whose fees and expenses will be paid by EUA in accordance with EUA's agreement with such firm, and EUA shall indemnify and hold NEES harmless from and against any and all claims, liabilities or obligations with -37- respect to any other such fee or commission or expenses related thereto asserted by any person on the basis of any act or statement alleged to have been made by EUA or its affiliates. 7.12 Anti-Takeover Statutes. If any "fair price", "moratorium", "business combination", "control share acquisition" or other form of anti-takeover statute or regulation shall become applicable to the Merger or other transactions contemplated hereby, EUA and the members of the Board of Trustees of EUA shall grant such approvals and take such actions consistent with their fiduciary duties and in accordance with applicable law as are reasonably necessary so that the Merger and other transactions contemplated hereby may be consummated as promptly as practicable on the terms contemplated hereby and otherwise act to eliminate or minimize the effects of such statute or regulation on the Merger and other transactions contemplated hereby. 7.13 Public Announcements. Except as otherwise required by law or the rules of any applicable securities exchange or national market system or any other Regulatory Authority, so long as this Agreement is in effect, NEES and EUA will not, and will not permit any of their respective Subsidiaries or Representatives to, issue or cause the publication of any press release or make any other public announcement with respect to the Merger and other transactions contemplated by this Agreement without the consent of the other party, which consent shall not be unreasonably withheld. NEES and EUA will cooperate with each other in the development and distribution of all press releases and other public announcements with respect to the Merger and other transactions contemplated hereby, and will furnish the other with drafts of any such releases and announcements as far in advance as practicable. 7.14 Restructuring of the Merger. It may be preferable to effectuate a business combination between NEES and EUA by means of an alternative structure to the Merger. Accordingly, if, prior to satisfaction of the conditions contained in Article VIII hereto, NEES proposes the adoption of an alternative structure that otherwise substantially preserves for NEES and EUA the economic benefits of the Merger and will not materially delay the consummation thereof, then the parties shall use their respective best efforts to effect a business combination among themselves by means of a mutually agreed upon structure other than the Merger that so preserves such benefits; provided, however, that prior to closing any such restructured transaction, all material third party and Governmental Authority declarations, filings, registrations, notices, authorizations, consents or approvals necessary for the effectuation of such alternative business combination shall have been obtained and all other conditions to the parties' obligations to consummate the Merger and other transactions contemplated hereby, as applied to such alternative business combination, shall have been satisfied or waived. -38- ARTICLE VIII CONDITIONS 8.01 Conditions to Each Party's Obligation to Effect the Merger. The respective obligation of each party to effect the Merger and other transactions contemplated hereby is subject to the satisfaction or waiver, at or prior to the Closing, of each of the following conditions: (a) Shareholder Approval. EUA Shareholders' Approval shall have been obtained. (b) HSR Act. Any waiting period (and any extension thereof) applicable to the consummation of the Merger under HSR shall have expired or been terminated. (c) Injunctions or Restraints. No court of competent jurisdiction or other competent Governmental Authority shall have enacted, issued, promulgated, enforced or entered any law or order (whether temporary, preliminary or permanent) which is then in effect and has the effect of making illegal or otherwise restricting, preventing or prohibiting consummation of the Merger or other transactions contemplated hereby. (d) Governmental and Regulatory and Other Consents and Approvals. The NEES Required Statutory Approvals and EUA Required Statutory Approvals shall have been obtained prior to the Effective Time, and shall have become Final Orders (as hereinafter defined). The Final Orders shall not, individually or in the aggregate, impose terms and conditions that (i) could reasonably be expected to have an EUA Material Adverse Effect; (ii) could reasonably be expected to have a NEES Material Adverse Effect; or (iii) materially impair the ability of the parties to complete the Merger. The parties shall have received Final Orders from the Massachusetts Department of Telecommunications and Energy and the Rhode Island Public Utilities Commission pertaining to the recovery of costs (including, without limitation, transaction premium and integration costs) associated with the Merger that are materially consistent with existing policy and previous orders of such agencies. "Final Order" for all purposes of this Agreement means action by the relevant regulatory authority which has not been reversed, stayed, enjoined, set aside, annulled or suspended with respect to which any waiting period prescribed by law before the Merger and other transactions contemplated hereby may be consummated has expired, and as to which all conditions to be satisfied before the consummation of such transactions prescribed by law, regulation or order have been satisfied. 8.02 Conditions to Obligation of NEES and LLC to Effect the Merger. The obligation of NEES and LLC to effect the Merger and other transactions contemplated hereby is further subject to the satisfaction or waiver at or prior to the Closing, of each of the following additional conditions (all or any of which may be waived in whole or in part by NEES and LLC in the sole discretion): -39- (a) Representations and Warranties. The representations and warranties made by EUA in this Agreement, in each case made as if none of such representations or warranties contained any qualification or limitation as to "materiality" or "EUA Material Adverse Effect", shall be true and correct as so made as of the Closing Date as though so made on and as of the Closing Date, except to the extent expressly given as of a specified date, except where the failure of such representations and warranties to be true and correct as so made does not have and could not reasonably be expected to have, individually or in the aggregate, an EUA Material Adverse Effect, and EUA shall have delivered to NEES a certificate, dated the Closing Date and executed in the name and on behalf of EUA by its Chairman of the Board, President or any Executive or Senior Vice President, to such effect. (b) Performance of Obligations. EUA shall have performed and complied with, in all material respects, each agreement, covenant and obligation required by this Agreement to be so performed or complied with by EUA at or prior to the Closing, and EUA shall have delivered to NEES a certificate, dated the Closing Date and executed in the name and on behalf of EUA by its Chairman of the Board, President or any Executive or Senior Vice President, to such effect. (c) Material Adverse Effect. No EUA Material Adverse Effect shall have occurred and there shall exist no facts or circumstances which in the aggregate could reasonably be expected to have an EUA Material Adverse Effect. (d) EUA Required Consents. All EUA Required Consents shall have been obtained by EUA, except where the failure to receive such EUA Required Consents could not reasonably be expected to (i) have an EUA Material Adverse Effect, or (ii) delay or prevent the consummation of the Merger and other transactions contemplated hereby. 8.03 Conditions to Obligation of EUA to Effect the Merger. The obligation of EUA to effect the Merger and other transactions contemplated hereby is further subject to the satisfaction or waiver, at or prior to the Closing, of each of the following additional conditions (all or any of which may be waived in whole or in part by EUA in its sole discretion): (a) Representations and Warranties. The representations and warranties made by NEES and LLC in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.07, 5.08 and 5.09 of this Agreement, in each case made as if none of such representations or warranties contained any qualification or limitation as to "materiality" or "NEES Material Adverse Effect," shall be true and correct as so made as of the Closing Date, except to the extent expressly given as of a specified date and except where the failure of such representations and warranties to be so true and correct as so made does not have and could not reasonably be expected to have, individually or in the aggregate, a NEES Material Adverse Effect or a material adverse effect on LLC, and NEES and LLC shall each have delivered to EUA a certificate, dated the Closing Date and executed in the name and on behalf of NEES by any director of NEES and in the name and on behalf of LLC by a member of its management committee its Chairman of the Board, President or any Executive or Senior Vice President to such effect. -40- (b) NEES Required Consents. All NEES Required Consents shall have been obtained by NEES, except where the failure to receive such NEES Required Consents could not reasonably be expected to (i) have a NEES Material Adverse Effect or (ii) delay or prevent the consummation of the Merger and other transactions contemplated hereby. (c) Performance of Obligations. NEES and LLC shall have performed and complied with, in all material respects, each agreement, covenant and obligation required by this Agreement to be so performed or complied with by NEES or LLC at or prior to the Closing, and NEES and LLC shall each have delivered to EUA a certificate, dated the Closing Date and executed in the name and on behalf of NEES by its Chairman of the Board, President or any Executive or Senior Vice President, or on behalf of LLC by a member of its management committee to such effect. ARTICLE IX TERMINATION, AMENDMENT AND WAIVER 9.01 Termination. This Agreement may be terminated, and the Merger and other transactions contemplated hereby may be abandoned, at any time prior to the Effective Time, whether prior to or after EUA Shareholders' Approval (except as otherwise provided in Section 9.01(c) below): (a) By mutual written agreement of the Board of Directors of NEES and Board of Trustees of EUA, respectively; (b) By EUA or NEES, by written notice to the other, if the Closing Date shall not have occurred on or before December 31, 1999 (the "Initial Termination Date"); provided, however, that the right to terminate the Agreement under this Section 9.01(b) shall not be available to any party whose failure to fulfill any obligation under this Agreement has been the cause of, or resulted in, the failure of the Effective Time to occur on or before such date; and provided, further, that if on the Initial Termination Date the conditions to the Closing set forth in Section 8.01(d) shall not have been fulfilled but all other conditions to the Closing shall be fulfilled or shall be capable of being fulfilled, then the Initial Termination Date shall be extended for four (4) months beyond the Initial Termination Date (the "Extended Termination Date"); (c) By NEES, by written notice to EUA, if EUA Shareholders' Approval shall not have been obtained at a duly held meeting of such Shareholders, including any adjournments thereof; (d) By EUA or NEES, if any applicable state or federal law or applicable law of a foreign jurisdiction or any order, rule or regulation is adopted or issued that has the effect, as supported by the written opinion of outside counsel for such party, of prohibiting the Merger or other transactions contemplated hereby, or if any court of competent jurisdiction or any Governmental Authority shall have issued a nonappealable final order, judgment -41- or ruling or taken any other action having the effect of permanently restraining, enjoining or otherwise prohibiting the Merger or other transactions contemplated hereby (provided that the right to terminate this Agreement under this Section 9.01(d) shall not be available to any party that has not defended such lawsuit or other legal proceeding (including seeking to have any stay or temporary restraining order entered by any court or other Governmental Authority vacated or reversed)). (e) By EUA upon ten (10) days' prior notice to NEES if the Board of Trustees of EUA determines in good faith, that termination of this Agreement is necessary for the Board of Trustees of EUA to act in a manner consistent with its fiduciary duties to Shareholders under applicable law by reason of an unsolicited Alternative Proposal meeting the requirements of clauses (A) and (B) of Section 7.08 having been made; provided that (A) The Board of Trustees of EUA shall determine based on advice of outside counsel with respect to the Board of Trustees' fiduciary duties that notwithstanding a binding commitment to consummate an agreement of the nature of this Agreement entered into in the proper exercise of its applicable fiduciary duties, and notwithstanding all concessions which may be offered by NEES in negotiation entered into pursuant to clause (B) below, it is necessary pursuant to such fiduciary duties that the trustees reconsider such commitment as a result of such Alternative Proposal, and (B) prior to any such termination, EUA shall, and shall cause its respective financial and legal advisors to, negotiate with NEES to make such adjustments in the terms and conditions of this Agreement as would enable EUA to proceed with the Merger or other transactions contemplated hereby on such adjusted terms; and provided further that EUA's ability to terminate this Agreement pursuant to this Section 9.01(e) is conditioned upon the concurrent payment by EUA to NEES of any amounts owed by it pursuant to Section 9.03(a); (f) By EUA, by written notice to NEES, if (i) there shall have been any material breach of any representation or warranty, or any material breach of any covenant or agreement, of NEES hereunder (other than a breach described in clause (ii)), and such breach shall not have been remedied within twenty (20) days after receipt by NEES of notice in writing from EUA, specifying the nature of such breach and requesting that it be remedied; or (ii) NEES shall fail to deliver or cause to be delivered the amount of cash to the Paying Agent required pursuant to Section 2.02(a) at a time when all conditions to NEES's obligation to close have been satisfied or otherwise waived in writing by NEES. (g) By NEES, by written notice to EUA, if (i) there shall have been any material breach of any representation or warranty, or any material breach of any covenant or agreement, of EUA hereunder, and such breach shall not -42- have been remedied within twenty (20) days after receipt by EUA of notice in writing from NEES, specifying the nature of such breach and requesting that it be remedied; or (ii) the Board of Trustees of EUA (A) shall withdraw or modify in any manner adverse to NEES its approval of the Merger and other transactions contemplated hereby or its recommendation to its shareholders regarding the approval of this Agreement, the Merger and other transactions contemplated hereby, (B) shall approve or recommend or take no position with respect to an Alternative Proposal or (C) shall resolve to take any of the actions specified in clause (A) or (B). 9.02 Effect of Termination. If this Agreement is validly terminated by either EUA or NEES pursuant to Section 9.01, this Agreement shall forthwith become null and void and there shall be no liability or obligation on the part of either EUA or NEES (or any of their respective Representatives or affiliates), except that the provisions of this Section 9.02, Sections 7.10, 7.11 and 7.13, Section 9.03 and Sections 10.09 and 10.10 shall continue to apply following any such termination. 9.03 Termination Fees. (a) In the event that (i) this Agreement is terminated by EUA pursuant to Section 9.01(e) or (ii) any person or group shall have made an Alternative Proposal that has not been withdrawn and this Agreement is terminated by (A) NEES pursuant to Section 9.01(c) or Section 9.01(g) or (B) by EUA pursuant to Section 9.01(b) and, in the case of this clause (ii) only, a definitive agreement with respect to such Alternative Proposal is executed within two years after such termination, then EUA shall pay to NEES, by wire transfer of same day funds, either on the date contemplated in Section 9.01(e) if applicable, or otherwise, within five (5) business days after such termination, a termination fee of $20 million, plus an amount equal to all documented out-of-pocket expenses and fees incurred by NEES arising out of, or in connection with or related to, the Merger and other transactions contemplated hereby, not in excess of $5 million in the aggregate. (b) In the event that this Agreement is terminated by either NEES or EUA pursuant to Section 9.01(b) and at the time of such termination (i) the conditions to the Closing set forth in Section 8.01(d) shall not have been fulfilled, (ii) if the date of termination is any date other than a date which is on or after the Extended Termination Date, all conditions contained in Article VIII other than Sections 8.01(d) or 8.03(c) shall have been fulfilled or are capable of being fulfilled as of such date, and (iii) the merger contemplated by the National Grid Merger Agreement has not yet been consummated, then NEES shall pay to EUA, by wire transfer of same day funds, within five (5) business days after such termination, a termination fee of $10 million, plus an amount equal to all documented out-of-pocket expenses and fees incurred by EUA arising out of, or in connection with or related to, the Merger and other transactions contemplated hereby, not in excess of $5 million in the aggregate. (c) Nature of Fees. The parties agree that the agreements contained in this Section 9.03 are an integral part of the Merger and the other transactions contemplated hereby and constitute liquidated damages and not a penalty. The parties further agree that if any party is or becomes obligated to pay a termination fee pursuant to Sections 9.03(a) or (b), the right to receive such termination fee shall be the sole remedy of the other party with respect to -43- the facts and circumstances giving rise to such payment obligation. If this Agreement is terminated by a party as a result of a willful breach of a representation, warranty, covenant or agreement by the other party, including a termination pursuant to Section 9.01(f)(ii), the non-breaching party may pursue any remedies available to it at law or in equity and shall be entitled to recover any additional amounts thereunder. Notwithstanding anything to the contrary contained in this Section 9.03, if one party fails to promptly pay to the other any fee or expense due under this Section 9.03, in addition to any amounts paid or payable pursuant to such Section, the defaulting party shall pay the costs and expenses (including legal fees and expenses) in connection with any action, including the filing of any lawsuit or other legal action, taken to collect payment, together with interest on the amount of any unpaid fee at the publicly announced prime rate of Citibank, N.A. from the date such fee was required to be paid. 9.04 Amendment. This Agreement may be amended, supplemented or modified by action taken by or on behalf of the Board of Directors of NEES or the Board of Trustees of EUA at any time prior to the Effective Time, whether prior to or after EUA Shareholders' Approval shall have been obtained, but after such adoption and approval only to the extent permitted by applicable law. No such amendment, supplement or modification shall be effective unless set forth in a written instrument duly executed and delivered by or on behalf of each party hereto. 9.05 Waiver. At any time prior to the Effective Time, NEES or EUA, by action taken by or on behalf of its Board of Directors or Board of Trustees, respectively, may to the extent permitted by applicable law (i) extend the time for the performance of any of the obligations or other acts of the other parties hereto, (ii) waive any inaccuracies in the representations and warranties of the other parties hereto contained herein or in any document delivered pursuant hereto or (iii) waive compliance with any of the covenants, agreements or conditions of the other parties hereto contained herein. No such extension or waiver shall be effective unless set forth in a written instrument duly executed by or on behalf of the party extending the time of performance or waiving any such inaccuracy or non-compliance. No waiver by any party of any term or condition of this Agreement, in any one or more instances, shall be deemed to be or construed as a waiver of the same or any other term or condition of this Agreement on any future occasion. ARTICLE X GENERAL PROVISIONS 10.01 Non-Survival of Representations, Warranties, Covenants and Agreements. The representations, warranties, covenants and agreements contained in this Agreement or in any instrument delivered pursuant to this Agreement shall not survive the Merger but shall terminate at the Effective Time, except for the agreements contained in Article I and Article II, in Sections 7.05, 7.06, 7.08, 7.09 and 7.10, this Article X which shall survive the Effective Time. 10.02 Notices. All notices, requests and other communications hereunder must be in writing and will be deemed to have been duly given only if -44- delivered personally or by facsimile transmission or sent by overnight courier (providing proof of delivery) to the parties at the following addresses or facsimile numbers: If to NEES or LLC, to: New England Electric System 25 Research Drive Westborough, MA 01582 Attn: Richard P. Sergel President and Chief Executive Officer Telephone: (508) 389-2764 Facsimile: (508) 366-5498 with a copy to: Skadden, Arps, Slate, Meagher & Flom LLP 919 Third Avenue New York, NY 10022 Attn: Sheldon S. Adler, Esq. Telephone: (212) 735-3000 Facsimile: (212) 735-2000 If to EUA, to: Eastern Utilities Associates One Liberty Square Boston, MA 02109 Attn: Donald G. Pardus Chairman and Chief Executive Officer Telephone: (617) 357-9590 Facsimile: (617) 357-7320 with a copy to: Winthrop, Stimson, Putnam & Roberts 1 Battery Park Plaza New York, NY 10004 Attn: David P. Falck Telephone: (212) 858-1000 Facsimile: (212) 858-1500 All such notices, requests and other communications will (i) if delivered personally to the address as provided in this Section, be deemed given -45- upon delivery, (ii) if delivered by facsimile transmission to the facsimile number as provided in this Section, be deemed given when sent, provided that the facsimile is promptly confirmed by telephone confirmation thereof, and (iii) if delivered by mail in the manner described above to the address as provided in this Section, be deemed given one business day after delivery (in each case regardless of whether such notice, request or other communication is received by any other person to whom a copy of such notice, request or other communication is to be delivered pursuant to this Section). Any party from time to time may change its address, facsimile number or other information for the purpose of notices to that party by giving notice specifying such change to the other parties hereto. 10.03 Entire Agreement; Incorporation of Exhibits. (a) This Agreement supersedes all prior discussions and agreements, both written and oral, among the parties hereto with respect to the subject matter hereof, other than the Confidentiality Agreement, which shall survive the execution and delivery of this Agreement in accordance with its terms, and contains, together with the Confidentiality Agreement, the sole and entire agreement among the parties hereto with respect to the subject matter hereof. (b) The EUA Disclosure Letter, the NEES Disclosure Letter and any Exhibit attached to this Agreement and referred to herein are hereby incorporated herein and made a part hereof for all purposes as if fully set forth herein. 10.04 No Third Party Beneficiary. The terms and provisions of this Agreement are intended solely for the benefit of each party hereto and their respective successors or permitted assigns, and except as provided in Article II and Sections 7.04, 7.05(d)(ii) and 7.09 (which is intended to be for the benefit of the persons entitled to therein, and may be enforced by any of such persons), it is not the intention of the parties to confer third-party beneficiary rights upon any other person. 10.05 No Assignment; Binding Effect. Neither this Agreement nor any right, interest or obligation hereunder may be assigned, in whole or in part, by operation of law or otherwise, by any party hereto without the prior written consent of the other parties hereto and any attempt to do so will be void, except that LLC may assign any or all of its rights, interests and obligations hereunder to another direct or indirect wholly owned Subsidiary of NEES, provided that any such Subsidiary agrees in writing to be bound by all of the terms, conditions and provisions contained herein and provided further that such assignment (i) does not require a greater vote for EUA's Shareholder Approval, (ii) does not require a subsequent vote following EUA's Shareholders Meeting, or (iii) is not reasonably likely to materially delay or prevent EUA, LLC and NEES, as appropriate, from obtaining EUA Required Statutory Approvals, EUA Required Consents, EUA Shareholders' Approval, the NEES Required Shareholders' Approvals, or the NEES Required Consents. Subject to the preceding sentence, this Agreement is binding upon, inures to the benefit of and is enforceable by the parties hereto and their respective successors and assigns. -46- 10.06 Headings. The headings used in this Agreement have been inserted for convenience of reference only and do not define, modify or limit the provisions hereof. 10.07 Invalid Provisions. If any provision of this Agreement is held to be illegal, invalid or unenforceable under any present or future law or order, and if the rights or obligations of any party hereto under this Agreement will not be materially and adversely affected thereby, (i) such provision will be fully severable, (ii) this Agreement will be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, and (iii) the remaining provisions of this Agreement will remain in full force and effect and will not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom. 10.08 Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the Commonwealth of Massachusetts. 10.09 Enforcement of Agreement. The parties hereto agree that irreparable damage would occur in the event that any of the provisions of this Agreement was not performed in accordance with its specified terms or was otherwise breached. It is accordingly agreed that the parties shall be entitled to an injunction or injunctions to prevent breaches of this Agreement and to enforce specifically the terms and provisions hereof in any court of competent jurisdiction, this being in addition to any other remedy to which they are entitled at law or in equity. 10.10 Certain Definitions. As used in this Agreement: (a) except as provided in Section 4.14, the term "affiliate," as applied to any person, shall mean any other person directly or indirectly controlling, controlled by, or under common control with, that person; for purposes of this definition, "control" (including, with correlative meanings, the terms "controlling," "controlled by" and "under common control with"), as applied to any person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of that person, whether through the ownership of voting securities, by contract or otherwise; (b) a person will be deemed to "beneficially" own securities if such person would be the beneficial owner of such securities under Rule 13d-3 under the Exchange Act, including securities which such person has the right to acquire (whether such right is exercisable immediately or only after the passage of time); (c) the term "business day" means a day other than Saturday, Sunday or any day on which banks located in the Massachusetts are authorized or obligated to close; (d) the term "knowledge" or any similar formulation of "knowledge" shall mean, with respect to any party hereto, the actual knowledge after due inquiry of the executive officers of NEES and its Subsidiaries or EUA and its Subsidiaries, respectively, set forth in Section 10.11(d) of the NEES Disclosure Letter or Section 10.11(d) of the EUA Disclosure Letter; provided -47- that as used in Section 4.13 the term "knowledge" shall also include the knowledge of the environmental, health and safety personnel of EUA; (e) the term "person" shall include individuals, corporations, partnerships, trusts, limited liability companies, other entities and groups (which term shall include a "group" as such term is defined in Section 13(d)(3) of the Exchange Act); (f) the "Representatives" of any entity shall have the same meaning as set forth in the Confidentiality Agreement; (g) the term "Subsidiary" means any corporation or other entity, whether incorporated or unincorporated, in which such party directly or indirectly owns at least a majority of the voting power represented by the outstanding capital stock or other voting securities or interests having voting power under ordinary circumstances to elect a majority of the directors or similar members of the governing body, or otherwise to direct the management and policies, or such corporation or entity. 10.11 Counterparts. This Agreement may be executed in any number of counterparts, each of which will be deemed an original, but all of which together will constitute one and the same instrument and will become effective when one or more counterparts have been signed by each party and delivered to the other parties. 10.12 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION. -48- IN WITNESS WHEREOF, each party hereto has caused this Agreement to be signed by its officer thereunto duly authorized as of the date first above written. NEW ENGLAND ELECTRIC SYSTEM By: /s/ Richard P. Sergel ----------------------------------- Name: Richard P. Sergel Title: President and CEO The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer, or agent thereof assumes or shall be held to any liability therefor. EASTERN UTILITIES ASSOCIATES By: /s/ Donald G. Pardus ----------------------------------- Name: Donald G. Pardus Title: Chairman The name "Eastern Utilities Associates" is the designation of the Trustees of EUA for the time being in their collective capacity but not personally, under a Declaration of Trust dated April 2, 1928, as amended, a copy of which amended Declaration of Trust has been filed in the office of the Secretary of The Commonwealth of Massachusetts and elsewhere as required by law; and all persons dealing with EUA must look solely to the trust property for the enforcement of any claim against EUA, as neither the Trustees nor the officers or shareholders of EUA assume any personal liability for obligations entered into on behalf of EUA. RESEARCH DRIVE LLC By: /s/ John G. Cochrane ----------------------------------- Name: John G. Cochrane Title: Manager -49- EX-99 4 EXHIBIT H-1 Exhibit H-1 UNITED STATES OF AMERICA before the SECURITIES AND EXCHANGE COMMISSION PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 Release No. / , 1999 - ------------------------------------ ) In the Matter of ) ) New England Electric System ) 25 Research Drive ) Westborough, MA 01582 ) ) and ) ) Eastern Utilities Associates ) One Liberty Square, P.O. Box 2333 ) Boston, MA 02109 ) ) (70- ) ) - ------------------------------------ New England Electric System ("NEES"), organized and existing under the laws of Massachusetts as a voluntary association pursuant to an Agreement and Declaration of Trust dated January 2, 1926, as amended, and Eastern Utilities Associates ("EUA"), organized and existing under the laws of Massachusetts pursuant to a Declaration of Trust dated April 2, 1928, as amended, have filed an Application on Form U-1 seeking approvals related to the proposed combination of NEES, EUA and Research Drive LLC ("LLC"), a Massachusetts limited liability company wholly-owned by NEES (the "Merger"). Pursuant to the Merger, LLC will merge with and into EUA, with EUA as the surviving entity, and, therefore, a wholly-owned subsidiary of NEES. EUA subsequently will be merged with and into NEES, with NEES as the surviving entity (together with the Merger, the "Transaction"). Subsequent to the Transaction, EUA shall cease to exist and NEES will remain a registered holding company pursuant to the Public Utility Holding Company Act of 1935 (the "Act"). NEES is a registered public utility holding company, and NEES and its subsidiaries are subject to the broad regulatory provisions of the Act administered by the Securities and Exchange Commission (the "Commission"). NEES owns all of the voting securities of the following four distribution subsidiaries: Massachusetts Electric Company ("Mass. Electric"), The Narragansett Electric Company ("Narragansett"), Granite State Electric Company ("Granite State"), and Nantucket Electric Company ("Nantucket"). NEES also owns 99.97 percent of the outstanding voting securities of its principal transmission subsidiary, New England Power Company ("NEP"). NEES and its utility subsidiaries (the "NEES System") serve a territory covering more than 4,500 square miles with a population of approximately 3,000,000. NEES also engages in non-utility operations through various other subsidiaries including New England Power Service Company ("Service Company"), which provides, at cost, such administrative, engineering, construction, legal, and financial services as NEES and its subsidiaries request pursuant to a service agreement approved by the Commission in accordance with the requirements of Rule 90. EUA operates as a registered holding company pursuant to the Act, and EUA and its subsidiaries are subject to the broad regulatory provisions of the Act administered by the Commission. EUA directly owns all of the shares of common stock of the following electric public utility companies: Blackstone Valley Electric Company ("Blackstone"), Eastern Edison Company ("Eastern Edison") and Newport Electric Corporation ("Newport"). Eastern Edison presently owns all of the outstanding securities of Montaup Electric Company ("Montaup"). On July 14, 1999, Eastern Edison filed a Form U-1 requesting the Commission's authorization for Eastern Edison to transfer to EUA, and for EUA to acquire from Eastern Edison, all of Eastern Edison's investment in Montaup's capitalization. EUA and its utility subsidiaries (the "EUA System") serve approximately 305,000 retail customers in Massachusetts and Rhode Island. EUA also engages in non-utility operations through various other subsidiaries, including EUA Service Corporation ("EUA Service"), which provides various accounting, financial, engineering, planning, data processing, and other services to EUA System companies. As part of the Transaction, Eastern Edison and Mass. Electric will merge, with Mass. Electric being the surviving entity; NEP and Montaup will merge, with NEP being the surviving entity; and Blackstone, Newport and Narragansett will merge, with Narragansett being the surviving entity. In addition, NEES will indirectly acquire EUA's non-utility businesses through NEES' ownership of common shares or equity in those non-utility businesses. Finally, EUA Service and Service Company will merge, with Service Company being the surviving company. Pursuant to an Agreement and Plan of Merger, dated as of December 11, 1998, by and among The National Grid Group plc ("NGG"), NGG Holdings LLC, a Massachusetts limited liability company and a wholly-owned subsidiary of NGG, and NEES, NGG Holdings LLC will be merged with and into NEES with NEES as the surviving entity. As a result, NEES will become an indirect, wholly-owned subsidiary of NGG, which will become a registered holding company under the Act. The merger of EUA with and into LLC will be governed by the terms of an Agreement and Plan of Merger, dated as of February 1, 1999 (the "Merger Agreement"), by and among NEES, EUA and LLC. As a result of the Transaction, each one percent of the issued and outstanding membership interests in LLC will be converted into one transferable certificate of participation or share in EUA. All EUA shares that are owned by EUA as treasury shares and any EUA shares owned by NEES or any other wholly-owned subsidiary of NEES will be cancelled and retired and shall cease to exist, and no cash or other consideration shall be delivered in exchange therefor. The remaining EUA shares issued and outstanding immediately prior to the Effective Date (as defined below) will be cancelled and converted into the right to receive cash in the amount of $31.00 per share (the "Per Share Amount"), as such amount may be adjusted. The Effective Date shall be the date upon which a certificate of merger has been executed and filed by EUA and LLC with the Secretary of Massachusetts, or any later date specified by such certificate. NEES and EUA state that the Transaction fully complies with the Act and does not prompt any of the concerns that the Act was intended to address. NEES and EUA further contend that the Transaction promotes the goals of the Act by creating an integrated merged entity that will benefit the interests of the general public, investors and consumers. Finally, NEES and EUA state that both state and federal regulation will ensure that the interests of the public, investors and consumers continue to be protected. The Application and any amendments thereto are available for public inspection through the Commission's Office of Public Reference. Interested persons wishing to comment or request a hearing should submit their views in writing by _______, 1999, to the Secretary, Securities and Exchange Commission, Washington, D.C. 20549, and serve a copy on NEES and EUA at the addresses specified above. Proof of service (by affidavit or, in case of an attorney at law, by certificate) should be filed with the request. Any request for hearing shall identify specifically the issues of fact or law that are disputed. A person who so requests will be notified of any hearing, if ordered, and will receive a copy of any notice or order issued in the manner. After said date, the Application, as filed or as amended, may be granted and/or permitted to become effective. For the Commission, by the Division of Investment Management, pursuant to delegated authority. Jonathan G. Katz Secretary EX-99 5 EXHIBIT K-1 Exhibit K-1 Discussion of Negotiations Between NEES and EUA A special meeting of the EUA Board was held on May 29, 1998. The sole purpose of this meeting was to review in detail EUA's strategic options for future operations. Following this special meeting, Donald G. Pardus, EUA's Chairman of the Board was instructed to open communication with selected electric utilities in the region in an attempt to determine their interest in discussing some type of business combination. From June 1998 through October 1998, EUA's Chairman had informal conversations with respect to business combinations with senior executives of four electric utilities in the region. In early December 1998, EUA's Chairman was contacted by the chairman of a regional electric utility company ("Company A") with whom previous informal conversations had taken place. EUA's Chairman was asked if EUA was still interested in entering into discussions with Company A with respect to a possible business combination. EUA's Chairman indicated that EUA was continually reviewing its options and that, subject to the EUA Board's concurrence, EUA would be interested in entering into such discussions. The EUA Board agreed and EUA entered into a confidentiality agreement with Company A shortly thereafter and a due diligence process began. Shortly after the telephone call from Company A, EUA's Chairman contacted Richard P. Sergel, the President and Chief Executive Officer of NEES, and suggested that a meeting take place to explore NEES's interest in discussing a possible business combination with EUA. A meeting between Mr. Sergel and Mr. Padus took place on December 10, 1998. A follow-up meeting took place on December 16 and was attended by Alfred D. Houston, NEES's Chairman, Mr. Sergel, Mr. Pardus and John R. Stevens, EUA's President. On December 18 and December 21, confidentiality agreements were signed between EUA, NEES and NEES's prospective parent, NGG. A due diligence process commenced immediately. In addition, during the period December 7, 1998 through January 13, 1999, and as the due diligence process was taking place, EUA's Chairman had four face-to-face meetings and 10 telephone conversations with the Chairman of Company A and four face-to-face meetings and five telephone conversations with the Chief Executive Officer of NEES. On January 13, 1999, NEES submitted to EUA a proposal to acquire EUA, which included an indicative price and was subject to the negotiation of a satisfactory merger agreement. On January 14, 1999, Company A submitted to EUA a proposal to acquire EUA, which also included an indicative price and was subject to the negotiation of a satisfactory merger agreement. Company A and NEES both anticipated that EUA Cogenex, EUA's energy services subsidiary, would be sold in a separate transaction, and therefore did not include a value for EUA Cogenex in their proposals. The EUA Board met on January 19, 1999 and, with input from EUA executives and its financial advisors, considered the proposals received from Company A and NEES. The EUA Board instructed the Chairman and EUA's financial advisors to go back to Company A and to NEES and inform them that EUA Cogenex would not be disposed of in a separate transaction; therefore, their proposals needed to be modified to include a valuation for EUA Cogenex. Both Company A and NEES were requested to present their best revised proposal by the close of business on January 26, 1999. Significant due diligence took place with respect to EUA Cogenex between January 19, 1999 and January 26, 1999. In addition, during the period January 19, 1999 through January 28, 1999, EUA's Chairman had eight telephone conversations with the Chairman or his associates of Company A and one face-to-face meeting and two telephone conversations with the Chief Executive Officer of NEES. During this period, there were also frequent discussions between EUA's financial advisors and the financial advisors for Company A and NEES. On January 26, 1999, NEES presented its revised proposal which included a valuation for EUA Cogenex. Following presentation of NEES's January 26, 1999 proposal, negotiations continued with NEES and its financial advisors in an effort to enhance the proposal. On the evening of January 28, 1999, Company A presented its revised proposal. Two face-to-face meetings were held on January 29, 1999 between the Chairman of EUA and the Chief Executive Officer of NEES. On January 31, 1999 and February 1, 1999, the EUA Board held a special meeting to review and consider the proposals received from Company A and NEES. After presentations by Mr. Pardus and Mr. Stevens and the EUA Board's legal and financial advisors, and a full discussion and analysis by the EUA Board, the EUA Board unanimously (1) determined that it was in the best interests of EUA shareholders, its employees and its customers for EUA to enter into a business combination with NEES; (2) determined that the terms of the Merger were fair to, and in the best interests of EUA shareholders; and (3) authorized, approved and adopted the proposed agreement and plan of merger and the transaction contemplated by the Merger Agreement and the execution and delivery of the Merger Agreement. EUA was advised that NEES obtained the consent of NGG to enter into the Merger Agreement and on the morning of February 1, 1999, at the conclusion of the EUA Board meeting and prior to the opening of markets, EUA and NEES executed and delivered the Merger Agreement. EX-99 6 EXHIBIT D-1 APPLICATION TO THE FERC UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) THE NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-70-000 NEW ENGLAND HYDRO-TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO-TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY, L.L.C. ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) JOINT APPLICATION OF NEW ENGLAND POWER COMPANY, et al. AND MONTAUP ELECTRIC COMPANY, et al. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS APPLICATION, ATTACHMENTS AND VERIFICATIONS Edward Berlin, Esq. David A. Fazzone, Esq. of Kenneth G. Jaffe, Esq. David A. Fazzone, P.C., and Scott P. Klurfeld, Esq. McDermott, Will & Emery Swidler Berlin Shereff Friedman, LLP 28 State Street 3000 K Street, N.W., Suite 300 Boston, Massachusetts 02109-1775 Washington, D.C. 20007-5116 (617) 535-4000 (202) 424-7500 Attorneys for Montaup Electric Company and Affiliated Applicants Thomas G. Robinson, Esq. New England Power Company 25 Research Drive Westborough, MA 01582 (508) 389-2877 Attorneys for New England Power Company and Affiliated Applicants May, 1999 TABLE OF CONTENTS PAGE I. INTRODUCTION..................................................... 1 II. EXECUTIVE SUMMARY................................................ 4 A. The Merger will not adversely affect competition............................................ 5 B. The Merger will not subject customers to increased rates........................................ 6 C. The Merger will not impair the effectiveness of federal or state regulation......................... 7 III. DESCRIPTION OF THE PARTIES TO THE MERGER......................... 8 A. The NEES System of Companies........................... 8 1. NEES......................................... 8 2. NEP.......................................... 8 3. Affiliates of NEP............................ 9 B. The EUA System of Companies............................ 12 1. EUA.......................................... 12 2. Affiliates of EUA............................ 12 IV. DESCRIPTION OF THE MERGER........................................ 16 A. Goals and Benefits of the Merger....................... 16 B. Procedural Status of the Merger........................ 17 V. THE MERGER IS CONSISTENT WITH THE PUBLIC INTEREST................ 19 A. The Merger Will Have No Adverse Effect on Competition............................................ 19 1. The Merger Will Not Increase Market Power with Respect to Generation............. 20 2. The Merger Will Not Have an Adverse Effect on the Transmission Market in New England.................................. 21 TABLE OF CONTENTS (Cont'd) PAGE 3. The Merger Does Not Raise Vertical Market Power Issues.......................... 22 4. Conclusion Regarding Effect of the Merger on Competition........................ 23 B. The Merger Will Have No Adverse Effect on Rates........ 24 1. Applicants Have Proposed a Rate Plan That Will Hold Transmission Ratepayers Harmless..................................... 24 2. No Recovery of Transaction Costs and Acquisition Premium Will Be Awarded Without Proof of Countervailing Benefits..................................... 27 3. Conclusion Regarding Effect on Rates......... 28 C. The Merger Will Have No Adverse Effect on Regulation... 28 1. Federal Regulation........................... 29 2. State Regulation............................. 30 VI. ACCOUNTING TREATMENT............................................. 30 VII. INFORMATION REQUIRED OF APPLICANTS BY SECTION 33.2 OF THE COMMISSION'S REGULATIONS..................................... 32 A. The exact name and address of the principal business office.............................. 32 B. Name and address of the person authorized to receive notices and communications with respect to application................................. 33 C. Designation of the territories served by counties and states.................................... 33 D. A general statement briefly describing the facilities owned or operated for transmission of electric energy in interstate commerce or the sale of electric energy at wholesale in interstate commerce.................................... 35 -ii- TABLE OF CONTENTS (Cont'd) PAGE E. Whether the application is for disposition of facilities by sale, lease, or otherwise, a merger or consolidation of facilities, or for purchase or acquisition of securities of a public utility, also a description of the consideration, if any, and the method of arriving at the amount thereof......................... 36 F. A statement of facilities to be disposed of, consolidated, or merged, giving a description of their present use and of their proposed use after disposition, consolidation, or merger. State whether the proposed disposition of facilities or plan for consolidation or merger includes all the operating facilities of the parties to the transaction............................................ 36 G. A statement (in the form prescribed by the Commission's Uniform System of Accounts for Public Utilities and Licensees) of the cost of the facilities involved in the sale, lease, or other disposition or merger or consolidation. If original cost is not known, an estimate of original cost based, insofar as possible, upon records or data of the applicant or its predecessors must be furnished, together with a full explanation of the manner in which such estimate has been made, and a description and statement of the present custody of all existing pertinent data and records....................................... 37 H. A statement as to the effect of the proposed transaction upon any contract for the purchase, sale, or interchange of electric energy................................................. 37 I. A statement as to whether or not any application with respect to the transaction or any part thereof is required to be filed with any other Federal or State regulatory body................................................... 37 J. The facts relied upon by applicants to show that the proposed disposition, merger, or consolidation of facilities or acquisition of securities will be consistent with the public interest............................................... 38 K. A brief statement of franchises held, showing date of expiration if not perpetual.................... 38 L. A form of notice suitable for publication in the Federal Register, which will briefly summarize the facts contained in the application in such way as to acquaint the public with its scope and purpose...................... 40 -iii- TABLE OF CONTENTS (Cont'd) PAGE VIII. EXHIBITS REQUIRED PURSUANT TO SECTION 33.3 OF THE COMMISSION'S REGULATIONS......................................... 40 IX. REQUEST FOR APPROVAL OF NATIONAL GRID-NEES MERGER WITH RESPECT TO EUA COMPANIES AND FOR INCORPORATION BY REFERENCE OF REQUIRED EXPLANATIONS AND EXHIBITS.................. 41 X. PROCEDURAL MATTERS............................................... 44 XI. CONCLUSION....................................................... 45 -iv- UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION ) NEW ENGLAND POWER COMPANY, et al. ) and ) Docket No. EC99-70-000 MONTAUP ELECTRIC COMPANY, et al. ) ) JOINT APPLICATION OF NEW ENGLAND POWER COMPANY, et al. and MONTAUP ELECTRIC COMPANY, et al. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS I. INTRODUCTION Pursuant to Section 203 of the Federal Power Act ("FPA"),1/ and Part 33 of the Commission's Regulations,2/ New England Power Company ("NEP") and its affiliates holding jurisdictional assets3/ (collectively, the "NEES Companies"), Montaup Electric Company ("Montaup") and its affiliates holding jurisdictional assets4/ (collectively the "EUA Companies"),5/ and Research Drive LLC submit - --------------- 1/ 16 U.S.C. section 824b (1994). 2/ 18 C.F.R. section 33.1 et seq. (1998). 3/ These include the following: Massachusetts Electric Company ("Massachusetts Electric"); The Narragansett Electric Company ("Narragansett"); New England Electric Transmission Corporation; New England Hydro-Transmission Corporation; New England Hydro-Transmission Electric Company, Inc.; and AllEnergy Marketing Company, L.L.C. (which holds no physical facilities for the generation or transmission of electricity but does hold a power marketing certificate (see 82 FERC P. 61,179 (1998))). 4/ These include the following: Blackstone Valley Electric Company ("Blackstone Valley"), Eastern Edison Company ("Eastern Edison"), and Newport Electric Corporation ("Newport Electric"). 5/ All the applicants together are referred to jointly as "Applicants." While not applicants, the parent companies of NEP and Montaup, New England Electric System and Eastern Utilities Associates, respectively, join this Application for purposes of supporting the approvals sought by the Applicants. this Application seeking the Commission's approval and related waivers or authorizations to effectuate the following: (i) the merger of Eastern Utilities Associates ("EUA") with Research Drive LLC, which will make EUA a subsidiary of New England Electric System ("NEES"), with EUA subsequently being consolidated into NEES (referred to as the "HoldCo Merger"); and (ii) the subsequent mergers and consolidations of the complementary operating companies of the two systems, to the extent such mergers involve companies holding jurisdictional assets (referred to as the "OpCo Mergers"). NEES is the existing holding company for the NEES Companies and EUA is the existing holding company for the EUA Companies. Through the HoldCo Merger, EUA will be merged so that it becomes a subsidiary of NEES, and will thereafter be consolidated into NEES. It is expected that as soon as practicable after the completion of the HoldCo Merger, Montaup will be merged into NEP, and the retail operating companies of EUA will be merged into the complementary NEES operating companies.6/ This Application seeks approval of both the HoldCo Merger and the subsequent OpCo Mergers (which together are referred to below as the "Merger"). - --------------- 6/ This means that Eastern Edison will merge into Massachusetts Electric, and Blackstone Valley and Newport Electric will be merged and consolidated into Narragansett. These mergers will be completed only after receipt of necessary regulatory approvals or other authorizations. (In Rhode Island, for example, there may be a need for a statutory change.) It is also contemplated that some of the non-jurisdictional subsidiaries of NEES and EUA (such as the service companies) will be merged and consolidated. -2- The NEES Companies currently have pending in Docket No. EC99-49-000 a request for approval of a merger that will make NEES a subsidiary of The National Grid Group plc ("National Grid"). The two mergers are not conditioned on each other and National Grid supports the merger of NEES and EUA and their operating companies.7/ It is possible that the National Grid-NEES merger will be completed before the OpCo Mergers. In that case, Commission approval would be required for the acquisition of the EUA Companies by National Grid as a result of the National Grid-NEES merger.8/ The NEES Companies and the EUA Companies believe that the most efficient means of obtaining such approval would be by having the Commission grant such approval in connection with this Application.9/ The basis and reasons for approving the National Grid-NEES merger are fully explained in the application filed in Docket No. EC99-49. Section IX of this Application summarizes the reasons why the same analysis should apply to the National Grid-NEES merger with respect to the EUA Companies. Applicants thus request that the necessary descriptions regarding the National Grid transaction, which are presented in full in the filings in Docket No. EC99-49, be incorporated by reference into this proceeding to permit the Commission to - --------------- 7/ While not an applicant, National Grid also joins this Application for purposes of supporting the approvals sought by the Applicants. 8/ The reverse is not true. If the OpCo Mergers are completed before the National Grid-NEES merger, the jurisdictional facilities at issue in this proceeding will have been fully incorporated into and become part of the facilities held by the applicants in Docket No. EC99-49. Accordingly, no further approval beyond that requested in Docket No. EC99-49 would be required to complete the National Grid merger with the then-expanded NEES operating companies. 9/ This is a slight change from the original view noted in the EC99-49 application, which indicated that an amendment would be made to that filing. Instead, National Grid, the NEES Companies and the EUA Companies believe that it is more efficient to seek the approval in this Application and are doing so. No amendment will be sought for the application seeking approval of the National Grid merger. -3- approve the acquisition by National Grid of the EUA Companies, which would result from the consummation of the National Grid-NEES merger. This Application includes all the information and exhibits required by Part 33 of the Commission's regulations and the Commission's Merger Policy Statement.10/ As demonstrated below, the Merger easily satisfies the criteria established by the Commission. Accordingly, the Applicants respectfully request that the Commission approve this Application without condition, modification or evidentiary, trial-type hearing. The parties are attempting to close the Merger expeditiously and seek approval by July 31, 1999. II. EXECUTIVE SUMMARY The Applicants request that the Commission approve the Merger pursuant to Section 203 of the FPA. The Merger establishes a synergistic combination that brings together the resources and skills of two complementary companies, NEES and EUA, each focused on providing low-cost transmission and distribution services in the New England market. Combined, the two companies provide the size and expertise needed to allow the merged entity to take advantage of economies of scale that would permit it to increase efficiency and thereby reduce costs and improve service. - --------------- 10/ Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, Docket No. RM96-6-000, 61 Fed. Reg. 68,595 (Dec. 30, 1996), III FERC Stats. & Regs., Regulations Preambles P. 31,044 ("Merger Policy Statement"). The materials supporting the request for approval regarding the acquisition by National Grid of the EUA Companies resulting from the National Grid- NEES merger are incorporated by reference. -4- Included with the Application are the required exhibits, as well as a declaration of Dr. Henry J. Kahwaty, Senior Managing Economist at LECG, Inc. (formerly, the Law and Economics Consulting Group) (Attachment 1), demonstrating that the Merger will not have any adverse impact on competition. The Application shows that the Merger is in the public interest, satisfying each of the three tests established in the Merger Policy Statement: (1) it does not adversely affect competition in any market; (2) it does not increase customers' rates; and (3) it does not impair the effectiveness of regulation. A. The Merger will not adversely affect competition. The Merger will not have an adverse effect on competition. Indeed, as demonstrated by the declaration of Dr. Kahwaty and as explained further below, the Merger creates no issues with respect to generation or transmission market power, or vertical effects. In accordance with electric restructuring legislation and settlement agreements approved by the Commission and state regulators, subsidiaries of both NEES and EUA have divested virtually all of their generation assets and power purchase contracts. As a result of these restructuring agreements, neither company has operational control over any generation resources or the ability to increase generation prices. Moreover, there will be no limitation on access to transmission facilities created by the Merger because transmission will continue to be provided under Commission-regulated open-access tariffs. Finally, both NEES' and EUA's -5- operating affiliates provide retail access to power suppliers under open delivery tariffs.11/ As a result, the Merger presents no vertical issues. B. The Merger will not subject customers to increased rates. The Merger will not increase transmission rates to wholesale customers because Applicants are making a "hold harmless" commitment. To that end, NEP and Montaup are contemporaneously filing under Section 205 of the FPA a transmission rate plan that will assure that transmission customers' rates do not increase as a result of the Merger.12/ No other rates or contracts with wholesale customers are affected by the Merger, and the restructuring settlements terminating requirements sales between NEP or Montaup and their respective wholesale customers will continue to be honored after the Merger. In addition, although the Merger will generate certain costs in the form of an acquisition premium and transaction costs, to avoid any rate impact from these costs, the Applicants commit to exclude the premium and the transaction costs from Commission jurisdictional rates, unless and until permitted to include them by specific order of this Commission. In Massachusetts and Rhode Island, these costs are recoverable if offsetting benefits from the Merger are demonstrated. Accordingly, the retail operating companies intend to seek recovery of these costs as part of a comprehensive rate plan filed in those two states. The retail rate plans are subject to the jurisdiction of the state commissions in those states. Consequently, the Merger's effects on the rates - --------------- 11/ NEES, through its subsidiary AllEnergy, sells electricity at retail within and outside the operating companies' combined service territories. The electricity is delivered by the affiliated operating companies at filed, non-discriminatory tariff rates and all affiliate dealings are subject to standards of conduct approved by this Commission and the state commissions in Massachusetts, Rhode Island and New Hampshire. 12/ Applicants have requested consolidation of that filing with this proceeding since the Section 205 filing is contingent upon approval of and consummation of the Merger. -6- paid by the retail customers of the NEES or EUA Companies will be subject to full regulatory review by the agency with jurisdiction. That regulatory review will assure that the wholesale and retail rate plans associated with the Merger are reasonable for all customers. C. The Merger will not impair the effectiveness of federal or state regulation. The Merger will not adversely affect either federal or state regulation. With respect to federal regulation, NEES and EUA are currently registered holding companies under the Public Utility Holding Company Act of 1935 ("PUHCA")13/ and consequently there will be only a very limited impact on the federal regulatory structure as a result of the Merger. To avoid any impact on federal regulation from this change, the Applicants commit to be subject to the Commission's policy regarding intra-corporate transactions for those transactions involving the sale of non-power goods and services between Montaup, NEP, and their franchised public utility affiliates. With respect to state regulation, Applicants believe that the states will continue to have the same jurisdiction over the operations of the utilities after the Merger as they had before. In any case, filings have been or will be made with the appropriate state regulatory commissions seeking approval of the Merger, where necessary. Each affected state will thus have a full opportunity to address any impact on state regulation in connection with those filings. The Merger, accordingly, will not impair state regulation. * * * * - --------------- 13/ 15 U.S.C. ss. 79 et seq. (1994). -7- Because the Merger satisfies all of the requirements of Section 203 of the FPA, the Commission's regulations and the Merger Policy Statement, the Commission should find that the Merger is consistent with the public interest and approve the Application by July 31, 1999, without modification or condition and without holding a trial-type hearing. III. DESCRIPTION OF THE PARTIES TO THE MERGER A. The NEES System of Companies 1. NEES NEES is a registered public utility holding company headquartered in Westborough, Massachusetts. Its subsidiaries are engaged in the transmission and distribution of electricity and the marketing of energy commodities and services. The electricity delivery companies serve approximately 1.3 million customers in Massachusetts, Rhode Island, and New Hampshire. Other NEES subsidiaries offer telecommunications and other services. NEES does not directly own any facilities subject to Commission jurisdiction. 2. NEP NEP, a wholly-owned subsidiary of NEES, is a Commission-regulated public utility company organized and operated under the laws of the Commonwealth of Massachusetts. It operates over 2,600 miles of transmission facilities. NEP has recently disposed of effectively all its non-nuclear generating assets,14/ but still holds minority, non-operating interests in three nuclear generating - --------------- 14/ NEP continues to own a 9.3 percent share in a single oil-fired generating unit, which it is selling. See Attachment 1 at paragraph 6. companies with retired nuclear facilities (Connecticut Yankee, Maine Yankee, and Yankee Atomic) and in three other operating nuclear units (Millstone 3, Seabrook and Vermont Yankee). NEP has agreed to attempt to divest these nuclear entitlements as required by its restructuring settlements approved by this Commission and the state commissions regulating its affiliates. 3. Affiliates of NEP a. Distribution Companies (1) Massachusetts Electric Massachusetts Electric is a wholly-owned subsidiary of NEES and delivers electric energy to approximately 980,000 retail customers in 146 cities and towns in the Commonwealth of Massachusetts. Massachusetts Electric's service area covers approximately 43 percent of the Commonwealth. (2) Narragansett Narragansett is a wholly-owned subsidiary of NEES. Narragansett is the largest electric utility company in Rhode Island and provides delivery service to approximately 335,000 retail customers across a service territory that covers 27 cities and towns. (3) Granite State Electric Company Granite State Electric Company ("Granite State") is a wholly-owned subsidiary of NEES operating in New Hampshire. It is engaged in the distribution of electric energy at retail. Granite State provides service to approximately 37,000 customers in 21 communities. (4) Nantucket Electric Company Nantucket Electric Company ("Nantucket Electric") is a wholly-owned subsidiary of NEES operating in the Commonwealth of Massachusetts. Nantucket -9- Electric is engaged in the distribution of electric energy at retail to approximately 10,000 customers on Nantucket Island. The company's service area covers the entire island.15/ b. Transmission Companies (1) New England Electric Transmission Corporation New England Electric Transmission Corporation is a wholly-owned subsidiary of NEES and operates a direct current/alternating current converter terminal and related facilities for the first phase of the Hydro-Quebec and New England interconnection and six miles of high-voltage direct current transmission line in New Hampshire. (2) New England Hydro-Transmission Corporation NEES owns 50.4338 percent of the common stock of New England Hydro-Transmission Corporation. New England Hydro-Transmission Corporation operates 121 miles of high-voltage direct current transmission line in New Hampshire for the second phase of the Hydro-Quebec and New England interconnection, extending to the Massachusetts border. (3) New England Hydro-Transmission Electric Company, Inc. NEES owns 50.4338 percent of the common stock of New England Hydro-Transmission Electric Company, Inc. which operates a direct current/alternating current terminal and related facilities for the second phase of the Hydro-Quebec and New England interconnection and 12 miles of high-voltage direct current transmission line in Massachusetts. - --------------- 15/ Both Granite State and Nantucket Electric support the transaction, but are not listed as applicants because neither owns any jurisdictional facilities. -10- c. Energy Marketer - AllEnergy Marketing Company, L.L.C. NEES, through its subsidiary, NEES Energy, Inc., owns 100 percent of the voting securities of AllEnergy Marketing Company, L.L.C. ("AllEnergy"). AllEnergy is a power marketer operating under a Commission certificate. It is engaged in the sale of electric energy, natural gas and heating oil to commercial, industrial and residential consumers in competitive markets in the Northeast, as well as offering related value-added services. AllEnergy also markets propane, fuel oil and other liquid fuels through its subsidiary, Texas Fluids. In addition, AllEnergy sells fuel oil through its PAL and Griffith operating divisions, which were recently acquired by the Company. d. Research Drive LLC Research Drive LLC, a Massachusetts limited liability company, is owned by NEES and NEES Global, Inc. and was formed for the express purpose of effectuating the HoldCo Merger. e. Other Companies NEES owns equity in the following companies: NEES Global, which owns a 100 percent equity interest in New England Water Heater Co., Inc. (providing rental, service, sales and installation of water heaters) and which also provides consulting services to utilities in the United States, Canada and elsewhere; New England Power Service Company (providing support services to NEES and its subsidiaries); NEES Communications, Inc. (providing telecommunication and information-related products and services); Granite State Energy, Inc. (marketing electricity to New Hampshire customers participating in that state's -11- pilot program for retail choice) and Metrowest Realty LLC (owning certain properties occupied by NEES subsidiaries). B. The EUA System of Companies 1. EUA EUA is a diversified energy-services holding company organized and existing in Massachusetts. Its utility subsidiaries are engaged in the transmission and distribution of electricity in Massachusetts and Rhode Island, delivering electric service to more than 305,000 consumers in southeastern Massachusetts and northern and coastal Rhode Island. Non-utility subsidiaries market energy efficiency services nationwide and invest in other non-regulated businesses. 2. Affiliates of EUA a. Distribution Companies (1) Eastern Edison Eastern Edison is a wholly-owned subsidiary of EUA. It provides distribution service to approximately 186,000 customers in non-contiguous service territories covering the southeastern Massachusetts cities of Brockton and Fall River plus 20 surrounding towns. Together with Montaup, it owns approximately 4,600 miles of transmission and distribution lines. (2) Blackstone Valley Blackstone Valley is a wholly-owned subsidiary of EUA. It provides distribution service to approximately 86,000 customers in the northern Rhode Island cities of Pawtucket and Woonsocket and five neighboring communities. It owns approximately 1,700 miles of transmission and distribution lines. -12- (3) Newport Electric Newport Electric is a wholly-owned subsidiary of EUA. It provides distribution service to approximately 33,000 customers in Newport, Jamestown, Middletown, and Portsmouth, Rhode Island. Newport Electric owns approximately 800 miles of transmission and distribution lines. b. Transmission Company (1) Montaup Montaup, which is a subsidiary of Eastern Edison, provides transmission service in interstate commerce to its retail distribution affiliates (Eastern Edison, Blackstone Valley, and Newport Electric) and to two non-affiliated municipal electric utilities.16/ Montaup previously sold significant amounts of wholesale electricity but, as part of the restructuring of the utility industry in Massachusetts and Rhode Island, Montaup has negotiated comprehensive settlement agreements with its regulators. These settlement agreements, which have been approved by the state commissions as well as by this Commission (in Docket Nos. ER97-2800-000, et al.), provide for the complete divestiture of Montaup's generating business. In conformance with those settlements, Montaup has recently sold or signed purchase and sale agreements for all its non-nuclear generation assets.17/ - --------------- 16/ Montaup has a very small stock ownership investment in New England Hydro-Transmission Corporation and New England Hydro-Electric Transmission Electric Company, Inc. 17/ See Attachment 1 at paragraph 8. As explained below, Montaup's affiliate, EUA Ocean State Corporation, continues to retain its ownership interest in Ocean State Power, an independent power producer. -13- Montaup currently has minority, non-operating interests in the same nuclear generating companies as NEP, including those with retired nuclear facilities (Connecticut Yankee, Maine Yankee and Yankee Atomic) and those with operating units (Millstone 3, Seabrook and Vermont Yankee). Montaup has signed an agreement for the sale of its share of Seabrook, for which it is seeking regulatory approval, and it is attempting to divest its remaining nuclear ownership interests. c. Energy Providers (1) EUA Ocean State Corporation EUA Ocean State, wholly-owned by EUA, owns a 29.9 percent partnership interest in the Ocean State Power generating station in northern Rhode Island, a non-utility generating plant that is subject to regulation by the Commission. EUA Ocean State does not market the power produced from this plant. All rights to the power produced are committed under long term contracts. d. Other Companies18/ (1) EUA Cogenex Corporation EUA Cogenex, a wholly-owned subsidiary of EUA, is an energy services company that utilizes energy efficient technology and equipment to reduce the energy consumption and costs of its customers.19/ EUA Cogenex has service agreements nationwide and in Canada. - --------------- 18/ Besides the companies listed in this section, EUA also owns EUA Energy Services, which was created to own an interest in a limited liability company. That limited liability company has broken up, and EUA Energy Services is currently inactive. 19/ EUA Cogenex Corporation also owns EUA Day, which is primarily engaged in the business of customization, installation, and servicing of building temperature control systems for the purpose of energy conservation. -14- (2) EUA Energy Investment Corporation EUA Energy Investment Corporation is a wholly-owned subsidiary of EUA. It invests in energy-related projects, including the following: Bluestone Energy Services (proposed regional water desalinization plant); EUA BIOTEN (developing biomass-fueled generating units); EUA Compression Services (joint venture being developed to market automated electric compression systems to natural gas pipeline companies); Separation Technologies, Inc. (markets and installs equipment for separating unburned carbon); Renova (provides lighting products designed to achieve an efficiency gain through the integration of various lamp, ballast, and light reflector products); and EUA TransCapacity (markets services and computer software to natural gas clients). (3) EUA Service Corporation EUA Service Corporation provides professional and technical services to all EUA System companies. (4) EUA Telecommunications EUA Telecommunications was established to provide telecommunications and information services to third-party customers. -15- IV. DESCRIPTION OF THE MERGER A. Goals and Benefits of the Merger As is explained in more detail in the attached filings with state commissions,20/ the Merger is one that produces traditional synergies from combining the resources and skills of two complementary companies focused on providing services in the same market. The two companies are organized similarly, with a holding company established over a federally regulated transmission company serving retail distribution affiliates, a service company and various unregulated affiliates. Each is a low-cost provider, has a similar philosophy of system operations, offers strong customer service and has a lean workforce. Combined, the two companies will achieve economies of scale necessary to increase efficiency and thereby reduce costs. Applicants believe that customers, employees and shareholders will all benefit from the combination. Customers will benefit by being served by a larger, more cost-efficient enterprise, with the same commitment to the region that each company has demonstrated in the past. Consolidation and elimination of redundant operations will help produce efficiency gains that will result in savings, which in turn will be important in maintaining low rates. Applicants have studied the potential for these efficiency gains.21/ The study identifies annual savings (after netting out costs to achieve them) of more than $27 million in 2002, - --------------- 20/ See Testimony of M. Jesanis and Testimony of R.G. Powderly in New England Electric Systems and Eastern Utilities Associates, Massachusetts Department of Telecommunications and Energy, Dkt. No. D.T.E.99-47 ("Joint Massachusetts Filing"), copy included in Exhibit G. 21/ The results of the study are included in the Testimony of Hoffman and Levin in Joint Massachusetts Filing. -16- escalating thereafter.22/ The Applicants also believe that the combination of the two companies will enhance expertise and allow more resources to be invested in customer service and modern transmission and distribution technology.23/ This will permit the merged entity to provide better service to all customers. Employees will also benefit from the Merger. Although there will be an initial, small reduction in the workforce (which will be accomplished through attrition or early retirement), the new, stronger company will have both the incentive and resources to expand the business. This will offer increased opportunities for employees. Upon conclusion of NEES's merger with National Grid, these opportunities will expand to encompass the international market. Finally, shareholders will benefit. EUA's shareholders will receive a price for their stock that reflects a premium over value, whether compared to market (23 percent over the price on the last trading day before other mergers in this industry were announced and 5 percent over the price on the day before this Merger was announced) or book value (169 percent of book value). B. Procedural Status of the Merger The Merger Agreement (attached as Exhibit H) establishes the procedure for the HoldCo Merger. It will be accomplished by having Research Drive LLC merge with EUA, which will make EUA a wholly-owned subsidiary of NEES. EUA will - --------------- 22/ Testimony of Hoffman and Levin, supra n. 21 at 7, 26 and Exhibit DJH-1. 23/ As the applicants in Docket No. EC99-49-000 explained, National Grid has expertise in operating transmission systems in connection with ISO, Transco, and power exchange structures in the United Kingdom, Argentina and other countries. The EUA-NEES merger extends to EUA's customers the benefits that will be produced from gaining access to that expertise as a result of the National Grid-NEES merger. -17- then merge into NEES. EUA's shareholders will receive in return for their shares a cash payment of $31.00 per share (subject to upward adjustment). The total purchase price is approximately $634 million. After completion of the HoldCo Merger, Applicants intend to merge EUA's operating companies into the NEES operating companies, as well as merge certain non-regulated entities (such as the service companies). The NEES operating companies will be the surviving entities in these OpCo Mergers, which require the approval of various state regulators.24/ The Boards of Directors of both NEES and EUA have approved the Merger, as shown in Exhibit A. The completion of the Merger is subject to certain conditions, including those involving regulatory and shareholder approval, which are now being sought. As the Commission is aware by the Section 203 application filed on March 10, 1999, in Docket No. EC99-49-000, NEES is seeking authority to merge with National Grid, with NEES becoming a wholly-owned subsidiary of National Grid. If the National Grid-NEES merger is completed before the OpCo Mergers, National Grid would effectively acquire the EUA Companies. That acquisition would require Commission approval, which, as explained earlier, this Application is seeking concurrently with approval of this Merger. - --------------- 24/ In addition, legislative action may be required in Rhode Island. -18- V. THE MERGER IS CONSISTENT WITH THE PUBLIC INTEREST Section 203(a) of the FPA provides, in pertinent part, that No public utility shall sell, lease, or otherwise dispose of . . . its facilities subject to the jurisdiction of the Commission . . . or by any means whatsoever, directly or indirectly, merge or consolidate such facilities or any part thereof with those of any other person, or purchase, acquire, or take any security of any other public utility, without first having secured an order of the Commission authorizing it to do so . . . . After notice and opportunity for hearing, if the Commission finds that the proposed disposition, consolidation, acquisition, or control will be consistent with the public interest, it shall approve the same.25/ The statute thus requires the Commission to approve a merger if it finds the merger is in the public interest. In the Merger Policy Statement the Commission established that the following issues need to be examined to determine if a merger is in the public interest: (1) the effect of the merger on competition; (2) the effect of the merger on rates; and (3) the effect of the merger on regulation. As is demonstrated in this Application and supporting materials, the Merger will not have an adverse effect in any of the three areas. Consequently, the Merger is in the public interest and the Commission should approve it promptly. A. The Merger Will Have No Adverse Effect on Competition. The declaration of Dr. Henry Kahwaty (Attachment 1) establishes that the Merger raises no competitive issues. Dr. Kahwaty examines the Merger with respect to horizontal market power concerns involving generation and transmission, and with respect to vertical issues. Dr. Kahwaty concludes that the Merger will not result in a reduction in competition in any of these areas. - --------------- 25/ 16 U.S.C. section 824b(a) (1994) (emphasis added). -19- 1. The Merger Will Not Increase Market Power with Respect to Generation Dr. Kahwaty explains that pursuant to electric utility restructuring legislation and settlement agreements approved by the Commission and state regulators, both NEP and Montaup have divested virtually all of their generation assets and power purchase contracts.26/ Upon conclusion of all pending sales, the combined entity will own a de minimus share of generation in the relevant market of New England, less than 2 percent.27/ Moreover, since both companies are committed to selling their few remaining generation resources, this de minimus share will decrease to zero when the resources are successfully sold.28/ While NEP and Montaup retain ownership interests, neither has operational control over any generation resources, and thus neither has control over the output of those facilities. They cannot restrict output in an attempt - --------------- 26/ Attachment 1 at paragraphs 6 and 8. Montaup also has a power purchase agreement with the buyer of the Pilgrim nuclear facility, which, upon termination of its existing life of unit contract would entitle Montaup to an 11 percent share of the plant's output, which share declines over time. Id. at paragraph 8. Both NEP and Montaup have either transferred or agreed to transfer, subject to Commission approval, the economic benefit and burden of their other power purchase contracts, although technically each may still be a party to many of them even after the transfer is complete. NEP and Montaup do sell the output from their share of the few remaining generation units (primarily nuclear) that have not been divested. Those sales are made to entities participating in the competitive wholesale market in New England. 27/ Attachment 1 at paragraphs 18 and 19. 28/ Id. at paragraph 21. -20- to increase prices.29/ Similarly, neither company has direct ability to increase prices, given the remaining de minimus share of generation resources they own. Even assuming arguendo that there were a concern with respect to de minimus generation assets held by the Applicants, Dr. Kahwaty explains that construction and expansion of generation is occurring in the New England market, and this new entry limits horizontal market power concerns with respect to generation.30/ Finally, Dr. Kahwaty examines the generation market by applying the Department of Justice and Federal Trade Commission's Horizontal Merger Guidelines, using the Herfindahl-Hirschman Index of Concentration ("HHI"). This analysis is performed by overlaying the EUA-NEES changes on the results from three other recent studies of the market. Given that this is a moderately concentrated market, the safe-harbor screening threshold for the HHI Index is an increase of 100. In each of the three cases for the markets examined, the increase in the HHI is almost nonexistent, producing increases of less than two (2) to less than twelve (12) at the highest.31/ Consequently, Dr. Kahwaty concludes that there will be no adverse competitive effects in the generation market from the Merger. 2. The Merger Will Not Have an Adverse Effect on the Transmission Market in New England. NEP and Montaup are members of the New England Power Pool ("NEPOOL") and have committed their pool transmission facilities to the operational control of the ISO-New England. The NEPOOL tariff provides for open-access transmission - --------------- 29/ Id. at paragraph 22. 30/ Id. at paragraphs 24 - 26. 31/ Id. at paragraphs 27 - 30 and Appendix. -21- under regulated rates.32/ In addition, NEP and Montaup provide transmission service on their local facilities under existing open-access transmission tariffs. Neither NEP nor Montaup have offered discounts under their tariffs to gain transmission customers or otherwise.33/ Moreover, none of the three transmission-dependent utilities served by Montaup is interconnected with NEP's system. As a result, these three entities do not choose between taking service from NEP or Montaup, and NEP and Montaup do not compete for the sale of transmission services.34/ Furthermore, as explained in the Section 205 application filed by NEP and Montaup contemporaneously with this Section 203 Application, after the HoldCo Merger, NEP and Montaup will provide service under a unified set of terms and conditions under a Commission-approved open-access transmission tariff.35/ Consequently, access to the combined transmission facilities of NEP and Montaup will not be restricted in any manner by the Merger, and there can be no concern regarding transmission market power.36/ 3. The Merger Does Not Raise Vertical Issues. Dr. Kahwaty's declaration also considers potential vertical issues. He explains that, as a result of industry restructuring, both NEES and EUA are exiting the generation business and the operating companies provide retail - --------------- 32/ Id. at paragraph 32. 33/ Id. at paragraph 33. 34/ Id. 35/ See Testimony of P. Viapiano filed in Application for Required Approvals Under Section 205 of the Federal Power Act for Merger of New England Electric System and Eastern Utilities Associates, Docket No. ER99-_____ ("Section 205 Filing"). 36/ Attachment 1 at paragraph 33. -22- access under filed non-discriminatory transmission and distribution tariffs. The operating companies are all subject as well to standards of conduct established by the Commission and relevant state commissions. All retail customers served by NEP's and Montaup's distribution affiliates therefore have the ability and right to purchase electricity from the market and have it delivered under non-discriminatory, filed rates. Consequently, the NEES and EUA Companies no longer operate as vertically integrated concerns, and the Merger will not result in adverse vertical competitive effects.37/ Dr. Kahwaty also concludes that, except for transmission and distribution services, which, as explained above, are provided at non-discriminatory, regulated tariff rates, the NEES and EUA Companies do not control key inputs used in the production or delivery of electric products or services to each other or to other utilities in New England.38/ Accordingly, Dr. Kahwaty concludes that the Merger is not a vertical merger, and will not impact the incentive or ability of the NEES or EUA Companies to affect competition or competitors through vertical effects. 4. Conclusion Regarding Effect of the Merger on Competition Dr. Kahwaty's analysis demonstrates that the Merger will not have any adverse effect on competition. The Merger creates no market power issues with respect to generation, transmission or vertical arrangements and the transaction easily passes the competitive screen adopted by the Commission in its Merger Policy Statement. In fact, Dr. Kahwaty concludes that the Merger will likely - --------------- 37/ Id. at paragraph 34. 38/ Id. at paragraph 35. It should be noted that NEP and Montaup own land for future use that may be considered potential generation sites, but those properties will be divested. -23- result in significant efficiencies that will promote competition in retail electricity markets.39/ The Merger thus satisfies the first test of the Commission's Merger Policy Statement. (It should be noted that on April 30, 1999, the Federal Trade Commission granted the Applicants early termination of the pre-merger notification waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.) B. The Merger Will Have No Adverse Effect on Rates. The Merger Policy Statement provides that the Commission's concern regarding the effect on rates is with wholesale and transmission ratepayer protection.40/ The Commission has made clear that if customers are held harmless from cost increases as a result of a merger, this second test is satisfied.41/ Applicants commit to hold their customers harmless from such rate increases. 1. Applicants Have Proposed a Rate Plan That Will Hold Transmission Ratepayers Harmless. As described in the accompanying Section 205 Filing, Applicants propose a rate plan for their local transmission service charges42/ that would apply to the two phases of the Merger: (1) during the period between the conclusion of HoldCo Merger but before the conclusion of the merger of NEP and - --------------- 39/ Id. at paragraphs 37-40; see Jesanis, supra note 20 and Hoffman and Levin, supra note 21 for further descriptions of the efficiencies. 40/ Merger Policy Statement at 68,599. 41/ See, e.g., id. at 68,603; MidAmerican Energy Co. and MidAmerican Energy Holdings Co., 85 FERC paragraph 61,354 (1998) (no additional protection needed for transmission customers if held harmless from costs). 42/ There will be no impact from the Merger on the rates applicable to the use of NEP's or Montaup's transmission systems for non-local service, since the NEPOOL tariff rate would continue to apply. -24- Montaup; and (2) after the merger and consolidation of Montaup into NEP. During the first phase, the formula rates for local transmission service on the effective date of the HoldCo Merger would continue to apply to each company's respective customers. Accordingly, during the first phase, transmission customers would see no change in the formula or the cost elements that are included in their local transmission service charge.43/ During the second phase, a single formula transmission rate, using NEP's currently effective tariff formula, would be placed into effect. Because NEP's rates are slightly higher than Montaup's, all of NEP's customers, affiliated and non-affiliated, would experience lower rates. Montaup's existing non-affiliated customers (the municipalities of Middleborough, Taunton and Pascoag) would face a slight rate increase if no action were taken. To avoid this, the rate plan would apply special provisions to these customers that would freeze their local transmission service charges at the pre-existing Montaup rate level. As explained in the testimony in the Section 205 Filing, under the terms of a transition rate plan adopted by NEPOOL, over several years these local charges would be phased out for those customers not actually using local facilities. For those customers actually using such local facilities, the charge would remain, but would be reduced to reflect Montaup's pre-existing local facilities charges prior to the OpCo Mergers, and then locked-in for at least five years.44/ With regard to transmission charges to NEP's and Montaup's affiliated distribution companies and the transmission components of retail rates, the analysis is similar. NEP's distribution affiliates would see lower transmission - --------------- 43/ See Testimony of P. Viapiano, supra, n. 35 at 6-8. 44/ Id. at 10-11. -25- rates, while customers of Montaup's distribution affiliates would face a small increase in transmission rates. This small increase in the transmission component of retail rates to Montaup's affiliates, however, will be more than offset by other components of a comprehensive rate plan. Specifically, in Massachusetts, NEP's and Montaup's customers pay a Contract Termination Charge ("CTC"), which is a charge assessed to former requirements customers by NEP and Montaup that permits the companies to recover an allocable share of the costs each had incurred to provide service to those former requirements customers.45/ Montaup's CTC is greater than NEP's, and the blending of the two more than offsets the small increase in the transmission component of the retail rate. Moreover, the distribution component of the retail rate will be frozen, providing economic benefits to all retail customers in Massachusetts. A similar result will occur in Rhode Island, where Montaup's affiliates Blackstone Valley and Newport Electric will be consolidated with Nagagansett. The rate plan will produce lower rates for Blackstone Valley's and Newport Electric's customers by reducing distribution rates for their customers and by equalizing over time transmission and CTC charges. In all cases, the blending of the CTCs will offset any transmission cost increases to Montaup's affiliates, producing no adverse rate effects from the transmission rate consolidation.46/ - --------------- 45/ The CTC includes the costs associated with investments in generating assets, contractual commitments for purchased power and fuel transportation, deferred costs, and other regulatory assets. 46/ See Testimony of P. Viapiano, supra, n. 35 at 14-17. Another change that would be made as a result of the consolidation of Montaup's and NEP's tariffs is one regarding charges applicable to interconnections to the local transmission system for delivery to the NEPOOL "PTF" system. The tariff change, however, would not increase any customer's cost, but instead would reduce the costs of the one former Montaup customer affected. Id. at 6-7. -26- 2. No Recovery of Transaction Costs and Acquisition Premium Will Be Awarded Without Proof of Countervailing Benefits. There will be an acquisition premium and transaction costs associated with the Merger,47/ but the Applicants are not requesting in this Application or in the accompanying Section 205 rate filing to recover these items through wholesale transmission rates that are subject to the Commission's jurisdiction.48/ The acquisition premium and transaction costs may be pushed down to the operating companies.49/ Under state law governing the operating companies, recovery of the acquisition premium and transaction costs requires a showing of countervailing savings or other benefits.50/ Neither the acquisition premium nor transaction costs will be recovered in rates at either the state or federal level without separate approval by the appropriate regulatory agency. Consequently, there can be no adverse effect on rates. - --------------- 47/ See Testimony of M. Jesanis, supra, n. 20 at 30. 48/ Applicants recognize that Commission policy would ordinarily not allow recovery in wholesale or transmission rates of an acquisition premium for this kind of transaction. See, e.g., Arkla Energy Resources, 61 FERC paragraph 61,004 (1992); Minnesota Power & Light Co. and Northern States Power Co., 43 FERC paragraph 61,104, 61,342 (1988); United Gas Pipe Line Co., 25 FPC 26 (1961), reversed and remanded on other grounds sub nom., Willmut Gas and Oil Co. v. FPC, 299 F.2d 111 (D.C. Cir. 1962). Accordingly, Applicants will not request recovery of the acquisition premium or transaction costs in rates subject to the Commission's jurisdiction absent a change in policy from the Commission. 49/ See Testimony of M. Jesanis, supra, n. 20 at 30-33. 50/ See, e.g., Northern Indiana Public Service Co. - Bay State Gas Co. Acquisition, Docket D.T.E. 98-31 (Mass. D.T.E. 1998); Eastern Enterprises - Essex Gas Co. Acquisition, Docket D.T.E. 98-27 (Mass. D.T.E. 1998); Mergers and Acquisitions, Docket D.T.E. 93-167-A (Mass. D.P.U. 1994); Valley Gas Co., Docket No. 2276, pp. 18-20 (Rhode Island PUC, Oct. 18, 1995). -27- 3. Conclusion Regarding Effect on Rates. Applicant's rate plan combined with their commitment regarding no recovery of transaction costs or any acquisition premium without countervailing savings will hold ratepayers harmless from the effects of the Merger.51/ The second test is satisfied. C. The Merger Will Have No Adverse Effect on Regulation. In the Merger Policy Statement, the Commission stated that its analysis would address two aspects in order to determine whether a merger would impair effective regulation. The first is whether the merger would transfer authority from the Commission to the Securities and Exchange Commission ("SEC"). If no such transfer would occur or if the applicants were to commit to abide by the Commission's policies with respect to intra-system transactions within the holding company structure, the test would be satisfied. Otherwise, a hearing on the impact of the proposed transaction on effective regulation by the Commission would be required. The second part of the test is whether the affected states would have authority to act on the merger.52/ If the states have authority to act on the merger, the Commission will find that there would be no adverse effect on state regulation, and will not set the issue for hearing. The Merger satisfies both aspects of this test and hence would not impair effective regulation at the federal or state level. - --------------- 51/ There are no rate concerns associated with wholesale sales of electricity because NEP and Montaup make only extremely limited wholesale sales to non-affiliates, with Montaup's sales terminating in 1999 and 2000. Under approved settlement agreements, Montaup and NEP have wholesale back-up sales obligations to their affiliates, but these obligations are provided under standard offer fixed price schedules, which, in any event, have been assigned to the purchasers of NEP's and Montaup's generation assets. 52/ Merger Policy Statement at 68,603-04. -28- 1. Federal Regulation NEES and EUA are currently registered holding companies under PUHCA and consequently there will be only a very limited impact on the federal regulatory structure as a result of the Merger. The Merger will have no impact on the relationship of NEES to its subsidiaries. Although initially the EUA operating companies will be separate affiliates of NEES, upon completion of the OpCo Mergers, the EUA affiliates will cease to exist, and hence the companies' structure will return to the pre-existing NEES structure. At the same time, Applicants recognize the commitment that Montaup has made currently in its Standards of Conduct53/ regarding sales of non-power goods and services.54/ In order to avoid any change in the pre-existing scope of federal regulation, Applicants make the following commitment: after completion of the HoldCo Merger, any transaction involving the sale of non-power goods and services between NEP or Montaup and any of their franchised public utility affiliates will be subject to the same commitment currently applicable to Montaup under its Standards of Conduct.55/ Because this commitment assures that - --------------- 53/ Applicants understand that, upon conclusion of the HoldCo Merger, both NEP's and Montaup's Standards of Conduct will apply to their respective new affiliated entities. Upon completion of the merger of Montaup into NEP, Montaup's Standards of Conduct will cease to exist, and NEP will be governed by its then-existing standards which, of course, would apply to any remaining former EUA affiliates, as well as all existing NEES affiliates. 54/ These commitments are as follows: "(1) any sale of non-power goods or services by the Company [Montaup] to its franchised public utility affiliate shall be at a price equal to the higher of its cost or market; and (2) any sale of non-power goods or services by a franchised public utility affiliate to the Company [Montaup] shall be at a price not to exceed market." 55/ See n. 54, supra. Upon completion of the OpCo and related mergers, many of the currently existing EUA Companies will cease to exist and, of course, this commitment would cease with respect to those entities at that time. -29- the Commission will have oversight over sales of non-power goods and services, there will be no adverse effect on federal regulation from the transaction. 2. State Regulation With respect to state regulation, the commissions in Massachusetts and Rhode Island, which have direct jurisdiction over the consolidation of the operating companies, will need to approve the mergers of the operating companies and the associated retail rate plans. In addition, state commissions in New Hampshire and Vermont, where Montaup owns property, may need to approve the transaction. Applicants believe that the states will continue to have the same jurisdiction over the operations of the utilities after the Merger as they had before, but, in any case, each affected state will have a full opportunity to address any impact on state regulation in connection with the filings that have been or will be made. No further action or review by the Commission is therefore required. Accordingly, there will be no adverse effect on state regulation as a result of the Merger. VI. ACCOUNTING TREATMENT In accordance with the Merger Policy Statement,56/ proper accounting principles will be applied to the Merger. The proposed transaction will be accounted for using the purchase method of accounting because the necessary - --------------- 56/ Merger Policy Statement at 68,604. -30- conditions to apply pooling of interest accounting are not met by the structure of this business combination.57/ The purchase method has been approved by the Commission when the pooling of interests method is not appropriate.58/ The acquisition premium recorded under the purchase method of accounting may be pushed down to the EUA operating companies.59/ Recording the acquisition premium on the acquired companies' books is consistent with SEC guidance,60/ and the Commission has approved it previously.61/ Section IV.A., above, explains that the Applicants expect to achieve savings and efficiencies for their customers as a result of this Merger. To the extent the acquisition premium and transaction costs are pushed down, the retail operating companies are seeking permission from state authorities to recover the acquisition premium and transaction costs in rates when it can be demonstrated that such savings and efficiencies have been achieved.62/ The operating companies subject to the Commission's jurisdiction will seek rate recovery only if Commission policy changes to permit such recovery. - --------------- 57/ This acquisition is being accomplished by an exchange of EUA's shares for cash, not by an exchange of EUA shares for NEES shares as required under the pooling rules. 58/ MidAmerican Energy Co., 85 FERC at 62,370; PG&E Corp. and Valero Energy Corp., 80 FERC paragraph 61,041 (1997); Enron Corp. and Portland General Corp., 78 FERC paragraph 61,179, 61,739-40; Entergy Services, Inc. and Gulf States Utils. Co., 65 FERC paragraph 61,332, 62,532-40 (1993). 59/ That premium would then be moved to the appropriate NEES company upon conclusion of the OpCo Mergers. 60/ See APB Opinion No. 16. 61/ See El Paso Electric Co. and Central and South West Services, Inc., 68 FERC paragraph 61,181, 61,918-19 (1994); Entergy Services, 65 FERC at 62,537. 62/ See Section V.B.2, above. -31- Finally, consistent with Commission policy, Applicants will submit their proposed accounting entries to the Commission for approval within six months after the Merger is consummated.63/ This submission will provide all accounting entries necessary to reflect the Merger, along with appropriate narrative explanations describing the bases for the entries. VII. INFORMATION REQUIRED OF APPLICANTS BY SECTION 33.2 OF THE COMMISSION'S REGULATIONS A. The exact name and address of the principal business office. The address of the principal business office to be used for the NEES companies is: New England Power Company 25 Research Drive Westborough, MA 01582 The address of EUA's principal business office is: Eastern Utilities Associates 1 Liberty Square Boston, MA 02107 - --------------- 63/ MidAmerican Energy Co., 85 FERC at 62,370; 18 C.F.R. Pt. 101, Electric Plant Instruction No. 5 and Account 102, paragraph B (1998). -32- B. Name and address of the person authorized to receive notices and communications with respect to application. For the NEES Companies: Edward Berlin, Esq. Thomas G. Robinson, Esq. Kenneth G. Jaffe, Esq. New England Power Company Scott P. Klurfeld, Esq. 25 Research Drive Swidler Berlin Shereff Friedman, LLP Westborough, MA 01582 3000 K Street, N.W., Suite 300 Telephone: 508-389-2877 Washington, DC 20007-5116 Facsimile: 508-389-2463 Telephone: 202-424-7500 robint@neesnet.com Facsimile: 202-424-7643 eberlin@swidlaw.com kgjaffe@swidlaw.com spklurfeld@swidlaw.com For EUA: David A. Fazzone, Esq. of David A. Fazzone, P.C., and McDermott, Will & Emery 28 State Street Boston, Massachusetts 02109-1775 Telephone: 617-535-4000 Facsimile: 617-535-3800 dfazzone@mwe.com C. Designation of the territories served by counties and states. NEP provides transmission service through facilities located in Massachusetts, Rhode Island, New Hampshire, and Vermont. It also continues to provide very limited wholesale electric service to a few customers. Granite State Electric Company provides retail electric service in 23 municipalities in Cheshire, Grafton, Hillsborough, Rockingham, and Sullivan Counties in New Hampshire. -33- Massachusetts Electric provides retail electric service in 149 municipalities in Berkshire, Bristol, Essex, Franklin, Hampden, Hampshire, Middlesex, Norfolk, Suffolk, and Worcester Counties in Massachusetts. Nantucket Electric Company provides retail electric service in the County of Nantucket in Massachusetts. Narragansett provides retail electric service in 27 municipalities in Bristol, Kent, Newport, Providence, and Washington Counties in Rhode Island. New England Electric Transmission Corporation, New England Hydro- Transmission Corporation, and New England Hydro-Transmission Electric Company, Inc. provide high-voltage transmission service in New Hampshire or Massachusetts. AllEnergy sells electric power and other energy products as a marketer throughout the Northeast and elsewhere in the United States. Montaup provides transmission service through facilities located in Massachusetts and Rhode Island. Blackstone Valley provides retail electric service in the cities of Central Falls, Pawtucket, Woonsocket, and four surrounding towns in Rhode Island. Eastern Edison provides retail electric service in Brockton and Fall River, Massachusetts, and 20 other cities and towns in southeastern Massachusetts. Newport Electric provides retail electric service in Jamestown, Middleton, Newport and Portsmouth, Rhode Island. -34- D. A general statement briefly describing the facilities owned or operated for transmission of electric energy in interstate commerce or the sale of electric energy at wholesale in interstate commerce. NEP is engaged in the wholesale sale and transmission of electric energy in interstate commerce. NEP owns approximately 2,200 miles of transmission lines that are used to transmit power in New England. As described above in Section III, NEP owns minority, non-operating interests in certain nuclear generating facilities and a very small minority interest in one oil-fired plant. Narragansett owns approximately 300 miles and Massachusetts Electric owns approximately 80 miles of transmission facilities that are controlled by NEP under integrated facilities agreements. Three other NEES subsidiaries own and operate a total of approximately 139 miles of bi-polar transmission facilities that comprise part of the transmission intertie between New England and Hydro Quebec: New England Electric Transmission Corporation, New England Hydro-Transmission Corporation, and New England Hydro-Transmission Electric Company, Inc. NEES, as stated above, is a registered holding company and, as such, is subject to regulation by the SEC. NEES does not directly own any facilities subject to the Commission's jurisdiction. Montaup is engaged in the wholesale sale and transmission of electric energy in interstate commerce. As described above in Section III, it owns minority, non-operating interests in certain nuclear generating facilities, but has sold or entered into sales agreements regarding all other generation facilities it once owned. Besides owning transmission facilities, it leases transmission facilities from its affiliates. -35- Eastern Edison is the direct holding company of Montaup. It owns with Montaup approximately 4,600 miles of transmission and distribution lines. Blackstone Valley owns approximately 1,700 miles of transmission and distribution lines. Newport Electric owns approximately 800 miles of transmission and distribution lines. EUA, as stated above, is a registered holding company and, as such, is subject to regulation by the SEC. It does not directly own any facilities subject to the Commission's jurisdiction. E. Whether the application is for disposition of facilities by sale, lease, or otherwise, a merger or consolidation of facilities, or for purchase or acquisition of securities of a public utility, also a description of the consideration, if any, and the method of arriving at the amount thereof. The Merger involves the acquisition by NEES of EUA, and subsequent mergers of their respective operating companies, as described in Section IV of the Application, above. A copy of the Merger Agreement is included as Exhibit H to this Application. F. A statement of facilities to be disposed of, consolidated, or merged, giving a description of their present use and of their proposed use after disposition, consolidation, or merger. State whether the proposed disposition of facilities or plan for consolidation or merger includes all the operating facilities of the parties to the transaction. The Merger includes all of the operating facilities of Applicants, including all franchises, permits and operating rights owned by them and their subsidiaries. Following the Merger, all jurisdictional facilities will be operated in substantially the same manner as they are currently operated. -36- G. A statement (in the form prescribed by the Commission's Uniform System of Accounts for Public Utilities and Licensees) of the cost of the facilities involved in the sale, lease, or other disposition or merger or consolidation. If original cost is not known, an estimate of original cost based, insofar as possible, upon records or data of the applicant or its predecessors must be furnished, together with a full explanation of the manner in which such estimate has been made, and a description and statement of the present custody of all existing pertinent data and records. See Exhibit C to this Application. H. A statement as to the effect of the proposed transaction upon any contract for the purchase, sale, or interchange of electric energy. Except as described in this Application and the accompanying Section 205 Filing, the Merger will not have any known effect on the rights, interests or obligations of the parties to contracts for the purchase, sale, transmission or interchange of electric energy involving NEES, the NEES Companies, EUA, or the EUA Companies. I. A statement as to whether or not any application with respect to the transaction or any part thereof is required to be filed with any other Federal or State regulatory body. The following are the other regulatory approvals or filings that are contemplated being made and copies are included with this Application in Exhibit G or will be provided upon filing: 1. NEES and EUA will file an application with the SEC for approval of the Merger pursuant to PUHCA. 2. Montaup, as holder of minority interests in several nuclear facilities as described above, will file an application with the Nuclear Regulatory Commission for approval because the Merger will transfer these facilities to NEP. -37- 3. NEES and EUA obtained on April 30, 1999, from the Federal Trade Commission early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. 4. NEP and Montaup are filing contemporaneously an application for approval of consolidation of NEP's and Montaup's transmission rates, as a rate change under Section 205 of the FPA and are requesting consolidation of the proceedings. A Section 205 filing modifying Montaup's CTC will be made if required. 5. Requests for approval of the Merger and approval of a rate plan have been made with the Massachusetts Department of Telecommunications & Energy and will shortly be filed with the Rhode Island Public Utilities Commission. 6. Requests for approval of the Merger will be filed with the Connecticut Department of Public Utility Control, the Vermont Department of Public Service and the New Hampshire Public Utilities Commission, if required. J. The facts relied upon by applicants to show that the proposed disposition, merger, or consolidation of facilities or acquisition of securities will be consistent with the public interest. See Section V of this Application, above. K. A brief statement of franchises held, showing date of expiration if not perpetual. The retail distribution affiliates of NEES and EUA have franchises. The franchises of those companies that are Applicants are listed below. -38- Massachusetts Electric Company has non-exclusive franchise rights to serve in the following cities and towns located in the Commonwealth of Massachusetts: Adams, Alford, Amesbury, Andover, Athol, Attleboro, Auburn, Ayer, Barre, Belchertown, Bellingham, Berlin, Beverly, Billerica, Blackstone, Bolton, Boxford, Brimfield, Brookfield, Charlemont, Charlton, Chelmsford, Cheshire, Clarksburg, Clinton, Douglas, Dracut, Dudley, Dunstable, East Brookfield, East Longmeadow, Egremont, Erving, Essex, Everett, Florida, Foxborough, Franklin, Gardner, Gloucester, Goshen, Grafton, Granby, Great Barrington, Groton, Hamilton, Hampden, Hancock, Hardwick, Harvard, Haverhill, Hawley, Heath, Hingham, Holbrook, Holland, Hopedale, Hubbardston, Lancaster, Lawrence, Leicester, Lenox, Leominster, Lowell, Lynn, Malden, Manchester, Marlborough, Medford, Melrose, Mendon, Methuen, Milford, Millbury, Millville, Monroe, Monson, Montery, Mt. Washington, Nahant, Nantucket, New Braintree, Newbury, Newburyport, New Marlborough, New Salem, North Adams, Northampton, North Andover, Northborough, Northbridge, North Brookfield, Norton, Oakham, Orange, Oxford, Palmer, Paxton, Pepperell, Petersham, Phillipston, Plainville, Quincy, Randolph, Rehoboth, Revere, Rockport, Rowe, Royalston, Rutland, Salem, Salisbury, Saugus, Seekonk, Sheffield, Shirley, Shutesbury, Southborough, Southbridge, Spencer, Stockbridge, Sturbridge, Sutton, Swampscott, Tewksbury, Topsfield, Tyngsborough, Upton, Uxbridge, Wales, Ware, Warren, Warwick, Webster, Wendell, Wenham, Westborough, West Brookfield, Westford, Westminster, West Newbury, West Stockbridge, Weymouth, Wilbraham, Williamsburg, Williamstown, Winchendon, Winthrop, Worcester, Wrentham. -39- Narragansett has retail exclusive electric distribution franchises in the State of Rhode Island, including the cities and towns of Barrington, Bristol, Charlestown, Coventry, Cranston, East Greenwich, East Providence, Exeter, Foster, Glocester, Hopkinton, Johnston, Little Compton, Narragansett, North Kingstown, North Providence, Providence, Richmond, Scituate, Smithfield, South Kingstown, Tiverton, Warren, Warwick, Westerly, West Greenwich, and West Warwick. Eastern Edison has retail franchises in the following communities in the Commonwealth of Massachusetts: Abington, Avon, Bridgewater, Brockton, Cohasset, Dighton, East Bridgewater, Easton, Fall River, Halifax, Hanson, Hanover, Norwell, Pembroke, Rockland, Scituate, Somerset, Stoughton, Swansea, West Bridgewater, Westport, and Whitman. Blackstone Valley has retail franchises in the following communities in the State of Rhode Island: Central Falls, Cumberland, Lincoln, North Smithfield, Pawtucket, Woonsocket and Burrillville. Newport Electric has retail franchises in the following communities in the State of Rhode Island: Jamestown, Middletown, Newport, and Portsmouth. L. A form of notice suitable for publication in the Federal Register, which will briefly summarize the facts contained in the application in such way as to acquaint the public with its scope and purpose. A form of notice suitable for publication in the Federal Register is attached to this Application, both in hard copy form and on diskette. -40- VIII. EXHIBITS REQUIRED PURSUANT TO SECTION 33.3 OF THE COMMISSION'S REGULATIONS Pursuant to Section 33.3 of the Commission's regulations, the following Exhibits are submitted, which are attached to and included with this Application: Exhibit A. Copies of All Resolutions of Directors. Exhibit B. Statement of Intercorporate Relationships. Exhibit C. Statements A and B, FERC Form No. 1. Exhibit D. Statement of All Known Contingent Liabilities. Exhibit E. Statement C, FERC Form No. 1. Exhibit F. Analysis of Retained Earnings. Exhibit G. Copies of All Applications Filed with Other Federal and State Regulatory Bodies and Certified Copies of Each Order Relating Thereto, Where Applicable. Exhibit H. Copies of All Contracts with Respect to the Merger. Exhibit I. Map. IX. REQUEST FOR APPROVAL OF NATIONAL GRID-NEES MERGER WITH RESPECT TO EUA COMPANIES AND FOR INCORPORATION BY REFERENCE OF REQUIRED EXPLANATIONS AND EXHIBITS The NEES Companies currently have pending in Docket No. EC99-49-000 a request for approval of a merger that will make NEES a subsidiary of National Grid. If the National Grid-NEES merger is completed before the OpCo Mergers, Commission approval would be required for the acquisition by National Grid of the EUA Companies resulting from the National Grid-NEES merger. For administrative efficiency, Applicants request that such approval be granted in connection with approval of this Application because the National Grid transaction satisfies the Commission's merger policy criteria with respect to the EUA Companies in the same manner as it does with respect to the NEES Companies. -41- As explained in the National Grid-NEES application, National Grid is a holding company incorporated in England and Wales. It owns all the shares of The National Grid Company plc, a corporation that is the world's largest privately-owned independent electric transmission company. The National Grid Company owns, operates and maintains the high voltage network in England and Wales, which connects power stations with distribution networks. The National Grid Company is also responsible for scheduling and dispatching generation to meet demand second-by-second and manages and controls the software systems to do so. Additionally, The National Grid Company owns and operates interconnectors that enable electricity to be transferred between the England and Wales market and Scotland and France. The National Grid-NEES application demonstrates that their merger is in the public interest, satisfying the three requirements for approval established by the Commission. The same criteria are equally satisfied with respect to the EUA Companies. First, as in the case of the NEES Companies, the EUA Companies do not have facilities or sell products in any common geographic markets with National Grid and its related companies.64/ Since National Grid and the EUA Companies do not conduct business in the same geographic markets, there can be no adverse impact on competition.65/ - --------------- 64/ Attachment 2 is a declaration from Dr. Kahwaty confirming that the competition analysis applicable to the NEES Companies and National Grid applies equally to the EUA Companies. 65/ It should be noted that on April 9, 1999, the Federal Trade Commission granted the request for early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 filed by NEES and National Grid. A copy of that termination notice was filed in Docket No. EC99-49-000 on April 14, 1999. -42- Second, the combination of EUA with NEES in the overall context of a National Grid acquisition will not increase rates, but instead will serve to lower costs through improved efficiency and enhanced operations of EUA's existing operating companies. These savings will be both direct, in terms of reduced costs for transmission and distribution services, and indirect by producing improvements in the transmission and distribution network that will in turn improve the overall operations of the electricity market. Finally, bringing the EUA Companies into the National Grid-NEES merger will not adversely affect either federal or state regulation. With respect to federal regulation, there will be no change in the relationship among the EUA system of companies, and hence there will be no impact on federal regulation for transactions among those companies. With respect to the new affiliate relationships created by the National Grid-NEES merger, the EUA Companies will make the same commitment as the NEES Companies have done: they commit to abide by Commission policy with respect to sales of non-power goods and services for transactions between the EUA Companies and National Grid or its affiliates.66/ With respect to state regulation, the structure of the EUA Companies will not be changed by the National Grid-NEES merger. Each state commission that currently has authority over the EUA operating companies will continue to have authority over the rates, services and operations of those companies. - --------------- 66/ This separate commitment is applicable only for the interim period until the OpCo Mergers are completed, since at that point, only NEES Companies survive. -43- Because (i) the analysis supporting approval of the National Grid-NEES merger is exactly the same for the EUA Companies as it is for the NEES Companies, and (ii) the specific information regarding National Grid that is not included in this Application is included in the National Grid-NEES application in Docket No. EC99-49, and (iii) administrative efficiency would be served by avoiding the duplicative filing in this proceeding of the same materials that are already included in that existing docket, Applicants request that the Commission incorporate by reference all materials in Docket No. EC99-49 that are needed to support approval here of the acquisition of the EUA Companies by National Grid. X. PROCEDURAL MATTERS The facts and analysis provided in this Application demonstrate that the Merger will not have an adverse effect on competition, rates or regulation. It easily satisfies all requirements of Section 203 of the FPA, as implemented by Commission regulation and policy, and thus is in the public interest. Consequently, Applicants, NEES and EUA, as well as National Grid, respectfully request, on the basis of the facts and analysis set forth in this Application both directly and incorporated by reference, that by July 31, 1999, the Commission act without hearing (i) to approve the Merger and, (ii) if required, grant approval of the acquisition of the EUA Companies by National Grid. -44- XI. CONCLUSION For the foregoing reasons, Applicants, NEES and EUA respectfully request that the Commission: (1) approve both the HoldCo Merger and the OpCo Mergers under Section 203 of the FPA, (2) approve the acquisition by National Grid of the EUA Companies (to the extent required), (3) grant any other authorizations, approvals or waivers necessary or appropriate to allow this Application to be accepted for filing and granted; and (4) issue such approvals, authorizations and waivers expeditiously, without condition, modification or trial-type hearing. Respectfully submitted, /s/ Scott P. Klurfeld /s/ David A. Fazzone - ------------------------------------ ---------------------------------------- Edward Berlin, Esq. David A. Fazzone, Esq. of Kenneth G. Jaffe, Esq. David A. Fazzone, P.C., and Scott P. Klurfeld, Esq. McDermott, Will & Emery Swidler Berlin Shereff Friedman, LLP 28 State Street 3000 K Street, N.W., Suite 300 Boston, Massachusetts 02109-1775 Washington, D.C. 20007-5116 (617) 535-4000 (202) 424-7500 Attorney for Montaup Electric Company and Affiliated Applicants Thomas G. Robinson, Esq. New England Power Company 25 Research Drive Westborough, MA 01582 (508) 389-2877 Attorneys for New England Power Company and Affiliated Applicants May 5, 1999 -45- [FORM OF NOTICE] UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) THE NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-70-000 NEW ENGLAND HYDRO-TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO-TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY, L.L.C. ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) NOTICE OF FILING Take notice that on May 5, 1999, New England Power Company ("NEP") and its affiliates holding jurisdictional assets (Massachusetts Electric Company, The Narragansett Electric Company, New England Electric Transmission Corporation, New England Hydro-Transmission Corporation, New England Hydro-Transmission Electric Company, Inc., and AllEnergy Marketing Company, L.L.C.) (collectively, the "NEES Companies"), Montaup Electric Company and its affiliates holding jurisdictional assets (Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation) (collectively, the "EUA Companies"), and Research Drive LLC submitted for filing an application under Section 203 of the Federal Power Act (16 U.S.C. ss. 824b) and Part 33 of the Commission's Regulations (18 C.F.R. ss. 33.1 et seq. (1998)) seeking the Commission's approval and related authorizations to effectuate a merger, the result of which would be to merge New England Electric System ("NEES"), the parent company of the NEES Companies, with the Eastern Utilities Associates ("EUA"), the parent company of the EUA Companies. Through the Merger, EUA will become a wholly-owned subsidiary of NEES, and will subsequently be consolidated into NEES. In addition, the Application seeks the Commission's approval and authorization for the subsequent mergers and consolidations of the complementary operating companies of the two systems that hold jurisdictional assets. Finally, the Application requests approval, if required, of the acquisition by The National Grid Group plc ("National Grid") of the EUA Companies resulting from the proposed merger of National Grid and NEES, approval of which has been sought in Docket No. EC99-49-000. The Application states that it (i) includes all the information and exhibits required by Part 33 of the Commission's regulations and the Commission's Merger Policy Statement with respect to the Merger; (ii) incorporates by reference any additional materials required with respect to the acquisition by National Grid of the EUA Companies; and (iii) easily satisfies the criteria set forth in the Commission's Merger Policy Statement. The Application requests that the Commission grant whatever waivers or authorizations are needed and grant approval without condition, modification or an evidentiary, trial-type hearing. The Application states that the parties are seeking to close the Merger expeditiously and thus the Applicants have requested Commission approval by July 31, 1999. The Applicants have served copies of the filing on the state commissions of Connecticut, Massachusetts, New Hampshire, Rhode Island and Vermont. Any person desiring to be heard or to protest said application should file a motion to intervene or protest with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426 in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 C.F.R. 385.211 and 18 C.F.R. 385.214). All such motions or protests should be filed on or before . Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make the protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. Copies of this filing are on file with the Commission and are available for public inspection. -2- Attachment 1 [LECG Logo] UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) THE NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-_____ NEW ENGLAND HYDRO-TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO-TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY, L.L.C. ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) Declaration of Henry J. Kahwaty I, Henry J. Kahwaty, declare: I. Introduction. 1. My name is Henry J. Kahwaty. I am a Senior Managing Economist with LECG (formerly Law & Economics Consulting Group, Inc.). LECG is a firm providing management consulting and expert analysis in the areas of economics, finance, and accounting. My business address is 1600 M Street, N.W., Suite 700, Washington, D.C. 20036. 2. I received my Ph.D. in Economics from the University of Pennsylvania in 1991. My fields of specialization include industrial organization and public economics. Industrial organization involves the study of competition and regulation in individual markets. Prior to joining LECG, I worked for nearly four years as an economist for the Antitrust Division of the U.S. Department of Justice. I have analyzed the competitive implications of numerous mergers, both during my employment with the Antitrust Division and with LECG. I have worked on competition issues in electricity, telecommunications, and other network industries, and I have broad experience in applied microeconomic analysis. A copy of my curriculum vitae is provided as Exhibit HJK-1. 3. I have been asked by counsel for New England Power Company ("New England Power") and Montaup Electric Company ("Montaup") to consider the competitive implications of the proposed acquisition of Eastern Utilities Associates ("EUA") by New England Electric System ("NEES").1 This Declaration summarizes my analysis of the acquisition. 4. I conclude that this acquisition will not result in any reduction in competition because NEES, EUA, and their affiliates have divested nearly all of their generation facilities or entitlements to others and have exited the generation business as a part of the industry restructuring efforts of several states and the Federal Energy Regulatory Commission ("FERC" or "Commission"). While both systems continue to hold minor entitlements in generation assets, their shares of generation are de minimus, and both are committed to divesting their small remaining - --------------- 1 New England Power is a subsidiary of NEES; Montaup is a subsidiary of EUA. 2 entitlements. Furthermore, the merged company will not have controlling interests in any generation facility. As a result, the merged company will not be able to withhold supply in an effort to increase prices. In addition, there is no competition between NEES and EUA affiliates for the provision of transmission services. Transmission services will continue to be available under the open access tariffs of NEPOOL and the merged company. Finally, the transaction will not result in harm to competition arising from vertical effects. Both systems supply transmission and distribution services at regulated rates under open access tariffs, and neither controls other inputs, such as fuel supplies or equipment, necessary for the generation or delivery of electricity. Thus, the proposed acquisition of EUA by NEES will not result in harm to competition. II. Background. 5. NEES is a holding company whose affiliates own and operate electric transmission and distribution assets in New England. In particular, NEES subsidiary New England Power owns transmission assets located in Massachusetts, New Hampshire, and Vermont. In addition, New England Power operates transmission facilities in Rhode Island and Massachusetts through integrated transmission agreements with its affiliates, The Narragansett Electric Company and Massachusetts Electric Company. Other NEES affiliates own and operate transmission facilities interconnecting New England and 3 Quebec.2 The NEES distribution companies include Massachusetts Electric Company, Nantucket Electric Company, The Narragansett Electric Company, and Granite State Electric Company. Massachusetts Electric Company and Nantucket Electric Company provide distribution service in Massachusetts; The Narragansett Electric Company provides distribution service in Rhode Island; and Granite State Electric Company provides distribution service in New Hampshire. NEES also owns several unregulated companies that market energy or provide other services. These companies operate primarily in the northeastern United States. As a result, virtually all of the NEES companies' revenues are derived from services provided primarily in the states of Massachusetts, Rhode Island, and New Hampshire.3 6. Pursuant to electric utility restructuring legislation enacted in Rhode Island, Massachusetts, and New Hampshire and settlement agreements approved by state regulators and the FERC, New England Power recently completed a divestiture of its fossil and hydroelectric generation assets and its power purchase contracts to USGen New England, Inc. This divestiture was - --------------- 2 These affiliates include New England Electric Transmission Corporation, New England Hydro-Transmission Corporation, and New England Hydro- Transmission Electric Company, Inc. 3 Revenues from activities outside the northeastern United States are generated by NEES subsidiary NEES Global, Inc. This subsidiary performs certain consulting services within and outside the United States. In addition, NEES subsidiary AllEnergy recently purchased Griffith Consumers Company, a distributor of residential and commercial heating oil in Washington, D.C., and in parts of Maryland, Delaware, Virginia, and West Virginia. 4 finalized on September 1, 1998. Prior to divestiture, New England Power owned approximately 5,450 MW of generation capacity, including fossil, hydroelectric, nuclear, and purchased power contracts. All of its generation capacity was located in New England. New England Power divested over 5,000 MW of this capacity, including the sale of its ownership stakes in 18 power plants and the assignment or transfer of its entitlements under 23 power contracts, to USGen New England. As a result, New England Power retained only approximately 400 MW of generation capacity. This capacity includes minority interests in three operating nuclear facilities and one fossil generation facility. o Millstone 3. New England Power owns 12.21 percent of the Millstone 3 nuclear generation station. This represents a generation capacity of 139 MW.4 o Seabrook 1. New England Power owns 9.96 percent of the Seabrook 1 nuclear generation station. This represents a generation capacity of 116 MW.5 o Vermont Yankee. New England Power has a net entitlement to 17.98 percent of the Vermont Yankee nuclear generation station. This represents a generation capacity of 90 MW.6 - --------------- 4 NEPOOL Forecast Report of Capacity, Energy, Loads and Transmission 1997-2006 ("1997 CELT Report"), April 1, 1997 at 18. 5 NEPOOL Forecast Report of Capacity, Energy, Loads and Transmission 1998-2007 ("1998 CELT Report"), April 1, 1998 at 19. 6 This is New England Power's share of Vermont Yankee's summer capability rating. New England Power's share of this facility's winter capability rating is 95 MW. 1998 CELT Report at 19. New England Power owns 20 percent of Vermont Yankee, but it has resold a portion to a group of municipals. 5 o Wyman 4. New England Power owns 9.27 percent of the Wyman 4 oil-fired steam turbine generating station. This represents a generation capacity of 57 MW.7 7. EUA is a holding company whose affiliates own and operate electric transmission and distribution assets in Massachusetts and Rhode Island. In particular, EUA subsidiary Montaup owns transmission assets in Massachusetts and leases transmission facilities from affiliates in both Massachusetts and Rhode Island. The EUA distribution companies include Eastern Edison Company, Blackstone Valley Electric Company, and Newport Electric Corporation. Eastern Edison Company provides distribution service in Massachusetts, and both Blackstone Valley Electric Company and Newport Electric Corporation provide distribution service in Rhode Island. The EUA distribution companies do not provide transmission services. EUA also owns several unregulated companies active in energy-related businesses, including the energy management company, Cogenex Corporation. 8. As with New England Power, Montaup has sold or entered into agreements to sell nearly all of its generation assets to other companies pursuant to electric utility restructuring legislation and settlement agreements approved by regulators in Rhode Island, Massachusetts, and at the FERC. Prior to its divestitures, Montaup owned or held equity interest in approximately 570 MW of generation capacity, all in New England. It also - --------------- 7 1998 CELT Report at 19. 6 held power purchase entitlements in an additional 500 MW. Montaup, however, recently has sold or entered into agreements to sell its fossil and hydroelectric generation capacity. It has also signed agreements for the transfer of power purchase contracts and for a buyout of its 11 percent power entitlement from the Pilgrim nuclear generation station. Overall, Montaup has sold, or agreed to sell or transfer, assets and rights to purchase power entitlements to Constellation Power Source (an affiliate of Baltimore Gas and Electric), NRG Energy (an affiliate of Northern State Power), FPL Group, BayCorp Holdings (an affiliate of Great Bay Power), Southern Energy (an affiliate of Southern Company), TransCanada Power Marketing, and others.8 Montaup's remaining generation resources are minority shares in three nuclear generating stations including: o Millstone 3. Montaup owns 4.01 percent of the Millstone 3 nuclear generation station. This represents a generation capacity of 46 MW.9 o Vermont Yankee. Montaup has a net entitlement to 2.25 percent of the Vermont Yankee nuclear generation station. This represents a generation capacity of 11 MW.10 - --------------- 8 Montaup's sales of generation assets and entitlements to Southern Energy, TransCanada Power Marketing, and NRG Energy, and Newport Electric Corporation's sale to Wabash Power Equipment, have been completed. The remaining asset and entitlement sales or transfers are pending. 9 1998 CELT Report at 15. 10 This is Montaup's share of Vermont Yankee's summer capability rating. Montaup's share of this facility's winter capability rating is 12 MW. 1998 CELT Report at 15. Montaup owns 2.5 percent of Vermont Yankee, but it has resold a portion to a group of municipals. 7 o Pilgrim. Montaup has a purchased power agreement with Entergy giving Montaup an entitlement to 11 percent of the output of this nuclear station in 1999. This represents a generation capacity of 74 MW.11 This entitlement declines over time and ends after 2004.12 These resources represent a total of approximately 131 MW of generation capacity currently, declining to 57 MW after 2004. 9. Industry restructuring in New England has involved the unbundling of generation, transmission, and distribution, and the advent of the retail marketing of electricity. Transmission and distribution remain regulated activities, and competition is being introduced in generation and retail supply. An independent system operator, ISO New England, was established on July 1, 1997.13 ISO New England is responsible for managing the New England region's electric bulk power generation and transmission systems and administering the region's open access transmission tariff. The region's open access transmission tariff includes a combination of "license plate" and "postage stamp" pricing. This allows power to be transmitted from any - --------------- 11 1998 CELT Report at 15. 12 Montaup presently has a life-of-unit purchase power agreement with Boston Edison Company covering 11 percent of the energy generated by the Pilgrim station. Boston Edison Company is selling Pilgrim to Entergy Nuclear Generating Company, and Montaup has an agreement with Entergy Nuclear Generating to purchase power from this unit. The purchase power agreement entitles Montaup to 11 percent of the output of the Pilgrim station in 1999. This entitlement declines to 8.8 percent in 2002, 5.5 percent in 2003 and 2004, and ends thereafter. 13 The FERC approved the creation of the ISO New England in 79 FERC paragraph 61,374 (1997), reh'g denied, 85 FERC paragraph 61,242 (1998). 8 location in New England to load on a transmission provider's system at uniform, flat rates that vary among the transmission providers. The ISO also operates the wholesale electric power market for New England and settles "spot" transactions. In addition, it tracks bilateral contracts between market participants. 10. Access to New England's transmission system has been opened to all competitors in electric generation via the region's open access transmission tariff and the open access transmission tariffs of the individual utilities owning transmission assets. Participants who desire to reserve transmission services for the supply of electricity into the New England region, or through the New England region, can do so through ISO New England. An Internet-based Open Access Same Time Information System ("OASIS") has been designed to provide participants with real-time information about the transmission system. Participants can use the OASIS to reserve transmission services. NEPOOL's rates for transmission services are derived from the actual costs of building and maintaining transmission facilities and are reviewed and approved by the FERC. III. The Analysis of Market Power. 11. Market power is the ability profitably to increase and maintain prices above competitive levels for a significant period of time. My analysis of 9 the proposed acquisition of EUA by NEES addresses whether this transaction will create or enhance market power or otherwise facilitate its exercise. 12. The analysis of the competitive implications of mergers typically has several parts. The first part includes the definition of the relevant market or markets, the identification of the participants in these markets, and the calculation of market shares and market concentration. Market concentration is a measure that reflects that extent to which a few firms account for market sales or capacity.14 Markets with many firms and low levels of concentration are generally presumed to be competitive. Markets with fewer firms and high levels of concentration require more detailed analysis to determine whether significant market power exists. Thus, market concentration is used to distinguish between markets where there are enough participants to result in competitive outcomes and markets where an analysis of other structural market features is required to evaluate the prospects for a successful exercise of market power. - --------------- 14 The Herfindahl-Hirschman Index ("HHI") is a commonly used measure of market concentration. This index is calculated by summing the squares of the market shares of the firms in the market. For example, a market with three firms with market shares of 35 percent, 40 percent, and 25 percent would have an HHI value of 35(squared) + 40(squared) + 25 (squared) or 3,450. Markets with a large number of firms, each with a small market share, have HHI values near zero. Markets served by only one provider have an HHI of 1002 or 10,000. 10 13. In its Policy Statement15 on mergers, the FERC adopted the market concentration screening criteria set out in the Horizontal Merger Guidelines of the U.S. Department of Justice and the Federal Trade Commission.16 (These screens are described in more detail in the Appendix to this Declaration.) When a merger fails to satisfy the safe harbor concentration-based screening criteria, the analysis then considers the competitive effects likely to result from the proposed transaction. Concentration screens consider only market structure; competition analysis moves past structure to consider both conduct and the effect of that conduct on market prices. 14. After analyzing the likely competitive effects, if any, the next step in merger analysis involves the study of the barriers to entry facing new suppliers and the barriers to expansion by existing suppliers. In the absence of significant barriers to entry, existing firms in an industry are not likely to be able to exert substantial market power because any attempt to raise prices above competitive levels would attract the entry of new providers. Thus, entry can deter or counteract an exercise of market power. On the other hand, where barriers to entry are substantial, new providers - --------------- 15 Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, ("Policy Statement"), Order No. 592, 77 FERC 61,263 (1996). 16 The Horizontal Merger Guidelines were issued April 2, 1992 and revised April 8, 1997. http://www.usdoj.gov/atr/public/guidelines/horiz_book/ hmg1.html. 11 would find it difficult or impossible to enter the market in response to an attempt by the incumbent(s) to raise prices above competitive levels. 15. The final step in the analysis is to ask whether an otherwise anticompetitive merger may nevertheless be socially beneficial due to the potential for the merger to result in cost reductions or other efficiencies that would not otherwise be achievable. Efficiencies from economies of scale, the exploitation of complementary assets, expanded applications of research and development, best-practice cost reductions, and others are pro-competitive. The purpose of merger analysis is to consider whether the potential harm to competition from the structural change induced by a merger outweighs any resulting efficiencies from the merger. Regulators should permit mergers when anticipated benefits exceed potential social costs.17 In the next two sections, I discuss whether the proposed acquisition of EUA by NEES will result in harm to competition in the generation and transmission of electricity. - --------------- 17 For example, although not the case there, the antitrust enforcement agencies will allow an otherwise anticompetitive merger or acquisition to proceed unchallenged if the imminent failure of one of the merging parties would cause the assets of that firm to exit the relevant market. Horizontal Merger Guidelines at section 5. 12 IV. The Proposed Merger Will Not Harm Electric Generation Competition 16. The proposed acquisition of EUA by NEES will not result in harm to competition in the wholesale generation market. New England Power and Montaup own only a de minimus share of the generation in New England. In addition, both are committed to selling their few remaining generation resources, so their ownership of generation is likely only to be temporary. Furthermore, as the merged company will have only minority interests in generation facilities, it will control neither the operations nor the pricing of the NEPOOL market products from these facilities. In particular, due to its lack of operational control, the merged company will not have the ability to exercise market power by restricting output from these facilities. In addition, the New England market recently has experienced both entry by new merchant plants and the expansion of existing plants. This demonstrates that barriers to entry are low and reinforces my conclusion that the merged company will not possess generation market power. My analysis bypasses the definition of relevant markets and the consideration of market concentration screens and instead directly considers competitive effects analysis. However, in the Appendix, I consider recent screening analyses for New England prepared by others. When modified to represent the NEES/EUA transaction, the resulting increases in HHIs are well below the FERC's screening thresholds, further supporting my conclusion that the acquisition of EUA by NEES will not harm competition in wholesale markets. 13 17. I assume for the purposes of my analysis that the relevant geographic market is NEPOOL. This is reasonable because the pool-wide transmission tariff in New England permits the delivery of power from anywhere in the region covered by ISO New England to a given location for one price and because, under ordinary conditions, NEPOOL dispatch is generally unconstrained by transmission limitations. In the absence of transmission limitations, NEPOOL's transmission pricing allows generation assets located across the region to compete with each other without having cost advantages or disadvantages caused by different transmission fees. This geographic market definition is consistent with the hypothetical monopolist paradigm of the Horizontal Merger Guidelines as it likely represents the most narrow geographic market relevant to the analysis of this merger. Basing the analysis on a larger relevant geographic market would only serve to reduce the market shares of NEES and EUA insomuch as all their generation resources are located with the NEPOOL geographic area. 18. Post-merger, NEES affiliates will own only a de minimus share of generation in New England. Assuming that all of the generation asset sales and purchase power transfers announced by EUA and its affiliates are consummated, the post-merger generation portfolio of NEES and its affiliates will consist solely of minority shares in five power plants 14 resulting in generation resource entitlements totaling 533 MW.18 The merged company's shares of these five facilities are summarized in Exhibit HJK-2. 19. There is over 24,200 MW of generation capacity in New England.19 As a result, the merged firm's post-merger entitlement of 533 MW represents only about two percent of all generation in New England. 20. Furthermore, USGen New England has an option to purchase 98 percent of New England Power's nuclear plant capacity and energy output. This option lasts as long as New England Power retains its interests in these facilities and as long as USGen New England is obligated to supply wholesale standard offer service to NEES's distribution company subsidiaries.20 Any sales to USGen New England are made at the discretion of USGen New England and are - --------------- 18 This will fall to 455 MW after 2004 when Montaup's entitlements in the Pilgrim station expire as contemplated in its pending agreement with Entergy Nuclear Generation. See Footnote 12 above. 19 NEPOOL Forecast Report of Capacity, Energy, Loads and Transmission 1999-2008 ("1999 CELT Report"), April 1, 1999 at 5. 20 See Wholesale Sales Agreement between New England Power Company and USGen Acquisition Corporation, August 5, 1997 ("Wholesale Sales Agreement") at Article 3 section 3.1. All former retail customers of the NEES and EUA distribution companies in Massachusetts and Rhode Island have an option to take service from the distribution company under a standard contract at regulated rates as opposed to taking service from competitive providers at prices prevailing in the market. Standard offer rates increase over time to encourage customers to move from regulated service to market alternatives. The NEES and EUA distribution companies must make wholesale purchases to meet their standard offer service obligations. For a description of the standard offer, see, for example, Restructuring Settlement Agreement, Massa chusetts Department of Public Utilities Docket Nos. 96-100 and 96-25 ("Restructuring Settlement Agreement"), at section I.B.5, http://www.nees.com/news/settlmnt.htm. 15 priced at either spot market rates or regulated rates, depending on the use of the electricity.21 USGen New England has exercised its option and has taken most of the output from New England Power's nuclear entitlements since August 1998. This further limits the amount of capacity and energy under the control of New England Power. 21. The merged company's ownership of these assets will only be temporary, however. New England Power and Montaup have each committed in their Restructuring Agreements with Massachusetts and Rhode Island to endeavor to divest all of their generation resources, including their nuclear entitlements, and are presently attempting to do so.22 Vermont Yankee Nuclear Power Corporation, with both New England Power's and Montaup's support, has signed a letter of intent to sell the Vermont Yankee plant to - --------------- 21 The prices for sales to USGen New England are spot market prices for energy, installed capacity, and operable capacity, except for the part of the nuclear output used to provide wholesale standard offer service to NEES distribution companies. Sales to USGen New England for wholesale standard offer service are priced at the lower of spot market rates and rates just below the wholesale standard offer price. See Wholesale Sales Agreement at Article 5 section 5.1. 22 See, for example, Restructuring Settlement Agreement at section V.D.1. 16 a third party. In addition, New England Power is currently in discussions with a party interested in purchasing its share of Wyman 4. Furthermore, New England Power is obligated to file a plan for divesting its remaining generation with regulators in New Hampshire by July 1, 1999. As a result, the ownership of the generation resources summarized in Exhibit HJK-2 by New England Power, Montaup, or their affiliates is likely to be temporary. 22. Neither New England Power nor Montaup maintains operational control over any generation facility. The firm's largest share in a generation resource post-merger is approximately 20 percent, and its shares of both Seabrook 1 and Wyman 4 are below 10 percent. In addition to lacking operational control, all but one of the generating stations in which the merged company will have entitlements are non-dispatchable nuclear units. As a result, the merged firm will not be able unilaterally to restrict output in an attempt to increase prices. 23. Due to the very small generation entitlements of NEES and EUA affiliates in New England, their commitment to divest these remaining entitlements, and their lack of operational control over their generation resources, I conclude that the proposed acquisition of EUA by NEES will not harm competition in electric generation in New England. In particular, the proposed acquisition will not enable the parties profitably to restrict output or increase prices. 17 24. New participants have joined the New England market recently by purchasing divested generation resources. Exhibit HJK-3 provides information on several of these firms. Purchasers of generation resources in New England include affiliates of Baltimore Gas and Electric, FPL Group, Northern States Power, PG&E, Sithe Energies, Southern Company, and Wisconsin Energy. 25. Many of these new market participants have announced the construction of new generation facilities or the expansion of existing facilities. Examples include: o PG&E Corp. PG&E subsidiary Millennium Power Partners is constructing the Millennium Power natural gas-fueled plant in Charlton, Massachusetts. This facility will have a capacity of 360 MW.23 It is expected to begin operation in the summer of 2000. PG&E affiliates are also developing additional facilities in New England with a total of over 2,000 MW of capacity.24 o Sithe Energies. Sithe Energy subsidiary Sithe New England has announced plans to build 1,500 MW of new gas-fired units at the Mystic site it acquired from Boston Edison. It has also announced plans to build an additional 750 MW at Boston Edison's former Edgar site.25 In addition, Sithe New England is developing the Medway and Everett - --------------- 23 USGen Affiliate Begins Construction of Millennium Power Plant," U.S. Generating Company press release, June 24, 1998, http://www.usgen.com/ news/pr062498.html. 24 "U.S. Generating Co. Completes Acquisition of New England Electric's Generating Facilities," U.S. Generating Company press release, September 1, 1998, http://www.usgen.com/news/pr090198.html. 25 "Sithe New England Construction Plans Include Building 2,250 MW of New Plant," Northeast Power Report, July 17, 1998, at 10. 18 gas-fired stations in Massachusetts. Both of these facilities will have a capacity of 1,500 MW and are expected to be in service in 2001.26 o Southern Company. Southern Company affiliate Southern Energy has announced plans to build a new 525 MW, gas-fired generating unit at the site of the Canal generating station it recently acquired from Commonwealth Energy and EUA.27 In addition, Southern Energy has announced plans to upgrade the Kendall station it acquired from Commonwealth Energy. The upgrade will include environmental improvements in addition to increasing the plant's capacity from 110 MW to 270 MW.28 Additional merchant plant developers, such as Duke Energy Power Services, have facilities in New England which are either under construction or have regulatory approval.29 26. These examples demonstrate that actual entry into the generation business by a number of firms is occurring in New England. New market participants are not only purchasing existing generation facilities but are also - --------------- 26 "Merchant Plant Development Booms But Abandoned Projects Likely," The Energy Report, February 1, 1999. 27 "SEI to Build New 525 MW Plant at Canal Site It Bought From ComElectric/EUA," Northeast Power Report, January 15, 1999, at 1. 28 "Southern Energy Plans Environmental, Efficiency Upgrades for Kendall Square Station Power Plant," Southern Company press release, August 19, 1998, http://newsinfo.southernco.com/article.asp?id=522&co=southernco. 29 1998 CELT Report at 31. 19 increasing the capacity of existing plants, adding new units at existing generation sites, and developing merchant plants at new locations. This track record of entry and expansion shows that plant sites, fuel supplies, and other inputs are available for new generation facilities. As a result, gaining access to inputs is not a barrier to the development of new facilities or the entry of new competitors. The actual, recent market experience with entry and expansion by wholesale electric market participants in New England further supports my conclusion that the combination of the generation entitlements of affiliates of NEES and EUA will not result in an anticompetitive reduction in electricity output or an increase in wholesale electric prices. 27. In order to confirm my conclusions, I have analyzed several other market power or "Appendix A" studies related to New England that have been filed with the FERC in other dockets in the past few years. My analysis involved considering the implications of the NEES/EUA transaction on these other studies. 28. For example, in February 1999, BEC Energy and Commonwealth Energy Systems filed an analysis of their proposed merger prepared by John Reed (Docket No. EC99-33-000). Adjusting Mr. Reed's analysis to reflect recent divestitures by Montaup and New England Power yields increases in HHIs which are far below the FERC's merger screening thresholds. As discussed in more detail in the Appendix, the HHI values that result for the seven markets analyzed by Mr. Reed are in the moderately concentrated range, and the increases in the HHIs due to the NEES/EUA transaction are all very 20 small. In particular, the increases in the HHIs are all under six (6). Under the FERC's Policy Statement on mergers and the Horizontal Merger Guidelines, such small HHI increases indicate that the acquisition of EUA by NEES is presumed unlikely to raise significant competitive concerns. 29. In September 1997, New England Power, the Narragansett Electric Company, and USGen New England filed a market power analysis related to the divestiture by New England Power and The Narragansett Electric Company of substantially all of their non-nuclear generation resources to USGen New England. This analysis, filed in Docket Nos. EC98-1-000 and ER98-6-000, was prepared by Joe D. Pace. Dr. Pace considered a variety of total capacity and total economic capacity HHIs in his analysis. After adjusting Dr. Pace's analysis to reflect recent divestitures by EUA affiliates, I calculated the increases in the total installed capacity and total economic capacity HHIs due to the NEES/EUA transaction. These calculations yield increases in total installed capacity and total economic capacity HHIs that fall well within the FERC's safe harbor screens. In particular, the increases in the total installed capacity HHIs are less than two (2), and the increases in the total economic capacity HHIs are less than nine (9). These calculations are discussed in more detail in the Appendix. 30. In February 1997, the NEPOOL Executive committee submitted a market power analysis related to the restructuring of NEPOOL and the receipt of 21 market-based rates by NEPOOL members. This analysis was filed in Docket Nos. OA97-237-000 and ER97-1079-000 and was prepared by William Hieronymous. His analysis studied seven relevant products under the Restated NEPOOL Agreement: (1) Installed Capability, (2) Energy, (3) Ten-Minute Spinning Reserve, (4) Ten-Minute Non-Spinning Reserve, (5) 30-Minute Operating Reserve, (6) Automatic Generation Control, and (7) Operable Capability. Because Montaup's only remaining generation entitlements will be in nuclear plants, its shares of generation resources capable of supplying ten-minute spinning reserves, ten-minute non-spinning reserves, 30-minute operating reserves, and automatic generation control are all zero. Hence the HHI increases due to the NEES/EUA transaction are zero for these products. To calculate increases in HHIs for the remaining products, I adjusted NEES and EUA resources to reflect recent divestitures by their affiliates. I then calculated increases in installed capability and energy HHIs due to the NEES/EUA transaction for a range of time periods. The increases in the total installed capability HHIs were all less than two (2), and the increases in the energy HHI were all less than eight (8). These HHI increases fall well within the FERC's safe harbor screens. These calculations are discussed in more detail in the Appendix. V. The Proposed Merger Will Not Harm Electric Transmission Competition. 31. Both NEES and EUA provide transmission services in New England through affiliates. The merger of NEES and EUA, however, will not result in a reduction in competition for the provision of transmission services. 22 32. Individual entities in NEPOOL provide transmission services using both pool transmission facilities ("PTF") and non-PTF facilities. Service using PTF facilities is available using NEPOOL's open access transmission tariff. Under the NEPOOL tariff, transmission services for delivery between entities within NEPOOL are provided at a combination of license plate and postage stamp rates. The use of a NEPOOL-wide rate is being phased in over several years, and both firms have network service rates in their own open access transmission tariffs that also may be used to provide service during the phase-in of NEPOOL's rates. NEPOOL-wide rates that combine license plate and postage stamp pricing will continue to be available after the consummation of the NEES/EUA merger. 33. NEES and EUA affiliates do not "compete" for the sale of transmission services using either PTF or other facilities. The EUA system is interconnected with three transmission dependent utilities: Pascoag, Middleboro, and Taunton. None of these entities is interconnected with the NEES system. Consequently, these three entities cannot choose between taking service from NEES and EUA. Neither NEES nor EUA has offered discounts under its tariffs to win transmission customers or for any other reason. As a result, the proposed merger will not result in a restriction in the production of transmission services or otherwise reduce competition in these services. 23 VI. The Proposed Merger Will Not Harm Competition Due to Vertical Effects. 34. As a result of industry restructuring and the divestiture of generation, both NEES and EUA have exited the generation business. Their operating companies provide retail access to market suppliers under filed, non-discriminatory transmission and distribution tariffs. These tariffs include regulated rates and standards of conduct established by this Commission and the relevant state commissions. All retail customers serviced by the NEES and EUA operating companies have the right to purchase electricity supplies from their provider of choice. Consequently, the NEES and EUA companies no longer operate as vertically integrated concerns, and their merger will not result in harm to competition due to vertical effects. 35. Other than transmission and distribution services, neither NEES nor its subsidiaries presently provides fuel supplies, fuel transportation services, equipment, or other inputs used in the production or delivery of electric products or services to EUA, its affiliates, or other utilities in New England.30 As part of the NEES companies' divestiture of their generating business, NEES affiliate New England Energy Incorporated sold its oil and gas properties in February 1998.31 Similarly, the EUA companies do not supply inputs (other than transmission and distribution services) - --------------- 30 AllEnergy may occasionally make sales of natural gas at wholesale to other utilities as part of its retail marketing business. These sales represent an insignificant portion of the natural gas sales in New England. 31 New England Energy Inc. had been involved in domestic oil and gas explora tion, development, and production. 24 used in the production or delivery of electricity to NEES, its affiliates, or others in New England. Consequently, this transaction will not create or enhance incentives for the NEES or EUA companies adversely to affect prices and output in downstream electricity markets. In particular, this transaction will not create incentives for NEES and EUA affiliates to restrict non-affiliate access to the transmission or distribution systems of the NEES and EUA companies. 36. Furthermore, NEES and EUA affiliates provide transmission services to electric generators and power marketers through FERC-approved open access tariffs and will continue to do so after NEES completes its acquisition of EUA. Similarly, NEES and EUA affiliates provide distribution services through state-regulated distribution rates paid by the customer, not the supplier.32 As a result, the acquisition will not affect the ability of NEES or EUA affiliates to restrict access to their transmission or distribution assets. I conclude that this transaction is not a vertical merger and will not impact the incentive or ability of the NEES and EUA companies adversely to affect competition through vertical effects such as foreclosure, facilitating coordination, or regulatory evasion.33 - --------------- 32 Although NEES, through AllEnergy, markets electricity and natural gas at retail, delivery service in the service territories of NEES and EUA is at regulated rates and preferential service to affiliated marketers is expressly prohibited. 33 My analysis is consistent with the FERC's current thinking on vertical merger analysis. See Revised Filing Requirements Under part 33 of the Commission's Regulations, April 16, 1998, Docket No. RM98-4-000, slip op. at 46-50. 25 VII. The Proposed Acquisition Will Generate Significant Efficiencies. 37. The acquisition of EUA by NEES is likely to result in significant efficiencies. Following the merger of the NEES and EUA holding companies, the parties are planning to merge related affiliates. For example, the parties will combine their principal transmission affiliates, New England Power and Montaup. Similarly, the Massachusetts distribution companies (Massachusetts Electric Company and Eastern Edison Company) will merge, as will the Rhode Island distribution companies (The Narragansett Electric Company, Blackstone Valley Electric Company, and Newport Electric Corporation). Other related affiliates, such as the service companies, will merge as well. These combinations of companies with similar functions are likely to result in significant cost reductions. These cost savings are not likely to be achievable outside of the NEES/EUA merger because they are derived from the elimination of the redundancies between affiliated operating and service companies active in common lines of business. These redundancies are in personnel, facilities, systems, and other areas. 38. Management consultants David J. Hoffman and Richard J. Levin from Mercer Management Consulting have estimated the net merger efficiencies to be approximately $30 million per year by the end of the distribution rate freeze period.34,35 Messrs. Hoffman and Levin estimated these net savings - --------------- 34 Direct Testimony of David J. Hoffman and Richard J. Levin before the Massachusetts Department of Telecommunications and Energy ("Hoffman/Levin Testimony"), April 30, 1999, at 7 and Exhibit DJH-2. 35 The parties have proposed a four year distribution rate freeze beyond the distribution rate freeze in the Massachusetts Electric Company and Eastern Edison Company Restructuring Settlements which expire on December 31, 2000. See Direct Testimony of Michael E. Jesanis before the Massachusetts Department of Telecommunications and Energy ("Jesanis Testimony"), April 30, 1999 at 9-14. Mr. Jesanis is presently Senior Vice president and Chief Financial Officer of NEES and also Vice President of New England Power, The Narragansett Electric Company, and New England Power Service Company. New England Power Service Company provides administrative, engineering, construction, legal, and financial services to NEES and its subsidiaries. 26 from the regulated operations of NEES and EUA. Their estimates derive from areas such as the elimination of duplication, cost avoidance, the adoption of different management practices and policies, and the improved utilization of assets and employees.36 They assumed that the financial, accounting, human resources, external affairs, and corporate planning functions of NEES and EUA will be fully combined. In addition, they assumed that the information system data centers, call centers, central transmission and distribution planning, engineering, and support functions, and transmission field forces also will be integrated.37 Furthermore, Michael E. Jesanis estimated that additional savings identified as part of the integration process will increase annual savings to $35 million per year in the first year after the rate freeze.38 Messrs. Hoffman and Levin did not estimate efficiencies resulting from the non-regulated NEES and EUA operations. Thus, they likely underestimate the total efficiencies arising from the proposed merger. 39. Consumers will derive significant benefits from the proposed acquisition. Because the likely cost savings found by Messrs. Hoffman, Levin and Jesanis derive from the regulated operations of NEES and EUA, some of these cost reductions will flow through the merged companies' regulated rates for transmission and distribution service. End users will benefit directly from reduced transmission and distribution charges.39 For example, the consolidation of Eastern Edison and Massachusetts Electric rates and a - --------------- 36 Hoffman/Levin Testimony at 8. 37 Hoffman/Levin Testimony at 10. 38 Jesanis Testimony at 16, 22, 24-26. 39 See Jesanis Testimony at 8-12, 16-17. 27 following freeze in distribution rates is anticipated to save Eastern Edison customers about $20 million in 2002 alone.40 40. The proposed acquisition and subsequent subsidiary combinations will likely result in additional benefits for consumers by promoting competition in retail electricity markets. In particular, the integration of the distribution companies will likely make it easier for power marketers to enter the retail market and gain customers. In the case of Rhode Island, for example, three distribution companies will be merged into one. The consolidation of the distribution companies will not harm competition in distribution services because distribution is now and will remain a regulated, natural monopoly service. The consolidation will, however, reduce transaction costs for competitive retail electricity suppliers. Power marketers will have to interface with fewer distribution company support systems, simplifying procedures and reducing costs. Differing distribution rates and availability clauses for providing distribution services complicate the power supply business. Furthermore, the combination of the distribution companies will enable marketers to use common advertising and simplify marketing efforts. This is likely to reduce the costs and enhance the effectiveness of their promotional activities. Though these and other similar benefits may be difficult to quantify, consumers clearly gain from actions that promote the development of a competitive retail marketplace in electricity. - --------------- 40 Jesanis Testimony at Exhibit MEJ-4, revised. 28 VIII. Conclusion. 41. The proposed acquisition of EUA by NEES will not create or enhance market power in electric generation or transmission or otherwise facilitate its exercise. Both NEES and EUA are exiting the generation business. In addition, many divested generation facilities in New England have been acquired by out-of-market firms, resulting in new market participants. These and other new participants are actively expanding the capacity of current facilities, adding new units to existing generation locations, and developing new generation sites. This activity is strongly procompetitive, and it provides additional support to my conclusion that this transaction will not result in harm to competition in wholesale electricity markets. In addition, this transaction will not result in harm to competition in the provision of transmission services or result in vertical competitive effects. Furthermore, this merger will likely result in significant benefits for consumers arising from both cost reduction efficiencies and the promotion of competitive retail markets for electricity. Thus, I conclude that the proposed acquisition of EUA by NEES will not adversely impact competition but rather will advance consumer interests due to the likely realization of significant efficiencies and the transaction's potential to further the development of competitive retail markets. I declare under penalty of perjury that the foregoing is true and correct. /s/ Henry J. Kahwaty ---------------------------------------- Henry J. Kahwaty Signed on this 5th day of May, 1999 29 Appendix Several market power studies related to New England have been completed in the last few years. These studies have all relied, in part, on market concentration calculations and the screening thresholds set out in the Horizontal Merger Guidelines jointly issued by the U.S. Department of Justice and the Federal Trade Commission. The concentration-based screening thresholds contained in the Horizontal Merger Guidelines were adopted by the FERC in its Policy Statement on mergers. In this Appendix, I describe the screening criteria in the Horizontal Merger Guidelines and then consider the impact of the proposed acquisition of EUA by NEES on the market concentration screens considered in these studies. In all cases, the resulting changes in the HHI implied by the NEES/EUA transaction are well within the Horizontal Merger Guidelines screening thresholds, indicating that this proposed acquisition is not likely to create or enhance market power or facilitate its exercise. The Horizontal Merger Guidelines divides the range of potential HHI values into three regions. If the post-merger HHI is below 1,000, the market is deemed unconcentrated and an exercise of market power is presumed unlikely. These markets "pass" the HHI screen and ordinarily require no further analysis. If the post-merger HHI is between 1,000 and 1,800 the market is deemed to be moderately concentrated. If, as a result of the merger, the HHI increases less than 100 in a moderately concentrated market, the merger is presumed unlikely to result in competitive effects. If the increase is over 100, however, the Horizontal Merger Guidelines state that significant competitive concerns may arise, and further analysis is required to determine whether harm to competition is likely. Finally, if the post-merger HHI is above 1,800, the market is 1 deemed "highly concentrated." A market with five firms of equal size has an HHI of 2,000. Thus, the overall level of market concentration implicit in an HHI value of 1,800 is similar to that of a market with approximately five equally-sized competitors. If the HHI increase arising from a merger in a highly concentrated market is less than 50, significant competitive effects are presumed unlikely. If the increase is between 50 and 100, then the Horizontal Merger Guidelines state that significant competitive concerns may arise, and further analysis is required to determine whether harm to competition is likely. Finally, if the increase is above 100, the Horizontal Merger Guidelines presume that merger will be "likely to create or enhance market power or facilitate its exercise."1 This presumption may be overcome if ease of entry or other considerations make the exercise of market power unlikely. John Reed prepared a Report assessing the competitive implications of the proposed merger of BEC Energy and Commonwealth Energy Systems (the "Reed Report"). The Reed Report, dated February 8, 1999, was filed in Docket No. EC99-33-000. The Reed Report assess the competitive implications of the BEC Energy and Commonwealth Energy Systems merger in part by completing an analysis consistent with the FERC's Policy Statement on mergers. The Reed Report identified several product markets relevant to the analysis of the BEC Energy/Commonwealth Energy Systems merger. These product markets include: o Total Summer Capacity, o Total Winter Capacity, o Total Shoulder Capacity, o Summer Peak Economic Capacity, - --------------- 1 Horizontal Merger Guidelines at section 1.51. 2 o Summer Off-Peak Economic Capacity, o Winter Peak Economic Capacity, o Winter Off-Peak Economic Capacity, o Shoulder Peak Economic Capacity, o Shoulder Off-Peak Economic Capacity, and o Super Peak Economic Capacity. The relevant geographic market considered in the Reed Report is NEPOOL. As part of its analysis, the Reed Report calculates HHIs for these product markets in the NEPOOL geographic market. I have used the information in the Reed Report to consider the implications of the proposed acquisition of EUA by NEES. To complete my analysis, I adjusted the data in the Reed Report in several ways. These adjustments include the following: o Reallocated generation resources from New England Power to USGen New England. New England Power has completed the divestiture of its generation resources to USGen New England with the exception of its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. All other resources for New England Power in the Reed Report have been reallocated to USGen New England. New England Power's remaining generation resources include approximately 400 MW of generation capacity. o Reallocated USGen New England's Ocean States Power entitlement to TransCanada Power Marketing. Immediately after New England Power transferred its entitlement from the Ocean States Power facility to USGen New England, USGen New England transferred this entitlement to TransCanada Power Marketing. I have reallocated this capacity to TransCanada Power Marketing. This reallocation involved approximately 250 MW of capacity. o Reallocated generation resources from EUA affiliates to other market participants. Montaup has completed the sale of several of its generation resources to other market participants and has additional sale and transfer agreements pending. Outside of these agreements, Montaup's only remaining generation resources are its entitlements in Millstone 3, Vermont Yankee, and Pilgrim. I have reallocated resources from EUA to Constellation Power Source, FPL Group, NRG Energy, 3 TransCanada Power Marketing, Great Bay Power Corporation, and others to reflect these divestitures. After making these adjustments, I recalculated market HHI levels and increases due to the NEES/EUA transaction for the ten capacity and economic capacity markets listed above. In all ten cases, the HHI calculations indicated that the market was moderately concentrated, having a post-merger HHI between 1,250 and 1,650. Furthermore, the increases in the HHIs due to the NEES/EUA merger were all between one (1) and six (6). These are very small increases and clearly fall within the safe harbors set out in the Horizontal Merger Guidelines and the FERC's Policy Statement on mergers. Details of these HHI calculations are provided in Workpaper HJK-1. Joe D. Pace submitted a market power analysis on behalf of New England Power, The Narragansett Electric Company, and USGen New England (the "Pace Report"). The Pace Report was filed in Docket Nos. EC98-1-000 and ER98-6-000 on September 30, 1997.2 The Pace Report analyzed the competitive effects of New England Power's and The Narragansett Electric Company's divestiture of substantially all of their generation resources to USGen New England. The parties also requested market-based pricing authority for themselves and for NEES affiliate AllEnergy. - --------------- 2 Dr. Pace also submitted a supplemental analysis in these dockets dated November 4, 1997. This analysis considered the sale by USGen New England of an equity interest in the Ocean State Power and Ocean State Power II project to subsidiaries of TransCanada Pipelines Limited and related agree ments. USGen New England was to acquire this interest as part of its pur chase of the generation business of New England Power and its affiliates. 4 The Pace Report considers short run capacity and energy product markets. Dr. Pace concludes that the relevant geographic market is at least as broad as NEPOOL because of the structure of NEPOOL transmission rates and the limited impact of transmission constraints in NEPOOL.3 The Pace Report considers short run capacity market conditions by analyzing market shares and HHIs based on total installed capacity and on uncommitted capacity. Both total installed capacity and uncommitted capacity are analyzed for summer and winter in each of several years. Dr. Pace analyzes energy market conditions by considering market shares and HHIs for total economic capacity and available economic capacity for a range of load conditions in each of the four seasons for both 1998 and 2000. Due to the progress made on market restructuring in New England since Dr. Pace completed his analysis in late 1997, I focus only on his study of total installed capacity and total economic capacity. I first considered Dr. Pace's analysis of total installed capacity. All of Dr. Pace's total capacity HHIs are in the moderately concentrated range of HHI values.4 With recent divestitures in New England, these HHIs have likely fallen. To consider the impact of the NEES/EAU transaction on these HHIs, I first adjusted EUA's capacity to reflect its pending and completed divestitures. I then calculated the increases in the total installed capacity HHIs for both - --------------- 3 Pace Report at 27-29. 4 Pace Report at Table JDP-4. 5 winter and summer in 1999 and 2000.5 All four of the resulting HHI increases are less than two (2), indicating that the NEES/EUA transaction comfortably meets the safe harbor screening criteria of the Horizontal Merger Guidelines. These calculations are detailed in Workpaper HJK-2. Next, I consider Dr. Pace's analysis of total economic capacity in 1998 and 2000.6 His total economic capacity HHIs are all below 1,700, and some are even below 1,000 (in the unconcentrated range of HHI values). These HHIs have likely fallen due to recent divestitures. To consider the impact of the NEES/EAU transaction on these HHIs, I first adjusted EUA's capacity to reflect its pending and completed divestitures. I then calculated the increases in the total economic capacity HHIs for both winter and summer in 1998 and 2000. I only calculated HHI increases for Dr. Pace's lowest level of load - typically 8,000 MW. This is because most of New England Power's and all of Montaup's generation resources are nuclear and hence are economic for these load levels. In addition, to simplify my calculations, I also assumed that New England Power's economic capacity includes its Wyman 4 entitlement, even at low load levels. This assumption overestimates New England Power's share of total economic capacity for these low load levels, and hence it overestimates the resulting HHI increases. The largest HHI increase due to NEES/EUA transaction is under nine (9). Furthermore, the shares of total economic capacity for New England Power and Montaup fall as load levels increase, so the increases in the HHI for other - --------------- 5 If Firms 1 and 2 have market shares of s1 and s2, respectively, then the change in the HHI due to a merger of these two firms is two times the product of the market shares of firms 1 and 2, or 2*s1*s2. 6 Pace Report at Table JDP-6. 6 load levels must all be smaller than nine (9). Thus, the increases in total economic capacity HHIs due to the NEES/EUA transaction are all well below safe harbor screening thresholds. My calculations of the total economic capacity HHI increases are detailed in Workpaper HJK-2. William Hieronymous submitted a market power analysis on behalf of the NEPOOL Executive Committee related to the restructuring of NEPOOL and the receipt of market-based rates by NEPOOL members (the "Hieronymous Report"). The Hieronymous Report was filed in Docket Nos. OA97-237-000 and ER97-1079-000 on February 28, 1997. The Hieronymous Report studied seven relevant products under the Restated NEPOOL Agreement: (1) Installed Capability, (2) Energy, (3) Ten-Minute spinning Reserve, (4) Ten-Minute Non-Spinning Reserve, (5) 30-Minute Operating Reserve, (6) Automatic Generation Control, and (7) Operable Capability. He concluded that, under ordinary conditions, the NEPOOL dispatch is essentially unconstrained by transmission limitations. This, in combination with postage-stamp transmission pricing, led him to conclude that the NEPOOL control area was a relevant geographic market.7 The Hieronymous Report considers market power issues based upon two alternative scenarios - the then present world with native load obligations and a restructured world without native load obligations. Given the progress made on - --------------- 7 Hieronymous Report at 19-20, 23. 7 market restructuring since Dr. Hieronymous completed his analysis in early 1997, I focus only on his study of restructured electricity markets without native load obligations. Dr. Hieronymous begins his analysis with a discussion of the installed capability product market.8 His study includes monthly HHI calculations for this market between July 1997 and December 1999. These HHIs range between 1,711 and 1,830, and have likely fallen recently due to divestitures. I altered Dr. Hieronymous' data to represent completed and pending divestitures by New England Power, Montaup, and their affiliates. I then calculated the resulting HHI increases due to the NEES/EUA transaction. These increases are all below two (2), well under the FERC's screening thresholds. Details of these calculations are provided in Workpaper HJK-3. Due to the similarities between installed capability and operable capability, I did not analyze operable capability. Dr. Hieronymous also analyzes energy markets.9 He provides annual energy HHIs for 1998, 1999, and July - December 1997 for all hours as well as for on-peak hours, off-peak hours, and for six ranges related to the energy clearing price.10 He finds HHIs that range between 1,647 and 2,004. I used 1996 and 1997 FERC Form 1 energy output data to determine energy output for the facilities in which NEES and EUA affiliates continue to own entitlements to calculate the increase in energy market HHIs for 1998 and 1999 due to the NEES/EAU merger. These increases are both less than eight (8), again well within - --------------- 8 Hieronymous Report at 40-41 and Exhibit No. WHH-12. 9 Hieronymous Report at 41 and Exhibit No. WHH-13. 10 These energy clearing price ("ECP") ranges are ECP<20, 20<=ECP<25, 25<=ECP<30, 30<=ECP35, 35<=ECP40, and ECP>=40. 8 the Horizontal Merger Guidelines safe harbors. Details of these calculations are provided in Workpaper HJK-3. Dr. Hieronymous also analyzes Ten-Minute Spinning Reserve, Ten-Minute Non-Spinning Reserve, 30-Minute Operating Reserve, and Automatic Generation Control product markets.11 Because EUA affiliates will only have entitlements to the output of nuclear facilities after completing pending divestitures, EUA affiliates will have no resources that can supply these products. As a result, EUA's shares in these markets are all zero. Hence there will be no change in the HHIs for these markets due to NEES's acquisition of EUA. - ---------------- 11 Hieronymous Analysis at 41-42 and Exhibit Nos. WHH-14, WHH-15, WHH-16, and WHH-18. 9 [LECG Logo] New England Power Company, et al. Docket No. EC99-______ Exhibit HJK-1 Page 1 of 4 HENRY J. KAHWATY LECG 1600 M Street, N.W., Suite 700 Washington, D.C. 20036 Tel. (202) 466-4422 Fax (202) 466-4487 EDUCATION Ph.D., Economics, UNIVERSITY OF PENNSYLVANIA, Graduate School of Arts and Sciences, Philadelphia, PA, 1991 Thesis Title: Essays on Vertical Relationships Thesis Topic: Vertical Relationships with Asymmetric Information and Incomplete Contracting Specialty Areas: Industrial Organization, Public Economics, Monetary Economics M.A., Economics, UNIVERSITY OF PENNSYLVANIA, Graduate School of Arts and Sciences, Philadelphia, PA, 1988 B.A. magna cum laude and Phi Beta Kappa, Mathematics and Economics, UNIVERSITY OF PENNSYLVANIA, College of Arts and Sciences, Philadelphia, PA, 1986 PRESENT POSITION LECG, Washington, D.C. Senior Managing Economist, 1997-present Senior Economist, 1995-1996 o Analysis of antitrust market definition. o Analysis of the competitive effects resulting from mergers. o Monopolization analysis. [LECG Logo] New England Power Company, et al. Docket No. EC99-______ Exhibit HJK-1 Page 2 of 4 o Analysis of competition issues in the electric utility industry, including market-based pricing and deregulation proposals, mergers, wholesale markets, and retail wheeling. o Analysis of competition and other issues in telecommunications. o Damage studies. Consultant to Rational Software Corp. in proposed acquisition of Pure Atria Corp., 1997. Consultant to National Communications Association, Inc. in National Communications Association, Inc. v. American Telephone and Telegraph Company, 1997-1998. Consultant to Public Service Enterprises of Pennsylvania, Inc. in arbitration between Public Service Enterprises of Pennsylvania, Inc. and AT&T Corporation, 1997-1998. Consultant to Aptix Corporation in Aptix Corporation v. Quickturn Design Systems, Inc., 1998. Consultant to New England Electric System in proposed acquisition by National Grid Group plc, 1999. Consultant to New England Electric System in proposed acquisition of Eastern Utilities Associates, 1999. Experience with the following industries: o Local and long distance telecommunications o Computer software and software development tools o Computer hardware, including microprocessors and modems o Electricity o Defense electronics o Hardware emulation 2 [LECG Logo] New England Power Company, et al. Docket No. EC99-______ Exhibit HJK-1 Page 3 of 4 PROFESSIONAL EXPERIENCE U.S. DEPARTMENT OF JUSTICE, Antitrust Division, Economic Litigation Section, 1991-1995 Economist o Prepared economic models and analysis for antitrust cases. o Prepared antitrust investigation plans. o Reviewed civil investigative demands, second requests, subpoenas, complaints, affidavits, and other documents. o Assisted attorneys with gathering evidence, including conducting witness interviews and assisting with witness depositions. o Recommended whether to institute enforcement actions. o Specialized in computer software, defense, and banking industries. TESTIMONY Provided deposition and trial testimony in National Communications Association, Inc. v. American Telephone and Telegraph Company, 92 Civ. 1735 (LAP), U.S. District Court for the Southern District of New York, 1997-1998. Provided deposition testimony in Aptix Corporation v. Quickturn Design Systems, Inc., C-96-20909 JF (EAI), U.S. District Court for the Northern District of California, 1998. SPEECHES "Unregulated Affiliates and the Market Power Problem," Forum on Electric Power Market Restructuring, Washington, D.C., February 19, 1999. "Antitrust Damages," Litigation Services Subcommittee of the Greater Washington Society of Certified Public Accountants, Washington, D.C., January 28, 1999. 3 [LECG Logo] New England Power Company, et al. Docket No. EC99-______ Exhibit HJK-1 Page 4 of 4 TEACHING EXPERIENCE UNIVERSITY OF PENNSYLVANIA, Philadelphia, PA, 1988-1991 o Industrial Organization o Topics in Microeconomics o Topics in Macroeconomics o Intermediate Microeconomics o Introductory Microeconomics o Introductory Macroeconomics UNPUBLISHED RESEARCH "The Analysis of Market Concentration, Market Power and the Competitive Effects of Mergers in the Electric Industry," with Richard J. Gilbert, June 1997. RESEARCH INTERESTS Oligopoly models, network externalities and asymmetric information. PROFESSIONAL ACTIVITIES Member, American Economic Association Member, European Association for Research in Industrial Economics Citizenship: United States of America 4 [LECG Logo] New England Power Company, et al. Docket No. EC99-____ Exhibit HJK-2 Page 1 of 1
Net Generation Entitlements for NEES Affiliates Post-Merger Entitlement Entitlement Capacity Plant Share (%) (MW) Millstone 3 16.22 185 Pilgrim 11.00 74 Seabrook 1 9.96 116 Vermont Yankee 20.23 101 Wyman 4 9.27 57 Total 533
Source: Declaration at paras. 6 and 8. [LECG Logo] New England Power Company, et al. Docket No. EC99-______ Exhibit HJK-3 Page 1 of 1
Recent Acquirers of Generation Resources Divested by New England Utilities Corporate Affiliation of Acquiring Company Acquiring Company Divesting Company Source - ----------------------------------------------------------------------------------------------------------------------------------- TransCanada Power Marketing TransCanada PipeLines Montaup 1 Great Bay Power Corporation BayCorp Holdings, Ltd. Montaup 1 Wabash Power Equipment Newport Electric 1 Pawtucket Generating Co. LLC Blackstone Valley Electric 1 Constellation Power Source Baltimore Gas and Electric Co. Montaup 1 Southern Energy Inc. Southern Company Montaup/Cambridge Electric Light Company, 1.2 Canal Electric Company, and Commonwealth Electric Company FPL Group/FPL Energy Maine FPL Group Montaup/Central Maine Power Co. 1.3 Sithe New England Sithe Energies Boston Edison Company 4 USGen New England PG&E Corporation New England Power 5 NRG Energy Northern States Power Company Montaup 6 PP & L Global, Inc. PP&L Resources, Inc. Bangor Hydro-Electric Co. 7 Consolidated Edison Energy Consolidated Edison, Inc. Western Massachusetts Electric Company 8 (affiliate of Northeast Utilities) Entergy Nuclear Generating Co. Entergy Corporation Boston Edison Company 9 Wisvest Wisconsin Energy Corporation United Illuminating Company 10 - ---------------------------------------------------------------------------------------------------------------------------------- Sources: 1. http://www.eua.com/divestiturelinks.html 2. http://www.comenergy.com/news.htm#south 3. http://www.cmpco.com/news/older_releases/980106.html; http://www.cmpco.com/news/older_releases/980618.html 4. http://www.bostonedison.com/NEWS/P_SITHE.HTM 5. http://www.nees.com/news/080697a.htm 6. http://www.nees.com/news/090198b.htm 7. http://www.pplresources.com/webre_dcd/owa/News_Releases.Show_Release?art_id=332&co_id=0 8. http://www.conedison.com/cone_ny/about/news/pr19990127.asp?from=hc 9. http://www.bedison.com/NEWWS/entergy.htm 10. http://www.unitilcorp.com/News/NewHaven.htm
[LECG Logo] New England Power Company, et al. Docket No. EC 99-_____ Workpaper HJK-1 Page 1 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Legend Symbol Company BECO Boston Edison Company BELD Braintree Electric Light Department BHE Bangor Hydro-Electric Company BPDI Berkshire Power Development, Inc. CES Commonwealth Energy System Companies CLNP Constellation Power Source CMEES Connecticut Municipal Electric Energy Cooperative CMLP Chicopee Municipal Lighting Plant CMP Central Maine Power Company CV Central Vermont Public Service Corporation DPA Dighton Power Associates DUKE Duke Power Company ENT Entergy Nuclear Generating EUA Eastern Utilities Associates FGE Fitchburg Gas and Electric Department FPL FPL Group GBPC Great Bay Power Corporation GMP Green Mountain Power Corporation HGE Holyoke Gas and Electric Department HLPD Hudson Light and Power Department HMLP Hingham Municipal Lighting Plant IMEL Indeck Maine Energy, LLC IMLD Ipswich Municipal Light Department IPPA Indeck-Pepperell Power Associates, Inc. MGED Middleborough Gas and Electric Department MMLD Marblehead Municipal Light Department MMWEC Massachusetts Municipal Wholesale Electric Co. MPLP Milford Power Limited Partnership NAED North Attleborough Electric Department NEP New England Electric System Operating Companies NHCO New Hampshire Electric Cooperative NRG NRG Energy NU Northeast Utilities Companies PMLD Princeton Municipal Light Department PMLP Peabody Municipal Light Plant SC Southern Company SELP Shrewsbury Electric Light Plant SITHE Sithe Energies, Inc. TCPM TransCanada Power Marketing TMLP Taunton Municipal Lighting Plant UI The United Illuminating Company UNITIL UNITIL Corp. NH Participant Companies USG USGen New England VTGP Vermont Group WBSH Wabash Power Equipment
New England Power Company, et al. Docket No. EC 99-_____ Workpaper HJK-1 Page 2 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Total Capacity Analysis, Summer Pre-Merger Post-Merger Total Total Summer Share of Summer Share of Capacity Summer Square of Capacity Summer Square of Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share - --------------------------------------------------------------------------------------------------------------------------- EUA 1 132.9 0.49% 0 NEP 2 409.1 1.51% 2 EUA/NEP 542.0 2.01% 4 BECO/CES 2034.3 7.53% 57 BECO/CES 2034.3 7.53% 57 BELD 73.8 0.27% 0 BELD 73.8 0.27% 0 BHE 176.0 0.65% 0 BHE 176.0 0.65% 0 BPDI 265.9 0.98% 1 BPDI 265.9 0.98% 1 CLNP 5 227.9 0.84% 1 CLNP 5 227.9 0.84% 1 CMEEC 192.3 0.71% 1 CMEEC 192.3 0.71% 1 CMLP 33.8 0.13% 0 CMLP 33.8 0.13% 0 CMP 1519.8 5.63% 32 CMP 1519.8 5.63% 32 CV 322.8 1.19% 1 CV 322.8 1.19% 1 DPA 168.0 0.62% 0 DPA 168.0 0.62% 0 DUKE 480.0 1.78% 3 DUKE 480.0 1.78% 3 FGE 71.3 0.26% 0 FGE 71.3 0.26% 0 FPL 5 16.2 0.06% 0 FPL 5 16.2 0.06% 0 GBPC 3 174.7 0.65% 0 GBPC 3 174.7 0.65% 0 GMP 301.4 1.12% 1 GMP 301.4 1.12% 1 HGE 31.6 0.12% 0 HGE 31.6 0.12% 0 HLPD 14.2 0.05% 0 HLPD 14.2 0.05% 0 HMLP 6.3 0.02% 0 HMLP 6.3 0.02% 0 IMEL 52.4 0.19% 0 IMEL 52.4 0.19% 0 IMLD 15.3 0.06% 0 IMLD 15.3 0.06% 0 IPPA 34.1 0.13% 0 IPPA 34.1 0.13% 0 MGED 2.8 0.01% 0 MGED 2.8 0.01% 0 MMLD 6.0 0.02% 0 MMLD 6.0 0.02% 0 MMWEC 677.7 2.51% 6 SITHE 677.7 2.51% 6 MPLP 149.0 0.55% 0 MPLP 149.0 0.55% 0 NAED 15.2 0.06% 0 NAED 15.2 0.06% 0 NHCO 25.3 0.09% 0 NHCO 25.3 0.09% 0 NRG 5 150.7 0.56% 0 NRG 5 150.7 0.56% 0 NU 7418.4 27.46% 754 NU 7418.4 27.46% 754 PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0` PMLP 55.3 0.20% 0 PMLP 55.3 0.20% 0 SC 581.5 2.15% 5 SC 581.5 2.15% 5 SELP 16.0 0.06% 0 SELP 16.0 0.06% 0 SITHE 1980.4 7.33% 54 SITHE 1980.4 7.33% 54` TCPM 4, 5 387.6 1.43% 2 TCPM 4, 5 387.6 1.43% 2 TMLP 114.8 0.42% 0 TMLP 114.8 0.42% 0 UI 1467.1 5.43% 29 UI 1467.1 5.43% 29 UNITIL 32.8 0.12% 0 UNITIL 32.8 0.12% 0 USG 4 4597.7 17.02% 290 USG 4 4597.7 17.02% 290 VTGP 202.4 0.75% 1 VTGP 202.4 0.75% 1 NY 1675.0 6.20% 38 NY 1675.0 6.20% 38 NB 700.0 2.59% 7 NB 700.0 2.59% 7 WBSH 5 8.0 0.03% 0 WBSH 5 8.0 0.03% 0 - --------------------------------------------------------------------------------------------------------------------------- Total 27018.1 100.00% Total 27018.1 100.00% HHI 1286.61 HHI 1288.10 Change in HHI 1.49 Source: Reed Report at Table 10. Notes: 1. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee. 2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. 3. EUA divested 33.7 MW of generation capacity to GBPC. 4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP capacity is attributed to USG. 5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-1 Page 3 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Total Capacity Analysis, Winter Pre-Merger Post-Merger Total Total Summer Share of Summer Share of Capacity Summer Square of Capacity Summer Square of Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share - ----------------------------------------------------------------------------------------------------------------------------------- EUA 1 133.5 0.47% 0 NEP 2 415.1 1.47% 2 EUA/NEP 548.6 1.94% 4 BECO/CES 2210.7 7.80% 61 BECO/CES 2210.7 7.80% 61 BELD 91.1 0.32% 0 BELD 91.1 0.32% 0 BHE 185.4 0.65% 0 BHE 185.4 0.65% 0 BPDI 295.0 1.04% 1 BPDI 295.0 1.04% 1 CMEEC 198.8 0.70% 0 CMEEC 198.8 0.70% 0 CLNP 5 234.7 0.83% 1 CLNP 5 234.7 0.83% 1 CMLP 33.9 0.12% 0 CMLP 33.9 0.12% 0 CMP 1577.8 5.57% 31 CMP 1577.8 5.57% 31 CV 312.0 1.10% 0 CV 312.0 1.10% 1 DPA 185.0 0.65% 0 DPA 185.0 0.65% 0 DUKE 520.0 1.84% 3 DUKE 520.0 1.84% 3 FGE 77.2 0.27% 0 FGE 77.2 .27% 0 FPL 5 16.3 0.06% 0 FPL 5 16.3 0.06% 0 GBPC 3 174.7 0.62% 0 GBPC 3 174.7 0.62% 0 GMP 325.4 1.15% 1 GMP 325.4 1.15% 1 HGE 29.9 0.11% 0 HGE 29.9 0.11% 0 HLPD 14.4 0.05% 0 HLPD 14.4 0.05% 0 HMLP 6.9 0.02% 0 HMLP 6.9 0.02% 0 IMEL 52.4 0.18% 0 IMEL 52.4 0.18% 0 IMLD 15.8 0.06% 0 IMLD 15.8 0.06% 0 IPPA 42.3 0.15% 0 IPPA 42.3 0.15% 0 MGED 2.9 0.01% 0 MGED 2.9 0.01% 0 MMLD 6.0 0.02% 0 MMLD 6.0 0.02% 0 MMWEC 800.4 2.83% 8 MMWEC 800.4 2.83% 8 MPLP 170.7 0.60% 0 MPLP 170.7 0.60% 0 NAED 16.5 0.06% 0 NAED 16.5 0.06% 0 NHCO 25.3 0.09% 0 NHCO 25.3 0.09% 0 NRG 5 163.3 0.58% 0 NRG 5 163.3 0.58% 0 NU 7724.3 27.27% 743 NU 7724.3 27.27% 743 TCPM 4, 5 445.1 1.57% 2 TCPM 4, 5 445.1 1.57% 2 PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0 PMLP 76.7 0.27% 0 PMLP 76.7 0.27% 0 SC 591.6 2.09% 4 SC 591.6 2.09% 4 SELP 16.0 0.06% 0 SELP 16.0 0.06% 0 SITHE 2066.8 7.30% 53 SITHE 2066.8 7.30% 53 TMLP 118.0 0.42% 0 TMLP 118.0 0.42% 0 UI 1496.4 5.28% 28 UI 1496.4 5.28% 28 UNITIL 42.7 0.15% 0 UNITIL 42.7 0.15% 0 USG 4 4779.2 16.87% 285 USG 4 4779.2 16.87% 285 VTGP 257.0 0.91% 1 VTGP 257.0 0.91% 1 NY 1675.0 5.91% 35 NY 1675.0 5.91% 35 NB 700.0 2.47% 6 NB 700.0 2.47% 6 WBSH 5 8.0 0.03% 0 WBSH 5 8.0 0.03% 0 - ----------------------------------------------------------------------------------------------------------------------------------- Total 28330.4 100.00% Total 28330.4 100.00% HHI 1270.71 HHI 1272.09 Change in HHI 1.38 Source: Reed Report at Table 10. Notes: 1. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee. 2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. 3. EUA divested 33.7 MW of generation capacity to GBPC. 4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP capacity is attributed to USG. 5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-1 Page 4 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Total Capacity Analysis, Shoulder Pre-Merger Post-Merger Total Total Shoulder Share of Shoulder Share of Capacity Shoulder Square of Capacity Shoulder Square of Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share - ----------------------------------------------------------------------------------------------------------------------------------- EUA 1 133.2 0.48% 0 NEP 2 412.1 1.49% 2 EUA/NEP 545.3 1.97% 4 BECO/CES 2122.3 7.67% 59 BECO/CES 2122.3 7.67% 59 BELD 82.4 0.30% 0 BELD 82.4 0.30% 0 BHE 180.7 0.65% 0 BHE 180.7 0.65% 0 BPDI 280.5 1.01% 1 BPDI 280.5 1.01% 1 CLNP 5 231.3 0.84% 1 CLNP 5 231.3 0.84% 1 CMEEC 195.5 0.71% 0 CMEEC 195.5 0.71% 0 CMLP 33.8 0.12% 0 CMLP 33.8 0.12% 0 CMP 1549.1 5.60% 31 CMP 1549.1 5.60% 31 CV 305.3 1.10% 1 CV 305.3 1.10% 1 DPA 176.5 0.64% 0 DPA 176.5 0.64% 0 DUKE 500.0 1.81% 3 DUKE 500.0 1.81% 3 FGE 74.3 0.27% 0 FGE 74.3 0.27% 0 FPL 5 16.2 0.06% 0 FPL 5 16.2 0.06% 0 GBPC 3 174.7 0.63% 0 GBPC 3 174.7 0.63% 0 GMP 314.5 1.14% 1 GMP 314.5 1.14% 1 HGE 30.8 0.11% 0 HGE 30.8 0.11% 0 HLPD 14.3 0.05% 0 HLPD 14.3 0.05% 0 HMLP 6.6 0.02% 0 HMLP 6.6 0.02% 0 IMEL 52.4 0.19% 0 IMEL 52.4 0.19% 0 IMLD 15.6 0.06% 0 IMLD 15.6 0.06% 0 IPPA 38.2 0.14% 0 IPPA 38.2 0.14% 0 MGED 2.9 0.01% 0 MGED 2.9 0.01% 0 MMLD 6.0 0.02% 0 MMLD 6.0 0.02% 0 MMWEC 750.1 2.71% 7 MMWEC 750.1 2.71% 7 MPLP 159.9 0.58% 0 MPLP 159.9 0.58% 0 NAED 15.8 0.06% 0 NAED 15.8 0.06% 0 NHCO 25.3 0.09% 0 NHCO 25.3 0.09% 0 NRG 5 157.0 0.57% 0 NRG 5 157.0 0.57% 0 NU 7567.9 27.34% 747 NU 7567.9 27.34% 747 TCPM 4, 5 409.5 1.48% 2 TCPM 4, 5 409.5 1.48% 2 PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0 PMLP 66.0 0.24% 0 PMLP 66.0 0.24% 0 SC 586.6 2.12% 4 SC 586.6 2.12% 4 SELP 16.0 0.06% 0 SELP 16.0 0.06% 0 SITHE 2023.6 7.31% 53 SITHE 2023.6 7.31% 53 TMLP 116.4 0.42% 0 TMLP 116.4 0.42% 0 UI 1481.8 5.35% 29 UI 1481.8 5.35% 29 UNITIL 40.8 0.15% 0 UNITIL 40.8 0.15% 0 USG 4 4693.0 16.95% 287 USG 4 4693.0 16.95% 287 VTGP 239.1 0.86% 1 VTGP 239.1 0.86% 1 NY 1675.0 6.05% 37 NY 1675.0 6.05% 37 NB 700.0 2.53% 6 NB 700.0 2.53% 6 WBSH 5 8.0 0.03% 0 WBSH 5 8.0 0.03% 0 - ----------------------------------------------------------------------------------------------------------------------------------- Total 27681.2 100.00% Total 27681.2 100.00% HHI 1277.70 HHI 1279.13 Change in HHI 1.43 Source: Reed Report at Table 10. Notes: 1. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee. 2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. 3. EUA divested 33.7 MW of generation capacity to GBPC. 4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP capacity is attributed to USG. 5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-1 Page 5 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Economic Capacity Analysis, Summer Peak Pre-Merger Post-Merger Total Total Summer Share of Summer Share of Capacity Summer Square of Capacity Summer Square of Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share - ----------------------------------------------------------------------------------------------------------------------------------- EUA 1 132.9 0.78% 1 NEP 2 352.2 2.08% 4 EUA/NEP 485.1 2.86% 8 BECO/CES 1313.6 7.74% 60 BECO/CES 1313.6 7.74% 60 BELD 6.1 0.04% 0 BELD 6.1 0.04% 0 BHE 104.7 0.62% 0 BHE 104.7 0.62% 0 BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0 CLNP 5 196.6 1.16% 1 CLNP 5 196.6 1.16% 1 CMEEC 83.9 0.49% 0 CMEEC 83.9 0.49% 0 CMLP 25.5 0.15% 0 CMLP 25.5 0.15% 0 CMP 920.3 5.42% 29 CMP 920.3 5.42% 29 CV 278.5 1.64% 3 CV 278.5 1.64% 3 DPA 0.0 0.00% 0 DPA 0.0 0.00% 0 DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0 FGE 50.0 0.29% 0 FGE 50.0 0.29% 0 FPL 5 0.0 0.00% 0 FPL 5 0.0 0.00% 0 GBPC 3 174.7 1.03% 1 GBPC 3 174.7 1.03% 1 GMP 200.2 1.18% 1 GMP 200.2 1.18% 1 HGE 5.7 0.03% 0 HGE 5.7 0.03% 0 HLPD 7.3 0.04% 0 HLPD 7.3 0.04% 0 HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0 IMEL 52.4 0.31% 0 IMEL 52.4 0.31% 0 IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0 IPPA 34.1 0.20% 0 IPPA 34.1 0.20% 0 MGED 2.8 0.02% 0 MGED 2.8 0.02% 0 MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0 MMWEC 274.9 1.62% 3 MMWEC 274.9 1.62% 3 MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0 NAED 1.5 0.01% 0 NAED 1.5 0.01% 0 NHCO 25.3 0.15% 0 NHCO 25.3 0.15% 0 NRG 5 111.0 0.65% 0 NRG 5 111.0 0.65% 0 NU 4664.0 27.49% 756 NU 4664.0 27.49% 756 TCPM 4,5 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0 PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0 PMLP 10.7 0.06% 0 PMLP 10.7 0.06% 0 SC 0.0 0.00% 0 SC 0.0 0.00% 0 SELP 2.2 0.01% 0 SELP 2.2 0.01% 0 SITHE 388.0 2.29% 5 SITHE 388.0 2.29% 5 TMLP 15.3 0.09% 0 TMLP 15.3 0.09% 0 UI 1451.0 8.55% 73 UI 1451.0 8.55% 73 UNITIL 12.6 0.07% 0 UNITIL 12.6 0.07% 0 USG 4 3573.5 21.06% 444 USG 4 3573.5 21.06% 444 VTGP 119.3 0.70% 0 VTGP 119.3 0.70% 0 NY 1675.0 9.87% 97 NY 1675.0 9.87% 97 NB 700.0 4.13% 17 NB 700.0 4.13% 17 WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0 - ----------------------------------------------------------------------------------------------------------------------------------- Total 16967.7 100.00% Total 16967.7 100.00% HHI 1497.17 HHI 1500.42 Change in HHI 3.25 Source: Reed Report at Table 7. Notes: 1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim and Vermont Yankee. 2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. 3. EUA divested 33.7 MW of generation capacity to GBPC. 4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP capacity is attributed to USG. 5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-1 Page 6 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Economic Capacity Analysis, Summer Off Peak Pre-Merger Post-Merger Total Total Summer Share of Summer Share of Capacity Summer Square of Capacity Summer Square of Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share - ----------------------------------------------------------------------------------------------------------------------------------- EUA 1 132.9 0.89% 1 NEP 2 352.2 2.35% 6 EUA/NEP 485.1 3.24% 11 BECO/CES 1313.6 8.78% 77 BECO/CES 1313.6 8.78% 77 BELD 6.1 0.04% 0 BELD 6.1 0.04% 0 BHE 104.7 0.70% 0 BHE 104.7 0.70% 0 BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0 CLNP 5 196.6 1.31% 2 CLNP 5 196.6 1.31% 2 CMEEC 75.6 0.51% 0 CMEEC 75.6 0.51% 0 CMLP 25.5 0.17% 0 CMLP 25.5 0.17% 0 CMP 804.3 5.38% 29 CMP 804.3 5.38% 29 CV 278.5 1.86% 3 CV 278.5 1.86% 3 DPA 0.0 0.00% 0 DPA 0.0 0.00% 0 DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0 FGE 50.0 0.33% 0 FGE 50.0 0.33% 0 FPL 5 0 0.00% 0 FPL 5 0.0 0.00% 0 GBPC 3 174.7 1.17% 1 GBPC 3 174.7 1.17% 1 GMP 200.2 1.34% 2 GMP 200.2 1.34% 2 HGE 5.7 0.04% 0 HGE 5.7 0.04% 0 HLPD 7.3 0.05% 0 HLPD 7.3 0.05% 0 HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0 IMEL 52.4 0.35% 0 IMEL 52.4 0.35% 0 IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0 IPPA 34.1 0.23% 0 IPPA 34.1 0.23% 0 MGED 2.8 0.02% 0 MGED 2.8 0.02% 0 MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0 MMWEC 274.9 1.84% 3 MMWEC 274.9 1.84% 3 MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0 NAED 1.5 0.01% 0 NAED 1.5 0.01% 0 NHCO 25.3 0.17% 0 NHCO 25.3 0.17% 0 NRG 5 111.0 0.74% 1 NRG 5 111.0 0.74% 1 NU 4054.7 27.10% 734 NU 4054.7 27.10% 734 TCPM 4, 5 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0 PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0 PMLP 10.7 0.07% 0 PMLP 10.7 0.07% 0 SC 0.0 0.00% 0 SC 0.0 0.00% 0 SELP 2.2 0.01% 0 SELP 2.2 0.01% 0 SITHE 0.0 0.00% 0 SITHE 0.0 0.00% 0 TMLP 15.3 0.10% 0 TMLP 15.3 0.10% 0 UI 1451.0 9.70% 94 UI 1451.0 9.70% 94 UNITIL 12.6 0.08% 0 UNITIL 12.6 0.08% 0 USG 4 2690.9 17.98% 323 USG 4 2690.9 17.98% 323 VTGP 119.3 0.80% 1 VTGP 119.3 0.80% 1 NY 1675.0 11.19% 125 NY 1675.0 11.19% 125 NB 700.0 4.68% 22 NB 700.0 4.68% 22 WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0 - ----------------------------------------------------------------------------------------------------------------------------------- Total 14963.5 100.00% Total 14963.5 100.00% HHI 1425.18 HHI 1429.36% Change in HHI 4.18 Source: Reed Report at Table 7. Notes: 1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim and Vermont Yankee. 2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. 3. EUA divested 33.7 MW of generation capacity to GBPC. 4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP capacity is attributed to USG. 5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-1 Page 7 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Economic Capacity Analysis, Winter Peak Pre-Merger Post-Merger Total Total Winter Share of Winter Share of Capacity Winter Square of Capacity Winter Square of Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share - ----------------------------------------------------------------------------------------------------------------------------------- EUA 1 133.5 0.83% 1 NEP 2 357.7 2.21% 5 EUA/NEP 491.1 3.04% 9 BECO/CES 1356.6 8.39% 70 BECO/CES 1356.6 8.39% 70 BELD 6.2 0.04% 0 BELD 6.2 0.04% 0 BHE 112.4 0.69% 0 BHE 112.4 0.69% 0 BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0 CLNP 5 56.8 0.35% 0 CLNP 5 56.8 0.35% 0 CMEEC 76.3 0.47% 0 CMEEC 76.3 0.47% 0 CMLP 25.7 0.16% 0 CMLP 25.7 0.16% 0 CMP 852.0 5.27% 28 CMP 852.0 5.27% 28 CV 258.7 1.60% 3 CV 258.7 1.60% 3 DPA 0.0 0.00% 0 DPA 0.0 0.00% 0 DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0 FGE 50.1 0.31% 0 FGE 50.1 0.31% 0 FPL 5 0.0 0.00% 0 FPL 5 0.0 0.00% 0 GBPC 3 174.7 1.08% 1 GBPC 3 174.7 1.08% 1 GMP 203.3 1.26% 2 GMP 203.3 1.26% 2 HGE 5.7 0.04% 0 HGE 5.7 0.04% 0 HLPD 7.3 0.05% 0 HLPD 7.3 0.05% 0 HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0 IMEL 52.4 0.32% 0 IMEL 52.4 0.32% 0 IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0 IPPA 42.3 0.26% 0 IPPA 42.3 0.26% 0 MGED 2.9 0.02% 0 MGED 2.9 0.02% 0 MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0 MMWEC 300.1 1.86% 3 MMWEC 300.1 1.86% 3 MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0 NAED 1.5 0.1% 0 NAED 1.5 0.01% 0 NHCO 25.3 0.16% 0 NHCO 25.3 0.16% 0 NRG 5 115.3 0.71% 1 NRG 5 115.3 0.71% 1 NU 4841.6 29.93% 896 NU 4841.6 29.93% 896 TCPM 4, 5 0.0 0.00% 0 TCPM 4,5 0.0 0.00% 0 PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0 PMLP 10.8 0.07% 0 PMLP 10.8 0.07% 0 SC 0.0 0.00% 0 SC 0.0 0.00% 0 SELP 2.2 0.01% 0 SELP 2.2 0.01% 0 SITHE 0.0 0.00% 0 SITHE 0.0 0.00% 0 TMLP 15.4 0.10% 0 TMLP 15.4 0.10% 0 UI 1475.9 9.12% 83 UI 1475.9 9.12% 83 UNITIL 18.7 0.12% 0 UNITIL 18.7 0.12% 0 USG 4 3060.8 18.92% 358 USG 4 3060.8 18.92% 358 VTGP 157.7 0.97% 1 VTGP 157.7 0.97% 1 NY 1675.0 10.35% 107 NY 1675.0 10.35% 107 NB 700.0 4.33% 19 NB 700.0 4.33% 19 WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0 - ----------------------------------------------------------------------------------------------------------------------------------- Total 16176.8 100.00% Total 16176.8 100.00% HHI 1577.96 HHI 1581.61 Change in HHI 3.65 Source: Reed Report at Table 7. Notes: 1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim and Vermont Yankee. 2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. 3. EUA divested 33.7 MW of generation capacity to GBPC. 4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP capacity is attributed to USG. 5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-1 Page 8 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Economic Capacity Analysis, Winter Off Peak Pre-Merger Post-Merger Total Total Winter Share of Winter Share of Capacity Winter Square of Capacity Winter Square of Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share - ----------------------------------------------------------------------------------------------------------------------------------- EUA 1 133.5 0.94% 1 NEP 2 357.7 2.52% 6 EUA/NEP 491.1 3.46% 12 BECO/CES 1356.6 9.57% 92 BECO/CES 1356.6 9.57% 92 BELD 6.2 0.04% 0 BELD 6.2 0.04% 0 BHE 112.4 0.79% 1 BHE 112.4 0.79% 1 BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0 CLNP 5 56.8 0.40% 0 CLNP 5 56.8 0.40% 0 CMEEC 76.3 0.54% 0 CMEEC 76.3 0.54% 0 CMLP 25.7 0.18% 0 CMLP 25.7 0.18% 0 CMP 852.0 6.01% 36 CMP 852.0 6.01% 36 CV 258.7 1.82% 3 CV 258.7 1.82% 3 DPA 0.0 0.00% 0 DPA 0.0 0.00% 0 DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0 FGE 29.1 0.21% 0 FGE 29.1 0.21% 0 FPL 5 0.0 0.00% 0 FPL 5 0.0 0.00% 0 GBPC 3 174.7 1.23% 2 GBPC 3 174.7 1.23% 2 GMP 203.3 1.43% 2 GMP 203.3 1.43% 2 HGE 5.7 0.04% 0 HGE 5.7 0.04% 0 HLPD 7.3 0.05% 0 HLPD 7.3 0.05% 0 HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0 IMEL 52.4 0.37% 0 IMEL 52.4 0.37% 0 IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0 IPPA 42.3 0.30% 0 IPPA 42.3 0.30% 0 MGED 2.9 0.02% 0 MGED 2.9 0.02% 0 MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0 MMWEC 291.7 2.06% 4 MMWEC 291.7 2.06% 4 MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0 NAED 1.5 0.01% 0 NAED 1.5 0.01% 0 NHCO 25.3 0.18% 0 NHCO 25.3 0.18% 0 NRG 5 115.3 0.81% 1 NRG 5 115.3 0.81% 1 NU 4279.6 30.18% 911 NU 4279.6 30.18% 911 PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0 PMLP 10.8 0.08% 0 PMLP 10.8 0.08% 0 SC 0.0 0.00% 0 SC 0.0 0.00% 0 SELP 2.2 0.02% 0 SELP 2.2 0.02% 0 SITHE 0.0 0.00% 0 SITHE 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0 TMLP 15.4 0.11% 0 TMLP 15.4 0.11% 0 UI 384.2 2.71% 7 UI 384.2 2.71% 7 UNITIL 18.7 0.13% 0 UNITIL 18.7 0.13% 0 USG 4 2746.8 19.37% 375 USG 4 2746.8 19.37% 375 VTGP 157.7 1.11% 1 VTGP 157.7 1.11% 1 NY 1675.0 11.81% 140 NY 1675.0 11.81% 140 NB 700.0 4.94% 24 NB 700.0 4.94% 24 WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0 - ----------------------------------------------------------------------------------------------------------------------------------- Total 14179.7 100.00% Total 14179.7 100.00% HHI 1606.77 HHI 1611.52 Change in HHI 4.75 Source: Reed Report at Table 10. Notes: 1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee. 2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. 3. EUA divested 33.7 MW of generation capacity to GBPC. 4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP capacity is attributed to USG. 5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-1 Page 9 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Economic Capacity Analysis, Shoulder Peak Pre-Merger Post-Merger Total Total Shoulder Share of Shoulder Share of Capacity Shoulder Square of Capacity Shoulder Square of Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share - ----------------------------------------------------------------------------------------------------------------------------------- EUA 1 133.2 0.80% 1 NEP 2 354.9 2.14% 5 EUA/NEP 488.1 2.94% 9 BECO/CES 1334.9 8.04% 65 BECO/CES 1334.9 8.04% 65 BELD 6.1 0.04% 0 BELD 6.1 0.04% 0 BHE 108.6 0.65% 0 BHE 108.6 0.65% 0 BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0 CLNP 5 56.8 0.34% 0 CLNP 5 56.8 0.34% 0 CMEEC 84.3 0.51% 0 CMEEC 84.3 0.51% 0 CMLP 25.6 0.15% 0 CMLP 25.6 0.15% 0 CMP 828.4 4.99% 25 CMP 828.4 4.99% 25 CV 256.5 1.54% 2 CV 256.5 1.54% 2 DPA 0.0 0.00% 0 DPA 0.0 0.00% 0 DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0 FGE 50.1 0.30% 0 FGE 50.1 0.30% 0 FPL 5 0.0 0.00% 0 FPL 5 0.0 0.00% 0 GBPC 3 174.7 1.05% 1 GBPC 3 174.7 1.05% 1 GMP 202.8 1.22% 1 GMP 202.8 1.22% 1 HGE 5.7 0.03% 0 HGE 5.7 0.03% 0 HLPD 7.3 0.04% 0 HLPD 7.3 0.04% 0 HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0 IMEL 52.4 0.32% 0 IMEL 52.4 0.32% 0 IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0 IPPA 38.2 0.23% 0 IPPA 38.2 0.23% 0 MGED 2.9 0.02% 0 MGED 2.9 0.02% 0 MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0 MMWEC 298.6 1.80% 3 MMWEC 298.6 1.80% 3 MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0 NAED 1.5 0.01% 0 NAED 1.5 0.01% 0 NHCO 25.3 0.15% 0 NHCO 25.3 0.15% 0 NRG 5 115.3 0.69% 0 NRG 5 115.3 0.69% 0 NU 4984.6 30.02% 901 NU 4984.6 30.02% 901 PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0 PMLP 10.8 0.07% 0 PMLP 10.8 0.07% 0 SC 0.0 0.00% 0 SC 0.0 0.00% 0 SELP 2.2 0.01% 0 SELP 2.2 0.01% 0 SITHE 388.1 2.34% 5 SITHE 388.1 2.34% 5 TCPM 4, 5 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0 TMLP 15.4 0.09% 0 TMLP 15.4 0.09% 0 UI 1463.4 8.81% 78 UI 1463.4 8.81% 78 UNITIL 18.6 0.11% 0 UNITIL 18.6 0.11% 0 USG 4 3031.9 18.26% 333 USG 4 3031.9 18.26% 333 VTGP 147.9 0.89% 1 VTGP 147.9 0.89% 1 NY 1675.0 10.09% 102 NY 1675.0 10.09% 102 NB 700.0 4.22% 18 NB 700.0 4.22% 18 WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0 - ----------------------------------------------------------------------------------------------------------------------------------- Total 16604.0 100.00% Total 16604.0 100.00% 1542.70 1546.13 Change in HHI 3.43 Source: Reed Report at Table 7. Notes: 1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee. 2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. 3. EUA divested 33.7 MW of generation capacity to GBPC. 4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP capacity is attributed to USG. 5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-1 Page 10 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Economic Capacity Analysis, Shoulder Off Peak Pre-Merger Post-Merger Total Total Shoulder Share of Shoulder Share of Capacity Shoulder Square of Capacity Shoulder Square of Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share - ----------------------------------------------------------------------------------------------------------------------------------- EUA 1 133.2 1.07% 1 NEP 2 354.9 2.85% 8 EUA/NEP 488.1 3.92% 15 BECO/CES 1334.9 10.72% 115 BECO/CES 1334.9 10.72% 115 BELD 6.1 0.05% 0 BELD 6.1 0.05% 0 BHE 108.6 0.87% 1 BHE 108.6 0.87% 1 BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0 CLNP 5 56.8 0.46% 0 CLNP 5 56.8 0.46% 0 CMEEC 75.9 0.61% 0 CMEEC 75.9 0.61% 0 CMLP 25.6 0.21% 0 CMLP 25.6 0.21% 0 CMP 828.4 6.65% 44 CMP 828.4 6.65% 44 CV 256.5 2.06% 4 CV 256.5 2.06% 4 DPA 0.0 0.00% 0 DPA 0.0 0.00% 0 DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0 FGE 29.1 0.23% 0 FGE 29.1 0.23% 0 FPL 5 0.0 0.00% 0 FPL 5 0.0 0.00% 0 GBPC 3 174.7 1.40% 2 GBPC 3 174.7 1.40% 2 GMP 202.8 1.63% 3 GMP 202.8 1.63% 3 HGE 5.7 0.05% 0 HGE 5.7 0.05% 0 HLPD 7.3 0.06% 0 HLPD 7.3 0.06% 0 HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0 IMEL 52.4 0.42% 0 IMEL 52.4 0.42% 0 IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0 IPPA 38.2 0.31% 0 IPPA 38.2 0.31% 0 MGED 2.9 0.02% 0 MGED 2.9 0.02% 0 MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0 MMWEC 290.2 2.33% 5 MMWEC 290.2 2.33% 5 MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0 NAED 1.5 0.01% 0 NAED 1.5 0.01% 0 NHCO 25.3 0.20% 0 NHCO 25.3 0.20% 0 NRG 5 115.3 0.91% 1 NRG 5 113.2 0.91% 1 NU 4220.0 33.88% 1148 NU 4220.0 33.88% 1148 PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0 PMLP 10.8 0.09% 0 PMLP 10.8 0.09% 0 SC 0.0 0.00% 0 SC 0.0 0.00% 0 SELP 2.2 0.02% 0 SELP 2.2 0.02% 0 SITHE 0.0 0.00% 0 SITHE 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0 TMLP 15.4 0.12% 0 TMLP 15.4 0.12% 0 UI 383.8 3.08% 9 UI 383.8 3.08% 9 UNITIL 18.6 0.15% 0 UNITIL 18.6 0.15% 0 USG 4 1156.9 9.29% 86 USG 4 1156.9 9.29% 86 VTGP 147.9 1.19% 1 VTGP 147.9 1.19% 1 NY 1675.0 13.45% 181 NY 1675.0 13.45% 181 NB 700.0 5.62% 32 NB 700.0 5.62% 32 WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0 - ----------------------------------------------------------------------------------------------------------------------------------- Total 12456.7 100.00% Total 12456.7 100.00% 1642.46 1648.55 Change in HHI 6.09 Source: Reed Report at Table 10. Notes: 1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee. 2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. 3. EUA divested 33.7 MW of generation capacity to GBPC. 4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP capacity is attributed to USG. 5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-1 Page 11 of 11 Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report Economic Capacity Analysis, Super Peak Pre-Merger Post-Merger Total Total Summer Share of Summer Share of Capacity Summer Square of Capacity Summer Square of Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share - ----------------------------------------------------------------------------------------------------------------------------------- EUA 1 132.9 0.52% 0 NEP 2 409.1 1.60% 3 EUA/NEP 542.0 2.12% 4 BECO/CES 1938.2 7.58% 57 BECO/CES 1938.2 7.58% 57 BELD 70.0 0.27% 0 BELD 70.0 0.27% 0 BHE 155.9 0.61% 0 BHE 155.9 0.61% 0 BPDI 265.9 1.04% 1 BPDI 265.9 1.04% 1 CLNP 5 231.3 0.90% 1 CLNP 5 231.3 0.90% 1 CMEEC 159.4 0.62% 0 CMEEC 159.4 0.62% 0 CMLP 25.5 0.10% 0 CMLP 25.5 0.10% 0 CMP 1390.9 5.44% 30 CMP 1390.9 5.44% 30 CV 299.8 1.17% 1 CV 299.8 1.17% 1 DPA 168.0 0.66% 0 DPA 168.0 0.66% 0 DUKE 480.0 1.88% 4 DUKE 480.0 1.88% 4 FGE 51.1 0.20% 0 FGE 51.1 0.20% 0 FPL 5 16.2 0.06% 0 FPL 5 16.2 0.06% 0 GBPC 3 174.7 0.68% 0 GBPC 3 174.7 0.68% 0 GMP 241.0 0.94% 1 GMP 241.0 0.94% 1 HGE 31.6 0.12% 0 HGE 31.6 0.12% 0 HLPD 13.4 0.05% 0 HLPD 13.4 0.05% 0 HMLP 5.8 0.02% 0 HMLP 5.8 0.02% 0 IMEL 52.4 0.20% 0 IMEL 52.4 0.20% 0 IMLD 2.8 0.01% 0 IMLD 2.8 0.01% 0 IPPA 34.1 0.13% 0 IPPA 34.1 0.13% 0 MGED 2.8 0.01% 0 MGED 2.8 0.01% 0 MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0 MMWEC 547.7 2.14% 5 MMWEC 547.7 2.14% 5 MPLP 149.0 0.58% 0 MPLP 149.0 0.58% 0 NAED 13.5 0.05% 0 NAED 13.5 0.05% 0 NHCO 25.3 0.10% 0 NHCO 25.3 0.10% 0 NRG 5 113.2 0.44% 0 NRG 5 113.2 0.44% 0 NU 6961.9 27.23% 742 NU 6961.9 27.23% 742 PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0 PMLP 24.7 0.10% 0 PMLP 24.7 0.10% 0 SC 531.8 2.08% 4 SC 531.8 2.08% 4 SELP 2.2 0.01% 0 SELP 2.2 0.01% 0 SITHE 1776.2 6.95% 48 SITHE 1776.2 6.95% 48 TCPM 4, 5 373.9 1.46% 2 TCPM 4, 5 373.9 1.46% 2 TMLP 103.8 0.41% 0 TMLP 103.8 0.41% 0 UI 1451.0 5.68% 32 UI 1451.0 5.68% 32 UNITIL 32.8 0.13% 0 UNITIL 32.8 0.13% 0 USG 4 4563.7 17.85% 319 USG 4 4563.7 17.85% 319 VTGP 167.0 0.65% 0 VTGP 167.0 0.65% 0 NY 1675.0 6.55% 43 NY 1675.0 6.55% 43 NB 700.0 2.74% 7 NB 700.0 2.74% 7 WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0 - ----------------------------------------------------------------------------------------------------------------------------------- Total 25565.8 100.0% Total 25565.8 100.00% 1302.79 1304.45 Change in HHI 1.66 Source: Reed Report at Table 10. Notes: 1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee. 2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4. 3. EUA divested 33.7 MW of generation capacity to GBPC. 4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP capacity is attributed to USG. 5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
[LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-2 Page 1 of 2 Analysis of the Acquisition of EUA by NEES Based Upon Pace Report Total Installed Capability 1999 - 2000 - --------------------------------------------------------------------------------------------- Sum-1999 Win-1999 Sum-2000 Win-2000 - --------------------------------------------------------------------------------------------- Total Capacity 25,660 26,022 25,681 26,022 New England Power Capacity (MW) 401.75 407.46 401.75 407.46 Montaup Capacity (MW) 130.1 131.3 130.1 131.3 New England Power Share 1.57% 1.57% 1.56% 1.57% Montaup Share 0.51% 0.50% 0.51% 0.50% Change in HHI* 1.59 1.58 1.59 1.58 Sources: Total Installed Capacity from Pace Report. Capacity Figures from 1999 CELT Report. Notes: *Change in HHI due to the NEES/EUA transaction is two times the product of the NEES and EUA capability shares. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-3 Page 2 of 2 Analysis of the Acquisition of EUA by NEES Based Upon the Pace Report Total Economic Capacity 1998 and 2000 - ----------------------------------------------------------------------------------------------------- Spr-98 Sum-98 Fal-98 Win-98 Spr-00 Sum-00 Fal-00 Win-00 - ----------------------------------------------------------------------------------------------------- Total Economic 9174 9326 9373 9748 9226 9343 9389 9855 Capacity (MW) New England Power (MW)* 252.79 341.67 323.73 318.79 252.47 341.61 323.61 319.19 Montaup (MW)* 85.22 114.31 107.75 106.18 85.12 114.3 107.71 106.3 New England Power Share 2.76% 3.66% 3.45% 3.27% 2.74% 3.66% 3.45% 3.24% Montaup Share 0.93% 1.23% 1.15% 1.09% 0.92% 1.22% 1.15% 1.08% Change in HHI** 5.12 8.98 7.94 7.12 5.05 8.95 7.91 6.99 Source: Pace Report. Notes: * Assumes all entitlements for EUA and NEES are included in total economic capacity. **Change in HHI due to the NEES/EUA transaction is two times the product of the NEES and EUA total economic capacity shares.
[LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-3 Page 1 of 2 Analysis of the Acquisition of EUA by NEES Based Upon the Hieronymous Report Total Installed Capability July 1997 - December 1999 - ---------------------------------------------------------------------------------------------------------------------------- Jul-97 Aug-97 Sep-97 Oct-97 Nov-97 Dec-97 Jan-98 Feb-98 Mar-98 Apr-98 - ---------------------------------------------------------------------------------------------------------------------------- Total Installed Capability (MW) 26809 26809 26809 27255 26607 26607 26607 26607 26607 26607 New England Power Capability (MW)* 401.75 401.75 401.75 407.46 407.46 407.46 407.46 407.46 407.46 401.75 Montaup Capability (MW)* 130.1 130.1 130.1 131.3 131.3 131.3 131.3 131.3 131.3 130.1 New England Power Share 1.52% 1.52% 1.52% 1.49% 1.53% 1.53% 1.51% 1.51% 1.51% 1.51% Montaup Share 0.49% 0.49% 0.49% 0.48% 0.49% 0.49% 0.49% 0.49% 0.49% 0.49% Change in HHI** 1.13 1.13 1.13 1.08 1.16 1.16 1.11 1.11 1.11 1.11 - ---------------------------------------------------------------------------------------------------------------------------- May-98 Jun-98 Jul-98 Aug-98 Sep-98 Oct-98 Nov-98 Dec-98 Jan-99 Feb-99 - ---------------------------------------------------------------------------------------------------------------------------- Total Installed Capability (MW) 27255 26809 26809 26809 26809 27255 27255 27255 27255 27255 New England Power Capability (MW)* 401.75 401.75 401.75 401.75 401.75 407.46 407.46 407.46 407.46 407.46 Montaup Capability (MW)* 130.1 130.1 130.1 130.1 130.1 131.3 131.3 131.3 131.3 131.3 New England Power Share 1.47% 1.50% 1.52% 1.52% 1.52% 1.49% 1.49% 1.49% 1.49% 1.49% Montaup Share 0.48% 0.49% 0.49% 0.49% 0.49% 0.48% 0.48% 0.48% 0.48% 0.48% Change in HHI** 1.04 1.09 1.13 1.13 1.13 1.08 1.08 1.08 1.08 1.08 - ---------------------------------------------------------------------------------------------------------------------------- Mar-99 Apr-99 May-99 Jun-99 Jul-99 Aug-99 Sep-99 Oct-99 Nov-99 Dec-99 - ---------------------------------------------------------------------------------------------------------------------------- Total Installed Capability (MW) 27255 27255 27255 26809 26809 26809 26809 27255 27255 27255 New England Power Capability (MW)* 407.46 401.75 401.75 401.75 401.75 401.75 401.75 407.46 407.46 407.46 Montaup Capability (MW)* 131.3 130.1 130.1 130.1 130.1 130.1 130.1 131.3 131.3 131.3 New England Power Share 1.49% 1.49% 1.49% 1.50% 1.50% 1.50% 1.50% 1.49% 1.49% 1.49% Montaup Share 0.48% 0.48% 0.48% 0.49% 0.49% 0.49% 0.49% 0.48% 0.48% 0.48% Change in HHI** 1.08 1.04 1.04 1.09 1.09 1.09 1.09 1.08 1.08 1.08 Sources: New England Power and Montaup capabilities from 1999 CELT Report. Total Installed capability from Hieronymous Report at WHH-12. Notes: *Summer capabilities used for April - September. Winter capabilities used for October - March. **Change in HHI due to the NEES/EUA transaction is two times the product of the NEES and EUA capability shares. [LECG Logo] New England Power Company, et al. Docket No. EC 99-____ Workpaper HJK-3 Page 2 of 2 Analysis of the Acquisition of EUA by NEES Based Upon the Hieronymous Report Total Energy 1998-1999 Company Plant MWh - -------------------------------------------------------------------------------- New England Power Millstone 31 302,413 New England Power Seabrook 12 791,206 New England Power Vermont Yankee 3 767,214* New England Power Wyman 42 74,825 Montaup Millstone 31 99,300 Montaup Vermont Yankee3 95,998** Montaup Pilgrim4 474,147*** - -------------------------------------------------------------------------------- 1998 1999 - -------------------------------------------------------------------------------- Total Energy5 58,741,078 59,788,486 New England Power Energy (MWh) 1,935,658 1,935,658 Montaup Energy (MWh) 669,445 669,445 New England Power 3.30% 3.24% Montaup 1.14% 1.12% Change in HHI**** 7.51 7.25
Source: 1. Milestone 3 MWh data from Montaup and New England Power's 1997 FERC Form 1. 2. Seabrook 1 and Wyman 4 MWh data from New England Power's 1998 FERC Form 1. 3. Vermont Yankee MWh data from Vermont Yankee Nuclear Power Corporation 1998 FERC Form 1. 4. Pilgrim MWh from Boston Edison Company's 1998 FERC Form 1. 5. Total Energy from Hieronymous Report at WHH-13. Notes: * Vermont Yankee's total production listed in the 1998 FERC Form 1 is 4,266,866 MWh. New England Power's Vermont Yankee entitlement is 17.982% of plant capacity. ** Vermont Yankee's total production listed in the 1998 FERC Form 1 is 4,266,866 MWh. Montaup's Vermont Yankee entitlement is 2.25% of plant capacity. *** Pilgrim's total production listed in the 1998 FERC Form 1 is 4,310,431 MWh. Montaup's Pilgrim entitlement is 11% of plant capacity. **** Change in HHI due to the NEES/EUA transaction is two times the product of the NEES and EUA energy shares. [LECG Logo] Attachment 2 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) THE NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-_____ NEW ENGLAND HYDRO-TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO-TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY, L.L.C. ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) Declaration of Henry J. Kahwaty I, Henry J. Kahwaty, declare: 1. My name is Henry J. Kahwaty. I am a Senior Managing Economist with LECG (formerly Law & Economics Consulting Group, Inc.). LECG is a firm providing management consulting and expert analysis in the areas of economics, finance, and accounting. My business address is 1600 M. Street, N.W., Suite 700, Washington, D.C. 20036. [LECG Logo] Declaration of Henry J. Kahwaty 2. I received my Ph.D. in Economics from the University of Pennsylvania in 1991. My fields of specialization include industrial organization and public economics. Industrial organization involves the study of competition and regulation in individual markets. Prior to joining LECG, I worked for nearly four years as an economist for the Antitrust Division of the U.S. Department of Justice. I have analyzed the competitive implications of numerous mergers, both during my employment with the Antitrust Division and with LECG. I have worked on competition issues in electricity, telecommunications, and other network industries, and I have broad experience in applied microeconomics analysis. A copy of my curriculum vitae is attached to this Declaration. 3. I submitted a Declaration analyzing the competitive implications of the proposed acquisition of New England Electric System ("NEES") by the National Grid Group plc ("National Grid") in Docket No. EC99-49-000 dated March 8, 1999, and filed March 10, 1999. My analysis demonstrated that the proposed acquisition of NEES by National Grid does not raise horizontal competitive concerns because NEES and National Grid affiliates do not provide competing products or services in any relevant geographic market. In addition, the proposed acquisition of NEES by National Grid does not 2 [LECG Logo] Declaration of Henry J. Kahwaty raise vertical concerns because NEES and National Grid affiliates do not provide inputs, such as fuel supplies, used in the production or delivery of electric products or services in the region(s) served by the other. 4. I have been asked by counsel for New England Power Company ("New England Power"), Montaup Electric Company ("Montaup"), and National Grid to consider whether the acquisition of Eastern Utilities Associates ("EUA") by NEES alters my analysis of the competitive implications of the proposed acquisition of NEES by National Grid.1 This Declaration summarizes my analysis of this question. 5. My conclusion, that the acquisition of NEES by National Grid will not harm competition, is not altered by NEES's proposed acquisition of EUA. The NEES and EUA systems are similar in that neither system provides competing products or services in any relevant geographic market presently served by National Grid or its affiliates. In addition, EUA's and National Grid's affiliates do not provide inputs into the production or delivery of electricity in the regions served by the other. Furthermore, NEES's and EUA's affiliates will continue to provide transmission and distribution service under open access tariffs after the completion of the EUA acquisition. As a result, the acquisition of EUA by NEES does not alter my conclusion that the acquisition of NEES by National Grid will not harm competition. 6. EUA is a holding company whose affiliates own and operate electric transmission and distribution assets in Massachusetts and Rhode Island. In particular, EUA subsidiary Montaup owns transmission assets in Massachusetts and leases transmission facilities from - --------------- 1 New England Power is a subsidiary of NEES, and Montaup is a subsidiary of EUA. 3 [LECG Logo] Declaration of Henry J. Kahwaty affiliates in both Massachusetts and Rhode Island. The EUA distribution companies include Eastern Edison Company, Blackstone Valley Electric Company, and Newport Electric Corporation. Eastern Edison Company provides distribution service in Massachusetts, and both Blackstone Valley Electric Company and Newport Electric Corporation provide distribution service in Rhode Island. The EUA distribution companies do not provide transmission services. EUA also owns several unregulated companies active in energy-related businesses, including the energy management company, Cogenex Corporation. 7. As with New England Power, Montaup has also sold or entered into agreements to sell nearly all of its generation assets to other companies pursuant to electric utility restructuring legislation and settlement agreements approved by regulators in Rhode Island, Massachusetts, and at the Federal Energy Regulatory Commission ("FERC"). Prior to its divestitures, Montaup owned or held equity interest in approximately 570 MW of generation capacity, all in New England, and held power purchase entitlements in an additional 500 MW. Montaup, however, recently has sold or entered into agreements to sell its fossil and hydroelectric generation capacity. It has also signed agreements for the transfer of power purchase contracts and for a buyout of its 11 percent power entitlement from the Pilgrim nuclear generation station. Overall, Montaup has sold or agreed to sell or transfer assets and rights to purchase power entitlements to Constellation Power Source (an affiliate of Baltimore Gas and Electric Co.), NRG Energy (an affiliate of Northern States Power), FPL 4 [LECG Logo] Declaration of Henry J. Kahwaty Group, BayCorp Holdings (an affiliate of Great Bay Power), Southern Energy (an affiliate of Southern Company), TransCanada Power Marketing, and others.2 8. Montaup's remaining generation resources are minority shares in three nuclear generating stations. In particular, Montaup owns entitlements to 4.01 percent of the Millstone 3 and 2.25 percent of the Vermont Yankee nuclear plants.3 In addition, Montaup has a purchased power agreement with Entergy giving Montaup an entitlement to 11 percent of the output of the Pilgrim nuclear station in 1999. This entitlement declines over time and ends after 2004.4) These resources represent a total of approximately 131 MW of generation capacity currently, declining to 57 MW after 2004. 9. National Grid was formed in 1990 as part of the privatization of the electric industry in England and Wales. National Grid and its subsidiaries own and operate the transmission system in England and Wales and they also operate the interconnections between this system and the transmission systems in Scotland and France. In addition, National Grid, through its - --------------- 2 These affiliates include New England Electric Transmission Corporation, New England Hydro-Transmission Corporation, and New England Hydro- Transmission Electric Company, Inc. 3 NEPOOL Forecast of Capacity, Energy, Loads and Transmission, April 1, 1999 at 15. Montaup owns 2.5 percent of Vermont Yankee, but it has resold a portion to a group of municipals. 5 [LECG Logo] Declaration of Henry J. Kahwaty subsidiary, National Grid ("NGC") serves as a power market matching the generation of electricity with demand on a real time basis. NGC also facilitates the trading of power in the electricity market by managing the daily bidding system for generators desiring to sell power, calculating market prices and payments due by individual traders, and managing the transfer of funds to settle electricity trades. Prior to 1996, the regional electricity companies in England and Wales owned National Grid. In December, 1995, however, National Grid was floated as a separate company on the London Stock Exchange. 10. National Grid also owns and, through subsidiaries, operates transmission assets outside of the U.K., including assets in Argentina and Zambia. In particular, National Grid, through a subsidiary, owns 41.25 percent of Transener, the main Argentine transmission company. National Grid also jointly (with CINergy Global) owns 80 percent of the Power Division of Zambia Consolidated Copper mines. National Grid has been selected to build a transmission line in southern India as part of a joint venture with the Karnataka Electricity Board. Neither National Grid nor any of its subsidiaries owns or operates any transmission assets in the United States, Canada, or Mexico. 11. Neither National Grid nor any of its subsidiaries provides transmission or distribution services in any geographic area that overlaps with the areas served by the EUA companies. EUA's affiliates provide transmission and distribution services solely in the northeastern United States. National Grid and its subsidiaries do not provide transmission or distribution services in the northeastern United States or elsewhere in North America. EUA's - --------------- 4 Montaup presently has a life-of-unit purchase power agreement with Boston Edison Company covering 11 percent of the energy generated by the Pilgrim station. Boston Edison Company is selling Pilgrim to Entergy Nuclear Generating Company, and Montaup has an agreement with Entergy Nuclear Generating to purchase power from this unit. The purchase power agreement entitles Montaup to the 11 percent of the output of the Pilgrim station in 1999, and this entitlement declines to 8.8 percent in 2002, 5.5 percent in 2003 and 2004, and ends thereafter. 6 [LECG Logo] Declaration of Henry J. Kahwaty transmission or distribution customers presently cannot turn to National Grid or its subsidiaries as alternative providers of these services. 12. With regard to electric generation services, the EUA companies do not provide electric generation services in any geographic area that overlaps with National Grid or its subsidiaries. Montaup has sold nearly all of its generation assets and does not have operating control over the generation plants in which it continues to hold entitlements. EUA's remaining generation interests are located in New England. Neither National Grid nor any of its present subsidiaries owns or controls any generation facilities located in New England or elsewhere in North America. 13. The FERC has recognized that mergers involving firms serving no common geographic markets typically do not raise competitive concerns. In its Policy Statement on mergers, the FERC stated: [I]t will not be necessary for the merger applicants to perform the screen analysis or file data needed for the screen analysis in cases where the merging firms do not have facilities or sell relevant products in common geographic markets. In these cases, the proposed merger will not have an adverse competitive impact (i.e., there can be no increase in the applicants' market power unless they are selling relevant products in the same geographic markets) so there is no need for a detailed analysis.5 - --------------- 5 Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, [("Policy Statement")] Order No. 592, 77 FERC 61,263 (1996). 7 [LECG Logo] Declaration of Henry J. Kahwaty 14. This is consistent with the Horizontal Merger Guidelines jointly issued by the Department of Justice and the Federal Trade Commission.6 The Horizontal Merger Guidelines is the statement of the horizontal merger enforcement policy of these two agencies under the federal antitrust statutes. Horizontal mergers are mergers involving companies that compete in one or more markets. The Horizontal Merger Guidelines state: A merger is unlikely to create or enhance market power or facilitate its exercise unless it significantly increases concentration and results in a concentrated market, properly defined and measured. Mergers that either do not significantly increase concentration or do not result in a concentrated market ordinarily require no further analysis.7 Because National Grid, its subsidiaries, and the EUA companies do not provide any products or services in any overlapping relevant markets, this transaction is not a horizontal merger and will not result in the elimination of a competitor in any market. As a result, I conclude that the combination of EUA's assets with those of National Grid will not result in competitive harm due to the creation or enhancement of market power. 15. Neither National Grid nor its subsidiaries presently provide fuel supplies, fuel transportation services, equipment, or other inputs used in the production or delivery of electric products or services in the region served by the EUA companies - the northeastern United States. Similarly, the EUA companies do not supply inputs used in the production or delivery of - --------------- 6 The Horizontal Merger Guidelines were issued April 2, 1992 and revised April 8, 1997. www.usdoj.gov/atr/public/guidelines/horiz book/hmg1.html. 7 Horizontal Merger Guidelines at section 1.0. 8 [LECG Logo] Declaration of Henry J. Kahwaty electricity in regions currently served by National Grid or its subsidiaries. Neither the EUA companies nor National Grid and its subsidiaries generate or market electricity in the geographic areas served by the other. As a result, the combination of EUA's assets with those of National Grid will not create or enhance incentives for the EUA companies, National Grid, or its subsidiaries adversely to affect prices and output in downstream electricity markets. In particular, this combination will not create incentives for EUA's affiliates to restrict the access of non-affiliates to the transmission or distribution systems of the EUA companies. 16. Furthermore, EUA affiliates currently provide transmission and distribution service to electric generators and power marketers under open access tariffs. These assets will continue to be available for use by others under open access tariffs after the completion of National Grid's acquisition of NEES and NEES's acquisition of EUA. As a result, these acquisitions will not affect the ability of EUA, NEES, or National Grid affiliates to restrict access to these transmission or distribution assets. I conclude that the combination of EUA and its subsidiaries with National Grid is not a vertical merger and will not impact the incentive or ability of the EUA companies, the NEES companies, National Grid, or its subsidiaries adversely to affect competition through vertical effects such as foreclosure, facilitating coordination, or regulatory evasion.8 - --------------- 8 My analysis is consistent with the FERC's current thinking on vertical merger analysis. See Revised Filing Requirements Under Part 33 of the Commission's Regulations, April 16, 1998, Docket No. RM98-4-000, slip op. at 46-50. 9 [LECG Logo] Declaration of Henry J. Kahwaty 17. I conclude that the proposed acquisition of EUA by NEES has no impact on the competitive implications of NEES's acquisition by National Grid. In particular, the combination of the NEES, EUA, and National Grid assets will not result in harm to competition. Neither the NEES nor the EUA companies currently compete with National Grid or its subsidiaries in any relevant market. As a result, there is no horizontal overlap between the EUA companies and National Grid and its subsidiaries, and thus there is no prospect for the combination of EUA and National Grid to result in any horizontal competitive effects, adverse or otherwise. In addition, neither the EUA companies nor National Grid and its subsidiaries currently supply inputs used in the generation or delivery of electric products or services in regions served by the other. Also, EUA's transmission and distribution facilities will continue to be available for use under open access tariffs. As a result, the ultimate combination of National Grid with NEES and EUA will not result in anticompetitive effects arising from vertical concerns. I declare under penalty of perjury that the foregoing is true and correct. /s/ HENRY J. KAHWATY ---------------------------------------- Henry J. Kahwaty Signed on this 5th day of May, 1999 [LECG Logo] HENRY J. KAHWATY LECG 1600 M Street, N.W., Suite 700 Washington, D.C. 20036 Tel. (202) 466-4422 Fax (202) 466-4487 EDUCATION Ph.D., Economics, UNIVERSITY OF PENNSYLVANIA, Graduate School of Arts and Sciences, Philadelphia, PA, 1991 Thesis Title: Essays on Vertical Relationships Thesis Topic: Vertical Relationships with Asymmetric Information and Incomplete Contracting Specialty Areas: Industrial Organization, Public Economics, Monetary Economics M.A., Economics, UNIVERSITY OF PENNSYLVANIA, Graduate School of Arts and Sciences, Philadelphia, PA, 1988 B.A. magna cum laude and Phi Beta Kappa, Mathematics and Economics, UNIVERSITY OF PENNSYLVANIA, College of Arts and Sciences, Philadelphia, PA, 1986 PRESENT POSITION LECG, Washington, D.C. Senior Managing Economist, 1997-present [LECG Logo] Henry J. Kahwaty Page 2 Senior Economist, 1995-1996 o Analysis of antitrust market definition. o Analysis of the competitive effects resulting from mergers. o Monopolization analysis. o Analysis of competition issues in the electric utility industry, including market-based pricing and deregulation proposals, mergers, wholesale markets, and retail wheeling. o Analysis of competition and other issues in telecommunications. o Damage studies. Consultant to Rational Software Corp. in proposed acquisition of Pure Atria Corp., 1997. Consultant to National Communications Association, Inc. in National Communications Association, Inc. v. American Telephone and Telegraph Company, 1997-1998. [LECG Logo] Henry J. Kahwaty Page 2 Consultant to Public Service Enterprises of Pennsylvania, Inc. in arbitration between Public Service Enterprises of Pennsylvania, Inc. and AT&T Corporation, 1997-1998. Consultant to Aptix Corporation in Aptix Corporation v. Quickturn Design Systems, Inc., 1998. Consultant to New England Electric System in proposed acquisition by National Grid Group plc, 1999. Consultant to New England Electric System in proposed acquisition of Eastern Utilities Associates, 1999. Experience with the following industries: o Local and long distance telecommunications o Computer software and software development tools o Computer hardware, including microprocessors and modems o Electricity o Defense electronics o Hardware emulation [LECG Logo] Henry J. Kahwaty Page 3 PROFESSIONAL EXPERIENCE U.S. DEPARTMENT OF JUSTICE, Antitrust Division, Economic Litigation Section, 1991-1995 Economist o Prepared economic models and analysis for antitrust cases. o Prepared antitrust investigation plans. o Reviewed civil investigative demands, second requests, subpoenas, complaints, affidavits, and other documents. o Assisted attorneys with gathering evidence, including conducting witness interviews and assisting with witness depositions. o Recommended whether to institute enforcement actions. o Specialized in computer software, defense, and banking industries. TESTIMONY Provided deposition and trial testimony in National Communications Association, Inc. v. American Telephone and Telegraph Company, 92 Civ. 1735 (LAP), U.S. District Court for the Southern District of New York, 1997- 1998. Provided deposition testimony in Aptix Corporation v. Quickturn Design Systems, Inc., C-96-20909 JF (EAI), U.S. District Court for the Northern District of California, 1998. SPEECHES "Unregulated Affiliates and the Market Power Problem," Forum on Electric Power Market Restructuring, Washington, D.C., February 19, 1999. "Antitrust Damages," Litigation Services Subcommittee of the Greater Washington Society of Certified Public Accountants, Washington, D.C., January 28, 1999. [LECG Logo] Henry J. Kahwaty Page 4 TEACHING EXPERIENCE UNIVERSITY OF PENNSYLVANIA, Philadelphia, PA, 1988-1991 o Industrial Organization o Topics in Microeconomics o Topics in Macroeconomics o Intermediate Microeconomics o Introductory Microeconomics o Introductory Macroeconomics UNPUBLISHED RESEARCH "The Analysis of Market Concentration, Market Power and the Competitive Effects of Mergers in the Electric Industry," with Richard J. Gilbert, June 1997. RESEARCH INTERESTS Oligopoly models, network externalities and asymmetric information. PROFESSIONAL ACTIVITIES Member, American Economic Association Member, European Association for Research in Industrial Economics Citizenship: United States of America April 1999 Form of Notice [FORM OF NOTICE] UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) THE NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. NEW ENGLAND HYDRO-TRANSMISSION ) EC99-______ CORPORATION ) NEW ENGLAND HYDRO-TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY, L.L.C. ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) NOTICE OF FILING Take notice that on May 5, 1999, New England Power Company ("NEP") and its affiliates holding jurisdictional assets (Massachusetts Electric Company, The Narragansett Electric Company, New England Electric Transmission Corporation, New England Hydro-Transmission Corporation, New England Hydro-Transmission Electric Company, Inc., and AllEnergy Marketing Company, L.L.C.) (collectively, the "NEES Companies"), Montaup Electric Company and its affiliates holding jurisdictional assets (Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation) (collectively, the "EUA Companies"), and Research Drive LLC submitted for filing an application under Section 203 of the Federal Power Act (16 U.S.C. section 824b) and Part 33 of the Commission's Regulations (18 C.F.R. section 33.1 et seq. (1998)) seeking the Commission's approval and related authorizations to effectuate a merger, the result of which would be to merge New England Electric System ("NEES"), the parent company of the NEES Companies, with the Eastern Utilities Associates ("EUA"), the parent company of the EUA Companies. Through the Merger, EUA will become a wholly-owned subsidiary of NEES, and will subsequently be consolidated into NEES. In addition, the Application seeks the Commission's approval and authorization for the subsequent mergers and consolidations of the complementary operating companies of the two systems that hold jurisdictional assets. Finally, the Application requests approval, if required, of the acquisition by The National Grid Group plc ("National Grid") of the EUA Companies resulting from the proposed merger of National Grid and NEES, approval of which has been sought in Docket No. EC99-49-000. The Application states that it (i) includes all the information and exhibits required by Part 33 of the Commission's regulations and the Commission's Merger Policy Statement with respect to the Merger; (ii) incorporates by reference any additional materials required with respect to the acquisition by National Grid of the EUA Companies; and (iii) easily satisfies the criteria set forth in the Commission's Merger Policy Statement. The Application requests that the Commission grant whatever waivers or authorizations are needed and grant approval without condition, modification or an evidentiary, trial-type hearing. The Application states that the parties are seeking to close the Merger expeditiously and thus the Applicants have requested Commission approval by July 31, 1999. The Applicants have served copies of the filing on the state commissions of Connecticut, Massachusetts, New Hampshire, Rhode Island and Vermont. Any person desiring to be heard or to protest said application should file a motion to intervene or protest with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426 in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 C.F.R. 385.211 and 18 C.F.R. 385.214). All such motions or protests should be filed on or before __________. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make the protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. Copies of this filing are on file with the Commission and are available for public inspection. 2 Verifications UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-_____ NEW ENGLAND HYDRO TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY LLC ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) VERIFICATION Robert G. Powderly, being duly sworn upon oath, states that he is Executive Vice-President of Montaup Electric Company, Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation and has read the attached JOINT APPLICATION OF NEW ENGLAND POWER COMPANY et al. AND MONTAUP ELECTRIC COMPANY et al. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS; that he knows the contents thereof; that the statements made therein are true and correct to the best of his knowledge, information and belief; and that he has full power and authority to sign this document on behalf of Montaup Electric Company, Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation. /s/ ROBERT G. POWDERLY ---------------------------------------- Robert G. Powderly Executive Vice-President Subscribed and sworn to before me this 26th day of April, 1999. /s/ BARBRA L. DANTONO ---------------------------------------- Notary Public My Commission expires March 30, 2001 -------------------- UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-_____ NEW ENGLAND HYDRO TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY LLC ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) VERIFICATION Michael E. Jesanis, being duly sworn upon oath, states that he is Senior Vice President and Chief Financial Officer of New England Electric System, and has read the attached JOINT APPLICATION OF NEW ENGLAND POWER COMPANY et al. AND MONTAUP ELECTRIC COMPANY et al. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS; that he knows the contents thereof; that the statements made therein are true and correct to the best of his knowledge, information and belief; and that he has full power and authority to sign this document on behalf of the Applicants which are New England Electric System companies. /s/ MICHAEL E. JESANIS ---------------------------------------- Michael E. Jesanis Senior Vice President and Chief Financial Officer Subscribed and sworn to before me this 28th day of April, 1999. /s/ Sandra J. Brocher - ----------------------------------- Notary Public My Commission expires 8/19/2005 ------------- 2 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-_____ NEW ENGLAND HYDRO TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY LLC ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) VERIFICATION Jonathan M. G. Carlton, being duly sworn upon oath, states that he is Business Development Manager, Regulation of The National Grid Group plc, and has read the attached JOINT APPLICATION OF NEW ENGLAND POWER COMPANY et al. AND MONTAUP ELECTRIC COMPANY et al. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS; that he knows the contents thereof; that the statements made therein are true and correct to the best of his knowledge, information and belief; and that he has full power and authority to sign this document on behalf of The National Grid Group plc. /s/ JONATHAN M.G. CARLTON ---------------------------------------- Jonathan M.G. Carlton Business Development Manager, Regulation Subscribed and sworn to before me this 28th day of April, 1999. /s/ SANDRA J. BROCHER - ----------------------------------- Notary Public My Commission expires 8/19/2005 ------------- 3 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS AFFIDAVIT OF CHERYL A. LAFLEUR I, Cheryl A. Lafleur, Secretary of New England Electric System which is a business trust organized and existing under the laws of the Commonwealth of Massachusetts, HEREBY CERTIFY that I have reviewed exhibits A, B, and G annexed hereto and they are true and correct to the best of my knowledge. IN WITNESS WHEREOF, I have hereunto subscribed my name this 27th day of April, 1999. /s/ CHERYL A. LAFLEUR ---------------------------------------- Cheryl A. LaFleur Secretary Subscribed and sworn to before me this 27th day of April, 1999. /s/ SANDRA J. BROCHER - ----------------------------------- Notary Public My Commission expires 8/19/2005 ------------- 4 UNITED STATES OF AMERICA before the FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS AFFIDAVIT OF WILLIAM R. RICHER I, William R. Richer, Manager of General Accounting of New England Power Service Company, which provides accounting and other professional services for the New England Electric System companies ("NEES companies") and which is a corporation organized and existing under the laws of the Commonwealth of Massachusetts, HEREBY CERTIFY that I have reviewed NEES companies' portions of Exhibits C, D, E, and F annexed hereto and they are true and correct to the best of my knowledge. IN WITNESS WHEREOF, I have hereunto subscribed my name this 20th day of April, 1999. /s/ WILLIAM R. RICHER ---------------------------------------- William R. Richer Manager of General Accounting Subscribed and sworn to before me this 20th day of April, 1999. /s/ JOAN P. MORTIMER - ----------------------------------- Notary Public My Commission expires July 21, 2000 ----------------- UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS AFFIDAVIT OF MICHAEL E. JESANIS I, Michael E. Jesanis, Senior Vice President and Chief Financial Officer of New England Electric System which is a business trust organized and existing under the laws of the Commonwealth of Massachusetts, HEREBY CERTIFY that I have reviewed Exhibit H annexed hereto and it is true and correct to the best of my knowledge. IN WITNESS WHEREOF, I have hereunto subscribed my name this 28th day of April, 1999. /s/ MICHAEL E. JESANIS ---------------------------------------- Michael E. Jesanis Senior Vice President and Chief Financial Officer Subscribed and sworn to before me this 28th day of April, 1999. /s/ SANDRA J. BROCHER - ----------------------------------- Notary Public My Commission expires 8/19/2005 ------------- 6 UNITED STATES OF AMERICA before the FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS AFFIDAVIT OF DOMENICO A. GUAETTA I, Domenico A. Guaetta, Manager, Substation Design of New England Power Service Company, which provides design and other professional services for the New England Electric System companies and which is a corporation organized and existing under the laws of the Commonwealth of Massachusetts, HEREBY CERTIFY that I have reviewed Exhibit I annexed hereto and it is true and correct to the best of my knowledge. IN WITNESS WHEREOF, I have hereunto subscribed my name this 23rd day of April, 1999. /s/ DOMENICO A. GUAETTA ---------------------------------------- Domenico A. Guaetta Manager, Substation Design Subscribed and sworn to before me this 23rd day of April, 1999. /s/ DIANE J. CHAREST - ----------------------------------- Notary Public My commission expires April 23, 2004 ------------------ 7 UNITED STATES OF AMERICA before the FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS AFFIDAVIT OF I, Clifford J. Hebert, Jr., Treasurer and Secretary of Eastern Utilities Associates, which provides accounting and other professional services for the Eastern Utilities Associates companies and which is a voluntary association organized and existing under the laws of the Commonwealth of Massachusetts, HEREBY CERTIFY that I have reviewed Exhibit(s) A-I annexed hereto and they are true and correct to the best of my knowledge. IN WITNESS WHEREOF, I have hereunto subscribed my name this 27th day of April, 1999. /s/ CLIFFORD J. HEBERT, JR. ---------------------------------------- Clifford J. Hebert, Jr. Treasurer and Secretary Subscribed and sworn to before me this 27th day of April, 1999. /s/ ROSE MARY ABRAMS - ----------------------------------- Notary Public My Commission expires May 6, 2005 --------------- 8 NEW ENGLAND ELECTRIC SYSTEM Secretary's Certificate The undersigned, the Secretary of New England Electric System, a voluntary association created under the laws of The Commonwealth of Massachusetts, DOES HEREBY CERTIFY, on behalf of the Association, that: Attached hereto as Exhibit A is a true and correct copy of votes duly adopted by The Board of Directors of the Association, and registered with the Trustee, which Votes have not been revoked, modified, amended, or rescinded and remain in full force and effect on the date hereof, except as indicated therein. IN WITNESS WHEREOF, the undersigned has executed and delivered this certificate this 27th day of April, 1999. NEW ENGLAND ELECTRIC SYSTEM By: /s/ CHERYL A. LAFLEUR ----------------------------------- Cheryl A. LaFleur Secretary Subscribed and sworn to before me this 27th day of April, 1999. /s/ SANDRA J. BROCHER - ----------------------------------- Notary Public My Commission expires 8/19/2005 ------------- 9 NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Directors' Authorization Resolutions Votes Adopted at New England Electric System Board of Directors on January 30, 1999 VOTED: That Richard P. Sergel, President and Chief Executive Officer, and Michael E. Jesanis, Senior Vice president and Chief Financial Officer, are severally authorized to execute and deliver, in the name and on behalf of the Company, The Agreement and Plan of Merger, by and among Eastern Utilities Associates, a Merger Acquisition Subsidiary LLC of the Company, and the Company (the Merger Agreement) specifying the terms and conditions for the acquisition for cash of all the outstanding common shares of Eastern Utilities Associates at a price of $31.00 per share for an aggregate purchase price of up to $650 million, subject to adjustments as specified in the Merger Agreement; said Merger Agreement to be substantially in the form presented to this meeting, with such changes, additions, and modifications thereto as the officer or officers executing the same shall approve, such approval to be evidenced by the execution and delivery thereof. That the officers of the Company are severally authorized, in the name and on behalf of the Company, to form a Merger Acquisition Subsidiary LLC as a Massachusetts limited liability company with the Company having a ninety nine percent interest therein as a member (NEES Global, Inc. having a one percent interest); said Merger acquisition Subsidiary LLC being formed to execute and deliver the Merger Agreement; and all acts done and taken in pursuance thereof are authorized, approved, adopted, ratified, and confirmed. 10 That the officers of the Company are severally authorized to execute and deliver, in the name and on behalf of the Company, the Consent Agreement between National Grid Group plc. and the Company, containing the consent of National Grid Group plc to the Company's execution and delivery of the Merger Agreement and with respect to certain actions relating to the consummation of the transactions set forth therein; said Consent Agreement to be substantially in the form presented to this meeting, with such changes, additions, and modifications thereto as the officer or officers executing the same shall approve, such approval to be evidenced by the execution and delivery thereof. 11 EASTERN UTILITIES ASSOCIATES Secretary's Certificate The undersigned, the Secretary of Eastern Utilities Associates, a voluntary association created under the laws of The Commonwealth of Massachusetts (the "Association"), DOES HEREBY CERTIFY, on behalf of the Association, that: Attached hereto as Exhibit A is a true and correct copy of votes duly adopted by The Board of Trustees of the Association, which Votes have not been revoked, modified, amended, or rescinded and remain in full force and effect on the date hereof, except as indicated therein. IN WITNESS WHEREOF, the undersigned has executed and delivered this certificate this 27th day of April, 1999. EASTERN UTILITIES ASSOCIATES By: /s/ CLIFFORD J. HEBERT, JR. ----------------------------------- Clifford J. Hebert, Jr. Secretary Subscribed and sworn to before me this 27th day of April, 1999. /s/ ROSE MARY ABRAMS - ----------------------------------- Notary Public My Commission expires May 6, 2005 --------------- 12 NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Trustees' Authorization Resolutions Votes Adopted by Eastern Utilities Associates Board of Trustees on February 1, 1999 Attached 13 SPECIAL MEETING OF TRUSTEES, FEBRUARY 1, 1999 Pursuant to the action taken at the January 31, 1999 Special Meeting of the Trustees, a Special Meeting of the Trustees of Eastern Utilities Associates was held at the office of the Association, One Liberty Square, Boston, Massachusetts, on Monday, February 1, 1999 at 5:30 o'clock in the forenoon. There were present - Russell A. Boss (via conference telephone), Paul J. Choquette, Jr. (via conference telephone), Peter S. Damon (via conference telephone), Peter B. Freeman (via conference telephone), Larry A. Liebenow (via conference telephone), Jacek Makowski (via conference telephone), Wesley W. Marple, Jr. (via conference telephone) Donald G. Pardus, Margaret M. Stapleton (via conference telephone), John R. Stevens and W. Nicholas Thorndike (via conference telephone), being all of the Trustees. Clifford J. Hebert, Jr., Treasurer and Secretary of the Association, Henry A. Clark II (via conference telephone) and Robert N. Hoglund (via conference telephone), Managing Directors, of Salomon Smith Barney, Inc. ("Salomon"); David P. Falck (via conference telephone) of Winthrop, Stimson, Putnam & Roberts; and Arthur I. Anderson and David A. Fazzone (via conference telephone) of McDermott, Will & Emery, Counsel for the Association, were also present at the meeting. Donald G. Pardus, Chairman, presided. Arthur I. Anderson, Acting Secretary, kept the records of the meeting. Mr. Pardus asked if there were any additional questions regarding the proposed transaction with New England Electric System ("NEES"). A general discussion then ensued with respect to several questions which were raised by Trustees after review of the draft Merger Agreement. 14 The representatives of Salomon indicated that they were prepared to deliver their fairness opinion in connection with the NEES transaction as contemplated by the Merger Agreement. On motion duly made and seconded, the following votes were unanimously adopted: VOTED - that the form, terms and provisions of, and the transactions contemplated by, that certain Agreement and Plan of Merger (the "Agreement") by and among New England Electric System ("NEES"), Research Drive LLC ("LLC") and the Association in the form presented to the Trustees, pursuant to which LLC will be merged (the "Merger") into this Association and each Common Share of this Association will be converted into and exchanged for $31 in cash, subject to adjustment, be and it hereby is approved; and that the Chairman of the Board, Donald G. Pardus, be, and he hereby is, acting singly, authorized and directed to execute the Agreement and an acknowledgment of the Consent Agreement between NEES and National Group PLC pertaining to the Merger on behalf of the Association, with such changes, modifications and deletions as he so deems necessary, the execution and delivery thereof to be conclusive evidence of his authority so to act. VOTED - that, in accordance with the terms and conditions of the Agreement and the transactions contemplated thereby, the Chairman of the Board, the Vice Chairman of the Board, the President, any Vice President, the Treasurer, the Assistant Treasurer, the Secretary or any Assistant Secretary (collectively, the "Authorized Officers") of the Association be, and each of them hereby is, acting singly, authorized and directed to execute and file on behalf of the Association, all necessary regulatory filings as may be required, including, but not limited to, filings with the Department of Justice, the Federal Trade Commission, the Federal Communications Commission, the Nuclear Regulatory Commission, the Federal Energy Regulatory Commission, the Securities and Exchange Commission (the "SEC") and any of the following states: Massachusetts, New Hampshire, Maine, Connecticut, Vermont and Rhode Island, the filing by such Authorized Officer or Authorized Officers to be conclusive evidence of his or their authority so to act. VOTED - that the Association cause a proxy statement (the "Proxy Statement") to be prepared, in accordance with the requirements of the SEC, setting forth the necessary information concerning the transactions contemplated by the Agreement to obtain the required shareholder 15 authorization for the consummation of the transactions contemplated by the Agreement (including, without limitation, any required authorizations pursuant to Article 37 of this Association's Declaration of Trust, as amended) and that the Authorized Officers be, and each of them hereby is, acting singly, authorized and directed, to file the Proxy Statement with the SEC, with such provisions therein as the Authorized Officer or Authorized Officers filing the Proxy Statement may deem necessary or desirable, the filing by such Authorized Officer or Authorized Officers to be conclusive evidence of his or their authority so to act. VOTED - that the Trustees hereby declare that the Merger is advisable and in the best interests of the Association and recommend to shareholders that they approve the Merger. VOTED - that the Authorized Officers of this Association be, and each of them acting singly hereby is, authorized and empowered to do or cause to be done all such acts or things and to sign and deliver, or cause to be signed and delivered, all such documents, instruments and certificates (including, without limitation, obtaining all required shareholder authorizations under Article 37 of this Association's Declaration of Trust, as amended) as such officer of this Association may deem necessary, advisable or appropriate to effectuate or carry out the purposes and intent of the foregoing votes and to perform the obligations of this Association under the agreements and instruments referred to therein. 16 There being no further business to discuss, on motion duly made and seconded, it was VOTED - to adjourn at 5:45 o'clock in the forenoon. A true record. Attest: Acting Secretary 17 National Grid Letterhead The National Grid Group plc IOSTA, Inc. NGG Holdings LLC Secretary's Certificate The undersigned, Acting Secretary of The National Grid Group plc, IOSTA, Inc., and NGG Holdings LLC, DO HEREBY CERTIFY on behalf of The National Grid Group plc, IOSTA, Inc., and NGG Holdings LLC THAT: Attached hereto as Exhibit A is a true and correct copy of Resolutions duly adopted by the Boards of The National Grid Group plc, IOSTA, Inc., and NGG Holdings LLC, which Resolutions have not been revoked, modified, amended, or rescinded and remain in full force and effect on the date hereof, except as indicated therein. IN WITNESS WHEREOF, the undersigned has executed and delivered this certificate this 28th day of April, 1999. THE NATIONAL GRID GROUP plc IOSTA, INC. NGG HOLDINGS PLC By: /s/ CLARE M. PHELAN ----------------------------------- Clare M. Phelan Acting Secretary Signed and sworn to before me this 28th day of April, 1999. /s/ SANDRA J. BROCHER - ----------------------------------- Notary Public My commission expires: 8/19/2005 ------------- 18 NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Directors' Authorization Resolutions Resolved at The National Grid Group plc Committee of the Board of Directors Meeting on January 29, 1999 RESOLVED: Each of the Directors present confirmed that he had sufficiently and carefully considered the terms of the Consent Agreement and, accordingly, IT WAS RESOLVED that the Chairman or any one Executive Director or Fiona Smith be and is hereby authorised to agree any further amendments to and to execute and deliver on behalf of the Company the Consent Agreement. 19 NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Managers' Authorization Resolutions Resolved at IOSTA, Inc. Meeting of the Managers on January 29, 1999 RESOLVED: It was noted that the Acquisition would be entered into by NEES as soon as reasonably practicable after the date hereof AND IT WAS ACCORDINGLY RESOLVED that subject to being satisfied as to valuation and price, The National Grid Group plc be and is hereby authorised to give consent to NEES to the entering into of the Acquisition by way of entering into a Consent Agreement with NEES. 20 NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Directors' Authorization Resolutions Resolved at NGG Holdings LLC Meeting of the Managers on January 29, 1999 RESOLVED: It was noted that the Acquisition would be entered into by NEES as soon as reasonably practicable after the date hereof AND IT WAS ACCORDINGLY RESOLVED that subject to being satisfied as to valuation and price, The National Grid Group plc be and is hereby authorised to give consent to NEES to the entering into of the Acquisition by way of entering into a Consent Agreement with NEES. 21 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) THE NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-70-000 NEW ENGLAND HYDRO-TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO-TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY, L.L.C. ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) JOINT APPLICATION OF NEW ENGLAND POWER COMPANY, et al. AND MONTAUP ELECTRIC COMPANY, et al. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBITS Edward Berlin, Esq. David A. Fazzone, Esq. of Kenneth G. Jaffe, Esq. David A. Fazzone, P.C., and Scott P. Klurfeld, Esq. McDermott, Will & Emery Swidler Berlin Shereff Friedman, LLP 28 State Street 3000 K Street, N.W., Suite 300 Boston, Massachusetts 02109-4000 Washington, D.C. 20007-5116 (617) 535-4016 (202) 424-7500 Attorneys for Montaup Electric Company and Affiliated Applicants Thomas G. Robinson, Esq. New England Power Company 25 Research Drive Westborough, MA 01582 (508) 389-2877 Attorneys for New England Power Company and Affiliated Applicants May, 1999 NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Directors' Authorization Resolutions NEW ENGLAND ELECTRIC SYSTEM Secretary's Certificate The undersigned, the Secretary of New England Electric System, a voluntary association created under the laws of The Commonwealth of Massachusetts, DOES HEREBY CERTIFY, on behalf of the Association, that: Attached hereto as Exhibit A is a true and correct copy of votes duly adopted by The Board of Directors of the Association, and registered with the Trustee, which Votes have not been revoked, modified, amended, or rescinded and remain in full force and effect on the date hereof, except as indicated therein. IN WITNESS WHEREOF, the undersigned has executed and delivered this certificate this 27th day of April, 1999. NEW ENGLAND ELECTRIC SYSTEM By: /s/ Cheryl A. LaFleur ----------------------------------- Cheryl A. LaFleur Secretary Signed and sworn to before me this 27th day of April, 1999. /s/ Sandra J. Brochu - ----------------------------------- Notary Public My commission expires: 8/19/2005 NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Directors' Authorization Resolutions Votes Adopted at New England Electric System Board of Directors on January 30, 1999 VOTED: That Richard P. Sergel, President and Chief Executive Officer, and Michael E. Jesanis, Senior Vice President and Chief Financial Officer, are severally authorized to execute and deliver, in the name and on behalf of the Company, The Agreement and Plan of Merger, by and among Eastern Utilities Associates, a Merger Acquisition Subsidiary LLC of the Company, and the Company (the Merger Agreement) specifying the terms and conditions for the acquisition for cash of all the outstanding common shares of Eastern Utilities Associates at a price of $31.00 per share for an aggregate purchase price of up to $650 million, subject to adjustments as specified in the Merger Agreement; said Merger Agreement to be substantially in the form presented to this meeting, with such changes, additions, and modifications thereto as the officer or officers executing the same shall approve, such approval to be evidenced by the execution and delivery thereof. That the officers of the Company are severally authorized, in the name and on behalf of the Company, to form a Merger Acquisition Subsidiary LLC as a Massachusetts limited liability company with the Company having a ninety-nine percent interest therein as a member (NEES Global, Inc. having a one percent interest); said Merger Acquisition Subsidiary LLC being formed to execute and deliver the Merger Agreement; and all acts done and taken in pursuance thereof are authorized, approved, adopted, ratified, and confirmed. -2- That the officers of the Company are severally authorized to execute and deliver, in the name and on behalf of the Company, the Consent Agreement between National Grid Group plc. and the Company, containing the consent of National Grid Group plc to the Company's execution and delivery of the Merger Agreement and with respect to certain actions relating to the consummation of the transactions set forth therein; said Consent Agreement to be substantially in the form presented to this meeting, with such changes, additions, and modifications thereto as the officer or officers executing the same shall approve, such approval to be evidenced by the execution and delivery thereof. EASTERN UTILITIES ASSOCIATES Secretary's Certificate The undersigned, the Secretary of Eastern Utilities Associates, a voluntary association created under the laws of The Commonwealth of Massachusetts (the "Association"), DOES HEREBY CERTIFY, on behalf of the Association, that: Attached hereto as Exhibit A is a true and correct copy of votes duly adopted by The Board of Trustees of the Association, which Votes have not been revoked, modified, amended, or rescinded and remain in full force and effect on the date hereof, except as indicated therein. IN WITNESS WHEREOF, the undersigned has executed and delivered this certificate this 27th day of April, 1999. EASTERN UTILITIES ASSOCIATES By: /s/ Clifford J. Hebert, Jr. ----------------------------------- Clifford J. Hebert, Jr. Secretary Signed and sworn to before me this 27th day of April, 1999. /s/ Rose Mary Abrams - ----------------------------------- Notary Public My commission expires: May 6, 2005 NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Directors' Authorization Resolutions Votes Adopted by Eastern Utilities Associates Board of Trustees on February 1, 1999 Attached SPECIAL MEETING OF TRUSTEES, FEBRUARY 1, 1999 Pursuant to the action taken at the January 31, 1999 Special Meeting of the Trustees, a Special Meeting of the Trustees of Eastern Utilities Associates was held at the office of the Association, One Liberty Square, Boston, Massachusetts, on Monday, February 1, 1999 at 5:30 o'clock in the forenoon. There were present - Russell A. Boss (via conference telephone), Paul J. Choquette, Jr. (via conference telephone), Peter S. Damon (via conference telephone), Peter B. Freeman (via conference telephone), Larry A. Liebenow (via conference telephone), Jacek Makowski (via conference telephone), Wesley W. Marple, Jr. (via conference telephone), Donald G. Pardus, Margaret M. Stapleton (via conference telephone), John R. Stevens and W. Nicholas Thorndike (via conference telephone), being all of the Trustees. Clifford J. Hebert, Jr., Treasurer and Secretary of the Association, Henry A. Clark II (via conference telephone) and Robert N. Hoglund (via conference telephone), Managing Directors, of Salomon Smith Barney, Inc. ("Salomon"); David P. Falck (via conference telephone) of Winthrop, Stimson, Putnam & Roberts; and Arthur I. Anderson and David A. Fazzone (via conference telephone) of McDermott, Will & Emery, Counsel for the Association, were also present at the meeting. Donald G. Pardus, Chairman, presided. Arthur I. Anderson, Acting Secretary, kept the records of the meeting. Mr. Pardus asked if there were any additional questions regarding the proposed transaction with New England Electric System ("NEES"). A general discussion then ensued with respect to several questions which were raised by Trustees after review of the draft Merger Agreement. The representatives of Salomon indicated that they were prepared to deliver their fairness opinion in connection with the NEES transaction as contemplated by the Merger Agreement. On motion duly made and seconded, the following votes were unanimously adopted: VOTED - that the form, terms and provisions of, and the transactions contemplated by, that certain Agreement and Plan of Merger (the "Agreement") by and among New England Electric System ("NEES"), Research Drive LLC ("LLC") and the Association in the form presented to the Trustees, pursuant to which LLC will be merged (the "Merger") into this Association and each Common Share of this Association will be converted into and exchanged for $31 in cash, subject to adjustment, be and it hereby is approved; and that the Chairman of the Board, Donald G. Pardus, be, and he hereby is, acting singly, authorized and directed to execute the Agreement and an acknowledgment of the Consent Agreement between NEES and National Group PLC pertaining to the Merger on behalf of the Association, with such changes, modifications and deletions as he so deems necessary, the execution and delivery thereof to be conclusive evidence of his authority so to act. VOTED - that, in accordance with the terms and conditions of the Agreement and the transactions contemplated thereby, the Chairman of the Board, the Vice Chairman of the Board, the President, any vice President, the Treasurer, the Assistant Treasurer, the Secretary or any Assistant Secretary (collectively, the "Authorized Officers") of the Association be, and each of them hereby is, acting singly, authorized and directed to execute and file on behalf of the Association, all necessary regulatory filings as may be required including, but not limited to, filings with the Department of Justice, the 2 Federal Trade Commission, the Federal Communications Commission, the Nuclear Regulatory Commission, the Federal Energy Regulatory Commission, the Securities and Exchange Commission (the "SEC") and any of the following states: Massachusetts, New Hampshire, Maine, Connecticut, Vermont and Rhode Island, the filing by such Authorized Officer or Authorized Officers to be conclusive evidence of his or their authority so to act. VOTED - that the Association cause a proxy statement (the "Proxy Statement") to be prepared, in accordance with the requirements of the SEC, setting forth the necessary information concerning the transactions contemplated by the Agreement to obtain the required shareholder authorization for the consummation of the transactions contemplated by the Agreement (including, without limitation, any required authorizations pursuant to Article 37 of this Association's Declaration of Trust, as amended) and that the Authorized Officers be, and each of them hereby is, acting singly, authorized and directed, to file the Proxy Statement with the SEC, with such provisions therein as the Authorized Officer or Authorized Officers filing the Proxy Statement may deem necessary or desirable, the filing by such Authorized Officer or Authorized Officers to be conclusive evidence of his or their authority so to act. VOTED - that the Trustees hereby declare that the Merger is advisable and in the best interests of the Association and recommend to shareholders that they approve the Merger. VOTED - that the Authorized Officers of this Association be, and each of them acting singly hereby is, authorized and empowered to do or cause to be done all such acts or things and to sign and deliver, or cause to be signed and delivered, all such documents, instruments and certificates (including, without limitation, obtaining all required shareholder authorizations under Article 37 3 of this Association's Declaration of Trust, as amended) as such officer of this Association may deem necessary advisable or appropriate to effectuate or carry out the purposes and intent of the foregoing votes and to perform the obligations of this Association under the agreements and instruments referred to therein. There being no further business to discuss, on motion duly made and seconded, it was VOTED - to adjourn at 5:45 o'clock in the forenoon. A true record. Attest: Acting Secretary 4 The National Grid Group plc IOSTA, Inc. NGG Holdings LLC Secretary's Certificate The undersigned, Acting Secretary of The National Grid Group plc, IOSTA, Inc., and NGG Holdings LLC, DO HEREBY CERTIFY on behalf of The National Grid Group plc, IOSTA, Inc., and NGG Holginds LLC that: Attached hereto as Exhibit A is a true and correct copy of Resolutions duly adopted by the Boards of The National Grid Group plc, IOSTA, Inc., and NGG Holdings LLC, which Resolutions have not been revoked, modified, amended, or rescinded and remain in full force and effect on the date hereof, except as indicated therein. IN WITNESS WHEREOF, the undersigned has executed and delivered this certificate this 28th day of April, 1999. THE NATIONAL GRID GROUP plc IOSTA, INC. NGG HOLDINGS PLC By: /s/ Clare M. Phelan ----------------------------------- Clare M. Phelan Acting Secretary Signed and sworn to before me this 28th day of April, 1999. /s/ Sandra J. Brochu - ----------------------------------- Notary Public My commission expires: 8/19/2005 NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Directors' Authorization Resolutions Resolved at The National Grid Group plc Committee of the Board of Directors Meeting on January 29, 1999 RESOLVED: Each of the Directors present confirmed that he had sufficiently and carefully considered the terms of the consent Agreement and, accordingly, IT WAS RESOLVED that the Chairman or any one Executive Director or Fiona Smith be and is hereby authorised to agree any further amendments to and to execute and deliver on behalf of the Company the Consent Agreement. NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Managers' Authorization Resolutions Resolved at IOSTA, Inc. Meeting of the Managers on January 29, 1999 RESOLVED: It was noted that the Acquisition would be entered into by NEES as soon as reasonably practicable after the date hereof AND IT WAS ACCORDINGLY RESOLVED that subject to being satisfied as to valuation and price, The National Grid Group plc be and is hereby authorised to give consent to NEES to the entering into of the Acquisition by way of entering into a Consent Agreement with NEES. NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT A Board of Managers' Authorization Resolutions Resolved at NGG Holdings LLC Meeting of the Managers on January 29, 1999 RESOLVED: It was noted that the Acquisition would be entered into by NEES as soon as reasonably practicable after the date hereof AND IT WAS ACCORDINGLY RESOLVED that subject to being satisfied as to valuation and price, The National Grid Group plc be and is hereby authorised to give consent to NEES to the entering into of the Acquisition by way of entering into a Consent Agreement with NEES. NEW ENGLAND POWER COMPANY MASSACHUSETTS ELECTRIC COMPANY THE NARRAGANSETT ELECTRIC COMPANY NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION CORPORATION NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. ALLENERGY MARKETING COMPANY, L.L.C. MONTAUP ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY NEWPORT ELECTRIC CORPORATION RESEARCH DRIVE LLC FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT B Statement of Control of Ownership Exhibit B Page 1 of 12 New England Power Company No ownership or control is exercised by or over New England Power Company as to any bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. The NEES Companies parent, however, does have certain directors who are directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. In any event, a minority of directors who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Exhibit B Page 2 of 12 Massachusetts Electric Company No ownership or control is exercised by or over Massachusetts Electric Company as to any bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. The NEES Companies parent, however, does have certain directors who are directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. In any event, a minority of directors who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Exhibit B Page 3 of 12 The Narragansett Electric Company No ownership or control is exercised by or over The Narragansett Electric Company as to any bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. The NEES Companies parent, however, does have certain directors who are directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. In any event, a minority of directors who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Exhibit B Page 4 of 12 New England Electric Transmission Corporation No ownership or control is exercised by or over New England Electric Transmission Corporation as to any bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. The NEES Companies parent, however, does have certain directors who are directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. In any event, a minority of directors who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Exhibit B Page 5 of 12 New England Hydro-Transmission Corporation No ownership or control is exercised by or over New England Hydro-Transmission Corporation as to any bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. The NEES Companies parent, however, does have certain directors who are directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. In any event, a minority of directors who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Exhibit B Page 6 of 12 New England Hydro-Transmission Electric Company, Inc. No ownership or control is exercised by or over New England Hydro-Transmission Electric Company, Inc. as to any bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. The NEES Companies parent, however, does have certain directors who are directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. In any event, a minority of directors who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Exhibit B Page 7 of 12 AllEnergy Marketing Company, L.L.C. No ownership or control is exercised by or over AllEnergy Marketing Company, L.L.C. as to any bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. The NEES Companies parent, however, does have certain directors who are directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. In any event, a minority of directors who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Exhibit B Page 8 of 12 Montaup Electric Company Montaup Electric Company is a wholly owned subsidiary of Eastern Edison Company, which is a public utility company and an indirect subsidiary of Eastern Utilities Associates ("EUA"), a public utility holding company. No ownership or control is exercised by or over Montaup Electric Company as to any bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. Certain of the EUA trustees, representing a minority of the EUA Board of Trustees, also serve as directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. A minority of trustees who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Montaup Electric Company has officers and directors in common with Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation and EUA. Exhibit B Page 9 of 12 Blackstone Valley Electric Company Blackstone Valley Electric Company is a wholly owned subsidiary of EUA, a public utility holding company. No ownership or control is exercised by or over Blackstone Valley Electric Company as to any public utility or bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. Certain of the EUA trustees, representing a minority of the EUA Board of Trustees, also serve as directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. A minority of trustees who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Blackstone Valley Electric Company has officers and directors in common with Montaup Electric Company, Eastern Edison Company, Newport Electric Corporation and EUA. Exhibit B Page 10 of 12 Eastern Edison Company Eastern Edison Company is a wholly owned subsidiary of EUA, a public utility holding company. Eastern Edison Company owns all of the issued and outstanding common stock of Montaup Electric Company, a public utility company. No ownership or control is exercised by or over Eastern Edison Company as to any bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. Certain of the EUA trustees, representing a minority of the EUA Board of Trustees, also serve as directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. A minority of trustees who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Eastern Edison Company has officers and directors in common with Blackstone Valley Electric Company, Montaup Electric Company, Newport Electric Corporation and EUA. Exhibit B Page 11 of 12 Newport Electric Corporation Newport Electric Corporation is a wholly owned subsidiary of EUA, a public utility holding company. No ownership or control is exercised by or over Newport Electric Corporation as to any public utility or bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. Certain of the EUA trustees, representing a minority of the EUA Board of Trustees, also serve as directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. A minority of trustees who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. Newport Electric Corporation has officers and directors in common with Montaup Electric Company, Eastern Edison Company, Blackstone Valley Electric Company and EUA. Exhibit B Page 12 of 12 Research Drive LLC No ownership or control is exercised by or over Research Drive LLC as to any bank, trust company, banking association, or firm that is authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to such companies. The NEES Companies parent, however, does have certain directors who are directors of commercial banks or of companies which have subsidiaries authorized to underwrite or participate in the marketing of securities. In any event, a minority of directors who also serve on boards of commercial banks or companies who have subsidiaries authorized to underwrite securities are not likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B. JOINT APPLICATION OF NEW ENGLAND POWER COMPANY, ET AL. AND MONTAUP ELECTRIC COMPANY, ET AL. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT C-1 New England Power Company EXHIBIT C-2 Massachusetts Electric Company EXHIBIT C-3 The Narragansett Electric Company EXHIBIT C-4 New England Electric Transmission Corporation EXHIBIT C-5 New England Hydro Transmission Corporation EXHIBIT C-6 New England Hydro-Transmission Electric Company, Inc. EXHIBIT C-7 Montaup Electric Company EXHIBIT C-8 Blackstone Valley Electric Company EXHIBIT C-9 Eastern Edison Company EXHIBIT C-10 Newport Electric Corporation ACTUAL AND PRO FORMA BALANCE SHEETS AND PLANT SCHEDULES SEPTEMBER 30, 1998
NEES Companies Exhibit No. C-1 Page 1 of 5 Name of Respondent New England Power Company At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 1,510,284,010 1,510,284,010 3 Construction Work in Progress (107) 28,179,703 28,179,703 4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 1,538,463,713 1,538,463,713 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 1,100,830,086 1,100,830,086 6 Net Utility Plant (Enter total of line 4 less 5) 437,633,627 437,633,627 7 Nuclear fuel (120.1-120.4, 120.6) 72,825,922 72,825,922 8 (Less) Accum. Prov. for Amort. of Nucl. 59,232,721 59,232,721 Assemblies (120.5) 9 Net Nuclear Fuel (Enter Total of line 7 Less 8) 13,593,201 13,593,201 10 Net Utility Plant (Enter Total of lines 6 and 9) 451,226,828 451,226,828 11 Utility Plant Adjustments (116) 12 Gas Stored Underground-Noncurrent (117) 13 OTHER PROPERTY AND INVESTMENTS 14 Nonutility Property (121) 6,345,708 6,345,708 15 (Less) Accum. Prov. for Depr. and Amort. (122) 10,287 10,287 16 Investments in Associated Companies (123) 48,202,681 48,202,681 17 Investment in Subsidiary Companies (123.1) 18 (For Cost of Account 123.1, See Footnote Page 224, Line 42) 19 Noncurrent Portion of Allowances 20 Other Investments (124) 233,566 233,566 21 Special Funds (125-128) 27,740,101 27,740,101 22 TOTAL Other Property and Investments (Total of 82,511,769 82,511,769 lines 14-17, 19-21) 23 CURRENT AND ACCRUED ASSETS 24 Cash (131) 74,602 74,602 25 Special Deposits (132-134) 2,001,662 2,001,662 26 Working Fund (135) 46,030 46,030 27 Temporary Cash Investments (136) 28 Notes Receivable (141) 29 Customer Accounts Receivable (142) 20,362,387 20,362,387 30 Other Accounts Receivable (143) 13,345,437 13,345,437 31 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 32 Notes Receivable from Associated Companies (145) 147,200,000 147,200,000 33 Accounts Receivable from Assoc. Companies (146) 149,982,908 149,982,908 34 Fuel Stock (151) 510,793 510,793 35 Fuel Stock Expenses Undistributed (152) 36 Residuals (Elec) and Extracted Products (153) 37 Plant Materials and Operating Supplies (154) 9,177,832 9,177,832 38 Merchandise (155) 39 Other Materials and Supplies (156) 40 Nuclear Materials Held for Sale (157) 41 Allowances (158.1 and 158.2) 42 (Less) Noncurrent Portion of Allowances 43 Stores Expense Undistributed (163) 44 Gas Stored Underground-Current (164.1) 45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 46 Prepayments (165) 3,477,340 3,477,340 47 Advances for Gas (166-167) 48 Interest and Dividends Receivable (171) 2,755,846 2,755,846 49 Rents Receivable (172) 50 Accrued Utility Revenues (173) 51 Miscellaneous Current and Accrued Assets (174) 25,201 25,201 NEES Companies Exhibit No. C-1 Page 2 of 5 Name of Respondent New England Power Company At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 52 TOTAL Current and Accrued Assets (Enter Total of lines 24 thru 51) 348,960,038 348,960,038 53 DEFERRED DEBITS 54 Unamortized Debt Expenses (181) 3,039,869 3,039,869 55 Extraordinary Property Losses (182.1) 56 Unrecovered Plant and Regulatory Study Costs (182.2) 57 Other Regulatory Assets (182.3) 1,576,719,353 1,576,719,353 58 Prelim. Survey and Investigation Charges 132,814 132,814 (Electric) (183) 59 Prelim. Sur. And Invest. Charges (Gas) (183.1, 183.2) 60 Clearing Accounts (184) 182,213 182,213 61 Temporary Facilities (185) 62 Miscellaneous Deferred Debits (186) 35,068,645 35,068,645 63 Def. Losses from Disposition of Utility Plt. (187) 64 Research, Devel. and Demonstration Expend. (188) 65 Unamortized Loss on Reacquired Debt (189) 66 Accumulated Deferred Income Taxes (190) 127,606,257 127,606,257 67 Unrecovered Purchased Gas Costs (191) 68 TOTAL Deferred Debits 1,742,749,151 1,742,749,151 (Enter Total of Lines 54 thru 67) 69 TOTAL Assets and other Debits (Enter Total of 2,625,447,786 2,625,447,786 lines 10, 11, 12, 22, 52 and 68) NEES Companies Exhibit No. C-1 Page 3 of 5 Name of Respondent New England Power Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS ) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 1 PROPRIETARY CAPITAL 2 Common Stock Issued (201) 74,997,920 74,997,920 3 Preferred Stock Issued (204) 10,574,500 10,574,500 4 Capital Stock Subscribed (202, 205) 5 Stock Liability for Conversion (203, 206) 6 Premium on Capital Stock (207) 50,395,347 50,395,347 7 Other Paid-in Capital (208-211) 190,721,846 190,721,846 8 Installments Received on Capital Stock (212) 9 (Less) Discount on Capital Stock (213) 10 (Less) Capital Stock Expense (214) 11 Retained Earnings (215, 215.1, 216) 172,101,567 172,101,567 12 Unappropriated Undistributed Subsidiary Earnings 14,252,922 14,252,922 (216.1) 13 (Less) Reacquired Capital Stock (217) 14 TOTAL Proprietary Capital (Enter Total of Lines 2 thru 13) 513,044,102 513,044,102 15 LONG-TERM DEBT 16 Bonds (221) 371,850,000 371,850,000 17 (Less) Reacquired Bonds (222) 18 Advances from Associated Companies (223) 19 Other Long-Term Debt (224) 20 Unamortized Premium on Long-Term Debt (225) 21 (Less) Unamortized Discount on Long-Term 86,585 86,585 Debt-Debit (226) 22 TOTAL Long-Term Debt (Enter Total of Lines 16 371,763,415 371,763,415 thru 21) 23 OTHER NONCURRENT LIABILITIES 24 Obligations Under Capital Leases-Noncurrent (227) 25 Accumulated Provision for Property Insurance (228.1) 26 Accumulated Provision for Injuries and Damages (228.2) 27 Accumulated Provision for Pensions and Benefits (228.3) 28 Accumulated Miscellaneous Operating Provisions 1,916,764 1,916,764 (228.4) 29 Accumulated Provision for Rate Refunds (229) 30 TOTAL OTHER Noncurrent Liabilities (Enter Total 1,916,764 1,916,764 of lines 24 thru 29) 31 CURRENT AND ACCRUED LIABILITIES 32 Notes Payable (231) 33 Accounts Payable (232) 68,409,221 68,409,221 34 Notes Payable to Associated Companies (233) 35 Accounts Payable to Associated Companies (234) 11,542,824 11,542,824 36 Customer Deposits (235) 37 Taxes Accrued (236) 24,674,915 24,674,915 38 Interest Accrued (237) 266,558 266,558 39 Dividends Declared (238) 141,340 141,340 40 Matured Long-Term Debt (239) 41 Matured Interests (240) 42 Tax Collections Payable (241) 27,396 27,396 43 Miscellaneous Current and Accrued Liabilities 134,184,483 134,184,483 (242) 44 Obligations Under Capital Leases - Current (243) 45 TOTAL Current and Accrued Liabilities (Enter 239,246,737 239,246,737 Total of lines 32 thru 44) NEES Companies Exhibit No. C-1 Page 4 of 5 Name of Respondent New England Power Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS ) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 46 DEFERRED CREDITS 47 Customer Advances for Construction (252) 48 Accumulated Deferred Investment Tax Credits (255) 30,648,837 30,648,837 49 Deferred Gains from Disposition of Utility Plant (256) 50 Other Deferred Credits (253) 1,134,673,476 1,134,673,476 51 Other Regulatory Liabilities (254) 36,341,946 36,341,946 52 Unamortized Gain on Reacquired Debt (257) 53 Accumulated Deferred Income Taxes (281-283) 297,812,509 297,812,509 54 TOTAL Deferred Credits (Enter Total of Lines 47 1,499,476,768 1,499,476,768 thru 53) 55 56 57 58 59 60 61 62 63 64 65 66 67 68 Total Liabilities and Other Credits (Enter Total of Lines 14, 22, 30, 45 and 54) 2,625,447,786 2,625,447,786 SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND DEPLETION Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 1,393,566,319 1,393,566,319 4 Property Under Capital Leases 5 Plant Purchased or Sold 6 Completed Construction not Classified 108,238,451 108,238,451 7 Experimental Plant Unclassified 8 Total (Enter Total of lines 3 thru 7) 1,501,804,770 1,501,804,770 9 Leased to Others 10 Held for Future Use 8,479,240 8,479,240 11 Construction Work in Progress 28,179,703 28,179,703 12 Acquisition Adjustments 13 Total Utility Plant (Enter total of lines 8 thru 12) 1,538,463,713 1,538,463,713 14 Accum. Prov. for Depr., Amort., and Depl. 1,100,830,086 1,100,830,086 15 Net Utility Plant (Enter Total of line 13 less 14) 437,633,627 437,633,627 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In service: 18 Depreciation 762,764,185 762,764,185 18 Amort. and Depl. of Producing Natural Gas & Land Rights 20 Amort. of Underground Storage Land and Land Rights 21 Amort. of Other Utility Plant 338,065,901 338,065,901 22 TOTAL In Service (Enter Total of lines 18 thru 21) 1,100,830,086 1,100,830,086 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Enter Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (Enter Total of lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amort. of Plant Acquisition Adj. 33 Total Accumulated Provisions (Should agree with line 14 above) 1,100,830,086 1,100,830,086 (Enter Total of lines 22, 26, 30, 31 and 32)
NEES Companies Exhibit No. C-2 Page 1 of 5 Name of Respondent Massachusetts Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 52 TOTAL Current and Accrued Assets (Enter Total of 348,960,038 348,960,038 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 1,603,921,360 1,603,921,360 3 Construction Work in Progress (107) 18,932,439 18,932,439 4 TOTAL UTILITY PLANT (Enter total of lines 2 1,622,853,799 1,622,853,799 and 3) 5 (Less) Accum. Prov. for Depr. Amort. Depl. 487,714,629 487,714,629 (108, 111, 115) 6 Net Utility Plant (enter total of line 4 Less 1,135,139,170 1,135,139,170 5) 7 Nuclear Fuel (120.1-120.4, 120.6) 8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies (120.5) 9 Net Nuclear Fuel (Enter Total of line 7 Less 8) 10 Net Utility Plant (Enter Total of lines 6 and 1,135,139,170 1,135,139,170 9) 11 Utility Plant Adjustments (116) 12 Gas Stored Underground-Noncurrent (117) 13 OTHER PROPERTY AND INVESTMENTS 14 Nonutility Property (121) 12,719,532 12,719,532 15 (Less) Accum. Prov. for Depr. and Amort. (122) 856,183 856,183 16 Investments in Associated Companies (123) 17 Investment in Subsidiary Companies (123.1) 18 (For Cost of Account 123.1, See Footnote Page 224, Line 42) 19 Noncurrent Portion of Allowance 20 Other Investments (124) 360,594 360,594 21 Special funds (125-128) 1,974,098 1,974,098 22 TOTAL Other Property and Investments (Total 14,198,041 14,198,041 of lines 14-17, 19-21) 23 CURRENT AND ACCRUED ASSETS 24 Cash (131) 7,157,257 7,157,257 25 Special Deposits (132-134) 1,149,887 1,149,887 26 Working Fund (135) 107,738 107,738 27 Temporary Cash Investments (136) 28 Notes Receivable (141) 29 Customer Accounts Receivable (142) 174,776,613 174,776,613 30 Other Accounts Receivable (143) 546,204 546,204 31 (Less) Accum. Prov. for Uncollectible 14,889,674 14,889,674 Acct-Credit (144) 32 Notes Receivable from Associated Companies (145) 33 Accounts Receivable from Assoc. Companies 33,795,614 33,795,614 (146) 34 Fuel Stock (151) 35 Fuel Stock Expenses Undistributed (152) 36 Residuals (Elec) and Extracted Products (153) 37 Plant Materials and Operating Supplies (154) 9,274,158 9,274,158 38 Merchandise (155) 39 Other Materials and Supplies (156) 40 Nuclear Materials Held for Sale (157) 41 Allowances (158.1 and 158.2) 42 (Less) Noncurrent Portion of Allowances 43 Stores Expense Undistributed (163) 44 Gas Stored Underground-Current (164.1) 45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 46 Prepayments (165) 13,947,353 13,947,353 47 Advances for Gas (166-167) 48 Interest and Dividends Receivable (171) 49 Rents Receivable (172) 50 Accrued Utility Revenues (173) 52,702,000 52,702,000 51 Miscellaneous Current and Accrued Assets (174) 821,036 821,036 NEES Companies Exhibit No. C-2 Page 2 of 5 Name of Respondent Massachusetts Electric Company At September 30, 1998 Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) 52 TOTAL Current and Accrued Assets (Enter Total 279,388,186 279,388,186 of lines 24 thru 51) 53 DEFERRED DEBITS 54 Unamortized Debt Expenses (181) 613,887 613,887 55 Extraordinary Property Losses (182.1) 56 Unrecovered Plant and Regulatory Study Costs (182.2) 57 Other Regulatory Assets (182.3) 32,633,218 32,633,218 58 Prelim. Survey and Investigation Charges 78,698 78,698 (Electric) (183) 59 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2) 60 Clearing Accounts (184) (148,654) (148,654) 61 Temporary Facilities (185) 62 Miscellaneous Deferred Debits (186) 6,942,267 6,942,267 63 Def. Losses from Disposition of Utility Plt. (187) 64 Research, Devel. and Demonstration Expend. (188) 65 Unamortized Loss on Reacquired Debt (189) 66 Accumulated Deferred Income Taxes (190) 60,657,945 60,657,945 67 Unrecovered Purchased Gas Costs (191) 68 TOTAL Deferred Debits (Enter Total of lines 100,777,361 100,777,361 54 thru 67) 69 TOTAL Assets and Other Debits (Enter Total of 1,529,502,758 1,529,502,758 lines 10, 11, 12, 22, 52, and 68) NEES Companies Exhibit No. C-2 Page 3 of 5 Name of Respondent Massachusetts Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 52 TOTAL Current and Accrued Assets (Enter Total of 348,960,038 348,960,038 1 PROPRIETARY CAPITAL 2 Common Stock issued (201) 59,952,775 59,952,775 3 Preferred Stock issued (204) 15,738,525 15,738,525 4 Capital Stock Subscribed (202, 205) 5 Stock Liability for Conversion (203, 206) 6 Premium on Capital Stock (207) 45,945,427 45,945,427 7 Other Paid-in Capital (208-211) 193,498,180 192,498,180 8 Installments Received on Capital Stock (212) 9 (Less) Discount on Capital Stock (213) 10 (Less) Capital Stock Expense (214) 11 Retained Earnings (215, 215.1, 216) 196,579,054 196,579,054 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 13 (Less) Reacquired Capital Stock (217) 14 TOTAL Proprietary Capital (Enter Total of Lines 2 thru 13) 511,713,961 511,713,961 15 LONG-TERM DEBT 16 Bonds (221) 17 (Less) Reacquired bonds (222) 18 Advances from Associated Companies (223) 19 Other Long-Term Debt (224) 355,000,000 355,000,000 20 Unamortized Premium on Long-Term Debt (225) 21 (Less) Unamortized Discount on Long-term 1,561,996 1,561,996 Debt-Debit (226) 22 TOTAL Long-Term Debt 353,438,004 353,438,004 (Enter Total of Lines 16 thru 21) 23 OTHER NONCURRENT LIABILITIES 24 Obligations Under Capital Leases-Noncurrent (227) 651,829 651,829 25 Accumulated Provision for Property Insurance (228.1) 26 Accumulated Provision for Injuries and Damages (228.2) 27 Accumulated provision for Pensions and Benefits (228.3) 28 Accumulated Miscellaneous Operating Provisions (228.4) 29 Accumulated Provision for Rate Refunds (229) 30 TOTAL OTHER Noncurrent Liabilities 651,829 651,829 (enter Total of lines 24 thru 29) 31 CURRENT AND ACCRUED LIABILITIES 32 Notes Payable (231) 33 Accounts Payable (232) 83,868,192 83,868,192 34 Notes Payable to Associated Companies (233) 52,950,000 52,950,000 35 Accounts Payable to Associated Companies (234) 112,820,067 112,820,067 36 Customer Deposits (235) 4,639,484 4,639,484 37 Taxes Accrued (236) 1,893,091 1,893,091 38 Interest Accrued (237) 7,774,998 7,774,998 39 Dividends Declared (238) 240,149 240,149 40 Matured Long-Term Debt (239) 41 Matured Interests (240) 42 Tax Collections Payable (241) 504,125 504,125 43 Miscellaneous Current and Accrued Liabilities (242) 64,739,809 64,739,809 44 Obligations Under Capital leases - Current (243) 192,534 192,534 45 TOTAL Current and Accrued Liabilities 329,622,449 329,622,449 (Enter Total of lines 32 thru 44) NEES Companies Exhibit No. C-2 Page 4 of 5 Name of Respondent Massachusetts Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 46 DEFERRED CREDITS 47 Customer Advances for Construction (252) 292,673 292,673 48 Accumulated Deferred Investment Tax Credits (255) 14,648,573 14,648,573 49 Deferred Gains from Disposition of Utility Plant (256) 50 Other Deferred Credits (253) 53,264,732 53,264,732 51 Other Regulatory Liabilities (254) 20,212,371 20,212,371 52 Unamortized Gain on Reacquired Debt (257) 53 Accumulated Deferred Income Taxes (281-283) 245,658,166 245,658,166 54 TOTAL Deferred Credits (Enter Total of Lines 47 thru 53) 334,076,515 334,076,515 55 56 57 58 59 60 61 62 63 64 65 66 67 68 Total Liabilities and Other credits (Enter Total of Lines 14, 22, 30, 45 and 54) 1,529,502,758 1,529,502,758 NEES Companies Exhibit No. C-2 Page 5 of 5 Name of Respondent Massachusetts Electric Company At September 30, 1998 SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND DEPLETION At September 30, 1998 Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 1,413,389,021 1,413,389,021 4 Property Under Capital Leases 844,364 844,364 5 Plant Purchased or Sold 6 Completed Construction not Classified 188,904,329 188,904,329 7 Experimental Plant Unclassified 8 Total (Enter Total of lines 3 thru 7) 1,603,137,714 1,603,137,714 9 Leased to Others 10 Held for Future Use 783,646 783,646 11 Construction Work in Progress 18,932,439 18,932,439 12 Acquisition Adjustments 13 Total Utility Plant (Enter total of lines 8 thru 12) 1,622,853,799 1,622,853,799 14 Accum. Prov. for Depr. Amort. And Depl. 487,714,629 487,714,629 15 Net Utility Plant (Enter Total of line 13 less 14) 1,135,139,170 1,135,139,170 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In Service: 18 Depreciation 487,714,629 487,714,629 19 Amort. and Depl. Of Producing Natural Gas & Land Rights 20 Amort. of Underground Storage Land and Land Rights 21 Amort. of Other Utility Plant 22 TOTAL in Service (Enter Total of lines 18 thru 21) 487,714,629 487,714,629 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Enter Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (Enter Total of Lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amort. of Plant Acquisition Adj. 33 Total Accumulated Provisions (Should agree with line 14 above) (Enter Total of lines 22, 26, 30, 31 and 32) 487,714,629 487,714,629
NEES Companies Exhibit No. C-3 Page 1 of 5 Name of Respondent Narragansett Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 726,338,509 726,338,509 3 Construction Work in Progress (107) 2,717,852 2,717,852 4 TOTAL UTILITY PLANT (Enter Tota of lines 2 and 3) 729,056,361 729,056,361 5 (Less) Accum. Prov. for Depr. Amort. Depl. 203,908,243 203,908,243 (108, 111, 115) 6 Net Utility Plant (Enter Total of line 4 Less 5) 525,148,118 525,148,118 7 Nuclear Fuel (120.1-120.4, 120.6) 8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies (120.5) 9 Net Nuclear Fuel (Enter Total of line 7 Less 8) 10 Net Utility Plant (enter Total of lines 6 and 9) 525,148,118 525,148,118 11 Utility Plant Adjustments (116) 12 Gas Stored Underground-Noncurrent (117) 13 OTHER PROPERTY AND INVESTMENTS 14 Nonutility Property (121) 2,492,201 2,492,201 15 (Less) Accum. Prov. for Depr. and Amort. (122) 4,511 4,511 16 Investments in Associated Companies (123) 17 Investment in Subsidiary Companies (123.1) 18 (For Cost of Account 123.1. See Footnote Page 224, Line 42) 19 Noncurrent Portion of Allowances 20 Other Investments (124) 565,541 565,541 21 Special Funds (125-128) 1,548,940 1,548,940 22 TOTAL Other Property and Investments (Total of 4,602,171 4,602,171 lines 14-17, 19-21) 23 CURRENT AND ACCRUED ASSETS 24 Cash (131) 3,181,620 3,181,620 25 Special Deposits (132-134) 213,011 213,011 26 Working Fund (135) 26,607 26,607 27 Temporary Cash Investments (136) 28 Notes Receivable (141) 29 Customer Accounts Receivable (142) 50,680,661 50,680,661 30 Other Accounts Receivable (143) 2,712,633 2,712,633 31 (Less) Accum. Prov. for Uncollectible 5,002,071 5,002,071 Acct.-Credit (144) 32 Notes Receivable from Associated Companies (145) 33 Accounts Receivable from Assoc. Companies (146) 20,580,742 20,580,742 34 Fuel Stock (151) 61,948 61,948 35 Fuel Stock Expenses Undistributed (152) 36 Residuals (Elec) and Extracted Products (153) 37 Plant Materials and Operating Supplies (154) 3,501,637 3,501,637 38 Merchandise (155) 39 Other Materials and Supplies (156) 40 Nuclear Materials Held for Sale (157) 41 Allowances (158.1 and 158.2) 42 (Less) Noncurrent Portion of Allowances 43 Stores Expense Undistributed (163) 44 Gas Stored Underground-Current (164.1) 45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 46 Prepayments (165) 9,798,341 9,798,341 47 Advances for Gas (166-167) 48 Interest and Dividends receivable (171) 8,363 8,363 49 Rents Receivable (172) 50 Accrued Utility Revenues (173) 19,536,000 19,536,000 51 Miscellaneous Current and Accrued Assets (174) 181,394 181,394 52 TOTAL Current and Accrued Assets (Enter Total 105,480,886 105,480,886 of lines 24 thru 51) NEES Companies Exhibit No. C-3 Page 2 of 5 Name of Respondent Narragansett Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 53 DEFERRED DEBITS 54 Unamortized Debt Expenses (181) 709,785 709,785 55 Extraordinary Property Losses (182.1) 56 Unrecovered Plant and Regulatory Study Costs (182.2) 57 Other Regulatory Assets (182.3) 41,696,083 41,696,083 58 Prelim. Survey and Investigation Charges 319,376 319,376 (Electric) (183) 59 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2) 60 Clearing Accounts (184) 142,669 142,669 61 Temporary Facilities (185) 62 Miscellaneous Deferred Debits (186) 12,616,238 12,616,238 63 Def. Losses from Disposition of Utility Plt. (187) 64 Research, Devel. and Demonstration Expend. (188) 65 Unamortized Loss on Reacquired Debt (189) 66 Accumulated Deferred Income taxes (190) 16,312,823 16,312,823 67 Unrecovered Purchased Gas Costs (191) 68 TOTAL Deferred Debits (Enter Total of lines 54 71,796,974 71,796,974 thru 67) 69 TOTAL Assets and other Debits (Enter Total of 707,028,149 707,028,149 lines 10,11,12,22,52, and 68) NEES Companies Exhibit No. C-3 Page 3 of 5 Name of Respondent Narragansett Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 PROPRIETARY CAPITAL 2 Common Stock Issued (201) 56,624,350 56,624,350 3 Preferred Stock Issued (204) 7,601,300 7,601,300 4 Capital Stock Subscribed (202, 205) 5 Stock Liability for Conversion (203, 206) 6 Premium on Capital Stock (207) 80,161 80,161 7 Other Paid-in Capital (208-211) 105,713,572 105,713,572 8 Installments Received on Capital Stock (212) 9 (Less) Discount on Capital Stock (213) 10 (Less) Capital Stock Expense (214) 11 Retained Earnings (215, 215.1, 216) 83,524,686 83,524,686 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 13 (Less) Reacquired Capital Stock (217) 14 TOTAL Proprietary Capital (Enter Total of 253,544,069 253,544,069 Lines 2 thru 13) 15 LONG-TERM DEBT 16 Bonds (221) 179,700,000 179,700,000 17 (Less) Reacquired Bonds (222) 18 Advances from Associated Companies (223) 19 Other Long-Term Debt (224) 20 Unamortized Premium on Long-Term Debt (225) 21 (Less) Unamortized Discount on Long-Term 1,041,937 1,041,937 Debt-Debit (226) 22 TOTAL Long-Term Debt (Enter Total of Lines 16 178,658,063 178,658,063 thru 21) 23 OTHER NONCURRENT LIABILITIES 24 Obligations Under Capital Leases-Noncurrent (227) 25 Accumulated Provision for Property Insurance (228.1) 26 Accumulated Provision for Injuries and Damages (228.2) 27 Accumulated Provision for Pensions and Benefits (228.3) 28 Accumulated Miscellaneous Operating Provisions (228.4) 29 Accumulated Provision for Rate Refunds (229) 30 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29) 31 CURRENT AND ACCRUED LIABILITIES 32 Notes Payable (231) 33 Accounts Payable (232) 17,029,894 17,029,894 34 Notes Payable to Associated Companies (233) 40,750,000 40,750,000 35 Accounts Payable to Associated Companies (234) 34,355,863 34,355,863 36 Customer Deposits (235) 6,165,541 6,165,541 37 Taxes Accrued (236) 3,357,327 3,357,327 38 Interest Accrued (237) 3,121,364 3,121,364 39 Dividends Declared (238) 99,326 99,326 40 Matured Long-Term Debt (239) 41 Matured Interests (240) 42 Tax Collections Payable (241) 948,630 948,630 43 Miscellaneous Current and Accrued Liabilities 37,943,157 37,943,157 (242) 44 Obligations Under Capital Leases - Current (243) 45 TOTAL Current and Accrued Liabilities (Enter 143,771,102 143,771,102 Total of lines 32 thru 44) NEES Companies Exhibit No. C-3 Page 4 of 5 Name of Respondent Narragansett Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 46 DEFERRED CREDITS 47 Customer Advances for Construction (252) (10,133) (10,133) 48 Accumulated Deferred Investment Tax Credits 6,655,589 6,655,589 (255) 49 Deferred Gains from Disposition of Utility Plant (256) 50 Other Deferred Credits (253) 14,029,220 14,029,220 51 Other Regulatory Liabilities (254) 8,846,730 8,846,730 52 Unamortized Gain on Reacquired Debt (257) 53 Accumulated Deferred Income Taxes (281-283) 101,533,509 101,533,509 54 TOTAL Deferred Credits (Enter Total of Lines 131,054,915 131,054,915 47 thru 53) 55 56 57 58 59 60 61 62 63 64 65 66 67 68 Total Liabilities and Other Credits (Enter 707,028,149 707,028,149 Total of Lines 14, 22, 30, 45, and 54) NEES Companies Exhibit No. C-3 Page 5 of 5 Name of Respondent Narragansett Electric Company At September 30, 1998 SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND DEPLETION Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 593,280,225 593,280,225 4 Property Under Capital Leases 5 Plant Purchased or Sold 6 Completed Construction not Classified 120,410,883 120,410,883 7 Experimental Plant Unclassified 8 Total (Enter Total of lines 3 thru 7) 713,691,108 713,691,108 9 Leased to Others 10 Held for Future Use 12,647,401 12,647,401 11 Construction Work in Progress 2,717,852 2,717,852 12 Acquisition Adjustments 13 Total Utility Plant (Enter total of lines 8 thru 12) 729,056,361 729,056,361 14 Accum. Prov. for Depr., Amort., and Depl. 203,908,243 203,908,243 15 Net Utility Plant (Enter Total of line 13 less 14) 525,148,118 525,148,118 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In service: 18 Depreciation 203,908,243 203,908,243 19 Amort. and Depl. of Producing Natural Gas & Land Rights 20 Amort. of Underground Storage Land and Land Rights 21 Amort. of Other Utility Plant 22 TOTAL in Service (Enter Total of lines 18 thru 21) 203,908,243 203,908,243 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Enter Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (Enter Total of lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amort. of Plant Acquisition Adj. 33 Total Accumulated Provisions (Should agree with 203,908,243 203,908,243 line 14 above)(Enter Total of lines 22, 26, 30, 31 and 32)
NEES Companies Exhibit No. C-4 Page 1 of 5 Name of Respondent New England Electric Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 91,168,193 91,168,193 3 Construction Work in Progress (107) 4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 91,168,193 91,168,193 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 55,614,132 55,614,132 111, 115) 6 Net Utility Plant (Enter total of line 4 less 5) 35,554,061 35,554,061 7 Nuclear fuel (120.1-120.4, 120.6) 8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies (120.5) 9 Net Nuclear Fuel (Enter Total of line 7 Less 8) 10 Net Utility Plant (Enter Total of lines 6 and 9) 35,554,061 35,554,061 11 Utility Plant Adjustments (116) 12 Gas Stored Underground-Noncurrent (117) 13 OTHER PROPERTY AND INVESTMENTS 14 Nonutility Property (121) 15 (Less) Accum. Prov. for Depr. and Amort. (122) 16 Investments in Associated Companies (123) 17 Investment in Subsidiary Companies (123.1) 18 (For Cost of Account 123.1, See Footnote Page 224, Line 42) 19 Noncurrent Portion of Allowances 20 Other Investments (124) 21 Special Funds (125-128) 22 TOTAL Other Property and Investments (Total of lines 14-17, 19-21) 23 CURRENT AND ACCRUED ASSETS 24 Cash (131) 21,763 21,763 25 Special Deposits (132-134) 26 Working Fund (135) 27 Temporary Cash Investments (136) 28 Notes Receivable (141) 29 Customer Accounts Receivable (142) 30 Other Accounts Receivable (143) (239) (239) 31 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 32 Notes Receivable from Associated Companies (145) 33 Accounts Receivable from Assoc. Companies (146) 13,940 13,940 34 Fuel Stock (151) 35 Fuel Stock Expenses Undistributed (152) 36 Residuals (Elec) and Extracted Products (153) 37 Plant Materials and Operating Supplies (154) 87,007 87,007 38 Merchandise (155) 39 Other Materials and Supplies (156) 40 Nuclear Materials Held for Sale (157) 41 Allowances (158.1 and 158.2) 42 (Less) Noncurrent Portion of Allowances 43 Stores Expense Undistributed (163) 44 Gas Stored Underground-Current (164.1) 45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 46 Prepayments (165) 8,732 8,732 47 Advances for Gas (166-167) 48 Interest and Dividends Receivable (171) 23 23 49 Rents Receivable (172) 50 Accrued Utility Revenues (173) COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued) NEES Companies Exhibit No. C-4 Page 2 of 5 Name of Respondent New England Electric Transmission Corporation At September 30, 1998 Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 51 Miscellaneous Current and Accrued Assets (174) 52 TOTAL Current and Accrued Assets (Enter Total of lines 24 thru 51) 131,226 131,226 53 DEFERRED DEBITS 54 Unamortized Debt Expenses (181) 310,736 310,736 55 Extraordinary Property Losses (182.1) 56 Unrecovered Plant and Regulatory Study Costs (182.2) 57 Other Regulatory Assets (182.3) 1,522,900 1,522,900 58 Prelim. Survey and Investigation Charges (Electric) (183) 59 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2) 60 Clearing Accounts (184) 61 Temporary Facilities (185) 62 Miscellaneous Deferred Debits (186) 63 Def. Losses from Disposition of Utility Plt. (187) 64 Research, Devel. and Demonstration Expend. (188) 65 Unamortized Loss on Reacquired Debt (189) 66 Accumulated Deferred Income Taxes (190) 3,027,920 3,027,920 67 Unrecovered Purchased Gas Costs (191) 68 TOTAL Deferred Debits (Enter Total of Lines 54 4,861,556 4,861,556 thru 67) 69 TOTAL Assets and other Debits (Enter Total of 40,546,843 40,546,843 lines 10, 11, 12, 22, 52 and 68) NEES Companies Exhibit No. C-4 Page 3 of 5 Name of Respondent New England Electric Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 PROPRIETARY CAPITAL 2 Common Stock Issued (201) 450 450 3 Preferred Stock Issued (204) 4 Capital Stock Subscribed (202, 205) 5 Stock Liability for Conversion (203, 206) 6 Premium on Capital Stock (207) 89,550 89,550 7 Other Paid-In Capital (208-211) 2,160,000 2,160,000 8 Installments Received on Capital Stock (212) 9 (Less) Discount on Capital Stock (213) 10 (Less) Capital Stock Expense (214) 11 Retained Earnings (215, 215.1, 216) 127,400 127,400 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 13 (Less) Reacquired Capital Stock (217) 14 TOTAL Proprietary Capital (Enter Total of Lines 2 2,377,400 2,377,400 thru 13) 15 LONG-TERM DEBT 16 Bonds (221) 17 (Less) Reacquired Bonds (222) 18 Advances from Associated Companies (223) 19 Other Long-Term Debt (224) 17,392,000 17,392,000 20 Unamortized Premium on Long-Term Debt (225) 21 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 22 TOTAL Long-Term Debt (Enter Total of Lines 16 thru 17,392,000 17,392,000 21) 23 OTHER NONCURRENT LIABILITIES 24 Obligations Under Capital Leases-Noncurrent (227) 25 Accumulated Provision for Property Insurance (228.1) 26 Accumulated Provision for Injuries and Damages (228.2) 27 Accumulated Provision for Pensions and Benefits (228.3) 28 Accumulated Miscellaneous Operating Provisions (228.4) 29 Accumulated Provision for Rate Refunds (229) 30 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29) 31 CURRENT AND ACCRUED LIABILITIES 32 Notes Payable (231) 33 Accounts Payable (232) 67,228 67,228 34 Notes Payable to Associated Companies (233) 3,500,000 3,500,000 35 Accounts Payable to Associated Companies (234) 75,031 75,031 36 Customer Deposits (235) 37 Taxes Accrued (236) (41,734) (41,734) 38 Interest Accrued (237) 80,361 80,361 39 Dividends Declared (238) 40 Matured Long-Term Debt (239) 41 Matured Interests (240) 42 Tax Collections Payable (241) 445 445 43 Miscellaneous Current and Accrued Liabilities (242) 91,666 91,666 44 Obligations Under Capital Leases - Current (243) 45 TOTAL Current and Accrued Liabilities (Enter Total 3,772,997 3,772,997 of lines 32 thru 44) NEES Companies Exhibit No. C-4 Page 4 of 5 Name of Respondent New England Electric Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 46 DEFERRED CREDITS 47 Customer Advances for Construction (252) 48 Accumulated Deferred Investment Tax Credits (255) 3,082,234 3,082,234 49 Deferred Gains from Disposition of Utility Plant (256) 50 Other Deferred Credits (253) 51 Other Regulatory Liabilities (254) 2,448,249 2,448,249 52 Unamortized Gain on Reacquired Debt (257) 53 Accumulated Deferred Income Taxes (281-283) 11,473,963 11,473,963 54 TOTAL Deferred Credits (Enter Total of Lines 47 17,004,446 17,004,446 thru 53) 55 56 57 58 59 60 61 62 63 64 65 66 67 68 Total Liabilities and Other Credits (Enter Total 40,546,843 40,546,843 of Lines 14, 22, 30, 45 and 54) NEES Companies Exhibit No. C-4 Page 5 of 5 Name of Respondent New England Electric Transmission Corporation At September 30, 1998 SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND DEPLETION Adjusted Line Balance at Pro-Forma Balance at No. Item 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 91,168,193 91,168,193 4 Property Under Capital Leases 5 Plant Purchased or Sold 6 Completed Construction not Classified 7 Experimental Plant Unclassified 8 Total (Enter Total of lines 3 thru 7) 91,168,193 91,168,193 9 Leased to Others 10 Held for Future Use 11 Construction Work in Progress 12 Acquisition Adjustments 13 Total Utility Plant (Enter total of lines 8 thru 12) 91,168,193 91,168,193 14 Accum. Prov. for Depr., Amort., and Depl. 55,614,132 55,614,132 15 Net Utility Plant (Enter Total of line 13 less 14) 35,554,061 35,554,061 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In service: 18 Depreciation 55,573,632 55,573,632 18 Amort. and Depl. of Producing Natural Gas & Land Rights 20 Amort. of Underground Storage Land and Land Rights 21 Amort. of Other Utility Plant 40,500 40,500 22 TOTAL In Service (Enter Total of lines 18 thru 21) 55,614,132 55,614,132 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Enter Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (Enter Total of lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amort. of Plant Acquisition Adj. 33 Total Accumulated Provisions (Should agree with line 14 above) (Enter Total of lines 22, 26, 30, 31 and 32) 55,614,132 55,614,132
NEES Companies Exhibit No. C-5 Page 1 of 11 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 173,245,669 173,245,669 3 Construction Work in Progress (107) 4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 173,245,669 173,245,669 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 45,222,278 45,222,278 111, 115) 6 Net Utility Plant (Enter total of line 4 less 5) 128,023,391 128,023,391 7 Nuclear fuel (120.1-120.4, 120.6) 8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies (120.5) 9 Net Nuclear Fuel (Enter Total of line 7 Less 8) 10 Net Utility Plant (Enter Total of lines 6 and 9) 128,023,391 128,023,391 11 Utility Plant Adjustments (116) 12 Gas Stored Underground-Noncurrent (117) 13 OTHER PROPERTY AND INVESTMENTS 14 Nonutility Property (121) 15 (Less) Accum. Prov. for Depr. and Amort. (122) 16 Investments in Associated Companies (123) 17 Investment in Subsidiary Companies (123.1) 5,000 5,000 18 (For Cost of Account 123.1, See Footnote Page 224, Line 42) 19 Noncurrent Portion of Allowance 20 Other Investments (124) 21 Special Funds (125-128) 22 TOTAL Other Property and Investments (Total of 5,000 5,000 lines 14-17, 19-21) 23 CURRENT AND ACCRUED ASSETS 24 Cash (131) 19,583 19,583 25 Special Deposits (132-134) 26 Working Fund (135) 27 Temporary Cash Investments (136) 28 Notes Receivable (141) 29 Customer Accounts Receivable (142) 30 Other Accounts Receivable (143) (28,653) (28,653) 31 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 32 Notes Receivable from Associated Companies (145) 33 Accounts Receivable from Assoc. Companies (146) 34 Fuel Stock (151) 35 Fuel Stock Expenses Undistributed (152) 36 Residuals (Elec) and Extracted Products (153) 37 Plant Materials and Operating Supplies (154) 86,804 86,804 38 Merchandise (155) 39 Other Materials and Supplies (156) 40 Nuclear Materials Held for Sale (157) 41 Allowances (158.1 and 158.2) 42 (Less) Noncurrent Portion of Allowances 43 Stores Expense Undistributed (163) 44 Gas Stored Underground-Current (164.1) 45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 46 Prepayments (165) 6,360 6,360 47 Advances for Gas (166-167) 48 Interest and Dividends Receivable (171) 181 181 49 Rents Receivable (172) 50 Accrued Utility Revenues (173) NEES Companies Exhibit No. C-5 Page 2 of 11 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 51 Miscellaneous Current and Accrued Assets (174) 52 TOTAL Current and Accrued Assets (Enter Total of 84,275 84,275 lines 24 thru 51) 53 DEFERRED DEBITS 54 Unamortized Debt Expenses (181) 484,827 484,827 55 Extraordinary Property Losses (182.1) 56 Unrecovered Plant and Regulatory Study Costs (182.2) 57 Other Regulatory Assets (182.3) 9,526,405 9,526,405 58 Prelim. Survey and Investigation Charges (Electric) (183) 59 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2) 60 Clearing Accounts (184) 61 Temporary Facilities (185) 62 Miscellaneous Deferred Debits (186) 63 Def. Losses from Disposition of Utility Plt. (187) 64 Research, Devel. and Demonstration Expend. (188) 65 Unamortized Loss on Reacquired Debt (189) 66 Accumulated Deferred Income Taxes (190) 7,334,675 7,334,675 67 Unrecovered Purchased Gas Costs (191) 68 TOTAL Deferred Debits (Enter Total of Lines 54 17,345,907 17,345,907 thru 67) 69 TOTAL Assets and other Debits (Enter Total of 145,458,573 145,458,573 lines 10, 11, 12, 22, 52 and 68) NEES Companies Exhibit No. C-5 Page 3 of 11 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS ) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 1 PROPRIETARY CAPITAL 2 Common Stock Issued (201) 82,500 82,500 3 Preferred Stock Issued (204) 4 Capital Stock Subscribed (202, 205) 5 Stock Liability for Conversion (203, 206) 6 Premium on Capital Stock (207) 16,417,499 16,417,499 7 Other Paid-In Capital (208-211) 13,593,689 13,593,689 8 Installments Received on Capital Stock (212) 9 (Less) Discount on Capital Stock (213) 10 (Less) Capital Stock Expense (214) 11 Retained Earnings (215, 215.1, 216) 90,276 90,276 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 13 (Less) Reacquired Capital Stock (217) 14 TOTAL Proprietary Capital (Enter Total of Lines 30,183,964 30,183,964 2 thru 13) 15 LONG-TERM DEBT 16 Bonds (221) 17 (Less) Reacquired Bonds (222) 18 Advances from Associated Companies (223) 48,500,000 48,500,000 19 Other Long-Term Debt (224) 20 Unamortized Premium on Long-Term Debt (225) 21 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 22 TOTAL Long-Term Debt (Enter Total of Lines 16 48,500,000 48,500,000 thru 21) 23 OTHER NONCURRENT LIABILITIES 24 Obligations Under Capital Leases-Noncurrent (227) 26,559,367 26,559,367 25 Accumulated Provision for Property Insurance (228.1) 26 Accumulated Provision for Injuries and Damages (228.2) 27 Accumulated Provision for Pensions and Benefits (228.3) 28 Accumulated Miscellaneous Operating Provisions (228.4) 29 Accumulated Provision for Rate Refunds (229) 30 TOTAL OTHER Noncurrent Liabilities (Enter Total 26,559,367 26,559,367 of lines 24 thru 29) 31 CURRENT AND ACCRUED LIABILITIES 32 Notes Payable (231) 33 Accounts Payable (232) 35,002 35,002 34 Notes Payable to Associated Companies (233) 1,700,000 1,700,000 35 Accounts Payable to Associated Companies (234) 580,708 580,708 36 Customer Deposits (235) 37 Taxes Accrued (236) 856,767 856,767 38 Interest Accrued (237) 190,392 190,392 39 Dividends Declared (238) 40 Matured Long-Term Debt (239) 41 Matured Interests (240) 42 Tax Collections Payable (241) 43 Miscellaneous Current and Accrued Liabilities 112,006 112,006 (242) 44 Obligations Under Capital Leases - Current (243) 1,577,784 1,577,784 45 TOTAL Current and Accrued Liabilities (Enter 5,052,659 5,052,659 Total of lines 32 thru 44) NEES Companies Exhibit No. C-5 Page 4 of 11 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 46 DEFERRED CREDITS 47 Customer Advances for Construction (252) 48 Accumulated Deferred Investment Tax Credits (255) 4,636,578 4,636,578 49 Deferred Gains from Disposition of Utility Plant (256) 50 Other Deferred Credits (253) 51 Other Regulatory Liabilities (254) 5,061,420 5,061,420 52 Unamortized Gain on Reacquired Debt (257) 53 Accumulated Deferred Income Taxes (281-283) 25,464,585 25,464,585 54 TOTAL Deferred Credits (Enter Total of Lines 47 thru 53) 35,162,583 35,162,583 55 56 57 58 59 60 61 62 63 64 65 66 67 68 Total Liabilities and Other Credits (Enter Total 145,458,573 145,458,573 of Lines 14, 22, 30, 45, and 54) NEES Companies Exhibit No. C-5 Page 5 of 11 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND DEPLETION Adjusted Line Balance at Pro-Forma Balance at No. Item 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 134,048,639 134,048,639 4 Property Under Capital Leases 28,137,151 28,137,151 5 Plant Purchased or Sold 6 Completed Construction not Classified 11,059,879 11,059,879 7 Experimental Plant Unclassified 8 Total (Enter Total of lines 3 thru 7) 173,245,669 173,245,669 9 Leased to Others 10 Held for Future Use 11 Construction Work in Progress 12 Acquisition Adjustments 13 Total Utility Plant (Enter total of lines 8 thru 12) 173,245,669 173,245,669 14 Accum. Prov. for Depr., Amort., and Depl. 45,222,278 45,222,278 15 Net Utility Plant (Enter Total of line 13 less 14) 128,023,391 128,023,391 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In service: 18 Depreciation 45,222,278 45,222,278 18 Amort. and Depl. of Producing Natural Gas & Land Rights 20 Amort. of Underground Storage Land and Land Rights 21 Amort. of Other Utility Plant 22 TOTAL In Service (Enter Total of lines 18 thru 21) 45,222,278 45,222,278 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Enter Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (Enter Total of lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amort. of Plant Acquisition Adj. 33 Total Accumulated Provisions (Should agree with line 14 above) (Enter Total of lines 22, 26, 30, 31 and 32) 45,222,278 45,222,278 NEES Companies Exhibit No. C-5 Page 6 of 11 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 220,637,167 220,637,167 3 Construction Work In Progress (107) 4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 220,637,167 220,637,167 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 68,342,093 68,342,093 6 Net Utility Plant (enter Total of Line 4 Less 5) 152,295,074 152,295,074 7 Nuclear Fuel (120.1-120.4, 120.6) 8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies (120.5) 9 Net Nuclear Fuel (Enter Total of line 7 Less 8) 10 Net Utility Plan (Enter Total of lines 6 and 9) 152,295,074 152,295,074 11 Utility Plant Adjustments (116) 12 Gas Stored Underground-Noncurrent (117) 13 OTHER PROPERTY AND INVESTMENTS 14 Nonutility Property (121) 15 (Less) Accum. Prov. for Depr. and Amort. (122) 16 Investments in Associated Companies (123) 17 Investment in Subsidiary Companies (123.1) 5,000 5,000 18 (For Cost of Account 123.1, See Footnote Page 224, Line 42) 19 Noncurrent Portion of Allowances 20 Other Investments (124) 21 Special Funds (125-128) 22 TOTAL Other Property and Investments (Total of lines 14-17, 19-21) 5,000 5,000 23 CURRENT AND ACCRUED ASSETS 24 Cash (131) 17,360 17,360 25 Special Deposits (132-134) 26 Working Fund (135) 27 Temporary Cash Investments (136) 28 Notes Receivable (141) 29 Customer Accounts Receivable (142) 30 Other Accounts Receivable (143) (20,450) (20,450) 31 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 32 Notes Receivable from Associated Companies (145) 4,675,000 4,675,000 33 Accounts Receivable from Assoc. Companies (146) 3,582 3,582 34 Fuel Stock (151) 35 Fuel Stock Expenses Undistributed (152) 36 Residuals (Elec) and Extracted Products (153) 37 Plant Materials and Operating Supplies (154) 1,919,818 1,919,818 38 Merchandise (155) 39 Other Materials Held for Sale (156) 40 Nuclear Materials Held for Sale (157) 41 Allowances (158.1 and 158.2) 42 (Less) Noncurrent Portion of Allowances 43 Stores Expense Undistributed (163) 44 Gas Stored Underground-Current (164.1) 45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 46 Prepayments (165) 40,624 40,624 47 Advances for Gas (166-167) 48 Interest and Dividends Receivable (171) 24,188 24,188 49 Rents Receivable (172) 50 Accrued Utility Revenues (173) NEES Companies Exhibit No. C-5 Page 7 of 11 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 51 Miscellaneous Current and Accrued Assets (174) 4,607 4,607 52 TOTAL Current and Accrued Assets (Enter Total of lines 24 thru 51) 6,664,729 6,664,729 NEES Companies Exhibit No. C-5 Page 8 of 11 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 53 DEFERRED DEBITS 54 Unamortized Debt Expenses (181) 728,307 728,307 55 Extraordinary Property Losses (182.1) 56 Unrecovered Plant and Regulatory Study Costs (182.1) 57 Other Regulatory Assets (182.3) 10,655,530 10,655,530 58 Prelim. Survey and Investigation Charges (Electric) (183) 59 Prelim Sur. and Invest. Charges (Gas) (183.1, 183.2) 60 Cleaning Accounts (184) 61 Temporary Facilities (185) 62 Miscellaneous Deferred Debits (186) 63 Def. Losses from Disposition of Utility Pit. (187) 64 Research, Devel. and Demonstration Expend. (188) 65 Unamortized Loss on Reacquired Debt (189) 66 Accumulated Deferred Income Taxes (190) 11,839,622 11,839,622 67 Unrecovered Purchased Gas Costs (191) 68 TOTAL Deferred Debits (Enter total of lines 23,223,459 23,223,459 54 thru 67) 69 TOTAL Assets and other Debits (Enter Total of lines 10, 11, 12, 22, 52, and 68) 182,188,262 182,188,262 NEES Companies Exhibit No. C-5 Page 9 of 11 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 1 PROPRIETARY CAPITAL 2 Common Stock Issued (201) 3,700,014 3,700,014 3 Preferred Stock Issued (204) 4 Capital Stock Subscribed (202, 205) 5 Stock Liability for Conversion (203, 206) 6 Premium on Capital Stock (207) 33,300,130 33,200,130 7 Other Paid-in Capital (208-211) 15,155,770 15,155,770 8 Installments Received on Capital Stock (212) 9 (Less) Discount on Captial Stock (213) 10 (Less) Capital Stock expense (214) 11 Retained Earnings (215, 215.1, 216) 96,398 96,398 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 13 (Less) Reacquired Capital Stock (217) 14 TOTAL Proprietary Capital (Enter Total of Lines 2 thru 13) 52,252,312 52,252,312 15 LONG-TERM DEBT 16 Bonds (221) 17 (Less) Reacquired Bonds (222) 18 Advances from Associated Companies (223) 79,350,000 79,350,000 19 Other Long-Term (224) 20 Unamortized Premium on Long-Term Debt (225) 21 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 22 TOTAL Long-Term Debt (Enter Total of 79,350,000 79,350,000 Lines 16 thru 21 23 OTHER NONCURRENT LIABILITIES 24 Obligations Under Capital Leases-Noncurrent (227) 25 Accumulated Provision for Property Insurance (228.1) 26 Accumulated Provision for Injuries and Damages (228.2) 27 Accumulated Provision for Pensions and Benefits (228.3) 28 Accumulated Miscellaneous Operating Provisions (228.4) 29 Accumulated Provision for Rate Refunds (229) 30 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29) 31 CURRENT AND ACCRUED LIABILITIES 32 Notes Payable (231) 33 Accounts Payable (232) 456,426 456,426 34 Notes Payable to Associated Companies (233) 35 Accounts Payable to Associated Companies 76,152 76,152 (234) 36 Customer Deposits (235) 37 Taxes Accrued (236) 602,704 602,704 38 Interest Accrued (237) 304,689 304,689 39 Dividends Declared (238) 40 Matured Long-Term Debt (239) 41 Matured Interests (240) 42 Tax Collections Payable (241) 3,690 3,690 43 Miscellaneous Current and Accrued Liabilities (242) 438,813 438,813 44 Obligations Under Capital Leases - Current (243) 45 TOTAL Current and Accrued Liabilities (Enter Total of lines 32 thru 44) 1,882,474 1,882,474 NEES Companies Exhibit No. C-5 Page 10 of 11 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued) Adjusted Line Balance at Pro-Forma Balance at No. Title of Account 9-30-98 Adjustments 9-30-98 46 DEFERRED CREDITS 47 Customer Advances for Construction (252) 48 Accumulated Deferred Investment Tax Credits (255) 7,991,098 7,991,098 49 Deferred Gains from Disposition of Utility Plant (256) 50 Other Deferred Credits (253) 51 Other Regulatory Liabilities (254) 7,334,350 7,334,350 52 Unamortized Gain on Reacquired Debt (257) 53 Accumulated Deferred Income Taxes (281-283) 33,378,028 33,378,028 54 TOTAL Deferred Credits (Enter Total of Lines 47 thru 53) 48,703,476 48,703,476 55 56 57 58 59 60 61 62 63 64 65 66 67 68 Total Liabilities and Other Credits (Enter Total of Lines 14,22,30,45, and 54) 182,188,262 182,188,262 NEES Companies Exhibit No. C-6 Page 11 of 11 Name of Respondent New England Hydro Transmission Electric Company SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND DEPLETION At September 30, 1998 Adjusted Line Balance at Pro-Forma Balance at No. Item 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 4 Property Under Capital Leases 5 Plant Purchased or Sold 6 Completed Construction not Classified 220,637,167 220,637,167 7 Experimental Plant Unclassified 8 Total (Enter Total of lines 3 thru 7) 220,637,167 220,637,167 9 Leased to Others 10 Held for Future Use 11 Construction Work in Progress 12 Acquisition Adjustments 13 Total Utility Plant (Enter total of lines 8 thru 12) 220,637,167 220,637,167 14 Accum. Prov. for Depr. Amort., and Depl. 68,342,093 68,342,093 15 Net Utility Plant (Enter Total of line 13 220,637,167 220,637,167 less 14) 220,637,167 220,637,167 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In Service: 18 Depreciation 68,123,593 68,123,593 19 Amort. and Depl. of Producing Natural Gas & Land Rights 20 Amort. of Underground Storage Land and Land Rights 21 Amort. of Other Utility Plant 218,500 218,500 22 TOTAL In Service (Enter Total of lines 18 thru 12) 68,342,093 68,342,093 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Enter Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (Enter total of lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amort. of Plant Acquisition Adj. 33 Total Accumulated Provisions (Should agree with line 14 above) (Enter total of lines 22, 26, 30, 31 and 32) 68,342,093 68,342,093
EUA Companies Exhibit No. C-7 Page 1 of 5 Name of Respondent Montaup ElectricCompany At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 571,772,660 571,772,660 3 Construction Work in Progress (107) 3,683,654 3,683,654 4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 575,456,314 575,456,314 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 202,785,329 202,785,329 6 Net Utility Plant (Enter Total of line 4 Less 5) 372,670,985 372,670,985 7 Nuclear Fuel (120.1-120.4, 120.6) 10,322,443 10,322,443 8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies (120.5) 5,988,016 5,988,016 9 Net Nuclear Fuel (Enter Total of line 7 Less 8) 4,334,427 4,334,427 10 Net Utility Plant (Enter Total of lines 6 and 9) 377,005,412 377,055,412 11 Utility Plant Adjustments (116) 12 Gas Stored Underground-Noncurrent (117) 13 OTHER PROPERTY AND INVESTMENTS 14 Nonutility Property (121) 2,446,513 2,446,513 15 (Less) Accum. Prov. for Depr. and Amort. (122) 16 Investments in Associated Companies (123) 17 Investment in Subsidiary Companies (123.1) 13,129,910 13,129,910 18 (for Cost of Account 123.1, See footnote Page 224, Line 42) 19 Noncurrent Portion of Allowances 20 Other Investments (124) 21 Special Funds (125-128) 7,726,838 7,726,838 22 TOTAL Other Property and Investments (Total of lines 14-17, 19-21) 23,303,261 23,303,261 23 CURRENT AND ACCRUED ASSETS 24 Cash (131) 193,458 193,458 25 Special Deposits (132-134) 26 Working Fund (135) 5,800 5,800 27 Temporary Cash Investments (136) 28 Notes Receivable (141) 29 Customer Accounts Receivable (142) 3,117,329 3,117,329 30 Other Accounts Receivable (143) 428,048 428,048 31 (Less) Accum. Prov. for Uncollectible Acct-Credit (144) 32 Notes Receivable from Associated Companies (145) 33 Accounts Receivable from Assoc. Companies (146) 60,613,693 60,613,693 34 Fuel Stock (151) 5,156,045 5,156,045 35 Fuel Stock Expenses Undistributed (152) 102,418 102,418 36 Residuals (Elec) and Extracted Products (153) 37 Plant Materials and Operating Supplies (154) 1,918,242 1,918,242 38 Merchandise (155) 39 Other Materials and Supplies (156) 40 Nuclear Materials Held for Sale (157) 41 Allowances (158.1 and 158.2) 18,050 18,050 42 (Less) Noncurrent Potion of Allowances 43 Stores Expense Undistributed (163) 70,258 70,258 44 Gas Stored Underground-Current (164.1) 45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 46 Prepayments (165) 2,855,763 2,855,763 47 Advances for Gas (166-167) 48 Interest and Dividends Receivable (171) 49 Rents Receivable (172) 65,548 65,548 50 Accrued Utility Revenues (173) 51 Miscellaneous Current and Accrued Assets (174) 97,458 97,458 52 TOTAL Current and Accrued Assets (Enter Total of 74,642,110 74,642,110 lines 24 thru 51) EUA Companies Exhibit No. C-7 Page 2 of 5 Name of Respondent Montaup Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 53 DEFERRED DEBITS 54 Unamoritzed Debt Expenses (181) 22,321 22,321 55 Extraordinary Property Losses (182.2) 56 Unrecovered Plant and Regulatory Study Costs (182.2) 60,672,177 60,672,177 57 Other Regulatory Assets (182.3) 77,096,573 77,096,573 58 Prelim. Survey and Investigation Charges (Electric (183) (550,692) (550,692) 59 Prelim Sur. and Invest. Charges (Gas) (183.1, 183.2) 60 Clearing Accounts (184) 61 Temporary Facilities (185) 62 Miscellaneous Deferred Debits (186) 9,752,754 9,752,754 63 Def. Losses from Disposition of Utility Plt. (187) 64 Research, Devel. and Demonstration Expend. (188) 65 Unamortized Loss on Reacquired Debt (189) 9,998,437 9,998,437 66 Accumulated Deferred Income Taxes (190) 7,908,353 7,908,353 67 Unrecovered Purchased Gas Costs (191) 68 TOTAL Deferred Debits (Enter total of lines 54 thru 67) 164,899,923 164,899,923 69 TOTAL Assets and other Debits (Enter Total of lines 10,11,22,52, and 68) 639,850,706 639,850,706 EUA Companies Exhibit No. C-7 Page 3 of 5 Name of Respondent Montaup ElectricCompany At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 PROPRIETARY CAPITAL 2 Common Stock issued (201) 58,600,000 58,600,000 3 Preferred Stock Issued (204) 1,500,000 1,500,000 4 Capital Stock Subscribed (202, 205) 5 Stock Liability for Conversion (203, 206) 6 Premium on Capital Stock (207) 7 Other Paid-in Capital (208-211) 29,528,000 29,528,000 8 Installments Received on Capital Stock (212) 9 (Less) discount on Capital Stock (213) 10 (Less) Capital Stock Expense (214) 11 Retained Earnings (215, 215.1, 216) 69,730,306 69,730,306 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 4,059,386 4,059,386 13 (Less) Reacquired Capital Stock (217) 14 TOTAL Proprietary Capital (Enter Total of Lines 2 thru 13) 163,417,692 163,417,692 15 LONG-TERM DEBT 16 Bonds (221) 172,913,929 172,913,929 17 (Less) Reacquired Bonds (222) 18 Advances from Associated Companies (223) 19 Other Long-term Debt (224) 20 Unamortized Premium on Long-Term Debt (226) 21 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 22 TOTAL Long-Term Debt (Enter Total of Lines 16 thru 21) 172,913,929 172,913,929 23 OTHER NONCURRENT LIABILITIES 24 Obligations Under Capital Leases-Noncurrent (227) 25 Accumulated Provision for Property Insurance (228.1) 26 Accumulated Provision for Injuries and Damages (228.2) 27 Accumulated Provision for Pensions and Benefits (228.3) 542,945 542,945 28 Accumulated Miscellaneous Operating Provisions (228.4) 431,750 431,750 29 Accumulated Provision for Rate Refunds (229) 30 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29) 974,695 974,695 31 CURRENT AND ACCRUED LIABILITIES 32 Notes Payable (231) 33 Accounts Payable (232) 23,632,257 23,632,257 34 Notes Payable to Associated Companies (233) 35 Accounts Payable to Associated Companies (234) 13,549,498 13,549,498 36 Customer Deposits (235) 37 Taxes Accrued (236) 2,154,094 2,154,094 38 Interest Accrued (237) 5,745,563 5,745,563 39 Dividends Declared (238) 40 Matured Long-Term Debt (239) 41 Matured Interests (240) 42 Tax Collections Payable (241) 8,225 8,225 43 Miscellaneous Current and Accrued Liabilities (242) 1,644,957 1,644,957 44 Obligations Under Capital Leases - Current (243) 45 TOTAL Current and Accrued Liabilities (Enter Total of lines 32 thru 44) 46,734,594 46,734,594 EUA Companies Exhibit No. C-7 Page 4 of 5 Name of Respondent Montaup Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 46 DEFERRED CREDITS 47 Customer Advances for Construction (252) 48 Accumulated Deferred Investment Tax Credits (255) 11,605,710 11,605,710 49 Deferred Gains from Disposition of Utility Plant (256) 50 Other Deferred Credits (253) 77,065,660 77,065,660 51 Other Regulatory Liabilities (2540 36,757,546 36,757,546 52 Unamortized Gain on Reacquired Debt (257) 53 Accumulated Deferred Income Taxes (281-283) 130,380,880 130,380,880 54 TOTAL Deferred Credits (Enter Total of Lines 47 thru 53) 255,809,796 255,809,796 55 56 57 58 59 60 61 62 63 64 65 66 67 68 Total Liabilities and Other Credits (Enter Total of 639,850,706 639,850,706 Lines 14, 22, 30, 45, and 54) EUA Companies Exhibit No. C-7 Page 5 of 5 Name of Respondent Montaup Electric Company At September 30, 1998 SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND DEPLETION Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 566,134,233 566,134,233 4 Property Under Capital Leases 5 Plant Purchased or Sold 6 Completed Construction not Classified 7 Experimental Plant Unclassified 8 Total (Enter Total of lines 3 thru 7) 566,134,233 566,134,233 9 Leased to Others 10 Held for Future Use 5,638,427 5,638,427 11 Construction Work in Progress 3,683,654 3,683,654 12 Acquisition Adjustments 13 Total Utility Plant (Enter total of lines 8 thru 12) 575,456,314 575,456,314 14 Accum. Prov. for Depr., Amort., and Depl. 15 Net Utility Plant (Enter Total of line 13 less 14) 575,456,314 575,456,314 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In service: 18 Depreciation 195,038,776 195,038,776 19 Amort. and Depl. of Producing Natural Gas & Land Rights 20 Amort. of Underground Storage Land and Land Rights 21 Amort. of Other Utility Plant 64,099 64,099 22 TOTAL In Service (Enter Total of lines 18 thru 21) 195,102,875 195,102,875 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Enter Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (Enter Total of lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amort. of Plant Acquisition Adj. 33 Total Accumulated Provisions (Should agree with line 14 above (Enter Total of lines 22, 26, 30, 31 and 32) 195,102,875 195,102,875
EUA Companies Exhibit No. C-8 Page 1 of 5 Name of Respondent Blackstone Valley Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 142,289,834 142,289,834 3 Construction Work in Progress (107) 3,022,539 3,022,539 4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 145,312,373 145,312,373 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 59,929,466 59,929,466 111, 115) 6 Net Utility Plant (Enter Total of line 4 Less 5) 85,382,907 85,382,907 7 Nuclear Fuel (120.1-120.4, 120.6) 8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies (120.5) 9 Net Nuclear Fuel (Enter Total of line 7 less 8) 10 Net Utility Plant (Enter Total of lines 6 and 9) 85,382,907 85,382,907 11 Utility Plant Adjustments (116) 12 Gas Stored Underground-Noncurrent (117) 13 OTHER PROPERTY AND INVESTMENTS 14 Nonutility Property (121) 70,206 70,206 15 (Less) Accum. Prov. For Depr. and Amort. (122) 26,248 26,248 16 Investments in Associated Companies (123) 17 Investment in Subsidiary Companies (123.1) 18 (For Cost of Account 123.1, See Footnote Page 224, Line 42) 19 Noncurrent Portion of Allowances 20 Other Investments (124) 21 Special Funds (125-128) 7,325,402 7,325,402 22 TOTAL Other Property and Investments (Total of 7,369,360 7,369,360 lines 14-17, 19-21) 23 CURRENT AND ACCRUED ASSETS 24 Cash (131) 730,073 730,073 25 Special Deposits (132-134) 26 Working Fund (135) 22,700 22,700 27 Temporary Cash Investments (136) 28 Notes Receivable (141) 29 Customer Accounts Receivable (142) 11,149,804 11,149,804 30 Other Accounts Receivable (143) 4,517,229 4,517,229 31 (Less) Accum. Prov. Uncollectible Acct.-Credit (144) 150,333 150,333 32 Notes Receivable from Associated Companies (145) 33 Accounts Receivable from Assoc. Companies (146) 436,116 436,116 34 Fuel Stock (151) 35 Fuel Stock Expenses Undistributed (152) 36 Residuals (Elec.) and Extracted Products (153) 37 Plant Materials and Operating Supplies (154) 833,765 833,765 38 Merchandise (155) 39 Other Materials and Supplies (156) 40 Nuclear Materials Held for Sale (157) 41 Allowances (158.1 and 158.2) 42 (Less) Noncurrent Portion of Allowances 43 Stores Expense Undistributed (163) (27,692) (27,692) 44 Gas Stored Underground-Current (164.1) 45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 46 Prepayments (165) 159,800 159,800 47 Advances for Gas (166-167) 48 Interest and Dividends Receivable (171) 49 Rents Receivable (172) 50 Accrued Utility Revenues (173) 2,584,848 2,584,848 51 Miscellaneous Current and Accrued Assets (174) 132,130 132,130 52 TOTAL Current and Accrued Assets ( Enter Total of lines 24 thru 51) 20,388,440 20,388,440 EUA Companies Exhibit No. C-8 Page 2 of 5 Name of Respondent Blackstone Valley Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 53 DEFERRED DEBITS 54 Unamortized Debt Expenses (181) 548,775 548,775 55 Extraordinary Property Losses (182.1) 56 Unrecovered Plant and Regulatory Study Costs (182.2) 57 Other Regulatory Assets (182.3) 13,582,789 13,582,789 58 Prelim. Survey and Investigation Charges (Electric)(183) 59 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2) 60 Clearing Accounts (184) (365) (365) 61 Temporary Facilities (185) 62 Miscellaneous Deferred Debits (186) 7,331,798 7,331,798 63 Def. Losses from Disposition of Utility Plt. (187) 64 Research, Devel. and Demonstration Expend. (188) 65 Unamortized Loss on Reacquired Debt (189) 371,387 371,387 66 Accumulated Deferred Income Taxes (190) 2,767,376 2,767,376 67 Unrecovered Purchased Gas Costs (191) 68 TOTAL Deferred Debits (Enter Total of lines 54 thru 67) 24,601,760 24,601,760 69 TOTAL Assets and other Debits (Enter Total of lines 10, 11, 12, 22, 52, and 68) 137,742,467 137,742,467 EUA Companies Exhibit No. C-8 Page 3 of 5 Name of Respondent Blackstone Valley Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 PROPRIETARY CAPITAL 2 Common Stock Issued (201) 9,203,100 9,203,100 3 Preferred Stock Issued (204) 6,000,000 6,000,000 4 Capital Stock Subscribed (202, 205) 5 Stock Liability for Conversion (203, 206) 6 Premium on Capital Stock (207) 737,430 737,430 7 Other Paid-in Capital (208-211) 17,300,000 17,300,000 8 Installments Received on Capital Stock (212) 9 (Less) Discount on Capital Stock (213) 10 (Less) Capital Stock Expense (214) 11 Retained Earnings (215, 215.1, 216) 13,679,581 13,679,581 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 13 (Less) Reacquired Capital Stock (217) 14 TOTAL Proprietary Capital (Enter Total of Lines 2 thru 13) 46,920,111 42,920,111 15 LONG-TERM DEBT 16 Bonds (221) 33,500,000 33,500,00 17 (Less) Reacquired Bonds (222) 18 Advances from Associated Companies (223) 19 Other Long-Term Debt (224) 20 Unamortized Premium on Long-Term Debt (225) 21 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 22 TOTAL Long-Term Debt (Enter Total of Lines 16 thru 21) 33,500,000 33,500,000 23 OTHER NONCURRENT LIABILITIES 24 Obligations Under Capital Leases-Noncurrent (227) 25 Accumulated Provision for Property Insurance (228.1) 26 Accumulated Provision for Injuries and Damages (228.2) 27 Accumulated Provision for Pensions and Benefits (228.3) 3,818,586 3,818,586 28 Accumulated Miscellaneous Operating Provisions (228.4) 7,325,403 7,325,403 29 Accumulated Provision for Rate Refunds (229) 30 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29) 11,143,989 11,143,989 31 CURRENT AND ACCRUED LIABILITIES 32 Note Payable (231) 2,350,000 2,350,000 33 Accounts Payable (232) 376,329 376,329 34 Notes Payable to Associated Companies (233) 35 Accounts Payable to Associated Companies (234) 12,570,244 12,570,244 36 Customer Deposits (235) 970,789 970,789 37 Taxes Accrued (236) 1,468,909 1,468,909 38 Interest Accrued (237) 1,039,448 1,039,448 39 Dividends Declared (238) 72,188 72,188 40 Matured Long-Term Debt (239) 41 Matured Interest (240) 42 Tax Collections Payable (241) 195,296 195,296 43 Miscellaneous Current and Accrued Liabilities (242) 4,863,514 4,863,514 44 Obligations Under Capital Leases - Current (243) 45 TOTAL Current and Accrued Liabilities (Enter Total of lines 32 thru 44) 23,906,717 23,906,717 EUA Companies Exhibit No. C-8 Page 4 of 5 Name of Respondent Blackstone Valley Electric Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 46 DEFERRED CREDITS 47 Customer Advances for Construction (252) 48 Accumulated Deferred Investment Tax Credits (255) 2,246,686 2,246,686 49 Deferred Gains from Disposition of Utility Plant (256) 50 Other Deferred Credits (253) 337,205 337,205 51 Other Regulatory Liabilities (254) 3,747,169 3,747,169 52 Unamortized Gain on Reacquired Debt (257) 53 Accumulated Deferred Income Taxes (281-283) 15,940,590 15,940,590 54 TOTAL Deferred Credits (Enter Total of Lines 47 thru 53) 22,271,650 22,271,650 55 56 57 59 60 61 62 63 64 65 66 67 68 Total Liabilities and Other Credits (Enter Total of 137,742,467 137,742,467 Lines 14, 22,30,45, and 54) EUA Companies Exhibit No. C-8 Page 5 of 5 Name of Respondent Blackstone Valley Electric Company At September 30, 1998 SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION Page 1 of 5 FOR DEPRECIATION, AMORTIZATION AND DEPLETION Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 142,289,834 142,289,834 4 Property Under Capital Leases 5 Plant Purchased or Sold 6 Completed Construction not Classified 7 Experimental Plant Unclassified 8 Total (Enter Total of lines 3 thru 7) 142,289,834 142,289,834 9 Leased to Others 10 Held for Future Use 11 Construction Work in Progress 3,022,539 3,022,539 12 Acquisition Adjustments 13 Total Utility Plant (Enter total of lines 8 thru 12) 145,312,373 145,312,373 14 Accum. Prov. for Depr., Amort., and Depl. 59,929,466 59,929,466 15 Net Utility Plant (Enter Total of line 13 less 14) 85,382,907 85,382,907 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In service: 18 Depreciation 59,929,466 59,929,466 19 Amort. and Depl. of Producing Natural Gas & Land Rights 20 Amort. of Underground Storage Land and Land Rights 21 Amort. of Other Utility Plant 22 TOTAL In Service (Enter Total of lines 18 thru 21) 59,929,466 59,929,466 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Enter Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (Enter Total of lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amort. of Plant Acquisition Adj. 33 Total Accumulated Provisions (Should agree with line 14 above) (Enter Total of lines 22, 26, 30, 31 and 32) 59,929,466 59,929,466
EUA Companies Exhibit No. C-9 Page 1 of 5 Name of Respondent Eastern Edison Company At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 239,866,645 239,866,645 3 Construction Work in Progress (107) 6,724,868 6,724,868 4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 246,591,513 246,591,513 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 95,357,566 95,357,566 6 Net Utility Plant (Enter Total of line 4 Less 5) 151,233,947 151,233,947 7 Nuclear Fuel (120.1-142.4, 120.6) 8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies (120.5) 9 Net Nuclear Fuel (Enter Total of line 7 less 8) 10 Net Utility Plant (Enter Total of lines 6 and 9) 151,233,947 151,233,947 11 Utility Plant Adjustments (116) 12 Gas Stored Underground-Noncurrent (117) 13 OTHER PROPERTY AND INVESTMENTS 14 Nonutility Property (121) 105,734 105,734 15 (Less) Accum. Prov. For Depr. and Amort. (122) 9,697 9,697 16 Investments in Associated Companies (123) 306,803,621 306,803,621 17 Investment in Subsidiary Companies (123.1) 29,528,000 29,528,000 18 (For Cost of Account 123.1, See Footnote Page 224, Line 42) 19 Noncurrent Portion of Allowances 20 Other Investments (124) 10,405 10,405 21 Special Funds (125-128) 22 TOTAL Other Property and Investments (Total of lines 14-17, 19-21) 336,438,063 336,438,063 23 CURRENT AND ACCRUED ASSETS 24 Cash (131) 92,204 92,204 25 Special Deposits (132-134) 26 Working Fund (135) 13,200 13,200 27 Temporary Cash Investments (136) 28 Notes Receivable (141) 29 Customer Accounts Receivable (142) 24,582,138 24,582,138 30 Other Accounts Receivable (143) 7,458,318 7,458,318 31 (Less) Accum. Prov. Uncollectible Acct.-Credit (144) 32 Notes Receivable from Associated Companies (145) 33 Accounts Receivable from Assoc. Companies (146) 16,702,455 16,702,455 34 Fuel Stock (151) 35 Fuel Stock Expenses Undistributed (152) 36 Residuals (Elec) and Extracted Products (153) 37 Plant Materials and Operating Supplies (154) 1,955,186 1,955,186 38 Merchandise (155) 39 Other Materials and Supplies (156) 40 Nuclear Materials Held for Sale (157) 41 Allowances (158.1 and 158.2) 42 (Less) Noncurrent Portion of Allowances 43 Stores Expense Undistributed (163) 82,313 82,313 44 Gas Stored Underground-Current (164.1) 45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 46 Prepayments (165) 431,655 431,655 47 Advances for Gas (166-167) 48 Interest and Dividends Receivable (171) 49 Rents Receivable (172) 50 Accrued Utility Revenues (173) 5,552,427 5,552,427 51 Miscellaneous Current and Accrued Assets (174) 256,505 256,505 52 TOTAL Current and Accrued Assets ( Enter Total of lines 24 thru 51) 57,126,401 57,126,401 EUA Companies Exhibit No. C-9 Page 2 of 5 Name of Respondent Eastern Edison Company At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 53 DEFERRED DEBITS 54 Unamortized Debt Expenses (181) 1,841,761 1,841,761 55 Extraordinary Property Losses (182.1) 56 Unrecovered Plant and Regulatory Study Costs (182.2) 57 Other Regulatory Assets (182.3) 7,121,375 7,121,375 58 Prelim. Survey and Investigation Charges (Electric)(183) 59 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2) 60 Clearing Accounts (184) 3,175 3,175 61 Temporary Facilities (185) 62 Miscellaneous Deferred Debits (186) 9,678,602 9,678,602 63 Def. Losses from Disposition of Utility Plt. (187) 64 Research, Devel. and Demonstration Expend. (188) 65 Unamortized Loss on Reacquired Debt (189) 572,909 572,909 66 Accumulated Deferred Income Taxes (190) 6,051,869 6,051,869 67 Unrecovered Purchased Gas Costs (191) 68 TOTAL Deferred Debits (Enter Total of lines 54 thru 67) 25,269,691 25,269,691 69 TOTAL Assets and other Debits (Enter Total of lines 10, 11, 12, 22, 52, and 68) 570,068,102 570,068,102 EUA Companies Exhibit No. C-9 Page 3 of 5 Name of Respondent Eastern Edison Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 PROPRIETARY CAPITAL 2 Common Stock Issued (201) 72,283,925 72,283,925 3 Preferred Stock Issued (204) 30,000,000 30,000,000 4 Capital Stock Subscribed (202, 205) 5 Stock Liability for Conversion (203, 206) 6 Premium on Capital Stock (207) 5,824,633 5,824,633 7 Other Paid-in Capital (208-211) 39,663,601 39,663,601 8 Installments Received on Capital Stock (212) 9 (Less) discount on Capital Stock (213) 10 (Less) Capital Stock Expense (214) 379,410 379,410 11 Retained Earnings (215, 215.1, 216) 25,671,690 25,671,690 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 73,789,692 73,789,692 13 (Less) Reacquired Capital Stock (217) 14 TOTAL Proprietary Capital (Enter Total of Lines 2 thru 13) 246,854,131 246,854,131 15 LONG-TERM DEBT 16 Bonds (221) 163,000,000 163,000,000 17 (Less) Reacquired Bonds (222) 18 Advances from Associated Companies (223) 19 Other Long-Term Debt (224) 20 Unamortized Premium on Long-Term Debt (225) 21 (Less) Unamortized Discount on Long-Term 458,781 458,781 Debt-Debit (226) 22 TOTAL Long-Term Debt (Enter Total of Lines 16 thru 21) 162,541,219 162,541,219 23 OTHER NONCURRENT LIABILITIES 24 Obligations Under Capital Leases-Noncurrent (227) 25 Accumulated Provision for Property Insurance (228.1) 26 Accumulated Provision for Injuries and Damages (228.2) 27 Accumulated Provision for Pensions and Benefits (228.3) 5,208,566 5,208,566 28 Accumulated Miscellaneous Operating Provisions (228.4) 29 Accumulated Provision for Rate Refunds (229) 30 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29) 5,208,566 5,208,566 31 CURRENT AND ACCRUED LIABILITIES 32 Note Payable (231) 52,195,000 52,195,000 33 Accounts Payable (232) 1,030,631 1,030,631 34 Notes Payable to Associated Companies (233) 35 Accounts Payable to Associated Companies (234) 52,383,867 52,383,867 36 Customer Deposits (235) 1,431,214 1,431,214 37 Taxes Accrued (236) (771,961) (771,961) 38 Interest Accrued (237) 3,876,191 3,876,191 39 Dividends Declared (238) 40 Matured Long-Term Debt (239) 41 Matured Interest (240) 42 Tax Collections Payable (241) 287,954 287,954 43 Miscellaneous Current and Accrued Liabilities (242) 9,525,902 9,525,902 44 Obligations Under Capital Leases - Current (243) 45 TOTAL Current and Accrued Liabilities (Enter Total of lines 32 thru 44) 119,958,798 119,958,798 EUA Companies Exhibit No. C-9 Page 4 of 5 Name of Respondent Eastern Edison Company At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 46 DEFERRED CREDITS 47 Customer Advances for Construction (252) 48 Accumulated Deferred Investment Tax Credits (255) 3,385,727 3,385,727 49 Deferred Gains from Disposition of Utility Plant (256) 50 Other Deferred Credits (253) 1,094,191 1,094,191 51 Other Regulatory Liabilities (254) 6,202,507 6,202,507 52 Unamortized Gain on Reacquired Debt (257) 53 Accumulated Deferred Income Taxes (281-283) 24,822,963 24,822,963 54 TOTAL Deferred Credits (Enter Total of Lines 47 thru 35,505,388 35,505,388 53) 55 56 57 59 60 61 62 63 64 65 66 67 68 Total Liabilities and Other Credits (Enter Total of 570,068,102 570,068,102 Lines 14, 22,30,45, and 54) EUA Companies Exhibit No. C-9 Page 5 of 5 Name of Respondent Eastern Edison Company At September 30, 1998 SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND DEPLETION Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 239,866,645 239,866,645 4 Property Under Capital Leases 5 Plant Purchased or Sold 6 Completed Construction not Classified 7 Experimental Plant Unclassified 8 Total (Enter Total of lines 3 thru 7) 239,866,645 239,866,645 9 Leased to Others 10 Held for Future Use 11 Construction Work in Progress 6,724,868 6,724,868 12 Acquisition Adjustments 13 Total Utility Plant (Enter total of lines 8 thru 12) 246,591,513 246,591,513 14 Accum. Prov. for Depr., Amort., and Depl. 95,357,566 95,357,566 15 Net Utility Plant (Enter Total of line 13 less 14) 151,233,947 151,233,947 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In service: 18 Depreciation 95,357,566 95,357,566 19 Amort. and Depl. of Producing Natural Gas & Land Rights 20 Amort. of Underground Storage Land and Land Rights 21 Amort. of Other Utility Plant 22 TOTAL In Service (Enter Total of lines 18 thru 21) 95,357,566 95,357,566 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Enter Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (Enter Total of lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amort. of Plant Acquisition Adj. 33 Total Accumulated Provisions (Should agree with line 14 above) (Enter Total of lines 22, 26, 30, 31 and 32) 95,357,566 95,357,566
EUA Companies Exhibit No. C-10 Page 1 of 5 Name of Respondent Newport Electric Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 82,995,307 82,995,307 3 Construction Work in Progress (107) 1,353,158 1,353,158 4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 84,348,465 84,348,465 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 29,066,441 29,066,441 6 Net Utility Plant (Enter Total of line 4 Less 5) 55,282,024 55,282,024 7 Nuclear Fuel (120.1-120.4, 120.6) 8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies (120.5) 9 Net Nuclear Fuel (Enter Total of line 7 less 8) 10 Net Utility Plant (Enter Total of lines 6 and 9) 55,282,024 55,282,024 11 Utility Plant Adjustments (116) 12 Gas Stored Underground-Noncurrent (117) 13 OTHER PROPERTY AND INVESTMENTS 14 Nonutility Property (121) 15 (Less) Accum. Prov. for Depr. and Amort. (122) 16 Investments in Associated Companies (123) 17 Investment in Subsidiary Companies (123.1) 18 (For Cost of Account 123.1, See Footnote Page 224, Line 42) 19 Noncurrent Portion of Allowances 20 Other Investments (124) 21 Special Funds (125-128) 22 TOTAL Other Property and Investments (Total of lines 14-17, 19-21) 23 CURRENT AND ACCRUED ASSETS 24 Cash (131) 269,892 269,892 25 Special Deposits (132-134) 26 Working Fund (135) 4,740 4,740 27 Temporary Cash Investments (136) 28 Notes Receivable (141) 29 Customer Accounts Receivable (142) 4,885,295 4,885,295 30 Other Accounts Receivable (143) 2,719,166 2,719,166 31 (Less) Accum. Prov. Uncollectible Acct.-Credit (144) 100,768 100,768 32 Notes Receivable from Associated Companies (145) 33 Accounts Receivable from Assoc. Companies (146) 261,182 261,182 34 Fuel Stock (151) 53,017 53,017 35 Fuel Stock Expenses Undistributed (152) 36 Residuals (Elec) and Extracted Products (153) 37 Plant Materials and Operating Supplies (154) 795,183 795,183 38 Merchandise (155) 39 Other Materials and Supplies (156) 40 Nuclear Materials Held for Sale (157) 41 Allowances (158.1 and 158.2) 42 (Less) Noncurrent Portion of Allowances 43 Stores Expense Undistributed (163) 57,108 57,108 44 Gas Stored Underground-Current (164.1) 45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 46 Prepayments (165) 111,097 111,097 47 Advances for Gas (166-167) 48 Interest and Dividends Receivable (171) 49 Rents Receivable (172) 50 Accrued Utility Revenues (173) 1,245,890 1,245,890 51 Miscellaneous Current and Accrued Assets (174) 134,354 134,354 52 TOTAL Current and Accrued Assets ( Enter Total of lines 24 thru 51) 10,436,156 10,436,156 EUA Companies Exhibit No. C-10 Page 2 of 5 Name of Respondent Newport Electric Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 53 DEFERRED DEBITS 54 Unamortized Debt Expenses (181) 371,814 371,814 55 Extraordinary Property Losses (182.1) 56 Unrecovered Plant and Regulatory Study Costs (182.2) 57 Other Regulatory Assets (182.3) 4,109,449 4,109,449 58 Prelim. Survey and Investigation Charges (Electric) (183) 59 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2) 60 Clearing Accounts (184) (465) (465) 61 Temporary Facilities (185) 62 Miscellaneous Deferred Debits (186) 1,022,224 1,022,224 63 Def. Losses from Disposition of Utility Plt. (187) 64 Research, Devel. and Demonstration Expend. (188) 65 Unamortized Loss on Reacquired Debt (189) 285,162 285,162 66 Accumulated Deferred Income Taxes (190) 714,543 714,543 67 Unrecovered Purchased Gas Costs (191) 68 TOTAL Deferred Debits (Enter Total of lines 54 thru 67) 6,502,727 6,502,727 69 TOTAL Assets and other Debits (Enter Total of lines 10, 11, 12, 22, 52, and 68) 72,220,907 72,220,907 EUA Companies Exhibit No. C-10 Page 3 of 5 Name of Respondent Newport Electric Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 PROPRIETARY CAPITAL 2 Common Stock Issued (201) 11,368,779 11,368,779 3 Preferred Stock Issued (204) 768,900 768,900 4 Capital Stock Subscribed (202, 205) 5 Stock Liability for Conversion (203, 206) 6 Premium on Capital Stock (207) 7 Other Paid-in Capital (208-211) 9,002,150 9,002,150 8 Installments Received on Capital Stock (212) 9 (Less) Discount on Capital Stock (213) 10 (Less) Capital Stock Expense (214) 742,214 742,214 11 Retained Earnings (215, 215.1, 216) 3,248,396 3,248,396 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 13 (Less) Reacquired Capital Stock (217) 14 TOTAL Proprietary Capital (Enter Total of Lines 2 thru 13) 23,646,011 23,646,011 15 LONG-TERM DEBT 16 Bonds (221) 19,816,516 19,816,516 17 (Less) Reacquired Bonds (222) 18 Advances from Associated Companies (223) 19 Other Long-Term Debt (224) 20 Unamortized Premium on Long-Term Debt (225) 21 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 22 TOTAL Long-Term Debt (Enter Total of Lines 16 thru 21) 19,816,516 19,816,516 23 OTHER NONCURRENT LIABILITIES 24 Obligations Under Capital Leases-Noncurrent (227) 25 Accumulated Provision for Property Insurance (228.1) 26 Accumulated Provision for Injuries and Damages (228.2) 27 Accumulated Provision for Pensions and Benefits (228.3) 28 Accumulated Miscellaneous Operating Provisions (228.4) 29 Accumulated Provision for Rate Refunds (229) 30 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29) 31 CURRENT AND ACCRUED LIABILITIES 32 Note Payable (231) 5,120,000 5,120,000 33 Accounts Payable (232) 127,057 127,057 34 Notes Payable to Associated Companies (233) 35 Accounts Payable to Associated Companies (234) 7,019,840 7,019,840 36 Customer Deposits (235) 577,209 577,209 37 Taxes Accrued (236) 586,675 586,675 38 Interest Accrued (237) 218,317 218,317 39 Dividends Declared (238) 7,208 7,208 40 Matured Long-Term Debt (239) 41 Matured Interest (240) 42 Tax Collections Payable (241) 121,652 121,652 43 Miscellaneous Current and Accrued Liabilities (242) 951,242 951,242 44 Obligations Under Capital Leases - Current (243) 45 TOTAL Current and Accrued Liabilities (Enter Total of lines 32 thru 44) 14,729,200 14,729,200 EUA Companies Exhibit No. C-10 Page 4 of 5 Name of Respondent Newport Electric Corporation At September 30, 1998 COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued) Adjusted Line Title of Account Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 46 DEFERRED CREDITS 47 Customer Advances for Construction (252) 48 Accumulated Deferred Investment Tax Credits (255) 1,060,284 1,060,284 49 Deferred Gains from Disposition of Utility Plant (256) 50 Other Deferred Credits (253) 1,524,300 1,524,300 51 Other Regulatory Liabilities (254) 1,268,555 1,268,555 52 Unamortized Gain on Reacquired Debt (257) 53 Accumulated Deferred Income Taxes (281-283) 10,176,041 10,176,041 54 TOTAL Deferred Credits (Enter Total of Lines 47 thru 53) 14,029,180 14,029,180 55 56 57 59 60 61 62 63 64 65 66 67 68 Total Liabilities and Other Credits (Enter Total of 72,220,907 72,220,907 Lines 14, 22,30,45, and 54) EUA Companies Exhibit No. C-10 Page 5 of 5 Name of Respondent Newport Electric Corporation At September 30, 1998 SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND DEPLETION Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 82,779,252 82,779,252 4 Property Under Capital Leases 5 Plant Purchased or Sold 6 Completed Construction not Classified 7 Experimental Plant Unclassified 8 Total (Enter Total of lines 3 thru 7) 82,779,252 82,779,252 9 Leased to Others 10 Held for Future Use 216,055 216,055 11 Construction Work in Progress 1,353,158 1,353,158 12 Acquisition Adjustments 13 Total Utility Plant (Enter total of lines 8 thru 12) 84,348,465 84,348,465 14 Accum. Prov. for Depr., Amort., and Depl. 29,066,441 29,066,441 15 Net Utility Plant (Enter Total of line 13 less 14) 55,282,024 55,282,024 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In service: 18 Depreciation 28,721,895 28,721,895 19 Amort. and Depl. of Producing Natural Gas & Land Rights 20 Amort. of Underground Storage Land and Land Rights 21 Amort. of Other Utility Plant 344,546 344,546 22 TOTAL In Service (Enter Total of lines 18 thru 21) 29,066,441 29,066,441 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Enter Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (Enter Total of lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amort. of Plant Acquisition Adj. 33 Total Accumulated Provisions (Should agree with line 14 above) (Enter Total of lines 22, 26, 30, 31 and 32) 29,066,441 29,066,441
JOINT APPLICATION OF NEW ENGLAND POWER COMPANY, et al. AND MONTAUP ELECTRIC COMPANY, et al. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT D-1 New England Power Company EXHIBIT D-2 Massachusetts Electric Company EXHIBIT D-3 The Narragansett Electric Company EXHIBIT D-4 New England Electric Transmission Corporation EXHIBIT D-5 New England Hydro Transmission Corporation EXHIBIT D-6 New England Hydro - Transmission Electric Company, Inc. EXHIBIT D-7 Montaup Electric Company EXHIBIT D-8 Blackstone Valley Electric Company EXHIBIT D-9 Eastern Edison Company EXHIBIT D-10 Newport Electric Corporation Statement of all Known Contingent Liabilities EXHIBIT D-1 Page 1 of 9 NEW ENGLAND POWER COMPANY Statement of all Known Contingent Liabilities Note A - Hazardous Waste - ------------------------ The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. New England Power Company (the Company) currently has in place an internal environmental audit program and an external waste disposal vendor audit and qualification program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for six sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The Company is currently aware of other possible hazardous waste sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. The New England Electric System (NEES) companies have recovered amounts from certain insurers and other third parties, and, where appropriate, the Company intends to seek recovery from other insurers and from other PRPs, but it is uncertain whether, and to what extent, such efforts will be successful. The Company believes that hazardous waste liabilities for all sites of which it is aware are not material to its financial position. EXHIBIT D-1 Page 2 of 9 NEW ENGLAND POWER COMPANY Statement of all Known Contingent Liabilities Note B - Nuclear Units - ---------------------- Yankee Nuclear Power Companies (Yankees) A summary of combined results of operations, assets and liabilities of the four Yankee Nuclear Power Companies in which the Company has investments is as follows:
Twelve Months Ended September 30, ---------------------------- 1998 1997 ---- ---- (In Thousands) Operating revenue $480,305 $767,441 -------- -------- Net Income $ 29,194 $ 29,594 -------- -------- Company's equity in net income $ 5,467 $ 4,898 -------- -------- September 30, September 30, 1998 1997 ---- ---- (In Thousands) Net plant $ 177,372 $ 420,918 Other assets 2,958,662 2,225,214 Liabilities and debt (2,875,214) (2,374,643) ------------ ------------ Net assets $ 260,820 $ 271,489 ------------ ------------ Company's equity in $ 48,203 $ 50,370 net assets ------------ ------------
At September 30, 1998, $14,259,000 of undistributed earnings of the nuclear power companies were included in the Company's retained earnings. EXHIBIT D-1 Page 3 of 9 NEW ENGLAND POWER COMPANY Statement of all Known Contingent Liabilities Note B - Nuclear Units - continued - ---------------------- Nuclear Units Permanently Shut Down Three regional nuclear generating companies in which the Company has a minority interest own nuclear generating units which have been permanently shut down. These three units are as follows:
NEP's Investment Future Estimated Unit Percent Amount($) Date Retired Billings to NEP($) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yankee Atomic 30 6 million Feb 1992 33 million Connecticut Yankee 15 15 million Dec 1996 83 million Maine Yankee 20 16 million Aug 1997 145 million - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
In the case of each of these units, the Company has recorded an estimate of the total future payment obligation as a liability and an offsetting regulatory asset, reflecting estimated future billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant as well as unfunded nuclear decommissioning costs and other costs. The Company's industry restructuring settlements allow it to recover all costs that the FERC allows these Yankee companies to bill to the Company. Connecticut Yankee and Maine Yankee have both filed similar requests with the FERC. Several parties have intervened in opposition to both filings. On August 31, 1998, a FERC Administrative Law Judge (ALJ) issued an initial decision which would allow for full recovery of Connecticut Yankee's unrecovered investment, but precluded a return on that investment. The ALJ's initial decision is subject to review and approval by the FERC. Connecticut Yankee, the Company, and other parties have filed exceptions to the ALJ's decision with the FERC. Should the FERC uphold the ALJ's initial decision in its current form, the Company's share of the loss of the return component would total approximately $12 million to $15 million before taxes. The Citizen's Awareness Network and Nuclear Information and Resource Service have indicated their intention to file a request with the Nuclear Regulatory commission (NRC) designed to overturn a current NRC rule on decommissioning. The Company cannot predict what impact, if any, these activities, if successful, would have on the cost of decommissioning the plants. EXHIBIT D-1 Page 4 of 9 NEW ENGLAND POWER COMPANY Statement of all Known Contingent Liabilities Note B - Nuclear Units - continued - ---------------------- At Main Yankee, the NRC issued a notice of violation on October 8, 1998 for issues identified prior to the shut down of the plant in August 1997. The NRC did not assess any civil penalties related to the notice of violation. In the 1970s, the Company and several other shareholders (Sponsors) of Maine Yankee entered into 27 contracts (Secondary Purchase Agreements) under which they sold portions of their entitlements to Maine Yankee power output through 2002 to various entities, primarily municipal and cooperative systems in New England (Secondary Purchasers). Virtually all of the Secondary Purchasers have ceased making payments under the Secondary Purchase Agreements and have demanded arbitration, claiming that such agreements excuse further payments upon plant shutdown. The motion of the Secondary Purchasers to compel arbitration was denied by the Maine Superior Court on the grounds that the FERC has jurisdiction. The Secondary Purchasers are appealing this decision to the Maine Supreme Judicial Court. The Company has asked the FERC to enforce the Company's rights under the agreements. In the event that no further payments are forthcoming from Secondary Purchasers, the Company, as a primary obligor to Maine Yankee, would be required to pay an additional $7 million of future shutdown costs. These costs are not included in the $145 million estimate disclosed in the table above. Shutdown costs are recoverable from customers under the industry restructuring settlements. A Maine statute provides that if both Maine Yankee and its decommissioning trust fund have insufficient assets to pay for the plant decommissioning, the owners of Maine Yankee are jointly and severally liable for the shortfall. Operating Nuclear Units The Company has minority interests in three other nuclear generating units, Vermont Yankee, Millstone 3, and Seabrook 1. Uncertainties regarding the future of nuclear generating stations, particularly older units, such as Vermont Yankee, are increasing rapidly and could adversely affect their service lives, availability, and costs. These uncertainties stem from a combination of factors, including the acceleration of competitive pressures in the power generation industry and increased NRC scrutiny. The company performs periodic economic viability reviews of operating nuclear units in which it holds ownership interests. EXHIBIT D-1 Page 5 of 9 NEW ENGLAND POWER COMPANY Statement of all Known Contingent Liabilities Note B - Nuclear Units - continued - ---------------------- Millstone 3 In April 1996, the NRC ordered Millstone 3, which had experienced numerous technical and nontechnical problems, to shut down pending verification that the unit's operations were in accordance with NRC regulations and the unit's operating license. In July 1998, Millstone 3 returned to full operation. Millstone 3 remains on the NRC "Watch List," signifying that it continues to warrant increased NRC attention. Millstone 3 is operated by a subsidiary of Northeast Utilities (NU). The Company is not an owner of the Millstone 2 nuclear generating unit, which is temporarily shut down under NRC orders, or the Millstone 1 nuclear generating unit, which has been permanently shut down. During the Millstone 3 outage, the Company incurred an estimated $45 million in incremental replacement power costs. Through February 1998, when most of the Company's power sales were subject to a fuel clause, the Company recovered its incremental replacement power costs from customers through its fuel clause. Starting in March 1998, most of the Company's power sales are at a stated rate which is not subject to a fuel clause. However, certain true-up mechanisms exist in lieu of the fuel clause, which cover most of these costs. Several criminal investigations related to Millstone 3 are ongoing. In December 1997, the NRC assessed civil penalties totaling $2.1 million for numerous violations at the three Millstone units. The Company's share of this fine was less than $100,000. On September 24, 1998, NU, the Connecticut Department of Environmental Protection and the Connecticut Attorney General reached a stipulated agreement for alleged wastewater discharge violations at the Millstone units. As part of the agreement, NU will pay a civil penalty of $700,000, and an additional $500,000 to fund three environmental projects. The Company's share of this fine will be immaterial. EXHIBIT D-1 Page 6 of 9 NEW ENGLAND POWER COMPANY Statement of all Known Contingent Liabilities Note B - Nuclear Units - continued - ---------------------- In August 1997, the Company sued NU in Massachusetts Superior Court for damages resulting from the tortious conduct of NU that caused the shutdown of Millstone 3. The Company's damages include the costs of replacement power during the outage and costs necessary to return Millstone 3 to safe operation. The Company also seeks punitive damages. The Company also sent a demand for arbitration to Connecticut Light & Power Company (CL&P) and Western Massachusetts Electric Company (WMEC), both subsidiaries of NU, seeking damages resulting from their breach of obligations under an agreement with the Company and others regarding the operation and ownership of Millstone 3. The arbitration is scheduled for October 1999. NU moved to dismiss the Company's suit, or, in the alternative, stay the suit pending arbitration of the Company's claims against CL&P and WMEC. NU also moved to consolidate the Company's suit with suits filed by other joint owners in Massachusetts Superior Court. On July 3, 1998, the court denied NU's motion to dismiss and its motion to stay pending arbitration. On July 21, 1998, the Company amended its complaint by, among other things, adding NU's Trustees as defendants. The Worcester Superior Court granted the Company's motion for a trial in June 1999, subject to revision if the cases are consolidated. No ruling has been made on NU's motion to consolidate. Nuclear Decommissioning In New Hampshire, legislation was recently enacted which makes owners of Seabrook 1, of which the Company owns a 10 percent interest, proportional guarantors for decommissioning costs in the event that an owner without a franchise service territory fails to fund its share of decommissioning costs. Currently, a single owner of an approximate 12 percent share of Seabrook 1 has no franchise service territory. For more information on nuclear decommissioning, refer to the Company's Annual Report on Form 10-K for 1997. The New Hampshire Nuclear Decommissioning Finance Committee is reviewing Seabrook Station's decommissioning estimate and associated annual funding levels. Among the items being considered is the imposition of joint and several liability among the Seabrook joint owners for decommissioning funding. The Company cannot predict what additional liability, if any, may be imposed on it. EXHIBIT D-1 Page 7 of 9 NEW ENGLAND POWER COMPANY Statement of all Known Contingent Liabilities Note B - Nuclear Units - continued - ---------------------- The Nuclear Waste Policy Act of 1982 establishes that the federal government (through the Department of Energy (DOE)) is responsible for the disposal of spent nuclear fuel. The federal government requires the Company to pay a fee based on its share of the net generation from the Millstone 3 and Seabrook 1 nuclear units. Through February 1998, the company recovered this fee through its fuel clause. Subsequently, most of these costs are recovered through the Company's restructuring settlement in lieu of the fuel clause. Similar costs are incurred by the Vermont Yankee nuclear generating unit. These costs are billed to the Company and also recovered from customers through the same mechanism. In November 1997, ruling on a lawsuit brought against the DOE by numerous utilities and state regulatory commissions, the Court of Appeals for the District of Columbia (the Appeals Court) held that the DOE was obligated to begin disposing of utilities' spent nuclear fuel by January 31, 1998. The DOE failed to meet this deadline, and is not scheduled to have a temporary or permanent repository for spent nuclear fuel for several years. In February 1998, Maine Yankee petitioned the Appeals Court to compel the DOE to remove Maine Yankee's spent fuel from the site. In May 1998, the Appeals Court rejected the petitions of Maine Yankee and the other utilities and state regulatory commissions stating that the issue of damages was a contractual matter. The operators of the units in which the Company has an obligation, including Maine Yankee, Connecticut Yankee, and Yankee Atomic, continue to pursue damage claims against the DOE in the Federal Court of Claims (Claims Court). On October 30, 1998, the Claims Court ruled that the DOE violated a commitment to remove spent fuel from Yankee Atomic. The Claims Court issued similar rulings in November 1998 related to cases brought by Connecticut Yankee and Maine Yankee. Further proceedings will be scheduled by the Claims Court to decide the amount of damages. EXHIBIT D-1 Page 8 of 9 NEW ENGLAND POWER COMPANY Statement of all Known Contingent Liabilities Note C - Town of Norwood - ------------------------ On September 29, 1998, the United States District Court for the District Massachusetts dismissed the lawsuit filed by the Town of Norwood, Massachusetts against NEES and the Company in April 1997. The company had been a wholesale power supplier for Norwood pursuant to rates approved by the FERC. In the lawsuit, Norwood had alleged that the Company's divestiture of its power generating assets would violate the terms of a 1983 power contract. Norwood also alleged that the divestiture and recovery of stranded investment costs contravened federal antitrust laws. The District Court judge granted NEES' and the Company's motion for dismissal on the grounds that the contract did not require the Company to retain its generating units, that the FERC-approved filed rates govern these matters and that Norwood had adequate opportunity at the FERC to litigate these matters. Norwood has filed a motion to alter or amend the order of dismissal. In March 1998, Norwood gave notice of its intent to terminate its contract with the Company, without accepting responsibility for its share of the Company's stranded costs, and began taking power from another supplier commencing in April 1998. In May 1998, the FERC ruled that the Company could assess a contract termination charge to any of the Company's unaffiliated customers that choose to terminate their wholesale power contracts early. Norwood claimed that the contract termination charge approved by the FERC did not apply to Norwood; however, in denying Norwood's motion for rehearing, the FERC ruled that the charge did apply to Norwood. On October 2, 1998, Norwood appealed this decision to the First Circuit Court of Appeals (First Circuit). The Company's billings to Norwood for this charge through September 1998 have been approximately $4 million. Norwood has not paid any of these billings. The Company intends to pursue collection action to recover these amounts. Norwood appealed the FERC's orders approving the divestiture and the Massachusetts and Rhode Island industry restructuring settlement agreements (including modification of the Company's contracts with Massachusetts Electric and Narragansett Electric) to the First Circuit on July 31, 1998 and August 7, 1998, respectively. The FERC had found that the challenged orders do not apply to Norwood. EXHIBIT D-1 Page 9 of 9 NEW ENGLAND POWER COMPANY Statement of all Known Contingent Liabilities Note C - Town of Norwood - continued - ------------------------ On October 20, 1998, the First Circuit consolidated all three of Norwood's appeals from the FERC's orders. These consolidated appeals will likely be consolidated with two other appeals that were filed on August 6, 1998 with the Second Circuit Court of Appeals and transferred to the First Circuit on October 13, 1998. Both appeals, filed by the Northeast Center for Social Issue Studies, challenge the FERC's approval of the Company's sale of its hydroelectric facilities. Note D - Hydro-Quebec Arbitration - --------------------------------- In 1996, various New England utilities which are members of the New England Power Pool, including the Company, submitted a dispute to arbitration regarding their Firm Energy Purchased Power Contract with Hydro-Quebec. In June 1997, Hydro-Quebec presented a damage claim of approximately $37 million for past damages, of which the Company's share would have been approximately $6 million to $9 million. The claims involved a dispute over the components of a pricing formula and additional costs under the contract. With respect to ongoing claims, the Company paid Hydro-Quebec the higher amount (additional costs of approximately $3 million per year) from July 1996 until September 1, 1998 under protest and subject to refund. The contract was transferred to USGen on September 1, 1998 in conjunction with the sale of the nonnuclear generating business. In October 1997, an arbitrator ruled in favor of the New England utilities in all respects. Hydro-Quebec has not yet refunded any monies and has appealed the decision. In June 1998, the United States District Court (District Court) issued an order affirming the 1997 arbitration decision in favor of the Company and the other utilities. Hydro-Quebec is appealing this order to the Court of Appeals for the First Circuit. On July 31, 1998, in a separate proceeding, an arbitrator denied the request of the Company and other utilities that they be allowed to withhold payment of disputed amounts from Hydro-Quebec during the pendency of Hydro-Quebec's appeal. The Company and the other utilities have filed a petition with the District Court to vacate this decision, and Hydro-Quebec has petitioned the District Court to confirm it. EXHIBIT D-2 Page 1 of 2 MASSACHUSETTS ELECTRIC COMPANY Statement of all Known Contingent Liabilities Note A - Hazardous Waste - ------------------------ The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. Massachusetts Electric Company (the Company) currently has in place an internal environmental audit program and an external waste disposal vendor audit and qualification program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for 16 sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The most prevalent types of hazardous waste sites with which the Company has been associated are manufactured gas locations. (Until the early 1970's, New England Electrical System (NEES) was a combined electric and holding company system.) The Company is aware of approximately 35 such manufactured gas locations in Massachusetts. The Company has been identified as a PRP at eight of these manufactured gas locations, which are included in the 16 PRP sites discussed above. The Company is engaged in various phases of investigation and remediation work at 17 of the manufactured gas locations. The Company is currently aware of other possible locations. The Company is currently aware of other possible hazardous waste sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. In 1993, the Massachusetts Department of Public Utilities approved a settlement agreement regarding the rate recovery of remediation costs of former manufactured gas sites and certain other hazardous waste sites located in Massachusetts. Under that agreement, qualified remedial costs related to these sites are paid out of a special fund established on the Company's books. The Company made an initial $30 million contribution to the fund. Rate-recoverable contributions of $3 million, adjusted since 1993 for inflation, are added annually to the fund along with interest and any recoveries from insurance carriers and other third parties. At September 30, 1998, the fund had a balance of $46 million. EXHIBIT D-2 Page 2 of 2 MASSACHUSETTS ELECTRIC COMPANY Statement of all Known Contingent Liabilities Note A - Hazardous Waste - continued - ------------------------ Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. The NEES companies have recovered amounts from certain insurers and other third parties, and, where appropriate, the Company intends to seek recovery from other insurers and from other PRPs, but it is uncertain whether, and to what extent, such efforts will be successful. At September 30, 1998, the Company had total reserves for environmental response costs of $47 million. This represents an increase from the $35 million balance at the end of 1997. Since all of the sites for which increased reserves were recognized are covered by rate agreements, this increase in the reserves did not have an adverse effect on net income. The Company believes that hazardous waste liabilities for all sites of which it is aware, and which are not covered by a rate agreement, are not material to its financial position. EXHIBIT D-3 Page 1 of 1 THE NARRAGANSETT ELECTRIC COMPANY Statement of all Known Contingent Liabilities Note A - Hazardous Waste - ------------------------ The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. The Narragansett Electric Company (the Company) currently has in place an internal environmental audit program and an external waste disposal vendor audit and qualification program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for three sites (two of which are located in Massachusetts) at which hazardous waste is alleged to have been disposed. The Company is currently aware of other possible hazardous waste sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. Gas was manufactured from coal in Rhode Island in the past. The Company is aware of five sites on which gas was manufactured or manufactured gas was stored that were owned either by the Company or by its predecessor companies. It is not known to what extent the Company would be held liable for hazardous wastes, if any, left at these manufactured gas locations. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. A preliminary review by a consultant hired by the New England Electric System (NEES) companies of the potential cost of investigating and, if necessary, remediating Rhode Island manufactured gas sites resulted in costs per site ranging from less than $1 million to $11 million. An informal survey of other utilities conducted on behalf of NEES and its subsidiaries indicated costs in a similar range. The NEES companies have recovered amounts from certain insurers and other third parties, and, where appropriate, the Company intends to seek recovery from other insurers and from other PRPs, but it is uncertain whether, and to what extent, such efforts will be successful. The Company believes that hazardous waste liabilities for all sites of which it is aware are not material to its financial position. EXHIBIT D-4 NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION No known contingent liabilities EXHIBIT D-5 NEW ENGLAND HYDRO TRANSMISSION CORPORATION No known contingent liabilities EXHIBIT D-6 NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. No known contingent liabilities EXHIBIT D-7 Page 1 of 5 MONTAUP ELECTRIC COMPANY Statement of all Known Contingent Liabilities Note A - Nuclear Fuel Disposal and Nuclear Decommissioning Costs - ---------------------------------------------------------------- The owners (or lead participants) of the nuclear units in which Montaup has an interest have made, or expect to make, various arrangements for the acquisition of uranium concentrate, the conversion, enrichment, fabrication and utilization of nuclear fuel and the disposition of that fuel after use. The owners (or lead participants) of United States nuclear units have entered into contracts with the Department of Energy (DOE) for disposal of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982 (NWPA). The NWPA requires (subject to various contingencies) that the federal government design, license, construct and operate a permanent repository for high level radioactive wastes and spent nuclear fuel and establish a prescribed fee for the disposal of such wastes and nuclear fuel. The NWPA specifies that the DOE provide for the disposal of such waste and spent nuclear fuel starting in 1998. Objections on environmental and other grounds have been asserted against proposals for storage as well as disposal of spent nuclear fuel. The DOE now estimates that a permanent disposal site for spent fuel will not be ready to accept fuel for storage or disposal until as late as the year 2010. In early 1998, a number of utilities filed suit in federal appeals court seeking, among other things, an order requiring the DOE to immediately establish a program for the disposal of spent nuclear fuel. Montaup owns a 4.01% interest in Millstone 3 and a 2.9% interest in Seabrook I. Northeast Utilities, the operator of the units, indicates that Millstone 3 has sufficient on-site storage facilities which, with rack additions, can accommodate its spent fuel for the projected life of the unit. At the Seabrook Project, there is on-site storage capacity which, with rack additions, will be sufficient to at least the year 2011. The Energy Policy Act of 1992 requires that a fund be created for the decommissioning and decontamination of the DOE uranium enrichment facilities. The fund will be financed in part by special assessments on nuclear power plants in which Montaup has an interest. These assessments are calculated based on the utilities' prior use of the government facilities and have been levied by the DOE, starting in September 1993, and will continue over 15 years. This cost is passed on to the joint owners or power buyers as an additional fuel charge on a monthly basis and is currently being recovered by Montaup through rates. EXHIBIT D-7 Page 2 of 5 MONTAUP ELECTRIC COMPANY Statement of all Known Contingent Liabilities Note A - Nuclear Fuel Disposal and Nuclear - ------------------------------------------ Decommissioning Costs - continued --------------------- Montaup has a 4.5% equity ownership in Connecticut Yankee, a nuclear generating facility which is in the process of decommissioning. Montaup's share of the total estimated costs for the permanent shutdown, decommissioning and recovery of the investment in Connecticut Yankee is approximately $23.8 million. On August 31, 1998, a FERC law judge rejected Connecticut Yankee's filed plan to decommission the plant. The judge claimed that estimates of clean-up costs were flawed and certain restoration costs were not supported. The judge also said Connecticut Yankee could not pass on spent fuel storage costs to rate-payers. The judge recommended that Connecticut Yankee withdraw its decommissioning plan and submit a new plan which addresses the issues cited by him. FERC will review the judge's recommendation and issue a decision on this case in the coming months. If FERC concurs with the judge's recommendation, this may result in a write down of certain of Connecticut Yankee plant investments. In August 1997, as a result of an economic evaluation, the Maine Yankee Board of Directors voted to permanently close that nuclear plant. Montaup has a 4.0% equity ownership in Maine Yankee. Montaup's share of the total estimated costs for the permanent shutdown, decommissioning and recovery of the remaining investment in Maine Yankee is approximately $31.0 million. In January 1998, FERC accepted Maine Yankee's rate filing, subject to refund, for the recovery of its costs during the decommissioning period. Also, Montaup is recovering through rates its share of estimated decommissioning costs for Millstone 3 and Seabrook I. Montaup's share of the current estimate of total costs to decommission Millstone 3 is $22.4 million in 1998 dollars, and Seabrook I is $14.4 million in 1998 dollars. These figures are based on studies performed for the lead owner of the units. Montaup also pays into decommissioning reserves pursuant to contractual arrangements with other nuclear generating facilities in which it has an equity ownership interest or life of the unit entitlement. Such expenses are currently recoverable through rates. EXHIBIT D-7 Page 3 of 5 MONTAUP ELECTRIC COMPANY Statement of all Known Contingent Liabilities Note B - Environmental Matters - ------------------------------ There is an extensive body of federal and state statutes governing environmental matters, which permit, among other things, federal and state authorities to initiate legal action providing for liability, compensation, cleanup, and emergency response to the release or threatened release of hazardous substances into the environment and for the cleanup of inactive hazardous waste disposal sites which constitute substantial hazards. Because of the nature of Montaup's business, various by-products and substances are produced or handled which are classified as hazardous under the rules and regulations promulgated by the United States Environmental Protection Agency (EPA) as well as state and local authorities. The Company generally provides for the disposal of such substances through licensed contractors, but these statutory provisions generally impose potential joint and several responsibility on the generators of the wastes for cleanup costs. In the past, Montaup had been notified with respect to a number of sites where they were allegedly responsible for such costs, including sites where they allegedly had joint and several liability with other responsible parties. Montaup is currently not involved in any environmental site investigation. It is the policy of Montaup to notify liability insurers and to initiate claims. The Company is unable to predict whether liability, if any, will be assumed by, or can be enforced against, the insurance carriers in these matters. The costs incurred in connection with these sites have been financed primarily with internally generated cash. The Clean Air Act Amendments created new regulatory programs and generally updated and strengthened air pollution control laws. These amendments expanded the regulatory role of the EPA regarding emissions from electric generating facilities and a host of other sources. Montaup generating facilities were first affected in 1995, when EPA regulations took effect for facilities owned by Montaup. Montaup's coal-fired Somerset Unit No. 6 is utilizing lower sulfur content coal to meet the 1995 air standards. Eastern Edison does not anticipate the impact from the Amendments to be material to its financial position. EXHIBIT D-7 Page 4 of 5 MONTAUP ELECTRIC COMPANY Statement of all Known Contingent Liabilities Note B - Environmental Matters - continued - ------------------------------ In July, the EPA issued a new and more stringent rule covering ozone particulate matter which is to be followed by promulgation of more stringent ozone and particulate matter standards. The effect that such standards will have on the EUA System cannot be determined by management at this time. Montaup and the Massachusetts Attorney General and Division of Energy Resources entered into a settlement regarding electric utility industry restructuring in Massachusetts. The settlement includes a plan for emissions reductions related to Montaup's Somerset Station Units 5 and 6, and to Montaup's 50% ownership share of Canal Electric's Unit 2. The basis for sulfur dioxide (SO2) and nitrogen oxide (NOx) emission reductions in the proposed settlement is an allowance cap calculation. Montaup may meet its allowance caps by any combination of control technologies, fuel switching, operational changes, and/or the use of purchased or surplus allowances. The proposed settlement was approved by FERC on December 19, 1997. In April 1992, the Northeast States for Coordinated Air Use Management (NESCAUM), an environmental advisory group for eight Northeast states including Massachusetts and Rhode Island issued recommendations for NOx controls for existing utility boilers required to meet the ozone non-attainment requirements of the Clean Air Act. The NESCAUM recommendations are more restrictive than the Clean Air Act requirements. The Massachusetts Department of Environmental Management has amended its regulations to require that Reasonably Available Control Technology (RACT) be implemented at all stationary sources potentially emitting 50 tons or more per year of NOx. Similar regulations have been issued in Rhode Island. Montaup has initiated compliance, through, among other things, selective, noncatalytic reduction processes. A number of scientific studies in the past several years have examined the possibility of health effects from EMF that are found wherever there is electricity. While some of the studies have indicated some association between exposure to EMF and health effects, many others have indicated no direct association. Some states have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. Rhode Island has enacted a statute which authorizes and directs the Energy Facility Siting Board to establish rules and regulations governing construction of high voltage transmission lines of 69kv or more. Management cannot predict the ultimate outcome of the EMF issue. EXHIBIT D-7 Page 5 of 5 MONTAUP ELECTRIC COMPANY Statement of all Known Contingent Liabilities Note C - Other - -------------- Since early 1997, fourteen plaintiffs brought suit against numerous defendants, including EUA, for injuries and illness all allegedly caused by exposure to asbestos over approximately a thirty-year period, at premises, including some owned by EUA companies. The total damages claimed in all of these complaints was $34 million in compensatory and punitive damages, plus exemplary damages and interest and costs. Each names between fifteen and twenty-eight defendants, including EUA. These complaints have been referred to the applicable insurance companies. Counsel has been retained by the insurers and is actively defending all cases. Four cases have been dismissed as against EUA companies. EUA cannot predict the ultimate outcome of this matter at this time. EXHIBIT D-8 Page 1 of 4 BLACKSTONE VALLEY ELECTRIC Statement of all Known Contingent Liabilities Note A - Environmental Matters - ------------------------------- The Comprehensive Environmental Response, Compensation Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, and certain similar state statutes authorize various governmental authorities to seek court orders compelling responsible parties to take cleanup action at disposal sites which have been determined by such governmental authorities to present an imminent and substantial danger to the public and to the environment because of an actual or threatened release of hazardous substances. Because of the nature of Blackstone's business, various by-products and substances are produced or handled which are classified as hazardous under the rules and regulations promulgated by the EPA as well as state and local authorities. Blackstone generally provides for the disposal of such substances through licensed contractors, but these statutory provisions generally impose potential joint and several responsibility on the generators of the wastes for cleanup costs. Blackstone has been notified with respect to a number of sites where they may be responsible for such costs, including sites where they may have joint and several liability with other responsible parties. It is the policy of Blackstone to notify liability insurers and to initiate claims. However, it is not possible at this time to predict whether liability, if any, will be assumed by, or can be enforced against, the insurance carriers in these matters. On December 13, 1994, the United States District Court for the District of Massachusetts (District Court) issued a judgment against Blackstone, finding Blackstone liable to the Commonwealth of Massachusetts (commonwealth) for the full amount of response costs incurred by the Commonwealth in the cleanup of a by-product of manufactured gas at a site at Mendon Road in Attleboro, Massachusetts. The judgment also found Blackstone liable for interest and litigation expenses calculated to the date of judgment. The total liability is approximately $5.9 million, including approximately $3.6 million in interest which has accumulated since 1985. Due to the uncertainty of the ultimate outcome of this proceeding and anticipated recoverability, Blackstone recorded the $5.9 million District Court judgment as a deferred debit. This amount is included with Other Assets on the Balance Sheet at December 31, 1997 and 1996. EXHIBIT D-8 Page 2 of 4 BLACKSTONE VALLEY ELECTRIC Statement of all Known Contingent Liabilities Note A - Environmental Matters - continued - ------------------------------ On January 20, 1995, Blackstone entered into an escrow agreement with the Commonwealth whereby Blackstone deposited $5.9 million with an escrow agent who transferred the funds into an interest bearing money market account. The distribution of the proceeds of the escrow account will be determined upon the final resolution of the judgment. No additional interest expense will accrue on the judgment amount. Blackstone filed a Notice of Appeal of the District Court's judgment and filed its brief with the United States Court of Appeals for the First Circuit (Circuit Court) on February 24, 1995. On October 6, 1995, the Circuit Court vacated the District Court's $5.9 million judgement to refer the matter to the EPA to determine whether the chemical substance ferric ferrocyanide (FFC) contained within the by-product is a hazardous substance. Given the present posture of the case, Blackstone may not be liable to reimburse the Commonwealth for the Mendon Road cleanup costs if the EPA determines that FFC is not a hazardous substance. On January 9, 1997, Blackstone met with representatives of EPA and the Commonwealth to discuss the procedure EPA would follow in resolving the FFC issue. In January 1997, Blackstone submitted written comments which were followed by the Commonwealth's written reply in March 1997. Both parties submitted additional memoranda to EPA during remainder of the year. The EPA will now determine whether FFC is a hazardous substance. Further court proceedings are likely. On January 28, 1994, Blackstone filed a complaint in the Massachusetts District court, seeking, among other relief, contribution and reimbursement from Stone & Webster Inc., of New York City and several of its affiliated companies (Stone & Webster), and Valley Gas Company of Cumberland, Rhode Island (Valley) for any damages incurred by Blackstone regarding the Mendon Road site. On November 7, 1994, the Court denied motions to dismiss the complaint filed by Stone & Webster and Valley. This proceeding was stayed in December 1995 pending final EPA determination as to whether FFC is a hazardous substance. EXHIBIT D-8 Page 3 of 4 BLACKSTONE VALLEY ELECTRIC Statement of all Known Contingent Liabilities Note A - Environmental Matters - continued - ------------------------------ In addition, Blackstone has notified certain liability insurers and has filed claims with respect to the Mendon Road site, as well as other sites. Blackstone reached settlement with one carrier for reimbursement of legal costs related to the Mendon Road case. In January 1996, Blackstone received the proceeds of the settlement. As of December 31, 1998, Blackstone had incurred costs of approximately $6.7 million (excluding the $5.9 million Mendon Road judgment) in connection with the investigation and cleanup of these sites. These amounts have been financed primarily by internally generated cash. Blackstone is currently amortizing all of its incurred costs over a five-year period consistent with prior regulatory recovery periods and is recovering certain of those costs in rates. The Company estimates that additional costs of up to approximately $1.8 million (excluding the $5.9 million Mendon Road judgment) may be incurred at these sites through 1999 by it and the other responsible parties. Estimated amounts after 1999 are not now determinable since site studies, which are the basis of these estimates, have not been completed. As a result of the recoverability of cleanup costs in rates and the uncertainly regarding both its estimated liability, as well as potential contributions from insurance carriers and other responsible parties, Blackstone does not believe that the ultimate impact of the environmental costs will be material to its financial position and thus, no loss provision is required at this time. A number of scientific studies in the past several years have examined the possibility of health effects from electric and magnetic fields (EMF) that are found wherever there is electricity. While some of the studies have indicated some association between exposure to EMF and health effects, many others have indicated no direct association. Some states have enacted regulations to limit the strength of EMF at the edge of transmission line rights-of-way. The Rhode Island legislature has enacted a statute which authorizes and directs the Rhode Island Energy Facility Siting Board to establish rules and regulations governing construction of high voltage transmission lines of 69 kv or more. In addition, an energy facility siting application, in Rhode Island must include, when applicable, any current independent, scientific research pertaining to EMF exposure for review by the Board. Management cannot predict the impact, if any, that legislation or other developments concerning EMF may have on Blackstone. EXHIBIT D-8 Page 4 of 4 BLACKSTONE VALLEY ELECTRIC Statement of all Known Contingent Liabilities Note B- Other - ------------- Since early 1997, thirteen plaintiffs brought suit against numerous defendants, including EUA, for injuries and illness allegedly caused by exposure to asbestos over approximately a thirty-year period, at premises, including some owned by EUA companies. The total damages claimed in all of these complaints was $34 million in compensatory and punitive damages, plus exemplary damages and interest and costs. Each complaint names between fifteen and twenty-eight defendants, including EUA. These complaints have been referred to the applicable insurance companies. Counsel has been retained by the insurers and is actively defending all cases. Four cases have been dismissed as against EUA companies, with prejudice. EUA cannot predict the ultimate outcome of this matter at this time. EXHIBIT D-9 Page 1 of 5 EASTERN EDISON COMPANY Statement of all Known Contingent Liabilities Note A - Nuclear Fuel Disposal and Nuclear Decommissioning Costs - ---------------------------------------------------------------- The owners (or lead participants) of the nuclear units in which Montaup has an interest have made, or expect to make, various arrangements for the acquisition of uranium concentrate, the conversion, enrichment, fabrication and utilization of nuclear fuel and the disposition of that fuel after use. The owners (or lead participants) of United States nuclear units have entered into contracts with the Department of Energy (DOE) for disposal of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982 (NWPA). The NWPA requires (subject to various contingencies) that the federal government design, license, construct and operate a permanent repository for high level radioactive wastes and spent nuclear fuel and establish a prescribed fee for the disposal of such wastes and nuclear fuel. The NWPA specifies that the DOE provide for the disposal of such waste and spent nuclear fuel starting in 1998. Objections on environmental and other grounds have been asserted against proposals for storage as well as disposal of spent nuclear fuel. The DOE now estimates that a permanent disposal site for spent fuel will not be ready to accept fuel for storage or disposal until as late as the year 2010. In early 1998, a number of utilities filed suit in federal appeals court seeking, among other things, an order requiring the DOE to immediately establish a program for the disposal of spent nuclear fuel. Montaup owns a 4.01% interest in Millstone 3 and a 2.9% interest in Seabrook I. Northeast Utilities, the operator of the units, indicates that Millstone 3 has sufficient on-site storage facilities which, with rack additions, can accommodate its spent fuel for the projected life of the unit. At the Seabrook Project, there is on-site storage capacity which, with rack additions, will be sufficient to at least the year 2011. The Energy Policy Act of 1992 requires that a fund be created for the decommissioning and decontamination of the DOE uranium enrichment facilities. The fund will be financed in part by special assessments on nuclear power plants in which Montaup has an interest. These assessments are calculated based on the utilities' prior use of the government facilities and have been levied by the DOE, starting in September 1993, and will continue over 15 years. This cost is passed on to the joint owners or power buyers as an additional fuel charge on a monthly basis and is currently being recovered by Montaup through rates. EXHIBIT D-9 Page 2 of 5 EASTERN EDISON COMPANY Statement of all Known Contingent Liabilities Note A - Nuclear Fuel Disposal and Nuclear - ------------------------------------------ Decommissioning Costs - continued --------------------- Montaup has a 4.5% equity ownership in Connecticut Yankee, a nuclear generating facility which is in the process of decommissioning. Montaup's share of the total estimated costs for the permanent shutdown, decommissioning and recovery of the investment in Connecticut Yankee is approximately $23.8 million. On August 31, 1998, a FERC law judge rejected Connecticut Yankee's filed plan to decommission the plant. The judge claimed that estimates of clean-up costs were flawed and certain restoration costs were not supported. The judge also said Connecticut Yankee could not pass on spent fuel storage costs to rate-payers. The judge recommended that Connecticut Yankee withdraw its decommissioning plan and submit a new plan which addresses the issues cited by him. FERC will review the judge's recommendation and issue a decision on this case in the coming months. If FERC concurs with the judge's recommendation, this may result in a write down of certain of Connecticut Yankee plant investments. In August 1997, as a result of an economic evaluation, the Maine Yankee Board of Directors voted to permanently close that nuclear plant. Montaup has a 4.0% equity ownership in Maine Yankee. Montaup's share of the total estimated costs for the permanent shutdown, decommissioning and recovery of the remaining investment in Maine Yankee is approximately $31.0 million. In January 1998, FERC accepted Maine Yankee's rate filing, subject to refund, for the recovery of its costs during the decommissioning period. Also, Montaup is recovering through rates its share of estimated decommissioning costs for Millstone 3 and Seabrook I. Montaup's share of the current estimate of total costs to decommission Millstone 3 is $22.4 million in 1998 dollars, and Seabrook I is $14.4 million in 1998 dollars. These figures are based on studies performed for the lead owner of the units. Montaup also pays into decommissioning reserves pursuant to contractual arrangements with other nuclear generating facilities in which it has an equity ownership interest or life of the unit entitlement. Such expenses are currently recoverable through rates. EXHIBIT D-9 Page 3 of 5 EASTERN EDISON COMPANY Statement of all Known Contingent Liabilities Note B - Environmental Matters - ------------------------------ There is an extensive body of federal and state statutes governing environmental matters, which permit, among other things, federal and state authorities to initiate legal action providing for liability, compensation, cleanup, and emergency response to the release or threatened release of hazardous substances into the environment and for the cleanup of inactive hazardous waste disposal sites which constitute substantial hazards. Because of the nature of the Eastern Edison business, various by-products and substances are produced or handled which are classified as hazardous under the rules and regulations promulgated by the United States Environmental protection Agency (EPA) as well as state and local authorities. The Company generally provides for the disposal of such substances through licensed contractors, but these statutory provisions generally impose potential joint and several responsibility on the generators of the wastes for cleanup costs. In the past, Eastern Edison and Montaup had been notified with respect to a number of sites where they were allegedly responsible for such costs, including sites where they allegedly had joint and several liability with other responsible parties. It is the policy of Eastern Edison and Montaup to notify liability insurers and to initiate claims. Eastern Edison is currently not involved in any environmental site investigation. It is the policy of Eastern Edison to notify liability insurers and to initiate claims. The Company is unable to predict whether liability, if any, will be assumed by, or can be enforced against, the insurance carriers in these matters. The costs incurred in connection with these sites have been financed primarily with internally generated cash. The Clean Air Act Amendments created new regulatory programs and generally updated and strengthened air pollution control laws. These amendments expanded the regulatory role of the EPA regarding emissions from electric generating facilities and a host of other sources. Montaup generating facilities were first affected in 1995, when EPA regulations took effect for facilities owned by Montaup. Montaup's coal-fired Somerset Unit No. 6 is utilizing lower sulfur content coal to meet the 1995 air standards. Eastern Edison does not anticipate the impact from the Amendments to be material to its financial position. In July, the EPA issued a new and more stringent rule covering ozone particulate matter which is to be followed by promulgation of more stringent ozone and particulate matter standards. The effect that such standards will have on the EUA System cannot be determined by management at this time. EXHIBIT D-9 Page 4 of 5 EASTERN EDISON COMPANY Statement of all Known Contingent Liabilities Note B - Environmental Matters - continued - ------------------------------ Eastern Edison, Montaup, the Massachusetts Attorney General and Division of Energy Resources entered into a settlement regarding electric utility industry restructuring in Massachusetts. The settlement includes a plan for emissions reductions related to Montaup's Somerset Station Units 5 and 6, and to Montaup's 50% ownership share of Canal Electric's Unit 2. The basis for sulfur dioxide (SO2) and nitrogen oxide (NOx) emission reductions in the proposed settlement is an allowance cap calculation. Montaup may meet its allowance caps by any combination of control technologies, fuel switching, operational changes, and/or the use of purchased or surplus allowances. The proposed settlement was approved by FERC on December 19, 1997. In April 1992, the Northeast States for Coordinated Air Use Management (NESCAUM), an environmental advisory group for eight Northeast states including Massachusetts and Rhode Island issued recommendations for NOx controls for existing utility boilers required to meet the ozone non-attainment requirements of the Clean Air Act. The NESCAUM recommendations are more restrictive than the Clean Air Act requirements. The Massachusetts Department of Environmental Management has amended its regulations to require that Reasonably Available Control Technology (RACT) be implemented at all stationary sources potentially emitting 50 tons or more per year of NOx. Similar regulations have been issued in Rhode Island. Montaup has initiated compliance, through, among other things, selective, noncatalytic reduction processes. A number of scientific studies in the past several years have examined the possibility of health effects from EMF that are found wherever there is electricity. While some of the studies have indicated some association between exposure to EMF and health effects, many others have indicated no direct association. Some states have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. Rhode Island has enacted a statute which authorizes and directs the Energy Facility Siting Board to establish rules and regulations governing construction of high voltage transmission lines of 69kv or more. Management cannot predict the ultimate outcome of the EMF issue. EXHIBIT D-9 Page 5 of 5 EASTERN EDISON COMPANY Statement of all Known Contingent Liabilities Since early 1997, fourteen plaintiffs brought suit against numerous defendants, including EUA, for injuries and illness all allegedly caused by exposure to asbestos over approximately a thirty-year period, at premises, including some owned by EUA companies. The total damages claimed in all of these complaints was $34 million in compensatory and punitive damages, plus exemplary damages and interest and costs. Each names between fifteen and twenty-eight defendants, including EUA. These complaints have been referred to the applicable insurance companies. Counsel has been retained by the insurers and is actively defending all cases. Four cases have been dismissed as against EUA companies. EUA cannot predict the ultimate outcome of this matter at this time. A pending class action, filed on March 2, 1998, in the Massachusetts Supreme Judicial Court naming all eight Massachusetts electric distribution companies, including Eastern Edison, and certain Massachusetts state agencies, seeks to invalidate certain sections of the Electric Restructuring Act of 1997. The Act directs electric distribution companies to fund energy efficient activities to promote renewable energy projects, and impose a mandatory charge on all electricity sold to customers to fund such activities and projects. In addition to declaratory judgement, plaintiffs seek remittance of monies paid to each distribution company by customers along with any interest earned. The outcome of this class action is unknown at this time, however Eastern Edison is vigorously defending the lawsuit. EXHIBIT D-10 Page 1 of 1 EASTERN EDISON COMPANY Statement of all Known Contingent Liabilities Note A - Environmental Matters - ------------------------------ The Comprehensive Environmental Response, Compensation Liability Act of 1980, as amended by the Superfund Amendments and Reauthorizaton Act of 1986, and certain similar state statutes authorize various governmental authorities to seek court orders compelling responsible parties to take cleanup action at disposal sites which have been determined by such governmental authorities to present an imminent and substantial danger to the public and to the environment because of an actual or threatened release of hazardous substances. Because of the nature of Newport's business, various by-products and substances are produced or handled which are classified as hazardous under the rules and regulations promulgated by the EPA as well as state and local authorities. The Company is currently not involved in any environmental site investigations. Newport generally provides for the disposal of such substances through licensed contractors, but these statutory provisions generally impose potential joint and several responsibility on the generators of the wastes for cleanup costs. It is the policy of Newport to notify liability insurers and to initiate claims. However, it is not possible at this time to predict whether liability, if any, will be assumed by, or can be enforced against, the insurance carrier in this matter. The Clean Air Act Amendments created new regulatory programs and generally updated and strengthened air pollution control laws. These amendments expanded the regulatory role of the United States Environmental Protection Agency (EPA) regarding emissions from electric generating facilities and a host of other sources. The Company does not anticipate the impact from the Amendments to be material to its financial position. In April 1992, the Northeast States for Coordinated Air Use Management (NESCAUM), an environmental advisory group for eight Northeast states including Massachusetts and Rhode Island issued recommendations for nitrogen oxide (NOx) controls for existing utility boilers required to meet the ozone non-attainment requirements of the Clean Air Act. The NESCAUM recommendations are more restrictive than the Clean Air Act requirements. The Massachusetts Department of Environmental Management has amended its regulations to require that Reasonably Available Control Technology (RACT) be implemented at all stationary sources potentially emitting 50 tons or more per year of NOx. Rhode Island has issued similar regulations also requiring that RACT be implemented at all stationary sources potentially emitting 50 tons or more per year of NOx. The Company has initiated compliance through, among other things, selective, reduction processes. Effective October 1, 1999 Newport sold its own generation as part of the utility restructuring laws. Newport still owns its share of the Wyman generating station. JOINT APPLICATION OF NEW ENGLAND POWER COMPANY, et al. AND MONTAUP ELECTRIC COMPANY, et al. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT E-1 New England Power Company EXHIBIT E-2 Massachusetts Electric Company EXHIBIT E-3 The Narragansett Electric Company EXHIBIT E-4 New England Electric Transmission Corporation EXHIBIT E-5 New England Hydro Transmission Corporation EXHIBIT E-6 New England Hydro - Transmission Electric Company, Inc. EXHIBIT E-7 Montaup Electric Company EXHIBIT E-8 Blackstone Valley Electric Company EXHIBIT E-9 Eastern Edison Company EXHIBIT E-10 Newport Electric Corporation Income Statement for the 12 Months Ending September 30, 1998
NEES Companies Exhibit No. E-1 Page 1 of 2 Name of Respondent New England Power Company STATEMENT OF INCOME FOR THE YEAR 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) 1,481,067,948 1,481,067,948 3 Operating Expenses 4 Operation Expenses (401) 963,957,991 963,957,991 5 Maintenance Expenses (402) 75,560,088 75,560,088 6 Depreciation Expense (403) 78,245,773 78,245,773 7 Amort. & Depl. of Utility Plant (404-405) 3,000 3,000 8 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. of Property Losses, Unrecovered Plant and Regulatory Study Costs (407) 10 Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 33,786,395 33,786,395 12 (Less) Regulatory Credits (407.4) 13 Taxes Other Than Income Taxes (408.1) 61,346,769 61,346,769 14 Income Taxes - Federal (409.1) 243,772,477 243,772,477 15 - Other (409.1) 48,628,105 48,628,105 16 Provision for Deferred Income Taxes (410.1) 210,590,379 210,590,379 17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 414,473,197 414,473,197 18 Investment Tax Credit Adj. - Net (411.4) (1,897,334) (1,897,334) 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23 TOTAL Utility Operating Expenses (Enter Total of Lines 4 thru 22) 1,299,520,446 1,299,520,446 24 Net Utility Operating Income (Enter Total of line 2 less 23) (Carry forward to line 25) 181,547,502 181,547,502 NEES Companies Exhibit No. E-1 Page 2 of 2 Name of Respondent New England Power Company STATEMENT OF INCOME FOR THE YEAR (Continued) 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 25 Net Utility Operating Income (Carried forward) 181,547,502 181,547,502 26 Other Income and Deductions 27 Other Income 28 Nonutility Operating Income 29 Revenues From Merchandising, Jobbing and Contract Work (415) 30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 31 Revenues From Nonutility Operations (417) 32 (Less) Expenses of Nonutility Operations (417.1) 2,627,907 2,627,907 33 Nonoperating Rental Income (418) 524,820 524,820 34 Equity in Earnings of Subsidiary Companies (418.1) 5,466,612 5,466,612 35 Interest and Dividend Income (419) 3,547,764 3,547,764 36 Allowance for Other Funds Used During Construction (419.1) 113,773 113,773 37 Miscellaneous Nonoperating Income (421) 76,473 76,473 38 Gain on Disposition of Property (421.1) 483,765 483,765 39 TOTAL Other Income (Enter Total of lines 29 thru 38) 7,585,300 7,585,300 40 Other Income Deductions 41 Loss on Disposition of Property (421.2) (7,007) (7,007) 42 Miscellaneous Amortization (425) 43 Miscellaneous Income Deductions (426.1-426.5) 22,273,872 22,273,872 44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 22,266,865 22,266,865 45 Taxes Applic. to Other Income and Deductions 46 Taxes Other Than Income Taxes (408.2) 330,286 330,286 47 Income Taxes - Federal (409.2) (741,885) (741,885) 48 Income Taxes - Other (409.2) (12,200) (12,200) 49 Provision for Deferred Inc. Taxes (410.2) 381,700 381,700 50 (Less) Provision for Deferred Income Taxes - Cr. (411.2) 51 Investment Tax Credit Adj. - Net (411.5) 52 (Less) Investment Tax Credits (420) (21,422,661) (21,422,661) 53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) (21,464,760) (21,464,760) 54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 6,783,195 6,783,195 55 Interest Charges 56 Interest on Long-Term Debt (427) 34,408,021 34,408,021 57 Amort. of Debt Disc. and Expense (428) 862,427 862,427 58 Amortization of Loss on Reacquired Debt (428.1) 2,358,015 2,358,015 59 (Less) Amort. of Premium on Debt - Credit (429) 60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1) 61 Interest on Debt to Assoc. Companies (430) 2,700,216 2,700,216 62 Other Interest Expense (431) 9,754,285 9,754,285 63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 1,147,923 1,147,923 64 Net Interest Charges (Enter Total of lines 56 thru 63) 48,935,041 48,935,041 65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 139,395,656 139,395,656 66 Extraordinary Items 67 Extraordinary Income (434) 68 (Less) Extraordinary Deductions (435) 69 Net Extraordinary Items (Enter Total of line 67 less line 68) 70 Income Taxes-Federal and Other (409.3) 71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 72 Net Income (Enter Total of lines 65 and 71) 139,395,656 139,395,656
NEES Companies Exhibit No. E-2 Page 1 of 2 Name of Respondent Massachusetts Electric Company STATEMENT OF INCOME FOR THE YEAR 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) 1,583,046,649 1,583,046,649 3 Operating Expenses 4 Operation Expenses (401) 1,302,105,564 1,302,105,564 5 Maintenance Expenses (402) 37,630,776 37,630,776 6 Depreciation Expense (403) 58,845,497 58,845,497 7 Amort. & Depl. of Utility Plant (404-405) 8 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. of Property Losses, Unrecovered Plant and Regulatory Study Costs (407) 10 Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 (Less) Regulatory Credits (407.4) 13 Taxes Other Than Income Taxes (408.1) 36,990,471 36,990,471 14 Income Taxes - Federal (409.1) 26,868,282 26,868,282 15 - Other (409.1) 5,424,674 5,424,674 16 Provision for Deferred Income Taxes (410.1) 28,663,972 28,663,972 17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 14,205,743 14,205,743 18 Investment Tax Credit Adj. - Net (411.4) (1,090,292) (1,090,292) 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23 TOTAL Utility Operating Expenses (Enter Total of Lines 4 thru 22) 1,481,233,201 1,481,233,201 24 Net Utility Operating Income (Enter Total of line 2 less 23) (Carry forward to line 25) 101,813,448 101,813,448 NEES Companies Exhibit No. E-2 Page 2 of 2 Name of Respondent Massachusetts Electric Company STATEMENT OF INCOME FOR THE YEAR (Continued) 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 25 Net Utility Operating Income (Carried forward) 101,813,448 101,813,448 26 Other Income and Deductions 27 Other Income 28 Nonutility Operating Income 29 Revenues From Merchandising, Jobbing and Contract Work (415) 30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 31 Revenues From Nonutility Operations (417) 32 (Less) Expenses of Nonutility Operations (417.1) 1,701,619 1,701,619 33 Nonoperating Rental Income (418) (12,241) (12,241) 34 Equity in Earnings of Subsidiary Companies (418.1) 35 Interest and Dividend Income (419) 3,088,624 3,088,624 36 Allowance for Other Funds Used During Construction (419.1) 37 Miscellaneous Nonoperating Income (421) 49,375 49,375 38 Gain on Disposition of Property (421.1) 227,271 227,271 39 TOTAL Other Income (Enter Total of lines 29 thru 38) 1,651,410 1,651,410 40 Other Income Deductions 41 Loss on Disposition of Property (421.2) 625 625 42 Miscellaneous Amortization (425) 43 Miscellaneous Income Deductions (426.1-426.5) 4,859,474 4,859,474 44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 4,860,099 4,860,099 45 Taxes Applic. to Other Income and Deductions 46 Taxes Other Than Income Taxes (408.2) 280,079 280,079 47 Income Taxes - Federal (409.2) (734,407) (734,407) 48 Income Taxes - Other (409.2) (140,900) (140,900) 49 Provision for Deferred Inc. Taxes (410.2) 36,200 36,200 50 (Less) Provision for Deferred Income Taxes - Cr. (411.2) 51 Investment Tax Credit Adj. - Net (411.5) 52 (Less) Investment Tax Credits (420) 53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) (559,028) (559,028) 54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) (2,649,661) (2,649,661) 55 Interest Charges 56 Interest on Long-Term Debt (427) 26,302,043 26,302,043 57 Amort. of Debt Disc. and Expense (428) 237,624 237,624 58 Amortization of Loss on Reacquired Debt (428.1) 510,833 510,833 59 (Less) Amort. of Premium on Debt - Credit (429) 60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1) 61 Interest on Debt to Assoc. Companies (430) 462,294 462,294 62 Other Interest Expense (431) 5,169,282 5,169,282 63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 590,154 590,154 64 Net Interest Charges (Enter Total of lines 56 thru 63) 32,091,922 32,091,922 65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 67,071,865 67,071,865 66 Extraordinary Items 67 Extraordinary Income (434) 68 (Less) Extraordinary Deductions (435) 69 Net Extraordinary Items (Enter Total of line 67 less line 68) 70 Income Taxes-Federal and Other (409.3) 71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 72 Net Income (Enter Total of lines 65 and 71) 67,071,865 67,071,865
NEES Companies Exhibit No. E-3 Page 1 of 2 Name of Respondent Narragansett Electric Company STATEMENT OF INCOME FOR THE YEAR 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) 492,755,355 492,755,355 3 Operating Expenses 4 Operation Expenses (401) 353,720,050 353,720,050 5 Maintenance Expenses (402) 12,030,441 12,030,441 6 Depreciation Expense (403) 23,048,075 23,048,075 7 Amort. & Depl. of Utility Plant (404-405) 8 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. of Property Losses, Unrecovered Plant and Regulatory Study Costs (407) 10 Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 (Less) Regulatory Credits (407.4) 13 Taxes Other Than Income Taxes (408.1) 40,685,062 40,685,062 14 Income Taxes - Federal (409.1) 14,754,386 14,754,386 15 - Other (409.1) 16 Provision for Deferred Income Taxes (410.1) 10,064,285 10,064,285 17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 8,482,700 8,482,700 18 Investment Tax Credit Adj. - Net (411.4) (490,596) (490,596) 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23 TOTAL Utility Operating Expenses (Enter Total of Lines 4 thru 22) 445,329,003 445,329,003 24 Net Utility Operating Income (Enter Total of line 2 less 23) (Carry forward to line 25) 47,426,352 47,426,352 NEES Companies Exhibit No. E-3 Page 2 of 2 Name of Respondent Narragansett Electric Company STATEMENT OF INCOME FOR THE YEAR (Continued) 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 25 Net Utility Operating Income (Carried forward) 47,426,352 47,426,352 26 Other Income and Deductions 27 Other Income 28 Nonutility Operating Income 29 Revenues From Merchandising, Jobbing and Contract Work (415) 30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 31 Revenues From Nonutility Operations (417) 32 (Less) Expenses of Nonutility Operations (417.1) 826,705 826,705 33 Nonoperating Rental Income (418) 6,096 6,096 34 Equity in Earnings of Subsidiary Companies (418.1) 35 Interest and Dividend Income (419) 834,809 834,809 36 Allowance for Other Funds Used During Construction (419.1) 37 Miscellaneous Nonoperating Income (421) 1,760,164 1,760,164 38 Gain on Disposition of Property (421.1) 266,939 266,939 39 TOTAL Other Income (Enter Total of lines 29 thru 38) 2,041,303 2,041,303 40 Other Income Deductions 41 Loss on Disposition of Property (421.2) 36,101 36,101 42 Miscellaneous Amortization (425) 43 Miscellaneous Income Deductions (426.1-426.5) 807,314 807,314 44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 843,415 843,415 45 Taxes Applic. to Other Income and Deductions 46 Taxes Other Than Income Taxes (408.2) 72,073 72,073 47 Income Taxes - Federal (409.2) (464,501) (464,501) 48 Income Taxes - Other (409.2) 49 Provision for Deferred Inc. Taxes (410.2) (26,053) (26,053) 50 (Less) Provision for Deferred Income Taxes - Cr. (411.2) 51 Investment Tax Credit Adj. - Net (411.5) 52 (Less) Investment Tax Credits (420) 53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) (418,481) (418,481) 54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 1,616,369 1,616,369 55 Interest Charges 56 Interest on Long-Term Debt (427) 14,323,257 14,323,257 57 Amort. of Debt Disc. and Expense (428) 140,171 140,171 58 Amortization of Loss on Reacquired Debt (428.1) 732,145 732,145 59 (Less) Amort. of Premium on Debt - Credit (429) 60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1) 61 Interest on Debt to Assoc. Companies (430) 366,514 366,514 62 Other Interest Expense (431) 3,072,789 3,072,789 63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 127,378 127,378 64 Net Interest Charges (Enter Total of lines 56 thru 63) 18,507,498 18,507,498 65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 30,535,223 30,535,223 66 Extraordinary Items 67 Extraordinary Income (434) 68 (Less) Extraordinary Deductions (435) 69 Net Extraordinary Items (Enter Total of line 67 less line 68) 70 Income Taxes-Federal and Other (409.3) 71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 72 Net Income (Enter Total of lines 65 and 71) 30,535,223 30,535,223
NEES Companies Exhibit No. E-4 Page 1 of 2 Name of Respondent New England Electric Transmission Corporation STATEMENT OF INCOME FOR THE YEAR 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) 9,360,175 9,360,175 3 Operating Expenses 4 Operation Expenses (401) 1,195,551 1,195,551 5 Maintenance Expenses (402) 309,577 309,577 6 Depreciation Expense (403) 4,688,448 4,688,448 7 Amort. & Depl. of Utility Plant (404-405) 8 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. of Property Losses, Unrecovered Plant and Regulatory Study Costs (407) 10 Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 (Less) Regulatory Credits (407.4) 13 Taxes Other Than Income Taxes (408.1) 424,728 424,728 14 Income Taxes - Federal (409.1) 346,865 346,865 15 - Other (409.1) 51,336 51,336 16 Provision for Deferred Income Taxes (410.1) 108,090 108,090 17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 147,210 147,210 18 Investment Tax Credit Adj. - Net (411.4) (406,443) (406,443) 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23 TOTAL Utility Operating Expenses (Enter Total of Lines 4 thru 22) 6,570,942 6,570,942 24 Net Utility Operating Income (Enter Total of line 2 less 23) (Carry forward to line 25) 2,789,233 2,789,233 NEES Companies Exhibit No. E-4 Page 2 of 2 Name of Respondent New England Electric Transmission Corporation STATEMENT OF INCOME FOR THE YEAR (Continued) 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 25 Net Utility Operating Income (Carried forward) 2,789,233 2,789,233 26 Other Income and Deductions 27 Other Income 28 Nonutility Operating Income 29 Revenues From Merchandising, Jobbing and Contract Work (415) 30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 31 Revenues From Nonutility Operations (417) 32 (Less) Expenses of Nonutility Operations (417.1) 4,666 4,666 33 Nonoperating Rental Income (418) 34 Equity in Earnings of Subsidiary Companies (418.1) 35 Interest and Dividend Income (419) 9,781 9,781 36 Allowance for Other Funds Used During Construction (419.1) 37 Miscellaneous Nonoperating Income (421) 861 861 38 Gain on Disposition of Property (421.1) 39 TOTAL Other Income (Enter Total of lines 29 thru 38) 5,976 5,976 40 Other Income Deductions 41 Loss on Disposition of Property (421.2) 42 Miscellaneous Amortization (425) 43 Miscellaneous Income Deductions (426.1-426.5) 702 702 44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 702 702 45 Taxes Applic. to Other Income and Deductions 46 Taxes Other Than Income Taxes (408.2) 47 Income Taxes - Federal (409.2) 17 17 48 Income Taxes - Other (409.2) 49 Provision for Deferred Inc. Taxes (410.2) 50 (Less) Provision for Deferred Income Taxes - Cr. (411.2) 51 Investment Tax Credit Adj. - Net (411.5) 52 (Less) Investment Tax Credits (420) 53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 17 17 54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 5,257 5,257 55 Interest Charges 56 Interest on Long-Term Debt (427) 1,734,068 1,734,068 57 Amort. of Debt Disc. and Expense (428) 40,968 40,968 58 Amortization of Loss on Reacquired Debt (428.1) 59 (Less) Amort. of Premium on Debt - Credit (429) 60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1) 61 Interest on Debt to Assoc. Companies (430) 173,164 173,164 62 Other Interest Expense (431) 16,694 16,694 63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 64 Net Interest Charges (Enter Total of lines 56 thru 63) 1,964,894 1,964,894 65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 829,596 829,596 66 Extraordinary Items 67 Extraordinary Income (434) 68 (Less) Extraordinary Deductions (435) 69 Net Extraordinary Items (Enter Total of line 67 less line 68) 70 Income Taxes-Federal and Other (409.3) 71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 72 Net Income (Enter Total of lines 65 and 71) 829,596 829,596
NEES Companies Exhibit No. E-5 Page 1 of 2 Name of Respondent New England Hydro Transmission Corporation STATEMENT OF INCOME FOR THE YEAR 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) 31,394,424 31,394,424 3 Operating Expenses 4 Operation Expenses (401) 9,747,947 9,747,947 5 Maintenance Expenses (402) 173,008 173,008 6 Depreciation Expense (403) 5,866,290 5,866,290 7 Amort. & Depl. of Utility Plant (404-405) 8 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. of Property Losses, Unrecovered Plant and Regulatory Study Costs (407) 10 Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 (Less) Regulatory Credits (407.4) 13 Taxes Other Than Income Taxes (408.1) 2,940,284 2,940,284 14 Income Taxes - Federal (409.1) 917,086 917,086 15 - Other (409.1) 353,305 353,305 16 Provision for Deferred Income Taxes (410.1) 683,800 683,800 17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 34,200 34,200 18 Investment Tax Credit Adj. - Net (411.4) 1,000,943 1,000,943 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23 TOTAL Utility Operating Expenses (Enter Total of Lines 4 thru 22) 21,648,463 21,648,463 24 Net Utility Operating Income (Enter Total of line 2 less 23) (Carry forward to line 25) 9,745,961 9,745,961 NEES Companies Exhibit No. E-5 Page 2 of 2 Name of Respondent New England Hydro Transmission Corporation STATEMENT OF INCOME FOR THE YEAR (Continued) 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 25 Net Utility Operating Income (Carried forward) 9,745,961 9,745,961 26 Other Income and Deductions 27 Other Income 28 Nonutility Operating Income 29 Revenues From Merchandising, Jobbing and Contract Work (415) 30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 31 Revenues From Nonutility Operations (417) 32 (Less) Expenses of Nonutility Operations (417.1) 4,334 4,334 33 Nonoperating Rental Income (418) 34 Equity in Earnings of Subsidiary Companies (418.1) 35 Interest and Dividend Income (419) 131,916 131,916 36 Allowance for Other Funds Used During Construction (419.1) 37 Miscellaneous Nonoperating Income (421) 370 370 38 Gain on Disposition of Property (421.1) 39 TOTAL Other Income (Enter Total of lines 29 thru 38) 127,952 127,952 40 Other Income Deductions 41 Loss on Disposition of Property (421.2) 42 Miscellaneous Amortization (425) 43 Miscellaneous Income Deductions (426.1-426.5) 240 240 44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 240 240 45 Taxes Applic. to Other Income and Deductions 46 Taxes Other Than Income Taxes (408.2) 47 Income Taxes - Federal (409.2) 30,620 30,620 48 Income Taxes - Other (409.2) 49 Provision for Deferred Inc. Taxes (410.2) 50 (Less) Provision for Deferred Income Taxes - Cr. (411.2) 51 Investment Tax Credit Adj. - Net (411.5) 52 (Less) Investment Tax Credits (420) 53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 30,620 30,620 54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 97,092 97,092 55 Interest Charges 56 Interest on Long-Term Debt (427) 57 Amort. of Debt Disc. and Expense (428) 58 Amortization of Loss on Reacquired Debt (428.1) 28,800 28,800 59 (Less) Amort. of Premium on Debt - Credit (429) 60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1) 61 Interest on Debt to Assoc. Companies (430) 4,674,165 4,674,165 62 Other Interest Expense (431) 7,235 7,235 63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 64 Net Interest Charges (Enter Total of lines 56 thru 63) 4,710,200 4,710,200 65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 5,132,853 5,132,853 66 Extraordinary Items 67 Extraordinary Income (434) 68 (Less) Extraordinary Deductions (435) 69 Net Extraordinary Items (Enter Total of line 67 less line 68) 70 Income Taxes-Federal and Other (409.3) 71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 72 Net Income (Enter Total of lines 65 and 71) 5,132,853 5,132,853
NEES Companies Exhibit No. E-6 Page 1 of 2 Name of Respondent New England Hydro Transmission Electric Company STATEMENT OF INCOME FOR THE YEAR 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) 39,364,267 39,364,267 3 Operating Expenses 4 Operation Expenses (401) 4,937,241 4,937,241 5 Maintenance Expenses (402) 1,279,759 1,279,759 6 Depreciation Expense (403) 8,867,993 8,867,993 7 Amort. & Depl. of Utility Plant (404-405) 27,600 27,600 8 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. of Property Losses, Unrecovered Plant and Regulatory Study Costs (407) 10 Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 (Less) Regulatory Credits (407.4) 13 Taxes Other Than Income Taxes (408.1) 3,251,403 3,251,403 14 Income Taxes - Federal (409.1) 1,883,988 1,883,988 15 - Other (409.1) 824,873 824,873 16 Provision for Deferred Income Taxes (410.1) 1,610,000 1,610,000 17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) (168,364) (168,364) 18 Investment Tax Credit Adj. - Net (411.4) 1,167,961 1,167,961 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23 TOTAL Utility Operating Expenses (Enter Total of Lines 4 thru 22) 24,019,182 24,019,182 24 Net Utility Operating Income (Enter Total of line 2 less 23) (Carry forward to line 25) 15,345,085 15,345,085 NEES Companies Exhibit No. E-6 Page 2 of 2 Name of Respondent New England Hydro Transmission Electric Company STATEMENT OF INCOME FOR THE YEAR (Continued) 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 25 Net Utility Operating Income (Carrie forward) 15,345,085 15,345,085 26 Other Income and Deductions 27 Other Income 28 Nonutility Operating Income 29 Revenues From Merchandising, Jobbing and Contract Work (415) 30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 31 Revenues From Nonutility Operations (417) 32 (Less) Expenses of Nonutility Operations (417.1) 10,526 10,526 33 Nonoperating Rental Income (418) 34 Equity in Earnings of Subsidiary Companies (418.1) 35 Interest and Dividend Income (419) 252,190 252,190 36 Allowance for Other Funds Used During Construction (419.1) 37 Miscellaneous Nonoperating Income (421) 4,614 4,614 38 Gain on Disposition of Property (421.1) 39 TOTAL Other Income (Enter Total of lines 29 thru 38) 246,278 246,278 40 Other Income Deductions 41 Loss on Disposition of Property (421.2) 42 Miscellaneous Amortization (425) 43 Miscellaneous Income Deductions (426.1-426.5) 2,238 2,238 44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 2,238 2,238 45 Taxes Applic. to Other Income and Deductions 46 Taxes Other Than Income Taxes (408.2) 47 Income Taxes - Federal (409.2) 86,419 86,419 48 Income Taxes - Other (409.2) 17,600 17,600 49 Provision for Deferred Inc. Taxes (410.2) 50 (Less) Provision for Deferred Income Taxes - Cr. (411.2) 51 Investment Tax Credit Adj. - Net (411.5) 52 (Less) Investment Tax Credits (420) 53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 104,019 104,019 54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 140,021 140,021 55 Interest Charges 56 Interest on Long-Term Debt (427) 57 Amort. of Debt Disc. and Expense (428) 43,200 43,200 58 Amortization of Loss on Reacquired Debt (428.1) 59 (Less) Amort. of Premium on Debt - Credit (429) 60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1) 61 Interest on Debt to Assoc. Companies (430) 7,620,007 7,620,007 62 Other Interest Expense (431) 10,375 10,375 63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 64 Net Interest Charges (Enter Total of lines 56 thru 63) 7,673,582 7,673,582 65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 7,811,524 7,811,524 66 Extraordinary Items 67 Extraordinary Income (434) 68 (Less) Extraordinary Deductions (435) 69 Net Extraordinary Items (Enter Total of line 67 less line 68) 70 Income Taxes-Federal and Other (409.3) 71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 72 Net Income (Enter Total of lines 65 and 71) 7,811,524 7,811,524
EUA Companies Exhibit No. E-7 Page 1 of 2 Name of Respondent Montaup Electric Company At September 30, 1998 STATEMENT OF INCOME FOR THE YEAR 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) 332,786,837 332,786,837 3 Operating Expenses 4 Operation Expenses (401) 257,077,165 257,077,165 5 Maintenance Expenses (402) 12,402,499 12,402,499 6 Depreciation Expense (403) 17,221,414 17,221,414 7 Amort. & Depl. of Utility Plant (404-405) 682,111 682,111 8 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. of Property Losses, Unrecovered Plant and Regulatory Study Costs (407) 676,468 676,468 10 Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 (Less) Regulatory Credits (407.4) 13 Taxes Other Than Income Taxes (408.1) 6,328,539 6,328,539 14 Income Taxes - Federal (409.1) 5,701,818 5,701,818 15 - Other (409.1) 1,088,045 1,088,045 16 Provision for Deferred Income Taxes (410.1) 1,471,757 1,471,757 17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 678,952 678,952 18 Investment Tax Credit Adj. - Net (411.4) (905,104) (905,104) 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23 TOTAL Utility Operating Expenses (Enter Total of Lines 4 thru 22) 301,065,760 301,065,760 24 Net Utility Operating Income (Enter Total of line 2 less 23) (Carry forward to line 25) 31,721,077 31,721,077 EUA Companies Exhibit No. E-7 Page 2 of 2 Name of Respondent Montaup Electric Company At September 30, 1998 STATEMENT OF INCOME FOR THE YEAR (Continued) 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 25 Net Utility Operating Income (Carried forward) 31,721,077 31,721,077 26 Other Income and Deductions 27 Other Income 28 Nonutility Operating Income 29 Revenues From Merchandising, Jobbing and Contract Work (415) 30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 31 Revenues From Nonutility Operations (417) 32 (Less) Expenses of Nonutility Operations (417.1) 33 Nonoperating Rental Income (418) 34 Equity in Earnings of Subsidiary Companies (418.1) 1,548,829 1,548,829 35 Interest and Dividend Income (419) 1,674,347 1,674,347 36 Allowance for Other Funds Used During Construction (419.1) 132,163 132,163 37 Miscellaneous Nonoperating Income (421) 89,804 89,804 38 Gain on Disposition of Property (421.1) 138,533 138,533 39 TOTAL Other Income (Enter Total of lines 29 thru 38) 3,583,676 3,583,676 40 Other Income Deductions 41 Loss on Disposition of Property (421.2) 42 Miscellaneous Amortization (425) 43 Miscellaneous Income Deductions (426.1-426.5) (178,932) (178,932) 44 TOTAL Other Income Deductions (Total of lines 41 thru 43) (178,932) (178,932) 45 Taxes Applic. to Other Income and Deductions 46 Taxes Other Than Income Taxes (408.2) 47 Income Taxes - Federal (409.2) 875,589 875,589 48 Income Taxes - Other (409.2) 190,795 190,795 49 Provision for Deferred Inc. Taxes (410.2) 29,667 29,667 50 (Less) Provision for Deferred Income Taxes - Cr. (411.2) 51 Investment Tax Credit Adj. - Net (411.5) 52 (Less) Investment Tax Credits (420) 53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 1,096,051 1,096,051 54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 2,666,557 2,666,557 55 Interest Charges 56 Interest on Long-Term Debt (427) 19,994,750 19,994,750 57 Amort. of Debt Disc. and Expense (428) 68,950 68,950 58 Amortization of Loss on Reacquired Debt (428.1) 870,418 870,418 59 (Less) Amort. of Premium on Debt - Credit (429) 60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1) 61 Interest on Debt to Assoc. Companies (430) 62 Other Interest Expense (431) 277,863 277,863 63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 83,786 83,786 64 Net Interest Charges (Enter Total of lines 56 thru 63) 21,128,195 21,128,195 65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 13,259,439 13,259,439 66 Extraordinary Items 67 Extraordinary Income (434) 68 (Less) Extraordinary Deductions (435) 69 Net Extraordinary Items (Enter Total of line 67 less line 68) 70 Income Taxes-Federal and Other (409.3) 71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 72 Net Income (Enter Total of lines 65 and 71) 13,259,439 13,259,439
EUA Companies Exhibit No. E-8 Page 1 of 2 Name of Respondent Blackstone Valley Electric Company At September 30, 1998 STATEMENT OF INCOME FOR THE YEAR 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) $131,551,288 131,551,288 3 Operating Expenses 4 Operation Expenses (401) 101,814,860 101,814,860 5 Maintenance Expenses (402) 2,815,522 2,815,522 6 Depreciation Expense (403) 5,999,741 5,999,741 7 Amort. & Depl. of Utility Plant (404-405) 88,650 88,650 8 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. of Property Losses, Unrecovered Plant and Regulatory Study Costs (407) 10 Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 (Less) Regulatory Credits (407.4) 13 Taxes Other Than Income Taxes (408.1) 7,717,100 7,717,100 14 Income Taxes - Federal (409.1) 1,700,202 1,700,202 15 - Other (409.1) 1,134 1,134 16 Provision for Deferred Income Taxes (410.1) 2,188,258 2,188,258 17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 319,823 319,823 18 Investment Tax Credit Adj. - Net (411.4) (178,839) (178,839) 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23 TOTAL Utility Operating Expenses (Enter Total of Lines 4 thru 22) 121,826,805 121,826,805 24 Net Utility Operating Income (Enter Total of line 2 less 23) (Carry forward to line 25) 9,724,483 9,724,483 EUA Companies Exhibit No. E-8 Page 2 of 2 Name of Respondent Blackstone Valley Electric Company At September 30, 1998 STATEMENT OF INCOME FOR THE YEAR (Continued) 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 25 Net Utility Operating Income (Carried forward) 9,724,483 9,724,483 26 Other Income and Deductions 27 Other Income 28 Nonutility Operating Income 29 Revenues From Merchandising, Jobbing and Contract Work (415) 30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 31 Revenues From Nonutility Operations (417) 32 (Less) Expenses of Nonutility Operations (417.1) 33 Nonoperating Rental Income (418) 34 Equity in Earnings of Subsidiary Companies (418.1) 35 Interest and Dividend Income (419) (3,114) (3,114) 36 Allowance for Other Funds Used During Construction (419.1) 37 Miscellaneous Nonoperating Income (421) 76,396 76,396 38 Gain on Disposition of Property (421.1) 45,744 45,744 39 TOTAL Other Income (Enter Total of lines 29 thru 38) 119,026 119,026 40 Other Income Deductions 41 Loss on Disposition of Property (421.2) 42 Miscellaneous Amortization (425) 43 Miscellaneous Income Deductions (426.1-426.5) 154,821 154,821 44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 154,821 154,821 45 Taxes Applic. to Other Income and Deductions 46 Taxes Other Than Income Taxes (408.2) 47 Income Taxes - Federal (409.2) 15,561 15,561 48 Income Taxes - Other (409.2) 49 Provision for Deferred Inc. Taxes (410.2) 50 (Less) Provision for Deferred Income Taxes - Cr. (411.2) 51 Investment Tax Credit Adj. - Net (411.5) 52 (Less) Investment Tax Credits (420) 53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 15,561 15,561 54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) (51,356) (51,356) 55 Interest Charges 56 Interest on Long-Term Debt (427) 3,073,092 3,073,092 57 Amort. of Debt Disc. and Expense (428) 82,023 82,023 58 Amortization of Loss on Reacquired Debt (428.1) 59 (Less) Amort. of Premium on Debt - Credit (429) 60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1) 61 Interest on Debt to Assoc. Companies (430) 62 Other Interest Expense (431) 836,696 836,696 63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 108,232 108,232 64 Net Interest Charges (Enter Total of lines 56 thru 63) 3,883,579 3,883,579 65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 5,789,548 5,789,548 66 Extraordinary Items 67 Extraordinary Income (434) 68 (Less) Extraordinary Deductions (435) 69 Net Extraordinary Items (Enter Total of line 67 less line 68) 70 Income Taxes-Federal and Other (409.3) 71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 72 Net Income (Enter Total of lines 65 and 71) 5,789,548 5,789,548
EUA Companies Exhibit No. E-9 Page 1 of 2 Name of Respondent Eastern Edison Company At September 30, 1998 STATEMENT OF INCOME FOR THE YEAR 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) $266,376,072 266,376,072 3 Operating Expenses 4 Operation Expenses (401) 220,415,459 220,415,459 5 Maintenance Expenses (402) 5,126,282 5,126,282 6 Depreciation Expense (403) 10,625,246 10,625,246 7 Amort. & Depl. of Utility Plant (404-405) 8 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. of Property Losses, Unrecovered Plant and Regulatory Study Costs (407) 10 Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 (Less) Regulatory Credits (407.4) 13 Taxes Other Than Income Taxes (408.1) 4,623,228 4,623,228 14 Income Taxes - Federal (409.1) 7,500,708 7,500,708 15 - Other (409.1) 1,486,136 1,486,136 16 Provision for Deferred Income Taxes (410.1) 2,454,729 2,454,729 17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 153,009 153,009 18 Investment Tax Credit Adj. - Net (411.4) (304,593) (304,593) 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23 TOTAL Utility Operating Expenses (Enter Total of Lines 4 thru 22) 251,774,186 251,774,186 24 Net Utility Operating Income (Enter Total of line 2 less 23) (Carry forward to line 25) 14,601,886 14,601,886 EUA Companies Exhibit No. E-9 Page 2 of 2 Name of Respondent Eastern Edison Company At September 30, 1998 STATEMENT OF INCOME FOR THE YEAR (Continued) 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 25 Net Utility Operating Income (Carried forward) 14,601,886 14,601,886 26 Other Income and Deductions 27 Other Income 28 Nonutility Operating Income 29 Revenues From Merchandising, Jobbing and Contract Work (415) 30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 31 Revenues From Nonutility Operations (417) 32 (Less) Expenses of Nonutility Operations (417.1) 33 Nonoperating Rental Income (418) 34 Equity in Earnings of Subsidiary Companies (418.1) 13,259,439 13,259,439 35 Interest and Dividend Income (419) 20,139,609 20,139,609 36 Allowance for Other Funds Used During Construction (419.1) (45,605) (45,605) 37 Miscellaneous Nonoperating Income (421) 132,766 132,766 38 Gain on Disposition of Property (421.1) (13,879) (13,879) 39 TOTAL Other Income (Enter Total of lines 29 thru 38) 33,472,330 33,472,330 40 Other Income Deductions 41 Loss on Disposition of Property (421.2) 42 Miscellaneous Amortization (425) 43 Miscellaneous Income Deductions (426.1-426.5) 640,491 640,491 44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 640,491 640,491 45 Taxes Applic. to Other Income and Deductions 46 Taxes Other Than Income Taxes (408.2) 47 Income Taxes - Federal (409.2) 50,332 50,332 48 Income Taxes - Other (409.2) 9,997 9,997 49 Provision for Deferred Inc. Taxes (410.2) 50 (Less) Provision for Deferred Income Taxes - Cr. (411.2) 51 Investment Tax Credit Adj. - Net (411.5) 52 (Less) Investment Tax Credits (420) 53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 60,329 60,329 54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 32,771,510 32,771,510 55 Interest Charges 56 Interest on Long-Term Debt (427) 13,941,414 13,941,414 57 Amort. of Debt Disc. and Expense (428) 322,185 322,185 58 Amortization of Loss on Reacquired Debt (428.1) 568,186 586,186 59 (Less) Amort. of Premium on Debt - Credit (429) 60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1) 61 Interest on Debt to Assoc. Companies (430) 62 Other Interest Expense (431) 3,404,253 3,404,253 63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 176,180 176,180 64 Net Interest Charges (Enter Total of lines 56 thru 63) 18,059,858 18,059,858 65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 29,313,538 29,313,538 66 Extraordinary Items 67 Extraordinary Income (434) 68 (Less) Extraordinary Deductions (435) 69 Net Extraordinary Items (Enter Total of line 67 less line 68) 70 Income Taxes-Federal and Other (409.3) 71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 72 Net Income (Enter Total of lines 65 and 71) 29,313,538 29,313,538
EUA Companies Exhibit No. E-10 Page 1 of 2 Name of Respondent Newport Electric Corporation At September 30, 1998 STATEMENT OF INCOME FOR THE YEAR 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) $61,343,166 $61,343,166 3 Operating Expenses 4 Operation Expenses (401) 44,831,555 44,831,555 5 Maintenance Expenses (402) 2,188,747 2,188,747 6 Depreciation Expense (403) 2,864,116 2,864,116 7 Amort. & Depl. of Utility Plant (404-405) 61,860 61,860 8 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. of Property Losses, Unrecovered Plant and Regulatory Study Costs (407) 10 Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 (Less) Regulatory Credits (407.4) 13 Taxes Other Than Income Taxes (408.1) 4,016,508 4,016,508 14 Income Taxes - Federal (409.1) 1,170,049 1,170,049 15 - Other (409.1) 1,162 1,162 16 Provision for Deferred Income Taxes (410.1) 652,811 652,811 17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) (662) (662) 18 Investment Tax Credit Adj. - Net (411.4) (3,960) (3,960) 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23 TOTAL Utility Operating Expenses (Enter Total of Lines 4 thru 22) 55,783,510 55,783,510 24 Net Utility Operating Income (Enter Total of line 2 less 23) (Carry forward to line 25) 5,559,656 5,559,656 EUA Companies Exhibit No. E-10 Page 2 of 2 Name of Respondent Newport Electric Company At September 30, 1998 STATEMENT OF INCOME FOR THE YEAR (Continued) 12 months 12 months Line Account ended Pro-Forma Adjusted No. 9-30-98 Adjustments 9-30-98 25 Net Utility Operating Income (Carried forward) 5,559,656 5,559,656 26 Other Income and Deductions 27 Other Income 28 Nonutility Operating Income 29 Revenues From Merchandising, Jobbing and Contract Work (415) 30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 31 Revenues From Nonutility Operations (417) 32 (Less) Expenses of Nonutility Operations (417.1) 33 Nonoperating Rental Income (418) 34 Equity in Earnings of Subsidiary Companies (418.1) 35 Interest and Dividend Income (419) 10,617 10,617 36 Allowance for Other Funds Used During Construction (419.1) 37 Miscellaneous Nonoperating Income (421) 4,209 4,209 38 Gain on Disposition of Property (421.1) (4,345) (4,345) 39 TOTAL Other Income (Enter Total of lines 29 thru 38) 10,481 10,481 40 Other Income Deductions 41 Loss on Disposition of Property (421.2) 42 Miscellaneous Amortization (425) 43 Miscellaneous Income Deductions (426.1-426.5) 76,463 76,463 44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 76,463 76,463 45 Taxes Applic. to Other Income and Deductions 46 Taxes Other Than Income Taxes (408.2) 47 Income Taxes - Federal (409.2) 48 Income Taxes - Other (409.2) (10,452) (10,452) 49 Provision for Deferred Inc. Taxes (410.2) 50 (Less) Provision for Deferred Income Taxes - Cr. (411.2) 51 Investment Tax Credit Adj. - Net (411.5) 52 (Less) Investment Tax Credits (420) 81,360 81,360 53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) (91,812) (91,812) 54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 25,830 25,830 55 Interest Charges 56 Interest on Long-Term Debt (427) 1,444,216 1,444,216 57 Amort. of Debt Disc. and Expense (428) 54,539 54,539 58 Amortization of Loss on Reacquired Debt (428.1) 47,056 47,056 59 (Less) Amort. of Premium on Debt - Credit (429) 60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1) 61 Interest on Debt to Assoc. Companies (430) 62 Other Interest Expense (431) 677,550 677,550 63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 41,530 41,530 64 Net Interest Charges (Enter Total of lines 56 thru 63) 2,181,831 2,181,831 65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 3,403,655 3,403,655 66 Extraordinary Items 67 Extraordinary Income (434) 68 (Less) Extraordinary Deductions (435) 69 Net Extraordinary Items (Enter Total of line 67 less line 68) 70 Income Taxes-Federal and Other (409.3) 71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70) 72 Net Income (Enter Total of lines 65 and 71) 3,403,655 3,403,655
JOINT APPLICATION OF NEW ENGLAND POWER COMPANY, et al. AND MONTAUP ELECTRIC COMPANY, et al. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS EXHIBIT F-1 New England Power Company EXHIBIT F-2 Massachusetts Electric Company EXHIBIT F-3 The Narragansett Electric Company EXHIBIT F-4 New England Electric Transmission Corporation EXHIBIT F-5 New England Hydro Transmission Corporation EXHIBIT F-6 New England Hydro-Transmission Electric Company, Inc. EXHIBIT F-7 Montaup Electric Company EXHIBIT F-8 Blackstone Valley Electric Company EXHIBIT F-9 Eastern Edison Company EXHIBIT F-10 Newport Electric Corporation Analysis of Retained Earnings for the 12 Months Ending September 30, 1998
NEES Companies Exhibit No. F-1 Page 1 of 2 Name of Respondent New England Power Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance - Beginning of Year 372,385,240 372,385,240 2 Changes (Identify by prescribed retained earnings accounts) 3 Adjustments to Retained Earnings (Account 439) 4 Credit: Transfer from 215.1 23,204,856 23,204,856 5 Credit: 6 Credit: 7 Credit: 8 Credit: 9 TOTAL Credits to Retained Earnings (Acc. 439) (Total of lines 4 thru 8) 23,204,856 23,204,856 10 Debit: Repurchase of Common Stock (193,817,339) (193,817,339) 11 Debit: 12 Debit: 13 Debit: 14 Debit: 15 TOTAL Debits to Retained Earnings (Acc. 439) (Total of lines 10 thru 14) (193,817,339) (193,817,339) 16 Balance Transferred from Income (Account 433 less Account 418.1) 133,929,044 133,929,044 17 Appropriations of Retained Earnings (Account 436) 18 Amortization Reserve, Federal (3,451,609) (3,451,609) 19 20 21 22 Total Appropriations of Retained Earnings (Acc. 436) (Total of lines 18 thru 21) (3,451,609) (3,451,609) 23 Dividends Declared - Preferred Stock (Account 437) 24 *Dividends Declared on Preferred Stock (1,697,833) (1,697,833) 25 26 27 28 29 TOTAL Dividends Declared - Preferred Stock (Acct. 437) (Total of lines 24 thru 28) (1,697,833) (1,697,833) 30 Dividends Declared - Common Stock (Account 438) 31 Dividends Declared on Common Stock (166,084,822) (166,084,822) 32 33 34 35 36 TOTAL Dividends Declared - Common Stock (Acct. 438) (Total of lines 31 thru 35) (166,084,822) (166,084,822) 37 Transfers from Acct. 216.1, Unappropriated Undistributed Subsidiary Earnings 7,634,030 7,634,030 38 Balance - End of Year (Total of lines 01,09,15,16,22,29,36, and 37) 172,101,567 172,101,567 NEES Companies Exhibit No. F-1 Page 2 of 2 Name of Respondent New England Power Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued) Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 41 42 43 44 45 Total Appropriated Retained Earnings (Account 215) APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL (Account 215.1) 46 Total Appropriated Retained Earnings - Amortization Reserve, Federal (Account 215.1) 47 Total Appropriated Retained Earnings - (Account 215,215.1) (Enter total of lines 45 and 46) 48 Total Retained Earnings (Account 215, 215.1, 216)(Enter total of lines 38 and 47) 172,101,567 172,101,567 UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1) 49 Balance - Beginning of Year (Debit or Credit) 16,420,340 16,420,340 50 Equity in Earnings for Year (Credit) (Account 418.1) 5,466,612 5,466,612 51 (Less) Dividends Received (Debit) 7,634,030 7,634,030 52 Other Changes (Explain) 53 Balance - End of Year (Total of Lines 49 thru 52) 14,252,922 14,252,922
NEES Companies Exhibit No. F-2 Page 1 of 2 Name of Respondent Massachusetts Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance - Beginning of Year 171,807,605 171,807,605 2 Changes (Identify by prescribed retained earnings accounts) 3 Adjustments to Retained Earnings (Account 439) 4 Credit: 5 Credit: 6 Credit: 7 Credit: 8 Credit: 9 TOTAL Credits to Retained Earnings (Acc. 439) (Total of lines 4 thru 8) 10 Debit: Premium on Redemption of Preferred Stock (3,764,951) (3,764,951) 11 Debit: 12 Debit: 13 Debit: 14 Debit: 15 TOTAL Debits to Retained Earnings (Acc. 439) (3,764,951) (3,764,951) (Total of lines 10 thru 14) 16 Balance Transferred from Income (Account 433 less Account 418.1) 67,071,865 67,071,865 17 Appropriations of Retained Earnings (Account 436) 18 Amortization Reserve, Federal 19 20 21 22 Total Appropriations of Retained Earnings (Acc. 436) (Total of lines 18 thru 21) 23 Dividends Declared - Preferred Stock (Account 437) 24 *Dividends declared on preferred stock 25 Cummulative Preferred Stock 4.44% (147,360) (147,360) 26 Cummulative Preferred Stock 4.76% (156,776) (156,776) 27 Cummulative Preferred Stock 6.99% (493,691) (493,691) 28 Cummulative Preferred Stock 6.84% (408,042) (408,042) 29 TOTAL Dividends Declared - Preferred Stock (Acct. 437) (Total of lines 24 thru 28) (1,205,869) (1,205,869) 30 Dividends Declared - Common Stock (Account 438) 31 2,398,111 Shares @ $17.50/Share (41,966,943) (41,966,943) 32 33 34 35 36 TOTAL Dividends Declared - Common Stock (Acct. 438) (Total of lines 31 thru 35) (41,966,943) (41,966,943) 37 Transfers from Acct. 216.1, Unappropriated Undistributed Subsidiary Earnings 38 Balance - End of Year (Total of lines 01,09,15,16,22,29,36, and 37) 191,941,707 191,941,707 NEES Companies Exhibit No. F-2 Page 2 of 2 Name of Respondent Massachusetts Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued) Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 APPROPRIATED RETAINED EARNINGS (Account 215) 39 4,637,347 40 41 42 43 44 45 Total Appropriated Retained Earnings (Account 215) 4,637,347 APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL (Account 215.1) 46 Total Appropriated Retained Earnings - Amortization Reserve, Federal (Account 215.1) 47 Total Appropriated Retained Earnings - (Account 215,215.1) (Enter total of lines 45 and 46) 4,637,347 4,637,347 48 Total Retained Earnings (Account 215, 215.1, 216) (Enter total of lines 38 and 47) 196,579,054 196,579,054 UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1) 49 Balance - Beginning of Year (Debit or Credit) 50 Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 Other Changes (Explain) 53 Balance - End of Year (Total of Lines 49 thru 52)
NEES Companies Exhibit No. F-3 Page 1 of 2 Name of Respondent Narragansett Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance - Beginning of Year 129,686,160 129,686,160 2 Changes (Identify by prescribed retained earnings accounts) 3 Adjustments to Retained Earnings (Account 439) 4 Credit: 5 Credit: 6 Credit: 7 Credit: 8 Credit: 9 TOTAL Credits to Retained Earnings (Acc. 439) (Total of lines 4 thru 8) 10 Debit: Reacquisition of Preferred Stock (2,826,003) (2,826,003) 11 Debit: 12 Debit: 13 Debit: 14 Debit: 15 TOTAL Debits to Retained Earnings (Acc. 439) (2,826,003) (2,826,003) (Total of lines 10 thru 14) 16 Balance Transferred from Income (Account 433 less Account 30,535,223 30,535,223 418.1) 17 Appropriations of Retained Earnings (Account 436) 18 Amortization Reserve, Federal 19 20 21 22 Total Appropriations of Retained Earnings (Acc. 436) (Total of lines 18 thru 21) 23 Dividends Declared - Preferred Stock (Account 437) 24 *Dividends declared on preferred stock 25 4.50% Series (144,600) (144,600) 26 4.64% Series (165,596) (165,596) 27 6.95% Series (515,086) (515,086) 28 29 TOTAL Dividends Declared - Preferred Stock (Acct. (825,282) (825,282) 437) (Total of lines 24 thru 28) 30 Dividends Declared - Common Stock (Account 438) 31 1,132,487 Shares at $64.50 (73,045,412) (73,045,412) 32 33 34 35 36 TOTAL Dividends Declared - Common Stock (Acct. 73,045,412) (73,045,412) 438) (Total of lines 31 thru 35) 37 Transfers from Acct. 216.1, Unappropriated Undistributed Subsidiary Earnings 38 Balance - End of Year (Total of lines 83,524,686 83,524,686 01,09,15,16,22,29,36, and 37) NEES Companies Exhibit No. F-3 Page 2 of 2 Name of Respondent Narragansett Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued) Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 41 42 43 44 45 Total Appropriated Retained Earnings (Account 215) APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL (Account 215.1) 46 Total Appropriated Retained Earnings - Amortization Reserve, Federal (Account 215.1) 47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total of lines 45 and 46) 48 Total Retained Earnings (Account 215, 215.1, 83,524,686 83,524,686 216)(Enter total of lines 38 and 47) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1) 49 Balance - Beginning of Year (Debit or Credit) 50 Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 Other Changes (Explain) 53 Balance - End of Year (Total of Lines 49 thru 52)
NEES Companies Exhibit No. F-4 Page 1 of 2 Name of Respondent New England Electric Transmission Corporation At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance - Beginning of Year 294,086 294,086 2 Changes (Identify by prescribed retained earnings accounts) 3 Adjustments to Retained Earnings (Account 439) 4 Credit: 5 Credit: 6 Credit: 7 Credit: 8 Credit: 9 TOTAL Credits to Retained Earnings (Acc. 439) (Total of lines 4 thru 8) 10 Debit: Premium on reacquisition of Capital Stock (42,282) (42,282) 11 Debit: 12 Debit: 13 Debit: 14 Debit: 15 TOTAL Debits to Retained Earnings (Acc. 439) (Total of lines 10 thru 14) 16 Balance Transferred from Income (Account 433 less Account 418.1) 829,596 829,596 17 Appropriations of Retained Earnings (Account 436) 18 Amortization Reserve, Federal 19 20 21 22 Total Appropriations of Retained Earnings (Acc. 436) (Total of lines 18 thru 21) 23 Dividends Declared - Preferred Stock (Account 437) 24 *Dividends declared on preferred stock 25 26 27 28 29 TOTAL Dividends Declared - Preferred Stock (Acct.437) (Total of lines 24 thru 28) 30 Dividends Declared - Common Stock (Account 438) 31 (954,000) (954,000) 32 33 34 35 36 TOTAL Dividends Declared - Common Stock (Acct.438) (954,000) (954,000) (Total of lines 31 thru 35) 37 Transfers from Acct. 216.1, Unappropriated Undistributed Subsidiary Earnings 38 Balance - End of Year (Total of lines 127,400 127,400 01,09,15,16,22,29,36, and 37) NEES Companies Exhibit No. F-4 Page 2 of 2 Name of Respondent New England Electric Transmission Corporation At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued) Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 APPROPRIATED RETAINED EARNINGS (Account 215) 39 39 40 41 42 43 44 45 Total Appropriated Retained Earnings (Account 215) APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL (Account 215.1) 46 Total Appropriated Retained Earnings - Amortization Reserve, Federal (Account 215.1) 47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total of lines 45 and 46) 48 Total Retained Earnings (Account 215, 215.1, 216) 127,400 127,400 (Enter total of lines 38 and 47) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1) 49 Balance - Beginning of Year (Debit or Credit) 50 Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 Other Changes (Explain) 53 Balance - End of Year (Total of Lines 49 thru 52)
NEES Companies Exhibit No. F-5 Page 1 of 2 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance - Beginning of Year 557,639 537,639 2 Changes (Identify by prescribed retained earnings accounts) 3 Adjustments to Retained Earnings (Account 439) 4 Credit: 5 Credit: 6 Credit: 7 Credit: 8 Credit: 9 TOTAL Credits to Retained Earnings (Acc. 439) (Total of lines 4 thru 8) 10 Debit: Premium on reacquisition of Capital Stock (50,466) (50,466) 11 Debit: 12 Debit: 13 Debit: 14 Debit: 15 TOTAL Debits to Retained Earnings (Acc. 439) (50,466) (50,466) (Total of lines 10 thru 14) 16 Balance Transferred from Income (Account 433 less Account 418.1) 5,132,853 5,132,853 17 Appropriations of Retained Earnings (Account 436) 18 Amortization Reserve, Federal 19 20 21 22 Total Appropriations of Retained Earnings (Acc. 436) (Total of lines 18 thru 21) 23 Dividends Declared - Preferred Stock (Account 437) 24 *Dividends declared on preferred stock 25 26 27 28 29 TOTAL Dividends Declared - Preferred Stock (Acct. 437) (Total of lines 24 thru 28) 30 Dividends Declared - Common Stock (Account 438) 31 (5,549,750) (5,549,750) 32 33 34 35 36 TOTAL Dividends Declared - Common Stock (Acct. 438) (5,549,750) (5,549,750) (Total of lines 31 thru 35) 37 Transfers from Acct. 216.1, Unappropriated Undistributed Subsidiary Earnings 38 Balance - End of Year (Total of lines 90,276 90,276 01,09,15,16,22,29,36, and 37) NEES Companies Exhibit No. F-5 Page 2 of 2 Name of Respondent New England Hydro Transmission Corporation At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued) Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 41 42 43 44 45 Total Appropriated Retained Earnings (Account 215) APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL (Account 215.1) 46 Total Appropriated Retained Earnings - Amortization Reserve, Federal (Account 215.1) 47Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total of lines 45 and 46) 48 Total Retained Earnings (Account 215, 215.1, 90,276 90,276 216)(Enter total of lines 38 and 47) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1) 49 Balance - Beginning of Year (Debit or Credit) 50 Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 Other Changes (Explain) 53 Balance - End of Year (Total of Lines 49 thru 52)
NEES Companies Exhibit No. F-6 Page 1 of 2 Name of Respondent New England Hydro Transmission Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance - Beginning of Year 456,236 456,226 2 Changes (Identify by prescribed retained earnings accounts) 3 Adjustments to Retained Earnings (Account 439) 4 Credit: 5 Credit: 6 Credit: 7 Credit: 8 Credit: 9 TOTAL Credits to Retained Earnings (Acc. 439) (Total of lines 4 thru 8) 10 Debit: Premium on reacquisition of Capital Stock (31,362) (31,362) 11 Debit: 12 Debit: 13 Debit: 14 Debit: 15 TOTAL Debits to Retained Earnings (Acc. 439) (31,362) (31,362) (Total of lines 10 thru 14) 16 Balance Transferred from Income (Account 433 less Account 7,811,524 7,811,524 418.1) 17 Appropriations of Retained Earnings (Account 436) 18 Amortization Reserve, Federal 19 20 21 22 Total Appropriations of Retained Earnings (Acc. 436) (Total of lines 18 thru 21) 23 Dividends Declared - Preferred Stock (Account 437) 24 *Dividends declared on preferred stock 25 26 27 28 29 TOTAL Dividends Declared - Preferred Stock (Acct. 437) (Total of lines 24 thru 28) 30 Dividends Declared - Common Stock (Account 438) 31 (8,140,000) (8,140,000) 32 33 34 35 36 TOTAL Dividends Declared - Common Stock (Acct. (8,140,000) (8,140,000) 438) (Total of lines 31 thru 35) 37 Transfers from Acct. 216.1, Unappropriated Undistributed Subsidiary Earnings 38 Balance - End of Year (Total of lines 96,398 96,398 01,09,15,16,22,29,36, and 37) NEES Companies Exhibit No. F-6 Page 2 of 2 Name of Respondent New England Hydro Transmission Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued) Adjusted Line Item Balance at Pro-Forma Balance at No. 9-30-98 Adjustments 9-30-98 APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 41 42 43 44 45 Total Appropriated Retained Earnings (Account 215) APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL (Account 215.1) 46 Total Appropriated Retained Earnings - Amortization Reserve, Federal (Account 215.1) 47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total of lines 45 and 46) 48 Total Retained Earnings (Account 215, 215.1, 96,398 96,398 216)(Enter total of lines 38 and 47) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1) 49 Balance - Beginning of Year (Debit or Credit) 50 Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 Other Changes (Explain) 53 Balance - End of Year (Total of Lines 49 thru 52)
NEES Companies Exhibit No. F-7 Page 1 of 2 Name of Respondent Montaup Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR Adjusted Line Item Balance at Pro-Forma Balance at No. September 1998 Adjustments September 1998 UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance - Beginning of Year 69,650,578 69,650,578 2 Changes (Identify by prescribed retained earnings accounts) 3 Adjustments to Retained Earnings (Account 439) 4 Credit: 5 Credit: 6 Credit: 7 Credit: 8 Credit: 9 TOTAL Credits to Retained Earnings (Acc. 439) (Total of lines 4 thru 8) 10 Debit: 11 Debit: 12 Debit: 13 Debit: 14 Debit: 15 TOTAL Debits to Retained Earnings (Acc. 439) (Total of lines 10 thru 14) 16 Balance Transferred from Income (Account 433 less Account 11,710,610 11,710,610 418.1) 17 Appropriations of Retained Earnings (Account 436) 18 Amortization Reserve, Federal 19 20 21 22 Total Appropriations of Retained Earnings (Acc. 436) (Total of lines 18 thru 21) 23 Dividends Declared - Preferred Stock (Account 437) 24 *Dividends declared on preferred stock (339,000) (339,000) 25 26 27 28 29 TOTAL Dividends Declared - Preferred Stock (Acct. (339,000)` (339,000) 437) (Total of lines 24 thru 28) 30 Dividends Declared - Common Stock (Account 438) 31 (13,243,600) (13,243,600) 32 33 34 35 36 TOTAL Dividends Declared - Common Stock (Acct. (13,243,600) (13,243,600) 438) (Total of lines 31 thru 35) 37 Transfers from Acct. 216.1, Unappropriated Undistributed 1,951,718 1,951,718 Subsidiary Earnings 38 Balance - End of Year (Total of lines 69,730,306 69,730,306 01,09,15,16,22,29,36, and 37) NEES Companies Exhibit No. F-7 Page 2 of 2 Name of Respondent Montaup Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued) Adjusted Line Item Balance at Pro-Forma Balance at No. September 1998 Adjustments September 1998 APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 41 42 43 44 45 Total Appropriated Retained Earnings (Account 215) APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL (Account 215.1) 46 Total Appropriated Retained Earnings - Amortization Reserve, Federal (Account 215.1) 47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total of lines 45 and 46) 48 Total Retained Earnings (Account 215, 215.1, 69,730,306 69,730,306 216)(Enter total of lines 38 and 47) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1) 49 Balance - Beginning of Year (Debit or Credit) 4,462,275 4,462,275 50 Equity in Earnings for Year (Credit) (Account 418.1) 1,548,829 1,548,829 51 (Less) Dividends Received (Debit) 1,951,718 1,951,718 52 Other Changes (Explain) 53 Balance - End of Year (Total of Lines 49 thru 52) 4,059,386 4,059,386
NEES Companies Exhibit No. F-8 Page 1 of 2 Name of Respondent Blackstone Valley Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR Adjusted Line Item Balance at Pro-Forma Balance at No. September 1998 Adjustments September 1998 UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance - Beginning of Year 10,102,232 10,102,232 2 Changes (Identify by prescribed retained earnings accounts) 3 Adjustments to Retained Earnings (Account 439) 4 Credit: 5 Credit: 6 Credit: 7 Credit: 8 Credit: 9 TOTAL Credits to Retained Earnings (Acc. 439) (Total of lines 4 thru 8) 10 Debit: 11 Debit: 12 Debit: 13 Debit: 14 Debit: 15 TOTAL Debits to Retained Earnings (Acc. 439) (Total of lines 10 thru 14) 16 Balance Transferred from Income (Account 433 less Account 5,789,548 5,789,548 418.1) 17 Appropriations of Retained Earnings (Account 436) 18 Amortization Reserve, Federal 19 20 21 22 Total Appropriations of Retained Earnings (Acc. 436) (Total of lines 18 thru 21) 23 Dividends Declared - Preferred Stock (Account 437) 24 *Dividends declared on preferred stock 25 4.25% Preferred Stock (148,750) (148,750) 26 5.60% Preferred Stock (140,000) (140,000) 27 28 29 TOTAL Dividends Declared - Preferred Stock (Acct. (288,750) (288,750) 437) (Total of lines 24 thru 28) 30 Dividends Declared - Common Stock (Account 438) 31 32 Common Stock (1,923,449) (1,923,449) 33 34 35 36 TOTAL Dividends Declared - Common Stock (Acct. (1,923,449) (1,923,449) 438) (Total of lines 31 thru 35) 37 Transfers from Acct. 216.1, Unappropriated Undistributed Subsidiary Earnings 38 Balance - End of Year (Total of lines 13,679,581 13,679,581 01,09,15,16,22,29,36, and 37) NEES Companies Exhibit No. F-8 Page 2 of 2 Name of Respondent Blackstone Valley Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued) Adjusted Line Item Balance at Pro-Forma Balance at No. September 1998 Adjustments September 1998 APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 41 42 43 44 45 Total Appropriated Retained Earnings (Account 215) APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL (Account 215.1) 46 Total Appropriated Retained Earnings - Amortization Reserve, Federal (Account 215.1) 47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total of lines 45 and 46) 48 Total Retained Earnings (Account 215, 215.1, 13,679,581 13,679,581 216)(Enter total of lines 38 and 47) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1) 49 Balance - Beginning of Year (Debit or Credit) 50 Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 Other Changes (Explain) 53 Balance - End of Year (Total of Lines 49 thru 52)
NEES Companies Exhibit No. F-9 Page 1 of 2 Name of Respondent Eastern Edison Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR Adjusted Line Item Balance at Pro-Forma Balance at No. September 1998 Adjustments September 1998 UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance - Beginning of Year 26,070,503 26,070,503 2 Changes (Identify by prescribed retained earnings accounts) 3 Adjustments to Retained Earnings (Account 439) 4 Credit: 5 Credit: 6 Credit: 7 Credit: 8 Credit: 9 TOTAL Credits to Retained Earnings (Acc. 439) (Total of lines 4 thru 8) 10 Debit: Amortization of Preferred Stock Redemption Cost (435,552) (435,552) 11 Debit: 12 Debit: 13 Debit: 14 Debit: 15 TOTAL Debits to Retained Earnings (Acc. 439) ($435,552) (435,552) (Total of lines 10 thru 14) 16 Balance Transferred from Income (Account 433 less Account 16,054,099 16,054,099 418.1) 17 Appropriations of Retained Earnings (Account 436) 18 Amortization Reserve, Federal 19 20 21 22 Total Appropriations of Retained Earnings (Acc. 436) (Total of lines 18 thru 21) 23 Dividends Declared - Preferred Stock (Account 437) 24 6.625% (1,987,500) (1,987,500) 25 26 27 28 29 TOTAL Dividends Declared - Preferred Stock (Acct. (1,987,500) (1,987,500) 437) (Total of lines 24 thru 28) 30 Dividends Declared - Common Stock (Account 438) 31 (27,612,460) (27,612,460) 32 33 34 35 36 TOTAL Dividends Declared - Common Stock (Acct. (27,612,460) (27,612,460) 438) (Total of lines 31 thru 35) 37 Transfers from Acct. 216.1, Unappropriated Undistributed 13,582,600 13,582,600 Subsidiary Earnings 38 Balance - End of Year (Total of lines 25,671,690 25,671,690 01,09,15,16,22,29,36, and 37) NEES Companies Exhibit No. F-9 Page 2 of 2 Name of Respondent Eastern Edison Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued) Adjusted Line Item Balance at Pro-Forma Balance at No. September 1998 Adjustments September 1998 APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 41 42 43 44 45 Total Appropriated Retained Earnings (Account 215) APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL (Account 215.1) 46 Total Appropriated Retained Earnings - Amortization Reserve, Federal (Account 215.1) 47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total of lines 45 and 46) 48 Total Retained Earnings (Account 215, 215.1, 25,671,690 25,671,690 216)(Enter total of lines 38 and 47) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1) 49 Balance - Beginning of Year (Debit or Credit) 74,112,853 74,112,853 50 Equity in Earnings for Year (Credit) (Account 418.1) 13,259,439 13,259,439 51 (Less) Dividends Received (Debit) 13,582,600 13,582,600 52 Other Changes (Explain) 53 Balance - End of Year (Total of Lines 49 thru 52) 73,789,692 73,789,692
NEES Companies Exhibit No. F-10 Page 1 of 2 Name of Respondent Newport Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR Adjusted Line Item Balance at Pro-Forma Balance at No. September 1998 Adjustments September 1998 UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance - Beginning of Year 2,283,575 2,283,575 2 Changes (Identify by prescribed retained earnings accounts) 3 Adjustments to Retained Earnings (Account 439) 4 Credit: 5 Credit: 6 Credit: 7 Credit: 8 Credit: 9 TOTAL Credits to Retained Earnings (Acc. 439) (Total of lines 4 thru 8) 10 Debit: Amortization of Preferred Stock Redemption Cost 11 Debit: 12 Debit: 13 Debit: 14 Debit: 15 TOTAL Debits to Retained Earnings (Acc. 439) (Total of lines 10 thru 14) 16 Balance Transferred from Income (Account 433 less Account 3,403,655 3,403,655 418.1) 17 Appropriations of Retained Earnings (Account 436) 18 Amortization Reserve, Federal 19 20 21 22 Total Appropriations of Retained Earnings (Acc. 436) (Total of lines 18 thru 21) 23 Dividends Declared - Preferred Stock (Account 437) 24 *Dividends declared on preferred stock (28,834) (28,834) 25 3.75% Preferred Stock 26 27 28 29 TOTAL Dividends Declared - Preferred Stock (Acct. (28,834) (28,834) 437) (Total of lines 24 thru 28) (Account 438) 30 Dividends Declared - Common Stock 31 (2,410,000) (2,410,000) 32 33 34 35 36 TOTAL Dividends Declared - Common Stock (Acct. (2,410,000) (2,410,000) 438) (Total of lines 31 thru 35) 37 Transfers from Acct. 216.1, Unappropriated Undistributed Subsidiary Earnings 38 Balance - End of Year (Total of lines 3,248,396 3,248,396 01,09,15,16,22,29,36, and 37) NEES Companies Exhibit No. F-10 Page 2 of 2 Name of Respondent Newport Electric Company At September 30, 1998 STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued) Adjusted Line Item Balance at Pro-Forma Balance at No. September 1998 Adjustments September 1998 APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 41 42 43 44 45 Total Appropriated Retained Earnings (Account 215) APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL (Account 215.1) 46 Total Appropriated Retained Earnings - Amortization Reserve, Federal (Account 215.1) 47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total of lines 45 and 46) 48 Total Retained Earnings (Account 215, 215.1, 3,248,396 3,248,396 216)(Enter total of lines 38 and 47) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1) 49 Balance - Beginning of Year (Debit or Credit) 50 Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 Other Changes (Explain) 53 Balance - End of Year (Total of Lines 49 thru 52)
Exhibit G State filings to be provided separately. Exhibit H See separate volume. AGREEMENT AND PLAN OF MERGER and CONSENT AGREEMENT dated as of February 1, 1999 Exhibit I [Map Reflecting the NEES and EUA Direct Retail Service Areas and Transmission Networks] AGREEMENT AND PLAN OF MERGER and CONSENT AGREEMENT dated as of February 1, 1999 TABLE OF CONTENTS AGREEMENT AND PLAN OF MERGER...................................................1 CONSENT AGREEMENT..............................................................2 Tab 1 AGREEMENT AND PLAN OF MERGER dated as of February 1, 1999 by and among NEW ENGLAND ELECTRIC SYSTEM, RESEARCH DRIVE LLC and EASTERN UTILITIES ASSOCIATES TABLE OF CONTENTS Page No. ARTICLE I THE MERGER......................................................... 1 1.01 The Merger......................................................... 1 1.02 Effective Time..................................................... 1 1.03 Effects of the Merger.............................................. 2 ARTICLE II CONVERSION OF SHARES............................................... 2 2.01 Conversion of Capital Stock........................................ 2 2.02 Surrender of Shares................................................ 3 2.03 Withholding Rights................................................. 4 ARTICLE III THE CLOSING........................................................ 4 ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EUA.............................. 5 4.01 Organization and Qualification..................................... 5 4.02 Capital Stock...................................................... 6 4.03 Authority.......................................................... 7 4.04 Non-Contravention; Approvals and Consents.......................... 7 4.05 SEC Reports, Financial Statements and Utility Reports.............. 8 4.06 Absence of Certain Changes or Events............................... 9 4.07 Legal Proceedings.................................................. 9 4.08 Information Supplied............................................... 9 4.09 Compliance......................................................... 10 4.10 Taxes.............................................................. 10 4.11 Employee Benefit Plans; ERISA...................................... 12 4.12 Labor Matters...................................................... 14 4.13 Environmental Matters.............................................. 15 4.14 Regulation as a Utility............................................ 17 4.15 Insurance.......................................................... 17 4.16 Nuclear Facilities................................................. 18 4.17 Vote Required...................................................... 18 4.18 Opinion of Financial Advisor....................................... 18 -i- Page No. 4.19 Ownership of NEES Common Shares.................................... 18 4.20 State Anti-Takeover Statutes....................................... 18 4.21 Year 2000.......................................................... 19 4.22 EUA Associates..................................................... 19 ARTICLE V REPRESENTATIONS AND WARRANTIES OF NEES............................. 19 5.01 Organization and Qualification..................................... 19 5.02 Authority.......................................................... 20 5.03 Capital Stock...................................................... 20 5.04 Non-Contravention; Approvals and Consents.......................... 20 5.05 Information Supplied............................................... 21 5.06 Compliance......................................................... 21 5.07 Financing.......................................................... 22 5.08 No Vote Required................................................... 22 5.09 Ownership of EUA Shares............................................ 22 5.10 Merger with The National Grid Group plc............................ 22 ARTICLE VI COVENANTS................................................ 22 6.01 Covenants of EUA................................................... 22 6.02 Covenants of NEES.................................................. 28 6.03 Additional Covenants by NEES and EUA............................... 29 ARTICLE VII ADDITIONAL AGREEMENTS.................................... 30 7.01 Access to Information.............................................. 30 7.02 Proxy Statement.................................................... 31 7.03 Approval of Shareholders........................................... 31 7.04 Regulatory and Other Approvals..................................... 31 7.05 Employee Benefit Plans............................................. 32 7.06 Labor Agreements and Workforce Matters............................. 34 7.07 Post Merger Operations............................................. 34 7.08 No Solicitations................................................... 35 7.09 Directors' and Officers' Indemnification and Insurance............. 36 7.10 Expenses........................................................... 37 7.11 Brokers or Finders................................................. 37 7.12 Anti-Takeover Statutes............................................. 38 7.13 Public Announcements............................................... 38 -ii- Page No. 7.14 Restructuring of the Merger........................................ 38 ARTICLE VIII CONDITIONS......................................................... 39 8.01 Conditions to Each Party's Obligation to Effect the Merger......... 39 8.02 Conditions to Obligation of NEES and LLC to Effect the Merger...... 39 8.03 Conditions to Obligation of EUA to Effect the Merger............... 40 ARTICLE IX TERMINATION, AMENDMENT AND WAIVER.................................. 41 9.01 Termination........................................................ 41 9.02 Effect of Termination.............................................. 43 9.03 Termination Fees................................................... 43 9.04 Amendment.......................................................... 44 9.05 Waiver............................................................. 44 ARTICLE X GENERAL PROVISIONS................................................. 44 10.01 Non-Survival of Representations, Warranties, Covenants and Agreements......................................................... 44 10.02 Notices............................................................ 44 10.03 Entire Agreement; Incorporation of Exhibits........................ 46 10.04 No Third Party Beneficiary......................................... 46 10.05 No Assignment; Binding Effect...................................... 46 10.06 Headings........................................................... 47 10.07 Invalid Provisions................................................. 47 10.08 Governing Law...................................................... 47 10.09 Enforcement of Agreement........................................... 47 10.10 Certain Definitions................................................ 47 10.11 Counterparts....................................................... 48 10.12 WAIVER OF JURY TRIAL............................................... 48 -iii- GLOSSARY OF DEFINED TERMS The following terms, when used in this Agreement, have the meanings ascribed to them in the corresponding Sections of this Agreement listed below: "1935 Act" -- Section 4.05(b) "Adjustment Date" -- Section 2.01(c) "Affected Employees" -- Section 7.05(a) "affiliate" -- Section 10.11(a) "Agreement" -- Preamble "Alternative Proposal" -- Section 7.08 "beneficially" -- Section 10.10(b) "business day" -- Section 10.10(c) "Canceled Shares" -- Section 2.02(b) "Certificates" -- Section 2.02(b) "Closing" -- Article III "Closing Agreement" -- Section 4.10(j) "Closing Date" -- Article III "Code" -- Section 2.03 "Confidentiality Agreement" -- Section 7.01 "Constituent Entities" -- Section 1.01 "Contracts" -- Section 4.04(a) "control," "controlling," "controlled by" and "under common control with" -- Section 10.10(a) "DOE" -- Section 4.05(b) "Effective Time" -- Section 1.02 "Environmental Claim" -- Section 4.13(f)(i) "Environmental Laws" -- Section 4.13(f)(ii) "Environmental Permits" -- Section 4.13(b) "ERISA" -- Section 4.11(a) "ERISA Affiliate" -- Section 4.11(c) "EUA" -- Preamble "EUA Associates" -- Section 4.01(b) "EUA Employee Agreements" -- Section 7.05(d)(ii) "EUA Executives" -- Section 7.05(d)(ii) "EUA Shares" -- Preamble "EUA Disclosure Letter" -- Section 4.01(a) "EUA Employee Benefit Plans" -- Section 4.11(a) "EUA Financial Statements" -- Section 4.05(a) "EUA Nuclear Facilities" -- Section 4.16 "EUA Material Adverse Effect" -- Section 4.01(a) "EUA Required Consents" -- Section 4.04(a) "EUA Required Statutory Approvals" -- Section 4.04(b) "EUA SEC Reports" -- Section 4.05(a) -iv- "EUA Shareholders' Approval" -- Section 7.03 "EUA Shareholders' Meeting" -- Section 7.03 "EUA Significant Subsidiary" -- Section 7.08 "EUA Shares" -- Preamble "EUA Trust Agreement" -- Section 1.03 "EUA Voting Debt -- Section 4.02(d) "Evaluation Material" -- Section 7.01(a) "Exchange Act" -- Section 4.05(a) "Exchange Fund" -- Section 2.02(a) "Extended Termination Date" -- Section 9.01(b) "FCC" -- Section 4.05(b) "FERC" -- Section 4.05(b) "Final Order" -- Section 8.01(d) "Governmental Authority" -- Section 4.04(a) "Hazardous Materials" -- Section 4.13(f)(iii) "HSR Act" -- Section 7.04(a) "Indemnified Liabilities" -- Section 7.09(a) "Indemnified Party" -- Section 7.09(a) "Indemnified Parties" -- Section 7.09(a) "Information Systems" -- Section 4.21 "Initial Termination Date" -- Section 9.01(b) "IRS" -- Section 4.10(m) "knowledge" -- Section 10.11(d) "laws" -- Section 4.04(a) "Lien" -- Section 4.02(b) "LLC" -- Preamble "Massachusetts Secretary" -- Section 1.02 "Merger" -- Preamble "Merger Consideration" -- Section 2.01(b)(ii) "MGL" -- Section 1.01 "National Grid Group" -- Section 5.10 "National Grid Merger Agreement" -- Section 5.10 "NEES" -- Preamble "NEES Disclosure Letter" -- Section 5.03 "NEES Material Adverse Effect" -- Section 5.01 "NEES-EUA Regulatory Approvals" -- Section 7.04(b) "NEES-EUA Regulatory Proceedings" -- Section 7.04(c) "NEES Required Consents" -- Section 5.04(a) "NEES Required Statutory Approvals" -- Section 5.04(b) "NEES-NGG Regulatory Approvals" -- Section 7.04(c) "NEES-NGG Regulatory Proceedings" -- Section 7.04(c) "NEES-NGG Required Statutory Approvals"-- Section 7.04 "NEES-NGG Transactions" -- Section 7.04 "NEES Shares" -- Section 5.03 -v- "NEES Trust Agreement" -- Section 5.01 "NGG Circular" -- Section 7.02 "NRC" -- Section 4.05(b) "Options" -- Section 4.02(a) "orders" -- Section 4.04(a) "Out-of-Pocket Expenses" -- Section 9.03(a) "Paying Agent" -- Section 2.02(a) "PBGC" -- Section 4.11(g) "person" -- Section 10.11(e) "Per Share Amount" -- Section 2.01(b)(ii) "Post Closing Plans" -- Section 7.05(b) "Proxy Statement" -- Section 4.08(a) "Release" -- Section 4.13(f)(iv) "Representatives" -- Section 10.11(f) "SEC" -- Section 4.05(a) "Securities Act" -- Section 4.05(a) "Subsidiary" -- Section 10.11(g) "Surviving Entity" -- Section 1.01 "Tax Ruling" -- Section 4.10(j) "Taxes" -- Section 4.10 "Tax Return" -- Section 4.10 "US GAAP" -- Section 4.05(a) "Yankee Companies" -- Section 4.16 "Y2K Consultant" -- Section 6.01(o) -vi- This AGREEMENT AND PLAN OF MERGER, dated as of February 1, 1999 (this "Agreement"), is made and entered into by and among NEW ENGLAND ELECTRIC SYSTEM, a Massachusetts business trust ("NEES"), RESEARCH DRIVE LLC ("LLC"), a Massachusetts limited liability company which is directly and indirectly wholly owned by NEES, and EASTERN UTILITIES ASSOCIATES, a Massachusetts business trust ("EUA"). WHEREAS, the Board of Directors of NEES, the Board of Trustees of EUA and the members of LLC have each determined that it is advisable and in the best interests of their respective shareholders and members to consummate, and have approved, the business combination transaction provided for herein in which LLC would merge with and into EUA, with EUA being the surviving entity (the "Merger"), pursuant to the terms and conditions of this Agreement, as a result of which NEES will own, directly or indirectly, all of the issued and outstanding common shares of EUA (the "EUA Shares"); WHEREAS, NEES, LLC and EUA desire to make certain representations, warranties and agreements in connection with the Merger and also to prescribe various conditions to the Merger; NOW, THEREFORE, in consideration of the mutual covenants and agreements set forth in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows: ARTICLE I THE MERGER 1.01 The Merger. Upon the terms and subject to the conditions of this Agreement, at the Effective Time (as defined in Section 1.02), LLC shall be merged with and into EUA in accordance with Section 2 of Chapter 182 and Section 59 of Chapter 156C of the Massachusetts General Laws ("MGL"). At the Effective Time, the separate existence of LLC shall cease and EUA shall continue as the surviving entity in the Merger. EUA, after the Effective Time, is sometimes referred to herein as the "Surviving Entity" and EUA and LLC are sometimes referred to herein as the "Constituent Entities". The effect and consequences of the Merger shall be as set forth in Article II. 1.02 Effective Time. Subject to the provisions of this Agreement, on the Closing Date (as defined in Article III), a certificate of merger shall be executed and filed by EUA and LLC with the Secretary of the Commonwealth of Massachusetts (the "Massachusetts Secretary"). The Merger shall become effective at the time of the filing of the certificate of merger relating to the Merger with the Massachusetts Secretary, or at such later time as is specified in the certificate of merger (such date and time being referred to herein as the "Effective Time"). 1.03 Effects of the Merger. At the Effective Time, the Agreement and Declaration of Trust of EUA (the "EUA Trust Agreement") as in effect immediately prior to the Effective Time shall be the agreement and declaration of trust of the Surviving Entity, until thereafter amended as provided by law and such agreement and declaration of trust. Subject to the foregoing, the additional effects of the Merger shall be as provided in the applicable provisions of Section 2 of Chapter 182 of the MGL and Section 62 of the Limited Liability Company Act of Massachusetts. ARTICLE II CONVERSION OF SHARES 2.01 Conversion of Capital Stock. At the Effective Time, by virtue of the Merger and without any action on the part of the holder thereof: (a) Membership Interests of LLC. Each one percent of the issued and outstanding membership interests in LLC shall be converted into one transferable certificate of participation or share of the Surviving Entity. (b) Conversion of EUA Shares. (i) Cancellation of Treasury Shares and Shares Owned by NEES and Subsidiaries. All EUA Shares that are owned by EUA as treasury shares and any EUA Shares owned by NEES or any other wholly owned Subsidiary (as defined in Section 10.11) of NEES shall be canceled and retired and shall cease to exist and no cash or other consideration shall be delivered in exchange therefor. (ii) Conversion of EUA Shares. Each EUA Share issued and outstanding immediately prior to the Effective Time (other than shares to be canceled in accordance with Section 2.01(b)(i)) shall be canceled and converted in accordance with the provisions of this Section 2.01 into the right to receive cash in the amount (the "Per Share Amount") of $31.00 as such amount may hereafter be adjusted in accordance with Section 2.01(c) hereof (the "Merger Consideration"), payable, without interest, to the holder of such EUA Share, upon surrender, in the manner provided in Section 2.02 hereof, of the certificate formerly evidencing such share. (c) Adjustment in Amount of Merger Consideration. In the event that the Closing Date shall not have occurred on or prior to the date that is the six (6) month anniversary of the date on which EUA Shareholders' Approval is obtained (the "Adjustment Date"), the Per Share Amount shall be increased, for each day after the Adjustment Date up to and including the day which is one day prior to the earlier of the Closing Date and the Extended Termination Date, by an amount equal to $0.003. -2- 2.02 Surrender of Shares. (a) Deposit with Paying Agent. Prior to the Effective Time, NEES shall designate a bank or trust company reasonably acceptable to EUA to act as agent (the "Paying Agent") for the benefit of the holders of EUA Shares in connection with the Merger to receive the funds to which holders of EUA Shares shall become entitled pursuant to Section 2.01(b)(ii) (the "Exchange Fund"). From time to time at, immediately prior to or after the Effective Time, NEES or LLC shall make or cause to be made available to the Paying Agent immediately available funds in amounts and at the times necessary for the payment of the Merger Consideration upon surrender of Certificates (as defined in Section 2.02(b)) in accordance with Section 2.02(b), it being understood that any and all interest or other income earned on funds made available to the Paying Agent pursuant to this Section 2.02(a) shall belong to and shall be paid (at the time provided for in Section 2.02(e)) as directed by NEES or LLC. Any such funds deposited with the Paying Agent by NEES shall be invested by the Paying Agent as directed by NEES or LLC. (b) Exchange Procedure. As soon as practicable after the Effective Time, the Paying Agent shall mail to each holder of record of a certificate or certificates (the "Certificates") which immediately prior to the Effective Time represented outstanding EUA Shares (the "Canceled Shares") that were canceled and became instead the right to receive the Merger Consideration pursuant to Section 2.01(b)(ii): (i) a letter of transmittal in such form as NEES and EUA may reasonably agree (which shall specify that delivery shall be effected, and risk of loss and title to the Certificates shall pass, only upon actual delivery of the Certificates to the Paying Agent) and (ii) instructions for effecting the surrender of the Certificates in exchange for the Merger Consideration. Upon surrender of a Certificate or Certificates to the Paying Agent for cancellation (or to such other agent or agents as may be appointed by NEES and are reasonably acceptable to EUA), together with a duly executed letter of transmittal and such other documents as the Paying Agent shall require, the holder of such Certificate shall be entitled to receive the Merger Consideration in exchange for each EUA Share formerly evidenced by such Certificate which such holder has the right to receive pursuant to Section 2.01(b)(ii). In the event of a transfer of ownership of Canceled Shares which is not registered in the transfer records of EUA, the Merger Consideration in respect of such Canceled Shares may be given to the transferee thereof if the Certificate or Certificates representing such Canceled Shares is presented to the Paying Agent, accompanied by all documents required to evidence and effect such transfer and by evidence satisfactory to the Paying Agent that any applicable stock transfer taxes have been paid. At any time after the Effective Time, each Certificate shall be deemed to represent only the right to receive the Merger Consideration subject to and upon the surrender of such Certificate as contemplated by this Section 2.02. No interest shall be paid or will accrue on the Merger Consideration payable to holders of Certificates pursuant to Section 2.01(b)(ii). (c) No Further Ownership Rights in EUA Shares. The Merger Consideration paid upon the surrender of Certificates in accordance with the terms of Section 2.01(b)(ii) shall be deemed to have been paid at the Effective Time in full satisfaction of all rights pertaining to EUA Shares represented thereby. From and after the Effective Time, the share transfer books of EUA shall be closed and there shall be no further registration of transfers thereon of EUA Shares which were outstanding immediately prior to the Effective Time. -3- If, after the Effective Time, Certificates are presented to NEES for any reason, they shall be canceled and exchanged as provided in this Section 2.02. (d) Lost, Stolen or Destroyed Certificates. In the event any owner of any Certificate shall claim that such Certificate shall have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the owner of such Certificate and delivery of that affidavit to the Paying Agent and, if required by NEES or LLC, the posting by such person of a bond in customary amount as indemnity against any claim that may be made against NEES, EUA or the Surviving Entity with respect to such Certificate, the Paying Agent will issue in exchange for such lost, stolen or destroyed Certificate the Merger Consideration payable upon due surrender of, and deliverable pursuant to this Section 2.02 in respect of, EUA Shares to which such Certificate relates. (e) Termination of Exchange Fund. Any portion of the Exchange Fund which remains undistributed to the shareholders of EUA for one (1) year after the Effective Time shall be delivered to the Surviving Entity, upon demand, and any Shareholders of EUA who have not theretofore complied with this Article II shall thereafter look only to the Surviving Entity (subject to abandoned property, escheat and other similar laws) as general creditors for payment of their claim for the Merger Consideration payable upon due surrender of the Certificates held by them. None of NEES, LLC or the Surviving Entity shall be liable to any former holder of EUA Shares for the Merger Consideration delivered to a public official pursuant to any applicable abandoned property, escheat or similar law. 2.03 Withholding Rights. Each of the Surviving Entity and NEES shall be entitled to deduct and withhold from the consideration otherwise payable pursuant to this Agreement to any holder of EUA Shares such amounts as it is required to deduct and withhold with respect to the making of such payment under the Internal Revenue Code of 1986, as amended (the "Code"), or any other provision of state, local or foreign tax law. To the extent that amounts are so withheld by the Surviving Entity or NEES, as the case may be, such withheld amounts shall be treated for all purposes of this Agreement as having been paid to the holder of EUA Shares in respect of which such deduction and withholding was made by the Surviving Entity or NEES, as the case may be. ARTICLE III THE CLOSING The closing of the Merger and other transactions contemplated hereby (the "Closing") will take place at the offices of Skadden, Arps, Slate, Meagher & Flom LLP, 919 Third Avenue, New York, New York 10022, at 10:00 a.m., local time, on the second business day following satisfaction or waiver (where applicable) of the conditions set forth in Article VIII (other than those conditions that by their nature are to be fulfilled at the Closing, but subject to the fulfillment or waiver of such conditions), unless another date, time or place is agreed to in writing by the parties hereto (the "Closing Date"). -4- ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EUA EUA represents and warrants to NEES and LLC as follows: 4.01 Organization and Qualification. (a) EUA is a voluntary association duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has full power, authority and legal right to own its property and assets and to transact the business in which it is engaged. Each of EUA's Subsidiaries is a corporation duly organized or incorporated, validly existing and in good standing under the laws of its jurisdiction of organization or incorporation and has full corporate power and authority to conduct its business as and to the extent now conducted and to own, use and lease its assets and properties, except where failure to be so organized or incorporated, existing and in good standing or to have such power and authority, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. As used in this Agreement, the term "EUA Material Adverse Effect" means a material adverse effect on the business, assets, results of operations, condition (financial or otherwise) or prospects of EUA and its Subsidiaries taken as a whole. Each of EUA and its Subsidiaries is duly qualified, licensed or admitted to do business and is in good standing in each jurisdiction in which the ownership, use or leasing of its assets and properties, or the conduct or nature of its business, makes such qualification, licensing or admission necessary, except where failure to be so qualified, licensed or admitted and in good standing, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. Section 4.01 of the letter dated the date hereof and delivered to NEES and LLC by EUA concurrently with the execution and delivery of this Agreement (the "EUA Disclosure Letter") sets forth (i) the name and jurisdiction of incorporation or organization of each Subsidiary of EUA, (ii) such Subsidiary's authorized capital stock, (iii) the number of issued and outstanding shares of capital stock of such Subsidiary and (iv) the number of shares of such Subsidiary held of record by EUA. EUA has previously delivered to NEES correct and complete copies of the EUA Trust Agreement and the certificate or articles of organization or incorporation and bylaws (or other comparable charter documents) of its Subsidiaries. (b) Section 4.01 of the EUA Disclosure Letter sets forth a description as of the date hereof, of all EUA Associates, including (i) the name of each such entity and EUA's interest therein and (ii) a brief description of the principal line or lines of business conducted by each such entity. For purposes of this Agreement "EUA Associates" shall mean any corporation or other entity (including partnerships and other business associations) that is not a Subsidiary of EUA in which EUA and/or one or more of its Subsidiaries, directly or indirectly, owns an equity interest (other than short-term investments in the ordinary course of business) if such corporation or other entity (including partnerships and other business associations) contributes five percent or more of EUA's consolidated revenues, assets, income or costs. -5- 4.02 Capital Stock. (a) The authorized equity securities of EUA consists of 36,000,000 EUA Shares, of which 20,435,997 shares were issued and outstanding as of the close of business on January 29, 1999. As of the close of business on January 29, 1999, no EUA Shares were held in the treasury of EUA. Since such date there has been no change in the sum of the issued and outstanding EUA Shares. All of the issued and outstanding EUA Shares are duly authorized, validly issued, fully paid and nonassessable. Except pursuant to this Agreement and except as described in Section 4.02 of the EUA Disclosure Letter, on the date hereof there are no outstanding subscriptions, options, warrants, rights (including share appreciation rights), preemptive rights or other contracts, commitments, understandings or arrangements, including any right of conversion or exchange under any outstanding security, instrument or agreement (together, "Options"), obligating EUA or any of its Subsidiaries to issue or sell any shares of equity securities of EUA or to grant, extend or enter into any Option with respect thereto. The EUA Disclosure Letter sets forth all capital stock authorized, issued and outstanding at subsidiary levels as of the close of business on January 29, 1999. (b) Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, all of the outstanding shares of capital stock of each Subsidiary of EUA are duly authorized, validly issued, fully paid and nonassessable and are owned, beneficially and of record, by EUA or a Subsidiary, which is wholly owned, directly or indirectly, by EUA, free and clear of any liens, claims, mortgages, encumbrances, pledges, security interests, equities and charges of any kind (each a "Lien"). Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no (i) outstanding Options obligating EUA or any of its Subsidiaries to issue or sell any shares of capital stock of any Subsidiary of EUA or to grant, extend or enter into any such Option or (ii) voting trusts, proxies or other commitments, understandings, restrictions or arrangements in favor of any person other than EUA or a Subsidiary which is wholly owned, directly or indirectly, by EUA with respect to the voting of, or the right to participate in, dividends or other earnings on any capital stock of any Subsidiary of EUA. (c) Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no outstanding contractual obligations of EUA or any Subsidiary of EUA to repurchase, redeem or otherwise acquire any EUA Shares or any capital stock of any Subsidiary of EUA or to provide funds to, or make any investment (in the form of a loan, capital contribution or otherwise) in, any Subsidiary of EUA or any other person. (d) As of the date of this Agreement, no bonds, debentures, notes or other indebtedness of EUA or any Subsidiary of EUA having the right to vote (or which are convertible into or exercisable for securities having the right to vote) (together "EUA Voting Debt") on any matters on which Shareholders may vote are issued or outstanding nor are there any outstanding Options obligating EUA or any of its Subsidiaries to issue or sell any EUA Voting Debt or to grant, extend or enter into any Option with respect thereto. -6- 4.03 Authority. EUA has full power and authority to enter into this Agreement, to perform its obligations hereunder and, subject to obtaining EUA Shareholders' Approval (as defined in Section 7.03(b)) and EUA Required Statutory Approvals (as defined in Section 4.04(b)), to consummate the Merger and other transactions contemplated hereby. The execution, delivery and performance of this Agreement by EUA and the consummation by EUA of the Merger and other transactions contemplated hereby have been duly authorized by all necessary action on the part of EUA, subject to obtaining EUA Shareholders' Approval with respect to the consummation of the Merger and the other transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by EUA and constitutes a legal, valid and binding obligation of EUA enforceable against EUA in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). 4.04 Non-Contravention; Approvals and Consents. (a) The execution and delivery of this Agreement by EUA do not, and the performance by EUA of its obligations hereunder and the consummation of the Merger and other transactions contemplated hereby will not, conflict with, result in a violation or breach of, constitute (with or without notice or lapse of time or both) a default under, result in or give to any person any right of payment or reimbursement, termination, cancellation, modification or acceleration of, or result in the creation or imposition of any Lien upon any of the assets or properties of EUA or any of its Subsidiaries or any of the terms, conditions or provisions of (i) the EUA Trust Agreement or the certificates or articles of incorporation or organization or bylaws (or other comparable charter documents) of EUA's Subsidiaries, or (ii) subject to the obtaining of EUA Shareholders' Approval, EUA Required Consents, EUA Required Statutory Approvals and the taking of any other actions described in this Section 4.04, (x) any statute, law, rule, regulation or ordinance (together, "laws"), or any judgment, decree, order, writ, permit or license (together, "orders"), of any court, tribunal, arbitrator, authority, agency, commission, official or other instrumentality of the United States, any foreign country or any domestic or foreign state, county, city or other political subdivision (a "Governmental Authority") applicable to EUA or any of its Subsidiaries or any of their respective assets or properties, or (y) subject to obtaining the third-party consents set forth in Section 4.04 of the EUA Disclosure Letter (the "EUA Required Consents"), any note, bond, mortgage, security agreement, indenture, license, franchise, permit, concession, contract, lease or other instrument, obligation or agreement of any kind (together, "Contracts") to which EUA or any of its Subsidiaries is a party or by which EUA or any of its Subsidiaries or any of their respective assets or properties is bound, excluding from the foregoing clauses (x) and (y) such conflicts, violations, breaches, defaults, payments or reimbursements, terminations, cancellations, modifications, accelerations and creations and impositions of Liens which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. -7- (b) No declaration, filing or registration with, or notice to or authorization, consent or approval of, any Governmental Authority is necessary for the execution and delivery of this Agreement by EUA or the consummation by EUA of the Merger and other transactions contemplated hereby except as described in Section 4.04 of the EUA Disclosure Letter or the failure of which to obtain could not reasonably be expected to result in an EUA Material Adverse Effect (the "EUA Required Statutory Approvals," it being understood that references in this Agreement to "obtaining" such EUA Required Statutory Approvals shall mean making such declarations, filings or registrations; giving such notices; obtaining such authorizations, consents or approvals; and having such waiting periods expire as are necessary to avoid a violation of law). 4.05 SEC Reports, Financial Statements and Utility Reports. (a) EUA delivered to NEES prior to the execution of this Agreement a true and complete copy of each form, report, schedule, registration statement, registration exemption, if applicable, definitive proxy statement and other document (together with all amendments thereof and supplements thereto) filed by EUA or any of its Subsidiaries with the Securities and Exchange Commission (the "SEC") under the Securities Act of 1933, as amended, and the rules and regulations thereunder (the "Securities Act") and the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder (the "Exchange Act") since December 31, 1995 (as such documents have since the time of their filing been amended or supplemented, the "EUA SEC Reports"), which are all the documents (other than preliminary materials) that EUA and its Subsidiaries were required to file with the SEC under the Securities Act and the Exchange Act since such date. As of their respective dates, EUA SEC Reports (i) complied as to form in all material respects with the requirements of the Securities Act or the Exchange Act, as the case may be, and (ii) did not contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. Each of the audited consolidated financial statements and unaudited interim consolidated financial statements (including, in each case, the notes, if any, thereto) included in EUA SEC Reports (the "EUA Financial Statements") complied as to form in all material respects with the published rules and regulations of the SEC with respect thereto, were prepared in accordance with U.S. generally accepted accounting principles ("US GAAP") applied on a consistent basis during the periods involved (except as may be indicated therein or in the notes thereto and except with respect to unaudited statements as permitted by Form 10-Q of the SEC) and fairly present (subject, in the case of the unaudited interim financial statements, to normal, recurring year-end audit adjustments (which are not expected to be, individually or in the aggregate, materially adverse to EUA and its Subsidiaries taken as a whole)) the consolidated financial position of EUA and its consolidated subsidiaries as at the respective dates thereof and the consolidated results of their operations and cash flows for the respective periods then ended. Except as set forth in Section 4.05 of the EUA Disclosure Letter, each Subsidiary of EUA is treated as a consolidated subsidiary of EUA in EUA Financial Statements for all periods covered thereby. (b) All filings (other than immaterial filings) required to be made by EUA or any of its Subsidiaries since December 31, 1995, under the Public -8- Utility Holding Company Act of 1935 (the "1935 Act"), the Federal Power Act, the Atomic Energy Act of 1954, the Communications Act of 1934, and applicable state laws and regulations, have been filed with the SEC, the Federal Energy Regulatory Commission (the "FERC"), the Department of Energy (the "DOE"), the Nuclear Regulatory Commission (the "NRC"), the Federal Communications Commission (the "FCC") or any appropriate state public utility commissions (including, without limitation, to the extent required, the state public utility regulatory agencies of Massachusetts, Rhode Island, New Hampshire, Maine, Vermont and Connecticut as the case may be, including all forms, statements, reports, agreements (oral or written) and all documents, exhibits, amendments and supplements appertaining thereto, including but not limited to all rates, tariffs, franchises, service agreements and related documents and all such filings complied, as of their respective dates, in all material respects with all applicable requirements of the appropriate statutes and the rules and regulations thereunder. 4.06 Absence of Certain Changes or Events. Except as set forth in Section 4.06 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date of this Agreement since December 31, 1997, EUA and each of EUA's Subsidiaries have conducted its business only in the ordinary course of business consistent with past practice and there has not been, and no fact or condition exists which, individually or in the aggregate, has or could reasonably be expected to have an EUA Material Adverse Effect. 4.07 Legal Proceedings. Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or in Section 4.07 of the EUA Disclosure Letter and except for environmental matters which are governed by Section 4.13, (i) there are no actions, claims, hearings, suits, arbitrations or proceedings pending or, to the knowledge of EUA or any of its Subsidiaries, threatened against, specifically relating to or affecting, and, to the knowledge of EUA or any of its Subsidiaries, there are no Governmental Authority investigations or audits pending or threatened against, specifically relating to or affecting, EUA or any of its Subsidiaries or any of their respective assets and properties which, individually or in the aggregate, could reasonably be expected to have an EUA Material Adverse Effect and (ii) neither EUA nor any of its Subsidiaries is subject to any order of any Governmental Authority which, individually or in the aggregate, could reasonably be expected to have an EUA Material Adverse Effect. 4.08 Information Supplied. (a) The proxy statement relating to EUA Shareholders' Meeting, as amended or supplemented from time to time (as so amended and supplemented, the "Proxy Statement"), and any other documents to be filed by EUA with the SEC (including, without limitation, under the 1935 Act) or any other Governmental Authority in connection with the Merger and other transactions contemplated hereby will comply as to form in all material respects with the requirements of the Exchange Act, the Securities Act and the 1935 Act, as applicable, and will not, on the date of their respective filings or, in the case of the Proxy Statement, at the date it is mailed to Shareholders of EUA and at the time of EUA Shareholders' Meeting (as defined in Section 7.03), contain any untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in light of the circumstances under which they are made, not misleading. -9- (b) Notwithstanding the foregoing provisions of this Section 4.08, no representation or warranty is made by EUA with respect to statements made or incorporated by reference in the Proxy Statement based on information supplied by NEES or LLC for inclusion or incorporation by reference therein. 4.09 Compliance. Except as set forth in Section 4.09 of the EUA Disclosure Letter, or as disclosed in EUA SEC Reports filed prior to the date hereof, neither EUA nor any of EUA's Subsidiaries is in violation of, is, to the knowledge of EUA, under investigation with respect to any violation of, or has been given notice or been charged with any violation of, any law, statute, order, rule, regulation, ordinance or judgment (including, without limitation, any applicable environmental law, ordinance or regulation) of any Governmental Authority, except for possible violations which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. Except as set forth in Section 4.09 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date hereof, EUA and EUA's Subsidiaries have all permits, licenses, franchises and other governmental authorizations, consents and approvals necessary to conduct their businesses as presently conducted except for such failures which could not reasonably be expected to have an EUA Material Adverse Effect. Neither EUA nor any of EUA's Subsidiaries is in breach or violation of, or in default in the performance or observance of any term or provision of, (i) the EUA Trust Agreement, in the case of EUA, or articles of incorporation or organization or by-laws, in the case of EUA's Subsidiaries, or (ii) any contract, commitment, agreement, indenture, mortgage, loan agreement, note, lease, bond, license, approval or other instrument to which it is a party or by which EUA or any Subsidiary of EUA is bound or to which any of their respective property is subject, except for possible violations, breaches or defaults which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. 4.10 Taxes. Except as disclosed in Section 4.10 of the EUA Disclosure Letter: (a) Filing of Timely Tax Returns. EUA and each of its Subsidiaries have timely filed all Tax Returns required to be filed by each of them under applicable law. All Tax Returns were (and, as to Tax Returns not filed as of the date hereof, will be) true, complete and correct; (b) Payment of Taxes. EUA and each of its Subsidiaries have, within the time and in the manner prescribed by law, paid (and until the Closing Date will pay within the time and in the manner prescribed by law) all Taxes that are currently due and payable except for those contested in good faith and for which adequate reserves have been taken; (c) Tax Reserves. EUA and its Subsidiaries have established (and until the Closing Date will maintain) on their books and records adequate reserves for all Taxes and for any liability for deferred income taxes in accordance with GAAP; -10- (d) Extensions of Time for Filing Tax Returns. Neither EUA nor any of its Subsidiaries has requested any extension of time within which to file any Tax Return, which Tax Return has not since been filed; (e) Waivers of Statute of Limitations. Neither EUA nor any of its Subsidiaries has in effect any extension, outstanding waivers or comparable consents regarding the application of the statute of limitations with respect to any Taxes or Tax Returns; (f) Expiration of Statute of Limitations. The Tax Returns of EUA, each of its Subsidiaries and any affiliated, consolidated, combined or unitary group that includes EUA or any of its Subsidiaries either have been examined and settled with the appropriate Tax authority or closed by virtue of the expiration of the applicable statute of limitations for all years through and including 1993; (g) Audit, Administrative and Court Proceedings. No audits or other administrative proceedings or court proceedings are presently pending or threatened with regard to any Taxes or Tax Returns of EUA or any of its Subsidiaries (other than those being contested in good faith and for which adequate reserves have been established) and no issues have been raised in writing by any Tax authority in connection with any Tax or Tax Return; (h) Tax Liens. There are no Tax liens upon any asset of EUA or any of its Subsidiaries except liens for Taxes not yet due. (i) Powers of Attorney. No power of attorney currently in force has been granted by EUA or any of its Subsidiaries concerning any Tax matter; (j) Tax Rulings. Neither EUA nor any of its Subsidiaries has, during the five year period prior to the date of this Agreement, received a Tax Ruling (as defined below) or entered into a Closing Agreement (as defined below) with any taxing authority. "Tax Ruling", as used in this Agreement, shall mean a written ruling of a taxing authority relating to Taxes. "Closing Agreement", as used in this Agreement, shall mean a written and legally binding agreement with a taxing authority relating to Taxes; (k) Availability of Tax Returns. EUA and its Subsidiaries have made available to NEES complete and accurate copies, covering all years ending on or after December 31, 1993, of (i) all Tax Returns, and any amendments thereto, filed by EUA or any of its Subsidiaries, (ii) all audit reports received from any taxing authority relating to any Tax Return filed by EUA or any of its Subsidiaries and (iii) any Closing Agreements entered into by EUA or any of its Subsidiaries with any taxing authority. (l) Tax Sharing Agreements. No agreements relating to the allocation or sharing of Taxes exist between or among EUA and any of its Subsidiaries and neither EUA nor any of its Subsidiaries (i) has been a member of an affiliated group filing a consolidated federal income tax return (other -11- than a group the common parent of which was EUA) or (ii) has any liability for Taxes of any Person (other than EUA or its Subsidiaries) under United States Treasury Regulation Section 1.1502-6 (or any provision of state, local), or foreign law, as a transferee or successor, by contract or otherwise; (m) Code Section 481 Adjustments. Neither EUA nor any of its Subsidiaries is required to include in income any adjustment pursuant to Code Section 481(a) by reason of a voluntary change in accounting method initiated by EUA or any of its Subsidiaries, and, the Internal Revenue Service ("IRS") has not proposed any such adjustment or change in accounting method; (n) Code Sections 6661 and 6662. All transactions that could give rise to an understatement of federal income tax, and within the meaning of Code Section 6662 have been adequately disclosed (or, with respect to Tax Returns filed following the Closing, will be adequately disclosed) on the Tax Returns of EUA and its Subsidiaries in accordance with Code Section 6662(d)(2)(B); (o) Intercompany Transactions. Neither EUA nor any of its Subsidiaries has engaged in any intercompany transactions within the meaning of Treasury Regulations ss. 1.1502-13 for which any income or gain will remain unrecognized as of the close of the last taxable year prior to the Closing Date; and (p) Foreign Tax Returns. Neither EUA nor any of its Subsidiaries is required to file a foreign tax return. "Taxes" as used in this Agreement, shall mean any federal, state, county, local or foreign taxes, charges, fees, levies, or other assessments, including all net income, gross income, premiums, sales and use, ad valorem, transfer, gains, profits, windfall profits, excise, franchise, real and personal property, gross receipts, capital stock, production, business and occupation, employment, disability, payroll, license, estimated, stamp, custom duties, severance or withholding taxes, other taxes or similar charges of any kind whatsoever imposed by any governmental entity, whether imposed directly on a Person or resulting under Treasury Regulation Section 1.1502-6 (or any similar provision of state, local or foreign law), as a transferee or successor, by contract or otherwise and includes any interest and penalties on or additions to any such taxes or in respect of a failure to comply with any requirement relating to any Tax Return. "Tax Return" as used in this Agreement, shall mean a report, return or other information required to be supplied to a governmental entity with respect to Taxes including, where permitted or required, combined, unitary or consolidated returns for any group of entities. 4.11 Employee Benefit Plans; ERISA. (a) Each "employee benefit plan" (as defined in Section 3(3) of the Employee Retirement Income Security Act of 1974, as amended ("ERISA")), bonus, deferred compensation, share option or other written agreement relating to employment or fringe benefits for employees, former employees, officers, trustees or directors of EUA or any of its Subsidiaries effective as of the date hereof or providing benefits as of the date hereof to current employees, former employees, officers, trustees or -12- directors of EUA or pursuant to which EUA or any of its subsidiaries has or could reasonably be expected to have any liability (collectively, the "EUA Employee Benefit Plans") is listed in Section 4.11(a) of the EUA Disclosure Letter, is in material compliance with applicable law, and has been administered and operated in all material respects in accordance with its terms. Each EUA Employee Benefit Plan which is intended to be qualified within the meaning of Section 401(a) of the Code has received a favorable determination letter from the IRS as to such qualification and, to the knowledge of EUA, no event has occurred and no condition exists which could reasonably be expected to result in the revocation of, or have any adverse effect on, any such determination. (b) Complete and correct copies of the following documents have been made available to NEES as of the date of this Agreement: (i) all EUA Employee Benefit Plans and any related trust agreements or insurance contracts, (ii) the most current summary descriptions of each EUA Employee Benefit Plan subject to ERISA, (iii) the three most recent Form 5500s and Schedules thereto for each EUA Employee Benefit Plan subject to such reporting, (iv) the most recent determination of the IRS with respect to the qualified status of each EUA Employee Benefit Plan that is intended to qualify under Section 401(a) of the Code, (v) the most recent accountings with respect to each EUA Employee Benefit Plan funded through a trust and (vi) the most recent actuarial report of the qualified actuary of each EUA Employee Benefit Plan with respect to which actuarial valuations are conducted. (c) Except as set forth in Section 4.11(c) of the EUA Disclosure Letter, neither EUA nor any Subsidiary maintains or is obligated to provide benefits under any EUA Employee Benefit Plan (other than as an incidental benefit under a Plan qualified under Section 401(a) of the Code) which provides health or welfare benefits to retirees or other terminated employees other than benefit continuations as required pursuant to Section 601 of ERISA. Each EUA Employee Benefit Plan subject to the requirements of Section 601 of ERISA has been operated in material compliance therewith. EUA has not contributed to a nonconforming group health plan (as defined in Code Section 5000(c)) and no person under common control with EUA within the meaning of Section 414 of the Code ("ERISA Affiliate") has incurred a tax liability under Code Section 5000(a) that is or could reasonably be expected to be a liability of EUA's. (d) Except as set forth in Section 4.11(d) of the EUA Disclosure Letter, each EUA Employee Benefit Plan covers only employees who are employed by EUA or a Subsidiary (or former employees or beneficiaries with respect to service with EUA or a Subsidiary). (e) Except as set forth in Section 4.11(e) of the EUA Disclosure Letter, neither EUA, any Subsidiary, any ERISA Affiliate nor any other corporation or organization controlled by or under common control with any of the foregoing within the meaning of Section 4001 of ERISA has, within the five-year period preceding the date of this Agreement, at any time contributed to any "multiemployer plan," as that term is defined in Section 4001 of ERISA. -13- (f) No event has occurred, and there exists no condition or set of circumstances in connection with any EUA Employee Benefit Plan, under which EUA or any Subsidiary, directly or indirectly (through any indemnification agreement or otherwise), could be subject to any liability under Section 409 of ERISA, Section 502(i) of ERISA, Title IV of ERISA or Section 4975 of the Code except for instances of non-compliance which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. (g) Neither EUA nor any ERISA Affiliate has incurred any liability to the Pension Benefit Guaranty Corporation (the "PBGC") under Section 302(c)(ii), 4062, 4063, 4064 or 4069 of ERISA, or otherwise that has not been satisfied in full and no event or condition exists or has existed which could reasonably be expected to result in any such material liability. As of the date of this Agreement, no "reportable event" within the meaning of Section 4043 of ERISA has occurred with respect to any EUA Employee Benefit Plan that is a defined benefit plan under Section 3(35) of ERISA. (h) Except as set forth in Section 4.11(h) of the EUA Disclosure Letter, no employer securities, employer real property or other employer property is included in the assets of any EUA Employee Benefit Plan. (i) Full payment has been made of all material amounts which EUA or any affiliate thereof was required under the terms of EUA Employee Benefit Plans to have paid as contributions to such plans on or prior to the Effective Time (excluding any amounts not yet due) and no EUA Employee Benefit Plan which is subject to Part III of Subtitle B of Title I of ERISA has incurred any "accumulated funding deficiency" within the meaning of Section 302 of ERISA or Section 412 of the Code, whether or not waived. (j) Except as set forth in Section 4.11(j) of the EUA Disclosure Letter, no amounts payable under any EUA Employee Benefit Plan or other agreement, contract, or arrangement will fail to be deductible for federal income tax purposes by virtue of Section 280G or Section 162(m) of the Code. 4.12 Labor Matters. As of the date hereof, except as set forth in Section 4.12 of the EUA Disclosure Letter, neither EUA nor any of its Subsidiaries is a party to any material collective bargaining agreement or other labor agreement with any union or labor organization. To the knowledge of EUA, as of the date hereof, there is no current union representation question involving employees of EUA or any of its Subsidiaries, nor does EUA know of any activity or proceeding of any labor organization (or representative thereof) or employee group to organize any such employees. Except as set forth in Section 4.12 of the EUA Disclosure Letter, (i) there is no unfair labor practice, employment discrimination or other employment-related complaint or proceeding against EUA or any of its Subsidiaries pending or, to the knowledge of EUA, threatened, which has or could reasonably be expected to have an EUA Material Adverse Effect, (ii) there is no strike, dispute, slowdown, work stoppage or lockout pending, or, to the knowledge of EUA, threatened, against or involving EUA or any of its Subsidiaries which has or could reasonably be expected to have, an EUA Material Adverse Effect and (iii) there is no proceeding, claim, -14- suit, or action pending or, to the knowledge of EUA or any of its Subsidiaries, threatened, nor, to the knowledge of EUA or any of its Subsidiaries is there any Governmental Authority investigation pending or threatened, in respect of which any trustee, director, officer, employee or agent of EUA or any of its Subsidiaries is or may be entitled to claim indemnification from EUA or any of its Subsidiaries pursuant to the EUA Trust Agreement, in the case of EUA, and their respective articles of incorporation and by-laws, in the case of EUA's Subsidiaries, or as provided in the indemnification agreements listed in Section 4.12 of the EUA Disclosure Letter. Except as set forth in Section 4.12 of the EUA Disclosure Letter, EUA and its Subsidiaries are in compliance with all federal, state and local laws with respect to employment practices and labor relations, including, without limitation, any provisions relating to affirmative action, employment discrimination, wages, hours, collective bargaining, and the payment of social security and similar taxes, safety and health regulations and mass layoffs and plant closings except for such instances of noncompliance which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. 4.13 Environmental Matters. Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or in Section 4.13 of the EUA Disclosure Letter: (a) (i) Each of EUA and its Subsidiaries is in compliance with all applicable Environmental Laws (as hereinafter defined), except where the failure to be in compliance, in the aggregate could not reasonably be expected to result in an EUA Material Adverse Effect; and (ii) Neither EUA nor any of its Subsidiaries has received any written communication from any person or Governmental Authority that alleges that EUA or any of its Subsidiaries is not in such compliance (including the materiality qualifier set forth in clause (i) above) with applicable Environmental Laws. (b) Each of EUA and its Subsidiaries has obtained all environmental, health and safety permits and governmental authorizations (collectively, the "Environmental Permits") necessary for the construction of their facilities and the conduct of their operations, as applicable, and all such Environmental Permits are in good standing or, where applicable, a renewal application has been timely filed and agency approval is expected in the ordinary course of business, and EUA and its Subsidiaries are in compliance with all terms and conditions of the Environmental Permits, except where the failure have such Environmental Permits, file a renewal application for such Environmental Permits, or to be in compliance with such Environmental Permits, in the aggregate could not reasonably be expected to result in an EUA Material Adverse Effect. (c) There is no Environmental Claim (as hereinafter defined) that could, individually or in the aggregate, reasonably be expected to have an EUA Material Adverse Effect pending (i) against EUA or any of its Subsidiaries; (ii) against any person or entity whose liability for any Environmental Claim EUA or any of its Subsidiaries has or may have retained or assumed either contractually or by operation of law; or (iii) against any real or personal -15- property or operations which EUA or any of its Subsidiaries owns, leases or manages, in whole or in part. (d) To the knowledge of EUA there have not been any material Releases (as hereinafter defined) of any Hazardous Material (as hereinafter defined) that would be reasonably likely to form the basis of any material Environmental Claim against EUA or any of its Subsidiaries, or against any person or entity whose liability for any material Environmental Claim EUA or any of its Subsidiaries has or may have retained or assumed either contractually or by operation of law, except for any Environmental Claim that, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. (e) To the knowledge of EUA with respect to any predecessor of EUA or any of its Subsidiaries, there is no material Environmental Claim pending or threatened, and there has been no Release of Hazardous Materials that could reasonably be expected to form the basis of any material Environmental Claim except for any Environmental Claim that, individually or in the aggregate, could not be reasonably be expected to have an EUA Material Adverse Effect. (f) As used in this Section 4.13: (i) "Environmental Claim" means any and all written administrative, regulatory or judicial actions, suits, demands, demand letters, directives, claims, liens, investigations, proceedings or notices or noncompliance, liability or violation by any person or entity (including any Governmental Authority) alleging potential liability (including, without limitation, potential responsibility or liability for enforcement, investigatory costs, cleanup costs, governmental response costs, removal costs, remedial costs, natural resources damages, property damages, personal injuries or penalties) arising out of, based on or resulting from (A) the presence, or Release or threatened Release into the environment, of any Hazardous Materials at any location, whether or not owned, operated, leased or managed by EUA or any of its Subsidiaries; or (B) circumstances forming the basis of any violation, or alleged violation, of any Environmental Law; or (C) any and all claims by any third party seeking damages, contribution, indemnification, cost recovery, compensation or injunctive relief resulting from the presence or Release of any Hazardous Materials; (ii) "Environmental Laws" means all federal, state and local laws, rules and regulations and binding interpretation thereof, relating to pollution, the environment (including, without limitation, ambient air, surface water, groundwater, land surface or subsurface strata) or protection of human health as it relates to the environment including, without limitation, laws and -16- regulations relating to Releases or threatened Releases of Hazardous Materials, or otherwise relating to the manufacture, generation, processing, distribution, use, treatment, storage, disposal, transport or handling of Hazardous Materials; (iii) "Hazardous Materials" means (A) any petroleum or petroleum products, radioactive materials, asbestos in any form that is or could become friable, urea formaldehyde foam insulation, and transformers or other equipment that contain dielectric fluid containing polychlorinated biphenyls; and (B) any chemicals, materials or substances which are now defined as or included in the definition of "hazardous substances", "hazardous wastes", "hazardous materials", "extremely hazardous wastes", "restricted hazardous wastes", "toxic substances", "toxic pollutants", or words of similar import, under any Environmental Law; and (c) any other chemical, material, substance or waste, exposure to which is now prohibited, limited or regulated under any Environmental Law in a jurisdiction in which EUA or any of its Subsidiaries (x) operates or (y) stores, treats or disposes of Hazardous Materials; and (iv) "Release" means any release, spill, emission, leaking, injection, deposit, disposal, discharge, dispersal, leaching or migration into the atmosphere, soil, surface water, groundwater or property. 4.14 Regulation as a Utility. (a) EUA is a public utility holding company registered under Section 5, and subject to the provisions, of the 1935 Act. Section 4.14 of the EUA Disclosure Letter lists the subsidiaries of EUA that are "public utility companies" within the meaning of Section 2(a)(5) of the 1935 Act and lists the jurisdictions where each such Subsidiary is subject to regulation as a public utility company or public service company. Except as set forth above and as set forth in Section 4.14 of the EUA Disclosure Letter, neither EUA nor any "subsidiary company" or "affiliate" of EUA is subject to regulation as a public utility or public service company (or similar designation) by the federal government of the United States, any state in the United States or any political subdivision thereof, or any foreign country. (b) As used in this Section 4.14, the terms "subsidiary company" and "affiliate" shall have the respective meanings ascribed to them in Section 2(a)(8) and Section 2(a)(11), respectively, of the 1935 Act. 4.15 Insurance. Except as set forth in Section 4.15 of the EUA Disclosure Letter, each of EUA and its Subsidiaries is, and has been continuously since January 1, 1994, insured with financially responsible insurers in such amounts and against such risks and losses as are customary in all material respects for companies in the United States conducting the business conducted by EUA and its Subsidiaries during such time period. Except as set forth in Section 4.15 of the EUA Disclosure Letter, neither EUA nor any of its Subsidiaries has received any notice of cancellation or termination with respect to any material insurance policy of EUA or any of its Subsidiaries. The insurance policies of EUA and each of its Subsidiaries are valid and enforceable policies. -17- 4.16 Nuclear Facilities. Montaup Electric Company, a Subsidiary of EUA, is a minority common stockholder of each of Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power Corporation and Yankee Atomic Electric Company (the "Yankee Companies") and a minority joint owner in Millstone 3 and Seabrook 1 (collectively, as described in Section 4.16 of the EUA Disclosure Letter, the "EUA Nuclear Facilities"). With respect to its ownership of Millstone 3 and Seabrook 1, Montaup Electric Company holds the required operating licenses from the NRC. With respect to the Yankee Companies, each Yankee Company holds its own operating license from the NRC. Because it is a minority stockholder or a minority joint owner, Montaup Electric Company does not have responsibility for the operation of EUA Nuclear Facilities. Except as set forth in Section 4.16 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date hereof, to the knowledge of EUA, neither EUA nor any of its Subsidiaries is in violation of any applicable health, safety, regulatory and other legal requirement, including NRC laws and regulations and Environmental Laws, applicable to EUA Nuclear Facilities except for such failure to comply as could not reasonably be expected to have a material adverse effect with respect to EUA Nuclear Facilities and the ownership interest of EUA therein. To the knowledge of EUA, each of EUA Nuclear Facilities maintains emergency plans designed to respond to an unplanned release therefrom of radioactive materials into the environment and insurance coverages consistent with industry practice. EUA has funded, or has caused the funding of, its portion of the decommissioning cost of each of the EUA Nuclear Facilities and the storage of spent nuclear fuel consistent with the most recently approved plan for each of the EUA Nuclear Facilities and FERC authorized rates. Except as set forth in Section 4.16 of the EUA Disclosure Letter, to the knowledge of EUA, no EUA Nuclear Facility is as of the date of this Agreement on the List of Nuclear Power Plants Warranting Increased Regulatory Attention maintained by the NRC. 4.17 Vote Required. The affirmative vote of two-thirds of the outstanding EUA Shares voting as a single class (with each EUA Share having one vote per share) with respect to the approval of the Merger and other transactions contemplated hereby is the only vote of the holders of any class or series of equity securities of EUA or its Subsidiaries required to approve this Agreement and approve the Merger and other transactions contemplated hereby. 4.18 Opinion of Financial Advisor. EUA has received the opinion of Salomon Smith Barney Inc., dated the date of this Agreement, to the effect that, as of such date, the Merger Consideration is fair from a financial point of view to the holders of EUA Shares. A true and complete copy of the written opinion will be delivered to NEES promptly after receipt thereof by EUA. 4.19 Ownership of NEES Common Shares. Neither EUA nor any of its Subsidiaries or other affiliates beneficially owns any NEES Common Shares. 4.20 State Anti-Takeover Statutes. EUA has taken all necessary actions so that the provisions of Chapters 110C, 110D or 110F of the MGL will not apply to this Agreement, the Merger or other transactions contemplated hereby or thereby. -18- 4.21 Year 2000. The Information Systems operated by EUA and its Subsidiaries which is used in the conduct of their business is capable of providing or being adapted to provide uninterrupted millennium functionality to record, store, process and present calendar dates falling on or after January 1, 2000 in substantially the same manner and with the same functionality as such Information Systems record, store, process and present such calendar dates falling on or before December 31, 1999 other than such interruptions in millennium functionality that could not, individually or in the aggregate, reasonably be expected to result in a EUA Material Adverse Effect. EUA reasonably believes as of the date hereof that the remaining cost of adaptations referred to in the foregoing sentence will not exceed the amounts reflected in the Form 10-Q filed by EUA for the quarter ended September 30, 1998 (excluding the fees and costs of any Y2K Consultant retained pursuant to Section 6.01(o) hereof and of the implementation of any recommendations by such Y2K Consultant actually made by EUA that are not already part of EUA's compliance plan as of the date hereof). "Information Systems" means mainframe and midrange hardware, operating system software and applications programs; network and desktop (PC) hardware, operating system software and applications programs; EDI (Electronic Date Interchange) and FTP (File Transfer Protocol) software; and embedded systems hardware and applications software. 4.22 EUA Associates. The representations and warranties set forth in Sections 4.04(a), 4.06, 4.07, 4.09, 4.12 and 4.13 are true and correct in all material respects with regard to EUA Associates. ARTICLE V REPRESENTATIONS AND WARRANTIES OF NEES NEES represents and warrants to EUA as follows: 5.01 Organization and Qualification. NEES is a voluntary association duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has full power, authority and legal right to own its property and assets and to transact the business in which it is engaged. Each of the NEES Subsidiaries is a corporation duly organized or incorporated, validly existing and in good standing under the laws of its jurisdiction of organization or incorporation and has full corporate power and authority to conduct its business as and to the extent now conducted and to own, use and lease its assets and properties, except where failure to be so organized or incorporated, existing and in good standing or to have such power and authority, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. As used in this Agreement, the term "NEES Material Adverse Effect" means a material adverse effect on the business, assets, results of operations, condition (financial or otherwise) or prospects of NEES and its Subsidiaries taken as a whole. LLC is a limited liability company validly existing under the laws of the Commonwealth of Massachusetts. LLC was formed solely for the purpose of engaging in the Merger and other transactions contemplated hereby, has engaged in no other business activities (other than in connection with the formation and capitalization of LLC pursuant to or in -19- accordance with the LLC Agreement (as defined below)) and has conducted its operations only as contemplated hereby and by the LLC Agreement. Each of NEES and its Subsidiaries is duly qualified, licensed or admitted to do business and is in good standing in each jurisdiction in which the ownership, use or leasing of its assets and properties, or the conduct or nature of its business, makes such qualification, licensing or admission necessary, except where failure to be so qualified, licensed or admitted and in good standing, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. NEES has previously delivered to EUA correct and complete copies of its Agreement and Declaration of Trust (the "NEES Trust Agreement") and the articles of association of LLC. 5.02 Authority. Each of NEES and LLC has full power and authority to enter into this Agreement, and to perform its obligations hereunder, and to consummate the Merger and other transactions contemplated hereby. The execution, delivery and performance of this Agreement by each of NEES and LLC and the consummation by each of NEES and LLC of the Merger and other transactions contemplated hereby have been duly authorized by all necessary corporate action on the part of NEES and all necessary action on the part of LLC. This Agreement has been duly and validly executed and delivered by each of NEES and LLC and constitutes a legal, valid and binding obligation of each of NEES and LLC enforceable against each of NEES and LLC in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). 5.03 Capital Stock. The authorized equity securities of NEES consists of 150,000,000 common shares of NEES (the "NEES Shares"), of which 59,170,986 shares were issued and outstanding as of the close of business on January 29, 1999. As of the close of business on January 29, 1999, 5,798,666 NEES Shares were held in the treasury of NEES. All of the issued and outstanding NEES Shares are duly authorized, validly issued, fully paid and nonassessable. Except as may be provided by the New England Electric System Companies' Incentive Share Plan, the New England Electric System Companies Incentive Thrift Plan I, the New England Electric System Companies Incentive Thrift Plan II, the New England Electric Companies Long-Term Performance Share Award Plan, and the New England Electric System Directors' annual retainer shares, and except as set forth in Section 5.03 of the letter dated the date hereof and delivered to EUA by NEES and LLC concurrently with the execution and delivery of this Agreement (the "NEES Disclosure Letter"), on the date hereof there are no outstanding Options obligating NEES or any of its Subsidiaries to issue or sell any shares of equity securities of NEES or to grant, extend or enter into any Option with respect thereto. 5.04 Non-Contravention; Approvals and Consents. (a) The execution and delivery of this Agreement by each of NEES and LLC do not, and the performance by each of NEES and LLC of its obligations hereunder and the consummation of the Merger and other transactions contemplated hereby will not, conflict with, result in a violation or breach of, constitute (with or without notice or lapse of time or both) a default under, result in or give to any person any right of payment or reimbursement, termination, cancellation, modification or -20- acceleration of, or result in the creation or imposition of any Lien upon any of the assets or properties of NEES, or LLC under, any of the terms, conditions or provisions of (i) the NEES Agreement and Declaration of Trust or the articles of organization of LLC, (ii) subject to the actions described in paragraph (b) of this Section, (x) any laws or orders of any Governmental Authority applicable to NEES or LLC or any of their respective assets or properties, or (y) subject to obtaining the third-party consents (the "NEES Required Consents") set forth in Section 5.04 of the NEES Disclosure Letter any Contracts to which NEES is a party or by which NEES or any of its Subsidiaries or any of their respective assets or properties is bound, excluding from the foregoing clauses (x) and (y) conflicts, violations, breaches, defaults, terminations, modifications, accelerations and creations and impositions of Liens which, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. (b) No declaration, filing or registration with, or notice to or authorization, consent or approval of, any Governmental Authority is necessary for the execution and delivery of this Agreement by NEES or LLC or the consummation by NEES or LLC of the Merger and other transactions contemplated hereby except as described in Section 5.04 of the NEES Disclosure Letter or the failure of which to obtain could not reasonably be expected to result in a NEES Material Adverse Effect (the "NEES Required Statutory Approvals," it being understood that references in this Agreement to "obtaining" such NEES Required Statutory Approvals shall mean making such declarations, filings or registrations; giving such notices; obtaining such authorizations, consents or approvals; and having such waiting periods expire as are necessary to avoid a violation of law). 5.05 Information Supplied. (a) The information supplied by NEES or LLC and included in the Proxy Statement with the written consent of NEES or LLC, as the case may be, will not, at the date mailed to EUA's Shareholders or at the time of EUA Shareholder's Meeting, contain any untrue statements of a material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. (b) Notwithstanding the foregoing provisions of this Section 5.05, no representation or warranty is made by NEES with respect to statements made or incorporated by reference in the Proxy Statement based on information supplied by EUA for inclusion or incorporation by reference therein or based on information which is not made in or incorporated by reference in such documents but which should have been disclosed pursuant to this Section 5.05. 5.06 Compliance. Except as set forth in Section 5.06 of the NEES Disclosure Letter, or as disclosed in the NEES Reports filed prior to the date hereof, NEES is not in violation of, is, to the knowledge of NEES, under investigation with respect to any violation of, or has been given notice or been charged with any violation of, any law, statute, order, rule, regulation, ordinance or judgment (including, without limitation, any applicable environmental law, ordinance or regulation) of any Governmental Authority, except for possible violations which, individually or in the aggregate, could -21- not reasonably be expected to have a NEES Material Adverse Effect. Except as set forth in Section 5.06 of the NEES Disclosure Letter or as disclosed in the NEES Reports filed prior to the date hereof, NEES and its Subsidiaries have all material permits, licenses and other governmental authorizations, consents and approvals necessary to conduct their businesses as presently conducted which are material to the operation of the businesses of NEES. NEES is not in breach or violation of, or in default in the performance or observance of, any term or provision of, and no event has occurred which, with lapse of time or action by a third party, could result in a default by NEES under (i) the NEES Agreement and Declaration of Trust or by-laws or (ii) any contract, commitment, agreement, indenture, mortgage, loan agreement, note, lease, bond, license, approval or other instrument to which it is a party or by which NEES is bound or to which any of their respective property is subject, except for possible violations, breaches or defaults which, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. 5.07 Financing. NEES has or will have available, prior to the Effective Time, sufficient cash in immediately available funds to pay or to cause LLC to pay the Merger Consideration pursuant to Article II hereof and to consummate the Merger and other transactions contemplated hereby. 5.08 No Vote Required. No vote of the NEES Shares or of any class or series of equity securities of NEES or its Subsidiaries is necessary for the approval of the Merger and other transactions contemplated hereby. 5.09 Ownership of EUA Shares. Neither NEES nor any of its Subsidiaries or other affiliates beneficially owns any EUA Shares. 5.10 Merger with The National Grid Group plc. NEES has entered into an Agreement and Plan of Merger dated as of December 11, 1998 by and among The National Grid Group plc ("National Grid Group"), NGG Holdings LLC (formerly known as Iosta LLC) and NEES (the "National Grid Merger Agreement"). Pursuant to Section 6.01 of the National Grid Merger Agreement, NEES has provided a copy of this Agreement to National Grid Group, and National Grid Group has given NEES its written consent to enter into this Agreement and consummate the Merger on the terms set forth in this Agreement. Prior to the execution of this Agreement, NEES has provided EUA with a copy of such written consent. ARTICLE VI COVENANTS 6.01 Covenants of EUA. At all times from and after the date hereof until the Effective Time, EUA covenants and agrees as to itself and its Subsidiaries that (except as expressly contemplated or permitted by this Agreement or as set forth in Section 6.01 of the EUA Disclosure Letter, or to the extent that NEES shall otherwise previously consent in writing): -22- (a) Ordinary Course. EUA and each of its Subsidiaries shall conduct their businesses only in, and EUA and each of its Subsidiaries shall not take any action except in, the ordinary course consistent with good utility practice. Without limiting the generality of the foregoing, EUA and its Subsidiaries shall use all commercially reasonable efforts to preserve intact in all material respects their present business organizations and reputation, to maintain in effect all existing permits, to keep available the services of their key officers and employees, to maintain their assets and properties in good working order and condition, ordinary wear and tear excepted, to maintain insurance on their tangible assets and businesses in such amounts and against such risks and losses as are currently in effect, to preserve their relationships with customers and suppliers and others having significant business dealings with them and to comply in all material respects with all laws and orders of all Governmental Authorities applicable to them. (b) Charter Documents. EUA shall not, nor shall it permit any of its Subsidiaries to, amend or propose to amend the EUA Trust Agreement, in the case of EUA, and its certificate or articles of incorporation or organization or bylaws (or other comparable charter documents), in the case of EUA's Subsidiaries. (c) Dividends. EUA shall not, nor shall it permit any of its Subsidiaries to, (i) declare, set aside or pay any dividends on, or make other distributions in respect of, any of its capital stock or share capital, except: (A) that EUA may continue the declaration and payment of regular quarterly dividends on EUA Shares with usual record and payment dates not, in any fiscal year, in excess of the dividend for the comparable period in the prior fiscal year; (B) that the Subsidiaries of EUA set forth in Section 6.01(c) of the EUA Disclosure Letter may continue the declaration and payment of dividends on preferred stock in accordance with the terms of such stock, with the record and payment dates and in the amounts set forth in Section 6.01(c) of the EUA Disclosure Letter; (C) if the Effective Time does not occur between a record date and payment date of a regular quarterly dividend, for a special dividend on EUA Shares with respect to the quarter in which the Effective Time occurs with a record date on or prior to the date on which the Effective Time occurs, which does not exceed an amount equal to the product of (x) the number of days between the last payment date of a regular quarterly dividend and the record date of such special dividend, multiplied by (y) $.0045; and (D) for dividends and distributions (including liquidating distributions) by a direct or indirect Subsidiary of EUA to its parent. -23- (ii) split, combine, subdivide, reclassify or take similar action with respect to any of its capital stock or share capital or issue or authorize or propose the issuance of any other securities in respect of, in lieu of or in substitution for shares of its capital stock or comprised in its share capital, (iii) adopt a plan of complete or partial liquidation or resolutions providing for or authorizing such liquidation or a dissolution, merger, consolidation, restructuring, recapitalization or other reorganization or (iv) directly or indirectly redeem, repurchase or otherwise acquire any shares of its capital stock or any Option with respect thereto except: (A) in connection with intercompany purchases of capital stock or share capital, (B) for the purpose of funding EUA's dividend reinvestment and share purchase plan in accordance with past practice, or (C) subject to EUA's obligations under the Securities Act and the Exchange Act, pursuant to EUA's previously announced share repurchase program provided that the number of EUA Shares repurchased does not exceed 3,000,000 and the price paid per share does not exceed 95% of the Per Share Amount. (d) Share Issuances. EUA shall not, nor shall it permit any of its Subsidiaries to, issue, deliver or sell, or authorize or propose the issuance, delivery or sale of, any shares of its capital stock or any Option with respect thereto (other than the issuance by a wholly owned Subsidiary of its capital stock to its direct or indirect parent corporation, or modify or amend any right of any holder of outstanding shares of capital stock or Options with respect thereto). (e) Acquisitions. EUA shall not, nor shall it permit any of its Subsidiaries to acquire or agree to acquire (by merging or consolidating with, or by purchasing a substantial equity interest in or substantial portion of the assets of, or by any other manner) any business or any corporation, partnership, association or other business organization or division thereof. (f) Dispositions. EUA shall not, nor shall it permit any of its Subsidiaries to sell, lease, securitize, grant any security interest in or otherwise dispose of or encumber any of its assets or properties, other than dispositions in the ordinary course of its business consistent with past practice and having an aggregate value of less than $1,000,000 for each disposition and $5,000,000 in the aggregate. (g) Indebtedness. EUA shall not, nor shall it permit any of its Subsidiaries to incur or guarantee any indebtedness (including any debt borrowed or guaranteed or otherwise assumed, including, without limitation, the issuance of debt securities or warrants or rights to acquire debt) or enter into any "keep well" or other agreement to maintain any financial condition of another Person or enter into any arrangement having the economic effect of any of the foregoing other than (i) short-term indebtedness in the ordinary course of business consistent with past practice (such as the issuance of commercial paper -24- or the use of existing credit facilities) in amounts not exceeding the amounts set forth in Section 6.01(g) of the EUA Disclosure Letter, (ii) long-term indebtedness in connection with the refinancing of existing indebtedness either at its stated maturity or at a lower cost of funds (calculating such cost on an aggregate after-tax basis) or (iii) guarantees or "keep well" agreements in favor of wholly owned Subsidiaries of EUA in connection with the conduct of the business of such wholly owned Subsidiaries of EUA not aggregating more than $1,000,000. (h) Capital Expenditures. Except (i) as required by law or (ii) as reasonably deemed necessary by EUA after consulting with NEES following a catastrophic event, such as a major storm, EUA shall not, nor shall it permit any of its Subsidiaries to make any capital expenditures or commitments during any fiscal year that is in excess of 110% of (i) the aggregate amount set forth in Section 6.01(h) of the EUA Disclosure Letter with respect to EUA and its Subsidiaries that are public utility companies within the meaning of Section 2(a)(5) of the 1935 Act or (ii) the amount set forth in Section 6.01(h) of the EUA Disclosure Letter with respect to each of EUA's other Subsidiaries. (i) Employee Benefits. EUA shall not, nor shall it permit any of its Subsidiaries to enter into, adopt, amend (except as may be required by applicable law) or terminate any EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy between EUA or one of its Subsidiaries and one or more of its trustees, directors, officers, employees or former employees, or, except for normal increases in the ordinary course of business, (a) increase in any manner the compensation or fringe benefits of any trustee, director or executive officer, (b) increase in any manner the compensation or fringe benefits of any employee, (c) pay any benefit not required by any plan or arrangement in effect as of the date hereof or, (d) cause any trustee, director, officer, employee or former employee of EUA to accrue or receive additional benefits, accelerate vesting or accelerate the payment of any benefits under any EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy. EUA, prior to the Closing Date, shall take all necessary action and make all necessary amendments to its stock-based plans so that all such plans will be in a form that allows the plans to function after the Effective Time and after any merger of EUA and its Subsidiaries into NEES or its Subsidiaries. EUA, prior to the Closing Date, shall take all necessary actions, in a manner satisfactory to NEES, so that on or after the Closing Date, neither EUA, the Surviving Entity nor their affiliates' stock or securities will be required to be held in, or distributed pursuant to, any EUA Employee Benefit Plan. (j) Labor Matters. Notwithstanding any other provision of this Agreement to the contrary, EUA or its Subsidiaries may negotiate successor collective bargaining agreements to those referenced in Section 4.12 hereof, and may negotiate other collective bargaining agreements or arrangements as required by law or for the purpose of implementing the agreements referenced in Section 4.12 hereof. EUA will keep NEES informed as to the status of, and will consult with NEES as to the strategy for, all negotiations with collective bargaining representatives. EUA and its Subsidiaries shall act prudently and reasonably and consistent with their obligation under applicable law in such negotiations. -25- (k) Discharge of Liabilities. EUA shall not, nor shall it permit its Subsidiaries to, pay, discharge or satisfy any material claims, liabilities or obligations (absolute, accrued, asserted or unasserted, contingent or otherwise), other than the payment, discharge or satisfaction, in the ordinary course of business consistent with past practice (which includes the payment of final and unappealable judgments) or in accordance with their terms, of liabilities reflected or reserved against in, or contemplated by, the most recent consolidated financial statements (or the notes thereto) of such party included in EUA SEC Reports, or incurred in the ordinary course of business consistent with past practice. (l) Contracts. EUA shall not, nor shall it permit its Subsidiaries, except in the ordinary course of business consistent with past practice or as set forth in Section 6.01(l) of the EUA Disclosure Letter, (i) to modify, amend, terminate or fail to use commercially reasonable efforts to renew any material Contract to which EUA or any of its Subsidiaries is a party or waive, release or assign any material rights or claims or (ii) to enter into any new material Contracts except as expressly permitted by Sections 6.01 (f), (g) or (i) and 7.06 hereof. (m) Equity Investments. EUA shall not, nor shall it permit its Subsidiaries or affiliates to, make equity contributions to non-affiliates or to its non-utility Subsidiaries. (n) Loans. EUA shall not, nor shall it permit its Subsidiaries or affiliates to, loan money to non-affiliates or to its non-utility Subsidiaries. (o) Year 2000. EUA, within 15 days of the date of this Agreement, shall engage a qualified third party ("Y2K Consultant") to conduct a detailed assessment of the adequacy and state of completion of its Year 2000 Program, including but not limited to assessment and testing of its customer, accounting, and operational systems. The Y2K Consultant and scope of work of the Y2K Consultant shall be acceptable to NEES. Such assessment and testing shall be completed as soon thereafter as practicable. EUA shall have such assessment updated by the Y2K Consultant at the end of each fiscal quarter of 1999. EUA shall allow designated NEES personnel and representatives access to the Y2K Consultant's personnel, reports and recommendations and access to EUA's personnel, documents, and information related to the Y2K issue. EUA and the third party shall meet with such designated NEES personnel and representatives on a periodic basis (but not less frequently than monthly) to update NEES on EUA's Year 2000 Program. If this Agreement is terminated pursuant to Section 9.01 hereof, NEES shall reimburse EUA for the costs and expenses of the Y2K Consultant. (p) Insurance. EUA shall, and shall cause its Subsidiaries to, maintain with financially responsible insurance companies (or through self-insurance, consistent with past practice) insurance in such amounts and against such risks and losses as are customary for companies engaged in their respective businesses. (q) 1935 Act. EUA shall not, nor shall it permit any of its Subsidiaries to, engage in any activities which would cause a change in its status, or that of its Subsidiaries, under the 1935 Act. -26- (r) Regulatory Matters. Subject to applicable law and except for non-material filings in the ordinary course of business consistent with past practice, EUA shall consult with NEES prior to implementing any changes in its or any of its Subsidiaries' rates or charges, standards of service or accounting or executing any agreement with respect thereto that is otherwise permitted under this Agreement and shall, and shall cause its Subsidiaries to, deliver to NEES a copy of each such filing or agreement at least four (4) business days prior to the filing or execution thereof so that NEES may comment thereon. EUA shall, and shall cause its Subsidiaries to, make all such filings (i) only in the ordinary course of business consistent with past practice or (ii) as required by a Governmental Authority or regulatory agency with appropriate jurisdiction. (s) Accounting. EUA shall not, nor shall it permit any of its Subsidiaries to make any changes in their accounting methods, policies or procedures, except as required by law, rule, regulation or applicable generally accepted accounting principles; (t) Tax Status. Neither EUA nor any of its Subsidiaries shall (i) make or rescind any material express or deemed election relating to Taxes, (ii) make a request for a Tax Ruling or enter into a Closing Agreement, (iii) settle or compromise any material claim, action, suit, litigation, proceeding, arbitration, investigation, audit, or controversy relating to Taxes or (iv) change in any material respect any of its methods of reporting income, deductions or accounting for federal income tax purposes from those employed in the preparation of its federal income Tax Return for the taxable year ending December 31, 1997, except as may be required by applicable law. (u) No Breach. EUA shall not, nor shall it permit any of its Subsidiaries to willfully take or fail to take any action that would or is reasonably likely to result in (i) a material breach of any provision of this Agreement or (ii) its representations and warranties set forth in this Agreement being untrue in any material respect on and as of the Closing Date. (v) Advice of Changes. EUA shall confer with NEES on a regular and frequent basis with respect to EUA's business and operations and other matters relevant to the Merger to the extent permitted by law, and shall promptly advise NEES, orally and in writing, of any material change or event, including, without limitation, any complaint, investigation or hearing by any Governmental Authority (or communication indicating the same may be contemplated) or the institution or threat of material litigation; provided that EUA shall not be required to make any disclosure to the extent such disclosure would constitute a violation of any applicable law or regulation. (w) Notice and Cure. EUA will notify NEES in writing of, and will use all commercially reasonable efforts to cure before the Closing, any event, transaction or circumstance, as soon as practical after it becomes known to EUA, that causes or will or may be likely to cause any covenant or agreement of EUA under this Agreement to be breached or that renders or will render untrue in any material respect any representation or warranty of EUA contained in this Agreement. EUA also will notify NEES in writing of, and will use all -27- commercially reasonable efforts to cure, before the Closing, any material violation or breach, as soon as practical after it becomes known to EUA, of any representation, warranty, covenant or agreement made by EUA. No notice given pursuant to this paragraph shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein. (x) Fulfillment of Conditions. Subject to the terms and conditions of this Agreement, EUA will take or cause to be taken all commercially reasonable steps necessary or desirable and proceed diligently and in good faith to satisfy each condition to the other's obligations contained in this Agreement and to consummate and make effective the Merger and other transactions contemplated by this Agreement, and EUA will not, nor will it permit any of its Subsidiaries to, take or fail to take any action that could be reasonably expected to result in the nonfulfillment of any such condition. (y) Third Party Standstill Agreements. Except as provided in Section 7.08 hereto, during the period from the date of this Agreement through the Effective Time, neither EUA nor any of its Subsidiaries shall terminate, amend, modify or waive any provision of any confidentiality or standstill agreement to which it is a party. During such period, EUA shall take all steps necessary to enforce, to the fullest extent permitted under applicable law, the provisions of any such agreement. 6.02 Covenants of NEES. At all times from and after the date hereof until the Effective Time, NEES covenants and agrees that (except as expressly contemplated or permitted by this Agreement or to the extent that EUA shall otherwise previously consent in writing): (a) No Breach. NEES shall not, nor shall it permit any of its Subsidiaries to, except as otherwise expressly provided for in this Agreement, willfully take or fail to take any action that would or is reasonably likely to result in (i) a material breach of any of its covenants or agreements contained in this Agreement or (ii) any of its representations and warranties set forth in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.06, 5.07, 5.08 and 5.09 of this Agreement being untrue in any material respect on and as of the Closing Date. (b) Advice of Changes. NEES shall confer with EUA on a regular and frequent basis with respect to any matter having, or which, insofar as can be reasonably foreseen, could reasonably be expected to have, a NEES Material Adverse Effect or materially impair the ability of NEES to consummate the Merger and other transactions contemplated hereby; provided that NEES shall not be required to make any disclosure to the extent such disclosure would constitute a violation of any applicable law or regulation. (c) Notice and Cure. NEES will notify EUA in writing of, and will use all commercially reasonable efforts to cure before the Closing, any event, transaction or circumstance, as soon as practical after it becomes known to NEES, that causes or will or may be likely to cause any covenant or agreement of NEES under this Agreement to be breached or that renders or will render -28- untrue in any material respect any representation or warranty of NEES contained in this Agreement. NEES also will notify EUA in writing of, and will use all commercially reasonable efforts to cure before the Closing, any material violation or breach, as soon as practical after it becomes known to such party, of any representation, warranty, covenant or agreement made by NEES. No notice given pursuant to this paragraph shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein. (d) Fulfillment of Conditions. Subject to the terms and conditions of this Agreement, NEES will take or cause to be taken all commercially reasonable steps necessary or desirable and proceed diligently and in good faith to satisfy each condition to its obligations contained in this Agreement and to consummate and make effective the Merger and other transactions contemplated by this Agreement, and NEES will not, nor will it permit any of its Subsidiaries to, take or fail to take any action that could be reasonably expected to result in the nonfulfillment of any such condition. (e) Conduct of Business of LLC. Prior to the Effective Time, except as may be required by applicable law and subject to the other provisions of this Agreement, NEES shall cause LLC to (i) perform its obligations under this Agreement in accordance with its terms, and (ii) not engage directly or indirectly in any business or activities of any type or kind and not enter into any agreements or arrangements with any person, or be subject to or bound by any obligation or undertaking, which is inconsistent with this Agreement. (f) Certain Mergers. NEES shall not, and shall not permit any of its Subsidiaries to, acquire or agree to acquire by merging or consolidating with, or by purchasing a substantial portion of the assets of or equity in, or by any other manner, any business or any corporation, partnership, association or other business organization or division thereof, or otherwise acquire or agree to acquire any assets if the entering into of a definitive agreement relating to or the consummation of such acquisition, merger or consolidation could reasonably be expected to (i) impose any material delay in the obtaining of, or significantly increase the risk of not obtaining, any authorizations, consents, orders, declarations or approvals of any Governmental Authority necessary to consummate the Merger or the expiration or termination of any applicable waiting period, (ii) significantly increase the risk of any Governmental Authority entering an order prohibiting the consummation of the Merger, (iii) significantly increase the risk of not being able to remove any such order on appeal or otherwise or (iv) materially delay the consummation of the Merger. 6.03 Additional Covenants by NEES and EUA. (a) Control of Other Party's Business. Nothing contained in this Agreement shall give NEES, directly or indirectly, the right to control or direct EUA's operations prior to the Effective Time. Nothing contained in this Agreement shall give EUA, directly or indirectly, the right to control or direct NEES' operations prior to the Effective Time. Prior to the Effective Time, each of EUA and NEES shall exercise, consistent with the terms and conditions of this Agreement, complete control and supervision over its respective operations. -29- (b) Transition Steering Team. As soon as reasonably practicable after the date hereof, NEES and EUA shall create a special transition steering team, with representation from EUA and NEES, that will develop recommendations concerning the future structure and operations of EUA after the Effective Time, subject to applicable law. The members of the transition steering team shall be appointed by the Chief Executive Officers of NEES and EUA. The functions of the transition steering team shall include (i) to direct the exchange of information and documents between the parties and their Subsidiaries as contemplated by Section 7.01 and (ii) the development of regulatory plans and proposals, corporate organizational and management plans, workforce combination proposals, and such other matters as they deem appropriate. ARTICLE VII ADDITIONAL AGREEMENTS 7.01 Access to Information. EUA shall, and shall cause each of its Subsidiaries to, and shall use commercially reasonable efforts to cause EUA Associates to, throughout the period from the date hereof to the Effective Time to the extent permitted by law, (i) provide NEES and its Representatives with full access, upon reasonable prior notice and during normal business hours, to all facilities, operations, officers (including EUA's environmental, health and safety personnel), employees, agents and accountants of EUA and its Subsidiaries and Associates and their respective assets, properties, books and records, to the extent EUA or any Subsidiary of EUA or EUA Associate is not under a legal obligation not to provide access or to the extent that such access would not constitute a waiver of the attorney client privilege and does not unreasonably interfere with the business and operations of EUA and its Subsidiaries and Associates and (ii) furnish promptly to such persons (x) a copy of each report, statement, schedule and other document filed or received by EUA or any of its Subsidiaries pursuant to the requirements of federal or state securities laws and each material report, statement, schedule and other document filed with any other Governmental Authority, and (y) all other information and data (including, without limitation, copies of Contracts, EUA Employee Benefit Plans, and other books and records) concerning the business and operations of EUA and its Subsidiaries as NEES or any of its Representatives reasonably may request. No review pursuant to this Section 7.01 or otherwise shall affect any representation or warranty contained in this Agreement or any condition to the obligations of the parties hereto. Any such information or material obtained pursuant to this Section 7.01 that constitutes "Evaluation Material" (as such term is defined in the letter agreement dated as of December 18, 1998 between EUA and NEES (the "Confidentiality Agreement")) shall be governed by the terms of the Confidentiality Agreement. NEES may provide information or materials that it obtains relating to EUA or any EUA Subsidiary pursuant to this Section 7.01 to National Grid Group; the treatment by National Grid Group of such information or material shall be governed by the terms of the letter agreement dated as of December 21, 1998 between EUA and National Grid Group. 7.02 Proxy Statement. As soon as reasonably practicable after the date of this Agreement, EUA shall prepare and file the Proxy Statement with the -30- SEC. NEES and EUA shall cooperate with each other in the preparation of the Proxy Statement and any amendment or supplement thereto, and EUA shall promptly notify NEES of the receipt of any comments of the SEC with respect to the Proxy Statement and of any requests by the SEC for any amendment or supplement thereto or for additional information, and shall promptly provide to NEES copies of all correspondence between EUA or any of its Representatives and the SEC with respect to the Proxy Statement (except reports from financial advisors other than with the consent of such financial advisors). Each of the parties hereto shall furnish all information concerning itself which is required or customary for inclusion in the Proxy Statement. EUA shall consult with NEES regarding the Proxy Statement and have due regard to any comments NEES may make in relation to the Proxy Statement. EUA shall give NEES and its counsel the opportunity to review the Proxy Statement and all responses to requests for additional information by and replies to comments of the SEC before their being filed with, or sent to, the SEC. Each of EUA and NEES agrees to use its reasonable best efforts, after consultation with the other parties hereto, to respond promptly to all such comments of and requests by the SEC. After obtaining the consent of EUA, which consent shall not be unreasonably withheld, NEES may provide information supplied to NEES by EUA to National Grid Group for inclusion of such information in the Super Class 1 circular ("NGG Circular") to be issued to shareholders of National Grid Group in connection with approval by such shareholders of the National Grid Merger Agreement. NEES shall use its best efforts to provide EUA with a draft of any portion of the NGG Circular with information relating to EUA prior to the issuance of the NGG Circular. 7.03 Approval of Shareholders. EUA shall, through its Board of Trustees, duly call, give notice of, convene and hold a meeting of its shareholders (the "EUA Shareholders' Meeting") for the purpose of voting on the approval of the Merger and other transactions contemplated hereby (the "EUA Shareholders' Approval") as soon as reasonably practicable after the date hereof; provided, however, subject to the fiduciary duties of its Board of Trustees and the requirements of applicable law, EUA shall include in the Proxy Statement the recommendation of the Board of Trustees of EUA that the Shareholders of EUA approve the Merger and the other transactions contemplated hereby, and shall use its reasonable best efforts to obtain such approval. 7.04 Regulatory and Other Approvals. (a) HSR Filings. Each party hereto shall file or cause to be filed with the Federal Trade Commission and the Department of Justice any notifications required to be filed by its respective "ultimate parent" company under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"), and the rules and regulations promulgated thereunder with respect to the Merger and other transactions contemplated hereby. Such parties will use all commercially reasonable efforts to make such filings in a timely manner and to respond on a timely basis to any requests for additional information made by either of such agencies. (b) Other Regulatory Approvals. Each party shall cooperate and use its best efforts to promptly prepare and file all necessary applications, notices, petitions, filings and other documents with, and to use all commercially reasonable efforts to obtain all necessary permits, consents, approvals and authorizations of, all Governmental Authorities necessary or -31- advisable to obtain the EUA Required Statutory Approvals, the NEES Required Statutory Approvals and the approvals of the state utility commissions referred to in Section 8.01(d) (collectively, the "NEES-EUA Regulatory Approvals"). The parties agree that they will consult with each other with respect to obtaining the NEES-EUA Regulatory Approvals; provided, however, that NEES shall have primary responsibility for the preparation and filing of any related applications, filings or other material with the SEC, the FERC, the NRC and state utility commissions. EUA shall have the right to review and approve in advance drafts of and final applications, filings and other material (including material with respect to proposed settlements) submitted to or filed with the SEC, the FERC, the NRC and state utility commissions or parties to such proceedings before such Governmental Authority, which approval shall not be unreasonably withheld or delayed. (c) NEES-NGG Regulatory Proceedings. EUA and NEES acknowledge that, at the same time EUA and NEES will be seeking to obtain the NEES-EUA Regulatory Approvals, National Grid Group and NEES will be seeking to obtain the regulatory approvals (the "NEES-NGG Regulatory Approvals") required to consummate the transactions contemplated by the National Grid Merger Agreement. NEES and EUA agree to seek to prosecute the proceedings relating to the NEES-EUA Regulatory Approvals (the "NEES-EUA Regulatory Proceedings") separately from the prosecution by National Grid Group and NEES of the proceedings relating to the NEES-NGG Regulatory Approvals (the "NEES-NGG Regulatory Proceedings"), but recognize that one or more of the NEES-EUA Regulatory Proceedings may be consolidated with one or more of the NEES-NGG Regulatory Proceedings by the relevant Governmental Authority. Upon the request of EUA, NEES will keep EUA reasonably apprised of the status of the NEES-NGG Regulatory Proceedings. 7.05 Employee Benefit Plans. (a) For a period of twelve (12) months immediately following the Closing Date, the compensation, benefits and coverage provided to those non-union individuals who continue to be employees of the Surviving Entity (the "Affected Employees") pursuant to employee benefit plans or arrangements maintained by NEES or the Surviving Entity shall be, in the aggregate, not less favorable (as determined by NEES and the Surviving Entity using reasonable assumptions and benefit valuation methods) than those provided, in the aggregate, to such Affected Employees immediately prior to the Closing Date. In addition to the foregoing, NEES shall, or shall cause the Surviving Entity to, pay any Affected Employee whose employment is terminated by NEES or the Surviving Entity within twelve (12) months of the Closing Date a severance benefit package equivalent to the severance benefit package that would be provided under the NEES Standard Severance Plan as in effect on the date hereof. (b) NEES shall, or shall cause the Surviving Entity to, give the Affected Employees full credit for purposes of eligibility, vesting, benefit accrual (including, without limitation, benefit accrual under any defined benefit pension plans) and determination of the level of benefits under any employee benefit plans or arrangements maintained by NEES or the Surviving Entity in effect as of the Closing Date for such Affected Employees' service with EUA or any Subsidiary of EUA (or any prior employer) to the same extent -32- recognized by EUA or such Subsidiary immediately prior to the Closing Date. With respect to any employee benefit plan or arrangement established by NEES, EUA or the Surviving Entity after the Closing Date (the "Post Closing Plans"), service shall be credited in accordance with the terms of such Post Closing Plans. (c) NEES shall, or shall cause the Surviving Entity to, (i) waive all limitations as to preexisting conditions, exclusions and waiting periods with respect to participation and coverage requirements applicable to the Affected Employees under any welfare benefit plan established to replace any EUA welfare benefit plans in which such Affected Employees may be eligible to participate after the Closing Date, other than limitations or waiting periods that are already in effect with respect to such Affected Employees and that have not been satisfied as of the Closing Date under any welfare plan maintained for the Affected Employees immediately prior to the Closing Date, and (ii) provide each Affected Employee with credit for any co-payments and deductibles paid prior to the Closing Date in satisfying any applicable deductible or out-of-pocket requirements under any welfare plans that such Affected Employees are eligible to participate in after the Closing Date. (d)(i) NEES shall, or shall cause the Surviving Entity and its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving Entity and its Subsidiaries under, all EUA Employee Benefit Plans as in effect on the date hereof; provided, however, that this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity from exercising their rights with respect to all EUA Employee Benefit Plans solely in accordance with their terms, including but not limited to the right to alter, terminate or otherwise amend such EUA Employee Benefit Plans. (ii) NEES shall, or shall cause the Surviving Entity and its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving Entity and its Subsidiaries under, (A) all employment severance, consulting and retention agreements or arrangements as in effect on the date hereof, as set forth in Section 7.05(d)(ii) of the EUA Disclosure Letter, or as modified in accordance with Section 6.01(i) of the EUA Disclosure Letter (such agreements or arrangements, the "EUA Employee Agreements" and the individuals who are parties to such EUA Employee Agreements, the "EUA Executives") and (B) all EUA Employee Benefit Plans in which such EUA Executives participate; provided, however, that this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity from exercising their rights with respect to the EUA Employee Agreements and the EUA Employee Benefit Plans in which such EUA Executives participate, in each case solely in accordance with their terms, including but not limited to the right to alter, terminate or otherwise amend such EUA Employee Agreements and EUA Employee Benefit Plans. (e) Notwithstanding the foregoing, NEES and the Surviving Entity and its subsidiaries shall neither be required to or prevented from merging EUA's benefit plans, agreements, or arrangements into NEES or the Surviving Entity and its subsidiaries benefit plans, agreements, or arrangements or from -33- replacing EUA's benefit plans, agreements or arrangements with NEES or the Surviving Entity and its subsidiaries benefit plans, agreements or arrangements. 7.06 Labor Agreements and Workforce Matters. (a) Labor Agreements. NEES shall honor, or shall cause the appropriate subsidiaries of the Surviving Entity to honor, all collective bargaining agreements of EUA or its subsidiaries in effect as of the Effective Time until their expiration; provided, however, that this undertaking is not intended to prevent NEES or the Surviving Entity and its subsidiaries from exercising their rights with respect to such collective bargaining agreements and in accordance with their terms, including any right to amend, modify, suspend, revoke or terminate any such contract, agreement, collective bargaining agreement or commitment or portion thereof. (b) Workforce Matters. Subject to applicable law and obligations under applicable collective bargaining agreements, for a period of 2 years following the Effective Time, any reductions in workforce in respect of employees of the Surviving Entity and its Subsidiaries shall be made on a fair and equitable basis as determined by the Surviving Entity, with due consideration to prior experience and skills, and any employee whose employment is terminated or job is eliminated during such period shall be entitled to participate on a fair and equitable basis as determined by NEES or the Surviving Entity in the job opportunity and employment placement programs offered by NEES or the Surviving Entity or any of their Subsidiaries for which they are eligible. Any workforce reductions carried out following the Effective Time by the Surviving Entity and its Subsidiaries shall be done in accordance with all applicable collective bargaining agreements and all laws and regulations governing the employment relationship and termination thereof including, without limitation, the Worker Adjustment and Retraining Notification Act, and the regulations promulgated thereunder, and any comparable state or local law. 7.07 Post Merger Operations. (a) NEES Advisory Board. If the Merger is consummated, then, promptly following the closing of the merger contemplated by the National Grid Merger Agreement, NEES shall take such action as is necessary to cause all of the members of the Board of Directors of EUA to be appointed to serve on the advisory board to be formed pursuant to Section 7.07(e) of the National Grid Merger Agreement. (b) Charities. The parties agree that provision of charitable contribution and community support within the New England region serves a number of important goals. After the Effective Time, NEES intends to cause the Surviving Entity to provide charitable contributions and community support within the New England region at annual levels substantially comparable to the annual level of charitable contributions and community support provided, directly or indirectly, by EUA and its public utility subsidiaries within the New England region during 1998. -34- 7.08 No Solicitations. Prior to the Effective Time, EUA agrees: (a) that neither it nor any of its Subsidiaries shall, and it shall use its best efforts to cause its Representatives (as defined in Section 10.10) not to, knowingly initiate, solicit or encourage, directly or indirectly, any inquiries or any proposal or offer (including, without limitation, any proposal or offer to its Shareholders) with respect to a merger, consolidation or other business combination including EUA or any of its significant Subsidiaries (as defined in Rule 1-02(W) of Regulation S-X promulgated under the Exchange Act) other than EUA Cogenex Corporation (an "EUA Significant Subsidiary"), or any acquisition or similar transaction (including, without limitation, a tender or exchange offer) involving the purchase of (i) all or any significant portion of the assets of EUA and its Subsidiaries taken as a whole, (ii) ten percent or more of the outstanding EUA Shares or (iii) 50% or more of the outstanding shares of the capital stock of any EUA Significant Subsidiary (any such proposal or offer being hereinafter referred to as an "Alternative Proposal"), or engage in any negotiations concerning, or provide any confidential information or data to, or have any other discussions with, any person or group relating to an Alternative Proposal, or otherwise knowingly facilitate any effort or attempt to make or implement an Alternative Proposal other than from NEES and its affiliates; (b) that it will immediately cease and cause to be terminated any existing activities, discussions or negotiations with any parties with respect to any Alternative Proposal; and (c) that it will notify NEES immediately if any such inquiries, proposals or offers are received by, any such information is requested from, or any such negotiations or discussions are sought to be initiated or continued with, it or any of such persons; provided, however, that, prior to receipt of the EUA Shareholders' Approval, nothing contained in this Section 7.08 shall prohibit the Board of Trustees of EUA from (i) furnishing information to (but only pursuant to a confidentiality agreement in customary form and having terms and conditions no less favorable to EUA than the Confidentiality Agreement (as defined in Section 7.01)) or entering into discussions or negotiations with any person or group that makes an unsolicited Alternative Proposal, if, and only to the extent that, (A) the Board of Trustees of EUA, based upon advice of outside counsel with respect to fiduciary duties, determines in good faith that such action is necessary for the Board of Trustees to act in a manner consistent with its fiduciary duties to Shareholders under applicable law, (B) the Board of Trustees of EUA has reasonably concluded in good faith (after consultation with its financial advisors) that the person or group making such Alternative Proposal will have adequate sources of financing to consummate such Alternative Proposal and that such Alternative Proposal is likely to be more favorable to EUA's shareholders than the Merger, (C) prior to furnishing such information to, or entering into discussions or negotiations with, such person or group, EUA provides written notice to NEES to the effect that it is furnishing information to, or entering into discussions or negotiations with, such person or group, which notice shall identify such person or group and the material terms of the Alternative Proposal in reasonable detail, and (D) EUA keeps NEES promptly informed of the status and all material information with respect to any such discussions or negotiations; and (ii) to the extent required, complying with Rule 14e-2 promulgated under the Exchange Act with regard to an Alternative Proposal. Nothing in this Section 7.08 shall (x) permit EUA to terminate this Agreement (except as specifically provided in Article IX), (y) permit EUA to enter into any agreement with respect to an Alternative Proposal for so long as this Agreement remains in effect (it being agreed that for so long as this Agreement remains in effect, EUA shall not enter -35- into any agreement with any person or group that provides for, or in any way knowingly facilitates, an Alternative Proposal (other than a confidentiality agreement under the circumstances described above)), or (z) affect any other obligation of EUA under this Agreement. 7.09 Directors' and Officers' Indemnification and Insurance. (a) Indemnification. To the extent, if any, not provided by an existing right of indemnification or other agreement or policy, from and after the Effective Time, NEES shall, or shall cause the Surviving Entity to, to the fullest extent permitted by applicable law, indemnify, defend and hold harmless each person who is now, or has been at any time prior to the date hereof, or who becomes prior to the Effective Time, (x) an officer, trustee or director or (y) an employee covered as of the date hereof (to the extent of the coverage extended as of the date hereof) of EUA or any Subsidiary of EUA (each an "Indemnified Party," and collectively, the "Indemnified Parties") against (i) all losses, expenses (including reasonable attorney's fees and expenses), claims, damages or liabilities or, subject to the first proviso of the next succeeding sentence, amounts paid in settlement, arising out of actions or omissions occurring at or prior to the Effective Time (and whether asserted or claimed prior to, at or after the Effective Time) that are, in whole or in part, based on or arising out of the fact that such person is or was a director, trustee, officer or employee of EUA or any Subsidiary of EUA (the "Indemnified Liabilities"), and (ii) all Indemnified Liabilities to the extent they are based on or arise out of or pertain to the transactions contemplated by this Agreement, in each case, to the extent permitted by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter. In the event of any such loss, expense, claim, damage or liability (whether or not arising before the Effective Time), (i) NEES shall, or shall cause the Surviving Entity to, pay the reasonable fees and expenses of counsel selected by the Indemnified Parties, which counsel shall be reasonably satisfactory to NEES or the Surviving Entity, as appropriate, promptly after statements therefor are received and otherwise advance to such Indemnified Party upon request, reimbursement of documented expenses reasonably incurred, in either case to the extent not prohibited by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter upon receipt of an undertaking by or on behalf of such director, trustee or officer to repay such amounts as and to the extent required by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter, (ii) the Surviving Entity shall cooperate in the defense of any such matter and (iii) any determination required to be made with respect to whether an Indemnified Party's conduct complies with the standards set forth under the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter and the certificate of incorporation or by-laws or similar governing documents of the Surviving Entity shall be made by independent counsel mutually acceptable to the Surviving Entity and the Indemnified Party; provided, however, that the Surviving Entity shall not be liable for any settlement effected without its written consent (which consent shall not be unreasonably withheld) and provided further that no indemnification shall be made if such indemnification is prohibited by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter. -36- (b) Insurance. For a period of six years after the Effective Time, NEES and the Surviving Entity at NEES's election, (i) shall cause to be maintained in effect an extended reporting period for current policies of directors' and officers' liability insurance for the benefit of such persons who are currently covered by such policies of EUA on terms no less favorable than the terms of such current insurance coverage or (ii) shall provide tail coverage for such persons which provides such persons with coverage for a period of six years for acts prior to the Effective Time on terms no less favorable than the terms of such current insurance coverage. (c) Successors. In the event the Surviving Entity or any of its successors or assigns (i) consolidates with or merges into any other person or entity and shall not be the continuing or surviving corporation or entity of such consolidation or merger or (ii) transfers all or substantially all of its properties and assets to any person or entity, then and in either such case, proper provisions shall be made so that the successors and assigns of the Surviving Entity, as applicable, shall assume the obligations set forth in this Section 7.09. (d) Survival of Indemnification. To the fullest extent permitted by law, from and after the Effective Time, all rights to indemnification as of the date hereof in favor of the employees, agents, directors, trustees and officers of EUA and EUA's Subsidiaries with respect to their activities as such prior to the Effective Time, as provided in the EUA Trust Agreement or the respective certificates of incorporation and by-laws or similar governing documents in effect on the date hereof, or otherwise in effect on the date hereof, shall survive the Merger and shall continue in full force and effect for a period of not less than six years from the Effective Time. (e) Benefit. The provisions of this Section 7.09 are intended to be for the benefit of, and shall be enforceable by, each Indemnified Party, his or her heirs and his or her representatives. (f) Amendment of the EUA Trust Agreement. NEES shall not, and shall ensure that the Surviving Entity shall not, amend the EUA Trust Agreement to in any way limit the indemnification provided to the Indemnified Parties under this Section 7.09. 7.10 Expenses. Except as set forth in Section 9.03, whether or not the Merger is consummated, all costs and expenses incurred in connection with the Merger and other transactions contemplated hereby shall be paid by the party incurring such cost or expense, except that the filing fees in connection with the filings required under the HSR Act and the 1935 Act shall be paid by NEES. 7.11 Brokers or Finders. EUA represents, as to itself and its affiliates, that no agent, broker, investment banker, financial advisor or other firm or person is or will be entitled to any broker's, finder's or investment banker's fee or any other commission or similar fee in connection with the Merger and other transactions contemplated by this Agreement except Salomon Smith Barney Inc., whose fees and expenses will be paid by EUA in accordance with EUA's agreement with such firm, and EUA shall indemnify and hold NEES harmless from and against any and all claims, liabilities or obligations with -37- respect to any other such fee or commission or expenses related thereto asserted by any person on the basis of any act or statement alleged to have been made by EUA or its affiliates. 7.12 Anti-Takeover Statutes. If any "fair price", "moratorium", "business combination", "control share acquisition" or other form of anti-takeover statute or regulation shall become applicable to the Merger or other transactions contemplated hereby, EUA and the members of the Board of Trustees of EUA shall grant such approvals and take such actions consistent with their fiduciary duties and in accordance with applicable law as are reasonably necessary so that the Merger and other transactions contemplated hereby may be consummated as promptly as practicable on the terms contemplated hereby and otherwise act to eliminate or minimize the effects of such statute or regulation on the Merger and other transactions contemplated hereby. 7.13 Public Announcements. Except as otherwise required by law or the rules of any applicable securities exchange or national market system or any other Regulatory Authority, so long as this Agreement is in effect, NEES and EUA will not, and will not permit any of their respective Subsidiaries or Representatives to, issue or cause the publication of any press release or make any other public announcement with respect to the Merger and other transactions contemplated by this Agreement without the consent of the other party, which consent shall not be unreasonably withheld. NEES and EUA will cooperate with each other in the development and distribution of all press releases and other public announcements with respect to the Merger and other transactions contemplated hereby, and will furnish the other with drafts of any such releases and announcements as far in advance as practicable. 7.14 Restructuring of the Merger. It may be preferable to effectuate a business combination between NEES and EUA by means of an alternative structure to the Merger. Accordingly, if, prior to satisfaction of the conditions contained in Article VIII hereto, NEES proposes the adoption of an alternative structure that otherwise substantially preserves for NEES and EUA the economic benefits of the Merger and will not materially delay the consummation thereof, then the parties shall use their respective best efforts to effect a business combination among themselves by means of a mutually agreed upon structure other than the Merger that so preserves such benefits; provided, however, that prior to closing any such restructured transaction, all material third party and Governmental Authority declarations, filings, registrations, notices, authorizations, consents or approvals necessary for the effectuation of such alternative business combination shall have been obtained and all other conditions to the parties' obligations to consummate the Merger and other transactions contemplated hereby, as applied to such alternative business combination, shall have been satisfied or waived. -38- ARTICLE VIII CONDITIONS 8.01 Conditions to Each Party's Obligation to Effect the Merger. The respective obligation of each party to effect the Merger and other transactions contemplated hereby is subject to the satisfaction or waiver, at or prior to the Closing, of each of the following conditions: (a) Shareholder Approval. EUA Shareholders' Approval shall have been obtained. (b) HSR Act. Any waiting period (and any extension thereof) applicable to the consummation of the Merger under HSR shall have expired or been terminated. (c) Injunctions or Restraints. No court of competent jurisdiction or other competent Governmental Authority shall have enacted, issued, promulgated, enforced or entered any law or order (whether temporary, preliminary or permanent) which is then in effect and has the effect of making illegal or otherwise restricting, preventing or prohibiting consummation of the Merger or other transactions contemplated hereby. (d) Governmental and Regulatory and Other Consents and Approvals. The NEES Required Statutory Approvals and EUA Required Statutory Approvals shall have been obtained prior to the Effective Time, and shall have become Final Orders (as hereinafter defined). The Final Orders shall not, individually or in the aggregate, impose terms and conditions that (i) could reasonably be expected to have an EUA Material Adverse Effect; (ii) could reasonably be expected to have a NEES Material Adverse Effect; or (iii) materially impair the ability of the parties to complete the Merger. The parties shall have received Final Orders from the Massachusetts Department of Telecommunications and Energy and the Rhode Island Public Utilities Commission pertaining to the recovery of costs (including, without limitation, transaction premium and integration costs) associated with the Merger that are materially consistent with existing policy and previous orders of such agencies. "Final Order" for all purposes of this Agreement means action by the relevant regulatory authority which has not been reversed, stayed, enjoined, set aside, annulled or suspended with respect to which any waiting period prescribed by law before the Merger and other transactions contemplated hereby may be consummated has expired, and as to which all conditions to be satisfied before the consummation of such transactions prescribed by law, regulation or order have been satisfied. 8.02 Conditions to Obligation of NEES and LLC to Effect the Merger. The obligation of NEES and LLC to effect the Merger and other transactions contemplated hereby is further subject to the satisfaction or waiver at or prior to the Closing, of each of the following additional conditions (all or any of which may be waived in whole or in part by NEES and LLC in the sole discretion): -39- (a) Representations and Warranties. The representations and warranties made by EUA in this Agreement, in each case made as if none of such representations or warranties contained any qualification or limitation as to "materiality" or "EUA Material Adverse Effect", shall be true and correct as so made as of the Closing Date as though so made on and as of the Closing Date, except to the extent expressly given as of a specified date, except where the failure of such representations and warranties to be true and correct as so made does not have and could not reasonably be expected to have, individually or in the aggregate, an EUA Material Adverse Effect, and EUA shall have delivered to NEES a certificate, dated the Closing Date and executed in the name and on behalf of EUA by its Chairman of the Board, President or any Executive or Senior Vice President, to such effect. (b) Performance of Obligations. EUA shall have performed and complied with, in all material respects, each agreement, covenant and obligation required by this Agreement to be so performed or complied with by EUA at or prior to the Closing, and EUA shall have delivered to NEES a certificate, dated the Closing Date and executed in the name and on behalf of EUA by its Chairman of the Board, President or any Executive or Senior Vice President, to such effect. (c) Material Adverse Effect. No EUA Material Adverse Effect shall have occurred and there shall exist no facts or circumstances which in the aggregate could reasonably be expected to have an EUA Material Adverse Effect. (d) EUA Required Consents. All EUA Required Consents shall have been obtained by EUA, except where the failure to receive such EUA Required Consents could not reasonably be expected to (i) have an EUA Material Adverse Effect, or (ii) delay or prevent the consummation of the Merger and other transactions contemplated hereby. 8.03 Conditions to Obligation of EUA to Effect the Merger. The obligation of EUA to effect the Merger and other transactions contemplated hereby is further subject to the satisfaction or waiver, at or prior to the Closing, of each of the following additional conditions (all or any of which may be waived in whole or in part by EUA in its sole discretion): (a) Representations and Warranties. The representations and warranties made by NEES and LLC in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.07, 5.08 and 5.09 of this Agreement, in each case made as if none of such representations or warranties contained any qualification or limitation as to "materiality" or "NEES Material Adverse Effect," shall be true and correct as so made as of the Closing Date, except to the extent expressly given as of a specified date and except where the failure of such representations and warranties to be so true and correct as so made does not have and could not reasonably be expected to have, individually or in the aggregate, a NEES Material Adverse Effect or a material adverse effect on LLC, and NEES and LLC shall each have delivered to EUA a certificate, dated the Closing Date and executed in the name and on behalf of NEES by any director of NEES and in the name and on behalf of LLC by a member of its management committee its Chairman of the Board, President or any Executive or Senior Vice President to such effect. -40- (b) NEES Required Consents. All NEES Required Consents shall have been obtained by NEES, except where the failure to receive such NEES Required Consents could not reasonably be expected to (i) have a NEES Material Adverse Effect or (ii) delay or prevent the consummation of the Merger and other transactions contemplated hereby. (c) Performance of Obligations. NEES and LLC shall have performed and complied with, in all material respects, each agreement, covenant and obligation required by this Agreement to be so performed or complied with by NEES or LLC at or prior to the Closing, and NEES and LLC shall each have delivered to EUA a certificate, dated the Closing Date and executed in the name and on behalf of NEES by its Chairman of the Board, President or any Executive or Senior Vice President, or on behalf of LLC by a member of its management committee to such effect. ARTICLE IX TERMINATION, AMENDMENT AND WAIVER 9.01 Termination. This Agreement may be terminated, and the Merger and other transactions contemplated hereby may be abandoned, at any time prior to the Effective Time, whether prior to or after EUA Shareholders' Approval (except as otherwise provided in Section 9.01(c) below): (a) By mutual written agreement of the Board of Directors of NEES and Board of Trustees of EUA, respectively; (b) By EUA or NEES, by written notice to the other, if the Closing Date shall not have occurred on or before December 31, 1999 (the "Initial Termination Date"); provided, however, that the right to terminate the Agreement under this Section 9.01(b) shall not be available to any party whose failure to fulfill any obligation under this Agreement has been the cause of, or resulted in, the failure of the Effective Time to occur on or before such date; and provided, further, that if on the Initial Termination Date the conditions to the Closing set forth in Section 8.01(d) shall not have been fulfilled but all other conditions to the Closing shall be fulfilled or shall be capable of being fulfilled, then the Initial Termination Date shall be extended for four (4) months beyond the Initial Termination Date (the "Extended Termination Date"); (c) By NEES, by written notice to EUA, if EUA Shareholders' Approval shall not have been obtained at a duly held meeting of such Shareholders, including any adjournments thereof; (d) By EUA or NEES, if any applicable state or federal law or applicable law of a foreign jurisdiction or any order, rule or regulation is adopted or issued that has the effect, as supported by the written opinion of outside counsel for such party, of prohibiting the Merger or other transactions contemplated hereby, or if any court of competent jurisdiction or any Governmental Authority shall have issued a nonappealable final order, judgment -41- or ruling or taken any other action having the effect of permanently restraining, enjoining or otherwise prohibiting the Merger or other transactions contemplated hereby (provided that the right to terminate this Agreement under this Section 9.01(d) shall not be available to any party that has not defended such lawsuit or other legal proceeding (including seeking to have any stay or temporary restraining order entered by any court or other Governmental Authority vacated or reversed)). (e) By EUA upon ten (10) days' prior notice to NEES if the Board of Trustees of EUA determines in good faith, that termination of this Agreement is necessary for the Board of Trustees of EUA to act in a manner consistent with its fiduciary duties to Shareholders under applicable law by reason of an unsolicited Alternative Proposal meeting the requirements of clauses (A) and (B) of Section 7.08 having been made; provided that (A) The Board of Trustees of EUA shall determine based on advice of outside counsel with respect to the Board of Trustees' fiduciary duties that notwithstanding a binding commitment to consummate an agreement of the nature of this Agreement entered into in the proper exercise of its applicable fiduciary duties, and notwithstanding all concessions which may be offered by NEES in negotiation entered into pursuant to clause (B) below, it is necessary pursuant to such fiduciary duties that the trustees reconsider such commitment as a result of such Alternative Proposal, and (B) prior to any such termination, EUA shall, and shall cause its respective financial and legal advisors to, negotiate with NEES to make such adjustments in the terms and conditions of this Agreement as would enable EUA to proceed with the Merger or other transactions contemplated hereby on such adjusted terms; and provided further that EUA's ability to terminate this Agreement pursuant to this Section 9.01(e) is conditioned upon the concurrent payment by EUA to NEES of any amounts owed by it pursuant to Section 9.03(a); (f) By EUA, by written notice to NEES, if (i) there shall have been any material breach of any representation or warranty, or any material breach of any covenant or agreement, of NEES hereunder (other than a breach described in clause (ii)), and such breach shall not have been remedied within twenty (20) days after receipt by NEES of notice in writing from EUA, specifying the nature of such breach and requesting that it be remedied; or (ii) NEES shall fail to deliver or cause to be delivered the amount of cash to the Paying Agent required pursuant to Section 2.02(a) at a time when all conditions to NEES's obligation to close have been satisfied or otherwise waived in writing by NEES. (g) By NEES, by written notice to EUA, if (i) there shall have been any material breach of any representation or warranty, or any material breach of any covenant or agreement, of EUA hereunder, and such breach shall not -42- have been remedied within twenty (20) days after receipt by EUA of notice in writing from NEES, specifying the nature of such breach and requesting that it be remedied; or (ii) the Board of Trustees of EUA (A) shall withdraw or modify in any manner adverse to NEES its approval of the Merger and other transactions contemplated hereby or its recommendation to its shareholders regarding the approval of this Agreement, the Merger and other transactions contemplated hereby, (B) shall approve or recommend or take no position with respect to an Alternative Proposal or (C) shall resolve to take any of the actions specified in clause (A) or (B). 9.02 Effect of Termination. If this Agreement is validly terminated by either EUA or NEES pursuant to Section 9.01, this Agreement shall forthwith become null and void and there shall be no liability or obligation on the part of either EUA or NEES (or any of their respective Representatives or affiliates), except that the provisions of this Section 9.02, Sections 7.10, 7.11 and 7.13, Section 9.03 and Sections 10.09 and 10.10 shall continue to apply following any such termination. 9.03 Termination Fees. (a) In the event that (i) this Agreement is terminated by EUA pursuant to Section 9.01(e) or (ii) any person or group shall have made an Alternative Proposal that has not been withdrawn and this Agreement is terminated by (A) NEES pursuant to Section 9.01(c) or Section 9.01(g) or (B) by EUA pursuant to Section 9.01(b) and, in the case of this clause (ii) only, a definitive agreement with respect to such Alternative Proposal is executed within two years after such termination, then EUA shall pay to NEES, by wire transfer of same day funds, either on the date contemplated in Section 9.01(e) if applicable, or otherwise, within five (5) business days after such termination, a termination fee of $20 million, plus an amount equal to all documented out-of-pocket expenses and fees incurred by NEES arising out of, or in connection with or related to, the Merger and other transactions contemplated hereby, not in excess of $5 million in the aggregate. (b) In the event that this Agreement is terminated by either NEES or EUA pursuant to Section 9.01(b) and at the time of such termination (i) the conditions to the Closing set forth in Section 8.01(d) shall not have been fulfilled, (ii) if the date of termination is any date other than a date which is on or after the Extended Termination Date, all conditions contained in Article VIII other than Sections 8.01(d) or 8.03(c) shall have been fulfilled or are capable of being fulfilled as of such date, and (iii) the merger contemplated by the National Grid Merger Agreement has not yet been consummated, then NEES shall pay to EUA, by wire transfer of same day funds, within five (5) business days after such termination, a termination fee of $10 million, plus an amount equal to all documented out-of-pocket expenses and fees incurred by EUA arising out of, or in connection with or related to, the Merger and other transactions contemplated hereby, not in excess of $5 million in the aggregate. (c) Nature of Fees. The parties agree that the agreements contained in this Section 9.03 are an integral part of the Merger and the other transactions contemplated hereby and constitute liquidated damages and not a penalty. The parties further agree that if any party is or becomes obligated to pay a termination fee pursuant to Sections 9.03(a) or (b), the right to receive such termination fee shall be the sole remedy of the other party with respect to -43- the facts and circumstances giving rise to such payment obligation. If this Agreement is terminated by a party as a result of a willful breach of a representation, warranty, covenant or agreement by the other party, including a termination pursuant to Section 9.01(f)(ii), the non-breaching party may pursue any remedies available to it at law or in equity and shall be entitled to recover any additional amounts thereunder. Notwithstanding anything to the contrary contained in this Section 9.03, if one party fails to promptly pay to the other any fee or expense due under this Section 9.03, in addition to any amounts paid or payable pursuant to such Section, the defaulting party shall pay the costs and expenses (including legal fees and expenses) in connection with any action, including the filing of any lawsuit or other legal action, taken to collect payment, together with interest on the amount of any unpaid fee at the publicly announced prime rate of Citibank, N.A. from the date such fee was required to be paid. 9.04 Amendment. This Agreement may be amended, supplemented or modified by action taken by or on behalf of the Board of Directors of NEES or the Board of Trustees of EUA at any time prior to the Effective Time, whether prior to or after EUA Shareholders' Approval shall have been obtained, but after such adoption and approval only to the extent permitted by applicable law. No such amendment, supplement or modification shall be effective unless set forth in a written instrument duly executed and delivered by or on behalf of each party hereto. 9.05 Waiver. At any time prior to the Effective Time, NEES or EUA, by action taken by or on behalf of its Board of Directors or Board of Trustees, respectively, may to the extent permitted by applicable law (i) extend the time for the performance of any of the obligations or other acts of the other parties hereto, (ii) waive any inaccuracies in the representations and warranties of the other parties hereto contained herein or in any document delivered pursuant hereto or (iii) waive compliance with any of the covenants, agreements or conditions of the other parties hereto contained herein. No such extension or waiver shall be effective unless set forth in a written instrument duly executed by or on behalf of the party extending the time of performance or waiving any such inaccuracy or non-compliance. No waiver by any party of any term or condition of this Agreement, in any one or more instances, shall be deemed to be or construed as a waiver of the same or any other term or condition of this Agreement on any future occasion. ARTICLE X GENERAL PROVISIONS 10.01 Non-Survival of Representations, Warranties, Covenants and Agreements. The representations, warranties, covenants and agreements contained in this Agreement or in any instrument delivered pursuant to this Agreement shall not survive the Merger but shall terminate at the Effective Time, except for the agreements contained in Article I and Article II, in Sections 7.05, 7.06, 7.08, 7.09 and 7.10, this Article X which shall survive the Effective Time. 10.02 Notices. All notices, requests and other communications hereunder must be in writing and will be deemed to have been duly given only if -44- delivered personally or by facsimile transmission or sent by overnight courier (providing proof of delivery) to the parties at the following addresses or facsimile numbers: If to NEES or LLC, to: New England Electric System 25 Research Drive Westborough, MA 01582 Attn: Richard P. Sergel President and Chief Executive Officer Telephone: (508) 389-2764 Facsimile: (508) 366-5498 with a copy to: Skadden, Arps, Slate, Meagher & Flom LLP 919 Third Avenue New York, NY 10022 Attn: Sheldon S. Adler, Esq. Telephone: (212) 735-3000 Facsimile: (212) 735-2000 If to EUA, to: Eastern Utilities Associates One Liberty Square Boston, MA 02109 Attn: Donald G. Pardus Chairman and Chief Executive Officer Telephone: (617) 357-9590 Facsimile: (617) 357-7320 with a copy to: Winthrop, Stimson, Putnam & Roberts 1 Battery Park Plaza New York, NY 10004 Attn: David P. Falck Telephone: (212) 858-1000 Facsimile: (212) 858-1500 All such notices, requests and other communications will (i) if delivered personally to the address as provided in this Section, be deemed given -45- upon delivery, (ii) if delivered by facsimile transmission to the facsimile number as provided in this Section, be deemed given when sent, provided that the facsimile is promptly confirmed by telephone confirmation thereof, and (iii) if delivered by mail in the manner described above to the address as provided in this Section, be deemed given one business day after delivery (in each case regardless of whether such notice, request or other communication is received by any other person to whom a copy of such notice, request or other communication is to be delivered pursuant to this Section). Any party from time to time may change its address, facsimile number or other information for the purpose of notices to that party by giving notice specifying such change to the other parties hereto. 10.03 Entire Agreement; Incorporation of Exhibits. (a) This Agreement supersedes all prior discussions and agreements, both written and oral, among the parties hereto with respect to the subject matter hereof, other than the Confidentiality Agreement, which shall survive the execution and delivery of this Agreement in accordance with its terms, and contains, together with the Confidentiality Agreement, the sole and entire agreement among the parties hereto with respect to the subject matter hereof. (b) The EUA Disclosure Letter, the NEES Disclosure Letter and any Exhibit attached to this Agreement and referred to herein are hereby incorporated herein and made a part hereof for all purposes as if fully set forth herein. 10.04 No Third Party Beneficiary. The terms and provisions of this Agreement are intended solely for the benefit of each party hereto and their respective successors or permitted assigns, and except as provided in Article II and Sections 7.04, 7.05(d)(ii) and 7.09 (which is intended to be for the benefit of the persons entitled to therein, and may be enforced by any of such persons), it is not the intention of the parties to confer third-party beneficiary rights upon any other person. 10.05 No Assignment; Binding Effect. Neither this Agreement nor any right, interest or obligation hereunder may be assigned, in whole or in part, by operation of law or otherwise, by any party hereto without the prior written consent of the other parties hereto and any attempt to do so will be void, except that LLC may assign any or all of its rights, interests and obligations hereunder to another direct or indirect wholly owned Subsidiary of NEES, provided that any such Subsidiary agrees in writing to be bound by all of the terms, conditions and provisions contained herein and provided further that such assignment (i) does not require a greater vote for EUA's Shareholder Approval, (ii) does not require a subsequent vote following EUA's Shareholders Meeting, or (iii) is not reasonably likely to materially delay or prevent EUA, LLC and NEES, as appropriate, from obtaining EUA Required Statutory Approvals, EUA Required Consents, EUA Shareholders' Approval, the NEES Required Shareholders' Approvals, or the NEES Required Consents. Subject to the preceding sentence, this Agreement is binding upon, inures to the benefit of and is enforceable by the parties hereto and their respective successors and assigns. -46- 10.06 Headings. The headings used in this Agreement have been inserted for convenience of reference only and do not define, modify or limit the provisions hereof. 10.07 Invalid Provisions. If any provision of this Agreement is held to be illegal, invalid or unenforceable under any present or future law or order, and if the rights or obligations of any party hereto under this Agreement will not be materially and adversely affected thereby, (i) such provision will be fully severable, (ii) this Agreement will be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, and (iii) the remaining provisions of this Agreement will remain in full force and effect and will not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom. 10.08 Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the Commonwealth of Massachusetts. 10.09 Enforcement of Agreement. The parties hereto agree that irreparable damage would occur in the event that any of the provisions of this Agreement was not performed in accordance with its specified terms or was otherwise breached. It is accordingly agreed that the parties shall be entitled to an injunction or injunctions to prevent breaches of this Agreement and to enforce specifically the terms and provisions hereof in any court of competent jurisdiction, this being in addition to any other remedy to which they are entitled at law or in equity. 10.10 Certain Definitions. As used in this Agreement: (a) except as provided in Section 4.14, the term "affiliate," as applied to any person, shall mean any other person directly or indirectly controlling, controlled by, or under common control with, that person; for purposes of this definition, "control" (including, with correlative meanings, the terms "controlling," "controlled by" and "under common control with"), as applied to any person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of that person, whether through the ownership of voting securities, by contract or otherwise; (b) a person will be deemed to "beneficially" own securities if such person would be the beneficial owner of such securities under Rule 13d-3 under the Exchange Act, including securities which such person has the right to acquire (whether such right is exercisable immediately or only after the passage of time); (c) the term "business day" means a day other than Saturday, Sunday or any day on which banks located in the Massachusetts are authorized or obligated to close; (d) the term "knowledge" or any similar formulation of "knowledge" shall mean, with respect to any party hereto, the actual knowledge after due inquiry of the executive officers of NEES and its Subsidiaries or EUA and its Subsidiaries, respectively, set forth in Section 10.11(d) of the NEES Disclosure Letter or Section 10.11(d) of the EUA Disclosure Letter; provided -47- that as used in Section 4.13 the term "knowledge" shall also include the knowledge of the environmental, health and safety personnel of EUA; (e) the term "person" shall include individuals, corporations, partnerships, trusts, limited liability companies, other entities and groups (which term shall include a "group" as such term is defined in Section 13(d)(3) of the Exchange Act); (f) the "Representatives" of any entity shall have the same meaning as set forth in the Confidentiality Agreement; (g) the term "Subsidiary" means any corporation or other entity, whether incorporated or unincorporated, in which such party directly or indirectly owns at least a majority of the voting power represented by the outstanding capital stock or other voting securities or interests having voting power under ordinary circumstances to elect a majority of the directors or similar members of the governing body, or otherwise to direct the management and policies, or such corporation or entity. 10.11 Counterparts. This Agreement may be executed in any number of counterparts, each of which will be deemed an original, but all of which together will constitute one and the same instrument and will become effective when one or more counterparts have been signed by each party and delivered to the other parties. 10.12 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION. -48- IN WITNESS WHEREOF, each party hereto has caused this Agreement to be signed by its officer thereunto duly authorized as of the date first above written. NEW ENGLAND ELECTRIC SYSTEM By: /s/ Richard P. Sergel ----------------------------------- Name: Richard P. Sergel Title: President and CEO The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer, or agent thereof assumes or shall be held to any liability therefor. EASTERN UTILITIES ASSOCIATES By: /s/ Donald G. Pardus ----------------------------------- Name: Donald G. Pardus Title: Chairman The name "Eastern Utilities Associates" is the designation of the Trustees of EUA for the time being in their collective capacity but not personally, under a Declaration of Trust dated April 2, 1928, as amended, a copy of which amended Declaration of Trust has been filed in the office of the Secretary of The Commonwealth of Massachusetts and elsewhere as required by law; and all persons dealing with EUA must look solely to the trust property for the enforcement of any claim against EUA, as neither the Trustees nor the officers or shareholders of EUA assume any personal liability for obligations entered into on behalf of EUA. RESEARCH DRIVE LLC By: /s/ John G. Cochrane ----------------------------------- Name: John G. Cochrane Title: Manager -49- Tab 2 CONSENT AGREEMENT dated as of February 1, 1999 CONSENT AGREEMENT This Consent Agreement (the "Agreement") is entered into as of February 1, 1999 between The National Grid Group, p1c, a public limited company incorporated under the laws of England and Wales ("NGG") and New England Electric System, a Massachusetts business trust ("NEES"). WHEREAS, NGG, NEES and NGG Holdings LLC (formerly Iosta LLC), a wholly owned subsidiary of NGG, entered into an Agreement and Plan of Merger dated as of December 11, 1998 (the"Merger Agreement") pursuant to which NGG Holdings LLC will merge (the "Merger") with and into NEES with NEES being the surviving entity and becoming a wholly owned subsidiary of NGG; WHEREAS, NEES, Eastern Utilities Associates, a Massachusetts Business Trust ("EUA") and Research Drive LLC are proposing to enter into an Agreement and Plan of Merger in the form attached hereto as Exhibit A (the "EUA Merger Agreement") providing for the merger (the "EUA Merger") of Research Drive LLC with and into EUA with EUA being the surviving entity and becoming a wholly owned subsidiary of NEES; and WHEREAS, pursuant to the provisions of the Merger Agreement, NEES is required to obtain the consent of NGG before entering into the EUA Merger Agreement and with respect to certain actions relating to the consummation of the transactions set forth therein. NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows: 1. Consent to EUA Merger Agreement. Subject to the terms and conditions of this Consent, NGG hereby consents to NEES entering into the EUA Merger Agreement with EUA in the form set forth in Exhibit A and agrees that, subject to the immediately following sentence, the consummation by NEES of the transactions contemplated by the EUA Merger Agreement in accordance with the term thereof shall not constitute a breach by NEES of the terms of the Merger Agreement. NEES and NGG acknowledge that the financing necessary to consummate the EUA Merger was not contemplated when NEES and NGG agreed to the limitations set forth in Article VI of the Merger Agreement and NGG consents to such financing provided that such financing is consistent with the financing parameters set forth on Exhibit B hereto. NGG also consents to the formation and capitalization of Research Drive LLC by NEES for the purpose of effecting the EUA Merger as contemplated in the EUA Merger Agreement. 2. Access to Information. Subject to the following sentence, NEES hereby agrees to provide NGG with reasonable access to any information it receives regarding EUA pursuant to the terms of the EUA Merger Agreement and to consult with NGG on a regular basis concerning the status of EUA and the EUA Merger. NGG hereby acknowledges that any such material that is "Evaluation Material" (as such term is defined in the letter agreement dated as of December 21, 1998 between NGG and NEES (the "Confidentiality Agreement") shall be governed by the terms of the Confidentiality Agreement. 3. Regulatory Filings. NEES hereby agrees that NGG shall have the right to review in advance, and that NEES will consult with NGG and give due regard to NGG's views concerning, any applications, notices, petitions, filings and other documents filed with any Governmental Authority (as defined in the EUA Merger Agreement) in connection with the EUA Merger which could reasonably be expected to have a material adverse effect on NGG's or NEES' ability to consummate the Merger or which could reasonably be expected to adversely affect in any material manner any material benefit of the Merger to NGG or NEES. 4. Amendments to EUA Merger Agreement. NEES hereby agrees that it will not, without the prior written consent of NGG, amend or modify the EUA Merger Agreement in any material respect, including, without limitation, amend or otherwise modify any provision of the EUA Merger Agreement providing for or relating to the amount, type or structure of the Merger Consideration (as defined in the EUA Merger Agreement) or agree to any additional or different amount, type or structure for the Merger Consideration (as so defined). 5. Acknowledgment. NGG and NEES acknowledge and agree that the covenants set forth in Article VI of the Merger Agreement do not reflect the operations of EUA if the EUA Merger is consummated prior to the Effective Time (as defined in the Merger Agreement). In the event that the EUA Merger is consummated prior to the Effective Time, NGG and NEES hereby agree to negotiate in good faith to make appropriate modifications to such covenants set forth in Section 6.01 of the Merger Agreement to reflect the operations of EUA. 6. Termination and Amendment. This Consent Agreement and the obligations of NEES hereunder shall terminate upon the earlier to occur of (i) the termination of the Merger Agreement, (ii) the EUA Merger and (iii) the Merger, in each case without any further action by the parties hereto. Except as provided in the preceding sentence, this Consent can not be terminated or amended in any material respect prior to the termination of the EUA Merger Agreement without the prior written consent of EUA. The foregoing sentence is intended for the benefit of EUA and may be enforced by EUA. 7. Notices. NEES hereby agrees to provide NGG with copies of all notices and other communications it sends to EUA and all notices and other communications it receives from EUA under the EUA Merger Agreement. All notices and other communications provided under this Agreement must be in writing and shall be given in the same manner and to the same parties as set forth in Section 10.02 of the Merger Agreement. 8. Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument. 9. Governing Law and Waiver of Jury Trial. This Agreement shall be governed by and construed in accordance with the laws of the State of New York applicable to a contract executed and performed in such State, without giving effect to the conflicts of laws principles. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION. IN WITNESS WHEREOF, each of NGG and NEES has duly executed this Agreement as of the date first above written. THE NATIONAL GRID GROUP, PLC By: /s/ Fiona B. Smith ----------------------------------- Name: Fiona B. Smith Title: Company Secretary NEW ENGLAND ELECTRIC SYSTEM By: ___________________________ Name: Title: The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer or agent thereof assumes or shall be held to any liability therefor. IN WITNESS WHEREOF, each of NGG and NEES has duly executed this Agreement as of the date first above written. THE NATIONAL GRID GROUP, PLC By: ______________________________ Name: Title: NEW ENGLAND ELECTRIC SYSTEM By: /s/ Richard P. Sergel ----------------------------------- Name: Richard P. Sergel Title: President and CEO The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer or agent thereof assumes or shall be held to any liability therefor. ACKNOWLEDGMENT OF EASTERN UTILITIES ASSOCIATES (not legible) EXHIBIT B - Financing Parameters Financing will be in an amount of up to $630 M provided through a group of banks. The financing (i) will be prepayable, (ii) will have a term not to exceed seven years, (iii) will have a LIBOR-based borrowing option and (iv) will have other terms and conditions usual and customary for transactions of this nature. UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) THE NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-70 NEW ENGLAND HYDRO-TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO-TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY, L.L.C. ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) SUPPLEMENT TO APPLICATION TO ADD DESCRIPTION OF CORPORATE RESTRUCTURING AND FILING OF ADDITIONAL MATERIAL FOR EXHIBIT G Edward Berlin, Esq. David A. Fazzone, Esq. of Kenneth G. Jaffe, Esq. David A. Fazzone, P.C., and Scott P. Klurfeld, Esq. McDermott, Will & Emery Swidler Berlin Shereff Friedman, LLP 28 State Street 3000 K Street, N.W., Suite 300 Boston, Massachusetts 02109-1775 Washington, D.C. 20007-5116 (617) 535-4000 (202) 424-7500 Attorneys for Montaup Electric Company and Affiliated Applicants Thomas G. Robinson, Esq. New England Power Company 25 Research Drive Westborough, MA 01582 (508) 389-2877 Attorneys for New England Power Company and Affiliated Applicants July 1, 1999 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION ) NEW ENGLAND POWER COMPANY, et al. ) and ) Docket No. EC99-70 MONTAUP ELECTRIC COMPANY, et al. ) ) SUPPLEMENT TO APPLICATION TO ADD DESCRIPTION OF CORPORATE RESTRUCTURING AND FILING OF ADDITIONAL MATERIAL FOR EXHIBIT G Pursuant to Section 203 of the Federal Power Act ("FPA"),1/ and Part 33 of the Commission's Regulations,2/ New England Power Company ("NEP") and its affiliates holding jurisdictional assets ("NEES Companies"),3/ Montaup Electric Company ("Montaup") and its affiliates holding jurisdictional assets ("EUA Companies"),4/ and Research Drive LLC5/ submit this supplement to the - --------------- 1/ 16 U.S.C. section 824b (1994). 2/ 18 C.F. R. sections 33.1 et seq. (1998). 3/ These include the following: Massachusetts Electric Company; The Narragansett Electric Company; New England Electric Transmission Corporation; New England Hydro-Transmission Corporation; New England Hydro-Transmission Electric Company, Inc.; and AllEnergy Marketing Company, L.L.C. (which holds no physical facilities for the generation or transmission of electricity but does hold a power marketing certificate (see 82 FERC paragraph 61,179 (1998))). 4/ These include the following: Blackstone Valley Electric Company, Eastern Edison Company ("Eastern Edison"), and Newport Electric Corporation. 5/ Research Drive LLC, a Massachusetts limited liability company, is jointly-owned by NEES and EUA and was formed for the express purpose of effectuating the merger that is the subject of this proceeding. Application filed on May 5, 1999, in this docket. This proceeding involves the request for approval of the merger ("Merger") of New England Electric System ("NEES"), the existing holding company for the NEES Companies, and Eastern Utilities Associates ("EUA"), the existing holding company for the EUA Companies. Through the Merger, EUA and the EUA Companies will become subsidiaries of NEES and will ultimately be consolidated into their NEES counterparts. The filing of this Supplement has three purposes: (1) to describe a change in the corporate structure of Montaup that will be implemented prior to and independent of the closing of the Merger; (2) to the extent required, to obtain approval from the Commission of this planned corporate restructuring of Montaup; and (3) to file, in accordance with the commitment made in the original Application, additional material that should be made part of Exhibit G to the Application. DISCUSSION Corporate Restructuring As explained in the original Application, currently 100% of the common stock of Montaup is held by Eastern Edison, which in turn is wholly owned by EUA. This means that EUA is the existing ultimate parent company of Montaup. Independent of and prior to the closing of the Merger, Eastern Edison will transfer all of the common stock of Montaup to EUA so that EUA will become the direct parent of Montaup. This corporate restructuring is planned for organizational and financial reasons unrelated to the Merger. Among other things, this internal restructuring will: (i) complete the functional unbundling of EUA's remaining generation business from its distribution business through the complete corporate separation of Eastern Edison and Montaup; (ii) isolate -2- Eastern Edison's capital structure so it applies to distribution ratemaking only; and (iii) simplify EUA's corporate structure. The corporate restructuring of Montaup's parent companies has no impact on the Merger transaction. As a result of the Merger, Montaup will become a subsidiary of NEES and then will be consolidated into NEP; those steps will still occur as originally described. The only change is that Montaup will no longer have an intermediate parent company at the time of the Merger closing. This Supplement is being filed to make certain that the discussion of Montaup's corporate structure in the original Application is accurate in light of the planned restructuring. Request for Approval of Restructuring (If Required) In addition, to the extent the Commission determines that this corporate restructuring of Montaup's parent companies qualifies as a disposition of control of a jurisdictional entity requiring Commission approval under Section 203 of the FPA, Montaup requests such approval.6/ If such approval is required, Montaup, Eastern Edison and EUA believe that the most efficient means of granting it would be for the Commission to do so in connection with the processing of the Merger Application because all relevant materials are already included in this docket.7/ Approval under Section 203 is in the public interest - --------------- 6/ Applicants have or will inform and, if required, have or will request approval of the proposed corporate restructuring from the following federal and state regulatory authorities: the Nuclear Regulatory Commission, the Connecticut Department of Public Utility Control, and the Massachusetts Department of Telecommunications and Energy. 7/ Applicants do not foresee any reason that there would be a delay in approving the Merger Application itself. Accordingly, processing the request for approval of the independent restructuring of Montaup's parent companies (if any is required) in conjunction with the Merger Application should provide timely approval of the restructuring. If, however, there is a delay in granting approval of the Merger beyond the 60-90 day post-comment time frame established in the Merger Policy Statement, Applicants request the Commission grant separate approval of the restructuring of Montaup's parent companies so that the restructuring may be completed by the beginning of the fourth quarter of this year. -3- because the change in the structure of the parent companies of Montaup has no effect on competition, rates or regulation. The existing ultimate parent company of Montaup, EUA, will remain as the ultimate parent company and, other than eliminating the intermediate holding company, there is no change in the structure or operation of any jurisdictional company. In analogous circumstances, the Commission has approved a restructuring of a company.8/ Submission of Additional Material for Exhibit G Finally, Applicants submit for filing copies of the following material that should be made part of Exhibit G to the Application in this proceeding: Application of Montaup Electric Company and New England Power Company for Transfer of Licenses and Ownership Interests before the Nuclear Regulatory Commission (consisting of three volumes).9/ - --------------- 8/ See Doswell Limited Partnership,, 60 FERC paragraph 62,086 (1992) (approving conversion of partnership interests); Commonwealth Atlantic Limited Partnership, 57 FERC paragraph 61,193 (1991) (disclaiming jurisdiction under Section 203 resulting from elimination of intermediate layers of control where existing ultimate parent remained as such, and approving other changes in control); see also Citizens Utilities Company, 84 FERC paragraph 61,158 (1998) (approving spin-off involving distribution of stock of company). The Citizens Utilities case also directly determined that the payment of a stock dividend to effectuate the restructuring was not in violation of Section 305(a) of the FPA. The same is true in this situation with respect to Eastern Edison's transfer of 100% of the common stock of Montaup to EUA. That transfer is merely the vehicle to effectuate the corporate restructuring and is fully consistent with Section 305(a) of the FPA. 9/ Copies of this filing and all attachments are being filed with the state commissions of Connecticut, Massachusetts, New Hampshire, Rhode Island, and Vermont, all parties on the service list in Docket No. EC99-70, and all parties on the service list in Docket No. ER99-2832. -4- CONCLUSION In conclusion, Applicants respectfully request that the Commission approve the Merger Application, as supplemented, without condition, modification or evidentiary trial-type hearing. Also, to the extent approval is required, Applicants request that the Commission approve without condition, modification or evidentiary trial-type hearing, the independent corporate restructuring of Montaup described above. Respectfully submitted, /s/ Scott P. Klurfeld /s/ David A. Fazzone - ------------------------------------ ---------------------------------------- Edward Berlin, Esq. David A. Fazzone, Esq. of Kenneth G. Jaffe, Esq. David A. Fazzone, P.C., and Scott P. Klurfeld, Esq. McDermott, Will & Emery Swidler Berlin Shereff Friedman, LLP 28 State Street 3000 K Street, N.W., Suite 300 Boston, Massachusetts 02109-1775 Washington, D.C. 20007-5116 (617) 535-4000 (202) 424-7500 Attorney for Montaup Electric Company and Affiliated Applicants Thomas G. Robinson, Esq. New England Power Company 25 Research Drive Westborough, MA 01582 (508) 389-2877 Attorneys for New England Power Company and Affiliated Applicants July 1, 1999 -5- [FORM OF NOTICE] UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) THE NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-70 NEW ENGLAND HYDRO-TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO-TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY, L.L.C. ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) NOTICE OF FILING OF SUPPLEMENT TO APPLICATION TO ADD DESCRIPTION OF CORPORATE RESTRUCTURING AND FILING OF ADDITIONAL MATERIAL FOR EXHIBIT G Take notice that on July 1, 1999, New England Power Company ("NEP") and its affiliates holding jurisdictional assets (Massachusetts Electric Company, The Narragansett Electric Company, New England Electric Transmission Corporation, New England Hydro-Transmission Corporation, New England Hydro-Transmission Electric Company, Inc., and AllEnergy Marketing Company, L.L.C.) (collectively, the "NEES Companies"), Montaup Electric Company and its affiliates holding jurisdictional assets (Blackstone Valley Electric Company, Eastern Edison Company ("Eastern Edison"), Newport Electric Corporation) (collectively, the "EUA Companies"), and Research Drive LLC submitted a Supplement to their Application in the above referenced docket. The proceeding in the above-referenced docket seeks the Commission's approval and related authorizations to effectuate the merger involving New England Electric System ("NEES"), the parent company of the NEES Companies, and Eastern Utilities Associates ("EUA"), the parent company of the EUA Companies ("Merger"). The Supplement explains that currently 100% of the common stock of Montaup is held by Eastern Edison, which in turn is wholly owned by EUA. Independent of and prior to the closing of the Merger, Eastern Edison will transfer all of the common stock of Montaup to EUA so that EUA will become the direct parent of Montaup. The Supplement states that this independent internal corporate restructuring of Montaup's parent companies has no impact on the Merger, but is being filed to make certain that the discussion of Montaup's corporate structure in the original Application remains accurate. In addition, the Supplement states that to the extent the Commission determines that this internal corporate restructuring of Montaup's parent companies qualifies as a disposition of control of a jurisdictional entity that requires Commission approval under Section 203 of the FPA, the Applicants request such approval. Finally, the Applicants included for filing copies of the following material that the Applicants request be made part of Exhibit G to the Application: Application of Montaup Electric Company and New England Power Company for Transfer of Licenses and Ownership Interests before the Nuclear Regulatory Commission (consisting of three volumes). The Applicants have served copies of the filing on the state commissions of Connecticut, Massachusetts, New Hampshire, Rhode Island, and Vermont, all parties on the service list of EC99-70, and all parties on the service list on Docket No. ER99-2832. Any person desiring to be heard or to protest said amendment should file a motion to intervene or protest with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426 in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 C.F.R. 385.211 and 18 C.F.R. 385.214). All such motions or protests should be filed on or before __________. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make the protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. Copies of this filing are on file with the Commission and are available for public inspection. -2- CERTIFICATE OF SERVICE I hereby certify that I have this day served the foregoing document upon each person designated on the official service list compiled by the Secretary in this proceeding. Dated at Washington, D.C., this 1st day of July, 1999. /s/ Sara C. Weinberg - --------------------------- Sara C. Weinberg Swidler Berlin Shereff Friedman, LLP 3000 K Street, N.W., #300 Washington, D.C. 20007 Tel: (202) 424-7500 Fax: (202) 424-7643 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) THE NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-70 NEW ENGLAND HYDRO-TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO-TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY, L.L.C. ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) VERIFICATION Robert G. Powderly, being duly sworn upon oath, states that he is Executive Vice-President of Montaup Electric Company, Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation and has read the attached Supplement to Application to Add Description of Corporate Restructuring and Filing of Additional Material for Exhibit G; that he knows the contents thereof; that the statements made therein are true and correct to the best of his knowledge, information and belief; and that he has full power and authority to sign this document on behalf of Montaup Electric Company, Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation. /s/ Robert G. Powderly ---------------------------------------- Robert G. Powderly Executive Vice-President Subscribed and sworn to before me this 28th day of June, 1999. ---- ---- /s/ Barbara L. Dontono ---------------------------------------- Notary Public My Commission expires March 30, 2001 -------------- UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEW ENGLAND POWER COMPANY ) MASSACHUSETTS ELECTRIC COMPANY ) THE NARRAGANSETT ELECTRIC COMPANY ) NEW ENGLAND ELECTRIC TRANSMISSION ) CORPORATION ) Docket No. EC99-70 NEW ENGLAND HYDRO-TRANSMISSION ) CORPORATION ) NEW ENGLAND HYDRO-TRANSMISSION ) ELECTRIC COMPANY, INC. ) ALLENERGY MARKETING COMPANY, L.L.C. ) MONTAUP ELECTRIC COMPANY ) BLACKSTONE VALLEY ELECTRIC COMPANY ) EASTERN EDISON COMPANY ) NEWPORT ELECTRIC CORPORATION ) RESEARCH DRIVE LLC ) VERIFICATION Jennifer Zschokke being duly sworn upon oath, states that she is Manager of Finance of New England Power Service Company (which provides financial services to all New England Electric System companies, including New England Power Company) and has read the attached Supplement to Application to Add Description of Corporate Restructuring and Filing of Additional Material for Exhibit G; that she knows the contents thereof; that the statements made therein are true and correct to the best of her knowledge, information and belief; and that she has full power and authority to sign this document on behalf of the Applicants that are New England Electric System companies. /s/ Jennifer Zschokke ---------------------------------------- Jennifer Zschokke Manager of Finance Subscribed and sworn to before me this 30th day of June, 1999. ---- ---- /s/ Celia S. Byler ---------------------------------------- Notary Public My Commission expires April 5, 2002. ------------- EX-99 7 EXHIBIT D-2 APPLICATION TO THE MDTE New England Electric System and Eastern Utilities Associates Massachusetts Electric Company and Eastern Edison Company Rate Plan Filing In Support of Merger Volume 1 Filing Letter & Petition Testimony & Exhibits of: Michael E. Jesanis Robert G. Powderly Lawrence J. Reilly Jennifer K. Zschokke April 30, 1999 Submitted to: Massachusetts Department of Telecommunications and Energy Docket D.T.E. 99-_____ Submitted by: NEES Logo EUA Logo [NEES logo] [EUA logo] April 30, 1999 by hand Mary L. Cottrell, Secretary Dept. of Telecommunications and Energy 100 Cambridge Street, 12th Floor Boston, MA 02202 Re: New England Electric System and Eastern Utilities Associates Merger: Petition for Approval of Mergers, Financings, and Retail Rate Plan Dear Secretary Cottrell: As announced on February 1, 1999, New England Electric System ("NEES") agreed to acquire all of the outstanding shares of Eastern Utilities Associates ("EUA") for $31 per share subject to adjustment for the date of closing. Because NEES and EUA are both holding companies, the Department's approval is not required for the parent-level acquisition. However, following the acquisition, NEES intends to merge EUA's electric operating subsidiaries into NEES's electric operating subsidiaries. Thus, in Massachusetts, Eastern Edison Company ("Eastern") will merge into Massachusetts Electric Company ("Mass. Electric"), and Montaup Electric Company ("Montaup") will merge into New England Power Company ("NEP"). Enclosed is a Petition that requests approval for the merger of the NEES and EUA subsidiaries. Following the merger and the expiration of the distribution rate freeze in its Restructuring Settlement, Mass. Electric proposes to implement a rate consolidation plan under which Eastern's customers will be moved onto Mass. Electric's rates. This rate consolidation plan will reduce the average rates to Eastern's customers by 14.2 percent or $23 million in 2001. In addition, Mass. Electric will propose to extend the rate freeze on the distribution component of its delivery rate for up to four years beyond the end of the rate freeze in its Restructuring Settlement. This extension occurs in two steps. Upon the merger with Eastern, the distribution rate freeze will be extended through 2001 and 2002. If the National Grid Group's merger with NEES is approved, the distribution rate freeze will be extended through 2003 and 2004. Thus, under the rate plan, Mass. Electric's customers will see stable distribution charges through December 31, 2004. The enclosed Petition also requests approval by the Department of the rate plan. The mergers and rate plan are supported in the testimony of several witnesses. Michael E. Jesanis, Senior Vice President and Chief Financial Officer of NEES, describes the merger and the rate plan. Robert G. Powderly, Executive Vice President of EUA, discusses EUA's decision to enter the transaction and its compliance with the Department's standards for mergers and acquisitions. Lawrence J. Reilly, President and Chief Executive Officer of Mass. Electric, describes the service improvements and service quality plan that Mass. Electric proposes following the merger. Jennifer K. Zschokke, Manager of Finance for the NEES companies, explains the mergers of Mass. Electric and Eastern and of NEP and Montaup and the required financing approvals to implement the mergers. In the second volume of the filing, David M. Webster, Principal Financial Analyst for the NEES companies, explains the accounting issues associated with the mergers and describes the proposed amendments to Mass. Electric's funds for recovery of hazardous waste and extraordinary storm costs. The rate consolidation plan and the mapping of the availability provisions of Eastern's and Mass. Electric's tariffs are described in the testimonies of Theresa M. Burns, Principal Rate Analyst for the NEES companies and James J. Bonner, Jr., Manager of Retail Pricing and Rate Administration for the EUA companies. Finally, David J. Hoffman and Richard J. Levin of Mercer Management Consulting set forth the synergies and savings associated with the merger in third volume of our filing.1/ The NEES-EUA combination provides significant economic benefits to customers of both Eastern and Mass. Electric. As mentioned above, Eastern's customers receive a 14.2 percent average rate reduction upon the implementation of the rate plan. Over the four year period of the rate plan, the customers of the consolidated company receive economic benefits equal to $128 million. Almost $106 million of this amount stems directly from the economic value of the distribution rate freeze. The consolidation of the companies will also produce ongoing efficiency gains equal to $35 million annually after the expiration of the rate freeze in 2005.2/ The service quality standards proposed as part of the rate plan assure that reliability and responsiveness will be maintained during the period of the rate freeze. Finally, the consolidation of the companies and the integration of the Mass. Electric and Eastern billing systems should promote - --------------- 1/Exhibit 3 to Mr. Hoffman and Mr. Levin's testimony is being filed under separate cover. This exhibit contains confidential payroll and personnel information. The companies request confidential treatment of the exhibit pursuant to G.L. c. 25, ss. 5D. As grounds for this request, the companies state that Exhibit 3 contains confidential information about employees and their salaries and release to the public would unnecessarily reveal personal information. Accordingly, the information in Exhibit 3 has been redacted from the public filing. 2/Under our proposal, these savings are applied first to the cost of the EUA acquisition and are then divided equally between customers and the recovery of the acquisition costs resulting from the NEES-National Grid transaction. Recovery of the EUA acquisition costs in accordance with the Department's precedent, is a condition of the merger agreement. See Essex County Gas Co., Docket D.T.E. 98-27 (1998). the competitive market for electricity supplies by lowering marketing and transaction costs for suppliers and customers. For the reasons set forth here and in the accompanying testimony, we request the Department to grant the approvals and make the findings set forth in the accompanying Petition. Thank you for your attention to our filing. Very truly yours, /s/ Thomas G. Robinson ---------------------------------------- Thomas G. Robinson Attorney for New England Electric System and its subsidiaries, Massachusetts Electric Company and New England Power Company /s/ David A. Fazzone ---------------------------------------- David A. Fazzone of David A. Fazzone, P.C. and McDermott, Will & Emery Attorney for Eastern Utilities Associates and its subsidiaries, Eastern Edison Company and Montaup Electric Company cc: George B. Dean, Esq. Robert F. Sydney, Esq. COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - --------------------------------------------- ) Massachusetts Electric Company and ) New England Power Company, subsidiaries of ) NEW ENGLAND ELECTRIC SYSTEM ) ) and ) Docket D.T.E. 99-___ ) Eastern Edison Company and ) Montaup Electric Company, subsidiaries of ) EASTERN UTILITIES ASSOCIATES ) - ---------------------------------------------) PETITION FOR APPROVAL OF MERGERS, FINANCINGS, AND RETAIL RATE PLAN By this Petition, Massachusetts Electric Company ("Mass. Electric"), New England Power Company ("NEP"), Eastern Edison Company ("Eastern"), and Montaup Electric Company ("Montaup") (together the "Petitioners") request the Department of Telecommunications and Energy ("Department") to: 1. Approve Eastern's merger into Mass. Electric pursuant to G.L. c. 164, section 96; 2. Provide, pursuant to G.L. c. 164, section 96, confirmation and authorization of the rights and franchises of Mass. Electric to carry on its business in all cities and towns in which Eastern is now doing an electric business, and find that further action of the Commonwealth of Massachusetts under G.L. c. 164, section 21 is not required to consummate the merger; 3. Approve Montaup's merger into NEP pursuant to G.L. c. 164, section 96; 4. Provide, pursuant to G.L. c. 164, section 96, confirmation and authorization of the rights and franchises of NEP to carry on its business in all cities and towns in which Montaup is now doing an electric business, and find that further action of the Commonwealth of Massachusetts under G.L. c. 164, section 21 is not required to consummate the merger; 5. Approve Mass. Electric's and NEP's increase in capital stock to the extent necessary pursuant to G.L. c. 164, section 99; 6. Approve the disposition of Montaup's securities by Eastern to the extent necessary pursuant to G.L. c. 164, section 9A; 7. Approve the issuance of preferred stock, bonds, or other evidences of indebtedness by Mass. Electric to the extent necessary pursuant to G.L. c. 164, sections 14, 15, 15A, 16, 18 and 19. 8. Approve the amendments to the NEES Moneypool to permit the participation by Eastern, Montaup, and their affiliates in EUA in the NEES Moneypool pursuant to G.L. c. 164, section 17A. 9. Approve Mass. Electric's assumption of Eastern's obligations and NEP's assumption of Montaup's obligations to the extent necessary pursuant to G.L. c. 164, section 14; and 10. Approve the rate plan proposed for Mass. Electric and Nantucket Electric Company after the merger with Eastern detailed in the accompanying filing, including the recovery of the acquisition premium and transaction costs as set forth in the filing, the service quality standards, the accounting changes, and the treatment of the funds for environmental response costs and extraordinary storm costs pursuant to G.L. c. 164, section 94. In support of this Petition, Petitioners state the following: 1. The Petitioners are all electric companies in Massachusetts as defined pursuant to G.L. c. 164, section 1, and are subject to the Department's jurisdiction; 2. Mass. Electric and NEP are subsidiaries of New England Electric System ("NEES"), and Eastern and Montaup and subsidiaries of Eastern Utilities Associates ("EUA"); 3. On February 1, 1999, NEES and EUA agreed to the acquisition of EUA by NEES; 4. Following that acquisition, the Petitioners plan is for Eastern to merge into Mass. Electric, and Montaup to merge into NEP following votes of the holders of at least two thirds of each class of stock outstanding and entitled to vote on the question of each of the companies; 5. Following its merger with Eastern, Mass. Electric intends to implement the rate plan documented in the accompanying filing; and 6. The consummation of the mergers and rate plan requires the Department's approvals as set forth at the outset of this Petition and documented in the accompanying testimony. For the reasons stated in the accompanying filing, the Petitioners request the Department to grant the approvals and make the findings set forth at the outset of this Petition. Respectfully submitted, MASSACHUSETTS ELECTRIC COMPANY NEW ENGLAND POWER COMPANY By its attorney, /s/ Thomas G. Robinson ------------------------------------- Thomas G. Robinson 25 Research Drive Westborough, MA 01582 (508) 389-2877 EASTERN EDISON COMPANY MONTAUP ELECTRIC COMPANY By its attorney, /s/ David A. Fazzone ---------------------------------------- David A. Fazzone, Esq. of David A. Fazzone, P.C., and McDermott, Will & Emery 28 State Street Boston, MA 02109-1775 (617) 535-4016 April 30, 1999 COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF MICHAEL E. JESANIS COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF MICHAEL E. JESANIS Table of Contents Page I. Qualifications........................................................1 II. Purpose of Testimony and Summary of Filing............................2 III. Terms, Conditions, and Structure of the Transaction...................6 IV. Rate Plan.............................................................8 1. Rate Consolidation...........................................8 2. Distribution Rate Freeze.....................................9 a. NEES-EUA: Two-Year Extension.............10 b. NEES-National Grid: An Additional Two Year Extension........................12 3. Service Quality Plan........................................14 4. Recovering the Costs of Consolidation.......................15 V. Benefits Created by the NEES Acquisition of EUA......................21 VI. The Acquisition Premium and Transaction Costs........................30 VII. Compliance With Department's Merger Standards........................38 VIII. Other Regulatory Approvals...........................................39
New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 1 of 40 1 I. Qualifications. 2 Q. Please state your name and business address. 3 A. Michael E. Jesanis, 25 Research Drive, Westborough, Massachusetts. 4 5 Q. By whom are you employed and what is your position? 6 A. I am Senior Vice President and Chief Financial Officer of New England Electric System 7 ("NEES"). I am also Vice President of New England Power Company ("NEP"), The 8 Narragansett Electric Company ("Narragansett"), and New England Power Service 9 Company ("NEPSCO"). 10 11 Q. Please summarize your professional and educational background. 12 A. I joined the NEES companies in 1983 as a financial analyst and was elected Treasurer of 13 NEES in 1992. I was elected a Vice President of NEES in 1997 and Senior Vice 14 President and Chief Financial Officer effective March 1, 1998. I earned bachelor's and 15 master's degrees in mathematics from Clarkson College of Technology and a master of 16 business administration degree from the Wharton School at the University of 17 Pennsylvania. 18 New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 2 of 40 1 Q. Have you previously testified before any regulatory commission? 2 A. Yes. I have testified before the Department of Telecommunications and Energy 3 ("Department"), the Rhode Island Public Utilities Commission, the New Hampshire Public 4 Utilities Commission, and the Federal Energy Regulatory Commission. 5 6 II. Purpose of Testimony and Summary of Filing. 7 Q. What is the purpose of this filing? 8 A. On February 1, 1999, NEES, Eastern Utilities Associates ("EUA"), and Research Drive 9 LLC ("Research Drive"), a directly and indirectly wholly owned subsidiary of NEES 10 entered into an Agreement and Plan of Merger ("EUA Agreement"). This filing requests 11 certain approvals which are necessary for consummation of the EUA acquisition. 12 13 Q. Please describe the companies involved in this transaction? 14 A. NEES is a registered holding company under the Public Utility Holding Company Act of 15 1935 ("Holding Company Act") and owns the common equity of several electric utility 16 companies, including Massachusetts Electric Company and Nantucket Electric Company 17 (together "Mass. Electric"), NEP, Granite State Electric Company ("Granite State"), and 18 Narragansett. NEES has entered into an agreement to merge with National Grid Group 19 ("National Grid"), completion of which is awaiting regulatory approvals. New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 3 of 40 1 EUA is also a registered holding company under the Holding Company Act and 2 owns directly or indirectly the common equity of several electric utility companies, 3 including Eastern Edison Company ("Eastern"), Montaup Electric Company 4 ("Montaup"), Blackstone Valley Electric Company ("Blackstone Valley") and Newport 5 Electric Corporation ("Newport"). 6 7 Q. What approvals are being sought from the Department? 8 A. This filing requests Department approval of a number of transactions necessary to 9 consummate the acquisition of EUA. These transactions include: 10 1) the merger of Mass. Electric and Eastern, including the issuances of securities 11 pertaining to such merger; 12 2) the merger of NEP and Montaup, including the issuances of securities pertaining 13 to such merger; 14 3) amendments to the NEES Moneypool, an agreement among NEES companies that 15 allows daily borrowings between companies, to allow participation by EUA and 16 its subsidiaries for the period between the closing of the NEES-EUA merger and 17 the mergers of the operating companies; 18 4) the implementation of a rate plan for the combined Mass. Electric/Eastern which 19 incorporates recovery the acquisition premium paid to acquire EUA and a New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 4 of 40 1 mechanism for recovering a portion of the premium paid by National Grid to 2 acquire NEES, which has allowed this transaction to move forward; and 3 5) approval of service quality standards, certain accounting changes, and 4 amendments to Mass. Electric storm and hazardous waste funds. 5 6 Q. What issues will your testimony address? 7 A. NEES and EUA believe that this transaction provides significant benefits for our 8 constituencies, is in the public interest, and meets the standards for approval by the 9 Department. I will explain the structure and terms of the NEES-EUA merger and 10 summarize our plan for consolidating the NEES and EUA operating companies, moving 11 Eastern's customers to Mass. Electric's lower rates, and freezing Mass. Electric's 12 distribution rates to all customers in the combined companies. I then describe the 13 benefits of the merger and rate plan for customers, employees, and shareholders, and 14 describe the regulatory approvals necessary to implement the transaction. Finally, I 15 address the transaction and acquisition costs associated with the transaction and explain 16 our plans for allocating these costs among the NEES and EUA operating companies and 17 addressing them in the ratemaking process. 18 New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 5 of 40 1 Q. Who else is supporting the filing? 2 A. In addition to my testimony, Robert G. Powderly, Executive Vice President of EUA, will 3 discuss the reasons behind EUA's decision to be acquired by NEES. The service quality 4 improvements and longer term benefits of the merger are discussed by Lawrence J. 5 Reilly, President and Chief Executive Officer of Mass. Electric. Mr. Reilly describes the 6 integration process now underway between the two companies and the goals for 7 developing both efficiency gains and service quality improvements through development 8 of best practices. He also describes the service quality plan for Mass. Electric and 9 Eastern following the consolidation. Jennifer K. Zschokke, Manager of Finance, explains 10 the corporate consolidations of the operating companies and the resulting financing 11 savings from those consolidations, and our request for the Department's approval of the 12 amendments to the NEES Moneypool. 13 David M. Webster, Principal Financial Analyst with the NEES companies, 14 addresses the accounting issues associated with the combination of the two companies, 15 including for example, the development of consistent depreciation schedules and accruals 16 for accounting purposes. He also supports our requested amendments to the storm and 17 hazardous waste funds following the Mass. Electric and Eastern merger. Theresa M. 18 Burns, Principal Rate Analyst for the NEES companies, and James J. Bonner, Manager of 19 Retail Pricing and Rate Administration for the EUA companies, support the rate plan 20 following the consolidation of the operating companies. Their testimonies document the New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 6 of 40 1 rates and rate mapping associated with consolidating the NEP and Montaup transmission 2 rates and contract termination charges, and moving Eastern's customers onto Mass. 3 Electric's rates. 4 Finally, David J. Hoffman and Richard J. Levin of Mercer Management 5 Consulting provide the analysis of synergies and savings that were identified as part of 6 our analysis leading to the merger decision. These savings support the recovery of the 7 acquisition premium and transaction costs associated with the merger. 8 9 III. Terms, Conditions, and Structure of the Transaction. 10 Q. Mr. Jesanis, would you please summarize the transaction between NEES and EUA? 11 A. The transaction is set forth in the merger agreement included as Exhibit MEJ-1. Pursuant 12 to the EUA Agreement, Research Drive will merge with and into EUA with EUA 13 becoming a wholly owned subsidiary of NEES. EUA shareholders will receive $31 per 14 share in cash, which will be increased at a rate of $.003 each day beginning six months 15 after EUA shareholder approval of the EUA acquisition. The merger agreement contains 16 terms and conditions which are typical to a merger transaction. Closing of the merger is 17 subject to obtaining approval of EUA shareholders and obtaining required regulatory 18 approvals. New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 7 of 40 1 Q. How will the acquisition affect EUA's utility subsidiaries? 2 A. At the time of closing, there will be no immediate impact on EUA's utility subsidiaries. 3 For example, Eastern, currently a subsidiary of EUA, will remain so, with EUA 4 becoming a subsidiary of NEES. However, as soon as practicable thereafter, we intend to 5 merge the operating companies of EUA with the operating companies of NEES. We 6 propose that Eastern merge with Mass. Electric, Montaup merge with NEP, and 7 Blackstone Valley and Newport merge with Narragansett. Finally, we expect to combine 8 the operations of the two service companies, NEPSCO and EUA Service Corporation. 9 Therefore, with the exception of the addition of EUA's unregulated companies, the 10 corporate structure resulting from completion of the operating company consolidations 11 will look essentially the same as the current NEES corporate structure. A diagram 12 showing the proposed corporate structures immediately after the acquisition of EUA and 13 after the later consolidation of the operating companies is provided in Exhibit MEJ-2. 14 Even though the consolidation of the operating utility subsidiaries will occur after 15 NEES's acquisition of EUA, we are requesting the Department's approval of all steps and 16 financings necessary to complete the full consolidation of EUA and the utility 17 subsidiaries as well as the proposed rate plan for the consolidation of Mass. Electric and 18 Eastern customers. 19 New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 8 of 40 1 IV. Rate Plan. 2 Q. Please describe the proposed rate plan for Mass. Electric and Eastern customers following 3 the merger. 4 A. The rate plan has four elements. First, we propose to put all Eastern customers on Mass. 5 Electric's rates on January 1, 2001. Second, we propose to freeze the distribution 6 component of the rates for the combined Mass. Electric/Eastern for up to four years after 7 January 1, 2001. Third, we will implement service quality standards for the combined 8 company. Finally, we propose a mechanism to recover the acquisition premium for the 9 NEES-EUA transaction and a portion of the acquisition for the NEES-National Grid 10 transaction. Each of these elements is discussed below. 11 1. Rate Consolidation. First, we propose to put all Eastern customers on Mass. 12 Electric's delivery rates effective with the first billing cycle in January, 2001. 13 When combined with the second element of the rate plan, the distribution rate 14 freeze, Eastern customers will save $23 million in 2001 or 14.2 percent of total 15 retail delivery service charges to Eastern's customers. See Exhibit MEJ-3, page 1. 16 Both Mass. Electric's and Eastern's delivery rates are composed of separate 17 charges for distribution, Renewables and Demand Side Management, 18 transmission, and transition. Under the proposed plan, Eastern's customers will 19 be placed directly on Mass. Electric's existing distribution rates. The individual 20 transmission expenses and contract termination charge costs that were billed from New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 9 of 40 1 NEP to Mass. Electric and from Montaup to Eastern before consolidation will be 2 blended into consolidated transmission and transition factors after the merger of 3 Mass. Electric and Eastern. 4 The consolidation reduces average rates to Eastern's customers by 14.2 5 percent. As shown on Exhibit MEJ-3, page 4, Mass. Electric's customers will 6 also experience a rate decrease in 2001. However, as the result of the averaging 7 of the contract termination charge, the transition component of Mass. Electric's 8 rates is higher than it would have been otherwise. This increase is offset in part 9 by the lower transmission factor that results from blending Montaup's lower 10 transmission charge with NEP's to arrive at a consolidated transmission rate 11 applicable to the combined Mass. Electric. The net result is a slight increase of 12 $0.00062 per kilowatthour or 1.4 percent to Mass. Electric's customers from the 13 rates that would have otherwise been charged in 2001. See Exhibit MEJ-3, pages 14 1 and 4. 15 2. Distribution Rate Freeze. The economic effect of this blending of the transition 16 charge is more than offset by the second component of the rate plan -- a 17 distribution rate freeze. The freeze is proposed for four years beyond the 18 distribution rate freeze in Mass. Electric's and Eastern's Restructuring Settlements 19 which expire on December 31, 2000. The freeze consists of the two extensions 20 discussed below. New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 10 of 40 1 a. NEES-EUA: Two-Year Extension. Mass. Electric commits as 2 part of the NEES-EUA transaction to freeze the distribution component of 3 its rates for two years beyond the rate freeze currently in place under 4 Mass. Electric's Restructuring Settlement in D.P.U./D.T.E. Docket No. 5 96-25. The distribution rate freeze will apply to both Mass. Electric's and 6 Eastern's customers under the consolidated rate plan. Thus, it provides 7 significantly greater benefits than the rate freeze in the Essex County Gas 8 Co. acquisition, Docket D.T.E. 98-27 (1998), that applied only to the rates 9 of the acquired company, Essex County Gas, but not its Massachusetts 10 affiliate, Boston Gas Company. As shown on Exhibit MEJ-4, page 1, line 11 4, the freeze produces lower average rates for Mass. Electric in 2002, more 12 than offsetting the effects associated with the blending of the transition 13 charge. As a result, total delivery rates to Mass. Electric's existing 14 customers are lower as the result of the merger in 2002, the second year of 15 the EUA rate freeze. 16 Under the Restructuring Settlement, the distribution component of 17 Mass. Electric's rates has been frozen since March 1, 1998. Through this 18 new commitment, the freeze will be extended from December 31, 2000 19 through December 31, 2002. This means that, if the EUA merger is 20 completed, distribution rates to Mass. Electric's customers, which are New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 11 of 40 1 among the lowest in the state, will have remained at the same level for 2 almost five years. The Company would retain only the ability to adjust 3 rates to reflect exogenous events occurring during the rate freeze period 4 such as changes to local, state, and federal tax laws, regulations or 5 precedents, and changes to accounting rules and practices. The return on 6 equity cap and floor in the restructuring settlement would not apply to the 7 extended rate freeze. Assuming distribution rates would have otherwise 8 increased at an inflation rate of 2.2 percent per annum, the cumulative 9 value of the rate plan for the customers of the consolidated Mass. Electric 10 is approximately $38 million through December 31, 2002. See Exhibit 11 MEJ-4, page 1, line 12. 12 The two year distribution rate freeze shares the savings from the 13 NEES-EUA merger. As described more fully later in my testimony, we 14 believe that the merger will allow the combined system to reduce annual 15 costs by $35 million. In contrast, the distribution rate freeze eliminates 16 two inflationary increases that would otherwise add $28 million additional 17 revenues to the base distribution charges of the combined companies. 18 Thus, the NEES-EUA merger allows us to meet and extend the rate 19 targets imposed as a result of industry restructuring and to continue to 20 confer substantial economic benefits on customers from regulated New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 12 of 40 1 operations following industry restructuring. These rate benefits from 2 regulated operations are in addition to the benefits produced by the 3 competitive retail market for power supplies that provided the rationale for 4 industry restructuring. 5 b. NEES-National Grid: An Additional Two Year Extension. We 6 intend to continue this pattern of savings from consolidations and 7 efficiency gains through the National Grid merger that was described to 8 the Department in our March 10, 1998 filing. We believe that the National 9 Grid merger will allow us to produce significant additional savings 10 through improved operations, further efficiency gains, the adoption of best 11 practices, and improved scale economies. To reflect and share these 12 anticipated savings, Mass. Electric proposes to extend the distribution rate 13 freeze an additional two years through December 31, 2004 contingent 14 upon the closing of the NEES-National Grid merger. This provides Mass. 15 Electric's customers price stability for regulated service for almost seven 16 years following the introduction of retail choice. The value of the rate 17 plan will grow to over $50 million per year by 2004 and will total 18 approximately $128 million over the rate freeze period. See Exhibit MEJ- 19 4, page 1, line 12. New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 13 of 40 1 The distribution rate freeze represents the most significant element 2 of these savings. As shown on page 2, lines 21 and 22 of Exhibit MEJ-4, 3 the savings associated with the distribution rate freeze total $45 million in 4 2004 and $106 million over the 4 year period. Because of the length of 5 the rate freeze and the potential that inflation may exceed current 6 projections by a significant amount, we propose to add an adjustment in 7 the event that inflation occurring during the extended rate freeze in 8 calendar years 2003 and 2004 exceeds 3.0 percent. Specifically, the 9 average distribution rate at the Consolidation Date is 2.549 cents per 10 kilowatthour as shown in Exhibit MEJ-3, page 1, line 4. This amount will 11 be adjusted by the actual inflation rate in accordance with the 12 methodology illustrated in Exhibit MEJ-5, which compares actual 13 inflation as measured by the Consumer Price Index Deflator - All Urban 14 Consumers ("CPI-U") to 3.0 percent, and adjusts distribution rates in 15 effect in 2003 for 75 percent of the excess over 3.0 percent. The 16 adjustment would be calculated at the end of September, 2002 prior to the 17 first year of the extended rate freeze, and the adjustment, if any, would 18 be rolled into distribution rates as a permanent increase. The process 19 would be followed again for the end of September, 2003 for the following year, New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 14 of 40 1 2004 which is the last year of the rate freeze. This adjustment would be in 2 addition to any adjustments for other exogenous factors. 3 3. Service Quality Plan. These distribution rate freezes confer substantial savings in 4 the price of regulated distribution service for Mass. Electric's customers. The 5 Department has made it clear that these savings should not come at the expense of 6 quality service. We agree. Mr. Reilly addresses in his testimony the service 7 quality plan that we will be implementing to maintain and improve service, 8 customer satisfaction, and reliability. These efforts will continue the 9 commitments of both Eastern and Mass. Electric to provide the best service in the 10 state at the lowest rates in the state. 11 Distribution service represents only 2.5 cents per kilowatthour of Mass. 12 Electric's current average rate. The significant savings from industry 13 restructuring lie in the power supply component of the bill. Standard Offer 14 Service provided by Mass. Electric ends in February 2005, two months after the 15 end of the proposed distribution rate freeze. At the time it ends, Mass. Electric's 16 base standard service charge will be 5.1 cents per kilowatthour. Our most 17 significant challenge over this period is to provide the infrastructure, billing, and 18 data transfer systems necessary for the supply market to provide the economic 19 benefits to customers that we all expect from industry restructuring. The mergers 20 with EUA and National Grid will provide us with the savings and financial New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 15 of 40 1 resources necessary to accomplish this task within the constraints of our current 2 rates. If we are successful, the savings from the competitive market will greatly 3 exceed the savings under the rate plan. Our customers will doubly benefit from 4 the mergers that we have proposed. 5 4. Recovering the Costs of Consolidation. The final element of the proposed rate plan 6 focuses on Mass. Electric's financial integrity and the rate setting process 7 following the period of the distribution rate freeze. As set forth later in my 8 testimony, there are significant costs associated with producing the savings that 9 stem from the consolidation of NEES and EUA and NEES and National Grid. 10 These costs for the NEES-EUA transaction are quantified in this filing and 11 compared directly to the savings from the consolidation. As I explain below, the 12 savings from the NEES-EUA consolidation exceed the acquisition premium and 13 the transaction costs of the NEES-EUA acquisition. As a result, the transaction 14 meets the Department's standards for merger approval, and the acquisition 15 premium and costs of the transaction should be recovered in rates. Accordingly, 16 we are proposing to amortize for ratemaking purposes the EUA acquisition 17 premium and transaction costs that are allocated to Mass. Electric over 20 years as 18 shown on Exhibit MEJ-6. We are also proposing to retain 50 percent of the 19 savings from the EUA acquisition above and beyond the amortization of the EUA 20 acquisition premium and transaction costs to recover a portion of the acquisition New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 16 of 40 1 premium and transaction costs paid by National Grid to acquire NEES. 2 The remaining 50 percent of the excess savings will flow through to customers 3 following the rate freeze producing a reduction in distribution rates over the level 4 that customers would have experienced absent the merger. 5 6 Q. How will the sharing mechanism work? 7 A. The annual savings from the consolidation of the companies will equal $35 million per 8 year in the first full year after the rate freeze. These savings are expected to grow by 9 inflation over the long term. Of this amount, we expect that approximately 72 percent or 10 $25.2 million will flow to the consolidated Mass. Electric. These savings provide the 11 basis for the sharing plan. 12 Under our plan, the future annual savings will be fixed and determined in this 13 proceeding. At the time of any future Mass. Electric distribution rate proceeding, Mass. 14 Electric would be allowed to include in its cost of service the annual amortization of the 15 EUA acquisition premium and transaction costs, because the annual amortization is less 16 than the savings produced by the merger. As shown in Exhibit MEJ-6, the Massachusetts 17 portion of the annual amortization expense for the EUA transaction is $16,421,000 for 20 18 years and zero thereafter. Under our proposal, the amortization would first be subtracted 19 from the annual savings and 50 percent of the remaining savings would then be applied to 20 recover the NEES-National grid acquisition premium and transaction costs. For example, New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 17 of 40 1 if the Department found that the EUA consolidation produced $35 million of annual 2 savings in 2005 when the distribution rate freeze ends, and that $25,176,000 would be 3 allocated to Mass. Electric, Mass. Electric could include in its first cost of service 4 following the rate freeze, an annual amortization of the EUA-NEES acquisition premium 5 equal to $16,421,000 plus one half of the remaining savings to apply against the NEES- 6 National Grid acquisition premium. Thus, 50 percent of $8,755,000 ($25,176,000 - 7 $16,421,000 = $8,755,000) equal to 4,377,500 would be applied against the National 8 Grid premium and transaction costs, and $4,377,500 will be reflected in a lower cost of 9 service. 10 The amount of savings available for the 50/50 sharing mechanism grows over 11 time as the savings grow by inflation, and amortization of the EUA acquisition premium 12 is eliminated after 20 years. Exhibit MEJ-7 illustrates the calculation based on an 13 assumed level of inflation equal to 2.2 percent, and shows the annual sharing amounts. 14 The actual level of sharing will be based on actual inflation experience over the period. 15 Under our proposal, except for the adjustment to reflect actual inflation, these amounts 16 would be fixed for the NEES-EUA transaction in this proceeding. 17 18 Q. Does the share of savings that is applied against the National Grid acquisition premium 19 and transaction costs match the amortization of the premium for accounting purposes? New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 18 of 40 1 A. No. As we have explained, the ratemaking treatment for the acquisition premium and 2 transaction costs is different from the accounting treatment. As with the EUA acquisition 3 premium and transaction costs, the National Grid acquisition premium and transaction 4 costs will be pushed down to the NEES companies, including Mass. Electric, and 5 amortized for accounting purposes over 20 years. The sharing mechanism postpones rate 6 recovery of the portion of the National Grid acquisition premium recovered through the 7 proposed sharing mechanism to a later period. 8 9 Q. What is the portion of the NEES-National Grid premium that is recovered through this 10 mechanism? 11 A. The present values of the savings from the NEES-EUA merger, the amortization of the 12 EUA acquisition premium and transaction costs, and the remaining savings are shown on 13 Exhibit MEJ-8. As that exhibit shows, the net present value of the Massachusetts portion 14 of the merger savings in excess of the EUA recovery is $249 million. Fifty percent of 15 this present value or $125 million is the recovery of the NEES-National Grid premium. 16 This amount will be deducted from the present value of the amortization of the NEES- 17 National Grid premium allocated to Mass. Electric and will not be recovered in any other 18 way. 19 New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 19 of 40 1 Q. Would this sharing mechanism be applied to future acquisitions? 2 A. Yes. Our goal is to generate further savings through future consolidations in the 3 Northeast. Under our plan, 50 percent of the savings in excess of the acquisition 4 premium and transaction costs allocated to Massachusetts customers will also be applied 5 to recover the NEES-National Grid acquisition premium and the transaction costs. As we 6 explained in the NEES-National Grid informational filing, the National Grid acquisition 7 of NEES is essential for the consolidation of other low cost utilities in the Northeast. 8 Even if these consolidations involve acquisitions outside of Massachusetts, savings will 9 flow to Mass. Electric automatically without any associated acquisition premium or 10 transaction costs. For example, as shown on Exhibit MEJ-8, a portion of the savings 11 from the EUA transaction is automatically flowing to New Hampshire customers, but the 12 acquisition costs are not, because EUA has no operations in New Hampshire. These 13 benefits are the direct result of this and future consolidations. If we successfully 14 implement other mergers in the future, Mass. Electric's customers will share the benefits 15 of these consolidations even if they occur outside of Massachusetts. As in this case, 16 Mass. Electric would demonstrate the savings and the sharing at the outset through a 17 synergy study. 18 New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 20 of 40 1 Q. Would the 50 percent sharing apply to savings from ongoing efficiency gains? 2 A. No. Ongoing efficiencies will be generated through an array of activities beyond 3 consolidations. We propose to maintain flexibility to design incentives and sharing 4 mechanisms tailored to specific issues and problems. A simple sharing mechanism may 5 not produce the correct economic incentive for specific operations and programs. For 6 example, our DSM incentive has been based upon both a sharing the value produced by 7 the program and our performance and commitment to DSM programs. Other program- 8 specific incentive designs may be necessary in the future to encourage capital investment 9 to reduce operating costs, losses, or congestion, or to further specific public policy 10 objectives. 11 12 Q. Will there be a cap on recovery of the NEES-National Grid acquisition premium? 13 A. Yes. Mass. Electric's recovery will stop when the portion of the acquisition premium and 14 transaction costs associated with the National Grid transaction that is allocated to Mass. 15 Electric has been recovered. As explained above, the EUA transaction reduces the 16 present value of this recovery by $125 million. Future transactions will be applied to 17 reduce the premium in the same way. When the premium is fully offset, recovery of the 18 National Grid premium will cease. 19 New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 21 of 40 1 V. Benefits Created by the NEES Acquisition of EUA 2 Q. Would you summarize the benefits created through the NEES acquisition of EUA? 3 A. The acquisition of EUA by NEES will result in the creation of substantial benefits which 4 can be used to provide improved service at lower rates to customers, greater opportunities 5 for employees, a premium to EUA shareholders, and an opportunity for NEES and 6 National Grid shareholders to earn reasonable returns on their investments in the 7 companies. 8 The benefits to customers will be delivered through the proposed rate plan 9 described above. These benefits are financed in part by the savings produced by the 10 NEES-EUA consolidation. The acquisition and consolidation produce synergies which 11 are typical of utility combinations. These synergies build on efficiencies already 12 achieved by Mass. Electric and Eastern, which are already the lowest cost utilities in the 13 state. 14 15 Q. How will the cost savings you described be achieved? 16 A. The cost savings will come from a variety of categories. Approximately 70 percent of the 17 savings will come from eliminating approximately 250 positions from the combined 18 organization. These reductions will come from across the organization. Administrative 19 areas such as accounting and finance, where significant redundancies exist between the 20 two companies, will be reduced. EUA's and NEES' customer service operations will be New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 22 of 40 1 integrated to handle increased volumes at a lower unit cost. The unit cost of field 2 operations will also be reduced through standardization and mutual support. The 3 remainder of the operating savings will come from disposing of duplicate facilities, 4 realizing greater purchasing power, and eliminating redundant administrative costs, such 5 as corporate governance expense. Mr. Hoffman testifies at length on these savings. 6 7 Q. What is your estimate of savings that will be achieved? 8 A. Based on the analysis performed by NEES and Mercer Management, the savings will be 9 about $31.1 million per year by the end of the distribution rate freeze period. For reasons 10 I describe below, I believe that the estimate developed by Mercer Management is 11 conservative and that we will achieve total savings of $35 million per year by the end of 12 the rate freeze period. These savings will grow with inflation over time. As shown on 13 Exhibit MEJ-8, the present value of the savings after amortization of the EUA acquisition 14 premium and transaction costs will be at least $356 million. Mass. Electric's share of that 15 amount is $249 million. 16 17 Q. Please describe the goals of the NEES/EUA integration process. 18 A. In my view, there are two overriding goals to the integration process. First, the 19 integration process is critical to achieving the efficiency gains upon which the transaction 20 was predicated. Second, it is equally important to combine the two organizations in a New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 23 of 40 1 way that maintains or improves service quality. The integration process is providing us 2 the opportunity to review our business practices to identify additional opportunities to 3 streamline operations. The integration process also provides us the opportunity to 4 compare business processes and adopt best practices where they can improve service to 5 customers. 6 7 Q. How is the integration effort organized? 8 A. Following the announcement of the NEES-EUA transaction, the two companies created a 9 transition team charged with consolidating the companies in a manner which creates more 10 cost savings than were assumed in the Mercer analysis. The transition team is led by 11 Thomas E. Rogers, Vice President and Director of Corporate Planning for NEPSCO, who 12 directed the sale of our non-nuclear generating business, and Mr. Powderly of EUA, who 13 was responsible for integration activities following EUA's acquisition of Newport 14 Electric. The transition team has formed over 60 individual sub-teams covering all 15 aspects of the business. Each of these teams is charged with the task of identifying 16 savings and efficiency gains. 17 18 Q. What is the schedule for the integration effort? 19 A. The various transition teams have been established and are meeting regularly. For 20 planning purposes, we are targeting October 1, 1999, as the completion date for the New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 24 of 40 1 process so that we will be ready to move forward with implementation as soon as the 2 necessary regulatory approvals are in hand. 3 4 Q. How do you expect that the integration efforts will lead to an improvement on Mercer's 5 estimate of $30 million in annual savings? 6 A. One example of my expectation of better performance is within administrative functions. 7 The Mercer analysis concluded that the combined NEES-EUA companies would need 18 8 percent more personnel in administrative functions than NEES presently has today when 9 the combined company has 22 percent more customers. Given that we will be merging 10 the operating companies into a structure that is nearly identical to NEES's structure, I do 11 not believe that we will need 18 percent more accountants, information systems 12 professional, lawyers and rate analysts when we have no more utility companies in our 13 holding company creating accounting statements, making rate filings or requiring 14 information system resources. Reducing the incremental administrative needs by half 15 will increase savings by $3-5 million per year at the end of the rate freeze. I further 16 believe that Mercer's estimates in customer service and distribution operations understate 17 the benefits we will achieve from the larger scale of the combined NEES-EUA system. 18 New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 25 of 40 1 Q. Are there other savings that are not included in your analysis? 2 A. Yes. We believe that the NEES-National Grid merger will produce additional savings 3 and efficiency gains. We are now evaluating integration possibilities between NEES and 4 National Grid that will implement best practices. These efforts will produce savings for 5 NEES and for the newly acquired EUA companies. Equally important, we expect that 6 over time National Grid's significantly larger scale, both in financial and operational 7 terms, will enhance our ability to be at the leading edge of developments in transmission 8 and distribution technology, information systems and capital markets. The increased 9 expertise and resources will enhance our ability to provide customers of both NEES and 10 EUA with high quality transmission and distribution service at reasonable costs. The 11 benefits that will accrue to EUA from the NEES-National Grid integration process are not 12 reflected in our savings estimates for the NEES-EUA merger. Rather, the NEES- 13 National Grid savings will be demonstrated in a separate proceeding. 14 In addition, the savings study performed by Mr. Hoffman excludes certain cost 15 savings which are typically counted in other utility mergers. For example, most utility 16 mergers include as savings the costs of building one rather than two sets of new 17 information systems (usually customer or financial) at some time in the future. Both 18 NEES and EUA have older customer information systems. The cost of replacing these 19 systems would currently be in excess of $10 million per company. We did not include New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 26 of 40 1 these costs in our study because of the difficulty in pinpointing the timeframe in which 2 the savings will occur. Nevertheless, the savings are real and will provide future benefits. 3 Finally, as Ms. Zschokke testifies, we expect the higher credit ratings of the 4 NEES companies to lead to financing savings as the debt of the EUA companies is 5 refinanced over time. 6 7 Q. Can the annual savings included in your analysis be achieved absent the proposed 8 acquisition? 9 A. No. NEES and EUA have superb long-term records of managing costs. One measure of 10 this record is the rates charged to customers. As shown on Exhibit MEJ-9, NEES and 11 EUA customers in Massachusetts enjoy lower rates than the customers of any other 12 investor owned utility system in the Commonwealth. Residential customers of other 13 investor-owned utilities pay as much as 49% more than those of Mass. Electric and 33% 14 more than those of Eastern, and medium sized commercial customers pay as much as 15 66% more than Mass. Electric and 46% more than Eastern. 16 Another measure of cost efficiency is the number of employees required to serve 17 each 1,000 customers. Prior to the combination, NEES (at 2.4 employees/1,000 18 customers) and EUA (at 2.8 employees/1,000 customers) are significantly more efficient 19 than Boston Edison Company, the next largest utility in Massachusetts (which has 3.4 20 employees/1,000 customers). EUA's performance is particularly noteworthy because it New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 27 of 40 1 has achieved this record of performance despite the fact that it has less than half the 2 customers of Boston Edison. Both NEES and EUA have met their obligations to reduce 3 their costs on a stand alone basis. The combination of NEES, EUA and National Grid 4 represents the best opportunity to continue the track record of NEES and EUA in 5 controlling costs for the benefit of customers. 6 7 Q. How will EUA shareholders benefit from the combination? 8 A. The benefits to EUA shareholders stem from the consideration received for their shares at 9 closing. The base consideration of $31 per share is equal to 105 percent of the $29-1/16 10 market value of the shares on the last trading day before the merger was announced and 11 approximately 169 percent of EUA's book value per share of $18.29 as of December 31, 12 1998. The purchase is equal to a 23 percent premium over the market price on December 13 4, 1998, the last trading day before the BEC Energy-Commonwealth Energy merger was 14 announced. As explained earlier, the purchase price is subject to adjustment depending 15 on the timing of the closing. The purchase price will be paid in cash. Mr. Powderly 16 further describes the basis for EUA's conclusion that the price to be paid is fair to EUA 17 shareholders. 18 19 Q. Why did you use the December 4, 1998 closing price in determining the value to 20 shareholders? New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 28 of 40 1 A. Beginning on December 7, 1998 with the announcement of the BEC Energy - 2 Commonwealth Energy merger, EUA's share began rising substantially above the range 3 in which they had traded in recent months. Based on the long-term previous performance 4 of EUA shares in the market, I believe that this price appreciation is the result of 5 speculation that EUA would enter into some kind of merger agreement at a price 6 significantly higher than the trading price on December 4, 1998. 7 8 Q. What about the benefits to employees? 9 A. Although the merger is expected to reduce employment by about 250 positions in the 10 combined companies, we believe that these employee reductions can be achieved 11 predominantly through attrition or voluntary early retirement and without significant 12 involuntary layoffs. The efficiency gains are essential to the viability of our companies in 13 the restructured utility industry. For remaining employees, the merger and the NEES- 14 National Grid transaction represent a superb opportunity for growth as we move forward 15 as the United States base of operations for a large international group. The expanded 16 opportunities in this country will stem from National Grid's express intention to expand 17 and consolidate its operations here in this country. The fulfillment of this plan ensures 18 that NEES and EUA employees will remain active in the industry restructuring debate in 19 the United States. National Grid's expanding foreign operations will also provide 20 opportunities for employees abroad. New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 29 of 40 1 Q. Are NEES and EUA taking steps to mitigate the loss of positions following the NEES- 2 EUA merger? 3 A. Yes. In anticipation of the merger's approval, we have placed a limitation on hiring for 4 our company. The NEES companies expect to have a significant number of vacant 5 positions by the time the transaction closes. Natural attrition at EUA is expected to add 6 more positions. We are making every effort to leave these positions vacant until 7 employees affected by the acquisition have an opportunity to be considered for a position. 8 Beyond vacancies and attrition, we can economically offer 200 to 250 NEES and EUA 9 employees a voluntary early retirement program. Through these measures, we expect to 10 meet our workforce reduction targets without having a significant impact on individual 11 employees. 12 NEES has also agreed in the merger agreement to honor EUA's collective 13 bargaining agreements and to provide non-union employees joining the NEES companies 14 with compensation and benefits in the aggregate at least equivalent to those obtained 15 prior to the merger for a year following closing. EUA employees joining the NEES 16 system will find that the compensation and benefit philosophies of the two companies are 17 very similar, allowing us to merge benefit plans without significant disruption to 18 employees. 19 New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 30 of 40 1 VI. The Acquisition Premium and Transaction Costs. 2 Q. What are the costs associated with NEES's acquisition of EUA? 3 A. NEES is acquiring EUA at a premium of approximately $260 million above the book 4 value of EUA's shares. The exact amount will be determined at closing based on EUA's 5 financial results prior to closing and any endorsements required to conform EUA's banks 6 of account to NEES practices. Because the acquisition of EUA is for cash, the conditions 7 for pooling of interest accounting are not met in this transaction and therefore, purchase 8 accounting must be used. Under Generally Accepted Accounting Principles ("GAAP") 9 for purchase accounting, the premium is recorded as goodwill on the acquired company's 10 accounts. The premium will be allocated to each of the EUA operating companies 11 following the closing and added to their balance sheets as goodwill. The goodwill will be 12 amortized over 20 years for ratemaking purposes. 13 In addition to the acquisition premium, we expect that the transaction costs and 14 the cost of integrating EUA into NEES and achieving our savings targets will be 15 approximately $64 million. Mr. Hoffman provides support for our cost estimates. 16 17 Q. How will these costs be allocated among the EUA subsidiaries? 18 A. A "fair value" study will be conducted around the time of closing the merger to 19 determine the allocation of the purchase price among the EUA subsidiaries. The 20 acquisition premium and transaction costs will be allocated in two steps. First, the New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 31 of 40 1 acquisition premium will be allocated to the unregulated subsidiaries based on the 2 difference between their market value and their book value. This adjustment brings the 3 value of the unregulated firms up to the value reflected in the acquisition. For the 4 purpose of this filing, we have estimated this allocation based on the underlying book 5 value of the unregulated firms. Because the book value of an unregulated enterprise does 6 not bear any direct relationship to its market value, the actual allocation will be 7 determined in the valuation study. 8 The second step of the analysis allocates the remainder of the acquisition premium 9 among the regulated companies. This analysis includes the allocation of the transaction 10 and integration costs which are in this transaction all related to regulated operations. 11 Because of the similar operating structures of NEES and EUA, we believe that savings 12 achieved by Mass. Electric/Eastern will approximate its size relative to the combined 13 Rhode Island companies. Therefore, we propose that the portion of the allocation 14 premium that is allocated to the regulated businesses be allocated between Eastern and 15 the two Rhode Island subsidiaries on the basis of a three-year average of kilowatthour 16 deliveries to Rhode island and Massachusetts customers of the consolidated utility 17 following the merger. The integration costs, which are entirely related to the regulated 18 subsidiaries, would be allocated among them in a similar manner. 19 This allocation matches the allocation of savings from the transaction, and the 20 economic value that is produced by the consolidation and reflected in the purchase price. New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 32 of 40 1 Given that transmission and distribution remain regulated businesses priced at the cost of 2 providing service, the value added by the transaction is related to the underlying savings 3 produced by the consolidation. As the result of rate design and service company 4 allocations, these savings will generally be based on kilowatthour deliveries to retail 5 customers. The allocation of the acquisition premium and transaction costs follows this 6 methodology. 7 8 Q. Have you allocated any transaction costs or acquisition premium to Montaup/NEP? 9 A. Not in the analysis included in this filing. The primary savings associated with the EUA 10 transaction will be realized in distribution to retail delivery customers. Retail delivery 11 and its associated cost of service represent the bulk of the costs on the system and will 12 represent the most significant source of our savings, directly and indirectly through lower 13 administrative and general expense per customer service. This approach also matches the 14 allocation of the acquisition premium for other utilities whose transmission and 15 distribution rates remain unbundled in the same operating company. 16 Moreover, to the extent transmission savings exist, they will flow to retail 17 customers automatically through NEP's formula rate in proportion to Mass. Electric's 18 retail deliveries. NEP's transmission charges are based on demands at the time of NEP's 19 peak, and although NEP's rate includes deliveries to both affiliated and non-affiliated New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 33 of 40 1 customers, the allocation of acquisition costs parallels the kilowatthour allocation. Our 2 proposed allocation also maintains the Department's jurisdiction over the issue. 3 This approach also matches the allocation of the acquisition premium for other 4 utilities whose transmission and distribution rates remain bundled in the same operating 5 company. 6 7 Q. Do you have an estimate of the acquisition costs to be allocated to Eastern? 8 A. Yes. Eastern would be allocated $171,028,000 of acquisition premium which, when 9 adjusted for income taxes, produces a revenue requirement of $281,409,000. In addition 10 to this amount, Eastern would be allocated $47,007,000 of transaction costs producing a 11 total revenue requirement of $328,416,000. With a 20 year amortization period, the 12 annual revenue requirement is estimated at $16,421,000. This compares to about $25 13 million for Massachusetts' share of savings in the last year of the rate freeze. Exhibit 14 MEJ-6, page 1 illustrates the allocation of the costs of the transaction. The savings grow 15 with inflation over time, but the amortization of the acquisition premium and transaction 16 costs does not. As explained earlier, 50 percent of the excess of savings each year will be 17 applied to recover the NEES-National Grid premium, and following the rate freeze, the 18 remaining 50 percent of excess savings will be reflected in the cost of service to Mass. 19 Electric's customers. 20 New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 34 of 40 1 Q. Please explain Mass. Electric's proposal to retain savings to pay the premium paid by 2 National Grid to acquire NEES. 3 A. As we described in the informational filing made with the Department describing the 4 National Grid-NEES merger, one of the benefits of the National Grid-NEES merger was the 5 facilitation of consolidation of transmission and distribution companies by low-cost 6 companies such as NEES. The benefits from NEES's acquisition of EUA are the first 7 step in realizing the vision behind the National Grid-NEES merger. Therefore, we are 8 proposing that a portion of the benefits from the NEES-EUA acquisition be shared 9 between customers and National Grid-NEES. The sharing mechanism we propose is fair 10 and efficient. It provides customers with $90 million of up-front value through the 11 extension of the rate freeze, (Exhibit MEJ-4, page 1, line 12 ($128,418,140 - $38,325,170 12 = $90,092,970)), and with matching savings throughout the remainder of the period. The 13 proposal puts the risk on the Company to realize the savings during the rate freeze period, 14 and significantly postpones the recovery for this portion of the National Grid premium. 15 In short, the proposal is fair and efficient. It assures that Mass. Electric's customers are 16 better off economically because of the merger with National Grid and EUA, and the 17 future consolidations that will be produced from our new, larger and more financially 18 sound organization. 19 New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 35 of 40 1 Q. Wouldn't the benefits of the EUA acquisition be achieved without the National Grid- 2 NEES merger? 3 A. Without the National Grid-NEES merger, the full benefits of the EUA acquisition would 4 not be realized. First, it is unlikely that NEES would have agreed to acquire EUA at this 5 time absent the National Grid-NEES merger agreement. As described in NEES's proxy 6 statement dated March 26, 1999, over the course of 1998, the management and board of 7 directors of NEES determined that finding a strategic partner such as National Grid was 8 in the Company's best interest. As I have explained, the National Grid merger is 9 essential for a low cost utility like Mass. Electric to compete in the consolidation of the 10 industry. An agreement to acquire EUA by NEES prior to NEES finding a strategic 11 partner could have significantly impaired or delayed NEES's ability to find and reach 12 agreement with a strategic partner. Under these circumstances, an acquisition of EUA by 13 NEES would have been deferred for a year or longer and perhaps not have occurred at all. 14 Second, while EUA had alternatives to an acquisition by NEES, in my opinion, 15 those alternatives would not have produced the level of savings or the rate reductions to 16 EUA customers that can be achieved in this proposed acquisition. I believe that EUA's 17 alternatives generally involved mergers with or acquisitions by higher-cost regional 18 utilities. Those utilities do not possess the track record to operate their own service 19 territories at the efficiency levels of NEES or EUA. Therefore they cannot produce the 20 economic benefits by combining with EUA than NEES can achieve. In addition, to the New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 36 of 40 1 extent savings are achieved, EUA customers are less likely to benefit from these savings 2 since they would most likely be applied to reducing the rates of the acquiring company. 3 EUA's customers could actually be faced with higher costs as the acquiring company 4 combined its higher cost operations with EUA's low-cost operations. 5 The EUA acquisition by NEES represents the first tangible benefits of the 6 National Grid-NEES merger. Therefore, a portion of the savings should be used to 7 compensate National Grid for its investment in NEES. 8 9 Q. Does the proposed rate plan have any potential accounting ramifications? 10 A. Yes. Presently, both NEES and EUA apply Financial Accounting Standard No. 71 11 (FAS 71) to their regulated operations. Pursuant to FAS 71, regulated entities are 12 required to record regulatory assets and liabilities to reflect certain differences between 13 accounting and ratemaking principles. If the NEES-EUA and NEES-National Grid 14 transactions are completed under the rate plan proposed in this docket, Mass. 15 Electric/Eastern and NEP/Montaup may be required to discontinue use of FAS 71, 16 effective upon consummation of the NEES-National Grid merger. 17 18 Q. Why might these companies be required to discontinue use of FAS 71? 19 A. In order to apply FAS 71, a regulated entity must meet certain criteria, including the 20 criteria that the entity's rates are based on its costs of service. It is my understanding that New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 37 of 40 1 in interpreting FAS 71, that the accounting profession considers long-term fixed rate 2 plans to be inconsistent with the criteria of FAS 71. The extension of our current rate 3 freeze by an additional four years may require Mass. Electric/Eastern to discontinue use 4 of FAS 71. In the case of NEP/Montaup, their ability to continue to use FAS 71 for costs 5 being recovered through contract termination charges depends on their continued 6 recovery as part of cost-based rates. Because the underlying distribution companies may 7 no longer qualify to use FAS 71, NEP/Montaup may also be required to discontinue use 8 of FAS 71. 9 10 Q. What impact would the discontinuation of FAS 71 have on the financial statements of 11 NEES's affected subsidiaries including Mass. Electric? 12 A. There are several principal impacts. First, in establishing the initial balance sheet of 13 Mass. Electric/Eastern and NEP/Montaup, following the consummation of the mergers, 14 regulatory assets would not be recognized. The impact of not recognizing regulatory 15 assets would be to increase the goodwill account by the amount of the regulatory assets. 16 In addition, because the operation of FAS 71 would be discontinued, future differences 17 between accounting and ratemaking principles would not lead to the creation of 18 regulatory assets and liabilities. 19 The discontinuation of FAS 71 could cause other differences in accounting to 20 occur as well. Mass. Electric/Eastern and NEP/Montaup have traditionally adhered to the New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 38 of 40 1 accounting rules included in the FERC Uniform System of Accounts, which set of rules 2 have been adopted by the Department with limited exceptions. While those rules are in 3 most cases the same accounting rules followed by unregulated companies, there may be 4 some exceptions. For example, the companies would no longer record AFDC, but would 5 instead record capitalized interest calculated in accordance with accounting standards for 6 unregulated businesses. 7 In addition, while we have described previously the amount of goodwill that we 8 expect to be allocated to the companies and the amortization period for such goodwill for 9 ratemaking purposes, those amounts could differ for accounting purposes. 10 11 Q. Would the discontinuation of FAS 71 affect rates? 12 A. No. The recovery of regulatory assets today reflects ratemaking, rather than accounting 13 principles. While goodwill would be increased as a result of discontinuing FAS 71, the 14 definition of the acquisition premium to be recovered through rates would not include 15 goodwill resulting from regulatory assets otherwise being recovered through rates. 16 17 VII. Compliance With Department's Merger Standards. 18 Q. Is the merger consistent with the standards established by the Department for transactions 19 of this kind? New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 39 of 40 1 A. Yes. The Department set forth its merger standards in Docket 93-167-A, pp. 7-9 (1994) 2 and has recently applied them in Eastern Enterprises acquisition of Essex County Gas 3 Company, Essex County Gas Co., Docket D.T.E. 98-27, pp. 8-9 (1998) and in Northern 4 Indiana Public Service Company's acquisition of Bay State Gas Company, Bay State Gas 5 Co., Docket D.T.E. 98-31, pp. 9-10 (1998). In those orders, the Department established 6 several criteria for consideration. Mr. Powderly explains how this transaction and the 7 Eastern consolidation comply with the Department's standards. 8 9 VIII. Other Regulatory Approvals. 10 Q. Mr. Jesanis, what other regulatory approvals are necessary before the transaction can be 11 closed? 12 A. Federal approval is required from the SEC under the Holding Company Act. In addition, 13 the merger requires approval by FERC under Section 203 of the Federal Power Act. 14 FERC will also approve the consolidation of NEP and Montaup's transmission rates 15 under Section 205 of the Federal Power Act. A Nuclear Regulatory Commission 16 approval under the Atomic Energy Act, will be required to transfer Montaup's nuclear 17 entitlements to NEP as part of the merger. Approval of state commissions in Connecticut, 18 Vermont, and New Hampshire where Montaup owns property may also be required. The 19 Rhode Island Public Utilities Commission, like the Department, has direct jurisdiction 20 over the rate plan for the Rhode Island companies. The Rhode Island Division of Public New England Electric System Eastern Utilities Associates Testimony of M. E. Jesanis Page 40 of 40 1 Utilities and Carriers has jurisdiction over the consolidation of the Rhode Island 2 companies. Finally, the merger requires a Hart Scott Rodino filing with the Department 3 of Justice and the Federal Trade Commission. Our filings with the SEC and FERC will 4 be provided to the Department when they are made. The other filings will be provided on 5 request, except for the Hart Scott Rodino filing, which is treated confidentially. 6 7 Q. What is the estimated time schedule for those proceedings? 8 A. We hope to complete all regulatory proceedings on the merger this year and implement 9 the merger of NEES and EUA during the fourth quarter of this year. Consolidation of the 10 operating companies will be completed as soon as possible thereafter, and the rate plan 11 will be implemented on January 1, 2001 after the distribution rate freezes in both the 12 Mass. Electric and Eastern restructuring settlements expire. 13 14 Q. Does this complete your testimony? 15 A. Yes.
EXHIBITS OF M. E. JESANIS MEJ-1 NEES-EUA Merger Agreement MEJ-2 NEES-EUA: Simplified Corporate Organization, Post-Closing MEJ-3 Rate Comparison for Eastern and Mass. Electric in 2001 MEJ-4 Economic Impact of Rate Freeze Extensions MEJ-5 Illustration of Calculation of Inflation Adjustment to Distribution Rates in 2003 and 2004 MEJ-6 Eastern Acquisition Premium and Transaction Cost Amortization MEJ-7 Sharing of Savings Following NEES/EUA Merger MEJ-8 Present Value Analysis of Acquisition Costs and Savings from NEES-EUA Consolidation MEJ-9 Rate Comparison by Utility New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit MEJ-1 Exhibit MEJ-1 NEES-EUA Merger Agreement See Separate Volume New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit MEJ-2 Exhibit MEJ-2 NEES-EUA Simplified Corporate Organization, Post-Closing Exhibit MEJ-2 Simplified Corporate Structure for Regulated Operating Companies (Plan for Full Consolidation) ------------------------------------------------------ ----------------------- | National Grid | | Group | ----------------------- | | | | | | | | ---------- ----------- | NEES | <- - - - - - - - - - - - - - - - - -| EUA | ---------- ----------- | | | | | ---------------| | | ----------------- -------------------- | | |----| Mass. Electric | < - - | Eastern Edison | ------ | | | ----------------- -------------------- | | | | | | | | | ----------- | | --------------- ----------- | | Granite | | |----| New England | < - - | Montaup | | | State |---| | Power | ----------- | | Electric | | -------------- - - - - - - - - - - - | ----------- | | -------------------- | | | | | Blackstone Valley |- |--| | --------------- | -------------------- | | |----| Narragansett | < - - -| | | --------------- | ------------- | | | | Newport |-----------|--| | -------------- | - - - - - - - - - New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit MEJ-3 Exhibit MEJ-3 Rate Comparison for Eastern and Mass. Electric in 2001
S:\RADATA1\EASTED\Mej-3rev.wk4 New England Electric System PAGE 1 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-___ Exhibit MEJ-3, Revised Page 1 of 4 Massachusetts Electric Company Eastern Edison Company Effect on Individual Billing Components in 2001 Mass. Electric Eastern Total -------------- ------- ----- DISTRIBUTION WITHOUT MERGER (1) Average Rate 2.557 2.803 2.592 (2) Projected GWh Sales 17,131 2,803 19,934 ------- ------ ------ (3) Revenue $438,039,670 $78,568,090 $516,607,760 - ------------------------------------------------------------------------------------------------------------------- DISTRIBUTION WITH MERGER (4) Average Rate 2.502 2.838 2.549 (5) Projected GWh Sales 17,131 2,803 19,934 ------- ------ ------ (6) Revenue $428,617,620 $79,549,140 $508,166,760 - -------------------------------------------------------------------------------------------------------------------- (7) BENEFIT TO TOTAL CUSTOMERS $9,422,050 ($981,050) $8,441,000 ==================================================================================================================== TRANSMISSION WITHOUT MERGER (8) Average Rate 0.559 0.291 0.521 (9) Projected GWh Sales 17,131 2,803 19,934 ------- ------ ------ (10) Revenue $95,762,290 $8,156,730 $103,919,020 - -------------------------------------------------------------------------------------------------------------------- TRANSMISSION WITH MERGER (11) Average Rate 0.518 0.518 0.518 (12) Projected GWh Sales 17,131 2,803 19,934 ------- ------ ------ (13) Revenue $88,738,580 $14,519,540 $103,258,120 - -------------------------------------------------------------------------------------------------------------------- (14) BENEFIT TO TOTAL CUSTOMERS $7,023,710 ($6,362,810) $660,900 ==================================================================================================================== TRANSITION WITHOUT MERGER (15) Average Rate 1.070 2.300 1.243 (16) Projected GWh Sales 17,131 2,803 19,934 ------- ------ ------ (17) Revenue $183,301,700 $64,469,000 $247,770,700 - -------------------------------------------------------------------------------------------------------------------- TRANSITION WITH MERGER (18) Average Rate 1.250 1.250 1.250 (19) Projected GWh Sales 17,131 2,803 19,934 ------- ------ ------ (20) Revenue $214,137,500 $35,037,500 $249,175,000 - -------------------------------------------------------------------------------------------------------------------- (21) BENEFIT TO TOTAL CUSTOMERS ($30,835,800) $29,431,500 ($1,404,300) ==================================================================================================================== (22) TOTAL BENEFIT (COST) TO CUSTOMERS ($14,390,040) $22,087,640 $7,697,600 (23) TOTAL RETAIL DELIVERY RATE W/O MERGER (INCL. .370(CENT)DSM/RENEW) 4.556 5.764 4.726 (24) TOTAL RETAIL DELIVERY RATE W/ MERGER (INCL. .370(CENT)DSM/RENEW) 4.640 4.976 4.687 (25) % BENEFIT (COST) TO CUSTOMERS -1.84% 13.67% 0.82%
S:\RADATA1\EASTED\Mej-3rev.wk4 New England Electric System PAGE 2 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-___ Exhibit MEJ-3 Page 2 of 4 Massachusetts Electric Company Eastern Edison Company Effect on Individual Billing Components in 2001 (1) Mass. Electric: Exhibit TMB-1, Line (1) Eastern: Exhibit TMB-2, Revised, Line (1) (2) Mass. Electric: Per NEP's December 1, 1998CTC Eastern: Per EUA's February 12, 1999 RVC Filing Reconciliation Filing (3) Line (1) x Line (2) (4) Mass. Electric: Exhibit TMB-8, Revised, Line (1) Eastern: Exhibit TMB-9, Revised Line (1) and Exhibit TMB-7, Revised, Total Company Average Distribution Rate on Mass. Electric's Distribution Rates (5) Line (2) (6) Line (4) x Line (5) (7) Line (3) - Line (6) (8) Mass. Electric: Exhibit TMB-1, Line (2) Eastern: Exhibit TMB-2, Revised, Line (2) (9) Line (2) (10) Line (8) x Line (9) (11) Mass. Electric: Exhibit TMB-8, Revised Line (2) Eastern: Exhibit TMB-9, Revised, Line (2) (12) Line (2) (13) Line (11) x Line (12) (14) Line (10) - Line (13) (15) Mass. Electric: Exhibit TMB-1, Revised, Line (3) Eastern: Exhibit TMB-2, Revised, Line (3) (16) Line (2) (17) Line (15) x Line (16) (18) Mass. Electric: Exhibit TMB-8, Revised, Line (3) Eastern: Exhibit TMB -9, Revised, Line (3) (19) Line (2) (20) Line (18) x Line (19) (21) Line (17) - Line (20) (22) Line (7) + Line (14) + Line (21) (23) Line (1) + Line (8) + Line (15) (24) Line (4) + Line (11) + Line (18) (25) [Line (23) - Line (24)] / Line (23)
Eastern Edison Company Avg cents per kWh Exhibit MEJ-3 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Four time periods, as listed below. Y-axis (left side of chart): Average cents per kWh (listed in increments of 1 cent between and including 0 and 7 cents per kWh). [Bar Chart lists five sets of rates for Eastern Edison Company (i) distribution, (ii) DSM and Renewables, (iii) transmission, (iv) transition, and (iv) total rates. Total rates equal the sum of distribution, DSM and Renewables, transmission and transition rates.]
Time DSM & Period Distrib. Renew. Transmission Transition Total 4/1999 2.74 0.41 0.30 2.10 5.55 2000 2.74 0.41 0.29 2.38 5.82 2001 Pre-Merger 2.80 0.37 0.29 2.30 5.76 2001 Post-Merger 2.84 0.37 0.52 1.25 4.98
Future prices are subject to adjustment, but the total rates are capped in accordance with the Massachusetts statute. Page 3 of 4 Massachusetts Electric Company Avg cents per kWh [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Four time periods, as listed below. Y-axis (left side of chart): Average cents per kWh (listed in increments of 1 cent between and including 0 and 6 cents per kWh). [Bar Chart lists five sets of rates for Eastern Edison Company (i) distribution, (ii) DSM and Renewables, (iii) transmission, (iv) transition, and (iv) total rates. Total rates equal the sum of distribution, DSM and Renewables, transmission and transition rates.]
Time DSM & Period Distrib. Renew. Transmission Transition Total 3/1999 2.50 0.41 0.64 1.33 4.88 2000 2.50 0.41 0.55 1.32 4.78 2001 Pre-Merger 2.56 0.37 0.56 1.07 4.56 2001 Post-Merger 2.50 0.37 0.52 1.25 4.64
Future prices are subject to adjustment, but the total rates are capped in accordance with the Massachusetts statute. Page 4 of 4 New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit MEJ-4 Exhibit MEJ-4 Economic Impact of Rate Freeze Extensions
S:\RADATA1\EASTED\Mej-4rev.wk4 New England Electric System SUMMARY Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-___ Exhibit MEJ-4, Revised Page 1 of 4 Massachusetts Electric Company Eastern Edison Company Effects of Merger and Rate Consolidation Benefit (Cost) to Customers 2001 2002 2003 2004 Total ---- ---- ---- ---- ----- MASS. ELECTRIC (1) Distribution $9,422,050 $19,257,390 $29,573,040 $40,671,590 $98,924,070 (2) Transmission $7,023,710 $7,286,580 $7,569,290 $7,883,480 $29,763,060 (3) Transition ($30,835,800) ($27,758,400) ($19,363,300) ($19,708,700) ($97,666,200) ------------ ------------ ------------ ------------ ----------- (4) Total Net Effect ($14,390,040) ($1,214,430) $17,779,030 $28,846,370 $31,020,930 (5) Cumulative Net Effect ($14,390,040) ($15,604,470) $2,174,560 $31,020,930 ----------------------------------------------------------------------------------------------------- EASTERN (6) Distribution ($981,050) $765,450 $2,590,200 $4,509,120 $6,883,720 (7) Transmission ($6,362,810) ($6,577,200) ($6,820,860) ($7,085,760) ($26,846,630) (8) Transition $29,431,500 $28,066,500 $21,009,400 $18,739,200 $97,246,600 ----------- ----------- ----------- ----------- ----------- (9) Total Net Effect $22,087,640 $22,254,750 $16,778,740 $16,162,560 $77,283,690 (10) Cumulative Net Effect $22,087,640 $44,342,390 $61,121,130 $77,283,690 ----------------------------------------------------------------------------------------------------- COMBINED MASS. ELECTRIC (11) Total Net Effect $7,697,600 $21,040,320 $34,557,770 $45,008,930 $108,304,620 (12) Cumulative Net Effect $7,697,600 $28,737,920 $63,295,690 $108,304,620
(1) Page 2, Line (3) - Line (13) (2) Page 3, Line (3) - Line (13) (3) Page 4, Line (3) - Line (13) (4) Line (1) + Line (2) + Line (3) (5) Accumulation of Line (4) (6) Page 2, Line (7) - Line (17) (7) Page 3, Line (7) - Line (17) (8) Page 4, Line (7) - Line (17) (9) Line (6) + Line (7) + Line (8) (10) Accumulation of Line (9) (11) Line (4) + Line (9) (12) Accumulation of Line (11)
C:\eua files on disk\Mej-4rev.wk4 New England Electric System DISTRIBUTION Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-___ Exhibit MEJ-4, Revised Page 2 of 4 Massachusetts Electric Company Eastern Edison Company Estimated Value of Distribution Rate Freeze Over 4 Additional Years 2001 2002 2003 2004 Cumulative ---- ---- ---- ---- ---------- DISTRIBUTION WITHOUT MERGER MASS. ELECTRIC (1) Average Distribution Rate 2.557 2.613 2.670 2.729 (2) Projected GWh Sales 17,131 17,349 17,603 17,917 ------ ------ ------ ------ (3) Revenue $438,039,670 $453,329,370 $470,000,100 $488,954,930 $1,850,324,070 (4) Cumulative Revenue $438,039,670 $891,369,040 $1,361,369,140 $1,850,324,070 EASTERN (5) Average Distribution Rate 2.803 2.865 2.928 2.992 (6) Projected GWh Sales 2,803 2,835 2,878 2,928 ----- ----- ----- ----- (7) Revenue $78,568,090 $81,222,750 $84,267,840 $87,605,760 $331,664,440 (8) Cumulative Revenue $78,568,090 $159,790,840 $244,058,680 $331,664,440 TOTAL OF INDIVIDUAL COMPANIES (9) Total Revenue $516,607,760 $534,552,120 $554,267,940 $576,560,690 $2,181,988,510 (10) Cumulative Total Revenue $516,607,760 $1,051,159,880 $1,605,427,820 $2,181,988,510 - -------------------------------------------------------------------------------------------------------------------------- DISTRIBUTION WITH MERGER MASS. ELECTRIC (11) Average Distribution Rate 2.502 2.502 2.502 2.502 (12) Projected GWh Sales 17,131 17,349 17,603 17,917 ------ ------ ------ ------ (13) Revenue $428,617,620 $434,071,980 $440,427,060 $448,283,340 $1,751,400,000 (14) Cumulative Revenue $428,617,620 $862,689,600 $1,303,116,660 $1,751,400,000 EASTERN (15) Average Distribution Rate 2.838 2.838 2.838 2.838 (16) Projected GWh Sales 2,803 2,835 2,878 2,928 ----- ----- ----- ---- (17) Revenue $79,549,140 $80,457,300 $81,677,640 $83,096,640 $324,780,720 (18) Cumulative Revenue $79,549,140 $160,006,440 $241,684,080 $324,780,720 TOTAL OF INDIVIDUAL COMPANIES (19) Total Revenue $508,166,760 $514,529,280 $522,104,700 $531,379,980 $2,076,180,720 (20) Cumulative Total Revenue $508,166,760 $1,022,696,040 $1,544,800,740 $2,076,180,720 - -------------------------------------------------------------------------------------------------------------------------- BENEFIT TO ALL CUSTOMERS (21) Annual $8,441,000 $20,022,840 $32,163,240 $45,180,710 $105,807,790 ----------- ----------- (22) Cumulative $8,441,000 $28,463,840 $60,627,080 $105,807,790 ----------- ----------- - -------------------------------------------------------------------------------------------------------------------------- (1) Exhibit TMB-1, Line (1) (12) Per NEP's December 1, 1998 CTC Reconciliation Filing (2) Per NEP's December 1, 1998 CTC Reconciliation Filing (13) Line(11) x Line (12) (3) Line (1) x Line (2) (14) Accumulation of Line (13) (4) Accumulation of Line (3) (15) Consolidated Rate Frozen for 5 years (5) Exhibit TMB-2, Line (1) (16) Per EUA's February 12, 1999 RVC Filing (6) Per EUA's February 12, 1999 RVC Filing (17) Line (15) x Line (16) (7) Line (4) x Line (5) (18) Accumulation of Line (17) (8) Accumulation of Line (7) (19) Line (13) + Line (17) (9) Line (3) + Line (7) (20) Accumulation of Line (19) (10) Accumulation of Line (9) (21) Line (9) - Line (19) (11) Consolidated Rate Frozen for 5 years (22) Accumulation of Line (21)
C:\eua files on disk\Mej-4rev.wk4 New England Electric System TRANSMISSION Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-___ Exhibit MEJ-4, Revised Page 3 of 4 Massachusetts Electric Company Eastern Edison Company Estimated Value of Combined Transmission Costs Over 4 Years 2001 2002 2003 2004 Cumulative ---- ---- ---- ---- ---------- TRANSMISSION WITHOUT MERGER MASS. ELECTRIC (1) Average Transmission Rate 0.559 0.571 0.584 0.597 (2) Projected GWh Sales 17,131 17,349 17,603 17,917 ------ ------ ------ ------ (3) Revenue $95,762,290 $99,062,790 $102,801,520 $106,964,490 $404,591,090 (4) Cumulative Revenue $95,762,290 $194,825,080 $297,626,600 $404,591,090 EASTERN (5) Average Transmission Rate 0.291 0.297 0.304 0.311 (6) Projected GWh Sales 2,803 2,835 2,878 2,928 ----- ----- ----- ----- (7) Revenue $8,156,730 $8,419,950 $8,749,120 $9,106,080 $34,431,880 (8) Cumulative Revenue $8,156,730 $16,576,680 $25,325,80 $34,431,880 TOTAL OF INDIVIDUAL COMPANIES (9) Total Revenue $103,919,020 $107,482,740 $111,550,640 $116,070,570 $439,022,970 (10) Cumulative Total Revenue $103,919,020 $211,401,760 $322,952,400 $439,022,970 - -------------------------------------------------------------------------------------------------------------------------- TRANSMISSION WITH MERGER MASS. ELECTRIC (11) Average Transmission Rate 0.518 0.529 0.541 0.553 (12) Projected GWh Sales 17,131 17,349 17,603 17,917 ------ ------ ------ ------ (13) Revenue $88,738,580 $91,776,210 $95,232,230 $99,081,010 $374,828,030 (14) Cumulative Revenue $88,738,580 $180,514,790 $275,747,020 $374,828,030 EASTERN (15) Average Transmission Rate 0.518 0.529 0.541 0.553 (16) Projected GWh Sales 2,803 2,835 2,878 2,928 ----- ----- ----- ----- (17) Revenue $14,519,540 $14,997,150 $15,569,980 $16,191,840 $61,278,510 (18) Cumulative Revenue $14,519,540 $29,516,690 $45,086,670 $61,278,510 TOTAL OF INDIVIDUAL COMPANIES (19) Total Revenue $103,258,120 $106,773,360 $110,802,210 $115,272,850 $436,106,540 (20) Cumulative Total Revenue $103,258,120 $210,031,480 $320,833,690 $436,106,540 - -------------------------------------------------------------------------------------------------------------------------- BENEFIT TO ALL CUSTOMERS (21) Annual $660,900 $709,380 $748,430 $797,720 $2,916,430 (22) Cumulative $660,900 $1,370,280 $2,118,710 $2,916,430 - -------------------------------------------------------------------------------------------------------------------------- (1) Exhibit TMB-1, Line (2) (12) Per NEP's December 1, 1998 CTC Reconciliation Filing (2) Per NEP's December 1, 1998 CTC Reconciliation Filing (13) Line (11) x Line (12) (3) Line (1) x Line (2) (14) Accumulation of Line (13) (4) Accumulation of Line (3) (15) Consolidated Rate Frozen for 5 years (5) Exhibit TMB-2, Revised, Line (2) (16) Per EUA's February 12, 1999 RVC Filing (6) Per EUA's February 12, 1999 RVC Filing (17) Line (15) x Line (16) (7) Line (4) x Line (5) (18) Accumulation of Line (17) (8) Accumulation of Line (7) (19) Line (13) + Line (17) (9) Line (3) + Line (7) (20) Accumulation of Line (19) (10) Accumulation of Line (9) (21) Line (9) - Line (19) (11) Exhibits TMB-8, Revised, and TMB-9, Revised, Line (22) Accumulation of Line (21)
C:\eua files on disk\Mej-4rev.wk4 New England Electric System TRANSITION Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-___ Exhibit MEJ-4, Revised Page 4 of 4 Massachusetts Electric Company Eastern Edison Company Estimated Value of Combined Transition Charge Over 4 Years 2001 2002 2003 2004 Cumulative ---- ---- ---- ---- ---------- TRANSITION WITHOUT MERGER MASS. ELECTRIC (1) Transition Charge 1.070 1.070 1.000 0.940 (2) Projected GWh Sales 17,131 17,349 17,603 17,917 ------ ------ ------ ------ (3) Revenue $183,301,700 $185,634,300 $176,030,000 $168,419,800 $713,385,800 (4) Cumulative Revenue $183,301,700 $368,936,000 $544,966,000 $713,385,800 EASTERN (5) Transition Charge 2.300 2.220 1.840 1.690 (6) Projected GWh Sales 2,803 2,835 2,878 2,928 ----- ----- ----- ----- (7) Revenue $64,469,000 $62,937,000 $52,955,200 $49,483,200 $229,844,400 (8) Cumulative Revenue $64,469,000 $127,406,000 $180,361,200 $229,844,400 TOTAL OF INDIVIDUAL COMPANIES (9) Total Revenue $247,770,700 $248,571,300 $228,985,200 $217,903,000 $943,230,200 (10) Cumulative Total Revenue $247,770,700 $496,342,000 $725,327,200 $943,230,200 - --------------------------------------------------------------------------------------------------------------------------- TRANSITION WITH MERGER MASS. ELECTRIC (11) Transition Charge 1.250 1.230 1.110 1.050 (12) Projected GWh Sales 17,131 17,349 17,603 17,917 ------ ------ ------ ------ (13) Revenue $214,137,500 $213,392,700 $195,393,300 $188,128,500 $811,052,000 (14) Cumulative Revenue $214,137,500 $427,530,200 $622,923,500 $811,052,000 EASTERN (15) Transition Charge 1.250 1.230 1.110 1.050 (16) Projected GWh Sales 2,803 2,835 2,878 2,928 ----- ----- ----- ----- (17) Revenue $35,037,500 $34,870,500 $31,945,800 $30,744,000 $132,597,800 (18) Cumulative Revenue $35,037,500 $69,908,000 $101,853,800 $132,597,800 TOTAL OF INDIVIDUAL COMPANIES (19) Total Revenue $249,175,000 $248,263,200 $227,339,100 $218,872,500 $943,649,800 (20) Cumulative Total Revenue $249,175,000 $497,438,200 $724,777,300 $943,649,800 - --------------------------------------------------------------------------------------------------------------------------- BENEFIT TO ALL CUSTOMERS (21) Annual (Difference due to ($1,404,300) $308,100 $1,646,100 ($969,500) ($419,600) rounding vs. truncating methodologies in CTC/RVC calculations) (22) Cumulative ($1,404,300) ($1,096,200) $549,900 ($419,600) - --------------------------------------------------------------------------------------------------------------------------- (1) Exhibit TMB-1, Line (3) (12) Per NEP's December 1, 1998 CTC Reconciliation Filing (2) Per NEP's December 1, 1998 CTC Reconciliation Filing (13) Line (11) x Line (12) (3) Line (1) x Line (2) (14) Accumulation of Line (13) (4) Accumulation of Line (3) (15) Consolidated Rate Frozen for 5 years (5) Exhibit TMB-2, Line (3) (16) Per EUA's February 12, 1999 RVC Filing (6) Per EUA's February 12, 1999 RVC Filing (17) Line (15) x Line (16) (7) Line (4) x Line (5) (18) Accumulation of Line (17) (8) Accumulation of Line (7) (19) Line (13) + Line (17) (9) Line (3) + Line (7) (20) Accumulation of Line (19) (10) Accumulation of Line (9) (21) Line (9) - Line (19) (11) Exhibits TMB-8 and TMB-9, Line (3) (22) Accumulation of Line (21)
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit MEJ-5 Exhibit MEJ-5 Illustration of Calculation of Inflation Adjustment to Distribution Rates in 2003 and 2004
S:\RADATA1\EASTED\Mej-5.wk4 New England Electric System INFLAT ADJ 3 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Exhibit MEJ- 5 Page 1 of 1 Massachusetts Electric Company Illustration of Calculation Inflation Adjustment to Distribution Rates in 2003 and 2004 3% Annual Annual Benchmark Illustrative Annual CPI Percentage Inflation in 75% of Distribution Distribution End of Month Inflation Index Change Excess of 3% Excess Rate Adjustment (1) (2) (3) (4) (5) (6) (7) (8) September 2001 136.6 2/ September 2002 140.9 2/ Annual Total 3.000% 1/ 3.148% 3/ 0.148% 4/ 0.111% 5/ 2.549 6/ 0.002 7/ September 2002 140.9 2/ September 2003 144.8 2/ Annual Total 3.000% 1/ 2.768% 3/ n/a 2.551 8/ n/a - ---------------------------------------------------------------------------------------------------------------------------------- 1/ Annual rate of 3% for inflation benchmark 2/ Historical Consumer Price Index - All Urban Consumers (CPI-U) obtained from the Bureau of Laor Statistics 3/ Percentage change between prior month's CPI-U and current month's CPI-U 4/ Difference between actual inflation (3/) and assumed inflation benchmark of 3% (1/) 5/ 75% x excess inflation in 4/ 6/ Exhibit MEJ-3, Page 3 7/ 75% of excess inflation in 5/ multiplied by benchmark distribution rate in 6/ 8/ Prior year net distribution charge (6/) + (7/) as current year's distribution benchmark
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit MEJ-6 Exhibit MEJ-6 Eastern Acquisition Premium and Transaction Cost Amortization
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit MEJ-6 Page 1 of 3 NEES/EUA Acquisition Premium Amortization of Acquisition Premium and Transaction Costs In Thousands of Dollars Illustrative Calculation pending completion of Acquisition Premium Allocation Study Allocation to States 12/ -------------------------------- Massachusetts Rhode Island Total (Eastern Edison) 1 ACQUISITION PREMIUMS: 100.00% 73.91% 26.09% 2 Total Acquisition Premium 1/ $260,000 3 Less: Allocation to Unregulated Subsidiaries 2/ 28,600 4 Net Acquisition Premium to Regulated Subsidiaries 3/ $231,400 $171,028 $60,372 5 6 Times Tax Gross-Up Factor 4/ 1.6454 1.5384 7 8 Acquisition Premium at Revenue Requirement 5/ $374,285 $281,409 $92,876 9 10 Amortization Period (Years) 6/ 20 20 20 11 12 Amortization per year for Acquisition Premiums 7/ $18,714 $14,070 $4,644 13 14 15 TRANSACTION COSTS: 16 Total Estimated Transaction Costs 8/ $63,600 $47,007 $16,593 17 18 Amortization Period (Years) 9/ 20 20 20 19 20 Amortization per year for Transaction Costs 10/ $3,180 $2,351 $829 21 22 TOTAL AMORTIZATION PER YEAR 11/ $21,894 $16,421 $5,473 Notes: 1/ Exhibit MEJ-6, Page 3, Line 15. 2/ Allocation of costs to unregulated subsidiaries. (Exhibit MEJ-6, Page 3, Line 35 times Line 2.) 3/ Line 1 minus Line 2. 4/ For Massachusetts: 1 plus Federal Income Tax (FIT) Rate divided by 1 minus FIT rate plus State Income Tax (SIT) rate divided by 1 minus SIT rate divided by 1 minus FIT rate (1+(35%/(1-35%))+((6.5%/(1-6.5%)/(1-35%))). For Rhode Island: 1 plus Federal Income Tax (FIT) Rate divided by 1 minus FIT rate. (1+(35%/(1-35%))). 5/ Line 4 times Line 6. 6/ Proposed amortization period for Acquisition Premiums. 7/ Line 8 divided by Line 10. 8/ Total Estimated Transaction costs to complete NEES/EUA merger. 9/ Proposed amortization period for Transaction Costs. 10/ Line 16 divided by Line 18. 11/ Line 12 plus Line 20. 12/ Exhibit MEJ-6, Page 2, Column (f).
New England Electric System Eastern Utilities Associates M.D.T.E. Docket ____ Exhibit MEJ-6 Page 2 of 3 NEES/EUA Acquisition Premium Allocation of Acquisition Premium and Transaction Costs Illustrative Calculation pending completion of Acquisition Premium Allocation Study 1998 1997 1996 Total 3 Year Ave. MWh Sales MWh Sales MWh Sales MWh Sales MWh Sales Allocation to Ultimates to Ultimates to Ultimates to Ultimates to Ultimates Percentage Column (a) 1/ Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/ 1 Massachusetts Electric 16,590,946 16,141,173 16,009,209 48,741,328 2 Eastern Edison 2,707,973 2,641,448 2,622,517 7,971,938 3 Total Massachusetts 19,298,919 18,782,621 18,631,726 56,713,266 18,904,422 73.91% 4 5 Narragansett Electric 4,977,637 4,822,669 4,778,027 14,578,333 6 Blackstone Valley Electric 1,290,871 1,289,116 1,256,978 3,836,965 7 Newport Electric 542,466 536,209 525,372 1,604,047 8 Total Rhode I 6,810,974 6,647,994 6,560,377 20,019,345 6,673,115 26.09% 9 Grand Total 26,109,893 25,430,615 25,192,103 76,732,611 25,577,537 100.00% Notes: 1/ 1998 FERC Form 1, Pages 300-301. 2/ 1997 FERC Form 1, Pages 300-301. 3/ 1996 FERC Form 1, Pages 300-301. 4/ Sum of Columns (a) through (c). 5/ Column (d) divided by three. 6/ Ratio of Average MWh Sales to Total MWh Sales (Column (e)).
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit MEJ-6 Page 3 of 3 NEES/EUA Acquisition Premium Amortization of Acquisition Premium and Transaction Costs In Thousands of Dollars Illustrative Calculation pending completion of Acquisition Premium Allocation Study 1 Calculation of Acquisition Premium: 2 Acquisition Price Per Share $31.00 1/ 3 4 Outstanding EUA Common Shares 5 as of December 31, 1998 20,435,997 2/ 6 7 Total Acquisition Cost $633,516 3/ 8 9 10 EUA Consolidated Net Book Value 11 as of December 31, 1998 $373,674 4/ 12 13 Total Acquisition Premium $259,842 5/ 14 15 Total Acquisition Premium (Rounded) $260,000 6/ 16 17 18 Calculation of Allocation to Unregulated Subsidiaries: 19 20 Net Book Value of Unregulated Subsidiaries as of 21 December 31, 1998: 22 23 EUA Cogenex $48,361 24 EUA Energy Inv. (24,204) 25 EUA Energy Services (34) 26 EUA Ocean State 16,546 27 EUA Telecommunications (131) 28 Total Net Book Value of Unregulated Subsidiaries 40,538 7/ 29 30 Net Book Value of EUA Consolidated 31 as of December 31, 1998 (In Thousands) 373,674 8/ 32 33 Percentage of Unregulated Subsidiaries to Total 10.85% 9/ 34 35 Percentage (Rounded) 11.00% 10/ Notes: 1/ Acquisition Price per Share per NEES/EUA Merger Agreement. 2/ EUA common shares outstanding as of December 31, 1998 per EUA annual report. 3/ Line 2 times Line 5. 4/ Net Book Value (Common Equity) as of December 31, 1998 per EUA annual report before any adjustments required under purchase accounting rules. 5/ Line 7 minus Line 11. 6/ Line 13 rounded to tens on millions. 7/ Net Book Value (Common Equity) as of December 31, 1998 before any adjustments required under purchase accounting rules. 8/ Net Book Value (Common Equity) as of December 31, 1998 before any adjustments required under purchase accounting rules. 9/ Line 28 divided by Line 31. 10/ Line 33 rounded to nearest whole percent.
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit MEJ-7 Exhibit MEJ-7 Sharing of Savings Following NEES/EUA Merger
New England Electric System Eastern Utilities Associates M.D.T.E. Docket ____ Exhibit MEJ-7 Page 1 of 1 NEES/EUA Acquisition Premium Sharing of Savings following NEES/EUA Merger In Thousands of Dollars Illustrative Calculation pending completion of Acquisition Premium Allocation Study Massachusetts Sharing of Net Savings Massachusetts Apportionment ---------------------- Anticipated Apportionment of EUA Acquisition Massachusetts National Grid Massachusetts Savings (71.93%) Premium Recovery Net Savings Premium Customers Year Column (a) 1 Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/ ---- ------------ ------------- ---------------- -------------- ------------- ------------- 1 2005 $35,000 $25,176 $16,421 $8,755 $4,377 $4,378 2 2006 35,770 25,729 16,421 9,308 4,654 4,654 3 2007 36,557 26,295 16,421 9,874 4,937 4,937 4 2008 37,361 26,874 16,421 10,453 5,227 5,226 5 2009 38,183 27,465 16,421 11,044 5,522 5,522 6 2010 39,023 28,069 16,421 11,648 5,824 5,824 7 2011 39,882 28,687 16,421 12,266 6,133 6,133 8 2012 40,759 29,318 16,421 12,897 6,449 6,448 9 2013 41,656 29,963 16,421 13,542 6,771 6,771 10 2014 42,572 30,622 16,421 14,201 7,101 7,100 11 2015 43,509 31,296 16,421 14,875 7,438 7,437 12 2016 44,466 31,984 16,421 15,563 7,782 7,781 13 2017 45,444 32,688 16,421 16,267 8,134 8,133 14 2018 46,444 33,407 16,421 16,986 8,493 8,493 15 2019 47,466 34,142 16,421 17,721 8,861 8,860 16 2020 48,510 34,893 16,421 18,472 9,236 9,236 17 2021 and beyond 49,577 35,661 0 35,661 17,831 7/ 17,830 7/ Notes: 1/ Anticipated Savings from NEES/EUA Merger in 2005 dollars escalated by inflation of 2.2% per year. 2/ Column (a) times Massachusetts Savings Apportionment factor. (Exhibit MEJ-8, Page 2, Line 3, column (f)). 3/ Exhibit MEJ-6, Page 1, Line 22. 4/ Column (b) minus Column (c). 5/ Proposed Merger Savings Sharing (Column (d) times 50%). 6/ Column (d) minus Column (e). 7/ Increases by inflation beginning in 2021.
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit MEJ-8 Exhibit MEJ-8 Present Value Analysis of Acquisition costs and Savings from NEES-EUA Consolidation
New England Electric System Eastern Utilities Associates M.D.T.E. Docket ____ Exhibit MEJ-8 Page 1 of 2 NEES/EUA Acquisition Premium Net Present Value of Estimated Savings and Acquisition Premium In Thousands of Dollars Illustrative Calculation pending completion of Acquisition Premium Allocation Study Allocation to States 15/ -------------------------------------------- Massachusetts Rhode Island New Hampshire Total (Eastern Edison) Net Present Value of Merger Savings: 100.00% 71.93% 25.39% 2.68% - ----------------------------------- ------- ----- ----- ----- Estimated Annual Savings 1/ $30,716 $22,094 $7,799 $823 Estimated After Tax Cost of Capital 2/ 7.50% 7.50% 7.50% 7.50% Less: Estimated Inflation Rate 3/ 2.20% 2.20% 2.20% 2.20% ---- ---- ---- ---- Net Discount Rate 4/ 5.30% 5.30% 5.30% 5.30% Net Present Value of Estimated Annual Savings 5/ $579,547 $416,868 $147,151 $15,528 ======== ======== ======== ======= Net Present Value of Merger Costs: - --------------------------------- Annual Amortization of Acquisition Premium 6/ $18,714 $14,070 $4,644 Net Present Value of Amortization of Acquisition Premiums using 7.50% Discount Rate 7/ $190,780 $143,436 $47,343 -------- -------- ------- Annual Amortization of Transaction Premium 8/ $3,180 $2,351 $829 Net Present Value of Amortization of Acquisition Premiums using 7.50% Discount Rate 9/ $32,418 $23,967 $8,451 ------- ------- ------ Total Net Present Value of Merger Costs 10/ $223,198 $167,403 $55,794 ======== ======== ======= Net Present Value of Excess Merger Savings 11/ $356,349 $249,465 $91,357 $15,528 Sharing of Excess Merger Savings 12/ 50% 50% 50% 50% --- --- --- --- Allocation of Excess Merger Savings to National Grid Acquisition Premium 13/ $178,174 $124,732 $45,679 $7,764 -------- -------- ------- ------ Allocation of Excess Merger Savings to Customers 1 $178,175 $124,733 $45,678 $7,764 ======== ======== ======= ====== Notes: 1/ $35 million of estimated savings in 2005 discounted to 1999 dollars by inflation rate of 2.2%. 2/ Estimated after tax cost of capital. 3/ Estimated annual inflation rate. 4/ Line 4 minus Line 5. 5/ Line 2 divided by Line 6. 6/ Exhibit MEJ-6, Page 1, Line 12. 7/ Net Present Value of amortization of Acquisition Premium over 20 years. 8/ Exhibit MEJ-6, Page 1, Line 20. 9/ Net Present Value of amortization of Transaction Costs over 20 years. 10/ Line 15 plus Line 21. 11/ Line 8 minus Line 23. 12/ Proposed Sharing of Excess Savings between customers and shareholders. 13/ Line 25 times Line 27. 14/ Line 25 minus Line 30. 15/ Exhibit MEJ-8, Page 2, Column (f).
New England Electric System Eastern Utilities Associates M.D.T.E. Docket ____ Exhibit MEJ-8 Page 2 of 2 NEES/EUA Acquisition Premium Allocation of Acquisition Premium and Transaction Costs Illustrative Calculation pending completion of Acquisition Premium Allocation Study 1998 1997 1996 Total 3 Year Ave. MWh Sales MWh Sales MWh Sales MWh Sales MWh Sales Allocation to Ultimates to Ultimates to Ultimates to Ultimates to Ultimates Percentage Column (a) 1/ Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/ ------------- ------------ ------------- ------------ ------------- ------------- Massachusetts Electric 16,590,946 16,141,173 16,009,209 48,741,328 Eastern Edison 2,707,973 2,641,448 2,622,517 7,971,938 ---------- ---------- ---------- ---------- Total Massachusetts 19,298,919 18,782,621 18,631,726 56,713,266 18,904,422 71.93% ----------- ----------- ----------- ----------- Narragansett Electric 4,977,637 4,822,669 4,778,027 14,578,333 Blackstone Valley Electric 1,290,871 1,289,116 1,256,978 3,836,965 Newport Electric 542,466 536,209 525,372 1,604,047 -------- -------- -------- --------- Total Rhode Island 6,810,974 6,647,994 6,560,377 20,019,345 6,673,115 25.39% ---------- ---------- ---------- ----------- Granite State Electric 718,452 693,879 699,569 2,111,900 -------- -------- -------- --------- Total New Hampshire 718,452 693,879 699,569 2,111,900 703,967 2.68% -------- -------- -------- ---------- -------- ----- Grand Total 26,828,345 26,124,494 25,891,672 78,844,511 26,281,504 100.00% ----------- ----------- ----------- ----------- ----------- ------- Notes: 1/ 1998 FERC Form 1, Pages 300-301. 2/ 1997 FERC Form 1, Pages 300-301. 3/ 1996 FERC Form 1, Pages 300-301. 4/ Sum of Columns (a) through (c). 5/ Column (d) divided by three. 6/ Ratio of Average MWh Sales to Total MWh Sales (Column (e)).
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit MEJ-9 Exhibit MEJ-9 Rate Comparison by Utility Comparison of Massachusetts "Delivery" Rates Residential Customer (500 kWh Usage) (Cents per kWh) Exhibit MEJ-9 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Massachusetts utilities. Y-axis (left side of chart): Cents per kWh charged to residential customers (listed in increments of 2.0 cents between and including 0.0 and 10.0 cents per kWh). [Bar Chart lists four sets of rates for each of seven Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii) transition rates, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total MECO 4.1 0.7 1.3 6.1 EECO 4.2 0.3 2.1 6.6 Camb 4.0 1.3 1.4 6.7 WMeco* 5.1 0.3 2.8 8.2 Fitchburg* 5.4 0.5 2.5 8.4 BECO 5.6 0.3 2.8 8.7 Comm Elec 5.5 0.4 3.2 9.1
[NEES Logo] (*) Rates do not include any adjustment reflecting divestiture. Based on rates as of April 1, 1999. Page 1 of 5 Comparison of Massachusetts "Delivery" Rates Average G-1 Customer (6 kW Demand and 1,500 kWh Usage) (Cents per kWh) Exhibit MEJ-9 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Massachusetts utilities. Y-axis (left side of chart): Cents per kWh charged to average G-1 customers (listed in increments of 2.0 cents between and including 0.0 and 10.0 cents per kWh). [Bar Chart lists four sets of rates for each of seven Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii) transition rates, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total Camb 2.6 1.2 1.4 5.2 MECO 4.8 0.7 1.3 6.8 EECO 4.8 0.3 2.1 7.2 Comm Elec 4.3 0.4 3.2 7.8 WMeco* 4.8 0.3 2.8 7.9 Fitchburg* 5.5 0.5 2.4 8.4 BECO 5.8 0.4 2.7 8.9
[NEES Logo] (*) Rates do not include any adjustment reflecting divestiture. Based on rates as of April 1, 1999. Page 2 of 5 Comparison of Massachusetts "Delivery" Rates Average G-2 Customer (50 kW Demand and 16,700 kWh Usage) (Cents per kWh) Exhibit MEJ-9 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Massachusetts utilities. Y-axis (left side of chart): Cents per kWh charged to average G-2 customers (listed in increments of 2.0 cents between and including 0.0 and 8.0 cents per kWh). [Bar Chart lists four sets of rates for each of seven Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii) transition rates, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total MECO 2.4 0.6 1.3 4.4 Camb Elec 2.1 1.1 1.4 4.5 EECO 2.7 0.3 1.8 4.8 WMeco* 3.0 0.3 2.8 6.1 Fitchburg* 4.2 0.4 2.2 6.8 BECO 4.3 0.4 2.4 7.1 Comm 3.8 0.4 3.2 7.3
[NEES Logo] (*) Rates do not include any adjustment reflecting divestiture. Based on rates as of April 1, 1999. Page 3 of 5 Comparison of Massachusetts "Delivery" Rates Average G-3 Customer (610 kW Demand and 255,400 kWh Usage) (Cents per kWh) Exhibit MEJ-9 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Massachusetts utilities. Y-axis (left side of chart): Cents per kWh charged to average G-3 customers (listed in increments of 1.0 cent between and including 0.0 and 8.0 cents per kWh). [Bar Chart lists four sets of rates for each of seven Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii) transition rates, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total MECO 1.8 0.6 1.3 3.7 Camb 1.2 1.2 1.4 3.8 EECO 1.8 0.3 2.2 4.3 Comm 1.4 0.3 3.2 4.9 Fitchburg* 3.1 0.4 1.7 5.2 WMeco* 2.1 0.3 2.9 5.3 BECO 2.3 0.3 2.8 5.4
[NEES Logo] (*) Rates do not include any adjustment reflecting divestiture. Based on rates as of April 1, 1999. Page 4 of 5 Comparison of Massachusetts "Delivery" Rates Very Large C&I Customer (5,000 kW Demand and 2,000,000 kWh Usage) (Cents per kWh) Exhibit MEJ-9 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Massachusetts utilities. Y-axis (left side of chart): Cents per kWh charged to very large C&I customers (listed in increments of 1.0 cents between and including 0.0 and 6.0 cents per kWh). [Bar Chart lists four sets of rates for each of seven Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii) transition rates, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total MECO 1.8 0.6 1.3 3.7 Camb 1.2 1.4 1.4 4.0 EECO 1.8 0.3 2.2 4.3 Comm Elec 1.1 0.3 3.2 4.7 WMeco* 1.7 0.3 3.0 5.0 Fitchburg* 3.1 0.4 1.7 5.2 BECO 2.3 0.3 2.8 5.4
[NEES Logo] (*) Rates do not include any adjustment reflecting divestiture. Based on rates as of April 1, 1999. Page 5 of 5 COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF ROBERT G. POWDERLY COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF ROBERT G. POWDERLY Table of Contents Page I. Qualifications........................................................1 II. Purpose of Testimony..................................................4 III. Terms, Conditions, and Structure of the Transaction...................4 IV. Benefits to Customers, Employees and Shareholders.....................9 V. Compliance with the Department's Merger and Acquisition Standards....13 1. Effect on Rates.............................................14 2. Quality of Service..........................................14 3. Resulting Net Savings.......................................15 4. Effect on Competition.......................................15 5. Cost Allocation Issues......................................16 6. Financial Integrity of the Post-Merger Entity...............17 7. Societal Costs-Employment...................................17 8. Economic Development........................................18 9. Alternatives to Mergers or Acquisitions.....................18 VI. Conclusion...........................................................19
New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 1 of 19 1 I. Qualifications. 2 Q. Please state your name and business address. 3 A. My name is Robert G. Powderly and my business address is 750 West Center Street, 4 West Bridgewater, Massachusetts. 5 6 Q. By whom are you employed and in what capacity? 7 A. I am employed by EUA Service Corporation ("EUASC"). I am Executive Vice President 8 of Blackstone Valley Electric Company ("Blackstone"), Eastern Edison Company 9 ("Eastern"), Newport Electric Corporation ("Newport") and Montaup Electric Company 10 ("Montaup"). Additionally, I hold the same position for Eastern Utilities Associates 11 ("EUA"), the parent company of the above three retail affiliates and EUASC, the service 12 company for EUA's subsidiaries. My areas of responsibility for regulated companies in 13 the EUA system include Customer Service, Human Resources, Information Systems, and 14 Rates. 15 16 Q. Please summarize your educational background and your professional qualifications. 17 A. I was graduated from the College of the Holy Cross in 1969 with a Bachelor of Arts 18 degree in mathematics. After serving five years in the U. S. Navy, I attended 19 Northeastern University, and received a Master of Science in Accounting degree in 1975. New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 2 of 19 1 While in the Navy, I was involved in the operation of naval nuclear propulsion units and 2 in 1973 I qualified as Engineer of Naval Nuclear Propulsion plants. 3 After graduate school, I was employed for almost four years by an international 4 public accounting firm (Ernst & Ernst, now called Ernst & Young). During this period, 5 my responsibilities included audits of publicly-held, regulated, and non-profit 6 organizations. In 1978, I joined EUASC as Audit Supervisor. My responsibilities were 7 to develop and implement a comprehensive audit program for the EUA system companies 8 and to report the results of that program to both management and the Audit Committee of 9 the Board of Trustees. After three years as Audit Supervisor, I was promoted to the 10 position of Manager of System Revenue Requirements. In this position, I was 11 responsible for the detailed coordination and preparation of rate cases for EUA's 12 companies. I participated personally in these cases in various ways, including testifying 13 on matters reflected in the cost of service or preparing cost-of-service adjustments under 14 the direction of company accounting witnesses. Effective August 1, 1985, I was 15 promoted to Assistant Vice President and I assumed responsibilities for special projects 16 in the areas of accounting, taxes, finance, and personnel. On April 15, 1986, I was named 17 Vice President of EUA Service Corporation wherein I assumed responsibility for the 18 EUA's Rate and Customer Service Departments. In March 1990, I was elected President 19 of Newport upon its acquisition by EUA. I was responsible for the integration of 20 operations of Newport and EUA. In April 1992, I was elected Executive Vice President New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 3 of 19 1 with EUA system responsibilities of Corporate Communications, Customer Service, 2 Information Systems, and Rates. 3 I am a Certified Public Accountant in the Commonwealth of Massachusetts. In 4 addition, I have participated in several professional and utility associations, such as the 5 American Institute of Certified Accountants, the Massachusetts Society of Certified 6 Public Accountants, both the Audit Committee and the Rate Research Committee of the 7 Edison Electric Institute, both the Audit Committee and Energy Management Committee 8 of the Electric Council of New England, and the National Association of Accountants. 9 10 Q. Do you serve on any other boards or committees? 11 A. Yes. I serve on the Board of Directors of Blackstone, Eastern, Newport, EUASC, 12 Montaup, and the Southeastern Massachusetts Manufacturing Partnership. Also, I am the 13 past chairperson of the Electric Council of New England and the Rhode Island Good 14 Neighbor Energy Fund and past Vice Chairperson of the United Way of Newport County. 15 16 Q. Have you previously testified before any regulatory commission? 17 A. Yes. I have testified before the Department of Telecommunications and Energy 18 ("Department") in Eastern's general rate cases. I have also testified before the Rhode 19 Island Public Utilities Commission in general rate cases filed by Blackstone and 20 Newport, and presented testimony before the Federal Energy Regulatory Commission on New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 4 of 19 1 behalf of Montaup, EUA's transmission and generation company. Additionally, I have 2 testified before legislative committees in Rhode Island and Massachusetts on the subject 3 matter of electric utility restructuring. 4 5 II. Purpose of Testimony. 6 Q. What is the purpose of your testimony? 7 A. The purpose of my testimony is twofold. The first is to explain the benefits of the merger 8 of EUA with New England Electric System ("NEES") for the customers, employees, and 9 shareholders of the EUA companies. The second is to describe how this merger meets 10 the standard of review for mergers and acquisitions established by the Department in 11 Mergers and Acquisitions, D.P.U. 93-167A, and in recent merger cases. 12 13 III. Terms, Conditions, and Structure of the Transaction. 14 Q. What is the corporate form of EUA? 15 A. EUA is a Massachusetts voluntary association and a registered holding company under 16 the Public Utility Holding Company Act of 1935 ("Holding Company Act"). EUA owns 17 the common equity of three electric companies, Eastern, Blackstone, and Newport. 18 Eastern owns the common equity of Montaup. EUA also owns the common equity of 19 EUASC, the entity that provides nearly all professional, technical, and scientific services 20 to EUA affiliates. EUA owns the common equity of non-regulated subsidiaries, New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 5 of 19 1 including EUA Cogenex Corporation, EUA Energy Investment Corporation, and EUA 2 Ocean State Corporation. 3 4 Q. Mr. Powderly, would you please summarize the transaction between EUA and NEES? 5 A. Under the merger agreement, EUA shareholders will receive $31.00 for each share held 6 when the acquisition becomes effective. The cash payment will be subject to an increase 7 of $0.003 per share per day if the merger is not completed on or before the date following 8 six months after approval of the merger by EUA's shareholders. The precise structure of 9 the transaction will be a merger between Research Drive LLC ("Research Drive"), a 10 Massachusetts limited liability company which is owned by NEES, and EUA. Research 11 Drive will merge with and into EUA, with EUA becoming a wholly-owned subsidiary of 12 NEES. The Agreement and Plan of Merger, dated February 1, 1999, (the "Agreement") 13 contains terms and conditions which are typical of a merger transaction. A condition of 14 closing the merger is obtaining approval of the shareholders of EUA. 15 16 Q. Will the merger affect the corporate structure of the EUA operating companies? 17 A. Yes. At closing, EUA will become a wholly-owned subsidiary of NEES. Thereafter, 18 NEES and EUA plan, as part of this transaction, to merge both the holding companies 19 and to consolidate the underlying operating and service companies. Thus, Eastern will 20 merge with Massachusetts Electric Company ("Mass. Electric"), Montaup with New New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 6 of 19 1 England Power Company, and Blackstone and Newport with Narragansett Electric 2 Company. Finally, EUASC and New England Power Service Company ("NEPSCO") 3 will also be consolidated to lower administrative costs. In each case, the surviving entity 4 will be the existing NEES company. 5 6 Q. Will the merger affect the Department's jurisdiction over the EUA operating companies? 7 A. No. At all times, the Department will have the same jurisdiction over the EUA 8 subsidiaries and their ultimate successors as it has now. 9 10 Q. Please explain the impetus for EUA to seek a merger. 11 A. EUA began to consider a combination strategy as soon as it became apparent that the 12 electric utility industry would be restructured and generation deregulated at both the 13 federal and state levels. An integral part of restructuring, supported by both the 14 Department in its generic investigation in D.P.U. 96-100 and the Legislatures of 15 Massachusetts and Rhode Island, was the divestiture by the incumbent utilities of their 16 generation portfolios. In the divested environment, EUA determined, as did other electric 17 utilities, that our skills and assets were best focused on the transmission and distribution 18 business. At the same time, it became evident that if our transmission and distribution 19 companies were to realize greater efficiencies, cost reductions, and attractive returns, 20 EUA would have to grow by orders of magnitude. Put another way, without the New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 7 of 19 1 generation business and with relatively small service territories, EUA lost important 2 economies of scale and scope. The reduced scale and scope of the organization after 3 divestiture would make it impossible to sustain the infrastructure necessary to maintain 4 same level of low-cost, high-quality service our customers have come to expect. Our 5 options would be to reallocate fixed costs over a significantly smaller, wires-only, sales 6 base or cut back on service. Maintaining or improving performance in providing 7 customer service, delivering safe, adequate, and reliable electricity at a low cost, and 8 fairly compensating our investors would not likely be the results of operating a small 9 wires-only business. Therefore, we concluded that the only acceptable affiliation must be 10 one that would produce these positive results for all our stakeholders. 11 Consolidation was clearly foreseen by the Department in Mergers and 12 Acquisitions, D.P.U. 93-197A, where the Department found that: 13 Changes in the structure of electricity and gas markets may alter 14 the efficient scale of operations for firms in these industries and 15 may cause a move toward consolidation in some instances. Order 16 at 5. 17 18 In an increasingly competitive market, mergers and acquisitions 19 may represent one of many measures that could achieve savings, 20 efficiencies, increased reliability and better quality of service for 21 Massachusetts utilities. Id. at 5. 22 23 Moreover, in Electric Industry Restructuring, D.P.U./D.T.E. 96-100, the Department 24 specifically incorporated this initial finding into its evaluation of restructuring proposals: New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 8 of 19 1 We reaffirm our policy, articulated in Mergers and Acquisitions, 2 D.P.U. 93-167, at 5, that we expect utilities to explore thoroughly 3 all cost-saving measures to achieve efficiencies, including mergers 4 and acquisitions, and we encourage all companies to consider 5 combinations that are consistent with our long range objectives of 6 fostering effective competition and driving down rates. Order at 7 82 8 9 Q. How did EUA identify potential business combination partners? 10 A. From late 1996 to early 1999, management and the Board continually evaluated the 11 various strategic options available to EUA as restructuring and the transition to 12 competition were taking place. Among the options considered were remaining a 13 relatively small, independent transmission and distribution company, growing the 14 company by acquiring other, smaller electric and/or gas companies within the region, 15 looking for a merger partner of similar size, and looking for a merger partner of larger 16 size. EUA retained its long-time advisor, Salomon Smith Barney, to assist us in our 17 review of alternatives and, if appropriate, to seek out potential merger or acquisition 18 partners. To meet financial and customer objectives, EUA would seek out a partner of a 19 size that would allow the resulting enterprise to achieve the economics of scale necessary 20 to increase efficiency and reduce costs. The most desirable partners would also have 21 characteristics such as being a low cost provider, a similar philosophy of system 22 operations, a strong customer service commitment, and a quality workforce. Discussions 23 with possible partners ensued. 24 New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 9 of 19 1 Q. When did EUA reach a conclusion on its future? 2 A. On January 31, 1999 and February 1, 1999, the EUA Board held a special meeting to 3 review and consider the proposals received. After presentations by legal and financial 4 advisors and a full discussion and analysis, the Board unanimously determined that it was 5 in the best interests of all EUA stakeholders to enter into a business combination with 6 NEES and that the terms of the merger were fair to and in the best interests of EUA 7 shareholders; it authorized, approved, and adopted the plan of merger and the transaction 8 described in the Agreement. EUA was advised that NEES obtained the consent of 9 National Grid to enter into the Agreement and on the morning of February 1, 1999, at the 10 conclusion of the EUA Board meeting and prior to the opening of the financial markets, 11 EUA and NEES executed and delivered the Agreement. 12 13 IV. Benefits to Customers, Employees and Shareholders. 14 Q. Would you summarize the benefits of the merger for EUA customers? 15 A. Eastern's customers will realize quantifiable benefits almost immediately as a result of 16 the rate plan proposed by Mass. Electric. Put simply, all of Eastern's customers will be 17 moved to Mass. Electric's lower rates on January 1, 2001. The movement to Mass. 18 Electric's rates will save Eastern's customers approximately $23 million in the first year 19 of rate consolidation, or 14.2 percent over the retail delivery service rates that would 20 otherwise be in effect (See Exhibit MEJ-3). Eastern's customers will further benefit from New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 10 of 19 1 the distribution rate freeze of up to four years proposed by Mass. Electric under the rate 2 plan. Mr Jesanis's Exhibit MEJ-4 demonstrates that, during the four year period, the 3 economic benefits to Eastern's customers are $81 million as compared to the retail 4 delivery service rates that Eastern would have otherwise charged. These economic 5 benefits to customers are compelling. Moreover, the proposed rate plan assures that 6 economic benefits will not come at the sacrifice of quality service. Following the 7 acquisition, both Mass. Electric and Eastern will continue their commitment to maintain 8 the same high standards of service and reliability that their customers have come to 9 expect. Our historic commitment to our communities and local charities will also be 10 maintained. Eastern's record of quality service at low rates will be enhanced by this 11 transaction and we will join in Mass. Electric's exemplary performance of delivering low 12 rates, reliability, and innovation to our customers. 13 In addition to the distribution rate freeze, the merger will produce ongoing savings 14 and efficiency gains. The merger savings after the cost to achieve are projected by Mr. 15 Hoffman, Mr. Jesanis, and Ms. Zschokke to total at least $35 million per year in the first 16 full year after the rate freeze. These savings will endure and, as Mr. Hoffman 17 demonstrates, increase with inflation. Finally, Mr. Jesanis testifies that the NEES merger 18 with National Grid promises additional resources, scale, and the ability to implement 19 further consolidations in the Northeast. The benefits of savings from such future 20 consolidations and efficiencies gains would inure to Eastern's customers as well. The New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 11 of 19 1 promise of savings from future consolidations, together with the distribution rate freeze 2 and the savings from this transaction, provide compelling economic benefits to Eastern's 3 customers. After the merger, Eastern's customers will receive service from a wires 4 company several times larger than their former distribution company with more financial 5 and operational resources to deal with emerging issues regarding customer service and 6 reliability. Eastern's customers will enjoy lower rates and the benefit of rate stability 7 without sacrificing performance and reliability. 8 9 Q. How will the merger affect Eastern's employees? 10 A. As with most mergers, including ours, the achievable benefits are determined in major 11 part by the number and productivity of the employees retained by the surviving entity; 12 some workforce reduction is inevitable. One of EUA's chief concerns in seeking a 13 combination has been that its employees be treated fairly after the merger, a concern 14 shared by the Department as well. Several factors peculiar to this merger lead to the 15 conclusion that our employees will be treated fairly. First, as I describe below, the 16 number of necessary employee reductions is small. Second, we anticipate that most of 17 the employee reductions can be accomplished through attrition and voluntary early 18 retirement incentives. Third, we are combining with an organization that is structured 19 and operates much like EUA. Fourth, NEES has made clear its intention to grow its 20 transmission and distribution business and has the financial backing to do so. This New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 12 of 19 1 growth provides opportunities for our employees they would not otherwise have. Fifth, 2 National Grid is looking for candidates for assignment elsewhere in its operations; these 3 international job opportunities could also be very attractive to our employees. And last, 4 but not least, NEES has committed to honor EUA's labor contracts. For our non-union 5 workforce, NEES has agreed that for 12 months following the closing date, 6 compensation, benefits, and coverage shall not be less favorable, in the aggregate, than 7 those provided, in the aggregate, immediately prior to the closing date. Our employees 8 have heard directly from Richard P. Sergel, NEES's Chief Executive Officer, that their 9 opportunities in the post-merger organization will not be limited because they came from 10 EUA. 11 EUA has been steadfastly committed to maximizing the effectiveness of its 12 workforce through a combination of training and motivating employees and optimizing 13 their numbers. Consistent with that objective, we have reduced our electric company and 14 EUASC populations from 1,343 at the end of 1990 to 946 at the end of 1998 (a 30 15 percent reduction), while improving the quality of service. Our stringent control of 16 personnel counts has positioned us in this merger so that we will be able to achieve 17 synergy savings and still treat our employees fairly. The pre-merger combined staffing is 18 about 4,100. Projected merger savings are based on a reduction from that figure of 19 approximately 250 employees, or about 6 percent of the combined total. We fully expect New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 13 of 19 1 to achieve these reductions almost entirely through attrition and voluntary early 2 retirement programs. 3 4 Q. Would you summarize the benefits of the merger for EUA shareholders? 5 A. The benefits to EUA shareholders are directly related to the consideration they will 6 receive for their shares at the closing of the merger. The base consideration of $31.00 per 7 share represents a 23 percent premium above the price of EUA shares on December 4, 8 1998, the last trading day before other regional merger announcements caused the price 9 of its shares to increase significantly, and a 5 percent premium above the closing price on 10 January 29, 1999. As explained earlier, the purchase price is subject to an upward 11 adjustment related to the timing of the closing, and will be paid in cash. EUA's Board 12 received an opinion from Salomon Smith Barney that the consideration being paid to our 13 common stockholders is fair. We will request shareholder approval at our annual meeting 14 this spring. 15 16 V. Compliance with the Department's Merger and Acquisition Standards. 17 Q. Please address each factor the Department will use to determine whether the acquisition 18 is "consistent with the public interest." 19 A. At the outset, I would note that although the Department has cautioned that the list of 20 factors set forth in Mergers and Acquisitions is not exhaustive, these factors have been New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 14 of 19 1 used when evaluating the merits of other merger cases. In the instant case, I will also rely 2 upon them to demonstrate the public interest benefits of this transaction as it relates to 3 this transaction. 4 1. Effect on Rates. The merger will provide compelling rate benefits for 5 Eastern's customers. The proposed rate plan for consolidating Eastern and Mass. 6 Electric rates and freezing the distribution rates thereafter is summarized by Mr. 7 Jesanis. The economic benefits of the plan are detailed by Ms. Burns. The effect 8 of this plan on Eastern's customers will be a $23 million, 14.2 percent reduction 9 in retail delivery service billings in the first year after the consolidation of rates, 10 assuming a January 1, 2001 effective date. Eastern's rates are already among the 11 lowest in Massachusetts. A rate reduction and a distribution rate freeze promote 12 the economic well being of customers in our service territory. Furthermore, with the 13 cost savings described by Mr. Hoffman, we have the foundation for keeping 14 rates low through lower costs in the future. 15 2. Quality of Service. Both Eastern and Mass. Electric are now operating 16 under performance standards established in their Restructuring Settlement 17 Agreements, which were approved by the Department in D.P.U./D.T.E. 96-24 and 18 96-25, respectively. These standards are discussed in the testimony of Mr. Reilly. 19 As Mr. Reilly explains, the standards will be consolidated and updated for the 20 combined companies. As the Department found in D.P.U/D.T.E 96-24 and 96-25, New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 15 of 19 1 these standards provide the required assurance that Eastern and Mass. Electric will 2 maintain their historic levels of reliability and customer service. Pursuant to the 3 Settlements, these standards are in effect until 2001 and may be revised by the 4 Department if it adopts more stringent standards applicable to the other 5 distribution companies operating in the Commonwealth. These performance 6 standards meet the Department' requirements for a Service Quality Standards 7 under its merger policy. D.T.E. 98-31 at 31, inter alia. 8 3. Resulting Net Savings. The savings from consolidation, economies of 9 scale and other efficiency gains as a result of the merger support the proposed rate 10 plan for the customers of the regulated transmission and distribution businesses of 11 EUA and NEES subsidiaries. In their testimony, David J. Hoffman and Richard 12 J. Levin project net savings that, when added to further savings projected by Mr. 13 Jesanis, total $35 million in the first year after the rate freeze and grow higher 14 over time. The savings exceed the requirements associated with the amortization 15 of the acquisition premium and the transaction costs and will produce benefits to 16 Eastern's customers. 17 4. Effect on Competition. Both Eastern and Mass. Electric provide only 18 regulated retail delivery services for which there is no relevant competition. Thus, 19 there can be no competitive impact or harm from the merger to the wires business 20 in our respective service territories. With regard to competitive generation New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 16 of 19 1 services, EUA and NEES have disposed of nearly all of their generation and thus 2 the merger does not significantly affect competition. I do envision, however, that 3 the proposed merger is likely to enhance the development of competition for 4 customers of both Eastern and Mass. Electric. Competitive suppliers will have 5 the opportunity to serve a larger base of customers under a single set of terms and 6 conditions and under a single load settlement process. This consolidation will 7 reduce the administrative and transaction costs for competitive suppliers and 8 reduced costs can be expected to result in both lower barriers to entry for 9 competitive suppliers and ultimately lower costs to customers. 10 5. Cost Allocation Issues. As part of the consolidation of the NEES and 11 EUA subsidiaries, EUASC will be merged into NEPSCO. The service company 12 allocations will continue to be subject to review by the Department in Mass. 13 Electric's rate cases. Cost allocations for the other NEES companies will 14 continue to be subject to the SEC's requirements under the Holding Company 15 Act, and the standards of conduct promulgated by the Department, other state 16 commissions, and FERC. These regulatory controls assure that costs will be 17 allocated appropriately among subsidiaries. 18 Mr. Jesanis has testified regarding allocation of the acquisition costs and 19 merger savings to the regulated EUA companies. As he explains, under the 20 proposed rate plan, EUA customers realize immediate and substantial savings in New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 17 of 19 1 their rates. Moreover, following the distribution rate freeze period, the remaining 2 costs of the NEES-EUA merger will be entirely offset by savings produced as a 3 result of the merger. This proposal provides a fair distribution of these benefits 4 between customers and shareholders while encouraging and supporting further 5 consolidations in accordance with the Department's policy. 6 6. Financial Integrity of the Post-Merger Entity. Ms. Zschokke's testimony 7 demonstrates that the merger of EUA and NEES will enhance the financial 8 resources and access to financial markets of the combined entity, and reduce the 9 financing costs of Eastern. The post-merger entity, at the holding company level, 10 will continue to be regulated by the SEC as a registered holding company under 11 the Holding Company Act. The financings of the Massachusetts electric 12 companies will continue to be supervised and regulated by the Department. This 13 level of regulatory oversight will not diminish for the merged companies. 14 7. Societal Costs-Employment. Earlier in my testimony, I discussed 15 generally employee benefits and how the merger will provide EUA employees 16 with significant new opportunities. As a result of long-standing programs of cost 17 control and efficiency enhancements, we anticipate achieving almost all of the 18 required personnel reductions though attrition and voluntary early retirement 19 programs with minimal impact on individual employees. Overall, this merger 20 will provide the region with financially strong, technically sophisticated New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 18 of 19 1 transmission and distribution companies, lower rates, and an ongoing 2 commitment to customer service. 3 8. Economic Development. Low rates and good customer service promote 4 economic development, business growth, and enhance job markets in 5 Massachusetts. As I have shown above, the combination of EUA and NEES will 6 produce low rates and quality service. Under the proposed rate plan, customers of 7 Eastern will see their retail delivery service rates reduced by approximately $23 8 million, or 14.2 percent, one year after completion of the merger, with the 9 distribution component frozen thereafter. In the longer term after the rate freeze, 10 the synergies between the companies will produce annual net savings of $35 11 million per year. These economic benefits will make our region more 12 competitive. In addition, we will be participating in economic development 13 activities in the larger Mass. Electric franchise area, creating additional 14 opportunities for our communities to attract jobs. Finally, the merger with NEES 15 and National Grid will allow us to be a center of activity for National Grid's 16 activity in the Northeast providing growth in our own operations. 17 9. Alternatives to Mergers or Acquisitions. I am not aware of alternatives to 18 this merger that would produce benefits comparable to those described in this 19 application. As a stand-alone entity, EUA would either have to reduce drastically 20 its cost of doing business or increase rates to compensate for the loss of its New England Electric System Eastern Utilities Associates Testimony of R. G. Powderly Page 19 of 19 1 generation business. The required cost reductions would have to come by way of 2 reducing services or reliability to inadequate levels. Equally unacceptable as an 3 alternative is an EUA expansion of its unregulated ventures as a means of 4 increasing financial resources and economies of scale. This course of action 5 would significantly increase EUA's risk profile and, ultimately, its equity capital 6 would come at a higher price. Finally, other potential merger partners for EUA do 7 not have contiguous service territories and low distribution rates and EUA- 8 reliability and EUA-customer satisfaction levels and similarity of operations and 9 low costs. Our partner, NEES, does. EUA's affiliation with NEES makes the 10 most sense -- for our customers, for our employees, and for our shareholders. 11 12 VI. Conclusion. 13 Q. Does the proposed transaction between NEES and EUA satisfy the Department's criteria 14 for merger and acquisition? 15 A. Yes. Measured by the Department's standards, this merger is consistent with the public 16 interest and should be approved as filed. 17 18 Q. Does this complete your testimony? 19 A. Yes.
COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF LAWRENCE J. REILLY COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF LAWRENCE J. REILLY Table of Contents Page I. Qualifications....................................................... 1 II. Purpose of Testimony................................................. 4 III. Organization of NEES Distribution Companies.......................... 4 IV. Service Benefits from the Merger..................................... 7 V. Service Quality Performance Standards................................10 A. Introduction................................................10 B. Proposed Service Quality Performance Standards..............11 1. Reliability Performance Standard...................13 2. Customer Service Performance Standard..............15 3. Line Loss Standard.................................16 C. Implementation..............................................17 VI. Development of the Competitive Power Supply Market...................18
New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 1 of 21 1 I. Qualifications. 2 Q. Please state your name and business address. 3 A. My name is Lawrence J. Reilly. I have two business addresses: 55 Bearfoot Road, 4 Northborough, Massachusetts 05132; and 280 Melrose Street, Providence, Rhode Island 5 02907. 6 7 Q. By whom are you employed and in what position? 8 A. I am employed by New England Power Service Company ("NEPSCO"). I am President 9 and Chief Executive Officer of New England Electric System's ("NEES's") electricity 10 distribution subsidiaries: Massachusetts Electric Company and Nantucket Electric 11 Company (together "Mass. Electric" or the "Company"); The Narragansett Electric 12 Company ("Narragansett Electric"); and Granite State Electric Company ("Granite State 13 Electric"). I am also a Director of each of these companies. 14 15 Q. Please describe your educational background and training. 16 A. In 1978, I received a Bachelor of Arts degree magna cum laude from the State University 17 of New York at Albany. In 1982, I received the degree of Master in City and Regional 18 Planning from the John F. Kennedy School of Government at Harvard University where I 19 specialized in Energy and Environmental Policy. Also in 1982, I received a Juris Doctor 20 degree cum laude from Boston University School of Law. New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 2 of 21 1 Q. Please describe your professional experience. 2 A. I joined NEPSCO as an Attorney in the Corporate Legal Department in 1982. In that 3 capacity I advised various NEES companies in the areas of finance and securities law as 4 well as in the areas of environmental licensing and permitting. In 1987, I became legal 5 counsel to, and Secretary of, Narragansett Electric, in Providence, Rhode Island. In that 6 capacity my responsibilities included advising Narragansett Electric on a variety of 7 regulatory and rate matters as well as permitting for the Manchester Street Station 8 Repowering Project. In July 1990, I became Director of Rates for NEPSCO with 9 responsibility for wholesale and retail rate matters for all of the NEES companies. In 10 1993, I was elected a Vice President and assumed additional responsibility for retail 11 revenue requirements. Effective June 1, 1996, I became President of Mass. Electric. I 12 became President of Granite State Electric and Narragansett Electric in January, 1997, 13 and October, 1997, respectively. In my capacity as Vice President and Director of Rates 14 and as President and CEO of the NEES electricity distribution companies I have been 15 actively involved with electric industry restructuring matters. My current areas of 16 responsibility for the NEES electricity distribution companies include transmission and 17 distribution system operations, customer service, and business service functions. 18 New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 3 of 21 1 Q. Do you serve on the boards of any other organizations? 2 A. Yes. I am a Director of the Massachusetts Technology Park Corporation, the quasi- 3 public entity responsible for, among other things, administering the renewable energy 4 trust fund established by the 1997 Massachusetts electric restructuring law. I also 5 currently serve as Chairman of the Massachusetts Alliance for Economic Development, a 6 privately funded non-profit organization dedicated to promoting economic growth in 7 Massachusetts. I am also on the Board of Grow Smart Rhode Island, a non-profit 8 organization focused on the interaction of economic growth, environment, and land use 9 issues. In addition, I serve on the Boards of the United Way of Central Massachusetts, 10 the United Way of Southeastern New England, the Foundation for Ocean State Public 11 Radio, the Worcester State Foundation, and as a Corporator of the Worcester Art 12 Museum. 13 14 Q. Have you previously testified before any regulatory commission? 15 A. Yes, I have previously testified before the Department of Telecommunications and 16 Energy ("Department"), the Rhode Island Public Utilities Commission, the New 17 Hampshire Public Utilities Commission, and the Federal Energy Regulatory 18 Commission. 19 New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 4 of 21 1 II. Purpose of Testimony. 2 Q. What is the purpose of your testimony? 3 A. The purpose of my testimony is four-fold. First, I will describe how the NEES 4 distribution companies are organized today to provide quality service to customers. 5 Second, I will describe the integration process that is underway with Eastern Utilities 6 Associates ("EUA") and the anticipated benefits for customers. Third, as required by the 7 Department, I will propose a specific set of service quality performance standards to be 8 put in place prospectively to ensure that the high quality service customers currently 9 enjoy will continue after the merger. Finally, I will outline a program that is currently 10 under development to foster a robust power supply market where customers can fully 11 realize the economic benefits of competition in the restructured industry. 12 13 III. Organization of NEES Distribution Companies. 14 Q. Mr. Reilly, will you please describe how the NEES distribution companies are organized 15 to provide service to customers. 16 A. The NEES distribution companies currently provide service to almost 1.4 million 17 customers in 209 cities and towns in Massachusetts, Rhode Island, and New Hampshire. 18 The breakdown of customers by distribution company is detailed on Exhibit LJR-1. 19 Although each of the distribution companies is a separate legal entity, to the extent 20 possible we operate them as an integrated organization. This allows us to operate more New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 5 of 21 1 efficiently and provide better service to customers than if each company were managed 2 independently. For example, this method of operation allows us to implement best 3 practices uniformly across the system and provides us flexibility in terms of assigning 4 crews where needed most in response to major storms. Through this integrated 5 management we are able to achieve the efficiency gains that have historically been 6 available through the sharing of administrative functions such as accounting and legal 7 services through NEPSCO. 8 Because the three state service area of the combined organization covers almost 9 5000 square miles, we divide the territory up into six operating districts and a number of 10 operating satellites that are run from each district. Exhibit LJR-2 is a map showing the 11 current district boundaries within the service territory and the location of key facilities. 12 For the most part, each operating district includes a functional head for operations, 13 customer service, and business services. These individuals are responsible for service 14 performance and program implementation throughout their respective districts. In 15 general, where there is a need to be close to the customers (because of travel time or 16 because detailed knowledge of the local conditions is required), individuals work out of 17 the local district offices or satellite locations; where frequent local contact is not critical, 18 individuals tend to work in the central locations, principally, Northborough, 19 Westborough, and Providence. The degree to which each operating district is supported 20 centrally varies from function to function. New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 6 of 21 1 Q. Please explain the split between district and central functions in the Operations area. 2 A. In Operations, the physical workers (linemen, underground workers, substation 3 maintenance workers) are assigned to a district or satellite location. Certain engineering 4 functions are performed locally while other engineering functions such as substation 5 design and standards are performed centrally. Operating functions handled centrally for 6 all system companies include: training; material supply; relay & telecommunications; 7 transmission line engineering; engineering laboratory; construction; environment; safety; 8 and property assets. In some cases there are individuals assigned to local district offices 9 to implement programs and polices that are administered centrally. Safety, 10 environmental management, and vegetation management are examples of areas that fall 11 into this category. 12 13 Q. How is responsibility divided between the field and central office in the customer service 14 area? 15 A. Meter reading is the clearest example of a function where it is most efficient to have the 16 workers located near the customers. The meter operations group, which is responsible for 17 installing, maintaining, exchanging, and testing meters, is also decentralized; however, 18 field personnel receive central support from the Meter Operations and Engineering Group 19 in Worcester. Supplier services along with load research and load estimation, which have 20 become increasingly important in the restructured environment, are located centrally in New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 7 of 21 1 Northborough. Customer calls are handled in call centers located in Northborough and 2 Providence that are linked through telecommunications equipment which automatically 3 transfers calls between these two centers to minimize wait times for customers. This 4 arrangement also provides us access to two job markets for customer service 5 representatives and diversity of locations in the event of bad weather or a disaster at either 6 location. 7 8 Q. How is the Business Service function organized? 9 A. Each district office has a local Business Services Vice President and a staff of account 10 managers. The account managers handle service requests for our largest customers (200 11 kilowatts or greater demand per month) and are actively involved in the marketing of our 12 various Demand Side Management ("DSM") programs. DSM programs for residential 13 and small commercial and industrial customers are handled centrally from Northborough. 14 Special programs and new initiatives are also developed in Northborough and 15 implemented in close coordination with Business Services personnel in the field. 16 17 IV. Service Benefits from the Merger. 18 Q. Do you believe that the merger will create service benefits for the customers of both 19 companies? New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 8 of 21 1 A. Yes. Several factors lead us to conclude that the merger will improve service to 2 customers. First is geographic proximity. A map showing the relationship between the 3 NEES and EUA distribution companies is included as Exhibit LJR-3. As shown, the 4 service territories of these two companies are in very close proximity. It is this 5 geographic proximity that makes this merger so attractive from an operating perspective. 6 This merger goes a long way to rationalizing the service territories of the distribution 7 companies in southeastern New England and, with the integration of NEES and EUA 8 field and central functions, should enable us to provide comparable or better service at a 9 lower cost. Second, there is a long history of good working relationships between our 10 companies, including a history where a number of employees have moved between the 11 companies over time. Third, perhaps related to the first two items mentioned above, there 12 appears to be a very similar culture between the two companies -- one where quality 13 customer service and cost control are widely recognized objectives. In my opinion, all 14 three of these factors will facilitate a successful integration of the businesses. 15 16 Q. Are the companies also addressing service quality issues in the integration process for the 17 merger? 18 A. Yes. The proper integration of the companies is central to the effectiveness and 19 efficiency of our operations and the quality of our service following the merger. I am a 20 member of the integration steering committee that is responsible for the successful New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 9 of 21 1 integration of the companies. Our progress during the integration process has been 2 substantial. We have already found several ways to improve service and efficiency that 3 we will build upon as we complete the integration progress and following the merger. 4 The transition teams cover ten different disciplines and approximately sixty subgroups 5 have been established as part of the effort to focus on specific areas. The teams and the 6 areas they are responsible for are outlined on Exhibit LJR-4. 7 8 Q. What benefits of the merger have you identified to date? 9 A. Although it is still early in the process, it is apparent that several key benefits will flow 10 from the eventual consolidation of Eastern Edison Company ("Eastern") into Mass. 11 Electric. Specifically: 12 o The larger company will have more resources to draw upon in the event of storms 13 or natural disasters; 14 o Customer service costs and other costs associated with administering separate 15 rates and maintaining separate companies will be reduced; 16 o Eastern's customers will be provided 24 hour per day access to customer service 17 representatives for routine billing and payment inquires (currently such access is 18 limited to 7 a.m. to 9 p.m. Monday through Saturday); New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 10 of 21 1 o The consolidation of Mass. Electric and Eastern will produce administrative 2 savings for the Department by reducing the number of regulated companies and 3 associated reporting requirements; 4 o The customers of Mass. Electric and Eastern will benefit from the rate plan 5 proposed as part of this filing; and 6 o The consolidation of Mass. Electric and Eastern will help in the development of 7 the competitive power supply market. This benefit and other actions we are 8 planning to take to help facilitate development of that market are discussed in 9 Section VI of my testimony below. 10 11 V. Service Quality Performance Standards. 12 A. Introduction. 13 Q. Please describe the Mass. Electric's Service Quality Performance Standards proposal. 14 A. After the merger, the Company is proposing a single set of Service Quality Performance 15 Standards that is consistent with the Performance Standards adopted pursuant to 16 Restructuring Settlements approved in D.P.U./D.T.E. 96-24 (Eastern) and 96-25 (Mass. 17 Electric). Mass. Electric's currently effective standards for reliability and customer 18 service are attached as Exhibit LJR-5. Eastern's currently effective standards, which are 19 generally consistent with Mass. Electric's, are attached as Exhibit LJR-6. The 20 benchmarks for both companies under each performance standard are based on averages New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 11 of 21 1 of historic performance, plus one standard deviation. Each standard carries a maximum 2 penalty of $1,000,000 for Mass. Electric and $250,000 for Eastern. 3 4 B. Proposed Service Quality Performance Standards. 5 Q. Please summarize the Company's proposed Service Quality Performance Standards. 6 A. The Company's proposed Service Quality Performance Standards represent a 7 continuation of the present, Department-approved performance standards for Mass. 8 Electric and Eastern, with the addition of three important changes. First, the benchmarks 9 for the proposed standards are based on the average of the combined historic data for 10 Mass. Electric and Eastern. Second, the historic data used for the benchmarks has been 11 updated to reflect a more recent time period than that used in the original standards. 12 Finally, the Company is proposing a maximum penalty under the standards of 13 $2,500,000. All other characteristics of the proposed standards are consistent with the 14 standards approved in D.P.U./D.T.E. 96-24 and 96-25. The proposed performance 15 standards marked to show changes are included in Exhibit LJR-7. A clean version is 16 included in Exhibit LJR-8 17 18 Q. Please describe the development of the benchmarks for the proposed standards. 19 A. Mass. Electric and Eastern compiled their historic data under each of the areas covered by 20 the standards and found that the data were generally comparable and consistent. For New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 12 of 21 1 example, both companies use similar definitions for service outages and conduct similar 2 customer satisfaction surveys. The comparability and consistency of the data allowed the 3 companies to create a composite benchmark for each standard using data from Mass. 4 Electric and Eastern. 5 6 Q. Please describe the time period covered by the historic data used to develop the 7 benchmarks. 8 A. After reviewing their historical records, we determined that data from more recent years 9 was generally more comparable and consistent than data from earlier periods. 10 Accordingly, we have limited the time period for data used in the development of the 11 benchmarks to no earlier than 1991. Thus, to set the benchmarks for the reliability and 12 customer service standards after the merger, Mass. Electric has used the average of 13 historic data for 1991 through 1998, plus one standard deviation. 14 15 Q. Does this updating cause the benchmarks to be more stringent? 16 A. Yes, it does. 17 18 Q. Please describe the maximum penalty under the proposed standards. New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 13 of 21 1 A. The maximum penalty under both standards totals $2,500,000. This amount represents 2 the sum of the maximum penalties under the present standards for Mass. Electric and 3 Eastern. 4 5 Q. How does the proposal weight the two areas covered by the standards? 6 A. The total maximum penalty is split evenly between the two standards. Thus, each 7 standard has a maximum penalty of $1,250,000. The proposed standards preserve the 8 50/50 split in the present standards approved by the Department. 9 10 Q. How were the proposed penalty schedules under the standards developed? 11 A. The schedule of penalties under the proposed standards is designed in the same manner as 12 the schedules under the existing standards. The rationale behind the schedules is to 13 ensure that significant deviations from historic levels result in penalties under the 14 standards. 15 16 1. Reliability Performance Standard 17 Q. Please describe the proposed Reliability Service Quality Performance Standard. 18 A. As in the standard under the Restructuring Settlements, reliability of service is measured 19 by the duration of outages. The standard defines a customer interruption as the loss of 20 electric service to more than one customer for more than one minute. The duration of New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 14 of 21 1 outages per customer served is the total length of time in minutes that an average 2 customer is without service per year, as measured by the System Average Interruption 3 Duration Index (SAIDI). 4 5 Q. Please describe the development of the Duration of Outages Performance Standard. 6 A. Combining Mass. Electric's and Eastern's data for 1991 through 1998 results in an 7 average duration of outages (plus one standard deviation) of 96 minutes. Based on this 8 data, the companies are proposing a benchmark duration of outages of 96 minutes. 9 Exhibit LJR-9 provides the derivation of the duration of outages standard and its schedule 10 of penalties, with a maximum penalty of $1,250,000. 11 12 Q. Are any events excluded from reliability measurements? 13 A. Yes. Excluded from the companies' historic reliability measurements are severe weather 14 events, under-frequency load shedding events, and other extraordinary circumstances. 15 Severe weather events are defined as those resulting in the interruption of 10 percent or 16 more of the customers in a district at any given time during the storm. We are proposing 17 to use the same criteria for exclusion as under the present standards. The criteria for 18 exclusion of an event from reliability measurements is included in Exhibit LJR-8. 19 New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 15 of 21 1 2. Customer Service Performance Standard. 2 Q. Please describe the proposed Customer Service Performance Standard. 3 A. As in the existing standard under the Restructuring Settlements, we are proposing a 4 Customer Service standard based on overall residential customer satisfaction. The 5 standard has a maximum penalty of $1,250,000, or half of the total maximum penalty. 6 7 Q. How is customer satisfaction measured? 8 A. Mass. Electric and Eastern have historically commissioned an independent third party to 9 conduct a survey of customers to determine their overall level of satisfaction with the 10 companies. Comparable data for this survey is available from 1991. 11 12 Q. How have the surveys been conducted? 13 A. An independent market research firm conducts interviews with a representative sample of 14 customers. Several questions are asked as part of this interview, most of which change 15 annually. However, for the past several years, a consistent question has been asked 16 regarding customer satisfaction. For Mass. Electric, the question has been: "All things 17 considered, how would you rate Mass. Electric's service to you?" For Eastern, the 18 question has been: "I would like to know how you rate your electric company overall." 19 Respondents to both companies' surveys are asked to rate their service on a scale of 1 to 20 7, where 1 means poor and 7 means excellent. The responses in the top three categories New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 16 of 21 1 of satisfaction (i.e. 5, 6, and 7) are tabulated in Exhibit LJR-10 and form the basis for 2 developing the Customer Service Performance Standard. 3 4 Q. How is the proposed Customer Service Performance Standard established? 5 A. We are proposing a Customer Satisfaction Performance Standard based on the historical 6 results of the Mass. Electric's and Eastern's residential customer satisfaction surveys. 7 Using the average and standard deviation of data for 1991 through 1998, the proposed 8 Customer Service Performance Standard is 86 percent of responses in the top three 9 categories of customer satisfaction. Consistent with the existing performance standards, 10 we are proposing a sliding scale for penalties. Exhibit LJR-10 provides the calculation 11 and the schedule of penalties under this standard. 12 13 3. Line Loss Standard 14 Q. Is Mass. Electric proposing a line loss standard in this proceeding? 15 A. Not at this time. The Restructuring Settlements also required Mass. Electric and Eastern 16 to "propose ... a performance standard for the effective management of line losses." Both 17 Mass. Electric and Eastern filed such proposals with the Department. The Department, 18 however, has not ruled on these proposed standards and they have not been implemented. 19 In addition, both proposals were based on FERC Form 1 Sources and Disposition of 20 Energy data which is no longer available in a meaningful manner. For these two reasons, New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 17 of 21 1 we have not included a distribution line losses standard in our proposal. Rather, we are 2 reviewing the line loss issue and data as part of the integration team process discussed 3 more fully above and, if feasible, will design an alternative to the line loss standard 4 that has already been developed that will reflect current data and provide a meaningful 5 incentive. 6 7 C. Implementation 8 Q. When will the proposed standards become effective? 9 A. We propose to have the proposed standards be effective for consolidated Mass. Electric 10 beginning on the effective date of the rate plan or January 1, 2001 (the "Consolidation 11 Date"). Before that date the current standards would remain in effect. 12 13 Q. How will rate adjustments be implemented pursuant to the Performance Standards? 14 A. Mass. Electric would file a Performance Standards Report with the Department by May 15 1, 2002 and every year thereafter. In these filings, Mass. Electric would provide the 16 following: 17 (1) a determination of the Mass. Electric's performance against each of the 18 Performance Standards based on actual data for the 12 months ending December 19 31 of the previous year; New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 18 of 21 1 (2) a determination of the total penalty payment, if any, required under the plan by 2 summing the results of the Performance Standards; and 3 (3) a schedule showing the development of a per kilowatthour factor to credit 4 customers with any penalty payment required under the Performance Standards. 5 This factor would take effect at the time of Mass. Electric's next annual rate 6 adjustment and reflected over the following year. 7 8 VI. Development of the Competitive Power Supply Market. 9 Q. Earlier in your testimony you stated that you expected the consolidation of Mass. Electric 10 and Eastern to help in the development of the competitive power supply market. Please 11 explain why you believe this is to be the case. 12 A. Although it is certainly not the only barrier to development of a competitive market, the 13 multitude of distribution companies within the Commonwealth of Massachusetts has no 14 doubt retarded the growth of the competitive market in a number of ways. First, differing 15 distribution rates and availability clauses for providing distribution service complicate the 16 terrain for power suppliers considering entry into the market. Second, the patchwork 17 nature of the existing service territories complicates marketing efforts. Third, differing 18 electronic data interchange formats and testing requirements add to administrative 19 overheads for suppliers. The consolidation of Mass. Electric's and Eastern's rates for 20 delivery service, the contiguous nature of the expanded service territory, and one less New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 19 of 21 1 point of contact for suppliers entering the market here should all help to reduce barriers to 2 entry into the competitive supply market. 3 4 Q. Why is reducing barriers to entry for suppliers entering the competitive market 5 important? 6 A. Prior to restructuring, the generation or supply component of customer bills accounted for 7 roughly two-thirds of the total cost of electricity. The significant potential for savings in 8 that portion of the bill was one of the factors that led to restructuring. Nothing has 9 changed in this area. Power supply costs are still the area where customers stand to save 10 the most money on their bills. Without regulation, however, there must be an efficient 11 and vigorous market for electricity supplies for customers to realize the full benefits of 12 competition. 13 14 Q. In your opinion what other barriers exist to the development of a robust competitive 15 power supply market? 16 A. Lack of information is certainly a problem on several levels. Not all customers are aware 17 of their options or have ready access to billing data needed to minimize supply costs. 18 Power marketers may also lack information about potential customers that could benefit 19 from their products. 20 New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 20 of 21 1 Q. What actions are you planning to take to reduce these barriers? 2 A. We have a number of initiatives under way to inform customers of their options in the 3 power supply market. We currently offer "Power Talk", a speakers bureau program for 4 customer groups of all kinds. We have implemented a comprehensive education program 5 that includes bill inserts, participation in state-wide education efforts with the Division of 6 Energy Resources ("DOER"), and participation in trade shows and shopping mall 7 displays. We are including information in "PowerLink", a newsletter for our business 8 customers, and are hosting breakfast meetings for our largest customers to highlight 9 opportunities available in the market. Under our "Power Connection" program, with a 10 customer's consent, we will provide billing data to all registered suppliers in electronic 11 format so that prospective suppliers can develop offers suited to the individual customers. 12 We are also distributing a software product called "Energy Smart" to our customers that 13 provides educational information to customers and is expected to eventually aid 14 customers who wish to shop for power supplies on-line. 15 We have also developed a series of optional metering services that are available to 16 any customer that wants detailed interval or real time demand and energy use data. To 17 assist power marketers in getting access to prospective customers, we intend to offer a 18 mailing service to all power marketers whereby we would mail their marketing 19 information to customer segments they determine without disclosing any customer data to 20 the power marketer. New England Electric System Eastern Utilities Associates Testimony of L. J. Reilly Page 21 of 21 1 Q. How will the merger improve this effort? 2 A. As part of the integration process, we will continue to look for ways to improve our 3 outreach and education programs and make them more effective. The merger will assure 4 that the finally implemented programs will reach more customers, more efficiently. The 5 consolidation of Mass. Electric and Eastern will also facilitate marketers' efforts to reach 6 our customers with ideas and products that will provide our customers with more value at 7 lower prices. 8 9 Q. Does this conclude your testimony. 10 A. Yes.
EXHIBITS OF L. J. REILLY LJR-1 Customers Served by NEES Distribution Company LJR-2 Current Map of NEES Service Territory LJR-3 Map of Combined NEES-EUA Service Territory LJR-4 Integration Teams and Responsibilities LJR-5 Mass. Electric's Present Performance Standards LJR-6 Eastern's Present Performance Standards LJR-7 Proposed Performance Standards After Consolidation Date (Marked to Show Changes) LJR-8 Proposed Performance Standards After Consolidation Date LJR-9 Derivation of Duration of Outage Standard LJR-10 Calculation of Customer Satisfaction Measure New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit LJR-1 Exhibit LJR-1 Customers Served by NEES Distribution Company S:\RADATA1\EASTED\Ljr-1.wk4 Narragansett Electric PAGE 1 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-_____ Exhibit LJR-1 Page 1 of 1 New England Electric System Number of Customers per Distribution Company Number of Customers --------- Massachusetts: Massachusetts Electric Company 983,191 Nantucket Electric Company 10,169 ------ Total Massachusetts 993,360 Rhode Island: Narragansett Electric Company 336,029 New Hampshire: Granite State Electric Company 37,114 ------ 3 State Total 1,366,503 ========= New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit LJR-2 Exhibit LJR-2 Current Map of NEES Service Territory Exhibit LJR-2 Map of Existing NEES Service Territory Two Maps First Map: Reflects service territories, headquarters, customer service and operations centers and operating satellites for Granite State, Mass. Electric, Nantucket and Narragansett in Rhode Island, Massachusetts and New Hampshire. Second Map: Reflects Narragansett service territory, headquarters and operating satellites in Rhode Island.
Granite State Electric Massachusetts Electric Company Company Lebanon Western Merrimack Valley Acworth Adams Mount Washington Amesbury Alstead Alford New Marlboro Andover Bath Athol New Salem Billerica Canaan Barre North Adams Boxford Charlestown Belchertown Northampton Chelmsford Cornish Brimfield Orange Dracut Enfield Charlemont Palmer Haverhill Grafton Cheshire Petersham Lawrence Hanover Clarksburg Phillipston Lowell Lnagdon East Longmeadow Rowe Methuen Lebanon Erving Royalton Newbury Marlow Florida Sheffield Newburyport Monroe Goshen Shutesbury North Andover Orange Granby South Egremont Salisbury Plainfield Great Barrington Stockbridge Tewksbury Surry Hampden Templeton Tyngsboro Walpole Hancock Wales West Newbury Hardwick Ware Westford Hawley Warren Salem Heath Warwick North Shore Derry Holland Wendell Beverly Pelham Lenox West Stockbridge Essex Salem Monroe Wilbraham Everett Windham Monson Williamsburg Gloucester Monterey Williamstown Hamilton Lynn Narrangansett Electric Malden Company Central Manchester Auburn New Braintree Medford Southern Ayer North Brookfield Melrose Charlestown Berlin Oakham Nahant Coventry Bolton Oxford Revere East Greenwich Brookfield Paxton Rockport Exeter Charlton Pepperell Salem Hopkinton Clinton Rutland Saugus Narragansett Dudley Shirley Swampscott North Kingstown Dunstable Southbridge Topsfield Richmond East Brookfield Spencer Wenham South Kingstown Gardner Sturbridge Winthrop Warwick Grafton Sutton West Greenwich Harvard Webster West Warwick Hubbardston West Brookfield Westerly Lancaster West Groton Leicester Westminster Providence Leominster Winchendon Barrington Millbury Worcester Bristol Cranston Southeast East Providence Attleboro Northborough Foster Bellingham Northbridge Glocester Blackstone Norton Johnston Douglas Plainville Little Compton Foxborough Quincy North Providence Franklin Randolph Providence Hingham Rehoboth Scituate Holbrook Seekonk Smithfield Hopedale Southborough Tiverton Marlborough Upton Warren Mendon Uxbridge Milford Westborough Milville Weymouth Nantucket Wrentham
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit LJR-2 Exhibit LJR-3 Map of Combined NEES-EUA Service Territory Exhibit LJR-3 [Map of Combined NEES-EUA Service Territory]
S:\RADATA1\EASTED\Ljr-4.wk4 New England Electric System TEAMS Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-___ Exhibit LJR-4 Page 1 of 1 EUA/ NEES TRANSITION TEAMS - ------------------------------------------------------------------------------------------------------------------------------ General Business Areas - ------------------------------------------------------------------------------------------------------------------------------ HR & Supply Retail Information Power Rate/Rev Accou- Communi- Consul- Chain Companies Systems Company Treasury Req nting cations Legal Other tants - ------------------------------------------------------------------------------------------------------------------------------ R Compen- EO- Retail Trans- Finance Revenue General External Legal Audit A&G Best sation Central Appli- mission Require- Accounting and Employee Practices & Benefits Operations cations Marketing ment and Communi- Rates cations HR-Labor EO-Central Corporate Trans- Risk Plant Corpo- Plan- Early Engineering Applic- mission Manage- Accounting rate ning, Decisions ations Planning ment Gover- Bud- Support nance gets, and Re- porting Facil- ities HR-Culture EO-Field Divesti- Investor Service Revenue Organization Integration Operations Operations tures Relations Contracts Accounting Planning HR-Employee EO-Dispatch- Technology Nuclear Property Payroll Team Relations ing Services Issues Tax Support Asset SCM- CS-Call Y2000 PPA/PS Taxes Separa- Inventory Center A Power tion Contracts SCM-Goods CS-Meters IS Support NEPOOL Issues Records Management SCM-Accounts CS-Billing "Cut-over"Plan Payables "Tier 1 Transition Teams Health and CS-Credit Safety & Collections Benefit Plan RM&S-Demand Funding Side Management RM&S-Business Services Telecommunication Property Environmental and Safety External Affairs - --------------------------------------------------------------------------------------------------------------------------------- Transition Steering Committee Chairmen: T. Rogers / R. Powderly - --------------------------------------------------------------------------------------------------------------------------------- DC Kennedy LJ Reilly DL Holt PG Flynn J. Zschokke TL Schwennese WR Richer SM Stevens MA Katz T. Rogers Mercer Management HE Stapleford JL McGrath Consultants - --------------------------------------------------------------------------------------------------------------------------------- B Hassan J Carney W Norko K Kirby C Hebert D. St.Pierre A.Camara F. Mason D Fazzone M Hirsh - --------------------------------------------------------------------------------------------------------------------------------- Key Coordination Areas - --------------------------------------------------------------------------------------------------------------------------------- Regulatory Unregulated NGG Coord: Approvals Businesses - ---------------------------------------------------------------------------------------------------------------------------------
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit LJR-5 Exhibit LJR-5 Mass. Electric's Present Performance Standards New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Exhibit LJR-5 Page 1 of 3 MASSACHUSETTS ELECTRIC COMPANY PERFORMANCE STANDARDS UNDER RETAIL ACCESS TARIFFS Under the retail access tariffs, the Company shall establish performance standards for reliability and customer service. The standards are designed as a penalty-only approach, under which the Company would be penalized if its performance did not meet the standards, and there would be no reward for performance which exceeds the standard. The standards are set based on averages of historic data, as shown on page 3 of this exhibit. In the event that the Department establishes additional performance standards or performance standards for reliability and customer satisfaction for all electric utilities in Massachusetts that are more stringent than the standards set forth below, then Mass. Electric shall implement the additional or more stringent standards. SERVICE RELIABILITY PERFORMANCE STANDARD The Service Reliability Performance Standard shall be set at a duration of outages per customer served of 105 minutes. An outage is defined as the loss of electric service to more than one customer for more than one minute. The duration per customer served is the total length of time in minutes that an average customer is without service per year. Excluded from reliability measurements are extraordinary events such as severe storms and load shedding events resulting from generation or transmission problems. An event excluded from reliability measurements must meet one of the following criteria: o The event resulted in customer outages that represent more than ten percent (10%) of the customers in a district at any given time during the event; o The outages resulting from the event were as a result of the failure of other companies' supply or transmission to Massachusetts Electric Company customers and restoration of service was beyond the control of the Company and its employees; o The circumstances of the event were extraordinary, such as major disasters, earthquakes, wildfires, floods, hurricanes, tornadoes, ice storms, wind storms or other weather events beyond the control of the Company. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Exhibit LJR-5 Page 2 of 3 MASSACHUSETTS ELECTRIC COMPANY PERFORMANCE STANDARDS UNDER RETAIL ACCESS TARIFFS The schedule of customer credits under the Service Reliability Performance Standard is as follows: Duration of Outages Customer (minutes) Credit Up to 105 $0 106 to 112 $125,000 113 to 118 $250,000 119 to 124 $500,000 More than 124 $1,000,000 CUSTOMER SERVICE PERFORMANCE STANDARD The Customer Service Performance Standard shall be set at a customer satisfaction level of 85 percent. The Company will commission annual surveys of its customers to determine their overall level of satisfaction with the Company. The Company's measurement of customer satisfaction under this standard shall be based on the percentage of responses in the top three categories of customer satisfaction under a seven point scale (1=poor and 7=excellent). The schedule of customer credits under the Customer Service Performance Standard is as follows: % of Responses In Top Three Categories Customer (5,6,7) Credits Less than 76% $1,000,000 76% to 78% $500,000 79% to 81% $250,000 82% to 84% $125,000 85% or more $0
C:\eua files on disk\Ljr-5.wk4 New England Electric System STANDARDS Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-___ Exhibit LJR-5 Page 3 of 3 MASSACHUSETTS ELECTRIC COMPANY DEVELOPMENT OF PERFORMANCE STANDARDS FOR SERVICE RELIABILITY AND CUSTOMER SERVICE - ------------------------------------------------ ------------------------------------------------------ SERVICE RELIABILITY: CUSTOMER SERVICE: DURATION OF OUTAGES CUSTOMER SATISFACTION - ------------------------------------------------ ------------------------------------------------------ % of Respondents Duration Satisfied or of Outages Extremely YEAR (minutes) YEAR Satisfied 1995 116 1995 * 93% 1994 90 1994 92% 1993 79 1993 87% 1992 74 1992 83% 1991 83 1991 90% 1990 65 1990 93% 1989 100 1989 90% 1988 105 1988 88% 1987 100 1987 91% 1986 86 1986 90% Mean (Average) 89.8 Mean (Average) 89.5% Sample Standard Deviation 15.5 Sample Standard Deviation 3.1% - ------------------------------------------------ ------------------------------------------------------ PERFORMANCE STANDARD 105 PERFORMANCE STANDARD 85% - ------------------------------------------------ ------------------------------------------------------ Duration per Customer Served (minutes) = * Survey question response changed from four point scale Customer Minutes Interrupted (extremely satisfied, satisfied, somewhat dissatisfied, very Number of Customers Served dissatisfied) to seven point scale (1 = poor and 7 = excellent). 1995 amount represents % of responses in top 3 categories, i.e. 5, 6, and 7.
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit LJR-6 Exhibit LJR-6 Eastern's Present Performance Standards New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-___ Exhibit LJR-6 Page 1 of 4 EASTERN EDISON COMPANY PERFORMANCE STANDARDS UNDER RETAIL ACCESS TARIFFS Under the retail access tariffs, Eastern Edison (Company) shall establish performance standards for reliability and customer service. The Company shall establish these performance standards to ensure that historic levels of reliability and customer service are maintained. The standards are set based on averages of historic data, as shown on page 3. In the event that the Department establishes additional performance standards or performance standards for reliability and customer satisfaction for all electric utilities in Massachusetts that are more stringent than the standards set below, then Eastern Edison shall implement the additional or more stringent standards. SERVICE RELIABILITY PERFORMANCE STANDARD The reliability measure selected measures Company performance at minimizing outage duration and how quickly the Company responds to an outage problem. This measure is calculated by most utilities making it an appropriate benchmark of performance. The Service Reliability Performance Standard shall be set at a duration of outage per customer served of 81 minutes. The System Average Interruption Duration Index (SAIDI) is the total length of time, in minutes, the average customer is without service per calendar year. An event excluded from reliability measurements must meet one of the following criteria: o Any interruption of service lasting more than 24 consecutive hours for more than 10% of the number of customers being served at the time of the interruption and interruptions of less than one minute; o The outages resulting from the event were as a result of the failure of other companies' supply or transmission to Eastern Edison Company customers and restoration of service was beyond the control of the Company and its employees; o The circumstances of the event were extraordinary, such as major disasters, earthquakes, wildfires, floods, hurricanes, tornadoes, ice storms, wind storms or other weather events beyond the control of the Company. The schedule of penalties under Service Reliability Performance Standard is as follows: New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-___ Exhibit LJR-6 Page 2 of 4 EASTERN EDISON COMPANY PERFORMANCE STANDARDS UNDER RETAIL ACCESS TARIFFS Duration Eastern of Outage Edison (minutes) Penalty up to 81 $0 82 to 88 $62,500 89 to 95 $125,000 96 to 102 $187,000 103 or more $250,000 CUSTOMER SERVICE PERFORMANCE STANDARD The Customer Service Performance Standard shall be set at a customer satisfaction level of 76 percent. The customer service measure selected is the result of a Customer Attitude Survey. The Company will utilize the results of the EUA Customer Attitude Survey produced by Cambridge Reports Research International (CRRI) to track this measure. This survey is used as part of the Company's "Teaming Up for Performance" employee incentive program. The Company has historic data from 1991 through the present as a benchmark. The Company's measurement is based on the percentage of responses in the top three categories (categories 5,6, & 7) of customer satisfaction under a seven point scale (1 = poor and 7 = excellent). The schedule of penalties under Customer Service Performance Standard is as follows: Duration Eastern of Outage Edison (minutes) Penalty less than 66% $250,000 67% to 69% $187,000 70% to 72% $125,000 73% to 75% $62,500 76% or more $0 New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-___ Exhibit LJR-6 Page 3 of 4 EASTERN EDISON COMPANY PERFORMANCE STANDARDS UNDER RETAIL ACCESS TARIFFS PERFORMANCE STANDARDS: DURATION OF OUTAGE (SAIDI) Historic Data Duration of Outage Year (Minutes) ---- -------------- 1996 97 1995 66 1994 77 1993 64 1992 49 1991 48 1990 71 1989 64 1988 56 1987 74 1986 74 Mean (Average) 67.3 Sample Standard Deviation 13.2 Performance Standard 81 Duration Eastern of Outage Edison (minutes) Penalty --------- -------- up to 81 $0 82 to 88 $62,500 89 to 95 $125,000 96 to 102 $187,000 103 or more $250,000 SAIDI is defined as: Total # of customer outage hours X 60 Average number of customers served New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-___ Exhibit LJR-6 Page 4 of 4 EASTERN EDISON COMPANY PERFORMANCE STANDARDS UNDER RETAIL ACCESS TARIFFS PERFORMANCE STANDARDS: CUSTOMER ATTITUDE SURVEY Historic Data Of Responses In Top Three Categories Year (5, 6, & 7) ---- ------------- 1996 84% 1995 81% 1994 82% 1993 78% 1992 72% 1991 84% Mean (Average) 80% Sample Standard Deviation 4% Performance Standard 76% % of Responses in Top Three Eastern Categories Edison (5, 6, & 7) Penalty less than 66% $250,000 67% to 69% $187,000 70% to 72% $125,000 73% to 75% $62,500 76% or more $0 Customer Attitude Survey is based on the percentage of responses in the top three categories (categories 5, 6, & 7) of customer satisfaction under a seven point scale. (1 = poor and 7 = excellent) New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit LJR-7 Exhibit LJR-7 Proposed Performance Standards After Consolidation Date (Marked to Show Changes) New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Exhibit LJR-7 Page 1 of 2 MASSACHUSETTS ELECTRIC COMPANY PERFORMANCE STANDARDS UNDER RETAIL ACCESS TARIFFS Under the retail access tariffs, the Massachusetts Electric Company ("Mass. Electric or "the Company") shall establish performance standards for reliability and customer service. The standards are designed as a penalty-only approach, under which the Company would be penalized if its performance did not meet the standards, and there would be no reward for performance which exceeds the standard. The standards are set based on averages of historic data, as shown on page 3 of this exhibit. In the event that the Department establishes additional performance standards or performance standards for reliability and customer satisfaction for all electric utilities in Massachusetts that are more stringent than the standards set forth below, then Mass. Electric shall implement the additional or more stringent standards. SERVICE RELIABILITY PERFORMANCE STANDARD The Service Reliability Performance Standard shall be set at a duration of outages per customer served of [[105]] [96] minutes. An outage is defined as the loss of electric service to more than one customer for more than one minute. The duration per customer served is the total length of time in minutes that an average customer is without service per year. Excluded from reliability measurements are extraordinary events such as severe storms and load shedding events resulting from generation or transmission problems. An event excluded from reliability measurements must meet one of the following criteria: o The event resulted in customer outages that represent more than ten percent (10%) of the customers in a district at any given time during the event; o The outages resulting from the event were as a result of the failure of other companies' supply or transmission to [[Massachusetts Electric]] Company customers and restoration of service was beyond the control of the Company and its employees; o The circumstances of the event were extraordinary, such as major disasters, earthquakes, wildfires, floods, hurricanes, tornadoes, ice storms, wind storms or other weather events beyond the control of the Company. The schedule of customer credits under the Service Reliability Performance Standard is as follows: Legend: [ ] = insertion [[ ]] = deletion New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Exhibit LJR-7 Page 2 of 2 MASSACHUSETTS ELECTRIC COMPANY PERFORMANCE STANDARDS UNDER RETAIL ACCESS TARIFFS Duration Of Outages Customer (minutes) Credit Up to [[105]] [96] $0 [[106]] [97] to [[112]] [103] $[[125,000]] [156,250] [[113]] [104] to [[118]] [110] $[[250,000]] [312,500] [[119]] [111] to [[124]] [117] $[[500,000]] [625,000] More than [[124]] [117] $[[1,000]] [1,250,000] CUSTOMER SERVICE PERFORMANCE STANDARD The Customer Service Performance Standard shall be set at a customer satisfaction level of [[85]] [86] percent. The Company will commission annual surveys of its customers to determine their overall level of satisfaction with the Company. The Company's measurement of customer satisfaction under this standard shall be based on the percentage of responses in the top three categories of customer satisfaction under a seven point scale (1=poor and 7=excellent). The schedule of customer credits under the Customer Service Performance Standard is as follows: % of Responses In Top Three Categories Customer (5,6,7) Credits Less than 76% $[[1,000]] [1,250,000] 7[[6]][7]% to 7[[8]][9]% $[[500]] [625],000 [[79]][80]% to 8[[1]][2]% $[[250,000]] [312,500] 8[[2]][3]% to 8[[4]][5]% $[[125,000]] [156,250] 8[[5]]6% or more $0 New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit LJR-8 Exhibit LJR-8 Proposed Performance Standards After Consolidation Date New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Exhibit LJR-8 Page 1 of 2 MASSACHUSETTS ELECTRIC COMPANY PERFORMANCE STANDARDS UNDER RETAIL ACCESS TARIFFS Under the retail access tariffs, the Massachusetts Electric Company ("Mass. Electric or "the Company") shall establish performance standards for reliability and customer service. The standards are designed as a penalty-only approach, under which the Company would be penalized if its performance did not meet the standards, and there would be no reward for performance which exceeds the standard. The standards are set based on averages of historic data, as shown on page 3 of this exhibit. In the event that the Department establishes additional performance standards or performance standards for reliability and customer satisfaction for all electric utilities in Massachusetts that are more stringent than the standards set forth below, then Mass. Electric shall implement the additional or more stringent standards. SERVICE RELIABILITY PERFORMANCE STANDARD The Service Reliability Performance Standard shall be set at a duration of outages per customer served of 96 minutes. An outage is defined as the loss of electric service to more than one customer for more than one minute. The duration per customer served is the total length of time in minutes that an average customer is without service per year. Excluded from reliability measurements are extraordinary events such as severe storms and load shedding events resulting from generation or transmission problems. An event excluded from reliability measurements must meet one of the following criteria: o The event resulted in customer outages that represent more than ten percent (10%) of the customers in a district at any given time during the event; o The outages resulting from the event were as a result of the failure of other companies' supply or transmission to Company customers and restoration of service was beyond the control of the Company and its employees; o The circumstances of the event were extraordinary, such as major disasters, earthquakes, wildfires, floods, hurricanes, tornadoes, ice storms, wind storms or other weather events beyond the control of the Company. The schedule of customer credits under the Service Reliability Performance Standard is as follows: New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Exhibit LJR-8 Page 2 of 2 MASSACHUSETTS ELECTRIC COMPANY PERFORMANCE STANDARDS UNDER RETAIL ACCESS TARIFFS Duration Of Outages Customer (minutes) Credit Up to 96 $0 97 to 103 $156,250 104 to 110 $312,500 111 to 117 $625,000 More than 117 $1,250,000 CUSTOMER SERVICE PERFORMANCE STANDARD The Customer Service Performance Standard shall be set at a customer satisfaction level of 86 percent. The Company will commission annual surveys of its customers to determine their overall level of satisfaction with the Company. The Company's measurement of customer satisfaction under this standard shall be based on the percentage of responses in the top three categories of customer satisfaction under a seven point scale (1=poor and 7=excellent). The schedule of customer credits under the Customer Service Performance Standard is as follows: % of Responses In Top Three Categories Customer (5,6,7) Credits Less than 76% $1,250,000 77% to 79% $625,000 80% to 82% $312,500 83% to 85% $156,250 86% or more $0 New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit LJR-9 Exhibit LJR-9 Derivation of Duration of Outage Standard C:\eua files on disk\Ljr-9.WK4 New England Electric System SAIDI-MA Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-___ Exhibit LJR-9 Page 1 of 2 MASSACHUSETTS ELECTRIC COMPANY EASTERN EDISON COMANY PROPOSED COMBINED PERFORMANCE STANDARDS FOR RELIABILITY -------------------------------- SERVICE RELIABILITY: DURATION OF OUTAGES (SAIDI) -------------------------------- Duration of Outages Year (minutes) 1998 80 1997 84 1996 99 1995 108 1994 76 1993 77 1992 70 1991 78 Mean (Average) 84 Sample Standard Deviation 12.1 ---------------------------------------------------------------- PERFORMANCE STANDARD BASELINE Duration per Customer Served = 96 ---------------------------------------------------------------- Duration per Customer Served (minutes) = Customer Minutes Interrupted ---------------------------- Average Number of Customers Served ------------------------------------------- SCHEDULE OF PENALTIES ------------------------------------------- Duration of Outages Customer (Minutes) Credit ===================== =========== Minimum Maximum ------- ------- up to 96 $0 97 103 $156,250 104 110 $312,500 111 117 $625,000 more than 117 $1,250,000 New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-___ Exhibit LJR-9 Page 2 of 2 Massachsuetts Electric Company Eastern Edison Company Derivation of Combined Reliablity Standard for Duration of Outages (SAIDI) =========================================== Eastern Edison Performance Standard = 81 ------------------------------------------- ------------------------------------------- Cust Hrs In# Cust Int.Ave. Cust SAIDI ------------------------------------------- 1991 139,418 195,816 174,204 48 1992 143,836 180,408 174,944 49 1993 188,591 243,817 176,070 64 1994 227,715 265,283 177,603 77 1995 196,281 211,833 179,346 66 1996 292,478 335,617 180,863 97 1997 236,748 250,976 182,672 78 1998 149,437 231,484 182,672 49 =========================================== Average 66 =========================================== STD 16 =========================================== Baseline 82 =========================================== =========================================== Massachusetts Electric (Including Nantucket Electric in 1998) Performance Standard = 105 ------------------------------------------- ------------------------------------------- Cust Hrs In# Cust Int.Ave. Cust SAIDI ------------------------------------------- 1991 1,290,690 991,154 929,885 83 1992 1,160,294 971,684 936,480 74 1993 1,246,980 922,246 942,710 79 1994 1,196,328 1,003,317 950,950 75 1995 1,852,848 1,296,755 961,035 116 1996 1,616,230 1,291,653 970,420 100 1997 1,396,605 1,126,221 984,875 85 1998 1,442,755 1,185,766 1,006,475 86 =========================================== Average 87 =========================================== STD 13 =========================================== Baseline 100 =========================================== =========================================== Massachusetts Composite --------------------------------------------- --------------------------------------------- Cust Hrs Int # Cust Int. Ave. Cust SAIDI --------------------------------------------- 1991 1,430,108 1,186,970 1,104,089 78 1992 1,304,130 1,152,092 1,111,424 70 1993 1,435,571 1,166,063 1,118,780 77 1994 1,424,043 1,268,600 1,128,553 76 1995 2,049,129 1,508,588 1,140,381 108 1996 1,908,708 1,627,270 1,151,283 99 1997 1,633,353 1,377,197 1,167,547 84 1998 1,592,192 1,417,250 1,189,147 80 =============================================== Average 84 =============================================== STD 12.1 =============================================== Baseline 96.1 =============================================== Notes ----- 1. The Performance Standard is based on the average of historic data less one standard deviation. 2. Mass. Electric data includes Nantucket Electric beginning in 1998. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit LJR-10 Exhibit LJR-10 Calculation of Customer Satisfaction Measure C:\eua files on disk\Ljr-10.WK4 New England Electric System RELIAB-MA Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit LJR-10 Page 1 of 2 MASSACHUSETTS ELECTRIC COMPANY EASTERN EDISON COMPANY PROPOSED COMBINED PERFORMANCE STANDARDS FOR CUSTOMER SERVICE -------------------------------- CUSTOMER SERVICE: CUSTOMER SATISFACTION -------------------------------- % of Respondents Satisfied or Extremely Year Satisfied 1998 89% 1997 82% 1996 86% 1995 90% 1994 91% 1993 89% 1992 93% 1991 92% Mean (Average) 89% Sample Standard Deviation 3% ---------------------------------------------------------------- PERFORMANCE STANDARD BASELINE Customer Satisfaction Index = 86% ---------------------------------------------------------------- Customer Satisfaction = percentage of responses in the top three categories of customer satisfaction under the seven point scale. (1=poor and 7 = excellent) ------------------------------------------- SCHEDULE OF PENALTIES ------------------------------------------- % of Respondents Satisfied or Extremely Customer Satisfied Credit ===================== =========== Minimum Maximum ------- ------- 86% or more $0 83% 85% $156,250 80% 82% $312,500 77% 79% $625,000 less than 76% $1,250,000
C:\eua files on disk\Ljr-10.WK4 New England Electric System RELIAB CALC Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit LJR-10 Page 2 of 2 Massachsuetts Electric/ Eastern Edison Derivation of Combined Customer Satisfaction Standard for Residential Customers - Top 3 Categories on a 7-Point Scale ====================================================================================== Eastern Edison - BROCKTON Eastern Edison - FALL RIVER Performance Standard =76% Performance Standard =76% -------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------- Percent Scale Value Total Percent Scale Value Total 5 6 7 5 6 7 -------------------------------------------------------------------------------------- 1991 31% 20% 33% 84% 26% 24% 31% 81% 1992 28% 21% 27% 76% 30% 22% 25% 77% 1993 27% 19% 31% 77% 25% 22% 33% 80% 1994 22% 23% 36% 81% 20% 18% 42% 80% 1995 21% 23% 35% 79% 22% 24% 41% 87% 1996 24% 21% 38% 83% 21% 17% 49% 87% 1997 24% 25% 36% 85% 18% 21% 42% 81% 1998 20% 19% 41% 80% 19% 17% 50% 86% ====================================================================================== Average 81% 82% ====================================================================================== STD 3.0% 3.5% ====================================================================================== Baseline 78% 79% ====================================================================================== ====================================================================================== Massachusetts Electric MASSACHUSETTS COMPOSITE -------------------------------- Performance Standard = 85% WEIGHTED AVERAGE ------------------------------------------- ----------- Percent Scale Value Total Total 5 6 7 Brockton Fall River Mass. Elec. -------------------------------------------------------------------------------------- 1991 90% 9% 4% 76% 89% 1992 83% 8% 4% 70% 82% 1993 87% 8% 4% 73% 86% 1994 92% 9% 4% 78% 90% 1995 20% 24% 49% 93% 8% 4% 78% 91% 1996 21% 24% 45% 90% 9% 4% 76% 89% 1997 18% 24% 53% 95% 9% 4% 80% 93% 1998 17% 25% 52% 94% 8% 4% 79% 92% ====================================================================================== Average 90.5% 89% ====================================================================================== STD 3.7% 3% ====================================================================================== Baseline 87% 86% ====================================================================================== CUSTOMER WEIGHT --------------------------------------------------------------------------------------- Mass. % Weight % Weight % Weight Eastern = Brockton + Fall River Elec Total Brockton Fall River Mass. Elec. --------------------------------------------------------------------------------------- 1991 174,204 118,459 55,745 929,885 1,104,089 11% 5% 84% 1992 174,944 118,962 55,982 936,480 1,111,424 11% 5% 84% 1993 176,070 119,728 56,342 942,710 1,118,780 11% 5% 84% 1994 177,603 120,770 56,833 950,950 1,128,553 11% 5% 84% 1995 179,346 121,955 57,391 961,035 1,140,381 11% 5% 84% 1996 180,863 122,987 57,876 970,420 1,151,283 11% 5% 84% 1997 182,672 124,217 58,455 984,875 1,167,547 11% 5% 84% 1998 182,672 124,217 58,455 997,016 1,179,688 11% 5% 85% Notes ----- 1. EUA Surveys are conducted by Cambridge Reports 2. NEES Surveys were conducted by Cambridge Reports up to 1995. Now conducted by Applied Marketing Science (1996 - 1998). In the years 1991 - 1995 survey question responses were based on a 4-point scale (extremely satisfied, somewhat dissatisfied, very dissatisfied) and percentages shown represent the top 2 categories on the 4-point scale. 3. The Performance Standard is based on the average of historic data less one standard deviation. Massachusetts composite is based on a weighted value by number of customers for each company in each year. Each year's weight is the percentage of each company's number of customers as a percent of the total number of customers.
COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99- ______ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF JENNIFER K. ZSCHOKKE COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99- ______ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF JENNIFER K. ZSCHOKKE Table of Contents Page I. Qualifications 1 II. Purpose of Testimony and Summary of Filing 1 III. Consolidation of Distribution Companies 3 IV. Consolidation of Transmission Companies 7 V. Short-Term Financing for the Transition Period 9
New England Electric System Eastern Utilities Associates Testimony of J. K. Zschokke Page 1 of 10 1 I. Qualifications 2 Q. Please state your name, title, and business address. 3 A. My name is Jennifer K. Zschokke. I am Manager of Finance for New England Power 4 Service Company (NEPSCO), a New England Electric System (NEES) Company. My 5 business address is 25 Research Drive, Westborough, MA 01582. 6 7 Q. Please describe your educational background and training. 8 A. I have earned a Bachelor of Arts degree in Management Science from Westminster 9 College and a Masters of Science in Finance from Boston College. 10 11 Q. Please describe your professional experience. 12 A. I joined NEPSCO in 1987 as an assistant financial analyst and have been promoted several 13 times within the Finance Department, most recently to Manager in 1998. My 14 responsibilities include the long and short-term financing of NEES and its subsidiaries. In 15 addition, the Finance Department provides a variety of financial advisory services to other 16 functions in the NEES System. 17 18 II. Purpose of Testimony and Summary of Filing 19 Q. What is the purpose of your testimony? New England Electric System Eastern Utilities Associates Testimony of J. K. Zschokke Page 2 of 10 1 A. I will describe, from a financial perspective, the consolidation of the subsidiary companies 2 of NEES and Eastern Utilities Associates (EUA) which operate in the state of 3 Massachusetts. Specifically, I will explain the planned merger of Eastern Edison Company 4 (Eastern), an EUA distribution company, with and into Massachusetts Electric Company 5 (Mass. Electric), a NEES distribution company. Similarly, I will explain the planned 6 merger of Montaup Electric Company (Montaup), the EUA wholesale transmission 7 company, with and into New England Power Company (NEP), the NEES wholesale 8 transmission company. In addition, I will explain the financing benefits that will result 9 from the acquisition of EUA by NEES. 10 I will also address NEES's plan to include EUA and its regulated subsidiaries in the 11 NEES Moneypool, which is currently an efficient means for managing the daily cash 12 position of NEES and its subsidiaries. 13 14 Q. What approvals are you requesting from the Massachusetts Department of 15 Telecommunications and Energy (Department)? 16 A. The mergers require approval of the Department under Section 96 of Chapter 164. As I 17 will discuss later, Mass. Electric will be issuing preferred stock in exchange for the 18 preferred stock of Eastern and will be assuming liabilities for Eastern's pollution control 19 revenue bonds first mortgage and possibly its first mortgage bonds. I am advised by New England Electric System Eastern Utilities Associates Testimony of J. K. Zschokke Page 3 of 10 1 counsel that this transaction requires authorization under Section 99. As explained in the 2 filing letter, further authority is also requested from the Department under Sections 9A, 3 14, 15, 15A, 16, 18 or 19 to the extent it is necessary. 4 As mentioned above, we are requesting that after the merger of NEES and EUA 5 the regulated subsidiaries of EUA be authorized to participate in the NEES Moneypool 6 which is authorized under Section 17A. Other approvals are also requested of the 7 Department as part of this filing, but are addressed by other witnesses. 8 9 Q. When do you propose to consolidate the operating subsidiaries? 10 A. Subject to the receipt of necessary regulatory approvals, our objective is to complete the 11 merger of the operating subsidiaries during the first half of 2000. 12 13 III. Consolidation of Distribution Companies 14 Mass Electric and Eastern 15 16 Q. Please describe the balance sheets of Mass. Electric and Eastern as of year end 1998. 17 A. Please see Exhibit JKZ-1 for Mass. Electric's year end 1998 balance sheet and JKZ-2 for 18 Eastern's year end 1998 balance sheet. Mass. Electric is noticeably larger than Eastern. 19 This is evidenced by the fact that assets and liabilities for Mass. Electric total $1.455 New England Electric System Eastern Utilities Associates Testimony of J. K. Zschokke Page 4 of 10 1 billion and are approximately three times the size of Eastern's total assets and liabilities of 2 $522 million. At year end 1998, Mass. Electric owned $1.143 billion of net utility plant 3 and Eastern owned $151 million (excluding its interest in Montaup), approximately a 4 seven fold differential. As for capital structure, Mass. Electric and Eastern have similar 5 capitalization ratios as of year end 1998. 6 7 Q. Please describe where Mass. Electric and Eastern fit into the organizational structure of 8 the NEES and EUA systems, respectively. 9 A. Mass. Electric is a direct subsidiary of NEES which is a holding company subject to the 10 Public Utility Holding Company Act of 1935 (Holding Company Act). Similarly, Eastern 11 is a direct subsidiary of EUA which is also a holding company subject to the Holding 12 Company Act. NEES owns 100% of the common stock of Mass. Electric and EUA holds 13 100% of the common stock of Eastern. Both Mass. Electric and Eastern operate solely in 14 Massachusetts for the purpose of distributing electricity to the retail customer. 15 16 Q. Do either Mass. Electric or Eastern have any subsidiaries? 17 A. Mass. Electric does not have any subsidiaries. However, within the EUA system today, 18 Eastern is the sole owner of Montaup's securities, including 100% of the common equity. 19 Therefore, Montaup is a wholly owned subsidiary of Eastern and an indirect subsidiary of New England Electric System Eastern Utilities Associates Testimony of J. K. Zschokke Page 5 of 10 1 EUA. 2 3 Q. Are you aware of any changes in the EUA corporate organizational structure which may 4 occur prior to NEES's acquisition of EUA? 5 A. Yes. Eastern is contemplating a spin off its investment in Montaup to EUA. Thus, EUA 6 would hold Montaup's stock directly rather than indirectly through its ownership of 7 Eastern. The spinoff of Montaup by Eastern would i) complete the functional unbundling 8 of the generation business from the distribution business through the complete corporate 9 separation of Eastern and Montaup, ii) eliminate any risk that Eastern may have associated 10 with its direct ownership of Montaup pertaining to, for example, contingent liabilities and 11 nuclear ownership, iii) isolate Eastern's capital structure so that it applies to distribution 12 ratemaking only, and iv) simplify EUA's corporate structure. We will update the 13 Department during the proceeding as the details of this plan become available. 14 15 Q. What are the financial transactions necessary to consolidate Eastern with Mass. Electric? 16 A. Eastern would merge with and into Mass. Electric. Mass. Electric will assume the 17 obligation for repayment of Eastern's indebtedness. Mass Electric will issue preferred 18 stock to the holders of Eastern in exchange for their existing preferred stock. In addition, 19 we expect that Montaup will repay its debt and preferred stock held by Eastern. New England Electric System Eastern Utilities Associates Testimony of J. K. Zschokke Page 6 of 10 1 Q. Have you prepared a proforma balance sheet illustrating the impact of these transactions? 2 A. Yes. Exhibit JKZ-3 illustrates the impact of the merger of Eastern and Mass. Electric, the 3 spinoff of Montaup and the repayment by Montaup of its debt and preferred stock. As 4 permitted by accounting rules, the balance sheet of the combined entity will reflect the sum 5 of the balance sheets of the separate entities prior to the subsidiary merger. 6 7 Q. Are there any savings associated with the Eastern refinancing? 8 A. Yes. Because Mass. Electric is a larger company with higher credit ratings than Eastern, 9 Mass. Electric is able to access capital markets at rates generally lower than those Eastern 10 is able to obtain. Mass. Electric is rated "A1" by Moody's Investors Service, and "A+" by 11 Standard and Poor's, and "AA- " by Duff & Phelps Credit Rating Company. Eastern's 12 ratings are "Baa1", "BBB+", and "A-", respectively. 13 14 Q. How much do you expect the financing savings to be? 15 A. The difference between Eastern's cost of debt and Mass. Electric's, due solely to the 16 difference in credit rating is approximately 15 basis points in today's marketplace. 17 Historically this differential has been as high as 50 basis points. In addition to this spread, 18 Eastern would typically pay another 10 to 15 basis points more than Mass. Electric 19 because of the smaller size of its bond issuances and the overall illiquidity of those bonds. New England Electric System Eastern Utilities Associates Testimony of J. K. Zschokke Page 7 of 10 1 The total savings, which will be realized as Eastern's debt is refinanced, would be 2 approximately $300,000 to $400,000 per year. 3 4 IV. Consolidation of Transmission Companies 5 NEP and Montaup 6 7 Q. Please describe where NEP and Montaup fit into the organizational structure of the NEES 8 and EUA systems, respectively. 9 A. Similar to Mass. Electric, NEP is a direct subsidiary of NEES. This means that NEES 10 owns 100% of the common stock of NEP. Montaup is an indirect subsidiary of EUA 11 today; however, as I previously mentioned, Eastern is contemplating a spin off of 100% of 12 its ownership of the common stock of Montaup to EUA prior to the NEES's acquisition of 13 EUA. 14 NEP operates in several states, which include Massachusetts, Rhode Island, New 15 Hampshire, and Vermont. Montaup operates in Massachusetts and Rhode Island. Both 16 NEP and Montaup have minority interests in nuclear properties in Connecticut, Maine, 17 New Hampshire and Vermont as well as a fossil unit in Maine. Since the divestiture of 18 substantially all of its generating business in 1998, NEP is primarily a transmission 19 company. Montaup recently completed the sale of the Canal and Somerset generating New England Electric System Eastern Utilities Associates Testimony of J. K. Zschokke Page 8 of 10 1 stations and anticipates closing on its share of Wyman 4 shortly. Therefore, Montaup is 2 primarily a transmission company going forward similar to NEP. 3 In addition, NEP and Montaup each recover through Contract Termination 4 Charges (CTC's), stranded costs associated with prior investments in the generating 5 business. NEP and Montaup collect CTC's from affiliated and nonaffiliated customers. 6 Mass. Electric pays 72.6% of NEP's, and Eastern pays 59.0% of Montaup's total stranded 7 costs recovered through CTC's. Mass. Electric and Eastern recover their costs associated 8 with the CTC from distribution customers through a Transition Charge authorized by the 9 Massachusetts Utility Restructuring Act of 1997 as well as a Federal Energy Regulatory 10 Commission (FERC) approved settlement with various state parties. 11 12 Q. Please describe the balance sheets of NEP and Montaup? 13 A. Please see Exhibit JKZ-4 and JKZ-5, respectively. At year end 1998, NEP's balance sheet 14 was approximately four times the size of Montaup's. NEP's assets and liabilities totaled 15 $2.415 billion and Montaup's assets and liabilities totaled $641 million. As of year end, 16 NEP owned $458 million of net utility plant, most of which is transmission and Montaup 17 owned about $341 million of net utility plant, which still included the Somerset units 18 subsequently sold on April 27, 1999. Both NEP and Montaup have significant regulatory 19 assets which represent the future collection of Contract Termination Charges. As for New England Electric System Eastern Utilities Associates Testimony of J. K. Zschokke Page 9 of 10 1 capital structure, NEP and Montaup have similar capitalization ratios as of year end 1998. 2 3 Q. What are the financial transactions necessary to implement the consolidation of Montaup 4 and NEP? 5 A. Montaup will merge with and into NEP, and their balance sheets will be consolidated, 6 similar to the Mass. Electric/Eastern combination. We are assuming as part of this 7 transaction, NEP uses its cash on hand to pay off Montaup's debentures and preferred 8 stock currently held by Eastern. In addition, $147 million of common equity is expected 9 to be repaid to the parent. 10 11 Q. Have you prepared proforma financial statements for the merger of NEP and Montaup? 12 A. Yes. Exhibit JKZ-6 illustrates the impact of the merger of Montaup and NEP, and the 13 repayment by Montaup of its debt and preferred stock. As permitted by accounting rules, 14 the balance sheet of the combined entity will reflect the sum of the balance sheets of the 15 separate entities prior to the subsidiary merger. 16 17 V. Short-Term Financing for the Transition Period 18 19 Q. Please explain NEES's request to include EUA and its subsidiaries in the NEES New England Electric System Eastern Utilities Associates Testimony of J. K. Zschokke Page 10 of 10 1 Moneypool. 2 A. We are proposing that for the period between the NEES acquisition of EUA and the 3 merger of the subsidiaries, that the EUA regulated subsidiaries be granted approval to 4 participate in the NEES Moneypool both as borrowers and investors. The NEES 5 Moneypool is an efficient method of utilizing the excess cash of affiliated companies to 6 meet the needs of borrowing companies on a daily basis. This process reduces the 7 transaction costs that would otherwise be incurred if the affiliates were to invest or 8 borrow in the public markets. It also provides opportunities for those smaller companies 9 who do not have the ability to readily access public markets. The NEES Moneypool has 10 been in existence since 1981, and participation is authorized by the Department. For these 11 reasons, it is desirable to grant the same opportunities to the regulated EUA subsidiaries 12 once they are subsidiaries of NEES by amending the NEES Moneypool. 13 14 Q. Are there any other issues pertaining to the consolidation of the subsidiary companies? 15 A. No. This concludes my testimony.
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ EXHIBITS OF JENNIFER K. ZSCHOKKE JKZ-1 Massachusetts Electric Company 1998 Balance Sheet JKZ-2 Eastern Edison Company 1998 Balance Sheet JKZ-3 Proforma Balance Sheet Illustrating Mass. Electric and Eastern Merger JKZ-4 New England Power Company 1998 Balance Sheet JKZ-5 Montaup Electric Company 1998 Balance Sheet JKZ-6 Proforma Balance Sheet Illustrating NEP and Montaup Merger New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit JKZ-1 Exhibit JKZ-1 Massachusetts Electric Company 1998 Balance Sheet New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit JKZ-1 Page 1 of 1 MASSACHUSETTS ELECTRIC COMPANY 1998 BALANCE SHEET Dollars in Thousands DECEMBER 31, 1998 Line ASSETS 1 Utility Plant, at original cost $1,626,569 2 Less: Accumulated Depreciation 499,975 ------- 3 1,126,594 4 Construction Work in Progress 16,575 ------ 5 Net Utility Plant 1,143,169 6 7 Cash 6,994 8 Accounts Receivable, Associated Companies 6,629 9 Other Current Assets 256,535 10 11 Deferred Charges and Other Assets 41,235 ------ 12 13 TOTAL ASSETS 1,454,562 14 15 16 CAPITALIZATION AND LIABILITIES ------------------------------ 17 Common Equity 508,203 18 Preferred Stock 10,674 19 Long-term Debt 353,329 ------- 20 Total Capitalization 872,206 21 22 Long Term Debt due within one year 15,000 23 Short-term Debt 80,725 24 Other Current Liabilities 186,163 25 26 Deferred State and Federal Income Taxes 200,965 27 Unamortized Investment Tax Credits 14,377 28 Other Liabilities 85,126 29 30 TOTAL CAPITALIZATION AND LIABILITIES $1,454,562 31 32 CAPITALIZATION RATIOS 33 Common Equity 58% 34 Preferred Stock 1% 35 Long-term Debt 41% 36 Total Capitalization 100% New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit JKZ-2 Exhibit JKZ-2 Eastern Edison Company 1998 Balance Sheet New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit JKZ-2 Page 1 of 1 EASTERN EDISON COMPANY 1998 BALANCE SHEET Dollars in Thousands DECEMBER 31, 1998 Line ASSETS 1 Utility Plant, at original cost $245,700 2 Less: Accumulated Depreciation 96,143 ------ 3 149,557 4 Construction Work in Progress 1,384 ----- 5 Net Utility Plant 150,941 6 7 Investments in Subsidiary 266,499 8 9 Cash 25,798 10 Accounts Receivable, Associated Companies 16,883 11 Other Current Assets 43,277 12 13 Deferred Charges and Other Assets 18,645 ------ 14 15 TOTAL ASSETS 522,043 16 17 18 CAPITALIZATION AND LIABILITIES 19 Common Equity 225,998 20 Preferred Stock 27,995 21 Long-term Debt 162,550 ------- 22 Total Capitalization 416,543 23 24 Long Term Debt due within one year 0 25 Short-term Debt 0 26 Other Current Liabilities 69,269 27 28 Deferred State and Federal Income Taxes 20,076 29 Unamortized Investment Tax Credits 3,310 30 Other Liabilities 12,845 ------ 31 32 TOTAL CAPITALIZATION AND LIABILITIES $522,043 33 34 CAPITALIZATION RATIOS --------------------- 35 Common Equity 54% 36 Preferred Stock 7% 37 Long-term Debt 39% --- 38 Total Capitalization 100% New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit JKZ-3 Exhibit JKZ-3 Proforma Balance Sheet Illustrating Mass. Electric and Eastern Merger New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit JKZ-3 Page 1 of 1 MASSACHUSETTS ELECTRIC COMPANY EASTERN EDISON COMPANY PROFORMA BALANCE SHEET - MERGED Dollars in Thousands
ACTUAL PRO-FORMA ------------------- ------------------------- MASS. IMPACT OF ELECTRIC EASTERN NEP/MONTAUP MERGED 1998 1998 MERGER COMPANY Line ASSETS ---- ------ 1 Utility Plant, at original cost $1,626,569 $245,700 $1,872,269 2 Less: Accumulated Depreciation 499,975 96,143 596,118 -------- ------- ------- 3 1,126,594 149,557 1,276,151 4 Construction Work in Progress 16,575 1,384 17,959 ------- ------ ------ 5 Net Utility Plant 1,143,169 150,941 1,294,110 6 7 Investment in Subsidiary NA 266,499 (266,499) 0 8 9 Cash 6,994 25,798 38,757 (a) 71,549 10 Accounts Receivable, Associated Companies 6,629 16,883 23,512 11 Other Current Assets 256,535 43,277 299,812 12 13 Deferred Charges and Other Assets 41,235 18,645 59,880 ------- ------- ------ 14 15 TOTAL ASSETS 1,454,562 522,043 (227,742) 1,748,863 16 17 18 CAPITALIZATION AND LIABILITIES 19 Common Equity 508,203 225,998 (147,017) (b) 587,184 (c) 20 Preferred Stock 10,674 27,995 0 38,669 21 Long-term Debt 353,329 162,550 0 515,879 -------- -------- - ------- 22 Total Capitalization 872,206 416,543 (147,017) 1,141,732 23 24 Long Term Debt due within one year 15,000 0 15,000 25 Short-term Debt 80,725 0 (80,725) (a) 0 26 Other Current Liabilities 186,163 69,269 255,432 27 28 Deferred State and Federal Income Taxes 200,965 20,076 221,041 29 Unamortized Investment Tax Credits 14,377 3,310 17,687 30 Other Liabilities 85,126 12,845 97,971 ------- ------- ------ 31 32 TOTAL CAPITALIZATION AND LIABILITIES $1,454,562 $522,043 ($227,742) $1,748,863 33 34 CAPITALIZATION RATIOS --------------------- 35 Common Equity 58% 54% 51% 36 Preferred Stock 1% 7% 3% 37 Long-term Debt 41% 39% 45% --- --- --- 38 Total Capitalization 100% 100% 100% Notes: (a) See Exhibit JKZ-6, Line 23. Proceeds from redemption of Montaup debt and preferred use to paydown short-term debt and increase cash. (b) See Exhibit JKZ-5, Line 20. (c) The merged balance sheet does not reflect the impact of "push-down" accounting and the aquisition premium.
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit JKZ-4 Exhibit JKZ-4 New England Power Company 1998 Balance Sheet New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit JKZ-4 Page 1 of 1 NEW ENGLAND POWER COMPANY 1998 BALANCE SHEET Dollars in Thousands DECEMBER 31, 1998 Line ASSETS ---- ---- ------ 1 Utility Plant, at original cost $1,262,461 2 Less: Accumulated Depreciation 837,637 ------- 3 424,824 4 Construction Work in Progress 33,289 ------ 5 Net Utility Plant 458,113 6 7 Investments (Including in Subsidiaries) 88,121 8 9 Cash 179,413 10 Accounts Receivable, Associated Companies 107,878 11 Other Current Assets 63,362 12 13 Regulatory Assets 1,512,562 14 Deferred Charges and Other Assets 5,339 15 16 TOTAL ASSETS 2,414,788 17 18 19 CAPITALIZATION AND LIABILITIES ------------------------------ 20 Common Equity 520,896 21 Preferred Stock 1,567 22 Long-term Debt 371,765 ------- 23 Total Capitalization 894,228 24 25 Long Term Debt due within one year 0 26 Short-term Debt 0 27 Other Current Liabilities 199,919 28 29 Deferred State and Federal Income Taxes 165,115 30 Unamortized Investment Tax Credits 30,870 31 Accrued Yankee Nuclear Plant Costs 242,138 32 Purchased Power Obligations 832,668 33 Other Liabilities 49,850 ------ 34 35 TOTAL CAPITALIZATION AND LIABILITIES $2,414,788 36 37 CAPITALIZATION RATIOS --------------------- 38 Common Equity 58% 39 Preferred Stock 0% 40 Long-term Debt 42% --- 41 Total Capitalization 100% New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit JKZ-5 Exhibit JKZ-5 Montaup Electric Company 1998 Balance Sheet New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit JKZ-5 Page 1 of 1 MONTAUP ELECTRIC COMPANY 1998 BALANCE SHEET Dollars in Thousands DECEMBER 31 1998 Line ASSETS 1 Utility Plant, at original cost $496,203 2 Less: Accumulated Depreciation 156,158 ------- 3 340,045 4 Construction Work in Progress 1,307 ----- 5 Net Utility Plant 341,352 6 7 Investments in Subsidiaries 12,881 8 9 Cash 154 10 Accounts Receivable, Associated Companies 66,638 11 Other Current Assets 15,998 12 13 Unrecovered Regulatory Plant Costs 58,503 14 Deferred Charges and Other Assets 145,445 15 16 TOTAL ASSETS 640,971 17 18 19 CAPITALIZATION AND LIABILITIES ------------------------------ 20 Common Equity 147,017 21 Preferred Stock 1,500 22 Long-term Debt 117,982 ------- 23 Total Capitalization 266,499 24 25 Long Term Debt due within one year 0 26 Short-term Debt 0 27 Other Current Liabilities 69,759 28 29 Deferred State and Federal Income Taxes 99,567 30 Unamortized Investment Tax Credits 9,840 31 Other Liabilities 195,306 32 33 TOTAL CAPITALIZATION AND LIABILITIES $640,971 34 35 CAPITALIZATION RATIOS --------------------- 36 Common Equity 55% 37 Preferred Stock 1% 38 Long-term Debt 44% --- 39 Total Capitalization 100% New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit JKZ-6 Exhibit JKZ-6 Proforma Balance Sheet Illustrating NEP and Montaup Merger
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit JKZ-6 Page 1 of 1 NEW ENGLAND POWER COMPANY MONTAUP ELECTRIC COMPANY PROFORMA BALANCE SHEET - MERGED Dollars in Thousands Actual Pro-Forma ------------------- ------------------------------- Redemption of Montaup Repayment NEP Montaup Debt and of Common Merged 1998 1998 Preferred Equity Company Line Assets ---- ---- --------- --------- ------- ---- ------ 1 Utility Plant, at original cost $1,262,461 $496,203 ######### 2 Less: Accumulated Depreciation 837,637 156,158 993,795 3 424,824 340,045 764,869 4 Construction Work in Progress 33,289 1,307 34,596 5 Net Utility Plant 458,113 341,352 799,465 6 7 Investments (Including in Subsidiaries) 88,121 12,881 101,002 8 9 Cash 179,413 154 (119,482) (60,085) 0 10 Accounts Receivable, Associated Companies 107,878 66,638 174,516 11 Other Current Assets 63,362 15,998 79,360 12 13 Unrecovered Regulatory Plant Costs 1,512,562 58,503 1,571,065 14 Deferred Charges and Other Assets 5,339 145,445 150,784 15 16 Total Assets 2,414,788 640,971 (119,482) (60,085) 2,876,192 17 18 19 Capitalization and Liabilities 20 Common Equity 520,896 147,017 (147,017) 520,896 (a) 21 Preferred Stock 1,567 1,500 (1,500) 0 1,567 22 Long-term Debt 371,765 117,982 (117,982) 0 371,765 23 Total Capitalization 894,228 266,499 (119,482) (147,017) 894,228 24 25 Long Term Debt due within one year 0 0 0 26 Short-term Debt 0 0 86,932 86,932 27 Other Current Liabilities 199,919 69,759 269,678 28 29 Deferred State and Federal Income Taxes 165,115 99,567 264,682 30 Unamortized Investment Tax Credits 30,870 9,840 40,710 31 Accrued Yankee Costs 242,138 0 242,138 32 Purchased Power Obligations 832,668 0 832,668 33 Other Liabilities 49,850 195,306 245,156 34 35 $2,414,788 $640,971 (119,482) (60,085) 2,876,192 36 37 38 Total Capitalization and Liabilities 39 40 Capitalization Ratios 41 Common Equity 58% 55% 58% 42 Preferred Stock 0% 1% 0% 43 Long-term Debt 42% 44% 42% 44 Total Capitalization 100% 100% 100% (a) The merged balance sheet does not reflect the impact of "push-down" accounting and the aquisition premium.
New England Electric System Eastern Utilities Associates Massachusetts Electric Company and Eastern Edison Company Rate Plan Filing In Support of Merger Volume 2 Testimony & Exhibits of David M. Webster Theresa M. Burns James J. Bonner, Jr. April 30, 1999 Submitted to: Massachusetts Department of Telecommunications and Energy Docket D.T.E. 99-_____ Submitted by: NEES Logo EUA Logo COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF DAVID M. WEBSTER COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF DAVID M. WEBSTER Table of Contents Page ---- I. Qualifications........................................................1 II. Purpose of Testimony..................................................3 III. Depreciation Rates....................................................3 IV. Storm Contingency Fund................................................4 V. Environmental Response Fund...........................................7 VI. Other Amortizations and Accounting Adjustments........................9 VII. Conclusion...........................................................10
New England Electric System Eastern Utilities Associates Testimony of D.M. Webster Page 1 1 QUALIFICATIONS 2 Q. Please state your full name and business address. 3 A. David M. Webster, 25 Research Drive, Westborough, Massachusetts 01582. 4 5 Q. Please state your position. 6 A. I am a Principal Financial Analyst in the Rate Department of New England 7 Power Service Company ("NEPSCO"). NEPSCO provides engineering, 8 technical, accounting, and other services for the New England Electric System 9 ("NEES") Companies, including Massachusetts Electric Company ("Mass. 10 Electric") and Nantucket Electric Company. 11 12 Q. Please describe your educational background and training. 13 A. In 1986, I graduated with distinction from Southeastern Massachusetts University 14 with a Bachelor of Science degree in accounting. 15 16 Q. Please outline your professional experience. 17 A. In 1986, I was hired by NEPSCO as an Assistant Analyst in the Financial 18 Reporting Department. My responsibilities included assisting in the preparation 19 of the various external reporting requirements for NEES and subsidiaries. I was 20 promoted to Analyst in the Financial Analysis section in 1988. My responsibilities New England Electric System Eastern Utilities Associates Testimony of D.M. Webster Page 2 1 included conducting various calculations and analysis in support of the closing of 2 the accounting books of record for the various NEES companies. 3 4 In 1991, I was promoted to Supervisor of the NEPSCO Accounting Department, 5 responsible for the monthly closing of the accounting books of record as well as 6 all internal and external reporting requirements. In 1992, my supervisory 7 responsibilities were expanded to include overseeing the monthly closing of two 8 additional NEES subsidiaries' books of record as well as all internal and external 9 reporting requirements. 10 11 In 1993, I was promoted to Supervisor of Wholesale Accounting, overseeing the 12 monthly closing and internal reporting requirements for the Wholesale Business 13 unit of NEES. In 1995, I was promoted to Manager of Wholesale Accounting and was 14 given additional responsibilities associated with the Wholesale Accounting 15 section. 16 17 In February 1997, I accepted an assignment to the Rate Department to provide 18 revenue requirement analyses for the NEES retail companies. 19 20 Q. Have you previously testified before a regulatory commission? New England Electric System Eastern Utilities Associates Testimony of D.M. Webster Page 3 1 A. Yes, I have testified in proceedings before the Department, as well as regulatory 2 commissions in Rhode Island and New Hampshire. 3 4 II. PURPOSE OF TESTIMONY 5 Q. What is the purpose of your testimony? 6 A. As a result of the proposed merger, several accounting related issues need to be 7 addressed for the consolidated entity such as consolidation of depreciation rates, 8 storm contingency funds, recovery of hazardous waste expenditures and the 9 amortization of other items such as unfunded deferred taxes and deferred FAS 106 10 costs. My testimony describes the Company's proposals with regard to each of 11 these issues. 12 13 III. DEPRECIATION RATES 14 Q. What depreciation rates does the Company propose using for the combined 15 entity? 16 A. As described in the testimony of Ms. Zschokke, Mass. Electric will be the 17 surviving corporation, therefore the Company proposes to apply the depreciation 18 rates approved for Mass. Electric as part of the Electric Utility Industry 19 Restructuring Settlement Agreement ("Settlement Agreement") in Docket No. 20 D.P.U./D.T.E. 96-25, dated October 1, 1996. The depreciation rates approved in 21 the Settlement Agreement have been attached as Exhibit DMW-1. New England Electric System Eastern Utilities Associates Testimony of D.M. Webster Page 4 1 Q. What impact will applying Mass. Electric's settlement depreciation rates have on 2 the depreciation expense of the consolidated entity? 3 A. Since Eastern Edison's depreciation rates are slightly higher than Mass. Electric's 4 depreciation rates, applying Mass. Electric's depreciation rates to the combined 5 entity will decrease depreciation expense by approximately $700,000 per year. 6 7 Q. Please explain how the estimated decrease in depreciation expense was calculated. 8 A. As shown in Exhibit DMW-2, depreciation expense was calculated for both Mass. 9 Electric and Eastern Edison based upon their present rates and then based upon 10 Mass. Electric's present depreciation rates. In each case, these rates were applied 11 against depreciable distribution plant balances as of December 31, 1998. 12 This methodology resulted in a depreciation expense amount of approximately 13 $73.5 million, for the combined entity using the Mass. Electric depreciation rates, 14 compared to a consolidated depreciation expense of approximately $74.2 million 15 with each company applying their current depreciation rates. 16 17 IV. STORM CONTINGENCY FUND 18 Q. Please describe the how the storm contingency fund works. 19 A. A storm contingency fund is a reserve recorded on the Company's books to pay 20 for service restoration costs as a result of a major storm. A major storm is defined 21 as one where the incremental operations and maintenance costs of restoring New England Electric System Eastern Utilities Associates Testimony of D.M. Webster Page 5 1 service exceeds a predetermined threshold amount for each utility. The fund is 2 only intended to reimburse each utility for operation and maintenance costs 3 associated with service restoration. The fund is not intended to reimburse the 4 utility for capital related costs. An annual contribution to the fund is embedded in 5 rates. Interest is also accumulated on the balance in the fund. 6 7 Q. Please describe Mass. Electric's storm fund. 8 A. As part of Mass. Electric's Settlement Agreement, the Department authorized 9 Mass. Electric to establish a storm contingency fund. Attached as Exhibit DMW-3 10 is the portion of the Settlement Agreement which establishes the parameters of the 11 storm contingency fund. As stated in Exhibit DMW-3, a major storm is defined 12 for Mass. Electric as one in which the incremental costs of service restoration 13 exceed $1.0 million. The storm fund was established when the Company 14 transferred $3.0 million to the storm fund from its Purchased Power Cost 15 Adjustment reconciliation account. Under the terms of the Settlement Agreement, 16 Mass. Electric was authorized to collect in rates $3.0 million annually for the 17 continued funding of the storm fund beginning on March 1, 1998, the date of 18 Retail Access. This level of funding shall continue until a modification is 19 approved by the Department. As of December 31, 1998, Mass. Electric had 20 accumulated a storm reserve balance of approximately $6.5 million. 21 New England Electric System Eastern Utilities Associates Testimony of D.M. Webster Page 6 1 Q. Please describe Eastern Edison's storm fund. 2 A. As part of Eastern Edison's Settlement Agreement in Docket No. D.P.U./D.T.E. 3 96-24, the Department authorized Eastern Edison to establish a storm contingency 4 fund. Attached as Exhibit DMW-4 is the portion of the settlement agreement 5 which establishes the parameters of the storm contingency fund. As stated in 6 Exhibit DMW-4, a major storm is defined for Eastern Edison as one in which the 7 incremental costs of service restoration exceed $250,000. On March 1, 1998, the 8 storm fund was established when Eastern Edison Company transferred $2.0 9 million to the storm fund from its Purchased Power Cost Adjustment 10 reconciliation account. Under the terms of Eastern Edison's restructuring 11 agreement, it is authorized to collect in rates $1.3 million annually for the 12 continued funding of the storm fund beginning on March 1, 1998, the date of 13 Retail Access. This level of funding will continue until a modification is 14 approved by the Department. As of December 31, 1998, Eastern Edison had 15 accumulated a storm reserve balance of approximately $3.3 million. 16 17 Q. Please describe the Company's proposal with respect to treatment of the storm 18 contingency funds. 19 A. As shown in Exhibit DMW-5, the Company proposes to combine the current 20 storm contingency fund balances and funding levels of Mass. Electric and Eastern 21 Edison. This will result in an accumulated storm contingency fund balance of New England Electric System Eastern Utilities Associates Testimony of D.M. Webster Page 7 1 approximately $9.8 million, as of December 31, 1998 and an annual funding 2 level of $4.3 million. The Company proposes to adopt Mass. Electric's threshold 3 amount of $1.0 million per storm occurrence for the combined entity since its 4 threshold amount is larger than Eastern Edison's. 5 6 Also attached as Exhibits DMW-6 is the storm contingency fund guidelines from 7 the Mass. Electric's Settlement Agreement marked to show changes for the 8 combined company under the proposal described above. Exhibit DMW-7 is the 9 clean version of Exhibit DMW-6. The Company is requesting that the Department 10 approve Exhibit DMW-7. 11 12 V. ENVIRONMENTAL RESPONSE FUND 13 Q. Could you please describe the purpose of an environmental response fund? 14 A. Yes. The environmental response fund is a reserve recorded on the books of each 15 utility which is used to pay for the remediation of hazardous waste sites. For 16 Mass. Electric, the fund is primarily used for remediation of Mass. Electric's 17 manufactured gas facilities formerly owned by Mass. Electric or an affiliate of 18 Mass. Electric. 19 20 Q. Please describe Mass. Electric's environmental response fund. New England Electric System Eastern Utilities Associates Testimony of D.M. Webster Page 8 1 A. In M.D.P.U. 93-194, Mass. Electric was authorized to establish an environmental 2 response fund on its books for remediation of hazardous waste sites. Relevant 3 excerpts from the settlement approved in M.D.P.U. 93-194 establishing the 4 environmental response fund has been attached as Exhibit DMW-8. 5 6 The fund was initially created by a $30 million contribution from Mass. Electric's 7 shareholders. Mass. Electric was then authorized to collect $3.0 million annually 8 from customers for additional funding of the environmental response fund. This 9 contribution amount is adjusted annually, effective the first day of October each 10 year, by the change in the Gross Domestic Product Implicit Price Deflator over 11 the previous twelve months. Mass. Electric was also authorized to provide interest 12 on the accumulated balance in the fund using the same methodology as the 13 interest paid on customer deposits. 14 15 As of December 31, 1998, Mass. Electric had recorded on its books a net liability 16 for hazardous waste site remediation costs of approximately $47.1 million, 17 including accrued interest on the fund balance. The annual contribution level for 18 the year October 1, 1998 through September 30, 1999 is estimated to be 19 approximately $3.3 million. 20 21 Q. Does Eastern Edison currently have a hazardous waste fund? New England Electric System Eastern Utilities Associates Testimony of D.M. Webster Page 9 1 A. No. It does not. 2 3 Q. What accounting treatment does Eastern Edison apply to hazardous waste costs? 4 A. Prior to 1995, Eastern Edison had a minimal amount of costs associated with 5 hazardous waste site remediation (less than $50,000 annually). However, during 6 the period January 1, 1995 through December 31, 1997, Eastern Edison incurred 7 approximately $1.1 million of hazardous waste clean-up costs at two sites. Eastern 8 Edison, for book purposes, deferred the clean-up costs for these sites and is 9 currently amortizing them over five years. As of December 31, 1998, Eastern 10 Edison had approximately $205,000 remaining of unamortized hazardous waste 11 site remediation costs. The amortization of these costs will be completed by the 12 end of the year 2000. 13 14 Q. What is the company's proposal with regard to the environmental response fund? 15 A. Mass. Electric proposes to charge Eastern Edison's environmental liabilities to the 16 hazardous waste fund upon completion of the merger to the same extent that 17 Mass. Electric's waste costs would be chargeable to the fund. 18 19 VI. OTHER AMORTIZATIONS AND ACCOUNTING ADJUSTMENTS 20 Q. Please explain the other amortization and accounting adjustments under the 21 Company's proposed rate plan. New England Electric System Eastern Utilities Associates Testimony of D.M. Webster Page 10 1 A. Currently Mass. Electric and Eastern Edison have certain deferrals that are 2 currently being recovered in rates. These amortizations include recovery of 3 unfunded deferred taxes and deferred FAS 106 costs as well as other regulatory 4 assets. The amortization of these items will be completed at various times during 5 the period of the rate plan. 6 7 Q. What is the Company's proposal with regards to these amortizations? 8 A. The Company proposes to consolidate the remaining deferral balances of each 9 item upon completion of the merger and continue the amortization until the 10 recovery of each item is complete. At that point the savings from the reduced 11 amortization offset the expected increase in other costs that will have occurred 12 during the rate freeze period. 13 14 Mass. Electric's current rates are based upon a test year ending March 31, 1996 15 and a projected rate year ended December 31, 1998. These rates do not include an 16 allowance for increases in costs through the end of the rate plan proposed by 17 the Company in this case. 18 19 VIII. CONCLUSION 20 Q. Does this conclude your testimony? 21 A. Yes, it does.
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ EXHIBITS OF DAVID M. WEBSTER Exhibit DMW-1 Summary of Depreciation Rates Exhibit DMW-2 Incremental Impact of Depreciation Rate Changes Exhibit DMW-3 Establishment of Mass. Electric Storm Contingency Fund Exhibit DMW-4 Establishment of Eastern Edison Storm Contingency Fimd Exhibit DMW-5 Summary of Storm Contingency Fund Balances Exhibit DMW-6 Consolidated Storm Contingency Fund (Marked to Show Changes) Exhibit DMW-7 Consolidation of Storm Contingency Funds (Clean Version) Exhibit DMW-8 Mass. Electric Environmental Response Fund New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit DMW-1 Exhibit DMW-1 Summary of Depreciation Rates New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit DMW-1 Page 1 of 1 MASSACHUSETTS ELECTRIC COMPANY AG Settlement Attachment 5 MASSACHUSETTS ELECTRIC COMPANY Cost of Service Supporting Schedule Summary of Depreciation Study Rates (000)
Net Depreciation Salvage Combined Acct Accrual Accrual Accrual No. Account Title Rate Rate Rate 1 2 353 Station Equipment 1.79% -0.04% 1.75% 3 355 Poles and Fixtures 2.03% -0.04% 1.99% 4 356 Overhead Conductors & Devices 1.86% -0.04% 1.82% 5 357 Underground Conduit 0.76% -0.04% 0.72% 6 358 Underground Conductors & Devices 1.15% -0.04% 1.11% 7 359 Roads and Trails 1.52% -0.04% 1.48% 8 9 10 361 Structures and Improvements 2.09% 0.74% 2.83% 11 362 Station Equipment 2.10% 0.74% 2.84% 12 13 14 15 364 Poles, Towers and Fixtures 3.32% 0.74% 4.06% 16 365 Overhead Conductors and Devices 3.16% 0.74% 3.90% 17 366 Underground Conduit 2.17% 0.74% 2.91% 18 367 Underground Conductors & Devices 2.37% 0.74% 3.11% 19 368 Line Transformers 3.71% 0.74% 4.45% 20 369 Services 3.22% 0.74% 3.96% 21 370 Meters 3.68% 0.74% 4.42% 22 372 Leased Property on Cust. Premises 7.81% 0.74% 8.55% 23 24 373 Street Lighting & Signal Systems 7.39% 0.74% 8.13% 25 26 27 28 390 Structures and Improvements 2.72% 0.20% 2.92% 29 391 Office Furniture and Equipment 6.67%1/ 30 393 Stores Equipment 6.67%1/ 31 394 Tools, Shop & Garage Equipment 6.67%1/ 32 395 Laboratory Equipment 6.67%1/ 33 397 Communications Equipment 6.67%1/ 34 398 Miscellaneous Equipment 6.67%1/ 35 36 1\ The depreciation study recommends the use of 15 year amortization 37 for all categories of general plant with the exception of A/C# 390. 38 39 40
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit DMW-2 Exhibit DMW-2 Incremental Impact of Depreciation Rate Changes
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit DMW-2 Page 1 of 4 Massachusetts Electric Company Incremental Impact of Depreciation Rate Changes 1 Applying Mass. Electric Applying Each Company's Incremental 2 Depreciation Rates for Depreciation Rates for Increase/ 3 Function Combined Entity Combined Entity (Decrease) 4 -------- ----------------------- ----------------------- ----------- 5 Distribution Plant $70,277,862 1/ $70,993,351 2/ ($715,489) 6 7 Transmission Plant $277,893 3/ $347,340 4/ ($69,447) 8 9 General Plant $2,914,920 5/ $2,812,827 6/ $102,093 10 11 Total $73,470,675 $74,153,518 ($682,843) =========== =========== ========= Notes: 1/ Exhibit DMW-2, Page 2, Column (b), Line 49. 2/ Exhibit DMW-2, Page 2, Column (b), Line 51. 3/ Exhibit DMW-2, Page 3, Column (b), Line 45. 4/ Exhibit DMW-2, Page 3, Column (b), Line 47. 5/ Exhibit DMW-2, Page 4, Column (b), Line 48. 6/ Exhibit DMW-2, Page 4, Column (b), Line 50. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit DMW-2 Page 2 of 4 Massachusetts Electric Company Incremental Impact of Depreciation Rate Changes 1 Massachusetts Eastern 2 PUC Electric Edison 3 Distribution Account Deprec. Rates Deprec. Rates ------------ ------- ------------- ------------- 4 361 2.83% 1.98% 5 362 2.84% 2.59% 6 364 4.06% 5.24% 7 365 3.90% 4.41% 8 366 2.91% 1.72% 9 367 3.11% 3.49% 10 368 4.45% 4.65% 11 369 3.96% 4.40% 12 370 4.42% 3.57% 13 373 8.13% 8.78% 14 15 Mass. Electric Eastern Edison 16 12/31/98 Plant Depreciation Depreciation 17 Depreciable Plant Balance Rates Rates 18 Mass. Electric 1/ Column (a) Column (b) Column (c) ----------------- ---------- -------------- -------------- 19 361 $8,608,358 $243,617 $170,445 20 362 $170,058,118 $4,829,651 $4,404,505 21 364 $263,442,408 $10,695,762 $13,804,382 22 365 $376,534,102 $14,684,830 $16,605,154 23 366 $94,725,017 $2,756,498 $1,629,270 24 367 $173,368,214 $5,391,751 $6,050,551 25 368 $215,285,252 $9,580,194 $10,010,764 26 369 $88,514,512 $3,505,175 $3,894,639 27 370 $73,188,383 $3,234,927 $2,612,825 28 373 $82,381,918 $6,697,650 $7,233,132 29 ---------- ---------- 30 Total $61,620,055 $66,415,667 31 ----------- ----------- 32 Mass. Electric Eastern Edison 33 12/31/98 Plant Depreciation Depreciation 34 Depreciable Plant Balance Rates Rates 35 Eastern Edison 2/ Column (a) Column (b) Column (c) ----------------- ---------- -------------- -------------- 36 361 $1,438,026 $40,696 $28,473 37 362 $21,840,403 $620,267 $565,666 38 364 $41,288,534 $1,676,314 $2,163,519 39 365 $39,792,789 $1,551,919 $1,754,862 40 366 $9,943,321 $289,351 $171,025 41 367 $26,112,335 $812,094 $911,320 42 368 $36,185,965 $1,610,275 $1,682,647 43 369 $17,478,576 $692,152 $769,057 44 370 $12,225,902 $540,385 $436,465 45 373 $10,139,657 $824,354 $890,262 46 --------- ---------- 47 Total $8,657,807 $9,373,296 48 ---------- ---------- 49 Total Depreciation $70,277,862 $75,788,963 50 51 Baseline 3/ $70,993,351 $70,993,351 52 ----------- ----------- 53 Variance ($715,489) $4,795,612 Notes: 1/ Mass. Electric's 1998 FERC Form 1, Page 207, Column (g), lines 56 through 68. 2/ Eastern Edison's 1998 FERC Form 1, Page 207, Column (g), lines 56 through 68. 3/ Line 30 Column (b) plus Line 47 Column (c) New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit DMW-2 Page 3 of 4 Massachusetts Electric Company Incremental Impact of Depreciation Rate Changes 1 Massachusetts Eastern 2 PUC Electric Edison 3 Transmission Account Deprec. Rates Deprec. Rates ------------ ------- ------------- ------------- 4 5 352 1.90% 1.85% 6 353 1.75% 2.69% 7 354 3.32% 2.75% 8 355 1.99% 2.79% 9 356 1.82% 2.67% 10 357 0.72% 0.00% 11 358 1.11% 0.00% 12 359 1.48% 1.27% 13 14 Mass. Electric Eastern Edison 15 12/31/98 Plant Depreciation Depreciation 16 Depreciable Plant Balance Rates Rates 17 Mass. Electric 1/ Column (a) Column (b) Column (c) ----------------- ---------- ------------- -------------- 18 19 352 $0 $0 $0 20 353 488,282 8,545 13,135 21 354 0 0 0 22 355 2,958,000 58,864 82,528 23 356 1,956,204 35,603 52,231 24 357 84,935 $612 0 25 358 250,648 2,782 0 26 359 67,155 $994 853 27 --- --- 28 Total $107,400 $148,747 29 ------- ------- 30 31 Mass. Electric Eastern Edison 32 12/31/98 Plant Depreciation Depreciation 33 Depreciable Plant Balance Rates Rates 34 Eastern Edison 2/ Column (a) Column (b) Column (c) ----------------- ---------- ------------- -------------- 35 36 352 $196,761 $3,738 $3,640 37 353 2,394,252 41,899 64,405 38 354 273,231 9,071 7,514 39 355 3,530,308 70,253 98,496 40 356 2,419,470 44,034 64,600 41 357 0 0 0 42 358 0 0 0 43 359 101,185 1,498 1,285 44 ------ ------ 45 Total $170,493 $239,940 -------- -------- 46 Total Depreciation $277,893 $388,687 47 48 Baseline 3/ $347,340 $347,340 -------- -------- 49 Variance ($69,447) $41,347 Notes: - ----- 1/ Mass. Electric's 1998 FERC Form 1, Page 207, Column (g), lines 45 through 52. 2/ Eastern Edison's 1998 FERC Form 1, Page 207, Column (g), lines 45 through 52. 3/ Line 26 Column (b) plus Line 42 Column (c). New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit DMW-2 Page 4 of 4 Massachusetts Electric Company Incremental Impact of Depreciation Rate Changes 1 Massachusetts Eastern 2 PUC Electric Edison 3 General Account Deprec. Rates Deprec. Rates ------- ------- ------------- ------------- 4 390 2.92% 2.66% 5 391 6.67% 4.26% 6 392 0.00% 3.13% 7 393 6.67% 4.22% 8 394 6.67% 3.00% 9 395 6.67% 2.63% 10 396 0.00% 3.13% 11 397 6.67% 5.10% 12 398 6.67% 8.41% 13 14 Mass. Electric Eastern Edison 15 12/31/98 Plant Depreciation Depreciation 16 Depreciable Plant Balance Rates Rates 17 Mass. Electric 1/ Column (a) Column (b) Column (c) ----------------- ---------- ------------- ------------- 18 390 $40,245,879 $1,175,180 $1,070,540 19 391 1,378,544 91,949 58,726 20 392 1,519,116 101,325 64,107 21 393 0 0 0 22 394 8,308,271 554,162 249,248 23 395 2,735,716 182,472 71,949 24 396 0 0 0 25 397 4,057,655 270,646 206,940 26 398 584,668 38,997 49,171 27 ------- ------- 28 Total 2,414,731 1,770,681 29 ---------- ---------- 30 31 Mass. Electric Eastern Edison 32 12/31/98 Plant Depreciation Depreciation 33 Depreciable Plant Balance Rates Rates 34 Eastern Edison 2/ Column (a) Column (b) Column (c) ----------------- ---------- ------------- ------------- 35 390 $9,125,340 266,460 $242,734 36 391 824,842 55,017 35,138 37 392 11,068 0 346 38 393 139,283 9,290 5,878 39 394 775,835 51,748 23,275 40 395 512,204 34,164 13,471 41 396 11,271 0 353 42 397 857,830 57,217 43,749 43 398 394,201 26,293 33,152 44 ------- ------- 45 Total $500,189 $398,096 46 -------- -------- 47 48 Total Depreciation $2,914,920 $2,168,777 49 50 Baseline 3/ $2,812,827 $2,812,827 51 ---------- ---------- 52 Variance $102,093 ($644,050) Notes: 1/ Mass. Electric's 1998 FERC Form 1, Page 207, Column (g), lines 72 through 81. 2/ Eastern Edison's 1998 FERC Form 1, Page 207, Column (g), lines 72 through 81. 3/ Line 28 Column (b) plus Line 45 Column (c).
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit DMW-3 Exhibit DMW-3 Establishment of Mass. Electric Storm Contingency Fund New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit DMW-3 Page 1 of 2 MASSACHUSETTS ELECTRIC COMPANY ELECTRIC INDUSTRY RESTRUCTURING--OFFER OF SETTLEMENT ESTABLISHMENT OF STORM CONTINGENCY FUND--POLICIES AND PROCEDURES Massachusetts Electric Company (Mass. Electric or the Company) shall establish a storm contingency fund to pay for the incremental costs incurred by the Company as a result of major storms. Major storms shall be defined as those storms with incremental costs of over $1.0 million occurring after the date the settlement proposal is approved by the Department of Public Utilities. The fund shall be established and maintained as follows: 1. Mass. Electric will pre-fund the storm contingency fund effective August 1, 1996 through a $3 million transfer from the Purchased Power Cost Adjustment reconciliation account. Interest will accrue immediately on the balance of the fund and will be accounted for as described in item 3 below. Beginning on the date the Retail Access Rates in Attachment 2 become effective and through the duration of the effective period of the Retail Access Rates included in Attachment 2 to this settlement proposal, Mass. Electric shall collect $3 million annually through base rates. The accounting entry to record monthly contributions to the fund will be the following, provided that the fund is in a positive position: DR Account 924 Property insurance-storm contingency CR Account 254 Storm contingency reserve The storm fund will be in a positive position when the cumulative amount collected through rates exceeds amounts disbursed from the fund to pay for major storm costs. 2. Upon the occurrence of a major storm, all incremental costs incurred as a result of the storm shall be offset against the balance in Account 254. If the incremental costs of major storms exceeds the balance in Account 254, such excess (i.e., a negative fund balance) shall be debited to Account 182, Deferred charges-storm fund. As long as the fund balance remains negative, the monthly entry to record the collection of storm fund proceeds will be: DR Account 924 Property insurance-storm contingency CR Account 182 Deferred charges-storm fund Incremental costs are defined as the costs which Mass. Electric will incur as a direct result of a storm which are over and above Mass. Electric's normal costs of doing business. These costs shall include such things as overtime paid to employees to restore service to customers, rest time wages incurred as a result of storm restoration (as stipulated in union contracts), outside vendor costs, lodging and meal charges, material and supply charges, and other. The storm fund is not intended to reimburse Mass. Electric for incremental capital costs. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit DMW-3 Page 2 of 2 3. Interest shall be accrued on any positive or negative balance in the fund, calculated in accordance with the Terms and Conditions for interest expense calculated on customer deposits. If the fund is in a positive position, the entry on Mass. Electric's books will be: DR Account 431 Interest expense CR Account 254 Storm contingency reserve If the fund is in a negative position, the entry on Mass. Electric's books will be: DR Account 182 Deferred charges-storm fund CR Account 419 Interest income 4. After the occurrence of a major storm, Mass. Electric will account for all amounts charged to the fund, and provide such accounting to the Department of Public Utilities and the Attorney General. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit DMW-4 Exhibit DMW-4 Establishment of Eastern Edison Storm Contingency Fund New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit DMW-4 Page 1 of 3 Eastern Edison Company Establishment of Storm Contingency Fund and Policies and Procedures Eastern Edison Company (Eastern Edison or the Company) shall establish a storm contingency fund to pay for the incremental costs incurred by the Company as a result of major storms. A major storm shall be defined as a storm with incremental costs exceeding $250,000. Effective January 1, 1998, retail rates will be deemed to provide for a $1.3M accrual annually. Eastern will report to the M.D.P.U. anytime it is drawing funds from this account to cover incremental costs greater than $250,000. Interest on the account balance (positive or negative) will be accrued monthly at Eastern Edison's short term borrowing rate. Incremental costs are defined as the costs which Eastern will incur as a direct result of a storm which are over and above Eastern Edison's normal costs of doing business. These costs shall include such items as overtime paid to employees to restore service to customers, rest time wages incurred as a result of storm restoration (as stipulated in union contracts or company policies), outside vendor costs, lodging and meal charges, material and supply charges, and other. The storm fund is not intended to reimburse Eastern for incremental capital costs. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit DMW-4 Page 2 of 3 The fund shall be established and maintained as follows: 1. Eastern will pre-fund the storm contingency fund through a $2 million transfer from the reserve established from Montaup's 1996 PCAC refund. Interest will accrue immediately on the balance of the fund and will be accounted for as described in item 3 below. Beginning on the date the Retail Access Rates become effective, Eastern Edison's base rates shall be deemed to collect $1.3 million annually to be contributed to the storm contingency fund and continuing until these rates are superseded by new rates resulting from a base rate revenue requirement rate proceeding. The accounting entry to record monthly contributions to the fund will be the following, provided that the fund is in a positive position: DR Account 924 Property insurance-storm contingency CR Account 254 Storm contingency reserve The storm fund will be in a positive position when the cumulative amount collected through rates exceeds amounts disbursed from the fund to pay for major storm costs. 2. Upon the occurrence of a major storm, all incremental costs incurred as a result of the storm shall be offset against the balance in Account 254. If the incremental costs of major storms exceeds the balance in Account 254, such excess (i.e., a negative fund balance) shall be debited to Account 182, Deferred charges-storm fund. As long as the fund balance remains negative, the monthly entry to record the collection of storm fund proceeds will be: DR Account 924 Property insurance-storm contingency CR Account 182 Deferred charges-storm fund New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ____ Exhibit DMW-4 Page 3 of 3 3. Interest shall be accrued on any positive or negative balance in the fund, calculated in accordance with the Terms and Conditions for interest expense calculated on customer deposits. If the fund is in a positive position, the entry on Eastern Edison's books will be: DR Account 431 Interest expense CR Account 254 Storm contingency reserve If the fund is in a negative position, the entry on Eastern Edison's books will be: DR Account 182 Deferred charges-storm fund CR Account 419 Interest income 4. After the occurrence of a major storm, Eastern Edison will account for all amounts charged to the fund, and provide such accounting to the Department of Public Utilities and the Attorney General. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit DMW-5 Exhibit DMW-5 Summary of Storm Contingency Fund Balances New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit DMW-5 Page 1 of 1
Massachusetts Electric Company Summary of Storm Contingency Fund Balances Massachusetts Eastern Combined Electric Edison Entity 1. Balance in Storm Fund as of 2. December 31, 1998 $6,446,735 1/ $3,346,004 2/ $9,792,739 3. 4. Annual Storm Fund Contributions 5. Collected through Revenue $3,000,000 3/ $1,300,000 4/ $4,300,000 6. 7. Deductible Amount per each 8. Storm Occurrence $1,000,000 $250,000 $1,000,000
Notes: 1/ Mass. Electric's 1998 FERC Form 1, page 232. 2/ Eastern Edison's 1998 FERC Form 1, page 232. 3/ Annual Deferral Recovery per Settlement Agreement in M.D.P.U. Nos. 96-100 and 96-25. 4/ Annual Deferral Recovery per Settlement Agreement in M.D.P.U. Nos. 96-100 and 96-24. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit DMW-6 Exhibit DMW-6 Consolidated Storm Contingency Fund (Marked to Show Changes) New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. _____ Exhibit DMW-6 Page 1 of 2 Massachusetts Electric Company NEES/EUA Merger Proceeding Consolidation of Storm Contingency Funds--Polices and Procedures Massachusetts Electric Company (Mass. Electric or the Company) shall [maintain] [[establish]] a storm contingency fund to pay for the incremental costs incurred by the Company as a result of major storms. Major storms shall be defined as those storms with incremental costs of over $1.0 million [[occurring after the date the settlement proposal is approved by the Department of Public Utilities]]. The fund shall be established and maintained as follows: 1. Mass. Electric will [consolidate the existing storm contingency fund balances of Mass. Electric and Eastern Edison upon the completion of the merger] [[prefund the storm contingency fund effective August 1, 1996 through a $3 million transfer from the Purchased Power Cost Adjustment reconciliation account]]. Interest will accrue immediately on the balance of the fund and will be accounted for as described in item 3 below. Beginning on the [Rate Consolidation date, planned for January 1, 2001,] [[the Retail Access Rates in Attachment 2 become effective and through the duration of the effective period of the Retail Access Rates included in attachment 2 to this settlement proposal,]] Mass. Electric shall collect $[4.3] [[3]] million annually through base rates. The accounting entry to record monthly contributions to the fund will be the following, provided that the fund is in a positive position: DR Account 924 Property insurance-storm contingency CR Account 254 Storm contingency reserve The storm fund will be in a positive position when the cumulative amount collected through rates exceeds amounts disbursed from the fund to pay for major storm costs. 2. Upon the occurrence of a major storm, all incremental costs incurred as a result of the storm shall be offset against the balance in Account 254. If the incremental costs of major storms exceeds the balance in Account 254, such excess (i.e. a negative fund balance) shall be debited to Account 182, Deferred charges-storm fund. As long as the fund balance remains negative, the monthly entry to record the collection of storm fund proceeds will be: Legend: [ ] = insertion [[ ]] = deletion New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. Exhibit DMW-6 Page 1 of 2 DR Account 924 Property insurance-storm contingency CR Account 182 Deferred charges-storm fund Incremental costs are defined as the costs which Mass. Electric will incur as a direct result of a storm which are over and above Mass. Electric's normal costs of doing business. These costs shall include such things as overtime paid to employees to restore service to customers, rest time wages incurred as a result of storm restoration (as stipulated in union contracts), outside vendor costs, lodging and meal charges, material and supply charges, and other. The storm fund is not intended to reimburse Mass. Electric for incremental capital costs. 3. Interest shall be accrued on any positive or negative balance in the fund, calculated in accordance with the Terms and Conditions for interest expense calculated on customer deposits. If the fund is in a positive position, the entry on Mass. Electric's books will be: DR Account 431 Interest expense CR Account 254 Storm contingency reserve If the fund is in a negative position, the entry on Mass. Electric's books will be: DR Account 182 Deferred charges-storm fund CR Account 419 Interest income 4. After the occurrence of a major storm, Mass. Electric will account for all amounts charged to the fund, and provide such accounting to the Department of Public Utilities and the Attorney General. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit DMW-7 Exhibit DMW-7 Consolidation of Storm Contingency Funds (Clean Version) New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. _____ Exhibit DMW-7 Page 1 of 2 Massachusetts Electric Company NEES/EUA Merger Proceeding Consolidation of Storm Contingency Funds--Polices and Procedures Massachusetts Electric Company (Mass. Electric or the Company) shall maintain a storm contingency fund to pay for the incremental costs incurred by the Company as a result of major storms. Major storms shall be defined as those storms with incremental costs of over $1.0 million. The fund shall be established and maintained as follows: 1. Mass. Electric will consolidate the existing storm contingency fund balances of Mass. Electric and Eastern Edison upon the completion of the merger. Interest will accrue immediately on the balance of the fund and will be accounted for as described in item 3 below. Beginning on the Rate Consolidation date, planned for January 1, 2001, Mass. Electric shall collect $4.3 million annually through base rates. The accounting entry to record monthly contributions to the fund will be the following, provided that the fund is in a positive position: DR Account 924 Property insurance-storm contingency CR Account 254 Storm contingency reserve The storm fund will be in a positive position when the cumulative amount collected through rates exceeds amounts disbursed from the fund to pay for major storm costs. 2. Upon the occurrence of a major storm, all incremental costs incurred as a result of the storm shall be offset against the balance in Account 254. If the incremental costs of major storms exceeds the balance in Account 254, such excess (i.e. a negative fund balance) shall be debited to Account 182, Deferred charges-storm fund. As long as the fund balance remains negative, the monthly entry to record the collection of storm fund proceeds will be: DR Account 924 Property insurance-storm contingency CR Account 182 Deferred charges-storm fund Incremental costs are defined as the costs which Mass. Electric will incur as a direct result of a storm which are over and above Mass. Electric's normal costs of doing business. These costs shall include such things as overtime paid to employees to restore service to customers, rest time wages incurred as a result of storm restoration (as stipulated in union contracts), outside vendor costs, lodging and meal charges, material and supply charges, and other. The storm fund is not intended to reimburse Mass. Electric for incremental capital costs. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. _____ Exhibit DMW-7 Page 2 of 2 3. Interest shall be accrued on any positive or negative balance in the fund, calculated in accordance with the Terms and Conditions for interest expense calculated on customer deposits. If the fund is in a positive position, the entry on Mass. Electric's books will be: DR Account 431 Interest expense CR Account 254 Storm contingency reserve If the fund is in a negative position, the entry on Mass. Electric's books will be: DR Account 182 Deferred charges-storm fund CR Account 419 Interest income 4. After the occurrence of a major storm, Mass. Electric will account for all amounts charged to the fund, and provide such accounting to the Department of Public Utilities and the Attorney General. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit DMW-8 Exhibit DMW-8 Mass. Electric Environmental Response Fund New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ___ Exhibit DMW-8 Page 1 of 6 B. Rate Treatment for Environmental Response Costs. 1. Mass. Electric shall establish on its books a fund for hazardous waste clean up and liabilities. The fund will pay for Environmental Response Costs paid after June 30, 1993. Environmental Response Costs are defined as: (a) Reasonable and prudently incurred costs or expenses associated with the investigation, testing, remediation, or other liabilities attributable to NEES and its current subsidiaries relating to gas manufacturing facility sites, disposal sites, sites to which material may have migrated, or any sites at which manufactured gas waste may have been deposited as a result of the earlier operation or decommissioning of gas manufacturing facilities located in Massachusetts; (b) Reasonable and prudently incurred costs or expenses (excluding all fines or penalties) associated with the investigation, New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ___ Exhibit DMW-8 Page 2 of 6 testing, remediation, or other liabilities attributable to Mass. Electric relating to material regulated under the statutes in subparagraph B.1.(d) unrelated to Massachusetts gas manufacturing facilities deposited before 1980 on sites or migrating to sites as a result of the operations of Mass. Electric or its predecessor companies; (c) Reasonable and prudently incurred costs or expenses associated with the purchase of property that is acquired as part of an overall mitigation and response plan associated with sites identified in subparagraph B.1.(a) and B.1.(b); and (d) Reasonable and prudently incurred payments for liabilities, damages, claims, settlements, or judgments arising from Subparagraphs B.1.(a) and B.1.(b) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), Resource Conservation and Recovery Act (RCRA), Massachusetts G.L. c. 21C and 21E, and any other laws, regulations or orders by courts or governmental authorities, or resulting from claims and contentions arising in tort, breach of contract, or violation of law. Except for property acquired under Paragraph B.1.(c), Environmental Response Costs shall not include costs or expenses associated with the investigation, testing, remediation, or other liabilities relating to property acquired after the Approval Date. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ___ Exhibit DMW-8 Page 3 of 6 2. The fund shall be financed by: (a) A $30 million shareholder contribution will be credited to the fund effective as of October 1, 1993; (b) (i) Annual contributions by Mass. Electric of $3.0 million commencing as of October 1, 1993, adjusted each October 1 for changes to the Gross Domestic Product Implicit Price Deflator (GDPIPD) occurring after October 1, 1993. One-twelfth of the annual amount shall be credited to the fund each month. (ii) Interest free loans to the fund by Mass. Electric to the extent that the balance in the fund is inadequate to make the payments from the fund required under Paragraph B.1. (c) Proceeds from insurance companies related to Environmental Response Costs, proceeds from the sale of properties purchased under subparagraph B.1.(c), repayments of discounts as required under Paragraph C.1.(c), and recoveries from third parties, including natural gas companies; and (d) Interest on the fund credited each October 1 and calculated using the methodology for calculating interest on customer deposits specified in Mass. Electric's terms and conditions. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ___ Exhibit DMW-8 Page 4 of 6 3. Rate recovery for Mass. Electric shall be as follows: (a) Mass. Electric's contributions and loans to the fund under Paragraph B.2.(b) shall be includable in Mass. Electric's cost of service and recoverable in Mass. Electric's rates based on the kilowatthour consumption in each rate class. This recovery shall occur regardless of the prudence of the operations that have given rise to the Environmental Response Costs, provided, however, that nothing in this Offer of Settlement shall: (1) prevent any party from contending in either a general rate filing or a quarterly adjustment proceeding that the costs associated with clean up activities were unreasonable or imprudent or (2) relieve Mass. Electric of the obligation to demonstrate that its actions and the costs incurred associated with any cleanup activities were reasonable and prudent. To the extent that the Department concludes that any costs incurred after the test year in Mass. Electric's prior general rate case have not been demonstrated to be reasonable and prudent, Mass. Electric shall credit such amounts with interest back to the fund. Mass. Electric's recovery of these costs shall be implemented in the following manner: (i) Mass. Electric's annual contribution as adjusted under subparagraph B.2.(b)(i) shall be recovered in base rates. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ___ Exhibit DMW-8 Page 5 of 6 (ii) Any loans made by Mass. Electric under subparagraph B.2.(b)(ii) shall be amortized without interest or carrying charges over seven years and recovered net of the value of the rate base deduction associated with any deferred tax balances on the unamortized amounts through a separate quarterly adjustment included with the adjustment calculated under Mass. Electric's Standard Fuel Clause using the formula included in Attachment 1 to this Offer of Settlement. This recovery shall occur over the twelve months commencing on April 1 of the year following the year in which the loan was made. This Paragraph B.3.(a) shall be the exclusive method for rate recovery of the costs defined in Paragraph B.1. (b) All reasonable and prudently incurred fees and costs associated with law firms and consultants outside of Mass. Electric and its affiliates to defend or prosecute claims or liabilities under Paragraph B.1. shall be paid directly by Mass. Electric and shall not be paid by the fund. To the extent that these fees and costs are reasonable, prudent, and related to the Environmental Response Costs defined in Paragraph B.1., they shall be recoverable in Mass. Electric's base rates based on an historical three year rolling average. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. ___ Exhibit DMW-8 Page 6 of 6 4. Every three years, the Parties to this Settlement shall reevaluate the annual amount contributed to the fund under Paragraph B.2.(b)(i) for its ability together with the loans under Paragraph B.2.(b)(ii) to provide sufficient resources to satisfy future Environmental Response Costs in a prudent and reasonable fashion; provided, however, that under no circumstances shall the amounts contributed under Paragraph B.2.(b)(i) be increased. At the completion of payment and rate recovery for all Environmental Response Costs, any balance remaining in the fund shall be returned to customers. 5. Mass. Electric shall file with the Department semi-annually the information set forth in Attachment 2. COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ---------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ---------------------------------- DIRECT TESTIMONY OF THERESA M. BURNS COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ---------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ---------------------------------- DIRECT TESTIMONY OF THERESA M. BURNS Table of Contents Page I. Introduction and Qualifications..................................... 1 II. Purpose of Testimony................................................ 2 III. Summary of Mass. Electric's Current Rates........................... 3 IV. Summary of Eastern Edison's Current Rates........................... 5 V. Proposed Rate Plan.................................................. 7 General.................................................... 7 Distribution............................................... 12 Transmission............................................... 13 Transition................................................. 15 Results of Rate Plan on Retail Delivery Revenue............ 16 VI. Typical Bills....................................................... 18 VII. Tariffs and Terms and Conditions.................................... 25 VIII. Conclusion.......................................................... 27
New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 1 of 27 1 I. Introduction and Qualifications 2 Q. Please state your full name and business address. 3 A. Theresa M. Burns, 25 Research Drive, Westborough, Massachusetts 01582. 4 5 Q. Please state your position. 6 A. I am a Principal Rate Analyst for New England Power Service Company ("NEPSCO"), 7 performing rate related services for companies in the New England Electric System, 8 including Massachusetts Electric Company ("Mass. Electric" or "the Company"). 9 10 Q. Please describe your educational background and training. 11 A. I graduated from Babson College in Wellesley, Massachusetts with a Bachelor of Science 12 degree in Accounting in 1986. In 1994, I received a Masters in Business Administration 13 from Babson College. I am a certified public accountant and a member of the 14 Massachusetts Society of Certified Public Accountants. 15 16 Q. Please describe your professional experience. 17 A. From 1986 to 1990, I was an auditor for Ernst & Young in Boston, Massachusetts. In 18 June 1990, I joined NEPSCO as an Accounting Analyst in the Financial Analysis Group 19 of the General Accounting Department. In June 1991, I was given responsibility over New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 2 of 27 1 general ledger accounting for NEPSCO's three retail affiliates. In July 1993, I joined the 2 Internal Audit Department and was responsible for performing both financial and 3 operational audits. In June 1994, I was promoted to Senior Internal Auditor. In July 4 1995, I transferred to the Rate Department as a Senior Rate Analyst. In this position, I 5 have been responsible for the design and implementation of retail access rates. In April 6 1999, I was promoted to Principal Rate Analyst, with responsibility over Mass. Electric's 7 and Granite State Electric Company's retail rate design and implementation. 8 9 Q. Have you previously testified before the Department of Telecommunications and Energy 10 ("the Department")? 11 A. Yes I have. I have submitted pre-filed testimony and testified for Nantucket Electric 12 Company's Cable Facilities Surcharge. I have also testified in Massachusetts Electric 13 Company's Docket Nos. 98-69 and 98-76, Proposals for Alternative Street lighting 14 Service and Purchase Price Methodology for the sale of streetlights pursuant to Section 196 of the 15 Restructuring Act. 16 17 II. Purpose of Testimony 18 Q. What is the purpose of your testimony? 19 A. My testimony presents the Company's proposed rate plan with Eastern Edison Company New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 3 of 27 1 ("Eastern"), upon the Company's merger with Eastern following completion of the 2 acquisition of Eastern Utilities Associates ("EUA") by New England Electric System 3 ("NEES"), as described in the testimony of Mr. Jesanis. I will first provide a brief 4 summary of both Mass. Electric's and Eastern's current rates on a total company basis as 5 approved by the Department. Second, I will describe the proposed rate plan which will 6 serve as a means of consolidating the rates of Mass. Electric and Eastern onto one set of 7 retail delivery service tariffs. Third, I will present the anticipated effects of the proposed 8 rate plan on revenue, both at the component level (i.e., distribution, transmission and 9 transition individually) and at the retail delivery service level (i.e., distribution, 10 transmission and transition collectively). Finally, I will discuss the application of tariffs, 11 provisions, and terms and conditions to the combined company. 12 13 III. Summary of Mass. Electric's Current Rates 14 Q. Please provide a brief summary of Mass. Electric's current rates. 15 A. Exhibit TMB-1 illustrates Mass. Electric's total average rates for various time periods, 16 both historic and projected. The rates consist of several specific components: distribution 17 charges, transmission charges, transition charges, and DSM and renewables charges 18 (together "delivery rates"). In addition, customers have the option to take standard 19 service or to purchase electricity from the competitive market. In accordance with the New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 4 of 27 1 Company's Settlement Agreement in Docket No. 96-25 ("Settlement"), distribution rates 2 were approved by the Department to collect, on average 2.502(cent) per kilowatt-hour. The 3 distribution component of the delivery rate is to be maintained at its current levels 4 through calendar year 2000. The Company is allowed to file a general rate case to adjust 5 distribution rates for dates on or after January 1, 2001. Demand side management and 6 renewables charges are in accordance with the Electric Utility Restructuring Act of 1997 7 ("the Act"). 8 9 The Company's current average transmission rate of 0.641(cent) per kilowatt-hour as 10 approved by the Department collects both the current projection of transmission costs for 11 calendar year 1999 of 0.535(cent) per kilowatt-hour plus the recovery of an under collection 12 of transmission costs for the reconciliation period March 1, 1998 through September 30, 13 1998 of 0.106(cent) per kilowatt-hour. Mass. Electric's transmission rate recovers on a fully 14 reconciling basis the costs it incurs to provide transmission service to its customers. The 15 Company currently incurs transmission costs from New England Power Company 16 ("NEP"), as allocated to it by its load ratio share of NEP's total transmission costs, New 17 England Power Pool ("NEPOOL") and the Independent System Operator of New 18 England ("ISO"). The Company's transmission rate to its retail customers is a uniform 19 cents per kilowatt-hour charge unique to each rate class based upon an allocation of New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 5 of 27 1 transmission costs billed to it by NEP, NEPOOL and the ISO to each rate class. This 2 allocation is based on each rate class' demand at the time of NEP's peak, which is 3 analogous to the method with which NEP bills Mass. Electric. 4 5 The Company's current average transition charge of 1.328(cent) per kilowatt-hour as 6 approved by the Department reflects the contract termination charge being billed to it by 7 NEP of 1.339(cent) per kilowatt-hour, reduced by the refund of an over collection of transition 8 charge revenue for the reconciliation period March 1, 1998 through September 30, 1998 9 of 0.011(cent) per kilowatt-hour. Mass. Electric's transition charge recovers on a fully 10 reconciling basis the contract termination charge billed to it by NEP, and is a uniform 11 cents per kilowatt-hour charge for all rate classes other than the Company's Rate R-4, 12 Residential Time-of-Use (Optional), which maintains and on peak and off peak price 13 differential to ensure the rate reductions required under the Act. 14 15 IV. Summary of Eastern's Current Rates 16 Q. Please provide a brief summary of Eastern's current rates. 17 A. Exhibit TMB-2 illustrates Eastern's total average rates for various time periods, both 18 historic and projected. In accordance with Eastern's Settlement Agreement in Docket 19 No. 96-24, the distribution component of the delivery rate was approved by the New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 6 of 27 1 Department to collect, on average 2.743(cent) per kilowatt-hour. Similar to Mass. Electric's 2 Settlement, distribution rates are to be maintained at their current levels through calendar 3 year 2000. Eastern is also entitled to file a general rate case to adjust distribution rates, to 4 take effect on or after January 1, 2001. As with Mass. Electric, demand side management 5 and renewables charges are in accordance with the Act. 6 7 Eastern's current average transmission rate for calendar year 1999 is 0.298(cent) per kilowatt- 8 hour. Eastern's transmission rate is essentially the transmission rate of Montaup Electric 9 Company ("Montaup"), and recovers actual transmission costs that Montaup, NEPOOL, 10 and the ISO incur to provide transmission service to retail customers based on an historic 11 test year. These costs are allocated to Eastern, Blackstone Valley Electric Company, and 12 Newport Electric Company customers on a monthly basis and are divided by the total 13 monthly kilowatt-hours of the affiliate companies to arrive at a retail transmission rate 14 that Eastern will bill its customers on behalf of Montaup. Montaup's transmission rate, 15 as billed by Eastern, is a uniform cents per kilowatt-hour charge to all retail customers of 16 Montaup's affiliated companies. 17 18 Eastern's current average transition rate of 2.100(cent) per kilowatt-hour reflects the contract 19 termination charge being billed to it by Montaup. Eastern's transition charge recovers on New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 7 of 27 1 a fully reconciling basis Montaup's contract termination charge billed to Eastern, and is 2 billed to customers at differing rate structures, depending upon a customer's rate class. A 3 designed transition charge is included in the Rate R-4 Residential Time-of-Use tariff, and 4 the majority of General Service tariffs, while all other rate classes are billed at a uniform 5 cents per kilowatt-hour level. 6 7 V. Proposed Rate Plan 8 General 9 Q. Please provide a general description of the Company's proposed rate plan. 10 A. The Company's proposal for consolidating the rates of Eastern and Mass. Electric is 11 discussed in the testimony of Mr. Jesanis. As he explains, the rate consolidation and 12 distribution rate freeze will produce a reduction of $23.1 million, or 14.2%, in Eastern's 13 delivery rate in calendar year 2001. Mr. Jesanis's savings amount is based on projected 14 kilowatt-hour deliveries in calendar year 2001. In contrast, my exhibits, based on actual 15 billing determinants in calendar year 1998, reflect a savings amount of only $19.6 million 16 (see Exhibit TMB-7). My analysis also does not reflect the benefits of the distribution 17 rate freeze. As Mr. Bonner explains, the use of actual 1998 billing determinants is 18 necessary for the mapping process and its impacts. The Company is proposing to 19 consolidate all rates of Mass. Electric and Eastern effective on the first day of the billing New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 8 of 27 1 month of January 2001 ("Consolidation Date"). As I present below, the proposed rate 2 consolidation slightly increases distribution and transmission charges to Eastern's 3 customers, but these increases are more than offset by a significant reduction in Eastern's 4 transition charge. Mass. Electric's delivery rate increases slightly over the level 5 anticipated without the merger as the result of the blended transition charge, but still 6 declines in calendar year 2001 below the level expected for calendar year 2000, before 7 the proposed rate consolidation. 8 9 The proposed rate consolidation process begins with an analysis of the availability 10 provisions in the tariffs of the two companies. The rate classes of Eastern under which 11 Eastern's customers are served immediately prior to consolidation are proposed to be 12 mapped over to Mass. Electric's rate classes, as illustrated in Exhibit TMB-3. This 13 proposed rate mapping is performed by referencing the availability provisions of 14 Eastern's retail delivery service tariffs and matching each tariff to a corresponding Mass. 15 Electric retail delivery service tariff. As a result of this review, several Eastern general 16 service rates map to more than one Mass. Electric general service rate. This occurs 17 because the availability provisions of Eastern's general service tariffs encompass a wider 18 range of customer usage levels than those of Mass. Electric's general service tariffs. 19 Accordingly, the billing determinants under Eastern's retail delivery service tariffs have New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 9 of 27 1 been accumulated to match the availability provisions of Mass. Electric's retail delivery 2 service tariffs. The testimony of Mr. Bonner supports in more detail the rate mapping 3 process and the billing determinants that the Company is using as part of its proposed rate 4 plan and its effect on revenue. Once all of Eastern's customers are placed on the 5 appropriate Mass. Electric rate, all customers will be charged the same rates for 6 distribution, transmission, and transition as well as standard service, default service, 7 demand side management, and renewables. 8 9 Q. How will Mass. Electric implement the consolidated rates for Eastern's customers? 10 A. Mass. Electric will implement the consolidated rates for Eastern's customers on a bills 11 rendered basis for meter readings on and after the Consolidation Date. Because of the 12 complexity of separate billing systems and rate structures, a shift from Eastern's rates to 13 Mass. Electric's consolidated rates must occur on a bills rendered basis. Proration of 14 usage among two entirely different billing systems and rate structures is extremely 15 difficult and introduces needless complexity for customers, who would receive two 16 separate bills for one billing period under a prorated approach. Thus, the change on a 17 bills rendered basis ensures the proper billing of all usage between the meter reading 18 immediately subsequent to the Consolidation Date and the meter reading immediately 19 prior to the Consolidation Date. Under the Company's proposal, bills issued to Eastern's New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 10 of 27 1 customers for the billing period following the Consolidation Date will be based on Mass. 2 Electric's consolidated rates. 3 4 Q. Is the Company evaluating the adequacy of customer's meters for billing Mass. Electric's 5 rates as part of the rate consolidation? 6 A. Yes. First, Eastern's peak hours period is significantly different than Mass. Electric's 7 peak hours period. This will affect both the quantity of on peak kilowatt-hours in a 8 billing period once Eastern's time-of-use customers are placed on Mass. Electric's time- 9 of-use rates as well as the billing demand for the large general service customers 10 (maximum kilowatt usage during the peak hours period). Meters for these customers will 11 require reprogramming or replacement. Mass. Electric's medium general service 12 customers are charged uniform energy charges and their billing demand is based on the 13 maximum kilowatts used in all hours. Thus, for Eastern's general service customers 14 transferring to Mass. Electric's medium general service rate, meter configurations will be 15 evaluated and reprogrammed or replaced as needed. Additionally, some of Eastern's 16 large general service customers are not currently served on a time-of-use rate, and will be 17 placed on Mass. Electric's large general service rate which includes time-of-use pricing. 18 Meters for these customers will be replaced. Mass. Electric also determines billing 19 demand based on a comparison of kilowatts to kilovolt amperes. Eastern does not have New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 11 of 27 1 this provision in its general service tariffs, therefore kilovolt ampere meters are not 2 installed at customer locations. As part of all of Eastern's general service customers 3 transferring to Mass. Electric's medium and large general service tariffs, kilovolt ampere 4 meters will be installed at these customer locations requiring such meters. 5 6 Q. Who will be evaluating and performing these meter activities? 7 A. Mass. Electric's Meter Operations and Engineering group and its counterpart at Eastern, 8 along with Customer Service, will be identifying customers affected by required meter 9 activity and implementing the necessary changes. Meters will be reprogrammed, 10 replaced, or installed as soon as possible after the merger is approved to ensure the proper 11 billing of Mass. Electric's distribution rates. If kilovolt ampere meters are not installed 12 by the first billing cycle after the Consolidation Date at a customer's location, the 13 customer will have its demand charge based on maximum kilowatts registered until a 14 kilovolt ampere meter can be installed. 15 16 Q. What impact will the meter changes have on the revenues following the proposed 17 consolidation? 18 A. Mass. Electric and Eastern have attempted to redefine the billing units used in this filing 19 for Mass. Electric's peak hours period. This is explained more fully in Mr. Bonner's New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 12 of 27 1 testimony. Therefore, on peak kilowatt-hours and billing demand are estimated under 2 Mass. Electric's rates. Mass. Electric has not attempted to determine the effect on 3 kilovolt ampere usage on billing demand. Therefore, the demand-based revenue 4 calculated in this filing may increase with the installation of kilovolt ampere meters, 5 providing that the maximum kilowatts is less than 90 percent of the maximum kilovolt 6 amperes. Consequently, Eastern's savings projected following the proposed rate 7 consolidation may drop slightly. Moreover, the billing determinants presented in this 8 filing are actual units from calendar year 1998, and amounts and values will change when 9 the rates are applied to actual usage in calendar year 2001. 10 11 Distribution 12 Q. What is the Company's plan for consolidating the distribution rates of both Mass. Electric 13 and Eastern? 14 A. The Company is proposing to transfer Eastern's customers from Eastern's distribution 15 rates to those of Mass. Electric. Mass. Electric's distribution rates have been frozen since 16 March 1, 1998. As part of this proposal, Mass. Electric will extend its current 17 distribution rate freeze that expires on December 31, 2000, for either two or four 18 additional years. Mr. Jesanis describes the conditions behind the term of the freeze. 19 New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 13 of 27 1 Q. What is the estimated impact on Mass. Electric's distribution revenue generated from 2 Eastern's customers? 3 A. The movement of Eastern's customers to Mass. Electric's distribution rates is projected to 4 increase distribution revenues from Eastern's customers by approximately $2.6 million 5 over the distribution revenues under Eastern's current distribution rates. The revenue 6 comparison is shown on Exhibit TMB-4. This exhibit determines the annual normalized 7 distribution revenue of Eastern's customers, both on Eastern's current distribution rates 8 and Mass. Electric's current distribution rates. This analysis, along with many other total 9 company and total rate class analyses included in this filing, are based on calendar year 10 1998 billing determinants, and are explained in more detail in the testimony of Mr. 11 Bonner. 12 13 Transmission 14 Q. How will transmission costs be billed after the Consolidation Date? 15 A. After the Consolidation Date, Eastern's customers and Mass. Electric's customers will be 16 charged a consolidated transmission rate. If the NEP and Montaup transmission rates are 17 not fully consolidated, then the retail consolidated transmission rate will be based on the 18 sum of the projected Montaup transmission bill to Mass. Electric's retail delivery service 19 customers in the former Eastern service territory and the projected NEP bill to Mass. New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 14 of 27 1 Electric's existing retail delivery service customers for transmission service along with 2 projected bills from NEPOOL and the ISO to arrive at a total transmission expense for 3 the combined company. Once the NEP and Montaup transmission rates are consolidated, 4 NEP will issue one transmission bill to Mass. Electric that will include transmission 5 service to the combined retail delivery service customer base, and Mass. Electric will 6 continue to be allocated transmission costs from NEPOOL and the ISO. The Company 7 will then allocate the total transmission expense of the combined company to Mass. 8 Electric's rate classes based on coincident peak demand, a methodology that has 9 previously been used by Mass. Electric and approved by the Department. This allocation 10 ensures that transmission costs are allocated to each rate class based on how they 11 contribute to those costs. After allocating transmission expenses to the individual rate 12 classes, the Company will calculate a uniform cents per kilowatt-hour transmission rate 13 unique to each rate class to be charged equally to all customers of the particular rate class. 14 This calculation is illustrated in Workpaper TMB-3. 15 16 Q. What is the effect of the consolidation of transmission costs on transmission revenue 17 generated from Eastern's customers? 18 A. Consolidating the transmission rates of Eastern and Mass. Electric into one transmission 19 rate will result in Eastern's customers contributing additional transmission revenue above New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 15 of 27 1 what they otherwise would have contributed absent the consolidation. Exhibit TMB-5 2 illustrates the effect of consolidating transmission rates on the customers of Eastern as 3 compared to the average transmission rate these customers are projected to be charged in 4 calendar year 2001. Eastern's customers are expected to see an increase of approximately 5 $6 million in the transmission component of their delivery rate, as indicated in this 6 exhibit. Mass. Electric's transmission expenses from NEP, NEPOOL, and the ISO are 7 higher per kilowatt-hour than Eastern's transmission expenses from Montaup, NEPOOL, 8 and the ISO. Thus, blending the transmission rates reduces the transmission component 9 of Mass. Electric's delivery rate to Mass. Electric's existing customers and increases the 10 transmission component of the delivery rate to Eastern's existing customers. 11 12 Transition 13 Q. What is the Company's proposal for billing transition charges after the Consolidation 14 Date? 15 A. Mass. Electric is proposing to move Eastern's customers and Mass. Electric's customers 16 onto a consolidated transition charge. This consolidated transition charge will sum the 17 Montaup contract termination charge bill to Eastern and the NEP contract termination 18 charge bill to Mass. Electric to arrive at a total contract termination charge for the 19 combined company. This calculation is illustrated in Workpaper TMB-4. From this New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 16 of 27 1 combined contract termination charge, the Company will calculate a uniform cents per 2 kilowatt-hour transition charge to be charged equally to all customers of the combined 3 company. 4 5 Q. What is the effect of the proposed consolidation of contract termination charges on 6 transition revenue generated from Eastern's customers? 7 A. Eastern's customers are expected to receive a significant reduction in transition charges 8 as a result of consolidating the transition charges of Eastern and Mass. Electric. Exhibit 9 TMB-6 illustrates the effect of consolidating transition charges on the customers of 10 Eastern as compared to the transition charges these customers would otherwise be 11 charged in calendar year 2001, which is calculated in Workpaper TMB-5. Eastern's 12 customers are expected to see a transition rate decrease of approximately $28 million, as 13 indicated in this exhibit. This decrease is due to Mass. Electric's contract termination 14 charge as billed to it by NEP being significantly lower than Eastern's contract termination 15 charge as billed to it by Montaup. 16 17 Results of Rate Plan 18 Q. Has the Company determined what the results of the above proposed rate plan are on the 19 retail delivery service revenue to be generated by Eastern's customers? New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 17 of 27 1 A. Yes it has. The $28 million decrease in transition charges is offset by the increases in 2 transmission and distribution charges discussed above. As illustrated in Exhibit TMB-7, 3 Mass. Electric anticipates that overall, Eastern's customers will see a decrease in the first 4 year of rate consolidation of approximately $19.6 million in retail delivery service 5 billings in accordance with the proposed rate plan. This exhibit compares, for Eastern's 6 customers the estimated retail delivery service revenue generated in calendar year 2001 7 with and without the proposed rate consolidation. The significant reduction is driven by 8 the decrease in the projected consolidated transition charge that Eastern's customers are 9 anticipated to be charged during calendar year 2001 as compared to the Eastern-only 10 projected transition charge for the same year. 11 12 Q. Will the proposed rate plan still provide the rate reductions required under the Act for 13 Mass. Electric's customers? 14 A. Yes it will. Page 1 of Exhibit TMB-8 recasts Mass. Electric's total company rate path 15 provided in Exhibit TMB-1 for the proposed rate plan, reflecting the extension of the 16 current distribution rate freeze by two years. The average distribution rate remains at 17 current levels through calendar year 2002. Demand side management and renewables 18 charges are as mandated in the Act. The projected average transmission rate declines 19 slightly as compared to its original projection for calendar year 2001 due to the New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 18 of 27 1 consolidation of transmission expenses of Eastern and Mass. Electric. And the projected 2 average transition charge increases slightly as compared to the originally projected level 3 for calendar year 2001, but continues to decline from its level from calendar year 2000. 4 With these revisions to the total company rate path, the rate reductions required under the 5 Act continue to be met, as illustrated on p. 1, Line (8) of Exhibit TMB-8. 6 7 Q. Will the proposed rate plan provide the statutory rate reductions if the distribution rate 8 freeze is extended for an additional two years through the end of calendar year 2004? 9 A. Yes it will. Page 2 of Exhibit TMB-8 presents the effects of a longer distribution rate 10 freeze on the statutory rate reductions. Again, Line (8) reflects that Mass. Electric will 11 continue to provide the statutory rate reductions required under the Act. 12 13 VI. Typical Bills 14 Q. Has the Company prepared typical bills showing the impacts on the proposed rate plan at 15 typical usage levels for Eastern? 16 A. Yes it has. Exhibit TMB-10 presents typical bills for Eastern. This exhibit compares 17 stand-alone actual and projected rates on January 1, 2001 to consolidated actual and 18 projected rates on January 1, 2001 assuming the merger and rate consolidation occur as 19 proposed. A typical 500 kilowatt-hour residential customer on Eastern's Rate R-1 is New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 19 of 27 1 estimated to be billed $52.90 by Eastern after January 1, 2001, and is estimated to be 2 billed $48.16 by Mass. Electric based on consolidated rates after January 1, 2001, 3 reflecting a decrease of $4.74, or 9.0%. Further savings will be realized in the future as 4 the result of the distribution rate freeze. These savings are not reflected in the typical bill 5 analysis. 6 7 Q. Has the Company prepared similar typical bills showing the impacts on the proposed rate 8 plan at typical usage levels for Mass. Electric? 9 A. Yes it has. Exhibit TMB-11 presents typical bills for Mass. Electric. As in Exhibit 10 TMB-10, Exhibit TMB-11 presents a bill comparison between stand-alone actual and 11 projected rates after January 1, 2001 and consolidated actual and projected rates after 12 January 1, 2001. The bill for a typical 500 kilowatt-hour residential customer on Mass. 13 Electric's Rate R-1 after January 1, 2001 is estimated to increase by $0.56, or 1.2%, from 14 $47.60 to $48.16. However, the $48.16 monthly bill after the proposed rate consolidation 15 will represent a decrease of $0.84, or 1.7% from Mass. Electric's typical bill in calendar 16 year 2000 that is estimated to be $49.00. 17 18 A comparison of Mass. Electric's average delivery rates from calendar years 2000 to 19 2001 is shown in Exhibit TMB-8. The average delivery rate in calendar year 2001 of New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 20 of 27 1 4.619(cent) per kilowatt-hour represents a decrease of 3.3% from the average delivery rate in 2 calendar year 2000 of 4.779(cent) per kilowatt-hour. Therefore, the proposed rate plan 3 continues to provide lower rates to Mass. Electric's existing customers, despite the slight 4 increase caused by the blending of the transition charge. 5 6 Q. Do any bills to Eastern's customers increase after the proposed consolidation? 7 A. Yes. The proposed rate consolidation increases prices to one Eastern rate class as shown 8 in Exhibit TMB-7. In addition, a review of Eastern's typical bills in Exhibit TMB-10 9 shows that, at specific usage levels within rate classes, some customers may see increases 10 after the Consolidation Date as a result of the proposed rate plan. These are identified 11 below. 12 13 Eastern's S-1 Customers to Mass. Electric's S-1 Rate 14 The rate class which experiences an increase is Eastern's streetlight rate class, Rate S-1 15 (see Exhibit TMB-7). Even with the decrease in the transition charge, this rate class will 16 experience an increase in retail delivery service billings. This increase occurs because 17 Mass. Electric's streetlight distribution rates are higher than Eastern's streetlight 18 distribution rates, as shown in Exhibit TMB-4. However, most municipal customers will 19 still experience savings when all of their accounts are aggregated and analyzed in total for New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 21 of 27 1 the impact of the proposed rate consolidation. The results of this analysis by community 2 is presented in Exhibit TMB-12. In addition, Eastern's municipalities will experience a 3 further and ongoing benefit from the proposed distribution rate freeze that would not 4 occur absent the merger. Similar benefits will be realized by private lighting customers 5 who will see rate reductions for general use at their service locations, and will also realize 6 the benefits of the distribution rate freeze. 7 8 Eastern's Small G-2 Customers to Mass. Electric's G-1 Rate 9 Some of Eastern's small commercial and industrial customers now served on demand 10 rates will experience an increase when placed on Mass. Electric's Rate G-1 (Small 11 Commercial and Industrial). The effects are shown on pages 7-10 of Exhibit TMB-10. 12 Eastern's Rate G-2 maps to three of Mass. Electric's general service rates: Rate G-1, Rate 13 G-2 Demand General Service, and Rate G-3 Time-of-Use General Service, as discussed 14 in the testimony of Mr. Bonner. Based upon the differences between the rate structures 15 of Eastern's Rate G-2 tariff and Mass. Electric's Rate G-1 tariff, these small general 16 service customers with high hours use (illustrated on pp. 10-11) are expected to see 17 increases in their bills upon implementation of the rate consolidation in calendar year 18 2001. Eastern's Rate G-2 has a demand component to its rate structure, while Mass. 19 Electric's Rate G-1 does not, and the customer charge under Eastern's Rate G-2 is New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 22 of 27 1 significantly lower than that of Mass. Electric's Rate G-1. The short-term increase for 2 these customers is mitigated by the economic benefits from the proposed distribution rate 3 freeze. 4 5 Eastern's Small T-2 Customers to Mass. Electric's G-1 Rate 6 Small commercial and industrial customers served on Eastern's time-of-use Rate T-2 will 7 also see an increase (see Exhibit TMB-10, pp. 43-47). Eastern Edison's Rate T-2 also 8 maps to the three Mass. Electric general service rates. Again, based upon the differences 9 between the rate structures of Eastern's Rate T-2 tariff and Mass. Electric's Rate G-1 10 tariff, these small general service customers with high hours use (illustrated on pp. 45-47) 11 are expected to see increases in their bills upon implementation of the proposed rate 12 consolidation. Eastern's Rate T-2 has both a demand component and an on peak/off peak 13 kilowatt-hour charge differential to its rate structure, while Mass. Electric's Rate G-1 14 does not. Again, the economic effect of the short-term increase is mitigated by the 15 proposed distribution rate freeze. 16 17 Eastern's Small H-1 Customers to Mass. Electric's G-1 Rate 18 Eastern's smaller customers on Rate H-1, General Space Heating, transferring to Mass. 19 Electric's Rate G-1, Small Commercial and Industrial are also affected by the proposed New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 23 of 27 1 rate consolidation (see Exhibit TMB-10, p. 60, and Exhibit TMB-7). Eastern's Rate H-1 2 also maps to the three Mass. Electric general service rates. Mass. Electric has eliminated 3 its commercial space heating rates, and these small general service customers will see 4 increases in their bills upon transfer to Rate G-1. Both the customer charge and 5 distribution energy charge under Mass. Electric's Rate G-1 are greater than the customer 6 charge and distribution energy charge of Eastern's Rate H-1. 7 8 Eastern's Small H-2 Customers to Mass. Electric's G-1 Rate 9 Eastern's smaller customers on Rate H-2, General Heating, transferring to Mass. 10 Electric's Rate G-1, Small Commercial and Industrial are affected the same way (see 11 Exhibit TMB- 10, p. 73 and Exhibit TMB-7). Eastern's Rate H-2 maps to two of Mass. 12 Electric's general service rates: Rate G-1 and Rate G-2. Mass. Electric has eliminated its 13 commercial heating rate, and these small general service customers are also expected to 14 see increases in their bills upon transfer to Rate G-1. Both the customer charge and 15 distribution energy charge under Mass. Electric's Rate G-1 are greater than the customer 16 charge and distribution energy charge of Eastern's Rate H-2. 17 18 Eastern's Non-Residential W-1 Customers to Mass. Electric's G-1 Rate 19 The other Eastern special end use rate is for water heating and will also be eliminated, New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 24 of 27 1 producing increases in this component of the customer's bill. Eastern's non-residential 2 customers on Rate W-1, Controlled Water Heating, transferring to Mass. Electric's Rate 3 G-1, Small Commercial and Industrial. Eastern's Rate W-1 provides service to both 4 residential and non-residential customers, and therefore maps to Mass. Electric Rate R-1, 5 Regular Residential, Rate R-2, Low Income Residential, and Rate G-1. Mass. Electric 6 Rate R-1 and Rate R-2 include a provision for a controlled water heating credit, however 7 Rate G-1 does not. Therefore Eastern's non-residential Rate W-1 customers will see an 8 increase by transferring to Mass. Electric's Rate G-1. The increases under this rate will 9 be mitigated, if not eliminated, by reductions in the bill for the customer's general usage, 10 and by the proposed distribution rate freeze aspect of the proposed rate plan. 11 12 Q. Is the Company proposing any rate design changes to address these effects to specific 13 customer groups? 14 A. No. Eastern's customers as a whole will benefit significantly from the proposed merger 15 and rate consolidation, as illustrated by the approximately $19.6 million reduction in 16 retail delivery service revenue identified in Exhibit TMB-7. The rate increases discussed 17 above largely stem from the movement of Eastern's customers onto Mass. Electric's 18 simpler rate structure. As will occur in any rate design and implementation, the change 19 will produce benefits to one group of customers and detriments to a second group. In this New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 25 of 27 1 case, because the rate designs are similar between the two companies and because 2 Eastern's overall rates are declining, the bill impacts for these customers are relatively 3 small and reasonable. Moreover, many of the bill impacts occur for special end use rates. 4 These effects are mitigated or reversed when evaluated in light of the customer's overall 5 usage of electricity. For example, streetlight increases to municipalities are offset by 6 price reductions at municipal facilities, and as a whole municipal customers benefit from 7 the proposed rate plan, as illustrated in Exhibit TMB-12. Water heating rate increases are 8 substantially reduced or reversed by reductions in the customer's usage from other 9 general purposes. Finally, the short term increases for specific Eastern customers will be 10 offset by the other longer term economic benefits of the merger, such as the long term 11 blending of transition charges and the extension of the distribution rate freeze. 12 Accordingly, the short-term increases in typical bills are reasonable given the longer term 13 benefits conferred upon Eastern's customers as a result of the merger and proposed rate 14 plan. 15 16 VII. Tariffs and Terms and Conditions 17 Q. Will Eastern's customers be subject to Mass. Electric's terms and conditions and 18 adjustment provisions after the Consolidation Date? 19 A. Yes. Eastern's customers will be subject to all of Mass. Electric's tariffs and terms and New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 26 of 27 1 conditions after the Consolidation Date. 2 3 Q. Has the Company determined whether or not it needs to make any revisions to its 4 adjustment provisions as a result of the merger? 5 A. Yes it has. The Company has reviewed its Transmission Service Cost Adjustment 6 Provision (M.D.T.E. No. 977-D), Transition Cost Adjustment Provision (M.D.T.E. No. 7 978-C), Standard Service Cost Adjustment Provision (M.D.T.E. No. 981-A), and Default 8 Service Adjustment Provision (M.D.T.E. No. 987-A) to determine whether the provisions 9 are sufficient to provide for service, reconciliation, and adjustment of rates subsequent to 10 the merger. 11 12 Q. Based upon this review, are there any adjustment provisions requiring revision? 13 A. No, there are not. 14 15 Q. Currently, Eastern has one customer receiving auxiliary service under Rate A-6. What is 16 Mass. Electric's proposal for this customer? 17 A. Mass. Electric is proposing to provide auxiliary service to this customer under its existing 18 Auxiliary Service Provision, M.D.P.U. No. 649-D. To achieve this transfer, the customer 19 will be placed directly onto Mass. Electric's Rate G-3 and be billed for auxiliary service New England Electric System Eastern Utilities Associates Testimony of T. M. Burns Page 27 of 27 1 as needed under this rate. The shift to Mass. Electric's Rate G-3 will produce a rate 2 reduction for the customer and treats this customer consistently with Mass. Electric's 3 other auxiliary service customers. 4 5 VIII. Conclusion 6 Q. Does this conclude your testimony? 7 A. Yes it does.
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ EXHIBITS AND WORKPAPERS OF THERESA M. BURNS Exhibit TMB-1 Massachusets Electric Company Total Company Rate Path Assuming No Consolidation Exhibit TMB-2 Eastern Edison Company Total Company Rate Path Assuming No Consolidation Exhibit TMB-3 Proposed Mapping of Eastern Rate Classes to Mass. Electric Rate Classes Exhibit TMB-4 Eastern Edison Company - Impact on Distribution Revenue Exhibit TMB-5 Eastern Edison Company - Impact on Transmission Revenue Exhibit TMB-6 Eastern Edison Company - Impact on Transition Revenue Exhibit TMB-7 Eastern Edison Company - Impact on Retail Delivery Service Revenue Exhibit TMB-8 Massachusetts Electric Company Total Company Rate Path Assuming Rate Consolidation on January 1, 2001 Exhibit TMB-9 Eastern Edison Company Total Company Rate Path Assuming Rate Consolidation on January 1, 2001 Exhibit TMB-10 Eastern Edison Company Typical Bills - January 1, 2001 Assuming No Merger vs. January 1, 2001 Combined Rates Exhibit TMB-11 Massachusetts Electric Company Typical Bills - January 1, 2001 Assuming No Merger vs. January 1, 2001 Combined Rates Exhibit TMB-12 Eastern Edison Company - Total Municipal Revenue Analysis Workpaper TMB-1 Eastern Edison Company Detail Supporting Revenue Impact Workpaper TMB-2 Eastern Edison Company Estimated Retail Transmission Rate in Year 2001 Workpaper TMB-3 Massachusetts Electric Company Consolidated Retail Transmission Rates Assuming Rate Consolidation on January 1, 2001 Workpaper TMB-4 Massachusetts Electric Company Estimated Combined Transition Charge in Year 2001 Workpaper TMB-5 Eastern Edison Company Estimated Transition Charges in Year 2001 New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-1 Massachusets Electric Company Total Company Rate Path Assuming No Consolidation
C:\eua files on disk\tmb-1.WK4 New England Electric System MECO-1 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Exhibit TMB-1 Page 1 of 2 MASSACHUSETTS ELECTRIC COMPANY Average (cent)/kWh Without Consolidation with Eastern Edison 1998 1999 -------------------- ------------------------------- Benchmark Rates 8/01/97 March 1 September 1 January 1 March 1 September 1 2000 2001 2002 2003 2004 ------- ------- ----------- --------- ------- ----------- ---- ---- ---- ---- ---- (1) Distribution 2.270 2.502 2.502 2.502 2.502 2.502 2.502 2.557 2.613 2.670 2.729 (1a) DSM 0.350 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250 (1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050 ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- TOTAL DISTRIBUTION 2.620 2.907 2.907 2.912 2.912 2.912 2.912 2.927 2.938 2.970 3.029 (2) Transmission 0.429 0.404 0.404 0.535 0.535 0.535 0.547 0.559 0.571 0.584 0.597 (2a) Transmission Adjustment 0.106 0.106 0.106 tbd tbd tbd tbd tbd ----- ----- ----- ----- ----- ----- ----- ---- TOTAL TRANSMISSION 0.429 0.404 0.404 0.641 0.641 0.641 0.547 0.559 0.571 0.584 0.597 (3) Transition 3.400 2.707 1.407 1.246 1.339 1.339 1.320 1.070 1.070 1.000 0.940 (3a) Transition Adjustment (0.011) (0.011) (0.011) tbd tbd tbd tbd tbd ------ ------ ------ ----- ----- ----- ----- ----- TOTAL TRANSITION 3.400 2.707 1.407 1.235 1.328 1.328 1.320 1.070 1.070 1.000 0.940 (4) TOTAL AVERAGE RETAIL DELIVERY PRICE 6.449 6.018 4.718 4.788 4.881 4.881 4.779 4.556 4.579 4.554 4.566 - ----------------------------------------------------------------------------------------------------------------------------------- (5) Standard Service Backstop 3.366 2.800 3.200 3.500 3.500 3.500 3.800 3.800 4.200 4.700 5.100 (5a) Standard Service Adjustment 0.207 0.207 0.207 tbd tbd tbd tbd tbd ----- ----- ----- ----- ----- ----- ----- ----- TOTAL STANDARD SERVICE 3.366 2.800 3.200 3.707 3.707 3.707 3.800 3.800 4.200 4.700 5.100 (6) TOTAL AVERAGE PRICE (EXCL. DISCOUNTS 9.815 8.818 7.918 8.495 8.588 8.588 8.579 8.356 8.779 9.254 9.666 (7) Statutory Benchmark, Adjusted for Inflation 9.815 9.815 9.815 9.815 10.174 10.495 10.726 10.962 11.203 11.449 (8) Savings Off Inflation- Adjusted Price 10.16% 19.33% 13.45% 12.50% 15.59% 18.26% 22.10% 19.91% 17.40% 15.57% - ----------------------------------------------------------------------------------------------------------------------------------- (1),(2) Assumed Inflation Rate for Distribution and Transmission Components 2.2% and Statutory Benchmark Beyond 2000 (3) Exhibits of J.K. Zschokke (7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference Page 2 of 2
C:\eua files on disk\tmb-1.WK4 New England Electric System MECO INFLAT Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Exhibit TMB- 1 Page 2 of 2 Massachusetts Electric Company Determination of Statutory Benchmark, Adjusted for Inflation August 1, 1997 to December 31, 2000 CPI Percentage Benchmark Index Change Rates ----- ------ ----- ACTUAL Aug-97 160.5 1/ 9.815 Sep-97 160.8 1/ 0.187% 9.833 Oct-97 161.2 1/ 0.249% 9.857 Nov-97 161.6 1/ 0.248% 9.881 Dec-97 161.5 1/ -0.062% 9.875 Jan-98 161.3 1/ -0.124% 9.863 Feb-98 161.6 1/ 0.186% 9.881 Mar-98 161.9 1/ 0.186% 9.899 Apr-98 162.2 1/ 0.185% 9.917 May-98 162.5 1/ 0.185% 9.935 Jun-98 162.8 1/ 0.185% 9.953 Jul-98 163.0 1/ 0.123% 9.965 Aug-98 163.2 1/ 0.123% 9.977 Sep-98 163.4 1/ 0.123% 9.989 Oct-98 163.6 1/ 0.122% 10.001 Nov-98 164.0 1/ 0.244% 10.025 Dec-98 164.0 1/ 0.000% 10.025 PROJECTED 1st Quarter 1999 165.1 2/ 0.670% 10.092 2nd Quarter 1999 165.9 2/ 0.484% 10.141 3rd Quarter 1999 (through Aug-99) 166.7-2/ 0.321% 10.174 3rd Quarter 1999 (Sep-99) 0.160% 10.190 4th Quarter 1999 167.7 2/ 0.599% 10.251 1st Quarter 2000 168.6 2/ 0.536% 10.306 2nd Quarter 2000 169.6 2/ 0.593% 10.367 3rd Quarter 2000 170.6 2/ 0.589% 10.428 4th Quarter 2000 171.7 2/ 0.644% 10.495 ------------------------------------------------------------------- 1/ Historical Consumer Price Index - All Urban Consumers (CPI-U) obtained from the Bureau of Labor Statistics 2/ Projected CPI growth from the Blue Chip Economic Forecast dated February 10, 1999 New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-2 Eastern Edison Company Total Company Rate Path Assuming No Consolidation
S:\RADATA1\EASTED\2001\Path-01a.wk4 New England Electric System EEC-1 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Exhibit TMB-2, Revised Page 1 of 2 EASTERN EDISON COMPANY Average (cent)/kWh Without Consolidation with Massachusetts Electric 1998 1999 -------------------- ------------------------------- Benchmark Rates 8/01/97 March 1 September 1 January 1 April 1 September 1 2000 2001 2002 2003 2004 ------- ------- ----------- --------- ------- ----------- ---- ---- ---- ---- ---- (1) Distribution 2.743 2.743 2.743 2.743 2.743 2.743 2.803 2.865 2.928 2.992 (1a) DSM 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250 (1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050 ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- TOTAL DISTRIBUTION 0.000 3.148 3.148 3.153 3.153 3.153 3.153 3.173 3.190 3.228 3.292 (2) Transmission 0.258 0.258 0.215 0.270 0.298 0.285 0.291 0.297 0.304 0.311 (2a) Transmission Adjustment tbd tbd tbd tbd tbd tbd tbd ----- ----- ----- ----- ----- ----- ----- TOTAL TRANSMISSION 0.000 0.258 0.258 0.215 0.270 0.298 0.285 0.291 0.297 0.304 0.311 (3) Transition 3.040 3.040 3.040 2.100 2.100 2.380 2.300 2.220 1.840 1.690 (3a) Transition Adjustment tbd tbd tbd tbd tbd tbd tbd ----- ----- ----- ----- ----- ----- ----- TOTAL TRANSITION 0.000 3.040 3.040 3.040 2.100 2.100 2.380 2.300 2.220 1.840 1.690 (4) TOTAL AVERAGE RETAIL DELIVERY PRICE 6.446 6.446 6.408 5.523 5.551 5.818 5.764 5.707 5.372 5.293 - ----------------------------------------------------------------------------------------------------------------------------------- (5) Standard Service Backstop 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100 (5a) Standard Service Adjustment n/a n/a tbd tbd tbd tbd tbd ----- ----- ----- ----- ----- ----- ----- TOTAL STANDARD SERVICE 0.000 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100 (6) TOTAL AVERAGE PRICE (EXCL. DISCOUNTS 10.471 9.246 9.246 9.508 9.023 9.051 9.618 9.564 9.907 10.072 10.393 (7) Statutory Benchmark, Adjusted for Inflation 10.471 10.471 10.471 10.471 10.860 11.203 11.449 11.701 11.958 12.221 (8) Savings Off Inflation- Adjusted Price 11.70% 11.70% 9.20% 13.83% 16.66% 14.15% 16.46% 15.33% 15.77% 14.96% - ----------------------------------------------------------------------------------------------------------------------------------- (1),(2) Assumed Inflation Rate for Distribution and Transmission Components 2.2% and Statutory Benchmark Beyond 2000 (3) February 12, 1999 Divestiture Filing (7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference Page 2 of 2
C:\eua files on disk\tmb-2.WK4 New England Electric System EEC INFLAT Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Exhibit TMB- 2, Revised Page 2 of 2 Eastern Edison Company Determination of Statutory Benchmark, Adjusted for Inflation August 1, 1997 to December 31, 2000 CPI Percentage Benchmark Index Change Rates ----- ------ ----- ACTUAL Aug-97 160.5 1/ 10.471 Sep-97 160.8 1/ 0.187% 10.491 Oct-97 161.2 1/ 0.249% 10.517 Nov-97 161.6 1/ 0.248% 10.543 Dec-97 161.5 1/ -0.062% 10.536 Jan-98 161.3 1/ -0.124% 10.523 Feb-98 161.6 1/ 0.186% 10.543 Mar-98 161.9 1/ 0.186% 10.563 Apr-98 162.2 1/ 0.185% 10.583 May-98 162.5 1/ 0.185% 10.603 Jun-98 162.8 1/ 0.185% 10.623 Jul-98 163.0 1/ 0.123% 10.636 Aug-98 163.2 1/ 0.123% 10.649 Sep-98 163.4 1/ 0.123% 10.662 Oct-98 163.6 1/ 0.122% 10.675 Nov-98 164.0 1/ 0.244% 10.701 Dec-98 164.0 1/ 0.000% 10.701 PROJECTED 1st Quarter 1999 165.1 2/ 0.670% 10.773 2nd Quarter 1999 165.9 2/ 0.484% 10.825 3rd Quarter 1999 (through Aug-99) 166.7 2/ 0.321% 10.860 3rd Quarter 1999 (Sep-99) 0.160% 10.877 4th Quarter 1999 167.7 2/ 0.599% 10.942 1st Quarter 2000 168.6 2/ 0.536% 11.001 2nd Quarter 2000 169.6 2/ 0.593% 11.066 3rd Quarter 2000 170.6 2/ 0.589% 11.131 4th Quarter 2000 171.7 2/ 0.644% 11.203 ------------------------------------------------------------------------ 1/ Historical Consumer Price Index - All Urban Consumers (CPI-U) obtained from the Bureau of Labor Statistics 2/ Projected CPI growth from the Blue Chip Economic Forecast dated February 10, 1999 New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-3 Proposed Mapping of Eastern Rate Classes to Mass. Electric Rate Classes S:\RADATA1\EASTED\Mapping1.wk4 New England Electric System SUMMARY Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Exhibit TMB-3 Page 1 of 1 Massachusetts Electric Company Eastern Edison Company Summary of Rate Mapping - ------------------------------------------------------------------------------- EEC MECO Rate Description Rate Description - ------------------------------------------------------------------------------- R-1 Residential Service R-1 Residential Service - ------------------------------------------------------------------------------- R-2 Residential Low Income Service R-2 Residential Low Income Service - ------------------------------------------------------------------------------- R-3 Residential Space Heating Service R-1 Residential Service - ------------------------------------------------------------------------------- R-4 Residential Time of Use Service R-1 Residential Service (no minimum usage) - ------------------------------------------------------------------------------- G-1 Small Secondary Voltage Service G-1 Small C&I (kWh<10,000 per month) - ------------------------------------------------------------------------------- G-1 Small C&I G-2 Medium Secondary Voltage Service G-2 General Service Demand (kw<200 per month, kWh>10,000 per month) (1036,000) G-3 Time of Use (kw>200 per month) - ------------------------------------------------------------------------------- G-4 Large Secondary Voltage Service G-3 Time of Use - ------------------------------------------------------------------------------- G-2 General Service Demand G-5 Medium Primary Voltage Service (10036,000) G-3 Time of Use - ------------------------------------------------------------------------------- G-1 Small C&I H-1 Space Heating Service G-2 General Service Demand (non-residential) G-3 Time of Use - ------------------------------------------------------------------------------- G-1 Small C&I H-2 Space Heating Service (non-industrial) G-2 General Service Demand - ------------------------------------------------------------------------------- R-1 Residential Service W-1 Controlled Water Heating Service (all customer types) G-1 Small C&I - ------------------------------------------------------------------------------- S-1 Lighting Service S-1 Streetlighting-Company Owned (company owned) - ------------------------------------------------------------------------------- A-6 Auxiliary Service G-3 Time of Use - ------------------------------------------------------------------------------- New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-4 Eastern Edison Company Impact on Distribution Revenue
S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System DIST REVENUE Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Exhibit TMB-4 Page 1 of 1 Massachusetts Electric Company Eastern Edison Company Revenue Comparison Based on Distribution Rates Effective March 1, 1998 Distribution Revenue Eastern Eastern $ Edison Edison Revenue % Eastern Edison Mass. Electric Units on Units on Increase Increase Rate Class Rate Class EEC 2001 Rate $/kWh Consol. 2001 Rate $/kWh (Decrease) (Decrease) --------------- -------------- ------------- ----- ----------------- ----- --------- --------- R-1: Regular Residential R-1: Regular Residential $34,195,956 $0.03811 $32,359,837 $0.03606 ($1,836,119) -5.37% R-2: Low Income Residential R-2: Low Income Residential $535,326 $0.00797 $898,391 $0.01338 $363,065 67.82% R-3: Residential Space Heat R-1: Regular Residential $1,836,429 $0.02600 $2,176,005 $0.03081 $339,576 18.49% R-4: Large Residential R-1: Regular Residential $14,067 $0.02438 $17,600 $0.03050 $3,533 25.12% W-1: Controlled Water Heat R-1: Regular Residential $1,308,877 $0.02688 $1,276,239 $0.02621 ($32,638) -2.49% ---------- ---------- -------- Total Residential $37,890,656 $0.03494 $36,728,072 $0.03387 ($1,162,583) -3.07% - --------------------------------------------------------------------------------------------------------------------------- G-1: Small Secondary Voltage G-1: Small C&I $4,933,943 $0.04522 $5,944,826 $0.05449 $1,010,883 20.49% G-2: Medium Secondary Voltage G-1: Small C&I $6,763,214 $0.02797 $9,807,323 $0.04055 $3,044,109 45.01% G-2: Medium C&I $9,725,074 $0.02292 $8,568,240 $0.02020 ($1,156,834) -11.90% G-3: Large C&I $3,869,559 $0.02230 $3,011,607 $0.01735 ($857,953) -22.17% G-4: Large Secondary Voltage G-3: Large C&I $4,518,331 $0.01310 $4,977,073 $0.01443 $458,742 10.15% G-5: Medium Primary Voltage G-2: Medium C&I $146,756 $0.02059 $122,553 $0.01720 ($24,203) -16.49% G-3: Large C&I $376,004 $0.02060 $308,082 $0.01688 ($67,922) -18.06% G-6: Large Primary Voltage G-3: Large C&I $2,623,010 $0.01349 $2,537,193 $0.01305 ($85,818) -3.27% T-2: Medium TOU Secondary G-1: Small C&I $19,356 $0.01642 $47,777 $0.04053 $28,422 146.84% G-2: Medium C&I $174,447 $0.00931 $300,863 $0.01605 $126,416 72.47% G-3: Large C&I $444,783 $0.00837 $693,296 $0.01304 $248,512 55.87% H-1: Space Heating (non- resid) G-1: Small C&I $74,569 $0.02930 $108,058 $0.04245 $33,489 44.91% G-2: Medium C&I $19,002 $0.02696 $21,794 $0.03092 $2,792 14.69% G-3: Large C&I $179,140 $0.02673 $185,431 $0.02767 $6,291 3.51% H-2: Space Heating (non- indust) G-1: Small C&I $67,696 $0.02944 $104,828 $0.04559 $37,131 54.85% G-2: Medium C&I $3,844 $0.02840 $3,306 $0.02442 ($538) -14.00% W-1: Controlled Water Heat G-1: Small C&I $20,705 $0.02657 $52,542 $0.06741 $31,837 153.76% ------- ------- ------ Total Commercial and Industrial $33,959,436 $0.02123 $36,794,790 $0.02300 $2,835,354 8.35% - ---------------------------------------------------------------------------------------------------------------------------- S-1: Lighting S-1: Company Owned $2,538,661 $0.09083 $3,454,923 $0.12105 $916,262 36.09% - ---------------------------------------------------------------------------------------------------------------------------- Total Company $74,388,752 $0.02743 $76,977,785 $0.02838 $2,589,033 3.48% - ---------------------------------------------------------------------------------------------------------------------------- Total kWh 2,711,961,115 2,712,552,392 Source: Workpaper TMB-1
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-5 Eastern Edison Company Impact on Transmission Revenue
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Exhibit TMB-5, Revised Page 1 of 1 Massachusetts Electric Company Eastern Edison Company Revenue Comparison Based on Transmission Rates Transmission Revenue EASTERN $ EDISON EASTERN EDISON REVENUE % EASTERN EDISON MASS. ELECTRIC UNITS ON UNITS ON CONSOL. INCREASE INCREASE RATE CLASS RATE CLASS EEC 2001 RATES $/KWH 2001 RATES $/KWH (DECREASE) (DECREASE) ---------- ---------- -------------- ----- ----------- ------- ---------- ---------- R-1: Regular R-1: Regular $2,611,387 $0.00291 $5,124,062 $0.00571 $2,512,675 96.22% Residential Residential R-2: Low Income R-2: Low Income $195,402 $0.00291 $383,418 $0.00571 $188,016 96.22% Residential Residential R-3: Residential R-1: Regular $205,500 $0.00291 $403,232 $0.00571 $197,732 96.22% Space Heat Residential R-4: Large R-1: Regular $1,679 $0.00291 $3,295 $0.00571 $1,616 96.22% Residential Residential W-1: Controlled R-1: Regular $141,709 $0.00291 $278,062 $0.00571 $136,353 96.22% Water Heat Residential --------- --------- --------- Total Residential $3,155,678 $0.00291 $6,192,068 $0.00571 $3,036,391 96.22% --------------------------------------------------------------------------------------------------------------------------- G-1: Small Secondary G-1: Small C&I $317,475 $0.00291 $619,677 $0.00568 $302,202 95.19% Voltage G-2: Medium Secondary G-1: Small C&I $703,722 $0.00291 $1,373,587 $0.00568 $669,866 95.19% Voltage G-2: Medium C&I $1,234,553 $0.00291 $2,176,377 $0.00513 $941,824 76.29% G-3: Large C&I $505,004 $0.00291 $798,288 $0.00460 $293,284 58.08% G-4: Large Secondary G-3: Large C&I $1,003,391 $0.00291 $1,586,117 $0.00460 $582,726 58.08% Voltage G-5: Medium Primary G-2: Medium C&I $20,738 $0.00291 $36,193 $0.00508 $15,455 74.53% Voltage G-3: Large C&I $53,107 $0.00291 $83,109 $0.00455 $30,003 56.49% G-6: Large Primary G-3: Large C&I $565,847 $0.00291 $885,521 $0.00455 $319,674 56.49% Voltage T-2: Medium TOU G-1: Small C&I $3,431 $0.00291 $6,696 $0.00568 $3,266 95.19% Secondary G-2: Medium C&I $54,544 $0.00291 $96,155 $0.00513 $41,611 76.29% G-3: Large C&I $154,671 $0.00291 $244,497 $0.00460 $89,826 58.08% H-1: Space Heating G-1: Small C&I $7,407 $0.00291 $14,457 $0.00568 $7,050 95.19% (non-resid) G-2: Medium C&I $2,051 $0.00291 $3,616 $0.00513 $1,565 76.29% G-3: Large C&I $19,503 $0.00291 $30,830 $0.00460 $11,327 58.08% H-2: Space Heating G-1: Small C&I $6,691 $0.00291 $13,060 $0.00568 $6,369 95.19% (non-indust) G-2: Medium C&I $394 $0.00291 $694 $0.00513 $301 76.29% W-1: Controlled G-1: Small C&I $2,268 $0.00291 $4,427 $0.00568 $2,159 95.19% Water Heat ------- ------- ------- Total Commercial $4,654,796 $0.00291 $7,973,302 $0.00498 $3,318,506 71.29% and Industrial -------------------------------------------------------------------------------------------------------------------------- S-1: Lighting S-1: Company Owned $81,333 $0.00291 $137,566 $0.00482 $56,233 69.14% -------------------------------------------------------------------------------------------------------------------------- Total Company $7,891,807 $0.00291 $14,302,937 $0.00527 $6,411,130 81.24% ------------------------------------------------------------------------------------------------------------------------- Total kWh 2,711,961,115 2,712,552,392
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-6 Eastern Edison Company Impact on Transition Revenue
S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System TRANSI REVENUE Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Exhibit TMB-6 Page 1 of 1 Massachusetts Electric Company Eastern Edison Company Revenue Comparison Based on Transition Rates Transition Revenue Eastern Eastern Edison Edison $ Units on Units on Revenue % Eastern Edison Mass. Electric EEC 2001 Consol. Increase Increase Rate Class Rate Class Rate $/kWh 2001 Rate $/kWh (Decrease) (Decrease) ---------- ---------- -------- ----- --------- ----- ---------- --------- R-1: Regular Residential R-1: Regular Residential $20,639,828 $0.02300 $11,217,298 $0.01250 ($9,422,530) -45.65% R-2: Low Income Residential R-2: Low Income Residential $1,544,415 $0.02300 $839,356 $0.01250 ($705,059) -45.65% R-3: Residential Space Heat R-1: Regular Residential $1,624,226 $0.02300 $882,732 $0.01250 ($741,495) -45.65% R-4: Large Residential R-1: Regular Residential $13,350 $0.02313 $7,214 $0.01250 ($6,136) -45.96% W-1: Controlled Water Heat R-1: Regular Residential $1,120,039 $0.02300 $608,717 $0.01250 ($511,322) -45.65% Total Residential $24,941,858 $0.02300 $13,555,316 $0.01250 ($11,386,54) -45.65% - ---------------------------------------------------------------------------------------------------------------------------------- G-1: Small Secondary Voltage G-1: Small C&I $2,509,256 $0.02300 $1,363,726 $0.01250 ($1,145,530) -45.65% G-2: Medium Secondary Voltage G-1: Small C&I $6,800,623 $0.02812 $3,022,860 $0.01250 ($3,777,763) -55.55% G-2: Medium C&I $8,735,503 $0.02059 $5,303,063 $0.01250 ($3,432,440) -39.29% G-3: Large C&I $3,430,400 $0.01977 $2,169,262 $0.01250 ($1,261,139) -36.76% G-4: Large Secondary Voltage G-3: Large C&I $7,823,168 $0.02269 $4,310,100 $0.01250 ($3,513,068) -44.91% G-5: Medium Primary Voltage G-2: Medium C&I $160,783 $0.02256 $89,080 $0.01250 ($71,703) -44.60% G-3: Large C&I $432,655 $0.02371 $228,122 $0.01250 ($204,533) -47.27% G-6: Large Primary Voltage G-3: Large C&I $4,505,296 $0.02317 $2,430,612 $0.01250 ($2,074,684) -46.05% T-2: Medium TOU Secondary G-1: Small C&I $39,752 $0.03372 $14,737 $0.01250 ($25,015) -62.93% G-2: Medium C&I $462,403 $0.02467 $234,295 $0.01250 ($228,108) -49.33% G-3: Large C&I $1,237,834 $0.02329 $664,393 $0.01250 ($573,441) -46.33% H-1: Space Heating (non-resid) G-1: Small C&I $58,542 $0.02300 $31,816 $0.01250 ($26,726) -45.65% G-2: Medium C&I $16,212 $0.02300 $8,811 $0.01250 ($7,401) -45.65% G-3: Large C&I $154,151 $0.02300 $83,778 $0.01250 ($70,373) -45.65% H-2: Space Heating (non-indust) G-1: Small C&I $52,884 $0.02300 $28,742 $0.01250 ($24,143) -45.65% G-2: Medium C&I $3,113 $0.02300 $1,692 $0.01250 ($1,421) -45.65% W-1: Controlled Water Heat G-1: Small C&I $17,927 $0.02300 $9,743 $0.01250 ($8,184) -45.65% Total Commercial and Industrial $36,440,502 $0.02278 $19,994,829 $0.01250 ($16,445,672) -45.13% - ---------------------------------------------------------------------------------------------------------------------------------- S-1: Lighting S-1: Company Owned $642,838 $0.02300 $356,760 $0.01250 ($286,079) -44.50% - ---------------------------------------------------------------------------------------------------------------------------------- Total Company $62,025,198 $0.02287 $33,906,905 $0.01250 ($28,118,293) -45.33% - ---------------------------------------------------------------------------------------------------------------------------------- Total kWh 2,711,961,115 2,712,552,392 Source: Workpaper TMB-1
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-7 Eastern Edison Company Impact on Retail Delivery Service Revenue
S:\RADATA1\EASTED\2001\01vs01a.wk4 New England Electric System WIRES REVENUE Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Exhibit TMB-7, Revised Page 1 of 1 Massachusetts Electric Company Eastern Edison Company Revenue Comparison Based on Rates Effective March 1, 1999 Retail Delivery Service Revenue Eastern Eastern $ Edison Edison Revenue % Eastern Edison Mass. Electric Units on Units on Increase Increase Rate Class Rate Class EEC 2001 Rates $/kWh Consol. 2001 Rates $/kWh (Decrease) (Decrease) -------------- -------------- -------------- ----- ------------------ ----- ---------- --------- R-1: Regular Residential R-1: Regular Residential $57,447,171 $0.06402 $48,701,196 $0.05427 ($8,745,975) -15.22% R-2: Low Income Residential R-2: Low Income Residential $2,275,143 $0.03388 $2,121,165 $0.03159 ($153,978) -6.77% R-3: Residential Space Heat R-1: Regular Residential $3,666,155 $0.05191 $3,461,968 $0.04902 ($204,187) -5.57% R-4: Large Residential R-1: Regular Residential $29,097 $0.05042 $28,110 $0.04871 ($987) -3.39% W-1: Controlled Water Heat R-1: Regular Residential $2,570,625 $0.05279 $2,163,018 $0.04442 ($407,607) -15.86% ---------- ---------- --------- Total Residential $65,988,191 $0.06085 $56,475,456 $0.05208 ($9,512,735) -14.42% - ------------------------------------------------------------------------------------------------------------------------------ G-1: Small Secondary Voltage G-1: Small C&I $7,760,675 $0.07113 $7,928,229 $0.07267 $167,554 2.16% G-2: Medium Secondary Voltage G-1: Small C&I $14,267,559 $0.05900 $14,203,770 $0.05873 ($63,789) -0.45% G-2: Medium C&I $19,695,130 $0.04642 $16,047,680 $0.03783 ($3,647,451) -18.52% G-3: Large C&I $7,804,964 $0.04497 $5,979,157 $0.03445 ($1,825,807) -23.39% G-4: Large Secondary Voltage G-3: Large C&I $13,344,890 $0.03870 $10,873,290 $0.03153 ($2,471,600) -18.52% G-5: Medium Primary Voltage G-2: Medium C&I $328,277 $0.04606 $247,826 $0.03478 ($80,451) -24.51% G-3: Large C&I $861,766 $0.04722 $619,313 $0.03394 ($242,452) -28.13% G-6: Large Primary Voltage G-3: Large C&I $7,694,153 $0.03957 $5,853,325 $0.03010 ($1,840,828) -23.93% T-2: Medium TOU Secondary G-1: Small C&I $62,538 $0.05305 $69,210 $0.05871 $6,672 10.67% G-2: Medium C&I $691,393 $0.03689 $631,312 $0.03368 ($60,081) -8.69% G-3: Large C&I $1,837,288 $0.03457 $1,602,185 $0.03014 ($235,103) -12.80% H-1: Space Heating (non- resid) G-1: Small C&I $140,518 $0.05521 $154,331 $0.06063 $13,814 9.83% G-2: Medium C&I $37,265 $0.05287 $34,221 $0.04855 ($3,045) -8.17% G-3: Large C&I $352,794 $0.05264 $300,039 $0.04477 ($52,756) -14.95% H-2: Space Heating (non- indust) G-1: Small C&I $127,272 $0.05535 $146,630 $0.06377 $19,358 15.21% G-2: Medium C&I $7,351 $0.05431 $5,693 $0.04205 ($1,659) -22.57% W-1: Controlled Water Heat G-1: Small C&I $40,900 $0.05248 $66,712 $0.08559 $25,812 63.11% ------- ------- ------- Total Commercial and Industrial $75,054,734 $0.04692 $64,762,921 $0.04049 ($10,291,812) -13.71% - ------------------------------------------------------------------------------------------------------------------------------ S-1: Lighting S-1: Company Owned $3,262,832 $0.11674 $3,949,249 $0.13837 $686,417 21.04% - ------------------------------------------------------------------------------------------------------------------------------ Total Company $144,305,757 $0.05321 $125,187,627 $0.04615 ($19,118,130) -13.25% - ------------------------------------------------------------------------------------------------------------------------------ Total kWh 2,711,961,115 2,712,552,392 Source: Workpaper TMB-1
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-8 Massachusetts Electric Company Total Company Rate Path Assuming Rate Consolidation on January 1, 2001
S:\RADATA1\EASTED\2001\Path-01a.wk4 New England Electric System MECO-2 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Exhibit TMB-8, Revised Page 1 of 2 MASSACHUSETTS ELECTRIC COMPANY Average (cent)/kWh With Consolidation with Eastern Edison on January 1, 2001 1998 1999 -------------------- ------------------------------- Benchmark Rates 8/01/97 March 1 September 1 January 1 March 1 September 1 2000 2001 2002 2003 2004 ------- ------- ----------- --------- ------- ----------- ---- ---- ---- ---- ---- (1) Distribution 2.270 2.502 2.502 2.502 2.502 2.502 2.502 2.502 2.502 2.557 2.613 (1a) DSM 0.350 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250 (1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050 ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- TOTAL DISTRIBUTION 2.620 2.907 2.907 2.912 2.912 2.912 2.912 2.872 2.827 2.857 2.913 (2) Transmission 0.429 0.404 0.404 0.535 0.535 0.535 0.547 0.518 0.529 0.541 0.553 (2a) Transmission Adjustment 0.106 0.106 0.106 tbd tbd tbd tbd tbd ----- ----- ----- ----- ----- ----- ----- ----- TOTAL TRANSMISSION 0.429 0.404 0.404 0.641 0.641 0.641 0.547 0.518 0.529 0.541 0.553 (3) Transition 3.400 2.707 1.407 1.246 1.339 1.339 1.320 1.250 1.230 1.110 1.050 (3a) Transition Adjustment (0.011) (0.011) (0.011) tbd tbd tbd tbd tbd ------ ------ ------ ----- ----- ----- ----- ----- TOTAL TRANSITION 3.400 2.707 1.407 1.235 1.328 1.328 1.320 1.250 1.230 1.110 1.050 (4) TOTAL AVERAGE RETAIL DELIVERY PRICE 6.449 6.018 4.718 4.788 4.881 4.881 4.779 4.640 4.586 4.508 4.516 - ----------------------------------------------------------------------------------------------------------------------------------- (5) Standard Service Backstop 3.366 2.800 3.200 3.500 3.500 3.500 3.800 3.800 4.200 4.700 5.100 (5a) Standard Service Adjustment 0.207 0.207 0.207 tbd tbd tbd tbd tbd ----- ----- ----- ----- ----- ----- ----- ----- TOTAL STANDARD SERVICE 3.366 2.800 3.200 3.707 3.707 3.707 3.800 3.800 4.200 4.700 5.100 (6) TOTAL AVERAGE PRICE (EXCL. DISCOUNTS 9.815 8.818 7.918 8.495 8.588 8.588 8.579 8.440 8.786 9.208 9.616 (7) Statutory Benchmark, Adjusted for Inflation 9.815 9.815 9.815 9.815 10.174 10.495 10.726 10.962 11.203 11.449 (8) Savings Off Inflation- Adjusted Price 10.16% 19.33% 13.45% 12.50% 15.59% 18.26% 21.31% 19.85% 17.81% 16.01% - ----------------------------------------------------------------------------------------------------------------------------------- (2) 2001: 1999 Combined Company transmission costs per FERC 205 Filing, Exhibit__(PAV-4), Statement BG plus estimated NEPOOL transmission costs / combined kWh sales inflated at 2.2% for 2 years; see Workpaper TMB-3 2002 & beyond: inflated by 2.2% per year (3) 2001 & beyond: Workpaper TMB-4 (7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference Exhibit TMB-1, Page 2 S:\RADATA1\EASTED\2001\Path-01a.wk4 New England Electric System MECO-3 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Exhibit TMB-8, Revised Page 2 of 2 MASSACHUSETTS ELECTRIC COMPANY Average (cent)/kWh With Consolidation with Eastern Edison on January 1, 2001 1998 1999 ------------------------------------------- Benchmark Rates 8/01/97 March 1 September 1 January 1 March 1 September 1 2000 2001 2002 2003 2004 ------- ------- ----------- --------- ------- ----------- ---- ---- ---- ---- ---- (1) Distribution 2.270 2.502 2.502 2.502 2.502 2.502 2.502 2.502 2.502 2.502 2.502 (1a) DSM 0.350 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250 (1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050 ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- TOTAL DISTRIBUTION 2.620 2.907 2.907 2.912 2.912 2.912 2.912 2.872 2.827 2.802 2.802 (2) Transmission 0.429 0.404 0.404 0.535 0.535 0.535 0.547 0.518 0.529 0.541 0.553 (2a) Transmission Adjustment 0.106 0.106 0.106 tbd tbd tbd tbd tbd ----- ----- ----- ----- ----- ----- ----- ----- TOTAL TRANSMISSION 0.429 0.404 0.404 0.641 0.641 0.641 0.547 0.518 0.529 0.541 0.553 (3) Transition 3.400 2.707 1.407 1.246 1.339 1.339 1.320 1.250 1.230 1.110 1.050 (3a) Transition Adjustment (0.011) (0.011) (0.011) tbd tbd tbd tbd tbd ------ ------ ------ ----- ----- ----- ----- ----- TOTAL TRANSITION 3.400 2.707 1.407 1.235 1.328 1.328 1.320 1.250 1.230 1.110 1.050 (4) TOTAL AVERAGE RETAIL DELIVERY PRICE 6.449 6.018 4.718 4.788 4.881 4.881 4.779 4.640 4.586 4.453 4.405 - ----------------------------------------------------------------------------------------------------------------------------------- (5) Standard Service Backstop 3.366 2.800 3.200 3.500 3.500 3.500 3.800 3.800 4.200 4.700 5.100 (5a) Standard Service Adjustment 0.207 0.207 0.207 tbd tbd tbd tbd tbd ----- ----- ----- ----- ----- ----- ----- ----- TOTAL STANDARD SERVICE 3.366 2.800 3.200 3.707 3.707 3.707 3.800 3.800 4.200 4.700 5.100 (6) TOTAL AVERAGE PRICE (EXCL. DISCOUNTS 9.815 8.818 7.918 8.495 8.588 8.588 8.579 8.440 8.786 9.153 9.505 (7) Statutory Benchmark, Adjusted for Inflation 9.815 9.815 9.815 9.815 10.174 10.495 10.726 10.962 11.203 11.449 (8) Savings Off Inflation- Adjusted Price 10.16% 19.33% 13.45% 12.50% 15.59% 18.26% 21.31% 19.85% 18.30% 16.98% - ----------------------------------------------------------------------------------------------------------------------------------- (2) 2001: 1999 Combined Company transmission costs per FERC 205 Filing, Exhibit__(PAV-4), Statement BG plus estimated NEPOOL transmission costs / combined kWh sales inflated at 2.2% for 2 years; see Workpaper TMB-3 2002 & beyond: inflated by 2.2% per year (3) 2001 & beyond: Workpaper TMB-4 (7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference Exhibit TMB-1, Page 2
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-9 Eastern Edison Company Total Company Rate Path Assuming Rate Consolidation on January 1, 2001
S:\RADATA1\EASTED\2001\Path-01a.wk4 New England Electric System EEC-2 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Exhibit TMB-9, Revised Page 1 of 2 EASTERN EDISON COMPANY Average (cent)/kWh With Consolidation with Massachusetts Electric on January 1, 2001 1998 1999 ----------------- ----------------------- Benchmark Rates Sept- Jan- Sept- 8/01/97 March 1 ember 1 uary 1 April 1 ember 2000 2001 2002 2003 2004 ------- ------- ------- ------ ------ ------ ---- ---- ---- ---- ---- (1) Distribution 2.743 2.743 2.743 2.743 2.743 2.743 2.838 2.838 2.900 2.964 (1a) DSM 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250 (1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050 ------ ------ ------ ------ ------ ------ ------ ------ ------ ----- TOTAL DISTRIBUTION 0.000 3.148 3.148 3.153 3.153 3.153 3.153 3.208 3.163 3.200 3.264 (2) Transmission 0.258 0.258 0.215 0.270 0.298 0.285 0.518 0.529 0.541 0.553 (2a) Transmission Adjustment tbd tbd tbd tbd tbd tbd tbd ---- ---- ---- ---- ---- ---- --- TOTAL TRANSMISSION 0.000 0.258 0.258 0.215 0.270 0.298 0.285 0.518 0.529 0.541 0.553 (3) Transition 3.040 3.040 3.040 2.100 2.100 2.300 1.250 1.230 1.110 1.050 (3a) Transition Adjustment tbd tbd tbd tbd tbd tbd tbd ---- ---- ---- ---- ---- ---- --- TOTAL TRANSITION 0.000 3.040 3.040 3.040 2.100 2.100 2.300 1.250 1.230 1.110 1.050 (4) TOTAL AVERAGE RETAIL DELIVERY PRICE 6.446 6.446 6.408 5.523 5.551 5.738 4.976 4.922 4.851 4.867 - --------------------------------------------------------------------------------------------------------------------------------- (5) Standard Service Backstop 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100 (5a) Standard Service Adjustment n/a n/a tbd tbd tbd tbd tbd ---- ---- ---- ---- ---- ---- --- TOTAL STANDARD SERVICE 0.000 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100 (6) TOTAL AVERAGE PRICE (EXCL. DISCOUNTS) 10.471 9.246 9.246 9.508 9.023 9.051 9.538 8.776 9.122 9.551 9.967 (7) Statutory Benchmark, Adjusted for Inflation 10.471 10.471 10.471 10.471 10.860 11.203 11.449 11.701 11.958 12.221 (8) Savings Off Inflation- Adjusted Price 11.70% 11.70% 9.20% 13.83% 16.66% 14.86% 23.35% 22.04% 20.13% 18.44% - --------------------------------------------------------------------------------------------------------------------------------- (2) 2001: 1999 Combined Company transmission costs per FERC 205 Filing, Exhibit__(PAV-4), Statement BG plus estimated NEPOOL transmission costs / combined kWh sales inflated at 2.2% for 2 years; see Workpaper TMB-3 2002 & beyond: inflated by 2.2% per year (3) 2001 & beyond: Workpaper TMB-4 (7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference Exhibit TMB-2, Page 2 S:\RADATA1\EASTED\2001\Path-01a.wk4 New England Electric System EEC-3 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Exhibit TMB-9, Revised Page 2 of 2 EASTERN EDISON COMPANY Average (cent)/kWh With Consolidation with Massachusetts Electric on January 1, 2001 1998 1999 ----------------- ----------------------- Benchmark Rates Sept- Jan- Sept- 8/01/97 March 1 ember 1 uary 1 April 1 ember 2000 2001 2002 2003 2004 ------- ------- ------- ------ ------ ------ ---- ---- ---- ---- ---- (1) Distribution 2.743 2.743 2.743 2.743 2.743 2.743 2.838 2.838 2.838 2.838 (1a) DSM 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250 (1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050 ------ ------ ------ ------ ------ ------ ------ ------ ------ ----- TOTAL DISTRIBUTION 0.000 3.148 3.148 3.153 3.153 3.153 3.153 3.208 3.163 3.138 3.138 (2) Transmission 0.258 0.258 0.215 0.270 0.298 0.285 0.518 0.529 0.541 0.553 (2a) Transmission Adjustment tbd tbd tbd tbd tbd tbd tbd ---- ---- ---- ---- ---- ---- --- TOTAL TRANSMISSION 0.000 0.258 0.258 0.215 0.270 0.298 0.285 0.518 0.529 0.541 0.553 (3) Transition 3.040 3.040 3.040 2.100 2.100 2.300 1.250 1.230 1.110 1.050 (3a) Transition Adjustment tbd tbd tbd tbd tbd tbd tbd ---- ---- ---- ---- ---- ---- --- TOTAL TRANSITION 0.000 3.040 3.040 3.040 2.100 2.100 2.300 1.250 1.230 1.110 1.050 (4) TOTAL AVERAGE RETAIL DELIVERY PRICE 6.446 6.446 6.408 5.523 5.551 5.738 4.976 4.922 4.789 4.741 - --------------------------------------------------------------------------------------------------------------------------------- (5) Standard Service Backstop 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100 (5a) Standard Service Adjustment n/a n/a tbd tbd tbd tbd tbd ---- ---- ---- ---- ---- ---- --- TOTAL STANDARD SERVICE 0.000 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100 (6) TOTAL AVERAGE PRICE (EXCL. DISCOUNTS) 10.471 9.246 9.246 9.508 9.023 9.051 9.538 8.776 9.122 9.489 9.841 (7) Statutory Benchmark, Adjusted for Inflation 10.471 10.471 10.471 10.471 10.860 11.203 11.449 11.701 11.958 12.221 (8) Savings Off Inflation- Adjusted Price 11.70% 11.70% 9.20% 13.83% 16.66% 14.86% 23.35% 22.04% 20.65% 19.47% - --------------------------------------------------------------------------------------------------------------------------------- (2) 2001: 1999 Combined Company transmission costs per FERC 205 Filing, Exhibit__(PAV-4), Statement BG plus estimated NEPOOL transmission costs / combined kWh sales inflated at 2.2% for 2 years; see Workpaper TMB-3 2002 & beyond: inflated by 2.2% per year (3) 2001 & beyond: Workpaper TMB-4 (7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference Exhibit TMB-2, Page 2
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-10 Eastern Edison Company Typical Bills January 1, 2001 Assuming No Merger vs. January 1, 2001 Combined Rates
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: R-1 TO R-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:37 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 1 of 82 Impact on R-1 to R-1 Rate Customers - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % - ---------------------------------------------------------------------------------------------------------------------------------- 10 $2.38 $0.38 $2.00 $6.66 $0.38 $6.28 $4.28 179.8% 50 $6.51 $1.90 $4.61 $10.06 $1.90 $8.16 $3.55 54.5% 100 $11.66 $3.80 $7.86 $14.30 $3.80 $10.50 $2.64 22.6% 250 $27.14 $9.50 $17.64 $27.04 $9.50 $17.54 ($0.10) -0.4% 500 $52.93 $19.00 $33.93 $48.28 $19.00 $29.28 ($4.65) -8.8% 750 $78.72 $28.50 $50.22 $69.51 $28.50 $41.01 ($9.21) -11.7% 1,000 $104.51 $38.00 $66.51 $90.74 $38.00 $52.74 ($13.77) -13.2% 1,500 $156.10 $57.00 $99.10 $133.21 $57.00 $76.21 ($22.89) -14.7% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates R-1 to R-1 Year 2001 Consolidated Rates R-1 to R-1 Customer Charge $1.34 Customer Charge $5.81 Distribution Charge KWh x $0.03556 Distribution Charge KWh x $0.02502 Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00571 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: R-2 TO R-2 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:37 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 2 of 82 Impact on R-2 to R-2 Rate Customers - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % - ---------------------------------------------------------------------------------------------------------------------------------- 10 $1.61 $0.38 $1.23 $4.42 $0.38 $4.04 $2.81 174.5% 50 $4.55 $1.90 $2.65 $7.00 $1.90 $5.10 $2.45 53.8% 100 $8.21 $3.80 $4.41 $10.22 $3.80 $6.42 $2.01 24.5% 250 $19.23 $9.50 $9.73 $19.91 $9.50 $10.41 $0.68 3.5% 500 $37.58 $19.00 $18.58 $36.04 $19.00 $17.04 ($1.54) -4.1% 600 $44.91 $22.80 $22.11 $42.49 $22.80 $19.69 ($2.42) -5.4% 750 $55.92 $28.50 $27.42 $52.18 $28.50 $23.68 ($3.74) -6.7% 1,000 $74.27 $38.00 $36.27 $68.31 $38.00 $30.31 ($5.96) -8.0% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates R-2 to R-2 Year 2001 Consolidated Rates R-2 to R-2 Customer Charge $0.87 Customer Charge $3.77 Distribution Charge KWh x $0.00579 Distribution Charge KWh x $0.00463 Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00571 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: R-3 TO R-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:37 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 3 of 82 Impact on R-3 to R-1 Rate Customers - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % - ---------------------------------------------------------------------------------------------------------------------------------- 50 $6.39 $1.90 $4.49 $10.06 $1.90 $8.16 $3.67 57.4% 100 $10.97 $3.80 $7.17 $14.30 $3.80 $10.50 $3.33 30.4% 250 $24.76 $9.50 $15.26 $27.04 $9.50 $17.54 $2.28 9.2% 500 $47.71 $19.00 $28.71 $48.28 $19.00 $29.28 $0.57 1.2% 750 $70.67 $28.50 $42.17 $69.51 $28.50 $41.01 ($1.16) -1.6% 1,000 $93.62 $38.00 $55.62 $90.74 $38.00 $52.74 ($2.88) -3.1% 1,500 $139.54 $57.00 $82.54 $133.21 $57.00 $76.21 ($6.33) -4.5% 2,000 $185.45 $76.00 $109.45 $175.67 $76.00 $99.67 ($9.78) -5.3% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates R-3 to R-1 Year 2001 Consolidated Rates R-3 to R-1 Customer Charge $1.79 Customer Charge $5.81 Distribution Charge KWh x $0.02422 Distribution Charge KWh x $0.02502 Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00571 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: R-4 TO R-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:37 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 4 of 82 Impact on R-4 to R-1 Rate Customers KWh Split: - On-Peak 20% - Off-Peak 80% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % - ---------------------------------------------------------------------------------------------------------------------------------- 500 $53.08 $19.00 $34.08 $48.28 $19.00 $29.28 ($4.80) -9.0% 750 $75.65 $28.50 $47.15 $69.52 $28.50 $41.02 ($6.13) -8.1% 1,000 $98.22 $38.00 $60.22 $90.74 $38.00 $52.74 ($7.48) -7.6% 1,250 $120.80 $47.50 $73.30 $111.99 $47.50 $64.49 ($8.81) -7.3% 1,500 $143.36 $57.00 $86.36 $133.21 $57.00 $76.21 ($10.15) -7.1% 2,000 $188.50 $76.00 $112.50 $175.67 $76.00 $99.67 ($12.83) -6.8% 2,500 $233.65 $95.00 $138.65 $218.14 $95.00 $123.14 ($15.51) -6.6% 3,000 $278.78 $114.00 $164.78 $260.60 $114.00 $146.60 ($18.18) -6.5% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates R-4 to R-1 Year 2001 Consolidated Rates R-4 to R-1 Customer Charge $7.93 Customer Charge $5.81 Distribution Charge KWh x $0.01690 Distribution Charge KWh x $0.02502 Access Charge: On Peak KWh x $0.10899 Transition Charge KWh x $0.01250 Access Charge: Off Peak KWh x $0.00872 Transmission Charge KWh x $0.00571 Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-1 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:37 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 5 of 82 Impact on G-1 to G-1 Rate Customers - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % - ---------------------------------------------------------------------------------------------------------------------------------- 50 $6.86 $1.90 $4.96 $13.24 $1.90 $11.34 $6.38 93.0% 100 $12.36 $3.80 $8.56 $18.15 $3.80 $14.35 $5.79 46.8% 250 $28.90 $9.50 $19.40 $32.90 $9.50 $23.40 $4.00 13.8% 500 $56.45 $19.00 $37.45 $57.48 $19.00 $38.48 $1.03 1.8% 1,000 $111.55 $38.00 $73.55 $106.63 $38.00 $68.63 ($4.92) -4.4% 2,500 $276.87 $95.00 $181.87 $254.10 $95.00 $159.10 ($22.77) -8.2% 5,000 $552.39 $190.00 $362.39 $499.87 $190.00 $309.87 ($52.52) -9.5% 7,500 $827.92 $285.00 $542.92 $745.65 $285.00 $460.65 ($82.27) -9.9% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-1 to G-1 Year 2001 Consolidated Rates G-1 to G-1 Customer Charge $1.34 Customer Charge $8.32 Distribution Charge KWh x $0.04260 Distribution Charge KWh x $0.03843 Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00568 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 6 of 82 Impact on G-2 to G-1 Rate Customers Hours Use: 100 - ---------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 10 1,000 $156.70 $38.00 $118.70 $106.39 $38.00 $68.39 ($50.31) -32.1% 12 1,200 $186.60 $45.60 $141.00 $126.00 $45.60 $80.40 ($60.60) -32.5% 15 1,500 $231.44 $57.00 $174.44 $155.43 $57.00 $98.43 ($76.01) -32.8% 17 1,700 $261.33 $64.60 $196.73 $175.04 $64.60 $110.44 ($86.29) -33.0% 20 2,000 $306.16 $76.00 $230.16 $204.46 $76.00 $128.46 ($101.70) -33.2% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1 Customer Charge $7.24 Customer Charge $8.32 Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843 Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00544 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 7 of 82 Impact on G-2 to G-1 Rate Customers Hours Use: 150 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 10 1,500 $186.94 $57.00 $129.94 $155.43 $57.00 $98.43 ($31.51) -16.9% 12 1,800 $222.86 $68.40 $154.46 $184.85 $68.40 $116.45 ($38.01) -17.1% 15 2,250 $276.78 $85.50 $191.28 $228.98 $85.50 $143.48 ($47.80) -17.3% 17 2,550 $312.72 $96.90 $215.82 $258.40 $96.90 $161.50 ($54.32) -17.4% 20 3,000 $366.62 $114.00 $252.62 $302.53 $114.00 $188.53 ($64.09) -17.5% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1 Customer Charge $7.24 Customer Charge $8.32 Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843 Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00544 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 8 of 82 Impact on G-2 to G-1 Rate Customers Hours Use: 200 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 10 2,000 $217.16 $76.00 $141.16 $204.46 $76.00 $128.46 ($12.70) -5.8% 12 2,400 $259.14 $91.20 $167.94 $243.69 $91.20 $152.49 ($15.45) -6.0% 15 3,000 $322.12 $114.00 $208.12 $302.53 $114.00 $188.53 ($19.59) -6.1% 17 3,400 $364.10 $129.20 $234.90 $341.76 $129.20 $212.56 ($22.34) -6.1% 20 4,000 $427.08 $152.00 $275.08 $400.60 $152.00 $248.60 ($26.48) -6.2% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1 Customer Charge $7.24 Customer Charge $8.32 Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843 Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00544 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 9 of 82 Impact on G-2 to G-1 Rate Customers Hours Use: 250 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 10 2,500 $247.40 $95.00 $152.40 $253.50 $95.00 $158.50 $6.10 2.5% 12 3,000 $295.42 $114.00 $181.42 $302.53 $114.00 $188.53 $7.11 2.4% 15 3,750 $367.48 $142.50 $224.98 $376.08 $142.50 $233.58 $8.60 2.3% 17 4,250 $415.50 $161.50 $254.00 $425.12 $161.50 $263.62 $9.62 2.3% 20 5,000 $487.54 $190.00 $297.54 $498.67 $190.00 $308.67 $11.13 2.3% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1 Customer Charge $7.24 Customer Charge $8.32 Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843 Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00544 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 10 of 82 Impact on G-2 to G-1 Rate Customers Hours Use: 300 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 10 3,000 $277.62 $114.00 $163.62 $302.53 $114.00 $188.53 $24.91 9.0% 12 3,600 $331.70 $136.80 $194.90 $361.37 $136.80 $224.57 $29.67 8.9% 15 4,500 $412.82 $171.00 $241.82 $449.64 $171.00 $278.64 $36.82 8.9% 17 5,100 $466.89 $193.80 $273.09 $508.48 $193.80 $314.68 $41.59 8.9% 20 6,000 $548.00 $228.00 $320.00 $596.74 $228.00 $368.74 $48.74 8.9% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1 Customer Charge $7.24 Customer Charge $8.32 Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843 Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00544 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 11 of 82 Impact on G-2 to G-1 Rate Customers Hours Use: 350 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 10 3,500 $308.07 $133.00 $175.07 $352.41 $133.00 $219.41 $44.34 14.4% 12 4,200 $368.23 $159.60 $208.63 $421.22 $159.60 $261.62 $52.99 14.4% 15 5,250 $458.48 $199.50 $258.98 $524.45 $199.50 $324.95 $65.97 14.4% 17 5,950 $518.63 $226.10 $292.53 $593.26 $226.10 $367.16 $74.63 14.4% 20 7,000 $608.88 $266.00 $342.88 $696.49 $266.00 $430.49 $87.61 14.4% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1 Customer Charge $7.24 Customer Charge $8.32 Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843 Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00568 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00291 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 12 of 82 Impact on G-2 to G-2 Rate Customers Hours Use: 200 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 10,000 $1,056.84 $380.00 $676.84 $916.13 $380.00 $536.13 ($140.71) -13.3% 100 20,000 $2,106.44 $760.00 $1,346.44 $1,817.03 $760.00 $1,057.03 ($289.41) -13.7% 125 25,000 $2,631.24 $950.00 $1,681.24 $2,267.48 $950.00 $1,317.48 ($363.76) -13.8% 150 30,000 $3,156.04 $1,140.00 $2,016.04 $2,717.93 $1,140.00 $1,577.93 ($438.11) -13.9% 175 35,000 $3,680.84 $1,330.00 $2,350.84 $3,168.38 $1,330.00 $1,838.38 ($512.46) -13.9% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2 Customer Charge $7.24 Customer Charge $15.23 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KWh x $5.92 Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250 Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00491 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 13 of 82 Impact on G-2 to G-2 Rate Customers Hours Use: 250 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 12,500 $1,208.00 $475.00 $733.00 $1,067.36 $475.00 $592.36 ($140.64) -11.6% 100 25,000 $2,408.74 $950.00 $1,458.74 $2,119.48 $950.00 $1,169.48 ($289.26) -12.0% 125 31,250 $3,009.12 $1,187.50 $1,821.62 $2,645.54 $1,187.50 $1,458.04 ($363.58) -12.1% 150 37,500 $3,609.50 $1,425.00 $2,184.50 $3,171.61 $1,425.00 $1,746.61 ($437.89) -12.1% 175 43,750 $4,209.88 $1,662.50 $2,547.38 $3,697.67 $1,662.50 $2,035.17 ($512.21) -12.2% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2 Customer Charge $7.24 Customer Charge $15.23 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250 Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00491 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 14 of 82 Impact on G-2 to G-2 Rate Customers Hours Use: 300 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 15,000 $1,359.14 $570.00 $789.14 $1,218.58 $570.00 $648.58 ($140.56) -10.3% 100 30,000 $2,711.04 $1,140.00 $1,571.04 $2,421.93 $1,140.00 $1,281.93 ($289.11) -10.7% 125 37,500 $3,387.00 $1,425.00 $1,962.00 $3,023.61 $1,425.00 $1,598.61 ($363.39) -10.7% 150 45,000 $4,062.94 $1,710.00 $2,352.94 $3,625.28 $1,710.00 $1,915.28 ($437.66) -10.8% 175 52,500 $4,738.90 $1,995.00 $2,743.90 $4,226.96 $1,995.00 $2,231.96 ($511.94) -10.8% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2 Customer Charge $7.24 Customer Charge $15.23 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250 Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00491 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 15 of 82 Impact on G-2 to G-2 Rate Customers Hours Use: 350 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 17,500 $1,510.30 $665.00 $845.30 $1,369.81 $665.00 $704.81 ($140.49) -9.3% 100 35,000 $3,013.34 $1,330.00 $1,683.34 $2,724.38 $1,330.00 $1,394.38 ($288.96) -9.6% 125 43,750 $3,764.88 $1,662.50 $2,102.38 $3,401.67 $1,662.50 $1,739.17 ($363.21) -9.6% 150 52,500 $4,516.40 $1,995.00 $2,521.40 $4,078.96 $1,995.00 $2,083.96 ($437.44) -9.7% 175 61,250 $5,267.92 $2,327.50 $2,940.42 $4,756.24 $2,327.50 $2,428.74 ($511.68) -9.7% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2 Customer Charge $7.24 Customer Charge $15.23 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250 Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00491 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 16 of 82 Impact on G-2 to G-2 Rate Customers Hours Use: 400 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 20,000 $1,661.44 $760.00 $901.44 $1,521.03 $760.00 $761.03 ($140.41) -8.5% 100 40,000 $3,315.64 $1,520.00 $1,795.64 $3,026.83 $1,520.00 $1,506.83 ($288.81) -8.7% 125 50,000 $4,142.74 $1,900.00 $2,242.74 $3,779.73 $1,900.00 $1,879.73 ($363.01) -8.8% 150 60,000 $4,969.84 $2,280.00 $2,689.84 $4,532.63 $2,280.00 $2,252.63 ($437.21) -8.8% 175 70,000 $5,796.94 $2,660.00 $3,136.94 $5,285.53 $2,660.00 $2,625.53 ($511.41) -8.8% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2 Customer Charge $7.24 Customer Charge $15.23 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250 Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00491 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-2 TO G-2 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 17 of 82 Impact on G-2 to G-2 Rate Customers Hours Use: 450 - --------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - --------------------------------------------------------------------------------------------------------------------------- 50 22,500 $1,813.95 $855.00 $958.95 $1,677.21 $855.00 $822.21 ($136.74) -7.5% 100 45,000 $3,620.64 $1,710.00 $1,910.64 $3,339.18 $1,710.00 $1,629.18 ($281.46) -7.8% 125 56,250 $4,524.00 $2,137.50 $2,386.50 $4,170.17 $2,137.50 $2,032.67 ($353.83) -7.8% 150 67,500 $5,427.35 $2,565.00 $2,862.35 $5,001.16 $2,565.00 $2,436.16 ($426.19) -7.9% 175 78,750 $6,330.70 $2,992.50 $3,338.20 $5,832.14 $2,992.50 $2,839.64 ($498.56) -7.9% - --------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2 Customer Charge $7.24 Customer Charge $15.23 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250 Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00513 Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 18 of 82 Impact on G-2 to G-3 Rate Customers Hours Use: 250 kWh Split: On Peak: 55% Off Peak: 45% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 62,500 $6,011.00 $2,375.00 $3,636.00 $5,043.93 $2,375.00 $2,668.93 ($967.07) -16.1% 300 75,000 $7,211.74 $2,850.00 $4,361.74 $6,039.26 $2,850.00 $3,189.26 ($1,172.48) -16.3% 350 87,500 $8,412.50 $3,325.00 $5,087.50 $7,034.59 $3,325.00 $3,709.59 ($1,377.91) -16.4% 400 100,000 $9,613.24 $3,800.00 $5,813.24 $8,029.92 $3,800.00 $4,229.92 ($1,583.32) -16.5% 450 112,500 $10,814.00 $4,275.00 $6,539.00 $9,025.25 $4,275.00 $4,750.25 ($1,788.75) -16.5% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3 Customer Charge $7.24 Customer Charge $67.27 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00285 Transmission Charge KWh x $0.00440 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 19 of 82 Impact on G-2 to G-3 Rate Customers Hours Use: 300 kWh Split: On Peak: 50% Off Peak: 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 75,000 $6,766.74 $2,850.00 $3,916.74 $5,813.40 $2,850.00 $2,963.40 ($953.34) -14.1% 300 90,000 $8,118.64 $3,420.00 $4,698.64 $6,962.62 $3,420.00 $3,542.62 ($1,156.02) -14.2% 350 105,000 $9,470.54 $3,990.00 $5,480.54 $8,111.85 $3,990.00 $4,121.85 ($1,358.69) -14.3% 400 120,000 $10,822.44 $4,560.00 $6,262.44 $9,261.07 $4,560.00 $4,701.07 ($1,561.37) -14.4% 450 135,000 $12,174.34 $5,130.00 $7,044.34 $10,410.30 $5,130.00 $5,280.30 ($1,764.04) -14.5% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3 Customer Charge $7.24 Customer Charge $67.27 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00285 Transmission Charge KWh x $0.00440 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 20 of 82 Impact on G-2 to G-3 Rate Customers Hours Use: 350 kWh Split: On Peak: 50% Off Peak: 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 87,500 $7,522.50 $3,325.00 $4,197.50 $6,619.83 $3,325.00 $3,294.83 ($902.67) -12.0% 300 105,000 $9,025.54 $3,990.00 $5,035.54 $7,930.35 $3,990.00 $3,940.35 ($1,095.19) -12.1% 350 122,500 $10,528.60 $4,655.00 $5,873.60 $9,240.86 $4,655.00 $4,585.86 ($1,287.74) -12.2% 400 140,000 $12,031.64 $5,320.00 $6,711.64 $10,551.37 $5,320.00 $5,231.37 ($1,480.27) -12.3% 450 157,500 $13,534.70 $5,985.00 $7,549.70 $11,861.88 $5,985.00 $5,876.88 ($1,672.82) -12.4% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3 Customer Charge $7.24 Customer Charge $67.27 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00285 Transmission Charge KWh x $0.00440 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 21 of 82 Impact on G-2 to G-3 Rate Customers Hours Use: 400 kWh Split: On Peak: 45% Off Peak: 55% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 100,000 $8,278.24 $3,800.00 $4,478.24 $7,367.12 $3,800.00 $3,567.12 ($911.12) -11.0% 300 120,000 $9,932.44 $4,560.00 $5,372.44 $8,827.09 $4,560.00 $4,267.09 ($1,105.35) -11.1% 350 140,000 $11,586.64 $5,320.00 $6,266.64 $10,287.06 $5,320.00 $4,967.06 ($1,299.58) -11.2% 400 160,000 $13,240.84 $6,080.00 $7,160.84 $11,747.03 $6,080.00 $5,667.03 ($1,493.81) -11.3% 450 180,000 $14,895.04 $6,840.00 $8,055.04 $13,207.00 $6,840.00 $6,367.00 ($1,688.04) -11.3% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3 Customer Charge $7.24 Customer Charge $67.27 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00285 Transmission Charge KWh x $0.00440 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 22 of 82 Impact on G-2 to G-3 Rate Customers Hours Use: 450 kWh Split: On Peak: 45% Off Peak: 55% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 112,500 $9,034.00 $4,275.00 $4,759.00 $8,166.16 $4,275.00 $3,891.16 ($867.84) -9.6% 300 135,000 $10,839.34 $5,130.00 $5,709.34 $9,785.94 $5,130.00 $4,655.94 ($1,053.40) -9.7% 350 157,500 $12,644.70 $5,985.00 $6,659.70 $11,405.72 $5,985.00 $5,420.72 ($1,238.98) -9.8% 400 180,000 $14,450.04 $6,840.00 $7,610.04 $13,025.50 $6,840.00 $6,185.50 ($1,424.54) -9.9% 450 202,500 $16,255.40 $7,695.00 $8,560.40 $14,645.28 $7,695.00 $6,950.28 ($1,610.12) -9.9% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3 Customer Charge $7.24 Customer Charge $67.27 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00285 Transmission Charge KWh x $0.00440 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-2 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 23 of 82 Impact on G-2 to G-3 Rate Customers Hours Use: 500 kWh Split: On Peak: 45% Off Peak: 55% - ---------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ---------------------------------------------------------------------------------------------------------------------------------- 10 3,500 $308.07 $133.00 $175.07 $352.41 $133.00 $219.41 $44.34 14.4% 250 125,000 $9,797.24 $4,750.00 $5,047.24 $8,990.21 $4,750.00 $4,240.21 ($807.03) -8.2% 300 150,000 $11,755.24 $5,700.00 $6,055.24 $10,774.80 $5,700.00 $5,074.80 ($980.44) -8.3% 350 175,000 $13,713.24 $6,650.00 $7,063.24 $12,559.38 $6,650.00 $5,909.38 ($1,153.86) -8.4% 400 200,000 $15,671.24 $7,600.00 $8,071.24 $14,343.97 $7,600.00 $6,743.97 ($1,327.27) -8.5% 450 225,000 $17,629.24 $8,550.00 $9,079.24 $16,128.56 $8,550.00 $7,578.56 ($1,500.68) -8.5% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3 Customer Charge $7.24 Customer Charge $67.27 Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00460 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 24 of 82 Impact on G-4 to G-3 Rate Customers Hours Use: 250 kWh Split: On Peak: 35% 55% Off Peak: 65% 45% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 600 150,000 $14,427.12 $5,700.00 $8,727.12 $12,011.25 $5,700.00 $6,311.25 ($2,415.87) -16.7% 800 200,000 $19,230.22 $7,600.00 $11,630.22 $15,992.57 $7,600.00 $8,392.57 ($3,237.65) -16.8% 1000 250,000 $24,033.32 $9,500.00 $14,533.32 $19,973.90 $9,500.00 $10,473.90 ($4,059.42) -16.9% 1500 375,000 $36,041.07 $14,250.00 $21,791.07 $29,927.21 $14,250.00 $15,677.21 ($6,113.86) -17.0% 3000 750,000 $72,064.32 $28,500.00 $43,564.32 $59,787.15 $28,500.00 $31,287.15 ($12,277.17) -17.0% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3 Customer Charge $17.82 Customer Charge $67.27 Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 25 of 82 Impact on G-4 to G-3 Rate Customers Hours Use: 300 kWh Split: On Peak: 30% 50% Off Peak: 70% 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 600 180,000 $16,191.90 $6,840.00 $9,351.90 $13,857.97 $6,840.00 $7,017.97 ($2,333.93) -14.4% 800 240,000 $21,583.26 $9,120.00 $12,463.26 $18,454.87 $9,120.00 $9,334.87 ($3,128.39) -14.5% 1000 300,000 $26,974.62 $11,400.00 $15,574.62 $23,051.77 $11,400.00 $11,651.77 ($3,922.85) -14.5% 1500 450,000 $40,453.02 $17,100.00 $23,353.02 $34,544.02 $17,100.00 $17,444.02 ($5,909.00) -14.6% 3000 900,000 $80,888.22 $34,200.00 $46,688.22 $69,020.77 $34,200.00 $34,820.77 ($11,867.45) -14.7% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3 Customer Charge $17.82 Customer Charge $67.27 Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 26 of 82 Impact on G-4 to G-3 Rate Customers Hours Use: 150 350 kWh Split: On Peak: 30% 50% Off Peak: 70% 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 600 210,000 $18,002.58 $7,980.00 $10,022.58 $15,793.42 $7,980.00 $7,813.42 ($2,209.16) -12.3% 800 280,000 $23,997.50 $10,640.00 $13,357.50 $21,035.47 $10,640.00 $10,395.47 ($2,962.03) -12.3% 1000 350,000 $29,992.42 $13,300.00 $16,692.42 $26,277.52 $13,300.00 $12,977.52 ($3,714.90) -12.4% 1500 525,000 $44,979.72 $19,950.00 $25,029.72 $39,382.65 $19,950.00 $19,432.65 ($5,597.07) -12.4% 3000 1,050,000 $89,941.62 $39,900.00 $50,041.62 $78,698.02 $39,900.00 $38,798.02 ($11,243.60) -12.5% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3 Customer Charge $17.82 Customer Charge $67.27 Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 27 of 82 Impact on G-4 to G-3 Rate Customers Hours Use: 400 kWh Split: On Peak: 25% 45% Off Peak: 75% 55% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 600 240,000 $19,739.82 $9,120.00 $10,619.82 $17,586.91 $9,120.00 $8,466.91 ($2,152.91) -10.9% 800 320,000 $26,313.82 $12,160.00 $14,153.82 $23,426.79 $12,160.00 $11,266.79 ($2,887.03) -11.0% 1000 400,000 $32,887.82 $15,200.00 $17,687.82 $29,266.67 $15,200.00 $14,066.67 ($3,621.15) -11.0% 1500 600,000 $49,322.82 $22,800.00 $26,522.82 $43,866.37 $22,800.00 $21,066.37 ($5,456.45) -11.1% 3000 1,200,000 $98,627.82 $45,600.00 $53,027.82 $87,665.47 $45,600.00 $42,065.47 ($10,962.35) -11.1% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3 Customer Charge $17.82 Customer Charge $67.27 Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 28 of 82 Impact on G-4 to G-3 Rate Customers Hours Use: 450 kWh Split: On Peak: 25% 45% Off Peak: 75% 55% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 600 270,000 $21,541.32 $10,260.00 $11,281.32 $19,504.62 $10,260.00 $9,244.62 ($2,036.70) -9.5% 800 360,000 $28,715.82 $13,680.00 $15,035.82 $25,983.73 $13,680.00 $12,303.73 ($2,732.09) -9.5% 1000 450,000 $35,890.32 $17,100.00 $18,790.32 $32,462.85 $17,100.00 $15,362.85 ($3,427.47) -9.5% 1500 675,000 $53,826.57 $25,650.00 $28,176.57 $48,660.63 $25,650.00 $23,010.63 ($5,165.94) -9.6% 3000 1,350,000 $107,635.32 $51,300.00 $56,335.32 $97,254.00 $51,300.00 $45,954.00 ($10,381.32) -9.6% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3 Customer Charge $17.82 Customer Charge $67.27 Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-4 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 29 of 82 Impact on G-4 to G-3 Rate Customers Hours Use: 500 kWh Split: On Peak: 25% 45% Off Peak: 75% 55% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 600 300,000 $23,360.82 $11,400.00 $11,960.82 $21,482.32 $11,400.00 $10,082.32 ($1,878.50) -8.0% 800 400,000 $31,141.82 $15,200.00 $15,941.82 $28,620.67 $15,200.00 $13,420.67 ($2,521.15) -8.1% 1,000 500,000 $38,922.82 $19,000.00 $19,922.82 $35,759.02 $19,000.00 $16,759.02 ($3,163.80) -8.1% 1,500 750,000 $58,375.32 $28,500.00 $29,875.32 $53,604.90 $28,500.00 $25,104.90 ($4,770.42) -8.2% 3,000 1,500,000 $116,732.82 $57,000.00 $59,732.82 $107,142.52 $57,000.00 $50,142.52 ($9,590.30) -8.2% - -------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3 Customer Charge $17.82 Customer Charge $67.27 Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00460 Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 30 of 82 Impact on G-5 to G-3 Rate Customers Hours Use: 250 kWh Split: On Peak: 35% 55% Off Peak: 65% 45% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 150 37,500 $3,620.70 $1,425.00 $2,195.70 $2,955.23 $1,425.00 $1,530.23 ($665.47) -18.4% 200 50,000 $4,812.97 $1,900.00 $2,912.97 $3,918.11 $1,900.00 $2,018.11 ($894.86) -18.6% 300 75,000 $7,197.53 $2,850.00 $4,347.53 $5,843.86 $2,850.00 $2,993.86 ($1,353.67) -18.8% 400 100,000 $9,582.07 $3,800.00 $5,782.07 $7,769.62 $3,800.00 $3,969.62 ($1,812.45) -18.9% 450 112,500 $10,774.35 $4,275.00 $6,499.35 $8,732.50 $4,275.00 $4,457.50 ($2,041.85) -19.0% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 31 of 82 Impact on G-5 to G-3 Rate Customers Hours Use: 300 kWh Split: On Peak: 30% 50% Off Peak: 70% 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 150 45,000 $4,113.64 $1,710.00 $2,403.64 $3,412.30 $1,710.00 $1,702.30 ($701.34) -17.0% 200 60,000 $5,470.23 $2,280.00 $3,190.23 $4,527.53 $2,280.00 $2,247.53 ($942.70) -17.2% 300 90,000 $8,183.41 $3,420.00 $4,763.41 $6,757.99 $3,420.00 $3,337.99 ($1,425.42) -17.4% 400 120,000 $10,896.59 $4,560.00 $6,336.59 $8,988.46 $4,560.00 $4,428.46 ($1,908.13) -17.5% 450 135,000 $12,253.18 $5,130.00 $7,123.18 $10,103.69 $5,130.00 $4,973.69 ($2,149.49) -17.5% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 32 of 82 Impact on G-5 to G-3 Rate Customers Hours Use: 350 kWh Split: On Peak: 30% 50% Off Peak: 70% 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 150 52,500 $4,616.95 $1,995.00 $2,621.95 $3,891.32 $1,995.00 $1,896.32 ($725.63) -15.7% 200 70,000 $6,141.29 $2,660.00 $3,481.29 $5,166.23 $2,660.00 $2,506.23 ($975.06) -15.9% 300 105,000 $9,190.00 $3,990.00 $5,200.00 $7,716.04 $3,990.00 $3,726.04 ($1,473.96) -16.0% 400 140,000 $12,238.71 $5,320.00 $6,918.71 $10,265.86 $5,320.00 $4,945.86 ($1,972.85) -16.1% 450 157,500 $13,763.08 $5,985.00 $7,778.08 $11,540.76 $5,985.00 $5,555.76 ($2,222.32) -16.1% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 33 of 82 Impact on G-5 to G-3 Rate Customers Hours Use: 400 kWh Split: On Peak: 25% 45% Off Peak: 75% 55% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 150 60,000 $5,103.67 $2,280.00 $2,823.67 $4,335.21 $2,280.00 $2,055.21 ($768.46) -15.1% 200 80,000 $6,790.27 $3,040.00 $3,750.27 $5,758.08 $3,040.00 $2,718.08 ($1,032.19) -15.2% 300 120,000 $10,163.47 $4,560.00 $5,603.47 $8,603.82 $4,560.00 $4,043.82 ($1,559.65) -15.3% 400 160,000 $13,536.67 $6,080.00 $7,456.67 $11,449.56 $6,080.00 $5,369.56 ($2,087.11) -15.4% 450 180,000 $15,223.27 $6,840.00 $8,383.27 $12,872.43 $6,840.00 $6,032.43 ($2,350.84) -15.4% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 34 of 82 Impact on G-5 to G-3 Rate Customers Hours Use: 450 kWh Split: On Peak: 25% 45% Off Peak: 75% 55% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 150 67,500 $5,604.90 $2,565.00 $3,039.90 $4,809.84 $2,565.00 $2,244.84 ($795.06) -14.2% 200 90,000 $7,458.57 $3,420.00 $4,038.57 $6,390.92 $3,420.00 $2,970.92 ($1,067.65) -14.3% 300 135,000 $11,165.93 $5,130.00 $6,035.93 $9,553.08 $5,130.00 $4,423.08 ($1,612.85) -14.4% 400 180,000 $14,873.27 $6,840.00 $8,033.27 $12,715.25 $6,840.00 $5,875.25 ($2,158.02) -14.5% 450 202,500 $16,726.95 $7,695.00 $9,031.95 $14,296.33 $7,695.00 $6,601.33 ($2,430.62) -14.5% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-5 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 35 of 82 Impact on G-5 to G-3 Rate Customers Hours Use: 500 kWh Split: On Peak: 25% 45% Off Peak: 75% 55% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 600 300,000 $23,360.82 $11,400.00 $11,960.82 $21,482.32 $11,400.00 $10,082.32 ($1,878.50) -8.0% 150 75,000 $6,110.63 $2,850.00 $3,260.63 $5,299.32 $2,850.00 $2,449.32 ($811.31) -13.3% 200 100,000 $8,132.87 $3,800.00 $4,332.87 $7,043.56 $3,800.00 $3,243.56 ($1,089.31) -13.4% 300 150,000 $12,177.37 $5,700.00 $6,477.37 $10,532.05 $5,700.00 $4,832.05 ($1,645.32) -13.5% 400 200,000 $16,221.87 $7,600.00 $8,621.87 $14,020.53 $7,600.00 $6,420.53 ($2,201.34) -13.6% 450 225,000 $18,244.13 $8,550.00 $9,694.13 $15,764.77 $8,550.00 $7,214.77 ($2,479.36) -13.6% - -------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00460 Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 36 of 82 Impact on G-6 to G-3 Rate Customers Hours Use: 250 kWh Split: On Peak: 35% 55% Off Peak: 65% 45% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 600 150,000 $14,165.18 $5,700.00 $8,465.18 $11,621.13 $5,700.00 $5,921.13 ($2,544.05) -18.0% 800 200,000 $18,872.27 $7,600.00 $11,272.27 $15,472.64 $7,600.00 $7,872.64 ($3,399.63) -18.0% 1000 250,000 $23,579.39 $9,500.00 $14,079.39 $19,324.16 $9,500.00 $9,824.16 ($4,255.23) -18.0% 1500 375,000 $35,347.12 $14,250.00 $21,097.12 $28,952.94 $14,250.00 $14,702.94 ($6,394.18) -18.1% 3000 750,000 $70,650.38 $28,500.00 $42,150.38 $57,839.27 $28,500.00 $29,339.27 ($12,811.11) -18.1% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 37 of 82 Impact on G-6 to G-3 Rate Customers Hours Use: 300 kWh Split: On Peak: 30% 50% Off Peak: 70% 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 600 180,000 $16,099.75 $6,840.00 $9,259.75 $13,449.39 $6,840.00 $6,609.39 ($2,650.36) -16.5% 800 240,000 $21,451.71 $9,120.00 $12,331.71 $17,910.32 $9,120.00 $8,790.32 ($3,541.39) -16.5% 1000 300,000 $26,803.67 $11,400.00 $15,403.67 $22,371.25 $11,400.00 $10,971.25 ($4,432.42) -16.5% 1500 450,000 $40,183.57 $17,100.00 $23,083.57 $33,523.58 $17,100.00 $16,423.58 ($6,659.99) -16.6% 3000 900,000 $80,323.27 $34,200.00 $46,123.27 $66,980.56 $34,200.00 $32,780.56 ($13,342.71) -16.6% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 38 of 82 Impact on G-6 to G-3 Rate Customers Hours Use: 350 kWh Split: On Peak: 30% 50% Off Peak: 70% 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 600 210,000 $18,075.73 $7,980.00 $10,095.73 $15,365.49 $7,980.00 $7,385.49 ($2,710.24) -15.0% 800 280,000 $24,086.35 $10,640.00 $13,446.35 $20,465.12 $10,640.00 $9,825.12 ($3,621.23) -15.0% 1000 350,000 $30,096.97 $13,300.00 $16,796.97 $25,564.74 $13,300.00 $12,264.74 ($4,532.23) -15.1% 1500 525,000 $45,123.53 $19,950.00 $25,173.53 $38,313.82 $19,950.00 $18,363.82 ($6,809.71) -15.1% 3000 1,050,000 $90,203.17 $39,900.00 $50,303.17 $76,561.04 $39,900.00 $36,661.04 ($13,642.13) -15.1% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 39 of 82 Impact on G-6 to G-3 Rate Customers Hours Use: 400 kWh Split: On Peak: 25% 45% Off Peak: 75% 55% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 600 240,000 $19,985.47 $9,120.00 $10,865.47 $17,141.04 $9,120.00 $8,021.04 ($2,844.43) -14.2% 800 320,000 $26,632.67 $12,160.00 $14,472.67 $22,832.52 $12,160.00 $10,672.52 ($3,800.15) -14.3% 1000 400,000 $33,279.87 $15,200.00 $18,079.87 $28,524.00 $15,200.00 $13,324.00 ($4,755.87) -14.3% 1500 600,000 $49,897.87 $22,800.00 $27,097.87 $42,752.71 $22,800.00 $19,952.71 ($7,145.16) -14.3% 3000 1,200,000 $99,751.87 $45,600.00 $54,151.87 $85,438.82 $45,600.00 $39,838.82 ($14,313.05) -14.3% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 40 of 82 Impact on G-6 to G-3 Rate Customers Hours Use: 450 kWh Split: On Peak: 25% 45% Off Peak: 75% 55% - ---------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 600 270,000 $21,953.18 $10,260.00 $11,693.18 $19,039.57 $10,260.00 $8,779.57 ($2,913.61) -13.3% 800 360,000 $29,256.27 $13,680.00 $15,576.27 $25,363.89 $13,680.00 $11,683.89 ($3,892.38) -13.3% 1000 450,000 $36,559.38 $17,100.00 $19,459.38 $31,688.22 $17,100.00 $14,588.22 ($4,871.16) -13.3% 1500 675,000 $54,817.12 $25,650.00 $29,167.12 $47,499.03 $25,650.00 $21,849.03 ($7,318.09) -13.4% 3000 1,350,000 $109,590.38 $51,300.00 $58,290.38 $94,931.46 $51,300.00 $43,631.46 ($14,658.92) -13.4% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 41 of 82 Impact on G-6 to G-3 Rate Customers Hours Use: 500 kWh Split: On Peak: 25% 45% Off Peak: 75% 55% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 600 300,000 $23,938.87 $11,400.00 $12,538.87 $20,997.50 $11,400.00 $9,597.50 ($2,941.37) -12.3% 800 400,000 $31,903.87 $15,200.00 $16,703.87 $27,974.46 $15,200.00 $12,774.46 ($3,929.41) -12.3% 1,000 500,000 $39,868.87 $19,000.00 $20,868.87 $34,951.43 $19,000.00 $15,951.43 ($4,917.44) -12.3% 1,500 750,000 $59,781.38 $28,500.00 $31,281.38 $52,393.85 $28,500.00 $23,893.85 ($7,387.53) -12.4% 3,000 1,500,000 $119,518.87 $57,000.00 $62,518.87 $104,721.09 $57,000.00 $47,721.09 ($14,797.78) -12.4% - ------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3 Customer Charge $43.87 Customer Charge $67.27 Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00460 Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45) High Voltage Delivery Discount -1% Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 42 of 82 Impact on T-2 to G-1 Rate Customers Hours Use: 175 kWh Split: On Peak: 25% Off Peak: 75% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 10 1,750 $205.78 $66.50 $139.28 $179.94 $66.50 $113.44 ($25.84) -12.6% 12 2,100 $244.37 $79.80 $164.57 $214.27 $79.80 $134.47 ($30.10) -12.3% 15 2,625 $302.25 $99.75 $202.50 $265.75 $99.75 $166.00 ($36.50) -12.1% 17 2,975 $340.83 $113.05 $227.78 $300.08 $113.05 $187.03 ($40.75) -12.0% 20 3,500 $398.73 $133.00 $265.73 $351.57 $133.00 $218.57 ($47.16) -11.8% - ------------------------------------------------------------------------------------------------------------------------------ Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates T-2 to G-1 Customer Charge $12.84 Customer Charge $8.32 Distribution Demand Charge KW x $2.92 Distribution KWh x $0.03843 Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00544 Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270 Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 43 of 82 Impact on T-2 to G-1 Rate Customers Hours Use: 200 kWh Split: On Peak: 20% Off Peak: 80% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 10 2,000 $219.57 $76.00 $143.57 $204.46 $76.00 $128.46 ($15.11) -6.9% 12 2,400 $260.91 $91.20 $169.71 $243.69 $91.20 $152.49 ($17.22) -6.6% 15 3,000 $322.94 $114.00 $208.94 $302.53 $114.00 $188.53 ($20.41) -6.3% 17 3,400 $364.28 $129.20 $235.08 $341.76 $129.20 $212.56 ($22.52) -6.2% 20 4,000 $426.31 $152.00 $274.31 $400.60 $152.00 $248.60 ($25.71) -6.0% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates T-2 to G-1 Customer Charge $12.84 Customer Charge $8.32 Distribution Demand Charge KW x $2.92 Distribution KWh x $0.03843 Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00544 Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270 Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 44 of 82 Impact on T-2 to G-1 Rate Customers Hours Use: 225 kWh Split: On Peak: 20% Off Peak: 80% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 10 2,250 $233.90 $85.50 $148.40 $228.98 $85.50 $143.48 ($4.92) -2.1% 12 2,700 $278.12 $102.60 $175.52 $273.11 $102.60 $170.51 ($5.01) -1.8% 15 3,375 $344.44 $128.25 $216.19 $339.31 $128.25 $211.06 ($5.13) -1.5% 17 3,825 $388.65 $145.35 $243.30 $383.44 $145.35 $238.09 ($5.21) -1.3% 20 4,500 $454.97 $171.00 $283.97 $449.64 $171.00 $278.64 ($5.33) -1.2% - ------------------------------------------------------------------------------------------------------------------------------ Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates T-2 to G-1 Customer Charge $12.84 Customer Charge $8.32 Distribution Demand Charge KW x $2.92 Distribution KWh x $0.03843 Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00544 Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270 Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 45 of 82 Impact on T-2 to G-1 Rate Customers Hours Use: 250 kWh Split: On Peak: 15% Off Peak: 85% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 10 2,500 $247.47 $95.00 $152.47 $253.50 $95.00 $158.50 $6.03 2.4% 12 3,000 $294.39 $114.00 $180.39 $302.53 $114.00 $188.53 $8.14 2.8% 15 3,750 $364.78 $142.50 $222.28 $376.08 $142.50 $233.58 $11.30 3.1% 17 4,250 $411.70 $161.50 $250.20 $425.12 $161.50 $263.62 $13.42 3.3% 20 5,000 $482.09 $190.00 $292.09 $498.67 $190.00 $308.67 $16.58 3.4% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates T-2 to G-1 Customer Charge $12.84 Customer Charge $8.32 Distribution Demand Charge KW x $2.92 Distribution KWh x $0.03843 Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00544 Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270 Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 46 of 82 Impact on T-2 to G-1 Rate Customers Hours Use: 275 kWh Split: On Peak: 15% Off Peak: 85% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 10 2,750 $261.73 $104.50 $157.23 $278.01 $104.50 $173.51 $16.28 6.2% 12 3,300 $311.49 $125.40 $186.09 $331.95 $125.40 $206.55 $20.46 6.6% 15 4,125 $386.16 $156.75 $229.41 $412.86 $156.75 $256.11 $26.70 6.9% 17 4,675 $435.93 $177.65 $258.28 $466.80 $177.65 $289.15 $30.87 7.1% 20 5,500 $510.60 $209.00 $301.60 $547.71 $209.00 $338.71 $37.11 7.3% - ---------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates T-2 to G-1 Customer Charge $12.84 Customer Charge $8.32 Distribution Demand Charge KW x $2.92 Distribution KWh x $0.03843 Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00544 Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270 Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 47 of 82 Impact on T-2 to G-1 Rate Customers Hours Use: 300 kWh Split: On Peak: 15% Off Peak: 85% - --------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - --------------------------------------------------------------------------------------------------------------- 10 3,000 $276.15 $114.00 $162.15 $303.25 $114.00 $189.25 $27.10 9.8% 12 3,600 $328.81 $136.80 $192.01 $362.24 $136.80 $225.44 $33.43 10.2% 15 4,500 $407.81 $171.00 $236.81 $450.72 $171.00 $279.72 $42.91 10.5% 17 5,100 $460.46 $193.80 $266.66 $509.70 $193.80 $315.90 $49.24 10.7% 20 6,000 $539.45 $228.00 $311.45 $598.18 $228.00 $370.18 $58.73 10.9% - --------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates: T-2 to G-1 Customer Charge $12.84 Customer Charge $8.32 Distribution Demand Charge KW x $2.92 Distribution Charge KWh x $0.03843 Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250 Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00568 Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270 Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 48 of 82 Impact on T-2 to G-2 Rate Customers Hours Use: 200 kWh Split: On Peak: 25% Off Peak: 75% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 50 10,000 $1,049.57 $380.00 $669.57 $916.13 $380.00 $536.13 ($133.44) -12.7% 100 20,000 $2,086.29 $760.00 $1,326.29 $1,817.03 $760.00 $1,057.03 ($269.26) -12.9% 125 25,000 $2,604.65 $950.00 $1,654.65 $2,267.48 $950.00 $1,317.48 ($337.17) -12.9% 150 30,000 $3,123.02 $1,140.00 $1,938.02 $2,717.93 $1,140.00 $1,577.93 ($405.09) -13.0% 175 35,000 $3,641.38 $1,330.00 $2,311.38 $3,168.38 $1,330.00 $1,838.38 ($473.00) -13.0% Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates T-2 to G-2 Customer Charge $12.84 Customer Charge $15.23 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250 Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00491 Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 49 of 82 Impact on T-2 to G-2 Rate Customers Hours Use: 250 kWh Split: On Peak: 20% Off Peak: 80% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 50 12,500 $1,189.80 $475.00 $714.80 $1,067.36 $475.00 $592.36 ($122.44) -10.3% 100 25,000 $2,366.74 $950.00 $1,416.74 $2,119.48 $950.00 $1,169.48 ($247.26) -10.4% 125 31,250 $2,955.22 $1,187.50 $1,767.72 $2,645.54 $1,187.50 $1,458.04 ($309.68) -10.5% 150 37,500 $3,543.70 $1,425.00 $2,118.70 $3,171.61 $1,425.00 $1,746.61 ($372.09) -10.5% 175 43,750 $4,132.17 $1,662.50 $2,469.67 $3,697.67 $1,662.50 $2,035.17 ($434.50) -10.5% - ------------------------------------------------------------------------------------------------------------------------------ Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates T-2 to G-2 Customer Charge $12.84 Customer Charge $15.23 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250 Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00491 Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 50 of 82 Impact on T-2 to G-2 Rate Customers Hours Use: 300 kWh Split: On Peak: 20% Off Peak: 80% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 50 15,000 $1,333.08 $570.00 $763.08 $1,218.58 $570.00 $648.58 ($114.50) -8.6% 100 30,000 $2,653.32 $1,140.00 $1,513.32 $2,421.93 $1,140.00 $1,281.93 ($231.39) -8.7% 125 37,500 $3,313.45 $1,425.00 $1,888.45 $3,023.61 $1,425.00 $1,598.61 ($289.84) -8.7% 150 45,000 $3,973.56 $1,710.00 $2,263.56 $3,625.28 $1,710.00 $1,915.28 ($348.28) -8.8% 175 52,500 $4,633.69 $1,995.00 $2,638.69 $4,226.96 $1,995.00 $2,231.96 ($406.73) -8.8% - ------------------------------------------------------------------------------------------------------------------------------ Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates T-2 to G-2 Customer Charge $12.84 Customer Charge $15.23 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250 Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00491 Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 51 of 82 Impact on T-2 to G-2 Rate Customers Hours Use: 350 kWh Split: On Peak: 15% Off Peak: 85% - -------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - -------------------------------------------------------------------------------------------------------------------------------- 50 17,500 $1,471.02 $665.00 $806.02 $1,369.81 $665.00 $704.81 ($101.21) -6.9% 100 35,000 $2,929.17 $1,330.00 $1,599.17 $2,724.38 $1,330.00 $1,394.38 ($204.79) -7.0% 125 43,750 $3,658.26 $1,662.50 $1,995.76 $3,401.67 $1,662.50 $1,739.17 ($256.59) -7.0% 150 52,500 $4,387.35 $1,995.00 $2,392.35 $4,078.96 $1,995.00 $2,083.96 ($308.39) -7.0% 175 61,250 $5,116.43 $2,327.50 $2,788.93 $4,756.24 $2,327.50 $2,428.74 ($360.19) -7.0% - -------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates T-2 to G-2 Customer Charge $12.84 Customer Charge $15.23 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250 Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00491 Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 52 of 82 Impact on T-2 to G-2 Rate Customers Hours Use: 400 kWh Split: On Peak: 15% Off Peak: 85% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 20,000 $1,613.53 $760.00 $853.53 $1,521.03 $760.00 $761.03 ($92.50) -5.7% 100 40,000 $3,214.22 $1,520.00 $1,694.22 $3,026.83 $1,520.00 $1,506.83 ($187.39) -5.8% 125 50,000 $4,014.57 $1,900.00 $2,114.57 $3,779.73 $1,900.00 $1,879.73 ($234.84) -5.8% 150 60,000 $4,814.91 $2,280.00 $2,534.91 $4,532.63 $2,280.00 $2,252.63 ($282.28) -5.9% 175 70,000 $5,615.26 $2,660.00 $2,955.26 $5,285.53 $2,660.00 $2,625.53 ($329.73) -5.9% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates T-2 to G-2 Customer Charge $12.84 Customer Charge $15.23 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250 Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00491 Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-2 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 53 of 82 Impact on T-2 to G-2 Rate Customers Hours Use: 450 kWh Split: On Peak: 15% Off Peak: 85% - --------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - --------------------------------------------------------------------------------------------------------------- 50 22,500 $1,757.41 $855.00 $902.41 $1,677.21 $855.00 $822.21 ($80.20) -4.6% 100 45,000 $3,501.97 $1,710.00 $1,791.97 $3,339.18 $1,710.00 $1,629.18 ($162.79) -4.6% 125 56,250 $4,374.26 $2,137.50 $2,236.76 $4,170.17 $2,137.50 $2,032.67 ($204.09) -4.7% 150 67,500 $5,246.54 $2,565.00 $2,681.54 $5,001.16 $2,565.00 $2,436.16 ($245.38) -4.7% 175 78,750 $6,118.81 $2,992.50 $3,126.31 $5,832.14 $2,992.50 $2,839.64 ($286.67) -4.7% - --------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates: T-2 to G-2 Customer Charge $12.84 Customer Charge $15.23 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92 Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138 Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250 Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00513 Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00291 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 54 of 82 Impact on T-2 to G-3 Rate Customers Hours Use: 250 kWh Split: On Peak: 25% 55% Off Peak: 75% 45% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 250 62,500 $5,916.76 $2,375.00 $3,541.76 $5,043.93 $2,375.00 $2,668.93 ($872.83) -14.8% 300 75,000 $7,097.53 $2,850.00 $4,247.53 $6,039.26 $2,850.00 $3,189.26 ($1,058.27) -14.9% 350 87,500 $8,278.32 $3,325.00 $4,953.32 $7,034.59 $3,325.00 $3,709.59 ($1,243.73) -15.0% 400 100,000 $9,459.09 $3,800.00 $5,659.09 $8,029.92 $3,800.00 $4,229.92 ($1,429.17) -15.1% 450 112,500 $10,639.88 $4,275.00 $6,364.88 $9,025.25 $4,275.00 $4,750.25 ($1,614.63) -15.2% - ------------------------------------------------------------------------------------------------------------------------------ Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates T-2 to G-3 Customer Charge $12.84 Customer Charge $67.27 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 55 of 82 Impact on T-2 to G-3 Rate Customers Hours Use: 300 kWh Split: On Peak: 20% 50% Off Peak: 80% 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 75,000 $6,614.04 $2,850.00 $3,764.04 $5,813.40 $2,850.00 $2,963.40 ($800.64) -12.1% 300 90,000 $7,934.28 $3,420.00 $4,514.28 $6,962.62 $3,420.00 $3,542.62 ($971.66) -12.2% 350 105,000 $9,254.52 $3,990.00 $5,264.52 $8,111.85 $3,990.00 $4,121.85 ($1,142.67) -12.3% 400 120,000 $10,574.76 $4,560.00 $6,014.76 $9,261.07 $4,560.00 $4,701.07 ($1,313.69) -12.4% 450 135,000 $11,895.00 $5,130.00 $6,765.00 $10,410.30 $5,130.00 $5,280.30 ($1,484.70) -12.5% Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates T-2 to G-3 Customer Charge $12.84 Customer Charge $67.27 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Standard Service Charge KWh x $0.03800 KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 56 of 82 Impact on T-2 to G-3 Rate Customers Hours Use: 350 kWh Split: On Peak: 20% 50% Off Peak: 80% 50% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 250 87,500 $7,330.50 $3,325.00 $4,005.50 $6,619.83 $3,325.00 $3,294.83 ($710.67) -9.7% 300 105,000 $8,794.02 $3,990.00 $4,804.02 $7,930.35 $3,990.00 $3,940.35 ($863.67) -9.8% 350 122,500 $10,257.56 $4,655.00 $5,602.56 $9,240.86 $4,655.00 $4,585.86 ($1,016.70) -9.9% 400 140,000 $11,721.08 $5,320.00 $6,401.08 $10,551.37 $5,320.00 $5,231.37 ($1,169.71) -10.0% 450 157,500 $13,184.62 $5,985.00 $7,199.62 $11,861.88 $5,985.00 $5,876.88 ($1,322.74) -10.0% - ------------------------------------------------------------------------------------------------------------------------------ Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates T-2 to G-3 Customer Charge $12.84 Customer Charge $67.27 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 57 of 82 Impact on T-2 to G-3 Rate Customers Hours Use: 400 kWh Split: On Peak: 15% 45% Off Peak: 85% 55% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 250 100,000 $8,016.29 $3,800.00 $4,216.29 $7,367.12 $3,800.00 $3,567.12 ($649.17) -8.1% 300 120,000 $9,616.98 $4,560.00 $5,056.98 $8,827.09 $4,560.00 $4,267.09 ($789.89) -8.2% 350 140,000 $11,217.67 $5,320.00 $5,897.67 $10,287.06 $5,320.00 $4,967.06 ($930.61) -8.3% 400 160,000 $12,818.36 $6,080.00 $6,738.36 $11,747.03 $6,080.00 $5,667.03 ($1,071.33) -8.4% 450 180,000 $14,419.05 $6,840.00 $7,579.05 $13,207.00 $6,840.00 $6,367.00 ($1,212.05) -8.4% - ------------------------------------------------------------------------------------------------------------------------------ Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates T-2 to G-3 Customer Charge $12.84 Customer Charge $67.27 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 58 of 82 Impact on T-2 to G-3 Rate Customers Hours Use: 450 kWh Split: On Peak: 15% 45% Off Peak: 85% 55% - ------------------------------------------------------------------------------------------------------------------------------ Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------------------ 250 112,500 $8,728.92 $4,275.00 $4,453.92 $8,166.16 $4,275.00 $3,891.16 ($562.76) -6.4% 300 135,000 $10,472.12 $5,130.00 $5,342.12 $9,785.94 $5,130.00 $4,655.94 ($686.18) -6.6% 350 157,500 $12,215.35 $5,985.00 $6,230.35 $11,405.72 $5,985.00 $5,420.72 ($809.63) -6.6% 400 180,000 $13,958.55 $6,840.00 $7,118.55 $13,025.50 $6,840.00 $6,185.50 ($933.05) -6.7% 450 202,500 $15,701.77 $7,695.00 $8,006.77 $14,645.28 $7,695.00 $6,950.28 ($1,056.49) -6.7% - ------------------------------------------------------------------------------------------------------------------------------ Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates T-2 to G-3 Customer Charge $12.84 Customer Charge $67.27 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00440 Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 59 of 82 Impact on T-2 to G-3 Rate Customers Hours Use: 500 kWh Split: On Peak: 15% 45% Off Peak: 85% 55% - --------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - --------------------------------------------------------------------------------------------------------------- 250 125,000 $9,449.03 $4,750.00 $4,699.03 $8,990.21 $4,750.00 $4,240.21 ($458.82) -4.9% 300 150,000 $11,336.27 $5,700.00 $5,636.27 $10,774.80 $5,700.00 $5,074.80 ($561.47) -5.0% 350 175,000 $13,223.50 $6,650.00 $6,573.50 $12,559.38 $6,650.00 $5,909.38 ($664.12) -5.0% 400 200,000 $15,110.74 $7,600.00 $7,510.74 $14,343.97 $7,600.00 $6,743.97 ($766.77) -5.1% 450 225,000 $16,997.98 $8,550.00 $8,447.98 $16,128.56 $8,550.00 $7,578.56 ($869.42) -5.1% - --------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates: T-2 to G-3 Customer Charge $12.84 Customer Charge $67.27 Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63 Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183 Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000 Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250 Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00460 Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: H-1 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 60 of 82 Impact on H-1 to G-1 Rate Customers - ---------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % - ---------------------------------------------------------------------------------------------------------------- 50 $10.11 $1.90 $8.21 $13.24 $1.90 $11.34 $3.13 31.0% 100 $14.82 $3.80 $11.02 $18.15 $3.80 $14.35 $3.33 22.5% 250 $28.97 $9.50 $19.47 $32.90 $9.50 $23.40 $3.93 13.6% 500 $52.55 $19.00 $33.55 $57.48 $19.00 $38.48 $4.93 9.4% 1,000 $99.69 $38.00 $61.69 $106.63 $38.00 $68.63 $6.94 7.0% 2,500 $241.15 $95.00 $146.15 $254.10 $95.00 $159.10 $12.95 5.4% 5,000 $476.89 $190.00 $286.89 $499.87 $190.00 $309.87 $22.98 4.8% 7,500 $712.65 $285.00 $427.65 $745.65 $285.00 $460.65 $33.00 4.6% - ---------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-1 Year 2001 Consolidated Rates H-1 to G-1 Customer Charge $5.39 Customer Charge $8.32 Distribution Charge KWh x $0.02669 Distribution Charge KWh x $0.03843 Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00568 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 61 of 82 Impact on H-1 to G-2 Rate Customers Hours Use: 200 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 10,000 $947.79 $380.00 $567.79 $916.13 $380.00 $536.13 ($31.66) -3.3% 100 20,000 $1,890.19 $760.00 $1,130.19 $1,817.03 $760.00 $1,057.03 ($73.16) -3.9% 125 25,000 $2,361.39 $950.00 $1,411.39 $2,267.48 $950.00 $1,317.48 ($93.91) -4.0% 150 30,000 $2,832.59 $1,140.00 $1,692.59 $2,717.93 $1,140.00 $1,577.93 ($114.66) -4.0% 175 35,000 $3,303.79 $1,330.00 $1,973.79 $3,168.38 $1,330.00 $1,838.38 ($135.41) -4.1% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2 Customer Charge $5.39 Customer Charge $15.23 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01250 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 62 of 82 Impact on H-1 to G-2 Rate Customers Hours Use: 250 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 12,500 $1,183.40 $475.00 $708.40 $1,067.36 $475.00 $592.36 ($116.04) -9.8% 100 25,000 $2,361.39 $950.00 $1,411.39 $2,119.48 $950.00 $1,169.48 ($241.91) -10.2% 125 31,250 $2,950.39 $1,187.50 $1,762.89 $2,645.54 $1,187.50 $1,458.04 ($304.85) -10.3% 150 37,500 $3,539.40 $1,425.00 $2,114.40 $3,171.61 $1,425.00 $1,746.61 ($367.79) -10.4% 175 43,750 $4,128.40 $1,662.50 $2,465.90 $3,697.67 $1,662.50 $2,035.17 ($430.73) -10.4% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2 Customer Charge $5.39 Customer Charge $15.23 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01250 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 63 of 82 Impact on H-1 to G-2 Rate Customers Hours Use: 300 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 15,000 $1,418.99 $570.00 $848.99 $1,218.58 $570.00 $648.58 ($200.41) -14.1% 100 30,000 $2,832.59 $1,140.00 $1,692.59 $2,421.93 $1,140.00 $1,281.93 ($410.66) -14.5% 125 37,500 $3,539.40 $1,425.00 $2,114.40 $3,023.61 $1,425.00 $1,598.61 ($515.79) -14.6% 150 45,000 $4,246.19 $1,710.00 $2,536.19 $3,625.28 $1,710.00 $1,915.28 ($620.91) -14.6% 175 52,500 $4,953.00 $1,995.00 $2,958.00 $4,226.96 $1,995.00 $2,231.96 ($726.04) -14.7% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2 Customer Charge $5.39 Customer Charge $15.23 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01250 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 64 of 82 Impact on H-1 to G-2 Rate Customers Hours Use: 350 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 17,500 $1,654.60 $665.00 $989.60 $1,369.81 $665.00 $704.81 ($284.79) -17.2% 100 35,000 $3,303.79 $1,330.00 $1,973.79 $2,724.38 $1,330.00 $1,394.38 ($579.41) -17.5% 125 43,750 $4,128.40 $1,662.50 $2,465.90 $3,401.67 $1,662.50 $1,739.17 ($726.73) -17.6% 150 52,500 $4,953.00 $1,995.00 $2,958.00 $4,078.96 $1,995.00 $2,083.96 ($874.04) -17.6% 175 61,250 $5,777.59 $2,327.50 $3,450.09 $4,756.24 $2,327.50 $2,428.74 ($1,021.35) -17.7% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2 Customer Charge $5.39 Customer Charge $15.23 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01250 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 65 of 82 Impact on H-1 to G-2 Rate Customers Hours Use: 400 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 20,000 $1,890.19 $760.00 $1,130.19 $1,521.03 $760.00 $761.03 ($369.16) -19.5% 100 40,000 $3,774.99 $1,520.00 $2,254.99 $3,026.83 $1,520.00 $1,506.83 ($748.16) -19.8% 125 50,000 $4,717.39 $1,900.00 $2,817.39 $3,779.73 $1,900.00 $1,879.73 ($937.66) -19.9% 150 60,000 $5,659.79 $2,280.00 $3,379.79 $4,532.63 $2,280.00 $2,252.63 ($1,127.16) -19.9% 175 70,000 $6,602.19 $2,660.00 $3,942.19 $5,285.53 $2,660.00 $2,625.53 ($1,316.66) -19.9% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2 Customer Charge $5.39 Customer Charge $15.23 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01250 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: H-1 TO G-2 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 66 of 82 Impact on H-1 to G-2 Rate Customers Hours Use: 450 - ------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------- 50 22,500 $2,127.15 $855.00 $1,272.15 $1,677.21 $855.00 $822.21 ($449.94) -21.2% 100 45,000 $4,248.89 $1,710.00 $2,538.89 $3,339.18 $1,710.00 $1,629.18 ($909.71) -21.4% 125 56,250 $5,309.77 $2,137.50 $3,172.27 $4,170.17 $2,137.50 $2,032.67 ($1,139.60) -21.5% 150 67,500 $6,370.65 $2,565.00 $3,805.65 $5,001.16 $2,565.00 $2,436.16 ($1,369.49) -21.5% 175 78,750 $7,431.52 $2,992.50 $4,439.02 $5,832.14 $2,992.50 $2,839.64 ($1,599.38) -21.5% - ------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2 Customer Charge $5.39 Customer Charge $15.23 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00291 Transition Charge KWh x $0.01250 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00513 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 67 of 82 Impact on H-1 to G-3 Rate Customers Hours Use: 250 kWh Split: On Peak: 55% Off Peak: 45% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 62,500 $5,895.40 $2,375.00 $3,520.40 $5,043.93 $2,375.00 $2,668.93 ($851.47) -14.4% 300 75,000 $7,073.39 $2,850.00 $4,223.39 $6,039.26 $2,850.00 $3,189.26 ($1,034.13) -14.6% 350 87,500 $8,251.40 $3,325.00 $4,926.40 $7,034.59 $3,325.00 $3,709.59 ($1,216.81) -14.7% 400 100,000 $9,429.39 $3,800.00 $5,629.39 $8,029.92 $3,800.00 $4,229.92 ($1,399.47) -14.8% 450 112,500 $10,607.40 $4,275.00 $6,332.40 $9,025.25 $4,275.00 $4,750.25 ($1,582.15) -14.9% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3 Customer Charge $5.39 Customer Charge $67.27 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63 Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183 Transmission Charge KWh x $0.00285 Distribution Charge: Off Peak KWh x $0.00000 Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00440 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 68 of 82 Impact on H-1 to G-3 Rate Customers Hours Use: 300 kWh Split: On Peak: 50% Off Peak: 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 75,000 $7,073.39 $2,850.00 $4,223.39 $5,813.40 $2,850.00 $2,963.40 ($1,259.99) -17.8% 300 90,000 $8,486.99 $3,420.00 $5,066.99 $6,962.62 $3,420.00 $3,542.62 ($1,524.37) -18.0% 350 105,000 $9,900.59 $3,990.00 $5,910.59 $8,111.85 $3,990.00 $4,121.85 ($1,788.74) -18.1% 400 120,000 $11,314.19 $4,560.00 $6,754.19 $9,261.07 $4,560.00 $4,701.07 ($2,053.12) -18.1% 450 135,000 $12,727.79 $5,130.00 $7,597.79 $10,410.30 $5,130.00 $5,280.30 ($2,317.49) -18.2% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3 Customer Charge $5.39 Customer Charge $67.27 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63 Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183 Transmission Charge KWh x $0.00285 Distribution Charge: Off Peak KWh x $0.00000 Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00440 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 69 of 82 Impact on H-1 to G-3 Rate Customers Hours Use: 350 kWh Split: On Peak: 50% Off Peak: 50% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 87,500 $8,251.40 $3,325.00 $4,926.40 $6,619.83 $3,325.00 $3,294.83 ($1,631.57) -19.8% 300 105,000 $9,900.59 $3,990.00 $5,910.59 $7,930.35 $3,990.00 $3,940.35 ($1,970.24) -19.9% 350 122,500 $11,549.80 $4,655.00 $6,894.80 $9,240.86 $4,655.00 $4,585.86 ($2,308.94) -20.0% 400 140,000 $13,198.99 $5,320.00 $7,878.99 $10,551.37 $5,320.00 $5,231.37 ($2,647.62) -20.1% 450 157,500 $14,848.20 $5,985.00 $8,863.20 $11,861.88 $5,985.00 $5,876.88 ($2,986.32) -20.1% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3 Customer Charge $5.39 Customer Charge $67.27 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63 Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183 Transmission Charge KWh x $0.00285 Distribution Charge: Off Peak KWh x $0.00000 Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00440 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 70 of 82 Impact on H-1 to G-3 Rate Customers Hours Use: 400 kWh Split: On Peak: 45% Off Peak: 55% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 100,000 $9,429.39 $3,800.00 $5,629.39 $7,367.12 $3,800.00 $3,567.12 ($2,062.27) -21.9% 300 120,000 $11,314.19 $4,560.00 $6,754.19 $8,827.09 $4,560.00 $4,267.09 ($2,487.10) -22.0% 350 140,000 $13,198.99 $5,320.00 $7,878.99 $10,287.06 $5,320.00 $4,967.06 ($2,911.93) -22.1% 400 160,000 $15,083.79 $6,080.00 $9,003.79 $11,747.03 $6,080.00 $5,667.03 ($3,336.76) -22.1% 450 180,000 $16,968.59 $6,840.00 $10,128.59 $13,207.00 $6,840.00 $6,367.00 ($3,761.59) -22.2% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3 Customer Charge $5.39 Customer Charge $67.27 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63 Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183 Transmission Charge KWh x $0.00285 Distribution Charge: Off Peak KWh x $0.00000 Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00440 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 71 of 82 Impact on H-1 to G-3 Rate Customers Hours Use: 450 kWh Split: On Peak: 45% Off Peak: 55% - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 250 112,500 $10,607.40 $4,275.00 $6,332.40 $8,166.16 $4,275.00 $3,891.16 ($2,441.24) -23.0% 300 135,000 $12,727.79 $5,130.00 $7,597.79 $9,785.94 $5,130.00 $4,655.94 ($2,941.85) -23.1% 350 157,500 $14,848.20 $5,985.00 $8,863.20 $11,405.72 $5,985.00 $5,420.72 ($3,442.48) -23.2% 400 180,000 $16,968.59 $6,840.00 $10,128.59 $13,025.50 $6,840.00 $6,185.50 ($3,943.09) -23.2% 450 202,500 $19,089.00 $7,695.00 $11,394.00 $14,645.28 $7,695.00 $6,950.28 ($4,443.72) -23.3% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3 Customer Charge $5.39 Customer Charge $67.27 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63 Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183 Transmission Charge KWh x $0.00285 Distribution Charge: Off Peak KWh x $0.00000 Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00440 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: H-1 TO G-3 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 72 of 82 Impact on H-1 to G-3 Rate Customers Hours Use: 500 kWh Split: On Peak: 45% Off Peak: 55% - ------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------------- 250 125,000 $11,792.89 $4,750.00 $7,042.89 $8,990.21 $4,750.00 $4,240.21 ($2,802.68) -23.8% 300 150,000 $14,150.39 $5,700.00 $8,450.39 $10,774.80 $5,700.00 $5,074.80 ($3,375.59) -23.9% 350 175,000 $16,507.89 $6,650.00 $9,857.89 $12,559.38 $6,650.00 $5,909.38 ($3,948.51) -23.9% 400 200,000 $18,865.39 $7,600.00 $11,265.39 $14,343.97 $7,600.00 $6,743.97 ($4,521.42) -24.0% 450 225,000 $21,222.89 $8,550.00 $12,672.89 $16,128.56 $8,550.00 $7,578.56 ($5,094.33) -24.0% - ------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3 Customer Charge $5.39 Customer Charge $67.27 Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63 Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183 Transmission Charge KWh x $0.00291 Distribution Charge: Off Peak KWh x $0.00000 Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250 Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00460 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: H-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 73 of 82 Impact on H-2 to G-1 Rate Customers - ------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------- 50 $6.15 $1.90 $4.25 $13.24 $1.90 $11.34 $7.09 115.3% 100 $10.94 $3.80 $7.14 $18.15 $3.80 $14.35 $7.21 65.9% 250 $25.33 $9.50 $15.83 $32.90 $9.50 $23.40 $7.57 29.9% 500 $49.30 $19.00 $30.30 $57.48 $19.00 $38.48 $8.18 16.6% 1,000 $97.24 $38.00 $59.24 $106.63 $38.00 $68.63 $9.39 9.7% 2,500 $241.08 $95.00 $146.08 $254.10 $95.00 $159.10 $13.02 5.4% 5,000 $480.80 $190.00 $290.80 $499.87 $190.00 $309.87 $19.07 4.0% 7,500 $720.53 $285.00 $435.53 $745.65 $285.00 $460.65 $25.12 3.5% - ------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-2 to G-1 Year 2001 Consolidated Rates H-2 to G-1 Customer Charge $1.35 Customer Charge $8.32 Distribution Charge KWh x $0.02828 Distribution Charge KWh x $0.03843 Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00568 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 74 of 82 Impact on H-2 to G-2 Rate Customers Hours Use: 50 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 22,500 $2,157.53 $855.00 $1,302.53 $1,671.58 $855.00 $816.58 ($485.95) -22.5% 100 45,000 $4,313.70 $1,710.00 $2,603.70 $3,327.93 $1,710.00 $1,617.93 ($985.77) -22.9% 125 56,250 $5,391.79 $2,137.50 $3,254.29 $4,156.11 $2,137.50 $2,018.61 ($1,235.68) -22.9% 150 67,500 $6,469.88 $2,565.00 $3,904.88 $4,984.28 $2,565.00 $2,419.28 ($1,485.60) -23.0% 175 78,750 $7,547.97 $2,992.50 $4,555.47 $5,812.46 $2,992.50 $2,819.96 ($1,735.51) -23.0% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2 Customer Charge $1.35 Customer Charge $15.23 Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 75 of 82 Impact on H-2 to G-2 Rate Customers Hours Use: 100 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 22,500 $2,157.53 $855.00 $1,302.53 $1,671.58 $855.00 $816.58 ($485.95) -22.5% 100 45,000 $4,313.70 $1,710.00 $2,603.70 $3,327.93 $1,710.00 $1,617.93 ($985.77) -22.9% 125 56,250 $5,391.79 $2,137.50 $3,254.29 $4,156.11 $2,137.50 $2,018.61 ($1,235.68) -22.9% 150 67,500 $6,469.88 $2,565.00 $3,904.88 $4,984.28 $2,565.00 $2,419.28 ($1,485.60) -23.0% 175 78,750 $7,547.97 $2,992.50 $4,555.47 $5,812.46 $2,992.50 $2,819.96 ($1,735.51) -23.0% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2 Customer Charge $1.35 Customer Charge $15.23 Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KW x $0.01393 Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01393 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00198 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 76 of 82 Impact on H-2 to G-2 Rate Customers Hours Use: 200 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 22,500 $2,157.53 $855.00 $1,302.53 $1,671.58 $855.00 $816.58 ($485.95) -22.5% 100 45,000 $4,313.70 $1,710.00 $2,603.70 $3,327.93 $1,710.00 $1,617.93 ($985.77) -22.9% 125 56,250 $5,391.79 $2,137.50 $3,254.29 $4,156.11 $2,137.50 $2,018.61 ($1,235.68) -22.9% 150 67,500 $6,469.88 $2,565.00 $3,904.88 $4,984.28 $2,565.00 $2,419.28 ($1,485.60) -23.0% 175 78,750 $7,547.97 $2,992.50 $4,555.47 $5,812.46 $2,992.50 $2,819.96 ($1,735.51) -23.0% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2 Customer Charge $1.35 Customer Charge $15.23 Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 77 of 82 Impact on H-2 to G-2 Rate Customers Hours Use: 250 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 22,500 $2,157.53 $855.00 $1,302.53 $1,671.58 $855.00 $816.58 ($485.95) -22.5% 100 45,000 $4,313.70 $1,710.00 $2,603.70 $3,327.93 $1,710.00 $1,617.93 ($985.77) -22.9% 125 56,250 $5,391.79 $2,137.50 $3,254.29 $4,156.11 $2,137.50 $2,018.61 ($1,235.68) -22.9% 150 67,500 $6,469.88 $2,565.00 $3,904.88 $4,984.28 $2,565.00 $2,419.28 ($1,485.60) -23.0% 175 78,750 $7,547.97 $2,992.50 $4,555.47 $5,812.46 $2,992.50 $2,819.96 ($1,735.51) -23.0% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2 Customer Charge $1.35 Customer Charge $15.23 Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 78 of 82 Impact on H-2 to G-2 Rate Customers Hours Use: 300 - ----------------------------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------------------------- 50 22,500 $2,157.53 $855.00 $1,302.53 $1,671.58 $855.00 $816.58 ($485.95) -22.5% 100 45,000 $4,313.70 $1,710.00 $2,603.70 $3,327.93 $1,710.00 $1,617.93 ($985.77) -22.9% 125 56,250 $5,391.79 $2,137.50 $3,254.29 $4,156.11 $2,137.50 $2,018.61 ($1,235.68) -22.9% 150 67,500 $6,469.88 $2,565.00 $3,904.88 $4,984.28 $2,565.00 $2,419.28 ($1,485.60) -23.0% 175 78,750 $7,547.97 $2,992.50 $4,555.47 $5,812.46 $2,992.50 $2,819.96 ($1,735.51) -23.0% - ----------------------------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2 Customer Charge $1.35 Customer Charge $15.23 Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KW x $0.01393 Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: H-2 TO G-2 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 79 of 82 Impact on H-2 to G-2 Rate Customers Hours Use: 350 - ------------------------------------------------------------------------------------------------------------- Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Power Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------- 50 22,500 $2,158.88 $855.00 $1,303.88 $1,672.93 $855.00 $817.93 ($485.95) -22.5% 100 45,000 $4,316.40 $1,710.00 $2,606.40 $3,330.63 $1,710.00 $1,620.63 ($985.77) -22.8% 125 56,250 $5,395.17 $2,137.50 $3,257.67 $4,159.48 $2,137.50 $2,021.98 ($1,235.69) -22.9% 150 67,500 $6,473.93 $2,565.00 $3,908.93 $4,988.33 $2,565.00 $2,423.33 ($1,485.60) -22.9% 175 78,750 $7,552.69 $2,992.50 $4,560.19 $5,817.18 $2,992.50 $2,824.68 ($1,735.51) -23.0% - ------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2 Customer Charge $1.35 Customer Charge $15.23 Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92 Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00291 Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00291 Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: W-1 TO G-1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 80 of 82 Impact on W-1 to G-1 - ------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % - ------------------------------------------------------------------------------------------------------------- 250 $23.67 $9.50 $14.17 $32.90 $9.50 $23.40 $9.23 39.0% 500 $46.43 $19.00 $27.43 $57.48 $19.00 $38.48 $11.05 23.8% 750 $69.18 $28.50 $40.68 $82.05 $28.50 $53.55 $12.87 18.6% 1,000 $91.94 $38.00 $53.94 $106.63 $38.00 $68.63 $14.69 16.0% 1,250 $114.71 $47.50 $67.21 $131.21 $47.50 $83.71 $16.50 14.4% 1,500 $137.47 $57.00 $80.47 $155.79 $57.00 $98.79 $18.32 13.3% 2,000 $182.98 $76.00 $106.98 $204.94 $76.00 $128.94 $21.96 12.0% 2,500 $228.51 $95.00 $133.51 $254.10 $95.00 $159.10 $25.59 11.2% - ------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates W-1 to G-1 Year 2001 Consolidated Rates W-1 to G-1 Customer Charge $0.90 Customer Charge $8.32 Distribution Charge KWh x $0.02343 Distribution Charge KWh x $0.03843 Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00568 Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: W-1 TO R-1 1 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 81 of 82 Impact on W-1 to R-1 Rate Customers with Interruptible Credit #1 - ----------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------- 10 $1.81 $0.38 $1.43 $1.16 $0.38 $0.78 ($0.65) -35.9% 50 $5.46 $1.90 $3.56 $4.56 $1.90 $2.66 ($0.90) -16.5% 100 $10.00 $3.80 $6.20 $8.80 $3.80 $5.00 ($1.20) -12.0% 250 $23.67 $9.50 $14.17 $21.54 $9.50 $12.04 ($2.13) -9.0% 500 $46.43 $19.00 $27.43 $42.78 $19.00 $23.78 ($3.65) -7.9% 750 $69.18 $28.50 $40.68 $64.01 $28.50 $35.51 ($5.17) -7.5% 1,000 $91.94 $38.00 $53.94 $85.24 $38.00 $47.24 ($6.70) -7.3% 1,500 $137.47 $57.00 $80.47 $127.71 $57.00 $70.71 ($9.76) -7.1% - ----------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates W-1 to R-1 Year 2001 Consolidated Rates W-1 to R-1 Customer Charge $0.90 Customer Charge $5.81 Distribution Charge KWh x $0.02343 Distribution Charge KWh x $0.02502 Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00571 Energy Conservation Charge KWh x $0.00270 Interruptible Credit #1 ($5.50) Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System Range: W-1 TO R-1 2 Massachusetts Electric Company Eastern Utilities Associates Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__ Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised Page 82 of 82 Impact on W-1 to R-1 Rate Customers with Interruptible Credit #2 - ----------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % - ----------------------------------------------------------------------------------------------------------------- 10 $1.81 $0.38 $1.43 ($0.84) $0.38 ($1.22) ($2.65) -146.4% 50 $5.46 $1.90 $3.56 $2.56 $1.90 $0.66 ($2.90) -53.1% 100 $10.00 $3.80 $6.20 $6.80 $3.80 $3.00 ($3.20) -32.0% 250 $23.67 $9.50 $14.17 $19.54 $9.50 $10.04 ($4.13) -17.4% 500 $46.43 $19.00 $27.43 $40.78 $19.00 $21.78 ($5.65) -12.2% 750 $69.18 $28.50 $40.68 $62.01 $28.50 $33.51 ($7.17) -10.4% 1,000 $91.94 $38.00 $53.94 $83.24 $38.00 $45.24 ($8.70) -9.5% 1,500 $137.47 $57.00 $80.47 $125.71 $57.00 $68.71 ($11.76) -8.6% - ----------------------------------------------------------------------------------------------------------------- Estimated Year 2001 EEC Rates W-1 to R-1 Year 2001 Consolidated Rates W-1 to R-1 Customer Charge $0.90 Customer Charge $5.81 Distribution Charge KWh x $0.02343 Distribution Charge KWh x $0.02502 Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00571 Energy Conservation Charge KWh x $0.00270 Interruptible Credit #2 ($7.50) Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-11 Massachusetts Electric Company Typical Bills January 1, 2001 Assuming No Merger vs. January 1, 2001 Combined Rates
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 1 of 22 Impact on R-1 Rate Customers Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % 125 $16.26 $4.75 $11.51 $16.40 $4.75 $11.65 $0.14 0.9% 250 $26.71 $9.50 $17.21 $26.98 $9.50 $17.48 $0.27 1.0% 500 $47.60 $19.00 $28.60 $48.16 $19.00 $29.16 $0.56 1.2% 750 $68.50 $28.50 $40.00 $69.33 $28.50 $40.83 $0.83 1.2% 1,000 $89.39 $38.00 $51.39 $90.50 $38.00 $52.50 $1.11 1.2% 1,250 $110.29 $47.50 $62.79 $111.67 $47.50 $64.17 $1.38 1.3% 1,500 $131.18 $57.00 $74.18 $132.85 $57.00 $75.85 $1.67 1.3% 2,000 $172.97 $76.00 $96.97 $175.19 $76.00 $99.19 $2.22 1.3% Projected January 1, 2001 Rates: R-1 Proposed Combined 2001 Rates R-1 Customer Charge $5.81 Customer Charge $5.81 Distribution Charge KWh x $0.02502 Distribution Charge KWh x $0.02502 Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547 DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 2 of 22 Impact on R-1 Rate Customers (with Interruptible Credit #1) Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % 250 $21.21 $9.50 $11.71 $21.48 $9.50 $11.98 $0.27 1.3% 500 $42.10 $19.00 $23.10 $42.66 $19.00 $23.66 $0.56 1.3% 750 $63.00 $28.50 $34.50 $63.83 $28.50 $35.33 $0.83 1.3% 1,000 $83.89 $38.00 $45.89 $85.00 $38.00 $47.00 $1.11 1.3% 1,250 $104.79 $47.50 $57.29 $106.17 $47.50 $58.67 $1.38 1.3% 1,500 $125.68 $57.00 $68.68 $127.35 $57.00 $70.35 $1.67 1.3% 2,000 $167.47 $76.00 $91.47 $169.69 $76.00 $93.69 $2.22 1.3% 2,500 $209.26 $95.00 $114.26 $212.04 $95.00 $117.04 $2.78 1.3% Projected January 1, 2001 Rates: R-1 Proposed Combined 2001 Rates R-1 Customer Charge $5.81 Customer Charge $5.81 Distribution Charge KWh x $0.02502 Distribution Charge KWh x $0.02502 Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547 Interruptible Credit #1 KWh x ($5.50) Interruptible Credit #1 KWh x ($5.50) DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 3 of 22 Impact on R-1 Rate Customers (with Interruptible Credit #2) Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % 250 $19.21 $9.50 $9.71 $19.48 $9.50 $9.98 $0.27 1.4% 500 $40.10 $19.00 $21.10 $40.66 $19.00 $21.66 $0.56 1.4% 750 $61.00 $28.50 $32.50 $61.83 $28.50 $33.33 $0.83 1.4% 1,000 $81.89 $38.00 $43.89 $83.00 $38.00 $45.00 $1.11 1.4% 1,250 $102.79 $47.50 $55.29 $104.17 $47.50 $56.67 $1.38 1.3% 1,500 $123.68 $57.00 $66.68 $125.35 $57.00 $68.35 $1.67 1.4% 2,000 $165.47 $76.00 $89.47 $167.69 $76.00 $91.69 $2.22 1.3% 2,500 $207.26 $95.00 $112.26 $210.04 $95.00 $115.04 $2.78 1.3% Projected January 1, 2001 Rates: R-1 Proposed Combined 2001 Rates R-1 Customer Charge $5.81 Customer Charge $5.81 Distribution Charge KWh x $0.02502 Distribution Charge KWh x $0.02502 Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547 Interruptible Credit #2 KWh x ($7.50) Interruptible Credit #2 KWh x ($7.50) DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 4 of 22 Impact on R-2 Rate Customers Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % 50 $6.93 $1.90 $5.03 $6.99 $1.90 $5.09 $0.06 0.9% 100 $10.09 $3.80 $6.29 $10.20 $3.80 $6.40 $0.11 1.1% 150 $13.25 $5.70 $7.55 $13.42 $5.70 $7.72 $0.17 1.3% 250 $19.57 $9.50 $10.07 $19.85 $9.50 $10.35 $0.28 1.4% 300 $22.73 $11.40 $11.33 $23.06 $11.40 $11.66 $0.33 1.5% 500 $35.37 $19.00 $16.37 $35.92 $19.00 $16.92 $0.55 1.6% 600 $41.68 $22.80 $18.88 $42.35 $22.80 $19.55 $0.67 1.6% 750 $51.16 $28.50 $22.66 $52.00 $28.50 $23.50 $0.84 1.6% Projected January 1, 2001 Rates: R-2 Proposed Combined 2001 Rates R-2 Customer Charge $3.77 Customer Charge $3.77 Distribution Charge KWh x $0.00463 Distribution Charge KWh x $0.00463 Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547 DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 5 of 22 Impact on R-2 Rate Customers With Interruptible Credit #1 Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % 300 $17.23 $11.40 $5.83 $17.56 $11.40 $6.16 $0.33 1.9% 500 $29.87 $19.00 $10.87 $30.42 $19.00 $11.42 $0.55 1.8% 600 $36.18 $22.80 $13.38 $36.85 $22.80 $14.05 $0.67 1.9% 750 $45.66 $28.50 $17.16 $46.50 $28.50 $18.00 $0.84 1.8% 900 $55.14 $34.20 $20.94 $56.14 $34.20 $21.94 $1.00 1.8% 1,000 $61.46 $38.00 $23.46 $62.57 $38.00 $24.57 $1.11 1.8% 1,500 $93.06 $57.00 $36.06 $94.72 $57.00 $37.72 $1.66 1.8% 1,750 $108.85 $66.50 $42.35 $110.80 $66.50 $44.30 $1.95 1.8% Projected January 1, 2001 Rates: R-2 Proposed Combined 2001 Rates R-2 Customer Charge $3.77 Customer Charge $3.77 Distribution Charge KWh x $0.00463 Distribution Charge KWh x $0.00463 Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547 Interruptible Credit #1 KWh x ($5.50) Interruptible Credit #1 KWh x ($5.50) DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 6 of 22 Impact on R-2 Rate Customers With Interruptible Credit #2 Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % 300 $15.23 $11.40 $3.83 $15.56 $11.40 $4.16 $0.33 2.2% 500 $27.87 $19.00 $8.87 $28.42 $19.00 $9.42 $0.55 2.0% 600 $34.18 $22.80 $11.38 $34.85 $22.80 $12.05 $0.67 2.0% 750 $43.66 $28.50 $15.16 $44.50 $28.50 $16.00 $0.84 1.9% 900 $53.14 $34.20 $18.94 $54.14 $34.20 $19.94 $1.00 1.9% 1,000 $59.46 $38.00 $21.46 $60.57 $38.00 $22.57 $1.11 1.9% 1,500 $91.06 $57.00 $34.06 $92.72 $57.00 $35.72 $1.66 1.8% 1,750 $106.85 $66.50 $40.35 $108.80 $66.50 $42.30 $1.95 1.8% Projected January 1, 2001 Rates: R-2 Proposed Combined 2001 Rates R-2 Customer Charge $3.77 Customer Charge KWh x $3.77 Distribution Charge KWh x $0.00463 Distribution Charge KWh x $0.00463 Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547 Interruptible Credit #2 KWh x ($7.50) Interruptible Credit #2 KWh x ($7.50) DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 7 of 22 Impact on R-4 Rate Customers KWh Split: - On Peak 25% - Off Peak 75% Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % 1,000 $93.86 $38.00 $55.86 $94.31 $38.00 $56.31 $0.45 0.5% 1,500 $131.29 $57.00 $74.29 $131.97 $57.00 $74.97 $0.68 0.5% 2,000 $168.72 $76.00 $92.72 $169.63 $76.00 $93.63 $0.91 0.5% 3,000 $243.57 $114.00 $129.57 $244.94 $114.00 $130.94 $1.37 0.6% 4,000 $318.43 $152.00 $166.43 $320.25 $152.00 $168.25 $1.82 0.6% 5,000 $393.29 $190.00 $203.29 $395.56 $190.00 $205.56 $2.27 0.6% 8,000 $617.86 $304.00 $313.86 $621.50 $304.00 $317.50 $3.64 0.6% 10,000 $767.58 $380.00 $387.58 $772.13 $380.00 $392.13 $4.55 0.6% Projected January 1, 2001 Rates: R-4 Proposed Combined 2001 Rates R-4 Customer Charge $19.00 Customer Charge $19.00 Distribution Charge: On Peak KWh x $0.05527 Distribution Charge: On Peak KWh x $0.05527 Distribution Charge: Off Peak KWh x $0.00730 Distribution Charge: Off Peak KWh x $0.00730 Transition Charge: On Peak KWh x $0.02659 Transition Charge: On Peak KWh x $0.03017 Transition Charge: Off Peak KWh x $0.00217 Transition Charge: Off Peak KWh x $0.00253 Transmission Charge: On Peak KWh x $0.00559 Transmission Charge: On Peak KWh x $0.00488 Transmission Charge: Off Peak KWh x $0.00559 Transmission Charge: Off Peak KWh x $0.00488 DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 8 of 22 Impact on R-4 Rate Customers KWh Split: - On Peak 30% - Off Peak 70% Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % 1,000 $97.48 $38.00 $59.48 $98.09 $38.00 $60.09 $0.61 0.6% 1,500 $136.72 $57.00 $79.72 $137.64 $57.00 $80.64 $0.92 0.7% 2,000 $175.95 $76.00 $99.95 $177.19 $76.00 $101.19 $1.24 0.7% 3,000 $254.43 $114.00 $140.43 $256.28 $114.00 $142.28 $1.85 0.7% 4,000 $332.91 $152.00 $180.91 $335.37 $152.00 $183.37 $2.46 0.7% 5,000 $411.39 $190.00 $221.39 $414.47 $190.00 $224.47 $3.08 0.7% 8,000 $646.82 $304.00 $342.82 $651.74 $304.00 $347.74 $4.92 0.8% 10,000 $803.77 $380.00 $423.77 $809.93 $380.00 $429.93 $6.16 0.8% Projected January 1, 2001 Rates: R-4 Proposed Combined 2001 Rates R-4 Customer Charge $19.00 Customer Charge $19.00 Distribution Charge: On Peak KWh x $0.05527 Distribution Charge: On Peak KWh x $0.05527 Distribution Charge: Off Peak KWh x $0.00730 Distribution Charge: Off Peak KWh x $0.00730 Transition Charge: On Peak KWh x $0.02659 Transition Charge: On Peak KWh x $0.03017 Transition Charge: Off Peak KWh x $0.00217 Transition Charge: Off Peak KWh x $0.00253 Transmission Charge: On Peak KWh x $0.00559 Transmission Charge: On Peak KWh x $0.00488 Transmission Charge: Off Peak KWh x $0.00559 Transmission Charge: Off Peak KWh x $0.00488 DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 9 of 22 Impact on R-4 Rate Customers KWh Split: - On Peak 40% - Off Peak 60% Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % 1,000 $104.72 $38.00 $66.72 $105.65 $38.00 $67.65 $0.93 0.9% 1,500 $147.57 $57.00 $90.57 $148.98 $57.00 $91.98 $1.41 1.0% 2,000 $190.43 $76.00 $114.43 $192.31 $76.00 $116.31 $1.88 1.0% 3,000 $276.15 $114.00 $162.15 $278.96 $114.00 $164.96 $2.81 1.0% 4,000 $361.86 $152.00 $209.86 $365.62 $152.00 $213.62 $3.76 1.0% 5,000 $447.58 $190.00 $257.58 $452.27 $190.00 $262.27 $4.69 1.0% 8,000 $704.73 $304.00 $400.73 $712.23 $304.00 $408.23 $7.50 1.1% 10,000 $876.16 $380.00 $496.16 $885.54 $380.00 $505.54 $9.38 1.1% Projected January 1, 2001 Rates: R-4 Proposed Combined 2001 Rates R-4 Customer Charge $19.00 Customer Charge $19.00 Distribution Charge: On Peak KWh x $0.05527 Distribution Charge: On Peak KWh x $0.05527 Distribution Charge: Off Peak KWh x $0.00730 Distribution Charge: Off Peak KWh x $0.00730 Transition Charge: On Peak KWh x $0.02659 Transition Charge: On Peak KWh x $0.03017 Transition Charge: Off Peak KWh x $0.00217 Transition Charge: Off Peak KWh x $0.00253 Transmission Charge: On Peak KWh x $0.00559 Transmission Charge: On Peak KWh x $0.00488 Transmission Charge: Off Peak KWh x $0.00559 Transmission Charge: Off Peak KWh x $0.00488 DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 10 of 22 Impact on G-1 Rate Customers Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KWh Total Service Delivery Total Service Delivery Amount % 50 $13.16 $1.90 $11.26 $13.22 $1.90 $11.32 $0.06 0.5% 100 $17.99 $3.80 $14.19 $18.13 $3.80 $14.33 $0.14 0.8% 250 $32.50 $9.50 $23.00 $32.84 $9.50 $23.34 $0.34 1.0% 500 $56.68 $19.00 $37.68 $57.36 $19.00 $38.36 $0.68 1.2% 1,000 $105.04 $38.00 $67.04 $106.39 $38.00 $68.39 $1.35 1.3% 2,500 $250.12 $95.00 $155.12 $253.50 $95.00 $158.50 $3.38 1.4% 5,000 $491.92 $190.00 $301.92 $498.67 $190.00 $308.67 $6.75 1.4% 7,500 $733.72 $285.00 $448.72 $743.85 $285.00 $458.85 $10.13 1.4% Projected January 1, 2001 Rates: G-1 Proposed Combined 2001 Rates G-1 Customer Charge $8.32 Customer Charge $8.32 Distribution Charge KWh x $0.03843 Distribution Charge KWh x $0.03843 Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250 Transmission Charge KWh x $0.00589 Transmission Charge KWh x $0.00544 DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 11 of 22 Impact on G-2 Rate Customers Hours Use: 200 Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 15 3,000 $282.17 $114.00 $168.17 $285.50 $114.00 $171.50 $3.33 1.2% 20 4,000 $371.15 $152.00 $219.15 $375.59 $152.00 $223.59 $4.44 1.2% 40 8,000 $727.07 $304.00 $423.07 $735.95 $304.00 $431.95 $8.88 1.2% 75 15,000 $1,349.93 $570.00 $779.93 $1,366.58 $570.00 $796.58 $16.65 1.2% 150 30,000 $2,684.63 $1,140.00 $1,544.63 $2,717.93 $1,140.00 $1,577.93 $33.30 1.2% Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2 Customer Charge $15.23 Customer Charge $15.23 Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92 Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00 Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 12 of 22 Impact on G-2 Rate Customers Hours Use: 250 Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 15 3,750 $326.71 $142.50 $184.21 $330.87 $142.50 $188.37 $4.16 1.3% 20 5,000 $430.53 $190.00 $240.53 $436.08 $190.00 $246.08 $5.55 1.3% 40 10,000 $845.83 $380.00 $465.83 $856.93 $380.00 $476.93 $11.10 1.3% 75 18,750 $1,572.61 $712.50 $860.11 $1,593.42 $712.50 $880.92 $20.81 1.3% 150 37,500 $3,129.98 $1,425.00 $1,704.98 $3,171.61 $1,425.00 $1,746.61 $41.63 1.3% Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2 Customer Charge $15.23 Customer Charge $15.23 Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92 Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00 Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 13 of 22 Impact on G-2 Rate Customers Hours Use: 300 Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 15 4,500 $371.24 $171.00 $200.24 $376.24 $171.00 $205.24 $5.00 1.3% 20 6,000 $489.91 $228.00 $261.91 $496.57 $228.00 $268.57 $6.66 1.4% 40 12,000 $964.59 $456.00 $508.59 $977.91 $456.00 $521.91 $13.32 1.4% 75 22,500 $1,795.28 $855.00 $940.28 $1,820.26 $855.00 $965.26 $24.98 1.4% 150 45,000 $3,575.33 $1,710.00 $1,865.33 $3,625.28 $1,710.00 $1,915.28 $49.95 1.4% Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2 Customer Charge $15.23 Customer Charge $15.23 Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92 Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00 Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 14 of 22 Impact on G-2 Rate Customers Hours Use: 350 Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 15 5,250 $415.78 $199.50 $216.28 $421.60 $199.50 $222.10 $5.82 1.4% 20 7,000 $549.29 $266.00 $283.29 $557.06 $266.00 $291.06 $7.77 1.4% 40 14,000 $1,083.35 $532.00 $551.35 $1,098.89 $532.00 $566.89 $15.54 1.4% 75 26,250 $2,017.96 $997.50 $1,020.46 $2,047.09 $997.50 $1,049.59 $29.13 1.4% 150 52,500 $4,020.68 $1,995.00 $2,025.68 $4,078.96 $1,995.00 $2,083.96 $58.28 1.4% Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2 Customer Charge $15.23 Customer Charge $15.23 Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92 Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00 Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 15 of 22 Impact on G-2 Rate Customers Hours Use: 400 Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 15 6,000 $460.31 $228.00 $232.31 $466.97 $228.00 $238.97 $6.66 1.4% 20 8,000 $608.67 $304.00 $304.67 $617.55 $304.00 $313.55 $8.88 1.5% 40 16,000 $1,202.11 $608.00 $594.11 $1,219.87 $608.00 $611.87 $17.76 1.5% 75 30,000 $2,240.63 $1,140.00 $1,100.63 $2,273.93 $1,140.00 $1,133.93 $33.30 1.5% 150 60,000 $4,466.03 $2,280.00 $2,186.03 $4,532.63 $2,280.00 $2,252.63 $66.60 1.5% Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2 Customer Charge $15.23 Customer Charge $15.23 Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92 Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00 Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 16 of 22 Impact on G-2 Rate Customers Hours Use: 450 Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 15 6,750 $504.85 $256.50 $248.35 $512.34 $256.50 $255.84 $7.49 1.5% 20 9,000 $668.05 $342.00 $326.05 $678.04 $342.00 $336.04 $9.99 1.5% 40 18,000 $1,320.87 $684.00 $636.87 $1,340.85 $684.00 $656.85 $19.98 1.5% 75 33,750 $2,463.31 $1,282.50 $1,180.81 $2,500.77 $1,282.50 $1,218.27 $37.46 1.5% 150 67,500 $4,911.38 $2,565.00 $2,346.38 $4,986.31 $2,565.00 $2,421.31 $74.93 1.5% Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2 Customer Charge $15.23 Customer Charge $15.23 Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92 Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00 Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138 Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 17 of 22 Impact on G-3 Rate Customers Hours Use: 250 KWh Split: - On Peak 55% - Off Peak 45% Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 600 150,000 $11,832.75 $5,700.00 $6,132.75 $12,011.25 $5,700.00 $6,311.25 $178.50 1.5% 800 200,000 $15,754.57 $7,600.00 $8,154.57 $15,992.57 $7,600.00 $8,392.57 $238.00 1.5% 1000 250,000 $19,676.40 $9,500.00 $10,176.40 $19,973.90 $9,500.00 $10,473.90 $297.50 1.5% 1500 375,000 $29,480.96 $14,250.00 $15,230.96 $29,927.21 $14,250.00 $15,677.21 $446.25 1.5% 3000 750,000 $58,894.65 $28,500.00 $30,394.65 $59,787.15 $28,500.00 $31,287.15 $892.50 1.5% Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3 Customer Charge $67.27 Customer Charge $67.27 Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63 Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00 Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183 Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000 Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 18 of 22 Impact on G-3 Rate Customers Hours Use: 300 KWh Split: - On Peak 50% - Off Peak 50% Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 600 180,000 $13,643.77 $6,840.00 $6,803.77 $13,857.97 $6,840.00 $7,017.97 $214.20 1.6% 800 240,000 $18,169.27 $9,120.00 $9,049.27 $18,454.87 $9,120.00 $9,334.87 $285.60 1.6% 1000 300,000 $22,694.77 $11,400.00 $11,294.77 $23,051.77 $11,400.00 $11,651.77 $357.00 1.6% 1500 450,000 $34,008.52 $17,100.00 $16,908.52 $34,544.02 $17,100.00 $17,444.02 $535.50 1.6% 3000 900,000 $67,949.77 $34,200.00 $33,749.77 $69,020.77 $34,200.00 $34,820.77 $1,071.00 1.6% Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3 Customer Charge $67.27 Customer Charge $67.27 Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63 Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00 Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183 Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000 Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 19 of 22 Impact on G-3 Rate Customers Hours Use: 350 KWh Split: - On Peak 50% - Off Peak 50% Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 600 210,000 $15,543.52 $7,980.00 $7,563.52 $15,793.42 $7,980.00 $7,813.42 $249.90 1.6% 800 280,000 $20,702.27 $10,640.00 $10,062.27 $21,035.47 $10,640.00 $10,395.47 $333.20 1.6% 1000 350,000 $25,861.02 $13,300.00 $12,561.02 $26,277.52 $13,300.00 $12,977.52 $416.50 1.6% 1500 525,000 $38,757.90 $19,950.00 $18,807.90 $39,382.65 $19,950.00 $19,432.65 $624.75 1.6% 3000 1,050,000 $77,448.52 $39,900.00 $37,548.52 $78,698.02 $39,900.00 $38,798.02 $1,249.50 1.6% Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3 Customer Charge $67.27 Customer Charge $67.27 Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63 Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00 Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183 Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000 Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 20 of 22 Impact on G-3 Rate Customers Hours Use: 400 KWh Split: - On Peak 45% - Off Peak 55% Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 600 240,000 $17,301.31 $9,120.00 $8,181.31 $17,586.91 $9,120.00 $8,466.91 $285.60 1.7% 800 320,000 $23,045.99 $12,160.00 $10,885.99 $23,426.79 $12,160.00 $11,266.79 $380.80 1.7% 1000 400,000 $28,790.67 $15,200.00 $13,590.67 $29,266.67 $15,200.00 $14,066.67 $476.00 1.7% 1500 600,000 $43,152.37 $22,800.00 $20,352.37 $43,866.37 $22,800.00 $21,066.37 $714.00 1.7% 3000 1,200,000 $86,237.47 $45,600.00 $40,637.47 $87,665.47 $45,600.00 $42,065.47 $1,428.00 1.7% Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3 Customer Charge $67.27 Customer Charge $67.27 Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63 Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00 Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183 Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000 Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 21 of 22 Impact on G-3 Rate Customers Hours Use: 450 KWh Split: - On Peak 45% - Off Peak 55% Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 600 270,000 $19,183.32 $10,260.00 $8,923.32 $19,504.62 $10,260.00 $9,244.62 $321.30 1.7% 800 360,000 $25,555.33 $13,680.00 $11,875.33 $25,983.73 $13,680.00 $12,303.73 $428.40 1.7% 1000 450,000 $31,927.35 $17,100.00 $14,827.35 $32,462.85 $17,100.00 $15,362.85 $535.50 1.7% 1500 675,000 $47,857.38 $25,650.00 $22,207.38 $48,660.63 $25,650.00 $23,010.63 $803.25 1.7% 3000 1,350,000 $95,647.50 $51,300.00 $44,347.50 $97,254.00 $51,300.00 $45,954.00 $1,606.50 1.7% Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3 Customer Charge $67.27 Customer Charge $67.27 Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63 Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00 Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183 Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000 Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System New England Electric System Eastern Utilities Associates Eastern Edison Company M.D.T.E Docket No. 99-______ Calculation of Monthly Typical Bill Exhibit TMB-11 Page 22 of 22 Impact on G-3 Rate Customers Hours Use: 500 KWh Split: - On Peak 45% - Off Peak 55% Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease) Monthly Standard Retail Standard Retail KW KWh Total Service Delivery Total Service Delivery Amount % 600 300,000 $21,065.32 $11,400.00 $9,665.32 $21,422.32 $11,400.00 $10,022.32 $357.00 1.7% 800 400,000 $28,064.67 $15,200.00 $12,864.67 $28,540.67 $15,200.00 $13,340.67 $476.00 1.7% 1000 500,000 $35,064.02 $19,000.00 $16,064.02 $35,659.02 $19,000.00 $16,659.02 $595.00 1.7% 1500 750,000 $52,562.40 $28,500.00 $24,062.40 $53,454.90 $28,500.00 $24,954.90 $892.50 1.7% 3000 1,500,000 $105,057.52 $57,000.00 $48,057.52 $106,842.52 $57,000.00 $49,842.52 $1,785.00 1.7% Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3 Customer Charge $67.27 Customer Charge $67.27 Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63 Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00 Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183 Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000 Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250 DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440 Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270 Renewables Charge KWh x $0.00100 Supplier Services Supplier Services Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit TMB-12 Eastern Edison Company Total Municipal Revenue Analysis S:\RADATA1\EASTED\2001\Munireva.wk4 New England Electric System MUNI SUMMARY Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No 99-___ Exhibit TMB-12, Revised Page 1 of 1 Eastern Edison Company Impact on Municipal Retail Delivery Service Billings For All Municipal Accounts, Including Lighting Retail Delivery Service Revenue on ---------------------------------- Eastern's Mass. Electric's Year 2001 Year 2001 Increase/ Town Rates Rates (Decrease) % ---- ----- ----- ---------- - (1) (2) (3) (4) Abington $195,919 $187,756 ($8,163) -4.2% Avon $126,864 $142,726 $15,862 12.5% Bridgewater $355,989 $321,141 ($34,848) -9.8% Brockton $1,959,706 $1,775,505 ($184,201) -9.4% Cohasset $170,822 $162,741 ($8,081) -4.7% Dighton $159,073 $145,216 ($13,857) -8.7% East Bridgewater $246,924 $223,014 ($23,910) -9.7% Easton $426,248 $370,346 ($55,902) -13.1% Fall River $2,179,500 $1,945,967 ($233,533) -10.7% Halifax $66,499 $61,249 ($5,250) -7.9% Hanover $267,408 $219,716 ($47,692) -17.8% Hanson $146,252 $135,841 ($10,411) -7.1% (a) Hingham $392 $516 $124 31.6% Norwell $193,825 $179,413 ($14,412) -7.4% Pembroke $542,509 $439,262 ($103,247) -19.0% Rockland $334,890 $299,326 ($35,564) -10.6% Scituate $342,826 $338,278 ($4,548) -1.3% Somerset $456,831 $428,068 ($28,763) -6.3% Stoughton $419,560 $392,212 ($27,348) -6.5% Swansea $246,760 $254,262 $7,502 3.0% West Bridgewater $119,102 $114,854 ($4,248) -3.6% (a) Westport $5,370 $6,305 $935 17.4% Whitman $150,698 $151,558 $860 0.6% ---------- ---------- --------- $9,113,967 $8,295,272 ($818,695) -9.0% ========== ========== ========= (1) Billing determinants of municipal accounts priced at Eastern's rates in 2001 as projected (2) Billing determinants of municipal accounts priced at Mass. Electric's proposed rates in 2001 as proposed (3) Column (2) - Column(1) (4) Column (3) / Column (1) (a) Municipality only has lighting service through Eastern. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Workpaper TMB-1 Eastern Edison Company Detail Supporting Revenue Impact
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: R1 TO R1 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 1 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate R-1 to R-1 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO R-1 to R-1 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 1,705,214 $1.34 $2,284,987 $5.81 $9,907,293 2 Interruptible Credit #1 ($5.50) $0 3 Interruptible Credit #2 ($7.50) $0 4 Total kWh 897,383,838 Distribution Charge 897,383,838 $0.03556 $31,910,969 $0.02502 $22,452,544 Transmission Charge 897,383,838 $0.00291 $2,611,387 $0.00571 $5,124,062 Transition Charge 897,383,838 $0.02300 $20,639,828 $0.01250 $11,217,298 Standard Service Charge 897,383,838 $0.03800 $34,100,586 $0.03800 $34,100,586 DSM/Renewables Charge 897,383,838 $0.00370 $3,320,320 $0.00370 $3,320,320 ----------- ----------- 5 Total Revenue $94,868,077 $86,122,102 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 1,705,214 Interruptible Credit #1 0 Interruptible Credit #2 0 KWh 897,383,838 2 Total Design EEC Rates $94,868,077 Revenue: MECO 3/1/99 Rates $86,122,102 3 Increase (Decrease) in Total Revenue ($8,745,975) -9.22% Component Inc/(Dec) 4 Revenue by Component Distribution ($1,836,119) $34,195,956 $32,359,837 Transmission $2,512,675 $2,611,387 $5,124,062 Transition ($9,422,530) $20,639,828 $11,217,298 Standard Service $0 $34,100,586 $34,100,586 DSM/Renewables $0 $3,320,320 $3,320,320 --- ($8,745,975) ================================================================================================================================== Sources: Distribution Charges:Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Eastern Edison: Settlement Agreement Charges: Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: R2 TO R2 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 2 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate R-2 to R-2 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO R-2 to R-2 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 168,433 $0.87 $146,537 $3.77 $634,992 2 Interruptible Credit #1 8,636 ($5.50) ($47,498) 3 Interruptible Credit #2 ($7.50) $0 4 Total kWh 67,148,463 Distribution Charge 67,148,463 $0.00579 $388,790 $0.00463 $310,897 Transmission Charge 67,148,463 $0.00291 $195,402 $0.00571 $383,418 Transition Charge 67,148,463 $0.02300 $1,544,415 $0.01250 $839,356 Standard Service Charge 67,148,463 $0.03800 $2,551,642 $0.03800 $2,551,642 DSM/Renewables Charge 67,148,463 $0.00370 $248,449 $0.00370 $248,449 --------- -------- 5 Total Revenue $5,075,234 $4,921,256 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 168,433 Interruptible Credit #1 8,636 Interruptible Credit #2 0 KWh 67,148,463 2 Total Design RevenEEC Rates $5,075,234 MECO 3/1/99 Rates $4,921,256 3 Increase (Decrease) in Total Revenue ($153,978) -3.03% Component Inc/(Dec) 4 Revenue by Component Distribution $363,065 $535,326 $898,391 Transmission $188,016 $195,402 $383,418 Transition ($705,059) $1,544,415 $839,356 Standard Service $0 $2,551,642 $2,551,642 DSM/Renewables $0 $248,449 $248,449 --- ($153,978) ================================================================================================================================== Sources: Distribution Eastern Edison: Currently Effective Tariffs Charges: Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Eastern Edison: Settlement Agreement Charges: Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: R3 TO R1 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 3 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate R-3 to R-1 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO R-3 to R-1 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 70,418 $1.79 $126,048 $5.81 $409,129 2 Total kWh 70,618,533 Distribution Charge 70,618,533 $0.02422 $1,710,381 $0.02502 $1,766,876 Transmission Charge 70,618,533 $0.00291 $205,500 $0.00571 $403,232 Transition Charge 70,618,533 $0.02300 $1,624,226 $0.01250 $882,732 Standard Service Charge 70,618,533 $0.03800 $2,683,504 $0.03800 $2,683,504 DSM/Renewables Charge 70,618,533 $0.00370 $261,289 $0.00370 $261,289 --------- --------- 3 Total Revenue $6,610,948 $6,406,761 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 70,418 KWh 70,618,533 2 Total Design RevenEEC Rates $6,610,948 MECO 3/1/99 Rates $6,406,761 3 Increase (Decrease) in Total Revenue ($204,187) -3.09% Component Inc/(Dec) 4 Revenue by Component Distribution $339,576 $1,836,429 $2,176,005 Transmission $197,732 $205,500 $403,232 Transition ($741,495) $1,624,226 $882,732 Standard Service $0 $2,683,504 $2,683,504 DSM/Renewables $0 $261,289 $261,289 --- ($204,187) ================================================================================================================================== Sources: Distribution Eastern Edison: Currently Effective Tariffs Charges: Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Eastern Edison: Settlement Agreement Charges: Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: R4 TO R1 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 4 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate R-4 to R-1 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO R-4 to R-1 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 544 $7.93 $4,314 544 $5.81 $3,161 2 Total kWh 577,111 577,111 Distribution Charge 577,111 $0.01690 $9,753 577,111 $0.02502 $14,439 Transmission Charge 577,111 $0.00291 $1,679 577,111 $0.00571 $3,295 Transition Charge-On Peak 82,953 $0.10899 $9,041 577,111 $0.01250 $7,214 Transition Charge-Off Peak 494,158 $0.00872 $4,309 $0 Standard Service Charge 577,111 $0.03800 $21,930 577,111 $0.03800 $21,930 DSM/Renewables Charge 577,111 $0.00370 $2,135 577,111 $0.00370 $2,135 ------- ------ 3 Total Revenue $53,162 $52,175 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 544 544 On Peak kWh 82,953 577,111 Off Peak kWh 494,158 0 -------- ------- Total kWh 577,111 577,111 2 Total Design EEC Rates $53,162 Revenue MECO 3/1/99 Rates $52,175 3 Increase (Decrease) in Total Revenue ($987) -1.86% Component Inc/(Dec) 4 Revenue by Component Distribution $3,533 $14,067 $17,600 Transmission $1,616 $1,679 $3,295 Transition ($6,136) $13,350 $7,214 Standard Service $0 $21,930 $21,930 DSM/Renewables $0 $2,135 $2,135 --- ($987) ================================================================================================================================== Sources: Distribution Charges:Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Eastern Edison: Settlement Agreement Charges: Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: W1 TO R1 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 5 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate W-1 to R-1 ============================================================================================================ Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO W-1 to R-1 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ============================================================================================================ Section 1: Revenue Calculation 1 Customer Charge 186,554 $0.90 $167,899 $5.81 $1,083,879 2 Interruptible Credit #1 186,554 ($5.50) ($1,026,047) 3 Interruptible Credit #2 ($7.50) $0 4 Total kWh 48,697,330 Distribution Charge 48,697,330 $0.02343 $1,140,978 $0.02502 $1,218,407 Transmission Charge 48,697,330 $0.00291 $141,709 $0.00571 $278,062 Transition Charge 48,697,330 $0.02300 $1,120,039 $0.01250 $608,717 Standard Service Charge 48,697,330 $0.03800 $1,850,499 $0.03800 $1,850,499 DSM/Renewables Charge 48,697,330 $0.00370 $180,180 $0.00370 $180,180 --------- ---------- 5 Total Revenue $4,601,304 $4,193,696 ========================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 186,554 Interruptible Credit #1 186,554 Interruptible Credit #2 0 KWh 48,697,330 2 Total Design EEC Rates $4,601,304 Revenue: MECO 3/1/99 Rates $4,193,696 3 Increase (Decrease) in Total Revenue ($407,607) -8.86% Component Inc/(Dec) ---------- 4 Revenue by Component Distribution ($32,638) $1,308,877 $1,276,239 Transmission $136,353 $141,709 $278,062 Transition ($511,322) $1,120,039 $608,717 Standard Service $0 $1,850,499 $1,850,499 DSM/Renewables $0 $180,180 $180,180 ($407,607) ========================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge: Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: G1 TO G1 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 6 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate G-1 to G-1 =================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO G-1 to G-1 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) =================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 213,705 $1.34 $286,365 199,662 $8.32 $1,661,188 2 Location Charge 14,043 $6.48 $90,999 3 Total kWh 109,098,086 109,098,086 Distribution Charge 109,098,086 $0.04260 $4,647,578 109,098,086 $0.03843 $4,192,639 Transmission Charge 109,098,086 $0.00291 $317,475 109,098,086 $0.00568 $619,677 Transition Charge 109,098,086 $0.02300 $2,509,256 109,098,086 $0.01250 $1,363,726 Standard Service Charge 109,098,086 $0.03800 $4,145,727 109,098,086 $0.03800 $4,145,727 DSM/Renewables Charge 109,098,086 $0.00370 $403,663 109,098,086 $0.00370 $403,663 --------- --------- 4 Total Revenue $12,310,065 $12,477,619 =================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 213,705 Location Charge 0 KWh 109,098,086 2 Total Design RevenEEC Rates $12,310,065 MECO 3/1/99 Rates $12,477,619 3 Increase (Decrease) in Total Revenue $167,554 1.36% Component Inc/(Dec) 4 Revenue by Component Distribution $1,010,883 $4,933,943 $5,944,826 Transmission $302,202 $317,475 $619,677 Transition ($1,145,530) $2,509,256 $1,363,726 Standard Service ($0) $4,145,727 $4,145,727 DSM/Renewables $0 $403,663 $403,663 --- $167,554 =================================================================================================================================== Sources: Distribution Charges:Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Eastern Edison: Settlement Agreement Charges: Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: G2 TO G1 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 7 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate G-2 to G-1 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO G-2 to G-1 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 61,760 $7.24 $447,142 $8.32 $513,843 2 Demand Charge Distribution Charge 1,041,483 $2.83 $2,947,397 $0.00 $0 Transition Charge 1,041,483 $6.07 $6,321,802 $0.00 $0 ------ ----------- ------ -- Total $8.90 $9,269,199 $0.00 $0 ----------- -- 3 Total Customer & Demand Revenues $9,716,341 $513,843 4 Total kWh 241,828,775 Distribution Charge 241,828,775 $0.01393 $3,368,675 $0.03843 $9,293,480 Transmission Charge 241,828,775 $0.00291 $703,722 $0.00568 $1,373,587 Transition Charge 241,828,775 $0.00198 $478,821 $0.01250 $3,022,860 Standard Service Charge 241,828,775 $0.03800 $9,189,493 $0.03800 $9,189,493 DSM/Renewables Charge 241,828,775 $0.00370 $894,766 $0.00370 $894,766 --------- -------- 5 Total Revenue $24,351,819 $24,288,030 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 61,760 KW: 1,041,483 KWh 241,828,775 2 Total Design RevenEEC Rates $24,351,819 MECO 3/1/99 Rates $24,288,030 3 Increase (Decrease) in Total Revenue ($63,789) -0.26% Component Inc/(Dec) 4 Revenue by Component Distribution $3,044,109 $6,763,214 $9,807,323 Transmission $669,866 $703,722 $1,373,587 Transition ($3,777,763) $6,800,623 $3,022,860 Standard Service $0 $9,189,493 $9,189,493 DSM/Renewables $0 $894,766 $894,766 --- ($63,789) ================================================================================================================================== Sources: Distribution Charges:Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Eastern Edison: Settlement Agreement Charges: Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: G2 TO G2 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 8 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate G-2 to G-2 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO G-2 to G-2 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 18,542 $7.24 $134,244 $15.23 $282,395 2 Demand Charge Distribution Charge 1,300,741 $2.83 $3,681,097 $5.92 $7,700,387 Transition Charge 1,300,741 $6.07 $7,895,498 $0.00 $0 ------ ----------- ------ ---------- Total $8.90 $11,576,595 $5.92 $7,700,387 ------------ ---------- 3 Total Customer & Demand Revenues $11,710,839 $7,982,782 4 Total kWh 424,245,027 Distribution Charge 424,245,027 $0.01393 $5,909,733 $0.00138 $585,458 Transmission Charge 424,245,027 $0.00291 $1,234,553 $0.00513 $2,176,377 Transition Charge 424,245,027 $0.00198 $840,005 $0.01250 $5,303,063 Standard Service Charge 424,245,027 $0.03800 $16,121,311 $0.03800 $16,121,311 DSM/Renewables Charge 424,245,027 $0.00370 $1,569,707 $0.00370 $1,569,707 ----------- ----------- 5 Total Revenue $37,386,148 $33,738,697 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 18,542 KW: 1,300,741 KWh 424,245,027 2 Total Design RevenEEC Rates $37,386,148 MECO 3/1/99 Rates $33,738,697 3 Increase (Decrease) in Total Revenue ($3,647,451) -9.76% Component Inc/(Dec) 4 Revenue by Component Distribution ($1,156,834) $9,725,074 $8,568,240 Transmission $941,824 $1,234,553 $2,176,377 Transition ($3,432,440) $8,735,503 $5,303,063 Standard Service $0 $16,121,311 $16,121,311 DSM/Renewables $0 $1,569,707 $1,569,707 ------------ ($3,647,451) ================================================================================================================================== Sources: Distribution Charges:Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Eastern Edison: Settlement Agreement Charges: Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: G2 TO G3 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 9 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate G-2 to G-3 =================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO G-2 to G-3 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) =================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 1,794 $7.24 $12,989 1,794 $67.27 $120,682 2 Demand Charge Distribution Charge 508,532 $2.83 $1,439,146 513,617 $3.63 $1,864,430 Transition Charge 508,532 $6.07 $3,086,789 513,617 $0.00 $0 ------ ----------- ------ ----------- Total $8.90 $4,525,935 $3.63 $1,864,430 ----------- ----------- 3 Total Customer & Demand Revenues $4,538,923 $1,985,112 4 Total kWh 173,540,944 173,540,944 Distribution Charge: On Peak 173,540,944 $0.01393 $2,417,425 86,770,472 $0.01183 $1,026,495 Distribution Charge: Off Peak $0 86,770,472 $0.00000 $0 Transmission Charge 173,540,944 $0.00291 $505,004 173,540,944 $0.00460 $798,288 Transition Charge 173,540,944 $0.00198 $343,611 173,540,944 $0.01250 $2,169,262 Standard Service Charge 173,540,944 $0.03800 $6,594,556 173,540,944 $0.03800 $6,594,556 DSM/Renewables Charge 173,540,944 $0.00370 $642,101 173,540,944 $0.00370 $642,101 ----------- --------- 5 Total Revenue $15,041,621 $13,215,814 =================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 1,794 1,794 KW 508,532 513,617 On Peak kWh 86,770,472 Off Peak kWh 86,770,472 Total kWh 173,540,944 173,540,944 2 Total Design RevenEEC Rates $15,041,621 MECO 3/1/99 Rates $13,215,814 3 Increase (Decrease) in Total Revenue ($1,825,807) -12.14% Component Inc/(Dec) 4 Revenue by Component Distribution ($857,953) $3,869,559 $3,011,607 Transmission $293,284 $505,004 $798,288 Transition ($1,261,139) $3,430,400 $2,169,262 Standard Service $0 $6,594,556 $6,594,556 DSM/Renewables $0 $642,101 $642,101 --- ($1,825,807) =================================================================================================================================== Sources: Distribution Charges:Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Eastern Edison: Settlement Agreement Charges: Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: G4 TO G3 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 10 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate G-4 to G-3 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO G-4 to G-3 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 1,097 $17.82 $19,549 1,097 $67.27 $73,795 2 Demand Charge Distribution Charge 794,802 $2.81 $2,233,394 822,620 $3.63 $2,986,111 Transition Charge 794,802 $6.04 $4,800,604 822,620 $0.00 $0 ------ ----------- ------ ---------- Total $8.85 $7,033,998 $3.63 $2,986,111 ----------- ---------- 3 Total Customer & Demand Revenues $7,053,546 $3,059,906 4 Total kWh 344,807,994 344,807,994 Distribution Charge: On Peak 344,807,994 $0.00657 $2,265,389 162,059,757 $0.01183 $1,917,167 Distribution Charge: Off Peak $0.00657 $0 182,748,237 $0.00000 $0 Transmission Charge 344,807,994 $0.00291 $1,003,391 344,807,994 $0.00460 $1,586,117 Transition Charge: On Peak 76,958,311 $0.01352 $1,040,476 162,059,757 $0.01250 $2,025,747 Transition Charge: Off Peak 267,849,683 $0.00740 $1,982,088 182,748,237 $0.01250 $2,284,353 Standard Service Charge 344,807,994 $0.03800 $13,102,704 344,807,994 $0.03800 $13,102,704 DSM/Renewables Charge 344,807,994 $0.00370 $1,275,790 344,807,994 $0.00370 $1,275,790 ----------- ---------- 5 Total Revenue $27,723,383 $25,251,783 =================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 1,097 1,097 KW 794,802 822,620 On Peak kWh 76,958,311 162,059,757 Off Peak kWh 267,849,683 182,748,237 ------------ ----------- Total kWh 344,807,994 344,807,994 2 Total Design Revenue:EEC Rates $27,723,383 MECO 3/1/99 Rates $25,251,783 3 Increase (Decrease) in Total Revenue ($2,471,600) -8.92% Component Inc/(Dec) 4 Revenue by Component Distribution $458,742 $4,518,331 $4,977,073 Transmission $582,726 $1,003,391 $1,586,117 Transition ($3,513,068) $7,823,168 $4,310,100 Standard Service $0 $13,102,704 $13,102,704 DSM/Renewables $0 $1,275,790 $1,275,790 --- ($2,471,600) =================================================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge:Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: G5 TO G2 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 11 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate G-5 to G-2 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO G-5 to G-2 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 168 $43.87 $7,370 168 $15.23 $2,559 2 Demand Charge Distribution Charge 20,285 $2.22 $45,033 21,096 $5.92 $124,888 Transition Charge 20,285 $4.78 $96,962 21,096 $0.00 $0 ------ -------- ------ -------- Total $7.00 $141,995 $5.92 $124,888 --------- -------- 3 Total Customer & Demand Revenues $149,365 $127,447 4 Total kWh 7,126,400 7,126,400 Distribution Charge 7,126,400 $0.01324 $94,354 7,126,400 $0.00138 $9,834 Transmission Charge 7,126,400 $0.00291 $20,738 7,126,400 $0.00513 $36,558 Transition Charge: On Peak 1,672,460 $0.01318 $22,043 7,126,400 $0.01250 $89,080 Transition Charge: Off Peak 5,453,940 $0.00766 $41,777 Standard Service Charge 7,126,400 $0.03800 $270,803 7,126,400 $0.03800 $270,803 DSM/Renewables Charge 7,126,400 $0.00370 $26,368 7,126,400 $0.00370 $26,368 -------- ------- 5 Total Bill $625,448 $560,091 6 High Voltage Metering @ -1% Distribution -1.00% ($5,235) Transmission -1.00% ($366) -------- Total ($5,601) 7 High Voltage Delivery @ -$.45 20,285 21,096 ($0.45) ($9,493) -------- 8 Total Revenue $625,448 $544,997 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 168 168 KW 20,285 21,096 On Peak kWh 1,672,460 Off Peak kWh 5,453,940 Total kWh 7,126,400 7,126,400 2 Total Design Revenue:EEC Rates $625,448 MECO 3/1/99 Rates $544,997 3 Increase (Decrease) in Total Revenue ($80,451) -12.86% Component Inc/(Dec) 4 Revenue by Component Distribution ($24,203) $146,756 $122,553 Transmission $15,455 $20,738 $36,193 Transition ($71,703) $160,783 $89,080 Standard Service $0 $270,803 $270,803 DSM/Renewables $0 $26,368 $26,368 --- ($80,451) ================================================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge:Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: G5 TO G3 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 12 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate G-5 to G-3 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO G-5 to G-3 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 234 $43.87 $10,266 234 $67.27 $15,741 2 Demand Charge Distribution Charge 55,906 $2.22 $124,111 60,155 $3.63 $218,363 Transition Charge 55,906 $4.78 $267,231 60,155 $0.00 $0 ------ --------- ------ -------- Total $7.00 $391,342 $3.63 $218,363 --------- -------- 3 Total Customer & Demand Revenues $401,608 $234,104 4 Total kWh 18,249,760 18,249,760 Distribution Charge: On Peak 18,249,760 $0.01324 $241,627 9,672,373 $0.01183 $114,424 Distribution Charge: Off Peak 8,577,387 $0.00000 $0 Transmission Charge 18,249,760 $0.00291 $53,107 18,249,760 $0.00460 $83,949 Transition Charge: On Peak 4,643,330 $0.01318 $61,199 9,672,373 $0.01250 $120,905 Transition Charge: Off Peak 13,606,430 $0.00766 $104,225 8,577,387 $0.01250 $107,217 Standard Service Charge 18,249,760 $0.03800 $693,491 18,249,760 $0.03800 $693,491 DSM/Renewables Charge 18,249,760 $0.00370 $67,524 18,249,760 $0.00370 $67,524 -------- ------- 5 Total Bill $1,622,781 $1,421,614 6 High Voltage Metering @ -1% Distribution -1.00% ($13,377) Transmission -1.00% ($839) ------ Total ($14,216) 7 High Voltage Delivery @ -$.45 55,906 60,155 ($0.45) ($27,070) --------- 8 Total Revenue $1,622,781 $1,380,328 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 234 234 KW 55,906 60,155 On Peak kWh 4,643,330 9,672,373 Off Peak kWh 13,606,430 8,577,387 ----------- --------- Total kWh 18,249,760 18,249,760 2 Total Design Revenue:EEC Rates $1,622,781 MECO 3/1/99 Rates $1,380,328 3 Increase (Decrease) in Total Revenue ($242,452) -14.94% Component Inc/(Dec) 4 Revenue by Component Distribution ($67,922) $376,004 $308,082 Transmission $30,003 $53,107 $83,109 Transition ($204,533) $432,655 $228,122 Standard Service $0 $693,491 $693,491 DSM/Renewables $0 $67,524 $67,524 --- ($242,452) ================================================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge:Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: G6 TO G3 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 13 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate G-6 to G-3 =================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO G-6 to G-3 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) =================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 380 $43.87 $16,671 380 $67.27 $25,563 2 Demand Charge Distribution Charge 439,150 $2.22 $974,913 513,806 $3.63 $1,865,116 Transition Charge 439,150 $4.78 $2,099,137 513,806 $0.00 $0 ------ ----------- ------ ---------- Total $7.00 $3,074,050 $3.63 $1,865,116 ----------- ---------- 3 Total Customer & Demand Revenues $3,090,721 $1,890,679 4 Total kWh 194,448,972 194,448,972 Distribution Charge: On Peak 194,448,972 $0.00839 $1,631,427 85,557,548 $0.01183 $1,012,146 Distribution Charge: Off Peak 108,891,424 $0.00000 $0 Transmission Charge 194,448,972 $0.00291 $565,847 194,448,972 $0.00460 $894,465 Transition Charge: On Peak 38,898,442 $0.01679 $653,105 85,557,548 $0.01250 $1,069,469 Transition Charge: Off Peak 155,550,530 $0.01127 $1,753,054 108,891,424 $0.01250 $1,361,143 Standard Service Charge 194,448,972 $0.03800 $7,389,061 194,448,972 $0.03800 $7,389,061 DSM/Renewables Charge 194,448,972 $0.00370 $719,461 194,448,972 $0.00370 $719,461 --------- ---------- 5 Total Bill $15,802,675 $14,336,424 6 High Voltage Metering @ -1% Distribution -1.00% ($134,420) Transmission -1.00% ($8,945) -------- Total ($143,364) 7 High Voltage Delivery @ -$.45 439,150 513,806 ($0.45) ($231,213) ---------- 8 Total Revenue $15,802,675 $13,961,847 =================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 380 380 KW 439,150 513,806 On Peak kWh 38,898,442 85,557,548 Off Peak kWh 155,550,530 108,891,424 ------------ ------------ Total kWh 194,448,972 194,448,972 2 Total Design Revenue:EEC Rates $15,802,675 MECO 3/1/99 Rates $13,961,847 3 Increase (Decrease) in Total Revenue ($1,840,828) -11.65% Component Inc/(Dec) 4 Revenue by Component Distribution ($85,818) $2,623,010 $2,537,193 Transmission $319,674 $565,847 $885,521 Transition ($2,074,684) $4,505,296 $2,430,612 Standard Service $0 $7,389,061 $7,389,061 DSM/Renewables $0 $719,461 $719,461 --- ($1,840,828) ================================================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge:Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: T2 TO G1 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 14 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate T-2 to G-1 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO T-2 to G-1 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 297 $12.84 $3,813 $8.32 $2,471 2 Demand Charge Distribution Charge 4,390 $2.92 $12,819 $0.00 $0 Transition Charge 4,390 $6.29 $27,613 $0.00 $0 ------ -------- ------ -- Total $9.21 $40,432 $0.00 $0 -------- -- 3 Total Customer & Demand Revenues $44,245 $2,471 4 Total kWh 1,178,927 Distribution Charge 1,178,927 $0.00231 $2,723 $0.03843 $45,306 Transmission Charge 1,178,927 $0.00291 $3,431 $0.00568 $6,696 Transition Charge: On Peak 205,124 $0.01536 $3,151 $0.01250 $2,564 Transition Charge: Off Peak 973,803 $0.00923 $8,988 $0.01250 $12,173 Standard Service Charge 1,178,927 $0.03800 $44,799 $0.03800 $44,799 DSM/Renewables Charge 1,178,927 $0.00370 $4,362 $0.00370 $4,362 ------- ------- 5 Total Revenue $111,700 $118,371 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 297 KW 4,390 KWh 1,178,927 2 Total Design Revenue:EEC Rates $111,700 MECO 3/1/99 Rates $118,371 3 Increase (Decrease) in Total Revenue $6,672 5.97% Component Inc/(Dec) 4 Revenue by Component Distribution $28,422 $19,356 $47,777 Transmission $3,266 $3,431 $6,696 Transition ($25,015) $39,752 $14,737 Standard Service $0 $44,799 $44,799 DSM/Renewables $0 $4,362 $4,362 --- $6,672 ================================================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge:Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: T2 TO G2 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 15 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate T-2 to G-2 ================================================================================================================================ Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO T-2 to G-2 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) =============================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 554 $12.84 $7,113 554 $15.23 $8,437 2 Demand Charge Distribution Charge 42,478 $2.92 $124,036 45,027 $5.92 $266,560 Transition Charge 42,478 $6.29 $267,187 45,027 $0.00 $0 ------ --------- ------ -- Total $9.21 $391,222 $5.92 $266,560 --------- -------- 3 Total Customer & Demand Revenues $398,336 $274,997 4 Total kWh 18,743,578 18,743,578 Distribution Charge 18,743,578 $0.00231 $43,298 18,743,578 $0.00138 $25,866 Transmission Charge 18,743,578 $0.00291 $54,544 18,743,578 $0.00513 $96,155 Transition Charge: On Peak 3,623,614 $0.01536 $55,659 18,743,578 $0.01250 $234,295 Transition Charge: Off Peak 15,119,964 $0.00923 $139,557 Standard Service Charge 18,743,578 $0.03800 $712,256 18,743,578 $0.03800 $712,256 DSM/Renewables Charge 18,743,578 $0.00370 $69,351 18,743,578 $0.00370 $69,351 -------- ----------- ------- 5 Total Revenue $1,473,000 $1,412,919 ================================================================================================================================ Section 2: Summary 1 Total Units - Number of Bills 554 KW 42,478 KWh 18,743,578 2 Total Design Revenue: EEC Rates $1,473,000 MECO 3/1/99 Rates $1,412,919 3 Increase (Decrease) in Total Revenue ($60,081) -4.08% Component Inc/(Dec) 4 Revenue by Component Distribution $126,416 $174,447 $300,863 Transmission $41,611 $54,544 $96,155 Transition ($228,108) $462,403 $234,295 Standard Service $0 $712,256 $712,256 DSM/Renewables $0 $69,351 $69,351 --- ($60,081) ================================================================================================================================= Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge: Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: T2 TO G3 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 16 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate T-2 to G-3 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO T-2 to G-3 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 348 $12.84 $4,468 348 $67.27 $23,410 2 Demand Charge Distribution Charge 108,745 $2.92 $317,535 111,790 $3.63 $405,798 Transition Charge 108,745 $6.29 $684,006 111,790 $0.00 $0 ------ ---------- ------ -------- Total $9.21 $1,001,541 $3.63 $405,798 ---------- -------- 3 Total Customer & Demand Revenues $1,006,010 $429,208 4 Total kWh 53,151,417 53,151,417 Distribution Charge: On Peak 53,151,417 $0.00231 $122,780 22,323,595 $0.01183 $264,088 Distribution Charge: Off Peak $0 30,827,822 $0.00000 $0 Transmission Charge 53,151,417 $0.00291 $154,671 53,151,417 $0.00460 $244,497 Transition Charge: On Peak 10,316,557 $0.01536 $158,462 22,323,595 $0.01250 $279,045 Transition Charge: Off Peak 42,834,860 $0.00923 $395,366 30,827,822 $0.01250 $385,348 Standard Service Charge 53,151,417 $0.03800 $2,019,754 53,151,417 $0.03800 $2,019,754 DSM/Renewables Charge 53,151,417 $0.00370 $196,660 53,151,417 $0.00370 $196,660 --------- -------- 5 Total Revenue $4,053,702 $3,818,599 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 348 348 KW 108,745 111,790 On Peak kWh 10,316,557 22,323,595 Off Peak kWh 42,834,860 30,827,822 ----------- ---------- Total kWh 53,151,417 53,151,417 2 Total Design Revenue:EEC Rates $4,053,702 MECO 3/1/99 Rates $3,818,599 3 Increase (Decrease) in Total Revenue ($235,103) -5.80% Component Inc/(Dec) 4 Revenue by Component Distribution $248,512 $444,783 $693,296 Transmission $89,826 $154,671 $244,497 Transition ($573,441) $1,237,834 $664,393 Standard Service $0 $2,019,754 $2,019,754 DSM/Renewables $0 $196,660 $196,660 ----------- ($235,103) ================================================================================================================================= Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge:Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: H1 TO G1 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 17 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate H-1 to G-1 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO H-1 to G-1 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ================================================================================================================================== Section 1: Rate Design 1 Customer Charge 1,231 $5.39 $6,635 $8.32 $10,242 2 Location Charge $6.48 $0 3 Total kWh 2,545,293 Distribution Charge 2,545,293 $0.02669 $67,934 $0.03843 $97,816 Transmission Charge 2,545,293 $0.00291 $7,407 $0.00568 $14,457 Transition Charge 2,545,293 $0.02300 $58,542 $0.01250 $31,816 Standard Service Charge 2,545,293 $0.03800 $96,721 $0.03800 $96,721 DSM/Renewables Charge 2,545,293 $0.00370 $9,418 $0.00370 $9,418 ------- ------ 4 Total Revenue $246,656 $260,470 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 1,231 Location Charge 0 KWh 2,545,293 2 Total Design Revenue:EEC Rates $246,656 MECO 3/1/99 Rates $260,470 3 Increase (Decrease) in Total Revenue $13,814 5.60% Component Inc/(Dec) 4 Revenue by Component Distribution $33,489 $74,569 $108,058 Transmission $7,050 $7,407 $14,457 Transition ($26,726) $58,542 $31,816 Standard Service $0 $96,721 $96,721 DSM/Renewables $0 $9,418 $9,418 --- $13,814 ================================================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge:Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: H1 TO G2 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 18 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate H-1 to G-2 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO H-1 to G-1 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 35 $5.39 $189 35 $15.23 $533 2 Demand Charge Distribution Charge 3,427 $0.00 $0 3,427 $5.92 $20,288 Transition Charge 3,427 $0.00 $0 3,427 $0.00 $0 Total $0.00 $0 $5.92 $20,288 3 Total Customer & Demand Revenues $189 $20,821 4 Total kWh 704,880 704,880 Distribution Charge 704,880 $0.02669 $18,813 704,880 $0.00138 $973 Transmission Charge 704,880 $0.00291 $2,051 704,880 $0.00513 $3,616 Transition Charge 704,880 $0.02300 $16,212 704,880 $0.01250 $8,811 Standard Service Charge 704,880 $0.03800 $26,785 704,880 $0.03800 $26,785 DSM/Renewables Charge 704,880 $0.00370 $2,608 704,880 $0.00370 $2,608 5 Total Revenue $66,659 $63,614 =================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 35 KW 3,427 KWh 704,880 2 Total Design RevEECeRates $66,659 MECO 3/1/99 Rates $63,614 3 Increase (Decrease) in Total Revenue ($3,045) -4.57% Component Inc/(Dec) 4 Revenue by Component Distribution $2,792 $19,002 $21,794 Transmission $1,565 $2,051 $3,616 Transition ($7,401) $16,212 $8,811 Standard Service $0 $26,785 $26,785 DSM/Renewables $0 $2,608 $2,608 ($3,045) ================================================================================================================================== Sources: Distribution ChargeEastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission ChargeEastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges:Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service ChEastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables:Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: H1 TO G3 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 19 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate H-1 to G-3 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO H-1 to G-3 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 48 $5.39 $259 48 $67.27 $3,229 2 Demand Charge Distribution Charge 34,790 $0.00 $0 38,617 $3.63 $140,180 Transition Charge 34,790 $0.00 $0 38,617 $0.00 $0 ------ --- ------ -- Total $0.00 $0 $3.63 $140,180 --- -------- 3 Total Customer & Demand Revenues $259 $143,409 4 Total kWh 6,702,200 6,702,200 Distribution Charge: On Peak 6,702,200 $0.02669 $178,882 3,552,166 $0.01183 $42,022 Distribution Charge: Off Peak $0 3,150,034 $0.00000 $0 Transmission Charge 6,702,200 $0.00291 $19,503 6,702,200 $0.00460 $30,830 Transition Charge 6,702,200 $0.02300 $154,151 6,702,200 $0.01250 $83,778 Standard Service Charge 6,702,200 $0.03800 $254,684 6,702,200 $0.03800 $254,684 DSM/Renewables Charge 6,702,200 $0.00370 $24,798 6,702,200 $0.00370 $24,798 -------- ------- 5 Total Revenue $632,276 $579,520 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 48 48 KW 34,790 38,617 On Peak kWh 3,552,166 Off Peak kWh 3,150,034 --------- Total kWh 6,702,200 6,702,200 2 Total Design Revenue:EEC Rates $632,276 MECO 3/1/99 Rates $579,520 3 Increase (Decrease) in Total Revenue ($52,756) -8.34% Component Inc/(Dec) 4 Revenue by Component Distribution $6,291 $179,140 $185,431 Transmission $11,327 $19,503 $30,830 Transition ($70,373) $154,151 $83,778 Standard Service $0 $254,684 $254,684 DSM/Renewables $0 $24,798 $24,798 --- ($52,756) ================================================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge:Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: H2 TO G1 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 20 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate H-2 to G-1 ================================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO H-2 to G-1 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ================================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 1,979 $1.35 $2,672 $8.32 $16,465 2 Location Charge $6.48 $0 3 Total kWh 2,299,322 Distribution Charge 2,299,322 $0.02828 $65,025 $0.03843 $88,363 Transmission Charge 2,299,322 $0.00291 $6,691 $0.00568 $13,060 Transition Charge 2,299,322 $0.02300 $52,884 $0.01250 $28,742 Standard Service Charge 2,299,322 $0.03800 $87,374 $0.03800 $87,374 DSM/Renewables Charge 2,299,322 $0.00370 $8,507 $0.00370 $8,507 ------- ------ 4 Total Revenue $223,154 $242,511 ================================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 1,979 Location Charge 0 KWh 2,299,322 2 Total Design Revenue:EEC Rates $223,154 MECO 3/1/99 Rates $242,511 3 Increase (Decrease) in Total Revenue $19,358 8.67% Component Inc/(Dec) 4 Revenue by Component Distribution $37,131 $67,696 $104,828 Transmission $6,369 $6,691 $13,060 Transition ($24,143) $52,884 $28,742 Standard Service ($0) $87,374 $87,374 DSM/Renewables $0 $8,507 $8,507 --- $19,358 ================================================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge:Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: H2 TO G2 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 21 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate H-2 to G-2 ==================================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO MECO H-2 to G-2 Units Rate Revenues Units Rate Revenues Comments (1) (2) (3) (4) (5) (6) ==================================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 12 $1.35 $16 12 $15.23 $183 2 Demand Charge Distribution Charge 496 $0.00 $0 496 $5.92 $2,936 Transition Charge 496 $0.00 $0 496 $0.00 $0 ------ --- ------ -- Total $0.00 $0 $5.92 $2,936 --- ------ 3 Total Customer & Demand Revenues $16 $3,119 4 Total kWh 135,360 135,360 Distribution Charge 135,360 $0.02828 $3,828 135,360 $0.00138 $187 Transmission Charge 135,360 $0.00291 $394 135,360 $0.00513 $694 Transition Charge 135,360 $0.02300 $3,113 135,360 $0.01250 $1,692 Standard Service Charge 135,360 $0.03800 $5,144 135,360 $0.03800 $5,144 DSM/Renewables Charge 135,360 $0.00370 $501 135,360 $0.00370 $501 ----- ---- 5 Total Revenue $12,996 $11,337 ==================================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 12 On Peak kWh 496 KWh 135,360 2 Total Design EEC Rates $12,996 Revenue: MECO 3/1/99 Rates $11,337 3 Increase (Decrease) in Total Revenue ($1,659) -12.76% Component Inc/(Dec) 4 Revenue by Component Distribution ($538) $3,844 $3,306 Transmission $301 $394 $694 Transition ($1,421) $3,113 $1,692 Standard Service $0 $5,144 $5,144 DSM/Renewables $0 $501 $501 --- ($1,659) ==================================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge: Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges: Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge: Eastern Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables: Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System Range: W1 TO G1 Eastern Utilities Associates Date: 04-May-99 M.D.T.E. Docket No. 99-__ Time: 09:05 AM Workpaper TMB-1, Revised Page 22 of 25 Massachusetts Electric Company Eastern Edison Company Revenue Analysis for Rate W-1 to G-1 ========================================================================================================== Estimated Year 2001 Consolidated Year 2001 EEC EEC MECO MECO W-1 to G-1 Units Rate Revenues Rate Revenues Comments (1) (2) (3) (4) (5) ========================================================================================================== Section 1: Revenue Calculation 1 Customer Charge 2,715 $0.90 $2,444 $8.32 $22,589 2 Total kWh 779,421 Distribution Charge 779,421 $0.02343 $18,262 $0.03843 $29,953 Transmission Charge 779,421 $0.00291 $2,268 $0.00568 $4,427 Transition Charge 779,421 $0.02300 $17,927 $0.01250 $9,743 Standard Service Charge 779,421 $0.03800 $29,618 $0.03800 $29,618 DSM/Renewables Charge 779,421 $0.00370 $2,884 $0.00370 $2,884 ------- ------- 5 Total Revenue $73,402 $99,214 ========================================================================================================== Section 2: Summary 1 Total Units - Number of Bills 2,715 KWh 779,421 2 Total Design EEC Rates $73,402 Revenue: MECO 3/1/99 Rates $99,214 3 Increase (Decrease) in Total Revenue $25,812 35.17% Component Inc/(Dec) --------- 4 Revenue by Component Distribution $31,837 $20,705 $52,542 Transmission $2,159 $2,268 $4,427 Transition ($8,184) $17,927 $9,743 Standard Service ($0) $29,618 $29,618 DSM/Renewables ($0) $2,884 $2,884 --------- $25,812 ========================================================================================================== Sources: Distribution Charges: Eastern Edison: Currently Effective Tariffs Mass. Electric: Currently Effective Tariffs Transmission Charge" Eastern Edison: Workpaper TMB-2 Mass. Electric: Workpaper TBM-3 Transition Charges" Eastern Edison: Workpaper TMB-5 Mass. Electric: Workpaper TMB-4 Standard Service Charge: Eastern:Edison: Settlement Agreement Mass. Electric: Settlement Agreement DSM and Renewables" Eastern Edison: Utility Restructuring Act Mass. Electric: Utility Restructuring Act Massachusetts Electric Company Eastern Edison Company Streetlight Revenue Analysis EEC EEC EEC EEC EEC Annual Total EEC Annual Lighting Lumen Service Special 12/98 kWh Annual Annual Distribution Code Wattage Size & Pole Type Pricing Quantity per Light kWh Price Revenue -------- ------- ------ -------- ---- ------- -------- --------- ------ ------ ------------ METAL HALIDE 3004120 250 20,000 OH_WoodLine FldLt 9 1,180 10,620 $98.66 $888 3004220 250 20,000 OH_WoodLitg FldLt 2 1,180 2,360 $188.89 $378 4664120 400 40,000 OH_WoodLine FldLt 39 1,832 71,448 $138.15 $5,388 10804120 1,000 115,000 OH_WoodLine FldLt 4 4,247 16,988 $123.98 $496 ------ ------ Total Metal Halide 54 101,416 $7,149 - ----------------------------------------------------------------------------------------------------------------------------- INCANDESCENT 1031110 103 1,000 OH_WoodLine StLt 2 405 810 $40.22 $80 2021110 202 2,500 OH_WoodLine StLt 1 794 794 $49.52 $50 --- --- Total Incandescent 3 1,604 $130 - ----------------------------------------------------------------------------------------------------------------------------- MERCURY VAPOR 1302110 100 4,200 OH_WoodLine StLt 269 511 137,459 $54.85 $14,755 1302810 100 4,200 URD_LamWood StLt 14 511 7,154 $215.15 $3,012 1302811 100 4,200 URD_LamWood StLt CustPaidPole 2 511 1,022 $59.13 $118 1302941 100 4,200 URD_WoodPost T&C CustPaidPole 4 511 2,044 $52.09 $208 2092110 175 8,600 OH_WoodLine StLt 39 822 32,058 $62.28 $2,429 2092130 175 8,600 OH_WoodLine PBU 226 822 185,772 $68.08 $15,386 2092211 175 8,600 OH_WoodLitg StLt CustPaidPole 1 822 822 $62.28 $62 2092231 175 8,600 OH_WoodLitg PBU CustPaidPole 7 822 5,754 $68.08 $477 2092541 175 8,600 UG_Steel T&C CustPaidPole 37 822 30,414 $59.52 $2,202 2092610 175 8,600 UG_Aluminum StLt 5 822 4,110 $222.57 $1,113 3002110 250 12,100 OH_WoodLine StLt 3 1,180 3,540 $77.01 $231 4742110 400 22,500 OH_WoodLine StLt 15 1,864 27,960 $94.83 $1,422 4742120 400 22,500 OH_WoodLine FldLt 174 1,864 324,336 $97.08 $16,892 4742130 400 22,500 OH_WoodLine PBU 30 1,864 55,920 $98.50 $2,955 4742211 400 22,500 OH_WoodLitg StLt CustPaidPole 8 1,864 14,912 $94.83 $759 4742221 400 22,500 OH_WoodLitg FldLt CustPaidPole 42 1,864 78,288 $97.08 $4,077 4742231 400 22,500 OH_WoodLitg PBU CustPaidPole 1 1,864 1,864 $98.50 $99 11352120 1,000 63,000 OH_WoodLine FldLt 34 4,463 151,742 $175.49 $5,967 11352221 1,000 63,000 OH_WoodLitg FldLt CustPaidPole 5 4,463 22,315 $175.49 $877 -- ------- ------ Total Mercury Vapor 916 1,087,486 $73,041 - ---------------------------------------------------------------------------------------------------------------------------- SODIUM VAPOR 613110 50 3,300 OH_WoodLine StLt 4,424 240 1,061,76 $45.14 $199,699 613211 50 3,300 OH_WoodLitg StLt CustPaidPole 5 240 1,200 $45.14 $226 613941 50 3,300 URD_WoodPost T&C CustPaidPole 2 240 480 $44.38 $89 853110 70 5,800 OH_WoodLine StLt 14,491 334 4,839,99 $47.39 $686,728 853120 70 5,800 OH_WoodLine FldLt 111 334 37,074 $59.87 $6,646 853210 70 5,800 OH_WoodLitg StLt 3 334 1,002 $119.97 $360 853211 70 5,800 OH_WoodLitg StLt CustPaidPole 20 334 6,680 $47.39 $948 853221 70 5,800 OH_WoodLitg FldLt CustPaidPole 2 334 668 $59.87 $120 New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Workpaper TMB-1, Revised Page 23 of 25 MECO MECO MECO Increase MECO Annual Total MECO Annual (Decrease) in MECO Lumen 12/98 kWh Annual Annual Distribution Distribution Code Size Type Quantity per Light kWh Price Revenue Revenue ----- ------ ---- -------- --------- ------ ------ ------------ ------------ 77 27,500 Flood 9 1,255 11,295 $143.82 $1,294 $406 77 27,500 Flood 2 1,255 2,510 143.82 $288 ($90) P wood pole $41.90 $84 $84 78 50,000 Flood 39 1,968 76,752 $163.80 $6,388 $1,000 80 140,000 Flood 4 4,578 18,312 $220.41 $882 $386 -- ------ 54 108,869 $8,936 $1,786 - ----------------------------------------------------------------------------------------- 10 1,000 StLt 2 440 880 $48.46 $97 $16 11 2,500 StLt 1 845 845 $59.83 $60 $10 -- --- ---- ---- 3 1,725 $157 $27 - ---------------------------------------------------------------------------------------- 3 4,000 StLt 269 561 150,909 $48.49 $13,044 ($1,711) 3 4,000 StLt 14 561 7,854 $48.49 $679 ($2,333) R fiberglass w/o base $49.36 $691 $691 3 4,000 StLt 2 561 1,122 $48.49 $97 ($21) 1 4,000 Post Top 4 561 2,244 $57.46 $230 $21 4 8,000 StLt 39 908 35,412 $53.89 $2,102 ($327) 4 8,000 StLt 226 908 205,208 $53.89 $12,179 ($3,207) 4 8,000 StLt 1 908 908 $53.89 $54 ($8) 4 8,000 StLt 7 908 6,356 $53.89 $377 ($99) 2 8,000 Post Top 37 908 33,596 $76.89 $2,845 $643 4 8,000 StLt 5 908 4,540 $53.89 $269 ($843) T metal w/foundation $128.30 $642 $642 16 11,000 StLt 3 1,248 3,744 $69.43 $208 ($23) 5 22,000 StLt 15 1,897 28,455 $89.34 $1,340 ($82) 23 22,000 Flood 174 1,897 330,078 $107.27 $18,665 $1,773 5 22,000 StLt 30 1,897 56,910 $89.34 $2,680 ($275) 5 22,000 StLt 8 1,897 15,176 $89.34 $715 ($44) 23 22,000 Flood 42 1,897 79,674 $107.27 $4,505 $428 5 22,000 StLt 1 1,897 1,897 $89.34 $89 ($9) 24 63,000 Flood 34 4,569 155,346 $195.22 $6,637 $671 24 63,000 Flood 5 4,569 22,845 $195.22 $976 $99 -- ------- ------ ----- 916 1,142,274 $69,025 ($4,016) - ---------------------------------------------------------------------------------------- 70 4,000 StLt 4,424 248 1,097,152 $55.82 $246,948 $47,248 70 4,000 StLt 5 248 1,240 $55.82 $279 $53 83 4,000 Post Top 2 248 496 $61.22 $122 $34 71 5,800 StLt 14,491 349 5,057,359 $67.52 $978,432 $291,704 77 27,500 Flood 111 1,255 139,305 $143.82 $15,964 $9,318 71 5,800 StLt 3 349 1,047 $67.52 $203 ($157) P wood pole $41.90 $126 $126 71 5,800 StLt 20 349 6,980 $67.52 $1,350 $403 77 27,500 Flood 2 1,255 2,510 $143.82 $288 $168 C:\eua files on disk\wptmb-1.WK4 15-Jun-99 Massachusetts Electric Company Eastern Edison Company Streetlight Revenue Analysis EEC EEC EEC EEC EEC Annual Total EEC Annual Lighting Lumen Service Special 12/98 kWh Annual Annual Distribution Code Wattage Size & Pole Type Pricing Quantity per Light kWh Price Revenue ------- ------- ----- -------- ---- ------- -------- --------- ------ ------ 853441 70 5,800 URD_Fiberglass T&C CustPaidPole 118 334 39,412 $45.55 $5,375 853461 70 5,800 URD_Fiberglass SBA CustPaidPole 146 334 48,764 $87.16 $12,725 853641 70 5,800 UG_Aluminum T&C CustPaidPole 3 334 1,002 $45.55 $137 853711 70 5,800 UG_WoodLitg StLt CustPaidPole 7 334 2,338 $56.72 $397 853811 70 5,800 URD_LamWood StLt CustPaidPole 199 334 66,466 $51.66 $10,280 853941 70 5,800 URD_WoodPost T&C CustPaidPole 222 334 74,148 $45.55 $10,112 1213110 100 9,500 OH_WoodLine StLt 7,510 476 3,574,76 $51.05 $383,386 1213130 100 9,500 OH_WoodLine PBU 357 476 169,932 $55.98 $19,985 1213211 100 9,500 OH_WoodLitg StLt CustPaidPole 88 476 41,888 $51.05 $4,492 1213230 100 9,500 OH_WoodLitg PBU 1 476 476 $128.54 $129 1213231 100 9,500 OH_WoodLitg PBU CustPaidPole 39 476 18,564 $55.98 $2,183 1213441 100 9,500 URD_Fiberglass T&C CustPaidPole 46 476 21,896 $50.49 $2,323 1213460 100 9,500 URD_Fiberglass SBA 4 476 1,904 $191.25 $765 1213461 100 9,500 URD_Fiberglass SBA CustPaidPole 28 476 13,328 $99.88 $2,797 1213610 100 9,500 UG_Aluminum StLt 29 476 13,804 $211.33 $6,129 1213631 100 9,500 UG_Aluminum PBU CustPaidPole 3 476 1,428 $65.30 $196 1213641 100 9,500 UG_Aluminum T&C CustPaidPole 31 476 14,756 $50.49 $1,565 1213651 100 9,500 UG_Aluminum PMA CustPaidPole 18 476 8,568 $69.30 $1,247 1213711 100 9,500 UG_WoodLitg StLt CustPaidPole 29 476 13,804 $60.35 $1,750 1213811 100 9,500 URD_LamWood StLt CustPaidPole 41 476 19,516 $55.53 $2,277 1213940 100 9,500 URD_WoodPost T&C 3 476 1,428 $118.61 $356 1213941 100 9,500 URD_WoodPost T&C CustPaidPole 279 476 132,804 $50.49 $14,087 1763110 150 16,000 OH_WoodLine StLt 125 692 86,500 $56.20 $7,025 1763120 150 16,000 OH_WoodLine FldLt 90 692 62,280 $69.53 $6,258 1763211 150 16,000 OH_WoodLitg StLt CustPaidPole 10 692 6,920 $56.20 $562 1763220 150 16,000 OH_WoodLitg FldLt 2 692 1,384 $142.11 $284 1763221 150 16,000 OH_WoodLitg FldLt CustPaidPole 2 692 1,384 $69.53 $139 1763610 150 16,000 UG_Aluminum StLt 37 692 25,604 $216.49 $8,010 1763611 150 16,000 UG_Aluminum StLt CustPaidPole 2 692 1,384 $68.22 $136 1763614 150 16,000 UG_Aluminum StLt AddlFixt 15 692 10,380 $68.22 $1,023 3243110 250 25,000 OH_WoodLine StLt 2,129 1,274 2,712,34 $76.33 $162,507 3243120 250 25,000 OH_WoodLine FldLt 1,030 1,274 1,312,22 $83.44 $85,943 3243124 250 25,000 OH_WoodLine FldLt AddlFixt 1 1,274 1,274 $83.44 $83 3243210 250 25,000 OH_WoodLitg StLt 1 1,274 1,274 $148.91 $149 3243211 250 25,000 OH_WoodLitg StLt CustPaidPole 46 1,274 58,604 $76.33 $3,511 New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Workpaper TMB-1, Revised Page 24 of 25 MECO MECO MECO Increase MECO Annual Total MECO Annual (Decrease) in MECO Lumen 12/98 kWh Annual Annual Distribu Distribution Code Size Type Quantity per Light kWh Price Revenue Revenue 83 4,000 Post Top 118 248 29,264 $61.22 $7,224 $1,849 71 5,800 StLt 146 349 50,954 $67.52 $9,858 ($2,867) 83 4,000 Post Top 3 248 744 $61.22 $184 $47 71 5,800 StLt 7 349 2,443 $67.52 $473 $76 71 5,800 StLt 199 349 69,451 $67.52 $13,436 $3,156 83 4,000 Post Top 222 248 55,056 $61.22 $13,591 $3,479 72 9,600 StLt 7,510 490 3,679,900 $71.23 $534,937 $151,552 72 9,600 StLt 357 490 174,930 $71.23 $25,429 $5,444 72 9,600 StLt 88 490 43,120 $71.23 $6,268 $1,776 72 9,600 StLt 1 490 490 $71.23 $71 ($57) P wood pole $41.90 $42 $42 72 9,600 StLt 39 490 19,110 $71.23 $2,778 $595 79 9,600 Post Top 46 490 22,540 $65.50 $3,013 $690 72 9,600 StLt 4 490 1,960 $71.23 $285 ($480) 72 9,600 StLt 28 490 13,720 $71.23 $1,994 ($802) 72 9,600 StLt 29 490 14,210 $71.23 $2,066 ($4,063) T metal w/foundation $128.30 $3,721 $3,721 72 9,600 StLt 3 490 1,470 $71.23 $214 $18 79 9,600 Post Top 31 490 15,190 $65.50 $2,031 $465 79 9,600 Post Top 18 490 8,820 $65.50 $1,179 ($68) 72 9,600 StLt 29 490 14,210 $71.23 $2,066 $316 72 9,600 StLt 41 490 20,090 $71.23 $2,920 $644 79 9,600 Post Top 3 490 1,470 $65.50 $197 ($159) R fiberglass w/o base $49.36 $148 $148 79 9,600 Post Top 279 490 136,710 $65.50 $18,275 $4,188 73 16,000 StLt 125 714 89,250 $75.78 $9,473 $2,448 77 27,500 Flood 90 1,255 112,950 $143.82 $12,944 $6,686 73 16,000 StLt 10 714 7,140 $75.78 $758 $196 77 27,500 Flood 2 1,255 2,510 $143.82 $288 $3 P wood pole $41.90 $84 $84 77 27,500 Flood 2 1,255 2,510 $143.82 $288 $149 73 16,000 StLt 37 714 26,418 $75.78 $2,804 ($5,206) T metal w/foundation $128.30 $4,747 $4,747 73 16,000 StLt 2 714 1,428 $75.78 $152 $15 73 16,000 StLt 15 714 10,710 $75.78 $1,137 $113 74 27,500 StLt 2,129 1,284 2,733,636 $94.06 $200,254 $37,747 77 27,500 Flood 1,030 1,255 1,292,650 $143.82 $148,135 $62,191 77 27,500 Flood 1 1,255 1,255 $143.82 $144 $60 74 27,500 StLt 1 1,284 1,284 $94.06 $94 ($55) P wood pole $41.90 $42 $42 74 27,500 StLt 46 1,284 59,064 $94.06 $4,327 $816 C:\eua files on disk\wptmb-1.WK4 15-Jun-99 Massachusetts Electric Company Eastern Edison Company Streetlight Revenue Analysis EEC EEC EEC EEC EEC Annual Total EEC Annual Lighting Lumen Service Special 12/98 kWh Annual Annual Distribution Code Wattage Size & Pole Type Pricing Quantity per Light kWh Price Revenue ------- ------- ------ ----------- ---- ------- -------- --------- ------ ------- ------------ 3243220 250 25,000 OH_WoodLitg FldLt 1 1,274 1,274 $156.02 $156 3243221 250 25,000 OH_WoodLitg FldLt CustPaidPole 85 1,274 108,290 $83.44 $7,092 3243610 250 25,000 UG_Aluminum StLt 681 1,274 867,594 $236.61 $161,131 3243611 250 25,000 UG_Aluminum StLt CustPaidPole 9 1,274 11,466 $88.36 $795 3243621 250 25,000 UG_Aluminum FldLt CustPaidPole 1 1,274 1,274 $98.82 $99 3243624 250 25,000 UG_Aluminum FldLt AddlFixt 10 1,274 12,740 $98.82 $988 3243711 250 25,000 UG_WoodLitg StLt CustPaidPole 1 1,274 1,274 $85.64 $86 5003110 400 50,000 OH_WoodLine StLt 581 1,966 1,142,246 $97.42 $56,601 5003120 400 50,000 OH_WoodLine FldLt 4,258 1,966 8,371,228 $105.45 $449,006 5003124 400 50,000 OH_WoodLine FldLt AddlFixt 2 1,966 3,932 $105.45 $211 5003210 400 50,000 OH_WoodLitg StLt 2 1,966 3,932 $170.00 $340 5003211 400 50,000 OH_WoodLitg StLt CustPaidPole 67 1,966 131,722 $97.42 $6,527 5003220 400 50,000 OH_WoodLitg FldLt 48 1,966 94,368 $178.03 $8,545 5003221 400 50,000 OH_WoodLitg FldLt CustPaidPole 426 1,966 837,516 $105.45 $44,922 5003224 400 50,000 OH_WoodLitg FldLt AddlFixt 1 1,966 1,966 $105.45 $105 5003610 400 50,000 UG_Aluminum StLt 99 1,966 194,63 $257.70 $25,512 5003614 400 50,000 UG_Aluminum StLt AddlFixt 6 1,966 11,796 $109.45 $657 5003620 400 50,000 UG_Aluminum FldLt 28 1,966 55,048 $269.09 $7,535 5003621 400 50,000 UG_Aluminum FldLt CustPaidPole 10 1,966 19,660 $120.81 $1,208 5003624 400 50,000 UG_Aluminum FldLt AddlFixt 111 1,966 218,226 $120.81 $13,410 5003721 400 50,000 UG_WoodLitg FldLt CustPaidPole 1 1,966 1,966 $114.77 $115 6483612 500 25,000 UG_Aluminum StLt TwinFixts 61 2,548 155,428 $330.50 $20,161 --- ------- ------- Total Sodium Vapor 38,238 26,758,978 $2,458,340 - ----------------------------------------------------------------------------------------------------------------------------- TOTAL STREETLIGHT DISTRIBUTION REVENUE 39,211 27,949,484 $2,538,661 - -------------------------------------- Year 2001 Estimated Rates --------- TRANSMISSION 27,949,484 $0.00291 $81,333 - ------------ TRANSITION 27,949,484 $0.02300 $642,838 - ---------- DSM AND RENEWABLES 27,949,484 $0.00370 $103,413 - ------------------ STANDARD SERVICE 27,949,484 $0.03800 $1,062,080 - ---------------- ---------- TOTAL STREETLIGHT REVENUE $4,428,326 - ------------------------- ========== New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-__ Workpaper TMB-1, Revised Page 25 of 25 MECO MECO MECO Increase MECO Annual Total MECO Annual (Decrease) in MECO Lumen 12/98 kWh Annual Annual Distribution Distribution Code Size Type Quantity per Light kWh Price Revenue Revenue ------ ----- ----- -------- --------- ------ ------- ------------ ------------- 77 27,500 Flood 1 1,255 1,255 $143.82 $144 ($12) P wood pole $41.90 $42 $42 77 27,500 Flood 85 1,255 106,675 $143.82 $12,225 $5,132 74 27,500 StLt 681 1,284 874,404 $94.06 $64,055 ($97,077) T metal w/foundation $128.30 $87,372 $87,372 74 27,500 StLt 9 1,284 11,556 $94.06 $847 $51 77 27,500 Flood 1 1,255 1,255 $143.82 $144 $45 77 27,500 Flood 10 1,255 12,550 $143.82 $1,438 $450 74 27,500 StLt 1 1,284 1,284 $94.06 $94 $8 75 50,000 StLt 581 1,968 1,143,408 $130.65 $75,908 $19,307 78 50,000 Flood 4,258 1,968 8,379,744 $163.80 $697,460 $248,454 78 50,000 Flood 2 1,968 3,936 $163.80 $328 $117 75 50,000 StLt 2 1,968 3,936 $130.65 $261 ($79) P wood pole $41.90 $84 $84 75 50,000 StLt 67 1,968 131,856 $130.65 $8,754 $2,226 78 50,000 Flood 48 1,968 94,464 $163.80 $7,862 ($683) P wood pole $41.90 $2,011 $2,011 78 50,000 Flood 426 1,968 838,368 $163.80 $69,779 $24,857 78 50,000 Flood 1 1,968 1,968 $163.80 $164 $58 75 50,000 StLt 99 1,968 194,832 $130.65 $12,934 ($12,578) T metal w/foundation $128.30 $12,702 $12,702 75 50,000 StLt 6 1,968 11,808 $130.65 $784 $127 78 50,000 Flood 28 1,968 55,104 $163.80 $4,586 ($2,948) T metal w/foundation $128.30 $3,592 $3,592 78 50,000 Flood 10 1,968 19,680 $163.80 $1,638 $430 78 50,000 Flood 111 1,968 218,448 $163.80 $18,182 $4,772 78 50,000 Flood 1 1,968 1,968 $163.80 $164 $49 74 27,500 StLt 122 1,284 156,648 $94.06 $11,475 ($8,685) T metal w/foundation $128.30 $7,826 $7,826 38,299 27,287,893 $3,376,806 $918,466 - --------------------------------------------------------------------------------------------------- 39,272 28,540,761 $3,454,923 $916,262 difference due to twin 25,000 lumen streetlights doubled under MECO's rate structure Year 2001 Consolidated Rates ------------ 28,540,761 $0.00482 $137,566 $56,233 28,540,761 $0.01250 $356,760 ($286,079) 28,540,761 $0.00370 $105,601 $2,188 28,540,761 $0.03800 $1,084,549 $22,469 ---------- ------- $5,139,399 $711,073 ========== ========
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Workpaper TMB-2 Eastern Edison Company Estimated Retail Transmission Rate in Year 2001
S:\RADATA1\EASTED\2001\Eectrana.wk4 New England Electric System EEC TRANSM Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Workpaper TMB-2, Revised Page 1 of 1 Eastern Edison Company Calendar Year 2001 Estimated Montaup Stand-Alone Transmission Charge Calculation (1) Projected 1999 Transmission Cost to Serve Eastern Customers from Montaup $5,440,383 (2) Projected 1999 Transmission Cost to Serve Eastern Customers from NEPOOL $2,136,194 ---------- (3) Total Projected 1999 Transmission Cost to Serve Eastern Customers $7,576,577 2000 2001 ---- ---- (4) Adjusted for 2.2% Inflation $7,743,262 $7,913,613 (5) Total Eastern kWh Sales 2,711,961,115 2,711,961,115 -------------- (6) Estimated Annual Average Transmission Rate to Retail Customers $0.00285 $0.00291 ========= ======== (1) Per FERC Section 205 Filing, Exhibit__(PAV-4), Statement BH, Schedule 1, Page 3 of 3 (2) Estimate of NEPOOL transmission expenses (3) Line (1) + Line (2) (4) Line (3) x 1.022% per year (5) Actual 1998 kWh sales (6) Line (4) / Line (5), truncated after 5 decimal places
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Workpaper TMB-3 Massachusetts Electric Company Consolidated Retail Transmission Rates Assuming Rate Consolidation on January 1, 2001
S:\RADATA1\EASTED\2001\Tran-01a.wk4 Massachusetts Electric Company COMBINED TRANSM Eastern Edison Company M.D.T.E. Docket No. Workpaper TMB-3, Revised Page 1 of 3 Massachusetts Electric Company Nantucket Electric Company Eastern Edison Company Calendar Year 2001 Combined Transmission Charge Calculation Total R-1/R-2/E R-4 G-1 G-2 G-3 Streetlights ----- --------- --- --- --- --- ----------- (1) 1999 Estimate of Combined Transmission $99,174,277 (2) Inflated Transmission Expense to 2001 $103,585,946 ------------------------------------------------------------------------------------------------------------------------- (3) Combined Coincident Peak with NEP's Peak (KW) 35,627,600 14,218,120 102,837 3,760,755 5,050,497 12,275,322 220,068 (4) Coincident Peak Allocator 100.00% 39.91% 0.29% 10.56% 14.18% 34.45% 0.62% ------------------------------------------------------------------------------------------------------------------------- (5) Allocated Combined Transmission Expense $103,585,946 $41,338,666 $298,995 $10,934,258 $14,684,136 $35,690,049 $639,841 (6) Forecasted kWh Sales 19,958,898,115 7,231,927,275 58,543,000 1,922,930,824 2,859,452,245 7,753,477,287 132,567,484 (7) Combined Transmission Charge per kWh $0.00518 $0.00571 $0.00510 $0.00568 $0.00513 $0.00460 $0.00482 (1) FERC Section 205 Filing, Exhibit__ (PAV-4), Statements BG & BH, plus estimate of NEPOOL transmission costs for 1999 (2) Line (1) x 1.022% for 2 years (3) Page 2 of 3 (4) Line (3) as a percent of total Line (3) (5) Line (3) x Line (4) (6) Page 3 of 3 S:\RADATA1\EASTED\2001\Tran-01a.wk4 Massachusetts Electric Company PEAK Eastern Edison Company M.D.T.E. Docket No. Workpaper TMB-3, Revised Page 2 of 3 Massachusetts Electric Company 1997 Coincident Peak Data Total R-1/R-2/E R-4 G-1 G-2 G-3 Streetlights Total Mass. Electric (including Nantucket) 30,289,338 11,907,601 102,837 2,899,941 4,244,281 10,964,364 170,313 Eastern in Mass. Electric Rate Structure 5,338,262 2,310,519 0 860,814 806,216 1,310,958 49,755 ---------- ---------- ------- --------- --------- --------- -------- Total 35,627,600 14,218,120 102,837 3,760,755 5,050,497 12,275,322 220,068 ========== ========== ======= ========= ========= ========== ======= Source: Company Load Data for 1997 Eastern Load Data allocated to Mass. Electric rate structure based on mapping of retail billing determinants S:\RADATA1\EASTED\2001\Tran-01a.wk4 Massachusetts Electric Company KWH Eastern Edison Company M.D.T.E. Docket No. Workpaper TMB-3, Revised Page 3 of 3 Massachusetts Electric Company Nantucket Electric Company Eastern Edison Company Forecasted kWh Sales Total R-1/R-2/E R-4 G-1 G-2 G-3 Streetlights (1) Mass. Electric 17,246,937,000 6,147,502,000 58,543,000 1,565,201,000 2,408,497,000 6,962,576,000 104,618,000 (incl. Nantucket Electric) (2) Eastern Edison 2,711,961,115 1,084,425,275 0 357,729,824 450,955,245 790,901,287 27,949,484 ------------- ------------- - ----------- ----------- ----------- ---------- (3) Total 19,958,898,115 7,231,927,275 58,543,000 1,922,930,824 2,859,452,245 7,753,477,287 132,567,484 ============== ============= ========== ============= ============= ============= =========== (1) Company Forecast for Calendar Year 2000 (2) Actual 1998 kWh Sales Mapped to Mass. Electric rate classes (3) Line (1) + Line (2)
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Workpaper TMB-4 Massachusetts Electric Company Estimated Combined Transition Charge in Year 2001
S:\RADATA1\EASTED\2001\Mecoctc.wk4 Massachusetts Electric Company CTC ESTIMATE Eastern Edison Company 15-Jun-99 M.D.T.E. Docket No. Workpaper TMB-4 Page 1 of 1 Massachusetts Electric Company Eastern Edison Company Combined Contract Termination Charge 2001 2002 2003 2004 ---- ---- ---- ---- (1) Mass. Electric's Share of Contract Termination Charge $184,000 $186,000 $175,000 $169,000 (2) Eastern Edisons's Share of Contract Termination Charge $64,404 $62,925 $52,943 $49,617 ------- ------- ------- ------- (3) Total Combined Contract Termination Charge $248,404 $248,925 $227,943 $218,617 ------------------------------------------------------------------------------ (4) Estimated Mass. Electric GWh Deliveries 17,131 17,349 17,603 17,917 (5) Estimated Eastern Edison GWh Deliveries 2,803 2,835 2,878 2,928 ----- ----- ----- ----- (6) Total Combined GWh Deliveries 19,934 20,184 20,481 20,845 ------------------------------------------------------------------------------ (7) Combined CTC 1.25 1.23 1.11 1.05
(1) Ex. 3, Schedule 1 of NEP's December 1, 1998 CTC Reconciliation (2) Ex. 3, Schedule 1 of NEP's December 1, 1998 CTC Reconciliation (3) Line (1) + Line (2) (4) Ex. MEC-DTS-6-EEC, Schedule 1 of Montaup's February 12, 1999 CTC Filing (5) Ex. MEC-DTS-6-EEC, Schedule 1 of Montaup's February 12, 1999 CTC Filing (6) Line (4) + Line (5) (7) Line (3) / Line (6) New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Workpaper TMB-5 Eastern Edison Company Estimated Transition Charges in Year 2001 S:\RADATA1\EASTED\2001\Eecctc1.wk4 New England Electric System EEC CTC Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-__ Workpaper TMB-5 Page 1 of 1 Eastern Edison Company Calendar Year 2001 Estimated Stand-Alone Transition Charge Calculation (1) Year 2001 CTC per Divestiture Filing $0.02300 (2) CTC for Remainder of 1999 $0.02100 (3) Ratio 109.524% Current Transition Estimated Transition Charge Ratio Charge (4) (5) (6) R-1, R-2, R-3, G-1, H-1, H-2, W-1, S-1 all kWh $0.02100 109.524% $0.02300 R-4 on peak kwh $0.09952 109.524% $0.10899 off peak kw $0.00797 109.524% $0.00872 G-2 all KW $5.55 109.524% $6.07 all kWh $0.00181 109.524% $0.00198 G-4 all KW $5.52 109.524% $6.04 on peak kwh $0.01235 109.524% $0.01352 off peak kw $0.00676 109.524% $0.00740 G-5 all KW $4.37 109.524% $4.78 on peak kwh $0.01204 109.524% $0.01318 off peak kw $0.00700 109.524% $0.00766 G-6 all KW $4.37 109.524% $4.78 on peak kwh $0.01533 109.524% $0.01679 off peak kw $0.01029 109.524% $0.01127 T-2 all KW $5.75 109.524% $6.29 on peak kwh $0.01403 109.524% $0.01536 off peak kw $0.00843 109.524% $0.00923 A-6 KW $4.46 109.524% $4.88 on peak kwh $0.00997 109.524% $0.01091 off peak kw $0.00493 109.524% $0.00539 (1) Per February 12, 1999 Divestiture Filing (2) Currently Effective Transition Charge (3) Line (1) / Line (2) (4) Per Currently Effective Tariffs (5) Line (3) (6) Line (4) x Line (5), truncated after 2 or 5 decimal places, depending upon charge COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF JAMES J. BONNER, Jr. COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY - ----------------------------------- ) New England Electric System ) Docket D.T.E. 99-___ Eastern Utilities Associates ) ) - ----------------------------------- DIRECT TESTIMONY OF JAMES J. BONNER, Jr. Table of Contents Page I. Introduction and Qualifications..................................... 1 II. Purpose of Testimony................................................ 3 III. Mapping of Eastern's Customers to Mass. Electric's Rates............ 4 IV. Derivation of Billing Determinants for Eastern's Customers under Mass. Electric's Rates............................. ................ 14 V. Conclusion.......................................................... 18
New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 1 of 18 1 I. Introduction and Qualifications 2 Q. Please state your full name and business address. 3 A. My name is James J. Bonner, Jr. My business address is 750 West Center Street, West 4 Bridgewater, Massachusetts. 5 6 Q. Please state your present position and responsibilities. 7 A. I am Manager of Retail Pricing and Rate Administration for EUA Service Corporation. 8 My responsibilities include the direct supervision of EUA Service Corporation's Retail 9 Pricing and Rate Administration supervisor and staff. Among the responsibilities of that 10 staff are the study, analysis, and design of retail delivery service rates for Eastern Edison 11 Company ("Eastern" or "EECo"). 12 13 Q. Please describe your educational background and work experience. 14 A. I graduated from Northeastern University in 1976 with a Bachelor of Science degree in 15 Electrical Engineering (Power Systems). I attended the Edison Electric Institute's 16 ("EEI") Rate Fundamentals Course at Indiana University in November 1985 and the EEI 17 Advanced Rate Course at Indiana University in August 1986 and in August 1988. I was 18 Chairman of the Electric Council of New England's Rate and Regulatory Committee 19 from 1993 through 1995. 20 New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 2 of 18 1 From August 1976 through February 1983, I was employed by the Belcher Division of 2 Dayton Malleable Inc., a malleable iron foundry located in Easton, Massachusetts, as 3 Plant Engineer. My duties included plant maintenance management, energy 4 management, capital budgeting, and production engineering. 5 6 In March 1983, I joined Eastern as Consumer Service Engineer for the Brockton 7 Division. In that capacity, I served as Eastern's representative for its fifty largest 8 commercial-industrial customers in the Brockton Division's service area and as a staff 9 assistant to the Consumer Service Manager. 10 11 I transferred to the Rate Department of EUA Service Corporation in February 1985 as an 12 Associate Rate Engineer. I was promoted to Rate Engineer in February 1987, to Senior 13 Rate Engineer in February 1989, to Supervisor of Rate Design in January 1991, and to 14 Manager of Retail Pricing and Rate Administration in January 1999. Since assuming the 15 position of Supervisor of Rate Design in 1991, I have supervised the preparation of 16 Eastern's retail rates approved by the Department of Telecommunications and Energy 17 ("Department") in subsequent regulatory proceedings. 18 19 Q. Have you previously testified before the Department? 20 A. Yes, I have testified before the Department on several occasions. Most recently, I New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 3 of 18 1 testified in D.P.U./D.T.E. 96-100, Electric Industry Restructuring, as part of the 2 Basic/Universal Service panel in June 1996, and I testified in support of Eastern's 3 proposed rates in D.P.U. 92-148, Eastern's last general rate case, in September 1992. 4 5 Q. Were the schedules attached to your direct testimony prepared by you or under your 6 supervision and direction? 7 A. Yes, they were. 8 9 II. Purpose of Testimony 10 Q. What is the purpose of your testimony? 11 A. The purpose of my testimony is to present and support the mapping of Eastern's customers 12 under Eastern's retail delivery service rates to Massachusetts Electric 13 Company's ("Mass. Electric's") retail delivery service rates and the derivation of the 14 billing determinants for Eastern's customers mapped to Mass. Electric's rates. Ms. Burns 15 makes use of this mapping and these billing determinants in her testimony and exhibits 16 regarding the proposed Mass. Electric/Eastern merger rate plan and its impact on revenue. 17 18 Q. Please explain how you have organized your testimony. 19 A. My testimony is organized as follows: (1) An explanation of the mapping process 20 that we used to align the schedule of rates between Eastern and Mass. Electric, and (2) an New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 4 of 18 1 explanation of the derivation of the billing determinants used for transferring Eastern's 2 customers to Mass. Electric's rates. 3 4 III. Mapping of Eastern's Customers to Mass. Electric's Rates 5 Q. Please describe how Eastern's customers were mapped to Mass. Electric's retail delivery 6 service rates. 7 A. A mapping of Eastern's retail delivery service rates to Mass. Electric's retail delivery 8 service rates was performed by comparing the availability provisions between Eastern's 9 rates and Mass. Electric's rates. Exhibit JJB-1 demonstrates this comparing of rates. This 10 exhibit shows a comparison of the availability provisions of Eastern's and Mass. 11 Electric's rates. A summary of the mapping of Eastern's rates to Mass. Electric's is 12 provided by Ms. Burns in her Exhibit TMB-3. 13 14 Although Eastern's schedule of rates is comparable to Mass. Electric's schedule of rates, 15 Eastern's applicability and rate structures are not identical to those of Mass. Electric's 16 schedule of rates. Eastern has, in some customer classes, more available rates than Mass. 17 Electric. Eastern uses different billing determinant breakpoints to subdivide its general 18 service (commercial-industrial) customer class into several rates. Eastern uses fewer 19 optional rates than does Mass. Electric. And Eastern makes use of supplementary1 rates, - --------------- 1 A supplementary rate is a rate that is available only to customers who also receive part of their electric service under another rate, called a principal rate. A principal rate can be the only rate New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 5 of 18 1 whereas Mass. Electric does not. 2 3 Q. How were the determinants necessary for developing the rate mapping proposal 4 developed? 5 A. EECo based the mapping of Eastern's rates to Mass. Electric's rates on its customer 6 billing information for calendar year 1998. For each of Eastern's rate classes, the number 7 of bills rendered and annual energy consumption were determined. Where required for 8 certain rate classes, monthly billing demands and annual peak and off-peak energy 9 consumption were determined. In many cases, especially for those current Eastern rate 10 classes that were subdivided into two or more Mass. Electric rate classes, these 11 determinants were required to be developed on a customer-by-customer basis and 12 transformed from Eastern's definition of a determinant--e.g., billing demand--to Mass. 13 Electric's definition of the same determinant. 14 15 Q. Please describe Eastern's Schedule of Rates. 16 A. Eastern's Schedule of Rates consists of four (4) residential rates, 17 Residential Retail Delivery Service Rate R-1 - --------------- under which a customer receives service at a given location, but a supplementary rate cannot. For example, Eastern's Controlled Water Heating Service Rate W-1 is a supplementary rate. To be eligible for Rate W-1, a customer must also receive service under one or more of Eastern's residential or general service rates at the same service location. New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 6 of 18 Low Income Residential Retail Delivery Service Rate R-2 Residential Space Heating Retail Delivery Service Rate R-3 TOU Residential Retail Delivery Service Rate R-4 seven (7) general service rates, Small Secondary Voltage General Retail Delivery Service Rate G-1 Medium Secondary Voltage General Retail Delivery Service Rate G-2 Large Secondary Voltage General Retail Delivery Service Rate G-4 Medium Primary Voltage General Retail Delivery Service Rate G-5 Large Primary Voltage General Retail Delivery Service Rate G-6 Medium TOU Secondary Voltage General Retail Delivery Service Rate T-2 Large Pri. Voltage Auxiliary General Retail Delivery Service Rate A-6 General Space Heating Retail Delivery Service Rate H-1 two (2) supplementary rates, General Heating Retail Delivery Service Rate H-2 Controlled Water Heating Retail Delivery Service Rate W-1 and a lighting service rate, Lighting Retail Delivery Service Rate S-1. In addition to the foregoing, Eastern's Schedule of Rates contains the following terms and conditions, adjustment clauses, generation services, and rate riders: New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 7 of 18 Terms and Conditions for Distribution Service Terms and Conditions for Competitive Suppliers Transition Cost Adjustment Clause Standard Offer Service Demand Side Management Clause Renewable Energy Clause Farm Discount Rate Rider Interim Default Service Q. Please describe Mass. Electric's Schedule of Rates. A. Mass. Electric's Schedule of Rates consists of three (3) residential rates, Residential Regular R-1 Retail Delivery Service Residential Low Income R-2 Retail Delivery Service Residential - Time-of-Use (Optional) R-4 Retail Delivery Service four (4) general service rates, General Service - Small Commercial & Industrial G-1 Retail Delivery Service General Service - Demand G-2 Retail Delivery Service Time-of-Use G-3 Retail Delivery Service Experimental Flexible Time-Of-Use Pricing (G-5) one (1) interruptible rate, New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 8 of 18 Scheduled Interruptible Service Rate I-1 and four (4) lighting service rates, Street & Security Lighting - Co. Owned Equipment S-1 Retail Delivery Service Street Lighting - Overhead - Cust.-Owned Equipment S-2 Retail Delivery Service Street Lighting - Underground - Div. Of Ownership S-3 Retail Delivery Service Street Lighting - Company Owned Equipment S-20 Retail Delivery Service Street Lighting - Customer Owned Equipment S-5 Retail Delivery Service2 In addition to the foregoing, Mass. Electric's Schedule of Rates contains the following terms and conditions, adjustment provisions, generation service tariffs, and interruptible service provisions: Terms and Conditions for Distribution Service Terms and Conditions for Competitive Suppliers Transmission Service Cost Adjustment Provision Transition Cost Adjustment Provision Demand Side Management Provision Renewables Provision Standard Service Cost Adjustment Provision Default Service Adjustment Provision - --------------- 2 Currently pending approval in M.D.T.E. Docket No. 98.69. New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 9 of 18 1 Tariff for Standard Service 2 Tariff for Default Service 3 Cooperative Interruptible Service Provisions For I-3 4 Cooperative Interruptible Service Provisions For I-4 5 Cooperative Interruptible Service Provisions For I-5 6 7 Q. How are Eastern's residential rates mapped to Mass. Electric's residential rates? 8 A. Eastern's residential rates are available only to residential customers for domestic 9 purposes. Rate R-1 is the ordinary residential retail delivery service rate, Rate R-2 is 10 restricted to low-income customers, Rate R-3 is available only to electric space heating 11 customers, and Rate R-4 is Eastern's optional time-of-use rate. 12 13 Like Eastern, Mass. Electric's residential rates are available to residential customers for 14 domestic purposes. Rate R-1 is Mass. Electric's ordinary residential retail delivery 15 service rate, Rate R-2 is restricted to low-income customers, and Rate R-4 is Mass. 16 Electric's optional time-of-use rate. 17 18 As shown on Exhibit TMB-3, Eastern's Rates R-1, R-3, and R-4 are mapped to Mass. 19 Electric's Rate R-1. Eastern's Low Income Residential Rate R-2 is mapped to Mass. 20 Electric's Residential Low Income Rate R-2. New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 10 of 18 1 Q. Why was Eastern's time-of-use residential service rate, Rate R-4, mapped to Mass. 2 Electric's regular residential service rate, Rate R-1, instead of Mass. Electric's time-of- 3 use residential service rate, Rate R-4? 4 A. None of Eastern's current Rate R-4 customers meet Mass. Electric's Rate R-4's minimum 5 energy usage eligibility requirement of an average of 2,500 kWh/month and 30,000 6 kWh/year; therefore, Eastern's Rate R-4 customers are mapped to Mass. Electric's Rate 7 R-1. 8 9 Q. How are Eastern's general service rates mapped to Mass. Electric's general service rates? 10 A. Eastern's general service rates are open to all customers, including residential customers, 11 provided a customer otherwise meets the availability and/or the applicability provisions 12 of the rate. 13 14 Eastern's "G" series rates form the main sequence of Eastern's general service tariffs. 15 The "G" series rates are divided into two groups: (1) Secondary distribution voltage 16 rates--Rates G-1, G-2, and G-4, and (2) primary distribution voltage rates--Rates G-5 17 and G-6. The availability of the secondary voltage rates is as follows: Rate G-1 is 18 available to customers whose monthly demand is less than 10 kW and whose average 19 monthly energy consumption is less than 3,000 kWh. Rate G-2 is available to customers 20 whose monthly demand is at least 10 kW but less than 500 kW or whose average monthly New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 11 of 18 1 energy consumption is 3,000 kWh or more. Rate G-4 is required for customers whose 2 monthly demand is 500 kW or more. For general service customers served at primary 3 voltage, Rate G-5 is required if a customer's monthly demand is less than 500 kW; 4 otherwise Rate G-6 applies. 5 6 The remaining Eastern general service rates are as follows: Eastern's Rate T-2 is an 7 optional time-of-use rate available to Rate G-2 customers. Rate A-6 is Eastern's large 8 primary distribution voltage auxiliary3 service rate and is closed to new customers. Rate 9 H-1 is available only to certain non-residential electric space heating customers. 10 11 Mass. Electric's general service rates are considerably simpler than Eastern's. Mass. 12 Electric's has four general service rates (Rates G-1, G-2, G-3, and G-5) which apply to 13 customers as follows: Rate G-1 is available to customers whose monthly demand is 200 14 kW or less and whose average monthly energy consumption is 10,000 kWh or less. Rate 15 G-2 is available to customers whose monthly demand is 200 kW or less and whose 16 average monthly energy consumption is more than 10,000 kWh. Rate G-3 is available to 17 customers whose monthly demand is more than 200 kW. Rate G-5 is an experimental --------------- 1 3 Auxiliary service is one or more of the following services: supplementary power, backup 2 power, and maintenance power. Eastern provides auxiliary service to customers who self- 3 generate all or part of their electric service requirements and whose generation facilities are 4 Qualifying Facilities pursuant to 220 CMR 8.00 et seq. New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 12 of 18 1 rate with a "real-time pricing"-like structure. It has been closed to new customers since 2 1997. 3 4 As shown in Exhibit TMB-3, Eastern's Rate G-1 was mapped to Mass. Electric's Rate G- 5 1. Eastern's Rates G-2 and T-2 were mapped to Mass. Electric's Rates G-1, G-2, and G- 6 3. Eastern's Rate G-4 was mapped Mass. Electric's Rate G-3. Eastern's Rate G-5 was 7 mapped to Mass. Electric's Rates G-2 and G-3. Eastern's Rate G-6 was mapped to Mass. 8 Electric's Rate G-3. Eastern's Rate H-1 was mapped to Mass. Electric's Rates G-1, G-2, 9 and G-3. 10 11 Q. How is Eastern's auxiliary service Rate A-6 mapped to Mass. Electric's rates? 12 A. Mass. Electric does not have an auxiliary service rate. Eastern's sole Rate A-6 customer 13 is transferred to Mass. Electric Rate G-3, which is the rate closest to Eastern's Rate A-6, 14 and will receive auxiliary service under Mass. Electric's current auxiliary service 15 provision. 16 17 Q. How are Eastern's supplementary service rates mapped to Mass. Electric's rates? 18 A. In general, customers receiving service under Eastern's supplementary rates, Rates H-2 19 and W-1, are first matched with their companion principal rate, then mapped to the Mass. 20 Electric rate which corresponds to the companion principal rate. Thus, the residential New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 13 of 18 1 portion of Eastern's Rate W-1 is mapped to Mass. Electric's Rate R-1, and the 2 non-residential portion of Eastern's Rate W-1 is mapped to Mass. Electric's Rate G-1. 3 Eastern's Rate H-2 is mapped to two of Mass. Electric's rates: Rates G-1 and G-2. 4 5 Q. Are any of Eastern's customers transferred to Mass. Electric's interruptible service rates 6 or are any of Mass. Electric's interruptible service provisions applied? 7 A. No. Eastern does not have any interruptible service customers currently, nor does Eastern 8 have any rates or rate riders applicable to such service. Moreover, all of the foregoing 9 Mass. Electric rates and provisions are closed to new customers. 10 11 Q. How is Eastern's lighting service rate mapped to Mass. Electric's lighting service rates? 12 A. Eastern offers only one lighting service rate to its customers, Rate S-1. Eastern's Rate 13 S-1 provides customers with a wide choice of lighting fixtures (streetlights, floodlights, 14 and area lights) mounted on distribution or specialty lighting poles served from overhead 15 or underground conductors. All lighting equipment (luminaires, poles, conductors, etc.) 16 required to provide service under Rate S-1 is furnished, installed, owned, and maintained 17 by Eastern. For certain fixture-pole combinations, Eastern permits customers to pay the 18 initial cost of installation by a contribution in aid of construction to obtain a lower 19 monthly rate. 20 New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 14 of 18 1 Mass. Electric provides a broader selection of lighting services than does Eastern. Mass. 2 Electric offers four lighting service rates to its customers: Rates S-1, S-2, S-3, and S-20. 3 Rate S-1 is similar in its applicability to Eastern's Rate S-1. Rates S-2 and S-3 provide 4 for partial or full ownership of lighting equipment by customers. Rate S-20 is a special 5 rate for customers seeking to convert their existing incandescent and mercury vapor lights 6 to sodium vapor lights. Mass. Electric also has currently pending before the Department 7 Rate S-5 for municipal customers choosing to purchase streetlighting equipment from 8 Mass. Electric pursuant to Section 34A of the Electric Utility Restructuring Act of 1997. 9 10 Eastern's Rate S-1 is mapped to Mass. Electric's Rate S-1 because of the similarity in 11 their applicability provisions. 12 13 IV. Derivation of Billing Determinants for Eastern's Customers under Mass. Electric's 14 Rates 15 Q. Please summarize how billing determinants for Eastern's customers under Mass. 16 Electric's rates are derived. 17 A. Billing determinants are customer usage parameters that are applied to the component 18 charges of a rate schedule to calculate a customer's bill. Examples of commonly used 19 billing determinants are the number of bills, monthly energy consumption, and monthly 20 maximum demand. The precise definition of a billing determinant is dependent upon the New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 15 of 18 1 rate to which it is applied. Consequently, the derivation of billing determinants for a 2 customer depends upon which rate the customer is currently served as well as the rate 3 which the customer is to be transferred. 4 5 In some cases, the billing determinants for Eastern's customers under Mass. Electric's 6 rates are the same determinants Eastern uses to bill these same customers under its rates. 7 This is exactly the case for Eastern's customers served under Rates R-1, R-2, R-3, R-4, 8 G-1, W-1, and S-1 that will be transferred to Mass. Electric's Rates R-1, R-2, G-1, and S- 9 1. 10 11 In all other cases, the billing determinants for Eastern's customers under Mass. Electric's 12 rates must be calculated or estimated, at least for some of the customers being transferred 13 from a particular Eastern rate to a particular Mass. Electric rate. All of Eastern's 14 customers served under its general service rates and all of Eastern's customers served 15 under its supplementary rates require the calculation or estimation of billing determinants 16 under Mass. Electric's rates. 17 18 Exhibit JJB-2 shows the billing determinants for each Eastern to Mass. Electric rate 19 mapping. Each mapping is shown on a separate page, and, where appropriate, 20 explanatory notes detailing how the billing determinants were derived is included on the New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 16 of 18 1 page. 2 3 Q. Why is it necessary to estimate billing determinants for some customers? 4 A. It is necessary to estimate billing determinants for customers where Eastern's definition 5 of a billing determinant is different from that of Mass. Electric's and/or Eastern does not 6 record, or does not have readily available, the data required to calculate the determinant. 7 The determinants estimated are billing demands and time-differentiated energy 8 consumption. For example, Eastern's Rate H-1 non-demand metered customers 9 transferring to Mass. Electric's Rate G-2 require the estimation of billing demands. A 10 second example are Eastern's Rate G-6 customers transferring to Mass. Electric's Rate 11 G-3. This transfer requires the estimation of peak-hours maximum demand, peak-hours 12 energy, and off-peak-hours energy values. Exhibit JJB-2 details each instance where 13 estimated determinants are required. 14 15 Q. In general, is Eastern's definition of billing demand substantially different from Mass. 16 Electric's? 17 A. No, it is not. Both companies define demand as a fifteen-minute integrated demand, 18 define billing demand as the maximum demand over all hours for non-time-differentiated 19 rates, and define billing demand as the maximum demand within peak hours for time- 20 differentiated rates. The companies differ in the details of their definitions with respect to New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 17 of 18 1 minimum billing demand (Mass. Electric only), maximum billing demand (Eastern only), 2 and conversion of kilovolt-ampere demand to kilowatt demand (Mass. Electric only). 3 4 Q. Is Eastern's definition of time periods for its time-differentiated rates substantially 5 different from Mass. Electric's? 6 A. Yes, it is. Eastern defines it time periods as follows: 7 Peak Hours 8 Monday through Friday excluding holidays: 9 April through September, 11:00 a.m. to 4:00 p.m. 10 October through March, 8:00 a.m. to 12:00 noon, and 11 4:00 p.m. to 7:00 p.m. 12 Off-Peak Hours 13 All other hours. 14 15 Mass. Electric defines it time periods as follows: 16 Peak Hours 17 Monday through Friday excluding holidays: 18 January through December 8:00 a.m. to 9:00 p.m. 19 Off-Peak Hours 20 All other hours. New England Electric System Eastern Utilities Associates Testimony of James J. Bonner, Jr. Page 18 of 18 1 Both companies define holidays as follows: 2 New Year's Day Columbus Day 3 President's Day Veteran's Day 4 Memorial Day Thanksgiving Day 5 Independence Day Christmas Day 6 Labor Day 7 8 V. Conclusion 9 Q. Does this conclude your testimony? 10 A. Yes, it does.
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ EXHIBITS OF JAMES J. BONNER, JR. Exhibit JJB-1 Comparison of Availability Provisions of Rates Exhibit JJB-2 Billing Determinants New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit JJB-1 Comparison of Availability Provisions of Rates New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-___ Exhibit JJB-1 Page 1 of 6 MASSACHUSETTS ELECTRIC COMPANY EASTERN EDISON COMPANY Comparison of Availability Provisions of Rates EASTERN'S RATE MASS. ELECTRIC'S RATE RESIDENTIAL RETAIL DELIVERY SERVICE RESIDENTIAL REGULAR R-1 RETAIL RATE R-1 DELIVERY SERVICE Available only to residential Available for all domestic purposes customers for domestic purposes. in an individual private dwelling or an individual apartment and for church and farm purposes. LOW INCOME RESIDENTIAL RETAIL RESIDENTIAL LOW INCOME R-2 RETAIL DELIVERY SERVICE RATE R-2 DELIVERY SERVICE Available upon verification of a Available upon verification of a low-income Customer receipt of low-income Customer's receipt of any means-tested public benefit, or any means-tested public benefit, or verification of eligibility for the verification of eligibility for the low- income home energy assistance low- income home energy assistance program, or its successor program, program, or its successor program, for which eligibility does not for which eligibility does not exceed 175 percent of the federal exceed 175 percent of the federal poverty level based on a poverty level based on a household's gross income. The household's gross income. It is the customer will be required to responsibility of the customer to annually certify his or her annually certify, by forms provided continued eligibility for this Rate by the utility, the continued Schedule. compliance with the foregoing qualifications. RESIDENTIAL SPACE HEATING RETAIL DELIVERY SERVICE RATE R-3 Available only to residential customers where electricity is the sole source of energy used for comfort heating and water heating. TOU RESIDENTIAL RETAIL DELIVERY RESIDENTIAL TIME-OF-USE (OPTIONAL) SERVICE RATE R-4 R-4 RETAIL DELIVERY SERVICE Available only to residential Available for all domestic purposes customers. in an individual private dwelling or an individual apartment and for church and farm purposes. Any residential customer whose average usage exceeds 2,500 kWh/month for a 12 month period may elect delivery service under this rate effective with installation of appropriate metering. SMALL SECONDARY VOLTAGE GENERAL GENERAL SERVICE -- SMALL COMMERCIAL RETAIL DELIVERY SERVICE RATE G-1 AND INDUSTRIAL G-1 RETAIL DELIVERY SERVICE Available to customers whose actual or estimated annual maximum monthly Available for all purposes. A new demand is less than 10 kW and Customer will begin service on this annual energy consumption is less rate if the Company estimates that than 36,000 kWh. its average use will not exceed 10,000 kWh/month or 200 kW of demand. MEDIUM SECONDARY VOLTAGE GENERAL GENERAL SERVICE DEMAND G-2 RETAIL RETAIL DELIVERY SERVICE RATE G-2 DELIVERY SERVICE Available only to customers whose Available for all purposes. A new actual or estimated annual maximum customer will begin delivery on monthly demand is at least 10 kW this rate if the Company estimates but less than 500 kW or whose that its average use will exceed actual or estimated annual energy 10,000 kWh/month, but not exceed consumption is 36,000 kWh or more. 200 kW of Demand. TIME-OF-USE G-3 RETAIL DELIVERY SERVICE Available for all purposes. A new Customer will begin delivery service on this rate if the Company estimates that its average use will exceed 200 kW of Demand. LARGE SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-4 Mandatory for all customers whose actual or estimated annual maximum monthly demand is 500 kW or more. MEDIUM PRIMARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-5 Mandatory for all customers whose actual or estimated annual maximum monthly demand is at least 100 kW but less than 500 kW. LARGE PRIMARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-6 Mandatory for all customers whose actual or estimated annual maximum monthly demand is 500 kW or more. MEDIUM TOU SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE T-2 Available to all customers whose actual or estimated annual maximum monthly demand is at least 10 kW but less than 500 kW or whose actual or estimated annual energy consumption is 36,000 kWh or more. LARGE PRIMARY VOLTAGE AUXILIARY GENERAL RETAIL DELIVERY SERVICE RATE A-6 Available to any Customer of record prior to March 1, 1997, who furnishes its own electric power supply for all or part of its total electric retail delivery service requirements. EXPERIMENTAL FLEXIBLE TIME-OF-USE PRICING G-5 Not available to new customers after February 26, 1997. Customers may remain on this rate until the contract anniversary date following the date of retail access for all Customers. However, Customers choosing to leave the rate before their annual anniversary date will be required to refund any Customer base load savings achieved over the Company's U-3 Rate and/or G-3 Rate, between the termination date of service under the G-5 Rate and the previous contract anniversary date. All customers served on this rate must elect to take their total electric service under the metering installation as approved by the Company. SCHEDULED INTERRUPTIBLE SERVICE RATE I-1 This rate is closed to new customers as of February 26, 1997. Service under this rate is available only for electric equipment under the control of the Company. Electric service for all other purposes at the customer location will be provided under the applicable rate in effect and available. GENERAL SPACE HEATING RETAIL DELIVERY SERVICE RATE H-1 Available only to non-residential Customers where electricity, or electricity in conjunction with a renewable energy source, is the sole source of energy used for comfort heating and water heating. GENERAL HEATING RETAIL DELIVERY SERVICE RATE H-2 Closed to new Customers. Available to customers that were taking service under former General Heating Service Rate 35 before 1-24-89, where electricity, or electricity in conjunction with a renewable energy source, is the sole source of energy used for space heating, cooking, air conditioning or water heating for other than industrial purposes. CONTROLLED WATER HEATING RETAIL DELIVERY SERVICE RATE W-1 Closed to new Customers. Available to Customers that were taking retail delivery service from the Company under former Off-Peak Water Heating Rate 41 before 1-24-89. LIGHTING RETAIL DELIVERY SERVICE STREET AND SECURITY LIGHTING RATE S-1 COMPANY OWNED EQUIPMENT S-1 Available only to Customers where Available to any Customer where the electricity is supplied to lighting necessary fixtures can be supported equipment owned and maintained by on the Company's existing poles and the Company on Company owned poles, where such service can be supplied for dusk-to-dawn operation of directly from existing secondary approximately 4,000 burning hours voltage circuits. per year. STREET LIGHTING -OVERHEAD-CUSTOMER OWNED EQUIPMENT S-2 Available for street lighting installations owned by any city or town or other public authority, hereinafter referred to as the Customer, for street lighting installations served by overhead conductors. This rate is closed for service to new applicants or lights effective March 1, 1998. STREET LIGHTING - UNDERGROUND - DIVISION OF OWNERSHIP S-3 Available to any city, town or other public authority, hereinafter referred to as the Customer, only for street lighting installations served by underground conductors and involving a division of ownership and service. STREET LIGHTING - COMPANY OWNED EQUIPMENT S-20 Available to any Customer on Rate S-1 which agrees to convert all existing incandescent and mercury vapor source lights to sodium-vapor source lights. New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ Exhibit JJB-2 Billing Determinants S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System R-1 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 1 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Eastern's Rate R-1 v. Mass. Electric's Rate R-1 Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------ Bills 1,705,214 1,705,214 Energy (kWh) 897,383,838 897,383,838 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System R-2 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 2 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Eastern's Rate R-2 v. Mass. Electric's Rate R-2 Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - -------------------------------------------------- Bills 168,433 168,433 Energy (kWh) 67,148,463 67,148,463 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System R-3 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 3 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Eastern's Rate R-3 v. Mass. Electric's Rate R-1 Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - --------------------------------------------------- Bills 70,418 70,418 Energy (kWh) 70,618,533 70,618,533 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System R-4 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 4 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Eastern's Rate R-4 v. Mass. Electric's Rate R-1 Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - --------------------------------------------------- Bills 544 544 Energy (kWh) 577,111 577,111 Peak Energy (kWh) 82,953 n/a Off-Peak Energy (KWh) 494,158 n/a S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System G-1 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 5 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Eastern's Rate G-1 v. Mass. Electric's Rate G-1 Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------- Bills 213,705 213,705 Energy (kWh) 109,098,086 109,098,086 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System G-2 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 6 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Note: Eastern's Rate G-2: Total 1. Eastern's Rate G-2 Eastern's determinants were apportioned Billing Billing among Mass. Electric's Rates Parameter Determinant G-1, G-2 and G-3 based on the - ------------------------------- availability provisions of Bills 82,096 Mass. Electric's rates. Demand (kW) 2,850,756 Energy (kWh) 839,614,746 2. For those Eastern Rate G-2 customers to be transferred to Mass. Electric's Rate G-3, the billing determinants were estimated based upon Eastern's Rate G-2 load research data using Mass. Electric's TOU hours. Kilowatthours were split equally between peak and off peak periods. Eastern's Rate G-2 v. Mass. Electric's Rate G-1 - --------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------- Bills 61,760 61,760 Demand (kW) 1,041,483 n/a Energy (kWh) 241,828,775 241,828,775 Eastern's Rate G-2 v. Mass. Electric's Rate G-2 - ----------------------------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - -------------------------------------------------- Bills 18,542 18,542 Demand (kW) 1,300,741 1,300,741 Energy (kWh) 424,245,027 424,245,027 Eastern's Rate G-2 v. Mass. Electric's Rate G-3 - ------------------------------------------------ Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - --------------------------------------------------- Bills 1,794 1,794 Demand (kW) 508,532 513,617 Energy (kWh) 173,540,944 173,540,944 Peak Energy (kWh) n/a 86,770,472 Off-Peak Energy (kWh) n/a 86,770,472 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System G-4 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 7 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Eastern's Rate G-4 v. Mass. Note: Electric's Rate G-3 1. The billing determinants were estimated based upon Eastern's Rate G-4 load research data using Mass. Electric's TOU hours. Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------- Bills 1,097 1,097 Demand (kW) 794,802 822,620 Energy (kWh) 344,807,994 344,807,994 Peak Energy (kWh) 76,958,311 162,059,757 Off-Peak Energy (267,849,683 182,748,237 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System G-5 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 8 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Note: Eastern's Rate G-5: Total 1. Eastern's Rate G-5 billing demand is maximum monthly peak Eastern's hours demand. Mass. Electric's Billing Billing Rate G-2 billing demand is Parameter Determinant maximum monthly demand. - ------------------------------------ Eastern's Rate G-5 billing Bills 402 demand was recalculated to Demand (kW) 76,191 conform with Mass. Electric's Energy (kWh) 25,376,160 definition. Peak Energy (kWh) 6,315,790 Off-Peak Energy (kWh) 19,060,370 2. For those Eastern Rate G-5 customers to be transferred to Mass. Electric's Rate G-3, the billing determinants were estimated based upon Eastern's Rate G-5 load research data using Mass. Electric's TOU hours. Eastern's Rate G-5 v. Mass. Electric's Rate G-2 - --------------------------- Eastern's Mass. Electric 3. Eastern's Rate G-5 is a Billing Billing Billing primary distribution voltage Parameter Determinant Determinant rate. By definition, all of - ------------------------------------------ Eastern's Rate G-5 customers Bills 168 168 meet the criteria for receiving Demand (kW) 20,285 21,096 Mass. Electric's Rate G-3 high Energy (kWh) 7,126,400 7,126,400 voltage discount. Peak Energy (kWh) 1,672,460 n/a Off-Peak Energy (kWh) 5,453,940 n/a Eastern's Rate G-5 v. Mass. Electric's Rate G-3 - -------------------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - -------------------------------------------------- Bills 234 234 Demand (kW) 55,906 60,155 Energy (kWh) 18,249,760 18,249,760 Peak Energy (kWh) 4,643,330 9,672,373 Off-Peak Energy (kWh) 13,606,430 8,577,387 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System G-6 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 9 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Note: Eastern's Rate G-6 v. Mass. 1. The billing determinants Electric's Rate G-3 were estimated based upon - ----------------------------- Eastern's Rate G-6 load research data using Mass. Electric's TOU hours. Eastern's Mass. Electric's Billing Billing Billing 2. Eastern's Rate G-6 is a Parameter Determinant Determinant primary distribution voltage - ------------------------------------------ rate. By definition, all of Eastern's Rate G-6 customers Bills 380 380 meet the criteria for Demand (kW) 439,150 513,806 receiving Mass. Electric's Energy (kWh) 194,448,972 194,448,972 Rate G-3 high voltage Peak Energy (kWh) 38,898,442 85,557,548 discount. Off-Peak Energy (kWh) 155,550,530 108,891,424 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System T-2 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 10 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Note: Eastern's Rate T-2: Total 1. Eastern's Rate T-2 billing Eastern's demand is maximum monthly Billing Billing peak hours demand. Mass. Parameter Determinant Electric's Rate G-2 billing - ----------------------------------- demand is maximum monthly Bills 1,199 demand. Eastern's Rate T-2 Demand (kW) 155,613 billing demand was Energy (kWh) 73,073,922 recalculated to conform with Peak Energy (kWh) 14,145,295 Mass. Electric's definition. Off-Peak Energy (kWh) 58,928,627 2. For those Eastern Rate T-2 customers to be transferred Eastern's Rate T-2 v. Mass. to Mass. Electric's Rate G-3, Electric's Rate G-1 the billing determinants were - --------------------------- estimated based upon Eastern's Rate T-2 load Mass research data using Mass. Eastern's Electric's Electric's TOU hours. Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------- Bills 297 297 Demand (kW) 4,390 n/a Energy (kWh) 1,178,927 1,178,927 Peak Energy (kWh) 205,124 n/a Off-Peak Energy (kWh) 973,803 n/a Eastern's Rate T-2 v. Mass. Electric's Rate G-2 - --------------------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------- Bills 554 554 Demand (kW) 42,478 45,027 Energy (kWh) 18,743,578 18,743,578 Peak Energy (kWh) 3,623,614 n/a Off-Peak Energy (kWh) 15,119,964 n/a Eastern's Rate T-2 v. Mass. Electric's Rate G-3 - --------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - -------------------------------------------------- Bills 348 348 Demand (kW) 108,745 111,790 Energy (kWh) 53,151,417 53,151,417 Peak Energy (kWh) 10,316,557 22,323,595 Off-Peak Energy (kWh) 42,834,860 30,827,822 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System H-1 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 11 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Note: Eastern's Rate H-1: Total 1. Eastern's Rate H-1 non-demand metered customers Eastern's are to be transferred to Billing Billing Mass. Electric's Rate G-1. Parameter Determinant - ------------------------------- 2. Eastern's Rate H-1 determinants were apportioned Bills 1,314 among Mass. Electric's Rates Demand (kW) 38,217 G-1, G-2 and G-3 based on the availability provisions of Mass. Electric's rates. 3. For Eastern's Rate H-1 customers to be transferred to Mass. Electric's Rate G-2, all of the customers are demand metered. Eastern's Rate H-1 v. Mass. Electric's 4. For Eastern's Rate H-1 Rate G-1 customers to be transferred - -------------------------------------- to Mass. Electric's Rate G-3, Mass the billing determinants were Eastern's Electric estimated based upon Billing Billing Billing Eastern's Rate H-1 load Parameter Determinant Determinant research data using Mass. - ------------------------------------------- Electric's TOU hours. Bills 1,231 1,231 Energy (kWh) 2,545,293 2,545,293 Eastern's Rate H-1 v. Mass. Electric's Rate G-2 - --------------------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------- Bills 35 35 Demand (kW) 3,427 3,427 Energy (kWh) 704,880 704,880 Eastern's Rate H-1 v. Mass. Electric's Rate G-3 - -------------------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - ----------------------------------------------- Bills 48 48 Demand (kW) 34,790 38,617 Energy (kWh) 6,702,200 6,702,200 Peak Energy (kWh) n/a 3,552,166 Off Peak Energy (kWh) n/a 3,150,034 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System H-2 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 12 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Note: Eastern's Rate H-2: Total 1. Eastern's Rate H-2 determinants were apportioned Eastern's among Mass. Electric's Rates Billing Billing G-1 and G-2 based on the Parameter Determinant availability provisions of - ------------------------------- Mass. Electric's rates. Bills 1,991 Demand (kW) 496 Energy (kWh) 2,434,682 Eastern's Rate H-2 v. Mass. Electric's Rate G-1 - ----------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------ Bills 1,979 1,979 Energy (kWh) 2,299,322 2,299,322 Eastern's Rate H-2 v. Mass. Electric's Rate G-2 - --------------------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - -------------------------------------------------- Bills 12 12 Demand (kW) 496 496 Energy (kWh) 135,360 135,360 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System W-1 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 13 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Note: Eastern's Rate W-1: Total 1. Eastern's Rate W-1 determinants were apportioned Eastern's among Mass. Electric's Rates Billing Billing R-1 and G-1 based on the Parameter Determinant availability provisions of - ------------------------- Mass. Electric's rates. Bills 189,269 Energy (kWh) 49,476,751 Eastern's Rate W-1 v. Mass. Electric's Rate R-1 - --------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------- Bills 186,554 186,554 Energy (kWh) 48,697,330 48,697,330 Eastern's Rate W-1 v. Mass. Electric's Rate G-1 - -------------------------------------- Eastern's Mass. Electric's Billing Billing Billing Parameter Determinant Determinant - -------------------------------------------- Bills 2,715 2,715 Energy (kWh) 779,421 779,421 Fixture S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System S-1 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 14 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Month Ending December 31, 1998, Billing Determinants Eastern's Rate S-1 Streetlighting Rate
Eastern's Service Eastern's Eastern's Eastern's Lamp Lumen & Pole Fixture Special Fixture Annual kWh Total Annual Lighting Code Wattage Size Type Type Pricing Option Count per Light Energy - ---------------------------------------------------------------------------------------------------------- Metal Halide 0300-4-120 250 20,000 OH_WoodLine FldLt 9 1,180 10,620 0300-4-220 250 20,000 OH_WoodLitg FldLt 2 1,180 2,360 0466-4-120 400 40,000 OH_WoodLine FldLt 39 1,832 71,448 1080-4-120 1,000 115,000 OH_WoodLine FldLt 4 4,247 16,988 ---------- ----------- Total Metal Halide 54 101,416 - ----------------------------------------------------------------------------------------------------- Incandescent 0103-1-110 103 1,000 OH_WoodLine StLt 2 405 810 0202-1-110 202 2,500 OH_WoodLine StLt 1 794 794 ---------- ----------- Total Incandescent 3 1,604 - ------------------------------------------------------------------------------------------------- Mercury Vapor 0130-2-110 100 4,200 OH_WoodLine StLt 269 511 137,459 0130-2-810 100 4,200 URD_LamWood StLt 14 511 7,154 0130-2-811 100 4,200 URD_LamWood StLt CustPaidPole 2 511 1,022 0130-2-941 100 4,200 URD_WoodPost T&C CustPaidPole 4 511 2,044 0209-2-110 175 8,600 OH_WoodLine StLt 39 822 32,058 0209-2-130 175 8,600 OH_WoodLine PBU 226 822 185,772 0209-2-211 175 8,600 OH_WoodLitg StLt CustPaidPole 1 822 822 0209-2-231 175 8,600 OH_WoodLitg PBU CustPaidPole 7 822 5,754 0209-2-541 175 8,600 UG_Steel T&C CustPaidPole 37 822 30,414 0209-2-610 175 8,600 UG_Aluminum StLt 5 822 4,110 0300-2-110 250 12,100 OH_WoodLine StLt 3 1,180 3,540 0474-2-110 400 22,500 OH_WoodLine StLt 15 1,864 27,960 0474-2-120 400 22,500 OH_WoodLine FldLt 174 1,864 324,336 0474-2-130 400 22,500 OH_WoodLine PBU 30 1,864 55,920 0474-2-211 400 22,500 OH_WoodLitg StLt CustPaidPole 8 1,864 14,912 0474-2-221 400 22,500 OH_WoodLitg FldLt CustPaidPole 42 1,864 78,288 0474-2-231 400 22,500 OH_WoodLitg PBU CustPaidPole 1 1,864 1,864 1135-2-120 1,000 63,000 OH_WoodLine FldLt 34 4,463 151,742 1135-2-221 1,000 63,000 OH_WoodLitg FldLt CustPaidPole 5 4,463 22,315 ---------- ----------- Total Mercury Vapor 916 1,087,486 - ------------------------------------------------------------------------------------------------- Sodium Vapor 0061-3-110 50 3,300 OH_WoodLine StLt 4,424 240 1,061,760 0061-3-211 50 3,300 OH_WoodLitg StLt CustPaidPole 5 240 1,200 0061-3-941 50 3,300 URD_WoodPost T&C CustPaidPole 2 240 480 0085-3-110 70 5,800 OH_WoodLine StLt 14,491 334 4,839,994 0085-3-120 70 5,800 OH_WoodLine FldLt 111 334 37,074 0085-3-210 70 5,800 OH_WoodLitg StLt 3 334 1,002 0085-3-211 70 5,800 OH_WoodLitg StLt CustPaidPole 20 334 6,680 0085-3-221 70 5,800 OH_WoodLitg FldLt CustPaidPole 2 334 668 0085-3-441 70 5,800 URD_FiberglasT&C CustPaidPole 118 334 39,412 0085-3-461 70 5,800 URD_FiberglasSBA CustPaidPole 146 334 48,764 0085-3-641 70 5,800 UG_Aluminum T&C CustPaidPole 3 334 1,002 S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System S-1 Eastern Utilities Associates 15-Jun-99 M.D.T.E. Docket No. 99-____ Exhibit JJB-2 Page 15 of 15 Massachusetts Electric Company Eastern Edison Company Apportionment of Company Billing Determinants Month Ending December 31, 1998, Billing Determinants Eastern's Rate S-1 Streetlighting Rate Eastern's Service Eastern's Eastern's Eastern's Lamp Lumen & Pole Fixture Special Fixture Annual kWh Total Annual Lighting Code Wattage Size Type Type Pricing Option Count per Light Energy - ---------------------------------------------------------------------------------------------------------- 0085-3-711 70 5,800 UG_WoodLitg StLt CustPaidPole 7 334 2,338 0085-3-811 70 5,800 URD_LamWood StLt CustPaidPole 199 334 66,466 0085-3-941 70 5,800 URD_WoodPost T&C CustPaidPole 222 334 74,148 0121-3-110 100 9,500 OH_WoodLine StLt 7,510 476 3,574,760 0121-3-130 100 9,500 OH_WoodLine PBU 357 476 169,932 0121-3-211 100 9,500 OH_WoodLitg StLt CustPaidPole 88 476 41,888 0121-3-230 100 9,500 OH_WoodLitg PBU 1 476 476 0121-3-231 100 9,500 OH_WoodLitg PBU CustPaidPole 39 476 18,564 0121-3-441 100 9,500 URD_FiberglasT&C CustPaidPole 46 476 21,896 0121-3-460 100 9,500 URD_FiberglasSBA 4 476 1,904 0121-3-461 100 9,500 URD_FiberglasSBA CustPaidPole 28 476 13,328 0121-3-610 100 9,500 UG_Aluminum StLt 29 476 13,804 0121-3-631 100 9,500 UG_Aluminum PBU CustPaidPole 3 476 1,428 0121-3-641 100 9,500 UG_Aluminum T&C CustPaidPole 31 476 14,756 0121-3-651 100 9,500 UG_Aluminum PMA CustPaidPole 18 476 8,568 0121-3-711 100 9,500 UG_WoodLitg StLt CustPaidPole 29 476 13,804 0121-3-811 100 9,500 URD_LamWood StLt CustPaidPole 41 476 19,516 0121-3-940 100 9,500 URD_WoodPost T&C 3 476 1,428 0121-3-941 100 9,500 URD_WoodPost T&C CustPaidPole 279 476 132,804 0176-3-110 150 16,000 OH_WoodLine StLt 125 692 86,500 0176-3-120 150 16,000 OH_WoodLine FldLt 90 692 62,280 0176-3-211 150 16,000 OH_WoodLitg StLt CustPaidPole 10 692 6,920 0176-3-220 150 16,000 OH_WoodLitg FldLt 2 692 1,384 0176-3-221 150 16,000 OH_WoodLitg FldLt CustPaidPole 2 692 1,384 0176-3-610 150 16,000 UG_Aluminum StLt 37 692 25,604 0176-3-611 150 16,000 UG_Aluminum StLt CustPaidPole 2 692 1,384 0176-3-614 150 16,000 UG_Aluminum StLt AddlFixt 15 692 10,380 0324-3-110 250 25,000 OH_WoodLine StLt 2,129 1,274 2,712,346 0324-3-120 250 25,000 OH_WoodLine FldLt 1,030 1,274 1,312,220 0324-3-124 250 25,000 OH_WoodLine FldLt AddlFixt 1 1,274 1,274 0324-3-210 250 25,000 OH_WoodLitg StLt 1 1,274 1,274 0324-3-211 250 25,000 OH_WoodLitg StLt CustPaidPole 46 1,274 58,604 0324-3-220 250 25,000 OH_WoodLitg FldLt 1 1,274 1,274 0324-3-221 250 25,000 OH_WoodLitg FldLt CustPaidPole 85 1,274 108,290 0324-3-610 250 25,000 UG_Aluminum StLt 681 1,274 867,594 0324-3-611 250 25,000 UG_Aluminum StLt CustPaidPole 9 1,274 11,466 0324-3-621 250 25,000 UG_Aluminum FldLt CustPaidPole 1 1,274 1,274 0324-3-624 250 25,000 UG_Aluminum FldLt AddlFixt 10 1,274 12,740 0324-3-711 250 25,000 UG_WoodLitg StLt CustPaidPole 1 1,274 1,274 0500-3-110 400 50,000 OH_WoodLine StLt 581 1,966 1,142,246 0500-3-120 400 50,000 OH_WoodLine FldLt 4,258 1,966 8,371,228 0500-3-124 400 50,000 OH_WoodLine FldLt AddlFixt 2 1,966 3,932 0500-3-210 400 50,000 OH_WoodLitg StLt 2 1,966 3,932 0500-3-211 400 50,000 OH_WoodLitg StLt CustPaidPole 67 1,966 131,722 0500-3-220 400 50,000 OH_WoodLitg FldLt 48 1,966 94,368 0500-3-221 400 50,000 OH_WoodLitg FldLt CustPaidPole 426 1,966 837,516 0500-3-224 400 50,000 OH_WoodLitg FldLt AddlFixt 1 1,966 1,966 0500-3-610 400 50,000 UG_Aluminum StLt 99 1,966 194,634 0500-3-614 400 50,000 UG_Aluminum StLt AddlFixt 6 1,966 11,796 0500-3-620 400 50,000 UG_Aluminum FldLt 28 1,966 55,048 0500-3-621 400 50,000 UG_Aluminum FldLt CustPaidPole 10 1,966 19,660 0500-3-624 400 50,000 UG_Aluminum FldLt AddlFixt 111 1,966 218,226 0500-3-721 400 50,000 UG_WoodLitg FldLt CustPaidPole 1 1,966 1,966 0648-3-612 500 25,000 UG_Aluminum StLt TwinFixts 61 2,548 155,428 ---------- ----------- Total Sodium Vapor 38,238 26,758,978 - ------------------------------------------------------------------------------------------------- Total Streetlighting Billing Determinants 39,211 27,949,484 ========== ===========
New England Electric System and Eastern Utilities Associates Massachusetts Electric Company and Eastern Edison Company Rate Plan Filing in Support of Merger Volume 3 Testimony and Exhibits of: David J. Hoffman & Richard J. Levin April 30, 1999 Submitted to: Massachusetts Department of Telecommunications and Energy Docket D.T.E. 99-_____ Submitted by: Nees Logo Eastern Utilities Associates Logo Commonwealth of Massachusetts Department of Telecommunications and Energy - ------------------------------------ ) New England Electric System ) Docket D.T.E. 99-__ Eastern Utilities Associates ) ) - ------------------------------------ DIRECT TESTIMONY OF DAVID J. HOFFMAN AND RICHARD J. LEVIN Table of Contents Page I. Introduction and Qualifications.................................... 1 II. Summary of Testimony............................................... 6 III. Detailed Estimate of Cost Savings.................................. 12 A. Summary of Personnel and Non-Personnel Savings................ 12 B. Personnel Savings............................................. 13 C. Information Systems Savings (Non-Personnel)................... 17 D. Supply Chain Savings (Non-Personnel).......................... 18 E. Facilities Savings (Non-Personnel)............................ 20 F. Administrative and General Savings (Non-Personnel)............ 20 G. Comparison with Other Transactions............................ 24 IV. Detailed Estimate of Cost to Achieve............................... 26
New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 1 of 29 1 I. Introduction and Qualifications 2 Q. Please state your names, current positions and business addresses. 3 A. My name is David J. Hoffman. I am a Vice President with Mercer Management 4 Consulting, Lexington, Massachusetts. 5 6 My name is Richard J. Levin. I am a management consultant with Mercer 7 Management Consulting, Lexington, Massachusetts. 8 9 Q. Mr. Hoffman, please summarize your educational and professional background. 10 A. I received a B.S. degree in finance in 1976 and a MBA degree (with honors) in 11 management information systems in 1980 from Boston University. 12 13 My professional experience includes over 15 years as a consultant to electric and gas 14 utilities. I joined Mercer in 1982 and prior to that, worked for United Information 15 Systems (from 1980 to 1982). 16 17 During my consulting career, I have led a broad range of assignments, encompassing: 18 o Merger and acquisition analysis 19 o Organizational and performance improvement 20 o Strategic and business planning 21 o Information systems strategy 22 Hoffman/Levin -1- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 2 of 29 1 Q. Mr. Levin, please summarize your educational and professional background. 2 A. I received a B.A. in economics from Washington University in 1972 and an M.A. in 3 economics from The Ohio State University in 1974. In 1977, I received a J.D. degree 4 from Ohio State and was admitted to the Ohio Bar. 5 6 My professional experience includes over nineteen years as a management consultant 7 specializing in the management and regulation of utilities. I joined Mercer in May 1983 and, 8 prior to that, worked as an independent consultant (June 1982 through April 1983) and for 9 Booz, Allen & Hamilton, Inc. (April 1979 through May 1982). 10 11 During my consulting career, I have served as a project manager or lead consultant on a broad 12 range of assignments for utilities and regulatory commissions. The subject matter of these 13 assignments has encompassed: 14 o Merger and acquisition analysis 15 o Organizational and performance improvement 16 o Strategic and business planning 17 o Management audits 18 o Rate of return and cost of capital studies 19 o Financial forecasting and planning 20 o Economic and financial feasibility evaluations 21 22 Prior to my consulting career, I was a lecturer at Ohio State in economic theory and corporate 23 finance. I held that position from January 1978 through March 1979. From June 1975 to 24 September 1978, I was employed by the Public Utilities Commission of Ohio. From 1975 to Hoffman/Levin -2- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 3 of 29 1 1977, I served as a financial economist with the Commission's staff and testified on rate of 2 return and financial issues in electric, gas, telephone, and water rate cases. After graduation 3 from law school in 1977, I became a Hearing Examiner for the Commission. My primary 4 responsibilities in that position were presiding over rate and other proceedings, drafting 5 proposed rules, and preparing written orders for the Commission's consideration. 6 7 I have testified before the Massachusetts Department of Public Utilities, the Maine 8 Public Utilities Commission, and the Ohio Public Utilities Commission on the cost of 9 capital. I have also testified before the Maine PUC, New Mexico Public Service 10 Commission, the Iowa State Commerce Commission, the Pennsylvania Public Utility 11 Commission, and the Massachusetts Appellate Tax Board on other regulatory issues. 12 13 Q. Mr. Hoffman and Mr. Levin, please summarize your relevant experience. 14 A. Over the past several years, we have both been actively involved in the merger and 15 acquisitions (M&A) area. This work has included 1) screening and evaluating 16 potential merger candidates, 2) estimating cost savings for approximately 15 potential 17 mergers, and 3) assisting utilities in post-merger integration planning. 18 19 We have also been involved in organizational and/or performance improvement work at more 20 than 30 utilities. This work has been done for utility clients and on behalf of regulatory 21 commissions (as part of management audits). This work has included organizational design, Hoffman/Levin -3- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 4 of 29 1 determining appropriate staffing levels, process redesign, and identifying opportunities to 2 reduce costs. The work has encompassed all aspects of the utility business (generation, 3 transmission, distribution, customer and marketing-related, and A&G functions). With 4 respect specifically to A&G activities, we have both been involved in assignments dealing 5 with the following functions: information services, accounting, human resources, finance and 6 treasury, supply chain management, legal, rates and regulatory affairs, and corporate 7 communication and external affairs. 8 9 Important elements of this work have been benchmarking a particular utility's performance 10 against other companies and understanding the drivers of costs on the overall business and on 11 specific functions. We are also two of the principal authors of Mercer's utility staffing 12 survey. This survey has become an industry standard for evaluating staffing levels; its 13 definition of utility functions and sub-functions is also widely used in merger analysis and 14 testimony. 15 16 Q. Please describe Mercer's experience in working with NEES. 17 A. Mercer Management Consulting has worked extensively with NEES since 1992. Our 18 work with the Company has included the following types of assignments: 19 o Organizational transformation 20 o Process improvement 21 o Business strategy Hoffman/Levin -4- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 5 of 29 1 o Mergers and acquisitions analysis 2 3 These assignments have encompassed all operating, customer-related, and A&G 4 functions in the operating companies and the service company. 5 6 Mercer's extensive knowledge of NEES management and operations was extremely 7 helpful in discussing integration strategies, identifying cost savings opportunities and 8 ultimately, in developing sound estimates of savings and cost to achieve for the 9 proposed NEES-EUA merger. 10 11 Q. Please describe some of these assignments. 12 A. In 1992 and 1993, Mercer assisted NEES in a major organizational transformation, 13 which included the creation of business units, the alignment and clarification of roles 14 and responsibilities, and a significant streamlining of organizational structure and 15 staffing. In 1993 and 1994, we assisted NEES in developing a customer call center 16 strategy which led to the successful consolidation of Massachusetts Electric's six 17 individual call centers into a single center (the Northboro Customer Service Center). 18 During the 1996-1998 period, Mercer helped NEES in the transition from a 19 fully-integrated utility into a "wires" utility; this particular effort included identifying 20 corporate support services required after the divestiture of generation assets. Hoffman/Levin -5- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 6 of 29 1 2 Q. In addition to this testimony, has Mercer been retained to assist in other aspects 3 of the proposed NEES-EUA merger? 4 A. Yes. Mercer has been retained to assist in the post-merger integration process. 5 6 II. Summary of Testimony 7 Q. What is the purpose of your testimony? 8 A. We have been asked to describe the analysis conducted to estimate the potential cost 9 savings associated with a merger of the New England Electric System ("NEES") and 10 Eastern Utilities Associates ("EUA"). Mercer Management Consulting (Mercer) 11 assisted NEES and EUA (also referred to as the "Companies") in 1) identifying areas 12 with potential cost saving or cost to achieve, 2) collecting relevant data, 3) developing 13 related operating and financial assumptions, and 4) estimating potential savings and 14 costs. 15 16 This testimony presents the results of the analysis, including: 17 o A summary of results (this section) 18 o A detailed estimate of savings (Section III) 19 o A detailed estimate of cost to achieve (Section IV) 20 Hoffman/Levin -6- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 7 of 29 1 Exhibit DJH-1 provides a summary of potential merger cost savings for the first 10 2 years (2000-2009) and the cost to achieve. Exhibit DJH-2 contains the 3 non-confidential working papers that support the estimates. Exhibit DJH-3 contains our 4 confidential working papers. 5 6 Q. Please summarize your testimony. 7 A. The planned merger will result in savings that would not otherwise be achieved by 8 the stand-alone operations of NEES (through its Massachusetts Electric, Narragansett 9 Electric, Granite State Electric, Nantucket Electric, and New England Power Service 10 Company subsidiaries) and EUA (through its Eastern Edison, Blackstone Valley 11 Electric, Newport Electric and EUA Service Corporation subsidiaries). Based on 12 information provided by NEES and EUA and the analysis conducted by NEES 13 management and Mercer, merger-related savings were estimated at approximately 14 $31.1 million in 2005, as shown below: 15 Estimated Savings in 2005 16 Savings Component ($ Millions) ----------------- ------------ 17 Personnel Savings $21.5 18 Information Systems Savings 0.1 19 Supply Chain Savings 0.6 20 Facilities Savings 4.7 21 Administrative and General Savings 4.2 --- 22 Total Savings 31.1 23 Hoffman/Levin -7- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 8 of 29 1 The figures above include merger-related savings related only to the regulated "wires" 2 and A&G-related operations of NEES and EUA. No revenue enhancements were 3 identified for the regulated business. 4 5 Only cost savings that would result from the merger were included in estimated 6 savings. These types of savings are derived from the elimination of duplication, cost 7 avoidance, adoption of different management practices and policies, and the improved 8 utilization of assets and employees. Savings which could be achieved without a 9 merger (e.g., position reductions resulting from a process improvement in one 10 company) were not included in the estimated savings. 11 12 Q. When will the savings commence? 13 A. Savings will begin in 2000 and continue permanently. Exhibit DJH-1 presents savings 14 for only the first 10 years (2000-2009). The cost to achieve the merger savings will 15 occur primarily in the 1999-2002 period. 16 17 Q. Could the cost savings discussed above and in detail in Section III be achieved 18 without a merger? 19 A. No. The savings are based upon the elimination of redundancies (in personnel, 20 facilities and other areas) and the gaining of economies brought about by a merger. In Hoffman/Levin -8- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 9 of 29 1 addition, the savings would not result without incurring the cost to achieve discussed 2 above and in detail in Section IV. 3 4 Q. Please describe the process utilized to estimate merger cost savings and cost to 5 achieve. 6 A. Mercer worked with senior and middle managers at both NEES and EUA to gather 7 the information required to estimate savings and costs. We also met with EUA 8 managers to develop a fuller understanding of the company's business practices, 9 operations, and costs. As discussed earlier, we already had an extensive 10 understanding of NEES business practices, operations, and costs. 11 12 We also worked with NEES management to determine how the merged companies 13 would operate in the future, e.g., the expected level of integration in the A&G, 14 customer-related, and T&D functions. 15 16 Based on information collected and assumptions about how the merged companies 17 would operate, estimates of merger savings and costs were developed, discussed, and 18 refined. The process used to develop the estimated savings and cost to achieve was 19 reasonable, and captured the significant sources of savings available and costs that 20 would be incurred in a merger. 21 Hoffman/Levin -9- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 10 of 29 1 Q. What assumptions were made in the analysis? 2 A. The following assumptions were made in estimating cost savings: 3 o The combined companies will begin integrated operations on January 1, 2000 4 o The "wires" business will be run with one principal operating company in each 5 state (Massachusetts, Rhode Island, and New Hampshire) and one service 6 company 7 o A high-degree of integration will occur, e.g.: 8 - Financial, accounting, human resources, legal, external affairs, and corporate 9 planning functions will be fully integrated 10 - IS data centers will be consolidated 11 - Call centers will be consolidated 12 - Central T&D planning, engineering, and support will be fully integrated, as 13 will transmission field forces 14 o Annual savings will escalate at a rate of 2.2 percent 15 16 Q. How were capital-related savings calculated? 17 A. Capital-related savings were calculated using a revenue requirement methodology. 18 Under this methodology, for example, a capital deferral or avoidance of $1 million in 19 2000 would not result in a merger savings of $1 million in that year; rather annual 20 savings relating to the fixed charges (cost of capital, depreciation, insurance, and 21 taxes on the $1 million deferral or avoided) are calculated. The revenue requirements 22 methodology reflects the timing of merger savings and how capital or 23 construction-related costs are treated for ratemaking purposes. Hoffman/Levin -10- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 11 of 29 1 Fixed charge rates for NEES and EUA were estimated and then blended, based on the 2 relative size of the companies. A levelized fixed charge rate of 13.5 percent was used 3 for capital items other than IS-related. A levelized fixed charge rate of 28.6 percent 4 was used for IS-related items; the higher rate is due to a more rapid (five-year) 5 depreciation period. 6 7 Q. Is the level of estimated cost savings achievable? 8 A. We believe that the level of savings identified in our study has a high likelihood of 9 achievement. Beyond that level, we are aware that Mr. Jesanis is testifying that he 10 expects the savings to be achieved from the acquisition of EUA will be $35 million 11 per year or more in 2005. We believe that this higher level of savings is likely to be 12 achieved for the following reasons: 13 o NEES management approach: During our previous assignments with NEES, the 14 Company has been very creative and aggressive in identifying opportunities to 15 reduce costs; the early creation of a transition team to facilitate the merger 16 illustrates NEES's aggressive approach to opportunities. 17 o NEES "track record": NEES has successfully addressed many of the same 18 issues that arise in a merger, e.g., designing a streamlined organization, 19 integrating multiple call centers, and optimizing field forces and work out 20 locations. 21 o National Grid-related synergies: Additional synergies are expected to result 22 from the National Grid-NEES merger, e.g., taking advantage of National Grid 23 best practices and financing capabilities. 24 Hoffman/Levin -11- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 12 of 29 1 o Additional sources of savings: Opportunities may arise which have not been 2 captured in our estimates. These include 1) outsourcing functions (given the 3 greater volume of work for the merged companies); 2) taking advantage of new 4 technologies (given the merged companies greater scale); and 3) achieving 5 longer-term IS savings by avoiding duplicative efforts. 6 7 As such, we agree with Mr. Jesanis that actual savings are likely to exceed our 8 estimated savings. 9 10 III. Detailed Estimate of Cost Savings 11 12 A. Summary of Personnel and Non-Personnel Savings 13 Q. You have estimated merger cost savings of $31.1 million in 2005. Would you 14 define the principal components of cost savings and the estimated savings in each 15 component? 16 A. As illustrated in the table on page 7 of this testimony and in Exhibit DJH-2, savings 17 have been classified into five components: 18 o Personnel savings: related to position reductions in A&G, customer, 19 transmission and distribution, and other functions 20 o Information systems savings (non-personnel): related to integration of 21 applications; mainframe, network, midrange/server, and PC/workstation 22 operations; projects; and telecommunications 23 o Supply chain savings (non-personnel): related to reductions in inventory; lower 24 costs for materials, equipment, and contractor services; and reductions in the 25 number of vehicles Hoffman/Levin -12- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 13 of 29 1 o Facilities savings (non-personnel): related to the closing of facilities, including 2 office space 3 o Administrative and general savings (non-personnel): related to A&G 4 overheads, advertising, association dues, benefits administration, corporate 5 governance (i.e., shareholder services and board fees), financing costs and fees, 6 insurance, professional services, and regulatory expenses 7 8 The level of estimated savings (in 2005 dollars unless otherwise indicated) and the 9 bases for the estimates are discussed below. 10 11 B. Personnel Savings 12 Q. Please discuss the analysis supporting your personnel savings estimate of $21.5 13 million in 2005. 14 A. Personnel savings were estimated using the following process: 15 o First, staffing levels for NEES and EUA were estimated as of January 1, 2000. 16 Both companies provided detailed organizational and functional breakdowns that 17 assigned each employee to one of the following functions: 18 Hoffman/Levin -13- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 14 of 29 1 ------------------------------------------------------------------------------------------------------- A&G Functions Customer Functions o Purchasing and Material Management o Retail Marketing and Sales (excluding Storeroom Personnel) o Customer Service o Human Resources Electric Transmission and Distribution Functions o Finance, Accounting, and Planning o Electric Distribution o Information Services and Telecommunications o Electric System Technical Support o External Relations o Electric Transmission o Legal o Transportation, Real Estate, and Facilities Maintenance o Administrative and Support Services (excluding Transportation, Real Estate, and Facilities o Storeroom Personnel Maintenance) Other o Executive Management o Other Activities 2 ------------------------------------------------------------------------------------------------------- 3 Within these functions, employees were also assigned to specific sub-functions. 4 For example, within Customer Service, an employee could be assigned to meter 5 reading, customer inquiry, credit and collections, or another sub-function. The 6 complete list of functions and sub-functions used in this analysis is included in 7 the Exhibit DJH-3 working papers. The use of a common format (Mercer's staffing 8 survey function and sub-function classification) allowed for an "apples-to-apples" 9 staffing analysis. 10 o Second, the number of positions that could be eliminated as a result of the merger 11 was estimated. The magnitude of the reduction in each sub-function was based 12 upon identified duplication or redundant activities; the expected degree of 13 integration; potential changes in policies or practices; and any incremental 14 workloads that would result in that area. The number of position reductions in 15 any one sub-function were not allowed to exceed the smaller of the number of 16 positions of either NEES or EUA on a stand-alone basis. For example, if NEES 17 had 15 positions in a sub-function and EUA had 5 positions, the reduction could 18 not exceed 5 positions. Hoffman/Levin -14- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 15 of 29 1 o Third, an average compensation was calculated for each sub-function and then 2 multiplied by the number of positions reduced in that sub-function. The 3 compensation figures used were the average of NEES and EUA compensation 4 levels. Compensation figures included base compensation (wages or salaries) and 5 benefits. Benefits included such items as pension plans, medical insurance, life 6 insurance, savings (401K) plans, bonuses and incentives, and payroll taxes. The 7 average total compensation (salary and benefits) for positions reduced was 8 $84,900 (in 2000 dollars). 9 10 Q. Please describe the results of the personnel analysis. 11 A. NEES was estimated to have 3,240 positions in utility operations and EUA was 12 estimated to have 869 positions as of January 1, 2000. Total position reductions were 13 estimated at 234, or approximately 6 percent of the 4,109 combined positions. These 14 reductions consist of 88 A&G, 62 customer, 78 T&D, and 6 other function positions, 15 as shown below. Position Reductions ---------------------------------------------------------------------------------------- A&G Customer T&D Other Total NEES Positions 461 722 2,057 0 3,240 EUA Positions 173 201 488 7 869 --- --- --- - --- Combined Positions 634 923 2,545 7 4,109 Estimated Reductions (88) (62) (78) (6) (234) Reduction as a % of 14% 7% 3% 86% 6% Combined Positions Reduction as a % of 51% 31% 16% 86% 27% EUA Positions 16 17 The 234 position reductions also equals 27 percent of EUA's 869 positions. At this 18 point, no decisions have been made as to which reductions will come from current 19 NEES positions or EUA positions. Hoffman/Levin -15- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 16 of 29 1 2 As shown above, the percentage reductions in the A&G functions are significantly 3 higher than the percentage reductions in the customer and T&D functions. The 4 relative difference reflects the fact that "headquarter" or "office" type functions 5 offer greater opportunities for savings than do "field" functions, such as line maintenance 6 and construction. 7 8 Q. What was the assumed timing of the estimated reduction in positions? 9 A. In the A&G (except for IS), customer, and T&D functions, 75 percent of reductions 10 were assumed to occur in 2000 with the remaining 25 percent occurring in 2001. In 11 the IS area, reductions were assumed to be 0 percent in 2000, 50 percent in 2001, and 12 the remaining 50 percent in 2002. The slower timing of reductions in IS reflects the 13 complicated work required to integrate the two companies' systems. 14 15 Q. How were capital-related personnel savings calculated? 16 A. The percent of payroll savings allocated to capital was 0 percent for the A&G and 17 customer functions and 35 percent for the T&D functions. These rates were based on 18 payroll allocation figures provided by the companies, weighted by their relative sizes. 19 As discussed earlier, capital-related savings were translated into revenue 20 requirements, based on estimated fixed charge rates. 21 Hoffman/Levin -16- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 17 of 29 1 C. Information Systems Savings (Non-Personnel) 2 Q. Please describe the information systems functions at NEES and EUA. 3 A. NEES information systems operate on an IBM mainframe computer, an IBM 4 midrange computer, approximately 60 servers, and approximately 2,500 PCs. 5 Corporate, financial and administrative systems utilize Walker software; HR/payroll 6 will utilize PeopleSoft; and the customer information system was developed in-house. 7 The company also has numerous operational systems running on the midrange and 8 mainframe computers. The NEES data center is located in the Westborough 9 headquarters. 10 11 EUA information systems operate on an Amdahl mainframe computer, approximately 12 20 servers, and approximately 600 PCs. EUA operates various financial packages; a 13 CYBORG HR/payroll system; a customer information system developed in-house; 14 and numerous operational systems. The EUA data center is located in the West 15 Bridgewater headquarters. 16 17 Q. Please discuss estimated cost savings in the IS area? 18 A. Merger savings were estimated based on two major assumptions: first, that data 19 centers will be consolidated; second, that the combined companies will migrate to 20 NEES applications including Walker, PeopleSoft, and the NEES customer 21 information system. Hoffman/Levin -17- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 18 of 29 1 2 Most of the savings come from a reduction in personnel, which was discussed earlier. 3 Non-personnel savings relating to the consolidation of data centers are largely offset 4 by the cost of adding computing capacity for combined mainframe and midrange 5 computer operations. In 2005, non-personnel IS savings were estimated at 6 approximately $0.1 million. 7 8 D. Supply Chain Savings (Non-Personnel) 9 Q. What are the potential areas of cost savings in the supply chain area? 10 A. Cost savings in supply chain can potentially occur in the following areas: 11 o A reduction in inventory, based on the consolidation of the companies' 12 storerooms and a sharing of spare parts 13 o Lower prices paid for materials, equipment and contractor services, based on 14 greater purchasing leverage and the potential for more standardization and vendor 15 consolidation 16 o A reduction in the number of vehicles, based on a reduction in the number of 17 field and headquarter positions 18 19 Q. Please discuss the estimated level of savings in supply chain? 20 A. Supply chain-related savings in 2005 of $0.6 million were estimated. 21 Hoffman/Levin -18- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 19 of 29 1 Inventory savings were $0.1 million of the total. Savings were based on a reduction 2 in fixed charges associated with a 25 percent reduction in EUA's current inventory of 3 $3.6 million. 4 5 Procurement savings on materials and equipment were estimated at $0.3 million in 6 2005. These savings were based on an estimated 3 percent reduction in the cost of 7 EUA's annual purchases of approximately $9.4 million. Merger-related savings for 8 contractor services were minimal, since EUA does not have significant contractor 9 services costs (estimated at $2.4 million for vegetation control and $0.2 million for 10 other services in 1998). In addition, the ability to gain purchasing leverage on 11 contractor services is difficult. 12 13 Vehicle-related savings were estimated at $0.2 million in 2005. Vehicle savings will 14 occur as a result of the reductions in the number of positions. An elimination of 5 15 heavy duty vehicles (due to the reduction of 5 T&D crews) and 10 passenger vehicles 16 (due to the reduction of approximately 90 A&G personnel) were estimated. Savings were 17 based on annual operating and fixed costs of $20,000 per heavy duty vehicle 18 and $5,000 per passenger vehicle. 19 Hoffman/Levin -19- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 20 of 32 1 E. Facilities Savings (Non-Personnel) 2 Q. Does the merger of NEES and EUA create an opportunity to consolidate 3 facilities? 4 A. Yes. As a result of the NEES-EUA merger, only one headquarters building will be 5 required, since A&G functions will be fully integrated. Based on planned T&D 6 operations, the EUA service centers and work out locations will continue to operate in 7 order to meet customer needs. As a result, no other opportunities to reduce facility 8 costs were identified. 9 Q. What are the estimated facilities-related savings? 10 A. The consolidation of headquarters will provide an estimated savings of $4.7 million in 11 2005. The savings reflect reductions in both operating expenses (e.g., maintenance 12 and outside services) and capital-related costs. 13 14 F. Administrative and General Savings (Non-Personnel) 15 Q. What are the potential areas of non-personnel savings related to administrative 16 and general functions? 17 A. We identified the following nine potential areas of cost savings: A&G overheads; 18 advertising; association dues; benefits administration; corporate governance (i.e., 19 shareholder services and board-related costs); financial fees; insurance; professional 20 services; and regulatory expenses. 21 Hoffman/Levin -20- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 21 of 29 1 Q. What level of non-personnel A&G savings were estimated in the merger 2 analysis? 3 A. Savings in 2005 of $4.2 million were estimated. Sources of significant savings 4 included the professional services and corporate governance areas. Savings estimates 5 for each area are discussed below. 6 7 Q. Please discuss estimated savings related to A&G overheads in 2005. 8 A. Estimated A&G overhead-related merger savings of $0.8 million were identified. 9 A&G overheads include expenses for office supplies, publications, personal 10 computers, and other miscellaneous expenses. These types of expenses are often 11 captured in FERC Account 921. 12 13 Using NEES and EUA FERC data and other reports, we estimated overheads at 14 $3,000 per employee (in 2000 dollars). This figure was multiplied by the number of 15 position reductions to estimate annual savings. 16 17 Q. Please discuss estimated savings related to advertising. 18 A. Estimated savings in the advertising area were $0.3 million in 2005. Savings will 19 result from an elimination of duplicative costs, e.g., some media purchases. For this 20 transaction, savings were estimated at 50 percent of EUA's annual, normalized 21 advertising expenses. Hoffman/Levin -21- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 22 of 29 1 2 Q. Please discuss estimated savings related to association dues. 3 A. Association dues-related savings of $0.1 million in 2005 were identified. Savings 4 were based on lower expenditures for combined membership in the Edison Electric 5 Institute and the termination of membership in other associations. 6 7 Q. Please discuss estimated savings related to benefits administration. 8 A. Estimated merger savings in this area were $0.1 million in 2005. Although total 9 benefit costs for medical, dental, life and other insurance, pensions, and savings 10 plans are significant, the opportunity to reduce costs is very limited. For example, NEES' 11 HMO benefits are self-insured and do not provide an opportunity for savings. 12 13 Q. Please discuss estimated savings related to corporate governance. 14 A. Merger savings related to a reduction in corporate governance costs were estimated 15 at $0.9 million in 2005. Savings related to shareholder services result from the 16 elimination of duplicate activities and costs, such as preparation of the annual 17 shareholders' report and transfer agent fees. Additional savings result from the 18 elimination of director fees and expenses for one company. 19 20 Q. Please discuss estimated savings related to financing costs and fees. Hoffman/Levin -22- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 23 of 29 1 A. Merger savings in this area were estimated at $0.3 million in 2005, based on a 2 reduction in line of credit fees for the combined company. The savings related to 3 lines of credit are based on a 100 percent elimination of EUA's stand-alone fees. 4 5 Q. Please discuss estimated savings related to insurance. 6 A. Merger-related insurance savings were estimated at $0.7 million in 2005. Savings 7 were based on expected reductions in property and liability coverage premiums (due 8 to reduction in cost per additional dollar of coverage); reductions in directors and 9 officers insurance premiums (due to the elimination of one board of directors); and 10 reductions in brokerage fees (due to the consolidation of insurance purchasing). 11 12 Q. Please discuss estimated savings related to professional services. 13 A. Merger-related savings for professional services were estimated at $1.0 million in 14 2005. Professional services savings result from the elimination of duplicative efforts 15 in areas such as external auditing, legal support, legislative services, and general 16 consulting. The savings were based on an approximate 40 percent reduction in 17 EUA's stand-alone annual professional services costs. 18 18 Q. Please discuss estimated savings related to regulatory expenses. Hoffman/Levin -23- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 24 of 29 1 A. Merger-related savings for regulatory expenses were estimated at $0.1 million in 2 2005. Savings (non-personnel) in this area are relatively small, since annual 3 assessments (the largest component of costs) are not likely to be reduced when the 4 two companies merge. The savings estimate is based on a 20 percent reduction in 5 EUA's annual reporting, filing, and miscellaneous expenses of approximately $0.3 6 million, to reflect the elimination of some duplication and gains from integrating 7 regulatory affairs management. 8 9 G. Comparison with Other Transactions 10 Q. Did you compare the NEES-EUA merger to other transactions? 11 A. Yes. We reviewed a number of transactions, including the BEC Energy-COM/Energy 12 merger. 13 14 The 6 percent reduction in positions for the NEES-EUA merger falls in the 3 15 percent-11 percent range for other transactions that we reviewed. We would not expect the 16 NEES-EUA percentage reductions to be at the high end of the range given the 17 significant difference in staffing levels between NEES and EUA (NEES has 3.7 times 18 the staffing of EUA). In the other transactions, the ratio of employees for the merger 19 partners is typically in the 1 to 2 times range, which creates the potential for higher 20 percentage savings. Hoffman/Levin -24- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 25 of 29 1 Q. Why did you conclude that the NEES-EUA merger has a more limited 2 opportunity to reduce costs? 3 A. First, NEES and EUA are relatively "lean" utilities. This limits the ability to reduce 4 staffing (the largest source of savings) in a merger situation. 5 6 For example, NEES and EUA were estimated to have a combined pre-merger staffing 7 of 4,109 or 2.5 employees per thousand customers (based on a total of 1.66 million 8 customers). The comparable figures for BEC Energy and COM/Energy are combined 9 pre-merger staffing of 3,338 or 3.2 employees per thousand customers (based on a 10 total of 1.04 electric customers). Based on estimated position reductions in each 11 transaction, post-merger NEES-EUA will have 2.3 employees per thousand customers 12 compared to 2.9 employees per thousand customers for post-merger BEC 13 Energy-COM/Energy. 14 15 Second, EUA has a relatively small cost base. For example, in 1997, combined T&D, 16 customer (excluding demand-side management) and A&G-related expenses were $77 17 million. COM/Energy's expenses were $116 million for the same electric functions 18 and $147 million if gas-related A&G expenses are included. Again, the lower cost 19 base limits the potential savings. 20 21 Q. Please summarize this section of your testimony. Hoffman/Levin -25- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 26 of 29 1 A. Merger cost savings of $31.1 million in 2005 were estimated. Approximately 70 2 percent of savings ($21.5 million) were personnel-related. The savings are based 3 upon an assumed merger of NEES and EUA and would not result otherwise. 4 5 IV. Detailed Estimate of Cost to Achieve 6 Q. What types of costs are incurred when two companies merge? 7 A. Costs fall into the following four categories: 8 o Transaction costs: primarily the fees paid to investment bankers for advice on 9 the merger transaction and to outside legal counsel for advice on the merger 10 transaction and support in regulatory proceedings 11 o Personnel costs: primarily the out-of-pocket costs incurred to achieve the 12 reduction in positions, e.g., early retirement/severance packages; other costs 13 include retention payments to employees deemed necessary for a successful 14 integration, as well as relocation and retraining costs 15 o Transition costs: the costs incurred to integrate the two companies, e.g., support 16 for organizational redesign and process integration; communication costs; and 17 costs related to the closing of facilities 18 o Information systems costs: the costs associated with integrating systems, 19 consolidating data centers, creating a common meter reading standard, and 20 connecting telecommunication networks 21 22 Q. How were these costs estimated for the potential merger of NEES and EUA? Hoffman/Levin -26- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 27 of 29 1 A. Banker and legal fees were estimated by NEES and EUA management. Other 2 estimated costs to achieve were based on information provided by NEES and EUA 3 and on discussions with NEES management concerning the degree of integration 4 expected, planned corporate policies, and the resulting integration requirements. This 5 process addressed all significant costs to achieve. 6 7 Q. Please summarize the estimated cost to achieve for the merger. 8 A. The cost to achieve was estimated at $63.6 million - approximately $11.4 million for 9 transaction costs, $40.1 million for personnel costs; $4.6 million for transition costs, 10 and $7.6 million for information systems costs. Details are provided in Exhibits 11 DJH-1 and 2 and below. Approximately 85 percent of the costs will be incurred in the 12 1999-2000 period. 13 14 Q. Please discuss the estimated transaction costs of approximately $11.4 million. 15 A. The primary transaction costs are for merger assistance provided by investment 16 bankers and merger and regulatory assistance from outside counsel. These costs 17 were estimated by NEES and EUA at $7.5 million for banker fees and $3.5 million for legal 18 fees. The other transaction cost included is for director and officer tail liability 19 coverage ($0.4 million). 20 Hoffman/Levin -27- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 28 of 29 1 Q. Please discuss the estimated personnel costs of approximately $40.1 million. 2 A. The most significant personnel costs incurred in a merger are related to achieving 3 targeted reductions in the workforce. 4 5 Separation and retention costs were estimated at $35.2 million. These costs include 6 payments to employees for early retirement, severance and/or other separation 7 packages; payments to executives other than EUA parent company, generation-related, 8 and unregulated business executives; and retention of key employees. 9 10 Other costs were estimated at $5 million. These costs include estimated relocation 11 and miscellaneous costs ($2.8 million) and estimated retraining and reorientation 12 costs for customer services, T&D, and administrative personnel to learn about future work 13 processes, as well as company policies and practices ($2.2 million). 14 Hoffman/Levin -28- New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 29 of 29 1 Q. Please discuss the estimated transition costs of $4.6 million. 2 A. Transition costs are costs incurred to integrate the separate operations of the two 3 companies. Estimated costs for the NEES-EUA merger included $2.0 million for 4 outside organizational and change management support; $0.8 million for internal 5 process integration teams; $0.5 million for communications about the merger and 6 integration process to employees and external parties, e.g., shareholders, regulatory 7 commissions, vendors, and the investment community; $1.0 million for the closing of 8 some facilities and for the reconfiguration of other facilities; and $0.3 million for 9 changes to corporate signage and stationary. 10 11 Q. Please discuss the estimated information systems costs of $7.6 million. 12 A. The most significant IS cost was an estimated $6.6 million for applications 13 integration, data conversion, and the consolidation of data centers. Other costs 14 included $0.6 million to outfit EUA meter readers with NEES-standard meter reading 15 devices; and $0.4 million to link the two telecommunications networks and to 16 reconfigure/reprogram customer service center switches. 17 18 Q. Does this conclude your testimony? 19 A. Yes, it does. Hoffman/Levin -29-
New England Electric System Eastern Utilities Associates M.D.T.E. Docket No. 99-_____ EXHIBITS OF DAVID J. HOFFMAN & RICHARD J. LEVIN Exhibit DJH-1 Summary of Savings and Cost to Achieve Exhibit DJH-2 Supporting Working Papers Exhibit DJH-3 Supporting Working Papers (Confidential) Narragansett Electric BVE/Newport Electric M.D.T.E. Docket No. 99- _____ Exhibit DJH-1 Exhibit DJH-1 Summary of Savings and Cost to Achieve
Exhibit DJH-1 Savings Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Personnel 12,365 17,846 19,326 20,040 20,771 21,517 22,279 23,059 23,855 24,669 205,728 Non-Personnel Information Systems 17 34 52 53 55 56 57 58 60 61 502 Supply Chain 247 513 539 566 594 622 651 680 710 741 5,862 Facilities - 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001 Administrative and General 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359 ------------------------------------------------------------------------------------------------------- Total Savings 16,137 26,442 28,224 29,149 30,095 31,061 32,049 33,059 34,090 35,145 295,452 Cost to Achieve 54,060 8,350 1,200 - - - - - - - 63,610 ------------------------------------------------------------------------------------------------------- Net Savings (37,923) 18,092 27,024 29,149 30,095 31,061 32,049 33,059 34,090 35,145 231,842 Confidential Page 1 of 13
NEES-EUA Savings Summary Personnel Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total A&G Personnel % Capitalized 0% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized--- IS 0% 50% 100% 100% 100% 100% 100% 100% 100% 100% % Realized---Other 75% 100% 100% 100% 100% 100% 100% 100% 100% 100% Reductions ---------- Ongong savings - IS 1,528 18 Ongoing savings - Other 6,680 70 Total Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719 O&M Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719 1 Capital Savings - - - - - - - - - - 2 - - - - - - - - - 3 - - - - - - - - 4 - - - - - - - 5 - - - - - - 6 - - - - - 7 - - - - 8 - - - 9 - - 10 - -------------------------------------------------------------------------------------------------------- Total Capital Savings - - - - - - - - - - - Rev Req Savings - - - - - - - - - - - -------------------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719 Confidential Page 2 of 13
NEES-EUA Savings Summary 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Customer Related Personnel % Capitalized 0% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100% Reductions Ongoing savings 4,930 62 Total Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242 O&M Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242 1 Capital Savings - - - - - - - - - - 2 - - - - - - - - - 3 - - - - - - - - 4 - - - - - - - 5 - - - - - - 6 - - - - - 7 - - - - 8 - - - 9 - - 10 - Total Capital Savings - - - - - - - - - - - Rev Req Savings - - - - - - - - - - - Total O&M + Rev Req Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242 Confidential Page 3 of 13
NEES-EUA Savings Summary 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total T&D Personnel % Capitalized 35% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100% Reductions Ongoing savings 6,088 78 Total Savings 4,566 6,222 6,359 6,499 6,642 6,788 6,938 7,090 7,246 7,406 65,757 O&M Savings 2,968 4,045 4,133 4,224 4,317 4,412 4,509 4,609 4,710 4,814 42,742 1 Capital Savings 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598 2 2,178 2,178 2,178 2,178 2,178 2,178 2,178 2,178 2,178 3 2,226 2,226 2,226 2,226 2,226 2,226 2,226 2,226 4 2,275 2,275 2,275 2,275 2,275 2,275 2,275 5 2,325 2,325 2,325 2,325 2,325 2,325 6 2,376 2,376 2,376 2,376 2,376 7 2,428 2,428 2,428 2,428 8 2,482 2,482 2,482 9 2,536 2,536 10 2,592 -------------------------------------------------------------------------------------------------------- Total Capital Savings 1,598 3,776 6,002 8,276 10,601 12,977 15,405 17,887 20,423 23,015 119,961 Rev Req Savings 216 510 810 1,117 1,431.16 1,752 2,080 2,415 2,757 3,107 16,195 -------------------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 3,184 4,554 4,944 5,342 5,749 6,164 6,589 7,023 7,467 7,921 58,937 Confidential Page 4 of 13
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Other Personnel % Capitalized 0% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100% Reductions Ongoing savings 632 6 Total Savings 474 646 661 675 690 705 721 737 753 769 6,831 O&M Savings 474 646 661 675 690 705 721 737 753 769 6,831 1 Capital Savings - - - - - - - - - - 2 - - - - - - - - - 3 - - - - - - - - 4 - - - - - - - 5 - - - - - - 6 - - - - - 7 - - - - 8 - - - 9 - - 10 - -------------------------------------------------------------------------------------------------------- Total Capital Savings - - - - - - - - - - - Rev Req Savings - - - - - - - - - - - -------------------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 474 646 661 675 690 705 721 737 753 769 6,831 Total Personnel Savings A&G 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719 Customer-Related 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242 T&D 3,184 4,554 4,944 5,342 5,749 6,164 6,589 7,023 7,467 7,921 58,937 Other 474 646 661 675 690 705 721 737 753 769 6,831 -------------------------------------------------------------------------------------------------------- Total 12,365 17,846 19,326 20,040 20,771 21,517 22,279 23,059 23,855 24,669 205,728 Confidential Page 5 of 13
NEES-EUA Savings Summary IS Savings Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Rev Req Rate 28.6% Total Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 33% 67% 100% 100% 100% 100% 100% 100% 100% 100% O&M Savings A&G Applications - - - - - - - - - - - T&D Applications - - - - - - - - - - - Customer Applications - - - - - - - - - - - Mainframe and Network 17 34 52 53 55 56 57 58 60 61 502 Midrange/Servers - - - - - - - - - - - PC/Workstations - - - - - - - - - - - Projects - - - - - - - - - - - Telecommunications - - - - - - - - - - - - ----------------------------------------------------------------------------------------------------------------------------------- Total O&M Savings 17 34 52 53 55 56 57 58 60 61 502 Capital Savings A&G Applications T&D Applications Customer Applications Mainframe and Network Midrange/Servers PC/Workstations Projects (PeopleSoft) - - Telecommunications Total Capital Savings - - - - - - - - - - - 1 Capital Savings - - - - - 2 - - - - - 3 - - - - - 4 - - - - - 5 - - - - - 6 - - - - - 7 - - - - 8 - - - 9 - - 10 - -------------------------------------------------------------------------------------------------------- Total Capital Savings - - - - - - - - - - - Rev Req Savings - - - - - - - - - - - -------------------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 17 34 52 53 55 56 57 58 60 61 502 Confidential Page 6 of 13
NEES-EUA Savings Summary Supply Chain Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Inventory % Capitalized 100% Carrying Cost 13.7% Total Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100% Inventory Reduction 899 Annual Savings 450 919 939 960 981 1,002 1,024 1,047 1,070 1,093 9,485 O&M Savings 0 0 0 0 0 0 0 0 0 0 0 Capital Savings 450 919 939 960 981 1,002 1,024 1,047 1,070 1,093 9,485 Rev Req Savings 62 126 129 131 134 137 140 143 147 150 1,299 ----------------------------------------------------------------------------------------------- O&M +Rev Req Savings 62 126 129 131 134 137 140 143 147 150 1,299 Confidential Page 7 of 13
NEES-EUA Savings Summary 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Procurement % Capitalized 35% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100% Ongoing savings 290 Total Savings 145 296 303 310 316 323 330 338 345 353 3,060 O&M Savings 94 193 197 201 206 210 215 220 224 229 1,989 1 Capital Savings 51 51 51 51 51 51 51 51 51 51 2 104 104 104 104 104 104 104 104 104 3 106 106 106 106 106 106 106 106 4 108 108 108 108 108 108 108 5 111 111 111 111 111 111 6 113 113 113 113 113 7 116 116 116 116 8 118 118 118 9 121 121 10 123 ----------------------------------------------------------------------------------------------- Total Capital Savings 51 154 260 369 480 593 708 827 947 1,071 5,460 Rev Req Savings 7 21 35 50 65 80 96 112 128 145 737 ----------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 101 214 232 251 270 290 310 331 352 374 2,726 Confidential Page 8 of 13
NEES-EUA Savings Summary 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Contractor Services % Capitalized 35% Rev Req Rate 13.5% Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100% Ongoing savings 27 Total Savings 14 28 28 29 29 30 31 31 32 33 285 O&M Savings 9 18 18 19 19 20 20 20 21 21 185 1 Capital Savings 5 5 5 5 5 5 5 5 5 5 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 Total Capital Savings 5 14 24 34 45 55 66 77 88 100 508 Rev Req Savings 1 2 3 5 6 7 9 10 12 13 69 Total O&M + Rev Req Savings 9 20 22 23 25 27 29 31 33 35 254 Confidential Page 9 of 13
NEES-EUA Savings Summary 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Vehicles % Capitalized 0% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100% Ongoing savings 150 Total Savings 75 153 157 160 164 167 171 175 179 182 1,583 O&M Savings 75 153 157 160 164 167 171 175 179 182 1,583 1 Capital Savings 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 0 3 0 0 0 0 0 0 0 0 4 0 0 0 0 0 0 0 5 0 0 0 0 0 0 6 0 0 0 0 0 7 0 0 0 0 8 0 0 0 9 0 0 10 0 ----------------------------------------------------------------------------------------------- Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0 Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0 ----------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 75 153 157 160 164 167 171 175 179 182 1,583 Total SCM Savings Inventory 62 126 129 131 134 137 140 143 147 150 1,299 Procurement 101 214 232 251 270 290 310 331 352 374 2,726 Contractor Services 9 20 22 23 25 27 29 31 33 35 254 Vehicles 75 153 157 160 164 167 171 175 179 182 1,583 ----------------------------------------------------------------------------------------------- Total 247 513 539 566 594 622 651 680 710 741 5,862 Confidential Page 10 of 13
NEES-EUA Savings Summary Facilities Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total % Capitalized 0% Rev Req Rate 13.5% Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% Phase-in 0% 100% 100% 100% 100% 100% 100% 100% 100% 100% Ongoing Savings 4,179 Total Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001 O&M Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001 1 Capital Savings 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 0 3 0 0 0 0 0 0 0 0 4 0 0 0 0 0 0 0 5 0 0 0 0 0 0 6 0 0 0 0 0 7 0 0 0 0 8 0 0 0 9 0 0 10 0 ----------------------------------------------------------------------------------------------- Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0 Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0 ----------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001 Confidential Page 11 of 13
NEES-EUA Savings Summary Non-Labor A&G Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total % Capitalized 0% Rev Req Rate 13.5% Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% A&G Overheads 486 690 733 749 766 783 800 818 835 854 7,514 Advertising 273 279 285 291 298 304 311 318 325 332 3,017 Association Dues 82 84 86 88 89 91 93 95 98 100 906 Benefits Administration 0 0 52 53 55 56 57 58 60 61 451 Corporate Governance 787 804 822 840 859 877 897 916 937 957 8,697 Financing Costs and Fees 272 278 284 290 297 303 310 317 324 331 3,006 Insurance 646 660 675 690 705 720 736 752 769 786 7,139 Professional Services 905 925 945 966 987 1,009 1,031 1,054 1,077 1,101 10,001 Regulatory Expenses 57 58 60 61 62 64 65 66 68 69 630 Total Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359 O&M Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359 1 Capital Savings 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 0 3 0 0 0 0 0 0 0 0 4 0 0 0 0 0 0 0 5 0 0 0 0 0 0 6 0 0 0 0 0 7 0 0 0 0 8 0 0 0 9 0 0 10 0 ----------------------------------------------------------------------------------------------- Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0 Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0 ----------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359 Confidential Page 12 of 13
NEES-EUA Savings Summary Cost to Achieve Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Transaction Costs Bankers fees 7,500 7,500 Legal fees 3,500 3,500 D&O liability tail coverage 400 400 Total Transaction Costs 11,400 - - 11,400 Personnel Costs Separation / Retention 25,850 8,100 1,200 35,150 Relocation, Retraining, Reorientation and Miscellaneous 4,950 4,950 Total Personnel Costs 30,800 8,100 1,200 40,100 Transition Costs Internal/Outside Support 2,810 2,810 Communications 500 500 Facilities Consolidation 750 250 1,000 Other 250 250 Total Transition Costs 4,310 250 - 4,560 Information Systems Systems Integration and Data Center Consolidation 6,600 6,600 Meter Reading Hardware 600 600 Telecommunications Costs 350 350 Total Information Systems Costs 7,550 7,550 Total Cost to Achieve 54,060 8,350 1,200 63,610 Confidential Page 13 of 13
Narragansett Electric BVE/Newport Electric M.D.T.E. Docket No. 99-_____ Exhibit DJH-2 Exhibit DJH-2 Supporting Working Papers (Non-Confidential) Exhibit DJH-2 Information Systems Savings
Software comparisons Confidential - ---------------------------------------------------------------------------------------------------------------------- Application NEES EUA Comments - ---------------------------------------------------------------------------------------------------------------------- Corporate, Financial, and o Walker o Various financial packages Administrative Systems - Significant programming/ - IVIS (AP, 1993, Y2K customization has upgrade scheduled improved speed 1Q99) - Works well for NEES' - GEAC (Fixed assets, 1988) business model (intracompany billing, etc.) - Limited decision support - In-house S/W (Purchasing/ capabilities Materials Mgmt, 1992) - Expandable for similar - Lawson (General Ledger, 12/98) business model o Focus for 1999 on Y2K upgrades - ----------------------------------------------------------------------------------------------------------------------- HR/Payroll o PeopleSoft o CYBORG - Installation complete in - Y2K upgrade in 1999 early 1999 - Expandable, but license may be restrictive - ----------------------------------------------------------------------------------------------------------------------- 2 Software comparisons Confidential - ----------------------------------------------------------------------------------------------------------------------- Application NEES EUA Comments - ----------------------------------------------------------------------------------------------------------------------- Customer System o CIS - developed in-house o CIS - developed in-house - GUI front-end placed - GUI front-end placed on mainframe system on mainframe system - Expandable, but only - Major upgrade 1997 for one dimensional (e.g., electric only) - Integrated with Radix customers hand-held meter reading devices - ----------------------------------------------------------------------------------------------------------------------- Operational Systems o Numerous o Numerous - Many systems running - Many systems running on midrange and on mainframe mainframe - Intergraph digital - Major GIS system topology mapping implementation half system complete - Map-based trouble reporting system - -----------------------------------------------------------------------------------------------------------------------
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Hardware comparisons Confidential - ----------------------------------------------------------------------------------------------------------------------- Device NEES EUA - ----------------------------------------------------------------------------------------------------------------------- Mainframes o IBM 390 SP; CMOS 4 engines 220 o Amdahl 45 MIPS MIPS - Expandable up to 540-600 MIPS - ----------------------------------------------------------------------------------------------------------------------- Midrange o IBM RS6000 - Runs decision support, PeopleSoft and retail applications - ----------------------------------------------------------------------------------------------------------------------- Servers o DEC alpha and IBM AIX o Sun (Unix) o Few Digital VAXes left - ~60 o Compaq, Gateway o Migrating to NT o Approximately 20 servers total - ----------------------------------------------------------------------------------------------------------------------- PCs o 2500 Pentium PCs o 600 Pentium PCs (Gateway, Compaq) o Additional 400 devices o 150 "Dumb" terminals - -----------------------------------------------------------------------------------------------------------------------
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System environment comparisons Confidential - ----------------------------------------------------------------------------------------------------------------------- Device NEES EUA - ----------------------------------------------------------------------------------------------------------------------- Mainframes o VMS, IMS, CICS, DB2 o VMS, CICS, Sybase - ----------------------------------------------------------------------------------------------------------------------- Servers o Unix (primary), NT (becoming o Unix, NT (becoming standard standard) - ----------------------------------------------------------------------------------------------------------------------- Networks o Novell 4.11 o Eliminate TAO e-mail and standardize on MS-Outlook (MS-Exchange-based) - Considering 5.0 o Ethernet 100% - ----------------------------------------------------------------------------------------------------------------------- PCs o Windows 3.1, 95, NT o MS Office - Standard is 95 for A&G positions - Standard is NT for operations positions - -----------------------------------------------------------------------------------------------------------------------
5
Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Savings opportunities - ----------------------------------------------------------------------------------------------------------------------------------- Area Opportunity Savings Assumptions Savings - ----------------------------------------------------------------------------------------------------------------------------------- Applications o Corporate, financial, administrative systems: - Integrate EUA data into Walker - No incremental license fees for -> NEES - Discontinue EUA's financial - Reduce 1/3 of EUA's financial - 3 positions systems applications support positions - Move data onto NEES' - Reduce 100% of EUA's HR and - 1 position PeopleSoft system payroll applications support - Discontinue EUA's CYBORG -> positions HR and payroll system ---------------------------------------------------------------------------------------------------------- o Customer and related systems: - Integrate EUA call center - Reduce 1/3 of EUA's call center - 3 positions applications into NEES' system -> applications support positions - Discontinue EUA's CIS systems ---------------------------------------------------------------------------------------------------------- o T&D systems: - Migrate EUA's work -> - Reduce 1/3 of EUA's T&D - 3 positions management system to NEES' applications support positions WIN system - Migrate topological info from EUA's Intergraph into NEGIS and re-digitize if appropriate - Discontinue EUA's T&D systems - ----------------------------------------------------------------------------------------------------------------------------------- 6 Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Savings opportunities - ----------------------------------------------------------------------------------------------------------------------------------- Area Opportunity Savings Assumptions Savings - ----------------------------------------------------------------------------------------------------------------------------------- Hardware/System o Data center/mainframe: Software - Close EUA's data center -> - Reduce EUA's data center and - 5 positions tech support positions by 50% - Reduce EUA's associated $2M - $1M non-labor IS cost for mainframe maintenance, S/W licenses, and disaster recovery by $1M; remaining $1M to focus on software licenses and support ---------------------------------------------------------------------------------------------------------- o Midrange system: - - - - - ---------------------------------------------------------------------------------------------------------- o Servers/network: - - - ---------------------------------------------------------------------------------------------------------- o PCs/workstations: - Reduce end-user/help desk -> - Reduce EUA's help desk/end - 1 position support staff user support by 20% - ----------------------------------------------------------------------------------------------------------------------------------- 7 Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Savings opportunities - ----------------------------------------------------------------------------------------------------------------------------------- Area Opportunity Savings Assumptions Savings - ----------------------------------------------------------------------------------------------------------------------------------- Telecommunications o Integrates NEES's and EUA's -> - Reduce 15% of EUA's network - 1 position telecommunications networks support positions - ----------------------------------------------------------------------------------------------------------------------------------- Facilities o Cost savings captured in the -> - Cost savings captured in closing of West Bridgewater; IS Facilities section is a portion o Integrate EUA's bill printing, -> - Cost avoidance of outsourcing - $250K stuffing, and mailing operations bill printing, stuffing, and into NEES' operations mailing (one additional resource required is already reflected in office services) - -----------------------------------------------------------------------------------------------------------------------------------
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Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Cost to achieve - ----------------------------------------------------------------------------------------------------------------------------------- Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost - ----------------------------------------------------------------------------------------------------------------------------------- Applications o Corporate, financial, administrative systems: - System "combination" costs -> - Cost for application and - $2.1 M1 data conversion --------------------------------------------------------------------------------------------------------------- o Customer and related systems: - System "combination" costs -> - Cost for application and - $2.1M1 data conversion - Outfit meter readers with -> - 55 devices @$10,000 each - $0.6M ITRON devices (including device, training, programming, transfer of routing info) --------------------------------------------------------------------------------------------------------------- o T&D systems: - System "combination" costs -> - Cost for application and - $2.1M1 data conversion - ----------------------------------------------------------------------------------------------------------------------------------- - --------------- 1 Prorated from base of $6.3M. 9 Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Cost to achieve - ----------------------------------------------------------------------------------------------------------------------------------- Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost - ----------------------------------------------------------------------------------------------------------------------------------- Hardware/System o Data center/mainframe: Software - Discontinuation of EUA -> - Closing cost -$0.3M data center - Increase NEES' processing -> - Turn up 2 additional - - $1.0M power CMOS enginees (cost of H/W & S/W) --------------------------------------------------------------------------------------------------------------- o Midrange system: - Transfer midrange -> - Turn up 2 additional - - $0.2M application to NEES nodes of IBM RS6000 midrange system --------------------------------------------------------------------------------------------------------------- o Servers/networks: - Network reconfiguration -> - - - --------------------------------------------------------------------------------------------------------------- o PCs/workstations: - No costs incurred -> - Freed-up PCs available to - - replace dumb terminals - ----------------------------------------------------------------------------------------------------------------------------------- 10 Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Cost to achieve - ----------------------------------------------------------------------------------------------------------------------------------- Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost - ----------------------------------------------------------------------------------------------------------------------------------- Telecommunications o Costs to integrate both companies' - $100K networks o Customer service center switch: - Switch capacity sufficient - $250K Cost to reconfigure EUA's tie-lines to handle EUA's and reprogram switch additional inbound calls - ----------------------------------------------------------------------------------------------------------------------------------- Facilities o Costs are captured in the closing of West Bridgewater facility - -----------------------------------------------------------------------------------------------------------------------------------
11 Purchases 35 1 12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 35 Annual materials and equipment purchases by commodity class a) T&D related b) Corporate and other See attached. ADDRL #35 35 2 N35 Annual materials and equipment purchases by commodity class, T&D Issues from M&S Total T&D Corp. & Stock, Cap,&Exp. Purchases Other Blackstone Valley 990,780 442,254 1,433,034 195,459 Eastern Edison 2,404,158 840,142 3,244,300 377,438 Newport Electric 604,470 187,815 792,285 101,099 -------------------------------------------------- 3,999,408 1,470,211 5,469,619 673,996 ========= ======= Meters 998,000 Transformers 2,249,000 Inputs
EUA DISTRIBUTION COMPANIES & MONTAUP TRANSMISSION 1999 Capital Budget BVE EECo NECo VEC Blankets: Priority Priority Req 1999 1999 Cumm Distrib Transm No Code No Title Expenditures Expenditures OH Lines UG Substation OH Lines 1 1-99 New Business $4,484.0 $ 4,484.0 30,400 11,500 0 0 2 2-99 Routine Distribution Imps/Rets 2,445.0 6,929.0 20,900 2,060 0 0 3 3-99 Meter Devices & Installations 998.0 7,927.0 0 0 0 0 4 4-99 Line Transf Capacitors & Regs 2,249.0 10,176.0 0 0 0 0 5 5-99 Distribution Substations 235.0 10,411.0 67 0 1,634 0 6 6-99 Street & Area Lighting 786.9 11,197.9 5,960 1,090 0 0 7 7-99 Building Imps/Rets 108.1 11,306.0 0 0 0 0 8 8-99 Transmission Lines & Subs 388.0 11,694.0 400 0 0 45000 9 9-99 Damages and/or Failures 534.0 12,228.0 4,750 2,192 0 0 10 10-99 Furniture, Tools, Lab & Comm 263.9 12,491.9 0 0 0 0 Equip 11 12-99 Land & Land Rights 90.0 12,581.9 0 0 0 0 12 13-99 Misc. Production Imps/Rets 0.0 12,581.9 0 0 0 0 Blanket Subtotal $12,581.9 62,477 16,842 1,634 4,500 Specifics: General Projects 1 HP.B Fire Alarm Replacement $35.0 $35.0 0 0 0 0 2 HP.O BVE Operations Roof 120.0 155.0 0 0 0 0 Replacement Specifics: Substation Projects 1 HP.D Dupont Sub Capacitor Bank $102.0 $102.0 0 120 269 0 Addition 2 MP.C 690 Swansea DFP Upgrades 76.9 178.9 0 0 696 0 3 MP.C Scituate Substation Relay 44.0 222.9 0 0 192 0 Upgrades 4 MP.C Riverside Substation Rebuild 1,108.0 1,330.9 0 576 4,416 0 5 MP.C Mill St. Substation Relay 61.0 1,391.9 0 0 288 0 Upgrades 6 MP.C Jepson Sub Ground Gnd 143.0 1,534.9 0 0 864 0 Replacement 7 MP.C 199 Jepson Sub Bus Thermal 65.5 1,600.4 0 0 290 0 Upgrade 8 MP.C Install 2nd Transformer at 222.0 1,822.4 0 0 1,728 0 Eldred 9 MP.C 198 Gate II Overcurrent Relay 78.0 1,900.4 0 0 851 0 Upgrade 10 LP.A Repl Jepson Sub Breaker 3729 55.0 1,955.4 0 0 346 0 11 LP.B Repl Gate II Transformer 33.0 1,988.4 0 0 288 0 Bushings Substation Subtotal $1,988.4 0 696 10,228 0 Specifics: Transmission Projects 1 HP. EMI/Tiverton Power Plant $1,070.0 $1,070.0 0 0 0 6,400 2 HP. EMI/Tiverton Power Plant 260.0 1,330.0 0 0 1800 0 3 HP. 839 EMI/Tiverton Power Plant 1,950.0 3,305.0 0 0 4 HP. 837 EMI/Dignton Interconnection 220.0 3,525.0 0 0 5 HP. ANP Power Plant 1,135.0 4,660.0 0 0 3,200 440 6 HP.D 238 Sherman Rd Sub Foundations 40.0 4,700.0 0 0 2 0 7 HP.D Belmont Replace Switch S1-1 29.0 4,729.0 0 0 0 307 8 MP.C Washington Substation Doub 2,100.0 6,829.0 0 180 3,643 4,151 End Transmission Subtotal $6,829.0 0 180 8,893 18,998 Specifics: Distribution Projects 1 HP.A Gate II Feeder Addition $86.0 $86.0 220 170 220 0 2 HP.C 692 Marvel St. Swansea Road Imps 18.9 104.9 75 0 0 0 3 HP.C 283 Main St. Easton - Road 74.8 179.7 302 128 0 0 Widening 4 HP.C 691 Bank St. Swansea Road Imps. 86.1 265.8 180 0 0 0 Phase II 5 HP.C 1999 Street Light Conversion 385.0 650.8 1,200 800 0 0 Program 6 HP.C 1999 St. Light Conversion, 57.0 707.8 300 0 0 0 Portsmouth 7 HP.D Washington Substation Feeder 220.0 927.8 550 150 0 0 Addition 8 HP.D 196 Reliability Imps. Back yard 22.0 949.8 100 0 0 0 Construction 9 HP.D 293 North Main St. Rebuild 42.5 992.3 0 0 0 0 10 HP.D R270 Main St. Rebuild, Brockton 46.8 1,039.1 0 0 0 0 11 HP.D 197 Conversion - Senes St. Light 60.0 1,099.1 250 420 0 0 Circuits 12 HP.D Condenmed Pole Replacement 580.0 1,679.1 7,600 0 0 0 - 1999 13 HP.D Condemned Pole Replacement 220.0 1,899.1 2,850 0 0 0 - 1999 14 MP.C 278 Storm Proofing 618.4 7,447.4 5,719 0 0 0 15 MP.C Modern Furniture Vault 147.0 7,594.4 0 1,200 0 0 16 MP.C Distribution Automation 325.0 7,919.4 700 0 640 0 17 MP.C Distribution Automation 650.0 8,569.4 1,400 0 1,280 0 18 MP.C 269 Condemned Poles Easton 166.1 8,735.5 1,789 0 0 0 19 MP.C R274 Belmont St Rebuild, Brockton 199.1 8,934.6 558 200 0 0 20 MP.C 261 #6 CU Replacement-Scituate 232.0 9,166.6 2,167 0 0 0 21 MP.C 262 #6 CU Replacement-Brockton 432.0 9,598.6 3,728 0 0 0 22 LP.A 181 Install Neutral Wire, 51.0 9,649.6 450 0 0 0 Portsmouth 23 LP.A 679 Cable Removal-Fall River 46.0 9,695.6 0 4,380 0 0 24 LP.A 675 23kV Cable Removal-Fall 32.3 9,727.9 0 4,000 0 0 River 25 LP.B 178 Remove 23kV Cable 13.5 9,741.4 0 270 0 0 Distribution Subtotal $4,811.5 30,138 11,718 2,140 0 Total dollars/Manhours $26,365.8 92,615 29,436 22,895 23,498 Budgeted Total Available Manhours 78,235 19,673 21,206 4,121 Surplus/Deficit Manhours (14,380) (9,763) (1,689) 19,377 EUASC MH Requirements 0 0 0 0 Surplus (Deficit) Manhours (14,380) (9,763) (1,689) 19,377 including EUASC * Note There is an estimated contribution of $128,000 from EMI on this project ** Note There are 250 Electrical Maintenance manhours associated with this job *** Note There are 3,500 Electrical Maintenance manhours associated with this job
Inventory 55 1 DDRL (12/17/98) 55. Details of how materials are stocked, ordered and distributed including: - value of T&D inventory - degree of centralization - quantities of materials in field locations - use of vendors to provide materials in emergencies Value of T&D inventory / Quantities of materials stored in field locations Inventory Value 6/30/98 Lincoln $906,287 Brockton $941,766 Hanover $244,522 Fall River $725,489 Newport $776,757 -------- System Total $3,594,821 Input Degree of centralization This is answered in ADDRL (12/19/98) #39. Use of vendors to provide materials in emergencies In addition to maintaining a safety stock, we make an assessment of our critical material needs prior to a forecasted storm and contact vendors for immediate re-supply where appropriate. Our vendors have been responsive in the past and we have not experienced a shortage of critical materials in any storm or other emergency in at least the last ten years. EUA does not have alliances with any vendors to maintain inventory on our behalf. Inventory 39R 1 ADDRL (12/19/98) 39. High-level overview of central stores, e.g. value of inventory, annual receipts and issues, square footage, expandability. EUA operates on a "main stocking" philosophy. A number of stock items are stocked at one of the retail company stockrooms in quantity sufficient to provide for the needs of the other retail locations. The daily courier or scheduled trips by the stockroom stake-body vehicle are used to deliver this material where needed. We are presently studying a central warehouse concept. The year-to-date monthly average inventory value as of 6/30/98 (excluding Somerset plant) is $3,552,719. The year-to-date receipts as of 6/30/98 annualized are $4,391,220. The year-to-date issues as of 6/30/98 annualized are $4,613,724. The Inventory Turns Ratio as of 6/30/98 is 1.30. Inventory Turns Ratio is defined as Total Inventory Issues for the last 12 months divided by the 12 month rolling average Inventory level. All items in inventory are included. This includes safety stock, scrap, emergency spares and obsolete items. Inventory at Somerset Station excluded. The Carrying Cost for inventory is approximately 53% as of 10/31/98. Carrying Cost (or Stores Clearing Rate) is defined as the 12 month rolling average of the sum of storeroom expenses, storeroom overheads, related EUASC expenses, inventory over/short, lobby stock, storeroom electric use, misc. journal entries applied to all stock items issued by the storeroom. We maintain stockrooms at all operating centers. The square footage is not readily available. The Lincoln and Newport stockrooms provide for some level of expandability. ADDRL (12/19/98) 39 1 39. High-level overview of central stores, e.g. value of inventory, annual receipts and issues, square footage, expandability. EUA operates on a "main stocking" philosophy. A number of stock items are stocked at one of the retail company stockrooms in quantity sufficient to provide for the needs of the other retail locations. The daily courier or scheduled trips by the stockroom stake-body vehicle are used to deliver this material where needed. We are presently studying a central warehouse concept. Total value of inventory (excluding Somerset plant) is $3,600,000. Annual receipts are $730,000. Annual issues are $760,000. Inventory Turns Ratio (no exclusions) as of 10/31/98 is 1.30. We maintain stockrooms at all operating centers. The square footage is not readily available. The Lincoln and Newport stockrooms provide for some level of expandability. DDRL (12/17/98) 56 1 56. Details of how the Company manages distribution transformer inventory. Transformers are pre-capitalized. The inventory level of transformers is managed by the Materials Management Department. Similar to regular inventory items, minimums and maximums are established for the most frequently used distribution transformers. All purchases are coordinated by Materials Management. Engineering provides input on planned requirements. A goal of 4% in-stock to in-service units has been established for Materials Management. Transformer refurbishing is performed by an outside firm. Refurbishing and junking are coordinated by Materials Management. DDRL (12/17/98) 58 1 58. List of the ten largest contracts the Company and its utility subsidiaries have with suppliers of O&M related equipment and services. Contract Services DESCRIPTION 1998 VENDOR NAME OF SERVICE PROJECTED INPUTS Asplundh Tree Expert Co. Vegetation Control $936,240 $000 Barnes Tree Service Vegetation Control 540,220 R.A. Gill Tree Service Vegetation Control 319,604 Northern Tree Service Vegetation Control 418,796 2,383 New England Tree Vegetation Control 99,253 Vegetation, Inc. Vegetation Control 69,150 Collins Crane Rigging 1,325 Clean Harbors Environmental 60,973 Environ. Protect. Serv. Transformer Refurbishin 75,833 198 QSC Tower Painting 60,000 ADDRL #38 N38 38 BLACKSTONE VALLEY ELECTRIC 2 PROFESSIONAL SERVICES VENDOR NAME DESCRIPTION OF SERVICE 1997 Asplundh Tree Trimming 56,222 Barnes Tree Services Tree Trimming 140,399 Blackstone Valley Security Security Services 0 Clean Harbor Environmental 19,603 Coopers & Lybrand Accounting 34,145 Credit Bureau Collection Fees 20,959 Dickstein, Shapiro & Moris Legal Financial Collection Collection Fees 1,149 Isaacson, Rosenbaum Legal 743,588 McDermott, Will & Emery Legal 32,576 Northern Tree Service Tree Trimming 491,290 Ocean State Janitorial Cleaning 40,408 Osmose Wood Press Pole Treatment/Inspection 448 Stanley Bleeker, Esq. Legal 0 Tillinghast, Collins & Graham Legal 1,911 (A) Colflax Packing Conservation 1,214 (A) Delta Electric Motor Conservation 639 (A) RISE Conservation 7,690 (A) Slater Dye Works Conservation 17,313 ------- 1,609,534 ========= (A) These vendors participated in Eastern Edison's conservation, load, management programs. management programs. NOTE: The source for this information was based on o&m codes 9, 10, 11 & 16. Prepared by Michelle Uzzo 12/22/98
EASTERN EDISON COMPANY 38 PROFESSIONAL SERVICES 3 VENDOR NAME DESCRIPTION OF SERVICE 1997 American Staffing Assoc. Employment 118,240 Asplundh Tree Trimming 919,253 Barnes Tree Service Tree Trimming 140,782 Clean Harbors Environmental Coopers and Lybrand Accounting 62,883 Duff & Phelps Consulting 40,000 Environmental Protection Service Maintenance 44,555 First Financial Resources Collection Fees 33,933 First Security Services Security Hanson Police Dept. Police Detail 31,478 J. D. Payroll Services Temp Services MASS Save Consulting 342,286 McDermott,Will & Emery Legal 1,209,449 Misc. Contract Services* 1,605,966 Misc. Engineering* 38,605 Misc. Legal* 12,155 Miscellaneous* 314,463 Osmose Wood Press Pole Treatment/Inspection Pembroke Police Dept. Police Detail R.A. Gill Tree Service Tree Trimming 227,341 R.E. Tilgren Tree Trimming 46,695 Read, Adami, Kaiser Legal 72,599 Rockland Police Dept Police Detail 26,218 Service Master Maintenance 29,796 State Street Bank & Trust Trustee/Administrative Fee Suburban Contract Cleaning Town of Bridgewater Police Detail Town of Easton Police Detail 56,526 Town of Norwell Police Detail 42,745 Town of Scituate Police Detail Town of Stoughton Police Detail (A) Conservation Services Group Conservation 361,903 (A) Demand Mgmt Conservation (A) Energie Innovation Inc. Conservation 84,095 (A) Energy Conservation Conservation 123,124 (A) Energy Federation Conservation 306,904 (A) Fall Realty & Harris Energy Conservation 38,353 (A) Fleet Bank Conservation 28,182 (A) Harris Energy Systems Conservation 489,801 (A) J&R Industrial Wiring Conservation 206,124 (A) Main Street Textiles Conservation 133,990 (A) MUPAC Corp & Harris Energy Conservation 26,114 (A) National Resource Mgmt. Conservation 375,923 (A) Relocation Resources, Inc. Conservation 61,985 (A) Shaws Supermarkets Inc. Conservation 168,265 (A) Star Market & Harris Energy Conservation 31,080 (A) Stop & Shop Supermarket Co. Conservation 49,799 (A) Ware Rite & Harris Energy Conservation 32,759 (A) Whaling Mfg. Co., Inc. Conservation 29,235 ------- 7,963,604 =========
* Aggregate amounts to any one entity less than $25,000 have been accumulated in this description. (A) These vendors participated in Eastern Edison's conservation, load, management programs. management programs. Note: The source for this information was based on O&M codes 9, 10, 11 & 16. NEWPORT ELECTRIC CORPORATION 38 PROFESSIONAL SERVICES 4 VENDOR NAME DESCRIPTION OF SERVICE 1997 Barnes Tree Services Tree Trimming 187,206 Clean Harbor Environmental 11,989 Coopers & Lybrand Accounting 30,982 Credit Info Collection Fees 12,118 McDermott, Will & Emery Legal 16,803 Morgan, Brown & Joy Legal 340 RISE Conservation 141,057 Tillinghast, Collins & Graham Legal 45,587 ------ 446,062 ======= NOTE: The source for this information was based on o&m codes 9, 10, 11 & 19. EUA Service Corp. 38 PROFESSIONAL SERVICES 5 (Account # 923)
VENDOR NAME DESCRIPTION OF SERVICE 1997 McDermott, Will & Emery Legal 359,773 First Security Services Security 124,975 Contract Cleaning Collaborative Cleaning Eastern Edison Company Arborist/Technical Trainers 351,846 Salomon Brothers Inc. Investment Services 107,956 Media Concepts Printing Services 114,897 Norfolk Date Data Processing Time Cards Cambridge Reports, Inc. Customer Services 70,560 J. Flanagan & Co. Legislative Activity 48,000 DRI McGraw-Hill Newport Electric Corp. Arborist/Technical Trainers Twenty First Century AUC Management Consultants Consulting Misc Legal * 82,677 Misc Accounting 68,988 Misc EDP * 41,871 Misc Building & Maintenance 182,203 Other * 421,494 Misc Engineering 788 --- 1,956,038
* Payments made to payee is less than $100,000 Amounts in Bold print are estimates based on the average of 1996 & 1997. Prepared by Michelle Uzzo 12/22108 o:\profsvs VEHICLES 56 DDRL (12/17/98) 1 54. Details of vehicles including: - types and numbers of vehicles - age of vehicles - maintenance programs and replacement criteria - fuel management programs - criteria for assigning vehicles to non-physical workers 12/15/98 TYPE OF FLEET VEHICLE COUNT BUCKET TRUCK, MATERIAL HANDLER 51 BUCKET TRUCK, LIGHT-DUTY 15 DIGGER -DERRICK TRUCK 8 VAN, LARGE STEP TYPE 25 VAN, SMALL 68 DUMPTRUCK 8 STAKE-BODY TRUCK 2 EFFER CRANE TRUCK 3 PICKUP TRUCK 110 SEDAN 52 TRAILER 62 MOBILE SUBSTATION, XFMR OR REGUL. 6 TRACTOR 5 FORKLIFT 11 TRACK VEHICLE 1 CRANE TRUCK 2 TANKER TRUCK 1 SPECIAL EQUIPMENT* 24 TOTAL 454 * Includes powered reel trailers, puller-tensioners, woodchippers, generator trailer, cement mixer, tank trailer, test equipment trailers, waterpump trailer, compressors. AVERAGE AGE OF VEHICLES MONTHS All Vehicles (excl. trailers, spec. equip.) 93 All Units 120 DDRL (12/17/98) 54 2 54. Cont'd MAINTENANCE PROGRAMS AND REPLACEMENT CRITERIA EUA adheres to a preventative maintenance program based on manufacturers' recommendations, generally accepted automotive industry practices and experience related specifically to a particular vehicle or class of vehicles. A computerized maintenance management system (FleetTracker) is used to track vehicle usage in terms of miles and/or hours and scheduled maintenance periods to determine when "A", "B" or "C" level maintenance procedures are due. The replacement of a vehicle is considered based on the following criteria: Aerial devices are considered for replacement based on age and condition of the boom and chassis (particularly with respect to fiberglass strength and metal fatigue). These vehicles are usually replaced at the 12-14 year point. Other large vehicles (e.g. step vans, stakebody trucks, etc.) are considered for replacement based on condition of chassis and body. These vehicles are usually replaced at the 12-14 year point. Small vehicles (e.g. panel vans, pickups, etc.) are considered for replacement based on condition of body and engine maintenance needs and are typically replaced at a point above 130,000 miles. FUEL MANAGEMENT PROGRAMS PetroVend fuel management systems and VeederRoot leak detection systems are installed at all EUA gasoline fueling stations. DDRL (12/17/98) 54 3 54. Cont'd CRITERIA FOR ASSIGNING VEHICLES TO NON-PHYSICAL WORKERS Vehicles with two-way radios and cellular phones are assigned on a 24-hour basis to firstline supervisors who are in the field most of the workday, who must be visible to customers and within the communities, and who have on-call and emergency responsibilities. Vehicles with two-way radios and cellular phones are assigned on a 24-hour basis to certain management personnel in Operations due to their emergency responsibilities. Vehicles are provided to certain executives as part of their compensation package. Other non-physical workers, such as engineers and distribution service coordinators, have access to company vehicles during the workday. NEES Supply Chain in $000 Overall Purchases 1997 T&D purchase order spending 217,528 incl supplies, materials, services 1998 estimate 211,979 1997 po and non-po spending Cable 16,047 Transformers 13,908 Wood poles 3,288 Meters and accessories (po only) 3,585 Contractor Services 1997 veg. mgt 17,609 Inventory 8/98 RBU inventory 14,211 9/98 distribution transformers 14,123 12/97 meters 2,762 Vehicles Passenger 35 Trucks 1504 (incl. 318 aerial)
Exhibit DJH-2 Facilities FACILITIES in $000 Prelim DDRL #33 BOSTON W. BRIDGEWATER Miscellaneous 413 Note: WB excludes internal labor M&S, Stores 170 of $1.1 million Outside Svcs 111 IS 9 Rents 346 34 Contract Services 6 467 Overheads 31 Sub-total 383 1,204 1,587 Ownership cost for WB 2,470 (levelized) Total 4,057 Escalate to 2000 1.03 - --------------------------------------------------------------------------- Total savings in 2000 4,179 - --------------------------------------------------------------------------- BOSTON lease exp 1999; assume no change in cost per sq ft WEST BRIDGEWATER WESTBOROUGH room for 300-350 Levelized cost 2,470 additional people 60,000 sq. ft. structures and improvements 18,860 life 40 year carrying cost 10.50% Annual Westborough cost incl.lease ($3.6) property tax 2.50% $5 million
PDDRL 12/17/98 33. List of all facilities owned or leased, including the following: (a) Address: (b) Occupied space in square feet; space available for expansion; (c) Description of the lease, including monthly cost, terms, and a description of assignability or change of control provisions; (d) Number of employees using the facility, including detail as to department/function. (e) If owned, estimate of the current market value; (f) Whether or not the facility is known to have experienced any instances of oil or hazardous material releases which would subject the facility to response actions under the Massachusetts or Rhode Island waste site cleanup regulations. If such releases have occurred, provide a summary of the status of the remedial response, any future costs expected to be incurred in addressing the release(s)and the duration of the response action(s). (g) Provide a statement of the presence and condition of asbestos, lead or other hazardous substances that may be present in the facility and, if present, the plan and costs for maintaining or removing the substances Note 1 Note 3 Company (a) (b) (c) (d) (e) (f) (g) =========================================================================================================================== Eastern Edison 161 Mulberry St. $23,000 N/A 102 $750,000 None None Brockton Mass 82 Hartwell St $20,250 N/A 67 $550,000 None None 60 Hartwell St. $18,500 $250,000 Note 5 River St. $11,200 $215,000 Note 6 Fall River Mass 10 Phillips Lane $14,400 N/A 21 $1,500,000 None None Hanover Mass Blackstone Valley 642 Washington Highway $60,000 N/A 94 $2,000,000 Note None Electric Lincoln, Rhode Island 4 Newport Electric 12 Turner Road Note 7 $35,000 N/A 49 $1,500,000 None None Middletown, Rhode Island EUA Service EUA Corporate Offices $12,800 Note 2 20 N/A None None Corporation One Liberty Square Boston, Mass EUA System Operating $133,000 N/A 542 $20,000,000 None None Center 750 West Center Street West Bridgewater Mass Note 1: Available for expansion: Lincoln 12000 sq. Ft., Fall River 8500 sq. ft. Note 2: Boston Office lease and overheads are $382,450 and expires 1999 Note 3: Detail of employees by company, department/function is attached. Note 4: See second page attachment Note 5: Lead Paint Note 6: Asbestos in boiler room Note 7: Leased space to Bank of Newport - $140,000 annual net income.
PDRL OF 12/17/98 continued 33. List of all facilities, owned or leased, indicating the following: a) address; b) occupied space in square feet; space available for expansion; c) description of the lease, including monthly cost, terms, and a description of assighnability or change of control provisions; d) number of employees using the facility; including detail as to department/function; e) if owned, estimate of current market value; f) whether or not the facility is known to have experienced any instances of oil or hazardous material releases which would subject the facility to response actions under the Massachusetts or Rhode Island waste site cleanup regulations. If such releases have occurred, provide a summary of the status of the remedial response, any future costs expected to be incurred in addressing the release(s) and the duration of the response actions(s) g) provide a statement of the presence and condition of asbestos, lead or other hazardous substances that may be present in the facility and, if present, the plan and costs for maintaining or removing the substances. Note 4: Blackstone Valley Electric experienced a release of gasoline in 1989 from an underground storage tank at its Lincoln Operations facility. The release was detected during an annual tightness testing, and was estimated at approximately 100 gallons. Soil and groundwater were impacted. A removal action was performed in 1989, and a groundwater treatment system has been in operation since that time. The zone of contamination has been reduced to a small area and levels of contamination greatly reduced. BVE expects to resolve this matter in 1999 and complete this response action with little additional expense. The costs to complete are not expected to be material.
PDDRL 12/17/98 Facility Expense 33d cont. Company EUA Service Corporation Eastern Edison Blackstone Valley Newport Location Boston W. Bridgewater Brockton Fall River Lincoln Middletown Miscellaneous 413,400 Payroll 1,051,400 90,900 94,300 92,200 84,800 Employee Expense 10,800 500 500 500 500 Education & Training 5,300 500 500 500 500 Materials & Supplies 151,500 19,000 44,500 23,600 12,000 Stores 18,800 10,000 8,900 11,000 9,000 Outside Services 111,000 Information Systems - Hardware 9,400 Rents 345,600 33,500 25,500 500 26,400 8,500 Contract Services 5,850 467,400 104,500 69,900 128,600 59,100 Office Overheads 31,000 33,000 22,000 90,000 28,000 Totals $382,450 $2,272,500 $283,900 $241,100 $372,800 $202,400 System Total $3,755,150
33d Meter OH Property Company Address Union Reading Lines Trouble Meter Garage Stores Maint. Eastern Edison 161 Mulberry St. None X X X X X X X Brockton Mass. 82 Hartwell St. IBEW X X X X X X X Fall River Mass. 10 Phillips Lane None X X X Hanover Mass. Blackstone Valley 642 Washington Highway None X X X X X X X Electric Lincoln, Rhode Island Newport Electric 12 Turner Road BUW X X X X X X X Middletown, Rhode Island
33d UG Substation Radio & System Consumer Company Address Union Lines Maint. Microwave Operations Service Eastern Edison 161 Mulberry St. None X X X Brockton Mass. 82 Hartwell St. IBEW X X Fall River Mass. 10 Phillips Lane None Havoner Mass. Blackstone Valley 642 Washington Highway None X X X X Electric Lincoln, Rhode Island Newport Electric 12 Turner Road BUW X X X Middletown, Rhode Island
PDDRL 12/17/98 33d cont. Company Address Union Function Performed ================================================================================================================================== EUA Service Corporation EUA Corporate Offices None Corporate Executive Offices One Liberty Square Treasury Boston Mass. EUA System Operating Center None Executive - Admin. & Support 750 West Center Street Facilities Management West Bridgewater Mass. Internal Audit Consumer Services Marketing Information Services Human Resources Corporate Communications Corporate Benefits Risk Management Office Services Safety Transmission Services Load Forecasting Power Supply Special Projects Purchasing Material Management Rates Accounting Customer Service Security Real Estate Engineering Transmission and Distribution Somerset Station None Transmission Crews 1606 Riverside Avenue Somerset Mass.
(ALL FROM U13-60) ACC DEPN 12/31/97 @ 12/31/97 NET WB BUILDING 18142620 4015211 14127409 LAND & LAND RIGHTS 717080 0 717080 18859700 4015211 14844489 DEPRECIATION 452158 YEARS 40 COST % OF TOTAL TAX(B) C EUASC COMMON EQUITY 2895346 11.00% 19.50% 0. EUASC LTD 6800000 10.20% 45.81% 9695346 A SHORT TERM 5149143 6.50% 34.69% 14844489 100.00% A - ASSUMED REMAINING BALANCE FINANCED BY EUA SHORT TERM BORROWINGS B - COMBINED TAX RATES (FED AND STATE) OF 40% C - USED RETURN ON COMMON EQUITY OF RETAILS REVENUE REQUIREMENTS DEPRECIATION (% OF UNDEPRECIATED) 3.05% CARRYING COSTS 10.50% COUNTY TAXES 2.50% TOTAL 16.05%
Exhibit DJH-2 Administrative and General Savings -------------------------------------------------------------------- Mercer Management Consulting
A&G Overheads in $000 This savings component reflects miscellaneous overheads, such as office supplies and personal computers; but excludes facilities and benefits related overheads EE BVE NE Total FERC Acct #921 730 394 201 1,325 Office supplies and expenses employees 881 per employee (000) 1.5 (higher for service co only) EUA PC costs configured prices of 1.9-3.4 per unit (in 000) Annualized cost for pc, cell phones, and pagers 640 Savings per employee 3 reduced in $000 in 2000 Savings in 2000 486 162 reductions x 3 Savings in 2001 690 225 cumulative red. X 3 x I.022 Savings in 2002 733 234 cumulative red. X 3 x 1.044
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT 48 Summary of other miscellaneous A&G overheads. See attached.
Summary - Other Miscellaneous and A&G Company 1997 - ------- ---- Blackstone Valley Electric Company $344,714.00 Eastern Edison Company $632,170.00 Newport Electric Corporation $238,947.00 Total $1,215,831.00 ============= Blackstone Valley Electric Company Description 1997 - ----------- ---- Industrial Association Dues $49,591.00 Other Experimental & General Research $339.00 Publishing and Distribution Information and reports as well as other expenses of servicing Outstanding Securities of Respondent. $37,084.00 EUA Service Corporation General and Administrative $161,923.00 R.I. Industrial Revenue Bonds Fee $8,125.00 Employee Training and Seminars $85,298.00 Citicorp Remarketing - R.I. Industrial Bonds $22,344.00 Miscellaneous $10.00 ------------- Total $344,714.00 ============= Eastern Edison Company Description 1997 - ----------- ---- Industrial Association Dues $103,047.00 Other Experimental & General Research $701.00 Publishing and Distribution information and reports as well as other expenses of servicing Outstanding Securities of Respondent. $68,824.00 EUA Service Corporation General and Administrative $314,908.00 Employee Training and Seminars $138,456.00 Service Anniversary Expense $4,864.00 Miscellaneous $1,370.00 ------------- Total $632,170.00 ============= Newport Electric Corporation Description 1997 - ----------- ---- Industrial Association Dues $24,190.00 Other Experimental & General Research $131.00 Publishing and Distribution Information and reports as well as other expenses of servicing Outstanding Securities of Respondent. $18,200.00 EUA Service Corporation General and Administrative $85,579.00 Employee Training and Seminars $41,155.00 Settlement Agreement $58,481.00 Remarketing Expenses $10,146.00 Miscellaneous $1,085.00 ------------- Total $236,447.00 =============
GP6-350 Page 1 of 2 For the Enthusiast Customize It & Buy It! GP6-350 ============================================================ Processor: Intel 350MHz Pentium II Processor w/ 512K Cache Memory: 64MB 100MHz SDRAM expandable to 256MB Monitor: EV700 l7inch color monitor (15.9inch viewable area) Graphics Accelerator: Integrated nVidia 8MB AGP Graphics Accelerator Hard Drive: 10GB Ultra ATA hard drive added: US$60 Floppy Drive: 3.5inch 1.44MB diskette drive (IOMEGA Internal ZIP Drive Deleted) subtracted: US$50 CD-ROM: 13X min./32X max. CD-ROM drive Multimedia Package: Boston Acoustics BA635 Speakers added: US$30 Sound System: Integrated Sound Blaster AudioPCI 64D Case: Mid Tower Case Network Adapter: 3COM PCI 10/100 twisted pair Ethernet Keyboard: 104+ Keyboard Mouse: MS IntelliMouse Mouse; Gateway mouse pad Additional Software: McAfee Anti Virus Software Application Software: MS Office 97, Small Business Edition, on CD w/Bookshelf Operating System: Microsoft Windows 98 Service Program: Gateway Gold Service for PCs (1 yr. Onsite) Tape Backup Unit: TR5 IDE TBU and tape added: US$249 ============================================================ Base Price: US $1599 Configured Price: US $1888 Quantity: 1 Total Price: US $1888 ============================================================ ============================================================ Many Gateway products are custom engineered to Gateway specifications, which may vary from the retail versions of the software and/or hardware in functionality, performance or compatibility. Prices and configurations are subject to change without notice or obligation. The price above does not include shipping and handling or any applicable taxes. After your system has been built (lead times vary), it may be shipped via second-day shipping in the continental U.S. Second-day shipping within the continental U.S. is US$95 for desktops and US$25 for portables. Five-day shipping for Destination (R) Digital Media Computers is US$149. All prices quoted are in U.S. dollars. o I would like to order this system via the World Wide Web. Clicking "Continue" below takes you to our secure server. Gateway uses Secure Sockets Layer (SSL) encryption to assure that all information entered on the next screen --including your credit card number -- can only be understood by us. After thousands of online transactions worth millions of dollars, no Gateway client has ever reported misappropriation of a credit card number protected by SSL technology. Check our article on how SSL works and why we think it's extremely safe to learn more. o Please have a sales representative contact me about this system or other Gateway products. Copyright (C) 1997, 1998 Gateway 2000 Inc. All rights reserved. Please see our ______________________. Please send feedback to ___________________________. GP6-450 Page 1 of 2 For the Enthusiast Customize It & Buy It! GP6-450 ============================================================ Processor: Intel 450MHz Pentium II Processor w/ 512K Cache Memory: 128MB 100Mhz SDRAM expandable to 384 Monitor: VX900T 19inch color monitor (18.0 inch viewable area) added: US$60 Graphics Accelerator: 16MB AGP Graphics Accelerator Hard Drive: 16.8GB 5400RPM Ultra ATA hard drive Floppy Drive: 3.5inch 1.44MB diskette drive & SuperDisk LS-120 w/5 Disks added:US$60 CD-ROM: 13X min./32X max. CD-ROM drive Multimedia Package: Boston Acoustics BA635 Speakers added: US$30 Sound System: Integrated Sound Blaster AudioPCI 64D Fax/Modem: TelePath(R) 56K Modem added: US$129 Case: Tower added: US$50 Network Adapter: 3COM PCI 10/100 twisted pair Ethernet Keyboard: 104+ Keyboard Mouse: MS IntelliMouse Mouse; Gateway mouse pad Additional Software: McAfee Anti Virus Software Application Software: MS Office 97, Professional Edition, on CD added: US$199 Operating System: Microsoft Windows 98 Service Program: Gateway Gold Service for PCs (lyr. Onsite) Tape Backup Unit: TR5 IDE TBU and tape added: US$249 ============================================================ Base Price: US $2599 Configured Price: US $3376 Quantity: 1 Total Price: US $3376 ============================================================ Many Gateway products are custom engineered to Gateway specifications, which may vary from the retail versions of the software and/or hardware in functionality, performance or compatibility. Prices and configurations are subject to change without notice or obligation. The price above does not include shipping and handling or any applicable taxes. After your system has been built (lead times vary), it may be shipped via second-day shipping in the continental U.S. Second-day shipping within the continental U.S. is US$95 for desktops and US$25 for portables. Five-day shipping for Destination (R) Digital Media Computers is US$149. All prices quoted are in U.S. dollars. o I would like to order this system via the World Wide Web. Clicking "Continue" below takes you to our secure server. Gateway uses Secure Sockets Layer (SSL) encryption to assure that all information entered on the next screen --including your credit card number -- can only be understood by us. After thousands of online transactions worth millions of dollars, no Gateway client has ever reported misappropriation of a credit card number protected by SSL technology. Check our article on how SSL works and why we think it's extremely safe to learn more. o Please have a sales representative contact me about this system or other Gateway products. Copyright (C) 1997, 1998 Gateway 2000 Inc. All rights reserved. Please see our ______________________. Please send feedback to ___________________________. Privileged and Confidential ADDRL #34 34. Estimate of "personal tools" costs per employee, e.g. PC, pager, cellular phone. (This information is needed to estimate merger savings.). 1. Workstation replacement program ended in 1997. There are about 50 workstations currently in use. They will be phased out through attrition. 2. Replacement of PCs is a department head decision. Expected replacements are identified in the O&M budget. A PC Replacement form is used as a control document. 3. New PCs are identified in the O&M budget (unless they are related to a capital project). A PC Acquisition form is used as a control document. 4. Average replacement costs and base-line specifications for the two classes of recommended PCs is attached - #1. 5. Divisional breakdown of PCs is attached - #2. 6. Average life expectance for a PC is three years. However, older useful PCs are recirculated to low-end users identified by department heads. 7. Department heads on an as needed basis distributes pagers and cell phones. 8. Company annualized cost for PC's - $450,000; pagers and cell phones - $90,000. 1998 Inventory Number of PCs by Department Total Configurations as of 12/14/98: 584 Accounting 48 Bldg & Facil 11 CIS 78 Engineering 70 Executive 31 Garage 10 Gen. Office Svcs 2 HR 30 Info Services 62 Internal Audit 4 Meter 11 Meter Reading 11 Power Supply 15 Purchasing 6 Rates 23 Real Estate 5 Records 1 Retail Bus Svcs. 65 Safety & Risk Mgmt 7 SCADA 5 Special Projects 5 Stores Mgmt & Supp 14 Sub & Comm 13 System Operations 3 Telecommunications 3 Trans & Dist 32 Trans Svcs 7
Advertising in $000 1997 1998 annualized EUA NEES Addit. data req #47 825 Customer 4,318 dsm,choice related Normalized 500 Image 50 FERC # 930.1 4,368 Savings 50% Savings in 1997 250 Escalation to 2000 1.09 Savings in 2000 273
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT 47 Summary of advertising costs. See attached.
Advertising Costs - 1997 1997 ------------------------ ---- Company Advertising Costs ------- ----------------- Co 01 Blackstone Valley Electric $215,091.17 Co 08 Eastern Edison Company $519,027.05 Co 14 Newport Electric Corporatio $90,729.57 ------------ Total $824,847.79
Association Dues in $000 Addit data req # 45, 48 EUA 1997 Savings% Savings EEI 136 25% 34 Other 41 100% 41 177 42% 75 Escalation to 2000 1.09 Savings in 2000 82
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 45 Summary of associations dues. 1997 Blackstone Newport Eastern Total - ---- ---------- ------- ------- ----- Utility Air Regulatory Group 225 562 787 Electric Council of New England 6,983 2,745 13,665 23,393 EEI 38,842 17,780 78,980 135,602 Utility Water Act Group 2,847 2,788 5,752 11,387 Associated Industries of MA 720 720 NU College of Business 2,500 2,500 Administration Miscellaneous 696 315 1,431 2,442 49,593 24,190 103,048 176,831
Benefits Administration in $000 Expect no savings in HMO ( self insured) and group life Minimal savings in retirement and thrift plan administration Per conversation with NEES Savings in 2000 50 12/19/98 ADDITIONAL DUE DILIGENCE (List #3) REQUEST LIST PRIVILEGED AND CONFIDENTIAL ATTORNEY-CLIENT COMMUNICATION ATTORNEY WORK PRODUCT ADDRL # 46 Cost to administer benefits.
EASTERN UTILITIES ASSOCIATES Responsibility Center 220 - Corporate Benefits O&M Budget 1999 "ADDRL"12/19/98 Question #46 OTHER EXPENSES: O&M EUASC XX Payroll 01 $220,000 20 Miscellaneous (NEEBC Dues) 00 $400 20 Retiree Organizations Support (700 rets @ $10.00) 00 $7,000 01 Employee Expense 05 $1,800 XX Ed. & Training 06 $3,500 20 Materials & Supplies 07 $2,000 07 Materials & Supplies - WSJ,CCH 07 $1,600 XX General Consulting - Pension & ESP* 11 $36,000* 20 Financial Education/ Retirement Planning Program 11 $23,500 20 FSA Admin. Fees-Estimated FICA tax offset is $10,000 11 $9,000 20 Executive Annual Physicals 11 $16,800 20 Split $ Consulting Fee - Vinings Management 11 $16,900 25 Cyborg Maintenance Contract 22 $12,500 Total Other Expenses: $351,000 ======== * not payable from the pension trusts.
TOTAL BVE EECO NEWPORT EUASC TOTAL EUASC Group Health 452,022 978,362 211,337 171,001 1,812,722 204,034 Dental Insurance 49,016 105,728 33,918 3,130,326 3,318,988 3,735,027 Group Life 7,154 65,696 35,153 570,642 678,645 680,876 Pension (854,720) (1,351,822) (74,320) 4,329,463 2,048,601 5,165,807 Post Retirement Benefits 1,319,782 2,284,618 588,458 356,773 4,549,631 425,693 Employee Thrift Plan 113,012 218,567 94,990 0 426,569 1,086,266 2,301,149 889,536 8,558,205 12,835,156 10,211,437 ---------- 12,835,156 BVE 2,367,906 0.276698653 0.2319 EECO 4,621,878 0.540083693 0.4526 NWPT 1,231,339 0.143886557 0.1206 MECO TRANS 336,584 0.039331097 0.033 8,557,707 1 0.8381
Corporate Governance Shareholder Services in $000 ADDRL #43 EUA 1999 budget Million Million Shares Price Mkt Cap Annual rpt 112 NEES 59.8 48.06 2,874 Transfer agent 87 EUA 20.4 27.81 567 NYSE 33 EUA equiv 11.8 Other 61 % increase 11.8/59.8 293 20% Savings 80% Savings in 1999 234 Savings in 2000 241 Trustees ADDRL #40 1999 1998 EUA NEES Outside directors 9 11 Fees 550 Other expenses 100 Total 530 650 Savings in 1999 530 Escalate to 2000 1.03 Savings in 2000 546 Total Corp Governance 787
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 43 Summary of shareholder services expenses, including the production of the annual report, the annual meeting, mailings and other fees. Budget for 1999 Annual Report Production 112,000 Mailing of AR and Proxy, etc. 28,000 10K printing 5,700 Proxy printing 7,000 Transfer agent fees 87,000 NYSE listing fee 33,000 Quarterly dividend enclosure 11,000 Postage and miscellaneous 9,700 --------- 293,400 12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE (List # 3) ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 40 Directors' fees and related expenses. See attached summary of EUA Parent 1999 Budget for details of information requested.
EUA PARENT 1999 BUDGET 1999 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC TOTAL --- --- --- --- --- --- --- --- --- --- --- --- ----- 9200 DO AMORT RESTR STK PLAN 500 500 500 500 500 500 500 500 500 500 500 500 6,000 9302 07 MISCELLANEOUS FIDUCIARY/DIRECTORS LIB INS 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,737 92,800 TOTAL 9302 07 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,737 92,800 9302 09 CORP & FISCAL MISCELLANEOUS 200 200 9302 06 DIRECTORS FEES ANNUAL TRUSTEE FEE 36,000 36,000 36,000 36,000 144,000 REGULARLY SCHEDULED MTGS FULL BOARD 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 84,190 FINANCE COMM 4,250 4,250 4,250 4,250 17,000 AUDIT COMM 4,250 4,250 4,250 12,750 PENSION TRUST COMM 3,400 3,400 3,400 3,400 3,400 3,400 20,400 COMPENSATION 3,400 3,400 3,400 10,200 RETIREMENT BENEFIT 36,130 12,130 12,130 38,130 12,130 12,130 36,130 12,130 12,130 36,130 12,130 12,130 241,560 TOTAL 9302 05 84,030 26,580 24,030 87,430 19,780 27,430 84,030 15,530 27,430 90,830 19,780 23,220 530,100 TOTAL DO 92,263 34,813 32,263 95,853 28,013 35,883 92,263 23,763 35,663 99,063 28,013 31,457 629,100 9230 10 OUTSIDE LEGAL 28,300 27,100 14,500 33,400 24,000 7,600 7,000 7,900 9,800 12,900 5,000 6,200 183,700 TOTAL 09 28,300 27,100 14,500 33,400 24,000 7,600 7,000 7,900 9,800 12,900 5,000 6,200 183,700 9210 02 OFFICE SUPPLIES & EXP BANK CHARGES 400 400 400 400 400 400 400 400 400 400 400 400 4,800 9230 20 OUTSIDE ACCOUNTING C&L AUDIT FEE 4,700 2,800 1,030 1,700 10,000 9302 10 TRANSFER AGENT FEES COMON STOCK EXPENSE 1,000 1,000 2,500 1,000 1,000 2,500 1,000 1,000 2,500 1,000 1,000 2,500 18,000 TOTAL 11 1,400 5,100 5,500 1,400 1,400 2,900 1,400 1,400 2,900 2,400 1,400 4,600 32,800 TOTAL 000 121,963 58,013 52,283 130,483 53,413 46,363 100,563 33,063 40,363 114,383 34,413 42,257 845,600
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New England Electric Sys. NYSE : NES Financial Links Address: 25 Research Drive o Company News Westborough, MA 01582 o Research Report: Basic / Detailed Phone: (508) 389-2000 o Upgrade/Downgrade History Fax: (508) 836-0276 o Free Annual Report Industry: Electric Utilities o Latest Stock Price Sector: Utilities o Insider Trades Employees: 4,665 o SEC Filings (raw filings) Officers: Richard P. Sergel, Pres./CEO o Message Board Joan T. Bok, Chmn. Cheryl A. Lafleur, Sr. VP/Secy./Counsel Michael E. Jesanis, Sr. VP/CFO Company's Web Presence John G. Cochrane, Treas./CAO. o Home Page o Search Yahoo! for related links...
Business Summary NES is a public utility holding company, whose subsidiaries are engaged in the transmission, distribution, sale and generation of electricity. For the nine months ended 9/30/98, revenues fell 1% to $1.82 billion. Net income applicable to Common fell 3% to $157.5 million. Revenues reflect decreases in generation-related, fuel cost-related, and oil and gas-related revenues. Earnings also reflect monthly contractual payments to USGen and increased transmission wheeling costs.
More from Market Guide: Highlights - Performance Statistics at a Glance - NES Last Updated: Dec 23, 1998 Price and Volume Per-Share Data Management Effectiveness (updated Dec 23, 1998) Book Value (mrq) $26.79 Return on Assets (ttm) 4.34% 52-Week Low $38.938 Earnings (ttm) $3.39 Return on Equity (ttm) 12.66% Recent Price $48.063 Sales (ttm) $38.91 Financial Strength 52-Week High $49.125 Cash (mrq) $8.26 Current Ratio (mrq) 1.23 Beta 0.32 Valuation Ratios Long-Term Debt/Equity (mrq) 0.63 Daily Volume (3- 148.9K Price/Book (mrq) 1.79 Total Cash (mrq) $494.3M month avg) Share-Related Items Price/Earnings (ttm) 14.19 Short Interest Market Capitalization $2.88B Price/Sales (ttm) 1.24 Shares Short 23 as of Dec 8, 1998 Shares Outstanding 59.8M Income Statements Float 54.5M After-Tax Income (ttm) $231.8M Short Ratio 5.81 Dividend Information Sales (ttm) $2.48B Stock Performance Annual Dividend $2.36 Profitability NES 24-Dec-1998 (C) Yahoo! (indicated) Profit Margin (ttm) 9.3% _____________________________________ 50|| | 45|| | 40 | | 35 | | ------------------------------------| Jan Mar May Jul Sep Nov big chart [ld | 5d | 3mo | 1yr | 2yr | 5 yr | max] Dividend Yield 4.91% See the Profile FAQ for a description of each item above; K = thousands; M = millions; B = billions; mrq = most-recent quarter (Sep 30, 1998); ttm = trailing twelve months through Sep 30, 1998 Market Guide offers more in-depth Company Research, Stock Screening, and Hottest Stocks and Industries on over 10,000 U.S. Equities. - ------------------------------------------------------------------------------------------------------------------- Copyright (C) 1998 Yahoo! Inc. All Rights Reserved. See our Important Disclaimers and Legal Information. Company information Copyright (C) Market Guide Historical chart data and daily updates provided by Commodity Systems, Inc. (CSI). Data and information is provided for informational purposes only, and is not intended for trading purposes. Neither Yahoo nor any of its data or content providers (such as Market Guide, CSI, Reuters, Zacks, etc.) shall be liable for any errors or delays in the content, or for any actions taken in reliance thereon. Questions or Comments?
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Eastern Utilities Assoc. NYSE : EUA Financial Links Address: One Liberty Square o Company News Boston MA 02109 o Research Report: Basic / Detailed Phone: (617) 357-9590 o Latest Stock Price Fax: (617) 357-7320 o Insider Trades Industry: Electric Utilities o SEC Filings (raw filings) Sector: Utilities o Message Board Employees: 1,180 Officers: Donald G. Pardus, Chmn./CEO John R. Stevens, Pres./COO Company's Web Presence Richard M. Burns, Contr./CAO o Home Page Clifford J. Herbert, Jr., Treas./Secy. o Search Yahoo! for related links...
Business Summary EUA is a holding company for Blackstone, Eastern Edison, and Newport, which provide retail electric utility services in MA and RI. EUA also operates various service subsidiaries. For the nine months ended 9/98, revenues fell 4% to $405.4 million. Net income applicable to Common fell 4% to $26.2 million. Results suffered from a decrease in core electric business revenues due to customer rate reductions and the termination of the power marketing joint venture. More from Market Guide: Highlights - Performance
Statistics at a Glance - EUA Last Updated: Dec 23, 1998 Price and Volume Per-Share Data Management Effectiveness (updated Dec 23, 1998) Book Value (mrq) $18.27 Return on Assets (ttm) 3.05% 52-Week Low $23.563 Earnings (ttm) $1.80 Return on Equity (ttm) 9.85% Recent Price $27.813 Sales (ttm) $26.98 Financial Strength 52-Week High $28.00 Cash (mrq) $0.33 Current Ratio (mrq) 0.71 Beta 0.50 Valuation Ratios Long-Term Debt/Equity (mrq) 0.77 Daily Volume (3- 73.9K Price/Book (mrq) 1.52 Total Cash (mrq) $6.64M month avg) Price/Earnings (ttm) 15.45 Short Interest Share-Related Items Price/Sales (ttm) 1.03 Shares Short as of Dec 8, 1998 137.9 Market Capitalization $568.4M Shares Outstanding 20.4M Income Statements Short Ratio Float 20.2M After-Tax Income (ttm) $39.1M
Financing Costs and Fees in $000 Includes savings associated with lines of credit Lines of Credit 1998 est NEES x NEP EUA Commitment fees 567 256 Lines of credit 637,000 165,000 % fee 0.089% 0.155% Savings 100% Savings in 1998 256 Escalation to 2000 1.06 Savings in 2000 272
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE (List #3) ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 41 Summary of any lines of credit. See attached summary of EUA System lines of credit.
EUA SYSTEM Short-Term Credit Facility Fees (1) For 1998/1999 LINE FACILITY ANNUAL BANK OF CREDIT FEE FEE EUA BVE EECO REVOLVING CREDIT FACILITY: BANK OF NEW YORK $100,000,000 $20,000,000 $75,000,000 (Availability: All Companies) 29% 6% 21% $75,000,000 0.1250% $93,750 $26,786 $5,357 $20,089 OTHER CREDIT FACILITIES: $20,000,000 $75,000,000 BANK OF NEW YORK 16% 60% (Availability: BVE,EECO, MECO) $10,000,000 0.1250% $12,500 $2,000 $7,500 STATE STREET BANK $100,000,000 $75,000,000 (Availability: EUA, EECO) 57% 43% $15,000,000 0.2500% $37,500 $21,429 $16,071 UNION BANK OF CALIFORNIA (2) $100,000,000 $20,000,000 $75,000,000 (Availability: EUA, BVE, EECO, MECO, NECO) 8% 30% $20,000,000 0.1875%(2) $0 40% $0 $0 $0 NATIONS BANK, N.A. $75,000,000 (Availability: EECO) $45,000,000 0.2500% $112,500 100% $112,500 ANNUAL FACILITY FEE TOTALS $165,000,000 $256,250 $48,214 $7,357 $156,161 MONTHLY ACCRUAL $4,018 $613 $13,013 BANK MECO COGENEX EUA OS SERVICE NECO TOTAL REVOLVING CREDIT FACILITY: $30,000,000 $75,000,000 $10,000,000 $15,000,000 $25,000,000 $350,000,000 BANK OF NEW YORK 9% 21% 3% 4% 7% 100% (Availability: All Companies) $8,036 $20,089 $2,679 $4,018 $6,696 $93,750 OTHER CREDIT FACILITIES: $30,000,000 $125,000,000 BANK OF NEW YORK 24% 100% (Availability: BVE,EECO, MECO) $3,000 $12,500 STATE STREET BANK $175,000,000 (Availability: EUA, EECO) 100% $37,500 $30,000,000 $25,000,000 $250,000,000 UNION BANK OF CALIFORNIA (2) 12% 10% 100% (Availability: EUA, BVE, EECO, MECO, NECO) $0 $0 $0 $75,000,000 NATIONS BANK, N.A. 100% (Availability: EECO) $112,500 ANNUAL FACILITY FEE TOTALS $11,036 $20,089 $2,679 $4,018 $6,696 $256,250 $920 $1,674 $223 $335 $558 $21,354 MONTHLY ACCRUAL (1) Allocation Percentages Based on March 20, 1998 SEC Order Authorizing Company Short-Term Borrowing Limitations. (2) Facility Fee based on .1875% of the average daily unused amount of the Facility during such period. For allocation of Fee, assumption will be credit line will be fully drawn, hence, zero fee. September 22, 1998 JWH/d:/1231997/comfee/feebad98
Insurance Premiums in $000 Data Response #102 Major Coverages 1999 EUA % Savings Savings excl MTP Property 90 5% 5 Property 68 5% 3 Boiler 95 5% 5 Marine Cable Liability General 285 50% 143 Excess 343 50% 172 Auto 94 50% 47 Pollution 191 25% 48 D&O adjusted 100 75% 75 Brokerage Fees 175 75% 131 (per phone conversation) Total 1,441 44% 628 Escalate to 2000 1.03 Savings in 2000 646
INSURANCE COSTS - 1999 TYPE EECO NPT EUA BVE MTP EUA TOTAL PROPERTY 27000 21300 8200 33500 110000 200000 BOILER 13500 17800 4500 32400 141800 210000 OFFICE CONTENTS 1100 1100 EDP 10000 10000 CONT EQUIP 3178 2794 1377 2651 10000 MICROWAVE 2191 716 4336 1473 1284 10000 VALUABLE PAPERS 133 133 134 400 MARINE CABLE 95000 95000 TRANSIT 722 542 586 550 2400 CRIME 2230 590 6230 1100 850 11000 GENERAL LIABILITY 120000 45000 15000 105000 15000 300000 AUTOMOBILE 42000 14000 17500 21000 5500 100000 AUTO PHYSICAL 8350 2750 3650 4200 1050 20000 WORKERS COMP 55500 15000 19500 30000 30000 150000 D&O 15000 15000 15000 15000 122000 182000 PENSION 2493 662 7046 1195 954 12350 POLLUTION 91000 31500 15000 54000 63500 25500 UNDERGROUND TANKS 1300 2550 2050 2550 2550 11000 EXCESS LIABILITY 130500 42500 100000 70000 37000 380000 LETTER OF CREDIT 25000 25000 MONTAUP EXTRA EXP 140000 140000 BOND PREMIUM 15000 15000 SMALL CLAIM EXPENSE 247500 88000 27500 126500 60500 550000 $762,597 $392,910 $299,539 $499,881 $735,323 $2,690,250
DDRL #102 Question: List all liability, property, casualty, and other insurance policies held by the Company or its subsidiaries, or if self insured, the extent of self insurance, including limits of coverage, policy dates, premiums, insurance brokers, and cash surrender value, if any. Answer: The person in the organization responsible for risk management is not involved in the data request process. At this point in the process the information we will provide will be very limited. Attached you will find the planned 1999 expenses by category. Once the sale of Montaup is complete, the insurance expenses will be prorated for the remainder of the policy year. DDRL #103 Question: Describe all claims made by the Company or its subsidiaries under the insurance policies carried by the Company or its subsidiaries over the past two years in which the amount claimed exceeded $1,000,000. Answer: To the best of my knowledge, none. DDRL 104 Question: List and describe any pending litigation relating to insurance coverage. Answer: To the best of my knowledge there are two cases. 1. The family of a deceased woman in Fall River has filed a claim against the Company. The woman died as a result of a pedestrian truck accident involving an EUA driver in a meter van. The driver was not found to be negligent. Maximum exposure to the Company is $350,000. 2. A civilian has placed a claim with the Company as a result of a manhole explosion. The civilian received burns over 30% of his body. He has nearly fully recovered and is looking for medical expense recovery. We expect to settle for a reasonable amount. The maximum exposure is $350,000. In both cases the insurance will cover anything over the $350,000. Neither case is expected to exceed the $350,000 deductible. DDRL #105 Question: Copies of all material correspondence with insurers or insurance brokers or agents relating to environmental impairment liability claims. Answer: Did not have access to the information
Professional Services in $000 1997 BE EE NE Service Total Addit. data req #38 1,610 7,964 446 1,956 11,976 incl. ops-related Savings % Savings Accounting 34 63 31 69 197 50% 99 Legal incl dereg McDermott 33 1,209 17 360 Isaacson 744 Other 2 73 46 83 Total 779 1,282 63 443 2,567 adj. 1,500 33% 495 Employment 118 118 33% 39 Consulting 40 40 100% 40 Invest. Svcs 108 108 100% 108 Legislative 48 48 100% 48 Prof Svcs Total 2,011 41% 828 Escalation to 2000 1.093 Savings in 2000 905 Engineering 39 1 40 Environmental 20 12 32 Conservation 27 2,548 141 - 2,716 Facilities/Cleaning 40 162 202 incl in facilities calculation Security 125 125 incl in facilities calculation Misc Other 314 421 735 Tree Trimming 687 1,334 187 352 2,560 Misc Contract Svcs 1,606.0 1,606 8,016 10,027
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 38 List of professional services purchased by major area, e.g. a) Audits and accounting b) Legal c) Information systems See attached.
BLACKSTONE VALLEY ELECTRIC PROFESSIONAL SERVICES VENDOR NAME DESCRIPTION OF SERVICE 1997 ----------- ---------------------- ---- Asplundh Tree Trimming 56,222 Barnes Tree Services Tree Trimming 140,399 Blackstone Valley Security Security Services 0 Clean Harbor Environmental 19,603 Coopers & Lybrand Accounting 34,145 Credit Bureau Collection Fees 20,959 Dickstein, Shapiro & Moris Legal Financial Collection Collection Fees 1,149 Isaacson, Rosenbaum Legal 743,568 McDermott, Will & Emery Legal 32,578 Northern Tree Service Tree Trimming 491,290 Ocean State Janitorial Cleaning 40,408 Osmose Wood Press Pole Treatment/Inspection 448 Stanley Bleeker, Esq. Legal 0 Tillinghast, Collins & Graham Legal 1,911 (A) Coflax Packing Conservation 1,214 (A) Delta Electric Motor Conservation 639 (A) RISE Conservation 7,690 (A) Slater Dye Works Conservation 17,313 --------------------- 1,809,534 ===================== (A) These vendors participated in Eastern Edison's conservation, load, management programs, management programs. NOTE: The source for this information was based on o&m codes 9, 10, 11 & 16. Prepared by Michelle Uzzo 12/22/98
EASTERN EDISON COMPANY PROFESSIONAL SERVICES VENDOR NAME DESCRIPTION OF SERVICE 1997 ----------- ---------------------- ---- American Staffing Assoc. Employment 118,240 Asplundh Tree Trimming 919,253 Barnes Tree Service Tree Trimming 140,782 Clean Harbors Environmental Coopers and Lybrand Accounting 62,883 Duff & Phelps Consulting 40,000 Environmental Protection Service Maintenance 44,555 First Financial Resources Collection Fees 33,933 First Security Services Security Hanson Police Dept. Police Detail 31,478 J. D. Payroll Services Temp Services MASS Save Consulting 342,286 McDermott, Will & Emery Legal 1,209,446 Misc. Contract Services* 1,605,966 Misc. Engineering* 38,605 Misc. Legal* 12,155 Miscellaneous* 314,463 Osmose Wood Press Pole Treatment/Inspection Pembroke Police Dept. Police Detail R.A. Gill Tree Service Tree Trimming 227,341 R.E. Tilgren Tree Trimming 46,695 Reed, Adami, Kaiser Legal 72,589 Rockland Police Dept. Police Detail 26,218 Service Master Maintenance 29,796 State Street Bank & Trust Trustee/Administrative Fee Suburban Contract Cleaning Town of Bridgewater Police Detail Town of Easton Police Detail 56,526 Town of Norwell Police Detail 42,745 Town of Scituate Police Detail Town of Stoughton Police Detail (A) Conservation Services Group Conservation 361,903 (A) Demand Mgmt Conservation (A) Energie Innovation Inc. Conservation 84,095 (A) Energy Conservation Conservation 123,124 (A) Energy Federation Conservation 306,904 (A) Fall Realty & Harris Energy Conservation 38,353 (A) Fleet Bank Conservation 28,182 (A) Harris Energy Systems Conservation 489,801 (A) J&R Industrial Wiring Conservation 206,124 (A) Main Street Textiles Conservation 133,990 (A) MUPAC Corp & Harris Energy Conservation 26,114 (A) National Resource Mgmt. Conservation 375,923 (A) Relocation Resources, Inc. Conservation 61,985 (A) Shews Supermarkets Inc. Conservation 168,265 (A) Star Market & Harris Energy Conservation 31,080 (A) Stop & Shop Supermarket Co. Conservation 49,799 (A) Ware Rite & Harris Energy Conservation 32,759 (A) Whaling Mfg. Co., Inc. Conservation 29,235 ------------------- 7,963,604 =================== * Aggregate amounts to any one entity less than $25,000 have been accumulated in this description. (A) These vendors participated in Eastern Edison's conservation, load, management programs; management programs. NOTE: The source for this information was found on o&m codes 9, 10, 11 & 12. Prepared by Michelle Uzzo 12/22/98
NEWPORT ELECTRIC CORPORATION PROFESSIONAL SERVICES VENDOR NAME DESCRIPTION OF SERVICE 1997 ----------- ---------------------- ---- Barnes Tree Services Tree Trimming 187,208 Clean Harbor Environmental 11,989 Coopers & Lybrand Accounting 30,982 Credit Info Collection Fees 12,118 McDermott, Will & Emery Legal 16,808 Morgan, Brown & Joy Legal 340 RISE Conservation 141,057 Tillinghast, Collins & Graham Legal 45,587 ----------------- 446,062 ================= NOTE: The source for this information was based on o&m codes 9, 10, 11 & 19.
EUA SERVICE CORP. PROFESSIONAL SERVICES (Account # 923) VENDOR NAME DESCRIPTION OF SERVICE 1997 ----------- ---------------------- ---- McDermott, Will & Emery Legal 359,773 First Security Services Security 124,975 Contract Cleaning Collaborative Cleaning Eastern Edison Company Arborist/Technical Trainers 351,846 Salomon Brothers Inc. Investment Services 107,986 Media Concepts Printing Services 114,897 Norfolk Data Data Processing Time Cards Cambridge Reports, Inc. Customer Services 70,560 J. Flanagan & Co. Legislative Activity 48,000 DRI McGraw-Hill Newport Electric Corp. Arborist/Technical Trainers Twenty First Century AUC Management Consultants Consulting Misc. Legal * 82,677 Misc. Accounting * 68,988 Misc. EDP * 41,871 Misc. Building & Maintenance* 162,203 Other * 421,494 Misc. Engineering * 768 ----------------- 1,956,038 ================= * Payments made to payee is less than $100,000 Amounts in Bold print are estimates based on the average of 1996 & 1997. Prepared by Michelle Uzzo 12/22/98 a:\profsvs
REGULATORY EXPENSES in $000 1997 1997 EUA NEES Addit. data req #42 1,002 FERC acct #928 4,008 Assessments 739 Filings and misc. 263 Total 1,002 Savings on filings and misc. 20% Savings in 1997 53 Escalation to 2000 1.09 Savings in 2000 57
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 42 Summary of regulatory expenses. 1997 Newport Blackstone Eastern Total ---- ------- ---------- ------- ----- PUC Assessment 119,983 267,118 387,101 DTE Assessment 351,663 351,663 Tariff Filings & Misc. 57,258 144,113 61,899 263,270 ------- ------- ------ ------- 177,241 411,231 413,562 1,002,034
Cost to Achieve in $000 Total Basis for Cost Estimate - ---------------------------------------------------------------------------------------------------------------------------------- Transaction Costs Bankers fees 7,500 Estimate from NEES and EUA Legal fees 3,500 Estimate for NEES and EUA D&O liability tail coverage 400 1.5 times EUA's current annual D&O liability premium Total Transaction Costs 11,400 - ---------------------------------------------------------------------------------------------------------------------------------- Personnel Costs Separation/Retention 35,150 Relocation 2,750 Cost equals 90 employees required to relocate @ $25,000 per employee; also includes $500,000 miscellaneous Retraining 1,950 Cost includes: Customer service training: 100 employees x 4 weeks @ $1,000 per week ($400,000) Meter reader training: 50 employees x 1 week @ $1,000 per week ((50,000) Transmission and distribution training: 200 employees x 3 weeks @ $1,500 per week ($900,000) Administrative functions training: 100 employees x 4 weeks @ $1,500 per week ($600,000) General reorientation 250 Cost to train 500 employees x 2 days @ $250 per day ($250,000) Total Personnel Costs 40,100 - ---------------------------------------------------------------------------------------------------------------------------------- Transition Costs Internal Support 810 Cost equals 15 employees x 9 months @ $6,000 per month ($810,000) No cost shown 35 employees working on transition in addition to regular workload Outside Support 2,000 Cost for organizational and change management consultants and other outside support Communications 500 Costs for both internal and external communication Facilities Consolidation 1,000 Estimate based on other transactions Other 250 Cost of changing corporate signage, stationary, etc. Total Transition Costs 4,560 - ---------------------------------------------------------------------------------------------------------------------------------- Information Systems Systems Integration and Data 6,600 Cost of application integration and data conversion; cost to close one data center Center Consolidation Meter Reading Hardware 600 Cost to outfit EUA meter readers with 55 new ITRON devices Telecommunications Costs 350 Cost to connect telecommunications networks; reconfigure and reprogram customer service center switch Total Information Systems Costs 7,550 - ---------------------------------------------------------------------------------------------------------------------------------- Total Cost to Achieve 63,610
D&O Tail Coverage Conversation with Diane Kenney Coverage Premiums EUA in Millions in Thousands Policy #1 25 232 Policy #2 10 47 35 279 Budget for tail coverage 150% 419 Cost to achieve 400
Hoffman, David - ------------------------------------------------------------------------------ From: Michael J. Hirsh [mhirsh@eua.com] Sent: Monday, April 12,1999 5:49 PM To: david-hoffman@mercermc.com Subject: EUA-side transaction costs David- Following up on our conversation today, our transaction costs include the following: Banker fees$4.2 million (per contract) Legal $1.6 million actual + est. ($.535 billed through Feb, assume $.3 added through April and $.1/mo Thanks. MJH Exhibit DJH-2 Miscellaneous MODEL INPUTS - -------------------------------------- Escalation rate 3% - -------------------------------------- - -------------------------------------- % labor capitalized A&G 0% Customer 0% T&D 35% - -------------------------------------- - -------------------------------------- Benefits adder 32.63% for EUA - -------------------------------------- EUA (EE) % cap % b-t cost % a-t cost wacc - --------------------------- Revenue equirement ltd 45.5% 7.6% 7.6% 3.5% Rate ps 5.5% 9.8% 16.3% 0.9% cse 49.0% 11.5% 19.2% 9.4% Non-IS(30 yr) 13.5% 13.7% IS (5 yr) 28.6% - --------------------------- NEES(MECo) % cap % b-t cost % a-t cost wacc ltd 44.0% 7.5% 7.5% 3.3% - --------------------------- Fixed Charge Rate ps 5.9% 6.3% 10.5% 0.6% on EUA inventory 13.7% cse 50.1% 11.0% 18.3% 9.2% - --------------------------- 13.1% Depreciation on distribution plant x land depr ave plant % yrs MECo 47,760 1,466,280 3.26% 30.7 NECo 17,744 543,775 3.26% 30.6 EE 9,139 213,037 4.29% 23.3 BV 4,067 98,925 4.11% 24.3 Average 78,710 2,322,016 3.39% 29.5 NEES 2,010,055 87% EUA 311,961 13% 2,322,016
ADDRL #21 N21 % of employee benefits, taxes and unproductive time, i.e., vacations, holidays, sick, jury duty. (Benefits & Unproductive / Productive Wages). Blackstone Valley 54.24% Eastern Edison 53.64% Newport Electric 61.91% EUA Service Corp 52.91% % of payroll charged to O&M and to Capital O&M Capital Blackstone Valley 23.7% 76.3% Eastern Edison 26.4% 73.6% Newport Electric 22.5% 77.5% EUA Service Corporation wages billed to companies Blackstone Valley 95.3% 4.7% Eastern Edison 92.6% 7.4% Newport Electric 94.6% 5.4%
Capital Payroll by Function Payroll Capital Percent Total Payroll To Capital Total A&G 31,138,865 1,416,698 (Note 1) 4.55% Total Retail Svcs 11,567,105 11,327 0.10% Customer Service Northboro Inquiry 6,533,923 0 0.00% Meters 1,445,504 16,713 1.16% Collections 460,700 0 0.00% Cust Ld Analysis 464,638 0 0.00% --------- ------ 8,904,765 16,713 0.19% Providence Inquiry 3,531,849 0 0.00% Meter Read 2,648,213 0 0.00% Meter OPs 1,378,950 302,358 21.93% --------- ------- 7,117,580 302,358 4.25% MValley Inquiry 975,652 0 0.00% Meter Read 2,121,637 0 0.00% Meter OPs 1,082,295 138,419 12.79% --------- ------- 4,179,584 138,419 3.31% North Shore Inquiry 362,948 0 0.00% Meter Read 2,253,417 0 0.00% Meter OPs 907,277 106,033 11.69% --------- ------- 3,523,642 106,033 3.01% ========= M Valley/ N Shore 7,703,228 244,452 3.17% West Inquiry 222,012 0 0.00% Meter Read 1,174,272 0 0.00% Meter OPs 621,829 10,811 1.74% --------- ------ 2,018,113 10,811 0.54% Central Inquiry 468,606 0 0.00% Meter Read 1,519,383 0 0.00% Meter OPs 722,902 61,649 8.52% --------- ------ 2,578,891 61,649 2.39% ========= Central/West 4,597,004 72,460 1.58% Southeast Inquiry 614,464 0 0.00% Meter Read 1,453,783 0 0.00% Meter OPs 634,979 27,813 4.38% --------- ------ 2,573,226 27,813 1.08% Management 221,586 0 0.00% Total Customer Service 30,373,079 663,796 2.19%
CAPITAL PAYROLL BY FUNCTION Payroll Capital Percent Total Payroll To Capital Operations (Note A) Engineering 7,133,255 1,883,343 26.40% Dispatch 3,156,387 4,485 0.14% Const Svcs 18,732,509 12,200,687 65.13% T&D Svcs 6,910,541 901,301 13.04% Env/Safety 768,947 9,269 1.21% MValley/Gseco 15,120,701 4,519,335 29.89% North Shore 10,961,770 3,325,721 30.34% West 7,769,538 2,259,936 29.09% Central 16,202,800 4,890,090 30.18% Southeast 14,412,473 4,399,649 30.53% Providence 18,495,146 5,927,166 32.05% Mgmt 854,059 0 0.00% ------- - Total Operations 120,318,126 40,320,982 33.51% Executive 1,799,736 0 0.00% Total Wires 149,648,046 40,996,105 27.40% Wires plus A&G 181,215,151 40,007,432 25.44% Note A Detail costs excludes the following: Stores (district level) 3,823,817 42,819 1.12% Transportation (T&D Sv) 2,774,631 44,052 1.59% Note 1 A&G Capital payroll includes A&G credit of $1,409,148
This Report Is: Name of Respondent (1) [x] An Original Date of Report Year of Report Massachusetts Electric Company (2) [ ] A Resubmisson (Mo, Da, Yr) Dec. 31, 1997 - ---------------------------------------------------------------------------------------------------------------------------------- GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE - ---------------------------------------------------------------------------------------------------------------------------------- 1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the to cover, (b) the general procedure for determining the amount provisions of Electric Plant Instructions 3(17) of the capitalized, (c) the method of distribution to constrution U.S. of A. tion jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used, types of construction, (e) basis of differentiation in rates show the appropriate tax effect adjustment to the computa- different types of construction, and (f) whether the overhead tions below in a manner that clearly indicates the amount is directly or indirectly assigned. of reduction in the gross rate for tax effects. - ---------------------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------- COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES --------------------------------------------------------------------------------- For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average rate earned during the preceding three years. - ---------------------------------------------------------------------------------------------------------------------------------- 1. Components of Formula (Derived from actual book balances and actual cost rates): - ---------------------------------------------------------------------------------------------------------------------------------- Capitalization Cost Rate Line Title Amount Ratio (Percent) Percentage No. (a) (b) (c) (d) (1) Average Short-Term Debt S $29,054,000 (2) Short-Term Interest s 5.63% (3) Long-Term Debt D $375,000,000 44.01% d 7.46% (4) Preferred Stock P $50,000,000 5.87% p 6.30% (5) Common Equity C $427,061,000 50.12% c 11.00% (6) Total Capitalization $852,061,000 100% (7) Average Construction Work in Progress Balance W $17,700,000 - ---------------------------------------------------------------------------------------------------------------------------------- 2. Gross Rate for Borrowed Funds S D S s(--) + d ( -- ) (1---) 5.63% W D+P+C W - ---------------------------------------------------------------------------------------------------------------------------------- 3. Rate for Other Funds S P C [ 1 - -- ] [ p(-- -) + c(--) ] 0 W D+P+C D+P+C - ---------------------------------------------------------------------------------------------------------------------------------- 4. Weighted Average Rate Actually Used for the Year: a. Rate for Borrowed Funds - 5.71% b. Rate for Other Funds - 0 - ----------------------------------------------------------------------------------------------------------------------------------
This Report Is: Date of Report Name of Respondent (1) [x] An Original (Mo, Da, Yr) Year of Report Massachusetts Electric Company (2) [ ] A Resubmisson 03/31/98 Dec. 31, 1997 - --------------------------------------------------------------------------------------------------------------------------------- GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE - --------------------------------------------------------------------------------------------------------------------------------- 1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the to cover, (b) the general procedure for determining the provisions of Electric Plant Instructions 3(17) of the amount capitalized, (c) the method of distribution to construction U.S. of A. jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used, types of construction, (e) basis of differentiation in rates for show the appropriate tax effect adjustment to the computations different types of construction, and (f) whether the overhead below in a manner that clearly indicates the amount is directly or indirectly assigned. of reduction in the gross rate for tax effects. - --------------------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------- COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES --------------------------------------------------------------------------------- For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average rate earned during the preceding three years. - --------------------------------------------------------------------------------------------------------------------------------- 1. Components of Formula (Derived from actual book balances and actual cost rates): - ---------------------------------------------------------------------------------------------------------------------------------- Capitalization Cost Rate Line Title Amount Ratio (Percent) Percentage No. (a) (b) (c) (d) (1) Average Short-Term Debt S $5,117,538 (2) Short-Term Interest s 6.58% (3) Long-Term Debt D $223,000,000 45.48% d 7.62% (4) Preferred Stock P $27,034,771 5.51% p 9.83% (5) Common Equity C $240,213,303 49.0% c 11.50% (6) Total Capitalization $490,248,074 100% (7) Average Construction Work in Progress Balance W $4,399,855 - ---------------------------------------------------------------------------------------------------------------------------------- 2. Gross Rate for Borrowed Funds S D S s(--) + d(--) (1---) 6.58% W D+P+C W - ---------------------------------------------------------------------------------------------------------------------------------- 3. Rate for Other Funds S P C [ 1 - -- ] [ p(-- -) + c(--) ] 0 W D+P+C D+P+C - ---------------------------------------------------------------------------------------------------------------------------------- 4. Weighted Average Rate Actually Used for the Year: a. Rate for Borrowed Funds - 6.58% b. Rate for Other Funds - - ----------------------------------------------------------------------------------------------------------------------------------
This Report Is: Date of Report Name of Respondent (1) [x] An Original (Mo, Da, Yr) Year of Report Massachusetts Electric Company (2) [ ] A Resubmisson 03/31/98 Dec. 31, 1997 - --------------------------------------------------------------------------------------------------------------------------------- GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE - --------------------------------------------------------------------------------------------------------------------------------- 1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the to cover, (b) the general procedure for determining the provisions of Electric Plant Instructions 3(17) of the amount capitalized, (c) the method of distribution to construction U.S. of A. jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used, types of construction, (e) basis of differentiation in rates for show the appropriate tax effect adjustment to the computations different types of construction, and (f) whether the overhead below in a manner that clearly indicates the amount is directly or indirectly assigned. of reduction in the gross rate for tax effects. - --------------------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------- COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES --------------------------------------------------------------------------------- For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average rate earned during the preceding three years. - --------------------------------------------------------------------------------------------------------------------------------- 1. Components of Formula (Derived from actual book balances and actual cost rates): - ---------------------------------------------------------------------------------------------------------------------------------- Capitalization Cost Rate Line Title Amount Ratio (Percent) Percentage No. (a) (b) (c) (d) (1) Average Short-Term Debt S $3,501,308 (2) Short-Term Interest s 7.11% (3) Long-Term Debt D $36,500,000 46.29% d 9.35% (4) Preferred Stock P $6,129,500 7.77% p 4.81% (5) Common Equity C $36,232,083 45.94% c 11.43% (6) Total Capitalization $78,861,583 100% (7) Average Construction Work in Progress Balance W $1,965,253 - ---------------------------------------------------------------------------------------------------------------------------------- 2. Gross Rate for Borrowed Funds S D S s(--) + d(--) (1---) 7.11% W D+P+C W - ---------------------------------------------------------------------------------------------------------------------------------- 3. Rate for Other Funds S P C [ 1 - -- ] [ p(-- -) + c(--) ] 0 W D+P+C D+P+C - ---------------------------------------------------------------------------------------------------------------------------------- 4. Weighted Average Rate Actually Used for the Year: a. Rate for Borrowed Funds - 7.11% b. Rate for Other Funds - 0 - ----------------------------------------------------------------------------------------------------------------------------------
3. Stock-based compensation At December 31, 1997, NEES has three stock-based compensation plans and measures its compensation cost for those plans using the method of accounting prescribed by Accounting Principles Board Opinion No. 25. Accounting for Stock Issued to Employees, and related interpretations. The compensation cost that has been charged against income for these plans was $3.3 million, $3.7 million and $1.6 million for 1997, 1996, and 1995, respectively. If compensation cost for stock-based compensation had been accounted for under Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, the 1997 cost figures shown above would have been slightly smaller. Total income taxes in the statements of consolidated income are as follows: - ---------------------------------------------------------------------------------------------------------------------------------- Year ended December 31 (thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------------------------- Income taxes charged to operations $152,024 $139,199 $128,340 Income taxes charged to "Other income" (7,268) (3.018) 762 - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes $144,756 $136,181 $129,102 - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes, as shown above, consist of the following components: Year ended December 31 (thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------------------------- Current income taxes $175,934 $166,509 $105,046 Deferred income taxes (29,260) (28,652) 25,578 Investment tax credits, net (1,918) (1,676) (1,522) - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes $144,756 $136,181 $129,102 - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes, as shown above, consist of federal and state components as follows: - ---------------------------------------------------------------------------------------------------------------------------------- Year ended December 31 (thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------------------------- Federal income taxes $118,317 $111,573 $103,503 State income taxes 26,439 24,608 25,599 - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes $144,756 $136,181 $129,102 - ---------------------------------------------------------------------------------------------------------------------------------- Investment tax credits of subsidiaries are deferred and amortized over the estimated lives of the property giving rise to the credits. Although investment tax credits were generally eliminated by the 1986 tax legislation, additional carryforward amounts continue to be recognized. With regulatory approval, the subsidiaries have adopted comprehensive interperiod tax allocation (normalization) for temporary book/tax differences. Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows: - ---------------------------------------------------------------------------------------------------------------------------------- Year ended December 31 (thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------------------------- Computed rate at statutory rate $131,989 $123,053 $119,892 Increases (reductions) in tax resulting from Reversal of deferred taxes recorded at a higher rate (2,216) (2,175) (3,306) Amortization of investment tax credits (4,469) (4,347) (4,443) State income tax, net of federal income tax benefit 17,185 15,995 16,639 All other differences 2,267 3,655 320 - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes $144,756 $136,181 $129,102 - ----------------------------------------------------------------------------------------------------------------------------------
Percentage of employee benefits, taxes as a percentage of total wages. Company Percentage Blackstone Valley Electric Co. 30.45% Eastern Edison Co. 31.74% Newport Electric Corp. 38.16% EUA Service Corp. 32.75% Composite Percentage of employee benefits, taxes as a percentage of total wages for companies listed above Composite Description Amount Percentage Taxes & Benefits $16,030,158.00 Total Labor $49,132,790.00 32.63%
Com Energy 1997 O&M in $000 Com Elec Cambr Elec Total Elec Com Gas Total transmission 6,667 5,612 12,279 distribution 25,239 4,085 29,324 customer accounts 15,579 2,197 17,776 csi and sales 7,639 1,760 9,399 a&g(not adj.) 40,763 12,323 53,086 30,919 Total O&M 95,887 25,977 121,864 30,919 152,783 DSM expenditures 5,500 5,500 Net O&M 116,364 147,283 customers in 000 322.3 44.9 367.2 distribution cap. additions in millions 18.4 3.5 21.9 EUA 1997 O&M in $000 Eastern Blackstone Newport Edison Valley Electric Total transmission 529 616 282 1,427 distribution 16,149 6,532 3,968 26,649 customer accounts 6,779 3,228 1,107 11,114 csi and sales 7,045 3,300 1,547 11,892 a&g (not adj.) 16,417 9,241 5,429 31,087 Total O&M 46,919 22,917 12,333 82,169 DSM expenditures 5,000 Net O&M 77,169 customers in 000 190.3 90.3 35.0 315.6 distribution cap. additions in millions 9.5 3.2 2.8 15.5 EUA 77,169 EUA 77,169 COM electric 116,364 COM total 147,283 % 66% % 52%
BEC Com Pre-Merger Savings Post-Merger 1/1/2000 Staffing 2,230 1,108 3,338 362 2,976 Customers in 000 670 370 1,040 1,040 Employees per 000 Customers 3.3 3.0 3.2 2.9 Incremental staffing to BEC 746 33% Incremental customers to BEC 370 55% NEES EUA Pre-Merger Savings Post-Merger 1/1/2000 Staffing 3,240 869 4,109 234 3,875 Customers in 000 1,340 320 1,660 1,660 Employees per 000 Customers 2.4 2.7 2.5 2.3 Incremental staffing to NEES 635 20% Incremental customers to NEES 320 24% 1997 Ave. Customers (FERC #1) Boston Edison 670 Com Elec 322 Cam Elec 45 COM Total 367 Com Gas 237 SEC 10-K Mass Elec 960 Eastern 190 Narr Elec 331 Blackstone 90 Granite State 36 Newport 35 Nantucket 10 EUA Total 316 NEES Total 1,337
Narragansett Electric BVE/Newport Electric M.D.T.E. Docket No. 99-_____ Exhibit DJH-3 Exhibit DJH-3 Supporting Working Papers (Confidential) AGREEMENT AND PLAN OF MERGER and CONSENT AGREEMENT dated as of February 1, 1999 Exhibit I [Map Reflecting the NEES and EUA Direct Retail Service Areas and Transmission Networks] AGREEMENT AND PLAN OF MERGER and CONSENT AGREEMENT dated as of February 1, 1999 TABLE OF CONTENTS AGREEMENT AND PLAN OF MERGER...................................................1 CONSENT AGREEMENT..............................................................2 Tab 1 AGREEMENT AND PLAN OF MERGER dated as of February 1, 1999 by and among NEW ENGLAND ELECTRIC SYSTEM, RESEARCH DRIVE LLC and EASTERN UTILITIES ASSOCIATES TABLE OF CONTENTS Page No. ARTICLE I THE MERGER......................................................... 1 1.01 The Merger......................................................... 1 1.02 Effective Time..................................................... 1 1.03 Effects of the Merger.............................................. 2 ARTICLE II CONVERSION OF SHARES............................................... 2 2.01 Conversion of Capital Stock........................................ 2 2.02 Surrender of Shares................................................ 3 2.03 Withholding Rights................................................. 4 ARTICLE III THE CLOSING........................................................ 4 ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EUA.............................. 5 4.01 Organization and Qualification..................................... 5 4.02 Capital Stock...................................................... 6 4.03 Authority.......................................................... 7 4.04 Non-Contravention; Approvals and Consents.......................... 7 4.05 SEC Reports, Financial Statements and Utility Reports.............. 8 4.06 Absence of Certain Changes or Events............................... 9 4.07 Legal Proceedings.................................................. 9 4.08 Information Supplied............................................... 9 4.09 Compliance......................................................... 10 4.10 Taxes.............................................................. 10 4.11 Employee Benefit Plans; ERISA...................................... 12 4.12 Labor Matters...................................................... 14 4.13 Environmental Matters.............................................. 15 4.14 Regulation as a Utility............................................ 17 4.15 Insurance.......................................................... 17 4.16 Nuclear Facilities................................................. 18 4.17 Vote Required...................................................... 18 4.18 Opinion of Financial Advisor....................................... 18 -i- Page No. 4.19 Ownership of NEES Common Shares.................................... 18 4.20 State Anti-Takeover Statutes....................................... 18 4.21 Year 2000.......................................................... 19 4.22 EUA Associates..................................................... 19 ARTICLE V REPRESENTATIONS AND WARRANTIES OF NEES............................. 19 5.01 Organization and Qualification..................................... 19 5.02 Authority.......................................................... 20 5.03 Capital Stock...................................................... 20 5.04 Non-Contravention; Approvals and Consents.......................... 20 5.05 Information Supplied............................................... 21 5.06 Compliance......................................................... 21 5.07 Financing.......................................................... 22 5.08 No Vote Required................................................... 22 5.09 Ownership of EUA Shares............................................ 22 5.10 Merger with The National Grid Group plc............................ 22 ARTICLE VI COVENANTS................................................ 22 6.01 Covenants of EUA................................................... 22 6.02 Covenants of NEES.................................................. 28 6.03 Additional Covenants by NEES and EUA............................... 29 ARTICLE VII ADDITIONAL AGREEMENTS.................................... 30 7.01 Access to Information.............................................. 30 7.02 Proxy Statement.................................................... 31 7.03 Approval of Shareholders........................................... 31 7.04 Regulatory and Other Approvals..................................... 31 7.05 Employee Benefit Plans............................................. 32 7.06 Labor Agreements and Workforce Matters............................. 34 7.07 Post Merger Operations............................................. 34 7.08 No Solicitations................................................... 35 7.09 Directors' and Officers' Indemnification and Insurance............. 36 7.10 Expenses........................................................... 37 7.11 Brokers or Finders................................................. 37 7.12 Anti-Takeover Statutes............................................. 38 7.13 Public Announcements............................................... 38 -ii- Page No. 7.14 Restructuring of the Merger........................................ 38 ARTICLE VIII CONDITIONS......................................................... 39 8.01 Conditions to Each Party's Obligation to Effect the Merger......... 39 8.02 Conditions to Obligation of NEES and LLC to Effect the Merger...... 39 8.03 Conditions to Obligation of EUA to Effect the Merger............... 40 ARTICLE IX TERMINATION, AMENDMENT AND WAIVER.................................. 41 9.01 Termination........................................................ 41 9.02 Effect of Termination.............................................. 43 9.03 Termination Fees................................................... 43 9.04 Amendment.......................................................... 44 9.05 Waiver............................................................. 44 ARTICLE X GENERAL PROVISIONS................................................. 44 10.01 Non-Survival of Representations, Warranties, Covenants and Agreements......................................................... 44 10.02 Notices............................................................ 44 10.03 Entire Agreement; Incorporation of Exhibits........................ 46 10.04 No Third Party Beneficiary......................................... 46 10.05 No Assignment; Binding Effect...................................... 46 10.06 Headings........................................................... 47 10.07 Invalid Provisions................................................. 47 10.08 Governing Law...................................................... 47 10.09 Enforcement of Agreement........................................... 47 10.10 Certain Definitions................................................ 47 10.11 Counterparts....................................................... 48 10.12 WAIVER OF JURY TRIAL............................................... 48 -iii- GLOSSARY OF DEFINED TERMS The following terms, when used in this Agreement, have the meanings ascribed to them in the corresponding Sections of this Agreement listed below: "1935 Act" -- Section 4.05(b) "Adjustment Date" -- Section 2.01(c) "Affected Employees" -- Section 7.05(a) "affiliate" -- Section 10.11(a) "Agreement" -- Preamble "Alternative Proposal" -- Section 7.08 "beneficially" -- Section 10.10(b) "business day" -- Section 10.10(c) "Canceled Shares" -- Section 2.02(b) "Certificates" -- Section 2.02(b) "Closing" -- Article III "Closing Agreement" -- Section 4.10(j) "Closing Date" -- Article III "Code" -- Section 2.03 "Confidentiality Agreement" -- Section 7.01 "Constituent Entities" -- Section 1.01 "Contracts" -- Section 4.04(a) "control," "controlling," "controlled by" and "under common control with" -- Section 10.10(a) "DOE" -- Section 4.05(b) "Effective Time" -- Section 1.02 "Environmental Claim" -- Section 4.13(f)(i) "Environmental Laws" -- Section 4.13(f)(ii) "Environmental Permits" -- Section 4.13(b) "ERISA" -- Section 4.11(a) "ERISA Affiliate" -- Section 4.11(c) "EUA" -- Preamble "EUA Associates" -- Section 4.01(b) "EUA Employee Agreements" -- Section 7.05(d)(ii) "EUA Executives" -- Section 7.05(d)(ii) "EUA Shares" -- Preamble "EUA Disclosure Letter" -- Section 4.01(a) "EUA Employee Benefit Plans" -- Section 4.11(a) "EUA Financial Statements" -- Section 4.05(a) "EUA Nuclear Facilities" -- Section 4.16 "EUA Material Adverse Effect" -- Section 4.01(a) "EUA Required Consents" -- Section 4.04(a) "EUA Required Statutory Approvals" -- Section 4.04(b) "EUA SEC Reports" -- Section 4.05(a) -iv- "EUA Shareholders' Approval" -- Section 7.03 "EUA Shareholders' Meeting" -- Section 7.03 "EUA Significant Subsidiary" -- Section 7.08 "EUA Shares" -- Preamble "EUA Trust Agreement" -- Section 1.03 "EUA Voting Debt -- Section 4.02(d) "Evaluation Material" -- Section 7.01(a) "Exchange Act" -- Section 4.05(a) "Exchange Fund" -- Section 2.02(a) "Extended Termination Date" -- Section 9.01(b) "FCC" -- Section 4.05(b) "FERC" -- Section 4.05(b) "Final Order" -- Section 8.01(d) "Governmental Authority" -- Section 4.04(a) "Hazardous Materials" -- Section 4.13(f)(iii) "HSR Act" -- Section 7.04(a) "Indemnified Liabilities" -- Section 7.09(a) "Indemnified Party" -- Section 7.09(a) "Indemnified Parties" -- Section 7.09(a) "Information Systems" -- Section 4.21 "Initial Termination Date" -- Section 9.01(b) "IRS" -- Section 4.10(m) "knowledge" -- Section 10.11(d) "laws" -- Section 4.04(a) "Lien" -- Section 4.02(b) "LLC" -- Preamble "Massachusetts Secretary" -- Section 1.02 "Merger" -- Preamble "Merger Consideration" -- Section 2.01(b)(ii) "MGL" -- Section 1.01 "National Grid Group" -- Section 5.10 "National Grid Merger Agreement" -- Section 5.10 "NEES" -- Preamble "NEES Disclosure Letter" -- Section 5.03 "NEES Material Adverse Effect" -- Section 5.01 "NEES-EUA Regulatory Approvals" -- Section 7.04(b) "NEES-EUA Regulatory Proceedings" -- Section 7.04(c) "NEES Required Consents" -- Section 5.04(a) "NEES Required Statutory Approvals" -- Section 5.04(b) "NEES-NGG Regulatory Approvals" -- Section 7.04(c) "NEES-NGG Regulatory Proceedings" -- Section 7.04(c) "NEES-NGG Required Statutory Approvals"-- Section 7.04 "NEES-NGG Transactions" -- Section 7.04 "NEES Shares" -- Section 5.03 -v- "NEES Trust Agreement" -- Section 5.01 "NGG Circular" -- Section 7.02 "NRC" -- Section 4.05(b) "Options" -- Section 4.02(a) "orders" -- Section 4.04(a) "Out-of-Pocket Expenses" -- Section 9.03(a) "Paying Agent" -- Section 2.02(a) "PBGC" -- Section 4.11(g) "person" -- Section 10.11(e) "Per Share Amount" -- Section 2.01(b)(ii) "Post Closing Plans" -- Section 7.05(b) "Proxy Statement" -- Section 4.08(a) "Release" -- Section 4.13(f)(iv) "Representatives" -- Section 10.11(f) "SEC" -- Section 4.05(a) "Securities Act" -- Section 4.05(a) "Subsidiary" -- Section 10.11(g) "Surviving Entity" -- Section 1.01 "Tax Ruling" -- Section 4.10(j) "Taxes" -- Section 4.10 "Tax Return" -- Section 4.10 "US GAAP" -- Section 4.05(a) "Yankee Companies" -- Section 4.16 "Y2K Consultant" -- Section 6.01(o) -vi- This AGREEMENT AND PLAN OF MERGER, dated as of February 1, 1999 (this "Agreement"), is made and entered into by and among NEW ENGLAND ELECTRIC SYSTEM, a Massachusetts business trust ("NEES"), RESEARCH DRIVE LLC ("LLC"), a Massachusetts limited liability company which is directly and indirectly wholly owned by NEES, and EASTERN UTILITIES ASSOCIATES, a Massachusetts business trust ("EUA"). WHEREAS, the Board of Directors of NEES, the Board of Trustees of EUA and the members of LLC have each determined that it is advisable and in the best interests of their respective shareholders and members to consummate, and have approved, the business combination transaction provided for herein in which LLC would merge with and into EUA, with EUA being the surviving entity (the "Merger"), pursuant to the terms and conditions of this Agreement, as a result of which NEES will own, directly or indirectly, all of the issued and outstanding common shares of EUA (the "EUA Shares"); WHEREAS, NEES, LLC and EUA desire to make certain representations, warranties and agreements in connection with the Merger and also to prescribe various conditions to the Merger; NOW, THEREFORE, in consideration of the mutual covenants and agreements set forth in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows: ARTICLE I THE MERGER 1.01 The Merger. Upon the terms and subject to the conditions of this Agreement, at the Effective Time (as defined in Section 1.02), LLC shall be merged with and into EUA in accordance with Section 2 of Chapter 182 and Section 59 of Chapter 156C of the Massachusetts General Laws ("MGL"). At the Effective Time, the separate existence of LLC shall cease and EUA shall continue as the surviving entity in the Merger. EUA, after the Effective Time, is sometimes referred to herein as the "Surviving Entity" and EUA and LLC are sometimes referred to herein as the "Constituent Entities". The effect and consequences of the Merger shall be as set forth in Article II. 1.02 Effective Time. Subject to the provisions of this Agreement, on the Closing Date (as defined in Article III), a certificate of merger shall be executed and filed by EUA and LLC with the Secretary of the Commonwealth of Massachusetts (the "Massachusetts Secretary"). The Merger shall become effective at the time of the filing of the certificate of merger relating to the Merger with the Massachusetts Secretary, or at such later time as is specified in the certificate of merger (such date and time being referred to herein as the "Effective Time"). 1.03 Effects of the Merger. At the Effective Time, the Agreement and Declaration of Trust of EUA (the "EUA Trust Agreement") as in effect immediately prior to the Effective Time shall be the agreement and declaration of trust of the Surviving Entity, until thereafter amended as provided by law and such agreement and declaration of trust. Subject to the foregoing, the additional effects of the Merger shall be as provided in the applicable provisions of Section 2 of Chapter 182 of the MGL and Section 62 of the Limited Liability Company Act of Massachusetts. ARTICLE II CONVERSION OF SHARES 2.01 Conversion of Capital Stock. At the Effective Time, by virtue of the Merger and without any action on the part of the holder thereof: (a) Membership Interests of LLC. Each one percent of the issued and outstanding membership interests in LLC shall be converted into one transferable certificate of participation or share of the Surviving Entity. (b) Conversion of EUA Shares. (i) Cancellation of Treasury Shares and Shares Owned by NEES and Subsidiaries. All EUA Shares that are owned by EUA as treasury shares and any EUA Shares owned by NEES or any other wholly owned Subsidiary (as defined in Section 10.11) of NEES shall be canceled and retired and shall cease to exist and no cash or other consideration shall be delivered in exchange therefor. (ii) Conversion of EUA Shares. Each EUA Share issued and outstanding immediately prior to the Effective Time (other than shares to be canceled in accordance with Section 2.01(b)(i)) shall be canceled and converted in accordance with the provisions of this Section 2.01 into the right to receive cash in the amount (the "Per Share Amount") of $31.00 as such amount may hereafter be adjusted in accordance with Section 2.01(c) hereof (the "Merger Consideration"), payable, without interest, to the holder of such EUA Share, upon surrender, in the manner provided in Section 2.02 hereof, of the certificate formerly evidencing such share. (c) Adjustment in Amount of Merger Consideration. In the event that the Closing Date shall not have occurred on or prior to the date that is the six (6) month anniversary of the date on which EUA Shareholders' Approval is obtained (the "Adjustment Date"), the Per Share Amount shall be increased, for each day after the Adjustment Date up to and including the day which is one day prior to the earlier of the Closing Date and the Extended Termination Date, by an amount equal to $0.003. -2- 2.02 Surrender of Shares. (a) Deposit with Paying Agent. Prior to the Effective Time, NEES shall designate a bank or trust company reasonably acceptable to EUA to act as agent (the "Paying Agent") for the benefit of the holders of EUA Shares in connection with the Merger to receive the funds to which holders of EUA Shares shall become entitled pursuant to Section 2.01(b)(ii) (the "Exchange Fund"). From time to time at, immediately prior to or after the Effective Time, NEES or LLC shall make or cause to be made available to the Paying Agent immediately available funds in amounts and at the times necessary for the payment of the Merger Consideration upon surrender of Certificates (as defined in Section 2.02(b)) in accordance with Section 2.02(b), it being understood that any and all interest or other income earned on funds made available to the Paying Agent pursuant to this Section 2.02(a) shall belong to and shall be paid (at the time provided for in Section 2.02(e)) as directed by NEES or LLC. Any such funds deposited with the Paying Agent by NEES shall be invested by the Paying Agent as directed by NEES or LLC. (b) Exchange Procedure. As soon as practicable after the Effective Time, the Paying Agent shall mail to each holder of record of a certificate or certificates (the "Certificates") which immediately prior to the Effective Time represented outstanding EUA Shares (the "Canceled Shares") that were canceled and became instead the right to receive the Merger Consideration pursuant to Section 2.01(b)(ii): (i) a letter of transmittal in such form as NEES and EUA may reasonably agree (which shall specify that delivery shall be effected, and risk of loss and title to the Certificates shall pass, only upon actual delivery of the Certificates to the Paying Agent) and (ii) instructions for effecting the surrender of the Certificates in exchange for the Merger Consideration. Upon surrender of a Certificate or Certificates to the Paying Agent for cancellation (or to such other agent or agents as may be appointed by NEES and are reasonably acceptable to EUA), together with a duly executed letter of transmittal and such other documents as the Paying Agent shall require, the holder of such Certificate shall be entitled to receive the Merger Consideration in exchange for each EUA Share formerly evidenced by such Certificate which such holder has the right to receive pursuant to Section 2.01(b)(ii). In the event of a transfer of ownership of Canceled Shares which is not registered in the transfer records of EUA, the Merger Consideration in respect of such Canceled Shares may be given to the transferee thereof if the Certificate or Certificates representing such Canceled Shares is presented to the Paying Agent, accompanied by all documents required to evidence and effect such transfer and by evidence satisfactory to the Paying Agent that any applicable stock transfer taxes have been paid. At any time after the Effective Time, each Certificate shall be deemed to represent only the right to receive the Merger Consideration subject to and upon the surrender of such Certificate as contemplated by this Section 2.02. No interest shall be paid or will accrue on the Merger Consideration payable to holders of Certificates pursuant to Section 2.01(b)(ii). (c) No Further Ownership Rights in EUA Shares. The Merger Consideration paid upon the surrender of Certificates in accordance with the terms of Section 2.01(b)(ii) shall be deemed to have been paid at the Effective Time in full satisfaction of all rights pertaining to EUA Shares represented thereby. From and after the Effective Time, the share transfer books of EUA shall be closed and there shall be no further registration of transfers thereon of EUA Shares which were outstanding immediately prior to the Effective Time. -3- If, after the Effective Time, Certificates are presented to NEES for any reason, they shall be canceled and exchanged as provided in this Section 2.02. (d) Lost, Stolen or Destroyed Certificates. In the event any owner of any Certificate shall claim that such Certificate shall have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the owner of such Certificate and delivery of that affidavit to the Paying Agent and, if required by NEES or LLC, the posting by such person of a bond in customary amount as indemnity against any claim that may be made against NEES, EUA or the Surviving Entity with respect to such Certificate, the Paying Agent will issue in exchange for such lost, stolen or destroyed Certificate the Merger Consideration payable upon due surrender of, and deliverable pursuant to this Section 2.02 in respect of, EUA Shares to which such Certificate relates. (e) Termination of Exchange Fund. Any portion of the Exchange Fund which remains undistributed to the shareholders of EUA for one (1) year after the Effective Time shall be delivered to the Surviving Entity, upon demand, and any Shareholders of EUA who have not theretofore complied with this Article II shall thereafter look only to the Surviving Entity (subject to abandoned property, escheat and other similar laws) as general creditors for payment of their claim for the Merger Consideration payable upon due surrender of the Certificates held by them. None of NEES, LLC or the Surviving Entity shall be liable to any former holder of EUA Shares for the Merger Consideration delivered to a public official pursuant to any applicable abandoned property, escheat or similar law. 2.03 Withholding Rights. Each of the Surviving Entity and NEES shall be entitled to deduct and withhold from the consideration otherwise payable pursuant to this Agreement to any holder of EUA Shares such amounts as it is required to deduct and withhold with respect to the making of such payment under the Internal Revenue Code of 1986, as amended (the "Code"), or any other provision of state, local or foreign tax law. To the extent that amounts are so withheld by the Surviving Entity or NEES, as the case may be, such withheld amounts shall be treated for all purposes of this Agreement as having been paid to the holder of EUA Shares in respect of which such deduction and withholding was made by the Surviving Entity or NEES, as the case may be. ARTICLE III THE CLOSING The closing of the Merger and other transactions contemplated hereby (the "Closing") will take place at the offices of Skadden, Arps, Slate, Meagher & Flom LLP, 919 Third Avenue, New York, New York 10022, at 10:00 a.m., local time, on the second business day following satisfaction or waiver (where applicable) of the conditions set forth in Article VIII (other than those conditions that by their nature are to be fulfilled at the Closing, but subject to the fulfillment or waiver of such conditions), unless another date, time or place is agreed to in writing by the parties hereto (the "Closing Date"). -4- ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EUA EUA represents and warrants to NEES and LLC as follows: 4.01 Organization and Qualification. (a) EUA is a voluntary association duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has full power, authority and legal right to own its property and assets and to transact the business in which it is engaged. Each of EUA's Subsidiaries is a corporation duly organized or incorporated, validly existing and in good standing under the laws of its jurisdiction of organization or incorporation and has full corporate power and authority to conduct its business as and to the extent now conducted and to own, use and lease its assets and properties, except where failure to be so organized or incorporated, existing and in good standing or to have such power and authority, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. As used in this Agreement, the term "EUA Material Adverse Effect" means a material adverse effect on the business, assets, results of operations, condition (financial or otherwise) or prospects of EUA and its Subsidiaries taken as a whole. Each of EUA and its Subsidiaries is duly qualified, licensed or admitted to do business and is in good standing in each jurisdiction in which the ownership, use or leasing of its assets and properties, or the conduct or nature of its business, makes such qualification, licensing or admission necessary, except where failure to be so qualified, licensed or admitted and in good standing, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. Section 4.01 of the letter dated the date hereof and delivered to NEES and LLC by EUA concurrently with the execution and delivery of this Agreement (the "EUA Disclosure Letter") sets forth (i) the name and jurisdiction of incorporation or organization of each Subsidiary of EUA, (ii) such Subsidiary's authorized capital stock, (iii) the number of issued and outstanding shares of capital stock of such Subsidiary and (iv) the number of shares of such Subsidiary held of record by EUA. EUA has previously delivered to NEES correct and complete copies of the EUA Trust Agreement and the certificate or articles of organization or incorporation and bylaws (or other comparable charter documents) of its Subsidiaries. (b) Section 4.01 of the EUA Disclosure Letter sets forth a description as of the date hereof, of all EUA Associates, including (i) the name of each such entity and EUA's interest therein and (ii) a brief description of the principal line or lines of business conducted by each such entity. For purposes of this Agreement "EUA Associates" shall mean any corporation or other entity (including partnerships and other business associations) that is not a Subsidiary of EUA in which EUA and/or one or more of its Subsidiaries, directly or indirectly, owns an equity interest (other than short-term investments in the ordinary course of business) if such corporation or other entity (including partnerships and other business associations) contributes five percent or more of EUA's consolidated revenues, assets, income or costs. -5- 4.02 Capital Stock. (a) The authorized equity securities of EUA consists of 36,000,000 EUA Shares, of which 20,435,997 shares were issued and outstanding as of the close of business on January 29, 1999. As of the close of business on January 29, 1999, no EUA Shares were held in the treasury of EUA. Since such date there has been no change in the sum of the issued and outstanding EUA Shares. All of the issued and outstanding EUA Shares are duly authorized, validly issued, fully paid and nonassessable. Except pursuant to this Agreement and except as described in Section 4.02 of the EUA Disclosure Letter, on the date hereof there are no outstanding subscriptions, options, warrants, rights (including share appreciation rights), preemptive rights or other contracts, commitments, understandings or arrangements, including any right of conversion or exchange under any outstanding security, instrument or agreement (together, "Options"), obligating EUA or any of its Subsidiaries to issue or sell any shares of equity securities of EUA or to grant, extend or enter into any Option with respect thereto. The EUA Disclosure Letter sets forth all capital stock authorized, issued and outstanding at subsidiary levels as of the close of business on January 29, 1999. (b) Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, all of the outstanding shares of capital stock of each Subsidiary of EUA are duly authorized, validly issued, fully paid and nonassessable and are owned, beneficially and of record, by EUA or a Subsidiary, which is wholly owned, directly or indirectly, by EUA, free and clear of any liens, claims, mortgages, encumbrances, pledges, security interests, equities and charges of any kind (each a "Lien"). Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no (i) outstanding Options obligating EUA or any of its Subsidiaries to issue or sell any shares of capital stock of any Subsidiary of EUA or to grant, extend or enter into any such Option or (ii) voting trusts, proxies or other commitments, understandings, restrictions or arrangements in favor of any person other than EUA or a Subsidiary which is wholly owned, directly or indirectly, by EUA with respect to the voting of, or the right to participate in, dividends or other earnings on any capital stock of any Subsidiary of EUA. (c) Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no outstanding contractual obligations of EUA or any Subsidiary of EUA to repurchase, redeem or otherwise acquire any EUA Shares or any capital stock of any Subsidiary of EUA or to provide funds to, or make any investment (in the form of a loan, capital contribution or otherwise) in, any Subsidiary of EUA or any other person. (d) As of the date of this Agreement, no bonds, debentures, notes or other indebtedness of EUA or any Subsidiary of EUA having the right to vote (or which are convertible into or exercisable for securities having the right to vote) (together "EUA Voting Debt") on any matters on which Shareholders may vote are issued or outstanding nor are there any outstanding Options obligating EUA or any of its Subsidiaries to issue or sell any EUA Voting Debt or to grant, extend or enter into any Option with respect thereto. -6- 4.03 Authority. EUA has full power and authority to enter into this Agreement, to perform its obligations hereunder and, subject to obtaining EUA Shareholders' Approval (as defined in Section 7.03(b)) and EUA Required Statutory Approvals (as defined in Section 4.04(b)), to consummate the Merger and other transactions contemplated hereby. The execution, delivery and performance of this Agreement by EUA and the consummation by EUA of the Merger and other transactions contemplated hereby have been duly authorized by all necessary action on the part of EUA, subject to obtaining EUA Shareholders' Approval with respect to the consummation of the Merger and the other transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by EUA and constitutes a legal, valid and binding obligation of EUA enforceable against EUA in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). 4.04 Non-Contravention; Approvals and Consents. (a) The execution and delivery of this Agreement by EUA do not, and the performance by EUA of its obligations hereunder and the consummation of the Merger and other transactions contemplated hereby will not, conflict with, result in a violation or breach of, constitute (with or without notice or lapse of time or both) a default under, result in or give to any person any right of payment or reimbursement, termination, cancellation, modification or acceleration of, or result in the creation or imposition of any Lien upon any of the assets or properties of EUA or any of its Subsidiaries or any of the terms, conditions or provisions of (i) the EUA Trust Agreement or the certificates or articles of incorporation or organization or bylaws (or other comparable charter documents) of EUA's Subsidiaries, or (ii) subject to the obtaining of EUA Shareholders' Approval, EUA Required Consents, EUA Required Statutory Approvals and the taking of any other actions described in this Section 4.04, (x) any statute, law, rule, regulation or ordinance (together, "laws"), or any judgment, decree, order, writ, permit or license (together, "orders"), of any court, tribunal, arbitrator, authority, agency, commission, official or other instrumentality of the United States, any foreign country or any domestic or foreign state, county, city or other political subdivision (a "Governmental Authority") applicable to EUA or any of its Subsidiaries or any of their respective assets or properties, or (y) subject to obtaining the third-party consents set forth in Section 4.04 of the EUA Disclosure Letter (the "EUA Required Consents"), any note, bond, mortgage, security agreement, indenture, license, franchise, permit, concession, contract, lease or other instrument, obligation or agreement of any kind (together, "Contracts") to which EUA or any of its Subsidiaries is a party or by which EUA or any of its Subsidiaries or any of their respective assets or properties is bound, excluding from the foregoing clauses (x) and (y) such conflicts, violations, breaches, defaults, payments or reimbursements, terminations, cancellations, modifications, accelerations and creations and impositions of Liens which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. -7- (b) No declaration, filing or registration with, or notice to or authorization, consent or approval of, any Governmental Authority is necessary for the execution and delivery of this Agreement by EUA or the consummation by EUA of the Merger and other transactions contemplated hereby except as described in Section 4.04 of the EUA Disclosure Letter or the failure of which to obtain could not reasonably be expected to result in an EUA Material Adverse Effect (the "EUA Required Statutory Approvals," it being understood that references in this Agreement to "obtaining" such EUA Required Statutory Approvals shall mean making such declarations, filings or registrations; giving such notices; obtaining such authorizations, consents or approvals; and having such waiting periods expire as are necessary to avoid a violation of law). 4.05 SEC Reports, Financial Statements and Utility Reports. (a) EUA delivered to NEES prior to the execution of this Agreement a true and complete copy of each form, report, schedule, registration statement, registration exemption, if applicable, definitive proxy statement and other document (together with all amendments thereof and supplements thereto) filed by EUA or any of its Subsidiaries with the Securities and Exchange Commission (the "SEC") under the Securities Act of 1933, as amended, and the rules and regulations thereunder (the "Securities Act") and the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder (the "Exchange Act") since December 31, 1995 (as such documents have since the time of their filing been amended or supplemented, the "EUA SEC Reports"), which are all the documents (other than preliminary materials) that EUA and its Subsidiaries were required to file with the SEC under the Securities Act and the Exchange Act since such date. As of their respective dates, EUA SEC Reports (i) complied as to form in all material respects with the requirements of the Securities Act or the Exchange Act, as the case may be, and (ii) did not contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. Each of the audited consolidated financial statements and unaudited interim consolidated financial statements (including, in each case, the notes, if any, thereto) included in EUA SEC Reports (the "EUA Financial Statements") complied as to form in all material respects with the published rules and regulations of the SEC with respect thereto, were prepared in accordance with U.S. generally accepted accounting principles ("US GAAP") applied on a consistent basis during the periods involved (except as may be indicated therein or in the notes thereto and except with respect to unaudited statements as permitted by Form 10-Q of the SEC) and fairly present (subject, in the case of the unaudited interim financial statements, to normal, recurring year-end audit adjustments (which are not expected to be, individually or in the aggregate, materially adverse to EUA and its Subsidiaries taken as a whole)) the consolidated financial position of EUA and its consolidated subsidiaries as at the respective dates thereof and the consolidated results of their operations and cash flows for the respective periods then ended. Except as set forth in Section 4.05 of the EUA Disclosure Letter, each Subsidiary of EUA is treated as a consolidated subsidiary of EUA in EUA Financial Statements for all periods covered thereby. (b) All filings (other than immaterial filings) required to be made by EUA or any of its Subsidiaries since December 31, 1995, under the Public -8- Utility Holding Company Act of 1935 (the "1935 Act"), the Federal Power Act, the Atomic Energy Act of 1954, the Communications Act of 1934, and applicable state laws and regulations, have been filed with the SEC, the Federal Energy Regulatory Commission (the "FERC"), the Department of Energy (the "DOE"), the Nuclear Regulatory Commission (the "NRC"), the Federal Communications Commission (the "FCC") or any appropriate state public utility commissions (including, without limitation, to the extent required, the state public utility regulatory agencies of Massachusetts, Rhode Island, New Hampshire, Maine, Vermont and Connecticut as the case may be, including all forms, statements, reports, agreements (oral or written) and all documents, exhibits, amendments and supplements appertaining thereto, including but not limited to all rates, tariffs, franchises, service agreements and related documents and all such filings complied, as of their respective dates, in all material respects with all applicable requirements of the appropriate statutes and the rules and regulations thereunder. 4.06 Absence of Certain Changes or Events. Except as set forth in Section 4.06 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date of this Agreement since December 31, 1997, EUA and each of EUA's Subsidiaries have conducted its business only in the ordinary course of business consistent with past practice and there has not been, and no fact or condition exists which, individually or in the aggregate, has or could reasonably be expected to have an EUA Material Adverse Effect. 4.07 Legal Proceedings. Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or in Section 4.07 of the EUA Disclosure Letter and except for environmental matters which are governed by Section 4.13, (i) there are no actions, claims, hearings, suits, arbitrations or proceedings pending or, to the knowledge of EUA or any of its Subsidiaries, threatened against, specifically relating to or affecting, and, to the knowledge of EUA or any of its Subsidiaries, there are no Governmental Authority investigations or audits pending or threatened against, specifically relating to or affecting, EUA or any of its Subsidiaries or any of their respective assets and properties which, individually or in the aggregate, could reasonably be expected to have an EUA Material Adverse Effect and (ii) neither EUA nor any of its Subsidiaries is subject to any order of any Governmental Authority which, individually or in the aggregate, could reasonably be expected to have an EUA Material Adverse Effect. 4.08 Information Supplied. (a) The proxy statement relating to EUA Shareholders' Meeting, as amended or supplemented from time to time (as so amended and supplemented, the "Proxy Statement"), and any other documents to be filed by EUA with the SEC (including, without limitation, under the 1935 Act) or any other Governmental Authority in connection with the Merger and other transactions contemplated hereby will comply as to form in all material respects with the requirements of the Exchange Act, the Securities Act and the 1935 Act, as applicable, and will not, on the date of their respective filings or, in the case of the Proxy Statement, at the date it is mailed to Shareholders of EUA and at the time of EUA Shareholders' Meeting (as defined in Section 7.03), contain any untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in light of the circumstances under which they are made, not misleading. -9- (b) Notwithstanding the foregoing provisions of this Section 4.08, no representation or warranty is made by EUA with respect to statements made or incorporated by reference in the Proxy Statement based on information supplied by NEES or LLC for inclusion or incorporation by reference therein. 4.09 Compliance. Except as set forth in Section 4.09 of the EUA Disclosure Letter, or as disclosed in EUA SEC Reports filed prior to the date hereof, neither EUA nor any of EUA's Subsidiaries is in violation of, is, to the knowledge of EUA, under investigation with respect to any violation of, or has been given notice or been charged with any violation of, any law, statute, order, rule, regulation, ordinance or judgment (including, without limitation, any applicable environmental law, ordinance or regulation) of any Governmental Authority, except for possible violations which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. Except as set forth in Section 4.09 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date hereof, EUA and EUA's Subsidiaries have all permits, licenses, franchises and other governmental authorizations, consents and approvals necessary to conduct their businesses as presently conducted except for such failures which could not reasonably be expected to have an EUA Material Adverse Effect. Neither EUA nor any of EUA's Subsidiaries is in breach or violation of, or in default in the performance or observance of any term or provision of, (i) the EUA Trust Agreement, in the case of EUA, or articles of incorporation or organization or by-laws, in the case of EUA's Subsidiaries, or (ii) any contract, commitment, agreement, indenture, mortgage, loan agreement, note, lease, bond, license, approval or other instrument to which it is a party or by which EUA or any Subsidiary of EUA is bound or to which any of their respective property is subject, except for possible violations, breaches or defaults which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. 4.10 Taxes. Except as disclosed in Section 4.10 of the EUA Disclosure Letter: (a) Filing of Timely Tax Returns. EUA and each of its Subsidiaries have timely filed all Tax Returns required to be filed by each of them under applicable law. All Tax Returns were (and, as to Tax Returns not filed as of the date hereof, will be) true, complete and correct; (b) Payment of Taxes. EUA and each of its Subsidiaries have, within the time and in the manner prescribed by law, paid (and until the Closing Date will pay within the time and in the manner prescribed by law) all Taxes that are currently due and payable except for those contested in good faith and for which adequate reserves have been taken; (c) Tax Reserves. EUA and its Subsidiaries have established (and until the Closing Date will maintain) on their books and records adequate reserves for all Taxes and for any liability for deferred income taxes in accordance with GAAP; -10- (d) Extensions of Time for Filing Tax Returns. Neither EUA nor any of its Subsidiaries has requested any extension of time within which to file any Tax Return, which Tax Return has not since been filed; (e) Waivers of Statute of Limitations. Neither EUA nor any of its Subsidiaries has in effect any extension, outstanding waivers or comparable consents regarding the application of the statute of limitations with respect to any Taxes or Tax Returns; (f) Expiration of Statute of Limitations. The Tax Returns of EUA, each of its Subsidiaries and any affiliated, consolidated, combined or unitary group that includes EUA or any of its Subsidiaries either have been examined and settled with the appropriate Tax authority or closed by virtue of the expiration of the applicable statute of limitations for all years through and including 1993; (g) Audit, Administrative and Court Proceedings. No audits or other administrative proceedings or court proceedings are presently pending or threatened with regard to any Taxes or Tax Returns of EUA or any of its Subsidiaries (other than those being contested in good faith and for which adequate reserves have been established) and no issues have been raised in writing by any Tax authority in connection with any Tax or Tax Return; (h) Tax Liens. There are no Tax liens upon any asset of EUA or any of its Subsidiaries except liens for Taxes not yet due. (i) Powers of Attorney. No power of attorney currently in force has been granted by EUA or any of its Subsidiaries concerning any Tax matter; (j) Tax Rulings. Neither EUA nor any of its Subsidiaries has, during the five year period prior to the date of this Agreement, received a Tax Ruling (as defined below) or entered into a Closing Agreement (as defined below) with any taxing authority. "Tax Ruling", as used in this Agreement, shall mean a written ruling of a taxing authority relating to Taxes. "Closing Agreement", as used in this Agreement, shall mean a written and legally binding agreement with a taxing authority relating to Taxes; (k) Availability of Tax Returns. EUA and its Subsidiaries have made available to NEES complete and accurate copies, covering all years ending on or after December 31, 1993, of (i) all Tax Returns, and any amendments thereto, filed by EUA or any of its Subsidiaries, (ii) all audit reports received from any taxing authority relating to any Tax Return filed by EUA or any of its Subsidiaries and (iii) any Closing Agreements entered into by EUA or any of its Subsidiaries with any taxing authority. (l) Tax Sharing Agreements. No agreements relating to the allocation or sharing of Taxes exist between or among EUA and any of its Subsidiaries and neither EUA nor any of its Subsidiaries (i) has been a member of an affiliated group filing a consolidated federal income tax return (other -11- than a group the common parent of which was EUA) or (ii) has any liability for Taxes of any Person (other than EUA or its Subsidiaries) under United States Treasury Regulation Section 1.1502-6 (or any provision of state, local), or foreign law, as a transferee or successor, by contract or otherwise; (m) Code Section 481 Adjustments. Neither EUA nor any of its Subsidiaries is required to include in income any adjustment pursuant to Code Section 481(a) by reason of a voluntary change in accounting method initiated by EUA or any of its Subsidiaries, and, the Internal Revenue Service ("IRS") has not proposed any such adjustment or change in accounting method; (n) Code Sections 6661 and 6662. All transactions that could give rise to an understatement of federal income tax, and within the meaning of Code Section 6662 have been adequately disclosed (or, with respect to Tax Returns filed following the Closing, will be adequately disclosed) on the Tax Returns of EUA and its Subsidiaries in accordance with Code Section 6662(d)(2)(B); (o) Intercompany Transactions. Neither EUA nor any of its Subsidiaries has engaged in any intercompany transactions within the meaning of Treasury Regulations ss. 1.1502-13 for which any income or gain will remain unrecognized as of the close of the last taxable year prior to the Closing Date; and (p) Foreign Tax Returns. Neither EUA nor any of its Subsidiaries is required to file a foreign tax return. "Taxes" as used in this Agreement, shall mean any federal, state, county, local or foreign taxes, charges, fees, levies, or other assessments, including all net income, gross income, premiums, sales and use, ad valorem, transfer, gains, profits, windfall profits, excise, franchise, real and personal property, gross receipts, capital stock, production, business and occupation, employment, disability, payroll, license, estimated, stamp, custom duties, severance or withholding taxes, other taxes or similar charges of any kind whatsoever imposed by any governmental entity, whether imposed directly on a Person or resulting under Treasury Regulation Section 1.1502-6 (or any similar provision of state, local or foreign law), as a transferee or successor, by contract or otherwise and includes any interest and penalties on or additions to any such taxes or in respect of a failure to comply with any requirement relating to any Tax Return. "Tax Return" as used in this Agreement, shall mean a report, return or other information required to be supplied to a governmental entity with respect to Taxes including, where permitted or required, combined, unitary or consolidated returns for any group of entities. 4.11 Employee Benefit Plans; ERISA. (a) Each "employee benefit plan" (as defined in Section 3(3) of the Employee Retirement Income Security Act of 1974, as amended ("ERISA")), bonus, deferred compensation, share option or other written agreement relating to employment or fringe benefits for employees, former employees, officers, trustees or directors of EUA or any of its Subsidiaries effective as of the date hereof or providing benefits as of the date hereof to current employees, former employees, officers, trustees or -12- directors of EUA or pursuant to which EUA or any of its subsidiaries has or could reasonably be expected to have any liability (collectively, the "EUA Employee Benefit Plans") is listed in Section 4.11(a) of the EUA Disclosure Letter, is in material compliance with applicable law, and has been administered and operated in all material respects in accordance with its terms. Each EUA Employee Benefit Plan which is intended to be qualified within the meaning of Section 401(a) of the Code has received a favorable determination letter from the IRS as to such qualification and, to the knowledge of EUA, no event has occurred and no condition exists which could reasonably be expected to result in the revocation of, or have any adverse effect on, any such determination. (b) Complete and correct copies of the following documents have been made available to NEES as of the date of this Agreement: (i) all EUA Employee Benefit Plans and any related trust agreements or insurance contracts, (ii) the most current summary descriptions of each EUA Employee Benefit Plan subject to ERISA, (iii) the three most recent Form 5500s and Schedules thereto for each EUA Employee Benefit Plan subject to such reporting, (iv) the most recent determination of the IRS with respect to the qualified status of each EUA Employee Benefit Plan that is intended to qualify under Section 401(a) of the Code, (v) the most recent accountings with respect to each EUA Employee Benefit Plan funded through a trust and (vi) the most recent actuarial report of the qualified actuary of each EUA Employee Benefit Plan with respect to which actuarial valuations are conducted. (c) Except as set forth in Section 4.11(c) of the EUA Disclosure Letter, neither EUA nor any Subsidiary maintains or is obligated to provide benefits under any EUA Employee Benefit Plan (other than as an incidental benefit under a Plan qualified under Section 401(a) of the Code) which provides health or welfare benefits to retirees or other terminated employees other than benefit continuations as required pursuant to Section 601 of ERISA. Each EUA Employee Benefit Plan subject to the requirements of Section 601 of ERISA has been operated in material compliance therewith. EUA has not contributed to a nonconforming group health plan (as defined in Code Section 5000(c)) and no person under common control with EUA within the meaning of Section 414 of the Code ("ERISA Affiliate") has incurred a tax liability under Code Section 5000(a) that is or could reasonably be expected to be a liability of EUA's. (d) Except as set forth in Section 4.11(d) of the EUA Disclosure Letter, each EUA Employee Benefit Plan covers only employees who are employed by EUA or a Subsidiary (or former employees or beneficiaries with respect to service with EUA or a Subsidiary). (e) Except as set forth in Section 4.11(e) of the EUA Disclosure Letter, neither EUA, any Subsidiary, any ERISA Affiliate nor any other corporation or organization controlled by or under common control with any of the foregoing within the meaning of Section 4001 of ERISA has, within the five-year period preceding the date of this Agreement, at any time contributed to any "multiemployer plan," as that term is defined in Section 4001 of ERISA. -13- (f) No event has occurred, and there exists no condition or set of circumstances in connection with any EUA Employee Benefit Plan, under which EUA or any Subsidiary, directly or indirectly (through any indemnification agreement or otherwise), could be subject to any liability under Section 409 of ERISA, Section 502(i) of ERISA, Title IV of ERISA or Section 4975 of the Code except for instances of non-compliance which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. (g) Neither EUA nor any ERISA Affiliate has incurred any liability to the Pension Benefit Guaranty Corporation (the "PBGC") under Section 302(c)(ii), 4062, 4063, 4064 or 4069 of ERISA, or otherwise that has not been satisfied in full and no event or condition exists or has existed which could reasonably be expected to result in any such material liability. As of the date of this Agreement, no "reportable event" within the meaning of Section 4043 of ERISA has occurred with respect to any EUA Employee Benefit Plan that is a defined benefit plan under Section 3(35) of ERISA. (h) Except as set forth in Section 4.11(h) of the EUA Disclosure Letter, no employer securities, employer real property or other employer property is included in the assets of any EUA Employee Benefit Plan. (i) Full payment has been made of all material amounts which EUA or any affiliate thereof was required under the terms of EUA Employee Benefit Plans to have paid as contributions to such plans on or prior to the Effective Time (excluding any amounts not yet due) and no EUA Employee Benefit Plan which is subject to Part III of Subtitle B of Title I of ERISA has incurred any "accumulated funding deficiency" within the meaning of Section 302 of ERISA or Section 412 of the Code, whether or not waived. (j) Except as set forth in Section 4.11(j) of the EUA Disclosure Letter, no amounts payable under any EUA Employee Benefit Plan or other agreement, contract, or arrangement will fail to be deductible for federal income tax purposes by virtue of Section 280G or Section 162(m) of the Code. 4.12 Labor Matters. As of the date hereof, except as set forth in Section 4.12 of the EUA Disclosure Letter, neither EUA nor any of its Subsidiaries is a party to any material collective bargaining agreement or other labor agreement with any union or labor organization. To the knowledge of EUA, as of the date hereof, there is no current union representation question involving employees of EUA or any of its Subsidiaries, nor does EUA know of any activity or proceeding of any labor organization (or representative thereof) or employee group to organize any such employees. Except as set forth in Section 4.12 of the EUA Disclosure Letter, (i) there is no unfair labor practice, employment discrimination or other employment-related complaint or proceeding against EUA or any of its Subsidiaries pending or, to the knowledge of EUA, threatened, which has or could reasonably be expected to have an EUA Material Adverse Effect, (ii) there is no strike, dispute, slowdown, work stoppage or lockout pending, or, to the knowledge of EUA, threatened, against or involving EUA or any of its Subsidiaries which has or could reasonably be expected to have, an EUA Material Adverse Effect and (iii) there is no proceeding, claim, -14- suit, or action pending or, to the knowledge of EUA or any of its Subsidiaries, threatened, nor, to the knowledge of EUA or any of its Subsidiaries is there any Governmental Authority investigation pending or threatened, in respect of which any trustee, director, officer, employee or agent of EUA or any of its Subsidiaries is or may be entitled to claim indemnification from EUA or any of its Subsidiaries pursuant to the EUA Trust Agreement, in the case of EUA, and their respective articles of incorporation and by-laws, in the case of EUA's Subsidiaries, or as provided in the indemnification agreements listed in Section 4.12 of the EUA Disclosure Letter. Except as set forth in Section 4.12 of the EUA Disclosure Letter, EUA and its Subsidiaries are in compliance with all federal, state and local laws with respect to employment practices and labor relations, including, without limitation, any provisions relating to affirmative action, employment discrimination, wages, hours, collective bargaining, and the payment of social security and similar taxes, safety and health regulations and mass layoffs and plant closings except for such instances of noncompliance which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. 4.13 Environmental Matters. Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or in Section 4.13 of the EUA Disclosure Letter: (a) (i) Each of EUA and its Subsidiaries is in compliance with all applicable Environmental Laws (as hereinafter defined), except where the failure to be in compliance, in the aggregate could not reasonably be expected to result in an EUA Material Adverse Effect; and (ii) Neither EUA nor any of its Subsidiaries has received any written communication from any person or Governmental Authority that alleges that EUA or any of its Subsidiaries is not in such compliance (including the materiality qualifier set forth in clause (i) above) with applicable Environmental Laws. (b) Each of EUA and its Subsidiaries has obtained all environmental, health and safety permits and governmental authorizations (collectively, the "Environmental Permits") necessary for the construction of their facilities and the conduct of their operations, as applicable, and all such Environmental Permits are in good standing or, where applicable, a renewal application has been timely filed and agency approval is expected in the ordinary course of business, and EUA and its Subsidiaries are in compliance with all terms and conditions of the Environmental Permits, except where the failure have such Environmental Permits, file a renewal application for such Environmental Permits, or to be in compliance with such Environmental Permits, in the aggregate could not reasonably be expected to result in an EUA Material Adverse Effect. (c) There is no Environmental Claim (as hereinafter defined) that could, individually or in the aggregate, reasonably be expected to have an EUA Material Adverse Effect pending (i) against EUA or any of its Subsidiaries; (ii) against any person or entity whose liability for any Environmental Claim EUA or any of its Subsidiaries has or may have retained or assumed either contractually or by operation of law; or (iii) against any real or personal -15- property or operations which EUA or any of its Subsidiaries owns, leases or manages, in whole or in part. (d) To the knowledge of EUA there have not been any material Releases (as hereinafter defined) of any Hazardous Material (as hereinafter defined) that would be reasonably likely to form the basis of any material Environmental Claim against EUA or any of its Subsidiaries, or against any person or entity whose liability for any material Environmental Claim EUA or any of its Subsidiaries has or may have retained or assumed either contractually or by operation of law, except for any Environmental Claim that, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. (e) To the knowledge of EUA with respect to any predecessor of EUA or any of its Subsidiaries, there is no material Environmental Claim pending or threatened, and there has been no Release of Hazardous Materials that could reasonably be expected to form the basis of any material Environmental Claim except for any Environmental Claim that, individually or in the aggregate, could not be reasonably be expected to have an EUA Material Adverse Effect. (f) As used in this Section 4.13: (i) "Environmental Claim" means any and all written administrative, regulatory or judicial actions, suits, demands, demand letters, directives, claims, liens, investigations, proceedings or notices or noncompliance, liability or violation by any person or entity (including any Governmental Authority) alleging potential liability (including, without limitation, potential responsibility or liability for enforcement, investigatory costs, cleanup costs, governmental response costs, removal costs, remedial costs, natural resources damages, property damages, personal injuries or penalties) arising out of, based on or resulting from (A) the presence, or Release or threatened Release into the environment, of any Hazardous Materials at any location, whether or not owned, operated, leased or managed by EUA or any of its Subsidiaries; or (B) circumstances forming the basis of any violation, or alleged violation, of any Environmental Law; or (C) any and all claims by any third party seeking damages, contribution, indemnification, cost recovery, compensation or injunctive relief resulting from the presence or Release of any Hazardous Materials; (ii) "Environmental Laws" means all federal, state and local laws, rules and regulations and binding interpretation thereof, relating to pollution, the environment (including, without limitation, ambient air, surface water, groundwater, land surface or subsurface strata) or protection of human health as it relates to the environment including, without limitation, laws and -16- regulations relating to Releases or threatened Releases of Hazardous Materials, or otherwise relating to the manufacture, generation, processing, distribution, use, treatment, storage, disposal, transport or handling of Hazardous Materials; (iii) "Hazardous Materials" means (A) any petroleum or petroleum products, radioactive materials, asbestos in any form that is or could become friable, urea formaldehyde foam insulation, and transformers or other equipment that contain dielectric fluid containing polychlorinated biphenyls; and (B) any chemicals, materials or substances which are now defined as or included in the definition of "hazardous substances", "hazardous wastes", "hazardous materials", "extremely hazardous wastes", "restricted hazardous wastes", "toxic substances", "toxic pollutants", or words of similar import, under any Environmental Law; and (c) any other chemical, material, substance or waste, exposure to which is now prohibited, limited or regulated under any Environmental Law in a jurisdiction in which EUA or any of its Subsidiaries (x) operates or (y) stores, treats or disposes of Hazardous Materials; and (iv) "Release" means any release, spill, emission, leaking, injection, deposit, disposal, discharge, dispersal, leaching or migration into the atmosphere, soil, surface water, groundwater or property. 4.14 Regulation as a Utility. (a) EUA is a public utility holding company registered under Section 5, and subject to the provisions, of the 1935 Act. Section 4.14 of the EUA Disclosure Letter lists the subsidiaries of EUA that are "public utility companies" within the meaning of Section 2(a)(5) of the 1935 Act and lists the jurisdictions where each such Subsidiary is subject to regulation as a public utility company or public service company. Except as set forth above and as set forth in Section 4.14 of the EUA Disclosure Letter, neither EUA nor any "subsidiary company" or "affiliate" of EUA is subject to regulation as a public utility or public service company (or similar designation) by the federal government of the United States, any state in the United States or any political subdivision thereof, or any foreign country. (b) As used in this Section 4.14, the terms "subsidiary company" and "affiliate" shall have the respective meanings ascribed to them in Section 2(a)(8) and Section 2(a)(11), respectively, of the 1935 Act. 4.15 Insurance. Except as set forth in Section 4.15 of the EUA Disclosure Letter, each of EUA and its Subsidiaries is, and has been continuously since January 1, 1994, insured with financially responsible insurers in such amounts and against such risks and losses as are customary in all material respects for companies in the United States conducting the business conducted by EUA and its Subsidiaries during such time period. Except as set forth in Section 4.15 of the EUA Disclosure Letter, neither EUA nor any of its Subsidiaries has received any notice of cancellation or termination with respect to any material insurance policy of EUA or any of its Subsidiaries. The insurance policies of EUA and each of its Subsidiaries are valid and enforceable policies. -17- 4.16 Nuclear Facilities. Montaup Electric Company, a Subsidiary of EUA, is a minority common stockholder of each of Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power Corporation and Yankee Atomic Electric Company (the "Yankee Companies") and a minority joint owner in Millstone 3 and Seabrook 1 (collectively, as described in Section 4.16 of the EUA Disclosure Letter, the "EUA Nuclear Facilities"). With respect to its ownership of Millstone 3 and Seabrook 1, Montaup Electric Company holds the required operating licenses from the NRC. With respect to the Yankee Companies, each Yankee Company holds its own operating license from the NRC. Because it is a minority stockholder or a minority joint owner, Montaup Electric Company does not have responsibility for the operation of EUA Nuclear Facilities. Except as set forth in Section 4.16 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date hereof, to the knowledge of EUA, neither EUA nor any of its Subsidiaries is in violation of any applicable health, safety, regulatory and other legal requirement, including NRC laws and regulations and Environmental Laws, applicable to EUA Nuclear Facilities except for such failure to comply as could not reasonably be expected to have a material adverse effect with respect to EUA Nuclear Facilities and the ownership interest of EUA therein. To the knowledge of EUA, each of EUA Nuclear Facilities maintains emergency plans designed to respond to an unplanned release therefrom of radioactive materials into the environment and insurance coverages consistent with industry practice. EUA has funded, or has caused the funding of, its portion of the decommissioning cost of each of the EUA Nuclear Facilities and the storage of spent nuclear fuel consistent with the most recently approved plan for each of the EUA Nuclear Facilities and FERC authorized rates. Except as set forth in Section 4.16 of the EUA Disclosure Letter, to the knowledge of EUA, no EUA Nuclear Facility is as of the date of this Agreement on the List of Nuclear Power Plants Warranting Increased Regulatory Attention maintained by the NRC. 4.17 Vote Required. The affirmative vote of two-thirds of the outstanding EUA Shares voting as a single class (with each EUA Share having one vote per share) with respect to the approval of the Merger and other transactions contemplated hereby is the only vote of the holders of any class or series of equity securities of EUA or its Subsidiaries required to approve this Agreement and approve the Merger and other transactions contemplated hereby. 4.18 Opinion of Financial Advisor. EUA has received the opinion of Salomon Smith Barney Inc., dated the date of this Agreement, to the effect that, as of such date, the Merger Consideration is fair from a financial point of view to the holders of EUA Shares. A true and complete copy of the written opinion will be delivered to NEES promptly after receipt thereof by EUA. 4.19 Ownership of NEES Common Shares. Neither EUA nor any of its Subsidiaries or other affiliates beneficially owns any NEES Common Shares. 4.20 State Anti-Takeover Statutes. EUA has taken all necessary actions so that the provisions of Chapters 110C, 110D or 110F of the MGL will not apply to this Agreement, the Merger or other transactions contemplated hereby or thereby. -18- 4.21 Year 2000. The Information Systems operated by EUA and its Subsidiaries which is used in the conduct of their business is capable of providing or being adapted to provide uninterrupted millennium functionality to record, store, process and present calendar dates falling on or after January 1, 2000 in substantially the same manner and with the same functionality as such Information Systems record, store, process and present such calendar dates falling on or before December 31, 1999 other than such interruptions in millennium functionality that could not, individually or in the aggregate, reasonably be expected to result in a EUA Material Adverse Effect. EUA reasonably believes as of the date hereof that the remaining cost of adaptations referred to in the foregoing sentence will not exceed the amounts reflected in the Form 10-Q filed by EUA for the quarter ended September 30, 1998 (excluding the fees and costs of any Y2K Consultant retained pursuant to Section 6.01(o) hereof and of the implementation of any recommendations by such Y2K Consultant actually made by EUA that are not already part of EUA's compliance plan as of the date hereof). "Information Systems" means mainframe and midrange hardware, operating system software and applications programs; network and desktop (PC) hardware, operating system software and applications programs; EDI (Electronic Date Interchange) and FTP (File Transfer Protocol) software; and embedded systems hardware and applications software. 4.22 EUA Associates. The representations and warranties set forth in Sections 4.04(a), 4.06, 4.07, 4.09, 4.12 and 4.13 are true and correct in all material respects with regard to EUA Associates. ARTICLE V REPRESENTATIONS AND WARRANTIES OF NEES NEES represents and warrants to EUA as follows: 5.01 Organization and Qualification. NEES is a voluntary association duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has full power, authority and legal right to own its property and assets and to transact the business in which it is engaged. Each of the NEES Subsidiaries is a corporation duly organized or incorporated, validly existing and in good standing under the laws of its jurisdiction of organization or incorporation and has full corporate power and authority to conduct its business as and to the extent now conducted and to own, use and lease its assets and properties, except where failure to be so organized or incorporated, existing and in good standing or to have such power and authority, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. As used in this Agreement, the term "NEES Material Adverse Effect" means a material adverse effect on the business, assets, results of operations, condition (financial or otherwise) or prospects of NEES and its Subsidiaries taken as a whole. LLC is a limited liability company validly existing under the laws of the Commonwealth of Massachusetts. LLC was formed solely for the purpose of engaging in the Merger and other transactions contemplated hereby, has engaged in no other business activities (other than in connection with the formation and capitalization of LLC pursuant to or in -19- accordance with the LLC Agreement (as defined below)) and has conducted its operations only as contemplated hereby and by the LLC Agreement. Each of NEES and its Subsidiaries is duly qualified, licensed or admitted to do business and is in good standing in each jurisdiction in which the ownership, use or leasing of its assets and properties, or the conduct or nature of its business, makes such qualification, licensing or admission necessary, except where failure to be so qualified, licensed or admitted and in good standing, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. NEES has previously delivered to EUA correct and complete copies of its Agreement and Declaration of Trust (the "NEES Trust Agreement") and the articles of association of LLC. 5.02 Authority. Each of NEES and LLC has full power and authority to enter into this Agreement, and to perform its obligations hereunder, and to consummate the Merger and other transactions contemplated hereby. The execution, delivery and performance of this Agreement by each of NEES and LLC and the consummation by each of NEES and LLC of the Merger and other transactions contemplated hereby have been duly authorized by all necessary corporate action on the part of NEES and all necessary action on the part of LLC. This Agreement has been duly and validly executed and delivered by each of NEES and LLC and constitutes a legal, valid and binding obligation of each of NEES and LLC enforceable against each of NEES and LLC in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). 5.03 Capital Stock. The authorized equity securities of NEES consists of 150,000,000 common shares of NEES (the "NEES Shares"), of which 59,170,986 shares were issued and outstanding as of the close of business on January 29, 1999. As of the close of business on January 29, 1999, 5,798,666 NEES Shares were held in the treasury of NEES. All of the issued and outstanding NEES Shares are duly authorized, validly issued, fully paid and nonassessable. Except as may be provided by the New England Electric System Companies' Incentive Share Plan, the New England Electric System Companies Incentive Thrift Plan I, the New England Electric System Companies Incentive Thrift Plan II, the New England Electric Companies Long-Term Performance Share Award Plan, and the New England Electric System Directors' annual retainer shares, and except as set forth in Section 5.03 of the letter dated the date hereof and delivered to EUA by NEES and LLC concurrently with the execution and delivery of this Agreement (the "NEES Disclosure Letter"), on the date hereof there are no outstanding Options obligating NEES or any of its Subsidiaries to issue or sell any shares of equity securities of NEES or to grant, extend or enter into any Option with respect thereto. 5.04 Non-Contravention; Approvals and Consents. (a) The execution and delivery of this Agreement by each of NEES and LLC do not, and the performance by each of NEES and LLC of its obligations hereunder and the consummation of the Merger and other transactions contemplated hereby will not, conflict with, result in a violation or breach of, constitute (with or without notice or lapse of time or both) a default under, result in or give to any person any right of payment or reimbursement, termination, cancellation, modification or -20- acceleration of, or result in the creation or imposition of any Lien upon any of the assets or properties of NEES, or LLC under, any of the terms, conditions or provisions of (i) the NEES Agreement and Declaration of Trust or the articles of organization of LLC, (ii) subject to the actions described in paragraph (b) of this Section, (x) any laws or orders of any Governmental Authority applicable to NEES or LLC or any of their respective assets or properties, or (y) subject to obtaining the third-party consents (the "NEES Required Consents") set forth in Section 5.04 of the NEES Disclosure Letter any Contracts to which NEES is a party or by which NEES or any of its Subsidiaries or any of their respective assets or properties is bound, excluding from the foregoing clauses (x) and (y) conflicts, violations, breaches, defaults, terminations, modifications, accelerations and creations and impositions of Liens which, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. (b) No declaration, filing or registration with, or notice to or authorization, consent or approval of, any Governmental Authority is necessary for the execution and delivery of this Agreement by NEES or LLC or the consummation by NEES or LLC of the Merger and other transactions contemplated hereby except as described in Section 5.04 of the NEES Disclosure Letter or the failure of which to obtain could not reasonably be expected to result in a NEES Material Adverse Effect (the "NEES Required Statutory Approvals," it being understood that references in this Agreement to "obtaining" such NEES Required Statutory Approvals shall mean making such declarations, filings or registrations; giving such notices; obtaining such authorizations, consents or approvals; and having such waiting periods expire as are necessary to avoid a violation of law). 5.05 Information Supplied. (a) The information supplied by NEES or LLC and included in the Proxy Statement with the written consent of NEES or LLC, as the case may be, will not, at the date mailed to EUA's Shareholders or at the time of EUA Shareholder's Meeting, contain any untrue statements of a material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. (b) Notwithstanding the foregoing provisions of this Section 5.05, no representation or warranty is made by NEES with respect to statements made or incorporated by reference in the Proxy Statement based on information supplied by EUA for inclusion or incorporation by reference therein or based on information which is not made in or incorporated by reference in such documents but which should have been disclosed pursuant to this Section 5.05. 5.06 Compliance. Except as set forth in Section 5.06 of the NEES Disclosure Letter, or as disclosed in the NEES Reports filed prior to the date hereof, NEES is not in violation of, is, to the knowledge of NEES, under investigation with respect to any violation of, or has been given notice or been charged with any violation of, any law, statute, order, rule, regulation, ordinance or judgment (including, without limitation, any applicable environmental law, ordinance or regulation) of any Governmental Authority, except for possible violations which, individually or in the aggregate, could -21- not reasonably be expected to have a NEES Material Adverse Effect. Except as set forth in Section 5.06 of the NEES Disclosure Letter or as disclosed in the NEES Reports filed prior to the date hereof, NEES and its Subsidiaries have all material permits, licenses and other governmental authorizations, consents and approvals necessary to conduct their businesses as presently conducted which are material to the operation of the businesses of NEES. NEES is not in breach or violation of, or in default in the performance or observance of, any term or provision of, and no event has occurred which, with lapse of time or action by a third party, could result in a default by NEES under (i) the NEES Agreement and Declaration of Trust or by-laws or (ii) any contract, commitment, agreement, indenture, mortgage, loan agreement, note, lease, bond, license, approval or other instrument to which it is a party or by which NEES is bound or to which any of their respective property is subject, except for possible violations, breaches or defaults which, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. 5.07 Financing. NEES has or will have available, prior to the Effective Time, sufficient cash in immediately available funds to pay or to cause LLC to pay the Merger Consideration pursuant to Article II hereof and to consummate the Merger and other transactions contemplated hereby. 5.08 No Vote Required. No vote of the NEES Shares or of any class or series of equity securities of NEES or its Subsidiaries is necessary for the approval of the Merger and other transactions contemplated hereby. 5.09 Ownership of EUA Shares. Neither NEES nor any of its Subsidiaries or other affiliates beneficially owns any EUA Shares. 5.10 Merger with The National Grid Group plc. NEES has entered into an Agreement and Plan of Merger dated as of December 11, 1998 by and among The National Grid Group plc ("National Grid Group"), NGG Holdings LLC (formerly known as Iosta LLC) and NEES (the "National Grid Merger Agreement"). Pursuant to Section 6.01 of the National Grid Merger Agreement, NEES has provided a copy of this Agreement to National Grid Group, and National Grid Group has given NEES its written consent to enter into this Agreement and consummate the Merger on the terms set forth in this Agreement. Prior to the execution of this Agreement, NEES has provided EUA with a copy of such written consent. ARTICLE VI COVENANTS 6.01 Covenants of EUA. At all times from and after the date hereof until the Effective Time, EUA covenants and agrees as to itself and its Subsidiaries that (except as expressly contemplated or permitted by this Agreement or as set forth in Section 6.01 of the EUA Disclosure Letter, or to the extent that NEES shall otherwise previously consent in writing): -22- (a) Ordinary Course. EUA and each of its Subsidiaries shall conduct their businesses only in, and EUA and each of its Subsidiaries shall not take any action except in, the ordinary course consistent with good utility practice. Without limiting the generality of the foregoing, EUA and its Subsidiaries shall use all commercially reasonable efforts to preserve intact in all material respects their present business organizations and reputation, to maintain in effect all existing permits, to keep available the services of their key officers and employees, to maintain their assets and properties in good working order and condition, ordinary wear and tear excepted, to maintain insurance on their tangible assets and businesses in such amounts and against such risks and losses as are currently in effect, to preserve their relationships with customers and suppliers and others having significant business dealings with them and to comply in all material respects with all laws and orders of all Governmental Authorities applicable to them. (b) Charter Documents. EUA shall not, nor shall it permit any of its Subsidiaries to, amend or propose to amend the EUA Trust Agreement, in the case of EUA, and its certificate or articles of incorporation or organization or bylaws (or other comparable charter documents), in the case of EUA's Subsidiaries. (c) Dividends. EUA shall not, nor shall it permit any of its Subsidiaries to, (i) declare, set aside or pay any dividends on, or make other distributions in respect of, any of its capital stock or share capital, except: (A) that EUA may continue the declaration and payment of regular quarterly dividends on EUA Shares with usual record and payment dates not, in any fiscal year, in excess of the dividend for the comparable period in the prior fiscal year; (B) that the Subsidiaries of EUA set forth in Section 6.01(c) of the EUA Disclosure Letter may continue the declaration and payment of dividends on preferred stock in accordance with the terms of such stock, with the record and payment dates and in the amounts set forth in Section 6.01(c) of the EUA Disclosure Letter; (C) if the Effective Time does not occur between a record date and payment date of a regular quarterly dividend, for a special dividend on EUA Shares with respect to the quarter in which the Effective Time occurs with a record date on or prior to the date on which the Effective Time occurs, which does not exceed an amount equal to the product of (x) the number of days between the last payment date of a regular quarterly dividend and the record date of such special dividend, multiplied by (y) $.0045; and (D) for dividends and distributions (including liquidating distributions) by a direct or indirect Subsidiary of EUA to its parent. -23- (ii) split, combine, subdivide, reclassify or take similar action with respect to any of its capital stock or share capital or issue or authorize or propose the issuance of any other securities in respect of, in lieu of or in substitution for shares of its capital stock or comprised in its share capital, (iii) adopt a plan of complete or partial liquidation or resolutions providing for or authorizing such liquidation or a dissolution, merger, consolidation, restructuring, recapitalization or other reorganization or (iv) directly or indirectly redeem, repurchase or otherwise acquire any shares of its capital stock or any Option with respect thereto except: (A) in connection with intercompany purchases of capital stock or share capital, (B) for the purpose of funding EUA's dividend reinvestment and share purchase plan in accordance with past practice, or (C) subject to EUA's obligations under the Securities Act and the Exchange Act, pursuant to EUA's previously announced share repurchase program provided that the number of EUA Shares repurchased does not exceed 3,000,000 and the price paid per share does not exceed 95% of the Per Share Amount. (d) Share Issuances. EUA shall not, nor shall it permit any of its Subsidiaries to, issue, deliver or sell, or authorize or propose the issuance, delivery or sale of, any shares of its capital stock or any Option with respect thereto (other than the issuance by a wholly owned Subsidiary of its capital stock to its direct or indirect parent corporation, or modify or amend any right of any holder of outstanding shares of capital stock or Options with respect thereto). (e) Acquisitions. EUA shall not, nor shall it permit any of its Subsidiaries to acquire or agree to acquire (by merging or consolidating with, or by purchasing a substantial equity interest in or substantial portion of the assets of, or by any other manner) any business or any corporation, partnership, association or other business organization or division thereof. (f) Dispositions. EUA shall not, nor shall it permit any of its Subsidiaries to sell, lease, securitize, grant any security interest in or otherwise dispose of or encumber any of its assets or properties, other than dispositions in the ordinary course of its business consistent with past practice and having an aggregate value of less than $1,000,000 for each disposition and $5,000,000 in the aggregate. (g) Indebtedness. EUA shall not, nor shall it permit any of its Subsidiaries to incur or guarantee any indebtedness (including any debt borrowed or guaranteed or otherwise assumed, including, without limitation, the issuance of debt securities or warrants or rights to acquire debt) or enter into any "keep well" or other agreement to maintain any financial condition of another Person or enter into any arrangement having the economic effect of any of the foregoing other than (i) short-term indebtedness in the ordinary course of business consistent with past practice (such as the issuance of commercial paper -24- or the use of existing credit facilities) in amounts not exceeding the amounts set forth in Section 6.01(g) of the EUA Disclosure Letter, (ii) long-term indebtedness in connection with the refinancing of existing indebtedness either at its stated maturity or at a lower cost of funds (calculating such cost on an aggregate after-tax basis) or (iii) guarantees or "keep well" agreements in favor of wholly owned Subsidiaries of EUA in connection with the conduct of the business of such wholly owned Subsidiaries of EUA not aggregating more than $1,000,000. (h) Capital Expenditures. Except (i) as required by law or (ii) as reasonably deemed necessary by EUA after consulting with NEES following a catastrophic event, such as a major storm, EUA shall not, nor shall it permit any of its Subsidiaries to make any capital expenditures or commitments during any fiscal year that is in excess of 110% of (i) the aggregate amount set forth in Section 6.01(h) of the EUA Disclosure Letter with respect to EUA and its Subsidiaries that are public utility companies within the meaning of Section 2(a)(5) of the 1935 Act or (ii) the amount set forth in Section 6.01(h) of the EUA Disclosure Letter with respect to each of EUA's other Subsidiaries. (i) Employee Benefits. EUA shall not, nor shall it permit any of its Subsidiaries to enter into, adopt, amend (except as may be required by applicable law) or terminate any EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy between EUA or one of its Subsidiaries and one or more of its trustees, directors, officers, employees or former employees, or, except for normal increases in the ordinary course of business, (a) increase in any manner the compensation or fringe benefits of any trustee, director or executive officer, (b) increase in any manner the compensation or fringe benefits of any employee, (c) pay any benefit not required by any plan or arrangement in effect as of the date hereof or, (d) cause any trustee, director, officer, employee or former employee of EUA to accrue or receive additional benefits, accelerate vesting or accelerate the payment of any benefits under any EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy. EUA, prior to the Closing Date, shall take all necessary action and make all necessary amendments to its stock-based plans so that all such plans will be in a form that allows the plans to function after the Effective Time and after any merger of EUA and its Subsidiaries into NEES or its Subsidiaries. EUA, prior to the Closing Date, shall take all necessary actions, in a manner satisfactory to NEES, so that on or after the Closing Date, neither EUA, the Surviving Entity nor their affiliates' stock or securities will be required to be held in, or distributed pursuant to, any EUA Employee Benefit Plan. (j) Labor Matters. Notwithstanding any other provision of this Agreement to the contrary, EUA or its Subsidiaries may negotiate successor collective bargaining agreements to those referenced in Section 4.12 hereof, and may negotiate other collective bargaining agreements or arrangements as required by law or for the purpose of implementing the agreements referenced in Section 4.12 hereof. EUA will keep NEES informed as to the status of, and will consult with NEES as to the strategy for, all negotiations with collective bargaining representatives. EUA and its Subsidiaries shall act prudently and reasonably and consistent with their obligation under applicable law in such negotiations. -25- (k) Discharge of Liabilities. EUA shall not, nor shall it permit its Subsidiaries to, pay, discharge or satisfy any material claims, liabilities or obligations (absolute, accrued, asserted or unasserted, contingent or otherwise), other than the payment, discharge or satisfaction, in the ordinary course of business consistent with past practice (which includes the payment of final and unappealable judgments) or in accordance with their terms, of liabilities reflected or reserved against in, or contemplated by, the most recent consolidated financial statements (or the notes thereto) of such party included in EUA SEC Reports, or incurred in the ordinary course of business consistent with past practice. (l) Contracts. EUA shall not, nor shall it permit its Subsidiaries, except in the ordinary course of business consistent with past practice or as set forth in Section 6.01(l) of the EUA Disclosure Letter, (i) to modify, amend, terminate or fail to use commercially reasonable efforts to renew any material Contract to which EUA or any of its Subsidiaries is a party or waive, release or assign any material rights or claims or (ii) to enter into any new material Contracts except as expressly permitted by Sections 6.01 (f), (g) or (i) and 7.06 hereof. (m) Equity Investments. EUA shall not, nor shall it permit its Subsidiaries or affiliates to, make equity contributions to non-affiliates or to its non-utility Subsidiaries. (n) Loans. EUA shall not, nor shall it permit its Subsidiaries or affiliates to, loan money to non-affiliates or to its non-utility Subsidiaries. (o) Year 2000. EUA, within 15 days of the date of this Agreement, shall engage a qualified third party ("Y2K Consultant") to conduct a detailed assessment of the adequacy and state of completion of its Year 2000 Program, including but not limited to assessment and testing of its customer, accounting, and operational systems. The Y2K Consultant and scope of work of the Y2K Consultant shall be acceptable to NEES. Such assessment and testing shall be completed as soon thereafter as practicable. EUA shall have such assessment updated by the Y2K Consultant at the end of each fiscal quarter of 1999. EUA shall allow designated NEES personnel and representatives access to the Y2K Consultant's personnel, reports and recommendations and access to EUA's personnel, documents, and information related to the Y2K issue. EUA and the third party shall meet with such designated NEES personnel and representatives on a periodic basis (but not less frequently than monthly) to update NEES on EUA's Year 2000 Program. If this Agreement is terminated pursuant to Section 9.01 hereof, NEES shall reimburse EUA for the costs and expenses of the Y2K Consultant. (p) Insurance. EUA shall, and shall cause its Subsidiaries to, maintain with financially responsible insurance companies (or through self-insurance, consistent with past practice) insurance in such amounts and against such risks and losses as are customary for companies engaged in their respective businesses. (q) 1935 Act. EUA shall not, nor shall it permit any of its Subsidiaries to, engage in any activities which would cause a change in its status, or that of its Subsidiaries, under the 1935 Act. -26- (r) Regulatory Matters. Subject to applicable law and except for non-material filings in the ordinary course of business consistent with past practice, EUA shall consult with NEES prior to implementing any changes in its or any of its Subsidiaries' rates or charges, standards of service or accounting or executing any agreement with respect thereto that is otherwise permitted under this Agreement and shall, and shall cause its Subsidiaries to, deliver to NEES a copy of each such filing or agreement at least four (4) business days prior to the filing or execution thereof so that NEES may comment thereon. EUA shall, and shall cause its Subsidiaries to, make all such filings (i) only in the ordinary course of business consistent with past practice or (ii) as required by a Governmental Authority or regulatory agency with appropriate jurisdiction. (s) Accounting. EUA shall not, nor shall it permit any of its Subsidiaries to make any changes in their accounting methods, policies or procedures, except as required by law, rule, regulation or applicable generally accepted accounting principles; (t) Tax Status. Neither EUA nor any of its Subsidiaries shall (i) make or rescind any material express or deemed election relating to Taxes, (ii) make a request for a Tax Ruling or enter into a Closing Agreement, (iii) settle or compromise any material claim, action, suit, litigation, proceeding, arbitration, investigation, audit, or controversy relating to Taxes or (iv) change in any material respect any of its methods of reporting income, deductions or accounting for federal income tax purposes from those employed in the preparation of its federal income Tax Return for the taxable year ending December 31, 1997, except as may be required by applicable law. (u) No Breach. EUA shall not, nor shall it permit any of its Subsidiaries to willfully take or fail to take any action that would or is reasonably likely to result in (i) a material breach of any provision of this Agreement or (ii) its representations and warranties set forth in this Agreement being untrue in any material respect on and as of the Closing Date. (v) Advice of Changes. EUA shall confer with NEES on a regular and frequent basis with respect to EUA's business and operations and other matters relevant to the Merger to the extent permitted by law, and shall promptly advise NEES, orally and in writing, of any material change or event, including, without limitation, any complaint, investigation or hearing by any Governmental Authority (or communication indicating the same may be contemplated) or the institution or threat of material litigation; provided that EUA shall not be required to make any disclosure to the extent such disclosure would constitute a violation of any applicable law or regulation. (w) Notice and Cure. EUA will notify NEES in writing of, and will use all commercially reasonable efforts to cure before the Closing, any event, transaction or circumstance, as soon as practical after it becomes known to EUA, that causes or will or may be likely to cause any covenant or agreement of EUA under this Agreement to be breached or that renders or will render untrue in any material respect any representation or warranty of EUA contained in this Agreement. EUA also will notify NEES in writing of, and will use all -27- commercially reasonable efforts to cure, before the Closing, any material violation or breach, as soon as practical after it becomes known to EUA, of any representation, warranty, covenant or agreement made by EUA. No notice given pursuant to this paragraph shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein. (x) Fulfillment of Conditions. Subject to the terms and conditions of this Agreement, EUA will take or cause to be taken all commercially reasonable steps necessary or desirable and proceed diligently and in good faith to satisfy each condition to the other's obligations contained in this Agreement and to consummate and make effective the Merger and other transactions contemplated by this Agreement, and EUA will not, nor will it permit any of its Subsidiaries to, take or fail to take any action that could be reasonably expected to result in the nonfulfillment of any such condition. (y) Third Party Standstill Agreements. Except as provided in Section 7.08 hereto, during the period from the date of this Agreement through the Effective Time, neither EUA nor any of its Subsidiaries shall terminate, amend, modify or waive any provision of any confidentiality or standstill agreement to which it is a party. During such period, EUA shall take all steps necessary to enforce, to the fullest extent permitted under applicable law, the provisions of any such agreement. 6.02 Covenants of NEES. At all times from and after the date hereof until the Effective Time, NEES covenants and agrees that (except as expressly contemplated or permitted by this Agreement or to the extent that EUA shall otherwise previously consent in writing): (a) No Breach. NEES shall not, nor shall it permit any of its Subsidiaries to, except as otherwise expressly provided for in this Agreement, willfully take or fail to take any action that would or is reasonably likely to result in (i) a material breach of any of its covenants or agreements contained in this Agreement or (ii) any of its representations and warranties set forth in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.06, 5.07, 5.08 and 5.09 of this Agreement being untrue in any material respect on and as of the Closing Date. (b) Advice of Changes. NEES shall confer with EUA on a regular and frequent basis with respect to any matter having, or which, insofar as can be reasonably foreseen, could reasonably be expected to have, a NEES Material Adverse Effect or materially impair the ability of NEES to consummate the Merger and other transactions contemplated hereby; provided that NEES shall not be required to make any disclosure to the extent such disclosure would constitute a violation of any applicable law or regulation. (c) Notice and Cure. NEES will notify EUA in writing of, and will use all commercially reasonable efforts to cure before the Closing, any event, transaction or circumstance, as soon as practical after it becomes known to NEES, that causes or will or may be likely to cause any covenant or agreement of NEES under this Agreement to be breached or that renders or will render -28- untrue in any material respect any representation or warranty of NEES contained in this Agreement. NEES also will notify EUA in writing of, and will use all commercially reasonable efforts to cure before the Closing, any material violation or breach, as soon as practical after it becomes known to such party, of any representation, warranty, covenant or agreement made by NEES. No notice given pursuant to this paragraph shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein. (d) Fulfillment of Conditions. Subject to the terms and conditions of this Agreement, NEES will take or cause to be taken all commercially reasonable steps necessary or desirable and proceed diligently and in good faith to satisfy each condition to its obligations contained in this Agreement and to consummate and make effective the Merger and other transactions contemplated by this Agreement, and NEES will not, nor will it permit any of its Subsidiaries to, take or fail to take any action that could be reasonably expected to result in the nonfulfillment of any such condition. (e) Conduct of Business of LLC. Prior to the Effective Time, except as may be required by applicable law and subject to the other provisions of this Agreement, NEES shall cause LLC to (i) perform its obligations under this Agreement in accordance with its terms, and (ii) not engage directly or indirectly in any business or activities of any type or kind and not enter into any agreements or arrangements with any person, or be subject to or bound by any obligation or undertaking, which is inconsistent with this Agreement. (f) Certain Mergers. NEES shall not, and shall not permit any of its Subsidiaries to, acquire or agree to acquire by merging or consolidating with, or by purchasing a substantial portion of the assets of or equity in, or by any other manner, any business or any corporation, partnership, association or other business organization or division thereof, or otherwise acquire or agree to acquire any assets if the entering into of a definitive agreement relating to or the consummation of such acquisition, merger or consolidation could reasonably be expected to (i) impose any material delay in the obtaining of, or significantly increase the risk of not obtaining, any authorizations, consents, orders, declarations or approvals of any Governmental Authority necessary to consummate the Merger or the expiration or termination of any applicable waiting period, (ii) significantly increase the risk of any Governmental Authority entering an order prohibiting the consummation of the Merger, (iii) significantly increase the risk of not being able to remove any such order on appeal or otherwise or (iv) materially delay the consummation of the Merger. 6.03 Additional Covenants by NEES and EUA. (a) Control of Other Party's Business. Nothing contained in this Agreement shall give NEES, directly or indirectly, the right to control or direct EUA's operations prior to the Effective Time. Nothing contained in this Agreement shall give EUA, directly or indirectly, the right to control or direct NEES' operations prior to the Effective Time. Prior to the Effective Time, each of EUA and NEES shall exercise, consistent with the terms and conditions of this Agreement, complete control and supervision over its respective operations. -29- (b) Transition Steering Team. As soon as reasonably practicable after the date hereof, NEES and EUA shall create a special transition steering team, with representation from EUA and NEES, that will develop recommendations concerning the future structure and operations of EUA after the Effective Time, subject to applicable law. The members of the transition steering team shall be appointed by the Chief Executive Officers of NEES and EUA. The functions of the transition steering team shall include (i) to direct the exchange of information and documents between the parties and their Subsidiaries as contemplated by Section 7.01 and (ii) the development of regulatory plans and proposals, corporate organizational and management plans, workforce combination proposals, and such other matters as they deem appropriate. ARTICLE VII ADDITIONAL AGREEMENTS 7.01 Access to Information. EUA shall, and shall cause each of its Subsidiaries to, and shall use commercially reasonable efforts to cause EUA Associates to, throughout the period from the date hereof to the Effective Time to the extent permitted by law, (i) provide NEES and its Representatives with full access, upon reasonable prior notice and during normal business hours, to all facilities, operations, officers (including EUA's environmental, health and safety personnel), employees, agents and accountants of EUA and its Subsidiaries and Associates and their respective assets, properties, books and records, to the extent EUA or any Subsidiary of EUA or EUA Associate is not under a legal obligation not to provide access or to the extent that such access would not constitute a waiver of the attorney client privilege and does not unreasonably interfere with the business and operations of EUA and its Subsidiaries and Associates and (ii) furnish promptly to such persons (x) a copy of each report, statement, schedule and other document filed or received by EUA or any of its Subsidiaries pursuant to the requirements of federal or state securities laws and each material report, statement, schedule and other document filed with any other Governmental Authority, and (y) all other information and data (including, without limitation, copies of Contracts, EUA Employee Benefit Plans, and other books and records) concerning the business and operations of EUA and its Subsidiaries as NEES or any of its Representatives reasonably may request. No review pursuant to this Section 7.01 or otherwise shall affect any representation or warranty contained in this Agreement or any condition to the obligations of the parties hereto. Any such information or material obtained pursuant to this Section 7.01 that constitutes "Evaluation Material" (as such term is defined in the letter agreement dated as of December 18, 1998 between EUA and NEES (the "Confidentiality Agreement")) shall be governed by the terms of the Confidentiality Agreement. NEES may provide information or materials that it obtains relating to EUA or any EUA Subsidiary pursuant to this Section 7.01 to National Grid Group; the treatment by National Grid Group of such information or material shall be governed by the terms of the letter agreement dated as of December 21, 1998 between EUA and National Grid Group. 7.02 Proxy Statement. As soon as reasonably practicable after the date of this Agreement, EUA shall prepare and file the Proxy Statement with the -30- SEC. NEES and EUA shall cooperate with each other in the preparation of the Proxy Statement and any amendment or supplement thereto, and EUA shall promptly notify NEES of the receipt of any comments of the SEC with respect to the Proxy Statement and of any requests by the SEC for any amendment or supplement thereto or for additional information, and shall promptly provide to NEES copies of all correspondence between EUA or any of its Representatives and the SEC with respect to the Proxy Statement (except reports from financial advisors other than with the consent of such financial advisors). Each of the parties hereto shall furnish all information concerning itself which is required or customary for inclusion in the Proxy Statement. EUA shall consult with NEES regarding the Proxy Statement and have due regard to any comments NEES may make in relation to the Proxy Statement. EUA shall give NEES and its counsel the opportunity to review the Proxy Statement and all responses to requests for additional information by and replies to comments of the SEC before their being filed with, or sent to, the SEC. Each of EUA and NEES agrees to use its reasonable best efforts, after consultation with the other parties hereto, to respond promptly to all such comments of and requests by the SEC. After obtaining the consent of EUA, which consent shall not be unreasonably withheld, NEES may provide information supplied to NEES by EUA to National Grid Group for inclusion of such information in the Super Class 1 circular ("NGG Circular") to be issued to shareholders of National Grid Group in connection with approval by such shareholders of the National Grid Merger Agreement. NEES shall use its best efforts to provide EUA with a draft of any portion of the NGG Circular with information relating to EUA prior to the issuance of the NGG Circular. 7.03 Approval of Shareholders. EUA shall, through its Board of Trustees, duly call, give notice of, convene and hold a meeting of its shareholders (the "EUA Shareholders' Meeting") for the purpose of voting on the approval of the Merger and other transactions contemplated hereby (the "EUA Shareholders' Approval") as soon as reasonably practicable after the date hereof; provided, however, subject to the fiduciary duties of its Board of Trustees and the requirements of applicable law, EUA shall include in the Proxy Statement the recommendation of the Board of Trustees of EUA that the Shareholders of EUA approve the Merger and the other transactions contemplated hereby, and shall use its reasonable best efforts to obtain such approval. 7.04 Regulatory and Other Approvals. (a) HSR Filings. Each party hereto shall file or cause to be filed with the Federal Trade Commission and the Department of Justice any notifications required to be filed by its respective "ultimate parent" company under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"), and the rules and regulations promulgated thereunder with respect to the Merger and other transactions contemplated hereby. Such parties will use all commercially reasonable efforts to make such filings in a timely manner and to respond on a timely basis to any requests for additional information made by either of such agencies. (b) Other Regulatory Approvals. Each party shall cooperate and use its best efforts to promptly prepare and file all necessary applications, notices, petitions, filings and other documents with, and to use all commercially reasonable efforts to obtain all necessary permits, consents, approvals and authorizations of, all Governmental Authorities necessary or -31- advisable to obtain the EUA Required Statutory Approvals, the NEES Required Statutory Approvals and the approvals of the state utility commissions referred to in Section 8.01(d) (collectively, the "NEES-EUA Regulatory Approvals"). The parties agree that they will consult with each other with respect to obtaining the NEES-EUA Regulatory Approvals; provided, however, that NEES shall have primary responsibility for the preparation and filing of any related applications, filings or other material with the SEC, the FERC, the NRC and state utility commissions. EUA shall have the right to review and approve in advance drafts of and final applications, filings and other material (including material with respect to proposed settlements) submitted to or filed with the SEC, the FERC, the NRC and state utility commissions or parties to such proceedings before such Governmental Authority, which approval shall not be unreasonably withheld or delayed. (c) NEES-NGG Regulatory Proceedings. EUA and NEES acknowledge that, at the same time EUA and NEES will be seeking to obtain the NEES-EUA Regulatory Approvals, National Grid Group and NEES will be seeking to obtain the regulatory approvals (the "NEES-NGG Regulatory Approvals") required to consummate the transactions contemplated by the National Grid Merger Agreement. NEES and EUA agree to seek to prosecute the proceedings relating to the NEES-EUA Regulatory Approvals (the "NEES-EUA Regulatory Proceedings") separately from the prosecution by National Grid Group and NEES of the proceedings relating to the NEES-NGG Regulatory Approvals (the "NEES-NGG Regulatory Proceedings"), but recognize that one or more of the NEES-EUA Regulatory Proceedings may be consolidated with one or more of the NEES-NGG Regulatory Proceedings by the relevant Governmental Authority. Upon the request of EUA, NEES will keep EUA reasonably apprised of the status of the NEES-NGG Regulatory Proceedings. 7.05 Employee Benefit Plans. (a) For a period of twelve (12) months immediately following the Closing Date, the compensation, benefits and coverage provided to those non-union individuals who continue to be employees of the Surviving Entity (the "Affected Employees") pursuant to employee benefit plans or arrangements maintained by NEES or the Surviving Entity shall be, in the aggregate, not less favorable (as determined by NEES and the Surviving Entity using reasonable assumptions and benefit valuation methods) than those provided, in the aggregate, to such Affected Employees immediately prior to the Closing Date. In addition to the foregoing, NEES shall, or shall cause the Surviving Entity to, pay any Affected Employee whose employment is terminated by NEES or the Surviving Entity within twelve (12) months of the Closing Date a severance benefit package equivalent to the severance benefit package that would be provided under the NEES Standard Severance Plan as in effect on the date hereof. (b) NEES shall, or shall cause the Surviving Entity to, give the Affected Employees full credit for purposes of eligibility, vesting, benefit accrual (including, without limitation, benefit accrual under any defined benefit pension plans) and determination of the level of benefits under any employee benefit plans or arrangements maintained by NEES or the Surviving Entity in effect as of the Closing Date for such Affected Employees' service with EUA or any Subsidiary of EUA (or any prior employer) to the same extent -32- recognized by EUA or such Subsidiary immediately prior to the Closing Date. With respect to any employee benefit plan or arrangement established by NEES, EUA or the Surviving Entity after the Closing Date (the "Post Closing Plans"), service shall be credited in accordance with the terms of such Post Closing Plans. (c) NEES shall, or shall cause the Surviving Entity to, (i) waive all limitations as to preexisting conditions, exclusions and waiting periods with respect to participation and coverage requirements applicable to the Affected Employees under any welfare benefit plan established to replace any EUA welfare benefit plans in which such Affected Employees may be eligible to participate after the Closing Date, other than limitations or waiting periods that are already in effect with respect to such Affected Employees and that have not been satisfied as of the Closing Date under any welfare plan maintained for the Affected Employees immediately prior to the Closing Date, and (ii) provide each Affected Employee with credit for any co-payments and deductibles paid prior to the Closing Date in satisfying any applicable deductible or out-of-pocket requirements under any welfare plans that such Affected Employees are eligible to participate in after the Closing Date. (d)(i) NEES shall, or shall cause the Surviving Entity and its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving Entity and its Subsidiaries under, all EUA Employee Benefit Plans as in effect on the date hereof; provided, however, that this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity from exercising their rights with respect to all EUA Employee Benefit Plans solely in accordance with their terms, including but not limited to the right to alter, terminate or otherwise amend such EUA Employee Benefit Plans. (ii) NEES shall, or shall cause the Surviving Entity and its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving Entity and its Subsidiaries under, (A) all employment severance, consulting and retention agreements or arrangements as in effect on the date hereof, as set forth in Section 7.05(d)(ii) of the EUA Disclosure Letter, or as modified in accordance with Section 6.01(i) of the EUA Disclosure Letter (such agreements or arrangements, the "EUA Employee Agreements" and the individuals who are parties to such EUA Employee Agreements, the "EUA Executives") and (B) all EUA Employee Benefit Plans in which such EUA Executives participate; provided, however, that this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity from exercising their rights with respect to the EUA Employee Agreements and the EUA Employee Benefit Plans in which such EUA Executives participate, in each case solely in accordance with their terms, including but not limited to the right to alter, terminate or otherwise amend such EUA Employee Agreements and EUA Employee Benefit Plans. (e) Notwithstanding the foregoing, NEES and the Surviving Entity and its subsidiaries shall neither be required to or prevented from merging EUA's benefit plans, agreements, or arrangements into NEES or the Surviving Entity and its subsidiaries benefit plans, agreements, or arrangements or from -33- replacing EUA's benefit plans, agreements or arrangements with NEES or the Surviving Entity and its subsidiaries benefit plans, agreements or arrangements. 7.06 Labor Agreements and Workforce Matters. (a) Labor Agreements. NEES shall honor, or shall cause the appropriate subsidiaries of the Surviving Entity to honor, all collective bargaining agreements of EUA or its subsidiaries in effect as of the Effective Time until their expiration; provided, however, that this undertaking is not intended to prevent NEES or the Surviving Entity and its subsidiaries from exercising their rights with respect to such collective bargaining agreements and in accordance with their terms, including any right to amend, modify, suspend, revoke or terminate any such contract, agreement, collective bargaining agreement or commitment or portion thereof. (b) Workforce Matters. Subject to applicable law and obligations under applicable collective bargaining agreements, for a period of 2 years following the Effective Time, any reductions in workforce in respect of employees of the Surviving Entity and its Subsidiaries shall be made on a fair and equitable basis as determined by the Surviving Entity, with due consideration to prior experience and skills, and any employee whose employment is terminated or job is eliminated during such period shall be entitled to participate on a fair and equitable basis as determined by NEES or the Surviving Entity in the job opportunity and employment placement programs offered by NEES or the Surviving Entity or any of their Subsidiaries for which they are eligible. Any workforce reductions carried out following the Effective Time by the Surviving Entity and its Subsidiaries shall be done in accordance with all applicable collective bargaining agreements and all laws and regulations governing the employment relationship and termination thereof including, without limitation, the Worker Adjustment and Retraining Notification Act, and the regulations promulgated thereunder, and any comparable state or local law. 7.07 Post Merger Operations. (a) NEES Advisory Board. If the Merger is consummated, then, promptly following the closing of the merger contemplated by the National Grid Merger Agreement, NEES shall take such action as is necessary to cause all of the members of the Board of Directors of EUA to be appointed to serve on the advisory board to be formed pursuant to Section 7.07(e) of the National Grid Merger Agreement. (b) Charities. The parties agree that provision of charitable contribution and community support within the New England region serves a number of important goals. After the Effective Time, NEES intends to cause the Surviving Entity to provide charitable contributions and community support within the New England region at annual levels substantially comparable to the annual level of charitable contributions and community support provided, directly or indirectly, by EUA and its public utility subsidiaries within the New England region during 1998. -34- 7.08 No Solicitations. Prior to the Effective Time, EUA agrees: (a) that neither it nor any of its Subsidiaries shall, and it shall use its best efforts to cause its Representatives (as defined in Section 10.10) not to, knowingly initiate, solicit or encourage, directly or indirectly, any inquiries or any proposal or offer (including, without limitation, any proposal or offer to its Shareholders) with respect to a merger, consolidation or other business combination including EUA or any of its significant Subsidiaries (as defined in Rule 1-02(W) of Regulation S-X promulgated under the Exchange Act) other than EUA Cogenex Corporation (an "EUA Significant Subsidiary"), or any acquisition or similar transaction (including, without limitation, a tender or exchange offer) involving the purchase of (i) all or any significant portion of the assets of EUA and its Subsidiaries taken as a whole, (ii) ten percent or more of the outstanding EUA Shares or (iii) 50% or more of the outstanding shares of the capital stock of any EUA Significant Subsidiary (any such proposal or offer being hereinafter referred to as an "Alternative Proposal"), or engage in any negotiations concerning, or provide any confidential information or data to, or have any other discussions with, any person or group relating to an Alternative Proposal, or otherwise knowingly facilitate any effort or attempt to make or implement an Alternative Proposal other than from NEES and its affiliates; (b) that it will immediately cease and cause to be terminated any existing activities, discussions or negotiations with any parties with respect to any Alternative Proposal; and (c) that it will notify NEES immediately if any such inquiries, proposals or offers are received by, any such information is requested from, or any such negotiations or discussions are sought to be initiated or continued with, it or any of such persons; provided, however, that, prior to receipt of the EUA Shareholders' Approval, nothing contained in this Section 7.08 shall prohibit the Board of Trustees of EUA from (i) furnishing information to (but only pursuant to a confidentiality agreement in customary form and having terms and conditions no less favorable to EUA than the Confidentiality Agreement (as defined in Section 7.01)) or entering into discussions or negotiations with any person or group that makes an unsolicited Alternative Proposal, if, and only to the extent that, (A) the Board of Trustees of EUA, based upon advice of outside counsel with respect to fiduciary duties, determines in good faith that such action is necessary for the Board of Trustees to act in a manner consistent with its fiduciary duties to Shareholders under applicable law, (B) the Board of Trustees of EUA has reasonably concluded in good faith (after consultation with its financial advisors) that the person or group making such Alternative Proposal will have adequate sources of financing to consummate such Alternative Proposal and that such Alternative Proposal is likely to be more favorable to EUA's shareholders than the Merger, (C) prior to furnishing such information to, or entering into discussions or negotiations with, such person or group, EUA provides written notice to NEES to the effect that it is furnishing information to, or entering into discussions or negotiations with, such person or group, which notice shall identify such person or group and the material terms of the Alternative Proposal in reasonable detail, and (D) EUA keeps NEES promptly informed of the status and all material information with respect to any such discussions or negotiations; and (ii) to the extent required, complying with Rule 14e-2 promulgated under the Exchange Act with regard to an Alternative Proposal. Nothing in this Section 7.08 shall (x) permit EUA to terminate this Agreement (except as specifically provided in Article IX), (y) permit EUA to enter into any agreement with respect to an Alternative Proposal for so long as this Agreement remains in effect (it being agreed that for so long as this Agreement remains in effect, EUA shall not enter -35- into any agreement with any person or group that provides for, or in any way knowingly facilitates, an Alternative Proposal (other than a confidentiality agreement under the circumstances described above)), or (z) affect any other obligation of EUA under this Agreement. 7.09 Directors' and Officers' Indemnification and Insurance. (a) Indemnification. To the extent, if any, not provided by an existing right of indemnification or other agreement or policy, from and after the Effective Time, NEES shall, or shall cause the Surviving Entity to, to the fullest extent permitted by applicable law, indemnify, defend and hold harmless each person who is now, or has been at any time prior to the date hereof, or who becomes prior to the Effective Time, (x) an officer, trustee or director or (y) an employee covered as of the date hereof (to the extent of the coverage extended as of the date hereof) of EUA or any Subsidiary of EUA (each an "Indemnified Party," and collectively, the "Indemnified Parties") against (i) all losses, expenses (including reasonable attorney's fees and expenses), claims, damages or liabilities or, subject to the first proviso of the next succeeding sentence, amounts paid in settlement, arising out of actions or omissions occurring at or prior to the Effective Time (and whether asserted or claimed prior to, at or after the Effective Time) that are, in whole or in part, based on or arising out of the fact that such person is or was a director, trustee, officer or employee of EUA or any Subsidiary of EUA (the "Indemnified Liabilities"), and (ii) all Indemnified Liabilities to the extent they are based on or arise out of or pertain to the transactions contemplated by this Agreement, in each case, to the extent permitted by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter. In the event of any such loss, expense, claim, damage or liability (whether or not arising before the Effective Time), (i) NEES shall, or shall cause the Surviving Entity to, pay the reasonable fees and expenses of counsel selected by the Indemnified Parties, which counsel shall be reasonably satisfactory to NEES or the Surviving Entity, as appropriate, promptly after statements therefor are received and otherwise advance to such Indemnified Party upon request, reimbursement of documented expenses reasonably incurred, in either case to the extent not prohibited by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter upon receipt of an undertaking by or on behalf of such director, trustee or officer to repay such amounts as and to the extent required by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter, (ii) the Surviving Entity shall cooperate in the defense of any such matter and (iii) any determination required to be made with respect to whether an Indemnified Party's conduct complies with the standards set forth under the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter and the certificate of incorporation or by-laws or similar governing documents of the Surviving Entity shall be made by independent counsel mutually acceptable to the Surviving Entity and the Indemnified Party; provided, however, that the Surviving Entity shall not be liable for any settlement effected without its written consent (which consent shall not be unreasonably withheld) and provided further that no indemnification shall be made if such indemnification is prohibited by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter. -36- (b) Insurance. For a period of six years after the Effective Time, NEES and the Surviving Entity at NEES's election, (i) shall cause to be maintained in effect an extended reporting period for current policies of directors' and officers' liability insurance for the benefit of such persons who are currently covered by such policies of EUA on terms no less favorable than the terms of such current insurance coverage or (ii) shall provide tail coverage for such persons which provides such persons with coverage for a period of six years for acts prior to the Effective Time on terms no less favorable than the terms of such current insurance coverage. (c) Successors. In the event the Surviving Entity or any of its successors or assigns (i) consolidates with or merges into any other person or entity and shall not be the continuing or surviving corporation or entity of such consolidation or merger or (ii) transfers all or substantially all of its properties and assets to any person or entity, then and in either such case, proper provisions shall be made so that the successors and assigns of the Surviving Entity, as applicable, shall assume the obligations set forth in this Section 7.09. (d) Survival of Indemnification. To the fullest extent permitted by law, from and after the Effective Time, all rights to indemnification as of the date hereof in favor of the employees, agents, directors, trustees and officers of EUA and EUA's Subsidiaries with respect to their activities as such prior to the Effective Time, as provided in the EUA Trust Agreement or the respective certificates of incorporation and by-laws or similar governing documents in effect on the date hereof, or otherwise in effect on the date hereof, shall survive the Merger and shall continue in full force and effect for a period of not less than six years from the Effective Time. (e) Benefit. The provisions of this Section 7.09 are intended to be for the benefit of, and shall be enforceable by, each Indemnified Party, his or her heirs and his or her representatives. (f) Amendment of the EUA Trust Agreement. NEES shall not, and shall ensure that the Surviving Entity shall not, amend the EUA Trust Agreement to in any way limit the indemnification provided to the Indemnified Parties under this Section 7.09. 7.10 Expenses. Except as set forth in Section 9.03, whether or not the Merger is consummated, all costs and expenses incurred in connection with the Merger and other transactions contemplated hereby shall be paid by the party incurring such cost or expense, except that the filing fees in connection with the filings required under the HSR Act and the 1935 Act shall be paid by NEES. 7.11 Brokers or Finders. EUA represents, as to itself and its affiliates, that no agent, broker, investment banker, financial advisor or other firm or person is or will be entitled to any broker's, finder's or investment banker's fee or any other commission or similar fee in connection with the Merger and other transactions contemplated by this Agreement except Salomon Smith Barney Inc., whose fees and expenses will be paid by EUA in accordance with EUA's agreement with such firm, and EUA shall indemnify and hold NEES harmless from and against any and all claims, liabilities or obligations with -37- respect to any other such fee or commission or expenses related thereto asserted by any person on the basis of any act or statement alleged to have been made by EUA or its affiliates. 7.12 Anti-Takeover Statutes. If any "fair price", "moratorium", "business combination", "control share acquisition" or other form of anti-takeover statute or regulation shall become applicable to the Merger or other transactions contemplated hereby, EUA and the members of the Board of Trustees of EUA shall grant such approvals and take such actions consistent with their fiduciary duties and in accordance with applicable law as are reasonably necessary so that the Merger and other transactions contemplated hereby may be consummated as promptly as practicable on the terms contemplated hereby and otherwise act to eliminate or minimize the effects of such statute or regulation on the Merger and other transactions contemplated hereby. 7.13 Public Announcements. Except as otherwise required by law or the rules of any applicable securities exchange or national market system or any other Regulatory Authority, so long as this Agreement is in effect, NEES and EUA will not, and will not permit any of their respective Subsidiaries or Representatives to, issue or cause the publication of any press release or make any other public announcement with respect to the Merger and other transactions contemplated by this Agreement without the consent of the other party, which consent shall not be unreasonably withheld. NEES and EUA will cooperate with each other in the development and distribution of all press releases and other public announcements with respect to the Merger and other transactions contemplated hereby, and will furnish the other with drafts of any such releases and announcements as far in advance as practicable. 7.14 Restructuring of the Merger. It may be preferable to effectuate a business combination between NEES and EUA by means of an alternative structure to the Merger. Accordingly, if, prior to satisfaction of the conditions contained in Article VIII hereto, NEES proposes the adoption of an alternative structure that otherwise substantially preserves for NEES and EUA the economic benefits of the Merger and will not materially delay the consummation thereof, then the parties shall use their respective best efforts to effect a business combination among themselves by means of a mutually agreed upon structure other than the Merger that so preserves such benefits; provided, however, that prior to closing any such restructured transaction, all material third party and Governmental Authority declarations, filings, registrations, notices, authorizations, consents or approvals necessary for the effectuation of such alternative business combination shall have been obtained and all other conditions to the parties' obligations to consummate the Merger and other transactions contemplated hereby, as applied to such alternative business combination, shall have been satisfied or waived. -38- ARTICLE VIII CONDITIONS 8.01 Conditions to Each Party's Obligation to Effect the Merger. The respective obligation of each party to effect the Merger and other transactions contemplated hereby is subject to the satisfaction or waiver, at or prior to the Closing, of each of the following conditions: (a) Shareholder Approval. EUA Shareholders' Approval shall have been obtained. (b) HSR Act. Any waiting period (and any extension thereof) applicable to the consummation of the Merger under HSR shall have expired or been terminated. (c) Injunctions or Restraints. No court of competent jurisdiction or other competent Governmental Authority shall have enacted, issued, promulgated, enforced or entered any law or order (whether temporary, preliminary or permanent) which is then in effect and has the effect of making illegal or otherwise restricting, preventing or prohibiting consummation of the Merger or other transactions contemplated hereby. (d) Governmental and Regulatory and Other Consents and Approvals. The NEES Required Statutory Approvals and EUA Required Statutory Approvals shall have been obtained prior to the Effective Time, and shall have become Final Orders (as hereinafter defined). The Final Orders shall not, individually or in the aggregate, impose terms and conditions that (i) could reasonably be expected to have an EUA Material Adverse Effect; (ii) could reasonably be expected to have a NEES Material Adverse Effect; or (iii) materially impair the ability of the parties to complete the Merger. The parties shall have received Final Orders from the Massachusetts Department of Telecommunications and Energy and the Rhode Island Public Utilities Commission pertaining to the recovery of costs (including, without limitation, transaction premium and integration costs) associated with the Merger that are materially consistent with existing policy and previous orders of such agencies. "Final Order" for all purposes of this Agreement means action by the relevant regulatory authority which has not been reversed, stayed, enjoined, set aside, annulled or suspended with respect to which any waiting period prescribed by law before the Merger and other transactions contemplated hereby may be consummated has expired, and as to which all conditions to be satisfied before the consummation of such transactions prescribed by law, regulation or order have been satisfied. 8.02 Conditions to Obligation of NEES and LLC to Effect the Merger. The obligation of NEES and LLC to effect the Merger and other transactions contemplated hereby is further subject to the satisfaction or waiver at or prior to the Closing, of each of the following additional conditions (all or any of which may be waived in whole or in part by NEES and LLC in the sole discretion): -39- (a) Representations and Warranties. The representations and warranties made by EUA in this Agreement, in each case made as if none of such representations or warranties contained any qualification or limitation as to "materiality" or "EUA Material Adverse Effect", shall be true and correct as so made as of the Closing Date as though so made on and as of the Closing Date, except to the extent expressly given as of a specified date, except where the failure of such representations and warranties to be true and correct as so made does not have and could not reasonably be expected to have, individually or in the aggregate, an EUA Material Adverse Effect, and EUA shall have delivered to NEES a certificate, dated the Closing Date and executed in the name and on behalf of EUA by its Chairman of the Board, President or any Executive or Senior Vice President, to such effect. (b) Performance of Obligations. EUA shall have performed and complied with, in all material respects, each agreement, covenant and obligation required by this Agreement to be so performed or complied with by EUA at or prior to the Closing, and EUA shall have delivered to NEES a certificate, dated the Closing Date and executed in the name and on behalf of EUA by its Chairman of the Board, President or any Executive or Senior Vice President, to such effect. (c) Material Adverse Effect. No EUA Material Adverse Effect shall have occurred and there shall exist no facts or circumstances which in the aggregate could reasonably be expected to have an EUA Material Adverse Effect. (d) EUA Required Consents. All EUA Required Consents shall have been obtained by EUA, except where the failure to receive such EUA Required Consents could not reasonably be expected to (i) have an EUA Material Adverse Effect, or (ii) delay or prevent the consummation of the Merger and other transactions contemplated hereby. 8.03 Conditions to Obligation of EUA to Effect the Merger. The obligation of EUA to effect the Merger and other transactions contemplated hereby is further subject to the satisfaction or waiver, at or prior to the Closing, of each of the following additional conditions (all or any of which may be waived in whole or in part by EUA in its sole discretion): (a) Representations and Warranties. The representations and warranties made by NEES and LLC in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.07, 5.08 and 5.09 of this Agreement, in each case made as if none of such representations or warranties contained any qualification or limitation as to "materiality" or "NEES Material Adverse Effect," shall be true and correct as so made as of the Closing Date, except to the extent expressly given as of a specified date and except where the failure of such representations and warranties to be so true and correct as so made does not have and could not reasonably be expected to have, individually or in the aggregate, a NEES Material Adverse Effect or a material adverse effect on LLC, and NEES and LLC shall each have delivered to EUA a certificate, dated the Closing Date and executed in the name and on behalf of NEES by any director of NEES and in the name and on behalf of LLC by a member of its management committee its Chairman of the Board, President or any Executive or Senior Vice President to such effect. -40- (b) NEES Required Consents. All NEES Required Consents shall have been obtained by NEES, except where the failure to receive such NEES Required Consents could not reasonably be expected to (i) have a NEES Material Adverse Effect or (ii) delay or prevent the consummation of the Merger and other transactions contemplated hereby. (c) Performance of Obligations. NEES and LLC shall have performed and complied with, in all material respects, each agreement, covenant and obligation required by this Agreement to be so performed or complied with by NEES or LLC at or prior to the Closing, and NEES and LLC shall each have delivered to EUA a certificate, dated the Closing Date and executed in the name and on behalf of NEES by its Chairman of the Board, President or any Executive or Senior Vice President, or on behalf of LLC by a member of its management committee to such effect. ARTICLE IX TERMINATION, AMENDMENT AND WAIVER 9.01 Termination. This Agreement may be terminated, and the Merger and other transactions contemplated hereby may be abandoned, at any time prior to the Effective Time, whether prior to or after EUA Shareholders' Approval (except as otherwise provided in Section 9.01(c) below): (a) By mutual written agreement of the Board of Directors of NEES and Board of Trustees of EUA, respectively; (b) By EUA or NEES, by written notice to the other, if the Closing Date shall not have occurred on or before December 31, 1999 (the "Initial Termination Date"); provided, however, that the right to terminate the Agreement under this Section 9.01(b) shall not be available to any party whose failure to fulfill any obligation under this Agreement has been the cause of, or resulted in, the failure of the Effective Time to occur on or before such date; and provided, further, that if on the Initial Termination Date the conditions to the Closing set forth in Section 8.01(d) shall not have been fulfilled but all other conditions to the Closing shall be fulfilled or shall be capable of being fulfilled, then the Initial Termination Date shall be extended for four (4) months beyond the Initial Termination Date (the "Extended Termination Date"); (c) By NEES, by written notice to EUA, if EUA Shareholders' Approval shall not have been obtained at a duly held meeting of such Shareholders, including any adjournments thereof; (d) By EUA or NEES, if any applicable state or federal law or applicable law of a foreign jurisdiction or any order, rule or regulation is adopted or issued that has the effect, as supported by the written opinion of outside counsel for such party, of prohibiting the Merger or other transactions contemplated hereby, or if any court of competent jurisdiction or any Governmental Authority shall have issued a nonappealable final order, judgment -41- or ruling or taken any other action having the effect of permanently restraining, enjoining or otherwise prohibiting the Merger or other transactions contemplated hereby (provided that the right to terminate this Agreement under this Section 9.01(d) shall not be available to any party that has not defended such lawsuit or other legal proceeding (including seeking to have any stay or temporary restraining order entered by any court or other Governmental Authority vacated or reversed)). (e) By EUA upon ten (10) days' prior notice to NEES if the Board of Trustees of EUA determines in good faith, that termination of this Agreement is necessary for the Board of Trustees of EUA to act in a manner consistent with its fiduciary duties to Shareholders under applicable law by reason of an unsolicited Alternative Proposal meeting the requirements of clauses (A) and (B) of Section 7.08 having been made; provided that (A) The Board of Trustees of EUA shall determine based on advice of outside counsel with respect to the Board of Trustees' fiduciary duties that notwithstanding a binding commitment to consummate an agreement of the nature of this Agreement entered into in the proper exercise of its applicable fiduciary duties, and notwithstanding all concessions which may be offered by NEES in negotiation entered into pursuant to clause (B) below, it is necessary pursuant to such fiduciary duties that the trustees reconsider such commitment as a result of such Alternative Proposal, and (B) prior to any such termination, EUA shall, and shall cause its respective financial and legal advisors to, negotiate with NEES to make such adjustments in the terms and conditions of this Agreement as would enable EUA to proceed with the Merger or other transactions contemplated hereby on such adjusted terms; and provided further that EUA's ability to terminate this Agreement pursuant to this Section 9.01(e) is conditioned upon the concurrent payment by EUA to NEES of any amounts owed by it pursuant to Section 9.03(a); (f) By EUA, by written notice to NEES, if (i) there shall have been any material breach of any representation or warranty, or any material breach of any covenant or agreement, of NEES hereunder (other than a breach described in clause (ii)), and such breach shall not have been remedied within twenty (20) days after receipt by NEES of notice in writing from EUA, specifying the nature of such breach and requesting that it be remedied; or (ii) NEES shall fail to deliver or cause to be delivered the amount of cash to the Paying Agent required pursuant to Section 2.02(a) at a time when all conditions to NEES's obligation to close have been satisfied or otherwise waived in writing by NEES. (g) By NEES, by written notice to EUA, if (i) there shall have been any material breach of any representation or warranty, or any material breach of any covenant or agreement, of EUA hereunder, and such breach shall not -42- have been remedied within twenty (20) days after receipt by EUA of notice in writing from NEES, specifying the nature of such breach and requesting that it be remedied; or (ii) the Board of Trustees of EUA (A) shall withdraw or modify in any manner adverse to NEES its approval of the Merger and other transactions contemplated hereby or its recommendation to its shareholders regarding the approval of this Agreement, the Merger and other transactions contemplated hereby, (B) shall approve or recommend or take no position with respect to an Alternative Proposal or (C) shall resolve to take any of the actions specified in clause (A) or (B). 9.02 Effect of Termination. If this Agreement is validly terminated by either EUA or NEES pursuant to Section 9.01, this Agreement shall forthwith become null and void and there shall be no liability or obligation on the part of either EUA or NEES (or any of their respective Representatives or affiliates), except that the provisions of this Section 9.02, Sections 7.10, 7.11 and 7.13, Section 9.03 and Sections 10.09 and 10.10 shall continue to apply following any such termination. 9.03 Termination Fees. (a) In the event that (i) this Agreement is terminated by EUA pursuant to Section 9.01(e) or (ii) any person or group shall have made an Alternative Proposal that has not been withdrawn and this Agreement is terminated by (A) NEES pursuant to Section 9.01(c) or Section 9.01(g) or (B) by EUA pursuant to Section 9.01(b) and, in the case of this clause (ii) only, a definitive agreement with respect to such Alternative Proposal is executed within two years after such termination, then EUA shall pay to NEES, by wire transfer of same day funds, either on the date contemplated in Section 9.01(e) if applicable, or otherwise, within five (5) business days after such termination, a termination fee of $20 million, plus an amount equal to all documented out-of-pocket expenses and fees incurred by NEES arising out of, or in connection with or related to, the Merger and other transactions contemplated hereby, not in excess of $5 million in the aggregate. (b) In the event that this Agreement is terminated by either NEES or EUA pursuant to Section 9.01(b) and at the time of such termination (i) the conditions to the Closing set forth in Section 8.01(d) shall not have been fulfilled, (ii) if the date of termination is any date other than a date which is on or after the Extended Termination Date, all conditions contained in Article VIII other than Sections 8.01(d) or 8.03(c) shall have been fulfilled or are capable of being fulfilled as of such date, and (iii) the merger contemplated by the National Grid Merger Agreement has not yet been consummated, then NEES shall pay to EUA, by wire transfer of same day funds, within five (5) business days after such termination, a termination fee of $10 million, plus an amount equal to all documented out-of-pocket expenses and fees incurred by EUA arising out of, or in connection with or related to, the Merger and other transactions contemplated hereby, not in excess of $5 million in the aggregate. (c) Nature of Fees. The parties agree that the agreements contained in this Section 9.03 are an integral part of the Merger and the other transactions contemplated hereby and constitute liquidated damages and not a penalty. The parties further agree that if any party is or becomes obligated to pay a termination fee pursuant to Sections 9.03(a) or (b), the right to receive such termination fee shall be the sole remedy of the other party with respect to -43- the facts and circumstances giving rise to such payment obligation. If this Agreement is terminated by a party as a result of a willful breach of a representation, warranty, covenant or agreement by the other party, including a termination pursuant to Section 9.01(f)(ii), the non-breaching party may pursue any remedies available to it at law or in equity and shall be entitled to recover any additional amounts thereunder. Notwithstanding anything to the contrary contained in this Section 9.03, if one party fails to promptly pay to the other any fee or expense due under this Section 9.03, in addition to any amounts paid or payable pursuant to such Section, the defaulting party shall pay the costs and expenses (including legal fees and expenses) in connection with any action, including the filing of any lawsuit or other legal action, taken to collect payment, together with interest on the amount of any unpaid fee at the publicly announced prime rate of Citibank, N.A. from the date such fee was required to be paid. 9.04 Amendment. This Agreement may be amended, supplemented or modified by action taken by or on behalf of the Board of Directors of NEES or the Board of Trustees of EUA at any time prior to the Effective Time, whether prior to or after EUA Shareholders' Approval shall have been obtained, but after such adoption and approval only to the extent permitted by applicable law. No such amendment, supplement or modification shall be effective unless set forth in a written instrument duly executed and delivered by or on behalf of each party hereto. 9.05 Waiver. At any time prior to the Effective Time, NEES or EUA, by action taken by or on behalf of its Board of Directors or Board of Trustees, respectively, may to the extent permitted by applicable law (i) extend the time for the performance of any of the obligations or other acts of the other parties hereto, (ii) waive any inaccuracies in the representations and warranties of the other parties hereto contained herein or in any document delivered pursuant hereto or (iii) waive compliance with any of the covenants, agreements or conditions of the other parties hereto contained herein. No such extension or waiver shall be effective unless set forth in a written instrument duly executed by or on behalf of the party extending the time of performance or waiving any such inaccuracy or non-compliance. No waiver by any party of any term or condition of this Agreement, in any one or more instances, shall be deemed to be or construed as a waiver of the same or any other term or condition of this Agreement on any future occasion. ARTICLE X GENERAL PROVISIONS 10.01 Non-Survival of Representations, Warranties, Covenants and Agreements. The representations, warranties, covenants and agreements contained in this Agreement or in any instrument delivered pursuant to this Agreement shall not survive the Merger but shall terminate at the Effective Time, except for the agreements contained in Article I and Article II, in Sections 7.05, 7.06, 7.08, 7.09 and 7.10, this Article X which shall survive the Effective Time. 10.02 Notices. All notices, requests and other communications hereunder must be in writing and will be deemed to have been duly given only if -44- delivered personally or by facsimile transmission or sent by overnight courier (providing proof of delivery) to the parties at the following addresses or facsimile numbers: If to NEES or LLC, to: New England Electric System 25 Research Drive Westborough, MA 01582 Attn: Richard P. Sergel President and Chief Executive Officer Telephone: (508) 389-2764 Facsimile: (508) 366-5498 with a copy to: Skadden, Arps, Slate, Meagher & Flom LLP 919 Third Avenue New York, NY 10022 Attn: Sheldon S. Adler, Esq. Telephone: (212) 735-3000 Facsimile: (212) 735-2000 If to EUA, to: Eastern Utilities Associates One Liberty Square Boston, MA 02109 Attn: Donald G. Pardus Chairman and Chief Executive Officer Telephone: (617) 357-9590 Facsimile: (617) 357-7320 with a copy to: Winthrop, Stimson, Putnam & Roberts 1 Battery Park Plaza New York, NY 10004 Attn: David P. Falck Telephone: (212) 858-1000 Facsimile: (212) 858-1500 All such notices, requests and other communications will (i) if delivered personally to the address as provided in this Section, be deemed given -45- upon delivery, (ii) if delivered by facsimile transmission to the facsimile number as provided in this Section, be deemed given when sent, provided that the facsimile is promptly confirmed by telephone confirmation thereof, and (iii) if delivered by mail in the manner described above to the address as provided in this Section, be deemed given one business day after delivery (in each case regardless of whether such notice, request or other communication is received by any other person to whom a copy of such notice, request or other communication is to be delivered pursuant to this Section). Any party from time to time may change its address, facsimile number or other information for the purpose of notices to that party by giving notice specifying such change to the other parties hereto. 10.03 Entire Agreement; Incorporation of Exhibits. (a) This Agreement supersedes all prior discussions and agreements, both written and oral, among the parties hereto with respect to the subject matter hereof, other than the Confidentiality Agreement, which shall survive the execution and delivery of this Agreement in accordance with its terms, and contains, together with the Confidentiality Agreement, the sole and entire agreement among the parties hereto with respect to the subject matter hereof. (b) The EUA Disclosure Letter, the NEES Disclosure Letter and any Exhibit attached to this Agreement and referred to herein are hereby incorporated herein and made a part hereof for all purposes as if fully set forth herein. 10.04 No Third Party Beneficiary. The terms and provisions of this Agreement are intended solely for the benefit of each party hereto and their respective successors or permitted assigns, and except as provided in Article II and Sections 7.04, 7.05(d)(ii) and 7.09 (which is intended to be for the benefit of the persons entitled to therein, and may be enforced by any of such persons), it is not the intention of the parties to confer third-party beneficiary rights upon any other person. 10.05 No Assignment; Binding Effect. Neither this Agreement nor any right, interest or obligation hereunder may be assigned, in whole or in part, by operation of law or otherwise, by any party hereto without the prior written consent of the other parties hereto and any attempt to do so will be void, except that LLC may assign any or all of its rights, interests and obligations hereunder to another direct or indirect wholly owned Subsidiary of NEES, provided that any such Subsidiary agrees in writing to be bound by all of the terms, conditions and provisions contained herein and provided further that such assignment (i) does not require a greater vote for EUA's Shareholder Approval, (ii) does not require a subsequent vote following EUA's Shareholders Meeting, or (iii) is not reasonably likely to materially delay or prevent EUA, LLC and NEES, as appropriate, from obtaining EUA Required Statutory Approvals, EUA Required Consents, EUA Shareholders' Approval, the NEES Required Shareholders' Approvals, or the NEES Required Consents. Subject to the preceding sentence, this Agreement is binding upon, inures to the benefit of and is enforceable by the parties hereto and their respective successors and assigns. -46- 10.06 Headings. The headings used in this Agreement have been inserted for convenience of reference only and do not define, modify or limit the provisions hereof. 10.07 Invalid Provisions. If any provision of this Agreement is held to be illegal, invalid or unenforceable under any present or future law or order, and if the rights or obligations of any party hereto under this Agreement will not be materially and adversely affected thereby, (i) such provision will be fully severable, (ii) this Agreement will be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, and (iii) the remaining provisions of this Agreement will remain in full force and effect and will not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom. 10.08 Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the Commonwealth of Massachusetts. 10.09 Enforcement of Agreement. The parties hereto agree that irreparable damage would occur in the event that any of the provisions of this Agreement was not performed in accordance with its specified terms or was otherwise breached. It is accordingly agreed that the parties shall be entitled to an injunction or injunctions to prevent breaches of this Agreement and to enforce specifically the terms and provisions hereof in any court of competent jurisdiction, this being in addition to any other remedy to which they are entitled at law or in equity. 10.10 Certain Definitions. As used in this Agreement: (a) except as provided in Section 4.14, the term "affiliate," as applied to any person, shall mean any other person directly or indirectly controlling, controlled by, or under common control with, that person; for purposes of this definition, "control" (including, with correlative meanings, the terms "controlling," "controlled by" and "under common control with"), as applied to any person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of that person, whether through the ownership of voting securities, by contract or otherwise; (b) a person will be deemed to "beneficially" own securities if such person would be the beneficial owner of such securities under Rule 13d-3 under the Exchange Act, including securities which such person has the right to acquire (whether such right is exercisable immediately or only after the passage of time); (c) the term "business day" means a day other than Saturday, Sunday or any day on which banks located in the Massachusetts are authorized or obligated to close; (d) the term "knowledge" or any similar formulation of "knowledge" shall mean, with respect to any party hereto, the actual knowledge after due inquiry of the executive officers of NEES and its Subsidiaries or EUA and its Subsidiaries, respectively, set forth in Section 10.11(d) of the NEES Disclosure Letter or Section 10.11(d) of the EUA Disclosure Letter; provided -47- that as used in Section 4.13 the term "knowledge" shall also include the knowledge of the environmental, health and safety personnel of EUA; (e) the term "person" shall include individuals, corporations, partnerships, trusts, limited liability companies, other entities and groups (which term shall include a "group" as such term is defined in Section 13(d)(3) of the Exchange Act); (f) the "Representatives" of any entity shall have the same meaning as set forth in the Confidentiality Agreement; (g) the term "Subsidiary" means any corporation or other entity, whether incorporated or unincorporated, in which such party directly or indirectly owns at least a majority of the voting power represented by the outstanding capital stock or other voting securities or interests having voting power under ordinary circumstances to elect a majority of the directors or similar members of the governing body, or otherwise to direct the management and policies, or such corporation or entity. 10.11 Counterparts. This Agreement may be executed in any number of counterparts, each of which will be deemed an original, but all of which together will constitute one and the same instrument and will become effective when one or more counterparts have been signed by each party and delivered to the other parties. 10.12 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION. -48- IN WITNESS WHEREOF, each party hereto has caused this Agreement to be signed by its officer thereunto duly authorized as of the date first above written. NEW ENGLAND ELECTRIC SYSTEM By: /s/ Richard P. Sergel ----------------------------------- Name: Richard P. Sergel Title: President and CEO The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer, or agent thereof assumes or shall be held to any liability therefor. EASTERN UTILITIES ASSOCIATES By: /s/ Donald G. Pardus ----------------------------------- Name: Donald G. Pardus Title: Chairman The name "Eastern Utilities Associates" is the designation of the Trustees of EUA for the time being in their collective capacity but not personally, under a Declaration of Trust dated April 2, 1928, as amended, a copy of which amended Declaration of Trust has been filed in the office of the Secretary of The Commonwealth of Massachusetts and elsewhere as required by law; and all persons dealing with EUA must look solely to the trust property for the enforcement of any claim against EUA, as neither the Trustees nor the officers or shareholders of EUA assume any personal liability for obligations entered into on behalf of EUA. RESEARCH DRIVE LLC By: /s/ John G. Cochrane ----------------------------------- Name: John G. Cochrane Title: Manager -49- Tab 2 CONSENT AGREEMENT dated as of February 1, 1999 CONSENT AGREEMENT This Consent Agreement (the "Agreement") is entered into as of February 1, 1999 between The National Grid Group, p1c, a public limited company incorporated under the laws of England and Wales ("NGG") and New England Electric System, a Massachusetts business trust ("NEES"). WHEREAS, NGG, NEES and NGG Holdings LLC (formerly Iosta LLC), a wholly owned subsidiary of NGG, entered into an Agreement and Plan of Merger dated as of December 11, 1998 (the"Merger Agreement") pursuant to which NGG Holdings LLC will merge (the "Merger") with and into NEES with NEES being the surviving entity and becoming a wholly owned subsidiary of NGG; WHEREAS, NEES, Eastern Utilities Associates, a Massachusetts Business Trust ("EUA") and Research Drive LLC are proposing to enter into an Agreement and Plan of Merger in the form attached hereto as Exhibit A (the "EUA Merger Agreement") providing for the merger (the "EUA Merger") of Research Drive LLC with and into EUA with EUA being the surviving entity and becoming a wholly owned subsidiary of NEES; and WHEREAS, pursuant to the provisions of the Merger Agreement, NEES is required to obtain the consent of NGG before entering into the EUA Merger Agreement and with respect to certain actions relating to the consummation of the transactions set forth therein. NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows: 1. Consent to EUA Merger Agreement. Subject to the terms and conditions of this Consent, NGG hereby consents to NEES entering into the EUA Merger Agreement with EUA in the form set forth in Exhibit A and agrees that, subject to the immediately following sentence, the consummation by NEES of the transactions contemplated by the EUA Merger Agreement in accordance with the term thereof shall not constitute a breach by NEES of the terms of the Merger Agreement. NEES and NGG acknowledge that the financing necessary to consummate the EUA Merger was not contemplated when NEES and NGG agreed to the limitations set forth in Article VI of the Merger Agreement and NGG consents to such financing provided that such financing is consistent with the financing parameters set forth on Exhibit B hereto. NGG also consents to the formation and capitalization of Research Drive LLC by NEES for the purpose of effecting the EUA Merger as contemplated in the EUA Merger Agreement. 2. Access to Information. Subject to the following sentence, NEES hereby agrees to provide NGG with reasonable access to any information it receives regarding EUA pursuant to the terms of the EUA Merger Agreement and to consult with NGG on a regular basis concerning the status of EUA and the EUA Merger. NGG hereby acknowledges that any such material that is "Evaluation Material" (as such term is defined in the letter agreement dated as of December 21, 1998 between NGG and NEES (the "Confidentiality Agreement") shall be governed by the terms of the Confidentiality Agreement. 3. Regulatory Filings. NEES hereby agrees that NGG shall have the right to review in advance, and that NEES will consult with NGG and give due regard to NGG's views concerning, any applications, notices, petitions, filings and other documents filed with any Governmental Authority (as defined in the EUA Merger Agreement) in connection with the EUA Merger which could reasonably be expected to have a material adverse effect on NGG's or NEES' ability to consummate the Merger or which could reasonably be expected to adversely affect in any material manner any material benefit of the Merger to NGG or NEES. 4. Amendments to EUA Merger Agreement. NEES hereby agrees that it will not, without the prior written consent of NGG, amend or modify the EUA Merger Agreement in any material respect, including, without limitation, amend or otherwise modify any provision of the EUA Merger Agreement providing for or relating to the amount, type or structure of the Merger Consideration (as defined in the EUA Merger Agreement) or agree to any additional or different amount, type or structure for the Merger Consideration (as so defined). 5. Acknowledgment. NGG and NEES acknowledge and agree that the covenants set forth in Article VI of the Merger Agreement do not reflect the operations of EUA if the EUA Merger is consummated prior to the Effective Time (as defined in the Merger Agreement). In the event that the EUA Merger is consummated prior to the Effective Time, NGG and NEES hereby agree to negotiate in good faith to make appropriate modifications to such covenants set forth in Section 6.01 of the Merger Agreement to reflect the operations of EUA. 6. Termination and Amendment. This Consent Agreement and the obligations of NEES hereunder shall terminate upon the earlier to occur of (i) the termination of the Merger Agreement, (ii) the EUA Merger and (iii) the Merger, in each case without any further action by the parties hereto. Except as provided in the preceding sentence, this Consent can not be terminated or amended in any material respect prior to the termination of the EUA Merger Agreement without the prior written consent of EUA. The foregoing sentence is intended for the benefit of EUA and may be enforced by EUA. 7. Notices. NEES hereby agrees to provide NGG with copies of all notices and other communications it sends to EUA and all notices and other communications it receives from EUA under the EUA Merger Agreement. All notices and other communications provided under this Agreement must be in writing and shall be given in the same manner and to the same parties as set forth in Section 10.02 of the Merger Agreement. 8. Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument. 9. Governing Law and Waiver of Jury Trial. This Agreement shall be governed by and construed in accordance with the laws of the State of New York applicable to a contract executed and performed in such State, without giving effect to the conflicts of laws principles. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION. IN WITNESS WHEREOF, each of NGG and NEES has duly executed this Agreement as of the date first above written. THE NATIONAL GRID GROUP, PLC By: /s/ Fiona B. Smith ----------------------------------- Name: Fiona B. Smith Title: Company Secretary NEW ENGLAND ELECTRIC SYSTEM By: ___________________________ Name: Title: The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer or agent thereof assumes or shall be held to any liability therefor. IN WITNESS WHEREOF, each of NGG and NEES has duly executed this Agreement as of the date first above written. THE NATIONAL GRID GROUP, PLC By: ______________________________ Name: Title: NEW ENGLAND ELECTRIC SYSTEM By: /s/ Richard P. Sergel ----------------------------------- Name: Richard P. Sergel Title: President and CEO The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer or agent thereof assumes or shall be held to any liability therefor. ACKNOWLEDGMENT OF EASTERN UTILITIES ASSOCIATES (not legible) EXHIBIT B - Financing Parameters Financing will be in an amount of up to $630 M provided through a group of banks. The financing (i) will be prepayable, (ii) will have a term not to exceed seven years, (iii) will have a LIBOR-based borrowing option and (iv) will have other terms and conditions usual and customary for transactions of this nature. EX-99 8 EXHIBIT D-3 APPLICATION TO THE RIPUC The Narragansett Electric Company, Blackstone Valley Electric Company, and Newport Electric Corporation Rate Plan Filing in Support of Merger Volume 1 Filing Letter and Testimony and Exhibits of: Michael E. Jesanis Robert G. Powderly Lawrence J. Reilly David M. Webster May, 1999 Submitted to: Rhode Island Public Utilities Commission RIPUC Docket __________ Submitted by: NEES Logo EUA Logo May 20, 1999 Luly E. Massaro Commission Clerk Public Utilities Commission 100 Orange Street Providence, RI 02903 Re: Rate Plan Filing Relating to the Consolidation of Narragansett Electric, Blackstone Valley Electric, and Newport Electric Dear Ms. Massaro: Enclosed for filing with the Commission are ten copies of a rate plan filing of The Narragansett Electric Company ("Narragansett"), Blackstone Valley Electric Company ("BVE"), and Newport Electric Corporation ("Newport") (collectively, "Companies"). The rate plan relates to the consolidation of the Companies in connection with the merger of New England Electric System ("NEES") and Eastern Utilities Associates ("EUA"). Through this filing the Companies are seeking approval of a rate plan that would go into effect within 120 days of the closing of the EUA-NEES merger or April 1, 2000, whichever occurs later ("Rate Consolidation Date"). On the Rate Consolidation Date, distribution rates for BVE and Newport customers would be immediately reduced by approximately $2 million and $3.4 million, respectively, as BVE's customers are placed on Narragansett's distribution rates and Newport's distribution rates are moved half the distance to Narragansett's distribution rates. This represents reductions in average total delivery rates for BVE and Newport in the first year (excluding the Standard Offer) of 2.6% and 8.8%, respectively. Additional customer savings will be accomplished through a two phase distribution rate freeze applicable to all customers (including Narragansett Rate Plan Filing of Narragansett Electric, BVE, and Newport Electric May 20, 1999 Page 2 of 3 customers) through 2004. Specifically, the Companies commit as part of the NEES-EUA transaction to freeze the distribution component of its rates through the year 2002. In addition, the Companies propose to extend the rate freeze on the distribution component of its delivery rate for an additional two years through 2004 if the National Grid Group's merger with NEES is approved. Thus, under the rate plan, customers will see stable distribution charges through December 31, 2004. In addition, by 2004, total average delivery rates for BVE and Newport under the rate plan will be approximately 15% and 20% less than they otherwise would have been in the absence of the merger. The four year distribution rate freeze shares the savings expected to result from the NEES-EUA merger. We believe that the merger will allow the combined Rhode Island and Massachusetts based system to reduce annual costs by $35 million in 2005. Rhode Island's annual share of that amount will be approximately $9 million after the expiration of the rate freeze in 2005.1 In addition, the distribution rate freeze eliminates cost of service increases that might otherwise have added $20 million additional revenues to the base distribution charges of the combined companies, assuming distribution rates would have risen by at least the rate of inflation. Over the four year period of the distribution rate freeze, customers of the consolidated company receive economic benefits equal to $79 million. Almost $49 million of this amount stems directly from the economic value of the distribution rate freeze. Finally, the consolidation of the Companies and the integration of the Narragansett, BVE, and Newport billing systems should promote the competitive market for electricity - --------------- 1 Under our proposal, these savings are applied first to the cost of the EUA acquisition and are then divided equally between customers and the recovery of the acquisition costs resulting from the NEES-National Grid transaction. Rate Plan Filing of Narragansett Electric, BVE, and Newport Electric May 20, 1999 Page 3 of 3 supplies by lowering marketing and transaction costs for suppliers and customers. Thank you for your attention to this matter. For the convenience of the Commission, a copy of this letter has been inserted and bound into volume 1 of the filing under the first tab. Sincerely, /s/ Ronald T. Gerwatowski ---------------------------------------- Ronald T. Gerwatowski Thomas G. Robinson Attorneys for Narragansett Electric Very truly yours, /s/ David A. Fazzone ---------------------------------------- David A. Fazzone McDermott, Will & Emery Attorney for Blackstone Valley Electric and Newport Electric THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - ------------------------------------ ) Narragansett Electric ) Blackstone Valley Electric Company ) R.I.P.U.C. No. __________ Newport Electric Corporation ) ) - ------------------------------------ DIRECT TESTIMONY OF MICHAEL E. JESANIS THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - ------------------------------------ ) Narragansett Electric ) Blackstone Valley Electric Company ) R.I.P.U.C. No. __________ Newport Electric Corporation ) ) - ------------------------------------ DIRECT TESTIMONY OF MICHAEL E. JESANIS Table of Contents Page I. Qualifications .......................................................1 II. Purpose of Testimony and Summary of Filing ...........................2 III. Terms, Conditions, and Structure of the Transaction ..................6 IV. Rate Plan.............................................................9 A. Rate Reductions and Rate Consolidation Plan..................9 B. Distribution Rate Freeze....................................15 1. First Phase: NEES-EUA, 2001 and 2002...............15 2. Second Phase: NEES-National Grid, 2003 and 2004....16 C. Recovering the Costs of Consolidation ......................18 V. Benefits Created by the NEES Acquisition of EUA......................24 VI. The Acquisition Premium and Transaction Costs........................33 VII. Future Earnings Reports .............................................39 VIII. FAS 71 ...................................................40 IX. Other Regulatory Approvals...........................................42
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 1 of 44 1 I. Qualifications. 2 Q. Please state your name and business address. 3 A. Michael E. Jesanis, 25 Research Drive, Westborough, Massachusetts. 4 5 Q. By whom are you employed and what is your position? 6 A. I am Senior Vice President and Chief Financial Officer of New England Electric System 7 ("NEES"). I am also Vice President of The Narragansett Electric Company 8 ("Narragansett"), New England Power Company ("NEP"), and New England Power 9 Service Company ("NEPSCO"). 10 11 Q. Please summarize your professional and educational background. 12 A. I joined the NEES companies in 1983 as a financial analyst and was elected Treasurer of 13 NEES in 1992. I was elected a Vice President of NEES effective January 1, 1997 and 14 Senior Vice President and Chief Financial Officer effective March 1, 1998. I earned 15 bachelor's and master's degrees in mathematics from Clarkson College of Technology and 16 a master of business administration degree from the Wharton School at the University of 17 Pennsylvania. 18 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 2 of 44 1 Q. Have you previously testified before any regulatory commission? 2 A. Yes. I have testified before the Commission, the Massachusetts Department of 3 Telecommunications and Energy, the New Hampshire Public Utilities Commission, and 4 the Federal Energy Regulatory Commission. 5 6 II. Purpose of Testimony and Summary of Filing. 7 Q. What is the purpose of this filing? 8 A. On February 1, 1999, NEES, Eastern Utilities Associates ("EUA"), and Research Drive 9 LLC ("Research Drive"), a directly and indirectly wholly owned subsidiary of NEES 10 entered into an Agreement and Plan of Merger ("EUA Agreement"), through which EUA 11 will become a wholly owned subsidiary of NEES. Upon the closing of the EUA 12 transaction, it is the intention of NEES to consolidate the three Rhode Island operating 13 companies, Narragansett, Blackstone Valley Electric ("BVE"), and Newport Electric 14 Corporation ("Newport") (together, the "Companies"). This filing requests the 15 Commission approve rates that would go into effect within 120 days of the closing of the 16 EUA merger or April 1, 2000, whichever occurs later. 17 18 Q. Please describe the companies involved in this transaction? 19 A. NEES is a registered holding company under the Public Utility Holding Company Act of 20 1935 ("Holding Company Act") and owns the common equity of several electric utility Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 3 of 44 1 companies, including Narragansett, Massachusetts Electric Company, Nantucket Electric 2 Company, NEP, and Granite State Electric Company. NEES has entered into an 3 agreement to merge with National Grid Group ("National Grid"), completion of which is 4 awaiting regulatory approvals. 5 6 EUA also is a registered holding company under the Holding Company Act and owns 7 directly or indirectly the common equity of several electric utility companies, including 8 BVE, Newport, Eastern Edison Company ("Eastern Edison"), and Montaup Electric 9 Company ("Montaup"). 10 11 Q. What approvals are being sought from the Commission? 12 A. The Companies are seeking approval of a rate plan that would go into effect within 120 13 days of the closing of the EUA acquisition or April 1, 2000, whichever occurs later. The 14 rate plan lowers Newport and BVE rates, and freezes distribution rates for all customers 15 through the year 2004. As a part of the rate plan, the Companies seek an order from the 16 Commission allowing rate recovery of the acquisition premium paid to acquire EUA and a 17 mechanism for recovering a portion of the premium paid by National Grid to acquire 18 NEES, which has allowed this transaction to move forward. In addition, the Companies 19 seek an order relating to the implementation of new depreciation rates, including a 20 mechanism for addressing a problem that Narragansett faces relating to the recovery of Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 4 of 44 1 cost of removal expenses, which will be described in greater detail in this filing. Finally, 2 the Companies request a consolidation of the respective storm funds of each of the three 3 Companies. 4 5 Q. What issues will your testimony address? 6 A. I explain the structure and terms of the EUA/NEES merger, summarize its benefits for 7 NEES customers, employees, and shareholders, and describe the regulatory approvals 8 necessary to implement the transaction. I also summarize our plan for consolidating the 9 NEES and EUA operating companies. In addition, I will summarize the Companies' rate 10 plan proposal that moves BVE's customers to Narragansett's lower distribution rates 11 reducing rates to BVE customers by approximately $2.0 million, lowers distribution rates 12 for Newport customers by $3.4 million, and implements a four year distribution rate freeze 13 across the board. As I explain, the four year rate freeze provides over $79 million of 14 economic value to the customers of the three companies and reduces retail delivery rates 15 by 15 percent for BVE and 20.4 percent for Newport below the rates that would have 16 occurred without the consolidation and distribution rate freeze. Finally, I address the 17 transaction and acquisition costs associated with the transaction and explain our plans for 18 allocating these costs among the NEES operating companies and addressing them in the 19 ratemaking process. 20 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 5 of 44 1 Q. Who else is supporting the filing? 2 A. In addition to my testimony, Mr. Robert Powderly, Executive Vice President of EUA will 3 discuss the reasons behind EUA's decision to be acquired by NEES. Lawrence J. Reilly, 4 President and Chief Executive Officer of Narragansett describes how Narragansett 5 Electric and its affiliated distribution companies are organized today to provide quality 6 service to customers. In addition, he describes the integration process that is underway 7 with EUA and the anticipated benefits for customers. Finally, he describes the benefits 8 that the merger creates for customers in the power supply market. 9 10 David M. Webster, Principal Financial Analyst with the NEES companies, addresses the 11 accounting issues associated with the combination of the three companies, including the 12 development of consistent depreciation schedules and accruals for accounting purposes. 13 Mr. Webster also explains the issues related to cost of removal expenditures that have 14 resulted in a deficiency in the deferred taxes reserves recorded on Narragansett's books 15 that the Company ultimately will need to reflect in rates. In addition, Mr. Webster 16 discusses the Company's proposal to consolidate the storm funds of the three Rhode 17 Island utilities. 18 19 James M. Molloy, Senior Rate Analyst for the NEES companies, and James J. Bonner, 20 Manager of Retail Pricing and Rate Administration for the EUA companies, support the Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 6 of 44 1 rate plan following the merger. Their testimonies document the rates and rate mapping 2 associated with consolidating the NEP and Montaup transmission rates, moving BVE 3 customers to Narragansett's rates, and lowering rates for Newport customers. 4 5 Finally, David J. Hoffman and Richard J. Levin of Mercer Management Consulting 6 provide the analysis of synergies and savings that were identified as part of our analysis 7 leading to the merger decision. These savings support the rate treatment of the acquisition 8 costs associated with the EUA/NEES merger. 9 10 III. Terms, Conditions, and Structure of the Transaction. 11 Q. Mr. Jesanis, would you please summarize the transaction between NEES and EUA? 12 A. The transaction is set forth in the EUA Agreement included as Exhibit MEJ-1. Pursuant 13 to the EUA Agreement, Research Drive will merge with and into EUA with EUA 14 becoming a wholly owned subsidiary of NEES. EUA shareholders will receive $31 per 15 share in cash, which will be increased at a rate of $.003 each day beginning six months 16 after EUA shareholder approval of the EUA acquisition. The merger agreement contains 17 terms and conditions which are typical to a merger transaction. Closing of the merger is 18 subject co obtaining approval of EUA shareholders and obtaining required regulatory 19 approvals. 20 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 7 of 44 1 Q. How will the acquisition affect EUA's utility subsidiaries? 2 A. At the time of closing, there will be no immediate impact on EUA's utility subsidiaries. 3 For example, BVE and Newport, currently subsidiaries of EUA, will remain so, with EUA 4 becoming a subsidiary of NEES. However, as soon as practicable thereafter, we intend to 5 consolidate the operating companies of EUA with the operating companies of NEES 6 7 Q. How will the consolidations be implemented? 8 A. In the case of the Rhode Island operating companies, it is our intention to merge BVE and 9 Newport into Narragansett. However, there may be an interim period during which the 10 three companies retain their legal existence as separate corporations, pending a 11 clarification in Rhode Island law that mergers of public utilities are permitted. Currently, 12 the law allows a public utility to purchase the business and assets of another public utility, 13 but the law is somewhat ambiguous as to whether it permits a formal merger. The 14 clarification could come in the form of legislation or, if necessary, a declaratory judgment 15 request. To the extent that a merger is not permitted, the Companies would exist as 16 separate legal entities, but be operated in a consolidated fashion. In such case, the 17 Companies would propose that the Commission allow one cost of service for the 18 consolidated companies for purposes of rate review. In either case, the Companies' rate 19 plan proposal is not affected by the form of the consolidation. 20 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 8 of 44 1 Q. What about the other operating companies? 2 A. There is no such complication for the other operating companies. Montaup will merge 3 into NEP, and Eastern Edison will merge into Massachusetts Electric. In addition, we 4 expect to combine the operations of the two service companies, NEPSCO and EUA 5 Service Corporation. With the exception of the addition of EUA's unregulated 6 companies, the resulting corporate structure will look essentially the same as NEES's 7 current corporate structure. The corporate structures immediately after the acquisition of 8 EUA and after the later consolidation of the operating companies are shown in Exhibit 9 MEJ-2. 10 11 Q. Are there any closing conditions in the EUA Agreement that pertain to Rhode Island 12 regulatory approvals? 13 A. Yes. In Article VIII, paragraph (d), of the EUA Agreement, there is a condition stating 14 that the parties need to receive "Final Orders from the Massachusetts Department of 15 Telecommunications and Energy and the Rhode Island Public Utilities Commission 16 pertaining to the recovery of costs (including, without limitation, transaction premium and 17 integration costs) associated with the Merger that are materially consistent with existing 18 policy and previous orders of such agencies." As I will explain later in my testimony, the 19 Company is requesting certain rate treatment for the EUA acquisition premium, consistent 20 with Commission precedent and the intent of that closing condition. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 9 of 44 1 IV. Rate Plan. 2 Q. What is the rate plan proposed for Narragansett, BVE, and Newport customers? 3 A. The rate plan has three components. First, we propose to lower distribution rates for 4 BVE and Newport customers by approximately $2.0 million and $3.4 million, respectively. 5 BVE customers would be moved to Narragansett's lower distribution rates, and Newport 6 customers are moved halfway to those lower rates. Transmission rates will be 7 consolidated and transition charges will gradually be moved into parity so that all 8 customers would pay the same transition charges by 2005. Second, we propose to freeze 9 the distribution component of rates for customers of all three Companies through the year 10 2004. Finally, we propose a mechanism to recover the acquisition premium for the 11 NEES-EUA transaction and a portion of the acquisition for the NEES-National Grid 12 transaction. Each of these components is discussed below. 13 14 A. Rate Reductions and Rate Consolidation Plan. 15 Q. What is the first component of the plan? 16 A. The first component of the plan is to reduce rates to the customers of BVE and Newport 17 effective on the later of April 1, 2000 or 120 days after the merger is approved (the "Rate 18 Consolidation Date"). Since the implementation of retail choice in 1997, each utility's 19 rates has been composed of four components -- the distribution charge (including 20 renewables and DSM charges), the transmission charge, the transition charge, and the Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 10 of 44 1 standard offer. The first three of these components represent the delivery rates for 2 customers. The final component represents power supply which is avoided when the 3 customer purchases its power supply in the market. The rate consolidation plan focuses 4 on each of these elements. 5 6 First, with respect to the distribution component, Narragansett proposes to place all of 7 BVE's customers on Narragansett's distribution rates and move Newport's customers half 8 the distance to Narragansett's rates. This would be accomplished by placing Newport's 9 customers on Narragansett's distribution rates and implementing a separate distribution 10 surcharge applicable only to Newport's customers that represents 50 percent of the 11 differential between Newport's distribution rates (excluding DSM and renewables 12 charges) and Narragansett's distribution rates. For purposes of the tariffs, we refer to this 13 distribution surcharge as the "Zonal Distribution Factor." 14 15 The Navy, which is now served by Newport under a special distribution rate, will continue 16 on that rate with a 14 percent rate reduction in the distribution component, which is equal 17 to the average distribution rate decrease for all other Newport customers as a result of the 18 merger. There also is a special rate adjustment that is being proposed to prevent 19 Newport's street lighting customers from experiencing rate increases as a result of the 20 consolidation that is explained in the testimony of Mr. Molloy. In addition, the Companies Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 11 of 44 1 are proposing an interim credit mechanism for low income customers of the EUA 2 companies that also is described in Mr. Molloy's testimony. The result of the 3 consolidation of distribution rates in the rate plan is an annual reduction of approximately 4 $2 million for BVE's customers and $3.4 million for Newport's. 5 6 The Companies are proposing to consolidate the transmission component of the rates 7 effective on January 1, 2001. Prior to that time, the transmission rate components in 8 effect for each of the Companies during 2000 would be locked in at their presently 9 effective levels. Because Montaup's transmission rates are lower than NEP's, the 10 transmission rate consolidation will result in a decrease in transmission component of 11 Narragansett's rates in 2001 and thereafter. Increases in transmission charges for BVE 12 and Newport customers will be more than offset by reduced transition charges. 13 14 Base transition charges will be established at 1.15 cents per kilowatthour for the 15 customers of all three companies on the Rate Consolidation Date. In addition, Newport 16 and BVE customers will pay a surcharge designed to recover the difference between the 17 contract termination charges paid to NEP and Montaup by the three companies and the 18 revenues collected under the base transition charge of 1.15 cents per kilowatthour from 19 the customers of the three companies. This difference divided by the kilowatthour 20 deliveries of BVE and Newport will be applied to deliveries in BVE and Newport service Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 12 of 44 1 territories. For purposes of the tariffs, the transition surcharge is referred to as the "Zonal 2 Transition Factor." The Companies are proposing to keep this transition mechanism in 3 effect until a surcharge is no longer necessary and transition charges come into complete 4 parity. Once this occurs, the Companies will propose consolidated transition factors. We 5 expect that this will occur around 2005. Thus, the customers of Narragansett would 6 continue to pay 1.15 cents per kilowatthour until transition charges are consolidated. 7 8 Q. Did you consider blending the transition charges without adding the surcharge to BVE 9 and Newport to transition charge? 10 A. Yes. However, the rate differential is significant and blending would result in an increase 11 to Narragansett's customers. BVE and Newport's contract termination charges from 12 Montaup are higher than NEP's contract termination charges to Narragansett. In 13 addition, Narragansett has already brought down a significant component of its transition 14 charge through an early payment to NEP. As a result, Narragansett's transition charges 15 are significantly below those of BVE and Newport. These disparities make it difficult to 16 equalize the transition charges prior to 2005. 17 18 Q. What is the effect of the rate plan in 2000 after the Rate Consolidation Date? 19 A. The consolidation will reduce average delivery rates excluding the Standard Offer to BVE 20 and Newport customers by 2.6 percent and 8.8 percent, below the levels in place before Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 13 of 44 1 the Rate Consolidation Date. Rates to Narragansett's current customers do not change. 2 The rates and revenues in 2000 before and after the merger are shown on Exhibit MEJ-3, 3 page 1. As that Exhibit demonstrates, the merger produces significant economic benefits 4 for BVE and Newport customers on the Rate Consolidation Date. 5 6 Q. What happens to rates of the consolidated companies in 2001? 7 A. As explained above, the transmission component of the retail delivery rate is combined on 8 January 1, 2001, producing a reduction for Narragansett's existing customers of about 9 .057 cents per kilowatthour. Under our plan this reduction is partially offset by an 10 increase in the distribution component of the rate of .039 cents per kilowatthour designed 11 to recover on a prospective basis Narragansett's costs of removing its equipment after the 12 equipment is retired. The distribution increase is applied to the consolidated distribution 13 rate of the three companies. As Mr. Webster explains, this recovery is necessary to assure 14 the Company's depreciation rates are adequate on a prospective basis to recover the full 15 cost of retiring and removing Narragansett's plant. Both BVE and Newport already 16 reflect cost of removal expenses in their rates and the Division has agreed in a prior case 17 that this recovery is appropriate for Narragansett. Under our plan, we will recognize the 18 increased depreciation expense on our books and match it with rate recovery on January 19 1, 2001. As shown on Exhibit MEJ-3, page 2, the net effect of the two adjustments is a 20 slight decrease for Narragansett's existing customers. Although transmission and Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 14 of 44 1 distribution rates for BVE and Newport customers increase slightly, these increases are 2 more than offset by reduced transition charges in 2001. Thus, the proposed rate plan 3 removes the likelihood of the need for a significant rate increase related to cost of removal 4 alone without increasing delivery charges to customers in 2001. In fact, delivery rates to 5 Narragansett's existing customers fall slightly, and the delivery rates to BVE and Newport 6 decline by an additional 6.5 percent and 6.0 percent respectively (Exhibit MEJ-3, page 2). 7 8 Q. Mr. Webster has also identified a significant deficiency in the provision for taxes for cost 9 of removal. How does the rate plan address that issue? 10 A. Narragansett proposes to recover the deficiency with revenue requirements of about $33 11 million through refunds that would otherwise be made resulting from certain 12 reconciliations in NEP's and Montaup's Contract Termination Charge to the Company. 13 Narragansett and NEP have already agreed to an adjustment equal to $ 10 million from the 14 Reconciliation Report filed in December. In addition, we expect further adjustments as 15 the result of the settlement of a claim with Hydro Quebec (about $2 million), and gas 16 pipeline refunds. These and other refunds that may be received from time to time from 17 either NEP or Montaup could reduce the prior unfunded amount significantly. We 18 propose to continue to apply future credits to Narragansett from settlements and the sale 19 of assets to the account balance until Narragansett's next rate case at which time any Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 15 of 44 1 remaining deficiency would be amortized and recovered beginning at the time of 2 Narragansett's next change in distribution base rates. 3 4 B. Distribution Rate Freeze. 5 Q. Please describe the rate freeze component of the plan. 6 A. The second component of the plan involves a two-phase distribution rate freeze through 7 the year 2004. I will describe each phase below. 8 9 1. First Phase: NEES-EUA, 2001 and 2002. 10 Q. Please explain the first phase of the distribution rate freeze. 11 A. The Company commits as part of the NEES-EUA transaction to freeze the distribution 12 component of its rates through the year 2002. The distribution rate freeze will apply to 13 the customers of all companies under the consolidated rate plan. Narragansett and BVE 14 will charge the same distribution rates through 2001 and 2002, and Newport will maintain 15 its Zonal Distribution Factor at the level initially established on the Rate Consolidation 16 Date through the two year rate freeze period. 17 18 Thus, if the EUA merger is completed, distribution rates to Narragansett's customers, 19 which are among the lowest in New England, will remain at the same level for five years, 20 except for the cost of removal and depreciation adjustment on January 1, 2001. The Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 16 of 44 1 Company would retain only the ability to adjust rates to reflect costs incurred as a result of 2 any one of the following exogenous events occurring during the rate freeze period: (1) 3 changes to local, state, and federal tax laws, regulations, or precedents, (2) incurrence of 4 hazardous waste clean up liability from manufactured gas plants of Narragansett, 5 Newport, or BVE or their predecessor companies, and (3) changes to accounting rules 6 and practices. Assuming distribution rates would have otherwise increased at an inflation 7 rate of 2.2 percent per annum, the cumulative value of the rate plan for the customers of 8 the consolidated Narragansett is approximately $31 million through December 31, 2002. 9 See Exhibit MEJ-4, page 1, line 5. 10 11 The two year distribution rate freeze shares the savings from the NEES-EUA merger. As 12 described more fully later in my testimony, we believe that the merger will allow the 13 combined system to reduce annual costs by $35 million in 2005. The Rhode Island share 14 of this amount is about $9 million per year. In contrast, the distribution rate freeze 15 eliminates cost of service increases that might otherwise have added $20 million additional 16 revenues to the base distribution charges of the combined companies, assuming 17 distribution rates would have risen by at least the rate of inflation. 18 19 2. Second Phase: NEES-National Grid, 2003 and 2004. 20 Q. Please describe the second phase of the rate freeze. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 17 of 44 1 A. The second phase involves a further two year extension of the distribution rate freeze. 2 Because we believe that the National Grid merger will allow us to produce significant 3 additional savings through improved operations, further efficiency gains, the adoption of 4 best practices, and improved scale economies, Narragansett proposes to extend the 5 distribution rate freeze an additional two years through December 31, 2004 contingent 6 upon the closing of the NEES-National Grid merger. This provides Narragansett's 7 customers price stability for regulated service for seven years. The value of the rate plan 8 will grow to over $26 million per year by 2004 and will total approximately $79 million 9 over the rate freeze period. See Exhibit MEJ-4, page 1, line 4. 10 11 The distribution rate freeze represents the most significant element of these savings. As 12 shown on page 1, lines 5 and 6 of Exhibit MEJ-5, the savings associated with the 13 distribution rate freeze total $20 million in 2004 and $49 million over the 4 year period. 14 Because of the length of the rate freeze and the potential that inflation may exceed current 15 projections by a significant amount, we propose to add an adjustment in the event that 16 inflation occurring during the extended rate freeze in calendar years 2003 and 2004 17 exceeds 3.0 percent. Specifically, the average distribution rate at the "Consolidation Date" 18 is 2.993 cents per kilowatthour as shown in Exhibit JMM-3, page 1, line 1. This amount 19 will be adjusted in accordance with the methodology illustrated in Exhibit MEJ-6, which 20 compares actual inflation as measured by the Consumer Price Index Deflator - All Urban Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 18 of 44 1 Consumers ("CPI-U") to 3.0 percent, and adjusts distribution rates in effect in 2003 for 75 2 percent of the excess over 3.0 percent. The adjustment would be calculated at the end of 3 September, 2002 prior to the first year of the extended rate freeze, and the adjustment, if 4 any, would be rolled into distribution rates as a permanent increase. The process would be 5 followed again for the end of September, 2003 for the following year, 2004 which is the 6 last year of the rate freeze. This adjustment would be in addition to any adjustments for 7 the other exogenous factors identified above. We are proposing to use CPI-U as the 8 inflation index because we already use this index in the adjustments to Narragansett's 9 storm fund. It is a broad index of inflation that is representative of the economic 10 conditions in Narragansett's service area. 11 12 C. Recovering the Costs of Consolidation. 13 Q. What is the fourth component of the plan? 14 A. The fourth and final component of the proposed rate plan focuses on Narragansett's 15 financial integrity and the rate setting process following the period of the distribution rate 16 freeze. As set forth later in my testimony, there are significant costs associated with 17 producing the savings that stem from the consolidation of NEES-EUA and NEES- 18 National Grid. These costs for the NEES-EUA transaction are quantified in this filing and 19 compared directly to the savings from the consolidation. As I explain below, the savings 20 from the NEES-EUA consolidation exceed the acquisition premium and the transaction Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 19 of 44 1 costs of the NEES-EUA acquisition. Accordingly, we are proposing to amortize for 2 ratemaking purposes the EUA acquisition premium and transaction costs that are allocated 3 to Narragansett over 20 years as shown on Exhibit MEJ-7. 4 5 Q. Is the Company proposing any rate treatment for the acquisition premium and transaction 6 costs arising out of the NEES-National Grid merger? 7 A. Yes. We also are proposing to retain 50 percent of the savings from the EUA acquisition 8 above and beyond the amortization of the EUA acquisition premium and transaction costs 9 to recover a portion of the acquisition premium and transaction costs paid by National 10 Grid to acquire NEES. The remaining 50 percent of the excess savings will flow through 11 to customers following the rate freeze producing a reduction in distribution rates from the 12 level that customers would have experienced absent the merger. 13 14 Q. Does the Company propose to recover the costs of severance payments for officers of 15 EUA, the parent company of BVE and Newport, or for NEES, the parent of 16 Narragansett? 17 A. No. We have excluded the costs of those severance payments for all EUA parent 18 company officers. However, the transaction costs do include other severance payments 19 that may be made to other EUA system employees who may be displaced as a result of the Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 20 of 44 1 merger. We have also excluded the costs of any severance payments that might be made 2 to any NEES parent company officers. 3 4 Q. How will the sharing mechanism relating to the National Grid-NEES acquisition premium 5 and transaction costs work? 6 A. The annual savings from the consolidation of the companies will equal $35 million per 7 year in the first full year after the rate freeze. These savings are expected to grow by 8 inflation over the long term. Of this amount, we expect that approximately 25 percent or 9 $9 million will flow to the consolidated Narragansett. These savings provide the basis for 10 the sharing plan. 11 12 Under our plan, the future annual savings will be fixed and determined in this proceeding. 13 At the time of any future Narragansett distribution rate proceeding, Narragansett would be 14 allowed to include in its cost of service the annual amortization of the EUA acquisition 15 premium and transaction costs, because the annual amortization is less than the savings 16 produced by the merger. As shown in Exhibit MEJ-8, the Rhode Island portion of the 17 annual amortization expense for the EUA transaction is $5,473,000 for 20 years and zero 18 thereafter. Under our proposal, the amortization would first be subtracted from the annual 19 savings and 50 percent of the remaining savings would then be applied to recover the 20 NEES-National Grid acquisition premium and transaction costs. For example, if the Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 21 of 44 1 Commission found that the EUA consolidation produced $35 million of annual savings in 2 2005 when the distribution rate freeze ends, and that $8,887,000 would be allocated to 3 Narragansett, Narragansett could include in its first cost of service following the rate 4 freeze, an annual amortization of the EUA-NEES acquisition premium equal to 5 $5,473,000 plus one half of the remaining savings to apply against the NEES-National 6 Grid acquisition premium. Thus, 50 percent of $3,414,000 ($8,887,000 - $5,473,000 = 7 $3,414,000) equal to $1,707,000 would be applied against the National Grid premium and 8 transaction costs, and $1,707,000 will be reflected in a lower cost of service. 9 10 The amount of savings available for the 50/50 sharing mechanism grows over time as the 11 savings grow by inflation, and amortization of the EUA acquisition premium is eliminated 12 after 20 years. Exhibit MEJ-8 illustrates the calculation based on an assumed level of 13 inflation equal to 2.2 percent, and shows the annual sharing amounts. The actual level of 14 sharing will be based on actual inflation experienced over the period. Under our proposal, 15 except for the adjustment to reflect actual inflation, these amounts would be fixed for the 16 NEES-EUA transaction in this proceeding. 17 18 Q. Does the share of savings that is applied against the National Grid acquisition premium 19 and transaction costs match the amortization of the premium for accounting purposes? Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 22 of 44 1 A. No. As we have explained, the ratemaking treatment for the acquisition premium and 2 transaction costs is different from the accounting treatment. As with the EUA acquisition 3 premium and transaction costs, the National Grid acquisition premium and transaction 4 costs will be pushed down to the NEES companies, including Narragansett, and amortized 5 for accounting purposes over 20 years. The accounting treatment of the National Grid 6 premium does not control rate recovery and the sharing mechanism postpones rate 7 recovery of the portion of the National Grid acquisition premium recovered through the 8 proposed sharing mechanism to a later period. 9 10 Q. What is the portion of the NEES-National Grid premium that is recovered through this 11 mechanism? 12 A. The present values of the savings from the NEES-EUA merger, the amortization of the 13 EUA acquisition premium and transaction costs, and the remaining savings are shown on 14 Exhibit MEJ-9. As that exhibit shows, the net present value of the Rhode Island portion 15 of the merger savings in excess of the EUA recovery is $91 million. Fifty percent of this 16 present value or $46 million is the recovery of the NEES-National Grid premium. This 17 amount will be deducted from the present value of the amortization of the NEES-National 18 Grid premium allocated to Narragansett and will not be recovered in any other way. 19 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 23 of 44 1 Q. Would this sharing mechanism be applied to future acquisitions? 2 A. Yes. Our goal is to generate further savings through future consolidations in the 3 Northeast. Under our plan, 50 percent of the savings in excess of the EUA acquisition 4 premium and transaction costs allocated to Rhode Island customers will also be applied to 5 recover the NEES-National Grid acquisition premium and the transaction costs. The 6 National Grid acquisition of NEES is essential for the consolidation of other low cost 7 utilities in the Northeast. Even though these consolidations, by definition, would involve 8 acquisitions outside of Rhode Island, savings will flow to Narragansett automatically 9 without any associated acquisition premium or transaction costs. For example, if Mass. 10 Electric were to merge with another Massachusetts utility, Rhode Island would see 11 benefits from that transaction without an allocation of acquisition costs. Similarly, as 12 shown on Exhibit MEJ-9, a portion of the savings from the EUA transaction is 13 automatically flowing to New Hampshire customers, but the acquisition costs are not, 14 because EUA has no operations in New Hampshire. These benefits are the direct result of 15 this and future consolidations. If we successfully implement other mergers in the future, 16 Narragansett's customers will share the benefits of these consolidations even though they 17 occur outside of Rhode Island. As in this case, Narragansett would demonstrate the 18 savings and the sharing at the outset through a synergy study. 19 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 24 of 44 1 Q. Would the 50 percent sharing apply to savings from ongoing efficiency gains? 2 A. No. Ongoing efficiencies will be generated through an array of activities beyond 3 consolidations. We propose to maintain flexibility to design incentives and sharing 4 mechanisms tailored to specific issues and problems. A simple sharing mechanism may 5 not produce the correct economic incentive for specific operations and programs. 6 Program-specific incentive designs may be necessary in the future to encourage capital 7 investment to reduce operating costs, losses, or congestion, or to further specific public 8 policy objectives. 9 10 Q. Will there be a cap on recovery of the NEES-National Grid acquisition premium? 11 A. Yes. Narragansett's recovery will stop when the portion of the acquisition premium and 12 transaction costs associated with the National Grid transaction that is allocated to 13 Narragansett has been recovered. As explained above, the EUA transaction reduces the 14 present value of this recovery by $46 million. Future transactions will be applied to 15 reduce the premium in the same way. When the premium is fully offset, recovery of the 16 National Grid premium will cease. 17 18 V. Benefits Created by the NEES Acquisition of EUA. 19 Q. Would you summarize the benefits created through the NEES acquisition of EUA? 20 A. The acquisition of EUA by NEES will result in the creation of substantial benefits which Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 25 of 44 1 can be used to provide improved service at lower rates to customers, greater opportunities 2 for employees, a premium to EUA shareholders, and an opportunity for NEES and 3 National Grid shareholders to earn reasonable returns on their investments in the 4 companies. 5 6 The benefits to customers will be produced by the proposed rate plan described above. 7 These benefits are financed in part by the savings produced by the NEES-EUA 8 consolidation. The acquisition and consolidation produce synergies which are typical of 9 utility combinations. These synergies build on efficiencies already achieved by the 10 Companies, which are low cost utilities in New England. 11 12 Q. How will the cost savings you described be achieved? 13 A. The cost savings will come from a variety of categories. Approximately 70 percent of the 14 savings will come from eliminating approximately 250 positions from the combined 15 organization. These reductions come from across the organization. Administrative areas 16 such as accounting and finance, where significant redundancies exist between the two 17 companies, will be reduced. EUA's and NEES' customer service operations will be 18 integrated to handle increased volumes at a lower unit cost. The unit cost of field 19 operations will also be reduced through standardization and mutual support. The 20 remainder of the operating savings will come from disposing of duplicate facilities, Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 26 of 44 1 realizing greater purchasing power, and eliminating redundant administrative costs, such as 2 corporate governance expense. Mr. Hoffman testifies at length on these savings. 3 4 Q. What is your estimate of savings that will be achieved? 5 A. Based on the analysis performed by NEES and Mercer Management, the savings will be 6 about $31.1 million per year by the end of the distribution rate freeze period for all of the 7 NEES/EUA retail distribution companies in Rhode Island and Massachusetts. For reasons 8 I describe below, I believe that the estimate developed by Mercer Management is 9 conservative and that we will achieve total savings of $3 5 million per year by the end of 10 the rate freeze period. These savings will grow with inflation over time. As shown on 11 Exhibit MEJ-9, the present value of the savings after amortization of the EUA acquisition 12 premium and transaction costs will be at least $356 million. Narragansett's share of that 13 amount is $91 million. 14 15 Q. Please describe the goals of the NEES/EUA integration process. 16 A. In my view, there are two overriding goals to the integration process. First, the 17 integration process is critical to achieving the efficiency gains upon which the transaction 18 was predicated. Second, it is equally important to combine the two organizations in a way 19 that maintains or improves service quality. The integration process is providing us the 20 opportunity to review our business practices to identify additional opportunities to Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 27 of 44 1 streamline operations. The integration process also provides us the opportunity to 2 compare business processes and adopt best practices where they can improve service to 3 customers. 4 5 Q. How is the integration effort organized? 6 A. Following the announcement of the NEES-EUA transaction, the two companies created a 7 transition team charged with consolidating the companies in a manner which creates more 8 cost savings than were assumed in the Mercer analysis. The transition team is led by 9 Thomas E. Rogers, Vice President and Director of Corporate Planning for NEPSCO, who 10 directed the sale of our non-nuclear generating business, and Mr. Powderly of EUA, who 11 was responsible for integration activities following EUA's acquisition of Newport. The 12 transition team has formed over 60 individual sub-teams covering all aspects of the 13 business. Each of these teams is charged with the task of identifying savings and 14 efficiency gains. 15 16 Q. What is the schedule for the integration effort? 17 A. The various transition teams have been established and are meeting regularly. For 18 planning purposes, we are targeting October 1, 1999, as the completion date for the 19 process so that we will be ready to move forward with implementation as soon as the 20 necessary regulatory approvals are in hand. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 28 of 44 1 Q. How do you expect that the integration efforts will lead to an improvement on Mercer's 2 estimate of $30 million in annual savings? 3 A. One example of my expectation of better performance is within administrative functions. 4 The Mercer analysis concluded that the combined NEES-EUA companies would need 18 5 percent more personnel in administrative functions than NEES presently has today when 6 the combined company has 22 percent more customers. Given that we will be merging the 7 operating companies into a structure that is nearly identical to NEES's structure, I do not 8 believe that we will need 18 percent more accountants, information systems professionals, 9 lawyers and rate analysts when we have no more utility companies in our holding company 10 creating accounting statements, making rate filings or requiring information system 11 resources. Reducing the incremental administrative needs by half will increase savings by 12 $3-5 million per year at the end of the rate freeze. I further believe that Mercer's 13 estimates in customer service and distribution operations understate the benefits we will 14 achieve from the larger scale of the combined NEES-EUA system. 15 16 Q. Are there other savings that are not included in your analysis? 17 A. Yes. We believe that the NEES-National Grid merger will produce additional savings and 18 efficiency gains. We are now evaluating integration possibilities between NEES and 19 National Grid that will implement best practices. These efforts will produce savings for 20 NEES and for the newly acquired EUA companies. Equally important, we expect that Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 29 of 44 1 over time National Grid's significantly larger scale, both in financial and operational terms, 2 will enhance our ability to be at the leading edge of developments in transmission and 3 distribution technology, information systems and capital markets. The increased expertise 4 and resources will enhance our ability to provide customers of both NEES and EUA with 5 high quality transmission and distribution service at reasonable costs. The benefits that 6 will accrue to EUA from the NEES-National Grid integration process are not reflected in 7 our savings estimates for the NEES-EUA merger. Rather, the NEES-National Grid 8 savings will be demonstrated in a separate proceeding. 9 10 In addition, the savings study performed by Mr. Hoffman excludes certain cost savings 11 which are typically counted in other utility mergers. For example, most utility mergers 12 include as savings the costs of building one rather than two sets of new information 13 systems (usually customer or financial) at some time in the future. Both NEES and EUA 14 have older customer information systems. The cost of replacing these systems would 15 currently be in excess of $10 million per company. We did not include these costs in our 16 study because of the difficulty in pinpointing the timeframe in which the savings will occur. 17 Nevertheless, the savings are real and Will provide future benefits. 18 19 Finally, we expect the higher credit ratings of the NEES companies to lead to financing 20 savings as the debt of the EUA companies is refinanced over time. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 30 of 44 1 Q. Can the annual savings included in your analysis be achieved absent the proposed 2 acquisition? 3 A. No. NEES and EUA have superb long-term records of managing costs. One measure of 4 this record is the rates charged to customers. As shown on Exhibit MEJ-10, NEES and 5 EUA customers enjoy lower rates than the customers of most investor owned utilities in 6 neighboring service areas in New England. 7 8 Another measure of cost efficiency is the number of employees required to serve each 9 1,000 customers. Prior to the combination, NEES (at 2.4 employees/1,000 customers) 10 and EUA (at 2.8 employees/1,000 customers) are significantly more efficient than Boston 11 Edison Company, the second largest utility in Massachusetts (which has 3.4 12 employees/1,000 customers). EUA's performance is particularly noteworthy because it 13 has achieved this record of performance despite the fact that it has less than half the 14 customers of Boston Edison. Both NEES and EUA have met their obligations to reduce 15 their costs on a stand alone basis. The combination of NEES, EUA and National Grid 16 represents the best opportunity to continue the track record of NEES and EUA in 17 controlling costs for the benefit of customers. 18 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 31 of 44 1 Q. How will EUA shareholders benefit from the combination? 2 A. The benefits to EUA shareholders stem from the consideration received for their shares at 3 closing. The base consideration of $31 per share is equal to 105 percent of the $29-1/16 4 market value of the shares on the last trading day before the merger was announced and 5 approximately 169 percent of EUA's book value per share of $18.29 as of December 31, 6 1998. The purchase is equal to a 23 percent premium over the market price on December 7 4, 1998, the last trading day before the BEC Energy-Commonwealth Energy merger was 8 announced. As explained earlier, the purchase price is subject to adjustment depending on 9 the timing of the closing The purchase price will be paid in cash. Mr. Powderly further 10 describes the basis for EUA's conclusion that the price to be paid is fair to EUA 11 shareholders. 12 13 Q. Why did you use the December 4, 1998 closing price in determining the value to 14 shareholders? 15 A. Beginning on December 7, 1998 with the announcement of the BEC Energy - 16 Commonwealth Energy merger, EUA's share began rising substantially above the range in 17 which they had traded in recent months. Based on the long-term previous performance of 18 EUA shares in the market, I believe that this price appreciation is the result of speculation 19 that EUA would enter into some kind of merger agreement at a price significantly higher 20 than the trading price on December 4, 1998. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 32 of 44 1 Q. What about the benefits to employees? 2 A. Although the merger is expected to reduce employment by about 250 positions in the 3 combined companies, we believe that these employee reductions can be achieved 4 predominantly through attrition or voluntary early retirement and without significant 5 involuntary layoffs. The efficiency gains are essential to the viability of our companies in 6 the restructured utility industry. For remaining employees, the merger and the NEES- 7 National Grid transaction represent a superb opportunity for growth as we move forward 8 as the United States base of operations for a large international group. The expanded 9 opportunities in this country will stem from National Grid's express intention to expand 10 and consolidate its operations here in this country. The fulfillment of this plan ensures that 11 NEES and EUA employees will remain active in the industry restructuring debate in the 12 United States. National Grid's expanding foreign operations will also provide 13 opportunities for employees abroad. 14 15 Q. Are NEES and EUA taking steps to mitigate the loss of positions following the NEES-EUA 16 merger? 17 A. Yes. In anticipation of the merger's approval, we have placed a limitation on hiring for 18 our company. The NEES companies expect to have a significant number of vacant 19 positions by the time the transaction closes. Natural attrition at EUA is expected to add 20 more positions. We are making every effort to leave these positions vacant until Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 33 of 44 1 employees affected by the acquisition have an opportunity to be considered for a position. 2 Beyond vacancies and attrition, we can economically offer 200 to 250 NEES and EUA 3 employees a voluntary early retirement program, Through these measures, we expect to 4 meet our workforce reduction targets without having a significant impact on individual 5 employees. 6 7 NEES has also agreed in the merger agreement to honor EUA's collective bargaining 8 agreements and to provide non-union employees joining the NEES companies with 9 compensation and benefits in the aggregate at least equivalent to those obtained prior to 10 the merger for a year following closing. EUA employees joining the NEES system will 11 find that the compensation and benefit philosophies of the two companies are very similar, 12 allowing us to merge benefit plans without significant disruption to employees. 13 14 VI. The Acquisition Premium and Transaction Costs. 15 Q. What are the costs associated with NEES's acquisition of EUA? 16 A. NEES is acquiring EUA at a premium of approximately $260 million above the book 17 value of EUA's shares. Because the acquisition of EUA is for cash, the conditions for 18 pooling of interest accounting are not met in this transaction and therefore, purchase 19 accounting must be used. Under Generally Accepted Accounting Principles (GAAP) for 20 purchase accounting, the premium is recorded as goodwill on the acquired company's Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 34 of 44 1 accounts. The premium will be allocated to each of the EUA operating companies 2 following the closing and added to their balance sheets as goodwill. The goodwill will be 3 amortized over 20 years for ratemaking purposes. 4 5 In addition to the acquisition premium, we expect that the transaction costs and the cost of 6 integrating EUA into NEES and achieving our savings targets will be approximately $64 7 million. Mr. Hoffman provides support for our cost estimates. 8 9 Q. How will these costs be allocated among the EUA subsidiaries? 10 A. A "fair value" study will be conducted around the time of closing the merger to determine 11 the allocation of the purchase price among the EUA subsidiaries. The acquisition 12 premium and transaction costs will be allocated in two steps. First, the acquisition 13 premium will be allocated to the unregulated subsidiaries based on the difference between 14 their market value and their book value. This adjustment brings the value of the 15 unregulated firms up to the value reflected in the acquisition. In our analysis we have 16 based this allocation on the underlying book value of the unregulated firms. We expect 17 the allocation to be refined in the valuation study, because the book value of an 18 unregulated enterprise does not bear any direct relationship to its market value. 19 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 35 of 44 1 The second step of the analysis allocates the remainder of the acquisition premium among 2 the regulated companies. This analysis includes the allocation of the transaction and 3 integration costs which are in this transaction all related to regulated operations. Our 4 proposed allocation among the regulated companies is based on the kilowatt-hour sales 5 following the consolidations in Rhode Island and Massachusetts. We propose that the 6 balance of the acquisition premium that is allocated to the regulated businesses be 7 allocated among BVE, Newport and the Massachusetts subsidiary Eastern Edison on the 8 basis of a three year average of kilowatt-hour deliveries to Rhode Island and 9 Massachusetts customers. The integration costs, which are entirely related to the 10 regulated subsidiaries, would be allocated among them in a similar manner. 11 12 This allocation matches the allocation of savings from the transaction, and the economic 13 value that is produced by the consolidation and reflected in the purchase price. Given that 14 transmission and distribution remain regulated businesses priced at the cost of providing 15 service, the value added by the transaction is related to the underlying savings produced by 16 the consolidation. As the result of rate design and service company allocations, these 17 savings will generally be based on kilowatthour deliveries to retail customers. The 18 allocation of the acquisition premium and transaction costs follows this methodology. 19 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 36 of 44 1 Q. Have you allocated any transaction costs or acquisition premium to Montaup/NEP? 2 A. Not in the analysis included in this filing. The primary savings associated with the EUA 3 transaction will be realized in distribution to retail delivery customers. Retail delivery and 4 its associated cost of service represent the bulk of the costs on the system and will 5 represent the most significant source of our savings, directly and indirectly through lower 6 administrative and general expense per customer service. This approach also matches the 7 allocation of the acquisition premium for other utilities whose transmission and 8 distribution rates remain unbundled in the same operating company. 9 10 Moreover, to the extent transmission savings exist, they will flow to retail customers 11 automatically through NEP's formula rate in proportion to Narragansett's retail deliveries. 12 NEP's transmission charges are based on demands at the time of NEP's peak, and 13 although NEP's rate includes deliveries to both affiliated and non-affiliated customers, the 14 allocation of acquisition costs parallels the kilowatthour allocation. Our proposed 15 allocation also maintains the Commission's jurisdiction over the issue. 16 17 Q. Do you have an estimate of the acquisition costs to be allocated to the EUA Companies? 18 A. Yes. BVE and Newport would be allocated $60,372,000 of acquisition premium which, 19 when adjusted for income taxes, produces a revenue requirement of $92,876,000. In 20 addition to this amount, BVE and Newport would be allocated $16,593,000 of transaction Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 37 of 44 1 costs. This produces a total revenue requirement of $109,469,000. With a 20 year 2 amortization period, the annual revenue requirement is estimated at $5,473,000. This 3 compares to about $8.9 million for Rhode Island's share of savings in the year following 4 the rate freeze. Exhibit MEJ-7, page 1 illustrates the allocation of the costs of the 5 transaction. The savings grow with inflation over time, but the amortization of the 6 acquisition premium and transaction costs does not. As explained earlier, 50 percent of 7 the excess of savings each year will be applied to recover the NEES-National Grid 8 premium, and following the rate freeze, the remaining 50 percent of excess savings will be 9 reflected in the cost of service to Narragansett's customers. 10 11 Q. Please explain Narragansett's proposal to retain savings to pay the premium paid by 12 National Grid to acquire NEES. 13 A. One of the benefits of the National Grid-NEES merger was the facilitation of 14 consolidation of transmission and distribution companies by low-cost companies such as 15 NEES. The benefits from NEES's acquisition of EUA are the first step in realizing the 16 vision behind the National Grid-NEES merger. Therefore, we are proposing that a 17 portion of the benefits from the NEES-EUA acquisition be shared between customers and 18 National Grid-NEES. The sharing mechanism we propose is fair and efficient. It provides 19 customers with $34.6 million of up-front value through the rate freeze, (Exhibit MEJ-5, 20 page 1, line 6 ($48,773,235 - $14,186,956 = $34,586,279)), and with matching savings Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 38 of 44 1 throughout the remainder of the period. The proposal puts the risk on the Company to 2 realize the savings during the rate freeze period, and significantly postpones the recovery 3 for this portion of the National Grid premium. In short, the proposal is fair and efficient. 4 It assures that Narragansett's customers are better off economically because of the merger 5 with National Grid and EUA, and the future consolidations that will be produced from our 6 new, larger and more financially sound organization. 7 8 Q. Wouldn't the benefits of the EUA acquisition be achieved without the National Grid 9 NEES merger? 10 A. Without the National Grid-NEES merger, the full benefits of the EUA acquisition would 11 not be realized. First, it is unlikely that NEES would have agreed to acquire EUA at this 12 time absent the National Grid-NEES merger agreement. As described in NEES's proxy 13 statement dated March 26, 1999, over the course of 1998, the management and board of 14 directors of NEES determined that finding a strategic partner such as National Grid was in 15 the Company's best interest. As I have explained, the National Grid merger is essential for 16 the low cost NEES utilities to compete in the consolidation of the industry. An agreement 17 to acquire EUA by NEES prior to NEES finding a strategic partner could have 18 significantly impaired or delayed NEES's ability to find and reach agreement with a 19 strategic partner. Under these circumstances, an acquisition of EUA by NEES would 20 have been deferred for a year or longer and perhaps not have occurred at all. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 39 of 44 1 Second, while EUA had alternatives to an acquisition by NEES, in my opinion, those 2 alternatives would not have produced the level of savings or the rate reductions to EUA 3 customers that can be achieved in this proposed acquisition. I believe that EUA's 4 alternatives generally involved mergers with or acquisitions by higher-cost regional 5 utilities. Those utilities do not possess the track record to operate their own service 6 territories at the efficiency levels of NEES or EUA. Therefore they cannot produce the 7 economic benefits by combining with EUA that NEES can achieve. In addition, to the 8 extent savings are achieved, EUA customers are less likely to benefit from these savings 9 since they would most likely be applied to reducing the rates of the acquiring company. 10 EUA's customers could actually be faced with higher costs as the acquiring company 11 combined its higher cost operations with EUA's low-cost operations. 12 13 The EUA acquisition by NEES represents the first tangible benefits of the National Grid 14 NEES merger. Therefore, a portion of the savings should be used to compensate National 15 Grid for its investment in NEES. 16 17 VII. Future Earnings Reports. 18 Q. How would the Company propose to treat the acquisition premiums for earnings report 19 purposes after the merger? Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 40 of 44 1 A. In order for the Company to assume the risks inherent in a long term rate freeze, the 2 Company needs a clarification from the Commission that the Company's amortization of 3 both the EUA and the National Grid premiums would be taken into account in 4 determining the Company's earnings. The Company requests the Commission provide this 5 clarification in any order it issues approving the rate plan. 6 7 VIII. FAS 71. 8 Q. Does the proposed rate plan have any other potential accounting ramifications? 9 A. Yes. Presently, both NEES and EUA apply Financial Accounting Standard No. 71 10 (FAS 71) to their regulated operations. Pursuant to FAS 71, regulated entities are 11 required to record regulatory assets and liabilities to reflect certain differences between 12 accounting and ratemaking principles. If the NEES-EUA and NEES-National Grid 13 transactions are completed under the rate plan proposed in this docket, 14 Narragansett/BVE/Newport and NEP/Montaup may be required to discontinue use of 15 FAS 71, effective upon consummation of the NEES-National Grid merger. 16 17 Q. Why might these companies be required to discontinue use of FAS 71? 18 A. In order to apply FAS 71, a regulated entity must meet certain criteria, including the 19 criteria that the entity's rates are based on its cost of service. It is my understanding that 20 in interpreting FAS 71, that the accounting profession considers long-term fixed rate plans Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 41 of 44 1 to be inconsistent with the criteria of FAS 71. The implementation of the distribution rate 2 freeze through 2004 may require Narragansett/BVE/Newport to discontinue use of FAS 3 71. In the case of NEP/Montaup, their ability to continue to use FAS 71 for costs being 4 recovered through contract termination charges depends on their continued recovery as 5 part of cost-based rates. Because the underlying distribution companies may no longer 6 qualify to use FAS 71, NEP/Montaup may also be required to discontinue use of FAS 71. 7 8 Q. What impact would the discontinuation of FAS 71 have on the financial statements of 9 NEES's affected subsidiaries including Narragansett? 10 A. There are several principal impacts. First, in establishing the initial balance sheet of 11 Narragansett/BVE/Newport and NEP/Montaup, following the consummation of the 12 mergers, regulatory assets would not be recognized. The impact of not recognizing 13 regulatory assets would be to increase the goodwill account by the amount of the 14 regulatory assets. In addition, because the operation of FAS 71 would be discontinued, 15 future differences between accounting and ratemaking principles would not lead to the 16 creation of regulatory assets and liabilities. 17 18 The discontinuation of FAS 71 could cause other differences in accounting to occur as 19 well. Narragansett/BVE/Newport and NEP/Montaup have traditionally adhered to the 20 accounting rules included in the FERC Uniform System of Accounts, which set of rules Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 42 of 44 1 have been adopted by the Commission with limited exceptions. While those rules are in 2 most cases the same accounting rules followed by unregulated companies, there may be 3 some exceptions. For example, the companies would no longer record AFDC, but would 4 instead record capitalized interest calculated in accordance with accounting standards for 5 unregulated businesses. 6 7 In addition, while we have described previously the amount of goodwill that we expect to 8 be allocated to the companies and the amortization period for such goodwill for 9 ratemaking purposes, those amounts could differ for accounting purposes. 10 11 Q. Would the discontinuation of FAS 71 affect rates? 12 A. No. The recovery of regulatory assets today reflects ratemaking, rather than accounting 13 principles. While goodwill would be increased as a result of discontinuing FAS 71, the 14 definition of the acquisition premium to be recovered through rates would not include 15 goodwill resulting from regulatory assets otherwise being recovered through rates. 16 17 IX. Other Regulatory Approvals. 18 Q. Mr. Jesanis what other regulatory approvals are necessary before the merger of the parent 19 companies, NEES and EUA, can be closed? Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 43 of 44 1 A. Federal approval is required from the SEC under the Holding Company Act and approval 2 by FERC under Section 203 of the Federal Power Act. FERC will also approve the 3 consolidation of NEP and Montaup's transmission rates under Section 205 of the Federal 4 Power Act. Modifications to Montaup's contract termination charge, if required, will also 5 be implemented pursuant to Section 205. A Nuclear Regulatory Commission approval 6 under the Atomic Energy Act, will be required to transfer Montaup's nuclear entitlements 7 to NEP as part of the merger. Approval of state commissions in Connecticut, Vermont, 8 and New Hampshire where Montaup owns property may also be required. The 9 Massachusetts Department of Telecommunications and Energy has direct jurisdiction over 10 the consolidation of the operating companies in Massachusetts as well as a rate plan for 11 the combined companies. The merger has already received clearance from the Federal 12 Trade Commission under the Hart Scott Rodino Act that requires review for potential 13 anti-trust effects of mergers. A copy of the FERC filing was provided to the Commission. 14 Our filing with the SEC will be provided to the Commission when it is made. The other 15 filings will be provided on request. 16 17 Q. Are any other Rhode Island approvals needed for the parent company merger? 18 A. No. The merger of the parent companies does not require any Rhode Island approvals. 19 However, in order for BVE and Newport to be merged into Narragansett, the Companies 20 would need to obtain approval from the Division of Public Utilities and Carriers pursuant Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of M.E. Jesanis Page 44 of 44 1 to Section 39-3-24 of Rhode Island General Laws once the law is clarified that a merger is 2 permissible under that section. 3 4 Q. What is the estimated time schedule for those proceedings? 5 A. We hope to complete all regulatory proceedings on the merger this year and implement 6 the rate plan on April 1, 2000. 7 8 Q. Does this complete your testimony? 9 A. Yes.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibits of Michael E. Jesanis Exhibit MEJ-1 NEES-EUA Merger Agreement Exhibit MEJ-2 NEES-EUA Simplified Corporate Organization, Post-Closing Exhibit MEJ-3 Rate Comparison for BVE, Newport and Narragansett Exhibit MEJ-4 Economic Impact of Rate Plan Exhibit MEJ-5 Economic Impact of Rate Freeze Extensions Exhibit MEJ-6 Illustration of Calculation of Inflation Adjustment to Distribution Rates in 2003 and 2004 Exhibit MEJ-7 Eastern Acquisition Premium and Transaction Cost Amortization Exhibit MEJ-8 Sharing of Savings Following NEES/EUA Merger Exhibit MEJ-9 Present Value Analysis of Acquisition Costs and Savings from NEES-EUA Consolidation Exhibit MEJ-10 Rate Comparison by Utility Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit MEJ-1 Exhibit MEJ-1 NEES-EUA Merger Agreement See Separate Volume Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit MEJ-2 Exhibit MEJ-2 NEES-EUA Simplified Corporate Organization, Post-Closing Exhibit MEJ-2 Simplified Corporate Structure for Regulated Operating Companies (Plan for Full Consolidation) -------------------------------------------------------------------- ----------------- | National Grid | | Group | ----------------- | | | | | | | | -------- ------- | NEES |<- - - - - - - - - - - - - - - - - - - - - | EUA | -------- ------- | | | | | ----------| | | ---------------- ---------------- | | |----|Mass. Electric|< - - - - -|Eastern Edison|------------| | | ---------------- ---------------- | | | | | | | | | - ---------- | | ---------------- ------------ | |Granite | | |----|New England |< - - - - -| Montaup | | | State |-----| | | Power | ------------ | |Electric| | ---------------- - - - - - - - - - - - - - - | - ---------- | | -------------------- | | | | | Blackstone Valley |-|-----| | ---------------- | -------------------- | | |----|Narragansett |< - - -| | | ---------------- | ------------ | | | | Newport |----------|-----| | ------------ | - - - - - - - - - - - - - -
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No.______ Exhibit MEJ-3 Page 1 of 7 Narragansett Electric Company Blackstone Valley Company and Newport Electric Corporation Effect on Individual Billing Components at Rate Merger Narraganset Blackstone Newport ----------- ---------- ------- DISTRIBUTION WITHOUT MERGER (1) Average Rate (Exhibit JMM-2, Column 1, Line 1) 2.967 3.003 4.189 (2) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ----- ----- --- (3) Revenue (Line (1) * Line (2) * 10,000) $153,245,550 $ 39,939,900 $ 22,788,160 - ---------------------------------------------------------------------------------------------------------------- DISTRIBUTION WITH MERGER (4) Average Rate (Exhibit JMM-2, Column 2, Line 1) 2.967 2.852 3.568 (5) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ---- ----- --- (6) Revenue (Line (4) * Line (5) * 10,000) $153,245,550 $ 37,931,600 $ 19,409,920 - ---------------------------------------------------------------------------------------------------------------- (7) BENEFIT TO TOTAL CUSTOMERS (LINE (3) + LINE (6)) $0 $2,008,300 $ 3,378,240 -- - ---------------------------------------------------------------------------------------------------------------- TRANSMISSION WITHOUT MERGER (8) Average Rate (Exhibit JMM-2, Column 1, Line 4) 0.466 0.278 0.273 (9) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ----- ----- --- (10) Revenue (Line (8) * Line (*8) * 10,000) $ 24,068,900 $ 3,697,400 $ 1,485,120 - ---------------------------------------------------------------------------------------------------------------- TRANSMISSION WITH MERGER (11) Average Rate (Exhibit JMM-2, Column 2, Line 4) 0.466 0.278 0.273 (12) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ----- ----- --- (13) Revenue (Line (11) * Line (12) * 10,000) $ 24,068,900 $ 3,697,400 $ 1,485,120 - ---------------------------------------------------------------------------------------------------------------- (14) BENEFIT TO TOTAL CUSTOMERS (LINE (10) + LINE (13) $0 $0 $0 - ---------------------------------------------------------------------------------------------------------------- TRANSITION WITHOUT MERGER (15) Average Rate (Exhibit JMM-2, Column 1, Line 5) 1.150 2.320 2.340 (16) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75 5,165 1,330 544 ----- ----- --- (17) Revenue (Line (15) * Line (16) * 10,000) $ 59,397,500 $ 30,856,000 $ 12,729,600 - ---------------------------------------------------------------------------------------------------------------- TRANSITION WITH MERGER (18) Average Rate (Exhibit JMM-2, Column 2, Line 5) 1.150 2.320 2.340 (19) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ----- ----- ----- (20) Revenue (Line (18) * Line (19) * 10,000) $ 59,397,500 $ 30,856,000 $ 12,729,600 - ---------------------------------------------------------------------------------------------------------------- (21) BENEFIT TO TOTAL CUSTOMERS (LINE (17) + LINE (20) $0 $0 $0 - ---------------------------------------------------------------------------------------------------------------- (22) TOTAL BENEFIT (COST) TO CUSTOMERS (LINE (7)+LINE (14) +LINE (21)) $0 $ 2,008,300 $ 3,378,240 (23) TOTAL RETAIL DELIVERY RATE W/O MERGER (INCL. .230(CENT)DSM) 4.813 5,831 7.032 (24) TOTAL RETAIL DELIVERY RATE W/MERGER (INCL. .230(CENT)DSM) 4.813 5.680 6.411 (25) % BENEFIT (COST) TO CUSTOMERS 0.00% 2.59% 8.83% - ---------------------------------------------------------------------------------------------------------------- Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No.______ Exhibit MEJ-3 Page 2 of 7 DISTRIBUTION 2000 (1) Average Rate (Exhibit JMM-2, Column 2, Line 1) 2.967 2.852 3.568 (2) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ----- ----- --- (3) Revenue (Line (1) * Line (2) * 10,000) $ 153,245,550 $ 37,931,600 $ 19,409,920 - ---------------------------------------------------------------------------------------------------------------- DISTRIBUTION 2001 (4) Average Rate (Exhibit JMM-2, Column 3, Line 1 and Line (1a)) 3.006 2.891 3.607 (5) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ----- ----- --- (6) Revenue (Line (4) * Line (5) * 10,000) $ 155,259,900 $ 38,450,300 $ 19,622,080 - ---------------------------------------------------------------------------------------------------------------- (7) BENEFIT TO TOTAL CUSTOMERS (LINE (3) + LINE (6)) ($2,014,350) ($518,700) ($212,160) - ---------------------------------------------------------------------------------------------------------------- TRANSMISSION 2000 (8) Average Rate (Exhibit JMM-2, Column 2, Line 4) 0.466 0.278 0.273 (9) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ----- ----- --- (10) Revenue (Line (8) * Line (8) * 10,000) $ 24,068,900 $ 3,697,400 $ 1,485,120 - ---------------------------------------------------------------------------------------------------------------- TRANSMISSION 2001 (11) Average Rate (Exhibit JMM-2, Column 3, Line 4) 0.409 0.429 0.431 (12) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ----- ----- --- (13) Revenue (Line (11) * Line (12) * 10,000) $ 21,124,850 $ 5,705,700 $ 2,344,640 - ---------------------------------------------------------------------------------------------------------------- (14) BENEFIT TO TOTAL CUSTOMERS (LINE (10) + LINE (13) $ 2,944,050 ($2,008,300) ($859,520) - ---------------------------------------------------------------------------------------------------------------- TRANSITION 2000 (15) Average Rate (Exhibit JMM-2, Column 2, Line 5) 1.150 2.320 2.340 (16) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ----- ----- --- (17) Revenue (Line (15) * Line (16) * 10,000) $ 59,397,500 $ 30,856,000 $ 12,729,600 - ---------------------------------------------------------------------------------------------------------------- TRANSITION 2001 (18) Average Rate (Exhibit JMM-2, Column 3, Line 5) 1.150 1.759 1.759 (19) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544 ----- ----- --- (20) Revenue (Line (18) * Line (19) * 10,000) $ 59,397,500 $ 23,394,700 $ 9,568,960 - ---------------------------------------------------------------------------------------------------------------- (21) BENEFIT TO TOTAL CUSTOMERS (LINE 917) + LINE (20)) $0 $ 7,461,300 $ 3,160,640 - ---------------------------------------------------------------------------------------------------------------- (22) TOTAL BENEFIT (COST) TO CUSTOMERS (LINE (7)+LINE (14) +LINE (21)) $ 929,700 $ 4,934,300 $ 2,088,960 (23) TOTAL RETAIL DELIVERY RATE W/O MERGER (INCL. .230(CENT)DSM) 4.813 5.680 6.411 (24) TOTAL RETAIL DELIVERY RATE W MERGER (INCL. .230(CENT)DSM) 4.795 5.309 6.027 (25) % BENEFIT (COST) TO CUSTOMERS 0.37% 6.53% 5.99%
Average Delivery Costs in Rhode Island Pre Rate Plan 2000 and Post Rate Plan 2000 Exhibit MEJ-3 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Pre and Post Rate Plans for Narragansett, Blackstone Valley and Newport. Y-axis (left side of chart): Cents per kWh(listed in increments of 1.0 cent between and including 0.0 and 8.0 cents per kWh). [Bar Chart lists four sets of rates for each of Narragansett, Blackstone Valley and Newport: (i) distribution, (ii) transmission, (iii) transition, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total Narragansett: Pre Rate Plan 3.197 0.466 1.150 4.813 Post Rate Plan 3.197 0.466 1.150 4.813 Blackstone Valley: Pre Rate Plan 3.233 0.278 2.320 5.831 Post Rate Plan 3.082 0.278 2.320 5.680 Newport: Pre Rate Plan 4.419 0.273 2.340 7.032 Post Rate Plan 3.798 0.273 2.340 6.411
[NEES Logo] Page 3 of 7 Average Delivery Costs in Rhode Island Post Rate Plan 2000 and 2001 Exhibit MEJ-3 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Post Rate Plan 2000 and 2001 for Narragansett, Blackstone Valley and Newport. Y-axis (left side of chart): Cents per kWh(listed in increments of 1.0 cent between and including 0.0 and 8.0 cents per kWh). [Bar Chart lists four sets of rates for each of Narragansett, Blackstone Valley and Newport: (i) distribution, (ii) transmission, (iii) transition, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total Narragansett: 2000 3.197 0.466 1.150 4.813 2001 3.236 0.409 1.150 4.795 Blackstone Valley: 2000 3.082 0.278 2.320 5.680 2001 3.121 0.429 1.759 5.309 Newport: 2000 3.798 0.273 2.340 6.411 2001 3.837 0.431 1.759 6.027
[NEES Logo] Page 4 of 7 Average Delivery Costs for Blackstone Valley Exhibit MEJ-3 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Average delivery costs for Blackstone Valley at Jan. 2000, Apr. 2000, 2001, 2002, 2003 and 2004. Y-axis (left side of chart): Cents per kWh(listed in increments of 1.0 cent between and including 0.0 and 8.0 cents per kWh). [Bar Chart lists four sets of rates for Blackstone Valley: (i) distribution, (ii) transmission, (iii) transition, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Date Distribution Transmission Transition Total Jan. 2000 3.233 0.278 2.320 5.831 Apr. 2000 3.082 0.278 2.320 5.680 2001 3.121 0.429 1.759 5.309 2002 3.121 0.429 1.859 5.409 2003 3.121 0.429 1.446 4.996 2004 3.121 0.429 1.298 4.848
[NEES Logo] Page 5 of 7 Average Delivery Costs for Narragansett Exhibit MEJ-3 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Average delivery costs for Narragansett at Jan. 2000, Apr. 2000, 2001, 2002, 2003 and 2004. Y-axis (left side of chart): Cents per kWh(listed in increments of 1.0 cent between and including 0.0 and 8.0 cents per kWh). [Bar Chart lists four sets of rates for Narragansett: (i) distribution, (ii) transmission, (iii) transition, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Date Distribution Transmission Transition Total Jan. 2000 3.197 0.466 1.150 4.813 Apr. 2000 3.197 0.466 1.150 4.813 2001 3.236 0.409 1.150 4.795 2002 3.236 0.409 1.150 4.795 2003 3.236 0.409 1.150 4.795 2004 3.236 0.409 1.150 4.795
[NEES Logo] Page 6 of 7 Average Delivery Costs for Newport Exhibit MEJ-3 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Average delivery costs for Newport at Jan. 2000, Apr. 2000, 2001, 2002, 2003 and 2004. Y-axis (left side of chart): Cents per kWh(listed in increments of 1.0 cent between and including 0.0 and 8.0 cents per kWh). [Bar Chart lists four sets of rates for Newport: (i) distribution, (ii) transmission, (iii) transition, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Date Distribution Transmission Transition Total Jan. 2000 4.419 0.273 2.340 7.032 Apr. 2000 3.798 0.273 2.340 6.411 2001 3.837 0.431 1.759 6.027 2002 3.837 0.431 1.859 6.127 2003 3.837 0.431 1.446 5.714 2004 3.837 0.431 1.298 5.566
[NEES Logo] Page 7 of 7 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit MEJ-4 Exhibit MEJ-4 Economic Impact of Rate Plan
C:\123data\JAMES\M&A\BASE\Mej-3.wk4 Narragansett Electric 4YR_TOTAL BVE/Newport Electric 19-May-99 R.I.P.U.C. Docket No. _______ Exhibit MEJ-4 Page 1 of 4 Narragansett Electric Company Blackstone Valley Electric Company and Newport Electric Corporation Total Combined Effect of Retail Delivery Service Billings With a Four Year Distribution Rate Freeze 2000 2001 2002 2003 2004 Cumulative Increase/(Decrease): (1) Blackstone Valley Electric Company ($1,506,225) ($4,685,052) ($6,060,292) ($9,336,185) ($11,984,285) (2) Newport Electric Corporation ($2,533,680) ($4,656,091) ($5,341,282) ($6,876,463) ($8,153,143) (3) Narragansett Electric Company $0 ($1,606,730) ($4,604,160) ($5,076,480) ($6,748,560) (4) Combined Comany ($4,039,905) ($10,947,872) ($16,005,734) ($21,289,129) ($26,885,988) ($79,168,628) (5) Cumulative Effect ($4,039,905) ($14,987,777) ($30,993,511) ($52,282,640) ($79,168,628) - ---------------------------------------------------------------------------------------------------------------------------------- (1) Page 1, Line (6) (2) Page 2, Line (6) (3) Lage 3, Line (6) (4) Line (1) + Line (2) + Line (3) (5) Accumulation of Line (4)
C:\123data\JAMES\M&A\BASE\Mej-3.wk4 Narragansett Electric 4YR_BVE SAVING BVE/Newport Electric 19-May-99 R.I.P.U.C. Docket No. _______ Exhibit MEJ-4 Page 2 of 4 Blackstone Valley Electric Company Estimated Reduction in Retail Delivery Service Billings With a Four Year Distribution Rate Freeze 2000 2001 2002 2003 2004 Cumulative Average Retail Delivery Rate - (1) With Merger on April 1, 2000 5.680 5.309 5.409 4.996 4.848 (2) Assuming No Merger 5.831 5.657 5.855 5.674 5.704 (3) cents/kWh Reduction in Retail Delivery Rate (0.151) (0.348) (0.446) (0.678) (0.856) (4) % Reduction in Retail Delivery Rate -2.6% -6.2% -7.6% -11.9% -15.0% (5) Forecasted MWh Sales 997,500 1,346,024 1,360,074 1,377,851 1,399,848 (6) $ Reduction in Retail Delivery Rate ($1,506,225) ($4,685,052) ($6,060,292) ($9,336,185) ($11,984,285) ($33,572,039) (7) Cumulative Reduction ($1,506,225) ($6,191,277) ($12,251,569) ($21,587,754) ($33,572,039) - ---------------------------------------------------------------------------------------------------------------------------------- (1) Exhibit JMM - 2, Page 2, Line (6) (2) Exhibit JMM - 2, Page 2, January 1, 2000, Line (1) (inflated at 2.2% per year) + Line (2) + Line (4) + Transition Charge from BVE RVC filing (3) Line (1) - Line (2) (4) Line (3)/Line (2) (5) Forecast (from CTC filings) (6) Line (3) x Line (5) (7) Accumulation of Line (6)
C:\123data\JAMES\M&A\BASE\Mej-3.wk4 Narragansett Electric 4YR_NECO SAVING BVE/Newport Electric 19-May-99 R.I.P.U.C. Docket No. _______ Exhibit MEJ-4 Page 3 of 4 Narragansett Electric Company Estimated Increase in Retail Delivery Service Billings With a Four Year Distribution Rate Freeze 2000 2001 2002 2003 2004 Cumulative Average Retail Delivery Rate - (1) With Merger on April 1, 2000 4.813 4.795 4.795 4.795 4.795 (2) Assuming No Merger 4.813 4.826 4.883 4.891 4.921 (3) cents/kWh Reduction in Retail Delivery Rate 0.000 (0.031) (0.088) (0.096) (0.126) (4) % Reduction in Retail Delivery Rate 0.0% -0.6% -1.8% -2.0% -2.6% (5) Forecasted MWh Sales 3,873,750 5,183,000 5,232,000 5,288,000 5,356,000 (6) $ Reduction in Retail Delivery Rate $0 ($1,606,730) ($4,604,160) ($5,076,480) ($6,748,560) ($18,035,930) (7) Cumulative Reduction $0 ($1,606,730) ($6,210,890) ($11,287,370) ($18,035,930) - ---------------------------------------------------------------------------------------------------------------------------------- (1) Exhibit JMM - 2, Page 2, Line (6) (2) Exhibit JMM - 2, Page 2, January 1, 2000, Line (1) (inflated at 2.2% per year) + Line (2) + Line (4) + Transition Charge from Narr. RVC filing + Cost of Removal Adjustment (Narragansett only) of 0.068 cents/kWh starting in 2001 (3) Line (1) - Line (2) (4) Line (3)/Line (2) (5) Forecast (from CTC filings) (6) Line (3) x Line (5) (7) Accumulation of Line (6)
C:\123data\JAMES\M&A\BASE\Mej-3.wk4 Narragansett Electric 4YR_NEW SAVINGS BVE/Newport Electric 19-May-99 R.I.P.U.C. Docket No. _______ Exhibit MEJ-4 Page 4 of 4 Newport Electric Corporation Estimated Reduction in Retail Delivery Service Billings With a Four Year Distribution Rate Freeze 2000 2001 2002 2003 2004 Cumulative Average Retail Delivery Rate - (1) With Merger on April 1, 2000 6.411 6.027 6.127 5.714 5.566 (2) Assuming No Merger 7.032 6.874 7.088 6.935 6.993 (3) cents/kWh Reduction in Retail Delivery Rate (0.621) (0.847) (0.961) (1.221) (1.427) (4) % Reduction in Retail Delivery Rate -8.8% -12.3% -13.6% -17.6% -20.4% (5) Forecasted MWh Sales 408,000 549,613 555,606 563,367 571,358 (6) $ Reduction in Retail Delivery Rate ($2,533,680) ($4,656,091) ($5,341,282) ($6,876,463) ($8,153,143) ($27,560,659) (7) Cumulative Reduction ($2,533,680) ($7,189,771) ($12,531,053) ($19,407,516) ($27,560,659) - ---------------------------------------------------------------------------------------------------------------------------------- (1) Exhibit JMM - 2, Page 4, Line (6) (2) Exhibit JMM - 2, Page 4, January 1, 2000, Line (1) (inflated at 2.2% per year) + Line (2) + Line (4) + Transition Charge from NEC RVC filing (3) Line (1) - Line (2) (4) Line (3)/Line (2) (5) Forecast (from CTC filings) (6) Line (3) x Line (5) (7) Accumulation of Line (6)
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit MEJ-5 Exhibit MEJ-5 Economic Impact of Rate Freeze Extensions
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. ___________ Exhibit MEJ-5 Page 1 of 3 Narragansett Electric Company Blackstone Valley Company and Newport Electric Corporation Estimated Value of Four Year Distribution Rate Freeze DISTRIBUTION WITHOUT MERGER 2000 2001 2002 2003 2004 ---- ---- ---- ---- ---- TOTAL OF INDIVIDUAL COMPANIES (1) Total Revenue $157,940,303 $216,670,421 $223,630,624 $231,183,289 $239,506,709 $1,068,931,347 (2) Cumulative Total Revenue $157,940,303 $374,610,724 $598,241,348 $829,424,638 $1,068,931,347 DISTRIBUTION WITH MERGER TOTAL OF INDIVIDUAL COMPANIES (3) Total Revenue $157,940,303 $212,005,610 $214,108,480 $216,568,800 $219,534,920 $1,020,158,113 (4) Cumulative Total Revenue $157,940,303 $369,945,913 $584,054,393 $800,623,193 $1,020,158,113 BENEFIT TO ALL CUSTOMERS (5) Annual $0 $4,664,811 $9,522,144 $14,614,489 $19,971,789 $48,773,235 (6) Cumulative $0 $4,664,811 $14,186,959 $28,801,445 $48,773,235
(1) Page 3, Line (13) (2) Page 3, Line (14) (3) Page 2, Line (13 (4) Page 2, Line (14) (5) Line (1) - Line (3) (6) Accumulation of Line (5)
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _________ Exhibit MEJ-5 Page 2 of 3 Narragansett Electric Company Blackstone Valley Company and Newport Electric Corporation Estimated Value of Four Year Distribution Rate Freeze DISTRIBUTION WITHOUT MERGER 2000 2001 2002 2003 2004 ---- ---- ---- ---- ---- NARRAGANSETT ELECTRIC (1) Average Rate 2.967 2.967 2.967 2.967 2.967 (2) Projected GWh Sales 3,874 5,183 5,232 5,288 5,356 ----- ----- ----- ----- ----- (3) Revenue $114,934,163 $153,779,610 $155,233,440 $156,894,960 $158,912,520 $739,754,693 (4) Cumulative Revenue $114,934,163 $268,713,773 $423,947,213 $580,842,173 $739,754,693 BLACKSTONE VALLEY ELECTRIC (5) Average Rate 2.852 2.852 2.852 2.852 2.852 (6) Projected GWh Sales 998 1,346 1,360 1,378 1,400 ---- ----- ----- ----- ------ (7) Revenue $28,448,700 $38,387,920 $38,787,200 $39,300,560 $39,928,000 $184,852,380 (8) Cumulative Revenue $28,448,700 $66,836,620 $105,623,820 $144,924,380 $184,852,380 NEWPORT ELECTRIC (9) Average Rate 3.568 3.568 3.568 3.568 3.568 (10) Projected GWh Sales 408 556 563 571 580 --- --- --- --- --- (11) Revenue $14,557,440 $19,838,080 $20,087,840 $20,373,280 $20,694,400 $95,551,040 (12) Cumulative Revenue $14,557,440 $34,395,520 $54,483,360 $74,856,640 $95,551,040 TOTAL OF INDIVIDUAL COMPANIES (13) Total Revenue $157,940,303 $212,005,610 $214,108,480 $216,568,800 $219,534,920 $1,020,158,113 (14) Cumulative Total Revenue $157,940,303 $369,945,913 $584,054,393 $800,623,193 $1,020,158,113
(1) Exhibit JMM - 2, Page 3, Line (1) (2) Forecast (from CTC filings) (3) Line (1) * Line (2) (4) Accumulation of Line (3) (5) Exhibit JMM - 2, Page 2, Line (1) (6) Forecast (from CTC filings) (7) Line (5) * Line (6) (8) Accumulation of Line (7) (9) Exhibit JMM - 2, Page 4, Line (1) (10) Forecast (from CTC filings) (11) Line (9) * Line (10) (12) Accumulation of Line (11) (13) Line (3) + Line (7) + Line (12) (14) Line (4) + Line (8) + Line (13)
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _________ Exhibit MEJ-5 Page 3 of 3 Narragansett Electric Company Blackstone Valley Company and Newport Electric Corporation Estimated Value of Four Year Distribution Rate Freeze DISTRIBUTION WITHOUT MERGER 2000 2001 2002 2003 2004 ---- ---- ---- ---- ---- NARRAGANSETT ELECTRIC (1) Average Rate (inflation begining in 2001) 2.967 3.032 3.099 2.967 3.237 (2) Projected GWh Sales 3,874 5,183 5,232 5,288 5,356 ----- ----- ----- ----- ----- (3) Revenue $114,934,163 $157,162,761 $162,138,844 $167,479,509 $173,365,109 $775,080,387 (4) Cumulative Revenue $114,934,163 $272,096,924 $434,235,768 $601,715,278 $775,080,387 BLACKSTONE VALLEY ELECTRIC (5) Average Rate (inflation beginning in 2001) 2.852 2.915 2.979 3.045 3.112 (6) Projected GWh Sales 998 1,346 1,360 1,378 1,400 ---- ----- ----- ----- ----- (7) Revenue $28,448,700 $39,235,900 $40,514,400 $41,960,100 $43,568,000 $193,727,100 (8) Cumulative Revenue $28,448,700 $67,684,600 $108,199,000 $150,159,100 $193,727,100 NEWPORT ELECTRIC (9) Average Rate (inflation beginning in 2001) 3.568 3.646 3.726 3.808 3.892 (10) Projected GWh Sales 408 556 563 571 580 --- --- --- --- --- (11) Revenue $14,557,440 $20,271,760 $20,977,380 $21,743,680 $22,573,600 $100,123,860 (12) Cumulative Revenue $14,557,440 $34,829,200 $55,806,580 $77,550,260 $100,123,860 TOTAL OF INDIVIDUAL COMPANIES (13) Total Revenue $157,940,303 $216,670,421 $223,630,624 $231,183,289 $239,506,709 $1,068,931,347 (14) Cumulative Total Revenue $157,940,303 $374,610,724 $598,241,348 $829,424,638 $1,068,931,347
(1) Exhibit JMM - 2, Page 3, Line (1), April 1, 2000, inflated at 2.2 percent (2) Forecast (from CTC filings) (3) Line (1) * Line (2) (4) Accumulation of Line (3) (5) Exhibit JMM - 2, Page 2, Line (1), April 1, 2000, inflated at 2.2 percent (6) Forecast (from CTC filings) (7) Line (5) * Line (6) (8) Accumulation of Line (7) (9) Exhibit JMM - 2, Page 4, Line (1), April 1, 2000, inflated at 2.2 percent (10) Forecast (from CTC filings) (11) Line (9) * Line (10) (12) Accumulation of Line (11) (13) Line (3) + Line (7) + Line (12) (14) Line (4) + Line (8) + Line (13) Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit MEJ-6 Exhibit MEJ-6 Illustration of Calculation of Inflation Adjustment to Distribution Rates in 2003 and 2004
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. ________ Exhibit MEJ-6 Page 1 of 1 Narragansett Electric Company Illustration of Calculation Inflation Adjustment to Distribution Rates in 2003 and 2004 3% Annual Annual Benchmark Illustrative Annual CPI Percentage Inflation in 75% of Distribution Distribution End of Month Inflation Index Change Excess of 3% Excess Rate Adjustment ------------ --------- ----- ------ ------------ ------ ---- ---------- (1) (2) (3) (4) (5) (6) (7) (8) September 2001 136.6 2/ September 2002 140.9 2/ Annual Total 3.000% 1/ 3.148% 3/ 0.148% 4/ 0.111% 5/ 2.993 6/ 0.003 7/ September 2002 140.9 2/ September 2003 144.8 2/ Annual Total 3.000% 1/ 2.768 3/ n/a 2.996 8/ n/a
- ----------------------------------------------------------------------------- 1/ Annual rate of 3% for inflation benchmark 2/ Historical Consumer Price Index - All Urban Consumers (CPI-U) obtained from the Bureau of Labor Statistics 3/ Percentage change between prior month's CPI-U and current month's CPI-U 4/ Difference between actual inflation (3/) and assumed inflation benchmark of 3% (1/) 5/ 75% x excess inflation in 4/ 6/ Exhibit JMM-2, Page 1, April 1, 2000, Line (1) 7/ 75% of excess inflation in 5/ multiplied by benchmark distribution rate in 6/ 8/ Prior year net distribution charge (6/) + (7/) as current year's distribution benchmark Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit MEJ-7 Exhibit MEJ-7 Eastern Acquisition Premium and Transaction Cost Amortization
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. ________ Exhibit MEJ-7 Page 1 of 3 NEES/EUA Acquisition Premium Amortization of Acquisition Premium and Transaction Costs In Thousands of Dollars Illustrative Calculation pending completion of Acquisition Premium Allocation Study Allocation to States 12/ ------------------------------- Massachusetts Rhode Island Total (Eastern Edison) 1 ACQUISITION PREMIUMS: 100.00% 73.91% 26.09% --------------------- ------- ------ ------ 2 Total Acquisition Premium 1/ $260,000 3 Less: Allocation to Unregulated Subsidiaries 2/ 28,600 ------- 4 Net Acquisition Premium to Regulated Subsidiaries 3/ $231,400 $171,028 $60,372 5 6 Times Tax Gross-Up Factor 4/ 1.6454 1.5384 ------ ------ 7 8 Acquisition Premium at Revenue Requirement 5/ $374,285 $281,409 $92,876 9 10 Amortization Period (Years) 6/ 20 20 20 11 12 Amortization per year for Acquisition Premiums 7/ $18,714 $14,070 $4,644 ------- ------- ------ 13 14 15 TRANSACTION COSTS: 16 Total Estimated Transaction Costs 8/ $63,600 $47,007 $16,593 17 18 Amortization Period (Years) 9/ 20 20 20 19 20 Amortization per year for Transaction Costs 10/ $3,180 $2,351 $829 ------ ------ ---- 21 22 TOTAL AMORTIZATION PER YEAR 11/ $21,894 $16,421 $5,473 ------- ------- ------
Notes: 1/ Exhibit MEJ-7, Page 3, Line 15. 2/ Allocation of costs to unregulated subsidiaries. (Exhibit MEJ-7, Page 3, Line 35 times Line 2.) 3/ Line 1 minus Line 2. 4/ For Massachusetts: 1 plus Federal Income Tax (FIT) Rate divided by 1 minus FIT rate plus State Income Tax (SIT) rate divided by 1 minus SIT rate divided by 1 minus FIT rate (1+(35%/(1-35%))+((6.5%/(1-6.5%)/(1-35%))). For Rhode Island: 1 plus Federal Income Tax (FIT) Rate divided by 1 minus FIT rate. (1+(35%/(1-35%))). 5/ Line 4 times Line 6. 6/ Proposed amortization period for Acquisition Premiums 7/ Line 8 divided by Line 10. 8/ Total Estimated Transaction costs to complete NEES/EUA merger. 9/ Proposed amortization period for Transaction Costs. 10/ Line16 divided by Line 18. 11/ Line 12 plus Line 20. 12/ Exhibit MEJ-7, Page 2, Column (f).
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. ____ Exhibit MEJ-7 Page 2 of 3 NEES/EUA Acquisition Premium Allocation of Acquisition Premium and Transaction Costs Illustrative Calculation pending completion of Acquisition Premium Allocation Study 1998 1997 1996 Total 3 Year Ave. MWh Sales MWh Sales MWh Sales MWh Sales MWh Sales Allocation to Ultimates to Ultimates to Ultimates to Ultimates to Ultimates Percentage Column (a) 1/ Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/ ------------- ------------- ------------- ------------- ------------- ------------- 1 Massachusetts Electric 16,590,946 16,141,173 16,009,209 48,741,328 2 Eastern Edison 2,707,973 2,641,448 2,622,517 7,971,938 --------- --------- --------- --------- 3 Total Massachusetts 19,298,919 18,782,621 18,631,726 56,713,266 18,904,422 73.91% ---------- ---------- ---------- ---------- 4 5 Narragansett Electric 4,977,637 4,822,669 4,778,027 14,578,333 6 Blackstone Valley Electric 1,290,871 1,289,116 1,256,978 3,836,965 7 Newport Electric 542,466 536,209 525,372 1,604,047 ------- ------- ------- --------- 8 Total Rhode Island 6,810,974 6,647,994 6,560,377 20,019,345 6,673,115 26.09% --------- --------- --------- ---------- --------- ------ 9 Grand Total 26,109,893 25,430,615 25,192,103 76,732,611 25,577,537 100.00% ---------- ---------- ---------- ---------- ---------- -------
Notes: 1/ 1998 FERC Form 1, Pages 300-301. 2/ 1997 FERC Form 1, Pages 300-301. 3/ 1996 FERC Form 1, Pages 300-301. 4/ Sum of Columns (a) through (c). 5/ Column (d) divided by three. 6/ Ratio of Average MWh Sales to Total MWh Sales (Column (e)). Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. ____ Exhibit MEJ-7 Page 3 of 3 NEES/EUA Acquisition Premium Amortization of Acquisition Premium and Transaction Costs In Thousands of Dollars Illustrative Calculation pending completion of Acquisition Premium Allocation Study 1 CALCULATION OF ACQUISITION PREMIUM: 2 Acquisition Price Per Share $31.00 1/ 3 4 Outstanding EUA Common Shares 5 as of December 31, 1998 20,435,997 2/ ---------- 6 7 Total Acquisition Cost $633,516 3/ 8 9 10 EUA Consolidated Net Book Value 11 as of December 31, 1998 $373,674 4/ ---------- 12 13 Total Acquisition Premium $259,842 5/ 14 15 Total Acquisition Premium (Rounded) $260,000 6/ ---------- 16 17 18 CALCULATION OF ALLOCATION TO UNREGULATED SUBSIDIARIES: 19 20 Net Book Value of Unregulated Subsidiaries as of 21 December 31, 1998: 22 23 EUA Cogenex $48,361 24 EUA Energy Inv. (24,204) 25 EUA Energy Services (34) 26 EUA Ocean State 16,546 27 EUA Telecommunications (131) ----- 28 Total Net Book Value of Unregulated Subsidiaries 40,538 7/ ------ 29 30 Net Book Value of EUA Consolidated 31 as of December 31, 1998 (In Thousands) 373,674 8/ 32 33 Percentage of Unregulated Subsidiaries to Total 10.85% 9/ 34 35 Percentage (Rounded) 11.00% 10/ Notes: 1/ Acquisition Price per Share per NEES/EUA Merger Agreement. 2/ EUA common shares outstanding as of December 31, 1998 per EUA annual report. 3/ Line 2 times Line 5. 4/ Net Book Value (Common Equity) as of December 31, 1998 per EUA annual report before any adjustments required under purchase accounting rules. 5/ Line 7 minus Line 11. 6/ Line 13 rounded to tens of millions. 7/ Net Book Value (Common Equity) as of December 31, 1998 before any adjustments required under purchase accounting rules. 8/ Net Book Value (Common Equity) as of December 31, 1998 before any adjustments required under purchase accounting rules. 9/ Line 28 divided by Line 31. 10/ Line 33 rounded to nearest whole percent. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit MEJ-8 Exhibit MEJ-8 Sharing of Savings Following NEES/EUA Merger
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. __________ Exhibit MEJ-8 Page 1 of 1 NEES/EUA ACQUISITION PREMIUM Sharing of Savings following NEES/EUA Merger In Thousands of Dollars Illustrative Calculation pending completion of Acquisition Premium Allocation Study Rhode Island Apportionment Rhode Island of EUA Sharing of Net Savings Anticipated Apportionment Acquisition Rhode Island National Grid Rhode Island Savings (25.39%) Premium Recovery Net Savings Premium Customers Year Column (a) 1/ Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/ ------------- ------------- ---------------- ------------- ------------- ------------- 1 2005 $35,000 $ 8,887 $5,473 $ 3,414 $1,707 $1,707 2 2006 35,770 9,082 5,473 3,609 1,804 1,805 3 2007 36,557 9,282 5,473 3,809 1,905 1,904 4 2008 37,361 9,486 5,473 4,013 2,006 2,007 5 2009 38,183 9,695 5,473 4,222 2,111 2,111 6 2010 39,023 9,908 5,473 4,435 2,218 2,217 7 2011 39,882 10,126 5,473 4,653 2,326 2,327 8 2012 40,759 10,349 5,473 4,876 2,438 2,438 9 2013 41,656 10,576 5,473 5,103 2,552 2,551 10 2014 42,572 10,809 5,473 5,336 2,668 2,668 11 2015 43,509 11,047 5,473 5,574 2,787 2,787 12 2016 44,466 11,290 5,473 5,817 2,908 2,909 13 2017 45,444 11,538 5,473 6,065 3,033 3,032 14 2018 46,444 11,792 5,473 6,319 3,159 3,160 15 2019 47,466 12,052 5,473 6,579 3,290 3,289 16 2020 48,510 12,317 5,473 6,844 3,422 3,422 17 2021 and beyond 49,577 12,588 0 12,588 6,294 7/ 6,294 7/
Notes: 1/ Anticipated Savings from NEES/EUA Merger in 2005 dollars escalated by inflation of 2.2% per year. 2/ Column (a) times Rhode Island Savings Apportionment factor. (Exhibit MEJ-9, Page 2, Line 3, column (f)). 3/ Exhibit MEJ-7, Page 1, Line 22. 4/ Column (b) minus Column (c). 5/ Proposed Merger Savings Sharing (Column (d) times 50%). 6/ Column (d) minus Column (e). 7/ Increases by inflation beginning in 2021. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit MEJ-9 Exhibit MEJ-9 Present Value Analysis of Acquisition Costs and Savings from NEES-EUA Consolidation
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Exhibit MEJ-9 Page 1 of 2 NEES/EUA Acquisition Premium Net Present Value of Estimated Savings and Acquisition Premium In Thousands of Dollars Illustrative Calculation pending completion of Acquisition Premium Allocation Study Allocation to States 15/ ------------------------------------------------ Massachusetts Rhode Island New Hampshire Total (Eastern Edison) 1 NET PRESENT VALUE OF MEREER SAVINES: 100.00% 71.93% 25.39% 2.68% -------- -------- -------- -------- 2 Estimated Annual Savings 1/ $ 30,716 $ 22,094 $ 7,799 $ 823 3 4 Estimated After Tax Cost of Capital 2/ 7.50% 7.50% 7.50% 7.50% 5 Less: Estimated Inflation Rate 3/ 2.20% 2.20% 2.20% 2.20% -------- -------- -------- -------- 6 Net Discount Rate 4/ 5.30% 5.30% 5.30% 5.30% 7 8 Net Present Value of Estimated Annual Savings 5/ $579,547 $416,868 $147,151 $ 15,528 -------- -------- -------- -------- 9 10 11 NET PRESENT VALUE OF MERGER COSTS: 12 Annual Amortization of Acquisition Premium 6/ $ 18,714 $ 14,070 $ 4,644 13 14 Net Present Value of Amortization of Acquisition 15 Premiums using 7.50% Discount Rate 7/ $190,780 $143,436 $ 47,343 -------- -------- -------- 16 17 18 Annual Amortization of Transaction Premium 8/ $ 3,180 $ 2,351 $ 829 19 20 Net Present Value of Amortization of Acquisition 21 Premiums using 7.50% Discount Rate 9/ $ 32,418 $ 23,967 $ 8,451 -------- -------- -------- 22 23 Total Net Present Value of Merger Costs 10/ $223,198 $167,403 $ 55,794 -------- -------- -------- 24 25 Net Present Value of Excess Merger Savings 11/ $356,349 $249,465 $ 91,357 $ 15,528 26 27 Sharing of Excess Merger Savings 12/ 50% 50% 50% 50% -------- -------- -------- -------- 28 29 Allocation of Excess Merger Savings to National 30 Grid Acquisition Premium 13/ $178,174 $124,732 $ 45,679 $ 7,764 -------- -------- -------- -------- 31 32 Allocation of Excess Merger Savings to Customers 14/ $178,175 $124,733 $ 45,678 $ 7,764 -------- -------- -------- --------
Notes: 1/ $35 million of estimated savings in 2005 discounted to 1999 dollars by inflation rate of 2.2%. 2/ Estimated after tax cost of capital. 3/ Estimated annual inflation rate. 4/ Line 4 minus Line 5. 5/ Line 2 divided by Line 6. 6/ Exhibit MEJ-7, Page 1, Line 12. 7/ Net Present Value of amortization of Acquisition Premium over 20 years. 8/ Exhibit MEJ-7, Page 1, Line 20. 9/ Net Present Value of amortization of Transaction Costs over 20 years. 10/ Line 15 plus Line 2 1. ll/ Line 8 minus Line 23. 12/ Proposed Sharing of Excess Savings between customers and shareholders. 13/ Line 25 times Line 27. 14/ Line 25 minus Line 30. 15/ Exhibit MEJ-9, Page 2, Column (f).
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. ________ Exhibit MEJ-9 Page 2 of 2 NEES/EUA Acquisition Premium Allocation of Acquisition Premium and Transaction Costs Illustrative Calculation pending completion of Acquisition Premium Allocation Study 1998 1997 1996 Total 3 Year Ave. MWh Sales MWh Sales MWh Sales MWh Sales MWh Sales Allocation to Ultimates to Ultimates to Ultimates to Ultimates to Ultimates Percentage Column (a) 1/ Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/ ------------- ------------- ------------- ------------- ------------- ------------- 1 Massachusetts Electric 16,590,946 16,141,173 16,009,209 48,741,328 2 Eastern Edison 2,707,973 2,641,448 2,622,517 7,971,938 --------- --------- --------- --------- 3 Total Massachusetts 19,298,919 18,782,621 18,631,726 56,713,266 18,904,422 71.93% ---------- ---------- ---------- ---------- 4 5 Narragansett Electric 4,977,637 4,822,669 4,778,027 14,578,333 6 Blackstone Valley Electric 1,290,871 1,289,116 1,256,978 3,836,965 7 Newport Electric 542,466 536,209 525,372 1,604,047 ------- ------- ------- --------- 8 Total Rhode Island 6,810,974 6,647,994 6,560,377 20,019,345 6,673,115 25.39% --------- --------- --------- ---------- 9 10 Granite State Electric 718,452 693,879 699,569 2,111,900 ------- ------- ------- --------- 11 Total New Hampshire 718,452 693,879 699,569 2,111,900 703,967 2.68% ------- ------- ------- --------- ------- ----- 12 13 Grand Total 26,828,345 26,124,494 25,891,672 78,844,511 26,281,504 100.00% ---------- ---------- ---------- ---------- ---------- -------
Notes: 1/ 1998 FERC Form 1, Pages 300-301. 2/ 1997 FERC Form 1, Pages 300-301. 3/ 1996 FERC Form 1, Pages 300-301. 4/ Sum of Columns (a) through (c). 5/ Column (d) divided by three. 6/ Ratio of Average MWh Sales to Total MWh Sales (Column (e)). Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit MEJ-10 Exhibit MEJ-10 Rate Comparison by Utility Comparison of Rhode Island and Massachusetts "Delivery" Rates Residential Customer (500 kWh Usage) (Cents per kWh) Exhibit MEJ-10 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Rhode Island and Massachusetts utilities. Y-axis (left side of chart): Cents per kWh charged to residential customers (listed in increments of 2.0 cents between and including 0.0 and 10.0 cents per kWh). [Bar Chart lists four sets of rates for each of ten Rhode Island and Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii) transition rates, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total MECO 4.1 0.7 1.3 6.1 NECO 4.4 0.5 1.2 6.1 EECO 4.2 0.3 2.1 6.6 Camb 4.0 1.3 1.4 6.7 BVE 4.7 0.3 2.0 7.0 Newport 5.5 0.3 2.1 7.8 WMeco* 5.1 0.3 2.8 8.2 FG&E* 5.4 0.5 2.5 8.4 BECO 5.6 0.3 2.8 8.7 Comm 5.5 0.4 3.2 9.1
[NEES Logo] (*) Rates do not include any adjustment reflecting divestiture. Based on rates as of May 1, 1999. Page 1 of 5 Comparison of Rhode Island and Massachusetts "Delivery" Rates Average G-1 Customer (6 kW Demand and 1,500 kWh Usage) (Cents per kWh) Exhibit MEJ-10 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Rhode Island and Massachusetts utilities. Y-axis (left side of chart): Cents per kWh charged to average G-1 customers (listed in increments of 2.0 cents between and including 0.0 and 10.0 cents per kWh). [Bar Chart lists four sets of rates for each of ten Rhode Island and Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii) transition rates, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total Camb 2.6 1.2 1.4 5.2 NECO 4.5 0.6 1.2 6.3 MECO 4.8 0.7 1.3 6.8 BVE 4.8 0.3 2.0 7.1 EECO 4.8 0.3 2.1 7.2 Comm 4.3 0.4 3.2 7.8 WMeco* 4.8 0.3 2.8 7.9 FG&E* 5.5 0.5 2.4 8.4 Newport 6.3 0.3 2.1 8.6 BECO 5.8 0.4 2.7 8.9
[NEES Logo] (*) Rates do not include any adjustment reflecting divestiture. Based on rates as of May 1, 1999. Page 2 of 5 Comparison of Rhode Island and Massachusetts "Delivery" Rates Average G-2 Customer (50 kW Demand and 16,700 kWh Usage) (Cents per kWh) Exhibit MEJ-10 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Rhode Island and Massachusetts utilities. Y-axis (left side of chart): Cents per kWh charged to average G-2 customers (listed in increments of 2.0 cents between and including 0.0 and 8.0 cents per kWh). [Bar Chart lists four sets of rates for each of ten Rhode Island and Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii) transition rates, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total MECO 2.4 0.6 1.3 4.4 NECO 2.6 0.4 1.2 4.2 Camb 2.1 1.1 1.4 4.5 EECO 2.7 0.3 1.8 4.8 BVE 3.0 0.3 2.0 5.3 WMeco* 3.0 0.3 2.8 6.1 Newport 4.2 0.3 2.1 6.5 FG&E* 4.2 0.4 2.2 6.8 BECO 4.3 0.4 2.4 7.1 Comm 3.8 0.4 3.2 7.3
[NEES Logo] (*) Rates do not include any adjustment reflecting divestiture. Based on rates as of May 1, 1999. Page 3 of 5 Comparison of Rhode Island and Massachusetts "Delivery" Rates Average G-3 Customer (610 kW Demand and 255,400 kWh Usage) (Cents per kWh) Exhibit MEJ-10 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Rhode Island and Massachusetts utilities. Y-axis (left side of chart): Cents per kWh charged to average G-3 customers (listed in increments of 1.0 cent between and including 0.0 and 7.0 cents per kWh). [Bar Chart lists four sets of rates for each of ten Rhode Island and Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii) transition rates, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total NECO 1.9 0.4 1.2 3.4 MECO 1.8 0.6 1.3 3.7 Camb 1.2 1.2 1.4 3.8 EECO 1.8 0.3 2.2 4.3 BVE 2.2 0.3 2.0 4.5 Comm 1.4 0.3 3.2 4.9 FG&E* 3.1 0.4 1.7 5.2 WMeco* 2.1 0.3 2.9 5.3 BECO 2.3 0.3 2.8 5.4 Newport 4.2 0.3 2.1 6.5
[NEES Logo] (*) Rates do not include any adjustment reflecting divestiture. Based on rates as of May 1, 1999. Page 4 of 5 Comparison of Rhode Island and Massachusetts "Delivery" Rates Very Large C&I Customer (5,000 kW Demand and 2,000,000 kWh Usage) (Cents per kWh) Exhibit MEJ-10 [Vertical, Stacked Bar Chart] X-axis (bottom of chart): Rhode Island and Massachusetts utilities. Y-axis (left side of chart): Cents per kWh charged to very large C&I customers (listed in increments of 1.0 cents between and including 0.0 and 7.0 cents per kWh). [Bar Chart lists four sets of rates for each of ten Rhode Island and Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii) transition rates, and (iv) total rates. Total rates equal the sum of distribution, transmission and transition rates.]
Utility Distribution Transmission Transition Total NECO 1.7 0.4 1.2 3.3 MECO 1.8 0.6 1.3 3.7 BVE 1.7 0.3 2.0 4.0 Camb 1.2 1.4 1.4 4.0 EECO 1.8 0.3 2.2 4.3 Comm 1.1 0.3 3.2 4.7 WMeco* 1.7 0.3 3.0 5.0 FG&E* 3.1 0.4 1.7 5.2 BECO 2.3 0.3 2.8 5.4 Newport 3.7 0.3 2.1 6.0
[NEES Logo] (*) Rates do not include any adjustment reflecting divestiture. Based on rates as of May 1, 1999. Page 5 of 5 THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - ---------------------------------------- ) Narragansett Electric Company ) R.I.P.U.C. No. __________ Blackstone Valley Electric Company ) Newport Electric Corporation ) ) - ---------------------------------------- DIRECT TESTIMONY OF ROBERT G. POWDERLY THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - ---------------------------------------- ) Narragansett Electric Company ) R.I.P.U.C. No. __________ Blackstone Valley Electric Company ) Newport Electric Corporation ) ) - ---------------------------------------- DIRECT TESTIMONY OF ROBERT G. POWDERLY Table of Contents Page I. Qualifications.......................................................1 II. Purpose of Testimony.................................................3 Ill. Terms, Conditions, and Structure of the Transaction..................4 IV. Benefits to Customers, Employees and Shareholders....................8
Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. __________ Testimony of R. G. Powderly Page 1 of 13 1 I. Qualifications. 2 Q. Please state your name and business address. 3 A. My name is Robert G. Powderly and my business address is 750 West Center Street, West 4 Bridgewater, Massachusetts. 5 6 Q. By whom are you employed and in what capacity? 7 A. I am employed by EUA Service Corporation ("EUASC"). I am Executive Vice President 8 of Blackstone Valley Electric Company ("Blackstone"), Eastern Edison Company 9 ("Eastern"), Newport Electric Corporation ("Newport") and Montaup Electric Company 10 (Montaup). Additionally, I hold the same position for Eastern Utilities Associates 11 ("EUA"), the parent company of the above three retail affiliates, and for EUASC, the 12 service company for EUA subsidiaries. My areas of responsibility for regulated companies 13 in the EUA system include Customer Service, Human Resources, Information Systems, 14 and Rates. 15 16 Q. Please summarize your educational background and your professional qualifications. 17 A. I was graduated from the College of the Holy Cross in 1969 with a Bachelor of Arts 18 degree in mathematics. After serving five years in the U. S. Navy, I attended Northeastern 19 University, and received a Master of Science in Accounting degree in 1975. While in the Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 2 of 13 1 Navy, I was involved in the operation of naval nuclear propulsion units and in 1973 I 2 qualified as Engineer of Naval Nuclear Propulsion plants. 3 4 After graduate school, I was employed for almost four years by an international public 5 accounting firm (Ernst & Ernst, now called Ernst & Young). During this period, my 6 responsibilities included audits of publicly-held, regulated, and non-profit organizations. 7 In 1978, I joined EUASC as Audit Supervisor. My responsibilities were to develop and 8 implement a comprehensive audit program for the EUA system companies and to report 9 the results of that program to both management and the Audit Committee of the Board of 10 Trustees. After three years as Audit Supervisor, I was promoted to the position of 11 Manager of System Revenue Requirements. In this position, I was responsible for the 12 detailed coordination and preparation of rate cases for the EUA companies. I participated 13 personally in these cases in various ways, including testifying on matters reflected in the 14 cost of service or preparing cost-of-service adjustments under the direction of company 15 accounting witnesses. Effective August 1, 1985, I was promoted to Assistant Vice 16 President and I assumed responsibilities for special projects in the areas of accounting, 17 taxes, finance, and personnel. On April 15, 1986, I was named Vice President of EUA 18 Service Corporation wherein I assumed responsibility for the EUA Rate and Customer 19 Service Departments. In March 1990, I was elected President of Newport upon its 20 acquisition by EUA. I was responsible for the integration of operations of Newport and Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 3 of 13 1 EUA. In April 1992, I was elected Executive Vice President with EUA system 2 responsibilities of Corporate Communications, Customer Service, Information Systems, 3 and Rates. 4 5 I am a Certified Public Accountant in the Commonwealth of Massachusetts. In addition, I 6 have participated in several professional and utility associations, such as the American 7 Institute of Certified Accountants, the Massachusetts Society of Certified Public 8 Accountants, both the Audit Committee and the Rate Research Committee of the Edison 9 Electric Institute, both the Audit Committee and Energy Management Committee of the 10 Electric Council of New England, and the National Association of Accountants. 11 12 Q. Have you previously testified before any regulatory commission? 13 A. Yes. I have testified before the Rhode Island Public Utilities Commission in general rate 14 cases filed by Blackstone and Newport. I also have testified before the Massachusetts 15 Department of Telecommunications and Energy in Eastern's general rate cases, and 16 presented testimony before the Federal Energy Regulatory Commission on behalf of 17 Montaup, EUA's transmission and generation company. 18 19 II. Purpose of Testimony. 20 Q. What is the purpose of your testimony? Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 4 of 13 1 A. The purpose of my testimony is to explain the benefits of the merger of EUA with the 2 New England Electric System ("NEES") for the customers, employees, and shareholders 3 of the EUA companies. 4 5 III. Terms, Conditions, and Structure of the Transaction. 6 Q. What is the corporate form of EUA? 7 A. EUA is a Massachusetts voluntary association and a registered holding company under the 8 Public Utility Holding Company Act of 1935 ("Holding Company Act"). EUA owns the 9 common equity of three electric companies, Eastern, Blackstone, and Newport. Eastern 10 owns the common equity of Montaup. EUA also owns the common equity of EUASC, 11 the entity that provides nearly all professional, technical, and scientific services to EUA 12 affiliates. EUA owns the common equity of non-regulated subsidiaries, including EUA 13 Cogenex Corporation, EUA Energy Investment Corporation, and EUA Ocean State 14 Corporation. 15 16 Q. Mr. Powderly, would you please summarize the transaction between EUA and NEES? 17 A. Under the merger agreement, EUA shareholders will receive $31.00 for each share held 18 when the acquisition becomes effective. The cash payment will be subject to an increase 19 of $0.003 per share per day if the merger is not completed on or before the date following 20 six months after approval of the merger by EUA's shareholders. The precise structure of Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 5 of 13 1 the transaction will be a merger between Research Drive LLC ("Research Drive"), a 2 Massachusetts limited liability company which is owned by NEES, and EUA. Research 3 Drive will merge with and into EUA, with EUA becoming a wholly-owned subsidiary of 4 NEES. The Agreement and Plan of Merger, dated February 1, 1999, (the "Agreement") 5 contains terms and conditions which are typical of a merger transaction. A condition of 6 closing the merger is obtaining approval of the shareholders of EUA. 7 8 Q. Will the merger affect the corporate structure of the EUA operating companies? 9 A. Yes. At closing, EUA will become a wholly-owned subsidiary of NEES. Thereafter, 10 NEES and EUA plan, as part of this transaction, to merge both the holding companies and 11 to consolidate the underlying operating and service companies. As explained in the 12 testimony of Mr. Jesanis, it is the intention of NEES to have Narragansett Electric 13 Company merge with Blackstone and Newport Eastern. In addition, Eastern will merge 14 with Massachusetts Electric Company, and Montaup with New England Power Company. 15 Finally, EUASC and New England Power Service Company will also be consolidated to 16 lower administrative costs. In each case, the surviving entity will be the existing NEES 17 company. 18 Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 6 of 13 1 Q. Will the merger affect the Commission's jurisdiction over the EUA operating companies? 2 A. No. At all times, the Commission will have the same jurisdiction over the EUA 3 subsidiaries and their ultimate successors as it has now. 4 5 Q. Please explain the impetus for EUA to seek a merger. 6 A. EUA began to consider a combination strategy as soon as it became apparent that the 7 electric utility industry would be restructured and generation deregulated at both the 8 federal and state levels. An integral part of restructuring was the divestiture by the 9 incumbent utilities of their generation portfolios. In the divested environment, EUA 10 determined, as did other electric utilities, that our skills and assets were best focused on 11 the transmission and distribution business. At the same time, it became evident that if our 12 transmission and distribution companies were to realize greater efficiencies, cost 13 reductions, and attractive returns, EUA would have to grow significantly. Put another 14 way, without the generation business and with relatively small service territories, EUA lost 15 important economies of scale and scope. The reduced scale and scope of the organization 16 after divestiture would make it impossible to sustain the infrastructure necessary to 17 maintain the same level of low-cost, high-quality service our customers have come to 18 expect. Our options would be to reallocate fixed costs over a significantly smaller, wires- 19 only, sales base or cut back on service. Maintaining or improving performance in 20 providing customer service, delivering safe, adequate, and reliable electricity at a low cost, Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 7 of 13 1 and fairly compensating our investors would not likely be the results of operating a small 2 wires-only business. Therefore, we concluded that the only acceptable affiliation must be 3 one that would produce these positive results for all our stakeholders. 4 5 Q. How did EUA identify potential business combination partners? 6 A. From late 1996 to early 1999, management and the Board continually evaluated the 7 various strategic options available to EUA as restructuring and the transition to 8 competition were taking place. Among the options considered were remaining a relatively 9 small, independent transmission and distribution company, growing the company by 10 acquiring other, smaller electric and/or gas companies within the region, looking for a 11 merger partner of similar size, and looking for a merger partner of larger size. EUA 12 retained its long-time advisor, Salomon Smith Barney, to assist us in our review of 13 alternatives and, if appropriate, to seek out potential merger or acquisition partners. To 14 meet financial and customer objectives, EUA would seek out a partner of a size that 15 would allow the resulting enterprise to achieve the economies of scale necessary to 16 increase efficiency and reduce costs. The most desirable partners would also have 17 characteristics such as being a low cost provider, a similar philosophy of system 18 operations, a strong customer service commitment, and a quality workforce. Discussions 19 with possible partners ensued. 20 Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 8 of 13 1 Q. When did EUA reach a conclusion on its future? 2 A. On January 31, 1999 and February 1, 1999, the EUA Board held a special meeting to 3 review and consider the proposals received. After presentations by legal and financial 4 advisors and a full discussion and analysis, the Board unanimously determined that it was 5 in the best interests of all EUA stakeholders to enter into a business combination with 6 NEES and that the terms of the merger were fair to and in the best interests of EUA 7 shareholders; it authorized, approved, and adopted the plan of merger and the transaction 8 described in the Agreement. EUA was advised that NEES obtained the consent of 9 National Grid to enter into the Agreement and on the morning of February 1, 1999, at the 10 conclusion of the EUA Board meeting and prior to the opening of the financial markets, 11 EUA and NEES executed and delivered the Agreement. 12 13 IV. Benefits to Customers, Employees and Shareholders. 14 Q. Would you summarize the benefits of the merger for Blackstone and Newport customers? 15 A. Blackstone and Newport's customers will realize quantifiable benefits almost immediately 16 as a result of the rate plan proposed by Narragansett Electric. This plan is described in 17 the testimony of Michael E. Jesanis. Put simply, on the later of April 1, 2000 or 120 days 18 after the merger is completed, the rates of Blackstone and Newport will be consolidated 19 with Narragansett's lower rates. This will provide Blackstone and Newport customers 20 with annual savings of $1.2 million and $3.2 million respectively. Moreover, the rate plan Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 9 of 13 1 assures that economic benefits will not come at the sacrifice of quality service. Following 2 the acquisition, both Narragansett Electric and the EUA companies will continue our 3 commitment to maintain the same high standards of service and reliability that our 4 customers have come to expect. Our historic commitment to our communities and local 5 charities will also be maintained. Blackstone and Newport's record of quality service at 6 low rates will be enhanced by this transaction and we will join in Narragansett Electric's 7 exemplary performance of delivering low rates, reliability, and innovation to our 8 customers. 9 10 In addition, the merger will produce ongoing savings and efficiency gains. The merger 11 savings after the cost to achieve are projected by Mr. Hoffman and Mr. Jesanis to total at 12 least $35 million per year in the first full year for all of the Rhode Island and 13 Massachusetts distribution companies. These savings will endure and, as Mr. Hoffman 14 demonstrates, increase with inflation. Finally, Mr. Jesanis testifies that the NEES merger 15 with National Grid promises additional resources, scale, and the ability to implement 16 further consolidations in the Northeast. The benefits of savings from such future 17 consolidations and efficiencies gains would inure to Blackstone and Newport customers as 18 well. The expectation of savings from future consolidations, together with the distribution 19 rate freeze and the savings from this transaction, provide compelling economic benefits to 20 Blackstone and Newport customers. After the merger, Blackstone and Newport Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 10 of 13 1 customers will receive service from a wires company several times larger than the size of 2 their former distribution company with more financial and operational resources to deal 3 with emerging issues regarding customer service and reliability. Customers will enjoy 4 lower rates and the benefit of rate stability without sacrificing performance and reliability. 5 6 Q. How will the merger affect Blackstone and Newport employees? 7 A. As with most mergers, including ours, the achievable benefits are determined in major part 8 by the number and productivity of the employees retained by the surviving entity; some 9 workforce reduction is inevitable. One of EUA's chief concerns in seeking a combination 10 has been that its employees be treated fairly after the merger, a concern shared by the 11 Commission as well. Several factors peculiar to this merger lead to the conclusion that 12 our employees will be treated fairly. First, as I describe below, the number of necessary 13 employee reductions is small. Second, we anticipate that most of the employee reductions 14 can be accomplished through attrition and voluntary early retirement incentives. Third, we 15 are combining with an organization that is structured and operates much like EUA. 16 Fourth, NEES has made clear its intention to grow its transmission and distribution 17 business and has the financial backing to do so. This growth provides opportunities for 18 our employees they would not otherwise have. Fifth, National Grid is looking for 19 candidates for assignment elsewhere in its operations; these international job opportunities 20 could also be very attractive to our employees. And last, but not least, NEES has Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 11 of 13 1 committed to honor EUA's labor contracts. For our non-union workforce, NEES has 2 agreed that for 12 months following the closing date, compensation, benefits, and 3 coverage shall not be less favorable, in the aggregate, than those provided, in the 4 aggregate, immediately prior to the closing date. Our employees have heard directly, from 5 Richard P. Sergel, NEES's Chief Executive Officer, that their opportunities in the post- 6 merger organization will not be limited because they came from EUA. 7 8 EUA has been steadfastly committed to maximizing the effectiveness of its workforce 9 through a combination of training and motivating employees and optimizing their numbers. 10 Consistent with that objective, we have reduced our electric company and EUASC 11 populations from 1,343 at the end of 1990 to 946 at the end of 1998 (a 30 percent 12 reduction), while improving the quality of service. Our stringent control of personnel 13 counts has positioned us in this merger so that we will be able to achieve synergy savings 14 and still treat our employees fairly. The pre-merger combined staffing is about 4,100. 15 Projected merger savings are based on a reduction from that figure of approximately 250 16 employees, or about 6 percent of the combined total. We fully expect to achieve these 17 reductions almost entirely through attrition and voluntary early retirement programs. 18 Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 12 of 13 1 Q. Would you summarize the benefits of the merger for EUA shareholders? 2 A. The benefits to EUA shareholders are directly related to the consideration they will receive 3 for their shares at the closing of the merger. The base consideration of $31.00 per share 4 represents a 23 percent premium above the price of EUA shares on December 4, 1998, the 5 last trading day before other regional merger announcements caused the price of its shares 6 to increase significantly, and a 5 percent premium above the closing price on January 29, 7 1999. As explained earlier, the purchase price is subject to an upward adjustment related 8 to the timing of the closing, and will be paid in cash. EUA's Board received an opinion 9 from Salomon Smith Barney that the consideration being paid to our common 10 stockholders is fair. We will request shareholder approval at our annual meeting this 11 spring. 12 13 Q. Would EUA have been able to deliver comparable benefits absent this merger? 14 A. Absolutely not. As I have testified earlier, a strategy of merger or acquisition in the 15 distribution and transmission business was essential to our continuing to meet the needs of 16 our stakeholders: low-cost, reliable service to our customers; a secure work environment 17 and continued opportunity for our employees; and a fair return to our shareholders. The 18 merger with NEES provides a partner with the size, proximity, low-cost structure and 19 operating philosophy to meet or exceed these objectives. I do not believe that there was 20 an alternative to this merger that would provide comparable benefits. Narragansett Electric Blackstone/Newport Electric R.I.P.U.C. Docket No. Testimony of R. G. Powderly Page 13 of 13 1 Q. Does this complete your testimony? 2 A. Yes.
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - ----------------------------------- ) Narragansett Electric Company ) R.I.P.U.C. No. __________ Blackstone Valley Electric Company ) Newport Electric Corporation ) ) - ----------------------------------- DIRECT TESTIMONY OF LAWRENCE J. REILLY THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - ----------------------------------- ) Narragansett Electric Company ) R.I.P.U.C. No. __________ Blackstone Valley Electric Company ) Newport Electric Corporation ) ) - ----------------------------------- DIRECT TESTIMONY OF LAWRENCE J. REILLY Table of Contents Page I. Qualifications .................................................... 1 II. Purpose of Testimony .............................................. 3 III. Organization of NEES Distribution Companies........................ 4 IV. Service Benefits from the Merger................................... 8 V. Development of the Competitive Power Supply Market................ 10
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 1 of 13 1 I. Qualifications. 2 Q. Please state your name and business address. 3 A. My name is Lawrence J. Reilly. I have two business addresses: 280 Melrose Street, 4 Providence, Rhode Island 02907; and 55 Bearfoot Road, Northborough, Massachusetts 5 05132. 6 7 Q. What is your position with the Company? 8 A. I am President and Chief Executive Officer of The Narragansett Electric Company 9 ("Narragansett Electric" or the "Company"). In addition, I hold the same position for New 10 England Electric System's other electricity distribution subsidiaries: Massachusetts 11 Electric Company, Nantucket Electric Company; and Granite State Electric Company. I 12 am also a Director of each of these companies. 13 14 Q. Please describe your educational background and training. 15 A. In 1978, I received a Bachelor of Arts degree magna cum laude from the State University 16 of New York at Albany. In 1982, I received the degree of Master in City and Regional 17 Planning from the John F. Kennedy School of Government at Harvard University where I 18 specialized in Energy and Environmental Policy. Also in 1982, I received a Juris Doctor 19 degree cum laude from Boston University School of Law. 20 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 2 of 13 1 Q. Please describe your professional experience. 2 A. I joined New England Power Service Company ("NEPSCO") as an Attorney in the 3 Corporate Legal Department in 1982. In that capacity I advised various New England 4 Electric System ("NEES") companies in the areas of finance and securities law as well as 5 in the areas of environmental licensing and permitting. In 1987, I became legal counsel to, 6 and Secretary of, Narragansett Electric. In that capacity my responsibilities included 7 advising the Company on a variety of regulatory and rate matters and permitting for the 8 Manchester Street Station Repowering Project. In July 1990, I became Director of Rates 9 for NEPSCO with responsibility for wholesale and retail rate matters for all of the NEES 10 companies. In 1993, I was elected a Vice President and assumed additional responsibility 11 for retail revenue requirements. Effective June 1, 1996, I was elected President of 12 Massachusetts Electric Company. I became President of Granite State Electric and 13 Narragansett Electric in January 1997 and October 1997, respectively. In my capacity as 14 Vice President and Director of Rates and as President and CEO of the NEES electricity 15 distribution companies I have been actively involved with electric industry restructuring 16 matters. My current areas of responsibility for the NEES electricity distribution 17 companies include transmission and distribution system operations, customer service, and 18 business service functions. 19 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 3 of 13 1 Q. Do you serve on the boards of any other organizations? 2 A. Yes. I am a Director of the Massachusetts Technology Park Corporation. I also currently 3 serve as Chairman of the Massachusetts Alliance for Economic Development, a privately 4 funded non-profit organization dedicated to promoting economic growth in 5 Massachusetts. I am also on the Board of Grow Smart Rhode Island, a non-profit 6 organization focused on the interaction of economic growth, environment, and land use 7 issues. In addition, I serve on the Boards of the United Way of Central Massachusetts, the 8 United Way of Southeastern New England, the Foundation for Ocean State Public Radio, 9 the Worcester State Foundation, and as a Corporator of the Worcester Art Museum. 10 11 Q. Have you previously testified before any regulatory commission? 12 A. Yes, I have previously testified before the Rhode Island Public Utilities Commission 13 ("Commission'), the Massachusetts Department of Telecommunications and Energy, the 14 New Hampshire Public Utilities Commission, and the Federal Energy Regulatory 15 Commission. 16 17 II. Purpose of Testimony. 18 Q. What is the purpose of your testimony? 19 A. The purpose of my testimony is three-fold. First, I will describe how Narragansett 20 Electric and its affiliated distribution companies are organized today to provide quality Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 4 of 13 1 service to customers. Second, I will describe the integration process that is underway 2 with Eastern Utility Associates ("EUA") and the anticipated benefits for customers. 3 Finally, I will describe the benefits that the merger creates for customers in the power 4 supply market. 5 6 III. Organization of NEES Distribution Companies. 7 Q. Mr. Reilly, will you please describe how Narragansett Electric and the other NEES 8 distribution companies are organized to provide service to customers. 9 A. Narragansett Electric and its affiliated distribution companies in Massachusetts and New 10 Hampshire together provide service to almost 1.4 million customers. The breakdown of 11 customers by distribution company is detailed on Exhibit LJR-1. Although Narragansett 12 Electric has its own corporate identity and continues to be a leading corporate citizen in 13 the Rhode Island business community, to the extent possible, we operate all the NEES 14 distribution companies as an integrated organization. This integration allows us to operate 15 more efficiently and provide better service to customers. For example, this method of 16 operation allows us to implement best practices uniformly across the system and provides 17 us flexibility in terms of assigning crews where needed most in response to major storms. 18 Through this integrated management we are able to alleve the efficiency gains that have 19 historically been available through the sharing of administrative functions such as 20 accounting and legal services through NEPSCO. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 5 of 13 1 The combined service areas of the NEES distribution companies in the three states cover 2 almost 5000 square miles. For that reason, we have divided the combined territories up 3 into six operating districts and a number of operating satellites that are run from each 4 district. Exhibit LJR-2 is a map showing the current district boundaries within the service 5 territory and the location of key facilities. 6 7 For the most part, each operating district includes a functional head for operations, 8 customer service, and business services. These individuals are responsible for service 9 performance and program implementation throughout their respective districts. In 10 general, where there is a need to be close to the customers (because of travel time or 11 because detailed knowledge of the local conditions is required), individuals work out of 12 the local district offices or satellite locations; where frequent local contact is not critical, 13 individuals tend to work in the central locations, principally, Northborough, Westborough, 14 and Providence. The degree to which each operating district is supported centrally varies 15 from function to function. Narragansett Electric is currently organized as a single 16 operating district with functional heads for operations, customer service, and business 17 services located in Providence. After the merger with EUA, I expect there will be two 18 operating districts in Rhode Island. 19 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 6 of 13 1 Q. Please explain the split between district and central functions in the Operations area. 2 A. In Operations, the physical workers (linemen, underground workers, substation 3 maintenance workers) are assigned to a district or satellite location. In the case of 4 Narragansett, that means that such workers are based in Providence or the other Rhode 5 Island satellite offices. Certain engineering functions are performed locally while other 6 engineering operations such as substation design and standards are performed centrally. 7 Operating functions handled centrally for all system companies include: training; material 8 supply; relay & telecommunications; transmission line engineering; engineering laboratory; 9 construction; environment; safety; and property assets. In some cases there are individuals 10 assigned to local district offices to implement programs and polices that are administered 11 centrally. Safety, environmental management, and vegetation management are examples 12 of areas that fall into this category. As such, there are employees of Narragansett 13 performing those functions in Rhode Island. 14 15 Q. How is responsibility divided between the field and central office in the customer service 16 area? 17 A. Meter reading is the clearest example of a function where it is most efficient to have the 18 workers located near the customers. Workers in the meter operations group, which is 19 responsible for installing, maintaining, exchanging, and testing meters, are also 20 decentralized; however, they receive central support from the Meter Operations and Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 7 of 13 1 Engineering Group in Worcester. Supplier services along with load research and load 2 estimation, which have become increasingly important in the restructured environment, are 3 located centrally in Northborough. Customer calls are handled in call centers located in 4 Providence and Northborough that are linked through telecommunications equipment 5 which automatically transfers calls between these two centers to minimize wait times for 6 customers. This arrangement also provides us access to two job markets for customer 7 service representatives and diversity of locations in the event of bad weather or a disaster 8 at either location. 9 10 Q. How is the Business Services function organized? 11 A. Each district office has a local Business Services Vice President and a staff of account 12 managers. The account managers handle service requests for our largest customers (200 13 kilowatts or greater demand per month) and are actively involved in the marketing of our 14 various Demand Side Management ("DSM") programs. DSM programs for residential 15 and small commercial and industrial customers are handled centrally by NEPSCO 16 employees in Northborough. Special programs and new initiatives are also developed in 17 Northborough and implemented in close coordination with Business Services personnel in 18 the field. 19 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 8 of 13 1 IV. Service Benefits from the Merger. 2 Q. Do you believe that the merger will create service benefits for customers? 3 A. Yes. Several factors lead us to conclude that the merger will improve service to 4 customers. First is geographic proximity. A map showing the relationship between the 5 NEES and EUA distribution companies is included as Exhibit LJR-3. As shown, the 6 service territories of the companies are in very close proximity. It is this geographic 7 proximity that makes this merger so attractive from an operating perspective. This merger 8 goes a long way to rationalizing the service territories of the distribution companies in 9 southeastern New England and, with the integration of NEES and EUA field and central 10 functions, should enable us to provide comparable or better service at a lower cost. 11 Second, there is a long history of good working relationships between our companies, 12 including a history where a number of employees have moved between the companies over 13 time. Third, perhaps related to the first two items mentioned above, there appears to be a 14 very similar culture between the two companies - one where quality customer service 15 and cost control are widely recognized objectives. In my opinion, all three of these factors 16 will facilitate a successful integration of the businesses. 17 18 Q. Are the companies also addressing service quality issues in the integration process for the 19 merger? Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 9 of 13 1 A. Yes. The proper integration of the companies is central to the effectiveness and efficiency 2 of our operations and the quality of our service following the merger. I am a member of 3 the integration steering committee that is responsible for the successful integration of the 4 companies. Our progress during the integration process has been substantial. We have 5 already found several ways to improve service and efficiency that we will build upon as we 6 complete the integration process and following the merger. The transition teams cover ten 7 different disciplines and approximately sixty subgroups have been established as part of the 8 effort to focus on specific areas. The teams and the areas they are responsible for are 9 outlined on Exhibit LJR-4. 10 11 Q. What benefits of the merger have you identified to date? 12 A. Although it is still early in the process, it is apparent that several key benefits will flow 13 from the eventual consolidation of the three Rhode Island utilities. Specifically: 14 o The larger company will have more resources to draw upon in the event of storms 15 or natural disasters; 16 o Customer service costs and other costs associated with administering separate 17 rates and maintaining separate companies will be reduced; 18 o BVE and Newport customers will be provided 24 hour per day access to customer 19 service representatives for routine billing and payment inquires (currently such 20 access is limited to 7 a.m. to 9 p.m. Monday through Saturday); Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 10 of 13 1 o The consolidation will produce administrative savings for the Commission and the 2 Division by reducing the number of regulated companies and associated reporting 3 requirements; 4 o The customers of Narragansett and the EUA companies benefit from the rate plan 5 proposed as part of this filing; and 6 o The consolidation will help in the development of the competitive power supply 7 market. 8 9 V. Development of the Competitive Power Supply Market. 10 Q. You stated that you expected the consolidation of Narragansett Electric and the EUA 11 companies to help in the development of the competitive power supply market. Please 12 explain why you believe this is to be the case. 13 A. Although it is certainly not the only barrier to development of a competitive market, the 14 multitude of distribution companies within southeastern New England has no doubt 15 retarded the growth of the competitive market in a number of ways. First, differing 16 distribution rates and availability clauses for providing distribution service complicate the 17 terrain for power suppliers considering entry into the market. Second, the patchwork 18 nature of the existing service territories complicates marketing efforts. Third, differing 19 electronic data interchange formats and testing requirements add to administrative 20 overheads for suppliers. The consolidation of rates for delivery service, the contiguous Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 11 of 13 1 nature of the expanded service territory, and one less point of contact for suppliers 2 entering the market here should all help to reduce barriers to entry into the competitive 3 supply market. 4 5 In Rhode Island, these benefits will be particularly important. Suppliers will be able to 6 enter the state by complying with a single set of regulations and a single set of terms and 7 conditions by the utility. We have an excellent opportunity to develop rational and 8 consistent rules that will make Rhode Island a key player in competitive power markets. 9 The more suppliers that we can attract, the higher value we will provide for Rhode Island 10 customers. 11 12 Q. Why is reducing barriers to entry for suppliers entering the competitive market important? 13 A. Prior to restructuring, the generation or supply component of customer bills accounted for 14 roughly two-thirds of the total cost of electricity. The significant potential for savings in 15 that portion of the bill was one of the factors that led to restructuring. Nothing has 16 changed in this area. Power supply costs are still the area where customers stand to save 17 the most money on their bills. Without regulation, however, there must be an efficient and 18 vigorous market for electricity supplies for customers to realize the full benefits of 19 competition. 20 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 12 of 13 1 Q. In your opinion what other barriers exist to the development of a robust competitive 2 power supply market? 3 A. Lack of information is certainly a problem on several levels. Not all customers are aware 4 of their options or have ready access to billing data needed to minimize supply costs. 5 Power marketers may also lack information about potential customers that could benefit 6 from their products. 7 8 Q What actions are you planning to take to reduce these barriers? 9 A. We have a number of initiatives under way to inform customers of their options in the 10 power supply market. We currently offer "Power Talk", a speakers bureau program for 11 customer groups of all kinds. We are including information in "PowerLink", a newsletter 12 for our business customers, and are hosting breakfast meetings for our largest customers 13 to highlight opportunities available in the market. Under our "Power Connection" 14 program, with a customer's consent, we will provide billing data to all registered suppliers 15 in electronic format so that prospective suppliers can develop offers suited to the 16 individual customers. We are also distributing a software product called "Energy Smart" 17 to our customers that provides educational information to customers and is expected to 18 eventually aid customers who wish to shop for power supplies on-line. 19 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Testimony of L. J. Reilly Page 13 of 13 1 In addition, we also are developing a series of optional metering services that will be 2 available to any customer that wants detailed interval or real time demand and energy 3 use data. Also, to assist power marketers in getting access to prospective customers, we 4 intend to offer a mailing service to all power marketers whereby we would mail their 5 marketing information to customer segments they determine without disclosing any 6 customer data to the power marketer. 7 8 Q. How will the merger improve this effort? 9 A. As part of the integration process, we will continue to look for ways to improve our 10 outreach and education programs and make them more effective. The merger will assure 11 that the finally implemented programs will reach more customers, more efficiently. The 12 consolidation will also facilitate marketers' efforts to reach our customers with ideas and 13 products that will provide our customers with more value at lower prices. 14 15 Q. Does this conclude your testimony? 16 A. Yes.
EXHIBITS OF L. J. REILLY LJR-1 Customers Served by NEES Distribution Company LJR-2 Current Map of NEES Service Territory LJR-3 Map of Combined NEES-EUA Service Territory LJR-4 Integration Teams and Responsibilities Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibits of Lawrence J. Reilly Exhibit LJR-1 Customers Served by NEES Distribution Company Exhibit LJR-2 Map of Existing NEES Service Territory Exhibit LJR-3 Map of Combined NEES-EUA Service Territory Exhibit LJR-4 Integration Teams and Responsibilities Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit LJR-1 Exhibit LJR-1 Customers Served by NEES Distribution Company S:\RADATA1\EASTED\Ljr-1.wk4 Narragansett Electric PAGE 1 BVE/NewPort Electric 10-May-1999 R.I.P.U.C. No. _____ Exhibit LJR-1 Page 1 of 1 New England Electric System Number of Customers per Distribution Company Number of Customers Massachusetts: Massachusetts Electric Company 983,191 Nantucket Electric Company 10,169 ------ Total Massachusetts 993,360 Rhode Island: Narragansett Electric Company 336,029 New Hampshire: Granite State Electric Company 37,114 3 State Total 1,366,503 ========= Source: March 1999 Billing Records Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit LJR-2 Exhibit LJR-2 Maps of Existing NEES Service Territory Exhibit LJR-2 Map of Existing NEES Service Territory Two Maps First Map: Reflects service territories, headquarters, customer service and operations centers and operating satellites for Granite State, Mass. Electric, Nantucket and Narragansett in Rhode Island, Massachusetts and New Hampshire. Second Map: Reflects Narragansett service territory, headquarters and operating satellites in Rhode Island.
Granite State Electric Massachusetts Electric Company Company Lebanon Western Merrimack Valley Acworth Adams Mount Washington Amesbury Alstead Alford New Marlboro Andover Bath Athol New Salem Billerica Canaan Barre North Adams Boxford Charlestown Belchertown Northampton Chelmsford Cornish Brimfield Orange Dracut Enfield Charlemont Palmer Haverhill Grafton Cheshire Petersham Lawrence Hanover Clarksburg Phillipston Lowell Lnagdon East Longmeadow Rowe Methuen Lebanon Erving Royalton Newbury Marlow Florida Sheffield Newburyport Monroe Goshen Shutesbury North Andover Orange Granby South Egremont Salisbury Plainfield Great Barrington Stockbridge Tewksbury Surry Hampden Templeton Tyngsboro Walpole Hancock Wales West Newbury Hardwick Ware Westford Hawley Warren Salem Heath Warwick North Shore Derry Holland Wendell Beverly Pelham Lenox West Stockbridge Essex Salem Monroe Wilbraham Everett Windham Monson Williamsburg Gloucester Monterey Williamstown Hamilton Lynn Narrangansett Electric Malden Company Central Manchester Auburn New Braintree Medford Southern Ayer North Brookfield Melrose Charlestown Berlin Oakham Nahant Coventry Bolton Oxford Revere East Greenwich Brookfield Paxton Rockport Exeter Charlton Pepperell Salem Hopkinton Clinton Rutland Saugus Narragansett Dudley Shirley Swampscott North Kingstown Dunstable Southbridge Topsfield Richmond East Brookfield Spencer Wenham South Kingstown Gardner Sturbridge Winthrop Warwick Grafton Sutton West Greenwich Harvard Webster West Warwick Hubbardston West Brookfield Westerly Lancaster West Groton Leicester Westminster Providence Leominster Winchendon Barrington Millbury Worcester Bristol Cranston Southeast East Providence Attleboro Northborough Foster Bellingham Northbridge Glocester Blackstone Norton Johnston Douglas Plainville Little Compton Foxborough Quincy North Providence Franklin Randolph Providence Hingham Rehoboth Scituate Holbrook Seekonk Smithfield Hopedale Southborough Tiverton Marlborough Upton Warren Mendon Uxbridge Milford Westborough Milville Weymouth Nantucket Wrentham
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit LJR-3 Exhibit LJR-3 Map of Combined NEES-EUA Service Territory Exhibit LJR-3 [Map of Combined NEES-EUA Service Territory] Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit LJR-4 Exhibit LJR-4 Integration Teams and Responsibilities Narragansett Electric BVE/Newport Electric R.I.P.U.C. No.______ Exhibit LJR-4 Page 1 of 1 EUA/NEES TRANSITION TEAMS General Business Areas HR & RETAIL INFORMATION POWER SUPPLY CHAIN COMPANIES SYSTEMS COMPANY - ------------ ------------ ------------ ------------ HR-Compensation EO-Central Retail Transmission & Operations Applications Marketing Benefits HR-Labor EO-Central Corporate Transmission Engineering Applications Planning HR-Culture EO-Field Operations Divestitures Integration Operations HR-Employee EO-Dispatching Technology Nuclear Relations Services Issues SCM-Inventory CS-Call Center Y2000 PPA/PSA Power SCM-Goods CS-Meters IS Support Contracts and Services SCM-Accounts CS-Billing NEPOOL Payable Issues Health and CS-Credit Safety & Collections Benefit RM&S-Demand Side Plan Funding Management RM&S-Business Services Telecommunication Property Environmental and Safety External Affairs ============ =========== ============ ============ TRANSITION STEERING COMMITTEE ============ =========== ============ ============ Chairman: T. Rogers/ R. Powderly - ------------ ------------ ------------ ------------ DC Kennedy LJ Reilly DL Holt PG Flynn HE Stapleford JL McGrath - ------------ ------------ ------------ ------------ B. Hassan J Carney W Norko K Kirby - ------------ ------------ ------------ ------------ KEY COORDINATION AREAS - ------------ ----------- ------------ Regulatory Unregulated NGG Coord. Approvals Businesses - ------------ ----------- ------------ TREASURY RATE/REVREQ ACCOUNTING COMMUNICATIONS LEGAL ------------ ------------ ------------ ------------ ----------- Finance Revenue General External Legal Requirement Accounting and and Employee Rates Communications Risk Plant Corporate Management Accounting Governance Investor Standard Revenue Relations Offer and Accounting Default Property Service Payroll Tax Contracts Taxes "TIER 1" TRANSITION TEAMS ---------- ----------- ---------- ========== =========== ========== =========== =========== TRANSITION STEERING COMMITTEE J.Zschokke TL WR Richer SM Stevens MA Katz Schwennesen ---------- ----------- ---------- ----------- ----------- C Hebert D.St.Pierre A.Camara F. Mason D Fazzone ---------- ----------- ---------- ----------- ----------- OTHER CONSULTANTS ------------ ------------ Audit A&G Best Practices Planning, Early Budgets and Decisions Reporting Support Facilities Organization Planning Asset Team Support Separation Records Management "Cut-over" Plan ========== ============ TRANSITION STEERING COMMITTEE T. Rogers Mercer Management Consultants ---------- ------------ M Hirsh ---------- ------------ THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - ---------------------------------- ) Narragansett Electric ) R.I.P.U.C. No. __________ BVE/Newport Electric ) ) - ---------------------------------- DIRECT TESTIMONY OF DAVID M. WEBSTER THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - ---------------------------------- ) Narragansett Electric ) R.I.P.U.C. No. __________ BVE/Newport Electric ) ) - ---------------------------------- DIRECT TESTIMONY OF DAVID M. WEBSTER Table of Contents Page I. Qualifications .................................................... 1 II. Purpose of Testimony............................................... 3 III. Recovery of Cost of Removal Expenditures .......................... 3 IV. Book/Tax Timing Differences on Cost of Removal..................... 9 V. Consolidation of Depreciation Rates ............................... 23 VI. Storm Contingency Fund............................................. 27 VII. Deferred FAS 106 Cost Recovery..................................... 29 VIII. Hazardous Waste Cost Recovery ..................................... 32 IX. Conclusion......................................................... 34 X.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 1 1 I. Qualifications 2 Q. Please state your full name and business address. 3 A. David M. Webster, 25 Research Drive, Westborough, Massachusetts 01582. 4 5 Q. Please state your position. 6 A. I am a Principal Financial Analyst in the Rate Department of New England Power 7 Service Company ("NEPSCO"). NEPSCO provides engineering, technical, 8 accounting, and other services for the New England Electric System ("NEES") 9 Companies, including The Narragansett Electric Company ("Narragansett" or 10 "Company"). 11 12 Q. Please describe your educational background and training. 13 A. In 1986, I graduated with distinction from Southeastern Massachusetts University 14 with a Bachelor of Science degree in accounting. 15 16 Q. Please outline your professional experience. 17 A. In 1986, 1 was hired by NEPSCO as an Assistant Analyst in the Financial Reporting 18 Department. My responsibilities included assisting in the preparation of the various 19 external reporting requirements for NEES and subsidiaries. I was promoted to 20 Analyst in the Financial Analysis section in 1988. My responsibilities included 21 conducting various calculations and analysis in support of the closing of the 22 accounting books of record for the various NEES companies. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 2 1 In 1991, I was promoted to Supervisor of the NEPSCO Accounting Department, 2 responsible for the monthly closing of the accounting books of record as well as 3 all internal and external reporting requirements. In 1992, my supervisory 4 responsibilities were expanded to include overseeing the monthly closing of two 5 additional NEES subsidiaries' books of record as well as all internal and external 6 reporting requirements. 7 8 In 1993, I was promoted to Supervisor of Wholesale Accounting, overseeing the 9 monthly closing and internal reporting requirements for the Wholesale Business 10 unit of NEES. In 1995, I was promoted to Manager of Wholesale Accounting and 11 was given additional responsibilities associated with the Wholesale Accounting 12 section. 13 14 In February 1997, I accepted an assignment to the Rate Department to provide 15 revenue requirement analyses for the NEES retail companies. 16 17 Q. Have you previously testified before a regulatory commission? 18 A. Yes, I have testified in proceedings before regulatory commissions in Rhode 19 Island, New Hampshire and Massachusetts. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 3 1 II. Purpose of Testimony 2 Q. What is the purpose of your testimony? 3 A. My testimony describes the Company's proposal with regard to several 4 accounting issues that will arise as a result of the proposed merger of 5 Narragansett, Blackstone Valley Electric Company ("BVE") and Newport 6 Electric Company ("Newport") (together, the "Companies"). The issues that need 7 to be addressed under the rate plan proposed in the testimony of Mr. Jesanis 8 include consolidation of depreciation rates, storm contingency funds and deferred 9 FAS 106 costs. I also address certain accounting issues related to recovery of 10 hazardous waste remediation costs. However, I will begin my testimony by 11 describing Narragansett's proposal to recover cost of removal expenses. I will 12 first describe the treatment of Narragansett's cost of removal expenses under the 13 current rates. I will then describe how this proposal affects the consolidated rates 14 of the Companies. 15 16 III. Recovery of Cost of Removal 17 Q. Please provide an overview of Narragansett's proposal to recover cost of removal 18 expenditures. 19 A. There are three elements that need to be addressed to allow Narragansett to fully 20 recover both prior and prospective cost of removal expenditures. First, 21 Narragansett must be allowed to implement depreciation rates which contain an 22 allowance for cost of removal expenditures on both a historical and prospective Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 4 1 basis. As I describe below, the depreciation rates that Narragansett proposes to 2 implement will meet this requirement. 3 4 Second, Narragansett must be allowed to "normalize" the timing difference that is 5 resulting from the current regulatory treatment of cost of removal expenditures. 6 The current treatment of cost of removal dictates that Narragansett "flow- 7 through" to customers the tax deduction it receives for the cost of removal 8 expenses. Thus, providing an offsetting deferred tax will "normalize" or 9 eliminate the timing difference created by the current treatment of cost of 10 removal. 11 12 Finally, since Narragansett has been "flowing-through" tax benefits to customers 13 for items which it has not been reimbursed, Narragansett has a deficiency in the 14 provision for deferred taxes recorded on its books. As I will describe below, 15 Narragansett proposes to recover its entire deferred tax deficiency by applying 16 certain current and future settlements against the amount of the deficiency. 17 18 Q. What is cost of removal? 19 A. Cost of removal expenditures are the costs incurred by the Companies to remove 20 a unit of utility plant from service. 21 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 5 1 Q. How does the Narragansett currently account for these cost of removal 2 expenditures? 3 A. Narragansett does not charge cost of removal to expense. Instead, consistent with 4 group accounting practices prescribed by the Commission in prior general rate 5 case proceedings, Narragansett charges cost of removal expenditures, as 6 incurred, against its accumulated provision for depreciation. In addition, 7 Narragansett is not permitted to accrue for negative salvage (cost of removal) in 8 its current depreciation rates. 9 10 Therefore, Narragansett is not currently collecting any cost of removal 11 expenditures through rates. While Narragansett has proposed in previous rate 12 cases to include an allowance for cost of removal in its depreciation rates 13 included in cost of service, such accounting treatment has not yet been approved 14 by the Commission. 15 16 The current accounting treatment, which charges cost of removal directly to the 17 depreciation reserve, reduces the amount of accumulated depreciation, thereby, 18 increasing the amount of rate base on which Narragansett earns a return. Thus, 19 Narragansett is currently earning a return on the cost of removal expenditures, 20 but is not recovering the cost of removal expenditures themselves, either directly 21 as an expense or indirectly through depreciation rates. Under this regulatory Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 6 1 practice, Narragansett continues to accumulate cost of removal expenditures 2 which must be recovered in the future from customers. 3 4 Q. What are the problems associated with the current treatment of cost of removal 5 expenditures? 6 A. As stated above, the current rate making policy regarding cost of removal does 7 not allow Narragansett to be reimbursed for any of its cost of removal 8 expenditures to date. These expenses have been charged directly against the 9 accumulated provision for depreciation and as a result, over time, created a 10 deficiency in the accumulated provision for depreciation. The Companies are 11 proposing depreciation rates that would recover the existing deficiency in the 12 accumulated depreciation reserve. I describe this provision later in my testimony. 13 14 In addition, to eliminate future deficiencies in the accumulated reserve for 15 depreciation, Narragansett needs to include in its depreciation rates an amount to 16 begin recovering future cost of removal expenses (this is also known as negative 17 salvage) for the future removal of an asset placed into service today. This 18 methodology would recover the cost of removing that asset proportionately over 19 the life of the asset. 20 21 Q. What depreciation rates would Narragansett implement? Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 7 1 A. The settlement agreement reached between Narragansett, the Rhode Island 2 Division of Public Utilities and Carriers ("Division"), and the Energy Council of 3 Rhode Island in RIPUC Docket No. 2290, resolved all issues except the 4 appropriate depreciation rates for Narragansett. As part of the settlement, the 5 parties agreed to further study the depreciation analysis presented to the 6 Commission by Narragansett. 7 8 After months of negotiation, the Division and Narragansett reached an agreement 9 resolving Narragansett's depreciation rates. The agreement was filed with the 10 Commission on May 9, 1996. This settlement represents an initial step in 11 attempting to resolve the problem associated with the Commission's treatment of 12 cost of removal expenses. A copy of the depreciation settlement agreement has 13 been included as Exhibit DMW-1. Under the terms of the agreement, 14 Narragansett may file with the Commission the agreed upon depreciation rates, 15 without opposition from the Division, which include a component for negative 16 salvage. As part of our rate plan, we are proposing to implement the agreed upon 17 depreciation rates which include an allowance for cost of removal on a 18 prospective basis. Specifically, we propose to implement the new rates as of 19 January 1, 2001. 20 21 Q. What impact will implementing the depreciation rates from the settlement have 22 on rates? Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 8 1 A. As shown in Exhibit DMW-2, page 1, applying the settlement depreciation rates, 2 including the negative salvage component, to Narragansett's intrastate distribution 3 and general plant balances as of December 31, 1998 will increase Narragansett's 4 depreciation expense by approximately $1.9 million. As I explain below, this 5 increase is mitigated by the merger. Because BVE's and Newport's depreciation 6 rates are higher than Narragansett's, merging the companies and using the settled 7 depreciation rates lowers the impact of the change on customers. 8 9 Q. How did you calculate the amount of the increase in depreciation rates? 10 A. As shown in Exhibit DMW-2, pages 2 and 3, depreciation expense was calculated 11 for Narragansett's intrastate distribution and general plant based upon the current 12 depreciation rates and then based upon the rates in the depreciation settlement. In 13 each case, these rates were applied against Narragansett's intrastate plant 14 balances as of December 31, 1998. The incremental impact of applying the 15 depreciation settlement to interstate plant was not calculated since, under 16 Narragansett's integrated facilities agreement with New England Power Company 17 ("NEP"), Narragansett is reimbursed by NEP for essentially all costs associated 18 with the operation and maintenance of its transmission system. Since that 19 agreement is under the jurisdiction of the Federal Energy Regulatory 20 Commission ("FERC"), a change in the interstate transmission-related 21 depreciation rates must be approved by the FERC. 22 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 9 1 Using the settlement depreciation rates resulted in depreciation expense 2 amounting to $20,645,374, Exhibit DMW-2, page 1, compared to depreciation 3 expense of $18,757,750 when Narragansett applies its current depreciation rates. 4 Therefore, the proposed increase in depreciation expense is $1,887,624 or the 5 difference between the two numbers. 6 7 IV. Book/Tax Timing Differences on Cost of Removal 8 Q. Please explain the difference between the accounting for cost of removal 9 expenditures for book purposes versus for tax purposes. 10 A. As explained earlier, intrastate cost of removal expenditures are charged to the 11 reserve for depreciation for book purposes and thus far no allowance for cost of 12 removal has ever been included in Narragansett's intrastate book depreciation 13 expense. However, for tax purposes, since 1972, intrastate cost of removal 14 expenditures have been deducted on Narragansett's tax return in the year in which 15 the expenditure is made. Therefore, there is a timing difference between the 16 treatment of cost of removal for tax purposes in the current period versus the 17 treatment for book purposes which does not recognize cost of removal as an 18 expense. Simply stated, Narragansett is realizing a tax deduction for cost of 19 removal before these expenditures have ever entered into a determination of book 20 expense. This is commonly referred to as a book/tax timing difference. 21 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 10 1 Q. What has been the rate making treatment of this book/tax timing difference for 2 cost of removal expenditures. 3 A. Narragansett has flowed through these tax deductions for intrastate cost of 4 removal expenditures to its customers even though customers have not 5 reimbursed Narragansett for the cost that gave rise to this tax deduction. Stated 6 another way, Narragansett has never been allowed to include any deferred taxes 7 for these cost of removal tax deductions in cost of service. This effectively 8 provides a subsidy to current customers at the expense of future customers who 9 will at some point be asked to bear this expense without any associated tax 10 benefits. 11 12 Q. Is this the case for Narragansett's other book/tax timing differences? 13 A. No. Narragansett has been allowed to adopt deferred tax accounting for all of its 14 other book/tax timing differences. 15 16 Q. How does Narragansett propose to correct the flow-through of cost of removal in 17 future years? 18 A. Narragansett proposes to cease the flow-through of tax deductions related to cost 19 of removal by recording an offsetting deferred tax. 20 21 Q. What impact will cessation of the "flow-through" of tax benefits have on rates? Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 11 1 A. As shown on Exhibit DMW-3, eliminating the "flow-though" of tax benefits will 2 increase rates by approximately $1.6 million. Together with the $1.9 million of 3 increased depreciation expense discussed above, this treatment increases 4 Narragansett's revenue requirement by $3.5 million on an ongoing basis as shown 5 on Exhibit DMW-4. As I explain below, these revenue requirements are 6 mitigated by the consolidation because the depreciation rates of BVE and 7 Newport are presently higher than the settlement rates that we propose to adopt 8 for the consolidated companies. 9 10 Q. How was this amount calculated? 11 A. To date there have not been any deferred taxes provided to normalize the 12 differences between Narragansett's books and its tax return, and because cost of 13 removal expenditures have not been recorded in book expense, the easiest way to 14 determine the impact on rates is to look at the actual cost of removal tax 15 deductions recorded. 16 17 Please refer to Exhibit DMW-3. The impact on rates was calculated by taking the 18 average of the actual intrastate cost of removal tax deduction taken by 19 Narragansett on its tax return for the years 1996, 1997 and 1998. Since the actual 20 amount of cost of removal expenditures varies from year to year, the three year 21 averaging approach was chosen to develop a representative amount of cost of 22 removal expenditures. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 12 1 As shown on line 9 of Exhibit DMW-3, the average intrastate tax deduction for 2 cost of removal amounted to approximately $3 million. Therefore, the resulting 3 average tax benefit amounted to approximately $1 million, as shown on line 11. 4 This amount is then grossed-up to its pre-tax level to reflect the annual impact on 5 rates on a prospective basis from eliminating the "flow-through" benefits from 6 cost of removal tax benefits. 7 8 Q. Could you explain how deferred tax accounting works? 9 A. Yes. Deferred tax accounting is meant to "normalize" or match up the differences 10 between the recognition of expenditures for tax purposes to the recognition of 11 those same expenditures on Narragansett's books. As mentioned above, these 12 differences are referred to as timing differences. 13 14 Q. Could you provide an example of how the accounting for cost of removal and the 15 related tax deductions should work in a normal situation? 16 A. I have prepared an example in Exhibit DMW-5, page 1. This example portrays 17 the proper method of accounting for cost of removal and its related tax benefits. 18 As previously mentioned, in Narragansett's case the tax deduction for cost of 19 removal actually occurs when the plant is removed from service, but the cost of 20 removal was never reflected in book depreciation expense. The correct method 21 of accounting for cost of removal would be to include a cost of removal 22 allowance in Narragansett's depreciation rates. Since cost of removal Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 13 1 expenditures occur at the end of the life of an asset, it should be anticipated in 2 advance and an estimated allowance for cost of removal should be included in 3 book depreciation expense during the period the asset is being depreciated. In 4 doing so, the reserve for depreciation at the end of the life of the asset would be at 5 a level which would cover the original cost plus the cost of removal expected to 6 be incurred. 7 8 In this example (Exhibit DMW-5, page 1) , an asset worth $20,000 is depreciated 9 over 10 years. It is anticipated that $ 1,000 will be incurred at the end of its ten 10 year life to remove it. Depreciation expense each year not only includes $2,000 11 per year for the original cost of the assets, but also an additional $100 per year in 12 anticipation of the cost of removal expenditure. At the end of year 10, the total 13 depreciation reserve would equal $21,000 which would be sufficient to cover the 14 original cost of the asset plus the cost of removing that asset. 15 16 For simplicity, we have assumed that tax depreciation is calculated exactly the 17 same as book depreciation with the exception that the Internal Revenue Service 18 ("IRS") would not permit the inclusion of the additional $100 for the anticipated 19 cost of removal allowance. However, since the Company will ultimately realize a 20 tax deduction, this allowance in book depreciation for cost of removal is a 21 book/timing difference for which deferred taxes should be recorded. In this 22 situation, a deferred tax receivable would be recorded which would have the Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 14 1 effect of reducing cost of service. This treatment would recognize that a 2 component of book depreciation is not deductible currently but will be in the 3 future, however it would accrue a future tax benefit during the life of the asset. 4 Absent deferred tax accounting, customers would have to bear the $100 portion 5 of book depreciation expense, representing the cost of removal allowance, 6 without the benefit of a tax deduction, which would ultimately occur in one year 7 at the end of the life of the asset. Deferred tax accounting attempts to normalize 8 the tax benefits over the period in which the book expense occurs instead of when 9 the tax deduction takes place. 10 11 Q. How does this compare to Narragansett's situation? 12 A. Narragansett's situation is much different because Narragansett has not been 13 allowed to include an allowance for cost of removal in its book depreciation in 14 advance of actually incurring the actual cost. Second, Narragansett has not been 15 allowed to record deferred taxes on its cost of removal tax deductions. 16 17 Q. Have you provided an example to illustrate this situation? 18 A. Yes. Please see Exhibit DMW-5, page 2. In this case, I have shown two assets, 19 each with 10-year lives, one constructed in year 0 and one constructed in year 11. 20 The first asset costs $20,000 and the second asset costs $30,000. The first asset 21 will incur $1,000 for cost of removal and the second asset will incur $1,500 for 22 cost of removal at the end of their useful lives. For asset number 1, I have not Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 15 1 reflected an allowance in depreciation expense for cost of removal. However, for 2 asset 2, I have built into the depreciation expense the anticipated cost of removal 3 for that asset and have also reflected a makeup provision for the actual cost of 4 removal for asset 1. In this example, I have also assumed that no deferred taxes 5 were recorded as is the case for Narragansett. 6 7 Two issues should be noted in this example. Customers who received service in 8 the last ten years of this example were paying for the cost of removal for asset 1 9 which should have been paid by the customers who received service during the 10 first ten years of this example. In addition, without deferred tax accounting, 11 customers in years 11 and 21 enjoyed the tax benefits of the cost of removal tax 12 deduction while customers in the years 12 through 20 not only paid the increased 13 depreciation cost related to cost of removal, but did so without the benefits of any 14 tax deductions relative to that cost. 15 16 Q. Have you provided any other examples? 17 A. Yes. In Exhibit DMW-5, page 3, I have an example which is similar to the one 18 described above. However, in this example I have included deferred taxes to 19 normalize the book/tax timing difference. The deferred tax accounting in the 20 example would have kept customers in years 11 and 21 from unfairly benefitting 21 from the cost of removal tax deductions and given those tax deductions to the 22 customers in years 12 through 20 who bore the related book expense. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 16 1 Q. Could you please explain what is meant by the prior flow-through of tax benefits 2 resulting from past regulatory practices? 3 A. As previously stated, Narragansett has been taking a tax deduction for the 4 amount of cost of removal expenditures incurred during the tax year. As a result, 5 customers have had their cost of service reduced to the extent of these tax 6 benefits, even though they have not been asked to pay for the cost which has 7 given rise to this tax benefit. 8 9 The example in Exhibit DMW-5, page 3, as described above, provides an 10 example of this situation. When you compare the example in Exhibit DMW-5, 11 page 2 to the example in Exhibit DMW-5, page 3, you can observe that a 12 deferred tax reserve should exist at the end of year 11 of $263 but in fact none 13 exists in the example in Exhibit DMW-5, page 2. This represents a deficiency in 14 the deferred tax reserves due to flow through accounting. Narragansett has such a 15 deficiency. 16 17 Q. How much in tax benefits has Narragansett "flowed-through" to customers since 18 1972? 19 A. As of December 31, 1998 Narragansett has a deficiency in its deferred tax 20 reserves amounting to approximately $21.7 million. The primary cause of this 21 deficiency is the cost of removal issue that is present in this filing. The 22 deficiency related to cost of removal represents $19.2 million of this amount. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 17 1 To fully reimburse Narragansett for the deficiency in its deferred tax reserves, 2 the amount of the deficiency must be grossed-up for federal income taxes to 3 ensure the proper amount is included in rates. As shown in Exhibit DMW-6, line 4 44, the grossed-up amount of the unfunded deferred taxes results in a revenue 5 requirement of $33.3 million to be collected from customers. The revenue 6 requirement associated with the accumulation of the tax benefits related to cost of 7 removal which Narragansett has "flowed-through" to customers represents 8 approximately $29.5 million of this amount. This deficiency will continue to 9 accumulate until deferred taxes are provided to offset the "flow-through" of tax 10 benefits related to cost of removal expenditures. The remainder of the deficiency 11 in the deferred tax reserves is comprised of other tax deductions previously 12 "flowed-through" to customers. These other tax benefits are partially offset by 13 excess deferred taxes resulting from the change in the federal tax rate from 46% 14 to 35%. Narragansett proposes to recover the $33.3 million deficiency. 15 16 Q. How can the continued accumulation of the deferred tax deficiency be resolved? 17 A. As stated above, allowing the Company to record deferred taxes related to cost of 18 removal upon implementation of the depreciation settlement rates, would stop 19 any further accumulation of the deferred tax reserve deficiency. This deferred 20 tax, based upon the timing difference for cost of removal, will normalize the 21 differences between the book expense for cost of removal and the tax deductions 22 on a prospective basis. In order to implement this deferred tax accounting Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 18 1 treatment, Narragansett needs an assurance from the Commission that it will be 2 allowed to recover the prior flow-through of tax benefits resulting from past 3 regulatory practices. 4 5 Q. How does Narragansett propose to recover the deficiency in its deferred tax 6 reserve? 7 A. There are two methods by which Narragansett could recover the deficiency in its 8 deferred tax reserves. In the first method, assuming that Narragansett is allowed to 9 recover cost of removal, the increase in Narragansett's book depreciation 10 expense would provide for both the recovery of past cost of removal expenditures 11 and the recovery of future cost of removal expenditures. 12 13 The portion of the book expense related to the recovery of the past cost of 14 removal expenditures would be included in depreciation rates without any related 15 tax benefits, because, as discussed above, the tax benefits associated with these 16 expenditures have previously been passed along to customers. When Narragansett 17 had ultimately recovered the full amount of its past cost of removal expenditures, 18 there would no longer be any past book/tax timing difference related to cost of 19 removal and the deficiency in the deferred tax reserve would no longer exist. 20 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 19 1 For the portion of the book expense related to the recovery of future cost of 2 removal expenditures, Narragansett would provide deferred taxes, and thus 3 eliminate any "flow-through" of future tax benefits. 4 5 Narragansett does not advocate using this first method for several reasons. This 6 methodology results in very difficult and complex calculations for separating the 7 amount of book expense related to the past recovery of cost of removal 8 expenditures versus the portion related to the recovery of future cost of removal. 9 Second, in the future as the timing differences begin to reverse themselves, it 10 would be extremely difficult to determine which portion of the reversal relates to 11 deferred taxes for which Narragansett had initially provided a reserve and the 12 portion where the deferred taxes are deficient. 13 14 Q. What is the second method to recover the deficiency in the deferred tax reserve? 15 A. In the second method, Narragansett would be permitted to recover the deficiency 16 in the deferred tax reserves over a fixed number of years. Under this approach, 17 Narragansett would provide deferred taxes on the entire difference between the 18 books and the tax return related to cost of removal on a prospective basis, because 19 the deficiency in the deferred tax reserves would be collected separately. This 20 methodology ultimately achieves full amortization of book and tax timing 21 differences in a much more straight forward fashion. 22 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 20 1 Q. Does Narragansett have a proposal to recover the deficiency? 2 A. Yes. The deficiency in the deferred tax reserves could be alleviated from funds 3 that would otherwise flow through the Companies' transition charge. New 4 England Power Company ("NEP"), the Commission and the Division have 5 reached a settlement agreement in principle regarding NEP's first reconciliation 6 of the Contract Termination Charges ("CTC") billed by NEP to Narragansett. 7 Under the CTC settlement agreement, NEP will flow-through approximately $10 8 million, on a revenue requirement basis, to Narragansett through its reconciliation 9 account in 2000. Rather than reflect the reconciliation in its retail transition 10 charges, Narragansett proposes to retain this amount and apply the $ 10 million 11 against its deficiency in the deferred tax reserves (with the appropriate adjustment 12 for tax effects as described below). In addition, Narragansett proposes to use the 13 same approach for its portion (approximately $2 million) of the resolution of the 14 Hydro-Quebec litigation by NEP. This amount will also be included in NEP's 15 reconciliation for 2000 to Narragansett and would be applied to the deferred tax 16 deficiency. 17 18 Since this approach will only recover a portion of the total amount of the 19 deficiency, Narragansett also proposes to apply any future credits received from 20 future settlements and proceeds from the sales of assets or other reconciliations 21 from NEP's or Montaup's contract termination charges against the deficiency 22 during the rate freeze period. To the extent there is a remaining deferred tax Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 21 1 deficiency, Narragansett requests as part of this proceeding to be allowed to 2 collect the remaining deficiency by amortizing it over a five year period in the 3 first rate case following the end of the distribution rate freeze period. 4 5 Q. If the Commission adopted Narragansett's proposal, what would be the 6 remaining amount of unfunded deferred taxes? 7 A. As discussed above, the pre-tax deficiency in the reserve for deferred taxes 8 amounts to approximately $33.3 million as of December 31, 1998, on a revenue 9 requirement basis. If the Commission adopted Narragansett's proposal to apply 10 NEP's CTC reconciliation against the deficiency, this amount would be reduced 11 by approximately $12 million on a pre-tax basis. Thus the deferred tax deficiency 12 would be reduced to approximately $21.3 million on a pre-tax basis as of 13 December 31, 1998. Since Narragansett is proposing to correct the cost of 14 removal problem on a prospective basis beginning on January 1, 2001, the 15 unfunded deferred tax deficiency will continue to grow until that date. Therefore, 16 the final unfunded deferred tax deficiency will need to be calculated as of 17 December 31, 2000. 18 19 Q. What would the overall rate impact be from correcting the cost of removal issues 20 on a prospective basis? 21 A. As stated above, the overall impact on rates for recovering cost of removal 22 expenditures prospectively would be approximately $3.5 million. This recovery Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 22 1 consists of increased depreciation expense of $1.9 million and the cessation of the 2 "flow-through" of cost of removal benefit of $1.6 million. 3 4 Q. Is it correct to assume this problem is limited to Narragansett? 5 A. Yes. As I will discuss in further detail below, the problem is currently limited to 6 Narragansett and does not exist for BVE and Newport. 7 8 Q. Are there any other issues surrounding cost of removal that the Commission 9 should be informed about? 10 A. Yes. The IRS is currently studying whether to disallow the tax deduction for cost 11 of removal expenditures incurred during the tax year for assets which are replaced 12 by new assets of like kind. The IRS contends that the cost of removal of the old 13 asset should be capitalized as a portion of the cost of the new asset. Cost of 14 removal tax deductions would be included in the amount of tax depreciation over 15 the life of the new asset. However, to the extent the asset is removed from 16 service and is not replaced, the IRS would continue to allow a current year tax 17 deduction for cost of removal expenditures. 18 19 Q. What would the impact be on Narragansett if the IRS disallowed the cost of 20 removal tax deductions? 21 A. If the IRS disallowed the tax deductions related to cost of removal, Narragansett 22 would be required to pay the IRS approximately $6.6 million of taxes related to Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 23 1 cost of removal expenditures for the years 1994 through 1998. Since the IRS has 2 completed its audit of Narragansett through the end of 1993, the only remaining 3 issue with regards to the years 1972 through 1993, is the recovery of the 4 deficiency in the deferred tax reserves. However, since the IRS has not audited 5 1994 through 1998, Narragansett could be required to repay, with interest, any tax 6 deductions related to cost of removal taken during those years. Narragansett 7 estimates the interest on these deductions will amount to $4.3 million. 8 9 Under Narragansett's proposal described above, the $12 million applied against 10 the unfunded deferred tax reserve balance would be assumed by Narragansett, 11 with the permission of the Commission, to apply to the years for which the IRS 12 has yet to complete its audit. Therefore, to the extent the IRS does disallow these 13 tax deductions, Narragansett would reverse a portion of the $12 million it had 14 applied against the amount of the disallowance, excluding any interest. This 15 methodology would allow Narragansett to fully recover the tax benefits it has 16 passed along to customers. 17 18 V. Consolidation of Depreciation Rates 19 Q. Please describe the Companies' proposal with regard to consolidation of 20 depreciation rates. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 24 1 A. Narragansett will be the surviving entity upon completion of the merger. Thus, 2 the Companies propose to use Narragansett's settled depreciation rates, as 3 described earlier in my testimony, for the consolidated entity. 4 5 Q. Please describe why the Companies are proposing to implement Narragansett's 6 depreciation settlement rates for the consolidated entity. 7 A. To correct the cost of removal problem for Narragansett on a prospective basis, 8 the Companies would have to implement depreciation rates which contain a 9 provision to recover both past and future cost of removal expenditures. The 10 depreciation rates from Narragansett's depreciation settlement meet this 11 requirement. 12 13 Additionally, by implementing the settlement depreciation rates, the incremental 14 increase in depreciation expense Narragansett would have realized as a stand 15 alone company would be partially offset by the decrease in deprecation expense 16 BVE and Newport will realize moving from their current depreciation rate, which 17 are higher than Narragansett's current depreciation rates, to the settlement 18 depreciation rates. 19 20 Q. What is the incremental impact of applying Narragansett's depreciation settlement 21 rates to the consolidated entity? Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 25 1 A. As shown in Exhibit DMW-7, page 1, the incremental impact of using the 2 settlement depreciation rates for the consolidated entity results in an increase in 3 depreciation expense of approximately $1.1 million. 4 5 This increase reflects an incremental increase of approximately $1.9 million for 6 Narragansett using the settlement depreciation rates. However as stated above, 7 since BVE's and Newport's depreciation rates are currently higher than those 8 contained in Narragansett's depreciation settlement, BVE and Newport will 9 realize an incremental decrease of approximately $815,000 and $25,000, 10 respectively, upon switching to the settlement rates. Thus, the net incremental 11 increase in deprecation expense is $ 1.1 million for the consolidated company. 12 13 Q. How did you calculate the incremental impact of using Narragansett's settled 14 depreciation rates for the consolidated entity? 15 A. I used the same methodology described above to calculate the incremental 16 impact of applying Narragansett' s settled depreciation rates for the consolidated 17 entity. As shown in Exhibit DMW-7, pages 2 and 3, depreciation expense was 18 calculated for each company's intrastate distribution and general plant based upon 19 their current depreciation rates and then based upon Narragansett's settled 20 depreciation rates. In each case, these rates were applied against the intrastate 21 plant balances as of December 31, 1998. As stated above, the incremental impact 22 of applying Narragansett's settled depreciation rates to the consolidated interstate Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 26 1 plant balances was not calculated since Narragansett, BVE and Newport each 2 operate their transmission facilities under integrated facilities agreements under 3 the jurisdiction of the FERC. Therefore, approval of a consolidated interstate 4 transmission-related depreciation rate must be obtained from the FERC. 5 6 Q. What effect does implementing Narragansett's settlement rates have on the 7 recovery of the cost of removal related items? 8 A. As shown in Exhibit DMW-8, using Narragansett's settlement depreciation rates, 9 the annual revenue requirement to correct the cost of removal issue going forward 10 would be approximately $2.7 million compared to approximately $3.5 million for 11 Narragansett as a stand alone company. 12 13 Q. Previously you discussed the possibility of the IRS disallowing the cost of 14 removal tax deductions. What would the impact be on BVE and Newport if the 15 IRS disallowed the cost of removal tax deductions? 16 A. If the IRS disallows the tax deductions for cost of removal, BVE and Newport 17 would also be required to pay to the IRS approximately $514,000 and $517,000, 18 respectively, for the period 1994 through 1998. BVE and Newport will also be 19 required to provide interest on the disallowed cost of removal which is estimated 20 to be approximately $200,000 and $158,000, respectively. 21 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 27 1 However, since BVE and Newport have been normalizing the book/tax timing 2 differences related to cost of removal over the past several years, if the IRS does 3 disallow these tax deductions, BVE and Newport would simply reverse their 4 respective corresponding deferred tax reserves to offset the impact of the 5 disallowance. Therefore, the impact of the disallowance will be limited to the 6 interest on the cost of removal tax deductions. 7 8 VI. Storm Contingency Fund 9 Q. Please describe how the Storm Contingency fund works. 10 A. Each electric utility operating in Rhode Island has a Storm Contingency Fund 11 which is used to pay for service restoration costs in the event of an extraordinary 12 storm. These reserves are funded by customers through an annual contribution 13 amount which is embedded in rates. The electric utilities also provide interest on 14 the accumulated balances in these funds. 15 16 To ensure that charges to these funds are only for extraordinary storms, the 17 Commission, in Docket No. 2500, set a threshold amount for each utility for 18 which the incremental costs per storm must exceed before service restoration 19 costs can be charged to the fund. Each year, the threshold amount is adjusted by 20 the change in the Consumer Price Index for All Urban (CPI-U) for the previous 21 year. Also, for each storm occurrence, to the extent the overall incremental cost 22 of service restoration exceeds the threshold amount, a deductible is assessed for Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 28 1 each company that is in turn deducted from the incremental storm costs charged 2 to the fund. 3 4 Q. Please describe each company's storm fund. 5 A. Please see Exhibit DMW-9. Narragansett currently collects in rates $641,000 on 6 an annual basis for continuing funding of the storm fund. As of December 31, 7 1998 Narragansett's storm contingency fund had accumulated into a reserve 8 balance of approximately $4.5 million. The threshold amount for Narragansett for 9 the year ended December 31, 1999 is $465,000. The deductible amount for 10 Narragansett is $300,000 for each storm occurrence. 11 12 BVE currently collects in rates $160,000 on an annual basis for continuing 13 funding of the storm fund. As of December 31, 1998 BVE's storm contingency 14 fund had accumulated into a reserve balance of approximately $210,000. The 15 threshold amount for BVE for the year ended December 31, 1999 is 16 approximately $145,000. The deductible amount for BVE is $94,000 for each 17 storm occurrence. 18 19 Newport currently collects in rates $240,000 on an annual basis for continuing 20 funding of the storm fund. As of December 31, 1998 Newport's storm 21 contingency fund had accumulated into a reserve balance of approximately $ 1.0 22 million. The threshold amount for Newport for the year ended December 31, Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 29 1 1999 is approximately $97,000. The deductible amount for Newport is $56,000 2 for each storm occurrence. 3 4 Q. Please describe the Companies' proposal with respect to treatment of the storm 5 contingency funds? 6 A. As shown in Exhibit DMW-9, the Companies propose to combine the current 7 storm contingency fund balances and funding levels. This will result in an 8 accumulated storm contingency fund balance of approximately $5.7 million, as of 9 December 31, 1998 and an annual funding level of $1,041,000. The Companies 10 propose to adopt Narragansett's threshold amount of $465,000 and deductible 11 amount of $300,000 for the combined entity since they are the largest. 12 13 VII. Deferred FAS 106 Cost Recovery 14 Q. Please describe the history of FAS 106. 15 A. In December 1990, the Financial Accounting Standards Board ("FASB") issued 16 Financial Accounting Standard No. 106 ("FAS 106") which required companies 17 to change from the practice of accounting for post-retirement benefits other than 18 pensions ("PBOPs") on a pay-as-you-go basis to an accrual basis. This resulted in 19 an additional incremental or "transition" expense for all companies. 20 21 As a result, the Commission opened a generic docket (Docket No. 2045) 22 regarding the rate making treatment of FAS 106. In that proceeding, the Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 30 1 Commission ordered companies switching from the pay-as-you-go approach to 2 the accrual basis to phase-in the incremental transition expense over a three year 3 period. The phase-in began on January 1, 1993. Companies were then allowed to 4 collect the deferred transition expenses at the end of the three year phase-in 5 period ratably over the next seven years. The recovery of the deferred expenses 6 was combined with the ongoing current year expense and developed into a 7 separate FAS 106 surcharge factor. 8 9 Q. Please describe the recovery of FAS 106 for each company. 10 A. Please see Exhibit DMW- 10. As of the end of 1995 Narragansett has completed 11 the transition to an accrual basis for FAS 106, and accumulated a deferred FAS 12 106 transition expense balance of approximately $4.4 million, related to intrastate 13 operations, to be recovered over the next seven years. Narragansett began 14 recovering these deferred expenses in 1996. 15 16 In November, 1997, as part of its 1998 Rate Adjustment filing, Narragansett 17 sought and received permission to apply overcollections generated by its FAS 18 106 surcharge factor to recover its remaining deferred FAS 106 balance. As a 19 result, as of December 31, 1997, Narragansett was fully recovered with respect to 20 its deferred FAS 106 costs. In that filing Narragansett also adjusted its annual 21 FAS 106 surcharge factor to collect only it's ongoing FAS 106 expenses. 22 Therefore, Narragansett has not been included in Exhibit DMW-10. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 31 1 By the end of 1995, BVE had also completed the transition to an accrual basis for 2 FAS 106, and had accumulated a deferred FAS 106 transition expense balance of 3 approximately $1.0 million to be recovered over the next seven years. BVE is 4 currently collecting approximately $145,000 in base rates annually to recover its 5 deferred FAS 106 costs. As of December 31, 1998, BVE's remaining deferred 6 FAS 106 balance was approximately $581,000. It is anticipated that at the 7 current levels, the recovery of deferred FAS 106 costs should be completed 8 during 2002. 9 10 Newport had completed the transition to an accrual basis for FAS 106 by the end 11 of 1995, and it too had an accumulated a deferred FAS 106 transition expense 12 balance of approximately $1.2 million to be recovered over the next seven years. 13 Newport is currently collecting approximately $172,000 in base rates annually to 14 recover its deferred FAS 106 costs. As of December 31, 1998, Newport's 15 remaining deferred FAS 106 balance was approximately $686,000. It is 16 anticipated that at the current levels, the recovery of deferred FAS 106 costs 17 should be completed during 2002. 18 19 Q. What are the Companies proposing with regard to deferred FAS 106 expenses? 20 A. As shown on Exhibit DMW-10, the Companies propose to combine the deferred 21 FAS 106 balances for BVE and Newport on the books of the combined entity. 22 The combined balance will be approximately $1.3 million. The Companies also Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 32 1 propose to combine the annual recovery levels for deferred FAS 106 factors 2 currently being charged by BVE and Newport until the recovery of the deferred 3 FAS 106 costs is completed, which the Company anticipates will be during the 4 year 2002. Thus, the annual recovery level of deferred FAS 106 costs for the 5 combined entity will amount to approximately $317,000. Upon completion of 6 the recovery of the deferred FAS 106 costs, this amount will be used to offset 7 other cost increases during the rate freeze period. 8 9 VIII. Hazardous Waste Cost Recovery 10 Q. Could you please describe the accounting issues related to hazardous waste? 11 A. BVE has recorded a regulatory asset for expenditures associated with hazardous 12 waste site remediation that have yet to be recovered from customers. As of 13 December 31, 1998, BVE had recorded on its books a deferred asset amounting 14 to approximately $1.5 million. As part of the settlement in RIPUC Docket No. 15 2016, BVE began recovering in rates $333,426 annually for hazardous waste site 16 remediation costs. However, for accounting purposes, BVE is amortizing 17 approximately $878,000 annually. At the present amortization level, BVE 18 anticipates that the deferred asset will be fully amortized during the year 2000. 19 20 In addition to the hazardous waste costs described above, BVE currently has 21 litigation pending on the issue of responsibility for certain remediation costs 22 associated with a manufactured gas site located on Mendon Road in Attleboro, Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 33 1 Massachusetts. In order to prevent the further accumulation of interest as a result 2 of a U. S. District court judgement that was appealed, BVE entered into an 3 escrow agreement with the Commonwealth of Massachusetts in January, 1995. 4 Under the terms of an escrow agreement arising out of the litigation, BVE 5 deposited $5.9 million, including $3.6 million of interest, into an interest bearing 6 escrow account which remains in the account while litigation continues. These 7 amounts have been recorded on BVE's books as a deferred asset. 8 9 Newport Electric does not have a hazardous waste regulatory asset recorded on its 10 books. Narragansett has recorded a provision on its books for its potential 11 liability in the remediation of a hazardous waste site. Narragansett is not currently 12 recovering these costs in rates. 13 14 Q. What are the Companies proposing with regard to recovery of the hazardous 15 waste expenditures? 16 A. The Companies propose to include BVE's hazardous waste regulatory asset on 17 the books of the combined entity and continue to recover the current amount 18 being collected in rates for BVE. The Companies propose to continue to collect 19 this amount until BVE's deferred hazardous waste cost recovery has been 20 completed. 21 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Testimony of D.M. Webster Page 34 1 The recovery of any future liabilities regarding the remediation of hazardous 2 waste sites would be addressed as part of a future rate proceeding when the extent 3 of the Companies' liability, if any, is known. As described in the testimony of 4 Mr. Jesanis, remediation costs for hazardous waste site is one of the exogenous 5 factors proposed in the Companies' distribution rate freeze plan. 6 7 IX. Conclusion 8 Q. Does this conclude your testimony? 9 A. Yes, it does.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibits of David M. Webster Exhibit DMW-1 Settlement on Depreciation Expense R.I.P.U.C. No. 2290 Exhibit DMW-2 Incremental Impact of Narragansett Depreciation Settlement to Correct Cost Removal Exhibit DMW-3 Cessation of Cost of Removal Flow-Through Benefit Exhibit DMW-4 Summary of Revenue Requirement for Cost of Removal before Consolidation Exhibit DMW-5 Book/Tax Timing Differences Related to Cost of Removal Exhibit DMW-6 Unfunded Deferred Federal Income Taxes Exhibit DMW-7 Incremental Impact of Narragansett Depreciation Settlement Exhibit DMW-8 Summary of Revenue Requirement for Cost of Removal after Consolidation Exhibit DMW-9 Summary of Storm Contingency Funds Exhibit DMW-10 Summary of Deferred FAS 106 Costs Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-1 Exhibit DMW-1 Settlement on Depreciation Expenses R.I.P.U.C. No. 2290 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ____ Exhibit DMW-1 Page 1 of 5 STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS PUBLIC UTILITIES COMMISSION - -------------------------------------------------- ) IN RE: NARRAGANSETT ELECTRIC COMPANY: ) Docket 2290 REQUEST FOR RATE INCREASE ) - --------------------------------------------------) SETTLEMENT ON DEPRECIATION EXPENSE I. Introduction On November 14, 1995, the Public Utilities Commission (Commission) approved settlement agreements (dated September 8, 1995 and September 14, 1995, as modified by a Supplemental Settlement dated October 11, 1995 - together, the "Settlement") between The Narragansett Electric Company (Narragansett or the Company), the Energy Council of Rhode island (TEC-RI), and the Division of Public Utilities and Carriers (Division). The Settlement resolved all the outstanding issues in Docket 2290 except for the appropriate depreciation rates to be used for Narragansett. As part of the Settlement, the parties agreed to complete, by January 31, 1996, a review of the depreciation study filed by Narragansett in the rebuttal phase of Docket 2290. The Settlement further states that if the parties reach agreement on the appropriate depreciation rates to be used for Narragansett, the rates may be submitted by Narragansett, without opposition by the Division, in Narragansett's next base rate proceeding. This Settlement reflects such an agreement by the Division and Narragansett. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ____ Exhibit DMW-1 Page 2 of 5 II. Stipulation and Settlement After extensive discussion and review by experts retained by both the Company and the Division, the Parties have reached agreement on the appropriate depreciation rate methods to be used for Narragansett without opposition by the Division, in Narragansett's next base rate proceeding filed pursuant to ss. 39-3-11, as follows: (A) Narragansett shall change from the Broad Group Whole Life Method of depreciation to the Vintage Group Remaining Life Method of depreciation. These changes are recommended to better achieve the goals and objectives of depreciation accounting through the use of a procedure that distinguishes service lines among vintages and provides cost apportionment over the estimated weighted average remaining life of a rate category. (B) For Transmission Plant, the lives shall be as set forth in Attachment A Projection Life-Transmission Plant (the same as proposed earlier in Docket 2290). (C) For Distribution Plant, Narragansett shall use the same lives as currently prescribed and specified on Attachment A. (D) For General Plant, the life for account 390, (Structures and Improvements), shall be reduced from 50 years to 40 years. For other General accounts, Narragansett shall use an amortization period of 20 years. 2 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ____ Exhibit DMW-1 Page 3 of 5 (E) For Salvage, transmission salvage shall be set at -20%. Distribution salvage shall be set at -10%. III. Miscellaneous Provisions (A) Unless expressly stated herein, the making of this settlement establishes no principles and shall not be deemed to foreclose any party from making any contention in any other proceeding or investigation. (B) Unless expressly stated herein, the acceptance of this settlement by the Commission shall not in any respect constitute a determination by the Commission as to the merits of any issue in any rate proceeding for this Company or another. (C) This settlement is the product of settlement negotiations. The content of those negotiations is privileged and all offers of settlement shall be without prejudice to the position of any party. (D) This settlement is submitted on the condition that it be approved in full by the Commission, and on the further condition that if the Commission does not approve it in its entirety it shall be deemed withdrawn and shall not constitute a part of the record in any proceeding or used for any purpose. (E) The Attachments referenced in and attached to this settlement shall be deemed an integral part hereof. In the event that any inconsistency exists between the provisions of this settlement and the 3 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ____ Exhibit DMW-1 Page 4 of 5 Attachment hereto, the provisions of this settlement shall supersede the provision of any such Attachment. IV. Conclusion WHEREFORE, the Division and Narragansett respectfully request the Commission approve this Settlement to resolve all depreciation rate issues in Docket 2290. 4 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ____ Exhibit DMW-1 Page 5 of 5 DATED AT PROVIDENCE, this 9th day of May, 1996. THE DIVISION OF PUBLIC THE NARRAGANSETT UTILITIES AND CARRIERS ELECTRIC COMPANY /s/ Patricia M. French /s/ Craig L. Eaton - ----------------------------- ---------------------------- Patricia M. French Esq. Craig L. Eaton, Esq. Assistant Attorney General Thomas G. Robinson, Esq. 150 South Main Street 280 Melrose Street Providence, RI 02903 Providence, RI 02907 (401) 274-4400 (401) 784-7526 5
Attachment A Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ___ Exhibit DMW-1 Page 5 of 5 NARRAGANSETT ELECTRIC COMPANY SETTLEMENT OF DEPRECIATION RATES Depreciation System Current: Straight line method, broad group procedure, whole life technique. Settled: Straight line method. vintage group procedure, remaining life technique for all but accounts 391 through 398, which are to follow amortization accounting. Proposed Protection Life - Transmission Plant in Rate Account Current Filing Settlement 352.00 Structures and Improvements 60.00 50.00 50.00 353.00 Station Equipment 35.00 55.00 55.00 354.00 Towers and Fixtures 65.00 50.00 50.00 355.00 Poles and Fixtures 40.00 45.00 45.00 356.00 Overhead Conductors and Devices 45.00 40.00 40.00 357.00 Underground Conduit 75.00 50.00 50.00 358.00 Underground Conductors and Devices 50.00 40.00 40.00 359.00 Roads and Trails 65.00 60.00 60.00 Estimated Annualized 1995 Accrual ($000's) $1,078 $859 $859 Projection Life - Distribution Plant 361.00 Structures and Improvements 50.00 40.00 50.00 362.00 Station Equipment 35.00 45.00 35.00 364.00 Poles Towers and Fixtures 25.00 32.00 25.00 365.00 Overhead Conductors and Devices 35.00 33.00 35.00 366.00 Underground Conduit 60.00 50.00 60.00 367.00 Underground Conductors and Devices 45.00 35.00 45.00 368.00 Line Transformers 25.00 27.00 25.00 369.00 Services 25.00 35.00 25.00 370.00 Meters 30.00 27.00 30.00 371.00 Installation on Customer Premises 35.00 20.00 35.00 372.00 Leased Property on Customer Premises 15.00 15.00 15.00 373.00 Street Lighting and Signal Systems 25.00 17.00 25.00 Estimated Annualized 1995 Accrual ($000's) $12.776 $13,703 S12,706 Projection Life - General Plant 390.00 Structures and Improvements 50.00 40.00 40.00 391.00 Office Furniture and Equipment 25.00 15.00 20.00 393.00 Stores Equipment 35.00 15.00 20.00 394.00 Tools Shop and Garage Equipment 30.00 15.00 20.00 395.00 Laboratory Equipment 25.00 15.00 20.00 397.00 Communication Equipment 10.00 15.00 20.00 398.00 Miscellaneous Equipment 25.00 15.00 20.00 Estimated Annualized 1995 Accrual ($000's) $420 $542 $495 Salvage 108.50 Transmission 0.00 -20.0% -20.0% 108.60 Distribution 0.00 -15.0% -10.0% 108.70 General 0.00 -5.0% -5.0% Estimated Annualized 1995 Accrual ($000's) $0 $2,326 $1,626 Total Estimated Annualized 1995 Accrual ($000's)* $14,274 $17,430 $15,686 * Estimated annualized accruals are based on 1994 electric plant in service amounts in FERC account 101.
6 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-2 Exhibit DMW-2 Incremental Impact of Narragansett Depreciation Settlement to Correct Cost Removal
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-2 Page 1 of 4 THE NARRAGANSETT ELECTRIC COMPANY Incremental Impact of Narragansett Depreciation Settlement 1 Depreciation Expense Depreciation Expense Incremental Impact 2 Applying Depreciation Applying Current of Settlement 3 Settlement Rates Depreciation Rates Depreciation Rates 4 (a) (b) (c)=(a)-(b) 5 --- --- ----------- 6 Distribution Plant Depreciation $19,920,336 1/ $18,037,140 2/ $1,883,196 7 8 General Plant Depreciation 725,038 3/ 720,610 4/ 4,428 ------- ------- ----- 9 10 Total Depreciation $20,645,374 $18,757,750 $1,887,624 ----------- ----------- ----------
Notes: 1/ Exhibit DMW-2, page 2, line 29, column (e). 2/ Exhibit DMW-2, page 2, line 29, column (b). 3/ Exhibit DMW-2, page 3, line 25, column (e). 4/ Exhibit DMW-2, page 3, line 25, column (b).
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ________ Exhibit DMW-2 Page 2 of 4 THE NARRAGANSETT ELECTRIC COMPANY Change in Distribution Plant Depreciation to Implement Depreciation Settlement Narragansett Depreciation Settlement PUC Narr. Current ------------------------------------ Account Rates Investment Negative Salvage Total Rate ------- ----- ---------- ---------------- ---------- 1 361 2.00% 1.73% 0.37% 2.10% 2 362 2.86% 2.60% 0.37% 2.97% 3 364 4.00% 3.80% 0.37% 4.17% 4 365 2.86% 2.91% 0.37% 3.28% 5 366 1.67% 1.68% 0.37% 2.05% 6 367 2.22% 2.21% 0.37% 2.58% 7 368 4.00% 4.07% 0.37% 4.44% 8 369 4.00% 3.89% 0.37% 4.26% 9 370 3.33% 3.41% 0.37% 3.78% 10 371 2.87% 1.60% 0.37% 1.97% 11 373 4.00% 4.25% 0.37% 4.62% 12 13 The Narragansett Electric Company Narragansett Depreciation Settlement 14 12/31/98 Depreciation ------------------------------------ 15 Plant at Current Investment Negative 16 Depreciable Plant Balance I/ Rates Accrual Salvage Total 17 PUC Account (a) (b) (c) (d) (e) ----------- --- --- --- --- --- 18 361 $2,082,573 $41,651 $36,029 $7,706 $43,735 19 362 79,464,967 2,272,698 2,066,089 294,020 2,360,109 20 364 85,780,758 3,431,230 3,259,669 317,389 3,577,058 21 365 139,893,298 4,000,948 4,070,895 517,605 4,588,500 22 366 29,089,158 485,789 488,698 107,630 596,328 23 367 54,221,858 1,203,725 1,198,303 200,621 1,398,924 24 368 75,907,086 3,036,283 3,089,418 280,856 3,370,274 25 369 31,202,210 1,248,088 1,213,766 115,448 1,329,214 26 370 29,609,146 985,985 1,009,672 109,554 1,119,226 27 371 3,037 87 49 11 60 28 373 33,266,398 1,330,656 1,413,822 123,086 1,536,908 --------- --------- ------- --------- 29 Total Narragansett $18,037,140 $17,846,410 $2,073,926 $19,920,336 ----------- ----------- ---------- -----------
Notes: 1/ Exhibit DMW-2, page 4, line 18-26, column (d)
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ________ Exhibit DMW-2 Page 3 of 4 THE NARRAGANSETT ELECTRIC COMPANY Change in General Plant Depreciation to Implement Depreciation Settlement Narragansett Depreciation Settlement PUC Narr. Current ------------------------------------ Account Rates Investment Negative Salvage Total Rate ------- ----- ---------- ---------------- ---------- 1 390 2.00% 2.65% 0.17% 2.82% 2 391 2/ 4.00% 5.00% 0.00% 5.00% 3 393 2/ 2.86% 5.00% 0.00% 5.00% 4 394 2/ 3.33% 5.00% 0.00% 5.00% 5 395 2/ 4.00% 5.00% 0.00% 5.00% 6 397 2/ 10.00% 5.00% 0.00% 5.00% 7 398 2/ 4.00% 5.00% 0.00% 5.00% 8 9 The Narragansett Electric Company Narragansett Depreciation Settlement 10 12/31/98 Depreciation ------------------------------------ 11 Plant at Current Investment Negative 12 Depreciable Plant Balance 1/ Rates Accrual Salvage Total 13 PUC Account (a) (b) (c) (d) (e) ----------- --- --- --- --- --- 14 390 $12,181,900 $243,638 $322,820 $20,709 $343,529 15 391 553,326 22,133 27,666 0 27,666 16 393 441,611 12,630 22,081 0 22,081 17 394 2,113,557 70,381 105,678 0 105,678 18 395 944,498 37,780 47,225 0 47,225 19 397 3,182,694 318,269 159,135 0 159,135 20 398 394,474 15,779 19,724 0 19,724 ------ ------ - ------ 21 Total Narragansett $720,610 $704,329 $20,709 $725,038 -------- -------- ------- --------
Notes: 1/ Exhibit DMW-2, page 4, Lines 2-14, column (d) 2/ Amortization Accounts equivalent to 5.0% depreciation rate.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ________ Exhibit DMW-2 Page 4 of 4 THE NARRAGANSETT ELECTRIC COMPANY Depreciable Plant Balances As of December 31, 1998 1/ Interstate Intrastate --------------------------------------------------- Percent of Total Amount Amount 1 Distribution Plant: (a) (b) (c)=(a) times (b) (d)= (a) - (c) ------------------ --- --- ----------------- -------------- 2 Structures and Improvements 361 $2,101,911 0.92% $19,338 $2,082,573 3 Station Equipment 362 80,202,833 0.92% 737,866 79,464,967 4 Poles, Towers and Fixtures 364 86,577,269 0.92% 796,511 85,780,758 5 Overhead Conductors 365 141,192,267 0.92% 1,298,969 139,893,298 6 Underground Conduit 366 29,359,263 0.92% 270,105 29,089,158 7 Underground Conductors 367 54,725,331 0.92% 503,473 54,221,858 8 Line Transformers 368 76,611,916 0.92% 704,830 75,907,086 9 Services 369 31,491,936 0.92% 289,726 31,202,210 10 Meters 370 29,884,080 0.92% 274,934 29,609,146 11 Installation on Cust. Premises 371 3,065 0.92% 28 3,037 12 Street lights 373 33,575,291 0.92% 308,893 33,266,398 ---------- ------- ---------- 13 Total $565,725,162 $5,204,673 $560,520,489 ------------ ---------- ------------ 14 15 General Plant: 16 Structures and Improvements 390 $15,140,318 19.54% $2,958,418 $12,181,900 17 Office Furniture and Equip. 391 687,703 19.54% 134,377 553,326 18 Stores Equipment 393 548,858 19.54% 107,247 441,611 19 Tools, Shop and Garage 394 2,626,842 19.54% 513,285 2,113,557 20 Laboratory Equip. 395 1,173,873 19.54% 229,375 944,498 21 Communication Equip. 397 3,955,623 19.54% 772,929 3,182,694 22 Miscellaneous Equipment 398 490,273 19.54% 95,799 394,474 ------- ------ ------- 23 Total $24,623,490 $4,811,430 $19,812,060 ---------- ---------- ----------- 24 25 Grand Total $590,348,652 $10,016,103 $580,332,549 ------------ ----------- ------------
Notes: 1/ Narragansett Electric's 1998 FERC Form 1, Page 207, Column (g), Lines 56-80. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-3 Exhibit DMW-3 Cessation of Cost of Removal Flow - Through Benefit Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ___ Exhibit DMW-3 Page 1 of 1 The Narragansett Electric Company Cessation of cost of Removal Flow-Through Benefit (Thousands of Dollars) 1. Calculation of 3 Year Average cost of Removal Tax Deduction: 2. 3. Total Interstate Intrastate 4. Year Company Plant Plant 5. 1998 $2,571 $373 $2,198 1/ 6. 1997 $4,439 $1,447 $2,992 1/ 7. 1996 $10,584 $6,753 $3,831 1/ ------ 8. 9. 3 Year Average $3,007 2/ 10. 11. Tax on Cost of Removal Dedution $1,052 3/ 12. 13. Revenue Requirement on cost of Removal 14. Flow-Through $1,618 4/ ------ Notes: 1/ Actual cost of removal Deduction per Tax Returns. 2/ Average of Intrastate cost of Removal Tax Deductions on Lines 5,6&7. 3/ Line 9 times Federal Income Tax Rate (35%). 4/ Line 11 divided by (1-.35) to Reflect Revenue Requirement. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-4 Exhibit DMW-4 Summary of Revenue Requirement for Cost of Removal before Consolidation Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ___ Exhibit DMW-4 Page 1 of 1 The Narragansett Electric Company Summary of Revenue Requirement for Cost of Removal (Thousands of Dollars) 1 Increase in Depreciation Expenses to Reflect 2 Narragansett Depreciation Settlement $1,888 1/ 3 4 5 Cessation of Cost of Removal Flow-Though Benefit $1,618 2/ 6 ------ 7 8 Total Increase in Narragansett Revenue Requirement $3,506 3/ ------ Notes: - ----- 1/ Exhibit DMW-2, page 1, line 10, column (c). 2/ Exhibit DMW-3, page 1, line 14. 3/ Sum of Lines 2 and Line 5. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-5 Exhibit DMW-5 Book/Tax Timing Differences Related to Cost of Removal
Narrangsett Electric BVE/Newport Electric R.I.P.U.C. No. _____ Exhibit DMW-5 Page 1 of 3 The Narragansett Electric Company Box/Tax Timing Differences Related to Cost of Removal 1 Assumptions: 2 Asset # 1 Installed Costs $20,000 3 Asset Depreciable Life 10 yrs. 4 Estimated Cost of Removal $1,000 5 6 7 8 9 Book Depreciation Tax Deductions Book/Tax Accumulated 10 Asset Cost of Asset Cost of Timing Deferred Deferred Tax 11 Depreciation Removal Total Depreciation Removal Total Difference Taxes Reserve 12 (a) 1/ (b) 2/ (c)=(a)+(b) (d) 3/ (e) 4/ (f)=(d)+(e) (g)=(f)-(c) (h) 5/ (i) 6/ 13 Year 1 $2,000 $100 $2,100 $2,000 $0 $2,000 ($100) $35 $35 14 Year 2 2,000 100 2,100 2,000 0 2,000 (100) 35 70 15 Year 3 2,000 100 2,100 2,000 0 2,000 (100) 35 105 16 Year 4 2,000 100 2,100 2,000 0 2,000 (100) 35 140 17 Year 5 2,000 100 2,100 2,000 0 2,000 (100) 35 175 18 Year 6 2,000 100 2,100 2,000 0 2,000 (100) 35 210 19 Year 7 2,000 100 2,100 2,000 0 2,000 (100) 35 245 20 Year 8 2,000 100 2,100 2,000 0 2,000 (100) 35 280 21 Year 9 2,000 100 2,100 2,000 0 2,000 (100) 35 315 22 Year 10 2,000 100 2,100 2,000 0 2,000 (100) 35 350 23 Year 11 1,000 1,000 1,000 (350) 0 24 25 Totals $20,000 $1,000 $21,000 $20,000 $1,000 $21,000 $0 $0 1 Assumptions: 2 Asset # 1 Installed Costs $20,000s 3 Asset Depreciable Life 10 yrs. 4 Estimated Cost of Removal $1,000l 5 6 7 8 9 Cost of Service 10 Depreciation Current Deferred 11 Expense FIT FIT Total 12 (j) = (c) (k) 7/ (l) = (h) (m)=(j)+(k)+(l) 13 14 Year 1 $2,100 ($35) $35 $2,100 15 Year 2 2,100 ($35) 35 2,100 16 Year 3 2,100 ($35) 35 2,100 17 Year 4 2,100 ($35) 35 2,100 18 Year 5 2,100 ($35) 35 2,100 19 Year 6 2,100 ($35) 35 2,100 20 Year 7 2,100 ($35) 35 2,100 21 Year 8 2,100 ($35) 35 2,100 22 Year 9 2,100 ($35) 35 2,100 23 Year 10 2,100 ($35) 35 2,100 24 Year 11 $350 (350) 0 25 Totals $21,000 $0 $0 $21,000 Notes: 1/ Column (a) equals depreciation of installed property over ten years. 2/ Column (b) equals cost of removal on installed property over ten years. 3/ Column (d) equals depreciation of installed property over ten years (column (a)). 4/ Column (e) reflects tax deduction in year cost of removal expenditures incurred. 5/ Column (h) equals column (g) times federal income tax rate (35%). 6/ Column (i) equals summation of column (h). 7/ Column (k) equals column (g) times 35% divided by 65% minus column (h) times 35% divided by 65%.
Narrangsett Electric BVE/Newport Electric R.I.P.U.C. No. _____ Exhibit DMW-5 Page 2 of 3 The Narragansett Electric Company Box/Tax Timing Differences Related to Cost of Removal 1 Assumptions: Asset #1 Asset #2 2 Installed Date Year 1 Year 11 3 Installed Cost $20,000 $30,000 4 Asset Depreciable Life 10 yrs. 10 yrs. 5 Estimated Cost of Removal $1,000 $l,500 6 7 8 9 10 Book Depreciation Tax Deductions Book/Tax Accumulated 11 Asset Cost of Asset Cost of Timing Deferred Deferred Tax 12 Depreciation Removal Total Depreciation Removal Total Difference Taxes Reserve 13 (a) 1/ (b) 2/ (c)=(a)+(b) (d) 3/ (e) 4/ (f)=(d)+(e) (g)=(f)-(c) (h) 5/ (i) 6/ 14 Year 1 $2,000 $0 $2,000 $2,000 $0 $2,000 $0 $0 $0 15 Year 2 2,000 0 2,000 2,000 0 2,000 0 0 0 16 Year 3 2,000 0 2,000 2,000 0 2,000 0 0 0 17 Year 4 2,000 0 2,000 2,000 0 2,000 0 0 0 18 Year 5 2,000 0 2,000 2,000 0 2,000 0 0 0 19 Year 6 2,000 0 2,000 2,000 0 2,000 0 0 0 20 Year 7 2,000 0 2,000 2,000 0 2,000 0 0 0 21 Year 8 2,000 0 2,000 2,000 0 2,000 0 0 0 22 Year 9 2,000 0 2,000 2,000 0 2,000 0 0 0 23 Year 10 2,000 0 2,000 2,000 0 2,000 0 0 0 24 Year 11 3,000 250 3,250 3,000 1,000 4,000 (750) 0 0 25 Year 12 3,000 250 3,250 3,000 0 3,000 250 0 0 26 Year 13 3,000 250 3,250 3,000 0 3,000 250 0 0 27 Year 14 3,000 250 3,250 3,000 0 3,000 250 0 0 28 Year 15 3,000 250 3,250 3,000 0 3,000 250 0 0 29 Year 16 3,000 250 3,250 3,000 0 3,000 250 0 0 30 Year 17 3,000 250 3,250 3,000 0 3,000 250 0 0 31 Year 18 3,000 250 3,250 3,000 0 3,000 250 0 0 32 Year 19 3,000 250 3,250 3,000 0 3,000 250 0 0 33 Year 20 3,000 250 3,250 3,000 0 3,000 250 0 0 34 Year 21 1,500 1,500 (1,500) 0 0 35 36 Totals $50,000 $2,500 $52,500 $50,000 $2,500 $52,500 $0 $0 $0 1 Assumptions: Asset #1 Asset #2 2 Installed Date Year 1 Year 11 3 Installed Cost $20,000 $30,000 4 Asset Depreciable Life 10 yrs. 10 yrs. 5 Estimated Cost of Removal $1,000 $l,500 6 7 8 9 10 Cost of Service 11 ---------------------------------------------------- 12 Depreciation Current Deferred 13 Expense FIT FIT Total (j)=(c) (k) 7/ (l)=(h) (m)=(j)+(k)+(l) 14 Year 1 $2,000 $0 $0 $2,000 15 Year 2 2,000 0 0 2,000 16 Year 3 2,000 0 0 2,000 17 Year 4 2,000 0 0 2,000 18 Year 5 2,000 0 0 2,000 19 Year 6 2,000 0 0 2,000 20 Year 7 2,000 0 0 2,000 21 Year 8 2,000 0 0 2,000 22 Year 9 2,000 0 0 2,000 23 Year 10 2,000 0 0 2,000 24 Year 11 3,250 (404) 0 2,846 25 Year 12 3,250 135 0 3,385 26 Year 13 3,250 135 0 3,385 27 Year 14 3,250 135 0 3,385 28 Year 15 3,250 135 0 3,385 29 Year 16 3,250 135 0 3,385 30 Year 17 3,250 135 0 3,385 31 Year 18 3,250 135 0 3,385 32 Year 19 3,250 135 0 3,385 33 Year 20 3,250 135 0 3,385 34 Year 21 0 (808) 0 (808) 35 36 Totals $52,500 $0 $0 $52,500 Notes: 1/ Column (a) equals depreciation of installed property over ten years. 2/ Column (b) equals cost of removal on installed property over ten years. 3/ Column (d) equals depreciation of installed property over ten years (Column (a)). 4/ Column (e) reflects tax deduction in year cost of removal expenditures incurred. 5/ Column (h) reflects the absence of deferred taxes in this example. 6/ Column (i) equals summation of column (h). 7/ Column (k) equals column (g) times 35% divided by 65% minus column (h) times 35% divided by 65%.
Narrangsett Electric BVE/Newport Electric R.I.P.U.C. No. _____ Exhibit DMW-5 Page 3 of 3 The Narragansett Electric Company Box/Tax Timing Differences Related to Cost of Removal 1 Assumptions: Asset #1 Asset #2 2 Installed Date Year 1 Year 11 3 Installed Cost $20,000 $30,000 4 Asset Depreciable Life 10 yrs. 10 yrs. 5 Estimated Cost of Removal $1,000 $l,500 6 7 8 10 Book Depreciation Tax Deductions Book/Tax Accumulated 11 Asset Cost of Asset Cost of Timing Deferred Deferred Tax 12 Depreciation Removal Total Depreciation Removal Total Difference Taxes Reserve 13 (a) 1/ (b) 2/ (c)=(a)+(b) (d) 3/ (e) 4/ (f)=(d)+(e) (g)= (f)-(c) (h) 5/ (i) 6/ 14 Year 1 $2,000 $0 $2,000 $2,000 $0 $2,000 $0 $0 $0 15 Year 2 2,000 0 2,000 2,000 0 2,000 0 0 0 16 Year 3 2,000 0 2,000 2,000 0 2,000 0 0 0 17 Year 4 2,000 0 2,000 2,000 0 2,000 0 0 0 18 Year 5 2,000 0 2,000 2,000 0 2,000 0 0 0 19 Year 6 2,000 0 2,000 2,000 0 2,000 0 0 0 20 Year 7 2,000 0 2,000 2,000 0 2,000 0 0 0 21 Year 8 2,000 0 2,000 2,000 0 2,000 0 0 0 22 Year 9 2,000 0 2,000 2,000 0 2,000 0 0 0 23 Year 10 2,000 0 2,000 2,000 0 2,000 0 0 0 24 Year 11 3,000 250 3,250 3,000 1,000 4,000 (750) 263 263 25 Year 12 3,000 250 3,250 3,000 0 3,000 250 (88) 175 26 Year 13 3,000 250 3,250 3,000 0 3,000 250 (88) 88 27 Year 14 3,000 250 3,250 3,000 0 3,000 250 (88) 0 28 Year 15 3,000 250 3,250 3,000 0 3,000 250 (88) (88) 29 Year 16 3,000 250 3,250 3,000 0 3,000 250 (88) (175) 30 Year 17 3,000 250 3,250 3,000 0 3,000 250 (88) (263) 31 Year 18 3,000 250 3,250 3,000 0 3,000 250 (88) (350) 32 Year 19 3,000 250 3,250 3,000 0 3,000 250 (88) (438) 33 Year 20 3,000 250 3,250 3,000 0 3,000 250 (88) (525) 34 Year 21 1,500 1,500 (1,500) 525 $0 35 36 Totals $50,000 $2,500 $52,500 $50,000 $2,500 $52,500 $0 $0 1 Assumptions: Asset #1 Asset #2 2 Installed Date Year 1 Year 11 3 Installed Cost $20,000 $30,000 4 Asset Depreciable Life 10 yrs. 10 yrs. 5 Estimated Cost of Removal $1,000 $l,500 6 7 8 9 10 Cost of Service 11 Depreciation Current Deferred 12 Expense FIT FIT Total 13 (j)=(c) (k)7/ (l)=(h) (m)=(j)+(k)+(l) 14 Year 1 $2,000 $0 $0 $2,000 15 Year 2 2,000 0 0 2,000 16 Year 3 2,000 0 0 2,000 17 Year 4 2,000 0 0 2,000 18 Year 5 2,000 0 0 2,000 19 Year 6 2,000 0 0 2,000 20 Year 7 2,000 0 0 2,000 21 Year 8 2,000 0 0 2,000 22 Year 9 2,000 0 0 2,000 23 Year 10 2,000 0 0 2,000 24 Year 11 3,250 (263) 263 3,250 25 Year 12 3,250 88 (88) 3,250 26 Year 13 3,250 88 (88) 3,250 27 Year 14 3,250 88 (88) 3,250 28 Year 15 3,250 88 (88) 3,250 29 Year 16 3,250 88 (88) 3,250 30 Year 17 3,250 88 (88) 3,250 31 Year 18 3,250 88 (88) 3,250 32 Year 19 3,250 88 (88) 3,250 33 Year 20 3,250 88 (88) 3,250 34 Year 21 0 (525) 525 0 35 36 Totals $52,500 $0 $0 $52,500 Notes: 1/ Column (a) equals depreciation of installed property over ten years. 2/ Column (b) equals cost of removal on installed property over ten years. 3/ Column (d) equals depreciation of installed property over ten years (Column (a)). 4/ Column (e) reflects tax deduction in year cost of removal expenditures incurred. 5/ Column (h) equals column (g) times federal tax rate (35%). 6/ Column (i) equals summation of column (h). 7/ Column (k) equals column (g) times 35% divided by 65% minus column (h) times 35% divided by 65%.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-6 Exhibit DMW-6 Unfunded Deferred Federal Income Taxes Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ____ Exhibit DMW-6 Page 1 of 1 THE NARRAGANSETT ELECTRIC COMPANY Unfunded Deferred Federal Income Taxes ($000s) 1 Book Depreciable Plant at 12/31/98 $713,405 2 Less: Accumulated Depreciation (209,159) 3 Permanent book/tax differences 4 Equity AFUDC (1,489) 5 ITC Basis Adjustment (1,689) ------- 6 Adjusted net plant per books $501,068 7 8 Tax Depreciable Plant 701,399 9 Less: Accumulated depreciation (406,543) -------- 10 Adjusted net tax plant 294,856 11 12 Cumulative Timing Difference 206,212 13 Current Tax Rate 35.0% ----- 14 15 Total Cumulative Deferred Federal Tax Liability $72,174 16 17 Property Related Deferred FIT Reserves per Books at 12/31/98: 18 19 Contributions in Aid of Construction ($2,408) 20 Liberalized Depreciation 55,012 21 Construction Interest (1,166) 22 Construction - Other (11) 23 Cost of Removal 2,591 24 ACRS Retirements 1,560 25 Transfer Accounts (1,340) 26 Unfunded Tax Liability 38 -- 27 Total $54,275 ------- 28 29 Unfunded Property-Related Deferred $17,899 FIT Reserves 30 31 Non-Property Related Deferred FIT Reserves per Books at 12/31/98: 32 33 Unfunded/ Bal. Per Bal. @ (Excess) Books 35% -------- 34 Deferred Tax Assets (14,694) (15,360) (666) 35 Deferred Tax Liabilities 10,287 14,751 4,464 36 37 38 Unfunded Non Property-Related Deferred FIT Reserves 3,798 39 ----- 40 Total Unfunded Deferred FIT Reserves $21,697 ------- 41 42 Tax Gross-Up Factor 1/ 1.5382 ------ 43 44 Total Revenue Retirement for Unfunded Deferred FIT Reserves $33,374 ------- 1/ For Rhode Island: 1 plus Federal Income Tax (FIT) Rate divided by 1 minus FIT rate. (1+(35%/(1-35%))). Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-7 Exhibit DMW-7 Incremental Impact of Narragansett Depreciation Settlement
Narrangansett Electric BVE/Newport Electric R.I.P.U.C. No. _____ Exhibit DMW-7 Page 1 of 4 The Narragansett Electric Company Incremental Impact of Narragansett Depreciation Settlement on Consolidated Entity 1 Distribution Plant Deprec. Distribution Plant Deprec. 2 Applying Depreciation Applying Current 3 Settlement Rates Depreciation Rates 4 Company (a) (b) 5 6 The Narragansett Electric Company $19,920,336 1/ $18,037,140 2/ 7 8 Blackstone Valley Electric Company 3,541,466 3/ 4,293,217 4/ 9 10 Newport Electric Company 2,065,635 5/ 2,135,668 6/ 11 12 Total Distribution Plant Depreciation $25,527,437 $24,466,025 13 14 15 General Plant Deprec. General Plant Deprec. 16 Applying Depreciation Applying Current 17 Settlement Rates Depreciation Rates 18 Company (a) (b) 19 20 The Narragansett Electric Company $725,038 7/ $720,610 8/ 21 22 Blackstone Valley Electric Company 160,952 9/ $222,867 10/ 23 24 Newport Electric Company 194,232 11/ $147,217 12/ 25 26 Total General Plant Depreciation $1,080,222 $1,090,694 27 28 Grand Total Depreciation $26,607,659 $25,556,719 1 Incremental Impact 2 of Settlement 3 Depreciation Rates 4 Company (c)=(a)-(b) 5 6 The Narragansett Electric Company $1,883,196 7 8 Blackstone Valley Electric Company (751,751) 9 10 Newport Electric Company (70,033) 11 12 Total Distribution Plant Depreciation $1,061,412 13 14 15 Incremental Impact 16 of Settlement 17 Depreciation Rates 18 Company (c)=(a)-(b) 19 20 The Narragansett Electric Company $4,428 21 22 Blackstone Valley Electric Company (61,915) 23 24 Newport Electric Company 47,015 25 26 Total General Plant Depreciation ($10,472) 27 28 Grand Total Depreciation $1,050,940 Notes: 1/ Exhibit DMW-7, page 2, line 29, column (e). 2/ Exhibit DMW-7, page 2, line 29, column (b). 3/ Exhibit DMW-7, page 2, line 47, column (e). 4/ Exhibit DMW-7, page 2, line 47, column (b). 5/ Exhibit DMW-7, page 2, line 65, column (e). 6/ Exhibit DMW-7, page 2, line 65, column (b). 7/ Exhibit DMW-7, page 3, line 25, column (e). 8/ Exhibit DMW-7, page 3, line 25, column (b). 9/ Exhibit DMW-7, page 3, line 41, column (e). 10/ Exhibit DMW-7, page 3, line 41, column (b). 11/ Exhibit DMW-7, page 3, line 57, column (e). 12/ Exhibit DMW-7, page 3, line 57, column (b).
Narrangansett Electric BVE/Newport Electric R.I.P.U.C. No. _____ Exhibit DMW-7 Page 2 of 4 The Narragansett Electric Company Change in Distribution Plant Depreciation to Narragansett's Depreciation Settlement for Consolidated Entity PUC Narr. Current Narragansett Depreciation Settlement Blackstone Newport Account Rates Investment Negative Salvage Total Rate Valley Electric 1 361 2.00% 1.73% 0.37% 2.10% 2.40% 1.71% 2 362 2.86% 2.60% 0.37% 2.97% 2.79% 3.73% 3 364 4.00% 3.80% 0.37% 4.17% 7.44% 4.28% 4 365 2.86% 2.91% 0.37% 3.28% 3.63% 2.74% 5 366 1.67% 1.68% 0.37% 2.05% 1.98% 1.28% 6 367 2.22% 2.21% 0.37% 2.58% 3.00% 3.11% 7 368 4.00% 4.07% 0.37% 4.44% 3.49% 3.57% 8 369 4.00% 3.89% 0.37% 4.26% 5.53% 5.14% 9 370 3.33% 3.41% 0.37% 3.78% 3.12% 2.89% 10 371 2.87% 1.60% 0.37% 1.97% 7.74% 7.74% 11 373 4.00% 4.25% 0.37% 4.62% 9.27% 4.08% 12 13 The Narragansett Electric Company 14 Intrastate Depreciation Narragansett Depreciation Settlement 15 Plant at Current Investment Negative 16 Depreciable Plant Balance 1/ Rates Accrual Salvage Total 17 PUC Account (a) (b) (c) (d) (e) 18 361 $2,082,573 $41,651 $36,029 $7,706 $43,735 19 362 79,464,967 2,272,698 2,066,089 294,020 2,360,109 20 364 85,780,758 3,431,230 3,259,669 317,389 3,577,058 21 365 139,893,298 4,000,948 4,070,895 517,605 4,588,500 22 366 29,089,158 485,789 488,698 107,630 596,328 23 367 54,221,858 1,203,725 1,198,303 200,621 1,398,924 24 368 75,907,085 3,036,283 3,089,418 280,856 3,370,274 25 369 31,202,210 1,248,088 1,213,766 115,448 1,329,214 26 370 29,609,147 985,985 1,009,672 109,554 1,119,226 27 371 3,037 87 49 11 60 28 373 33,266,397 1,330,656 1,413,822 123,086 1,536,908 29 Total Narragansett $18,037,140 $17,846,410 $2,073,926 $19,920,336 30 31 Blackstone Valley Electric Company 32 Intrastate Depreciation Narragansett Depreciation Settlement 33 Plant at Current Investment Negative 34 Depreciable Plant Balance 2/ Rates Accrual Salvage Total 35 PUC Account (a) (b) (c) (d) (e) 36 361 $2,038,522 $48,925 $35,266 $7,543 $42,809 37 362 14,912,929 416,071 387,736 55,178 442,914 38 364 15,911,336 1,183,803 604,631 58,872 663,503 39 365 18,006,124 653,622 523,978 66,623 590,601 40 366 4,820,439 95,445 80,983 17,836 98,819 41 367 8,098,313 242,949 178,973 29,964 208,937 42 368 14,093,867 491,876 573,620 52,147 625,767 43 369 9,474,467 523,938 368,557 35,056 403,613 44 370 6,617,396 206,463 225,653 24,484 250,137 45 373 4,639,963 430,125 197,198 17,168 214,366 46 Total Blackstone Valley $4,293,217 $3,176,595 $364,871 $3,541,466 47 48 Newport Electric Company 49 Intrastate Depreciation Depreciation Settlement 50 Plant at Current Investment Negative 51 Depreciable Plant Balance 3/ Rates Accrual Salvage Total 52 PUC Account (a) (b) (c) (d) (e) 53 361 $399,086 $6,824 $6,904 $1,477 $8,381 54 362 13,243,627 493,987 344,334 49,001 393,335 55 364 10,170,129 435,282 386,465 37,629 424,094 56 365 8,665,724 237,441 252,173 32,063 284,236 57 366 3,215,935 41,164 54,028 11,899 65,927 58 367 10,906,469 339,191 241,033 40,354 281,387 59 368 6,023,816 215,050 245,169 22,288 267,457 60 369 2,641,840 135,791 102,768 9,775 112,543 61 370 3,251,741 93,975 110,884 12,031 122,915 62 371 731,940 56,652 11,711 2,708 14,419 63 373 1,968,416 80,311 83,658 7,283 90,941 64 Total Newport $2,135,668 $1,839,127 $226,508 $2,065,635 65 66 Total Depreciation $24,466,025 $22,862,132 $2,665,305 $25,527,437 Notes: 1/ Exhibit DMW-7, page 4, lines 1-11, column (d) 2/ Exhibit DMW-7, page 4, lines 30-40, column (d) 3/ Exhibit DMW-7, page 4, lines 59-69, column (d)
Narrangansett Electric BVE/Newport Electric R.I.P.U.C. No. _____ Exhibit DMW-7 Page 3 of 4 The Narragansett Electric Company Change in General Plant Depreciation to Narragansett's Depreciation Settlement for Consolidated Entity PUC Narr. Current Narragansett Depreciation Settlement Blackstone Newport Account Rates Investment Negative Salvage Total Rate Valley Electric 1 390 2.00% 2.65% 0.17% 2.82% 4.57% 1.73% 2 391 4/ 4.00% 5.00% 0.00% 5.00% 4.62% 5.28% 3 392 4/ 0.00% 5.00% 0.00% 5.00% 0.00% 0.00% 4 393 4/ 2.86% 5.00% 0.00% 5.00% 6.71% 4.16% 5 394 4/ 3.33% 5.00% 0.00% 5.00% 4.58% 3.75% 6 395 4/ 4.00% 5.00% 0.00% 5.00% 3.23% 4.10% 7 396 4/ 4.68% 5.00% 0.00% 5.00% 0.00% 4.68% 8 397 4/ 10.00% 5.00% 0.00% 5.00% 9.53% 4.70% 9 398 4/ 4.00% 5.00% 0.00% 5.00% 8.47% 3.49% 10 11 The Narragansett Electric Company 12 Intrastate Depreciation Narragansett Depreciation Settlement 13 Plant at Current Investment Negative 14 Depreciable Plant Balance 1/ Rates Accrual Salvage Total 15 PUC Account (a) (b) (c) (d) (e) 16 390 $12,181,900 $243,638 $322,820 $20,709 $343,529 17 391 553,326 22,133 27,666 0 27,666 18 393 441,611 12,630 22,081 0 22,081 19 394 2,113,557 70,381 105,678 0 105,678 20 395 944,498 37,780 47,225 0 47,225 21 397 3,182,694 318,269 159,135 0 159,135 22 398 394,474 15,779 19,724 0 19,724 23 Total Narragansett $720,610 $704,329 $20,709 $725,038 24 25 Blackstone Valley Electric Company 26 Intrastate Depreciation Narragansett Depreciation Settlement 27 Plant at Current Investment Negative 28 Depreciable Plant Balance 2/ Rates Accrual Salvage Total 29 PUC Account (a) (b) (c) (d) (e) 30 390 $2,769,094 $126,548 $73,381 $4,707 $78,088 31 391 597,292 27,595 29,865 0 29,865 32 393 13,656 916 683 0 683 33 394 325,641 14,914 16,282 0 16,282 34 395 236,970 7,654 11,849 0 11,849 35 397 402,841 38,391 20,142 0 20,142 36 398 80,861 6,849 4,043 0 4,043 37 Total Blackstone Valley $222,867 $156,245 $4,707 $160,952 38 39 Newport Electric Company 40 Intrastate Depreciation Depreciation Settlement 41 Plant at Current Investment Negative 42 Depreciable Plant Balance 3/ Rates Accrual Salvage Total 43 PUC Account (a) (b) (c) (d) (e) 44 390 $3,490,322 $60,383 $92,494 $5,934 $98,428 45 391 576,798 30,455 28,840 0 28,840 46 392 5/ 1,058,572 0 0 0 0 47 393 61,135 2,543 3,057 0 3,057 48 394 419,532 15,732 20,977 0 20,977 49 395 251,853 10,326 12,593 0 12,593 50 396 11,874 556 594 0 594 51 397 534,023 25,099 26,701 0 26,701 52 398 60,841 2,123 3,042 0 3,042 53 Total Newport $147,217 $188,298 $5,934 $194,232 54 55 Total Depreciation $1,090,694 $1,048,872 $31,350 $1,080,222 Notes: 1/ Exhibit DMW-7, page 4, lines 15-23, column (d) 2/ Exhibit DMW-7, page 4, lines 44-52, column (d) 3/ Exhibit DMW-7, page 4, lines 73-81, column (d) 4/ Amortization Accounts equivalent to 5.0% depreciation rate. 5/ Newport Electric depreciates its vehicles on a vehicle by vehicle basis. During 1998 depreciation expense of $14,611 was recorded for vehicles. As of December 31, 1998, vehicles had a remaining net book values of $130,714. Depreciation Expense for 1999 is estimated to be $10,800. Therefore, the depreciation effects from account 392 have been excluded from this analysis.
Narrangansett Electric BVE/Newport Electric R.I.P.U.C. No. _____ Exhibit DMW-7 Page 4 of 4 The Narragansett Electric Company Depreciable Plant Balances Interstate Intrastate As of 12/31/98 1/ Percent of Total Amount Amount The Narragansett Electric Company (a) (b) (c) = (a) x (b) (d) = (a) - (c) Distribution Plant: 1 Structures and Improvements 361 $2,101,911 0.92% $19,338 $2,082,573 2 Station Equipment 362 80,202,833 0.92% 737,866 79,464,967 3 Poles, Towers and Fixtures 364 86,577,269 0.92% 796,511 85,780,758 4 Overhead Conductors 365 141,192,267 0.92% 1,298,969 139,893,298 5 Underground Conduit 366 29,359,263 0.92% 270,105 29,089,158 6 Underground Conductors 367 54,725,331 0.92% 503,473 54,221,858 7 Line Transformers 368 76,611,915 0.92% 704,830 75,907,085 8 Services 369 31,491,936 0.92% 289,726 31,202,210 9 Meters 370 29,884,081 0.92% 274,934 29,609,147 10 Installation on Cust. Premises 371 3,065 0.92% 28 3,037 11 Street lights 373 33,575,290 0.92% 308,893 33,266,397 12 Total $565,725,162 $5,204,673 $560,520,489 13 14 General Plant: 15 Structures and Improvements 390 $15,140,318 19.54% $2,958,418 $12,181,900 16 Office Furniture and Equip. 391 687,703 19.54% 134,377 553,326 17 Stores Equipment 393 548,858 19.54% 107,247 441,611 18 Tools, Shop and Garage 394 2,626,842 19.54% 513,285 2,113,557 19 Laboratory Equip. 395 1,173,873 19.54% 229,375 944,498 20 Communication Equip. 397 3,955,623 19.54% 772,929 3,182,694 21 Miscellaneous Equipment 398 490,273 19.54% 95,799 394,474 22 Total $24,623,490 $4,811,430 $19,812,060 23 24 Grand Total $590,348,652 $10,016,103 $580,332,549 25 26 Blackstone Valley Electric Company As of 12/31/98 Interstate Interstate Intrastate 27 Distribution Plant: (a) (b) (c) (d) 28 Structures and Improvements 361 $2,123,460 $84,938 $2,038,522 29 Station Equipment 362 15,534,301 4.00% 621,372 14,912,929 30 Poles, Towers and Fixtures 364 16,574,308 4.00% 662,972 15,911,336 31 Overhead Conductors 365 18,756,379 4.00% 750,255 18,006,124 32 Underground Conduit 366 5,021,291 4.00% 200,852 4,820,439 33 Underground Conductors 367 8,435,743 4.00% 337,430 8,098,313 34 Line Transformers 368 14,681,111 4.00% 587,244 14,093,867 35 Services 369 9,869,236 4.00% 394,769 9,474,467 36 Meters 370 6,893,121 4.00% 275,725 6,617,396 37 Street lights 373 4,833,295 4.00% 193,332 4,639,963 38 Total $102,722,245 4.00% $4,108,889 $98,613,356 39 40 General Plant: 41 Structures and Improvements 390 $2,884,473 4.00% $115,379 $2,769,094 42 Office Furniture and Equip. 391 622,179 4.00% 24,887 597,292 43 Stores Equipment 393 14,225 4.00% 569 13,656 44 Tools, Shop and Garage 394 339,209 4.00% 13,568 325,641 45 Laboratory Equip. 395 246,844 4.00% 9,874 236,970 46 Communication Equip. 397 419,626 4.00% 16,785 402,841 47 Miscellaneous Equipment 398 84,230 4.00% 3,369 80,861 48 Total $4,610,786 $184,431 $4,426,355 49 50 Grand Total $107,333,031 $4,293,320 $103,039,711 51 52 Newport Electric Company As of 12/31/98 Interstate Interstate Intrastate 53 Distribution Plant: (a) (b) (c) (d) 54 Structures and Improvements 361 $408,858 2.39% $9,772 $399,086 55 Station Equipment 362 13,567,900 2.39% 324,273 13,243,627 56 Poles, Towers and Fixtures 364 10,419,147 2.39% 249,018 10,170,129 57 Overhead Conductors 365 8,877,906 2.39% 212,182 8,665,724 58 Underground Conduit 366 3,294,678 2.39% 78,743 3,215,935 59 Underground Conductors 367 11,173,516 2.39% 267,047 10,906,469 60 Line Transformers 368 6,171,310 2.39% 147,494 6,023,816 61 Services 369 2,706,526 2.39% 64,686 2,641,840 62 Meters 370 3,331,361 2.39% 79,620 3,251,741 63 Installation on Cust. Premises 371 749,862 2.39% 17,922 731,940 64 Street lights 373 2,016,613 2.39% 48,197 1,968,416 65 Total $62,717,677 $1,498,954 $61,218,723 66 67 General Plant: 68 Structures and Improvements 390 $3,624,426 3.70% $134,104 $3,490,322 69 Office Furniture and Equip. 391 598,959 3.70% 22,161 576,798 70 Transportation Equip. 392 1,099,244 3.70% 40,672 1,058,572 71 Stores Equipment 393 63,484 3.70% 2,349 61,135 72 Tools, Shop and Garage 394 435,651 3.70% 16,119 419,532 73 Laboratory Equip. 395 261,530 3.70% 9,677 251,853 74 Power Operated Equip. 396 12,330 3.70% 456 11,874 75 Communication Equip. 397 554,541 3.70% 20,518 534,023 76 Miscellaneous Equipment 398 63,179 3.70% 2,338 60,841 77 Total $6,713,344 $248,393 $6,464,951 78 79 Grand Total $69,431,021 $1,747,347 $67,683,674 Notes: 1/ Narragansett Electric's 1998 FERC Form 1, Page 207, Column (g), Lines 56-68. 2/ Blackstone Valley Electric's 1998 FERC Form 1, Page 207, Column (g), Lines 56-68. 3/ Newport Electric's 1998 FERC Form 1, Page 207, Column (g), Lines 56-68.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-8 Exhibit DMW-8 Summary of Revenue Requirement for Cost of Removal after Consolidation Narragansett Electric BVE/Newport Electric R.I.P.U.C. No._______ Exhibit DMW-8 Page 1 of 1 The Narragansett Electric Company Summary of Revenue Requirement for Cost of Removal for Consolidated Entity (Thousands of Dollars) 1 Increase in Depreciation Expenses to Reflect 2 Narragansett Depreciation Settlement $1,051 l/ 3 4 5 Cessation of Cost of Removal Flow-Though Benefit $1,618 2/ ----- 6 7 8 Total Increase in Narragansett Revenue Requirement $2,669 3/ ------ Notes: 1/ Exhibit DMW-7, page 1, line 28, column (c). 2/ Exhibit DMW-3, page 1, line 14. 3/ Sum of Line 2 and Line 5. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-9 Exhibit DMW-9 Summary of Storm Contingency Funds
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ____ Exhibit DMW-9 Page 1 of 1 THE NARRAGANSETT ELECTRIC COMPANY Summary of Storm Contingency Funds Narragansett Blackston e Newport Combined Electric Valley Electric Entity -------- ------ -------- -------- 1 Balance in Storm Funds as of 2 December 31, 1998 $4,476,595 1/ $209,261 2/ $1,020,879 3/ $5,706,735 3 4 Annual Storm Fund Contributions 5 Collected through Revenue $641,000 4/ $160,000 5/ $240,000 6/ $1,041,000 6 7 Annual Threshold Amount for 8 the Year 1999 $465,000 7/ $145,000 8/ $97,000 9/ $465,000 9 10 Deductible Amount per each 11 Storm Occurrence $300,000 10/ $94,000 10/ $56,000 10/ $300,000
Notes: 1/ Narragansett Electric's 1998 FERC Form 1, Page 278. 2/ Blackstone Valley Electric's 1998 FERC Form 1, Page 278. 3/ Newport Electric's 1998 FERC Form 1, Page 278. 4/ RIPUC Order in Docket No. 1938. 5/ RIPUC Order in Docket No. 2016. 6/ RIPUC Order in Docket No. 2036. 7/ Narragansett Electric's Annual Storm Fund Report, Filed April 1, 1999. 8/ Blackstone Valley Electric's Annual Storm Fund Report, Filed April 1, 1999. 9/ Newport Electric's Annual Storm Fund Report, Filed April 1, 1999. 10/ RIPUC Order in Docket No. 2509. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit DMW-10 Exhibit DMW-10 Summary of Deferred FAS 106 Costs
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No._______ Exhibit DMW- 10 Page 1 of 1 The Narragansett Electric Company Summary of Deferred FAS 106 Costs Blackstone Newport Combined Valley Electric Entity 1 Deferred FAS 106 Balance as of $581,291 l/ $686,365 2/ $1,267,656 2 December 31, 1998 3 4 Annual Recovery of Deferred FAS 106 $145,300 3/ $171,600 3/ $316,900 5 Costs Collected through Revenue 6 7 Anticipated Year Deferred FAS 106 will 2002 2002 2002 8 be Completed Notes: 1/ Blackstone Valley Electric's 1998 FERC Form 1, Page 232. 2/ Newport Electric's 1998 FERC Form 1, Page 232. 3/ November, 1995 Compliance Filing in RIPUC Docket No. 2045.
The Narragansett Electric Company, Blackstone Valley Electric Company, and Newport Electric Corporation Rate Plan Filing in Support of Merger Volume 2 Testimony and Exhibits of: James M. Molloy James J. Bonner, Jr. May, 1999 Submitted to: Rhode Island Public Utilities Commission RIPUC Docket _____ Submitted by: Nees Logo Eastern Utilities Associates Logo THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - -------------------------) R.I.P.U.C. No. __________ Narragansett Electric ) BVE/Newport Electric ) - -------------------------) DIRECT TESTIMONY OF JAMES M. MOLLOY THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - -------------------------) R.I.P.U.C. No. __________ Narragansett Electric ) BVE/Newport Electric ) - -------------------------) DIRECT TESTIMONY OF JAMES M. MOLLOY Table of Contents I. Introduction and Qualifications.......................................1 II. Purpose of Testimony..................................................2 III. Summary of Current Rates..............................................3 A. Narragansett......................................................3 B. Blackstone and Newport............................................5 IV. Proposed Rate Plan....................................................6 A. Overview..........................................................6 B. Distribution Rates...............................................10 C. Transmission Rates...............................................14 D. Transition Charges...............................................16 E. Standard Offer Rates.............................................18 F. Other Rate Issues................................................18 V. Revenue Effects......................................................19 A. Overall..........................................................19 B. Typical Bills....................................................19 VI. Tariffs..............................................................20 A. Terms and Conditions.............................................20 B. Tariffs..........................................................21 C. Adjustment Provisions............................................21 VIII. Conclusion...........................................................22
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 1 of 22 1 I. Introduction and Qualifications 2 Q. Please state your full name and business address. 3 A. James M. Molloy, 25 Research Drive, Westborough, Massachusetts 01582. 4 5 Q. Please state your position. 6 A. I am a Senior Rate Analyst for New England Power Service Company, performing rate 7 related services for the New England Electric System, including The Narragansett 8 Electric Company ("Narragansett" or "the Company"). 9 10 Q. Will you describe your educational background and training? 11 A. In 1992, I graduated from Catholic University with a Bachelor of Arts degree in 12 Accounting. In 1994, I received a Masters in Business Administration with a 13 concentration in Finance from the William E. Simon Graduate School of Business 14 Administration at the University of Rochester. 15 16 Q. What is your professional background? 17 A. In 1995, I was hired by the New England Power Service Company as an Assistant Rate 18 Analyst in the Rate Department. In 1996, I was promoted to the position of Rate Analyst. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 2 of 22 1 In 1998, I was promoted to my current position of Senior Rate Analyst. In this position I 2 have been responsible for rate design analysis for various New England Electric System 3 companies. Specifically, I have conducted allocated distribution cost of service studies 4 and supported others in the development of cost allocation and rate design studies. 5 Further, I have provided analytical support for witnesses in various NEES retail company 6 regulatory proceedings on various rate design and cost allocation issues. In addition, I 7 have had primary responsibility for performing customer-specific rate impact analyses. 8 For the last two years, I have performed rate and cost allocation analytical work in the 9 unbundling of rates for the NEES retail companies in preparation of industry 10 restructuring. 11 12 Q. Have you testified in Rhode Island Public Utilities Commission proceedings? 13 A. Yes. I have testified at hearings during the past two years regarding the subject of 14 Narragansett's Standard Offer rates and other rate design matters. 15 16 II. Purpose of Testimony 17 Q. What is the purpose of your testimony? Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 3 of 22 1 A. The purpose of my testimony is to present the proposed rate plan of Narragansett, 2 Blackstone Valley Electric Company ("Blackstone") and Newport Electric Company 3 ("Newport") (together, "the Companies"), in connection with the merger of NEES and 4 Eastern Utilities Associates ("EUA"). First, I will provide a brief summary of all three 5 companies' current rates. Second, I will describe the proposed rate plan, including 6 special rate mapping issues, which will serve as a means of consolidating the rates of 7 Narragansett, Blackstone and Newport. Next, I will present the anticipated effects of the 8 rate plan on revenues, both at the component level and at the total revenue level. This 9 presentation will include an analysis of typical customer bills. Finally, I will discuss 10 tariff changes made necessary by the proposed plan. 11 12 III. Summary of Current Rates 13 A. Narragansett 14 Q. Please provide a brief summary of Narragansett's current rates. 15 A. Narragansett's distribution rates were approved by the Commission in Docket No. 2290 16 effective December 15, 1996 and unbundled in Docket No. 2515. In accordance with the 17 Rhode Island Utility Restructuring Act ("URA") these rates remained frozen through 18 December, 1998 except for increases allowed through the Performance Based Rate Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 4 of 22 1 mechanism of the URA, as approved by the Commission in Docket No. 2500. Currently, the 2 average distribution charge is 2.967(cent)/kWh. 3 4 Narragansett's current average transmission rate of 0.455(cent)/kWh as approved by the 5 Commission in Docket No. 2841 collects both the base transmission rate of 0.387(cent)/kWh 6 and the transmission adjustment for calendar year 1999 of 0.068(cent)/kWh. Narragansett's 7 transmission rate recovers on a fully reconciling basis the costs it incurs to provide 8 transmission. The transmission component of Narragansett's rates is based on 9 transmission costs incurred from New England Power Company ("NEP"), the New 10 England Power Pool ("NEPOOL") and the Independent System Operator ("ISO"). 11 Narragansett's base transmission rate is composed of a different rate for each rate class 12 which is based on the class demands coincident with NEP's 12 monthly transmission 13 peaks. 14 15 The Transition Charge is currently 1.15(cent)/kWh as approved in Docket No. 2771. 16 Narrangansett's transition charge recovers on a fully reconciling basis the Contract 17 Termination Charge ("CTC") billed to it by NEP. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 5 of 22 1 Narragansett's uniform Standard Offer charge of 3.5(cent)/kWh mirrors the 3.5(cent)/kWh charged 2 to the Company by its Standard Offer suppliers. The Standard Offer is scheduled to 3 increase to 3.8(cent)/kWh on January 1, 2000. 4 5 B. Blackstone and Newport 6 Q. Please provide a brief summary of Blackstone's and Newport's current rates. 7 A. Blackstone's and Newport's distribution rates were approved by the Commission in 8 Docket No. 2514 except for the increases allowed through the Performance Based Rate 9 mechanism of the URA which were approved in Docket No. 2498 for Blackstone and 10 Docket No. 2499 for Newport. Under the terms of the retail restructuring settlement in 11 consolidated Dockets 2514, 2651, and 2653 Blackstone's and Newport's distribution 12 rates are prohibited from any other increases through December 31, 2000. Currently, 13 Blackstone's average distribution charge is 3.002(cent)/kWh while Newport's average 14 distribution charge is 4.187(cent)/kWh. Finally, in Docket No. 2888 Blackstone and Newport 15 modified the distribution rates of certain rate classes as a means to hold customers 16 harmless from the implementation of a uniform, cents per kWh Standard Offer price. 17 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 6 of 22 1 Both Blackstone and Newport have a current average transmission rate of 0.267(cent)/kWh. 2 This rate collects the current annual cost of transmission for the calendar year 1999 for 3 each company. The transmission rate of each company is the transmission rate of 4 Montaup Electric Company ("Montaup") approved by FERC which recovers actual 5 transmission costs that Montaup, NEPOOL and the ISO incur to provide transmission 6 service based on a historical test year. Montaup's transmission rate, as billed to 7 customers by Blackstone and Newport, is an uniform (cent)/kWh charge applicable to all 8 retail customers of Montaup's affiliated companies. 9 10 The transition charge is currently 2.040(cent)/kWh for Blackstone and 2.060(cent)/kWh for 11 Newport. This charge was approved in Docket No. 2888. 12 13 Blackstone's and Newport's uniform Standard Offer charge of 3.5(cent)/kWh mirrors the 14 3.5(cent)/kWh charged to them by their Standard Offer suppliers. This wholesale Standard 15 Offer is scheduled to increase to 3.8(cent)/kWh on January 1, 2000. 16 17 IV. Proposed Rate Plan 18 A. Overview Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 7 of 22 1 Q. Before explaining the rate plan, are there any terms that you will be using that would be 2 helpful to define? 3 A. Yes. I believe it would be helpful to provide a definition of certain terms that I will use in 4 describing the rates. Specifically, when I refer to "distribution rates" or "distribution 5 component", I am referring to the component of rates relating to distribution that excludes 6 Transmission, Transition, Conservation and Load Management, and Standard Offer 7 charges. In contrast, when I refer to "delivery rates", I am referring to all rates, 8 excluding only Standard Offer service. Finally, when I refer to "rates" generically, I 9 intend to include all rates, including Standard Offer service. 10 11 12 Q. Please provide a general description of the Companies' proposed rate plan. 13 A. An overview of the rate plan is provided in the testimony of Mr. Jesanis. In summary, 14 the rate plan will become effective 120 days from the closing of the EUA-NEES merger 15 or April 1, 2000, whichever occurs later ("Rate Consolidation Date"). As described by 16 Mr. Jesanis, the plan creates immediate rate reductions for customers of Blackstone and 17 Newport, without increasing the delivery rates of Narragansett customers. After an 18 adjustment to the distribution rate is made on January 1, 2001, the distribution component Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 8 of 22 1 of all customers' bills will be frozen in two phases. The result would be a distribution 2 rate freeze through the year 2004. Mr. Jesanis describes the distribution rate freeze 3 proposal in greater detail, including exceptions for certain exogenous factors, as well as 4 the inflation protection provision that could only be triggered during the last two years of 5 the plan. 6 7 The plan would be implemented by placing all customers on Narragansett's rates with a 8 distribution surcharge to customers formerly served by Newport and a transition 9 surcharge to customers formerly served by Newport and BVE. However, there are three 10 exceptions to this general proposal. First, the companies are proposing special treatment 11 for the Newport C-1 rate as described below. The second exception allows an additional 12 credit to the low income customers of Blackstone and Newport during 2000 to ensure that 13 they are held harmless from the consolidation of rates during this period. A third 14 exception has been made for streetlighting customers of Blackstone and Newport who 15 would otherwise see significant increases under this proposal. Under the plan, all 16 customers of Blackstone and Newport would be moved onto the distribution rates of 17 Narragansett effective for bills rendered on the Rate Consolidation Date. However, 18 customers of Newport will be assessed a distribution surcharge as described below. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 9 of 22 1 In the case of the Navy, Newport has a special rate class C-1. The Companies would 2 retain the C-1 rate, but reduce it by 14% which is equal to the average distribution rate 3 decrease for all other Newport customers as a result of the merger. Instead of having the 4 rate function as an amendment to the antiquated 1961 contract entered into between 5 Newport and the Navy, the Company proposes a new tariff that embodies the old C-1 rate 6 reflecting the further 14% discount, with appropriate changes to the terms and conditions 7 in the tariff. The new tariff is designated as the "69kV Rate (N-01)". 8 9 Q. What impact would these proposed changes have on the customers of Narragansett, 10 Blackstone and Newport? 11 A. As shown in Exhibit JMM-1 the rate consolidation plan would reduce Blackstone's and 12 Newport's rates in 2000 by approximately $2.1 million and $3.4 million, respectively. An 13 exhibit summarizing the companies projected average rates or "rate paths" for the 14 years of the rate plan are included as Exhibit JMM-2. As shown in this exhibit, average 15 delivery rates for each of the Companies decline over the rate plan period. 16 17 Q. How would the customers of Blackstone and Newport be transferred to Narragansett's 18 rates? Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 10 of 22 1 A. Rate classes of Blackstone and Newport are proposed to be mapped to Narragansett's rate 2 classes as illustrated in Exhibit JMM-3. This proposed rate mapping is determined by 3 referring to the availability provisions of Blackstone and Newport retail delivery service 4 tariffs and matching each tariff to a corresponding Narragansett retail delivery service 5 tariff. Customer usage within several Blackstone and Newport general service rate 6 classes maps to more than one Narragansett rate class because the availability provisions 7 of the Blackstone and Newport tariffs encompass a wider range of customer usage levels 8 than the Narragansett tariffs. As part of the mapping process, the billing determinants 9 under some Blackstone and Newport rate classes have been broken down into 10 subcategories in order to assign them to the correct Narragansett rate classes. The 11 testimony of Mr. Bonner supports in more detail the rate mapping process and the billing 12 determinants that the Companies are using to determine the effect on revenue. 13 14 B. Distribution Rates 15 Q. What is the proposed plan for the distribution rates of Blackstone, Newport and 16 Narragansett? 17 A. As briefly described earlier in my testimony, the Company is proposing to maintain 18 Narragansett's customers on their current distribution rates and to move Blackstone's Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 11 of 22 1 customers onto Narragansett distribution rates. In addition the Companies are proposing 2 to reduce the distribution rates of Newport's customers by half the distance to 3 Narragansett's distribution rates, with the exception of the Navy. The Navy's rate C-1 4 would be reduced by the average percentage decrease in the distribution rate of all the 5 other Newport customers. All Newport customer except for the C-1 class would be 6 moved onto Narragansett distribution rates and assessed a uniform (cent)/kWh surcharge 7 designed to cut rates equal to 50% of the difference between Narragansett's distribution 8 rates and Newport's distribution rates, as shown in Exhibit JMM-4. For purposes of the 9 tariffs, we refer to this distribution surcharge in the Newport zone as the "Zonal 10 Distribution Factor". 11 12 Q. Please explain the treatment for low income and streetlight customers. 13 A. The Companies have designed a Low Income Equalization Credit to prevent the low 14 income rate classes in Blackstone and Newport from seeing rate increases due to the rate 15 plan. The credits apply to the first 300 kWh per month and equal the difference between 16 the R-2 billing units billed at Narragansett's rates as compared to Blackstone's and 17 Newport's rates divided by the initial 300 kWh block for the R-2 rate. The credits are 18 only necessary for the first year of the plan as reductions to transition charges for Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 12 of 22 1 Blackstone and Newport in 2001 will offset any distribution rate increase to the low 2 income rate classes. 3 4 The streetlight credit is designed to maintain the current distribution revenue from the 5 Blackstone's and Newport's streetlighting rates. The credit equals the difference between 6 the streetlight billing units billed at Narragansett rates as compared to 7 Blackstone/Newport's rates divided by total streetlight kWh. The total amount of the 8 annual credit is approximately $840,000. The Company proposes to apply its annual 9 streetlight refund ($827,494 for the past year) to fund the cost of the annual credit. 10 11 Q. How does the Company plan to implement the distribution rate plan? 12 A. As discussed above, Narragansett would implement its rates for customers of Blackstone 13 and Newport on a bills rendered basis for meter readings as of the Rate Consolidation 14 Date. Due to the complexity of prorating out Blackstone and Newport distribution rates 15 and prorating in Narragansett distribution rates, the Companies believe this "flash cut" 16 method would simplify bills and avoid any unnecessary customer confusion during the 17 transition. 18 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 13 of 22 1 Q. Are the Companies proposing any other distribution rate changes? 2 A. Yes. As discussed in Mr. Webster's testimony, Narragansett is proposing to modify its 3 depreciation rates to resolve certain issues related to cost of removal. The change to 4 depreciation rates results in an ongoing annual revenue requirement of $2.7 million and a 5 deficiency in deferred tax reserves of about $19.2 million. The Company is proposing to 6 increase distribution rates to collect on an ongoing basis $2.7 million beginning January 7 1, 2001. This would be done by increasing distribution energy charges by 8 $0.00039/kWh. The Company is also proposing to use refunds due to customers from any 9 CTC reconciliations to resolve the accumulated deferred tax deficiency, as described by 10 Mr. Jesanis and Mr. Webster. 11 12 Q. What is the estimated overall impact of the Companies' proposal on distribution rates? 13 A. As shown in Exhibit JMM-5, Blackstone's and Newport's average distribution rates 14 would be reduced by approximately $2.0 million and $3.4 million, respectively. 15 Narragansett's distribution rates would remain unchanged in the year 2000. In 2001, the 16 distribution component of all customers' rates would be increased by $.00039/kWh or 17 $2.7 million. However, this would not present an increase for Narragansett customers 18 because of the transmission rate decrease described below. Similarly, because Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 14 of 22 1 Blackstone's and Newport's customers will see a significant decrease in transition charges 2 in 2001, their rates will also decrease. 3 4 C. Transmission Rates 5 Q. What is the plan for transmission rates? 6 A. Beginning on the Rate Consolidation Date, the Company is proposing to move 7 Blackstone and Newport customers to the transmission rates of Narragansett. However, 8 in order to avoid an increase in transmission rates for Blackstone and Newport customers 9 in 2000, the Companies propose to maintain separate transmission adjustment factors in 10 2000 for the Narragansett, Blackstone and Newport zones to continue the present 11 allocation of transmission costs currently assigned to each company. However, 12 beginning in the year 2001, the Companies will complete the transmission rate 13 consolidation by creating one adjustment factor for all customers to recover the 14 consolidated transmission costs incurred above and beyond the revenue collected from 15 the base transmission rates. 16 17 Q. What is the impact of this plan on the transmission revenues of each Company? Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 15 of 22 1 A. On the Rate Consolidation Date, the overall transmission revenue for each company 2 remains relatively unchanged, but as Exhibit JMM-6 demonstrates, revenues shift 3 between rate classes for Blackstone and Newport. This shift, however, provides a better 4 matching between ultimate cost occurrence and revenue from each of the rate classes. 5 Although the consolidation of transmission rates in 2001 represents an increase to 6 Blackstone's and Newport's customers, any increase to those customers is more than 7 offset by decreases in transition charges. The consolidation of transmission rates in 2001 8 represents a decrease to Narragansett customers which is partially offset by the 9 distribution rate increase mentioned earlier in my testimony. 10 11 Q. How do the Companies plan to implement the transmission rate plan? 12 A. The transmission adjustment factors that would become effective on the Rate 13 Consolidation Date are illustrated in Exhibit JMM-7. In this exhibit, forecasted transmission 14 expenses of each of the three Companies are compared to the revenues from their 15 respective billing determinants billed at Narragansett's base transmission rates and the 16 difference is divided by total kWh sales of each company to produce the Transmission 17 Adjustment Factor. Exhibit JMM-7 provides only a demonstration of the calculations. 18 Actual transmission adjustment factors would be implemented based on a subsequent Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 16 of 22 1 filing by the companies in late 1999 which would incorporate the most current forecast of 2 transmission expenses. The consolidated transmission factors that would be in effect in 3 2001 are estimated on Page 7 in Exhibit JMM-7 for purposes of rate comparison. 4 5 In addition, it should be noted that Blackstone and Newport do not currently have a 6 transmission adjustment provision. Rather, both companies merely "pass-through" a 7 transmission factor charged to them by Montaup. Under the rate plan proposal, all 8 customers would fall under a transmission adjustment provision effective on the Rate 9 Consolidation Date. Thus, under the rate plan, the transmission component of the 10 Companies' rates would be set and reconciled on an annual basis. 11 12 D. Transition Charges 13 Q. What is the plan for transition charges? 14 A. The Companies are proposing to set the transition charge to Narragansett's customers at 15 1.15(cent)/kWh. Thus, transition charges collected from Narragansett's customers that are 16 above the CTC level billed by NEP will be used to reduce the transition charges of 17 Newport's and Blackstone's customers. The ultimate aim will be to keep the "Base" 18 transition charge in effect for Narragansett's customers until the transition charges of all Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 17 of 22 1 three Companies come into parity with each other and transition charges can be 2 consolidated into a single rate for all three Companies. 3 4 Q. How do the Companies propose to implement the transition rate plan? 5 A. The Companies would bill all customers in all three zones the same base transition charge 6 equal to the proposed Narragansett transition charge of 1.15 cents per kWh. However, 7 customers in the Blackstone and Newport zones will be assessed a "Zonal Transition 8 Factor". Effective on the Rate Consolidation Date, the Zonal Transition Factor will be 9 equal to the difference between the transition charge in effect prior to the Rate 10 Consolidation Date and the base transition charge of 1.15 cent per kWh. Effective on 11 January 1, 2001, the Zonal Transition Factor will collect an amount equal to the 12 difference between: 13 (1) Total projected CTC expense, including Narragansett; and 14 (2) and total kWh sales including Narragansett times the new base transition charge 15 of 1.15(cent)/kWh. 16 An illustrative example of the Zonal Transition Factor calculations is shown in Exhibit 17 JMM-8. 18 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 18 of 22 1 E. Standard Offer Rates 2 Q. Is the Company proposing any change to the Standard Offer charge? 3 A. No. Because the uniform Standard Offer for customers in Blackstone and Newport 4 proposed in RIPUC Docket No. 2888 was approved, the Company would have no need to 5 alter the rate for Standard Offer Service because the rates among the companies would 6 already match. 7 8 Q. How does the Company propose to collect any Standard Offer over/under collection? 9 A. Because of the projected small dollar value of the Standard Offer adjustment, the 10 Company is proposing to consolidate the over/under balances of Narragansett, Blackstone 11 and Newport, and apply Narragansett's current Standard Offer Adjustment Provision to 12 all three zones. 13 14 F. Other Rate Issues 15 Q. Are there any other rate issues with respect to this rate plan? 16 A. Yes. The Company needs to consolidate other generic tariff provisions including Terms 17 and Conditions for both customers and nonregulated power producers, as well as the 18 adjustment provisions. Accordingly, Narragansett's terms and conditions and adjustment Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 19 of 22 1 provisions will be applied to BVE and Newport customers. The consolidation of these 2 tariff provisions is discussed later in my testimony. 3 4 V. Revenue Effects 5 A. Overall 6 Q. What is the estimated impact on Blackstone and Newport customers from the proposed 7 rate plan? 8 A. As illustrated in Exhibit JMM-1, the impact on the Rate Consolidation Date is a decrease 9 of approximately $2.1 million for Blackstone's customers, and a decrease of 10 approximately $3.4 million for Newport's customers as illustrated in Exhibit JMM-1. As 11 discussed in more detail by Mr. Jesanis, there are additional benefits to customers after 12 the Rate Consolidation Date. 13 14 B. Typical Bills 15 Q. Has the Company provided typical bills showing the effects of the proposed rate plan on 16 the Rate Consolidation Date? Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 20 of 22 1 A. Yes, the Company has provided typical bills in Exhibit JMM-9 and Exhibit JMM-10 for 2 Blackstone and Newport, respectively. The Company has not provided typical bills for 3 current Narragansett customers since their bills will not change. 4 5 Q. What is the impact on a typical 500 kWh residential customer in all service territories? 6 A. On the Rate Consolidation Date, there is no change for a current Narragansett customer, a 7 $1.35 decrease monthly or 2.3% for a current Blackstone customer and a $2.07 decrease 8 monthly or 3.3% for a current Newport customer. 9 10 VI. Tariffs 11 A. Terms and Conditions 12 Q. Under which set of Terms and Conditions will customers be served? 13 A. Blackstone and Newport customers will be moved onto the Terms and Conditions of 14 Narragansett effective on the Rate Consolidation Date. 15 16 Q. Is the Company proposing any changes to the Terms and Conditions? Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 21 of 22 1 A. Yes, to facilitate the assessment of the zonal factors for transition and distribution rates, 2 the Company is proposing to add an additional definition to the Terms and Conditions. 3 The addition is shown in Exhibit JMM-11. 4 5 B. Tariffs 6 Q. Has the Company prepared updated tariff cover sheets reflecting the proposed changes. 7 A. Yes, the proposed cover sheets are included as Exhibit JMM-12. 8 9 Q. What happens if the two operating companies of EUA have not been formally merged 10 into Narragansett and retain separate legal existences because of the delay described in 11 Mr. Jesanis' testimony? 12 A. This does not substantively affect the Companies' proposal. My exhibits contemplate the 13 merger occurring. However, if there is a delay, the Companies nevertheless propose that 14 one set of tariffs apply to all three Companies. In such case, the Companies would make 15 a compliance filing to place tariffs containing the names of all three Companies on file 16 with the Commission until the merger of the three operating companies is consummated. 17 18 C. Adjustment Provisions Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Testimony of J.M. Molloy Page 22 of 22 1 Q. Under which set of adjustment provisions will customers be served? 2 A. Similar to the proposal relating to the tariffs, Blackstone and Newport customers will be 3 moved onto the adjustment provisions of Narragansett effective on the Rate 4 Consolidation Date. To the extent that there are any outstanding balances in any of the 5 BVE or Newport adjustment provisions that are in effect prior to the Rate Consolidation 6 Date, the Companies propose to roll those balances into the appropriate corresponding 7 adjustment provisions of the consolidated company. 8 9 Q. Is the Company proposing any changes to the provisions? 10 A. Yes. The Company is updating the language of the Non-Bypassable Transition Charge 11 Adjustment Provision and the Transmission Service Cost Adjustment Provision to reflect 12 the merger of the retail companies. A red-lined copy of the proposed provisions are 13 included as Exhibit JMM-13. All the other provisions will remain unchanged. 14 15 VIII. Conclusion 16 Q. Does this complete your testimony? 17 A. Yes.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ INDEX OF EXHIBITS JMM-1 Impact on Total Revenue JMM-2 Rate Mapping JMM-3 Rate Paths JMM-4 Calculation of Newport Zonal Distribution Factor JMM-5 Impact on Distribution Revenue JMM-6 Impact on Transmission Revenue JMM-7 Merged Transmission Adjustment Factors JMM-8 Post Merger Transition Charges JMM-9 Blackstone Valley Typical Bills JMM-10 Newport Typical Bills JMM-11 Terms and Conditions JMM-12 Tariffs JMM-13 Adjustment Provision Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JMM-1 Exhibit JMM-1 Impact on Total Revenue Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. ____ Exhibit JMM - 1 Page 1 of 3
The Narragansett Electric Company Total Revenue Shift from Merger to BVE Customers ================================================================================================================= Percent Pre Merger Post Merger Revenue Increase/ Units Revenues Revenues Shift (Decrease) (1) (2) (3) (4) (5) ================================================================================================================= R-1 362,568,042 $40,722,906 $39,704,361 ($1,018,544) -2.50% R-2 10,464,104 $892,790 $885,564 ($7,225) -0.81% R-3 9,162,722 $931,422 $974,130 $42,708 4.59% R-4 4,487,447 $437,683 $425,523 ($12,161) -2.78% W-1 3,602,371 $324,151 $372,483 $48,333 14.91% H-1 3,639,022 $350,069 $336,483 ($13,587) -3.88% H-2 2,290,392 $233,468 $242,340 $8,872 3.80% G-1 43,670,643 $5,088,566 $5,146,385 $57,819 1.14% G-2 313,855,524 $29,719,748 $29,660,495 ($59,253) -0.20% T-2 45,916,407 $4,263,798 $3,874,164 ($389,634) -9.14% T-4 78,036,479 $6,721,747 $6,470,366 ($251,381) -3.74% G-5 23,108,580 $2,025,532 $1,986,230 ($39,302) -1.94% T-5 8,474,950 $734,846 $679,699 ($55,146) -7.50% T-6 369,857,394 $29,787,298 $29,380,332 ($406,966) -1.37% A-6 6,085,455 $553,736 $531,237 ($22,499) -4.06% S-1 14,647,035 $2,399,359 $2,402,553 $3,194 0.13% ------------- ----------- ----------- ---------- ----- Total Company 1,299,866,567 $125,187,11 $123,072,346 ($2,114,773) -1.69%
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. ____ Exhibit JMM - 1 Page 2 of 3
The Narragansett Electric Company Total Revenue Shift from Merger to Narragansett Customers ================================================================================================================= Percent Pre Merger Post Merger Revenue Increase/ Units Revenues Revenues Shift (Decrease) (1) (2) (3) (4) (5) ================================================================================================================= A-16 1,475,595,371 $146,179,613 $146,179,613 $0 0.00% A-18 299,522,556 $27,232,677 $27,232,677 $0 0.00% A-32 33,569,784 $2,847,742 $2,847,742 $0 0.00% A-60 45,194,386 $3,572,777 $3,572,777 $0 0.00% E-30 1,519,157 $109,772 $109,772 $0 0.00% E-40 12,436,324 $872,223 $872,223 $0 0.00% C-06 319,448,478 $32,857,618 $32,857,618 $0 0.00% G-02 857,825,162 $71,725,832 $71,725,832 $0 0.00% G-32 1,497,395,176 $108,041,029 $108,041,029 $0 0.00% G-62 360,114,300 $23,033,841 $23,033,841 $0 0.00% R-02 4,803,789 $308,547 $308,547 $0 0.00% S-10 49,529,091 $9,620,076 $9,620,076 $0 0.00% T-06 21,835,478 $1,763,248 $1,763,248 $0 0.00% V-02 7,686,406 $718,448 $718,448 $0 0.00% ------------- ------------ ------------ -- ----- Total Company 4,986,475,458 $428,883,443 $428,883,443 $0 0.00%
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. ____ Exhibit JMM - 1 Page 3 of 3
The Narragansett Electric Company Total Revenue Shift from Merger to Newport Customers ================================================================================================================= Percent Pre Merger Post Merger Revenue Increase/ Units Revenues Revenues Shift (Decrease) (1) (2) (3) (4) (5) ================================================================================================================= R-1 167,201,036 $19,896,925 $19,237,969 ($658,956) -3.31% R-2 1,764,819 $164,092 $162,833 ($1,259) -0.77% R-4 7,100,991 $808,011 $718,668 ($89,343) -11.06% W-1 13,383,268 $1,422,017 $1,474,430 $52,412 3.69% H-1 4,908,488 $523,570 $465,875 ($57,695) -11.02% H-2 5,723,950 $665,920 $627,794 ($38,126) -5.73% G-1 42,449,011 $5,464,085 $5,082,244 ($381,841) -6.99% G-2 105,080,586 $11,113,180 $10,298,594 ($814,586) -7.33% T-2 14,361,960 $1,497,070 $1,277,833 ($219,237) -14.64% T-4 18,430,440 $1,953,393 $1,659,268 ($294,126) -15.06% G-5 15,075,589 $1,516,935 $1,361,051 ($155,884) -10.28% T-5 2,964,000 $293,737 $251,626 ($42,112) -14.34% T-6 24,547,599 $2,453,903 $2,137,672 ($316,231) -12.89% C-1 114,919,292 $10,247,646 $9,879,737 ($367,909) -3.59% S-1 5,614,981 $852,977 $853,283 $306 0.04% ----------- ----------- ----------- ---------- ------- Total Company 543,526,010 $58,873,463 $55,488,877 ($3,384,586) -5.75%
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JMM-2 Exhibit JMM-2 Rate Paths
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 2 Page 1 of 4 SUMMARY TABLE Consolidated Average (cent)/kWh Summary of Average Rates 2000 2000 2001 2002 2003 2004 ------------------------------------------------------------------------------------ January 1 April 1 January 1 January 1 January 1 January 1 --------- ------- --------- --------- --------- --------- (1) Distribution 3.071 2.993 2.993 2.993 2.993 2.993 (1a) Cost of Removal Adj. 0.039 0.039 0.039 0.039 (2) DSM 0.230 0.230 0.230 0.230 0.230 0.230 ----- ----- ----- ----- ------ ------ (3) Total Distribution 3.301 3.223 3.262 3.262 3.262 3.262 (4) Transmission 0.415 0.415 0.415 0.415 0.415 0.415 (5) Transition 1.467 1.467 1.314 1.341 1.230 1.190 ----- ----- ----- ----- ------ ------ (6) Total Delivery 5.183 5.105 4.991 5.018 4.907 4.867 (7) Standard Offer 3.800 3.800 3.800 4.200 4.700 5.100 ----- ----- ----- ----- ------ ------ (8) Total Average Price 8.983 8.905 8.791 9.218 9.607 9.967 (9) Total Average Price Adj for GET 9.358 9.276 9.158 9.602 10.007 10.382 (10) Percent Increase/(Decrease) -0.87% -1.28% 4.86% 4.22% 3.75% Notes: (1) Weighted average of Page 2, Line (1), Page 3, Line (1), and Page 4, Line (1) (6) = Line (3) + Line (4) + Line (5) (1a) Cost of Removal impact on rates 2001 through 2004 (7) per Settlement Agreements (2) Assumed at current level through 2004 (8) = Line (6) + Line (7) (3) = Line (1) + Line (1a) + Line (2) (9) Line (8)/.96 (4) Weighted average of Page 2, Line (4), Page 3, Line (4), and Page 4, Line (4) (10) = (Line (9) - Line (9) prior column)/ (5) Weighted average of Page 2, Line (5), Page 3, Line (5), and Page 4, Line (5) Line (9) prior column
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 2 Page 2 of 4 BLACKSTONE VALLEY Consolidated Average (cent)/kWh Summary of Average Rates 2000 2000 2001 2002 2003 2004 ------------------------------------------------------------------------------------ January 1 April 1 January 1 January 1 January 1 January 1 --------- ------- --------- --------- --------- --------- (1) Distribution 3.003 2.852 2.852 2.852 2.852 2.852 (1a) Cost of Removal Adj. 0.039 0.039 0.039 0.039 (2) DSM 0.230 0.230 0.230 0.230 0.230 0.230 ----- ----- ----- ----- ------ ------ (3) Total Distribution 3.233 3.082 3.121 3.121 3.121 3.121 (4) Transmission 0.278 0.278 0.429 0.429 0.429 0.429 (5) Transition 2.320 2.320 1.759 1.859 1.446 1.298 ----- ----- ----- ----- ------ ------ (6) Total Delivery 5.831 5.680 5.309 5.409 4.996 4.848 (7) Standard Offer 3.800 3.800 3.800 4.200 4.700 5.100 ----- ----- ----- ----- ------ ------ (8) Total Average Price 9.631 9.480 9.109 9.609 9.696 9.948 (9) Total Average Price Adj for GET 10.032 9.875 9.489 10.009 10.100 10.363 (10) Percent Increase/(Decrease) -1.57% -3.91% 5.49% 0.91% 2.60% Notes: (1) Base Distribution Charges - Frozen from 2001 through 2004 (6) = Line (3) + Line (4) + Line (5) (1a) Cost of Removal impact on rates 2001 through 2004 (7) per Settlement Agreements (2) Assumed at current level through 2004 (8) = Line (6) + Line (7) (3) = Line (1) + Line (1a) + Line (2) (9) Line (8)/.96 (4) Projected 2000 BVE alone; Projected 2001-2004 Consolidated Companies (10) = (Line (9) - Line (9) prior column)/ (5) Projected 2000 BVE alone; Projected 2001-2004 Consolidated Companies Line (9) prior column
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 2 Page 3 of 4 NARRAGANSETT ELECTRIC Consolidated Average (cent)/kWh Summary of Average Rates 2000 2000 2001 2002 2003 2004 ------------------------------------------------------------------------------------ January 1 April 1 January 1 January 1 January 1 January 1 --------- ------- --------- --------- --------- --------- (1) Distribution 2.967 2.967 2.967 2.967 2.967 2.967 (1a) Cost of Removal Adj. 0.039 0.039 0.039 0.039 (2) DSM 0.230 0.230 0.230 0.230 0.230 0.230 ----- ----- ----- ----- ----- ----- (3) Total Distribution 3.197 3.197 3.236 3.236 3.236 3.236 (4) Transmission 0.466 0.466 .0409 0.409 0.409 0.409 (5) Transition 1.150 1.150 1.150 1.150 1.150 1.150 ----- ----- ----- ----- ----- ----- (6) Total Delivery 4.813 4.813 4.795 4.795 4.795 4.795 (7) Standard Offer 3.800 3.800 3.800 4.200 4.700 5.100 ----- ----- ----- ----- ----- ----- (8) Total Average Price 8.613 8.613 8.595 8.995 9.495 9.895 (9) Total Average Price Adj for GET 8.972 8.972 8.953 9.370 9.891 10.307 (10) Percent Increase/(Decrease) 0.00% -0.21% 4.65% 5.56% 4.21% Notes: (1) Base Distribution Charges - Frozen from 2001 through 2004 (5) Projected 2000 Narragansett alone; (1a) Cost of Removal impact on rates 2001 through 2004 Projected 2001-2004 Consolidated (2) Assumed at current level through 2004 Companies (3) = Line (1) + Line (1a) + Line (2) (6) = Line (3) + Line (4) + Line (5) (4) Projected 2000 Narragansett alone; Projected 2001-2004 Consolidated (7) per Settlement Agreements Companies (8) = Line (6) + Line (7) (9) Line (8)/.96 (10) = (Line (9) - Line (9) prior column)/ Line (9) prior column
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 2 Page 4 of 4 NEWPORT ELECTRIC Consolidated Average (cent)/kWh Summary of Average Rates 2000 2000 2001 2002 2003 2004 ------------------------------------------------------------------------------------ January 1 April 1 January 1 January 1 January 1 January 1 --------- ------- --------- --------- --------- --------- (1) Distribution 4.189 3.568 3.568 3.568 3.568 3.568 (1a) Cost of Removal Adj. 0.039 0.039 0.039 0.039 (2) DSM 0.230 0.230 0.230 0.230 0.230 0.230 ------ ------ ------ ------ ------ ------ (3) Total Distribution 4.419 3.798 3.837 3.837 3.837 3.837 (4) Transmission 0.273 0.273 0.431 0.431 0.431 0.431 (5) Transition 2.340 2.340 1.759 1.859 1.446 1.298 ------ ------ ------ ------ ------ ------ (6) Total Delivery 7.032 6.411 6.027 6.127 5.714 5.566 (7) Standard Offer 3.800 3.800 3.800 4.200 4.700 5.100 ------ ------ ------ ------ ------ ------ (8) Total Average Price 10.832 10.211 9.827 10.327 10.414 10.666 (9) Total Average Price Adj for GET 11.283 10.636 10.236 10.757 10.848 11.110 (10) Percent Increase/(Decrease) -5.73% -3.76% 5.09% 0.84% 2.42% Notes: (1) Base Distribution Charges - Frozen from 2001 through 2004 (6) = Line (3) + Line (4) + Line (5) (1a) Cost of Removal impact on rates 2001 through 2004 (7) per Settlement Agreements (2) Assumed at current level through 2004 (8) = Line (6) + Line (7) (3) = Line (1) + Line (1a) + Line (2) (9) Line (8)/.96 (4) Projected 2000 Newport alone; Projected 2001-2004 Consolidated Companies (10) = (Line (9) - Line (9) prior column)/ (5) Projected 2000 Newport alone; Projected 2001-2004 Consolidated Companies Line (9) prior column
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JMM-3 Exhibit JMM-3 Rate Mapping Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 3 Page 1 of 2
Narragansett Electric Company Blackstone Valley Electric Company Summary of Rate Mapping - ---------------------------------------------------------------------------------------------------- Blackstone Narragansett Rate Description Rate Description - ---------------------------------------------------------------------------------------------------- R-1 Residential Service A-16 Basic Residential - ---------------------------------------------------------------------------------------------------- R-2 Residential Low Income Service A-60 Low Income - ---------------------------------------------------------------------------------------------------- R-3 Residential Space Heating Service A-16 Basic Residential - ---------------------------------------------------------------------------------------------------- R-4 Residential Time of Use Service A-32 Residential Time of Use - ---------------------------------------------------------------------------------------------------- G-1 Small Secondary Voltage Service C-06 Small C&I - ---------------------------------------------------------------------------------------------------- C-06 Small C&I G-2 Medium Secondary Voltage Service G-02 General C&I (1036,000) G-32 200 kW Demand - ---------------------------------------------------------------------------------------------------- G-02 General C&I G-5 Medium Primary Voltage Service (10036,000) G-32 200 kW Demand - ---------------------------------------------------------------------------------------------------- T-4 Large Secondary Voltage Service G-32 200 kW Demand - ---------------------------------------------------------------------------------------------------- G-02 General C&I T-5 Medium TOU Secondary Voltage Service (1036,000) G-32 200 kW Demand - ---------------------------------------------------------------------------------------------------- G-32 200 kW Demand T-6 Medium TOU Secondary Voltage Service (1036,000) G-62 3,000 kW Demand - ---------------------------------------------------------------------------------------------------- C-06 Small C&I H-1 Space Heating Service G-02 General C&I (non-industrial) G-32 200 kW Demand - ---------------------------------------------------------------------------------------------------- C-06 Small C&I H-2 Space Heating Service G-02 General C&I (non-industrial) G-32 200 kW Demand - ---------------------------------------------------------------------------------------------------- A-16 Basic Residential W-1 Controlled Water Heating Service (all customer types) C-06 Small C&I - ---------------------------------------------------------------------------------------------------- S-1 Lighting Service S-14 General Streetlighting (company owned) - ---------------------------------------------------------------------------------------------------- A-6 Auxiliary Service B-32 200 kW Back-Up - ----------------------------------------------------------------------------------------------------
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 3 Page 2 of 2
Narragansett Electric Company Newport Electric Corporation Summary of Rate Mapping - ---------------------------------------------------------------------------------------------------- Newport Narragansett Rate Description Rate Description - ---------------------------------------------------------------------------------------------------- R-1 Residential Service A-16 Basic Residential - ---------------------------------------------------------------------------------------------------- R-2 Residential Low Income Service A-60 Low Income - ---------------------------------------------------------------------------------------------------- R-4 Residential Time of Use Service A-32 Residential Time-of-Use - ---------------------------------------------------------------------------------------------------- G-1 Small Secondary Voltage Service C-06 Small C&I - ---------------------------------------------------------------------------------------------------- C-06 Small C&I G-2 Medium Secondary Voltage Service G-02 General C&I (1036,000) G-32 200 kW Demand - ---------------------------------------------------------------------------------------------------- G-02 General C&I G-5 Medium Primary Voltage Service (10036,000) G-32 200 kW Demand - ---------------------------------------------------------------------------------------------------- T-4 Large Secondary Voltage Service G-32 200 kW Demand - ---------------------------------------------------------------------------------------------------- T-5 Medium TOU Secondary Voltage Service G-32 200 kW Demand (1036,000) - ---------------------------------------------------------------------------------------------------- T-6 Medium TOU Secondary Voltage Service G-32 200 kW Demand (1036,000) G-62 3,000 kW Demand - ---------------------------------------------------------------------------------------------------- C-06 Small C&I H-1 Space Heating Service G-02 General C&I (non-industrial) G-32 200 kW Demand - ---------------------------------------------------------------------------------------------------- C-06 Small C&I H-2 Space Heating Service (non-industrial) G-02 General C&I - ---------------------------------------------------------------------------------------------------- A-16 Basic Resident W-1 Controlled Water Heating Service C-06 Small C&I (all customer types) G-02 General C&I - ---------------------------------------------------------------------------------------------------- S-1 Lighting Service S-14 General Streetlighting (company owned) - ---------------------------------------------------------------------------------------------------- C-1 Transmission Voltage General Service N-01 69 KV Rate - ----------------------------------------------------------------------------------------------------
2 Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JMM-4 Exhibit JMM-4 Calculation of Newport Zonal Distribution Factor
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 4 Page 1 of 1 The Narragansett Electric Company Calculation of Newport Zonal Distribution Factor ===================================================================================================== Percent Pre Merger Post Merger Revenue Increase/ Units Revenues Revenues Shift (Decrease) (1) (2) (3) (4) (5) ===================================================================================================== R-1 167,201,036 $8,789,761 $6,980,462 ($1,809,299) -20.58% R-2 1,764,819 $46,855 $41,685 ($5,170) -11.03% R-4 7,100,991 $336,292 $201,219 ($135,073) -40. 17% W-1 13,383,268 $532,967 $493,017 ($39,950) -7.50% H-1 4,908,488 $197,500 $109,028 ($88,471) -44.80% H-2 5,723,950 $285,678 $201,946 ($83,733) -29.31% G-1 42,449,011 $2,644,197 $1,927,858 ($716,339) -27.09% G-2 105,080,586 $4,132,677 $2,663,385 ($1,469,292) -35.55% T-2 14,361,960 $543,005 $246,665 ($296,340) -54.57% T-4 18,430,440 $729,059 $315,676 ($413,383) -56.70% G-5 15,075,589 $515,464 $270,179 ($245,285) -47.59% T-5 2,964,000 $96,839 $41,850 ($54,989) -56.78% T-6 24,547,599 $823,206 $386,545 ($436,661) -53.04% C-1 0 $0 $0 $0 0.0% S-1 5,614,981 $479,974 $611,896 $131,922 27.49% --------- -------- -------- -------- ------ Total Company 428,606,718 $20,153,473 $14,491,409 ($5,662,063) -28.09% 50% of Savings $2,831,032 14.05% Zonal Distribution Factor to Non C-1 Newport Customers $0.00661 Calculation of C-1 Rate Pre-Merger Allocation Post Merger Adjustment Base Rates Percentage Rates Factors Distribution Distribution Charge per kW $7.68 85.95% $6.60 $6.60 Distribution Charge per kVAR $0.23 85.95% $0.20 $0.20 Distribution Charge per kWh $0.00851 85.95% $0.00731 $0.00434 $0.00297
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JMM-5 Exhibit JMM-5 Impact on Distribution Revenue
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 5 Page 1 of 3 The Narragansett Electric Company Distribution Revenue Shift by Moving BVE Customers to Narragansett Rates Percent Pre Merger Post Merger Revenue Increase/ Units Revenues Revenues Shift (Decrease) (1) (2) (3) (4) (5) =================================================================================================================================== R-1 362,568,042 $16,691,896 $15,568,207 ($1,123,689) -6.73% R-2 10,464,104 $199,229 $199,223 ($5) -0.00% R-3 9,162,722 $324,117 $364,168 $40,051 12.36% R-4 4,487,447 $140,255 $128,768 ($11,488) -8.19% W-1 3,602,371 $85,385 $132,640 $47,255 55.34% H-1 3,639,022 $108,875 $91,618 ($17,257) -15.85% H-2 2,290,392 $81,661 $85,917 $4,256 5.21% G-1 43,670,643 $2,194,076 $2,195,560 $1,484 0.07% G-2 313,855,524 $8,917,404 $8,661,946 ($255,458) -2.86% T-2 45,916,407 $1,220,459 $855,627 ($364,831) -29.89% T-4 78,036,479 $1,549,489 $1,328,989 ($220,500) -14.23% G-5 23,108,580 $493,896 $446,164 ($47,732) -9.66% T-5 8,474,950 $173,126 $129,562 ($43,564) -25.16% T-6 369,857,394 $5,273,150 $5,336,703 $63,552 1.21% A-6 6,085,455 $150,392 $115,434 ($34,958) -23.24% S-1 14,647,035 $1,428,554 $1,428,459 ($95) -0.01% Total Company 1,299,866,567 $39,031,963 $37,068,984 ($1,962,978) -5.03% See Workpaper JMM - 1 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 5 Page 2 of 3 The Narragansett Electric Company Distribution Revenue Shift from Merger to Narragansett Customers =================================================================================================================================== Percent Pre Merger Post Merger Revenue Increase/ Units Revenues Revenues Shift (Decrease) (1) (2) (3) (4) (5) =================================================================================================================================== A-16 1,475,595,371 $62,144,457 $62,144,457 $0 0.00% A-18 299,522,556 $10,321,633 $10,321,633 $0 0.00% A-32 33,569,784 $950,714 $950,714 $0 0.00% A-60 45,194,386 $1,043,247 $1,043,247 $0 0.00% E-30 1,519,157 $25,915 $25,915 $0 0.00% E-40 12,436,324 $114,501 $114,501 $0 0.00% C-06 319,448,478 $14,345,578 $14,345,578 $0 0.00% G-02 857,825,162 $23,269,571 $23,269,571 $0 0.00% G-32 1,497,395,176 $24,752,330 $24,752,330 $0 0.00% G-62 360,114,300 $3,268,759 $3,268,759 $0 0.00% R-02 4,803,789 $43,474 $43,474 $0 0.00% S-10 49,529,091 $6,887,061 $6,887,061 $0 0.00% T-06 21,835,478 $536,094 $536,094 $0 0.00% V-02 7,686,406 $272,175 $272,175 $0 0.00% Total Company 4,986,475,458 $147,975,509 $147,975,509 $0 0.00% See Workpaper JMM - 2 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 5 Page 3 of 3 The Narragansett Electric Company Distribution Revenue Shift by Moving Newport Customers to Narragansett Rates Percent Pre Merger Post Merger Revenue Increase/ Units Revenues Revenues Shift (Decrease) (1) (2) (3) (4) (5) =================================================================================================================================== R-1 167,201,036 $8,789,761 $8,085,660 ($704,100) -8.01% R-2 1,764,819 $46,855 $46,849 ($6) -0.01% R-4 7,100,991 $336,292 $248,156 ($88,136) -26.21% W-1 13,383,268 $532,967 $581,480 $48,513 9.10% H-1 4,908,488 $197,500 $141,474 ($56,026) -28.37% H-2 5,723,950 $285,678 $239,781 ($45,898) -16.07% G-1 42,449,011 $2,644,197 $2,208,446 ($435,751) -16.48% G-2 105,080,586 $4,132,677 $3,357,967 ($774,709) -18.75% T-2 14,361,960 $543,005 $341,598 ($201,408) -37.09% T-4 18,430,440 $729,059 $437,501 ($291,558) -39.99% G-5 15,075,589 $515,464 $368,832 ($146,632) -28.45% T-5 2,964,000 $96,839 $61,246 ($35,593) -36.75% T-6 24,547,599 $823,206 $547,182 ($276,024) -33.53% C-1 114,919,292 $2,613,557 $2,245,649 ($367,909) -14.08% S-1 5,614,981 $479,974 $479,932 ($42) -0.01% Total Company 543,526,010 $22,767,030 $19,391,754 ($3,375,276) -14.83% See Workpaper JMM - 3
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JMM-6 Exhibit JMM-6 Impact on Transmission Revenue
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 6 Page 1 of 3 THE NARRAGANSETT ELECTRIC COMPANY TRANSMISSION REVENUE SHIFT BY MOVING BVE CUSTOMERS TO CONSOLIDATED TRANSMISSION RATES =============================================================================================== Percent Pre Merger Post Merger Revenue Increase/ Units Revenues Revenues Shift (Decrease) (1) (2) (3) (4) (5) =============================================================================================== R-1 362,568,042 $1,007,939 $1,113,084 $105,145 10.43% R-2 10,464,104 $29,090 $21,870 ($7,220) -24.82% R-3 9,162,722 $25,472 $28,130 $2,657 10.43% R-4 4,487,447 $12,475 $11,802 ($673) -5.40% W-1 3,602,371 $10,015 $11,093 $1,078 10.76% H-1 3,639,022 $10,116 $13,786 $3,670 36.28% H-2 2,290,392 $6,367 $10,983 $4,616 72.49% G-1 43,670,643 $121,404 $177,740 $56,335 46.40% G-2 313,855,524 $872,518 $1,068,723 $196,205 22.49% T-2 45,916,407 $127,648 $102,845 ($24,802) -19.43% T-4 78,036,479 $216,941 $186,061 ($30,881) -14.23% G-5 23,108,580 $64,242 $81,984 $17,742 27.62% T-5 8,474,950 $23,560 $15,393 ($8,167) -34.66% T-6 369,857,394 $1,028,204 $706,737 ($321,466) -31.26% A-6 6,085,455 $16,918 $31,829 $14,912 88.14% S-1 14,647,035 $40,719 $19,542 ($21,177) -52.01% ---------- ------- ------- --------- ------- TOTAL COMPANY 1,299,866,567 $3,613,629 $3,601,602 ($12,027) -0.33% Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 6 Page 2 of 3 THE NARRAGANSETT ELECTRIC COMPANY TRANSMISSION REVENUE SHIFT FROM MERGER TO NARRAGANSETT CUSTOMERS =============================================================================================== Percent Pre-Merger Post Merger Revenue Increase/ Units Revenues Revenues Shift (Decrease) (1) (2) (3) (4) (5) =============================================================================================== A-16 1,475,595,371 $7,599,316 $7,599,316 $0 0.00% A-18 299,522,556 $1,395,775 $1,395,775 $0 0.00% A-32 33,569,784 $158,114 $158,114 $0 0.00% A-60 45,194,386 $188,461 $188,461 $0 0.00% E-30 1,519,157 $5,165 $5,165 $0 0.00% E-40 12,436,324 $27,360 $27,360 $0 0.00% C-06 319,448,478 $1,964,608 $1,964,608 $0 0.00% G-02 857,825,162 $4,020,918 $4,020,918 $0 0.00% G-32 1,497,395,176 $6,327,079 $6,327,079 $0 0.00% G-62 360,114,300 $1,256,287 $1,256,287 $0 0.00% R-02 4,803,789 $16,237 $16,237 $0 0.00% S-10 49,529,091 $167,408 $167,408 $0 0.00% T-06 21,835,478 $96,076 $96,076 $0 0.00% V-02 7,686,406 $48,117 $48,117 $0 0.00% --------- ------- ------- -- ----- TOTAL COMPANY 4,986,475,458 $23,270,921 $23,270,921 $0 0.00% Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JMM - 6 Page 3 of 3 THE NARRAGANSETT ELECTRIC COMPANY TRANSMISSION REVENUE SHIFT BY MOVING CUSTOMERS TO CONSOLIDATED TRANSMISSION RATES =============================================================================================== Percent Pre Merger Post Merger Revenue Increase/ Units Revenues Revenues Shift (Decrease) (1) (2) (3) (4) (5) =============================================================================================== R-1 167,201,036 $456,459 $501,603 $45,144 9.89% R-2 1,764,819 $4,818 $3,565 ($1,253) -26.01% R-4 7,100,991 $19,386 $18,179 ($1,207) -6.23% W-1 13,383,268 $36,536 $40,435 $3,899 10.67% H-1 4,908,488 $13,400 $11,731 ($1,669) -12.46% H-2 5,723,950 $15,626 $23,398 $7,771 49.73% G-1 42,449,011 $115,886 $169,796 $53,910 46.52% G-2 105,080,586 $286,870 $246,993 ($39,877) -13.90% T-2 14,361,960 $39,208 $21,379 ($17,829) -45.47% T-4 18,430,440 $50,315 $47,748 ($2,568) -5.10% G-5 15,075,589 $41,156 $37,979 ($3,177) -7.72% T-5 2,964,000 $8,092 $2,767 ($5,324) -65.80% T-6 24,547,599 $67,015 $36,700 ($30,315) -45.24% C-1 114,919,292 $313,730 $313,730 $0 0.0% S-1 5,614,981 $15,329 $7,073 ($8,256) -53.86% --------- ------- ------ -------- ------- TOTAL COMPANY 543,526,010 $1,483,826 $1,483,075 ($751) -0.05%
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JMM-7 Exhibit JMM-7 Merged Transmission Adjustment Factors Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Exhibit JMM-7 Page 1 of 7 The Narragansett Electric Company Projected Year 2000 Narragansett Only Transmission Rate Calculation of Narragansett's Projected Transmission Adjustment Factor 1 Projected Revenue on Present Rates $19,288,812 2 1998 kWh Sales less Discounted kWh 4,979,191,154 3 Average Revenue per kWh $0.00387 4 Forecasted Transmission Expenses $23,218,705 5 1998 kWh Sales less Discounted kWh 4,979,191,154 6 Average Expense per kWh $0.00466 7 Transmission Adjustment Factor per kWh $0.00079 1 Exhibit JMM - 7, Page 2 of 7 2 1998 Actual kWh Less Discounted kWh 3 Line (1) / Line (2) 4 Workpaper JMM - 4, Line (3) + Line (4) 5 Line 2 6 Line (4) / Line (5) 7 Line (6) - Line (3)
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Exhibit JMM-7 Page 2 of 7 The Narragansett Electric Company Projected Year 2000 Narragansett Only Transmission Rate Projected Transmission Revenue on Narragansett Base Rates Total A-16 A-18 A-32 A-60 E-30 C-06 Projected Billing Determinants kW Demand kW Demand in Excess of 10 kW kWh Sales 1,475,595,371 299,522,556 33,569,784 45,194,386 1,519,157 319,448,478 Less: High Voltage Metering Units Present Transmission Rate $0.00387 $0.00436 $0.00387 $0.00392 $0.00338 $0.00261 $0.00536 Projected Transmission Revenues Demand Revenues $9,436,846 $0 $0 $0 $0 $0 $0 Energy Revenues $9,872,436 $6,433,596 $1,159,152 $131,594 $152,757 $3,965 $1,712,244 Less Discounts ($20,470) $-0 $-0 $-0 $-0 $-0 $-0 Total Projected Revenues $19,288,812 $6,433,596 $1,159,152 $131,594 $152,757 $3,965 $1,712,244 E-40 G-02 G-32 G-62 T-06 V-02 Streetlight Projected Billing Determinants kW Demand 4,100,824 631,081 kW Demand in Excess of 10 kW 2,393,998 kWh Sales 12,436,324 21,835,478 7,686,406 54,332,880 Less: High Voltage Metering Units 142 9,055 6,311 Present Transmission Rate $0.00141 $1.40 $1.27 $1.39 $0.00361 $0.00547 $0.00259 Projected Transmission Revenues Demand Revenues $0 $3,351,597 $5,208,046 $877,203 $0 $0 $0 Energy Revenues $17,535 $0 $0 $0 $78,826 $42,045 $140,722 Less Discounts $-0 ($198) ($11,500) ($8,772) $-0 $-0 $-0 Total Projected Revenues $17,535 $3,351,399 $5,196,547 $868,431 $78,826 $42,045 $140,722
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Exhibit JMM-7 Page 3 of 7 The Narragansett Electric Company Projected Year 2000 Blackstone Valley Only Transmission Rate Calculation of Blackstone's Projected Transmission Adjustment Factor 1 Projected Revenue on Present Rates $5,273,670 2 1998 kWh Sales less Discounted kWh 1,296,176,588 3 Average Revenue per kWh $0.00407 4 Forecasted Transmission Expenses $3,600,024 5 1998 kWh Sales less Discounted kWh 1,296,176,588 6 Average Expense per kWh $0.00278 7 Transmission Adjustment Factor per kWh ($0.00129) 1 Exhibit JMM - 7, Page 4 of 7 2 1998 Actual kWh Less Discounted kWh 3 Line (1) / Line (2) 4 Workpaper JMM - 4, Line (5) + Line (6) 5 Line 2 6 Line (4) / Line (5) 7 Line (6) - Line (3)
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Exhibit JMM-7 Page 4 of 7 The Narragansett Electric Company Projected Year 2000 Blackstone Valley Only Transmission Rate Projected Blackstone Transmission Revenue on Narragansett Base Rates Total A-16 A-18 A-32 A-60 E-30 C-06 Projected Billing Determinants kW Demand kW Demand in Excess of 10 kW kWh Sales 375,299,762 0 4,487,447 410,464,104 0 101,265,144 Less: High Voltage Metering Units Present Transmission Rate $0.00407 $0.00436 $0.00387 $0.00392 $0.00338 $0.00261 $0.00536 Projected Transmission Revenues Demand Revenues $3,016,389 $0 $0 $0 $0 $0 $0 Energy Revenues $2,270,981 $1,636,307 $0 $17,591 $35,369 $0 $542,781 Less Discounts ($13,701) $-0 $-0 $-0 $-0 $-0 $-0 Total Projected Revenues $5,273,670 $1,636,307 $0 $17,591 $35,369 $0 $542,781 E-40 G-02 G-32 G-62 T-06 V-02 Streetlight Projected Billing Determinants kW Demand 1,493,946 142,198 kW Demand in Excess of 10 kW 658,159 kWh Sales 0 0 0 15,032,320 Less: High Voltage Metering Units 274 8,930 1,422 Present Transmission Rate $0.00141 $1.40 $1.27 $1.39 $0.00361 $0.00547 $0.00259 Projected Transmission Revenues Demand Revenues $0 $921,423 $1,897,311 $197,655 $0 $0 $0 Energy Revenues $0 $0 $0 $0 $0 $0 $38,934 Less Discounts $-0 ($383) ($11,341) ($1,977) $-0 $-0 $-0 Total Projected Revenues $0 $921,039 $1,885,970 $195,679 $0 $0 $38,934
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Exhibit JMM-7 Page 5 of 7 The Narragansett Electric Company Projected Year 2000 Newport Only Transmission Rate Calculation of Newport's Projected Transmission Adjustment Factor 1 Projected Revenue on Present Rates $2,221,874 2 1998 kWh Sales less Discounted kWh 543,235,202 3 Average Revenue per kWh $0.00409 4 Forecasted Transmission Expenses $1,483,023 5 1998 kWh Sales less Discounted kWh 543,235,202 6 Average Expense per kWh $0.00273 7 Transmission Adjustment Factor per kWh ($0.00136) 1 Exhibit JMM - 7, Page 6 of 7 2 1998 Actual kWh Less Discounted kWh 3 Line (1) / Line (2) 4 Workpaper JMM - 4, Line (7) + Line (8) 5 Line 2 6 Line (4) / Line (5) 7 Line (6) - Line (3)
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Exhibit JMM-7 Page 6 of 7 The Narragansett Electric Company Projected Year 2000 Newport Only Transmission Rate Projected Newport Transmission Revenue on Narragansett Base Rates Total A-16 A-18 A-32 A-60 C-01 C-06 Projected Billing Determinants kW Demand kW Demand in Excess of 10 kW kWh Sales 180,263,882 0 7,100,991 1,764,819 114,919,292 54,074,092 Less: High Voltage Metering Units Present Transmission Rate $0.00409 $0.00436 $0.00387 $0.00392 $0.00338 $0.00409 $0.00536 Projected Transmission Revenues Demand Revenues $628,735 $0 $0 $0 $0 $0 $0 Energy Revenues $1,594,501 $785,951 $0 $27,836 $5,965 $470,020 $289,837 Less Discounts ($1,361) $-0 $-0 $-0 $-0 $-0 $-0 Total Projected Revenues $2,221,874 $785,951 $0 $27,836 $5,965 $470,020 $289,837 E-40 G-02 G-32 G-62 T-06 V-02 Streetlight Projected Billing Determinants kW Demand 177,940 36,233 kW Demand in Excess of 10 kW 251,705 kWh Sales 0 0 0 5,750,045 Less: High Voltage Metering Units 148 512 362 Present Transmission Rate $0.00141 $1.40 $1.27 $1.39 $0.00361 $0.00547 $0.00259 Projected Transmission Revenues Demand Revenues $0 $352,387 $225,984 $50,364 $0 $0 $0 Energy Revenues $0 $0 $0 $0 $0 $0 $14,893 Less Discounts $-0 ($208) ($650) ($504) $-0 $-0 $-0 Total Projected Revenues $0 $352,179 $225,334 $49,860 $0 $0 $14,893
Narragansett Electric BVE/Newport Electric R.I.P.U.C. DocketNo. _____ Exhibit JMM-7 Page 7 of 7 The Narragansett Electric Company Projected Consolidated Transmission Rate Calculation of Projected Consolidated Transmission Adjustment Factor 1 Projected Revenue on Present Rates $26,784,356 2 1998 kWh Sales less Discounted kWh 6,818,602,945 3 Average Revenue per kWh $0.00393 4 Forecasted Transmission Expenses $28,301,752 5 1998 kWh Sales less Discounted kWh 6,818,602,945 6 Average Expense per kWh $0.00415 7 Transmission Adjustment Factor per kWh $0.00022 1 Page 1, Line (1) + Page 3, Line (1) + Page 5, Line (1) 2 Page 1, Line (2) + Page 3, Line (2) + Page 5, Line (2) 3 Line (1) / Line (2) 4 Page 1, Line (4) + Page 3, Line (4) + Page 5, Line (4) 5 Line 2 6 Line (4) / Line (5) 7 Line (6) - Line (3) Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JMM-8 Exhibit JMM-8 Post Merger Transition Charges
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Exhibit JMM - 8 Page 1 of 2 The Narragansett Electric Company Illustrative Calculation of Projected Zonal Transition Factors as of the Rate Consolidation Date Narragansett Blackstone Newport 1 Pre Merger Transition Charge $0.01150 $0.02320 $0.02340 2 Base Transition $0.01150 $0.01150 $0.01150 -------- -------- -------- 3 Zonal Transition Factor $0.00000 $0.01170 $0.01190 1 Estimated Pre Merger Transition Charges in 2000 2 Minimum Line (1) 3 Line (1) - Line (2) Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. Exhibit JMM - 8 Page 2 of 2 The Narragansett Electric Company Illustrative Calculation of Projected Zonal Transition Factors Effective January 1, 2001 Narragansett Blackstone Newport Total 1 Contract Termination Charge $0.0103 $0.0208 $0.02090 2 Estimated MWh Sales 5,000,000 1,300,000 550,000 3 Total CTC Expense $51,500,000 $27,040,000 $11,495,000 $90,035,000 4 Base Transition Charge $0.0115 $0.0115 $0.01150 5 Estimated MWh Sales 5,000,000 1,300,000 550,000 6 Base Transition Revenue $57,500,000 $14,950,000 $6,325,000 $78,775,000 7 Residual CTC Expense $11,260,000 8 Blackstone and Newport MWH Sales 1,850,000 9 Zonal Transition Factor $0.00609 $0.00609 $0.00609 10 Total Nonbypassable Transition Charges $0.0115 $0.01759 $0.01759 1 From CTC Filings 2 Estimated 3 Line (1)*Line (2)* 1000 4 Set at 1.15(cent)/kWh 5 Line (2) 6 Line (4)*Line (5)* 1000 7 Line (3) less Line (6) 8 Line (2) Blackstone plus Newport columns 9 Line (7)/(Line (8)* 1000) 10 Line (4) + Line (9)
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JMM-9 Exhibit JMM-9 Blackstone Valley Typical Bills
The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on R-1 Rate Customers Page 1 of 26 Blackstone Valley Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total ------- ----- -------- ------- ------ -------- ------- ------------- ------------- 120 $16.33 $4.75 $11.58 $15.57 $4.75 $10.82 ($0.76) -4.7% 240 $29.43 $9.50 $19.93 $28.49 $9.50 $18.99 ($0.94) -3.2% 480 $55.64 $19.00 $36.64 $54.33 $19.00 $35.33 ($1.31) -2.4% 700 $79.67 $27.71 $51.96 $78.02 $27.71 $50.31 ($1.65) -2.1% 950 $106.97 $37.60 $69.37 $104.93 $37.60 $67.33 ($2.04) -1.9% 500 $57.83 $19.79 $38.04 $56.48 $19.79 $36.69 ($1.35) -2.3% Blackstone Valley Rates: R-1 Narragansett Rates: A-16 Customer Charge $3.09 Customer Charge $2.54 Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00436 Distribution Energy Char kWh x $0.03857 Distribution Energy Char kWh x $0.03246 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on R-3 Rate Customers Page 2 of 26 Blackstone Valley Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total ------- ----- -------- ------- ------ -------- ------- ------------- ------------- 280 $31.69 $11.08 $20.61 $32.79 $11.08 $21.71 $1.10 3.5% 550 $59.34 $21.77 $37.57 $61.87 $21.77 $40.10 $2.53 4.3% 1,100 $115.64 $43.54 $72.10 $121.09 $43.54 $77.55 $5.45 4.7% 1,650 $171.95 $65.31 $106.64 $180.31 $65.31 $115.00 $8.36 4.9% 2,200 $228.25 $87.08 $141.17 $239.53 $87.08 $152.45 $11.28 4.9% Blackstone Valley Rates: R-3 Narragansett Rates A-16 Customer Charge $2.91 Customer Charge $2.54 Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00436 Distribution Energy Char kWh x $0.03200 Distribution Energy Char kWh x $0.03246 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 FAS 106 kWh x $0.00278 FAX 106 kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on W-1 Rate Customers Page 3 of 26 Blackstone Valley Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total ------- ----- -------- ------- ------ -------- ------- ------------- ------------- 750 $67.16 $29.69 $37.47 $80.76 $29.69 $51.07 $13.60 20.3% 1,500 $132.94 $59.38 $73.56 $161.52 $59.38 $102.14 $28.58 21.5% 3,000 $264.50 $118.75 $145.75 $323.03 $118.75 $204.28 $58.53 22.1% 4,600 $404.83 $182.08 $222.75 $495.31 $182.08 $313.23 $90.48 22.4% 6,000 $527.63 $237.50 $290.13 $646.06 $237.50 $408.56 $118.43 22.4% Blackstone Valley Rates: W-1 Narragansett Rates: A-16 Customer Charge $1.32 Customer Charge $0.00 Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00436 Distribution Energy Char kWh x $0.01792 Distribution Energy Char kWh x $0.03246 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on R-4 Rate Customers Page 4 of 26 KWH SPLIT: -ON-PEAK 18% -OFF-PEAK 82% Blackstone Valley Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total ------- ----- -------- ------- ------ -------- ------- ------------- ------------- 2,000 $203.74 $79.17 $124.57 $198.88 $79.17 $119.71 ($4.86) -2.4% 2,500 $253.46 $98.96 $154.50 $246.84 $98.96 $147.88 ($6.62) -2.6% 3,000 $303.17 $118.75 $184.42 $294.80 $118.75 $176.05 ($8.37) -2.8% 4,000 $402.59 $158.33 $244.26 $390.73 $158.33 $232.40 ($11.86) -2.9% 5,000 $502.03 $197.92 $304.11 $486.66 $197.92 $288.74 ($15.37) -3.1% Blackstone Valley Rates: R-4 Narragansett Rates: A-32 Customer Charge $4.69 Customer Charge $2.30 Meter Charge $0.00 Meter Charge $4.44 Transmission Energy Char kWh x $0.00000 Transmission Energy Charge kWh x $0.00392 Dist Peak Energy Charge kWh x $0.11500 Distribution Energy Charge kWh x $0.02162 Dist Off Peak Energy Cha kWh x $0.01033 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on R-4 Rate Customers Page 5 of 26 KWH SPLIT: -ON-PEAK 22% -OFF-PEAK 78% Blackstone Valley Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total ------- ----- -------- ------- ------ -------- ------- ------------- ------------- 3,000 $316.25 $118.75 $197.50 $294.80 $118.75 $176.05 ($21.45) -6.8% 4,000 $420.04 $158.33 $261.71 $390.73 $158.33 $232.40 ($29.31) -7.0% 5,000 $523.83 $197.92 $325.91 $486.66 $197.92 $288.74 ($37.17) -7.1% 6,000 $627.62 $237.50 $390.12 $582.58 $237.50 $345.08 ($45.04) -7.2% 7,000 $731.40 $277.08 $454.32 $678.51 $277.08 $401.43 ($52.89) -7.2% Blackstone Valley Rates: R-4 Narragansett Rates: A-32 Customer Charge $4.69 Customer Charge $2.30 Meter Charge $0.00 Meter Charge $4.44 Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00392 Dist Peak Energy Charge kWh x $0.11500 Dist Peak Energy Charge kWh x $0.02162 Dist Off Peak Energy Cha kWh x $0.01033 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on R-2 Rate Customers Page 6 of 26 Blackstone Valley Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total ------- ----- -------- ------- ------ -------- ------- ------------- ------------- 100 $9.18 $3.96 $5.22 $8.53 $3.96 $4.57 ($0.65) -7.1% 300 $23.34 $11.88 $11.46 $25.59 $11.88 $13.71 $2.25 9.6% 500 $44.37 $19.79 $24.58 $44.17 $19.79 $24.38 ($0.20) -0.5% 700 $65.41 $27.71 $37.70 $62.76 $27.71 $35.05 ($2.65) -4.1% 1,000 $96.97 $39.58 $57.39 $90.63 $39.58 $51.05 ($6.34) -6.5% Blackstone Valley Rates: R-2 Narragansett Rates: A-60 Customer Charge $2.01 Customer Charge $0.00 Transmission Energy Charge kWh x $0.00000 Transmission Energy Char kWh x $0.00338 Dist Energy Charge first 300 kWh x $0.00170 Distribution Energy Char kWh x $0.02521 Dist Energy Charge excess 300 kWh x $0.03470 FAS 106 kWh x $0.00068 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129) Credit First 300 kWh kWh x ($0.00733) A-60 Rate Credit kWh x $0.00000 A-60 Rate Credit kWh x ($0.00227) Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on H-1 Rate Customers Page 7 of 26 Blackstone Valley Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total ------- ----- -------- ------- ------ -------- ------- ------------- ------------- 500 $53.15 $19.79 $33.36 $61.46 $19.79 $41.67 $8.31 15.6% 1,500 $153.19 $59.38 $93.81 $172.46 $59.38 $113.08 $19.27 12.6% 2,500 $253.22 $98.96 $154.26 $283.44 $98.96 $184.48 $30.22 11.9% 3,500 $353.24 $138.54 $214.70 $394.43 $138.54 $255.89 $41.19 11.7% 4,500 $453.28 $178.13 $275.15 $505.43 $178.13 $327.30 $52.15 11.5% Blackstone Valley Rates: H-1 Narragansett Rates: C-06 Customer Charge $3.01 Customer Charge $5.73 Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00536 Distribution Energy Char kWh x $0.02975 Distribution Energy Char kWh x $0.03464 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on H-2 Rate Customers Page 8 of 26 Blackstone Valley Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total ------- ----- -------- ------- ------ -------- ------- ------------- ------------- 500 $55.91 $19.79 $36.12 $55.49 $19.79 $35.70 ($0.42) -.08% 1,000 $108.25 $39.58 $68.67 $110.99 $39.58 $71.41 $2.74 2.5% 1,500 $160.59 $59.38 $101.21 $166.49 $59.38 $107.11 $5.90 3.7% 2,000 $212.93 $79.17 $133.76 $221.98 $79.17 $142.81 $9.05 4.3% 2,500 $265.27 $98.96 $166.31 $227.48 $98.96 $178.52 $12.21 4.6% Blackstone Valley Rates: H-2 Narragansett Rates: C-06 Customer Charge $3.43 Customer Charge $0.00 Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00536 Distribution Energy Char kWh x $0.03421 Distribution Energy Char kWh x $0.03464 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on G-1 Rate Customers Page 9 of 26 Blackstone Valley Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total ------- ----- -------- ------- ------ -------- ------- ------------- ------------- 250 $32.10 $9.90 $22.20 $33.72 $9.90 $23.82 $1.62 5.0% 500 $60.68 $19.79 $40.89 $61.46 $19.79 $41.67 $0.78 1.3% 750 $89.26 $26.69 $59.57 $89.21 $29.69 $59.52 ($0.05) -0.1% 1,000 $117.84 $39.58 $78.26 $116.96 $39.58 $77.38 ($0.88) -0.7% 1,250 $146.43 $49.48 $96.95 $144.71 $49.48 $95.23 ($1.72) -1.2% Blackstone Valley Rates: G-1 Narragansett Rates: C-06 Customer Charge $3.37 Customer Charge $5.73 Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00536 Distribution Energy Char kWh x $0.04348 Distribution Energy Char kWh x $0.03464 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on W-1 Rate Customers Page 10 of 26 Blackstone Valley Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total ------- ----- -------- ------- ------ -------- ------- ------------- ------------- 125 $12.34 $4.95 $7.39 $13.88 $4.95 $8.93 $1.54 12.5% 250 $23.31 $9.90 $13.41 $27.75 $9.90 $17.85 $4.44 19.0% 375 $34.26 $14.84 $19.42 $41.62 $14.84 $26.78 $7.36 21.5% 500 $45.23 $19.79 $25.44 $55.49 $19.79 $35.70 $10.26 22.7% 1,000 $89.08 $39.58 $49.50 $110.99 $39.58 $71.41 $21.91 24.6% Blackstone Valley Rates: W-1 Narragansett Rates: C-06 Customer Charge $1.32 Customer Charge $0.00 Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00536 Distribution Energy Char kWh x $0.01792 Distribution Energy Char kWh x $0.03464 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on H-1 Rate Customers Page 11 of 26 Hours Use: 300 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 20 6,000 $603.32 $237.50 $365.82 $605.80 $237.50 $368.30 $2.48 0.4% 50 15,000 $1,503.60 $593.75 $909.85 $1,420.27 $593.75 $826.52 ($83.33) -5.5% 100 30,000 $3,004.07 $1,187.50 $1,816.57 $2,777.72 $1,187.50 $1,590.22 ($226.35) -7.5% 150 45,000 $4,504.54 $1,781.25 $2,723.29 $4,135.17 $1,781.25 $2,353.92 ($369.37) -8.2% Blackstone Valley Rates: H-1 Narragansett Rates: G-02 Customer Charge $3.01 Customer Charge $103.41 Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40 Distribution Demand Charge kW x $0.00 Distribution Demand Charge-xcs 10 kW kW x $2.91 Distribution Energy Charge kWh x $0.02975 Distribution Energy Charge kWh x $0.00596 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on H-2 Rate Customers Page 12 of 26 Hours Use: 300 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 20 6,000 $631.64 $237.50 $394.14 $498.08 $237.50 $260.58 ($133.56) -21.1% 50 15,000 $1,573.73 $593.75 $979.98 $1,312.55 $593.75 $718.80 ($261.18) -16.6% 100 30,000 $3,143.89 $1,187.50 $1,956.39 $2,670.00 $1,187.50 $1,482.50 ($473.89) -15.1% 150 45,000 $4,714.04 $1,781.25 $2,932.79 $4,027.45 $1,781.25 $2,246.20 ($686.59) -14.6% Blackstone Valley Rates: H-2 Narragansett Rates: G-02 Customer Charge $3.43 Customer Charge $0.00 Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40 Distribution Demand Charge kW x $0.00 Distribution Demand Charge-xcs 10 kW kW x $2.91 Distribution Energy Charge kWh x $0.03421 Distribution Energy Charge kWh x $0.00596 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on G-2 te Customers Page 13 of 26 Hours Use: 300 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 20 6,000 $589.00 $237.50 $351.50 $605.80 $237.50 $368.30 $16.80 2.9% 50 15,000 $1,472.50 $593.75 $878.75 $1,420.27 $593.75 $826.52 ($52.23) -3.5% 100 30,000 $2,945.00 $1,187.50 $1757.50 $2,777.72 $1,187.50 $1,590.22 ($167.28) -5.7% 150 45,000 $4,417.50 $1,781.25 $2,636.25 $4,135.17 $1,781.25 $2,353.92 ($282.33) -6.4% Blackstone Valley Rates: G-2 Narragansett Rates: G-02 Customer Charge $0.00 Customer Charge $103.41 Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40 Distribution Demand Charge kW x $1.50 Distribution Demand Charge-xcs 10 kW kW x $2.91 Distribution Energy Charge kWh x $0.02296 Distribution Energy Charge kWh x $0.00596 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on T-2 Rate Customers Page 14 of 26 Hours Use: 300 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 20 6,000 $589.00 $237.50 $351.50 $605.80 $237.50 $368.30 $16.80 2.9% 50 15,000 $1,472.50 $593.75 $878.75 $1,420.27 $593.75 $826.52 ($52.23) -3.5% 100 30,000 $2,945.00 $1,187.50 $1757.50 $2,777.72 $1,187.50 $1,590.22 ($167.28) -5.7% 150 45,000 $4,417.50 $1,781.25 $2,636.25 $4,135.17 $1,781.25 $2,353.92 ($282.33) -6.4% Blackstone Valley Rates: T-2 Narragansett Rates: G-02 Customer Charge $0.00 Customer Charge $103.41 Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40 Distribution Demand Charge kW x $1.50 Distribution Demand Charge-xcs 10 kW kW x $2.91 Distribution Energy Charge kWh x $0.02296 Distribution Energy Charge kWh x $0.00596 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on G-5 Rate Customers Page 15 of 26 Hours Use: 400 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 20 8,000 $722.96 $316.67 $406.29 $756.87 $316.67 $440.20 $33.91 4.7% 50 20,000 $1,807.40 $791.67 $1,015.73 $1,797.93 $791.67 $1,006.26 ($9.47) -0.5% 100 40,000 $3,614.79 $1,583.33 $2,031.46 $3,533.03 $1,583.33 $1,949.70 ($81.76) -2.3% 150 60,000 $5,422.19 $2,375.00 $3,047.19 $5,268.14 $2,375.00 $2,893.14 ($154.05) -2.8% Blackstone Valley Rates: G-5 Narragansett Rates: G-02 Customer Charge $0.00 Customer Charge $103.41 Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40 Distribution Demand Charge kW x $1.35 Distribution Demand Charge-xcs 10 kW kW x $2.91 Distribution Energy Charge kWh x $0.01710 Distribution Energy Charge kWh x $0.00596 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on T-5 Rate Customers Page 16 of 26 Hours Use: 350 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 20 7,000 $636.10 $277.08 $359.02 $681.33 $277.08 $404.25 $45.23 7.1% 50 17,500 $1,590.26 $692.71 $897.55 $1,609.10 $692.71 $916.39 $18.84 1.2% 100 35,000 $3,180.52 $1,385.42 $1,795.10 $3,155.38 $1,385.42 $1,769.96 ($25.14) -0.8% 150 52,500 $4,770.79 $2,078.13 $2,692.66 $4,701.66 $2,078.13 $2,623.53 ($69.13) -1.4% Blackstone Valley Rates: T-5 Narragansett Rates: G-02 Customer Charge $0.00 Customer Charge $103.41 Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40 Distribution Demand Charge kW x $1.35 Distribution Demand Charge-xcs 10 kW kW x $2.91 Distribution Energy Charge kWh $0.01710 Distribution Energy Charge kWh x $0.00596 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on W-1Rate Customers Page 17 of 26 Hours Use: 100 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 1 100 $10.15 $3.96 $6.19 $7.55 $3.96 $3.59 ($2.60) -25.6% 3 300 $27.69 $11.88 $15.81 $22.66 $11.88 $10.78 ($5.03) -18.2% 5 500 $45.23 $19.79 $25.44 $37.76 $19.79 $17.97 ($7.47) -16.5% 10 1,000 $89.08 $39.58 $49.50 $75.53 $39.58 $35.95 ($13.55) -15.2% Blackstone Valley Rates: W-1 Narragansett Rates: G-02 Customer Charge $1.32 Customer Charge $0.00 Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40 Distribution Demand Charge kW x $0.00 Distribution Demand Charge-xcs 10 kW kW x $2.91 Distribution Energy Charge kWh x $0.01792 Distribution Energy Charge kWh x $0.00596 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on H-1 Rate Customers Page 18 of 26 Hours Use: 300 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 200 60,000 $6,005.01 $2,375.00 $3,630.01 $5,435.86 $2,375.00 $3,060.86 ($569.15) -9.5% 300 90,000 $9,005.95 $3,562.50 $5,443.45 $8,030.66 $3,562.50 $4,468.16 ($975.29) -10.8% 400 120,000 $12,006.89 $4,750.00 $7,256.89 $10,625.45 $4,750.00 $5,875.45 ($1,381.44) -11.5% 500 150,000 $15,007.82 $5,937.50 $9,070.32 $13,220.24 $5,937.50 $7,282.74 ($1,787.58) -11.9% 600 180,000 $18,008.76 $7,125.00 $10,883.76 $15,815.03 $7,125.00 $8,690.03 ($2,193.73) -12.2% Blackstone Valley Rates: H-1 Narragansett Rates: G-32 Customer Charge $3.01 Customer Charge $236.43 Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27 Distribution Demand Charge kW x $0.00 Distribution Demand Charge kW x $1.56 Distribution Energy Charge kWh x $0.02975 Distribution Energy Charge kWh x $0.00705 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on H-2 Rate Customers Page 19 of 26 Hours Use: 300 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 200 60,000 $6,284.20 $2,375.00 $3,909.20 $5,435.86 $2,375.00 $3,060.86 ($848.34) -13.5% 300 90,000 $9,424.51 $3,562.50 $5,862.01 $8,030.66 $3,562.50 $4,468.16 ($1,393.85) -14.8% 400 120,000 $12,564.82 $4,750.00 $7,814.82 $10,625.45 $4,750.00 $5,875.45 ($1,939.37) -15.4% 500 150,000 $15,705.14 $5,937.50 $9,767.64 $13,220.24 $5,937.50 $7,282.7 ($2,484.90) -15.8% 600 180,000 $18,845.45 $7,125.00 $11,720.45 $15,815.03 $7,125.00 $8,690.03 ($3,030.42) -16.1% Blackstone Valley Rates: H-2 Narragansett Rates: G-32 Customer Charge $3.43 Customer Charge $236.43 Transmission Demand Charge kW x $0.00 Transmission Demand Char kW x $1.27 Distribution Demand Charge kW x $0.00 Distribution Demand Charge kW x $1.56 Distribution Energy Charge kWh x $0.03421 Distribution Energy Charge kWh x $0.00705 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on G-2 Rate Customers Page20 of 26 Hours Use: 300 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 200 60,000 $5,523.75 $2,375.00 $3,148.75 $5,435.86 $2,375.00 $3,060.86 ($ 87.89) -1.6% 300 90,000 $8,285.63 $3,562.50 $4,723.13 $8,030.66 $3,562.50 $4,468.16 ($254.97) -3.1% 400 120,000 $11,047.50 $4,750.00 $6,297.50 $10,625.45 $4,750.00 $5,875.45 ($422.05) -3.8% 500 150,000 $13,809.38 $5,937.50 $7,871.88 $13,220.24 $5,937.50 $7,282.74 ($589.14) -4.3% 600 180,000 $16,571.25 $7,125.00 $9,446.25 $15,815.03 $7,125.00 $8,690.03 ($756.22) -4.6% Blackstone Valley Rates: G-2 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27 Distribution Demand Charge kW x $1.50 Distribution Demand Charge kW x $1.56 Distribution Energy Charge kWh x $0.01710 Distribution Energy Charge kWh x $0.00705 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on T-2 Rate Customers Page 21 of 26 Hours Use: 400 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 500 200,000 $19,372.92 $7,916.67 $11,456.25 $17,053.58 $7,916.67 $9,136.91 ($2,319.34) -12.0% 1,000 400,000 $38,745.83 $15,833.33 $22,912.50 $33,860.86 $15,833.33 $18,027.53 ($4,884.97) -12.6% 1,500 600,000 $58,118.75 $23,750.00 $34,368.75 $50,668.16 $23,750.00 $26,918.16 ($7,450.59) -12.8% 2,000 800,000 $77,491.67 $31,666.67 $45,825.00 $67,475.45 $31,666.67 $35,808.78 ($10,016.22) -12.9% 2,500 1,000,000 $96,864.58 $39,583.33 $57,281.25 $84,282.74 $39,583.33 $44,699.41 ($12,581.84) -13.0% Blackstone Valley Rates: T-2 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27 Distribution Demand Charge kW x $1.50 Distribution Demand Charge kW x $1.56 Distribution Energy Charge kWh x $0.02296 Distribution Energy Charge kWh x $0.00705 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on T-4 Rate Customers Page 22 of 26 Hours Use: 400 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 500 200,000 $17,943.75 $7,916.67 $10,027.08 $17,053.58 $7,916.67 $9,136.91 ($890.17) -5.0% 1,000 400,000 $35,887.50 $15,833.33 $20,054.17 $33,860.86 $15,833.33 $18,027.53 ($2,026.64) -5.6% 1,500 600,000 $53,831.25 $23,750.00 $30,081.25 $50,668.16 $23,750.00 $26,918.16 ($3,163.09) -5.9% 2,000 800,000 $71,775.00 $31,666.67 $40,108.33 $67,475.45 $31,666.67 $35,808.78 ($4,299.55) -6.0% 2,500 1,000,000 $89,718.75 $39,583.33 $50,135.42 $84,282.74 $39,583.33 $44,699.41 ($5,436.01) -6.1% Blackstone Valley Rates: T-4 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27 Distribution Demand Charge kW x $1.44 Distribution Demand Charge kW x $1.56 Distribution Energy Charge kWh x $0.01625 Distribution Energy Charge kWh x $0.00705 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on G-5 Rate Customers Page 23 of 26 Hours Use: 300 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 200 60,000 $5,492.50 $2,375.00 $3,117.50 $5,435.86 $2,375.00 $3,060.86 ($56.64) -1.0% 300 90,000 $8,238.75 $3,562.50 $4,676.25 $8,030.66 $3,562.50 $4,468.16 ($208.09) -2.5% 400 120,000 $10,985.00 $4,750.00 $6,235.00 $10,625.45 $4,750.00 $5,875.45 ($359.55) -3.3% 500 150,000 $13,731.25 $5,937.50 $7,793.75 $13,220.24 $5,937.50 $7,282.74 ($511.01) -3.7% 600 180,000 $16,477.50 $7,125.00 $9,352.50 $15,815.03 $7,125.00 $8,690.03 ($662.47) -4.0% Blackstone Valley Rates: G-5 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27 Distribution Demand Charge kW x $1.35 Distribution Demand Charge kW x $1.56 Distribution Energy Charge kWh x $0.01710 Distribution Energy Charge kWh x $0.00705 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on T-5 Rate Customers Page 24 of 26 Hours Use: 400 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 200 80,000 $7,229.59 $3,166.67 $4,062.92 $6,969.20 $3,166.67 $3,802.53 ($260.39) -3.6% 300 120,000 $10,844.38 $4,750.00 $6,094.38 $10,330.66 $4,750.00 $ 5,580.66 ($513.72) -4.7% 400 160,000 $14,459.16 $6,333.33 $8,125.83 $13,692.11 $ 6,333.33 $ 7,358.78 ($767.05) -5.3% 500 200,000 $18,073.96 $7,916.67 $10,157.29 $17,053.58 $ 7,916.67 $9,136.91 ($1,020.38) -5.6% 600 240,000 $21,688.75 $9,500.00 $12,188.75 $20,415.03 $ 9,500.00 $ 10,915.03 ($1,273.72) -5.9% Blackstone Valley Rates: T-5 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kW x $0.00 Transmission Demand Char kW x $1.27 Distribution Demand Charge kW x $1.35 Distribution Demand Charge kW x $1.56 Distribution Energy Charge kWh x $0.01710 Distribution Energy Charge kWh x $0.00705 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on T-6 Rate Customers Page 25 of 26 Hours Use: 450 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 500 225,000 $18,900.78 $8,906.25 $9,994.53 $18,970.24 $8,906.25 $10,063.99 $69.46 0.4% 1,000 450,000 $37,801.56 $17,812.50 $19,989.06 $37,694.20 $17,812.50 $19,881.70 ($107.36) -0.3% 1,500 675,000 $56,702.34 $26,718.75 $29,983.59 $56,418.16 $26,718.75 $29,699.41 ($284.18) -0.5% 2,000 900,000 $75,603.13 $35,625.00 $39,978.13 $75,142.11 $35,625.00 $39,517.11 ($461.02) -0.6% 2,500 1,125,000 $94,503.91 $44,531.25 $49,972.66 $93,866.07 $44,531.25 $49,334.82 ($637.84) -0.7% Blackstone Valley Rates:T-6 Narragansett RatesG-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27 Distribution Demand Charge kW x $1.32 Distribution Demand Charge kW x $1.56 Distribution Energy Charge kWh x $0.01143 Distribution Energy Charge kWh x $0.00705 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company The Narragansett Electric Company Calculation of Monthly Typical Bill R.I.P.U.C. Docket Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9 Impact on T-6 Rate Customers Page 26 of 26 Hours Use: 600 Blackstone Valley Rates Narragansett Rates Difference Monthly Power Standard Standard kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total --- --- ----- -------- ------- ------ -------- ------- ------------- ------------- 3,000 1,800,000 $149,831.25 $71,250.00 $78,581.25 $149,300.75 $71,250.00 $78,050.75 ($530.50) -0.4% 4,000 2,400,000 $199,775.00 $95,000.00 $104,775.00 $193,123.67 $95,000.00 $98,123.67 ($6,651.33) -3.3% 5,000 3,000,000 $249,718.75 $118,750.00 $130,968.75 $236,946.58 $118,750.00 $118,196.58 ($12,772.17) -5.1% 6,000 3,600,000 $299,662.50 $142,500.00 $157,162.50 $280,769.50 $142,500.00 $138,269.50 ($18,893.00) -6.3% 7,000 4,200,000 $349,606.25 $166,250.00 $183,356.25 $324,592.42 $166,250.00 $158,342.42 ($25,013.83) -7.2% Blackstone Valley Rates: T-6 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $17,118.72 Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.39 Distribution Demand Charge kW x $1.32 Distribution Demand Charge kW x $0.75 Transition Demand Charge kWh x $0.00 Transition Demand Charge kWh x $0.00 Distribution Energy Charge kWh x $0.01143 Distribution Energy Charge kWh x $0.00000 Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129) PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JMM-10 Exhibit JMM-10 Newport Typical Bills
The Narragansett Electric Company Range: A-10 THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 1 of 23 IMPACT ON R-1 RATE CUSTOMERS Newport Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 120 $17.35 $4.75 $12.60 $16.41 $4.75 $11.66 ($0.94) -5.4% 240 $31.47 $9.50 $21.97 $30.17 $9.50 $20.67 ($1.30) -4.1% 480 $59.71 $19.00 $40.71 $57.70 $19.00 $38.70 ($2.01) -3.4% 700 $85.60 $27.71 $57.89 $82.94 $27.71 $55.23 ($2.66) -3.1% 950 $115.01 $37.60 $77.41 $111.60 $37.60 $74.00 ($3.41) -3.0% 500 $62.06 $19.79 $42.27 $59.99 $19.79 $40.20 ($2.07) -3.3% Newport Rates: R-1 Narragansett Rates: A-16 Customer Charge $3.10 Customer Charge $2.54 Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00436 Distribution Energy Charge kWh x $0.04653 Distribution Energy Charge kWh x $0.03246 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 1 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: TA THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 2 of 23 IMPACT ON W-1 RATE CUSTOMERS Newport Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 750 $74.07 $29.69 $44.38 $86.03 $29.69 $56.34 $11.96 16.1% 1,500 $144.71 $59.38 $85.33 $172.05 $59.38 $112.67 $27.34 18.9% 3,000 $285.99 $118.75 $167.24 $344.09 $118.75 $225.34 $58.10 20.3% 4,600 $436.69 $182.08 $254.61 $527.61 $182.08 $345.53 $90.92 20.8% 6,000 $568.55 $237.50 $331.05 $688.19 $237.50 $450.69 $119.64 21.0% Newport Rates: W-1 Narragansett Rates: A-16 Customer Charge $3.29 Customer Charge $0.00 Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00436 Distribution Energy Charge kWh x $0.02399 Distribution Energy Charge kWh x $0.03246 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 2 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: A-30A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 3 of 23 IMPACT ON R-4 RATE CUSTOMERS KWH SPLIT: -ON-PEAK 23% -OFF-PEAK 77% Newport Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 2,000 $248.04 $79.17 $168.87 $212.92 $79.17 $133.75 ($35.12) -14.2% 2,500 $308.29 $98.96 $209.33 $264.39 $98.96 $165.43 ($43.90) -14.2% 3,000 $368.53 $118.75 $249.78 $315.86 $118.75 $197.11 ($52.67) -14.3% 4,000 $489.01 $158.33 $330.68 $418.81 $158.33 $260.48 ($70.20) -14.4% 5,000 $609.51 $197.92 $411.59 $521.76 $197.92 $323.84 ($87.75) -14.4% Newport Rates: R-4 Narragansett Rates: A-32 Customer Charge $6.78 Customer Charge $2.30 Meter Charge $0.00 Meter Charge $4.44 Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00392 Dist Peak Energy Charge kWh x $0.11000 Distribution Energy Charge kWh x $0.02162 Dist Off Peak Energy Charge kWh x $0.03109 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 3 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: A-30B THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 4 of 23 IMPACT ON R-4 RATE CUSTOMERS KWH SPLIT: -ON-PEAK 26% -OFF-PEAK 77% Newport Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 3,000 $375.93 $118.75 $257.18 $315.86 $118.75 $197.11 ($60.07) -16.0% 4,000 $498.88 $158.33 $340.55 $418.81 $158.33 $260.48 ($80.07) -16.0% 5,000 $621.84 $197.92 $423.92 $521.76 $197.92 $323.84 ($100.08) -16.1% 6,000 $744.79 $237.50 $507.29 $624.71 $237.50 $387.21 ($120.08) -16.1% 7,000 $867.74 $277.08 $590.66 $727.65 $277.08 $450.57 ($140.09) -16.1% Newport Rates: R-4 Narragansett Rates: A-32 Customer Charge $6.78 Customer Charge $2.30 Meter Charge $0.00 Meter Charge $4.44 Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00392 Dist Peak Energy Charge kWh x $0.11000 Distribution Energy Charge kWh x $0.02162 Dist Off Peak Energy Charge kWh x $0.03109 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 4 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: A-65A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:49 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 5 of 23 IMPACT ON R-2 RATE CUSTOMERS Newport Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 100 $9.94 $3.96 $5.98 $9.35 $3.96 $5.39 ($0.59) -5.9% 300 $25.37 $11.88 $13.49 $28.06 $11.88 $16.18 $2.69 10.6% 500 $47.96 $19.79 $28.17 $48.05 $19.79 $28.26 $0.09 0.2% 700 $70.57 $27.71 $42.86 $68.04 $27.71 $40.33 ($2.53) -3.6% 1,000 $104.46 $39.58 $64.88 $98.02 $39.58 $58.44 ($6.44) -6.2% Newport Rates: R-2 Narragansett Rates: A-60 Customer Charge $2.14 Customer Charge $0.00 Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00338 Dist. Energy Charge first 300 kWh kWh x $0.00759 Distribution Energy Charge kWh x $0.02521 Dist. Energy Charge excess 300 kWh kWh x $0.04206 Dist. Surcharge & FAS 106 kWh x $0.00729 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) Credit First 300 kWh kWh x ($0.00616) A-60 Rate Credit kWh x $0.00000 A-60 Rate Credit kWh x ($0.00227) Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 5 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: A-02A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 6 of 23 IMPACT ON H1 RATE CUSTOMERS Newport Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 500 $67.80 $19.79 $48.01 $64.97 $19.79 $45.18 ($2.83) -4.2% 1,500 $178.33 $59.38 $118.95 $182.99 $59.38 $123.61 $4.66 -2.6% 2,500 $288.86 $98.96 $189.90 $301.00 $98.96 $202.04 $12.14 4.2% 3,500 $399.39 $138.54 $260.85 $419.00 $138.54 $280.46 $19.61 4.9% 4,500 $509.93 $178.13 $331.80 $537.02 $178.13 $358.89 $27.09 5.3% Newport Rates: H-1 Narragansett Rates: C-06 Customer Charge $12.03 Customer Charge $5.73 Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00536 Distribution Energy Charge kWh x $0.03968 Distribution Energy Charge kWh x $0.03464 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 6 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: A-02B THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 7 of 23 IMPACT ON H-2 RATE CUSTOMERS Newport Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 500 $63.76 $19.79 $43.97 $59.00 $19.79 $39.21 ($4.76) -7.5% 1,000 $122.74 $39.58 $83.16 $118.01 39.58 $78.43 ($4.73) -3.9% 1,500 $181.72 $59.38 $122.34 $117.02 $59.38 $117.64 ($4.70) -2.6% 2,000 $240.70 $79.17 $161.53 $236.02 $79.17 $156.85 ($4.68) -1.9% 2,500 $299.68 $98.96 $200.72 $295.03 $98.96 $196.07 ($4.65) -1.6% Newport Rates: H-2 Narragansett Rates: C-06 Customer Charge $4.59 Customer Charge $0.00 Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00536 Distribution Energy Charge kWh x $0.04681 Distribution Energy Charge kWh x $0.03464 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 7 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: C-02C THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 8 of 23 IMPACT ON G-1 RATE CUSTOMERS Newport Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 250 $36.08 $9.90 $26.18 $35.48 $9.90 $25.58 ($0.60) -1.7% 500 $68.57 $19.79 $48.78 $64.97 $19.79 $45.18 ($3.60) -5.3% 750 $101.06 $29.69 $71.37 $94.48 $29.69 $64.79 ($6.58) -6.5% 1,000 $133.54 $39.58 $93.96 $123.98 $39.58 $84.40 ($9.56) -7.2% 1,250 $166.03 $49.48 $116.55 $153.48 $49.48 $104.00 ($12.55) -7.6% Newport Rates: G-1 Narragansett Rates: C-06 Customer Charge $3.45 Customer Charge $5.73 Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00536 Distribution Energy Charge kWh x $0.05832 Distribution Energy Charge kWh x $0.03464 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 8 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: C-02D THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 9 of 23 IMPACT ON W-1 RATE CUSTOMERS Newport Rates Narragansett Rates Difference Monthly Standard Standard kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 125 $15.20 $4.95 $10.25 $14.75 $4.95 $9.80 ($0.45) -3.0% 250 $26.98 $9.90 $17.08 $29.51 $9.90 $19.61 $2.53 9.4% 375 $38.74 $14.84 $23.90 $44.25 $14.84 $29.41 $5.51 14.2% 500 $50.52 $19.79 $30.73 $59.00 $19.79 $39.21 $8.48 16.8% 1,000 $97.61 $39.58 $58.03 $118.01 $39.58 $78.43 $20.40 20.9% Newport Rates: W-1 Narragansett Rates: C-06 Customer Charge $3.29 Customer Charge $0.00 Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00536 Distribution Energy Charge kWh x $0.02399 Distribution Energy Charge kWh x $0.03464 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 9 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-00 THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 10 of 23 IMPACT ON H-1 RATE CUSTOMERS Hours Use: 300 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 20 6,000 $675.72 $237.50 $438.22 $647.93 $237.50 $410.43 ($27.29) -4.1% 50 15,000 $1,670.50 $593.75 $1,076.75 $1,525.58 $593.75 $931.83 ($144.92) -8.7% 100 30,000 $3,328.47 $1,187.50 $2,140.97 $2,988.34 $1,187.50 $1,800.84 ($340.13) -10.2% 150 45,000 $4,986.44 $1,781.25 $3,205.19 $4,451.10 $1,781.25 $2,669.85 ($535.34) -10.7% Newport Rates: H-1 Narragansett Rates: G-02 Customer Charge $12.03 Customer Charge $103.41 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40 Distribution Demand Charge kWh x $0.00 Distribution Demand Charge-xcs 10 kW kWh x $2.91 Distribution Energy Charge kWh x $0.03968 Distribution Energy charge kWh x $0.00596 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 10 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-00A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 11 of 23 IMPACT ON H-2 RATE CUSTOMERS Hours Use: 300 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 20 6,000 $712.53 $237.50 $475.03 $540.21 $237.50 $302.71 ($172.32) -24.2% 50 15,000 $1,774.16 $593.75 $1,180.41 $1,417.86 $593.75 $824.11 ($356.30) -20.1% 100 30,000 $3,543.53 $1,187.50 $2,356.03 $2,880.63 $1,187.50 $1,693.13 ($662.90) -18.7% 150 45,000 $5,312.91 $1,781.25 $3,531.66 $4,343.39 $1,781.25 $2,562.14 ($969.52) -18.2% Newport Rates: H-2 Narragansett Rates: G-02 Customer Charge $4.59 Customer Charge $0.00 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40 Distribution Demand Charge kWh x $0.00 Distribution Demand Charge-xcs 10 kW kWh x $2.91 Distribution Energy Charge kWh x $0.04681 Distribution Energy charge kWh x $0.00596 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 11 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-00B THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 12 of 23 IMPACT ON G-2 RATE CUSTOMERS Hours Use: 300 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 20 6,000 $663.71 $237.50 $426.21 $647.93 $237.50 $410.43 ($15.78) -2.4% 50 15,000 $1,659.27 $593.75 $1,065.52 $1,525.58 $593.75 $931.83 ($133.69) -8.1% 100 30,000 $3,318.54 $1,187.50 $2,131.04 $2,988.34 $1,187.50 $1,800.84 ($330.20) -10.0% 150 45,000 $4,977.81 $1,781.25 $3,196.56 $4,451.10 $1,781.25 $2,669.85 ($526.71) -10.6% Newport Rates: G-2 Narragansett Rates: G-02 Customer Charge $0.00 Customer Charge $103.41 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40 Distribution Demand Charge kWh x $1.60 Distribution Demand Charge-xcs 10 kW kWh x $2.91 Distribution Energy Charge kWh x $0.03443 Distribution Energy charge kWh x $0.00596 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 12 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-00C THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 13 of 23 IMPACT ON T-2 RATE CUSTOMERS Hours Use: 300 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 20 6,000 $663.71 $237.50 $426.21 $647.93 $237.50 $410.43 ($15.78) -2.4% 50 15,000 $1,659.27 $593.75 $1,065.52 $1,525.58 $593.75 $931.83 ($133.69) -8.1% 100 30,000 $3,318.54 $1,187.50 $2,131.04 $2,988.34 $1,187.50 $1,800.84 ($330.20) -10.0% 150 45,000 $4,977.81 $1,781.25 $3,196.56 $4,451.10 $1,781.25 $2,669.85 ($526.71) -10.6% Newport Rates: T-2 Narragansett Rates: G-02 Customer Charge $0.00 Customer Charge $103.41 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40 Distribution Demand Charge kWh x $1.60 Distribution Demand Charge-xcs 10 kW kWh x $2.91 Distribution Energy Charge kWh x $0.03443 Distribution Energy charge kWh x $0.00596 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 13 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-00D THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 14 of 23 IMPACT ON G-5 RATE CUSTOMERS Hours Use: 400 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 20 8,000 $835.92 $316.67 $519.25 $813.03 $316.67 $496.36 ($22.89) -2.7% 50 20,000 $2,089.80 $791.67 $1,298.13 $1,938.35 $791.67 $1,146.68 ($151.45) -7.2% 100 40,000 $4,179.58 $1,583.33 $2,596.25 $3,813.66 $1,583.33 $2,230.53 ($365.72) -8.8% 150 60,000 $6,269.38 $2,375.00 $3,894.38 $5,689.39 $2,375.00 $3,314.39 ($579.99) -9.3% Newport Rates: G-5 Narragansett Rates: G-02 Customer Charge $0.00 Customer Charge $103.41 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40 Distribution Demand Charge kWh x $1.76 Distribution Demand Charge-xcs 10 kW kWh x $2.91 Distribution Energy Charge kWh x $0.02948 Distribution Energy charge kWh x $0.00596 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 14 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-00F THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 15 of 23 IMPACT ON W-1 RATE CUSTOMERS Hours Use: 100 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 1 100 $12.85 $3.96 $8.89 $8.26 $3.96 $4.30 ($4.59) -35.7% 3 300 $31.69 $11.88 $19.81 $24.77 $11.88 $12.89 ($6.92) -21.8% 5 500 $50.52 $19.79 $30.73 $41.27 $19.79 $21.48 ($9.25) -18.3% 10 1,000 $97.61 $39.58 $58.03 $82.55 $39.58 $42.97 ($15.06) -15.4% Newport Rates: W-1 Narragansett Rates: G-02 Customer Charge $3.29 Customer Charge $0.00 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40 Distribution Demand Charge kWh x $0.00 Distribution Demand Charge-xcs 10 kW kWh x $2.91 Distribution Energy Charge kWh x $0.02399 Distribution Energy charge kWh x $0.00596 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 15 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-30A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 16 of 23 IMPACT ON H-1 RATE CUSTOMERS Hours Use: 300 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 200 60,000 $6,644.41 $2,375.00 $4,269.41 $5,857.11 $2,375.00 $3,482.11 ($787.30) -11.8% 300 90,000 $9,960.34 $3,562.50 $6,397.84 $8,662.53 $3,562.50 $5,100.03 ($1,297.81) -13.0% 400 120,000 $13,276.28 $4,750.00 $8,526.28 $11,467.95 $4,750.00 $6,717.95 ($1,808.33) -13.6% 500 150,000 $16,592.22 $5,937.50 $10,654.72 $14,273.36 $5,937.50 $8,335.86 ($2,318.86) -14.0% 500 180,000 $19,908.16 $7,125.00 $12,783.16 $17,078.78 $7,125.00 $9,953.78 ($2,829.38) -14.2% Newport Rates: H-1 Narragansett Rates: G-32 Customer Charge $12.03 Customer Charge $236.43 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27 Distribution Demand Charge kWh x $0.00 Distribution Demand Charge-xcs 10 kW kWh x $1.56 Distribution Energy Charge kWh x $0.03968 Distribution Energy charge kWh x $0.00705 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 16 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-30C THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 17 of 23 IMPACT ON G-2 RATE CUSTOMERS Hours Use: 300 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 200 60,000 $6,327.71 $2,375.00 $3,952.71 $5,857.11 $2,375.00 $3,482.11 ($470.60) -7.4% 300 90,000 $9,491.56 $3,562.50 $5,929.06 $8,662.53 $3,562.50 $5,100.03 ($829.03) -8.7% 400 120,000 $12,655.42 $4,750.00 $7,905.42 $11,467.95 $4,750.00 $6,717.95 ($1,187.47) -9.4% 500 150,000 $15,819.27 $5,937.50 $9,881.77 $14,273.36 $5,937.50 $8,335.86 ($1,545.91) -9.8% 600 180,000 $18,983.13 $7,125.00 $11,858.13 $17,078.78 $7,125.00 $9,953.78 ($1,904.35) -10.0% Newport Rates: G-2 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27 Distribution Demand Charge kWh x $1.60 Distribution Demand Charge-xcs 10 kW kWh x $156 Distribution Energy Charge kWh x $0.02948 Distribution Energy charge kWh x $0.00705 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 17 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-30D THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 18 of 23 IMPACT ON T-2 RATE CUSTOMERS Hours Use: 300 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 500 200,000 $21,845.84 $7,916.67 $13,929.17 $18,457.74 $7,916.67 $10,541.07 ($3,388.10) -15.5% 1,000 400,000 $43,691.66 $15,833.33 $27,858.33 $36,669.19 $15,833.33 $20,835.86 ($7,022.47) -16.1% 1,500 600,000 $65,537.50 $23,750.00 $41,787.50 $54,880.66 $23,750.00 $31,130.66 ($10,656.84) -16.3% 2,000 800,000 $87,383.34 $31,666.67 $55,716.67 $73,092.12 $31,666.67 $41,425.45 ($14,291.22) -16.4% 2,500 1,000,000 $109,229.16 $39,583.33 $69,645.83 $91,303.57 $39,583.33 $51,720.24 ($17,925.59) -16.4% Newport Rates: T-2 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27 Distribution Demand Charge kWh x $1.60 Distribution Demand Charge-xcs 10 kW kWh x $1.56 Distribution Energy Charge kWh x $0.03443 Distribution Energy charge kWh x $0.00705 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 18 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G -30E THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 19 of 23 IMPACT ON T-4 RATE CUSTOMERS Hours Use: 400 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 500 200,000 $22,182.30 $7,916.67 $14,265.63 $18,457.74 $7,916.67 $10,541.07 ($3,724.56) -16.8% 1,000 400,000 $44,364.58 $15,833.33 $28,531.25 $36,669.19 $15,833.33 $20,835.86 ($7,695.39) -17.3% 1,500 600,000 $66,546.88 $23,750.00 $42,796.88 $54,880.66 $23,750.00 $31,130.66 ($11,666.22) -17.5% 2,000 800,000 $88,729.17 $31,666.67 $57,062.50 $73,092.12 $31,666.67 $41,425.45 ($15,637.05) -17.6% 2,500 1,000,000 $110,911.46 $39,583.33 $71,328.13 $91,303.57 $39,583.33 $51,720.24 ($19,607.89) -17.7% Newport Rates: T-4 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27 Distribution Demand Charge kWh x $1.95 Distribution Demand Charge-xcs 10 kW kWh x $1.56 Distribution Energy Charge kWh x $0.03517 Distribution Energy charge kWh x $0.00705 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 19 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-30F THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 20 of 23 IMPACT ON G-5 RATE CUSTOMERS Hours Use: 300 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 200 60,000 $6,361.04 $2,375.00 $3,986.04 $5,857.11 $2,375.00 $3,482.11 ($503.93) -7.9% 300 90,000 $9,541.56 $3,562.50 $5,979.06 $8,662.53 $3,562.50 $5,100.03 ($879.03) -9.2% 400 120,000 $12,722.08 $4,750.00 $7,972.08 $11,467.95 $4,750.00 $6,717.95 ($1,254.13) -9.9% 500 150,000 $15,902.60 $5,937.50 $9,965.10 $14,273.36 $5,937.50 $8,335.86 ($1,629.24) -10.2% 600 180,000 $19,083.13 $7,125.00 $11,958.13 $17,078.78 $7,125.00 $9,953.78 ($2,004.35) -10.5% Newport Rates: G-5 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27 Distribution Demand Charge kWh x $1.76 Distribution Demand Charge-xcs 10 kW kWh x $1.56 Distribution Energy Charge kWh x $0.02948 Distribution Energy charge kWh x $0.00705 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 20 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-30G THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 21 of 23 IMPACT ON T-5 RATE CUSTOMERS Hours Use: 400 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 200 80,000 $8,359.17 $3,166.67 $5,192.50 $7,530.87 $3,166.67 $4,364.20 ($828.30) -9.9% 300 120,000 $12,538.75 $4,750.00 $7,788.75 $11,173.16 $4,750.00 $6,423.16 ($13,365.59) -10.9% 400 160,000 $16,718.33 $6,333.33 $10,385.00 $14,815.44 $6,333.33 $8,482.11 ($1,902.89) -11.4% 500 200,000 $20,897.92 $7,916.67 $12,981.25 $18,457.74 $7,916.67 $10,541.07 ($2,440.18) -11.7% 600 240,000 $25,077.50 $9,500.00 $15,577.50 $22,100.03 $9,500.00 $12,600.03 ($2,977.47) -11.9% Newport Rates: T-5 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27 Distribution Demand Charge kWh x $1.76 Distribution Demand Charge-xcs 10 kW kWh x $1.56 Distribution Energy Charge kWh x $0.02948 Distribution Energy charge kWh x $0.00705 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 21 of 23 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-30H THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 22 of 23 IMPACT ON T-6 RATE CUSTOMERS Hours Use: 450 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 500 225,000 $23,501.04 $8,906.25 $14,594.79 $20,549.93 $8,906.25 $11,643.68 ($2,951.11) -12.6% 1,000 450,000 $47,002.08 $17,812.50 $29,189.58 $40,853.57 $17,812.50 $23,041.07 ($6,148.51) -13.1% 1,500 675,000 $70,503.13 $26,718.75 $43,784.38 $61,157.22 $26,718.75 $34,438.47 ($9,345.91) -13.3% 2,000 900,000 $94,004.17 $35,625.00 $58,379.17 $81,460.86 $35,625.00 $45,835.86 ($12.543.31) -13.3% 2,500 1,125,000 $117,505.21 $44,531.25 $72,973.96 $101,764.51 $44,531.25 $57,233.26 ($15,740.70) -13.4% Newport Rates: T-6 Narragansett Rates: G-32 Customer Charge $0.00 Customer Charge $236.43 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27 Distribution Demand Charge kWh x $1.76 Distribution Demand Charge-xcs 10 kW kWh x $1.56 Distribution Energy Charge kWh x $0.02993 Distribution Energy charge kWh x $0.00705 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company Range: G-60A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10 Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 23 of 23 IMPACT ON T-6 RATE CUSTOMERS Hours Use: 600 Monthly Newport Rates Narragansett Rates Difference Power Standard Standard kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total 3,000 1,800,000 $186,175.00 $71,250.00 $114,925.00 $161,938.25 $71,250.00 $90,688.25 ($24,236.75) -13.0% 4,000 2,400,000 $248,233.33 $95,000.00 $153,233.33 $209,973.67 $95,000.00 $114,973.67 ($38,259.66) -15.4% 5,000 3,000,000 $310,291.67 $118,750.00 $191,541.67 $258,009.08 $118,750.00 $139,259.08 ($52,282.59) -16.8% 6,000 3,600,000 $372,350.00 $142,500.00 $229,850.00 $306,044.50 $142,500.00 $163,544.50 ($66,305.50) -17.8% 7,000 4,200,000 $434,408.33 $166,250.00 $268,158.33 $354,079.92 $166,250.00 $187,829.92 ($80,328.41) -18.5% Newport Rates: T-6 Narragansett Rates: G-62 Customer Charge $0.00 Customer Charge $17,118.72 Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.39 Distribution Demand Charge kWh x $1.76 Distribution Demand Charge-xcs 10 kW kWh x $0.75 Transition Demand Charge kWh x $0.00 Transition Demand Charge kWh x $0.00 Distribution Energy Charge kWh x $0.02993 Distribution Energy charge kWh x $0.00000 Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340 DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230 Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136) PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095 Gross Earnings Tax 4.00% Gross Earnings Tax 4.00% Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800 The Narragansett Electric Company R.I.P.U.C. Docket Exhibit JMM - 10 Page 23 of 23
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Exhibit JMM-11 Addition to Narragansett Terms and Conditions Definitions of Zones 34. For purposes of interpreting rates, tariffs and Terms and Conditions, the following terms will have the meanings as follows: Narragansett Zone is the cities and towns of: Providence, North Providence, East Providence, Cranston, Johnston, Smithfield, Scituate, Foster, Gloucester, Warren, Barrington, Bristol, Tiverton, Little Compton, Warwick, West Warwick, East Greenwich, Coventry, North Kingstown, Westerly, Richmond, Charlestown, Exeter, Hopkinton, Narragansett, South Kingstown and West Greenwich. Blackstone Valley Zone is the cities and towns of: Pawtucket, Central Falls, Cumberland, Lincoln, Woonsocket, North Smithfield, and Burrillville. Newport Zone is the cities and towns of: Newport, Middletown, Portsmouth, and Jamestown.
Exhibit JMM-12 THE NARRAGANSETT ELECTRIC COMPANY Effective Basic Residential Rate (A-16) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1100-A Monthly Charge As Adjusted Rates for Retail Delivery Service Customer Charge per month $2.54 Non-Bypassable Transition Charge per kWh 1.150 cents Transmission Charge per kWh 0.436 cents Transmission Adjustment Factor per kWh 0.079 cents Distribution Charge per kWh * 3.708 cents Minimum Charge per month $2.54 Conservation and Load Management Adjustment per kWh 0.230 cents (Eff. Jan. 1, 1997) Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh 0.962 cents Transmission Adjustment Credit 12 per kWh 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents Zonal Distribution Factor per kWh 0.661 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh 3.800 cents(Eff. January 1, 2000) Last Resort per kWh per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective Residential Time-Of-Use Rate (A-32) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1102-A Monthly Charge As Adjusted Rates for Retail Delivery Service Customer Charge per month $2.30 Time-of-use Metering Charge per month $4.44 Non-Bypassable Transition Charge per kWh 1.150 cents Transmission Charge per kWh 0.392 cents Transmission Adjustment Factor per kWh 0.079 cents Distribution Charge per kWh * 2.624 cents Conservation and Load Management Adjustment per kWh 0.230 cents (Eff. Jan. 1, 1997) Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents Zonal Distribution Factor per kWh 0.661 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh 3.800 cents(Eff. January 1, 2000) Last Resort per kWh per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective Low Income Rate (A-60) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1103-A Monthly Charge As Adjusted Rates for Retail Delivery Service Non-Bypassable Transition Charge per kWh 1.150 cents Transmission Charge per kWh 0.338 cents Transmission Adjustment Factor per kWh 0.073 cents Distribution Charge per kWh * 2.617 cents Water Heater Credit per kWh for the first 750 kWh per month 0.661 cents Conservation and Load Management Adjustment per kWh 0.230 cents(Eff. Jan. 1, 1997) A-60 Rate Credit 0.227 cents Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents Blackstone Equalization Credit per first 300 kWh 0.733 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents Zonal Distribution Factor per kWh 0.661 cents Newport Equalization Credit per first 300 kWh 0.616 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh 3.800 cents(Eff. January 1, 2000) Last Resort per kWh per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998) and 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999). Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective General C&I Back-Up Service Rate (B-02) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1117-A Monthly Charge As Adjusted Rates for Rates for Back-Up Service Supplemental Service Rates for Retail Delivery Service Customer Charge per month $103.41 n/a Distribution Demand Charge per kW in excess 10 kW $2.91 $2.91 Transmission Demand Charge per kW in excess 10 kW $1.40 $1.40 Transmission Adjustment Factor per kWh 0.079 cents 0.079 cents, Distribution Energy Charge per kWh* 1.058 cents 1.058 cents Non-bypassable Transition Charge per kWh n/a 1.150 cents C&LM Adjustment per kWh n/a 0.230 cents Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh n/a 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh n/a 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents 0.215 cents Zonal Distribution Factor per kWh 0.661 cents 0.661 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh n/a 3.800 cents Last Resort per kWh n/a per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes, when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective Small C&I Back-Up Service Rate (B-06) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1118-A Monthly Charge As Adjusted Rates for Rates for Back-Up Service Supplemental Service Rates for Retail Delivery Service Customer Charge per month $5.73 n/a Transmission Energy Charge per kWh 0.536 cents 0.536 cents Transmission Adjustment Factor per kWh 0.079 cents 0.079 cents Distribution Energy Charge per kWh* 3.926 cents 3.926 cents Non-bypassable Transition Charge per kWh n/a 1.150 cents C&LM Adjustment per kWh n/a 0.230 cents Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh n/a 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh n/a 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents 0.215 cents Zonal Distribution Factor per kWh 0.661 cents 0.661 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh n/a 3.800 cents Last Resort per kWh n/a per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective 200 kW Back-Up Service Rate (B-32) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1119-A Monthly Charge As Adjusted Rates for Rates for Back-Up Service Supplemental Service Rates for Retail Delivery Service Customer Charge per month $236.43 n/a Transmission Demand Charge per kW $1.27 $1.27 Distribution Demand Charge per kW $1.56 $1.56 Transmission Adjustment Factor per kWh 0.079 cents 0.079 cents Distribution Energy Charge per kWh * 1.167 cents 1.167 cents Non-bypassable Transition Charge per kWh n/a 1.150 cents C&LM Adjustment per kWh n/a 0.230 cents Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh n/a 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh n/a 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents 0.215 cents Zonal Distribution Factor per kWh 0.661 cents 0.661 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh n/a 3.800 cents Last Resort per kWh n/a per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes, when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective 3,000 kW Back-Up Service Rate (B-62) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1120-A Monthly Charge As Adjusted Rates for Rates for Back-Up Service Supplemental Service Rates for Retail Delivery Service Customer Charge per month $17,118.72 n/a Distribution Demand Charge per kW $0.75 $0.75 Transmission Demand Charge per kW $1.39 $1.39 Transmission Adjustment Factor per kWh 0.079 cents 0.079 cents Distribution Energy Charge per kWh * 0.462 cents 0.462 cents Non-bypassable Transition Charge per kWh n/a 1.150 cents C&LM Adjustment per kWh n/a 0.230 cents Additional Delivery for Blackstone Valley Zone Zonal Transition Factor per kWh n/a 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh n/a 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents 0.215 cents Zonal Distribution Factor per kWh 0.661 cents 0.661 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh n/a 3.800 cents Last Resort per kWh n/a per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes, when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective Small C&I Rate (C-06) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1104-A Monthly Charge As Adjusted Rates for Retail Delivery Service Customer Charge per month $5.73 Unmetered Charge per month $1.83 Non-Bypassable Transition Charge per kWh 1.150 cents Transmission Charge per kWh 0.536 cents Transmission Adjustment Factor per kWh 0.079 cents (Eff. Jan. 1, 1999) Distribution Charge per kWh* 3.926 cents Conservation and Load Management Adjustment per kWh 0.230 cents (Eff. Jan. 1, 1997) Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents Zonal Distribution Factor per kWh 0.661 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh 3.800 cents(Eff. January 1, 2000) Last Resort per kWh per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes, when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective General C&I Rate (G-02) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1107-A Monthly Charge As Adjusted Rates for Retail Delivery Service Customer Charge per month $103.41 Transmission Charge per kW in excess of 10 kW $1.40 Distribution Charge per kW in excess of 10 kW $2.91 Non-Bypassable Transition Charge per kWh 1.150 cents Transmission Adjustment Factor per kWh 0.079 cents Distribution Charge per kWh* 1.058 cents Conservation and Load Management Adjustment per kWh 0.230 cents(Eff. Jan. 1, 1997) Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents Zonal Distribution Factor per kWh 0.661 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh 3.800 cents(Eff. January 1, 2000) Last Resort per kWh per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Base Rate Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes, when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective 200 kW Demand Rate (G-32) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1108-A Monthly Charge As Adjusted Rates for Retail Delivery Service Customer Charge per month $236.43 Transmission Charge per kW $1.27 Distribution Charge per kW $1.56 Non-Bypassable Transition Charge per kWh 1.150 cents Transmission Adjustment Factor per kWh 0.079 cents(Eff. Jan. 1, 1999) Distribution Charge per kWh* 1.167 cents Conservation and Load Management Adjustment per kWh 0.230 cents(Eff. Jan. 1, 1997) Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents Zonal Distribution Factor per kWh 0.661 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh 3.800 cents(Eff. January 1, 2000) Last Resort per kWh per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Base Rate Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes (when applicable). However, such taxes, when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective 3000 kW Demand Rate (G-62) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1109-A Monthly Charge As Adjusted Rates for Retail Delivery Service Customer Charge per month $17,118.72 Transmission Charge per kW $1.39 Distribution Charge per kW $0.75 Non-Bypassable Transition Charge per kWh 1.150 cents Transmission Adjustment Factor per kWh 0.079 cents (Eff. Jan. 1, 1999) Distribution Charge per kWh* 0.462 cents Conservation and Load Management Adjustment per kWh 0.230 cents (Eff. Jan. 1, 1997) Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents Zonal Distribution Factor per kWh 0.661 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh 3.800 cents(Eff. January 1, 2000) Last Resort per kWh per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Base Rate Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes (when applicable). However, such taxes, when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective General Streetlighting Service (S-14) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. 1113-A Luminaire Type/Lumens Code Annual kWh Incandescent 1,000 10 440 Mercury Vapor 8,000 02 908 4,000 03 561 8,000 04 908 22,000 05 1,897 63,000 06 4,569 Sodium Vapor 4,000 70 248 9,600 72,79 490 27,500 74 1,284 50,000 75 1,968 27,500 (24 hr) 84 2,568 50,000 FL 78 1,968 Narragansett Blackstone Newport Zone Zone Zone Non-Bypassable Transition Charge per kWh 1.150 cents 1.150 cents 1.150 cents Zonal Transition Factor per kWh 0.000 cents 0.962 cents 1.008 cents Distribution Energy Charge per kWh* 0.462 cents 0.462 cents 0.462 cents Transmission Charge per kWh 0.259 cents 0.259 cents 0.259 cents Transmission Adjustment Factor per kWh 0.079 cents 0.079 cents 0.079 cents Transmission Adjustment Credit per kWh 0.000 cents 0.208 cents 0.215 cents Conservation & Load Management Adj. Per kWh 0.230 cents 0.230 cents 0.230 cents Zonal Distribution Factor per kWh 0.000 cents 0.000 cents 0.661 cents Streetlight Credit per kWh 0.000 cents 4.458 cents 2.956 cents Plus 3.800 cents per kWh for Standard Offer (Eff. April 1, 2000) (Optional) Plus Last Resort per Last Resort Service tariff (Optional) * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard 0ffer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes (when applicable). However, such taxes, when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual. THE NARRAGANSETT ELECTRIC COMPANY Effective 69kV Rate (N-01) April 1, 2000 Retail Delivery Service R.I.P.U.C. No. Monthly Charge As Adjusted Rates for Retail Delivery Service Distribution Charge per kW $6.60 Distribution Charge per kVAR $0.20 Non-Bypassable Transition Charge per kWh 1.150 cents Transmission Charge per kWh 0.409 cents Transmission Adjustment Factor per kWh 0.079 cents Distribution Charge per kWh* 0.731 cents Conservation and Load Management Adjustment per kWh 0.230 cents(Eff. Jan. 1, 1997) Additional Delivery Rates for Blackstone Valley Zone Zonal Transition Factor per kWh 0.962 cents Transmission Adjustment Credit per kWh 0.208 cents Additional Delivery Rates for Newport Zone Zonal Transition Factor per kWh 1.008 cents Transmission Adjustment Credit per kWh 0.215 cents Rates for Standard Offer Service or Last Resort Service (Optional) Standard Offer per kWh 3.800 cents(Eff. January 1, 2000) ---------------------- Last Resort per kWh per Last Resort Service tariff * Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Base Rate Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively. Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes (when applicable). However, such taxes, when applicable, will appear on bills sent to customers. Other Rate Clauses apply as usual.
R.I.P.U.C. No. Sheet 1 Cancelling R.I.P.U.C. No. THE NARRAGANSETT ELECTRIC COMPANY 69kV Rate (N-01) RETAIL DELIVERY SERVICE AVAILABILITY This rate is available to customers taking service at a nominal voltage of 69,000 volts and is mandatory for the Department of the Navy, its successors, or assigns, for electric power service to the Naval Education and Training Center, Newport, Rhode Island. Electric retail delivery service supplied hereunder shall be three phase, alternating current, at a nominal frequency of sixty Hertz, and at a nominal voltage of 69,000 volts. MONTHLY CHARGE The Monthly Charge will be the sum of the Retail Delivery Service Charges set forth in the cover sheet this tariff. DETERMINATION OF BILLING PERIODS The Billing Period consists of the days between consecutive meter readings. Service under this Rate is rendered on a full calendar day basis. The first day of any billing period is included in its entirety and the last day of any billing period is excluded in its entirety. DETERMINATION OF BILLING DEMANDS I. Billing Demand A. Requirements Service The Demand in kilowatts for each month is the maximum metered fifteen-minute demand during the Billing Period. B. Partial Requirements Service The Demand in kilowatts for each month is the maximum fifteen-minute total demand during the month where the total demand is the combined of the Partial Requirements Service delivered by the Company and the service supplied by the customer's other power source. The Billing Demand in kilowatts for each month shall be the largest of: R.I.P.U.C. No. Sheet 2 THE NARRAGANSETT ELECTRIC COMPANY 69kV Rate (N-01) RETAIL DELIVERY SERVICE 1. the Demand, 2. Seventy-five percent (75%) of the highest Demand recorded during the previous eleven months, or 3. Fifty percent (50%) of the highest Demand recorded by the customer since 1961, where: For the purposes of determining the Billing Demand, all demands recorded before December 1, 1994, shall be deemed Demands, all Standby Demands recorded after December 1, 1994, through June 30, 1997 shall be deemed Demands, and all Distribution Demands recorded after June 30, 1997, shall be deemed Demands. II. Reactive Billing Demand The Reactive Billing Demand in kilovars for each month shall be the Reactive Demand in excess of seventeen and one-half percent (17.5%) of the Demand, where the Reactive Demand in kilovars for each month is the metered fifteen-minute reactive demand coincident with the Demand. DETERMINATION OF BILLING DEMAND CHARGES I. Billing Demand Charge The Billing Demand Charge shall be the Billing Demand times the Demand Rate. I. Reactive Billing Demand Charge The Reactive Billing Demand Charge shall be the Reactive Billing Demand times the Reactive Demand Rate. DETERMINATION OF MINIMUM BILLING ENERGY CHARGE The Minimum Billing Energy Charge shall be the Total Energy Requirements times the Transition Charge For the purposes of the foregoing, Total Energy Requirements shall mean the sum of the energy delivered by the Company and the energy supplied by the Navy's other power sources other than electrically isolated emergency power sources. RATE ADJUSTMENT PROVISIONS Transmission Service Charge Adjustment The prices under this rate as set forth under "Monthly Charge" may be adjusted from time to time in the manner described in the Company's Transmission Service Cost Adjustment Provision. Transition Charge Adjustment The prices under this rate as set forth under "Monthly Charge" may be adjusted from time to time in the manner described in the Company's Non-Bypassable Transition Charge Adjustment Provision. R.I.P.U.C. No. Sheet 3 THE NARRAGANSETT ELECTRIC COMPANY 69kV Rate (N-01) RETAIL DELIVERY SERVICE Standard Offer Adjustment All Customers served on this rate must pay any charges required pursuant to the terms of the Company's Standard Offer Adjustment Provisions, whether or not the Customer is taking or has taken Standard Offer Service. Conservation and Load Management Adjustment The amount determined under the preceding provisions shall be adjusted in accordance with the Company's Conservation and Load Management Adjustment Provision as from time to time effective in accordance with law. Performance Based Rate Adjustment The amount determined under the preceding provisions shall be adjusted periodically in accordance with Section 39-1-27.5 of the Rhode Island General Laws. STANDARD OFFER SERVICE Any Customer served under this rate who is eligible for Standard Offer Service shall receive such service pursuant to the Standard Offer Service tariff. LAST RESORT SERVICE Any Customer served under this rate who does not take its power supply from a non-regulated power producer and is ineligible for Standard Offer Service will receive Last Resort Service pursuant to the Last Resort Service tariff. GROSS EARNINGS TAX A Rhode Island Gross Earnings Tax adjustment will be applied to the charges determined above in accordance with Rhode Island General Laws. GROSS EARNINGS TAX CREDIT FOR MANUFACTURERS Consistent with the gross receipts tax exemption provided in Section 44-13-35 of Rhode Island General Laws, eligible manufacturing customers will be exempt from the Gross Earnings Tax to the extent allowed by the Division of Taxation. Eligible manufacturing customers are those customers who have on file with the Company a valid certificate of exemption from the Rhode Island sales tax (under section 44-18-30(H) of Rhode Island General Laws) indicating the customer's status as a manufacturer. If the Division of Taxation (or other Rhode Island taxing authority with jurisdiction) disallows any part or all of the exemption as it applies to a customer, the custome be required to reimburse the Company in the amount of the credits provided to such customer which were disallowed, including any interest required to be paid by the Company to such authority. R.I.P.U.C. No. Sheet 2 THE NARRAGANSETT ELECTRIC COMPANY 69kV Rate (N-01) RETAIL DELIVERY SERVICE DEFINITIONS OF TERMS "Requirements Service" means that the Company delivers all the energy and capacity necessary to meet the total electric service requirements of the Navy, other than electric service requirements provided by electrically isolated emergency power sources. "Partial Requirements Service" means Supplementary Service, Backup Service, and Maintenance Service either individually or in any combination. "Supplementary Service" means electric energy and capacity delivered by the Company on a regular basis in addition to that which is normally provided by the Navy's other power source. "Backup Service" means electric energy and capacity delivered by the Company to replace energy and capacity ordinarily provided by the Navy's other power source during an unscheduled outage of the power source. "Maintenance Service" means electric energy and capacity delivered by the Company to replace energy and capacity ordinarily provided by the Navy's other power source during a scheduled outage of the power source. TERMS AND CONDITIONS The Company's Terms and Conditions in effect from time to time, where not inconsistent with any specific provisions hereof, are a part of this rate. Effective: April 1, 2000 Exhibit JMM-13 R.I.P.U.C. No. [[1116]] Sheet 1 Cancelling R.I.P.U.C. No. [[1074]] [1116] THE NARRAGANSETT ELECTRIC COMPANY NON-BYPASSABLE TRANSITION CHARGE ADJUSTMENT PROVISION The Non-Bypassable Transition Charge shall [[be a pass through of the cents per kilowatthour contract termination charge that New England Power Company (NEP) bills to The Narragansett Electric Company (Company). The Non-Bypassable Transition Charge shall be adjusted each time that NEP's contract termination charge changes. The Non-Bypassable Transition Charge shall be computed to the nearest thousandth of a cent.]] [be designed to collect from customers all Contract Termination Charges billed to the Narragansett Electric Company (the Company) by the New England Power Company or Montaup Electric Company. The Non-Bypassable Transition Charge may be subject to adjustment each time any Contract Termination Charge changes]. Modifications to the Non-Bypassable Transition Charge shall be in accordance with a notice filed with the Public Utilities Commission (Commission) setting forth the revised charge and the amount of the increase or decrease. The notice shall further specify the effective date of the change. [A Base Transition Charge shall be established at 1.15 cents per kilowatt-hour and charged to all Customers. In the Blackstone and Newport zones, Zonal Transition Factors also shall apply. On the Effective Date of this adjustment provision, the Zonal Transition Factor shall be calculated as the difference between the Non-Bypassable Transition Charge in effect prior to the Effective Date of this adjustment provision and the Base Transition Charge. Effective on January 1, 2001, the Zonal Transition Factors shall be designed to recover the positive difference, if any, between the amount to be recovered from Customers through the Base Transition Charge and the total Non-Bypassable Transition Charge revenues to be recovered. At such time that the Base Transition Charge recovers the entire cost of Contract Termination Charges or over collects Contract Termination Charges, the Company may make a filing to adjust the Base Transition Charge and eliminate the Zonal Transition Factors. Legend: [ ] = insertion [[ ]] = deletion To the extent that there are any refunds made by New England Power Company or Montaup Electric Power Company to the Company in connection with Contract Termination Charges, such refunds shall be applied consistent with the methodology set forth in Attachment 1.] On an annual basis, the Company shall reconcile its total cost of Contract Termination Charges against its total transition charge revenue (appropriately adjusted to reflect the Rhode Island Gross Receipts Tax), and the excess or deficiency ("Transition Charge Adjustment Balance") shall be refunded to, or collected from, customers through the rate recovery/refund methodology approved by the Commission at the time the Company files its annual reconciliation. Any positive or negative balance will accrue interest calculated at the rate in effect for customer deposits. Exhibit JMM-13 R.I.P.U.C. No. [[1116]] Sheet 2 Cancelling R.I.P.U.C. No. [[1074]] [1116] THE NARRAGANSETT ELECTRIC COMPANY NON-BYPASSABLE TRANSITION CHARGE ADJUSTMENT PROVISION For purposes of the above reconciliation, total transition charge revenues shall mean all revenue collected from customers through the transition charges for the applicable reconciliation period. If there is a positive or negative balance in the then current Transition Charge Adjustment Balance outstanding from the prior period, the balance shall be credited against or added to the new reconciliation amount, as appropriate, in establishing the Transition Charge Adjustment Balance for the new reconciliation period. The Company shall annually determine the Transition Charge Adjustment Balance, if any, for the prior calendar year and make a filing with the Commission. The Company will propose at that time a rate recovery/refund methodology to recover or refund the balance, as appropriate, over a twelve month period. The Commission may order the Company to collect or refund the balance over any reasonable time period from (i) all customers, (ii) only from those customer classes that underpaid or overpaid transition charges, or (iii) through any other reasonable method. This provision is applicable to all Retail Delivery Service rates of the Company. Effective [[January 1, 1999]] [April 1, 2000] 3 Exhibit JMM-13 R.I.P.U.C. No. [[1116]] Sheet 3 Cancelling R.I.P.U.C. No. [[1074]] [1116] THE NARRAGANSETT ELECTRIC COMPANY NON-BYPASSABLE TRANSITION CHARGE ADJUSTMENT PROVISION [Attachment I] [Refunds received by the Company in connection with Contract Termination Charges shall first be applied to offset the deficiency in the Company's deferred tax reserves in an amount not to exceed the total balance of the deficiency as of December 31, 2000. If any refunds are received in excess of the revenue requirement associated with the deficiency, the Commission may order the Company to refund such amounts to Customers or otherwise use the funds to offset other charges to Customers.] Exhibit JMM-13 R.I.P.U.C. No.[[1054]] Sheet 1 [Cancelling R.I.P.U.C. No. 1054] THE NARRAGANSETT ELECTRIC COMPANY TRANSMISSION SERVICE COST ADJUSTMENT PROVISION The Transmission Service Cost Adjustment (TCA) shall collect from customers transmission costs billed to The Narragansett Electric Company (Narragansett or the Company) by entities such as the New England Power Company, by any other transmission provider, and by regional transmission entities such as the New England Power Pool, a regional transmission group, an independent system operator or any other entity that is authorized to bill Narragansett Electric directly for transmission services. [On the Effective Date of this adjustment provision, the TCA shall be separately determined for the Customers in the Narragansett, Blackstone and Newport zones to reflect the transmission costs of those companies prior to the Effective Date as determined by a filing made by the Companies at least 30 days prior to the Effective Date.] [Effective on January 1, 2001, t][[T]]he transmission service cost adjustment shall be a uniform cents per kilowatthour factor applicable to all kilowatthours delivered by the Company. The factor shall be established annually based on a forecast of transmission costs, taking into account revenues that will be received from base rate transmission charges, and shall include a full reconciliation and adjustment for any over- or under-recoveries of transmission costs incurred during the prior year. The Company may file to change the factor adjustment at any time should significant over- or under-recoveries occur. The reconciliation shall calculate all revenues received by the Company through the base rate transmission charges and this TCA, compare these revenues to all transmission costs incurred during the corresponding year, and pass through the resulting credit or charge, as appropriate, on a uniform per kWh basis, as provided above. Modifications to the Transmission Service Cost Adjustment Factor shall be in accordance with a notice filed with the Public Utilities Commission (the Commission) setting forth the amount of the revised factor and the amount of the increase or decrease. The notice shall further specify the effective date of such charges. [Effective April 1, 2000] Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Workpaper JMM-1 Workpaper JMM-1 Blackstone Valley Back-up
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate R1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 1 of 29 The Narragansett Electric Company Shifting BVE Rate R-1 to Narragansett Rate A-16 ============================================================================================================================= BVE Rate R-1 Narragansett Rate A-16 R-1/A-16 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 876,261 $3.09 $2,707,646 876,261 $2.54 $2,225,703 2 Energy Charges: Distribution Energy 362,568,042 $0.03857 $13,984,249 362,568,042 $0.03680 $13,342,504 Transmission Energy $0.00278 $1,007,939 $0.00307 $1,113,084 Transition Energy $0.02320 $8,411,579 $0.02320 $8,411,579 Standard Offer $0.03800 $13,777,586 $0.03800 $13,777,586 DSM $0.00230 $833,906 $0.00230 $833,906 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $40,722,906 $39,704,361 4 Total Revenue Shift: ($1,018,544) 5 Revenue Shift by Function: Distribution Revenue ($1,123,689) Transmission Revenue $105,145 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate R1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 2 of 29 The Narragansett Electric Company Shifting BVE Rate R-2 to Narragansett Rate A-60 ============================================================================================================================= BVE Rate R-2 Narragansett Rate A-60 R-2/A-60 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 25,844 $2.01 $51,946 25,844 $0.00 $0 2 Energy Charges: Distribution Energy first 300 kWh 6,540,065 $0.00170 $11,118 6,540,065 ($0.00733) ($47,939) Distribution Energy over 300 kWh 3,924,039 $0.03470 $136,164 Distribution Energy 10,464,104 $0.02362 $247,162 Transmission Energy $0.00278 $29,090 $0.00209 $21,870 Transition Energy $0.02320 $242,767 $0.02320 $242,767 Standard Offer $0.03800 $397,636 $0.03800 $397,636 DSM $0.00230 $24,067 $0.00230 $24,067 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $892,790 $885,564 4 Total Revenue Shift: ($7,225) 5 Revenue Shift by Function: Distribution Revenue ($5) Transmission Revenue ($7,220) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate R1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 3 of 29 The Narragansett Electric Company Shifting BVE Rate R-3 to Narragansett Rate A-16 ============================================================================================================================= BVE Rate R-3 Narragansett Rate A-16 R-3/A-16 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 10,622 $2.91 $30,910 10,622 $2.54 $26,980 2 Energy Charges: Distribution Energy 9,162,722 $0.03200 $293,207 9,162,722 $0.03680 $337,188 Transmission Energy $0.00278 $25,472 $0.00307 $28,130 Transition Energy $0.02320 $212,575 $0.02320 $212,575 Standard Offer $0.03800 $348,183 $0.03800 $348,183 DSM $0.00230 $21,074 $0.00230 $21,074 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $931,422 $974,130 4 Total Revenue Shift: $42,708 5 Revenue Shift by Function: Distribution Revenue $40,051 Transmission Revenue $2,657 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate R1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 4 of 29 The Narragansett Electric Company Shifting BVE Rate R-4 to Narragansett Rate A-32 ============================================================================================================================= BVE Rate R-4 Narragansett Rate A-32 R-4/A-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 1,821 $4.69 $8,540 1,821 $6.74 $12,274 2 Energy Charges: Distribution Peak 815,510 $0.11500 $93,784 815,510 $0.02596 $21,171 Distribution Off Peak 3,671,937 $0.01033 $37,931 3,671,937 $0.02596 $95,323 Transmission Energy 4,487,447 $0.00278 $12,475 4,487,447 $0.00263 $11,802 Transition Energy $0.02320 $104,109 $0.02320 $104,109 Standard Offer $0.03800 $170,523 $0.03800 $170,523 DSM $0.00230 $10,321 $0.00230 $10,321 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $437,683 $425,523 4 Total Revenue Shift: ($12,161) 5 Revenue Shift by Function: Distribution Revenue ($11,488) Transmission Revenue ($673) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate R1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 5 of 29 The Narragansett Electric Company Shifting BVE Rate W-1 to Narragansett Rate A-16 ============================================================================================================================= BVE Rate W-1 Narragansett Rate A-16 W-1/A-16 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 15,594 $1.32 $20,584 15,594 $0.00 $0 2 Energy Charges: Distribution Energy 3,568,998 $0.01792 $63,956 3,568,998 $0.03680 $131,339 Transmission Energy $0.00278 $9,922 $0.00307 $10,957 Transition Energy $0.02320 $82,801 $0.02320 $82,801 Standard Offer $0.03800 $135,622 $0.03800 $135,622 DSM $0.00230 $8,209 $0.00230 $8,209 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $321,094 $368,927 4 Total Revenue Shift: $47,834 5 Revenue Shift by Function: Distribution Revenue $46,799 Transmission Revenue $1,035 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate R1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 6 of 29 The Narragansett Electric Company Shifting BVE Rate W-1 to Narragansett Rate C-06 ============================================================================================================================= BVE Rate W-1 Narragansett Rate C-06 W-1/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: Customer Charge 187 $1.32 $247 187 $0.00 $0 Unmetered Charge 0 $0.00 $0 2 Energy Charges: Distribution Energy 33,373 $0.01792 $598 33,373 $0.03898 $1,301 Transmission Energy $0.00278 $93 $0.00407 $136 Transition Energy $0.02320 $774 $0.02320 $774 Standard Offer $0.03800 $1,268 $0.03800 $1,268 DSM $0.00230 $77 $0.00230 $77 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $3,057 $3,556 4 Total Revenue Shift: $499 5 Revenue Shift by Function: Distribution Revenue $456 Transmission Revenue $43 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate H1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 7 of 29 The Narragansett Electric Company Shifting BVE Rate H-1 to Narragansett Rate C-06 ====================================================================================================================== BVE Rate H-1 Narragansett Rate C-06 H-1/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ====================================================================================================================== 1 Customer Charge: 85 $3.01 $256 85 $5.73 $487 2 Energy Charges: Distribution Energy 225,822 $0.02975 $6,718 225,822 $0.03898 $8,803 Transmission Energy $0.00278 $628 $0.00407 $919 Transition Energy $0.02320 $5,239 $0.02320 $5,239 Standard Offer $0.03800 $8,581 $0.03800 $8,581 DSM $0.00230 $519 $0.00230 $519 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $21,942 $24,548 4 Total Revenue Shift: $2,607 5 Revenue Shift by Function: Distribution Revenue $2,316 Transmission Revenue $291 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate H1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 8 of 29 The Narragansett Electric Company Shifting BVE Rate H-1 to Narragansett Rate G-02 ====================================================================================================================== BVE Rate H-1 Narragansett Rate G-02 H-1/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ====================================================================================================================== 1 Customer Charge: 104 $3.01 $313 104 $103.41 $10,755 2 Demand Charge: Distribution Demand 8,848 $0.00 $0 8,848 $2.91 $25,748 Transmission Demand $1.40 $12,387 3 Energy Charges: Distribution Energy 2,380,400 $0.02975 $70,817 2,380,400 $0.01030 $24,518 Transmission Energy $0.00278 $6,618 ($0.00129) ($3,071) Transition Energy $0.02320 $55,225 $0.02320 $55,225 Standard Offer $0.03800 $90,455 $0.03800 $90,455 DSM $0.00230 $5,475 $0.00230 $5,475 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $228,903 $221,492 5 Total Revenue Shift: ($7,411) 6 Revenue Shift by Function: Distribution Revenue ($10,110) Transmission Revenue $2,699 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate H1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 9 of 29 The Narragansett Electric Company Shifting BVE Rate H-1 to Narragansett Rate G-32 ====================================================================================================================== BVE Rate H-1 Narragansett Rate G-32 H-1/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ====================================================================================================================== 1 Customer Charge: 15 $3.01 $45 15 $236.43 $3,546 2 Demand Charge: Distribution Demand 3,845 $0.00 $0 3,845 $1.56 $5,998 Transmission Demand $1.27 $4,883 3 Energy Charges: Distribution Energy 1,032,800 $0.02975 $30,726 1,032,800 $0.01139 $11,764 Transmission Energy $0.00278 $2,871 ($0.00129) ($1,332) Transition Energy $0.02320 $23,961 $0.02320 $23,961 Standard Offer $0.03800 $39,246 $0.03800 $39,246 DSM $0.00230 $2,375 $0.00230 $2,375 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $99,225 $90,442 5 Total Revenue Shift: ($8,783) 6 Revenue Shift by Function: Distribution Revenue ($9,463) Transmission Revenue $680 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate H2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 10 of 29 The Narragansett Electric Company Shifting BVE Rate H-2 to Narragansett Rate C-06 ============================================================================================================================= BVE Rate H-2 Narragansett Rate C-06 H-2/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 940 $3.43 $3,224 940 $0.00 $0 2 Energy Charges: Distribution Energy 2,034,902 $0.03421 $69,614 2,034,902 $0.03898 $79,320 Transmission Energy $0.00278 $5,657 $0.00407 $8,282 Transition Energy $0.02320 $47,210 $0.02320 $47,210 Standard Offer $0.03800 $77,326 $0.03800 $77,326 DSM $0.00230 $4,680 $0.00230 $4,680 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $207,712 $216,819 4 Total Revenue Shift: $9,107 5 Revenue Shift by Function: Distribution Revenue $6,482 Transmission Revenue $2,625 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate H2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 11 of 29 The Narragansett Electric Company Shifting BVE Rate H-2 to Narragansett Rate G-02 ============================================================================================================================= BVE Rate H-2 Narragansett Rate G-02 H-2/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 12 $3.43 $41 12 $0.00 $0 2 Demand Charge: Distribution Demand 0 $0.00 $0 0 $2.91 $0 Transmission Demand $1.40 $0 3 Energy Charges: Distribution Energy 33,090 $0.03421 $1,132 33,090 $0.01030 $341 Transmission Energy $0.00278 $92 ($0.00129) ($43) Transition Energy $0.02320 $768 $0.02320 $768 Standard Offer $0.03800 $1,257 $0.03800 $1,257 DSM $0.00230 $76 $0.00230 $76 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $3,366 $2,399 5 Total Revenue Shift: ($967) 6 Revenue Shift by Function: Distribution Revenue ($832) Transmission Revenue ($135) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate H2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 12 of 29 The Narragansett Electric Company Shifting BVE Rate H-2 to Narragansett Rate G-32 ============================================================================================================================= BVE Rate H-2 Narragansett Rate G-32 H-2/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 12 $3.43 $41 12 $0.00 $0 2 Demand Charge: Distribution Demand 2,386 $0.00 $0 2,386 $1.56 $3,722 Transmission Demand $1.27 $3,030 3 Energy Charges: Distribution Energy 222,400 $0.03421 $7,608 222,400 $0.01139 $2,533 Transmission Energy $0.00278 $618 ($0.00129) ($287) Transition Energy $0.02320 $5,160 $0.02320 $5,160 Standard Offer $0.03800 $8,451 $0.03800 $8,451 DSM $0.00230 $512 $0.00230 $512 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $22,390 $23,122 5 Total Revenue Shift: $731 6 Revenue Shift by Function: Distribution Revenue ($1,394) Transmission Revenue $2,125 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate G1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 13 of 29 The Narragansett Electric Company Shifting BVE Rate G-1 to Narragansett Rate C-06 ============================================================================================================================= BVE Rate G-1 Narragansett Rate C-06 G-1/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: Customer Charge 87,619 $3.37 $295,276 85,368 $5.73 $489,159 Unmetered Charge 2,251 $1.83 $4,119 2 Energy Charges: Distribution Energy 43,670,643 $0.04348 $1,898,800 43,670,643 $0.03898 $1,702,282 Transmission Energy $0.00278 $121,404 $0.00407 $177,740 Transition Energy $0.02320 $1,013,159 $0.02320 $1,013,159 Standard Offer $0.03800 $1,659,484 $0.03800 $1,659,484 DSM $0.00230 $100,442 $0.00230 $100,442 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $5,088,566 $5,146,385 4 Total Revenue Shift: $57,819 5 Revenue Shift by Function: Distribution Revenue $1,484 Transmission Revenue $56,335 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate G2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 14 of 29 The Narragansett Electric Company Shifting BVE Rate G-2 to Narragansett Rate C-06 ============================================================================================================================= BVE Rate G-2 Narragansett Rate C-06 G-2/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 17,427 $0.00 $0 17,427 $5.73 $99,857 2 Demand Charge: Distribution Demand 293,038 $1.50 $439,557 0 $0.00 $0 Transmission Demand $0.00 $0 $0.00 $0 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 55,207,092 $0.02296 $1,267,555 55,207,092 $0.03898 $2,151,972 Transmission Energy $0.00278 $153,476 $0.00407 $224,693 Transition Energy $0.02320 $1,280,805 $0.02320 $1,280,805 Standard Offer $0.03800 $2,097,869 $0.03800 $2,097,869 DSM $0.00230 $126,976 $0.00230 $126,976 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $5,366,238 $5,982,172 5 Total Revenue Shift: $615,934 6 Revenue Shift by Function: Distribution Revenue $544,717 Transmission Revenue $71,217 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate G2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 15 of 29 The Narragansett Electric Company Shifting BVE Rate G-2 to Narragansett Rate G-02 ============================================================================================================================= BVE Rate G-2 Narragansett Rate G-02 G-2/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 12,852 $0.00 $0 12,852 $103.41 $1,329,025 2 Demand Charge: Distribution Demand 621,666 $1.50 $932,499 597,149 $2.91 $1,737,704 Transmission Demand $0.00 $0 $1.40 $836,009 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 189,662,772 $0.02296 $4,354,657 189,662,772 $0.01030 $1,953,527 Transmission Energy $0.00278 $527,263 ($0.00129) ($244,665) Transition Energy $0.02320 $4,400,176 $0.02320 $4,400,176 Standard Offer $0.03800 $7,207,185 $0.03800 $7,207,185 DSM $0.00230 $436,224 $0.00230 $436,224 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $17,858,005 $17,655,185 5 Total Revenue Shift: ($202,820) 6 Revenue Shift by Function: Distribution Revenue ($266,901) Transmission Revenue $64,081 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate G2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 16 of 29 The Narragansett Electric Company Shifting BVE Rate G-2 to Narragansett Rate G-32 ============================================================================================================================= BVE Rate G-2 Narragansett Rate G-32 G-2/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 780 $0.00 $0 780 $236.43 $184,415 2 Demand Charge: Distribution Demand 226,150 $1.50 $339,225 269,038 $1.56 $419,699 Transmission Demand $0.00 $0 $1.27 $341,678 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 68,985,660 $0.02296 $1,583,911 68,985,660 $0.01139 $785,747 Transmission Energy $0.00278 $191,780 ($0.00129) ($88,992) Transition Energy $0.02320 $1,600,467 $0.02320 $1,600,467 Standard Offer $0.03800 $2,621,455 $0.03800 $2,621,455 DSM $0.00230 $158,667 $0.00230 $158,667 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $6,495,505 $6,023,138 5 Total Revenue Shift: ($472,368) 6 Revenue Shift by Function: Distribution Revenue ($533,274) Transmission Revenue $60,907 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate T2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 17 of 29 The Narragansett Electric Company Shifting BVE Rate T-2 to Narragansett Rate C-06 ============================================================================================================================= BVE Rate T-2 Narragansett Rate C-06 T-2/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 54 $0.00 $0 54 $5.73 $309 2 Demand Charge: Distribution Demand 707 $1.50 $1,061 1,888 $0.00 $0 Transmission Demand $0.00 $0 $0.00 $0 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 93,312 $0.02296 $2,142 93,312 $0.03898 $3,637 Transmission Energy $0.00278 $259 $0.00407 $380 Transition Energy $0.02320 $2,165 $0.02320 $2,165 Standard Offer On Peak 13,722 $0.03800 $521 $0.03800 $3,546 Standard Offer Off Peak 79,590 $0.03800 $3,024 DSM $0.00230 $215 $0.00230 $215 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $9,388 $10,252 5 Total Revenue Shift: $864 6 Revenue Shift by Function: Distribution Revenue $744 Transmission Revenue $120 Transition Revenue $0 Standard Offer Revenue ($0) DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate T2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 18 of 29 The Narragansett Electric Company Shifting BVE Rate T-2 to Narragansett Rate G-02 ============================================================================================================================= BVE Rate T-2 Narragansett Rate G-02 T-2/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 551 $0.00 $0 551 $103.41 $56,979 2 Demand Charge: Distribution Demand 31,864 $1.50 $47,796 24,796 $2.91 $72,156 Transmission Demand $0.00 $0 $1.40 $34,714 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 13,353,435 $0.02296 $306,595 13,353,435 $0.01030 $137,540 Transmission Energy $0.00278 $37,123 ($0.00129) ($17,226) Transition Energy $0.02320 $309,800 $0.02320 $309,800 Standard Offer On Peak 2,692,710 $0.03800 $102,323 $0.03800 $507,431 Standard Offer Off Peak 10,660,725 $0.03800 $405,108 DSM $0.00230 $30,713 $0.00230 $30,713 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $1,239,457 $1,132,107 5 Total Revenue Shift: ($107,349) 6 Revenue Shift by Function: Distribution Revenue ($87,715) Transmission Revenue ($19,634) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate T2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 19 of 29 The Narragansett Electric Company Shifting BVE Rate T-2 to Narragansett Rate G-32 ============================================================================================================================= BVE Rate T-2 Narragansett Rate G-32 T-2/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 251 $0.00 $0 251 $236.43 $59,344 2 Demand Charge: Distribution Demand 78,241 $1.50 $117,362 99,892 $1.56 $155,832 Transmission Demand $0.00 $0 $1.27 $126,863 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 32,469,660 $0.02296 $745,503 32,469,660 $0.01139 $369,829 Transmission Energy $0.00278 $90,266 ($0.00129) ($41,886) Transition Energy $0.02320 $753,296 $0.02320 $753,296 Standard Offer On Peak 6,866,980 $0.03800 $260,945 $0.03800 $1,233,847 Standard Offer Off Peak 25,602,680 $0.03800 $972,902 DSM $0.00230 $74,680 $0.00230 $74,680 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $3,014,954 $2,731,805 5 Total Revenue Shift: ($283,149) 6 Revenue Shift by Function: Distribution Revenue ($277,860) Transmission Revenue ($5,289) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate T4 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 20 of 29 The Narragansett Electric Company Shifting BVE Rate T-4 to Narragansett Rate G-32 ============================================================================================================================= BVE Rate T-4 Narragansett Rate G-32 T-4/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 372 $0.00 $0 372 $236.43 $87,952 2 Demand Charge: Distribution Demand 195,414 $1.44 $281,396 225,770 $1.56 $352,201 Transmission Demand $0.00 $0 $1.27 $286,728 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 78,036,479 $0.01625 $1,268,093 78,036,479 $0.01139 $888,835 Transmission Energy $0.00278 $216,941 ($0.00129) ($100,667) Transition Energy $0.02320 $1,810,446 $0.02320 $1,810,446 Standard Offer On Peak 18,111,219 $0.03800 $688,226 $0.03800 $2,965,386 Standard Offer Off Peak 59,925,260 $0.03800 $2,277,160 DSM $0.00230 $179,484 $0.00230 $179,484 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $6,721,747 $6,470,366 5 Total Revenue Shift: ($251,381) 6 Revenue Shift by Function: Distribution Revenue ($220,500) Transmission Revenue ($30,881) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate G5 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 21 of 29 The Narragansett Electric Company Shifting BVE Rate G-5 to Narragansett Rate G-02 ============================================================================================================================= BVE Rate G-5 Narragansett Rate G-02 G-5/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 228 $0.00 $0 228 $103.41 $23,577 2 Demand Charge: Distribution Demand 20,540 $1.35 $27,729 27,078 $2.91 $78,797 Transmission Demand $0.00 $0 $1.40 $37,909 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 7,714,640 $0.01710 $131,920 7,714,640 $0.01030 $79,461 Transmission Energy $0.00278 $21,447 ($0.00129) ($9,952) Transition Energy $0.02320 $178,980 $0.02320 $178,980 Standard Offer $0.03800 $293,156 $0.03800 $293,156 DSM $0.00230 $17,744 $0.00230 $17,744 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 27,078 ($0.37) ($10,019) Primary Metering $699,672 -1% ($6,997) 4 Total Revenue before GET: $670,976 $682,657 5 Total Revenue Shift: $11,681 6 Revenue Shift by Function: Distribution Revenue $8,559 Transmission Revenue $6,231 Transition Revenue $0 Standard Offer Revenue ($2,932) DSM ($177)
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate G5 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 22 of 29 The Narragansett Electric Company Shifting BVE Rate G-5 to Narragansett Rate G-32 ============================================================================================================================= BVE Rate G-5 Narragansett Rate G-32 G-5/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 166 $0.00 $0 166 $236.43 $39,247 2 Demand Charge: Distribution Demand 52,600 $1.35 $71,010 58,829 $1.56 $91,773 Transmission Demand $0.00 $0 $1.27 $74,713 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 15,393,940 $0.01710 $263,236 15,393,940 $0.01139 $175,337 Transmission Energy $0.00278 $42,795 ($0.00129) ($19,858) Transition Energy $0.02320 $357,139 $0.02320 $357,139 Standard Offer $0.03800 $584,970 $0.03800 $584,970 DSM $0.00230 $35,406 $0.00230 $35,406 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 58,829 ($0.37) ($21,767) Primary Metering $1,338,727 -1% ($13,387) 4 Total Revenue before GET: $1,354,557 $1,303,573 5 Total Revenue Shift: ($50,983) 6 Revenue Shift by Function: Distribution Revenue ($56,290) Transmission Revenue $11,511 Transition Revenue $0 Standard Offer Revenue ($5,850) DSM ($354)
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate T5 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 23 of 29 The Narragansett Electric Company Shifting BVE Rate T-5 to Narragansett Rate G-02 ============================================================================================================================= BVE Rate T-5 Narragansett Rate G-02 T-5/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 7 $0.00 $0 7 $103.41 $724 2 Demand Charge: Distribution Demand 358 $1.35 $483 288 $2.91 $838 Transmission Demand $0.00 $0 $1.40 $403 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 114,950 $0.01710 $1,966 114,950 $0.01030 $1,184 Transmission Energy $0.00278 $320 ($0.00129) ($148) Transition Energy $0.02320 $2,667 $0.02320 $2,667 Standard Offer On Peak 27,650 $0.03800 $1,051 $0.03800 $4,368 Standard Offer Off Peak 87,300 $0.03800 $3,317 DSM $0.00230 $264 $0.00230 $264 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 288 ($0.37) ($107) Primary Metering $10,300 -1% ($103) 5 Total Revenue before GET: $10,068 $10,091 6 Total Revenue Shift: $23 7 Revenue Shift by Function: Distribution Revenue $136 Transmission Revenue ($67) Transition Revenue $0 Standard Offer Revenue ($44) DSM ($3)
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate T5 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 24 of 29 The Narragansett Electric Company Shifting BVE Rate T-5 to Narragansett Rate G-32 ============================================================================================================================= BVE Rate T-5 Narragansett Rate G-32 T-5/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 45 $0.00 $0 45 $236.43 $10,639 2 Demand Charge: Distribution Demand 20,534 $1.35 $27,721 20,534 $1.56 $32,033 Transmission Demand $0.00 $0 $1.27 $26,078 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 8,360,000 $0.01710 $142,956 8,360,000 $0.01139 $95,220 Transmission Energy $0.00278 $23,241 ($0.00129) ($10,784) Transition Energy $0.02320 $193,952 $0.02320 $193,952 Standard Offer On Peak 1,979,450 $0.03800 $75,219 $0.03800 $317,680 Standard Offer Off Peak 6,380,550 $0.03800 $242,461 DSM $0.00230 $19,228 $0.00230 $19,228 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 20,534 ($0.37) ($7,598) Primary Metering $684,047 -1% ($6,840) 4 Total Revenue before GET: $724,778 $669,609 5 Total Revenue Shift: ($55,169) 6 Revenue Shift by Function: Distribution Revenue ($43,700) Transmission Revenue ($8,100) Transition Revenue $0 Standard Offer Revenue ($3,177) DSM ($192)
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate T6 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 25 of 29 The Narragansett Electric Company Shifting BVE Rate T-6 to Narragansett Rate G-32 ============================================================================================================================= BVE Rate T-6 Narragansett Rate G-32 T-6/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 656 $0.00 $0 656 $236.43 $155,098 2 Demand Charge: Distribution Demand 682,889 $1.32 $901,413 782,155 $1.56 $1,220,162 Transmission Demand $0.00 $0 $1.27 $993,337 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 300,621,894 $0.01143 $3,436,108 300,621,894 $0.01139 $3,424,083 Transmission Energy $0.00278 $835,729 ($0.00129) ($387,802) Transition Energy $0.02320 $6,974,428 $0.02320 $6,974,428 Standard Offer On Peak 66,237,289 $0.03800 $2,517,017 $0.03800 $11,423,632 Standard Offer Off Peak 234,384,605 $0.03800 $8,906,615 DSM $0.00230 $691,430 $0.00230 $691,430 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 782,155 ($0.37) ($289,397) Primary Metering $24,494,368 -1% ($244,944) 4 Total Revenue before GET: $24,262,741 $23,960,027 5 Total Revenue Shift: ($302,714) 6 Revenue Shift by Function: Distribution Revenue $54,686 Transmission Revenue ($236,250) Transition Revenue $0 Standard Offer Revenue ($114,236) DSM ($6,914)
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate T6 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 26 of 29 The Narragansett Electric Company Shifting BVE Rate T-6 to Narragansett Rate G-62 ============================================================================================================================= BVE Rate T-6 Narragansett Rate G-62 T-6/G-62 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 36 $0.00 $0 36 $17,118.72 $616,274 2 Demand Charge: Distribution Demand 109,293 $1.32 $144,267 142,198 $0.75 $106,649 Transmission Demand $0.00 $0 $1.39 $197,655 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 69,235,500 $0.01143 $791,362 69,235,500 $0.00434 $300,482 Transmission Energy $0.00278 $192,475 ($0.00129) ($89,314) Transition Energy $0.02320 $1,606,264 $0.02320 $1,606,264 Standard Offer On Peak 11,791,499 $0.03800 $448,077 $0.03800 $2,630,949 Standard Offer Off Peak 57,444,001 $0.03800 $2,182,872 DSM $0.00230 $159,242 $0.00230 $159,242 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 142,198 ($0.37) ($52,613) Primary Metering $5,528,200 -1% ($55,282) 4 Total Revenue before GET: $5,524,557 $5,420,305 5 Total Revenue Shift: ($104,253) 6 Revenue Shift by Function: Distribution Revenue $8,866 Transmission Revenue ($85,217) Transition Revenue $0 Standard Offer Revenue ($26,309) DSM ($1,592)
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: Rate A6 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 27 of 29 The Narragansett Electric Company Shifting BVE Rate A-6 to Narragansett Rate B-32 ============================================================================================================================= BVE Rate A-6 Narragansett Rate B-32 A-6/B-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================= 1 Customer Charge: 48 $14.17 $680 48 $236.43 $11,349 2 Demand Charge: Distribution Demand 31,497 $2.00 $62,994 31,497 $1.56 $49,135 Transmission Demand $0.00 $0 $1.27 $40,001 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 6,085,455 $0.01425 $86,718 6,085,455 $0.01139 $69,313 Transmission Energy $0.00278 $16,918 ($0.00129) ($7,850) Transition Energy $0.02320 $141,183 $0.02320 $141,183 Standard Offer On Peak 1,172,792 $0.03800 $44,566 $0.03800 $231,247 Standard Offer Off Peak 4,912,663 $0.03800 $186,681 DSM $0.00230 $13,997 $0.00230 $13,997 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 31,497 ($0.37) ($11,654) Primary Metering $548,375 -1% ($5,484) 4 Total Revenue before GET: $553,736 $531,237 5 Total Revenue Shift: ($22,499) 6 Revenue Shift by Function: Distribution Revenue ($34,958) Transmission Revenue $14,912 Transition Revenue $0 Standard Offer Revenue ($2,312) DSM ($140)
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: BVE BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 28 of 29 Shifting BVE Rate S-1 to Narragansett Rate S-14 Total Number Annual Annual Annual Distribution Transmission of Units kWh Price kWh Sales Revenues Revenues Overhead $0.00278 Sodium Vapor Lamp Existing or Prepaid Wood Poles 3300 Streetlight 14 240 $53.29 3,360 $746 $9 5800 Streetlight 10,859 334 $54.80 3,626,906 $595,073 $10,083 5800 Flood 9 334 $67.92 3,006 $611 $8 9500 Streetlight 2,289 476 $56.38 1,089,564 $129,054 $3,029 9500 T&C 3 476 $58.29 1,428 $175 $4 16000 Streetlight 31 692 $58.36 21,452 $1,809 $60 16000 Flood 78 692 $72.14 53,976 $5,627 $150 25000 Streetlight 1,079 1,274 $69.73 1,374,646 $75,239 $3,822 25000 Flood 892 1,274 $77.44 1,136,408 $69,076 $3,159 50000 Streetlight 102 1,966 $80.57 200,532 $8,218 $557 50000 Flood 1,916 1,966 $88.32 3,766,856 $169,221 $10,472 Lighting only Wood Poles 16000 Streetlight 1 692 $140.04 692 $140 $2 16000 Flood 1 692 $154.25 692 $154 $2 25000 Flood 7 1,274 $159.13 8,918 $1,114 $25 50000 Streetlight 1 1,966 $162.28 1,966 $162 $5 50000 Flood 72 1,966 $170.02 141,552 $12,241 $394 Lighting only Metal Poles 25000 Streetlight 24 1,274 $254.90 30,576 $6,118 $85 25000 Flood 1 1,274 $266.39 1,274 $266 $4 50000 Streetlight 1 1,966 $265.71 1,966 $266 $5 50000 Flood 5 1,966 $277.03 9,830 $1,385 $27 Mercury Vapor Lamp Existing or Prepaid Wood Poles 4200 Streetlight 2,280 511 $44.44 1,165,080 $101,323 $3,239 8600 Streetlight 467 822 $47.05 383,874 $21,972 $1,067 8600 T&C 16 822 $45.87 13,152 $734 $37 22500 Streetlight 105 1,864 $64.97 195,720 $6,822 $544 22500 Flood 99 1,864 $63.52 184,536 $6,288 $513 63000 Flood 23 4,463 $98.19 102,649 $2,258 $285 Lighting only Metal Poles 22500 Streetlight 3 1,864 $198.77 5,592 $596 $16 22500 Flood 2 1,864 $200.07 3,728 $400 $10 Metal Halide Lamp Existing or Prepaid Wood Poles 20000 Flood 5 1,180 $94.69 5,900 $473 $16 40000 Flood 28 1,832 $124.67 51,296 $3,491 $143 Total Overhead 20,413 13,587,127 $1,221,055 $37,772 Shifting BVE Rate S-1 to Narragansett Rate S-14 Standard Total Transition Offer DSM Total Annual Annual Annual Revenues Revenues Revenues Revenues kWh Price kWh Sale Overhead $0.02320 $0.03800 $0.00230 Sodium Vapor Lamp Existing or Prepaid Wood Poles 3300 Streetlight $78 $128 $8 $969 248 $62.78 3,472 5800 Streetlight $84,144 $137,822 $8,342 $835,465 349 $66.28 3,789,791 5800 Flood $70 $114 $7 $811 349 $66.28 3,141 9500 Streetlight $25,278 $41,403 $2,506 $201,270 490 $72.63 1,121,610 9500 T&C $33 $54 $3 $270 490 $72.63 1,470 16000 Streetlight $498 $815 $49 $3,231 490 $72.63 15,190 16000 Flood $1,252 $2,051 $124 $9,204 490 $72.63 38,220 25000 Streetlight $31,892 $52,237 $3,162 $166,350 1284 $120.39 1,385,436 25000 Flood $26,365 $43,184 $2,614 $144,398 1284 $143.14 1,145,328 50000 Streetlight $4,652 $7,620 $461 $21,509 1968 $163.46 200,736 50000 Flood $87,391 $143,141 $8,664 $418,888 1968 $181.37 3,770,688 Lighting only Wood Poles 16000 Streetlight $16 $26 $2 $186 490 $128.08 490 16000 Flood $16 $26 $2 $200 490 $128.08 490 25000 Flood $207 $339 $21 $1,705 1284 $198.59 8,988 50000 Streetlight $46 $75 $5 $293 1968 $218.91 1,968 50000 Flood $3,284 $5,379 $326 $21,624 1968 $236.82 141,696 Lighting only Metal Poles 25000 Streetlight $709 $1,162 $70 $8,144 1284 $429.21 30,816 25000 Flood $30 $48 $3 $351 1284 $451.96 1,284 50000 Streetlight $46 $75 $5 $396 1968 $472.28 1,968 50000 Flood $228 $374 $23 $2,037 1968 $490.19 9,840 Mercury Vapor Lamp Existing or Prepaid Wood Poles 4200 Streetlight $27,030 $44,273 $2,680 $178,545 561 $54.40 1,279,080 8600 Streetlight $8,906 $14,587 $883 $47,416 908 $70.77 424,036 8600 T&C $305 $500 $30 $1,606 908 $70.77 14,528 22500 Streetlight $4,541 $7,437 $450 $19,794 1897 $122.31 199,185 22500 Flood $4,281 $7,012 $424 $18,520 1897 $152.08 187,803 63000 Flood $2,381 $3,901 $236 $9,062 4569 $262.72 105,087 Lighting only Metal Poles 22500 Streetlight $130 $212 $13 $967 1897 $375.68 5,691 22500 Flood $86 $142 $9 $647 1897 $405.45 3,794 Metal Halide Lamp Existing or Prepaid Wood Poles 20000 Flood $137 $224 $14 $865 1284 $143.14 6,420 40000 Flood $1,190 $1,949 $118 $6,891 1968 $181.37 55,104 Total Overhead $315,221 $516,311 $31,250 $2,121,610 13,953,350 Standard Distribution Transmission Transition Offer DSM Total Revenues Revenues Revenues Revenues Revenues Revenues Overhead ($0.04024) $0.00130 $0.02320 $0.03800 $0.00230 Sodium Vapor Lamp Existing or Prepaid Wood Poles 3300 Streetlight $739 $5 $81 $132 $8 $964 5800 Streetlight $567,233 $4,927 $87,923 $144,012 $8,717 $812,812 5800 Flood $470 $4 $73 $119 $7 $674 9500 Streetlight $121,116 $1,458 $26,021 $42,621 $2,580 $193,797 9500 T&C $159 $2 $34 $56 $3 $254 16000 Streetlight $1,640 $20 $352 $577 $35 $2,625 16000 Flood $4,127 $50 $887 $1,452 $88 $6,604 25000 Streetlight $74,151 $1,801 $32,142 $52,647 $3,187 $163,927 25000 Flood $81,593 $1,489 $26,572 $43,522 $2,634 $155,810 50000 Streetlight $8,595 $261 $4,657 $7,628 $462 $21,603 50000 Flood $195,772 $4,902 $87,480 $143,286 $8,673 $440,113 Lighting only Wood Poles 16000 Streetlight $108 $1 $11 $19 $1 $140 16000 Flood $108 $1 $11 $19 $1 $140 25000 Flood $1,028 $12 $209 $342 $21 $1,611 50000 Streetlight $140 $3 $46 $75 $5 $267 50000 Flood $11,349 $184 $3,287 $5,384 $326 $20,531 Lighting only Metal Poles 25000 Streetlight $9,061 $40 $715 $1,171 $71 $11,058 25000 Flood $400 $2 $30 $49 $3 $483 50000 Streetlight $393 $3 $46 $75 $5 $521 50000 Flood $2,055 $13 $228 $374 $23 $2,693 Mercury Vapor Lamp Existing or Prepaid Wood Poles 4200 Streetlight $72,562 $1,663 $29,675 $48,605 $2,942 $155,446 8600 Streetlight $15,986 $551 $9,838 $16,113 $975 $43,464 8600 T&C $548 $19 $337 $552 $33 $1,489 22500 Streetlight $4,827 $259 $4,621 $7,569 $458 $17,735 22500 Flood $7,499 $244 $4,357 $7,137 $432 $19,668 63000 Flood $1,814 $137 $2,438 $3,993 $242 $8,623 Lighting only Metal Poles 22500 Streetlight $898 $7 $132 $216 $13 $1,267 22500 Flood $658 $5 $88 $144 $9 $904 Metal Halide Lamp Existing or Prepaid Wood Poles 20000 Flood $457 $8 $149 $244 $15 $873 40000 Flood $2,861 $72 $1,278 $2,094 $127 $6,432 Total Overhead 1,188,351 $18,139 $323,718 $530,227 $32,093 $2,092,528
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric Range: BVE BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 1 Page 29 of 29 Total Number Annual Annual Annual Distribution Transmission Transition of Units kWh Price kWh Sales Revenues Revenues Revenues Underground $0.00278 $0.02320 Sodium Vapor Lamp Existing or Prepaid Standard Metal Poles 16000 Flood 1 692 $83.98 692 $84 $2 $16 25000 Streetlight 4 1,274 $77.37 5,096 $309 $14 $118 25000 Flood 1 1,274 $88.86 1,274 $89 $4 $30 50000 Flood 11 1,966 $99.76 21,626 $1,097 $60 $502 Lighting only Standard Metal Poles 9500 Streetlight 95 476 $227.66 45,220 $21,628 $126 $1,049 9500 PBU 2 952 $283.46 1,904 $567 $5 $44 25000 Streetlight 354 1,274 $240.95 450,996 $85,296 $1,254 $10,463 25000 Streetlight-Twin 16 2,548 $318.71 40,768 $5,099 $113 $946 25000 Flood 18 1,274 $252.43 22,932 $4,544 $64 $532 50000 Streetlight 9 1,966 $251.76 17,694 $2,266 $49 $411 50000 Flood 10 1,966 $263.32 19,660 $2,633 $55 $456 Lighting only Poles less than 15 ft. 5800 T&C 129 334 $148.75 43,086 $19,189 $120 $1,000 9500 T&C 36 476 $150.96 17,136 $5,435 $48 $398 Lighting only Poles greater than 15 ft. 5800 Streetlight 38 334 $215.36 12,692 $8,184 $35 $294 9500 Shoe Box 26 476 $214.01 12,376 $5,564 $34 $287 Lighting only Wood Poles 5800 Streetlight 1 334 $174.47 334 $174 $1 $8 Mercury Vapor Lamp Lighting only Standard Metal Poles 8600 Streetlight 28 822 $170.78 23,016 $4,782 $64 $534 8600 Streetlight-Twin 18 1,644 $223.65 29,592 $4,026 $82 $687 22500 Streetlight 33 1,864 $188.70 61,512 $6,227 $171 $1,427 22500 Streetlight-Twin 3 3,728 $252.74 11,184 $758 $31 $259 Lighting only Poles less than 15 ft. 8600 T&C 269 822 $109.84 221,118 $29,547 $615 $5,130 Total Underground 1,102 1,059,908 $207,498 $2,947 $24,590 Total Overhead and Underground 21,515 14,647,035 $1,428,554 $40,719 $339,811 Standard Total Offer DSM Total Annual Annual Annual Revenues Revenues Revenues kWH Price kWh Sales Underground $0.03800 $0.00230 Sodium Vapor Lamp Existing or Prepaid Standard Metal Poles 16000 Flood $26 $2 $130 980 $145.26 980 25000 Streetlight $194 $12 $647 1284 $120.39 5,136 25000 Flood $48 $3 $173 1284 $143.14 1,284 50000 Flood $822 $50 $2,531 1968 $181.37 21,648 Lighting only Standard Metal Poles 9500 Streetlight $1,718 $104 $24,625 490 $326.00 46,550 9500 PBU $72 $4 $693 1960 $398.63 3,920 25000 Streetlight $17,138 $1,037 $115,188 1284 $373.76 454,536 25000 Streetlight-Twin $1,549 $94 $7,801 2568 $494.15 41,088 25000 Flood $871 $53 $6,064 1284 $396.51 23,112 50000 Streetlight $672 $41 $3,439 1968 $416.83 17,712 50000 Flood $747 $45 $3,936 1968 $434.74 19,680 Lighting only Poles less than 15 ft. 5800 T&C $1,637 $99 $22,044 349 $123.62 45,021 9500 T&C $651 $39 $6,570 490 $129.97 17,640 Lighting only Poles greater than 15 ft. 5800 Streetlight $482 $29 $9,025 349 $123.62 13,262 9500 Shoe Box $470 $28 $6,385 490 $129.97 12,740 Lighting only Wood Poles 5800 Streetlight $13 $1 $197 349 $121.73 349 Mercury Vapor Lamp Lighting only Standard Metal Poles 8600 Streetlight $875 $53 $6,307 908 $324.14 25,424 8600 Streetlight-Twin $1,124 $68 $5,987 908 $394.91 16,344 22500 Streetlight $2,337 $141 $10,304 1897 $375.68 62,601 22500 Streetlight-Twin $425 $26 $1,499 1897 $557.53 5,691 Lighting only Poles less than 15 ft. 8600 T&C $8,402 $509 $44,203 908 $128.11 244,252 Total Underground $40,277 $2,438 $277,749 1,078,970 Total Overhead and Underground $556,587 $33,688 $2,399,359 $15,032,320 Standard Distribution Transmission Transition Offer DSM Total Revenues Revenues Revenues Revenues Revenues Revenues Underground ($0.04024) $0.00130 $0.02320 $0.03800 $0.00230 Sodium Vapor Lamp Existing or Prepaid Standard Metal Poles 16000 Flood $106 $1 $23 $37 $2 $169 25000 Streetlight $275 $7 $119 $195 $12 $608 25000 Flood $91 $2 $30 $49 $3 $175 50000 Flood $1,124 $28 $502 $823 $50 $2,527 Lighting only Standard Metal Poles 9500 Streetlight $29,097 $61 $1,080 $1,769 $107 $32,113 9500 PBU $640 $5 $91 $149 $9 $894 25000 Streetlight $114,021 $591 $10,545 $17,272 $1,045 $143,474 25000 Streetlight-Twin $6,253 $53 $953 $1,561 $95 $8,916 25000 Flood $6,207 $30 $536 $878 $53 $7,705 50000 Streetlight $3,039 $23 $411 $673 $41 $4,186 50000 Flood $3,555 $26 $457 $748 $45 $4,831 Lighting only Poles less than 15 ft. 5800 T&C $14,135 $59 $1,044 $1,711 $104 $17,053 9500 T&C $3,969 $23 $409 $670 $41 $5,112 Lighting only Poles greater than 15 ft. 5800 Streetlight $4,164 $17 $308 $504 $31 $5,023 9500 Shoe Box $2,867 $17 $296 $484 $29 $3,692 Lighting only Wood Poles 5800 Streetlight $108 $0 $8 $13 $1 $130 Mercury Vapor Lamp Lighting only Standard Metal Poles 8600 Streetlight $8,053 $33 $590 $966 $58 $9,700 8600 Streetlight-Twin $6,451 $21 $379 $621 $38 $7,510 22500 Streetlight $9,878 $81 $1,452 $2,379 $144 $13,935 22500 Streetlight-Twin $1,444 $7 $132 $216 $13 $1,812 Lighting only Poles less than 15 ft. 8600 T&C $24,633 $318 $5,667 $9,282 $562 $40,460 Total Underground $240,108 $1,403 $25,032 $41,001 $2,482 $310,026 Total Overhead and Underground $1,428,459 $19,542 $348,750 $571,228 $34,574 $2,402,553
File: C:\JMM\[workjmm2.wk4]Rate A16 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 1 of 14 The Narragansett Electric Company Rate A-16 =========================================================================================================================== Pre Merger Rate A-16 Post Merger Rate A-16 A-16 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 3,087,617 $2.54 $7,842,547 3,087,617 $2.54 $7,842,547 2 Energy Charges: Distribution Energy 1,475,595,371 $0.03680 $54,301,910 1,475,595,371 $0.03680 $54,301,910 Transmission Energy $0.00515 $7,599,316 $0.00515 $7,599,316 Transition Energy $0.01150 $16,969,347 $0.01150 $16,969,347 Standard Offer $0.03800 $56,072,624 $0.03800 $56,072,624 DSM $0.00230 $3,393,869 $0.00230 $3,393,869 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $146,179,613 $146,179,613 4 Total Revenue Shift: $0 5 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0
File: C:\JMM\[workjmm2.wk4]Rate A18 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 2 of 14 The Narragansett Electric Company Rate A-18 =========================================================================================================================== Pre Merger Rate A-18 Post Merger Rate A-18 A-18 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 366,803 $2.52 $924,344 366,803 $2.52 $924,344 2 Energy Charges: Distribution Energy 299,522,556 $0.03602 $10,788,802 299,522,556 $0.03602 $10,788,802 Transmission Energy $0.00466 $1,395,775 $0.00466 $1,395,775 Transition Energy $0.01150 $3,444,509 $0.01150 $3,444,509 Standard Offer $0.03800 $11,381,857 $0.03800 $11,381,857 DSM $0.00230 $688,902 $0.00230 $688,902 Water Heater Credit 210,516,280 ($0.00661) ($1,391,513) 210,516,280 ($0.00661) ($1,391,513) 3 Total Revenue before GET: $27,232,677 $27,232,677 4 Total Revenue Shift: $0 5 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm2.wk4]Rate A32 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 3 of 14 The Narragansett Electric Company Rate A-32 =========================================================================================================================== Pre Merger Rate A-32 Post Merger Rate A-32 A-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 11,757 $6.74 $79,242 11,757 $6.74 $79,242 2 Energy Charges: Distribution Energy 33,569,784 $0.02596 $871,472 33,569,784 $0.02596 $871,472 Transmission Energy $0.00471 $158,114 $0.00471 $158,114 Transition Energy $0.01150 $386,053 $0.01150 $386,053 Standard Offer On Peak 7,649,055 $0.03800 $290,664 7,649,055 $0.03800 $290,664 Standard Offer Off Peak 25,920,729 $0.03800 $984,988 25,920,729 $0.03800 $984,988 DSM $0.00230 $77,211 $0.00230 $77,211 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $2,847,742 $2,847,742 4 Total Revenue Shift: $0 5 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm2.wk4]Rate A60 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 4 of 14 The Narragansett Electric Company Rate A-60 =========================================================================================================================== Pre Merger Rate A-60 Post Merger Rate A-60 A-60 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 100,072 $0.00 $0 100,072 $0.00 $0 2 Energy Charges: Distribution Energy 45,194,386 $0.02362 $1,067,491 45,194,386 $0.02362 $1,067,491 Transmission Energy $0.00417 $188,461 $0.00417 $188,461 Transition Energy $0.01150 $519,735 $0.01150 $519,735 Standard Offer $0.03800 $1,717,387 $0.03800 $1,717,387 DSM $0.00230 $103,947 $0.00230 $103,947 Water Heater Credit 3,667,794 ($0.00661) ($24,244) 3,667,794 ($0.00661) ($24,244) 3 Total Revenue before GET: $3,572,777 $3,572,777 4 Total Revenue Shift: $0 5 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm2.wk4]Rate C06 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 5 of 14 The Narragansett Electric Company Rate C-06 =========================================================================================================================== Pre Merger Rate C-06 Post Merger Rate C-06 C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: Customer Charge 327,918 $5.73 $1,878,970 327,918 $5.73 $1,878,970 Unmetered Charge 7,927 $1.83 $14,506 7,927 $1.83 $14,506 2 Energy Charges: Distribution Energy 319,448,478 $0.03898 $12,452,102 319,448,478 $0.03898 $12,452,102 Transmission Energy $0.00615 $1,964,608 $0.00615 $1,964,608 Transition Energy $0.01150 $3,673,657 $0.01150 $3,673,657 Standard Offer $0.03800 $12,139,042 $0.03800 $12,139,042 DSM $0.00230 $734,731 $0.00230 $734,731 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $32,857,618 $32,857,618 4 Total Revenue Shift: $0 5 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm2.wk4]Rate E30 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 6 of 14 The Narragansett Electric Company Rate E-30 ==================================================================================================================== Pre Merger Rate E-30 Post Merger Rate E-30 E-30 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ==================================================================================================================== 1 Customer Charge: 173 $7.54 $1,304 173 $7.54 $1,304 2 Energy Charges: Distribution Energy 1,519,157 $0.01620 $24,610 1,519,157 $0.01620 $24,610 Transmission Energy $0.00340 $5,165 $0.00340 $5,165 Transition Energy $0.01150 $17,470 $0.01150 $17,470 Standard Offer $0.03800 $57,728 $0.03800 $57,728 DSM $0.00230 $3,494 $0.00230 $3,494 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $109,772 $109,772 4 Total Revenue Shift: ($0) 5 Revenue Shift by Function: Distribution Revenue ($0) Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm2.wk4]Rate E40 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 7 of 14 The Narragansett Electric Company Rate E-40 =========================================================================================================================== Pre Merger Rate E-40 Post Merger Rate E-40 E-40 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 254 $75.15 $19,088 254 $75.15 $19,088 2 Energy Charges: Distribution On/Shoulder Energy 3,706,802 $0.02574 $95,413 3,706,802 $0.02574 $95,413 Distribution Off Peak Energy 8,729,522 $0.00987 $86,160 8,729,522 $0.00987 $86,160 Transmission Energy $0.00220 $27,360 $0.00220 $27,360 Transition Energy $0.01150 $143,018 $0.01150 $143,018 Standard Offer $0.03800 $472,580 $0.03800 $472,580 DSM $0.00230 $28,604 $0.00230 $28,604 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $872,223 $872,223 4 Total Revenue Shift: $0 5 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm2.wk4]Rate G02 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 8 of 14 The Narragansett Electric Company Rate G-02 =========================================================================================================================== Pre Merger Rate G-02 Post Merger Rate G-02 G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 72,380 $103.41 $7,484,816 72,380 $103.41 $7,484,816 2 Demand Charge: Distribution Demand 2,388,026 $2.91 $6,949,156 2,388,026 $2.91 $6,949,156 Transmission Demand $1.40 $3,343,236 $1.40 $3,343,236 3 Energy Charges: Distribution Energy 857,825,162 $0.01030 $8,835,599 857,825,162 $0.01030 $8,835,599 Transmission Energy $0.00079 $677,682 $0.00079 $677,682 Transition Energy $0.01150 $9,864,989 $0.01150 $9,864,989 Standard Offer $0.03800 $32,597,356 $0.03800 $32,597,356 DSM $0.00230 $1,972,998 $0.00230 $1,972,998 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $71,725,832 $71,725,832 5 Total Revenue Shift: $0 6 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm2.wk4]Rate G32 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 9 of 14 The Narragansett Electric Company Rate G-32 =========================================================================================================================== Pre Merger Rate G-32 Post Merger Rate G-32 G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 8,554 $236.43 $2,022,422 8,554 $236.43 $2,022,422 2 Demand Charge: Distribution Demand 4,100,824 $1.56 $6,397,285 4,100,824 $1.56 $6,397,285 Transmission Demand $1.27 $5,208,046 $1.27 $5,208,046 3 Energy Charges: Distribution Energy 1,497,395,176 $0.01139 $17,055,331 1,497,395,176 $0.01139 $17,055,331 Transmission Energy $0.00079 $1,182,942 $0.00079 $1,182,942 Transition Energy $0.01150 $17,220,045 $0.01150 $17,220,045 Standard Offer $0.03800 $56,901,017 $0.03800 $56,901,017 DSM $0.00230 $3,444,009 $0.00230 $3,444,009 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 799,345 ($0.37) ($295,758) 799,345 ($0.37) ($295,758) Primary Metering $109,431,098 -1% ($1,094,311) $109,431,098 -1% ($1,094,311) 5 Total Revenue before GET: $108,041,029 $108,041,029 6 Total Revenue Shift: $0 7 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm2.wk4]Rate G62 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 10 of 14 The Narragansett Electric Company Rate G-62 =========================================================================================================================== Pre Merger Rate G-62 Post Merger Rate G-62 G-62 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 84 $17,118.72 $1,437,972 84 $17,118.72 $1,437,972 2 Demand Charge: Distribution Demand 631,081 $0.75 $473,311 631,081 $0.75 $473,311 Transmission Demand $1.56 $984,486 $1.56 $984,486 3 Energy Charges: Distribution Energy 360,114,300 $0.00434 $1,562,896 360,114,300 $0.00434 $1,562,896 Transmission Energy $0.00079 $284,490 $0.00079 $284,490 Transition Energy $0.01150 $4,141,314 $0.01150 $4,141,314 Standard Offer $0.03800 $13,684,343 $0.03800 $13,684,343 DSM $0.00230 $828,263 $0.00230 $828,263 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 349,366 ($0.37) ($129,265) 349,366 ($0.37) ($129,265) Primary Metering $23,397,077 -1% ($233,971) $23,397,077 -1% ($233,971) 5 Total Revenue before GET: $23,033,841 $23,033,841 6 Total Revenue Shift: $0 7 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm2.wk4]Rate R02 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 11 of 14 The Narragansett Electric Company Rate R-02 =========================================================================================================================== Pre Merger Rate R-02 Post Merger Rate R-02 R-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 7,642 $0.00 $0 7,642 $0.00 $0 2 Energy Charges: Distribution Energy 4,803,789 $0.00905 $43,474 4,803,789 $0.00905 $43,474 Transmission Energy $0.00338 $16,237 $0.00338 $16,237 Transition Energy $0.01150 $55,244 $0.01150 $55,244 Standard Offer $0.03800 $182,544 $0.03800 $182,544 DSM $0.00230 $11,049 $0.00230 $11,049 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $308,547 $308,547 4 Total Revenue Shift: $0 5 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
C:\JMM\[worjmm2a.wk4]A Narragansett Electric STREETLIGHTS BVE/Newport Electric R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 12 of 14 The Narragansett Electric Company Normalized Streetlight Revenue ================================================================================================================================== Pre-merger Rate Streetlights Lumen Annual Standard Code Rate kWh Units kWh Sales Distribution DSM Transmission Transition Offer Total ================================================================================================================================== $0.00434 $0.00230 $0.00338 $0.01150 $0.03800 INCANDESCENT 1,000 10 $75.22 440 107 47,080 $8,253 $108 $159 $541 $1,789 $10,851 1,000 50 $75.22 440 4 1,760 $309 $4 $6 $20 $67 $406 2,500 11 $67.45 845 3 2,535 $213 $6 $9 $29 $96 $353 MERCURY VAPOR 8,000 (Post Top) 2 $108.85 908 23 20,884 $2,594 $48 $71 $240 $794 $3,747 4,000 3 $58.40 561 6,614 3,710,454 $402,361 $8,534 $12,541 $42,670 $140,997 $607,104 8,000 4 $70.77 908 1,792 1,627,136 $133,882 $3,742 $5,500 $18,712 $61,831 $223,667 15,000 (Providence) 17 $122.97 1,874 115 215,510 $15,077 $496 $728 $2,478 $8,189 $26,969 15,000 (Outside) 18 $122.97 1,874 114 213,636 $14,946 $491 $722 $2,457 $8,118 $26,734 22,000 5 $122.31 1,897 2,201 4,175,297 $287,325 $9,603 $14,113 $48,016 $158,661 $517,718 22,000 - 24 HR. 64 $222.87 3,794 0 $0 $0 $0 $0 $0 $0 63,000 6 $234.25 4,569 116 530,004 $29,473 $1,219 $1,791 $6,095 $20,140 $58,719 Flood lights 22,000 23 $152.08 1,897 910 1,726,270 $145,885 $3,970 $5,835 $19,852 $65,598 $241,140 63,000 24 $262.72 4,569 588 2,686,572 $166,139 $6,179 $9,081 $30,896 $102,090 $314,384 SODIUM VAPOR 4,000 70 $62.78 248 24,157 5,990,936 $1,542,577 $13,779 $20,249 $68,896 $227,656 $1,873,15 4,000 750 $62.78 248 248 61,504 $15,836 $141 $208 $707 $2,337 $19,230 4,000 755 $62.78 248 2,411 597,928 $153,958 $1,375 $2,021 $6,876 $22,721 $186,951 4,000 756 $62.78 248 458 113,584 $29,246 $261 $384 $1,306 $4,316 $35,514 4,000 711 $62.78 248 248 61,504 $15,836 $141 $208 $707 $2,337 $19,230 4,000 710 $62.78 248 10,698 2,653,104 $683,135 $6,102 $8,967 $30,511 $100,818 $829,533 5,800 71 $66.28 349 385 134,365 $26,101 $309 $454 $1,545 $5,106 $33,515 9,600 72 $72.63 490 11,786 5,775,140 $881,081 $13,283 $19,520 $66,414 $219,455 $1,199,75 27,500 74 $120.39 1,284 12,641 16,231,044 $1,592,293 $37,331 $54,861 $186,657 $616,780 $2,487,92 27,500(24 HR) 84 $172.21 2,568 0 $0 $0 $0 $0 $0 $0 50,000 75 $163.46 1,968 466 917,088 $80,153 $2,109 $3,100 $10,547 $34,849 $130,757 50,000 (Flood) 78 $181.37 1,968 718 1,413,024 $136,356 $3,250 $4,776 $16,250 $53,695 $214,327 27,500 (Flood) 77 $143.14 1,284 298 382,632 $44,316 $880 $1,293 $4,400 $14,540 $65,430 9,600 (Post top) 79 $78.56 490 490 240,100 $39,536 $552 $812 $2,761 $9,124 $52,785 UNDERGROUND Providence (In) / (Out) $110.86 3,298 $365,616 $365,616 Wood Poles P $55.45 32 $1,774 $1,774 Fiberglass without base R $57.34 368 $21,101 $21,101 Fiberglass with base < 25 f C $111.04 $0 $0 Fiberglass with base >= 25 D $185.67 $0 $0 Metal Poles with base T $253.37 204 $51,687 $51,687 Total 49,529,091 $6,887,061 $113,917 $167,408 $569,585 $1,882,105 $9,620,076 ================================================================================================================================== Post-merger Streetlights Standard Distribution DSM Transmission Transition Offer Total ================================================================================================================================== $0.00434 $0.00230 $0.00338 $0.01150 $0.03800 INCANDESCENT 1,000 $8,253 $108 $159 $541 $1,789 $10,851 1,000 $309 $4 $6 $20 $67 $406 2,500 $213 $6 $9 $29 $96 $353 MERCURY VAPOR 8,000 (Post Top) $2,594 $48 $71 $240 $794 $3,747 4,000 $402,361 $8,534 $12,541 $42,670 $140,997 $607,104 8,000 $133,882 $3,742 $5,500 $18,712 $61,831 $223,667 15,000 (Providence) $15,077 $496 $728 $2,478 $8,189 $26,969 15,000 (Outside) $14,946 $491 $722 $2,457 $8,118 $26,734 22,000 $287,325 $9,603 $14,113 $48,016 $158,661 $517,718 22,000 - 24 HR. $0 $0 $0 $0 $0 $0 63,000 $29,473 $1,219 $1,791 $6,095 $20,140 $58,719 Flood lights 22,000 $145,885 $3,970 $5,835 $19,852 $65,598 $241,140 63,000 $166,139 $6,179 $9,081 $30,896 $102,090 $314,384 SODIUM VAPOR 4,000 $1,542,577 $13,779 $20,249 $68,896 $227,656 $1,873,157 4,000 $15,836 $141 $208 $707 $2,337 $19,230 4,000 $153,958 $1,375 $2,021 $6,876 $22,721 $186,951 4,000 $29,246 $261 $384 $1,306 $4,316 $35,514 4,000 $15,836 $141 $208 $707 $2,337 $19,230 4,000 $683,135 $6,102 $8,967 $30,511 $100,818 $829,533 5,800 $26,101 $309 $454 $1,545 $5,106 $33,515 9,600 $881,081 $13,283 $19,520 $66,414 $219,455 $1,199,754 27,500 $1,592,293 $37,331 $54,861 $186,657 $616,780 $2,487,922 27,500(24 HR) $0 $0 $0 $0 $0 $0 50,000 $80,153 $2,109 $3,100 $10,547 $34,849 $130,757 50,000 (Flood) $136,356 $3,250 $4,776 $16,250 $53,695 $214,327 27,500 (Flood) $44,316 $880 $1,293 $4,400 $14,540 $65,430 9,600 (Post top) $39,536 $552 $812 $2,761 $9,124 $52,785 UNDERGROUND Providence (In) / (Out) $365,616 $365,616 Wood Poles $1,774 $1,774 Fiberglass without base $21,101 $21,101 Fiberglass with base < 25 f $0 $0 Fiberglass with base >= 25 $0 $0 Metal Poles with base $51,687 $51,687 Total $6,887,061 $113,917 $167,408 $569,585 $1,882,106 $9,620,076
File: C:\JMM\[workjmm2.wk4]Rate T06 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 13 of 14 The Narragansett Electric Company Rate T-06 =========================================================================================================================== Pre Merger Rate T-06 Post Merger Rate T-06 T-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 4,739 $7.84 $37,154 4,739 $7.84 $37,154 2 Energy Charges: Distribution Energy 21,835,478 $0.02285 $498,941 21,835,478 $0.02285 $498,941 Transmission Energy $0.00440 $96,076 $0.00440 $96,076 Transition Energy $0.01150 $251,108 $0.01150 $251,108 Standard Offer $0.03800 $829,748 $0.03800 $829,748 DSM $0.00230 $50,222 $0.00230 $50,222 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $1,763,248 $1,763,248 4 Total Revenue Shift: $0 5 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm2.wk4]Rate V02 Narragansett Electric Range: STREETLIGHTS BVE/Newport Electric Date: 31-Jul-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 2 Page 14 of 14 The Narragansett Electric Company Rate V-02 =========================================================================================================================== Pre Merger Rate V-02 Post Merger Rate V-02 V-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 4,553 $7.85 $35,741 4,553 $7.85 $35,741 2 Energy Charges: Distribution Energy 7,686,406 $0.03076 $236,434 7,686,406 $0.03076 $236,434 Transmission Energy $0.00626 $48,117 $0.00626 $48,117 Transition Energy $0.01150 $88,394 $0.01150 $88,394 Standard Offer $0.03800 $292,083 $0.03800 $292,083 DSM $0.00230 $17,679 $0.00230 $17,679 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $718,448 $718,448 4 Total Revenue Shift: $0 5 Revenue Shift by Function: Distribution Revenue $0 Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. __________ Workpaper JMM-3 Workpaper JMM-3 Newport Back-up
File: C:\JMM\[workjmm3.wk4]Rate R1 Narragansett Electric Range: Rate R1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 1 of 26 The Narragansett Electric Company Shifting NEC Rate R-1 to Narragansett Rate A-16 =================================================================================================================================== NEC Rate R-1 Narragansett Rate A-16 R-1/A-16 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =================================================================================================================================== 1 Customer Charge: 325,773 $3.10 $1,009,896 325,773 $2.54 $827,463 2 Energy Charges: Distribution Energy 167,201,036 $0.04653 $7,779,864 167,201,036 $0.04341 $7,258,197 Transmission Energy $0.00273 $456,459 $0.00300 $501,603 Transition Energy $0.02340 $3,912,504 $0.02340 $3,912,504 Standard Offer $0.03800 $6,353,639 $0.03800 $6,353,639 DSM $0.00230 $384,562 $0.00230 $384,562 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $19,896,925 $19,237,969 4 Total Revenue Shift: ($658,956) 5 Revenue Shift by Function: Distribution Revenue ($704,100) Transmission Revenue $45,144 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate R2 Narragansett Electric Range: Rate R2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 2 of 26 The Narragansett Electric Company Shifting NEC Rate R-2 to Narragansett Rate A-60 ================================================================================================================================== NEC Rate R-2 Narragansett Rate A-60 R-2/A-60 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 4,208 $2.14 $9,005 4,208 $0.00 $0 2 Energy Charges: Distribution Energy first 300 kWh 1,055,362 $0.00759 $8,010 1,055,362 ($0.00616) (6,501) Distribution Energy over 300 kWh 709,457 $0.04206 $29,840 Distribution Energy 1,764,819 $0.03023 $53,350 Transmission Energy $0.00273 $4,818 $0.00202 $3,565 Transition Energy $0.02340 $41,297 $0.02340 $41,297 Standard Offer $0.03800 $67,063 $0.03800 $67,063 DSM $0.00230 $4,059 $0.00230 $4,059 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $164,092 $162,833 4 Total Revenue Shift: ($1,259) 5 Revenue Shift by Function: Distribution Revenue ($6) Transmission Revenue ($1,253) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate R4 Narragansett Electric Range: Rate R4 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 3 of 26 The Narragansett Electric Company Shifting NEC Rate R-4 to Narragansett Rate A-32 ================================================================================================================================== NEC Rate R-4 Narragansett Rate A-32 R-4/A-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 2,504 $6.78 $16,977 2,504 $6.74 $16,877 2 Energy Charges: Distribution Peak 1,248,828 $0.11000 $137,371 1,248,828 $0.03257 $40,674 Distribution Off Peak 5,852,163 $0.03109 $181,944 5,852,163 $0.03257 $190,605 Transmission Energy 7,100,991 $0.00273 $19,386 7,100,991 $0.00256 $18,179 Transition Energy $0.02340 $166,163 $0.02340 $166,163 Standard Offer $0.03800 $269,838 $0.03800 $269,838 DSM $0.00230 $16,332 $0.00230 $16,332 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $808,011 $718,668 4 Total Revenue Shift: ($89,343) 5 Revenue Shift by Function: Distribution Revenue ($88,136) Transmission Revenue ($1,207) Transition Revenue $0 Standard Offer Revenue $0 DSM $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate W1 Narragansett Electric Range: Rate W1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 4 of 26 The Narragansett Electric Company Shifting NEC Rate W-1 to Narragansett Rate A-16 ================================================================================================================================== NEC Rate W-1 Narragansett Rate A-16 W-1/A-16 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 63,065 $3.29 $207,484 63,065 $0.00 $0 2 Energy Charges: Distribution Energy 13,062,846 $0.02399 $313,378 13,062,846 $0.04341 $567,058 Transmission Energy $0.00273 $35,662 $0.00300 $39,189 Transition Energy $0.02340 $305,671 $0.02340 $305,671 Standard Offer $0.03800 $496,388 $0.03800 $496,388 DSM $0.00230 $30,045 $0.00230 $30,045 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $1,388,626 $1,438,350 4 Total Revenue Shift: $49,724 5 Revenue Shift by Function: Distribution Revenue $46,197 Transmission Revenue $3,527 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate W1 Narragansett Electric Range: Rate W1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 5 of 26 The Narragansett Electric Company Shifting NEC Rate W-1 to Narragansett Rate C-06 ================================================================================================================================== NEC Rate W-1 Narragansett Rate C-06 W-1/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: Customer Charge 1,303 $3.29 $4,287 1,303 $0.00 $0 Unmetered Charge 0 $0.00 $0 2 Energy Charges: Distribution Energy 313,931 $0.02399 $7,531 313,931 $0.04559 $14,312 Transmission Energy $0.00273 $857 $0.00400 $1,256 Transition Energy $0.02340 $7,346 $0.02340 $7,346 Standard Offer $0.03800 $11,929 $0.03800 $11,929 DSM $0.00230 $722 $0.00230 $722 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $32,673 $35,565 4 Total Revenue Shift: $2,893 5 Revenue Shift by Function: Distribution Revenue $2,494 Transmission Revenue $399 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate W1 Narragansett Electric Range: Rate W1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 6 of 26 The Narragansett Electric Company Shifting NEC Rate W-1 to Narragansett Rate G-02 ================================================================================================================================== NEC Rate W-1 Narragansett Rate G-02 W-1/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 40 $3.29 $132 40 $0.00 $0 2 Demand Charge: Distribution Demand 0 $0.00 $0 0 $2.91 $0 Transmission Demand $1.40 $0 3 Energy Charges: Distribution Energy 6,491 $0.02399 $156 6,491 $0.01691 $110 Transmission Energy $0.00273 $18 ($0.00136) ($9) Transition Energy $0.02340 $152 $0.02340 $152 Standard Offer $0.03800 $247 $0.03800 $247 DSM $0.00230 $15 $0.00230 $15 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $719 $514 5 Total Revenue Shift: ($204) 6 Revenue Shift by Function: Distribution Revenue ($178) Transmission Revenue ($27) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate H1 Narragansett Electric Range: Rate H1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 7 of 26 The Narragansett Electric Company Shifting NEC Rate H-1 to Narragansett Rate C-06 ============================================================================================================================== NEC Rate H-1 Narragansett Rate C-06 H-1/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================== 1 Customer Charge: 36 $12.03 $433 36 $5.73 $206 2 Energy Charges: Distribution Energy 146,940 $0.03968 $5,831 146,940 $0.04559 $6,699 Transmission Energy $0.00273 $401 $0.00400 $588 Transition Energy $0.02340 $3,438 $0.02340 $3,438 Standard Offer $0.03800 $5,584 $0.03800 $5,584 DSM $0.00230 $338 $0.00230 $338 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $16,025 $16,853 4 Total Revenue Shift: $828 5 Revenue Shift by Function: Distribution Revenue $642 Transmission Revenue $187 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate H1 Narragansett Electric Range: Rate H1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 8 of 26 The Narragansett Electric Company Shifting NEC Rate H-1 to Narragansett Rate G-02 ============================================================================================================================== NEC Rate H-1 Narragansett Rate G-02 H-1/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ============================================================================================================================== 1 Customer Charge: 179 $12.03 $2,153 179 $103.41 $18,510 2 Demand Charge: Distribution Demand 7,866 $0.00 $0 7,866 $2.91 $22,890 Transmission Demand $1.40 $11,012 3 Energy Charges: Distribution Energy 3,203,948 $0.03968 $127,133 3,203,948 $0.01691 $54,179 Transmission Energy $0.00273 $8,747 ($0.00136) ($4,357) Transition Energy $0.02340 $74,972 $0.02340 $74,972 Standard Offer $0.03800 $121,750 $0.03800 $121,750 DSM $0.00230 $7,369 $0.00230 $7,369 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $342,124 $306,326 5 Total Revenue Shift: ($35,799) 6 Revenue Shift by Function: Distribution Revenue ($33,707) Transmission Revenue ($2,092) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate H1 Narragansett Electric Range: Rate H1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 9 of 26 The Narragansett Electric Company Shifting NEC Rate H-1 to Narragansett Rate G-32 =========================================================================================================================== NEC Rate H-1 Narragansett Rate G-32 H-1/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) =========================================================================================================================== 1 Customer Charge: 12 $12.03 $144 12 $236.43 $2,837 2 Demand Charge: Distribution Demand 5,202 $0.00 $0 5,202 $1.56 $8,115 Transmission Demand $1.27 $6,607 3 Energy Charges: Distribution Energy 1,557,600 $0.03968 $61,806 1,557,600 $0.01800 $28,037 Transmission Energy $0.00273 $4,252 ($0.00136) ($2,118) Transition Energy $0.02340 $36,448 $0.02340 $36,448 Standard Offer $0.03800 $59,189 $0.03800 $59,189 DSM $0.00230 $3,582 $0.00230 $3,582 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $165,421 $142,696 5 Total Revenue Shift: ($22,725) 6 Revenue Shift by Function: Distribution Revenue ($22,961) Transmission Revenue $236 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate H2 Narragansett Electric Range: Rate H2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 10 of 26 The Narragansett Electric Company Shifting NEC Rate H-2 to Narragansett Rate C-06 ================================================================================================================================== NEC Rate H-2 Narragansett Rate C-06 H-2/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 3,752 $4.59 $17,222 3,752 $0.00 $0 2 Energy Charges: Distribution Energy 4,457,199 $0.04681 $208,641 4,457,199 $0.04559 $203,204 Transmission Energy $0.00273 $12,168 $0.00400 $17,829 Transition Energy $0.02340 $104,298 $0.02340 $104,298 Standard Offer $0.03800 $169,374 $0.03800 $169,374 DSM $0.00230 $10,252 $0.00230 $10,252 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $521,955 $504,956 4 Total Revenue Shift: ($16,999) 5 Revenue Shift by Function: Distribution Revenue ($22,659) Transmission Revenue $5,661 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate H2 Narragansett Electric Range: Rate H2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 11 of 26 The Narragansett Electric Company Shifting NEC Rate H-2 to Narragansett Rate G-02 ================================================================================================================================== NEC Rate H-2 Narragansett Rate G-02 H-2/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 113 $4.59 $519 113 $0.00 $0 2 Demand Charge: Distribution Demand 5,208 $0.00 $0 5,208 $2.91 $15,156 Transmission Demand $1.40 $7,292 3 Energy Charges: Distribution Energy 1,266,751 $0.04681 $59,297 1,266,751 $0.01691 $21,421 Transmission Energy $0.00273 $3,458 ($0.00136) ($1,723) Transition Energy $0.02340 $29,642 $0.02340 $29,642 Standard Offer $0.03800 $48,137 $0.03800 $48,137 DSM $0.00230 $2,914 $0.00230 $2,914 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $143,966 $122,838 5 Total Revenue Shift: ($21,127) 6 Revenue Shift by Function: Distribution Revenue ($23,238) Transmission Revenue $2,111 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate H2 Narragansett Electric Range: Rate G1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 12 of 26 The Narragansett Electric Company Shifting NEC Rate G-1 to Narragansett Rate C-06 ================================================================================================================================== NEC Rate H-2 Narragansett Rate C-06 G-1/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: Customer Charge 48,861 $3.45 $168,570 47,123 $5.73 $270,015 Unmetered Charge 1,738 $1.83 $3,181 2 Energy Charges: Distribution Energy 42,449,011 $0.05832 $2,475,626 42,449,011 $0.04559 $1,935,250 Transmission Energy $0.00273 $115,886 $0.00400 $169,796 Transition Energy $0.02340 $993,307 $0.03800 $993,307 Standard Offer $0.03800 $1,613,062 $0.03800 $1,613,062 DSM $0.00230 $97,633 $0.00230 $97,633 Renewables $0.00000 $0 $0.00000 $0 3 Total Revenue before GET: $5,464,085 $5,082,244 4 Total Revenue Shift: ($381,841) 5 Revenue Shift by Function: Distribution Revenue ($435,751) Transmission Revenue $53,910 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate G2 Narragansett Electric Range: Rate G2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 13 of 26 The Narragansett Electric Company Shifting NEC Rate G-2 to Narragansett Rate C-06 ================================================================================================================================== NEC Rate G-2 Narragansett Rate C-06 G-2/C-06 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 1,272 $0.00 $0 1,272 $5.73 $7,289 2 Demand Charge: Distribution Demand 29,206 $1.60 $46,730 0 $0.00 $0 Transmission Demand $0.00 $0 $0.00 $0 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 6,707,011 $0.03443 $230,922 6,707,011 $0.04559 $305,773 Transmission Energy $0.00273 $18,310 $0.00400 $26,828 Transition Energy $0.02340 $156,944 $0.02340 $156,944 Standard Offer $0.03800 $254,866 $0.03800 $254,866 DSM $0.00230 $15,426 $0.00230 $15,426 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $723,199 $767,126 5 Total Revenue Shift: $43,927 6 Revenue Shift by Function: Distribution Revenue $35,409 Transmission Revenue $8,518 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate G2 Narragansett Electric Range: Rate G2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 14 of 26 The Narragansett Electric Company Shifting NEC Rate G-2 to Narragansett Rate G-02 ================================================================================================================================== NEC Rate G-2 Narragansett Rate G-02 G-2/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 6,226 $0.00 $0 6,226 $103.41 $643,831 2 Demand Charge: Distribution Demand 255,636 $1.60 $409,018 213,521 $2.91 $621,346 Transmission Demand $0.00 $0 $1.40 $298,929 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 85,631,955 $0.03443 $2,948,308 85,631,955 $0.01691 $1,448,036 Transmission Energy $0.00273 $233,775 ($0.00136) ($116,459) Transition Energy $0.02340 $2,003,788 $0.02340 $2,003,788 Standard Offer $0.03800 $3,254,014 $0.03800 $3,254,014 DSM $0.00230 $196,953 $0.00230 $196,953 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $9,045,857 $8,350,439 5 Total Revenue Shift: ($695,418) 6 Revenue Shift by Function: Distribution Revenue ($644,113) Transmission Revenue ($51,305) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate G2 Narragansett Electric Range: Rate G2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 15 of 26 The Narragansett Electric Company Shifting NEC Rate G-2 to Narragansett Rate G-32 ================================================================================================================================== NEC Rate G-2 Narragansett Rate G-32 G-2/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 147 $0.00 $0 147 $236.43 $34,755 2 Demand Charge: Distribution Demand 36,878 $1.60 $59,005 43,326 $1.56 $67,589 Transmission Demand $0.00 $0 $1.27 $55,024 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 12,741,620 $0.03443 $438,694 12,741,620 $0.01800 $229,349 Transmission Energy $0.00273 $34,785 ($0.00136) ($17,329) Transition Energy $0.02340 $298,154 $0.02340 $298,154 Standard Offer $0.03800 $484,182 $0.03800 $484,182 DSM $0.00230 $29,306 $0.00230 $29,306 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $1,344,125 $1,181,030 5 Total Revenue Shift: ($163,095) 6 Revenue Shift by Function: Distribution Revenue ($166,006) Transmission Revenue $2,911 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate T2 Narragansett Electric Range: Rate T2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 16 of 26 The Narragansett Electric Company Shifting NEC Rate T-2 to Narragansett Rate G-02 ================================================================================================================================== NEC Rate T-2 Narragansett Rate G-02 T-2/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 84 $0.00 $0 84 $103.41 $8,686 2 Demand Charge: Distribution Demand 11,103 $1.60 $17,765 10,263 $2.91 $29,865 Transmission Demand $0.00 $0 $1.40 $14,368 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 4,675,660 $0.03443 $160,983 4,675,660 $0.01691 $79,065 Transmission Energy $0.00273 $12,765 ($0.00136) ($6,359) Transition Energy $0.02340 $109,410 $0.02340 $109,410 Standard Offer On Peak 862,640 $0.03800 $32,780 $0.03800 $177,675 Standard Offer Off Peak 3,813,020 $0.03800 $144,895 DSM $0.00230 $10,754 $0.00230 $10,754 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $489,352 $423,466 5 Total Revenue Shift: ($65,886) 6 Revenue Shift by Function: Distribution Revenue ($61,131) Transmission Revenue ($4,755) Transition Revenue $0 Standard Offer Revenue ($0) DSM $0
File: C:\JMM\[workjmm3.wk4]Rate T2 Narragansett Electric Range: Rate T2 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 17 of 26 The Narragansett Electric Company Shifting NEC Rate T-2 to Narragansett Rate G-32 ================================================================================================================================== NEC Rate T-2 Narragansett Rate G-32 T-2/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 72 $0.00 $0 72 $236.43 $17,023 2 Demand Charge: Distribution Demand 19,224 $1.60 $30,758 20,900 $1.56 $32,604 Transmission Demand $0.00 $0 $1.27 $26,543 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 9,686,300 $0.03443 $333,499 9,686,300 $0.01800 $174,353 Transmission Energy $0.00273 $26,444 ($0.00136) ($13,173) Transition Energy $0.02340 $226,659 $0.02340 $226,659 Standard Offer On Peak 1,818,780 $0.03800 $69,114 $0.03800 $368,079 Standard Offer Off Peak 7,867,520 $0.03800 $298,966 DSM $0.00230 $22,278 $0.00230 $22,278 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $1,007,719 $854,367 5 Total Revenue Shift: ($153,351) 6 Revenue Shift by Function: Distribution Revenue ($140,277) Transmission Revenue ($13,074) Transition Revenue ($0) Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate T4 Narragansett Electric Range: Rate T4 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 18 of 26 The Narragansett Electric Company Shifting NEC Rate T-4 to Narragansett Rate G-32 ================================================================================================================================== NEC Rate T-4 Narragansett Rate G-32 T-4/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 69 $0.00 $0 69 $236.43 $16,314 2 Demand Charge: Distribution Demand 41,467 $1.95 $80,861 57,333 $1.56 $89,439 Transmission Demand $0.00 $0 $1.27 $72,813 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 18,430,440 $0.03517 $648,199 18,430,440 $0.01800 $331,748 Transmission Energy $0.00273 $50,315 ($0.00136) ($25,065) Transition Energy $0.02340 $431,272 $0.02340 $431,272 Standard Offer On Peak 3,531,400 $0.03800 $134,193 $0.03800 $700,357 Standard Offer Off Peak 14,899,040 $0.03800 $566,164 DSM $0.00230 $42,390 $0.00230 $42,390 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $1,953,393 $1,659,268 5 Total Revenue Shift: ($294,126) 6 Revenue Shift by Function: Distribution Revenue ($291,558) Transmission Revenue ($2,568) Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate T5 Narragansett Electric Range: Rate T5 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 19 of 26 The Narragansett Electric Company Shifting NEC Rate T-5 to Narragansett Rate G-32 ================================================================================================================================== NEC Rate T-5 Narragansett Rate G-32 T-5/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 12 $0.00 $0 12 $236.43 $2,837 2 Demand Charge: Distribution Demand 5,375 $1.76 $9,460 5,375 $1.56 $8,385 Transmission Demand $0.00 $0 $1.27 $6,826 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 2,964,000 $0.02948 $87,379 2,964,000 $0.01800 $53,352 Transmission Energy $0.00273 $8,092 ($0.00136) ($4,031) Transition Energy $0.02340 $69,358 $0.02340 $69,358 Standard Offer On Peak 531,000 $0.03800 $20,178 $0.03800 $112,632 Standard Offer Off Peak 2,433,000 $0.03800 $92,454 DSM $0.00230 $6,817 $0.00230 $6,817 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 5,375 ($0.37) ($1,989) Primary Metering $256,176 -1% ($2,562) 4 Total Revenue before GET: $293,737 $251,626 5 Total Revenue Shift: ($42,112) 6 Revenue Shift by Function: Distribution Revenue ($35,593) Transmission Revenue ($5,324) Transition Revenue $0 Standard Offer Revenue ($1,126) DSM ($68)
File: C:\JMM\[workjmm3.wk4]Rate G5 Narragansett Electric Range: Rate G5 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 20 of 26 The Narragansett Electric Company Shifting NEC Rate G-5 to Narragansett Rate G-02 ================================================================================================================================== NEC Rate G-5 Narragansett Rate G-02 G-5/G-02 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 158 $0.00 $0 158 $103.41 $16,339 2 Demand Charge: Distribution Demand 12,834 $1.76 $22,588 14,847 $2.91 $43,205 Transmission Demand $0.00 $0 $1.40 $20,786 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 4,061,340 $0.02948 $119,728 4,061,340 $0.01691 $68,677 Transmission Energy $0.00273 $11,087 ($0.00136) ($5,523) Transition Energy $0.02340 $95,035 $0.02340 $95,035 Standard Offer 4,061,340 $0.03800 $154,331 $0.03800 $154,331 DSM $0.00230 $9,341 $0.00230 $9,341 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 14,847 ($0.37) ($5,493) Primary Metering $402,191 -1% ($4,022) 4 Total Revenue before GET: $412,111 $392,675 5 Total Revenue Shift: ($19,436) 6 Revenue Shift by Function: Distribution Revenue ($21,821) Transmission Revenue $4,022 Transition Revenue $0 Standard Offer Revenue ($1,543) DSM ($93)
File: C:\JMM\[workjmm3.wk4]Rate G5 Narragansett Electric Range: Rate G5 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 21 of 26 The Narragansett Electric Company Shifting NEC Rate G-5 to Narragansett Rate G-32 ================================================================================================================================== NEC Rate G-5 Narragansett Rate G-32 G-5/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 83 $0.00 $0 83 $236.43 $19,624 2 Demand Charge: Distribution Demand 27,527 $1.76 $48,448 29,984 $1.56 $46,775 Transmission Demand $0.00 $0 $1.27 $38,080 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 11,014,249 $0.02948 $324,700 11,014,249 $0.01800 $198,256 Transmission Energy $0.00273 $30,069 ($0.00136) ($14,979) Transition Energy $0.02340 $257,733 $0.02340 $257,733 Standard Offer 11,014,249 $0.03800 $418,541 $0.03800 $418,541 DSM $0.00230 $25,333 $0.00230 $25,333 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 29,984 ($0.37) ($11,094) Primary Metering $989,363 -1% ($9,894) 4 Total Revenue before GET: $1,104,824 $968,375 5 Total Revenue Shift: ($136,449) 6 Revenue Shift by Function: Distribution Revenue ($124,810) Transmission Revenue ($7,200) Transition Revenue $0 Standard Offer Revenue ($4,185) DSM ($253)
File: C:\JMM\[workjmm3.wk4]Rate T6 Narragansett Electric Range: Rate T6 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 22 of 26 The Narragansett Electric Company Shifting NEC Rate T-6 to Narragansett Rate G-32 ================================================================================================================================== NEC Rate T-6 Narragansett Rate G-32 T-6/G-32 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 12 $0.00 $0 12 $236.43 $2,837 2 Demand Charge: Distribution Demand 14,305 $1.76 $25,177 15,820 $1.56 $24,679 Transmission Demand $0.00 $0 $1.27 $20,091 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 6,958,000 $0.02993 $208,253 6,958,000 $0.01800 $125,244 Transmission Energy $0.00273 $18,995 ($0.00136) ($9,463) Transition Energy $0.02340 $162,817 $0.02340 $162,817 Standard Offer On Peak 1,417,000 $0.03800 $53,846 $0.03800 $264,404 Standard Offer Off Peak 5,541,000 $0.03800 $210,558 DSM $0.00230 $16,003 $0.00230 $16,003 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 15,820 ($0.37) ($5,853) Primary Metering $606,613 -1% ($6,066) 4 Total Revenue before GET: $695,650 $594,694 5 Total Revenue Shift: ($100,956) 6 Revenue Shift by Function: Distribution Revenue ($89,679) Transmission Revenue ($8,473) Transition Revenue $0 Standard Offer Revenue ($2,644) DSM ($160)
File: C:\JMM\[workjmm3.wk4]Rate T6 Narragansett Electric Range: Rate T6 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 23 of 26 The Narragansett Electric Company Shifting NEC Rate T-6 to Narragansett Rate G-62 ================================================================================================================================== NEC Rate T-6 Narragansett Rate G-62 T-6/G-62 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 12 $0.00 $0 12 $17,118.72 $205,425 2 Demand Charge: Distribution Demand 35,977 $1.76 $63,320 36,233 $0.75 $27,175 Transmission Demand $0.00 $0 $1.39 $50,364 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 17,589,599 $0.02993 $526,457 17,589,599 $0.01095 $192,606 Transmission Energy $0.00273 $48,020 ($0.00136) ($23,922) Transition Energy $0.02340 $411,597 $0.02340 $411,597 Standard Offer On Peak 3,754,799 $0.03800 $142,682 $0.03800 $668,405 Standard Offer Off Peak 13,834,800 $0.03800 $525,722 DSM $0.00230 $40,456 $0.00230 $40,456 Renewables $0.00000 $0 $0.00000 $0 4. High Voltage Credits Transformer Ownership 36,233 ($0.37) ($13,406) Primary Metering $1,572,105 -1% ($15,721) 4 Total Revenue before GET: $1,758,253 $1,542,978 5 Total Revenue Shift: ($215,276) 6 Revenue Shift by Function: Distribution Revenue ($186,345) Transmission Revenue ($21,842) Transition Revenue $0 Standard Offer Revenue ($6,684) DSM ($405)
File: C:\JMM\[workjmm3.wk4]Rate C1 Narragansett Electric Range: Rate C1 BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 24 of 26 The Narragansett Electric Company Shifting NEC Rate C-1 to Narragansett Rate N-01 ================================================================================================================================== NEC Rate C-1 Narragansett Rate N-01 C-1/N-01 Units Rate Revenues Units Rate Revenues (1) (2) (3) (4) (5) (6) ================================================================================================================================== 1 Customer Charge: 12 $0.00 $0 12 $0.00 $0 2 Demand Charge: Distribution Demand 212,968 $7.68 $1,635,594 212,968 $6.60 $1,405,589 Transmission Demand $0.00 $0 $0.00 $0 Standard Offer $0.00 $0 3 Energy Charges: Distribution Energy 114,919,292 $0.00851 $977,963 114,919,292 $0.00731 $840,060 Transmission Energy $0.00273 $313,730 $0.00273 $313,730 Transition Energy $0.02340 $2,689,111 $0.02340 $2,689,111 Standard Offer On Peak 23,608,292 $0.03800 $897,115 $0.03800 $4,366,933 Standard Offer Off Peak 91,311,000 $0.03800 $3,469,818 DSM $0.00230 $264,314 $0.00230 $264,314 Renewables $0.00000 $0 $0.00000 $0 4 Total Revenue before GET: $10,247,646 $9,879,737 5 Total Revenue Shift: ($367,909) 6 Revenue Shift by Function: Distribution Revenue ($367,909) Transmission Revenue $0 Transition Revenue $0 Standard Offer Revenue $0 DSM $0
File: C:\JMM\[workjmm3.wk4]Rate C1 Narragansett Electric Range: NEC BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 25 of 26 The Narragansett Electric Company Shifting NEC Rate S-1 to Narragansett Rate S-14 Total Standard Number Annual Annual Annual Distribution Transmission Transition Offer DSM Total of Units kWh Price kWh Sale Revenues Revenues Revenues Revenues Revenues Revenues Overhead $0.00273 $0.02340 $0.03800 $0.00230 Sodium Vapor Lamp Existing or Prepaid Wood Poles 5800 Streetlight 651 334 $53.46 217,434 $34,802 $594 $5,088 $8,262 $500 $49,247 5800 Flood 41 334 $62.46 13,694 $2,561 $37 $320 $520 $31 $3,471 9500 Streetlight 7 476 $60.43 3,332 $423 $9 $78 $127 $8 $644 25000 Streetlight 189 1,274 $103.46 240,786 $19,554 $657 $5,634 $9,150 $554 $35,549 25000 Flood 275 1,274 $107.55 350,350 $29,576 $956 $8,198 $13,806 $806 $52,850 50000 Streetlight 12 1,966 $144.74 23,592 $1,737 $64 $552 $896 $54 $3,304 50000 Flood 353 1,966 $144.25 693,998 $50,920 $1,895 $16,240 $26,372 $1,596 $97,023 Lighting only Wood Poles 5800 Streetlight 32 334 $123.20 10,688 $3,942 $29 $250 $406 $25 $4,652 25000 Streetlight 6 1,274 $173.20 7,644 $1,039 $21 $179 $290 $18 $1,547 25000 Flood 27 1,274 $177.28 34,398 $4,787 $94 $805 $1,307 $79 $7,072 50000 Streetlight 2 1,966 $214.48 3,932 $429 $11 $92 $149 $9 $690 50000 Flood 50 1,966 $215.91 98,300 $10,796 $268 $2,300 $3,735 $226 $17,326 Mercury Vapor Lamp Existing or Prepaid Wood Poles 4200 Streetlight 2525 511 $50.98 1,290,275 $128,725 $3,522 $30,192 $49,030 $2,968 $214,437 8600 Streetlight 47 822 $60.92 38,634 $2,863 $105 $904 $1,468 $89 $5,430 12100 Streetlight 24 1,180 $77.08 28,320 $1,850 $77 $663 $1,076 $65 $3,731 22500 Streetlight 377 1,864 $98.98 702,728 $37,315 $1,918 $16,444 $26,704 $1,616 $83,998 22500 Flood 111 1,864 $100.38 206,904 $11,142 $565 $4,842 $7,862 $476 $24,887 63000 Flood 37 4,463 $195.06 165,131 $7,217 $451 $3,864 $6,275 $380 $18,187 Lighting only Wood Poles 4200 Streetlight 74 511 $110.86 37,814 $8,204 $103 $885 $1,437 $87 $10,716 22500 Streetlight 34 1,864 $158.85 63,376 $5,401 $173 $1,483 $2,408 $146 $9,611 22500 Flood 32 1,864 $160.26 59,648 $5,128 $163 $1,396 $2,267 $137 $9,091 63000 Flood 9 4,463 $254.94 40,167 $2,294 $110 $940 $1,526 $92 $4,963 Incandescent Existing or Prepaid Standard Metal Poles 1000 Streetlight 383 362 $22.57 138,646 $8,644 $379 $3,244 $5,269 $319 $17,855 2500 Flood 64 743 $19.46 47,552 $1,245 $130 $1,113 $1,807 $109 $4,404 Metal Halide Lamp Existing or Prepaid Wood Poles 20000 Flood 5 1,180 $129.45 5,900 $647 $16 $138 $224 $14 $1,039 40000 Flood 6 1,832 $168.76 10,992 $1,013 $30 $257 $418 $25 $1,743 115000 Flood 37 4,247 $216.90 157,139 $8,025 $429 $3,677 $5,971 $361 $18,464 Total Overhead 5,410 4,691,374 $390,281 $12,807 $109,778 $178,272 $10,790 $701,929 Total Standard Annual Annual Annual Distribution Transmission Transition Offer DSM Total kWh Price kWh Sale Revenues Revenues Revenues Revenue Revenues Revenues Overhead ($0.01861) $0.00123 $0.02340 $0.0380 $0.00230 Sodium Vapor Lamp Existing or Prepaid Wood Poles 5800 Streetlight 349 $66.28 227,199 $38,920 $279 $5,316 $8,634 $523 $53,672 5800 Flood 349 $66.28 14,309 $2,451 $18 $335 $544 $33 $3,380 9500 Streetlight 490 $72.63 3,430 $445 $4 $80 $130 $8 $667 25000 Streetlight 1284 $120.39 242,676 $18,238 $298 $5,679 $9,222 $558 $33,994 25000 Flood 1284 $143.14 353,100 $32,792 $434 $8,263 $13,418 $812 $55,719 50000 Streetlight 1968 $163.46 23,616 $1,522 $29 $553 $897 $54 $3,055 50000 Flood 1968 $181.37 694,704 $51,095 $854 $16,256 $26,399 $1,598 $96,202 Lighting only Wood Poles 5800 Streetlight 349 $121.73 11,168 $3,688 $14 $261 $424 $26 $4,413 25000 Streetlight 1284 $175.84 7,704 $912 $9 $180 $293 $18 $1,412 25000 Flood 1284 $198.59 34,668 $4,717 $43 $811 $1,317 $80 $6,968 50000 Streetlight 1968 $218.91 3,936 $365 $5 $92 $150 $9 $620 50000 Flood 1968 $236.82 98,400 $10,010 $121 $2,303 $3,739 $226 $16,399 Mercury Vapor Lamp Existing or Prepaid Wood Poles 4200 Streetlight 561 $54.40 1,416,525 $110,998 $1,742 $33,147 $53,828 $3,258 $202,973 8600 Streetlight 908 $70.77 42,676 $2,532 $52 $999 $1,622 $98 $5,303 12100 Streetlight 908 $70.77 21,792 $1,293 $27 $510 $828 $50 $2,708 22500 Streetlight 1897 $122.31 715,169 $32,802 $880 $16,735 $27,176 $1,645 $79,237 22500 Flood 1897 $152.08 210,567 $12,962 $259 $4,927 $8,002 $484 $26,634 63000 Flood 4569 $262.72 169,053 $6,575 $208 $3,956 $6,424 $389 $17,551 Lighting only Wood Poles 4200 Streetlight 561 $109.85 41,514 $7,356 $51 $971 $1,578 $95 $10,052 22500 Streetlight 1897 $177.76 64,498 $4,844 $79 $1,509 $2,451 $148 $9,031 22500 Flood 1897 $207.53 60,704 $5,511 $75 $1,420 $2,307 $140 $9,453 63000 Flood 4569 $318.17 41,121 $2,098 $51 $962 $1,563 $95 $4,768 Incandescent Existing or Prepaid Standard Metal Poles 1000 Streetlight 440 $75.22 168,520 $25,673 $207 $3,943 $6,404 $388 $36,615 2500 Flood 845 $67.45 54,080 $3,310 $67 $1,265 $2,055 $124 $6,822 Metal Halide Lamp Existing or Prepaid Wood Poles 20000 Flood 1284 $143.14 6,420 $596 $8 $150 $244 $15 $1,013 40000 Flood 1968 $181.37 11,808 $868 $15 $276 $449 $27 $1,635 115000 Flood 1968 $181.37 72,816 $5,356 $90 $1,704 $2,767 $167 $10,084 Total Overhead 4,812,173 $387,928 $5,919 $112,605 $182,863 $11,068 $700,382
File: C:\JMM\[workjmm3.wk4]Rate C1 Narragansett Electric Range: NEC BVE/Newport Electric Date: 14-May-99 R.I.P.U.C. Docket No. _______ Workpaper JMM - 3 Page 26 of 26 The Narragansett Electric Company Shifting NEC Rate S-1 to Narragansett Rate S-14 Total Standard Number Annual Annual Annual Distribution Transmision Transition Offer DSM Total of Units kWh Price kWh Sales Revenues Revenues Revenues Revenues Revenues Revenues Underground $0.00273 $0.02340 $0.03800 $0.00230 Sodium Vapor Lamp Existing or Prepaid Standard Metal Poles 5800 Streetlight 8 334 $60.8 2,672 $487 $7 $63 $102 $6 $665 25000 Streetlight 12 1,274 $110.89 15,288 $1,331 $42 $358 $581 $35 $2,346 25000 Flood 1 1,274 $115.74 1,274 $116 $3 $30 $48 $3 $200 50000 Flood 1 1,966 $152.43 1,966 $152 $5 $46 $75 $5 $283 Lighting only Standard Metal Poles 5800 Streetlight 14 334 $161.51 4,676 $2,261 $13 $109 $178 $11 $2,572 Existing or Prepaid Poles less than 15 ft. 5800 T&C 247 334 $54.12 82,498 $13,368 $225 $1,930 $3,135 $190 $18,848 Existing or Prepaid Wood Poles 5800 Streetlight 78 334 $56.99 26,052 $4,445 $71 $610 $990 $60 $6,176 25000 Streetlight 24 1,274 $106.98 30,576 $2,568 $83 $715 $1,162 $70 $4,599 50000 Streetlight-Twin 12 3,932 $276.25 47,184 $3,315 $129 $1,104 $1,793 $109 $6,449 Lighting only Wood Poles 25000 Flood 1 1,274 $171.14 1,274 $171 $3 $30 $48 $3 $256 Mercury Vapor Lamp Existing or Prepaid Standard Metal Poles 22500 Flood 6 1,864 $103.41 11,184 $620 $31 $262 $425 $26 $1,363 Lighting only Standard Metal Poles 4200 Streetlight 2 511 $143.76 1,022 $288 $3 $24 $39 $2 $355 22500 Streetlight 16 1,864 $191.74 29,824 $3,068 $81 $698 $1,133 $69 $5,049 22500 Streetlight-Twin 3 3,728 $278.38 11,184 $835 $31 $262 $425 $26 $1,578 Existing or Prepaid Wood Poles 4200 Streetlight 27 51 $54.01 13,797 $1,458 $38 $323 $524 $32 $2,375 22500 Streetlight 1 1,864 $102.00 1,864 $102 $5 $44 $71 $4 $226 Lighting only Wood Poles 4200 Streetlight 55 511 $105.59 28,105 $5,807 $77 $658 $1,068 $65 $7,674 8600 Streetlight 13 822 $115.53 10,686 $1,502 $29 $250 $406 $25 $2,212 12100 Streetlight 19 1,180 $136.93 22,420 $2,602 $61 $525 $852 $52 $4,091 12100 Streetlight-Twin 6 2,359 $186.86 14,154 $1,121 $39 $331 $538 $33 $2,061 22500 Streetlight 231 1,864 $153.58 430,584 $35,477 $1,175 $10,076 $16,362 $990 $64,081 22500 Streetlight-Twin 26 3,728 $235.30 96,928 $6,118 $265 $2,268 $3,683 $223 $12,557 63000 Streetlight 7 4,463 $245.38 31,241 $1,718 $85 $731 $1,187 $72 $3,793 Existing or Prepaid Poles less than 15 ft. 4200 T&C 14 511 $54.54 7,154 $764 $20 $167 $272 $16 $1,239 Total Underground 824 923,607 $89,693 $2,521 $21,612 $35,097 $2,124 $151,048 Total Overhead and Underground 6,234 5,614,981 $479,974 $15,329 $131,391 $213,369 $12,914 $852,977 Total Standard Annual Annual Annual Distribution Transmission Transition Offer DSM Total kWh Price kWh Sales Revenues Revenues Revenues Revenues Revenues Revenues Underground ($0.01861) $0.00123 $0.02340 $0.0380 $0.00230 Sodium Vapor Lamp Existing or Prepaid Standard Metal Poles 5800 Streetlight 349 $66.28 2,792 $478 $3 $65 $106 $6 $660 25000 Streetlight 1284 $120.39 15,408 $1,158 $19 $361 $586 $35 $2,158 25000 Flood 1284 $143.14 1,284 $119 $2 $30 $49 $3 $203 50000 Flood 1968 $181.37 1,968 $145 $2 $46 $75 $5 $273 Lighting only Standard Metal Poles 5800 Streetlight 349 $319.65 4,886 $4,384 $6 $114 $186 $11 $4,701 Existing or Prepaid Poles less than 15 ft. 5800 T&C 349 $66.28 86,203 $14,767 $106 $2,017 $3,276 $198 $20,364 Existing or Prepaid Wood Poles 5800 Streetlight 349 $66.28 27,222 $4,663 $33 $637 $1,034 $63 $6,431 25000 Streetlight 1284 $120.39 30,816 $2,316 $38 $721 $1,171 $71 $4,317 50000 Streetlight-Twin 3936 $326.92 47,232 $3,044 $58 $1,105 $1,795 $109 $6,111 Lighting only Wood Poles 25000 Flood 1284 $198.59 1,284 $175 $2 $30 $49 $3 $258 Mercury Vapor Lamp Existing or Prepaid Standard Metal Poles 22500 Flood 1897 $152.08 11,382 $701 $14 $266 $433 $26 $1,440 Lighting only Standard Metal Poles 4200 Streetlight 561 $311.77 1,122 $603 $1 $26 $43 $3 $676 22500 Streetlight 1897 $375.68 30,352 $5,446 $37 $710 $1,153 $70 $7,417 22500 Streetlight-Twin 3794 $497.99 11,382 $1,282 $14 $266 $433 $26 $2,021 Existing or Prepaid Wood Poles 4200 Streetlight 561 $58.40 15,147 $1,295 $19 $354 $576 $35 $2,278 22500 Streetlight 1897 $122.31 1,897 $87 $2 $44 $72 $4 $210 Lighting only Wood Poles 4200 Streetlight 561 $113.85 30,855 $5,688 $38 $722 $1,172 $71 $7,691 8600 Streetlight 908 $126.22 11,804 $1,421 $15 $276 $449 $27 $2,188 12100 Streetlight 908 $126.22 17,252 $2,077 $21 $404 $656 $40 $3,197 12100 Streetlight-Twin 1816 $196.99 10,896 $979 $13 $255 $414 $25 $1,687 22500 Streetlight 1897 $177.76 438,207 $32,908 $539 $10,254 $16,652 $1,008 $61,360 22500 Streetlight-Twin 3794 $300.07 98,644 $5,966 $121 $2,308 $3,748 $227 $12,371 63000 Streetlight 4569 $318.17 31,983 $1,632 $39 $748 $1,215 $74 $3,709 Existing or Prepaid Poles less than 15 ft. 4200 T&C 561 $58.40 7,854 $671 $10 $184 $298 $18 $1,181 Total Underground 937,872 $92,005 $1,154 $21,946 $35,639 $2,157 $152,901 Total Overhead and Underground 5,750,045 $479,933 $7,073 $134,551 $218,502 $13,225 $853,283
C:\JMM\[workjmm4.wk4]A Narragansett Electric Range: BVE/Newport Electric R.I.P.U.C. Docket No. _______ Workpaper JMM - 4 Workpaper JMM-4 Transmission Back-up
C:\JMM\[workjmm4.wk4]A Narragansett Electric Range: BVE/Newport Electric R.I.P.U.C. Docket No. _______ Workpaper JMM - 4 Page 1 of 1 The Narragansett Electric Company Calculation of Projected Transmission Expenses (based on 1998 actual expenses and coincident peak data) Narragansett Blackstone Newport 1 NEP Tariff No. 9 Expenses $17,271,638 $2,584,364 $1,081,211 2 NEPOOL Tariff No. 1 $5,947,067 $1,015,660 $401,812 3 Total Transmission Expenses $23,218,705 $3,600,024 $1,483,023 1 FERC Docket ER99-2832-000, Exhibit ____ (PAV-2), Statement BH 2 Average 1998 12 Month Coincident Peak Load * NEPOOL Rate in effect during Year 2 of transition CP Load NEPOOL Rate NEPOOL Charges Narragansett Electric 838,570 $7.02 $5,883,405 New England Power for Narragansett 13,792 $4.62 $ 63,662 Blackstone Valley Electric 220,030 $4.62 $1,015,660 Newport Electric 87,048 $4.62 $ 401,812 3 line (1) + Line (2)
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - ------------------------------------------------ ) Narragansett Electric Company ) R.I.P.U.C. No.________ Blackstone Valley Electric Company ) Newport Electric Corporation ) ) - ------------------------------------------------ DIRECT TESTIMONY OF JAMES J. BONNER., JR. THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILITIES COMMISSION - ------------------------------------------------ ) Narragansett Electric Company ) R.I.P.U.C. No.________ Blackstone Valley Electric Company ) Newport Electric Corporation ) ) - ------------------------------------------------ DIRECT TESTIMONY OF JAMES J. BONNER., JR. Table of Contents I. Introduction and Qualifications.................................... 1 II. Purpose of Testimony............................................... 3 III. Mapping of Blackstone/Newport's Customers to Narragansett's Rates............................................... 4 IV. Derivation of Billing Determinants for Blackstone/Newport's Customers Under Narragansett's Rates............................... 16
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 1 of 22 1 I. Introduction and Qualifications 2 Q. Please state your full name and business address. 3 A. My name is James J. Bonner, Jr. My business address is 750 West Center Street, West 4 Bridgewater, Massachusetts. 5 6 Q. Please state your present position and responsibilities. 7 A. I am Manager of Retail Pricing and Rate Administration for EUA Service Corporation. 8 My responsibilities include the direct supervision of EUA Service Corporation's Retail 9 Pricing and Rate Administration supervisor and staff. Among the responsibilities of that 10 staff are the study, analysis, and design of retail delivery electric service rates for 11 Blackstone Valley Electric Company ("Blackstone") and Newport Electric Corporation 12 ("Newport") (collectively "Blackstone/Newport"). 13 14 Q. Please describe your educational background and work experience. 15 A. I graduated from Northeastern University in 1976 with a Bachelor of Science degree in 16 Electrical Engineering (Power Systems). I attended the Edison Electric Institute's ("EEI") 17 Rate Fundamentals Course at Indiana University in November 1995 and the EEI 18 Advanced Rate Course at Indiana University in August 1986 and in August 1988. I was 19 Chairman of the Electric Council of New England's Rate and Regulatory Committee from 1993 20 through 1995. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 2 of 22 1 From August 1976 through February 1983, I was employed by the Belcher Division of 2 Dayton Malleable Inc., a malleable iron foundry located in Easton, Massachusetts, as Plant 3 Engineer. My duties included plant maintenance management, energy management, 4 capital budgeting, and production engineering. 5 6 In March 1983, I joined Eastern Edison Company ("Eastern") as Consumer Service 7 Engineer for the Brockton Division. In that capacity, I served as Eastern's representative 8 for its fifty largest commercial-industrial customers in the Brockton Division's service area 9 and as a staff assistant to the Consumer Service Manager. 10 11 I transferred to the Rate Department of EUA Service Corporation in February 1985 as an 12 Associate Rate Engineer, I was promoted to Rate Engineer in February 1987, to Senior 13 Rate Engineer in February 1989, to Supervisor of Rate Design in January 1991, and to 14 Manager of Retail Pricing and Rate Administration in January 1999. 15 16 Since assuming the position of Supervisor of Rate Design in 1991, I have supervised the 17 preparation of Blackstone/Newport's retail rates approved by the Commission in 18 subsequent regulatory proceedings. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 3 of 22 1 Q. Have you previously testified before the Commission? 2 A. Yes, I have testified before the Commission on numerous occasions. Most recently, I 3 testified in support of Blackstone/Newport's proposed Standard Offer Service tariffs in 4 Docket No. 2716 in May 1998. 5 6 Q. Were the schedules attached to your direct testimony prepared by you or under your 7 supervision and direction? 8 A. Yes, they were. 9 10 II. Purpose of Testimony 11 Q. What is the purpose of your testimony? 12 A. The purpose of my testimony is to present and support the mapping of 13 Blackstone/Newport's customers under Blackstone/Newport's rates to Narragansett 14 Electric Company's ("Narragansett's") rates and the derivation of the billing determinants 15 for Blackstone/Newport's customers mapped to Narragansett's rates. Mr. Molloy makes 16 use of this mapping and these billing determinants in his testimony and exhibits regarding 17 the Narragansett/Blackstone/Newport merger rate plan. 18 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 4 of 22 1 Q. Please explain how you have organized your testimony. 2 A. My testimony is organized as follows: (1) An explanation of the mapping process used to 3 cross match the schedule of rates between Blackstone/Newport and Narragansett, and (2) 4 an explanation of the derivation of the billing determinants used for transferring 5 Blackstone/Newport's customers to Narragansett's rates. 6 7 III. Mapping of Blackstone/Newport's Customers to Narragansett's Rates 8 Q. Please describe how Blackstone/Newport's customers were mapped to Narragansett's 9 rates. 10 A. A mapping of Blackstone/Newport's current rates to Narragansett's current rates was 11 performed by cross matching the availability provisions of Blackstone/Newport's rates and 12 Narragansett's rates. Exhibit JJB-1 and Exhibit JJB-2 show comparisons of the availability 13 provisions of Blackstone/Newport's and Narragansett's rates. Mr. Molloy in his Exhibit 14 JMM-2 provides a summary of the cross matching of Blackstone/Newport's rates to 15 Narragansett's. 16 17 Although Blackstone/Newport's schedule of rates is roughly comparable to Narragansett's 18 schedule of rates, Blackstone/Newport's scheme is not the same as Narragansett's. 19 Blackstone/Newport has, in some customer classes, more available rates than 20 Narragansett-in others, less. Blackstone/Newport uses distribution service voltage level Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 5 of 22 1 and billing determinant breakpoints to subdivide its general service customers among 2 several rate classes. Narragansett uses only billing determinant breakpoints to subdivide 3 its general service customers among several rate classes, and these breakpoints differ from 4 Blackstone/Newport's. Narragansett has more auxiliary service and lighting service rates 5 than does Blackstone/Newport. Blackstone and Newport used rate riders for economic 6 development purposes, while Narragansett used provisions in their base rate tariffs. 7 Finally Blackstone/Newport offers more supplementary1 rates than does Narragansett 8 (three rates to one). 9 10 Q. How were the determinants for the rate mapping scheme developed? 11 A. Blackstone-Newport based the mapping of Blackstone/Newport's rates to Narragansett's rates 12 on its customer billing information for calendar year 1998. For each of 13 Blackstone/Newport's rate classes, the number of bills rendered and annual energy 14 consumption were determined. In addition, monthly billing demands and annual peak and off 15 peak energy consumption were determined when applicable. In many cases, especially for 16 those current Blackstone/Newport rate classes that were subdivided into two or more - --------------- 1 A supplementary rate is a rate that is available only to customers who also receive part of their electric service under another rate, called a principal rate. A principal rate can be the only rate under which a customer receives service at a given location, but a supplementary rate cannot. For example, Blackstone/Newport's Controlled Water Heating Service Rate W-1 is a supplementary rate. To be eligible for Rate W-1, a customer must also receive service under one or more of Blackstone/Newport's residential or general service rates at the same service location. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 6 of 22 1 Narragansett rate classes, these determinants were required to be developed on a 2 customer-by-customer basis and transformed from Blackstone/Newport's definition of a 3 determinant -- e.g., billing demand -- to Narragansett's definition of the same determinant. 4 5 Q. Please describe Blackstone and Newport's Schedule of Rates. 6 A. Blackstone and Newport's Schedule of Rates are similar but not identical. Exhibit JJB-1 7 and Exhibit JJB-2 provide a brief description of the availabilities of Blackstone's and 8 Newport's rates, respectively. 9 10 In addition to the above referenced rates, Blackstone/Newport's Schedule of Rates 11 contains the following rate riders, terms and conditions, generation services, and 12 adjustment clauses: 13 Late Payment Charge2 14 Economic Development Rate Rider ED3 15 Economic Development Rate Rider EDR 16 Economic Development Rate Rider VSR 17 Economic Development Rate Rider DIR4 18 Terms and Conditions for Electric Service - --------------- 2 Blackstone only. 3 Id. 4 Newport only. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 7 of 22 1 Terms and Conditions for Electric Power Suppliers 2 Last Resort Service 3 Standard Offer Service 4 Transition Cost Adjustment Clause 5 6 Q. Please describe Narragansett's Schedule of Rates. 7 A. Exhibit JJB-1 and Exhibit JJB-2 provide a brief description of the availabilities of 8 Narragansett's rates. 9 10 In addition to the above referenced rates, Narragansett's Schedule of Rates contains the 11 following terms and conditions, adjustment provisions, and generation service tariffs: 12 Terms and Conditions 13 Terms and Conditions for Nonregulated Power Producers 14 Transmission Service Charge Adjustment Provision 15 Transition Charge Adjustment Provision 16 Standard Offer Adjustment Provision 17 Conservation and Load Management Adjustment Provision 18 Tariff for Standard Offer Service 19 Tariff for Last Resort Service 20 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 8 of 22 1 Q. How were Blackstone/Newport's residential rates mapped to Narragansett's residential 2 rates? 3 A. Blackstone/Newport's residential rates are available only to residential customers for 4 domestic purposes. Rate R-1 is the basic residential retail delivery service rate, Rate R-2 5 is restricted to low-income customers, and Rate R-4 is Blackstone/Newport's time-of-use 6 residential rate. For Blackstone customers, Rate R-3 is available to certain electric space 7 heating customers. This rate was closed to new customers in 1984. 8 9 Like Blackstone/Newport, Narragansett's residential rates are available to residential 10 customers for domestic purposes. In addition, farms and churches are eligible to receive 11 service under Narragansett's residential rates. Rate A-16 is Narragansett's basic 12 residential retail delivery service rate, Rate A-60 is restricted to low-income customers, 13 and Rate A-32 is Narragansett's large-use residential rate. 14 15 As shown on Exhibit JMM-2, Blackstone/Newport's Rates R-1 and the residential portion 16 of W-1 were mapped to Narragansett's Rate A-16. Blackstone/Newport's Rate R-2 was 17 mapped to Narragansett's Rate A-60. Blackstone's Rate R-3 was mapped to 18 Narragansett's Rate A-16. Blackstone/Newport's Rate R-4 was mapped to 19 Narragansett's Rate A-32. 20 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 9 of 22 1 Q. Were any of Blackstone/Newport's residential customers mapped to Narragansett's 2 Rates A-18 and E-30? 3 A. No. Those Narragansett rates, Residential Water Heating Control Rate A-18 and 4 Residential Storage Heating Rate E-30, are closed to new customers. 5 6 Q. Briefly describe Blackstone/Newport's general service rate scheme. 7 A. Blackstone/Newport's "G" and "T" series rates form the main sequence of 8 Blackstone/Newport's general service tariffs. The "G" and "T" series rates are divided 9 into two groups: (1) Secondary distribution voltage rates-Rates G-1, G-2, T-2, and T-4, 10 and (2) primary distribution voltage rates-Rates G-5, T-5, and T-6. The available 11 provisions in the "G" and "T" series rates for Blackstone differ somewhat from Newport's. 12 13 For Blackstone, the availability of the secondary distribution voltage rates is as follows: 14 Rate G-1 is available to customers whose annual maximum monthly demand is less than 15 10 kW and whose annual energy consumption is less than 36,000 kWh. Rate G-2 is 16 available to customers whose annual maximum monthly demand is at least 10 kW but less 17 than 500 kW or whose annual energy consumption is 36,000 kWh or more. For Newport, 18 the availability of the secondary voltage rates is as follows: Rate G-1 is available to 19 customers whose average monthly demand is less than 500 kW and whose annual energy 20 consumption is less than 54,000 kWh. Rate G-2 is available to customers whose average Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 10 of 22 1 monthly demand is less than 500 kW and whose annual energy consumption is 54,000 2 kWh or more. For both Blackstone and Newport, Rate T-4 is mandatory for customers 3 whose monthly demand is 500 kW or more. 4 5 For Blackstone's general service customers served at primary distribution voltage, Rate 6 G-5 is available to customers whose annual maximum monthly demand is at least 10 kW 7 but less than 500 kW or whose annual energy consumption is 36,000 kWh or more. Rate 8 T-5 is an optional time-of-use rate for Rate G-5 customers. Rate T-6 is mandatory for 9 customers whose annual maximum monthly demand is 500 kW or more. 10 11 For Newport's general service customers served at primary voltage, Rate G-5 is available 12 to customers whose average monthly demand is at least 15 kW but less than 500 kW or 13 whose annual energy consumption is 54,000 kWh or more. Rate T-5 is an optional time-of-use 14 rate for Rate G-5 customers. Rate T-6 is mandatory for customers whose average 15 monthly demand is 500 kW or more. In addition, Newport offers Transmission Voltage 16 General Retail Delivery Service Rate C-1, which is applicable only to the U.S. Navy under 17 the terms of a special electric service contract originally executed in 1961 and was 18 amended to incorporate the C-1. 19 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 11 of 22 1 Q How does Narragansett's general service rate scheme compare to Blackstone/Newport's? 2 A. Narragansett's general service rate scheme is generally comparable to 3 Blackstone/Newport's. Narragansett offers six general service rates, Rates C-06, E-40, 4 G-02, G-32, G-62, and T-06. 5 6 Narragansett's main sequence of general service rates consists of Rates C-06, G-02, G-32, 7 and G-62. These rates roughly correspond with Blackstone/Newport's "G" and "T" series 8 rates and apply to customers as follows: Rate C-06 is a non-demand metered general 9 service rate available to customers whose monthly demand is 200 kW or less. Rate G-02 10 is a non-time-differentiated demand metered rate available to customers whose monthly 11 demand is at least 10 kW but not more than 200 M Rate G-32 is a time-differentiated 12 demand metered rate available to customers whose monthly demand is more than 200 kW 13 but less than 3,000 kW. Rate G-62 is a time-differentiated demand metered rate available 14 to customers whose demand is 3,000 kW or greater. 15 16 In addition, Narragansett offers Storage Cooling Rate E-40 and Limited Service - All 17 Electric Living Rate T-06. Blackstone/Newport does not offer a rate that corresponds to 18 Narragansett's Rate E-40; however, Blackstone/Newport's Rate H-1 is comparable to 19 Narragansett's Rate T-06. 20 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 12 of 22 1 Q. How were Blackstone/Newport's general service rates mapped to Narragansett's general 2 service rates? 3 A. As shown in Exhibit JMM-2, Blackstone/Newport's Rate G-1 was mapped to 4 Narragansett's Rate C-06. Blackstone/Newport's Rate G-2 was mapped to 5 Narragansett's Rates C-06, G-02, and G-32. Blackstone/Newport's Rate T-4 was 6 mapped to Narragansett's Rate G-32. Blackstone/Newport's Rate G-5 was mapped to 7 Narragansett's Rates G-02 and G-32. Blackstone/Newport's Rate T-6 was mapped to 8 Narragansett's Rate G-32 and G-62. Blackstone/Newport's Rate H-1 was mapped to 9 Narragansett's Rates C-06, G-02, and G-32. Newport's Rate C-1 was mapped to 10 Narragansett's Rate N-01, which is a new rate and is described in greater detail in Mr. 11 Molloy's testimony. 12 13 Q. Were any of Blackstone/Newport's general service customers mapped to Narragansett's 14 Rates E-40 and T-06? 15 A. No. Blackstone/Newport does not have any customers who qualify for Narragansett Rate 16 E-40, and Narragansett Rate T-06 is closed to new customers. 17 18 Q. How were Blackstone/Newport's auxiliary service Rates A-4 and A-6 mapped to 19 Narragansett's rates? Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 13 of 22 1 A. Blackstone/Newport offers two auxiliary service rates: Large Secondary Voltage Auxiliary 2 General Retail Delivery Service Rate A-4 and Large Primary Voltage Auxiliary General 3 Retail Delivery Service Rate A-6. 4 5 Narragansett's auxiliary service rate offerings are more extensive than 6 Blackstone/Newport's. Narragansett offers rates that are applicable to partial 7 requirements customers whose total electric service requirements exceed 30 kW, while 8 Blackstone/Newport offers rates that are applicable to partial requirements customers 9 whose total electric service requirements exceed 500 kW. 10 11 The availability provisions of Narragansett's auxiliary rates, their "B" series rates, 12 correspond with the availability provisions of the general service rates having the same 13 numerical suffix. Thus, Narragansett's Rate B-06 is available to customers who supply 14 part of their load from on-site generation and who would otherwise be served by 15 Narragansett's Rate C-06. Likewise, Narragansett's Rate B-32 is available to partial 16 requirements customers who would otherwise be served by Narragansett's Rate G-32. 17 And, Narragansett's Rate B-62 is available to partial requirements customers who would 18 otherwise be served by Narragansett's Rate G-62. 19 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 14 of 22 1 Blackstone/Newport's Rate A-4 would be mapped to Narragansett's Rate B-06; however, 2 there are no customers on this rate; Blackstone/Newport's Rate A-6 was mapped to 3 Narragansett's Rate B-32. 4 5 Q. How were Blackstone/Newport's supplementary service rates mapped to Narragansett's 6 rates? 7 A. To determine the proper mapping of Blackstone/Newport's customers who receive part of 8 their service under a supplementary rate, the supplementary rate was paired with the 9 principal rate for each customer. The supplementary rate was then mapped to the 10 Narragansett rate that corresponded to the customer's principal rate. Thus, the residential 11 portion of Blackstone/Newport's Rate W-1 was mapped to Narragansett's Rate A-16, and 12 the non-residential portion of Blackstone/Newport's Rate W-1 was mapped to 13 Narragansett's Rate C-06. Blackstone's Rate H-2 was mapped to three of Narragansett's 14 rates: Rates C-06, G-02, and G-32. Newport's Rate H-2 was mapped to two of 15 Narragansett's rates: Rates C-06 and G-02. 16 17 Q. Were any Blackstone/Newport supplementary rates mapped to Narragansett's 18 supplementary rate, Rate V-02? 19 A. No. Although Limited Service - Business Space Heating Rate V-02 is comparable to 20 Blackstone/Newport's Rate H-2, it is closed to new customers. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 15 of 22 1 Q. How was Blackstone/Newport's lighting service rate mapped to Narragansett's lighting 2 service rates? 3 A. Blackstone/Newport offers only one lighting service rate to its customers, Rate S-1. 4 Blackstone/Newport's Rate S-1 provides customers with a wide choice of lighting fixtures 5 (streetlights, floodlights, and area lights) mounted on distribution or specialty lighting 6 poles served from overhead or underground conductors. All lighting equipment 7 (luminaires, poles, conductors, etc.) required to provide service under Rate S-1 is 8 furnished, installed, owned, and maintained by Blackstone/Newport. For certain fixture-pole 9 combinations, Blackstone/Newport permits customers to pay the initial cost of 10 installation by a contribution in aid of construction to obtain a lower monthly rate. 11 12 Although it appears that Narragansett offers more lighting rates than does 13 Blackstone/Newport, in fact, Narragansett offers only one. Three of Narragansett's 14 lighting rates are frozen: Rates R-02, S-10, and S-12. Only Rate S-14 is currently 15 available for new installations. 16 17 Blackstone/Newport's Rate S-1 was mapped to Narragansett's Rate S-14. 18 Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 16 of 22 1 IV. Derivation of Billing Determinants for Blackstone/Newport's Customers 2 Under Narragansett's Rates 3 Q. Please summarize how billing determinants for Blackstone/Newport's customers under 4 Narragansett's rates were derived. 5 A. Billing determinants are customer usage parameters that are applied to the component 6 charges of a rate schedule to calculate a customer's bill. Examples of commonly used 7 billing determinants are the number of bills, monthly energy consumption, and monthly 8 maximum demand. The precise definition of a billing determinant is dependent upon the 9 rate to which it is applied. Consequently, the derivation of billing determinants for a 10 customer to be transferred from one rate to another depends upon the rate to which the 11 customer is to be transferred. 12 13 In some cases, the billing determinants for Blackstone/Newport's customers under 14 Narragansett's rates are the same determinants Blackstone/Newport uses to bill these 15 same customers under its rates. This is exactly the case for Blackstone/Newport's 16 customers served under Rates R-1, R-2, R-3, R-4, G-1, W-1, and S-1 that will be 17 transferred to Narragansett's Rates A-16, A-32, A-60, C-06, and S-14. 18 19 In all other cases, the billing determinants for Blackstone/Newport's customers under 20 Narragansett's rates had to be calculated or estimated, at least for some of the customers Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 17 of 22 1 being transferred from a particular Blackstone/Newport rate to a particular Narragansett 2 rate. All of Blackstone/Newport's customers served under its general service rates, other 3 than Rate G-1 customers, and all of Blackstone/Newport's customers served under its 4 supplementary rates required the calculation or estimation of billing determinants under 5 Narragansett's rates. 6 7 Exhibit JJB-3 and Exhibit JJB-4 show the billing determinants for each Blackstone and 8 Newport to Narragansett rate mapping, respectively. Each Blackstone/Newport rate 9 mapping is shown on a separate page, and, where appropriate, explanatory notes detailing 10 how the billing determinants were derived is included on the page. 11 12 Q. Why was it necessary to estimate billing determinants for some customers? 13 A. Estimated billing determinants, particularly billing demands, for customers were used 14 where Blackstone/Newport's definition of a billing determinant differs from 15 Narragansett's and/or where Blackstone/Newport does not record, or does not have 16 readily available, the data required to calculate the determinant. For example, 17 Blackstone/Newport's Rate H-1 non-demand metered customers transferring to 18 Narragansett's demand metered Rates G-02 and G-32 required the estimation of billing 19 demands. Exhibits JJB-3 and JJB-4 detail each instance where estimated determinants 20 were required. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 18 of 22 1 Q. In general, is Blackstone/Newport's definition of billing demand for its general service 2 rates substantially different from Narragansett's? 3 A. Yes, it is. Although both companies define demand as a fifteen-minute integrated demand, 4 the determination of billing demand from raw demand data is generally more complicated 5 under Narragansett's rates than it is under Blackstone/Newport's rates. 6 7 Blackstone/Newport generally defines billing demand as the maximum demand over all 8 hours for non-time-differentiated rates and as the maximum demand within peak hours for 9 time-differentiated rates. 10 11 Narragansett generally determines billing demand as the largest of several demands. For 12 example, Narragansett defines billing demand for their Rate G-32 customers as the 13 greatest of the following: 14 (a) The greatest fifteen-minute demand occurring in such month during Peak 15 or Shoulder hours as measured in kilowatts, 16 (b) 80% of the greatest fifteen-minute demand occurring in such month during 17 Peak or Shoulder hours as measured in kilovolt-amperes, 18 (c) 50% of the greatest fifteen-minute demand occurring in such month during 19 Off-Peak Hours as measured in kilowatts, Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 19 of 22 1 (d) 40% of the greatest fifteen-minute demand occurring in such month during 2 Off-Peak Hours as measured in kilovolt-amperes, 3 (e) 75% of the greatest billing demand as determined above during the 4 preceding eleven months, or 5 (f) 10 kilowatts. 6 Similar "greatest of" criteria are used to determine billing demand under other 7 Narragansett demand metered rates. 8 9 Q. Is Blackstone/Newport's definition of time periods for its time-differentiated general 10 service rates substantially different from Narragansett's? 11 A. Yes, it is. Blackstone/Newport use a two-part definition with relatively short peak hour 12 periods. Narragansett uses a three-part time period definition and relatively long 13 peak-shoulder hour periods. 14 15 Blackstone defines its time periods for all time-differentiated rates as follows: 16 Peak Hours 17 Monday through Friday excluding holidays: 18 April through September, 11:00 a.m. to 4:00 p.m. 19 October through March, 8:00 a.m. to 12:00 noon, and 20 4:00 p.m. to 7:00 p.m. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 20 of 22 1 Off-Peak Hours 2 All other hours. 3 Newport's time periods are slightly differ from Blackstone's and are as follows for all 4 time-differentiated rates: 5 Peak Hours 6 Monday through Friday excluding holidays: 7 May through September, 10:00 a.m. to 4:00 p.m. 8 October through April, 9:00 a.m. to 12:00 noon, and 9 5:00 p.m. to 8:00 p.m. 10 Off-Peak Hours 11 All other hours. 12 Narragansett defines its time periods as follows: 13 Peak Hours 14 Monday through Friday excluding holidays: 15 June through September, 9:00 a.m. to 6:00 p.m. 16 December through February, 8:00 a.m. to 8:00 p.m. 17 Shoulder Hours 18 Monday through Friday excluding holidays: Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 21 of 22 1 June through September, 8:00 a.m. to 9:00 a.m., and 2 6:00 p.m. to 10:00 p.m. 3 December through February, 7:00 a.m. to 8:00 a.m., and 4 8:00 p.m. to 10:00 p.m. 5 October through November and March through May, 6 8:00 a.m. to 9:00 p.m. 7 Off-Peak Hours 8 All other hours. 9 All companies define holidays as follows: 10 New Year's Day Columbus Day 11 President's Day Veteran's Day 12 Memorial Day Thanksgiving Day 13 Independence Day Christmas Day 14 Labor Day 15 16 Q. Are the differences in the definition of billing demand and TOU time periods between 17 Blackstone/Newport and Narragansett taken into consideration in the estimation of billing 18 determinants for affected rate classes. Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _____ Testimony of J. J. Bonner Page 22 of 22 1 A. Yes. As shown in Exhibit JJB-3 and Exhibit JJB-4, these definitional differences are taken 2 into account. Where such considerations were material, they are so noted on the 3 individual pages of the exhibit. 4 5 Q. Does this conclude your testimony? 6 A. Yes, it does.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibits of James J.Bonner, Jr. JJB-1 Blackstone - Comparison of Availability Provisions of Rates JJB-2 Newport - Comparison of Availability Provisions of Rates JJB-3 Blackstone - Billing Determinants JJB-4 Newport - Billing Determinants Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JJB-1 Exhibit JJB-1 Blackstone - Comparison of Availability Provisions of Rates Narragansett Electric Company Blackstone Valley Electric Company R.I.P.U.C. Docket No. _______ Exhibit JJB-1 Page 1 of 7 THE NARRAGANSETT ELECTRIC COMPANY BLACKSTONE VALLEY ELECTRIC COMPANY COMPARISON OF AVAILABILITY PROVISIONS OF RATES BLACKSTONE'S RATE RESIDENTIAL RETAIL DELIVERY SERVICE RATE R-1 Available only to residential customers whose energy consumption is <30,000 kWh. NARRAGANSETT'S RATE BASIC RESIDENTIAL RATE A-16 Available for all domestic purposes in an individual private dwelling or an individual private apartment. Notwithstanding the foregoing, service is not available under this rate for any customer required to take service on the Residential Time-of-Use Rate A-32. Service is also available for farm customers where all electricity is delivered by the Company. RESIDENTIAL WATER HEATING CONTROL RATE A-18 This rate is closed to new customers as of January 1, 1998. Available for all domestic purposes wherein the customer has installed and has in regular operation an electric water heater. BLACKSTONE'S RATE RESIDENTIAL SSI RETAIL DELIVERY SERVICE RATE R-2 Available to residential Customers that meet the following criteria: 1. Must be the head of a household or principal wage earner. 2. Must be presently receiving Supplemental Security income from the Social Security Administration or one of the following from the appropriate Rhode Island agencies: Medicaid, Food Stamps, General Public Assistance or Aid to Families with Dependent Children. NARRAGANSETT'S RATE LOW INCOME RATE A-60 Available only to currently qualified customers for all domestic purposes in an individual private dwelling or an individual apartment, providing such customer meets both of the following criteria: 1. Must be the head of a household or principal wage earner. 2. Must be presently receiving Supplemental Security Income from the Social Security Administration or one of the following from the appropriate Rhode Island agencies: Medicaid, Food Stamps, General Public Assistance or Aid to Families with Dependent Children. BLACKSTONE'S RATE RESIDENTIAL SPACE HEATING RETAIL DELIVERY SERVICE RATE R-3 Closed to new customers. Available only to residential customers where electricity is the sole source of energy used for comfort heating and water heating and energy consumption is <30,000 kWh. Narragansett Electric Company Blackstone Valley Electric Company R.I.P.U.C. Docket No. ________ Exhibit JJB-1 Page 2 of 7 BLACKSTONE'S RATE LARGE RESIDENTIAL RETAIL DELIVERY SERVICE RATE R-4 Available to residential customers whose actual or estimated energy consumption is at least 6,000 kWh but < 30,000 kWh. NARRAGANSETT'S RATE RESIDENTIAL TIME-OF-USE RATE A-32 Available for all domestic purposes in an individual private dwelling or an individual private apartment. Service is also available for farm customers where delivery is provided by the Company. A church and adjacent buildings owned and operated by the church may be served under this rate, but any such buildings separated by public ways must be billed separately. The Company will require any Customer taking service on the Basic Residential Rate A- 16 or the Residential Water Heater Control Rate A- 18 to take service on this rate if the Customer's usage for the previous 12 months exceeds 30,000 kWh. The Company will require any new customer to take service under this rate if the Company estimates that the Customer's annual usage will exceed 30,000 kWh. A Customer who has been placed on this rate pursuant to this paragraph may transfer to another available rate if the Customer's usage for the previous 12 months is less than 24,000 kWh. RESIDENTIAL STORAGE HEATING RATE E-30 Available to customers who were served under Limited Residential Service - Storage Heating (E01) on July 1, 1990. GENERAL C&I BACK-UP SERVICE RATE B-02 Apply to Customers in the class identified below: (I) who receive all or any portion of their electric supply from non-emergency generation unit(s) with a nameplate rating greater than 30 kW ("Generation Units"), where electricity received by the Customer from the Generation Units is not being delivered over Company-owned distribution facilities pursuant to an applicable retail delivery tariff, and (ii) who expect the Company to provide retail delivery service to supply the Customer's load at the service location when the Generation Units are not supplying all of that load. Narragansett Electric Company Blackstone Valley Electric Company R.I.P.U.C. Docket No. _______ Exhibit JJB-1 Page 3 of 7 BLACKSTONE'S RATE SMALL SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-1 Available to customers whose actual or estimated average monthly demand is less than 500 kW and annual energy consumption is less than 54,000 kWh. NARRAGANSETT'S RATE SMALL C&I RATE C-06 Available for all purposes. The Company may require any customer with a 12-month average demand greater than 200 kW to take service on the 200 kW Demand Rate G-32. If any electricity is delivered hereunder at a given location, then all electricity delivered by the Company at such location shall be delivered hereunder, except such electricity as may be delivered under the provisions of the Limited Service - Business Space Heating (V-02) rate. STORAGE COOLING RATE E-40 Available to any customer solely for use in operating a full storage air conditioning system. BLACKSTONE'S RATE MEDIUM SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-2 Available only to customers whose actual or estimated average monthly demand is less than 500 kW and whose actual or estimated annual energy consumption is 54,000 kWh or more. NARRAGANSETT'S RATE GENERAL C&I RATE G-02 Available for all purposes to customers with a Demand of 10 kW or more. The Company may require any customer with a 12-month average Demand greater than 200 kW to take service on the 200 kW Demand Rate G-32. BLACKSTONE'S RATE MEDIUM PRIMARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-5 Available only to customers whose actual or estimated average monthly demand is at least 15 kW but less than 500 kW or whose actual or estimated annual energy consumption is 54,000 kWh or more. NARRAGANSETT'S RATE 200 KW DEMAND RATE G-32 The Company shall place on this rate any customer who has a 12-month average Demand of 200 kW or greater for 3 consecutive months as soon as practicable. BLACKSTONE'S RATE LARGE SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE T-4 Mandatory for all customers whose actual or estimated average monthly demand is 500 kW or more. Narragansett Electric Company Blackstone Valley Electric Company R.I.P.U.C. Docket No. _______ Exhibit JJB-1 Page 4 of 7 BLACKSTONE'S RATE LARGE PRIMARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE T-6 Mandatory for all customers whose actual or estimated average monthly demand is 500 kW or more. NARRAGANSETT'S RATE 3000 KW DEMAND RATE G-62 The Company shall place on this rate any customer who has a 12-month maximum Demand of 3,000 kW or greater. Delivery service can be taken under this rate by customers who do not meet the qualifications on a voluntary basis. New Customers: Delivery service will initially be taken under this rate by any new customer who requests delivery service capability of 3,375 kVA or greater. Transfers From Rate G-62: Any customer whose 12-month maximum demand is less than 2,700 kW for twelve consecutive months may elect to transfer from the 3,000 kW Demand Rate G-62 to another available rate. BLACKSTONE'S RATE LARGE SECONDARY VOLTAGE AUXILIARY GENERAL RETAIL DELIVERY SERVICE RATE A-4 Available to any Customer served at secondary voltage, who furnishes its own electric power supply for all or part of its total electric retail delivery service requirements. NARRAGANSETT'S RATE SMALL C&I BACK-UP SERVICE RATE B-06 Apply to Customers in the class identified below: (I) who receive all or any portion of their electric supply from non-emergency generation unit(s) with a nameplate rating greater than 30 kW ("Generation Units"), where electricity received by the Customer from the Generation Units is not being delivered over Company-owned distribution facilities pursuant to an applicable retail delivery tariff, and (ii) who expect the Company to provide retail delivery service to supply the Customer's load at the service location when the Generation Units are not supplying all of that load. Electric delivery service under this rate is applicable to those Customers being served by Generation Unit(s) installed on or after April 1, 1998 and would otherwise be served under the Company's Small C&I Rate C-06 if the Generation Units were not supplying electricity to the Customer. This tariff shall not apply to customers with a contracted demand of 25 kVA or less. Narragansett Electric Company Blackstone Valley Electric Company R.I.P.U.C. Docket No. _______ Exhibit JJB-1 Page 5 of BLACKSTONE'S RATE LARGE PRIMARY VOLTAGE AUXILIARY GENERAL RETAIL DELIVERY SERVICE RATE A-6 Available to any Customer served at primary voltage, who furnishes its own electric power supply for all or part of its total electric retail delivery service requirements. NARRAGANSETT'S RATE 200 KW DEMAND BACK-UP SERVICE RATE B-32 This service shall apply to Customers in the class identified below: (I) who receive all or any portion of their electric supply from non-emergency generation unit(s) with a nameplate rating greater than 30 kW ("Generation Units"), where electricity received by the Customer from the Generation Units is not being delivered over Company-owned distribution facilities pursuant to an applicable retail delivery tariff, and (ii) who expect the Company to provide retail delivery service to supply the Customer's load at the service location when the Generation Units are not supplying all of that load. 3,000 KW DEMAND BACK-UP SERVICE RATE B-62 This service shall apply to Customers in the class identified below: (I) who receive all or any portion of their electric supply from non-emergency generation unit(s) with a nameplate rating greater than 30 kW ("Generation Units"), where electricity received by the Customer from the Generation Units is not being delivered over Company-owned distribution facilities pursuant to an applicable retail delivery tariff, and (ii) who expect the Company to provide retail delivery service to supply the Customer's load at the service location when the Generation Units are not supplying all of that load. Electric delivery service under this rate is applicable to those Customers being served by Generation Unit(s) installed on or after April 1, 1998 and would otherwise be served under the Company's 3,000 kW Demand Rate G-62 if the Generation Units were not supplying electricity to the Customer. This tariff shall not apply to customers with a contracted demand of 25 kVA or less. Narragansett Electric Company Blackstone Valley Electric Company R.I.P.U.C. Docket No. _______ Exhibit JJB-1 Page 6 of 7 NARRAGANSETT'S RATE LIMITED SERVICE - ALL ELECTRIC LIVING RATE T-06 The availability of this rate is limited to those customers who were served under Limited Service - All Electric Living Rate T, on May 1, 1984 and have continuously been served under the AllElectric Living Rate since that date. LIMITED SERVICE - BUSINESS SPACE HEATING RATE V-02 The availability of this rate is limited to those customers who were served under Limited Service - Business Space Heating Rate V on May 1, 1984 and have continuously been served under the Business Space Heating Rate since that date. BLACKSTONE'S RATE GENERAL SPACE HEATING RETAIL DELIVERY SERVICE RATE H-1 Closed to new Customers. Available only to Customers whose actual or estimated average monthly demand is < 500 kW that were taking service from the former Total Electric Living Rate -Limited, R.I.P.U.C. No. 205-L prior to April 1, 1988. GENERAL HEATING RETAIL DELIVERY SERVICE RATE H-2 Closed to new Customers. Available to customers that were taking service under the Special Space Heating Provision - Limited of former General Service Rate R.I.P.U.C. No. 201-N prior to April 1, 1988. CONTROLLED WATER HEATING RETAIL DELIVERY SERVICE RATE W-1 Closed to new Customers. Available to Customers that were taking retail delivery service from the Company under former Controlled Off-Peak Rate, R.I.P.U.C. No. 102-N before 10-28-92. Narragansett Electric Company Blackstone Valley Electric Company R.I.P.U.C. Docket No. ________ Exhibit JJB-1 Page 7 of 7 NARRAGANSETT'S RATE LIMITED TRAFFIC SIGNAL SERVICE RATE R-02 Availability of this rate is limited to the following customers and locations: those customers and locations who were served under Traffic Signal Rate R - R.I.P.U.C. No. 937 on May 10, 1992. LIMITED SERVICE - PRIVATE LIGHTING RATE S-10 Private lighting and floodlighting service is available under this rate to any Customer who prior to the date of this rate was served on Limited Service-Private Lighting Rate S-6, R.I.P.U.C. No. 872. There will be no new installations or relocations under this rate. LIMITED STREET LIGHTING RATE S-12 Street Lighting Service is available under this rate to any Customer who prior to the date of this rate was served on Limited Street Lighting Service (S-7), R.I.P.U.C. NO. 873. There will be no installations or relocations under this rate. BLACKSTONE'S RATE LIGHTING RETAIL DELIVERY SERVICE RATE S-1 Available to all Customers where electricity is supplied to lighting equipment owned and maintained by the Company on Company owned poles, for dusk-to-dawn operation of approximately 4,000 burning hours per year. NARRAGANSETT'S RATE GENERAL STREETLIGHTING SERVICE RATE S-14 Street Lighting Service is available under this rate to any city, town, or other public authority hereinafter referred to as the Customer, in accordance with the provisions and the specifications hereinafter set forth for all installations made after January 1, 1990. 1. For municipally-owned or accepted roadways, which includes those classified as "private ways" for which a municipality has agreed to supply street lighting service. 2. Service under this rate is contingent upon Company ownership and maintenance of street lighting equipment. 3. Service under this rate is not available for limited access highways or the access and egress ramps. 4. Service under this rate is available to private contractors for street lighting service for streets which have not yet been accepted by the municipality. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JJB-2 Exhibit JJB-2 Newport - Comparison of Availability Provisions of Rates Narragansett Electric Company Newport Electric Corporation R.I.P.U.C. Docket No. _______ Exhibit JJB-2 Page 1 of 7 THE NARRAGANSETT ELECTRIC COMPANY NEWPORT ELECTRIC COMPANY COMPARISON OF AVAILABILITY PROVISIONS OF RATES NEWPORT'S RATE RESIDENTIAL RETAIL DELIVERY SERVICE RATE R-1 Available only to residential customers whose energy consumption is <30,000 kWh. NARRAGANSETT'S RATE BASIC RESIDENTIAL RATE A-16 Available for all domestic purposes in an individual private dwelling or an individual private apartment. Notwithstanding the foregoing, service is not available under this rate for any customer required to take service on the Residential Time-of-Use Rate A-32. Service is also available for farm customers where all electricity is delivered by the Company. RESIDENTIAL WATER HEATING CONTROL RATE A-18 This rate is closed to new customers as of January 1, 1998, Available for all domestic purposes wherein the customer has installed and has in regular operation an electric water heater. NEWPORT'S RATE RESIDENTIAL SSI RETAIL DELIVERY SERVICE RATE R-2 Available to residential Customers that meet the following criteria: 1. Must be the head of a household or principal wage earner. 2. Must be presently receiving Supplemental Security Income from the Social Security Administration or one of the following from the appropriate Rhode Island agencies: Medicaid, Food Stamps, General Public Assistance or Aid to Families with Dependent Children. NARRAGANSETT'S RATE LOW INCOME RATE A-60 Available only to currently qualified customers for all domestic purposes in an individual private dwelling or an individual apartment, providing such customer meets both of the following criteria: 1. Must be the head of a household or principal wage earner. 2. Must be presently receiving Supplemental Security Income from the Social Security Administration or one of the following from the appropriate Rhode Island agencies: Medicaid, Food Stamps, General Public Assistance or Aid to Families with Dependent Children. Narragansett Electric Company Newport Electric Corporation R.I.P.U.C. Docket No. _______ Exhibit JJB-2 Page 2 of 7 NEWPORT'S RATE LARGE RESIDENTIAL RETAIL DELIVERY SERVICE RATE R-4 Available to residential customers whose actual or estimated energy consumption is at least 6,000 kWh but < 30,000 kWh. NARRAGANSETT'S RATE RESIDENTIAL TIME-OF-USE RATE A-32 Available for all domestic purposes in an individual private dwelling or an individual private apartment. Service is also available for farm customers where delivery is provided by the Company. A church and adjacent buildings owned and operated by the church may be served under this rate, but any such buildings separated by public ways must be billed separately. The Company will require any Customer taking service on the Basic Residential Rate A-16 or the Residential Water Heater Control Rate A-18 to take service on this rate if the Customer's usage for the previous 12 months exceeds 30,000 kWh. The Company will require any new customer to take service under this rate if the Company estimates that the Customer's annual usage will exceed 30,000 kWh. A Customer who has been placed on this rate pursuant to this paragraph may transfer to another available rate if the Customer's usage for the previous 12 months is less than 24,000 kWh. RESIDENTIAL STORAGE HEATING RATE E-30 Available to customers who were served under Limited Residential Service - Storage Heating (E-01) on July 1, 1990. GENERAL C&I BACK-UP SERVICE RATE B-02 Apply to Customers in the class identified below: (I) who receive all or any portion of their electric supply from non-emergency generation unit(s) with a nameplate rating greater than 30 kW ("Generation Units"), where electricity received by the Customer from the Generation Units is not being delivered over Company-owned distribution facilities pursuant to an applicable retail delivery tariff, and (ii) who expect the Company to provide retail delivery service to supply the Customer's load at the service location when the Generation Units are not supplying all of that load. Narragansett Electric Company Newport Electric Corporation R.I.P.U.C. Docket No. _______ Exhibit JJB-2 Page 3 of 7 NEWPORT'S RATE SMALL SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-1 Available to customers whose actual or estimated average monthly demand is less than 500 kW and annual energy consumption is less than 54,000 kWh. NARRAGANSETT'S RATE SMALL C&I RATE C-06 Available for all purposes. The Company may require any customer with a 12-month average demand greater than 200 kW to take service on the 200 kW Demand Rate G-32. If any electricity is delivered hereunder at a given location, then all electricity delivered by the Company at such location shall be delivered hereunder, except such electricity as may be delivered under the provisions of the Limited Service - Business Space Heating (V-02) rate. STORAGE COOLING RATE E40 Available to any customer solely for use in operating a full storage air conditioning system. NEWPORT'S RATE MEDIUM SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-2 Available only to customers whose actual or estimated average monthly demand is less than 500 kW and whose actual or estimated annual energy consumption is 54,000 kWh or more. NARRAGANSETT'S RATE GENERAL C&I RATE G-02 Available for all purposes to customers with a Demand of 10 kW or more. The Company may require any customer with a 12-month average Demand greater than 200 kW to take service on the 200 kW Demand Rate G-32. NEWPORT'S RATE MEDIUM PRIMARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-5 Available only to customers whose actual or estimated average monthly demand is at least 15 kW but less than 500 kW or whose actual or estimated annual energy consumption is 54,000 kWh or more. NARRAGANSETT'S RATE 200 KW DEMAND RATE G-32 The Company shall place on this rate any customer who has a 12-month average Demand of 200 kW or greater for 3 consecutive months as soon as practicable. NEWPORT'S RATE LARGE SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE T-4 Mandatory for all customers whose actual or estimated average monthly demand is 500 kW or more. Narragansett Electric Company Newport Electric Corporation R.I.P.U.C. Docket No. _______ Exhibit JJB-2 Page 4 of 7 NEWPORT'S RATE LARGE PRIMARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE T-6 Mandatory for all customers whose actual or estimated average monthly demand is 500 kW or more. NARRAGANSETT'S RATE 3000 KW DEMAND RATE G-62 The Company shall place on this rate any customer who has a 12-month maximum Demand of 3,000 kW or greater. Delivery service can be taken under this rate by customers who do not meet the qualifications on a voluntary basis. New Customers: Delivery service will initially be taken under this rate by any new customer who requests delivery service capability of 3,375 kVA or greater. Transfers From Rate G-62: Any customer whose 12-month maximum demand is less than 2,700 kW for twelve consecutive months may elect to transfer from the 3,000 kW Demand Rate G-62 to another available rate. NEWPORT'S RATE TRANSMISSION VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE C-1 Available only to the Dept. of the Navy under the provisions of the contract dated May 1, 1961. NEWPORT'S RATE LARGE SECONDARY VOLTAGE AUXILIARY GENERAL RETAIL DELIVERY SERVICE RATE A-4 Available to any Customer served at secondary voltage, who furnishes its own electric power supply for all or part of its total electric retail delivery service requirements. NARRAGANSETT'S RATE SMALL C&I BACK-UP SERVICE RATE B-06 Apply to Customers in the class identified below: (I) who receive all or any portion of their electric supply from non-emergency generation unit(s) with a nameplate rating greater than 30 kW ("Generation Units"), where electricity received by the Customer from the Generation Units is not being delivered over Company-owned distribution facilities pursuant to an applicable retail delivery tariff, and (ii) who expect the Company to provide retail delivery service to supply the Customer's load at the service location when the Generation Units are not supplying all of that load. Electric delivery service under this rate is applicable to those Customers being served by Generation Unit(s) installed on or after April 1, 1998 and would otherwise be served under the Company's Small C&I Rate C-06 if the Generation Units were not supplying electricity to the Customer. This tariff shall not apply to customers with a contracted demand of 25 kVA or less. Narragansett Electric Company Newport Electric Corporation R.I.P.U.C. Docket No. _______ Exhibit JJB-2 Page 5 of 7 NEWPORT'S RATE LARGE PRIMARY VOLTAGE AUXILIARY GENERAL RETAIL DELIVERY SERVICE RATE A-6 Available to any Customer served at primary voltage, who furnishes its own electric power supply for all or part of its total electric retail delivery service requirements. NARRAGANSETT'S RATE 200 KW DEMAND BACK-UP SERVICE RATE B-32 This service shall apply to Customers in the class identified below: (I) who receive all or any portion of their electric supply from non-emergency generation unit(s) with a nameplate rating greater than 30 kW ("Generation Units"), where electricity received by the Customer from the Generation Units is not being delivered over Company-owned distribution facilities pursuant to an applicable retail delivery tariff, and (ii) who expect the Company to provide retail delivery service to supply the Customer's load at the service location when the Generation Units are not supplying all of that load. 3,000 KW DEMAND BACK-UP SERVICE RATE B-62 This service shall apply to Customers in the class identified below: (I) who receive all or any portion of their electric supply from non-emergency generation unit(s) with a nameplate rating greater than 30 kW ("Generation Units"), where electricity received by the Customer from the Generation Units is not being delivered over Company-owned distribution facilities pursuant to an applicable retail delivery tariff, and (ii) who expect the Company to provide retail delivery service to supply the Customer's load at the service location when the Generation Units are not supplying all of that load. Electric delivery service under this rate is applicable to those Customers being served by Generation Unit(s) installed on or after April 1, 1998 and would otherwise be served under the Company's 3,000, kW Demand Rate G-62 if the Generation Units were not supplying electricity to the Customer. This tariff shall not apply to customers with a contracted demand of 25 kVA or less. Narragansett Electric Company Newport Electric Corporation R.I.P.U.C. Docket No. _______ Exhibit JJB-2 Page 6 of 7 NARRAGANSETT'S RATE LIMITED SERVICE - ALL ELECTRIC LIVING RATE T-06 The availability of this rate is limited to those customers who were served under Limited Service - All Electric Living Rate T, on May 1, 1984 and have continuously been served under the All Electric Living Rate since that date. NEWPORT'S RATE GENERAL SPACE HEATING RETAIL DELIVERY SERVICE RATE H-1 Closed to new Customers. Available only to Customers whose actual or estimated average monthly demand is < 500 kW that were taking service from the former Total Electric Living Rate -Limited, R.I.P.U.C. No. 205-L prior to April 1, 1988. NARRAGANSETT'S RATE LIMITED SERVICE - BUSINESS SPACE HEATING RATE V-02 The availability of this rate is limited to those customers who were served wider Limited Service - Business Space Heating Rate V on May 1, 1984 and have continuously been served under the Business Space Heating Rate since that date. NEWPORT'S RATE GENERAL HEATING RETAIL DELIVERY SERVICE RATE H-2 Closed to new Customers. Available to customers that were taking service under the Special Space Heating Provision - Limited of former General Service Rate R.I.P.U.C. No. 201-N prior to April 1, 1988. CONTROLLED WATER HEATING RETAIL DELIVERY SERVICE RATE W-1 Closed to new Customers. Available to Customers that were taking retail delivery service from the Company under former Controlled Off-Peak Rate, R.I.P.U.C. No. 102-N before 10-28-92. Narragansett Electric Company Newport Electric Corporation R.I.P.U.C. Docket No. _______ Exhibit JJB-2 Page 7 of 7 NARRAGANSETT'S RATE LIMITED TRAFFIC SIGNAL SERVICE RATE R-02 Availability of this rate is limited to the following customers and locations: those customers and locations who were served under Traffic Signal Rate R - R.I.P.U.C. No. 937 on May 10, 1992. LIMITED SERVICE - PRIVATE LIGHTING RATE S-10 Private lighting and floodlighting service is available under this rate to any Customer who prior to the date of this rate was served on Limited Service-Private Lighting Rate S-6, R.I.P.U.C. No. 872. There will be no new installations or relocations under this rate. LIMITED STREET LIGHTING RATE S-12 Street Lighting Service is available under this rate to any Customer who prior to the date of this rate was served on Limited Street Lighting Service (S-7), R.I.P.U.C. NO. 873. There will be no installations or relocations under this rate. NEWPORT'S RATE LIGHTING RETAIL DELIVERY SERVICE RATE S-1 Available to all Customers where electricity is supplied to lighting equipment owned and maintained by the Company on Company owned poles, for dusk-to-dawn operation of approximately 4,000 burning hours per year. NARRAGANSETT'S RATE GENERAL STREETLIGHTING SERVICE RATE S-14 Street Lighting Service is available under this rate to any city, town, or other public authority hereinafter referred to as the Customer, in accordance with the provisions and the specifications hereinafter set forth for all installations made after January 1, 1990. 1. For municipally-owned or accepted roadways, which includes those classified as "private ways" for which a municipality has agreed to supply street lighting service. 2. Service under this rate is contingent upon Company ownership and maintenance of street lighting equipment. 3. Service under this rate is not available for limited access highways or the access and egress ramps. 4. Service under this rate is available to private contractors for street lighting service for streets which have not yet been accepted by the municipality. Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JJB-3 Exhibit JJB-3 Blackstone - Billing Determinants
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 1 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate R-1 v. Narragansett's Rate A-16 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 876,261 876,261 Energy (kWh) 362,568,042 362,568,042
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 2 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate R-2 v. Narragansett's Rate A-60 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 25,844 25,844 Energy (kWh) 10,464,104 10,464,104 First 300 kWh 6,540,065 6,540,065 Excess 300 kWh 3,924,039 3,924,039
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 3 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate R-3 v. Narragansett's Rate A-16 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 10,622 10,622 Energy (kWh) 9,162,722 9,162,722
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 4 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate R-4 v. Narragansett's Rate A-32 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 1,821 1,821 Energy (kWh) 4,487,447 4,487,447 Peak Energy (kWh) 815,510 0 Off-Peak Energy (KWh) 3,671,937 0
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 5 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate G-1 v. Narragansett's Rate C-06 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 87,619 85,368 Unmetered 2,251 Energy (kWh) 43,670,643 43,670,643
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 6 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate G-2: Total Blackstone's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 31,059 Demand (kW) 1,140,854 Energy (kWh) 313,855,524 Blackstone's Rate G-2 v. Narragansett's Rate C-06 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 17,427 17,427 Demand (kW) 293,038 Energy (kWh) 55,207,092 55,207,092 Blackstone's Rate G-2 v. Narragansett's Rate G-02 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 12,852 12,852 Demand (kW) 621,666 597,149 Energy (kWh) 189,662,772 189,662,772 Blackstone's Rate G-2 v. Narragansett's Rate G-32 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 780 780 Demand (kW) 226,150 269,038 Energy (kWh) 68,985,660 68,985,660 Note: 1. For Blackstone's Rate G-2 customers apportioned to Narragansett's C-06, the revenue for each customer was calculation under both Narragansett's Rate C-06 and G-02. The Blackstone Rate G-2 customers were then transferred to the Narragansett rate producing the lower revenue.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 7 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate G-5: Total Blackstone's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 394 Demand (kW) 73,140 Energy (kWh) 23,108,580 Blackstone's Rate G-5 v. Narragansett's Rate G-02 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 228 228 Demand (kW) 20,540 27,078 Energy (kWh) 7,714,640 7,714,640 Blackstone's Rate G-5 v. Narragansett's Rate G-32 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 166 166 Demand (kW) 52,600 58,829 Energy (kWh) 15,393,940 15,393,940 Note: 1. Blackstone's Rate G-5 determinants were apportioned among Narragansett Rates G-02 and G-32 based on the availability provisions of Narragansett's rates. 2. Narragansett's billing demands are estimated based upon Blackstone's Rate G-5 load research data using Narragansett TOU hours. 3. Billing demands used to determine whether a Blackstone Rate G-5 is to be transferred to Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest demand in the previous 11 months less 10 kW. 4. Billing demands used to determine whether a Blackstone Rate G-5 customer is to be transferred to Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11 months, or (4) 10 kW.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 8 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate T-2: Total Blackstone's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 856 Demand (kW) 110,812 Energy (kWh) 45,916,407 Peak Energy (kWh) 9,573,412 Off-Peak Energy (kWh) 36,342,995 Blackstone's Rate T-2 v. Narragansett's Rate C-06 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 54 54 Demand (kW) 707 1,888 Energy (kWh) 93,312 93,312 Peak Energy (kWh) 13,722 0 Off-Peak Energy (kWh) 79,590 0 Blackstone's Rate T-2 v. Narragansett's Rate G-02 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 551 551 Demand (kW) 31,864 24,796 Energy (kWh) 13,353,435 13,353,435 Peak Energy (kWh) 2,692,710 0 Off-Peak Energy (kWh) 10,660,725 0 Blackstone's Rate T-2 v. Narragansett's Rate G-32 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 251 251 Demand (kW) 78,241 99,892 Energy (kWh) 32,469,660 32,469,660 Peak Energy (kWh) 6,866,980 0 Off-Peak Energy (kWh) 25,602,680 0 Note: 1. For Blackstone's Rate T-2 customers apportioned to Narragansett's C-06, the revenue for each customer was calculation under both Narragansett's Rate C-06 and G-02. The Blackstone Rate T-2 customers were then transferred to the Narragansett rate producing the lower revenue.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 9 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate T-4 v. Narragansett's Rate G-32 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 372 372 Demand (kW) 195,414 225,770 Energy (kWh) 78,036,479 78,036,479 Peak Energy (kWh) 18,111,219 0 Off-Peak Energy (kWh) 59,925,260 0
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 10 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate T-5: Total Blackstone's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 52 Demand (kW) 20,892 Energy (kWh) 8,474,950 Peak Energy (kWh) 2,007,100 Off-Peak Energy (kWh) 6,467,850 Blackstone's Rate T-5 v. Narragansett's Rate G-02 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 7 7 Demand (kW) 358 288 Energy (kWh) 114,950 114,950 Peak Energy (kWh) 27,650 0 Off-Peak Energy (kWh) 87,300 0 Blackstone's Rate T-5 v. Narragansett's Rate G-32 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 45 45 Demand (kW) 20,534 20,534 Energy (kWh) 8,360,000 8,360,000 Peak Energy (kWh) 1,979,450 0 Off-Peak Energy (kWh) 6,380,550 0 Note: 1. Blackstone's Rate T-5 determinants were apportioned among Narragansett Rates G-02 and G-32 based on the availability provisions of Narragansett's rates. 2. Narragansett's billing demands are estimated based upon Blackstone's Rate T-5 load research data using Narragansett TOU hours. 3. Billing demands used to determine whether a Blackstone Rate T-5 is to be transferred to Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest demand in the previous 11 months less 10 kW. 4. Billing demands used to determine whether a Blackstone Rate T-5 customer is to be transferred to Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11 months, or (4) 10 kW.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 11 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate T-6: Total Blackstone's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 692 Demand (kW) 792,182 Energy (kWh) 369,857,394 Peak Energy (kWh) 78,028,788 Off-Peak Energy (kWh) 291,828,606 Blackstone's Rate T-6 v. Narragansett's Rate G-32 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 656 656 Demand (kW) 682,889 782,155 Energy (kWh) 300,621,894 300,621,894 Peak Energy (kWh) 66,237,289 0 Off-Peak Energy (kWh) 234,384,605 0 Blackstone's Rate T-6 v. Narragansett's Rate G-62 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 36 36 Demand (kW) 109,293 142,198 Energy (kWh) 69,235,500 69,235,500 Peak Energy (kWh) 11,791,499 0 Off-Peak Energy (kWh) 57,444,001 0 Note: 1. Blackstone's Rate T-6 determinants were apportioned among Narragansett Rates G-32 and G-62 based on the availability provisions of Narragansett's rates. 2. Billing demands used to determine whether a Blackstone Rate T-2 customer is to be transferred to Narragansett's Rate G-32 and G-62 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11 months, or (4) 10 kW.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 12 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate A-6 v. Narragansett's Rate B-32 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 48 48 Demand (kW) 31,497 31,497 Energy (kWh) 6,085,455 6,085,455 Peak Energy (kWh) 1,172,792 0 Off-Peak Energy (kWh) 4,912,663 0
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 13 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate H-1: Total Blackstone's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 204 Demand (kW) 0 Energy (kWh) 3,639,022 Blackstone's Rate H-1 v. Narragansett's Rate C-06 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 85 85 Energy (kWh) 225,822 225,822 Blackstone's Rate H-1 v. Narragansett's Rate G-02 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 104 104 Demand (kW) 0 8,848 Energy (kWh) 2,380,400 2,380,400 Blackstone's Rate H-1 v. Narragansett's Rate G-32 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 15 15 Demand (kW) 0 3,845 Energy (kWh) 1,032,800 1,032,800 Note: 1. Blackstone's Rate H-1 determinants were apportioned among Narragansett Rates C-06, G-02 and G-32 based on the availability provisions of Narragansett's rates. 2. Narragansett's billing demands are estimated based upon Blackstone's Rate H-1 load research data using Narragansett TOU hours. 3. Billing demands used to determine whether a Blackstone Rate H-1 is to be transferred to Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest demand in the previous 11 months less 10 kW. 4. Billing demands used to determine whether a Blackstone Rate H-1 customer is to be transferred to Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11 months, or (4) 10 kW.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 14 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate H-2: Total Blackstone's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 964 Demand (kW) 0 Energy (kWh) 2,290,392 Blackstone's Rate H-2 v. Narragansett's Rate C-06 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 940 940 Energy (kWh) 2,034,902 2,034,902 Blackstone's Rate H-2 v. Narragansett's Rate G-02 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 12 12 Demand (kW) 0 0 Energy (kWh) 33,090 33,090 Blackstone's Rate H-2 v. Narragansett's Rate G-32 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 12 12 Demand (kW) 0 2,386 Energy (kWh) 222,400 222,400 Note: 1. Blackstone's Rate H-2 is a supplementary rate. Each customer's Rate H-2 usage was combined with the customer's principal rate usage. Based on the combined usage, revenue for each customer was colculated under both Narragansett's Rates C-06 and G-02. The Blackstone Rate H-2 customers were then transferred to the Narragansett rate producing the lower revenue. 2. The billing determinants for Blackstone's H-2 customers to be transferred to Narragansett's Rate G-32 are identical to the determinants shown in Schedule JJB-2
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 15 of 16 Narragansett Electric Company Blackstone Valley Electric Company Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate W-1: Total Blackstone's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 15,781 Energy (kWh) 3,602,371 Blackstone's Rate W-1 v. Narragansett's Rate A-16 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 15,594 15,594 Energy (kWh) 3,568,998 3,568,998 Blackstone's Rate W-1 v. Narragansett's Rate C-06 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 187 187 Energy (kWh) 33,373 33,373 Blackstone's Rate W-1 v. Narragansett's Rate G-02 Blackstone's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 0 0 Energy (kWh) 0 0 Note: 1. Blackstone's Rate W-1 is a supplementary rate. Each customer's Rate W-1 usage was combined with the customer's principal rate usage. Based on the combined usage, revenue for each customer was colculated under both Narragansett's Rates C-06 and G-02. The Blackstone Rate W-1 customers were then transferred to the Narragansett rate producing the lower revenue.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 3 Page 16 of 16 Narragansett Electric Company Blackstone Valley Electric Company Original Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Blackstone's Rate S-1 Streetlighting Rate Blackstone's Blackstone's Blackstone's Lamp Blackstone's Service & Special Fixture Annual kWh Total Annual Lighting Code Wattage Lumen Size Pole Type Fixture Type Pricing Option Count per Light Energy - ----------------------------------------------------------------------------------------------------------------------------------- Metal Halide 0300-4-120 250 20,000 OH_WoodLine FldLt 5 1,180 5,900 0466-4-120 400 40,000 OH_WoodLine FldLt 28 1,832 51,296 ------ ---------- Total Metal Halide 33 57,196 - ----------------------------------------------------------------------------------------------------------------------------------- Mercury Vapor 0130-2-110 100 4,200 OH_WoodLine StLt 2,279 511 1,164,569 0130-2-211 100 4,200 OH_WoodLitg StLt CustPaidPole 1 511 511 0209-2-110 175 8,600 OH_WoodLine StLt 465 822 382,230 0209-2-140 175 8,600 OH_WoodLine T&C 16 822 13,152 0209-2-211 175 8,600 OH_WoodLitg StLt CustPaidPole 2 822 1,644 0209-2-610 175 8,600 UG_Aluminum StLt 28 822 23,016 0209-2-640 175 8,600 UG_Aluminum T&C 1 822 822 0209-2-940 175 8,600 URD_WoodPost T&C 268 822 220,296 0418-2-612 350 8,600 UG_Aluminum StLt TwinFixts 18 1,644 29,592 0474-2-110 400 22,500 OH_WoodLine StLt 105 1,864 195,720 0474-2-120 400 22,500 OH_WoodLine FldLt 99 1,864 184,536 0474-2-310 400 22,500 OH_Aluminum StLt 3 1,864 5,592 0474-2-320 400 22,500 OH_Aluminum FldLt 2 1,864 3,728 0474-2-610 400 22,500 UG_Aluminum StLt 33 1,864 61,512 0948-2-612 800 22,500 UG_Aluminum StLt TwinFixts 3 3,728 11,184 1135-2-120 1,000 63,000 OH_WoodLine FldLt 23 4,463 102,649 ------ ---------- Total Mercury Vapor 3,346 2,400,753 - ----------------------------------------------------------------------------------------------------------------------------------- Sodium Vapor 0061-3-110 50 3,300 OH_WoodLine StLt 14 240 3,360 0085-3-110 70 5,800 OH_WoodLine StLt 9,055 334 3,024,370 0085-3-120 70 5,800 OH_WoodLine FldLt 9 334 3,006 0085-3-170 70 5,800 OH_WoodLine StLtSC 1,804 334 602,536 0085-3-440 70 5,800 URD_Fiberglass T&C 25 334 8,350 0085-3-710 70 5,800 UG_WoodLitg StLt 1 334 334 0085-3-810 70 5,800 URD_LamWood StLt 38 334 12,692 0085-3-940 70 5,800 URD_WoodPost T&C 104 334 34,736 0121-3-110 100 9,500 OH_WoodLine StLt 1,813 476 862,988 0121-3-140 100 9,500 OH_WoodLine T&C 3 476 1,428 0121-3-170 100 9,500 OH_WoodLine StLtSC 476 476 226,576 0121-3-440 100 9,500 URD_Fiberglass T&C 6 476 2,856 0121-3-460 100 9,500 URD_Fiberglass SBA 26 476 12,376 0121-3-610 100 9,500 UG_Aluminum StLt 95 476 45,220 0121-3-940 100 9,500 URD_WoodPost T&C 30 476 14,280 0176-3-110 150 16,000 OH_WoodLine StLt 30 692 20,760 0176-3-120 150 16,000 OH_WoodLine FldLt 78 692 53,976 0176-3-170 150 16,000 OH_WoodLine StLtSC 1 692 692 0176-3-210 150 16,000 OH_WoodLitg StLt 1 692 692 0176-3-220 150 16,000 OH_WoodLitg FldLt 1 692 692 0176-3-624 150 16,000 UG_Aluminum FldLt AddlFixt 1 692 692 0242-3-612 200 9,500 UG_Aluminum StLt TwinFixts 2 952 1,904 0324-3-110 250 25,000 OH_WoodLine StLt 901 1,274 1,147,874 0324-3-120 250 25,000 OH_WoodLine FldLt 886 1,274 1,128,764 0324-3-170 250 25,000 OH_WoodLine StLtSC 168 1,274 214,032 0324-3-211 250 25,000 OH_WoodLitg StLt CustPaidPole 10 1,274 12,740 0324-3-220 250 25,000 OH_WoodLitg FldLt 7 1,274 8,918 0324-3-221 250 25,000 OH_WoodLitg FldLt CustPaidPole 3 1,274 3,822 0324-3-310 250 25,000 OH_Aluminum StLt 2 1,274 2,548 0324-3-320 250 25,000 OH_Aluminum FldLt 1 1,274 1,274 0324-3-324 250 25,000 OH_Aluminum FldLt AddlFixt 3 1,274 3,822 0324-3-370 250 25,000 OH_Aluminum StLtSC 22 1,274 28,028 0324-3-610 250 25,000 UG_Aluminum StLt 354 1,274 450,996 0324-3-614 250 25,000 UG_Aluminum StLt AddlFixt 4 1,274 5,096 0324-3-620 250 25,000 UG_Aluminum FldLt 18 1,274 22,932 0324-3-624 250 25,000 UG_Aluminum FldLt AddlFixt 1 1,274 1,274 0500-3-110 400 50,000 OH_WoodLine StLt 102 1,966 200,532 0500-3-120 400 50,000 OH_WoodLine FldLt 1,884 1,966 3,703,944 0500-3-210 400 50,000 OH_WoodLitg StLt 1 1,966 1,966 0500-3-220 400 50,000 OH_WoodLitg FldLt 72 1,966 141,552 0500-3-221 400 50,000 OH_WoodLitg FldLt CustPaidPole 32 1,966 62,912 0500-3-310 400 50,000 OH_Aluminum StLt 1 1,966 1,966 0500-3-320 400 50,000 OH_Aluminum FldLt 5 1,966 9,830 0500-3-610 400 50,000 UG_Aluminum StLt 9 1,966 17,694 0500-3-620 400 50,000 UG_Aluminum FldLt 10 1,966 19,660 0500-3-621 400 50,000 UG_Aluminum FldLt CustPaidPole 2 1,966 3,932 0500-3-624 400 50,000 UG_Aluminum FldLt AddlFixt 9 1,966 17,694 0648-3-612 500 25,000 UG_Aluminum StLt TwinFixts 16 2,548 40,768 ------ ---------- Total Sodium Vapor 18,136 12,189,086 - ----------------------------------------------------------------------------------------------------------------------------------- Total Streetlighting 21,515 14,647,035 - -----------------------------------------------------------------------------------------------------------------------------------
Narragansett Electric BVE/Newport Electric R.I.P.U.C. No. ______ Exhibit JJB-4 Exhibit JJB-4 Newport - Billing Determinants
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 1 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate R-1 v. Narragansett's Rate A-16 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 325,773 325,773 Energy (kWh) 167,201,036 167,201,036
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 2 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate R-2 v. Narragansett's Rate A-60 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 4,208 4,208 Energy (kWh) 1,764,819 1,764,819 First 300 kWh 1,055,362 1,055,362 Excess 300 kWh 709,457 709,457
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 3 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate R-4 v. Narragansett's Rate A-32 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 2,504 2,504 Energy (kWh) 7,100,991 7,100,991 Peak Energy (kWh) 1,248,828 0 Off-Peak Energy (KWh) 5,852,163 0
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 4 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate G-1 v. Narragansett's Rate C-06 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 48,861 47,123 Unmetered 1,738 Energy (kWh) 42,449,011 42,449,011
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 5 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate G-2: Total Newport's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 7,645 Demand (kW) 321,720 Energy (kWh) 105,080,586 Newport's Rate G-2 v. Narragansett's Rate C-06 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 1,272 1,272 Demand (kW) 29,206 Energy (kWh) 6,707,011 6,707,011 Newport's Rate G-2 v. Narragansett's Rate G-02 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 6,226 6,226 Demand (kW) 255,636 213,521 Energy (kWh) 85,631,955 85,631,955 Newport's Rate G-2 v. Narragansett's Rate G-32 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 147 147 Demand (kW) 36,878 43,326 Energy (kWh) 12,741,620 12,741,620 Note: 1. For Newport's Rate G-2 customers apportioned to Narragansett's C-06, the revenue for each customer was calculation under both Narragansett's Rate C-06 and G-02. The Newport Rate G-2 customers were then transferred to the Narragansett rate producing the lower revenue.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 6 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate G-5: Total Newport's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 241 Demand (kW) 40,361 Energy (kWh) 15,075,589 Newport's Rate G-5 v. Narragansett's Rate G-02 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 158 158 Demand (kW) 12,834 14,847 Energy (kWh) 4,061,340 4,061,340 Newport's Rate G-5 v. Narragansett's Rate G-32 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 83 83 Demand (kW) 27,527 29,984 Energy (kWh) 11,014,249 11,014,249 Note: 1. Newport's Rate G-5 determinants were apportioned among Narragansett Rates G-02 and G-32 based on the availability provisions of Narragansett's rates. 2. Narragansett,s billing demands are estimated based upon Newport's Rate G-5 load research data using Narragansett TOU hours. 3. Billing demands used to determine whether a Newport Rate G-5 is to be transferred to Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest demand in the previous 11 months less 10 kW. 4. Billing demands used to determine whether a Newport Rate G-5 customer is to be transferred to Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11 months, or (4) 10 kW.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 7 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate T-2: Total Newport's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 156 Demand (kW) 30,327 Energy (kWh) 14,361,960 Peak Energy (kWh) 2,681,420 Off-Peak Energy (kWh) 11,680,540 Newport's Rate T-2 v. Narragansett's Rate G-02 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 84 84 Demand (kW) 11,103 10,263 Energy (kWh) 4,675,660 4,675,660 Peak Energy (kWh) 862,640 0 Off-Peak Energy (kWh) 3,813,020 0 Newport's Rate T-2 v. Narragansett's Rate G-32 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 72 72 Demand (kW) 19,224 20,900 Energy (kWh) 9,686,300 9,686,300 Peak Energy (kWh) 1,818,780 0 Off-Peak Energy (kWh) 7,867,520 0 Note: 1. Newport's Rate T-2 determinants were apportioned among Narragansett Rates G-02 and G-32 based on the availability provisions of Narragansett's rates. 2. Narragansett's billing demands are estimated based upon Newport's Rate T-2 load research data using Narragansett TOU hours. 3. Billing demands used to determine whether a Newport Rate T-2 is to be transferred to Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest demand in the previous 11 months less 10 kW. 4. Billing demands used to determine whether a Newport Rate T-2 customer is to be transferred to Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11 months, or (4) 10 kW.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 8 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate T-4 v. Narragansett's Rate G-32 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 69 69 Demand (kW) 41,467 57,333 Energy (kWh) 18,430,440 18,430,440 Peak Energy (kWh) 3,531,400 0 Off-Peak Energy (kWh) 14,899,040 0
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 9 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate T-5 v. Narragansett's Rate G-32 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 12 12 Demand (kW) 5,375 5,375 Energy (kWh) 2,964,000 2,964,000 Peak Energy (kWh) 531,000 0 Off-Peak Energy (kWh) 2,433,000 0
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 10 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate T-6: Total Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 24 Demand (kW) 50,282 Energy (kWh) 24,547,599 Peak Energy (kWh) 5,171,799 Off-Peak Energy (kWh) 19,375,800 Newport's Rate T-6 v. Narragansett's Rate G-32 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 12 12 Demand (kW) 14,305 15,820 Energy (kWh) 6,958,000 6,958,000 Peak Energy (kWh) 1,417,000 0 Off-Peak Energy (kWh) 5,541,000 0 Newport's Rate T-6 v. Narragansett's Rate G-62 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 12 12 Demand (kW) 35,977 36,233 Energy (kWh) 17,589,599 17,589,599 Peak Energy (kWh) 3,754,799 0 Off-Peak Energy (kWh) 13,834,800 0 Note: 1. Newport's Rate T-6 determinants were apportioned among Narragansett Rates G-32 and G-62 based on the availability provisions of Narragansett's rates. 2. Billing demands used to determine whether a Newport Rate T-2 customer is to be transferred to Narragansett's Rate G-32 and G-62 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11 months, or (4) 10 kW.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 11 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate C-1 v. Narragansett's Rate N-01 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 12 12 Demand (kW) 212,968 212,968 Energy (kWh) 114,919,292 114,919,292 Peak Energy (kWh) 23,608,292 23,608,292 Off-Peak Energy (kWh) 91,311,000 91,311,000
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 12 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate H-1: Total Newport's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 227 Demand (kW) 0 Energy (kWh) 4,908,488 Newport's Rate H-1 v. Narragansett's Rate C-06 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 36 36 Energy (kWh) 146,940 146,940 Newport's Rate H-1 v. Narragansett's Rate G-02 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 179 179 Demand (kW) 0 7,866 Energy (kWh) 3,203,948 3,203,948 Newport's Rate H-1 v. Narragansett's Rate G-32 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 12 12 Demand (kW) 0 5,202 Energy (kWh) 1,557,600 1,557,600 Note: 1. Newport's Rate H-1 determinants were apportioned among Narragansett Rates C-06, G-02 and G-32 based on the availability provisions of Narragansett's rates. 2. Narragansett's billing demands are estimated based upon Newport's Rate H-1 load research data using Narragansett TOU hours. 3. Billing demands used to determine whether a Newport Rate H-1 is to be transferred to Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest demand in the previous 11 months less 10 kW. 4. Billing demands used to determine whether a Newport Rate H-1 customer is to be transferred to Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11 months, or (4) 10 kW.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 13 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate H-2: Total Newport's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 3,865 Demand (kW) 0 Energy (kWh) 5,723,950 Newport's Rate H-2 v. Narragansett's Rate C-06 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 3,752 3,752 Energy (kWh) 4,457,199 4,457,199 Newport's Rate H-2 v. Narragansett's Rate G-02 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 113 113 Demand (kW) 0 5,208 Energy (kWh) 1,266,751 1,266,751 Note: 1. Newport's Rate H-2 is a supplementary rate. Each customer's Rate H-2 usage was combined with the customer's principal rate usage. Based on the combined usage, revenue for each customer was colculated under both Narragansett's Rates C-06 and G-02. The Newport Rate H-2 customers were then transferred to the Narragansett rate producing the lower revenue.
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 14 of 15 Narragansett Electric Company Newport Electric Corporation Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate W-1: Total Newport's Billing Billing Parameter Determinant - ---------------------------------------------------------------------------- Bills 64,408 Energy (kWh) 13,383,268 Newport's Rate W-1 v. Narragansett's Rate A-16 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 63,065 63,065 Energy (kWh) 13,062,846 13,062,846 Newport's Rate W-1 v. Narragansett's Rate C-06 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 1,303 1,303 Energy (kWh) 313,931 313,931 Newport's Rate W-1 v. Narragansett's Rate G-02 Newport's Narragansett's Billing Billing Billing Parameter Determinant Determinant - ------------------------------------------------------------------------------------------------- Bills 40 40 Energy (kWh) 6,491 6,491 Note: 1. Newport's Rate W-1 is a supplementary rate. Each customer's Rate W-1 usage was combined with the customer's principal rate usage. Based on the combined usage, revenue for each customer was colculated under both Narragansett's Rates C-06 and G-02. The Newport Rate W-1 customers were then transferred to the Narragansett rate producing the lower revenue.
C:\JJB\[jjb4.wk4]O Narragansett Electric 08/01/99 BVE/Newport Electric R.I.P.U.C. Docket No. _______ Exhibit JJB - 4 Page 15 of 15 Narragansett Electric Company Newport Electric Corporation Original Apportionment of Company Billing Determinants Year Ending December 31, 1998, Billing Determinants Newport's Rate S-1 Streetlighting Rate Newport's Newport's Newport's Lamp Newport's Service & Special Fixture Annual kWh Total Annual Lighting Code Wattage Lumen Size Pole Type Fixture Type Pricing Option Count per Light Energy - ---------------------------------------------------------------------------------------------------------------------------------- Incandescent 0092-1-110 92 1,000 OH_WoodLine StLt 383 362 138,646 0189-1-110 189 2,500 OH_WoodLine StLt 64 743 47,552 ------ --------- Total Incandescent 447 186,198 - ---------------------------------------------------------------------------------------------------------------------------------- Metal Halide 0300-4-120 250 20,000 OH_WoodLine FldLt 5 1,180 5,900 0466-4-120 400 40,000 OH_WoodLine FldLt 6 1,832 10,992 1080-4-120 1,000 115,000 OH_WoodLine FldLt 37 4,247 157,139 ------ --------- Total Metal Halide 48 174,031 - ---------------------------------------------------------------------------------------------------------------------------------- Mercury Vapor 0130-2-110 100 4,200 OH_WoodLine StLt 2,525 511 1,290,275 0130-2-210 100 4,200 OH_WoodLitg StLt 74 511 37,814 0130-2-441 100 4,200 URD_Fiberglass T&C CustPaidPole 14 511 7,154 0130-2-610 100 4,200 UG_Aluminum StLt 2 511 1,022 0130-2-710 100 4,200 UG_WoodLitg StLt 55 511 28,105 0130-2-711 100 4,200 UG_WoodLitg StLt CustPaidPole 27 511 13,797 0209-2-110 175 8,600 OH_WoodLine StLt 47 822 38,634 0209-2-710 175 8,600 UG_WoodLitg StLt 13 822 10,686 0300-2-110 250 12,100 OH_WoodLine StLt 24 1,180 28,320 0300-2-710 250 12,100 UG_WoodLitg StLt 19 1,180 22,420 0474-2-110 400 22,500 OH_WoodLine StLt 377 1,864 702,728 0474-2-120 400 22,500 OH_WoodLine FldLt 111 1,864 206,904 0474-2-210 400 22,500 OH_WoodLitg StLt 34 1,864 63,376 0474-2-220 400 22,500 OH_WoodLitg FldLt 32 1,864 59,648 0474-2-610 400 22,500 UG_Aluminum StLt 16 1,864 29,824 0474-2-621 400 22,500 UG_Aluminum FldLt CustPaidPole 2 1,864 3,728 0474-2-624 400 22,500 UG_Aluminum FldLt AddlFixt 4 1,864 7,456 0474-2-710 400 22,500 UG_WoodLitg StLt 231 1,864 430,584 0474-2-711 400 22,500 UG_WoodLitg StLt CustPaidPole 1 1,864 1,864 0600-2-712 250 12,100 UG_WoodLitg StLt TwinFixts 6 2,359 14,154 0948-2-612 800 22,500 UG_Aluminum StLt TwinFixts 3 3,728 11,184 0948-2-712 800 22,500 UG_WoodLitg StLt TwinFixts 26 3,728 96,928 1135-2-120 1,000 63,000 OH_WoodLine FldLt 37 4,463 165,131 1135-2-220 1,000 63,000 OH_WoodLitg FldLt 9 4,463 40,167 1135-2-710 1,000 63,000 UG_WoodLitg StLt 7 4,463 31,241 ------ --------- Total Mercury Vapor 3,696 3,343,144 - ---------------------------------------------------------------------------------------------------------------------------------- Sodium Vapor 0085-3-110 70 5,800 OH_WoodLine StLt 642 334 214,428 0085-3-120 70 5,800 OH_WoodLine FldLt 41 334 13,694 0085-3-210 70 5,800 OH_WoodLitg StLt 32 334 10,688 0085-3-211 70 5,800 OH_WoodLitg StLt CustPaidPole 9 334 3,006 0085-3-441 70 5,800 URD_Fiberglass T&C CustPaidPole 247 334 82,498 0085-3-610 70 5,800 UG_Aluminum StLt 14 334 4,676 0085-3-611 70 5,800 UG_Aluminum StLt CustPaidPole 8 334 2,672 0085-3-711 70 5,800 UG_WoodLitg StLt CustPaidPole 78 334 26,052 0121-3-110 100 9,500 OH_WoodLine StLt 7 476 3,332 0324-3-110 250 25,000 OH_WoodLine StLt 188 1,274 239,512 0324-3-120 250 25,000 OH_WoodLine FldLt 269 1,274 342,706 0324-3-210 250 25,000 OH_WoodLitg StLt 6 1,274 7,644 0324-3-211 250 25,000 OH_WoodLitg StLt CustPaidPole 1 1,274 1,274 0324-3-220 250 25,000 OH_WoodLitg FldLt 27 1,274 34,398 0324-3-221 250 25,000 OH_WoodLitg FldLt CustPaidPole 6 1,274 7,644 0324-3-611 250 25,000 UG_Aluminum StLt CustPaidPole 12 1,274 15,288 0324-3-621 250 25,000 UG_Aluminum FldLt CustPaidPole 1 1,274 1,274 0324-3-711 250 25,000 UG_WoodLitg StLt CustPaidPole 24 1,274 30,576 0324-3-720 250 25,000 UG_WoodLitg FldLt 1 1,274 1,274 0500-3-110 400 50,000 OH_WoodLine StLt 12 1,966 23,592 0500-3-120 400 50,000 OH_WoodLine FldLt 349 1,966 686,134 0500-3-210 400 50,000 OH_WoodLitg StLt 2 1,966 3,932 0500-3-220 400 50,000 OH_WoodLitg FldLt 50 1,966 98,300 0500-3-221 400 50,000 OH_WoodLitg FldLt CustPaidPole 4 1,966 7,864 0500-3-624 400 50,000 UG_Aluminum FldLt AddlFixt 1 1,966 1,966 1000-3-613 800 50,000 UG_Aluminum StLt CustPaidTwinFixt 6 3,932 23,592 1000-3-713 800 50,000 UG_WoodLitg StLt CustPaidTwinFixt 6 3,932 23,592 ------ --------- Total Sodium Vapor 2,043 1,911,608 - ---------------------------------------------------------------------------------------------------------------------------------- Total Streetlighting 6,234 5,614,981 - ----------------------------------------------------------------------------------------------------------------------------------
The Narragansett Electric Company, Blackstone Valley Electric Company, and Newport Electric Corporation Rate Plan Filing in Support of Merger Volume 3 Testimony and Exhibits of: David J. Hoffman & Richard J. Levin May, 1999 Submitted to: Rhode Island Public Utilities Commission RIPUC Docket _____ Submitted by: Nees Logo Eastern Utilities Associates Logo STATE OF RHODE ISLAND RHODE ISLAND PUBLIC UTILITIES COMMISSION - ------------------------------ New England Electric System ) ) R.I.P.U.C. Docket __________ Eastern Utilities Associates ) - ------------------------------ DIRECT TESTIMONY OF DAVID J. HOFFMAN AND RICHARD J. LEVIN STATE OF RHODE ISLAND RHODE ISLAND PUBLIC UTILITIES COMMISSION - ------------------------------ New England Electric System ) ) R.I.P.U.C. Docket __________ Eastern Utilities Associates ) - ------------------------------ DIRECT TESTIMONY OF DAVID J. HOFFMAN AND RICHARD J. LEVIN Table of Contents I. Introduction and Qualifications..................................... 1 II. Summary of Testimony................................................ 6 III. Detailed Estimate of Cost Savings................................... 12 A. Summary of Personnel and Non-Personnel Savings............. 12 B. Personnel Savings.......................................... 13 C. Information Systems Savings (Non-Personnel)................ 17 D. Supply Chain Savings (Non-Personnel)....................... 18 E. Facilities Savings (Non-Personnel)......................... 20 F. Administrative and General Savings (Non-Personnel)......... 20 G. Comparison with Other Transactions......................... 24 IV. Detailed Estimate of Cost to Achieve................................ 26
New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 1 of 29 1 I. Introduction and Qualifications 2 Q. Please state your names, current positions and business addresses. 3 A. My name is David J. Hoffman. I am a Vice President with Mercer Management 4 Consulting, Lexington, Massachusetts. 5 6 My name is Richard J. Levin. I am a management consultant with Mercer 7 Management Consulting, Lexington, Massachusetts. 8 9 Q. Mr. Hoffman, please summarize your educational and professional background. 10 A. I received a B.S. degree in finance in 1976 and a MBA degree (with honors) in 11 management information systems in 1980 from Boston University. 12 13 My professional experience includes over 15 years as a consultant to electric and gas 14 utilities. I joined Mercer in 1982 and prior to that, worked for United Information Systems 15 (from 1980 to 1982). 16 17 During my consulting career, I have led a broad range of assignments, encompassing: 18 o Merger and acquisition analysis 19 o Organizational and performance improvement 20 o Strategic and business planning 21 o Information systems strategy 22 Hoffman/Levin - 1 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 2 of 29 1 Q. Mr. Levin, please summarize your educational and professional background. 2 A. I received a B.A. in economics from Washington University in 1972 and an M.A. in 3 economics from The Ohio State University in 1974. In 1977, I received a J.D. degree 4 from Ohio State and was admitted to the Ohio Bar. 5 6 My professional experience includes over nineteen years as a management consultant 7 specializing in the management and regulation of utilities. I joined Mercer in May 1983 8 and, prior to that, worked as an independent consultant (June 1982 through April 1983) and 9 for Booz, Allen & Hamilton, Inc. (April 1979 through May 1982). 10 11 During my consulting career, I have served as a project manager or lead consultant on a 12 broad range of assignments for utilities and regulatory commissions. The subject matter of 13 these assignments has encompassed: 14 o Merger and acquisition analysis 15 o Organizational and performance improvement 16 o Strategic and business planning 17 o Management audits 18 o Rate of return and cost of capital studies 19 o Financial forecasting and planning 20 o Economic and financial feasibility evaluations 21 22 Prior to my consulting career, I was a lecturer at Ohio State in economic theory and 23 corporate finance. I held that position from January 1978 through March 1979. From June 24 1975 to September 1978, I was employed by the Public Utilities Commission of Ohio. From Hoffman/Levin - 2 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 3 of 29 1 1975 to 1977, I served as a financial economist with the Commission's staff and testified on 2 rate of return and financial issues in electric, gas, telephone, and water rate cases. 3 After graduation from law school in 1977, I became a Hearing Examiner for the Commission. 4 My primary responsibilities in that position were presiding over rate and other proceedings, 5 drafting proposed rules, and preparing written orders for the Commission's consideration. 6 7 I have testified before the Massachusetts Department of Public Utilities, the Maine 8 Public Utilities Commission, and the Ohio Public Utilities Commission on the cost 9 of capital. I have also testified before the Maine PUC, New Mexico Public Service 10 Commission, the Iowa State Commerce Commission, the Pennsylvania Public Utility 11 Commission, and the Massachusetts Appellate Tax Board on other regulatory issues. 12 13 Q. Mr. Hoffman and Mr. Levin, please summarize your relevant experience. 14 A. Over the past several years, we have both been actively involved in the merger and 15 acquisitions (M&A) area. This work has included 1) screening and evaluating 16 potential merger candidates, 2) estimating cost savings for approximately 15 17 potential mergers, and 3) assisting utilities in post-merger integration planning. 18 19 We have also been involved in organizational and/or performance improvement work at 20 more than 30 utilities. This work has been done for utility clients and on behalf of 21 regulatory commissions (as part of management audits). This work has included Hoffman/Levin - 3 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 4 of 29 1 organizational design, determining appropriate staffing levels, process redesign, and 2 identifying opportunities to reduce costs. The work has encompassed all aspects of the 3 utility business (generation, transmission, distribution, customer and marketing-related, and 4 A&G functions). With respect specifically to A&G activities, we have both been involved 5 in assignments dealing with the following functions: information services, accounting, 6 human resources, finance and treasury, supply chain management, legal, rates and regulatory 7 affairs, and corporate communication and external affairs. 8 9 Important elements of this work have been benchmarking a particular utility's performance 10 against other companies and understanding the drivers of costs on the overall business and 11 on specific functions. We are also two of the principal authors of Mercer's utility staffing 12 survey. This survey has become an industry standard for evaluating staffing levels; its 13 definition of utility functions and sub-functions is also widely used in merger analysis and 14 testimony. 15 16 Q. Please describe Mercer's experience in working with NEES. 17 A. Mercer Management Consulting has worked extensively with NEES since 1992. Our 18 work with the Company has included the following types of assignments: 19 o Organizational transformation 20 o Process improvement 21 o Business strategy Hoffman/Levin - 4 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 5 of 29 1 o Mergers and acquisitions analysis 2 3 These assignments have encompassed all operating, customer-related, and A&G 4 functions in the operating companies and the service company. 5 6 Mercer's extensive knowledge of NEES management and operations was extremely 7 helpful in discussing integration strategies, identifying cost savings opportunities and 8 ultimately, in developing sound estimates of savings and cost to achieve for the 9 proposed NEES-EUA merger. 10 11 Q. Please describe some of these assignments. 12 A. In 1992 and 1993, Mercer assisted NEES in a major organizational transformation, 13 which included the creation of business units, the alignment and clarification of roles 14 and responsibilities, and a significant streamlining of organizational structure and 15 staffing. In 1993 and 1994, we assisted NEES in developing a customer call center 16 strategy which led to the successful consolidation of Massachusetts Electric's six 17 individual call centers into a single center (the Northboro Customer Service Center). 18 During the 1996-1998 period, Mercer helped NEES in the transition from a fully- 19 integrated utility into a "wires" utility; this particular effort included identifying 20 corporate support services required after the divestiture of generation assets. Hoffman/Levin - 5 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 6 of 29 1 2 Q. In addition to this testimony, has Mercer been retained to assist in other aspects 3 of the proposed NEES-EUA merger? 4 A. Yes. Mercer has been retained to assist in the post-merger integration process. 5 6 II. Summary of Testimony 7 Q. What is the purpose of your testimony? 8 A. We have been asked to describe the analysis conducted to estimate the potential cost 9 savings associated with a merger of the New England Electric System ("NEES") and 10 Eastern Utilities Associates ("EUA"). Mercer Management Consulting (Mercer) 11 assisted NEES and EUA (also referred to as the "Companies") in 1) identifying areas 12 with potential cost saving or cost to achieve, 2) collecting relevant data, 3) 13 developing related operating and financial assumptions, and 4) estimating potential 14 savings and costs. 15 16 This testimony presents the results of the analysis, including: 17 o A summary of results (this section) 18 o A detailed estimate of savings (Section III) 19 o A detailed estimate of cost to achieve (Section IV) 20 Hoffman/Levin - 6 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 7 of 29 1 Exhibit DJH-1 provides a summary of potential merger cost savings for the first 10 2 years (2000-2009) and the cost to achieve. Exhibit DJH-2 contains the non- 3 confidential working papers that support the estimates. Exhibit DJH-3 contains our 4 confidential working papers. 5 6 Q. Please summarize your testimony. 7 A. The planned merger will result in savings that would not otherwise be achieved by 8 the stand-alone operations of NEES (through its Massachusetts Electric, Narragansett 9 Electric, Granite State Electric, Nantucket Electric, and New England Power Service 10 Company subsidiaries) and EUA (through its Eastern Edison, Blackstone Valley 11 Electric, Newport Electric and EUA Service Corporation subsidiaries). Based on 12 information provided by NEES and EUA and the analysis conducted by NEES 13 management and Mercer, merger-related savings were estimated at approximately 14 $31.1 million in 2005, as shown below: Estimated Savings in 2005 Savings Component ($ Millions) Personnel Savings $21.5 Information Systems Savings 0.1 Supply Chain Savings 0.6 Facilities Savings 4.7 Administrative and General Savings 4.2 --- Total Savings 31.1 Hoffman/Levin - 7 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 8 of 29 1 The figures above include merger-related savings related only to the regulated 2 "wires" and A&G-related operations of NEES and EUA. No revenue enhancements 3 were identified for the regulated business. 4 5 Only cost savings that would result from the merger were included in estimated 6 savings. These types of savings are derived from the elimination of duplication, cost 7 avoidance, adoption of different management practices and policies, and the 8 improved utilization of assets and employees. Savings which could be achieved 9 without a merger (e.g., position reductions resulting from a process improvement in 10 one company) were not included in the estimated savings. 11 12 Q. When will the savings commence? 13 A. Savings will begin in 2000 and continue permanently. Exhibit DJH-l presents savings for 14 only the first 10 years (2000-2009). The cost to achieve the merger savings will occur 15 primarily in the 1999-2002 period. 16 17 Q. Could the cost savings discussed above and in detail in Section III be achieved 18 without a merger? 19 A. No. The savings are based upon the elimination of redundancies (in personnel, 20 facilities and other areas) and the gaining of economies brought about by a merger. Hoffman/Levin - 8 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 9 of 29 1 In addition, the savings would not result without incurring the cost to achieve 2 discussed above and in detail in Section IV. 3 4 Q. Please describe the process utilized to estimate merger cost savings and cost to 5 achieve. 6 A. Mercer worked with senior and middle managers at both NEES and EUA to gather 7 the information required to estimate savings and costs. We also met with EUA 8 managers to develop a fuller understanding of the company's business practices, 9 operations, and costs. As discussed earlier, we already had an extensive 10 understanding of NEES business practices, operations, and costs. 11 12 We also worked with NEES management to determine how the merged companies 13 would operate in the future, e.g., the expected level of integration in the A&G, 14 customer-related, and T&D functions. 15 16 Based on information collected and assumptions about now the merged companies 17 would operate, estimates of merger savings and costs were developed, discussed, and 18 refined. The process used to develop the estimated savings and cost to achieve was 19 reasonable, and captured the significant sources of savings available and costs that 20 would be incurred in a merger. Hoffman/Levin - 9 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 10 of 29 1 Q. What assumptions were made in the analysis? 2 A. The following assumptions were made in estimating cost savings: 3 o The combined companies will begin integrated operations on January 1, 2000 4 o The "wires" business will be run with one principal operating company in each 5 state (Massachusetts, Rhode Island, and New Hampshire) and one service 6 company 7 o A high-degree of integration will occur, e.g.: 8 - Financial, accounting, human resources, legal, external affairs, and corporate 9 planning functions will be fully integrated 10 - IS data centers will be consolidated 11 - Call centers will be consolidated 12 - Central T&D planning, engineering, and support will be fully integrated, as 13 will transmission field forces 14 o Annual savings will escalate at a rate of 2.2 percent 15 16 Q. How were capital-related savings calculated? 17 A. Capital-related savings were calculated using a revenue requirement methodology. 18 Under this methodology, for example, a capital deferral or avoidance of $1 million in 19 2000 would not result in a merger savings of $1 million in that year; rather annual 20 savings relating to the fixed charges (cost of capital, depreciation, insurance, and 21 taxes on the $1 million deferral or avoided) are calculated. The revenue 22 requirements methodology reflects the timing of merger savings and how capital or 23 construction-related costs are treated for ratemaking purposes. 24 Hoffman/Levin - 10 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 11 of 29 1 Fixed charge rates for NEES and EUA were estimated and then blended, based on the 2 relative size of the companies. A levelized fixed charge rate of 13.5 percent was 3 used for capital items other than IS-related. A levelized fixed charge rate of 28.6 4 percent was used for IS-related items; the higher rate is due to a more rapid (five-year) 5 depreciation period. 6 7 Q. Is the level of estimated cost savings achievable? 8 A. We believe that the level of savings identified in our study has a high likelihood of 9 achievement. Beyond that level, we are aware that Mr. Jesanis is testifying that he 10 expects the savings to be achieved from the acquisition of EUA will be $35 million per 11 year or more in 2005. We believe that this higher level of savings is likely to be 12 achieved for the following reasons: 13 o NEES management approach: During our previous assignments with NEES, 14 the Company has been very creative and aggressive in identifying opportunities 15 to reduce costs; the early creation of a transition team to facilitate the merger 16 illustrates NEES's aggressive approach to opportunities. 17 o NEES "track record": NEES has successfully addressed many of the same 18 issues that arise in a merger, e.g., designing a streamlined organization, 19 integrating multiple call centers, and optimizing field forces and work out 20 locations. 21 o National Grid-related synergies: Additional synergies are expected to result 22 from the National Grid-NEES merger, e.g., taking advantage of National Grid test 23 practices and financing capabilities. Hoffman/Levin - 11 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 12 of 29 1 o Additional sources of savings: Opportunities may arise which have not been 2 captured in our estimates. These include 1) outsourcing functions (given the 3 greater volume of work for the merged companies); 2) taking advantage of new 4 technologies (given the merged companies greater scale); and 3) achieving 5 longer-term IS savings by avoiding duplicative efforts. 6 7 As such, we agree with Mr. Jesanis that actual savings are likely to exceed our 8 estimated savings. 9 10 III. Detailed Estimate of Cost Savings 11 12 A. Summary of Personnel and Non-Personnel Savings 13 Q. You have estimated merger cost savings of $31.1 million in 2005. Would you 14 define the principal components of cost savings and the estimated savings in 15 each component? 16 A. As illustrated in the table on page 7 of this testimony and in Exhibit DJH-2, savings 17 have been classified into five components: 18 o Personnel savings: related to position reductions in A&G, customer, transmission and 19 distribution, and other functions 20 o Information systems savings (non-personnel): related to integration of applications; 21 mainframe, network, midrange/server, and PC/workstation operations; projects; and 22 telecommunications 23 o Supply chain savings (non-personnel): related to reductions in inventory; lower costs 24 for materials, equipment, and contractor services; and reductions in the number of 25 vehicles Hoffman/Levin - 12 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 13 of 29 1 o Facilities savings (non-personnel): related to the closing of facilities, including 2 office space 3 o Administrative and general savings (non-personnel): related to A&G 4 overheads, advertising, association dues, benefits administration, corporate 5 governance (i.e., shareholder services and board fees), financing costs and fees, 6 insurance, professional services, and regulatory expenses 7 8 The level of estimated savings (in 2005 dollars unless otherwise indicated) and the 9 bases for the estimates are discussed below. 10 11 B. Personnel Savings 12 Q. Please discuss the analysis supporting your personnel savings estimate of $21.5 13 million in 2005. 14 A. Personnel savings were estimated using the following process: 15 o First, staffing levels for NEES and EUA were estimated as of January 1, 2000. 16 Both companies provided detailed organizational and functional breakdowns that 17 assigned each employee to one of the following functions: Hoffman/Levin - 13 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 14 of 29 1 A&G Functions Customer Functions o Purchasing and Material Management (excluding o Retail Marketing and Sales Storeroom Personnel) o Customer Service o Human Resources Electric Transmission and Distribution Functions o Finance, Accounting, and Planning o Electric Distribution o Information Services and Telecommunications o Electric System Technical Support o External Relations o Electric Transmission o Legal o Transportation, Real Estate, and Facilities o Administrative and Support Services (excluding Maintenance Transportation, Real Estate and Facilities Maintenance) o Storeroom Personnel o Executive Management Other o Other Activities 2 3 Within these functions, employees were also assigned to specific sub-functions. 4 For example, within Customer Service, an employee could be assigned to meter 5 reading, customer inquiry, credit and collections, or another sub-function. The 6 complete list of functions and sub-functions used in this analysis is included in 7 the Exhibit DJH-3 working papers. The use of a common format (Mercer's 8 staffing survey function and sub-function classification) allowed for an 9 "apples-to-apples" staffing analysis. 10 o Second, the number of positions that could be eliminated as a result of the merger 11 was estimated. The magnitude of the reduction in each sub-function was based 12 upon identified duplication or redundant activities; the expected degree of 13 integration; potential changes in policies or practices; and any incremental 14 workloads that would result in that area. The number of position reductions in 15 any one sub-function were not allowed to exceed the smaller of the number of 16 positions of either NEES or EUA on a stand-alone basis. For example, if NEES 17 had 15 positions in a sub-function and EUA had 5 positions, the reduction could 18 not exceed 5 positions. Hoffman/Levin - 14 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 15 of 29 1 o Third, an average compensation was calculated for each sub-function and then 2 multiplied by the number of positions reduced in that sub-function. The 3 compensation figures used were the average of NEES and EUA compensation 4 levels. Compensation figures included base compensation (wages or salaries) 5 and benefits. Benefits included such items as pension plans, medical insurance, 6 life insurance, savings (401K) plans, bonuses and incentives, and payroll taxes. 7 The average total compensation (salary and benefits) for positions reduced was 8 $84,900 (in 2000 dollars). 9 10 Q. Please describe the results of the personnel analysis. 11 A. NEES was estimated to have 3,240 positions in utility operations and EUA was 12 estimated to have 869 positions as of January 1, 2000. Total position reductions 13 were estimated at 234, or approximately 6 percent of the 4,109 combined positions. 14 These reductions consist of 88 A&G, 62 customer, 78 T&D, and 6 other function 15 positions, as shown below. Position Reductions ------------------------------------------------------- A&G Customer T&D Other Total NEES Positions 461 722 2,057 0 3,240 EUA Positions 173 201 488 7 869 --- --- --- - --- Combined Positions 634 923 2,545 7 4,109 Estimated Reductions (88) (62) (78) (6) (234) Reduction as a % of 14% 7% 3% 86% 6% Combined Positions Reduction as a % of 51% 31% 16% 86% 27% EUA Positions 16 17 The 234 position reductions also equals 27 percent of EUA's 869 positions. At this 18 point, no decisions have been made as to which reductions will come from current 19 NEES positions or EUA positions. Hoffman/Levin - 15 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 16 of 29 1 2 As shown above, the percentage reductions in the A&G functions are significantly 3 higher than the percentage reductions in the customer and T&D functions. The 4 relative difference reflects the fact that "headquarter" or "office" type functions offer 5 greater opportunities for savings than do "field" functions, such as line maintenance 6 and construction. 7 8 Q. What was the assumed timing of the estimated reduction in positions? 9 A. In the A&G (except for IS), customer, and T&D functions, 75 percent of reductions 10 were assumed to occur in 2000 with the remaining 25 percent occurring in 2001. In 11 the IS area, reductions were assumed to be 0 percent in 2000, 50 percent in 2001, and 12 the remaining 50 percent in 2002. The slower timing of reductions in IS reflects the 13 complicated work required to integrate the two companies' systems. 14 15 Q. How were capital-related personnel savings calculated? 16 A. The percent of payroll savings allocated to capital was 0 percent for the A&G and 17 customer functions and 35 percent for the T&D functions. These rates were based on 18 payroll allocation figures provided by the companies, weighted by their relative sizes. 19 As discussed earlier, capital-related savings were translated into revenue 20 requirements, based on estimated fixed charge rates. 21 Hoffman/Levin - 16 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 17 of 29 1 C. Information Systems Savings (Non-Personnel) 2 Q. Please describe the information systems functions at NEES and EUA. 3 A. NEES information systems operate on an MM mainframe computer, an IBM 4 midrange computer, approximately 60 servers, and approximately 2,500 PCs. 5 Corporate, financial and administrative systems utilize Walker software; HR/payroll 6 will utilize PeopleSoft; and the customer information system was developed 7 in-house. The company also has numerous operational systems running on the 8 midrange and mainframe computers. The NEES data center is located in the 9 Westborough headquarters. 10 11 EUA information systems operate on an Amdahl mainframe computer, 12 approximately 20 servers, and approximately 600 PCs. EUA operates various 13 financial packages; a CYBORG HR/payroll system; a customer information system 14 developed in-house; and numerous operational systems. The EUA data center is 15 located in the West Bridgewater headquarters. 16 17 Q. Please discuss estimated cost savings in the IS area? 18 A. Merger savings were estimated based on two major assumptions: first, that data 19 centers will be consolidated; second, that the combined companies will migrate to 20 NEES applications including Walker, PeopleSoft, and the NEES customer 21 information system. Hoffman/Levin - 17 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 18 of 29 1 2 Most of the savings come from a reduction in personnel, which was discussed earlier. 3 Non-personnel savings relating to the consolidation of data centers are largely offset 4 by the cost of adding computing capacity for combined mainframe and midrange 5 computer operations. In 2005, non-personnel IS savings were estimated at 6 approximately $0.1 million. 7 8 D. Supply Chain Savings (Non-Personnel) 9 Q. What are the potential areas of cost savings in the supply chain area? 10 A. Cost savings in supply chain can potentially occur in the following areas: 11 o A reduction in inventory, based on the consolidation of the companies' 12 storerooms and a sharing of spare parts 13 o Lower prices paid for materials, equipment and contractor services, based on 14 greater purchasing leverage and the potential for more standardization and vendor 15 consolidation 16 o A reduction in the number of vehicles, based on a reduction in the number of 17 field and headquarter positions 18 19 Q. Please discuss the estimated level of savings in supply chain? 20 A. Supply chain-related savings in 2005 of $0.6 million were estimated. 21 Hoffman/Levin - 18 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 19 of 29 1 Inventory savings were $0.1 million of the total. Savings were based on a reduction 2 in fixed charges associated with a 25 percent reduction in EUA's current inventory of 3 $3.6 million. 4 5 Procurement savings on materials and equipment were estimated at $0.3 million in 6 2005. These savings were based on an estimated 3 percent reduction in the cost of 7 EUA's annual purchases of approximately $9.4 million. Merger-related savings for 8 contractor services were minimal, since EUA does not have significant contractor 9 services costs (estimated at $2.4 million for vegetation control and $0.2 million for 10 other services in 1998). In addition, the ability to gain purchasing leverage on 11 contractor services is difficult. 12 13 Vehicle-related savings were estimated at $0.2 million in 2005. Vehicle savings will 14 occur as a result of the reductions in the number of positions. An elimination of 5 15 heavy duty vehicles (due to the reduction of 5 T&D crews) and 10 passenger vehicles 16 (due to the reduction of approximately 90 A&G personnel) were estimated. Savings 17 were based on annual operating and fixed costs of $20,000 per heavy duty vehicle 18 and $5,000 per passenger vehicle. 19 Hoffman/Levin - 19 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 20 of 29 1 E. Facilities Savings (Non-Personnel) 2 Q. Does the merger of NEES and EUA create an opportunity to consolidate 3 facilities? 4 A. Yes. As a result of the NEES-EUA merger, only one headquarters building will be 5 required, since A&G functions will be fully integrated. Based on planned T&D 6 operations, the EUA service centers and work out locations will continue to operate 7 in order to meet customer needs. As a result, no other opportunities to reduce facility 8 costs were identified. 9 Q. What are the estimated facilities-related savings? 10 A. The consolidation of headquarters will provide an estimated savings of $4.7 million 11 in 2005. The savings reflect reductions in both operating expenses (e.g., 12 maintenance and outside services) and capital-related costs. 13 14 F. Administrative and General Savings (Non-Personnel) 15 Q. What are the potential areas of non-personnel savings related to administrative 16 and general functions? 17 A. We identified the following nine potential areas of cost savings: A&G overheads; 18 advertising; association dues; benefits administration; corporate governance (i.e., 19 shareholder services and board-related costs); financial fees; insurance; professional 20 services; and regulatory expenses. 21 Hoffman/Levin - 20 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 21 of 29 1 Q. What level of non-personnel A&G savings were estimated in the merger 2 analysis? 3 A. Savings in 2005 of $4.2 million were estimated. Sources of significant savings 4 included the professional services and corporate governance areas. Savings estimates 5 for each area are discussed below. 6 7 Q. Please discuss estimated savings related to A&G overheads in 2005. 8 A. Estimated A&G overhead-related merger savings of $0.8 million were identified. 9 A&G overheads include expenses for office supplies, publications, personal 10 computers, and other miscellaneous expenses. These types of expenses are often 11 captured in FERC Account 921. 12 13 Using NEES and EUA FERC data and other reports, we estimated overheads at 14 $3,000 per employee (in 2000 dollars). This figure was multiplied by the number of 15 position reductions to estimate annual savings. 16 17 Q. Please discuss estimated savings related to advertising. 18 A. Estimated savings in the advertising area were $0.3 million in 2005. Savings will 19 result from an elimination of duplicative costs, e.g., some media purchases. For this 20 transaction, savings were estimated at 50 percent of EUA's annual, normalized 21 advertising expenses. Hoffman/Levin - 21 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 22 of 29 1 2 Q. Please discuss estimated savings related to association dues. 3 A. Association dues-related savings of $0.1 million in 2005 were identified. Savings 4 were based on lower expenditures for combined membership in the Edison Electric 5 Institute and the termination of membership in other associations. 6 7 Q. Please discuss estimated savings related to benefits administration. 8 A. Estimated merger savings in this area were $0.1 million in 2005. Although total 9 benefit costs for medical, dental, life and other insurance, pensions, and savings 10 plans are significant, the opportunity to reduce costs is very limited. For example, 11 NEES' HMO benefits are self-insured and do not provide an opportunity for savings. 12 13 Q. Please discuss estimated savings related to corporate governance. 14 A. Merger savings related to a reduction in corporate governance costs were estimated 15 at $0.9 million in 2005. Savings related to shareholder services result from the 16 elimination of duplicate activities and costs, such as preparation of the annual 17 shareholders' report and transfer agent fees. Additional savings result from the 18 elimination of director fees and expenses for one company. 19 20 Q. Please discuss estimated savings related to financing costs and fees. Hoffman/Levin - 22 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 23 of 29 1 A. Merger savings in this area were estimated at $0.3 million in 2005, based on a 2 reduction in line of credit fees for the combined company. The savings related to 3 lines of credit are based on a 100 percent elimination of EUA's stand-alone fees. 4 5 Q. Please discuss estimated savings related to insurance. 6 A. Merger-related insurance savings were estimated at $0.7 million in 2005. Savings 7 were based on expected reductions in property and liability coverage premiums (due 8 to reduction in cost per additional dollar of coverage); reductions in directors and 9 officers insurance premiums (due to the elimination of one board of directors); and 10 reductions in brokerage fees (due to the consolidation of insurance purchasing). 11 12 Q. Please discuss estimated savings related to professional services. 13 A. Merger-related savings for professional services were estimated at $1.0 million in 14 2005. Professional services savings result from the elimination of duplicative efforts 15 in areas such as external auditing, legal support, legislative services, and general 16 consulting. The savings were based on an approximate 40 percent reduction in 17 EUA's stand-alone annual professional services costs. 18 19 Q. Please discuss estimated savings related to regulatory expenses. Hoffman/Levin - 23 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 24 of 29 1 A. Merger-related savings for regulatory expenses were estimated at $0.1 million in 2 2005. Savings (non-personnel) in this area are relatively small, since annual 3 assessments (the largest component of costs) are not likely to be reduced when the 4 two companies merge. The savings estimate is based on a 20 percent reduction in 5 EUA's annual reporting, filing, and miscellaneous expenses of approximately $0.3 6 million, to reflect the elimination of some duplication and gains from integrating 7 regulatory affairs management. 8 9 G. Comparison with Other Transactions 10 Q. Did you compare the NEES-EUA merger to other transactions? 11 A. Yes. We reviewed a number of transactions, including the BEC Energy-COM/Energy 12 merger. 13 14 The 6 percent reduction in positions for the NEES-EUA merger falls in the 3 percent- 15 11 percent range for other transactions that we reviewed. We would not expect the 16 NFES-EUA percentage reductions to be at the high end of the range given the 17 significant difference in staffing levels between NEES and EUA (NEES has 3.7 18 times the staffing of EUA). In the other transactions, the ratio of employees for the 19 merger partners is typically in the 1 to 2 times range, which creates the potential for 20 higher percentage savings. 21 Hoffman/Levin - 24 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 25 of 29 1 Q. Why did you conclude that the NEES-EUA merger has a more limited 2 opportunity to reduce costs? 3 A. First, NEES and EUA are relatively "lean" utilities. This limits the ability to reduce 4 staffing (the largest source of savings) in a merger situation. 5 6 For example, NEES and EUA were estimated to have a combined pre-merger staffing of 7 4,109 or 2.5 employees per thousand customers (based on a total of 1.66 million 8 customers). The comparable figures for BEC Energy and COM/Energy are combined 9 pre-merger staffing of 3,338 or 3.2 employees per thousand customers (based on a 10 total of 1.04 electric customers). Based on estimated position reductions in each 11 transaction, post-merger NEES-EUA will have 2.3 employees per thousand customers 12 compared to 2.9 employees per thousand customers for post-merger BEC 13 Energy-CONI/Energy. 14 15 Second, EUA has a relatively small cost base. For example, in 1997, combined T&D, 16 customer (excluding demand-side management) and A&G-related expenses were $77 17 million. COM/Energy's expenses were $116 million for the same electric functions and 18 $147 million if gas-related A&G expenses are included. Again, the lower cost base 19 limits the potential savings. 20 21 Q. Please summarize this section of your testimony. Hoffman/Levin - 25 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 26 of 29 1 A. Merger cost savings of $31.1 million in 2005 were estimated. Approximately 70 2 percent of savings ($21.5 million) were personnel-related. The savings are based 3 upon an assumed merger of NEES and EUA and would not result otherwise. 4 5 IV. Detailed Estimate of Cost to Achieve 6 Q. What types of costs are incurred when two companies merge? 7 A. Costs fall into the following four categories: 8 o Transaction costs: primarily the fees paid to investment bankers for advice on 9 the merger transaction and to outside legal counsel for advice on the merger 10 transaction and support in regulatory proceedings 11 o Personnel costs: primarily the out-of-pocket costs incurred to achieve the 12 reduction in positions, e.g., early retirement/severance packages; other costs 13 include retention payments to employees deemed necessary for a successful 14 integration, as well as relocation and retraining costs 15 o Transition costs: the costs incurred to integrate the two companies, e.g., 16 support for organizational redesign and process integration; communication 17 costs; and costs related to the closing of facilities 18 o Information systems costs: the costs associated with integrating systems, 19 consolidating data centers, creating a common meter reading standard, and 20 connecting telecommunication networks 21 22 Q. How were these costs estimated for the potential merger of NEES and EUA? Hoffman/Levin - 26 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 27 of 29 1 A. Banker and legal fees were estimated by NEES and EUA management. Other 2 estimated costs to achieve were based on information provided by NEES and EUA 3 and on discussions with NEES management concerning the degree of integration 4 expected, planned corporate policies, and the resulting integration requirements. 5 This process addressed all significant costs to achieve. 6 7 Q. Please summarize the estimated cost to achieve for the merger. 8 A. The cost to achieve was estimated at $63.6 million - approximately $11.4 million for 9 transaction costs, $40.1 million for personnel costs; $4.6 million for transition costs, 10 and $7.6 million for information systems costs. Details are provided in Exhibits 11 DJH-1 and 2 and below. Approximately 85 percent of the costs will be incurred in 12 the 1999-2000 period. 13 14 Q. Please discuss the estimated transaction costs of approximately $11.4 million. 15 A. The primary transaction costs are for merger assistance provided by investment 16 bankers and merger and regulatory assistance from outside counsel. These costs 17 were estimated by NEES and EUA at $7.5 million for banker fees and $3.5 million 18 for legal fees. The other transaction cost included is for director and officer tail 19 liability coverage ($0.4 million). 20 Hoffman/Levin - 27 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 28 of 29 1 Q. Please discuss the estimated personnel costs of approximately $40.1 million. 2 A. The most significant personnel costs incurred in a merger are related to achieving 3 targeted reductions in the workforce. 4 5 Separation and retention costs were estimated at $35.2 million. These costs include 6 payments te employees for early retirement, severance and/or other separation 7 packages; payments to executives other than EUA parent company, generation-related, 8 and unregulated business executives; and retention of key employees. 9 10 Other costs were estimated at $5 million. These costs include estimated relocation 11 and miscellaneous costs ($2.8 million) and estimated retraining and reorientation 12 costs for customer services, T&D, and administrative personnel to learn about future 13 work processes, as well as company policies and practices ($2.2 million). 14 Hoffman/Levin - 28 - New England Electric System Eastern Utilities Associates Testimony of D. J. Hoffman and R. J. Levin Page 29 of 29 1 Q. Please discuss the estimated transition costs of $4.6 million. 2 A. Transition costs are costs incurred to integrate the separate operations of the two 3 companies. Estimated costs for the NEES-EUA merger included $2.0 million for 4 outside organizational and change management support; $0.8 million for internal 5 process integration teams; $0.5 million for communications about the merger and 6 integration process to employees and external parties, e.g., shareholders, regulatory 7 commissions, vendors, and the investment community; $1.0 million for the closing 8 of some facilities and for the reconfiguration of other facilities; and $0.3 million for 9 changes to corporate signage and stationary. 10 11 Q. Please discuss the estimated information systems costs of $7.6 million. 12 A. The most significant IS cost was an estimated $6.6 million for applications 13 integration, data conversion, and the consolidation of data centers. Other costs 14 included $0.6 million to outfit EUA meter readers with NEES-standard meter 15 reading devices; and $0.4 million to link the two telecommunications networks and 16 to reconfigure/reprogram customer service center switches. 17 18 Q. Does this conclude your testimony? 19 A. Yes, it does. Hoffman/Levin - 29 -
New England Electric System Eastern Utilities Associates R.I.P.U.C. Docket _____ EXHIBITS OF DAVID J. HOFFMAN & RICHARD J. LEVIN Exhibit DJH-1 Summary of Savings and Cost to Achieve Exhibit DJH-2 Supporting Working Papers Exhibit DJH-3 Supporting Working Papers (Confidential) Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket _____ Exhibit DJH-1 Exhibit DJH-1 Summary of Savings and Cost to Achieve
Exhibit DJH-1 Savings Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Personnel 12,365 17,846 19,326 20,040 20,771 21,517 22,279 23,059 23,855 24,669 205,728 Non-Personnel Information Systems 17 34 52 53 55 56 57 58 60 61 502 Supply Chain 247 513 539 566 594 622 651 680 710 741 5,862 Facilities - 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001 Administrative and General 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359 ------------------------------------------------------------------------------------------------------- Total Savings 16,137 26,442 28,224 29,149 30,095 31,061 32,049 33,059 34,090 35,145 295,452 Cost to Achieve 54,060 8,350 1,200 - - - - - - - 63,610 ------------------------------------------------------------------------------------------------------- Net Savings (37,923) 18,092 27,024 29,149 30,095 31,061 32,049 33,059 34,090 35,145 231,842 Confidential Page 1 of 13
NEES-EUA Savings Summary Personnel Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total A&G Personnel % Capitalized 0% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized--- IS 0% 50% 100% 100% 100% 100% 100% 100% 100% 100% % Realized---Other 75% 100% 100% 100% 100% 100% 100% 100% 100% 100% Reductions ---------- Ongong savings - IS 1,528 18 Ongoing savings - Other 6,680 70 Total Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719 O&M Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719 1 Capital Savings - - - - - - - - - - 2 - - - - - - - - - 3 - - - - - - - - 4 - - - - - - - 5 - - - - - - 6 - - - - - 7 - - - - 8 - - - 9 - - 10 - -------------------------------------------------------------------------------------------------------- Total Capital Savings - - - - - - - - - - - Rev Req Savings - - - - - - - - - - - -------------------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719 Confidential Page 2 of 13
NEES-EUA Savings Summary 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Customer Related Personnel % Capitalized 0% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100% Reductions Ongoing savings 4,930 62 Total Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242 O&M Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242 1 Capital Savings - - - - - - - - - - 2 - - - - - - - - - 3 - - - - - - - - 4 - - - - - - - 5 - - - - - - 6 - - - - - 7 - - - - 8 - - - 9 - - 10 - Total Capital Savings - - - - - - - - - - - Rev Req Savings - - - - - - - - - - - Total O&M + Rev Req Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242 Confidential Page 3 of 13
NEES-EUA Savings Summary 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total T&D Personnel % Capitalized 35% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100% Reductions Ongoing savings 6,088 78 Total Savings 4,566 6,222 6,359 6,499 6,642 6,788 6,938 7,090 7,246 7,406 65,757 O&M Savings 2,968 4,045 4,133 4,224 4,317 4,412 4,509 4,609 4,710 4,814 42,742 1 Capital Savings 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598 2 2,178 2,178 2,178 2,178 2,178 2,178 2,178 2,178 2,178 3 2,226 2,226 2,226 2,226 2,226 2,226 2,226 2,226 4 2,275 2,275 2,275 2,275 2,275 2,275 2,275 5 2,325 2,325 2,325 2,325 2,325 2,325 6 2,376 2,376 2,376 2,376 2,376 7 2,428 2,428 2,428 2,428 8 2,482 2,482 2,482 9 2,536 2,536 10 2,592 -------------------------------------------------------------------------------------------------------- Total Capital Savings 1,598 3,776 6,002 8,276 10,601 12,977 15,405 17,887 20,423 23,015 119,961 Rev Req Savings 216 510 810 1,117 1,431.16 1,752 2,080 2,415 2,757 3,107 16,195 -------------------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 3,184 4,554 4,944 5,342 5,749 6,164 6,589 7,023 7,467 7,921 58,937 Confidential Page 4 of 13
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Other Personnel % Capitalized 0% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100% Reductions Ongoing savings 632 6 Total Savings 474 646 661 675 690 705 721 737 753 769 6,831 O&M Savings 474 646 661 675 690 705 721 737 753 769 6,831 1 Capital Savings - - - - - - - - - - 2 - - - - - - - - - 3 - - - - - - - - 4 - - - - - - - 5 - - - - - - 6 - - - - - 7 - - - - 8 - - - 9 - - 10 - -------------------------------------------------------------------------------------------------------- Total Capital Savings - - - - - - - - - - - Rev Req Savings - - - - - - - - - - - -------------------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 474 646 661 675 690 705 721 737 753 769 6,831 Total Personnel Savings A&G 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719 Customer-Related 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242 T&D 3,184 4,554 4,944 5,342 5,749 6,164 6,589 7,023 7,467 7,921 58,937 Other 474 646 661 675 690 705 721 737 753 769 6,831 -------------------------------------------------------------------------------------------------------- Total 12,365 17,846 19,326 20,040 20,771 21,517 22,279 23,059 23,855 24,669 205,728 Confidential Page 5 of 13
NEES-EUA Savings Summary IS Savings Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Rev Req Rate 28.6% Total Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 33% 67% 100% 100% 100% 100% 100% 100% 100% 100% O&M Savings A&G Applications - - - - - - - - - - - T&D Applications - - - - - - - - - - - Customer Applications - - - - - - - - - - - Mainframe and Network 17 34 52 53 55 56 57 58 60 61 502 Midrange/Servers - - - - - - - - - - - PC/Workstations - - - - - - - - - - - Projects - - - - - - - - - - - Telecommunications - - - - - - - - - - - - ----------------------------------------------------------------------------------------------------------------------------------- Total O&M Savings 17 34 52 53 55 56 57 58 60 61 502 Capital Savings A&G Applications T&D Applications Customer Applications Mainframe and Network Midrange/Servers PC/Workstations Projects (PeopleSoft) - - Telecommunications Total Capital Savings - - - - - - - - - - - 1 Capital Savings - - - - - 2 - - - - - 3 - - - - - 4 - - - - - 5 - - - - - 6 - - - - - 7 - - - - 8 - - - 9 - - 10 - -------------------------------------------------------------------------------------------------------- Total Capital Savings - - - - - - - - - - - Rev Req Savings - - - - - - - - - - - -------------------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 17 34 52 53 55 56 57 58 60 61 502 Confidential Page 6 of 13
NEES-EUA Savings Summary Supply Chain Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Inventory % Capitalized 100% Carrying Cost 13.7% Total Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100% Inventory Reduction 899 Annual Savings 450 919 939 960 981 1,002 1,024 1,047 1,070 1,093 9,485 O&M Savings 0 0 0 0 0 0 0 0 0 0 0 Capital Savings 450 919 939 960 981 1,002 1,024 1,047 1,070 1,093 9,485 Rev Req Savings 62 126 129 131 134 137 140 143 147 150 1,299 ----------------------------------------------------------------------------------------------- O&M +Rev Req Savings 62 126 129 131 134 137 140 143 147 150 1,299 Confidential Page 7 of 13
NEES-EUA Savings Summary 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Procurement % Capitalized 35% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100% Ongoing savings 290 Total Savings 145 296 303 310 316 323 330 338 345 353 3,060 O&M Savings 94 193 197 201 206 210 215 220 224 229 1,989 1 Capital Savings 51 51 51 51 51 51 51 51 51 51 2 104 104 104 104 104 104 104 104 104 3 106 106 106 106 106 106 106 106 4 108 108 108 108 108 108 108 5 111 111 111 111 111 111 6 113 113 113 113 113 7 116 116 116 116 8 118 118 118 9 121 121 10 123 ----------------------------------------------------------------------------------------------- Total Capital Savings 51 154 260 369 480 593 708 827 947 1,071 5,460 Rev Req Savings 7 21 35 50 65 80 96 112 128 145 737 ----------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 101 214 232 251 270 290 310 331 352 374 2,726 Confidential Page 8 of 13
NEES-EUA Savings Summary 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Contractor Services % Capitalized 35% Rev Req Rate 13.5% Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100% Ongoing savings 27 Total Savings 14 28 28 29 29 30 31 31 32 33 285 O&M Savings 9 18 18 19 19 20 20 20 21 21 185 1 Capital Savings 5 5 5 5 5 5 5 5 5 5 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 Total Capital Savings 5 14 24 34 45 55 66 77 88 100 508 Rev Req Savings 1 2 3 5 6 7 9 10 12 13 69 Total O&M + Rev Req Savings 9 20 22 23 25 27 29 31 33 35 254 Confidential Page 9 of 13
NEES-EUA Savings Summary 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Vehicles % Capitalized 0% Rev Req Rate 13.5% Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% % Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100% Ongoing savings 150 Total Savings 75 153 157 160 164 167 171 175 179 182 1,583 O&M Savings 75 153 157 160 164 167 171 175 179 182 1,583 1 Capital Savings 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 0 3 0 0 0 0 0 0 0 0 4 0 0 0 0 0 0 0 5 0 0 0 0 0 0 6 0 0 0 0 0 7 0 0 0 0 8 0 0 0 9 0 0 10 0 ----------------------------------------------------------------------------------------------- Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0 Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0 ----------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 75 153 157 160 164 167 171 175 179 182 1,583 Total SCM Savings Inventory 62 126 129 131 134 137 140 143 147 150 1,299 Procurement 101 214 232 251 270 290 310 331 352 374 2,726 Contractor Services 9 20 22 23 25 27 29 31 33 35 254 Vehicles 75 153 157 160 164 167 171 175 179 182 1,583 ----------------------------------------------------------------------------------------------- Total 247 513 539 566 594 622 651 680 710 741 5,862 Confidential Page 10 of 13
NEES-EUA Savings Summary Facilities Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total % Capitalized 0% Rev Req Rate 13.5% Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% Phase-in 0% 100% 100% 100% 100% 100% 100% 100% 100% 100% Ongoing Savings 4,179 Total Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001 O&M Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001 1 Capital Savings 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 0 3 0 0 0 0 0 0 0 0 4 0 0 0 0 0 0 0 5 0 0 0 0 0 0 6 0 0 0 0 0 7 0 0 0 0 8 0 0 0 9 0 0 10 0 ----------------------------------------------------------------------------------------------- Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0 Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0 ----------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001 Confidential Page 11 of 13
NEES-EUA Savings Summary Non-Labor A&G Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total % Capitalized 0% Rev Req Rate 13.5% Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6% A&G Overheads 486 690 733 749 766 783 800 818 835 854 7,514 Advertising 273 279 285 291 298 304 311 318 325 332 3,017 Association Dues 82 84 86 88 89 91 93 95 98 100 906 Benefits Administration 0 0 52 53 55 56 57 58 60 61 451 Corporate Governance 787 804 822 840 859 877 897 916 937 957 8,697 Financing Costs and Fees 272 278 284 290 297 303 310 317 324 331 3,006 Insurance 646 660 675 690 705 720 736 752 769 786 7,139 Professional Services 905 925 945 966 987 1,009 1,031 1,054 1,077 1,101 10,001 Regulatory Expenses 57 58 60 61 62 64 65 66 68 69 630 Total Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359 O&M Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359 1 Capital Savings 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 0 3 0 0 0 0 0 0 0 0 4 0 0 0 0 0 0 0 5 0 0 0 0 0 0 6 0 0 0 0 0 7 0 0 0 0 8 0 0 0 9 0 0 10 0 ----------------------------------------------------------------------------------------------- Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0 Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0 ----------------------------------------------------------------------------------------------- Total O&M + Rev Req Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359 Confidential Page 12 of 13
NEES-EUA Savings Summary Cost to Achieve Summary in $000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total Transaction Costs Bankers fees 7,500 7,500 Legal fees 3,500 3,500 D&O liability tail coverage 400 400 Total Transaction Costs 11,400 - - 11,400 Personnel Costs Separation / Retention 25,850 8,100 1,200 35,150 Relocation, Retraining, Reorientation and Miscellaneous 4,950 4,950 Total Personnel Costs 30,800 8,100 1,200 40,100 Transition Costs Internal/Outside Support 2,810 2,810 Communications 500 500 Facilities Consolidation 750 250 1,000 Other 250 250 Total Transition Costs 4,310 250 - 4,560 Information Systems Systems Integration and Data Center Consolidation 6,600 6,600 Meter Reading Hardware 600 600 Telecommunications Costs 350 350 Total Information Systems Costs 7,550 7,550 Total Cost to Achieve 54,060 8,350 1,200 63,610 Confidential Page 13 of 13
Narragansett Electric BVE/Newport Electric R.I.P.U.C. Docket _____ Exhibit DJH-2 Exhibit DJH-2 Supporting Working Papers (Non-Confidential) Exhibit DJH-2 Information Systems Savings
Software comparisons Confidential - ---------------------------------------------------------------------------------------------------------------------- Application NEES EUA Comments - ---------------------------------------------------------------------------------------------------------------------- Corporate, Financial, and o Walker o Various financial packages Administrative Systems - Significant programming/ - IVIS (AP, 1993, Y2K customization has upgrade scheduled improved speed 1Q99) - Works well for NEES' - GEAC (Fixed assets, 1988) business model (intracompany billing, etc.) - Limited decision support - In-house S/W (Purchasing/ capabilities Materials Mgmt, 1992) - Expandable for similar - Lawson (General Ledger, 12/98) business model o Focus for 1999 on Y2K upgrades - ----------------------------------------------------------------------------------------------------------------------- HR/Payroll o PeopleSoft o CYBORG - Installation complete in - Y2K upgrade in 1999 early 1999 - Expandable, but license may be restrictive - ----------------------------------------------------------------------------------------------------------------------- 2 Software comparisons Confidential - ----------------------------------------------------------------------------------------------------------------------- Application NEES EUA Comments - ----------------------------------------------------------------------------------------------------------------------- Customer System o CIS - developed in-house o CIS - developed in-house - GUI front-end placed - GUI front-end placed on mainframe system on mainframe system - Expandable, but only - Major upgrade 1997 for one dimensional (e.g., electric only) - Integrated with Radix customers hand-held meter reading devices - ----------------------------------------------------------------------------------------------------------------------- Operational Systems o Numerous o Numerous - Many systems running - Many systems running on midrange and on mainframe mainframe - Intergraph digital - Major GIS system topology mapping implementation half system complete - Map-based trouble reporting system - -----------------------------------------------------------------------------------------------------------------------
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Hardware comparisons Confidential - ----------------------------------------------------------------------------------------------------------------------- Device NEES EUA - ----------------------------------------------------------------------------------------------------------------------- Mainframes o IBM 390 SP; CMOS 4 engines 220 o Amdahl 45 MIPS MIPS - Expandable up to 540-600 MIPS - ----------------------------------------------------------------------------------------------------------------------- Midrange o IBM RS6000 - Runs decision support, PeopleSoft and retail applications - ----------------------------------------------------------------------------------------------------------------------- Servers o DEC alpha and IBM AIX o Sun (Unix) o Few Digital VAXes left - ~60 o Compaq, Gateway o Migrating to NT o Approximately 20 servers total - ----------------------------------------------------------------------------------------------------------------------- PCs o 2500 Pentium PCs o 600 Pentium PCs (Gateway, Compaq) o Additional 400 devices o 150 "Dumb" terminals - -----------------------------------------------------------------------------------------------------------------------
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System environment comparisons Confidential - ----------------------------------------------------------------------------------------------------------------------- Device NEES EUA - ----------------------------------------------------------------------------------------------------------------------- Mainframes o VMS, IMS, CICS, DB2 o VMS, CICS, Sybase - ----------------------------------------------------------------------------------------------------------------------- Servers o Unix (primary), NT (becoming o Unix, NT (becoming standard standard) - ----------------------------------------------------------------------------------------------------------------------- Networks o Novell 4.11 o Eliminate TAO e-mail and standardize on MS-Outlook (MS-Exchange-based) - Considering 5.0 o Ethernet 100% - ----------------------------------------------------------------------------------------------------------------------- PCs o Windows 3.1, 95, NT o MS Office - Standard is 95 for A&G positions - Standard is NT for operations positions - -----------------------------------------------------------------------------------------------------------------------
5
Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Savings opportunities - ----------------------------------------------------------------------------------------------------------------------------------- Area Opportunity Savings Assumptions Savings - ----------------------------------------------------------------------------------------------------------------------------------- Applications o Corporate, financial, administrative systems: - Integrate EUA data into Walker - No incremental license fees for -> NEES - Discontinue EUA's financial - Reduce 1/3 of EUA's financial - 3 positions systems applications support positions - Move data onto NEES' - Reduce 100% of EUA's HR and - 1 position PeopleSoft system payroll applications support - Disconue EIA's CYBORG -> positions HR and payroll system ---------------------------------------------------------------------------------------------------------- o Customer and related systems: - Integrate EUA call center - Reduce 1/3 of EUA's call center - 3 positions application into NEES' system -> applications support positions - Discontinue EUA's CIS systems ---------------------------------------------------------------------------------------------------------- o T&D systems: - Migrate EUA's work -> - Reduce 1/3 of EUA's T&D - 3 positions management system to NEES' applications support positions WIN system - Migrate topological info from EUA's Intergraph into NEGIS and re-digitize if appropriate - Discontinue EUA's T&D systems - ----------------------------------------------------------------------------------------------------------------------------------- 6 Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Savings opportunities - ----------------------------------------------------------------------------------------------------------------------------------- Area Opportunity Savings Assumptions Savings - ----------------------------------------------------------------------------------------------------------------------------------- Hardware/System o Data center/mainframe: Software - Close EUA's data center -> - Reduce EUA's data center and - 5 positions tech support positions by 50% - Reduce EUA's associated $2M - $1M non-labor IS cost for mainframe maintenance, S/W licenses, and disaster recovery by $1M; remaining $1M to focus on software licenses and support ---------------------------------------------------------------------------------------------------------- o Midrange system: - - - - - ---------------------------------------------------------------------------------------------------------- o Servers/network: - - - ---------------------------------------------------------------------------------------------------------- o PCs/workstations: - Reduce end-user/help desk -> - Reduce EUA's help desk/end - 1 position support staff user support by 20% - ----------------------------------------------------------------------------------------------------------------------------------- 7 Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Savings opportunities - ----------------------------------------------------------------------------------------------------------------------------------- Area Opportunity Savings Assumptions Savings - ----------------------------------------------------------------------------------------------------------------------------------- Telecommunications o Integrates NEES's and EUA's -> - Reduce 15% of EUA's network - 1 position telecommunications networks support positions - ----------------------------------------------------------------------------------------------------------------------------------- Facilities o Cost savings captured in the -> - Cost savings captured in closing of West Bridgewater; IS Facilities section is a portion o Integrate EUA's bill printing, -> - Cost avoidance of outsourcing - $250K stuffing, and mailing operations bill printing, stuffing, and into NEES' operations mailing (one additional resource required is already reflected in office services) - -----------------------------------------------------------------------------------------------------------------------------------
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Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Cost to achieve - ----------------------------------------------------------------------------------------------------------------------------------- Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost - ----------------------------------------------------------------------------------------------------------------------------------- Applications o Corporate, financial, administrative systems: - System "combination" costs -> - Cost for application and - $2.1 M1 data conversion --------------------------------------------------------------------------------------------------------------- o Customer and related systems: - System "combination" costs -> - Cost for application and - $2.1M1 data conversion - Outfit meter readers with -> - 55 devices @$10,000 each - $0.6M ITRON devices (including device, training, programming, transfer of routing info) --------------------------------------------------------------------------------------------------------------- o T&D systems: - System "combination" costs -> - Cost for application and - $2.1M1 data conversion - ----------------------------------------------------------------------------------------------------------------------------------- - --------------- 1 Prorated from base of $6.3M. 9 Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Cost to achieve - ----------------------------------------------------------------------------------------------------------------------------------- Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost - ----------------------------------------------------------------------------------------------------------------------------------- Hardware/System o Data center/mainframe: Software - Discontinuation of EUA -> - Closing cost -$0.3M data center - Increase NEES' processing -> - Turn up 2 additional - - $1.0M power CMOS enginees (cost of H/W & S/W) --------------------------------------------------------------------------------------------------------------- o Midrange system: - Transfer midrange -> - Turn up 2 additional - - $0.2M application to NEES nodes of IBM RS6000 midrange system --------------------------------------------------------------------------------------------------------------- o Servers/networks: - Network reconfiguration -> - - - --------------------------------------------------------------------------------------------------------------- o PCs/workstations: - No costs incurred -> - Freed-up PCs available to - - replace dumb terminals - ----------------------------------------------------------------------------------------------------------------------------------- 10 Information systems and telecommunications Confidential - ----------------------------------------------------------------------------------------------------------------------------------- Cost to achieve - ----------------------------------------------------------------------------------------------------------------------------------- Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost - ----------------------------------------------------------------------------------------------------------------------------------- Telecommunications o Costs to integrate both companies' - $100K networks o Customer service center switch: - Switch capacity sufficient - $250K Cost to reconfigure EUA's tie-lines to handle EUA's and reprogram switch additional inbound calls - ----------------------------------------------------------------------------------------------------------------------------------- Facilities o Costs are captured in the closing of West Bridgewater facility - -----------------------------------------------------------------------------------------------------------------------------------
11 Purchases 35 1 12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 35 Annual materials and equipment purchases by commodity class a) T&D related b) Corporate and other See attached. ADDRL #35 35 2 N35 Annual materials and equipment purchases by commodity class, T&D Issues from M&S Total T&D Corp. & Stock, Cap,&Exp. Purchases Other Blackstone Valley 990,780 442,254 1,433,034 195,459 Eastern Edison 2,404,158 840,142 3,244,300 377,438 Newport Electric 604,470 187,815 792,285 101,099 -------------------------------------------------- 3,999,408 1,470,211 5,469,619 673,996 ========= ======= Meters 998,000 Transformers 2,249,000 Inputs
EUA DISTRIBUTION COMPANIES & MONTAUP TRANSMISSION 1999 Capital Budget BVE EECo NECo VEC Blankets: Priority Priority Req 1999 1999 Cumm Distrib Transm No Code No Title Expenditures Expenditures OH Lines UG Substation OH Lines 1 1-99 New Business $4,484.0 $ 4,484.0 30,400 11,500 0 0 2 2-99 Routine Distribution Imps/Rets 2,445.0 6,929.0 20,900 2,060 0 0 3 3-99 Meter Devices & Installations 998.0 7,927.0 0 0 0 0 4 4-99 Line Transf Capacitors & Regs 2,249.0 10,176.0 0 0 0 0 5 5-99 Distribution Substations 235.0 10,411.0 67 0 1,634 0 6 6-99 Street & Area Lighting 786.9 11,197.9 5,960 1,090 0 0 7 7-99 Building Imps/Rets 108.1 11,306.0 0 0 0 0 8 8-99 Transmission Lines & Subs 388.0 11,694.0 400 0 0 45000 9 9-99 Damages and/or Failures 534.0 12,228.0 4,750 2,192 0 0 10 10-99 Furniture, Tools, Lab & Comm 263.9 12,491.9 0 0 0 0 Equip 11 12-99 Land & Land Rights 90.0 12,581.9 0 0 0 0 12 13-99 Misc. Production Imps/Rets 0.0 12,581.9 0 0 0 0 Blanket Subtotal $12,581.9 62,477 16,842 1,634 4,500 Specifics: General Projects 1 HP.B Fire Alarm Replacement $35.0 $35.0 0 0 0 0 2 HP.O BVE Operators Roof 120.0 155.0 0 0 0 0 Replacement Specifics: Substation Projects 1 HP.D Dupont Sub Capacitor Bank $102.0 $102.0 0 120 269 0 Addition 2 MP.C 690 Swansea DFP Upgrades 76.9 178.9 0 0 696 0 3 MP.C Scituate Substation Relay 44.0 222.9 0 0 192 0 Upgrades 4 MP.C Riverside Substation Rebuild 1,108.0 1,330.9 0 576 4,416 0 5 MP.C Mill St. Substation Relay 61.0 1,391.9 0 0 288 0 Upgrades 6 MP.C Jepson Sub Ground Gnd 143.0 1,534.9 0 0 864 0 Replacement 7 MP.C 199 Jepson Sub Bus Thermal 65.5 1,600.4 0 0 290 0 Upgrade 8 MP.C Install 2nd Transformer at 222.0 1,822.4 0 0 1,728 0 Eldred 9 MP.C 198 Gate II Overcurrent Relay 78.0 1,900.4 0 0 851 0 Upgrade 10 LP.A Repl Jepson Sub Breaker 3729 55.0 1,955.4 0 0 346 0 11 LP.B Repl Gate II Transformer 33.0 1,988.4 0 0 288 0 Bushings Substation Subtotal $1,988.4 0 696 10,228 0 Specifics: Transmission Projects 1 HP. EMI/Tiverton Power Plant $1,070.0 $1,070.0 0 0 0 6,400 2 HP. EMI/Tiverton Power Plant 260.0 1,330.0 0 0 1800 0 3 HP. 839 EMI/Tiverton Power Plant 1,950.0 3,305.0 0 0 4 HP. 837 EMI/Dignton Interconnection 220.0 3,525.0 0 0 5 HP. ANP Power Plant 1,135.0 4,660.0 0 0 3,200 440 6 HP.D 238 Sherman Rd Sub Foundations 40.0 4,700.0 0 0 2 0 7 HP.D Belmont Replace Switch S1-1 29.0 4,729.0 0 0 0 307 8 MP.C Washington Substation Doub 2,100.0 6,829.0 0 180 3,643 4,151 End Transmission Subtotal $6,829.0 0 180 8,893 18,998 Specifics: Distribution Projects 1 HP.A Gate II Feeder Addition $86.0 $86.0 220 170 220 0 2 HP.C 692 Marvel St. Swansea Road Imps 18.9 104.9 75 0 0 0 3 HP.C 283 Main St. Easton - Road 74.8 179.7 302 128 0 0 Widening 4 HP.C 691 Bank St. Swansea Road Imps. 86.1 265.8 180 0 0 0 Phase II 5 HP.C 1999 Street Light Conversion 385.0 650.8 1,200 800 0 0 Program 6 HP.C 1999 St. Light Conversion, 57.0 707.8 300 0 0 0 Portsmouth 7 HP.D Washington Substation Feeder 220.0 927.8 550 150 0 0 Addition 8 HP.D 196 Reliability Imps. Back yard 22.0 949.8 100 0 0 0 Construction 9 HP.D 293 North Main St. Rebuild 42.5 992.3 0 0 0 0 10 HP.D R270 Main St. Rebuild, Brockton 46.8 1,039.1 0 0 0 0 11 HP.D 197 Conversion - Senes St. Light 60.0 1,099.1 250 420 0 0 Circuits 12 HP.D Condenmed Pole Replacement 580.0 1,679.1 7,600 0 0 0 - 1999 13 HP.D Condemned Pole Replacement 220.0 1,899.1 2,850 0 0 0 - 1999 14 MP.C 278 Storm Proofing 618.4 7,447.4 5,719 0 0 0 15 MP.C Modern Furniture Vault 147.0 7,594.4 0 1,200 0 0 16 MP.C Distribution Automation 325.0 7,919.4 700 0 0 0 17 MP.C Distribution Automation 650.0 8,569.4 1,400 0 1,280 0 18 MP.C 269 Condemned Poles Easton 166.1 8,735.5 1,789 0 0 0 19 MP.C R274 Belmont St Rebuild, Brockt 199.1 8,934.6 558 200 0 0 20 MP.C 261 #6 CU Replacement-Scituate 232.0 9,166.6 2,167 0 0 0 21 MP.C 262 #6 CU Replacement-Brockton 432.0 9,598.6 3,728 0 0 0 22 LP.A 181 Install Neutral Wire, 51.0 9,649.6 450 0 0 0 Portsmouth 23 LP.A 679 Cable Removal-Fall River 46.0 9,695.6 0 4,380 0 0 24 LP.A 675 23kV Cable Removal-Fall 32.3 9,727.9 0 4,000 0 0 River 25 LP.B 178 Remove 23kV Cable 13.5 9,741.4 0 270 0 0 Distribution Subtotal $4,811.5 30,138 11,718 2,140 0 Total dollars/Manhours $26,365.8 92,615 29,436 22,895 22,498 Budgeted Total Available Manhours 78,235 19,673 21,206 22,498 Surplus/Deficit Manhours (14,380) (9,763) (1,689) 19,800 EUASC MH Requirements 0 0 0 0 Surplus (Deficit) Manhours (14,380) (9,763) (1,689) 19,800 including EUASC * Note There is an estimated contribution of $128,000 from EMI on this project ** Note There are 250 Electrical Maintenance manhours associated with this job *** Note There are 3,500 Electrical Maintenance manhours associated with this job
Inventory 55 1 DDRL (12/17/98) 55. Details of how materials are stocked, ordered and distributed including: - value of T&D inventory - degree of centralization - quantities of materials in field locations - use of vendors to provide materials in emergencies Value of T&D inventory / Quantities of materials stored in field locations Inventory Value 6/30/98 Lincoln $906,287 Brockton $941,766 Hanover $244,522 Fall River $725,489 Newport $776,757 -------- System Total $3,594,821 Input Degree of centralization This is answered in ADDRL (12/19/98) #39. Use of vendors to provide materials in emergencies In addition to maintaining a safety stock, we make an assessment of our critical material needs prior to a forecasted storm and contact vendors for immediate re-supply where appropriate. Our vendors have been responsive in the past and we have not experienced a shortage of critical materials in any storm or other emergency in at least the last ten years. EUA does not have alliances with any vendors to maintain inventory on our behalf. Inventory 39R 1 ADDRL (12/19/98) 39. High-level overview of central stores, e.g. value of inventory, annual receipts and issues, square footage, expandability. EUA operates on a "main stocking" philosophy. A number of stock items are stocked at one of the retail company stockrooms in quantity sufficient to provide for the needs of the other retail locations. The daily courier or scheduled trips by the stockroom stake-body vehicle are used to deliver this material where needed. We are presently studying a central warehouse concept. The year-to-date monthly average inventory value as of 6/30/98 (excluding Somerset plant) is $3,552,719. The year-to-date receipts as of 6/30/98 annualized are $4,391,220. The year-to-date issues as of 6/30/98 annualized are $4,613,724. The Inventory Turns Ratio as of 6/30/98 is 1.30. Inventory Turns Ratio is defined as Total Inventory Issues for the last 12 months divided by the 12 month rolling average Inventory level. All items in inventory are included. This includes safety stock, scrap, emergency spares and obsolete items. Inventory at Somerset Station excluded. The Carrying Cost for inventory is approximately 53% as of 10/31/98. Carrying Cost (or Stores Clearing Rate) is defined as the 12 month rolling average of the sum of storeroom expenses, storeroom overheads, related EUASC expenses, inventory over/short, lobby stock, storeroom electric use, misc. journal entries applied to all stock items issued by the storeroom. We maintain stockrooms at all operating centers. The square footage is not readily available. The Lincoln and Newport stockrooms provide for some level of expandability. ADDRL (12/19/98) 39 1 39. High-level overview of central stores, e.g. value of inventory, annual receipts and issues, square footage, expandability. EUA operates on a "main stocking" philosophy. A number of stock items are stocked at one of the retail company stockrooms in quantity sufficient to provide for the needs of the other retail locations. The daily courier or scheduled trips by the stockroom stake-body vehicle are used to deliver this material where needed. We are presently studying a central warehouse concept. Total value of inventory (excluding Somerset plant) is $3,600,000. Annual receipts are $730,000. Annual issues are $760,000. Inventory Turns Ratio (no exclusions) as of 10/31/98 is 1.30. We maintain stockrooms at all operating centers. The square footage is not readily available. The Lincoln and Newport stockrooms provide for some level of expandability. DDRL (12/17/98) 56 1 56. Details of how the Company manages distribution transformer inventory. Transformers are pre-capitalized. The inventory level of transformers is managed by the Materials Management Department. Similar to regular inventory items, minimums and maximums are established for the most frequently used distribution transformers. All purchases are coordinated by Materials Management. Engineering provides input on planned requirements. A goal of 4% in-stock to in-service units has been established for Materials Management. Transformer refurbishing is performed by an outside firm. Refurbishing and junking are coordinated by Materials Management. DDRL (12/17/98) 58 1 58. List of the ten largest contracts the Company and its utility subsidiaries have with suppliers of O&M related equipment and services. Contract Services DESCRIPTION 1998 VENDOR NAME OF SERVICE PROJECTED INPUTS Asplundh Tree Expert Co. Vegetation Control $936,240 $000 Barnes Tree Service Vegetation Control 540,220 R.A. Gill Tree Service Vegetation Control 319,604 Northern Tree Service Vegetation Control 418,796 2,383 New England Tree Vegetation Control 99,253 Vegetation, Inc. Vegetation Control 69,150 Collins Crane Rigging 1,325 Clean Harbors Environmental 60,973 Environ. Protect. Serv. Transformer Refurbishin 75,833 198 QSC Tower Painting 60,000 ADDRL #38 N38 38 BLACKSTONE VALLEY ELECTRIC 2 PROFESSIONAL SERVICES VENDOR NAME DESCRIPTION OF SERVICE 1997 Asplundh Tree Trimming 56,222 Barnes Tree Services Tree Trimming 140,399 Blackstone Valley Security Security Services 0 Clean Harbor Environmental 19,603 Coopers & Lybrand Accounting 34,145 Credit Bureau Collection Fees 20,959 Dickstein, Shapiro & Moris Legal Financial Collection Collection Fees 1,149 Isaacson, Rosenbaum Legal 743,588 McDermott, Will & Emery Legal 32,576 Northern Tree Service Tree Trimming 491,290 Ocean State Janitorial Cleaning 40,408 Osmose Wood Press Pole Treatment/Inspection 448 Stanley Bleeker, Esq. Legal 0 Tillinghast, Collins & Graham Legal 1,911 (A) Colflax Packing Conservation 1,214 (A) Delta Electric Motor Conservation 639 (A) RISE Conservation 7,690 (A) Slater Dye Works Conservation 17,313 ------- 1,609,534 ========= (A) These vendors participated in Eastern Edison's conservation, load, management programs. management programs. NOTE: The source for this information was based on o&m codes 9, 10, 11 & 16. Prepared by Michelle Uzzo 12/22/98
EASTERN EDISON COMPANY 38 PROFESSIONAL SERVICES 3 VENDOR NAME DESCRIPTION OF SERVICE 1997 American Staffing Assoc. Employment 118,240 Asplundh Tree Trimming 919,253 Barnes Tree Service Tree Trimming 140,782 Clean Harbors Environmental Coopers and Lybrand Accounting 62,883 Duff & Phelps Consulting 40,000 Environmental Protection Service Maintenance 44,555 First Financial Resources Collection Fees 33,933 First Security Services Security Hanson Police Dept. Police Detail 31,478 J. D. Payroll Services Temp Services MASS Save Consulting 342,286 McDermott,Will & Emery Legal 1,209,449 Misc. Contract Services* 1,605,966 Misc. Engineering* 38,605 Misc. Legal* 12,155 Miscellaneous* 314,463 Osmose Wood Press Pole Treatment/Inspection Pembroke Police Dept. Police Detail R.A. Gill Tree Service Tree Trimming 227,341 R.E. Tilgren Tree Trimming 46,695 Read, Adami, Kaiser Legal 72,599 Rockland Police Dept Police Detail 26,218 Service Master Maintenance 29,796 State Street Bank & Trust Trustee/Administrative Fee Suburban Contract Cleaning Town of Bridgewater Police Detail Town of Easton Police Detail 56,526 Town of Norwell Police Detail 42,745 Town of Scituate Police Detail Town of Stoughton Police Detail (A) Conservation Services Group Conservation 361,903 (A) Demand Mgmt Conservation (A) Energie Innovation Inc. Conservation 84,095 (A) Energy Conservation Conservation 123,124 (A) Energy Federation Conservation 306,904 (A) Fall Realty & Harris Energy Conservation 38,353 (A) Fleet Bank Conservation 28,182 (A) Harris Energy Systems Conservation 489,801 (A) J&R Industrial Wiring Conservation 206,124 (A) Main Street Textiles Conservation 133,990 (A) MUPAC Corp & Harris Energy Conservation 26,114 (A) National Resource Mgmt. Conservation 375,923 (A) Relocation Resources, Inc. Conservation 61,985 (A) Shaws Supermarkets Inc. Conservation 168,265 (A) Star Market & Harris Energy Conservation 31,080 (A) Stop & Shop Supermarket Co. Conservation 49,799 (A) Ware Rite & Harris Energy Conservation 32,759 (A) Whaling Mfg. Co., Inc. Conservation 29,235 ------- 7,963,604 =========
* Aggregate amounts to any one entity less than $25,000 have been accumulated in this description. (A) These vendors participated in Eastern Edison's conservation, load, management programs. management programs. Note: The source for this information was based on O&M codes 9, 10, 11 & 16. NEWPORT ELECTRIC CORPORATION 38 PROFESSIONAL SERVICES 4 VENDOR NAME DESCRIPTION OF SERVICE 1997 Barnes Tree Services Tree Trimming 187,206 Clean Harbor Environmental 11,989 Coopers & Lybrand Accounting 30,982 Credit Info Collection Fees 12,118 McDermott, Will & Emery Legal 16,803 Morgan, Brown & Joy Legal 340 RISE Conservation 141,057 Tillinghast, Collins & Graham Legal 45,587 ------ 446,062 ======= NOTE: The source for this information was based on o&m codes 9, 10, 11 & 19. EUA Service Corp. 38 PROFESSIONAL SERVICES 5 (Account # 923)
VENDOR NAME DESCRIPTION OF SERVICE 1997 McDermott, Will & Emery Legal 359,773 First Security Services Security 124,975 Contract Cleaning Collaborative Cleaning Eastern Edison Company Arborist/Technical Trainers 351,846 Salomon Brothers Inc. Investment Services 107,956 Media Concepts Printing Services 114,897 Norfolk Date Data Processing Time Cards Cambridge Reports, Inc. Customer Services 70,560 J. Flanagan & Co. Legislative Activity 48,000 DRI McGraw-Hill Newport Electric Corp. Arborist/Technical Trainers Twenty First Century AUC Management Consultants Consulting Misc Legal * 82,677 Misc Accounting 68,988 Misc EDP * 41,871 Misc Building & Maintenance 182,203 Other * 421,494 Misc Engineering 788 --- 1,956,038
* Payments made to payee is less than $100,000 Amounts in Bold print are estimates based on the average of 1996 & 1997. Prepared by Michelle Uzzo 12/22108 o:\profsvs VEHICLES 56 DDRL (12/17/98) 1 54. Details of vehicles including: - types and numbers of vehicles - age of vehicles - maintenance programs and replacement criteria - fuel management programs - criteria for assigning vehicles to non-physical workers 12/15/98 TYPE OF FLEET VEHICLE COUNT BUCKET TRUCK, MATERIAL HANDLER 51 BUCKET TRUCK, LIGHT-DUTY 15 DIGGER -DERRICK TRUCK 8 VAN, LARGE STEP TYPE 25 VAN, SMALL 68 DUMPTRUCK 8 STAKE-BODY TRUCK 2 EFFER CRANE TRUCK 3 PICKUP TRUCK 110 SEDAN 52 TRAILER 62 MOBILE SUBSTATION, XFMR OR REGUL. 6 TRACTOR 5 FORKLIFT 11 TRACK VEHICLE 1 CRANE TRUCK 2 TANKER TRUCK 1 SPECIAL EQUIPMENT* 24 TOTAL 454 * Includes powered reel trailers, puller-tensioners, woodchippers, generator trailer, cement mixer, tank trailer, test equipment trailers, waterpump trailer, compressors. AVERAGE AGE OF VEHICLES MONTHS All Vehicles (excl. trailers, spec. equip.) 93 All Units 120 DDRL (12/17/98) 54 2 54. Cont'd MAINTENANCE PROGRAMS AND REPLACEMENT CRITERIA EUA adheres to a preventative maintenance program based on manufacturers' recommendations, generally accepted automotive industry practices and experience related specifically to a particular vehicle or class of vehicles. A computerized maintenance management system (FleetTracker) is used to track vehicle usage in terms of miles and/or hours and scheduled maintenance periods to determine when "A", "B" or "C" level maintenance procedures are due. The replacement of a vehicle is considered based on the following criteria: Aerial devices are considered for replacement based on age and condition of the boom and chassis (particularly with respect to fiberglass strength and metal fatigue). These vehicles are usually replaced at the 12-14 year point. Other large vehicles (e.g. step vans, stakebody trucks, etc.) are considered for replacement based on condition of chassis and body. These vehicles are usually replaced at the 12-14 year point. Small vehicles (e.g. panel vans, pickups, etc.) are considered for replacement based on condition of body and engine maintenance needs and are typically replaced at a point above 130,000 miles. FUEL MANAGEMENT PROGRAMS PetroVend fuel management systems and VeederRoot leak detection systems are installed at all EUA gasoline fueling stations. DDRL (12/17/98) 54 3 54. Cont'd CRITERIA FOR ASSIGNING VEHICLES TO NON-PHYSICAL WORKERS Vehicles with two-way radios and cellular phones are assigned on a 24-hour basis to firstline supervisors who are in the field most of the workday, who must be visible to customers and within the communities, and who have on-call and emergency responsibilities. Vehicles with two-way radios and cellular phones are assigned on a 24-hour basis to certain management personnel in Operations due to their emergency responsibilities. Vehicles are provided to certain executives as part of their compensation package. Other non-physical workers, such as engineers and distribution service coordinators, have access to company vehicles during the workday. NEES Supply Chain in $000 Overall Purchases 1997 T&D purchase order spending 217,528 incl supplies, materials, services 1998 estimate 211,979 1997 po and non-po spending Cable 16,047 Transformers 13,908 Wood poles 3,288 Meters and accessories (po only) 3,585 Contractor Services 1997 veg. mgt 17,609 Inventory 8/98 RBU inventory 14,211 9/98 distribution transformers 14,123 12/97 meters 2,762 Vehicles Passenger 35 Trucks 1504 (incl. 318 aerial)
Exhibit DJH-2 Facilities FACILITIES in $000 Prelim DDRL #33 BOSTON W. BRIDGEWATER Miscellaneous 413 Note: WB excludes internal labor M&S, Stores 170 of $1.1 million Outside Svcs 111 IS 9 Rents 346 34 Contract Services 6 467 Overheads 31 Sub-total 383 1,204 1,587 Ownership cost for WB 2,470 (levelized) Total 4,057 Escalate to 2000 1.03 - --------------------------------------------------------------------------- Total savings in 2000 4,179 - --------------------------------------------------------------------------- BOSTON lease exp 1999; assume no change in cost per sq ft WEST BRIDGEWATER WESTBOROUGH room for 300-350 Levelized cost 2,470 additional people 60,000 sq. ft. structures and improvements 18,860 life 40 year carrying cost 10.50% Annual Westborough cost incl.lease ($3.6) property tax 2.50% $5 million
PDDRL 12/17/98 33. List of all facilities owned or leased, including the following: (a) Address: (b) Occupied space in square feet; space available for expansion; (c) Description of the lease, including monthly cost, terms, and a description of assignability or change of control provisions; (d) Number of employees using the facility, including detail as to department/function. (e) If wned, estimate of the current market value; (f) Whether or not the facility is known to have experienced any instances of oil or hazardous material releases which would subject the facility to response actions under the Massachusetts or Rhode Island waste site cleanup regulations. If such releases have occurred, provide a summary of the status of the remedial response, any future costs expected to be incurred in addressing the release(s)and the duration of the response action(s). (g) Provide a statement of the presence and condition of asbestos, lead or other hazardous substances that may be present in the facility and, if present, the plan and costs for maintaining or removing the substances Note 1 Note 3 Company (a) (b) (c) (d) (e) (f) (g) =========================================================================================================================== Eastern Edison 161 Mulberry St. $23,000 N/A 102 $750,000 None None Brockton Mass 82 Hartwell St $20,250 N/A 67 $550,000 None None 60 Hartwell St. $18,500 $250,000 Note 5 River St. $11,200 $215,000 Note 6 Fall River Mass 10 Phillips Lane $14,400 N/A 21 $1,500,000 None None Hanover Mass Blackstone Valley 642 Washington Highway $60,000 N/A 94 $2,000,000 Note None Electric Lincoln, Rhode Island 4 Newport Electric 12 Turner Road Note 7 $35,000 N/A 49 $1,500,000 None None Middletown, Rhode Island EUA Service EUA Corporate Offices $12,800 Note 2 20 N/A None None Corporation One Liberty Square Boston, Mass EUA System Operating $133,000 N/A 542 $20,000,000 None None Center 750 West Center Street West Bridgewater Mass Note 1: Available for expansion: Lincoln 12000 sq. Ft., Fall River 8500 sq. ft. Note 2: Boston Office lease and overheads are $382,450 and expires 1999 Note 3: Detail of employees by company, department/function is attached. Note 4: See second page attachment Note 5: Lead Paint Note 6: Asbestos in boiler room Note 7: Leased space to Bank of Newport - $140,000 annual net income.
PDRL OF 12/17/98 33. List of all facilities, owned or leased, indicating the following: a) address; b) occupied space in square feet; space available for expansion; c) description of the lease, including monthly cost, terms, and a description of assighnability or change of control provisions; d) number of employees using the facility; including detail as to department/function; e) if owned, estimate of current market value; f) whether or not the facility is known to have experienced any instances of oil or hazardous material releases which would subject the facility to response actions under the Massachusetts or Rhode Island waste site cleanup regulations. If such releases have occurred, provide a summary of the status of the remedial response, any future costs expected to be incurred in addressing the release(s) and the duration of the response actions(s) g) provide a statement of the presence and condition of asbestos, lead or other hazardous substances that may be present in the facility and, if present, the plan and costs for maintaining or removing the substances. Note 4: Blackstone Valley Electric experienced a release of gasoline in 1989 from an underground storage tank at its Lincoln Operations facility. The release was detected during an annual tightness testing, and was estimated at approximately 100 gallons. Soil and groundwater were impacted. A removal action was performed in 1989, and a groundwater treatment system has been in operation since that time. The zone of contamination has been reduced to a small area and levels of contamination greatly reduced. BVE expects to resolve this matter in 1999 and complete this response action with little additional expense. The costs to complete are not expected to be material.
PDDRL 12/17/98 Facility Expense 33d cont. Company EUA Service Corporation Eastern Edison Blackstone Valley Newport Location Boston W. Bridgewater Brockton Fall River Lincoln Middletown Miscellaneous 413,400 Payroll 1,051,400 90,900 94,300 92,200 84,800 Employee Expense 10,800 500 500 500 500 Education & Training 5,300 500 500 500 500 Materials & Supplies 151,500 19,000 44,500 23,600 12,000 Stores 18,800 10,000 8,900 11,000 9,000 Outside Services 111,000 Information Systems - Hardware 9,400 Rents 345,600 33,500 25,500 500 26,400 8,500 Contract Services 5,850 467,400 104,500 69,900 128,600 59,100 Office Overheads 31,000 33,000 22,000 90,000 28,000 Totals $382,450 $2,272,500 $283,900 $241,100 $372,800 $202,400 System Total $3,755,150
33d Meter OH Property Company Address Union Reading Lines Trouble Meter Garage Stores Maint. Eastern Edison 161 Mulberry St. None X X X X X X X Brockton Mass. 82 Hartwell St. IBEW X X X X X X X Fall River Mass. 10 Phillips Lane None X X X Hanover Mass. Blackstone Valley 642 Washington Highway None X X X X X X X Electric Lincoln, Rhode Island Newport Electric 12 Turner Road BUW X X X X X X X Middletown, Rhode Island
33d UG Substation Radio & System Consumer Company Address Union Lines Maint. Microwave Operations Service Eastern Edison 161 Mulberry St. None X X X Brockton Mass. 82 Hartwell St. IBEW X X Fall River Mass. 10 Phillips Lane None Hanover Mass. Blackstone Valley 642 Washington Highway None X X X X Electric Lincoln, Rhode Island Newport Electric 12 Turner Road BUW X X X Middletown, Rhode Island
PDDRL 12/17/98 33d cont. Company Address Union Function Performed ================================================================================================================================== EUA Service Corporation EUA Corporate Offices None Corporate Executive Offices One Liberty Square Treasury Boston Mass. EUA System Operating Center None Executive - Admin. & Support 750 West Center Street Facilities Management West Bridgewater Mass. Internal Audit Consumer Services Marketing Information Services Human Resources Corporate Communications Corporate Benefits Risk Management Office Services Safety Transmission Services Load Forecasting Power Supply Special Projects Purchasing Material Management Rates Accounting Customer Service Security Real Estate Engineering Transmission and Distribution Somerset Station None Transmission Crews 1606 Riverside Avenue Somerset Mass.
(ALL FROM U13-60) ACC DEPN 12/31/97 @ 12/31/97 NET WB BUILDING 18142620 4015211 14127409 LAND & LAND RIGHTS 717080 0 717080 18859700 4015211 14844489 DEPRECIATION 452158 YEARS 40 COST % OF TOTAL TAX(B) C EUASC COMMON EQUITY 2895346 11.00% 19.50% 0. EUASC LTD 6800000 10.20% 45.81% 9695346 A SHORT TERM 5149143 6.50% 34.69% 14844489 100.00% A - ASSUMED REMAINING BALANCE FINANCED BY EUA SHORT TERM BORROWINGS B - COMBINED TAX RATES (FED AND STATE) OF 40% C - USED RETURN ON COMMON EQUITY OF RETAILS REVENUE REQUIREMENTS DEPRECIATION (% OF UNDEPRECIATED) 3.05% CARRYING COSTS 10.50% COUNTY TAXES 2.50% TOTAL 16.05%
Exhibit DJH-2 Administrative and General Savings -------------------------------------------------------------------- Mercer Management Consulting
A&G Overheads in $000 This savings component reflects miscellaneous overheads, such as office supplies and personal computers; but excludes facilities and benefits related overheads EE BVE NE Total FERC Acct #921 730 394 201 1,325 Office supplies and expenses employees 881 per employee (000) 1.5 (higher for service co only) EUA PC costs configured prices of 1.9-3.4 per unit (in 000) Annualized cost for pc, cell phones, and pagers 640 Savings per employee 3 reduced in $000 in 2000 Savings in 2000 486 162 reductions x 3 Savings in 2001 690 225 cumulative red. X 3 x I.022 Savings in 2002 733 234 cumulative red. X 3 x 1.044
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT 48 Summary of other miscellaneous A&G overheads. See attached.
Summary - Other Miscellaneous and A&G Company 1997 - ------- ---- Blackstone Valley Electric Company $344,714.00 Eastern Edison Company $632,170.00 Newport Electric Corporation $238,947.00 Total $1,215,831.00 ============= Blackstone Valley Electric Company Description 1997 - ----------- ---- Industrial Association Dues $49,591.00 Other Experimental & General Research $339.00 Publishing and Distribution Information and reports as well as other expenses of servicing Outstanding Securities of Respondent. $37,084.00 EUA Service Corporation General and Administrative $161,923.00 R.I. Industrial Revenue Bonds Fee $8,125.00 Employee Training and Seminars $85,298.00 Citicorp Remarketing - R.I. Industrial Bonds $22,344.00 Miscellaneous $10.00 ------------- Total $344,714.00 ============= Eastern Edison Company Description 1997 - ----------- ---- Industrial Association Dues $103,047.00 Other Experimental & General Research $701.00 Publishing and Distribution information and reports as well as other expenses of servicing Outstanding Securities of Respondent. $68,824.00 EUA Service Corporation General and Administrative $314,908.00 Employee Training and Seminars $138,456.00 Service Anniversary Expense $4,864.00 Miscellaneous $1,370.00 ------------- Total $632,170.00 ============= Newport Electric Corporation Description 1997 - ----------- ---- Industrial Association Dues $24,190.00 Other Experimental & General Research $131.00 Publishing and Distribution Information and reports as well as other expenses of servicing Outstanding Securities of Respondent. $18,200.00 EUA Service Corporation General and Administrative $85,579.00 Employee Training and Seminars $41,155.00 Settlement Agreement $58,481.00 Remarketing Expenses $10,146.00 Miscellaneous $1,085.00 ------------- Total $236,447.00 =============
GP6-350 Page 1 of 2 For the Enthusiast Customize It & Buy It! GP6-350 ============================================================ Processor: Intel 350MHz Pentium II Processor w/ 512K Cache Memory: 64MB 100MHz SDRAM expandable to 256MB Monitor: EV700 l7inch color monitor (15.9inch viewable area) Graphics Accelerator: Integrated nVidia 8MB AGP Graphics Accelerator Hard Drive: 10GB Ultra ATA hard drive added: US$60 Floppy Drive: 3.5inch 1.44MB diskette drive (IOMEGA Internal ZIP Drive Deleted) subtracted: US$50 CD-ROM: 13X min./32X max. CD-ROM drive Multimedia Package: Boston Acoustics BA635 Speakers added: US$30 Sound System: Integrated Sound Blaster AudioPCI 64D Case: Mid Tower Case Network Adapter: 3COM PCI 10/100 twisted pair Ethernet Keyboard: 104+ Keyboard Mouse: MS IntelliMouse Mouse; Gateway mouse pad Additional Software: McAfee Anti Virus Software Application Software: MS Office 97, Small Business Edition, on CD w/Bookshelf Operating System: Microsoft Windows 98 Service Program: Gateway Gold Service for PCs (1 yr. Onsite) Tape Backup Unit: TR5 IDE TBU and tape added: US$249 ============================================================ Base Price: US $1599 Configured Price: US $1888 Quantity: 1 Total Price: US $1888 ============================================================ ============================================================ Many Gateway products are custom engineered to Gateway specifications, which may vary from the retail versions of the software and/or hardware in functionality, performance or compatibility. Prices and configurations are subject to change without notice or obligation. The price above does not include shipping and handling or any applicable taxes. After your system has been built (lead times vary), it may be shipped via second-day shipping in the continental U.S. Second-day shipping within the continental U.S. is US$95 for desktops and US$25 for portables. Five-day shipping for Destination (R) Digital Media Computers is US$149. All prices quoted are in U.S. dollars. o I would like to order this system via the World Wide Web. Clicking "Continue" below takes you to our secure server. Gateway uses Secure Sockets Layer (SSL) encryption to assure that all information entered on the next screen --including your credit card number -- can only be understood by us. After thousands of online transactions worth millions of dollars, no Gateway client has ever reported misappropriation of a credit card number protected by SSL technology. Check our article on how SSL works and why we think it's extremely safe to learn more. o Please have a sales representative contact me about this system or other Gateway products. Copyright (C) 1997, 1998 Gateway 2000 Inc. All rights reserved. Please see our ______________________. Please send feedback to ___________________________. GP6-450 Page 1 of 2 For the Enthusiast Customize It & Buy It! GP6-450 ============================================================ Processor: Intel 450MHz Pentium II Processor w/ 512K Cache Memory: 128MB 100Mhz SDRAM expandable to 384 Monitor: VX900T 19inch color monitor (18.0 inch viewable area) added: US$60 Graphics Accelerator: 16MB AGP Graphics Accelerator Hard Drive: 16.8GB 5400RPM Ultra ATA hard drive Floppy Drive: 3.5inch 1.44MB diskette drive & SuperDisk LS-120 w/5 Disks added:US$60 CD-ROM: 13X min./32X max. CD-ROM drive Multimedia Package: Boston Acoustics BA635 Speakers added: US$30 Sound System: Integrated Sound Blaster AudioPCI 64D Fax/Modem: TelePath(R) 56K Modem added: US$129 Case: Tower added: US$50 Network Adapter: 3COM PCI 10/100 twisted pair Ethernet Keyboard: 104+ Keyboard Mouse: MS IntelliMouse Mouse; Gateway mouse pad Additional Software: McAfee Anti Virus Software Application Software: MS Office 97, Professional Edition, on CD added: US$199 Operating System: Microsoft Windows 98 Service Program: Gateway Gold Service for PCs (lyr. Onsite) Tape Backup Unit: TR5 IDE TBU and tape added: US$249 ============================================================ Base Price: US $2599 Configured Price: US $3376 Quantity: 1 Total Price: US $3376 ============================================================ Many Gateway products are custom engineered to Gateway specifications, which may vary from the retail versions of the software and/or hardware in functionality, performance or compatibility. Prices and configurations are subject to change without notice or obligation. The price above does not include shipping and handling or any applicable taxes. After your system has been built (lead times vary), it may be shipped via second-day shipping in the continental U.S. Second-day shipping within the continental U.S. is US$95 for desktops and US$25 for portables. Five-day shipping for Destination (R) Digital Media Computers is US$149. All prices quoted are in U.S. dollars. o I would like to order this system via the World Wide Web. Clicking "Continue" below takes you to our secure server. Gateway uses Secure Sockets Layer (SSL) encryption to assure that all information entered on the next screen --including your credit card number -- can only be understood by us. After thousands of online transactions worth millions of dollars, no Gateway client has ever reported misappropriation of a credit card number protected by SSL technology. Check our article on how SSL works and why we think it's extremely safe to learn more. o Please have a sales representative contact me about this system or other Gateway products. Copyright (C) 1997, 1998 Gateway 2000 Inc. All rights reserved. Please see our ______________________. Please send feedback to ___________________________. Privileged and Confidential ADDRL #34 34. Estimate of "personal tools" costs per employee, e.g. PC, pager, cellular phone. (This information is needed to estimate merger savings.). 1. Workstation replacement program ended in 1997. There are about 50 workstations currently in use. They will be phased out through attrition. 2. Replacement of PCs is a department head decision. Expected replacements are identified in the O&M budget. A PC Replacement form is used as a control document. 3. New PCs are identified in the O&M budget (unless they are related to a capital project). A PC Acquisition form is used as a control document. 4. Average replacement costs and base-line specifications for the two classes of recommended PCs is attached - #1. 5. Divisional breakdown of PCs is attached - #2. 6. Average life expectance for a PC is three years. However, older useful PCs are recirculated to low-end users identified by department heads. 7. Department heads on an as needed basis distributes pagers and cell phones. 8. Company annualized cost for PC's - $450,000; pagers and cell phones - $90,000. 1998 Inventory Number of PCs by Department Total Configurations as of 12/14/98: 584 Accounting 48 Bldg & Facil 11 CIS 78 Engineering 70 Executive 31 Garage 10 Gen. Office Svcs 2 HR 30 Info Services 62 Internal Audit 4 Meter 11 Meter Reading 11 Power Supply 15 Purchasing 6 Rates 23 Real Estate 5 Records 1 Retail Bus Svcs. 65 Safety & Risk Mgmt 7 SCADA 5 Special Projects 5 Stores Mgmt & Supp 14 Sub & Comm 13 System Operations 3 Telecommunications 3 Trans & Dist 32 Trans Svcs 7
Advertising in $000 1997 1998 annualized EUA NEES Addit. data req #47 825 Customer 4,318 dsm,choice related Normalized 500 Image 50 FERC # 930.1 4,368 Savings 50% Savings in 1997 250 Escalation to 2000 1.09 Savings in 2000 273
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT 47 Summary of advertising costs. See attached.
Advertising Costs - 1997 1997 ------------------------ ---- Company Advertising Costs ------- ----------------- Co 01 Blackstone Valley Electric $215,091.17 Co 08 Eastern Edison Company $519,027.05 Co 14 Newport Electric Corporatio $90,729.57 ------------ Total $824,847.79
Association Dues in $000 Addit data req # 45, 48 EUA 1997 Savings% Savings EEI 136 25% 34 Other 41 100% 41 177 42% 75 Escalation to 2000 1.09 Savings in 2000 82
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 45 Summary of associations dues. 1997 Blackstone Newport Eastern Total - ---- ---------- ------- ------- ----- Utility Air Regulatory Group 225 562 787 Electric Council of New England 6,983 2,745 13,665 23,393 EEI 38,842 17,780 78,980 135,602 Utility Water Act Group 2,847 2,788 5,752 11,387 Associated Industries of MA 720 720 NU College of Business 2,500 2,500 Administration Miscellaneous 696 315 1,431 2,442 49,593 24,190 103,048 176,831
Benefits Administration in $000 Expect no savings in HMO ( self insured) and group life Minimal savings in retirement and thrift plan administration Per conversation with NEES Savings in 2000 50 12/19/98 ADDITIONAL DUE DILIGENCE (List #3) REQUEST LIST PRIVILEGED AND CONFIDENTIAL ATTORNEY-CLIENT COMMUNICATION ATTORNEY WORK PRODUCT ADDRL # 46 Cost to administer benefits.
EASTERN UTILITIES ASSOCIATES Responsibility Center 220 - Corporate Benefits O&M Budget 1999 "ADDRL"12/19/98 Question #46 OTHER EXPENSES: O&M EUASC XX Payroll 01 $220,000 20 Miscellaneous (NEEBC Dues) 00 $400 20 Retiree Organizations Support (700 rets @ $10.00) 00 $7,000 01 Employee Expense 05 $1,800 XX Ed. & Training 06 $3,500 20 Materials & Supplies 07 $2,000 07 Materials & Supplies - WSJ,CCH 07 $1,600 XX General Consulting - Pension & ESP* 11 $36,000* 20 Financial Education/ Retirement Planning Program 11 $23,500 20 FSA Admin. Fees-Estimated FICA tax offset is $10,000 11 $9,000 20 Executive Annual Physicals 11 $16,800 20 Split $ Consulting Fee - Vinings Management 11 $16,900 25 Cyborg Maintenance Contract 22 $12,500 Total Other Expenses: $351,000 ======== * not payable from the pension trusts.
TOTAL BVE EECO NEWPORT EUASC TOTAL EUASC Group Health 452,022 978,362 211,337 171,001 1,812,722 204,034 Dental Insurance 49,016 105,728 33,918 3,130,326 3,318,988 3,735,027 Group Life 7,154 65,696 35,153 570,642 678,645 680,876 Pension (854,720) (1,351,822) (74,320) 4,329,463 2,048,601 5,165,807 Post Retirement Benefits 1,319,782 2,284,618 588,458 356,773 4,549,631 425,693 Employee Thrift Plan 113,012 218,567 94,990 0 426,569 1,086,266 2,301,149 889,536 8,558,205 12,835,156 10,211,437 ---------- 12,835,156 BVE 2,367,906 0.276698653 0.2319 EECO 4,621,878 0.540083693 0.4526 NWPT 1,231,339 0.143886557 0.1206 MECO TRANS 336,584 0.039331097 0.033 8,557,707 1 0.8381
Corporate Governance Shareholder Services in $000 ADDRL #43 EUA 1999 budget Million Million Shares Price Mkt Cap Annual rpt 112 NEES 59.8 48.06 2,874 Transfer agent 87 EUA 20.4 27.81 567 NYSE 33 EUA equiv 11.8 Other 61 % increase 11.8/59.8 293 20% Savings 80% Savings in 1999 234 Savings in 2000 241 Trustees ADDRL #40 1999 1998 EUA NEES Outside directors 9 11 Fees 550 Other expenses 100 Total 530 650 Savings in 1999 530 Escalate to 2000 1.03 Savings in 2000 546 Total Corp Governance 787
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 43 Summary of shareholder services expenses, including the production of the annual report, the annual meeting, mailings and other fees. Budget for 1999 Annual Report Production 112,000 Mailing of AR and Proxy, etc. 28,000 10K printing 5,700 Proxy printing 7,000 Transfer agent fees 87,000 NYSE listing fee 33,000 Quarterly dividend enclosure 11,000 Postage and miscellaneous 9,700 --------- 293,400 12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE (List # 3) ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 40 Directors' fees and related expenses. See attached summary of EUA Parent 1999 Budget for details of information requested.
EUA PARENT 1999 BUDGET 1999 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC TOTAL --- --- --- --- --- --- --- --- --- --- --- --- ----- 9200 DO AMORT RESTR STK PLAN 500 500 500 500 500 500 500 500 500 500 500 500 6,000 9302 07 MISCELLANEOUS FIDUCIARY/DIRECTORS LIB INS 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,737 92,800 TOTAL 9302 07 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,737 92,800 9302 09 CORP & FISCAL MISCELLANEOUS 200 200 9302 06 DIRECTORS FEES ANNUAL TRUSTEE FEE 36,000 36,000 36,000 36,000 144,000 REGULARLY SCHEDULED MTGS FULL BOARD 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 84,190 FINANCE COMM 4,250 4,250 4,250 4,250 17,000 AUDIT COMM 4,250 4,250 4,250 12,750 PENSION TRUST COMM 3,400 3,400 3,400 3,400 3,400 3,400 20,400 COMPENSATION 3,400 3,400 3,400 10,200 RETIREMENT BENEFIT 36,130 12,130 12,130 38,130 12,130 12,130 36,130 12,130 12,130 36,130 12,130 12,130 241,560 TOTAL 9302 05 84,030 26,580 24,030 87,430 19,780 27,430 84,030 15,530 27,430 90,830 19,780 23,220 530,100 TOTAL DO 92,263 34,813 32,263 95,853 28,013 35,883 92,263 23,763 35,663 99,063 28,013 31,457 629,100 9230 10 OUTSIDE LEGAL 28,300 27,100 14,500 33,400 24,000 7,600 7,000 7,900 9,800 12,900 5,000 6,200 183,700 TOTAL 09 28,300 27,100 14,500 33,400 24,000 7,600 7,000 7,900 9,800 12,900 5,000 6,200 183,700 9210 02 OFFICE SUPPLIES & EXP BANK CHARGES 400 400 400 400 400 400 400 400 400 400 400 400 4,800 9230 20 OUTSIDE ACCOUNTING C&L AUDIT FEE 4,700 2,800 1,030 1,700 10,000 9302 10 TRANSFER AGENT FEES COMON STOCK EXPENSE 1,000 1,000 2,500 1,000 1,000 2,500 1,000 1,000 2,500 1,000 1,000 2,500 18,000 TOTAL 11 1,400 5,100 5,500 1,400 1,400 2,900 1,400 1,400 2,900 2,400 1,400 4,600 32,800 TOTAL 000 121,963 58,013 52,283 130,483 53,413 46,363 100,563 33,063 40,363 114,383 34,413 42,257 845,600
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New England Electric Sys. NYSE : NES Financial Links Address: 25 Research Drive o Company News Westborough, MA 01582 o Research Report: Basic / Detailed Phone: (508) 389-2000 o Upgrade/Downgrade History Fax: (508) 836-0276 o Free Annual Report Industry: Electric Utilities o Latest Stock Price Sector: Utilities o Insider Trades Employees: 4,665 o SEC Filings (raw filings) Officers: Richard P. Sergel, Pres./CEO o Message Board Joan T. Bok, Chmn. Cheryl A. Lafleur, Sr. VP/Secy./Counsel Michael E. Jesanis, Sr. VP/CFO Company's Web Presence John G. Cochrane, Treas./CAO. o Home Page o Search Yahoo! for related links...
Business Summary NES is a public utility holding company, whose subsidiaries are engaged in the transmission, distribution, sale and generation of electricity. For the nine months ended 9/30/98, revenues fell 1% to $1.82 billion. Net income applicable to Common fell 3% to $157.5 million. Revenues reflect decreases in generation-related, fuel cost-related, and oil and gas-related revenues. Earnings also reflect monthly contractual payments to USGen and increased transmission wheeling costs.
More from Market Guide: Highlights - Performance Statistics at a Glance - NES Last Updated: Dec 23, 1998 Price and Volume Per-Share Data Management Effectiveness (updated Dec 23, 1998) Book Value (mrq) $26.79 Return on Assets (ttm) 4.34% 52-Week Low $38.938 Earnings (ttm) $3.39 Return on Equity (ttm) 12.66% Recent Price $48.063 Sales (ttm) $38.91 Financial Strength 52-Week High $49.125 Cash (mrq) $8.26 Current Ratio (mrq) 1.23 Beta 0.32 Valuation Ratios Long-Term Debt/Equity (mrq) 0.63 Daily Volume (3- 148.9K Price/Book (mrq) 1.79 Total Cash (mrq) $494.3M month avg) Share-Related Items Price/Earnings (ttm) 14.19 Short Interest Market Capitalization $2.88B Price/Sales (ttm) 1.24 Shares Short 23 as of Dec 8, 1998 Shares Outstanding 59.8M Income Statements Float 54.5M After-Tax Income (ttm) $231.8M Short Ratio 5.81 Dividend Information Sales (ttm) $2.48B Stock Performance Annual Dividend $2.36 Profitability NES 24-Dec-1998 (C) Yahoo! (indicated) Profit Margin (ttm) 9.3% _____________________________________ 50|| | 45|| | 40 | | 35 | | ------------------------------------| Jan Mar May Jul Sep Nov big chart [ld | 5d | 3mo | 1yr | 2yr | 5 yr | max] Dividend Yield 4.91% See the Profile FAQ for a description of each item above; K = thousands; M = millions; B = billions; mrq = most-recent quarter (Sep 30, 1998); ttm = trailing twelve months through Sep 30, 1998 Market Guide offers more in-depth Company Research, Stock Screening, and Hottest Stocks and Industries on over 10,000 U.S. Equities. - ------------------------------------------------------------------------------------------------------------------- Copyright (C) 1998 Yahoo! Inc. All Rights Reserved. See our Important Disclaimers and Legal Information. Company information Copyright (C) Market Guide Historical chart data and daily updates provided by Commodity Systems, Inc. (CSI). Data and information is provided for informational purposes only, and is not intended for trading purposes. Neither Yahoo nor any of its data or content providers (such as Market Guide, CSI, Reuters, Zacks, etc.) shall be liable for any errors or delays in the content, or for any actions taken in reliance thereon. Questions or Comments?
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Eastern Utilities Assoc. NYSE : EUA Financial Links Address: One Liberty Square o Company News Boston MA 02109 o Research Report: Basic / Detailed Phone: (617) 357-9590 o Latest Stock Price Fax: (617) 357-7320 o Insider Trades Industry: Electric Utilities o SEC Filings (raw filings) Sector: Utilities o Message Board Employees: 1,180 Officers: Donald G. Pardus, Chmn./CEO John R. Stevens, Pres./COO Company's Web Presence Richard M. Burns, Contr./CAO o Home Page Clifford J. Herbert, Jr., Treas./Secy. o Search Yahoo! for related links...
Business Summary EUA is a holding company for Blackstone, Eastern Edison, and Newport, which provide retail electric utility services in MA and RI. EUA also operates various service subsidiaries. For the nine months ended 9/98, revenues fell 4% to $405.4 million. Net income applicable to Common fell 4% to $26.2 million. Results suffered from a decrease in core electric business revenues due to customer rate reductions and the termination of the power marketing joint venture. More from Market Guide: Highlights - Performance
Statistics at a Glance - EUA Last Updated: Dec 23, 1998 Price and Volume Per-Share Data Management Effectiveness (updated Dec 23, 1998) Book Value (mrq) $18.27 Return on Assets (ttm) 3.05% 52-Week Low $23.563 Earnings (ttm) $1.80 Return on Equity (ttm) 9.85% Recent Price $27.813 Sales (ttm) $26.98 Financial Strength 52-Week High $28.00 Cash (mrq) $0.33 Current Ratio (mrq) 0.71 Beta 0.50 Valuation Ratios Long-Term Debt/Equity (mrq) 0.77 Daily Volume (3- 73.9K Price/Book (mrq) 1.52 Total Cash (mrq) $6.64M month avg) Price/Earnings (ttm) 15.45 Short Interest Share-Related Items Price/Sales (ttm) 1.03 Shares Short as of Dec 8, 1998 137.9 Market Capitalization $568.4M Shares Outstanding 20.4M Income Statements Short Ratio Float 20.2M After-Tax Income (ttm) $39.1M
Financing Costs and Fees in $000 Includes savings associated with lines of credit Lines of Credit 1998 est NEES x NEP EUA Commitment fees 567 256 Lines of credit 637,000 165,000 % fee 0.089% 0.155% Savings 100% Savings in 1998 256 Escalation to 2000 1.06 Savings in 2000 272
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE (List #3) ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 41 Summary of any lines of credit. See attached summary of EUA System lines of credit.
EUA SYSTEM Short-Term Credit Facility Fees (1) For 1998/1999 LINE FACILITY ANNUAL BANK OF CREDIT FEE FEE EUA BVE EECO REVOLVING CREDIT FACILITY: BANK OF NEW YORK $100,000,000 $20,000,000 $75,000,000 (Availability: All Companies) 29% 6% 21% $75,000,000 0.1250% $93,750 $26,786 $5,357 $20,089 OTHER CREDIT FACILITIES: $20,000,000 $75,000,000 BANK OF NEW YORK 16% 60% (Availability: BVE,EECO, MECO) $10,000,000 0.1250% $12,500 $2,000 $7,500 STATE STREET BANK $100,000,000 $75,000,000 (Availability: EUA, EECO) 57% 43% $15,000,000 0.2500% $37,500 $21,429 $16,071 UNION BANK OF CALIFORNIA (2) $100,000,000 $20,000,000 $75,000,000 (Availability: EUA, BVE, EECO, MECO, NECO) 8% 30% $20,000,000 0.1875%(2) $0 40% $0 $0 $0 (Availability: EECO) $45,000,000 0.2500% $112,500 100% ANNUAL FACILITY FEE TOTALS $165,000,000 $256,250 $48,214 $7,357 $156,161 MONTHLY ACCRUAL $4,018 $613 $13,013 BANK MECO COGENEX EUA OS SERVICE NECO TOTAL REVOLVING CREDIT FACILITY: $30,000,000 $75,000,000 $10,000,000 $15,000,000 $25,000,000 $350,000,000 BANK OF NEW YORK 9% 21% 3% 4% 7% 100% (Availability: All Companies) $8,036 $20,089 $2,679 $4,018 $6,696 $93,750 OTHER CREDIT FACILITIES: $30,000,000 $125,000,000 BANK OF NEW YORK 24% 100% (Availability: BVE,EECO, MECO) $3,000 $12,500 STATE STREET BANK $175,000,000 (Availability: EUA, EECO) 100% $37,500 $30,000,000 $25,000,000 $250,000,000 UNION BANK OF CALIFORNIA (2) 12% 10% 100% (Availability: EUA, BVE, EECO, MECO, NECO) $0 $0 $0 $25,000,000 $75,000,000 10% 100% (Availability: EECO) $0 $112,500 ANNUAL FACILITY FEE TOTALS $11,036 $20,089 $2,679 $4,018 $6,696 $256,250 $920 $1,674 $223 $335 $558 $21,354 MONTHLY ACCRUAL (1) Allocation Percentages Based on March 20, 1998 SEC Order Authorizing Company Short-Term Borrowing Limitations. (2) Facility Fee based on .1875% of the average daily unused amount of the Facility during such period. For allocation of Fee, assumption will be credit line will be fully drawn, hence, zero fee. September 22, 1998 JWH/d:/1231997/comfee/feebad98
Insurance Premiums in $000 Data Response #102 Major Coverages 1999 EUA % Savings Savings excl MTP Property 90 5% 5 Property 68 5% 3 Boiler 95 5% 5 Marine Cable Liability General 285 50% 143 Excess 343 50% 172 Auto 94 50% 47 Pollution 191 25% 48 D&O adjusted 100 75% 75 Brokerage Fees 175 75% 131 (per phone conversation) Total 1,441 44% 628 Escalate to 2000 1.03 Savings in 2000 646
INSURANCE COSTS - 1999 TYPE EECO NPT EUA BVE MTP EUA TOTAL PROPERTY 27000 21300 8200 33500 110000 200000 BOILER 13500 17800 4500 32400 141800 210000 OFFICE CONTENTS 1100 1100 EDP 10000 10000 CONT EQUIP 3178 2794 1377 2651 10000 MICROWAVE 2191 716 4336 1473 1284 10000 VALUABLE PAPERS 133 133 134 400 MARINE CABLE 95000 95000 TRANSIT 722 542 586 550 2400 CRIME 2230 590 6230 1100 850 11000 GENERAL LIABILITY 120000 45000 15000 105000 15000 300000 AUTOMOBILE 42000 14000 17500 21000 5500 100000 AUTO PHYSICAL 8350 2750 3650 4200 1050 20000 WORKERS COMP 55500 15000 19500 30000 30000 150000 D&O 15000 15000 15000 15000 122000 182000 PENSION 2493 662 7046 1195 954 12350 POLLUTION 91000 31500 15000 54000 63500 25500 UNDERGROUND TANKS 1300 2550 2050 2550 2550 11000 EXCESS LIABILITY 130500 42500 100000 70000 37000 380000 LETTER OF CREDIT 25000 25000 MONTAUP EXTRA EXP 140000 140000 BOND PREMIUM 15000 15000 SMALL CLAIM EXPENSE 247500 88000 27500 126500 60500 550000 $762,597 $392,910 $299,539 $499,881 $735,323 $2,690,250
DDRL #102 Question: List all liability, property, casualty, and other insurance policies held by the Company or its subsidiaries, or if self insured, the extent of self insurance, including limits of coverage, policy dates, premiums, insurance brokers, and cash surrender value, if any. Answer: The person in the organization responsible for risk management is not involved in the data request process. At this point in the process the information we will provide will be very limited. Attached you will find the planned 1999 expenses by category. Once the sale of Montaup is complete, the insurance expenses will be prorated for the remainder of the policy year. DDRL #103 Question: Describe all claims made by the Company or its subsidiaries under the insurance policies carried by the Company or its subsidiaries over the past two years in which the amount claimed exceeded $1,000,000. Answer: To the best of my knowledge, none. DDRL 104 Question: List and describe any pending litigation relating to insurance coverage. Answer: To the best of my knowledge there are two cases. 1. The family of a deceased woman in Fall River has filed a claim against the Company. The woman died as a result of a pedestrian truck accident involving an EUA driver in a meter van. The driver was not found to be negligent. Maximum exposure to the Company is $350,000. 2. A civilian has placed a claim with the Company as a result of a manhole explosion. The civilian received burns over 30% of his body. He has nearly fully recovered and is looking for medical expense recovery. We expect to settle for a reasonable amount. The maximum exposure is $350,000. In both cases the insurance will cover anything over the $350,000. Neither case is expected to exceed the $350,000 deductible. DDRL #105 Question: Copies of all material correspondence with insurers or insurance brokers or agents relating to environmental impairment liability claims. Answer: Did not have access to the information
Professional Services in $000 1997 BE EE NE Service Total Addit. data req #38 1,610 7,964 446 1,956 11,976 incl. ops-related Savings % Savings Accounting 34 63 31 69 197 50% 99 Legal incl dereg McDermott 33 1,209 17 360 Isaacson 744 Other 2 73 46 83 Total 779 1,282 63 443 2,567 adj. 1,500 33% 495 Employment 118 118 33% 39 Consulting 40 40 100% 40 Invest. Svcs 108 108 100% 108 Legislative 48 48 100% 48 Prof Svcs Total 2,011 41% 828 Escalation to 2000 1.093 Savings in 2000 905 Engineering 39 1 40 Environmental 20 12 32 Conservation 27 2,548 141 - 2,716 Facilities/Cleaning 40 162 202 incl in facilities calculation Security 125 125 incl in facilities calculation Misc Other 314 421 735 Tree Trimming 687 1,334 187 352 2,560 Misc Contract Svcs 1,606.0 1,606 8,016 10,027
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 38 List of professional services purchased by major area, e.g. a) Audits and accounting b) Legal c) Information systems See attached.
BLACKSTONE VALLEY ELECTRIC PROFESSIONAL SERVICES VENDOR NAME DESCRIPTION OF SERVICE 1997 ----------- ---------------------- ---- Asplundh Tree Trimming 56,222 Barnes Tree Services Tree Trimming 140,399 Blackstone Valley Security Security Services 0 Clean Harbor Environmental 19,603 Coopers & Lybrand Accounting 34,145 Credit Bureau Collection Fees 20,959 Dickstein, Shapiro & Moris Legal Financial Collection Collection Fees 1,149 Isaacson, Rosenbaum Legal 743,568 McDermott, Will & Emery Legal 32,578 Northern Tree Service Tree Trimming 491,290 Ocean State Janitorial Cleaning 40,408 Osmose Wood Press Pole Treatment/Inspection 448 Stanley Bleeker, Esq. Legal 0 Tillinghast, Collins & Graham Legal 1,911 (A) Coflax Packing Conservation 1,214 (A) Delta Electric Motor Conservation 639 (A) RISE Conservation 7,690 (A) Slater Dye Works Conservation 17,313 --------------------- 1,809,534 ===================== (A) These vendors participated in Eastern Edison's conservation, load, management programs, management programs. NOTE: The source for this information was based on o&m codes 9, 10, 11 & 16. Prepared by Michelle Uzzo 12/22/98
EASTERN EDISON COMPANY PROFESSIONAL SERVICES VENDOR NAME DESCRIPTION OF SERVICE 1997 ----------- ---------------------- ---- American Staffing Assoc. Employment 118,240 Asplundh Tree Trimming 919,253 Barnes Tree Service Tree Trimming 140,782 Clean Harbors Environmental Coopers and Lybrand Accounting 62,883 Duff & Phelps Consulting 40,000 Environmental Protection Service Maintenance 44,555 First Financial Resources Collection Fees 33,933 First Security Services Security Hanson Police Dept. Police Detail 31,478 J. D. Payroll Services Temp Services MASS Save Consulting 342,286 McDermott, Will & Emery Legal 1,209,446 Misc. Contract Services* 1,605,966 Misc. Engineering* 38,605 Misc. Legal* 12,155 Miscellaneous* 314,463 Osmose Wood Press Pole Treatment/Inspection Pembroke Police Dept. Police Detail R.A. Gill Tree Service Tree Trimming 227,341 R.E. Tilgren Tree Trimming 46,695 Reed, Adami, Kaiser Legal 72,589 Rockland Police Dept. Police Detail 26,218 Service Master Maintenance 29,796 State Street Bank & Trust Trustee/Administrative Fee Suburban Contract Cleaning Town of Bridgewater Police Detail Town of Easton Police Detail 56,526 Town of Norwell Police Detail 42,745 Town of Scituate Police Detail Town of Stoughton Police Detail (A) Conservation Services Group Conservation 361,903 (A) Demand Mgmt Conservation (A) Energie Innovation Inc. Conservation 84,095 (A) Energy Conservation Conservation 123,124 (A) Energy Federation Conservation 306,904 (A) Fall Realty & Harris Energy Conservation 38,353 (A) Fleet Bank Conservation 28,182 (A) Harris Energy Systems Conservation 489,801 (A) J&R Industrial Wiring Conservation 206,124 (A) Main Street Textiles Conservation 133,990 (A) MUPAC Corp & Harris Energy Conservation 26,114 (A) National Resource Mgmt. Conservation 375,923 (A) Relocation Resources, Inc. Conservation 61,985 (A) Shews Supermarkets Inc. Conservation 168,265 (A) Star Market & Harris Energy Conservation 31,080 (A) Stop & Shop Supermarket Co. Conservation 49,799 (A) Ware Rite & Harris Energy Conservation 32,759 (A) Whaling Mfg. Co., Inc. Conservation 29,235 ------------------- 7,963,604 =================== * Aggregate amounts to any one entity less than $25,000 have been accumulated in this description. (A) These vendors participated in Eastern Edison's conservation, load, management programs, management programs. NOTE: The source for this information was found on o&m codes 9, 10, 11 & 12.
NEWPORT ELECTRIC CORPORATION PROFESSIONAL SERVICES VENDOR NAME DESCRIPTION OF SERVICE 1997 ----------- ---------------------- ---- Barnes Tree Services Tree Trimming 187,208 Clean Harbor Environmental 11,989 Coopers & Lybrand Accounting 30,982 Credit Info Collection Fees 12,118 McDermott, Will & Emery Legal 16,808 Morgan, Brown & Joy Legal 340 RISE Conservation 141,057 Tillinghast, Collins & Graham Legal 45,587 ----------------- 446,062 ================= NOTE: The source for this information was based on o&m codes 9, 10, 11 & 19.
EUA SERVICE CORP. PROFESSIONAL SERVICES (Account # 923) VENDOR NAME DESCRIPTION OF SERVICE 1997 ----------- ---------------------- ---- McDermott, Will & Emery Legal 359,773 First Security Services Security 124,975 Contract Cleaning Collaborative Cleaning Eastern Edison Company Arborist/Technical Trainers 351,846 Salomon Brothers Inc. Investment Services 107,986 Media Concepts Printing Services 114,897 Norfolk Data Data Processing Time Cards Cambridge Reports, Inc. Customer Services 70,560 J. Flanagan & Co. Legislative Activity 48,000 DRI McGraw-Hill Newport Electric Corp. Arborist/Technical Trainers Twenty First Century AUC Management Consultants Consulting Misc. Legal * 82,677 Misc. Accounting * 68,988 Misc. EDP * 41,871 Misc. Building & Maintenance* 162,203 Other * 421,494 Misc. Engineering * 768 ----------------- 1,956,038 ================= * Payments made to payee is less than $100,000 Amounts in Bold print are estimates based on the average of 1996 & 1997. Prepared by Michelle Uzzo 12/22/98 a:\profsvs
REGULATORY EXPENSES in $000 1997 1997 EUA NEES Addit. data req #42 1,002 FERC acct #928 4,008 Assessments 739 Filings and misc. 263 Total 1,002 Savings on filings and misc. 20% Savings in 1997 53 Escalation to 2000 1.09 Savings in 2000 57
12/19/98 PRIVILEGED AND CONFIDENTIAL ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION REQUEST LIST ATTORNEY WORK PRODUCT ADDRL # 42 Summary of regulatory expenses. 1997 Newport Blackstone Eastern Total ---- ------- ---------- ------- ----- PUC Assessment 119,983 267,118 387,101 DTE Assessment 351,663 351,663 Tariff Filings & Misc. 57,258 144,113 61,899 263,270 ------- ------- ------ ------- 177,241 411,231 413,562 1,002,034
Cost to Achieve in $000 Total Basis for Cost Estimate - ---------------------------------------------------------------------------------------------------------------------------------- Transaction Costs Bankers fees 7,500 Estimate from NEES and EUA Legal fees 3,500 Estimate for NEES and EUA D&O liability tail coverage 400 1.5 times EUA's current annual D&O liability premium Total Transaction Costs 11,400 - ---------------------------------------------------------------------------------------------------------------------------------- Personnel Costs Separation/Retention 35,150 Relocation 2,750 Cost equals 90 employees required to relocate @ $25,000 per employee; also includes $500,000 miscellaneous Retraining 1,950 Cost includes: Customer service training: 100 employees x 4 weeks @ $1,000 per week ($400,000) Meter reader training: 50 employees x 1 week @ $1,000 per week ((50,000) Transmission and distribution training: 200 employees x 3 weeks @ $1,500 per week ($900,000) Administrative functions training: 100 employees x 4 weeks @ $1,500 per week ($600,000) General reorientation 250 Cost to train 500 employees x 2 days @ $250 per day ($250,000) Total Personnel Costs 40,100 - ---------------------------------------------------------------------------------------------------------------------------------- Transition Costs Internal Support 810 Cost equals 15 employees x 9 months @ $6,000 per month ($810,000) No cost shown 35 employees working on transition in addition to regular workload Outside Support 2,000 Cost for organizational and change management consultants and other outside support Communications 500 Costs for both internal and external communication Facilities Consolidation 1,000 Estimate based on other transactions Other 250 Cost of changing corporate signage, stationary, etc. Total Transition Costs 4,560 - ---------------------------------------------------------------------------------------------------------------------------------- Information Systems Systems Integration and Data 6,600 Cost of application integration and data conversion; cost to close one data center Center Consolidation Meter Reading Hardware 600 Cost to outfit EUA meter readers with 55 new ITRON devices Telecommunications Costs 350 Cost to connect telecommunications networks; reconfigure and reprogram customer service center switch Total Information Systems Costs 7,550 - ---------------------------------------------------------------------------------------------------------------------------------- Total Cost to Achieve 63,610
D&O Tail Coverage Conversation with Diane Kenney Coverage Premiums EUA in Millions in Thousands Policy #1 25 232 Policy #2 10 47 35 279 Budget for tail coverage 150% 419 Cost to achieve 400
Hoffman, David - ------------------------------------------------------------------------------ From: Michael J. Hirsh [mhirsh@eua.com] Sent: Monday, April 12,1999 5:49 PM To: david-hoff man@ mercermc.corn Subject: EUA-side transaction costs David- Following up on our conversation today, our transaction costs include the following: Banker fees$4.2 million (per contract) Legal $1.6 million actual + est. ($.535 billed through Feb, assume $.3 added through April and $.1/mo Thanks. MJH Exhibit DJH-2 Miscellaneous MODEL INPUTS - -------------------------------------- Escalation rate 3% - -------------------------------------- - -------------------------------------- % labor capitalized A&G 0% Customer 0% T&D 35% - -------------------------------------- - -------------------------------------- Benefits adder 32.63% for EUA - -------------------------------------- EUA (EE) % cap % b-t cost % a-t cost wacc - --------------------------- Revenue equirement ltd 45.5% 7.6% 7.6% 3.5% Rate ps 5.5% 9.8% 16.3% 0.9% cse 49.0% 11.5% 19.2% 9.4% Non-IS(30 yr) 13.5% 13.7% IS (5 yr) 28.6% - --------------------------- NEES(MECo) % cap % b-t cost % a-t cost wacc ltd 44.0% 7.5% 7.5% 3.3% - --------------------------- Fixed Charge Rate ps 5.9% 6.3% 10.5% 0.6% on EUA inventory 13.7% cse 50.1% 11.0% 18.3% 9.2% - --------------------------- 13.1% Depreciation on distribution plant x land depr ave plant % yrs MECo 47,760 1,466,280 3.26% 30.7 NECo 17,744 543,775 3.26% 30.6 EE 9,139 213,037 4.29% 23.3 BV 4,067 98,925 4.11% 24.3 Average 78,710 2,322,016 3.39% 29.5 NEES 2,010,055 87% EUA 311,961 13% 2,322,016
ADDRL #21 N21 % of employee benefits, taxes and unproductive time, i.e., Vacations, holidays, sick, jury duty. (Benefits & Unproductive / Productive Wages). Blackstone Valley 54.24% Eastern Edison 53.64% Newport Electric 61.91% EUA Service Corp 52.91% % of payroll charged to O&M and to Capital O&M Capital Blackstone Valley 23.7% 76.3% Eastern Edison 26.4% 73.6% Newport Electric 22.5% 77.5% EUA Service Corporation wages billed to companies Blackstone Valley 95.3% 4.7% Eastern Edison 92.6% 7.4% Newport Electric 94.6% 5.4%
Capital Payroll by Function Payroll Capital Percent Total Payroll To Capital Total A&G 31,138,865 1,416,698 (Note 1) 4.55% Total Retail Svcs 11,567,105 11,327 0.10% Customer Service Northboro Inquiry 6,533,923 0 0.00% Meters 1,445,504 16,713 1.16% Collections 460,700 0 0.00% Cust Ld Analysis 464,638 0 0.00% --------- ------ 8,904,765 16,713 0.19% Providence Inquiry 3,531,849 0 0.00% Meter Read 2,648,213 0 0.00% Meter OPs 1,378,950 302,358 21.93% --------- ------- 7,117,580 302,358 4.25% MValley Inquiry 975,652 0 0.00% Meter Read 2,121,637 0 0.00% Meter OPs 1,082,295 138,419 12.79% --------- ------- 4,179,584 138,419 3.31% North Shore Inquiry 362,948 0 0.00% Meter Read 2,253,417 0 0.00% Meter OPs 907,277 106,033 11.69% --------- ------- 3,523,642 106,033 3.01% ========= M Valley/ N Shore 7,703,228 244,452 3.17% West Inquiry 222,012 0 0.00% Meter Read 1,174,272 0 0.00% Meter OPs 621,829 10,811 1.74% --------- ------ 2,018,113 10,811 0.54% Central Inquiry 468,606 0 0.00% Meter Read 1,519,383 0 0.00% Meter OPs 722,902 61,649 8.52% --------- ------ 2,578,891 61,649 2.39% ========= Central/West 4,597,004 72,460 1.58% Southeast Inquiry 614,464 0 0.00% Meter Read 1,453,783 0 0.00% Meter OPs 634,979 27,813 4.38% --------- ------ 2,573,226 27,813 1.08% Management 221,586 0 0.00% Total Customer Service 30,373,079 663,796 2.19%
CAPITAL PAYROLL BY FUNCTION Payroll Capital Percent Total Payroll To Capital Operations (Note A) Engineering 7,133,255 1,883,343 26.40% Dispatch 3,156,387 4,485 0.14% Const Svcs 18,732,509 12,200,687 65.13% T&D Svcs 6,910,541 901,301 13.04% Env/Safety 768,947 9,269 1.21% MValley/Gseco 15,120,701 4,519,335 29.89% North Shore 10,961,770 3,325,721 30.34% West 7,769,538 2,259,936 29.09% Central 16,202,800 4,890,090 30.18% Southeast 14,412,473 4,399,649 30.53% Providence 18,495,146 5,927,166 32.05% Mgmt 854,059 0 0.00% ------- - Total Operations 120,318,126 40,320,982 33.51% Executive 1,799,736 0 0.00% Total Wires 149,648,046 40,996,105 27.40% Wires plus A&G 181,215,151 40,007,432 25.44% Note A Detail costs excludes the following: Stores (district level) 3,823,817 42,819 1.12% Transportation (T&D Sv) 2,774,631 44,052 1.59% Note 1 A&G Capital payroll includes A&G credit of $1,409,148
This Report Is: Name of Respondent (1) [x] An Original Date of Report Year of Report Massachusetts Electric Company (2) [ ] A Resubmisson (Mo, Da, Yr) Dec. 31, 1997 - ---------------------------------------------------------------------------------------------------------------------------------- GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE - ---------------------------------------------------------------------------------------------------------------------------------- 1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the to cover, (b) the general procedure for determining the amount provisions of Electric Plant Instructions 3(17) of the capitalized, (c) the method of distribution to constrution U.S. of A. tion jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used, types of construction, (e) basis of differentiation in rates show the appropriate tax effect adjustment to the computa- different types of construction, and (f) whether the overhead tions below in a manner that clearly indicates the amount is directly or indirectly assigned. of reduction in the gross rate for tax effects. - ---------------------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------- COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES --------------------------------------------------------------------------------- For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average rate earned during the preceding three years. - ---------------------------------------------------------------------------------------------------------------------------------- 1. Components of Formula (Derived from actual book balances and actual cost rates): - ---------------------------------------------------------------------------------------------------------------------------------- Capitalization Cost Rate Line Title Amount Ratio (Percent) Percentage No. (a) (b) (c) (d) (1) Average Short-Term Debt S $29,054,000 (2) Short-Term Interest s 5.63% (3) Long-Term Debt D $375,000,000 44.01% d 7.46% (4) Preferred Stock P $50,000,000 5.87% p 6.30% (5) Common Equity C $427,061,000 50.12% c 11.00% (6) Total Capitalization $852,061,000 100% (7) Average Construction Work in Progress Balance W $17,700,000 - ---------------------------------------------------------------------------------------------------------------------------------- 2. Gross Rate for Borrowed Funds S D S s(--) + d ( -- ) (1---) 5.63% W D+P+C W - ---------------------------------------------------------------------------------------------------------------------------------- 3. Rate for Other Funds S P C [ 1 - -- ] [ p(-- -) + c(--) ] 0 W D+P+C D+P+C - ---------------------------------------------------------------------------------------------------------------------------------- 4. Weighted Average Rate Actually Used for the Year: a. Rate for Borrowed Funds - 5.71% b. Rate for Other Funds - 0 - ----------------------------------------------------------------------------------------------------------------------------------
This Report Is: Date of Report Name of Respondent (1) [x] An Original (Mo, Da, Yr) Year of Report Massachusetts Electric Company (2) [ ] A Resubmisson 03/31/98 Dec. 31, 1997 - --------------------------------------------------------------------------------------------------------------------------------- GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE - --------------------------------------------------------------------------------------------------------------------------------- 1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the to cover, (b) the general procedure for determining the provisions of Electric Plant Instructions 3(17) of the amount capitalized, (c) the method of distribution to construction U.S. of A. jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used, types of construction, (e) basis of differentiation in rates show the appropriate tax effect adjustment to the computations different types of construction, and (f) whether the overhead below in a manner that clearly indicates the amount is directly or indirectly assigned. of reduction in the gross rate for tax effects. - --------------------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------- COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES --------------------------------------------------------------------------------- For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average rate earned during the preceding three years. - --------------------------------------------------------------------------------------------------------------------------------- 1. Components of Formula (Derived from actual book balances and actual cost rates): - ---------------------------------------------------------------------------------------------------------------------------------- Capitalization Cost Rate Line Title Amount Ratio (Percent) Percentage No. (a) (b) (c) (d) (1) Average Short-Term Debt S $5,117,538 (2) Short-Term Interest s 6.58% (3) Long-Term Debt D $223,000,000 45.48% d 7.62% (4) Preferred Stock P $27,034,771 5.51% p 9.83% (5) Common Equity C $240,213,303 49.0% c 11.50% (6) Total Capitalization $490,248,074 100% (7) Average Construction Work in Progress Balance W $4,399,855 - ---------------------------------------------------------------------------------------------------------------------------------- 2. Gross Rate for Borrowed Funds S D S s(--) + d(--) (1---) 6.58% W D+P+C W - ---------------------------------------------------------------------------------------------------------------------------------- 3. Rate for Other Funds S P C [ 1 - -- ] [ p(-- -) + c(--) ] 0 W D+P+C D+P+C - ---------------------------------------------------------------------------------------------------------------------------------- 4. Weighted Average Rate Actually Used for the Year: a. Rate for Borrowed Funds - 6.58% b. Rate for Other Funds - - ----------------------------------------------------------------------------------------------------------------------------------
This Report Is: Date of Report Name of Respondent (1) [x] An Original (Mo, Da, Yr) Year of Report Massachusetts Electric Company (2) [ ] A Resubmisson 03/31/98 Dec. 31, 1997 - --------------------------------------------------------------------------------------------------------------------------------- GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE - --------------------------------------------------------------------------------------------------------------------------------- 1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the to cover, (b) the general procedure for determining the provisions of Electric Plant Instructions 3(17) of the amount capitalized, (c) the method of distribution to construction U.S. of A. jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used, types of construction, (e) basis of differentiation in rates show the appropriate tax effect adjustment to the computations different types of construction, and (f) whether the overhead below in a manner that clearly indicates the amount is directly or indirectly assigned. of reduction in the gross rate for tax effects. - --------------------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------- COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES --------------------------------------------------------------------------------- For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average rate earned during the preceding three years. - --------------------------------------------------------------------------------------------------------------------------------- 1. Components of Formula (Derived from actual book balances and actual cost rates): - ---------------------------------------------------------------------------------------------------------------------------------- Capitalization Cost Rate Line Title Amount Ratio (Percent) Percentage No. (a) (b) (c) (d) (1) Average Short-Term Debt S $3,501,308 (2) Short-Term Interest s 7.11% (3) Long-Term Debt D $36,500,000 46.29% d 9.35% (4) Preferred Stock P $6,129,500 7.77% p 4.81% (5) Common Equity C $36,232,083 45.94% c 11.43% (6) Total Capitalization $78,861,583 100% (7) Average Construction Work in Progress Balance W $1,965,253 - ---------------------------------------------------------------------------------------------------------------------------------- 2. Gross Rate for Borrowed Funds S D S s(--) + d(--) (1---) 7.11% W D+P+C W - ---------------------------------------------------------------------------------------------------------------------------------- 3. Rate for Other Funds S P C [ 1 - -- ] [ p(-- -) + c(--) ] 0 W D+P+C D+P+C - ---------------------------------------------------------------------------------------------------------------------------------- 4. Weighted Average Rate Actually Used for the Year: a. Rate for Borrowed Funds - 7.11% b. Rate for Other Funds - 0 - ----------------------------------------------------------------------------------------------------------------------------------
3. Stock-based compensation At December 31, 1997, NEES has three stock-based compensation plans and measures its compensation cost for those plans using the method of accounting prescribed by Accounting Principles Board Opinion No. 25. Accounting for Stock Issued to Employees, and related interpretations. The compensation cost that has been charged against income for these plans was $3.3 million, $3.7 million and $1.6 million for 1997, 1996, and 1995, respectively. If compensation cost for stock-based compensation had been accounted for under Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, the 1997 cost figures shown above would have been slightly smaller. Total income taxes in the statements of consolidated income are as follows: - ---------------------------------------------------------------------------------------------------------------------------------- Year ended December 31 (thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------------------------- Income taxes charged to operations $152,024 $139,199 $128,340 Income taxes charged to "Other income" (7,268) (3.018) 762 - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes $144,756 $136,181 $129,102 - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes, as shown above, consist of the following components: Year ended December 31 (thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------------------------- Current income taxes $175,934 $166,509 $105,046 Deferred income taxes (29,260) (28,652) 25,578 Investment tax credits, net (1,918) (1,676) (1,522) - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes $144,756 $136,181 $129,102 - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes, as shown above, consist of federal and state components as follows: - ---------------------------------------------------------------------------------------------------------------------------------- Year ended December 31 (thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------------------------- Federal income taxes $118,317 $111,573 $103,503 State income taxes 26,439 24,608 25,599 - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes $144,756 $136,181 $129,102 - ---------------------------------------------------------------------------------------------------------------------------------- Investment tax credits of subsidiaries are deferred and amortized over the estimated lives of the property giving rise to the credits. Although investment tax credits were generally eliminated by the 1986 tax legislation, additional carryforward amounts continue to be recognized. With regulatory approval, the subsidiaries have adopted comprehensive interperiod tax allocation (normalization) for temporary book/tax differences. Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows: - ---------------------------------------------------------------------------------------------------------------------------------- Year ended December 31 (thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------------------------- Computed rate at statutory rate $131,989 $123,053 $119,892 Increases (reductions) in tax resulting from Reversal of deferred taxes recorded at a higher rate (2,216) (2,175) (3,306) Amortization of investment tax credits (4,469) (4,347) (4,443) State income tax, net of federal income tax benefit 17,185 15,995 16,639 All other differences 2,267 3,655 320 - ---------------------------------------------------------------------------------------------------------------------------------- Total income taxes $144,756 $136,181 $129,102 - ----------------------------------------------------------------------------------------------------------------------------------
Percentage of employee benefits, taxes as a percentage of total wages. Company Percentage Blackstone Valley Electric Co. 30.45% Eastern Edison Co. 31.74% Newport Electric Corp. 38.16% EUA Service Corp. 32.75% Composite Percentage of employee benefits, taxes as a percentage of total wages for companies listed above Composite Description Amount Percentage Taxes & Benefits $16,030,158.00 Total Labor $49,132,790.00 32.63%
Com Energy 1997 O&M in $000 Com Elec Cambr Elec Total Elec Com Gas Total transmission 6,667 5,612 12,279 distribution 25,239 4,085 29,324 customer accounts 15,579 2,197 17,776 csi and sales 7,639 1,760 9,399 a&g(not adj.) 40,763 12,323 53,086 30,919 Total O&M 95,887 25,977 121,864 30,919 152,783 DSM expenditures 5,500 5,500 Net O&M 116,364 147,283 customers in 000 322.3 44.9 367.2 distribution cap. additions in millions 18.4 3.5 21.9 EUA 1997 O&M in $000 Eastern Blackstone Newport Edison Valley Electric Total transmission 529 616 282 1,427 distribution 16,149 6,532 3,968 26,649 customer accounts 6,779 3,228 1,107 11,114 csi and sales 7,045 3,300 1,547 11,892 a&g (not adj.) 16,417 9,241 5,429 31,087 Total O&M 46,919 22,917 12,333 82,169 DSM expenditures 5,000 Net O&M 77,169 customers in 000 190.3 90.3 35.0 315.6 distribution cap. additions in millions 9.5 3.2 2.8 15.5 EUA 77,169 EUA 77,169 COM electric 116,364 COM total 147,283 % 66% % 52%
BEC Com Pre-Merger Savings Post-Merger 1/1/2000 Staffing 2,230 1,108 3,338 362 2,976 Customers in 000 670 370 1,040 1,040 Employees per 000 Customers 3.3 3.0 3.2 2.9 Incremental staffing to BEC 746 33% Incremental customers to BEC 370 55% NEES EUA Pre-Merger Savings Post-Merger 1/1/2000 Staffing 3,240 869 4,109 234 3,875 Customers in 000 1,340 320 1,660 1,660 Employees per 000 Customers 2.4 2.7 2.5 2.3 Incremental staffing to NEES 635 20% Incremental customers to NEES 320 24% 1997 Ave. Customers (FERC #1) Boston Edison 670 Com Elec 322 Cam Elec 45 COM Total 367 Com Gas 237 SEC 10-K Mass Elec 960 Eastern 190 Narr Elec 331 Blackstone 90 Granite State 36 Newport 35 Nantucket 10 EUA Total 316 NEES Total 1,337
New England Electric System Eastern Utilities Associates R.I.P.U.C. Docket No. ______ Exhibit DJH-3 Exhibit DJH-3 Supporting Working Papers (Confidential) AGREEMENT AND PLAN OF MERGER and CONSENT AGREEMENT dated as of February 1, 1999 TABLE OF CONTENTS AGREEMENT AND PLAN OF MERGER...................................................1 CONSENT AGREEMENT..............................................................2 Tab 1 AGREEMENT AND PLAN OF MERGER dated as of February 1, 1999 by and among NEW ENGLAND ELECTRIC SYSTEM, RESEARCH DRIVE LLC and EASTERN UTILITIES ASSOCIATES TABLE OF CONTENTS Page No. ARTICLE I THE MERGER......................................................... 1 1.01 The Merger......................................................... 1 1.02 Effective Time..................................................... 1 1.03 Effects of the Merger.............................................. 2 ARTICLE II CONVERSION OF SHARES............................................... 2 2.01 Conversion of Capital Stock........................................ 2 2.02 Surrender of Shares................................................ 3 2.03 Withholding Rights................................................. 4 ARTICLE III THE CLOSING........................................................ 4 ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EUA.............................. 5 4.01 Organization and Qualification..................................... 5 4.02 Capital Stock...................................................... 6 4.03 Authority.......................................................... 7 4.04 Non-Contravention; Approvals and Consents.......................... 7 4.05 SEC Reports, Financial Statements and Utility Reports.............. 8 4.06 Absence of Certain Changes or Events............................... 9 4.07 Legal Proceedings.................................................. 9 4.08 Information Supplied............................................... 9 4.09 Compliance......................................................... 10 4.10 Taxes.............................................................. 10 4.11 Employee Benefit Plans; ERISA...................................... 12 4.12 Labor Matters...................................................... 14 4.13 Environmental Matters.............................................. 15 4.14 Regulation as a Utility............................................ 17 4.15 Insurance.......................................................... 17 4.16 Nuclear Facilities................................................. 18 4.17 Vote Required...................................................... 18 4.18 Opinion of Financial Advisor....................................... 18 -i- Page No. 4.19 Ownership of NEES Common Shares.................................... 18 4.20 State Anti-Takeover Statutes....................................... 18 4.21 Year 2000.......................................................... 19 4.22 EUA Associates..................................................... 19 ARTICLE V REPRESENTATIONS AND WARRANTIES OF NEES............................. 19 5.01 Organization and Qualification..................................... 19 5.02 Authority.......................................................... 20 5.03 Capital Stock...................................................... 20 5.04 Non-Contravention; Approvals and Consents.......................... 20 5.05 Information Supplied............................................... 21 5.06 Compliance......................................................... 21 5.07 Financing.......................................................... 22 5.08 No Vote Required................................................... 22 5.09 Ownership of EUA Shares............................................ 22 5.10 Merger with The National Grid Group plc............................ 22 ARTICLE VI COVENANTS................................................ 22 6.01 Covenants of EUA................................................... 22 6.02 Covenants of NEES.................................................. 28 6.03 Additional Covenants by NEES and EUA............................... 29 ARTICLE VII ADDITIONAL AGREEMENTS.................................... 30 7.01 Access to Information.............................................. 30 7.02 Proxy Statement.................................................... 31 7.03 Approval of Shareholders........................................... 31 7.04 Regulatory and Other Approvals..................................... 31 7.05 Employee Benefit Plans............................................. 32 7.06 Labor Agreements and Workforce Matters............................. 34 7.07 Post Merger Operations............................................. 34 7.08 No Solicitations................................................... 35 7.09 Directors' and Officers' Indemnification and Insurance............. 36 7.10 Expenses........................................................... 37 7.11 Brokers or Finders................................................. 37 7.12 Anti-Takeover Statutes............................................. 38 7.13 Public Announcements............................................... 38 -ii- Page No. 7.14 Restructuring of the Merger........................................ 38 ARTICLE VIII CONDITIONS......................................................... 39 8.01 Conditions to Each Party's Obligation to Effect the Merger......... 39 8.02 Conditions to Obligation of NEES and LLC to Effect the Merger...... 39 8.03 Conditions to Obligation of EUA to Effect the Merger............... 40 ARTICLE IX TERMINATION, AMENDMENT AND WAIVER.................................. 41 9.01 Termination........................................................ 41 9.02 Effect of Termination.............................................. 43 9.03 Termination Fees................................................... 43 9.04 Amendment.......................................................... 44 9.05 Waiver............................................................. 44 ARTICLE X GENERAL PROVISIONS................................................. 44 10.01 Non-Survival of Representations, Warranties, Covenants and Agreements......................................................... 44 10.02 Notices............................................................ 44 10.03 Entire Agreement; Incorporation of Exhibits........................ 46 10.04 No Third Party Beneficiary......................................... 46 10.05 No Assignment; Binding Effect...................................... 46 10.06 Headings........................................................... 47 10.07 Invalid Provisions................................................. 47 10.08 Governing Law...................................................... 47 10.09 Enforcement of Agreement........................................... 47 10.10 Certain Definitions................................................ 47 10.11 Counterparts....................................................... 48 10.12 WAIVER OF JURY TRIAL............................................... 48 -iii- GLOSSARY OF DEFINED TERMS The following terms, when used in this Agreement, have the meanings ascribed to them in the corresponding Sections of this Agreement listed below: "1935 Act" -- Section 4.05(b) "Adjustment Date" -- Section 2.01(c) "Affected Employees" -- Section 7.05(a) "affiliate" -- Section 10.11(a) "Agreement" -- Preamble "Alternative Proposal" -- Section 7.08 "beneficially" -- Section 10.10(b) "business day" -- Section 10.10(c) "Canceled Shares" -- Section 2.02(b) "Certificates" -- Section 2.02(b) "Closing" -- Article III "Closing Agreement" -- Section 4.10(j) "Closing Date" -- Article III "Code" -- Section 2.03 "Confidentiality Agreement" -- Section 7.01 "Constituent Entities" -- Section 1.01 "Contracts" -- Section 4.04(a) "control," "controlling," "controlled by" and "under common control with" -- Section 10.10(a) "DOE" -- Section 4.05(b) "Effective Time" -- Section 1.02 "Environmental Claim" -- Section 4.13(f)(i) "Environmental Laws" -- Section 4.13(f)(ii) "Environmental Permits" -- Section 4.13(b) "ERISA" -- Section 4.11(a) "ERISA Affiliate" -- Section 4.11(c) "EUA" -- Preamble "EUA Associates" -- Section 4.01(b) "EUA Employee Agreements" -- Section 7.05(d)(ii) "EUA Executives" -- Section 7.05(d)(ii) "EUA Shares" -- Preamble "EUA Disclosure Letter" -- Section 4.01(a) "EUA Employee Benefit Plans" -- Section 4.11(a) "EUA Financial Statements" -- Section 4.05(a) "EUA Nuclear Facilities" -- Section 4.16 "EUA Material Adverse Effect" -- Section 4.01(a) "EUA Required Consents" -- Section 4.04(a) "EUA Required Statutory Approvals" -- Section 4.04(b) "EUA SEC Reports" -- Section 4.05(a) -iv- "EUA Shareholders' Approval" -- Section 7.03 "EUA Shareholders' Meeting" -- Section 7.03 "EUA Significant Subsidiary" -- Section 7.08 "EUA Shares" -- Preamble "EUA Trust Agreement" -- Section 1.03 "EUA Voting Debt -- Section 4.02(d) "Evaluation Material" -- Section 7.01(a) "Exchange Act" -- Section 4.05(a) "Exchange Fund" -- Section 2.02(a) "Extended Termination Date" -- Section 9.01(b) "FCC" -- Section 4.05(b) "FERC" -- Section 4.05(b) "Final Order" -- Section 8.01(d) "Governmental Authority" -- Section 4.04(a) "Hazardous Materials" -- Section 4.13(f)(iii) "HSR Act" -- Section 7.04(a) "Indemnified Liabilities" -- Section 7.09(a) "Indemnified Party" -- Section 7.09(a) "Indemnified Parties" -- Section 7.09(a) "Information Systems" -- Section 4.21 "Initial Termination Date" -- Section 9.01(b) "IRS" -- Section 4.10(m) "knowledge" -- Section 10.11(d) "laws" -- Section 4.04(a) "Lien" -- Section 4.02(b) "LLC" -- Preamble "Massachusetts Secretary" -- Section 1.02 "Merger" -- Preamble "Merger Consideration" -- Section 2.01(b)(ii) "MGL" -- Section 1.01 "National Grid Group" -- Section 5.10 "National Grid Merger Agreement" -- Section 5.10 "NEES" -- Preamble "NEES Disclosure Letter" -- Section 5.03 "NEES Material Adverse Effect" -- Section 5.01 "NEES-EUA Regulatory Approvals" -- Section 7.04(b) "NEES-EUA Regulatory Proceedings" -- Section 7.04(c) "NEES Required Consents" -- Section 5.04(a) "NEES Required Statutory Approvals" -- Section 5.04(b) "NEES-NGG Regulatory Approvals" -- Section 7.04(c) "NEES-NGG Regulatory Proceedings" -- Section 7.04(c) "NEES-NGG Required Statutory Approvals"-- Section 7.04 "NEES-NGG Transactions" -- Section 7.04 "NEES Shares" -- Section 5.03 -v- "NEES Trust Agreement" -- Section 5.01 "NGG Circular" -- Section 7.02 "NRC" -- Section 4.05(b) "Options" -- Section 4.02(a) "orders" -- Section 4.04(a) "Out-of-Pocket Expenses" -- Section 9.03(a) "Paying Agent" -- Section 2.02(a) "PBGC" -- Section 4.11(g) "person" -- Section 10.11(e) "Per Share Amount" -- Section 2.01(b)(ii) "Post Closing Plans" -- Section 7.05(b) "Proxy Statement" -- Section 4.08(a) "Release" -- Section 4.13(f)(iv) "Representatives" -- Section 10.11(f) "SEC" -- Section 4.05(a) "Securities Act" -- Section 4.05(a) "Subsidiary" -- Section 10.11(g) "Surviving Entity" -- Section 1.01 "Tax Ruling" -- Section 4.10(j) "Taxes" -- Section 4.10 "Tax Return" -- Section 4.10 "US GAAP" -- Section 4.05(a) "Yankee Companies" -- Section 4.16 "Y2K Consultant" -- Section 6.01(o) -vi- This AGREEMENT AND PLAN OF MERGER, dated as of February 1, 1999 (this "Agreement"), is made and entered into by and among NEW ENGLAND ELECTRIC SYSTEM, a Massachusetts business trust ("NEES"), RESEARCH DRIVE LLC ("LLC"), a Massachusetts limited liability company which is directly and indirectly wholly owned by NEES, and EASTERN UTILITIES ASSOCIATES, a Massachusetts business trust ("EUA"). WHEREAS, the Board of Directors of NEES, the Board of Trustees of EUA and the members of LLC have each determined that it is advisable and in the best interests of their respective shareholders and members to consummate, and have approved, the business combination transaction provided for herein in which LLC would merge with and into EUA, with EUA being the surviving entity (the "Merger"), pursuant to the terms and conditions of this Agreement, as a result of which NEES will own, directly or indirectly, all of the issued and outstanding common shares of EUA (the "EUA Shares"); WHEREAS, NEES, LLC and EUA desire to make certain representations, warranties and agreements in connection with the Merger and also to prescribe various conditions to the Merger; NOW, THEREFORE, in consideration of the mutual covenants and agreements set forth in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows: ARTICLE I THE MERGER 1.01 The Merger. Upon the terms and subject to the conditions of this Agreement, at the Effective Time (as defined in Section 1.02), LLC shall be merged with and into EUA in accordance with Section 2 of Chapter 182 and Section 59 of Chapter 156C of the Massachusetts General Laws ("MGL"). At the Effective Time, the separate existence of LLC shall cease and EUA shall continue as the surviving entity in the Merger. EUA, after the Effective Time, is sometimes referred to herein as the "Surviving Entity" and EUA and LLC are sometimes referred to herein as the "Constituent Entities". The effect and consequences of the Merger shall be as set forth in Article II. 1.02 Effective Time. Subject to the provisions of this Agreement, on the Closing Date (as defined in Article III), a certificate of merger shall be executed and filed by EUA and LLC with the Secretary of the Commonwealth of Massachusetts (the "Massachusetts Secretary"). The Merger shall become effective at the time of the filing of the certificate of merger relating to the Merger with the Massachusetts Secretary, or at such later time as is specified in the certificate of merger (such date and time being referred to herein as the "Effective Time"). 1.03 Effects of the Merger. At the Effective Time, the Agreement and Declaration of Trust of EUA (the "EUA Trust Agreement") as in effect immediately prior to the Effective Time shall be the agreement and declaration of trust of the Surviving Entity, until thereafter amended as provided by law and such agreement and declaration of trust. Subject to the foregoing, the additional effects of the Merger shall be as provided in the applicable provisions of Section 2 of Chapter 182 of the MGL and Section 62 of the Limited Liability Company Act of Massachusetts. ARTICLE II CONVERSION OF SHARES 2.01 Conversion of Capital Stock. At the Effective Time, by virtue of the Merger and without any action on the part of the holder thereof: (a) Membership Interests of LLC. Each one percent of the issued and outstanding membership interests in LLC shall be converted into one transferable certificate of participation or share of the Surviving Entity. (b) Conversion of EUA Shares. (i) Cancellation of Treasury Shares and Shares Owned by NEES and Subsidiaries. All EUA Shares that are owned by EUA as treasury shares and any EUA Shares owned by NEES or any other wholly owned Subsidiary (as defined in Section 10.11) of NEES shall be canceled and retired and shall cease to exist and no cash or other consideration shall be delivered in exchange therefor. (ii) Conversion of EUA Shares. Each EUA Share issued and outstanding immediately prior to the Effective Time (other than shares to be canceled in accordance with Section 2.01(b)(i)) shall be canceled and converted in accordance with the provisions of this Section 2.01 into the right to receive cash in the amount (the "Per Share Amount") of $31.00 as such amount may hereafter be adjusted in accordance with Section 2.01(c) hereof (the "Merger Consideration"), payable, without interest, to the holder of such EUA Share, upon surrender, in the manner provided in Section 2.02 hereof, of the certificate formerly evidencing such share. (c) Adjustment in Amount of Merger Consideration. In the event that the Closing Date shall not have occurred on or prior to the date that is the six (6) month anniversary of the date on which EUA Shareholders' Approval is obtained (the "Adjustment Date"), the Per Share Amount shall be increased, for each day after the Adjustment Date up to and including the day which is one day prior to the earlier of the Closing Date and the Extended Termination Date, by an amount equal to $0.003. -2- 2.02 Surrender of Shares. (a) Deposit with Paying Agent. Prior to the Effective Time, NEES shall designate a bank or trust company reasonably acceptable to EUA to act as agent (the "Paying Agent") for the benefit of the holders of EUA Shares in connection with the Merger to receive the funds to which holders of EUA Shares shall become entitled pursuant to Section 2.01(b)(ii) (the "Exchange Fund"). From time to time at, immediately prior to or after the Effective Time, NEES or LLC shall make or cause to be made available to the Paying Agent immediately available funds in amounts and at the times necessary for the payment of the Merger Consideration upon surrender of Certificates (as defined in Section 2.02(b)) in accordance with Section 2.02(b), it being understood that any and all interest or other income earned on funds made available to the Paying Agent pursuant to this Section 2.02(a) shall belong to and shall be paid (at the time provided for in Section 2.02(e)) as directed by NEES or LLC. Any such funds deposited with the Paying Agent by NEES shall be invested by the Paying Agent as directed by NEES or LLC. (b) Exchange Procedure. As soon as practicable after the Effective Time, the Paying Agent shall mail to each holder of record of a certificate or certificates (the "Certificates") which immediately prior to the Effective Time represented outstanding EUA Shares (the "Canceled Shares") that were canceled and became instead the right to receive the Merger Consideration pursuant to Section 2.01(b)(ii): (i) a letter of transmittal in such form as NEES and EUA may reasonably agree (which shall specify that delivery shall be effected, and risk of loss and title to the Certificates shall pass, only upon actual delivery of the Certificates to the Paying Agent) and (ii) instructions for effecting the surrender of the Certificates in exchange for the Merger Consideration. Upon surrender of a Certificate or Certificates to the Paying Agent for cancellation (or to such other agent or agents as may be appointed by NEES and are reasonably acceptable to EUA), together with a duly executed letter of transmittal and such other documents as the Paying Agent shall require, the holder of such Certificate shall be entitled to receive the Merger Consideration in exchange for each EUA Share formerly evidenced by such Certificate which such holder has the right to receive pursuant to Section 2.01(b)(ii). In the event of a transfer of ownership of Canceled Shares which is not registered in the transfer records of EUA, the Merger Consideration in respect of such Canceled Shares may be given to the transferee thereof if the Certificate or Certificates representing such Canceled Shares is presented to the Paying Agent, accompanied by all documents required to evidence and effect such transfer and by evidence satisfactory to the Paying Agent that any applicable stock transfer taxes have been paid. At any time after the Effective Time, each Certificate shall be deemed to represent only the right to receive the Merger Consideration subject to and upon the surrender of such Certificate as contemplated by this Section 2.02. No interest shall be paid or will accrue on the Merger Consideration payable to holders of Certificates pursuant to Section 2.01(b)(ii). (c) No Further Ownership Rights in EUA Shares. The Merger Consideration paid upon the surrender of Certificates in accordance with the terms of Section 2.01(b)(ii) shall be deemed to have been paid at the Effective Time in full satisfaction of all rights pertaining to EUA Shares represented thereby. From and after the Effective Time, the share transfer books of EUA shall be closed and there shall be no further registration of transfers thereon of EUA Shares which were outstanding immediately prior to the Effective Time. -3- If, after the Effective Time, Certificates are presented to NEES for any reason, they shall be canceled and exchanged as provided in this Section 2.02. (d) Lost, Stolen or Destroyed Certificates. In the event any owner of any Certificate shall claim that such Certificate shall have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the owner of such Certificate and delivery of that affidavit to the Paying Agent and, if required by NEES or LLC, the posting by such person of a bond in customary amount as indemnity against any claim that may be made against NEES, EUA or the Surviving Entity with respect to such Certificate, the Paying Agent will issue in exchange for such lost, stolen or destroyed Certificate the Merger Consideration payable upon due surrender of, and deliverable pursuant to this Section 2.02 in respect of, EUA Shares to which such Certificate relates. (e) Termination of Exchange Fund. Any portion of the Exchange Fund which remains undistributed to the shareholders of EUA for one (1) year after the Effective Time shall be delivered to the Surviving Entity, upon demand, and any Shareholders of EUA who have not theretofore complied with this Article II shall thereafter look only to the Surviving Entity (subject to abandoned property, escheat and other similar laws) as general creditors for payment of their claim for the Merger Consideration payable upon due surrender of the Certificates held by them. None of NEES, LLC or the Surviving Entity shall be liable to any former holder of EUA Shares for the Merger Consideration delivered to a public official pursuant to any applicable abandoned property, escheat or similar law. 2.03 Withholding Rights. Each of the Surviving Entity and NEES shall be entitled to deduct and withhold from the consideration otherwise payable pursuant to this Agreement to any holder of EUA Shares such amounts as it is required to deduct and withhold with respect to the making of such payment under the Internal Revenue Code of 1986, as amended (the "Code"), or any other provision of state, local or foreign tax law. To the extent that amounts are so withheld by the Surviving Entity or NEES, as the case may be, such withheld amounts shall be treated for all purposes of this Agreement as having been paid to the holder of EUA Shares in respect of which such deduction and withholding was made by the Surviving Entity or NEES, as the case may be. ARTICLE III THE CLOSING The closing of the Merger and other transactions contemplated hereby (the "Closing") will take place at the offices of Skadden, Arps, Slate, Meagher & Flom LLP, 919 Third Avenue, New York, New York 10022, at 10:00 a.m., local time, on the second business day following satisfaction or waiver (where applicable) of the conditions set forth in Article VIII (other than those conditions that by their nature are to be fulfilled at the Closing, but subject to the fulfillment or waiver of such conditions), unless another date, time or place is agreed to in writing by the parties hereto (the "Closing Date"). -4- ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EUA EUA represents and warrants to NEES and LLC as follows: 4.01 Organization and Qualification. (a) EUA is a voluntary association duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has full power, authority and legal right to own its property and assets and to transact the business in which it is engaged. Each of EUA's Subsidiaries is a corporation duly organized or incorporated, validly existing and in good standing under the laws of its jurisdiction of organization or incorporation and has full corporate power and authority to conduct its business as and to the extent now conducted and to own, use and lease its assets and properties, except where failure to be so organized or incorporated, existing and in good standing or to have such power and authority, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. As used in this Agreement, the term "EUA Material Adverse Effect" means a material adverse effect on the business, assets, results of operations, condition (financial or otherwise) or prospects of EUA and its Subsidiaries taken as a whole. Each of EUA and its Subsidiaries is duly qualified, licensed or admitted to do business and is in good standing in each jurisdiction in which the ownership, use or leasing of its assets and properties, or the conduct or nature of its business, makes such qualification, licensing or admission necessary, except where failure to be so qualified, licensed or admitted and in good standing, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. Section 4.01 of the letter dated the date hereof and delivered to NEES and LLC by EUA concurrently with the execution and delivery of this Agreement (the "EUA Disclosure Letter") sets forth (i) the name and jurisdiction of incorporation or organization of each Subsidiary of EUA, (ii) such Subsidiary's authorized capital stock, (iii) the number of issued and outstanding shares of capital stock of such Subsidiary and (iv) the number of shares of such Subsidiary held of record by EUA. EUA has previously delivered to NEES correct and complete copies of the EUA Trust Agreement and the certificate or articles of organization or incorporation and bylaws (or other comparable charter documents) of its Subsidiaries. (b) Section 4.01 of the EUA Disclosure Letter sets forth a description as of the date hereof, of all EUA Associates, including (i) the name of each such entity and EUA's interest therein and (ii) a brief description of the principal line or lines of business conducted by each such entity. For purposes of this Agreement "EUA Associates" shall mean any corporation or other entity (including partnerships and other business associations) that is not a Subsidiary of EUA in which EUA and/or one or more of its Subsidiaries, directly or indirectly, owns an equity interest (other than short-term investments in the ordinary course of business) if such corporation or other entity (including partnerships and other business associations) contributes five percent or more of EUA's consolidated revenues, assets, income or costs. -5- 4.02 Capital Stock. (a) The authorized equity securities of EUA consists of 36,000,000 EUA Shares, of which 20,435,997 shares were issued and outstanding as of the close of business on January 29, 1999. As of the close of business on January 29, 1999, no EUA Shares were held in the treasury of EUA. Since such date there has been no change in the sum of the issued and outstanding EUA Shares. All of the issued and outstanding EUA Shares are duly authorized, validly issued, fully paid and nonassessable. Except pursuant to this Agreement and except as described in Section 4.02 of the EUA Disclosure Letter, on the date hereof there are no outstanding subscriptions, options, warrants, rights (including share appreciation rights), preemptive rights or other contracts, commitments, understandings or arrangements, including any right of conversion or exchange under any outstanding security, instrument or agreement (together, "Options"), obligating EUA or any of its Subsidiaries to issue or sell any shares of equity securities of EUA or to grant, extend or enter into any Option with respect thereto. The EUA Disclosure Letter sets forth all capital stock authorized, issued and outstanding at subsidiary levels as of the close of business on January 29, 1999. (b) Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, all of the outstanding shares of capital stock of each Subsidiary of EUA are duly authorized, validly issued, fully paid and nonassessable and are owned, beneficially and of record, by EUA or a Subsidiary, which is wholly owned, directly or indirectly, by EUA, free and clear of any liens, claims, mortgages, encumbrances, pledges, security interests, equities and charges of any kind (each a "Lien"). Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no (i) outstanding Options obligating EUA or any of its Subsidiaries to issue or sell any shares of capital stock of any Subsidiary of EUA or to grant, extend or enter into any such Option or (ii) voting trusts, proxies or other commitments, understandings, restrictions or arrangements in favor of any person other than EUA or a Subsidiary which is wholly owned, directly or indirectly, by EUA with respect to the voting of, or the right to participate in, dividends or other earnings on any capital stock of any Subsidiary of EUA. (c) Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no outstanding contractual obligations of EUA or any Subsidiary of EUA to repurchase, redeem or otherwise acquire any EUA Shares or any capital stock of any Subsidiary of EUA or to provide funds to, or make any investment (in the form of a loan, capital contribution or otherwise) in, any Subsidiary of EUA or any other person. (d) As of the date of this Agreement, no bonds, debentures, notes or other indebtedness of EUA or any Subsidiary of EUA having the right to vote (or which are convertible into or exercisable for securities having the right to vote) (together "EUA Voting Debt") on any matters on which Shareholders may vote are issued or outstanding nor are there any outstanding Options obligating EUA or any of its Subsidiaries to issue or sell any EUA Voting Debt or to grant, extend or enter into any Option with respect thereto. -6- 4.03 Authority. EUA has full power and authority to enter into this Agreement, to perform its obligations hereunder and, subject to obtaining EUA Shareholders' Approval (as defined in Section 7.03(b)) and EUA Required Statutory Approvals (as defined in Section 4.04(b)), to consummate the Merger and other transactions contemplated hereby. The execution, delivery and performance of this Agreement by EUA and the consummation by EUA of the Merger and other transactions contemplated hereby have been duly authorized by all necessary action on the part of EUA, subject to obtaining EUA Shareholders' Approval with respect to the consummation of the Merger and the other transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by EUA and constitutes a legal, valid and binding obligation of EUA enforceable against EUA in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). 4.04 Non-Contravention; Approvals and Consents. (a) The execution and delivery of this Agreement by EUA do not, and the performance by EUA of its obligations hereunder and the consummation of the Merger and other transactions contemplated hereby will not, conflict with, result in a violation or breach of, constitute (with or without notice or lapse of time or both) a default under, result in or give to any person any right of payment or reimbursement, termination, cancellation, modification or acceleration of, or result in the creation or imposition of any Lien upon any of the assets or properties of EUA or any of its Subsidiaries or any of the terms, conditions or provisions of (i) the EUA Trust Agreement or the certificates or articles of incorporation or organization or bylaws (or other comparable charter documents) of EUA's Subsidiaries, or (ii) subject to the obtaining of EUA Shareholders' Approval, EUA Required Consents, EUA Required Statutory Approvals and the taking of any other actions described in this Section 4.04, (x) any statute, law, rule, regulation or ordinance (together, "laws"), or any judgment, decree, order, writ, permit or license (together, "orders"), of any court, tribunal, arbitrator, authority, agency, commission, official or other instrumentality of the United States, any foreign country or any domestic or foreign state, county, city or other political subdivision (a "Governmental Authority") applicable to EUA or any of its Subsidiaries or any of their respective assets or properties, or (y) subject to obtaining the third-party consents set forth in Section 4.04 of the EUA Disclosure Letter (the "EUA Required Consents"), any note, bond, mortgage, security agreement, indenture, license, franchise, permit, concession, contract, lease or other instrument, obligation or agreement of any kind (together, "Contracts") to which EUA or any of its Subsidiaries is a party or by which EUA or any of its Subsidiaries or any of their respective assets or properties is bound, excluding from the foregoing clauses (x) and (y) such conflicts, violations, breaches, defaults, payments or reimbursements, terminations, cancellations, modifications, accelerations and creations and impositions of Liens which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. -7- (b) No declaration, filing or registration with, or notice to or authorization, consent or approval of, any Governmental Authority is necessary for the execution and delivery of this Agreement by EUA or the consummation by EUA of the Merger and other transactions contemplated hereby except as described in Section 4.04 of the EUA Disclosure Letter or the failure of which to obtain could not reasonably be expected to result in an EUA Material Adverse Effect (the "EUA Required Statutory Approvals," it being understood that references in this Agreement to "obtaining" such EUA Required Statutory Approvals shall mean making such declarations, filings or registrations; giving such notices; obtaining such authorizations, consents or approvals; and having such waiting periods expire as are necessary to avoid a violation of law). 4.05 SEC Reports, Financial Statements and Utility Reports. (a) EUA delivered to NEES prior to the execution of this Agreement a true and complete copy of each form, report, schedule, registration statement, registration exemption, if applicable, definitive proxy statement and other document (together with all amendments thereof and supplements thereto) filed by EUA or any of its Subsidiaries with the Securities and Exchange Commission (the "SEC") under the Securities Act of 1933, as amended, and the rules and regulations thereunder (the "Securities Act") and the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder (the "Exchange Act") since December 31, 1995 (as such documents have since the time of their filing been amended or supplemented, the "EUA SEC Reports"), which are all the documents (other than preliminary materials) that EUA and its Subsidiaries were required to file with the SEC under the Securities Act and the Exchange Act since such date. As of their respective dates, EUA SEC Reports (i) complied as to form in all material respects with the requirements of the Securities Act or the Exchange Act, as the case may be, and (ii) did not contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. Each of the audited consolidated financial statements and unaudited interim consolidated financial statements (including, in each case, the notes, if any, thereto) included in EUA SEC Reports (the "EUA Financial Statements") complied as to form in all material respects with the published rules and regulations of the SEC with respect thereto, were prepared in accordance with U.S. generally accepted accounting principles ("US GAAP") applied on a consistent basis during the periods involved (except as may be indicated therein or in the notes thereto and except with respect to unaudited statements as permitted by Form 10-Q of the SEC) and fairly present (subject, in the case of the unaudited interim financial statements, to normal, recurring year-end audit adjustments (which are not expected to be, individually or in the aggregate, materially adverse to EUA and its Subsidiaries taken as a whole)) the consolidated financial position of EUA and its consolidated subsidiaries as at the respective dates thereof and the consolidated results of their operations and cash flows for the respective periods then ended. Except as set forth in Section 4.05 of the EUA Disclosure Letter, each Subsidiary of EUA is treated as a consolidated subsidiary of EUA in EUA Financial Statements for all periods covered thereby. (b) All filings (other than immaterial filings) required to be made by EUA or any of its Subsidiaries since December 31, 1995, under the Public -8- Utility Holding Company Act of 1935 (the "1935 Act"), the Federal Power Act, the Atomic Energy Act of 1954, the Communications Act of 1934, and applicable state laws and regulations, have been filed with the SEC, the Federal Energy Regulatory Commission (the "FERC"), the Department of Energy (the "DOE"), the Nuclear Regulatory Commission (the "NRC"), the Federal Communications Commission (the "FCC") or any appropriate state public utility commissions (including, without limitation, to the extent required, the state public utility regulatory agencies of Massachusetts, Rhode Island, New Hampshire, Maine, Vermont and Connecticut as the case may be, including all forms, statements, reports, agreements (oral or written) and all documents, exhibits, amendments and supplements appertaining thereto, including but not limited to all rates, tariffs, franchises, service agreements and related documents and all such filings complied, as of their respective dates, in all material respects with all applicable requirements of the appropriate statutes and the rules and regulations thereunder. 4.06 Absence of Certain Changes or Events. Except as set forth in Section 4.06 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date of this Agreement since December 31, 1997, EUA and each of EUA's Subsidiaries have conducted its business only in the ordinary course of business consistent with past practice and there has not been, and no fact or condition exists which, individually or in the aggregate, has or could reasonably be expected to have an EUA Material Adverse Effect. 4.07 Legal Proceedings. Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or in Section 4.07 of the EUA Disclosure Letter and except for environmental matters which are governed by Section 4.13, (i) there are no actions, claims, hearings, suits, arbitrations or proceedings pending or, to the knowledge of EUA or any of its Subsidiaries, threatened against, specifically relating to or affecting, and, to the knowledge of EUA or any of its Subsidiaries, there are no Governmental Authority investigations or audits pending or threatened against, specifically relating to or affecting, EUA or any of its Subsidiaries or any of their respective assets and properties which, individually or in the aggregate, could reasonably be expected to have an EUA Material Adverse Effect and (ii) neither EUA nor any of its Subsidiaries is subject to any order of any Governmental Authority which, individually or in the aggregate, could reasonably be expected to have an EUA Material Adverse Effect. 4.08 Information Supplied. (a) The proxy statement relating to EUA Shareholders' Meeting, as amended or supplemented from time to time (as so amended and supplemented, the "Proxy Statement"), and any other documents to be filed by EUA with the SEC (including, without limitation, under the 1935 Act) or any other Governmental Authority in connection with the Merger and other transactions contemplated hereby will comply as to form in all material respects with the requirements of the Exchange Act, the Securities Act and the 1935 Act, as applicable, and will not, on the date of their respective filings or, in the case of the Proxy Statement, at the date it is mailed to Shareholders of EUA and at the time of EUA Shareholders' Meeting (as defined in Section 7.03), contain any untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in light of the circumstances under which they are made, not misleading. -9- (b) Notwithstanding the foregoing provisions of this Section 4.08, no representation or warranty is made by EUA with respect to statements made or incorporated by reference in the Proxy Statement based on information supplied by NEES or LLC for inclusion or incorporation by reference therein. 4.09 Compliance. Except as set forth in Section 4.09 of the EUA Disclosure Letter, or as disclosed in EUA SEC Reports filed prior to the date hereof, neither EUA nor any of EUA's Subsidiaries is in violation of, is, to the knowledge of EUA, under investigation with respect to any violation of, or has been given notice or been charged with any violation of, any law, statute, order, rule, regulation, ordinance or judgment (including, without limitation, any applicable environmental law, ordinance or regulation) of any Governmental Authority, except for possible violations which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. Except as set forth in Section 4.09 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date hereof, EUA and EUA's Subsidiaries have all permits, licenses, franchises and other governmental authorizations, consents and approvals necessary to conduct their businesses as presently conducted except for such failures which could not reasonably be expected to have an EUA Material Adverse Effect. Neither EUA nor any of EUA's Subsidiaries is in breach or violation of, or in default in the performance or observance of any term or provision of, (i) the EUA Trust Agreement, in the case of EUA, or articles of incorporation or organization or by-laws, in the case of EUA's Subsidiaries, or (ii) any contract, commitment, agreement, indenture, mortgage, loan agreement, note, lease, bond, license, approval or other instrument to which it is a party or by which EUA or any Subsidiary of EUA is bound or to which any of their respective property is subject, except for possible violations, breaches or defaults which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. 4.10 Taxes. Except as disclosed in Section 4.10 of the EUA Disclosure Letter: (a) Filing of Timely Tax Returns. EUA and each of its Subsidiaries have timely filed all Tax Returns required to be filed by each of them under applicable law. All Tax Returns were (and, as to Tax Returns not filed as of the date hereof, will be) true, complete and correct; (b) Payment of Taxes. EUA and each of its Subsidiaries have, within the time and in the manner prescribed by law, paid (and until the Closing Date will pay within the time and in the manner prescribed by law) all Taxes that are currently due and payable except for those contested in good faith and for which adequate reserves have been taken; (c) Tax Reserves. EUA and its Subsidiaries have established (and until the Closing Date will maintain) on their books and records adequate reserves for all Taxes and for any liability for deferred income taxes in accordance with GAAP; -10- (d) Extensions of Time for Filing Tax Returns. Neither EUA nor any of its Subsidiaries has requested any extension of time within which to file any Tax Return, which Tax Return has not since been filed; (e) Waivers of Statute of Limitations. Neither EUA nor any of its Subsidiaries has in effect any extension, outstanding waivers or comparable consents regarding the application of the statute of limitations with respect to any Taxes or Tax Returns; (f) Expiration of Statute of Limitations. The Tax Returns of EUA, each of its Subsidiaries and any affiliated, consolidated, combined or unitary group that includes EUA or any of its Subsidiaries either have been examined and settled with the appropriate Tax authority or closed by virtue of the expiration of the applicable statute of limitations for all years through and including 1993; (g) Audit, Administrative and Court Proceedings. No audits or other administrative proceedings or court proceedings are presently pending or threatened with regard to any Taxes or Tax Returns of EUA or any of its Subsidiaries (other than those being contested in good faith and for which adequate reserves have been established) and no issues have been raised in writing by any Tax authority in connection with any Tax or Tax Return; (h) Tax Liens. There are no Tax liens upon any asset of EUA or any of its Subsidiaries except liens for Taxes not yet due. (i) Powers of Attorney. No power of attorney currently in force has been granted by EUA or any of its Subsidiaries concerning any Tax matter; (j) Tax Rulings. Neither EUA nor any of its Subsidiaries has, during the five year period prior to the date of this Agreement, received a Tax Ruling (as defined below) or entered into a Closing Agreement (as defined below) with any taxing authority. "Tax Ruling", as used in this Agreement, shall mean a written ruling of a taxing authority relating to Taxes. "Closing Agreement", as used in this Agreement, shall mean a written and legally binding agreement with a taxing authority relating to Taxes; (k) Availability of Tax Returns. EUA and its Subsidiaries have made available to NEES complete and accurate copies, covering all years ending on or after December 31, 1993, of (i) all Tax Returns, and any amendments thereto, filed by EUA or any of its Subsidiaries, (ii) all audit reports received from any taxing authority relating to any Tax Return filed by EUA or any of its Subsidiaries and (iii) any Closing Agreements entered into by EUA or any of its Subsidiaries with any taxing authority. (l) Tax Sharing Agreements. No agreements relating to the allocation or sharing of Taxes exist between or among EUA and any of its Subsidiaries and neither EUA nor any of its Subsidiaries (i) has been a member of an affiliated group filing a consolidated federal income tax return (other -11- than a group the common parent of which was EUA) or (ii) has any liability for Taxes of any Person (other than EUA or its Subsidiaries) under United States Treasury Regulation Section 1.1502-6 (or any provision of state, local), or foreign law, as a transferee or successor, by contract or otherwise; (m) Code Section 481 Adjustments. Neither EUA nor any of its Subsidiaries is required to include in income any adjustment pursuant to Code Section 481(a) by reason of a voluntary change in accounting method initiated by EUA or any of its Subsidiaries, and, the Internal Revenue Service ("IRS") has not proposed any such adjustment or change in accounting method; (n) Code Sections 6661 and 6662. All transactions that could give rise to an understatement of federal income tax, and within the meaning of Code Section 6662 have been adequately disclosed (or, with respect to Tax Returns filed following the Closing, will be adequately disclosed) on the Tax Returns of EUA and its Subsidiaries in accordance with Code Section 6662(d)(2)(B); (o) Intercompany Transactions. Neither EUA nor any of its Subsidiaries has engaged in any intercompany transactions within the meaning of Treasury Regulations ss. 1.1502-13 for which any income or gain will remain unrecognized as of the close of the last taxable year prior to the Closing Date; and (p) Foreign Tax Returns. Neither EUA nor any of its Subsidiaries is required to file a foreign tax return. "Taxes" as used in this Agreement, shall mean any federal, state, county, local or foreign taxes, charges, fees, levies, or other assessments, including all net income, gross income, premiums, sales and use, ad valorem, transfer, gains, profits, windfall profits, excise, franchise, real and personal property, gross receipts, capital stock, production, business and occupation, employment, disability, payroll, license, estimated, stamp, custom duties, severance or withholding taxes, other taxes or similar charges of any kind whatsoever imposed by any governmental entity, whether imposed directly on a Person or resulting under Treasury Regulation Section 1.1502-6 (or any similar provision of state, local or foreign law), as a transferee or successor, by contract or otherwise and includes any interest and penalties on or additions to any such taxes or in respect of a failure to comply with any requirement relating to any Tax Return. "Tax Return" as used in this Agreement, shall mean a report, return or other information required to be supplied to a governmental entity with respect to Taxes including, where permitted or required, combined, unitary or consolidated returns for any group of entities. 4.11 Employee Benefit Plans; ERISA. (a) Each "employee benefit plan" (as defined in Section 3(3) of the Employee Retirement Income Security Act of 1974, as amended ("ERISA")), bonus, deferred compensation, share option or other written agreement relating to employment or fringe benefits for employees, former employees, officers, trustees or directors of EUA or any of its Subsidiaries effective as of the date hereof or providing benefits as of the date hereof to current employees, former employees, officers, trustees or -12- directors of EUA or pursuant to which EUA or any of its subsidiaries has or could reasonably be expected to have any liability (collectively, the "EUA Employee Benefit Plans") is listed in Section 4.11(a) of the EUA Disclosure Letter, is in material compliance with applicable law, and has been administered and operated in all material respects in accordance with its terms. Each EUA Employee Benefit Plan which is intended to be qualified within the meaning of Section 401(a) of the Code has received a favorable determination letter from the IRS as to such qualification and, to the knowledge of EUA, no event has occurred and no condition exists which could reasonably be expected to result in the revocation of, or have any adverse effect on, any such determination. (b) Complete and correct copies of the following documents have been made available to NEES as of the date of this Agreement: (i) all EUA Employee Benefit Plans and any related trust agreements or insurance contracts, (ii) the most current summary descriptions of each EUA Employee Benefit Plan subject to ERISA, (iii) the three most recent Form 5500s and Schedules thereto for each EUA Employee Benefit Plan subject to such reporting, (iv) the most recent determination of the IRS with respect to the qualified status of each EUA Employee Benefit Plan that is intended to qualify under Section 401(a) of the Code, (v) the most recent accountings with respect to each EUA Employee Benefit Plan funded through a trust and (vi) the most recent actuarial report of the qualified actuary of each EUA Employee Benefit Plan with respect to which actuarial valuations are conducted. (c) Except as set forth in Section 4.11(c) of the EUA Disclosure Letter, neither EUA nor any Subsidiary maintains or is obligated to provide benefits under any EUA Employee Benefit Plan (other than as an incidental benefit under a Plan qualified under Section 401(a) of the Code) which provides health or welfare benefits to retirees or other terminated employees other than benefit continuations as required pursuant to Section 601 of ERISA. Each EUA Employee Benefit Plan subject to the requirements of Section 601 of ERISA has been operated in material compliance therewith. EUA has not contributed to a nonconforming group health plan (as defined in Code Section 5000(c)) and no person under common control with EUA within the meaning of Section 414 of the Code ("ERISA Affiliate") has incurred a tax liability under Code Section 5000(a) that is or could reasonably be expected to be a liability of EUA's. (d) Except as set forth in Section 4.11(d) of the EUA Disclosure Letter, each EUA Employee Benefit Plan covers only employees who are employed by EUA or a Subsidiary (or former employees or beneficiaries with respect to service with EUA or a Subsidiary). (e) Except as set forth in Section 4.11(e) of the EUA Disclosure Letter, neither EUA, any Subsidiary, any ERISA Affiliate nor any other corporation or organization controlled by or under common control with any of the foregoing within the meaning of Section 4001 of ERISA has, within the five-year period preceding the date of this Agreement, at any time contributed to any "multiemployer plan," as that term is defined in Section 4001 of ERISA. -13- (f) No event has occurred, and there exists no condition or set of circumstances in connection with any EUA Employee Benefit Plan, under which EUA or any Subsidiary, directly or indirectly (through any indemnification agreement or otherwise), could be subject to any liability under Section 409 of ERISA, Section 502(i) of ERISA, Title IV of ERISA or Section 4975 of the Code except for instances of non-compliance which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. (g) Neither EUA nor any ERISA Affiliate has incurred any liability to the Pension Benefit Guaranty Corporation (the "PBGC") under Section 302(c)(ii), 4062, 4063, 4064 or 4069 of ERISA, or otherwise that has not been satisfied in full and no event or condition exists or has existed which could reasonably be expected to result in any such material liability. As of the date of this Agreement, no "reportable event" within the meaning of Section 4043 of ERISA has occurred with respect to any EUA Employee Benefit Plan that is a defined benefit plan under Section 3(35) of ERISA. (h) Except as set forth in Section 4.11(h) of the EUA Disclosure Letter, no employer securities, employer real property or other employer property is included in the assets of any EUA Employee Benefit Plan. (i) Full payment has been made of all material amounts which EUA or any affiliate thereof was required under the terms of EUA Employee Benefit Plans to have paid as contributions to such plans on or prior to the Effective Time (excluding any amounts not yet due) and no EUA Employee Benefit Plan which is subject to Part III of Subtitle B of Title I of ERISA has incurred any "accumulated funding deficiency" within the meaning of Section 302 of ERISA or Section 412 of the Code, whether or not waived. (j) Except as set forth in Section 4.11(j) of the EUA Disclosure Letter, no amounts payable under any EUA Employee Benefit Plan or other agreement, contract, or arrangement will fail to be deductible for federal income tax purposes by virtue of Section 280G or Section 162(m) of the Code. 4.12 Labor Matters. As of the date hereof, except as set forth in Section 4.12 of the EUA Disclosure Letter, neither EUA nor any of its Subsidiaries is a party to any material collective bargaining agreement or other labor agreement with any union or labor organization. To the knowledge of EUA, as of the date hereof, there is no current union representation question involving employees of EUA or any of its Subsidiaries, nor does EUA know of any activity or proceeding of any labor organization (or representative thereof) or employee group to organize any such employees. Except as set forth in Section 4.12 of the EUA Disclosure Letter, (i) there is no unfair labor practice, employment discrimination or other employment-related complaint or proceeding against EUA or any of its Subsidiaries pending or, to the knowledge of EUA, threatened, which has or could reasonably be expected to have an EUA Material Adverse Effect, (ii) there is no strike, dispute, slowdown, work stoppage or lockout pending, or, to the knowledge of EUA, threatened, against or involving EUA or any of its Subsidiaries which has or could reasonably be expected to have, an EUA Material Adverse Effect and (iii) there is no proceeding, claim, -14- suit, or action pending or, to the knowledge of EUA or any of its Subsidiaries, threatened, nor, to the knowledge of EUA or any of its Subsidiaries is there any Governmental Authority investigation pending or threatened, in respect of which any trustee, director, officer, employee or agent of EUA or any of its Subsidiaries is or may be entitled to claim indemnification from EUA or any of its Subsidiaries pursuant to the EUA Trust Agreement, in the case of EUA, and their respective articles of incorporation and by-laws, in the case of EUA's Subsidiaries, or as provided in the indemnification agreements listed in Section 4.12 of the EUA Disclosure Letter. Except as set forth in Section 4.12 of the EUA Disclosure Letter, EUA and its Subsidiaries are in compliance with all federal, state and local laws with respect to employment practices and labor relations, including, without limitation, any provisions relating to affirmative action, employment discrimination, wages, hours, collective bargaining, and the payment of social security and similar taxes, safety and health regulations and mass layoffs and plant closings except for such instances of noncompliance which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. 4.13 Environmental Matters. Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or in Section 4.13 of the EUA Disclosure Letter: (a) (i) Each of EUA and its Subsidiaries is in compliance with all applicable Environmental Laws (as hereinafter defined), except where the failure to be in compliance, in the aggregate could not reasonably be expected to result in an EUA Material Adverse Effect; and (ii) Neither EUA nor any of its Subsidiaries has received any written communication from any person or Governmental Authority that alleges that EUA or any of its Subsidiaries is not in such compliance (including the materiality qualifier set forth in clause (i) above) with applicable Environmental Laws. (b) Each of EUA and its Subsidiaries has obtained all environmental, health and safety permits and governmental authorizations (collectively, the "Environmental Permits") necessary for the construction of their facilities and the conduct of their operations, as applicable, and all such Environmental Permits are in good standing or, where applicable, a renewal application has been timely filed and agency approval is expected in the ordinary course of business, and EUA and its Subsidiaries are in compliance with all terms and conditions of the Environmental Permits, except where the failure have such Environmental Permits, file a renewal application for such Environmental Permits, or to be in compliance with such Environmental Permits, in the aggregate could not reasonably be expected to result in an EUA Material Adverse Effect. (c) There is no Environmental Claim (as hereinafter defined) that could, individually or in the aggregate, reasonably be expected to have an EUA Material Adverse Effect pending (i) against EUA or any of its Subsidiaries; (ii) against any person or entity whose liability for any Environmental Claim EUA or any of its Subsidiaries has or may have retained or assumed either contractually or by operation of law; or (iii) against any real or personal -15- property or operations which EUA or any of its Subsidiaries owns, leases or manages, in whole or in part. (d) To the knowledge of EUA there have not been any material Releases (as hereinafter defined) of any Hazardous Material (as hereinafter defined) that would be reasonably likely to form the basis of any material Environmental Claim against EUA or any of its Subsidiaries, or against any person or entity whose liability for any material Environmental Claim EUA or any of its Subsidiaries has or may have retained or assumed either contractually or by operation of law, except for any Environmental Claim that, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. (e) To the knowledge of EUA with respect to any predecessor of EUA or any of its Subsidiaries, there is no material Environmental Claim pending or threatened, and there has been no Release of Hazardous Materials that could reasonably be expected to form the basis of any material Environmental Claim except for any Environmental Claim that, individually or in the aggregate, could not be reasonably be expected to have an EUA Material Adverse Effect. (f) As used in this Section 4.13: (i) "Environmental Claim" means any and all written administrative, regulatory or judicial actions, suits, demands, demand letters, directives, claims, liens, investigations, proceedings or notices or noncompliance, liability or violation by any person or entity (including any Governmental Authority) alleging potential liability (including, without limitation, potential responsibility or liability for enforcement, investigatory costs, cleanup costs, governmental response costs, removal costs, remedial costs, natural resources damages, property damages, personal injuries or penalties) arising out of, based on or resulting from (A) the presence, or Release or threatened Release into the environment, of any Hazardous Materials at any location, whether or not owned, operated, leased or managed by EUA or any of its Subsidiaries; or (B) circumstances forming the basis of any violation, or alleged violation, of any Environmental Law; or (C) any and all claims by any third party seeking damages, contribution, indemnification, cost recovery, compensation or injunctive relief resulting from the presence or Release of any Hazardous Materials; (ii) "Environmental Laws" means all federal, state and local laws, rules and regulations and binding interpretation thereof, relating to pollution, the environment (including, without limitation, ambient air, surface water, groundwater, land surface or subsurface strata) or protection of human health as it relates to the environment including, without limitation, laws and -16- regulations relating to Releases or threatened Releases of Hazardous Materials, or otherwise relating to the manufacture, generation, processing, distribution, use, treatment, storage, disposal, transport or handling of Hazardous Materials; (iii) "Hazardous Materials" means (A) any petroleum or petroleum products, radioactive materials, asbestos in any form that is or could become friable, urea formaldehyde foam insulation, and transformers or other equipment that contain dielectric fluid containing polychlorinated biphenyls; and (B) any chemicals, materials or substances which are now defined as or included in the definition of "hazardous substances", "hazardous wastes", "hazardous materials", "extremely hazardous wastes", "restricted hazardous wastes", "toxic substances", "toxic pollutants", or words of similar import, under any Environmental Law; and (c) any other chemical, material, substance or waste, exposure to which is now prohibited, limited or regulated under any Environmental Law in a jurisdiction in which EUA or any of its Subsidiaries (x) operates or (y) stores, treats or disposes of Hazardous Materials; and (iv) "Release" means any release, spill, emission, leaking, injection, deposit, disposal, discharge, dispersal, leaching or migration into the atmosphere, soil, surface water, groundwater or property. 4.14 Regulation as a Utility. (a) EUA is a public utility holding company registered under Section 5, and subject to the provisions, of the 1935 Act. Section 4.14 of the EUA Disclosure Letter lists the subsidiaries of EUA that are "public utility companies" within the meaning of Section 2(a)(5) of the 1935 Act and lists the jurisdictions where each such Subsidiary is subject to regulation as a public utility company or public service company. Except as set forth above and as set forth in Section 4.14 of the EUA Disclosure Letter, neither EUA nor any "subsidiary company" or "affiliate" of EUA is subject to regulation as a public utility or public service company (or similar designation) by the federal government of the United States, any state in the United States or any political subdivision thereof, or any foreign country. (b) As used in this Section 4.14, the terms "subsidiary company" and "affiliate" shall have the respective meanings ascribed to them in Section 2(a)(8) and Section 2(a)(11), respectively, of the 1935 Act. 4.15 Insurance. Except as set forth in Section 4.15 of the EUA Disclosure Letter, each of EUA and its Subsidiaries is, and has been continuously since January 1, 1994, insured with financially responsible insurers in such amounts and against such risks and losses as are customary in all material respects for companies in the United States conducting the business conducted by EUA and its Subsidiaries during such time period. Except as set forth in Section 4.15 of the EUA Disclosure Letter, neither EUA nor any of its Subsidiaries has received any notice of cancellation or termination with respect to any material insurance policy of EUA or any of its Subsidiaries. The insurance policies of EUA and each of its Subsidiaries are valid and enforceable policies. -17- 4.16 Nuclear Facilities. Montaup Electric Company, a Subsidiary of EUA, is a minority common stockholder of each of Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power Corporation and Yankee Atomic Electric Company (the "Yankee Companies") and a minority joint owner in Millstone 3 and Seabrook 1 (collectively, as described in Section 4.16 of the EUA Disclosure Letter, the "EUA Nuclear Facilities"). With respect to its ownership of Millstone 3 and Seabrook 1, Montaup Electric Company holds the required operating licenses from the NRC. With respect to the Yankee Companies, each Yankee Company holds its own operating license from the NRC. Because it is a minority stockholder or a minority joint owner, Montaup Electric Company does not have responsibility for the operation of EUA Nuclear Facilities. Except as set forth in Section 4.16 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date hereof, to the knowledge of EUA, neither EUA nor any of its Subsidiaries is in violation of any applicable health, safety, regulatory and other legal requirement, including NRC laws and regulations and Environmental Laws, applicable to EUA Nuclear Facilities except for such failure to comply as could not reasonably be expected to have a material adverse effect with respect to EUA Nuclear Facilities and the ownership interest of EUA therein. To the knowledge of EUA, each of EUA Nuclear Facilities maintains emergency plans designed to respond to an unplanned release therefrom of radioactive materials into the environment and insurance coverages consistent with industry practice. EUA has funded, or has caused the funding of, its portion of the decommissioning cost of each of the EUA Nuclear Facilities and the storage of spent nuclear fuel consistent with the most recently approved plan for each of the EUA Nuclear Facilities and FERC authorized rates. Except as set forth in Section 4.16 of the EUA Disclosure Letter, to the knowledge of EUA, no EUA Nuclear Facility is as of the date of this Agreement on the List of Nuclear Power Plants Warranting Increased Regulatory Attention maintained by the NRC. 4.17 Vote Required. The affirmative vote of two-thirds of the outstanding EUA Shares voting as a single class (with each EUA Share having one vote per share) with respect to the approval of the Merger and other transactions contemplated hereby is the only vote of the holders of any class or series of equity securities of EUA or its Subsidiaries required to approve this Agreement and approve the Merger and other transactions contemplated hereby. 4.18 Opinion of Financial Advisor. EUA has received the opinion of Salomon Smith Barney Inc., dated the date of this Agreement, to the effect that, as of such date, the Merger Consideration is fair from a financial point of view to the holders of EUA Shares. A true and complete copy of the written opinion will be delivered to NEES promptly after receipt thereof by EUA. 4.19 Ownership of NEES Common Shares. Neither EUA nor any of its Subsidiaries or other affiliates beneficially owns any NEES Common Shares. 4.20 State Anti-Takeover Statutes. EUA has taken all necessary actions so that the provisions of Chapters 110C, 110D or 110F of the MGL will not apply to this Agreement, the Merger or other transactions contemplated hereby or thereby. -18- 4.21 Year 2000. The Information Systems operated by EUA and its Subsidiaries which is used in the conduct of their business is capable of providing or being adapted to provide uninterrupted millennium functionality to record, store, process and present calendar dates falling on or after January 1, 2000 in substantially the same manner and with the same functionality as such Information Systems record, store, process and present such calendar dates falling on or before December 31, 1999 other than such interruptions in millennium functionality that could not, individually or in the aggregate, reasonably be expected to result in a EUA Material Adverse Effect. EUA reasonably believes as of the date hereof that the remaining cost of adaptations referred to in the foregoing sentence will not exceed the amounts reflected in the Form 10-Q filed by EUA for the quarter ended September 30, 1998 (excluding the fees and costs of any Y2K Consultant retained pursuant to Section 6.01(o) hereof and of the implementation of any recommendations by such Y2K Consultant actually made by EUA that are not already part of EUA's compliance plan as of the date hereof). "Information Systems" means mainframe and midrange hardware, operating system software and applications programs; network and desktop (PC) hardware, operating system software and applications programs; EDI (Electronic Date Interchange) and FTP (File Transfer Protocol) software; and embedded systems hardware and applications software. 4.22 EUA Associates. The representations and warranties set forth in Sections 4.04(a), 4.06, 4.07, 4.09, 4.12 and 4.13 are true and correct in all material respects with regard to EUA Associates. ARTICLE V REPRESENTATIONS AND WARRANTIES OF NEES NEES represents and warrants to EUA as follows: 5.01 Organization and Qualification. NEES is a voluntary association duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has full power, authority and legal right to own its property and assets and to transact the business in which it is engaged. Each of the NEES Subsidiaries is a corporation duly organized or incorporated, validly existing and in good standing under the laws of its jurisdiction of organization or incorporation and has full corporate power and authority to conduct its business as and to the extent now conducted and to own, use and lease its assets and properties, except where failure to be so organized or incorporated, existing and in good standing or to have such power and authority, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. As used in this Agreement, the term "NEES Material Adverse Effect" means a material adverse effect on the business, assets, results of operations, condition (financial or otherwise) or prospects of NEES and its Subsidiaries taken as a whole. LLC is a limited liability company validly existing under the laws of the Commonwealth of Massachusetts. LLC was formed solely for the purpose of engaging in the Merger and other transactions contemplated hereby, has engaged in no other business activities (other than in connection with the formation and capitalization of LLC pursuant to or in -19- accordance with the LLC Agreement (as defined below)) and has conducted its operations only as contemplated hereby and by the LLC Agreement. Each of NEES and its Subsidiaries is duly qualified, licensed or admitted to do business and is in good standing in each jurisdiction in which the ownership, use or leasing of its assets and properties, or the conduct or nature of its business, makes such qualification, licensing or admission necessary, except where failure to be so qualified, licensed or admitted and in good standing, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. NEES has previously delivered to EUA correct and complete copies of its Agreement and Declaration of Trust (the "NEES Trust Agreement") and the articles of association of LLC. 5.02 Authority. Each of NEES and LLC has full power and authority to enter into this Agreement, and to perform its obligations hereunder, and to consummate the Merger and other transactions contemplated hereby. The execution, delivery and performance of this Agreement by each of NEES and LLC and the consummation by each of NEES and LLC of the Merger and other transactions contemplated hereby have been duly authorized by all necessary corporate action on the part of NEES and all necessary action on the part of LLC. This Agreement has been duly and validly executed and delivered by each of NEES and LLC and constitutes a legal, valid and binding obligation of each of NEES and LLC enforceable against each of NEES and LLC in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). 5.03 Capital Stock. The authorized equity securities of NEES consists of 150,000,000 common shares of NEES (the "NEES Shares"), of which 59,170,986 shares were issued and outstanding as of the close of business on January 29, 1999. As of the close of business on January 29, 1999, 5,798,666 NEES Shares were held in the treasury of NEES. All of the issued and outstanding NEES Shares are duly authorized, validly issued, fully paid and nonassessable. Except as may be provided by the New England Electric System Companies' Incentive Share Plan, the New England Electric System Companies Incentive Thrift Plan I, the New England Electric System Companies Incentive Thrift Plan II, the New England Electric Companies Long-Term Performance Share Award Plan, and the New England Electric System Directors' annual retainer shares, and except as set forth in Section 5.03 of the letter dated the date hereof and delivered to EUA by NEES and LLC concurrently with the execution and delivery of this Agreement (the "NEES Disclosure Letter"), on the date hereof there are no outstanding Options obligating NEES or any of its Subsidiaries to issue or sell any shares of equity securities of NEES or to grant, extend or enter into any Option with respect thereto. 5.04 Non-Contravention; Approvals and Consents. (a) The execution and delivery of this Agreement by each of NEES and LLC do not, and the performance by each of NEES and LLC of its obligations hereunder and the consummation of the Merger and other transactions contemplated hereby will not, conflict with, result in a violation or breach of, constitute (with or without notice or lapse of time or both) a default under, result in or give to any person any right of payment or reimbursement, termination, cancellation, modification or -20- acceleration of, or result in the creation or imposition of any Lien upon any of the assets or properties of NEES, or LLC under, any of the terms, conditions or provisions of (i) the NEES Agreement and Declaration of Trust or the articles of organization of LLC, (ii) subject to the actions described in paragraph (b) of this Section, (x) any laws or orders of any Governmental Authority applicable to NEES or LLC or any of their respective assets or properties, or (y) subject to obtaining the third-party consents (the "NEES Required Consents") set forth in Section 5.04 of the NEES Disclosure Letter any Contracts to which NEES is a party or by which NEES or any of its Subsidiaries or any of their respective assets or properties is bound, excluding from the foregoing clauses (x) and (y) conflicts, violations, breaches, defaults, terminations, modifications, accelerations and creations and impositions of Liens which, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. (b) No declaration, filing or registration with, or notice to or authorization, consent or approval of, any Governmental Authority is necessary for the execution and delivery of this Agreement by NEES or LLC or the consummation by NEES or LLC of the Merger and other transactions contemplated hereby except as described in Section 5.04 of the NEES Disclosure Letter or the failure of which to obtain could not reasonably be expected to result in a NEES Material Adverse Effect (the "NEES Required Statutory Approvals," it being understood that references in this Agreement to "obtaining" such NEES Required Statutory Approvals shall mean making such declarations, filings or registrations; giving such notices; obtaining such authorizations, consents or approvals; and having such waiting periods expire as are necessary to avoid a violation of law). 5.05 Information Supplied. (a) The information supplied by NEES or LLC and included in the Proxy Statement with the written consent of NEES or LLC, as the case may be, will not, at the date mailed to EUA's Shareholders or at the time of EUA Shareholder's Meeting, contain any untrue statements of a material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. (b) Notwithstanding the foregoing provisions of this Section 5.05, no representation or warranty is made by NEES with respect to statements made or incorporated by reference in the Proxy Statement based on information supplied by EUA for inclusion or incorporation by reference therein or based on information which is not made in or incorporated by reference in such documents but which should have been disclosed pursuant to this Section 5.05. 5.06 Compliance. Except as set forth in Section 5.06 of the NEES Disclosure Letter, or as disclosed in the NEES Reports filed prior to the date hereof, NEES is not in violation of, is, to the knowledge of NEES, under investigation with respect to any violation of, or has been given notice or been charged with any violation of, any law, statute, order, rule, regulation, ordinance or judgment (including, without limitation, any applicable environmental law, ordinance or regulation) of any Governmental Authority, except for possible violations which, individually or in the aggregate, could -21- not reasonably be expected to have a NEES Material Adverse Effect. Except as set forth in Section 5.06 of the NEES Disclosure Letter or as disclosed in the NEES Reports filed prior to the date hereof, NEES and its Subsidiaries have all material permits, licenses and other governmental authorizations, consents and approvals necessary to conduct their businesses as presently conducted which are material to the operation of the businesses of NEES. NEES is not in breach or violation of, or in default in the performance or observance of, any term or provision of, and no event has occurred which, with lapse of time or action by a third party, could result in a default by NEES under (i) the NEES Agreement and Declaration of Trust or by-laws or (ii) any contract, commitment, agreement, indenture, mortgage, loan agreement, note, lease, bond, license, approval or other instrument to which it is a party or by which NEES is bound or to which any of their respective property is subject, except for possible violations, breaches or defaults which, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. 5.07 Financing. NEES has or will have available, prior to the Effective Time, sufficient cash in immediately available funds to pay or to cause LLC to pay the Merger Consideration pursuant to Article II hereof and to consummate the Merger and other transactions contemplated hereby. 5.08 No Vote Required. No vote of the NEES Shares or of any class or series of equity securities of NEES or its Subsidiaries is necessary for the approval of the Merger and other transactions contemplated hereby. 5.09 Ownership of EUA Shares. Neither NEES nor any of its Subsidiaries or other affiliates beneficially owns any EUA Shares. 5.10 Merger with The National Grid Group plc. NEES has entered into an Agreement and Plan of Merger dated as of December 11, 1998 by and among The National Grid Group plc ("National Grid Group"), NGG Holdings LLC (formerly known as Iosta LLC) and NEES (the "National Grid Merger Agreement"). Pursuant to Section 6.01 of the National Grid Merger Agreement, NEES has provided a copy of this Agreement to National Grid Group, and National Grid Group has given NEES its written consent to enter into this Agreement and consummate the Merger on the terms set forth in this Agreement. Prior to the execution of this Agreement, NEES has provided EUA with a copy of such written consent. ARTICLE VI COVENANTS 6.01 Covenants of EUA. At all times from and after the date hereof until the Effective Time, EUA covenants and agrees as to itself and its Subsidiaries that (except as expressly contemplated or permitted by this Agreement or as set forth in Section 6.01 of the EUA Disclosure Letter, or to the extent that NEES shall otherwise previously consent in writing): -22- (a) Ordinary Course. EUA and each of its Subsidiaries shall conduct their businesses only in, and EUA and each of its Subsidiaries shall not take any action except in, the ordinary course consistent with good utility practice. Without limiting the generality of the foregoing, EUA and its Subsidiaries shall use all commercially reasonable efforts to preserve intact in all material respects their present business organizations and reputation, to maintain in effect all existing permits, to keep available the services of their key officers and employees, to maintain their assets and properties in good working order and condition, ordinary wear and tear excepted, to maintain insurance on their tangible assets and businesses in such amounts and against such risks and losses as are currently in effect, to preserve their relationships with customers and suppliers and others having significant business dealings with them and to comply in all material respects with all laws and orders of all Governmental Authorities applicable to them. (b) Charter Documents. EUA shall not, nor shall it permit any of its Subsidiaries to, amend or propose to amend the EUA Trust Agreement, in the case of EUA, and its certificate or articles of incorporation or organization or bylaws (or other comparable charter documents), in the case of EUA's Subsidiaries. (c) Dividends. EUA shall not, nor shall it permit any of its Subsidiaries to, (i) declare, set aside or pay any dividends on, or make other distributions in respect of, any of its capital stock or share capital, except: (A) that EUA may continue the declaration and payment of regular quarterly dividends on EUA Shares with usual record and payment dates not, in any fiscal year, in excess of the dividend for the comparable period in the prior fiscal year; (B) that the Subsidiaries of EUA set forth in Section 6.01(c) of the EUA Disclosure Letter may continue the declaration and payment of dividends on preferred stock in accordance with the terms of such stock, with the record and payment dates and in the amounts set forth in Section 6.01(c) of the EUA Disclosure Letter; (C) if the Effective Time does not occur between a record date and payment date of a regular quarterly dividend, for a special dividend on EUA Shares with respect to the quarter in which the Effective Time occurs with a record date on or prior to the date on which the Effective Time occurs, which does not exceed an amount equal to the product of (x) the number of days between the last payment date of a regular quarterly dividend and the record date of such special dividend, multiplied by (y) $.0045; and (D) for dividends and distributions (including liquidating distributions) by a direct or indirect Subsidiary of EUA to its parent. -23- (ii) split, combine, subdivide, reclassify or take similar action with respect to any of its capital stock or share capital or issue or authorize or propose the issuance of any other securities in respect of, in lieu of or in substitution for shares of its capital stock or comprised in its share capital, (iii) adopt a plan of complete or partial liquidation or resolutions providing for or authorizing such liquidation or a dissolution, merger, consolidation, restructuring, recapitalization or other reorganization or (iv) directly or indirectly redeem, repurchase or otherwise acquire any shares of its capital stock or any Option with respect thereto except: (A) in connection with intercompany purchases of capital stock or share capital, (B) for the purpose of funding EUA's dividend reinvestment and share purchase plan in accordance with past practice, or (C) subject to EUA's obligations under the Securities Act and the Exchange Act, pursuant to EUA's previously announced share repurchase program provided that the number of EUA Shares repurchased does not exceed 3,000,000 and the price paid per share does not exceed 95% of the Per Share Amount. (d) Share Issuances. EUA shall not, nor shall it permit any of its Subsidiaries to, issue, deliver or sell, or authorize or propose the issuance, delivery or sale of, any shares of its capital stock or any Option with respect thereto (other than the issuance by a wholly owned Subsidiary of its capital stock to its direct or indirect parent corporation, or modify or amend any right of any holder of outstanding shares of capital stock or Options with respect thereto). (e) Acquisitions. EUA shall not, nor shall it permit any of its Subsidiaries to acquire or agree to acquire (by merging or consolidating with, or by purchasing a substantial equity interest in or substantial portion of the assets of, or by any other manner) any business or any corporation, partnership, association or other business organization or division thereof. (f) Dispositions. EUA shall not, nor shall it permit any of its Subsidiaries to sell, lease, securitize, grant any security interest in or otherwise dispose of or encumber any of its assets or properties, other than dispositions in the ordinary course of its business consistent with past practice and having an aggregate value of less than $1,000,000 for each disposition and $5,000,000 in the aggregate. (g) Indebtedness. EUA shall not, nor shall it permit any of its Subsidiaries to incur or guarantee any indebtedness (including any debt borrowed or guaranteed or otherwise assumed, including, without limitation, the issuance of debt securities or warrants or rights to acquire debt) or enter into any "keep well" or other agreement to maintain any financial condition of another Person or enter into any arrangement having the economic effect of any of the foregoing other than (i) short-term indebtedness in the ordinary course of business consistent with past practice (such as the issuance of commercial paper -24- or the use of existing credit facilities) in amounts not exceeding the amounts set forth in Section 6.01(g) of the EUA Disclosure Letter, (ii) long-term indebtedness in connection with the refinancing of existing indebtedness either at its stated maturity or at a lower cost of funds (calculating such cost on an aggregate after-tax basis) or (iii) guarantees or "keep well" agreements in favor of wholly owned Subsidiaries of EUA in connection with the conduct of the business of such wholly owned Subsidiaries of EUA not aggregating more than $1,000,000. (h) Capital Expenditures. Except (i) as required by law or (ii) as reasonably deemed necessary by EUA after consulting with NEES following a catastrophic event, such as a major storm, EUA shall not, nor shall it permit any of its Subsidiaries to make any capital expenditures or commitments during any fiscal year that is in excess of 110% of (i) the aggregate amount set forth in Section 6.01(h) of the EUA Disclosure Letter with respect to EUA and its Subsidiaries that are public utility companies within the meaning of Section 2(a)(5) of the 1935 Act or (ii) the amount set forth in Section 6.01(h) of the EUA Disclosure Letter with respect to each of EUA's other Subsidiaries. (i) Employee Benefits. EUA shall not, nor shall it permit any of its Subsidiaries to enter into, adopt, amend (except as may be required by applicable law) or terminate any EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy between EUA or one of its Subsidiaries and one or more of its trustees, directors, officers, employees or former employees, or, except for normal increases in the ordinary course of business, (a) increase in any manner the compensation or fringe benefits of any trustee, director or executive officer, (b) increase in any manner the compensation or fringe benefits of any employee, (c) pay any benefit not required by any plan or arrangement in effect as of the date hereof or, (d) cause any trustee, director, officer, employee or former employee of EUA to accrue or receive additional benefits, accelerate vesting or accelerate the payment of any benefits under any EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy. EUA, prior to the Closing Date, shall take all necessary action and make all necessary amendments to its stock-based plans so that all such plans will be in a form that allows the plans to function after the Effective Time and after any merger of EUA and its Subsidiaries into NEES or its Subsidiaries. EUA, prior to the Closing Date, shall take all necessary actions, in a manner satisfactory to NEES, so that on or after the Closing Date, neither EUA, the Surviving Entity nor their affiliates' stock or securities will be required to be held in, or distributed pursuant to, any EUA Employee Benefit Plan. (j) Labor Matters. Notwithstanding any other provision of this Agreement to the contrary, EUA or its Subsidiaries may negotiate successor collective bargaining agreements to those referenced in Section 4.12 hereof, and may negotiate other collective bargaining agreements or arrangements as required by law or for the purpose of implementing the agreements referenced in Section 4.12 hereof. EUA will keep NEES informed as to the status of, and will consult with NEES as to the strategy for, all negotiations with collective bargaining representatives. EUA and its Subsidiaries shall act prudently and reasonably and consistent with their obligation under applicable law in such negotiations. -25- (k) Discharge of Liabilities. EUA shall not, nor shall it permit its Subsidiaries to, pay, discharge or satisfy any material claims, liabilities or obligations (absolute, accrued, asserted or unasserted, contingent or otherwise), other than the payment, discharge or satisfaction, in the ordinary course of business consistent with past practice (which includes the payment of final and unappealable judgments) or in accordance with their terms, of liabilities reflected or reserved against in, or contemplated by, the most recent consolidated financial statements (or the notes thereto) of such party included in EUA SEC Reports, or incurred in the ordinary course of business consistent with past practice. (l) Contracts. EUA shall not, nor shall it permit its Subsidiaries, except in the ordinary course of business consistent with past practice or as set forth in Section 6.01(l) of the EUA Disclosure Letter, (i) to modify, amend, terminate or fail to use commercially reasonable efforts to renew any material Contract to which EUA or any of its Subsidiaries is a party or waive, release or assign any material rights or claims or (ii) to enter into any new material Contracts except as expressly permitted by Sections 6.01 (f), (g) or (i) and 7.06 hereof. (m) Equity Investments. EUA shall not, nor shall it permit its Subsidiaries or affiliates to, make equity contributions to non-affiliates or to its non-utility Subsidiaries. (n) Loans. EUA shall not, nor shall it permit its Subsidiaries or affiliates to, loan money to non-affiliates or to its non-utility Subsidiaries. (o) Year 2000. EUA, within 15 days of the date of this Agreement, shall engage a qualified third party ("Y2K Consultant") to conduct a detailed assessment of the adequacy and state of completion of its Year 2000 Program, including but not limited to assessment and testing of its customer, accounting, and operational systems. The Y2K Consultant and scope of work of the Y2K Consultant shall be acceptable to NEES. Such assessment and testing shall be completed as soon thereafter as practicable. EUA shall have such assessment updated by the Y2K Consultant at the end of each fiscal quarter of 1999. EUA shall allow designated NEES personnel and representatives access to the Y2K Consultant's personnel, reports and recommendations and access to EUA's personnel, documents, and information related to the Y2K issue. EUA and the third party shall meet with such designated NEES personnel and representatives on a periodic basis (but not less frequently than monthly) to update NEES on EUA's Year 2000 Program. If this Agreement is terminated pursuant to Section 9.01 hereof, NEES shall reimburse EUA for the costs and expenses of the Y2K Consultant. (p) Insurance. EUA shall, and shall cause its Subsidiaries to, maintain with financially responsible insurance companies (or through self-insurance, consistent with past practice) insurance in such amounts and against such risks and losses as are customary for companies engaged in their respective businesses. (q) 1935 Act. EUA shall not, nor shall it permit any of its Subsidiaries to, engage in any activities which would cause a change in its status, or that of its Subsidiaries, under the 1935 Act. -26- (r) Regulatory Matters. Subject to applicable law and except for non-material filings in the ordinary course of business consistent with past practice, EUA shall consult with NEES prior to implementing any changes in its or any of its Subsidiaries' rates or charges, standards of service or accounting or executing any agreement with respect thereto that is otherwise permitted under this Agreement and shall, and shall cause its Subsidiaries to, deliver to NEES a copy of each such filing or agreement at least four (4) business days prior to the filing or execution thereof so that NEES may comment thereon. EUA shall, and shall cause its Subsidiaries to, make all such filings (i) only in the ordinary course of business consistent with past practice or (ii) as required by a Governmental Authority or regulatory agency with appropriate jurisdiction. (s) Accounting. EUA shall not, nor shall it permit any of its Subsidiaries to make any changes in their accounting methods, policies or procedures, except as required by law, rule, regulation or applicable generally accepted accounting principles; (t) Tax Status. Neither EUA nor any of its Subsidiaries shall (i) make or rescind any material express or deemed election relating to Taxes, (ii) make a request for a Tax Ruling or enter into a Closing Agreement, (iii) settle or compromise any material claim, action, suit, litigation, proceeding, arbitration, investigation, audit, or controversy relating to Taxes or (iv) change in any material respect any of its methods of reporting income, deductions or accounting for federal income tax purposes from those employed in the preparation of its federal income Tax Return for the taxable year ending December 31, 1997, except as may be required by applicable law. (u) No Breach. EUA shall not, nor shall it permit any of its Subsidiaries to willfully take or fail to take any action that would or is reasonably likely to result in (i) a material breach of any provision of this Agreement or (ii) its representations and warranties set forth in this Agreement being untrue in any material respect on and as of the Closing Date. (v) Advice of Changes. EUA shall confer with NEES on a regular and frequent basis with respect to EUA's business and operations and other matters relevant to the Merger to the extent permitted by law, and shall promptly advise NEES, orally and in writing, of any material change or event, including, without limitation, any complaint, investigation or hearing by any Governmental Authority (or communication indicating the same may be contemplated) or the institution or threat of material litigation; provided that EUA shall not be required to make any disclosure to the extent such disclosure would constitute a violation of any applicable law or regulation. (w) Notice and Cure. EUA will notify NEES in writing of, and will use all commercially reasonable efforts to cure before the Closing, any event, transaction or circumstance, as soon as practical after it becomes known to EUA, that causes or will or may be likely to cause any covenant or agreement of EUA under this Agreement to be breached or that renders or will render untrue in any material respect any representation or warranty of EUA contained in this Agreement. EUA also will notify NEES in writing of, and will use all -27- commercially reasonable efforts to cure, before the Closing, any material violation or breach, as soon as practical after it becomes known to EUA, of any representation, warranty, covenant or agreement made by EUA. No notice given pursuant to this paragraph shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein. (x) Fulfillment of Conditions. Subject to the terms and conditions of this Agreement, EUA will take or cause to be taken all commercially reasonable steps necessary or desirable and proceed diligently and in good faith to satisfy each condition to the other's obligations contained in this Agreement and to consummate and make effective the Merger and other transactions contemplated by this Agreement, and EUA will not, nor will it permit any of its Subsidiaries to, take or fail to take any action that could be reasonably expected to result in the nonfulfillment of any such condition. (y) Third Party Standstill Agreements. Except as provided in Section 7.08 hereto, during the period from the date of this Agreement through the Effective Time, neither EUA nor any of its Subsidiaries shall terminate, amend, modify or waive any provision of any confidentiality or standstill agreement to which it is a party. During such period, EUA shall take all steps necessary to enforce, to the fullest extent permitted under applicable law, the provisions of any such agreement. 6.02 Covenants of NEES. At all times from and after the date hereof until the Effective Time, NEES covenants and agrees that (except as expressly contemplated or permitted by this Agreement or to the extent that EUA shall otherwise previously consent in writing): (a) No Breach. NEES shall not, nor shall it permit any of its Subsidiaries to, except as otherwise expressly provided for in this Agreement, willfully take or fail to take any action that would or is reasonably likely to result in (i) a material breach of any of its covenants or agreements contained in this Agreement or (ii) any of its representations and warranties set forth in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.06, 5.07, 5.08 and 5.09 of this Agreement being untrue in any material respect on and as of the Closing Date. (b) Advice of Changes. NEES shall confer with EUA on a regular and frequent basis with respect to any matter having, or which, insofar as can be reasonably foreseen, could reasonably be expected to have, a NEES Material Adverse Effect or materially impair the ability of NEES to consummate the Merger and other transactions contemplated hereby; provided that NEES shall not be required to make any disclosure to the extent such disclosure would constitute a violation of any applicable law or regulation. (c) Notice and Cure. NEES will notify EUA in writing of, and will use all commercially reasonable efforts to cure before the Closing, any event, transaction or circumstance, as soon as practical after it becomes known to NEES, that causes or will or may be likely to cause any covenant or agreement of NEES under this Agreement to be breached or that renders or will render -28- untrue in any material respect any representation or warranty of NEES contained in this Agreement. NEES also will notify EUA in writing of, and will use all commercially reasonable efforts to cure before the Closing, any material violation or breach, as soon as practical after it becomes known to such party, of any representation, warranty, covenant or agreement made by NEES. No notice given pursuant to this paragraph shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein. (d) Fulfillment of Conditions. Subject to the terms and conditions of this Agreement, NEES will take or cause to be taken all commercially reasonable steps necessary or desirable and proceed diligently and in good faith to satisfy each condition to its obligations contained in this Agreement and to consummate and make effective the Merger and other transactions contemplated by this Agreement, and NEES will not, nor will it permit any of its Subsidiaries to, take or fail to take any action that could be reasonably expected to result in the nonfulfillment of any such condition. (e) Conduct of Business of LLC. Prior to the Effective Time, except as may be required by applicable law and subject to the other provisions of this Agreement, NEES shall cause LLC to (i) perform its obligations under this Agreement in accordance with its terms, and (ii) not engage directly or indirectly in any business or activities of any type or kind and not enter into any agreements or arrangements with any person, or be subject to or bound by any obligation or undertaking, which is inconsistent with this Agreement. (f) Certain Mergers. NEES shall not, and shall not permit any of its Subsidiaries to, acquire or agree to acquire by merging or consolidating with, or by purchasing a substantial portion of the assets of or equity in, or by any other manner, any business or any corporation, partnership, association or other business organization or division thereof, or otherwise acquire or agree to acquire any assets if the entering into of a definitive agreement relating to or the consummation of such acquisition, merger or consolidation could reasonably be expected to (i) impose any material delay in the obtaining of, or significantly increase the risk of not obtaining, any authorizations, consents, orders, declarations or approvals of any Governmental Authority necessary to consummate the Merger or the expiration or termination of any applicable waiting period, (ii) significantly increase the risk of any Governmental Authority entering an order prohibiting the consummation of the Merger, (iii) significantly increase the risk of not being able to remove any such order on appeal or otherwise or (iv) materially delay the consummation of the Merger. 6.03 Additional Covenants by NEES and EUA. (a) Control of Other Party's Business. Nothing contained in this Agreement shall give NEES, directly or indirectly, the right to control or direct EUA's operations prior to the Effective Time. Nothing contained in this Agreement shall give EUA, directly or indirectly, the right to control or direct NEES' operations prior to the Effective Time. Prior to the Effective Time, each of EUA and NEES shall exercise, consistent with the terms and conditions of this Agreement, complete control and supervision over its respective operations. -29- (b) Transition Steering Team. As soon as reasonably practicable after the date hereof, NEES and EUA shall create a special transition steering team, with representation from EUA and NEES, that will develop recommendations concerning the future structure and operations of EUA after the Effective Time, subject to applicable law. The members of the transition steering team shall be appointed by the Chief Executive Officers of NEES and EUA. The functions of the transition steering team shall include (i) to direct the exchange of information and documents between the parties and their Subsidiaries as contemplated by Section 7.01 and (ii) the development of regulatory plans and proposals, corporate organizational and management plans, workforce combination proposals, and such other matters as they deem appropriate. ARTICLE VII ADDITIONAL AGREEMENTS 7.01 Access to Information. EUA shall, and shall cause each of its Subsidiaries to, and shall use commercially reasonable efforts to cause EUA Associates to, throughout the period from the date hereof to the Effective Time to the extent permitted by law, (i) provide NEES and its Representatives with full access, upon reasonable prior notice and during normal business hours, to all facilities, operations, officers (including EUA's environmental, health and safety personnel), employees, agents and accountants of EUA and its Subsidiaries and Associates and their respective assets, properties, books and records, to the extent EUA or any Subsidiary of EUA or EUA Associate is not under a legal obligation not to provide access or to the extent that such access would not constitute a waiver of the attorney client privilege and does not unreasonably interfere with the business and operations of EUA and its Subsidiaries and Associates and (ii) furnish promptly to such persons (x) a copy of each report, statement, schedule and other document filed or received by EUA or any of its Subsidiaries pursuant to the requirements of federal or state securities laws and each material report, statement, schedule and other document filed with any other Governmental Authority, and (y) all other information and data (including, without limitation, copies of Contracts, EUA Employee Benefit Plans, and other books and records) concerning the business and operations of EUA and its Subsidiaries as NEES or any of its Representatives reasonably may request. No review pursuant to this Section 7.01 or otherwise shall affect any representation or warranty contained in this Agreement or any condition to the obligations of the parties hereto. Any such information or material obtained pursuant to this Section 7.01 that constitutes "Evaluation Material" (as such term is defined in the letter agreement dated as of December 18, 1998 between EUA and NEES (the "Confidentiality Agreement")) shall be governed by the terms of the Confidentiality Agreement. NEES may provide information or materials that it obtains relating to EUA or any EUA Subsidiary pursuant to this Section 7.01 to National Grid Group; the treatment by National Grid Group of such information or material shall be governed by the terms of the letter agreement dated as of December 21, 1998 between EUA and National Grid Group. 7.02 Proxy Statement. As soon as reasonably practicable after the date of this Agreement, EUA shall prepare and file the Proxy Statement with the -30- SEC. NEES and EUA shall cooperate with each other in the preparation of the Proxy Statement and any amendment or supplement thereto, and EUA shall promptly notify NEES of the receipt of any comments of the SEC with respect to the Proxy Statement and of any requests by the SEC for any amendment or supplement thereto or for additional information, and shall promptly provide to NEES copies of all correspondence between EUA or any of its Representatives and the SEC with respect to the Proxy Statement (except reports from financial advisors other than with the consent of such financial advisors). Each of the parties hereto shall furnish all information concerning itself which is required or customary for inclusion in the Proxy Statement. EUA shall consult with NEES regarding the Proxy Statement and have due regard to any comments NEES may make in relation to the Proxy Statement. EUA shall give NEES and its counsel the opportunity to review the Proxy Statement and all responses to requests for additional information by and replies to comments of the SEC before their being filed with, or sent to, the SEC. Each of EUA and NEES agrees to use its reasonable best efforts, after consultation with the other parties hereto, to respond promptly to all such comments of and requests by the SEC. After obtaining the consent of EUA, which consent shall not be unreasonably withheld, NEES may provide information supplied to NEES by EUA to National Grid Group for inclusion of such information in the Super Class 1 circular ("NGG Circular") to be issued to shareholders of National Grid Group in connection with approval by such shareholders of the National Grid Merger Agreement. NEES shall use its best efforts to provide EUA with a draft of any portion of the NGG Circular with information relating to EUA prior to the issuance of the NGG Circular. 7.03 Approval of Shareholders. EUA shall, through its Board of Trustees, duly call, give notice of, convene and hold a meeting of its shareholders (the "EUA Shareholders' Meeting") for the purpose of voting on the approval of the Merger and other transactions contemplated hereby (the "EUA Shareholders' Approval") as soon as reasonably practicable after the date hereof; provided, however, subject to the fiduciary duties of its Board of Trustees and the requirements of applicable law, EUA shall include in the Proxy Statement the recommendation of the Board of Trustees of EUA that the Shareholders of EUA approve the Merger and the other transactions contemplated hereby, and shall use its reasonable best efforts to obtain such approval. 7.04 Regulatory and Other Approvals. (a) HSR Filings. Each party hereto shall file or cause to be filed with the Federal Trade Commission and the Department of Justice any notifications required to be filed by its respective "ultimate parent" company under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"), and the rules and regulations promulgated thereunder with respect to the Merger and other transactions contemplated hereby. Such parties will use all commercially reasonable efforts to make such filings in a timely manner and to respond on a timely basis to any requests for additional information made by either of such agencies. (b) Other Regulatory Approvals. Each party shall cooperate and use its best efforts to promptly prepare and file all necessary applications, notices, petitions, filings and other documents with, and to use all commercially reasonable efforts to obtain all necessary permits, consents, approvals and authorizations of, all Governmental Authorities necessary or -31- advisable to obtain the EUA Required Statutory Approvals, the NEES Required Statutory Approvals and the approvals of the state utility commissions referred to in Section 8.01(d) (collectively, the "NEES-EUA Regulatory Approvals"). The parties agree that they will consult with each other with respect to obtaining the NEES-EUA Regulatory Approvals; provided, however, that NEES shall have primary responsibility for the preparation and filing of any related applications, filings or other material with the SEC, the FERC, the NRC and state utility commissions. EUA shall have the right to review and approve in advance drafts of and final applications, filings and other material (including material with respect to proposed settlements) submitted to or filed with the SEC, the FERC, the NRC and state utility commissions or parties to such proceedings before such Governmental Authority, which approval shall not be unreasonably withheld or delayed. (c) NEES-NGG Regulatory Proceedings. EUA and NEES acknowledge that, at the same time EUA and NEES will be seeking to obtain the NEES-EUA Regulatory Approvals, National Grid Group and NEES will be seeking to obtain the regulatory approvals (the "NEES-NGG Regulatory Approvals") required to consummate the transactions contemplated by the National Grid Merger Agreement. NEES and EUA agree to seek to prosecute the proceedings relating to the NEES-EUA Regulatory Approvals (the "NEES-EUA Regulatory Proceedings") separately from the prosecution by National Grid Group and NEES of the proceedings relating to the NEES-NGG Regulatory Approvals (the "NEES-NGG Regulatory Proceedings"), but recognize that one or more of the NEES-EUA Regulatory Proceedings may be consolidated with one or more of the NEES-NGG Regulatory Proceedings by the relevant Governmental Authority. Upon the request of EUA, NEES will keep EUA reasonably apprised of the status of the NEES-NGG Regulatory Proceedings. 7.05 Employee Benefit Plans. (a) For a period of twelve (12) months immediately following the Closing Date, the compensation, benefits and coverage provided to those non-union individuals who continue to be employees of the Surviving Entity (the "Affected Employees") pursuant to employee benefit plans or arrangements maintained by NEES or the Surviving Entity shall be, in the aggregate, not less favorable (as determined by NEES and the Surviving Entity using reasonable assumptions and benefit valuation methods) than those provided, in the aggregate, to such Affected Employees immediately prior to the Closing Date. In addition to the foregoing, NEES shall, or shall cause the Surviving Entity to, pay any Affected Employee whose employment is terminated by NEES or the Surviving Entity within twelve (12) months of the Closing Date a severance benefit package equivalent to the severance benefit package that would be provided under the NEES Standard Severance Plan as in effect on the date hereof. (b) NEES shall, or shall cause the Surviving Entity to, give the Affected Employees full credit for purposes of eligibility, vesting, benefit accrual (including, without limitation, benefit accrual under any defined benefit pension plans) and determination of the level of benefits under any employee benefit plans or arrangements maintained by NEES or the Surviving Entity in effect as of the Closing Date for such Affected Employees' service with EUA or any Subsidiary of EUA (or any prior employer) to the same extent -32- recognized by EUA or such Subsidiary immediately prior to the Closing Date. With respect to any employee benefit plan or arrangement established by NEES, EUA or the Surviving Entity after the Closing Date (the "Post Closing Plans"), service shall be credited in accordance with the terms of such Post Closing Plans. (c) NEES shall, or shall cause the Surviving Entity to, (i) waive all limitations as to preexisting conditions, exclusions and waiting periods with respect to participation and coverage requirements applicable to the Affected Employees under any welfare benefit plan established to replace any EUA welfare benefit plans in which such Affected Employees may be eligible to participate after the Closing Date, other than limitations or waiting periods that are already in effect with respect to such Affected Employees and that have not been satisfied as of the Closing Date under any welfare plan maintained for the Affected Employees immediately prior to the Closing Date, and (ii) provide each Affected Employee with credit for any co-payments and deductibles paid prior to the Closing Date in satisfying any applicable deductible or out-of-pocket requirements under any welfare plans that such Affected Employees are eligible to participate in after the Closing Date. (d)(i) NEES shall, or shall cause the Surviving Entity and its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving Entity and its Subsidiaries under, all EUA Employee Benefit Plans as in effect on the date hereof; provided, however, that this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity from exercising their rights with respect to all EUA Employee Benefit Plans solely in accordance with their terms, including but not limited to the right to alter, terminate or otherwise amend such EUA Employee Benefit Plans. (ii) NEES shall, or shall cause the Surviving Entity and its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving Entity and its Subsidiaries under, (A) all employment severance, consulting and retention agreements or arrangements as in effect on the date hereof, as set forth in Section 7.05(d)(ii) of the EUA Disclosure Letter, or as modified in accordance with Section 6.01(i) of the EUA Disclosure Letter (such agreements or arrangements, the "EUA Employee Agreements" and the individuals who are parties to such EUA Employee Agreements, the "EUA Executives") and (B) all EUA Employee Benefit Plans in which such EUA Executives participate; provided, however, that this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity from exercising their rights with respect to the EUA Employee Agreements and the EUA Employee Benefit Plans in which such EUA Executives participate, in each case solely in accordance with their terms, including but not limited to the right to alter, terminate or otherwise amend such EUA Employee Agreements and EUA Employee Benefit Plans. (e) Notwithstanding the foregoing, NEES and the Surviving Entity and its subsidiaries shall neither be required to or prevented from merging EUA's benefit plans, agreements, or arrangements into NEES or the Surviving Entity and its subsidiaries benefit plans, agreements, or arrangements or from -33- replacing EUA's benefit plans, agreements or arrangements with NEES or the Surviving Entity and its subsidiaries benefit plans, agreements or arrangements. 7.06 Labor Agreements and Workforce Matters. (a) Labor Agreements. NEES shall honor, or shall cause the appropriate subsidiaries of the Surviving Entity to honor, all collective bargaining agreements of EUA or its subsidiaries in effect as of the Effective Time until their expiration; provided, however, that this undertaking is not intended to prevent NEES or the Surviving Entity and its subsidiaries from exercising their rights with respect to such collective bargaining agreements and in accordance with their terms, including any right to amend, modify, suspend, revoke or terminate any such contract, agreement, collective bargaining agreement or commitment or portion thereof. (b) Workforce Matters. Subject to applicable law and obligations under applicable collective bargaining agreements, for a period of 2 years following the Effective Time, any reductions in workforce in respect of employees of the Surviving Entity and its Subsidiaries shall be made on a fair and equitable basis as determined by the Surviving Entity, with due consideration to prior experience and skills, and any employee whose employment is terminated or job is eliminated during such period shall be entitled to participate on a fair and equitable basis as determined by NEES or the Surviving Entity in the job opportunity and employment placement programs offered by NEES or the Surviving Entity or any of their Subsidiaries for which they are eligible. Any workforce reductions carried out following the Effective Time by the Surviving Entity and its Subsidiaries shall be done in accordance with all applicable collective bargaining agreements and all laws and regulations governing the employment relationship and termination thereof including, without limitation, the Worker Adjustment and Retraining Notification Act, and the regulations promulgated thereunder, and any comparable state or local law. 7.07 Post Merger Operations. (a) NEES Advisory Board. If the Merger is consummated, then, promptly following the closing of the merger contemplated by the National Grid Merger Agreement, NEES shall take such action as is necessary to cause all of the members of the Board of Directors of EUA to be appointed to serve on the advisory board to be formed pursuant to Section 7.07(e) of the National Grid Merger Agreement. (b) Charities. The parties agree that provision of charitable contribution and community support within the New England region serves a number of important goals. After the Effective Time, NEES intends to cause the Surviving Entity to provide charitable contributions and community support within the New England region at annual levels substantially comparable to the annual level of charitable contributions and community support provided, directly or indirectly, by EUA and its public utility subsidiaries within the New England region during 1998. -34- 7.08 No Solicitations. Prior to the Effective Time, EUA agrees: (a) that neither it nor any of its Subsidiaries shall, and it shall use its best efforts to cause its Representatives (as defined in Section 10.10) not to, knowingly initiate, solicit or encourage, directly or indirectly, any inquiries or any proposal or offer (including, without limitation, any proposal or offer to its Shareholders) with respect to a merger, consolidation or other business combination including EUA or any of its significant Subsidiaries (as defined in Rule 1-02(W) of Regulation S-X promulgated under the Exchange Act) other than EUA Cogenex Corporation (an "EUA Significant Subsidiary"), or any acquisition or similar transaction (including, without limitation, a tender or exchange offer) involving the purchase of (i) all or any significant portion of the assets of EUA and its Subsidiaries taken as a whole, (ii) ten percent or more of the outstanding EUA Shares or (iii) 50% or more of the outstanding shares of the capital stock of any EUA Significant Subsidiary (any such proposal or offer being hereinafter referred to as an "Alternative Proposal"), or engage in any negotiations concerning, or provide any confidential information or data to, or have any other discussions with, any person or group relating to an Alternative Proposal, or otherwise knowingly facilitate any effort or attempt to make or implement an Alternative Proposal other than from NEES and its affiliates; (b) that it will immediately cease and cause to be terminated any existing activities, discussions or negotiations with any parties with respect to any Alternative Proposal; and (c) that it will notify NEES immediately if any such inquiries, proposals or offers are received by, any such information is requested from, or any such negotiations or discussions are sought to be initiated or continued with, it or any of such persons; provided, however, that, prior to receipt of the EUA Shareholders' Approval, nothing contained in this Section 7.08 shall prohibit the Board of Trustees of EUA from (i) furnishing information to (but only pursuant to a confidentiality agreement in customary form and having terms and conditions no less favorable to EUA than the Confidentiality Agreement (as defined in Section 7.01)) or entering into discussions or negotiations with any person or group that makes an unsolicited Alternative Proposal, if, and only to the extent that, (A) the Board of Trustees of EUA, based upon advice of outside counsel with respect to fiduciary duties, determines in good faith that such action is necessary for the Board of Trustees to act in a manner consistent with its fiduciary duties to Shareholders under applicable law, (B) the Board of Trustees of EUA has reasonably concluded in good faith (after consultation with its financial advisors) that the person or group making such Alternative Proposal will have adequate sources of financing to consummate such Alternative Proposal and that such Alternative Proposal is likely to be more favorable to EUA's shareholders than the Merger, (C) prior to furnishing such information to, or entering into discussions or negotiations with, such person or group, EUA provides written notice to NEES to the effect that it is furnishing information to, or entering into discussions or negotiations with, such person or group, which notice shall identify such person or group and the material terms of the Alternative Proposal in reasonable detail, and (D) EUA keeps NEES promptly informed of the status and all material information with respect to any such discussions or negotiations; and (ii) to the extent required, complying with Rule 14e-2 promulgated under the Exchange Act with regard to an Alternative Proposal. Nothing in this Section 7.08 shall (x) permit EUA to terminate this Agreement (except as specifically provided in Article IX), (y) permit EUA to enter into any agreement with respect to an Alternative Proposal for so long as this Agreement remains in effect (it being agreed that for so long as this Agreement remains in effect, EUA shall not enter -35- into any agreement with any person or group that provides for, or in any way knowingly facilitates, an Alternative Proposal (other than a confidentiality agreement under the circumstances described above)), or (z) affect any other obligation of EUA under this Agreement. 7.09 Directors' and Officers' Indemnification and Insurance. (a) Indemnification. To the extent, if any, not provided by an existing right of indemnification or other agreement or policy, from and after the Effective Time, NEES shall, or shall cause the Surviving Entity to, to the fullest extent permitted by applicable law, indemnify, defend and hold harmless each person who is now, or has been at any time prior to the date hereof, or who becomes prior to the Effective Time, (x) an officer, trustee or director or (y) an employee covered as of the date hereof (to the extent of the coverage extended as of the date hereof) of EUA or any Subsidiary of EUA (each an "Indemnified Party," and collectively, the "Indemnified Parties") against (i) all losses, expenses (including reasonable attorney's fees and expenses), claims, damages or liabilities or, subject to the first proviso of the next succeeding sentence, amounts paid in settlement, arising out of actions or omissions occurring at or prior to the Effective Time (and whether asserted or claimed prior to, at or after the Effective Time) that are, in whole or in part, based on or arising out of the fact that such person is or was a director, trustee, officer or employee of EUA or any Subsidiary of EUA (the "Indemnified Liabilities"), and (ii) all Indemnified Liabilities to the extent they are based on or arise out of or pertain to the transactions contemplated by this Agreement, in each case, to the extent permitted by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter. In the event of any such loss, expense, claim, damage or liability (whether or not arising before the Effective Time), (i) NEES shall, or shall cause the Surviving Entity to, pay the reasonable fees and expenses of counsel selected by the Indemnified Parties, which counsel shall be reasonably satisfactory to NEES or the Surviving Entity, as appropriate, promptly after statements therefor are received and otherwise advance to such Indemnified Party upon request, reimbursement of documented expenses reasonably incurred, in either case to the extent not prohibited by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter upon receipt of an undertaking by or on behalf of such director, trustee or officer to repay such amounts as and to the extent required by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter, (ii) the Surviving Entity shall cooperate in the defense of any such matter and (iii) any determination required to be made with respect to whether an Indemnified Party's conduct complies with the standards set forth under the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter and the certificate of incorporation or by-laws or similar governing documents of the Surviving Entity shall be made by independent counsel mutually acceptable to the Surviving Entity and the Indemnified Party; provided, however, that the Surviving Entity shall not be liable for any settlement effected without its written consent (which consent shall not be unreasonably withheld) and provided further that no indemnification shall be made if such indemnification is prohibited by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter. -36- (b) Insurance. For a period of six years after the Effective Time, NEES and the Surviving Entity at NEES's election, (i) shall cause to be maintained in effect an extended reporting period for current policies of directors' and officers' liability insurance for the benefit of such persons who are currently covered by such policies of EUA on terms no less favorable than the terms of such current insurance coverage or (ii) shall provide tail coverage for such persons which provides such persons with coverage for a period of six years for acts prior to the Effective Time on terms no less favorable than the terms of such current insurance coverage. (c) Successors. In the event the Surviving Entity or any of its successors or assigns (i) consolidates with or merges into any other person or entity and shall not be the continuing or surviving corporation or entity of such consolidation or merger or (ii) transfers all or substantially all of its properties and assets to any person or entity, then and in either such case, proper provisions shall be made so that the successors and assigns of the Surviving Entity, as applicable, shall assume the obligations set forth in this Section 7.09. (d) Survival of Indemnification. To the fullest extent permitted by law, from and after the Effective Time, all rights to indemnification as of the date hereof in favor of the employees, agents, directors, trustees and officers of EUA and EUA's Subsidiaries with respect to their activities as such prior to the Effective Time, as provided in the EUA Trust Agreement or the respective certificates of incorporation and by-laws or similar governing documents in effect on the date hereof, or otherwise in effect on the date hereof, shall survive the Merger and shall continue in full force and effect for a period of not less than six years from the Effective Time. (e) Benefit. The provisions of this Section 7.09 are intended to be for the benefit of, and shall be enforceable by, each Indemnified Party, his or her heirs and his or her representatives. (f) Amendment of the EUA Trust Agreement. NEES shall not, and shall ensure that the Surviving Entity shall not, amend the EUA Trust Agreement to in any way limit the indemnification provided to the Indemnified Parties under this Section 7.09. 7.10 Expenses. Except as set forth in Section 9.03, whether or not the Merger is consummated, all costs and expenses incurred in connection with the Merger and other transactions contemplated hereby shall be paid by the party incurring such cost or expense, except that the filing fees in connection with the filings required under the HSR Act and the 1935 Act shall be paid by NEES. 7.11 Brokers or Finders. EUA represents, as to itself and its affiliates, that no agent, broker, investment banker, financial advisor or other firm or person is or will be entitled to any broker's, finder's or investment banker's fee or any other commission or similar fee in connection with the Merger and other transactions contemplated by this Agreement except Salomon Smith Barney Inc., whose fees and expenses will be paid by EUA in accordance with EUA's agreement with such firm, and EUA shall indemnify and hold NEES harmless from and against any and all claims, liabilities or obligations with -37- respect to any other such fee or commission or expenses related thereto asserted by any person on the basis of any act or statement alleged to have been made by EUA or its affiliates. 7.12 Anti-Takeover Statutes. If any "fair price", "moratorium", "business combination", "control share acquisition" or other form of anti-takeover statute or regulation shall become applicable to the Merger or other transactions contemplated hereby, EUA and the members of the Board of Trustees of EUA shall grant such approvals and take such actions consistent with their fiduciary duties and in accordance with applicable law as are reasonably necessary so that the Merger and other transactions contemplated hereby may be consummated as promptly as practicable on the terms contemplated hereby and otherwise act to eliminate or minimize the effects of such statute or regulation on the Merger and other transactions contemplated hereby. 7.13 Public Announcements. Except as otherwise required by law or the rules of any applicable securities exchange or national market system or any other Regulatory Authority, so long as this Agreement is in effect, NEES and EUA will not, and will not permit any of their respective Subsidiaries or Representatives to, issue or cause the publication of any press release or make any other public announcement with respect to the Merger and other transactions contemplated by this Agreement without the consent of the other party, which consent shall not be unreasonably withheld. NEES and EUA will cooperate with each other in the development and distribution of all press releases and other public announcements with respect to the Merger and other transactions contemplated hereby, and will furnish the other with drafts of any such releases and announcements as far in advance as practicable. 7.14 Restructuring of the Merger. It may be preferable to effectuate a business combination between NEES and EUA by means of an alternative structure to the Merger. Accordingly, if, prior to satisfaction of the conditions contained in Article VIII hereto, NEES proposes the adoption of an alternative structure that otherwise substantially preserves for NEES and EUA the economic benefits of the Merger and will not materially delay the consummation thereof, then the parties shall use their respective best efforts to effect a business combination among themselves by means of a mutually agreed upon structure other than the Merger that so preserves such benefits; provided, however, that prior to closing any such restructured transaction, all material third party and Governmental Authority declarations, filings, registrations, notices, authorizations, consents or approvals necessary for the effectuation of such alternative business combination shall have been obtained and all other conditions to the parties' obligations to consummate the Merger and other transactions contemplated hereby, as applied to such alternative business combination, shall have been satisfied or waived. -38- ARTICLE VIII CONDITIONS 8.01 Conditions to Each Party's Obligation to Effect the Merger. The respective obligation of each party to effect the Merger and other transactions contemplated hereby is subject to the satisfaction or waiver, at or prior to the Closing, of each of the following conditions: (a) Shareholder Approval. EUA Shareholders' Approval shall have been obtained. (b) HSR Act. Any waiting period (and any extension thereof) applicable to the consummation of the Merger under HSR shall have expired or been terminated. (c) Injunctions or Restraints. No court of competent jurisdiction or other competent Governmental Authority shall have enacted, issued, promulgated, enforced or entered any law or order (whether temporary, preliminary or permanent) which is then in effect and has the effect of making illegal or otherwise restricting, preventing or prohibiting consummation of the Merger or other transactions contemplated hereby. (d) Governmental and Regulatory and Other Consents and Approvals. The NEES Required Statutory Approvals and EUA Required Statutory Approvals shall have been obtained prior to the Effective Time, and shall have become Final Orders (as hereinafter defined). The Final Orders shall not, individually or in the aggregate, impose terms and conditions that (i) could reasonably be expected to have an EUA Material Adverse Effect; (ii) could reasonably be expected to have a NEES Material Adverse Effect; or (iii) materially impair the ability of the parties to complete the Merger. The parties shall have received Final Orders from the Massachusetts Department of Telecommunications and Energy and the Rhode Island Public Utilities Commission pertaining to the recovery of costs (including, without limitation, transaction premium and integration costs) associated with the Merger that are materially consistent with existing policy and previous orders of such agencies. "Final Order" for all purposes of this Agreement means action by the relevant regulatory authority which has not been reversed, stayed, enjoined, set aside, annulled or suspended with respect to which any waiting period prescribed by law before the Merger and other transactions contemplated hereby may be consummated has expired, and as to which all conditions to be satisfied before the consummation of such transactions prescribed by law, regulation or order have been satisfied. 8.02 Conditions to Obligation of NEES and LLC to Effect the Merger. The obligation of NEES and LLC to effect the Merger and other transactions contemplated hereby is further subject to the satisfaction or waiver at or prior to the Closing, of each of the following additional conditions (all or any of which may be waived in whole or in part by NEES and LLC in the sole discretion): -39- (a) Representations and Warranties. The representations and warranties made by EUA in this Agreement, in each case made as if none of such representations or warranties contained any qualification or limitation as to "materiality" or "EUA Material Adverse Effect", shall be true and correct as so made as of the Closing Date as though so made on and as of the Closing Date, except to the extent expressly given as of a specified date, except where the failure of such representations and warranties to be true and correct as so made does not have and could not reasonably be expected to have, individually or in the aggregate, an EUA Material Adverse Effect, and EUA shall have delivered to NEES a certificate, dated the Closing Date and executed in the name and on behalf of EUA by its Chairman of the Board, President or any Executive or Senior Vice President, to such effect. (b) Performance of Obligations. EUA shall have performed and complied with, in all material respects, each agreement, covenant and obligation required by this Agreement to be so performed or complied with by EUA at or prior to the Closing, and EUA shall have delivered to NEES a certificate, dated the Closing Date and executed in the name and on behalf of EUA by its Chairman of the Board, President or any Executive or Senior Vice President, to such effect. (c) Material Adverse Effect. No EUA Material Adverse Effect shall have occurred and there shall exist no facts or circumstances which in the aggregate could reasonably be expected to have an EUA Material Adverse Effect. (d) EUA Required Consents. All EUA Required Consents shall have been obtained by EUA, except where the failure to receive such EUA Required Consents could not reasonably be expected to (i) have an EUA Material Adverse Effect, or (ii) delay or prevent the consummation of the Merger and other transactions contemplated hereby. 8.03 Conditions to Obligation of EUA to Effect the Merger. The obligation of EUA to effect the Merger and other transactions contemplated hereby is further subject to the satisfaction or waiver, at or prior to the Closing, of each of the following additional conditions (all or any of which may be waived in whole or in part by EUA in its sole discretion): (a) Representations and Warranties. The representations and warranties made by NEES and LLC in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.07, 5.08 and 5.09 of this Agreement, in each case made as if none of such representations or warranties contained any qualification or limitation as to "materiality" or "NEES Material Adverse Effect," shall be true and correct as so made as of the Closing Date, except to the extent expressly given as of a specified date and except where the failure of such representations and warranties to be so true and correct as so made does not have and could not reasonably be expected to have, individually or in the aggregate, a NEES Material Adverse Effect or a material adverse effect on LLC, and NEES and LLC shall each have delivered to EUA a certificate, dated the Closing Date and executed in the name and on behalf of NEES by any director of NEES and in the name and on behalf of LLC by a member of its management committee its Chairman of the Board, President or any Executive or Senior Vice President to such effect. -40- (b) NEES Required Consents. All NEES Required Consents shall have been obtained by NEES, except where the failure to receive such NEES Required Consents could not reasonably be expected to (i) have a NEES Material Adverse Effect or (ii) delay or prevent the consummation of the Merger and other transactions contemplated hereby. (c) Performance of Obligations. NEES and LLC shall have performed and complied with, in all material respects, each agreement, covenant and obligation required by this Agreement to be so performed or complied with by NEES or LLC at or prior to the Closing, and NEES and LLC shall each have delivered to EUA a certificate, dated the Closing Date and executed in the name and on behalf of NEES by its Chairman of the Board, President or any Executive or Senior Vice President, or on behalf of LLC by a member of its management committee to such effect. ARTICLE IX TERMINATION, AMENDMENT AND WAIVER 9.01 Termination. This Agreement may be terminated, and the Merger and other transactions contemplated hereby may be abandoned, at any time prior to the Effective Time, whether prior to or after EUA Shareholders' Approval (except as otherwise provided in Section 9.01(c) below): (a) By mutual written agreement of the Board of Directors of NEES and Board of Trustees of EUA, respectively; (b) By EUA or NEES, by written notice to the other, if the Closing Date shall not have occurred on or before December 31, 1999 (the "Initial Termination Date"); provided, however, that the right to terminate the Agreement under this Section 9.01(b) shall not be available to any party whose failure to fulfill any obligation under this Agreement has been the cause of, or resulted in, the failure of the Effective Time to occur on or before such date; and provided, further, that if on the Initial Termination Date the conditions to the Closing set forth in Section 8.01(d) shall not have been fulfilled but all other conditions to the Closing shall be fulfilled or shall be capable of being fulfilled, then the Initial Termination Date shall be extended for four (4) months beyond the Initial Termination Date (the "Extended Termination Date"); (c) By NEES, by written notice to EUA, if EUA Shareholders' Approval shall not have been obtained at a duly held meeting of such Shareholders, including any adjournments thereof; (d) By EUA or NEES, if any applicable state or federal law or applicable law of a foreign jurisdiction or any order, rule or regulation is adopted or issued that has the effect, as supported by the written opinion of outside counsel for such party, of prohibiting the Merger or other transactions contemplated hereby, or if any court of competent jurisdiction or any Governmental Authority shall have issued a nonappealable final order, judgment -41- or ruling or taken any other action having the effect of permanently restraining, enjoining or otherwise prohibiting the Merger or other transactions contemplated hereby (provided that the right to terminate this Agreement under this Section 9.01(d) shall not be available to any party that has not defended such lawsuit or other legal proceeding (including seeking to have any stay or temporary restraining order entered by any court or other Governmental Authority vacated or reversed)). (e) By EUA upon ten (10) days' prior notice to NEES if the Board of Trustees of EUA determines in good faith, that termination of this Agreement is necessary for the Board of Trustees of EUA to act in a manner consistent with its fiduciary duties to Shareholders under applicable law by reason of an unsolicited Alternative Proposal meeting the requirements of clauses (A) and (B) of Section 7.08 having been made; provided that (A) The Board of Trustees of EUA shall determine based on advice of outside counsel with respect to the Board of Trustees' fiduciary duties that notwithstanding a binding commitment to consummate an agreement of the nature of this Agreement entered into in the proper exercise of its applicable fiduciary duties, and notwithstanding all concessions which may be offered by NEES in negotiation entered into pursuant to clause (B) below, it is necessary pursuant to such fiduciary duties that the trustees reconsider such commitment as a result of such Alternative Proposal, and (B) prior to any such termination, EUA shall, and shall cause its respective financial and legal advisors to, negotiate with NEES to make such adjustments in the terms and conditions of this Agreement as would enable EUA to proceed with the Merger or other transactions contemplated hereby on such adjusted terms; and provided further that EUA's ability to terminate this Agreement pursuant to this Section 9.01(e) is conditioned upon the concurrent payment by EUA to NEES of any amounts owed by it pursuant to Section 9.03(a); (f) By EUA, by written notice to NEES, if (i) there shall have been any material breach of any representation or warranty, or any material breach of any covenant or agreement, of NEES hereunder (other than a breach described in clause (ii)), and such breach shall not have been remedied within twenty (20) days after receipt by NEES of notice in writing from EUA, specifying the nature of such breach and requesting that it be remedied; or (ii) NEES shall fail to deliver or cause to be delivered the amount of cash to the Paying Agent required pursuant to Section 2.02(a) at a time when all conditions to NEES's obligation to close have been satisfied or otherwise waived in writing by NEES. (g) By NEES, by written notice to EUA, if (i) there shall have been any material breach of any representation or warranty, or any material breach of any covenant or agreement, of EUA hereunder, and such breach shall not -42- have been remedied within twenty (20) days after receipt by EUA of notice in writing from NEES, specifying the nature of such breach and requesting that it be remedied; or (ii) the Board of Trustees of EUA (A) shall withdraw or modify in any manner adverse to NEES its approval of the Merger and other transactions contemplated hereby or its recommendation to its shareholders regarding the approval of this Agreement, the Merger and other transactions contemplated hereby, (B) shall approve or recommend or take no position with respect to an Alternative Proposal or (C) shall resolve to take any of the actions specified in clause (A) or (B). 9.02 Effect of Termination. If this Agreement is validly terminated by either EUA or NEES pursuant to Section 9.01, this Agreement shall forthwith become null and void and there shall be no liability or obligation on the part of either EUA or NEES (or any of their respective Representatives or affiliates), except that the provisions of this Section 9.02, Sections 7.10, 7.11 and 7.13, Section 9.03 and Sections 10.09 and 10.10 shall continue to apply following any such termination. 9.03 Termination Fees. (a) In the event that (i) this Agreement is terminated by EUA pursuant to Section 9.01(e) or (ii) any person or group shall have made an Alternative Proposal that has not been withdrawn and this Agreement is terminated by (A) NEES pursuant to Section 9.01(c) or Section 9.01(g) or (B) by EUA pursuant to Section 9.01(b) and, in the case of this clause (ii) only, a definitive agreement with respect to such Alternative Proposal is executed within two years after such termination, then EUA shall pay to NEES, by wire transfer of same day funds, either on the date contemplated in Section 9.01(e) if applicable, or otherwise, within five (5) business days after such termination, a termination fee of $20 million, plus an amount equal to all documented out-of-pocket expenses and fees incurred by NEES arising out of, or in connection with or related to, the Merger and other transactions contemplated hereby, not in excess of $5 million in the aggregate. (b) In the event that this Agreement is terminated by either NEES or EUA pursuant to Section 9.01(b) and at the time of such termination (i) the conditions to the Closing set forth in Section 8.01(d) shall not have been fulfilled, (ii) if the date of termination is any date other than a date which is on or after the Extended Termination Date, all conditions contained in Article VIII other than Sections 8.01(d) or 8.03(c) shall have been fulfilled or are capable of being fulfilled as of such date, and (iii) the merger contemplated by the National Grid Merger Agreement has not yet been consummated, then NEES shall pay to EUA, by wire transfer of same day funds, within five (5) business days after such termination, a termination fee of $10 million, plus an amount equal to all documented out-of-pocket expenses and fees incurred by EUA arising out of, or in connection with or related to, the Merger and other transactions contemplated hereby, not in excess of $5 million in the aggregate. (c) Nature of Fees. The parties agree that the agreements contained in this Section 9.03 are an integral part of the Merger and the other transactions contemplated hereby and constitute liquidated damages and not a penalty. The parties further agree that if any party is or becomes obligated to pay a termination fee pursuant to Sections 9.03(a) or (b), the right to receive such termination fee shall be the sole remedy of the other party with respect to -43- the facts and circumstances giving rise to such payment obligation. If this Agreement is terminated by a party as a result of a willful breach of a representation, warranty, covenant or agreement by the other party, including a termination pursuant to Section 9.01(f)(ii), the non-breaching party may pursue any remedies available to it at law or in equity and shall be entitled to recover any additional amounts thereunder. Notwithstanding anything to the contrary contained in this Section 9.03, if one party fails to promptly pay to the other any fee or expense due under this Section 9.03, in addition to any amounts paid or payable pursuant to such Section, the defaulting party shall pay the costs and expenses (including legal fees and expenses) in connection with any action, including the filing of any lawsuit or other legal action, taken to collect payment, together with interest on the amount of any unpaid fee at the publicly announced prime rate of Citibank, N.A. from the date such fee was required to be paid. 9.04 Amendment. This Agreement may be amended, supplemented or modified by action taken by or on behalf of the Board of Directors of NEES or the Board of Trustees of EUA at any time prior to the Effective Time, whether prior to or after EUA Shareholders' Approval shall have been obtained, but after such adoption and approval only to the extent permitted by applicable law. No such amendment, supplement or modification shall be effective unless set forth in a written instrument duly executed and delivered by or on behalf of each party hereto. 9.05 Waiver. At any time prior to the Effective Time, NEES or EUA, by action taken by or on behalf of its Board of Directors or Board of Trustees, respectively, may to the extent permitted by applicable law (i) extend the time for the performance of any of the obligations or other acts of the other parties hereto, (ii) waive any inaccuracies in the representations and warranties of the other parties hereto contained herein or in any document delivered pursuant hereto or (iii) waive compliance with any of the covenants, agreements or conditions of the other parties hereto contained herein. No such extension or waiver shall be effective unless set forth in a written instrument duly executed by or on behalf of the party extending the time of performance or waiving any such inaccuracy or non-compliance. No waiver by any party of any term or condition of this Agreement, in any one or more instances, shall be deemed to be or construed as a waiver of the same or any other term or condition of this Agreement on any future occasion. ARTICLE X GENERAL PROVISIONS 10.01 Non-Survival of Representations, Warranties, Covenants and Agreements. The representations, warranties, covenants and agreements contained in this Agreement or in any instrument delivered pursuant to this Agreement shall not survive the Merger but shall terminate at the Effective Time, except for the agreements contained in Article I and Article II, in Sections 7.05, 7.06, 7.08, 7.09 and 7.10, this Article X which shall survive the Effective Time. 10.02 Notices. All notices, requests and other communications hereunder must be in writing and will be deemed to have been duly given only if -44- delivered personally or by facsimile transmission or sent by overnight courier (providing proof of delivery) to the parties at the following addresses or facsimile numbers: If to NEES or LLC, to: New England Electric System 25 Research Drive Westborough, MA 01582 Attn: Richard P. Sergel President and Chief Executive Officer Telephone: (508) 389-2764 Facsimile: (508) 366-5498 with a copy to: Skadden, Arps, Slate, Meagher & Flom LLP 919 Third Avenue New York, NY 10022 Attn: Sheldon S. Adler, Esq. Telephone: (212) 735-3000 Facsimile: (212) 735-2000 If to EUA, to: Eastern Utilities Associates One Liberty Square Boston, MA 02109 Attn: Donald G. Pardus Chairman and Chief Executive Officer Telephone: (617) 357-9590 Facsimile: (617) 357-7320 with a copy to: Winthrop, Stimson, Putnam & Roberts 1 Battery Park Plaza New York, NY 10004 Attn: David P. Falck Telephone: (212) 858-1000 Facsimile: (212) 858-1500 All such notices, requests and other communications will (i) if delivered personally to the address as provided in this Section, be deemed given -45- upon delivery, (ii) if delivered by facsimile transmission to the facsimile number as provided in this Section, be deemed given when sent, provided that the facsimile is promptly confirmed by telephone confirmation thereof, and (iii) if delivered by mail in the manner described above to the address as provided in this Section, be deemed given one business day after delivery (in each case regardless of whether such notice, request or other communication is received by any other person to whom a copy of such notice, request or other communication is to be delivered pursuant to this Section). Any party from time to time may change its address, facsimile number or other information for the purpose of notices to that party by giving notice specifying such change to the other parties hereto. 10.03 Entire Agreement; Incorporation of Exhibits. (a) This Agreement supersedes all prior discussions and agreements, both written and oral, among the parties hereto with respect to the subject matter hereof, other than the Confidentiality Agreement, which shall survive the execution and delivery of this Agreement in accordance with its terms, and contains, together with the Confidentiality Agreement, the sole and entire agreement among the parties hereto with respect to the subject matter hereof. (b) The EUA Disclosure Letter, the NEES Disclosure Letter and any Exhibit attached to this Agreement and referred to herein are hereby incorporated herein and made a part hereof for all purposes as if fully set forth herein. 10.04 No Third Party Beneficiary. The terms and provisions of this Agreement are intended solely for the benefit of each party hereto and their respective successors or permitted assigns, and except as provided in Article II and Sections 7.04, 7.05(d)(ii) and 7.09 (which is intended to be for the benefit of the persons entitled to therein, and may be enforced by any of such persons), it is not the intention of the parties to confer third-party beneficiary rights upon any other person. 10.05 No Assignment; Binding Effect. Neither this Agreement nor any right, interest or obligation hereunder may be assigned, in whole or in part, by operation of law or otherwise, by any party hereto without the prior written consent of the other parties hereto and any attempt to do so will be void, except that LLC may assign any or all of its rights, interests and obligations hereunder to another direct or indirect wholly owned Subsidiary of NEES, provided that any such Subsidiary agrees in writing to be bound by all of the terms, conditions and provisions contained herein and provided further that such assignment (i) does not require a greater vote for EUA's Shareholder Approval, (ii) does not require a subsequent vote following EUA's Shareholders Meeting, or (iii) is not reasonably likely to materially delay or prevent EUA, LLC and NEES, as appropriate, from obtaining EUA Required Statutory Approvals, EUA Required Consents, EUA Shareholders' Approval, the NEES Required Shareholders' Approvals, or the NEES Required Consents. Subject to the preceding sentence, this Agreement is binding upon, inures to the benefit of and is enforceable by the parties hereto and their respective successors and assigns. -46- 10.06 Headings. The headings used in this Agreement have been inserted for convenience of reference only and do not define, modify or limit the provisions hereof. 10.07 Invalid Provisions. If any provision of this Agreement is held to be illegal, invalid or unenforceable under any present or future law or order, and if the rights or obligations of any party hereto under this Agreement will not be materially and adversely affected thereby, (i) such provision will be fully severable, (ii) this Agreement will be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, and (iii) the remaining provisions of this Agreement will remain in full force and effect and will not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom. 10.08 Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the Commonwealth of Massachusetts. 10.09 Enforcement of Agreement. The parties hereto agree that irreparable damage would occur in the event that any of the provisions of this Agreement was not performed in accordance with its specified terms or was otherwise breached. It is accordingly agreed that the parties shall be entitled to an injunction or injunctions to prevent breaches of this Agreement and to enforce specifically the terms and provisions hereof in any court of competent jurisdiction, this being in addition to any other remedy to which they are entitled at law or in equity. 10.10 Certain Definitions. As used in this Agreement: (a) except as provided in Section 4.14, the term "affiliate," as applied to any person, shall mean any other person directly or indirectly controlling, controlled by, or under common control with, that person; for purposes of this definition, "control" (including, with correlative meanings, the terms "controlling," "controlled by" and "under common control with"), as applied to any person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of that person, whether through the ownership of voting securities, by contract or otherwise; (b) a person will be deemed to "beneficially" own securities if such person would be the beneficial owner of such securities under Rule 13d-3 under the Exchange Act, including securities which such person has the right to acquire (whether such right is exercisable immediately or only after the passage of time); (c) the term "business day" means a day other than Saturday, Sunday or any day on which banks located in the Massachusetts are authorized or obligated to close; (d) the term "knowledge" or any similar formulation of "knowledge" shall mean, with respect to any party hereto, the actual knowledge after due inquiry of the executive officers of NEES and its Subsidiaries or EUA and its Subsidiaries, respectively, set forth in Section 10.11(d) of the NEES Disclosure Letter or Section 10.11(d) of the EUA Disclosure Letter; provided -47- that as used in Section 4.13 the term "knowledge" shall also include the knowledge of the environmental, health and safety personnel of EUA; (e) the term "person" shall include individuals, corporations, partnerships, trusts, limited liability companies, other entities and groups (which term shall include a "group" as such term is defined in Section 13(d)(3) of the Exchange Act); (f) the "Representatives" of any entity shall have the same meaning as set forth in the Confidentiality Agreement; (g) the term "Subsidiary" means any corporation or other entity, whether incorporated or unincorporated, in which such party directly or indirectly owns at least a majority of the voting power represented by the outstanding capital stock or other voting securities or interests having voting power under ordinary circumstances to elect a majority of the directors or similar members of the governing body, or otherwise to direct the management and policies, or such corporation or entity. 10.11 Counterparts. This Agreement may be executed in any number of counterparts, each of which will be deemed an original, but all of which together will constitute one and the same instrument and will become effective when one or more counterparts have been signed by each party and delivered to the other parties. 10.12 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION. -48- IN WITNESS WHEREOF, each party hereto has caused this Agreement to be signed by its officer thereunto duly authorized as of the date first above written. NEW ENGLAND ELECTRIC SYSTEM By: /s/ Richard P. Sergel ----------------------------------- Name: Richard P. Sergel Title: President and CEO The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer, or agent thereof assumes or shall be held to any liability therefor. EASTERN UTILITIES ASSOCIATES By: /s/ Donald G. Pardus ----------------------------------- Name: Donald G. Pardus Title: Chairman The name "Eastern Utilities Associates" is the designation of the Trustees of EUA for the time being in their collective capacity but not personally, under a Declaration of Trust dated April 2, 1928, as amended, a copy of which amended Declaration of Trust has been filed in the office of the Secretary of The Commonwealth of Massachusetts and elsewhere as required by law; and all persons dealing with EUA must look solely to the trust property for the enforcement of any claim against EUA, as neither the Trustees nor the officers or shareholders of EUA assume any personal liability for obligations entered into on behalf of EUA. RESEARCH DRIVE LLC By: /s/ John G. Cochrane ----------------------------------- Name: John G. Cochrane Title: Manager -49- Tab 2 CONSENT AGREEMENT dated as of February 1, 1999 CONSENT AGREEMENT This Consent Agreement (the "Agreement") is entered into as of February 1, 1999 between The National Grid Group, p1c, a public limited company incorporated under the laws of England and Wales ("NGG") and New England Electric System, a Massachusetts business trust ("NEES"). WHEREAS, NGG, NEES and NGG Holdings LLC (formerly Iosta LLC), a wholly owned subsidiary of NGG, entered into an Agreement and Plan of Merger dated as of December 11, 1998 (the"Merger Agreement") pursuant to which NGG Holdings LLC will merge (the "Merger") with and into NEES with NEES being the surviving entity and becoming a wholly owned subsidiary of NGG; WHEREAS, NEES, Eastern Utilities Associates, a Massachusetts Business Trust ("EUA") and Research Drive LLC are proposing to enter into an Agreement and Plan of Merger in the form attached hereto as Exhibit A (the "EUA Merger Agreement") providing for the merger (the "EUA Merger") of Research Drive LLC with and into EUA with EUA being the surviving entity and becoming a wholly owned subsidiary of NEES; and WHEREAS, pursuant to the provisions of the Merger Agreement, NEES is required to obtain the consent of NGG before entering into the EUA Merger Agreement and with respect to certain actions relating to the consummation of the transactions set forth therein. NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows: 1. Consent to EUA Merger Agreement. Subject to the terms and conditions of this Consent, NGG hereby consents to NEES entering into the EUA Merger Agreement with EUA in the form set forth in Exhibit A and agrees that, subject to the immediately following sentence, the consummation by NEES of the transactions contemplated by the EUA Merger Agreement in accordance with the term thereof shall not constitute a breach by NEES of the terms of the Merger Agreement. NEES and NGG acknowledge that the financing necessary to consummate the EUA Merger was not contemplated when NEES and NGG agreed to the limitations set forth in Article VI of the Merger Agreement and NGG consents to such financing provided that such financing is consistent with the financing parameters set forth on Exhibit B hereto. NGG also consents to the formation and capitalization of Research Drive LLC by NEES for the purpose of effecting the EUA Merger as contemplated in the EUA Merger Agreement. 2. Access to Information. Subject to the following sentence, NEES hereby agrees to provide NGG with reasonable access to any information it receives regarding EUA pursuant to the terms of the EUA Merger Agreement and to consult with NGG on a regular basis concerning the status of EUA and the EUA Merger. NGG hereby acknowledges that any such material that is "Evaluation Material" (as such term is defined in the letter agreement dated as of December 21, 1998 between NGG and NEES (the "Confidentiality Agreement") shall be governed by the terms of the Confidentiality Agreement. 3. Regulatory Filings. NEES hereby agrees that NGG shall have the right to review in advance, and that NEES will consult with NGG and give due regard to NGG's views concerning, any applications, notices, petitions, filings and other documents filed with any Governmental Authority (as defined in the EUA Merger Agreement) in connection with the EUA Merger which could reasonably be expected to have a material adverse effect on NGG's or NEES' ability to consummate the Merger or which could reasonably be expected to adversely affect in any material manner any material benefit of the Merger to NGG or NEES. 4. Amendments to EUA Merger Agreement. NEES hereby agrees that it will not, without the prior written consent of NGG, amend or modify the EUA Merger Agreement in any material respect, including, without limitation, amend or otherwise modify any provision of the EUA Merger Agreement providing for or relating to the amount, type or structure of the Merger Consideration (as defined in the EUA Merger Agreement) or agree to any additional or different amount, type or structure for the Merger Consideration (as so defined). 5. Acknowledgment. NGG and NEES acknowledge and agree that the covenants set forth in Article VI of the Merger Agreement do not reflect the operations of EUA if the EUA Merger is consummated prior to the Effective Time (as defined in the Merger Agreement). In the event that the EUA Merger is consummated prior to the Effective Time, NGG and NEES hereby agree to negotiate in good faith to make appropriate modifications to such covenants set forth in Section 6.01 of the Merger Agreement to reflect the operations of EUA. 6. Termination and Amendment. This Consent Agreement and the obligations of NEES hereunder shall terminate upon the earlier to occur of (i) the termination of the Merger Agreement, (ii) the EUA Merger and (iii) the Merger, in each case without any further action by the parties hereto. Except as provided in the preceding sentence, this Consent can not be terminated or amended in any material respect prior to the termination of the EUA Merger Agreement without the prior written consent of EUA. The foregoing sentence is intended for the benefit of EUA and may be enforced by EUA. 7. Notices. NEES hereby agrees to provide NGG with copies of all notices and other communications it sends to EUA and all notices and other communications it receives from EUA under the EUA Merger Agreement. All notices and other communications provided under this Agreement must be in writing and shall be given in the same manner and to the same parties as set forth in Section 10.02 of the Merger Agreement. 8. Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument. 9. Governing Law and Waiver of Jury Trial. This Agreement shall be governed by and construed in accordance with the laws of the State of New York applicable to a contract executed and performed in such State, without giving effect to the conflicts of laws principles. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION. IN WITNESS WHEREOF, each of NGG and NEES has duly executed this Agreement as of the date first above written. THE NATIONAL GRID GROUP, PLC By: /s/ Fiona B. Smith ----------------------------------- Name: Fiona B. Smith Title: Company Secretary NEW ENGLAND ELECTRIC SYSTEM By: ___________________________ Name: Title: The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer or agent thereof assumes or shall be held to any liability therefor. IN WITNESS WHEREOF, each of NGG and NEES has duly executed this Agreement as of the date first above written. THE NATIONAL GRID GROUP, PLC By: ______________________________ Name: Title: NEW ENGLAND ELECTRIC SYSTEM By: /s/ Richard P. Sergel ----------------------------------- Name: Richard P. Sergel Title: President and CEO The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer or agent thereof assumes or shall be held to any liability therefor. ACKNOWLEDGMENT OF EASTERN UTILITIES ASSOCIATES (not legible) EXHIBIT B - Financing Parameters Financing will be in an amount of up to $630 M provided through a group of banks. The financing (i) will be prepayable, (ii) will have a term not to exceed seven years, (iii) will have a LIBOR-based borrowing option and (iv) will have other terms and conditions usual and customary for transactions of this nature. EX-99 9 EXHIBIT D-4 APPLICATION TO THE VPSB Filing with the Vermont Public Service Board [DOWNS RACHLIN & MARTIN PLLC] July 12, 1999 VIA FEDERAL EXPRESS Mrs. Susan M. Hudson, Clerk Vermont Public Service Board 112 State Street Drawer 20 Montpelier, VT 05620-2701 Re: Petition of New England Power Company Dear Mrs. Hudson: Enclosed for filing on behalf of New England Power Company ("New England Power") are one original and six copies of each of the following: 1. Petition of New England Power; 2. Prefiled Testimony of Jennifer K. Zschokke, with Exhibits. New England Power requests consent to merge with Montaup Electric Company, pursuant to 30 V.S.A. s. 109. Also attached are the Notice of Appearance of Downs Rachlin & Martin PLLC on behalf of New England Power, Statement of Notice Required and form of notice, and a Certificate of Service. Copies of this filing have been provided to James Volz, Dr. William Steinhurst, and Thomas Dunn at the Department of Public Service. [DOWNS RACHLIN & MARTIN PLLC] Mrs. Susan M. Hudson -2- July 12, 1999 Kindly acknowledge receipt of this filing by date stamping the duplicate copy of this letter provided for this purpose, and returning it to me in the enclosed stamped envelope. Thank you for your assistance in this matter. Very truly yours, DOWNS RACHLIN & MARTIN PLLC Attorneys for New England Power Company By: /s/ Nancy S. Malmquist --------------------------- Nancy S. Malmquist Enclosures cc: Thomas G. Robinson, Esq. Carlos A. Gavilondo, Esq. APPEARANCE STATE OF VERMONT PUBLIC SERVICE BOARD Petition of New England Power Company ) pursuant to 30 V.S.A. s.109, to merge with ) Docket No. __________ Montaup Electric Company ) APPEARANCE Downs Rachlin & Martin PLLC, appears for the petitioner, New England Power Company. Provide copies of all filings in this docket to: Nancy S. Malmquist, Esq. Downs Rachlin & Martin PLLC 90 Prospect Street P.O. Box 99 St. Johnsbury, VT 05819-0099 and to Carlos A. Gavilondo, Esq. Thomas G. Robinson, Esq. New England Power Company 25 Research Drive Westborough, MA 01582-0099 St. Johnsbury, Vermont. July 12, 1999. Respectfully submitted, DOWNS RACHLIN & MARTIN PLLC Attorneys for New England Power Company By: /s/ Nancy S. Malmquist ----------------------------------- Nancy S. Malmquist 2 STATEMENT OF NOTICE REQUIRED STATE OF VERMONT PUBLIC SERVICE BOARD Petition of New England Power Company ) pursuant to 30 V.S.A. s.109, to merge with ) Docket No. __________ Montaup Electric Company ) STATEMENT OF NOTICE REQUIRED The petitioner, New England Power Company, hereby states that notice of the above-captioned petition is required, pursuant to Subsection 109 of Title 30, Vermont Statutes Annotated, to the Department of Public Service, and to such other persons as the Board directs. Exhibit A is a proposed form of notice to the public, if required. St. Johnsbury, Vermont. July 12, 1999 DOWNS RACHLIN & MARTIN PLLC Attorneys for New England Power Company By: /s/ Nancy S. Malmquist ----------------------------------- Nancy S. Malmquist STATE OF VERMONT PUBLIC SERVICE BOARD Take notice that, on July 13, 1999, New England Power Company, a company qualified to transact business in Vermont as a foreign corporation, petitioned the Vermont Public Service Board, pursuant to 30 V.S.A. s. 109, for consent to merge with Montaup Electric Company. Take notice further that the Public Service Board will hold a hearing on this petition at ___________________ in ______________________ on __________, 1999, at _____________. Any person wishing to intervene in this proceeding should give written notice thereof to the Board by July 30, 1999. Any questions or filings concerning this petition should be made to: Mrs. Susan M. Hudson, Clerk Vermont Public Service Board 112 State Street Drawer 20 Montpelier, VT 05620-2701 CERTIFICATE OF SERVICE STATE OF VERMONT PUBLIC SERVICE BOARD Petition of New England Power Company ) pursuant to 30 V.S.A. s. 109, to ) Docket No. __________ merge with Montaup Electric Company ) CERTIFICATE OF SERVICE Downs Rachlin & Martin PLLC, certifies that it has provided three copies of the above-captioned petition, including its appearance, a statement of notice required, this certificate and related prefiled testimony and exhibits, to the Vermont Department of Public Service, by first-class mail, postage prepaid, with one copy provided to the Department's Director of Public Advocacy, one copy to the Department's Director of Utility Planning, Dr. William Steinhurst, and one copy to the Department's Chief Engineer, Thomas Dunn. St. Johnsbury, Vermont. July 12, 1999 DOWNS RACHLIN & MARTIN PLLC Attorneys for New England Power Company By: /s/ Nancy S. Malmquist ----------------------------------- Nancy S. Malmquist STATE OF VERMONT PUBLIC SERVICE BOARD Petition of New England Power Company, ) pursuant to 30 V.S.A. s. 109, to ) Docket No. __________ merge with Montaup Electric Company ) PETITION This is a petition by New England Power Company (herein "NEP"). I. By this petition, NEP represents that: 1. NEP is a Massachusetts corporation that owns and operates properties in Massachusetts, New Hampshire, Connecticut, Maine and Vermont, including transmission lines, and is a transmission subsidiary of New England Electric System ("NEES"); NEP owns properties in several Vermont communities used primarily for the transmission of electricity; 2. NEP has qualified to transact business in Vermont as a foreign corporation but does not engage in local distribution of electricity therein; 3. NEES is a registered holding company under the Public Utility Holding Company Act of 1935 ("Holding Company Act") and owns the common equity of several electric utility companies, including NEP, Narragansett Electric Company ("Narragansett"), Massachusetts Electric Company ("Mass Electric"), Nantucket Electric Company, and Granite State Electric Company; 4. Eastern Utilities Associates ("EUA") is a registered holding company under the Holding Company Act and owns directly or indirectly the common equity of several electric utility companies, including Montaup Electric Company ("Montaup"), Blackstone Valley Electric Company ("BVE"), Newport Electric Corporation ("Newport"), and Eastern Edison Company ("Eastern"); 5. On February 1, 1999, NEES, EUA, and Research Drive LLC ("Research Drive"), a directly and indirectly wholly-owned subsidiary of NEES, entered into an Agreement and Plan of Merger ("EUA Agreement"), pursuant to which EUA will become a wholly-owned subsidiary of NEES; 6. As soon as practicable after the closing of the merger transaction with EUA, NEES intends to merge the operating companies of EUA (none of which operate in Vermont) with and into the operating companies of NEES. NEES intends to merge Montaup with and into NEP, pursuant to which NEP will be the surviving entity (and will continue to be wholly-owned by NEES). Similarly, NEES intends to merge Eastern into Mass Electric, and BVE and Newport with and into Narragansett. 7. Following the merger of Montaup into NEP, NEP will remain a separate corporation wholly owned by NEES and will continue to own and conduct a public service business subject to the jurisdiction of the Board; 8. The proposed merger of Montaup with and into NEP requires a finding of general good and the issuance of a certificate of consent by the Board pursuant to 30 V.S.A. s.109; and 9. The proposed merger of Montaup with and into NEP will promote the general good of Vermont and will not result in obstructing of preventing competition. -2- II. In support of this petition, NEP prefiles testimony and supporting exhibits by the following witness: Witness Subject Matter Jennifer K. Zschokke Overview; description of merger transaction; general good promoted by merger of Montaup with and into NEP. III. NEP requests that the Board: A. Appoint a Hearing Officer to hear, schedule a prehearing conference for, and issue notice of the opportunity for hearing on this petition, in accordance with 30 V.S.A. s.109; B. Find that the merger of Montaup with and into NEP will promote the general good of the State of Vermont and issue a certificate of consent therefor; C. Find that the merger of Montaup with and into NEP will not result in obstructing or preventing competition in the purchase or sale of any product, service or commodity, in the sale, purchase or manufacture of which Montaup and NEP are engaged; and D. Take such other measures as in the Board's judgment are necessary for a full and expeditious resolution of this petition. Respectfully submitted, NEW ENGLAND POWER COMPANY By: Downs Rachlin & Martin PLLC Attorneys for New England Power Company By: /s/ Nancy S. Malmquist ---------------------------------------- Nancy S. Malmquist Date: July 12, 1999 -3- STATE OF VERMONT PUBLIC SERVICE BOARD - ---------------------------------------- ) In Re: New England Power Company ) ) Docket No. _____ Petition For Approval of Merger with ) Montaup Electric Company ) - ---------------------------------------- TESTIMONY OF JENNIFER K. ZSCHOKKE STATE OF VERMONT PUBLIC SERVICE BOARD - ---------------------------------------- ) In Re: New England Power Company ) ) Docket No. _____ Petition For Approval of Merger with ) Montaup Electric Company ) - ---------------------------------------- TESTIMONY OF JENNIFER K. ZSCHOKKE Table of Contents Page I. Qualifications.................................................... 1 II. Purpose of Filing................................................. 1 III. Description of the Transactions................................... 3 VI. Benefits Created by the Merger.................................... 6
Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 1 of 11 1 I. Qualifications. 2 Q. Please state your name, title, and business address. 3 A. My name is Jennifer K. Zschokke. I am Manager of Finance for New England Power 4 Service Company (NEPSCO), a New England Electric System (NEES) Company. My 5 business address is 25 Research Drive, Westborough, MA 01582. 6 7 Q. Please describe your educational background and training. 8 A. I have earned a Bachelor of Arts degree in Management Science from Westminster 9 College and a Masters of Science in Finance from Boston College. 10 11 Q. Please describe your professional experience. 12 A. I joined NEPSCO in 1987 as an assistant financial analyst and have been promoted several 13 times within the Finance Department, most recently to Manager in 1998. My 14 responsibilities include the long and short-term financing of NEES and its subsidiaries. In 15 addition, the Finance Department provides a variety of financial advisory services to other 16 functions in the NEES System. 17 18 II. Purpose of Filing. 19 Q. What is the purpose of this filing? Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 2 of 11 1 A. On February 1, 1999, NEES, Eastern Utilities Associates ("EUA"), and Research Drive 2 LLC ("Research Drive"), a directly and indirectly wholly owned subsidiary of NEES 3 entered into an Agreement and Plan of Merger ("EUA Agreement"), through which EUA 4 will become a wholly owned subsidiary of NEES. Upon the closing of the EUA 5 transaction, it is NEES's intention to consolidate and merge New England Power 6 Company ("NEP") with Montaup Electric Company ("Montaup") (together, the 7 "Companies"). This filing requests the Vermont Public Service Board (the "Board") to 8 approve the merger of NEP and Montaup. 9 10 Q. Please describe the entities and transactions that relate to this filing? 11 A. NEES is a registered holding company under the Public Utility Holding Company Act of 12 1935 ("Holding Company Act") and owns the common equity of several electric utility 13 companies, including NEP, Narragansett, Massachusetts Electric Company, Nantucket 14 Electric Company, and Granite State Electric Company. 15 EUA also is a registered holding company under the Holding Company Act and 16 owns directly or indirectly the common equity of several electric utility companies, 17 including Montaup, Blackstone Valley Electric Company ("BVE"), Newport Electric 18 Corporation ("Newport"), and Eastern Edison Company ("Eastern Edison" or "Eastern"). 19 Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 3 of 11 1 Q. What issues will your testimony address? 2 A. I will briefly describe both the merger of the parent companies and the merger of NEP and 3 Montaup. I also will describe the benefits of the mergers in support of the Companies' 4 Petition for approval of the merger of Montaup into NEP. 5 6 III. Description of the Transactions. 7 Q. Ms. Zschokke, would you please describe the parent company merger between NEES and 8 EUA? 9 A. The transaction is set forth in the EUA Agreement included as Exhibit JKZ-1. Pursuant to 10 the EUA Agreement, Research Drive will merge with and into EUA with EUA becoming 11 a wholly owned subsidiary of NEES. The merger agreement contains terms and 12 conditions which are typical to a merger transaction. Closing of the NEES-EUA merger 13 has been approved by EUA shareholders and is subject to obtaining required regulatory 14 approvals. The NEES-EUA merger does not, however, require this Board's approval. 15 16 Q. Please describe the merger of the underlying operating companies? 17 A. As soon as practicable after the parent company merger, NEES intends to merge the 18 operating companies of EUA with the operating companies of NEES. As shown on 19 Exhibit JKZ-2, Montaup will merge into NEP. In Massachusetts, Eastern Edison will 20 merge with and into Massachusetts Electric Company ("Mass. Electric"), and in Rhode Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 4 of 11 1 Island, BVE and Newport will merge with and into Narragansett, with Narragansett being 2 the sole surviving entity. Because NEP is a Vermont utility, the merger of Montaup with 3 and into NEP requires approval by the Board. 4 5 Q. Please describe where NEP and Montaup fit into the organizational structure of the NEES 6 and EUA systems, respectively. 7 A. NEP is a direct subsidiary of NEES. This means that NEES owns 100% of the common 8 stock of NEP. Montaup is an indirect subsidiary of EUA and 100% of its common equity 9 is owned by Eastern. However, Eastern is contemplating a spin off of 100% of its 10 ownership of the common stock of Montaup to EUA prior to the NEES's acquisition of 11 EUA. The spinoff of Montaup by Eastern would i) complete the functional unbundling of 12 the generation business from the distribution business through the complete corporate 13 separation of Eastern and Montaup, ii) eliminate any risk that Eastern may have associated 14 with its direct ownership of Montaup pertaining to, for example, contingent liabilities and 15 nuclear ownership, iii) isolate Eastern's capital structure so that it applies to distribution 16 ratemaking only, and iv) simplify EUA's corporate structure. Following the spinoff, 17 Montaup will be a direct subsidiary of EUA, just as NEP is a direct subsidiary of NEES. 18 NEP operates in several states, which include Massachusetts, Rhode Island, New 19 Hampshire, and Vermont. Montaup operates in Massachusetts and Rhode Island. Both 20 NEP and Montaup have minority interests in nuclear properties in Connecticut, Maine, Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 5 of 11 1 New Hampshire and Vermont as well as a fossil unit in Maine. Since the divestiture of 2 substantially all of its generating business in 1998, NEP is primarily a transmission 3 company. Montaup recently completed the sale of the Canal, Somerset, and Wyman 4 4 generating stations. Therefore, Montaup is primarily a transmission company going 5 forward similar to NEP. 6 In addition, NEP and Montaup each recover through FERC-approved, wholesale 7 Contract Termination Charges (CTC's), stranded costs associated with prior investments 8 in the generating business. NEP and Montaup collect CTC's from affiliated and 9 nonaffiliated customers. 10 11 Q. Please describe the balance sheets of NEP and Montaup? 12 A. Please see Exhibit JKZ-3 and JKZ-4, respectively. At year end 1998, NEP's balance sheet 13 was approximately four times the size of Montaup's. NEP's assets and liabilities totaled 14 $2.415 billion and Montaup's assets and liabilities totaled $641 million. As of year end, 15 NEP owned $458 million of net utility plant, most of which is transmission and Montaup 16 owned about $341 million of net utility plant, which still included the Somerset units 17 subsequently sold on April 27, 1999. Both NEP and Montaup have significant regulatory 18 assets which represent the future collection of Contract Termination Charges. As for 19 capital structure, NEP and Montaup have similar capitalization ratios as of year end 1998. 20 Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 6 of 11 1 Q. What are the financial transactions necessary to implement the consolidation of Montaup 2 and NEP? 3 A. Montaup will merge with and into NEP, and their balance sheets will be consolidated. We 4 are assuming as part of this transaction, NEP will use its cash on hand to pay off 5 Montaup's debentures and preferred stock currently held by Eastern. In addition, $147 6 million of common equity is expected to be repaid to the direct parent of Montaup. 7 8 Q. Have you prepared pro forma financial statements for the merger of NEP and Montaup? 9 A. Yes. Exhibit JKZ-5 illustrates the impact of the merger of Montaup and NEP, and the 10 repayment by Montaup of its debt and preferred stock. As permitted by accounting rules, 11 the balance sheet of the combined entity will reflect the sum of the balance sheets of the 12 separate entities prior to the subsidiary merger. 13 14 VI. Benefits Created by the Merger. 15 Q. Would you summarize the benefits created through the merger of NEP and Montaup? 16 A. In considering the benefits of the NEP-Montaup merger, it is important to consider that 17 such merger arises out of and directly relates to the merger occurring at the parent 18 company level. The two mergers, taken together, will result in the creation of substantial 19 benefits which can be used to provide improved service at lower cost to customers. 20 Specifically, the mergers produce synergies which are typical of utility combinations. Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 7 of 11 1 These synergies build on efficiencies already achieved by the Companies, which are 2 already among the lowest cost utilities in New England. 3 4 Q. How will the cost savings you described be achieved? 5 A. The cost savings will come from a variety of categories. Approximately 70 percent of the 6 savings will come from eliminating approximately 250 positions from the combined 7 NEES-EUA organization. These reductions come from across the organization. 8 Administrative areas such as accounting and finance, where significant redundancies exist 9 between the two organizations, will be reduced. EUA's and NEES' customer service 10 operations will be integrated to handle increased volumes at a lower unit cost. The unit 11 cost of field operations will also be reduced through standardization and mutual support. 12 The remainder of the operating savings will come from disposing of duplicate facilities, 13 realizing greater purchasing power, and eliminating redundant administrative costs, such 14 as corporate governance expense. The cost savings achieved by the mergers ultimately 15 will be shared with customers through lower and more stable rates. 16 17 Q. Are there any other areas of cost savings or efficiencies created by the mergers? 18 A. Yes. Most utility mergers include as savings the costs of building one rather than two sets 19 of new information systems (usually customer or financial) at some time in the future. 20 Both NEES and EUA have older customer information systems. The cost of replacing Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 8 of 11 1 these systems would currently be in excess of $10 million per company. When combined, 2 the costs are cut in half. Although it is difficult to pinpoint the timeframe in which the 3 savings will occur, the savings are real and will provide future benefits. 4 In addition, we expect the higher credit ratings of the NEES companies to lead to 5 financing savings as the debt of the EUA companies is refinanced over time. 6 7 Q. Are there any benefits that are directly produced for NEP's transmission customers? 8 A. Yes. As the result of the merger, NEP's transmission rates to NEP's existing open-access 9 transmission customers will be reduced. First, because Montaup's transmission rates are 10 on average lower than NEP's, the combination of the two Companies will lower NEP's 11 FERC-filed, open access transmission rates. Secondly, the efficiency gains discussed above 12 will automatically flow to NEP's open access, transmission customers through NEP cost 13 of service formula transmission rate. Both factors will produce savings for NEP's 14 transmission customers following the merger. 15 16 Q. Will the merger prevent or obstruct competition in Vermont? 17 A. No. Other than its minority share in Vermont Yankee, Montaup owns no facilities and no 18 business in Vermont. As a result, the merger will have no affect on the power markets in 19 this state. In addition, both NEP and Montaup have divested substantially all of their non- 20 nuclear generating entitlements and have focused instead on the transmission business Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 9 of 11 1 which remains regulated by FERC. The transaction has passed the Hart-Scott-Rodino 2 screen for adverse effects on competition. Finally, the Companies have filed a competitive 3 analysis with FERC as part of their application under s. 203 of the Federal Power Act that 4 demonstrates that the merger will not have an adverse effect on competition in the New 5 England market. See Affidavit of Henry Kahwaty in FERC Docket EC99-70-000. As a 6 result, we do not believe that the merger of NEP and Montaup will prevent or obstruct 7 competition in Vermont. 8 9 Q. What will the impact be on employees from the mergers? 10 A. Although the merger of the two organizations is expected to reduce employment by about 11 250 positions in the combined companies in Massachusetts and Rhode Island, we believe 12 that these employee reductions can be achieved predominantly through attrition or 13 voluntary early retirement and without significant involuntary layoffs. 14 15 Q. Are NEES and EUA taking steps to mitigate the loss of positions following the NEES- 16 EUA merger? 17 A. Yes. In anticipation of the merger's approval, we have placed a limitation on hiring for 18 our company. The NEES companies expect to have a significant number of vacant 19 positions by the time the transaction closes. Natural attrition at EUA is expected to add 20 more positions. We are making every effort to leave these positions vacant until Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 10 of 11 1 employees affected by the acquisition have an opportunity to be considered for a position. 2 Beyond vacancies and attrition, we can economically offer 200 to 250 NEES and EUA 3 employees a voluntary early retirement program. Through these measures, we expect to 4 meet our workforce reduction targets without having a significant impact on individual 5 employees. 6 NEES has also agreed in the merger agreement to honor EUA's collective 7 bargaining agreements and to provide non-union employees joining the NEES companies 8 with compensation and benefits in the aggregate at least equivalent to those obtained prior 9 to the merger for a year following closing. EUA employees joining the NEES system will 10 find that the compensation and benefit philosophies of the two companies are very similar, 11 allowing us to merge benefit plans without significant disruption to employees. 12 13 Q. Are other regulatory approvals required to consummate the merger? Yes. The NEES 14 acquisition of EUA and the merger of the operating companies are being filed together in 15 several jurisdictions. Approvals have been or are being requested from the Federal Energy 16 Regulatory Commission and the Securities and Exchange Commission at the federal level, 17 and from state commissions in Massachusetts, Rhode Island, and Connecticut. An 18 approval may also be required from New Hampshire if a transfer of Montaup's share of 19 Seabrook to NEP is necessary. 20 Petition of New England Power Company Vermont Public Service Board Testimony of J. K. Zschokke Page 11 of 11 1 Q. Please summarize why you believe the merger of Montaup into NEP will promote the 2 general good of the State of Vermont and is in the public interest. 3 A. The merger will bring cost savings to NEP's transmission customers, produce efficiency 4 gains, and improve the ability of the Companies to provide reliable service to customers. 5 For all of these reasons, the merger meets the statutory requirements for approval by the 6 Board. Specifically, the merger (i) is consistent with the public interest, (ii) will not 7 diminish the facilities of the Companies used for furnishing service to the public, and (iii) 8 will not prevent or obstruct competition in Vermont. In fact, the merger will improve the 9 Companies' ability to provide service. 10 11 Q. Does this complete your testimony? 12 A. Yes.
AGREEMENT AND PLAN OF MERGER and CONSENT AGREEMENT dated as of February 1, 1999 TABLE OF CONTENTS AGREEMENT AND PLAN OF MERGER...................................................1 CONSENT AGREEMENT..............................................................2 Tab 1 AGREEMENT AND PLAN OF MERGER dated as of February 1, 1999 by and among NEW ENGLAND ELECTRIC SYSTEM, RESEARCH DRIVE LLC and EASTERN UTILITIES ASSOCIATES TABLE OF CONTENTS Page No. ARTICLE I THE MERGER......................................................... 1 1.01 The Merger......................................................... 1 1.02 Effective Time..................................................... 1 1.03 Effects of the Merger.............................................. 2 ARTICLE II CONVERSION OF SHARES............................................... 2 2.01 Conversion of Capital Stock........................................ 2 2.02 Surrender of Shares................................................ 3 2.03 Withholding Rights................................................. 4 ARTICLE III THE CLOSING........................................................ 4 ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EUA.............................. 5 4.01 Organization and Qualification..................................... 5 4.02 Capital Stock...................................................... 6 4.03 Authority.......................................................... 7 4.04 Non-Contravention; Approvals and Consents.......................... 7 4.05 SEC Reports, Financial Statements and Utility Reports.............. 8 4.06 Absence of Certain Changes or Events............................... 9 4.07 Legal Proceedings.................................................. 9 4.08 Information Supplied............................................... 9 4.09 Compliance......................................................... 10 4.10 Taxes.............................................................. 10 4.11 Employee Benefit Plans; ERISA...................................... 12 4.12 Labor Matters...................................................... 14 4.13 Environmental Matters.............................................. 15 4.14 Regulation as a Utility............................................ 17 4.15 Insurance.......................................................... 17 4.16 Nuclear Facilities................................................. 18 4.17 Vote Required...................................................... 18 4.18 Opinion of Financial Advisor....................................... 18 -i- Page No. 4.19 Ownership of NEES Common Shares.................................... 18 4.20 State Anti-Takeover Statutes....................................... 18 4.21 Year 2000.......................................................... 19 4.22 EUA Associates..................................................... 19 ARTICLE V REPRESENTATIONS AND WARRANTIES OF NEES............................. 19 5.01 Organization and Qualification..................................... 19 5.02 Authority.......................................................... 20 5.03 Capital Stock...................................................... 20 5.04 Non-Contravention; Approvals and Consents.......................... 20 5.05 Information Supplied............................................... 21 5.06 Compliance......................................................... 21 5.07 Financing.......................................................... 22 5.08 No Vote Required................................................... 22 5.09 Ownership of EUA Shares............................................ 22 5.10 Merger with The National Grid Group plc............................ 22 ARTICLE VI COVENANTS................................................ 22 6.01 Covenants of EUA................................................... 22 6.02 Covenants of NEES.................................................. 28 6.03 Additional Covenants by NEES and EUA............................... 29 ARTICLE VII ADDITIONAL AGREEMENTS.................................... 30 7.01 Access to Information.............................................. 30 7.02 Proxy Statement.................................................... 31 7.03 Approval of Shareholders........................................... 31 7.04 Regulatory and Other Approvals..................................... 31 7.05 Employee Benefit Plans............................................. 32 7.06 Labor Agreements and Workforce Matters............................. 34 7.07 Post Merger Operations............................................. 34 7.08 No Solicitations................................................... 35 7.09 Directors' and Officers' Indemnification and Insurance............. 36 7.10 Expenses........................................................... 37 7.11 Brokers or Finders................................................. 37 7.12 Anti-Takeover Statutes............................................. 38 7.13 Public Announcements............................................... 38 -ii- Page No. 7.14 Restructuring of the Merger........................................ 38 ARTICLE VIII CONDITIONS......................................................... 39 8.01 Conditions to Each Party's Obligation to Effect the Merger......... 39 8.02 Conditions to Obligation of NEES and LLC to Effect the Merger...... 39 8.03 Conditions to Obligation of EUA to Effect the Merger............... 40 ARTICLE IX TERMINATION, AMENDMENT AND WAIVER.................................. 41 9.01 Termination........................................................ 41 9.02 Effect of Termination.............................................. 43 9.03 Termination Fees................................................... 43 9.04 Amendment.......................................................... 44 9.05 Waiver............................................................. 44 ARTICLE X GENERAL PROVISIONS................................................. 44 10.01 Non-Survival of Representations, Warranties, Covenants and Agreements......................................................... 44 10.02 Notices............................................................ 44 10.03 Entire Agreement; Incorporation of Exhibits........................ 46 10.04 No Third Party Beneficiary......................................... 46 10.05 No Assignment; Binding Effect...................................... 46 10.06 Headings........................................................... 47 10.07 Invalid Provisions................................................. 47 10.08 Governing Law...................................................... 47 10.09 Enforcement of Agreement........................................... 47 10.10 Certain Definitions................................................ 47 10.11 Counterparts....................................................... 48 10.12 WAIVER OF JURY TRIAL............................................... 48 -iii- GLOSSARY OF DEFINED TERMS The following terms, when used in this Agreement, have the meanings ascribed to them in the corresponding Sections of this Agreement listed below: "1935 Act" -- Section 4.05(b) "Adjustment Date" -- Section 2.01(c) "Affected Employees" -- Section 7.05(a) "affiliate" -- Section 10.11(a) "Agreement" -- Preamble "Alternative Proposal" -- Section 7.08 "beneficially" -- Section 10.10(b) "business day" -- Section 10.10(c) "Canceled Shares" -- Section 2.02(b) "Certificates" -- Section 2.02(b) "Closing" -- Article III "Closing Agreement" -- Section 4.10(j) "Closing Date" -- Article III "Code" -- Section 2.03 "Confidentiality Agreement" -- Section 7.01 "Constituent Entities" -- Section 1.01 "Contracts" -- Section 4.04(a) "control," "controlling," "controlled by" and "under common control with" -- Section 10.10(a) "DOE" -- Section 4.05(b) "Effective Time" -- Section 1.02 "Environmental Claim" -- Section 4.13(f)(i) "Environmental Laws" -- Section 4.13(f)(ii) "Environmental Permits" -- Section 4.13(b) "ERISA" -- Section 4.11(a) "ERISA Affiliate" -- Section 4.11(c) "EUA" -- Preamble "EUA Associates" -- Section 4.01(b) "EUA Employee Agreements" -- Section 7.05(d)(ii) "EUA Executives" -- Section 7.05(d)(ii) "EUA Shares" -- Preamble "EUA Disclosure Letter" -- Section 4.01(a) "EUA Employee Benefit Plans" -- Section 4.11(a) "EUA Financial Statements" -- Section 4.05(a) "EUA Nuclear Facilities" -- Section 4.16 "EUA Material Adverse Effect" -- Section 4.01(a) "EUA Required Consents" -- Section 4.04(a) "EUA Required Statutory Approvals" -- Section 4.04(b) "EUA SEC Reports" -- Section 4.05(a) -iv- "EUA Shareholders' Approval" -- Section 7.03 "EUA Shareholders' Meeting" -- Section 7.03 "EUA Significant Subsidiary" -- Section 7.08 "EUA Shares" -- Preamble "EUA Trust Agreement" -- Section 1.03 "EUA Voting Debt -- Section 4.02(d) "Evaluation Material" -- Section 7.01(a) "Exchange Act" -- Section 4.05(a) "Exchange Fund" -- Section 2.02(a) "Extended Termination Date" -- Section 9.01(b) "FCC" -- Section 4.05(b) "FERC" -- Section 4.05(b) "Final Order" -- Section 8.01(d) "Governmental Authority" -- Section 4.04(a) "Hazardous Materials" -- Section 4.13(f)(iii) "HSR Act" -- Section 7.04(a) "Indemnified Liabilities" -- Section 7.09(a) "Indemnified Party" -- Section 7.09(a) "Indemnified Parties" -- Section 7.09(a) "Information Systems" -- Section 4.21 "Initial Termination Date" -- Section 9.01(b) "IRS" -- Section 4.10(m) "knowledge" -- Section 10.11(d) "laws" -- Section 4.04(a) "Lien" -- Section 4.02(b) "LLC" -- Preamble "Massachusetts Secretary" -- Section 1.02 "Merger" -- Preamble "Merger Consideration" -- Section 2.01(b)(ii) "MGL" -- Section 1.01 "National Grid Group" -- Section 5.10 "National Grid Merger Agreement" -- Section 5.10 "NEES" -- Preamble "NEES Disclosure Letter" -- Section 5.03 "NEES Material Adverse Effect" -- Section 5.01 "NEES-EUA Regulatory Approvals" -- Section 7.04(b) "NEES-EUA Regulatory Proceedings" -- Section 7.04(c) "NEES Required Consents" -- Section 5.04(a) "NEES Required Statutory Approvals" -- Section 5.04(b) "NEES-NGG Regulatory Approvals" -- Section 7.04(c) "NEES-NGG Regulatory Proceedings" -- Section 7.04(c) "NEES-NGG Required Statutory Approvals"-- Section 7.04 "NEES-NGG Transactions" -- Section 7.04 "NEES Shares" -- Section 5.03 -v- "NEES Trust Agreement" -- Section 5.01 "NGG Circular" -- Section 7.02 "NRC" -- Section 4.05(b) "Options" -- Section 4.02(a) "orders" -- Section 4.04(a) "Out-of-Pocket Expenses" -- Section 9.03(a) "Paying Agent" -- Section 2.02(a) "PBGC" -- Section 4.11(g) "person" -- Section 10.11(e) "Per Share Amount" -- Section 2.01(b)(ii) "Post Closing Plans" -- Section 7.05(b) "Proxy Statement" -- Section 4.08(a) "Release" -- Section 4.13(f)(iv) "Representatives" -- Section 10.11(f) "SEC" -- Section 4.05(a) "Securities Act" -- Section 4.05(a) "Subsidiary" -- Section 10.11(g) "Surviving Entity" -- Section 1.01 "Tax Ruling" -- Section 4.10(j) "Taxes" -- Section 4.10 "Tax Return" -- Section 4.10 "US GAAP" -- Section 4.05(a) "Yankee Companies" -- Section 4.16 "Y2K Consultant" -- Section 6.01(o) -vi- This AGREEMENT AND PLAN OF MERGER, dated as of February 1, 1999 (this "Agreement"), is made and entered into by and among NEW ENGLAND ELECTRIC SYSTEM, a Massachusetts business trust ("NEES"), RESEARCH DRIVE LLC ("LLC"), a Massachusetts limited liability company which is directly and indirectly wholly owned by NEES, and EASTERN UTILITIES ASSOCIATES, a Massachusetts business trust ("EUA"). WHEREAS, the Board of Directors of NEES, the Board of Trustees of EUA and the members of LLC have each determined that it is advisable and in the best interests of their respective shareholders and members to consummate, and have approved, the business combination transaction provided for herein in which LLC would merge with and into EUA, with EUA being the surviving entity (the "Merger"), pursuant to the terms and conditions of this Agreement, as a result of which NEES will own, directly or indirectly, all of the issued and outstanding common shares of EUA (the "EUA Shares"); WHEREAS, NEES, LLC and EUA desire to make certain representations, warranties and agreements in connection with the Merger and also to prescribe various conditions to the Merger; NOW, THEREFORE, in consideration of the mutual covenants and agreements set forth in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows: ARTICLE I THE MERGER 1.01 The Merger. Upon the terms and subject to the conditions of this Agreement, at the Effective Time (as defined in Section 1.02), LLC shall be merged with and into EUA in accordance with Section 2 of Chapter 182 and Section 59 of Chapter 156C of the Massachusetts General Laws ("MGL"). At the Effective Time, the separate existence of LLC shall cease and EUA shall continue as the surviving entity in the Merger. EUA, after the Effective Time, is sometimes referred to herein as the "Surviving Entity" and EUA and LLC are sometimes referred to herein as the "Constituent Entities". The effect and consequences of the Merger shall be as set forth in Article II. 1.02 Effective Time. Subject to the provisions of this Agreement, on the Closing Date (as defined in Article III), a certificate of merger shall be executed and filed by EUA and LLC with the Secretary of the Commonwealth of Massachusetts (the "Massachusetts Secretary"). The Merger shall become effective at the time of the filing of the certificate of merger relating to the Merger with the Massachusetts Secretary, or at such later time as is specified in the certificate of merger (such date and time being referred to herein as the "Effective Time"). 1.03 Effects of the Merger. At the Effective Time, the Agreement and Declaration of Trust of EUA (the "EUA Trust Agreement") as in effect immediately prior to the Effective Time shall be the agreement and declaration of trust of the Surviving Entity, until thereafter amended as provided by law and such agreement and declaration of trust. Subject to the foregoing, the additional effects of the Merger shall be as provided in the applicable provisions of Section 2 of Chapter 182 of the MGL and Section 62 of the Limited Liability Company Act of Massachusetts. ARTICLE II CONVERSION OF SHARES 2.01 Conversion of Capital Stock. At the Effective Time, by virtue of the Merger and without any action on the part of the holder thereof: (a) Membership Interests of LLC. Each one percent of the issued and outstanding membership interests in LLC shall be converted into one transferable certificate of participation or share of the Surviving Entity. (b) Conversion of EUA Shares. (i) Cancellation of Treasury Shares and Shares Owned by NEES and Subsidiaries. All EUA Shares that are owned by EUA as treasury shares and any EUA Shares owned by NEES or any other wholly owned Subsidiary (as defined in Section 10.11) of NEES shall be canceled and retired and shall cease to exist and no cash or other consideration shall be delivered in exchange therefor. (ii) Conversion of EUA Shares. Each EUA Share issued and outstanding immediately prior to the Effective Time (other than shares to be canceled in accordance with Section 2.01(b)(i)) shall be canceled and converted in accordance with the provisions of this Section 2.01 into the right to receive cash in the amount (the "Per Share Amount") of $31.00 as such amount may hereafter be adjusted in accordance with Section 2.01(c) hereof (the "Merger Consideration"), payable, without interest, to the holder of such EUA Share, upon surrender, in the manner provided in Section 2.02 hereof, of the certificate formerly evidencing such share. (c) Adjustment in Amount of Merger Consideration. In the event that the Closing Date shall not have occurred on or prior to the date that is the six (6) month anniversary of the date on which EUA Shareholders' Approval is obtained (the "Adjustment Date"), the Per Share Amount shall be increased, for each day after the Adjustment Date up to and including the day which is one day prior to the earlier of the Closing Date and the Extended Termination Date, by an amount equal to $0.003. -2- 2.02 Surrender of Shares. (a) Deposit with Paying Agent. Prior to the Effective Time, NEES shall designate a bank or trust company reasonably acceptable to EUA to act as agent (the "Paying Agent") for the benefit of the holders of EUA Shares in connection with the Merger to receive the funds to which holders of EUA Shares shall become entitled pursuant to Section 2.01(b)(ii) (the "Exchange Fund"). From time to time at, immediately prior to or after the Effective Time, NEES or LLC shall make or cause to be made available to the Paying Agent immediately available funds in amounts and at the times necessary for the payment of the Merger Consideration upon surrender of Certificates (as defined in Section 2.02(b)) in accordance with Section 2.02(b), it being understood that any and all interest or other income earned on funds made available to the Paying Agent pursuant to this Section 2.02(a) shall belong to and shall be paid (at the time provided for in Section 2.02(e)) as directed by NEES or LLC. Any such funds deposited with the Paying Agent by NEES shall be invested by the Paying Agent as directed by NEES or LLC. (b) Exchange Procedure. As soon as practicable after the Effective Time, the Paying Agent shall mail to each holder of record of a certificate or certificates (the "Certificates") which immediately prior to the Effective Time represented outstanding EUA Shares (the "Canceled Shares") that were canceled and became instead the right to receive the Merger Consideration pursuant to Section 2.01(b)(ii): (i) a letter of transmittal in such form as NEES and EUA may reasonably agree (which shall specify that delivery shall be effected, and risk of loss and title to the Certificates shall pass, only upon actual delivery of the Certificates to the Paying Agent) and (ii) instructions for effecting the surrender of the Certificates in exchange for the Merger Consideration. Upon surrender of a Certificate or Certificates to the Paying Agent for cancellation (or to such other agent or agents as may be appointed by NEES and are reasonably acceptable to EUA), together with a duly executed letter of transmittal and such other documents as the Paying Agent shall require, the holder of such Certificate shall be entitled to receive the Merger Consideration in exchange for each EUA Share formerly evidenced by such Certificate which such holder has the right to receive pursuant to Section 2.01(b)(ii). In the event of a transfer of ownership of Canceled Shares which is not registered in the transfer records of EUA, the Merger Consideration in respect of such Canceled Shares may be given to the transferee thereof if the Certificate or Certificates representing such Canceled Shares is presented to the Paying Agent, accompanied by all documents required to evidence and effect such transfer and by evidence satisfactory to the Paying Agent that any applicable stock transfer taxes have been paid. At any time after the Effective Time, each Certificate shall be deemed to represent only the right to receive the Merger Consideration subject to and upon the surrender of such Certificate as contemplated by this Section 2.02. No interest shall be paid or will accrue on the Merger Consideration payable to holders of Certificates pursuant to Section 2.01(b)(ii). (c) No Further Ownership Rights in EUA Shares. The Merger Consideration paid upon the surrender of Certificates in accordance with the terms of Section 2.01(b)(ii) shall be deemed to have been paid at the Effective Time in full satisfaction of all rights pertaining to EUA Shares represented thereby. From and after the Effective Time, the share transfer books of EUA shall be closed and there shall be no further registration of transfers thereon of EUA Shares which were outstanding immediately prior to the Effective Time. -3- If, after the Effective Time, Certificates are presented to NEES for any reason, they shall be canceled and exchanged as provided in this Section 2.02. (d) Lost, Stolen or Destroyed Certificates. In the event any owner of any Certificate shall claim that such Certificate shall have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the owner of such Certificate and delivery of that affidavit to the Paying Agent and, if required by NEES or LLC, the posting by such person of a bond in customary amount as indemnity against any claim that may be made against NEES, EUA or the Surviving Entity with respect to such Certificate, the Paying Agent will issue in exchange for such lost, stolen or destroyed Certificate the Merger Consideration payable upon due surrender of, and deliverable pursuant to this Section 2.02 in respect of, EUA Shares to which such Certificate relates. (e) Termination of Exchange Fund. Any portion of the Exchange Fund which remains undistributed to the shareholders of EUA for one (1) year after the Effective Time shall be delivered to the Surviving Entity, upon demand, and any Shareholders of EUA who have not theretofore complied with this Article II shall thereafter look only to the Surviving Entity (subject to abandoned property, escheat and other similar laws) as general creditors for payment of their claim for the Merger Consideration payable upon due surrender of the Certificates held by them. None of NEES, LLC or the Surviving Entity shall be liable to any former holder of EUA Shares for the Merger Consideration delivered to a public official pursuant to any applicable abandoned property, escheat or similar law. 2.03 Withholding Rights. Each of the Surviving Entity and NEES shall be entitled to deduct and withhold from the consideration otherwise payable pursuant to this Agreement to any holder of EUA Shares such amounts as it is required to deduct and withhold with respect to the making of such payment under the Internal Revenue Code of 1986, as amended (the "Code"), or any other provision of state, local or foreign tax law. To the extent that amounts are so withheld by the Surviving Entity or NEES, as the case may be, such withheld amounts shall be treated for all purposes of this Agreement as having been paid to the holder of EUA Shares in respect of which such deduction and withholding was made by the Surviving Entity or NEES, as the case may be. ARTICLE III THE CLOSING The closing of the Merger and other transactions contemplated hereby (the "Closing") will take place at the offices of Skadden, Arps, Slate, Meagher & Flom LLP, 919 Third Avenue, New York, New York 10022, at 10:00 a.m., local time, on the second business day following satisfaction or waiver (where applicable) of the conditions set forth in Article VIII (other than those conditions that by their nature are to be fulfilled at the Closing, but subject to the fulfillment or waiver of such conditions), unless another date, time or place is agreed to in writing by the parties hereto (the "Closing Date"). -4- ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EUA EUA represents and warrants to NEES and LLC as follows: 4.01 Organization and Qualification. (a) EUA is a voluntary association duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has full power, authority and legal right to own its property and assets and to transact the business in which it is engaged. Each of EUA's Subsidiaries is a corporation duly organized or incorporated, validly existing and in good standing under the laws of its jurisdiction of organization or incorporation and has full corporate power and authority to conduct its business as and to the extent now conducted and to own, use and lease its assets and properties, except where failure to be so organized or incorporated, existing and in good standing or to have such power and authority, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. As used in this Agreement, the term "EUA Material Adverse Effect" means a material adverse effect on the business, assets, results of operations, condition (financial or otherwise) or prospects of EUA and its Subsidiaries taken as a whole. Each of EUA and its Subsidiaries is duly qualified, licensed or admitted to do business and is in good standing in each jurisdiction in which the ownership, use or leasing of its assets and properties, or the conduct or nature of its business, makes such qualification, licensing or admission necessary, except where failure to be so qualified, licensed or admitted and in good standing, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. Section 4.01 of the letter dated the date hereof and delivered to NEES and LLC by EUA concurrently with the execution and delivery of this Agreement (the "EUA Disclosure Letter") sets forth (i) the name and jurisdiction of incorporation or organization of each Subsidiary of EUA, (ii) such Subsidiary's authorized capital stock, (iii) the number of issued and outstanding shares of capital stock of such Subsidiary and (iv) the number of shares of such Subsidiary held of record by EUA. EUA has previously delivered to NEES correct and complete copies of the EUA Trust Agreement and the certificate or articles of organization or incorporation and bylaws (or other comparable charter documents) of its Subsidiaries. (b) Section 4.01 of the EUA Disclosure Letter sets forth a description as of the date hereof, of all EUA Associates, including (i) the name of each such entity and EUA's interest therein and (ii) a brief description of the principal line or lines of business conducted by each such entity. For purposes of this Agreement "EUA Associates" shall mean any corporation or other entity (including partnerships and other business associations) that is not a Subsidiary of EUA in which EUA and/or one or more of its Subsidiaries, directly or indirectly, owns an equity interest (other than short-term investments in the ordinary course of business) if such corporation or other entity (including partnerships and other business associations) contributes five percent or more of EUA's consolidated revenues, assets, income or costs. -5- 4.02 Capital Stock. (a) The authorized equity securities of EUA consists of 36,000,000 EUA Shares, of which 20,435,997 shares were issued and outstanding as of the close of business on January 29, 1999. As of the close of business on January 29, 1999, no EUA Shares were held in the treasury of EUA. Since such date there has been no change in the sum of the issued and outstanding EUA Shares. All of the issued and outstanding EUA Shares are duly authorized, validly issued, fully paid and nonassessable. Except pursuant to this Agreement and except as described in Section 4.02 of the EUA Disclosure Letter, on the date hereof there are no outstanding subscriptions, options, warrants, rights (including share appreciation rights), preemptive rights or other contracts, commitments, understandings or arrangements, including any right of conversion or exchange under any outstanding security, instrument or agreement (together, "Options"), obligating EUA or any of its Subsidiaries to issue or sell any shares of equity securities of EUA or to grant, extend or enter into any Option with respect thereto. The EUA Disclosure Letter sets forth all capital stock authorized, issued and outstanding at subsidiary levels as of the close of business on January 29, 1999. (b) Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, all of the outstanding shares of capital stock of each Subsidiary of EUA are duly authorized, validly issued, fully paid and nonassessable and are owned, beneficially and of record, by EUA or a Subsidiary, which is wholly owned, directly or indirectly, by EUA, free and clear of any liens, claims, mortgages, encumbrances, pledges, security interests, equities and charges of any kind (each a "Lien"). Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no (i) outstanding Options obligating EUA or any of its Subsidiaries to issue or sell any shares of capital stock of any Subsidiary of EUA or to grant, extend or enter into any such Option or (ii) voting trusts, proxies or other commitments, understandings, restrictions or arrangements in favor of any person other than EUA or a Subsidiary which is wholly owned, directly or indirectly, by EUA with respect to the voting of, or the right to participate in, dividends or other earnings on any capital stock of any Subsidiary of EUA. (c) Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no outstanding contractual obligations of EUA or any Subsidiary of EUA to repurchase, redeem or otherwise acquire any EUA Shares or any capital stock of any Subsidiary of EUA or to provide funds to, or make any investment (in the form of a loan, capital contribution or otherwise) in, any Subsidiary of EUA or any other person. (d) As of the date of this Agreement, no bonds, debentures, notes or other indebtedness of EUA or any Subsidiary of EUA having the right to vote (or which are convertible into or exercisable for securities having the right to vote) (together "EUA Voting Debt") on any matters on which Shareholders may vote are issued or outstanding nor are there any outstanding Options obligating EUA or any of its Subsidiaries to issue or sell any EUA Voting Debt or to grant, extend or enter into any Option with respect thereto. -6- 4.03 Authority. EUA has full power and authority to enter into this Agreement, to perform its obligations hereunder and, subject to obtaining EUA Shareholders' Approval (as defined in Section 7.03(b)) and EUA Required Statutory Approvals (as defined in Section 4.04(b)), to consummate the Merger and other transactions contemplated hereby. The execution, delivery and performance of this Agreement by EUA and the consummation by EUA of the Merger and other transactions contemplated hereby have been duly authorized by all necessary action on the part of EUA, subject to obtaining EUA Shareholders' Approval with respect to the consummation of the Merger and the other transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by EUA and constitutes a legal, valid and binding obligation of EUA enforceable against EUA in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). 4.04 Non-Contravention; Approvals and Consents. (a) The execution and delivery of this Agreement by EUA do not, and the performance by EUA of its obligations hereunder and the consummation of the Merger and other transactions contemplated hereby will not, conflict with, result in a violation or breach of, constitute (with or without notice or lapse of time or both) a default under, result in or give to any person any right of payment or reimbursement, termination, cancellation, modification or acceleration of, or result in the creation or imposition of any Lien upon any of the assets or properties of EUA or any of its Subsidiaries or any of the terms, conditions or provisions of (i) the EUA Trust Agreement or the certificates or articles of incorporation or organization or bylaws (or other comparable charter documents) of EUA's Subsidiaries, or (ii) subject to the obtaining of EUA Shareholders' Approval, EUA Required Consents, EUA Required Statutory Approvals and the taking of any other actions described in this Section 4.04, (x) any statute, law, rule, regulation or ordinance (together, "laws"), or any judgment, decree, order, writ, permit or license (together, "orders"), of any court, tribunal, arbitrator, authority, agency, commission, official or other instrumentality of the United States, any foreign country or any domestic or foreign state, county, city or other political subdivision (a "Governmental Authority") applicable to EUA or any of its Subsidiaries or any of their respective assets or properties, or (y) subject to obtaining the third-party consents set forth in Section 4.04 of the EUA Disclosure Letter (the "EUA Required Consents"), any note, bond, mortgage, security agreement, indenture, license, franchise, permit, concession, contract, lease or other instrument, obligation or agreement of any kind (together, "Contracts") to which EUA or any of its Subsidiaries is a party or by which EUA or any of its Subsidiaries or any of their respective assets or properties is bound, excluding from the foregoing clauses (x) and (y) such conflicts, violations, breaches, defaults, payments or reimbursements, terminations, cancellations, modifications, accelerations and creations and impositions of Liens which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. -7- (b) No declaration, filing or registration with, or notice to or authorization, consent or approval of, any Governmental Authority is necessary for the execution and delivery of this Agreement by EUA or the consummation by EUA of the Merger and other transactions contemplated hereby except as described in Section 4.04 of the EUA Disclosure Letter or the failure of which to obtain could not reasonably be expected to result in an EUA Material Adverse Effect (the "EUA Required Statutory Approvals," it being understood that references in this Agreement to "obtaining" such EUA Required Statutory Approvals shall mean making such declarations, filings or registrations; giving such notices; obtaining such authorizations, consents or approvals; and having such waiting periods expire as are necessary to avoid a violation of law). 4.05 SEC Reports, Financial Statements and Utility Reports. (a) EUA delivered to NEES prior to the execution of this Agreement a true and complete copy of each form, report, schedule, registration statement, registration exemption, if applicable, definitive proxy statement and other document (together with all amendments thereof and supplements thereto) filed by EUA or any of its Subsidiaries with the Securities and Exchange Commission (the "SEC") under the Securities Act of 1933, as amended, and the rules and regulations thereunder (the "Securities Act") and the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder (the "Exchange Act") since December 31, 1995 (as such documents have since the time of their filing been amended or supplemented, the "EUA SEC Reports"), which are all the documents (other than preliminary materials) that EUA and its Subsidiaries were required to file with the SEC under the Securities Act and the Exchange Act since such date. As of their respective dates, EUA SEC Reports (i) complied as to form in all material respects with the requirements of the Securities Act or the Exchange Act, as the case may be, and (ii) did not contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. Each of the audited consolidated financial statements and unaudited interim consolidated financial statements (including, in each case, the notes, if any, thereto) included in EUA SEC Reports (the "EUA Financial Statements") complied as to form in all material respects with the published rules and regulations of the SEC with respect thereto, were prepared in accordance with U.S. generally accepted accounting principles ("US GAAP") applied on a consistent basis during the periods involved (except as may be indicated therein or in the notes thereto and except with respect to unaudited statements as permitted by Form 10-Q of the SEC) and fairly present (subject, in the case of the unaudited interim financial statements, to normal, recurring year-end audit adjustments (which are not expected to be, individually or in the aggregate, materially adverse to EUA and its Subsidiaries taken as a whole)) the consolidated financial position of EUA and its consolidated subsidiaries as at the respective dates thereof and the consolidated results of their operations and cash flows for the respective periods then ended. Except as set forth in Section 4.05 of the EUA Disclosure Letter, each Subsidiary of EUA is treated as a consolidated subsidiary of EUA in EUA Financial Statements for all periods covered thereby. (b) All filings (other than immaterial filings) required to be made by EUA or any of its Subsidiaries since December 31, 1995, under the Public -8- Utility Holding Company Act of 1935 (the "1935 Act"), the Federal Power Act, the Atomic Energy Act of 1954, the Communications Act of 1934, and applicable state laws and regulations, have been filed with the SEC, the Federal Energy Regulatory Commission (the "FERC"), the Department of Energy (the "DOE"), the Nuclear Regulatory Commission (the "NRC"), the Federal Communications Commission (the "FCC") or any appropriate state public utility commissions (including, without limitation, to the extent required, the state public utility regulatory agencies of Massachusetts, Rhode Island, New Hampshire, Maine, Vermont and Connecticut as the case may be, including all forms, statements, reports, agreements (oral or written) and all documents, exhibits, amendments and supplements appertaining thereto, including but not limited to all rates, tariffs, franchises, service agreements and related documents and all such filings complied, as of their respective dates, in all material respects with all applicable requirements of the appropriate statutes and the rules and regulations thereunder. 4.06 Absence of Certain Changes or Events. Except as set forth in Section 4.06 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date of this Agreement since December 31, 1997, EUA and each of EUA's Subsidiaries have conducted its business only in the ordinary course of business consistent with past practice and there has not been, and no fact or condition exists which, individually or in the aggregate, has or could reasonably be expected to have an EUA Material Adverse Effect. 4.07 Legal Proceedings. Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or in Section 4.07 of the EUA Disclosure Letter and except for environmental matters which are governed by Section 4.13, (i) there are no actions, claims, hearings, suits, arbitrations or proceedings pending or, to the knowledge of EUA or any of its Subsidiaries, threatened against, specifically relating to or affecting, and, to the knowledge of EUA or any of its Subsidiaries, there are no Governmental Authority investigations or audits pending or threatened against, specifically relating to or affecting, EUA or any of its Subsidiaries or any of their respective assets and properties which, individually or in the aggregate, could reasonably be expected to have an EUA Material Adverse Effect and (ii) neither EUA nor any of its Subsidiaries is subject to any order of any Governmental Authority which, individually or in the aggregate, could reasonably be expected to have an EUA Material Adverse Effect. 4.08 Information Supplied. (a) The proxy statement relating to EUA Shareholders' Meeting, as amended or supplemented from time to time (as so amended and supplemented, the "Proxy Statement"), and any other documents to be filed by EUA with the SEC (including, without limitation, under the 1935 Act) or any other Governmental Authority in connection with the Merger and other transactions contemplated hereby will comply as to form in all material respects with the requirements of the Exchange Act, the Securities Act and the 1935 Act, as applicable, and will not, on the date of their respective filings or, in the case of the Proxy Statement, at the date it is mailed to Shareholders of EUA and at the time of EUA Shareholders' Meeting (as defined in Section 7.03), contain any untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in light of the circumstances under which they are made, not misleading. -9- (b) Notwithstanding the foregoing provisions of this Section 4.08, no representation or warranty is made by EUA with respect to statements made or incorporated by reference in the Proxy Statement based on information supplied by NEES or LLC for inclusion or incorporation by reference therein. 4.09 Compliance. Except as set forth in Section 4.09 of the EUA Disclosure Letter, or as disclosed in EUA SEC Reports filed prior to the date hereof, neither EUA nor any of EUA's Subsidiaries is in violation of, is, to the knowledge of EUA, under investigation with respect to any violation of, or has been given notice or been charged with any violation of, any law, statute, order, rule, regulation, ordinance or judgment (including, without limitation, any applicable environmental law, ordinance or regulation) of any Governmental Authority, except for possible violations which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. Except as set forth in Section 4.09 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date hereof, EUA and EUA's Subsidiaries have all permits, licenses, franchises and other governmental authorizations, consents and approvals necessary to conduct their businesses as presently conducted except for such failures which could not reasonably be expected to have an EUA Material Adverse Effect. Neither EUA nor any of EUA's Subsidiaries is in breach or violation of, or in default in the performance or observance of any term or provision of, (i) the EUA Trust Agreement, in the case of EUA, or articles of incorporation or organization or by-laws, in the case of EUA's Subsidiaries, or (ii) any contract, commitment, agreement, indenture, mortgage, loan agreement, note, lease, bond, license, approval or other instrument to which it is a party or by which EUA or any Subsidiary of EUA is bound or to which any of their respective property is subject, except for possible violations, breaches or defaults which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. 4.10 Taxes. Except as disclosed in Section 4.10 of the EUA Disclosure Letter: (a) Filing of Timely Tax Returns. EUA and each of its Subsidiaries have timely filed all Tax Returns required to be filed by each of them under applicable law. All Tax Returns were (and, as to Tax Returns not filed as of the date hereof, will be) true, complete and correct; (b) Payment of Taxes. EUA and each of its Subsidiaries have, within the time and in the manner prescribed by law, paid (and until the Closing Date will pay within the time and in the manner prescribed by law) all Taxes that are currently due and payable except for those contested in good faith and for which adequate reserves have been taken; (c) Tax Reserves. EUA and its Subsidiaries have established (and until the Closing Date will maintain) on their books and records adequate reserves for all Taxes and for any liability for deferred income taxes in accordance with GAAP; -10- (d) Extensions of Time for Filing Tax Returns. Neither EUA nor any of its Subsidiaries has requested any extension of time within which to file any Tax Return, which Tax Return has not since been filed; (e) Waivers of Statute of Limitations. Neither EUA nor any of its Subsidiaries has in effect any extension, outstanding waivers or comparable consents regarding the application of the statute of limitations with respect to any Taxes or Tax Returns; (f) Expiration of Statute of Limitations. The Tax Returns of EUA, each of its Subsidiaries and any affiliated, consolidated, combined or unitary group that includes EUA or any of its Subsidiaries either have been examined and settled with the appropriate Tax authority or closed by virtue of the expiration of the applicable statute of limitations for all years through and including 1993; (g) Audit, Administrative and Court Proceedings. No audits or other administrative proceedings or court proceedings are presently pending or threatened with regard to any Taxes or Tax Returns of EUA or any of its Subsidiaries (other than those being contested in good faith and for which adequate reserves have been established) and no issues have been raised in writing by any Tax authority in connection with any Tax or Tax Return; (h) Tax Liens. There are no Tax liens upon any asset of EUA or any of its Subsidiaries except liens for Taxes not yet due. (i) Powers of Attorney. No power of attorney currently in force has been granted by EUA or any of its Subsidiaries concerning any Tax matter; (j) Tax Rulings. Neither EUA nor any of its Subsidiaries has, during the five year period prior to the date of this Agreement, received a Tax Ruling (as defined below) or entered into a Closing Agreement (as defined below) with any taxing authority. "Tax Ruling", as used in this Agreement, shall mean a written ruling of a taxing authority relating to Taxes. "Closing Agreement", as used in this Agreement, shall mean a written and legally binding agreement with a taxing authority relating to Taxes; (k) Availability of Tax Returns. EUA and its Subsidiaries have made available to NEES complete and accurate copies, covering all years ending on or after December 31, 1993, of (i) all Tax Returns, and any amendments thereto, filed by EUA or any of its Subsidiaries, (ii) all audit reports received from any taxing authority relating to any Tax Return filed by EUA or any of its Subsidiaries and (iii) any Closing Agreements entered into by EUA or any of its Subsidiaries with any taxing authority. (l) Tax Sharing Agreements. No agreements relating to the allocation or sharing of Taxes exist between or among EUA and any of its Subsidiaries and neither EUA nor any of its Subsidiaries (i) has been a member of an affiliated group filing a consolidated federal income tax return (other -11- than a group the common parent of which was EUA) or (ii) has any liability for Taxes of any Person (other than EUA or its Subsidiaries) under United States Treasury Regulation Section 1.1502-6 (or any provision of state, local), or foreign law, as a transferee or successor, by contract or otherwise; (m) Code Section 481 Adjustments. Neither EUA nor any of its Subsidiaries is required to include in income any adjustment pursuant to Code Section 481(a) by reason of a voluntary change in accounting method initiated by EUA or any of its Subsidiaries, and, the Internal Revenue Service ("IRS") has not proposed any such adjustment or change in accounting method; (n) Code Sections 6661 and 6662. All transactions that could give rise to an understatement of federal income tax, and within the meaning of Code Section 6662 have been adequately disclosed (or, with respect to Tax Returns filed following the Closing, will be adequately disclosed) on the Tax Returns of EUA and its Subsidiaries in accordance with Code Section 6662(d)(2)(B); (o) Intercompany Transactions. Neither EUA nor any of its Subsidiaries has engaged in any intercompany transactions within the meaning of Treasury Regulations ss. 1.1502-13 for which any income or gain will remain unrecognized as of the close of the last taxable year prior to the Closing Date; and (p) Foreign Tax Returns. Neither EUA nor any of its Subsidiaries is required to file a foreign tax return. "Taxes" as used in this Agreement, shall mean any federal, state, county, local or foreign taxes, charges, fees, levies, or other assessments, including all net income, gross income, premiums, sales and use, ad valorem, transfer, gains, profits, windfall profits, excise, franchise, real and personal property, gross receipts, capital stock, production, business and occupation, employment, disability, payroll, license, estimated, stamp, custom duties, severance or withholding taxes, other taxes or similar charges of any kind whatsoever imposed by any governmental entity, whether imposed directly on a Person or resulting under Treasury Regulation Section 1.1502-6 (or any similar provision of state, local or foreign law), as a transferee or successor, by contract or otherwise and includes any interest and penalties on or additions to any such taxes or in respect of a failure to comply with any requirement relating to any Tax Return. "Tax Return" as used in this Agreement, shall mean a report, return or other information required to be supplied to a governmental entity with respect to Taxes including, where permitted or required, combined, unitary or consolidated returns for any group of entities. 4.11 Employee Benefit Plans; ERISA. (a) Each "employee benefit plan" (as defined in Section 3(3) of the Employee Retirement Income Security Act of 1974, as amended ("ERISA")), bonus, deferred compensation, share option or other written agreement relating to employment or fringe benefits for employees, former employees, officers, trustees or directors of EUA or any of its Subsidiaries effective as of the date hereof or providing benefits as of the date hereof to current employees, former employees, officers, trustees or -12- directors of EUA or pursuant to which EUA or any of its subsidiaries has or could reasonably be expected to have any liability (collectively, the "EUA Employee Benefit Plans") is listed in Section 4.11(a) of the EUA Disclosure Letter, is in material compliance with applicable law, and has been administered and operated in all material respects in accordance with its terms. Each EUA Employee Benefit Plan which is intended to be qualified within the meaning of Section 401(a) of the Code has received a favorable determination letter from the IRS as to such qualification and, to the knowledge of EUA, no event has occurred and no condition exists which could reasonably be expected to result in the revocation of, or have any adverse effect on, any such determination. (b) Complete and correct copies of the following documents have been made available to NEES as of the date of this Agreement: (i) all EUA Employee Benefit Plans and any related trust agreements or insurance contracts, (ii) the most current summary descriptions of each EUA Employee Benefit Plan subject to ERISA, (iii) the three most recent Form 5500s and Schedules thereto for each EUA Employee Benefit Plan subject to such reporting, (iv) the most recent determination of the IRS with respect to the qualified status of each EUA Employee Benefit Plan that is intended to qualify under Section 401(a) of the Code, (v) the most recent accountings with respect to each EUA Employee Benefit Plan funded through a trust and (vi) the most recent actuarial report of the qualified actuary of each EUA Employee Benefit Plan with respect to which actuarial valuations are conducted. (c) Except as set forth in Section 4.11(c) of the EUA Disclosure Letter, neither EUA nor any Subsidiary maintains or is obligated to provide benefits under any EUA Employee Benefit Plan (other than as an incidental benefit under a Plan qualified under Section 401(a) of the Code) which provides health or welfare benefits to retirees or other terminated employees other than benefit continuations as required pursuant to Section 601 of ERISA. Each EUA Employee Benefit Plan subject to the requirements of Section 601 of ERISA has been operated in material compliance therewith. EUA has not contributed to a nonconforming group health plan (as defined in Code Section 5000(c)) and no person under common control with EUA within the meaning of Section 414 of the Code ("ERISA Affiliate") has incurred a tax liability under Code Section 5000(a) that is or could reasonably be expected to be a liability of EUA's. (d) Except as set forth in Section 4.11(d) of the EUA Disclosure Letter, each EUA Employee Benefit Plan covers only employees who are employed by EUA or a Subsidiary (or former employees or beneficiaries with respect to service with EUA or a Subsidiary). (e) Except as set forth in Section 4.11(e) of the EUA Disclosure Letter, neither EUA, any Subsidiary, any ERISA Affiliate nor any other corporation or organization controlled by or under common control with any of the foregoing within the meaning of Section 4001 of ERISA has, within the five-year period preceding the date of this Agreement, at any time contributed to any "multiemployer plan," as that term is defined in Section 4001 of ERISA. -13- (f) No event has occurred, and there exists no condition or set of circumstances in connection with any EUA Employee Benefit Plan, under which EUA or any Subsidiary, directly or indirectly (through any indemnification agreement or otherwise), could be subject to any liability under Section 409 of ERISA, Section 502(i) of ERISA, Title IV of ERISA or Section 4975 of the Code except for instances of non-compliance which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. (g) Neither EUA nor any ERISA Affiliate has incurred any liability to the Pension Benefit Guaranty Corporation (the "PBGC") under Section 302(c)(ii), 4062, 4063, 4064 or 4069 of ERISA, or otherwise that has not been satisfied in full and no event or condition exists or has existed which could reasonably be expected to result in any such material liability. As of the date of this Agreement, no "reportable event" within the meaning of Section 4043 of ERISA has occurred with respect to any EUA Employee Benefit Plan that is a defined benefit plan under Section 3(35) of ERISA. (h) Except as set forth in Section 4.11(h) of the EUA Disclosure Letter, no employer securities, employer real property or other employer property is included in the assets of any EUA Employee Benefit Plan. (i) Full payment has been made of all material amounts which EUA or any affiliate thereof was required under the terms of EUA Employee Benefit Plans to have paid as contributions to such plans on or prior to the Effective Time (excluding any amounts not yet due) and no EUA Employee Benefit Plan which is subject to Part III of Subtitle B of Title I of ERISA has incurred any "accumulated funding deficiency" within the meaning of Section 302 of ERISA or Section 412 of the Code, whether or not waived. (j) Except as set forth in Section 4.11(j) of the EUA Disclosure Letter, no amounts payable under any EUA Employee Benefit Plan or other agreement, contract, or arrangement will fail to be deductible for federal income tax purposes by virtue of Section 280G or Section 162(m) of the Code. 4.12 Labor Matters. As of the date hereof, except as set forth in Section 4.12 of the EUA Disclosure Letter, neither EUA nor any of its Subsidiaries is a party to any material collective bargaining agreement or other labor agreement with any union or labor organization. To the knowledge of EUA, as of the date hereof, there is no current union representation question involving employees of EUA or any of its Subsidiaries, nor does EUA know of any activity or proceeding of any labor organization (or representative thereof) or employee group to organize any such employees. Except as set forth in Section 4.12 of the EUA Disclosure Letter, (i) there is no unfair labor practice, employment discrimination or other employment-related complaint or proceeding against EUA or any of its Subsidiaries pending or, to the knowledge of EUA, threatened, which has or could reasonably be expected to have an EUA Material Adverse Effect, (ii) there is no strike, dispute, slowdown, work stoppage or lockout pending, or, to the knowledge of EUA, threatened, against or involving EUA or any of its Subsidiaries which has or could reasonably be expected to have, an EUA Material Adverse Effect and (iii) there is no proceeding, claim, -14- suit, or action pending or, to the knowledge of EUA or any of its Subsidiaries, threatened, nor, to the knowledge of EUA or any of its Subsidiaries is there any Governmental Authority investigation pending or threatened, in respect of which any trustee, director, officer, employee or agent of EUA or any of its Subsidiaries is or may be entitled to claim indemnification from EUA or any of its Subsidiaries pursuant to the EUA Trust Agreement, in the case of EUA, and their respective articles of incorporation and by-laws, in the case of EUA's Subsidiaries, or as provided in the indemnification agreements listed in Section 4.12 of the EUA Disclosure Letter. Except as set forth in Section 4.12 of the EUA Disclosure Letter, EUA and its Subsidiaries are in compliance with all federal, state and local laws with respect to employment practices and labor relations, including, without limitation, any provisions relating to affirmative action, employment discrimination, wages, hours, collective bargaining, and the payment of social security and similar taxes, safety and health regulations and mass layoffs and plant closings except for such instances of noncompliance which, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. 4.13 Environmental Matters. Except as disclosed in EUA SEC Reports filed prior to the date of this Agreement or in Section 4.13 of the EUA Disclosure Letter: (a) (i) Each of EUA and its Subsidiaries is in compliance with all applicable Environmental Laws (as hereinafter defined), except where the failure to be in compliance, in the aggregate could not reasonably be expected to result in an EUA Material Adverse Effect; and (ii) Neither EUA nor any of its Subsidiaries has received any written communication from any person or Governmental Authority that alleges that EUA or any of its Subsidiaries is not in such compliance (including the materiality qualifier set forth in clause (i) above) with applicable Environmental Laws. (b) Each of EUA and its Subsidiaries has obtained all environmental, health and safety permits and governmental authorizations (collectively, the "Environmental Permits") necessary for the construction of their facilities and the conduct of their operations, as applicable, and all such Environmental Permits are in good standing or, where applicable, a renewal application has been timely filed and agency approval is expected in the ordinary course of business, and EUA and its Subsidiaries are in compliance with all terms and conditions of the Environmental Permits, except where the failure have such Environmental Permits, file a renewal application for such Environmental Permits, or to be in compliance with such Environmental Permits, in the aggregate could not reasonably be expected to result in an EUA Material Adverse Effect. (c) There is no Environmental Claim (as hereinafter defined) that could, individually or in the aggregate, reasonably be expected to have an EUA Material Adverse Effect pending (i) against EUA or any of its Subsidiaries; (ii) against any person or entity whose liability for any Environmental Claim EUA or any of its Subsidiaries has or may have retained or assumed either contractually or by operation of law; or (iii) against any real or personal -15- property or operations which EUA or any of its Subsidiaries owns, leases or manages, in whole or in part. (d) To the knowledge of EUA there have not been any material Releases (as hereinafter defined) of any Hazardous Material (as hereinafter defined) that would be reasonably likely to form the basis of any material Environmental Claim against EUA or any of its Subsidiaries, or against any person or entity whose liability for any material Environmental Claim EUA or any of its Subsidiaries has or may have retained or assumed either contractually or by operation of law, except for any Environmental Claim that, individually or in the aggregate, could not reasonably be expected to have an EUA Material Adverse Effect. (e) To the knowledge of EUA with respect to any predecessor of EUA or any of its Subsidiaries, there is no material Environmental Claim pending or threatened, and there has been no Release of Hazardous Materials that could reasonably be expected to form the basis of any material Environmental Claim except for any Environmental Claim that, individually or in the aggregate, could not be reasonably be expected to have an EUA Material Adverse Effect. (f) As used in this Section 4.13: (i) "Environmental Claim" means any and all written administrative, regulatory or judicial actions, suits, demands, demand letters, directives, claims, liens, investigations, proceedings or notices or noncompliance, liability or violation by any person or entity (including any Governmental Authority) alleging potential liability (including, without limitation, potential responsibility or liability for enforcement, investigatory costs, cleanup costs, governmental response costs, removal costs, remedial costs, natural resources damages, property damages, personal injuries or penalties) arising out of, based on or resulting from (A) the presence, or Release or threatened Release into the environment, of any Hazardous Materials at any location, whether or not owned, operated, leased or managed by EUA or any of its Subsidiaries; or (B) circumstances forming the basis of any violation, or alleged violation, of any Environmental Law; or (C) any and all claims by any third party seeking damages, contribution, indemnification, cost recovery, compensation or injunctive relief resulting from the presence or Release of any Hazardous Materials; (ii) "Environmental Laws" means all federal, state and local laws, rules and regulations and binding interpretation thereof, relating to pollution, the environment (including, without limitation, ambient air, surface water, groundwater, land surface or subsurface strata) or protection of human health as it relates to the environment including, without limitation, laws and -16- regulations relating to Releases or threatened Releases of Hazardous Materials, or otherwise relating to the manufacture, generation, processing, distribution, use, treatment, storage, disposal, transport or handling of Hazardous Materials; (iii) "Hazardous Materials" means (A) any petroleum or petroleum products, radioactive materials, asbestos in any form that is or could become friable, urea formaldehyde foam insulation, and transformers or other equipment that contain dielectric fluid containing polychlorinated biphenyls; and (B) any chemicals, materials or substances which are now defined as or included in the definition of "hazardous substances", "hazardous wastes", "hazardous materials", "extremely hazardous wastes", "restricted hazardous wastes", "toxic substances", "toxic pollutants", or words of similar import, under any Environmental Law; and (c) any other chemical, material, substance or waste, exposure to which is now prohibited, limited or regulated under any Environmental Law in a jurisdiction in which EUA or any of its Subsidiaries (x) operates or (y) stores, treats or disposes of Hazardous Materials; and (iv) "Release" means any release, spill, emission, leaking, injection, deposit, disposal, discharge, dispersal, leaching or migration into the atmosphere, soil, surface water, groundwater or property. 4.14 Regulation as a Utility. (a) EUA is a public utility holding company registered under Section 5, and subject to the provisions, of the 1935 Act. Section 4.14 of the EUA Disclosure Letter lists the subsidiaries of EUA that are "public utility companies" within the meaning of Section 2(a)(5) of the 1935 Act and lists the jurisdictions where each such Subsidiary is subject to regulation as a public utility company or public service company. Except as set forth above and as set forth in Section 4.14 of the EUA Disclosure Letter, neither EUA nor any "subsidiary company" or "affiliate" of EUA is subject to regulation as a public utility or public service company (or similar designation) by the federal government of the United States, any state in the United States or any political subdivision thereof, or any foreign country. (b) As used in this Section 4.14, the terms "subsidiary company" and "affiliate" shall have the respective meanings ascribed to them in Section 2(a)(8) and Section 2(a)(11), respectively, of the 1935 Act. 4.15 Insurance. Except as set forth in Section 4.15 of the EUA Disclosure Letter, each of EUA and its Subsidiaries is, and has been continuously since January 1, 1994, insured with financially responsible insurers in such amounts and against such risks and losses as are customary in all material respects for companies in the United States conducting the business conducted by EUA and its Subsidiaries during such time period. Except as set forth in Section 4.15 of the EUA Disclosure Letter, neither EUA nor any of its Subsidiaries has received any notice of cancellation or termination with respect to any material insurance policy of EUA or any of its Subsidiaries. The insurance policies of EUA and each of its Subsidiaries are valid and enforceable policies. -17- 4.16 Nuclear Facilities. Montaup Electric Company, a Subsidiary of EUA, is a minority common stockholder of each of Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power Corporation and Yankee Atomic Electric Company (the "Yankee Companies") and a minority joint owner in Millstone 3 and Seabrook 1 (collectively, as described in Section 4.16 of the EUA Disclosure Letter, the "EUA Nuclear Facilities"). With respect to its ownership of Millstone 3 and Seabrook 1, Montaup Electric Company holds the required operating licenses from the NRC. With respect to the Yankee Companies, each Yankee Company holds its own operating license from the NRC. Because it is a minority stockholder or a minority joint owner, Montaup Electric Company does not have responsibility for the operation of EUA Nuclear Facilities. Except as set forth in Section 4.16 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports filed prior to the date hereof, to the knowledge of EUA, neither EUA nor any of its Subsidiaries is in violation of any applicable health, safety, regulatory and other legal requirement, including NRC laws and regulations and Environmental Laws, applicable to EUA Nuclear Facilities except for such failure to comply as could not reasonably be expected to have a material adverse effect with respect to EUA Nuclear Facilities and the ownership interest of EUA therein. To the knowledge of EUA, each of EUA Nuclear Facilities maintains emergency plans designed to respond to an unplanned release therefrom of radioactive materials into the environment and insurance coverages consistent with industry practice. EUA has funded, or has caused the funding of, its portion of the decommissioning cost of each of the EUA Nuclear Facilities and the storage of spent nuclear fuel consistent with the most recently approved plan for each of the EUA Nuclear Facilities and FERC authorized rates. Except as set forth in Section 4.16 of the EUA Disclosure Letter, to the knowledge of EUA, no EUA Nuclear Facility is as of the date of this Agreement on the List of Nuclear Power Plants Warranting Increased Regulatory Attention maintained by the NRC. 4.17 Vote Required. The affirmative vote of two-thirds of the outstanding EUA Shares voting as a single class (with each EUA Share having one vote per share) with respect to the approval of the Merger and other transactions contemplated hereby is the only vote of the holders of any class or series of equity securities of EUA or its Subsidiaries required to approve this Agreement and approve the Merger and other transactions contemplated hereby. 4.18 Opinion of Financial Advisor. EUA has received the opinion of Salomon Smith Barney Inc., dated the date of this Agreement, to the effect that, as of such date, the Merger Consideration is fair from a financial point of view to the holders of EUA Shares. A true and complete copy of the written opinion will be delivered to NEES promptly after receipt thereof by EUA. 4.19 Ownership of NEES Common Shares. Neither EUA nor any of its Subsidiaries or other affiliates beneficially owns any NEES Common Shares. 4.20 State Anti-Takeover Statutes. EUA has taken all necessary actions so that the provisions of Chapters 110C, 110D or 110F of the MGL will not apply to this Agreement, the Merger or other transactions contemplated hereby or thereby. -18- 4.21 Year 2000. The Information Systems operated by EUA and its Subsidiaries which is used in the conduct of their business is capable of providing or being adapted to provide uninterrupted millennium functionality to record, store, process and present calendar dates falling on or after January 1, 2000 in substantially the same manner and with the same functionality as such Information Systems record, store, process and present such calendar dates falling on or before December 31, 1999 other than such interruptions in millennium functionality that could not, individually or in the aggregate, reasonably be expected to result in a EUA Material Adverse Effect. EUA reasonably believes as of the date hereof that the remaining cost of adaptations referred to in the foregoing sentence will not exceed the amounts reflected in the Form 10-Q filed by EUA for the quarter ended September 30, 1998 (excluding the fees and costs of any Y2K Consultant retained pursuant to Section 6.01(o) hereof and of the implementation of any recommendations by such Y2K Consultant actually made by EUA that are not already part of EUA's compliance plan as of the date hereof). "Information Systems" means mainframe and midrange hardware, operating system software and applications programs; network and desktop (PC) hardware, operating system software and applications programs; EDI (Electronic Date Interchange) and FTP (File Transfer Protocol) software; and embedded systems hardware and applications software. 4.22 EUA Associates. The representations and warranties set forth in Sections 4.04(a), 4.06, 4.07, 4.09, 4.12 and 4.13 are true and correct in all material respects with regard to EUA Associates. ARTICLE V REPRESENTATIONS AND WARRANTIES OF NEES NEES represents and warrants to EUA as follows: 5.01 Organization and Qualification. NEES is a voluntary association duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has full power, authority and legal right to own its property and assets and to transact the business in which it is engaged. Each of the NEES Subsidiaries is a corporation duly organized or incorporated, validly existing and in good standing under the laws of its jurisdiction of organization or incorporation and has full corporate power and authority to conduct its business as and to the extent now conducted and to own, use and lease its assets and properties, except where failure to be so organized or incorporated, existing and in good standing or to have such power and authority, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. As used in this Agreement, the term "NEES Material Adverse Effect" means a material adverse effect on the business, assets, results of operations, condition (financial or otherwise) or prospects of NEES and its Subsidiaries taken as a whole. LLC is a limited liability company validly existing under the laws of the Commonwealth of Massachusetts. LLC was formed solely for the purpose of engaging in the Merger and other transactions contemplated hereby, has engaged in no other business activities (other than in connection with the formation and capitalization of LLC pursuant to or in -19- accordance with the LLC Agreement (as defined below)) and has conducted its operations only as contemplated hereby and by the LLC Agreement. Each of NEES and its Subsidiaries is duly qualified, licensed or admitted to do business and is in good standing in each jurisdiction in which the ownership, use or leasing of its assets and properties, or the conduct or nature of its business, makes such qualification, licensing or admission necessary, except where failure to be so qualified, licensed or admitted and in good standing, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. NEES has previously delivered to EUA correct and complete copies of its Agreement and Declaration of Trust (the "NEES Trust Agreement") and the articles of association of LLC. 5.02 Authority. Each of NEES and LLC has full power and authority to enter into this Agreement, and to perform its obligations hereunder, and to consummate the Merger and other transactions contemplated hereby. The execution, delivery and performance of this Agreement by each of NEES and LLC and the consummation by each of NEES and LLC of the Merger and other transactions contemplated hereby have been duly authorized by all necessary corporate action on the part of NEES and all necessary action on the part of LLC. This Agreement has been duly and validly executed and delivered by each of NEES and LLC and constitutes a legal, valid and binding obligation of each of NEES and LLC enforceable against each of NEES and LLC in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). 5.03 Capital Stock. The authorized equity securities of NEES consists of 150,000,000 common shares of NEES (the "NEES Shares"), of which 59,170,986 shares were issued and outstanding as of the close of business on January 29, 1999. As of the close of business on January 29, 1999, 5,798,666 NEES Shares were held in the treasury of NEES. All of the issued and outstanding NEES Shares are duly authorized, validly issued, fully paid and nonassessable. Except as may be provided by the New England Electric System Companies' Incentive Share Plan, the New England Electric System Companies Incentive Thrift Plan I, the New England Electric System Companies Incentive Thrift Plan II, the New England Electric Companies Long-Term Performance Share Award Plan, and the New England Electric System Directors' annual retainer shares, and except as set forth in Section 5.03 of the letter dated the date hereof and delivered to EUA by NEES and LLC concurrently with the execution and delivery of this Agreement (the "NEES Disclosure Letter"), on the date hereof there are no outstanding Options obligating NEES or any of its Subsidiaries to issue or sell any shares of equity securities of NEES or to grant, extend or enter into any Option with respect thereto. 5.04 Non-Contravention; Approvals and Consents. (a) The execution and delivery of this Agreement by each of NEES and LLC do not, and the performance by each of NEES and LLC of its obligations hereunder and the consummation of the Merger and other transactions contemplated hereby will not, conflict with, result in a violation or breach of, constitute (with or without notice or lapse of time or both) a default under, result in or give to any person any right of payment or reimbursement, termination, cancellation, modification or -20- acceleration of, or result in the creation or imposition of any Lien upon any of the assets or properties of NEES, or LLC under, any of the terms, conditions or provisions of (i) the NEES Agreement and Declaration of Trust or the articles of organization of LLC, (ii) subject to the actions described in paragraph (b) of this Section, (x) any laws or orders of any Governmental Authority applicable to NEES or LLC or any of their respective assets or properties, or (y) subject to obtaining the third-party consents (the "NEES Required Consents") set forth in Section 5.04 of the NEES Disclosure Letter any Contracts to which NEES is a party or by which NEES or any of its Subsidiaries or any of their respective assets or properties is bound, excluding from the foregoing clauses (x) and (y) conflicts, violations, breaches, defaults, terminations, modifications, accelerations and creations and impositions of Liens which, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. (b) No declaration, filing or registration with, or notice to or authorization, consent or approval of, any Governmental Authority is necessary for the execution and delivery of this Agreement by NEES or LLC or the consummation by NEES or LLC of the Merger and other transactions contemplated hereby except as described in Section 5.04 of the NEES Disclosure Letter or the failure of which to obtain could not reasonably be expected to result in a NEES Material Adverse Effect (the "NEES Required Statutory Approvals," it being understood that references in this Agreement to "obtaining" such NEES Required Statutory Approvals shall mean making such declarations, filings or registrations; giving such notices; obtaining such authorizations, consents or approvals; and having such waiting periods expire as are necessary to avoid a violation of law). 5.05 Information Supplied. (a) The information supplied by NEES or LLC and included in the Proxy Statement with the written consent of NEES or LLC, as the case may be, will not, at the date mailed to EUA's Shareholders or at the time of EUA Shareholder's Meeting, contain any untrue statements of a material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. (b) Notwithstanding the foregoing provisions of this Section 5.05, no representation or warranty is made by NEES with respect to statements made or incorporated by reference in the Proxy Statement based on information supplied by EUA for inclusion or incorporation by reference therein or based on information which is not made in or incorporated by reference in such documents but which should have been disclosed pursuant to this Section 5.05. 5.06 Compliance. Except as set forth in Section 5.06 of the NEES Disclosure Letter, or as disclosed in the NEES Reports filed prior to the date hereof, NEES is not in violation of, is, to the knowledge of NEES, under investigation with respect to any violation of, or has been given notice or been charged with any violation of, any law, statute, order, rule, regulation, ordinance or judgment (including, without limitation, any applicable environmental law, ordinance or regulation) of any Governmental Authority, except for possible violations which, individually or in the aggregate, could -21- not reasonably be expected to have a NEES Material Adverse Effect. Except as set forth in Section 5.06 of the NEES Disclosure Letter or as disclosed in the NEES Reports filed prior to the date hereof, NEES and its Subsidiaries have all material permits, licenses and other governmental authorizations, consents and approvals necessary to conduct their businesses as presently conducted which are material to the operation of the businesses of NEES. NEES is not in breach or violation of, or in default in the performance or observance of, any term or provision of, and no event has occurred which, with lapse of time or action by a third party, could result in a default by NEES under (i) the NEES Agreement and Declaration of Trust or by-laws or (ii) any contract, commitment, agreement, indenture, mortgage, loan agreement, note, lease, bond, license, approval or other instrument to which it is a party or by which NEES is bound or to which any of their respective property is subject, except for possible violations, breaches or defaults which, individually or in the aggregate, could not reasonably be expected to have a NEES Material Adverse Effect. 5.07 Financing. NEES has or will have available, prior to the Effective Time, sufficient cash in immediately available funds to pay or to cause LLC to pay the Merger Consideration pursuant to Article II hereof and to consummate the Merger and other transactions contemplated hereby. 5.08 No Vote Required. No vote of the NEES Shares or of any class or series of equity securities of NEES or its Subsidiaries is necessary for the approval of the Merger and other transactions contemplated hereby. 5.09 Ownership of EUA Shares. Neither NEES nor any of its Subsidiaries or other affiliates beneficially owns any EUA Shares. 5.10 Merger with The National Grid Group plc. NEES has entered into an Agreement and Plan of Merger dated as of December 11, 1998 by and among The National Grid Group plc ("National Grid Group"), NGG Holdings LLC (formerly known as Iosta LLC) and NEES (the "National Grid Merger Agreement"). Pursuant to Section 6.01 of the National Grid Merger Agreement, NEES has provided a copy of this Agreement to National Grid Group, and National Grid Group has given NEES its written consent to enter into this Agreement and consummate the Merger on the terms set forth in this Agreement. Prior to the execution of this Agreement, NEES has provided EUA with a copy of such written consent. ARTICLE VI COVENANTS 6.01 Covenants of EUA. At all times from and after the date hereof until the Effective Time, EUA covenants and agrees as to itself and its Subsidiaries that (except as expressly contemplated or permitted by this Agreement or as set forth in Section 6.01 of the EUA Disclosure Letter, or to the extent that NEES shall otherwise previously consent in writing): -22- (a) Ordinary Course. EUA and each of its Subsidiaries shall conduct their businesses only in, and EUA and each of its Subsidiaries shall not take any action except in, the ordinary course consistent with good utility practice. Without limiting the generality of the foregoing, EUA and its Subsidiaries shall use all commercially reasonable efforts to preserve intact in all material respects their present business organizations and reputation, to maintain in effect all existing permits, to keep available the services of their key officers and employees, to maintain their assets and properties in good working order and condition, ordinary wear and tear excepted, to maintain insurance on their tangible assets and businesses in such amounts and against such risks and losses as are currently in effect, to preserve their relationships with customers and suppliers and others having significant business dealings with them and to comply in all material respects with all laws and orders of all Governmental Authorities applicable to them. (b) Charter Documents. EUA shall not, nor shall it permit any of its Subsidiaries to, amend or propose to amend the EUA Trust Agreement, in the case of EUA, and its certificate or articles of incorporation or organization or bylaws (or other comparable charter documents), in the case of EUA's Subsidiaries. (c) Dividends. EUA shall not, nor shall it permit any of its Subsidiaries to, (i) declare, set aside or pay any dividends on, or make other distributions in respect of, any of its capital stock or share capital, except: (A) that EUA may continue the declaration and payment of regular quarterly dividends on EUA Shares with usual record and payment dates not, in any fiscal year, in excess of the dividend for the comparable period in the prior fiscal year; (B) that the Subsidiaries of EUA set forth in Section 6.01(c) of the EUA Disclosure Letter may continue the declaration and payment of dividends on preferred stock in accordance with the terms of such stock, with the record and payment dates and in the amounts set forth in Section 6.01(c) of the EUA Disclosure Letter; (C) if the Effective Time does not occur between a record date and payment date of a regular quarterly dividend, for a special dividend on EUA Shares with respect to the quarter in which the Effective Time occurs with a record date on or prior to the date on which the Effective Time occurs, which does not exceed an amount equal to the product of (x) the number of days between the last payment date of a regular quarterly dividend and the record date of such special dividend, multiplied by (y) $.0045; and (D) for dividends and distributions (including liquidating distributions) by a direct or indirect Subsidiary of EUA to its parent. -23- (ii) split, combine, subdivide, reclassify or take similar action with respect to any of its capital stock or share capital or issue or authorize or propose the issuance of any other securities in respect of, in lieu of or in substitution for shares of its capital stock or comprised in its share capital, (iii) adopt a plan of complete or partial liquidation or resolutions providing for or authorizing such liquidation or a dissolution, merger, consolidation, restructuring, recapitalization or other reorganization or (iv) directly or indirectly redeem, repurchase or otherwise acquire any shares of its capital stock or any Option with respect thereto except: (A) in connection with intercompany purchases of capital stock or share capital, (B) for the purpose of funding EUA's dividend reinvestment and share purchase plan in accordance with past practice, or (C) subject to EUA's obligations under the Securities Act and the Exchange Act, pursuant to EUA's previously announced share repurchase program provided that the number of EUA Shares repurchased does not exceed 3,000,000 and the price paid per share does not exceed 95% of the Per Share Amount. (d) Share Issuances. EUA shall not, nor shall it permit any of its Subsidiaries to, issue, deliver or sell, or authorize or propose the issuance, delivery or sale of, any shares of its capital stock or any Option with respect thereto (other than the issuance by a wholly owned Subsidiary of its capital stock to its direct or indirect parent corporation, or modify or amend any right of any holder of outstanding shares of capital stock or Options with respect thereto). (e) Acquisitions. EUA shall not, nor shall it permit any of its Subsidiaries to acquire or agree to acquire (by merging or consolidating with, or by purchasing a substantial equity interest in or substantial portion of the assets of, or by any other manner) any business or any corporation, partnership, association or other business organization or division thereof. (f) Dispositions. EUA shall not, nor shall it permit any of its Subsidiaries to sell, lease, securitize, grant any security interest in or otherwise dispose of or encumber any of its assets or properties, other than dispositions in the ordinary course of its business consistent with past practice and having an aggregate value of less than $1,000,000 for each disposition and $5,000,000 in the aggregate. (g) Indebtedness. EUA shall not, nor shall it permit any of its Subsidiaries to incur or guarantee any indebtedness (including any debt borrowed or guaranteed or otherwise assumed, including, without limitation, the issuance of debt securities or warrants or rights to acquire debt) or enter into any "keep well" or other agreement to maintain any financial condition of another Person or enter into any arrangement having the economic effect of any of the foregoing other than (i) short-term indebtedness in the ordinary course of business consistent with past practice (such as the issuance of commercial paper -24- or the use of existing credit facilities) in amounts not exceeding the amounts set forth in Section 6.01(g) of the EUA Disclosure Letter, (ii) long-term indebtedness in connection with the refinancing of existing indebtedness either at its stated maturity or at a lower cost of funds (calculating such cost on an aggregate after-tax basis) or (iii) guarantees or "keep well" agreements in favor of wholly owned Subsidiaries of EUA in connection with the conduct of the business of such wholly owned Subsidiaries of EUA not aggregating more than $1,000,000. (h) Capital Expenditures. Except (i) as required by law or (ii) as reasonably deemed necessary by EUA after consulting with NEES following a catastrophic event, such as a major storm, EUA shall not, nor shall it permit any of its Subsidiaries to make any capital expenditures or commitments during any fiscal year that is in excess of 110% of (i) the aggregate amount set forth in Section 6.01(h) of the EUA Disclosure Letter with respect to EUA and its Subsidiaries that are public utility companies within the meaning of Section 2(a)(5) of the 1935 Act or (ii) the amount set forth in Section 6.01(h) of the EUA Disclosure Letter with respect to each of EUA's other Subsidiaries. (i) Employee Benefits. EUA shall not, nor shall it permit any of its Subsidiaries to enter into, adopt, amend (except as may be required by applicable law) or terminate any EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy between EUA or one of its Subsidiaries and one or more of its trustees, directors, officers, employees or former employees, or, except for normal increases in the ordinary course of business, (a) increase in any manner the compensation or fringe benefits of any trustee, director or executive officer, (b) increase in any manner the compensation or fringe benefits of any employee, (c) pay any benefit not required by any plan or arrangement in effect as of the date hereof or, (d) cause any trustee, director, officer, employee or former employee of EUA to accrue or receive additional benefits, accelerate vesting or accelerate the payment of any benefits under any EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy. EUA, prior to the Closing Date, shall take all necessary action and make all necessary amendments to its stock-based plans so that all such plans will be in a form that allows the plans to function after the Effective Time and after any merger of EUA and its Subsidiaries into NEES or its Subsidiaries. EUA, prior to the Closing Date, shall take all necessary actions, in a manner satisfactory to NEES, so that on or after the Closing Date, neither EUA, the Surviving Entity nor their affiliates' stock or securities will be required to be held in, or distributed pursuant to, any EUA Employee Benefit Plan. (j) Labor Matters. Notwithstanding any other provision of this Agreement to the contrary, EUA or its Subsidiaries may negotiate successor collective bargaining agreements to those referenced in Section 4.12 hereof, and may negotiate other collective bargaining agreements or arrangements as required by law or for the purpose of implementing the agreements referenced in Section 4.12 hereof. EUA will keep NEES informed as to the status of, and will consult with NEES as to the strategy for, all negotiations with collective bargaining representatives. EUA and its Subsidiaries shall act prudently and reasonably and consistent with their obligation under applicable law in such negotiations. -25- (k) Discharge of Liabilities. EUA shall not, nor shall it permit its Subsidiaries to, pay, discharge or satisfy any material claims, liabilities or obligations (absolute, accrued, asserted or unasserted, contingent or otherwise), other than the payment, discharge or satisfaction, in the ordinary course of business consistent with past practice (which includes the payment of final and unappealable judgments) or in accordance with their terms, of liabilities reflected or reserved against in, or contemplated by, the most recent consolidated financial statements (or the notes thereto) of such party included in EUA SEC Reports, or incurred in the ordinary course of business consistent with past practice. (l) Contracts. EUA shall not, nor shall it permit its Subsidiaries, except in the ordinary course of business consistent with past practice or as set forth in Section 6.01(l) of the EUA Disclosure Letter, (i) to modify, amend, terminate or fail to use commercially reasonable efforts to renew any material Contract to which EUA or any of its Subsidiaries is a party or waive, release or assign any material rights or claims or (ii) to enter into any new material Contracts except as expressly permitted by Sections 6.01 (f), (g) or (i) and 7.06 hereof. (m) Equity Investments. EUA shall not, nor shall it permit its Subsidiaries or affiliates to, make equity contributions to non-affiliates or to its non-utility Subsidiaries. (n) Loans. EUA shall not, nor shall it permit its Subsidiaries or affiliates to, loan money to non-affiliates or to its non-utility Subsidiaries. (o) Year 2000. EUA, within 15 days of the date of this Agreement, shall engage a qualified third party ("Y2K Consultant") to conduct a detailed assessment of the adequacy and state of completion of its Year 2000 Program, including but not limited to assessment and testing of its customer, accounting, and operational systems. The Y2K Consultant and scope of work of the Y2K Consultant shall be acceptable to NEES. Such assessment and testing shall be completed as soon thereafter as practicable. EUA shall have such assessment updated by the Y2K Consultant at the end of each fiscal quarter of 1999. EUA shall allow designated NEES personnel and representatives access to the Y2K Consultant's personnel, reports and recommendations and access to EUA's personnel, documents, and information related to the Y2K issue. EUA and the third party shall meet with such designated NEES personnel and representatives on a periodic basis (but not less frequently than monthly) to update NEES on EUA's Year 2000 Program. If this Agreement is terminated pursuant to Section 9.01 hereof, NEES shall reimburse EUA for the costs and expenses of the Y2K Consultant. (p) Insurance. EUA shall, and shall cause its Subsidiaries to, maintain with financially responsible insurance companies (or through self-insurance, consistent with past practice) insurance in such amounts and against such risks and losses as are customary for companies engaged in their respective businesses. (q) 1935 Act. EUA shall not, nor shall it permit any of its Subsidiaries to, engage in any activities which would cause a change in its status, or that of its Subsidiaries, under the 1935 Act. -26- (r) Regulatory Matters. Subject to applicable law and except for non-material filings in the ordinary course of business consistent with past practice, EUA shall consult with NEES prior to implementing any changes in its or any of its Subsidiaries' rates or charges, standards of service or accounting or executing any agreement with respect thereto that is otherwise permitted under this Agreement and shall, and shall cause its Subsidiaries to, deliver to NEES a copy of each such filing or agreement at least four (4) business days prior to the filing or execution thereof so that NEES may comment thereon. EUA shall, and shall cause its Subsidiaries to, make all such filings (i) only in the ordinary course of business consistent with past practice or (ii) as required by a Governmental Authority or regulatory agency with appropriate jurisdiction. (s) Accounting. EUA shall not, nor shall it permit any of its Subsidiaries to make any changes in their accounting methods, policies or procedures, except as required by law, rule, regulation or applicable generally accepted accounting principles; (t) Tax Status. Neither EUA nor any of its Subsidiaries shall (i) make or rescind any material express or deemed election relating to Taxes, (ii) make a request for a Tax Ruling or enter into a Closing Agreement, (iii) settle or compromise any material claim, action, suit, litigation, proceeding, arbitration, investigation, audit, or controversy relating to Taxes or (iv) change in any material respect any of its methods of reporting income, deductions or accounting for federal income tax purposes from those employed in the preparation of its federal income Tax Return for the taxable year ending December 31, 1997, except as may be required by applicable law. (u) No Breach. EUA shall not, nor shall it permit any of its Subsidiaries to willfully take or fail to take any action that would or is reasonably likely to result in (i) a material breach of any provision of this Agreement or (ii) its representations and warranties set forth in this Agreement being untrue in any material respect on and as of the Closing Date. (v) Advice of Changes. EUA shall confer with NEES on a regular and frequent basis with respect to EUA's business and operations and other matters relevant to the Merger to the extent permitted by law, and shall promptly advise NEES, orally and in writing, of any material change or event, including, without limitation, any complaint, investigation or hearing by any Governmental Authority (or communication indicating the same may be contemplated) or the institution or threat of material litigation; provided that EUA shall not be required to make any disclosure to the extent such disclosure would constitute a violation of any applicable law or regulation. (w) Notice and Cure. EUA will notify NEES in writing of, and will use all commercially reasonable efforts to cure before the Closing, any event, transaction or circumstance, as soon as practical after it becomes known to EUA, that causes or will or may be likely to cause any covenant or agreement of EUA under this Agreement to be breached or that renders or will render untrue in any material respect any representation or warranty of EUA contained in this Agreement. EUA also will notify NEES in writing of, and will use all -27- commercially reasonable efforts to cure, before the Closing, any material violation or breach, as soon as practical after it becomes known to EUA, of any representation, warranty, covenant or agreement made by EUA. No notice given pursuant to this paragraph shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein. (x) Fulfillment of Conditions. Subject to the terms and conditions of this Agreement, EUA will take or cause to be taken all commercially reasonable steps necessary or desirable and proceed diligently and in good faith to satisfy each condition to the other's obligations contained in this Agreement and to consummate and make effective the Merger and other transactions contemplated by this Agreement, and EUA will not, nor will it permit any of its Subsidiaries to, take or fail to take any action that could be reasonably expected to result in the nonfulfillment of any such condition. (y) Third Party Standstill Agreements. Except as provided in Section 7.08 hereto, during the period from the date of this Agreement through the Effective Time, neither EUA nor any of its Subsidiaries shall terminate, amend, modify or waive any provision of any confidentiality or standstill agreement to which it is a party. During such period, EUA shall take all steps necessary to enforce, to the fullest extent permitted under applicable law, the provisions of any such agreement. 6.02 Covenants of NEES. At all times from and after the date hereof until the Effective Time, NEES covenants and agrees that (except as expressly contemplated or permitted by this Agreement or to the extent that EUA shall otherwise previously consent in writing): (a) No Breach. NEES shall not, nor shall it permit any of its Subsidiaries to, except as otherwise expressly provided for in this Agreement, willfully take or fail to take any action that would or is reasonably likely to result in (i) a material breach of any of its covenants or agreements contained in this Agreement or (ii) any of its representations and warranties set forth in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.06, 5.07, 5.08 and 5.09 of this Agreement being untrue in any material respect on and as of the Closing Date. (b) Advice of Changes. NEES shall confer with EUA on a regular and frequent basis with respect to any matter having, or which, insofar as can be reasonably foreseen, could reasonably be expected to have, a NEES Material Adverse Effect or materially impair the ability of NEES to consummate the Merger and other transactions contemplated hereby; provided that NEES shall not be required to make any disclosure to the extent such disclosure would constitute a violation of any applicable law or regulation. (c) Notice and Cure. NEES will notify EUA in writing of, and will use all commercially reasonable efforts to cure before the Closing, any event, transaction or circumstance, as soon as practical after it becomes known to NEES, that causes or will or may be likely to cause any covenant or agreement of NEES under this Agreement to be breached or that renders or will render -28- untrue in any material respect any representation or warranty of NEES contained in this Agreement. NEES also will notify EUA in writing of, and will use all commercially reasonable efforts to cure before the Closing, any material violation or breach, as soon as practical after it becomes known to such party, of any representation, warranty, covenant or agreement made by NEES. No notice given pursuant to this paragraph shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein. (d) Fulfillment of Conditions. Subject to the terms and conditions of this Agreement, NEES will take or cause to be taken all commercially reasonable steps necessary or desirable and proceed diligently and in good faith to satisfy each condition to its obligations contained in this Agreement and to consummate and make effective the Merger and other transactions contemplated by this Agreement, and NEES will not, nor will it permit any of its Subsidiaries to, take or fail to take any action that could be reasonably expected to result in the nonfulfillment of any such condition. (e) Conduct of Business of LLC. Prior to the Effective Time, except as may be required by applicable law and subject to the other provisions of this Agreement, NEES shall cause LLC to (i) perform its obligations under this Agreement in accordance with its terms, and (ii) not engage directly or indirectly in any business or activities of any type or kind and not enter into any agreements or arrangements with any person, or be subject to or bound by any obligation or undertaking, which is inconsistent with this Agreement. (f) Certain Mergers. NEES shall not, and shall not permit any of its Subsidiaries to, acquire or agree to acquire by merging or consolidating with, or by purchasing a substantial portion of the assets of or equity in, or by any other manner, any business or any corporation, partnership, association or other business organization or division thereof, or otherwise acquire or agree to acquire any assets if the entering into of a definitive agreement relating to or the consummation of such acquisition, merger or consolidation could reasonably be expected to (i) impose any material delay in the obtaining of, or significantly increase the risk of not obtaining, any authorizations, consents, orders, declarations or approvals of any Governmental Authority necessary to consummate the Merger or the expiration or termination of any applicable waiting period, (ii) significantly increase the risk of any Governmental Authority entering an order prohibiting the consummation of the Merger, (iii) significantly increase the risk of not being able to remove any such order on appeal or otherwise or (iv) materially delay the consummation of the Merger. 6.03 Additional Covenants by NEES and EUA. (a) Control of Other Party's Business. Nothing contained in this Agreement shall give NEES, directly or indirectly, the right to control or direct EUA's operations prior to the Effective Time. Nothing contained in this Agreement shall give EUA, directly or indirectly, the right to control or direct NEES' operations prior to the Effective Time. Prior to the Effective Time, each of EUA and NEES shall exercise, consistent with the terms and conditions of this Agreement, complete control and supervision over its respective operations. -29- (b) Transition Steering Team. As soon as reasonably practicable after the date hereof, NEES and EUA shall create a special transition steering team, with representation from EUA and NEES, that will develop recommendations concerning the future structure and operations of EUA after the Effective Time, subject to applicable law. The members of the transition steering team shall be appointed by the Chief Executive Officers of NEES and EUA. The functions of the transition steering team shall include (i) to direct the exchange of information and documents between the parties and their Subsidiaries as contemplated by Section 7.01 and (ii) the development of regulatory plans and proposals, corporate organizational and management plans, workforce combination proposals, and such other matters as they deem appropriate. ARTICLE VII ADDITIONAL AGREEMENTS 7.01 Access to Information. EUA shall, and shall cause each of its Subsidiaries to, and shall use commercially reasonable efforts to cause EUA Associates to, throughout the period from the date hereof to the Effective Time to the extent permitted by law, (i) provide NEES and its Representatives with full access, upon reasonable prior notice and during normal business hours, to all facilities, operations, officers (including EUA's environmental, health and safety personnel), employees, agents and accountants of EUA and its Subsidiaries and Associates and their respective assets, properties, books and records, to the extent EUA or any Subsidiary of EUA or EUA Associate is not under a legal obligation not to provide access or to the extent that such access would not constitute a waiver of the attorney client privilege and does not unreasonably interfere with the business and operations of EUA and its Subsidiaries and Associates and (ii) furnish promptly to such persons (x) a copy of each report, statement, schedule and other document filed or received by EUA or any of its Subsidiaries pursuant to the requirements of federal or state securities laws and each material report, statement, schedule and other document filed with any other Governmental Authority, and (y) all other information and data (including, without limitation, copies of Contracts, EUA Employee Benefit Plans, and other books and records) concerning the business and operations of EUA and its Subsidiaries as NEES or any of its Representatives reasonably may request. No review pursuant to this Section 7.01 or otherwise shall affect any representation or warranty contained in this Agreement or any condition to the obligations of the parties hereto. Any such information or material obtained pursuant to this Section 7.01 that constitutes "Evaluation Material" (as such term is defined in the letter agreement dated as of December 18, 1998 between EUA and NEES (the "Confidentiality Agreement")) shall be governed by the terms of the Confidentiality Agreement. NEES may provide information or materials that it obtains relating to EUA or any EUA Subsidiary pursuant to this Section 7.01 to National Grid Group; the treatment by National Grid Group of such information or material shall be governed by the terms of the letter agreement dated as of December 21, 1998 between EUA and National Grid Group. 7.02 Proxy Statement. As soon as reasonably practicable after the date of this Agreement, EUA shall prepare and file the Proxy Statement with the -30- SEC. NEES and EUA shall cooperate with each other in the preparation of the Proxy Statement and any amendment or supplement thereto, and EUA shall promptly notify NEES of the receipt of any comments of the SEC with respect to the Proxy Statement and of any requests by the SEC for any amendment or supplement thereto or for additional information, and shall promptly provide to NEES copies of all correspondence between EUA or any of its Representatives and the SEC with respect to the Proxy Statement (except reports from financial advisors other than with the consent of such financial advisors). Each of the parties hereto shall furnish all information concerning itself which is required or customary for inclusion in the Proxy Statement. EUA shall consult with NEES regarding the Proxy Statement and have due regard to any comments NEES may make in relation to the Proxy Statement. EUA shall give NEES and its counsel the opportunity to review the Proxy Statement and all responses to requests for additional information by and replies to comments of the SEC before their being filed with, or sent to, the SEC. Each of EUA and NEES agrees to use its reasonable best efforts, after consultation with the other parties hereto, to respond promptly to all such comments of and requests by the SEC. After obtaining the consent of EUA, which consent shall not be unreasonably withheld, NEES may provide information supplied to NEES by EUA to National Grid Group for inclusion of such information in the Super Class 1 circular ("NGG Circular") to be issued to shareholders of National Grid Group in connection with approval by such shareholders of the National Grid Merger Agreement. NEES shall use its best efforts to provide EUA with a draft of any portion of the NGG Circular with information relating to EUA prior to the issuance of the NGG Circular. 7.03 Approval of Shareholders. EUA shall, through its Board of Trustees, duly call, give notice of, convene and hold a meeting of its shareholders (the "EUA Shareholders' Meeting") for the purpose of voting on the approval of the Merger and other transactions contemplated hereby (the "EUA Shareholders' Approval") as soon as reasonably practicable after the date hereof; provided, however, subject to the fiduciary duties of its Board of Trustees and the requirements of applicable law, EUA shall include in the Proxy Statement the recommendation of the Board of Trustees of EUA that the Shareholders of EUA approve the Merger and the other transactions contemplated hereby, and shall use its reasonable best efforts to obtain such approval. 7.04 Regulatory and Other Approvals. (a) HSR Filings. Each party hereto shall file or cause to be filed with the Federal Trade Commission and the Department of Justice any notifications required to be filed by its respective "ultimate parent" company under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"), and the rules and regulations promulgated thereunder with respect to the Merger and other transactions contemplated hereby. Such parties will use all commercially reasonable efforts to make such filings in a timely manner and to respond on a timely basis to any requests for additional information made by either of such agencies. (b) Other Regulatory Approvals. Each party shall cooperate and use its best efforts to promptly prepare and file all necessary applications, notices, petitions, filings and other documents with, and to use all commercially reasonable efforts to obtain all necessary permits, consents, approvals and authorizations of, all Governmental Authorities necessary or -31- advisable to obtain the EUA Required Statutory Approvals, the NEES Required Statutory Approvals and the approvals of the state utility commissions referred to in Section 8.01(d) (collectively, the "NEES-EUA Regulatory Approvals"). The parties agree that they will consult with each other with respect to obtaining the NEES-EUA Regulatory Approvals; provided, however, that NEES shall have primary responsibility for the preparation and filing of any related applications, filings or other material with the SEC, the FERC, the NRC and state utility commissions. EUA shall have the right to review and approve in advance drafts of and final applications, filings and other material (including material with respect to proposed settlements) submitted to or filed with the SEC, the FERC, the NRC and state utility commissions or parties to such proceedings before such Governmental Authority, which approval shall not be unreasonably withheld or delayed. (c) NEES-NGG Regulatory Proceedings. EUA and NEES acknowledge that, at the same time EUA and NEES will be seeking to obtain the NEES-EUA Regulatory Approvals, National Grid Group and NEES will be seeking to obtain the regulatory approvals (the "NEES-NGG Regulatory Approvals") required to consummate the transactions contemplated by the National Grid Merger Agreement. NEES and EUA agree to seek to prosecute the proceedings relating to the NEES-EUA Regulatory Approvals (the "NEES-EUA Regulatory Proceedings") separately from the prosecution by National Grid Group and NEES of the proceedings relating to the NEES-NGG Regulatory Approvals (the "NEES-NGG Regulatory Proceedings"), but recognize that one or more of the NEES-EUA Regulatory Proceedings may be consolidated with one or more of the NEES-NGG Regulatory Proceedings by the relevant Governmental Authority. Upon the request of EUA, NEES will keep EUA reasonably apprised of the status of the NEES-NGG Regulatory Proceedings. 7.05 Employee Benefit Plans. (a) For a period of twelve (12) months immediately following the Closing Date, the compensation, benefits and coverage provided to those non-union individuals who continue to be employees of the Surviving Entity (the "Affected Employees") pursuant to employee benefit plans or arrangements maintained by NEES or the Surviving Entity shall be, in the aggregate, not less favorable (as determined by NEES and the Surviving Entity using reasonable assumptions and benefit valuation methods) than those provided, in the aggregate, to such Affected Employees immediately prior to the Closing Date. In addition to the foregoing, NEES shall, or shall cause the Surviving Entity to, pay any Affected Employee whose employment is terminated by NEES or the Surviving Entity within twelve (12) months of the Closing Date a severance benefit package equivalent to the severance benefit package that would be provided under the NEES Standard Severance Plan as in effect on the date hereof. (b) NEES shall, or shall cause the Surviving Entity to, give the Affected Employees full credit for purposes of eligibility, vesting, benefit accrual (including, without limitation, benefit accrual under any defined benefit pension plans) and determination of the level of benefits under any employee benefit plans or arrangements maintained by NEES or the Surviving Entity in effect as of the Closing Date for such Affected Employees' service with EUA or any Subsidiary of EUA (or any prior employer) to the same extent -32- recognized by EUA or such Subsidiary immediately prior to the Closing Date. With respect to any employee benefit plan or arrangement established by NEES, EUA or the Surviving Entity after the Closing Date (the "Post Closing Plans"), service shall be credited in accordance with the terms of such Post Closing Plans. (c) NEES shall, or shall cause the Surviving Entity to, (i) waive all limitations as to preexisting conditions, exclusions and waiting periods with respect to participation and coverage requirements applicable to the Affected Employees under any welfare benefit plan established to replace any EUA welfare benefit plans in which such Affected Employees may be eligible to participate after the Closing Date, other than limitations or waiting periods that are already in effect with respect to such Affected Employees and that have not been satisfied as of the Closing Date under any welfare plan maintained for the Affected Employees immediately prior to the Closing Date, and (ii) provide each Affected Employee with credit for any co-payments and deductibles paid prior to the Closing Date in satisfying any applicable deductible or out-of-pocket requirements under any welfare plans that such Affected Employees are eligible to participate in after the Closing Date. (d)(i) NEES shall, or shall cause the Surviving Entity and its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving Entity and its Subsidiaries under, all EUA Employee Benefit Plans as in effect on the date hereof; provided, however, that this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity from exercising their rights with respect to all EUA Employee Benefit Plans solely in accordance with their terms, including but not limited to the right to alter, terminate or otherwise amend such EUA Employee Benefit Plans. (ii) NEES shall, or shall cause the Surviving Entity and its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving Entity and its Subsidiaries under, (A) all employment severance, consulting and retention agreements or arrangements as in effect on the date hereof, as set forth in Section 7.05(d)(ii) of the EUA Disclosure Letter, or as modified in accordance with Section 6.01(i) of the EUA Disclosure Letter (such agreements or arrangements, the "EUA Employee Agreements" and the individuals who are parties to such EUA Employee Agreements, the "EUA Executives") and (B) all EUA Employee Benefit Plans in which such EUA Executives participate; provided, however, that this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity from exercising their rights with respect to the EUA Employee Agreements and the EUA Employee Benefit Plans in which such EUA Executives participate, in each case solely in accordance with their terms, including but not limited to the right to alter, terminate or otherwise amend such EUA Employee Agreements and EUA Employee Benefit Plans. (e) Notwithstanding the foregoing, NEES and the Surviving Entity and its subsidiaries shall neither be required to or prevented from merging EUA's benefit plans, agreements, or arrangements into NEES or the Surviving Entity and its subsidiaries benefit plans, agreements, or arrangements or from -33- replacing EUA's benefit plans, agreements or arrangements with NEES or the Surviving Entity and its subsidiaries benefit plans, agreements or arrangements. 7.06 Labor Agreements and Workforce Matters. (a) Labor Agreements. NEES shall honor, or shall cause the appropriate subsidiaries of the Surviving Entity to honor, all collective bargaining agreements of EUA or its subsidiaries in effect as of the Effective Time until their expiration; provided, however, that this undertaking is not intended to prevent NEES or the Surviving Entity and its subsidiaries from exercising their rights with respect to such collective bargaining agreements and in accordance with their terms, including any right to amend, modify, suspend, revoke or terminate any such contract, agreement, collective bargaining agreement or commitment or portion thereof. (b) Workforce Matters. Subject to applicable law and obligations under applicable collective bargaining agreements, for a period of 2 years following the Effective Time, any reductions in workforce in respect of employees of the Surviving Entity and its Subsidiaries shall be made on a fair and equitable basis as determined by the Surviving Entity, with due consideration to prior experience and skills, and any employee whose employment is terminated or job is eliminated during such period shall be entitled to participate on a fair and equitable basis as determined by NEES or the Surviving Entity in the job opportunity and employment placement programs offered by NEES or the Surviving Entity or any of their Subsidiaries for which they are eligible. Any workforce reductions carried out following the Effective Time by the Surviving Entity and its Subsidiaries shall be done in accordance with all applicable collective bargaining agreements and all laws and regulations governing the employment relationship and termination thereof including, without limitation, the Worker Adjustment and Retraining Notification Act, and the regulations promulgated thereunder, and any comparable state or local law. 7.07 Post Merger Operations. (a) NEES Advisory Board. If the Merger is consummated, then, promptly following the closing of the merger contemplated by the National Grid Merger Agreement, NEES shall take such action as is necessary to cause all of the members of the Board of Directors of EUA to be appointed to serve on the advisory board to be formed pursuant to Section 7.07(e) of the National Grid Merger Agreement. (b) Charities. The parties agree that provision of charitable contribution and community support within the New England region serves a number of important goals. After the Effective Time, NEES intends to cause the Surviving Entity to provide charitable contributions and community support within the New England region at annual levels substantially comparable to the annual level of charitable contributions and community support provided, directly or indirectly, by EUA and its public utility subsidiaries within the New England region during 1998. -34- 7.08 No Solicitations. Prior to the Effective Time, EUA agrees: (a) that neither it nor any of its Subsidiaries shall, and it shall use its best efforts to cause its Representatives (as defined in Section 10.10) not to, knowingly initiate, solicit or encourage, directly or indirectly, any inquiries or any proposal or offer (including, without limitation, any proposal or offer to its Shareholders) with respect to a merger, consolidation or other business combination including EUA or any of its significant Subsidiaries (as defined in Rule 1-02(W) of Regulation S-X promulgated under the Exchange Act) other than EUA Cogenex Corporation (an "EUA Significant Subsidiary"), or any acquisition or similar transaction (including, without limitation, a tender or exchange offer) involving the purchase of (i) all or any significant portion of the assets of EUA and its Subsidiaries taken as a whole, (ii) ten percent or more of the outstanding EUA Shares or (iii) 50% or more of the outstanding shares of the capital stock of any EUA Significant Subsidiary (any such proposal or offer being hereinafter referred to as an "Alternative Proposal"), or engage in any negotiations concerning, or provide any confidential information or data to, or have any other discussions with, any person or group relating to an Alternative Proposal, or otherwise knowingly facilitate any effort or attempt to make or implement an Alternative Proposal other than from NEES and its affiliates; (b) that it will immediately cease and cause to be terminated any existing activities, discussions or negotiations with any parties with respect to any Alternative Proposal; and (c) that it will notify NEES immediately if any such inquiries, proposals or offers are received by, any such information is requested from, or any such negotiations or discussions are sought to be initiated or continued with, it or any of such persons; provided, however, that, prior to receipt of the EUA Shareholders' Approval, nothing contained in this Section 7.08 shall prohibit the Board of Trustees of EUA from (i) furnishing information to (but only pursuant to a confidentiality agreement in customary form and having terms and conditions no less favorable to EUA than the Confidentiality Agreement (as defined in Section 7.01)) or entering into discussions or negotiations with any person or group that makes an unsolicited Alternative Proposal, if, and only to the extent that, (A) the Board of Trustees of EUA, based upon advice of outside counsel with respect to fiduciary duties, determines in good faith that such action is necessary for the Board of Trustees to act in a manner consistent with its fiduciary duties to Shareholders under applicable law, (B) the Board of Trustees of EUA has reasonably concluded in good faith (after consultation with its financial advisors) that the person or group making such Alternative Proposal will have adequate sources of financing to consummate such Alternative Proposal and that such Alternative Proposal is likely to be more favorable to EUA's shareholders than the Merger, (C) prior to furnishing such information to, or entering into discussions or negotiations with, such person or group, EUA provides written notice to NEES to the effect that it is furnishing information to, or entering into discussions or negotiations with, such person or group, which notice shall identify such person or group and the material terms of the Alternative Proposal in reasonable detail, and (D) EUA keeps NEES promptly informed of the status and all material information with respect to any such discussions or negotiations; and (ii) to the extent required, complying with Rule 14e-2 promulgated under the Exchange Act with regard to an Alternative Proposal. Nothing in this Section 7.08 shall (x) permit EUA to terminate this Agreement (except as specifically provided in Article IX), (y) permit EUA to enter into any agreement with respect to an Alternative Proposal for so long as this Agreement remains in effect (it being agreed that for so long as this Agreement remains in effect, EUA shall not enter -35- into any agreement with any person or group that provides for, or in any way knowingly facilitates, an Alternative Proposal (other than a confidentiality agreement under the circumstances described above)), or (z) affect any other obligation of EUA under this Agreement. 7.09 Directors' and Officers' Indemnification and Insurance. (a) Indemnification. To the extent, if any, not provided by an existing right of indemnification or other agreement or policy, from and after the Effective Time, NEES shall, or shall cause the Surviving Entity to, to the fullest extent permitted by applicable law, indemnify, defend and hold harmless each person who is now, or has been at any time prior to the date hereof, or who becomes prior to the Effective Time, (x) an officer, trustee or director or (y) an employee covered as of the date hereof (to the extent of the coverage extended as of the date hereof) of EUA or any Subsidiary of EUA (each an "Indemnified Party," and collectively, the "Indemnified Parties") against (i) all losses, expenses (including reasonable attorney's fees and expenses), claims, damages or liabilities or, subject to the first proviso of the next succeeding sentence, amounts paid in settlement, arising out of actions or omissions occurring at or prior to the Effective Time (and whether asserted or claimed prior to, at or after the Effective Time) that are, in whole or in part, based on or arising out of the fact that such person is or was a director, trustee, officer or employee of EUA or any Subsidiary of EUA (the "Indemnified Liabilities"), and (ii) all Indemnified Liabilities to the extent they are based on or arise out of or pertain to the transactions contemplated by this Agreement, in each case, to the extent permitted by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter. In the event of any such loss, expense, claim, damage or liability (whether or not arising before the Effective Time), (i) NEES shall, or shall cause the Surviving Entity to, pay the reasonable fees and expenses of counsel selected by the Indemnified Parties, which counsel shall be reasonably satisfactory to NEES or the Surviving Entity, as appropriate, promptly after statements therefor are received and otherwise advance to such Indemnified Party upon request, reimbursement of documented expenses reasonably incurred, in either case to the extent not prohibited by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter upon receipt of an undertaking by or on behalf of such director, trustee or officer to repay such amounts as and to the extent required by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter, (ii) the Surviving Entity shall cooperate in the defense of any such matter and (iii) any determination required to be made with respect to whether an Indemnified Party's conduct complies with the standards set forth under the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter and the certificate of incorporation or by-laws or similar governing documents of the Surviving Entity shall be made by independent counsel mutually acceptable to the Surviving Entity and the Indemnified Party; provided, however, that the Surviving Entity shall not be liable for any settlement effected without its written consent (which consent shall not be unreasonably withheld) and provided further that no indemnification shall be made if such indemnification is prohibited by the EUA Trust Agreement or the indemnification agreements set forth in Section 7.09 of the EUA Disclosure Letter. -36- (b) Insurance. For a period of six years after the Effective Time, NEES and the Surviving Entity at NEES's election, (i) shall cause to be maintained in effect an extended reporting period for current policies of directors' and officers' liability insurance for the benefit of such persons who are currently covered by such policies of EUA on terms no less favorable than the terms of such current insurance coverage or (ii) shall provide tail coverage for such persons which provides such persons with coverage for a period of six years for acts prior to the Effective Time on terms no less favorable than the terms of such current insurance coverage. (c) Successors. In the event the Surviving Entity or any of its successors or assigns (i) consolidates with or merges into any other person or entity and shall not be the continuing or surviving corporation or entity of such consolidation or merger or (ii) transfers all or substantially all of its properties and assets to any person or entity, then and in either such case, proper provisions shall be made so that the successors and assigns of the Surviving Entity, as applicable, shall assume the obligations set forth in this Section 7.09. (d) Survival of Indemnification. To the fullest extent permitted by law, from and after the Effective Time, all rights to indemnification as of the date hereof in favor of the employees, agents, directors, trustees and officers of EUA and EUA's Subsidiaries with respect to their activities as such prior to the Effective Time, as provided in the EUA Trust Agreement or the respective certificates of incorporation and by-laws or similar governing documents in effect on the date hereof, or otherwise in effect on the date hereof, shall survive the Merger and shall continue in full force and effect for a period of not less than six years from the Effective Time. (e) Benefit. The provisions of this Section 7.09 are intended to be for the benefit of, and shall be enforceable by, each Indemnified Party, his or her heirs and his or her representatives. (f) Amendment of the EUA Trust Agreement. NEES shall not, and shall ensure that the Surviving Entity shall not, amend the EUA Trust Agreement to in any way limit the indemnification provided to the Indemnified Parties under this Section 7.09. 7.10 Expenses. Except as set forth in Section 9.03, whether or not the Merger is consummated, all costs and expenses incurred in connection with the Merger and other transactions contemplated hereby shall be paid by the party incurring such cost or expense, except that the filing fees in connection with the filings required under the HSR Act and the 1935 Act shall be paid by NEES. 7.11 Brokers or Finders. EUA represents, as to itself and its affiliates, that no agent, broker, investment banker, financial advisor or other firm or person is or will be entitled to any broker's, finder's or investment banker's fee or any other commission or similar fee in connection with the Merger and other transactions contemplated by this Agreement except Salomon Smith Barney Inc., whose fees and expenses will be paid by EUA in accordance with EUA's agreement with such firm, and EUA shall indemnify and hold NEES harmless from and against any and all claims, liabilities or obligations with -37- respect to any other such fee or commission or expenses related thereto asserted by any person on the basis of any act or statement alleged to have been made by EUA or its affiliates. 7.12 Anti-Takeover Statutes. If any "fair price", "moratorium", "business combination", "control share acquisition" or other form of anti-takeover statute or regulation shall become applicable to the Merger or other transactions contemplated hereby, EUA and the members of the Board of Trustees of EUA shall grant such approvals and take such actions consistent with their fiduciary duties and in accordance with applicable law as are reasonably necessary so that the Merger and other transactions contemplated hereby may be consummated as promptly as practicable on the terms contemplated hereby and otherwise act to eliminate or minimize the effects of such statute or regulation on the Merger and other transactions contemplated hereby. 7.13 Public Announcements. Except as otherwise required by law or the rules of any applicable securities exchange or national market system or any other Regulatory Authority, so long as this Agreement is in effect, NEES and EUA will not, and will not permit any of their respective Subsidiaries or Representatives to, issue or cause the publication of any press release or make any other public announcement with respect to the Merger and other transactions contemplated by this Agreement without the consent of the other party, which consent shall not be unreasonably withheld. NEES and EUA will cooperate with each other in the development and distribution of all press releases and other public announcements with respect to the Merger and other transactions contemplated hereby, and will furnish the other with drafts of any such releases and announcements as far in advance as practicable. 7.14 Restructuring of the Merger. It may be preferable to effectuate a business combination between NEES and EUA by means of an alternative structure to the Merger. Accordingly, if, prior to satisfaction of the conditions contained in Article VIII hereto, NEES proposes the adoption of an alternative structure that otherwise substantially preserves for NEES and EUA the economic benefits of the Merger and will not materially delay the consummation thereof, then the parties shall use their respective best efforts to effect a business combination among themselves by means of a mutually agreed upon structure other than the Merger that so preserves such benefits; provided, however, that prior to closing any such restructured transaction, all material third party and Governmental Authority declarations, filings, registrations, notices, authorizations, consents or approvals necessary for the effectuation of such alternative business combination shall have been obtained and all other conditions to the parties' obligations to consummate the Merger and other transactions contemplated hereby, as applied to such alternative business combination, shall have been satisfied or waived. -38- ARTICLE VIII CONDITIONS 8.01 Conditions to Each Party's Obligation to Effect the Merger. The respective obligation of each party to effect the Merger and other transactions contemplated hereby is subject to the satisfaction or waiver, at or prior to the Closing, of each of the following conditions: (a) Shareholder Approval. EUA Shareholders' Approval shall have been obtained. (b) HSR Act. Any waiting period (and any extension thereof) applicable to the consummation of the Merger under HSR shall have expired or been terminated. (c) Injunctions or Restraints. No court of competent jurisdiction or other competent Governmental Authority shall have enacted, issued, promulgated, enforced or entered any law or order (whether temporary, preliminary or permanent) which is then in effect and has the effect of making illegal or otherwise restricting, preventing or prohibiting consummation of the Merger or other transactions contemplated hereby. (d) Governmental and Regulatory and Other Consents and Approvals. The NEES Required Statutory Approvals and EUA Required Statutory Approvals shall have been obtained prior to the Effective Time, and shall have become Final Orders (as hereinafter defined). The Final Orders shall not, individually or in the aggregate, impose terms and conditions that (i) could reasonably be expected to have an EUA Material Adverse Effect; (ii) could reasonably be expected to have a NEES Material Adverse Effect; or (iii) materially impair the ability of the parties to complete the Merger. The parties shall have received Final Orders from the Massachusetts Department of Telecommunications and Energy and the Rhode Island Public Utilities Commission pertaining to the recovery of costs (including, without limitation, transaction premium and integration costs) associated with the Merger that are materially consistent with existing policy and previous orders of such agencies. "Final Order" for all purposes of this Agreement means action by the relevant regulatory authority which has not been reversed, stayed, enjoined, set aside, annulled or suspended with respect to which any waiting period prescribed by law before the Merger and other transactions contemplated hereby may be consummated has expired, and as to which all conditions to be satisfied before the consummation of such transactions prescribed by law, regulation or order have been satisfied. 8.02 Conditions to Obligation of NEES and LLC to Effect the Merger. The obligation of NEES and LLC to effect the Merger and other transactions contemplated hereby is further subject to the satisfaction or waiver at or prior to the Closing, of each of the following additional conditions (all or any of which may be waived in whole or in part by NEES and LLC in the sole discretion): -39- (a) Representations and Warranties. The representations and warranties made by EUA in this Agreement, in each case made as if none of such representations or warranties contained any qualification or limitation as to "materiality" or "EUA Material Adverse Effect", shall be true and correct as so made as of the Closing Date as though so made on and as of the Closing Date, except to the extent expressly given as of a specified date, except where the failure of such representations and warranties to be true and correct as so made does not have and could not reasonably be expected to have, individually or in the aggregate, an EUA Material Adverse Effect, and EUA shall have delivered to NEES a certificate, dated the Closing Date and executed in the name and on behalf of EUA by its Chairman of the Board, President or any Executive or Senior Vice President, to such effect. (b) Performance of Obligations. EUA shall have performed and complied with, in all material respects, each agreement, covenant and obligation required by this Agreement to be so performed or complied with by EUA at or prior to the Closing, and EUA shall have delivered to NEES a certificate, dated the Closing Date and executed in the name and on behalf of EUA by its Chairman of the Board, President or any Executive or Senior Vice President, to such effect. (c) Material Adverse Effect. No EUA Material Adverse Effect shall have occurred and there shall exist no facts or circumstances which in the aggregate could reasonably be expected to have an EUA Material Adverse Effect. (d) EUA Required Consents. All EUA Required Consents shall have been obtained by EUA, except where the failure to receive such EUA Required Consents could not reasonably be expected to (i) have an EUA Material Adverse Effect, or (ii) delay or prevent the consummation of the Merger and other transactions contemplated hereby. 8.03 Conditions to Obligation of EUA to Effect the Merger. The obligation of EUA to effect the Merger and other transactions contemplated hereby is further subject to the satisfaction or waiver, at or prior to the Closing, of each of the following additional conditions (all or any of which may be waived in whole or in part by EUA in its sole discretion): (a) Representations and Warranties. The representations and warranties made by NEES and LLC in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.07, 5.08 and 5.09 of this Agreement, in each case made as if none of such representations or warranties contained any qualification or limitation as to "materiality" or "NEES Material Adverse Effect," shall be true and correct as so made as of the Closing Date, except to the extent expressly given as of a specified date and except where the failure of such representations and warranties to be so true and correct as so made does not have and could not reasonably be expected to have, individually or in the aggregate, a NEES Material Adverse Effect or a material adverse effect on LLC, and NEES and LLC shall each have delivered to EUA a certificate, dated the Closing Date and executed in the name and on behalf of NEES by any director of NEES and in the name and on behalf of LLC by a member of its management committee its Chairman of the Board, President or any Executive or Senior Vice President to such effect. -40- (b) NEES Required Consents. All NEES Required Consents shall have been obtained by NEES, except where the failure to receive such NEES Required Consents could not reasonably be expected to (i) have a NEES Material Adverse Effect or (ii) delay or prevent the consummation of the Merger and other transactions contemplated hereby. (c) Performance of Obligations. NEES and LLC shall have performed and complied with, in all material respects, each agreement, covenant and obligation required by this Agreement to be so performed or complied with by NEES or LLC at or prior to the Closing, and NEES and LLC shall each have delivered to EUA a certificate, dated the Closing Date and executed in the name and on behalf of NEES by its Chairman of the Board, President or any Executive or Senior Vice President, or on behalf of LLC by a member of its management committee to such effect. ARTICLE IX TERMINATION, AMENDMENT AND WAIVER 9.01 Termination. This Agreement may be terminated, and the Merger and other transactions contemplated hereby may be abandoned, at any time prior to the Effective Time, whether prior to or after EUA Shareholders' Approval (except as otherwise provided in Section 9.01(c) below): (a) By mutual written agreement of the Board of Directors of NEES and Board of Trustees of EUA, respectively; (b) By EUA or NEES, by written notice to the other, if the Closing Date shall not have occurred on or before December 31, 1999 (the "Initial Termination Date"); provided, however, that the right to terminate the Agreement under this Section 9.01(b) shall not be available to any party whose failure to fulfill any obligation under this Agreement has been the cause of, or resulted in, the failure of the Effective Time to occur on or before such date; and provided, further, that if on the Initial Termination Date the conditions to the Closing set forth in Section 8.01(d) shall not have been fulfilled but all other conditions to the Closing shall be fulfilled or shall be capable of being fulfilled, then the Initial Termination Date shall be extended for four (4) months beyond the Initial Termination Date (the "Extended Termination Date"); (c) By NEES, by written notice to EUA, if EUA Shareholders' Approval shall not have been obtained at a duly held meeting of such Shareholders, including any adjournments thereof; (d) By EUA or NEES, if any applicable state or federal law or applicable law of a foreign jurisdiction or any order, rule or regulation is adopted or issued that has the effect, as supported by the written opinion of outside counsel for such party, of prohibiting the Merger or other transactions contemplated hereby, or if any court of competent jurisdiction or any Governmental Authority shall have issued a nonappealable final order, judgment -41- or ruling or taken any other action having the effect of permanently restraining, enjoining or otherwise prohibiting the Merger or other transactions contemplated hereby (provided that the right to terminate this Agreement under this Section 9.01(d) shall not be available to any party that has not defended such lawsuit or other legal proceeding (including seeking to have any stay or temporary restraining order entered by any court or other Governmental Authority vacated or reversed)). (e) By EUA upon ten (10) days' prior notice to NEES if the Board of Trustees of EUA determines in good faith, that termination of this Agreement is necessary for the Board of Trustees of EUA to act in a manner consistent with its fiduciary duties to Shareholders under applicable law by reason of an unsolicited Alternative Proposal meeting the requirements of clauses (A) and (B) of Section 7.08 having been made; provided that (A) The Board of Trustees of EUA shall determine based on advice of outside counsel with respect to the Board of Trustees' fiduciary duties that notwithstanding a binding commitment to consummate an agreement of the nature of this Agreement entered into in the proper exercise of its applicable fiduciary duties, and notwithstanding all concessions which may be offered by NEES in negotiation entered into pursuant to clause (B) below, it is necessary pursuant to such fiduciary duties that the trustees reconsider such commitment as a result of such Alternative Proposal, and (B) prior to any such termination, EUA shall, and shall cause its respective financial and legal advisors to, negotiate with NEES to make such adjustments in the terms and conditions of this Agreement as would enable EUA to proceed with the Merger or other transactions contemplated hereby on such adjusted terms; and provided further that EUA's ability to terminate this Agreement pursuant to this Section 9.01(e) is conditioned upon the concurrent payment by EUA to NEES of any amounts owed by it pursuant to Section 9.03(a); (f) By EUA, by written notice to NEES, if (i) there shall have been any material breach of any representation or warranty, or any material breach of any covenant or agreement, of NEES hereunder (other than a breach described in clause (ii)), and such breach shall not have been remedied within twenty (20) days after receipt by NEES of notice in writing from EUA, specifying the nature of such breach and requesting that it be remedied; or (ii) NEES shall fail to deliver or cause to be delivered the amount of cash to the Paying Agent required pursuant to Section 2.02(a) at a time when all conditions to NEES's obligation to close have been satisfied or otherwise waived in writing by NEES. (g) By NEES, by written notice to EUA, if (i) there shall have been any material breach of any representation or warranty, or any material breach of any covenant or agreement, of EUA hereunder, and such breach shall not -42- have been remedied within twenty (20) days after receipt by EUA of notice in writing from NEES, specifying the nature of such breach and requesting that it be remedied; or (ii) the Board of Trustees of EUA (A) shall withdraw or modify in any manner adverse to NEES its approval of the Merger and other transactions contemplated hereby or its recommendation to its shareholders regarding the approval of this Agreement, the Merger and other transactions contemplated hereby, (B) shall approve or recommend or take no position with respect to an Alternative Proposal or (C) shall resolve to take any of the actions specified in clause (A) or (B). 9.02 Effect of Termination. If this Agreement is validly terminated by either EUA or NEES pursuant to Section 9.01, this Agreement shall forthwith become null and void and there shall be no liability or obligation on the part of either EUA or NEES (or any of their respective Representatives or affiliates), except that the provisions of this Section 9.02, Sections 7.10, 7.11 and 7.13, Section 9.03 and Sections 10.09 and 10.10 shall continue to apply following any such termination. 9.03 Termination Fees. (a) In the event that (i) this Agreement is terminated by EUA pursuant to Section 9.01(e) or (ii) any person or group shall have made an Alternative Proposal that has not been withdrawn and this Agreement is terminated by (A) NEES pursuant to Section 9.01(c) or Section 9.01(g) or (B) by EUA pursuant to Section 9.01(b) and, in the case of this clause (ii) only, a definitive agreement with respect to such Alternative Proposal is executed within two years after such termination, then EUA shall pay to NEES, by wire transfer of same day funds, either on the date contemplated in Section 9.01(e) if applicable, or otherwise, within five (5) business days after such termination, a termination fee of $20 million, plus an amount equal to all documented out-of-pocket expenses and fees incurred by NEES arising out of, or in connection with or related to, the Merger and other transactions contemplated hereby, not in excess of $5 million in the aggregate. (b) In the event that this Agreement is terminated by either NEES or EUA pursuant to Section 9.01(b) and at the time of such termination (i) the conditions to the Closing set forth in Section 8.01(d) shall not have been fulfilled, (ii) if the date of termination is any date other than a date which is on or after the Extended Termination Date, all conditions contained in Article VIII other than Sections 8.01(d) or 8.03(c) shall have been fulfilled or are capable of being fulfilled as of such date, and (iii) the merger contemplated by the National Grid Merger Agreement has not yet been consummated, then NEES shall pay to EUA, by wire transfer of same day funds, within five (5) business days after such termination, a termination fee of $10 million, plus an amount equal to all documented out-of-pocket expenses and fees incurred by EUA arising out of, or in connection with or related to, the Merger and other transactions contemplated hereby, not in excess of $5 million in the aggregate. (c) Nature of Fees. The parties agree that the agreements contained in this Section 9.03 are an integral part of the Merger and the other transactions contemplated hereby and constitute liquidated damages and not a penalty. The parties further agree that if any party is or becomes obligated to pay a termination fee pursuant to Sections 9.03(a) or (b), the right to receive such termination fee shall be the sole remedy of the other party with respect to -43- the facts and circumstances giving rise to such payment obligation. If this Agreement is terminated by a party as a result of a willful breach of a representation, warranty, covenant or agreement by the other party, including a termination pursuant to Section 9.01(f)(ii), the non-breaching party may pursue any remedies available to it at law or in equity and shall be entitled to recover any additional amounts thereunder. Notwithstanding anything to the contrary contained in this Section 9.03, if one party fails to promptly pay to the other any fee or expense due under this Section 9.03, in addition to any amounts paid or payable pursuant to such Section, the defaulting party shall pay the costs and expenses (including legal fees and expenses) in connection with any action, including the filing of any lawsuit or other legal action, taken to collect payment, together with interest on the amount of any unpaid fee at the publicly announced prime rate of Citibank, N.A. from the date such fee was required to be paid. 9.04 Amendment. This Agreement may be amended, supplemented or modified by action taken by or on behalf of the Board of Directors of NEES or the Board of Trustees of EUA at any time prior to the Effective Time, whether prior to or after EUA Shareholders' Approval shall have been obtained, but after such adoption and approval only to the extent permitted by applicable law. No such amendment, supplement or modification shall be effective unless set forth in a written instrument duly executed and delivered by or on behalf of each party hereto. 9.05 Waiver. At any time prior to the Effective Time, NEES or EUA, by action taken by or on behalf of its Board of Directors or Board of Trustees, respectively, may to the extent permitted by applicable law (i) extend the time for the performance of any of the obligations or other acts of the other parties hereto, (ii) waive any inaccuracies in the representations and warranties of the other parties hereto contained herein or in any document delivered pursuant hereto or (iii) waive compliance with any of the covenants, agreements or conditions of the other parties hereto contained herein. No such extension or waiver shall be effective unless set forth in a written instrument duly executed by or on behalf of the party extending the time of performance or waiving any such inaccuracy or non-compliance. No waiver by any party of any term or condition of this Agreement, in any one or more instances, shall be deemed to be or construed as a waiver of the same or any other term or condition of this Agreement on any future occasion. ARTICLE X GENERAL PROVISIONS 10.01 Non-Survival of Representations, Warranties, Covenants and Agreements. The representations, warranties, covenants and agreements contained in this Agreement or in any instrument delivered pursuant to this Agreement shall not survive the Merger but shall terminate at the Effective Time, except for the agreements contained in Article I and Article II, in Sections 7.05, 7.06, 7.08, 7.09 and 7.10, this Article X which shall survive the Effective Time. 10.02 Notices. All notices, requests and other communications hereunder must be in writing and will be deemed to have been duly given only if -44- delivered personally or by facsimile transmission or sent by overnight courier (providing proof of delivery) to the parties at the following addresses or facsimile numbers: If to NEES or LLC, to: New England Electric System 25 Research Drive Westborough, MA 01582 Attn: Richard P. Sergel President and Chief Executive Officer Telephone: (508) 389-2764 Facsimile: (508) 366-5498 with a copy to: Skadden, Arps, Slate, Meagher & Flom LLP 919 Third Avenue New York, NY 10022 Attn: Sheldon S. Adler, Esq. Telephone: (212) 735-3000 Facsimile: (212) 735-2000 If to EUA, to: Eastern Utilities Associates One Liberty Square Boston, MA 02109 Attn: Donald G. Pardus Chairman and Chief Executive Officer Telephone: (617) 357-9590 Facsimile: (617) 357-7320 with a copy to: Winthrop, Stimson, Putnam & Roberts 1 Battery Park Plaza New York, NY 10004 Attn: David P. Falck Telephone: (212) 858-1000 Facsimile: (212) 858-1500 All such notices, requests and other communications will (i) if delivered personally to the address as provided in this Section, be deemed given -45- upon delivery, (ii) if delivered by facsimile transmission to the facsimile number as provided in this Section, be deemed given when sent, provided that the facsimile is promptly confirmed by telephone confirmation thereof, and (iii) if delivered by mail in the manner described above to the address as provided in this Section, be deemed given one business day after delivery (in each case regardless of whether such notice, request or other communication is received by any other person to whom a copy of such notice, request or other communication is to be delivered pursuant to this Section). Any party from time to time may change its address, facsimile number or other information for the purpose of notices to that party by giving notice specifying such change to the other parties hereto. 10.03 Entire Agreement; Incorporation of Exhibits. (a) This Agreement supersedes all prior discussions and agreements, both written and oral, among the parties hereto with respect to the subject matter hereof, other than the Confidentiality Agreement, which shall survive the execution and delivery of this Agreement in accordance with its terms, and contains, together with the Confidentiality Agreement, the sole and entire agreement among the parties hereto with respect to the subject matter hereof. (b) The EUA Disclosure Letter, the NEES Disclosure Letter and any Exhibit attached to this Agreement and referred to herein are hereby incorporated herein and made a part hereof for all purposes as if fully set forth herein. 10.04 No Third Party Beneficiary. The terms and provisions of this Agreement are intended solely for the benefit of each party hereto and their respective successors or permitted assigns, and except as provided in Article II and Sections 7.04, 7.05(d)(ii) and 7.09 (which is intended to be for the benefit of the persons entitled to therein, and may be enforced by any of such persons), it is not the intention of the parties to confer third-party beneficiary rights upon any other person. 10.05 No Assignment; Binding Effect. Neither this Agreement nor any right, interest or obligation hereunder may be assigned, in whole or in part, by operation of law or otherwise, by any party hereto without the prior written consent of the other parties hereto and any attempt to do so will be void, except that LLC may assign any or all of its rights, interests and obligations hereunder to another direct or indirect wholly owned Subsidiary of NEES, provided that any such Subsidiary agrees in writing to be bound by all of the terms, conditions and provisions contained herein and provided further that such assignment (i) does not require a greater vote for EUA's Shareholder Approval, (ii) does not require a subsequent vote following EUA's Shareholders Meeting, or (iii) is not reasonably likely to materially delay or prevent EUA, LLC and NEES, as appropriate, from obtaining EUA Required Statutory Approvals, EUA Required Consents, EUA Shareholders' Approval, the NEES Required Shareholders' Approvals, or the NEES Required Consents. Subject to the preceding sentence, this Agreement is binding upon, inures to the benefit of and is enforceable by the parties hereto and their respective successors and assigns. -46- 10.06 Headings. The headings used in this Agreement have been inserted for convenience of reference only and do not define, modify or limit the provisions hereof. 10.07 Invalid Provisions. If any provision of this Agreement is held to be illegal, invalid or unenforceable under any present or future law or order, and if the rights or obligations of any party hereto under this Agreement will not be materially and adversely affected thereby, (i) such provision will be fully severable, (ii) this Agreement will be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, and (iii) the remaining provisions of this Agreement will remain in full force and effect and will not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom. 10.08 Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the Commonwealth of Massachusetts. 10.09 Enforcement of Agreement. The parties hereto agree that irreparable damage would occur in the event that any of the provisions of this Agreement was not performed in accordance with its specified terms or was otherwise breached. It is accordingly agreed that the parties shall be entitled to an injunction or injunctions to prevent breaches of this Agreement and to enforce specifically the terms and provisions hereof in any court of competent jurisdiction, this being in addition to any other remedy to which they are entitled at law or in equity. 10.10 Certain Definitions. As used in this Agreement: (a) except as provided in Section 4.14, the term "affiliate," as applied to any person, shall mean any other person directly or indirectly controlling, controlled by, or under common control with, that person; for purposes of this definition, "control" (including, with correlative meanings, the terms "controlling," "controlled by" and "under common control with"), as applied to any person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of that person, whether through the ownership of voting securities, by contract or otherwise; (b) a person will be deemed to "beneficially" own securities if such person would be the beneficial owner of such securities under Rule 13d-3 under the Exchange Act, including securities which such person has the right to acquire (whether such right is exercisable immediately or only after the passage of time); (c) the term "business day" means a day other than Saturday, Sunday or any day on which banks located in the Massachusetts are authorized or obligated to close; (d) the term "knowledge" or any similar formulation of "knowledge" shall mean, with respect to any party hereto, the actual knowledge after due inquiry of the executive officers of NEES and its Subsidiaries or EUA and its Subsidiaries, respectively, set forth in Section 10.11(d) of the NEES Disclosure Letter or Section 10.11(d) of the EUA Disclosure Letter; provided -47- that as used in Section 4.13 the term "knowledge" shall also include the knowledge of the environmental, health and safety personnel of EUA; (e) the term "person" shall include individuals, corporations, partnerships, trusts, limited liability companies, other entities and groups (which term shall include a "group" as such term is defined in Section 13(d)(3) of the Exchange Act); (f) the "Representatives" of any entity shall have the same meaning as set forth in the Confidentiality Agreement; (g) the term "Subsidiary" means any corporation or other entity, whether incorporated or unincorporated, in which such party directly or indirectly owns at least a majority of the voting power represented by the outstanding capital stock or other voting securities or interests having voting power under ordinary circumstances to elect a majority of the directors or similar members of the governing body, or otherwise to direct the management and policies, or such corporation or entity. 10.11 Counterparts. This Agreement may be executed in any number of counterparts, each of which will be deemed an original, but all of which together will constitute one and the same instrument and will become effective when one or more counterparts have been signed by each party and delivered to the other parties. 10.12 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION. -48- IN WITNESS WHEREOF, each party hereto has caused this Agreement to be signed by its officer thereunto duly authorized as of the date first above written. NEW ENGLAND ELECTRIC SYSTEM By: /s/ Richard P. Sergel ----------------------------------- Name: Richard P. Sergel Title: President and CEO The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer, or agent thereof assumes or shall be held to any liability therefor. EASTERN UTILITIES ASSOCIATES By: /s/ Donald G. Pardus ----------------------------------- Name: Donald G. Pardus Title: Chairman The name "Eastern Utilities Associates" is the designation of the Trustees of EUA for the time being in their collective capacity but not personally, under a Declaration of Trust dated April 2, 1928, as amended, a copy of which amended Declaration of Trust has been filed in the office of the Secretary of The Commonwealth of Massachusetts and elsewhere as required by law; and all persons dealing with EUA must look solely to the trust property for the enforcement of any claim against EUA, as neither the Trustees nor the officers or shareholders of EUA assume any personal liability for obligations entered into on behalf of EUA. RESEARCH DRIVE LLC By: /s/ John G. Cochrane ----------------------------------- Name: John G. Cochrane Title: Manager -49- Tab 2 CONSENT AGREEMENT dated as of February 1, 1999 CONSENT AGREEMENT This Consent Agreement (the "Agreement") is entered into as of February 1, 1999 between The National Grid Group, p1c, a public limited company incorporated under the laws of England and Wales ("NGG") and New England Electric System, a Massachusetts business trust ("NEES"). WHEREAS, NGG, NEES and NGG Holdings LLC (formerly Iosta LLC), a wholly owned subsidiary of NGG, entered into an Agreement and Plan of Merger dated as of December 11, 1998 (the"Merger Agreement") pursuant to which NGG Holdings LLC will merge (the "Merger") with and into NEES with NEES being the surviving entity and becoming a wholly owned subsidiary of NGG; WHEREAS, NEES, Eastern Utilities Associates, a Massachusetts Business Trust ("EUA") and Research Drive LLC are proposing to enter into an Agreement and Plan of Merger in the form attached hereto as Exhibit A (the "EUA Merger Agreement") providing for the merger (the "EUA Merger") of Research Drive LLC with and into EUA with EUA being the surviving entity and becoming a wholly owned subsidiary of NEES; and WHEREAS, pursuant to the provisions of the Merger Agreement, NEES is required to obtain the consent of NGG before entering into the EUA Merger Agreement and with respect to certain actions relating to the consummation of the transactions set forth therein. NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows: 1. Consent to EUA Merger Agreement. Subject to the terms and conditions of this Consent, NGG hereby consents to NEES entering into the EUA Merger Agreement with EUA in the form set forth in Exhibit A and agrees that, subject to the immediately following sentence, the consummation by NEES of the transactions contemplated by the EUA Merger Agreement in accordance with the term thereof shall not constitute a breach by NEES of the terms of the Merger Agreement. NEES and NGG acknowledge that the financing necessary to consummate the EUA Merger was not contemplated when NEES and NGG agreed to the limitations set forth in Article VI of the Merger Agreement and NGG consents to such financing provided that such financing is consistent with the financing parameters set forth on Exhibit B hereto. NGG also consents to the formation and capitalization of Research Drive LLC by NEES for the purpose of effecting the EUA Merger as contemplated in the EUA Merger Agreement. 2. Access to Information. Subject to the following sentence, NEES hereby agrees to provide NGG with reasonable access to any information it receives regarding EUA pursuant to the terms of the EUA Merger Agreement and to consult with NGG on a regular basis concerning the status of EUA and the EUA Merger. NGG hereby acknowledges that any such material that is "Evaluation Material" (as such term is defined in the letter agreement dated as of December 21, 1998 between NGG and NEES (the "Confidentiality Agreement") shall be governed by the terms of the Confidentiality Agreement. 3. Regulatory Filings. NEES hereby agrees that NGG shall have the right to review in advance, and that NEES will consult with NGG and give due regard to NGG's views concerning, any applications, notices, petitions, filings and other documents filed with any Governmental Authority (as defined in the EUA Merger Agreement) in connection with the EUA Merger which could reasonably be expected to have a material adverse effect on NGG's or NEES' ability to consummate the Merger or which could reasonably be expected to adversely affect in any material manner any material benefit of the Merger to NGG or NEES. 4. Amendments to EUA Merger Agreement. NEES hereby agrees that it will not, without the prior written consent of NGG, amend or modify the EUA Merger Agreement in any material respect, including, without limitation, amend or otherwise modify any provision of the EUA Merger Agreement providing for or relating to the amount, type or structure of the Merger Consideration (as defined in the EUA Merger Agreement) or agree to any additional or different amount, type or structure for the Merger Consideration (as so defined). 5. Acknowledgment. NGG and NEES acknowledge and agree that the covenants set forth in Article VI of the Merger Agreement do not reflect the operations of EUA if the EUA Merger is consummated prior to the Effective Time (as defined in the Merger Agreement). In the event that the EUA Merger is consummated prior to the Effective Time, NGG and NEES hereby agree to negotiate in good faith to make appropriate modifications to such covenants set forth in Section 6.01 of the Merger Agreement to reflect the operations of EUA. 6. Termination and Amendment. This Consent Agreement and the obligations of NEES hereunder shall terminate upon the earlier to occur of (i) the termination of the Merger Agreement, (ii) the EUA Merger and (iii) the Merger, in each case without any further action by the parties hereto. Except as provided in the preceding sentence, this Consent can not be terminated or amended in any material respect prior to the termination of the EUA Merger Agreement without the prior written consent of EUA. The foregoing sentence is intended for the benefit of EUA and may be enforced by EUA. 7. Notices. NEES hereby agrees to provide NGG with copies of all notices and other communications it sends to EUA and all notices and other communications it receives from EUA under the EUA Merger Agreement. All notices and other communications provided under this Agreement must be in writing and shall be given in the same manner and to the same parties as set forth in Section 10.02 of the Merger Agreement. 8. Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument. 9. Governing Law and Waiver of Jury Trial. This Agreement shall be governed by and construed in accordance with the laws of the State of New York applicable to a contract executed and performed in such State, without giving effect to the conflicts of laws principles. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION. IN WITNESS WHEREOF, each of NGG and NEES has duly executed this Agreement as of the date first above written. THE NATIONAL GRID GROUP, PLC By: /s/ Fiona B. Smith ----------------------------------- Name: Fiona B. Smith Title: Company Secretary NEW ENGLAND ELECTRIC SYSTEM By: ___________________________ Name: Title: The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer or agent thereof assumes or shall be held to any liability therefor. IN WITNESS WHEREOF, each of NGG and NEES has duly executed this Agreement as of the date first above written. THE NATIONAL GRID GROUP, PLC By: ______________________________ Name: Title: NEW ENGLAND ELECTRIC SYSTEM By: /s/ Richard P. Sergel ----------------------------------- Name: Richard P. Sergel Title: President and CEO The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer or agent thereof assumes or shall be held to any liability therefor. ACKNOWLEDGMENT OF EASTERN UTILITIES ASSOCIATES (not legible) EXHIBIT B - Financing Parameters Financing will be in an amount of up to $630 M provided through a group of banks. The financing (i) will be prepayable, (ii) will have a term not to exceed seven years, (iii) will have a LIBOR-based borrowing option and (iv) will have other terms and conditions usual and customary for transactions of this nature. Exhibit JKZ-2 Simplified Corporate Structure for Regulated Operating Companies (Plan for Full Consolidation) ------------------------------------------------------ ---------------- | National Grid | | Group | ---------------- | | | | | | | | | | ---------- ----- | NEES |--------------------------------- | EUA | ---------- ----- | | | |--------------| | | | | | | ---------------- ----------------- | | |----| Mass. Electric |------ | Eastern Edison | | | | ---------------- ----------------- | | | | | | | | | - ----------- | | -------------- ----------- | | Granite | | |----| New England |-------- | Montaup | | | State |-----| | | Power | ----------- | | Electric | | -------------- - - - - - - - - | ----------- | | ------------------- | | | | | Blackstone Valley |-|-------| | ---------------- | ------------------- | | |----| Narragansett |-----| | | ---------------- | ---------- | | | | Newport |----------|-------| | ---------- | - - - - - - - - - Petition of New England Power Company Vermont Public Service Board Exhibit JKZ-3 Page 1 of 1
New England Power Company 1998 Balance Sheet Dollars in Thousands December 31, 1998 Line Assets ---- ---- ------ 1 Utility Plant, at original cost $1,262,461 2 Less: Accumulated Depreciation 837,637 ------- 3 424,824 4 Construction Work in Progress 33,289 ------ 5 Net Utility Plant 458,113 6 7 Investments (Including in Subsidiaries) 88,121 8 9 Cash 179,413 10 Accounts Receivable, Associated Companies 107,878 11 Other Current Assets 63,362 12 13 Regulatory Assets 1,512,562 14 Deferred Charges and Other Assets 5,339 15 ----- 16 Total Assets 2,414,788 17 18 19 Capitalization and Liabilities ------------------------------ 20 Common Equity 520,896 21 Preferred Stock 1,567 22 Long-term Debt 371,765 ------- 23 Total Capitalization 894,228 24 25 Long Term Debt due within one year 0 26 Short-term Debt 0 27 Other Current Liabilities 199,919 28 29 Deferred State and Federal Income Taxes 165,115 30 Unamortized Investment Tax Credits 30,870 31 Accrued Yankee Nuclear Plant Costs 242,138 32 Purchased Power Obligations 832,668 33 Other Liabilities 49,850 ------- 34 35 Total Capitalization and Liabilities $2,414,788 36 37 Capitalization Ratios --------------------- 38 Common Equity 58% 39 Preferred Stock 0% 40 Long-term Debt 42% --- 41 Total Capitalization 100% Petition of New England Power Company Vermont Public Service Board Exhibit JKZ-4 Page 1 of 1 Montaup Electric Company 1998 Balance Sheet Dollars in Thousands December 31, 1998 Line Assets ---- ------ 1 Utility Plant, at original cost $496,203 2 Less: Accumulated Depreciation 156,158 ------- 3 340,045 4 Construction Work in Progress 1,307 ----- 5 Net Utility Plant 341,352 6 7 Investments in Subsidiaries 12,881 8 9 Cash 154 10 Accounts Receivable, Associated Companies 66,638 11 Other Current Assets 15,998 12 13 Unrecovered Regulatory Plant Costs 58,503 14 Deferred Charges and Other Assets 145,445 15 ------- 16 Total Assets 640,971 17 18 19 Capitalization and Liabilities ------------------------------ 20 Common Equity 147,017 21 Preferred Stock 1,500 22 Long-term Debt 117,982 ------- 23 Total Capitalization 266,499 24 25 Long Term Debt due within one year 0 26 Short-term Debt 0 27 Other Current Liabilities 69,759 28 29 Deferred State and Federal Income Taxes 99,567 30 Unamortized Investment Tax Credits 9,840 31 Other Liabilities 195,306 32 33 Total Capitalization and Liabilities $640,971 34 35 Capitalization Ratios --------------------- 36 Common Equity 55% 37 Preferred Stock 1% 38 Long-term Debt 44% --- 39 Total Capitalization 100%
Petition of New England Power Company Vermont Public Service Board Exhibit JKZ-5 Page 1 of 1 NEW ENGLAND POWER COMPANY MONTAUP ELECTRIC COMPANY PROFORMA BALANCE SHEET - MERGED Dollars in Thousands Actual Pro-Forma ------------------- ------------------------------- Redemption of Montaup Repayment NEP Montaup Debt and of Common Merged 1998 1998 Preferred Equity Company Line Assets ---- ---- --------- --------- ------- ---- ------ 1 Utility Plant, at original cost $1,262,461 $496,203 $1,758,664 2 Less: Accumulated Depreciation 837,637 156,158 993,795 ------- ------- ------- 3 424,824 340,045 764,869 4 Construction Work in Progress 33,289 1,307 34,596 ------ ----- ------ 5 Net Utility Plant 458,113 341,352 799,465 6 7 Investments (Including in Subsidiaries) 88,121 12,881 101,002 8 9 Cash 179,413 154 (119,482) (60,085) 0 10 Accounts Receivable, Associated Companies 107,878 66,638 174,516 11 Other Current Assets 63,362 15,998 79,360 12 13 Unrecovered Regulatory Plant Costs 1,512,562 58,503 1,571,065 14 Deferred Charges and Other Assets 5,339 145,445 150,784 15 ----- ------- ------- 16 Total Assets 2,414,788 640,971 (119,482) (60,085) 2,876,192 17 18 19 Capitalization and Liabilities ------------------------------ 20 Common Equity 520,896 147,017 (147,017) 520,896 (a) 21 Preferred Stock 1,567 1,500 (1,500) 0 1,567 22 Long-term Debt 371,765 117,982 (117,982) 0 371,765 ------- ------- ------- - ------- 23 Total Capitalization 894,228 266,499 (119,482) (147,017) 894,228 24 25 Long Term Debt due within one year 0 0 0 26 Short-term Debt 0 0 86,932 86,932 27 Other Current Liabilities 199,919 69,759 269,678 28 29 Deferred State and Federal Income Taxes 165,115 99,567 264,682 30 Unamortized Investment Tax Credits 30,870 9,840 40,710 31 Accrued Yankee Costs 242,138 0 242,138 32 Purchased Power Obligations 832,668 0 832,668 33 Other Liabilities 49,850 195,306 245,156 34 ------ ------- ------- 35 $2,414,788 $640,971 ($119,482) ($60,085) $2,876,192 36 37 38 Total Capitalization and Liabilities 39 40 Capitalization Ratios 41 Common Equity 58% 55% 58% 42 Preferred Stock 0% 1% 0% 43 Long-term Debt 42% 44% 42% -- -- -- 44 Total Capitalization 100% 100% 100% (a) The merged balance sheet does not reflect the impact of "push-down" accounting and the aquisition premium.
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