-----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, LoB2IT0e9XIZGuYUEpkI6qoN+eddaYtI6b5NS422JoO/+mRnL771rlnGWCN16BrL t5S+cZlYW+pGgU3brTEDpQ== 0000071337-01-500008.txt : 20010629 0000071337-01-500008.hdr.sgml : 20010629 ACCESSION NUMBER: 0000071337-01-500008 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20010331 FILED AS OF DATE: 20010628 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NEW ENGLAND POWER CO CENTRAL INDEX KEY: 0000071337 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041663070 STATE OF INCORPORATION: MA FISCAL YEAR END: 0331 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 002-26651 FILM NUMBER: 1670557 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 10-K 1 nep2001.txt SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For fiscal year ended March 31, 2001 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Registrant; State of Incorporation or I.R.S. Employer Commission Organization; Address; Identification File Number and Telephone Number Number - ------------ ---------------------- --------------- 1-6564 NEW ENGLAND POWER COMPANY 04-1663070 (A Massachusetts corporation) 25 Research Drive Westborough, Massachusetts 01582 Telephone: 508-389-2000 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. (X) Yes ( ) No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ( )
Aggregate market value of the voting stock Number of shares of held by nonaffiliates common stock outstanding of the registrant at of the registrant at June 14, 2001 June 14, 2001 - ---------------------- ------------------------- New England $1,181,192 3,619,896($20 par value) Power Company
Documents Incorporated by Reference
Part of Form 10-K into which Description document is incorporated - ---------------------------------- ---------------------------- Portions of New England Power Company Parts I and II Annual Report to Stockholders for the year ended March 31, 2001 as set forth in Parts I and II
TABLE OF CONTENTS PAGE GLOSSARY OF TERMS.......................................... FORWARD LOOKING INFORMATION................................ PART I ITEM 1. BUSINESS............................................ THE COMPANY................................................. Merger with National Grid ............................. Acquisition of EUA..................................... Merger Agreement with Niagara Mohawk................... Employees.............................................. ELECTRIC UTILITY OPERATIONS................................. Transmission and Nuclear Generation Business........... Description of Business............................. Rates............................................... Operating Revenues.................................. Electric Utility Properties............................ Transmission Properties............................. Interconnection with Quebec ........................ Nuclear Generation Properties....................... Nuclear Units..................................... Purchased Power Transfer Agreement................ Regulatory and Environmental Matters................... Regulation.......................................... Environmental Requirements.......................... Construction and Financing............................. EXECUTIVE OFFICERS.......................................... ITEM 2. PROPERTIES.......................................... ITEM 3. LEGAL PROCEEDINGS................................... ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS................................................ PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS........................ ITEM 6. SELECTED FINANCIAL DATA............................. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.................... ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK............................................ ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA......... ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.................... PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT............................................. ITEM 11. EXECUTIVE COMPENSATION............................ ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT......................................... PART IV ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.... ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K.................. INDEX TO FINANCIAL STATEMENTS............................... GLOSSARY OF TERMS Term Meaning ---- ------- AFDC allowance for funds used during construction CMS/MSS Congestion Management System and Multi- Settlement System Connecticut Yankee Connecticut Yankee Atomic Power Company CTC contract termination charges DOE U.S. Department of Energy EUA Eastern Utilities Associates Electricity Delivery Mass. Electric, Narragansett, Granite Companies State, and Nantucket FERC Federal Energy Regulatory Commission Granite State Granite State Electric Company Interconnection transmission interconnection between participating New England utilities and Hydro-Quebec ISO Independent System Operator kWh kilowatthour Maine Yankee Maine Yankee Atomic Power Company Mass. Electric Massachusetts Electric Company Mass. Hydro New England Hydro-Transmission Electric Company, Inc. MDTE Massachusetts Department of Telecommunications and Energy MW megawatts Nantucket Nantucket Electric Company Narragansett The Narragansett Electric Company National Grid National Grid Group plc National Grid USA Successor to NEES and a wholly-owned subsidiary of National Grid Group plc N.E. Hydro Finance New England Hydro Finance Company, Inc. NEEI New England Energy Incorporated NEES New England Electric System (renamed National Grid USA) NEES Energy NEES Energy, Inc. NEET New England Electric Transmission Corporation NEP New England Power Company NEPOOL New England Power Pool N.H. Hydro New England Hydro-Transmission Corporation NRC Nuclear Regulatory Commission PG&E Gen PG&E Generating, formerly USGen New England, Inc. RTO Regional Transmission Organization GLOSSARY OF TERMS Term Meaning ---- ------- Seabrook 1 Seabrook Nuclear Generating Station Unit 1 SEC Securities and Exchange Commission Sellers NEP and Narragansett Service Company National Grid USA Service Company, Inc. spent nuclear fuel high level radioactive waste stranded costs the amounts by which prudently incurred costs to supply customers electricity under a regulated industry structure exceed market prices under an unregulated industry structure Vermont Yankee Vermont Yankee Nuclear Power Corporation VPSB Vermont Public Service Board Yankee Atomic Yankee Atomic Electric Company Yankee Companies Yankee Atomic, Vermont Yankee, Maine Yankee, and Connecticut Yankee 1935 Act Public Utility Holding Company Act of 1935, as amended FORWARD LOOKING INFORMATION This report and other presentations made by New England Power Company (NEP or the Company) contain forward looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Throughout this report, forward looking statements can be identified by the words or phrases ?will likely result?, ?are expected to?, ?will continue?, ?is anticipated?, ?estimated?, ?projected?, ?believe?, ?hopes?, or similar expressions. Although NEP believes that, in making any such statements, its expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Important factors that could cause actual results to differ materially from those in the forward looking statements include, but are not limited to: (a) the impact of industry restructuring, as more fully set out under Regulatory Environment below; (b) the impact of general economic changes in New England; (c) federal and state regulatory developments and changes in law which may have a substantial adverse impact on the value of NEP?s assets; (d) federal regulatory developments concerning regional transmission organizations, as more fully set out under Transmission Properties below; (e) changes in accounting rules and interpretations which may have an adverse impact on NEP?s statements of financial position and reported earnings; (f) timing and adequacy of rate relief; (g) adverse changes in electric load; (h) climatic changes or unexpected changes in weather patterns; and (i) operation and decommissioning costs associated with nuclear generating facilities, as set out under Nuclear Units below, page __. PART I ITEM 1. BUSINESS THE COMPANY New England Power Company (NEP or the Company), a wholly owned subsidiary of National Grid USA (formerly New England Electric System (NEES)), is a Massachusetts corporation qualified to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine, and Vermont. NEP is subject, for certain purposes, to the jurisdiction of the regulatory commissions of all these states (except Connecticut), the Securities and Exchange Commission, under the Public Utility Holding Company Act of 1935 (the 1935 Act), the Federal Energy Regulatory Commission, and the Nuclear Regulatory Commission. NEP?s business is primarily the transmission of electric energy in wholesale quantities to other electric utilities, principally its distribution affiliates, National Grid USA's four electricity delivery companies, Massachusetts Electric Company (Mass. Electric), The Narragansett Electric Company (Narragansett), Granite State Electric Company (Granite State), and Nantucket Electric Company (Nantucket), (together, the Electricity Delivery Companies). NEP?s transmission facilities are part of National Grid USA's transmission operations, which are represented under the name National Grid Transmission USA. Holders of common stock and 6% Cumulative Preferred Stock have general voting rights. National Grid USA owns 99.60% of the voting stock of NEP and the NEP 6% preferred holders own 0.40%. NEP owns voting stock in the amounts indicated of the following companies:
% Voting Securities State of Type of Owned by Name of Company Organization Business NEP - --------------- ------------ -------- --------- Connecticut Yankee Atomic Conn. Ownership of 19.5% Power Company Permanently Shutdown Nuclear Unit (a) Maine Yankee Atomic Maine Ownership of 24.0% Power Company Permanently Shutdown Nuclear Unit (a) Vermont Yankee Nuclear Vermont Ownership of 22.5% Power Corporation Operating Nuclear Unit (a) Yankee Atomic Electric Company Mass. Ownership of 34.5% Permanently Shutdown Nuclear Unit (a)
(a) For information on NEP?s ownership interest in nuclear generating units, see Nuclear Units, page __. The facilities of NEP, together with the Electricity Delivery Companies constitute an electrical transmission and distribution system that is directly interconnected with other utilities in New England and New York State, and indirectly interconnected with utilities in Canada. See ELECTRIC UTILITY OPERATIONS, page __. Merger with National Grid On March 22, 2000, the merger of NEES and National Grid Group plc (National Grid) was completed, with NEES (renamed National Grid USA) becoming a wholly owned subsidiary of National Grid. NEP maintained its existing name and remained a wholly owned subsidiary of National Grid USA. Acquisition of EUA The acquisition of Eastern Utilities Associates (EUA) by National Grid USA was completed on April 19, 2000. On May 1, 2000, Montaup Electric Company (Montaup), formerly a subsidiary of EUA, was merged into the Company. Merger Agreement with Niagara Mohawk On September 5, 2000, National Grid and Niagara Mohawk Holdings, Inc., (NiMo) announced a merger agreement under which National Grid will acquire NiMo through the formation of a new National Grid holding company and the exchange of NiMo shares for a combination of National Grid's American Depositary Shares (ADSs) and cash. The terms of the agreement value the transaction at approximately $3.0 billion. The transaction is expected to be completed by late calendar year 2001, and is subject to a number of conditions, including regulatory and other governmental approvals and the sale of NiMo's nuclear facilities or other satisfactory arrangements being reached. EMPLOYEES At March 31, 2001, NEP had 114 employees, of which 15 are members of labor organizations. Collective bargaining agreements with the Brotherhood of Utility Workers of New England, Inc., the International Brotherhood of Electrical Workers, and the Utility Workers Union of America, AFL-CIO expire in May, 2004. ACCOUNTING IMPLICATIONS For a full discussion of Accounting Implications see the Regulatory Environment and Accounting Implications section of the 2001 NEP Annual Report, incorporated herein by reference. OVERVIEW OF FINANCIAL RESULTS For a full discussion of Overview of Financial Results see the Overview of Financial Results section of the 2001 NEP Annual Report, incorporated herein by reference. TRANSMISSION AND NUCLEAR GENERATION BUSINESS Description of Business On September 1, 1998, NEP completed the sale of substantially all of its nonnuclear generating business to PG&E Generating (PG&E Gen) an indirect wholly-owned subsidiary of PG&E Corporation. NEP?s primary business is now the transmission of electric energy to other electric utilities, principally its distribution affiliates, the Electricity Delivery Companies. NEP owns a system of transmission lines and substations. NEP continues to own a minority interest in a joint owned nuclear generating unit as well as minority equity interests in four nuclear generating companies (see Nuclear Units, page __). Regulatory Environment Under settlement agreements, the Company is permitted to recover costs associated with its former generating investments and related contractual commitments that were not recovered through the sale of those investments (stranded costs). These costs are recovered from the Company's wholesale customers with which it has settlement agreements through contract termination charges (CTC). The Company's retail distribution affiliates recover CTC-related costs through delivery charges to distribution customers. The recovery of the Company's stranded costs (including the Montaup share) is divided into several categories. The Company's unrecovered costs associated with generating plants (nuclear and nonnuclear) and most regulatory assets were fully recovered through the CTC by the end of 2000 and earned a return on equity averaging 9.7 percent. The Montaup share of unrecovered costs associated with generating plants and most regulatory assets will be fully recovered through the CTC by the end of 2009. The Company's obligation related to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC as such costs are actually incurred. As the CTC rate declines, the Company, under certain of the settlement agreements, earns incentives based on successful mitigation of its stranded costs. These incentives supplement the Company's return on equity. Until such time as the Company divests its operating nuclear interests, 80 percent of the revenues and operating costs related to the units will be allocated to customers through the CTC, with shareholders being allocated the balance. In conjunction with the divestiture, the Company transferred to the buyer of its nonnuclear generating business (the buyer) its entitlement to power procured under several long-term contracts in exchange for monthly fixed payments by the Company. Similar to the Company, Montaup also transferred its purchased power obligations as part of the divestiture and in return agreed to make fixed monthly payments. The aggregate fixed monthly payments, including the Montaup share, average $11.3 million per month through December 2009 toward the above-market cost of those contracts. The liability relating to purchased power obligations, which is also reflected in regulatory assets, represents the net present value of these fixed monthly payments. At March 31, 2001, the net present value is approximately $786 million. For certain contracts which have been formally assigned to the buyer, the Company has made lump sum payments equivalent to the present value of the monthly fixed payment obligations of those contracts (approximately $453 million), which were separate from the $786 million figure referred to above. Prior to divesting substantially all of its nonnuclear generation business in 1998, the Company was the wholesale supplier of the electric energy requirements to its retail distribution affiliates as well as unaffiliated customers. The Company's all- requirements contracts with its affiliated distribution companies, as well as with some unaffiliated customers, were generally terminated pursuant to settlement agreements and tariff provisions in 1998. However, the Company remains obligated to provide transition power supply service to new customer load in Rhode Island at the standard offer price, but does not have a regulatory agreement that necessarily allows full recovery of the costs of such standard offer power. Consequently, the Company is at risk for the difference between the actual cost of serving this load and the revenue received from this obligation. The standard offer rate that the Company charges for continuing to meet this obligation increased from 3.5 cents per kilowatthour (kWh) in 1999 to 3.8 cents per kWh effective January 1, 2000. The standard offer rate is also subject to a rolling twelve-month fuel index adjustment factor, which increased the rate by an additional 0.121 cents per kWh beginning in April 2000 up to 2.404 cents per kWh by March 2001. The Company meets this obligation through a combination of generation from some of its remaining generation sources, as well as by periodically procuring power at market prices. Over time, the Company cannot predict whether the resulting revenues will be sufficient to cover the costs of procuring such power. For the year ended March 31, 2001, the Company's losses from this obligation were approximately $5 million. In a December 15, 2000 Order, the Federal Energy Regulatory Commission (FERC) rejected the Independent System Operator-New England's (ISO New England's) proposed $0.17 per kW-month Installed Capacity (ICAP) deficiency charge and reinstated an administratively-determined deficiency charge of $8.75 per kW- month, retroactive to August 1, 2000. Several parties, including the Company, filed motions requesting rehearing and stay of the FERC's order. On January 10, 2001, the FERC granted these motions. On March 6, 2001, the FERC reversed its earlier order by allowing ISO New England's previously proposed ICAP rate of $0.17 per kW-month to be effective from August 1, 2000 through March 31, 2001. Effective April 1, 2001, the FERC ordered an ICAP rate of $8.75 per kW-month. On March 16, 2001, National Grid and others filed a motion to stay the FERC Order with the United States Court of Appeals for the First Circuit (First Circuit). The First Circuit stayed the ICAP rate of $8.75 per kW-month on March 30, 2001. On June 4, 2001, ISO New England made a filing to comply with the March FERC order that proposed a maximum charge of $4.87 per kW-month. On June 8, 2001, the First Circuit, ruling on the merits of the appeal to the FERC's orders imposing the $8.75 charge, remanded the case to the FERC for further consideration. The First Circuit order allows the FERC to reinstate its initial order on a prospective basis, but asks the FERC to answer several questions to support its order. National Grid and others have asked FERC to consider the June 4 ISO filing while it is reconsidering its initial order on remand. At this time, the Company cannot predict how ICAP charges will affect its forward looking power supply costs. OPERATING REVENUES The following is the detail of kWh sales and deliveries, electric sales and other operating revenue, and operating income for the year ended March 31, 2001, the quarter ended March 31, 2000 and each of the years ended December 31, 1999, and 1998.
Sales and Deliveries of Electricity (in thousands of kWh) ------------------------------------ Year Ended Quarter Ended Year Ended December 31, March 31, 2001 March 31, 2000 1999 1998 -------------- -------------- ---- ---- Total Sales and Deliveries 4,518,054 901,723 2,970,43318,214,193 ========== ======= ========== ========== Operating Revenues (in thousands of dollars) ------------------------------------ Year Ended Quarter Ended Year Ended December 31, March 31, 2001 March 31, 2000 1999 1998 -------------- -------------- ---- ---- Total Electric 168,057 32,048 90,639 631,943 Sales Revenue Other Operating 488,215 102,515 505,702 586,397 Revenue -------- --------- --------- ------- Total Operating Revenue $656,272 $134,564 $596,341 $1,218,340 ======== ========= ========== ========== Operating Income $87,715 $ 16,685 $78,563 $157,362 ======== ========= ========== ==========
Operating revenue for 1999 decreased $622 million compared with 1998 due to the divestiture and reduced CTC charges. ELECTRIC UTILITY PROPERTIES Transmission Properties NEP's integrated system consists of approximately 2,800 circuit miles of transmission lines, and approximately 116 substations. The properties of National Grid USA subsidiaries also include the ownership interests of New England Electric Transmission Corporation (NEET),New England Hydro-Transmission Electric Company, Inc. (Mass.Hydro), and New England Hydro- Transmission Corporation (N.H.Hydro) in the Hydro-Quebec Interconnection, and an integrated system of transmission lines, substations, and distribution facilities. NEP is a participant in ISO New England's Power Pool (NEPOOL). The NEPOOL Agreement provides for coordination of the operation of the generation and transmission facilities of its members. The NEPOOL Agreement further provides for New England-wide central dispatch of generation by the Independent System Operator (ISO). ISO-New England was activated on July 1, 1997 and has been operating the control area since that time. It operates under contract with NEPOOL and is governed by an independent Board of Directors. NEPOOL?s Open Access Transmission Tariff, which covers service across pool transmission facilities is administered by ISO-New England. In May 1999, NEPOOL and ISO-New England commenced implementation of the NEPOOL competitive market system. The market system establishes markets for several tradable energy and reserve products. Implementation of the markets also has resulted in the imposition of certain costs including congestion related costs. By Order issued June 28, 2000, FERC conditionally approved a congestion management system and multi-settlement system (CMS/MSS). The CMS/MSS includes a number of transitional steps towards the establishment of a permanent congestion management system which would include a Financial Congestion Rights scheme, a transmission planning process, and locational marginal pricing. On May 31, 2001, and June 4, 2001, ISO-NE and NEPOOL, respectively filed proposals with FERC to implement a revised standard market design (SMD) to implement CMS/MSS. The SMD is based on the market system presently in place in the PJM (Pennsylvania, New Jersey, Maryland) interconnection, and is intended to bring greater consistency to power markets in the Northeast. ISO-NE and NEPOOL have requested FERC action on SMD later this year. NEPOOL?s governance structure consists of five sectors: transmission owners, generators, suppliers, public power, and end users. National Grid USA participates in the transmission owners sector. The Transmission sector accounts for 20 percent of the NEPOOL vote and the National Grid USA Companies account for one- seventh of the Transmission sector vote. Under NEPOOL?s revised governance structure, all National Grid USA companies are considered ?related persons? and therefore receive only a single vote. National Grid USA presented to the FERC in January 2001 a joint proposal, with ISO-New England and other utilities in New England, for a Regional Transmission Organization (RTO) in the northeastern US. The RTO would consist of an ISO with responsibility for administering a competitive wholesale market in electricity and an Independent Transmission Company (ITC) offering transmission services and undertaking transmission network development and the provision of connections for new generation. The proposal responds to the FERC's objective, set out in its "Order 2000", of separating transmission operations from market participation and would give the ITC, of which National Grid USA would be a member, the opportunity to propose financial incentives to deliver greater value for customers and shareholders. The proposal is subject to FERC approval and the ability of the utility group to reach agreement on a number of additional issues. Interconnection with Quebec NEET owns and operates a portion of an international transmission interconnection between the electric systems of Hydro-Quebec and New England. Mass. Hydro and N.H. Hydro own and operate facilities in connection with an expanded second phase of this interconnection. New England Hydro Finance Company, Inc. (N.E. Hydro Finance) provides the debt financing to Mass. Hydro and N.H. Hydro for the capital costs of the interconnection. National Grid USA owns 100% of the voting stock of NEET and 57.47% of the voting stock of both Mass. Hydro and N.H. Hydro. Mass. Hydro and N.H. Hydro each own 50% of the voting securities of N.E. Hydro Finance. NEET, Mass. Hydro, and N.H. Hydro own and operate, on behalf of NEPOOL participants in the project, a 450 kV direct current transmission line and related terminals to interconnect the New England and Quebec transmission systems (the Interconnection). The transfer capability of the Interconnection is currently rated at 2,000 megawatts (MW). Operating limits implemented by adjacent Power Pools covering New York, New Jersey, Pennsylvania, and Maryland often restrict the effective transfer capability to levels of 1,200 MW to 1,400 MW. The Interconnection has two phases. NEP's participation in both is approximately 22 percent. NEP and the other participants have entered into support agreements that end in 2020. Under the support agreements, NEP has agreed to guarantee its share of debt financing for the second phase. At March 31, 2001, NEP had guaranteed approximately $18 million of project debt with terms through 2015. NEP?s rights and obligations under its support agreements were transferred to PG&E Gen upon completion of the sale of NEP?s nonnuclear generating business. Also, as a result of Montaup being merged into NEP, at March 31, 2001, NEP had guaranteed an additional amount of approximately $4 million originally guaranteed by Montaup. NEP remains an obligor under the support agreements until 2020. Nuclear Units General NEP has interests in five nuclear units. Three of the units have been permanently shut down. The remaining two are currently operating. NEP is a stockholder of Yankee Atomic Electric Company (Yankee Atomic), Vermont Yankee Nuclear Power Corporation (Vermont Yankee), Maine Yankee Atomic Power Company (Maine Yankee), and Connecticut Yankee Atomic Power Company (Connecticut Yankee). Each of these companies (collectively referred to as the ?Yankee Companies?) owns a single nuclear generating unit. The stockholders of three of the Yankee Companies (Vermont Yankee, Maine Yankee, and Connecticut Yankee) have agreed, subject to regulatory approval, to provide capital requirements in the same proportion as their ownership percentages of the particular Yankee Company. NEP also has power contracts with each Yankee Company that require NEP to pay an amount equal to its share of total fixed and operating costs (including decommissioning costs) of the plant plus a return on equity. Yankee Atomic, Connecticut Yankee, and Maine Yankee have permanently ceased operations. NEP purchases the output of the Vermont Yankee plant in the same percentage as its stock ownership, less small entitlements taken by municipal utilities. In addition, NEP is a joint owner of the Seabrook Nuclear Generating Station Unit 1 (Seabrook 1) in New Hampshire. Seabrook 1 is operated by subsidiaries of Northeast Utilities (NU). NEP pays its proportionate share of costs and receives its proportionate share of output from Seabrook 1. Listed below is certain information on each nuclear plant in which NEP has an ownership interest. Under restructuring settlement agreements approved by regulators in Massachusetts, New Hampshire and Rhode Island, NEP has agreed to attempt to divest its interest in the two operating nuclear generating units. Nuclear Units Permanently Shut Down Three of the Yankee Nuclear Power Companies in which the Company has a minority interest own nuclear generating units that have been permanently shut down. These three units are as follows:
Future The Company's Estimated Investment Billings to as of 3/31/01 Date the Company Unit % $(millions) Retired $(millions) - ----------------------------------------------------------------- Yankee Atomic 34.5 2 Feb 1992 0 Connecticut Yankee 19.5 15 Dec 1996 50 Maine Yankee 24.0 17 Aug 1997 129
In the case of each of these units, the Company has recorded a liability and a regulatory asset reflecting the estimated future billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant, including a return on that investment, as well as unfunded nuclear decommissioning costs and other costs. Maine Yankee and Connecticut Yankee recover their costs, including a return, in accordance with settlement agreements approved by the FERC in May 1999 and July 2000, respectively. Prospectively, under the FERC settlement agreement, Connecticut Yankee agreed to reduce annual collections for decommissioning through the use of its pre-1983 spent fuel trust funds and to limit its return on equity to 6 percent. In addition, Connecticut Yankee, Yankee Atomic, and Maine Yankee continue to pursue litigation against the Department of Energy (DOE) to assume financial responsibility for storage of spent nuclear fuel. Under rate provisions approved by the FERC for Connecticut Yankee and Yankee Atomic, any recovery from the DOE proceedings after litigation expenses and taxes will be returned to customers. 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. Maine Yankee had hired Stone & Webster, Inc. (S&W), an engineering, construction, and consulting company, as the principal contractor to decommission the unit. In May 2000, Maine Yankee terminated its long-term contract with S&W and negotiated an arrangement with S&W to continue work through June 2000. In June 2000, S&W filed for Chapter 11 bankruptcy protection. Subsequently, Maine Yankee decided to self-manage the unit's decommissioning process. In June 2000, Federal Insurance Company (Federal) filed a complaint in S&W's bankruptcy proceeding which alleges that Maine Yankee improperly terminated its contract with S&W. If the court were to make such a finding, Federal would be excused from a $37 million performance bond liability to Maine Yankee. Federal's complaint has been removed to the US Federal District Court in Maine for jury trial. In August 2000, Maine Yankee filed a $78.2 million (later increased to approximately $86 million) damage claim against S&W in the bankruptcy proceeding. At this time, the Company is unable to determine the potential impact, if any, of these developments. Under the provisions of the Company's industry restructuring settlement agreements approved by state and federal regulators in 1998, the Company recovers all costs, including shutdown costs, that the FERC allows these Yankee companies to bill to the Company. Operating Nuclear Units The Company currently has minority interests in two operating nuclear generating units which the Company is engaged in efforts to divest: Vermont Yankee and Seabrook 1. In addition the Company sold its 16.2 percent interest in Millstone 3 to Dominion Resources, Inc. (Dominion) on March 31, 2001. Until such time as the Company divests its operating nuclear interests, 80 percent of the revenues and operating costs related to the Company's interest in these units will be allocated to customers through the CTC, with shareholders being allocated the balance. Vermont Yankee The following table summarizes the Company's interest in the Vermont Yankee Nuclear Power Corporation as of March 31, 2001:
The Company's Interest (millions of dollars) --------------------------------------------------- Net Decommissioning Equity Plant Estimated Fund License Ownership Equity Assets Decommissioning Balance Expiration Interest (%) Investments Cost (in 2000 $) ------------- -------------------------------------------------------------------- 22.5 $12 $36 $102 $57 2012
In November 1999, the Vermont Yankee Nuclear Power Corporation entered into an agreement with AmerGen Energy Company (AmerGen), a joint venture between PECO Energy and British Energy, to sell the assets of Vermont Yankee. Several other parties, including Entergy Corporation (Entergy), indicated to the Vermont Public Service Board (VPSB) that they were prepared to make an offer for Vermont Yankee. On February 14, 2001, the VPSB rejected Vermont Yankee's sale agreement with AmerGen and formally terminated the AmerGen proceeding on March 15, 2001. The VPSB also required Entergy to post a $26 million bond payable in the event that Entergy withdraws its offer. In addition, the VPSB stated that if the Entergy bond were redeemed, the proceeds would go exclusively to Vermont customers. The Vermont Yankee Board of Directors is presently considering its options with respect to that part of the order. On March 15, 2001, Vermont Yankee terminated its agreement with AmerGen. After considering the pros and cons of shutting the plant down, continuing to operate it, or sell it, Vermont Yankee decided to proceed with a formal auction of the plant. The auction was officially launched on April 16, 2001. The Company expects that the winning bidder of the plant will be named in the fall of 2001. Any sale of the plant is contingent upon the receipt of regulatory approvals by the SEC, under the 1935 Act, the FERC, the NRC, the VPSB, and other state regulatory commissions with jurisdiction over other equity owners of Vermont Yankee. Under the terms of the original AmerGen agreement, the existing power purchasers (including the Company) were required to continue to purchase the output of the plant or to buy out of the purchased power obligation. In November 1999, the Company signed an agreement to buy out of its obligation, requiring future payments which would be recovered through the Company's CTC. At that time, the Company recorded a liability and offsetting regulatory asset of $80 million for its share of future liabilities related to Vermont Yankee, including the purchased power contract termination payment obligation, but excluding interest and a return allowance. With Vermont Yankee's termination of the agreement with AmerGen in March 2001, the Company was relieved of this obligation and accordingly reversed the liability and offsetting regulatory asset of $80 million. To date, the Company has not determined if it will enter into a purchased power agreement with a proposed new owner of Vermont Yankee. Seabrook 1 The table below lists information on the Seabrook nuclear plant in which the Company is a joint owner.
Company's share of (millions of dollars) -------------------------------------------- Decommissioning The Company's Net Estimated Fund Ownership Plant Assets Decommissioning Balances* License Interest (%) (at 3/31/01) Cost (in 2000 $) (at 3/31/01) Expiration - ------------------------------------------------------------------------------------------- 10 $17** $61 $16 2026
*Certain additional amounts are anticipated to be available through tax deductions. **Represents post-December 1995 spending including nuclear fuel. As part of its restructuring settlement with the State of New Hampshire, Public Service Company of New Hampshire (PSNH), through its affiliate, North Atlantic Energy Corporation (NAEC), committed to seek New Hampshire Public Utilities Commission (NHPUC) approval of a definitive plan to sell, via public auction administered by the NHPUC, its share of Seabrook 1, with such sale to occur no later than December 31, 2003. NAEC owns the largest percentage of the plant with a 35.98 percent interest, and its affiliate, North Atlantic Energy Service Corporation, is the plant operator. As part of its settlement, PSNH has also agreed to make all reasonable efforts to bundle its interests with those of other owners (including the Company) seeking to sell their interests so that a controlling interest may be offered in the auction. In December 2000, NU filed its divestiture plan before the NHPUC, requesting an expeditious process in order to permit a prompt sale of the plant. Under the terms of the PSNH Settlement and enabling legislation, the NHPUC will administer the sale of the plant with the assistance of an asset sale specialist. On April 12, 2001, the Company filed a Seabrook Divestiture Plan with the NHPUC as directed by its 1998 restructuring settlement agreement. Under the Divestiture Plan, the Company has indicated its interest in selling its share of Seabrook 1 and has requested that the NHPUC administer an auction on the Company's behalf under certain guidelines and conditions. On May 22, 2001, legislation was enacted in New Hampshire to provide New Hampshire residents additional protections against the restructuring problems encountered in California. Although the legislation includes provisions to delay the sale of PSNH fossil and hydro generation assets, it directs the NHPUC to expedite the auction of the Seabrook Station in a manner that benefits customers of all New Hampshire utilities, including the Company. Millstone 3 In November 1999, the Company entered into an agreement with NU and certain of NU's subsidiaries to settle claims made by the Company relative to the operation of Millstone 3. Among other things, the settlement provided for NU to include the Company's share of Millstone 3 in an auction of NU's share of the unit. Upon the closing of the sale, NU would pay the Company a total of $25 million, regardless of the actual sale price, with adjustments for certain capital and fuel procurement expenditures. The settlement also required NU to indemnify the Company and assume any residual liabilities resulting from the sale, including any requirements that the sellers continue to purchase output from the unit. In August 2000, Dominion agreed to purchase the Millstone units, including the Company's 16.2 percent interest in Millstone 3, for $1.3 billion in cash. In November 2000, the Rhode Island Attorney General and the Rhode Island Division of Public Utilities and Carriers filed a protest at the FERC contending that the payment the Company would receive from the sale of Millstone 3, as established by its agreement with NU, was insufficient. In December 2000, the Company and other parties to the Millstone sale submitted answers opposing Rhode Island's position and arguing, among other things, that Rhode Island's contention was well beyond the scope of the FERC proceeding. The Company further stated that concerns over the customer rate impact of the Company's agreement with NU would be more appropriately addressed under the terms of its restructuring settlements. On January 25, 2001, the FERC found that Rhode Island's objection was beyond the scope of the proceeding and approved the sale. On March 31, 2001, the Company completed the sale of its 16.2 percent interest in Millstone 3 for approximately $27.9 million. In addition, the Company paid approximately $5.8 million to increase the decommissioning trust fund to the level prescribed in its settlement agreement with NU. The amounts received pursuant to the sale will, after reimbursement of the Company's transaction costs and net investment in Millstone 3, be credited to customers. The Company cannot predict whether the Rhode Island regulators will reassert their claims in connection with the recovery of stranded costs. Nuclear Decommissioning The Company is liable for its share of decommissioning costs for Seabrook 1 and all of the Yankees. Decommissioning costs include not only estimated costs to decontaminate the units as required by the NRC, but also costs to dismantle the units. The Company records decommissioning costs on its books consistent with its rate recovery. The Company is recovering its share of projected decommissioning costs for Seabrook 1 through depreciation expense. In addition, the Company is paying its portion of projected decommissioning costs for Connecticut Yankee and Maine Yankee. The Company has completed its projected decommissioning obligation for Yankee Atomic. Such costs reflect estimates of total decommissioning costs approved by the FERC. In New Hampshire, legislation was enacted in 1998 which makes owners of Seabrook 1, in 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, there is a single owner of an approximate 15 percent share of Seabrook 1 that is subject to the legislation. The impact of this legislation to the Company is not considered material to its financial position or results of operation. The Company has been working to amend the current nuclear decommissioning statute to become effective upon the sale of Seabrook. Decommissioning legislation has passed in the New Hampshire legislature. This bill, initiated and supported by Seabrook's joint owners, including the Company and members of the New Hampshire Nuclear Decommissioning Financing Committee (NHNDFC), modifies New Hampshire's current decommissioning law and removes utility owners from the role of proportional guarantor for non- utility owners. The new legislation also seeks to protect customers from future decommissioning risks by requiring a buyer to provide funding assurance even in the event of a premature shutdown at the plant. The bill also enhances the potential sale price of Seabrook by allowing the buyer to retain any decommissioning funds in excess of those contributed by customers of the present utility owners and by reducing the standard set by the NHNDFC for non-radiological decommissioning. The Nuclear Waste Policy Act of 1982 establishes that the federal government (through the 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 Seabrook 1 nuclear generating unit. Prior to 1998, the Company recovered this fee through its fuel clause. Under settlement agreements, substantially all of these costs are recovered through CTCs. Similar costs are billed to the Company by Vermont Yankee and are also recovered from customers through CTCs. In 1997, ruling on a lawsuit brought against the DOE by numerous utilities and state regulatory commissions, the U.S. Court of Appeals for the District of Columbia held that the DOE was obligated to begin disposing of utilities' spent nuclear fuel by January 1998. The DOE failed to meet this deadline and is not expected to have a temporary or permanent repository for spent nuclear fuel before 2010, at the earliest. Many utilities, including Yankee Atomic, Connecticut Yankee, and Maine Yankee filed claims for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE's failure to begin to take fuel in 1998. As an interim measure until the DOE meets its contractual obligations to dispose of their spent fuel, those companies are proceeding with construction of independent spent fuel storage installations on the plant sites. Each nuclear unit in which the Company has an ownership interest has established a decommissioning trust fund or escrow fund into which payments are being made to meet the projected costs of decommissioning. There is no assurance that decommissioning costs actually incurred by Seabrook 1 or the Yankees will not substantially exceed the estimated amounts. For example, decommissioning cost estimates assume the availability of permanent repositories for both low-level and high-level nuclear waste; those repositories do not currently exist. The temporary low-level repository located in Barnwell, South Carolina may become unavailable, which could increase the cost of decommissioning the Yankee Atomic, Connecticut Yankee, and Maine Yankee plants. If any of the operating units were shut down prior to the end of their operating licenses, the funds collected for decommissioning to that point may be insufficient. Under settlement agreements, the Company will recover decommissioning costs through CTCs. Nuclear Insurance The Price-Anderson Act limits the amount of liability claims that would have to be paid in the event of a single incident at a nuclear plant to $9.5 billion (based upon 106 licensed reactors). The maximum amount of commercially available insurance coverage to pay such claims is $200 million. The remaining $9.3 billion would be provided by an assessment of up to $88.1 million per incident levied on each of the participating nuclear units in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. The maximum assessment, which was most recently adjusted in 1998, is adjusted for inflation at least every five years. The Company's current interest in Vermont Yankee and Seabrook 1 would subject the Company to a $28.6 million maximum assessment per incident. The Company's payment of any such assessment would be limited to a maximum of $3.2 million per year. As a result of the permanent cessation of power operation of the Yankee Atomic, Connecticut Yankee, and Maine Yankee plants, these units have received from the NRC an exemption from participating in the secondary financial protection system under the Price-Anderson Act. However, these plants must continue to maintain $100 million of commercially available nuclear liability insurance coverage. Each of the nuclear units in which the Company has either an ownership or purchased power interest also carries nuclear property insurance to cover the costs of property damage, decontamination, and premature decommissioning resulting from a nuclear incident. These policies may require additional premium assessments if losses relating to nuclear incidents at units covered by this insurance occur in a prior six-year period. The Company's maximum potential exposure for these assessments, either directly or indirectly, is approximately $3.0 million with respect to the current policy period. Nuclear Fuel Supply The utilities responsible for the fuel supply for these operating nuclear units are not experiencing any difficulties in obtaining commitments for the supply of each element of the nuclear fuel cycle. Purchased Power Transfer Agreement As part of the sale of NEP?s nonnuclear generating business to PG&E Gen on September 1, 1998, NEP signed a purchased power transfer agreement through which PG&E Gen purchased NEP?s entitlement to approximately 1,100 MW of power procured under long-term contracts. For more information, see the Regulatory Environment and Accounting Implications section of the 2001 NEP Annual Report. Wyman 4 NEP is a 9 percent owner of the Wyman 4 generating unit, a 600 MW oil fired generating unit located in Yarmouth, ME. For more information, see Legal Proceedings. REGULATORY AND ENVIRONMENTAL MATTERS Regulation Numerous activities of NEP are subject to regulation by various federal agencies. Under the 1935 Act, many transactions of NEP are subject to the jurisdiction of the SEC. With the intensifying competitive pressures within the electric utility industry, there has been increasing debate about modifying or repealing the 1935 Act. Under the Federal Power Act, NEP is subject to the jurisdiction of the FERC with respect to rates and accounting. In addition, the NRC has broad jurisdiction over nuclear units and federal environmental agencies have broad jurisdiction over environmental matters. For more information, see the Regulatory Environment and Accounting Implications section of the 2001 NEP Annual Report, Nuclear Units, page__ and Environmental Requirements, below. Environmental Requirements Existing Operations NEP is subject to federal, state, and local environmental regulation of, among other things, wetlands and flood plains; air and water quality; storage, transportation, and disposal of hazardous wastes and substances; underground storage tanks; and land-use. Upon completion of the sale of substantially all of NEES? nonnuclear generating business to PG&E Gen, PG&E Gen assumed responsibility for environmental conditions at the Sellers? nonnuclear generating stations. See the Regulatory Environment and Accounting Implications section of the 2001 NEP Annual Report. ISO 14001 In June 2001, the Company announced that its transmission business achieved ISO (International Organization of Standardization) 14001 registration of its Environmental Management System, the first linear electric utility system in the country to achieve such designation. This also marks the first ISO 14001 registration of a high-voltage direct current (HVDC) transmission system in the U.S. The registration certifies that all activities, products, and services required to operate, maintain, and construct transmission lines, rights-of- way, HVDC converter terminals, and vegetation management activities meet the requirements of the internationally accepted ISO 14001 environmental standard. Siting and Construction Activities for New Transmission Facilities All New England states require, in certain circumstances, regulatory approval for site selection or construction of major transmission facilities. Connecticut, Maine, Massachusetts, New Hampshire, and Rhode Island also have programs of coastal zone management that might restrict construction of electrical facilities in, or potentially affecting, coastal areas. These New England states have environmental laws which require project proponents to prepare reports of the environmental impact of certain proposed actions for review by various agencies. Environmental Protection Facilities Expenditures NEP estimates that capital expenditures for environmental protection facilities in 2001 and 2002 will not be material. Hazardous Substances The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. For more information regarding sites for which NEP has been named as a potentially responsible party, other sites, a settlement agreement covering rate recovery of certain remediation costs, and reserves, see Note D of the Notes to the Financial Statements of the NEP 2001 Annual Report. Nuclear The NRC, along with other federal and state agencies, has extensive regulations pertaining to environmental aspects of nuclear reactors. Safety aspects of nuclear reactors, including design controls and inspection programs to mitigate any possibility of nuclear accidents and to reduce any damages therefrom, are also subject to NRC regulation. See Nuclear Units, page __. CONSTRUCTION AND FINANCING NEP?s estimated construction expenditures (including nuclear fuel) are shown below for the fiscal years ended March 2002 through 2004. NEP conducts a continuing review of its construction and financing programs. These programs and the estimates shown below are subject to revision based upon changes in assumptions as to load growth, rates of inflation, receipt of adequate and timely rate relief, the availability and timing of regulatory approvals, new environmental and legal or regulatory requirements, total costs of major projects, technological changes, and the availability and costs of external sources of capital.
Estimated Construction Expenditures for the years ended March ----------------------------------- 2002 2003 2004 Total - ---- ---- ---- ----- ($ in Millions - excluding AFDC) Nuclear Generation (1) 10 10 10 30 Transmission 40 60 50 150 ---- ---- ---- ---- Total NEP 50 70 60 180 ---- ---- ---- ---- (1) Includes nuclear fuel.
Financing All of NEP?s construction expenditures during the fiscal years ended March 2002 through March 2004 are expected to be financed by internally generated funds. NEP?s general practice has been to finance construction expenditures in excess of internally generated funds initially by issuing unsecured short-term debt. This short-term debt is subsequently reduced through sales of long-term debt securities and through capital contributions from its parent. The ability of NEP to issue short-term debt is limited by the need to obtain regulatory approval from the SEC under the 1935 Act and from the NHPUC. The following table summarizes the short-term debt amounts for which regulatory approval has been granted at March 31, 2001, and the amount of outstanding short-term debt and lines of credit and standby bond facilities at such date.
($ millions) Lines of Credit/ Regulatory Standby Bond Limit Outstanding Facilities - ---------- ----------- ---------------- NEP 375 0 456
NEP and certain affiliates, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies which invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice. At March 31, 2001, NEP had no moneypool borrowings outstanding. EXECUTIVE OFFICERS The Treasurer is elected by the stockholders to hold office until the next annual meeting of stockholders and until the successor is duly chosen and qualified. The other executive officers are elected by the Board of Directors to hold office subject to the pleasure of the directors and until the first meeting of directors after the next annual meeting of stockholders and until their successors are duly chosen and qualified. Certain officers of NEP are, or at various times in the past have been, officers and/or directors of the affiliated companies with which NEP has entered into contracts and had other business relations. The list below is as of March 31, 2001. Peter G. Flynn - Age: 47 - Elected President in 1999 - National Grid USA Vice President since 2000 - Vice President and Director of Rates for the Service Company from 1996 to 1999. Michael E. Jesanis - Age: 44 - Vice President since 1998 - National Grid USA Executive Vice President since 1/1/01 - NEES Senior Vice President and Chief Financial Officer from 1998 - 2000 - NEES Vice President from 1997 to 1998 - NEES Treasurer from 1992 to 1998 - Elected Vice President of Narragansett in 1998 - Treasurer of Mass. Electric and NEP from 1992 to 1998. Marc F. Mahoney - Age: 47- Elected Vice President in 2000 - Vice President, Field Operations for EUA from 1997 to 2000 - Director, Transmission and Distribution for EUA from 1995 to 1997. John F. Malley - Age: 52 - Vice President since 1992. Lawrence J. Reilly - Age: 45 - Vice President since 1/1/01 - National Grid USA Senior Vice President since 2000 - National Grid USA Secretary and General Counsel since 1/1/01 - - President of Mass. Electric, Narragansett, Nantucket, and Granite State from 1996 to 2000. James S. Robinson - Age: 47 - Vice President since 1998 - Director of Nuclear Investments from 1997 to 1998 - Manager, Wholesale Business Administration from 1993 to 1997. Masheed H. Rosenqvist - Age: 46 - Vice President since 1998 - - Manager, Transmission Tariffs and Contracts for NEP or Service Company since 1997. Terry L. Schwennesen - Age: 45 - Elected Vice President in 2000 - Associate General Counsel of Mass. Electric from 1999 to 2000 - Director of Rates for Service Company from 1998 to 1999 - Manager of Rates during 1998 - Manager of Wholesale Rates until 1998. John G. Cochrane - Age: 43 - Treasurer since 1998 - National Grid USA Chief Financial Officer since 1/1/01 - NEES Vice President since 1999 - NEES and Service Company Treasurer since 1998 - Vice President of the Service Company since 1993 - Treasurer of Mass. Electric Company from 1998 to 2000 - - Treasurer of Narragansett from 1993 to 2000. Kwong O. Nuey - Age: 52 - Elected Controller in 2000 - Vice President and Director, Retail Information Services for Mass. Electric from 1993 to 2000. ITEM 2. PROPERTIES See ITEM 1. Business - Transmission Properties, Page __ and Nuclear Generation Properties, page __. ITEM 3. LEGAL PROCEEDINGS See Item 1. Business - TRANSMISSION AND NUCLEAR GENERATION BUSINESS - Regulatory Environment, Page __ and ELECTRIC UTILITY PROPERTIES - Nuclear Units, Page ___ Norwood From 1983 until 1998, the Company was the wholesale power supplier for the town of Norwood, Massachusetts (Norwood). In April 1998, Norwood began taking power from another supplier. Pursuant to a tariff amendment approved by the FERC in May 1998, the Company has been assessing Norwood a CTC. Through March 2001, the charges assessed Norwood amount to approximately $29 million, all of which remain unpaid. The Company filed a collection action in Massachusetts Superior Court (Superior Court). The Superior Court deferred action until the various appeals described below were decided. On March 14, 2001, the Superior Court ordered Norwood to pay the Company $27 million including interest. Norwood was ordered to pay the judgement in monthly installments of $600,000. Norwood has also entered a consent order to establish a segregated account for the benefit of the Company in the amount of $14 million and to make regular additions to the account. Separately, Norwood filed suit in Federal District Court (District Court) in April 1997 alleging that the divestiture of the Company's nonnuclear generating business (the divestiture) violated the terms of the 1983 power contract and contravened antitrust laws. The District Court dismissed the lawsuit. On appeal, the First Circuit consolidated appeals Norwood made from the FERC's orders approving the Company's divestiture, the wholesale rate settlement between the Company and its distribution affiliates, and the CTC tariff amendment. In February 2000, the First Circuit dismissed Norwood's appeal from the FERC orders and dismissed its appeal from all but one of Norwood's District Court claims, which relates to alleged generation market power. In February and March 2000, respectively, the First Circuit denied Norwood's petition for further review of its District Court claims decision and its decision on the FERC orders. In May 2000, Norwood petitioned the US Supreme Court for review of the First Circuit decisions. In October 2000, the US Supreme Court refused Norwood's petitions to review the First Circuit decisions affirming (a) the FERC's approval of the CTC, the divestiture, and the settlement agreements regarding termination of the Company's power sales agreements with its affiliates, and (b) the District Court's dismissal of Norwood's antitrust and breach of contract claims. In the District Court action, in April 2000, the Company renewed its motion to dismiss Norwood's remaining claim. Norwood amended its complaint to reassert a request for rescission of the divestiture, which it had earlier dropped. A hearing took place before the District Court in July 2000. Norwood has also appealed a June 1999 FERC decision that rejected Norwood's challenge to the calculation of the CTC based on the terms of the 1983 power contract, which Norwood contended ended in October 1998, not October 2008. In June 2000, the First Circuit rejected Norwood's appeal. Norwood filed a petition for certiorari to the US Supreme Court for review of the First Circuit's decision. On April 24, 2001, the US Supreme Court denied Norwood's petition. NSTAR Settlement On March 30, 2001, the Company reached a settlement in principal with NSTAR, formerly known as Boston Edison Company (BECO), resolving issues surrounding a $3 million refund to Montaup ordered by the FERC in January 2000. The order stemmed from an earlier proceeding initiated by the FERC where it required BECO to reduce its ROE under a life of unit purchased power agreement (PPA) with Montaup for 11 percent of the output from the Pilgrim plant. BECO subsequently divested its ownership in the Pilgrim plant in July 1999, and Montaup terminated its life of unit PPA in favor of a PPA that expires in 2004. BECO appealed the FERC Order to the First Circuit which, in turn, has remanded the case to the FERC for further proceedings. Proceeds from the refund have already been credited to customers through Montaup's CTC reconciliation mechanism. Under the terms of the settlement, the Company will return to BECO 75 percent of the refund amount, plus interest through March 31, 2001. The settlement is conditioned on consent from the parties to Montaup's restructuring settlement to recover this amount from customers through the CTC. Wyman 4 Settlement On April 23, 2001, Central Maine Power (CMP) and the Wyman 4 minority owners reached a settlement under which CMP will pay a total of $12 million to the minority owners. NEP's pro rata share of the settlement proceeds will be $2.9 million. The proceeds of the settlement, less legal costs, will be returned to customers via the CTC mechanism. The settlement is the result of arbitration brought by NEP and others against CMP regarding the sharing of CMP's proceeds from its sale of the Wyman 4 unit and site in Yarmouth, Maine in 1999. NEP is a 9 percent minority owner of the Wyman 4 generating unit. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to the shareholders for vote during the fourth quarter of the fiscal year. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS The information required by this item is not applicable as the common stock of NEP is held solely by National Grid USA. Information pertaining to payment of dividends and restrictions on payment of dividends is incorporated herein by reference to the NEP 2001 Annual Report. ITEM 6. SELECTED FINANCIAL DATA The information required by this item is incorporated herein by reference to Selected Financial Information, Note K of the NEP 2001 Annual Report. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The information required by this item is incorporated herein by reference to the Financial Review section of the NEP 2001 Annual Report. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by this item is incorporated herein by reference to the Risk Management section of the NEP 2001 Annual Report. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by this item is incorporated herein by reference to the financial statements and Notes to Financial Statements in the NEP 2001 Annual Report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The names of the directors of NEP, their ages, and a brief account of their business experience during the past five years appear below. Information required by this item for Executive Officers is provided under the caption EXECUTIVE OFFICERS in Part I of this report. Directors are elected to hold office until the next annual meeting of stockholders or special meeting held in lieu thereof and until their respective successors are chosen and qualified. The list below is as of March 31, 2001 L. Joseph Callan - Age: 53 - Elected Director in 2000 - Consultant since 1998 - Several positions at the NRC, including Regional Administrator and Executive Director of Operations, from 1979 to 1998. Peter G. Flynn* - Elected Director in 1999. Michael E. Jesanis* - Elected Director in 2000 - Directorships of National Grid USA Companies: EUA Bioten, Inc., EUA Energy Investment Corporation, Granite State Electric Company, Massachusetts Electric Company, Nantucket Electric Company, National Grid USA, National Grid USA Service Company, Inc., NEES Communications, Inc., New England Electric Transmission Corporation, New England Energy Incorporated, New England Hydro Finance Company, Inc., New England Hydro-Transmission Corporation, New England Hydro-Transmission Electric Company, Inc., New England Power Company, and The Narragansett Electric Company. Robert G. Powderly - Age: 54 - Elected Director in 2000 - Executive Vice President of EUA until 2000 - Directorships of National Grid USA Companies: EUA Bioten, Inc., EUA Energy Investment Corporation, National Grid USA, National Grid USA Service Company, Inc., and New England Power Company. Lawrence J. Reilly* - Director since 2001. Directorships of National Grid USA companies: AllEnergy Fuels Corp., EUA Bioten, Inc., EUA Energy Investment Corporation, Granite State Electric Company, Massachusetts Electric Company, Nantucket Electric Company, National Grid Transmission Services Corporation, National Grid USA, National Grid USA Service Company, Inc., NEES Communications, Inc., NEES Energy, Inc., NEES Telecommunications Corp., New England Electric Transmission Corporation, New England Energy Incorporated, New England Hydro Finance Company, Inc., New England Hydro-Transmission Corporation, New England Hydro- Transmission Electric Company, Inc., New England Power Company, NEWHC, Inc., New England Wholesale Electric Company, The Narragansett Electric Company and Wayfinder Group, Inc. Terry L. Schwewnnesen* - Elected Director in 2000. Richard P. Sergel - Age: 52 - Director since 1998. Director of National Grid Group plc. Directorships of National Grid USA companies: EUA Bioten, Inc., EUA Energy Investment Corporation, Granite State Electric Company, Massachusetts Electric Company, Nantucket Electric Company, National Grid Transmission Services Corporation, National Grid USA, National Grid USA Service Company, Inc., NEES Communications, Inc., NEES Energy, Inc., NEES Telecommunications Corp., New England Energy Incorporated, New England Electric Transmission Corporation, New England Hydro Finance Company, Inc., New England Hydro-Transmission Corporation, New England Hydro-Transmission Electric Company, Inc., New England Power Company, NEWHC, Inc., The Narragansett Electric Company, and Wayfinder Group, Inc. Philip R. Sharp - Age: 58 - Elected Director in 2000 - Lecturer, Harvard University John F. Kennedy School of Government since 1995 - US Congressman from 1975 to 1995. Other directorship: Cinergy Corporation. *Please refer to the material supplied under the caption EXECUTIVE OFFICERS in Part I of this report for other information regarding these directors. Section 16(a) Beneficial Ownership Reporting Compliance ------------------------------------------------------- Section 16(a) of the Securities Exchange Act of 1934 requires NEP's officers and directors, and persons who own more than 10 percent of a registered class of NEP's equity securities, to file reports on Forms 3, 4, and 5 of share ownership and changes in share ownership with the SEC and the New York Stock Exchange and to furnish NEP with copies of all Section 16(a) forms they file. Based solely on NEP?s review of the copies of such forms received by it, or written representations from certain reporting persons that such forms were not required for those persons, NEP believes that, during fiscal year 2001, all filing requirements applicable to its officers, directors, and 10 percent beneficial owners were complied with, with the exception that, due to Company error, a Form 3 for each of Marc Mahoney, Lawrence Reilly, and Terry Schwennesen was filed late. ITEM 11. EXECUTIVE COMPENSATION EXECUTIVE COMPENSATION The following table gives information with respect to all compensation (whether paid directly by NEP or billed to it as hourly charges) for services in all capacities for NEP for the fiscal year ending March 31, 2001, the first calendar quarter of 2000, and calendar years 1999 and 1998 to or for the benefit of the Chief Executive Officer and the four other most highly compensated executive officers. NEP SUMMARY COMPENSATION TABLE
Long-Term Annual Compensation (b) Compensation -------------------------- ------------------- Other Restricted Securities Name and Annual & Deferred Under All Other Principal Compensa- Share Lying LTIP Compensa- Position Year Salary Bonus tion Awards Options Payouts tion (a) ($) ($)(c) ($)(d) (#) ($) ($)(f) - ---------- ---- ------- ------ --------- ---------- -------- ------- ------ Peter G. 2001(g) 177,211 30,270 12,175 0 0 0 432 Flynn (i) 2000(h) 40,997 107,889 2,050 0 36,473 118,615 90 President 1999 154,707 74,812 3,616 30,220 46,464 359 1998 57,838 29,383 1,151 12,176 0 6,864 75 Marc F. 2001(g) 118,010 78,428 11,352 0 35,886 0 280 Mahoney(j) Vice President Masheed H. 2001(g) 146,112 17,892 18,452 0 0 0 539 Rosenqvist 2000(h) 32,745 63,412 1,637 0 16,023 54,855 103 Vice 1999 124,740 45,569 2,538 17,671 0 412 President 1998 113,697 44,654 2,285 17,618 0 366 James S. 2001(g) 130,137 39,862 18,649 0 0 0 204 Robinson 2000(h) 31,811 62,966 1,625 0 14,458 53,878 42 Vice 1999 115,920 42,415 2,693 16,405 22,018 167 President 1998 108,205 39,143 2,510 17,734 13,641 149 Terry L. 2001(g) 124,951 15,992 16,787 0 0 0 168 Schwennesen (j) Vice President
(a) Certain officers of NEP are also officers of affiliate companies. (b) Includes deferred compensation in category and year earned. (c) The bonus figure represents: cash bonuses under an incentive compensation plan, the all-employee goals program, the variable match of the incentive thrift plan, including related deferred compensation plan matches, special cash bonuses, and unrestricted shares under the incentive share plan. See descriptions under Plan Summaries. (d) Includes amounts reimbursed by NEP for the payment of taxes on certain noncash benefits and NEP contributions to the incentive thrift plan that are not bonus contributions including related deferred compensation plan match. See description under Plan Summaries. (e) The incentive share awards for the named executives who were also NEES executives (1998 - 1999) and the other named executives (in 1998 only) were in the form of restricted shares (with a five-year restriction) or deferred share equivalents, deferred for receipt for at least five years, at the executive?s option. As cash dividends were declared, the number of deferred share equivalents increased as if the dividends were reinvested in shares. (f) Includes NEP contributions to life insurance. See description under Plan Summaries. The life insurance contribution is calculated based on the value of term life insurance for the named individuals. The premium costs for most of these policies have been or will be recovered by NEP. (g) Information is for fiscal year ending March 31, 2001. (h) Information is for the first calendar quarter of 2000 only. (i) Elected January 1999. (j) Elected May 2000. Directors? Compensation Members of the NEP Board who are employees of National Grid USA companies receive no fees for service on the Board. Non- employee directors receive an annual retainer of $20,000 plus a meeting fee of $1,000 for each Board or committee meeting attended. The Chairman of the Nuclear Committee, Mr. Callan, receives $1,500 for each committee meeting he chairs. Retirement Plans The following table shows estimated annual benefits payable to executive officers under the qualified pension plan and the supplemental retirement plan, assuming retirement at age 65 in 2001. PENSION TABLE
Five-Year Average 15 Years 20 Years 25 Years 30 Years 35 Years Compensa- of of of of of tion Service Service Service Service Service - --------- -------- -------- -------- -------- -------- $100,000 $28,093 $36,790 $45,238 $53,685 $59,133 $150,000 $44,093 $57,790 $71,113 $84,435 $93,258 $200,000 $60,093 $78,790 $96,988 $115,185 $127,383 $250,000 $76,093 $99,790 $122,863 $145,935 $161,508 $300,000 $92,093 $120,790 $148,738 $176,685 $195,633 $350,000 $108,093 $141,790 $174,613 $207,435 $229,758 $400,000 $124,093 $162,790 $200,488 $238,185 $263,883 $450,000 $140,093 $183,790 $226,363 $268,935 $298,008 $500,000 $156,093 $204,790 $252,238 $299,685 $332,133
For purposes of the retirement plans, Mr. Flynn, Mr. Mahoney, Ms. Rosenqvist, Mr. Robinson, and Ms. Schwennesen currently have 19, 25, 19, 13, and 16 credited years of service, respectively. Benefits under the pension plans are computed using formulae based on percentages of highest average compensation computed over five consecutive years. The compensation covered by the pension plan includes salary, bonus, and incentive share awards. The benefits listed in the pension table are not subject to deduction for Social Security and are shown without any joint and survivor benefits. If the participant elected at age 65 a 100 percent joint and survivor benefit with a spouse of the same age, the benefit shown would be reduced by approximately 16 percent. NEP contributes the full cost of post-retirement health benefits for senior executives. PAYMENTS UPON A CHANGE OF CONTROL AND TERMINATION OF EMPLOYMENT National Grid USA is a party to a Change in Control Agreement with Mr. Flynn dated November 1, 1998 which remains in effect for 36 months beyond the month in which a (1) Change in Control of NEES (as defined in the Change in Control Agreement) or (2) Major Transaction (as defined in the Change in Control Agreement) occurs. In accordance with the terms of the Change in Control Agreement, if Mr. Flynn's employment is terminated without cause by the Company or for Good Reason (as defined in the Change in Control Agreement) by Mr. Flynn within 36 months following the event described in clause (1) or (2) National Grid USA will provide Mr. Flynn with the severance payments and benefits described below. The shareholder approval of the merger agreement with National Grid Group plc (May 1999) constituted a Major Transaction and the merger with National Grid Group plc on March 22, 2000 constituted a Change in Control. Accordingly, in the event Mr. Flynn's employment is terminated without cause by the Company or for Good Reason by Mr. Flynn within 36 months following the month in which the Major Transaction or Change in Control occurred, Mr. Flynn will be entitled to receive (in addition to any normal post-term compensation and benefits as they become due), (1) in lieu of any other salary payments: a lump sum cash payment equal to two times the sum of (a) the higher of (i) his annual base salary in effect at the time of termination and (ii) his annual base compensation in effect immediately prior to the Change in Control or Major Transaction and (b) the higher of (i) the average of the annual bonuses awarded him under the New England Electric System Companies? Senior Incentive Compensation Plan, New England Electric System Companies? Incentive Compensation Plan I, II or III and the Incentive Share Plan or successors of any such plans (collectively, the Incentive Plans) for the three performance years preceding the year in which his Date of Termination (as defined in the Change in Control Agreement) occurs or (ii) the average of the annual bonuses awarded him pursuant to the Incentive Plans for the three performance years preceding the year in which the Change in Control or Major Transaction occurs; (2)in addition to the retirement benefits to which Mr. Flynn is entitled, a lump sum cash payment equal to the excess of (a) the actuarial equivalent of the retirement pension which he would have accrued under the terms of each Pension Plan (as defined in the Change in Control Agreement) of National Grid USA (determined as if he (i) were fully vested thereunder and had accumulated 24 additional months of service credit thereunder and (ii) had been credited under each Pension Plan during such 24 month period with compensation at the higher of (A) his compensation during the 12 months immediately preceding his Date of Termination or (B) his compensation during the 12 months immediately preceding the Change in Control or Major Transaction) over (b) the actuarial equivalent of the retirement pension which he had actually accrued pursuant to the provisions of each pension plan as of the Date of Termination; (3) the continuation of life, disability, accident and health insurance benefits substantially similar to those which he had received prior to his Date of Termination for 24 months following the Date of Termination, reduced to the extent he receives such benefits or such benefits are made available to him from a subsequent employer, without cost to him; (4) if he would have otherwise been entitled to post- retirement health care or life insurance had his employment terminated at any time during the 24 months following his Date of Termination such post-retirement health care and life insurance commencing on the later of (a) the date that such coverage would have first become available to him and (b) the date that the benefits described in clause (3) above terminate; and (5) the reimbursement of legal fees and expenses, if any, incurred by him in disputing in good faith, any issue relating to the termination of his employment. Notwithstanding the above, the payments and benefits to be provided to Mr. Flynn will be reduced to the extent necessary to avoid imposition of the Excise Tax (as defined in the Change in Control Agreement) pursuant to Section 4999 of the Code; provided that such reduction would yield a greater result to Mr. Flynn than actual payment by Mr. Flynn of the Excise Tax. Upon a Change in Control a participant in the deferred compensation plan has the option of receiving a full distribution of the participant?s cash and share accounts and the actuarial value of future benefits from the insurance related benefits under a prior plan, all less 10 percent. NEES' bonus plans, including the Incentive Plans, the Incentive Thrift Plan, and the Goals Program, provided for payments equal to the average of the bonuses for the three prior years in the event of a Change of Control. These payments would be made in lieu of the regular bonuses for the year in which the Change in Control occurs. These payments were triggered upon the merger with National Grid and are reflected in the Summary Compensation Table in the bonus column for 2000. The Long-Term Performance Share Award Plan provided for a cash payment equal to the value of the performance shares in the participants? account times the average target achievement percentage for the Incentive Thrift Plan for the three prior years. This payment was triggered upon the merger with National Grid and is reflected in the Summary Compensation Table in the LTIP Payouts column for 2000. The Retirees Health and Life Insurance Plan has provisions preventing changes in benefits adverse to the participants for three years following a Change in Control. PLAN SUMMARIES A brief description of the various plans through which compensation and benefits have been provided to the named executive officers is presented below to better enable shareholders to understand the information presented in the tables shown earlier. The amounts of compensation and benefits provided to the named executive officers under the plans described below (and charged to NEP) are presented in the Summary Compensation Table. Goals Program The Goals cash bonus program is is a broad-based, all- employee bonus program, which focuses employees on both the financial performance of the Company and operational performance in key categories such as reliability, customer satisfaction and safety. Payout levels vary depending on both financial performance and the number of goals achieved in each work location and function. Assuming the minimum financial goal is met, and depending upon the number of other goals attained, an employee may earn a cash bonus of between 0.8% and 4.5% of their eligible pay. Incentive Thrift Plan The Incentive Thrift Plan permits eligible employees to contribute up to 20% of their pay on a on a pre-tax basis into the plan (subject to legal limits), and to receive a Company matching contribution of up to 5% of their base pay provided the employee contributes at least 6% of her or his base pay into the plan. Under Internal Revenue Code rules, annual salary deferrals could not exceed $10,500 during calendar years 2000 or 2001, and compensation taken into account for determining deferrals could not exceed $170,000. Consequently, matching contributions were capped at $8,500. Matching contributions are shown under Other Annual Compensation in the Summary Compensation Table. Deferred Compensation Plan The Deferred Compensation Plan offers executives the opportunity to defer bonuses and/or a portion of base pay until a later elected date. The plan offers returns on deferrals based upon either the prime rate, the S&P 500 Index, or parent company securities. In addition, the Company credits executives under the Deferred Compensation Plan with the amount of matching contribution that the executive was unable to contribute under the Incentive Thrift Plan due to the $170,000 compensation limit, determined by presuming a maximum executive deferral of $10,500. For calendar years 2000 and 2001 the maximum make-up contribution was approximately $250. Life Insurance Executives are offered life insurance funded by individual policies with death benefits of either two or three times the participant's annual salary depending upon the executive's level. These policies are structured in a manner that the employing company will recoup the premiums it has made into the policies at a later date. This program is under review due to a recently released Internal Revenue Service Notice on the subject matter. Incentive Compensation Plan There are two bonus plans applicable to executives, the Incentive Compensation Plan and the Incentive Share Plan. The former awards cash bonuses tied to the achievement of financial results and which are closely aligned with the company's strategic objectives. Annual financial targets and individual goals are established each year. In addition, depending upon the level of bonus awarded under the Incentive Compensation Plan, executives receive an award in the form of parent company securities under the Incentive Share Plan. If no cash bonus is paid, no Incentive Share Plan bonus is paid. For 2000, executives received incentive compensation bonuses under Change in Control provisions under the plans. Financial Counseling NEP pays for personal financial counseling for certain senior executives. As required by the Internal Revenue Service, a portion of the value of services is reported as taxable income to the executive. Stock Option Plan For description, please see the Option Grant and Fiscal Year-End Option Values tables.
OPTION GRANTS IN LAST FISCAL YEAR - ---------------------------------- Potential Realizable Value At Assumed Annual Rates of Stock Individual Grants Price Appreciation For Option Term - --------------------------------------------------------------------------------- Percent Of Number of Options Securities Granted Underlying To Exercise Option Employees Of Base Expi- Granted In Fiscal Price ration (#) Year ($/Sh) Date 5%($) 10 % ($) - --------------------------------------------------------------------------------- Marc F. Mahoney 35,886 20% 7.80 July 2010 176,047 446,139
In July 2000, National Grid granted stock options to Mr. Mahoney. The exercise price is 7.80 dollars (the mid market price on the day before the grant of the options) per share of National Grid stock. The options are for National Grid shares listed on the London Stock Exchange - not National Grid ADRs, each ADR being equal to 5 shares. The exercise price is 5.26 GBP and was converted to dollars for this table using a conversion of 1 GBP to 1.483 dollars. The options are not vested for 3 years and lapse after 10 years. The number of stock options granted was a multiple of base pay ranging from 1 to 3 times base pay. None of the options may be exercised if National Grid earnings per share growth does not exceed inflation on a rolling three year basis (EPS Exceeds Inflation) by 5.99%. Fifty percent of the options may be exercised if EPS Exceeds Inflation by 6% to 8.99% and 100% may be exercised if EPS Exceeds Inflation by 9% or more.
FISCAL YEAR-END OPTION VALUES -------------------------------------- Number of Value of Securities Unexercised Underlying In-the-Money Unexercised Options at Options at 3/31/01 ($)(a)(b) Name 3/31/01 (#)(a) - ------------------------------------------------------------------------------------ Peter G. Flynn 36,473(C) 0 Marc F. Mahoney 35,886 $9,579 Masheed H. Rosenqvist 16,023 0 James S. Robinson 14,458 0 Terry L. Schwennesen 14,315 0
(a) All of these options are unexercisable as they do not vest until 2003. (b) The dollar value for Mr. Mahoney was calculated as the difference between the exercise price (5.26 GBP) and the share price at fiscal year end (5.44 GBP) multiplied by the number of options and then converted to dollars using the ratio of 1 GBP to 1.483 dollars. The exercise price for the options of the other executives is 5.665 GBP and were not in-the-money. (c) Mr. Flynn holds a total of 38,900 options, however only 36,473 were allocated as compensation paid by NEP. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT National Grid USA owns 99.6 percent of the voting securities of NEP. The following table lists the holdings of National Grid American Depositary Receipts (ADRs) as of June 1, 2001 by the directors, the executive officers named in the Summary Compensation Table, and all directors and executive officers of the Company, as a group. All of the ADRs are held through the Incentive Thrift Plan described above.
Name ADRs Beneficially Owned L. Joseph Callan 0 Peter G. Flynn 2,990 Michael E. Jesanis 351 Marc F. Mahoney 178 Robert G. Powderly 235 Lawrence J. Reilly 291 James S. Robinson 409 Masheed H. Rosenqvist 216 Terry L. Schwennesen 198 Richard P. Sergel 276 Philip R. Sharp 0 All directors and executive officers, as a group (14 persons) 5,682
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Reference is made to ITEM 11. EXECUTIVE COMPENSATION. PART IV ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K List of Exhibits Unless otherwise indicated, the exhibits listed below are incorporated by reference to the appropriate exhibit numbers and the Commission file numbers indicated in parentheses. (3) (a) Articles of Organization as amended through June 25, 1987 (Exhibit 3(a) to 1988 Form 10-K, File No. 0-1229). Articles of Amendment dated January 27, 1998 (Exhibit B.18.a to National Grid USA 1999 Form U-5-S, File No. 30-33); Articles of Amendment dated February 25, 2000 (Exhibit 3(a) to 2000 Form 10-K, File No. 1-6564); Articles of Merger dated May 1, 2000 (Filed herewith). (b) By-laws of the Company as amended April 19, 2000 (Exhibit 3(b) to 2000 Form 10-K, File No. 1-6564). (10) Material Contracts (a) Boston Edison Company et al. and the Company: Amended REMVEC Agreement dated August 12, 1977 (Exhibit 5-4(d), File No. 2-61881). (i) Boston Edison Company et al. and the Company: REMVEC II Agreement dated on or about July 1, 1997 (Exhibit 10(a)(I) to NEES? 1997 Form 10- K, File No. 1-3446). (ii) Boston Edison Company et al. and the Company: Security Analysis Services Agreement dated on or about July 1, 1997 (Exhibit 10(a)(ii) to NEES? 1997 Form 10-K, File No. 1- 3446). (b) Connecticut Yankee Atomic Power Company et al. and the Company: Stockholders Agreement dated July 1, 1964 (Exhibit 13-9-A, File No. 2-2006); Power Purchase Contract dated July 1, 1964 (Exhibit 13-9-B, File No. 2-23006); Additional Power Contract dated as of April 30, 1984 and 1996; Amendatory Agreement dated as of December 4, 1996 (Exhibit 10(c) to 1996 Form 10-K, File No. 1-3446); Supplementary Power Contract dated as of April 1, 1987 (Exhibit 10(c) to 1987 Form 10-K, File No. 0-1229); Capital Funds Agreement dated September 1, 1964 (Exhibit 13-9-C, File No. 2-23006); Transmission Agreement dated October 1, 1964 (Exhibit 13-9-D, File No. 2-23006); Agreement revising Transmission Agreement dated July 1, 1979 (Exhibit to NEES' 1979 Form 10-K, File No. 1-3446); Amendment revising Transmission Agreement dated as of January 19, 1994 (Exhibit 10(c) to NEES? 1995 Form 10-K, File No. 1-3446); Five Year Capital Contribution Agreement dated November 1, 1980 (Exhibit 10(e) to NEES' 1980 Form 10-K, File No. 1-3446). (c) Maine Yankee Atomic Power Company et al. and the Company: Capital Funds Agreement dated May 20, 1968 and Power Purchase Contract dated May 20, 1968 (Exhibit 4-5, File No. 2-29145); Amendments dated as of January 1, 1984, March 1, 1984 (Exhibit 10(d) to NEES' 1983 Form 10-K, File No. 1-3446); October 1, 1984, and August 1, 1985 (Exhibit 10(d) to NEES' 1985 Form 10-K, File No. 1-3446); Stockholders Agreement dated May 20, 1968 (Exhibit 10-20; File No. 2-34267); Additional Power Contract dated as of February 1, 1984 (Exhibit 10(d) to NEES' 1985 Form 10-K, File No. 1-3446); 1997 Amendatory Agreement dated as of August 6, 1997 (Exhibit 10(d) to NEES? 1997 Form 10-K, File No. 1-3446). (d) New England Electric Transmission Corporation et al. and the Company: Phase I Terminal Facility Support Agreement dated as of December 1, 1981 (Exhibit 10(g) to NEES' 1981 Form 10-K, File No. 1-3446); Amendments dated as of June 1, 1982 and November 1, 1982 (Exhibit 10(f) to NEES' 1982 Form 10-K, File No. 1-3446); Agreement with respect to Use of the Quebec Interconnection dated as of December 1, 1981 (Exhibit 10(g) to NEES' 1981 Form 10-K, File No. 1-3446); Amendments dated as of May 1, 1982 and November 1, 1982 (Exhibit 10(f) to NEES' 1982 Form 10-K, File No. 1-3446); Amendment dated as of January 1, 1986 (Exhibit 10(f) to NEES' 1986 Form 10-K, File No. 1-3446); Agreement for Reinforcement and Improvement of the Company's Transmission System dated as of April 1, 1983 (Exhibit 10(f) to NEES' 1983 Form 10-K, File No. 1-3446); Lease dated as of May 16, 1983 (Exhibit 10(f) to NEES' 1983 Form 10-K, File No. 1-3446); Upper Development-Lower Development Transmission Line Support Agreement dated as of May 16, 1983 (Exhibit 10(f) to NEES' 1983 Form 10-K, File No. 1-3446). (e) Vermont Electric Transmission Company, Inc. et al. and the Company: Phase I Vermont Transmission Line Support Agreement dated as of December 1, 1981; Amendments dated as of June 1, 1982 and November 1, 1982 (Exhibit 10(g) to NEES' 1982 Form 10-K, File No. 1-3446); Amendment dated as of January 1, 1986 (Exhibit 10(h) to NEES' 1986 Form 10-K, File No. 1-3446). (f) New England Power Pool Agreement: (Exhibit 4(e), File No. 2-43025); Amendments dated July 1, 1972, March 1, 1973 (Exhibit 10-15, File No. 2-48543); Amendment dated March 15, 1974 (Exhibit 10-5, File No. 2-52775); Amendment dated June 1, 1975 (Exhibit 10-14, File No. 2-57831); Amendment dated September 1, 1975 (Exhibit 10-13, File No. 2-59182); Amendments dated December 31, 1976, January 31, 1977, July 1, 1977, and August 1, 1977 (Exhibit 10-16, File No. 2-61881); Amendments dated August 15, 1978, January 3, 1980, and February 1980 (Exhibit 10-3, File No. 2-68283); Amendment dated September 1, 1981 (Exhibit 10(h) to NEES' 1981 Form 10-K, File No. 1-3446); Amendment dated December 1, 1981 (Exhibit 10(h) to NEES' 1982 Form 10-K, File No. 1-3446); Amendments dated June 1, 1982, June 15, 1983, and October 1, 1983 (Exhibit 10(i) to NEES' 1983 Form 10-K, File 1-3446); Amendments dated August 1, 1985, August 15, 1985, September 1, 1985, and January 1, 1986 (Exhibit 10(i) to NEES' 1985 Form 10-K, File No. 1-3446); Amendment dated September 1, 1986 (Exhibit 10(i) to NEES' 1986 Form 10-K, File No. 1-3446); Amendment dated April 30, 1987 (Exhibit 10(i) to NEES' 1987 Form 10-K, File No. 1-3446); Amendments dated March 1, 1988 and May 1, 1988 (Exhibit 10(i) to NEES' 1988 Form 10-K, File No. 1-3446); Amendment dated March 15, 1989 (Exhibit 10(i) to 1989 NEES Form 10-K, File No. 1-3446); Amendment dated October 1, 1990 (Exhibit 10(i) to 1990 NEES Form 10-K, File No. 1-3446); Amendment dated October 1, 1990 Exhibit 10(i) to 1990 NEES Form 10-K, File No. 1-3446); Amendment dated as of September 15, 1992 (Exhibit 10(i) to 1992 NEES Form 10-K, File No. 1-3446); Amendments dated as of June 1, 1993, July 1, 1995, and September 1, 1995 (Exhibit 10(i) to 1995 NEES Form 10-K, File No. 1-3446); Amendment dated as of December 1, 1996 (Exhibit 10(i) to 1996 NEES Form 10- K, File No. 1-3446). Amendment dated as of September 1, 1997 and Amendment dated as of November 15, 1997 (Exhibit 10(i) to 1997 NEES Form 10-K, File No. 1- 3446); Second Restated New England Power Pool Agreement as amended through the Fifty-first Agreement amending the New England Power Pool Agreement issued on December 30, 1999 (Exhibit 10(i) to 1999 Form 10-K, File No. 1-6564); Restated New England Power Pool Agreement as amended through the Sixty-sixth Agreement amending New England Power Pool Agreement (Filed herewith). (g) National Grid USA Service Company, Inc. and the Company: Specimen of Service Contract (filed herewith). (h) Massachusetts Electric Company, et al. and the Company: Form of Mutual Assistance Agreement (Exhibit 10(n) to 1996 Form 10-K, File No. 0-1229). (i) Massachusetts Electric Company, et al. and the Company: Restructuring Settlement Agreement approved by the Massachusetts Department of Public Utilities (Exhibit 10(o) to 1996 Form 10-K, File No. 0-1229). (j) Public Service Company of New Hampshire et al. and the Company: Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units dated as of May 1, 1973; Amendments dated May 24, 1974, June 21, 1974, September 25, 1974 and October 25, 1974 (Exhibit 10-18(b), File No. 2-52820); Amendment dated January 31, 1975 (Exhibit 10-16(b), File No. 2-57831); Amendments dated April 18, 1979, April 25, 1979, June 8, 1979, October 11, 1979, December 15, 1979, June 16, 1980, and December 31, 1980 (Exhibit 10(i) to NEES' 1980 Form 10-K, File No. 1-3446); Amendments dated June 1, 1982, April 27, 1984, and June 15, 1984 (Exhibit 10(j) to NEES' 1984 Form 10-K, File No. 1-3446); Amendments dated March 8, 1985, March 14, 1986, May 1, 1986, and September 19, 1986 (Exhibit 10(j) to NEES' 1986 Form 10-K, File No. 1-3446); Amendment dated November 12, 1987 (Exhibit 10(j) to NEES' 1987 Form 10-K, File No. 1-3446); Amendment dated January 13, 1989 (Exhibit 10(j) to NEES' 1990 Form 10-K, File No. 1-3446); Seventh Amendment as of November 1, 1990 (Exhibit 10(m) to NEES' 1991 Form 10-K, File No. 1-3446). Transmission Support Agreement dated as of May 1, 1973 (Exhibit 10-23, File No. 2-49184); Instrument of Transfer to the Company with respect to the New Hampshire Nuclear Units and Assumptions of Obligations dated December 17, 1975 and Agreement Among Participants in New Hampshire Nuclear Units, certain Massachusetts Municipal Systems and Massachusetts Municipal Wholesale Electric Company dated May 28, 1976 (Exhibit 16(c), File No. 2-57831); Seventh Amendment To and Restated Agreement for Seabrook Project Disbursing Agent dated as of November 1, 1990 (Exhibit 10(m) to NEES' 1991 Form 10-K, File No. 1-3446); Amendments dated as of June 29, 1992 (Exhibit 10(j) to NEES' 1992 Form 10-K, File No. 1- 3446). Settlement Agreement dated as of July 19, 1990 between Northeast Utilities Service Company and the Company (Exhibit 10(m) to NEES' 1991 Form 10-K, File No. 1-3446). Seabrook Project Managing Agent Operating Agreement dated as of June 29, 1992, Amendment to Seabrook Project Managing Agent Operating Agreement dated as of June 29, 1992 (Exhibit 10(j) to NEES' 1992 Form 10-K, File No. 1- 3446). (k) Vermont Yankee Nuclear Power Corporation et al. and the Company: Capital Funds Agreement dated February 1, 1968, Amendment dated March 12, 1968 and Power Purchase Contract dated February 1, 1968 (Exhibit 4-6, File No. 2-29145); Amendments dated as of June 1, 1972, April 15, 1983 (Exhibit 10(k) to NEES' 1983 Form 10-K, File No. 0-1229) and April 24, 1985 (Exhibit 10(n) to NEES' 1985 Form 10-K, File No. 1-3446); Amendment dated as of June 1, 1985 (Exhibit 10(n) to 1988 Form 10-K, File No. 0-1229); Amendments dated May 6, 1988 (Exhibit 10(n) to 1988 Form 10-K, File No.0-1229); Amendment dated as of June 15, 1989 (Exhibit 10(k) to 1989 NEES Form 10-K, File No. 1-3446); Additional Power Contract dated as of February 1, 1984 (Exhibit 10(k) to NEES' 1983 Form 10-K, File No. 1-3446); Guarantee Agreement dated as of November 5, 1981 (Exhibit 10(j) to NEES' 1981 Form 10-K, File No. 1-3446). (l) Yankee Atomic Electric Company et al. and the Company: Amended and Restated Power Contract dated April 1, 1985 (Exhibit 10(l) to NEES' 1985 Form 10-K, File No. 1-3446); Amendment dated May 6, 1988 (Exhibit 10(l) to NEES' 1988 Form 10-K, File No. 1-3446); Amendments dated as of June 26, 1989 and July 1, 1989 (Exhibit 10(l) to 1989 NEES Form 10-K, File No. 1-3446); Amendment dated as of February 1, 1992 (Exhibit 10(l) to 1992 NEES Form 10-K, File No. 1-3446). *(m) New England Electric Companies' Deferred Compensation Plan as amended through February 28, 1998 (Exhibit 10(l) to NEES' 1998 Form 10-K, File No. 1-3446); Amendments effective as of March 1, 1999 and September 1, 1999 (Exhibit 10(p) to 1999 Form 10-K, File No. 1-6564). *(n) New England Electric System Companies Retirement Supplement Plan as amended through June 1, 1996 (Exhibit 10(n) to NEES' 1996 Form 10-K, File No. 1-3446); Amendment dated as of March 1, 1999 (Exhibit 10(q) to 1999 Form 10-K, File No. 1-6564). *(o) New England Electric Companies' Executive Supplemental Retirement Plan I as amended through December 11, 1998 (Exhibit 10(n) to NEES' 1998 Form 10-K, File No. 1-3446); Amendment dated as of March 1, 1999 (Exhibit 10(r) to 1999 Form 10-K, File No. 1-6564). *(p) New England Electric Companies Executive Retirees Health and Life Insurance Plan as Amended and Restated January 1, 1996 (Exhibit 10(o) to NEES? 1998 Form 10-K, File No. 1-3446). *(q) New England Electric Companies' Incentive Compensation Plan I as amended through January 1, 1998 (Exhibit 10(p) to NEES' 1998 Form 10-K, File No. 1-3446). *(r) New England Electric Companies' Incentive Compensation Plan II as amended through January 1, 1998 (Exhibit 10(q) to NEES' 1998 Form 10-K, File No. 1-3446). *(s) New England Electric Companies' Incentive Compensation Plan III as amended through January 1, 1998 (Exhibit 10(r) to NEES' 1998 Form 10-K, File No. 1-3446). *(t) New England Electric Companies' Senior Incentive Compensation Plan as amended through January 1, 1998 (Exhibit 10(s) to NEES' 1998 Form 10-K, File No. 1-3446). *(u) Forms of Life Insurance Program (Exhibit 10(s) to NEES' 1986 Form 10-K, File No. 1-3446); and Form of Life Insurance (Collateral Assignment) (Exhibit 10(t) to NEES' 1991 Form 10-K, File No. 1-3446). *(v) New England Electric Companies' Incentive Share Plan as amended through February 24, 1997 (Exhibit 10(w) to NEES? 1996 Form 10-K, File No. 1-3446); Amendment dated as of March 1, 1999 Exhibit 10(y) to 1999 Form 10-K, File No. 1-6564). *(w) Forms of Severance Protection Agreement (Exhibit 10(z) to NEES? 1996 Form 10-K, File No. 1-3446). Forms of Severance Protection Agreements (Exhibit 10(y) to NEES? 1998 Form 10-K, File No. 1-3446). (x) New England Hydro-Transmission Electric Company, Inc. et al. and the Company: Phase II Massachusetts Transmission Facilities Support Agreement dated as of June 1, 1985 (Exhibit 10(t) to NEES' 1986 Form 10-K, File No. 1-3446); Amendment dated as of May 1, 1986 (Exhibit 10(t) to NEES' 1986 Form 10-K, File No. 1-3446); Amendments dated as of February 1, 1987, June 1, 1987, September 1, 1987, and October 1, 1987 (Exhibit 10(u) to NEES' 1987 Form 10-K, File No. 1-3446); Amendment dated as of August 1, 1988 (Exhibit 10(u) to NEES' 1988 Form 10-K, File No. 1-3446); Amendment dated January 1, 1989 (Exhibit 10(u) to NEES' 1990 Form 10-K, File No. 1-3446). (y) New England Hydro-Transmission Corporation et al. and the Company: Phase II New Hampshire Transmission Facilities Support Agreement dated as of June 1, 1985 (Exhibit 10(u) to NEES' 1986 Form 10-K, File No. 1-3446); Amendment dated as of May 1, 1986 (Exhibit 10(u) to NEES' 1986 Form 10-K, File No. 1-3446); Amendments dated as of February 1, 1987, June 1, 1987, September 1, 1987, and October 1, 1987 (Exhibit 10(v) to NEES' 1987 Form 10-K, File No. 1-3446). Amendment dated as of August 1, 1988 (Exhibit 10(v) to NEES' 1988 Form 10-K, File No. 1-3446); Amendments dated January 1, 1989 and January 1, 1990 (Exhibit 10 (v) to NEES' 1990 Form 10-K, File No. 1-3446). (z) Vermont Electric Power Company et al. and the Company: Phase II New England Power AC Facilities Support Agreement dated as of June 1, 1985 (Exhibit 10(v) to NEES' 1986 Form 10-K, File No. 1-3446); Amendment dated as of May 1, 1986 (Exhibit 10(v) to NEES' 1986 Form 10-K, File No. 1-3446). Amendments dated as of February 1, 1987, June 1, 1987, and September 1, 1987 (Exhibit 10(w) to NEES' 1987 Form 10-K, File No. 1-3446); Amendment dated as of August 1, 1988 (Exhibit 10(w) to NEES' 1988 Form 10-K, File No. 1-3446). (aa) USGen New England Contracts (i) Asset Purchase Agreement among the Company, The Narragansett Electric Company and, USGen New England, Inc. dated as of August 5, 1997 (Exhibit 2 to NEES? Form 10-Q for period ended September 30, 1997, File No. 1-3446); Amendment No. 1 dated as of September 25, 1997, Amendment No. 2 dated as of October 29, 1997, Amendment No. 3 dated as of August 5, 1997, Amendment No. 4 dated as of September 1, 1998 (Exhibit 10(ee)(i) to 1999 Form 10-K, File No. 1- 6564). (ii) Wholesale Sales Agreement between the Company and USGen New England, Inc. dated as of August 5, 1997 (Exhibit 10(gg)(ii) to 1997 Form 10-K, File No. 1-6564); Amendment No. 1 dated as of September 25, 1997, Amendment No. 2 dated as of September 1, 1998 (Exhibit 10(ee)(ii) to 1999 Form 10-K, File No. 1-6564); Amendment No. 3 dated as of December 23, 1999 (Filed herewith). (iii) Amended and Restated PPA Transfer Agreement between the Company and USGen New England, Inc. dated as of October 29, 1997 (Filed herewith). (iv) Form of PSA Performance Support Agreement between the Company, USGen New England, Inc., and each of the following; Unitil Power Corp. (Ocean State), Braintree Electric Light Department, Littleton Electric Light Department, Massachusetts Government Land Bank, Shrewsbury Electric Light Plant, and Taunton Municipal Light Plant, dated as of August 5, 1997 (Exhibit 10(gg)(iv) to 1997 Form 10-K, File No. 1- 6564). (v) Quebec Interconnection Transfer Agreement between the Company, The Narragansett Electric Company, and USGen New England, Inc. dated as of September 1, 1998 (Exhibit 10(ee)(v) to 1999 Form 10-K, File No. 1- 6564). (bb) Montaup (now New England Power Company) (i) Equity Funding Agreement for New England Hydro-Transmission Corporation dated as of June 1, 1985, between New England Hydro- Transmission Corporation and several New England electric utilities, including Montaup (now New England Power Company) as amended as of May 1, 1986 and September 1, 1987 (Exhibits 10-96 and 10-97, Form 10-K of EUA for 1986, File No. 1-5366; Exhibit 10-116, Form 10-K of EUA for 1987, File No. 1-5366). (ii) Equity Funding Agreement for New England Hydro-Transmission Electric Company, Inc. dated as of June 1, 1985, between New England Hydro-Transmission Electric Company, Inc. and several New England electric utilities, including Montaup (now New England Power Company) as amended as of May 1, 1986 and September 1, 1987 (Exhibits 10-98 and 10-99, Form 10-K of EUA for 1986, File No. 1-5366; Exhibit 10-117, Form 10-K of EUA for 1987, File No. 1-5366). (iii) Unit Power Agreement for the Sale of Unit Capacity and Energy from Ocean State Power Project to Montaup Electric Company (now New England Power Company) dated as of May 14, 1986 as amended as of August 27, 1986, September 27, 1988, October 21, 1988, July 21, 1989, February 7, 1990, December 21, 1990, and February 12, 1996 (Exhibits 10- 101 and 10-102, Form 10-K of EUA for 1986, File No. 1-5366; Exhibits 10-106 and 10- 107, Form 10-K of EUA for 1988, File No. 1- 5366; Exhibit 10-106, Form 10-K of EUA for 1989, File No. 1-5366; Exhibits 10-86 and 10-87, Form 10-K of Eastern Edison for 1990, File No. 0-8480; Exhibit 10-39.05 and 10-40.05, Form 10-K of EUA for 1996, File No. 1-5366). (iv) Power Purchase Agreement dated as of October 17, 1986, between Northeast Energy Associates and Montaup (now New England Power Company) as amended as of June 28, 1989 (Exhibit 10-103, Form 10-K of EUA for 1986, File No. 1-5366; Exhibit 10-103, Form 10-K of EUA for 1989, File No. 1-5366). (v) Unit Power Agreement for the Sale of Second Unit Capacity and Energy from Ocean State Power Project to Montaup Electric Company (now New England Power Company) dated as of September 28, 1988 as amended as of July 21, 1989, February 7, 1990, and February 12, 1996 and a Supplemental Agreement dated July 21, 1989 (Exhibit 10-104, Form 10-K of EUA for 1989, File No. 1-5366; Exhibits 10- 41.05 and 10-42.05, Form 10-K of EUA for 1996, File No. 1-5366; Exhibit No. 10-88, Form 10-K of Eastern Edison for 1990, File No. 0-8480). (vi) Amended and Restated Power Sales Contract by and between Southern Energy Canal L.L.C. (as assignee of Canal Electric Company) and Montaup Electric Company (now New England Power Company), dated December 18, 1988 and effective on December 30, 1998 (Filed herewith). (vii) Power Purchase Agreement between Entergy Nuclear Generation Company and Montaup Electric Company (now New England Power Company), dated November 18, 1998 (Filed herewith). (viii) Power Purchase and Sale Agreement between Montaup Electric Company (now New England Power Company) and Constellation Power Source, Inc., dated December 21, 1998 (Filed herewith). (ix) PPA Transfer Agreement between Montaup Electric Company (now New England Power Company) and TransCanada Power Marketing Ltd, dated April 7, 1998 (Filed herewith). (x) Reinstatement Amendment, dated as of July 6, 1999 by and among Southern Energy Canal, L.L.C. and Montaup Electric Company (now New England Power Company) (Filed herewith). (13) 2001 Annual Report to Stockholders (24) Power of Attorney (filed herewith). Reports on Form 8-K NEP filed a report on Form 8-K dated February 14, 2001 containing Item 5. NEW ENGLAND POWER COMPANY SIGNATURES Pursuant to the Requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company. NEW ENGLAND POWER COMPANY s/Peter G. Flynn Peter G. Flynn President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company. (Signature and Title) Principal Executive Officer s/Peter G. Flynn Peter G. Flynn President Principal Financial Officer s/John G. Cochrane John G. Cochrane Treasurer Principal Accounting Officer s/Edward Capomacchio, Jr. Edward A. Capomacchio Controller Directors (a majority) L. Joseph Callan Peter G. Flynn Michael E. Jesanis Robert G. Powderly s/John G. Cochrane Lawrence J. Reilly All by: Terry L. Schwennesen John G. Cochrane Richard P. Sergel Attorney-in-fact Philip R. Sharp Date (as to all signatures on this page) June 28, 2001 NEP EXHIBIT INDEX ------------- Exhibit No. Description Page - ----------- ----------- ---- (3)(a) Articles of Organization as Incorporated amended through June 27, 1998 by Reference Articles of Merger dated Filed May 1, 2000 herewith (3)(b) By-laws of the Company as Incorporated amended April 19, 2000 by Reference (10)(a) Boston Edison Company et al. Incorporated and the Company: Amended by Reference REMVEC Agreement dated August 12, 1977 (10)(a)(i) Boston Edison Company et al. Incorporated and the Company: REMVEC II by Reference Agreement dated on or about July 1, 1997 (10)(a)(ii) Boston Edison Company et al. Incorporated and the Company: Security by Reference Analysis Services Agreement dated on or about July 1, 1997 (10)(b) Connecticut Yankee Atomic Power Incorporated Company et al. and the Company: by Reference Stockholders Agreement dated July 1, 1964; Power Purchase Contract dated July 1, 1964; Additional Power Contract dated as of April 30, 1984 and 1996; Amendatory Agreement dated as of December 4, 1996; Supplementary Power Contract dated as of April 1, 1987; Capital Funds Agreement dated September 1, 1964; Transmission Agreement dated October 1, 1964; Agreement revising Transmission Agreement dated July 1, 1979; Amendment revising Transmission Agreement dated as of January 19, 1994; Five Year Capital Contribution Agreement dated November 1, 1980 (10)(c) Maine Yankee Atomic Power Incorporated Company et al. and the Company: by Reference Capital Funds Agreement dated May 20, 1968 and Power Purchase Contract dated May 20, 1968; and Amendments thereto; Stockholders Agreement dated May 20, 1968; Additional Power Contract dated as of February 1, 1984; 1997 Amendatory Agreement dated as of August 6, 1997 (10)(d) New England Electric Incorporated Transmission Corporation et al. by Reference and the Company: Phase I Terminal Facility Support Agreement dated as of December 1, 1981; Amendments dated as of June 1, 1982 and November 1, 1982; Agreement with respect to Use of the Quebec Interconnection dated as of December 1, 1981; Amendments dated as of May 1, 1982 and November 1, 1982; Amendment dated as of January 1, 1986; Agreement for Reinforcement and Improvement of the Company's Transmission System dated as of April 1, 1983; Lease dated as of May 16, 1983; Upper Development-Lower Development Transmission Line Support Agreement dated as of May 16, 1983 (10)(e) Vermont Electric Transmission Incorporated Company, Inc. et al. and the by Reference Company: Phase I Vermont Transmission Line Support Agreement dated as of December 1, 1981 and Amendments thereto (10)(f) New England Power Pool Filed herewith Agreement and Amendments thereto (10)(g) National Grid USA Service Filed herewith Company, Inc. and the Company: Specimen of Service Contract (10)(h) Massachusetts Electric Incorporated Company, et al. and the by Reference Company: Form of Mutual Assistance Agreement (10)(i) Massachusetts Electric Incorporated Company, et al. and the by Reference Company: Restructuring Settlement Agreement approved by the Massachusetts Department of Public Utilities (10)(j) Public Service Company of New Incorporated Hampshire et al. and the by Reference Company: Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units dated as of May 1, 1973 and Amendments thereto; Seventh Amendment as of November 1, 1990; Transmission Support Agreement dated as of May 1, 1973; Instrument of Transfer to the Company with respect to the New Hampshire Nuclear Units and Assumptions of Obligations dated December 17, 1975 and Agreement Among Participants in New Hampshire Nuclear Units, certain Massachusetts Municipal Systems and Massachusetts Municipal Wholesale Electric Company dated May 28, 1976; Seventh Amendment To and Restated Agreement for Seabrook Project Disbursing Agent dated as of November 1, 1990; Amendments dated as of June 29, 1992; Settlement Agreement dated as of July 19, 1990 between Northeast Utilities Service Company and the Company; Seabrook Project Managing Agent Operating Agreement dated as of June 29, 1992; and Amendment thereto (10)(k) Vermont Yankee Nuclear Power Incorporated Corporation et al. and the by Reference Company: Capital Funds Agreement dated February 1, 1968, Amendment dated March 12, 1968 and Power Purchase Contract dated February 1, 1968 and Amendments thereto; Additional Power Contract dated as of February 1, 1984; Guarantee Agreement dated as of November 5, 1981 1999 Amendatory Agreements Incorporated by Reference (10)(l) Yankee Atomic Electric Company Incorporated et al. and the Company: by Reference Amended and Restated Power Contract dated April 1, 1985 and Amendments thereto (10)(m) New England Electric Companies' Incorporated Deferred Compensation Plan as by Reference amended through February 28, 1998 and amendments thereto (10)(n) New England Electric System Incorporated Companies Retirement Supplement by Reference Plan as amended through June 1, 1996 and an Amendment thereto (10)(o) New England Electric Companies' Incorporated Executive Supplemental Retirement by Reference Plan I as amended through December 11, 1998 and an Amendment thereto (10)(p) New England Electric Companies' Incorporated Executive Retirees Health and Life by Reference Insurance Plan as Amended and Restated January 1, 1996 (10)(q) New England Electric Companies' Incorporated Incentive Compensation Plan I as by Reference amended through January 1, 1998 (10)(r) New England Electric Companies' Incorporated Incentive Compensation Plan II as by Reference amended through January 1, 1998 (10)(s) New England Electric Companies' Incorporated Incentive Compensation Plan III as by Reference amended through January 1, 1998 (10)(t) New England Electric Companies' Incorporated Senior Incentive Compensation by Reference Plan as amended through January 1, 1998 (10)(u) Forms of Life Insurance Program Incorporated and Form of Life Insurance by Reference (Collateral Assignment) (10)(v) New England Electric Companies? Incorporated Incentive Share Plan as amended by Reference through February 24, 1997 and an Amendment thereto (10)(w) Forms of Severance Protection Incorporated Agreements by Reference (10)(x) New England Hydro-Transmission Incorporated Electric Company, Inc. et al. by Reference and the Company: Phase II Massachusetts Transmission Facilities Support Agreement dated as of June 1, 1985 and Amendments thereto (10)(y) New England Hydro-Transmission Incorporated Corporation et al. and the by Reference Company: Phase II New Hampshire Transmission Facilities Support Agreement dated as of June 1, 1985 and Amendments thereto (10)(z) Vermont Electric Power Company Incorporated et al. and the Company: Phase by Reference II New England Power AC Facilities Support Agreement dated as of June 1, 1985 and Amendments thereto (10)(aa)(i) Asset Purchase Agreement between Incorporated USGen New England and the Company by Reference and The Narragansett Electric Company dated as of August 5, 1997 (10)(aa)(ii) Wholesale Sales Agreement between Filed herewith the Company and USGen New England, Inc. dated as of August 5, 1997 and Amendments thereto (10)(aa)(iii) Amended and Restated PPA Transfer Filed herewith Agreement between the Company and USGen New England, Inc. dated as of October 29, 1997 (10)(aa)(iv) Form of PSA Performance Support Incorporated Agreement between the Company, by Reference USGen New England, Inc., and various Wholesale Customers dated as of August 5, 1997 (10)(aa)(v) Quebec Interconnection Transfer Incorporated Agreement between the Company, by Reference The Narragansett Electric Company, and USGen New England, Inc., dated as of September 1, 1998 (10)(bb)(i) Equity Funding Agreement for New Incorporated England Hydro-Transmission by Reference Corporation dated as of June 1, 1985, between New England Hydro-Transmission Corporation and several New England Electric utilities, including Montaup as amended as of May 1, 1986 and September 1, 1987 (10)(bb)(ii) Equity Funding Agreement for New Incorporated England Hydro-Transmission by Reference Corporation dated as of June 1, 1985, between New England Hydro- Transmission Electric Company, Inc. and several New England electric utilities, including Montaup as amended as of May 1, 1986 and September 1, 1987 (10)(bb)(iii) Unit Power Agreement for Sale of Incorporated Unit Capacity and Energy from by Reference Ocean State Power Project to Montaup Electric Company dated as of May 14, 1986 and amendements thereto. (10)(bb)(iv) Power Purchase Agreement dated as Incorporated of October 17, 1986, between by Reference Northeast Energy Associates and Montaup as amended as of June 28, 1989 (10)(bb)(v) Unit Power Agreement for the sale Incorporated of Second Unit Capacity and Energy by Reference from Ocean State Power Project to Montaup Electric Company dated as Of September 28, 1988 and amendments thereto. (10)(bb)(vi) Amended and Restated Power Sales Filed herewith Contract by and between Southern Energy Canal L.L.C. and Montaup Electric Company, dated December 18, 1988 and effective on December 30, 1998. (10)(bb)(vii) Power Purchase Agreement between Filed herewith Entergy Nuclear Generation Company and Montaup Electric Company dated November 18, 1998 (10)(bb)(viii)Power Purchase and Sale Agreement Filed herewith between Montaup Electric Company and Constellation Power Source, Inc. dated December 21, 1998 (10)(bb)(ix) PPA Transfer Agreement between Filed herewith Montaup Electric Company and TransCanada Power Marketing Ltd, Dated April 7, 1998 (10)(bb)(x) Reinstatement Amendment, dated Filed herewith as of July 6, 1999 by and among Southern Energy Canal, L.L.C. and Montaup Electric Company (13) 2001 Annual Report to Filed herewith Stockholders (24) Power of Attorney Filed herewith EXHIBIT 3(a) New England Power Company Articles of Merger As of May 1, 2000, Montaup Electric Company and New England Power Company, the constituent corporations, merged into New England Power Company. The undersigned officers of each of the constituent corporations certify under the penalties of perjury as follows: 1. An agreement of merger has been duly adopted in compliance with the requirements of General Laws, Chapter 164, Section 96 and 102A, and will be kept as provided by Section 102A thereof. The surviving corporation will furnish a copy of said agreement to any of its stockholders, or to any person who was a stockholder of any constituent corporation, upon written request and without charge. 2. The effective date of the merger determined pursuant to the agreement of merger shall be the date approved and filed by the Secretary of the Commonwealth. If a later effective date is desired, specify such date which shall not be more than thirty days after the date of filing. 3. The following amendments to the Articles of Organization of the surviving corporation have been effected pursuant to the agreement of merger: None. Exhibit 10 (f) NEW ENGLAND POWER POOL RESTATED NEW ENGLAND POWER POOL AGREEMENT FERC ELECTRIC THIRD REVISED RATE SCHEDULE NO. 5 (As amended through the Sixty-Sixth Agreement Amending New England Power Pool Agreement) THIS AGREEMENT dated as of the first day of September, 1971, as amended, was entered into by the signatories thereto for the establishment by them of a bulk power pool to be known as NEPOOL and is restated by an amendment dated as of December 1, 1996 and amended by subsequent amendments. In consideration of the mutual agreements and undertakings herein, the signatories hereby agree as follows: PART ONE INTRODUCTION SECTION 1 DEFINITIONS Whenever used in this Agreement, in either the singular or the plural number, the terms contained in this Section shall have the meanings set forth herein. If a term is identified in this Section with an asterisk (*), the definition may be modified in certain cases pursuant to the last subsection of this Section 1. If a term includes language in brackets ([ ]), such language shall become effective automatically on the CMS/MSS Effective Date. Certain definitions are included in braces ({ }). These definitions are still subject to further modification or deletion and will not become effective except pursuant to a further Commission order. To the extent appropriate to reflect the understandings of this introductory text, future composite copies of this Agreement may remove brackets ([]), and braces ({ }), and part or all of this explanatory introductory language, and may renumber the definitions, without further specific amendment to or restatement of this Agreement. 1.1 Accepted Electric Industry Practice shall mean any of the practices, methods, and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods, and acts which, in the exercise of reasonable judgement in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Accepted Electric Industry Practice is not limited to a single, optimum practice method or act to the exclusion of others, but rather is intended to include acceptable practices, methods, or acts generally accepted in the region. 1.2 Adjusted Load * (not less than zero) of a Participant during any particular hour is the Participant's Load during such hour less any Kilowatts received (or Kilowatts which would have been received except for the application of Section 14.7(b)) by such Participant pursuant to a Firm Contract. 1.3 Adjusted Monthly Peak of a Participant for a month is its Monthly Peak, provided that if there has been a transfer between Participants, in whole or part, of the responsibilities under this Agreement during such month pursuant to a Firm Contract, the Adjusted Monthly Peak of each such Participant shall reflect the effect of such transaction, but the Adjusted Monthly Peak of a Participant shall not be changed from the Monthly Peak to reflect the effect of any other transaction. 1.4 Adjusted Net Interchange of a Participant for an hour is (a) the Kilowatts produced by or delivered to the Participant from its Energy Entitlements or pursuant to arrangements entered into under Section 14.6, as adjusted in accordance with Market Rules approved by the Markets Committee to take account of associated electrical losses, as appropriate, minus (b) the sum of (i) the Electrical Load of the Participant for the hour, and (ii) the kilowatthours delivered by such Participant to other Participants pursuant to Firm Contracts or System Contracts, in accordance with the treatment agreed to pursuant to Section 14.7(a), together with any associated electrical losses. This section shall terminate and be of no further force and effect after final settlement with respect to services rendered until the CMS/MSS Effective Date. 1.5 Administrative Procedures are procedures adopted by the System Operator in order to fulfill its responsibilities to apply and implement NEPOOL System Rules. 1.6 AGC Capability of an electric generating unit or combination of units is the maximum dependable ability of the unit or units to increase or decrease the level of output within a time frame specified by Market Rules approved by the Markets Committee, in response to a remote direction from the System Operator in order to maintain currently proper power flows into and out of the NEPOOL Control Area and to control frequency. 1.7 AGC Entitlement is the right for the purposes of settlement to all or a portion of the AGC Capability of a generating unit or units to which an Entity is entitled as an owner (either sole or in common) or as a purchaser under a Unit Contract, reduced by any portion thereof which such Entity is selling pursuant to a Unit Contract. An AGC Entitlement in a generating unit or units may, but need not, be combined with any other Entitlements relating to such generating unit or units and may be transferred separately from the related Installed Capability Entitlement, Energy Entitlement[, 4-Hour Reserve Entitlement] or Operating Reserve Entitlement. 1.8 Agreement is this restated contract and attachments, including the Tariff, as amended and restated from time to time. 1.9 Annual Transmission Revenue Requirements of a Participant's PTF or of all Participants' PTF for purposes of this Agreement are the amounts determined in accordance with Attachment F to the Tariff. 1.10 Automatic Generation Control or AGC is a measure of the ability of a generating unit or portion thereof to respond automatically within a specified time to a remote direction from the System Operator to increase or decrease the level of output in order to control frequency and to maintain currently proper power flows into and out of the NEPOOL Control Area. 1.11 Balloting Agent is the Secretary of the Participants Committee. 1.12 Bid Price is the amount which a Participant offers to accept, in a notice furnished to the System Operator by it or on its behalf in accordance with the Market Rules approved by the Markets Committee, as compensation for (i) furnishing Installed Capability to other Participants pursuant to this Agreement, or (ii) preparing the start up or starting up or increasing the level of operation of, and thereafter operating, a generating unit or units to provide Energy to other Participants pursuant to this Agreement, or (iii) having a unit or units available to provide Operating Reserve to other Participants pursuant to this Agreement, or (iv) having a unit or units available to provide AGC to other Participants pursuant to this Agreement, or (v) providing to other Participants Installed Capability, Energy, Operating Reserve and/or AGC pursuant to a Firm Contract or System Contract in accordance with Section 14.7. This definition shall terminate and be of no further force and effect after final settlement with respect to services rendered before the CMS/MSS Effective Date. 1.13 Bilateral Transaction is a transaction, including a Firm Contract, System Contract, Load Asset Contract or other contract, between two or more Participants submitted for the transfer of Settlement Obligations in accordance with the Market Rules with respect to Installed Capability, Energy at one or more Locations within the NEPOOL Control Area, Operating Reserve[, 4-Hour Reserve] and/or AGC. When used in the plural form, it may be any or all such arrangements or combinations thereof, as the context requires. 1.14 Clearing Price is the amount determined for Energy, Operating Reserve and AGC pursuant to Sections 14.8, 14.9 and 14.10, respectively, until the CMS/MSS Effective Date, and thereafter pursuant to Sections 14A.8(a), 14A.8(b) and 14A.8(c), respectively. 1.15 CMS is the Congestion management system under the NEPOOL arrangements, including Locational Prices for Energy and Financial Congestion Rights. 1.16 CMS/MSS Effective Date is the date on which the provisions of Section 14A shall become fully effective and supersede the provisions of Section 14. The CMS/MSS Effective Date shall be a date fixed by the Participants Committee which occurs after NEPOOL System Rules and computer programs to fully implement Section 14A of the Agreement and Schedules 13, 14 and 15 of the Tariff are in place and at least thirty (30) days have elapsed since the Participants Committee has provided notice to the Commission of the proposed CMS/MSS Effective Date. 1.17 Commission is the Federal Energy Regulatory Commission. 1.18 Congestion is a condition of the NEPOOL Transmission System in which transmission limitations prevent unconstrained regional economic dispatch of the power system. Following the CMS/MSS Effective Date, Congestion is the condition that results in the Congestion Component of the Locational Price at one Location being different from the Congestion Component of the Locational Price at another Location during any given hour of the Dispatch Day in the Day-Ahead Market and Real-Time Market. 1.19 Congestion Component is the component of the Nodal Price that reflects the marginal cost of Congestion at a given Node or External Node relative to the Reference Node. When used in connection with Zonal Price and Hub Price, the term Congestion Component refers to the Congestion Components of the Nodal Prices that comprise the Zonal Price and Hub Price averaged or weighted in the same way that Nodal Prices are averaged or weighted to determine the Zonal Price and Hub Price, respectively. 1.20 Congestion Cost is the cost of Congestion as defined in Section 14.14 of the Agreement and Section 24 of the Tariff for services until the CMS/MSS Effective Date. On and after the CMS/MSS Effective Date, Congestion Cost is the cost of Congestion as measured by the difference between the Congestion Components of the Locational Prices at different Locations and/or Reliability Regions on the NEPOOL Transmission System. 1.21 Congestion Revenue for each hour is the surplus revenue, if any, for each hour after netting the revenues paid and collected for the Congestion Components of Locational Price for all Energy transactions on the NEPOOL Transmission System, including Energy deliveries by Non-Participant Transmission Customers taking service under the Tariff, as settled in accordance with the Market Rules. Congestion Revenue is calculated for each hour of the Dispatch Day in the Day-Ahead Market and Real-Time Market as provided in Section E of Schedule 14 of the Tariff and the applicable Market Rules. 1.22 Congestion Revenue Fund is the fund of Congestion Revenue administered by the System Operator in accordance with Section 14A.17 of the Agreement, Schedules 13 and 14 of the Tariff, and the applicable Market Rules. 1.23 Control Area is an electric power system or combination of electric power systems to which a common automatic generation control scheme is applied in order to: (i) match, at all times, the power output of the generators within the electric power system(s) and capacity and energy purchased from entities outside the electric power system(s), with the load within the electric power system(s); (ii) maintain scheduled interchange with other Control Areas, within the limits of Accepted Electric Industry Practice; (iii) maintain the frequency of the electric power system(s) within reasonable limits in accordance with Accepted Electric Industry Practice and the criteria of the applicable regional reliability council or the NERC; and (iv) provide sufficient generating capacity to maintain operating reserves in accordance with Accepted Electric Industry Practice. 1.24 Curtailment is a reduction in firm or non-firm transmission service in response to a transmission capacity shortage as a result of system reliability conditions. 1.25 Day-Ahead is the calendar day immediately preceding a Dispatch Day for which Participants submit Demand Bids and Supply Offers in accordance with applicable Market Rules and the System Operator schedules Resources for Energy, Operating Reserve, 4-Hour Reserve and AGC in accordance with applicable NEPOOL System Rules. 1.26 Day-Ahead Market is the market provided for in Section 14A and conducted in the calendar day immediately preceding a Dispatch Day in which Energy, Operating Reserve, 4-Hour Reserve and AGC are scheduled for a Dispatch Day, based on the Day-Ahead Demand Bids and Supply Offers and applicable NEPOOL System Rules. 1.27 Demand Bid is a proposal by a Participant to receive and pay for Energy, at a specified Location and at a specified Demand Bid Price, that is submitted to the System Operator pursuant to the Agreement and applicable Market Rules, and includes information with respect to the quantity to be received and paid for and other matters complying with the Market Rules. 1.28 Demand Bid Price is the price specified by a Participant to the System Operator in a Demand Bid for Energy at a specified Location. 1.29 Direct Assignment Facilities are facilities or portions of facilities that are Non-PTF and are constructed for the sole use/benefit of a particular Transmission Customer requesting service under the Tariff or Generator Owner requesting an interconnection. Direct Assignment Facilities shall be specified in a separate agreement with the Transmission Provider whose transmission system is to be modified to include and/or interconnect with said Facilities, shall be subject to applicable Commission requirements and shall be paid for by the Transmission Customer or a Generator Owner in accordance with the separate agreement and not under the Tariff. 1.30 Dispatch Day is the period beginning at the minute ending 0001 and ending at 2400 each day. 1.31 Dispatchable Load is any portion of the Electrical Load of a Participant that meets the requirements of the Market Rules to qualify as Operating Reserve or 4-Hour Reserve or to have its Energy consumption modified in Real-Time because of its ability to respond to remote dispatch instructions from the System Operator. A Demand Bid to receive and pay for Energy at an External Node shall, if scheduled, be considered a Dispatchable Load for the purposes of the Day-Ahead Market and the Real-Time Market. 1.32 Dispatch Price of a generating unit or combination of units, or a Firm Contract or System Contract permitted to be bid to supply Energy in accordance with Section 14.7(b) until the CMS/MSS Effective Date or permitted to be included in a Supply Offer for Energy in accordance with 14A.11(b) on and after the CMS/MSS Effective Date, is the price to provide Energy from the unit or units or Firm Contract or System Contract, as determined pursuant to the Market Rules to incorporate the Bid Price or Supply Offer Price, as appropriate, for such Energy and any loss adjustments, if and as appropriate under applicable Market Rules. 1.33 Distribution Company has the meaning specified in Section 14A.12(b). 1.34 Distribution Company Load Zone has the meaning specified in Section 14A.12(b). 1.35 EHV PTF are PTF transmission lines which are operated at 230 kV or above and related PTF facilities, including transformers which link other EHV PTF facilities, but do not include transformers which step down from 230 kV or a higher voltage to a voltage below 230 kV. 1.36 Electrical Load (in Kilowatts) of a Participant during any particular hour is the total during such hour (eliminating any distortion arising out of (i) Interchange Transactions, or (ii) transactions across the system of such Participant, or (iii) deliveries between Entities constituting a single Participant, or (iv) other electrical losses, if and as appropriate), of (a) kilowatthours provided by such Participant to its retail customers for consumption, plus (b) kilowatthours of use by such Participant, plus (c) kilowatthours of electrical losses and unaccounted for use by the Participant on its system, plus (d) kilowatthours used by such Participant for pumping Energy for its Entitlements in pumped storage hydroelectric generating facilities, plus (e) kilowatthours delivered by such Participant to Non- Participants, plus (f) kilowatthours of Electrical Load responsibility incurred due to a transfer from another Participant pursuant to a Load Asset Contract for Electrical Load, minus (g) kilowatthours of Electrical Load responsibility transferred to another Participant pursuant to a Load Asset Contract for Electrical Load. The Electrical Load of a Participant may be calculated in any reasonable manner which substantially complies with this definition. 1.37 Eligible Customer is the following: (i) Any Participant that is engaged, or proposes to engage, in the wholesale or retail electric power business is an Eligible Customer under the Tariff. (ii) Any electric utility (including any power marketer), Federal power marketing agency, or any other entity generating electric energy for sale or for resale is an Eligible Customer under the Tariff. Electric energy sold or produced by such entity may be electric energy produced in the United States, Canada or Mexico. However, with respect to transmission service that the Commission is prohibited from ordering by Section 212(h) of the Federal Power Act, such entity is eligible only if the service is provided pursuant to a state requirement that the Transmission Provider with which that entity is directly interconnected offer the unbundled transmission service, or pursuant to a voluntary offer of such service by the Transmission Provider with which that entity is directly interconnected. (iii) Any end user taking or eligible to take unbundled transmission service pursuant to a state requirement that the Transmission Provider with which that end user is directly interconnected offer the transmission service, or pursuant to a voluntary offer of such service by the Transmission Provider with which that end user is directly interconnected, is an Eligible Customer under the Tariff. 1.38 End User Behind-the-Meter Generation is generation that has all three of the following attributes: (a) it is owned by a Governance Only Member; and (b) it is used to meet that Governance Only Member's load or, for any hour in which the output of the End User Behind-the-Meter Generation owned by the Governance Only Member exceeds its Electrical Load, another Participant which is not a Governance Only Member is obligated under tariff or contract to report such excess to the ISO pursuant to applicable Market Rules; and (c) it is delivered to the Governance Only Member without the use of PTF or another Entity's transmission or distribution facilities. 1.39 End User Organization is an End User Participant which is (a) a registered tax-exempt non-profit organization with (i) an organized board of directors and (ii) a membership (A) of at least 100 Entities that buy electricity at wholesale or retail in the New England states or (B) with an aggregate peak monthly demand (non- coincident) for load in New England, including load served by End User Behind-the-Meter Generation, of at least ten (10) megawatts or (b) a municipality or other governmental agency located in New England which does not meet the definition of Publicly Owned Entity. 1.40 End User Participant is a Participant which is a consumer of electricity in the NEPOOL Control Area that generates or purchases electricity primarily for its own consumption or a non-profit group representing such consumers. 1.41 Energy is electrical energy, measured in kilowatthours or megawatthours. 1.42 Energy Entitlement is a right for purposes of settlement to all or a portion of the electric output of a generating unit at the Node where such unit is interconnected to the NEPOOL Transmission System to which an Entity is entitled as an owner (either sole or in common) or as a purchaser pursuant to a Unit Contract, reduced by any portion thereof which such Entity is selling pursuant to a Unit Contract. An Energy Entitlement in a generating unit or units may, but need not, be combined with any other Entitlements relating to such generating unit or units and may be transferred separately from the related Installed Capability Entitlement, Operating Reserve Entitlements[, 4-Hour Reserve Entitlement] or AGC Entitlement. 1.43 Entitlement is an Installed Capability Entitlement, Energy Entitlement, Operating Reserve Entitlement[, 4-Hour Reserve Entitlement] or AGC Entitlement. When used in the plural form, it may be any or all such Entitlements or combinations thereof, as the context requires. 1.44 Entity is any person or organization whether the United States of America or Canada or a state or province or a political subdivision thereof or a duly established agency of any of them, a private corporation, a partnership, an individual, an electric cooperative or any other person or organization recognized in law as capable of owning property and contracting with respect thereto that is either: (a) engaged in the electric power business (the generation and/or transmission and/or distribution of electricity for consumption by the public or the purchase, as a principal or broker, of Installed Capability, Energy, Operating Reserve, [4-Hour Reserve] and/or AGC for resale); or (b) a consumer of electricity in the NEPOOL Control Area that generates or purchases electricity primarily for its own consumption or a non-profit group representing such consumers. 1.45 Excepted Transaction is a transaction specified in Section 25 of the Tariff for the applicable period specified in that Section, or in Sections 25A and 25B of the Tariff. 1.46 External Node is a bus or buses used for establishing a Locational Price for Energy received by Participants from, or delivered by Participants to, a neighboring Control Area. 1.47 Facilities Study is an engineering study conducted pursuant to this Agreement or the Tariff by the System Operator and/or one or more affected Participants to determine the required modifications to the NEPOOL Transmission System, including the cost and scheduled completion date for such modifications, that will be required to provide a requested transmission service or interconnection. 1.48 FCR is a Financial Congestion Right. 1.49 Financial Congestion Right is a financial instrument that evidences the rights and obligations specified in Schedule 14 of the Tariff. 1.50 Firm Contract is any contract, other than a Unit Contract, for the purchase of Installed Capability, Energy [at a Location], Operating Reserves[, 4-Hour Reserves] and/or AGC, pursuant to which the purchaser's right to receive such Installed Capability, Energy, Operating Reserves[, 4-Hour Reserves] and/or AGC is subject only to the supplier's inability to satisfy its obligations thereunder as the result of events beyond the supplier's reasonable control. 1.51 First Effective Date is March 1, 1997. 1.52 Governance Only Member is an End User Participant that participates in NEPOOL for governance purposes only and elects to be a Governance Only Member before its application is approved by NEPOOL. 1.53 HQ Contracts are the HQ Interconnection Agreement, the HQ Phase I Energy Contract, and the HQ Phase II Firm Energy Contract. 1.54 HQ Energy Banking Agreement is the Energy Banking Agreement entered into on March 21, 1983 by Hydro-Quebec, the Participants, New England Electric Transmission Corporation and Vermont Electric Transmission Company, Inc., as it may be amended from time to time. 1.55 HQ Interconnection is the United States segment of the transmission interconnection which connects the systems of Hydro- Quebec and the Participants. "Phase I" is the United States portion of the 450 kV HVDC transmission line from a terminal at the Des Cantons Substation on the Hydro-Quebec system near Sherbrooke, Quebec to a terminal having an approximate rating of 690 MW at a substation at the Comerford Generating Station on the Connecticut River. "Phase II" is the United States portion of the facilities required to increase to approximately 2000 MW the transfer capacity of the HQ Interconnection, including an extension of the HVDC transmission line from the terminus of Phase I at the Comerford Station through New Hampshire to a terminal at the Sandy Pond Substation in Massachusetts. The HQ Interconnection does not include any PTF facilities installed or modified to effect reinforcements of the New England AC transmission system required in connection with the HVDC transmission line and terminals. 1.56 HQ Interconnection Agreement is the Interconnection Agreement entered into on March 21, 1983 by Hydro-Quebec and the Participants, as it may be amended from time to time. 1.57 HQ Interconnection Capability Credit of a Participant for a month during the Base Term (as defined in Section 1.63) of the HQ Phase II Firm Energy Contract is the sum in Kilowatts of (1)(a) the Participant's percentage share, if any, of the HQ Phase I Transfer Capability times (b) the HQ Phase I Transfer Credit, plus (2)(a) the Participant's percentage share, if any, of the HQ Phase II Transfer Capability, times (b) the HQ Phase II Transfer Credit. The Participants Committee shall establish appropriate HQ Interconnection Capability Credits to apply for a Participant which has such a percentage share (i) during an extension of the HQ Phase II Firm Energy Contract, and (ii) following the expiration of the HQ Phase II Firm Energy Contract. 1.58 HQ Interconnection Transfer Capability is the transfer capacity of the HQ Interconnection under normal operating conditions, as determined in accordance with Accepted Electric Industry Practice. The "HQ Phase I Transfer Capability" is the transfer capacity under normal operating conditions, as determined in accordance with Accepted Electric Industry Practice, of the Phase I terminal facilities as determined initially as of the time immediately prior to Phase II of the Interconnection first being placed in service, and as adjusted thereafter only to take into account changes in the transfer capacity which are independent of any effect of Phase II on the operation of Phase I. The "HQ Phase II Transfer Capability" is the difference between the HQ Interconnection Transfer Capability and the HQ Phase I Transfer Capability. Determinations of, and any adjustment in, transfer capacity shall be made by the Markets Committee in accordance with a schedule consistent with that followed by it in its determination of the Winter Capability and Summer Capability of generating units. 1.59 HQ Net Interconnection Capability Credit of a Participant at a particular time is its HQ Interconnection Capability Credit at the time in Kilowatts, minus a number of Kilowatts equal to (1) the percentage of its share of the HQ Interconnection Transfer Capability committed or used by it for an "Entitlement Transaction" at the time under the HQ Use Agreement, times (2) its HQ Interconnection Capability Credit for the current month. 1.60 HQ Phase I Energy Contract is the Energy Contract entered into on March 21, 1983 by Hydro-Quebec and the Participants, as it may be amended from time to time. 1.61 HQ Phase I Percentage is the percentage of the total HQ Interconnection Transfer Capability represented by the HQ Phase I Transfer Capability. 1.62 HQ Phase I Transfer Credit is 60/69 of the HQ Phase I Transfer Capability, or such other fraction of the HQ Phase I Transfer Capability as the Participants Committee may establish. 1.63 HQ Phase II Firm Energy Contract is the Firm Energy Contract dated as of October 14, 1985 between Hydro-Quebec and certain of the Participants, as it may be amended from time to time. The "Base Term" of the HQ Phase II Firm Energy Contract is the period commencing on the date deliveries were first made under the Contract and ending on August 31, 2000. 1.64 HQ Phase II Gross Transfer Responsibility of a Participant for any month during the Base Term of the HQ Phase II Firm Energy Contract (as defined in Section 1.63) is the number in Kilowatts of (a) the Participant's percentage share, if any, of the HQ Phase II Transfer Capability for the month times (b) the HQ Phase II Transfer Credit. Following the Base Term of the HQ Phase II Firm Energy Contract, and again following the expiration of the HQ Phase II Firm Energy Contract, the Participants Committee shall establish an appropriate HQ Phase II Gross Transfer Responsibility that shall remain in effect concurrently with the HQ Interconnection Capability Credit. 1.65 HQ Phase II Net Transfer Responsibility of a Participant for any month is its HQ Phase II Gross Transfer Responsibility for the month minus a number of Kilowatts equal to (1) the highest percentage of its share of the HQ Interconnection Transfer Capability committed or used by it on any day of the month for an "Entitlement Transaction" under the HQ Use Agreement, times (2) its HQ Phase II Gross Transfer Responsibility for the month. 1.66 HQ Phase II Percentage is the percentage of the total HQ Interconnection Transfer Capability represented by the HQ Phase II Transfer Capability. 1.67 HQ Phase II Transfer Credit is 90/131 of the HQ Phase II Transfer Capability, or such other fraction of the HQ Phase II Transfer Capability as the Participants Committee may establish. 1.68 HQ Use Agreement is the Agreement with Respect to Use of Quebec Interconnection dated as of December 1, 1981 among certain of the Participants, as amended and restated as of September 1, 1985 and as it may be further amended from time to time. 1.69 Hub is a specific set of pre-defined Nodes, approved by the Participants Committee, for which a Locational Price will be calculated and which can be used to establish a reference price for Energy purchases and the transfer of Settlement Obligations for Energy and for the designation of FCRs in accordance with Schedule 14 of the Tariff. 1.70 Hub Price in each hour of the Dispatch Day in the Day-Ahead Market and the Real-Time Market is the price used for Energy purchases and Settlement Obligations for Energy which are treated as being transferred at a Hub in the hour. Hub Prices are calculated in accordance with Section 14A.12 of the Agreement and Schedule 13 of the Tariff. 1.71 Installed Capability of an electric generating unit or combination of units during the Winter Period is the Winter Capability of such unit or units and during the Summer Period is the Summer Capability of such unit or units. 1.72 Installed Capability Entitlement is (a) the right to all or a portion of the Installed Capability of a generating unit or units to which an Entity is entitled as an owner (either sole or in common) or as a purchaser pursuant to a Unit Contract, (b) reduced by any portion thereof which such Entity is selling pursuant to a Unit Contract, and (c) further reduced or increased, as appropriate, to recognize rights to receive or obligations to supply Installed Capability pursuant to Firm Contracts or System Contracts in accordance with Section 14.7(a). An Installed Capability Entitlement relating to a unit or units may, but need not, be combined with any other Entitlements relating to such generating unit or units and may be transferred separately from the related Energy Entitlement, Operating Reserve Entitlements, or AGC Entitlement. 1.73 Installed Capability Responsibility * of a Participant for any month is the number of Kilowatts determined in accordance with Section 12.2. 1.74 Installed System Capability of a Participant at a particular time is (i) the sum of such Participant's Installed Capability Entitlements plus (ii) its HQ Net Interconnection Capability Credit at the time. 1.75 Interchange Transactions are transactions deemed to be effected under Section 12 of the Prior NEPOOL Agreement prior to the Second Effective Date, and transactions deemed to be effected under Section 14 of this Agreement on and after the Second Effective Date. 1.76 Internal Point-to-Point Service is the transmission service by that name provided pursuant to Section 19 of the Tariff. 1.77 Interruption Until the CMS/MSS Effective Date, Interruption is a reduction in non-firm transmission service due to economic reasons pursuant to Section 28.7 of the Tariff, other than a reduction which results from a failure to dispatch a generating resource, including a contract, used in a transaction requiring Through or Out Service which is out of merit order. On and after the CMS/MSS Effective Date, Interruption is a reduction in non-firm transmission service due to economic reasons pursuant to Section 28.7 of the Tariff, other than a reduction which results from a failure to dispatch a generating resource, including a Supply Offer or a Demand Bid at an External Node, used in a transaction requiring Through or Out Service which is out of merit order. 1.78 ISO is the Independent System Operator which is responsible for the continued operation of the NEPOOL Control Area from the NEPOOL control center and the administration of the Tariff, subject to regulation by the Commission. 1.79 Kilowatt is a kilowatthour per hour. 1.80 Large End User is an End User Participant which is considered for this purpose to be (a) a single end user with a peak monthly demand (non-coincident) for load in New England, including load served by End User Behind-the-Meter Generation, of at least one (1) megawatt, or (b) a group of two or more corporate entities each with a peak monthly demand (non-coincident) for load in New England, including load served by End User Behind-the-Meter Generation, of at least 0.35 megawatts that together totals at least one (1) megawatt. 1.81 Liaison Committee is the committee whose responsibilities are specified in Section 11C. 1.82 Load * (in Kilowatts) of a Participant during any particular hour is the total during such hour (eliminating any distortion arising out of (i) Interchange Transactions, or (ii) transactions across the system of such Participant, or (iii) deliveries between Entities constituting a single Participant, or (iv) other electrical losses, if and as appropriate) of kilowatthours provided by such Participant to its retail customers for consumption (excluding any kilowatthours which may be classified as interruptible under Market Rules approved by the Markets Committee), plus kilowatthours delivered by such Participant pursuant to Firm Contracts to its wholesale customers for resale, plus kilowatthours of use by such Participant, exclusive of use by such Participant for the operation and maintenance of its generating unit or units, plus kilowatthours of electrical losses and unaccounted for use by the Participant on its system. The Load of a Participant may be calculated in any reasonable manner which substantially complies with this definition. For the purposes of calculating a Participant's Annual Peak, Adjusted Monthly Peak, Adjusted Annual Peak and Monthly Peak, the Load of a Participant shall be adjusted to eliminate any distortions resulting from voltage reductions. In addition, upon the request of any Participant, the Markets Committee shall make, or supervise the making of, appropriate adjustments in the computation of Load for the purposes of calculating any Participant's Annual Peak, Adjusted Monthly Peak, Adjusted Annual Peak and Monthly Peak to eliminate any distortions resulting from emergency load curtailments which would significantly affect the Load of any Participant. 1.83 Load Asset Contract is a transaction for the transfer of responsibility for Electrical Load (and may include Electrical Load qualifying as Dispatchable Load), Installed Capability, or the rights to compensation for Operating Reserve to the extent the transfer relates to Dispatchable Load, the terms of which shall conform to the requirements of applicable Market Rules. 1.84 Load Zone is a Reliability Region, except as otherwise provided in Section 14A.12(b) of the Agreement and Schedule 13 of the Tariff. 1.85 Local Network is the transmission facilities constituting a local network identified on Attachment E to the Tariff, and any other local network or change in the designation of a Local Network as a Local Network which the Participants Committee may designate or approve from time to time. The Participants Committee may not unreasonably withhold approval of a request by a Participant that it effect such a change or designation. 1.86 Local Network Service is the service provided, under a separate tariff or contract, by a Participant that is a Transmission Provider to another Participant, or other entity connected to the Transmission Provider's Local Network to permit the other Participant or entity to efficiently and economically utilize its resources to serve its load. 1.87 Location is a Node, External Node, Load Zone, or Hub. 1.88 Locational Price is the price of Energy at a Location or Reliability Region, calculated in accordance with Section 14A.12 of the Agreement and Schedule 13 of the Tariff. The Locational Price for a Node is the Nodal Price at that Node; the Locational Price for an External Node is the Nodal Price at that External Node; the Locational Price for a Load Zone or Reliability Region is the Zonal Price for that Load Zone or Reliability Region, respectively; and the Locational Price for a Hub is the Hub Price for that Hub. 1.89 Lost Opportunity Cost is the amount determined for a Resource, other than a Dispatchable Load, in accordance with Section 14A.13(d). 1.90 Lower Voltage PTF are all PTF facilities other than EHV PTF. 1.91 Marginal Loss is the additional Energy required to overcome transmission losses or the decrease in Energy consumed through losses on the NEPOOL Transmission System associated with serving a small increment of demand at a Node or External Node. The cost of Marginal Losses at each Location, relative to the cost of Marginal Losses at the Reference Node, is reflected in the Marginal Loss Component of the Locational Price at that Location. 1.92 Marginal Loss Component is the component of the Nodal Price at a given Node or External Node that reflects the Marginal Loss at that Node or External Node. When used in connection with Hub Price or Zonal Price, the term Marginal Loss Component refers to the Marginal Loss Components of the Nodal Prices that comprise the Hub Price or Zonal Price, which Marginal Loss Components are averaged or weighted in the same way that Nodal Prices are averaged or weighted to determine the Hub Price and Zonal Price, respectively. 1.93 Marginal Loss Revenue for each hour is the surplus revenue, if any, that is collected by the System Operator after netting payments for Energy under Sections 14A.8 and 14A.9, and subtracting Congestion Revenue, as settled in accordance with the Market Rules. 1.94 Marginal Loss Revenue Fund is the fund of Marginal Loss Revenue administered by the System Operator in accordance with Section 14A.16 of the Agreement, Schedule 13 of the Tariff, and the applicable Market Rules. 1.95 Market Products are Installed Capability, Operable Capability, Energy, each category of Operating Reserve and AGC. 1.96 Market Rules are the system rules and operating procedures adopted pursuant to the System Operator Agreement in connection with the administration of the NEPOOL Market. 1.97 Markets Committee is the committee whose responsibilities are specified in Section 10 and which may have additional responsibilities under a proper delegation of authority by the Participants Committee. To the extent practicable, references in the Agreement to the Markets Committee shall include the prior Regional Market Operations Committee as the predecessor of the Markets Committee. 1.98 Megawatt is a measure of the rate at which Energy is produced and is equal to a megawatthour per hour. Use of the term Megawatt shall be construed to include fractional Megawatts. 1.99 Monthly Peak of a Participant for a month is the maximum Adjusted Load of the Participant during any hour in the month. 1.100 MSS is the multi-settlement system provided for in Section 14A. 1.101 NEPOOL is the New England Power Pool, the power pool created under and governed by this Agreement, and the Entities collectively participating in the New England Power Pool as Participants. 1.102 NEPOOL Control Area is the integrated electric power system to which a common Automatic Generation Control scheme and various operating procedures are applied by or under the supervision of the System Operator in order to: (i) match, at all times, the power output of the generators within the electric power system and capacity and Energy purchased from entities outside the electric power system, with the load within the electric power system; (ii) maintain scheduled interchange with other interconnected systems, within the limits of Accepted Electric Industry Practice; (iii) maintain the frequency of the electric power system within reasonable limits in accordance with Accepted Electric Industry Practice and the criteria of the NPCC and NERC; and (iv) provide sufficient generating capacity to maintain operating reserves in accordance with Accepted Electric Industry Practice. 1.103 NEPOOL Installed Capability at any particular time is the sum of the Installed System Capabilities of all Participants at such time. 1.104 NEPOOL Installed Capability Responsibility for any month is the sum of the Installed Capability Responsibilities of all Participants during that month. 1.105 NEPOOL Objective Capability for any year or period during a year is the minimum NEPOOL Installed Capability, treating the reliability benefits of the HQ Interconnection as Installed Capability, as established by the Participants Committee, required to be provided by the Participants in aggregate for the period to meet the reliability standards established by the Participants Committee pursuant to Section 7.5(e). 1.106 NEPOOL Market is the market for electric energy, capacity and certain ancillary services within the NEPOOL Control Area. 1.107 NEPOOL System Rules are the Market Rules, the NEPOOL Information Policy, the Administrative Procedures, the Reliability Standards and any other system rules, procedures or criteria for the operation of the NEPOOL System and administration of the NEPOOL Market, the NEPOOL Agreement and the NEPOOL Tariff. 1.108 NEPOOL Transmission System is the system of transmission facilities defined as PTF. 1.109 NERC is the North American Electric Reliability Council. 1.110 Net Hourly Load Obligation for Energy ("NHLO") of a Participant for an hour is an amount equal to (i) the Participant's Electrical Load for the hour, (ii) plus or minus, as appropriate, the Settlement Obligations for Energy which the Participant transfers to or assumes from another Participant pursuant to a Bilateral Transaction (other than a Load Asset Contract already reflected in the determination of the Participant's Electrical Load) in which the quantity of Settlement Obligation for Energy transferred from the Participant purchaser to the Participant seller thereunder is expressed in terms of a percentage (with or without an optional cap on the total transfer) of the Participant purchaser's Energy obligation, where the obligation is calculated as the Electrical Load of the Participant purchaser less megawatthours of Energy sales by the Participant purchaser to Non- Participants. The Bilateral Transaction identified in (ii) includes a transaction which is submitted in accordance with Market Rule 4, Appendix 4-D, "Internal Obligation Transfer Contracts" and is described in the second bullets of Market Rule 12, Appendix 12- A-1, Sections B.IIa.4 and D.II.a4, as such Market Rules were in effect on December 31, 1999.} 1.111 New Unit is an electric generating unit (including a unit or units owned by a Non-Participant in which a Participant has an Entitlement under a Unit Contract) first placed into commercial operation after May 1, 1987 (or, in the case of a unit or units owned by a Non-Participant, in which a Participant's Unit Contract Entitlement became effective after May 1, 1987) and not listed on Exhibit B to the Prior NEPOOL Agreement. 1.112 No-Load Price is the price, in dollars per hour, for a generating unit that must be paid to Participants with Energy Entitlements in the unit for being scheduled in the Day-Ahead Market, in addition to the Start-Up Price and Supply Offer Price for Energy, for each hour that the generating unit is scheduled in the Day-Ahead Market. 1.113 Nodal Price in each hour of the Dispatch Day in the Day- Ahead Market and Real-Time Market is the price for Energy received or furnished at a Node or External Node in the hour, as calculated in accordance with Section 14A.12 of the Agreement and Schedule 13 of the Tariff. 1.114 Node is a point on the NEPOOL Transmission System where Energy is received or furnished, and for which Nodal Prices are calculated. 1.115 Non-Participant is any entity which is not a Participant. 1.116 NPCC is the Northeast Power Coordinating Council. 1.117 OASIS is the Open Access Same-Time Information System of the System Operator. 1.118 Operable Capability of an electric generating unit or units in any hour is the portion of the Installed Capability of the unit or units which is operating or available to respond within an appropriate period (as identified in Market Rules approved by the Markets Committee) to the System Operator's call to meet the Energy and/or Operating Reserve and/or AGC requirements of the NEPOOL Control Area during a Scheduled Dispatch Period or is available to respond within an appropriate period to a schedule submitted by a Participant for the hour in accordance with Market Rules approved by the Markets Committee. 1.119 Operating Reserve is any or a combination of 10-Minute Spinning Reserve, 10-Minute Non-Spinning Reserve, and 30-Minute Operating Reserve, as the context requires. 1.20 Operating Reserve Entitlement is the right to all or a portion of the Operating Reserve of any category which can be provided by a Resource to which an Entity is entitled as an owner (either sole or in common), as a supplier of Dispatchable Load, or as a purchaser pursuant to a Unit Contract, reduced by any portion thereof which such Entity is selling pursuant to a Unit Contract. An Operating Reserve Entitlement in any category relating to a generating unit or units may, but need not, be combined with any other Entitlements relating to such generating unit or units and may be transferred separately from the other categories of Operating Reserve Entitlements related to such unit or units and from the related Installed Capability Entitlement, Energy Entitlement[, 4-Hour Reserve Entitlement] or AGC Entitlement. 1.121 Other HQ Energy is Energy purchased under the HQ Phase I Energy Contract which is classified as "Other Energy" under that contract. 1.222 Participant is an eligible Entity (or group of Entities which has elected to be treated as a single Participant pursuant to Section 4.1) which is a signatory to this Agreement and has become a Participant in accordance with Section 3.1 until such time as such Entity's status as a Participant terminates pursuant to Section 21.2. 1.123 Participants Committee is the committee whose responsibilities are specified in Section 7. To the extent applicable, references in the Agreement to the Participants Committee shall include the prior Management Committee or Executive Committee as the predecessor of the Participants Committee. 1.124 Pool-Planned Facility is a generation or transmission facility designated as "pool-planned" pursuant to Section 18.1. 1.125 Pool-Planned Unit is one of the following units: New Haven Harbor Unit 1 (Coke Works), Mystic Unit 7, Canal Unit 2, Potter Unit 2, Wyman Unit 4, Stony Brook Units 1, 1A, 1B, 1C, 2A and 2B, Millstone Unit 3, Seabrook Unit 1 and Waters River Unit 2 (to the extent of 7 megawatts of its Summer Capability and 12 megawatts of its Winter Capability). 1.126 Power Year is (i) the period of twelve (12) months commencing on November 1, in each year to and including 1997; (ii) the period of seven (7) months commencing on November 1, 1998; and (iii) the period of twelve (12) months commencing on June 1, 1999 and each June 1 thereafter. 1.127 Prior NEPOOL Agreement is the NEPOOL Agreement as in effect on December 1, 1996. 1.128 Proxy Unit is a hypothetical electric generating unit which possesses a Winter Capability, equivalent forced outage rate, annual maintenance outage requirement, and seasonal derating determined in accordance with Section 12.2(a)(2). 1.129 PTF are the pool transmission facilities defined in Section 15.1, and any other new transmission facilities which the Reliability Committee determines, in accordance with criteria approved by the Participants Committee and subject to review by the System Operator, should be included in PTF. 1.130 Publicly Owned Entity is an Entity which is either a municipality or an agency thereof, or a body politic and public corporation created under the authority of one of the New England states, authorized to own, lease and operate electric generation, transmission or distribution facilities, or an electric cooperative, or an organization of any such entities. 1.131 Real-Time is a current period of a Dispatch Day for which the System Operator dispatches Resources for Energy and AGC, designates Resources for AGC and Operating Reserve and, if necessary, activates 4-Hour Reserves. 1.132 Real-Time Market is the market provided for in Section 14A in which obligations and prices with respect to Energy, Operating Reserve, 4-Hour Reserve and AGC are determined from the actual dispatch and designations by the System Operator during a Dispatch Day, based on applicable Demand Bids and Supply Offers and NEPOOL System Rules. 1.133 Reference Node is the Node identified by the System Operator in accordance with the NEPOOL System Rules relative to which all mathematical quantities pertaining to physical operation, including Shift Factors and Withdrawal Factors, shall be calculated with respect to the dispatch of the system and the derivation of Locational Prices. 1.134 Regional Network Service is the transmission service by that name provided pursuant to Section 14 of the Tariff. 1.135 Related Person of a Participant is: for all Participants, either (i) a corporation, partnership, business trust or other business organization 10% or more of the stock or equity interest in which is owned directly or indirectly by, or is under common control with, the Participant, or (ii) a corporation, partnership, business trust or other business organization which owns directly or indirectly 10% or more of the stock or other equity interest in the Participant, or (iii) a corporation, partnership, business trust or other business organization 10% or more of the stock or other equity interest in which is owned directly or indirectly by a corporation, partnership, business trust or other business organization which also owns 10% or more of the stock or other equity interest in the Participant, or (iv) a natural person, or a member of such natural person's immediate family, who is, or within the last 12 months has been, an officer, director, partner, employee, or representative in NEPOOL activities of, or natural person having a material ongoing business or professional relationship directly related to NEPOOL activities with, the Participant or any corporation, partnership, business trust or other business organization related to the Participant pursuant to clauses (i), (ii) or (iii) of this Section 1.135(a); and for all End User Participants which are also natural persons, a Related Person is (i) a member of such End User's immediate family, or (ii) a Participant and any corporation, partnership, business trust, or other business organization related to the Participant pursuant to clauses (i), (ii) or (iii) of Section 1.135(a), of which such End User Participant, or a member of such End User Participant's immediate family, is, or within the last twelve (12) months has been, an officer, director, partner, or employee of, or with which an individual End User Participant has, or within the last twelve (12) months had, a material ongoing business or professional relationship directly related to NEPOOL activities, or (iii) another Participant which, within the last twelve (12) months, has paid a portion of the End User Participant's expenses under Section 19 of this Agreement, or (iv) a corporation, partnership, business trust or other business organization in which the End User Participant owns stock and/or equity with a fair market value in excess of $50,000. Notwithstanding the foregoing, for the purposes of this definition, an individual shall not be deemed to have or had a material on-going business relationship directly related to NEPOOL activities with any corporation, partnership, business trust, other business organization or Publicly Owned Entity solely as a result of being served, as a customer, with electricity or gas. 1.136 Reliability Committee is the committee whose responsibilities are specified in Section 8 and which may have additional responsibilities under a proper delegation of authority by the Participants Committee. To the extent practicable, references in the Agreement to the Reliability Committee shall include the prior Market Reliability Planning Committee or the prior Regional Transmission Planning Committee as the predecessor of the Reliability Committee. 1.137 Reliability Standards are those rules, standards, procedures and protocols approved by the Participants Committee pursuant to Section 7.3, or its predecessors, that set forth specifics concerning how the System Operator shall exercise its authority over matters pertaining to the reliability of the bulk power system. 1.138 Reliability Must Run is a Resource or portion of a Resource that is scheduled in the Day-Ahead Market by the System Operator out of merit in order to create sufficient local Operating Reserve to preserve reliability within a Reliability Region. 1.139 Reliability Region is, as of March 31, 2000, any one of the regions identified in Attachment C to the Agreement. Subsequent to March 31, 2000, the System Operator, in a filing with the Commission and following consultation with the Reliability Committee, may reconfigure Reliability Regions and add or subtract Reliability Regions as necessary over time to reflect changes to the grid or changes in patterns of usage and intra-zonal Congestion. Reliability Regions reflect the operating characteristics of, and the major transmission constraints on, the NEPOOL Transmission System. 1.140 {Reserve Contract is a contract entered into pursuant to Section 14A.10(c) between the System Operator and a Participant under which the Participant agrees to furnish 10-Minute Non- Spinning Reserve, 30-Minute Operating Reserve and/or 4-Hour Reserve.} 1.141 {Reserve Price is the price a Participant agrees to accept in a Reserve Contract for furnishing 10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve and/or 4-Hour Reserve.} 1.142 Resource means a generating unit, a Dispatchable Load, or a Supply Offer to supply service from another Control Area at an External Node. 1.143 Review Board is the board whose responsibilities are specified in Section 11A. 1.144 RMR is Reliability Must Run. 1.145 RMR Charge is the charge to Participants pursuant to Section 14A.19(d) to recover RMR Uplift. 1.146 RMR Uplift is the uplift for RMR determined in accordance with Section 14A.19(d). 1.147 Scheduled Dispatch Period is the shortest period for which the System Operator performs and publishes a projected dispatch schedule based on projected Electrical Load and actual Bid Prices and Participant-directed schedules for Resources submitted in accordance with Section 14.2(d) until the CMS/MSS Effective Date, and based on projected Electrical Load, Demand Bids, Supply Offers, and Self-Schedules and Self-Supplies submitted in accordance with applicable Market Rules for periods on and after the CMS/MSS Effective Date. 1.148 Second Effective Date is May 1, 1999. 1.149 Sector has the meaning specified in Section 6.2. 1.150 Self-Schedule is the action of a Participant in scheduling its Resource, in accordance with applicable Market Rules, to provide service in an hour, whether or not in the absence of that action the Resource would have been scheduled or dispatched to provide the service by the System Operator. 1.151 Self-Supply is the action of a Participant in designating its Resource in accordance with applicable Market Rules to meet its own service requirements in whole or in part. 1.152 Service Agreement is the initial agreement and any amendments or supplements thereto entered into by the Transmission Customer and the System Operator for service under the Tariff. 1.153 Settlement Obligation, prior to the CMS/MSS Effective Date, is an obligation as defined in Section 14.1(a) for Energy, Section 14.1(b) for Operating Reserve and Section 14.1(c) for AGC, and all applicable Market Rules and, on and after the CMS/MSS Effective Date, is an obligation as defined in Section 14A.1(b) for Energy, Section 14A.1(c) for Operating Reserve, Section 14A.1(d) for 4-Hour Reserve and Section 14A.1(e) for AGC, and all applicable Market Rules. 1.154 Shift Factor is the factor which relates to the change in power flow over the PTF that results from an increment of generation at a given Node or External Node and a corresponding increment of load at the Reference Node, relative to the size of the increment of generation. Shift Factors are used to calculate Locational Prices in accordance with Section 14A.12 of the Agreement and Schedule 13 of the Tariff. 1.155 Small End User is a End User Participant which does not otherwise meet the definition of Large End User or End User Organization. 1.156 Standard Offer Obligation has the meaning specified in Section 14A.12(b)(ii) of the Agreement and Schedule 13 of the Tariff. 1.157 Start-Up Price is the price, in dollars, that must be paid for a generating unit to Participants with Energy Entitlements in the unit each time the unit is scheduled in the Day-Ahead Market to start up. 1.158 Summer Capability of an electric generating unit or combination of units is the maximum dependable load carrying ability in Kilowatts of such unit or units (exclusive of capacity required for station use) during the Summer Period, as determined by the Markets Committee in accordance with Section 10.4(d). 1.159 Summer Period in each Power Year is the four-month period from June through September. 1.160 Supply Obligation is an obligation as defined in Section 14A.1(a) for Energy, Operating Reserve, 4-Hour Reserve, and/or AGC. 1.161 Supply Offer is a proposal to furnish Energy at a Node or External Node, Operating Reserve, 4-Hour Reserve and/or AGC from a Resource that meets the applicable requirements set forth in the Market Rules that a Participant with Supply Offer authority for the Resource submits to the System Operator pursuant to the Agreement and applicable Market Rules, and includes a Supply Offer Price and information with respect to the quantity proposed to be furnished, technical parameters for the Resource, timing and other matters. 1.162 Supply Offer Price is the price specified to the System Operator in a Supply Offer to provide Energy, Operating Reserve, AGC and/or 4-Hour Reserve from a Resource pursuant to this Agreement and applicable Market Rules. 1.163 System Contract is any contract for the purchase of Installed Capability, Energy [at a Location], Operating Reserves[, 4-Hour Reserves] and/or AGC, other than a Unit Contract, pursuant to which the purchaser is entitled to a specifically determined or determinable amount of such Installed Capability, Energy, Operating Reserves[, 4-Hour Reserves] and/or AGC. 1.164 System Impact Study is an assessment pursuant to Part V, VI or VII of the Tariff of (i) the adequacy of the NEPOOL Transmission System to accommodate a request for the interconnection of a new or materially changed generating unit or a new or materially changed interconnection to another Control Area or new Regional Network Service, Internal Point-to-Point Service or Through or Out Service, and (ii) whether any additional costs may be required to be incurred in order to provide the interconnection or transmission service. 1.165 System Operator is the central dispatching agency provided for in this Agreement which has responsibility for the operation of the NEPOOL Control Area from the NEPOOL control center and the administration of the Tariff. The System Operator is ISO New England Inc., unless replaced by a substitute independent system operator, a regional transmission organization or an entity that forms a part of a regional transmission organization that has, in each case, been approved by the Commission. 1.166 Target Availability Rate is the assumed availability of a type of generating unit utilized by the Participants Committee in its determination pursuant to Section 7.5(e) of NEPOOL Objective Capability. 1.167 Tariff is the NEPOOL Open Access Transmission Tariff set out in Attachment B to the Agreement, as modified and amended from time to time. 1.168 Tariff Committee is the committee whose responsibilities are specified in Section 9 and which may have additional responsibilities under a proper delegation of authority by the Participants Committee. To the extent practicable, references in the Agreement to the Tariff Committee shall include the prior Regional Transmission Operations Committee as the predecessor of the Tariff Committee. 1.169 Technical Committees are the Reliability Committee, the Tariff Committee and the Markets Committee. 1.170 Third Effective Date is the date on which all Interchange Transactions shall begin to be effected on the basis of separate Bid Prices for each type of Entitlement. The Third Effective Date shall be fixed at the discretion of the Participants Committee to occur within six months to one year after the Second Effective Date, or at such later date as the Commission may fix on its own or pursuant to a request by the Participants Committee. 1.171 Through or Out Service is the transmission service by that name provided pursuant to Section 18 of the Tariff. 1.172 Transition Period is the six-year period commencing on March 1, 1997. 1.173 Transmission Customer is any Eligible Customer that (i) is a Participant which is not required to sign a Service Agreement with respect to a service to be furnished to it in accordance with Section 48 of the Tariff or (ii) executes, on its own behalf or through its Designated Agent, a Service Agreement, or (iii) requests in writing, on its own behalf or through its Designated Agent, that NEPOOL file with the Commission a proposed unexecuted Service Agreement in order that the Eligible Customer may receive transmission service under the Tariff. 1.174 Transmission Owner is a Transmission Provider which makes its PTF available under the Tariff and owns a Local Network listed in Attachment E to the Tariff which is not a Publicly Owned Entity, including any affiliate of a Transmission Provider that owns transmission facilities that are made available as part of the Transmission Provider's Local Network; provided that if a Transmission Provider is not listed in Attachment E to the Tariff on May 10, 1999, the Transmission Provider must also (i) own, or lease with rights equivalent to ownership, PTF with an original capital investment in its PTF as of the end of the most recent year for which figures are available from annual reports submitted to the Commission in Form 1 or any similar form containing comparable annualized data of at least $30,000,000, and (ii) provide transmission service to non-affiliated customers pursuant to an open access transmission tariff on file with the Commission. 1.175 Transmission Owners Committee is the committee whose responsibilities are specified in Section 11B. 1.176 Transmission Provider is the Participants, collectively, which own PTF and are in the business of providing transmission service or provide service under a local open access transmission tariff, or in the case of a state or municipal or cooperatively- owned Participant, would be required to do so if requested pursuant to the reciprocity requirements specified in the Tariff, or an individual such Participant, whichever is appropriate. 1.177 Unit Contract is a purchase contract pursuant to which the purchaser is in effect currently entitled, [at a specified Location], either (i) to a specifically determined or determinable portion of the capability of a specific electric generating unit or units, or (ii) to a specifically determined or determinable amount of Installed Capability, Energy, Operating Reserves[, 4-Hour Reserves] and/or AGC if, or to the extent that, a specific electric generating unit or units is or can be operated. 1.178 Withdrawal Factor is the factor which measures the proportion of a small increment of power injected at a given Node that can be withdrawn at the Reference Node (with any difference between the amounts injected and withdrawn attributable to Marginal Losses). Withdrawal Factors are used to calculate Locational Prices in accordance with Section 14A.12 of the Agreement and Schedule 13 of the Tariff. 1.179 Winter Capability of an electric generating unit or combination of units is the maximum dependable load carrying ability in Kilowatts of such unit or units (exclusive of capacity required for station use) during the Winter Period, as determined by the Markets Committee in accordance with Section 10.4(d). 1.180 Winter Period in each Power Year is (i) the seven-month period from November through May and the month of October for the Power Year commencing on November 1 in 1997 or a prior Power Year; (ii) the seven-month period from November through May for the Power Year commencing on November 1, 1998; and (iii) the eight-month period from October through May for the Power Year commencing on June 1, 1999 and each June 1 thereafter. 1.181 Zonal Price in each hour of the Dispatch Day in the Day- Ahead Market and the Real-Time Market is the price for Energy received in a Load Zone or Reliability Region in the hour, as calculated in accordance with Section 14A.12 of the Agreement and Schedule 13 of the Tariff. 1.182 4-Hour Reserve is an option for Energy, which can be called upon by the System Operator in one or more hours of the Dispatch Day for at least the minimum period defined in the NEPOOL System Rules and for the number of hours offered and at Energy prices at least equal to the prices set forth in a Day-Ahead Supply Offer (unless such prices are reduced in a Real-Time Supply Offer) and to or from which Energy can be adjusted within four hours in response to dispatch instructions and in accordance with applicable NEPOOL System Rules, from one of the following Resources to the extent the Resource providing 4-Hour Reserve has not been scheduled to provide Energy, Operating Reserve or AGC in the Day-Ahead Market: (i) a generating unit capable of providing Energy; (ii) a load capable of reducing its consumption of Energy within four hours, including Demand Bids at External Nodes; and (iii) to the extent permitted by applicable NEPOOL System Rules, a Supply Offer to supply Energy from another Control Area at an External Node. 1.183 4-Hour Reserve Entitlement is the right for the purpose of satisfying a Supply Obligation for Energy from all or a portion of the 4-Hour Reserve which can be provided by a Resource to which an Entity is entitled as an owner (either sole or in common), as a supplier of load or as a purchaser pursuant to a Unit Contract, reduced by any portion thereof which such Entity is selling pursuant to a Unit Contract. A 4-Hour Reserve Entitlement in a generating unit or units may, but need not, be combined with any other Entitlements relating to such generating unit or units and may be transferred separately from the related {Installed Capability Entitlement,} Energy Entitlement, Operating Reserve Entitlement or AGC Entitlement. 1.184 10-Minute Spinning Reserve Until the CMS/MSS Effective Date, in an hour is the contingency protection benefit for the system available from the combination of the following Resources that are designated by the System Operator in accordance with the Market Rules to be available: (i) the Megawatts available from an electric generating unit or units that are synchronized to the system (including units outside the NEPOOL Control Area to the extent permitted by applicable Market Rules), unloaded during all or part of the hour, and capable of providing contingency protection by loading to supply Energy immediately on demand, increasing the Energy output over no more than ten minutes to the full amount of generating capacity so designated, and sustaining such Energy output for so long as the System Operator determines in accordance with the Market Rules is necessary; and (ii) any Dispatchable Load of a Participant that the System Operator is able to verify as capable of providing contingency protection by immediately on demand reducing Energy requirements within ten minutes and maintaining such reduced Energy requirements for so long as the System Operator determines in accordance with the Market Rules is necessary. On and after the CMS/MSS Effective Date, in an hour is an option for Energy, which can be called upon by the System Operator in such hour at Energy prices at least equal to the prices set forth in a Day-Ahead Supply Offer (unless such prices are reduced in a Real-Time Supply Offer), from one of the following Resources to the extent the Resource in the Day- Ahead Market has not been scheduled or in the Real-Time Market has not been dispatched for Energy and to or from which Energy can be adjusted within ten (10) minutes in response to dispatch instructions and sustaining such adjusted level of Energy for so long as the System Operator determines in accordance with the Market Rules is necessary: (i) a generating unit that is synchronized to the system; or (ii) a Dispatchable Load; and (iii) to the extent permitted by applicable Market Rules, a Supply Offer to supply Energy from another Control Area at an External Node. 1.185 10-Minute Non-Spinning Reserve Until the CMS/MSS Effective Date, in an hour is the contingency protection benefit for the system available from the combination of the following Resources that are designated by the System Operator in accordance with the Market Rules to be available: (i) the Megawatts available from an electric generating unit or units that are not synchronized to the system (including units outside the NEPOOL Control Area to the extent permitted by applicable Market Rules), during all or part of the hour, and capable of providing contingency protection by loading to supply Energy within ten minutes to the full amount of generating capacity so designated, and sustaining such Energy output for so long as the System Operator determines in accordance with the Market Rules is necessary; (ii) any Dispatchable Load of a Participant that the System Operator is able to verify as capable of providing contingency protection by reducing Energy requirements within ten minutes and maintaining such reduced Energy requirements for so long as the System Operator determines in accordance with the Market Rules is necessary; and (3) any other Resources that were able to be designated for the hour as 10- Minute Spinning Reserve but were not designated by the System Operator for such purpose in the hour. On and after the CMS/MSS Effective Date, in an hour is an option for Energy, which can be called upon by the System Operator in such hour at Energy prices at least equal to the prices set forth in a Day-Ahead Supply Offer (unless such prices are reduced in a Real-Time Supply Offer), from one of the following Resources to the extent the Resource in the Day- Ahead Market has not been scheduled or in the Real-Time Market has not been dispatched for Energy or for AGC or 10-Minute Spinning Reserve, and to or from which Energy can be adjusted within ten (10) minutes in response to dispatch instructions and which is capable of sustaining such adjusted level of Energy for so long as the System Operator determines in accordance with Market Rules is necessary: (i) a generating unit capable of providing such Energy; (ii) a Dispatchable Load; and (iii) to the extent permitted by applicable Market Rules, a Supply Offer to supply Energy from another Control Area at an External Node. 1.186 30-Minute Operating Reserve Until the CMS/MSS Effective Date, in an hour is the contingency protection benefit for the system available from the combination of the following Resources that are designated by the System Operator in accordance with the Market Rules to be available: (i) the Megawatts available from an electric generating unit or units (including units outside the NEPOOL Control Area to the extent permitted by applicable Market Rules) that are capable of providing contingency protection by loading to supply Energy within thirty minutes of demand at an output equal to its full amount of generating capacity so designated and sustaining Energy output for so long as the System Operator determines in accordance with the Market Rules is necessary; (ii) any Dispatchable Load of a Participant that the System Operator is able to verify as capable of providing contingency protection by reducing Energy requirements within thirty minutes and maintaining such reduced Energy requirements for so long as the System Operator determines in accordance with the Market Rules is necessary; and (3) any other Resources that were able to be designated for the hour as 10-Minute Spinning Reserve or 10-Minute Non-Spinning Reserve but were not designated by the System Operator for such purposes in the hour. On and after the CMS/MSS Effective Date, in an hour is an option for Energy, which can be called upon by the System Operator in such hour at Energy prices at least equal to the prices set forth in a Day-Ahead Supply Offer (unless such prices are reduced in a Real-Time Supply Offer) from one of the following Resources to the extent the Resource in the Day- Ahead Market has not been scheduled or in the Real-Time Market has not been dispatched for Energy or designated for AGC, 10- Minute Spinning Reserve, or 10-Minute Non-Spinning Reserve, and to or from which Energy can be adjusted in response to dispatch instructions within thirty (30) minutes and which are capable of sustaining such adjusted level of Energy for so long as the System Operator determines in accordance with the Market Rules is necessary: (i) a generating unit capable of providing such Energy; (ii) a Dispatchable Load; and (iii) to the extent provided in applicable Market Rules, a Supply Offer to supply Energy from another Control Area at an External Node. 1.187 Modification of Certain Definitions When a Participant Purchases a Portion of Its Requirements from Another Participant Pursuant to Firm Contract. Definitions marked by an asterisk (*) are modified as follows when a Participant purchases a portion of its requirements of electricity from another Participant pursuant to a Firm Contract: If the Firm Contract limits deliveries to a specifically stated number of Kilowatts and requires payment of a demand charge thereon (thus placing the responsibility for meeting additional demands on the purchasing Participant): in computing the Adjusted Load of the purchasing Participant, the Kilowatts received pursuant to such Firm Contract shall be deemed to be the number of Kilowatts specified in the Firm Contract; and in computing the Load of the supplying Participant, the Kilowatts delivered pursuant to such Firm Contract shall be deemed to be the number of Kilowatts specified in the Firm Contract. If the Firm Contract does not limit deliveries to a specifically stated number of Kilowatts, but entitles the Participant to receive such amounts of electricity as it may require to supply its electric needs (thus placing the responsibility for meeting additional demands on the supplying Participant): the Installed Capability Responsibility of the purchasing Participant shall be equal to the amount of its Installed Capability Entitlements; in computing the Adjusted Load of the purchasing Participant, the Kilowatts received pursuant to such Firm Contract shall be deemed to be a quantity Rl; and in computing the Load of the supplying Participant, the Kilowatts delivered pursuant to such Firm Contract shall be deemed to be a quantity Rl. The quantity Rl equals (i) the Load of the purchasing Participant less (ii) the amount of the purchasing Participant's Installed Capability Entitlements multiplied by a fraction wherein: X is the maximum Load of the purchasing Participant in the month, and Y is the NEPOOL Installed Capability Responsibility multiplied by the purchasing Participant's fraction P determined pursuant to Section 12.2(a)(1), computed as if the Firm Contract did not exist. Terms used in this Agreement that are not defined above, or in the sections in which such terms are used, shall have the meanings customarily attributed to such terms in the electric power industry in New England. [Next Sheet is 58] SECTION 2 PURPOSE; EFFECTIVE DATES 2.1 Purpose. This Restated NEPOOL Agreement is intended to provide for a restructuring of the New England Power Pool by modifying the pool's governance and market provisions to take account of a changed competitive environment, by modifying the transmission responsibilities of the Participants so that the pool will perform the functions of a regional transmission group and provide service to Participants and Non-Participants under a regional open access transmission tariff, and by providing for the activation of the ISO and the execution of a contract between the ISO and NEPOOL to define the ISO's responsibilities. 2.2 Effective Dates; Transitional Provisions. The provisions of Parts One, Two, Four and Five of this Agreement and the Tariff became effective on the First Effective Date and replaced on the First Effective Date the provisions of Sections 1-8, inclusive, 10, 11, 13, 14.2, 14.3, 14.4 and 16 of the Prior NEPOOL Agreement. The provisions of Sections 12.1(a), 12.2, 12.4 (as to Installed Capability only), 12.5 and 12.7(a) of this Agreement became effective on April 1, 1998 and replaced on such date the provisions of Section 9 of the Prior NEPOOL Agreement. The effectiveness of the remaining Sections of this Restated NEPOOL Agreement shall be delayed pending the preparation of implementing criteria, rules and standards and computer programs. These Sections became effective on the Second Effective Date and replaced on the Second Effective Date the remaining provisions of the Prior NEPOOL Agreement, which continued in effect until the Second Effective Date. As provided in Section 14, certain portions of Section 14 which became effective on the Second Effective Date will be superseded on the Third Effective Date by other portions of Section 14. [Next Sheet is 60] SECTION 3 MEMBERSHIP 3.1 Membership. Those Entities which are Participants in NEPOOL on the First Effective Date shall continue to be Participants. Any other Entity may, upon compliance with such reasonable conditions as the Participants Committee may prescribe, become a Participant by depositing a counterpart of this Agreement as theretofore amended, duly executed by it, with the Secretary of the Participants Committee, accompanied by a certified copy of a vote of its board of directors, or such other body or bodies as may be appropriate, duly authorizing its execution and performance of this Agreement, and a check in payment of the application fee described below. Any such Entity which satisfies the requirements of this Section 3.1 shall become a Participant, and this Agreement shall become fully binding and effective in accordance with its terms as to such Entity, as of the first day of the second calendar month following its satisfaction of such requirements; provided that an earlier or later effective time may be fixed by the Participants Committee with the concurrence of such Entity or by the Commission. The application fee to be paid by each Entity seeking to become a Participant shall be in addition to the annual fee provided by Section 19.1 and shall be $500 for an applicant which qualifies for membership only as an End User Participant, and $5,000 for all other applicants, or such other amount as may be fixed by the Participants Committee. 3.2 Operations Outside the Control Area. Subject to the reciprocity requirements of the Tariff, if a Participant serves a Load, or has rights in supply or demand-side resources or owns transmission and/or distribution facilities, located outside of the NEPOOL Control Area, such Load and resources shall not be included for purposes of determining the Participant's rights, responsibilities and obligations under this Agreement, except that the Participant's Entitlements in facilities or its rights in demand side-resources outside the NEPOOL Control Area shall be included in such determinations if, to the extent, and while such Entitlements are used for retail or wholesale sales within the NEPOOL Control Area or such Entitlements or rights are designated by a Participant for purposes of meeting its obligations under Section 12 of this Agreement. 3.3 Lack of Place of Business in New England. If and for so long as a Participant does not have a place of business located in one of the New England states, the Participant shall be deemed to irrevocably (1) submit to the jurisdiction of any Connecticut state court or United States Federal court sitting in Connecticut (the state whose laws govern this Agreement) over any action or proceeding arising out of or relating to this Agreement that is not subject to the exclusive jurisdiction of the Commission, (2) agree that all claims with respect to such action or proceeding may be heard and determined in such Connecticut state court or Federal court, (3) waive any objection to venue or any action or proceeding in Connecticut on the basis of forum non conveniens, and (4) agree that service of process may be made on the Participant outside Connecticut by certified mail, postage prepaid, mailed to the Participant at the address of its member on the Participants Committee as set out in the NEPOOL roster or at the address of its principal place of business. 3.4 Obligation for Deferred Expenses. NEPOOL may provide for the deferral on the books of the Participants from time to time of capital or other expenditures, and the recovery of the deferred expenses in subsequent periods. Any Entity which becomes a Participant during the recovery period for any such deferred expenses shall be obligated, together with the continuing Participants, for its share of the current and deferred expenses pursuant to Section 19.2. 3.5 Financial Security. For an Entity applying to become a Participant or any continuing Participant that the Participants Committee reasonably determines may fail to meet its financial obligations under the Agreement, the Participants Committee may require reasonable credit review procedures which shall be made in accordance with standard commercial practices. In addition, the Participants Committee may prescribe for such Entity or Participant a requirement that the Entity or Participant provide and maintain in effect an irrevocable letter of credit as security to meet its responsibilities and obligations under the Agreement, or an alternative form of security proposed by the Entity or Participant and acceptable to the Participants Committee and consistent with commercial practices established by the Uniform Commercial Code that protects the Participants against the risk of non-payment. [Next Sheet is 64] SECTION 4 STATUS OF PARTICIPANTS 4.1 Treatment of Certain Entities as Single Participant. All Entities which are controlled by a single person (such as a corporation or a business trust) which owns at least seventy-five percent of the voting shares of, or equity interest in, each of them shall be collectively treated as a single Participant for purposes of this Agreement, if they each elect such treatment. They are encouraged to do so. Such an election shall be made in writing and shall continue in effect until revoked in writing. In view of the long-standing arrangements in Vermont, Vermont Electric Power Company, Inc. and any other Vermont electric utilities which elect in writing to be grouped with it shall be collectively treated as a single Participant for purposes of this Agreement; provided, however, that any Vermont electric utility which is a Publicly Owned Entity may elect to join the Publicly Owned Entity Sector and be treated as a member of that Sector for purposes of governance, annual fees and NEPOOL expense allocation, without losing the benefits of single Participant status for any other purpose under this Agreement. 4.2 Participants to Retain Separate Identities. The signatories to this Agreement shall not become partners by reason of this Agreement or their activities hereunder, but as to each other and to third persons, they shall be and remain independent contractors in all matters relating to this Agreement. This Agreement shall not be construed to create any liability on the part of any signatory to anyone not a party to this Agreement. Each signatory shall retain its separate identity and, to the extent not limited hereby, its individual freedom in rendering service to its customers. [Next Sheet is 66] SECTION 5 NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS 5.1 NEPOOL Objectives. The objectives of NEPOOL are, through joint planning, central dispatching, cooperation in environmental matters and coordinated construction, central dispatch by the operation and coordinated maintenance of electric supply and demand-side resources and transmission facilities, the provision of an open access regional transmission tariff and the provision of a means for effective coordination with other power pools and utilities situated in the United States and Canada, (a) to assure that the bulk power supply of the NEPOOL Control Area conforms to proper standards of reliability; (b) to create and maintain open, non-discriminatory, competitive, unbundled markets for Energy, capacity, and ancillary services that function efficiently in a changing electric power industry and have access to regional transmission at rates that do not vary with distance; (c) to attain maximum practicable economy, consistent with proper standards of reliability and the maintenance of competitive markets, in such bulk power supply; and (d) to provide access to competitive markets within the NEPOOL Control Area and to neighboring regions; and to provide for equitable sharing of the resulting responsibilities, benefits and costs. 5.2 Cooperation by Participants. In order to attain the objectives of NEPOOL set forth in Section 5.1, each Participant shall observe the provisions of this Agreement in good faith, shall cooperate with all other Participants and shall not either alone or in conjunction with one or more other Entities take advantage of the provisions of this Agreement so as to harm another Participant or to prejudice the position of any Participant in the electric power business. PART TWO GOVERNANCE SECTION 6 COMMITTEE ORGANIZATION AND VOTING 6.1 Principal Committees. There shall be four principal NEPOOL Committees (the "Principal Committees"), as follows: (a) the Participants Committee which shall have the responsibilities specified in Section 7; (b) the Reliability Committee which shall have the responsibilities specified in Section 8; (c) the Tariff Committee which shall have the responsibilities specified in Section 9; and (d) the Markets Committee which shall have the responsibilities specified in Section 10. In addition, there shall be a Transmission Owners Committee and a Liaison Committee, which shall have the responsibilities specified in Sections 11B and 11C, respectively, and such other committees as may be established from time to time by the Participants Committee. 6.2 Sector Representation. The members of each Principal Committee shall each belong to a single sector for voting purposes ("Sector"). Each Participant shall be obligated to designate in a notice to the Secretary of the Participants Committee a Sector that it or its Related Persons is eligible to join and that it elects to join for purposes of all of the Principal Committees; provided, however, that a Participant and the Participants which are its Related Persons shall not be eligible to join the End User Sector if any one of them is not eligible to join the End User Sector. A Participant and its Related Persons shall together be entitled to join only one Sector and shall have no more than one vote on each Principal Committee. The Sectors for each Principal Committee, the criteria for eligibility for membership in each Sector and the minimum requirement which a Participant must meet as a member of a Sector in order to appoint a voting member of the Sector and Committee are as follows: a Generation Sector, which a Participant shall be eligible to join if (i) it (A) owns or leases with rights equivalent to ownership facilities for the generation of electric energy that are located within the NEPOOL Control Area which are currently in operation, or (B) has proposed generation for operation within the NEPOOL Control Area either which has received approvals under Sections 18.4 and/or 18.5 within the past two years or for which completed environmental air or environmental siting applications have been filed or permits exist, and (ii) it is not a Publicly Owned Entity. Purchasing all or a portion of the output of a generation facility shall not be sufficient to qualify a Participant to join the Generation Sector. A Participant which joins the Generation Sector shall be entitled but not required to designate an individual voting member of each Principal Committee, and an alternate to the member, if its operating or proposed generation facilities in the NEPOOL Control Area have or will have, when placed in operation, an aggregate Winter Capability of at least 15 MW. A Participant which joins the Generation Sector but elects not to or is not eligible to designate an individual voting member, shall be represented by a group voting member and an alternate to that member for each Principal Committee (collectively, the "Generation Group Member"). The Generation Group Member shall be appointed by a majority of the Participants in the Generation Sector electing or required to be represented by that member. The Generation Group Member shall have the same percentage of the Sector vote as the individual voting members designated by other Participants in the Generation Sector which meet the 15 MW threshold and designate an individual voting member. The Generation Group Member shall be entitled to split his or her vote. A Transmission Sector, which a Participant shall be eligible to join if it is a Transmission Provider and is not a Publicly Owned Entity. Taking transmission service shall not be sufficient to qualify a Participant to join the Transmission Sector. A Participant which joins the Transmission Sector shall be entitled to designate an individual voting member of each Principal Committee, and an alternate to the member, if it owns or leases with rights equivalent to ownership PTF with an original capital investment in its PTF as of the end of the most recent year for which figures are available from annual reports submitted to the Commission in Form 1 or any similar form containing comparable annualized data of at least $30,000,000. A Transmission Provider with facilities which were included as PTF prior to December 31, 1998 only pursuant to clause (3) of the definition of PTF pursuant to Section 15.1 shall be entitled to designate an individual voting member of each Principal Committee, and an alternate to the member, whether or not PTF which it owns or leases with rights equivalent to ownership which has an original capital investment of at least $30,000,000, so long as such Transmission Provider continues to own PTF. A Participant which joins the Transmission Sector but which is not entitled to designate an individual voting member of each Principal Committee because (i) it, together with all of its Related Persons, does not meet the $30,000,000 threshold or (ii) it no longer owns PTF and it does not have a Related Person that is entitled to designate an individual voting member for each Principal Committee in another Sector, together with the other Participants in the Transmission Sector which for the same reasons are unable to designate an individual voting member, shall be represented by a group voting member of each Principal Committee (the "Transmission Group Member"), and an alternate to that member. The Transmission Group Member and alternate shall be appointed by a majority vote of all Participants in the Transmission Sector required to be represented by that Member. The Transmission Group Member shall have the same percentage of the Sector vote as the individual voting members designated by other Participants in the Transmission Sector which meet the $30,000,000 threshold unless and until the original capital investment in PTF of the Participants represented by the Transmission Group Member equals or exceeds twice the $30,000,000 threshold amount. If the aggregate original capital investment in PTF equals or exceeds twice the $30,000,000 threshold amount, the percentage of the Sector votes assigned to the Transmission Group Member shall equal the number of full multiples of the $30,000,000 threshold, provided that the Transmission Group Member shall in no event be entitled to more than twenty-five percent (25%) of the Sector vote. For example, if Participants represented by the Transmission Group Member have an aggregate original capital investment in PTF in the NEPOOL Control Area totaling $70,000,000, the Transmission Group Member will have the same percentage of such votes as two ($70,000,000/$30,000,000 Threshold = 2.33) individual voting members designated by individual Participants, provided that there are at least six other members in the Sector so the Transmission Group Member does not have more than twenty-five percent (25%) of the Transmission Sector vote. The Transmission Group Member shall be entitled to split his or her vote. a Supplier Sector, which a Participant shall be eligible to join if (i) it engages in, or is licensed or otherwise authorized by a state or federal agency with jurisdiction to engage in, power marketing, power brokering or load aggregation within the NEPOOL Control Area or it had been engaged on and before December 31, 1998 solely in the distribution of electricity in the NEPOOL Control Area, and (ii) it is not a Publicly Owned Entity. A Participant which joins the Supplier Sector shall be entitled to designate a voting member of each Principal Committee, and an alternate to the member. a Publicly Owned Entity Sector, which all Participants which are Publicly Owned Entities are eligible to join and shall join, and which End User Participants are eligible to join if there is not an activated End User Sector. A Participant which joins the Publicly Owned Entity Sector shall be entitled to designate a voting member of each Principal Committee, and an alternate to the member, except for End User Participants whose voting interests while they are in the Publicly Owned Entity Sector are defined in Section 6.2(e) below. an End User Sector, which an End User Participant is eligible to join provided all of its Related Persons which are Participants are also eligible to join the End User Sector. Participants which join the End User Sector shall be entitled to designate an individual voting member of each Principal Committee and an alternate to the member; provided, however, that a voting member, and the alternate to the member, designated by a Small End User shall not be a Related Person of another Participant in a Sector other than the End User Sector. Until the total number of End User Participants electing to join the End User Sector and eligible to designate an individual voting member ("End User Votes") is at least ten (10), all End User Participants electing to join the End User Sector shall be members of the Publicly Owned Entity Sector. So long as the total number of End User Votes is less than three (3), the End User Participants in the Publicly Owned Entity Sector shall be represented on each Principal Committee by a single voting member. During such time as there are at least three (3), but less than ten (10), End User Votes, End User Participants electing to join the End User Sector shall become a sub- sector of the Publicly Owned Entity Sector. Such sub- sector shall have twenty percent (20%) of the Publicly Owned Entity Sector's vote, and each individual voting member of such sub-sector shall be allocated a per capita share of the sub-sector's vote. The End User Sector shall become fully operational automatically as soon, and shall remain operational so long as, there are at least ten (10) End User Votes. The System Operator shall have the right to designate, by written notice delivered to the Secretary of the appropriate Principal Committee, a non-voting member and an alternate to each Principal Committee. All Participants have the right to join and be a member of a Sector. If a Participant ceases to be eligible to be a member of the Sector which it previously joined and is not eligible to join another existing Sector other than the End User Sector, it shall have the right to remain and vote in the Sector in which the Participant is currently a member for up to one year. By the end of such year, the NEPOOL Participants Committee shall make a filing with the Commission pursuant to which the Participant can join another Sector that either exists or is created pursuant to the NEPOOL Participants Committee filing. Separate Sectors may be created, and the membership of existing Sectors may be modified, by amendment of the Agreement. 6.3 Appointment of Members and Alternates. A Participant or group of Participants shall designate, by a written notice delivered to the Secretary of the appropriate Committee, the voting member appointed by it for the Committee and an alternate of the member. In the absence of the member, the alternate shall have all the powers of the member, including the power to vote. A Participant may change the Sector of which it is a member. Other than for Sector changes required by Section 6.4(c), a change in the Sector in which a Participant is a member shall become effective beginning on the first annual meeting of the Participants Committee following notice of such change. 6.4 Term of Members. Each voting member of a Principal Committee shall hold office until either (a) such member is replaced by the Participant or group of Participants which appointed the member, or (b) the appointing Participant ceases to be a Participant, or (c) the appointing Participant (or its Related Person) is no longer eligible to be in the Sector to which it belongs, but is eligible to join a different Sector. Replacement of a member shall be effected by delivery by a Participant or group of Participants of written notice of such replacement to the Secretary of the appropriate Committee. 6.5 Regular and Special Meetings. Each Principal Committee shall hold its annual meeting in December or January at such time and place as the Chair shall designate and shall hold other meetings in accordance with a schedule adopted by the Committee or at the call of the Chair. Five or more voting members of a Principal Committee may call subject to the notice provisions of Section 6.6 a special meeting of the Committee in the event that the Chair fails to schedule such a meeting within three business days following the Chair's receipt from such members of a request specifying the subject matters to be acted upon at the meeting. 6.6 Notice of Meetings. Written or electronic notice of each meeting of a Principal Committee shall be given to each Participant, whether or not such Participant is entitled to appoint an individual voting member of the Committee, not less than three business days prior to the date of the meeting in the case of the Technical Committees and five business days prior to the date of the meeting for the Participants Committee. A notice of meeting shall specify the principal subject matters expected to be acted upon at the meeting. In addition, such notice shall include, or specify internet location of, all draft resolutions to be voted at the meeting (which draft resolutions may be subject to amendment of intent but not subject matter during the meeting), and all background materials deemed by the Chair or Secretary to be necessary to the Committee to have an informed opinion on such matters. Motions raised for which no draft resolutions or background materials have been provided may not be acted upon at a meeting and shall be deferred to a subsequent meeting which is properly noticed. 6.7 Attendance. Regular and special meetings may be conducted in person, by telephone, or other electronic means by means of which all persons participating in the meeting can communicate in real time with each other. In order to vote during the course of a meeting, attendance is required in person or by telephone or other real time electronic means by a voting member or its alternate or a duly designated agent who has been given, in writing, the authority to vote for the member on all matters or on specific matters in accordance with Section 6.12. 6.8 Quorum. All actions by a Principal Committee, other than a vote by the Participants Committee by written ballot to amend the NEPOOL Agreement or Tariff, shall be taken at a meeting at which the members in attendance pursuant to Section 6.7 constitute a Quorum. A Quorum requires the attendance by members which satisfy the Sector Quorum requirements (as defined in Section 6.9) for a majority of the activated Sectors. No action may be taken by a Principal Committee unless a Quorum is present; provided, however, that if a Quorum is not present, the voting members then present shall have the power to adjourn the meeting from time to time until a Quorum shall be present. 6.9 Voting Definitions. For purposes of this Section 6.9 and Sections 6.10, 6.11 and 6.13, the following terms shall have the following respective meanings: Sector Voting Share: for each active Sector, is the quotient obtained by dividing one hundred percent (100%) by the number of active Sectors. For example, if there are five active Sectors, the Sector Voting Share of each of the Sectors is twenty percent (20%). The aggregate Sector Voting Shares shall equal one hundred percent (100%). Sector Quorum: for a Sector shall be the lesser of (i) fifty percent (50%) or more (rounded to the next higher whole number) of the voting members of the Sector, or (ii) five (5) or more voting members of the Sector for the Participants Committee or three (3) or more voting members of the Sector for the Technical Committees. Member Fixed Voting Share: for a Committee voting member, whether or not the member is in attendance, is the quotient obtained by dividing (i) the Sector Voting Share of the Sector to which the Participant or group of Participants which appointed the Committee voting member belongs by (ii) the total number of Committee voting members appointed by members of that Sector, adjusted, if necessary, to take into account (A) the manner in which the voting shares of End User Participants are to be determined while they are members of the Publicly Owned Entity Sector, and (B) any required change in the voting share of a Group Member, in each case as determined in accordance with Section 6.2. Member Adjusted Voting Share: for a Committee voting member which casts an affirmative or negative vote on a proposed action or amendment and which has been appointed by a Participant or group of Participants which are members of a Sector satisfying its Sector Quorum requirement for the proposed action or amendment, is the quotient obtained by dividing (i) the Sector Voting Share of that Sector by (ii) the number of voting members appointed by members of that Sector which cast affirmative or negative votes on the matter, adjusted, if necessary, for End User Participants and group voting members as provided in the definition of "Member Fixed Voting Share". NEPOOL Vote: with respect to a proposed action or amendment is the sum of (i) the Member Adjusted Voting Shares of the voting members of the Committee which cast an affirmative vote on the proposed action or amendment and which have been appointed by a Participant or group of Participants which are members of a Sector satisfying its Sector Quorum requirements and (ii) the Member Fixed Voting Shares of the voting members of the Committee which cast an affirmative vote on the proposed action or amendment and which have been appointed by a Participant or group of Participants which are members of a Sector which fails to satisfy its Sector Quorum requirements. Minimum Response Requirement: with respect to a proposed amendment to this Agreement or Tariff means that the ballots received by the Balloting Agent from Participants relating to the proposed amendment before the end of the appropriate time specified in Section 6.11(c) must satisfy the following thresholds: (i) the sum of the Member Fixed Voting Shares of the Participant voting members whose ballots are received must equal at least fifty percent (50%); and (ii) the Participants whose voting members timely return ballots for or against the amendment must include Participants that are represented by voting members having at least fifty percent (50%) of the Member Fixed Voting Shares in each of a majority of the activated Sectors. 6.10 Voting On Proposed Actions. All matters to be acted upon by a Principal Committee shall be stated in the form of a motion by a voting member, which must be seconded. Only one motion and any one amendment to that motion may be pending at one time. Passage of a motion requires a NEPOOL Vote as determined pursuant to Section 6.9 equal to or greater than two thirds of the aggregate Sector Voting Shares. Voting members not in attendance or represented at a meeting as specified in Section 6.7 or abstaining shall not be counted as affirmative or negative votes. 6.11 Voting On Amendments. Subject to Section 21.11 and Section 17A, amendments to the NEPOOL Agreement or Tariff shall be accomplished as follows: Amendments shall be drafted by a standing or ad hoc NEPOOL committee or a Participant and sent to the Participants Committee for its consideration. The Participants Committee shall take action pursuant to Section 6.10 to direct the Balloting Agent to circulate ballots for approval of the draft Amendment to each Participant for execution by its voting member or alternate on the Participants Committee or such Participant's duly authorized officer. In order to be counted, ballots must be executed and returned to the Balloting Agent for NEPOOL in accordance with the following schedule: (i) If the ballots are delivered to each Participant by regular mail, properly executed ballots must be returned to and received by the Balloting Agent within ten (10) business days after deposit of such ballots in the mail by the Balloting Agent, and (ii) If the ballots are delivered to each Participant by overnight delivery, facsimile, electronic mail or hand delivery, then properly executed ballots must be returned to and received by the Balloting Agent within five (5) business days after (A) deposit of such ballots with an overnight delivery courier if delivered by overnight delivery, or (B) transmission of such ballots by the Balloting Agent if delivered by facsimile or electronic mail, or (C) receipt by the Participant if delivered by hand delivery. (iii) If the Minimum Response Requirement for an amendment has not been received by the Balloting Agent within the schedule identified in subsection (i) or (ii) above, the Balloting Agent shall send notice by overnight delivery, facsimile, electronic mail or hand delivery to all non-responding Participants and shall count any additional properly executed ballots which it receives within five (5) business days after such notice. The date by which properly executed ballots must be returned and received by the Balloting Agent shall be specified by the Balloting Agent in the notice accompanying such ballots. A Participant may appeal to the Review Board or submit for resolution pursuant to the alternative dispute resolution provisions of Section 21.1 a proposed amendment for which ballots have been circulated, provided that such appeal is taken or submission is presented before the end of the tenth (10th) business day after the Participants Committee has taken action to direct the Balloting Agent to circulate ballots for approval of the draft amendment, by giving to the Secretary of the Participants Committee a signed and written notice of appeal or submission. The appeal shall be moot, or submission shall be deemed withdrawn, if the amendment is not approved in balloting by the Participants Committee. If the amendment is approved, a valid appeal or submission shall stay the filing with the Commission of any amendment to the NEPOOL Agreement or Tariff until either (i) a decision on the appeal by the Review Board, or (ii) the earlier of resolution pursuant to Section 21.1 or termination pursuant to Section 21.1.B(2) of the suspension effects of the submission. In order for a proposed amendment to the NEPOOL Agreement or Tariff to be approved by the Participants Committee, the following criteria must be satisfied: (i) The Minimum Response Requirement must be satisfied with respect to the proposed amendment. (ii) The affirmative ballot votes with respect to the proposed amendment must equal or exceed two thirds of the aggregate Sector Voting Shares. 6.12 Designated Representatives and Proxies. The vote of any member of a Principal Committee or the member's alternate, other than a ballot on an amendment, may be cast by another person pursuant to a written, standing designation or proxy; provided, however, that the vote of a member or alternate to that member representing a Small End User may not be cast by a Participant or a Related Person of a Participant in a Sector other than the End User Sector. A designation or proxy shall be dated not more than one year previous to the meeting and shall be delivered by the member or alternate to the Secretary of the Committee at or prior to any votes being taken at the meeting at which the vote is cast pursuant to such designation or proxy. A single individual may be the designated representative of or be given the proxy of the voting members representing any number of Participants of any one Sector or Participants from multiple Sectors. 6.13 Limits on Representatives. In the Generation Sector, no one person may exercise more than twenty-five percent (25%) of that Sector's total Member Fixed Voting Shares without the unanimous written agreement of all members of the Generation Sector. In the End User Sector, no one person may vote on behalf of more than five (5) Small End Users. Except as otherwise provided herein, other Sectors may by unanimous written agreement elect to impose limits on the voting power any one individual may have in that Sector through being the designated representative of multiple voting members or carrying multiple proxies from voting members of that Sector. Notice of any such limits on voting power must be posted on the System Operator home page and be capable of being accessed by all Participants. 6.14 Adoption of Bylaws. The Participants Committee shall adopt bylaws, consistent with this Agreement, governing procedural matters including the conduct of its meetings and those of the other Principal Committees. If there is any conflict between such bylaws and the Agreement, the Agreement shall control. A Principal Committee may vote to waive its bylaws for a particular meeting, provided the motion to effect the waiver is approved in accordance with Section 6.10. 6.15 Joint Meetings of Technical Committees. It is recognized that responsibilities of the Technical Committees may overlap in certain areas. In areas of overlap, the Reliability Committee is responsible for addressing reliability matters, the Markets Committee is responsible for addressing market implications of actions or recommendations, and the Tariff Committee is responsible for addressing issues relating to transmission and ancillary services. The Chairs of the Technical Committees, with input from the Liaison Committee Co-Chairs or entire Liaison Committee, as appropriate, shall prioritize and sequence Technical Committee activities to ensure full and proper input by Participants while maximizing the efficiency of the decision making process. To the extent appropriate and desirable, the Technical Committees are authorized and encouraged to hold meetings, and to conduct studies and exercise responsibilities, jointly with other Technical Committees. [Next Sheet is 90] SECTION 7 PARTICIPANTS COMMITTEE 7.1 Officers. At its annual meeting, the Participants Committee shall elect from among its members a Chair and Vice-Chair; it shall also elect a Secretary who shall not be a member. These officers shall have the powers and duties usually incident to such offices and as set forth in the Committee bylaws. 7.2 Adoption of Budgets. At each annual meeting, the Participants Committee shall adopt a NEPOOL budget for the ensuing calendar year. In adopting budgets the Participants Committee shall give due consideration to the budgetary requests of each committee. The Participants Committee may modify any NEPOOL budget from time to time after its adoption. 7.3 Establishing Reliability Standards. It shall be the duty of the Participants Committee, after review of reports, recommendations and actions of the System Operator and the Reliability Committee and such other matters as the Participants Committee deems pertinent, to establish or approve Reliability Standards for the bulk power supply of NEPOOL. Such Reliability Standards shall be consistent with the directives of NERC and the NPCC and shall be reviewed periodically by the Participants Committee and revised as the Participants Committee deems appropriate. 7.4 Appointment and Compensation of NEPOOL Personnel. The Participants Committee shall determine what personnel are desirable for the effective operation and administration of NEPOOL and shall fix or authorize the fixing of the compensation for such persons. In addition, the Participants Committee shall determine what resources are desirable for the effective operation of the Technical Committees and shall, on its own or pursuant to the recommendation of a Technical Committee, authorize the incurrence of such expenses as may be required to enable the Technical Committee, or its subgroups, to properly perform their duties, including, but not limited to, the retention of a consultant or the procurement of computer time. 7.5 Duties and Authority. (a) The Participants Committee shall have the duty and requisite authority to administer, enforce and interpret the provisions of this Agreement and any other agreement or document approved by the Participants Committee or its predecessor in order to accomplish the objectives of NEPOOL including the making of any decision or determination necessary under any provision of this Agreement or any other agreement or document approved by the Participants Committee or its predecessor and not expressly specified to be decided or determined by any other body. (b) The Participants Committee shall have the authority to provide for such facilities, materials and supplies as the Participants Committee may determine are necessary or desirable to carry out the provisions of this Agreement. (c) The Participants Committee shall have, in addition to the authority provided in Section 7.3, the authority, after consultation with other NEPOOL committees and the System Operator, to establish or approve consistent standards with respect to any aspect of arrangements between Participants and Non-Participants which it determines may adversely affect the reliability of NEPOOL, and to review such arrangements to determine compliance with such standards. (d) The Participants Committee, or its designee, shall have the authority to act on behalf of all Participants in carrying out any action properly taken pursuant to the provisions of this Agreement. Without limiting the foregoing general authority, the Participants Committee, or its designee, shall have the authority on behalf of all Participants to execute any contract, lease or other instrument which has been properly authorized pursuant to this Agreement including, but not limited to, one or more contracts with the System Operator, and to file with the Commission and other appropriate regulatory bodies: (i) this Agreement and documents amending or supplementing this Agreement, including the Tariff, (ii) contracts with Non-Participants or the System Operator, and (iii) related tariffs, rate schedules and certificates of concurrence. The Participants Committee shall, in addition, have the authority to represent NEPOOL in proceedings before the Commission. (e) The Participants Committee shall have the duty and requisite authority, after consultation with other NEPOOL committees and the System Operator, to fix the NEPOOL Objective Capability for each month of each Power Year prior to the beginning of the Power Year and thereafter to review at least annually the anticipated Load of the NEPOOL Participants and NEPOOL Installed Capability for each month of such Power Year and to make such adjustments in the NEPOOL Objective Capability as the Participants Committee may determine on the basis of such review. Since changes in the circumstances which must be assumed by the Participants Committee in fixing NEPOOL Objective Capability for a future period can significantly affect the required level of NEPOOL Objective Capability for that period, the Participants Committee shall, where appropriate, also determine the effect on NEPOOL Objective Capability of significant changes in circumstances from those assumed, either by fixing alternative NEPOOL Objective Capabilities, or by adopting adjustment factors or formulas. (f) The Participants Committee shall have the duty and requisite authority to establish or approve schedules fixing the amounts to be paid by Participants and Non-Participants to permit the recovery of expenses incurred in furnishing some or all of the services furnished by NEPOOL either directly or through the System Operator. (g) The Participants Committee shall have the duty and requisite authority to provide for the sharing by Participants, on such basis as the Participants Committee may deem appropriate, of payments and costs which are not otherwise reimbursed under this Agreement and which are incurred by Participants or under arrangements with Non- Participants and approved or authorized by the Committee as necessary in order to meet or avoid short-term deficiencies in the amount of resources available to meet the Pool's reliability objectives. (h) The Participants Committee shall have the authority, at the time that it acts on an Entity's application pursuant to Section 3.1 to become a Participant, to waive, conditionally or unconditionally, compliance by such Entity with one or more of the obligations imposed by this Agreement if the Participants Committee determines that such compliance would be unnecessary or inappropriate for such Entity and the waiver for such Entity will not impose an additional burden on other Participants. (i) The Participants Committee shall have the authority to establish standard conditions and waivers with respect to applications by Entities for membership in NEPOOL and to modify such standard conditions and waivers as appropriate in connection with changed circumstances with respect to such applicants, provided that the Participants Committee determines that the standard conditions and waivers for such Entities will not impose an additional burden on other Participants. (j) The Participants Committee shall have the duty and requisite authority to act on appeals to it from the actions of other Principal Committees if delegated to such Committees by the Participants Committee pursuant to Section 7.5(k), to appoint the Review Board, and to appoint a special committee to administer NEPOOL's alternate dispute resolution procedures or to take any other action if it determines that such action is necessary or appropriate to achieve a prompt resolution of disputes under the provisions of Section 21.1. (k) The Participants Committee shall have the authority to delegate its powers and duties to one or more of the Technical Committees, the System Operator, or other entity as it sees fit provided that (i) such delegation is clearly stated and approved by a Participant Committee action, (ii) such delegation does not violate any other provision set forth herein, and (iii) the action of such entity on any matter delegated to it may be appealed by any Participant to the Participants Committee provided such an appeal is taken prior to the end of the tenth business day following the action of the Technical Committee, the System Operator, or such entity by giving to the Secretary of the Participants Committee a signed and written notice of appeal, a copy of which the Secretary shall provide to the System Operator and each member and alternate of the Participants Committee. Pending action on the appeal by the Participants Committee, the giving of a notice of appeal as aforesaid shall suspend the action appealed from. (l) The Participants Committee shall have the duty and requisite authority to establish the NEPOOL Information Policy. (m) The Participants Committee shall have the duty and requisite authority to adopt and approve, amend and approve or resubmit to one or more Technical Committees for additional comment, any matter submitted to the Participants Committee by a Technical Committee. (n) The Participants Committee shall have such further powers and duties as are conferred or imposed upon it by other sections of this Agreement. 7.6 Attendance of Participants at Committee Meeting. Each Participant which does not have the right to designate an individual voting member of the Participants Committee shall, with the exception of meetings held pursuant to Section 11B.9 and meetings in executive session pursuant to Section 11B.10, be entitled to attend any meeting of the Committee or any other NEPOOL committee, and shall have a reasonable opportunity to express views on any matter to be acted upon at the meeting. 7.7 Appeal of Actions to Review Board. Any Participant which otherwise has the ability to submit a matter for resolution under Section 21.1 may, in lieu of submitting a dispute as to a Participants Committee action or failure to take action for resolution pursuant to Section 21.1, appeal such matter to the Review Board. Except as otherwise provided in Section 6.11, such an appeal shall be taken prior to the end of the tenth business day following the meeting of the Participants Committee to which the appeal relates by giving to the Secretary of the Participants Committee by hand delivery, facsimile, electronic mail or regular mail a signed and written notice of appeal, a copy of which the Secretary shall provide to each Participant. If no appeal of a Participants Committee action or failure to take action is taken, and the action or failure to take action is not submitted for resolution pursuant to Section 21.1, within such time period, that Participants Committee action or failure to take action shall be final and effective. If an appeal is taken, pending action on the appeal by the Review Board, the giving of a notice of appeal as aforesaid shall suspend the action appealed from. To the extent any action taken relates to the approval of a rule or procedure which must be filed with the Commission, the rule or procedure shall not be filed until the time for appeal or submission for dispute resolution has elapsed and, if an appeal has been filed or submission for dispute resolution has been made, either (i) a decision on the appeal has been issued by the Review Board, or (ii) the earlier of resolution pursuant to Section 21.1 of the matter submitted for dispute resolution or the termination pursuant to Section 21.1.B(2) of the suspension effect of such submission. [Next Sheet is 100] SECTION 8 RELIABILITY COMMITTEE 8.1 Officers. The Reliability Committee shall have a Chair, Vice- Chair and Secretary. The Chair and Secretary of the Reliability Committee shall be appointed by the System Operator from time to time in accordance with Section 20(j). The Chair will be responsible for presiding at meetings of the Committee and establishing agendas for its meetings in conjunction with the Vice- Chair and shall have the powers and duties as set forth in the Committee bylaws. The Secretary shall have the powers and duties usually incident to such office and as set forth in the Committee bylaws. The Chair and Secretary shall have no voting rights. The Vice-Chair shall be elected by the Reliability Committee from among its voting members from time to time. The Vice-Chair shall have the powers and duties usually incident to such office and such powers and duties as set forth in the Committee bylaws, including, without limitation, the responsibility to develop in conjunction with the Chair, Committee meeting agendas. 8.2 Notice to Members and Alternates of Participants Committee. Prior to the end of the fifth business day following a meeting of the Reliability Committee, the Secretary of the Reliability Committee shall give written notice to the System Operator and each member and alternate of the Participants Committee of any action taken by the Reliability Committee at such meeting. 8.3 Voting; Appeal of Actions. Votes taken by the Reliability Committee shall be binding on the Participants only for those matters in which the Committee has specifically designated authority under this Agreement or has been properly delegated authority by the Participants Committee pursuant to Section 7.5(k). Any Participant may appeal to the Participants Committee any binding action taken by the Reliability Committee. Such an appeal shall be taken prior to the end of the tenth business day following the meeting of the Reliability Committee to which the appeal relates by giving to the Secretary of the Participants Committee a signed and written notice of appeal, a copy of which the Secretary shall provide to the System Operator and each member and alternate of the Participants Committee. Pending action on the appeal by the Participants Committee, the giving of a notice of appeal as aforesaid shall suspend the action appealed from. 8.4 Responsibilities. The Reliability Committee shall perform the following functions, in conjunction with the System Operator as appropriate, and shall recommend action to the System Operator, Participants Committee or Transmission Owners, as appropriate, with respect thereto: (a) provide input to the Participants Committee, Transmission Owners, and System Operator, as appropriate, on transmission facilities and the development of a regional transmission plan in order to achieve the objectives of NEPOOL; (b) following appropriate study, recommend NEPOOL Objective Capability for each Power Year; (c) periodically review the procedures used to calculate NEPOOL Installed Capability, NEPOOL Objective Capability and NEPOOL Capability Responsibility; (d) periodically prepare short and long term load forecasts for use in NEPOOL studies and operations and to meet requirements of regulatory agencies; (e) review communications and liaison arrangements between NEPOOL and governmental authorities on power supply, environmental, load forecasting, and transmission issues; (f) coordinate the collection and exchange of necessary system data and future plans related to reliability for use in NEPOOL planning and to meet requirements of regulatory agencies; (g) coordination of studies of, and provide information to Participants on, maintenance schedules for the supply and demand-side resources and transmission facilities of the Participants; (h) based on appropriate studies, recommend for Participants Committee approval Reliability Standards to assure the reliable operation and facilitate the efficient operation of the NEPOOL Control Area bulk power system and those operating rules which guide the implementation of the Reliability Standards. Such Reliability Standards and operating rules shall include, without limitation, the following: (i) standards to determine the current Annual Peak, Adjusted Annual Peak, Monthly Peak, Adjusted Monthly Peak, and aggregate obligations of the Participants in each of the NEPOOL Markets; (ii) standards to establish short and long term load forecasts for use in NEPOOL operations and to meet requirements of regulatory agencies; (iii) standards with respect to the administration and enforcement of, and reporting pursuant to, NERC and NPCC policies and requirements; (iv) standards for use in planning and design of the NEPOOL interconnected bulk power system; (v) standards to ensure the continuous reliability of the bulk power transmission system, such standards to include, without limitation, criteria and rules relating to protective equipment, transfer limits, voltage schedules, voltage guides, operating guides, sub-area reserves, switching, voltage control, load shedding, emergency and restoration procedures, and the coordination of scheduling of the operation and maintenance of supply and demand-side resources and transmission facilities of the Participants; (vi) standards for determining the capabilities of each electric generating unit or combination of units in which a Participant has an Entitlement in a uniform manner applying generally accepted engineering principles; and (vii) as appropriate, reliability standards for interpool coordination transactions. (a) review proposed supply and demand-side resource plans and the proposed transmission and interconnection plans of Participants pursuant to Section 18.4 and, based on such review, recommend action regarding such proposed plans; (b) make recommendations regarding procedures for dispatch infrastructure (i.e. voice and data communications protocols, AGC pulsing arrangements, Energy Management System and System Control and Data Acquisition interfaces, Satellite relations, etc.); (c) provide input and make recommendations with respect to the reliability considerations of general system operations (i.e. commitment/ decommitment, real time dispatch, review and approval of distribution of reserves, etc.); (d) recommend to the Participants Committee the retention of a consultant, procurement of computer time, or the incurrence of consultant expenses or such other expenses as may be required to enable the Reliability Committee, its subcommittees, and task forces properly to perform their duties; (e) make recommendations to the Participants Committee, Transmission Owners, and System Operator, as appropriate, with respect to development and amendment of interconnection procedures and documents related to such procedures; and (f) to the extent appropriate, develop criteria, guidelines and methodologies to assure consistency in monitoring and assessing conformance of Participant and regional transmission plans to accepted reliability criteria. 8.5 Establishment of Subcommittees and Task Forces. The Reliability Committee shall have the authority to establish subcommittees and task forces for particular studies. 8.6 Further Powers and Duties. The Reliability Committee shall have such further powers and duties as are consistent with the duties and responsibilities set forth herein or as may be properly delegated to it by the Participants Committee. [Next Sheet is 108] SECTION 9 TARIFF COMMITTEE 9.1 Officers. The Tariff Committee shall have a Chair, Vice-Chair and Secretary. The Chair and Secretary of the Tariff Committee shall be appointed by the System Operator from time to time in accordance with Section 20(j). The Chair will be responsible for presiding at meetings of the Committee and establishing agendas for its meetings in conjunction with the Vice-Chair and shall have the powers and duties as set forth in the Committee bylaws. The Secretary shall have the powers and duties usually incident to such office and as set forth in the Committee bylaws. The Chair and Secretary shall have no voting rights. The Vice-Chair shall be elected by the Tariff Committee from among its voting members from time to time. The Vice-Chair shall have the powers and duties usually incident to such office and such powers and duties as set forth in the Committee bylaws, including, without limitation, the responsibility to develop in conjunction with the Chair, Committee meeting agendas. 9.2 Notice to Members and Alternates of Participants Committee. Prior to the end of the fifth business day following a meeting of the Tariff Committee, the Secretary of the Tariff Committee shall give written notice to the System Operator and each member and alternate of the Participants Committee of any action taken by the Tariff Committee at such meeting. 9.3 Voting; Appeal of Actions. Votes taken by the Tariff Committee shall be binding on the Participants only for those matters in which the Committee has specifically designated authority under this Agreement or has been properly delegated authority by the Participants Committee pursuant to Section 7.5(k). Any Participant may appeal to the Participants Committee any binding action taken by the Tariff Committee. Such an appeal shall be taken prior to the end of the tenth business day following the meeting of the Tariff Committee to which the appeal relates by giving to the Secretary of the Participants Committee a signed and written notice of appeal, a copy of which the Secretary shall provide to the System Operator and each member and alternate of the Participants Committee. Pending action on the appeal by the Participants Committee, the giving of a notice of appeal as aforesaid shall suspend the action appealed from. 9.4 Responsibilities. The Tariff Committee shall perform the following functions, in conjunction with the System Operator as appropriate, and shall recommend action to the System Operator, Participants Committee or Transmission Owners, as appropriate, with respect thereto: (a) develop appropriate billing procedures for transmission and ancillary services pursuant to this Agreement and the Tariff; (b) develop and recommend to the Participants Committee and the Transmission Owners Committee, as appropriate, (i) amendments, additions and other changes to the Tariff and (ii) related Tariff rules; (c) providing input to the System Operator on the development of Administrative Procedures with respect to the administration of the Tariff and the OASIS; (d) to the extent appropriate, conduct and/or review such studies and make such determinations as are assigned to the Committee pursuant to this Agreement and the Tariff with respect to financial treatment of additions to or upgrades of PTF; and (e) recommend to the Participants Committee the retention of a consultant, procurement of computer time, or the incurrence of consultant expenses or such other expenses as may be required to enable the Tariff Committee, its subcommittees, and task forces properly to perform their duties. 9.5 Establishment of Subcommittees and Task Forces. The Tariff Committee shall have the authority to establish subcommittees and task forces for particular studies. 9.6 Further Powers and Duties. The Tariff Committee shall have such further powers and duties as are consistent with the duties and responsibilities set forth herein or as may be properly delegated to it by the Participants Committee. [Next Sheet is 112] SECTION 10 MARKETS COMMITTEE 10.1 Officers. The Markets Committee shall have a Chair, Vice- Chair and Secretary. The Chair and Secretary of the Markets Committee shall be appointed by the System Operator from time to time in accordance with Section 20(j). The Chair will be responsible for presiding at meetings of the Committee and establishing agendas for its meetings in conjunction with the Vice- Chair and shall have the powers and duties as set forth in the Committee bylaws. The Secretary shall have the powers and duties usually incident to such office and as set forth in the Committee bylaws. The Chair and Secretary shall have no voting rights. The Vice-Chair shall be elected by the Markets Committee from among its voting members from time to time. The Vice-Chair shall have the powers and duties usually incident to such office and such powers and duties as set forth in the Committee bylaws, including, without limitation, the responsibility to develop in conjunction with the Chair, Committee meeting agendas. 10.2 Notice to Members and Alternates of Participants Committee. Prior to the end of the fifth business day following a meeting of the Markets Committee, the Secretary of the Markets Committee shall give written notice to the System Operator and each member and alternate of the Participants Committee of any action taken by the Markets Committee at such meeting. 10.3 Voting; Appeal of Actions. Votes taken by the Markets Committee shall be binding on the Participants only for those matters in which the Committee has specifically designated authority under this Agreement or has been properly delegated authority by the Participants Committee pursuant to Section 7.5(k). Any Participant may appeal to the Participants Committee any binding action taken by the Markets Committee. Such an appeal shall be taken prior to the end of the tenth business day following the meeting of the Markets Committee to which the appeal relates by giving to the Secretary of the Participants Committee a signed and written notice of appeal, a copy of which the Secretary shall provide to the System Operator and each member and alternate of the Participants Committee. Pending action on the appeal by the Participants Committee, the giving of a notice of appeal as aforesaid shall suspend the action appealed from. 10.4 Responsibilities. The Markets Committee shall perform the following functions, in conjunction with the System Operator as appropriate, and shall recommend action to the System Operator, Participants Committee or Transmission Owners, as appropriate, with respect thereto: (a) based on appropriate studies, develop market procedures to assure the reliable operation and facilitate the efficient operation of the NEPOOL Control Area bulk power supply; (b)(i) evaluate studies of the market implications of maintenance schedules for the supply and demand-side resources and transmission facilities of the Participants and operable capacity margins, and (ii) develop market procedures for scheduling maintenance for supply and demand resources and transmission resources; (c) to the extent appropriate to assure the efficient operation of the NEPOOL Markets, develop reasonable standards, criteria and rules relating to protective equipment, switching, voltage control, load shedding, emergency and restoration procedures, and the operation and maintenance of supply and demand-side resources and transmission facilities of the Participants; (d) develop procedures for determining the market implications of the seasonal capabilities of each electric generating unit or combination of units in which a Participant has an Entitlement; (e) develop procedures for determining as appropriate from time to time the current Annual Peak, Adjusted Annual Peak, Monthly Peak, Adjusted Monthly Peak, Installed Capability Responsibility, and obligations for Energy, Operating Reserve and AGC of each Participant; (f) develop Market Rules and periodically review and recommend changes thereto as appropriate. Such Market Rules shall include, without limitation, the following: (i) submission of Bid Prices and the determination of prices for each of the NEPOOL Markets; (ii) determination for each Participants of its obligations under each of the NEPOOL Markets; (iii) establishment or approval of appropriate billing procedures for market transactions pursuant to this Agreement; (iv) calculation and equitable apportionment of losses incurred in connection with Interchange Transactions; and (v) interpool market contract coordination as appropriate. (a) develop operating procedures relating to the administration of the NEPOOL Markets and periodically review and recommend changes thereto as appropriate; and (b) recommend the retention of a consultant, procurement of computer time, or the incurrence of consultant expenses or such other expenses as may be required to enable the Markets Committee, its subcommittees, and task forces properly to perform their duties. 10.5 Establishment of Subcommittees and Task Forces. The Markets Committee shall have the authority to establish subcommittees and task forces for particular studies. 10.6 Further Powers and Duties. The Markets Committee shall have such further powers and duties as are consistent with the duties and responsibilities set forth herein or as may be properly delegated to it by the Participants Committee. 10.7 Development of Rules Relating to Non-Participant Supply and Demand-side Resources. It is recognized that arrangements between Participants and Non-Participants with respect to the Non- Participants' supply and demand-side resources may create special problems in the application of Sections 12 and 14. Accordingly, the Markets Committee shall analyze such special problems and recommend to the Participants Committee appropriate rules for reflecting such resources in the Installed System Capability of a Participant which enters into such an arrangement and for the treatment of such arrangements for Energy, Operating Reserve and AGC purposes. Upon approval by the Participants Committee, such rules shall supersede the provisions of Sections 12 and 14 (and the related definitions in Section 1) to the extent of any conflict therewith upon acceptance by the Commission. [Next Sheet is 118] SECTION 11 FURTHER RESTRUCTURING The NEPOOL Participants undertake to finalize by March 31, 2000 the negotiation of more comprehensive arrangements for the reassignment of appropriate administrative responsibilities to the System Operator in the Interim ISO Agreement. SECTION 11A REVIEW BOARD 11A.1 Organization. There shall be a Review Board which, in addition to responsibility under Section 11B.12, shall be responsible for ruling on appeals taken from actions of the Participants Committee and for advising the Participants Committee as to the issues raised on any appeals before it provided that appeals from actions of the System Operator shall not be taken to the Review Board. In ruling on appeals, the Review Board shall consider, among other things, whether the action is consistent with Commission policies. In addition, if the appeal relates to an amendment to the Agreement or market rule, the Review Board shall consider the extent to which such amendment imposes a burden on the Participants which do not vote in favor of the amendment that is materially greater in degree than that imposed on the Participants which have voted in favor of the amendment. The Review Board shall not have the right to review or otherwise participate in actions of the System Operator or to take any action with respect to any matter involving a dispute between the System Operator and either NEPOOL or any Participant. The Participants agree that the process of selecting the Review Board shall commence upon the initial formation of the Participants Committee. Until the initial organization of the Review Board is completed, the Board of Directors of the System Operator or a committee thereof consisting of not less than three System Operator Directors designated by the System Operator Board of Directors shall perform the functions of the Review Board, provided that the provisions of Sections 11A.2 through 11A.6 shall not be applicable to the Board of Directors of the System Operator acting as a Review Board. All expenses incurred by the System Operator as a result of the Board of Directors in acting as the Review Board shall be NEPOOL expenses. 11A.2 Composition. The Review Board shall be composed of five members. The Review Board Members shall initially be selected by the Participants Committee from a slate of candidates. An independent consultant, retained by the Participants Committee, shall prepare a list of persons qualified and willing to serve on the Review Board. A subcommittee appointed by the Participants Committee shall review the list and distribute to the members of the Participants Committee a slate from among the list proposed by the independent consultant, along with information on the background and experience of the persons on the slate appropriate to evaluating their fitness for service on the Review Board. If the Participants Committee fails to select a full Review Board from the slate proposed by the subcommittee, the Committee shall direct the independent consultant to propose a further list of nominees for consideration at the next regular meeting of the Participants Committee. Thereafter, prior to the expiration of a Review Board Member's term, and upon the occurrence of any vacancy on the Board, the Participants Committee shall select a successor Member. 11A.3 Qualifications. The Review Board Members shall be independent experts knowledgeable about issues typically faced by entities engaged in energy production, transmission, distribution and sale under Federal or State regulation. A Review Board Member shall not be, and shall not have been at any time within five years of election to the Review Board, a director, officer or employee of a Participant or of a Related Person of a Participant. While serving on the Review Board, a Review Board Member shall have no direct business relationship or other affiliation with any Participant or its Related Persons and shall otherwise be subject to the same independence requirements imposed on Directors of the System Operator Board of Directors. 11A.4 Term. A Review Board Member shall serve for a term of three years; provided, however, that two of the Review Board Members selected initially shall be chosen by lot to serve a term of two years, two of the Review Board Members selected initially shall be chosen by lot to serve a term of three years and the other Review Board Member selected initially shall serve a term of four years. 11A.5 Meetings. Meetings of the Review Board may be conducted in person or by telephone or other electronic means by means of which all persons participating in the meeting can communicate in real time with each other. 11A.6 Bylaws. To the extent not inconsistent with any provision of this Agreement, the Participants Committee shall adopt bylaws establishing procedures for the Review Board's activities as it may deem appropriate, including but not limited to bylaws governing the scheduling, noticing and conduct of meetings of the Review Board, a code of conduct, selection of a Chair and Vice- Chair of the Review Board, and action by the Review Board without a meeting. Such bylaws shall not modify or be inconsistent with any of the rights or obligations established by this Agreement. 11A.7 Procedure on Appeal of Participant Committee Action or Failure to Take Action. (a) Submission of an Appeal: A Participant seeking review ("Appealing Party") by the Review Board of action of the Participants Committee shall give written notice of the appeal in accordance with Section 7.7, and the appeal shall have the suspension effect specified in Section 7.7. (b) Intervenors and Time Limits: Any other Participant that wishes to participate in the appeal proceeding hereunder shall give signed written notice to the Secretary of the Participants Committee no later than ten (10) business days after the Appealing Party has given notice of appeal and shall upon the approval of the Review Board be permitted to participate in the appeal. (c) Procedural Rules: The procedural rules (if any), for the conduct of the appeal shall be determined by the Review Board in consultation with the Participants Committee and each Appealing Party on a case-by-case basis. (d) Pre-hearing Submissions: Each Appealing Party shall provide the Review Board, within 15 days of the giving of its notice of appeal or such other time as permitted by the Review Board, a brief written statement of its complaint and a statement of the remedy or remedies it seeks, accompanied by copies of any documents or other materials it wishes the Review Board to review. The Participants Committee and, as appropriate, any other Participant participating in the appeal will provide the Review Board, within 10 days of the Appealing Party's submission or such other time as permitted by the Review Board, copies of the minutes of all NEPOOL committee meetings at which the matter was discussed and if deemed appropriate by the Participants Committee or otherwise requested by the Review Board a brief description of the action (or failure to act) being appealed and a brief statement explaining why the Participants Committee believes its action (or failure to act) should be upheld by the Review Board, together with copies of documents or other materials referenced in such submission for the Review Board to review and materials, if any, which interested Participants provide to the Secretary of the Participants Committee and reasonably request be submitted to the Review Board. In addition, each party shall designate one or more individuals to be available to answer questions the Review Board may have on the documents or other materials submitted. The answers to all such questions shall be reduced to writing by the party providing the answer and a copy shall be made available to any requesting Participant. (a) Hearing: A hearing (if any) will be held as soon as is reasonably practicable. (b) Decision: The Review Board's decision, to the extent practicable, shall be due, within ninety (90) days of the giving of notice of the appeal. 11A.8 Effect of a Review Board Decision. (a) Each Review Board Member shall have one vote and a decision of the Review Board, either to grant or deny an appeal, shall require affirmative votes by a majority of the Review Board Members but not less than three (3) such Members. (b)(i) Appeal denied. If the Review Board denies the appeal, the action of the Participants Committee will be final and effective, subject to Commission acceptance if and as required. (ii) Appeal granted. If the Review Board grants the appeal, the Review Board's determination (granting the appeal) will be final and the action of the Participants Committee shall not take effect. (c) If the Review Board grants an appeal, the Review Board may submit a proposed resolution of the matter that was the subject of the appeal to the Participants Committee. The Participants Committee may, but is not required to, take further action with regard to the matter. If the Participants Committee votes on an action regarding the matter (including a vote not to act on the matter), the action or non-action of the Participants Committee shall be subject to further appeal by any Participant to the Review Board in accordance with Section 7.7. Any proposed resolution that the Review Board submits to the Participants Committee is advisory only. 11A.9 An action or failure to act once appealed by a Participant to the Review Board may not be subject to the alternative dispute resolution provisions of Section 21.1, regardless of the outcome of the appeal. Conversely, an action or failure to act submitted for resolution by a Participant pursuant to Section 21.1 may not be brought before the Review Board. If more than one Participant appeals and/or submits for alternative dispute resolution under Section 21.1 the same issue, the Participant that first takes such action shall determine whether the issue is to be heard by the Review Board or considered under Section 21.1; provided that each Participant challenging an action or failure to take action shall have the same opportunity to present its case and may not be excluded from participating under Section 11A.7(b). 11A.10 Any action taken or failure to take action by the Review Board does not restrict or limit in any way the rights of a Participant to seek review by the Commission, or a review in any other forum available to the Participant and there shall be no requirement to submit an appeal to the Review Board concerning any amendment, action or inaction by the Participants Committee prior to a Participant exercising any such rights to seek review by the Commission or any other forum with jurisdiction. 11A.11 The Review Board may not take action that is inconsistent with or infringes upon any of the rights set forth in Section 17A. [Next Sheet is 128] SECTION 11B TRANSMISSION OWNERS COMMITTEE 11B.1 Organization. There shall be a Transmission Owners Committee established pursuant to this Section 11B which shall implement the rights reserved to Transmission Owners by Section 17A. 11B.2 Membership. Membership on the Transmission Owners Committee shall be open to all Transmission Owners, regardless of their individual choices in Sector membership under Section 6.2. 11B.3 Appointment of Members and Alternates. A Transmission Owner shall join the Transmission Owners Committee by written notice delivered to the Secretary of the Transmission Owners Committee, and shall designate in the notice the initial member appointed by it for the Committee and an alternate of the member. In the absence of the member, the alternate shall have all the powers of the member, including the power to vote. 11B.4 Term of Members. A member of the Transmission Owners Committee appointed by a Transmission Owner shall serve until replaced by the Transmission Owner which appointed it or until such Transmission Owner ceases to be a Participant or otherwise lose its right to appoint the member. Appointment or replacement of a member shall be effected by a Transmission Owner by giving written notice of such appointment or replacement to the Secretary of the Transmission Owners Committee. 11B.5 Regular and Special Meetings. The Transmission Owners Committee shall hold its annual meeting in December or January at such time and place as the Chair shall designate and shall hold other meetings in accordance with a schedule adopted by the Committee or at the call of the Chair. Thirty percent (30%) or more of the voting members of the Transmission Owners Committee may call a special meeting of the Committee in the event that the Chair shall fail to call such a meeting within three business days following the Chair's receipt from such members of a request specifying the subject matters to be acted upon at the meeting. 11B.6 Notice of Meetings. Written notice of each meeting of the Transmission Owners Committee shall be given to each Transmission Owner and to other Participants not less than five (5) business days to the date of the meeting. 11B.7 Attendance. Regular and special meetings may be conducted in person, by telephone, or other electronic means by means of which all persons participating in the meeting can communicate in real time with each other. In order to vote during the course of a meeting, attendance is required in person or by telephone or other real time electronic means by a voting member or its alternate or a duly designated agent who has been given, in writing, the authority to vote for the member on all matters or the proxy to vote for the member on specific matters. 11B.8 Votes. Any action taken by the Transmission Owners Committee shall require the concurrence of: (i) representatives of at least two-thirds of the Transmission Owners provided that Transmission Owners that are Related Persons to one another shall together have a single vote; and (ii) representatives of Transmission Owners having at least two-thirds of the Weighted Votes of all Transmission Owners, where each Transmission Owner's Weighted Vote is equal to its original capital investment in its PTF as of the end of the most recent year for which figures are available. Notwithstanding the foregoing, if a vote is taken and paragraph (i) above is satisfied but paragraph (ii) above is not, the action being voted on by the Transmission Owners Committee shall pass if (1) there are seven or more Transmission Owners on the Committee and fewer than three Transmission Owners oppose the action or (2) there are less than seven Transmission Owners on the Committee and only one Transmission Owner opposes the action. 11B.9 Appointment of Task Forces or Working Groups. The Transmission Owners Committee shall have the authority to appoint task forces or working groups to address matters for which the Committee is responsible. Notwithstanding Section 7.6, such tasks force or working groups may be limited to Transmission Owners only. 11B.10 Officers. At its annual meeting, the Transmission Owners Committee shall elect from its members a Chair and a Vice- Chair; it shall also elect a Secretary who need not be a member of the Committee. These officers shall have the powers and duties usually incident to such offices, including the right to convene an executive session of the Transmission Owners Committee to consider and vote upon submittals to the Commission or litigation strategy. 11B.11 Adoption of Bylaws. The Transmission Owners Committee may adopt bylaws, consistent with this Agreement, governing procedural matters including the conduct of its meetings. 11B.12 Review of Committee Actions. To the extent the Commission determines, pursuant to Section 17A.7, that Transmission Owners have the exclusive right to make unilateral filings under Section 205 of the Federal Power Act, a Transmission Owner may either submit a dispute for resolution pursuant to Section 21.1 or appeal to the Review Board any action taken by the Transmission Owners Committee with respect to such a Section 205 filing. Such a submission or appeal shall be taken prior to the end of the tenth business day following the meeting of the Transmission Owners Committee to which the submission or appeal relates by giving to the Secretary of the Transmission Owners Committee a signed and written notice of submission or appeal. Pending action on an appeal by the Review Board, the giving of a notice of appeal as aforesaid shall suspend the action appealed from. For purposes of the application of the dispute resolution process of Section 21.1 and the suspension effect of a submission to alternative dispute resolution, Section 21.1 shall be applied as if the Transmission Owners Committee were the Participants Committee. SECTION 11C LIAISON COMMITTEE 11C.1 Organization; Duties. There shall be a Liaison Committee which shall be an advisory committee only responsible to act as a steering committee for managing NEPOOL business through the committee process and facilitating communications between NEPOOL and the System Operator and among Participants. The Liaison Committee's duties as a steering committee include, without limitation, recommending that matters be assigned to particular committees for action where the subject matter of a proposed rule or other action potentially falls in the purview of more than one committee and assuring appropriate input from other committees as needed. 11C.2 Membership. The Liaison Committee shall have the following members: the Chair and Vice-Chair of each of the Principal Committees; the Chair of the Transmission Owners Committee; a Participant representative of each Sector that is not otherwise represented on the Liaison Committee; the chief executive officer of the System Operator; and two members of the System Operator's Board of Directors. 11C.3 Regular and Special Meetings. The Liaison Committee shall hold meetings in accordance with a schedule adopted by the Committee or at the call of the Co-Chairs. 11C.4 Notice of Meetings. Written notice of each meeting of the Liaison Committee shall be given to each member of the Committee and all members of the Participants Committee not less than five business days prior to the date of the meeting. 11C.5 Attendance. Regular and special meetings may be conducted in person, by telephone, or other electronic means by means of which all persons participating in the meeting can communicate in real time with each other. Participants Committee members and alternates may attend meetings of the Liaison Committee. Any individual that is not a member of the Liaison Committee may participate at a meeting at the invitation of a Co-Chair. 11C.6 Officers. The Co-Chairs of the Liaison Committee shall be the chief executive officer of the System Operator and the Chair of the Participants Committee. The Liaison Committee shall elect a Secretary who need not be a member of the Committee. These officers shall have the powers and duties usually incident to such offices. [Next Sheet is 135] PART THREE MARKET PROVISIONS SECTION 12 INSTALLED CAPABILITY OBLIGATIONS AND PAYMENTS 12.0 Continuing Reliability Measures. (a) Commencing in 2000 the System Operator shall perform, and furnish to Participants, an annual, independent "Regional Resource Adequacy Assessment" to determine whether adequate generation and transmission resources are in place or under development to assure that regional and subregional reliability standards established for NEPOOL can be met. (b) During 2000, the Participants Committee shall commence development of alternative, market-based reliability assurance mechanisms. A status report on this development effort shall be submitted to the Commission and furnished to Participants on or before January 1, 2001. (c) Certain provisions of the Agreement that impose obligations on Participants, including Participants with generation and transmission resources, were contained within the Agreement at a time when wholesale power and transmission services were subject to very different regulatory rules and an Operable Capability market and Installed Capability auction market were included within the Agreement. During 2000, concurrent with the review pursuant to Section 12.0(b) and in recognition of the implementation of CMS and MSS, the Participants Committee shall also identify those of such obligations, if any, that should be eliminated, modified, or replaced. 12.1 Obligations to Provide Installed Capability. Each Participant shall have Installed System Capability during each hour of each month at least sufficient to satisfy its Installed Capability Responsibility for the month. 12.2 Computation of Installed Capability Responsibilities. (a)(1) At the conclusion of each month, the System Operator under the direction of the Participants Committee shall determine each Participant's tentative Installed Capability Responsibility in Kilowatts for such month in accordance with the following formula: X = (P(A-N)+Np)(1+T) - C(Dp) As used in this Section 12.2(a)(1), the symbols used in the formula and the additional symbols defined below have the following meanings: X is the Participant's tentative Installed Capability Responsibility for the month. P is the value of the Participant's fraction for the month as determined in accordance with the following formula: P = (Fp + Dp) / (F + D), wherein: Fp is the Participant's Adjusted Monthly Peak for the month less any Kilowatts received by such Participant pursuant to a contract of a type that traditionally has been treated by NEPOOL as a firm contract for the purposes of this Section prior to January 1, 1999, but which does not constitute a Firm Contract as defined in this Agreement. Dp is the Participant's actual or potential load reduction resulting from its NEPOOL Interruptible and Dispatchable Loads for the month. F is the aggregate for the month of the Adjusted Monthly Peaks for all Participants less any Kilowatts received by any Participant pursuant to a contract of a type that traditionally has been treated by NEPOOL as a firm contract for the purposes of this Section prior to January 1, 1999, but which does not constitute a Firm Contract as defined in this Agreement. D is the aggregate for the month of the actual or potential load reduction resulting from all Participants' NEPOOL Interruptible and Dispatchable Loads. C is the factor, which when multiplied by D in megawatts, results in the reduction to NEPOOL Objective Capability that would result from including D in the determination of NEPOOL Objective Capability. The value for C shall be adopted by the Participants Committee each time it fixes NEPOOL Objective Capability pursuant to Section 7.5(e). A is the NEPOOL Objective Capability in megawatts for the month as fixed by the Participants Committee pursuant to Section 7. N is the aggregate of the New Unit Adjustments for all Participants for the month as determined by the Participants Committee in accordance with Section 12.2(a)(2). Np is the aggregate of the Participant's New Unit Adjustments for the month, as determined by the Participants Committee, and is equal to the aggregate of the Participant's adjustments for each New Unit included in its Installed System Capability during the hour of the coincident peak load of the Participants for the month. The Participant's adjustment for each New Unit may be positive or negative and shall be the product of (i) the Participant's Installed Capability Entitlement in the New Unit during the hour of the coincident peak load of the Participants for the month, times (ii) the New Unit Adjustment Factor applicable to the New Unit as determined in accordance with Section 12.2(a)(2). T is the Participant's Unit Availability Adjustment Factor for the month. T may be positive or negative and shall be determined in accordance with the following formula: T = (I-H) x J x R, wherein: 100 I for the Participant for the month is the percentage which represents the weighted average (using the Installed Capability of each Installed Capability Entitlement for such month for the weighting) of the Four Year Installed Capability Target Availability Rates of the Installed Capability Entitlements which are included in the Participant's Installed System Capability during the hour of the coincident peak load of the Participants for the month. The Four Year Target Availability Rate for an Installed Capability Entitlement for any month is the average of the monthly Target Availability Rates for the forty-eight months which comprise the period of four consecutive calendar years ending within the Power Year which includes such month, as determined on the basis of the Target Availability Rates for each of the forty-eight months, and as applied on a basis which is consistent with the fuel or maturity status of the unit for each of the forty-eight months; provided, however, that for the purpose of determining the Four Year Target Availability Rate (i) for months included within the Power Year which commences June 1, 1999, the determination shall be made for the months of June through October on the basis of the calendar years 1995 through 1998, and shall be made for the months of November through May on the basis of the calendar years 1996 through 1999, and (ii) for months included within the Power Year which commences June 1, 2000, the determination shall be made on the basis of the calendar years 1996 through 1999. The Target Availability Rates shall be those utilized by the Participants Committee in its most recent determination of NEPOOL Objective Capability pursuant to Section 7. H for the Participant for the month is the percentage which represents the weighted average (using the Installed Capability of each Installed Capability Entitlement for such month for the weighting) of the Four Year Actual Availability Rates of the Installed Capability Entitlements which are included in the Participant's Installed System Capability during the hour of the coincident peak load of the Participants for the month. The Four Year Actual Availability Rate for an Installed Capability Entitlement for any month is the percentage which represents the average of the amounts determined for H1 for the four applicable Twelve-Month Measurement Periods within the forty-eight months which comprise the period of four consecutive calendar years ending within the Power Year which includes such month; provided, however, that for the purpose of determining the Four Year Actual Availability Rate (i) for months included within the Power Year which commences June 1, 1999, the determination shall be made for the months of June through October on the basis of the calendar years 1995 through 1998, and shall be made for the months of November through May on the basis of the calendar years 1996 through 1999, and (ii) for months included within the Power Year which commences June 1, 2000, the determination shall be made on the basis of the calendar years 1996 through 1999. A Twelve- Month Measurement Period is a period of twelve sequential months. For purposes of this sequence, the first month in the four years and the immediately succeeding months shall be considered to follow the forty-eighth month in the four-year period. The four applicable Twelve-Month Measurement Periods to be used in the determination of H1 for an Installed Capability Entitlement shall be the four sequential Twelve-Month Measurement Periods out of the twelve possible combinations which yield the highest H1. H1 for an Installed Capability Entitlement in a unit or combination of units for a Twelve-Month Measurement Period is its Actual Availability Rate. The Actual Availability Rate of an Installed Capability Entitlement for a Twelve- Month Measurement Period is a percentage and shall be the greater of: (i) the percentage of (a) the amount of generation which could have been received with respect to the Installed Capability Entitlement if the unit or combination of units had been fully available at its full Installed Capability throughout the Twelve- Month Measurement Period, which is represented by (b) the amount of generation which was actually available during such period, or (ii) the average Target Availability Rate expressed as a percentage for the Installed Capability Entitlement for the Twelve-Month Measurement Period less twenty percentage points. The average Target Availability Rate of an Installed Capability Entitlement for a Twelve-Month Measurement Period is a percentage and is the average of the monthly Target Availability Rates for the months which comprise the Twelve-Month Measurement Period, as determined on the basis of the Target Availability Rates for each of the twelve months, and as applied on a basis which is consistent with the fuel or maturity status of the unit or combination of units for each month in the Twelve-Month Measurement Period. The Target Availability Rates shall be those utilized by the Participants Committee in its most recent determination of NEPOOL Objective Capability pursuant to Section 7. J for the month is the estimated percentage point change in NEPOOL Objective Capability which would be required as a result of a one percentage point change in the weighted average equivalent availability rate of the generating units in which the Participants have Installed Capability Entitlements. The value for J shall be adopted by the Participants Committee each time it fixes NEPOOL Objective Capability pursuant to Section 7. R for the month is the phase-out factor for the month, which shall be as follows: R=0.75 for the Power Year beginning November 1, 1997. R=0.50 for the 12 month period beginning November 1, 1998. R=0.25 for the 12 month period beginning November 1, 1999. R=0 for the 12 month period beginning November 1, 2000 and all subsequent 12 month periods. (2) A New Unit Adjustment Factor for a New Unit shall be determined to assign the effects of the New Unit on NEPOOL Objective Capability to those Participants with Entitlements in the New Unit. The New Unit Adjustment Factor for each New Unit for each month shall be determined by the System Operator under the direction of the Participants Committee in accordance with the following formula: n = R(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) + K5(f- F)c2) As used in this Section 12.2(a)(2), the symbols used in the formula have the following meanings: R is the phase out factor as defined in Section 12.2(a)(1) above. n is the New Unit Adjustment Factor, expressed as a fraction, for the month for a New Unit. c is the Winter Capability of the New Unit. C is the Winter Capability of the Proxy Unit, which shall be the number of Kilowatts, as determined by the Participants Committee, which would result in the NEPOOL Objective Capability being approximately the same if the generating units in which the Participants have Installed Capability Entitlements were all units possessing Proxy Unit characteristics. f is the equivalent forced outage rate of the New Unit, expressed as a fraction of a year, utilized in the determination by the Participants Committee of NEPOOL Objective Capability for the month. F is the equivalent forced outage rate of the Proxy Unit. F, a fraction, shall be the weighted average equivalent forced outage rate (using the Winter Capability of each generating unit for such weighting) of the generating units in which the Participants have Installed Capability Entitlements, adjusted to compensate for the rounding of the annual maintenance outage requirement of the Proxy Unit. m is the four-year average annual maintenance outage requirement of the New Unit, expressed as a fraction of a year. The data used to determine m shall include the annual maintenance outage requirements for the current Power Year and the next three Power Years, as utilized for the New Unit in the most recent determination by the Participants Committee of NEPOOL Objective Capability pursuant to Section 7. M is the annual maintenance outage requirement of the Proxy Unit. M shall be a fraction, the numerator of which shall be the number of weeks (rounded to the nearest full number) that most closely approximates the weighted four-year average annual maintenance outage requirement (using the Winter Capability of each generating unit for such weighting) for the generating units in which the Participants have Installed Capability Entitlements, and the denominator of which shall be 52 weeks. d is the summer derating of the New Unit, expressed as a fraction of the Winter Capability of the New Unit. D is the summer derating of the Proxy Unit. D shall be a fraction and shall be equal to the weighted average fractional summer derating (using the Winter Capability of each generating unit for such weighting) of the generating units in which the Participants have Installed Capability Entitlements. K1, K2, K3, K4, and K5 are conversion coefficients for each of the Summer and Winter Periods, determined by regression analysis such that the product for the Installed Capability of a New Unit times its New Unit Adjustment Factor approximates the effect on NEPOOL Objective Capability of the New Unit. Proxy Unit characteristics and conversion coefficients contained in the formula shall be adopted by the Participants Committee and reviewed every five years (or more frequently if the Participants Committee determines that exceptional circumstances require an earlier review) and revised as necessary. If a New Unit has unique characteristics affecting NEPOOL Objective Capability which are not adequately reflected in the New Unit Adjustment Factor formula, the Participants Committee shall determine for such New Unit a New Unit Adjustment Factor which accounts for the New Unit's unique characteristics. The New Unit Adjustment Factor for any Restricted Unit (as defined in Section 15.37B of the Prior NEPOOL Agreement) for which proposed plans were submitted subsequent to November 1, 1990 for review pursuant to Section 18.4 or its predecessor section in the Prior NEPOOL Agreement (or, in the case of a unit with a rated capacity of less than 5 MW, for which notification was first given to NEPOOL subsequent to November 1, 1990) and for the Peabody Municipal Light Plant's Waters River #2 unit shall be determined in accordance with the formula previously specified in Section 12.2(a)(2), modified as follows: n = R(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) +K5(f- F)c) + K5(2500-a) The symbols used in the above formula, as modified, shall have the meanings previously specified, except that the symbols "K6" and "a" shall have the following meanings: K6 is a scaling factor of 0.0001. a is as follows: for units with more than 2500 annual hours available for operation, "a" = 2500, for units with annual hours available for operation between 500 and 2500, inclusive, "a" = annual hours available for operation, and for units with annual hours available for operation less than 500 hours, "a" = -7500; provided, however, that a Participant may elect to avoid, in whole or part, the effect on its Installed Capability Responsibility of a Restricted Unit's availability being limited to 2500 hours or less a year by agreeing to leave unfilled a portion of its dispatchable load allocation in accordance with rules adopted by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter. (a) The tentative Installed Capability Responsibilities of the Participants for any month, as determined in accordance with Section 12.2(a), shall be adjusted in accordance with this Section 12.2(b) in the event the value of H for any Participant for any of the Twelve-Month Measurement Periods applicable to the Participant for the month is increased in accordance with Section 12.2(a) because of the application of paragraph (ii) of the definition of H1. In such event the System Operator under the direction of the Participants Committee shall determine each Participant's tentative Installed Capability Responsibility for the month with and without the application of said paragraph (ii). The difference between the sum of all Participants' tentative Installed Capability Responsibilities, with and without the application of said paragraph (ii) for the month, shall be added to the tentative Installed Capability Responsibilities of the Participants, as determined in accordance with Section 12.2(a), in proportion to said tentative Installed Capability Responsibilities, thereby establishing each Participant's adjusted tentative Installed Capability Responsibility for the month. (b) For each month, the System Operator under the direction of the Participants Committee shall determine the sum of all Participants' adjusted tentative Installed Capability Responsibilities, as initially determined in accordance with Section 12.2(a) and as adjusted in accordance with Section 12.2(b), if Section 12.2(b) is applicable for such month. If the sum is less than, or equal to, the minimum NEPOOL Installed Capability during the month, then the adjusted tentative Installed Capability Responsibility as determined pursuant to Section 12.2(a) or 12.2(b), whichever is applicable, for each Participant is the final Installed Capability Responsibility for each Participant. If the sum is greater than such minimum NEPOOL Installed Capability, then each Participant's final Installed Capability Responsibility shall be its adjusted tentative Installed Capability Responsibility as determined pursuant to Section 12.2(a) or 12.2(b), whichever is applicable, multiplied by the ratio of the minimum NEPOOL Installed Capability during the month to the sum of the adjusted tentative Installed Capability Responsibilities for the month. (c) It is recognized that the treatment of fuel conversions, dual fuel units, immature units, new Installed Capability Entitlements, cogeneration and small power-producing facilities, Unit Contracts and other contract arrangements, units with unusual maintenance cycles, and various other matters can result in special problems in the determination of Unit Availability Adjustment Factors and New Unit Adjustments. Accordingly, the Markets Committee shall analyze such special problems and recommend to the Participants Committee for approval appropriate Market Rules to be applied in taking such matters into account in the determination of Unit Availability Adjustment Factors and New Unit Adjustments. 12.3 [Deleted.]. 12.4 [Deleted.]. 12.5 Consequences of Deficiencies in Installed Capability Responsibility. (a) At the conclusion of each month, the System Operator shall determine whether each Participant has satisfied its Installed Capability Responsibility obligation for the month. If the minimum monthly Installed System Capability of a Participant during the month was less than its Installed Capability Responsibility, the number of Kilowatts of its deficiency shall be computed and the Participant shall be deemed to purchase from other Participants through NEPOOL Kilowatts of surplus Installed System Capability equal to the amount of its deficiency and shall pay to NEPOOL for the month any applicable fees for services assessed pursuant to Section 19.2 plus the product of its total Kilowatts of deficiency and the Installed Capability deficiency charge. For purposes of this Section 12, the minimum monthly Installed System Capability of a Participant for a month is the Participant's lowest Installed System Capability for any hour during the month. Retirements made on the last day of any month shall not be deducted from Installed System Capability for that month. (b) The Installed Capability deficiency charge shall be an administratively-determined charge approved by the Participants Committee, except that, if the Participants Committee is unable to finally approve such a charge on or before July 28, 2000, the Installed Capability deficiency charge shall be the charge determined by the System Operator, until such time as the Participants Committee finally approves a different charge. (c) The Installed Capability deficiency charge that is to become effective on August 1, 2000 is subject to the acceptance and/or approval by the Commission of the materials filed in compliance with the Commission's June 28, 2000 order in Docket Nos. EL00-62-000, et al. Pending Commission action on such charge, any collections for deficiencies in Installed Capability on and after August 1, 2000 shall be subject to refund or surcharge back to August 1, 2000 if the deficiency charge accepted and/or approved by the Commission is different from the charge identified in the compliance filing. (d) The Installed Capability Responsibility deficiency charges for each month shall be divided among and paid to those Participants whose minimum monthly Installed System Capabilities during such month exceeded their Installed Capability Responsibilities, in proportion to the amounts of their respective excesses over their Installed Capability Responsibilities. 12.6 [Deleted]. 12.7 Payments to Participants Furnishing Installed Capability. Participants that are deemed pursuant to Section 12.5 to furnish any surplus in their Installed System Capability to other Participants shall receive therefor their pro rata shares on a Kilowatt basis of all payments made by Participants for the month under Section 12.5, excluding any applicable fees for services assessed pursuant to Section 19.2. If two or more Participants with excess Installed System Capability have bid Kilowatts at the Installed Capability Clearing Price, but not all the excess Installed System Capability bid at such price is required to meet shortages of Installed System Capability, then the excess Installed System Capability bid at the Installed Capability Clearing Price that each such Participant shall be deemed to have furnished shall be the Kilowatts of excess Installed System Capability bid by the Participant at that price multiplied by the ratio of (i) the total Kilowatts of excess Installed System Capability bid at the Installed Capability Clearing Price needed to meet the shortages to (ii) the total Kilowatts of excess Installed System Capability bid by all Participants at the Installed Capability Clearing Price. [Next Sheet is 157] Sheet 157 is intentionally blank. [Next Sheet is 158] SECTION 13 OPERATION, GENERATION, OTHER RESOURCES, AND INTERRUPTIBLE CONTRACTS 13.1 Maintenance and Operation in Accordance with Accepted Electric Industry Practice. Each Participant shall, to the fullest extent practicable, cause all generating facilities and other resources owned or controlled by it to be designed, constructed, maintained and operated in accordance with Accepted Electric Industry Practice. 13.2 Central Dispatch. Subject to the following sentence, each Participant shall, to the fullest extent practicable, subject all generating facilities and other resources owned or controlled by it to central dispatch by the System Operator; provided, however, that each Participant shall at all times be the sole judge as to whether or not and to what extent safety requires that at any time any of such facilities will be operated at less than full capacity or not at all. Each Participant may remove from central dispatch a generating facility or other resources owned or controlled by it if and to the extent such removal is permitted by rules and standards approved by the Participants Committee. 13.3 Maintenance and Repair. Each Participant shall, to the fullest extent practicable: (a) cause generating facilities and other resources owned or controlled by it to be withdrawn from operation for maintenance and repair only in accordance with maintenance schedules reported to and published by the System Operator from time to time in accordance with procedures established or approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter, (b) restore such facilities to good operating condition with reasonable promptness, and (c) accelerate or delay maintenance and repair at the reasonable request of the System Operator in accordance with market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter. 13.4 Objectives of Day -to - Day System Operation. The day-to-day scheduling and coordination through the System Operator of the operation of generating units and other resources shall be designed to assure the reliability of the bulk power system of the NEPOOL Control Area. Such activity shall: (a) satisfy the NEPOOL Control Area's Operating Reserve requirements, including the proper distribution of those Operating Reserves; (b) satisfy the Automatic Generation Control requirements of the NEPOOL Control Area; and (c) satisfy the Energy requirements of all Electrical Load of the Participants, all at the lowest practicable aggregate dispatch costs to the NEPOOL Control Area based upon Participant-directed schedules and Bids until the CMS/MSS Effective Date and based upon Self- Schedules, Self-Supplies, Supply Offers and Demand Bids on and after that Date. 13.5 Satellite Membership. Each Participant which is responsible for the operation of transmission facilities rated 69 kV or above in the NEPOOL Control Area or generating units and other resources which are subject to central dispatch by NEPOOL, or which is responsible for implementing voltage reduction and load shedding procedures in the NEPOOL Control Area, shall become a member of the appropriate satellite dispatching center; provided that by mutual agreement among the affected Participants and the appropriate satellite, a Participant may be excused from joining the satellite if it has arranged with a satellite member to assume responsibility to the satellite for its facilities or obligations. SECTION 14 INTERCHANGE TRANSACTIONS 14.1 Obligation for Energy, Operating Reserve and Automatic Generation Control. This Section 14 shall remain in effect for service under this Agreement until the CMS/MSS Effective Date and shall be superseded by the provisions of Section 14A of this Agreement for service on and after the CMS/MSS Effective Date. (a) Each Participant shall have for each hour an Energy obligation equal to its Electrical Load plus the kilowatthours delivered by such Participant to other Participants in the hour pursuant to Firm Contracts or System Contracts, together with any associated electrical losses. (b) Each Participant shall have for each hour Operating Reserve obligations equal to its share of the quantity of each category of Operating Reserve required for the NEPOOL Control Area in the hour. Subject to adjustment pursuant to Section 14.6, a Participant's share of each category of Operating Reserve required for any hour shall be determined in accordance with the following formula: ORp=SAp + [(OR-SA) (ELp/EL)], wherein ORp is the Participant's share of that category of Operating Reserve for the hour. SAp is the number of Kilowatts, if any, of that category of Operating Reserve for the hour that the Participants Committee determines should be assigned specifically to such Participant and not be shared by all Participants. OR is the aggregate number of Kilowatts of that category of Operating Reserve determined by the System Operator in accordance with the directions of the Participants Committee to be required for the NEPOOL Control Area for the hour that is not assigned to Non-Participants. SA is the aggregate number of Kilowatts of that category of Operating Reserve for the hour that the Participants Committee determines should not be shared by all Participants, but not including Operating Reserve assigned to Non- Participants. ELp is the Participant's Electrical Load for the hour. EL is the sum of ELp for all Participants. (a) Each Participant shall have for each hour an AGC obligation equal to its share of AGC required for the NEPOOL Control Area in the hour. Subject to adjustment pursuant to Section 14.6, a Participant's share of AGC required for any hour shall be determined in accordance with the following formula: AGCp=AGC (ELp/EL), wherein AGCp is the Participant's share of AGC for the hour. AGC is the total amount of AGC determined by the System Operator in accordance with market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter to be required for the NEPOOL Control Area for the hour that is not assigned to Non-Participants. ELp and EL are as defined in Section 14.1(b). 14.2 Obligation to Bid or Schedule, and Right to Receive Energy, Operating Reserve and Automatic Generation Control. (a) A Participant which has Energy Entitlements shall submit to or have on file with the System Operator, in accordance with the market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter, one or more bids for the Energy Entitlements for which the Participant is permitted to bid specifying the Bid Price at which it will furnish Energy through NEPOOL to other Participants under this Agreement or to Non- Participants for ancillary services under the Tariff, or pursuant to arrangements with Non-Participants entered into under Section 14.6, except to the extent such Entitlements are scheduled by the Participant consistent with Section 14.2(d). (b) A Participant which has Operating Reserve Entitlements or AGC Entitlements shall also submit to or have on file with the System Operator, in accordance with the market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter, one or more bids for each such Entitlement for which the Participant is permitted to bid specifying the Bid Prices at which it will furnish 10-Minute Spinning Reserve, 10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve and/or AGC through NEPOOL to other Participants under this Agreement or to Non-Participants for ancillary services under the Tariff, except to the extent such Entitlements are scheduled by the Participant consistent with Section 14.2(d). (c) Except as emergency circumstances may result in the System Operator requiring load curtailments by Participants, each Participant shall be entitled to receive from the other Participants (or from the service made available from Non- Participants pursuant to arrangements entered into under Section 14.6) such amounts, if any, of Energy, Operating Reserve, and AGC as it requires and Non-Participants shall be entitled to receive from Participants the amount of ancillary services to which they are entitled pursuant to the Tariff. If, for any hour, load curtailments are required, the amount that Participants and Non-Participants with shortages are entitled to receive shall be proportionally reduced by the System Operator in a fair and non-discriminatory manner in light of the circumstances. (d) All Bid Prices for Entitlements shall be submitted in accordance with market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter. If a Bid Price is not submitted for any such Entitlement, the Bid Price shall be deemed to be zero. For a generating unit in which there are multiple Entitlement holders, only one Participant shall be permitted to submit Bid Prices for Energy, Operating Reserve and/or AGC Entitlements for such unit or to direct the scheduling of the unit for any Scheduled Dispatch Period. The Entitlement holders in each unit with multiple Entitlement holders shall designate a single Participant that will be permitted to submit Bid Prices and/or to direct the scheduling of the unit. In the event that more than one Participant is designated, or if the Entitlement holders do not designate a single Participant, then Bid Prices for the unit shall be based on its replacement cost of fuel, which shall be furnished to the System Operator by the Participant responsible for furnishing such information as of December 1, 1996. Further, any schedules for the unit will be submitted to the System Operator by such Participant. Nothing in this Agreement shall affect the rights of any Entitlement holder under the contractual arrangements among such Entitlement holders relating to the unit. Prior to the Third Effective Date, Bid Prices must be submitted for the next Scheduled Dispatch Period for all Energy, Operating Reserve and AGC Entitlements in generating unit or units and Energy Entitlements pursuant to Firm Contracts or System Contracts which may be scheduled by the buyer in accordance with Section 14.7(b) no later than noon on the preceding day or such later time as is specified in the market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter. On and after the Third Effective Date, such Bid Prices shall be submitted for each hour of the day and the notice period for such Bid Prices shall be reduced to one hour or such shorter time as the System Operator determines from time to time is practical while maintaining reliability and meeting its other obligations to the Participants, except that such notice period shall be longer than one hour if and to the extent that the System Operator reasonably determines that such notice is the shortest notice that is technically feasible at that time to maintain reliability and meet its other obligations to the Participants. The System Operator shall notify the Participants following its receipt of all Bid Prices of the expected dispatch schedule for the next Scheduled Dispatch Period. The System Operator shall reduce the notice required for Bid Prices and the applicable Scheduled Dispatch Period to the minimum time technically and practically feasible while maintaining reliability and meeting its other obligations to the Participants. Energy, Operating Reserve and/or AGC Entitlements in a generating unit or units may also be scheduled directly by the Participants permitted to submit Bid Prices for such Entitlements, but only in accordance with this Section 14.2(d) and market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter consistent herewith. Subject to the right of the System Operator to direct changes to schedules in order to ensure reliability in the NEPOOL Control Area or any neighboring control area, a Participant permitted to bid its Energy, Operating Reserve, and/or AGC Entitlements in a generating unit or units, or required to make Energy deliveries, may submit an hour-to-hour schedule for the operation or dispatch of such Entitlements during a Scheduled Dispatch Period at or before the time that Bid Prices are required to be submitted for such period. In addition, prior to the Third Effective Date, a Participant permitted to bid a unit or units may submit a short-notice schedule for the operation or dispatch of any or all of the Energy available from such unit or units during the current or a subsequent Scheduled Dispatch Period following the time that the System Operator notifies the appropriate Participants of their expected Entitlement commitments for that Scheduled Dispatch Period; provided that, for each such short-notice schedule, the Participant has not been advised by the System Operator that the Energy, Operating Reserve or AGC Entitlements from the unit or units covered by the Participant's schedule are expected to be used during the Scheduled Dispatch Period to meet the region's Energy, Operating Reserve and/or AGC requirements, and provided further that the Participant short-notice schedule is only to facilitate transactions during such period from resources or to load located outside the NEPOOL Control Area; and provided further that such schedule is furnished at least one hour in advance of the start of the transaction. In addition, a Participant may, on the same short notice, schedule System Contracts with Non-Participants from resources or to load located outside of the NEPOOL Control Area. 14.3 Amount of Energy, Operating Reserve and Automatic Generation Control Received or Furnished. (a) For purposes of Sections 14.4, 14.5, and 14.8, the amount of Energy which a Participant is deemed to receive or furnish in any hour shall be the amount of its Adjusted Net Interchange. If the Adjusted Net Interchange is negative, the Participant shall be deemed to be receiving Energy in the hour. If the Adjusted Net Interchange is positive, the Participant shall be deemed to be furnishing Energy in the hour. (b) For purposes of Sections 14.4, 14.5, and 14.9, prior to the Third Effective Date: the amount of each category of Operating Reserve which a Participant is deemed to receive in any hour is the Kilowatts of such Operating Reserve assigned to the Participant for the hour under Section 14.1(b) less any Kilowatts provided in the hour by the Participant in accordance with the market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter to meet any Operating Reserve requirements that were specifically assigned to it and not shared by all Participants; the amount of Operating Reserve of each category that the Participant is deemed to have furnished under the Agreement in the hour is the amount of such Operating Reserve designated by the System Operator to be provided in the hour by the Participant's applicable Operating Reserve Entitlements, minus any Kilowatts used in the hour by the Participant in accordance with the market operation rules to meet any Operating Reserve requirements that were specifically assigned to it and not shared by all Participants. For purposes of Sections 14.4, 14.5, and 14.9, on and after the Third Effective Date, the amount of each category of Operating Reserve which a Participant is deemed to have received or furnished in any hour is the difference between the Kilowatts of such Operating Reserve assigned to the Participant for the hour under Section 14.1(b) and the Kilowatts of such Operating Reserve designated by the System Operator to be provided in the hour by the Participant's applicable Operating Reserve Entitlements. (c) For purposes of Sections 14.4, 14.5, and 14.10, prior to the Third Effective Date, the amount of AGC which a Participant is deemed to have received in an hour is the AGC assigned to the Participant for the hour under Section 14.1(c), and the amount a Participant is deemed to have furnished in the hour is the AGC designated by the System Operator to be provided in the hour by the Participant's AGC Entitlements. For purposes of Sections 14.4, 14.5, and 14.10, on and after the Third Effective Date, the amount of AGC which a Participant is deemed to have received or furnished in an hour is the difference between the AGC assigned to the Participant for the hour under Section 14.1(c) and the AGC designated by the System Operator to be provided in the hour by the Participant's AGC Entitlements. 14.4 Payments by Participants Receiving Energy Service, Operating Reserve and Automatic Generation Control. (a) For every hour in which a Participant's Adjusted Net Interchange is negative, the number of megawatthours of its Energy deficiency shall be computed and the Participant shall pay for the hour the product of its total megawatthours of deficiency and the Energy Clearing Price applicable for the hour as determined in accordance with Section 14.8, together with any applicable uplift charges assessed to the Participant under Sections 14.14 and 14.15 of this Agreement and Section 24 of the Tariff and any applicable fees for services assessed pursuant to Section 19.2. (b) For every hour in which a Participant is deemed to receive Operating Reserve of any category in accordance with Section 14.3(b), the number of Kilowatts it is deemed to receive for the hour in each category shall be computed. The Participant shall pay therefor for the hour any applicable uplift charge assessed under Section 14.15 and any applicable fees for services assessed pursuant to Section 19.2 plus the product of (i) the aggregate amount paid to Participants for that category of Operating Reserve for the hour pursuant to Section 14.5(b) and (ii) a fraction of which the numerator is the Kilowatts of that category of Operating Reserve deemed under Section 14.3(b) to have been received by the Participant for the hour and the denominator is the aggregate Kilowatts of that category of Operating Reserve deemed under Section 14.3(b) to have been received by all Participants for the hour. (c) For every hour in which a Participant is deemed under Section 14.3(c) to have received AGC, the amount it is deemed to receive shall be computed and the Participant shall pay therefor any applicable uplift charge assessed under Section 14.15 and any applicable fees for services assessed pursuant to Section 19.2 plus the product of (i) the aggregate amount paid to Participants for AGC for the hour pursuant to Section 14.5(c) and (ii) a fraction of which the numerator is the AGC the Participant is deemed under Section 14.3(c) to have received for the hour and the denominator is the aggregate amount of AGC all Participants are deemed under Section 14.3(c) to have received for the hour. 14.5 Payments to Participants Furnishing Energy Service, Operating Reserve, and Automatic Generation Control. (a) Subject to the provisions of Section 14.12, a Participant that is deemed in an hour to furnish Energy service to other Participants pursuant to Section 14.3, or to Non-Participants for ancillary services under the Tariff or pursuant to arrangements entered into under Section 14.6, shall receive for each megawatthour furnished by it the Energy Clearing Price for the hour determined in accordance with Section 14.8 or the Bid Price for that megawatthour, if higher than the Energy Clearing Price and the unit is either within the Energy Clearing Price Block (as defined in Section 14.8(c)) or is operated out of merit if such higher Bid Price is appropriately paid pursuant to market operation rules governing out-of-merit generation approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter. In addition, to the extent that the System Operator reduces Energy production from a generating unit or units in order to provide VAR support, Participants with Entitlements in such unit or units may receive their lost opportunity costs if and to the extent provided for by market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter. (b) A Participant that is deemed in an hour to furnish Operating Reserve under the Agreement shall receive for each Kilowatt of each category of Operating Reserve furnished by it the applicable Operating Reserve Clearing Price as defined and determined in accordance with Section 14.9 or the Bid Price to provide such Kilowatt, if higher than the Operating Reserve Selling Price for the hour. (c) A Participant that is deemed in an hour to furnish AGC under the Agreement shall receive therefor an amount calculated as follows: (i) the AGC Clearing Price for the hour as defined and determined in accordance with Section 14.10, times the change in AGC output of the Participant's AGC Entitlements which the System Operator requested in the hour, times an appropriate unit conversion factor as determined in accordance with market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter; plus (ii) an AGC reservation payment for each AGC Entitlement that the System Operator designated for AGC in the hour calculated as (A) the AGC Clearing Price in effect for the hour, times (B) the level of AGC the System Operator determines to be available in the hour from the Entitlement, times (C) the portion of the hour during which the System Operator had designated the Entitlement for AGC; plus (iii) a payment that compensates the Participant for its lost opportunity cost, if any, for the operation of the generating unit or combination of units designated for AGC in the hour below the desired level of output in order to provide AGC, as determined in accordance with Market Rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter. (a) In no event shall Participants be paid for lost opportunity costs resulting from a generating unit being dispatched down or off to accommodate transmission constraints, and nothing in this Agreement or the Market Rules shall provide for any such payment. 14.6 Energy Transactions with Non-Participants. (a) The Participants Committee is authorized to enter into contracts on behalf of and in the names of all Participants (i) with power pools or other entities in one or more other control areas to purchase or furnish emergency Energy (and related services) that is available for the System Operator to schedule in order to ensure reliability in the NEPOOL Control Area or neighboring control areas, and (ii) with Non- Participants pursuant to which ancillary services will be provided by the Participants pursuant to the Tariff. The terms of any such contractual arrangement shall not require the furnishing of emergency service to any other control area until the service needs of all Participants have been provided for with the least expensive resources practicable. Energy purchased in any hour from Non-Participants under a contract entered into pursuant to this Section 14.6(a) shall be deemed to be furnished to, and paid for by, Participants entitled to or requiring such Energy in the hour pursuant to this Section 14 at the higher of the Energy Clearing Price for the hour or the price paid to the Non-Participant for the Energy. (b) The Participants Committee is authorized to provide for the day-to-day scheduling through the System Operator of the HQ Phase II Firm Energy Contract, in accordance with the HQ Use Agreement, as if the Contract were a contract covering Energy transactions with a Non-Participant entered into pursuant to Section 14.6(a). The HQ Phase II Firm Energy Contract shall not be deemed a Firm Contract for purposes of this Agreement. Energy received in an hour from Hydro-Quebec pursuant to the HQ Energy Banking Agreement, and Energy purchased in any hour from Hydro-Quebec pursuant to the HQ Phase II Firm Energy Contract or any other HQ Contract shall be deemed to be Energy furnished to each Participant entitled to such Energy for the hour in the amount reflected for the Participant in the System Operator's scheduling of Energy deliveries in the hour from Hydro-Quebec; except that emergency Energy received from Hydro-Quebec under the HQ Interconnection Agreement shall be deemed to be Energy provided to (and shall be paid for by) Participants requiring such emergency Energy in the hour. The System Operator shall schedule such Energy deliveries to accommodate, to the maximum extent possible, the schedule of Energy deliveries from Hydro- Quebec requested by the Participant. The Participants deemed to have received such Energy shall pay therefor the higher of the Energy Clearing Price (together with any applicable uplift charges under Sections 14.14 and/or 14.15 of this Agreement and/or Section 24 of the Tariff and any applicable fees for services assessed pursuant to Section 19.2) or the price paid to Hydro-Quebec for the Energy (or in the case of Energy received under the HQ Energy Banking Agreement, the price paid for the related Energy deliveries to Hydro-Quebec under the Agreement and any amount payable to Hydro-Quebec with respect to the transaction). 14.7 Participant Purchases Pursuant to Firm Contracts and System Contracts. (a) A Participant may undertake to transfer all or select portions of its settlement rights and obligations under this Agreement to or from another Participant with respect to any of the NEPOOL markets pursuant to a Bilateral Transaction. Such transfer of settlement rights and obligations under this Agreement shall be as agreed to between the two parties to the Bilateral Transaction and shall be submitted to the System Operator in accordance with the Market Rules. If and to the extent necessary to implement the agreement between the parties, such Market Rules, upon approval by the Participants Committee, shall supersede the provisions of the Agreement that otherwise apply for determination of the respective settlement rights and obligations of the parties. (b) In the event a Participant has the right to receive Energy, Operating Reserve and/or AGC from a Non-Participant under a System Contract or a Firm Contract, such Contract shall be treated as nearly as possible as if it were a Unit Contract for an Energy Entitlement, Operating Reserve Entitlement and/or AGC Entitlement, as applicable, provided that, in the case of Energy, Operating Reserve, and/or AGC, the System Contract or Firm Contract permits the scheduling of deliveries of such Energy, Operating Reserve and/or AGC to be subject in whole or part to central dispatch through the System Operator in accordance with Market Rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter. 14.8 Determination of Energy Clearing Price. For each hour, the System Operator shall determine the Energy Clearing Price as follows: (a) The System Operator shall rank in the order of lowest to highest (i) the Dispatch Prices derived from the Bid Prices to furnish Energy in the hour and (ii) the cost to NEPOOL of any Energy received from Non-Participants in the hour pursuant to contracts referenced in Section 14.6. (b) The Energy Clearing Price shall be the weighted average of the Dispatch Prices (or NEPOOL cost) of the "Energy Clearing Price Block" as defined in the next sentence. The Energy Clearing Price Block shall be identified for each hour in accordance with market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter to reflect those resources with the highest Dispatch Prices or NEPOOL cost that were centrally dispatched by the System Operator for Energy deemed to have been furnished to the Participants, excluding resources that were dispatched out of merit as determined in accordance with market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter. 14.9 Determination of Operating Reserve Clearing Price. (a) For each hour as necessary, the System Operator shall determine the Operating Reserve Clearing Price for each category of Operating Reserve as follows: (i) The System Operator shall determine the aggregate Kilowatts of the applicable category of Operating Reserve that are deemed pursuant to Section 14.3(b) to have been received by Participants for the hour. (ii) For 10-Minute Non-Spinning Reserve and 30-Minute Operating Reserve, the System Operator shall rank in the order of lowest to highest the Bid Prices of the resources designated by the System Operator for that category of Operating Reserve for the hour. The applicable Operating Reserve Clearing Price for 10-Minute Non-Spinning Reserve or 30-Minute Operating Reserve shall be the weighted average of the highest Bid Prices for the 1000 Kilowatts (or such other number as may be specified by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter) of that category of Operating Reserve that are designated by the System Operator for use in the hour. (iii) For 10-Minute Spinning Reserve the System Operator shall rank in order of lowest to highest the 10- Minute Spinning Reserve Lost Opportunity Prices (as defined in Section 14.9(b)) of the resources designated by the System Operator for the hour. The Operating Reserve Clearing Price for 10-Minute Spinning Reserve shall be the weighted average for the 1000 Kilowatts (or such other number as may be specified by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter) of the highest 10-Minute Spinning Reserve Lost Opportunity Prices for the hour of the Entitlements that were designated by the System Operator for use in the hour. (b) The System Operator shall determine a 10-Minute Spinning Reserve Lost Opportunity Price for each hour for use in determining the Operating Reserve Clearing Price for 10-Minute Spinning Reserve. For the purposes of Section 14.9, the 10- Minute Spinning Reserve Lost Opportunity Price for a Participant's resource shall be the amount by which the Energy Clearing Price for the hour exceeds the resource's Dispatch price (not less than zero), plus the Bid Price in the hour for each resource to provide 10-Minute Spinning Reserve. 14.10 Determination of AGC Clearing Price. For each hour, the System Operator shall determine the AGC Clearing Price. The AGC Clearing Price shall be the weighted average "AGC Capability Price" for the "AGC Clearing Price Block," as both terms are defined below in this Section 14.10. The AGC Capability Price for each hour for each AGC Entitlement designated by the System Operator to provide AGC in the hour shall be a cost per unit of AGC capability based on the Bid Price for the Entitlement for the hour divided by the amount of AGC available in the hour from that Entitlement. The AGC Clearing Price Block shall be identified by the System Operator for each hour in accordance with market operation rules approved by the Markets Committee prior to the activation of the Participants Committee or the Participants Committee thereafter to reflect those AGC resources with the highest Bid Prices that were designated by the System Operator to provide AGC in the hour and were deemed pursuant to Section 14.3(c) to have been received by Participants for the hour. 14.11 Funds to or from which Payments are to be Made. (a) All payments for Energy, Operating Reserves or AGC furnished or received, all uplift charges paid pursuant to this Section 14 of this Agreement and Section 24 of the Tariff, and all fees for services paid pursuant to Section 19.2, and any payments by Non-Participants for ancillary services under Schedules 2-7 to the Tariff or pursuant to arrangements referenced in Section 14.6, shall be allocated each month through the Pool Interchange Fund as follows: Step One. For each week in which Energy is delivered or received under the HQ Energy Banking Agreement, all payments with respect to transactions under that Agreement shall be made to or from the Energy Banking Fund provided for in Section 14.11(b). Step Two. (i) For each week in which Pre-Scheduled Energy (as defined in the HQ Phase I Energy Contract) is purchased pursuant to the HQ Phase I Energy Contract, the aggregate amount which is paid pursuant to Section 14.6(b) for such Energy by each Participant which is a participant in the Phase I arrangements with Hydro-Quebec shall be determined and paid on the Participant's account into the Phase I Savings Fund. (ii) For each week in which Energy is purchased pursuant to the HQ Phase II Firm Energy Contract, the aggregate amount which is paid pursuant to Section 14.6(b) for such Energy by each Participant which is a participant in the Phase II arrangements with Hydro-Quebec shall be determined and paid on the Participant's account into the Phase II Savings Fund. Step Three. For each week in which Other HQ Energy is purchased pursuant to the HQ Phase I Energy Contract or Energy is purchased pursuant to the HQ Interconnection Agreement, the aggregate amount paid pursuant to Section 14.6(b) for such Energy shall be determined for each Participant which is a participant in the Phase I or Phase II arrangements with Hydro-Quebec. Such amount shall be allocated between the Participant's share of the Phase I Savings Fund and the Participant's share of the Phase II Savings Fund created under the HQ Use Agreement in the same ratio as (A) the sum of (x) the number of kilowatthours of Other HQ Energy deemed to be purchased by the Participant during the week and (y) the HQ Phase I Percentage of the number of kilowatthours deemed to be purchased by the Participant under the HQ Interconnection Agreement during the week, bears to (B) the HQ Phase II Percentage of the number of kilowatthours purchased under the HQ Interconnection Agreement during the week. Step Four. The balance remaining in the Pool Interchange Fund after Steps One through Three shall be retained in the Pool Interchange Fund for the month and shall be used and disbursed after each month in the following order: (i) (A) amounts owed to Non-Participants (other than Hydro-Quebec) for the month under contracts entered into with them pursuant to Section 14.6(a) shall be paid, and (B) amounts owed to Hydro-Quebec for the month for Energy deemed to be furnished pursuant to Section 14.6(b) to Participants which are not participants in the Phase I or Phase II arrangements with Hydro-Quebec shall be paid and, in the event the price paid by any such Participant for such Energy is the Energy Clearing Price, the excess, if any, of the Energy Clearing Price over the amount owed to Hydro-Quebec shall be paid to the Participant; (ii) amounts paid by Participants for applicable fees for services assessed pursuant to Section 19.2 shall be used to reduce NEPOOL expenses; and (iii) amounts owed to Participants for the month pursuant to Section 14.5 shall then be paid. (b) HQ Energy Banking Fund. All amounts allocated to the HQ Energy Banking Fund for each month shall be used and disbursed as follows: (i) Participants which furnish Energy for delivery to Hydro-Quebec under the HQ Energy Banking Agreement shall receive therefor from their share of the Energy Banking Fund the amount to which they are entitled for such service in accordance with Section 14.5. (ii) amounts required to be paid to Hydro-Quebec under the HQ Energy Banking Agreement shall be paid from the shares of the Fund of the Participants engaging in transactions under the HQ Energy Banking Agreement for the month in accordance with their respective interests in the transactions for the month. If there is not enough in any such share, the Participants with the deficient shares shall be billed and pay into their shares of the Fund the amounts required for payments to Hydro-Quebec. (iii) subject to the remaining provisions of this Section, at the end of each month any balance remaining in each Participant's share of the HQ Energy Banking Fund shall (I) in the case of any Participant which is not a participant in the Phase I or Phase II arrangements with Hydro-Quebec, be paid to such Participant, and (II) in the case of any Participant which is a participant in the Phase I or Phase II arrangements with Hydro-Quebec, be paid to the Escrow Agent under the HQ Use Agreement to be held and disbursed by it through the Phase I Savings Fund and Phase II Savings Fund created under the HQ Use Agreement, and shall be allocated between the Participant's share of said Funds as follows: (A) the balance remaining in the Participant's share of the HQ Energy Banking Fund for the month shall be divided by the number of kilowatthours deemed to be received by the Participant under the HQ Energy Banking Agreement during the month to determine an average savings amount per kilowatthour; (B) for any hour during the month in which the number of kilowatthours received by NEPOOL under the HQ Energy Banking Agreement exceeded the HQ Phase I Transfer Capability, an amount equal to (A) the Participant's share of the excess of (1) the number of kilowatthours received over (2) the HQ Phase I Transfer Capability times (B) the average savings amount per kilowatthour determined for that Participant under (i) above shall be allocated to the Phase II Savings Fund; and (C) the remaining balance of the Participant's share of the HQ Energy Banking Fund for the month shall be allocated to the Phase I Savings Fund. It is recognized that, in view of the time which may elapse between the delivery of Energy to or by Hydro-Quebec in an Energy Banking transaction under the HQ Energy Banking Agreement and the return of the Energy, the amounts of Energy delivered to and received from Hydro-Quebec, after adjustment for losses, may not be in balance at the end of a particular month. Further, if as of the end of any month and after adjustment for electrical losses, the cumulative amount of Energy so received from Hydro-Quebec exceeds the amount so delivered, the aggregate amount paid by Participants for the excess Energy pursuant to Section 14.6(b) shall be paid to the Energy Banking Fund. The Escrow Agent under the HQ Use Agreement shall hold and invest these funds. On the return of the excess Energy to Hydro-Quebec, the amount so held by the Escrow Agent shall be repaid to Hydro-Quebec and Participants in accordance with the Energy Banking Agreement. (c) Phase I HQ Savings Fund. The aggregate amount allocated to each Participant's share of the Phase I HQ Savings Fund for each month shall be used, first, to pay to Hydro-Quebec the amount owed to it for the month for Energy furnished under the Phase I HQ Energy Contract and the HQ Phase I Percentage of the amount owed to it for the month for Energy furnished to the Participants under the HQ Interconnection Agreement. The balance of the amount allocated to the Fund for the month shall be paid to the Escrow Agent under the HQ Use Agreement to be held and disbursed by it through the Phase I HQ Savings Fund created thereunder in accordance with each Participant's contribution to such balance. (d) Phase II HQ Savings Fund. The aggregate amount allocated to the Phase II HQ Savings Fund for each month shall be used, first, to pay to Hydro-Quebec the amount owed to it for the month for Energy deemed to be furnished to the Participant under the Phase II HQ Firm Energy Contract and the HQ Phase II Percentage of the amount owed to it for the month for Energy deemed to be furnished to the Participant under the HQ Interconnection Agreement. The balance of the amount allocated to the Fund for the month shall be paid to the Escrow Agent under the HQ Use Agreement to be held and disbursed by it through the Phase II HQ Savings Fund created thereunder in accordance with each Participant's contribution to such balance. 14.12 Development of Rules Relating to Nuclear and Hydroelectric Generating Facilities, Limited-Fuel Generating Facilities, and Interruptible Loads. It is recognized that the central dispatch of Energy available from nuclear generating facilities and from pondage associated with hydroelectric generating facilities and from interruptible loads and of pumping Energy for pumped storage hydroelectric generating facilities and other limited-fuel generating facilities involves special problems which must be resolved to assure fair and non-discriminatory treatment of Participants having Entitlements in such generating facilities or having such interruptible loads or any other Participants involved in such transactions. Accordingly, the Markets Committee shall analyze such special problems and recommend to the Participants Committee for approval appropriate rules for dispatching such facilities (including, but not limited to, bids for dispatchable pumping load at pumped storage facilities), for handling such interruptible loads and for paying for Energy, Operating Reserve and AGC involved in such transactions on a basis consistent with the principles underlying this Section 14; and upon approval by the Participants Committee such rules shall supersede the provisions of Sections 12 and 14 to the extent of any conflict. 14.13 Dispatch and Billing Rules During Energy Shortages. It is recognized that Energy shortages can result in special problems which must be resolved to assure that dispatch and billing provisions do not prevent achievement of the objectives specified in Section 13.4. Accordingly, the Markets Committee shall analyze such special problems and recommend to the Participants Committee for approval appropriate dispatch and billing rules to be applied during periods when the Participants Committee determines that there is, or is anticipated to be, an Energy shortage which adversely affects the bulk power supply of the NEPOOL Control Area and any adjoining areas served by Participants. Upon approval by the Participants Committee, such rules shall supersede the economic dispatch and billing provisions of this Agreement to the extent of any conflict therewith for the duration of such Energy shortage period. 14.14 Congestion Uplift. (a) It shall be the responsibility of the Participants Committee to review prior to January 1, 2000 the Congestion Costs incurred with the new market arrangements contemplated by Section 14 of this Agreement and with retail access, and to determine whether subsection (b) of this Section, together with an amendment specifying the rights of Participants and Non-Participants across a constrained interface within the NEPOOL Control Area and to make other necessary or appropriate changes in subsection (b), all of the provisions of which shall be considered for modification, or some other modified or substitute provision dealing with the allocation of Congestion Costs in a constrained transmission area, should be made effective on March 1, 2000 and after the preparation of necessary implementing rules and computer software or on an earlier or later effective date. If the Participants Committee determines that such a provision should be made effective, it shall recommend to the Participants any required amendment to the Agreement and/or the Tariff and a schedule for implementation which will permit sufficient time for the development of necessary rules and computer software. If the Participants Committee is unable to agree on such a determination prior to January 1, 2000 any Participant or group of Participants may propose such an amendment and schedule in a filing with the Commission. (b) Commencing on the implementation effective date of an order by the Commission directing a different allocation of congestion costs, whenever limitations in available transmission capacity in any hour require that the System Operator dispatch out-of-merit resources that are bid by the Participants in any area which is determined to be a constrained transmission area in accordance with Market Rules, the System Operator shall determine for the constrained transmission area the aggregate Congestion Costs for the hour. [Next Sheet is 196] Such Congestion Costs for each hour shall be allocated to and paid by Participants and Non-Participants as a congestion uplift as follows: (i) In accordance with market operation rules approved by the Regional Market Operations Committee and the Regional Transmission Operations Committee prior to the activation of the Participants Committee or the Participants Committee thereafter, the System Operator shall identify for each Participant and Non-Participant the difference in megawatt hours, if any, between (A) Electrical Load served by the Participant or Non- Participant in the constrained area and transactions by the Participant or Non-Participant occurring in the hour which utilized the constrained interface to move Energy through the constrained area and (B) the Participant's or Non-Participant's in-merit Energy Entitlements located in [Next Sheet is 197] the constrained area that were used in the hour to serve such Electrical Load, taking into account Firm Contracts and System Contracts between Participants and electrical losses, if and as appropriate. (ii) The System Operator shall identify for each Participant and Non-Participant the megawatt hours, if any, of the rights of that Participant or Non-Participant to use the then effective transfer capability across the constrained interface. (iii) The System Operator shall identify for each Participant and Non-Participant the megawatt hours, if any, by which the amount determined pursuant to clause (i) above for that Participant or Non-Participant exceeds the amount determined for that Participant or Non- Participant pursuant to clause (ii) above. If the clause (i) amount exceeds the clause (ii) amount, the Participant or Non-Participant shall be responsible for paying a share of the aggregate Congestion Costs in proportion to the Participant's or Non-Participant's share of the aggregate amount of such excesses for all Participants and Non-Participants, and such Congestion Costs shall be included, as a transmission charge, in the Regional Network Service, Internal Point-to-Point Service or Through or Out Service charge, whichever is applicable. (c) As used in this Section 14.14, the "Congestion Cost" of an out-of-merit resource for an hour means the product of (i) the difference between its Dispatch Price and the Energy Clearing Price for the hour, times (ii) the number of megawatt hours of out-of-merit generation produced by the resource for the hour. 14.14A CMS/MSS Implementation Studies Related to Congestion. (a) Study of Transmission Constraints and Reliability Regions. The Participants Committee shall commission a study to determine whether the implementation of CMS and MSS is likely to result in substantial, adverse impacts on any load pockets within New England. As an additional component of this study, there shall be an initial determination of the existence or lack of workable competition in the NEPOOL Markets in Reliability Regions, Load Zones and any load pockets. This study shall commence on or before July 1, 2000 and shall be completed no later than December 31, 2000. If the results of this study determine that there is likely to be substantial adverse impacts on any load pocket due to the implementation CMS and MSS, the Participants Committee shall undertake to develop new measures to mitigate such impacts. Unless or until new measures are implemented to replace or supplement existing measures, the System Operator shall apply existing NEPOOL System Rules to mitigate such impacts to the extent possible and appropriate. In evaluating whether there will be substantial adverse impacts, the study shall take into account planned transmission enhancements to increase transfer capability into any load pocket, the anticipated operation of new or expanded generating units and anticipated retirements of existing generating units, the anticipated value of FCRs and revenues from the sale thereof that will be available to load in any load pocket, the concentration of ownership of generation and responsibilities for serving load in the load pocket, and the anticipated load response to such adverse impacts. (b) Study of Market Rule and Procedure 17 ("Market Rule 17"). Before the CMS/MSS Effective Date, the System Operator and Participants shall review Market Rule 17 and consider changes, where appropriate, to that Market Rule in light of the implementation of CMS and MSS. The review shall be supervised and assisted by persons who have recognized antitrust expertise and experience and are retained by or on behalf of the Participants Committee. At a minimum, before the CMS/MSS Effective Date, Market Rule 17 shall be amended to prescribe the process to determine whether a Reliability Region or load pocket within a Reliability Region is workably competitive and, if a Reliability Region or load pocket is determined not to be workably competitive, the types of mitigation measures available to be applied to remedy such situation. 14.15 Additional Uplift Charges. It is recognized that the System Operator may be required from time to time to dispatch resources out of merit for reasons other than those covered by Section 14.14 of this Agreement and Section 24 of the Tariff. Accordingly, if and to the extent appropriate, feasible and practical, dispatch and operational costs shall be categorized and allocated as uplift costs to those Participants and Non- Participants that are responsible for such costs. Such allocations shall be determined in accordance with Market Rules that are consistent with this Agreement and any applicable regulatory requirements and approved by the Regional Market Operations Committee prior to the activation of the Participants Committee or the Participants Committee thereafter. SECTION 14A PARTICIPANT MARKET TRANSACTIONS ON AND AFTER THE CMS/MSS EFFECTIVE DATE This Section 14A shall become effective, and shall supersede Section 14 in its entirety, for service under this Agreement on and after the CMS/MSS Effective Date. Certain provisions of this Section 14A are subject to further modification to comply with requirements of the Commission's June 28, 2000 order in Docket Nos. EL00-62-000, et al. and further Commission orders with respect thereto. This Section 14A shall have no effect for service or charges under this Agreement prior to the CMS/MSS Effective Date unless specific provisions are made applicable earlier pursuant to the Market Rules. This Section 14A specifies the rights and obligations of Participants under the Agreement with respect to the supply of, and payment for, Energy, Operating Reserve, 4-Hour Reserve and AGC. 14A.1 Supply Obligations and Settlement Obligations for Energy, Operating Reserve, 4-Hour Reserve and Automatic Generation Control. (a) Supply Obligation. Each Participant with a Resource or an Entitlement in a Resource that is scheduled in the Day- Ahead Market by the System Operator, in accordance with an applicable Supply Offer, Self-Schedule or designation for Self-Supply, to provide Energy at a Node or External Node, Operating Reserve, 4-Hour Reserve and/or AGC shall have a Day- Ahead Market Supply Obligation for the service scheduled in the amount so scheduled. The Day-Ahead Market Supply Obligation shall be satisfied by the Participant for each hour in one of the following two ways: (i) the Participant shall furnish or cause to be furnished in Real-Time such service under this Section 14A each hour pursuant to the schedule; or (ii) the Participant shall pay at the applicable Real-Time Nodal Price or Clearing Price for such amounts which it has not furnished or caused to be furnished in accordance with clause (i). Each Participant with a Resource or an Entitlement in a Resource that is scheduled in the Day-Ahead Market or that submits a Supply Offer, or that is scheduled pursuant to a Self-Schedule or designated pursuant to a Self- Supply in the Real-Time Market, for Energy at a Node or External Node, Operating Reserve or AGC, shall have a Real- Time Market Supply Obligation for each hour for which it is so scheduled or designated. Its Real-Time Market Supply Obligation for Energy shall be equal to the amounts of Energy at a Node or External Node it provides in the Real-Time Market in response to dispatch instructions by the System Operator (including dispatch instructions pursuant to a Self-Schedule or Self-Supply). Its Real-Time Market Supply Obligations for each category of Operating Reserve and/or AGC shall be equal to the amount of such service it is designated by the System Operator to provide in the Real-Time Market (including service designated by the Participant for Self-Supply and accepted by the System Operator). (b) Energy Settlement Obligation. Each Participant shall have for each hour a Day-Ahead Market Settlement Obligation for Energy at each Location equal to the megawatthours, if any, of its Demand Bid accepted by the System Operator in the Day-Ahead Market for Energy at that Location, adjusted up or down, as appropriate, to reflect Bilateral Transactions entered into by the Participant that transfer for the hour all or part of a Day-Ahead Market Settlement Obligation for Energy at that Location to or from another Participant. Each Participant also shall have for each hour a Real-Time Market Settlement Obligation for Energy at each Location equal to the megawatthours, if any, of its Electrical Load at that Location for the hour, adjusted up or down, as appropriate, to reflect Bilateral Transactions entered into by the Participant that transfer for the hour all or part of a Real-Time Market Settlement Obligation for Energy at that Location to or from another Participant. A Settlement Obligation for Energy shall require the Participant to pay, or entitle the Participant to be paid, in accordance with the provisions of Section 14A.8(a) and applicable Market Rules. (c) Operating Reserve Settlement Obligation. Settlement Obligations for each category of Operating Reserve for each hour are established by allocating the total Megawatts of that category designated for the hour in Real-Time by the System Operator to Participants under the Agreement and to Non- Participants under the Tariff. Each Participant shall have for each hour a Settlement Obligation for each category of Operating Reserve that, subject to adjustment pursuant to Section 14A.11, shall be the number of Megawatts determined in accordance with the following formula: ORp = SAp + [(OR-SA) (ELp/EL)] + ADJor, wherein ORp is the Megawatts of the Participant's Settlement Obligation for that category of Operating Reserve for the hour. SAp is the number of Megawatts, if any, of that category of Operating Reserve for the hour that is determined pursuant to applicable Market Rules as properly being assigned specifically to such Participant and not shared by all Participants. OR is the aggregate number of Megawatts of that category of Operating Reserve designated by the System Operator in the Real-Time Market in accordance with applicable NEPOOL System Rules to be required for the NEPOOL Control Area for the hour. SA is the aggregate number of Megawatts of that category of Operating Reserve for the hour that is determined pursuant to applicable Market Rules as properly not being shared by all Participants, including Operating Reserve assigned to Non-Participants. ELp is the Participant's Electrical Load for the hour. EL is the sum of ELp for all Participants. ADJor is the adjustment required to reflect the amount of that category of Operating Reserve that the Participant has Self-Supplied and all Bilateral Transactions entered into by the Participant that transfer for the hour all or part of a Settlement Obligation for that category of Operating Reserve to or from another Participant but have not been reflected in the Participant's Electrical Load for the hour. A Settlement Obligation for Operating Reserve shall require the Participant to pay in accordance with the provisions of Section 14A.8(b) and applicable Market Rules. (d) 4-Hour Reserve Settlement Obligation. Each Participant shall have for each hour a Settlement Obligation for 4-Hour Reserve to the extent provided for in Section 14A.8(d), adjusted up or down as appropriate to reflect all Bilateral Transactions entered into by the Participant that transfer all or a part of the Settlement Obligation for 4-Hour Reserve to or from another Participant. A Settlement Obligation for 4- Hour Reserve shall require the Participant to pay in accordance with Section 14A.8(d) and applicable Market Rules. (e) AGC Settlement Obligation. Settlement Obligations for AGC for each hour are established by allocating the total AGC designated for the hour in the Real-Time Market by the System Operator to Participants under the Agreement and Non-Participants under the Tariff. Each Participant shall have for each hour a Settlement Obligation for AGC that, subject to adjustment pursuant to Section 14A.11, shall be determined in accordance with the following formula: AGCp = AGC (ELp/EL) + ADJAGC, wherein AGCp is the Participant's share of AGC for the hour. AGC is the total amount of AGC determined by the System Operator in accordance with applicable NEPOOL System Rules to be required for the NEPOOL Control Area for the hour that is not assigned to Non-Participants. ELp and EL are as defined in Section 14A.1(c). ADJAGC is the adjustment required to reflect all Bilateral Transactions entered into by the Participant to transfer all or part of a Settlement Obligation for AGC to or from another Participant but that have not been reflected in the Participant's Electrical Load for the hour and the amount, if any, that the Participant has, in accordance with applicable Market Rules, Self-Supplied. A Settlement Obligation for AGC shall require the Participant to pay in accordance with Section 14A.8(c) and applicable Market Rules. 14A.2 Right to Receive Service. Except as emergency circumstances may result in the System Operator requiring load curtailments by Participants, and subject to the availability of transmission capacity, each Participant shall be entitled to receive from other Participants (or from the service made available from Non-Participants pursuant to arrangements entered into under Section 14A.11) such amounts, if any, of Energy, Operating Reserve, 4-Hour Reserve and AGC as it requires. If, for any hour, load curtailments or other emergency measures are required, the amount of services that Participants are entitled to receive shall be reduced by the System Operator in a fair and non-discriminatory manner in light of the circumstances and applicable NEPOOL System Rules. 14A.3 Participation in the Day-Ahead Market. (a) Demand Bids and Supply Offers for the Day-Ahead Market shall be submitted by Participants for each hour of the Dispatch Day, in accordance with this Agreement and applicable Market Rules. Such Demand Bids and Supply Offers shall include the information required by the Market Rules. (b) Any Participant with authority to submit a Supply Offer in accordance with Section 14A.4 for a Resource that is eligible to supply Energy at a Node or External Node, Operating Reserve, 4-Hour Reserve or AGC, or for load that is capable of reducing its consumption within four hours to supply 4-Hour Reserve, may submit in the Day-Ahead Market to, or have on file with, the System Operator, a Supply Offer for each such Resource or load reduction, to the extent permitted by and in accordance with Section 14A.4 and applicable Market Rules; provided that as one alternative to submitting Supply Offers for Operating Reserve and/or 4- Hour Reserve, a Participant desiring to provide such services may enter into a Reserve Contract with the System Operator pursuant to Section 14A.10(c) covering such services. (c) Any Participant wishing to purchase Energy in the Day- Ahead Market may submit to, or have on file with, the System Operator in accordance with applicable Market Rules a Day- Ahead Demand Bid or Bids specifying Demand Bid Prices for such Energy in each hour of the Dispatch Day at any Location, including the Hub. (d) Any Participant wishing to sell Energy into the Day-Ahead Market from a Control Area outside the NEPOOL Control Area may do so by submitting a Supply Offer for Energy in the Day-Ahead Market at an External Node. Participants wishing to purchase Energy in the Day-Ahead Market for sale outside of the NEPOOL Control Area may do so by submitting a Demand Bid in the Day- Ahead Market at an External Node. (e) Any Participant seeking to Self-Schedule a Resource in the Day-Ahead Market or to affect its Day-Ahead Settlement Obligation through a Bilateral Transaction, a Self-Supply of Operating Reserve, or a Self-Supply of AGC to the extent permitted by applicable Market Rules, shall submit or cause to be submitted all necessary information with respect thereto to the System Operator in accordance with Section 14A.4(i) or Section 14A.11 and applicable Market Rules. (f) In accordance with Market Rules, any Participant seeking to effect a transaction that moves Energy through or out of the NEPOOL Control Area by combining a Demand Bid at an External Node with a Supply Offer at any other Node may elect to specify the maximum Congestion Cost it is willing to pay to have its transaction scheduled or, once scheduled, to keep that transaction from being wholly or partially curtailed. 14A.4 Nature of Demand Bids and Supply Offers; Limitations; Self-Schedules and Self-Supplies. (a) Carry Over Procedures: If a Supply Offer or Demand Bid is not submitted for a Resource in the Day-Ahead Market, the Supply Offer or Demand Bid shall be deemed to be the last valid Supply Offer or Demand Bid on file with the System Operator, except for Supply Offers and Demand Bids at External Nodes, which shall be deemed to be unavailable. If a Supply Offer or Demand Bid for Dispatchable Load is not submitted for a Resource in the Real-Time Market, the Supply Offer or Demand Bid shall be deemed to be the Supply Offer or Demand Bid submitted in the Day-Ahead Market, except for Supply Offers and Demand Bids at External Nodes which shall not carry over and must be submitted in accordance with applicable Market Rules. For a generating unit in which there are multiple Entitlement holders, only one Participant shall be permitted to submit Supply Offers for such unit. The Entitlement holders in each unit with multiple Entitlement holders shall designate a single Participant that will be permitted to submit Supply Offers and/or to direct the scheduling of the unit. In the event that more than one Participant is designated, or if the Entitlement holders do not designate a single Participant, then the Supply Offer Price for Energy for the unit shall be based on the replacement cost of fuel. Such Supply Offer Price, operational parameters and other information required under the Market Rules to be furnished to the System Operator shall be furnished to the System Operator by the Participant validly furnishing replacement cost of fuel as of December 31, 1996. Nothing in this Agreement shall affect the rights of any Entitlement holder under the contractual arrangements among such Entitlement holders relating to a generating unit. (b) Each Supply Offer for Energy shall specify the Node or External Node where the Energy will be provided. Each Demand Bid shall specify the Location where theEnergy will be received. Supply Offers and Demand Bids at External Nodes shall be adjusted as appropriate by the System Operator to account for transmission losses on Non-PTF, if any, between the PTF and the transmission facilities of the neighboring Control Area. Metered values for Electrical Load on the Non-PTF shall be adjusted as appropriate by the System Operator to account for transmission losses on the Non-PTF, if any, between the PTF and the transmission facilities of the neighboring Control Area. The System Operator shall post on its Internet website loss factors for each External Node. (c) Each Supply Offer for Energy from a generating unit or Supply Offer at an External Node in the Day-Ahead Market shall contain the information required by applicable Market Rules and shall, at a minimum, specify the offered incremental Energy prices, and may include a Start-Up Price and No-Load Price, if any, and operational parameters. Each Supply Offer for Energy from Resources in the Real-Time Market shall specify, in addition to the Node or External Nodes, only incremental Energy prices. Each Supply Offer Price for incremental Energy from a segment of a Resource shall be equal to or greater than the Supply Offer Price for any lesser quantity of Energy. Each Demand Bid shall contain the information required by the applicable Market Rules and shall at a minimum state the bid decremental prices of Energy. Each Demand Bid Price for a block of Energy shall be equal to or less than the Price for any lesser quantity of Energy. (d) Supply Offers may be submitted in the Day-Ahead Market for 10-Minute Spinning Reserve, 10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve, 4-Hour Reserve, and AGC. Each Supply Offer shall specify a separate Supply Offer Price for the service offered. (e) Supply Offers for 10-Minute Spinning Reserve, 10-Minute Non-Spinning Reserve, and/or 30-Minute Operating Reserve may be submitted in the Real-Time Market only for fast start resources, as defined in the Market Rules. Each Supply Offer shall specify a separate Supply Offer Price for the service offered. Supply Offers for AGC also may be submitted in the Real-Time Market from a generating unit and shall specify the Supply Offer Price for such service. (f) To the extent a Resource qualifies to provide Operating Reserve or 4-Hour Reserve and is not self-scheduled or has not submitted a Supply Offer to provide such service(s), a Supply Offer to provide Energy from a Resource in any hour in the Day-Ahead Market may also be considered in accordance with the Market Rules to be a Supply Offer to provide Operating Reserve or 4-Hour Reserve at the Resource's Lost Opportunity Cost for such hour based on its Day-Ahead Supply Offer Price for Energy. The Supply Offer Price for a category of Operating Reserve or 4-Hour Reserve from a Resource in an hour shall be the greater for such hour of the submitted Supply Offer Price for such service or the Lost Opportunity Cost. Each Supply Offer to provide Energy from a Resource other than a Dispatchable Load in any hour in the Real-Time Market is also a Supply Offer to provide Operating Reserve at the Resource's Lost Opportunity Cost for such hour based on its Real-Time Energy Supply Offer Price if and to the extent such Resource qualifies to provide Operating Reserve under the applicable Market Rules. For Resources submitting Supply Offers for Operating Reserve in the Real-Time Market pursuant to Section 14A.4(e) or as otherwise permitted under the Agreement or the Market Rules, the Supply Offer Price for service from the Resource in each hour shall be the greater of the submitted Supply Offer Price or the Lost Opportunity Cost for such hour. (g) Each Real-Time Supply Offer Price for Energy from the portion of a Resource scheduled to provide Operating Reserve, 4-Hour Reserve or AGC in the Day-Ahead Market shall be less than or equal to the Day-Ahead Supply Offer Price for Energy for such portion. Each Real-Time Supply Offer Price for AGC from the portion of a generating unit eligible to provide AGC and scheduled to provide Energy, Operating Reserve, AGC or 4- Hour Reserve in the Day-Ahead Market shall be less than or equal to the Day-Ahead Supply Offer Price for AGC from such generating unit. Each Real-Time Supply Offer Price for any category of Operating Reserve for the portion of a Resource scheduled to provide Operating Reserve Day-Ahead and eligible to submit a Supply Offer Price for that portion of the Resource for that category of Operating Reserve in the Real-Time Market shall be less than or equal to the Day- Ahead Supply Offer Price for such category of Operating Reserve from such portion of that Resource. (h) If there are multiple Supply Offers for Energy submitted by Participants in the Day-Ahead or Real-Time Market specifying the same effective Supply Offer Price (as adjusted for Marginal Losses), and no lower Supply Offer Prices (as adjusted for Marginal Losses) are available in the applicable Market to meet the next decrement of load at that Node or External Node, then ties will be broken in accordance with or scheduled amounts pro rated in accordance with the Market Rules. (i) Each Participant with authority to submit Supply Offers for a Resource may submit a Self-Schedule for Energy from its Resources in either the Day-Ahead or Real-Time-Market in accordance with applicable Market Rules. The Self-Schedule defines the Participant's plan to provide Energy from a given generating unit or to consume Energy for a Dispatchable Load (e.g., a pumped storage facility in the pumping mode), or to import or export Energy at an External Node. The Self- Scheduled Energy from a generating unit or consumed by a Dispatchable Load must satisfy the operating parameters included in the applicable Supply Offer or Demand Bid. For a Self-Schedule of a Resource other than a Dispatchable Load to be accepted, the Participant submitting that Self-Schedule must also submit at least one or more Supply Offer Prices, each equal to or less than zero, for the Energy associated with the entire Self-Scheduled portion of that Resource. 14A.5 Scheduling Procedures in the Day-Ahead Market. (a) The System Operator shall perform for each Dispatch Day in accordance with the NEPOOL System Rules a security constrained unit commitment schedule using a computer algorithm which simultaneously minimizes the total cost for: (i) supplying Energy to satisfy accepted Demand Bids in the Day-Ahead Market; (ii) providing the quantity of Operating Reserves and AGC required by NEPOOL System Rules; and (iii) providing any necessary 4-Hour Reserves in accordance with Section 14A.5(f) and applicable NEPOOL System Rules. The schedule shall take into account all Self-Schedules and Self- Supplies submitted by Participants for the Day-Ahead Market. In accordance with the NEPOOL System Rules, the schedule shall also take into account, among other things, phase shifters and other power flow control devices, transmission system limitations, including but not limited to internal system limitations and external interface limits, and contingencies reasonably identified pursuant to criteria posted on the System Operator's Internet website that may constrain outputs or require additional supply in specific locations. (b) The amount of each category of Operating Reserve scheduled in the Day-Ahead Market by the System Operator shall be in accordance with the NEPOOL System Rules, shall take into account the grid and generator configuration for the Dispatch Day, and may be price sensitive in whole or in part such that the required amount of Operating Reserve decreases as the price for Operating Reserve increases. Any NEPOOL System Rule in effect before the CMS/MSS Effective Date designed to maintain reliability while producing just and reasonable charges and payments for Operating Reserves during times of emergency or shortages of available Energy and/or Operating Reserves shall remain in effect on and after the CMS/MSS Effective Date unless and until subsequently amended, and may be in addition to or in lieu of the establishment of price sensitive Operating Reserve requirements. (c) The simultaneous optimization process used to determine schedules in the Day- Ahead Market shall ensure that all portions of Resources with Supply Offers not scheduled to provide Energy shall cascade to the markets for AGC, Operating Reserves and 4-Hour Reserves to the extent such Resources are eligible to provide those services and consistent with the Supply Offer Prices established in accordance with Section 14A.4. This process shall also ensure that all portions of Resources with Supply Offers not scheduled to provide Energy may be considered for meeting the requirements to provide AGC, Operating Reserves and 4-Hour Reserves. (d) In the scheduling of Resources for Operating Reserves, 4- Hour Reserves and AGC in the Day-Ahead Market, the simultaneous optimization process shall use the following principles: Resources that are Self-Scheduled pursuant to applicable Market Rules to provide Energy shall be reflected in the schedule in accordance with the Self-Schedule except as provided below; Resources that are designated for Self-Supply in accordance with applicable Market Rules shall be reflected in the schedules to the extent they are so designated except as provided below; Resources, to the extent not scheduled or Self-Scheduled for Energy or designated for Self-Supply and eligible to provide Operating Reserve, shall be scheduled by the System Operator based on the higher of their Lost Opportunity Costs, if any, or their applicable Day-Ahead Supply Offer Prices; and Resources, to the extent not scheduled or Self-Scheduled for Energy or designated for Self- Supply and eligible to provide AGC, shall be scheduled based on their Lost Opportunity Costs, if any, plus their Day-Ahead Supply Offer Prices for AGC. The System Operator may direct changes to any Self-Schedule and/or Self-Supply if, but only to the extent, necessary for reliability. (e) At the conclusion of the scheduling process set forth in Section 14A.5(a), the System Operator shall publish each day in accordance with the Market Rules and in a way that is consistent with the NEPOOL Information Policy the information required by Section 14A.18. The System Operator's schedule for the Day-Ahead Market shall identify to each Entitlement holder, the expected start and shut down times for all of its Resources or Entitlements that are scheduled in the Day-Ahead Market. (f) If the System Operator's Day-Ahead forecast of the NEPOOL load exceeds the aggregate of the Participants' Demand Bids accepted in the Day-Ahead Market for any hour of the Dispatch Day, the System Operator may schedule, in accordance with the applicable NEPOOL System Rules, 4-Hour Reserves to be available to cover part or all of the difference. 14A.6 Participation in the Real-Time Market. (a) Supply Offers and Demand Bids for the Real-Time Market shall be submitted by Participants for each hour of the Dispatch Day of the Real-Time Market, to the extent permitted by and in accordance with Section 14A.4 and applicable Market Rules. Such Supply Offers and Demand Bids shall include the information required by the Market Rules. (b) Each Participant with authority to submit a Supply Offer in accordance with Section 14A.4 for a Resource that is eligible to supply Energy, Operating Reserve, or AGC, may submit in the Real-Time Market to, or have on file with, the System Operator, or modify, a Supply Offer for each such Resource, to the extent permitted by and in accordance with applicable Market Rules and subject to the limitations of Section 14A.4(g). New or modified Supply Offers may, among other matters, (i) offer Energy at a Node or External Node, Operating Reserves and AGC from a generating unit not scheduled in the Day-Ahead Market which can be dispatched by the System Operator in the Real-Time Market, (ii) increase or decrease the Supply Offer Price for Energy from a Resource scheduled in the Day-Ahead Market, (iii) reduce the Supply Offer Price for Energy from a generating unit scheduled to provide AGC, Operating Reserves, or 4-Hour Reserves in the Day- Ahead Market, and (iv) propose new Supply Offers and/or Demand Bids at External Nodes. (c) Each Participant seeking to Self-Schedule its Resource in the Real-Time Market or to affect its Real-Time Settlement Obligation through a Bilateral Transaction, a Self-Supply of Operating Reserve, or a Self-Supply of AGC to the extent permitted by applicable Market Rules, shall submit or cause to be submitted all necessary information with respect thereto to the System Operator in accordance with Section 14A.4(i) or Section 14A.11 and applicable Market Rules. 14A.7 Scheduling Procedures in the Real-Time Market. (a) A Participant at its own cost may bring on line a generating unit not scheduled to operate in the Day-Ahead Market, after giving such notice as is required by the Market Rules, and receiving the System Operator's approval, so that the generating unit can be dispatched by the System Operator based on the Participant's Real-Time Energy Supply Offer. The Participant electing to bring its generating unit on line in accordance with this Section 14A.7 shall not be entitled to any uplift under Section 14A.19 with respect to its costs in this instance, although such Participant may qualify for uplift under other provisions of this Agreement or applicable Market Rules. (b) The System Operator shall centrally dispatch all available Resources, including Self-Scheduled Resources, in Real-Time in accordance with NEPOOL System Rules, based on the schedule in the Day-Ahead Market, increases or decreases in load, the occurrence of contingencies, and the submission of new or modified Real-Time Demand Bids or Supply Offers, new or modified Self-Schedules and new or modified Self-Supply designations made in accordance with applicable Market Rules. This dispatch shall also include adjustments to the Day-Ahead Market schedule to reflect the activation of resources scheduled for 4-Hour Reserve if necessary to maintain system reliability. (c) The amount of each category of Operating Reserve designated in the Real-Time Market by the System Operator shall be in accordance with the NEPOOL System Rules, shall take into account the grid and generator configuration for the Dispatch Day, and may be price sensitive in whole or in part such that the required amount of Operating Reserve decreases as the price for Operating Reserve increases. Any NEPOOL System Rule in effect before the CMS/MSS Effective Date designed to maintain reliability while producing just and reasonable charges and payments for Operating Reserves during times of emergency or shortages of available Energy and/or Operating Reserves shall remain in effect on and after the CMS/MSS Effective Date unless and until subsequently amended, and may be in addition to or in lieu of the establishment of price sensitive Operating Reserve requirements. (d) A simultaneous optimization process shall be used to determine the Energy, AGC and Operating Reserve to be provided by each Resource in the Real-Time Market. This process shall ensure that all portions of Resources with Supply Offers not scheduled to provide Energy shall cascade to the markets for AGC and Operating Reserves to the extent such Resources are eligible to provide those services and consistent with Supply Offer Prices established in accordance with Section 14A.4. This process shall also ensure that all portions of Resources with Supply Offers not dispatched to provide Energy may be considered for meeting the requirements to provide AGC and Operating Reserves. (e) In selecting Resources to provide Operating Reserves and AGC in Real-Time, the simultaneous optimization process shall use the following principles: Resources that are Self- Scheduled to provide Energy in accordance with applicable Market Rules shall be reflected in the dispatch to the extent they so perform, except as provided below; Resources that are permitted by Market Rules to be designated for Self-Supply and are so designated shall be reflected in the dispatch to the extent they are so designated and perform or remain available, except as provided below; Resources, to the extent not scheduled or Self-Scheduled for Energy or designated for Self- Supply and eligible to provide 10-Minute Spinning Reserve in the Real-Time Market, shall be designated by the System Operator based on their Lost Opportunity Costs, if any. Resources, to the extent not scheduled or Self-Scheduled for Energy or designated for Self-Supply and eligible to provide 10-Minute Non-Spinning Reserves or 30 Minute Operating Reserves shall be designated based on the higher of their Lost Opportunity Costs, if any, or their applicable Supply Offer Prices. Generating units, to the extent they are not scheduled or Self-Scheduled for Energy or designated for Self- Supply and eligible to provide AGC, shall be designated based on their Lost Opportunity Costs, if any, plus their Real-Time Supply Offer Prices for AGC. The System Operator may direct changes to any Self-Schedule and/or Self-Supply if, but only to the extent, necessary for reliability. (f) Supply Offers and Demand Bids at External Nodes will be dispatched in the Real-Time Market based on the Real-Time Supply Offer Price and Demand Bid Price, respectively, for the hour. If the net aggregate amount of service pursuant to eligible Supply Offers or Demand Bids at an External Node would exceed the applicable interface limit, then Supply Offers with the lowest price or the Demand Bids with the highest price shall be scheduled. If such competing Supply Offers and/or Demand Bids have the same prices, ties will be broken or transactions pro rated in accordance with the Market Rules. 14A.8 Settlement Obligation Payments for Energy, Operating Reserves, 4-Hour Reserves and Automatic Generation Control. (a) For each hour in which a Participant has a Settlement Obligation for Energy at a Location in the Day-Ahead Market pursuant to Section 14A.1(b), the Participant shall pay or receive for the megawatthours of the Settlement Obligation at that Location at the applicable Day-Ahead Market Locational Price for that hour, as determined in accordance with Section 14A.12. For each hour in which a Participant has a Settlement Obligation for Energy at a Location in the Real-Time Market pursuant to Section 14A.1(b), the Participant either (i) shall pay the applicable hourly Real-Time Market Locational Price for the number of megawatthours, if any, by which the Participant's Settlement Obligation for Energy received at that Location in the Real-Time Market is more than the Participant's Settlement Obligation for Energy received at that Location in the Day-Ahead Market, or (ii) shall receive the applicable hourly Real-Time Market Locational Price for the number of megawatthours, if any, by which the Participant's Settlement Obligation for Energy received at that Location in the Real-Time Market is less than the Participant's Settlement Obligation for Energy received at that Location in the Day-Ahead Market, as determined in accordance with Section 14A.12. The Participant shall also pay any applicable uplift charges under Section 14A.19. A Participant shall pay the Zonal Price for Energy received in a Load Zone unless it elects, in accordance with applicable Market Rules, to pay the Nodal Price for such Energy. (b) For each hour in which a Participant has a Settlement Obligation for Operating Reserve pursuant to Section 14A.1(c), the Participant shall pay for Operating Reserve in each category in which it has an obligation a percentage share of the aggregate payments to Participants pursuant to Section 14A.9 for satisfying their Supply Obligations for each such category of Operating Reserve for the hour equal to the Participant's percentage share of the total Settlement Obligations for Operating Reserve of such category for the hour, as determined pursuant to Section 14A.1(c). In addition, the Participant shall pay any applicable uplift charge assessed under Section 14A.19. (c) For each hour in which a Participant has a Settlement Obligation for AGC pursuant to Section 14A.1(e), the Participant shall pay a percentage of the aggregate payments to Participants pursuant to Section 14A.9 for satisfying their Supply Obligations for AGC for the hour equal to the Participant's percentage share of the total Settlement Obligation for AGC for the hour as determined pursuant to Section 14A.1(e). (d) For any hour in which the System Operator schedules 4- Hour Reserves in the Day-Ahead Market, the aggregate payment to Participants pursuant to Section 14A.9 for satisfying their Supply Obligations for 4-Hour Reserves for the hour shall be allocated to Participants and paid by them as follows: Step 1. The hourly per Megawatt cost for 4-Hour Reserve for the hour shall be determined by dividing the total 4-Hour Reserve payments pursuant to Section 14A.9 for the hour by the number of Megawatts of 4-Hour Reserve scheduled in the Day- Ahead Market to be available in the hour. Step 2. If a Participant's Net Hourly Load Obligation for Energy for the hour is positive and exceeds the Participant's accepted Demand Bids for the hour in the Day-Ahead Market, it shall pay for each Megawatt of such excess the per Megawatt cost determined in accordance with Step 1 above, but not more than its pro rata share of the 4-Hour Reserve cost for the hour. Step 3. If the allocation in Step 2 above is insufficient to recover the full 4-Hour Reserve cost for the hour, the remaining cost shall be allocated to all Participants for the hour, including those required to make payments in accordance with Step 2, in proportion to their shares of the aggregate Net Hourly Load Obligation for Energy for the hour. The provisions of Step 2 and Step 3 above are subject to future modifications to comply with the Commission's June 28, 2000 order in Docket Nos. EL00-62-000, et al., and future orders pertaining thereto, with respect to the allocation of uplift costs and in light of filings concerning the use of Net Hourly Load Obligation for Energy as an allocation factor, and Steps 2 and 3 do not become effective except pursuant to a future Commission order. 14A.9 Supply Obligation Payments For Energy, Operating Reserves, 4-Hour Reserves and Automatic Generation Control. (a) Subject to the provisions of Section 14A.16, each Participant with a Supply Obligation for Energy in an hour in the Day-Ahead Market at any Node or External Node shall receive for each megawatthour scheduled at the Node or External Node in the Day-Ahead Market the Day-Ahead Nodal Price for the hour at that Node or External Node, as determined in accordance with Section 14A.12. Subject to the provisions of Section 14A.16, a Participant with a Supply Obligation for Energy at any Node or External Node in an hour in the Real-Time Market that is more than the Participant's Supply Obligation for Energy at that Node or External Node for the hour in the Day-Ahead Market, shall receive for each additional megawatthour of such excess the Real-Time Market Nodal Price for the hour at that Node or External Node, as determined in accordance with Section 14A.12. Subject to the provisions of Section 14A.16, each Participant with a Supply Obligation for Energy at any Node or External Node in an hour in the Real-Time Market that is less than the Participant's Supply Obligation for Energy at that Node or External Node for the hour in the Day-Ahead Market shall pay for each megawatthour of such deficiency the Real-Time Market Nodal Price for the hour at that Node or External Node, as determined in accordance with Section 14A.12. In addition, Participants may receive or be required to pay applicable uplift charges, if any, pursuant to Section 14A.19 or the Market Rules and to pay for 4-Hour Reserves pursuant to Section 14A.8(d). (b) Each Participant with a Supply Obligation for Operating Reserve or 4-Hour Reserve in an hour in the Day-Ahead Market shall receive for each Megawatt of each category of Operating Reserve and/or 4-Hour Reserve scheduled the applicable Day- Ahead Market Operating Reserve Clearing Price or 4-Hour Reserve Clearing Price, as appropriate, as determined in accordance with Section 14A.13. For any hour in which the Participant's Supply Obligation for Operating Reserve of any category in the Real-Time Market exceeds the Participant's Supply Obligation for such service for the hour in the Day- Ahead Market, the Participant shall receive for the additional Megawatts the applicable Real-Time Market Operating Reserve Clearing Price for the hour, as determined in accordance with Section 14A.13. For any hour in which the Participant's Supply Obligation for Operating Reserve of any category in the Real-Time Market is less than the Participant's Supply Obligation for such service for the hour in the Day-Ahead Market, the Participant shall pay for each Megawatt of such deficiency the applicable Real-Time Market Operating Reserve Clearing Price for the hour, as determined in accordance with Section 14A.13. If a Participant has a Supply Obligation for 4-Hour Reserve in any hour in the Day-Ahead Market and fails to provide all or a portion of the Energy from its 4-Hour Reserve in response to the System Operator's dispatch instructions, the Participant shall pay the Real-Time Market 30-Minute Operating Reserve Clearing Price for each Megawatt not provided, in addition to any payments required under Section 14A.8(d). (c) Each Participant with a Supply Obligation for AGC in an hour in the Day-Ahead Market shall receive for the scheduled amount the Day-Ahead Market AGC Clearing Price for the hour, as determined in accordance with Section 14A.14. For any hour in which the Participant's Supply Obligation for AGC in the Real-Time Market exceeds the Participant's Supply Obligation for AGC for the hour in the Day-Ahead Market, the Participant shall receive for such excess the Real-Time Market AGC Clearing Price for the hour, as determined in accordance with Section 14A.14. For any hour in which the Participant's Supply Obligation for AGC in the Real-Time Market is less than the Participant's Supply Obligation for AGC for the hour in the Day-Ahead Market, the Participant shall pay for such deficiency the Real-Time Market AGC Clearing Price for the hour, as determined in accordance with Section 14A.14. (d) In no event shall Participants be paid lost opportunity costs resulting from a generating unit being dispatched down or off to accommodate transmission constraints, and nothing in this Agreement or the Market Rules shall provide for any such payment. 14A.10 Contract and Scheduling Authority. (a) The Participants Committee is authorized to enter into contracts on behalf of and in the names of all Participants with Non-Participants to purchase or furnish emergency Energy that is available for the System Operator to schedule in order to ensure reliability in the NEPOOL Control Area or neighboring Control Areas. For sales to another Control Area, the terms of any such contractual arrangement shall not require the furnishing of such emergency service until the service needs of all Participants have been provided for with the least expensive resources practicable. Emergency purchases pursuant to this Section 14A.10 should not be required unless the Participants have been unable to furnish such Supply Offers as the System Operator determines are required to ensure reliability. For emergency purchases and sales pursuant to this Section 14A.10, the treatment of the transaction with the Non-Participant in the determination of a Locational Price shall be in accordance with applicable Market Rules. Energy (and related services) from any such emergency purchases shall be deemed to be furnished to and shall be paid for by Participants with Settlement Obligations in the Real- Time Market, in accordance with this Section 14A.10(a) and applicable Market Rules. (b) The NEU Management Committee (as defined in the HQ Use Agreement) is authorized to provide for the day-to-day scheduling through the System Operator of the HQ Phase II Firm Energy Contract, in accordance with the HQ Use Agreement, as if the Contract were a contract covering Energy transactions with a Non-Participant entered into pursuant to Section 14A.10(a). Energy received in an hour from Hydro-Quebec pursuant to the HQ Energy Banking Agreement, and Energy purchased in any hour from Hydro-Quebec pursuant to the HQ Phase II Firm Energy Contract any other HQ Contract shall be deemed to be Energy furnished at the appropriate External Node to each Participant which has submitted a Supply Offer at the appropriate External Node for such Energy for the hour in the amount reflected for the Participant in the System Operator's scheduling of Energy deliveries in the hour from Hydro-Quebec; except that emergency Energy received from Hydro-Quebec under the HQ Interconnection Agreement shall be deemed to be Energy provided to (and shall be paid for by) Participants requiring such emergency Energy in the hour. The System Operator shall schedule such Energy deliveries to accommodate, to the extent possible, the schedule of Energy deliveries from Hydro-Quebec requested by the Participants within their Supply Offers. The Participants deemed to have received such Energy shall have a corresponding Supply Obligation and shall satisfy this and all other Supply Obligations at this External Node and all other Nodes in accordance with Section 14A.1, 14A.8 and 14A.9. The Participants are responsible for paying to Hydro-Quebec the price for Energy deliveries under the HQ Phase II Firm Energy Contract and under the HQ Energy Banking Agreement. (c) The System Operator is authorized in accordance with applicable Market Rules to enter into Reserve Contracts with individual Participants under which the System Operator pays for and receives options or rights to all or a portion of 10- Minute Non-Spinning Reserve, 30-Minute Operating Reserve and/or 4-Hour Reserve from generating units or Dispatchable Loads for forward periods, such as a week or a month, as determined by the System Operator. Such Reserve Contracts shall be in accordance with applicable Market Rules and shall be entered into with Participants which offer the service in response to a request for proposals, shall include the Reserve Price at which the Operating Reserve or 4-Hour Reserve will be made available and the price at which Energy will be furnished on the activation of the Operating Reserve or 4-Hour Reserve, and shall contain standard terms and conditions specified by the System Operator in accordance with the Market Rules. 14A.11 Bilateral Transactions and Participant Transactions with Non-Participants. (a) Two Participants may undertake to transfer all or select portions of the Settlement Obligations of one of them under this Agreement to the other Participant with respect to any of the NEPOOL Markets pursuant to a Bilateral Transaction. Such transfer of Settlement Obligations under this Agreement shall be as agreed to between the two parties to the Bilateral Transaction and shall be submitted to the System Operator in accordance with the Market Rules. Each Bilateral Transaction submitted shall specify whether the transaction is to settle in the Day-Ahead Market or the Real-Time Market and, if it is for Energy, a Location. (b) In the event a Participant has the right to receive Energy, Operating Reserve, 4-Hour Reserve and/or AGC from a Non-Participant under a System Contract, such Contract may be submitted to the System Operator in a Supply Offer as a proposal to furnish Energy, Operating Reserve, 4-Hour Reserve, and/or AGC, to the extent the System Contract permits central dispatch by the System Operator in accordance with the Market Rules and otherwise qualifies for such service. 14A.12 Determination of Locational Prices. The System Operator shall calculate Locational Prices for the Day-Ahead and Real-Time Markets as described below. (a) Nodal Prices. The System Operator shall calculate the Nodal Price at each Node for each hour of the Dispatch Day for the Day-Ahead Market using the Day-Ahead unit commitment model, and for the Real-Time Market using the Real-Time scheduling software. In calculating Nodal Prices the System Operator shall use the Demand Bids and Supply Offers submitted pursuant to Sections 14A.3, 14A.4 and 14A.6. The Real-Time Nodal Price at each Node for each hour shall be the time interval weighted-average of the Clearing Prices calculated at that Node for each time interval within that hour, except as noted in subsection (d) below with respect to the prices used for Real-Time settlements at External Nodes. The System Operator shall calculate Nodal Prices for an hour for the Day-Ahead Market or the Real-Time Market at a given Node i using the following formula, or a formula similar in substance and effect: Y (i) = X r =+ Y L/i + Y c/i where: Y I= the Nodal Price at Node i in $/megawatthour; X r= the marginal cost in $/megawatthour, based on Demand Bids and Supply Offers, to serve additional load at the Reference Node; Y L/i=the Marginal Loss Component of the Nodal Price at Node i in $/megawatthour; and Y c/I=the Congestion Component of the Nodal Price at Node i in $/megawatthour. The Marginal Loss Component of the Nodal Price at any Node i on the NEPOOL Transmission System is calculated using the equation Y L/I= (WF I - 1) X r in which WFi, the Withdrawal Factor at Node i relative to the system Reference Node, is calculated using the following equation: where: L = NEPOOL Transmission System losses; Pi = the net amount of Energy injected into the NEPOOL Transmission System at Node i; and = the ratio of: (1) the amount by which NEPOOL Transmission System losses occurring in the Day-Ahead Schedule or Real-Time dispatch would have increased, as calculated by the System Operator's Day-Ahead or Real-Time computer algorithm, if a very small additional amount of Energy had been injected at Node i (in addition to the injections and withdrawals already scheduled to occur on the NEPOOL Transmission System in the Day-Ahead schedule or occurring on the NEPOOL Transmission System in the Real- Time dispatch), to (2) the size of the additional injection of Energy at Node i. The Congestion Component of the Nodal Price at Node i is calculated using the equation: where: K = the set of thermal or interface constraints; GFik = the Shift Factor for the generator at Node i on constraint k in the pre- or post- contingency case that limits flows across that constraint; and the reduction in system cost that results from an incremental relaxation of constraint k, expressed in $/megawatthour. Substituting the equations for calculating the Marginal Loss Component and the Congestion Component of the Nodal Price for the terms into the equation for calculating the Nodal Price for a given Node i yields: (b) Zonal Prices. For Congestion pricing purposes, Load Zones based on Reliability Regions have been established and Zonal Prices shall be calculated by the System Operator for each Load Zone. Each Load Zone shall be coterminous with a Reliability Region, except that a Participant which owns and operates distribution lines and other facilities used for the distribution of Energy to retail customers in a single state in New England and which is subject to regulation by the public utility regulatory authority in that state (a "Distribution Company"), which (i) serves retail customers in more than one Reliability Region in a single state and (ii) is subject to a state-imposed obligation to provide its retail customers with a power supply at fixed prices for a limited time period following the commencement of retail access ("Standard Offer Obligation"), may elect, by notice to the System Operator and the Secretary of the Participants Committee, within the time prescribed by the Market Rules, to have its entire service territory treated as a single Load Zone (a "Distribution Company Load Zone") until its Standard Offer Obligation ends. In addition, Vermont shall be a single Load Zone for those Distribution Companies in Vermont that maintain their single Participant status for settlement purposes with other Distribution Companies in Vermont pursuant to Section 4 of the Agreement even if Vermont spans more than one Reliability Region. The election by one or more Distribution Companies in Vermont not to be treated as a single Participant with other Vermont Participants shall not affect the Load Zone for the remaining Distribution Companies in Vermont maintaining the single Participant election. After consulting with the Participants, the System Operator may reconfigure Reliability Regions and add or subtract Reliability Regions as necessary over time to reflect changes to the grid, patterns of usage and intrazonal Congestion. The System Operator shall file any such changes with the Commission. The System Operator shall calculate Zonal Prices for each Reliability Region for both the Day-Ahead and Real-Time Markets for each hour using a load-weighted average of the Nodal Prices for the Nodes within that Reliability Region. The load weights used in calculating the Day- Ahead Zonal Prices for the Reliability Region shall be determined in accordance with applicable Market Rules and shall be based on the Demand Bids for the Nodes that make up that Reliability Region. The System Operator shall determine, in accordance with applicable Market Rules, the load weights used in Real-Time based on the calculated Real-Time load distribution. The System Operator shall calculate Zonal Prices for Reliability Regions using the following formula, or a formula similar in substance and effect, where the Zonal Price for a Reliability Region j can be written as: where: = Zonal Price for Reliability Region j in $/megawatthour; is as defined in Section 14A.12(a); is the Marginal Loss Component of the Zonal Price for Reliability Region j in $/megawatthour; is the Congestion Component of the Zonal Price for Reliability Region j in $/megawatthour; Nj = the set of Nodes that make up the Reliability Region j; and Wij = the load-weighting factor for Node i used to calculate the Zonal Price for Reliability Region j, determined such that the weighting factors for any given Reliability Region sum to one. For a Distribution Company Load Zone, the Zonal Price shall be determined by the weighted average of the Zonal Prices for the Reliability Regions making up the Load Zone, with the weights equal to that Distribution Company's share of the load in each of those Reliability Regions. The load weights used in calculating the Day- Ahead Zonal Prices for the Distribution Company Load Zones shall be determined in accordance with applicable Market Rules and shall be based on the Demand Bids for the Nodes that make up the Distribution Company Load Zones. The System Operator shall determine, in accordance with applicable Market Rules, the load weights used in Real- Time based on the calculated Real-Time load distribution. The System Operator shall calculate Zonal Prices for each hour of the Dispatch Day for Distribution Company Load Zones using the following formula: Zonal Price equals the Distribution Company's load in each Reliability Region making up the Distribution Company Load Zone times the Zonal Price for each such Reliability Region summed for all such Reliability Regions making up the Distribution Company Load Zone, divided by the sum of the Distribution Company's load in each Reliability Region making up the Distribution Company Load Zone. The Congestion and Marginal Loss Components of the Zonal Price for each Distribution Company Load Zone shall be calculated as the weighted average of the Congestion and Marginal Loss Components, respectively, of the Zonal Prices in the Reliability Regions making up that Load Zone, using the same weights that are used to calculate the Zonal Price for that Distribution Company Load Zone. (c) Hub Prices. On behalf of the Participants, the System Operator shall maintain and facilitate the use of a Hub or Hubs for the Energy market, comprised of a set of Nodes within NEPOOL, which Nodes shall be identified by the System Operator on its Internet website. The System Operator has used the following criteria to establish an initial Hub and shall use the same criteria to establish any additional Hubs: (i) each Hub shall contain a sufficient number of Nodes to try to ensure that a Hub Price can be calculated for that Hub at all times; (ii) each Hub shall contain a sufficient number of Nodes to ensure that the unavailability of, or an adjacent line outage to, any one Node or set of Nodes would have only a minor impact on the Hub Price; (iii) each Hub shall consist of Nodes with a relatively high rate of service availability; (iv) each Hub shall consist of Nodes among which transmission service is relatively unconstrained; and (v) no Hub shall consist of a set of Nodes for which directly connected load and/or generation at that set of Nodes is dominated by any one entity or its affiliates. The System Operator shall calculate hourly Hub Prices for both the Day-Ahead and Real-Time Markets using a fixed- weighted average of the Nodal Prices that comprise the Hub. The System Operator shall calculate Hub Prices using the following formula, or a formula similar in substance and effect, where the Hub Price for a Hub j can be written as: where: Y h/j= Hub Price for Hub j in $/megawatthour; Formula is as defined in Section 14A.12(a); is the Marginal Loss Component of the Hub Price for Hub j in $/megawatthour; is the Congestion Component of the Hub Price for Hub j in $/megawatthour; H j= the set of Nodes in Hub j; and the load weighting factor for Node i used to calculate the Hub Price for Hub j, determined such that the weighting factors for any given Hub sum to one. Participants may transfer their Settlement Obligations at the Hub Price in the Day-Ahead and Real-Time Markets pursuant to Bilateral Transactions. In accordance with Section 14A.8 of the Agreement, Participants with Settlement Obligations for Energy at the Hub shall pay or be charged the Hub Price for such Settlement Obligations. (d) Nodal Prices for External Nodes. The System Operator shall calculate Nodal Prices for External Nodes. The External Nodes shall be identified in applicable Market Rules. External Nodes shall be used for pricing Energy transactions by Participants receiving Energy from or delivering Energy to neighboring Control Areas. The Nodal Prices for External Nodes shall be calculated in the same way as Nodal Prices for Nodes, with the exception of the calculation of the Marginal Loss Component of the price. The Marginal Loss Component of Nodal Prices for External Nodes shall be calculated so as to ensure that it does not include the effect of withdrawals at a Node or External Node on the cost of losses incurred outside the NEPOOL Control Area. In order to accomplish this, a hypothetical transaction will be modeled, in which an increment of load at each External Node is served by an increment of generation at the Reference Node. The amount of Energy that would flow out of the NEPOOL Transmission System over each interconnection point between the NEPOOL Transmission System and an adjoining Control Area or the Non-PTF transmission system will be calculated next. Finally, the Marginal Loss Component of the Nodal Price at each External Node will be calculated as the weighted average of the Marginal Loss Components at each of the interconnection points between the NEPOOL Transmission System and an adjoining Control Area or the Non-PTF transmission system. The weight assigned to each interconnection will be equal to the proportion of the total amount of Energy delivered off of the NEPOOL Transmission System in association with this hypothetical transaction that flows over that interconnection. As a result, the Marginal Loss Component of the price at each External Node will only include the effects on Marginal Losses on the NEPOOL Transmission System. The Shift Factors for each External Node determine the proportion of the Energy in such a transaction that would flow over each interconnection point between the NEPOOL Transmission System and external Control Areas or the Non-PTF transmission system and, therefore, the Marginal Loss Component of the Nodal Price at an External Node i shall be calculated using the following equation, or a formula similar in substance and effect: where: = the Marginal Loss Component of the Nodal Price at an External Node i in $/megawatthour; I= the set of interconnection points between the NEPOOL Transmission System and adjacent Control Areas or the Non-PTF transmission system; GF in= Shift Factor at External Node i for the interconnection line that passes through Node n; and Formula = the Marginal Loss Component of the Nodal Price at Node n in $/megawatthour, where WFn is the withdrawal factor at Node n and formula is as defined in Section 14A.12(a). The price used for Real-Time settlements at External Nodes will be the Real-Time price as determined based on the Real-Time dispatch except in the circumstance in which imports or exports were constrained in the hour ahead scheduling process either by constraints that are not monitored in Real-Time or by closed interface constraints that are not affected by internal dispatchable generators. In this special circumstance, the price used for Real-Time settlements of imports from External Nodes will be the lower of the Real-Time price at the External Node or the hour ahead price at the External Node. Similarly, in this situation, the price used for Real-Time settlements of exports to External Nodes will be the higher of the Real-Time price at the External Node or the hour ahead price at the External Node. (e) Additional Rules and Procedures. Consistent with this Section 14A.12, the implementation of its provisions shall further be detailed, defined and carried out pursuant to Market Rules. 14A.13 Determination of Operating Reserve and 4-Hour Reserve Clearing Prices (a) Operating Reserve and 4-Hour Reserve shall be scheduled in the Day-Ahead Market and designated in the Real-Time Market in accordance with the simultaneous optimization processes described in Sections 14A.5 and 14A.7, respectively, and the NEPOOL System Rules. As a result, in the Day-Ahead Market and Real-Time Market, the respective Clearing Price for an hour for 10-Minute Spinning Reserve shall equal or exceed the Clearing Price for 10-Minute-Non-Spinning Reserve, which shall equal or exceed the Clearing Price for 30-Minute Operating Reserve, which shall equal or exceed the Clearing Price for 4- Hour Reserve. (b) For each hour, in accordance with the NEPOOL System Rules, the System Operator shall calculate the Operating Reserve Clearing Price for each category of Operating Reserve in the Day-Ahead Market and the Real-Time Market as follows: (i) The System Operator shall determine the aggregate Megawatts of the applicable category of Operating Reserve that are scheduled for the hour in the Day-Ahead Market or designated for the hour in the Real-Time Market. (ii) For each category of Operating Reserve in each of the Day-Ahead Market and Real-Time Market, the System Operator shall rank in the order of lowest to highest the Reserve Prices, Lost Opportunity Costs and Supply Offer Prices, as applicable, of the Resources scheduled by the System Operator for that category of Operating Reserve for the hour for the Day-Ahead Market or designated each interval during the hour in the Real-Time Market. (iii) The Operating Reserve Clearing Price per Megawatt for each category of Operating Reserve in each Market shall be the time-weighted average of the highest Reserve Prices, Lost Opportunity Costs or Supply Offer Prices, as applicable, for that category of Operating Reserve that are scheduled for the hour in the Day-Ahead Market or designated each interval during the hour in the Real-Time Market by the System Operator, as determined in accordance with the applicable Market Rules. (a) For each hour in the Day-Ahead Market for which the System Operator calculates it requires 4-Hour Reserves, the System Operator shall determine the 4-Hour Reserve Clearing Price as follows: (i) The System Operator shall determine the aggregate Megawatts of 4-Hour Reserves scheduled for the hour in the Day-Ahead Market. (ii) The System Operator shall rank from lowest to highest the Reserve Prices, Lost Opportunity Costs and Supply Offer Prices, as applicable, of the Resources scheduled for 4-Hour Reserves for the hour in the Day- Ahead Market. (iii) The 4-Hour Reserve Clearing Price per Megawatt in the Day-Ahead Market shall be the highest Reserve Prices, Lost Opportunity Costs or Supply Offer Prices, as applicable, for 4-Hour Reserves that are scheduled by the System Operator for the hour in accordance with applicable Market Rules. (b) The System Operator shall calculate a Lost Opportunity Cost for each hour for a Resource, other than Dispatchable Load, which shall, for each increment of Supply Offer Megawatts, be equal to the product of (i) the amount, if any, by which the Nodal Price for the hour at the Node or External Node where Energy from the Resource would be supplied in the Day-Ahead Market or Real-Time Market exceeds the Resource's Energy Supply Offer Price, for that increment of Supply Offer Megawatts, for that market and (ii) the additional Megawatts, in that increment of Supply Offer Megawatts, the Resource would have been scheduled or dispatched to in the Day-Ahead Market or Real-Time Market, respectively, had it been scheduled or dispatched to supply Energy at the Megawatt level specified in its Supply Offer relating to its Supply Offer Price and operating parameters. 14A.14 Determination of AGC Clearing Price. For each hour, the System Operator shall determine an AGC Clearing Price for the Day-Ahead Market and for the Real-Time Market. In the case of each Market, the AGC Clearing Price shall be the time-weighted average "AGC Capability Price," as defined below in this Section 14A.14. The AGC Capability Price for a generating unit furnishing AGC per the System Operator's schedule for the hour in the Day-Ahead Market or designated each interval during the hour in the Real-Time Market shall be equal to (A) the cost per unit of making the AGC capability of a generating unit available based on the AGC Supply Offer Price for the Entitlement for the hour, plus any Lost Opportunity Cost, divided by (B) the amount of AGC scheduled in the hour in the Day-Ahead Market or designated in the interval in the Real-Time Market from that Resource. The AGC Capability Price used to determine the AGC Clearing Price shall be the highest AGC Supply Offer for the generating units that, in the case of the Day-Ahead Market, were scheduled by the System Operator to provide AGC for the hour, or, in the case of the Real-Time Market, were designated each interval during the hour to provide AGC beyond their Supply Obligations for AGC in the Day-Ahead Market. 14A.15 Funds to or from which Payments are to Be Made. (a) All payments for Energy (except for payments to or from the Congestion Revenue Fund and the Marginal Loss Revenue Fund), Operating Reserve, 4-Hour Reserve and AGC furnished or received, all uplift charges paid pursuant to this Section 14A of this Agreement, and any payments by Non-Participants for ancillary services under Schedules 2 through 7 to the Tariff or pursuant to arrangements referenced in Section 14A.10, shall be allocated each month through the Pool Interchange Fund as follows: Step One. For each week in which Energy is delivered or received under the HQ Energy Banking Agreement, all payments with respect to transactions under that Agreement shall be made to or from the Energy Banking Fund provided for in Section 14A.15(b). Step Two. (i) For each week in which Pre-Scheduled Energy (as defined in the HQ Phase I Energy Contract) is purchased pursuant to the HQ Phase I Energy Contract, the aggregate amount which is paid pursuant to Section 14A.10(b) for such Energy by each Participant which is a participant in the Phase I arrangements with Hydro-Quebec shall be determined and paid on the Participant's account into the Phase I Savings Fund. (ii) For each week in which Energy is purchased pursuant to the HQ Phase II Firm Energy Contract, the aggregate amount which is paid pursuant to Section 14A.10(b) for such Energy by each Participant which is a participant in the Phase II arrangements with Hydro-Quebec shall be determined and paid on the Participant's account into the Phase II Savings Fund. Step Three. For each week in which Other HQ Energy is purchased pursuant to the HQ Phase I Energy Contract or Energy is purchased pursuant to the HQ Interconnection Agreement, the aggregate amount paid pursuant to Section 14A.10(b) for such Energy shall be determined for each Participant which is a participant in the Phase I or Phase II arrangements with Hydro-Quebec. Such amount shall be allocated between the Participant's share of the Phase I Savings Fund and the Participant's share of the Phase II Savings Fund created under the HQ Use Agreement in the same ratio as (A) the sum of (x) the number of kilowatthours of Other HQ Energy deemed to be purchased by the Participant during the week and (y) the HQ Phase I Percentage of the number of kilowatthours deemed to be purchased by the Participant under the HQ Interconnection Agreement during the week, bears to (B) the HQ Phase II Percentage of the number of kilowatthours purchased under the HQ Interconnection Agreement during the week. Step Four. The balance remaining in the Pool Interchange Fund after Steps One through Three shall be retained in the Pool Interchange Fund for the month and shall be used and disbursed after each month in the following order: (iii)(A) amounts owed to Non-Participants (other than Hydro-Quebec) for the month under contracts entered into with them pursuant to Section 14A.10(a) shall be paid, and (B) amounts owed to Hydro-Quebec for the month for Energy deemed to be furnished pursuant to Section 14A.10(b) to Participants which are not participants in the Phase I or Phase II arrangements with Hydro-Quebec shall be paid and, in the event the price paid by any such Participant for such Energy is the applicable Locational Price, the excess, if any, of such Locational Price over the amount owed to Hydro-Quebec shall be paid to the Participant; and (iv) amounts owed to Participants for the month pursuant to this Section 14A shall then be paid. (b) HQ Energy Banking Fund. All amounts allocated to the HQ Energy Banking Fund for each month shall be used and disbursed as follows: (i) Participants which furnish Energy for delivery to Hydro-Quebec under the HQ Energy Banking Agreement shall receive from their share of the Energy Banking Fund the amount to which they are entitled for such service in accordance with Section 14A.9. (ii) amounts required to be paid to Hydro-Quebec under the HQ Energy Banking Agreement shall be paid from the shares of the Fund of the Participants engaging in transactions under the HQ Energy Banking Agreement for the month in accordance with their respective interests in the transactions for the month. If there is not enough in any such share, the Participants with the deficient shares shall be billed and pay into their shares of the Fund the amounts required for payments to Hydro-Quebec. (iii) subject to the remaining provisions of this Section, at the end of each month any balance remaining in each Participant's share of the HQ Energy Banking Fund shall (I) in the case of any Participant which is not a participant in the Phase I or Phase II arrangements with Hydro-Quebec, be paid to such Participant, and (II) in the case of any Participant which is a participant in the Phase I or Phase II arrangements with Hydro-Quebec, be paid to the Escrow Agent under the HQ Use Agreement to be held and disbursed by it through the Phase I Savings Fund and Phase II Savings Fund created under the HQ Use Agreement, and shall be allocated between the Participant's share of said Funds as follows: (A) the balance remaining in the Participant's share of the HQ Energy Banking Fund for the month shall be divided by the number of kilowatthours deemed to be received by the Participant under the HQ Energy Banking Agreement during the month to determine an average savings amount per kilowatthour; (B) for any hour during the month in which the number of kilowatthours received by NEPOOL under the HQ Energy Banking Agreement exceeded the HQ Phase I Transfer Capability, an amount equal to (a) the Participant's share of the excess of (1) the number of kilowatthours received over (2) the HQ Phase I Transfer Capability times (b) the average savings amount per kilowatthour determined for that Participant under (A) above shall be allocated to the Phase II Savings Fund; and (C) the remaining balance of the Participant's share of the HQ Energy Banking Fund for the month shall be allocated to the Phase I Savings Fund. It is recognized that, in view of the time which may elapse between the delivery of Energy to or by Hydro- Quebec in an Energy Banking transaction under the HQ Energy Banking Agreement and the return of the Energy, the amounts of Energy delivered to and received from Hydro-Quebec, after adjustment for losses, may not be in balance at the end of a particular month. Further, if as of the end of any month and after adjustment for electrical losses, the cumulative amount of Energy so received from Hydro-Quebec exceeds the amount so delivered, the aggregate amount paid by Participants for the excess Energy pursuant to Section 14A.10(b) shall be paid to the Energy Banking Fund. The Escrow Agent under the HQ Use Agreement shall hold and invest these funds. On the return of the excess Energy to Hydro-Quebec, the amount so held by the Escrow Agent shall be repaid to Hydro-Quebec and Participants in accordance with the Energy Banking Agreement. (c) Phase I HQ Savings Fund. The aggregate amount allocated to each Participant's share of the Phase I HQ Savings Fund for each month shall be used, first, to pay to Hydro-Quebec the amount owed to it for the month for Energy furnished under the Phase I HQ Energy Contract and the HQ Phase I Percentage of the amount owed to it for the month for Energy furnished to the Participants under the HQ Interconnection Agreement. The balance of the amount allocated to the Fund for the month shall be paid to the Escrow Agent under the HQ Use Agreement to be held and disbursed by it through the Phase I HQ Savings Fund created thereunder in accordance with each Participant's contribution to such balance. (d) Phase II HQ Savings Fund. The aggregate amount allocated to the Phase II HQ Savings Fund for each month shall be used, first, to pay to Hydro-Quebec the amount owed to it for the month for Energy deemed to be furnished to the Participant under the Phase II HQ Firm Energy Contract and the HQ Phase II Percentage of the amount owed to it for the month for Energy deemed to be furnished to the Participants under the HQ Interconnection Agreement. The balance of the amount allocated to the Fund for the month shall be paid to the Escrow Agent under the HQ Use Agreement to be held and disbursed by it through the Phase II HQ Savings Fund created thereunder in accordance with each Participant's contribution to such balance. 14A.16 Marginal Losses. (a) Marginal Loss Cost. Marginal Loss cost shall be reflected in and recovered through the Marginal Loss Components of Locational Prices. Participants pay for Marginal Loss cost by paying the Locational Price for Energy. Locational Prices shall be calculated in accordance with Section 14A.12 of the Agreement and Schedule 13 of the Tariff. (b) Marginal Loss Revenue. To the extent that there is any Marginal Loss Revenue in any settlement period, such revenue shall be collected in a Marginal Loss Revenue Fund and allocated to load-serving entities in proportion to their Net Hourly Load Obligations for Energy in accordance with the Market Rules. (c) Additional Rules and Procedures. Consistent with this Section 14A.16, the implementation of its provisions shall further be detailed, defined and carried out pursuant to Market Rules. 14A.17 Congestion Cost and Revenues. (a) Congestion Cost. When Congestion exists, Congestion Cost shall be reflected in and recovered through the Congestion Components of Locational Prices. Participants pay for Congestion Costs by paying the Locational Price for Energy. Locational Prices shall be calculated in accordance with Section 14A.12 of the Agreement and Schedule 13 of the Tariff. (b) Congestion Revenue. For each hour of the Dispatch Day in the Day-Ahead and Real-Time Markets, the System Operator shall calculate and collect Congestion Revenue and maintain a Congestion Revenue Fund. (c) Additional Rules and Procedures. Consistent with this Section 14A.17, the implementation of its provisions shall further be detailed, defined and carried out pursuant to Market Rules. 14A.B Market Monitoring and Reports. (a) The System Operator shall complete and circulate to the Participants Committee and post on its Internet website for each month a market monitoring report. The monthly report shall be completed no later than sixty (60) days after the close of the calendar month of market activities covered by the report and shall contain the following information for each Load Zone and Reliability Region: (a) separately identified Congestion Costs, RMR Uplift and any other amounts that are paid for by Load Zone and/or Reliability Region, (b) the number of Supply Offers from Participants that were not Related Persons of each other and that were capable of meeting the marginal load within the Load Zone and/or Reliability Region to the extent that the number falls below limits prescribed in the Market Rules, (c) the aggregate import limitation to the Load Zone and/or Reliability Region, (d) the existence and a description of internal transmission constraints within the Load Zone and/or Reliability Region and (e), to the extent disclosure can be made consistent with the NEPOOL Information Policy, patterns of behavior that the System Operator has identified in the course of market monitoring that may affect price or other charges that are paid for Energy in the Load Zone and/or Reliability Region in a manner not consistent with the conditions that would prevail in a competitive market. If the System Operator has not commenced or taken corrective action with respect to Supply Offers, Demand Bids, or other behavior inconsistent with the conditions that would prevail in a competitive market identified in one of its monthly reports within thirty (30) days of the issuance of that report, any Participant may commence a complaint proceeding at the Commission to seek remediation of such behavior. The Participant or Participants initiating such a complaint proceeding shall, upon the issuance of a protective order by the Commission covering confidentiality and other relevant matters and subject to the terms of such protective order, be entitled to access to the data underlying the System Operator's conclusions as to behavior inconsistent with conditions that would prevail in a competitive market. The ability to initiate such a complaint proceeding at the Commission shall not prejudice the ability of such complaining Participant or Participants to pursue market power issues in any other forum. Nothing in this section shall preclude any Participant from contesting, in the context of a proceeding involving the issuance of a protective order by the Commission, the disclosure or other release of confidential information. (a) Studies Related to Congestion. The System Operator shall perform, on an ongoing basis, an evaluation of the effectiveness, efficiency and workability of the each of the main components of the CMS, including, without limitation, the system of Locational Prices and FCRs. Within sixty (60) days after the first anniversary of the CMS/MSS Effective Date, the System Operator shall issue a written report to the Participants Committee at least ten (10) business days prior to a Participants Committee meeting for discussion and shall not further distribute that report publicly until after the Participants Committee meeting. Such report shall contain in detail the System Operator's evaluations, conclusions and recommendations, if any, for changes to the CMS. To the extent practicable, the System Operator shall retain all data necessary to analyze the CMS. (b) Day-Ahead Market Information Reports. The System Operator shall make available as provided below for the Day- Ahead Market each day in accordance with the Market Rules and in a way that is consistent with the NEPOOL Information Policy the following items, but not limited to: (i) Each Participant shall be notified of the following: (A) The set of accepted Supply Offers for Resources, including Supply Offers at External Nodes, that will define the prices and quantities of the Participant's Supply Obligations for the Dispatch Day with respect to Energy, Operating Reserve, 4-Hour Reserve and AGC for each hour in the Day-Ahead Market. These schedules shall define expected start- up, loading levels, and shut down schedules for the Participant's Resources. (B) The set of accepted Demand Bids, including Demand Bids at External Nodes, that will define the Participant's Settlement Obligations to pay for a specified quantity of Energy at each specified Location for each hour in the Day- Ahead Market. (ii) the System Operator shall publish on a daily basis the following information: (A) Day-Ahead Locational Prices for each hour of the Dispatch Day determined in accordance with Section 14A.12, as well as all non-confidential data and assumptions used by the System Operator to calculate each such price. These prices will include Nodal Prices at all Nodes and External Nodes for Resources, Zonal Prices for each Load Zone, and Hub Prices for each Hub. In posting Locational Prices, the System Operator shall include all components of such prices, including the Nodal Price at the Reference Node, the Marginal Loss Component, and the Congestion Component. (B) The aggregate quantities of Supply Offers and Demand Bids accepted in each hour of the Day- Ahead Market. (C) Hourly Clearing Prices and the amounts scheduled in the Day-Ahead Market for Operating Reserves, 4-Hour Reserves, and AGC. (D) The System Operator's load forecast for each hour of the Dispatch Day compared to accepted Demand Bids. (E) The projected Net Supply Offer Shortfall Uplift as determined pursuant to Section 14A.19(a) and RMR Uplift and costs for voltage support for each Reliability Region. (c) Real-Time Market Information Reports. The System Operator shall publish for the Real-Time Market during the Dispatch Day, in a way that is consistent with the NEPOOL Information Policy the following items, but not limited to: (i) Real-Time Market Locational Prices, including the Nodal Prices (including External Nodes), Zonal Prices, and Hub Prices, as well as all non-confidential data and assumptions used by the System Operator to calculate each such price. As far in advance of each hour of the Real- Time Market as is feasible, the System Operator shall post its estimate of the Locational Prices for the remainder of the Dispatch Day. (ii) As far in advance of each hour of the Real-Time Market as is feasible, updates to the load forecast. (iii) Hourly Clearing Prices and amounts designated in the Real-Time Market for Operating Reserves and AGC. (iv) Actual loads compared to forecasted load and accepted Demand Bids. (d) Special Reporting. The System Operator shall publish with the Real-Time Market information the following data concerning emergency purchases and sales and Reserve Contracts entered into pursuant to Section 14A.10: (i) The hourly price and schedule for Energy under the emergency purchase or sale. (ii) Prices and quantities at which the Operating Reserve or 4-Hour Reserve are scheduled or designated by the System Operator for the hour pursuant to Reserve Contracts. 14A.19 Additional Uplift Charges. (a) Net Supply Offer Shortfall Uplift. It is anticipated that a generating unit may be scheduled by the System Operator in the Day-Ahead Market for all or part of a day when the Supply Offer Costs (as defined below) exceed the aggregate revenues received pursuant to this Section 14A for the generating unit from all Day-Ahead Markets. A Net Supply Offer Shortfall Uplift shall be calculated as provided in this Section 14A.19 to provide for payment of this shortfall to the affected generator and allocation of such difference. Except as provided below, each generating unit scheduled by the System Operator in the Day-Ahead Market shall be entitled to receive its Supply Offer Costs, provided that the foregoing evaluation shall be made only on an aggregate basis for the total hours scheduled to supply Energy, Operating Reserves, 4- Hour Reserves, and/or AGC in the Dispatch Day and not on an individual hour-by-hour basis, and shall be made only on a single Day-Ahead Market basis, so that, for example, the net shortfall for a unit scheduled for a particular Dispatch Day shall be entitled to this treatment only for the hours in that first Dispatch Day in that Day-Ahead Market even if the unit's minimum run time extends beyond the Dispatch Day. Any shortfall between Supply Offer Costs and aggregate market revenues in the subsequent period during uninterrupted operation of the Resource for hours that extend beyond the satisfaction of the Resource's minimum run time, will be addressed through the Net Supply Offer Shortfall Uplift determined for that Dispatch Day. Cost responsibility for this difference shall be allocated among Participants in accordance with subsection (c) of this Section 14A.19 for those hours in which the generating unit is scheduled to provide service during the Dispatch Day, with the allocation among such hours determined in accordance with applicable Market Rules. For purposes of this Section 14A.19, "Supply Offer Costs" for a generating unit shall mean the aggregate of the Start-Up Price, if applicable, plus the summation for the Dispatch Day of the No Load Price in each applicable hour and the product in each applicable hour of the applicable Supply Offer Prices and the amounts of Energy, Operating Reserve, 4-Hour Reserve and AGC scheduled from the unit in the Day-Ahead Market. The Net Supply Offer Shortfall Uplift is calculated as the Supply Offer Costs of a generating unit minus the aggregate revenues received by a Participant for the amounts of Energy, Operating Reserve, 4-Hour Reserve and AGC scheduled from the unit in the Day-Ahead Market for that Dispatch Day. A Participant with an Entitlement in a generating unit that is Self-Scheduled in the Day-Ahead Market shall only be entitled to receive payment of a Net Supply Offer Shortfall Uplift associated with the unit during hours that the unit is not Self-Scheduled. The calculation of Net Supply Offer Shortfall Uplift for a Self-Scheduled unit shall exclude No-Load costs for the hours the unit is Self-Scheduled and include revenues associated with the difference between the applicable Clearing Price and Supply Offer Price for the service from the unit beyond the Self-Scheduled service. If the System Operator schedules a generating unit to start-up and operate in the hours immediately prior to, and/or continue operation for a period beyond, the hours for which the unit was Self-Scheduled in the Day-Ahead Market, the Start-Up Price shall not be included in Supply Offer Costs for the purpose of determining whether the generating unit is entitled to receive a Net Supply Offer Shortfall Uplift for the hours of the Dispatch Day for which the unit was not Self-Scheduled. (b) Real-Time Uplift. There may be circumstances where the Real-Time Nodal Price for Energy paid to a generating unit in the Real-Time Market is less than the Real-Time Supply Offer Price for the generating unit. These circumstances may be caused by the time-weighted averaging calculation of the Real- Time Market Nodal Prices or as a result of the System Operator dispatching certain fast response generating units within an hour in response to anticipated system conditions in that hour. In such circumstances, the generating unit shall receive a Real-Time Uplift equal to the difference between the Real-Time Nodal Price and the corresponding Supply Offer Price for those megawatthours produced at the higher Supply Offer Price but only to the extent those megawatthours were produced pursuant to the dispatch instructions of the System Operator as described in the Market Rules. (c) Allocation of Net Supply Offer Shortfall Uplift. Where payment is due to a Participant under Section 14A.19(a), the aggregate amount of such payments shall be recovered from Participants, including the Participant to which such payment is made, as an uplift charge to be paid in accordance with this Section 14A.19(c). Net Supply Offer Shortfall Uplift will first be allocated among the Energy market and the three Operating Reserve Markets based on cost causation principles in accordance with applicable Market Rules. Net Supply Offer Shortfall Uplift will be allocated to specific markets to the extent that the benefit of incurring the uplift is recognized in that market because incurring the uplift relieved an otherwise binding constraint affecting the Clearing Price in that market. To the extent that incurrance of the uplift benefits more than one market such uplift will be allocated pro rata to all four markets in accordance with the aggregate Settlement Obligations (in dollars) in the Energy and Operating Reserve markets adjusted as specified in the Market Rules. Charges for Net Supply Offer Shortfall Uplift allocated to the Day-Ahead Energy Market ("Regional Energy Uplift") shall be determined for each hour and paid by each Participant in accordance with the following formula: DACH = (UCa) (X dai - SS dai) (Xda - SSda ) in which DACH is the amount to be paid by the Participant pursuant to this Section 14A.19(c) provided that if this amount is negative the Participant shall neither pay nor receive credit for such amount. UCa is the sum for the hour of uplift payments to generators made pursuant to Section 14A.19(a) in the Day-Ahead Market. Xdai is the Settlement Obligation for Energy of the Participant for the hour in the Day-Ahead Market adjusted for Bilateral Transactions as to which both the buyer(s) and the seller(s) elect or have elected to transfer Regional Energy Uplift obligations in the Day-Ahead Market with respect to any Bilateral Transaction in accordance with the Market Rules. Xda is the aggregate Settlement Obligation for Energy of all Participants for the hour in the Day-Ahead Market adjusted for Bilateral Transactions as to which both the buyer(s) and the seller(s) elect or have elected to transfer Regional Energy Uplift obligations in the Day- Ahead Market with respect to any Bilateral Transactions in accordance with the Market Rules. SSdai is the amount of the Participant's Self- Supply of its Day-Ahead Settlement Obligation for Energy that is actually supplied in the Real-Time Market from the Self-Scheduled Resources of the Participant. SSda is the aggregate of Participants' Self-Supply of their Day-Ahead Settlement Obligations for Energy that are supplied in the Real-Time Market from the Self-Scheduled Resources of those Participants. Charges for Net Supply Offer Shortfall Uplift allocated to each Operating Reserve Market ("Regional Operating Reserve Uplift") shall be determined for each hour and paid by each Participant in accordance with an equivalent calculation to that specified for the Energy Market, as follows. The calculation for each Operating Reserve Market will be specified in the Market Rules and will be based on the Settlement Obligation for the relevant category of Operating Reserve after accounting for those Bilateral Transactions described in the definitions of Xdai and Xda above with respect to the relevant category of Operating Reserve. (d) Allocation of Real-Time Uplift. Where payment is due to a Participant under Section 14A.19(b), the aggregate amount of such payments shall be recovered from Participants, including the Participant to which such payment is made, as an uplift charge to be paid in accordance with this Section 14A.19(d). Charges for Real-Time Uplift allocated to Participants in the Real-Time Energy Market ("Real-Time Energy Uplift") shall be determined for each hour and paid by each Participant in accordance with the following formula: RTCH = (UCb) (Xrti - SSrti ) (Xrt - SSrt ) in which RTCH is the amount to be paid by the Participant pursuant to this Section 14A.19(d) provided that if this amount is negative the Participant shall neither pay nor receive credit for such amount. UCb is the sum for the hour of uplift payments to generators made pursuant to Section 14A.19(b) in the Real-Time Market. Xrti is the Settlement Obligation for Energy of the Participant for the hour in the Real-Time Market adjusted for Bilateral Transactions as to which both the buyer(s) and the seller(s) elect or have elected to transfer Real-Time Energy Uplift obligations in the Real-Time Market with respect any Bilateral Transaction in accordance with the Market Rules. Xrt is the aggregate Settlement Obligation for Energy of all Participants for the hour in the Real-Time Market adjusted for Bilateral Transactions as to which both the buyer(s) and the seller(s) elect or have elected to transfer Real-Time Energy Uplift obligations in the Real-Time Market with respect to any Bilateral Transactions in accordance with the Market Rules. SSrti is the amount of the Participant's Self- Supply of its Real-Time Settlement Obligation for Energy that is actually supplied in the Real-Time Market from the Self-Scheduled Resources of the Participant. SSrt is the aggregate of Participants' Self-Supply of their Real-Time Settlement Obligations for Energy that are supplied in the Real-Time Market from the Self-Scheduled Resources of those Participants. (e) Uplift Allocation And Pre-Existing Contracts. With respect to any Bilateral Transaction entered into prior to September 26, 2000 (the "Effective Date"), the allocation of Regional Energy Uplift cost responsibility, Regional Operating Reserve Uplift cost responsibility and Real-Time Energy Uplift cost responsibility provided for in Sections 14A.19(c) and 14A.19(d) shall not alter the obligations of either the buyer or seller under such Bilateral Transaction as of the date immediately prior to the Effective Date without the agreement of both the buyer and seller. (f) RMR Uplift. It is also anticipated that it may be necessary from time to time to schedule a Participant's generating unit or Dispatchable Load to provide Operating Reserve in one or more hours at prices for Operating Reserve that exceed the applicable Clearing Price for that Operating Reserve service in the Day-Ahead Market in order to satisfy locational Operating Reserve requirements in a particular Reliability Region or Reliability Regions in accordance with applicable Market Rules. When this occurs the Participant providing such service shall be entitled to receive for the Dispatch Day the aggregate of the applicable Supply Offer Prices for Operating Reserve to provide the requested Operating Reserve service for all of the scheduled hours in the Dispatch Day. This comparison of Supply Offer Price against Clearing Price for the applicable Operating Reserve products shall be made on an aggregate basis for all hours scheduled in the Day-Ahead Market for that Dispatch Day, and not on an individual hour-by-hour basis. Where payment is made to a Participant under these circumstances, the amount by which the payment to the Participant exceeds the amount that would be paid if the Participant had only received the applicable Day-Ahead Market Operating Reserve Clearing Prices for the scheduled service during the hours in question shall be recovered as RMR Uplift from Participants which are obligated to pay under the Settlement Obligations for Operating Reserve associated with load in the affected Reliability Region or Reliability Regions for the hours during which the service is scheduled in the Dispatch Day. Except as provided below, RMR Uplift shall be paid by each Participant for each hour in accordance with the following formula: CHd = UCd)(ELi ) + ADJrr ELrr in which CHd is the amount to be paid by a Participant pursuant to this Section 14A.19(f) for RMR Uplift for the affected Reliability Region(s). UCd is the aggregate RMR Uplift payments to Participants for the hour for out of merit services for the affected Reliability Region(s) to be allocated and paid pursuant to this Section 14A.19(f). ELi is the number of kilowatthours of Electrical Load of the Participant for the hour in the affected Reliability Region(s). ELrr is the aggregate number of kilowatthours of Electrical Load of all Participants for the hour in the affected Reliability Region(s). ADJrr is the total uplift charge adjustment for the Participant required to reflect Operating Reserve that the Participant has Self-Supplied and all Bilateral Transactions entered into by the Participant for the transfer of Settlement Obligations for Operating Reserve pursuant to Section 14A.1(c) for the hours to the extent that each Bilateral Transaction is not reflected in the Participant's Electrical Load for the hour. The adjustment for each Bilateral Transaction shall equal the pro rata portion of the transferring Participant's Operating Reserve Settlement Obligations covered by such Bilateral Transaction. The adjustment shall be negative for all Bilateral Transactions under which the Participant transfers its Settlement Obligations for Operating Reserve to another Participant; the adjustment shall be positive for all Bilateral Transactions under which the Participant assumes the Settlement Obligations for Operating Reserve of another Participant. Notwithstanding the foregoing, the first six million dollars ($6,000,000) of the RMR Uplift under this Section 14A.19(f) shall be allocated for each hour among and paid by all Participants which have Settlement Obligations for Operating Reserve for the hour in accordance with the formula in Section 14A.1(c) for each of the following two periods: (i) the twelve-month period commencing on the CMS/MSS Effective Date; and (ii) the period commencing on the first anniversary of the CMS/MSS Effective Date and ending on December 31, 2004. Any such RMR Uplift in excess of six million dollars ($6,000,000) with respect to either period shall be allocated among and paid by the Participants with Settlement Obligations for Operating Reserve associated with load in the affected Reliability Region(s) in accordance with the formula of this Section 14A.19(f). [Next Sheet is 199] PART FOUR TRANSMISSION PROVISIONS SECTION 15 OPERATION OF TRANSMISSION FACILITIES 15.1 Definition of PTF. PTF or pool transmission facilities are the transmission facilities owned by Participants rated 69 kV or above required to allow energy from significant power sources to move freely on the New England transmission network, and include: 1. All transmission lines and associated facilities owned by Participants rated 69 kV and above, except for lines and associated facilities that contribute little or no parallel capability to the NEPOOL Transmission System (as defined in the Tariff). The following do not constitute PTF: (a) Those lines and associated facilities which are required to serve local load only. (b) Generator leads, which are defined as radial transmission from a generation bus to the nearest point on the NEPOOL Transmission System. (c) Lines that are normally operated open. 2. Parallel linkages in network stations owned by Participants (including substation facilities such as transformers, circuit breakers and associated equipment) interconnecting the lines which constitute PTF. 3. If a Participant with significant generation in its transmission and distribution system (initially 25 MW) is connected to the New England network and none of the transmission facilities owned by the Participant qualify to be included in PTF as defined in (1) and (2) above, then such Participant's connection to PTF will constitute PTF if both of the following requirements are met for this connection: (a) The connection is rated 69 kV or above. (b) The connection is the principal transmission link between the Participant and the remainder of the New England PTF network. 4. Rights of way and land owned by Participants required for the installation of facilities which constitute PTF under (1), (2) or (3) above. The Reliability Committee shall review at least annually the status of transmission lines and related facilities and determine whether such facilities constitute PTF and shall prepare and keep current a schedule or catalogue of PTF facilities. The following examples indicate the intent of the above definitions: (i) Radial tap lines to local load are excluded. (ii) Lines which loop, from two geographically separate points on the NEPOOL Transmission System, the supply to a load bus from the NEPOOL Transmission System are included. (iii) Lines which loop, from two geographically separate points on the NEPOOL Transmission System, the connections between a generator bus and the NEPOOL Transmission System are included. (iv) Radial connections or connections from a generating station to a single substation or switching station on the NEPOOL Transmission System are excluded, unless the requirements of paragraph (3) above are met. Transmission facilities owned by a Related Person of a Participant which are rated 69 kV or above and are required to allow Energy from significant power sources to move freely on the New England transmission network shall also constitute PTF provided (i) such Related Person files with the Secretary of the Participants Committee its consent to such treatment; and (ii) the Participants Committee determines that treatment of the facility as PTF will facilitate accomplishment of NEPOOL's objectives. If a facility constitutes PTF pursuant to this paragraph, it shall be treated as "owned" by a Participant for purposes of the Tariff and the other provisions of Part Four of the Agreement. 15.2 Maintenance and Operation in Accordance with Accepted Electric Industry Practice. Each Participant which owns or operates PTF or other transmission facilities rated 69 kV or above shall, to the fullest extent practicable, cause all such transmission facilities owned or operated by it to be designed, constructed, maintained and operated in accordance with Accepted Electric Industry Practice. 15.3 Central Dispatch. Each Participant which owns or operates PTF or other transmission facilities rated 69 kV or above shall, to the fullest extent practicable, subject all such transmission facilities owned or operated by it to central dispatch by the System Operator; provided, however, that each Participant shall at all times be the sole judge as to whether or not and to what extent safety requires that at any time any of such facilities will be operated at less than their full capability or not at all. 15.4 Maintenance and Repair. Each Participant shall, to the fullest extent practicable: (a) cause transmission facilities owned or operated by it to be withdrawn from operation for maintenance and repair only in accordance with maintenance schedules reported to and published by the System Operator in accordance with procedures approved or established by the Tariff Committee from time to time, (b) restore such facilities to good operating condition with reasonable promptness, and (c) in emergency situations, accelerate maintenance and repair at the reasonable request of the System Operator in accordance with rules approved by the Tariff Committee. 15.5 Additions to or Upgrades of PTF. The possible need for an addition to or upgrade of PTF may be identified in connection with the planning process of Section 51 of the Tariff, an application or request for service under the Tariff, or a request for the installation of or material change to a generation or transmission facility, or may be separately identified by a NEPOOL committee, a Participant or the System Operator. In such cases, a study, if necessary, to assess available transmission capacity and, if necessary, a System Impact Study and a Facility Study, shall be performed by the affected Participant(s) in whose Local Network(s) the addition or upgrade would or might be effected or their designee(s), or the Reliability Committee and/or the System Operator, in the case of a System Impact Study, or the Committee's or the System Operator's designee(s), with review of the study by the System Operator if it does not perform the study. Studies to assess available transmission capacity and System Impact Studies and Facilities Studies shall be conducted, as appropriate, in accordance with the affected Participant's Local Network Service Tariff, or in accordance with the applicable methodology specified in Attachments C and D to the Tariff, and the provisions of the Local Network Service Tariff or the applicable provisions of Attachments I and J to the Tariff shall apply, as appropriate, with respect to the payment of the costs of the study and the other matters covered thereby. Responsibility for the costs of new PTF or any modification or other upgrade of PTF shall be determined, to the extent applicable, in accordance with Parts V and VI and Schedules 11 and 12 of the Tariff, including without limitation the provisions relating to responsibility for the costs of new PTF or modifications or other upgrades to PTF exceeding regional system, regulatory or other public requirements set forth in Section (3)(b) of Schedule 11 to the Tariff and Schedule 12 of the Tariff. Sheet 206 is intentionally blank. SECTION 16 SERVICE UNDER TARIFF 16.1 Effect of Tariff. The Tariff specifies the terms and conditions under which the Participants will provide regional transmission service through NEPOOL. This Section 16 specifies various rights and obligations with respect to the revenues to be collected by NEPOOL for the Participants under the Tariff and related matters. 16.2 Obligation to Provide Regional Service. The Participants which own PTF shall collectively provide through NEPOOL regional transmission service over their PTF facilities, and the facilities of their Related Persons which constitute PTF in accordance with Section 15.1, to other Participants and other Eligible Customers pursuant to the Tariff. The Tariff provides open access for all of the types of regional transmission service required by Participants and other Eligible Customers over PTF and it is intended to be the only source of such service, except for service provided for Excepted Transactions. 16.3 Obligation to Provide Local Network Service. Each Participant which owns transmission facilities other than PTF shall provide service over such facilities to other Participants or other Eligible Customers connected to the Transmission Provider's transmission system pursuant to a tariff (a "Local Network Service Tariff") filed by the Transmission Provider with the Commission. A Participant is also obligated to provide service under its Local Network Service Tariff or otherwise (i) to permit a Participant or other Entity with an Entitlement in a generating unit in the Participant's local network to deliver the output of the generating unit to an interconnection point on PTF and (ii) to permit the delivery to an Eligible Customer taking Internal Point-to-Point Service under the Tariff of the Energy and/or capacity covered by its Completed Application for that Internal Point-to-Point Service. A Local Network Service Tariff shall provide: (i) for a pro rata allocation of monthly revenue requirements not otherwise paid for through charges to Eligible Customers for Local Point-to-Point Service among the Transmission Provider's Network Customers receiving service under the tariff on the basis of their loads during the hour in the month in which the total connected load to the Local Network is at its maximum, without any adjustment for credits for generation; (ii) for the recovery under the Local Network Service Tariff from Eligible Customers taking Regional Network Service and Internal Point-to-Point Service of that portion of the Transmission Provider's annual transmission revenue requirements with respect to PTF which is not recovered through the distribution of revenues from Regional Network Service or Internal Point- to-Point Service pursuant to Section 16.6; (iii) that where all or a part of the load of a Participant or other Eligible Customers taking service under the tariff is connected directly to PTF, the Participant or other Eligible Customers receiving the service shall pay each Year during the Transition Period for such service with respect to the load directly connected to PTF the percentage specified in the schedule below of the applicable Local Network Service Tariff charge for service across non-PTF transmission facilities and shall have no obligation to pay charges for service across non-PTF transmission facilities with respect to that portion of the connected load after the Transition Period, but shall continue to pay its share of any other Local Network Service costs directly associated with the PTF-connected load; provided that in the event of any inconsistency between the foregoing provisions and the terms of any Excepted Transaction which is listed in Attachment G-1 to the Tariff, the Excepted Transaction shall control:
Year Year Year Year Year One Two Three Four Five and Six ____ ____ _____ _____ ________ % of 100 % 80% 60% 40% 20% charge to be paid
(i) that if the Transmission Provider receives a distribution pursuant to Section 16.6 from NEPOOL out of revenues paid for Through or Out Service, the amounts received shall reduce its Local Network Service revenue requirements; and (ii) that if the Transmission Provider receives transmission revenues from an Eligible Customer taking Local Network Service from that Transmission Provider with respect to an Excepted Transaction, the amounts received shall reduce the amount due from such Eligible Customer connected to the Transmission Provider's transmission system for Local Network Service provided thereto by the Transmission Provider rather than reducing the Transmission Provider's total cost of service, except that any reductions to the amount due from Eligible Customers for Excepted Transactions identified in Section 25(1) and (2) of the Tariff shall be made only for service rendered through February 28, 1999, and such reductions shall cease and shall be replaced thereafter in their entirety with the credits under the NEPOOL Tariff, provided in accordance with Sections 25A and 25B of the Tariff. 16.4 Transmission Service Availability. The availability of transmission capacity to provide transmission service under the Tariff shall be determined in accordance with the Tariff. In determining the availability of transmission capacity, existing committed uses of the Participants' transmission facilities shall include uses for existing firm loads and reasonably forecasted changes in such loads, and for Excepted Transactions. 16.5 Transmission Information. Information concerning (i) available transmission capacity, (ii) transmission rates and (iii) system conditions that may give rise to Interruptions or Curtailments shall be made available to all Participants and Non- Participants through the OASIS on a timely and non-discriminatory basis. All Participants owning PTF or other transmission facilities rated 69 kV or higher shall make available to the System Operator the information required to permit the maintenance of the OASIS in compliance with Commission Order 889 and any other applicable Commission orders; provided that no Participant shall be required to furnish information which is required to be treated as confidential in accordance with NEPOOL policy without appropriate arrangements to protect the confidentiality of such information. 16.6 Distribution of Transmission Revenues. Payments required by the Tariff for the use of the NEPOOL Transmission System shall be made to NEPOOL and shall be distributed by it in accordance with this Section 16.6. A. Regional Network Service Revenues. Revenues received by NEPOOL for providing Regional Network Service each month during the Transition Period shall be distributed to those Participants owning PTF or those load-serving Participants supporting PTF which are obligated to take and pay for Regional Network Service and/or Internal Point-to-Point Service in accordance with the Tariff, in part on the basis of allocated flows for the region as determined in accordance with the methodology specified in Attachment A to this Agreement and in part in proportion to the respective Annual Transmission Revenue Requirements for PTF of such owners and supporters, in accordance with the following Schedule:
Year Year Year Year Year Year One Two Three Four Five Six Allocated 25% 20% 15% 10% 5% 2.5% Flows: Annual 75% 80% 85% 90% 95% 97.5% Trans- Mission Revenue Requirements:
Revenues received by NEPOOL for providing Regional Network Service each month after the Transition Period shall be distributed to the Participants owning or supporting PTF in proportion to their respective Annual Transmission Revenue Requirements for PTF. A. Through or Out Service Revenues. The revenues received by NEPOOL each month for providing Through or Out Service shall be distributed among the Participants owning PTF on the basis of allocated flows for the transaction determined in accordance with the methodology specified in Attachment A to this Agreement; provided that for service provided during the Transition Period but not thereafter, for an "Out" transaction which originates on the system of a Participant which owns the PTF interconnection facilities on the New England side of the interface with the other Control Area over which the transaction is delivered, 100% of the megawatt mile flows with respect to the transaction shall be deemed to occur on such Participant's system. B. Internal Point-to-Point Service Revenues. The revenues received by NEPOOL each month for providing Internal Point-to- Point Service shall be distributed among those load-serving Participants owning or supporting PTF which are obligated to take and pay for Regional Network Service and/or Internal Point-to-Point Service in accordance with the Tariff, in proportion to their respective Annual Transmission Revenue Requirements for PTF under Attachment F to the Tariff. C. Ancillary Service Payments. The revenues received by NEPOOL pursuant to Schedule 1 to the Tariff (scheduling, system control and dispatch service) will be used to reimburse NEPOOL, the System Operator (if the System Operator does not receive revenues for that service under a separate tariff) and Participants for the costs which are reflected in the charges for such service. The revenues received by NEPOOL pursuant to Schedules 2-7 to the Tariff shall be distributed prior to the Second Effective Date in accordance with the continuing provisions of the Prior NEPOOL Agreement and the rules adopted thereunder, and shall be distributed on or after the Second Effective Date in accordance with Section 14. D. Congestion Payments. Any congestion uplift charge received as a payment for transmission service pursuant to Section 24 of the Tariff for any hour shall be applied in accordance with Section 14.5(a) in payment for Energy service. [Next Sheet is 216] SECTION 17 POOL-PLANNED UNIT SERVICE 17.1 Effective Period. The provisions contained in this Section 17 shall continue in effect for the period to and including February 28, 2001, and shall be of no effect after that date. 17.2 Obligation to Provide Service. Until February 28, 2001, each Participant shall provide service over its PTF facilities under this Section 17 rather than under the Tariff, for the following purposes: (a) the transfer to a Participant's system of its ownership interest or its Unit Contract Entitlement under a contract entered into by it before November 1, 1996 in a Pool-Planned Unit which is off its system; (b) the transfer to a Participant's system of its Entitlement in a purchase under a contract entered into by it before November 1, 1996 (including a purchase under the HQ Phase II Firm Energy Contract) from Hydro-Quebec where the line over which the transfer is made into New England is the HQ Interconnection; and (c) the transfer to a Non-Participant of its Entitlement in a Pool-Planned Unit pursuant to an arrangement which has been approved prior to November 1, 1996 by the Participants Committee. 17.3 Rules for Determination of Facilities Covered by Particular Transactions. It is anticipated that it may be necessary with respect to a particular transmission use under subsection (a), (b) or (c) of Section 17.2 to determine whether the transaction is effected entirely over PTF, entirely over facilities that are not PTF, or partially over each. The following rules shall be controlling in the determination of the facilities required to effect the use: (a) To the extent that EHV PTF is available to effect the transaction, over all or part of the distance to be covered, the use shall be deemed to be effected on such EHV PTF over such portion of the distance to be covered. (b) To the extent that EHV PTF is not available for the entire distance to be covered by the use, but Lower Voltage PTF is available to cover all or part of the distance not covered by EHV PTF, the transaction shall be deemed to be effected on such Lower Voltage PTF. If a Participant has ownership or contractual rights with respect to an Excepted Transaction which are independent of this Agreement and the Tariff and are adequate to provide for a transfer of the types specified in subsections 17.2(a), (b) or (c), and such rights are not limited to the transfer in question, the transfer shall be deemed to have been effected pursuant to such rights and not pursuant to the provisions of this Agreement. A copy of each instrument establishing such rights, or an opinion of counsel describing and authenticating such rights, shall be filed with the Secretary of the Participants Committee. 17.4 Payments for Uses of EHV PTF During the Transition Period. (a) Each Participant shall pay each month for its uses of EHV PTF for transfers of Entitlements pursuant to subsections (a) or (b) of Section 17.2, one-twelfth of the NEPOOL EHV PTF Participant Summer or Winter Wheeling Rate in effect for the calendar year ending December 31, 1996, as determined in accordance with the Prior NEPOOL Agreement, for each Kilowatt of its current Entitlements which qualify for transfer pursuant to subsections (a) or (b) of Section 17.2, except as otherwise provided in Section 17.3; provided that such payment shall be required with respect to only one-half the Kilowatts covered by a NEPOOL Exchange Arrangement (as hereinafter defined). Each Participant which is a party to the HQ Phase II Firm Energy Contract (other than a Participant (i) whose system is directly interconnected to the HQ Interconnection or (ii) which has contractual rights independent of this Agreement and the Tariff which give it direct access to the HQ Interconnection and which are not limited to transfers of Energy delivered over the HQ Interconnection) shall also pay each month for the use of EHV PTF for deliveries under the Phase II Firm Energy Contract during the Base Term of the HQ Phase II Firm Energy Contract, one-twelfth of the NEPOOL EHV PTF Participant Summer or Winter Wheeling Rate in effect for the calendar year ending December 31, 1996, as determined in accordance with the Prior NEPOOL Agreement, for each Kilowatt of its HQ Phase II Net Transfer Responsibility for the month. If, and to the extent that, such Responsibility continues for any period by which the term of said Contract extends beyond the Base Term, each such Participant shall continue to pay the above rate during the extension period with respect to its continuing Responsibility. A Participant shall not be deemed to be directly interconnected to the HQ Interconnection for purposes of this paragraph solely because of its participation in arrangements for the support and/or use of PTF facilities installed or modified to effect reinforcements of the New England AC transmission system required in connection with the HQ Interconnection. A copy of each contract establishing rights independent of this Agreement and the Tariff which provides direct access to the HQ Interconnection, or an opinion of counsel describing and authenticating such rights, shall be filed with the Secretary of the Participants Committee. The NEPOOL EHV PTF Participant Summer Wheeling Rate for any calendar year shall be applicable to the months in the Summer Period. The NEPOOL EHV PTF Participant Winter Wheeling Rate for any calendar year shall be applicable to the months in the Winter Period. A NEPOOL Exchange Arrangement is one entered into by two Participants each of which has an ownership interest in a Pool-Planned Unit on its own system pursuant to which each sells out of its ownership interest, a Unit Contract Entitlement to the other for a period of time which is, in whole or part, the same for both sales. Such an arrangement shall constitute a NEPOOL Exchange Arrangement even though the beginning and ending dates of the two Unit Contract sale periods are different, but only for the period for which both sales are in effect. If for any period the number of Kilowatts covered by the two Unit Contract Entitlements of a NEPOOL Exchange Agreement are not the same, the portion of the larger Entitlement which exceeds the amount of the smaller Entitlement shall not be deemed to be covered by such NEPOOL Exchange Arrangement for purposes of this Section 17.4. (b) Each Participant shall pay each month for its use of EHV PTF for a transfer of an Entitlement in a Pool-Planned Unit to a Non-Participant pursuant to Section 17.2(c) such charge as is fixed by the Participants Committee at the time of its approval of the sale, and filed with the Commission. (c) Fifty percent of all amounts required to be paid with respect to transfers by a Participant pursuant to subsection (a) or (b) of Section 17.2 shall be paid to a pool transmission fund and distributed monthly among the Participants in proportion to the respective amounts of their costs with respect to EHV PTF for the calendar year 1996 as determined in accordance with the Prior NEPOOL Agreement. (d) The remaining 50% of all amounts required to be paid with respect to transfers by a Participant pursuant to subsections (a) or (b) of Section 17.2 shall be paid to, and retained by, the Participant on whose system the transfer originates, or in the event the EHV PTF system of such Participant is supported in part by other Participants, then to the Participant on whose system the transfer originates and such other Participants in proportion to the respective shares of the costs of such EHV PTF system borne by each of them or in such other manner as the Participants involved may jointly direct; provided that the Participant on whose system the transfer originates shall have the right to waive such 50% payment in whole or part as to a particular transfer except that no such waiver may adversely affect the payments to any other Participant which is supporting in part the originating system's EHV PTF system. 17.5 Payments for Uses of Lower Voltage PTF. Each Participant which uses another Participant's Lower Voltage PTF pursuant to this Section 17 shall pay each month to the owner of such Lower Voltage PTF (1) for each Kilowatt of its use of such Lower Voltage PTF for transfer of Entitlements pursuant to Subsections 17.2(a), (b) or (c) during the month, and (2) during the Base Term of the HQ Phase II Firm Energy Contract (and during any extension of the term of said Contract if and to the extent its HQ Phase II Net Transfer Responsibility continues during the extension period) for each Kilowatt of its HQ Phase II Net Transfer Responsibility for the month, the owner's Lower Voltage PTF Winter Wheeling Rate or Summer Wheeling Rate for the 1996 calendar year, as determined in accordance with the Prior NEPOOL Agreement; except that the requirements for such payments shall terminate on March 1, 1999 for Participants receiving network service under both the Tariff and applicable Local Network Service Tariff. 17.6 Use of Other Transmission Facilities by Participants. For the period to and including February 28, 1999, each Participant which has no direct connection between its system and PTF shall be entitled to use the non-PTF transmission facilities of any other Participant required to reach its system for any of the purposes for which PTF may be used under Section 17.2. Such use shall be effected, and payment made, in accordance with the other Participant's filed open access tariff. 17.7 Limits on Individual Transmission Charges. Any charges for transmission service pursuant to this Section 17 by any Participant to another Participant shall be just, reasonable and not unduly discriminatory or preferential. No provision of this Section 17 shall be construed to waive the right of any Participant to seek review of any charge, term or condition applicable to such transmission service by another Participant by the Commission or any other regulatory authority having jurisdiction of the transaction. [Next Sheet is 225] SECTION 17A TRANSMISSION OWNERS RESERVED RIGHTS Notwithstanding any other provision of this Agreement, or any other agreement or amendment made in connection with the restructuring of NEPOOL, each Transmission Owner shall retain all of the rights set forth in this Section 17A; provided, however, that such rights shall be exercised in a manner consistent with the Transmission Owner's rights and obligations under the Federal Power Act and the Commission's rules and regulations thereunder. 17A.1 Each Transmission Owner shall have the right at any time unilaterally to file pursuant to Section 205 of the Federal Power Act to change the revenue requirements underlying its component of the rates for service under the NEPOOL Tariff and the transmission- related provisions of this Agreement. 17A.2 Nothing in this Agreement shall restrict any rights, to the extent such rights exist: (a) of Transmission Owners that are parties to a merger, acquisition or other restructuring transaction to make a filing under Section 205 of the Federal Power Act with respect to the reallocation or redistribution of revenues among such Transmission Owners; or (b) of any Transmission Owner to terminate its participation in NEPOOL pursuant to Section 21.2 of this Agreement, notwithstanding any effect its withdrawal from NEPOOL may have on the distribution of transmission revenues among other Transmission Owners. Further, nothing in this Agreement shall be interpreted to permit the adoption of a rate design change that is inconsistent with any settlement under the Tariff accepted by the Commission without the consent of all signatories to the settlement. 17A.3 Each Transmission Owner retains all rights that it otherwise has incident to its ownership of its assets, including, without limitation, its PTF and non-PTF, including the right to build, acquire, sell, merge, dispose of, retire, use as security, or otherwise transfer or convey all or any part of its assets, including, without limitation, the right, individually or collectively, to amend or terminate the Transmission Owner's relationship with the ISO in connection with the creation of an alternative arrangement for the ownership and/or operation of its transmission facilities on an unbundled basis (e.g., a transmission company), subject to necessary regulatory approvals and to any approvals required under applicable provisions of this Agreement. This section is not intended to reduce or limit any other rights of a Transmission Owner as a signatory to this Agreement. 17A.4 The obligation of any Transmission Owner to expand or modify its transmission facilities in accordance with the Tariff shall be subject to the Transmission Owners' right to recover, pursuant to appropriate financial arrangements contained in Commission-accepted tariffs or agreements, all reasonably incurred costs, plus a reasonable return on investment, associated with constructing and owning or financing such expansions or modifications to its facilities. 17A.5 Each Transmission Owner shall have the right to adopt and implement procedures it deems necessary to protect its electric facilities from physical damage or to prevent injury or damage to persons or property. 17A.6 Each Transmission Owner retains the right to take whatever actions it deems necessary to fulfill its obligations under local, state or federal law. 17A.7 In addition to having the rights reserved under other provisions of this Section 17A, all Participants retain the right to take any position before the Commission, and any appellate court with jurisdiction to review a Commission determination, or to seek a determination by the Commission, regarding whether, and the extent to which, the Transmission Owners may retain the exclusive right to make unilateral filings under Section 205 of the Federal Power Act to amend the Tariff and the transmission related provisions of this Agreement. If and to the extent the Commission rules that the Transmission Owners do not retain such rights, then any such amendment that is not subject to any of Section 17A.1 through 17A.6 may be filed with the Commission only upon the approval by the Participants Committee of the amendment under Section 6.11, including Section 6.11(d). If and to the extent the Commission rules that the Transmission Owners do retain such rights, then the Transmission Owners, acting through the Transmission Owners Committee, shall have the exclusive right to make unilateral filings under Section 205 of the Federal Power Act to amend the Tariff and the transmission-related provisions of this Agreement, other than filings subject to Sections 17A.1 or 17A.2. 17A.8 (a) Notwithstanding anything to the contrary in this Agreement, the rights of each Participant under the Federal Power Act shall be preserved. (b) Any dispute over whether a matter falls within the scope of any of the rights reserved under this Section 17A will be subject to resolution pursuant to Section 11.A. (c)No amendment to any provision of this Section 17A or Section 11B may be adopted without the agreement of the Transmission Owners specified in Section 11B. (d) Any agreement entered into between NEPOOL and a System Operator shall require the System Operator to respect the rights reserved under this Section 17A. [Next Sheet is 230] PART FIVE GENERAL SECTION 18 GENERATION AND TRANSMISSION FACILITIES 18.1 Designation of Pool-Planned Facilities. At the request of a Participant, the Participants Committee shall designate as "pool- planned" a generating or transmission facility, for purposes of Chapter 164, Sections 11-22 of the Massachusetts General Laws, to be constructed by the Participant or its Related Person if the Participants Committee determines that the facility is consistent with NEPOOL planning. Designation of a transmission facility as a Pool-Planned Facility does not determine whether or not the facility is PTF. The Participants Committee may not unreasonably withhold designation as a Pool-Planned Facility of a generation unit or other facility proposed by one or more Participants. 18.2 Construction of Facilities. Subject to Sections 13.1, 15.2, 15.5, 18.3, 18.4 and 18.5, and to the provisions of the Tariff, each Participant shall have the right to determine whether, and to what extent, additions to and modifications in its generating and transmission facilities shall be made. However, each Participant shall give due consideration to recommendations made to it by the Participants Committee or the System Operator for any such additions or modifications and shall follow such recommendations unless it determines in good faith that the recommended actions would not be in its best interest. 18.3 Protective Devices for Transmission Facilities and Automatic Generation Control Equipment. Each Participant shall install, maintain and operate such protective equipment and switching, voltage control, load shedding and emergency facilities as the Participants Committee may determine to be required in order to assure continuity of service and the stability of the interconnected transmission facilities of the Participants. Until the Second Effective Date, each Participant shall also install, maintain and operate such Automatic Generation Control equipment as the Participants Committee may determine to be required in order to maintain proper frequency for the interconnected bulk power system of the Participants and to maintain proper power flows into and out of the NEPOOL Control Area. 18.4 Review of Participant's Proposed Plans. Each Participant shall submit to the System Operator, Participants Committee, the Reliability Committee, and the Markets Committee or the Tariff Committee, as appropriate, for review by them, in such form, manner and detail as the Participants Committee may reasonably prescribe, (i) any new or materially changed plan for additions to, retirements of, or changes in the capacity of any supply and demand-side resources or transmission facilities rated 69 kV or above subject to control of such Participant, and (ii) any new or materially changed plan for any other action to be taken by the Participant which may have a significant effect on the stability, reliability or operating characteristics of its system or the system of any other Participant. No significant action (other than preliminary engineering action) leading toward implementation of any such new or changed plan shall be taken earlier than sixty days (or ninety days, if the System Operator or the Participants Committee determines that it requires additional time to consider the plan and so notifies the Participant in writing within the sixty days) after the plan has been submitted to the Committees. Unless prior to the expiration of the sixty or ninety days, whichever is applicable, the Participants Committee notifies the Participant in writing that it has determined that implementation of the plan will have a significant adverse effect upon the reliability or operating characteristics of its system or of the systems of one or more other Participants, the Participant shall be free to proceed. The time limits provided by this Section 18.4 may be changed with respect to any such submission by agreement between the Participants Committee and the Participant required to submit the plan. 18.5 Participant to Avoid Adverse Effect. If the Participants Committee notifies a Participant pursuant to Section 18.4 that implementation of the Participant's plan has been determined to have a significant adverse effect upon the reliability or operating characteristics of its system or the systems of one or more other Participants, the Participant shall not proceed to implement such plan unless the Participant or the Non-Participant on whose behalf the Participant has submitted its plan takes such action or constructs at its expense such facilities as the Participants Committee determines to be reasonably necessary to avoid such adverse effect; provided that if the plan is for the retirement of a supply or demand-side resource, the Participant may proceed with its plan only if, after engaging in good faith negotiations with persons designated by the Participants Committee to address the adverse effects on reliability or operating characteristics, the negotiations either address the adverse effects to the satisfaction of the Participants Committee, or no satisfactory resolution can be achieved on terms acceptable to the parties within 90 days of the Participant's receipt of the Participants Committee's notice. Any agreement resulting from such negotiations shall be in writing and shall be filed in accordance with the Commission's filing requirements if it requires any payment. SECTION 19 EXPENSES 19.1 Annual Fee. Each Participant shall pay to NEPOOL in January of each year an annual fee, which shall be applied toward NEPOOL expenses, as follows: (a) Each End User Participant which is a Small End User or an End User Organization shall pay an annual fee of $500. (b) Each End User Participant which is a Large End User shall pay an annual fee of $500; plus an additional fee of $500 per megawatt hour of its highest Energy use during any hour in the preceding year (net of any use of on-site generation) up to a maximum of $5,000; plus an additional fee of $200 per megawatt hour for each megawatt hour by which its highest Energy use during any hour in the preceding year (net of any use of on- site generation during such hour) exceeded 20 megawatt hours. (c) Each Participant which is a Publicly Owned Entity and a member of the Publicly Owned Entity Sector shall pay an annual fee of $5,000, except that any such Participant which is engaged in electricity distribution and had annual Energy sales of less than 30,000 megawatt hours in the preceding year shall pay an annual fee of $500, and the difference between $5,000 and $500 for each such Participant shall be paid, as an additional fee, by the remaining Participants which are Publicly Owned Entities and members of the Publicly Owned Entity Sector. (d) Each Participant other than an End User Participant or a Publicly Owned Entity shall pay an annual fee of $5,000. 19.2 NEPOOL Expenses. Commencing on January 1, 1999, most expenses of the System Operator are recovered by it directly from Participants and Non-Participants under the ISO's Tariff for Transmission Dispatch and Power Administration (the "ISO Tariff") or through direct charges for services rendered by the ISO, and have ceased to be NEPOOL expenses. At that time, the payment of a portion of NEPEX expenses from the Savings Fund in accordance with the Prior NEPOOL Agreement also terminated. Further, commencing on January 1, 1999 through June 30, 1999, the balance of NEPOOL expenses remaining to be paid after the application of (i) the annual fee to be paid pursuant to Section 19.1 and (ii) any fees or other charges for services or other revenues received by NEPOOL, or collected on its behalf by the System Operator, shall, except as otherwise provided in Section 19.3, be allocated among and paid monthly by the Participants in accordance with their respective voting shares, as determined in accordance with the Agreement provisions in effect during such period. Commencing as of July 1, 1999, such balance of NEPOOL expenses for July and subsequent months shall be divided equally into as many shares as there are active Sectors pursuant to Sector 6.2 (other than an End User Sector) and each Sector's share shall be paid monthly by the Participants in each such Sector (other than an End User Sector) in such manner as the Participants in each Sector may determine by unanimous vote and advise the ISO, provided that if the Participants in a Sector fail to agree unanimously on the allocation of their Sector's share, the Participants in the Sector shall pay for such Sector share in the same proportion as the vote they are entitled to in the Sector. Participants in the Sector that are represented by a group voting member shall subdivide their portion of the Sector's share of expenses in such a manner as they may determine by unanimous agreement; provided that if there is not unanimous agreement among the Participants represented by a group member as to how to allocate their portion of the Sector's share of expenses, such portion shall be allocated among the Participants represented by that group member as follows: (i) for each Participant in the Generation Sector represented by a group voting member, the portion will be allocated in the same proportion that the Megawatts of generation owned by the Participants represents of the total Megawatts owned by Participants represented by the group voting member; and (ii) for Participants in the Transmission Sector, the portion will be allocated equally among the Participants represented by the group member. Notwithstanding the foregoing, no portion of such balance shall be paid by End User Participants and, until such time as an End User Sector is activated, the monthly share allocated to the Publicly Owned Entity Sector shall be reduced by one-twelfth of the aggregate annual fees paid by End Users for the year pursuant to Section 19.1 and one-third of the amount of such reduction shall be allocated to each of the other three Sectors. 19.3 Restructuring Costs. (a) The expense of restructuring NEPOOL ("Restructuring Expense"), including but not limited to (i) software development, hardware and system software costs for implementation of the Tariff and the new market system, (ii) the costs of the formation of the Independent System Operator and related separation costs, (iii) legal and consultant costs related to the amendment of the NEPOOL Agreement (including the Tariff) and the proceeding with respect thereto at the Federal Energy Regulatory Commission, and (iv) capital expenditures and capitalized project costs of the Independent System Operator, shall be funded (to the extent not already funded) and amortized according to this Section 19.3. (b) The Restructuring Expense incurred (other than certain capital expenditures and capitalized project costs funded separately by the ISO) before the Second Effective Date (the "Early Restructuring Expense") has been funded during the period prior to such date by those entities which have been the Participants during such period. Commencing at the Second Effective Date, the Early Restructuring Expense shall be amortized in equal monthly amounts and repaid over the next 60 months with interest thereon from the date of payment to August 18, 2000 at the rate of 8% per annum, and thereafter at the rate equal to the average Weighted Costs of Capital of all Transmission Providers in effect on October 20, 1999 (without subsequent adjustment) determined pursuant to Section II(A)(2)(a) of the Implementation Rule for Calculating Annual Transmission Revenue Requirements files as a supplement to the Tariff. Each month during the first twenty months of such period each Participant shall pay its percentage "X", as determined below, of 1/60th of the Early Restructuring Expense, plus accumulated interest, and each Participant or other Entity which previously paid an unreimbursed portion of the aggregate Early Restructuring Expense shall be entitled to receive each month its percentage "Y", as determined below, of the aggregate amount to be paid for the month, including accumulated interest. "X" and "Y" shall be determined in accordance with the following formulas: X = A /A1 in which X is the percentage to be paid for a month by a Participant of the aggregate amount payable pursuant to this subsection (b) by all Participants for the month. A is the amount payable by the Participant for the month under Schedule 2 (Energy Administration Services) of the ISO Tariff (as defined in Section 19.2) as amended or revised from time to time. A1 is the aggregate amount payable by all Participants for the month under Schedule 2 (Energy Administration Services) of the ISO Tariff as amended or revised from time to time. Y = B/B1 in which Y is the percentage to be received for a month by a Participant or other Entity of the aggregate amount to be received pursuant to this subsection (b) by all Participants or other Entities for the month. B is the amount of Early Restructuring Expense paid by the Participant or other Entity which has not previously been reimbursed. B1 is the aggregate amount of Early Restructuring Expense paid by all Participants and other Entities which has not previously been reimbursed. Notwithstanding the foregoing, the Participants will amend the Agreement by November 1, 2000 to specify how the balance of the Early Restructuring Expense is to be paid. It is also understood that the Commission could order refunds and reallocations with respect to amounts collected under Schedule 2 of the ISO Tariff for 2000. To the extent such refunds and reallocations are ordered by the Commission, refunds and reallocations of Early Restructuring Expenses shall also be made so that the total amount of Early Restructuring Expenses collected from each Participant in 2000 shall be proportionate to the amount ultimately due from such Participant in 2000 under Schedule 2 of the ISO Tariff. (c) The Restructuring Expense incurred on the Second Effective Date and to but not including January 1, 2000 or thereafter shall be funded each month by the Participants in proportion to the Member Fixed Voting Shares (as defined in Section 6.9(c)) of each Participant as in effect at the beginning of the month provided, however, that in calculating the allocation of this portion of the Restructuring Expense, the Member Fixed Voting Shares of End User Participants that participate in NEPOOL for governance purposes only in accordance with NEPOOL's Standard Membership Conditions, Waivers and Reminders ("Governance Only End User Participants") shall not be included in such calculations and the amounts that would otherwise have been payable by such Governance Only End User Participants will be allocated to all of the other Participants on the basis of their Member Fixed Voting Shares. (d) The Restructuring Expense incurred on or after January 1, 2000 (the "Late Restructuring Expense") shall initially be funded for each month, on an as incurred basis, by the Participants in proportion to their charges under the ISO Tariff for the prior month. The aggregate Late Restructuring Expense funded in any calendar year shall be amortized in equal monthly amounts and repaid over the next 60 months, commencing in January of the immediately succeeding calendar year, with interest thereon from the date of payment at the rate equal to the average Weighted Costs of Capital of all Transmission Providers in effect on October 20, 1999 (without subsequent adjustment) determined pursuant to Section II(A)(2)(a) of the Implementation Rule for Calculating Annual Transmission Revenue Requirements filed as a supplement to the Tariff. Thus, for example, the Late Restructuring Expense incurred in 2000 will be amortized and repaid over a 60-month period commencing in January 2001. Each month during the applicable amortization period each Participant shall pay its share of the portion of the Late Restructuring Expense being amortized during such period, plus accumulated interest, and each Participant or other Entity which previously paid an unreimbursed portion of the aggregate Late Restructuring Expense being amortized during such period shall be entitled to receive its share of the aggregate amount paid for such month, including accumulated interest, according to an allocation methodology that is based on the appropriate schedules of the ISO Tariff, which allocation methodology will be established under subsection (e) below. (a) The Participants agree to amend the Agreement within eighteen months after the Second Effective Date to specify how the balance of the Early Restructuring Expense is to be paid. The Participants agree to amend the Agreement by November 1, 2000 to provide for the amortization and repayment of the Late Restructuring Expense, according to an allocation methodology that is based on the appropriate schedules of the ISO Tariff as approved by the Commission with such amendment to become effective on January 1, 2001, or on such other date as the Commission shall provide that such amendment shall become effective. (b) The funding methodology set forth in subsection (d) shall terminate automatically upon the implementation of a permanent restructuring funding methodology acceptable to the Participants Committee and the ISO, to the extent superseded by such permanent restructuring funding methodology. SECTION 20 SECTION 20 INDEPENDENT SYSTEM OPERATOR (a) The Participants Committee is authorized and directed to approve one or more agreements to be entered into with the ISO (the "ISO Agreement") and any amendments to the ISO Agreement which the Committee may deem necessary or appropriate from time to time. The ISO Agreement shall specify the rights and responsibilities of NEPOOL and the ISO, for the continued operation of the NEPOOL control center by the ISO as the control center operator for the NEPOOL Control Area and the administration of the Tariff. In addition, the ISO shall be responsible for the furnishing of billing and other services required by NEPOOL. (b) The fees and charges of the ISO (other than those recovered under the ISO Tariff, as defined in Section 19.2, and fees and charges for services which are separately billed), and any indemnification payable under the ISO Agreement, shall be shared by the Participants in accordance with Section 19. (c) The Participants shall provide to the ISO the financial support, information and other resources necessary to enable the ISO to provide the services specified in the ISO Agreement, or in this Agreement, in accordance with Accepted Electric Industry Practice and subject to the budgeting, approval and dispute resolution provisions of the ISO Agreement and this Agreement. (d) The Participants shall provide appropriate funding for the acquisition of land, structures, fixtures, equipment and facilities, and other capital expenditures and capitalized project expenditures for the ISO, which are included in the annual budget for the ISO in accordance with the provisions of the ISO Agreement, or otherwise specifically approved by the Participants Committee. All such land, structures, fixtures, equipment and facilities, and other capital assets, and all software or other intellectual property or rights to intellectual property or other assets acquired or developed by the ISO in order to carry out its responsibilities under the ISO Agreement shall be the property of the Participants or shall be acquired by the Participants under lease in accordance with arrangements approved by the Participants Committee. For those Participants subject to the Public Utility Holding Company Act of 1935 ("PUHCA"), any such acquisition by those Participants is subject to PUHCA approval to the extent such acquisition requires approval under PUHCA. Unless otherwise agreed by the Participants, the funding of the acquisition, or lease, of land, structures, fixtures, equipment and facilities, and other capital and/or capitalized project related expenditures, or the acquisition of other assets, and the ownership thereof, or the obligations of Participants as lessees, shall be in accordance with Section 19.3 of this Agreement. The Participants shall make all such assets (including the assets of the existing NEPOOL headquarters and control center) available for use by the ISO in carrying out its responsibilities under the ISO Agreement. The ISO Agreement shall require the ISO, on behalf of the Participants, to maintain and care for, insure as appropriate, and pay any property taxes relating to, assets made available for its use. (e) The ISO Agreement shall require the ISO to refrain from any action that would create any lien, security interest or encumbrance of any kind upon the facilities, equipment or other assets of any Participant, or upon anything that becomes affixed to such facilities, equipment or other assets. The Participants and the ISO shall include in the ISO Agreement a provision that, upon the request of any Participant, the ISO shall (i) provide a written statement that it has taken no action that would create any such lien, security interest or encumbrance, and (ii) take all actions within the control of the ISO, at the direction and expense of the requesting Participant, required for compliance by such Participant with the provisions of its mortgage relating to such facilities, equipment or other assets. (f) The ISO shall have the right to appoint a non-voting member and an alternate to each NEPOOL committee other than the Participants Committee. The member appointed to each committee shall have all of the rights of any other member of the committee except the right to vote. (g) The ISO shall have the same rights as a Participant to appeal to the Participants Committee any action taken by any other NEPOOL committee, and shall be entitled to appear before the Participants Committee on any such appeal. Further, the ISO shall be entitled to submit any dispute with respect to a vote of the Participants Committee to approve, modify, or reject a proposed action to resolution in accordance with Section 21.1, whether or not the action could have been submitted by a Participant in accordance with Section 21.1A. In addition, the ISO shall be entitled to submit any dispute with respect to a vote of the Participants Committee which denies an appeal to the Participants Committee by the ISO or which takes action on any rulemaking issue to the Board of Directors of the ISO for determination, subject to the right of the Participants Committee to seek a review in accordance with the Alternate Dispute Resolution procedures or by the Commission. The ISO shall give notice of any such submission to the Secretary of the Participants Committee within ten days of the action of the Participants Committee and shall mail a copy of such notice to each member of the Participants Committee. Pending final action on the submission in accordance with Section 21.1 or by the Board of Directors of the ISO or the Commission, as appropriate, the giving of notice of the submission shall suspend the Participants Committee's action. Unless the Board of Directors of the ISO acts within 60 days of the ISO's notice to the Participants Committee, the Participants Committee action will be deemed to be approved. (h) The ISO Agreement shall specify the ISO's independent authority with respect to rulemaking. (i) NEPOOL and its committees and the ISO shall consult and coordinate from time to time with the relevant state regulatory, siting and other authorities of the six New England states on operating, planning and other issues of concern to the states. The New England Conference of Public Utilities Commissioners, Inc. ("NECPUC") or its designee shall be furnished notices of meetings of all NEPOOL committees and the Board of Directors of the ISO, and minutes of their meetings. NECPUC and other state authorities shall be provided an appropriate opportunity to appear at meetings of the NEPOOL committees and the Board of Directors of the ISO and to present their views. Representatives of NEPOOL and the ISO shall be designated to attend meetings of NECPUC or any committee or task force of NECPUC, to the extent NECPUC or its committee or task force may deem such attendance appropriate. (j) Appointment of Technical Committee Officers. The System Operator shall, after its chief executive officer has conferred with the Participant members of the Liaison Committee regarding such appointment(s), appoint the Chair and Secretary of each of the Technical Committees. Each individual appointed by the System Operator shall be an independent person not affiliated with any Participant. Before appointing an individual to the position of Chair or Secretary, the System Operator shall notify the Committee to which such officer is being appointed of the proposed assignment and, consistent with its personnel practices, provide any other information about the individual reasonably requested by the Committee. In the event that a Technical Committee determines that the performance of the Chair or Secretary of the Committee is not satisfactory, the Committee shall provide notice to the System Operator that such performance deficiencies must be corrected within 60 days. If the Committee determines that the performance deficiencies have not been corrected within the 60-day period, the Committee may vote to remove the officer, subject to appeal to the Participants Committee. A vote of the Technical Committee to remove its officer shall be immediately effective and binding on the System Operator and shall cause the System Operator to appoint a replacement officer in accordance with the provisions of this Section 20(j) unless an appeal to the Participants Committee has been taken prior to the end of the tenth business day following the vote to remove the officer in which case the vote for removal shall be subject to the outcome of such appeal. A vote of the Participants Committee with respect to any such appeal shall be immediately effective and binding on the System Operator and not subject to any further appeals. SECTION 21 MISCELLANEOUS PROVISIONS 21.1 Alternative Dispute Resolution. A. General: If the ISO is aggrieved by a vote of the Participants Committee to approve, modify or reject a proposed action under this Agreement, including the Tariff, it may submit the matter for resolution hereunder. If the Participants Committee is aggrieved by an action of the ISO Board of Directors ("ISO Board") under this Agreement, including the Tariff or the ISO Agreement (as defined in Section 20(a)), the Participants Committee may submit the matter for resolution hereunder; provided, however, that if the action of the ISO relates to rulemaking, the Participants Committee may submit the matters for resolution under this Section 21.1 only with the concurrence of the ISO. Any Participant which is aggrieved by a vote of the Participants Committee to approve, modify or reject a proposed action under this Agreement, including the Tariff, may, as provided below, submit the matter for resolution hereunder if the vote: (1) requires such Participant to make a payment or to take any action pursuant to this Agreement; or (2) reduces the amount of any receipt or forbids, pursuant to this Agreement, the taking of any action by the Participant; or (3) fails to afford it any right to which it is entitled under the provisions of this Agreement or imposes on it a burden to which it is not subject under the provisions of this Agreement; or (4) results in the termination of the Participant's status as a Participant or imposes any penalty on the Participant; or (5) results in an allocation of transmission or other facilities support obligations; or (6) fails to grant in full an application for transmission service pursuant to the Tariff. No legal or regulatory proceeding (except those reasonably necessary to toll statutes of limitations, claims for laches or other bars to later legal or regulatory action) shall be initiated by any Participant with respect to any such matter while proceedings are pending under this Section with respect to the matter. A. Procedure: (1) Submission of a Dispute: The ISO or a Participant seeking review of a vote of the Participants Committee shall give written notice to the Secretary of the Participants Committee within ten business days of the vote, and shall mail or telecopy a copy of its notice to each member of the Participants Committee. Where the Participants Committee is seeking review of an action of the ISO Board, the Participants Committee shall give written notice to the Secretary of the ISO Board. The provider of notice under this Section shall be referred to herein as the "Aggrieved Party." (2) Suspension of Action: If the ISO seeks review of a vote of the Participants Committee pursuant to this Section, the vote to be reviewed shall be suspended pending resolution of such review by the arbitrator or the Commission if raised in regulatory proceedings. If a Participant seeks such a review, the vote to be reviewed shall be suspended for up to 90 days following the giving of the Participant's notice pending resolution of any arbitration proceeding unless the Participants Committee determines that the suspension will imperil the stability or reliability of the NEPOOL Control Area bulk power supply. (3) Aggrieved Party Options: (i) If the notice is to seek review of a vote of the Participants Committee, the Aggrieved Party's notice to the Participants Committee shall invoke arbitration as described herein in its notice pursuant to paragraph B(1), and may also initiate mediation with the agreement of the Participants Committee, while reserving such Party's right to proceed with the arbitration if mediation does not resolve the matter within 20 days of the giving of the Party's notice or such longer period as may be fixed by mutual agreement of the Participants Committee and the Aggrieved Party. Notwithstanding the initiation of mediation, the arbitration proceeding shall proceed concurrently with the selection of the arbitrator pursuant to paragraph C(1) of this Section 21.1. (ii) If the notice is to seek review of an ISO action, the Participants Committee's notice to the ISO Board shall (subject to the concurrence of the ISO for actions relating to rulemaking as provided in Section 21.1A) invoke arbitration as described herein in its notice pursuant to paragraph B(1), and may also initiate mediation with the agreement of the ISO Board, while reserving the Participants Committee's right to proceed with the arbitration if mediation does not resolve the matter within 20 days of the giving of the Participants Committee's notice or such longer period as may be fixed by mutual agreement of the ISO Board and the Participants Committee. Notwithstanding the initiation of mediation, the arbitration proceeding shall proceed concurrently with the selection of the arbitrator pursuant to paragraph C(1) of this Section 21.1. (4) Mediation Positions not to be Used Elsewhere: All mediation proceedings pursuant to this Section are confidential and shall be treated as compromise and settlement negotiations for purposes of applicable rules of evidence. (5) Time Limits; Duration: Any other Participant that wishes to participate in an arbitration proceeding hereunder shall give signed written notice to the Secretary of the Participants Committee, and to the Secretary of the ISO Board if the ISO is involved in such arbitration, no later than ten calendar days after the giving of the notice of arbitration. The arbitration procedure shall not exceed 90 calendar days from the date of the Aggrieved Party's notice invoking arbitration to the arbitrator's decision unless the parties agree upon a longer or shorter time. All agreements by the ISO or the aggrieved Participant and the Participants Committee to use mediation shall establish a schedule which will control unless later changed by mutual agreement. B. Arbitration: (1) Selection of Arbitrator: The ISO or the aggrieved Participant and the Participants Committee shall attempt to choose by mutual agreement a single neutral arbitrator to hear the dispute. If the ISO or the Participant and the Participants Committee fail to agree upon a single arbitrator within ten calendar days of the giving of notice of arbitration to the Secretary of the Participants Committee or the Secretary of the ISO Board, as the case may be, the American Arbitration Association shall be asked to appoint an arbitrator. In either case, the arbitrator shall be knowledgeable in matters involving the electric power industry, including the operation of control areas and bulk power systems, and shall not have any substantial business or financial relationships with the ISO, NEPOOL or its Participants (other than previous experience as an arbitrator) unless otherwise mutually agreed by the ISO or the aggrieved Participant and the Participants Committee. (2) Costs: NEPOOL shall be responsible for all of the costs of the proceeding if it is initiated by the ISO or by the Participants Committee. If a proceeding is initiated by an aggrieved Participant, each party shall be responsible for the following costs, if applicable: (i) its own costs incurred during the arbitration process (except that this does not preclude billing the aggrieved Participant for its share of NEPOOL Expenses that may include the Participants Committee's arbitration costs); plus (ii) One half of the common costs of the arbitration including, but not limited to, the arbitrator's fee and expenses, the rental charge for a hearing room and the cost of a court reporter and transcript, if required. (3) Hearing Location: Unless otherwise mutually agreed, the site for all arbitration hearings shall be NEPOOL counsel's office. D. Rules and Procedures: (1) Procedure and Discovery: The procedural rules (if any), the conduct of the arbitration and the availability, extent and duration of pre-hearing discovery (if any), which shall be limited to the minimum necessary to resolve the matters in dispute, shall be determined by the arbitrator in his/her sole discretion at or prior to the initial hearing. (2) Pre-hearing Submissions: The Aggrieved Party shall provide the arbitrator with a brief written statement of its complaint and a statement of the remedy or remedies it seeks, accompanied by copies of any documents or other materials it wishes the arbitrator to review. The Participants Committee will provide the arbitrator with a copy of this Agreement and all relevant implementing documents, a brief description of the action being arbitrated, copies of the minutes of all NEPOOL committee meetings at which the matter was discussed, a brief statement explaining why the Participants Committee believes its decision should be upheld by the arbitrator, and copies of any documents or other materials the Participants Committee wishes the arbitrator to review. If the Participants Committee is the Aggrieved Party, the ISO Board will provide copies of minutes of the ISO Board meetings at which the matter was discussed, a brief statement explaining why the ISO Board believes its decision should be upheld by the arbitrator, and copies of any documents or other materials the ISO Board wishes the arbitrator to review. These submissions shall be made within five days after the selection of the arbitrator. In addition, each party shall designate one or more individuals to be available to answer questions the arbitrator may have on the documents or other materials submitted by that party. The answers to all such questions shall be reduced to writing by the party providing the answer and a copy shall be furnished to the other party. (3) Initial Hearing: An initial hearing will be held no later than 10 days after the selection of the arbitrator and shall be limited to issues raised in the pre-hearing filings. The scheduling of further hearings at the request of either party or on the arbitrator's own motion shall be within the sole discretion of the arbitrator. (4) Decision: The arbitrator's decision shall be due, unless the deadline is extended by mutual agreement of the ISO or the aggrieved Participant and the Participants Committee, within sixty days of the initial hearing or within ninety days of the Aggrieved Party's initiation of arbitration, whichever occurs first. The arbitrator shall be authorized only to interpret and apply the provisions of this Agreement and the arbitrator shall have no power to modify or change the Agreement in any manner. (5) Effect of Arbitration Decision: The decision of the arbitrator will be conclusive in a subsequent regulatory or legal proceeding as to the facts determined by the arbitrator but will not be conclusive as to the law or constitute precedent on issues of law in any subsequent regulatory or legal proceedings. An aggrieved party may initiate a proceeding with a court or with the Commission with respect to the arbitration or arbitrator's decision only: if the arbitration process does not result in a decision within the time period specified and the proceeding is initiated within thirty days after the expiration of such time period; or on the grounds specified in Sections 10 and 11 of Title 9 of the United States Code for judicial vacation or modification of an arbitration award and the proceeding is initiated within thirty days of the issuance of the arbitrator's decision. (6) Other Disputes: In the event a dispute arises with a Non-Participant which receives or is eligible to receive service under this Agreement or the Tariff with respect to such service, the Non-Participant shall have the right to have the dispute considered by the Participants Committee. In the event the Non-Participant is aggrieved by the Participants Committee's vote on the dispute, and the vote has any of the effects specified in paragraph A of this Section 21.1, the aggrieved Non- Participant may require that the dispute be resolved in accordance with this Section 21.1. To the extent that NEPOOL provides services to Non-Participants under separate agreements, the Participants Committee shall incorporate the provisions of this Section by reference in any such agreement, in which case the term "Participant" shall be deemed for purposes of the dispute resolution provisions to include such Non-Participant purchasers of NEPOOL services. 21.2 Payment of Pool Charges; Termination of Status as Participant. (a) Any Participant shall have the right to terminate its status as a Participant upon no less than six months' prior written notice given to the Secretary of the Participants Committee. (b) If at any time during the term of this Agreement a receiver or trustee of a Participant is appointed or a Participant is adjudicated bankrupt or an order for relief is entered under the Federal Bankruptcy Code against a Participant or if there shall be filed against any Participant in any court (pursuant to the Federal Bankruptcy Code or any statute of Canada or any state or province) a petition in bankruptcy or insolvency or for reorganization or for appointment of a receiver or trustee of all or a portion of the Participant's property, and within ninety days after the filing of such a petition against the Participant, the Participant shall fail to secure a discharge thereof, or if any Participant shall file a petition in voluntary bankruptcy or seeking relief under any provision of any bankruptcy or insolvency law or shall make an assignment for the benefit of creditors, the Participants Committee may terminate such Participant's status as a Participant as of any time thereafter. (c) Each Participant is obligated to pay when due in accordance with NEPOOL procedures all amounts invoiced to it by NEPOOL, or by the ISO on behalf of NEPOOL. If the Participant fails to meet this requirement for continuation of service, the actions described in subsection (d) of this Section 21.2 may be taken. If a Participant disputes a NEPOOL invoice with respect to charges for transmission service in whole or part, it shall be entitled to continue to receive service under the Agreement and the Tariff, so long as the Participant (i) continues to make all payments not in dispute, and (ii) pays into an independent escrow account the portion of the invoice in dispute, pending resolution of the dispute. (d) In the event a Participant fails to pay when due in accordance with NEPOOL System Rules (including, without limitation, the NEPOOL Billing Policy attached to the Tariff (the "Billing Policy")) all amounts invoiced to it by NEPOOL, or by the ISO on behalf of NEPOOL (a "Payment Default"), or the Participant fails to comply with the Financial Assurance Policy for NEPOOL Members attached to the Tariff (the "Member Financial Assurance Policy"), or the Participant fails to perform any other obligations under the Agreement or the Tariff, and such failure continues for at least ten days, NEPOOL, or the ISO on behalf of NEPOOL, may (but shall not be required to) notify such Participant in writing, electronically and by first class mail sent in each case to such Participant's member or alternate on the Participants Committee or billing contact, that it is in default, and NEPOOL may initiate a proceeding before the Commission to terminate such Participant's status as a Participant. Either simultaneously with the giving of the notice described in the preceding sentence or within ten days thereafter (unless the default or failure giving rise to such notice is cured during such period), NEPOOL, or the ISO on behalf of NEPOOL, shall notify each other member and alternate on the Participants Committee and each Participant's billing contact of the identity of the Participant receiving such notice, whether such notice relates to a Payment Default, to a failure to comply with the Member Financial Assurance Policy, or to another failure to perform obligations under the Agreement or the Tariff, and the actions the ISO plans to take and/or has taken in response to such default or failure. Pending Commission action on such termination, NEPOOL may suspend service, in whole or part, to the Participant on or after 50 days after the giving of notice and the initiation of such proceeding, in accordance with [Next Sheet is 265] Commission policy, unless the Participant cures the default within such 50-day period. (e) If the status of a Participant as a Participant is terminated pursuant to this Section 21.2 or any other provision of this Agreement, such former Participant's generation and transmission facilities shall continue to be subject to such NEPOOL or other requirements relating to reliability as the Commission may approve in acting on the termination, for so long as the Commission may direct. Further, if any of such former Participant's transmission facilities are required in order to permit transactions among any of the remaining Participants pursuant to this Agreement or the Tariff, all pending requests for transmission service under the Tariff relating to such Participant's facilities shall be followed to completion under the Participant's own tariff and all existing service over the Participant's facilities shall continue to be provided under the Tariff for a period of three years. It is the intent of this subsection that no such termination should be allowed to jeopardize the reliability of the bulk power facilities of any remaining Participant or should be allowed to impose any unreasonable financial burden on any remaining Participant. (f) No such termination of a Participant's status as a Participant shall affect any obligation of, or to, such former Participant incurred prior to the effective time of such termination. 21.3 Assignment. The Agreement shall inure to the benefit of, and shall be binding upon, the successors and assigns of the respective signatories hereto, but no assignment of a signatory's interests or obligations under the Agreement or any portion thereof shall be made without the written consent of the Participants Committee, except as otherwise permitted by the Tariff, or except in connection with a sale, merger, or consolidation which results in the transfer of all or a portion of a signatory's generation or transmission assets to, and the assumption of all of the obligations of the signatory under this Agreement (or in the case of a transfer of a portion of a signatory's generation or transmission assets, the assumption of obligations of the signatory under this Agreement with respect to such assets) by, an acquiring or surviving Entity which either is, or concurrently becomes, a Participant, or agrees to assume such of the signatory's obligations with respect to such assets as the Participants Committee may reasonably require, or except in connection with the grant of a security interest in a Participant's assets as security for bonds or other financing. 21.4 Force Majeure. A Participant shall not be considered to be in default in respect of any obligation hereunder if prevented from fulfilling such obligation by an event of Force Majeure. An event of Force Majeure means any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, any Curtailment, any order, regulation or restriction imposed by a court or governmental military or lawfully established civilian authorities, or any other cause beyond a Participant's control, provided that no event of Force Majeure affecting any Participant shall excuse that Participant from making any payment that it is obligated to make under this Agreement. A Participant whose performance under this Agreement is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations under this Agreement, and shall promptly notify the Participants Committee of the commencement and end of any event of Force Majeure. 21.5 Waiver of Defaults. No waiver of the performance by a Participant of any obligation under this Agreement or with respect to any default or any other matter arising in connection with this Agreement shall be effective unless given by the Participants Committee. Any such waiver by the Participants Committee in any particular instance shall not be deemed a waiver with respect to any subsequent performance, default or matter. 21.6 Other Contracts. No Participant shall be a party to any other agreement which in any manner is inconsistent with its obligations under this Agreement. 21.7 Liability and Insurance. (a) Each Participant will indemnify and save each of the other Participants, its officers, directors and Related Persons (each an "Indemnified Party") harmless from and against all actions, claims, demands, costs, damages and liabilities asserted by a third party against the Indemnified Party seeking indemnification and arising out of or relating to bodily injury, death or damage to property caused by or sustained on facilities owned or controlled by such Participant that are the subject of this Agreement, or caused by a failure to act in accordance with this Agreement by the Participant from which indemnification is sought, except (i) to the extent that such liabilities result from the negligence or willful misconduct of the Participant seeking indemnification, and (ii) each Participant shall be responsible for all claims of its own employees, agents and servants growing out of any workmen's compensation law. The amount of any indemnity payment under the provisions of this Section 21.7 shall be reduced (including, without limitation, retroactively) by any insurance proceeds or other amounts actually recovered by the Indemnified Party in respect of the indemnified action, claim, demand, cost, damage or liability. Notwithstanding the foregoing, no Participant shall be liable to any Indemnified Party for any claim for loss of profits or revenues, attorneys' fees or costs, cost of capital or financing, loss of goodwill or cost of replacement power arising from a Participant's carrying out, or failing to carry out, any obligations contemplated by this Agreement or for any other indirect, incidental, special, consequential, punitive, or multiple damages or loss; provided, however, that nothing herein shall reduce or limit the obligations of any Participant to Non-Participants. (b) Each Participant shall furnish, at its sole expense, such insurance coverage as the Participants Committee may reasonably require with respect to its obligation pursuant to Section 21.7(a). 21.8 Records and Information. Each Participant shall keep such records as may reasonably be required by a NEPOOL committee or the System Operator, and shall furnish to such committee or the System Operator such records, reports and information (including forecasts) as it may reasonably require, provided the confidentiality thereof is protected in accordance with NEPOOL's information policy. 21.9 Consistency with NPCC and NERC Standards. The standards, criteria and rules adopted by NEPOOL committees under this Agreement shall be consistent with those adopted by the NPCC and NERC or any successor to either. 21.10 Construction. (a) The Table of Contents contained in this Agreement and the headings of the Sections of this Agreement are intended for convenience only and shall not be deemed to be part of this Agreement or considered in construing it. (b) This Agreement shall be interpreted, construed and governed in accordance with the laws of the State of Connecticut. 21.11 Amendment. Subject to Section 17A and the provisions of this Section, this Agreement, including the Tariff, and any attachment or exhibit hereto may be amended from time to time by vote of the Participants in accordance with Section 6.11. Any amendment to this Agreement approved in accordance with Section 6.11 and/or Section 17A shall be in writing and shall become effective, and shall bind all Participants regardless of whether they have executed a ballot in favor of such amendment, on the date specified in the amendment, subject to acceptance or approval by the Commission. Nothing herein shall be construed to prevent any Participant from challenging any proposed amendment before a court or regulatory agency on the ground that the proposed amendment or its application to the Participant is in violation of law or of this Agreement. 21.12 Termination. This Agreement shall continue in effect until terminated, in accordance with the Commission's regulations, by Participants represented by members of the Participants Committee having Member Fixed Voting Shares equal to at least 70% of the Member Fixed Voting Shares of all Participants. No such termination shall relieve any party of any obligation arising prior to the effective time of such termination. 21.13 Notices to Participants, Committees, Committee Members, or the System Operator. (a) Any notice, demand, request or other communication required or authorized by this Agreement to be given to any Participant shall be in writing, and shall be (1) personally delivered to the Participants Committee member or alternate representing that Participant; (2) mailed, postage prepaid, to the Participant at the address of its member on the Participants Committee as set out in the NEPOOL roster; (3) sent by facsimile ("faxed") to the Participant at the fax number of its member on the Participants Committee as set out in the NEPOOL roster; or (4) delivered electronically to the Participant at the electronic mail address of its member on the Participants Committee or at the address of its principal office. The designation of any such address may be changed at any time by written notice delivered to the Secretary of the Participants Committee, who shall cause such change to be reflected in the NEPOOL roster. (b) Any notice, demand, request or other communication required or authorized by this Agreement to be given to any NEPOOL committee shall be in writing and shall be delivered to the Secretary of the committee. Each such notice shall either be personally delivered to the Secretary, mailed, postage prepaid, or sent by facsimile ("faxed") to the Secretary at the address or fax number set out in the NEPOOL roster, or delivered electronically to the Secretary. The designation of such address may be changed at any time by written notice delivered to each Participant. (c) Any notice, demand, request or other communication required or authorized by this Agreement to be given to a member or alternate to that member of a Principal Committee (for the purposes of this Section 21.13, individually or collectively, the "Committee Member") shall be (1) personally delivered to the Committee Member; (2) mailed, postage prepaid, to the Committee Member at the address of the Committee Member set out in the NEPOOL roster; (3) sent by facsimile ("faxed") to the Committee Member at the fax number of the Committee Member set out in the NEPOOL roster; or (4) delivered electronically to the Committee Member at the electronic mail address of the Committee Member set out in the NEPOOL roster. The designation of any such address may be changed at any time by written notice delivered to the Secretary of the Principal Committee on which the Committee Member serves, who shall cause such change to be reflected in the NEPOOL roster. (d) Any notice, demand, request or other communication required or authorized by this Agreement to be given to the System Operator shall be in writing, and shall be (1) personally delivered to the Participants Committee member or alternate appointed by the System Operator; (2) mailed, postage prepaid, to the System Operator at the address of its member on the Participants Committee as set out in the NEPOOL roster; (3) sent by facsimile ("faxed") to the System Operator at the fax number of its member on the Participants Committee as set out in the NEPOOL roster; or (4) delivered electronically to the System Operator at the electronic mail address of its member on the Participants Committee or at the address of its principal office. The designation of any such address may be changed at any time by written notice delivered to the Secretary of the Participants Committee, who shall cause such change to be reflected in the NEPOOL roster. (e) To the extent that the Participants Committee is required to serve upon any Participant a copy of any document or correspondence filed with the Commission under the Federal Power Act or the Commission's rules and regulations thereunder, by or on behalf of any Principal Committee, such service may be accomplished by electronic delivery to the Participant at the electronic mail address of its Participants Committee member and alternate. The designation of any such address may be changed at any time by written notice delivered to the Secretary of the Participants Committee. (f) Any such notice, demand or request so addressed and mailed by registered or certified mail shall be deemed to be given when so mailed. Any such notice, demand, request or other communication sent by regular mail or by facsimile ("faxed") or delivered electronically shall be deemed given when received by the Participant, Committee Member, System Operator, or Secretary of the NEPOOL committee, whichever is applicable. 21.14 Severability and Renegotiation. If any provision of this Agreement is held by a court or regulatory authority of competent jurisdiction to be invalid, void or unenforceable, the remainder of the terms, provisions, covenants and restrictions of this Agreement shall continue in full force and effect and shall in no way be affected, impaired or invalidated, except as otherwise explicitly provided in this Section. If any provision of this Agreement is held by a court or regulatory authority of competent jurisdiction to be invalid, void or unenforceable, or if the Agreement is modified or conditioned by a regulatory authority exercising jurisdiction over this Agreement, the Participants shall endeavor in good faith to negotiate such amendment or amendments to this Agreement as will restore the relative benefits and obligations of the Participants under this Agreement immediately prior to such holding, modification or condition. If after sixty days such negotiations are unsuccessful the Participants may exercise their withdrawal or termination rights under this Agreement. 21.15 No Third-Party Beneficiaries. Except for the provisions of this Agreement and the Tariff which provide for service to Non- Participants, this Agreement is intended to be solely for the benefit of the Participants and their respective successors and permitted assigns and, unless expressly stated herein, is not intended to and shall not confer any rights or benefits on any third party (other than successors and permitted assigns) not a signatory hereto. 21.16 Counterparts. This Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument and as if all the parties to all of the counterparts had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this Agreement identical in form hereto but having attached to it one or more signature pages. IN WITNESS WHEREOF, the signatories have caused this Agreement to be executed by their duly authorized officers or representatives. Sheet Nos. 279 through 299 are reserved for future use. ATTACHMENT A METHODOLOGY FOR DETERMINATION OF TRANSMISSION FLOWS The methodology for determining parallel path transmission flows to be used in determining the distribution of revenues received for Regional Network Service provided during the Transition Period, or for Through or Out Service, is as follows, and shall be determined (1) on the basis of the flows for all transactions in the NEPOOL Control Area ("Regional Flows") for the purpose of allocating during the Transition Period Regional Network Service revenues, and (2) on the basis of the flows for the particular transaction ("Transaction Flows") for the purpose of allocating revenues during or after the Transition Period from the furnishing of Through or Out Service: A. Responsibility for Calculations The calculation of megawatt mile allocations in accordance with this methodology shall be performed under the direction of the Reliability Committee. B. Periodic Review Calculations of MW-Mile allocations shall be performed whenever significant changes to the transmission system load flows, as determined by the Reliability Committee, occur. C. Facilities Included in the Analysis 1. Transmission Lines A calculation of MW-miles shall be determined for all PTF lines. 2. Generators The analysis shall include all generators with a Winter Capability equal to or greater than 10.0 MW. Multiple generators connected to a single bus with a total Winter Capability equal to or greater than 10.0 MW shall also be included. 3. Transformers All transformers connecting PTF transmission lines shall be included in the analysis. A. Determination of Rate Distribution 1. General Modeling of the transmission system shall be performed using a system simulation program and associated cases as approved by the Reliability Committee. 2. Determination of Regional Flows The change in real power flow (MW) over each transmission line and transformer shall be determined for each generator (or group of generators on a single bus) by determining the absolute value of the difference between the flows on each facility with the generator(s) modeled off and while operating at its net Winter Capability. In addition, a generator shall be simulated at each transmission line tie to the NEPOOL Control Area and changes in flow determined for this generator off or while generating at a level of 100 MW. Loads throughout the NEPOOL Control Area shall be proportionally scaled to account for differences in generator output and electrical losses. The changes in flow shall be multiplied by the length of each respective line. Changes in flow through transformers shall be multiplied by a factor of five. Changes in flow through phase-shifting transformers shall be multiplied by a factor of ten. The resulting values represent the MW-miles associated with each facility. 3. Determination of Transaction Flows a. Definition of Supply and Receipt Areas For the purposes of these calculations, areas of supply and receipt shall be determined by the Reliability Committee. These areas shall be based on the system boundaries of each Local Network. b. Calculation of MW-Miles The change in real power flow (MW) over each transmission line and transformer shall be determined for each combination of supply and receipt areas by determining the absolute value of the difference between the flows on each facility following a scaled increase of the supplying areas generation by 100 MW. Loads in the area of receipt shall be scaled to account for changes in generation and electrical losses. In instances where the areas of supply and/or receipt are outside the NEPOOL Control Area, the changes in real power flow will be determined only for facilities within the NEPOOL Control Area. The changes in flow shall then be multiplied by the length of each respective line. Changes in flow through transformers shall be multiplied by a factor of five. Changes in flow through phase-shifting transformers shall be multiplied by a factor of ten. The resulting values represent the MW- miles associated with each facility. 4. Assignment of MW-Miles to Participants Each Participant shall have assigned to it the MW- miles associated with each PTF facility for which it has full ownership and for which there are no arrangements in effect by which other Participants support the facility. For facilities that are jointly owned and/or supported, each Participant shall be assigned MW-miles in proportion to the percentage of its ownership of jointly-owned facilities and/or the percentage of its support for facilities that are jointly supported to the extent such support payments are included in the determination of Annual Transmission Revenue Requirements. ATTACHMENT B NEPOOL OPEN ACCESS TRANSMISSION TARIFF See FERC Electric Tariff, Fourth Revised Volume 1. ATTACHMENT C RELIABILITY REGIONS Exhibit 10(g) NATIONAL GRID USA SERVICE COMPANY, INC. 25 Research Drive Westborough, Massachusetts 01582 SERVICE CONTRACT January 1, 2001 National Grid USA Service Company, Inc. 25 Research Drive Westborough, MA 01582 National Grid USA Service Company, Inc. (hereinafter called Service Company) is a company engaged primarily in the rendering of services to companies in the National Grid USA holding-company system. The organization, conduct of business and method of cost allocation of the Service Company are designed to meet the requirements of Section 13 under the Public Utility Holding Company Act of 1935 and the rules and regulations promulgated thereunder to the end that services performed by the Service Company for said associate companies will be rendered to them at cost, fairly and equitably allocated. Services will be rendered by Service Company only upon receipt from time to time of specific or general request therefor. Said requests may always be modified or canceled by you at your discretion. The parties hereto agree as follows: 1. The Service Company agrees to furnish you upon the terms and conditions herein set forth such of the services described in Schedule 1 hereto as you may from time to time request. Service Company will also furnish, if available, such services not described in Schedule 1 as you may request. Notwithstanding the foregoing the Service Company shall not furnish under this agreement any engineering, construction, or maintenance services for a nuclear generating plant. 2. The Service Company has and will maintain a staff trained and experienced in the provision of services of a general and administrative nature. In addition to the services of its own staff, Service Company will, after consultation with you concerning services to be rendered pursuant to your request, arrange for services of non-affiliated experts, consultants, accountants and attorneys. 3. All of the services rendered under this agreement will be at actual cost thereof. Direct charges will be made for services where a direct allocation of cost is possible. The methods of determining such costs and the allocation thereof are set forth in Schedule II hereto. These methods are reviewed annually and more frequently, if appropriate. Such methods may be modified or changed by Service Company without the necessity of an amendment of this agreement provided that in each instance all services rendered hereunder will be at actual cost thereof, fairly and equitably allocated, and all in accordance with the requirements of the Public Utility Holding Company Act of 1935 and the rules and regulations and orders thereunder. You will be advised from time to time of any material changes in such methods. 4. Bills will be rendered during the first week of each month covering amounts due for the month calculated on an estimated basis using the actual expenses incurred to the extent possible during the second previous month. This estimated amount would be adjusted on the bill to be rendered by the conclusion of the following month. Any amount remaining unpaid after fifteen days following receipt of the bill shall bear interest thereon from the date of the bill at an annual rate of 2% above the lowest interest rate then being charged by the Fleet Bank on 90 day commercial loans. Services will be performed hereunder for not more than one year commencing January 1, 2001, and continuing through December 31, 2001, unless terminated at an earlier date by either party giving thirty days' written notice to the other of such termination at the end of any month. 5. This agreement will be subject to termination or modification at any time to the extent its performance may conflict with any federal or state law or any rule, regulation or order of a federal or state regulatory body having jurisdiction. The agreement shall be subject to approval of any federal or state regulatory body whose approval is a legal prerequisite to its execution and delivery or performance. NATIONAL GRID USA SERVICE COMPANY, INC. S/John G Cochrane By:_____________________________________ Treasurer Accepted: January 31, 2001 Exhibit 10(aa)(ii) AMENDMENT NO. 3 TO WHOLESALE SALES AGREEMENT Amendment No. 3 dated as of December 23, 1999 by and among New England Power Company, a Massachusetts corporation ("NEP") and USGen New England, Inc. (formerly named USGen Acquisition Corporation), a Delaware corporation ("USGenNE"), and Constellation Power Source, Inc. ("CPS"), a Delaware corporation, ("Amendment") to the Wholesale Sales Agreement, dated as of August 5, 1997 and amended as of September 25, 1997 and September 1, 1998 ("Sales Agreement"), by and among NEP and USGenNE. NEP, USGenNE and CPS may be referred to herein individually as a "Party" or together as the "Parties." Whereas USGenNE and CPS intend that USGenNE will assign all of its rights and obligations under the Sales Agreement to CPS effective March 1, 2000, and NEP will release USGenNE from all further liabilities and obligations under the Sales Agreement effective as of the date of such assignment. NOW, THEREFORE, in consideration of the premises and considerations and warranties, covenants and other agreements hereinafter set forth, the parties hereto, intending to be legally bound hereby, agree as follows: 1) Definitions. All capitalized terms have the meaning set forth herein, and if not defined herein, have the meaning set forth in the Sales Agreement. 2) Effective Date. This Amendment is effective upon execution and binding upon the parties, their successors and assigns upon execution and thereafter. 3) Assignment. Effective 12:01 a.m. on March 1, 2000, USGenNE hereby sells, assigns, conveys, transfers and delivers to CPS, and CPS hereby assumes from USGenNE, all of USGenNE's right, title, interest, claim and demand in, to and under the Sales Agreement and all of its obligations thereunder; provided that, USGenNE shall not assign the obligations incurred, its right to recovery of damages, or the exercise of remedies and indemnification as provided pursuant to the Sales Agreement for events or causes occurring prior to March 1, 2000 ("Assignment"). 4) Recognition Of, and Consent To, Assignment. NEP acknowledges and consents in accordance with Article 10, Section 10.1 of the Sales Agreement, to the Assignment. 5) Release. NEP releases, holds harmless and forever discharges USGenNE and each of its affiliates, including PG&E Corporation, a California corporation, from any and all claims, liabilities, obligations, and indemnities relating to any event or cause occurring on or after March 1, 2000 arising under or with respect to the Sales Agreement. NEP hereby waives and all rights and benefits that it now has, or in the future may have, conferred upon it by virtue of any statute or common law principle that provides that a general release does not extend to claims which a Party does not know or suspect in its favor at the time of executing the release. Nothing herein relieves USGenNE, or any of its affiliates, of any claim, liability, obligation or indemnity relating to any event or cause occurring prior to March 1, 2000 and arising under or relating to the Sales Agreement. For further certainty, USGenNE agrees to pay all amounts accrued or due pursuant to ARTICLE 5 of the Sales Agreement related to deliveries of Wholesale Nuclear Entitlements that occurred prior to March 1, 2000. 6) Amendments As Of The Effective Date. The following amendments will become effective as of 12:01 a.m. on March 1, 2000: a) All references to "Buyer" in the Sales Agreement will be deemed to refer to CPS, which shall thereafter exercise all of the right, title, interest, claim and demand in, to and under the Sales Agreement and all of the obligations thereunder designated as those of Buyer. b) In ARTICLE 2 of the Sales Agreement, the definition of "Wholesale Standard Offer Service Agreements" is amended by replacing the existing definition with the following: Wholesale Standard Offer Service Agreements. The agreements dated as of September 1, 1998 entered into by USGen New England, Inc. ("USGenNE") with Massachusetts Electric Company and Nantucket Electric Company (jointly, "MECO") and The Narragansett Electric Company ("NECO"), as such agreements may be amended or assigned (in whole or in part) from time to time, which cumulatively entitle the seller(s) thereunder to deliver to MECO and NECO, respectively, 90.78% of the requirements of such companies for wholesale standard offer service as provided therein. c) The second paragraph of ARTILCE 4, Section 4.2 is amended by adding at the end of such paragraph the following: Buyer further acknowledges and agrees that NEP is pursuing the sale or other disposition of all of its Nuclear Interests and that, upon the sale or other disposition of any of NEP's Nuclear Interests, NEP shall be released from any further obligation to deliver to Buyer any Wholesale Nuclear Entitlement relating to such Nuclear Interest. For the avoidance of doubt, the phrase " other disposition" as used in this Section 4.2 and Section 3.1, shall mean (i) in the case of Seabrook Unit 1 or Millstone Unit 3, a termination of NEP's entitlement to power produced by the applicable unit in a circumstance involving the transfer of all of NEP's interest as a joint owner therein to a non-affiliated third party or (ii) in the case of Vermont Yankee, a termination of NEP's obligation to purchase power from the unit in a circumstance involving a transfer of ownership of the Vermont Yankee Nuclear Power Station by its owner, Vermont Yankee Nuclear Power Corporation, to a non-affiliated third party. d) The last paragraph of ARITLCE 5, Section 5.1(b) of the Sales Agreement (as amended by Amendment 1 to the Sales Agreement), is amended by replacing the existing text with the following: Unless and until such time as USGenNE assigns any of all of its rights, interests and obligations under the Wholesale Standard Offer Service Agreements to CPS, the amount of the credit, if any, shall be the product of (i) the difference between (a) the average Energy Price (as expressed in dollars per megawatt-hour) and (b) the applicable value from the above table (expressed in dollars per megawatt-hour) and (ii) the lesser of (a) the number of megawatt-hours delivered under the Wholesale Standard Offer Service Agreements (cumulatively, by each and every seller) during the month or (b) the total number of megawatt-hours delivered by NEP from the Purchased Quantity for the month. As of such time as USGenNE assigns any or all of its rights, interests and obligations under the Wholesale Standard Offer Service Agreements to CPS, the amount of the credit, if any, shall be the product of (i) the difference between (a) the average Energy Price (as expressed in dollars per megawatt-hour) and (b) the applicable value from the above table (expressed in dollars per megawatt-hour) and (ii) the lesser of (a) the sum of (x) the number of megawatt-hours delivered by CPS to MECO under its agreement with MECO for the delivery of wholesale standard offer service, multiplied by .9078 and divided by the percentage of the total requirements of MECO for wholesale standard offer service that CPS is entitled to provide and (y) the number of megawatt-hours delivered by CPS to NECO under its agreement with NECO for the delivery of wholesale standard offer service, multiplied by .9078 and divided by the percentage of the total requirements of NECO for wholesale standard offer service that CPS is entitled to provide or (b) the total number of megawatt-hours delivered by NEP from the Purchased Quantity for the month. e) ARTICLE 8, Section 8.1 of the Sales Agreement is amended to replace Buyer's address with the following: Sarah Wright Constellation Power Source, Inc. 111 Market Place Suite 500 Baltimore, Maryland 21202 phone: (410) 468-3483 fax: (410) 468-3540 With a copy to: David M. Perlman, General Counsel Constellation Power Source, Inc. 111 Market Place Suite 500 Baltimore, Maryland 21202 phone: (410) 468-3490 fax: (410) 468-3499 f) ARTICLE 10, Section 10.1 (ii) of the Sales Agreement is amended by replacing "PG&E Corporation" with "Constellation Energy Group" and by deleting the phrase "; provided, further, however, that no such assignment and assumption shall relieve or in any way discharge PG&E Corporation from the performance of its duties and obligations under the Guaranty dated as of the date of this Agreement executed by PG&E Corporation," at the end of such Section. g) The Sales Agreement is amended by the addition of the following new ARTICLE 21. ARTICLE 21. CREDIT SUPPORT; SET OFF 21.1 Buyer Credit Support. If at any time during the term of this Agreement Buyer's Net Worth (as defined below) falls below One Hundred Twenty Five Million Dollars ($125,000,000) and at such time Buyer does not have a credit rating on its senior unsecured debt securities of at least Investment Grade (as defined below), then within ten (10) business days after a request from NEP, Buyer shall deliver credit support to NEP in an amount equal to Ten Million Dollars ($10,000,000) and, at Buyer's election, in the form of either: (a) a performance bond issued by a surety company with a rating of "B+" or better from A.M. Best Company; (b) a letter of credit directed to NEP from a commercial bank with long-term debt ratings of "Baa2" or better from Moody's Investors Service, Inc. ("Moody's") and "BBB" or better from Standard & Poor's Corporation ("S&P"); or (c) a guaranty from an affiliate of Buyer that has an Investment Grade rating on its senior unsecured debt securities. Such credit support shall be available to be drawn upon by NEP in the event that an event of default occurs with respect to Buyer hereunder and shall otherwise be in form and substance reasonably acceptable to NEP. For purposes of the Article 21, "Net Worth" shall mean total assets (exclusive of intangible assets) less total liabilities as reflected on a balance sheet prepared in accordance with generally accepted accounting principles consistently applied and "Investment Grade" shall mean (i) with regard to a credit rating assigned by Moody's, a credit rating equal to or better than "Baa3"; and (ii) with regard to a credit rating assigned by S&P, a credit rating equal to or better than "BBB-". 21.2 NEP Credit Support. If at any time during the term of this Agreement the credit rating assigned to the senior unsecured debt securities of NEP by Moody's or S&P falls below Investment Grade, then within ten (10) business days after a request from Buyer, NEP shall deliver credit support to Buyer in an amount equal to Twenty Million Dollars ($20,000,000) and, at NEP's election, in the form of either: (a) a performance bond issued by a surety company with a rating of "B+" or better from A.M. Best Company; (b) a letter of credit directed to NEP from a commercial bank with long-term debt ratings of "Baa2" or better from Moody's and "BBB" or better S&P; or (c) a guaranty from an affiliate of NEP that has an Investment Grade rating on its senior unsecured debt securities. Such credit support shall be available to be drawn upon by Buyer in the event that an event of default occurs with respect to NEP hereunder and shall otherwise be in form and substance reasonably acceptable to Buyer. 21.3 Buyer Financial Statements. Buyer shall deliver to NEP financial statements certified by a firm of certified public accountants of national standing annually within ninety (90) days following the end of Buyer's fiscal year and unaudited quarterly financial statements within forty-five (45) days following the end of each quarter. 21.4 Set Off. If at any time Buyer fails to pay any amounts due hereunder and fails to cure such payment default within the Cure Period provided therefore under and in accordance with Section 7.1(b) of this Agreement, then NEP and its affiliates shall be entitled to set off the amount of such delinquent payment against amounts owed by NEP and any of its affiliates to Buyer under other agreements among such parties. At any time after a default on the part of NEP under this Agreement, and a failure by NEP to cure such default within the period provided in Section 7.1(a) of this Agreement, the Buyer may set off any of all amounts which NEP owes to the Buyer under this Agreement against any or all amounts which the Buyer owes to NEP under this Agreement. 1) Other Agreements. a) Transition. Each of the Parties hereto acknowledge and agree that deliveries of Wholesale Nuclear Entitlements under the Sales Agreement during each Contract Period are made in accordance with nominations submitted at least 30 days prior to the commencement of the Contract Period in accordance with ARTICLE 4, Section 4.2 of the Sales Agreement. The Parties further acknowledge and agree that March 1, 2000 is the commencement of a Contract Period. To facilitate CPS's assumption of the right to purchase the Wholesale Nuclear Entitlements as of March 1, 2000, USGenNE, CPS and NEP agree that CPS may exercise USGenNE's right to make a nomination under Section 4.2 of the Sales Agreement for the Contract Period beginning March 1, 2000 at any time between the date first written above and January 30, 2000 and otherwise in accordance with the terms of the Sales Agreement, NEP will accept and honor CPS's nomination as if made by USGenNE and USGenNE agrees not to make a nomination for such Contract Period or any period thereafter. b) Regulatory Obligations. NEP agrees to file this Amendment with FERC promptly after execution and in no event later than thirty (30) days after execution. c) Indemnification. USGenNE agrees to defend, indemnify and hold harmless CPS and its officers, directors, employees, agents (other than USGenNE), successors, assigns and affiliates, and each affiliates' officers, directors, employees, agents, successors and assigns against any and all costs, damages, settlements, or other liabilities (including reasonable fees of attorneys, consultants and other professionals retained to assist in the defense or settlement) ("Losses") related to claims, suits, actions or causes of action relating to any event or cause occurring before March 1, 2000 arising under or with respect to the Sales Agreement. CPS agrees to defend, indemnify and hold harmless USGenNE and its officers, directors, employees, agents (other than CPS), successors, assigns and affiliates, and each affiliates' officers, directors, employees, agents, successors and assigns against any and all costs, damages, settlements, or other liabilities (including reasonable fees of attorneys, consultants and other professionals retained to assist in the defense or settlement) ("Losses") related to claims, suits, actions or causes of action relating to any event or cause occurring on or after March 1, 2000 arising under or with respect to the Sales Agreement. Each of CPS and USGenNE will make a good faith effort to provide prompt notice to the other of any claim or action reasonably likely to give rise to a claim under this section but in any event will provide notice to the other within 15 days of receipt of a notice of the commencement of any suit, action or proceeding before an arbitrator, court of law or regulatory agency brought by a person other than the other, including without limitation governmental agencies, that could potentially give rise to a claim under this section. The indemnitor (either USGenNE or CPS, as the case may be) will have the right to participate in, or by giving written notice to the indemnitee (either USGenNE or CPS, as the case may be), assume at its own expense the defense of an action brought by a person other than a the indemnitor against the indemnitee. The indemnitee will seek in good faith to recover any Losses under applicable insurance policies, and the indemnitor's obligations hereunder will be reduced to the extent of such recovery, provided that nothing in this Agreement shall be deemed to create an obligation to insure by either USGenNE or CPS. The indemnitee agrees not to compromise or settle any claim or action subject to indemnification under this section without the prior written consent of the indemnitor. IN WITNESS WHEREOF, the undersigned Parties hereto have executed this Amendment as of the date first written above. NEW ENGLAND POWER COMPANY S/James S. Robinson By: _____________________________ Name: James S. Robinson Title: Vice President, Generation Investments USGen NEW ENGLAND, INC. s/James V. Mahoney By: _____________________________ Name: James V. Mahoney Title: Senior Vice President CONSTELLATION POWER SOURCE, INC. s/John R. Collins By: _____________________________ Name: John R. Collins Title: Vice President and Treasurer Exhibit (10)(aa)(iii) AMENDED AND RESTATED PPA TRANSFER AGREEMENT This AMENDED AND RESTATED PPA TRANSFER AGREEMENT ("Agreement") is dated as of October 29, 1997 and is made by and between NEW ENGLAND POWER COMPANY, a Massachusetts corporation ("NEP"), and USGEN NEW ENGLAND, INC. (formerly named USGen Acquisition Corporation), a Delaware corporation ("Asset Purchaser"), and amends and restates and, together with the OSP PPA Transfer Agreement dated of even date herewith between NEP and Asset Purchaser (the "OSP PPA Transfer Agreement"), supersedes in its entirety the PPA Transfer Agreement dated as of August 5, 1997 between NEP and the Asset Purchaser (the "Original PPA Transfer Agreement"). This Agreement sets forth an amendment to, and restatement in their entirety of, the terms and conditions under which NEP will transfer to Asset Purchaser the economic benefits and performance obligations, subject to NEP's continuing obligations to make certain payments, associated with certain Power Purchase Agreements between NEP and third party power suppliers (the "Power Sellers") that NEP and Asset Purchaser desire to be transferred concurrently with the sale of NEP's generation business to Asset Purchaser pursuant to the Asset Purchase Agreement, dated as of August 5, 1997, as amended (as so amended, the "APA"), by and among NEP, The Narragansett Electric Company and Asset Purchaser. 1. The following Power Purchase Agreements (each, as amended or supplemented, a "Commitment") are incorporated into this Agreement by reference: Doc. No. Party Date 2068 Altresco Pittsfield, L.P. 12/9/87* 2071 Milford Power L.P. 4/24/96 2072 Pawtucket Power Associates L.P. 12/14/87* 2062 Ogden Haverhill Associates 12/30/85* 2065 SES Millbury Company, L.P. 12/17/85 2063 Massachusetts Refusetech, Inc. 1/6/81* 2064 Refuse Energy Systems Company 1/1/6 2075 L'Energia L.P. 2/26/91 2058 Lawrence Hydroelectric Associates 1/1/85 2061 Ridgewood Providence Power Partners, L.P. 11/6/87* 2060 Pontook Hydro L.P. 1/26/85 2102 Waste Management of New Hampshire, Inc. 5/20/91* 2067 Suncook Energy Corporation 9/7/94* 2059 Mascoma Hydro Corporation 11/14/86 2066 Phillip's Energy, Inc. 9/7/94* 2073 Massachusetts Water Resources Authority 9/21/95 2069 Clark University 2/12/82* 2070 Clark University 2/12/82* 2078 General Electric Lynn River Works 7/7/92 2079 Refuse Fuels Associates 6/12/80* 2080 Simpson Paper 1/1/85 2074 Canal I 12/1/65* 2035 HydroQuebec Phase II 10/14/85 2033 HydroQuebec Phase I 3/21/83 2103 Connecticut Light & Power 1/4/89* 2592 Cambridge Electric Light Company, Commonwealth Electric Light Company 7/3/93* * Indicates agreement has been amended or supplemented. A Commitment shall be automatically deleted from the above Commitment list without further action by the parties: (i) on the effective date of any Novation (as defined in Section 7, below), (ii) upon the expiration of a Commitment pursuant to its terms, or (iii) upon the termination of a Commitment pursuant to the written agreement of the parties thereto. 2. This Agreement shall become effective on the Effective Date (as defined in Section 13) and shall remain in effect until Asset Purchaser has made payment to NEP of amounts owed pursuant to Section 4(a), below, and NEP has made payment to Asset Purchaser and/or the Power Sellers of amounts owed pursuant to Section 3, 4(b) and 8, below, for the last month in which a Commitment is listed on the Section 1 Commitment list; provided however that the provisions of Section 8 of this Agreement shall survive until NEP has paid all amounts due thereunder. 3. Commencing as of the Effective Date, NEP agrees to provide to Asset Purchaser all electric capacity, energy and any other benefits it receives under each Commitment listed on the Section 1 Commitment list as of the first day of the month simultaneously with NEP's receipt thereof from each Power Seller. All electric energy shall be delivered to Asset Purchaser at the point at which the Power Seller makes delivery to NEP as established under the Commitment. Asset Purchaser shall be responsible for making all arrangements necessary for the further transmission of such energy. NEP shall, however, promptly reimburse Asset Purchaser for all costs actually and reasonably incurred by Asset Purchaser in transmitting such energy from such delivery points to the NEPOOL Pool Transmission Facility system either pursuant to this Section 3 or pursuant to a Commitment which has been amended and assigned pursuant to Section 7, provided that NEP shall not be responsible for an increase in such cost attributable to any amendment to a Commitment by the Asset Purchaser. 4. (a) Commencing as of the month following the Effective Date, Asset Purchaser agrees to pay to NEP each month all amounts properly due from NEP to the Power Seller for the preceding month associated with capacity, energy and any other benefits made available to NEP by the Power Seller and accordingly by NEP to it from each Commitment listed on the preceding month's Section 1 Commitment list, less the amount of NEP's Monthly Payment Obligation specified in Section 8 below. For purposes of the first monthly payment due from Asset Purchaser to NEP under this Agreement in connection with each Commitment, energy payments shall be based on meter readings taken on the first day for which Asset Purchaser has a payment obligation under this Agreement and capacity payments shall be based on the ratio of the number of days in the month for which Asset Purchaser has a payment obligation under this Agreement to the total number of days in the month. Asset Purchaser shall make such payment sufficiently in advance of the time that such payment is due by NEP to the Power Seller as to allow NEP to make timely payment under such Commitment. In turn, each month NEP agrees to timely pay each Power Seller all amounts due under each Commitment, which includes the amount NEP receives from Asset Purchaser in connection with such Commitment and the amount of NEP's payment obligation specified in Section 8 below. (b) Upon the Effective Date, NEP shall irrevocably and unconditionally assign and thereafter hold for the benefit of and/or credit to Asset Purchaser against payments due from it to NEP under Section 4(a) hereof or at the termination of this Agreement pay to Asset Purchaser any and all amounts which are then or thereafter received by NEP from the Power Sellers under the Commitments, including, without limitation, any aggregate differential balances under any Commitment and the benefit of and proceeds from any security deposits, letters of credit or other similar instruments or accounts established for the benefit of NEP by the Power Seller, but excluding any credits or refunds received by NEP after the Effective Date which relate to billing errors or reconciliations of pre- Effective Date bills, and any amounts paid by the Power Sellers to NEP with respect to disputes arising before the Effective Date that are attributable to a period prior to the Effective Date. 5. (a) Effective as of the Effective Date, NEP hereby irrevocably and unconditionally appoints Asset Purchaser as its representative and agent for all purposes under each Commitment. Asset Purchaser is hereby authorized to take all actions that NEP may lawfully take under the Commitment without further approval by NEP, including, without limitation, the following: with respect to all matters arising under the Commitments, deal directly with the Power Sellers, the New England Power Pool ("NEPOOL"), the Independent System Operator (as designated under the Restated NEPOOL Agreement as filed with the Federal Energy Regulatory Commission on December 31, 1996, and as amended from time to time), other transporters of electric energy, federal, state and local governmental authorities, and any other persons; act on NEP's behalf in the prosecution or defense, as the case may be, of any rights or liabilities arising under the Commitments; monitor the Power Sellers' performance under the Commitments; review and audit all bills and related documentation rendered by the Power Sellers; and on NEP's behalf enter into amendments to the Commitments of any nature; provided, however Asset Purchaser shall not amend any Commitment with respect to any of NEP's interconnection rights and obligations, or extend the term thereof or increase NEP's obligations thereunder without NEP's consent, which shall not be unreasonably withheld. Asset Purchaser shall have the right to delegate to its affiliated or third parties any of its responsibilities under this Section 5. NEP hereby agrees to provide and deliver to Asset Purchaser all information which NEP now has or hereafter acquires or to which it is entitled with respect to each Commitment and Asset Purchaser hereby agrees to be subject to any confidentiality provisions of such Commitment with respect to such information. NEP also agrees to participate at Asset Purchaser's request and under Asset Purchaser's direction in any governmental proceeding with respect to the Commitments or this Agreement. (b) NEP agrees not to agree to any amendment to or waiver of rights under a Commitment without Asset Purchaser's consent, which Asset Purchaser may grant or withhold in its sole discretion, and will not take any actions inconsistent with the provisions of this Section 5. 6. (a) NEP will indemnify, defend and hold harmless the Asset Purchaser from and against any and all claims, demands or suits (by any person), losses, liabilities, damages (excluding consequential or special damages), obligations, payments, costs and expenses (including, without limitation, the costs and expenses of any and all actions, suits, proceedings, assessments, judgments, settlements, and compromises relating thereto and reasonable attorneys' fees and reasonable disbursements in connection therewith) to the extent the foregoing are not covered by insurance (each, an "Indemnifiable Loss"), asserted against or suffered by Asset Purchaser relating to, resulting from or arising out of any relationship or payment obligation of NEP resulting from or contained in this Agreement or any obligation of NEP for any acts or omissions under the Commitments incurred prior to the Effective Date. For purposes hereof, any willful or negligent failure of NEP to perform any act required to be performed by it under a Commitment which increases the amounts payable by Asset Purchaser under Section 4(a) hereof shall be an Indemnifiable Loss for which Asset Purchaser shall be entitled to indemnification hereunder. (b) Asset Purchaser will indemnify, defend and hold harmless NEP from and against any and all Indemnifiable Losses asserted against or suffered by NEP relating to, resulting from or arising out of any relationship or payment obligation of Asset Purchaser resulting from or contained in this Agreement. For purposes hereof, NEP's costs incurred in administering the Commitments and performing its obligations under this Agreement shall not be an Indemnifiable Loss. (c) Any person entitled to receive indemnification under this Agreement (an "Indemnitee") having a claim under these indemnification provisions shall make a good faith effort to recover all losses, damages, costs and expenses from insurers of such Indemnitee under applicable insurance policies so as to reduce the amount of any Indemnifiable Loss hereunder. The amount of any Indemnifiable Loss shall be reduced (i) to the extent that Indemnitee receives any insurance proceeds with respect to an Indemnifiable Loss and (ii) to take into account any net Tax benefit recognized by the Indemnitee arising from the recognition of the Indemnifiable Loss and any payment actually received with respect to an Indemnifiable Loss. (d) The expiration, termination or extinguishment of any covenant or agreement shall not affect the parties' obligations under this Section 6 if the Indemnitee provided the person required to provide indemnification under this Agreement (the "Indemnifying Party") with proper notice of the claim or event for which indemnification is sought prior to such expiration, termination or extinguishment. (e) The rights and remedies of NEP and Asset Purchaser under this Section 6 are exclusive and in lieu of any and all other rights and remedies which NEP and Asset Purchaser may have under this Agreement or otherwise for monetary relief with respect to any relationship or payment obligation resulting from this Agreement. (f) NEP and Asset Purchaser each agree that, notwithstanding any provisions in this Agreement to the contrary, all parties to this Agreement retain their remedies at law or in equity with respect to willful or intentional breaches of this Agreement. (g) If any Indemnitee receives notice of the assertion of any claim or of the commencement of any claim, action, or proceeding made or brought by any person who is not a party to this Agreement or any affiliate of a party to this Agreement (a "Third Party Claim") with respect to which indemnification is to be sought from an Indemnifying Party, the Indemnitee will give such Indemnifying Party reasonably prompt written notice thereof, but in any event not later than ten (10) calendar days after the Indemnitee's receipt of notice of such Third Party Claim. Such notice shall describe the nature of the Third Party Claim in reasonable detail and will indicate the estimated amount, if practicable, of the Indemnifiable Loss that has been or may be sustained by the Indemnitee. The Indemnifying Party will have the right to participate in or, by giving written notice to the Indemnitee, to elect to assume the defense of any Third Party Claim at such Indemnifying Party's own expense and by such Indemnifying Party's own counsel, and the Indemnitee will cooperate in good faith in such defense at such Indemnitee's own expense. (h) If within ten (10) calendar days after an Indemnitee provides written notice to the Indemnifying Party of any Third Party Claim the Indemnitee receives written notice from the Indemnifying Party that such Indemnifying Party has elected to assume the defense of such Third Party Claim as provided in the last sentence of clause (g), the Indemnifying Party will not be liable for any legal expenses subsequently incurred by the Indemnitee in connection with the defense thereof; provided, however, that if the Indemnifying Party fails to take reasonable steps necessary to defend diligently such Third Party Claim within twenty (20) calendar days after receiving notice form the Indemnitee that the Indemnitee believes the Indemnifying Party has failed to take such steps, the Indemnitee may assume its own defense, and the Indemnifying Party will be liable for all reasonable expenses thereof. Without the prior written consent of the Indemnitee, the Indemnifying Party will not enter into any settlement of any Third Party Claim which would lead to liability or create any financial or other obligation on the part of the Indemnitee for which the Indemnitee is not entitled to indemnification hereunder. If a firm offer is made to settle a Third Party Claim without leading to liability or the creation of a financial or other obligation on the part of the Indemnitee for which the Indemnitee is not entitled to indemnification hereunder and the Indemnifying Party desires to accept and agree to such offer, the Indemnifying Party will give written notice to the Indemnitee to that effect. If the Indemnitee fails to consent to such firm offer within ten (10) calendar days after its receipt of such notice, the Indemnitee may continue to contest or defend such Third Party Claim and, in such event, the maximum liability of the Indemnifying Party as to such Third Party Claim will be the amount of such settlement offer, plus reasonable costs and expenses paid or incurred by the Indemnitee up to the date of such notice. (i) Any claim by an Indemnitee on account of an Indemnifiable Loss which does not result from a Third Party Claim (a "Direct Claim") will be asserted by giving the Indemnifying Party reasonably prompt written notice thereof, stating the nature of such claim in reasonable detail and indicating the estimated amount, if practicable, but in any event not later than ten (10) calendar days after the Indemnitee becomes aware of such Direct Claim, and the Indemnifying Party will have a period of thirty (30) calendar days within which to respond to such Direct Claim. If the Indemnifying Party does not respond within such thirty (30) calendar day period, the Indemnifying Party will be deemed to have accepted such claim. If the Indemnifying Party rejects such claim, the Indemnitee will be free to seek enforcement of its rights to indemnification under this Agreement. (j) If the amount of any Indemnifiable Loss, at any time subsequent to the making of an indemnity payment in respect thereof, is reduced by recovery, settlement or otherwise under or pursuant to any insurance coverage, or pursuant to any claim, recovery, settlement or payment by or against any other entity, the amount of such reduction, less any costs, expenses or premiums incurred in connection therewith (together with interest thereon from the date of payment thereof at the prime rate then in effect of the Bank of Boston), will promptly be repaid by the Indemnitee to the Indemnifying Party. Upon making any indemnity payment, the Indemnifying Party will, to the extent of such indemnity payment, be subrogated to all rights of the Indemnitee against any third party in respect of the Indemnifiable Loss to which the indemnity payment relates; provided, however, that (i) the Indemnifying Party will then be in compliance with its obligations under this Agreement in respect of such Indemnifiable Loss and (ii) until the Indemnitee recovers full payment of its Indemnifiable Loss, any and all claims of the Indemnifying Party against any such third party on account of said indemnity payment is hereby made expressly subordinated and subjected in right of payment to the Indemnitee's rights against such third party. Without limiting the generality or effect of any other provision hereof, each such Indemnitee and Indemnifying Party will duly execute upon request all instruments reasonably necessary to evidence and perfect the above-described subrogation and subordination rights, and otherwise cooperate in the prosecution of such claims at the direction of the Indemnifying Party. Nothing in this clause (j) shall be construed to require any party hereto to obtain or maintain any insurance coverage. (k) A failure to give timely notice as provided herein will not affect the rights or obligations of any party hereunder except if, and only to the extent that, as a result of such failure, the party which was entitled to receive such notice was actually prejudiced as a result of such failure. 7. NEP and Asset Purchaser agree to work cooperatively and use all reasonable efforts to amend each Commitment and assign each such amended Commitment to Asset Purchaser so that NEP will be released of all further liabilities and obligations under the Commitment and Asset Purchaser will be directly in contract with the Power Seller (a "Novation"). Any such Novation shall include all modifications necessary to reflect the substitution of Asset Purchaser for NEP as the purchasing party under the Commitment (including modifications to Commitment price indices, where appropriate) and to properly describe interconnection, delivery point and transmission system references and obligations in the Commitment. The provisions of Section 8(d) shall apply to all such Novations. It is intended by the parties that all such Novations preserve the economic benefit and other rights of the Commitment to the Asset Purchaser without increasing the Asset Purchaser's obligations under the Commitment while continuing to afford to NEP the protections for its transmission system embodied in the interconnection provisions of the Commitment; provided however that nothing contained herein is intended to limit the ability of Asset Purchaser to direct the availability, dispatch, quantity or timing of the capacity or electrical output of a plant, facility or system which is the subject of a Commitment, subject to the current terms of such Commitment. NEP and Asset Purchaser agree to execute all agreements and documents reasonably required by the other in connection with all such Novations. 8. (a) In the month in which the Effective Date occurs, NEP shall be obligated to pay the Power Sellers an aggregate amount equal to (i) the Monthly Payment Obligation (as defined in 8(d)(1) below), as adjusted in accordance with Section 8(d)(4) below, multiplied by (ii) a fraction, the numerator of which is the total number of days in the month in which the Effective Date occurs, less the number of days in such month up to the Effective Date, and the denominator of which is the total number of days in the month in which the Effective Date occurs, and such adjusted amount shall be deducted by Asset Purchaser from the amount due NEP under Section 4 above for such month. (b) Commencing as of the month following the Effective Date and continuing for each succeeding month through and including January 2008, NEP shall be obligated to pay the Power Sellers each month an aggregate amount equal to the Monthly Payment Obligation, as adjusted in accordance with Section 8(c) and Section 8(d)(4) below, and such adjusted amount shall be deducted by Asset Purchaser from the amount due NEP under Section 4 above. (c) In the event that the amount of NEP's Monthly Payment Obligation set forth in Section 8(b) (as adjusted to reflect any increases pursuant to this Section 8(c)) shall in any month exceed the amount due NEP from Asset Purchaser under Section 4, NEP shall increase the amount of its obligation in the next month (in addition to its obligation set forth in Section 8(b)) by the amount of such excess plus interest thereon at the Applicable Discount Rate (as defined in Section 8(d)(3)) from the date payment from Asset Purchaser for such month would have been due to the date of the next payment by Asset Purchaser under Section 4 (the "Excess Obligation") and Asset Purchaser shall also be allowed to deduct such Excess Obligation from the amount due NEP under Section 4 for such month. Should there be an Excess Obligation as of January 31, 2008, NEP shall within thirty days thereafter pay at the direction of Asset Purchaser the amount of such Excess Obligation. (d) To the extent that a "Trigger Event" (as hereinafter defined) shall occur with respect to any Commitment, NEP will, with the consent of Asset Purchaser, make a full or a partial lump-sum payment ("Trigger Payment") to the appropriate Power Seller or such other party as the Asset Purchaser may direct, as the case may be. Subject to subsection (6) below, Trigger Payments shall, unless otherwise agreed to by Asset Purchaser, be made concurrently with the Trigger Event, or as soon thereafter as is practicable (but not later than the later of (x) sixty (60) days thereafter and (y) one hundred twenty (120) days after reasonable notice was given by Asset Purchaser that a Trigger Event was likely to occur) ("Trigger Payment Date"). (1) NEP's monthly payment obligations under Sections 8(a) and (b) above, and before adjustment in accordance with subsection (5) below, are detailed on Schedule B hereto ("Monthly Payment Obligation"). For each Commitment, and for each year from 1998 through 2007, a corresponding percentage of the Monthly Payment Obligation is set forth on Schedule A hereto (the "Applicable Percentage"). (2) "Trigger Event" shall mean: (i) a Novation; (ii) a termination of a Commitment; (iii) a negotiated modification of a Commitment under which the obligations of NEP are reduced; or (iv) a legislative, regulatory or court-ordered change in the terms of a Commitment under which the obligations of NEP are reduced; provided, however, that if at the time any one of the events specified in (i), (ii), or (iii) above shall occur, Asset Purchaser shall be in default with respect to indemnification as to its payment obligations under Section 6(b) hereof, no Trigger Event shall be deemed to have arisen from any such event unless and until such default shall have been cured. (3) The amount of any Trigger Payment (i) if in respect of a Trigger Event listed in subsection (2)(i) or (ii) above, shall, except as otherwise approved by Asset Purchaser, be the discounted amount as of the Trigger Payment Date (using as the discount rate a percentage equal to the sum of (x) the yield reported on page PX1 of the Bloomberg Financial Market Services Screen (or, if not available, any other nationally recognized trading screen reporting on-line intraday trading in United States government securities) at 4:00 p.m. (New York time) on the day prior to the Trigger Payment Date for the off-the-run 5-year Treasury Note plus (y).50% (the "Applicable Discount Rate")) of (A) NEP's remaining Monthly Payment Obligations as of the Trigger Payment Date multiplied by (B) the Commitment's Applicable Percentage for the year in which the Trigger Payment Date occurs, and (ii) if in respect of a Trigger Event listed in subsection (2)(iii) or (iv) above, shall, except as otherwise approved by Asset Purchaser, equal (x) the amount calculated under clause (i) above multiplied by (y) a fraction (but in no event less than zero nor greater than one (1)) calculated by mutual agreement in accordance with the following sentence (the "Reduction Factor"). The parties shall mutually agree to a Reduction Factor for each applicable Trigger Event that represents the proportion by which the discounted present value, using the Applicable Discount Rate, of the projected costs under the affected Commitment minus $.032 per kWh (as adjusted to be held constant in 1998 dollars using the Consumer Price Index), has been reduced as a result of such Trigger Event. Any controversy in connection with the calculation of the Reduction Factor shall be determined and settled by arbitration in New York, New York, by a person or persons mutually agreed upon, or in the event of a disagreement as to the selection of the arbitrator or arbitrators, in accordance with the rules of the American Arbitration Association. Any award rendered therein shall specify the findings of fact of the arbitrator or arbitrators and the reasons for such award, with the reference to and reliance on relevant law. Any such award shall be final and binding on each and all of the parties thereto and their personal representatives, and judgment may be entered thereon in any court having jurisdiction thereof and the fees of such arbitrators in connection with the determination shall be paid by the party against whom the award was made, or if a compromise was made, shared equally. (4) Upon the making of any such Trigger Payment, except as otherwise agreed to by Asset Purchaser, the amounts thereafter payable in accordance with Section 8(a) or Section 8(b) shall be reduced by the sum of (i) the reductions arising under this subsection (4) from all previous Trigger Payments made by NEP plus (ii)(x) in the case of a Trigger Payment made under Section 8(d)(3)(i), by an amount equal to (A) the Applicable Percentage used in calculating such Trigger Payment multiplied by (B) the Monthly Payment Obligation and (y) in the case of a Trigger Payment made under Section 8(d)(3)(ii), by an amount equal to (A) the Applicable Percentage used in calculating such Trigger Payment multiplied by (B) the Monthly Payment Obligation multiplied by (C) the Reduction Factor. (5) Notwithstanding the foregoing, NEP's obligation to make any Trigger Payment shall, at the option of NEP, be deferred, in whole or in part, pending satisfaction of the following conditions: (i) NEP shall be reasonably satisfied that the full amount of such Trigger Payment will be currently deductible for Federal and state income tax purposes and that such deduction shall be fully utilized in its Federal and state tax returns and (ii) NEP shall have received approval from all necessary regulatory authorities for any financing that NEP reasonably requires in order to fund such Trigger Payment. NEP shall use reasonable efforts to obtain and maintain, from all regulatory authorities having jurisdiction, approvals for the issuance of up to $100,000,000 in long-term securities for the purposes of funding Trigger Payments. (6) If NEP shall elect to defer making a Trigger Payment pursuant to subsection (5) above, then not later than the date that such Trigger Payment is otherwise due, NEP will grant a first priority, perfected security interest to Asset Purchaser in such portion of NEP's Contract Termination Charge revenues and related Service Agreements (the "CTCs") with Massachusetts Electric Company ("MECO") and The Narragansett Electric Company ("NECO") as is equal to the amount by which each Monthly Payment Obligation would be reduced pursuant to subsection (4) above had the Trigger Payment not been deferred. Such security interest shall be granted pursuant to a duly executed security agreement in form and substance reasonably satisfactory to Asset Purchaser, and shall provide that proceeds of the collateral shall be assigned to Asset Purchaser and paid by MECO and NECO to Asset Purchaser or as otherwise directed by Asset Purchaser; provided, however, that unless and until there shall occur an event of default under such security agreement, the Asset Purchaser will waive its right to receive proceeds directly from MECO and NECO pursuant to such assignment. Further, NEP shall not be permitted to exercise its election under subsection (5) unless the granting of the security interest contemplated in this subsection (6) and the assignment of proceeds in connection therewith shall be consented to by MECO and NECO. (7) During the term of this Agreement, NEP shall not grant, permit or suffer to exist any encumbrance, pledge, security interest, assignment, lien or other disposition of its rights to such portion of the CTCs referred to in subsection (6) above as is sufficient at all times to cover NEP's then remaining aggregate Monthly Payment Obligations and will at its sole expense take all actions required to remove and/or defend against any claim or encumbrance that may be created or asserted by any other party thereon. (8) Asset Purchaser shall release any security interest granted hereunder with respect to any Trigger Payment if: (a) NEP has provided Asset Purchaser with a letter of credit, collateral or other security in substitution for, and replacement of, the collateral referred to in Section 8(d)(6) which shall be at least equivalent in value to the security represented by such collateral as agreed between NEP and the Asset Purchaser, in the exercise of by each of its reasonable commercial judgment, or (b) NEP has paid Asset Purchaser the present value of the remaining security, using the Applicable Discount Rate applied in calculating the related deferred Trigger Payment. 9. This Agreement and all rights, obligations, and performances of the parties hereunder, are subject to all applicable Federal and state laws, and to all duly promulgated orders and other duly authorized action of governmental authority having jurisdiction. 10. Except as otherwise set forth in Section 5 hereof, this Agreement and all of the provisions hereof shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns, but neither this Agreement nor any of the rights, interests or obligations hereunder shall be assigned by any party hereto, including by operation of law without the prior written consent of the other party, nor is this Agreement intended to confer upon any other person except the parties hereto any rights or remedies hereunder. Notwithstanding the foregoing, (i) the Asset Purchaser may assign all of its rights and obligations hereunder to any wholly owned Subsidiary (direct or indirect) of PG&E Corporation and upon NEP's receipt of notice from Asset Purchaser of any such assignment, the Asset Purchaser will be released from all liabilities and obligations hereunder, accrued and unaccrued, such assignee will be deemed to have assumed, ratified, agreed to be bound by and perform all such liabilities and obligations, and all references herein to Asset Purchaser shall thereafter be deemed references to such assignee, in each case without the necessity for further act or evidence by the parties hereto or such assignee; provided, however, that no such assignment and assumption shall release the Asset Purchaser from its liabilities and obligations hereunder unless the assignee shall have acquired all or substantially all of the Asset Purchaser's assets; provided, further, however, that no such assignment and assumption shall relieve or in any way discharge PG&E Corporation from the performance of its duties and obligations under the Guaranty dated as of the date of this Agreement executed by PG&E Corporation; and (ii) the Asset Purchaser or its permitted assignee may assign, transfer, pledge or otherwise dispose of its rights and interests hereunder to a trustee or lending institution(s) for the purpose of financing or refinancing the Purchased Assets (as defined in the APA), including upon or pursuant to the exercise of remedies under a financing or refinancing, or by way of assignments, transfers, conveyances or dispositions in lieu thereof; provided, however, that no such assignment or disposition shall relieve or in any way discharge the Asset Purchaser or such assignee from the performance of its duties and obligations under this Agreement. NEP agrees to execute and deliver such documents as may be reasonably necessary to accomplish any such assignment, transfer, conveyance, pledge or disposition of rights hereunder so long as NEP's rights under this Agreement are not thereby altered, amended, diminished or otherwise impaired. 11. This Agreement, the APA and any other agreement entered into by the parties pursuant to the APA constitute the entire agreement between the parties and supersede all previous offers, negotiations, discussions, communications and correspondence. This Agreement may be amended only by a written agreement signed by the parties. This Agreement is not intended to confer upon any other person (including, without limitation, the Power Sellers) except the parties hereto any rights or remedies. The interpretation and performance of this Agreement shall be according to and controller by the laws of The Commonwealth of Massachusetts (regardless of the laws that might otherwise govern under applicable Massachusetts principles of conflicts of laws). 12. All payments required under this Agreement shall be paid in cash by federal or other wire transfer of immediately available funds to an account designated by the party to receive such payment. 13. This Agreement shall be of no force and effect until the Effective Date. If the APA shall have been terminated before the occurrence of the Closing Date (as defined in the APA), this Agreement shall, without any action of the parties hereto, terminate as of the time of the termination of the APA. As used in this Agreement, "Effective Date" shall mean the Closing Date (as defined in the APA). This Agreement amends and restates and, together with the OSP PPA Transfer Agreement, supersedes in its entirety the Original PPA Transfer Agreement. IN WITNESS WHEREOF, the parties have caused their duly authorized representatives to execute this Agreement on their behalf as of the date first above written. NEW ENGLAND POWER COMPANY s/Michael E. Jesanis By:______________________________ Name: Michael E. Jesanis Title: Treasurer USGEN NEW ENGLAND, INC. s/M. Richard Smith By:__________________________ Name: M. Richard Smith Title: Vice President EXHIBIT 10(bb)(vi) AMENDED AND RESTATED POWER SALES CONTRACT THIS AMENDED AND RESTATED POWER SALES CONTRACT (the "Contract") is made and entered into this 18th day of December 1998 (the "Contract Date"), by and between SOUTHERN ENERGY CANAL, L.L.C., a Delaware limited liability company ("Seller") and MONTAUP ELECTRIC COMPANY, a Massachusetts corporation ("Purchaser"). Seller and Purchaser are referred to herein individually as a "Party" and collectively as the "Parties." RECITALS: A. Seller is a party to that certain Asset Sale Agreement dated May 15, 1998 (the "Asset Sale Agreement") between Seller (as successor by assignment to Southern Energy New England, L.L.C.) and Canal Electric Company ("CEC") providing for the sale of Canal Unit 1 from CEC to Seller. B. Purchaser is a party to that certain Power Contract between Purchaser and CEC dated December 1, 1965 (the "Original Contract") for the sale of 25% of the capacity and energy from Canal Unit I to Purchaser, and CEC is a party to Power Contract s dated December 1, 1965 with each of Boston Edison Company, Commonwealth Electric Company and Cambridge Electric Light Company and New England Power Company (the "Other Purchasers' Original Contracts"), each of which is substantially identical to the Original Contract and provides for the sale of 25% of the capacity and energy to each of the other purchasers. C. In connection with the closing of the Asset Sale Agreement, CEC has assigned the Original Contract and the Other Purchasers' Original Contracts to Seller effective as of the closing, and the Parties hereto desire to enter into this Contract t o amend, restate, supersede and replace the Original Contract, effective on the closing of the Asset Sale Agreement. NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements hereinafter set forth, the Parties hereto mutually covenant and agree as follows: 1 Definitions "Affiliate" means any other entity (other than an individual) that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with, such entity. For purposes of the foregoing, "control" means the direct or indirect ownership of more than seventy percent of the outstanding capital stock or other equity interest having ordinary voting power. "Asset Sale Agreement" has the meaning set forth in Recital A. "Base Amount" has the meaning set forth in Section 5(a). "Bid Procedures" means the bid procedures agreed to by Seller and the Contract Purchasers Committee from time to time for bidding Canal Unit I to the ISO consistent with the then effective Operational Characteristics. "Business Day" means any day other than a Saturday, Sunday or a Holiday that is observed on a weekday. If any performance date referenced in this Contract is not a Business Day, such performance date shall be the next succeeding Business Day. "Canal Unit I" means Unit I at the Canal Station in Sandwich, Massachusetts. "CEC" means Canal Electric Company, formerly known as Plymouth County Electric Company. "Commonwealth/Cambridge" means collectively, Commonwealth Electric Company and Cambridge Electric Company. Commonwealth/Cambridge shall be deemed to be one Contract Purchaser. "Contract Costs" means the costs Purchaser incurs under and in connection with this Contract. "Clean Air Act" means the federal environmental statute enacted at 42 U.S.C.A. 7401 et seq. to regulate and control air pollution. "Contract" means this Amended and Restated Power Sales Contract between Seller and Purchaser. "Contract Date" means the date of this Contract. "Contract Parties" means Seller and the Contract Purchasers. "Contract Purchasers" means Purchaser and the Other Purchasers. "Contract Purchasers Committee" means the standing committee of representatives of the Contract Purchasers and Seller established pursuant to Section 3 of this Contract. "Contract Year" means a calendar year during the term of this Contract; provided, however, the first Contract Year shall begin on the Effective Date and end on December 31, 1999, and the last Contract Year shall end on the expiration of the term of this Contract. "Creditworthiness Criteria" means an entity which has a credit rating of at least "BBB-," from the Standard & Poor's Rating Group (a division of McGraw Hill), or its successor ("S&P") or an equivalent rating from Moody's Investor Services, Inc. or its successor ("Moody's"). The Creditworthiness Criteria may be satisfied by the delivery of collateral security for the obligations of a Party hereunder in the form of (i) a guarantee in form and substance reasonably satisfactory to the other Party from an entity that meets the Creditworthiness Criteria, or (ii) a direct-pay, irrevocable, standby letter of credit from a major U.S. commercial bank having a credit rating of at least "A" from S&P or "A-2" from Moody 7 s; each in an amount, form and substance reasonably approved by the other Party. "CTC" or "Contract Termination Charges" shall have the meaning set forth in that certain settlement filed by Purchaser with FERC in Docket Nos. ER97-2800 et al, which settlement FERC approved with conditions on December 19, 1997. "Defaulting Party" shall have the meaning set forth in Section 27(a). "Delivery Point" means the point where capacity, energy and ancillary services generated by Canal Unit I are delivered to the NEPOOL PTF. "Demand Charge" shall have the meaning set forth in Section 5. "Edison" means Boston Edison Company. "Effective Date" has the meaning set forth in Section 2(a). "Energy" shall have the meaning assigned to such term by the Restated NEPOOL Agreement. "Energy Charge" shall have the meaning set forth in Section 6. "Emissions Allowances" means NOx Emission Allowances and SO2, Allowances. "Emissions Charge" shall have the meaning set forth in Section 7. "Existing NOx Allowances" shall have the meaning set forth in Section 7. "Event of Default" shall have the meaning set forth in Section 27(a). "Fuel" means number six (No. 6) fuel oil. "Fuel Procurement Policy" means the policy established by Seller and approved by the Contract Purchasers Committee to procure Fuel for Canal Unit 1. "FERC" means Federal Energy Regulatory Commission. "Good Utility Practice" means any of the practices, methods or acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts that in the exercise of reasonable judgment in light of the facts known at the time a decision was made, could have been expected to accomplish the desired result at reasonable cost consistent with reliability, safety and expedition and giving due regard for the compliance with applicable law and the requirements of governmental agencies having jurisdiction and the rules, regulations and procedures of NEPOOL and the ISO. Good Utility Practice is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be a spectrum of acceptable practices,, methods or acts. "Hearing" shall have the meaning set forth in Section 23(b). "Holiday" means New Year's Day, President's Day, Patriot's Day, Memorial Day, Independence Day, Labor Day, Columbus Day, Veteran's Day, Thanksgiving Day, the day following Thanksgiving Day, and Christmas Day. "Installed Capacity" shall have the meaning assigned to such term by the Restated NEPOOL Agreement. "Interest Rate" means, for any date, two (2) percent over the per annum rate of interest equal to the prime lending rate as may from time to time be published in The Wall Street Journal under "Money Rates"; provided, however, that the Interest Rate shall never exceed the maximum lawful rate permitted by applicable law. "ISO" means ISO New England, Inc., the independent system operator for the New England region, and its successors and assigns. "Market Implementation Date" means the effective date of the implementation of the bid-based market for energy in NEPOOL. "Mediation Notice" shall have the meaning set forth in Section 23(a). "NEPCO" means New England Power Company. "NEPOOL" means the New England Power Pool, and its successors and assigns. "NEPOOL Defined Products" means any electrical generation-related products established by NEPOOL which may be produced by Canal Unit 1, including without limitation, Installed Capacity, Operable Capacity, Energy, Ten Minute Spinning Reserve, Ten Minute Nonspinning Reserve, Thirty Minute Operating Reserve and Automatic Generation Control, as such terms are defined by the Restated NEPOOL Agreement. "NEPOOL PTF" means the NEPOOL Pool Transmission Facilities, as defined by the Restated NEPOOL Agreement. "New Contract Purchasers" means Purchaser and the Other Purchasers which enter into an Other Purchasers' New Contract, from time to time. "Non-Defaulting Party" shall have the meaning set forth in Section 27(a)(iii). "NOx Emission Allowance" means an authorization under Massachusetts air quality regulations to emit one ton of nitrogen oxides during the period May 1 through September 30 of any given year. "NOx Season" means the months of May through September of each year. "Operational Characteristics" means the operating characteristics of Canal Unit I as set forth in the NEPOOL NX-12(a) report or any similar report delivered by Seller to the Contract Purchasers seasonally, as revised from time to by Seller to reflect changes in the actual physical operating characteristics of Canal Unit I or as agreed to by the Contract Purchasers Committee in accordance with Section 3(b)(ii). "Original Contract" has the meaning set forth in Recital B. "Other Purchasers" means Commonwealth/Cambridge, Edison and NEPCO and their respective successors and permitted assigns. "Other Purchasers New Contracts" means any agreement between Seller and any of the Other Purchasers which terminates, amends or replaces such Other Purchaser's Original Contract. "Other Purchasers' Original Contracts" has the meaning set forth in Recital B. "Party" and collectively the "Parties" refers to Seller and/or Purchaser. "Purchaser" means Montaup Electric Company and its successors and permitted assigns. "Restated NEPOOL Agreement" means the NEPOOL Agreement dated December 31, 1996, as amended from time to time. "RFP" means a request for proposal as defined in Section 25(b) hereof. "SCR" means selective catalytic reduction equipment and process installed on Canal Unit 1. "SCR Amount" shall have the meaning set forth in Section 5(b). "SCR Operation Date" means the date the SCR becomes operational for Canal Unit 1. "Seller" means Southern Energy Canal, L.L.C, and its successors and assigns. "Senior Officers Committee" means a committee of senior officers of each Contract Party established in accordance with Section 23(a). "SO2 Allowance" means an authorization under the Clean Air Act to emit one ton of sulfur dioxide on an annual basis. 2. Effective Date; Assignment and Amendment (a) This Contract shall become effective upon the closing of the Asset Sale Agreement (the "Effective Date"). If the Effective Date does not occur on or before December 31, 1998, Purchaser shall have the right to terminate this Agreement and resume service under the Original Contract if Purchaser gives Seller written notice of such termination by January 5, 1999. (b) Purchaser hereby consents to the assignment of the Original Contract by CEC to Seller, and the Parties hereby amend and restate in its entirety the Original Contract. Such assignment, amendment and restatement shall be effective on the Effective Date. Purchaser acknowledges and agrees that it is not aware of any claims against CEC under the Original Contract and Seller shall have no liability for any claims or demands of Purchaser under the Original Contract or this Contract arising with respect to acts or omissions prior to the Effective Date. (c) If FERC has not issued a final non-appealable order acceptable to Purchaser, in its sole discretion, approving Purchaser's recovery of Contract Costs as just and reasonable pursuant to the provisions of Purchaser's CTC by the Reopener Date, t hen within five (5) Business Days after the Reopener Date, Purchaser may deliver written notice to Seller requiring the Parties to amend the terms of this Contract so that the charges to Purchaser will be computed in accordance with the terms of the Original Contract. As used herein the Reopener Date" shall be July 3 1, 1999, however, if FERC has issued an order that is acceptable to Purchaser but is not final and non-appealable by such date, the Reopener Date shall be automatically extended for sixty (60) days. Such amendment of this Contract shall also require that the Parties will make payments to each other as necessary to true-up any charges from the Effective Date of this Contract until the effective date of any such amendment as compared to charges under the Original Contract for such period. Purchaser shall diligently seek to obtain an order from FERC approving the recovery of Contract Costs as just and reasonable pursuant to the provisions of Purchaser's CTC. (d) Notwithstanding Sections 5 and 6 below, if the Effective Date occurs before January 1, 1999, CEC shall bill Purchaser in accordance with the Original Contract for service provided between the Effective Date and January 1, 1999, and Seller will recover from CEC such portion of the charges as are, attributable to service between the Effective Date and January 1, 1999. Seller will use reasonable efforts to have CEC perform all accountings required under the Original Contract after January 1, 1999. 3. Contract Purchasers Committee (a) For the mutual advantage of the Contract Parties, a Contract Purchasers Committee shall be established consisting of one (1) representative from each of the Contract Purchasers and one (1) representative from Seller. The New Contract Purchasers shall each have the right to vote and any Other Purchasers shall have the rig ht to attend meetings but shall only have the right to vote on matters which require each such Other Purchaser's consent under such Other Purchaser's Original Contract. The Purchaser and Seller shall each appoint to the Contract Purchasers Committee officers or representatives that have the authority to act on behalf of their respective Parties to the extent required under the terms of this Contract. The Contract Purchasers Committee shall meet at least once every six months during the ten-n at such times as may be announced by Seller. Each member of the Contract Purchasers Committee shall have the right to call a meeting on at least ten (10) Business Days prior notice to the other members of the Contract Purchasers Committee. (b) The approval of the Contract Purchasers Committee, which approval shall not be unreasonably withheld, is required for the following: (i) a change in the Bid Procedures shall require the unanimous approval of the Contract Purchasers Committee; provided, however, any change which has or may have a material adverse effect on Canal Unit I shall require the written approval of Seller, which shall not be unreasonably withheld; (ii) Seller's change in the Operational Characteristics shall require the unanimous approval of the Contract Purchasers Committee, except any change required, in Seller's reasonable judgment, to adhere to Good Utility Practice; (iii) Seller's scheduling of any planned outage for routine maintenance and overhauls if such planned outage is scheduled during a time other than the spring or fall shall require the approval of a majority of the Contract Purchasers Committee; Seller shall consult with the Contract Purchasers Committee regarding all planned outages including the planned outage to install the SCR for Canal Unit 1. Seller shall keep the Contract Purchasers Committee informed of the outage schedule for the SCR, and changes thereto which in Seller's reasonable judgment are necessary or prudent to install the SCR shall not require approval of the Contract Purchasers Committee; (iv) any change to the Fuel Procurement Policy shall require the unanimous approval of the Contract Purchasers Committee; (v) the acquisition and disposition of NOx Emission Allowances and SO, Allowances for Canal Unit I shall require the approval of a majority of the Contract Purchasers Committee (to the extent acquisitions are approved, Seller may acquire Emission Allowances from Contract Purchasers in accordance with Section 7(g)); provided, however, Seller shall not be liable for the failure of the Contract Purchasers Committee to approve the acquisition of NOx Emission Allowances and/or SO, Allowances sufficient for the operation of Canal Unit 1; (vi) the appointment of an agent by Seller pursuant to Sections 8 and 9 which is not an Affiliate of Seller shall require the approval of a majority of the Contract Purchasers Committee; (vii) instituting a material capital addition or other action for which approval of the Contract Purchasers Committee is required pursuant to Section 9 shall require the approval of a majority of the Contract Purchasers Committee. (c) Seller's representative shall have the night to attend all Contract Purchasers Committee meetings but shall not have the power to vote except in the case of a deadlock on a matter which Seller determines should be resolved to comply with Good Utility Practice. In the event an Affiliate of Seller becomes a Contract Purchaser (as a result of an assignment of an Other Purchaser's Original or New Contract), Seller's right to vote in the preceding sentence shall terminate, but Seller's Affiliate shall have the power to vote on all matters except the approval of any fuel or other contract between Seller and an Affiliate of Seller which requires the consent of the Contract Purchasers Committee. In such instance the unanimous vote of the other members of the Contract Purchasers Committee shall be required to approve such matters. (d) In the event of a deadlock in the Contract Purchasers Committee which is not resolved by Seller in accordance with Section 3(c), any Party may give notice to the other Party instituting the dispute resolution provisions of Section 23 hereof. (e) Seller and Purchaser acknowledge that they have reached agreement as to the initial Bid Procedures for the period prior to the Market Implementation Date and for the period from and after the Market Implementation Date. Any change to the Bid Procedures shall be made in accordance with Section 3(b)(i) except Seller shall have the right to make any change that in Seller's reasonable judgment is necessary to comply with NEPOOL or ISO rules and procedures or any change in the Operational Characteristics. 4. Sale, Purchase and Power Price (a) Commencing on the Effective Date and during the term of this Contract, Seller shall make available and provide to Purchaser and Purchaser shall be entitled to twenty-five percent (25%) of the capacity and associated energy, along with any other generation- related products produced by Canal Unit 1 including, without limitation, operable capacity, operating reserves and automatic generation control. Purchaser acknowledges that it has no right to any output of Canal Unit I following the termination of this Contract unless otherwise agreed to in writing by Seller. (b) With respect to each month commencing on the Effective Date, Purchaser shall pay Seller the amounts provided in this Contract. 5. Demand Charge The Demand Charge for each respective month during the term of this Contract shall be the Base Amount for such month plus the SCR Amount for such month. If the Effective Date occurs on a date other than the first day of a month, the Demand Charge for such month shall be appropriately pro-rated. (a) Base Amount. The Base Amount for each month during the term of this Contract shall be as follows: Year 1999 - $734,895.00 each month 2000 - $691,042.00 each month 2001 - $748,271.00 each month 2002 - $758,121.00 for each month from January through September, and $236,499.00 for October. (b) SCR Amount. The SCR Amount for each month during the term of this Contract beginning with January 2000 shall be: Year 2000 - $72,500.00 each month 2001 - $71,042.00 each month 2002 - $89,767.00 each month from January through September, and $29,594.00 for October. Notwithstanding the foregoing, if the SCR Operation Date has not occurred on or prior to the beginning of the NOx Season in 2000 or any year thereafter, the SCR Amount for such year shall be reduced as follows: (i) For each month during the NOx Season prior to the SCR Operation Date, the aggregate amount of the SCR Amount for such year shall be reduced by one- fifth (1/5th). (ii) If the SCR Operation Date occurs during a month in the NOx Season, the SCR Amount shall be prorated for such month. (iii) If the SCR Operation Date has not occurred on or prior to May 1, 2000, any amounts of the SCR Amount which have been paid by Purchaser prior to the SCR Operation Date shall be used by Seller as an advance to pay for Purchaser's share of any N Ox Allowances needed for the operation of Canal Unit 1 in accordance with Section 7(b) hereof, and any residual advance shall then be used as an offset against any further SCR Amount payable by Purchaser hereunder. Seller shall notify the Contract Purchasers Committee of the occurrence of the SCR Operation Date. Except as otherwise provided above, Seller shall have no liability to Purchaser for any delay in the SCR Operation Date. 6. Energy Charge The Energy Charge shall be 25% of all Fuel and Fuel handling costs incurred by Seller for Canal Unit I in accordance with the following: (a) Fuel shall be purchased by Seller from any Fuel supplier, including any Affiliate of Seller, in accordance with the Fuel Procurement Policy in effect from time to time. The Parties acknowledge and agree that they have reached agreement as to the initial Fuel Procurement Policy. Any changes to the Fuel Procurement Policy shall be made in accordance with Section 3(b)(iv). (b) The delivered cost of Fuel shall be charged to the Contract Purchasers monthly at Seller's cost based upon the sum of the daily deliveries to the Canal Unit 1 day tank. 7. Emissions Allowances (a) Seller shall allocate to Canal Unit I fifty percent (50%) of the Nox Emission Allowances allocated to the Canal Station (Canal Unit 1 and Canal Unit 2) by governmental agencies (the "Existing NOx Allowances"). (b) To the extent the Existing NOx Allowances are insufficient for the operation of Canal Unit I prior to the SCR Operation Date, Purchaser shall pay, as the "Emissions Charge," 25% of the cost of all NOx Emission Allowances acquired by Seller for Canal Unit I to comply with emission requirements applicable to Canal Unit 1. Seller shall charge Purchaser for twenty five percent (25%) of the cost of any NOx Emission Allowances, in excess of the Existing NOx Allowances, purchased by Seller from CEC at the closing of the Asset Sale Agreement. The amounts for the purchased NOx Emission Allowances shall be charged to the Contract Purchasers as the NOx Emission Allowances are used, and the purchased NOx Emission Allowances shall be deemed to be used prior to the Existing NOx Allowances. Seller may charge the Contract Purchasers interest on the purchase price of unexpensed NOx Allowances at the Interest Rate minus 2% per annum. (c) Seller is planning to install an SCR for Canal Unit I to become operational on or before May 1, 2000 which will be designed to achieve a reduction in NOx emissions for Canal Unit 1. Seller's cost of installing the SCR is included in the SCR A mount in the Demand Charges for 2000 and thereafter, and Purchaser shall not otherwise be responsible for any capital or operations and maintenance costs associated with the SCR. (d) Purchaser shall pay Seller for 25% of the cost of SO2 Allowances which are required for the operation of Canal Unit 1 in excess of the SO, Allowances allocated to Canal Unit I prior to the Effective Date. (e) If Seller projects that Seller will have excess Emission Allowances for any year during the term of this Contract, Seller shall so notify the Contract Purchasers Committee and Seller shall liquidate such Emission Allowances or retain such Emission Allowances for use in following years in accordance with the direction of the Contract Purchasers Committee. Seller shall distribute to Purchaser 25% of the proceeds of such a liquidation. (f) If Seller is planning to purchase additional NOx Allowances in accordance with the terms of this Agreement, Purchaser shall have the night to provide NOx Allowances to Seller, and in such event Purchaser shall receive a credit for the amount of NOx Allowances provided to Seller. Such credit shall be used to offset the charges Purchaser is obligated to pay for the Nox Allowances acquired by Seller for Canal Unit I or other charges pursuant to this Contract. (g) Seller shall pay or bear the cost of any fine or penalty arising from Seller's failure to observe and comply with Good Utility Practices in the operation of Canal Unit 1, where such failure results in insufficient Emissions Allowances for Canal Unit 1. Seller shall under no circumstances be obligated to operate Canal Unit I in a manner that would result in noncompliance with any emissions related requirement. 8. Scheduling Protocol Prior to the Market Implementation Date During the term of the Contract up to the Market Implementation Date: (a) Seller shall provide information regarding Canal Unit 1 to the ISO in accordance with the Bid Procedures to enable the ISO to dispatch Canal Unit 1. (b) Seller shall be responsible for coordinating the submission of all necessary information on behalf of Contract Purchasers and for communicating the outcome of the dispatch to Contract Purchasers. (c) Purchaser shall be entitled to 25% of the capacity and associated energy along with any other generation-related products produced by Canal Unit 1, including without limitation, operable capacity, operating reserves, and automatic generation control. (d) Seller and Purchaser shall take all action necessary in accordance with NEPOOL procedures to ensure that Purchaser shall receive appropriate credit for its 25% of the generation related products produced by Canal Unit 1, including without limitation, energy, installed capacity, operable capacity, operating reserves, and automatic generation control resulting from the ISO dispatch of Canal Unit 1. (e) Seller may appoint an agent to perform its obligations under this Section 8. The appointment of any agent which is not an Affiliate of Seller shall require the consent of a majority of the Contract Purchasers Committee, which consent may not be unreasonably withheld. 9. Scheduling Protocol After Market Implementation Date During the term of the Contract from and after the Market Implementation Date: (a) Purchaser shall receive its 25% share of Installed Capacity and Operable Capacity and shall be responsible for bidding such Installed Capacity and Operable Capacity to the ISO. Purchaser shall be entitled to all payments from ISO for such share of Installed Capacity and Operable Capacity. (b) Seller on behalf of all Contract Purchasers shall submit bids to the ISO for all NEPOOL Defined Products, other than Installed Capacity and Operable Capacity, in accordance with the Bid Procedures and the Operational Characteristics of Canal Unit I in order to enable the ISO to dispatch Canal Unit I in accordance with NEPOOL procedures. (c) Seller and Purchaser shall take all action necessary in accordance with NEPOOL procedures to ensure that Purchaser shall receive credit with the ISO for Purchaser's 25% of all NEPOOL Defined Products resulting from Canal Unit 1. (d) Seller shall be responsible for coordinating the submission of the bids, in compliance with the Bidding Procedures, to ISO on behalf of Contract Purchasers and Seller shall communicate the outcome of the dispatch to Contract Purchasers. The Purchaser and Seller shall cooperate to provide information to each other to comply with ISO rules and procedures. (e) Seller may appoint an agent to perform its obligations under this Section 9. The appointment of any agent which is not an Affiliate of Seller shall require the consent of a majority of the Contract Purchasers Committee, which consent may not be unreasonably withheld. 10. Accountings and Payment (a) Seller will deliver to Purchaser an invoice within ten (10) Business Days after the end of the month, or at such later date as is practicable, for all amounts payable by Purchaser with respect to the previous month. Such bills will be rendered in such detail as Purchaser may reasonably request. All bills are due and payable on the last Business Day of the month when rendered, but no earlier than seven (7) Business Days after receipt of the invoice. Each monthly billing may include expenses or charges for the amounts payable hereunder, estimated on a periodic basis. Adjustments of items included in prior billings shall be made in current billings. Adjustments shall accrue interest at the Interest Rate. Adjustments of such items may be made at any time within one year after the invoice as the result of-. (1) Occurrences which change amounts owed or paid to third parties by Seller or owed or paid to Seller by third parties. (2) Errors or omissions in computing the billing as required by this Contract. Purchaser shall pay Seller by wire transfer to an account specified by Seller from time to time. (b) Within 120 days after the end of each Contract Year, Seller shall render to Purchaser an accounting of such Contract Year's fuel usage and other amounts billed as a pass through to Purchaser, and any adjustment of the total amount billed for the period of said accounting shall be made in accordance with said yearly accounting. No Party shall have the night to challenge said yearly accounting or adjustment, to invoke dispute resolution under Section 23 of the same, or to bring any court or administrative action of any kind questioning the propriety of said accounting, with respect to any adjustment under paragraph (a)(2) of this Section (namely, any error or omission in computing the billing as required by this Contract), after a period of one year from the date said accounting is rendered. For purposes of this one year limitation provision, any adjustments made under paragraph (a)(1) of this Section (namely, adjustments occasioned by occurrences changing amounts owed to or by third parties), shall be deemed to have been made, whether or not actually made, in the year in which said adjustments are finally determined as between Seller and third parties. (c) Seller's books and records which directly pertain to the charges rendered to Purchaser shall be open to reasonable inspection and audit by Purchaser. (d) Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment. 11. Delivery The electricity generated for the Purchaser by Canal Unit I shall be delivered to Purchaser in the form of three (3) phase, sixty (60) cycle, alternating current at the Delivery Point. Purchaser will make its own arrangements for the transmission of power beyond the Delivery Point. 12. Term Unless earlier terminated pursuant to Section 2, 17 or 27, this Contract shall expire on October 10, 2002. 13. Purchaser's Right to Replacement Contract Purchaser shall have the option to enter into a new contract for the purchase of 25% of the capacity, energy, ancillary services and other NEPOOL Products from Canal Unit I for the five (5) year period commencing with the expiration of this Contract by delivering written notice to Seller on or before December 31, 1999 of its irrevocable election to enter into such contract. The terms of such replacement contract shall be as set forth on Schedule 1 attached hereto. If such option is exercised, the Parties shall negotiate in good faith to finalize and execute the replacement contract promptly after December 31, 1999. 14. Force Majeure Seller shall use all due diligence in accordance with Section 18 to deliver to Purchaser regularly and without interruption the electricity to which it is entitled under this Contract, but Seller shall be excused from delivering electricity hereunder if and to the extent that it shall be prevented from doing so by action of any court or any public authority or by reason of delays in construction, or total or partial shutdown of Canal Unit I by reason of breakdown, scheduled or unscheduled repair s or maintenance, strike, labor troubles, civil disorders, flood, fire or any cause beyond the reasonable control of Seller. Seller will use due diligence to resume normal delivery of electricity in accordance with Good Utility Practice. 15. Insurance Seller agrees to keep insured at all times Canal Unit I and all appurtenant facilities against all property risks on which insurance is available at commercially reasonable terms and conditions from reputable insurance companies including but without limitation thereto: (a) fire, explosion, wind, flood, earthquake, falling aircraft, vandalism, malicious mischief, not and civil commotion. (b) full breakdown of turbines, explosion, collapse or rupture of boilers and pressure vessels. All the foregoing insurance shall be carried in an amount at least equal to the reproduction cost new of the insured property less depreciation or, at Seller's option, a limit equal to two times the probable maximum loss for the facility as determined by an independent expert. Seller also agrees to carry basic public liability insurance with limits of at least $100,000/$1,000,000, basic property damage insurance with limits of at least $500,000 and a comprehensive excess combined personal injury and property damage policy with limits of at least $15,000,000. 16. No Right of Setoff Except as expressly provided in Section 5(b), neither Party shall be entitled to set off, deduct or withhold against the payments required to be made by it under this Contract any amounts which may from time to time be owed to it by the other Party. However, the foregoing shall not affect in any other way the rights and remedies which a Party may have with respect to any such amounts. 17. Cancellation of Contract (a) If Seller is unable to make energy deliveries to Purchaser because either (1) Canal Unit I is damaged to the extent of being completely or substantially completely destroyed, whether or not by reason of causes noted in Section 14 hereof, (2) Canal Unit I is taken by exercise of the right of eminent domain or a similar right or power; or (3) (A) Canal Unit I cannot be used because a necessary license or other necessary public authorization cannot be obtained or is revoked despite Seller's reasonable efforts in accordance with Good Utility Practice to maintain such license or public authorization, or because the use of such license or such authorization is made subject to specified conditions which are not met, and (B) the situation cannot be rectified to an extent which will permit Seller to make deliveries to Purchaser from Canal Unit 1, then and in each such case, either Party may cancel this Contract upon at least ten (10) Business Days prior notice to the other Party. (b) In all other circumstances no cancellation of the Contract or discontinuance of payments shall be permitted. 18. Operation and Maintenance Seller will operate and maintain Canal Unit I in accordance with Good Utility Practice, all applicable law and in' Contract Purchasers' best interest consistent with Good Utility Practice. Outages for inspection, maintenance and necessary capital replacements will be scheduled in accordance with Good Utility Practice and insofar as practicable shall be mutually agreed upon by a majority of the Contract Purchasers Committee to the extent the capital replacements affect the Contract Parties' rights and obligations under this Contract. In the event of an unscheduled outage due to the failure or impairment of any equipment or other cause, Seller will use its reasonable efforts in accordance with Good Utility Practice to restore Canal Unit It of service as soon as reasonably practical. Seller agrees to use due diligence to maintain at Canal Unit I fuel inventory for the operation of Canal Unit 1 in accordance with Good Utility Practice. 19. Change in Law In the event of a change in law, regulation or other legal requirement after the date of this Contract which materially increases Seller's costs of providing service to Purchaser, Seller shall confer with the Contract Purchasers Committee to discuss the most economical manner to address such change in costs in an effort to minimize the increase in costs. Seller shall obtain the approval of a majority of the Contract Purchaser's Committee as to the prudent course of action if such action require s any additional cost, including without limitation any material capital addition. Seller shall adjust the Demand Charge and/or the Energy Charge in a reasonable manner to allow Seller to recover from Purchaser 25% of the increased costs resulting from such change in law, regulation or other legal requirements and incurred in accordance with the actions approved by a majority of the Contract Purchasers Committee. Twenty-five percent (25%) of the reasonable costs of any such material capital addition shall be passed through to Purchaser at a reasonable rate of return, amortized over the normal useful life of the capital addition. The Contract Purchasers Committee shall not unreasonably withhold its consent to action proposed by Seller to respond to such change in law, regulation or other legal requirement, and in no event shall Seller be prevented from complying with such change. In the event of a change in law, regulation or other legal requirement after the date of this Contract which materially decreases Seller's costs of providing service to Purchaser, Seller shall adjust the Demand Charge and/or the Energy Charge in a reasonable manner to pass through to Purchaser 25% of the benefits of any cost reduction resulting from such change. 20. Taxes Purchaser shall pay any and all sales taxes, gross receipts taxes, excise taxes, franchise fees or any other fees or charges, including, without limitation, any BTU tax or carbon tax, imposed by any federal, state or local government or any regulatory agency over the provision of service hereunder or Canal Unit 1 (including without limitation any tax imposed on NEPOOL Defined Products produced by Canal Unit I or any tax imposed on interconnection services) with the exception of income taxes or property taxes. Seller represents and warrants that as of the date hereof it is not aware of any such taxes, fees or charges which are imposed by any governmental authority and which would be payable by Purchaser in accordance with this Section 20. 21. Interpretation The interpretation and performance of this Contract shall be in accordance with and controlled by the law of the Commonwealth of Massachusetts. 22. Regulation This Contract, and all rights, obligations and performance of the Parties hereunder, are subject to all present and future applicable federal, state and local laws and to all present and future duly issued and promulgated orders, regulations, requirements and other duly authorized action of any governmental authority having jurisdiction in the premises. 23. Dispute Resolution (a) In case of any dispute between the Parties and after notice of such dispute has been delivered from one Party to the other Party, such dispute shall be referred to the Contract Purchasers Committee for resolution. If the Contract Purchasers Committee fails to resolve the dispute in a manner satisfactory to each Party within 30 days after notice of said dispute is received by a Party, either Party may submit the matter to a Senior Officers Committee composed of the Presidents or other senior officers of each Party. Each Contract Party shall designate a senior officer to serve on the Senior Officers Committee for the purpose of resolving the dispute. If the Senior Officers Committee fails to resolve the dispute within 15 days following the submission of the dispute to said committee, either Party may give the other Party notice (a "Mediation Notice") that the dispute shall be referred to mediation in accordance with Section 23(b). If the dispute between the Parties involves one o r more of the Other Purchasers, each of the Other Purchasers shall have the rights of the Parties under this Section 23(a). (b) If either Party delivers a Mediation Notice to the other Party, the Parties shall participate in a non-binding dispute resolution procedure whereby each Party presents its case at a hearing (the "Hearing") before a neutral mediator approved by each Party. If the Parties fall to agree upon the mediator within seven (7) days after the date of the Mediation Notice, either Party may direct the American Arbitration Association to select the mediator. Each Party may be represented at the Hearing by lawyers. If the mediation proceedings do not result in a resolution of the dispute, such mediation proceedings shall be without prejudice to the legal position of either Party. The Parties shall each bear their respective costs incurred in connection with this procedure, except that the fees and expenses of the neutral mediator and the costs of the facility for the Hearing shall be allocated in the amount of fifty percent (50%) to each Party. If the dispute is not resolved pursuant to Section 23(a) or within twenty one (21) days after the date of the Mediation Notice, either Party may pursue any and all remedies and legal proceedings as are available. If the dispute between the Parties involves one or more of the Other Purchasers, each of the Other Purchasers shall have the rights of the Parties under this Section 23(b), and the fees and expenses of the neutral mediator and the costs of the facility for the Hearing shall be allocated equally among the Parties and the Other Purchasers involved in the dispute. (c) Nothing in this Section 23 shall limit the rights of either Party to seek in any court of competent jurisdiction such interim relief as may be needed to maintain the status quo, to prevent irreversible harm, or otherwise protect the subject matter of the mediation until the matter shall have been finally resolved; provided, however, any such interim relief ordered by a court shall not determine or prejudge the substantive issues to be decided by such mediation. (d) Notwithstanding anything to the contrary in this Section 23 or any other provision in this Contract, if Purchaser disputes an amount invoiced pursuant to Section 10 of this Contract, Purchaser shall pay the invoiced amount in full prior to invoking this Section 23, subject to later return with interest accrued in the interim at the Interest Rate. 24. Communications and Addresses Except as the Parties may otherwise agree, any notice, request, bill or other communication from one Party to the other, relating to this Contract or the rights, obligations or performance of the Parties hereunder, shall be in writing and shall be effective upon delivery to the other Party. Any notice, request, demand, or statement, which may be given to or made upon a Party hereto by the other Party hereto under any of the provisions of this Contract, shall be in writing unless it is specifically provided otherwise herein, and shall be treated as duly delivered either ( 1) when the same is delivered in person or by reliable courier service or (2) three (3) days after being deposited in the United States mail, by certified mail, postage prepaid, and properly addressed to the Party to be served at the addresses listed below the signature of such Party, or such other address as a Party may notify the other in accordance with this Section 24. 25. Amendments (a) Any amendments to this Contract shall be in writing. If the terms of any of the Other Purchasers' New Contracts, as amended from time to time, are different from the terms of this Contract, Seller shall give Purchaser the right to amend this Contract to the same or substantially similar terms to such Other Purchaser's New Contract. Purchaser shall notify Purchaser in writing within 15 days after Seller enters into any Other Purchaser's New Contract or any amendment thereto which contains different terms than the terms herein. Purchaser shall have 15 days after receipt of such notice to enter into an amendment of this Contract to contain such different terms. (b) Prior to Seller or its Affiliate accepting an assignment of any Other Purchaser's New Contract or Original Contract, Seller shall first issue a request for proposals (an "RFP") to Purchaser regarding the terms (other than price) under which Seller or its Affiliate is willing to accept such an assignment. The RFP shall allow Purchaser to submit an offer for the assignment of this Contract to Seller or its Affiliate, and such offer shall not be deemed to be nonconforming simply because this Contract contains different terms than an Other Purchaser's Original Contract or New Contract. If Purchaser submits a conforming offer, Seller or its Affiliate shall not accept an assignment from an Other Purchaser for a price that is less favorable to Seller than the offer submitted by Purchaser. Seller and its Affiliate shall not be under an obligation to accept any offer in response to the RFP, and if Seller or its Affiliate changes the terms under which it intends to accept an assignment of an Other Purchaser's Original Contract or New Contract, Seller shall reissue the RFP. (c) Seller's obligation under Section 25(b) shall terminate upon Purchaser's assignment of this Contract to a third party. 26. Assignment (a) Neither Party may assign this Contract without the written consent of the other Party except in accordance with this Section 26. (b) Upon not less than fifteen (15) days prior written notice to Purchaser, Seller may assign this Contract to any party which acquires Canal Unit I and which meets the Creditworthiness Criteria, provided, however, Purchaser shall not unreasonably withhold its consent if a proposed assignee is a direct or indirect subsidiary of an entity which meets the Creditworthiness Criteria. Seller may assign this Contract as security to its lenders and their agents. (c) Upon not less than fifteen (1 5) days prior written notice, Purchaser may assign this Contract to any party which meets the Creditworthiness Criteria provided, however, Seller shall not unreasonably withhold its consent if a proposed assignee is a direct or indirect subsidiary of an entity which meets the Creditworthiness Criteria. Purchaser may assign this Contract as security to its lenders and their agents. (d) Any other assignment of this Contract shall not operate to relieve the assigning Party of its obligations under this Contract without the written consent of the other Party. Each Party agrees to execute such consents as are reasonably requested by the other Party for an assignment to its lenders. 27. Default: Remedies; Limitation of Liability (a) As used herein, "Event of Default" shall mean, in relation to a Party (the "Defaulting Party"): (i) Purchaser as the Defaulting, Party fails to make any payment that is required hereunder to be made to Seller when due, and such failure continues for five (5) Business Days after written notice from Seller; (ii) Seller as the Defaulting Party breaches Section 4(a) by making deliveries of Purchaser's portion of NEPOOL Products from Canal Unit 1 to third parties; (iii) the Defaulting Party fails to perform any of its material obligations hereunder, other than as provided in subsection (i) or (ii), and such failure is not excused by force majeure and continues for sixty (60) days after the Defaulting Party receives written notice from the other Party (the "Non Defaulting Party") of such failure; provided, however, with respect to a failure to cure any such obligation, if a period in excess of sixty (60) days is required to cure such failure, the Defaulting Party shall have such additional amount of time, not to exceed one hundred eighty (I 80) days, as may be necessary to cure such failure provided that the Defaulting Party uses reasonable diligence to remedy such failure in accordance with Good Utility Practice; or (iv) the Defaulting Party makes an assignment or general arrangement for the benefit of creditors, files a petition in, or otherwise commences any proceedings in, bankruptcy or under similar law, or otherwise becomes bankrupt (however evidenced). (b) In the event Seller falls to deliver energy from Canal Unit I as a result of Seller's breach of its obligations under Section 18 which is not excused by Section 14, during any cure period provided in Section 27(a)(iii) Purchaser shall be entitled to all remedies available under Section (c) except termination of this Contract. Purchaser shall give Seller prompt written notice whenever Purchaser believes that the provisions of this Section 27(b) are applicable. (c) Upon an Event of Default, the Non-Defaulting Party may resort to all remedies available at law or in equity, subject to the limitations set forth in Section 27(d). If it is necessary for any Party to institute legal proceedings or retain an attorney in attempting to collect a delinquent bill. the other Party shall pay any and all expenses and costs of collection, including reasonable attorneys' fees, incurred by such collecting Party. (d) Except as otherwise explicitly stated herein, in no event shall either Party be liable for punitive, exemplary, special, consequential or incidental damages arising from any breach or default under this Contract, or from any act or omission under or in connection with this Contract. Seller's rights to payment of the Demand Charge, Energy Charge and other amounts payable hereunder shall not be deemed to be consequential damages. Purchaser's rights to payment for its incremental costs of Energy and other NEPOOL Defined Products as damages in the event of a breach of this Contract shall not be deemed to be consequential damages. 28. Indemnity Each Party expressly agrees to indemnify, hold harmless and defend the other Party against all claims, liability, costs or expense for loss, damage or injury to persons or property in any manner directly or indirectly connected with or arising out of, the generation, transmission or distribution of electric energy on its own side of the Delivery Point. 29. Prior Agreements Superseded Unless otherwise specifically provided, upon the Effective Date this Contract supersedes any and all prior agreements and contracts by and between the Parties relative to Canal Unit 1, including without limitation the Original Contract. This Contract has been made within the Commonwealth of Massachusetts and shall bind and inure to the benefit of the Parties hereto and their respective successors and permitted assigns. IN WITNESS WHEREOF, the Parties have caused this Amended and Restated Power Sales Contract to be executed by their officers duly authorized thereunto and have duly caused their corporate or company seals to be affixed hereto. SOUTHERN' ENERGY CANAL, L.L.C. By: /s/ Henry Coolidge Henry Coolidge, President Address: c/o Southern Energy Resources, Inc. 900 Ashwood Parkway, Suite 500 Atlanta, GA 30338 Attention: Alan Harrelson Vice President North American Assets MONTAUP ELECTRIC COMPANY By: /s/ Kevin A. Kirby Kevin A. Kirby, Vice President Address: Montaup Electric Company c/o EUA Service Corporation 75 West Center Street West Bridgewater, MA 02379 SCHEDULE 1 TERMS OF REPLACEMENT CONTRACT Same terms as the Power Contract, except: Demand Charge shall be 25% of the following: October 11, 2002 through December 31, 2002 $ 9,370,000.00 January 1, 2003 through December 31, 2003 $42,260,000.00 January 1, 2004 through December 31, 2004 $46,460,000.00 January 1, 2005 through December 31, 2005 $52,520,000.00 January 1, 2006 through December 31, 2006 $53,810,000.00 January 1, 2007 through October 10, 2007 $55,130,000.00 Any increases to the Demand Charge in the existing contract as a result of change of law shall be added to the above charges. Any increases in property taxes following 2005 will be passed through to Contract Purchasers. Voting among the Contract Purchasers Committee will be weighted based on percentage of entitlement from Canal Unit 1. For example, if two Contract Purchasers elect to enter into the Replacement Contract and Seller's Affiliate contracts for the remaining 50%, Seller's Affiliate would have 50% of the votes on the Contract Purchasers Committee. Each Party shall negotiate in good faith to make other reasonable modifications to terms of the Contract as may be requested by either Party. EX-10 (bb)(vii) POWER PURCHASE AGREEMENT BETWEEN ENTERGY NUCLEAR GENERATION COMPANY AND MONTAUP ELECTRIC COMPANY FOR PILGRIM NUCLEAR POWER STATION TABLE OF CONTENTS ARTICLE 1. Definitions ARTICLE 2. Purchase and Sale of Installed Capability, Operable Capability and Energy ARTICLE 3. Term, Termination ARTICLE 4. Purchase Rate for Installed Capability, Operable Capability and Energy ARTICLE 5. Dispatch ARTICLE 6. Billing, Meter Reading ARTICLE 7. Limitation of Liability; Indemnification; Insurance; Relationship of Parties ARTICLE 8. Miscellaneous Provisions ARTICLE 9. Assignment ARTICLE 10. Force Majeure ARTICLE 11. Default ARTICLE 12. Governing Law, Dispute Resolution ARTICLE 13. Waiver ARTICLE 14. Corporate Authorization ARTICLE 15. Notice POWER PURCHASE AGREEMENT BETWEEN ENTERGY NUCLEAR GENERATION COMPANY AND MONTAUP ELECTRIC COMPANY AGREEMENT entered into this 18th day of November 1998 by and between Entergy Nuclear Generation Company , a Delaware corporation (hereafter referred to as "Seller"), and Montaup Electric Company, a Massachusetts corporation having its principal place of business at W. Bridgewater, Massachusetts 02379, (hereafter referred to as "Company"). WHEREAS, Seller wishes to purchase from Boston Edison Company ("Boston Edison") the specific generating facility known as Pilgrim Nuclear Power Station (the "Facility"), pursuant to the terms of a certain Purchase and Sale Agreement dated November 18, 1998 by and between Boston Edison and Seller (the "Purchase and Sale Agreement"); and WHEREAS, Company contemplates that in connection with such purchase by Seller it will be necessary to terminate Company's rights and obligations under a certain power sale agreement with Boston Edison initially entered into on August 1, 1972, which provides for the sale of power from the Facility by Boston Edison to Company (the "Power Sale Agreement"); and WHEREAS, Company and Boston Edison have agreed to amend the Power Sale Agreement in order to effectuate such termination pursuant to the terms of the Third Amendment to the Power Sale Agreement dated November 18, 1998 by and between Company a nd Boston Edison ("Third Amendment"); and WHEREAS, as a condition to, and upon such termination and the closing of, the sale of the Facility to Seller, Seller wishes to sell to Company and Company wishes to purchase from Seller Installed Capability, Operable Capability and Energy from the Facility; NOW, THEREFORE, in consideration of the mutual promises and agreements contained herein, Seller and Company hereby agree as follows: ARTICLE 1. Definitions When used with initial capitalizations, whether in the singular or in the plural, the following terms shall have the meanings set forth below. (a) Agreement: This document, including its appendices, as amended from time to time. (b) Capability Audit: The procedure used pursuant to the NEPOOL Agreement to determine the Summer Net Capability and the Winter Net Capability of the Facility as currently set forth in the NEPOOL Standards. (c) Company's Entitlement: The percentage specified below of the Installed Capability, Operable Capability and Energy of the Facility for the applicable calendar years. 1999 11.00000% 2000 11.00000% 2001 11.00000% 2002 8.80000% 2003 5.50000% 2004 5.50000% (d) Energy: The actual hourly electricity production of the Facility adjusted for station service use and transformer losses. (e) Delivery Point: The point where capacity and energy generated by the Facility is delivered to the Pool Transmission Facilities, as defined by the NEPOOL Agreement. (f) Facility: The Pilgrim Nuclear Power Station, a 670 MW nuclear generating facility located in Plymouth, Massachusetts. (g) FERC: The Federal Energy Regulatory Commission. (h) Installed Capability: The Winter Net Capability during the Winter Period and the Summer Net Capability during the Summer Period. (i) ISO-NE: The Independent System Operator of New England provided for in the NEPOOL Agreement, or its successor. (j) MDTE: The Massachusetts Department of Telecommunications and Energy. (k) NEPOOL: The New England Power Pool, established by the NEPOOL Agreement, or its successor. (l) NEPOOL Agreement: The agreement, dated September 1, 1971, as amended from time to time, governing the operation of NEPOOL, as in full force and effect. (m) NEPOOL Standards: All Criteria, Rules and Standards (CRS), NEPOOL Automated Billing System Procedures (NABS), Operating Procedures (OP), and Market Rules (MR) issued or adopted by NEPOOL, ISO-NE and its satellite agencies, or their successors, as amended from time to time and all successor regulations, rules and standards. (n) Operable Capability: The portion of Installed Capability of the Facility which is operating or available to respond within an appropriate period (as defined by NEPOOL) to the ISO-NE call to meet the Energy requirements of the NEPOOL operating area. (o) Party: Seller or Company and its respective successors or assigns. (p) Prime Rate: That rate as announced by BankBoston (or its successor) as its prime rate in effect on the first day of the month. (q) Prudent Utility Practice: Any practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition and giving due regard for the requirements of governmental agencies having jurisdiction. Prudent Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the electric utility industry. (r) Summer Net Capability (Capability): The Maximum Claimed Capability, as defined in NEPOOL CRS - 4 , of the Facility during the Summer Period, expressed in kilowatts, and as determined by Capability Audit, exclusive of the capacity required for Facility use. (s) Summer Period: Summer Period shall have the meaning set forth in the NEPOOL Agreement. (t) Winter Net Capability (Capability): The Maximum Claimed Capability, as defined in NEPOOL CRS - 4 , of the Facility during the Winter Period, expressed in kilowatts, and as determined by Capability Audit, exclusive of the capacity required for Facility use. (u) Winter Period: Winter Period shall have the meaning set forth in the NEPOOL Agreement. ARTICLE 2. Purchase and Sale of Installed Capability, Operable Capability and Energy (a) Seller agrees to sell and to deliver and Company agrees to purchase and to accept delivery of the Company's Entitlement at the Delivery Point, for Company's own use and/or sale to others for the term of this Agreement. (b) Seller shall use Prudent Utility Practices in all aspects of the management and operation of the Facility. Seller shall use commercially reasonable efforts to maintain the Facility's Installed Capability at the level demonstrated by the most recent Capability Audit at the time of the Purchase and Sale Agreement and use its commercially reasonable efforts to make Energy and Operable Capability available to Company on an ongoing basis. Notwithstanding the foregoing, Seller may permanently retire the Facility upon 30 days written notice to the Company, at which time this Agreement will terminate. (c) Periodically after the execution of this Agreement, Seller shall undergo Capability Audits pursuant to NEPOOL Standards to demonstrate and audit the Summer Net Capability and/or the Winter Net Capability of the Facility. The Capability Audit shall be performed pursuant to NEPOOL Standards or standards mutually agreed to by the Parties if NEPOOL ceases to establish such standards. Seller agrees to provide to Company the results of the demonstrations and audits (NX-17s and supporting material). (d) Seller shall schedule maintenance activities in accordance with NEPOOL Standards. As soon as practically possible, Seller shall provide advance notice of planned maintenance activities and unplanned outages by telephone or telecopy to Company's designated agent. ARTICLE 3. Term, Termination The obligations of the Parties under this Agreement shall commence on the Effective Date as defined in the Third Amendment and, subject to the termination provisions set forth in this Agreement, shall continue through December 31, 2004. In addition, applicable provisions of this Agreement shall remain in effect after termination hereof, including Article 7 and provisions necessary to provide for final billings, billing adjustments, and payments. ARTICLE 4. Purchase Rate for Installed Capability, Operable Capability and Energy (a) Company shall pay Seller monthly (on a $/Mwh basis) for Installed Capability, Operable Capability and Energy, according to the following formula: TMAt = Pt x Ut where: TMAt = Total monthly amount due in month (t) Pt = The Purchase price expressed in $/Mwh = 35.00 $/Mwh for all the months in the year 1999 = 38.00 $/Mwh for all the months in the year 2000 = 35.19 $/Mwh for all the months in the year 2001 = 38.89 $/Mwh for all the months in the year 2002 = 43.52 $/Mwh for all the months in the year 2003 = 47.22 $/Mwh for all the months in the year 2004 Ut = The Energy portion of the Company's Entitlement delivered to Company in month (t) expressed in megawatthours. ARTICLE 5. Dispatch (a) Seller shall make the Facility available for dispatch by ISO-NE. (b) Seller shall comply with all NEPOOL Standards applicable to Seller. (c) Seller shall submit all forms to ISO-NE with a copy to Company. (d) Seller's and Company's designated agent shall mutually agree to any revision to the existing ISO-NE NX-12B Forms to be submitted to ISO-NE in accordance with the provisions of the NEPOOL Agreement and NEPOOL Standards. (e) Whenever Company's system or the systems with which it is directly interconnected experience an emergency, as designated by the affected utility, or whenever it is necessary to aid in the restoration of service on Company's system or on the systems with which it is directly or indirectly interconnected, or, whenever requested by ISO-NE, Seller or its designee shall curtail or interrupt the delivery of all or a portion of the production of electricity at the Facility provided such curtailment or interruption shall continue only for as long as reasonably necessary to deal with the emergency. (f) Whenever Seller's Facility experiences an emergency, Seller or its designee shall have the right to curtail or interrupt all or a portion of Seller's obligation hereunder, provided such curtailment or interruption shall continue only for so long as reasonably necessary to deal with the emergency, and provided Seller promptly notifies Company of the occurrence of such an emergency. ARTICLE 6. Billing, Meter Reading (a) Seller shall deliver Company's Entitlement to the Delivery Point. Seller is responsible for maintaining metering and telemetering equipment at the Facility. The metering equipment shall be capable of registering and recording instantaneous, and time-differentiated electric energy and other related data from the Facility, and shall comply with the requirements of NEPOOL's Standards as may be issued or revised from time to time. The telemetering shall be capable of transmitting such data to location(s) specified by Company. (b) Each day, Seller shall be required to provide Company with hourly integrated megawatt hour readings for each hour of the previous day. Seller shall record hourly meter readings and log sheets and, upon Company's request, provide copies of daily meter recordings and log sheets by electronic means with hard copy back-up. All metering equipment installed shall be routinely tested in accordance with Prudent Utility Practice. Any meter tested and found to register within one-half of one percent (0.5%) of the recognized comparative standard shall be considered correct and accurate. If at any time, any metering equipment is found to be defective or inaccurate, Seller shall cause such metering equipment to be made accurate or re placed at Seller's expense. Notwithstanding subarticle (e) below, in such event, a billing adjustment shall be made by Seller correcting all measurements made by the defective meter for either: (i) the actual period during which inaccurate measurements were made, if such period is determinable to the mutual satisfaction of the Company and Seller; or (ii) if such period is not determinable, for a period equal to one-half the time elapsed since the prior test, but in no event greater than six months. (c) Seller shall submit, by telecopy or other agreeable same day delivery mechanism, an invoice for all applicable Article 4 charges to Company as soon as practicable after the end of each calendar month that shall include the time and date of the meter readings. This invoice shall include such reasonable detail to enable the Company to determine the basis for the charges of such month. Seller and Company agree to provide additional information reasonably requested by the other Party as necessary for billing purposes or data verification. Invoices may be rendered on an estimated basis. Each invoice shall be subject to adjustment for any errors in arithmetic, computing, estimating or otherwise. Seller and Company shall include any such invoicing adjustments as promptly as practicable. (d) All payments shown to be due on such invoice, except amounts in dispute, shall be due and payable as shown on the invoice. Company shall pay by wire transfer per instructions on the invoice on or before ten (10) days after receipt of the invoice. (e) Any undisputed amounts unpaid after the Due Date shall bear interest at a rate equal to the Prime Rate then in effect on the Due Date, compounded on a monthly basis. Company may dispute all or any part of any invoice by written notification to Seller within 30 days of receipt of such invoice. All amounts paid by the Company which are subsequently determined to have been improperly invoiced by Seller under this Agreement shall be subject to refund with interest at a rate equal to the Prime Rate then in effect on the Due Date, compounded on a monthly basis. (f) Seller shall keep complete and accurate records and meter readings of its operations and shall maintain such data for a period of at least one (1) year after invoice for the final billing is rendered. Company shall have the right, upon five (5) business days prior notice, during normal business hours, to examine and inspect all such records and meter readings in so far as may be necessary for the purpose of ascertaining the reasonableness and accuracy of all relevant data, estimates or statements of charges submitted to it hereunder but shall not impair or interfere with the operation of the Facility owned by Seller. ARTICLE 7. Limitation of Liability; Indemnification; Insurance; Relationship of Parties (a) Notwithstanding subarticle (b) hereof or any other provision of this Agreement to the contrary, neither Company nor Seller nor their respective officers, directors, agents, employees, parent, subsidiaries or affiliates or their officers, directors, agents or employees shall be liable or responsible to the other Party or its parent, subsidiaries, affiliates, officers, directors, agents, employees, successors or assigns, or their respective insurers, for incidental, indirect, exemplary, punitive or consequential damages, connected with or resulting from performance or non-performance of this Agreement, or anything done in connection therewith including, without limitation, claims in the nature of lost revenues, income or profits (other than payments expressly required and properly due under this Agreement), and increased expense of, reduction in or loss of power generation production or equipment used therefor, irrespective of whether such claims are based upon breach of warranty, tort (including negligence, whether of Seller, Company or others), strict liability, contract, operation of law or otherwise, but excluding acts of gross negligence or willful misconduct. (b) Each Party (the "Indemnifying Party") shall defend, indemnify and save the other Party (the "Indemnified Party"), its officers, directors, agents, employees and affiliates and their respective officers, directors, agents and employees harmless from and against any and all claims, liabilities, demands, judgments, losses, costs, expenses (including reasonable attorneys' fees), suits, or damages arising by reason of bodily injury, death or damage to third party property sustained by any person or entity (whether or not a party to this Agreement) caused by or attributable to a breach of this Agreement by the Indemnifying Party or an action of gross negligence or willful misconduct of the Indemnifying Party or an officer, direct or, agent or employee of Indemnifying Party. (c) Seller shall maintain insurance coverage at its sole expense. (d) The rights, obligations and protections afforded by subarticles (a) and (b) above shall survive the termination, expiration or cancellation of this Agreement, and shall apply to the full extent permitted by law. (e) Nothing in this Agreement shall be construed as creating any relationship between the Parties other than that of independent contractors for the sale and purchase of Installed Capability, Operable Capability and Energy generated at the Facility. The Parties do not intend to create any rights, or grant any remedies to, any third party beneficiary of this Agreement. ARTICLE 8. Miscellaneous Provisions (a) The Parties hereto agree that time shall be of the essence of this Agreement. (b) This Agreement may not be modified or amended except in writing signed by or on behalf of both Parties by their duly authorized officers, and if applicable, after obtaining any required regulatory approvals. (c) It shall be the responsibility of Seller to take all necessary actions to satisfy any regulatory requirements which may be imposed on Seller by any statute, rule or regulation concerning the sale of Installed Capability, Operable Capability and Energy. Company shall cooperate with Seller and provide information or such other assistance, without cost to Company, as may be reasonably necessary for Seller to satisfy regulatory requirements relating specifically and only to the sale of Installed Capability, Operable Capability and Energy from the Facility. Seller shall cooperate with Company and provide information or such other assistance, without cost to Seller, as may be reasonably necessary for Company to satisfy regulatory requirements relating specifically and only to the purchase of Installed Capability, Operable Capability and Energy from the Facility. (d) Notwithstanding subarticle (c) above, Seller agrees to provide, at no cost to Company, all necessary forms, data, and other information reasonably requested of Company by ISO-NE, NEPOOL, or any governmental or regulatory agency or authority having jurisdiction. ARTICLE 9. Assignment (a) Neither Party shall have the right to assign this Agreement or its rights or obligations hereunder without the express written consent of the other Party. Such consent shall not be unreasonably withheld. No assignment shall be effective until any and all necessary regulatory approvals of the assignment have been obtained. (b) Notwithstanding the provisions in Section 9(a) above: (i) Seller may assign this Agreement to any affiliate to whom the Facility is transferred, without the Company's prior consent; provided that Seller shall not be released from liability hereunder without the Company's prior written consent. (ii) Seller may collaterally assign its rights in this Agreement to its lenders. (iii) The Company has the right to assign or transfer all of its rights and obligations under this Agreement, without the consent of Seller, provided that Company shall first provide Seller with thirty (30) days prior written notice of the proposed assignment or transfer and documentary evidence of the assignee's or transferee's financial capacity to satisfy any and all obligations so assigned; and provided further that such documentary evidence may be that such assignee or transferee has a current agency report indicating an investment grade rating from any two of the following: Standard & Poor's, Moody's, Duff & Phelps, or Fitch. Any assignment or transfer by the Company shall include an explicit requirement that the assignee or transferee agrees to undertake each and every obligation that the Company has under this Agreement. The Seller understands and acknowledges that the Company intends to assign or transfer all of its rights and obligations under this Agreement. ARTICLE 10. Force Majeure (a) If either Party is rendered wholly or partly unable to perform its obligations under this Agreement because of a Force Majeure event, that Party shall be excused from whatever performance is affected by the Force Majeure event to the extent so affected, provided that the non-performing Party shall: (i) provide prompt notice to the other Party of the occurrence of the Force Majeure event giving an estimation of its expected duration and the probable impact on the performance of it s obligations hereunder and submitting good and satisfactory evidence of the existence of the Force Majeure event; (ii) exercise all reasonable efforts to continue to perform its obligations hereunder; (iii) expeditiously take action to correct or cure the Force Majeure event and submit good and satisfactory evidence that it is making all reasonable efforts to correct or cure the Force Majeure event; (iv) exercise all reasonable efforts to mitigate or limit damages to the other Party to the extent such action shall not adversely effect its own interests; and (v) provide prompt notice to the other Party of the cessation of the Force Majeure event; provided further that any obligations of either Party which arose before the occurrence of the Force Majeure event causing non-performance shall not be excused as a result of the occurrence of a Force Majeure event. (b) "Force Majeure" means the failure or imminent threat of failure of facilities or equipment, flood, freeze, earthquake, storm, fire, lighting, other acts of God, epidemic, war, acts of a public enemy, riot, civil disturbance or disobedience, strike, lockout, work stoppages, other industrial disturbance or dispute, sabotage, restraint by court order or other public authority, and action or non-action by, or failure or inability to obtain the necessary authorizations or approvals from, any governmental agency or authority, which by the exercise of due diligence such Party could not reasonably have been expected to avoid and by exercise of due diligence its effect can not be overcome. Nothing contained herein shall be construed so as to require the Parties to settle any strike, lockout, work stoppage or any industrial disturbance or dispute in which it may be involved, or to seek review of or take an appeal from any administrative or judicial action. In no event shall the lack of funds or an inability to obtain funds or any action by any governmental authority that disallows, prevents or limits the recovery through rates of all or any portion of the charges imposed by this Agreement be a Force Majeure event. ARTICLE 11. Default (a) "Event of Default" shall mean in relation to a Party (the "Defaulting Party"): (i) the Defaulting Party fails to perform any of its material obligations hereunder, and such failure is not excused by Force Majeure and continues for thirty (30) days after the Defaulting Party receives written notice from the Non-Defaulting Party of such failure; provided, however, if a period in excess of thirty (30) days is required to cure such failure, the Defaulting Party shall have an additional amount of time, not to exceed 180 days, as may be necessary to cure such failure, provided t hat the Defaulting Party uses reasonable diligence to remedy such failure and provided further that, the foregoing "cure" provisions shall not apply to: y) failure by Company to make payments to Seller pursuant to Article 6, or z) failure by Seller to make available and deliver Company's Entitlement; or (ii) the Defaulting Party makes an assignment or general arrangement for the benefit of creditors, files a petition, or otherwise commences any proceeding, in bankruptcy or under similar law, otherwise becomes bankrupt (however evidenced) or is unable to pay its debts as they fall due. (b) Upon an Event of Default, the Non-Defaulting Party may resort to all remedies available at law or in equity, including, without limitation: (i) the termination of service; (ii) specific enforcement of the provisions of this Agreement ; and/or (iii) the recovery of damages except to the extent such damages are waived or limited pursuant to this Agreement. ARTICLE 12. Governing Law, Dispute Resolution (a) The interpretation and performance of this Agreement shall be in accordance with, and controlled by the law of, the Commonwealth of Massachusetts, notwithstanding its conflicts of law's principles. (b) If any dispute, disagreement, claim or controversy exists between Seller and Company arising out of or relating to this Agreement, such disputed matter shall be submitted to a committee comprised of one designated agent of each Party. Such committee shall be instructed to attempt to resolve the matter within twenty (20) days thereafter. If Company's and Seller's designees do not agree upon a decision within thirty (30) days after the submission of the matter to them, either Party may institute formal legal proceedings. ARTICLE 13. Waiver The failure of either Party to require compliance with any provision of this Agreement shall not affect that Party's right to later enforce the same. It is agreed that the waiver by either Party of performance of any of the terms of this Agreement, or of any breach thereof, shall not be held or deemed to be a waiver by that Party of any subsequent failure to perform the same, or any other term or condition of this Agreement, or of any breach thereof. ARTICLE 14. Corporate Authorization Prior to or simultaneous with the Effective Date of this Agreement, the Parties shall provide sufficient evidence to each other that each has the legal power and authority to perform this Agreement, that their respective officers executing this Agreement have been duly authorized to do so and that this Agreement, upon execution and delivery, shall be legally binding and enforceable. ARTICLE 15. Notice Except as otherwise provided herein, any notice, invoice or other communication which is required or permitted by this Agreement shall be in writing and delivered by personal service, telecopy, or mailed certified or registered first class mail, postage prepaid, properly addressed as follows: a) In the case of Company to: Montaup Electric Company c/o EUA Service Corp. W. Bridgewater, Massachusetts 02379 U.S.A. Attention: Robert P. Clarke Telecopy No: 508-583-2356 b) In the case of Seller to: Carolyn C. Shanks, CPA Vice President, Finance and Administration Entergy Nuclear Generation Company P.O. Box 31995 Jackson, MS 39286-1995 Street Address: 1340 Echelon Parkway Jackson, MS 39213 Telecopy No: 601-368-5323 Another address or addressee may be specified in a notice duly given as provided. Each notice, invoice or other communication which shall be mailed, delivered or transmitted in the manner described above shall be deemed sufficiently given an d received for all purposes at such time as it is delivered to the addressee (with return receipt, the delivered receipt, the affidavit of the messenger or with respect to a telecopy, the answer back, being deemed conclusive evidence of such delivery) or at such time as delivery is refused by the addressee upon presentation. IN WITNESS WHEREOF the Parties have executed this Agreement as of the date first written above. ENTERGY NUCLEAR GENERATION COMPANY By: /s/ Donald C. Hintz Name: Donald C. Hintz Title: President and Chief Executive Officer MONTAUP ELECTRIC COMPANY By: /s/ Kevin A. Kirby Name: Kevin A. Kirby Title: Vice President EX-10 (bb)(viii) POWER PURCHASE AND SALES AGREEMENT (REDACTED VERSION) POWER PURCHASE AND SALE AGREEMENT BETWEEN MONTAUP ELECTRIC COMPANY AND CONSTELLATION POWER SOURCE, INC. December 21, 1998 TABLE OF CONTENTS Page ARTICLE 1. Definitions ARTICLE 2. Effective Date; Term and Conditions Precedent ARTICLE 3. Delivery of Power; Hydro Quebec Transmission Use Rights; Designation of Purchaser as Agent; Assignment of Commitments ARTICLE 4. Payments ARTICLE 5. Covenants of the Parties ARTICLE 6. Force Majeure ARTICLE 7. Events of Default; Remedies ARTICLE 8. Representations and Warranties ARTICLE 9. Indemnification ARTICLE 10. Dispute Resolution ARTICLE 11. Miscellaneous SCHEDULE 1 Commitments SCHEDULE 1-A Agreements Related to Hydro-Quebec Interconnection SCHEDULE 2 Seller Payments SCHEDULE 3 Seller Required Regulatory Approvals SCHEDULE 4 Purchaser Required Regulatory Approvals SCHEDULE 5 Exceptions to Seller's Title to the Commitments SCHEDULE 6 Defaults Under the Commitments SCHEDULE 7 Legal Proceedings SCHEDULE 8 Form of Guaranty POWER PURCHASE AND SALE AGREEMENT This POWER PURCHASE AND SALE AGREEMENT ("Agreement") is dated as of December 21, 1998 and is made by and between MONTAUP ELECTRIC COMPANY, a Massachusetts corporation ("Seller"), and CONSTELLATION POWER SOURCE, INC. a Delaware corporation ("Purchaser") (each individually a "Party", or collectively the "Parties"). RECITALS WHEREAS, Seller is engaged in a complete divestiture of its generation assets and purchase power entitlements in accordance with the terms of comprehensive restructuring settlement agreements between Seller, its retail affiliates and regulatory and other parties in Massachusetts and Rhode Island which were approved by the FERC in Docket Nos. ER97-2800-000, et al.; and WHEREAS, Seller desires to sell, and Purchaser desires to purchase, the economic benefits and performance obligations, subject to Seller's continuing obligations to make certain payments, associated with the power purchase agreements and transmission support agreements hereinafter described between Seller and third party power suppliers. NOW, THEREFORE, in consideration of the mutual covenants, representations, warranties and agreements hereinafter set forth, and intending to be legally bound hereby, the parties hereto agree as follows: ARTICLE 1 DEFINITIONS 1.1 Definitions. (a) As used in this Agreement, the following terms have the meanings specified in this Section 1.1(a). "Administration Services" means those services provided by Seller: (i) to maintain the interconnection and meter the electricity produced and delivered under the BHI PPA (for which Seller is entitled to collect and retain the costs therefor from BHI), (ii) to determine and invoice the appropriate charges to be paid by Seller and Purchaser, (iii) to collect the aforementioned charges to be paid by Purchaser and (iv) to provide such operational data with respect to the Commitments that is reasonably available to Seller (to the extent permissible under that Commitment) and as Purchaser may request from time to time. "Affiliate" has the meaning set forth in Rule 12b-2 of the General Rules and Regulations under the Exchange Act. "Ancillary Agreements" means the Wholesale Standard Offer Service Agreement, the Seller Guaranty and the Subtransmission Service Agreement, if Purchaser elects, on or prior to the Effective Date in its sole discretion, to enter into such agreement. "Business Day" shall mean any day other than Saturday, Sunday and any day which is a legal holiday or a day on which banking institutions in Boston, Massachusetts are authorized by law or other governmental action to close. "Commitment" means the contracts described in Schedule 1 attached hereto and made a part hereof, together with any modifications, amendments or supplements thereto. "Eastern" means Eastern Edison Company, a Massachusetts corporation. "Encumbrances" means any mortgages, pledges, liens, security interests, assignment, conditional and installment sale agreements, activity and use limitations, conservation easements, easements, deed restrictions, encumbrances and charges of any kind. "Exchange Act" means the Securities Exchange Act of 1934, as amended. "Federal Power Act" means the Federal Power Act of 1935, as amended. "FERC" means the Federal Energy Regulatory Commission. "Good Utility Practice" means any of the applicable practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period; which in each case in the exercise of reasonable judgment in light of the facts known or that should have been known at the time a decision was made, could have been expected to accomplish the desired result in a manner consistent with law, regulation, safety, environmental protection, economy, and expedition. Good Utility Practice is intended to be acceptable practices, methods or acts as generally accepted in the region, and is not intended to be limited to the optimum practices, methods or acts to the exclusion of all others. "Holding Company Act" means the Public Utility Holding Company Act of 1935, as amended. "Interest Rate" means, for any date, the lesser of (a) the per annum rate of interest equal to the prime lending rate then in effect at the main office of BankBoston, or such other lending institution as agreed to by Seller and Purchaser and (b) the maximum rate permitted by applicable law. "Material Adverse Effect" means any change in or effect on Seller, Purchaser, Commitments or Power Sellers after the date of this Agreement that is materially adverse to any of the transactions contemplated hereby, other than (i) any change or effect resulting from changes in the international, national, regional or local wholesale or retail markets for electric power; (ii) any change or effect resulting from changes in the international, national, regional or local markets for any fuel used at any of the facilities providing Power under the Commitments; (iii) any change or effect resulting from changes in the North American, national, regional or local electric transmission systems; and (iv) any materially adverse change in or effect on or in connection with the Commitments which is cured (including by the payment of money) by Seller promptly in accordance with the terms of the Commitment before the Effective Date. "MDTE" means the Massachusetts Department of Telecommunications and Energy. "Moody's" means Moody's Investors Service, Inc., and any successor thereto. "NEPOOL" means the New England Power Pool, and any successor thereto, "Net Worth" means total assets (exclusive of intangible assets) less total liabilities as reflected on a balance sheet prepared in accordance with generally accepted accounting principles consistently applied. "Person" means any individual, a partnership, a limited liability company, a joint venture, a corporation, a trust, an unincorporated organization and a governmental entity or any department or agency thereof. "Power Seller" or "Power Sellers" means the party or parties with which Seller has contracted for the purchase of Power or the provision of transmission facilities or services under each of the Commitments. "Purchaser" means Constellation Power Source, Inc., a Delaware corporation and its successors and permitted assigns. "Purchaser Representatives" means Purchaser's accountants, counsel, environmental consultants, financial advisors and other authorized representatives. "Replacement Price" means the price at which Purchaser, acting in a commercially reasonable manner, purchases substitute Power for the Power not delivered by Seller, plus any additional transmission charges incurred by Purchaser to the Delivery Point; or, absent any such purchase, the market price for such quantity at such Delivery Point during the applicable delivery period as determined by Purchaser in a commercially reasonable manner; provided, that the "market price" for NEPOOL products other than capacity and energy shall be determined by reference to the applicable price for such products as determined by the NEPOOL independent system operator. "Retail Companies" means, as applicable, each, any or all of Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation. "RIPUC" means the Rhode Island Public Utilities Commission. "S&P" means Standard & Poor's Ratings Group, a division of McGraw Hill, Inc., and any successor thereto. "Sales Price" means the price at which Seller, acting in a commercially reasonable manner, resells the Power not received by Purchaser, reduced by additional transmission charges, if any, incurred by Seller to effect such resale. "SEC" means the Securities and Exchange Commission. "Securities Act" means the Securities Act of 1933, as amended. "Seller" means Montaup Electric Company, a Massachusetts corporation and its successors and permitted assigns. "Standard Offer Service" means the electric service, if any, required to be provided by one or more of the Retail Companies to its retail customers who do not elect to purchase electricity from an alternative supplier in the market. "Subsidiary" when used in reference to any other Person means any entity of which outstanding securities having ordinary voting power to elect a majority of the Board of Directors or other Persons performing similar functions of such entity are owned directly or indirectly by such other Person. "Subtransmission Service Agreement" means the Subtransmission Service Agreement between Seller and Purchaser pursuant to which Seller agrees to sell and Purchaser agrees to purchase certain subtransmission service to facilitate deliveries of Power under the BHI PPA. "Taxes" means all taxes, charges, fees, levies, penalties or other assessments imposed by any United States federal, state or local or foreign taxing authority, including, but not limited to, income, excise, property, sales, transfer, franchise, payroll, withholding, social security or other taxes, including any interest, penalties or additions attributable thereto. "Transition Costs" means the Contract Termination Charges calculated and collected in accordance with the settlement agreements between Seller and the Retail Companies, approved by FERC in Docket Nos. ER97-2800-000, ER97- 3127-000 and ER97-2338-000. "Wholesale Standard Offer Service Agreement" means the Wholesale Standard Offer Service Agreement between the Retail Companies and Purchaser of even date herewith pursuant to which Purchaser has agreed to deliver and sell and the Retail Companies have agreed to receive and purchase of the Retail Companies' Standard Offer Service load obligations. (b) Each of the following terms has the meaning specified in the Section or Schedule set forth opposite such term: Term Section/Schedule AAA 10.1 BHI Schedule 1 BHI PPA Schedule 1 Canal PPA Schedule 1 Commitment List Schedule 1 Delivery Point 3.1(a) Direct Claim 9.2(c) Due Date 4.4(a) Effective Date 2.1(a) Event of Default 7.1 Final Order 2.1(a)(ii) Firm Energy Contract Schedule 1 Force Majeure 6.2 GSP 11.11 Indemnifiable Loss 9.1(a) Indemnifying Party 9.1(d) Indemnitee 9.1(c) Initial Purchaser Credit Support 5.8(a) McNeil PPA Schedule 1 Northeast PPA Schedule 1 Northeast Security 2.1(b)(vii) Non-Performing Party 3.5(a) Other Party 3.5(a) Power 3.1(a) Purchaser Payment 4.1(a) Purchaser Required Regulatory Approvals Schedule 4 Resale Proceeds 4.4(a) Seller Additional Security 5.9(c) Seller Guarantor 5.9(a) Seller Guaranty 5.9(a) Seller Required Regulatory Approvals Schedule 3 Seller Payment 4.1 Term 2.2(a) Third Party Claim 9.2(a) Trigger Payment 4.3(a) Trigger Payment Date 4.3(a) Trigger Event 4.3(b) ARTICLE 2 EFFECTIVE DATE; TERM AND CONDITIONS PRECEDENT 2.1 Effective Date; Conditions Precedent. (a) The obligations of Seller and Purchaser hereunder are subject to satisfaction of the following conditions precedent and this Agreement shall become effective, unless the Parties otherwise agree, at midnight on the last day of the month in which all such conditions have been satisfied if the conditions are satisfied on or before the 5th Business Day prior to the last day of such month or if not, then midnight on the last day of the next succeeding month after the month in which such conditions have been satisfied, as the case may be; such date is hereinafter referred to as the "Effective Date": (i) No preliminary or permanent injunction or other order or decree by any federal or state court which prevents the consummation of transactions contemplated hereby shall have been issued and remain in effect (each Party agreeing to use its reasonable efforts to have any such injunction, order or decree lifted) and no statute, rule or regulation shall have been enacted by any state or federal government or governmental agency in the United States which prohibits the consummation of the transactions contemplated hereby; (ii) All federal, state and local government consents and approvals required for the consummation of the transactions contemplated hereby, including, without limitation, Seller Required Regulatory Approvals and Purchaser Required Regulatory Approvals, shall have been obtained or become Final Orders (a "Final Order" means a final order after all opportunities for rehearing and appeal are exhausted). If such approvals are conditional in any material respect or materially modify , directly or indirectly, the obligations of a Party hereto, such approvals must be acceptable to each Party, in its reasonable discretion; and (iii) All consents and approvals for the consummation of transactions contemplated hereby required under the terms of any note, bond, mortgage, indenture, contract or other agreement to which Seller or Purchaser, or any of their Subsidiaries or Affiliates, are a party shall have been obtained. (b) The obligation of Purchaser to effect the transactions contemplated by this Agreement shall be subject to the fulfillment of the following additional conditions: (i) There shall not have occurred and be continuing a Material Adverse Effect; (ii) Seller shall have performed and complied with in all material respects the covenants and agreements contained in this Agreement which are required to be performed and complied with by Seller on or prior to the Effective Date, and the representations and warranties of Seller set forth in this Agreement shall be true and correct in all material respects as of the date of this Agreement and as of the Effective Date as though made at and as of the Effective Date; (iii) There shall be no Encumbrances on any or all of Seller's rights under the Commitments; (iv) Purchaser shall have received certificates from authorized officers of Seller, dated the Effective Date, to the effect that, to the best of such officers' knowledge, the conditions set forth in Sections 2.1(b)(i), (ii) and (ii i) have been satisfied; (v); (vi) Seller shall have taken all actions necessary, including the completion and delivery of all agreements and documents required by NEPOOL, any other power pool, independent system operator, electric reliability council or govern mental or regulatory authority as reasonably requested by Purchaser to enable Purchaser to receive credit for the Power sold and delivered to Purchaser hereunder and to enable Purchaser to transact with respect to such Power for its own account; (vii); (viii) Seller and Eastern shall have and obtained a finding by the MDTE that Eastern's actions in regard to the Wholesale Standard Offer Service Agreement are in accordance with G.L. c. 164, 94A and 1B(b) and that the Wholesale Standard Offer Service Agreement may become effective, such finding to be final and no longer subject to rehearing, reconsideration or appeal; and (ix) Purchaser shall have received an opinion from McDermott, Will & Emery, counsel for Seller, dated the Effective Date and satisfactory in form and substance to Purchaser and its counsel, substantially as follows: (A) Each of Seller, the Retail Companies and the Seller Guarantor is a corporation organized, existing and in good standing under the laws of its state of incorporation and has the corporate power and authority to execute, deliver and perform this Agreement and the Ancillary Agreements and to consummate the transactions contemplated hereby and thereby; and the execution and delivery of this Agreement and such Ancillary Agreements and the consummation of the transactions contemplated hereby and thereby have been duly authorized by all requisite corporate action taken on the part of Seller, the Retail Companies and the Seller Guarantor, as applicable; (B) This Agreement and the Ancillary Agreements have been executed and delivered by Seller, the Retail Companies and the Seller Guarantor, as applicable and (assuming that Seller Required Regulatory Approvals and Purchaser Required Regulatory Approvals are obtained) are valid and binding obligations of Seller, the Retail Companies and the Seller Guarantor, as applicable enforceable against Seller, the Retail Companies and the Seller Guarantor in accordance with their terms, except (1) that such enforcement may be subject to bankruptcy, insolvency, reorganization, moratorium or other similar laws now or hereafter in effect relating to creditors' rights, and (2) that the remedy of specific performance and injunctive and other forms of equitable relief may be subject to certain equitable defenses and to the discretion of the court before which any proceeding therefor may be brought; (C) The execution, delivery and performance of this Agreement and the Ancillary Agreements by Seller, the Retail Companies and the Seller Guarantor will not (1) constitute a violation of the Certificates of Incorporation or Bylaws (or similar governing documents), as in effect on the Effective Date, of Seller, the Retail Companies and the Seller Guarantor, as applicable (2) result in a default (or give rise to any right of termination, cancellation or acceleration) under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license, agreement or other instrument or obligation to which Seller, the Retail Companies and the Seller Guarantor, as applicable is a party or by which Seller, t he Retail Companies and the Seller Guarantor, as applicable may be bound, including, without limitation, the Commitments except for such defaults (or rights of termination, cancellation or acceleration) as to which requisite waivers or consents have been obtained; or (3) violate any order, writ, injunction, decree, statute, rule or regulation applicable to Seller, the Retail Companies and the Seller Guarantor or any of their respective assets; (D) No declaration, filing or registration with, or notice to, or authorization, consent or approval of any governmental authority is necessary for the consummation by Seller, the Retail Companies and the Seller Guarantor of the transactions contemplated by this Agreement and the Ancillary Agreements, other than (1) Seller Required Regulatory Approvals, all of such Seller Required Regulatory Approvals which are applicable to the transactions contemplated hereby and thereby having been obtained and being in full force and effect with such terms and conditions as shall have been imposed by any applicable governmental authority, and (2) such declarations, filings, registrations, notices, authorizations, consents or approvals which, if not obtained or made, would not, in the aggregate have a Material Adverse Effect. As to any matter contained in such opinion which involves the laws of any jurisdiction other than the federal laws of the United States or the laws of Massachusetts, such counsel may rely upon opinions of counsel admitted in such other jurisdictions and reasonably acceptable to Purchaser. Any opinions relied upon by such counsel as aforesaid shall be delivered together with the opinion of such counsel. Such opinion may expressly rely as to matters of fact upon certificates furnished by Seller, the Retail Companies and the Seller Guarantor and appropriate officers and directors of Seller, the Retail Companies and the Seller Guarantor and by public officials. (c) The obligation of Seller to effect the transactions contemplated by this Agreement shall be subject to the fulfillment of the following additional conditions: (i) Purchaser shall have performed in all material respects covenants and agreements contained in this Agreement required to be performed on or prior to the Effective Date; (ii) The representations and warranties of Purchaser set forth in this Agreement shall be true and correct in all material respects as of the date of this Agreement and as of the Effective Date as though made at and as of the Effective Date; (iii) Seller shall have received a certificate from an authorized officer of Purchaser, dated the Effective Date, to the effect that, to the best of such officer's knowledge, the conditions set forth in Sections 2.1(c)(i) and (ii)) have been satisfied; (iv) FERC approval of the Stipulations and Agreements filed in FERC Docket No. ER97-3127-000 by and between the Office of the Attorney General of Massachusetts, the Massachusetts Division of Energy Resources,Eastern Edison Company and Seller, dated October 29, 1997; Docket No. ER97- 2800-000 by and between the RIPUC, the Rhode Island Division of Public Utilities and Carriers, Blackstone Valley Electric Company, Seller and Newport Electric Corporation; Docket No. ER97-3127-000 and ER97-2800-000 between Seller and the Pascoag Fire District of Rhode Island; Docket No. ER97-3127-00 and ER97-2800-000 between Seller and the Gas and Electric Department of the Town of Middleborough; and Docket No. ER97-2338-000 between Seller and the Taunton Municipal Lighting Plant, Pascoag Fire District of Rhode Island and the Gas and Electric Department of the Town of Middleborough shall continue to be in full force and effect; (v) All Seller Required Regulatory Approvals and all other consents and approvals required of Seller to consummate the transactions contemplated by this Agreement shall have been obtained and in full force and effect; (vi); and (vii) Seller shall have received an opinion from Hunton & Williams, counsel for Purchaser, dated the Effective Date and satisfactory in form and substance to Seller and their counsel, substantially to the effect that: (A) Purchaser is a corporation organized, existing and in good standing under the laws of the State of Delaware and has the corporate power and authority to execute and deliver this Agreement and the Ancillary Agreements a nd to consummate the transactions contemplated hereby; and the execution and delivery of this Agreement and such Ancillary Agreements and the consummation of the transactions contemplated hereby have been duly authorized by all requisite corporate action taken on the part of Purchaser; (B) This Agreement and the Ancillary Agreements have been executed and delivered by Purchaser and (assuming that Seller Required Regulatory Approvals and Purchaser Required Regulatory Approvals are obtained) are valid and binding obligations of Purchaser, enforceable against Purchaser in accordance with their terms, except (1) that such enforcement may be subject to bankruptcy, insolvency, reorganization, moratorium or other similar laws now or hereafter in effect relating to creditors' rights and (2) that the remedy of specific performance and injunctive and other forms of equitable relief may be subject to certain equitable defenses and to the discretion of the court before which any proceeding therefor may be brought; (C) The execution, delivery and performance of this Agreement and the Ancillary Agreements by Purchaser will not constitute a violation of the Certificate of Incorporation or Bylaws (or similar governing documents), as in effect on the Effective Date, of Purchaser; (D) No declaration, filing or registration with, or notice to, or authorization, consent or approval of any governmental authority is necessary for the consummation by Purchaser of the transactions contemplated by this Agreement and the Ancillary Agreements other than (1) Purchaser Required Regulatory Approvals, all of such Purchaser Required Regulatory Approvals which are applicable to the transactions contemplated hereby and thereby having been obtained and being in full force and effect with such terms and conditions as shall have been imposed by any applicable governmental authority and (2) such declarations, filings, registrations, notices, authorizations, consents or approvals which, if not obtained or made , would not, in the aggregate have a Material Adverse Effect. As to any matter contained in such opinion which involves the laws of any jurisdiction other than the federal laws of the United States and the laws of Delaware, such counsel may rely upon opinions of counsel admitted to practices in such other jurisdictions. Any opinions relied upon by such counsel as aforesaid shall be delivered together with the opinion of such counsel. Such opinion may expressly rely as to matters of facts upon certificates furnished by appropriate officers and directors of Purchaser and its Subsidiaries and by public officials. (d). (e) Each of the Parties shall cooperate in good faith and shall use reasonable efforts to cause the foregoing conditions precedent to be satisfied as soon as reasonably possible. If, notwithstanding the reasonable efforts by both Parties, the conditions precedent set forth in this Section 2.1 have not been satisfied or waived by the Party entitled to the benefit thereof and the Effective Date has not occurred, in each case, on or before the second anniversary of the date hereof, or the Parties mutually agree prior to such date that it will not be possible to satisfy a condition precedent, then either Party may terminate this Agreement, without additional cost or liability resulting from such termination, upon thirty (30) days prior written notice to the other Party. 2.2 Term. (a) The "Term" of this Agreement shall be the period from and including the date hereof and shall continue in effect, unless sooner terminated in accordance with its terms, until every obligation of either Party to pay the other Party an amount hereunder, including, without limitation, payments pursuant to Article 4, has been satisfied in full in accordance with the terms of this Agreement. (b) At the expiration of the Term, the Parties shall no longer be bound by the terms and provisions hereof, except (i) to the extent necessary to enforce the rights and the obligations of the Parties arising under this Agreement before such expiration or termination and (ii) the obligations of the Parties hereunder with respect to confidentiality, indemnification and audit rights shall survive the expiration or termination of this Agreement and shall continue for a period of two (2) calendar years following such termination. ARTICLE 3 DELIVERY OF POWER; HYDRO QUEBEC TRANSMISSION USE RIGHTS; DESIGNATION OF PURCHASER AS AGENT; ASSIGNMENT OF COMMITMENTS 3.1 Delivery of Power. (a) Commencing as of the Effective Date, each month Seller agrees to sell and deliver and Purchaser agrees to purchase and receive all capacity, energy, any other NEPOOL products and services and any other benefits it receives under each Commitment (collectively, "Power") simultaneously with Seller's receipt thereof from each Power Seller. All Power shall be delivered to Purchaser at the point at which the Power Seller makes delivery to Seller as established under such Commitment (each, a "Delivery Point"). Purchaser shall be responsible for making all arrangements necessary for the further transmission of such Power. (b) With respect to each Commitment, and until such time as there is an early termination, replacement or restructuring of the Commitment or a direct amendment and assignment of the Commitment to Purchaser pursuant to Section 3.4, Seller shall perform the Administration Services and from time to time during the Term of this Agreement take all actions necessary, including, without limitation, the completion and delivery of all agreements and documents required by NEPOOL, any other power pool, independent system operator, electric reliability council or governmental or regulatory authority as reasonably requested by Purchaser to enable Purchaser to receive credit for the Power sold and delivered to Purchaser hereunder and to enable Purchaser to transact with respect to such Power for its own account. 3.2 Hydro Quebec Firm Energy Contract; Transmission Use Rights. (a) Commencing as of the Effective Date, and terminating upon termination of the Firm Energy Contract pursuant to Article 21 of said Contract, Seller shall sell and deliver and Purchaser shall purchase and receive all Power that Seller receives under the Firm Energy Contract in accordance with Section 3.1 of this Agreement. Purchaser shall be responsible for scheduling its energy receipts under the Firm Energy Contract directly with NEPOOL and, if billed directly by NEPOOL for energy delivered under the Firm Energy Contract, shall be responsible for making payments therefor directly to NEPOOL. Failure of Purchaser to make such payments shall constitute an Event of Default under this Agreement. (b) Seller shall invoice Purchaser for and Purchaser shall pay Seller on a monthly basis, Seller's associated share of transmission facility support payments under those agreements set forth on Schedule 1-A associated with the delivery of Power by Seller to Purchaser that Seller receives under the Firm Energy Contract, as such amounts are increased by any costs incurred by Seller (including, without limitation, general and administrative costs incurred by Seller in administering Seller's open access transmission tariff as the Parties shall agree) or as decreased by any revenues received by Seller, both associated with the sale of transfer capability under Section 3.2(c). (c) Purchaser agrees that, to the extent it elects not to use a portion of the transfer capability available to it pursuant to Section 3.2(a),Purchaser shall so notify Seller in writing, and Seller shall make such transfer capability available under Seller's open access transmission tariff on file with the FERC. Seller shall credit Purchaser with the revenues Seller receives from the sale of transmission service associated with such transfer capability as provided in Section 3.2(b). Purchaser agrees to provide Seller with all information available to Purchaser that Seller reasonably requests for the purpose of calculating the charges to each customer that uses a portion of such transfer capability. (d) 3.3 Designation of Purchaser as Agent. (a) As of the Effective Date, Seller hereby irrevocably and unconditionally appoints Purchaser as its representative and agent for all purposes under each Commitment. Purchaser is authorized to take all actions that Seller may lawfully take under such Commitment without further approval by Seller and in Purchaser's sole discretion including, without limitation, the following: with respect to all matters arising under the Commitments (including, without limitation, directing and scheduling the availability, dispatch, quantity or timing of the Power under each Commitment) deal directly with the Power Sellers, NEPOOL, the independent system operator (as designated under the Restated NEPOOL Agreement, as amended from time to time), other transporters of electric energy, federal, state and local governmental or judicial authorities, and any other persons; act on Seller's behalf in the prosecution or defense, as the case may be, of any rights or liabilities arising under the Commitments; monitor the Power Seller's performance under the Commitments; review and audit all bills and related documentation rendered by the Power Sellers; and on Seller's behalf enter into amendments to the Commitments of any nature; provided, however, that Seller's prior written consent shall be required for (i) actions that increase the price charged for or the quantity of power to be purchased by Seller under a Commitment, (ii) Commitment term extensions, and (iii) any other matter which Seller reasonably believes will increase Seller's financial obligations under a Commitment, and (iv) any other matter which Seller reasonably believes will materially adversely affect Seller's indemnification rights under a Commitment, which consent shall not be unreasonably withheld. Seller agrees to participate at Purchaser's request and under Purchaser's reasonable direction in any governmental or judicial proceeding with respect to the Commitments, including but not limited to bringing an action to enforce the Commitments. Seller agrees to cooperate with and assist Purchaser in the exercise of its rights under this Section 3.3(a) as Purchaser shall reasonably request from time to time, so long as Purchaser reimburses Seller for the reasonable costs and expenses it incurs in providing such cooperation and assistance (other than with respect to the Administration Services). Seller hereby agrees to provide to Purchaser reasonable access to (including, at the expense of Purchaser, copies of) all information which Seller now has or hereafter acquires with respect to each Commitment (to the extent permissible under that Commitment). (b) In assuming responsibility for taking all actions which Seller may otherwise lawfully take under the Commitments pursuant to Section 3.3(a), Purchaser shall act as Seller's agent with respect to each Commitment commencing on the Effective Date and ending (i) with respect to each Commitment that is assigned to Purchaser pursuant to Section 3.4, at the time that such assignment is effective; and (ii) with respect to each Commitment that is not assigned to Purchaser, upon the expiration or termination of such Commitment. Seller shall give such notice to each Power Seller and take such other steps as may be required or appropriate under applicable law to establish the authority of Purchaser as agent and to permit Purchaser to take action under each Commitment consistent with this Agreement. Seller agrees that (i) prior to the appointment of Purchaser as agent for a Commitment, all communications between Seller and the Power Seller related to that Commitment shall be with Purchaser's prior written consent and participation unless such consent or participation is expressly waived by Purchaser; and (ii) subsequent to the appointment of Purchaser as Seller's agent for a Commitment, Seller shall communicate with the Power Seller on matters related to that Commitment only as expressly requested by Purchaser, except in each case for such communications as are necessary for Seller to perform the Administration Services so long as Seller notifies Purchaser of the occurrence and the content of such communications at such time, or as soon as practicable thereafter. (c) Seller shall not agree to any amendment to or waiver of rights, or convey to any other person any rights, under a Commitment without Purchaser's prior written consent, which consent shall not be unreasonably withheld, shall not take any actions inconsistent with the provisions of this Article 3 or take any action or fail to take any action that would result in a material breach of Seller's obligations under the Commitments. Seller shall not, except at the express request of Purchaser, (i) take any actions that increase the costs to be incurred or affect the quantity of Power to be purchased under any Commitment or (ii) exercise any options that may exist under a Commitment, including any extension of the term of a Commitment or (iii) take any actions inconsistent with the provisions of Sections 3.3(a) and(b), except as shall be necessary to perform its obligations under the Commitments for the period prior to the Effective Date and except with respect to the Firm Energy Contract, to the extent that any actions taken or omitted to be taken thereunder or in connection therewith are prudent and are not within the sole control of Seller. (d) Seller shall request the Power Sellers to direct all communications regarding operations of the facilities under the Commitments, dispatch, scheduling and other matters relevant to the respective Commitments and provided to Seller, directly to Purchaser. To the extent that Seller receives any such information or any notices or documents relating to the Commitments, Seller shall promptly forward such information, notices or documents to Purchaser. (e) Upon the request of Purchaser, Seller shall enforce the provisions of any Commitment and/or its rights thereunder, or otherwise support Purchaser in any dispute between Purchaser and the Power Sellers; provided, however, that Seller s hall be compensated for its reasonable costs associated with such efforts. 3.4 Termination or Assignment of Commitments by Purchaser. Purchaser is hereby authorized and shall be entitled, as Seller's representative and in Seller's name, to negotiate directly with the Power Sellers the early termination, replacement or restructuring of the Commitments or a direct amendment and assignment of the Commitments to Purchaser so that Seller will be released of all further liabilities and obligations under each Commitment and Purchaser will be directly in contract with the Power Seller. Seller shall work cooperatively and use all reasonable efforts to assist Purchaser in such negotiations. If Purchaser and a Power Seller have agreed to a termination, replacement or amendment and assignment of a Commitment, then Seller shall be deemed to have accepted all of the terms agreed to by Purchaser and Power Seller and shall take all actions and execute and deliver all agreements, documents, instruments and certificates as necessary to consummate such termination, replacement, restructuring or amendment and assignment; provided, how ever, that in the case of an amendment and assignment of a Commitment to Purchaser, the terms of such amendment and assignment must continue to afford to Seller the protections for its or its Affiliates' transmission system embodied in the Commitment . Any amendment and assignment shall include all modifications necessary to reflect the substitution of Purchaser for Seller as the purchasing party under such Commitment (including modifications to Commitment price indices, where appropriate) and to properly describe interconnection, delivery point and transmission system references in such Commitment. Except as provided in Section 4.3, Seller and Purchaser agree that any such termination or assignment of a Commitment shall not entitle Seller or Purchaser to an adjustment of the Seller Payment obligations. 3.5 Failure to Deliver or Receive Power; Remedies. (a) If either Party fails to deliver or receive ("Non-Performing Party"), as the case may be, Power in accordance with the terms and conditions of this Agreement, the other Party ("Other Party") shall, as promptly as practicable, give not ice of such failure to the Non-Performing Party. (b) The Other Party shall be entitled to receive from the Non-Performing Party an amount calculated as follows, unless excused by Force Majeure or the Other Party's failure to perform: (i) if at any time Seller fails to deliver all or part of the Power delivered to it by the Power Sellers under the Commitments in accordance with the terms and conditions of this Agreement, Seller shall pay Purchaser, on the date payment would otherwise be due to Seller pursuant to Section 4.4, an amount for each unit of such deficient quantity equal to the positive difference, if any, obtained by subtracting the per unit price applicable to such quantity under the related Commitment from the per unit Replacement Price, plus any reasonable administrative expenses and reasonable attorneys' fees incurred as a result of Seller's failure to deliver; and (ii) if Purchaser fails to take delivery of all or part of the Power delivered to it in accordance with the terms and conditions of this Agreement, Purchaser shall pay Seller, on the date payment would otherwise be due, an amount f or each unit of such deficient quantity equal to the positive difference, if any, obtained by subtracting the per unit Sales Price from the per unit price applicable to such quantity under the related Commitment, plus any reasonable administrative expenses and reasonable attorneys' fees incurred as a result of Purchaser's failure to take delivery. 3.6 Duty to Mitigate Damages. Each Party agrees that it has a duty to mitigate damages and covenants that it will use commercially reasonable efforts to minimize any damages it may incur as a result of the other Party's performance or non-performance of this Agreement. 3.7 Exclusive Remedy. The damages provided in Section 3.5 shall be the sole and exclusive remedy of each Party for any failure of the other Party to deliver or receive, as applicable, Power in the quantities or at the times required by this Agreement. ARTICLE 4 PAYMENTS 4.1 Payments. (a) Commencing as of the month following the Effective Date of this Agreement, Purchaser agrees to pay to Seller each month all amounts due and payable in accordance with the applicable provisions of the Commitments from Seller to the Power Seller for the preceding month associated with Power delivered or made available to Purchaser by Seller from each Commitment in the preceding month (each such payment obligation referred to herein as the "Purchaser Payment"). Seller expressly acknowledges and agrees that unless and until a Commitment is terminated or assigned to Purchaser pursuant to Section 3.4, Seller shall remain liable for and timely pay to the applicable Power Sellers all amounts due thereunder. (b) Commencing as of the month following the Effective Date of this Agreement and continuing for each succeeding month set forth on Schedule 2, Seller shall pay Purchaser each month the amounts set forth on Schedule 2 in respect of each Commitment applicable to the preceding month (each such amount referred to herein as the "Seller Payment"). Subject to Section 4.3, Seller shall remain obligated to pay each of the Seller Payments through and including the last month of the last year listed on Schedule 2, notwithstanding the termination, expiration, replacement, amendment, assignment or any other change to a Commitment during the Term hereof (or any failure of the Power Seller under any Commitment to deliver Power or otherwise honor its obligations to Seller thereunder). Amounts set forth in Section 2.1(d), if any, shall be set-off against the Seller Payments due in the first ten (10) months after the occurrence of the Effective Date in ten equal installments. (c) Except as otherwise provided in Section 4.3, the Purchaser Payment with respect to each Commitment and the Seller Payment with respect to that Commitment owing by each Party for any month shall be offset so that only the net amount shall be p aid by the Party having the greater payment obligation for such Commitment for such month. (d) In the event that the amount of the Seller Payment with respect to any Commitment shall in any month exceed the Purchaser Payment with respect to such Commitment under this Section 4.1, Seller shall pay the amount of such exceedance to Purchaser on the date such Purchaser Payment would otherwise be due under Section 4.4. 4.2 Purchaser Right to Amounts Owed by Power Sellers. (a) Upon the Effective Date, Seller shall irrevocably and unconditionally assign and thereafter hold for the benefit of and/or credit to Purchaser against payments due from it to Seller under Section 4.1 hereof or, at the election of Purchaser, pay to Purchaser, any and all amounts which are then or thereafter received by Seller from the Power Sellers under the Commitments, including, without limitation, any aggregate differential balances under any Commitment, any energy bank balances and the benefit of and proceeds from any security deposits, letters of credit or other similar instruments or accounts established for the benefit of Seller by the Power Seller, but excluding any credits or refunds received by Seller after the Effective Date which relate to billing errors or reconciliations of pre-Effective Date bills, any amounts paid by the Power Sellers to Seller with respect to disputes that are attributable to a period prior to the Effective Date, and any amounts paid by the Power Sellers to Seller with respect to indemnification rights under a Commitment. (b). 4.3 Acceleration of Payments Upon Termination or Assignment of Commitment. (a) To the extent that a Trigger Event occurs with respect to a Commitment, Seller shall, either (i) continue to make the remaining payments due from Seller to Purchaser in respect of such Commitment pursuant to Section 4.1 or (ii) upon the mutual agreement of the Parties make a full or partial lump-sum payment (the "Trigger Payment") to Purchaser. If Purchaser and Seller agree to a Trigger Payment, such amount shall be paid by Seller to Purchaser concurrently with the Trigger Event , or as soon thereafter as is practicable (but not later than sixty (60) days after the Trigger Event occurred; the date on which the payment occurs being referred to as the "Trigger Payment Date". (b) A "Trigger Event" shall mean: (i) an amendment and assignment of a Commitment to Purchaser; or (ii) a termination or expiration of a Commitment, whether by its terms or as a result of negotiations; provided, however, that if at the time any one of the events specified in (i) or (ii) above shall occur, an Event of Default on the part of Purchaser shall have occurred and be continuing, no Trigger Event shall be deemed to have arisen from any such event unless and until such Event of Default shall have been cured. (c) The amount of any Trigger Payment shall, except as otherwise mutually agreed by Purchaser and Seller, be the discounted amount as of the Trigger Payment Date (using as the annual discount rate 11.115%) of Seller's remaining payment obligations with respect to the affected Commitment(s) pursuant to Schedule 2 as of the Trigger Payment Date. (d) Upon the making of any such Trigger Payment the amounts thereafter payable in accordance with Schedule 2 shall be reduced by the reduction arising under this Section 4.3 from such Trigger Payment. 4.4 Billing and Payment. (a) Seller shall timely pay all amounts due to the Power Sellers under the Commitments each month during the Term hereof, which includes the amount Seller receives from Purchaser in connection with such Commitment. Within three (3) Business Days after Seller's receipt of an invoice from a Power Seller pursuant to a Commitment associated with Power delivered or made available to Purchaser by Seller under such Commitment in the preceding month (or after Seller's delivery of a statement to the Power Seller under a Commitment, if Seller prepares or causes the monthly billing statement to be prepared under a Commitment), Seller shall deliver such invoice or statement to Purchaser. On or before the date which is (i) one (1) Business Day prior to the due date set forth on such invoice or (ii) if Seller fails to timely deliver an invoice as provided herein, then ten (10) Business Days after Purchaser's receipt of such invoice or statement (either of such dates, the "Due Date"), Purchaser shall remit payment of the positive difference, if any, of (A) the amount set forth in such invoice or statement to Seller minus (B) the Seller Payment applicable to the Commitment to which such invoice or statement relates for such month minus (C) amounts received by Seller from sales of Power to third parties in accordance with Section 3.5(b)(ii) (such net amounts received by Seller referred to herein as "Resale Proceeds"), such Resale Proceeds to be paid by Seller to the Power Seller s in partial satisfaction of Seller's obligations to the Power Sellers. All payments required under this Agreement shall be paid in cash by federal or other wire transfer of immediately available funds to an account designated by the Party to receive such payment. (b) Each invoice or statement shall incorporate all information reasonably necessary to determine the payments due thereunder, including actual and estimated billing information with respect to the Commitments and true-ups and adjustments from prior months. (c) Each invoice or statement shall be subject to adjustment for a period of twelve (12) months from the date of its issuance for any changes in estimates or any errors in arithmetic, computation or otherwise. 4.5 Taxes. Purchaser shall be responsible for any Taxes, costs, losses or charges imposed on or associated with the Power. 4.6 Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including, the Due Date to, but excluding, the date of payment. 4.7 Billing Disputes. If either Party, in good faith, disputes an invoice, the disputing Party shall pay the entire amount of the invoice no later than the Due Date and immediately notify the other Party of the basis for the dispute. If any amount paid under dispute is ultimately determined to be due to the disputing Party, it shall be credited within one (1) day of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by the receiving Party upon request or deducted by the receiving Party from subsequent payments, with interest accrued at the Interest Rate until the date paid or deducted. ARTICLE 5 COVENANTS OF THE PARTIES 5.1 Conduct of Business of the Company. Seller and Purchaser shall conduct their businesses with respect to the Commitments according to their ordinary and usual course of business consistent with Good Utility Practice. 5.2 Maintenance of Existence. Seller agrees that during the Term of this Agreement, it will maintain its corporate existence and its good standing in all of the states in which it transacts business, will not dissolve and will not consolidate with or merge into another Person unless the Person with which it merges or into which it consolidates assumes in writing all of the obligations of Seller hereunder, and satisfies the Seller Credit Support obligations pursuant to Section 5.9. 5.3 Access to Information. (a) Seller will, during ordinary business hours and upon reasonable notice (i) give Purchaser and Purchaser Representatives reasonable access to all books and records of Seller relating to the Commitments; (ii) permit Purchaser to make such reasonable inspections thereof as Purchaser may reasonably request; and (iii) furnish Purchaser, at Purchaser's expense, with such financial and operating data and other information in Seller's possession with respect to the Commitments as Purchaser may from time to time reasonably request; provided, however, (A) Seller shall not be required to take any action which would constitute a waiver of the attorney-client privilege and (B) Seller need not supply Purchaser with any information which Seller is under a legal obligation not to supply. (b) All information furnished to or obtained by Purchaser and Purchaser Representatives pursuant to this Section 5.3 shall be subject to the confidentiality provisions of Section 5.5. 5.4 Further Assurances. Subject to the terms and conditions of this Agreement, each of the Parties hereto will use reasonable efforts to take, or cause to be taken, all action, and to do, or cause to be done, all things necessary, proper or advisable under applicable laws and regulations to consummate and make effective the transactions contemplated hereby. 5.5 Confidentiality. (a) Seller and Purchaser each agree not to disclose to any Person and to keep confidential, and to cause and instruct its Affiliates, officers, directors, employees, members and representatives not to disclose to any Person and to keep confidential, any and all of the following information: (i) the terms and provisions of this Agreement and the Ancillary Agreements; (ii) any financial, pricing or supply quantity relating to the Power to be supplied by Seller hereunder; (iii) any information that is clearly marked "Confidential;" (iv) any oral communication that is subsequently reduced to writing and marked "Confidential;" and (v) any information that is required to be kept confidential by the terms of a Commitment. Notwithstanding the foregoing, any such information may be disclosed (A) to the extent required by applicable laws and regulations or by any subpoena or similar legal process of any court or agency of federal, state or local government so long as the receiving Party gives the disclosing Party written notice as soon as practicable prior to such disclosure; (B) to lenders, advisors and accountants of such Parties; (C) to the extent the non-disclosing Party shall have consented in writing prior to any such disclosure; (D) to the extent any confidential information is available from public non-confidential sources or has been independently developed by the receiving Party prior to its receipt from the disclosing Party; and (E) by Purchaser to prospective buyers of the Power purchased by Purchaser under this Agreement. This Section 5.5 shall supersede any prior confidentiality agreement between Purchaser and Seller. Notwithstanding any provision to the contrary herein, Seller may provide copies or in formation regarding this Agreement to any regulatory agency requesting and/or requiring such information; provided, that any such disclosure includes a request for confidential treatment of the Agreement and/or the redaction of terms considered commercially sensitive by the Purchaser from the copies of the Agreement which are placed in the public record or otherwise made available to third parties. (b) Information of a confidential nature which (i) has become public other than as a result of a breach of this Section 5.5; or (ii) was received by the disclosing Party from another source who in turn disclosed the information without violating legal restrictions shall not be subject to this Section 5.5. (c) The Parties shall consult with each other prior to issuing any public announcement, statement or other disclosure with respect to this Agreement or the transactions contemplated hereby and shall not issue any such public announcement, statement or other disclosure without the prior written consent of the other Party, which consent shall not be unreasonably withheld. 5.6 Consents and Approvals. Seller and Purchaser shall cooperate with each other and (i) promptly prepare and file all necessary documentation, (ii) effect all necessary applications, notices, petitions and filings and execute all agreements and documents, and (iii) use all commercially reasonable efforts to obtain all necessary consents, approvals and authorizations of all other parties, in the case of each of the foregoing clauses (i), (ii) and (iii), necessary or advisable to consummate the transactions contemplated by this Agreement (including, without limitation, Seller Required Regulatory Approvals and Purchaser Required Regulatory Approvals) or required by the terms of any note, bond, mortgage, indenture, deed of trust, license, franchise, permit, concession, contract, lease or other instrument to which Seller or Purchaser is a party or by which any of them is bound. Seller shall have the right to review and approve in advance all characterizations of the information relating to the Commitments, and each of Seller and Purchaser shall have the right to review in advance all characterizations of the information relating to the transactions contemplated by this Agreement which appear in any filing made in connection with the transactions contemplated hereby. 5.7 Fees and Commissions. Seller and Purchaser each represent and warrant to the other that, except for Reed Consulting Group, which is acting for and at the expense of Seller, no broker, finder or other Person is entitled to any brokerage fees, commissions or finder' s fees in connection with the transaction contemplated hereby by reason of any action taken by the party making such representation. Seller and Purchaser will pay to the other or otherwise discharge, and will indemnify and hold the other harmless from and against, any and all claims or liabilities for all brokerage fees, commissions and finder's fees (other than as described above) incurred by reason of any action taken by such Party. 5.8 XX. 5.9 XX 5.10 Parties Bound by Terms. The rates, terms and conditions for service specified in this Agreement shall remain in effect for the entire Term hereof, and shall not be subject to change through any unilateral application by either Party to the FERC or the applicable governmental entity acting under the Federal Power Act (or pursuant to any other provision of law) or to any other governmental agency or authority. Each Party hereby irrevocably waives the right to seek any change or to support any application or complaint or other legislative, judicial or regulatory action made seeking a change in such rates or a change in such terms and conditions, absent the mutual agreement of the Parties. ARTICLE 6 FORCE MAJEURE 6.1 Performance Excused. If either Party is rendered unable by an event of Force Majeure to carry out, in whole or part, its obligations hereunder, then, during the pendency of such Force Majeure but for no longer period, the Party affected by the event (other than t he obligation to make payments then due or becoming due with respect to performance which occurred prior to the event) shall be relieved of its obligations insofar as they are affected by Force Majeure but for no longer period. The Party affected by an event of Force Majeure shall provide the other Party with written notice setting forth the full details thereof as soon as practicable after the occurrence of such event and shall take all reasonable measures to mitigate or minimize the effects of such event of Force Majeure; provided, however, that this provision shall not require Seller to deliver, or Purchaser to receive, Power at points other than the Delivery Point. 6.2 Definition. For purposes of Seller's obligation to deliver, and Purchaser's obligation to receive, Power received by Seller from the Power Sellers, the term "Force Majeure" with respect to such Power deliveries under a Commitment shall solely have the meaning given in such Commitment. ARTICLE 7 EVENTS OF DEFAULT; REMEDIES 7.1 Events of Default. Any one or more of the following shall constitute an "Event of Default" hereunder: (a) failure of either Party to pay when due any amount due hereunder, including without limitation, amounts due under the Firm Energy Contract as described in Section 3.2(a) and such failure is not remedied within after writ ten notice of such failure is given by the other Party; (b) failure of either Party, in a material respect, to comply with, observe or perform any covenant or obligation under this Agreement (other than the events that are otherwise specifically covered in this Article 7 as a separate Event of Default) and such failure is not cured within ten (10) days after receipt of written notice thereof from the other party; (c) any representation or warranty made by either Party herein shall be false or misleading in any material respect; (d) a custodian, receiver, liquidator or trustee of either Party or of any of the property of either, is appointed or takes possession and such appointment or possession remains uncontested or in effect for more than ; or either Party makes an assignment for the benefit of its creditors or admits in writing its inability to pay its debts as they mature; or either Party is adjudicated bankrupt or insolvent; or an order for relief is entered under the Federal Bankruptcy Code against such Party; or any of the material property of either Party is sequestered by court order and the order remains in effect for more than ; or a petition is filed against either Party under any bankruptcy, reorganization, arrangement, insolvency, readjustment of debt, dissolution or liquidation law of any jurisdiction, whether now or subsequently in effect, and is not stayed or dismissed within after filing; (e) either Party files a petition in voluntary bankruptcy or seeking relief under any provision of any bankruptcy, reorganization, arrangement, insolvency, readjustment of debt, dissolution or liquidation law of any jurisdiction, whether now or subsequently in effect; or consents to the filing of any petition against it under any such law; or consents to the appointment of or taking possession by a custodian, receiver, trustee or liquidator of the property of either Party; (f) an "Event of Default" (as defined in the Wholesale Standard Offer Service Agreement) on the part of "Supplier" (as defined in the Wholesale Standard Offer Service Agreement) or on the part of any of the "Companies" (as defined in the Wholesale Standard Offer Service Agreement), as the case may be, has occurred and is continuing under the Wholesale Standard Offer Service Agreement (such "Event of Default" on the part of "Supplier" shall constitute an Event of Default on the part o f Purchaser hereunder and such "Event of Default" on the part of one or more of the "Companies" shall constitute an Event of Default on the part of Seller hereunder); or (g) the failure of a Party to provide alternate credit support in accordance with the terms of Section 5.8 or 5.9, as the case may be, within ten (10) Business Days after receipt of a written notice with respect thereto, after the occurrence of any of the events described in Sections 7.1(d) or 7.1(e) with respect to such Party's credit support provider. 7.2 Remedies Upon Default. The Parties shall have the following remedies available to them with respect to the occurrence of an Event of Default with respect to the other Party hereunder: Upon the occurrence of an Event of Default by either Party hereunder, the non-defaulting Party shall have the right (i) to collect all amounts then or thereafter due in accordance with existing invoices to it from the defaulting Party hereunder, and (ii) upon two (2) days prior written notice, immediately and at any time thereafter, to liquidate and terminate this Agreement by closing out this Agreement at its market value at such time (so that a settlement payment in an amount equal to the difference, if any, between such then prevailing market value and the value specified in such agreement shall be due to Purchaser if such market value is greater than such contract value and with such settlement payment being due to Seller if the opposite is the case) and by setting off all market damages so determined and payable by each of the Parties to the other, whereupon all such amounts shall be aggregated or netted to a single liquidated amount, payable within one Business Day by the Party owing the greater such amount to the other. In addition, if Purchaser is the defaulting Party, then Seller shall have the right during the continuation of such default and prior to any termination of this Agreement to cease making the Commitments available to Purchaser hereunder and to instead sell such Commitments to third parties for the account of Seller. 7.3 Limitation of Remedies, Liability and Damages. The Parties confirm that the express remedies and measures of damages provided in this Agreement satisfy the essential purposes hereof. For breach of any provision for which and express remedy or measure of damages is provided, such express remedy or measure of damages shall be the sole and exclusive remedy, the obligor's liability shall be limited as set forth in such provision and all other remedies or damages at law or in equity are waived. If no remedy or measure of damages is expressly herein provided, the obligor's liability shall be limited to direct actual damages only, such direct actual damages shall be the sole and exclusive remedy and all other remedies or damages at law or in equity are waived. Unless expressly herein provided, neither Party shall be liable for any consequential, incidental, punitive, exemplary or indirect damages, lost profits or other business interruption damages, by statute, in tort or contract, under any indemnity provision or otherwise. It is the intent of the Parties that the limitations herein imposed on remedies and the measure of damages be without regard to the cause or causes related thereto, including, without limitation, the negligence of any Party, whether such negligence be sole, joint or concurrent, or active or passive. To the extent any damages required to be paid hereunder are liquidated, the Parties acknowledge that the damages are difficult or impossible to determine, otherwise obtaining an adequate remedy is in convenient and the liquidated damages constitute a reasonable approximation of the harm or loss. ARTICLE 8 REPRESENTATIONS AND WARRANTIES 8.1 Representations and Warranties of Seller. Seller represents and warrants to Purchaser as follows: (a) Organization; Qualification. Seller is a corporation duly organized, validly existing and in good standing under the laws of the State of Massachusetts and has all requisite corporate power and authority to own, lease, and operate it s properties and to carry on its business as is now being conducted. Seller is duly qualified or licensed to do business as a foreign corporation and is in good standing in each jurisdiction in which the property owned, leased or operated by it or t he nature of the business conducted by it makes such qualification necessary, except in each case in those jurisdictions where the failure to be so duly qualified or licensed and in good standing would not have a Material Adverse Effect. (b) Authority Relative to this Agreement. Seller has full corporate power and authority to execute and deliver this Agreement and to consummate the transactions contemplated hereby. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly and validly authorized by the Board of Directors of Seller and no other corporate proceedings on the part of Seller are necessary to authorize this Agreement or to consummate the transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by Seller, and assuming that this Agreement constitutes a valid and binding agreement of Purchaser, subject to the receipt of Seller Required Regulatory Approvals and Purchaser Required Regulatory Approvals, constitutes a valid and binding agreement of Seller, enforceable against Seller in accordance with its terms, except that such enforceability may be limited by applicable bankruptcy, insolvency, moratorium or other similar laws affecting or relating to enforcement of creditors' rights generally or general principles of equity. (c) Consents and Approvals; No Violation. (i) Other than obtaining Seller Required Regulatory Approvals and Purchaser Required Regulatory Approvals, neither the execution and delivery of this Agreement by Seller nor the performance by Seller of its obligations under this Agreement will (A) conflict with or result in any breach of any provision of the Certificate of Incorporation or Bylaws (or other similar governing documents) of Seller; (B) require any consent, approval, authorization or permit of, or filing with or notification to, any governmental or regulatory authority, except where the failure to obtain such consent, approval, authorization or permit, or to make such filing or notification, would not have a Material Adverse Effect; (C) result in a default (or give rise to any right of termination, cancellation or acceleration) under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license, agreement or other instrument or obligation to which Seller is a party or by which Seller or any of the Commitments may be bound, including, without limitation, the Commitments except for such defaults (or rights of termination, cancellation or acceleration) as to which requisite waivers or consents have been obtained or which, in the aggregate, would not have a Material Adverse Effect; or (D) violate any order, writ, injunction, decree, statute, rule or regulation applicable to Seller, or any of its assets, which violation would have a Material Adverse Effect (ii) Except for such notices or approvals set forth on Schedule 3 (the "Seller Required Regulatory Approvals"), no declaration, filing or registration with, or notice to, or authorization, consent or approval of any governmental or regulatory body or authority is necessary for the consummation by Seller of the transactions contemplated hereby, other than such declarations, filings, registrations, notices, authorizations, consents or approvals which, if not obtained or made, will not, in the aggregate, have a Material Adverse Effect. (d) Title and Related Matters. Except as set forth in Schedule 5, Seller has good and valid title to the Power, free and clear of all Encumbrances. (e) The Commitments. (i) Each of the Commitments (A) constitutes a valid, binding and enforceable obligation of Seller and to the best knowledge of Seller constitutes a valid and binding and enforceable obligation of the other parties thereto and (B) is in full force and effect. (ii) Except as set forth in Schedule 6, there is not, under any of the Commitments, any default or event which, with notice or lapse of time or both, would constitute a default on the part of Seller and to the best knowledge of Seller on the part of the other parties thereto. The Commitments have not been amended, supplemented or modified except as described in Schedule 1 and the Commitments (as described in Schedule 1) contain the entire understanding of Seller and the other parties thereto with respect to the transactions contemplated thereby. (f) Legal Proceedings, etc. Except as set forth in Schedule 7, there are no claims, actions, proceedings or investigations pending or, to Seller's knowledge, threatened against or relating to Seller before any court, governmental or regulatory authority or body acting in an adjudicative capacity relating to the transactions contemplated hereby or that could otherwise have a Material Adverse Effect on the transactions contemplated hereby. (g) Regulation as a Utility. Seller is an "electric company" under Massachusetts law and subject to regulation by the MDTE and is also subject to regulation by FERC and the SEC. Seller is subject to the jurisdiction for certain limited purposes of the New Hampshire Public Utility Commission, the Maine Public Utilities Commission and the Connecticut Department of Public Utility Control. (h) Disclosure. No representation or warranty by Seller in this Agreement, and no document (including, without limitation, the Commitments) furnished or to be furnished to Purchaser pursuant to this Agreement or in connection herewith or with the transactions contemplated hereby, contains or will contain any untrue or misleading statement or omits or will omit any material fact necessary to make the statements contained herein or therein, in light of the circumstances under which ma de, not misleading. All facts of material importance to the business, operations, prospects, condition (financial or otherwise), commitments or liabilities of Seller relevant to the transactions contemplated hereby have been truthfully and completely disclosed to Purchaser in this Agreement. 8.2 Representations and Warranties of Purchaser. Purchaser represents and warrants to Seller as follows: (a) Organization. Purchaser is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware and has all requisite corporate power and authority to own, lease and operate its properties and t o carry on its business as is now being conducted. Purchaser is duly qualified or licensed to do business as a foreign corporation and is in good standing in each jurisdiction in which the property owned, leased or operated by it or the nature of the business conducted by it makes such qualification necessary, except in each case in those jurisdictions where the failure to be so duly qualified or licensed and in good standing would not have a Material Adverse Effect. Purchaser has heretofore delivered to Seller complete and correct copies of its Certificate of Incorporation and Bylaws (or other similar governing documents), as currently in effect. (b) Authority Relative to this Agreement. Purchaser has full corporate power and authority to execute and deliver this Agreement and to consummate the transactions contemplated hereby. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly and validly authorized by the Board of Directors of Purchaser and no other corporate proceedings on the part of Purchaser are necessary to authorize this Agreement or to consummate the transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by Purchaser, and assuming that this Agreement constitutes a valid and binding agreement of Seller, subject to the receipt of Purchaser Required Regulatory Approvals and Seller Required Regulatory Approvals, constitutes a valid and binding agreement of Purchaser, enforceable against Purchaser in accordance with its terms, except that such enforceability may be limited by applicable bankruptcy, insolvency, moratorium or other similar laws affecting or relating to enforcement of creditors' rights generally or general principles of equity. (c) Consents and Approvals; No Violation. (i) Except as set forth in Schedule 4, and other than obtaining Purchaser Required Regulatory Approvals and Seller Required Regulatory Approvals, either the execution and delivery of this Agreement by Purchaser nor the performance by Purchaser of its obligations under this Agreement will (A) conflict with or result in any breach of any provision of the Certificate of Incorporation or Bylaws (or other similar governing documents) of Purchaser, (B) require any consent, approval, authorization or permit of, or filing with or notification to, any governmental or regulatory authority, except where the failure to obtain such consent, approval, authorization or permit, or to make such filing or notification, would not have a Material Adverse Effect, (C) result in a default (or give rise to any right of termination, cancellation or acceleration) under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, agreement, lease or other instrument or obligation to which Purchaser or any of its Subsidiaries is a party or by which any of their respective assets may be bound, except for such defaults (or rights of termination, cancellation or acceleration) as to which requisite waivers or consents h ave been obtained, or (D) violate any order, writ, injunction, decree, statute, rule or regulation applicable to Purchaser, or any of its assets. (ii) Except as set forth in Schedule 4 (the filings and approvals referred to in Schedule 4 are collectively referred to as the "Purchaser Required Regulatory Approvals"), no declaration, filing or registration with, or notice to, or authorization, consent or approval of any governmental or regulatory body or authority is necessary for the consummation by Purchaser of the transactions contemplated hereby. (d) Regulation as a Utility. Purchaser is a power marketer authorized by the FERC to engage in the wholesale sale and brokering of electric energy and capacity at market-based rates pursuant to FERC Order 79 FERC 61,167, dated May 15, 1 997. ARTICLE 9 INDEMNIFICATION 9.1 Indemnification. (a) Seller will indemnify, defend and hold harmless Purchaser from and against any and all claims, demands or suits (by any Person), losses, liabilities, damages, obligations, payments, costs and expenses (including, without limitation, t he costs and expenses of any and all actions, suits, proceedings, assessments, judgments, settlements and compromises relating thereto and reasonable attorneys' fees and reasonable disbursements in connection therewith) to the extent the foregoing are not covered by insurance (each, an "Indemnifiable Loss"), asserted against or suffered by Purchaser relating to, resulting from or arising out of (i) any breach or alleged breach by Seller of any covenant or agreement of Seller contained in this Agreement or the Commitments (ii) any claim of a Power Seller or any third party to the extent arising from the acts or omissions of Seller or any of its agents or employees or (iii) any material breach by Seller of any representation or warranty set forth in Section 8.1 hereof. (b) Purchaser will indemnify, defend and hold harmless Seller from and against any and all Indemnifiable Losses asserted against or suffered by Seller relating to, resulting from or arising out of (i) any breach by Purchaser of any covenant or agreement of Purchaser contained in this Agreement, (ii) any claim of a Power Seller or any third party to the extent arising from the acts or omissions of Purchaser or any of its agents or employees or (iii) any material breach by Purchaser of any representation or warranty set forth in Section 8.2 hereof. (c) Any Person entitled to receive indemnification under this Agreement (an "Indemnitee") having a claim under these indemnification provisions shall make a good faith effort to recover all losses, damages, costs and expenses from insurer s of such Indemnitee under applicable insurance policies, if any exist, so as to reduce the amount of any Indemnifiable Loss hereunder. The amount of any Indemnifiable Loss shall be reduced (i) to the extent that Indemnitee receives any insurance proceeds with respect to an Indemnifiable Loss and (ii) to take into account any net Tax benefit recognized by the Indemnitee arising from the recognition of the Indemnifiable Loss and any payment actually received with respect to an Indemnifiable Loss . (d) The expiration, termination or extinguishment of any covenant or agreement shall not affect the parties' obligations under this Section 9.1 if the Indemnitee provided the Person required to provide indemnification under this Agreement (the "Indemnifying Party") with proper notice of the claim or event for which indemnification is sought prior to such expiration, termination or extinguishment. (e)Purchaser and Seller each agree that notwithstanding any provisions in this Agreement to the contrary, all parties to this Agreement retain their remedies at law or in equity with respect to willful or intentional breaches of this Agreement. 9.2 Defense of Claims. (a) If any Indemnitee receives notice of the assertion of any claim or of the commencement of any claim, action, or proceeding made or brought by any Person who is not a party to this Agreement or any Affiliate of a party to this Agreement (a "Third Party Claim") with respect to which indemnification is to be sought from an Indemnifying Party, the Indemnitee will give such Indemnifying Party reasonably prompt written notice thereof, but in any event not later than ten (10) calendar days after the Indemnitee's receipt of notice of such Third Party Claim. Such notice shall describe the nature of the Third Party Claim in reasonable detail and will indicate the estimated amount, if practicable, of the Indemnifiable Loss that has be en or may be sustained by the Indemnitee. The Indemnifying Party will have the right to participate in or, by giving written notice to the Indemnitee, to elect to assume the defense of any Third Party Claim at such Indemnifying Party's own expense a nd by such Indemnifying Party's own counsel, and the Indemnitee will cooperate in good faith in such defense at the Indemnifying Party's expense. (b) If within ten (10) calendar days after an Indemnitee provides written notice to the Indemnifying Party of any Third Party Claim the Indemnitee receives written notice from the Indemnifying Party that such Indemnifying Party has elected to assume the defense of such Third Party Claim as provided in the last sentence of Section 9.2(a), the Indemnifying Party will not be liable for any legal expenses subsequently incurred by the Indemnitee in connection with the defense thereof; provided, however, that if the Indemnifying Party fails to take reasonable steps necessary to defend diligently such Third Party Claim within twenty (20) calendar days after receiving notice from the Indemnitee that the Indemnitee believes the Indemnifying Party has failed to take such steps, the Indemnitee may assume its own defense, and the Indemnifying Party will be liable for all reasonable expenses thereof. Without the prior written consent of the Indemnitee, the Indemnifying Party will not enter into any settlement of any Third Party Claim which would lead to liability or create any financial or other obligation on the part of the Indemnitee for which the Indemnitee is not entitled to indemnification hereunder. If a firm offer is made to settle a Third Party Claim without leading to liability or the creation of a financial or other obligation on the part of the Indemnitee for which the Indemnitee is not entitled to indemnification hereunder and the Indemnifying Party desires to accept and agree to such offer, the Indemnifying Party will give written notice to the Indemnitee to that effect. If the Indemnitee fails to consent to such firm offer within ten (10) calendar days after its receipt of such notice, the Indemnitee may continue to contest or defend such Third Party Claim and, in such event, the maximum liability of the Indemnifying Party as to such Third Party Claim will be the amount of such settlement offer, plus reasonable costs and expenses paid or incurred by the Indemnitee up to the date of such notice. (c) Any claim by an Indemnitee on account of an Indemnifiable Loss which does not result from a Third Party Claim (a "Direct Claim") will be asserted by giving the Indemnifying Party reasonably prompt written notice thereof, stating the nature of such claim in reasonable detail and indicating the estimated amount, if practicable, but in any event not later than ten (10) calendar days after the Indemnitee becomes aware of such Direct Claim, and the Indemnifying Party will have a period of thirty (30) calendar days within which to respond to such Direct Claim. If the Indemnifying Party does not respond within such thirty (30) calendar day period, the Indemnifying Party will be deemed to have accepted such claim. If the Indemnifying Party rejects such claim, the Indemnitee will be free to seek enforcement of its rights to indemnification under this Agreement. (d)If the amount of any Indemnifiable Loss, at any time subsequent to the making of an indemnity payment in respect thereof, is reduced by recovery, settlement or otherwise under or pursuant to any insurance coverage, or pursuant to any claim, recovery, settlement or payment by or against any other entity, the amount of such reduction, less any costs, expenses or premiums incurred in connection therewith (together with interest thereon from the date of payment thereof at the prime r ate then in effect of the Bank of Boston, N.A.), will promptly be repaid by the Indemnitee to the Indemnifying Party. Upon making any indemnity payment, the Indemnifying Party will, to the extent of such indemnity payment, be subrogated to all right s of the Indemnitee against any third party in respect of the Indemnifiable Loss to which the indemnity payment relates; provided, however, that (i) the Indemnifying Party will then be in compliance with its obligations under this Agreement in respect of such Indemnifiable Loss and (ii) until the Indemnitee recovers full payment of its Indemnifiable Loss, any and all claims of the Indemnifying Party against any such third party on account of said indemnity payment is hereby made expressly subordinated and subjected in right of payment to the Indemnitee's rights against such third party. Without limiting the generality or effect of any other provision hereof, each such Indemnitee and Indemnifying Party will duly execute upon request all instruments reasonably necessary to evidence and perfect the above-described subrogation and subordination rights. Nothing in this Section 9.2(d) shall be construed to require any party hereto to obtain or maintain any insurance coverage. (e) A failure to give timely notice as provided in this Section 9.2 will not affect the rights or obligations of any party hereunder except if, and only to the extent that, as a result of such failure, the Party which was entitled to receive such notice was actually prejudiced as a result of such failure. ARTICLE 10 DISPUTE RESOLUTION 10.1 Arbitration Proceedings. Any dispute or need of interpretation arising out of this Agreement pertaining to the calculation of a termination payment pursuant to Article 7 or a payment required pursuant to Article 4 may be submitted upon request of either Party to binding arbitration by one arbitrator who has not previously been employed by either Party, and does not have a direct or indirect interest in either Party or the subject matter of the arbitration. Such arbitrator shall either be as mutually agreed by t he Parties within thirty (30) days after written notice from either Party requesting arbitration, or failing agreement, shall be selected under the expedited rules of the American Arbitration Association (the "AAA"). Such arbitration shall be held in alternating locations of the home offices of the Parties, commencing with Purchaser's home office, or in any other mutually agreed upon location. The rules of the AAA shall apply to the extent not inconsistent with the rules herein specified. Either Party may initiate arbitration by written notice to the other Party and the arbitration shall be conducted according to the following: (a) not later than seven (7) days prior to the hearing date set by the arbitrator each Party shall submit a brief with a single proposal for settlement, (b) the hearing shall be conducted on a confidential basis without continuance or adjournment, (c) the arbitrator shall be limited to selecting only one of the two proposals submitted by the Parties, (d) each Party shall divide equally the cost of the arbitrator and the hearing and each Party shall be responsible for its own expenses and those of its counsel and representatives and (e) evidence concerning the financial position or organizational make-up of the Parties, any offer made or the details of any negotiation prior to arbitration and the cost to the Parties of their representatives and counsel shall not be permissible. Each Party agrees that it will not bring a lawsuit concerning any dispute covered by this arbitration provision. Any monetary award of the arbitrator may be enforced by the Party in whose favor such monetary award is made in any court of competent jurisdiction. ARTICLE 11 MISCELLANEOUS 11.1 Entire Agreement. This Agreement, together with all Schedules hereto and the Ancillary Agreements constitute the entire agreement between the Parties and supersede all previous offers, negotiations, discussions, communications and correspondence with respect t o the transactions contemplated hereby. 11.2 Amendment. This Agreement may be amended only by a written agreement signed by the Parties. 11.3 Assignment. Unless mutually agreed to by the Parties, no assignment, pledge, or transfer of this Agreement shall be made by any Party without the prior written consent of the other Party, which shall not be unreasonably withheld, provided, however, that no prior written consent shall be required for (i) the assignment, pledge or other transfer to another company or Affiliate in the same holding company system as the assignor, pledgor or transferor, or (ii) the transfer, incident to a merger or consolidation with, or transfer of all (or substantially all) of the assets of the transferor, to another Person or business entity; provided, however, that such assignee, pledgee, transferee or acquirer of such assets or the Person with which it merges or into which it consolidates assumes in writing all of the obligations of such Party hereunder, and satisfies the Seller Credit Support obligations pursuant to Section 5.9 or the Purchaser Credit Support obligations pursuant to Section 5.8, as the case may be; and provided, further, that either Party may, without the consent of the other Party (and without relieving itself from liability hereunder), transfer, sell, pledge, encumber or assign such Party's rights to the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements. 11.4 Governing Law. The interpretation and performance of this Agreement shall be according to and controlled by the laws of The Commonwealth of Massachusetts (regardless of the laws that might otherwise govern under applicable Massachusetts principles of conflicts of laws). 11.5 Counterparts. This Agreement may be executed in two or more counterparts and each such counterpart shall constitute one and the same instrument. 11.6 Waiver. No waiver by a Party of any default by the other Party shall be construed as a waiver of any other default. Any waiver shall be effective only for the particular event for which it is issued and shall not be deemed a waiver with respect to any subsequent performance, default or matter. 11.7 Notices. All notices, requests, statements or payments shall be made as specified below. Notices required to be in writing shall be delivered by letter, facsimile or other documentary form. Notice by facsimile or hand delivery shall be deemed to have been received by the close of the Business Day on which it was transmitted or hand delivered (unless transmitted or hand delivered after close in which case it shall be deemed received at the close of the next Business Day). Notice by overnight mail or courier shall be deemed to have been received two Business Days after it was sent. A Party may change its addresses by providing notice of same in accordance herewith: to Purchaser: NOTICES & CORRESPONDENCE: Constellation Power Source, Inc. David M. Perlman, Esq. 111 Market Place, Suite 500 Baltimore, Maryland 21202 FAX No.: (410) 468-3540 Phone No.: (410) 468-3490 PAYMENTS: Federal Wire Transfer First National Bank of Maryland ABA Routing #052000113 Account: Constellation Power Source, Inc. Account #: 191-9007-8 INVOICES: Attn.: Stuart Rubenstein FAX No.: (410) 468-3540 Phone No.: (410) 468-3430 CREDIT AND COLLECTIONS: John R. Collins FAX No. (410) 468-3540 Phone No.: (410) 468-3410 SCHEDULING: Attn: Stuart Rubenstein FAX No.: (410) 468-3540 Phone No.: (410) 468-3430 To Seller: NOTICES & CORRESPONDENCE: Montaup Electric Company Manager, Power Supply Administration 750 West Center Street West Bridgewater, MA 02379 Fax: 508/559-6125 Phone: 508/559-2000 x3809 INVOICES: Richard Davis, Accounting Supervisor c/o EUA Service Corporation 750 West Center Street West Bridgewater, MA 02379 Fax: 508/559-6125 Phone: 508/559-2000 x3554 PAYMENTS: Federal Wire Transfer Fleet Bank ABA #011-000-206 Montaup Electric Company regular account Account #028-610-808-5 00101 Contact: Richard Davis, Accounting Supervisor Fax: 508/427-6493 Phone: 508/559-2000 x3554 11.8 No Third Party Beneficiaries. This Agreement shall not impart any rights enforceable by any third party (other than a permitted successor or assignee bound to this Agreement). 11.9 Severability. Any provision declared or rendered unlawful by any applicable court of law or regulatory agency or deemed unlawful because of a statutory change will not otherwise affect the remaining lawful obligations that arise under this Agreement. 11.10 Construction. The term "including" when used in this Agreement shall be by way of example only and shall not be considered in any way to be in limitation. The headings used herein are for convenience and reference purposes only. 11.11 Advisor. Goldman Sachs Power LLC ("GSP") is the exclusive advisor to Purchaser and not a principal of Purchaser. From time to time, Purchaser may designate one or more employees of GSP as Purchaser's agent for purposes of performing its obligations under this Agreement. Purchaser shall be solely responsible for any and all obligations and liabilities associated with this Agreement. Neither GSP, Goldman, Sachs & Co. nor J. Aron & Company, nor any of their affiliates, has any responsibility for, or liability with respect to the obligations of Purchaser under this Agreement or otherwise. 11.12 Audit. Each Party has the right, at its sole expense and during normal working hours, to examine the records of the other Party to the extent reasonably necessary to verify the accuracy of any statement, charge or computation made pursuant to this Agreement. If requested, a Party shall provide to the other Party statements evidencing the quantities of Power delivered at the Delivery Point. If any such examination reveals any inaccuracy in any statement, the necessary adjustments in such statement and the payments thereof will be made promptly and shall bear interest calculated at the Interest Rate from the date the overpayment or underpayment was made until paid; provided, however, that no adjustment for any statement or payment will be made unless objection to the accuracy thereof was made prior to the lapse of twelve (12) months from the rendition thereof. IN WITNESS WHEREOF, the parties have caused their duly authorized representatives to execute this Agreement on their behalf as of the date first above written. MONTAUP ELECTRIC COMPANY By: /s/ Kevin A. Kirby Name: Kevin A. Kirby Title: Vice President CONSTELLATION POWER SOURCE, INC. By: /s/ John R. Collins Name: John R. Collins Title: Vice President & Treasurer SCHEDULE 1 to POWER PURCHASE AND SALE AGREEMENT COMMITMENTS 1. Amended and Restated Power Sales Contract, dated December 18, 1998, between Montaup Electric Company and Southern Energy Canal, L.L.C. (the "Canal PPA"). 2. Power Purchase Agreement, dated October 17, 1986, between Northeast Energy Associates and Montaup Electric Company, as amended on June 28, 1989 and supplemented by Letter Agreement dated May 11, 1992.(the "Northeast PPA"). 3. Purchase Power Agreement, dated January 3, 1989, between Blackstone Hydro, Inc. ("BHI") and Montaup Electric Company, as assignee of Blackstone Valley Electric Company (the "BHI PPA"). 4. Power Supply Agreement, dated December 19, 1984, by and between City of Burlington Electric Department and Montaup Electric Company, as assignee of Newport Electric Corp., as amended by Letter Agreement on July 15, 1986 and on December 29 , 1989 (the "McNeil PPA"). 5. The Firm Energy Contract among Hydro-Quebec and the New England Utilities (as defined therein) dated October 14, 1985 (the "Firm Energy Contract"). A Commitment shall be automatically deleted from the above Commitment list without further action by the parties: (i) on the effective date of any amendment and assignment of the Commitment pursuant to Section 3.4 of the Agreement, (ii) upon the expiration of such Commitment pursuant to its terms, or (iii) upon the termination of such Commitment pursuant to the written agreement of the parties thereto with the written consent of Purchaser. SCHEDULE 1-A to POWER PURCHASE AND SALE AGREEMENT AGREEMENTS RELATED TO HYDRO-QUEBEC INTERCONNECTION 1. Agreement with Respect to Use of the Quebec Interconnection, dated December 1, 1981, as amended and restated as of September 1, 1985, and as further amended and restated as of November 19, 1997, and as further amended as of April 8, 1998 ("Use Agreement"). 2. Phase I Vermont Transmission Line Support Agreement, dated December 1, 1981, as amended on June 1, 1982, November 1, 1982, and January 1, 1986. 3. Phase I Terminal Facility Support Agreement, dated December 1, 1981, as amended June 1, 1982, November 1, 1982, and January 1, 1986. 4. Phase I New Hampshire Transmission Facilities Support Agreement, dated December 1, 1981. 5. Phase II Boston Edison AC Facilities Support Agreement, dated June 1, 1985, as amended May 1, 1986, February 1, 1987, June 1, 1987, September 1, 1987, and August 1, 1988. 6. Phase II New England Power AC Facilities Support Agreement, dated June 1, 1985, as amended May 1, 1986, February 1, 1987, June 1, 1987, September 1, 1987, and August 1, 1988. 7. Phase II Massachusetts Transmission Facilities Support Agreement, dated June 1, 1985, as amended May 1, 1986, February 1, 1987, June 1, 1987, September 1, 1987, October 1, 1987, August 1, 1988, and January 1, 1989. 8. Phase II New Hampshire Transmission Facilities Support Agreement, dated June 1, 1985, as amended May 1, 1986, February 1, 1987, June 1, 1987, September 1, 1987, October 1, 1987, August 1, 1988, January 1, 1989, and January 1, 1990. SCHEDULE 2 to POWER PURCHASE AND SALE AGREEMENT SELLER PAYMENTS Monthly amounts SCHEDULE 3 to POWER PURCHASE AND SALE AGREEMENT SELLER REQUIRED REGULATORY APPROVALS (i) Any required approvals under the Federal Power Act; (ii) (A) notice by Seller to, and an order by, the MDTE approving the Seller Guaranty; (B) a finding by the MDTE that Eastern's actions in regard to the Wholesale Standard Offer Service Agreement are in accordance with G.L.c. 164, 94A and 1(B)(b) and that the Wholesale Standard Offer Service Agreement may become effective; and (iii) the approval of the Seller Guaranty by the SEC pursuant to the Holding Company Act. SCHEDULE 4 to POWER PURCHASE AND SALE AGREEMENT PURCHASER REQUIRED REGULATORY APPROVALS The Purchaser requires no regulatory approvals prior to the Effective Date. However, from time to time during the Term of this Agreement, Purchaser must file quarterly transaction reports with the FERC reporting the execution of this Agreement and detailing purchases hereunder that occurred in the prior quarter. SCHEDULE 5 to POWER PURCHASE AND SALE AGREEMENT EXCEPTIONS TO SELLER'S TITLE TO THE COMMITMENTS Nothing to Disclose SCHEDULE 6 to POWER PURCHASE AND SALE AGREEMENT DEFAULTS UNDER THE COMMITMENTS Nothing to Disclose SCHEDULE 7 to POWER PURCHASE AND SALE AGREEMENT LEGAL PROCEEDINGS Nothing to Disclose SCHEDULE 8 to POWER PURCHASE AND SALE AGREEMENT EXHIBIT 10(bb)(ix) PPA TRANSFER AGREEMENT This PPA TRANSFER AGREEMENT ("Agreement") is dated as of April 7, 1998 and is made by and between MONTAUP ELECTRIC COMPANY, a Massachusetts corporation ("Seller"), and TRANSCANADA POWER MARKETING LTD., a Delaware corporation ("Asset Purchaser"). This Agreement set forth the terms and conditions under which Seller transfers to Asset Purchaser the economic benefits and performance obligations, subject to Seller's continuing obligations to make certain payments, associated with the power purchase agreements herein after described ("the Power Purchase Agreement") between seller and third party power supplier ("the Power Seller"), to Asset Purchaser pursuant to the Asset Purchase Agreement dated as of April 7, 1998 ("the APA"), by and between Seller and Asset Purchaser. 1. The following Power Purchase Agreement (as amended or supplemented, a "Commitment") is attached as an exhibit hereto and is incorporated into this Agreement by reference. Date Power Supplier 5/14/86 Ocean State Power (Montaup) 9/28/88 Ocean State Power II (Montaup) 5/14/86 Ocean State Power (Montaup 7/12/88 Ocean State Power II (Montaup) A Commitment shall be automatically deleted from the above Commitment list (the "Commitment List"} without further action by the parties: (i) on the effective date of any amendment and assignment of the Commitment pursuant to Section 7, below, (ii) upon the expiration of such Commitment pursuant to its terms, or (iii) upon the termination of such Commitment pursuant to the written agreement of the parties thereto. 2. This Agreement shall become effective on the Effective Date (as defined in Section 12) and shall remain in effect until Asset Purchaser has made payment to Seller of amounts owed pursuant to Section 4, below, for the last month in which a Commitment is listed on the Commitment List, and Seller has made payment to Asset Purchaser of amounts owned pursuant to Section 8 below, for the last month in which such a payment is due. 3. Commencing as of the Effective Date, each month Seller agrees to provide to Asset Purchaser all capacity, energy and any other benefits it receives under each Conunitment as of the first day of the month. All electric energy shall be deliver ed to Asset Purchaser at the point at which the Power Seller makes delivery to Seller as established under such Commitment. Asset Purchase shall be responsible for making all arrangements necessary for the further transmission of such energy. 4. (a) Commencing as of the month following the Effective Date, Asset Purchaser agrees to Pay to Seller each month all amounts properly due from Seller to the Power Seller for the preceding month associated with capacity, energy and any other benefits made available to it by Seller from each Commitment on the preceding month's Commitment List, less the amount of Seller's payment obligation specified in Section 8 below. In turn, each month, Seller shall timely pay the Power Seller an amount equal to all amounts properly due to the Power Seller for the preceding month under each Commitment. For purposes of the first monthly payment due from Asset Purchaser to Seller under this Agreement in connection with each Commitment, energy payments shall be based on meter readings taken on the first day for which Asset Purchaser has a payment obligation under this Agreement and capacity payments shall be based on the ratio of the number of days in the month for which Asset Purchaser has a payment obligation under this Agreement to the total number of days in the month. Asset Purchaser shall make such payment sufficiently in advance of the time that such payment is due by Seller to the Power Seller as to allow Seller to make timely payment under such Commitment, which includes the amount Seller receives from Asset Purchaser in connection with such Commitment and the amount of Seller's payment obligation specified in Section 8 below. (b) Upon the -Effective Date, Seller shall irrevocably and unconditionally assign and thereafter hold for the benefit of and/or credit to Asset Purchaser against payments due from it to Seller under Section 4(a) hereof or, at the termination of t his Agreement pay to Asset Purchaser, any and all amounts which are then or thereafter received by Seller from the Power Sellers under the Commitments, including, without limitation, any aggregate differential balances under any Commitment and the benefit of and proceeds from any security deposits, letters of credit or other similar instruments or accounts established for the benefit of Seller by the Power Seller, but excluding any credits or refunds received by Seller after the Effective Date which relate to billing errors or reconciliations of pre-Effective Date bills, and any amounts paid by the Power Sellers to Seller with respect to disputes arising before the Effective Date that are attributable to a period prior to the Effective Date . 5. (a) Effective as of the Effective Date, Seller hereby irrevocably and unconditionally appoints Asset Purchaser as its agent for all purposes under each Commitment. Asset Purchaser is authorized to take all actions that Seller may lawfully take under such Commitment without further approval by Seller, except that Seller's prior written consent shall be required for (i) actions that materially increase the costs to be incurred or the quantity of power to be purchased by Seller under such Commitment (such as the approval of facility expansions or fuel supply arrangements) and (ii) Commitment option exercises, term extensions or amendments. Seller shall not unreasonably withold such consent. (b) Seller shall not agree to any amendment to or waiver of rights under a Commitment without Asset Purchaser's consent, which Asset Purchaser may grant or withhold in its sole discretion, and will not take any actions inconsistent with the provisions of this Section 5. 6. Each party shall be entitled to indemnification under this Agreement to the extent and in the manner set forth in Article 9 of the APA which is hereby incorporated herein by reference. 7. (a) Seller and Asset Purchaser agree to work cooperatively and use all reasonable efforts to amend each Commitment and assign the amended Commitment to Asset Purchaser so that Seller will be released of all further liabilities and obligations under each Commitment and Asset Purchaser will be directly in contract with the Power Seller (a "Novation"). Any such amendment shall include all modifications necessary to reflect the substitution of Asset Purchaser for Seller as the purchasing party under such Commitment (including modifications to Commitment price indices, where appropriate) and to properly describe interconnection, delivery point and transmission system references in such Commitment. It is intended by the parties that such Commitment amendment and assignment preserve the economic benefit of a Commitment to the Asset Purchaser while continuing to afford to Seller the protections for its or its Affiliates transmission system embodied in the Commitment, provided that nothing in this Agreement is intended to limit the ability of Asset Purchaser to direct the dispatch, availability, quantity of timing of capacity or electrical output of a facility that is the subject of a Commitment in accordance with the terms of such Commitment. Seller and Asset Purchaser agree to execute all agreements and documents reasonably requested by the other in connection with a Novation. The provisions of Section 8(d) shall apply in respect of a Novation. (b) Notwithstanding the provisions of 7(a) the Seller and Asset Purchaser agree that, as a condition of any Novation, the Asset Purchaser will require Seller to provide, either (i) payment of a lump sum pursuant to the provisions of Section 8(d) which reduces the Seller's continuing obligation to zero ($0); or, if Seller and Buyer do not mutually agree to payment of a lump sum, (ii) a security interest to the Asset Purchaser in a portion of the Seller's Contract Termination Charge revenues a nd related service agreements with Eastern Edison Company, Blackstone Valley Electric Company and Newport Electric Corporation which is equal to the continuing obligation of the Seller under 8(b) and is acceptable to the Asset Purchaser acting reasonably. 8.(a) In the month during which this Agreement is executed, Seller shall pay the Power Seller an aggregate amount equal to the amount as set out in Schedule "A" attached hereto (the "Monthly Support Payment"), multiplied by a fraction, the numerator of which is the total number of days in the month in which this Agreement is executed, less the number of days in such month up to and including the date of the execution of this Agreement, and the denominator of which is the total number of days in the month in which this Agreement is executed, and such amount shall be deducted by Asset Purchaser from the amount due Seller under Section 4 above for such month. (b) Commencing as of the month following the Effective Date of this Agreement and continuing for each succeeding month through and including January 2008, Seller shall pay to the Power Seller each month an aggregate amount equal to the Monthly Support Payment, and such amount shall be deducted by Asset Purchaser from the amount due Seller under Section 4 above. (c) n the event that the amount of the Monthly Support Payment set forth is Section 8(b) (as adjusted to reflect any increase pursuant to this Section 8(c)) shall in any month exceed the amount due Seller from Asset Purchaser under Section 4, Seller shall increase the amount of its Monthly Support Payment in the next month (in addition to its obligation set forth in Section 8(b)) by the amount of such excess and Asset Purchaser shall also be allowed to deduct such excess from the amount due Seller under Section 4 for such month. (d) To the extent that a Novation is executed with respect to a Commitment pursuant to Section 7 and Asset Purchaser and Seller agree to a lump-sum payment, Seller and Asset Purchaser agree to amend this Agreement to equitability provide for a lump-sum payment to either Asset Purchaser or the Power Seller to reduce the amount of Seller's retained obligation set forth in Section 8(b). Such lump-sum payment and such reduction in the amount of Seller's retained obligation shall be in amounts to b e negotiated in good faith by Asset Purchaser and Seller. It is the intention of the parties that the lump-sum payment shall be based on the net present value of the amounts set out in Schedule "A" calculated using a discount rate acceptable to Asset Purchaser and Seller acting reasonably and which is reasonable given the remaining term of the amounts payable by the Seller to the Asset Purchaser as set out in Schedule "A", prevailing interest rates for similar financings done at the time of payment of the lump sum and the creditworthiness of Seller at the time of payment of the lump sum. 9. This Agreement and all rights, obligations, and performances of the parties hereunder, are subject to all applicable Federal and state laws, and to all promulgated orders and other duly authorized action of governmental authority having jurisdiction. 10. This Agreement, the APA and any other agreement entered into by the parties pursuant to the APA constitute the entire agreement between the parties, and supersede all previous offers, negotiations, discussions, communications and correspondence. This Agreement may be amended only a written agreement signed by the parties. Except as otherwise set forth in Section 5 hereof, this Agreement and all of the provisions hereof shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns, but neither this Agreement nor any of the rights, interests or obligations hereunder shall be assigned by any party hereto, including by operation of law without the prior written consent of the other party, nor is this Agreement intended to confer upon any other person except the parties hereto any rights or remedies hereunder. Notwithstanding the foregoing, (i) the Asset Purchaser may assign all of its rights and obligations hereunder to any wholly owned subsidiary (direct or indirect) of TransCanada Pipelines Limited ("TransCanada") and upon Seller's receipt of notice from Asset Purchaser of any such assignment, the Asset Purchaser will be released from all liabilities and obligations hereunder, accrued and unaccrued, such assignee will be deemed to have assumed, ratified, agreed to be bound by and perform all such liabilities and obligations, and all references herein to Asset Purchaser shall thereafter by deemed references to such assignee, in each case without the necessity for further act or evidence by the parties hereto or such assignee; provided, however, that no such assignment an d assumption shall release the Asset Purchaser from its liabilities and obligations hereunder unless the assignee shall have acquired all or substantially all of the Asset Purchaser's assets; provided, further, however, that no such assignment and assumption shall relieve or in any way discharge TransCanada from the performance of its duties and obligations under the Guaranty dated as of the date of this Agreement executed by TransCanada; and (ii) the Asset Purchaser or its permitted assignee ma y assign, transfer, pledge or otherwise dispose of its rights and interests hereunder to a trustee or lending institutions) for the purpose of financing or refinancing the Commitment including upon or pursuant to the exercise of remedies under a financing or refinancing, or by way of assignments, transfers, conveyances or dispositions in lieu thereof, provided, however, the no such assignment or disposition shall relieve or in any way discharge the Asset Purchaser or such assignee from the performance of its duties and obligations under this Agreement. Seller agrees to execute and deliver such documents as may be reasonably necessary to accomplish any such assignment, transfer, conveyances, pledge or disposition of rights hereunder so long as Sellers rights under this Agreement are not thereby otherwise altered, amended, diminished or otherwise impaired. The interpretation and performance of this Agreement shall be according to and controlled by the laws of The Commonwealth of Massachusetts (regardless of the laws that might otherwise govern under applicable Massachusetts principles of conflicts of laws). This Agreement may be executed in one or more counterparts and each such counterpart shall constitute one and the same instrument. 11. All payments required under this Agreement shall be paid in cash by federal or other wire transfer of immediately available funds to an account designated by the party to receive such such payment. 12. This Agreement shall be of no force and effect until the Effective Date. If the APA shall have been terminated before the occurrence of the Closing Date (as defined in the APA), this Agreement shall, without any action of the parties hereto, terminate as of the time of the termination of the APA. As used in this Agreement, "Effective Date" shall mean the Effective Date (as defined in the APA). 13. In the event that TransCanada Power Marketing, Ltd. or successor is in default of the Wholesale Standard Offer Agreement between TransCanada Power Marketing, Ltd. and Eastern Edison Company, Blackstone Valley Electric Company and Newport Electric Corporation and, having been given notice has failed to cure such default within the time specified in the Wholesale Standard Offer Agreement, Seller's obligation to make support payments under Section 8(a) will be suspended until such default i s fully cured. IN WITNESS WHEREOF, the parties have caused their duly authorized representatives to execute this Agreement on their behalf as of the date first above written. MONTAUP ELECTRIC COMPANY By: /s/ Kevin A. Kirby Name: Kevin A. Kirby Title: Vice President TRANSCANADA POWER MARKETING LTD. By: /s/ Alex Pourbaix Name: Alex Pourbaix Title: Vice President By: /s/ Russ Girling Name: Russ Girling Title: Senior Vice President EXHIBIT 10 (bb)(x) REINSTATEMENT AGREEMENT This Reinstatement Agreement (the "Agreement") is dated as of July 6, 1999 by and among Southern Energy Canal, L.L.C. ("Southern Canal') and Montaup Electric Company ("Montaup"). The parties hereto are referred to herein individually as a "Party" and collectively as the "Parties." RECITALS A. In connection with Southern Canal's acquisition of the Canal Station, Southern Canal assumed certain Power Contracts with Montaup, New England Power Company ("NEPCO"), Commonwealth Electric Company and Cambridge Electric Light Company (collectively "COM/Elec") and Boston Edison Company ("BECO') (collectively the "Original Purchasers") dated December 1, 1965 (the "Original Contracts") for the sale of 25% of the capacity and energy from Canal Unit I to each of the Original Purchasers. B. Pursuant to that certain PPA Transfer Agreement dated October 29, 1997 between USGen New England, Inc. ("USGenNE") and NEPCO, USGenNE was entitled to certain rights and benefits and was required to perform certain obligations under NEPCO's Original Contract. C. Southern Canal entered into Amended and Restated Power Sales Contracts dated December 18, 1998 with COM/Elec, BECO, and Montaup (the "Amended Agreements") and submitted the Amended Agreements to the Federal Energy Regulatory Commission ("FERC') for filing under Southern Canal's market rate authority. D. NEPCO and USGenNE filed a protest with FERC regarding the Amended Agreements on the grounds that the consent of NEPCO was required for the amendment of the Original Contracts. E. FERC rejected Southern Canal's filing of the Amended Agreements, and Southern Canal withdrew its filing and then refiled the Original Contracts under cost of service rate authority. F. Southern Canal has obtained the consent of NEPCO and USGenNE to the Amended Agreements and has entered into a new Amended and Restated Power Sales Contract with NEPCO which then assigned the contract to USGenNE and which in turn will assign the contract to Southern Energy New England, L.L.C. effective August 1, 1999. G. The Parties desire to reinstate the Amended Agreement between them (the "Montaup Agreement") in accordance with the terms hereof. H. Montaup has entered into a Power Purchase and Sale Agreement dated as of December 21, 1998 with Constellation Power Source, Inc. ("Constellation") pursuant to which Montaup has agreed to sell the products it receives under the Montaup Agreement to Constellation. NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements hereinafter set forth, the Parties hereto mutually covenant and agree as follows: 1. Southern Canal and Montaup hereby reinstate the Montaup Agreement, effective as of July 1, 1999 (the "Effective Date"). 2. Southern Canal consents to any future assignment by Montaup of the Montaup Agreement to Constellation; provided, however, that at the time of such assignment Constellation meets the Creditworthiness Criteria asset forth in the Montaup Agreement or delivers to Southern Canal a duly executed Guarantee in form and substance satisfactory to Southern Canal from Constellation's parent company which meets the Creditworthiness Criteria. 3. Southern Canal shall file this Agreement with FERC and the Parties agree that the rates set forth in the Montaup Agreement apply for the period from January 1, 1999 through the Effective Date. Within 30 days after a final order from FERC approving this Agreement, Southern Canal shall pay Montaup the amount, if any, by which the sum of the demand charges for January 1, 1999 through the Effective Date billed to and paid by Montaup under the Original Agreement is greater than the amount that would have been payable if the Montaup Agreement were effective as of January 1, 1999; provided that such payment shall be made with interest computed in accordance with the FERC regulations. 4. In connection with this Agreement and the transactions contemplated hereby, each Party shall execute and deliver any additional documents and instruments and perform any additional acts that may be necessary or appropriate to effectuate and perform the provisions of this Agreement. 5. This Agreement shall inure to the benefit of and be binding upon the Parties and their respective successors and assigns. IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their officers duly authorized thereunto and have duly caused their corporate or company seals to be affixed hereto. SOUTHERN ENERGY CANAL, L.L.C. By: /s/Henry T. E. Coolidale, Jr. Name: Henry T. E. Coolidale, Jr Title: President MONTAUP ELECTRIC COMPANY By: /s/ Kevin A. Kirby Name: Kevin A. Kirby Title: Vice President Exhibit (13) Annual Report 2001 New England Power Company New England Power Company New England Power Company, (the Company) a wholly owned subsidiary of National Grid USA (formerly New England Electric System), is a Massachusetts corporation qualified to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine, and Vermont. The Company is subject, for certain purposes, to the jurisdiction of the regulatory commissions of all these states (except Connecticut), the Securities and Exchange Commission, under the Public Utility Holding Company Act of 1935, the Federal Energy Regulatory Commission, and the Nuclear Regulatory Commission. The Company's business is primarily the transmission of electric energy in wholesale quantities to other electric utilities, principally its distribution affiliates Granite State Electric Company, Massachusetts Electric Company, Nantucket Electric Company, and The Narragansett Electric Company. The Company's transmission facilities are part of National Grid USA's transmission operations, which are represented under the name National Grid Transmission USA. Report of Independent Accountants New England Power Company, Westborough, Massachusetts: In our opinion, the accompanying balance sheets and the related statements of income, of retained earnings, and of cash flows present fairly, in all material respects, the financial position of New England Power Company at March 31, 2001 and 2000, and the results of its operations and its cash flows for the year ended March 31, 2001, the three month period ended March 31, 2000, and the years ended December 31, 1999 and 1998, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. s/PricewaterhouseCoopers LLP Boston, Massachusetts April 25, 2001, except for the last paragraph of the Seabrook 1 section of Note D, as to which the date is May 22, 2001, and the fourth paragraph of Note C, as to which the date is June 8, 2001 New England Power Company Financial Review Merger with National Grid On March 22, 2000, the merger of New England Electric System (NEES) and National Grid Group plc (National Grid) was completed, with NEES (renamed National Grid USA) becoming a wholly owned subsidiary of National Grid. New England Power Company (the Company) maintained its existing name and remained a wholly owned subsidiary of National Grid USA. The merger was accounted for by the purchase method, the application of which, including the recognition of goodwill, was pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including the Company. Total goodwill amounted to $1.7 billion, of which the Company was allocated approximately $348 million. This amount was determined pursuant to a study conducted by an independent third party and is being amortized over 20 years. Amortization expense is approximately $17.4 million annually. The purchase accounting method requires the revaluation of assets and liabilities to their fair value. This revaluation resulted in an adjustment to the Company's pension and postretirement benefit accounts in the amount of approximately $61 million, with an offsetting net credit to a regulatory liability account (see Note E). Acquisition of EUA The acquisition of Eastern Utilities Associates (EUA) by National Grid USA was completed on April 19, 2000 for $642 million. On May 1, 2000, Montaup Electric Company (Montaup), formerly a subsidiary of EUA, was merged into the Company. The acquisition of EUA was accounted for by the purchase method, the application of which, including the recognition of goodwill, has been pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including the Company. Total goodwill recognized in this transaction was approximately $402 million, of which the Company was allocated approximately $8 million. This amount was determined pursuant to a study conducted by an independent third party and is being amortized over 20 years. Amortization expense is approximately $0.4 million annually. The purchase accounting method requires the revaluation of assets and liabilities to their fair value. This revaluation resulted in an adjustment to the Company's pension and postretirement benefit accounts in the amount of approximately $3 million, with an offsetting net credit to a regulatory liability account (see Note E). As a result of the acquisition, Montaup's balance sheet accounts were incorporated into the financial statements of the Company as of May 1, 2000. Listed below are the significant account balances incorporated.
May 1, 2000 balance (In thousands) Assets Utility plant, at original cost $227,114 Accumulated provisions for depreciation and amortization $(92,093) Regulatory assets (current and long-term) $547,412 Liabilities Other paid-in capital $135,444 Deferred federal and state income taxes $104,860 Accrued Yankee nuclear plant costs $ 46,030 Purchased power obligations (current and long-term) $176,257 Other reserves and deferred credits $174,942
The accompanying statements of operations do not include any revenues or expenses related to Montaup prior to the companies' merger on May 1, 2000. Regulatory Environment and Accounting Implications Under settlement agreements, the Company is permitted to recover costs associated with its former generating investments and related contractual commitments that were not recovered through the sale of those investments (stranded costs). These costs are recovered from the Company's wholesale customers with which it has settlement agreements through contract termination charges (CTC). The Company's retail distribution affiliates recover CTC-related costs through delivery charges to distribution customers. The recovery of the Company's stranded costs (including the Montaup share) is divided into several categories. The Company's unrecovered costs associated with generating plants (nuclear and nonnuclear) and most regulatory assets were fully recovered through the CTC by the end of 2000 and earned a return on equity (ROE) averaging 9.7 percent. The Montaup share of unrecovered costs associated with generating plants and most regulatory assets will be fully recovered through the CTC by the end of 2009. The Company's obligation related to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC as such costs are actually incurred. As the CTC rate declines, the Company, under certain of the settlement agreements, earns incentives based on successful mitigation of its stranded costs. These incentives supplement the Company's ROE. Until such time as the Company divests its operating nuclear interests, 80 percent of the revenues and operating costs related to the units will be allocated to customers through the CTC, with shareholders being allocated the balance. In conjunction with the divestiture, the Company transferred to the buyer of its nonnuclear generating business (the buyer) its entitlement to power procured under several long-term contracts in exchange for monthly fixed payments by the Company. Similar to the Company, Montaup also transferred its purchased power obligations as part of the divestiture and in return agreed to make fixed monthly payments. The aggregate fixed monthly payments, including the Montaup share, average $11.3 million per month through December 2009 toward the above-market cost of those contracts. The liability relating to purchased power obligations, which is also reflected in regulatory assets, represents the net present value of these fixed monthly payments. At March 31, 2001, the net present value is approximately $786 million. For certain contracts which have been formally assigned to the buyer, the Company has made lump sum payments equivalent to the present value of the monthly fixed payment obligations of those contracts (approximately $453 million), which were separate from the $786 million figure referred to above. Prior to divesting substantially all of its nonnuclear generation business in 1998, the Company was the wholesale supplier of the electric energy requirements to its retail distribution affiliates as well as unaffiliated customers. The Company's all-requirements contracts with its affiliated distribution companies, as well as with some unaffiliated customers, were generally terminated pursuant to settlement agreements and tariff provisions in 1998. However, the Company remains obligated to provide transition power supply service to new customer load in Rhode Island at the standard offer price, but does not have a regulatory agreement that necessarily allows full recovery of the costs of such standard offer power. Consequently, the Company is at risk for the difference between the actual cost of serving this load and the revenue received from this obligation. The standard offer rate that the Company charges for continuing to meet this obligation increased from 3.5 cents per kilowatthour (kWh) in 1999 to 3.8 cents per kWh effective January 1, 2000. The standard offer rate is also subject to a rolling twelve-month fuel index adjustment factor, which increased the rate by an additional 0.121 cents per kWh beginning in April 2000 up to 2.404 cents per kWh by March 2001. The Company meets this obligation through a combination of generation from some of its remaining generation sources, as well as by periodically procuring power at market prices. Over time, the Company cannot predict whether the resulting revenues will be sufficient to cover the costs of procuring such power. For the year ended March 31, 2001, the Company's losses from this obligation were approximately $5 million. In a December 15, 2000 Order, the Federal Energy Regulatory Commission (FERC) rejected the Independent System Operator-New England's (ISO New England) proposed $0.17 per kW-month Installed Capacity (ICAP) deficiency charge and reinstated an administratively-determined deficiency charge of $8.75 per kW-month, retroactive to August 1, 2000. Several parties, including the Company, filed motions requesting rehearing and stay of the FERC's order. On January 10, 2001, the FERC granted these motions. On March 6, 2001, the FERC reversed its earlier order by allowing ISO New England's previously proposed ICAP rate of $0.17 per kW-month to be effective from August 1, 2000 through March 31, 2001. Effective April 1, 2001, the FERC ordered an ICAP rate of $8.75 per kW-month. On March 16, 2001, National Grid and others filed a motion to stay the FERC Order with the United States Court of Appeals for the First Circuit (First Circuit). The First Circuit stayed the ICAP rate of $8.75 per kW-month on March 30, 2001. On June 4, 2001, ISO New England made a filing to comply with the March FERC order that proposed a maximum charge of $4.87 per kW-month. On June 8, 2001, the First Circuit, ruling on the merits of the appeal to the FERC's imposing the $8.75 per kW-month charge, remanded the case to the FERC for further consideration. The First Circuit order allows the FERC to reinstate its initial order on a prospective basis, but asks the FERC to answer several questions to support its order. National Grid and others have asked the FERC to consider the June 4th ISO filing while it is reconsidering its initial order on remand. At this time, the Company cannot predict how ICAP charges will affect its forward looking power supply costs. National Grid USA presented to the FERC in January 2001 a joint proposal, with ISO New England and other utilities in New England, for a Regional Transmission Organization (RTO) in the northeastern US. The RTO would consist of an ISO with responsibility for administering a competitive wholesale market in electricity and an Independent Transmission Company offering transmission services and undertaking transmission network development and the provision of connections for new generation. The proposal responds to the FERC's objective set out in "Order 2000", of separating transmission operations from market participation and would give the Independent Transmission Company, of which National Grid USA would be a member, the opportunity to propose financial incentives to deliver greater value for customers and shareholders. The proposal is subject to FERC approval and the ability of the utility group to reach agreement on a number of additional issues. Because electric utility rates have historically been based on a utility's costs, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. The Company applies the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), which requires regulated entities, in appropriate circumstances, to establish regulatory assets or liabilities, and thereby defer the income statement impact of certain charges or revenues because they are expected to be collected or refunded through future customer billings. In 1997, the Emerging Issues Task Force of the Financial Accounting Standards Board concluded that a utility that had received approval to recover stranded costs through regulated rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs. The Company has received authorization from the FERC to recover through CTCs substantially all of the costs associated with its former generating business not recovered through the divestiture. Additionally, FERC Order No. 888 enables transmission companies to recover their specific costs of providing transmission service. Therefore, substantially all of the Company's business, including the recovery of its stranded costs, remains under cost-based rate regulation. Because of the nuclear cost-sharing provisions related to the Company's CTC, the Company ceased applying FAS 71 in 1997 to 20 percent of its ongoing nuclear operations, the impact of which is immaterial. As a result of applying FAS 71, the Company has recorded a regulatory asset for the costs that are recoverable from customers through the CTC. At March 31, 2001, this amounted to approximately $1.7 billion, including $1.1 billion related to the above-market costs of purchased power contracts, $0.2 billion related to accrued Yankee nuclear plant costs, and $0.4 billion related to other net CTC regulatory assets. Overview of Financial Results Net income for the twelve months ended March 31, 2001 decreased $13 million compared with the twelve months ended December 31, 1999. The decrease is primarily due to goodwill amortization from the mergers with National Grid and EUA, increased purchased power costs, increased interest expense, and decreased mitigation incentives, partially offset by increased income due to the May 1, 2000 merger with Montaup, and increased earnings from nuclear operations. Net income for the three months ended March 31, 2000 decreased $6 million compared with the same period in 1999 primarily due to the elimination of certain liabilities related to open access transmission tariffs of approximately $5 million in the first quarter of 1999. Net income for the year ended December 31, 1999 decreased $52 million compared with the same period in 1998 as a result of the continuing impacts of the divestiture and the restructuring of the utility business. Partially offsetting the decrease was the recovery of stranded cost mitigation incentives of approximately $25 million in 1999 compared with $10 million in 1998, as well as increased transmission revenues of approximately $13 million due to the elimination of certain liabilities related to open access transmission tariffs. Operating Revenue Operating revenue for the twelve months ended March 31, 2001 increased approximately $60 million compared with the twelve months ended December 31, 1999. The increase is due to increased sales and rates related to obligations to new customer load in Rhode Island, and increased unit contract sales from partially owned nuclear units that experienced refueling outages in 1999. These increases are also affected by the merger with Montaup, effective May 1, 2000. Partially offsetting these increases are decreased CTC revenues due to fully reconciling true- up mechanisms that allow the Company to adjust revenues proportionately with correlating expenses, and decreased transmission revenues. The transmission charge is a formula rate that recovers the Company's actual costs plus a return on actual investment. Operating revenue for the three months ended March 31, 2000 decreased $33 million compared with the same period in 1999, largely due to CTC revenue of approximately $21 million from The Narragansett Electric Company (Narragansett Electric) in 1999 related to its access charge overcollections. This payment reduced Narragansett Electric's future CTC obligations. This additional revenue in 1999 had a corresponding impact to the amortization of CTC, discussed in "Operating Expenses" below. The decrease was also due to the elimination of certain liabilities related to open access transmission tariffs of $5 million in 1999. This decrease was partially offset by the impacts of increased standard offer rates effective January 1, 2000 and increased kWh sales in the three months ended March 31, 2000 compared with the same period in 1999. Operating revenue for the year ended December 31, 1999 decreased $622 million compared with 1998 due to the divestiture and reduced CTC charges. Partially offsetting this decrease was an increase in transmission revenues associated with the elimination of certain liabilities related to open access transmission tariffs discussed above. Operating Expenses Operating expenses for the twelve months ended March 31, 2001 increased approximately $51 million compared with the twelve months ended December 31, 1999. Fuel for generation increased approximately $2 million primarily related to charges at the Wyman 4 generating plant. Purchased power expense for the twelve months ended March 31, 2001 increased approximately $62 million compared with the twelve months ended December 31, 1999. This increase is primarily attributed to the inclusion of Montaup's purchased power costs effective May 1, 2000, increased fuel prices, and an increase in standard offer purchases related to obligations to supply new customer load in Rhode Island, partially offset by decreased purchased power charges from the Yankee Nuclear Power Companies (Yankees). Charges from Maine Yankee decreased due to a refund for the termination of excess nuclear insurance coverage. Vermont Yankee purchased power charges decreased due to the effect of a refueling outage during the quarter ended December 31, 1999. In addition, purchased power charges from the Yankee Atomic nuclear power plant decreased as a result of the completion of the purchased power contract and final billing in June 2000. Nuclear operation and maintenance expenses increased approximately $7 million primarily due to the merger of Montaup's ownership percentage of Millstone 3 with the Company's effective as of the merger date, as well as the effects of increased expenses related to refueling outages and other maintenance at Millstone 3 and Seabrook 1. Other nonnuclear operation and maintenance expenses decreased approximately $5 million compared with the twelve months ended December 31, 1999 primarily due to reduced pension and postretirement healthcare expenses and reduced transmission costs. These decreases are partially offset by the receipt of a transmission wheeling refund that reduced expense in June 1999. Depreciation and amortization expenses decreased approximately $24 million for the twelve months ended March 31, 2001 compared with the twelve months ended December 31, 1999. This decrease is primarily related to decreased CTC amortization as a result of the full recovery of the Company's CTC-related costs associated with its generating plants and regulatory assets (excluding Montaup's) at the end of 2000. This decrease is partially offset by the Company's payments to increase the Millstone 3 decommissioning trust fund to the level prescribed in the Release and Settlement Agreement with Northeast Utilities (NU) (see the "Millstone 3" disclosure in the "Nuclear units" section), as well as the effect of the addition of Montaup's ownership percentage of Millstone 3 effective as of the merger date. Operating expenses for the three months ended March 31, 2000 decreased $27 million compared with the same period in 1999. The increase in fuel and purchased power expense of approximately $5 million reflected increased purchased power expenses for standard offer requirements and increased kWh purchased. Other operating expenses in the three months ended March 31, 2000 decreased approximately $3 million compared with the same period in 1999 due to the reimbursement of start-up costs from 1999 of the ISO New England in 2000. Maintenance expenses decreased approximately $1 million as a result of reduced expenses at the partially owned Millstone 3 and Seabrook 1 nuclear generating facilities. Depreciation and amortization expenses in the three months ended March 31, 2000 decreased $23 million compared with the same period in 1999. This decrease was due to additional CTC amortization in 1999 related to the additional payment of approximately $21 million by Narragansett Electric to the Company, discussed above. Operating expenses for the year ended December 31, 1999 decreased $543 million compared with 1998. The divestiture reduced all categories of operating expenses in 1999, with the exception of depreciation and amortization expense. The decrease in fuel expense and purchased power costs reflected the divestiture and the assumption of the Company's obligations under most of its previously existing purchased power contracts by the buyer of its nonnuclear generating business. The Company remains obligated to pay predetermined amounts to the buyer related to the above-market cost of those contracts. In addition, the Company also remains obligated under purchased power contracts with the four Yankees, the costs of which decreased $8 million in 1999, reflecting reduced costs from Maine Yankee and Connecticut Yankee, net of increased costs of a 1999 refueling outage at Vermont Yankee. In addition to the impact of the divestiture, which reduced nonnuclear generation operation and maintenance expenses by $71 million, the decrease in other operation and maintenance expenses reflected reduced general and administrative costs due primarily to workforce reductions and reduced charges from New England Power Service Company following the divestiture. In addition, transmission costs decreased $16 million in 1999 due to the assumption of transmission support agreements by the buyer and reduced ISO New England start-up costs. These decreases were partially offset by increased costs of $3 million associated with the partially owned Millstone 3 and Seabrook 1 nuclear generating facilities that experienced refueling outages in the second quarter of 1999. Depreciation and amortization expenses increased $3 million for the year ended December 31, 1999, due to the recovery and amortization of generation-related stranded costs being greater than the depreciation and amortization of generation-related plant in the prior year. The increase was also due to new transmission plant expenditures. Other Income and Expense Other income for the twelve months ended March 31, 2001 increased compared with the twelve months ended December 31, 1999 primarily due to increased earnings from the Yankees, partially offset by a decrease in allowance for equity funds used during construction. The amortization of goodwill of approximately $18 million resulted from the mergers with National Grid and EUA. Other income for the three months ended March 31, 2000 increased compared with the same period in 1999 as a result of decreased expenses related to employee incentive plans from workforce reductions following the divestiture, partially offset by merger related expenses in 2000. For the year ended December 31, 1999, other income increased compared with the year ended December 31, 1998 primarily due to increased interest income resulting from the reinvestment of the proceeds from the divestiture. In 1999, this was partially offset by reduced equity income from nuclear power companies as a result of reductions in the rates of return for two of these companies. Interest Expense Interest expense increased for the twelve months ended March 31, 2001 compared with the twelve months ended December 31, 1999, primarily due to higher interest rates on variable rate long-term debt and increased short-term debt borrowings, as well as interest related to Montaup's CTC settlement. Interest expense for the three months ended March 31, 2000 increased compared with the same period in 1999 primarily due to increased interest rates on variable rate long-term debt and interest on short-term debt borrowings not present in 1999. Interest expense for the year ended December 31, 1999 decreased compared with the year ended December 31, 1998 principally due to reduced long-term and short-term debt as a result of the divestiture. Nuclear Units Nuclear Units Permanently Shut Down Three of the Yankees in which the Company has a minority interest own nuclear generating units that have been permanently shut down. These three units are as follows:
Future The Company's Estimated Investment Billings to as of 3/31/01 Date the Company Unit % $(millions) Retired $(millions) - ----------------------------------------------------------------- Yankee Atomic 34.5 2 Feb 1992 0 Connecticut Yankee 19.5 15 Dec 1996 50 Maine Yankee 24.0 17 Aug 1997 129
In the case of each of these units, the Company has recorded a liability and a regulatory asset reflecting the estimated future billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant, including a return on that investment, as well as unfunded nuclear decommissioning costs and other costs. Maine Yankee and Connecticut Yankee recover their costs, including a return, in accordance with settlement agreements approved by the FERC in May 1999 and July 2000, respectively. Prospectively, under the FERC settlement agreement, Connecticut Yankee agreed to reduce annual collections for decommissioning through the use of its pre-1983 spent fuel trust funds and to limit its ROE to 6 percent. In addition, Connecticut Yankee, Yankee Atomic, and Maine Yankee continue to pursue litigation against the Department of Energy (DOE) to assume financial responsibility for storage of spent nuclear fuel. Under rate provisions approved by the FERC for Connecticut Yankee and Yankee Atomic, any recovery from the DOE proceedings after litigation expenses and taxes will be returned to customers. 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. Maine Yankee had hired Stone & Webster, Inc. (S&W), an engineering, construction, and consulting company, as the principal contractor to decommission the unit. In May 2000, Maine Yankee terminated its long-term contract with S&W and negotiated an arrangement with S&W to continue work through June 2000. In June 2000, S&W filed for Chapter 11 bankruptcy protection. Subsequently, Maine Yankee decided to self-manage the unit's decommissioning process. In June 2000, Federal Insurance Company (Federal) filed a complaint in S&W's bankruptcy proceeding which alleges that Maine Yankee improperly terminated its contract with S&W. If the court were to make such a finding, Federal would be excused from a $37 million performance bond liability to Maine Yankee. Federal's complaint has been removed to the US Federal District Court in Maine for jury trial. In August 2000, Maine Yankee filed a $78.2 million (later increased to $86 million) damage claim against S&W in the bankruptcy proceeding. At this time, the Company is unable to determine the potential impact, if any, of these developments. Under the provisions of the Company's industry restructuring settlement agreements approved by state and federal regulators in 1998, the Company recovers all costs, including shutdown costs, that the FERC allows these Yankee companies to bill to the Company. Operating Nuclear Units The Company currently has minority interests in two operating nuclear generating units that the Company is engaged in efforts to divest: Vermont Yankee and Seabrook 1. In addition, the Company sold its 16.2 percent interest in Millstone 3 to Dominion Resources, Inc. (Dominion) on March 31, 2001. Until such time as the Company divests its operating nuclear interests, 80 percent of the revenues and operating costs related to the units will be allocated to customers through the CTC, with shareholders being allocated the balance. Vermont Yankee The following table summarizes the Company's interest in the Vermont Yankee Nuclear Power Corporation as of March 31, 2001:
The Company's Interest (millions of dollars) --------------------------------------------- Equity Net Estimated Decommissioning Ownership Equity Plant Decommissioning Fund License Interest (%) Investment Assets Cost (in 2000$) Balance Expiration ------------ ---------- ------ --------------- ------- ---------- 22.5 $12 $36 $102 $57 2012
In November 1999, the Vermont Yankee Nuclear Power Corporation entered into an agreement with AmerGen Energy Company (AmerGen), a joint venture between PECO Energy and British Energy, to sell the assets of Vermont Yankee. Several other parties, including Entergy Corporation (Entergy), indicated to the Vermont Public Service Board (VPSB) that they were prepared to make an offer for Vermont Yankee. On February 14, 2001, the VPSB rejected Vermont Yankee's sale agreement with AmerGen and formally terminated the AmerGen proceeding on March 15, 2001. The VPSB also required Entergy to post a $26 million bond payable in the event that Entergy withdraws its offer. In addition, the VPSB stated that if the Entergy bond were redeemed, the proceeds would go exclusively to Vermont customers. The Vermont Yankee Board of Directors is presently considering its options with respect to that part of the order. On March 15, 2001, Vermont Yankee terminated its agreement with AmerGen. After considering the pros and cons of shutting the plant down, continuing to operate it, or sell it, Vermont Yankee decided to proceed with a formal auction of the plant. The auction was officially launched on April 16, 2001. The Company expects that the winning bidder of the plant will be named in the fall of 2001. Any sale of the plant is contingent upon the receipt of regulatory approvals by the Securities and Exchange Commission, under the Public Utility Holding Company Act of 1935, the FERC, the Nuclear Regulatory Commission, the VPSB, and other state regulatory commissions with jurisdiction over other equity owners of Vermont Yankee. Under the terms of the original AmerGen agreement, the existing power purchasers (including the Company) were required to continue to purchase the output of the plant or to buy out of the purchased power obligation. In November 1999, the Company signed an agreement to buy out of its obligation, requiring future payments which would be recovered through the Company's CTC. At that time, the Company recorded a liability and offsetting regulatory asset of $80 million for its share of future liabilities related to Vermont Yankee, including the purchased power contract termination payment obligation, but excluding interest and a return allowance. With Vermont Yankee's termination of the agreement with AmerGen in March 2001, the Company was relieved of this obligation and accordingly reversed the liability and offsetting regulatory asset of $80 million. To date, the Company has not determined if it will enter into a purchased power agreement with a proposed new owner of Vermont Yankee. Seabrook 1 As part of its restructuring settlement with the State of New Hampshire, Public Service Company of New Hampshire (PSNH), through its affiliate, North Atlantic Energy Corporation (NAEC), committed to seek New Hampshire Public Utilities Commission (NHPUC) approval of a definitive plan to sell, via public auction administered by the NHPUC, its share of Seabrook 1, with such sale to occur no later than December 31, 2003. NAEC owns the largest percentage of the plant with a 35.98 percent interest, and its affiliate, North Atlantic Energy Service Corporation, is the plant operator. As part of its settlement, PSNH has also agreed to make all reasonable efforts to bundle its interests with those of other owners (including the Company) seeking to sell their interests so that a controlling interest may be offered in the auction. In December 2000, NU filed its divestiture plan before the NHPUC, requesting an expeditious process in order to permit a prompt sale of the plant. Under the terms of the PSNH Settlement and enabling legislation, the NHPUC will administer the sale of the plant with the assistance of an asset sale specialist. On April 12, 2001, the Company filed a Seabrook Divestiture Plan with the NHPUC as directed by its 1998 restructuring settlement agreement. Under the Divestiture Plan, the Company has indicated its interest in selling its share of Seabrook 1 and has requested that the NHPUC administer an auction on the Company's behalf under certain guidelines and conditions. On May 22, 2001, legislation was enacted in New Hampshire to provide New Hampshire residents additional protections against the restructuring problems encountered in California. Although the legislation includes provisions to delay the sale of PSNH fossil and hydro generation assets, it directs the NHPUC to expedite the auction of the Seabrook Station in a manner that benefits customers of all New Hampshire utilities, including the Company. Millstone 3 In November 1999, the Company entered into an agreement with NU and certain of NU's subsidiaries to settle claims made by the Company relative to the operation of Millstone 3. Among other things, the settlement provided for NU to include the Company's share of Millstone 3 in an auction of NU's share of the unit. Upon the closing of the sale, NU would pay the Company a total of $25 million, regardless of the actual sale price, with adjustments for certain capital and fuel procurement expenditures. The settlement also required NU to indemnify the Company and assume any residual liabilities resulting from the sale, including any requirements that the sellers continue to purchase output from the unit. In August 2000, Dominion agreed to purchase the Millstone units, including the Company's 16.2 percent interest in Millstone 3, for $1.3 billion in cash. In November 2000, the Rhode Island Attorney General and the Rhode Island Division of Public Utilities and Carriers filed a protest at the FERC contending that the payment the Company would receive from the sale of Millstone 3, as established by its agreement with NU, was insufficient. In December 2000, the Company and other parties to the Millstone sale submitted answers opposing Rhode Island's position and arguing, among other things, that Rhode Island's contention was well beyond the scope of the FERC proceeding. The Company further stated that concerns over the customer rate impact of the Company's agreement with NU would be more appropriately addressed under the terms of its restructuring settlements. On January 25, 2001, the FERC found that Rhode Island's objection was beyond the scope of the proceeding and approved the sale. On March 31, 2001, the Company completed the sale of its 16.2 percent interest in Millstone 3 for approximately $27.9 million. In addition, the Company paid approximately $5.8 million to increase the decommissioning trust fund to the level prescribed in its settlement agreement with NU. The amounts received pursuant to the sale will, after reimbursement of the Company's transaction costs and net investment in Millstone 3, be credited to customers. The Company cannot predict whether the Rhode Island regulators will reassert their claims in connection with the recovery of stranded costs, or the financial consequences if they do reassert their claims. As a result of the sale, certain balance sheet accounts related to the Company's investment in Millstone 3 were adjusted at March 31, 2001. Listed below are the significant adjustments recorded.
Increase (Decrease) (In thousands) Utility plant $(679,345) Construction work in process $ (6,684) Nuclear fuel $ (10,974) Materials and supplies $ (6,107) Decommissioning $ (34,141) Accumulated provisions for depreciation $ 597,851 Regulatory assets - net book value and transaction costs $ 94,501
NSTAR Settlement On March 30, 2001, the Company reached a settlement in principal with NSTAR, formerly known as Boston Edison Company (BECO), resolving issues surrounding a $3 million refund to Montaup ordered by the FERC in January 2000. The order stemmed from an earlier proceeding initiated by the FERC where it required BECO to reduce its ROE under a life of unit purchased power agreement (PPA) with Montaup for 11 percent of the output from the Pilgrim plant. BECO subsequently divested its ownership in the Pilgrim plant in July 1999, and Montaup terminated its life of unit PPA in favor of a PPA that expires in 2004. BECO appealed the FERC Order to the First Circuit which, in turn, has remanded the case to the FERC for further proceedings. Proceeds from the refund have already been credited to customers through Montaup's CTC reconciliation mechanism. Under the terms of the settlement, the Company will return to BECO 75 percent of the refund amount, plus interest through March 31, 2001. The settlement is conditioned on consent from the parties to Montaup's restructuring settlement to recover this amount from customers through the CTC. Wyman 4 Settlement On April 23, 2001, Central Maine Power (CMP) and the Wyman 4 minority owners reached a settlement under which CMP will pay a total of $12 million to the minority owners. The Company's pro rata share of the settlement proceeds will be $2.9 million. The proceeds of the settlement, less legal costs, will be returned to customers via the CTC. The settlement is the result of arbitration brought by the Company and others against CMP regarding the sharing of CMP's proceeds from its sale of the Wyman 4 unit and site in Yarmouth, Maine in 1999. The Company is a 9 percent minority owner of the Wyman 4 generating unit. Risk Management The Company's major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt. At March 31, 2001, the Company's tax exempt variable rate long-term debt had a carrying value and fair value of approximately $410 million. While the ultimate maturity dates of the underlying loan agreements range from 2015 through 2022, this debt is issued in tax exempt commercial paper mode. The various components that comprise this debt are issued for periods ranging from one day to 270 days, and are remarketed through remarketing agents at the conclusion of each period. The weighted average variable interest rate for the year ended March 31, 2001, was approximately 3.4 percent. As discussed in the "Regulatory Environment" section, the Company remains obligated to provide transition power supply service to new customer load in Rhode Island at the standard offer price, but does not have a regulatory agreement that allows full recovery of the costs of such standard offer power. The Company meets this obligation through a combination of generation from some of its remaining generation sources, as well as by periodically procuring power at market prices. Over time, the Company cannot predict whether the resulting revenues will be sufficient to cover the costs of procuring such power. For the year ended March 31, 2001, the Company's losses from this obligation were approximately $5 million. Utility Plant Expenditures and Financing Cash expenditures for the Company for utility plant totaled $57 million for the twelve months ended March 31, 2001 and were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds. Cash expenditures for fiscal year 2002 are estimated to be approximately $45 million, principally related to transmission functions. Internally generated funds are expected to fully cover capital expenditures in fiscal year 2002. In September 2000, the Company repurchased 961 shares of its 6 percent $100 par value preferred stock for $79,766. Approximately $17,000 of this transaction was credited to retained earnings. In October 2000, the Company repurchased 350 shares of its 6 percent $100 par value preferred stock for $30,455. Approximately $4,000 of this transaction was credited to retained earnings. In February 1999, the Company repurchased 130,000 shares of its common stock from NEES for $18 million. Approximately $7 million of the repurchase price was charged to retained earnings. Dividends payable at March 31, 2000, in the amount of $256 million were paid on June 27, 2000. The Company has regulatory approval to issue up to $375 million of short-term debt. In October 2000, the Company received the necessary regulatory approvals to allow approximately $39 million of variable rate debt to remain outstanding through 2015. This results in classifying that debt as long-term rather than short-term. At March 31, 2001, the Company had lines of credit and standby bond purchase facilities with banks totaling $456 million which are available to provide liquidity support for $410 million of the Company's long-term bonds in tax-exempt commercial paper mode, and for other corporate purposes. There were no borrowings under these lines of credit at March 31, 2001.
New England Power Company Statements of Income Year ended 3 Months ended Year ended March 31, March 31, December 31, (In thousands) 2001 2000 1999 1999 1998 (unaudited) - ------------------------------------------------------------------------------------------ Operating revenue, principally from affiliates $656,272 $134,564 $167,177 $596,341 $1,218,340 Operating expenses: Fuel for generation 14,342 3,548 3,058 12,803 223,828 Purchased electric energy: Contract termination and nuclear unit shutdown charges 214,948 47,405 46,873 187,777 97,469 Other 91,844 14,682 11,111 56,731 302,367 Other operation 69,624 15,760 19,210 70,936 155,065 Maintenance 31,748 4,320 5,766 28,536 60,239 Depreciation and amortization 78,762 16,962 40,367 103,080 99,924 Taxes, other than income taxes 22,343 5,561 5,634 20,282 48,492 Income taxes 44,946 9,641 13,100 37,633 73,594 -------- -------- -------- -------- ---------- Total operating expenses 568,557 117,879 145,119 517,778 1,060,978 -------- -------- -------- -------- ---------- Operating income 87,715 16,685 22,058 78,563 157,362 Other income: Allowance for equity funds used during construction 276 (393) 588 1,958 633 Equity in income of nuclear power companies 6,703 862 515 2,939 5,284 Amortization of goodwill (17,905) (366) - - - Other income (expense), net 3,559 1,850 434 2,087 118 -------- -------- -------- -------- ---------- Operating and other income 80,348 18,638 23,595 85,547 163,397 -------- -------- -------- -------- ---------- Interest: Interest on long-term debt 17,834 3,749 3,143 14,052 30,775 Other interest 4,883 853 240 1,003 10,688 Allowance for borrowed funds used during construction (669) (426) (133) (522) (961) -------- -------- -------- -------- ---------- Total interest 22,048 4,176 3,250 14,533 40,502 -------- -------- -------- -------- ---------- Net income $ 58,300 $ 14,462 $ 20,345 $ 71,014 $ 122,895 ======== ======== ======== ======== ========== Statements of Retained Earnings Year ended 3 Months ended Year ended March 31, March 31, December 31, (In thousands) 2001 2000 1999 1999 1998 (unaudited) - ------------------------------------------------------------------------------------------- Retained earnings at beginning of period $ 1,415 $ 27,287 $204,603 $ 204,603 $ 407,630 Net income 58,300 14,462 20,345 71,014 122,895 Dividends declared on cumulative preferred stock (91) (24) (24) (94) (1,230) Dividends declared on common stock, $-0-, $6.66, $-0-, $66.69, and $20.25, per share, respectively - (24,098) - (241,415) (130,610) Gain on redemption of preferred stock 21 - - 264 (264) Repurchase of common stock - - (7,085) (7,085) (193,818) Purchase accounting adjustment - (16,212) - - - Acquisition adjustment 465 - - - - ------- -------- -------- --------- --------- Retained earnings at end of period $60,110 $ 1,415 $217,839 $ 27,287 $ 204,603 ======= ======== ======== ========= ========= The accompanying notes are an integral part of these financial statements.
New England Power Company Balance Sheets At March 31, At March 31, (In thousands) 2001 2000 - ------------------------------------------------------------------------------------- Assets Utility plant, at original cost $ 846,935 $1,318,026 Less accumulated provisions for depreciation and amortization 320,238 854,309 ---------- ---------- 526,697 463,717 Construction work in progress 34,946 35,730 ---------- ---------- Net utility plant 561,643 499,447 ---------- ---------- Goodwill, net of amortization 338,188 333,771 Investments: Nuclear power companies, at equity (Note D-1) 46,474 45,966 Decommissioning trust funds (Note D-2) 16,331 36,279 Nonutility property and other investments 14,374 7,490 ---------- ---------- Total investments 77,179 89,735 ---------- ---------- Current assets: Cash and temporary cash investments (including $22,075 and $37,820 with affiliates) 22,360 226,921 Accounts receivable: Affiliated companies 61,191 72,780 Others 89,483 48,139 Fuel, materials, and supplies, at average cost 6,289 10,345 Prepaid and other current assets 2,051 25,377 Regulatory assets - purchased power obligations and accrued Yankee nuclear plant costs 158,578 82,698 ---------- ---------- Total current assets 339,952 466,260 ---------- ---------- Regulatory assets (Note C) 1,522,089 1,203,090 Deferred charges and other assets 50,170 37,271 ---------- ---------- $2,889,221 $2,629,574 ========== ========== Capitalization and Liabilities Capitalization: Common stock, par value $20 per share, Authorized - 6,449,896 shares Outstanding - 3,619,896 shares $ 72,398 $ 72,398 Other paid-in capital (Note J) 731,974 582,983 Retained earnings 60,110 1,415 Unrealized gain (loss) on securities, net (145) - ---------- ---------- Total common equity 864,337 656,796 Cumulative preferred stock, par value $100 per share (Note H) 1,436 1,567 Long-term debt 410,279 371,773 ---------- ---------- Total capitalization 1,276,052 1,030,136 ---------- ---------- Current liabilities: Short-term debt - 38,500 Accounts payable (including $25,287 and $26,993 to affiliates) 66,017 51,584 Accrued liabilities: Taxes 39,451 2,394 Interest 1,489 1,900 Purchased power obligations and accrued Yankee nuclear plant costs 158,578 82,698 Other accrued expenses (Note G) 7,621 10,879 Dividends payable 22 256,487 ---------- ---------- Total current liabilities 273,178 444,442 ---------- ---------- Deferred federal and state income taxes 272,304 176,351 Unamortized investment tax credits 9,312 16,733 Accrued Yankee nuclear plant costs (Note D-2) 172,340 261,145 Purchased power obligations 636,848 611,802 Other reserves and deferred credits 249,187 88,965 Commitments and contingencies (Note D) ---------- ---------- $2,889,221 $2,629,574 ========== ========== The accompanying notes are an integral part of these financial statements.
New England Power Company Statements of Cash Flows Year ended 3 Months ended Year ended
March 31, March 31, December 31, (In thousands) 2001 2000 1999 1999 1998 (unaudited) - ----------------------------------------------------------------------------------------- Operating activities: Net income $ 58,300 $ 14,462 $ 20,345 $ 71,014 $ 122,895 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 85,123 18,799 42,170 108,789 104,331 Amortization of goodwill 17,905 366 - - - Deferred income taxes and investment tax credits, net (11,480) (2,908) 5,726 14,111 (226,722) Allowance for funds used during construction (945) (33) (720) (2,480) (1,594) Reimbursement to New England Energy Incorporated of loss on sale of oil and gas properties - - - - (120,900) Buyout of purchased power contracts - - - (3,472) (326,590) Changes in assets and liabilities, net of effects of acquisition: Decrease (increase) in accounts receivable, net (7,914) (3,174) 37,890 22,706 130,914 Decrease (increase) in fuel, materials, and supplies 4,160 (874) 648 (251) (10,270) Decrease (increase) in regulatory assets 152,533 60,044 82,801 166,730 (1,071,524) Decrease (increase) in prepaid and other current assets 26,501 13,938 6,154 (17,746) (8,778) Increase (decrease) in accounts payable (813) (11,628) (81,950) (99,148) (31,761) Increase (decrease) in purchased power contract obligations (77,039) (16,947) (36,903) (128,931) 832,668 Increase (decrease) in other current liabilities 30,822 (7,787) (11,147) (14,575) 5,037 Increase (decrease) in other non-current liabilities (147,847) 20,349 (5,661) 45,483 (108,896) Other, net 73,202 (49,869) (40,946) (87,277) 298,141 --------- -------- -------- --------- ----------- Net cash provided by (used in) operating activities $ 202,508 $ 34,738 $ 18,407 $ 74,953 $ (413,049) --------- -------- -------- --------- ----------- Investing activities: Proceeds from sale of generating assets $ - $ - $ - $ - $ 1,688,863 Plant expenditures, excluding allowance for funds used during construction (56,558) (11,890) (13,739) (56,887) (64,446) Other investing activities (3,270) (271) (20) (4,411) (5,474) --------- -------- -------- --------- ----------- Net cash provided by (used in) investing activities $ (59,828) $(12,161) $(13,759) $ (61,298) $ 1,618,943 --------- -------- -------- --------- ----------- Financing activities: Capital contribution from parent $ - $ - $ - $ - $ 34,881 Dividends paid on common stock (256,463) - - (9,050) (166,084) Dividends paid on preferred stock (93) - (24) (118) (1,206) Changes in short-term debt (38,500) - - 38,500 (111,250) Long-term debt - issues 38,500 - - - - Long-term debt - retirements (90,575) - - - (328,000) Repurchase of common shares - - (18,056) (18,056) (417,960) Preferred stock - retirements (110) - - - (38,505) --------- -------- -------- --------- ----------- Net cash provided by (used in) financing activities $(347,241) $ - $(18,080) $ 11,276 $(1,028,124) --------- -------- -------- --------- ----------- Net increase (decrease) in cash and cash equivalents $(204,561) $ 22,577 $(13,432) $ 24,931 $ 177,770 Cash and cash equivalents at beginning of period 226,921 204,344 179,413 179,413 1,643 --------- -------- -------- --------- ----------- Cash and cash equivalents at end of period $ 22,360 $226,921 $165,981 $ 204,344 $ 179,413 ========= ======== ======== ========= =========== Supplementary Information: Interest paid less amounts capitalized $ 18,296 $ 5,322 $ 2,042 $ 11,849 $ 43,419 --------- -------- -------- --------- ----------- Federal and state income taxes paid (refunded) $ (3,233) $ (15) $ 11,321 $ 55,134 $ 282,076 --------- -------- -------- --------- ----------- Dividends received from investments at equity $ 13,986 $ 1,129 $ 1,730 $ 5,243 $ 6,571 --------- -------- -------- --------- ----------- The accompanying notes are an integral part of these financial statements.
New England Power Company Notes to Financial Statements Note A - Significant Accounting Policies 1. Nature of Operations: New England Power Company (the Company), a wholly owned subsidiary of National Grid USA (formerly New England Electric System (NEES)), is a Massachusetts corporation qualified to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine, and Vermont. The Company is subject, for certain purposes, to the jurisdiction of the regulatory commissions of all these states (except Connecticut), the Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935 (1935 Act), the Federal Energy Regulatory Commission (FERC), and the Nuclear Regulatory Commission (NRC). The Company's business is primarily the transmission of electric energy in wholesale quantities to other electric utilities, principally its distribution affiliates Granite State Electric Company, Massachusetts Electric Company, Nantucket Electric Company, and The Narragansett Electric Company. The Company's transmission facilities are part of National Grid USA's transmission operations, which are represented under the name National Grid Transmission USA. In addition, the Company also owns a minority interest in one joint owned nuclear generating unit and one fossil fuel generating unit, as well as minority equity interests in four nuclear generating companies, three of which own generating facilities that are permanently shut down. The output from these generating facilities is sold to third parties and used to serve the Company's load obligation. 2. System of Accounts and Financial Statement Presentation: The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by regulatory bodies having jurisdiction. National Grid USA and its subsidiaries changed their fiscal year from a calendar year ending December 31 to a fiscal year ending March 31. National Grid USA and its subsidiaries made this change in order to align their fiscal years with that of National Grid Group plc (National Grid)(see Note B). The Company's first new full fiscal year began on April 1, 2000 and ended on March 31, 2001. The accompanying financial information as of March 31, 2001 and 2000, and for the twelve months ended March 31, 2001, reflects the new basis of accounting established for the Company's assets and liabilities in connection with the acquisition of National Grid USA by National Grid on March 22, 2000. The audited results of operations for the three month period ended March 31, 2000 includes an immaterial amount of goodwill amortization for the ten day period from March 22 to March 31, 2000. Due to the immateriality of this effect, this transitional period has not been separated into the period preceding and the period following the pushdown of goodwill. In preparing the financial statements, management is required to make estimates that affect the reported amounts of assets and liabilities and disclosures of asset recovery and contingent liabilities as of the date of the balance sheets, and revenues and expenses for the period. These estimates may differ from actual amounts if future circumstances cause a change in the assumptions used to calculate these estimates. In addition, certain presentation adjustments have been made to conform prior years with the 2001 presentation. 3. Allowance for Funds Used During Construction (AFDC): The Company capitalizes AFDC as part of construction costs. AFDC represents the composite interest and equity costs of capital funds used to finance that portion of construction costs not yet eligible for inclusion in rate base. AFDC is capitalized in "Utility plant" with offsetting noncash credits to "Other income" and "Interest." This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFDC rates were 3.2 percent for the year ended March 31, 2001, 3.7 percent for the three month period ended March 31, 2000, 8.1 percent for the three month period ended March 31, 1999, and 7.6 percent and 6.1 percent for the years ended December 31, 1999 and 1998, respectively. 4. Depreciation and Amortization: The depreciation and amortization expense included in the statements of income is composed of the following:
Three Months Year Ended Ended Year Ended March 31, March 31, December 31, (In thousands) 2001 2000 1999 1999 1998 (unaudited) - --------------------------------------------------------------------------------- Depreciation - transmission related $15,055 $ 3,269 $ 3,440 $ 13,222 $12,553 Depreciation - all other 5,477 (15) 354 1,286 46,256 Nuclear decommissioning costs (Note D-2) 9,901 923 699 3,637 2,719 Amortization: Millstone 3 additional amortization, pursuant to 1995 rate settlement - - - - 22,040 Regulatory assets covered by contract termination charges (Note C) 48,329 12,785 35,874 84,935 16,356 ------- ------- -------- ------- ------- Total depreciation and amortization expense $78,762 $16,962 $40,367 $103,080 $99,924 ======= ======= ======= ======== =======
Depreciation is provided annually on a straight-line basis. The provision for depreciation as a percentage of weighted average depreciable transmission property was 2.3 percent for all periods presented. Amortization of Millstone investments above normal depreciation accruals and amortization of regulatory assets covered by contract termination charges (CTC) was in accordance with rate settlement agreements. 5. Cash: The Company classifies short-term investments with a maturity at purchase date of 90 days or less as cash. 6. Property, Plant, and Equipment: The Company's integrated system of transmission property consists of approximately 2,800 circuit miles of transmission lines and 116 substations. 7. Income Taxes: Income taxes have been computed utilizing the asset and liability approach which requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. 8. New Accounting Standards: In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133). FAS 133 requires that an entity recognize all derivative instruments as either assets or liabilities in the statement of financial position and the measure of those instruments at fair value. In June 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date," which amends FAS 133 to be effective for all fiscal quarters of fiscal years beginning after June 15, 2000. FAS 133 was subsequently amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." The Company expects the adoption of the new standard during fiscal 2002 will not have a material impact on its financial position or results of operations. In September 1999, the FASB issued an exposure draft of a proposed SFAS titled "Business Combinations and Intangible Assets - Accounting for Goodwill." A limited revision of the draft was issued on February 14, 2001. The proposed SFAS would continue recognition of goodwill as an asset but would not permit amortization as currently required by Accounting Principles Board Opinion No. 17, "Intangible Assets." In addition, goodwill would be tested periodically for impairment when events and circumstances occur indicating that it might be impaired. The proposed SFAS would be effective for fiscal years beginning after December 15, 2001. Early adoption would be permitted for companies with a fiscal year beginning after March 15, 2001. Currently, the Company is unable to determine the potential impact of the proposed accounting standard on its financial position or results of operations. Note B - Mergers and Acquisitions Merger with National Grid On March 22, 2000, the merger of NEES and National Grid was completed, with NEES (renamed National Grid USA) becoming a wholly owned subsidiary of National Grid. The Company maintained its existing name and remained a wholly owned subsidiary of National Grid USA. The merger was accounted for by the purchase method, the application of which, including the recognition of goodwill, was pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including the Company. Total goodwill amounted to $1.7 billion, of which the Company was allocated approximately $348 million. This amount was determined pursuant to a study conducted by an independent third party and is being amortized over 20 years. Amortization expense is approximately $17.4 million annually. The purchase accounting method requires revaluation of assets and liabilities to their fair value. This revaluation resulted in an adjustment to the Company's pension and postretirement benefit accounts in the amount of approximately $61 million, with an offsetting net credit to a regulatory liability account (see Note E). Acquisition of EUA The acquisition of Eastern Utilities Associates (EUA) by National Grid USA was completed on April 19, 2000 for $642 million. On May 1, 2000, Montaup Electric Company (Montaup), formerly a subsidiary of EUA, was merged into the Company. The acquisition of EUA was accounted for by the purchase method, the application of which, including the recognition of goodwill, has been pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including the Company. Total goodwill amounted to approximately $402 million, of which the Company was allocated approximately $8 million. This amount was determined pursuant to a study conducted by an independent third party and is being amortized over 20 years. Amortization expense is approximately $0.4 million annually. The purchase accounting method requires revaluation of assets and liabilities to their fair value. This revaluation resulted in an adjustment to the Company's pension and postretirement benefit accounts in the amount of approximately $3 million, with an offsetting net credit to a regulatory liability account (see Note E). As a result of the acquisition, Montaup's balance sheet accounts were incorporated into the financial statements of the Company as of May 1, 2000. Listed below are the significant account balances incorporated.
May 1, 2000 balance (In thousands) Assets Utility plant, at original cost $227,114 Accumulated provisions for depreciation and amortization $(92,093) Regulatory assets (current and long-term) $547,412 Liabilities Other paid-in capital $135,444 Deferred federal and state income taxes $104,860 Accrued Yankee nuclear plant costs $ 46,030 Purchased power obligations (current and long-term) $176,257 Other reserves and deferred credits $174,942
The accompanying statements of operations do not include any revenues or expenses related to Montaup prior to the companies' merger on May 1, 2000. Note C - Regulatory Environment and Accounting Implications Under settlement agreements, the Company is permitted to recover costs associated with its former generating investments and related contractual commitments that were not recovered through the sale of those investments (stranded costs). These costs are recovered from the Company's wholesale customers with which it has settlement agreements through CTCs. The Company's retail distribution affiliates recover CTC- related costs through delivery charges to distribution customers. The recovery of the Company's stranded costs (including the Montaup share) is divided into several categories. The Company's unrecovered costs associated with generating plants (nuclear and nonnuclear) and most regulatory assets were fully recovered through the CTC by the end of 2000 and earned a return on equity (ROE) averaging 9.7 percent. The Montaup share of unrecovered costs associated with generating plants and most regulatory assets will be fully recovered through the CTC by the end of 2009. The Company's obligation related to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC as such costs are actually incurred. As the CTC rate declines, the Company, under certain of the settlement agreements, earns incentives based on successful mitigation of its stranded costs. These incentives supplement the Company's ROE. Until such time as the Company divests its operating nuclear interests, 80 percent of the revenues and operating costs related to the units will be allocated to customers through the CTC, with shareholders being allocated the balance. In conjunction with the divestiture, the Company transferred to the buyer of its nonnuclear generating business (the buyer) its entitlement to power procured under several long-term contracts in exchange for monthly fixed payments by the Company. Similar to the Company, Montaup also transferred its purchased power obligations as part of the divestiture and in return agreed to make fixed monthly payments. The aggregate fixed monthly payments, including the Montaup share, average $11.3 million per month through December 2009 toward the above-market cost of those contracts. The liability relating to purchased power obligations, which is also reflected in regulatory assets, represents the net present value of these fixed monthly payments. At March 31, 2001, the net present value is approximately $786 million. For certain contracts which have been formally assigned to the buyer, the Company has made lump sum payments equivalent to the present value of the monthly fixed payment obligations of those contracts (approximately $453 million), which were separate from the $786 million figure referred to above. Prior to divesting substantially all of its nonnuclear generation business in 1998, the Company was the wholesale supplier of the electric energy requirements to its retail distribution affiliates as well as unaffiliated customers. The Company's all-requirements contracts with its affiliated distribution companies, as well as with some unaffiliated customers, were generally terminated pursuant to settlement agreements and tariff provisions in 1998. However, the Company remains obligated to provide transition power supply service to new customer load in Rhode Island at the standard offer price, but does not have a regulatory agreement that necessarily allows full recovery of the costs of such standard offer power. Consequently, the Company is at risk for the difference between the actual cost of serving this load and the revenue received from this obligation. The standard offer rate that the Company charges for continuing to meet this obligation increased from 3.5 cents per kilowatthour (kWh) in 1999 to 3.8 cents per kWh effective January 1, 2000. The standard offer rate is also subject to a rolling twelve-month fuel index adjustment factor, which increased the rate by an additional 0.121 cents per kWh beginning in April 2000 up to 2.404 cents per kWh by March 2001. The Company meets this obligation through a combination of generation from some of its remaining generation sources, as well as by periodically procuring power at market prices. Over time, the Company cannot predict whether the resulting revenues will be sufficient to cover the costs of procuring such power. For the year ended March 31, 2001, the Company's losses from this obligation were approximately $5 million. In a December 15, 2000 Order, the FERC rejected the Independent System Operator's (ISO New England) proposed $0.17 per kW-month Installed Capacity (ICAP) deficiency charge and reinstated an administratively- determined deficiency charge of $8.75 per kW-month, retroactive to August 1, 2000. Several parties, including the Company, filed motions requesting rehearing and stay of the FERC's order. On January 10, 2001, the FERC granted these motions. On March 6, 2001, the FERC reversed its earlier order by allowing ISO New England's previously proposed ICAP rate of $0.17 per kW-month to be effective from August 1, 2000 through March 31, 2001. Effective April 1, 2001, the FERC ordered an ICAP rate of $8.75 per kW-month. On March 16, 2001, National Grid and others filed a motion to stay the FERC Order with the United States Court of Appeals for the First Circuit (First Circuit). The First Circuit stayed the ICAP rate of $8.75 per kW-month on March 30, 2001. On June 4, 2001, ISO New England made a filing to comply with the March FERC order that proposed a maximum charge of $4.87 per kW-month. On June 8, 2001, the First Circuit, ruling on the merits of the appeal to the FERC's orders imposing the $8.75 per kW-month charge, remanded the case to the FERC for further consideration. The First Circuit order allows the FERC to reinstate its initial order on a prospective basis, but asks the FERC to answer several questions to support its order. National Grid and others have asked the FERC to consider the June 4th ISO filing while it is reconsidering its initial order on remand. At this time, the Company cannot predict how ICAP charges will affect its forward looking power supply costs. National Grid USA presented to the FERC in January 2001 a joint proposal, with ISO New England and other utilities in New England, for a Regional Transmission Organization (RTO) in the northeastern US. The RTO would consist of an ISO with responsibility for administering a competitive wholesale market in electricity and an Independent Transmission Company offering transmission services and undertaking transmission network development and the provision of connections for new generation. The proposal responds to the FERC's objective set out in "Order 2000", of separating transmission operations from market participation and would give the Independent Transmission Company, of which National Grid USA would be a member, the opportunity to propose financial incentives to deliver greater value for customers and shareholders. The proposal is subject to FERC approval and the ability of the utility group to reach agreement on a number of additional issues. Because electric utility rates have historically been based on a utility's costs, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. The Company applies the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS 71), which requires regulated entities, in appropriate circumstances, to establish regulatory assets or liabilities, and thereby defer the income statement impact of certain charges or revenues because they are expected to be collected or refunded through future customer billings. In 1997, the Emerging Issues Task Force of the FASB concluded that a utility that had received approval to recover stranded costs through regulated rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs. The Company has received authorization from the FERC to recover through CTCs substantially all of the costs associated with its former generating business not recovered through the divestiture. Additionally, FERC Order No. 888 enables transmission companies to recover their specific costs of providing transmission service. Therefore, substantially all of the Company's business, including the recovery of its stranded costs, remains under cost-based rate regulation. Because of the nuclear cost-sharing provisions related to the Company's CTC, the Company ceased applying FAS 71 in 1997 to 20 percent of its ongoing nuclear operations, the impact of which is immaterial. As a result of applying FAS 71, the Company has recorded a regulatory asset for the costs that are recoverable from customers through the CTC. At March 31, 2001, this amounted to approximately $1.7 billion, including $1.1 billion related to the above-market costs of purchased power contracts, $0.2 billion related to accrued Yankee nuclear plant costs, and $0.4 billion related to other net CTC regulatory assets. Note D - Commitments and Contingencies 1. Yankee Nuclear Power Companies The Company has minority interests in four Yankee Nuclear Power Companies (Yankees). These ownership interests are accounted for on the equity method. The Company's share of the expenses of the Yankees is accounted for in "Purchased electric energy" on the income statement. A summary of combined results of operations, assets, and liabilities of the four Yankees is as follows:
Year Ended Three Months Ended Year Ended March 31, March 31, December 31, (In thousands) 2001 2000 1999 1999 1998 (unaudited) - ---------------------------------------------------------------------------------------- Operating revenue $ 291,628 $ 81,225 $ 89,244 $ 377,039 $ 439,046 =========== =========== =========== =========== =========== Net income $ 29,589 $ 5,310 $ 5,138 $ 13,890 $ 23,218 =========== =========== =========== =========== =========== Company's equity in net income $ 6,703 $ 862 $ 515 $ 2,939 $ 5,284 =========== =========== =========== =========== =========== Net plant 160,701 167,317 166,062 172,100 171,582 Other assets 1,893,733 2,520,887 2,798,948 2,631,750 2,810,613 Liabilities and debt (1,855,775) (2,437,609) (2,707,749) (2,554,261) (2,723,454) ----------- ----------- ----------- ----------- ----------- Net assets $ 198,659 $ 250,595 $ 257,261 $ 249,589 $ 258,741 =========== =========== =========== =========== =========== Company's equity in net assets $ 46,474 $ 45,966 $ 47,323 $ 46,233 $ 48,538 =========== =========== =========== =========== =========== Company's purchased electric energy: Vermont Yankee $ 31,899 $ 7,761 $ 7,874 $ 37,551 $ 35,108 All other Yankees $ 21,616 $ 9,324 $ 9,370 $ 37,765 $ 48,543 =========== =========== =========== =========== ===========
At March 31, 2001, approximately $7 million of undistributed earnings of the nuclear power companies were included in the Company's retained earnings. 2. Nuclear Units Nuclear Units Permanently Shut Down Three of the Yankees in which the Company has a minority interest own nuclear generating units that have been permanently shut down. These three units are as follows:
Future The Company's Estimated Investment Billings to as of 3/31/01 Date the Company Unit % $(millions) Retired $(millions) - ----------------------------------------------------------------- Yankee Atomic 34.5 2 Feb 1992 0 Connecticut Yankee 19.5 15 Dec 1996 50 Maine Yankee 24.0 17 Aug 1997 129
In the case of each of these units, the Company has recorded a liability and a regulatory asset reflecting the estimated future billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant, including a return on that investment, as well as unfunded nuclear decommissioning costs and other costs. Maine Yankee and Connecticut Yankee recover their costs, including a return, in accordance with settlement agreements approved by the FERC in May 1999 and July 2000, respectively. Prospectively, under the FERC settlement agreement, Connecticut Yankee agreed to reduce annual collections for decommissioning through the use of its pre-1983 spent fuel trust funds and to limit its ROE to 6 percent. In addition, Connecticut Yankee, Yankee Atomic, and Maine Yankee continue to pursue litigation against the Department of Energy (DOE) to assume financial responsibility for storage of spent nuclear fuel. Under rate provisions approved by the FERC for Connecticut Yankee and Yankee Atomic, any recovery from the DOE proceedings after litigation expenses and taxes will be returned to customers. 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. Maine Yankee had hired Stone & Webster, Inc. (S&W), an engineering, construction, and consulting company, as the principal contractor to decommission the unit. In May 2000, Maine Yankee terminated its long-term contract with S&W and negotiated an arrangement with S&W to continue work through June 2000. In June 2000, S&W filed for Chapter 11 bankruptcy protection. Subsequently, Maine Yankee decided to self-manage the unit's decommissioning process. In June 2000, Federal Insurance Company (Federal) filed a complaint in S&W's bankruptcy proceeding which alleges that Maine Yankee improperly terminated its contract with S&W. If the court were to make such a finding, Federal would be excused from a $37 million performance bond liability to Maine Yankee. Federal's complaint has been removed to the US Federal District Court in Maine for jury trial. In August 2000, Maine Yankee filed a $78.2 million (later increased to $86 million) damage claim against S&W in the bankruptcy proceeding. At this time, the Company is unable to determine the potential impact, if any, of these developments. Under the provisions of the Company's industry restructuring settlement agreements approved by state and federal regulators in 1998, the Company recovers all costs, including shutdown costs, that the FERC allows these Yankee companies to bill to the Company. Operating Nuclear Units The Company currently has minority interests in two operating nuclear generating units that the Company is engaged in efforts to divest: Vermont Yankee and Seabrook 1. In addition, the Company sold its 16.2 percent interest in Millstone 3 to Dominion Resources, Inc. (Dominion) on March 31, 2001. Until such time as the Company divests its operating nuclear interests, 80 percent of the revenues and operating costs related to the units will be allocated to customers through the CTC, with shareholders being allocated the balance. Vermont Yankee The following table summarizes the Company's interest in the Vermont Yankee Nuclear Power Corporation as of March 31, 2001:
The Company's Interest (millions of dollars) ---------------------------------------------- Equity Net Estimated Decommissioning Ownership Equity Plant Decommissioning Fund License Interest (%) Investment Assets Cost (in 2000 $) Balance Expiration ------------- ---------------------------------------------------------------- 22.5 $12 $36 $102 $57 2012
In November 1999, the Vermont Yankee Nuclear Power Corporation entered into an agreement with AmerGen Energy Company (AmerGen), a joint venture between PECO Energy and British Energy, to sell the assets of Vermont Yankee. Several other parties, Including Entergy Corporation (Entergy), indicated to the Vermont Public Service Board (VPSB) that they were prepared to make an offer for Vermont Yankee. On February 14, 2001, the VPSB rejected Vermont Yankee's sale agreement with AmerGen and formally terminated the AmerGen proceeding on March 15, 2001. The VPSB also required Entergy to post a $26 million bond payable in the event that Entergy withdraws its offer. In addition, the VPSB stated that if the Entergy bond were redeemed, the proceeds would go exclusively to Vermont customers. The Vermont Yankee Board of Directors is presently considering its options with respect to that part of the order. On March 15, 2001, Vermont Yankee terminated its agreement with AmerGen. After considering the pros and cons of shutting the plant down, continuing to operate it, or sell it, Vermont Yankee decided to proceed with a formal auction of the plant. The auction was officially launched on April 16, 2001. The Company expects that the winning bidder of the plant will be named in the fall of 2001. Any sale of the plant is contingent upon the receipt of regulatory approvals by the SEC, under the 1935 Act, the FERC, the NRC, the VPSB, and other state regulatory commissions with jurisdiction over other equity owners of Vermont Yankee. Under the terms of the original AmerGen agreement, the existing power purchasers (including the Company) were required to continue to purchase the output of the plant or to buy out of the purchased power obligation. In November 1999, the Company signed an agreement to buy out of its obligation, requiring future payments which would be recovered through the Company's CTC. At that time, the Company recorded a liability and offsetting regulatory asset of $80 million for its share of future liabilities related to Vermont Yankee, including the purchased power contract termination payment obligation, but excluding interest and a return allowance. With Vermont Yankee's termination of the agreement with AmerGen in March 2001, the Company was relieved of this obligation and accordingly reversed the liability and offsetting regulatory asset of $80 million. To date, the Company has not determined if it will enter into a purchased power agreement with a proposed new owner of Vermont Yankee. Seabrook 1 The following table summarizes the Company's interest in the Seabrook 1 nuclear generating unit as of March 31, 2001;
The Company's share of (millions of dollars) --------------------------------------------- The Company's Net Estimated Decommissioning Ownership Plant Decommissioning Fund License Interest (%) Assets Cost (in 2000 $) Balances* Expiration - ------------------------------------------------------------------------------------- 10 $17** $61 $16 2026 *Certain additional amounts are anticipated to be available through tax deductions. **Represents post-December 1995 spending including nuclear fuel.
As part of its restructuring settlement with the State of New Hampshire, Public Service Company of New Hampshire (PSNH), through its affiliate, North Atlantic Energy Corporation (NAEC), committed to seek New Hampshire Public Utilities Commission (NHPUC) approval of a definitive plan to sell, via public auction administered by the NHPUC, its share of Seabrook 1, with such sale to occur no later than December 31, 2003. NAEC owns the largest percentage of the plant with a 35.98 percent interest, and its affiliate, North Atlantic Energy Service Corporation, is the plant operator. As part of its settlement, PSNH has also agreed to make all reasonable efforts to bundle its interests with those of other owners (including the Company) seeking to sell their interests so that a controlling interest may be offered in the auction. In December 2000, Northeast Utilities (NU) filed its divestiture plan before the NHPUC, requesting an expeditious process in order to permit a prompt sale of the plant. Under the terms of the PSNH Settlement and enabling legislation, the NHPUC will administer the sale of the plant with the assistance of an asset sale specialist. On April 12, 2001, the Company filed a Seabrook Divestiture Plan with the NHPUC as directed by its 1998 restructuring settlement agreement. Under the Divestiture Plan, the Company has indicated its interest in selling its share of Seabrook 1 and has requested that the NHPUC administer an auction on the Company's behalf under certain guidelines and conditions. On May 22, 2001, legislation was enacted in New Hampshire to provide New Hampshire residents additional protections against the restructuring problems encountered in California. Although the legislation includes provisions to delay the sale of PSNH fossil and hydro generation assets, it directs the NHPUC to expedite the auction of the Seabrook Station in a manner that benefits customers of all New Hampshire utilities, including the Company. Millstone 3 In November 1999, the Company entered into an agreement with NU and certain of NU's subsidiaries to settle claims made by the Company relative to the operation of Millstone 3. Among other things, the settlement provided for NU to include the Company's share of Millstone 3 in an auction of NU's share of the unit. Upon the closing of the sale, NU would pay the Company a total of $25 million, regardless of the actual sale price, with adjustments for certain capital and fuel procurement expenditures. The settlement also required NU to indemnify the Company and assume any residual liabilities resulting from the sale, including any requirements that the sellers continue to purchase output from the unit. In August 2000, Dominion agreed to purchase the Millstone units, including the Company's 16.2 percent interest in Millstone 3, for $1.3 billion in cash. In November 2000, the Rhode Island Attorney General and the Rhode Island Division of Public Utilities and Carriers filed a protest at the FERC contending that the payment the Company would receive from the sale of Millstone 3, as established by its agreement with NU, was insufficient. In December 2000, the Company and other parties to the Millstone sale submitted answers opposing Rhode Island's position and arguing, among other things, that Rhode Island's contention was well beyond the scope of the FERC proceeding. The Company further stated that concerns over the customer rate impact of the Company's agreement with NU would be more appropriately addressed under the terms of its restructuring settlements. On January 25, 2001, the FERC found that Rhode Island's objection was beyond the scope of the proceeding and approved the sale. On March 31, 2001, the Company completed the sale of its 16.2 percent interest in Millstone 3 for approximately $27.9 million. In addition, the Company paid approximately $5.8 million to increase the decommissioning trust fund to the level prescribed in its settlement agreement with NU. The amounts received pursuant to the sale will, after reimbursement of the Company's transaction costs and net investment in Millstone 3, be credited to customers. The Company cannot predict whether the Rhode Island regulators will reassert their claims in connection with the recovery of stranded costs or the financial consequences if they do reassert their claims. As a result of the sale, certain balance sheet accounts related to the Company's investment in Millstone 3 were adjusted at March 31, 2001. Listed below are the significant adjustments recorded.
Increase (Decrease) (In thousands) Utility plant $(679,345) Construction work in process $ (6,684) Nuclear fuel $ (10,974) Materials and supplies $ (6,107) Decommissioning $ (34,141) Accumulated provisions for depreciation $ 597,851 Regulatory assets - net book value and transaction costs $ 94,501
Nuclear Decommissioning The Company is liable for its share of decommissioning costs for Seabrook 1 and all of the Yankees. Decommissioning costs include not only estimated costs to decontaminate the units as required by the NRC, but also costs to dismantle the units. The Company records decommissioning costs on its books consistent with its rate recovery. The Company is recovering its share of projected decommissioning costs for Seabrook 1 through depreciation expense. In addition, the Company is paying its portion of projected decommissioning costs for Connecticut Yankee and Maine Yankee. The Company has completed its projected decommissioning obligation for Yankee Atomic. Such costs reflect estimates of total decommissioning costs approved by the FERC. In New Hampshire, legislation was enacted in 1998 that makes owners of Seabrook 1, in 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, there is a single owner of an approximate 15 percent share of Seabrook 1 that is subject to the legislation. The impact of this legislation to the Company is not considered material to its financial position or results of operation. The Company has been working to amend the current nuclear decommissioning statute to become effective upon the sale of Seabrook. Decommissioning legislation has passed in the New Hampshire legislature. This bill, initiated and supported by Seabrook's joint owners, including the Company and members of the New Hampshire Nuclear Decommissioning Financing Committee (NHNDFC), modifies New Hampshire's current decommissioning law and removes utility owners from the role of proportional guarantor for non- utility owners. The new legislation also seeks to protect customers from future decommissioning risks by requiring a buyer to provide funding assurance even in the event of a premature shutdown at the plant. The bill also enhances the potential sale price of Seabrook by allowing the buyer to retain any decommissioning funds in excess of those contributed by customers of the present utility owners and by reducing the standard set by the NHNDFC for non-radiological decommissioning. The Nuclear Waste Policy Act of 1982 establishes that the federal government (through the 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 Seabrook 1 nuclear generating unit. Prior to 1998, the Company recovered this fee through its fuel clause. Under settlement agreements, substantially all of these costs are recovered through CTCs. Similar costs are billed to the Company by Vermont Yankee and are also recovered from customers through CTCs. In 1997, ruling on a lawsuit brought against the DOE by numerous utilities and state regulatory commissions, the U.S. Court of Appeals for the District of Columbia held that the DOE was obligated to begin disposing of utilities' spent nuclear fuel by January 1998. The DOE failed to meet this deadline and is not expected to have a temporary or permanent repository for spent nuclear fuel before 2010, at the earliest. Many utilities, including Yankee Atomic, Connecticut Yankee, and Maine Yankee filed claims for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE's failure to begin to take fuel in 1998. As an interim measure until the DOE meets its contractual obligations to dispose of their spent fuel, those companies are proceeding with construction of independent spent fuel storage installations on the plant sites. Each nuclear unit in which the Company has an ownership interest has established a decommissioning trust fund or escrow fund into which payments are being made to meet the projected costs of decommissioning. There is no assurance that decommissioning costs actually incurred by Seabrook 1 or the Yankees will not substantially exceed the estimated amounts. For example, decommissioning cost estimates assume the availability of permanent repositories for both low-level and high-level nuclear waste; those repositories do not currently exist. The temporary low-level repository located in Barnwell, South Carolina may become unavailable, which could increase the cost of decommissioning the Yankee Atomic, Connecticut Yankee, and Maine Yankee plants. If any of the operating units were shut down prior to the end of their operating licenses, the funds collected for decommissioning to that point may be insufficient. Under settlement agreements, the Company will recover decommissioning costs through CTCs. Nuclear Insurance The Price-Anderson Act limits the amount of liability claims that would have to be paid in the event of a single incident at a nuclear plant to $9.5 billion (based upon 106 licensed reactors). The maximum amount of commercially available insurance coverage to pay such claims is $200 million. The remaining $9.3 billion would be provided by an assessment of up to $88.1 million per incident levied on each of the participating nuclear units in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. The maximum assessment, which was most recently adjusted in 1998, is adjusted for inflation at least every five years. The Company's current interest in Vermont Yankee and Seabrook 1 would subject the Company to a $28.6 million maximum assessment per incident. The Company's payment of any such assessment would be limited to a maximum of $3.2 million per year. As a result of the permanent cessation of power operation of the Yankee Atomic, Connecticut Yankee, and Maine Yankee plants, these units have received from the NRC an exemption from participating in the secondary financial protection system under the Price-Anderson Act. However, these plants must continue to maintain $100 million of commercially available nuclear liability insurance coverage. Each of the nuclear units in which the Company has either an ownership or purchased power interest also carries nuclear property insurance to cover the costs of property damage, decontamination, and premature decommissioning resulting from a nuclear incident. These policies may require additional premium assessments if losses relating to nuclear incidents at units covered by this insurance occur in a prior six-year period. The Company's maximum potential exposure for these assessments, either directly or indirectly, is approximately $3.0 million with respect to the current policy period. 3. Plant Expenditures The Company's utility plant expenditures are estimated to be approximately $45 million for fiscal year 2002. At March 31, 2001, substantial commitments had been made relative to future planned expenditures. 4. Hydro-Quebec Interconnection Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro-Quebec to New England. Under support agreements entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At March 31, 2001, the Company had guaranteed approximately $18 million of project debt with terms through 2015. The Company's rights and obligations under its support agreements were transferred to the purchaser of its nonnuclear generation. Also, as a result of the National Grid USA merger with EUA, at March 31, 2001, the Company had guaranteed an additional amount of approximately $4 million originally guaranteed by Montaup. The Company remains an obligor under the support agreements until 2020. Costs associated with these support agreements are recoverable through the CTCs. 5. 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. 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 several 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 Company has recovered amounts from certain insurers, and, where appropriate, 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. 6. Town of Norwood Dispute From 1983 until 1998, the Company was the wholesale power supplier for the town of Norwood, Massachusetts (Norwood). In April 1998, Norwood began taking power from another supplier. Pursuant to a tariff amendment approved by the FERC in May 1998, the Company has been assessing Norwood a CTC. Through March 2001, the charges assessed Norwood amount to approximately $29 million, all of which remain unpaid. The Company filed a collection action in Massachusetts Superior Court (Superior Court). The Superior Court deferred action until the various appeals described below were decided. On March 14, 2001, the Superior Court ordered Norwood to pay the Company $27 million including interest. Norwood was ordered to pay the judgement in monthly installments of $600,000. Norwood has also entered a consent order to establish a segregated account for the benefit of the Company in the amount of $14 million and to make regular additions to the account. Separately, Norwood filed suit in Federal District Court (District Court) in April 1997 alleging that the divestiture of the Company's nonnuclear generating business (the divestiture) violated the terms of the 1983 power contract and contravened antitrust laws. The District Court dismissed the lawsuit. On appeal, the First Circuit consolidated appeals Norwood made from FERC's orders approving the Company's divestiture, the wholesale rate settlement between the Company and its distribution affiliates, and the CTC tariff amendment. In February 2000, the First Circuit dismissed Norwood's appeal from the FERC orders and dismissed its appeal from all but one of Norwood's District Court claims, which relates to alleged generation market power. In February and March 2000, respectively, the First Circuit denied Norwood's petition for further review of its District Court claims decision and its decision on the FERC orders. In May 2000, Norwood petitioned the US Supreme Court for review of the First Circuit decisions. In October 2000, the US Supreme Court refused Norwood's petitions to review the First Circuit decisions affirming (a) the FERC's approval of the CTC, the divestiture, and the settlement agreements regarding termination of the Company's power sales agreements with its affiliates, and (b) the District Court's dismissal of Norwood's antitrust and breach of contract claims. In the District Court action, in April 2000, the Company renewed its motion to dismiss Norwood's remaining claim. Norwood amended its complaint to reassert a request for rescission of the divestiture, which it had earlier dropped. A hearing took place before the District Court in July 2000. Norwood has also appealed a June 1999 FERC decision that rejected Norwood's challenge to the calculation of the CTC based on the terms of the 1983 power contract, which Norwood contended ended in October 1998, not October 2008. In June 2000, the First Circuit rejected Norwood's appeal. Norwood filed a petition for certiorari to the US Supreme Court for review of the First Circuit's decision. On April 24, 2001, the US Supreme Court denied Norwood's petition. 7. Settlements NSTAR Settlement On March 30, 2001, the Company reached a settlement in principal with NSTAR, formerly known as Boston Edison Company (BECO), resolving issues surrounding a $3 million refund to Montaup ordered by the FERC in January 2000. The order stemmed from an earlier proceeding initiated by the FERC where it required BECO to reduce its ROE under a life of unit purchased power agreement (PPA) with Montaup for 11 percent of the output from the Pilgrim plant. BECO subsequently divested its ownership in the Pilgrim plant in July 1999, and Montaup terminated its life of unit PPA in favor of a PPA that expires in 2004. BECO appealed the FERC Order to the First Circuit which, in turn, has remanded the case to the FERC for further proceedings. Proceeds from the refund have already been credited to customers through Montaup's CTC reconciliation mechanism. Under the terms of the settlement, the Company will return to BECO 75 percent of the refund amount, plus interest through March 31, 2001. The settlement is conditioned on consent from the parties to Montaup's restructuring settlement to recover this amount from customers through the CTC. Wyman 4 Settlement On April 23, 2001, Central Maine Power (CMP) and the Wyman 4 minority owners reached a settlement under which CMP will pay a total of $12 million to the minority owners. The Company's pro rata share of the settlement proceeds will be $2.9 million. The proceeds of the settlement, less legal costs, will be returned to customers via the CTC. The settlement is the result of arbitration brought by the Company and others against CMP regarding the sharing of CMP's proceeds from its sale of the Wyman 4 unit and site in Yarmouth, Maine in 1999. The Company is a 9 percent minority owner of the Wyman 4 generating unit. Note E - Employee Benefits 1. Pension Plan: The Company participates with other subsidiaries of National Grid USA in a noncontributory, defined benefit plan covering substantially all employees of the Company. The plan provides pension benefits based on the employee's compensation during the five years prior to retirement. Absent unusual circumstances, the Company's funding policy is to contribute each year the net periodic pension cost for that year. However, the contribution for any year will not be less than the minimum contribution required by federal law or greater than the maximum tax deductible amount. Net pension cost for the year ended March 31, 2001, the three months ended March 31, 2000, and the years ended December 31, 1999 and 1998 included the following components:
Year Three Ended Months Ended Year Ended March 31, March 31, December 31, - ---------------------------------------------------------------------------------------- - - (thousands of dollars) 2001 2000 1999 1998 - ---------------------------------------------------------------------------------------- - - Service cost - benefits earned during the period $ 482 $ 118 $ 527 $ 2,430 Plus (less): Interest cost on projected benefit obligation 8,381 1,760 7,044 7,435 Return on plan assets at expected long-term rate (12,440) (2,200) (8,090) (8,675) Amortization of transition obligation - (33) (170) (184) Amortization of prior service cost - 24 115 161 Amortization of net (gain)/loss - (100) 36 159 Curtailment (gain)/loss - - - (5,680) - ---------------------------------------------------------------------------------------- - - Benefit cost/(income) $(3,577) $ (431) $ (538) $(4,354) - ---------------------------------------------------------------------------------------- - - Special termination benefits not included above $ - $ - $ - $10,911 - ---------------------------------------------------------------------------------------- - ---
The funded status of the plan cannot be presented separately for the Company as the Company participates in the plan with other National Grid USA subsidiaries. The following provides a reconciliation of benefit obligations and plan assets for the National Grid USA companies' plan:
At At March 31, December 31, - ---------------------------------------------------------------------------- (millions of dollars) 2001 2000 1999 - ---------------------------------------------------------------------------- Change in benefit obligation: Benefit obligation at beginning of period $ 800 $ 789 $ 843 Service cost 12 2 11 Interest cost 72 15 56 Actuarial (gain)/loss 47 10 (55) Benefits paid (90) (16) (66) Acquisitions 188 - - Special termination benefits 6 - - Plan amendments 20 - - - ---------------------------------------------------------------------------- Benefit obligation end of period 1,055 800 789 - ---------------------------------------------------------------------------- Reconciliation of change in plan assets: Fair value of plan assets at beginning of period 991 947 837 Actual return on plan assets during year (59) 59 117 Company contributions 8 1 59 Benefits paid from plan assets (90) (16) (66) Acquisitions 232 - - - --------------------------------------------------------------------------- Fair value of plan assets end of period 1,082 991 947 - --------------------------------------------------------------------------- Funded status 27 191 158 Unrecognized actuarial (gain)/loss 206 - (206) Unrecognized prior service cost 20 - 5 Unrecognized transition (asset)/liability - - (3) - --------------------------------------------------------------------------- Net amount recognized $ 253 $ 191 $ (46) - --------------------------------------------------------------------------- Amounts recognized in the statement of financial position consist of: Prepaid benefit cost $ 338 $ 262 $ 14 Accrued benefit liability (90) (71) (66) Intangible asset - - 2 Accumulated other comprehensive income 5 - 4 - --------------------------------------------------------------------------- Net amount recognized $ 253 $ 191 $ (46) - ---------------------------------------------------------------------------
March 31, December 31, 2001 2000 1999 1998 - ------------------------------------------------------------------------------- Assumptions used to determine pension cost: Discount rate 7.50% 7.75% 7.75% 6.75% Average rate of increase in future compensation level 4.61% 5.10% 5.10% 4.13% Expected long-term rate of return on assets 8.75% 8.50% 8.50% 8.50%
Plan assets are composed primarily of equity and fixed income securities. Fair value adjustments of approximately $33 million are reflected in the Company's financial statements at March 31, 2000. 2. Postretirement Benefit Plans Other than Pensions (PBOPs): The Company provides health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage. The Company's total cost of PBOPs for the year ended March 31, 2001, the three months ended March 31, 2000, and the years ended December 31, 1999 and 1998 included the following components:
Three Year Ended Months Ended Year Ended March 31, March 31, December 31, - -------------------------------------------------------------------------------------- - -- (thousands of dollars) 2001 2000 1999 1998 - -------------------------------------------------------------------------------------- - -- Service cost - benefits earned during the period $ 210 $ 47 $ 193 $ 1,109 Plus (less): Interest cost on projected benefit obligation 3,337 786 2,816 3,244 Return on plan assets at expected long-term rate (3,537) (803) (2,896) (2,656) Amortization of transition obligation - 19 85 1,732 Amortization of prior service cost - - - 5 Amortization of net (gain)/loss - (285) (1,252) (1,138) Curtailment (gain)/loss - - - 27,149 - -------------------------------------------------------------------------------------- - -- Benefit cost/(income) $ 10 $(236) $(1,054) $29,445 - -------------------------------------------------------------------------------------- - -- Special termination benefits not included above $ - $ - $ - $ 439 - -------------------------------------------------------------------------------------- - --
The following provides a reconciliation of benefit obligations and plan assets including fair value adjustments recorded in March 2000 of approximately $28 million:
At At March 31, December 31, - ------------------------------------------------------------------------------- (millions of dollars) 2001 2000 1999 - ------------------------------------------------------------------------------- Change in benefit obligation: Benefit obligation at beginning of period $38 $42 $ 41 Service cost - - - Interest cost 3 1 3 Actuarial (gain)/loss 2 (4) - Benefits paid (4) (1) (2) Acquisitions 8 - - - ------------------------------------------------------------------------------- Benefit obligation end of period 47 38 42 - ------------------------------------------------------------------------------- Reconciliation of change in plan assets: Fair value of plan assets at beginning of period 40 39 36 Actual return on plan assets during year (1) 2 4 Company contributions 2 - 1 Benefits paid from plan assets (4) (1) (2) Acquisitions 4 - - - ------------------------------------------------------------------------------- Fair value of plan assets end of period 41 40 39 - ----------------------------------------------------------------------------- Funded status (6) 2 (3) Unrecognized actuarial (gain)/loss 7 - (25) Unrecognized prior service cost - - - Unrecognized transition (asset)/liability - - 1 - ------------------------------------------------------------------------------- Net amount recognized $ 1 $ 2 $(27) - -------------------------------------------------------------------------------
March 31, December 31, 2001 2000 1999 1998 - ---------------------------------------------------------------------------- Assumptions used to determine postretirement benefit cost: Discount rate 7.50% 7.75% 7.75% 6.75% Expected long-term rate of return on assets 8.48% 8.40% 8.42% 8.35% Health care cost rates: 1998 to 1999 5.25% 2000 8.25% 8.25% 8.25% 5.25% 2001 8.00% 6.75% 6.75% 5.25% 2002 6.50% 5.25% 5.25% 5.25% 2003 and beyond 5.00% 5.25% 5.25% 5.25%
The assumptions used in the health care cost trends have a significant effect on the amounts reported. A one percentage point change in the assumed rates would increase the accumulated postretirement benefit obligation (APBO) as of March 31, 2001 by approximately $5 million or decrease the APBO by approximately $5 million, and change the net periodic cost for fiscal year 2001 by approximately $400,000. The Company generally funds the annual tax-deductible contributions. In connection with the mergers referred to in Note B, the Company adjusted its pension and PBOP accounts in the amount of approximately $64 million, with an offsetting net credit to a regulatory liability account. This adjustment eliminated any unrecognized net gain or loss, unrecognized prior service cost, or unrecognized transition obligation of the Company. The regulatory liability is being amortized over the service period to pension and postretirement health care costs. Note F - Income Taxes The Company and other subsidiaries intend to elect to participate with National Grid General Partnership, National Grid USA's parent company that is wholly owned by National Grid, in filing consolidated federal income tax returns. The Company's income tax provision is calculated on a separate return basis. Federal income tax returns have been examined and reported on by the Internal Revenue Service through 1996. Total income taxes in the statements of income are as follows:
Three Year Ended Months Ended Year Ended March 31, March 31, December 31, (In thousands) 2001 2000 1999 1999 1998 (unaudited) - -------------------------------------------------------------------------------------- Income taxes charged to operations $44,946 $9,641 $13,100 $37,633 $ 73,594 Income taxes charged (credited) to "Other income" (52) (4) - 1,985 (19,582) ------- ------ ------- ------- -------- Total income taxes $44,894 $9,637 $13,100 $39,618 $ 54,012 ======= ====== ======= ======= ========
Total income taxes, as shown above, consist of the following components:
Three Year Ended Months Ended Year Ended March 31, March 31, December 31, (In thousands) 2001 2000 1999 1999 1998 (unaudited) - -------------------------------------------------------------------------------------- Current income taxes $ 56,374 $12,545 $ 7,374 $ 25,507 $ 280,734 Deferred income taxes (1,111) (581) 10,732 25,921 (204,129) Investment tax credits, net (10,369) (2,327) (5,006) (11,810) (22,593) -------- ------- ------- -------- --------- Total income taxes $ 44,894 $ 9,637 $13,100 $ 39,618 $ 54,012 ======== ======= ======= ======== =========
Since 1998, the Company has been amortizing previously deferred investment tax credits (ITC) related to generation investments over the CTC recovery period. Unamortized ITC related to generating units divested in 1998 and 2001 were credited to other income pursuant to federal tax law. Previously recognized ITC related to transmission facilities are amortized over their estimated productive lives. Total income taxes, as shown above, consist of federal and state components as follows:
Three Year Ended Months Ended Year Ended March 31, March 31, December 31, (In thousands) 2001 2000 1999 1999 1998 (unaudited) - -------------------------------------------------------------------------- Federal income taxes $38,350 $ 8,035 $10,975 $33,746 $41,255 State income taxes 6,544 1,602 2,125 5,872 12,757 ------- ------- ------- ------- ------- Total income taxes $44,894 $ 9,637 $13,100 $39,618 $54,012 ======= ======= ======= ======= =======
With regulatory approval from the FERC, the Company has 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:
Three Year Ended Months Ended Year Ended March 31, March 31, December 31, (In thousands) 2001 2000 1999 1999 1998 (unaudited) - ---------------------------------------------------------------------------- Computed tax at statutory rate $36,118 $ 8,435 $11,706 $38,721 $ 61,917 Increases (reductions) in tax resulting from: Amortization of investment tax credits (7,762) (1,513) (3,254) (7,677) (15,157) State income taxes, net of federal income tax benefit 4,254 1,042 1,381 3,817 8,292 Rate recovery of deficiency in deferred tax reserves 4,339 1,617 3,508 8,207 - Amortization of goodwill 6,267 - - - - Prior year tax adjustment 773 - - (2,028) (188) Millstone 3 sale 1,787 - - - - All other differences (882) 56 (241) (1,422) (852) ------- ------- ------- ------- -------- Total income taxes $44,894 $ 9,637 $13,100 $39,618 $ 54,012 ======= ======= ======= ======= ========
The following table identifies the major components of total deferred income taxes:
At At March 31, December 31, (In millions) 2001 2000 1999 - ---------------------------------------------------------------------------- Deferred tax asset: Plant related $ 67 $ 67 $ 67 Investment tax credits 4 6 8 All other 30 3 2 ----- ----- ----- 101 76 77 ----- ----- ----- Deferred tax liability: Plant related (211) (159) (157) All other, principally regulatory assets (162) (93) (100) ----- ----- ----- (373) (252) (257) ----- ----- ----- Net deferred tax liability $(272) $(176) $(180) ===== ===== =====
Note G - Short-term Borrowings and Other Accrued Expenses At March 31, 2001, the Company had no short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of short- term debt. In October 2000, the Company received the necessary regulatory approvals to allow approximately $39 million of variable rate debt to remain outstanding through 2015. This results in classifying that debt as long-term rather than short-term. Proceeds from the increase in short- term debt were utilized to pay Montaup's debt of approximately $91 million and purchased power contract obligations of approximately $60 million. National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice. At March 31, 2001, the Company had lines of credit and standby bond purchase facilities with banks totaling $456 million which are available to provide liquidity support for $410 million of the Company's long-term bonds in tax-exempt commercial paper mode, and for other corporate purposes. There were no borrowings under these lines of credit at March 31, 2001. Fees are paid on the lines and facilities in lieu of compensating balances. The components of other accrued expenses are as follows:
At At March 31, December 31, (In thousands) 2001 2000 1999 - ----------------------------------------------------------------------------- Accrued wages and benefits $1,191 $ 1,215 $ 1,063 Rate adjustment mechanisms 5,555 9,110 14,550 Other 875 554 80 ------ ------- ------- $7,621 $10,879 $15,693 ------ ------- -------
Note H - Cumulative Preferred Stock A summary of cumulative preferred stock at March 31, 2001, March 31, 2000, and December 31, 1999 is as follows (in thousands of dollars except for share data):
Shares Dividends Call Outstanding Amount Declared Price - ------------------------------------------------------------------------------------ 2001 2000 1999 2001 2000 1999 2001 2000 1999 $100 par value 6.00% Series 14,361 15,672 15,672 $1,436 $1,567 $1,567 $91 $24 $94 (a) (a) Noncallable.
The annual dividend requirement for cumulative preferred stock was approximately $86,000 for 2001 and 2000, and $94,000 for 1999. In 2000, the Company repurchased or redeemed preferred stock with a par value of approximately $131,000. There are no mandatory redemption provisions on the Company's cumulative preferred stock. Note I - Long-term Debt A summary of long-term debt is as follows:
(In thousands) At At At March 31, March 31, December 31, Series Rate % Maturity 2001 2000 1999 - --------------------------------------------------------------------------------------- Pollution Control Revenue Bonds: CDA (a) variable October 15, 2015 $ 38,500 $ - $ - MIFA 1 (a) variable March 1, 2018 79,250 79,250 79,250 BFA 1 (b) variable November 1, 2020 135,850 135,850 135,850 BFA 2 (b) variable November 1, 2020 50,600 50,600 50,600 MIFA 2 (a) variable October 1, 2022 106,150 106,150 106,150 Unamortized discounts (71) (77) (79) -------- -------- ------ Total long-term debt $410,279 $371,773 $371,771 ======== ======== ======== (a) CDA = Connecticut Development Authority (b) MIFA = Massachusetts Industrial Finance Authority (c) BFA = Business Finance Authority of the State of New Hampshire
At March 31, 2001, interest rates on the Company's variable rate long-term bonds ranged from 3.0 percent to 4.2 percent. At March 31, 2001, the Company's long-term debt had a carrying value and fair value of approximately $410,000,000. The fair value of debt that reprices frequently at market rates approximates carrying value. Note J - Common Stock The purchase accounting method was used in the merger of National Grid and NEES, and in the acquisition of EUA by National Grid USA. This method resulted in a retained earnings adjustment of approximately $16 million for the National Grid/National Grid USA merger in order to reflect post-merger earnings. A retained earnings adjustment in the amount of approximately $0.5 million resulted from the merger of Montaup into the Company. Both mergers resulted in adjustments to other paid-in capital to reflect the pushdown of goodwill. The Company repurchased shares of its common stock in 1999 as follows (dollar amounts expressed in thousands):
Reductions to: --------------------------------------- Common stock Number of Cash and related Other paid- Retained Year Shares Paid premium in capital earnings - ---------------------------------------------------------------------------- 1999 130,000 $18,056 $4,348 $6,623 $7,085
Note K - Supplementary Income Statement Information Advertising expenses, expenditures for research and development, and rents were not material and there were no royalties paid in the year ended March 31, 2001, the three months ended March 31, 2000 or March 31, 1999, and the years ended December 31, 1999 or 1998. Taxes, other than income taxes, charged to operating expenses are set forth by class as follows:
Year Ended Three Months Ended Year Ended March 31, March 31, December 31, (In thousands) 2001 2000 1999 1999 1998 (unaudited) - -------------------------------------------------------------------------- Municipal property taxes $19,334 $4,718 $4,618 $17,640 $42,080 Federal and state payroll and other taxes 3,009 843 1,016 2,642 6,412 ------- ------ ------ ------- ------- $22,343 $5,561 $5,634 $20,282 $48,492 ======= ====== ====== ======= =======
Transactions between the Company and other affiliated companies for sales of electric energy and other sales amounted to approximately $385,982,000, $90,934,000, $120,700,000, $338,295,000, and $1,077,752,000 for the year ended March 31, 2001, the three months ended March 31, 2000, the three months ended March 31, 1999, and the years ended December 31, 1999 and 1998, respectively. National Grid USA Service Company, Inc., an affiliated service company operating pursuant to the provisions of Section 13 of the 1935 Act, furnished services to the Company at the cost of such services. These costs amounted to $44,315,000, $11,514,000, $10,088,000, $43,584,000, and $74,203,000, including capitalized construction costs of $19,117,000, $4,597,000, $3,415,000, $17,229,000, and $21,281,000, in the year ended March 31, 2001, the three months ended March 31, 2000, the three months ended March 31, 1999, and the years ended December 31, 1999 and 1998, respectively. Selected Financial Information
Year Three Ended Months Ended March 31, March 31, Year Ended December 31, 2001 2000 1999 1999 1998 1997 1996 (In millions) (unaudited) - ------------------------------------------------------------------------------------- Operating revenue $ 656 $ 135 $ 167 $ 596 $1,218 $1,678 $1,600 Net income $ 58 $ 14 $ 20 $ 71 $ 123 $ 145 $ 152 Total assets $2,889 $2,630 $2,282 $2,303 $2,415 $2,763 $2,648 Capitalization: Common equity $ 865 $ 657 $ 523 $ 332 $ 521 $ 913 $ 906 Cumulative preferred stock 1 1 1 2 1 40 40 Long-term debt 410 372 372 372 372 648 733 ------ ------ ------ ------ ------ ------ ------ Total capitalization $1,276 $1,030 $ 896 $ 706 $ 894 $1,601 $1,679 Preferred dividends declared $ - $ - $ - $ - $ 1 $ 2 $ 3 Common dividends declared $ - $ 24 $ - $ 241 $ 131 $ 135 $ 134 ------ ------ ------ ------ ------ ------ ------
Selected Quarterly Financial Information (Unaudited)
Quarter Quarter Quarter Quarter Quarter Ended Ended Ended Ended Ended March 31, June 30, Sept. 30, Dec. 31, March 31, (In thousands) 2000 2000 2000 2000 2001 - ------------------------------------------------------------------------------------ Operating revenue $134,564 $156,190 $175,390 $156,396 $168,296 Operating income $ 16,685 $ 15,908 $ 25,232 $ 22,040 $ 24,535 Net income $ 14,462 $ 14,223 $ 16,460 $ 14,780 $ 12,837 Quarter Quarter Quarter Quarter Ended Ended Ended Ended March 31, June 30, Sept. 30, Dec. 31, 1999 1999 1999 1999 - ------------------------------------------------------------------------------------- Operating revenue $167,177 $139,620 $142,066 $147,478 Operating income $ 22,058 $ 13,796 $ 18,782 $ 23,927 Net income $ 20,345 $ 14,254 $ 17,669 $ 18,746
Per share data is not relevant because the Company's common stock is wholly owned by National Grid USA, a wholly owned subsidiary of National Grid Group plc. New England Power Company 25 Research Drive Westborough, Massachusetts 01582 Directors (As of April 1, 2001) L. Joseph Callan Former Executive Director for Operations, Nuclear Regulatory Commission Peter G. Flynn President of the Company Michael E. Jesanis Vice President of the Company and Executive Vice President of National Grid USA Lawrence J. Reilly Vice President and General Counsel of the Company and Senior Vice President, General Counsel, and Secretary of National Grid USA Robert G. Powderly Vice President of National Grid USA Terry L. Schwennesen Vice President of the Company Richard P. Sergel President and Chief Executive Officer of National Grid USA Philip R. Sharp Lecturer, Harvard University, John F. Kennedy School of Government Officers (As of April 1, 2001) Peter G. Flynn President of the Company Michael E. Jesanis Vice President of the Company and Executive Vice President of National Grid USA Lawrence J. Reilly Vice President and General Counsel of the Company and Senior Vice President, General Counsel, and Secretary of National Grid USA Marc F. Mahoney Vice President of the Company and of certain affiliates John F. Malley Vice President of the Company James S. Robinson Vice President of the Company Masheed H. Rosenqvist Vice President of the Company and of certain affiliates Terry L. Schwennesen Vice President of the Company Gregory A. Hale Clerk of the Company and of certain affiliates, Assistant Secretary or Assistant Clerk of certain affiliates, and Secretary of an affiliate John G. Cochrane Treasurer of the Company and of certain affiliates, President of certain affiliates, Vice President of an affiliate, and Vice President, Chief Financial Officer, and Treasurer of National Grid USA Kirk L. Ramsauer Assistant Clerk of the Company and of certain affiliates and Secretary or Clerk of certain affiliates Geraldine M. Zipser Assistant Clerk of the Company and of certain affiliates, Secretary or Clerk of certain affiliates, and Assistant Secretary of an affiliate Patricia C. Easterly Assistant Treasurer of the Company and Treasurer of an affiliate Nancy B. Kellogg Assistant Treasurer of the Company and of certain affiliates Kwong O. Nuey Controller of the Company and of certain affiliates and Vice President of an affiliate Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock, Fleet National Bank, Boston, Massachusetts This report is not to be considered an offer to sell or buy or solicitation of an offer to sell or buy any security. EXHIBIT (24) POWER OF ATTORNEY ----------------- Each of the undersigned directors of New England Power Company (the ?Company?), individually as a director of the Company, hereby constitutes and appoints John G. Cochrane, Kirk L. Ramsauer, and Geraldine M. Zipser, individually, as attorney-in-fact to execute on behalf of the undersigned the Company?s transition report on Form 10-K for the period ended March 31, 2001 to be filed with the Securities and Exchange Commission, and to execute any appropriate amendment or amendments thereto as may be required by law. Dated this 25th day of May, 2001. s/L. Joseph Callan s/Peter G. Flynn _________________________ _________________________ L. Joseph Callan Peter G. Flynn s/Michael E. Jesanis s/Robert G. Powderly _________________________ _________________________ Michael E. Jesanis Robert G. Powderly s/Lawrence J. Reilly s/Terry L. Schwennesen _________________________ _________________________ Lawrence J. Reilly Terry L. Schwennesen s/Richard P. Sergel s/Philip R. Sharp _________________________ _________________________ Richard P. Sergel Philip R. Sharp NEP John G. Cochrane Treasurer June 28, 2001 Securities and Exchange Commission Judiciary Plaza 450 Fifth Street, N.W. Washington, D.C. 20549 Re: File No. 1-6564 Ladies and Gentlemen: New England Power Company is a participant in the Electronic Data Gathering and Retrieval Program. Submitted herewith in electronic format for filing with the Commission is a Transition Report for the transition period ended March 31, 2001 on Form 10-K for New England Power Company which is required to file a report pursuant to Section 13 of the Securities Exchange Act of 1934. This annual report is filed with you pursuant to Rule 13(a)-1 of the Securities and Exchange Commission under the Securities Exchange Act of 1934. Very truly yours, s/John G. Cochrane - -iii- - -41- - -67- Issued by: David T. Doot, Secretary Effective: June 28, 2000 Issued on: July 28, 2000 nep2001 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. EL00-62-000, issued June 28, 2000, 91 FERC 61,311 (2000). -----END PRIVACY-ENHANCED MESSAGE-----