-----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, VAiaJHjm8Jza9pYmfBclEgPLS3EJlwQ93MTdiFB2HrsAFNBm7Dh8VHSlCUxlwvcV qdQlhI+65zTI999BpMILMQ== 0000072741-01-000075.txt : 20010329 0000072741-01-000075.hdr.sgml : 20010329 ACCESSION NUMBER: 0000072741-01-000075 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 18 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010328 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHEAST UTILITIES SYSTEM CENTRAL INDEX KEY: 0000072741 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 042147929 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-05324 FILM NUMBER: 1581348 BUSINESS ADDRESS: STREET 1: 174 BRUSH HILL AVE CITY: WEST SPRINGFIELD STATE: MA ZIP: 01090-0010 BUSINESS PHONE: 4137855871 MAIL ADDRESS: STREET 1: 107 SELDON ST CITY: BERLIN STATE: CT ZIP: 06037-1616 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONNECTICUT LIGHT & POWER CO CENTRAL INDEX KEY: 0000023426 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 060303850 STATE OF INCORPORATION: CT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-00404 FILM NUMBER: 1581349 BUSINESS ADDRESS: STREET 1: SELDEN STREET CITY: BERLIN STATE: CT ZIP: 06037-1616 BUSINESS PHONE: 8606655000 FILER: COMPANY DATA: COMPANY CONFORMED NAME: WESTERN MASSACHUSETTS ELECTRIC CO CENTRAL INDEX KEY: 0000106170 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041961130 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-07624 FILM NUMBER: 1581350 BUSINESS ADDRESS: STREET 1: 174 BRUSH HILL AVE CITY: WEST SPRINGFIELD STATE: MA ZIP: 01090-0010 BUSINESS PHONE: 4137855871 MAIL ADDRESS: STREET 1: 107 SELDON ST CITY: BERLIN STATE: CT ZIP: 06037-1616 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE CO OF NEW HAMPSHIRE CENTRAL INDEX KEY: 0000315256 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 020181050 STATE OF INCORPORATION: NH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-06392 FILM NUMBER: 1581351 BUSINESS ADDRESS: STREET 1: 1000 ELM ST CITY: MANCHESTER STATE: NH ZIP: 03105 BUSINESS PHONE: 6036694000 MAIL ADDRESS: STREET 1: 1000 ELM STREET CITY: MANCHESTER STATE: NH ZIP: 03105 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTH ATLANTIC ENERGY CORP /NH CENTRAL INDEX KEY: 0000880416 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 061339460 STATE OF INCORPORATION: NH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 033-43508 FILM NUMBER: 1581352 BUSINESS ADDRESS: STREET 1: 1000 ELM ST CITY: MANCHESTER STATE: NH ZIP: 03105 BUSINESS PHONE: 6036694000 MAIL ADDRESS: STREET 1: 1000 ELM STREET CITY: MANCHESTER STATE: NH ZIP: 03105 10-K 1 0001.txt FORM 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549-1004 [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from ________ to ________ Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. - ----------- ----------------------------------- ------------------ 1-5324 NORTHEAST UTILITIES 04-2147929 (a Massachusetts voluntary association) 174 Brush Hill Avenue West Springfield, Massachusetts 01090-2010 Telephone: (413) 785-5871 0-11419 THE CONNECTICUT LIGHT AND POWER COMPANY 06-0303850 (a Connecticut corporation) 107 Selden Street Berlin, Connecticut 06037-1616 Telephone: (860) 665-5000 1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050 (a New Hampshire corporation) 1000 Elm Street Manchester, New Hampshire 03105-0330 Telephone: (603) 669-4000 0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY 04-1961130 (a Massachusetts corporation) 174 Brush Hill Avenue West Springfield, Massachusetts 01090-2010 Telephone: (413) 785-5871 33-43508 NORTH ATLANTIC ENERGY CORPORATION 06-1339460 (a New Hampshire corporation) 1000 Elm Street Manchester, New Hampshire 03105-0330 Telephone: (603) 669-400 Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Registrant Title of Each Class on Which Registered - ---------- ------------------- --------------------- Northeast Utilities Common Shares, New York Stock Exchange, Inc. $5.00 par value The Connecticut 9.3% Cumulative New York Stock Exchange, Inc. Light and Power Monthly Income Company Preferred Securities Series A (1) (1) Issued by CL&P Capital LP (CL&P LP), a wholly owned subsidiary of The Connecticut Light and Power Company (CL&P), and guaranteed by CL&P. Securities registered pursuant to Section 12(g) of the Act: Registrant Title of Each Class ---------- ------------------- The Connecticut Light Preferred Stock, par value $50.00 per share, and Power Company issuable in series, of which the following series are outstanding: $1.90 Series of 1947 4.96% Series of 1958 $2.00 Series of 1947 4.50% Series of 1963 $2.04 Series of 1949 5.28% Series of 1967 $2.20 Series of 1949 $3.24 Series G of 1968 3.90% Series of 1949 6.56% Series of 1968 $2.06 Series E of 1954 $2.09 Series F of 1955 4.50% Series of 1956 Public Service Company Preferred Stock, par value $25.00 per share, of New Hampshire issuable in series, of which the following series is outstanding: 10.60% Series A of 1991 Western Massachusetts Preferred Stock, par value $100.00 per share, Electric Company issuable in series, of which the following series is outstanding: 7.72% Series B of 1971 Class A Preferred Stock, par value $25.00 per share, issuable in series, of which the following series is outstanding: 7.60% Series of 1987 Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X 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 the 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. [ ] The aggregate market value of Northeast Utilities' Common Shares, $5.00 Par Value, held by nonaffiliates, was $3,035,128,320 based on a closing sales price of $20.40 per share for the 148,780,800 common shares outstanding on February 28, 2001. Northeast Utilities holds all of the 7,584,884 shares, 1,000 shares, 590,093 shares, and 1,000 shares of the outstanding common stock of The Connecticut Light and Power Company, Public Service Company of New Hampshire, Western Massachusetts Electric Company, and North Atlantic Energy Corporation, respectively. Documents Incorporated by Reference: Part of Form 10-K into Which Document Description is Incorporated ----------- ------------------- Portions of Annual Reports of the following companies for the year ended December 31, 2000: The Connecticut Light and Power Company Part II Public Service Company of New Hampshire Part II Western Massachusetts Electric Company Part II North Atlantic Energy Corporation Part II GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report: COMPANIES CL&P............................... The Connecticut Light and Power Company Con Edison......................... Consolidated Edison, Inc. CYAPC.............................. Connecticut Yankee Atomic Power Company Dominion........................... Dominion Resources, Inc. HEC................................ HEC Inc. HWP................................ Holyoke Water Power Company Mode 1............................. Mode 1 Communications, Inc. MYAPC.............................. Maine Yankee Atomic Power Company NAEC............................... North Atlantic Energy Corporation NAESCO............................. North Atlantic Energy Service Corporation NEON............................... NEON Communications, Inc. NGC................................ Northeast Generation Company NGS................................ Northeast Generation Services Company NNECO.............................. Northeast Nuclear Energy Company NU or the Company.................. Northeast Utilities NUEI............................... NU Enterprises, Inc. NUSCO or the Service Company....... Northeast Utilities Service Company PSNH............................... Public Service Company of New Hampshire RRR................................ The Rocky River Realty Company Select Energy...................... Select Energy, Inc. SEPPI.............................. Select Energy Portland Pipeline, Inc. The NU system...................... The Northeast Utilities System The Yankee Companies............... CYAPC, MYAPC, VYNPC, and YAEC VYNPC.............................. Vermont Yankee Nuclear Power Corporation WMECO.............................. Western Massachusetts Electric Company YAEC............................... Yankee Atomic Electric Company Yankee............................. Yankee Energy System, Inc. Yankee Gas......................... Yankee Gas Services Company GENERATING UNITS Millstone 1........................ Millstone Unit No. 1, a 660 MW nuclear unit completed in 1970; Millstone 1 is currently in decommissioning status. Millstone 2........................ Millstone Unit No. 2, an 870 MW nuclear electric generating unit completed in 1975 Millstone 3........................ Millstone Unit No. 3, a 1,154 MW nuclear electric generating unit completed in 1986 Seabrook or Seabrook 1............. Seabrook Unit No. 1, a 1,148 MW nuclear electric generating unit completed in 1986. Seabrook 1 went into service in 1990. REGULATORS CDEP............................... Connecticut Department of Environmental Protection DOE................................ United States Department of Energy DPUC............................... Connecticut Department of Public Utility Control DTE................................ Massachusetts Department of Telecommunications and Energy EPA................................ United States Environmental Protection Agency FERC............................... Federal Energy Regulatory Commission NHDES.............................. New Hampshire Department of Environmental Services NHPUC.............................. New Hampshire Public Utilities Commission NRC................................ Nuclear Regulatory Commission SEC................................ Securities and Exchange Commission OTHER 1935 Act........................... Public Utility Holding Company Act of 1935 CAAA............................... Clean Air Act Amendments of 1990 kWh................................ Kilowatt-hour MW................................. Megawatt NEPOOL............................. New England Power Pool NUG&T.............................. Northeast Utilities Generation and Transmission Agreement NORTHEAST UTILITIES THE CONNECTICUT LIGHT AND POWER COMPANY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE WESTERN MASSACHUSETTS ELECTRIC COMPANY NORTH ATLANTIC ENERGY CORPORATION 2000 Form 10-K Annual Report Table of Contents PART I Page ---- Item 1. Business................................................... 1 The Northeast Utilities System................................... 1 Safe Harbor Statement............................................ 2 Mergers and Acquisitions......................................... 3 Consolidated Edison, Inc. Merger........................... 3 Yankee Energy System, Inc. Merger.......................... 4 Rates and Electric Industry Restructuring........................ 4 General.................................................... 4 Connecticut Rates and Restructuring........................ 6 Massachusetts Rates and Restructuring...................... 8 New Hampshire Rates and Restructuring...................... 9 Competitive System Businesses.................................... 10 Energy-Related Products and Services and Gas Investments... 10 Energy Generation and Services............................. 12 Energy Management Services................................. 13 Gas Investments............................................ 13 Telecommunications......................................... 13 Financing Program................................................ 14 2000 Financings............................................ 14 2001 Financing Requirements................................ 16 2001 Financing Plans....................................... 16 Financing Limitations...................................... 17 Construction Program............................................. 22 Regulated Electric Operations.................................... 22 Distribution and Sales..................................... 22 Regional and System Coordination........................... 23 Transmission Access and FERC Regulatory Changes............ 25 Regulated Gas Operations......................................... 26 Regulation................................................. 26 Nuclear Generation............................................... 27 General.................................................... 27 Nuclear Plant Performance.................................. 28 Nuclear Insurance.......................................... 29 Nuclear Fuel............................................... 29 Decommissioning............................................ 31 Other Regulatory and Environmental Matters....................... 34 Environmental Regulation................................... 34 Electric and Magnetic Fields............................... 37 FERC Hydroelectric Project Licensing....................... 37 Employees........................................................ 38 Item 2. Properties................................................. 39 Item 3. Legal Proceedings.......................................... 44 Item 4. Submission of Matters to a Vote of Security Holders........ 49 PART II Item 5. Market for Registrants' Common Equity and Related Shareholder Matters....................................... 49 Item 6. Selected Financial Data................................... 50 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....................... 50 Item 7A. Quantitative and Qualitative Disclosures About Market Risk............................................... 50 Item 8. Financial Statements and Supplementary Data............... 51 Item 9. Changes in Disagreements with Accountants on Accounting and Financial Disclosure....................... 51 PART III Item 10. Directors and Executive Officers of the Registrants....... 52 Item 11. Executive Compensation.................................... 61 Item 12. Security Ownership of Certain Beneficial Owners and Management................................................ 71 Item 13. Certain Relationships and Related Transactions............ 76 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...................................... 77 NORTHEAST UTILITIES THE CONNECTICUT LIGHT AND POWER COMPANY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE WESTERN MASSACHUSETTS ELECTRIC COMPANY NORTH ATLANTIC ENERGY CORPORATION PART I ITEM 1. BUSINESS THE NORTHEAST UTILITIES SYSTEM Northeast Utilities (NU or the Company) is the parent company of the Northeast Utilities system (NU system). The NU system furnishes franchised retail electric service in Connecticut, New Hampshire and western Massachusetts through three of NU's wholly owned subsidiaries (CL&P, Public Service Company of New Hampshire [PSNH] and Western Massachusetts Electric Company [WMECO]) and to a limited number of customers through another wholly owned subsidiary, Holyoke Water Power Company (HWP). The NU system serves approximately 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues. The NU system also furnishes retail natural gas service in most of Connecticut through its Yankee Gas Services Company (Yankee Gas) subsidiary, the largest natural gas distribution company in Connecticut. Yankee Gas serves approximately 187,000 residential, commercial and industrial customers in 69 cities and towns in Connecticut. NU, through its wholly owned subsidiary, NU Enterprises, Inc. (NUEI), owns a number of competitive energy and telecommunications related businesses, including Northeast Generation Company (NGC), Northeast Generation Services Company (NGS), Select Energy, Inc. (Select Energy), HEC Inc. (HEC), Mode 1 Communications, Inc. (Mode 1), and Select Energy Portland Pipeline, Inc. (SEPPI). For information regarding the activities of these subsidiaries, see "Competitive System Businesses." North Atlantic Energy Corporation (NAEC) is a wholly owned special-purpose operating subsidiary of NU that owns a 35.98 percent interest in the Seabrook Station nuclear unit (Seabrook) in Seabrook, New Hampshire, and sells its share of the capacity and output from Seabrook to PSNH under two life-of-unit, full-cost recovery contracts (Seabrook Power Contracts). Several wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information technology, engineering, financial, legal, operational, planning, purchasing, and other services to the NU system companies. North Atlantic Energy Service Corporation (NAESCO) has operational responsibility for Seabrook. Northeast Nuclear Energy Company (NNECO) acts as agent for the NU system companies in operating the Millstone nuclear generating units (Millstone) in Waterford, Connecticut. Three other subsidiaries construct, acquire or lease some of the property and facilities used by the NU system companies. The NU system is regulated in virtually all aspects of its business by various federal and state agencies, including the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each company operates, including the Connecticut Department of Public Utility Control (DPUC), the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (DTE). In recent years, there has been significant legislative and regulatory activity changing the nature of regulation of the industry. For more information regarding these restructuring initiatives, see "Rates and Electric Industry Restructuring" and "Regulated Electric Operations." SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), NU and its reporting subsidiaries are hereby filing cautionary statements identifying important factors that could cause NU or its subsidiaries' actual results to differ materially from those projected in forward looking statements (as such term is defined in the Reform Act) made by or on behalf of NU or its subsidiaries in this combined Form 10-K, in any subsequent filings with the SEC, in presentations, in response to questions, or otherwise. Any statements that express or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events, or performance (often, but not always, through the use of words or phrases such as will likely result, are expected to, will continue, is anticipated, estimated, projection, outlook) are not statements of historical facts and may be forward looking. Forward looking statements involve estimates, assumptions and uncertainties that could cause actual results to differ materially from those expressed in the forward looking statements. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause NU or its subsidiaries' actual results to differ materially from those contained in forward looking statements of NU or its subsidiaries made by or on behalf of NU or its subsidiaries. Any forward looking statement speaks only as of the date on which such statement is made, and NU and its subsidiaries undertake no obligation to update any forward looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors may cause actual results to differ materially from those contained in any forward looking statements. Some important factors that could cause actual results or outcomes to differ materially from those discussed in the forward looking statements include prevailing governmental policies and regulatory actions, including those of the SEC, the NRC, the FERC, and state regulatory agencies, with respect to allowed rates of return, industry and rate structure, operation of nuclear power facilities, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased-power costs, stranded costs, decommissioning costs, and present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs). The business and profitability of NU and its subsidiaries are also influenced by economic and geographic factors including political and economic risks, changes in environmental and safety laws and policies, weather conditions (including natural disasters), population growth rates and demographic patterns, competition for retail and wholesale customers, pricing and transportation of commodities, market demand for energy from plants or facilities, changes in tax rates or policies or in rates of inflation, changes in project costs, unanticipated changes in certain expenses and capital expenditures, capital market conditions, competition for new energy development opportunities, and legal and administrative proceedings (whether civil or criminal) and settlements. All such factors are difficult to predict, contain uncertainties which may materially affect actual results and are beyond the control of NU or its subsidiaries. MERGERS AND ACQUISITIONS CONSOLIDATED EDISON, INC. MERGER In October 1999, NU and Consolidated Edison, Inc. (Con Edison) agreed to a merger to combine the two companies. During 2000, NU and Con Edison received most of the approvals needed to complete the merger. Shareholders from both companies approved the merger in April 2000 and all required state regulatory approvals were granted by the end of the year. Additionally, the FERC approved the merger in May 2000, which approval was reaffirmed on January 24, 2001, when FERC denied The United Illuminating Company's request for rehearing of the approval. The NRC and the U.S. Department of Justice approved the transaction in August 2000 and February 2001, respectively. The final required approval, that of the SEC, was expected in mid-March 2001. On February 28, 2001, NU announced that it had requested that Con Edison provide assurance in writing of its intent to close the merger on the agreed upon terms by March 2, 2001, which date was later extended to March 5, 2001. On March 5, 2001, NU announced that Con Edison had advised NU that Con Edison was not willing to close the merger on the previously agreed upon terms. NU said that it had notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that it would file a lawsuit to obtain the benefits of the transaction as negotiated for NU's shareholders. On March 6, 2001, Con Edison announced that Con Edison had filed suit in the U.S. District Court for the Southern District of New York (Southern District) seeking a declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement and that Con Edison had no further obligations under the merger agreement. On March 12, 2001, NU filed suit in the Southern District seeking substantial monetary damages against Con Edison arising out of Con Edison's breach of the merger agreement. NU cannot predict the outcome of these matters nor their effect upon NU. For further information on litigation relating to the proposed merger, see "Item 3. Legal Proceedings." Under the terms of the proposed transaction, NU shares would have been acquired by Con Edison for a base price of $25.00 per share, comprised of 50 percent cash and 50 percent Con Edison shares. NU shareholders would have received an additional $1 per share in proceeds because of the progress made in selling the Millstone nuclear station. NU shareholders would have received another $0.0034 per share for each day it took to complete the merger after August 5, 2000. Under the agreement, the overall value of the stock and the overall value of the cash that Con Edison would have provided to NU shareholders would have been the same if Con Edison's shares averaged between $36 and $46 per share during the pricing period. Should Con Edison shares have averaged below $36 per share, the value of the stock proceeds received by NU shareholders would have fallen, but should Con Edison shares have averaged above $46 per share, the value of the stock proceeds would have risen. Con Edison's share price had no bearing on the value of the cash portion of the proceeds. Assuming that Con Edison's stock price averaged between $36 and $46 per share during the applicable pricing period, NU shareholders would have received approximately $26.84 per share had the merger closed on April 10, 2001. Ultimately the value of the transaction to NU shareholders would have depended on the timing of the closing, the average price of Con Edison shares during the pricing period and the effect of proration among all shareholders. YANKEE ENERGY SYSTEM, INC. (YANKEE) MERGER On March 1, 2000, NU acquired Yankee, and Yankee became a wholly owned subsidiary of NU. Yankee is the parent of Yankee Gas, the largest natural gas distribution company in Connecticut. NU paid $45 per share, aggregating $478 million, in cash and stock for all Yankee shares. In addition, NU assumed $164 million of Yankee's outstanding long-term debt and all of its short-term debt, which totaled $70 million at closing. Yankee shareholders received 45 percent of the $478 million in NU common shares and 55 percent in cash. NU borrowed the cash portion of the acquisition through a short-term loan of $263 million, and met the stock component by issuing 11.1 million new NU shares. NU expects to redeem approximately the same number of shares in the second quarter of this year by closing out a forward share purchase program with proceeds from restructuring of its electric utility businesses. The forward share purchase program was conducted late in 1999 and early in 2000 through two financial institutions. With certain limited exceptions, NU's merger agreement with Con Edison prohibited NU from purchasing additional shares, but the forward shares may be retired at any time. Yankee continues to act as the holding company of Yankee Gas and its three nonutility subsidiaries, NorConn Properties, Inc., which holds the property and facilities of the Yankee companies; Yankee Energy Financial Services Company, which provides customers with financing for energy equipment installations, and; R.M. Services, Inc., which provides debt collection service to utilities and other businesses nationwide. For further information on the Yankee companies, see "Regulated Gas Operations." RATES AND ELECTRIC INDUSTRY RESTRUCTURING GENERAL NU's electric utility subsidiaries, CL&P, WMECO and PSNH, are undergoing fundamental changes in their business operations as a result of the restructuring of the electric industry in their respective jurisdictions. Most notably, the companies have been divesting, and are continuing to divest, their generation assets and will act solely as transmission and distribution companies in the future. In general, their customers will be able to choose their energy suppliers, with the electric utility companies furnishing "standard offer" service just to those customers who do not choose a competitive supplier. Critical to this restructuring is the companies' ability to recover their stranded costs. Stranded costs are expenditures incurred, or commitments for future expenditures made, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates. However, under certain circumstances these costs might not be recoverable from customers in a fully competitive electric utility industry (i.e., the costs may result in above-market energy prices). As discussed more fully below, Connecticut and Massachusetts have enacted restructuring legislation that permits CL&P and WMECO to recover substantially all of their prudently incurred stranded costs. NU, PSNH and the state of New Hampshire have reached a settlement (Settlement Agreement), which affects restructuring as to PSNH and will permit PSNH to recover a substantial portion of its stranded costs. Electric utility restructuring in Connecticut, New Hampshire and Massachusetts provides for a transition period of several years following the opening of each state's electric market to customer choice. During that interim period, the energy delivery companies, including CL&P, WMECO and PSNH, are responsible for arranging for the supply of power to customers who do not select alternative energy suppliers. Management recognizes that in other states electric companies have been negatively affected by the inability to recover supply costs on a timely basis. However, the Company believes that current statutes and regulatory policy in the three states in which NU subsidiaries operate electric delivery businesses will permit timely recovery. CL&P has signed fixed-price contracts with three suppliers who together will serve all of CL&P's standard offer requirements through 2003. One of these suppliers is the Company's competitive marketing affiliate, Select Energy. CL&P is fully recovering all of the payments it is making to those suppliers and has financial guarantees from each supplier to shield CL&P from risk in the event any of the suppliers encounters financial difficulties. See "Connecticut Rates and Restructuring." WMECO signed new one-year supply contracts with three unaffiliated suppliers in December 2000 that will continue through the end of 2001. In January 2001, the DTE approved a 17.4 percent increase in overall bills to allow WMECO to fully recover its supply costs on a current basis. See "Massachusetts Rates and Restructuring." As of the beginning of 2001, PSNH remained a vertically integrated utility with cost-of-service ratemaking and a fuel adjustment clause. For the first nine months following the commencement of retail competition, customers who do not choose alternative suppliers will be served by PSNH with energy from PSNH's existing generating plants and power purchase contracts. When they are fully operable, PSNH's current supply sources are generally well in excess of customer demand. Nine months after the commencement of retail competition, PSNH is required to bid out the supply of its transition service customers (those who do not take service from competitive suppliers). PSNH is currently limited to charging residential and small commercial customers 4.4 cents per kilowatt-hour for the first 12 months after the bids take effect and 4.6 cents per kilowatt-hour for the second 12 months. Those prices are now well below the wholesale market price for firm requirements power in New England. Under the New Hampshire restructuring statute, PSNH will be required to expense the first $7 million of costs that cannot be collected under the rate cap and then will be able to defer the balance for future recovery. See "New Hampshire Rates and Restructuring." CONNECTICUT RATES AND RESTRUCTURING In a series of decisions issued during 1999 and 2000, the DPUC approved CL&P's restructuring consistent with Connecticut's 1998 restructuring law. Choice of electric supplier was available to CL&P customers living in distressed cities (35 percent of CL&P total load) on January 1, 2000, and to all CL&P customers effective July 1, 2000. CL&P rates were unbundled effective January 1, 2000, with total rates 10 percent below rates in effect in December 1996, or 5 percent lower than rates in effect on December 31, 1999. Effective January 1, 2000, CL&P's primary responsibility is to serve as transmission and distribution provider to all customers within its service territory and to provide standard offer service to those customers who have not chosen a competitive supplier. CL&P's standard offer supply was obtained via a request for proposal process, conducted by J.P. Morgan Securities, Inc. (J.P. Morgan) on behalf of the DPUC. As approved by the DPUC, 50 percent of the standard offer supply is met by a CL&P affiliate and 50 percent by two unaffiliated suppliers. The contracts with all three suppliers terminate December 31, 2003. CL&P is recovering all of its supply costs in rates. The Connecticut restructuring legislation authorized the collection of mitigated generation-related stranded costs and the securitization of nonnuclear generation-related stranded costs. Securitization is the monetization of stranded costs through the sale of nonrecourse debt securities (rate reduction bonds) by a special purpose entity, which are collateralized by a company's interests in stranded cost recoveries. Securitization proceeds are applied in general to retire higher cost debt of the utility. The legislation also required the divestiture of all generating assets and the mitigation of purchased power contracts. Proceeds from asset divestiture are required to be used to offset stranded costs. The DPUC approved the divestiture plans, engaged J.P. Morgan to conduct the auctions and approved the ultimate transactions regarding the divestiture of all of CL&P's fossil and hydroelectric plants and the Millstone nuclear station. In December 1999, CL&P sold 2,235 megawatts (MW) of fossil-fueled generation assets to an unaffiliated company for $460 million. In March 2000, CL&P transferred 1,057 MW of hydroelectric generation assets in Connecticut and Massachusetts to NGC, an affiliated company, for $681 million. All proceeds have been used to offset stranded costs. In the fall of 1999, CL&P and WMECO sold the capacity and energy associated with their unit entitlements in Millstone 2 and 3 and Seabrook to Select Energy and five unaffiliated companies for the period beginning January 1, 2000, through December 31, 2001. The revenues that result from these contracts over the two year period (or until the units are sold, if earlier) are expected to recover CL&P's and WMECO's share of the nuclear operating costs, including a return on and the remaining nuclear plant balances. On August 7, 2000, the DPUC announced that an agreement had been reached with Dominion Resources, Inc. (Dominion) for the sale of Millstone 1, Millstone 2 and approximately 94 percent of Millstone 3, including nuclear fuel and inventory, for approximately $1.3 billion. All necessary state approvals for CL&P, WMECO, PSNH, and the other selling joint owners have been obtained. On February 20, 2001, the Connecticut Coalition Against Millstone (CCAM) appealed the DPUC's approval of the agreement to the Connecticut Superior Court and asked the court to issue a stay of the transaction pending resolution of the appeal. The parties are pursuing the necessary federal regulatory approvals to close the transaction as early as the end of March 2001. The DPUC has approved recovery of Millstone-related stranded costs not offset by asset divestiture proceeds. Pursuant to the DPUC order, CL&P will seek recovery of Millstone post-1997 capital additions in the nuclear proceeds calculation which will be filed after closing on the Millstone transaction. CL&P must prove that the costs are not related to the extended outage that began in 1996 and that the costs are reasonable relative to the benefits. Among other rulings in the DPUC's restructuring decisions, the Connecticut Office of Consumer Counsel (OCC) has appealed CL&P's ability to recover these costs. Oral argument on these issues is scheduled in Connecticut Superior Court for March 29, 2001. For further information on litigation relating to the sale of Millstone, see "Item 3. Legal Proceedings." CL&P intends to auction its interest in Seabrook when NAEC auctions its Seabrook interests. Divestiture plans were filed simultaneously with the DPUC and the NHPUC in December 2000. DPUC hearings are scheduled to commence in March 2001. The DPUC has approved CL&P negotiated buy-downs and buy-outs of 15 contracts with independent power producers (IPPs) and one wholesale power contract. The DPUC has approved securitization of $1.026 billion in buy down and buy out payments. Payments to the IPP projects will be made after receipt of funds from the issuance of rate reduction bonds. CL&P was unable to negotiate buy-downs or buy-outs with 15 IPPs that produce approximately 345 MW. The DPUC authorized J.P. Morgan to auction the long-term purchased power contracts and ultimately Constellation Power Source, Inc. (Constellation) was selected as the winning bidder. Constellation and CL&P entered an agreement, subject to DPUC approval, whereby Constellation would obtain the power from the power purchase agreements and assume CL&P's obligations thereunder, in exchange for monthly support payments from CL&P. The DPUC rejected the agreement between Constellation and CL&P, finding that it did not fully mitigate stranded costs. CL&P is selling the output from the projects into the market and will continue to collect the difference between the contract prices and the market revenues as stranded costs. These stranded costs cannot be securitized. The DPUC also approved recovery of and securitization of approximately $439 million of generation-related regulatory assets. The OCC appealed to the Connecticut Superior Court the methodology used by CL&P and endorsed by the DPUC to calculate the regulatory assets. The parties have reached a settlement of this appeal pursuant to which the OCC appeal will be withdrawn and securitization, including the full amount of generation-related regulatory assets, will go forward. DPUC approval of the settlement was received on March 12, 2001. On March 16, 2001, the OCC withdrew its appeal. On December 1, 2000, the Connecticut Attorney General (AG) and the OCC each filed a petition requesting that the DPUC initiate a proceeding to consider whether an interim decrease in the rates charged by CL&P is required. The applicable statute requires the DPUC to commence a special public hearing on the need for an interim rate decrease when, among other reasons, a public service company has for six consecutive months earned a return on equity (ROE) that exceeds the return authorized by the DPUC by at least one percentage point. The AG and the OCC petitions were filed after CL&P reported ROEs of 13.12 percent for the second quarter of 2000 and 14.17 percent for the third quarter of 2000. The DPUC conducted public hearings in this matter in February and March 2001, and a decision from the DPUC is expected in April 2001. MASSACHUSETTS RATES AND RESTRUCTURING Massachusetts enacted comprehensive electric utility industry restructuring in November 1997. That legislation required each electric company to submit a restructuring plan and to reduce its rates by 15 percent adjusted for inflation by September 1999. The 15 percent rate reduction is a rate cap for standard offer service customers that extends until February 2005, the end of the restructuring transition period. WMECO filed, and in 1999, the DTE approved, WMECO's restructuring plan. The plan allows WMECO's customers to choose their energy suppliers and allows WMECO to recover generation-related stranded costs. Two parties have appealed the DTE's decision on WMECO's restructuring plan to the Massachusetts Supreme Judicial Court. There has been no significant action in these appeals since they were filed in December 1999. In addition, the DTE-approved plan requires WMECO to procure competitively priced standard offer service and default service. These services provide power to customers that decline to purchase energy from a competitive supplier. WMECO competitively procured standard offer service and default service for 2000. For 2001, standard offer service has been procured as a composite rate of 7.383 cents per kilowatt-hour (kWh), including congestion costs. Default service has been procured through June 30, 2001, at a somewhat higher rate. In December 2000, WMECO requested that the DTE approve a standard offer service fuel adjustment for calendar year 2001. This fuel adjustment recognizes significant increases in fuel prices. On December 29, 2000, the DTE approved a fuel adjustment for standard offer customers of approximately 1.8 cents/kWh. The standard offer fuel adjustment and certain other rate factors offset, to some extent, by a slowing of the amortization of WMECO's stranded costs resulted in an average 17.4 percent rate increase for standard offer service customers as of January 1, 2001. A slightly higher increase was approved for default service customers as of February 1, 2001. Pursuant to the Massachusetts restructuring act, electric companies were required to divest their nonnuclear generation facilities. In July 1999, WMECO sold 290 MW of fossil and hydroelectric generation assets for $47 million to Consolidated Edison Energy Massachusetts, Inc. In March 2000, WMECO sold 272 MW of hydroelectric generation to NGC for approximately $184 million. In addition, in August 2000, WMECO agreed to sell its Millstone nuclear assets to Dominion. WMECO filed an application with the DTE in April 2000, requesting authorization to securitize a portion of its stranded costs. On February 7, 2001, the DTE approved the securitization of $155 million of stranded costs and issued the required financing order and in March 2001, WMECO received the approvals of the two Massachusetts state agencies directed by statute to oversee the bond issuance. The stranded costs to be securitized include the unrecovered plant balances of Millstone 2 and 3 and the buydown payment of one IPP contract. Final approval for the issuance of the rate reduction bonds must be obtained from the SEC. NEW HAMPSHIRE RATES AND RESTRUCTURING The state of New Hampshire's attempts to restructure the electric utility industry in that state have resulted in extensive litigation in various federal and state courts. In 1996, New Hampshire enacted legislation requiring a competitive electric industry beginning in 1997. In February 1997, the NHPUC issued restructuring orders that would have forced PSNH and NAEC to write off all of their regulatory assets and possibly seek protection under Chapter 11 of the bankruptcy laws. Following the issuance of these orders, PSNH obtained injunctive relief on various grounds from federal district court that prevents implementation of the NHPUC's restructuring orders. In September 2000, the NHPUC approved a Settlement Agreement intended to settle most of these proceedings. As required under the agreement, PSNH has written off in excess of $200 million after-tax of its stranded costs and will be allowed to recover the remaining amount. PSNH's obligations under the Settlement Agreement are contingent upon the issuance of $725 million in rate reduction bonds. In July 2000, the New Hampshire legislature endorsed the Settlement Agreement as approved by the NHPUC with several amendments. Other approvals are also required from the FERC and various financial lenders. Under the terms of the Settlement Agreement, as amended by the Legislature, customers' bills were reduced by 5 percent on October 1, 2000, and on the effective date, PSNH's rates will be further reduced from current levels by an average of 10.3 percent. The 5 percent rate reduction can be rescinded on April 1, 2001, if PSNH has not closed on the sale of rate reduction bonds by that time. The Settlement Agreement also requires PSNH to divest its generation assets and offer retail choice to its more than 420,000 electric customers following the sale of the rate reduction bonds. The net proceeds from all generation divestitures will be used to reduce PSNH's stranded costs. The sales are to be accomplished through a sale process administered by the NHPUC. Following the divestiture, the transmission and distribution portion of PSNH's business will continue to be cost-of-service regulated. On September 8, 2000, the NHPUC issued an order addressing various motions for clarification and the rehearing of its April 19, 2000, order. In its order, the NHPUC rejected motions for rehearing by various parties, granted the relief requested by PSNH related to certain regulatory obligations and reduced the amount PSNH could securitize from $725 million to up to $670 million, less $6 million for each month beginning October 2000, until competition begins, and found PSNH's compliance filing to be in conformance with New Hampshire law. The NHPUC also issued an order addressing specific issues related to securitization permitted under the Settlement Agreement. In October 2000, the securitization process and the implementation of the Settlement Agreement were delayed by two appeals of the NHPUC's order to the New Hampshire Supreme Court. The New Hampshire Supreme Court issued an order on January 16, 2001, rejecting both appeals, and on February 2, 2001, reaffirmed its decision. One of the appellants indicated publicly it would request a review of the New Hampshire decision by the United States Supreme Court. Such a request must be filed by May 1, 2001. Management believes that such an appeal would have a low probability of success, but cannot determine what effect it might have on the timing of the sale of rate reduction bonds and the implementation of customer choice. PSNH anticipates closing on its rate reduction bonds early in the second quarter of 2001, with competition to begin on the first day of the calendar month after such closing. In November 1999, the NHPUC also approved continuation of the fuel and purchased-power adjustment clause charge for PSNH at its current level until the beginning of electric supply choice in New Hampshire. In December 2000, PSNH filed divestiture plans with the NHPUC seeking approval to begin the process of selling its fossil and hydroelectric generation assets and NAEC's ownership share of Seabrook. COMPETITIVE SYSTEM BUSINESSES NU is engaged in a variety of competitive businesses. They are grouped essentially into two separate and distinct business activities: the competitive energy business and the telecommunications business. Select Energy is the lead competitive energy business within NU. Select Energy is an integrated energy business that buys, sells and markets electricity, gas and oil and energy-related products and services. Under the umbrella of the Select Energy brand, Select Energy, collectively with its affiliated competitive energy businesses, provides a wide range of energy products and energy services. These affiliated competitive energy companies include HEC, NGC, HWP, NGS, and SEPPI. With the exception of HEC, the competitive businesses operate primarily in the Northeast region of the United States. ENERGY-RELATED PRODUCTS AND SERVICES AND GAS INVESTMENTS Select Energy sells multiple energy products including electricity, natural gas and oil to wholesale and retail customers in the northeastern United States. Select Energy procures and delivers energy and capacity required to serve its electric, gas and oil customers. Select Energy is the largest wholesale and retail electric energy marketer in New England as measured by MW load. In order to support and complement its growing wholesale and retail business, Select Energy contracted in December of 1999 with NGC, its unregulated generation company affiliate, to purchase and market all of NGC's 1,289 MW for a 6-year period. These resources were acquired at auction from CL&P and WMECO. In addition, Select Energy is purchasing approximately 200 MW of coal and hydroelectric generating resources from HWP and more than 1,500 MW of electrical supply from various New England generating facilities on a long-term basis. Select Energy also utilizes generation failure insurance, options and energy futures to hedge its supply requirements. Moreover, Select Energy markets natural gas and develops and markets energy- related products and services. It offers energy management consulting and construction services through its affiliate, HEC, discussed more fully below. Select Energy and its integrated competitive energy business affiliates had aggregate revenues of approximately $1.9 billion in 2000, as compared to approximately $648.9 million in 1999, and contributed $13.6 million to consolidated earnings before extraordinary items in 2000, as compared to an aggregate loss of approximately $37 million in 1999. Select Energy is licensed to provide retail electric supply in Connecticut, Delaware, Maryland, New Jersey, Maine, Pennsylvania, New York, Massachusetts, Rhode Island, and New Hampshire. Within these states, Select Energy is currently registered with approximately 36 electric distribution companies and 52 gas distribution companies to provide retail services. Select Energy's goal is to be the regional leader in providing electric service to those Northeast markets opened to retail competition. In 2000, Select Energy provided more than 5,000 MW of standard offer load, making it the largest provider of standard offer service in the Northeast. During 2000, Select Energy provided several utilities with standard offer full requirements service and default services, comprising in the aggregate approximately 43 percent of its 2000 revenues. This included providing about 3,000 MW to a Massachusetts utility. A new contract for default service was signed with the same utility for a 6-month period in 2001. On January 1, 2000, Select Energy began serving one half of CL&P's standard offer load for a 4-year period. This equates to approximately 2,000 MW annually for each of the four contract years. Approximately 26 percent of 2000 competitive energy revenues came from this contract. The servicing of this load is a significant risk for Select Energy, as this contract is through the end of 2003, at fixed prices. This risk is partially mitigated by Select Energy entering into purchase contracts with other energy providers to supply a portion of the standard offer requirement, including its contracts with NGC, the purchase of 850 MW of output from the Millstone and Seabrook nuclear units through 2001, and other resources in the energy marketplace. Although there can be no assurance that it will be able to do so, management believes that Select Energy will be able to source its remaining load requirement at reasonable prices. If Select Energy is unable to source its remaining load requirement at prices below the standard offer contract price as a result of energy price increases, Select Energy's earnings would be adversely impacted. Select Energy has also entered into contracts with various retail customers to provide energy services at fixed rates. Under these retail contracts, Select Energy has the option to have the host utility provide energy services and is obligated to compensate the customer as defined in the contracts (CFD Payments). For the 12 months ended December 31, 2000, these CFD Payments totaled approximately $3.55 million. These CFD Payments may increase in the future. Policies and procedures have been established to manage these exposures, including the use of risk management instruments and the purchase of insurance for the output from the Millstone nuclear entitlements. In addition, beginning in January 2000, Select Energy assumed responsibility for serving approximately 500 MW of market-based wholesale contracts throughout New England with electric energy supply that was previously provided by CL&P and WMECO. For the most part, the prices are fixed by contract and applicable to actual volumes. As of December 31, 2000, Select Energy had contracts with high volume retail electric customers in states throughout the Northeast with primarily one-year terms. These contracts represent approximately 300 MW of load at about 10,000 service locations and include predominantly commercial, institutional and industrial accounts. This retail load is supplied by the Select Energy wholesale business line and establishes Select Energy among the largest competitive retail suppliers in New England as measured by MW load. However, recent significant increases in electric supply costs may cause the number of retail electric customers to decrease in the first quarter of 2001 as a result of contract expirations or terminations. There is no single retail customer that accounts for over 10 percent of Select Energy's expected retail revenues. The energy marketing business is intensely competitive. There are many large energy companies bidding for business in the increasingly restructured New England market. In 2000, the sharp increases in the cost of power supply caused by the extreme increases in oil and gas fuel costs, among other things, provided significant challenges and opportunities for Select Energy. In 2000, Select Energy increased its revenue by more than 300 percent over the 1999 revenue level, reporting $1.79 billion in 2000, as compared with $555 million in 1999. Disputes with respect to interpretation and implementation of the New England Power Pool (NEPOOL) market rules have arisen with respect to various competitive product markets. In certain cases, Select Energy and the NU operating companies stand to gain as a result of resolution of such disputes. In other cases, Select Energy and the NU operating companies could incur additional costs as a result of resolution of the disputes. These disputes are in various stages of resolution through alternative dispute resolution and regulatory review. It is too early to ascertain the level of potential gain or loss that may result upon resolution of these issues. During 2000, Select Energy significantly increased its competitive retail and wholesale natural gas business. Its revenue for this business segment increased from approximately $21 million in 1999, to approximately $221 million in 2000. As of December 31, 2000, Select Energy had contracts with approximately 2,000 retail gas customers, primarily located in Connecticut, Massachusetts and Pennsylvania. These contracts generally have one-year terms and include only commercial, institutional and industrial accounts. There is no single retail gas customer that accounts for over 5 percent of Select Energy's expected retail gas revenues. In 2000, Select Energy's retail gas revenues were approximately $67 million representing a 550 percent increase, as compared to 1999. The competitive retail gas business has contracted for approximately $100 million in gas sales which will extend into 2001 and 2002. ELECTRIC GENERATION AND SERVICES Select Energy buys, manages and markets the entire generation output from its unregulated generation affiliate, NGC, to retail and wholesale customers. NGC is a competitive business affiliate formed in 1999 to acquire generation facilities. In March 2000, NGC received 1,289 MW of hydroelectric and pumped storage generating assets in Connecticut and Massachusetts from CL&P and WMECO. These assets include seven hydroelectric facilities along the Housatonic River System (123 MW), the three facilities comprising the Eastern Connecticut System, including one gas turbine (27 MW), the Northfield Mountain pumped storage station and the Cabot and Turners Falls No. 1 hydroelectric stations located in Massachusetts previously owned by WMECO. NGC began selling the capacity and output of the plants to Select Energy for a period of 6 years in March 2000. HWP is another NU subsidiary which is considered part of the competitive energy businesses. Select Energy buys, markets and manages the entire generation output from its HWP affiliate. This generation consists of about 190 MW. HWP is selling all of its capacity and output to Select Energy through the end of December 2001, with annual or longer contract renewals available thereafter. Select Energy markets the entire output of electricity to retail and wholesale customers. HWP recognized as an extraordinary loss a decrease of $19.7 million, net of taxes in 2000, as a reduction in the value of its hydro assets. NGS was formed in 1999 to provide energy-related operation and maintenance services to owners of generation facilities and the industrial market in the Northeast. NGS currently focuses on providing turnkey management and operation services and also a full range of industrial and consulting services. Select Energy has contracted with NGS to operate and maintain all of the generating plants within the Select Energy affiliated businesses. NGS's industrial services include maintenance, permitting, environmental, and specialized electrical testing services to large and medium-sized industrial businesses. NGS also provides consulting services to these customers, including engineering and design, construction management, asset development, due diligence reviews and environmental regulatory compliance, and permitting services. During 2000, NGS's revenues were approximately $44 million and are expected to grow significantly in 2001. This anticipated growth will be due to NGS's increased geographical scope as a result of its recent acquisition of an electrical contracting business and a number of pending contracts with both new and repeat customers. ENERGY MANAGEMENT SERVICES As part of the Select Energy portfolio of products and services, Select Energy, in conjunction with its affiliate HEC, markets energy efficiency and design solutions to customers. In general, HEC contracts to reduce its customers' energy costs, improve their operating efficiency within their facilities and conserve energy and other resources. HEC's engineering, construction management and financing assistance services have been directed primarily to governmental and institutional markets and utilities in the eastern United States. HEC increased its vertical integration through its subsidiary Select Energy Contracting, Inc., which also provides mechanical and electrical contracting services in new construction and service contracts, primarily directed to commercial markets. In competitive procurements by the U.S. Departments of Defense and Energy during 1998 and 1999, HEC was selected as an "Energy Saving Performance Contractor" (ESPC) for all fifty states and overseas bases. Recent orders have been received calling for design, construction, financing, and long-term operation and maintenance of energy-efficient and environmentally clean systems to replace older infrastructure. Select Energy and HEC have recently begun construction of a central energy plant for a school in Middletown, Connecticut. This plant will include the largest U.S. installation of fuel cells yet achieved. In 2000, federal ESPC work constituted 27 percent of HEC's revenues, which were approximately $82.5 million (an increase of 20 percent over 1999). NU's aggregate equity investment in HEC was approximately $25 million as of December 31, 2000. GAS INVESTMENTS SEPPI was formed in March 1999 to hold a five percent partnership interest in the Portland Natural Gas Transmission System. SEPPI's investment in the project was $5.4 million as of December 31, 2000. During 2000, SEPPI recognized a $3.9 million reduction in the value of its investment. TELECOMMUNICATIONS Mode 1 was established in 1996 to participate in a wide range of telecommunications activities both within and outside New England. NU's cumulative, total investment in Mode 1 was approximately $10.1 million as of December 31, 2000. Mode 1 is a licensed competitive local exchange carrier authorized to provide local phone service within the state of Connecticut. Mode 1 currently owns approximately 4.8 million common shares of NEON Communications, Inc. (formerly NorthEast Optic Network, Inc.) (NEON), or 20.5 percent of its outstanding shares fully diluted (assuming the issuance of all shares to Consolidated Edison Communications, Inc. (CECI) and Exelon Ventures (Exelon), as discussed below). NEON is constructing a fiber optic communications network through New England, New York, Philadelphia, and Washington, D.C., utilizing a portion of the NU system companies' transmission and distribution facilities. An officer and trustee of NU and an officer of NUSCO are members of the Board of Directors of NEON. In addition, NU is a party to an agreement with Central Maine Power Company (CMP), an owner of approximately 19.2 percent of NEON's common shares, fully diluted, wherein NU and CMP each agree that, as long as NU owns at least 10 percent of the outstanding common stock of NEON, fully diluted, and the cumulative holdings of NU and CMP are at least 33 1/3 percent, fully diluted, neither NU nor CMP will take any action which will allow NEON to merge, consolidate, liquidate or sell, lease or transfer substantially all of its assets, or commence or acquiesce to any action or proceeding under any bankruptcy laws. In September 2000, CECI, a subsidiary of Con Edison, and Exelon, another unaffiliated company, acquired 10.75 and 9.25 percent, respectively, of NEON's common shares in exchange for contributions to NEON by each company of telecommunications assets in kind and cash. Mode 1 is party to two reciprocal agreements which commit it to vote for CMP's, CECI's and Exelon's nominees for director of NEON and such companies agree to support Mode 1's nominees. Under these arrangements, Mode 1 can presently designate two directors, and CMP, CECI and Exelon can designate two, one and one director(s), respectively. FINANCING PROGRAM 2000 FINANCINGS On March 1, 2000, NU completed its acquisition of Yankee. NU financed this acquisition with a combination of 11.1 million in newly issued shares and a $263 million term loan credit facility. On February 28, 2001, NU repaid this facility with the proceeds of a $263 million floating rate senior note issuance. The senior notes bore an effective interest cost of 6.9 percent at February 28, 2001, and mature in February 2003. Also, in anticipation of the Yankee acquisition, in late 1999 and early 2000, NU entered into forward share purchase arrangements with two financial institutions for a total of $215 million. These forward arrangements, which originally were due to expire on December 31, 2000, terminate on June 29, 2001. On March 14, 2000, CL&P and WMECO transferred to NGC certain of their hydroelectric generation assets. NGC financed this acquisition with a $435 million equity infusion from NU and a $430 million credit facility. In November 2000, the credit facility was extended from its original December 29, 2000, maturity date to June 29, 2001, with the ability to further extend to September 28, 2001, if certain conditions are met. On April 4, 2000, PSNH entered into two letters of credit and reimbursement agreements totaling $115.4 million, which support its Series D and E pollution control revenue bonds (PCRBs). The new letters of credit, which replaced similar letters of credit that were set to expire on April 12, 2000, allow the PCRBs to remain in a flexible, floating interest rate mode. On August 4, 2000, $39.5 million in principal amount of Series D PCRBs were redeemed and the related letter of credit and reimbursement agreement was terminated. On September 7, 2000, $69.7 million in principal amount of Series E PCRBs were redeemed and the related letter of credit and reimbursement agreement was terminated. On November 9, 2000, NAEC entered into an unsecured $200 million 364-day term credit agreement with four banks. This new facility replaced a 5-year $225 million term loan dated November 9, 1995, which had $200 million outstanding and was set to expire on November 9, 2000. An interest rate collar and swaps related to the $200 million 5-year term credit agreement also expired on November 9, 2000, and were not replaced. On November 17, 2000, NU entered into a new 364-day revolving credit facility for $400 million, replacing the previous $350 million revolving credit facility which was to expire on that date. The new credit facility is subject to two overlapping sublimits. First, subject to the notional amount of any letters of credit outstanding, amounts up to $300 million may be borrowed. Second, subject to outstanding borrowings, NU subsidiaries may access up to $200 million in letters of credit. On November 17, 2000, CL&P and WMECO entered into a new 364-day revolving credit facility for $350 million, replacing the previous $500 million facility, which was to expire on November 17, 2000. Under this agreement, CL&P and WMECO may borrow up to $200 million and $150 million, respectively. Once CL&P and WMECO receive the proceeds of securitization, the borrowing limits will be reduced to $250 million, with a $150 million limit for CL&P and a $100 million limit for WMECO. On November 17, 2000, Yankee Gas extended its $60 million revolving credit facility for an additional 364-day period from November 17, 2000, to November 16, 2001. Also on November 17, 2000, Yankee permanently retired $25 million of short-term bank debt. The level of common dividends totaled $57.4 million in 2000, up significantly from the $13.2 million paid in 1999. The increase was a result of NU paying a $0.10 per share quarterly common dividend for all of 2000, as compared to only paying a $0.10 per share dividend in the fourth quarter of 1999. Total NU system debt, including short-term and capitalized lease obligations, was $3.8 billion as of December 31, 2000, compared with $3.3 billion as of December 31, 1999. The increase was primarily due to the acquisition of Yankee. For more information regarding NU system financing, see "Notes to Consolidated Statements of Capitalization" in NU's financial statements, other footnotes related to long-term debt, short-term debt, and the sale of accounts receivables, as applicable, in the notes to NU's, CL&P's, PSNH's, WMECO's, and NAEC's financial statements and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." 2001 FINANCING REQUIREMENTS The NU system's aggregate capital requirements for 2001 are approximately as follows: CL&P PSNH WMECO NAEC Yankee Other NU system (Millions) Construction $231.3 $ 78.7 $26.6 $ 6.6 $39.2 $37.6 $420.0 Nuclear Fuel - - - 14.5 - - 14.5 Maturities 160.0 - 60.0 - - - 220.0 Cash Sinking Funds - 24.3 1.5 70.0 1.1 23.1 120.0 ------ ------ ----- ----- ----- ----- ------ Total $391.3 $103.0 $88.1 $91.1 $40.3 $60.7 $774.5 ====== ====== ===== ===== ===== ===== ====== For further information on the NU system's 2001 and 5-year financing requirements, see "Notes to Consolidated Statements of Capitalization" in NU's financial statements, "Long-Term Debt" in the notes to CL&P's, PSNH's, WMECO's, and NAEC's financial statements and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." 2001 FINANCING PLANS In 2001, NU expects to reduce the capitalization of its regulated electric subsidiaries significantly as a result of securitization of stranded costs and continued asset sales. NU expects its subsidiaries to receive about $830 million after expenses, certain cash settlements and taxes as a result of the sale of its interest in Millstone station to Dominion. The sale is projected to close as early as the end of March 2001. CL&P and WMECO will receive the vast majority of the $830 million (approximately $600 million for CL&P and more than $140 million for WMECO) and they are expected to use the cash to reduce their level of debt and capitalized lease obligations and to return equity capital to the parent company. In 2001, the Company hopes to complete the process of securitizing stranded costs for each of its major electric operating companies. In November 2000, the DPUC approved the securitization of up to $1.55 billion of CL&P's stranded costs, including the buyout and buydown of more than $1 billion in purchased power obligations. CL&P currently plans to securitize approximately $1.45 billion of these stranded costs in late March 2001. Of that sum, CL&P plans to use about $400 million to reduce debt. In September 2000, the NHPUC approved a comprehensive restructuring order that allows PSNH to securitize up to $670 million of stranded costs. In January 2001, the New Hampshire Supreme Court upheld the restructuring order on appeal and PSNH currently expects to work with the State of New Hampshire to issue securitization bonds early in the second quarter of 2001. Proceeds would be combined with cash on hand and used primarily to buy down the power contract between PSNH and NAEC, allowing a total reduction in debt at the two companies of approximately $300 million, the retirement of approximately $25 million of PSNH preferred stock and the return of equity capital to NU from PSNH and NAEC of another $375 million. By the end of 2002, PSNH also expects to complete the sale of approximately 1,200 megawatts of fossil and hydroelectric generating plants and all 418 megawatts of NAEC's share of Seabrook. PSNH's restructuring settlement was predicated upon PSNH and NAEC receiving approximately $400 million of net proceeds from those sales. In February 2001, the DTE approved the securitization of $155 million of stranded costs by WMECO. A significant amount of those proceeds would be used to buy out a purchased power contract with the remainder used to reduce WMECO's debt. WMECO hopes to complete the issuance early in the second quarter of 2001. Should NU's operating subsidiaries successfully complete all of the asset sales and securitization noted above, the regulated companies would receive in excess of $5 billion of cash between 1999 and 2002. Management currently expects NU's operating subsidiaries to use the proceeds in four primary ways. More than $2 billion would be used to repay debt and preferred stock; more than $1 billion to buy out and buy down high- cost nonutility generator arrangements; approximately $600 million to pay taxes on gains from the sale of generation assets; and approximately $1.2 billion would be returned to NU from these operating companies. Of that $1.2 billion, CL&P and WMECO repurchased $390 million of their common stock from NU in March 2000, the proceeds of which were immediately invested in NGC. NU will use another $215 million to settle the forward share purchase noted above. On February 28, 2001, NU issued $263 million aggregate principal amount floating rate notes due February 2003. The proceeds were used to pay off the $263 million term loan credit facility used to finance NU's acquisition of Yankee. In the first half of 2001, NGC expects to issue up to $440 million of long-term debt to replace the $430 million credit facility discussed above. Due to the fourth quarter write-down of certain assets owned by HWP, HWP did not meet its equity maintenance covenant under certain of its letter of credit and reimbursement agreements. In February 2001, HWP received a waiver to permit its common equity ratio to fall below 30 percent for the quarters ended December 31, 2000, March 31, 2001, and June 30, 2001. Thereafter, NU will provide a guarantee of HWP's obligations for the benefit of the banks. NU expects to receive approval from the SEC to implement this guarantee during the second quarter of 2001. FINANCING LIMITATIONS Many of the NU system companies' charters and borrowing facilities contain financial limitations that must be satisfied before borrowings can be made and for outstanding borrowings to remain outstanding. Under their current revolving credit facility, CL&P and WMECO are required to maintain a ratio of common equity to total capitalization (common equity ratio) of at least 30 percent. At December 31, 2000, CL&P's and WMECO's common equity ratios were 32.8 percent and 34.4 percent, respectively. This agreement also requires CL&P to maintain a 12-month earnings before interest and taxes to interest expense ratio (interest coverage ratio) of at least 2.5 to 1.0 for the quarters ending December 31, 2000, and March 31, 2001, and 3.0 to 1.0 thereafter. WMECO is required to maintain a quarterly interest coverage ratio of at least 2.0 to 1.0 for the quarters ending December 31, 2000, and March 31, 2001, and 2.2 to 1.0 thereafter. At December 31, 2000, CL&P's and WMECO's interest coverage ratios were 3.5 to 1 and 3.0 to 1, respectively. Under NU's revolving credit facility and its term loan credit agreement, NU is required to maintain a consolidated common equity ratio of at least 30 percent. At December 31, 2000, NU's consolidated common equity ratio was 35.1 percent. In addition, NU is required to maintain a 12-month consolidated interest coverage ratio of at least 2.0 to 1.0 for the quarters ending December 31, 2000, and March 31, 2001, and 2.2 to 1.0 thereafter. At December 31, 2000, NU's consolidated interest coverage ratio was 2.4 to 1.0. In addition, NU is required to maintain as of the end of each quarter with respect to the four quarters then ended a ratio of operating cash flow to fixed charges (cash flow ratio) of at least 1.5 to 1.0. At December 31, 2000, NU's cash flow ratio was 2.1 to 1.0. These agreements also limit NU's ability, without creditor approval, to incur additional debt and to make future investments, including acquisitions in excess of $25 million and investments in Select Energy and other subsidiaries in excess of $200 million and $100 million, respectively. NAEC is party to a 364-day term credit agreement which provides that outstanding advances can be terminated or accelerated if NAEC does not maintain specified minimum ratios of common equity to capitalization (as defined in the agreement). For NAEC, the minimum common equity ratio under its term credit agreement is 25 percent; at December 31, 2000, NAEC's common equity ratio was 32.4 percent. The agreement also requires a 12-month adjusted net income to interest expense ratio (interest coverage ratio) of not less than 1.5 to 1.0. At December 31, 2000, the ratio for NAEC was 2.0 to 1.0. The term credit agreement also provides for mandatory prepayment of 50 percent of the aggregate principal amount of advances outstanding within two days of a buydown of NAEC's interest in Seabrook (Seabrook Interest) to $100 million as contemplated by the PSNH restructuring Settlement Agreement, and prepayment of 100 percent within two business days of the sale of the Seabrook Interest or earlier termination of the Unit Contract as contemplated by the PSNH restructuring Settlement Agreement. The 364-day term credit agreement also limits NAEC's other unsecured debt to $60 million. Under Yankee Gas' 364-day revolving credit facility, Yankee Gas is required to maintain a common equity to stockholder's equity (common equity ratio) of at least 37.5 percent and to maintain stockholders' equity of at least $90 million. At December 31, 2000, Yankee Gas' common equity ratio was 75.0 percent and its consolidated stockholder's equity was $467.2 million. Yankee Gas is also required to maintain a 12-month interest coverage ratio of at least 2.0 to 1.0 for each fiscal quarter. At December 31, 2000, Yankee Gas's interest coverage ratio was 4.2 to 1.0. The amount of short-term debt that may be incurred by NU, CL&P, WMECO, PSNH, NNECO, HWP, and NAEC is also subject to periodic approval by the SEC under the Public Utility Holding Company Act of 1935 (1935 Act). PSNH's and NAEC's short-term debt in excess of 10 percent of net fixed plant is also regulated by the NHPUC. The following table shows the amount of short-term borrowings authorized by the SEC or the NHPUC for each company, as the case may be, as of December 31, 2000, and the net amounts of outstanding short-term debt and cash investments of those companies at the end of 2000 and as of March 1, 2001: Short-Term Debt Outstanding (Cash Investments) (1) Maximum Authorized ------------------ Short-Term Debt December 31, 2000 March 1, 2001 ------------------ ----------------- ------------- (Millions) NU Parent $400.0 $ 144.6 $ 182.5 CL&P 375.0 77.0 47.6 PSNH (2) 225.0 (110.0) (62.9) WMECO 250.0 110.6 90.7 HWP 5.0 (16.2) (17.1) NAEC(3) 260.0 172.2 132.8 NNECO 75.0 (9.3) 16.8 Yankee Parent 50.0 - (1.5) Yankee Gas 100.0 49.6 48.1 Other N/A 71.2 134.7 ------- ------- Total $ 489.7 $ 571.7 ======= ======= (1) These columns include borrowings of or cash investments by various NU system companies from NU and other NU system companies excluding borrowings under the NU term loan credit agreement and NGC credit facility. Total NU system short-term indebtedness to unaffiliated lenders excluding the NU term loan facility and NGC credit facility was $644.6 million at December 31, 2000, and $598 million at March 1, 2001. The NU term loan facility was separately approved by the SEC and is not considered short-term debt for purposes of the SEC authorization noted above. NGC's short-term debt is not subject to SEC approval. At December 31, 2000, NU had $263 million borrowed under the NU term loan facility and NGC had $403 million borrowed under the NGC credit facility. As of March 1, 2001, NU had paid off the $263 million term loan facility with proceeds from a $263 million debt issuance and NGC had $388 million borrowed under the NGC credit facility. (2) Under applicable NHPUC provisions, PSNH can incur short-term debt up to 10 percent of net fixed plant. As of December 31, 2000, PSNH's net fixed plant as measured by FERC was approximately $712.9 million; accordingly, PSNH could borrow up to $71.3 million of short-term debt. (3) Under applicable NHPUC regulations, NAEC can incur short-term debt up to 10 percent of net fixed plant. As of December 31, 2000, NAEC's net fixed plant as measured by FERC was approximately $524.8 million; accordingly, NAEC could borrow up to $52.5 million of short-term debt. In connection with the issuance of NAEC's 364-day term credit agreement, NAEC obtained NHPUC approval for a short-term debt limit of $260 million, representing $200 million of borrowings under the 364-day term credit agreement and $60 million of other short-term debt. The supplemental indentures under which NU issued $175 million in principal amount of 8.58 percent amortizing notes in December 1991, and $75 million in principal amount of 8.38 percent amortizing notes in March 1992, contain restrictions on dispositions of certain NU system companies' stock, limitations of liens on NU assets and restrictions on distributions on and acquisitions of NU stock. Under these provisions, NU, CL&P, PSNH, and WMECO may not dispose of voting stock of CL&P, PSNH or WMECO other than to NU or another NU system company, except that CL&P may sell voting stock for cash to third persons if so ordered by a regulatory agency so long as the amount sold is not more than 19 percent of CL&P's voting stock after the sale. The restrictions also generally prohibit NU from pledging voting stock of CL&P, PSNH or WMECO or granting liens on its other assets in amounts greater than 5 percent of the total common equity of NU. Many of the NU system companies' credit agreements have similar restrictions. As of December 31, 2000, no NU debt was secured by liens on NU assets. Furthermore, NU may not declare or make distributions on its capital stock, acquire its capital stock (or rights thereto), or permit a NU system company to do the same, at times when there is an event of default under the supplemental indentures under which the amortizing notes were issued. Pursuant to its revolving credit facility and the $263 million term loan credit agreement, NU may not declare dividends or make distributions, except for dividends not to exceed $60 million during any 12-month period and stock repurchases of up to $215 million in connection with the Yankee merger. Similar restrictions are found in NU's merger agreement with Con Edison. The charters of CL&P and WMECO contain preferred stock provisions restricting the amount of unsecured debt those companies may incur. As of December 31, 2000, CL&P's and WMECO's charters permit CL&P and WMECO to incur an additional $245 million and $94 million, respectively, of unsecured debt. The indentures securing the outstanding first mortgage bonds of CL&P, PSNH, WMECO, and NAEC provide that additional bonds may not be issued, except for certain refunding purposes, unless earnings (as defined in each indenture and before income taxes, and, in the case of PSNH, without deducting the amortization of PSNH's regulatory asset), are at least twice the pro forma annual interest charges on outstanding bonds, and certain prior lien obligations and bonds to be issued. While CL&P's and WMECO's 2000 earnings permit them to meet those earnings coverage tests, certain loan agreements prohibit the issuance of additional first mortgage bonds. The preferred stock provisions of CL&P's and WMECO's charters also prohibit the issuance of additional preferred stock (except for refinancing purposes) unless income before interest charges (as defined and after income taxes and depreciation) is at least 1.5 times the pro forma annual interest charges on indebtedness and the annual dividend requirements on preferred stock that will be outstanding after the additional stock is issued. CL&P's and WMECO's earnings currently permit them to meet those earnings tests. However, the companies are not expected to issue preferred stock during 2001. Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt agreements. These restrictions also limit the amount of retained earnings available for NU common dividends. At December 31, 2000, retained earnings available for the payment of dividends totaled $180.1 million. CL&P and WMECO's revolving credit agreement requires the companies to maintain at all times a ratio of common equity to total capitalization of at least 30 percent. At December 31, 2000, this requirement would allow CL&P and WMECO to make additional distributions from common equity of $90 million and $31 million, respectively. Under NAEC's first mortgage bond indenture, all retained earnings are available for payment or distribution, plus an allowance of $10 million, subject however to restrictions under New Hampshire statutes and the Federal Power Act, which limit the payment of dividends to book retained earnings. At December 31, 2000, NAEC's retained earnings was approximately $0.4 million. During much of 2000, PSNH was prohibited from paying dividends on its common stock and from investing any funds in the NU system money pool without NHPUC approval. Payment of a $50 million dividend at the time of the temporary rate reduction contemplated by the Settlement Agreement was authorized pursuant to New Hampshire law and was paid by PSNH to NU on October 1, 2000. In its finance order regarding securitization, the NHPUC authorized investment of PSNH funds in the NU system money pool upon the write-off required by the Settlement Agreement, which write-off was taken in the fourth quarter of 2000. PSNH is now participating in the money pool and can pay dividends on its common stock without NHPUC approval. New Hampshire statutes and the Federal Power Act limit the payment of dividends by PSNH to retained earnings. At December 31, 2000, PSNH's retained earnings was approximately $123 million. Applicable merger accounting rules require that upon acquisition by NU, Yankee's and its subsidiaries' retained earnings were reclassified as capital surplus. Also, the merger premium NU paid to acquire Yankee was allocated among Yankee and its subsidiaries and "pushed down" to their balance sheets and under current accounting rules is being amortized to expense. Under existing accounting conventions, the majority of the merger premium will be amortized over 40 years. The Financial Accounting Standards Board is currently evaluating merger accounting. The current proposal would no longer require companies to amortize goodwill as an expense to the income statement. Instead goodwill will be evaluated for impairment and any impairments to goodwill would be charged to expense. It is expected the new accounting rule will be effective January 1, 2002. If enacted, the effect will be an approximately $8 million annual reduction in goodwill expense. Under the 1935 Act, subsidiaries of registered holding companies are only allowed to pay dividends out of retained earnings unless the SEC allows otherwise. The effect of this rule would be to prevent Yankee from paying dividends to NU from any source other than post-merger earnings, as reduced by the merger premium amortization. NU has received permission from the SEC, through June 2002, for Yankee and Yankee Gas to pay dividends (i) out of additional paid-in capital up to the amount of their respective retained earnings just prior to the merger with NU and (ii) out of earnings before the amortization of the merger goodwill (gross earnings) in the case of Yankee Gas and out of distributed earnings in the case of Yankee. To assure that Yankee Gas has sufficient cash to fund operations, Yankee Gas will not pay dividends in excess of 80 percent of gross earnings on a rolling 5-year average basis. In no case would dividends be paid by Yankee or Yankee Gas if their common equity to total capitalization ratios were below 35 percent. NU has also received permission from the SEC, through June 2002, for Yankee and Yankee Gas to repurchase their common stock such that their common equity to total capitalization ratios do not fall below 35 percent. NU is required under the 1935 Act to maintain its consolidated common equity at a level equal to at least 30 percent of its consolidated capitalization. Following the issuance of rate reduction bonds by its subsidiaries, NU will temporarily be unable to meet this standard because such bonds, although nonrecourse to the NU system company issuers, are considered to be indebtedness of the companies under generally accepted accounting principles. The SEC has authorized the consolidated common equity ratio of NU to fall below 30 percent through December 31, 2001. The 30 percent test also applies to NU's electric operating subsidiaries. The SEC has authorized the common equity ratios of CL&P, WMECO and PSNH to fall below 30 percent through December 31, 2001. NU provides credit assurance in the form of guarantees, letters of credit, performance guarantees, and other assurances for the financial performance obligation of certain of its unregulated subsidiaries, particularly Select Energy. NU currently has authorization from the SEC to provide up to $500 million of guarantees. In addition, NU is limited under its revolving credit facility and its term loan credit agreement to $500 million of such arrangements without creditor approval. As of December 31, 2000, and March 1, 2001, NU had provided approximately $284 million and $376 million, respectively, of such credit assurances. Certain NU system credit agreements also have covenants or trigger events tied to credit ratings of certain NU system companies. CONSTRUCTION PROGRAM The NU system's construction program expenditures, including allowance for funds used during construction, is estimated to be in the range of from $395 million to $420 million in 2001. Of such total amount, approximately $206 million to $231 million is expected to be expended by CL&P, $79 million by PSNH, $27 million by WMECO, $7 million by NAEC, $11 million by NGC, $39 million by Yankee, and up to $26 million by other system entities. This construction program data includes all anticipated costs necessary for committed projects and for reasonably expected to become committed projects in 2001, regardless of whether the need for the project arises from environmental compliance, reliability requirements, nuclear safety, or other causes. The data assumes the sale of the Millstone units on March 30, 2001. The construction program's main focus in maintaining and upgrading the existing transmission and distribution system and nuclear and hydroelectric generation assets. The system expects to evaluate its needs beyond 2001 in light of future developments, such as restructuring, industry consolidation, performance, and other events. REGULATED ELECTRIC OPERATIONS DISTRIBUTION AND SALES CL&P, PSNH and WMECO furnish retail franchise service in 149, 198 and 59 cities and towns in Connecticut, New Hampshire and Massachusetts, respectively. In December 2000, CL&P furnished retail franchise service to approximately 1.13 million customers in Connecticut, PSNH provided retail service to approximately 434,000 customers in New Hampshire and WMECO served approximately 199,000 retail franchise customers in Massachusetts. HWP serves 30 retail customers in Holyoke, Massachusetts. The following table shows the sources of 2000 electric franchise retail revenues based on categories of customers: CL&P PSNH WMECO Total NU System Residential........ 46% 41% 40% 4% Commercial......... 39% 35% 37% 38% Industrial......... 14% 23% 22% 7% Other.............. 1% 1% 1% 1% --- --- --- --- Total.............. 100% 100% 100% 100% === === === === The actual changes in retail kWh sales for the last two years and the forecasted retail sales growth estimates for the 10-year period 2000 through 2010 for CL&P, PSNH and WMECO are set forth below: 2000 over 1999 over Forecast 2000-2010 1999 1998 Compound Rate of Growth NU system.......... 0.9% 3.8% 1.3% CL&P............... 0.4% 2.9% 1.2% PSNH............... 2.6% 5.3% 2.0% WMECO.............. -0.1% 3.6% 1.0% Consolidated NU retail sales rose by 0.9 percent in 2000, compared with 1999, primarily due to higher heating requirements and the strong economy, offset by lower cooling requirements. Residential electric sales were up 0.2 percent. Commercial sales were up by 1.3 percent for the year and industrial sales increased by 1.1 percent. Retail sales for all of the NU system electric operating companies increased in 2000 with CL&P, WMECO and PSNH sales up 0.4 percent, down 0.1 percent and up 2.6 percent, respectively. REGIONAL AND SYSTEM COORDINATION The NU system companies and most other New England utilities are parties to an agreement (NEPOOL Agreement), which provides for coordinated planning and operation of the region's generation and transmission facilities. The NEPOOL Agreement was restated and revised as of March 1997 to provide for (i) a pool- wide open access transmission tariff; (ii) the creation of an Independent System Operator (ISO), and; (iii) a broader governance structure for NEPOOL and a more open, competitive market structure. Under these new arrangements the ISO, a nonprofit corporation whose board of directors and staff are not controlled by or affiliated with market participants, ensures the reliability of the NEPOOL transmission system, administers the NEPOOL tariff and oversees the efficient and competitive functioning of the regional power market. The NEPOOL tariff provides for nondiscriminatory open access to the regional transmission network at a single rate regardless of transmitting distance for all transactions. The rate is a formula, structured to ensure that each transmission provider under the NEPOOL tariff recovers its revenue requirements. In 1999, the NEPOOL Executive Committee filed a comprehensive settlement of all issues set for hearing concerning the NEPOOL transmission tariff. The settlement resolves disputes concerning the calculation of revenue requirements for transmission over NEPOOL facilities and resolves disputes over alleged "double charges" under grandfathered transmission contracts retained by individual transmission providers, including NU. The settlement also includes a ROE component which sets the ROE for each individual transmission provider owning NEPOOL transmission facilities with respect to those facilities from March 1, 1997, through at least June 1, 2000, provided no changes to individual network transmission tariff rates are made after December 31, 1999. NU's ROE has been set at 11.75 percent. NU has made no changes to its transmission tariff rates since the settlement was reached; accordingly, its ROE has remained unchanged. As part of the settlement, the ISO is required to independently audit the charges in effect for the period June 1997 through May 2000, or direct that such an audit be conducted under its supervision. In June 2000, the ISO engaged an independent auditing firm to conduct such an audit. The audit remains ongoing and the results of the audit will be filed at the FERC as an informational filing. In December 2000, NU was notified by the FERC that it, along with several other companies, would be the subject of a separate FERC industry-wide audit of the accounting related to formula rate transmission tariffs. The FERC commenced its audit of NU in February 2001. Two agreements determine the manner in which costs and savings are allocated among the NU system electric operating companies. Under an agreement (NUG&T) among CL&P, WMECO and HWP, these companies pool their electric production costs and the costs of their principal transmission facilities. Pursuant to the merger agreement between NU and PSNH, these companies and PSNH entered into a 10-year sharing agreement (Sharing Agreement), expiring in June 2002, that provides, among other things, for the allocation of the capability responsibility savings and energy expense savings resulting from a single- system dispatch through NEPOOL. The NUG&T was revised in 1999 to eliminate the generation aspects of the agreement. Revision to the NUG&T was initially contested by the Massachusetts Attorney General, who claimed that such revision would result in stranded costs being transferred unfairly to WMECO. In July 1999, the FERC approved the proposed amendment subject to the outcome of a hearing which was held in abeyance pending the outcome of state restructuring proceedings. The DTE rejected the Massachusetts Attorney General's arguments in a December 1999 order. While the FERC hearing continues to be held in abeyance, NUSCO and the Massachusetts Attorney General reached settlement on a number of issues related to restructuring in Massachusetts. As part of that settlement, the Massachusetts Attorney General withdrew its opposition to the revisions to the NUG&T. The FERC approved such withdrawal in September 2000. The Settlement Agreement between PSNH and the state of New Hampshire was approved by the NHPUC on April 19, 2000. Accordingly, NU will file for FERC approval to terminate the Sharing Agreement, as mandated by the Settlement Agreement, effective December 31, 2000. Only minor revenue changes are expected in the future as no energy or capacity transactions have taken place under the Sharing Agreement since CL&P and WMECO relinquished their responsibilities to meet customer loads on January 1, 2000. Transmission revenues will be allocated going forward based upon the respective companies' cost of service where these revenues had been split equally by PSNH and CL&P under the Sharing Agreement. On March 6, 2001, the FERC issued an order on rehearing related to the price for installed capacity (ICAP) in New England. The FERC reinstituted the previously approved $8.75 per kilowatt-month charge for installed capacity, but made the price effective April 1, 2001. In an earlier decision in December 2000, the FERC had made the charge effective as of August 1, 2000, but in its revised decision, the FERC substituted a $0.17 per kilowatt- month charge for the period of August 2000 through March 2001. Because NU was a major seller of installed generating capacity during the last five months of 2000, the FERC's revised decision with respect to the August through March time period reduced NU's fourth quarter revenues by $24.6 million and lowered earnings by $14.8 million, or $0.10 per share. On March 16, 2001, NU filed with the FERC for rehearing of its order. On the same day, several utilities, the Massachusetts Attorney General and the Maine Public Utilities Commission appealed that portion of the FERC's order reinstituting the $8.75 charge on a going-forward basis to the First Circuit U.S. Appeals Court. TRANSMISSION ACCESS AND FERC REGULATORY CHANGES Pursuant to FERC Order 888 (issued in April 1996), NU system companies operate their transmission system under an open access, nondiscrimatory transmission tariff. In December 1999, the FERC issued an order calling on all transmission owners to voluntarily join regional transmission organizations (RTOs) in order to boost competition in electric markets (Order 2000). In general, each such organization would be an independent operator over all transmission facilities, and would perform, among other functions, tariff administration, construction planning and reliability management for the particular regional transmission system. NU's active voting interest in such an organization would be limited to 5 percent under the proposal. NU system companies and other parties have appealed this order. Of primary concern to NU is the ratemaking authority granted to RTOs and its impact on the ability of transmission owners to earn appropriate returns on their transmission investment under the organizational structure and the minimum functions proposed in the order. The NU system companies are required to participate in a collaborative process established by the FERC beginning in March of 2000. On January 16, 2001, NU along with the ISO and five other New England transmission owning utilities (National Grid, USA, The United Illuminating Company, Bangor Hydro-Electric Company, CMP and Vermont Electric Company) filed a proposal to establish a New England Regional Transmission Organization (NERTO) in compliance with FERC's order. As proposed, NERTO would consist of the ISO and a newly formed for-profit independent transmission company (Northeast ITC). Pursuant to an RTO agreement, both entities would share the minimum required functions of an RTO set forth in the FERC order. The ISO would be primarily responsible for short-term reliability functions and Northeast ITC would operate (but not initially own) the transmission assets of the participating transmission owners, develop and administer a transmission tariff, and engage in transmission planning and expansion activities. NU would be a shareholder in Northeast ITC and would appoint a member of the board of directors. NU's voting interest would remain capped at five percent, consistent with the requirement of the FERC order, until a change in law or regulation that would permit NU to have an increased voting interest. The NERTO proposal will require changes to the existing NEPOOL arrangements. Proposals for such changes continue to be discussed in regional meetings. The NERTO proposal will also require changes to the NEPOOL tariff and NU's other transmission tariffs and agreements. Provided the NERTO proposal is approved, NU expects to file tariff changes later this year. Since NEPOOL established competitive wholesale markets in 1999, congestion costs (the cost of higher energy prices within the New England market due to transmission constraints) have grown steadily surpassing $150 million in total by year end 2000. The ISO New England made a filing at the FERC in March 2000 to implement a congestion management system (CMS) similar to those in use in the New York ISO and Pennsylvania - New Jersey - Maryland Interconnection. CMS uses locational based pricing to assign costs to regional load zones, within New England. Individual load zones will experience higher or lower congestion costs as the CMS will replace the current practice of distributing and averaging congestion costs across all New England loads. The FERC's response to the ISO New England's CMS filing encouraged early implementation (less than a year); the ISO New England has indicated implementation will take 18 to 24 months. The current estimate for implementation of the CMS is during the first quarter of 2002. REGULATED GAS OPERATIONS REGULATION Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers and size of service territory. Total throughput (sales and transportation) for 2000 was 52.6 billion cubic feet. In 2000, total gas operating revenue of $345 million were comprised of the following: 48 percent residential; 28 percent commercial; 20 percent industrial, and; the remaining 4 percent other. Yankee Gas provides firm gas sales service to customers who require a continuous gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs. Yankee Gas also provides interruptible gas sales service to certain commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice. Yankee Gas can interrupt service to these customers during peak demand periods. Yankee Gas offers firm and interruptible transportation services to customers who purchase gas from sources other than Yankee Gas. In addition, Yankee Gas performs gas exchanges and capacity releases to marketers to reduce its overall gas expense. Although Yankee Gas is not subject to FERC jurisdiction, the FERC does regulate the interstate pipelines serving Yankee Gas' service territory. Yankee Gas, therefore, is directly and substantially affected by the FERC's policies and actions. Accordingly, Yankee Gas closely follows and, when appropriate, participates in proceedings before the FERC. Yankee Gas is subject to regulation by the DPUC, which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency, and construction and operation of distribution, production and storage facilities. The DPUC may, after a special public hearing, order an interim rate decrease if it finds that Yankee Gas' ROE exceeds a reasonable rate of return and rates are more than just, reasonable and adequate as determined by the DPUC. The DPUC also is empowered to grant an interim rate increase under compelling circumstances. On August 9, 2000, Yankee Gas was ordered by the DPUC to file a rate application. This review of Yankee Gas' rates is required under Connecticut law because 4 years have passed since its last rate review. In accordance with the most recent schedule approved by the DPUC, Yankee Gas filed a cost of service study on February 14, 2001, which reflected a historical test year ending September 30, 2000. Yankee Gas has asked the DPUC to approve a schedule that would call for Yankee Gas to file a letter of intent in May 2001, and its full filing in July 2001. NUCLEAR GENERATION GENERAL Certain NU system companies have ownership interests in four nuclear units, Millstone 1, 2 and 3 and Seabrook, and equity interests in four regional nuclear companies (the Yankee Companies) that separately own the Connecticut Yankee nuclear unit (CY), the Maine Yankee nuclear unit (MY), the Vermont Yankee nuclear unit (VY), and the Yankee Rowe nuclear unit (Yankee Rowe). NU system companies operate Millstone 2 and 3 and Seabrook. Yankee Rowe, CY, MY, and Millstone 1 have been permanently removed from service. CL&P and WMECO own 100 percent of Millstone 1 and 2 as tenants in common. Their respective ownership interests in each unit are 81 percent and 19 percent. CL&P, PSNH and WMECO have agreements with other New England utilities covering their joint ownership as tenants in common of Millstone 3. CL&P's, PSNH's and WMECO's ownership interests in the unit are 52.93, 2.85 and 12.24 percent, respectively. NAEC and CL&P have 35.98 percent and 4.06 percent ownership interests, respectively, in Seabrook. In 1996, one of the joint owners of Millstone 3, the Vermont Electric Generation and Transmission Cooperative, Inc. (VEG&T), filed for bankruptcy. The subsequent liquidation resulted in the offering of VEG&T's 0.35 percent share of Millstone 3 for sale to the joint owners of Millstone 3. None of the non-NU joint owners accepted the offer. The VEG&T ownership interest in Millstone 3 is included in the sale of the unit to Dominion. The Millstone 3 and Seabrook joint ownership agreements provide for pro- rata sharing by the owners of each unit of the construction and operating costs, the electrical output and the associated transmission costs. CL&P and WMECO, through NNECO as agent, operate Millstone 3 at cost, and without profit, under a sharing agreement that obligates them to utilize good utility operating practice and requires the joint owners to share the risk of employee negligence and other risks pro-rata in accordance with their ownership shares. The sharing agreement provides that CL&P and WMECO would only be liable for damages to the minority owners for a deliberate breach of the agreement pursuant to authorized corporate action. CL&P, PSNH, WMECO, and other New England electric utilities are the stockholders of the Yankee Companies. Each Yankee Company owns a single nuclear generating unit. The stockholder-sponsors of each Yankee Company are responsible for proportional shares of the operating and decommissioning costs of the respective Yankee Company and are entitled to proportional shares of the electrical output in the case of VY, which is the only operating unit of the four Yankee Companies set forth below. The relative rights and obligations with respect to the Yankee Companies are approximately proportional to the stockholders' percentage stock holdings, but vary slightly to reflect arrangements under which nonstockholder electric utilities have contractual rights to some of the output of particular units. CL&P's, PSNH's and WMECO's stock ownership percentages in the Yankee Companies are set forth below: CL&P PSNH WMECO NU system Connecticut Yankee Atomic Power Company (CYAPC) ...... 34.5% 5.0% 9.5% 49.0% Maine Yankee Atomic Power Company (MYAPC) ............ 12.0% 5.0% 3.0% 20.0% Vermont Yankee Nuclear Power Corporation (VYNPC)... 9.5% 4.0% 2.5% 16.0% Yankee Atomic Electric Company (YAEC) ............ 24.5% 7.0% 7.0% 38.5% In 1999, VYNPC agreed to sell its nuclear generating unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company would have agreed to assume the obligation to decommission the unit after it is taken out of service, and the owners of VYNPC (including CL&P, WMECO and PSNH) agreed to fund their shares of the decommissioning costs up to a negotiated amount. Subsequent to the time that agreement was executed, the original proposed acquiring company has increased the price it agreed to pay and three other unaffiliated companies have indicated their interest in buying VYNPC's generating unit on terms that have not been disclosed. Participants in the Vermont regulatory proceeding, including VYNPC, have argued that it is most appropriate for the unit to be sold in an open auction proceeding. On February 14, 2001, the Vermont Public Service Commission rejected the agreement to sell VY to the proposed purchaser. VYNPC is reviewing its options relating to VY, including the possibility of an auction. At present, CL&P, WMECO and PSNH expect that the unit will be sold, but the identity of the owner and the terms of sale, including price, future decommissioning obligations and future power purchase obligations, are not known. The operators of Millstone 2 and 3, VY and Seabrook hold full term operating licenses from the NRC and are subject to the jurisdiction of the NRC. The NRC has broad jurisdiction over the design, construction and operation of nuclear generating stations, including matters of public health and safety, financial qualifications, antitrust considerations, and environmental impact. The NRC issues 40-year initial operating licenses to nuclear units and NRC regulations permit renewal of licenses for an additional 20-year period. The NRC also has jurisdiction over the decommissioning activities at Yankee Rowe, CY, MY, and Millstone 1. The NRC also regularly conducts generic reviews of technical and other issues, a number of which may affect the nuclear plants in which NU system companies have interests. The cost of complying with any new requirements that may result from these reviews cannot be estimated at this time, but such costs could be substantial. NUCLEAR PLANT PERFORMANCE MILLSTONE 3 Millstone 3 has a license expiration date of November 25, 2025. In 2000, Millstone 3 operated at a capacity factor of virtually 100 percent. On February 3, 2001, Millstone 3 began a scheduled refueling outage and is expected to return to service during March 2001. MILLSTONE 2 Millstone 2 has a license expiration date of July 31, 2015. Millstone 2 returned to service on June 1, 2000, following a 41 day outage, which began in April 2000, and achieved a 97.4 percent capacity factor from that date to December 31, 2000. For the full year 2000, Millstone 2 operated at a capacity factor of 82 percent. SEABROOK Seabrook has a license expiration date of October 17, 2026. In 2000, Seabrook operated at a capacity factor of 78 percent. After an extended 101- day refueling and maintenance outage due to repairs to an emergency diesel generator, Seabrook returned to service on January 29, 2001. VERMONT YANKEE VY has a license expiration date of March 21, 2012. In 2000, VY operated at a capacity factor of 99.2 percent. NUCLEAR INSURANCE For information regarding nuclear insurance, see "Commitments and Contingencies - Nuclear Insurance Contingencies" in the notes to NU's, CL&P's, PSNH's, WMECO's, and NAEC's financial statements. NUCLEAR FUEL GENERAL The supply of nuclear fuel for the NU system's existing units requires the procurement of uranium concentrates, followed by the conversion, enrichment and fabrication of the uranium into fuel assemblies suitable for use in the NU system's units. Fuel may also be purchased at a point after any of the above processes are completed. The NU system expects that uranium concentrates and related services for the units operated by the NU system and for the other units in which the NU system companies are participating that are not covered by existing contracts, will be available for the foreseeable future on reasonable terms and prices. As a result of the Energy Policy Act, the United States commercial nuclear power industry is required to pay the United States Department of Energy (DOE), through a special assessment, for the costs of the decontamination and decommissioning of uranium enrichment plants owned by the United States government, no more than $150 million per annum for 15 years beginning in 1993. Each domestic nuclear utility's payment is based on its pro-rata share of all enrichment services received by the United States commercial nuclear power industry from the United States government through October 1992. Each year, the DOE adjusts the annual assessment using the Consumer Price Index. The Energy Policy Act provides that the assessments are to be treated as reasonable and necessary current costs of fuel, which costs shall be fully recoverable in rates in all jurisdictions. The NU system's remaining share to be recovered, assuming no escalation, is approximately $28.9 million as of December 31, 2000. Management believes that the DOE assessments against CL&P, WMECO, PSNH, and NAEC will be recoverable in future rates. Accordingly, each of these companies has recognized these costs as a regulatory asset, with a corresponding obligation on its balance sheet. In 1998, an action was initiated by the owners of Millstone in the U.S. Court of Federal Claims against the DOE regarding the special annual assessment that the DOE imposes on purchasers of enriched uranium to meet the future costs of decontaminating and decommissioning (D&D) government owned uranium enrichment facilities. Similar actions for Seabrook and CY were also filed. The lawsuits challenge the imposition of the D&D assessment on federal constitutional grounds, and are similar to actions filed by a number of other utilities against DOE. Proceedings in the Millstone, Seabrook and CY cases are stayed pending the final resolution of a similar claim brought against the DOE by MYAPC. In July 1999, the claims court dismissed MYAPC's complaint. MYAPC's appeal of this decision is pending before the court. As of December 31, 2000, the NU system companies had paid approximately $41.7 million into the fund. Nuclear fuel costs associated with nuclear plant operations include amounts for disposal of spent nuclear fuel. The NU system companies include in their nuclear fuel expense spent fuel disposal costs accepted by the DPUC, NHPUC and DTE in rate case or fuel adjustment decisions. Spent fuel disposal costs also are reflected in the FERC-approved wholesale charges. HIGH-LEVEL RADIOACTIVE WASTE The Nuclear Waste Policy Act of 1982 (NWPA) provides that the federal government is responsible for the permanent disposal of spent nuclear reactor fuel (SNF) and high-level waste. As required by the NWPA, electric utilities generating SNF and high-level waste are obligated to pay fees into a fund which would be used to cover the cost of siting, constructing, developing, and operating a permanent disposal facility for this waste. The NU system companies have been paying for such services for fuel burned on or after April 7, 1983, on a quarterly basis since July 1983. The DPUC, NHPUC and DTE permit the fee to be recovered through rates. For nuclear fuel used to generate electricity prior to April 7, 1983, payment must be made prior to the first delivery of spent fuel to the DOE. The DOE's current estimate for an available site is 2010. In return for payment of the fees prescribed by the NWPA, the federal government is to take title to and dispose of the utilities' high-level wastes and SNF. There have been numerous litigation proceedings involving the DOE's statutory and contractual obligation to accept high-level waste and SNF. While the courts have declined to order the DOE to begin accepting spent fuel for disposal on January 31, 1998, the courts left open the utilities' ability to bring damage claims against the DOE. In 1998, YAEC, CYAPC and MYAPC filed separate complaints against the DOE in the U.S. Court of Federal Claims seeking monetary damages resulting from DOE's failure to accept spent nuclear fuel for disposal. In decisions later that year, the court found liability on the part of DOE to the companies for breach of the standard contract, based upon the DOE's failure to begin disposal of spent nuclear fuel. Further proceedings to determine damages owed to YAEC, CYAPC and MYAPC remain stayed by the court as a result of DOE's appeal of the liability decisions and related litigation involving other utilities. Until the federal government begins accepting nuclear waste for disposal, nuclear generating plants will need to retain high-level waste and spent fuel onsite or make some other provisions for their storage. With the addition of new storage racks, storage facilities for Millstone 3 are expected to be adequate for the current licensed life of the unit. With the implementation of currently planned modifications, the storage facilities for Millstone 2 are expected to be adequate (maintaining the capacity to accommodate a full- core discharge from the reactor) until 2005 Seabrook is expected to have spent fuel storage capacity until at least 2010. The VY spent fuel pool is expected to be able to accommodate full-core removal through 2004 as a result of the installation and licensing of new racks in January 2001. In 2003, VYNPC expects to install an additional rack which would provide for full core off-load capability through 2008. Adequate storage capacity exists to accommodate all of the SNF at Millstone 1, CY, MY, and Yankee Rowe until that fuel is removed by the DOE. LOW-LEVEL RADIOACTIVE WASTE The NU system currently has contracts to dispose of its low-level radioactive waste (LLRW) at two privately operated facilities in Clive, Utah, and in Barnwell, South Carolina. In July 2000, the Northeast Interstate Low Level Radioactive Waste Management Compact, consisting of Connecticut and New Jersey, accepted South Carolina as a new member and is now known as the Atlantic Compact. This arrangement entitles Millstone and CY access to Barnwell through their decommissioning. This arrangement may eventually exclude other nuclear plants from accessing Barnwell. As a contingency, the NU system has plans that will allow for onsite storage of LLRW for at least 5 years. DECOMMISSIONING Based upon the NU system's most recent comprehensive site-specific updates of the decommissioning costs for each of the three Millstone units and for Seabrook, the recommended decommissioning method continues to be immediate and complete dismantlement of those units as soon as practical after their retirement. The table below sets forth the estimated Millstone and Seabrook decommissioning costs for the NU system companies. The estimates are based on the latest site studies, stated in December 31, 2000, dollars. CL&P PSNH WMECO NAEC NU system (Millions) Millstone 1* $ 580.3 $ - $136.1 $ - $ 716.4 Millstone 2 348.8 - 81.8 - 430.6 Millstone 3 343.1 18.4 79.3 - 440.8 Seabrook 23.8 - - 210.8 234.6 -------- ----- ------ ------ -------- Total $1,296.0 $18.4 $297.2 $210.8 $1,822.4 ======== ===== ====== ====== ======== *The costs shown include all of the billings associated with the funding of decommissioning, recovery of remaining assets and other closure costs associated with the early retirement of Millstone 1 as of December 31, 2000, which have been recorded as an obligation on the books of the NU system companies of which $74.4 million has been spent and reimbursed as of December 31, 2000. In 1986, the DPUC approved the establishment of separate external trusts for the currently tax-deductible portions of decommissioning expense accruals for Millstone 1 and 2 and for all expense accruals for Millstone 3. WMECO has established independent trusts to hold all decommissioning expense collections from customers. The DTE has authorized WMECO to collect its current decommissioning estimate for the three Millstone units. New Hampshire enacted a law in 1981 requiring the creation of a state- managed fund to finance decommissioning of any units in that state. NAEC's costs for decommissioning Seabrook are billed by it to PSNH and recovered by PSNH under the Rate Agreement. During April 1999, the Nuclear Decommissioning Finance Committee (NDFC) issued an order that adjusted the decommissioning collection period and funding levels. The NDFC's order concluded that Seabrook's anticipated energy producing life was 25 years from the date it went into commercial operation, and accordingly Seabrook will end its energy producing life in October 2015. This is 11 years earlier than the service life established by Seabrook's NRC operating license. The order also updated Seabrook's decommissioning estimate to $513 million (in 1998 dollars). In December 2000, the NDFC approved an updated decommissioning estimate of $585.9 million (in 2000 dollars). The cost of funding the decommissioning of Seabrook continues to be accrued over the expected remaining service life of the plant, as determined by the NDFC, and is included in depreciation expense. After commencement of competition, PSNH will recover decommissioning expenses as a stranded cost. As of December 31, 2000, the NU system recorded balances (at market) in its external decommissioning trust funds are as follows: CL&P PSNH WMECO NAEC NU system (Millions) Millstone 1 $226.8 $ - $ 62.5 $ - $289.3 Millstone 2 179.6 - 49.5 - 229.1 Millstone 3 124.7 7.4 32.9 - 165.0 Seabrook 5.8 - - 50.8 56.6 ------ ---- ------ ----- ------ Total $536.9 $7.4 $144.9 $50.8 $740.0 ====== ==== ====== ===== ====== Pursuant to NU's purchase and sale agreement (PSA) with Dominion for the sale of the Millstone units, upon the closing of the sale, which is expected to occur on or about April 2, 2001, the sellers are obligated to deliver to Dominion decommissioning funds in the amounts of $268.3 million for Unit 1, $253 million for Unit 2 and $244 million for Unit 3. With respect to Unit 3, the NU system companies are responsible for $178 million of the total amount to be turned over to Dominion. At that point, Dominion will assume full responsibility for decommissioning the three Millstone units, and NU shareholders, the NU system companies and their ratepayers will have no further obligation related to decommissioning. If the closing is delayed, the amount of decommissioning funds to be transferred to Dominion will be increased by 0.5 percent per month for each month of delay. Finally, the PSA requires that Unit 1 be turned over to Dominion in "cold and dark" condition. If it is not, the NU system companies have agreed to add to the decommissioning trust fund the necessary additional amount to place the unit in "cold and dark" condition. That amount, if any, is currently unknown, as it is expected that the unit will be turned over in a "cold and dark" condition. Pursuant to the PSNH Settlement Agreement, upon a successful sale of NAEC's share of Seabrook, the existing Seabrook Power Contracts between PSNH and NAEC will be terminated. However, subsequent to such sale, PSNH shall continue to be responsible for funding NAEC's former ownership share of its decommissioning liability, calculated on the basis of full funding by December 31, 2015, using an estimated decommissioning date of 2015, or as otherwise determined by the NDFC. PSNH may enter into a new contract to provide for the payment of Seabrook nuclear decommissioning costs, with full recovery of the costs of that contract to be recoverable from PSNH's customers. Under no circumstances will PSNH's customers have any responsibility for increases in decommissioning funding above the amount calculated based upon the payment schedule as of the sale date. In June 1999, NNECO filed with the NRC the Post-Shutdown Decommissioning Activities Report for Millstone 1. The total estimated decommissioning costs, which have been updated to reflect the early shutdown of the unit, are approximately $692 million as of December 31, 2000 ($560.5 million for CL&P and $131.5 million for WMECO). CYAPC, VYNPC and MYAPC are all collecting revenues for decommissioning from their power purchasers. The table below sets forth the NU system companies' estimated share of remaining decommissioning costs (and closure costs where applicable) of the Yankee units as of December 31, 2000. The estimates are based on the latest site studies. For information on the equity ownership of the NU system companies in each of the Yankee units and the proposed sale of VY, see "Nuclear Generation - General." CL&P PSNH WMECO NU system (Millions) VY $ 42.9 $18.1 $11.3 $ 72.3 CY* 93.5 13.5 25.8 132.8 MY* 67.1 27.9 16.8 111.8 ------ ----- ----- ------ Total $203.5 $59.5 $53.9 $316.9 ====== ===== ===== ====== *The costs shown include all of the expected future billings associated with the funding of decommissioning, recovery of remaining assets and other closure costs associated with the early retirement of Yankee Rowe, CY and MY as of December 31, 2000, which have been recorded as an obligation on the books of the NU system companies. As of December 31, 2000, the NU system's share of the external decommissioning trust fund balances (at market), which have been recorded on the books of the Yankee nuclear companies, is as follows: CL&P PSNH WMECO NU system (Millions) VY $ 26.8 $11.3 $ 7.0 $ 45.1 Yankee Rowe 36.8 10.5 10.5 57.8 CY 58.8 8.5 16.2 83.5 MY 18.7 7.8 4.7 31.2 ------ ----- ----- ------ Total $141.1 $38.1 $38.4 $217.6 ====== ===== ===== ====== On July 26, 2000, the FERC issued a letter approving an April 7, 2000, settlement between CYAPC, the DPUC and the OCC on CY decommissioning. Significant terms of the settlement include (1) decommissioning collections of $16.7 million per year, fully funding decommissioning and spent fuel storage costs through 2023; (2) consolidation of the pre-1983 spent fuel trust into the decommissioning trust and lowering total decommissioning collections by $56 million over the next seven years; (3) a ROE rate of 6 percent with no refunds of prior decommissioning or ROE collections, and; (4) an incentive/penalty mechanism for decommissioning. The effect of this settlement on CYAPC earnings is approximately $9.0 million, of which NU's share would be approximately $4.4 million. The settlement enabled the OCC to continue to argue that CYAPC was entitled to recover only costs directly related to decommission the plant, and may not recover remaining unamortized investment or any ROE, a position that had been denied by the FERC's administrative law judge. On September 28, 2000, the FERC issued an order confirming the ALJ's rejection of the OCC's argument, from which no further action has been taken. Effective January 1996, YAEC began billing its sponsors, including CL&P, WMECO and PSNH, amounts based on a revised decommissioning cost estimate approved by the FERC. Under the terms of its rate settlement agreement with the FERC, YAEC filed a revised decommissioning cost estimate, which was approved as of March 1, 2000. The YAEC filing assumes NRC license termination and completion of decommissioning activities by 2004. Billings to YAEC sponsor companies were completed in June 2000. In January 2001, NNECO filed a written notification with the NRC reporting that during a reconciliation and verification of Millstone spent nuclear fuel records, personnel concluded that the location of two full-length irradiated fuel rods could not be determined, and was not properly tracked in the records. The records reconciliation and verification effort is part of ongoing decommissioning activities at Millstone 1. NNECO reported that the two fuel rods are from the same fuel assembly, which was disassembled in 1972 for inspection, and were displaced from the fuel assembly in 1974. NNECO further reported that records indicate that in 1979 and 1980 the displaced rods were physically verified to be stored in a canister in the Millstone 1 spent fuel pool, and that the rods and canister are no longer in the spent fuel pool location documented in 1979 and 1980. NNECO's report indicated that records retrieved to date do not document the relocation or disposition of the two fuel rods. Due to the radiation levels associated with the fuel rods, NU believes that the two rods remain stored in the Millstone 1 spent fuel pool, or were shipped in a shielded cask to a facility licensed to accept radioactive material. NU's investigation into the location of the two fuel rods is ongoing. OTHER REGULATORY AND ENVIRONMENTAL MATTERS ENVIRONMENTAL REGULATION GENERAL The NU system and its subsidiaries are subject to federal, state and local regulations with respect to water quality, air quality, toxic substances, hazardous waste, and other environmental matters. Additionally, the NU system's major generation and transmission facilities may not be constructed or significantly modified without a review by the applicable state agency of the environmental impact of the proposed construction or modification. Compliance with environmental laws and regulations, particularly air and water pollution control requirements, may limit operations or require substantial investments in new equipment at existing facilities. SURFACE WATER QUALITY REQUIREMENTS The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the United States Environmental Protection Agency (EPA) or state environmental agency specifying the allowable quantity and characteristics of its effluent. NU system facilities are in the process of obtaining or renewing all required NPDES permits in effect. Compliance with NPDES and state water discharge permits has necessitated substantial expenditures, which are difficult to estimate, and may require further expenditures because of additional requirements that could be imposed in the future. For information regarding civil lawsuits related to alleged violations of certain facilities' NPDES permits, see "Item 3. Legal Proceedings." The Federal Oil Pollution Act of 1990 (OPA 90) sets out the requirements for facility response plans and periodic inspections of spill response equipment at facilities that can cause substantial harm to the environment by discharging oil or hazardous substances into the navigable waters of the United States and onto adjoining shorelines. The NU system companies are currently in compliance with the requirements of OPA 90. OPA 90 includes limits on the liability that may be imposed on persons deemed responsible for release of oil. The limits do not apply to oil spills caused by negligence or violation of laws or regulations. OPA 90 also does not preempt state laws regarding liability for oil spills. In general, the laws of the states in which the NU system owns facilities and through which the NU system transports oil could be interpreted to impose strict liability for the cost of remediating releases of oil and for damages caused by releases. The NU system currently carries general liability insurance in the total amount of $100 million annual coverage, which includes liability coverage for oil spills. AIR QUALITY REQUIREMENTS The Clean Air Act Amendments of 1990 (CAAA), as well as state laws in Connecticut, Massachusetts and New Hampshire, impose stringent requirements on emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Installation of continuous emissions monitors and expanded permitting provisions also are included. Compliance with CAAA requirements has cumulatively cost the NU system approximately $48 million as of December 31, 2000: $11 million for CL&P, $33 million for PSNH, $1 million for WMECO, and $3 million for HWP. In addition, PSNH expects to spend approximately $2 million a year for SO2 allowances. Further requirements for NOX reductions became effective in 1999. PSNH spent approximately $20 million for improvements at its Merrimack and Schiller Stations to meet these requirements. These costs were offset by the sale of $16 million of emission credits. Massachusetts and New Hampshire have proposed significant emission reduction requirements for power plants in those states. It is difficult to estimate the ultimate costs, since the proposals are not yet firm, but the total could be approximately $10 to 15 million over the next several years at Mt. Tom Station in Massachusetts. PSNH expects to divest the New Hampshire plants before the new requirements become effective. Following divestiture of the NU system's fossil units, these federal and state air quality regulations are not expected to have a material impact on the NU system companies. HAZARDOUS WASTE REGULATIONS As many other industrial companies have done in the past, the NU system companies disposed of residues from operations by depositing or burying such materials on-site or disposing of them at off-site landfills or facilities. Typical materials disposed of include coal gasification waste, fuel oils, gasoline, and other hazardous materials that might contain polychlorinated biphenyls. It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. The NU system has recorded a liability for what it believes is, based upon currently available information, its estimated environmental remediation costs for waste disposal sites for which the NU system companies expect to bear legal liability, and continues to evaluate the environmental impact of its former disposal practices. Under federal and state law, government agencies and private parties can attempt to impose liability on NU system companies for such past disposal. At December 31, 2000, the liability recorded by the NU system for its estimated environmental remediation costs for known sites needing remediation, including those sites described below, exclusive of recoveries from insurance or from third parties, was approximately $82.3 million, representing 42 sites. This total includes liabilities recorded by Yankee Gas of $35 million. All cost estimates were made in accordance with generally accepted accounting principles where remediation costs are probable and reasonably estimable. These costs could be significantly higher if alternative remedies become necessary. Under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, commonly known as Superfund, the EPA has the authority to clean up or order the clean up of hazardous waste sites and to impose the clean up costs on parties deemed responsible for the hazardous waste activities on the sites. Responsible parties include the current owner of a site, past owners of a site at the time of waste disposal, waste transporters, and waste generators. The NU system currently is involved in three Superfund sites: one in New York, one in New Hampshire, and one in Kentucky, which could have a material impact on the NU system. The NU system has committed in the aggregate approximately $1.4 million to its share of the clean up of these sites. The greatest liabilities currently relate to former manufactured gas plant (MGP) facilities which represent the largest share of future clean up costs. These facilities were owned and operated by predecessor companies to the NU system from the mid-1800's to mid-1900's. Byproducts from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, metals and other waste products that may pose risks to human health and the environment. The NU system currently has partial or full ownership responsibilities at 27 former MGP sites. Of the total NU system liabilities, $67.9 million has been established to address future remediation costs at MGP sites. Other sites undergoing comprehensive investigations or remedial actions under state programs located in Connecticut, Massachusetts, New Hampshire or New Jersey include four former fuel oil releases, three landfills, three asbestos hazard abatement projects and five miscellaneous projects. To date, approximately $12.9 million has been established to address future remediation costs at these sites. In the past, the NU system has received other claims from government agencies and third parties for the cost of remediating sites not currently owned by the NU system but affected by past NU system disposal activities and may receive more such claims in the future. The NU system expects that the costs of resolving claims for remediating sites about which it has been notified will not be material, but cannot estimate the costs with respect to sites about which it has not been notified. ELECTRIC AND MAGNETIC FIELDS Published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Most researchers, as well as numerous scientific review panels considering all significant EMF epidemiological and laboratory studies to date, agree that current information remains inconclusive, inconsistent and insufficient for characterizing EMF as a health risk. Based on this information, management does not believe that a causal relationship between EMF exposure and adverse health effects has been established or that significant capital expenditures are appropriate to minimize unsubstantiated risks. The NU system companies have closely monitored research and government policy developments for many years and will continue to do so. If further investigation were to demonstrate that the present electricity delivery system is contributing to increased risk of cancer or other health problems, the industry could be faced with the difficult problem of delivering reliable electric service in a cost-effective manner while managing EMF exposures. To date, no courts have concluded that individuals have been harmed by EMF from electric utility facilities, but if utilities were to be found liable for damages, the potential monetary exposure for all utilities, including the NU system companies, could be enormous. Without definitive scientific evidence of a causal relationship between EMF and health effects, and without reliable information about the kinds of changes in utilities' transmission and distribution systems that might be needed to address the problem, if one is found, no estimates of the cost impacts of remedial actions and liability awards are available. FERC HYDROELECTRIC PROJECT LICENSING Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of a license, any hydroelectric project so licensed is subject to reissuance by the FERC to the existing licensee or to others upon payment to the licensee of the lesser of fair value or the net investment in the project plus severance damages less certain amounts earned by the licensee in excess of a reasonable rate of return. The NU system companies currently hold FERC licenses for 12 hydroelectric projects aggregating approximately 1,411 MW of capacity, located in Connecticut, Massachusetts and New Hampshire. CL&P's and WMECO's 5 licenses with approximately 1,302 MW of capacity were transferred to NGC in March 2000. As part of the Settlement Agreement, PSNH has proposed to auction its 6 hydroelectric projects (totaling nine plants) with approximately 65 MW of capacity upon approval of the agreement. The original license for HWP's Holyoke Project expired in late 1999. In August 1999, the FERC issued a new 40-year license to HWP. HWP was the successful applicant in a contested license application proceeding for the project, winning over co-applicants, the City of Holyoke Gas & Electric Department, the Massachusetts Municipal Wholesale Electric Company and the Ashburnham Municipal Light Plant. HWP filed a motion for stay and motion for rehearing of the FERC's order, requesting that the FERC reconsider various aspects of the license, including mandatory Section 18 fishway prescriptions, bypass reach minimum flows and compliance schedules. Motions for rehearing of the FERC's order were also filed by various other parties. The FERC issued an order granting rehearing. HWP is awaiting further action by the FERC. In a separate but related proceeding, HWP filed an appeal of the state water quality certificate conditions and requested an adjudicatory hearing with the Massachusetts Department of Environmental Protection. A settlement agreement and revised water quality certificate were filed with the administrative law judge on February 9, 2001. NGC's FERC licenses for operation of the Falls Village and Housatonic hydroelectric projects expire in 2001. A license application, which proposed to combine both projects under one license, was submitted to the FERC in August 1999. A settlement has been reached with the Connecticut Department of Environmental Protection (DEP) on the Section 401 water certifications necessary for relicensing. The FERC has begun the process that delineates the items that it expects to review as part of its environmental assessment of the projects and the application for license. Public meetings and tours at the developments have been held and comments were filed by the public, agencies and applicant by the January 8, 2001, FERC deadline. No additional information requests have been received. PSNH's FERC license for the three dam Amoskeag project expires on December 31, 2005. PSNH filed a notice of intent to file for a new license on December 29, 2001. The FERC has issued a notice indicating that it has authority to order project licensees to decommission projects that are no longer economic to operate. The potential costs of decommissioning a project, however, could be substantial. The FERC has recently ordered its first project decommissioning under this authority. It is likely that this FERC decision will be appealed. EMPLOYEES As of December 31, 2000, the NU system companies had 9,260 employees on their payrolls, of which 2,057 were employed by CL&P, 1,227 by PSNH, 406 by WMECO, 410 by Yankee Gas, 110 by R. M. Services, 2 by HWP, 1,696 by NNECO, 2,044 by NUSCO, 782 by NAESCO, 104 by Select Energy, and 422 by HEC. NU, NAEC, Mode 1, NUEI, NGC, NGS, and SEPPI have no employees. On December 15, 2000, 498 employees of CL&P, PSNH, WMECO, HWP, NUSCO, and Yankee Gas were offered a voluntary separation program (VSP). There were 361 employees who accepted the VSP and are expected to retire between March 1, 2001, and March 2002. Costs relating to the VSP will be reflected in the first quarter of 2001 results. Approximately 2,450 employees of CL&P, PSNH, WMECO, NAESCO, HWP, and Yankee Gas are covered by 15 union agreements, which expire between June 1, 2001, and October 1, 2003. ITEM 2. PROPERTIES The physical properties of the NU system are owned or leased by subsidiaries of NU. CL&P's principal plants and other properties are located either on land which is owned in fee or on land, as to which CL&P owns perpetual occupancy rights adequate to exclude all parties except possibly state and federal governments, which has been reclaimed and filled pursuant to permits issued by the United States Army Corps of Engineers. The principal properties of PSNH are held by it in fee. In addition, PSNH leases space in an office building under a 30-year lease expiring in 2002. WMECO's principal plants and a major portion of its other properties are owned in fee, although one hydroelectric plant is leased. NAEC owns a 35.98 percent interest in Seabrook and approximately 560 acres of exclusion area land located around the unit. In addition, CL&P, PSNH and WMECO have certain substation equipment, data processing equipment, nuclear fuel, nuclear control room simulators, vehicles, and office space that are leased. With few exceptions, the NU system companies' lines are located on or under streets or highways, or on properties either owned or leased, or in which the Company has appropriate rights, easements or permits from the owners. CL&P's and PSNH's properties are subject to the lien of each company's respective first mortgage indenture. WMECO's properties are subject to the lien of its first mortgage indenture. NAEC's first mortgage bonds are secured by a lien on the Seabrook Interest described above, and all rights of NAEC under the Seabrook Power Contracts. In addition, CL&P's and WMECO's interests in Millstone 1 are subject to second liens for the benefit of lenders under agreements related to PCRBs. Also, CL&P and WMECO granted, as collateral, their second mortgage ownership interests in Millstone 2 and 3 that secure their borrowings under the new credit agreement. Various of these properties are also subject to minor encumbrances which do not substantially impair the usefulness of the properties to the owning company. The NU system companies' properties are well maintained and are in good operating condition. TRANSMISSION AND DISTRIBUTION SYSTEM At December 31, 2000, the NU system companies owned 103 transmission and 370 distribution substations that had an aggregate transformer capacity of 19,751,356 kilovoltamperes (kVa) and 8,957,289 kVa, respectively; 3,075 circuit miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV, and 196 cable miles of underground transmission lines ranging from 69 kV to 138 kV; 33,216 pole miles of overhead and 2,191 conduit bank miles of underground distribution lines; and 423,055 line transformers in service with an aggregate capacity of 18,268,000 kVa. ELECTRIC GENERATING PLANTS As of December 31, 2000, the electric generating plants of the NU system companies and the NU system companies' entitlement in the generating plant of the VYNPC were as follows (See "Item 1. Business - Nuclear Generation" for information on ownership and operating results for the year):
Claimed Year Capability* Owner Plant Name (Location) Type Installed (kilowatts) - ----- -------------------- ---- --------- ----------- CL&P Millstone (Waterford, CT) Unit 2 Nuclear 1975 706,543 Unit 3 Nuclear 1986 603,436 Seabrook (Seabrook, NH) Nuclear 1990 47,135 VT Yankee (Vernon, VT) Nuclear 1972 45,189 --------- Total Nuclear-Steam Plants ( 4 units) 1,402,303 Total Internal Combustion ( 4 units) 1970 195,600 --------- Total CL&P Generating Plant ( 8 units) 1,597,903 ========= PSNH Millstone (Waterford, CT) Unit 3 Nuclear 1986 32,461 VT Yankee (Vernon, VT) Nuclear 1972 18,999 --------- Total Nuclear-Steam Plants ( 2 units) 51,460 Total Fossil-Steam Plants ( 7 units) 1952-78 639,568 Total Hydro-Conventional (20 units) 1917-83 67,930 Total Internal Combustion ( 5 units) 1968-70 103,594 --------- Total PSNH Generating Plant (34 units) 862,552 ========= WMECO Millstone (Waterford, CT) Unit 2 Nuclear 1975 165,732 Unit 3 Nuclear 1986 139,519 VT Yankee (Vernon, VT) Nuclear 1972 11,904 --------- Total Nuclear-Steam Plants ( 3 units) 317,155 Total Hydro-Conventional ( 3 units) 1930 33,960** --------- Total WMECO Generating Plant ( 6 units) 351,115 ========= NAEC Seabrook (Seabrook, NH) Nuclear 1990 417,751 ========= HWP Mt. Tom (Holyoke, MA) Fossil-Steam 1960 147,000 Total Hydro-Conventional (15 units) 1905-83 43,560 --------- Total HWP Generating Plant (16 units) 190,560 ========= NGC Total Hydro-Conventional (36 units) 1903-55 158,220 Total Hydro-Pumped Storage ( 7 units) 1928-73 1,151,350 Tunnel (Preston, CT) ( 1 unit) 1969 20,800 --------- Total NGC Generating Plant (44 units) 1,330,370 ========= NU system Millstone (Waterford, CT) Unit 2 Nuclear 1975 872,275 Unit 3 Nuclear 1986 775,416 Seabrook (Seabrook, NH) Nuclear 1990 464,886 VT Yankee (Vernon, VT) Nuclear 1972 76,092 --------- Total Nuclear-Steam Plants ( 4 units) 2,188,669 Total Fossil-Steam Plants ( 8 units) 1952-78 786,568 Total Hydro-Conventional (74 units) 1903-83 303,670 Total Hydro-Pumped Storage ( 7 units) 1928-73 1,151,350 Total Internal Combustion (10 units) 1968-70 319,994 --------- Total NU system Generating Plant Including Vermont Yankee (103 units) 4,750,251 ========= Excluding Vermont Yankee (102 units) 4,674,159 =========
* Claimed capability represents winter ratings as of December 31, 2000. ** Total Hydro-Conventional capability includes the Cobble Mtn. plant's 33,960 kilowatts which is leased from the City of Springfield, MA. FRANCHISES CL&P. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services, and, until January 2000, to sell electricity, in the respective areas in which it is now supplying such service. In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth in Title 16 of the Connecticut General Statutes and the special act of the General Assembly constituting its charter, to manufacture, generate, purchase and sell electricity at retail, including to provide standard offer, backup, and default service, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. PSNH. The NHPUC, pursuant to statutory requirement, has issued orders granting PSNH exclusive franchises free from burdensome restrictions to sell electricity in the respective areas in which it is now supplying such service. In addition to the right to sell electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, transmit, and distribute electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of PSNH include the power of eminent domain. NNECO. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, NNECO has a valid franchise free from burdensome restrictions to sell electricity to utility companies doing an electric business in Connecticut and other states. In addition to the right to sell electricity as set forth above, the franchise of NNECO includes, among others, rights and powers to manufacture, generate and transmit electricity, and to erect and maintain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. WMECO. WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only, and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority. Pursuant to the Massachusetts restructuring legislation, the DTE is required to define service territories for each distribution company, including WMECO, based on the service territories actually served on July 1, 1997, and following to the extent possible municipal boundaries. The DTE has not yet defined service territories. After established by the DTE, until terminated by effect of law or otherwise, the distribution company shall have the exclusive obligation to provide distribution service to all retail customers within its service territory, and no other person shall provide distribution service within such service territory without the written consent of such distribution company. HWP and Holyoke Power and Electric Company (HP&E). HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them. HWP's electric business is subject to the restriction that sales be made by written contract in amounts of not less than 100 horsepower to purchasers who use the electricity in their own business in the counties of Hampden or Hampshire, Massachusetts and cities and towns in these counties, and customers who occupy property in which HWP has a financial interest, by ownership or purchase money mortgage. HWP also has certain dam and canal and related rights, all subject to such consents and approvals of public authorities and others as may be required by law. The two companies have locations in the public highways for their transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. HP&E has no retail service territory area and sells electric power exclusively at wholesale. ITEM 3. LEGAL PROCEEDINGS 1. Connecticut Superior Court - Connecticut Attorney General Civil Lawsuit and Appeal In 1997, the AG initiated a civil lawsuit, on behalf of the CDEP, in Connecticut Superior Court against NNECO and NUSCO for violations of the Millstone water discharge permit and Connecticut water discharge regulations. In 1998, the Superior Court approved a settlement between NNECO and the AG. The settlement required NNECO to pay a $700,000 civil penalty and expend $500,000 to fund three supplemental environmental projects. Additionally, the settlement requires NNECO to perform two environmental audits of its water compliance program, have a third-party review of the first NNECO audit and inform the CDEP of major changes to its environmental management system. The first audit and the third-party review have been completed. The second required water compliance audit by NNECO has been completed and the audit report was submitted to the CDEP for review on January 5, 2001. An intervenor in the Superior Court proceeding appealed the settlement order. On July 27, 2000, the Connecticut Supreme Court ruled in favor of NNECO and NUSCO and affirmed the lower court's decision. 2. Shareholder Securities Class Actions - Nuclear Matters Consolidated Federal Court Actions: Pursuant to a court order dated October 1, 1997, the six class actions separately filed against NU in 1996 were consolidated for pre-trial and trial purposes. The actions are based on various federal securities law and common law theories alleging misrepresentations and omissions in public disclosures related to the NU system's nuclear problems, which resulted in extended outages at Millstone and impacted the financial condition of NU and certain of its subsidiaries. These complaints represent classes of plaintiffs who purchased or otherwise acquired NU common stock from March 1994 to April 1996. The parties executed a settlement agreement and, on March 27, 2000, filed the agreement with the Federal court. On that date, the court also approved the form of the settlement notice to be sent to shareholder class members and set down a schedule for the mailing of the notice (May 10, 2000), the formal hearing to approve the settlement (July 24, 2000), and the date to file proof of claim forms (September 29, 2000). Any class member who wished to object to or opt-out of the settlement was required to do so in writing by July 5, 2000. On July 24, 2000, the court entered an Order approving the settlement which provides for the dismissal of Stepak v. NU et al, a related state court action. The time to take an appeal has expired and the judgment is final. 3. Merger-Related Shareholder Lawsuits On October 13, 1999, and October 19, 1999, virtually identical complaints were filed in the Supreme Court of New York against NU and its Board of Trustees. Both complaints purport to be "class action complaints" and allege that the trustees have breached their fiduciary duties to the plaintiffs and other members of the class by not (i) obtaining the best price for NU's assets and businesses and (ii) entrenching themselves and their corporate offices. The plaintiffs seek equitable relief, including an order that the trustees maximize shareholder value and award attorneys fees. The cases are now pending in state court in New York and have been inactive during the pendency of the Federal action referred to below. An additional action was brought in Federal court in New York by the plaintiffs in the shareholder state court actions, alleging that NU, Con Edison and NU's Trustees have, in addition to violating fiduciary duties, violated Section 14(a) of the Exchange Act by filing a joint proxy statement that fails to disclose material information about the Indian Point nuclear generating plant. To avoid a preliminary injunction proceeding and the possibility of the cancellation of the April 14, 2000, shareholders' vote to approve the merger, Con Edison and NU agreed to send a supplement to the proxy to the Companies' shareholders addressing recent developments concerning Indian Point. At a status conference on November 3, 2000, in the Federal case, a tentative settlement agreement was reached by which a class would be certified, counsel fees would be paid by Con Edison and the Section 14(a) claim would be dismissed with prejudice. The parties executed the settlement agreement which was submitted to the Court, for approval, at the status conference on March 16, 2001. At the conference, the Court, as a result of the termination of the merger agreement, dismissed the fiduciary duty claims without prejudice, and scheduled a hearing for approval of the settlement for July 13, 2001. Notice of the hearing will be sent to shareholders on or about May 17, 2001. After dismissal of the Federal action, the trustees will move to dismiss the state court actions, without prejudice, because the issues raised therein are moot. 4. Con Edison/NU Merger Appeals and Related Litigation On October 19, 2000, the DPUC issued a decision (the October Decision) in Docket No. 00-01-11, Joint Application of Con Edison and NU for Approval of Change of Control, approving with conditions the merger of Con Edison and NU. Subsequent to the October Decision, the AG, the OCC and Con Edison and NU (collectively, the Applicants) filed separate petitions for reconsideration. In a decision dated November 22, 2000 (the November Decision), the DPUC rejected the petitions for reconsideration of the AG and the OCC. The DPUC granted in part and rejected in part the Applicants' petition for reconsideration, and ordered a portion of the modifications that the Applicants had requested. On December 4, 2000, the AG appealed the November Decision to the Connecticut Superior Court. On December 6, 2000, the OCC appealed the October Decision to the Superior Court. The appeals are pending. On February 13, 2001, the AG and the OCC filed motions to stay the DPUC's approval, intended to prevent the merger from being consummated prior to the court's determination of the appeal. On February 14, 2001, NU, Con Edison and the DPUC filed motions to dismiss the appeals. A status conference was held on February 23, 2001, at which the court established a briefing and argument schedule for the motions for stay and motions to dismiss. On March 8, 2001, as a result of the events leading to the lawsuits described below, NU filed a motion with the court to suspend the briefing and argument schedule in the appeals. That motion was granted by the court on March 9, 2001. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District seeking a declaratory judgment that NU had failed to satisfy conditions precedent under the merger agreement and that Con Edison had no further obligations under the merger agreement. On March 12, 2001, NU filed suit in the U.S. District Court for the Southern District seeking substantial monetary damages against Con Edison arising out of Con Edison's material breach of the merger agreement. For further information on the events leading to these lawsuits, see "Part I, Item 1. Business - Mergers and Acquisitions." 5. Connecticut Superior Court - Fish Unlimited Lawsuits In March 1999, certain parties brought a civil suit in Connecticut Superior Court against NNECO and NUSCO seeking a temporary and a permanent injunction to prevent the restart of Millstone 2 until a fish return system and cooling tower are installed. In April 1999, the Superior Court issued a temporary restraining order (TRO) to prevent NNECO from starting up Millstone 2 until it ruled on the temporary injunction issue. In May 1999, the court dissolved the TRO and denied the applications for both temporary and permanent injunctions. The plaintiffs appealed this decision. In July 2000, the Connecticut Supreme Court ruled in favor of NNECO and NUSCO, holding that it did not have jurisdiction to consider the plaintiffs' claims for injunctive relief. The Supreme Court vacated the prior judgment and remanded the case to the trial court with direction to dismiss the action. Fish Unlimited's motion seeking reconsideration has been denied by the Supreme Court. In July 1999, the Connecticut Superior Court granted NNECO's and NUSCO's motion to dismiss an additional lawsuit that was filed by certain plaintiffs in June 1999, challenging the validity of Millstone's water discharge permit. Millstone's NPDES permit is currently under review for renewal, but both NNECO and CDEP contend that the existing NPDES permit is valid. The plaintiffs appealed the court's decision, and on July 24, 2000, the Connecticut Supreme Court ruled in favor of NNECO and NUSCO and affirmed the trial court's decision. 6. Millstone 3 - Damage to Fish Population Lawsuits On April 20, 2000, two lawsuits were filed in Connecticut Superior Court against NNECO and NUSCO seeking to enjoin operations at Millstone due to alleged damage caused to the winter flounder population in the Niantic River and Long Island Sound. The first action, brought by certain citizens groups, sought a temporary injunction to suspend Millstone 3 operations through the second week of June 2000. On August 30, 2000, NNECO filed a motion to dismiss on the grounds that the plaintiffs failed to exhaust their administrative remedies before resorting to the court. The motion also contended that the action should be dismissed as moot since plaintiffs only sought to enjoin the operation of Millstone 3 through June 2000. On October 16, 2000, NNECO's motion to dismiss this action was granted. The second action, brought by two fishermen, alleges two counts: common law nuisance and tortuous interference with a business expectancy. The suit alleges that Millstone has engaged in various actions, including entrainment of winter flounder, that have caused the two fishermen to suffer damages. The suit seeks, among other claims of relief, temporary and permanent injunctions to suspend Millstone operations during the winter flounder spawning season, conversion of Millstone to a close-cooling system or, in the alternative, permanent shutdown and compensatory and punitive damages. A motion to strike both counts of the plaintiffs' complaint was filed on July 31, 2000. On December 22, 2000, NNECO's motion to strike was denied. NNECO is now proceeding with discovery. On April 26, 2000, another lawsuit was filed in Hartford Superior Court against NUSCO, NNECO and the Commissioner of the CDEP challenging the validity of previously issued CDEP emergency and temporary authorizations allowing Millstone to discharge wastewater not expressly authorized by the facility's NPDES permit. The suit sought a temporary and permanent injunction against operations at Millstone 1, 2 and 3. On August 30, 2000, NNECO filed a motion to dismiss, and on October 16, 2000, NNECO's motion was granted. Plaintiffs have since filed an appeal, which remains pending, with the Connecticut Appellate Court. 7. Sale of Millstone to Dominion Nuclear Connecticut, Inc. On February 20, 2001, the CCAM filed in Connecticut Superior Court an appeal of the DPUC's decision approving the sale of Millstone to Dominion. CCAM alleges that the final decision violates the Connecticut general statues on multiple grounds and requests that the decision be reversed and vacated. On March 2, 2001, CCAM filed a motion to stay, which was heard by the court on March 12, 2001. The parties are awaiting a decision from the court on the motion. On March 8, 2001, CCAM and other parties also filed a lawsuit in Connecticut Superior Court against the CDEP, NNECO and Dominion challenging (1) the validity of Millstone's NPDES permit (Permit) and a previously issued CDEP emergency authorization allowing Millstone to discharge wastewater not expressly authorized by the facility's Permit, and (2) CDEP's authority to transfer both Millstone's Permit and emergency authorization to Dominion. The lawsuit seeks to declare both the Permit declaratory and emergency authorization invalid and to enjoin continued power operation at Millstone and the transfer of NNECO's Permit and emergency authorization to Dominion. The plaintiffs have applied for a TRO which seeks to enjoin CDEP from transferring both the permit and emergency authorization to Dominion prior to a full hearing. NNECO has filed a Motion to Dismiss and a memorandum in opposition to CCAM's request for a TRO. On March 21, 2001, this matter was transferred to the Superior Court's complex litigation docket. On March 12, 2001, the Millstone Station Employees Association filed in Connecticut Superior Court a request for a stay of the DPUC's approval of the sale of Millstone pending resolution of certain employee pension issues. The DPUC and CL&P have moved to dismiss the stay request on various grounds. No hearing date has been established. For further information on the sale of the Millstone units, see "Item 1. Business - Rates and Electric Industry Restructuring" and "Nuclear Generation." 8. Other Legal Proceedings The following sections of "Item 1. Business" discuss additional legal proceedings: See "Rates and Electric Industry Restructuring" for information about various state restructuring proceedings and civil lawsuits related thereto; "Regulated Electric Operations" and "Regulated Gas Operations" for information about proceedings relating to power, transmission and pricing issues; "Nuclear Generation" and "Nuclear Plant Performance" for information related to nuclear plant performance, nuclear fuel enrichment pricing, high- level and LLRW disposal, decommissioning matters, and NRC regulation, and; "Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality, toxic substances and hazardous waste, electric and magnetic fields, licensing of hydroelectric projects, and other matters. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No event that would be described in response to this item occurred with respect to NU, CL&P, PSNH, WMECO, or NAEC. PART II ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED SHAREHOLDER MATTERS NU. The common shares of NU are listed on the New York Stock Exchange. The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications. The high and low sales prices for the past two years, by quarters, are shown below. Year Quarter High Low ---- ------- ---- --- 2000 First $21.5000 $18.0000 Second 23.1250 20.8125 Third 23.9600 21.5000 Fourth 24.5600 18.2500 1999 First $16.4375 $13.7500 Second 18.3125 13.5625 Third 19.0000 17.3750 Fourth 22.0000 17.7500 As of January 31, 2001, there were 79,709 common shareholders of record of NU. As of the same date, there were a total of 148,772,670 common shares issued, including 4,913,146 unallocated ESOP shares held in the ESOP trust. On January 11, 2000, the NU Board of Trustees approved the payment of a 10 cent per share dividend, payable on March 31, 2000, to shareholders of record as of March 1, 2000. The record date for this dividend was changed on January 31, 2000 to March 6, 2000, to provide Yankee shareholders who received NU common shares the opportunity to receive the dividend following the Yankee merger. On April 12, 2000, the NU Board of Trustees approved the payment of a 10 cent per share dividend, payable on June 30, 2000, to shareholders of record as of June 1, 2000. On July 11, 2000, the NU Board of Trustees approved the payment of a 10 cent per share dividend, payable on September 29, 2000, to shareholders of record as of September 1, 2000. On October 10, 2000, the NU Board of Trustees approved the payment of a 10 cent per share dividend, payable on December 29, 2000, to shareholders of record as of December 1, 2000. On September 14, 1999, the NU Board of Trustees approved the payment of NU's first common share dividend since March 1997. NU paid a 10 cent per share dividend on December 30, 1999, to shareholders of record as of December 1, 1999. Information with respect to dividend restrictions for NU and its subsidiaries is contained in Item 1. Business under the caption "Financing Program - Financing Limitations" and in Note (b) to the "Consolidated Statements of Shareholders' Equity" on page F-26 of this document. CL&P, PSNH, WMECO, and NAEC. The information required by this item is not applicable because the common stock of CL&P, PSNH, WMECO, and NAEC is held solely by NU. ITEM 6. SELECTED FINANCIAL DATA NU. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page F-67 of this document. CL&P. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 41 of CL&P's 2000 Annual Report, which information is incorporated herein by reference. PSNH. Reference is made to information under the heading "Selected Financial Data" contained on page 38 of PSNH's 2000 Annual Report, which information is incorporated herein by reference. WMECO. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 37 of WMECO's 2000 Annual Report, which information is incorporated herein by reference. NAEC. Reference is made to information under the heading "Selected Financial Data" contained on page 27 of NAEC's 2000 Annual Report, which information is incorporated herein by reference. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS; AND ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK NU. Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained on pages F-1 through F-18 of this document. CL&P. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 1 through 11 in CL&P's 2000 Annual Report, which information is incorporated herein by reference. PSNH. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 1 through 9 in PSNH's 2000 Annual Report, which information is incorporated herein by reference. WMECO. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 1 through 9 in WMECO's 2000 Annual Report, which information is incorporated herein by reference. NAEC. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 1 through 7 in NAEC's 2000 Annual Report, which information is incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA NU. Reference is made to information under the headings "Company Report," "Report of Independent Public Accountants," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Balance Sheets," "Consolidated Statements of Shareholders' Equity," "Consolidated Statements of Cash Flows," "Consolidated Statements of Capitalization," "Consolidated Statements of Income Taxes," "Notes to Consolidated Financial Statements," and "Consolidated Statements of Quarterly Financial Data" contained on pages F-19 through F-65 of this document. CL&P. Reference is made to information under the headings "Report of Independent Public Accountants," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Balance Sheets," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained on pages 12 through 41 in CL&P's 2000 Annual Report, which information is incorporated herein by reference. PSNH. Reference is made to information under the headings "Report of Independent Public Accountants," "Statements of Income," "Statements of Comprehensive Income," "Balance Sheets," "Statements of Common Stockholder's Equity," "Statements of Cash Flows," "Notes to Financial Statements," and "Quarterly Financial Data" contained on pages 10 through 38 in PSNH's 2000 Annual Report, which information is incorporated herein by reference. WMECO. Reference is made to information under the headings "Report of Independent Public Accountants," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Balance Sheets," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained on pages 10 through 37 in WMECO's 2000 Annual Report, which information is incorporated herein by reference. NAEC. Reference is made to information under the headings "Report of Independent Public Accountants," "Statements of Income," "Balance Sheets," "Statements of Common Stockholder's Equity," "Statements of Cash Flows," "Notes to Financial Statements," and "Quarterly Financial Data" contained on pages 8 through 27 in NAEC's 2000 Annual Report, which information is incorporated herein by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE No event that would be described in response to this item has occurred with respect to NU, CL&P, PSNH, WMECO, or NAEC. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS NU. First First Positions Elected Elected Name Held an Officer a Trustee - ----------------------- --------- ---------- --------- Cotton M. Cleveland T n/a 06/23/92 Sanford Cloud, Jr. T n/a 05/09/00 William F. Conway T n/a 06/17/97 E. Gail de Planque T n/a 10/01/95 John H. Forsgren EVP, CFO 02/01/96 05/09/00 Raymond L. Golden T n/a 05/11/99 Cheryl W. Grise SVP, SEC, GC 06/01/91 n/a Elizabeth T. Kennan T n/a 01/22/80 Bruce D. Kenyon P 09/03/96 n/a Hugh C. MacKenzie (1) P 07/01/88 n/a Michael G. Morris CHB, P, CEO, T 08/19/97 08/19/97 Emery G. Olcott T n/a 05/09/00 William J. Pape II T n/a 04/23/74 Robert E. Patricelli T n/a 05/25/93 Gary D. Simon OTH 04/15/98 n/a John F. Swope T n/a 06/23/92 Lisa J. Thibdaue OTH 01/01/98 n/a John F. Turner T n/a 05/23/95 CL&P. First First Positions Elected Elected Name Held an Officer a Director - ----------------------- --------- ---------- ---------- David H. Boguslawski VP, D 09/09/96 06/30/99 John H. Forsgren (2) OTH 02/10/96 n/a Cheryl W. Grise (2) OTH 06/01/91 n/a Bruce D. Kenyon (2) OTH 09/03/96 n/a Hugh C. MacKenzie (1) P, D 07/01/88 06/06/90 Michael G. Morris (2) OTH 08/19/97 n/a Rodney O. Powell VP, D 10/18/98 06/30/99 Lisa J. Thibdaue (2) OTH 01/01/98 n/a PSNH. First First Positions Elected Elected Name Held an Officer a Director - ----------------------- --------- ---------- ---------- David H. Boguslawski VP, D 06/05/92 06/30/99 John C. Collins D n/a 10/19/92 John H. Forsgren (2) OTH, D 02/01/96 08/05/96 Cheryl W. Grise (2) OTH 07/31/98 n/a Bruce D. Kenyon (2) OTH 09/03/96 n/a Gerald Letendre D n/a 10/19/92 Gary A. Long P, COO, D 01/01/94 07/01/00 Hugh C. MacKenzie (1)(2) OTH, D 02/01/96 02/01/94 Michael G. Morris CH, D 08/19/97 08/19/97 Jane E. Newman D n/a 10/19/92 Lisa J. Thibdaue (2) OTH 01/01/98 n/a WMECO. First First Positions Elected Elected Name Held an Officer a Director - ----------------------- --------- ---------- ---------- David H. Boguslawski VP, D 09/09/96 06/30/99 James E. Byrne D n/a 09/17/99 John H. Forsgren (2) OTH, D 02/01/96 06/10/96 Cheryl W. Grise (2) OTH 06/01/91 n/a Bruce D. Kenyon (2) OTH 09/03/96 n/a Kerry J. Kuhlman P, COO, D 10/18/98 04/01/99 Hugh C. MacKenzie (1)(2) OTH, D 07/01/88 06/06/90 Paul J. McDonald D n/a 09/17/99 Michael G. Morris CH, CEO, D 08/19/97 08/19/97 Melinda M. Phelps D n/a 09/17/99 Lisa J. Thibdaue (2) OTH 01/01/98 n/a NAEC. First First Positions Elected Elected Name Held an Officer a Director - ----------------------- --------- ---------- ---------- William A. DiProfio (3) D n/a 06/30/99 Ted C. Feigenbaum EVP, CNO, D 10/21/91 06/30/99 John H. Forsgren (2) OTH 02/01/96 n/a George R. Gram II D n/a 02/02/01 Cheryl W. Grise (2) OTH 10/21/91 n/a Bruce D. Kenyon P, CEO, D 09/03/96 09/03/96 Michael G. Morris (2) OTH 08/19/97 n/a 1. Mr. MacKenzie retired effective January 1, 2001. 2. Executive Officers of Registrant because of policy-making functions for NU system. 3. Mr. DiProfio retired effective February 1, 2001. Key: CEO - Chief Executive Officer OTH - Executive Officer of CFO - Chief Financial Officer Registrant because of policy- CH - Chairman making functions for NU system CHB - Chairman of the Board P - President CNO - Chief Nuclear Officer SEC - Secretary COO - Chief Operating Officer SVP - Senior Vice President D - Director T - Trustee EVP - Executive Vice President VP - Vice President GC - General Counsel Name Age Business Experience During Past 5 Years - ------------------------- --- --------------------------------------- David H. Boguslawski 46 Vice President-Energy Delivery of CL&P, PSNH and WMECO, since 1996; previously Vice President-Customer Operations of PSNH from 1994 to 1996 and Vice President-Marketing of PSNH from 1992 to 1994. James E. Byrne 46 Partner, Finneran, Byrne & Dreshsler, L.L.P., since 1982. Cotton M. Cleveland (1) 48 President of Mather Associates, New London, New Hampshire (a firm specializing in leadership and organizational development for corporate and non-profit organizations). From 1991 until 1998, founding Executive Director of Leadership New Hampshire. Sanford Cloud, Jr. (2) 56 President and Chief Executive Officer of The National Conference for Community and Justice, New York, New York. From 1993 to 1994, he was a partner in the law firm of Robinson and Cole, Hartford, Connecticut. Previously Vice President of Aetna Life and Casualty Company and served for two terms as a state senator of Connecticut. John C. Collins (3) 55 Chief Executive Officer, Dartmouth-Hitchcock Clinic, Dartmouth-Hitchcock Medical Center since 1977. William F. Conway (4) 70 President of William F. Conway & Associates, Inc., Scottsdale, Arizona (a management consulting firm to the nuclear power industry). From 1989 to 1994 (retired July 1994), he was Executive Vice President- Nuclear of Arizona Public Service Company, Phoenix, Arizona. Previously, he was Senior Vice President of Nuclear Operations at Florida Power & Light Company, Juno Beach, Florida. E. Gail de Planque (5) 56 President, Strategy Matters, Inc., and Director Energy Strategies Consultancy, Ltd. From 1991 to 1995, Dr. de Planque was a Commissioner with the United States NRC. In 1967, Dr. de Planque joined the Health and Safety Laboratory of the United States Atomic Energy Commission. She served at the Laboratory, now known as the Environmental Measurements Laboratory, until December 1991, as Deputy Director beginning in 1982 and as Director in 1987. William A. DiProfio 58 Retired February 1, 2001. Seabrook Station Director, NAESCO from 1992 to 2000. Ted C. Feigenbaum (6) 50 Executive Vice President and Chief Nuclear Officer of NAEC since February, 1996; previously Senior Vice President of NAEC since 1991; Senior Vice President and Chief Nuclear Officer of PSNH from June 1992 to August 1992; President and Chief Executive Officer-New Hampshire Yankee Division of PSNH from 1990 to 1992 and Chief Nuclear Production Officer of PSNH from 1990 to 1992. John H. Forsgren (7) 54 Executive Vice President and Chief Financial Officer of NU since February 1996; previously Executive Vice President and Chief Financial Officer of CL&P, PSNH, WMECO and NAEC from February 1996 to June 1999; Managing Director of the Chase Manhattan Bank from 1995 to 1996 and Senior Vice President of The Walt Disney Company from 1990 to 1994. Raymond L. Golden (8) 63 Independent Consultant. Previously served as Chairman Emeritus of BT Wolfensohn, New York, New York, a business unit of BT Alex Brown Incorporated. From August 1996 to December 1997, he was Chairman of BT Wolfensohn. Prior to that, he served as President of Wolfensohn & Company. George W. Gram II 52 Director - Support Services, Seabrook Station, NAESCO since December 1999; Previously Director - Site Support from March 1999 to December 1999; and Executive Director of Support Services from 1991 to 1999. Cheryl W. Grise 48 Senior Vice President, Secretary and General Counsel of NU since July 1998; previously Senior Vice President, Secretary and General Counsel of CL&P, PSNH and NAEC and Senior Vice President, Secretary, Assistant Clerk and General Counsel of WMECO from July 1998 to June 1999; Senior Vice President and Chief Administrative Officer of CL&P, PSNH and NAEC, and Senior Vice President of WMECO from 1995 to 1998; Senior Vice President-Human Resources and Administrative Services of CL&P, WMECO and NAEC from 1994 to 1995 and Vice President-Human Resources of CL&P, WMECO and NAEC from 1992 to 1994. Elizabeth T. Kennan (9) 62 President Emeritus of Mount Holyoke College, South Hadley, Massachusetts. Previously President of Mount Holyoke College. Bruce D. Kenyon (10) 58 President and Chief Executive Officer of NAEC since September 1996 and President-Generation Group of NU since March 1999; previously President-Generation Group of CL&P, PSNH and WMECO from March 1999 to June 1999; President-Nuclear Group of NU, CL&P, PSNH and WMECO from September 1996 to March 1999; President and Chief Operating Officer of South Carolina Electric and Gas Company from 1990 to 1996. Kerry J. Kuhlman 50 President and Chief Operating Officer of WMECO since April 1999; previously Vice President-Customer Operations of WMECO from October 1998 to April 1999; Vice President- Central Region of CL&P from August 1997 to October 1998; and Vice President-Eastern Region of CL&P from July 1994 to August 1997. Gerald Letendre (11) 59 President, Diamond Casting & Machine Co., Inc. since 1972. Gary A. Long 49 President and Chief Operating Officer of PSNH since July 1, 2000; previously Senior Vice President-PSNH from February 2000 through June 2000 and Vice President- Customer Service and Economic Development of PSNH from January 1994 to February 2000. Hugh C. MacKenzie 58 Retired January 1, 2001; Previously President - Retail Business Group of NU from February 1996 and President of CL&P from January 1994 through December 2000; previously President of WMECO from January 1994 to April 1999; Senior Vice President-Customer Service Operations of CL&P and WMECO from 1990 to 1994. Paul J. McDonald (12) 57 Advisor to the Board of Directors, Friendly Ice Cream Corporation since January 2000; previously Senior Executive Vice President and Chief Financial Officer, Friendly Ice Cream Corporation, from 1986 to 1999. Michael G. Morris (13) 54 Chairman of the Board, President and Chief Executive Officer of NU, Chairman and Chief Executive Officer of PSNH since July 1, 2000, and Chairman of WMECO since August 1997; previously Chairman and Chief Executive Officer of PSNH from August 1997 to March 2000, previously Chairman of CL&P and NAEC from August 1997 to June 1999; President and Chief Executive Officer of Consumers Power Company from 1994 to 1997 and Executive Vice President and Chief Operating Officer of Consumers Power Company from 1992 to 1994. Jane E. Newman (14) 55 Executive Dean, Harvard University's John F. Kennedy School of Government since July 2000; Previously Managing Director, The Commerce Group, LLC, a strategic communications company, from January 1999 to July 2000; Dean, Whittemore School of Business and Economics of the University of New Hampshire from January 1998 to January 1999; Executive Vice President and Director, Exeter Trust Company from 1995 to 1997 and President, Coastal Broadcasting Corporation from 1992 to 1995. Emery G. Olcott (15) 62 Chairman, President and Chief Executive Officer of Packard BioScience Company (f/k/a Canberra Industries Incorporated), provider of systems and reagents for the life science and genomics industries and radiation detection instrumentation for environmental monitoring and clean up. William J. Pape II (16) 69 Publisher, Waterbury Republican-American, Waterbury, Connecticut (newspaper) and President of American-Republican, Inc. Robert J. Patricelli (17) 61 Chairman, President and Chief Executive Officer of Women's Health USA, Inc. (provides women's health care services), and of Evolution Health, LLC (provides employee benefit services), both of Avon, Connecticut. He is also Chairman of AviaHealth, Inc. (provides internet applications to doctors and patients), of Farmington, Connecticut. From 1987 to 1997, he was Chairman, President and Chief Executive Officer of Value Health, Inc., Avon Connecticut. Previously Executive Vice President of CIGNA Corporation and President of CIGNA's Affiliated Businesses Group. He has held various positions in the federal government, including White House Fellow in 1965; counsel to a United States Senate Subcommittee; Deputy Undersecretary of the Department of Health, Education and Welfare; and Administrator of the United States Urban Mass Transportation Administration. Melinda M. Phelps 57 Partner, Buckley, Richardson & Gelinas, LLP since January 1, 2001 and Police Commissioner, City of Springfield, Massachusetts since 1998. Previously Of Counsel to Buckley, Richardson & Gelinas, LLP, from May 2000 through December 2000; and Partner, Keyes and Donnellan, P.C., from 1992 to 2000. Rodney O. Powell 48 Vice President-Central Region of CL&P since October 1998; previously General Manager- Simsbury of CL&P from October 1997 to October 1998; Manager-Regulatory Relations of NUSCO from December 1995 to October 1997 and Senior Customer Engineering and Marketing Services Consultant of NUSCO from January 1994 to December 1995. Gary D. Simon (18) 52 Senior Vice President-Strategy and Development of NUSCO since April 1998. John F. Swope (19) 62 Previously President and Chief Executive Officer, Public Broadcasting Service, Alexandria, Virginia from 1999 to March 1, 2000. Retired in 1997 as of counsel to the law firm of Sheehan Phinney Bass & Green, Professional Association, Manchester, New Hampshire. Previously President of Chubb Life Insurance Company of America, Concord, New Hampshire (retired December 1994). Lisa J. Thibdaue 47 Vice President-Rates, Regulatory Affairs and Compliance of NUSCO since January 1998; previously Vice President-Rates, Regulatory Affairs and Compliance of CL&P, PSNH and WMECO from January 1998 to June 1999; Executive Director, Rates and Regulatory Affairs, Consumers Power Company from 1996 to 1998 and Director of Regulatory Affairs, Consumers Power Company from 1991 to 1996. John F. Turner (20) 58 President and Chief Executive Officer of The Conservation Fund, Arlington, Virginia (a national nonprofit organization dedicated to land and water conservation and economic development). From 1989 to 1993, he was Director of the United States Fish & Wildlife Service in the United States Department of the Interior. He has also served as President of the Wyoming State Senate. A former Chairman of the Board of Directors of the Bank of Jackson Hole, Mr. Turner continues as a partner in the family ranch business in Wyoming. (1) Ms. Cleveland is a Director of The National Grange Mutual Insurance Company and of the Ledyard National Bank and serves on the Board of the New Hampshire Center for Public Policy. She is the moderator of the Town of New London, New Hampshire. She has served on the University System of New Hampshire Board of Trustees as Chair, Vice Chair and a member and served on the Bank of Ireland First Holdings Board of Directors from 1986 to 1996. She was formerly Co-Chair of the Governor's Commission on New Hampshire in the 21st Century and an Incorporator for the New Hampshire Charitable Foundation. (2) Mr. Cloud is a Director of The Advest Group, Incorporated and Tenet Healthcare Corporation and Chairman of the Board of Ironbridge Mezzanine Fund, L.P. (3) Mr. Collins is a Director of Blue Cross and Blue Shield of Vermont, Hamden Assurance Company Limited and the Business and Industry Association of New Hampshire. (4) Mr. Conway is a member of the American Nuclear Society. He served on the Board of Directors of the Nuclear Utilities Management and Resources Council and its Issues Management Committee. He has also served on the Research Advisory Committee of the Electric Power Research Institute and served as Chairman of its Nuclear Power Division Advisory Committee. A former Chairman of the ABB Combustion Engineering Owners Group Executive Committee, Mr. Conway currently serves on its Advanced Light Water Reactor Executive Advisory Committee. Having been a member of the Institute of Nuclear Power Operations (INPO) Board of Directors, he currently serves on INPO's Advisory Council and is a member of the Accrediting Board of its National Academy for Nuclear Training. Mr. Conway is a Director of First Energy Corporation and is Chairman of its Nuclear Committee. He also serves on the Nuclear Safety Review Board at several nuclear facilities. (5) Dr. de Planque is a Fellow and past President of the American Nuclear Society, a member of the National Academy of Engineering and the National Council on Radiation Protection and Measurements, a Director of British Nuclear Fuels, plc., a Director of British Nuclear Fuels, Inc. and President of the International Nuclear Societies Council. She is a member of the Texas Utilities Electric Operations Review Committee; the Diablo Canyon Independent Safety Committee; the External Advisory Committee; Amarillo National Resource Center for Plutonium; the visiting Committee for the Department of Nuclear Engineering, Massachusetts Institute of Technology; and a consultant to the United Nation's International Atomic Energy Agency. (6) Mr. Feigenbaum is a Director of CYAPC, MYAPC, and VYAPC, and YAEC. (7) Mr. Forsgren is a Director of NEON and The Circle Trust Company and a member of the Board of Regents of Georgetown University. (8) Mr. Golden serves as a Trustee on the National Wildlife Federation Endowment and the Board of the Jewish Federation of Palm Beach County, Florida. (9) Dr. Kennan is a Director of The Putnam Funds and Talbots. She is a member of the Folger Shakespeare Library Committee and is Chairman of Cambus Kenneth Bloodstock, Inc. (10) Mr. Kenyon is a Trustee of Columbia College and Director of CYAPC. (11) Mr. Letendre is a Director of the National Association of Manufacturers (Washington, DC). (12) Mr. McDonald is a Director of CIGNA Investments Inc. and Polytainer's, LLC (Toronto, Canada). (13) Mr. Morris is a Director of the Institute of Nuclear Power Operations, the Nuclear Energy Institute, the Edison Electric Institute, the Association of Edison Illuminating Companies, Nuclear Electric Insurance Limited, Connecticut Business & Industry Association, and the Webster Financial Corporation. Mr. Morris is also a Regent of Eastern Michigan University. (14) Ms. Newman is a Director of Citizens Advisors. (15) Mr. Olcott is Vice Chairman and Trustee of the Loomis Chaffee School and serves on the Dean's Advisory Council for the Sloan School of Management at the Massachusetts Institute of Technology. (16) Mr. Pape is a Director of Platt Bros. & Co. and Paper Delivery, Inc. He is a Trustee of the Connecticut Policy and Economic Council, Inc. and the Waterbury Y.M.C.A. (17) Mr. Patricelli is a Director of Curagen Corporation, the Connecticut Business & Industry Association, and The Bushnell, and a Trustee of Wesleyan University. (18) Mr. Simon is a Director of NEON. (19) Mr. Swope is a Director of the Public Broadcasting Service and PBS Enterprises and the New Hampshire Business Committee for the Arts. He is President of The Currier Gallery of Art and a Trustee of Tabor Academy. (20) Mr. Turner is assisting schools of natural resources at the University of Wyoming, University of Michigan and Yale University with wildlife and land use projects. He is a member of the National Coal Council and a Director of Land Trust Alliance and National Wildlife Refuge Association. There are no family relationships between any director or executive officer and any other director or executive officer of NU, CL&P, PSNH, WMECO, or NAEC. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Securities Exchange Act of 1934 requires Trustees and certain officers of NU and persons who beneficially own more than 10 percent of the outstanding common shares of NU to file reports of ownership and changes in ownership with the SEC and the New York Stock Exchange. Based on review of copies of such forms furnished to NU, or written representations that no Form 5 was required, NU believes that for the year ended December 31, 2000, all such reporting requirements were complied with in a timely manner except that Mr. Cloud failed to include on his Form 3 shares of NU acquired in the Yankee merger, and Mr. Pape failed to report until 2001, 800 shares of CL&P preferred stock acquired in 1994 by a privately-held corporation of which he is a 7.9 percent owner. ITEM 11. EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE The following tables present the cash and non-cash compensation received by the Chief Executive Officer and the next four highest paid executive officers of NU, CL&P, PSNH, WMECO, and NAEC, in accordance with rules of the SEC:
Annual Compensation Long Term Compensation -------------------------------------------- ---------------------- Awards Payouts Securities Other Restrict- Underlying Long Term All Annual ed Stock Options/ Incentive Other Compensa- Award(s) Stock Program Compen- Name and Salary tion ($) ($) Appreciation Payouts sation ($) Principal Position Year ($) Bonus ($) (Note 1) (Note 2) Rights (#) ($) (Note 3) - ------------------ ---- ------ --------- --------- -------- ------------ --------- ---------- Michael G. Morris 2000 830,770 1,200,000 - - 140,000 - 27,326 Chairman of the Board, President 1999 783,173 1,253,300 92,243 348,611 118,352 - 23,210 and Chief Executive Officer 1998 757,692 891,000 134,376 255,261 64,574 - 22,731 Bruce D. Kenyon 2000 504,616 475,000 - - 20,000 - 16,274 President - Generation Group 1999 500,000 - - 77,690 20,804 462,500 15,000 1998 500,000 300,000 - - 21,236 - 14,800 John H. Forsgren 2000 444,615 450,000 - - 36,000 - 5,100 Executive Vice President and 1999 429,904 400,000 - 122,682 32,852 87,003 12,888 Chief Financial Officer 1998 373,077 - - - 73,183 - 104,800 Hugh C. MacKenzie 2000 270,000 250,000 - - 15,000 - 5,100 President - Retail Business Group 1999 270,000 250,000 - 73,612 19,712 - 108,100 1998 270,000 - - - 15,496 42,972 7,500 Cheryl W. Grise 2000 279,616 290,000 - - 23,000 - 8,795 Senior Vice President, 1999 244,712 250,000 - 73,612 19,712 - 82,247 Secretary and General Counsel 1998 209,231 - - - 12,916 20,720 6,123 (in NU, CL&P, PSNH and WMECO tables only) Ted C. Feigenbaum 2000 261,539 145,000 - - 12,000 216,200 8,198 Executive Vice President and 1999 260,000 130,000 - 28,620 7,664 24,827 5,849 Chief Nuclear Officer of NAEC 1998 260,000 48,750 - 40,961 10,044 20,723 7,800 (in NAEC table only)
OPTION/SAR GRANTS IN LAST FISCAL YEAR
Individual Grants Grant Date Value Number of % of Total Securities Options/SARs Underlying Granted to Exercise or Grant Date Options/SARs Employees Base Price Expiration Present Name Granted (#) in Fiscal Year ($/sh) Date Value ($) (Note 4) - ---- ------------ -------------- ----------- ---------- ----------- Michael G. Morris 140,000 22.1 18.4375 2/20/2010 1,027,600 Bruce D. Kenyon 20,000 3.2 18.4375 2/20/2010 146,800 John H. Forsgren 36,000 5.7 18.4375 2/20/2010 264,240 Hugh C. MacKenzie 15,000 2.4 18.4375 2/20/2010 110,100 Cheryl W. Grise 23,000 3.6 18.4375 2/20/2010 168,820 Ted C. Feigenbaum 12,000 1.9 18.4375 2/20/2010 88,080
AGGREGATED OPTIONS/SAR EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES
Shares With Respect to Number of Securities Value of Unexercised Which Underlying Unexercised In-the-Money SARs Were Value Options/SARs Options/SARs Exercised Realized at Fiscal Year End (#) at Fiscal Year End ($) Name (#) ($) Exercisable Unexercisable Exercisable Unexercisable Michael G. Morris - - 495,692 327,234 6,543,905 3,221,429 Bruce D. Kenyon - - 66,424 33,869 658,708 245,405 John H. Forsgren - - 134,605 57,901 1,244,361 413,203 Hugh C. MacKenzie 39,020 380,445 61,087 28,141 (Note 5) 618,289 209,563 Cheryl W. Grise - - 43,977 36,141 436,164 256,063 Ted C. Feigenbaum - - 12,599 36,733 103,518 231,392
Notes to Summary Compensation and Option/SAR Grants Tables: 1. Other annual compensation for Mr. Morris consists of 1998 and 1999 relocation expense reimbursements. 2. At December 31, 2000, the aggregate restricted stock holdings by the five individuals named in the table for NU, CL&P, WMECO, and PSNH were 31,070 shares with a value of $753,448 and for NAEC were 29,062 shares with a value of $704,754. Awards shown for 1998 have vested. Awards shown for 1999 vest one-third on February 23, 2000, one-third on February 23, 2001, and one-third on February 23, 2002. No restricted stock was awarded in 2000. Dividends paid on restricted stock are either paid out or reinvested into additional shares. 3. "All Other Compensation" for 2000 consists of employer matching contributions under the Northeast Utilities Service Company 401(k) Plan, generally available to all eligible employees ($5,100 for each named officer), and matching contributions under the Deferred Compensation Plan for Executives (Mr. Morris - $22,226, Mr. Kenyon - $11,174, Mrs. Grise - $3,695, and Mr. Feigenbaum - $3,098). 4. These options were granted on February 22, 2000, under the Northeast Utilities Incentive Plan. All options granted vest one-third on February 22, 2001, one-third on February 22, 2002, and one-third on February 22, 2003. Valued using the Black-Scholes option pricing model, with the following assumptions: Volatility: 26.06 percent (36 months of monthly data); Risk-free rate: 6.55 percent; Dividend yield: 1.82 percent; Exercise date: February 22, 2010. 5. Mr. MacKenzie's unvested stock options vested and became exercisable upon his retirement on January 1, 2001. COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION Overview and Strategy The Compensation Committee of the Board of Trustees (the Committee) is the administrator of executive compensation for the executives of the NU system (the Company) with authority to establish and interpret the terms of the Company's executive salary and incentive programs. The goal of the Committee's executive compensation program for 2000 was to provide a competitive compensation package to enable the Company to attract and retain key executives with an eye towards the future in a more competitive environment. To help achieve this, the Committee drew upon information from a variety of sources, including compensation consultants, utility and general industry surveys, and other publicly available information, including proxy statements. The Committee further sought to align executive interests with those of NU's shareholders and with Company performance by continuing with the use of share-based incentives as a significant part of executives' compensation. Base Salary The Committee sets the annual base salary for each executive officer except for the Chief Executive Officer (CEO), whose base salary is set by the Board of Trustees following a recommendation by the Committee pursuant to an evaluation process developed by the Committee in conjunction with the Corporate Governance Committee of the Board of Trustees. The Committee periodically adjusts officers' base salaries to reflect considerations such as changes in responsibility, market sensitivity, individual performance and internal equity. In 2000 the Committee reviewed the average salary growth of officers, as reported by several national surveys, with the goal of maintaining the current competitive salary positions. The CEO's base salary was increased by 12.5 percent in 2000 based on the market review and the Committee's judgment as to his past and expected future performance. Annual Incentive Awards The Committee again implemented an Annual Incentive Program during 2000. The incentive payout target was 80 percent of base salary for the CEO, and varied from 25 to 50 percent of base salary for the other officers. The Annual Incentive Program was designed to calculate actual aggregate payouts based on the Company's performance against a net income goal and pre- established individual goals. Individual awards were made in cash in January 2001. The CEO received an award under this program of $1,200,000, or 180 percent of target, determined on the fulfillment of the net income goal and the successful achievement during 2000 of critical strategic, restructuring, operational, and merger related goals. Long-Term Incentive Grants Long-term stock-based incentive grants were made in February 2000 to each executive officer and other officers and certain key employees of the Company. The Committee targeted these awards, which were made entirely in the form of stock options, such that long-term incentive awards for the officer group would be at the 50th percentile of general industry. The CEO's grant was targeted at 158 percent of base salary based upon the Committee's dual goals of market competitiveness and alignment with shareholder interests. Internal Revenue Service Limitation on Deductibility of Executive Compensation The Committee believes that its compensation program adequately responds to issues raised by the deductibility cap placed on executive salaries by Section 162(m) of the Internal Revenue Code because of the use of stock options and qualified performance-based compensation in Company incentive programs. Respectfully submitted, /s/ Robert E. Patricelli, Chairman /s/ William J. Pape II, Vice Chairman /s/ Cotton Mather Cleveland /s/ E. Gail de Planque /s/ Elizabeth T. Kennan /s/ John F. Swope Dated: February 27, 2001 PENSION BENEFITS The following table shows the estimated annual retirement benefits payable to an executive officer of NU upon retirement, assuming that retirement occurs at age 65 and that the officer is at that time not only eligible for a pension benefit under the Northeast Utilities Service Company Retirement Plan (the Retirement Plan) but also eligible for the make-whole benefit and the target benefit under the Supplemental Executive Retirement Plan for Officers of NU system companies (the Supplemental Plan). The Supplemental Plan is a non- qualified pension plan providing supplemental retirement income to system officers. The make-whole benefit under the Supplemental Plan, available to all officers, makes up for benefits lost through application of certain tax code limitations on the benefits that may be provided under the Retirement Plan, and includes as "compensation" awards under the executive incentive plans and deferred compensation (as earned). The target benefit further supplements these benefits and is available to officers at the Senior Vice President level and higher who are selected by the Board of Trustees to participate in the target benefit and who remain in the employ of NU companies until at least age 60 (unless the Board of Trustees sets an earlier age). The benefits presented below are based on a straight life annuity beginning at age 65 and do not take into account any reduction for joint and survivorship annuity payments. Final average compensation for purposes of calculating the target benefit is the highest average annual compensation of the participant during any 36 consecutive months compensation was earned. Compensation taken into account under the target benefit described above includes salary, bonus, restricted stock awards, and long-term incentive payouts shown in the Summary Compensation Table, but does not include employer matching contributions under the 401k Plan. In the event that an officer's employment terminates because of disability, the retirement benefits shown above would be offset by the amount of any disability benefits payable to the recipient that are attributable to contributions made by NU and its subsidiaries under long term disability plans and policies. ANNUAL BENEFIT Final Average Years of Credited Service Compensation 15 20 25 30 35 $ 200,000 $ 72,000 $ 96,000 $120,000 $120,000 $120,000 250,000 90,000 120,000 150,000 150,000 150,000 300,000 108,000 144,000 180,000 180,000 180,000 350,000 126,000 168,000 210,000 210,000 210,000 400,000 144,000 192,000 240,000 240,000 240,000 450,000 162,000 216,000 270,000 270,000 270,000 500,000 180,000 240,000 300,000 300,000 300,000 600,000 216,000 288,000 360,000 360,000 360,000 700,000 252,000 336,000 420,000 420,000 420,000 800,000 288,000 384,000 480,000 480,000 480,000 900,000 324,000 432,000 540,000 540,000 540,000 1,000,000 360,000 480,000 600,000 600,000 600,000 1,100,000 396,000 528,000 660,000 660,000 660,000 1,200,000 432,000 576,000 720,000 720,000 720,000 Each of the executive officers of NU named in the Summary Compensation Table is currently eligible for a target benefit, except Messrs. Morris and Kenyon, whose Employment Agreements provide specially calculated retirement benefits, based on their previous arrangements with CMS Energy/Consumers Energy Company (CMS Energy) and South Carolina Electric and Gas, respectively. Mr. Morris's agreement provides that upon retirement after reaching the fifth anniversary of his employment date (or upon disability or termination without cause or following a change in control, as defined) he will be entitled to receive a special retirement benefit calculated by applying the benefit formula of the CMS Energy Supplemental Executive Retirement Plan to all compensation earned from the NU system and to all service rendered to the Company and CMS Energy. If Mr. Kenyon retires with at least three years of service with the Company, he will be deemed to have 2 extra years of service for purpose of his special retirement benefit. If after achieving three years of service he voluntarily terminates employment following a "substantial change in responsibilities resulting from a material change in the business of Northeast Utilities", he will be deemed to have an additional year of service for purpose of his special retirement benefit, and if he retires with at least 3 years of service with the Company, he will receive a lump sum payment of $500,000. In addition, Mr. Forsgren's Employment Agreement provides for supplemental pension benefits based on crediting up to 10 years additional service and providing payments equal to 25 percent of salary for up to 15 years following retirement, reduced by four percentage points for each year that his age is less than 65 years at retirement. As of December 31, 2000, the executive officers named in the Summary Compensation Table had the following years of credited service for purposes of calculating target benefits under the Supplemental Plan (or in the case of Messrs. Morris and Kenyon, for purposes of calculating the special retirement benefits under their respective Employment Agreements): Mr. Morris - 22, Mr. Kenyon - 6, Mr. Forsgren - 4, Mr. MacKenzie - 35, Mrs. Grise - 20, and Mr. Feigenbaum - 15. In addition, Mr. Forsgren had 9 years of service for purposes of his supplemental pension benefit and would have 25 years of service for such purpose if he were to retire at age 65. Assuming that retirement were to occur at age 65 for these officers, retirement would occur with 33, 13, 15, 47, 36 and 29 years of credited service, respectively. COMPENSATION OF DIRECTORS During 2000, each Trustee who was not an employee of NU or its subsidiaries was compensated at an annual rate of $20,000 cash plus 500 common shares of NU, and received $1,000 for each meeting attended of the Board or its Committees. A non-employee Trustee who participates in a meeting of the Board or any of its Committees by conference telephone receives $675 per meeting. Also, a non-employee Trustee who is asked by either the Board of Trustees or the Chairman of the Board to perform extra services in the interest of the NU system may receive additional compensation of $1,000 per day plus necessary expenses. The Chairs of the Audit, the Compensation, the Corporate Affairs, the Corporate Governance and the Nuclear Committees were compensated at an additional annual rate of $3,500. In addition to the above compensation, Dr. Kennan is paid at the annual rate of $30,000 for the extra services performed as Lead Trustee. The Chair of the Nuclear Committee receives an additional retainer at the rate of $25,000 per year. Under the terms of the Incentive Plan adopted by shareholders at the 1998 Annual Meeting, each non-employee Trustee is eligible for stock-based grants. During 2000 each such Trustee was granted nonqualified options to purchase 2,500 common shares of NU. Receipt of shares acquired on exercise of these options may be deferred pursuant to the terms of the Northeast Utilities Deferred Compensation Plan for Executives. In February 2000, each non-employee Trustee was granted nonqualified options to purchase 2,500 common shares. Prior to the beginning of each calendar year, each non-employee Trustee may irrevocably elect to have all or any portion of the annual retainer fee paid in the form of common shares of NU. Pursuant to the Northeast Utilities Deferred Compensation Plan for Trustees, each Trustee may also irrevocably elect to defer receipt of some or all cash and/or share compensation. During 2000 each non-employee Director of PSNH and WMECO was compensated at an annual rate of $10,000 cash, and received $500 for each meeting attended of the Board of Directors or, in the case of PSNH, its committees. A non- employee Director who participates in a meeting of the Board of Directors or any of its committees by conference telephone receives $300 per meeting. Also, committee chairs were compensated at an additional annual rate of $1,500. EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT ARRANGEMENTS NUSCO has entered into employment agreements (the Officer Agreements) with each of the named executive officers. The Officer Agreements are also binding on NU and on each majority-owned subsidiary of NU. Each Officer Agreement obligates the officer to perform such duties as may be directed by the NUSCO Board of Directors or the NU Board of Trustees, protect the Company's confidential information, and refrain, while employed by the Company and for a period of time thereafter, from competing with the Company in a specified geographic area. Each Officer Agreement provides that the officer's base salary will not be reduced below certain levels without the consent of the officer, and that the officer will participate in specified benefits under the Supplemental Executive Retirement Plan or other supplemental retirement programs (see Pension Benefits, above) and/or in certain executive incentive programs at specified incentive opportunity levels. Each Officer Agreement provides for a specified employment term and for automatic one-year extensions of the employment term unless at least six months' notice of non-renewal is given by either party. The employment term may also be ended by the Company for "cause", as defined, at any time (in which case no supplemental retirement benefit, if any, shall be due), or by the officer on thirty days' prior written notice for any reason. Absent "cause", the Company may remove the officer from his or her position on 60 days' prior written notice, but in the event the officer is so removed and signs a release of all claims against the Company, the officer will receive one or two years' base salary and annual incentive payments, specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock. Under the terms of an Officer Agreement, upon any termination of employment following a change of control, as defined, between (a) the earlier of the date shareholders approve a change of control transaction or a change of control transaction occurs and (b) the earlier of the date, if any, on which the Board of Trustees abandons the transaction or the date 2 years following the change of control, if the officer signs a release of all claims against the Company, the officer will be entitled to certain payments including a multiple (not to exceed four) of annual base salary, annual incentive payments, specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock. Certain of the change in control provisions may be modified by the Board of Trustees prior to a change in control, on at least two years' notice to the affected officer(s). Besides the terms described above, the Officer Agreements of Messrs. Morris, Kenyon and Forsgren provide for a specified salary, cash, restricted stock and/or stock options upon employment, special incentive programs and/or special retirement benefits. See Pension Benefits, above, for further description of these provisions. The descriptions of the various agreements set forth above are for purpose of disclosure in accordance with the proxy and other disclosure rules of the SEC and shall not be controlling on any party; the actual terms of the agreements themselves determine the rights and obligations of the parties. SHARE PERFORMANCE CHART The following chart compares the cumulative total return on an investment in NU common shares with the cumulative total return of the S&P 500 Stock Index and the S&P Electric Companies Index over the last five fiscal years, in accordance with the rules of the SEC: (Assumes $100 invested on January 1, 1996, in NU common shares, S&P 500 Index and S&P Electric Companies Index with all dividends reinvested.) Year Ended December 31, 2000 NU Common* S&P Electric Companies S&P 500 ---------- ---------------------- ------- 1996 59.00 100.00 123.00 1997 55.00 126.00 164.00 1998 75.00 146.00 211.00 1999 97.00 117.00 255.00 2000 116.00 203.00 232.00 *Total return of NU common shares assumes reinvestment of all dividends on payment date. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT NU. The following table provides, as of December 31, 2000, information with respect to persons who are known to NU to beneficially own more than five percent of the common shares of NU. NU has no other class of voting securities. Name and Address Amount and Nature of Percent of of Beneficial Owner Beneficial Ownership Class - ------------------- -------------------- ---------- Barrow, Hanley, Mewhinney 11,274,868 (1) 7.58% & Strauss, Inc. One McKinney Plaza 3232 McKinney Avenue, 15th Floor Dallas, TX Capital Research and 7,525,000 (2) 5.06% Management Company 333 South Hope Street Los Angeles, California 90071 - ----------------------- (1) According to a Statement on Schedule 13G dated February 12, 2001, Barrow, Hanley, Mewhinney & Strauss, Inc. holds 11,274,868 common shares of NU. According to the Schedule 13G, Barrow, Hanley, Mewhinney & Strauss, Inc. has sole voting power for 7,238,468 shares, shared voting power for 4,036,400 shares and sole dispositive power for 11,274,868 shares. (2) According to an Amendment to Schedule 13G dated February 9, 2001, Capital Research and Management Company holds 10,938,200 common shares of NU. According to the Amendment, Capital Research and Management Company has sole voting power for zero shares, shared voting power for zero shares, sole dispositive power for 10,938,200 shares and shared dispositive power for zero shares. The Schedule 13G states that beneficial ownership is disclaimed pursuant to Rule 13d-4. The following table provides information as of February 28, 2001, as to the beneficial ownership of the common shares of NU by each Trustee and nominee for Trustee, each of the 5 highest paid executive officers of NU and its subsidiaries, and all Trustees, nominees for Trustee and executive officers as a group. Unless otherwise noted, each Trustee, nominee and executive officer has sole voting and investment power with respect to the listed shares. Amount and Nature of Percent Name Beneficial Ownership of Class (1) ---- -------------------- ------------ Cotton M. Cleveland 15,169 (2) Sanford Cloud, Jr. 10,913 (3) William F. Conway 14,280 (2)(4) E. Gail de Planque 12,256 (2) John H. Forsgren 115,014 (5) Raymond L. Golden 13,210 (6) Cheryl W. Grise 51,396 (7) Elizabeth T. Kennan 13,600 (2) Bruce D. Kenyon 109,458 (8) Hugh C. MacKenzie 18,360 (9) Michael G. Morris 621,767 (10) Emery G. Olcott 17,751 (3) William J. Pape II 9,203 (2)(11) Robert E. Patricelli 17,877 (2) John F. Swope 15,814 (2) John F. Turner 9,705 (2)(12) All Trustees and Executive Officers as a Group (18 persons) 1,147,925 (13) - ---------------------- (1) As of February 28, 2001, the Trustees and executive officers of NU, as a group, beneficially owned less than one percent of the NU common shares outstanding. (2) Includes 8,750 shares that could be acquired by the beneficial owner pursuant to currently exercisable options. (3) Includes 3,750 shares that could be acquired by the beneficial owner pursuant to currently exercisable options. (4) Includes 5,530 shares held jointly by Mr. Conway and his wife, who share voting and investment power. (5) Includes 2,738 restricted shares, as to which Mr. Forsgren has sole voting power but no dispositive power. Includes 107,087 shares that could be acquired by Mr. Forsgren pursuant to currently exercisable options. (6) Includes 6,250 shares that could be acquired by Mr. Golden pursuant to currently exercisable options. (7) Includes 1,643 restricted shares, as to which Mrs. Grise has sole voting power, but no dispositive power. Includes 33,724 shares that could be acquired by Mrs. Grise pursuant to currently exercisable options. Includes 265 shares held by Mrs. Grise's husband as custodian for her children, with whom she shares voting and dispositive power. (8) Includes 1,734 restricted shares, as to which Mr. Kenyon has sole voting power but no dispositive power. Includes 41,772 shares that could be acquired by Mr. Kenyon pursuant to currently exercisable options. (9) Mr. MacKenzie retired effective January 1, 2001. Beneficial ownership is given as of December 31, 2000, and includes 3,285 restricted shares, as to which Mr. MacKenzie had sole voting power but no dispositive power, and 22,067 shares that could be acquired by Mr. MacKenzie pursuant to then exercisable options. Mr. MacKenzie's restricted stock and 28,141 unvested options vested upon his retirement. (10) Includes 7,779 restricted shares, as to which Mr. Morris has sole voting power but no dispositive power. Includes 573,476 shares that could be acquired by Mr. Morris pursuant to currently exercisable options. Includes 13,499 shares held jointly by Mr. Morris and his wife, who share voting and investment power. (11) Includes 5,176 shares as to which Mr. Pape shares voting and dispositive power. Includes 1,250 shares that could be acquired by Mr. Pape pursuant to currently exercisable options. In addition, Mr. Pape shares beneficial ownership of 800 shares of CL&P 4.50% Preferred Series 1956. (12) Includes 955 shares held jointly by Mr. Turner and his wife, who share voting and investment power. (13) Includes 2,053 restricted shares held by executive officers other than those named in the table above as to which they have sole voting power but no dispositive power. Includes 70,623 shares that could be acquired by them pursuant to currently exercisable options. CL&P, PSNH, WMECO, and NAEC. NU owns 100% of the outstanding common stock of registrants CL&P, PSNH, WMECO, and NAEC. As of February 28, 2001, the Directors and Executive Officers of CL&P, PSNH, WMECO, and NAEC beneficially owned the number of shares of each class of equity securities of NU listed below. No equity securities of CL&P, PSNH, WMECO, or NAEC are owned by the Directors and Executive Officers of CL&P, PSNH, WMECO, and NAEC. Unless otherwise noted, each Director and Executive Officer of CL&P, PSNH, WMECO, and NAEC has sole voting and investment power with respect to the listed shares. Title of Amount and Nature of Percent of Class Name Beneficial Ownership Class (1) NU Common David H. Boguslawski 23,246 (2) NU Common James E. Byrne None NU Common John C. Collins None NU Common William A. DiProfio 5,326 (3) NU Common Ted C. Feigenbaum 38,459 (4) NU Common John H. Forsgren 115,014 (5) NU Common George R. Gram II 6,634 (6) NU Common Cheryl W. Grise 51,396 (7) NU Common Bruce D. Kenyon 109,458 (8) NU Common Kerry J. Kuhlman 14,509 (9) NU Common Gerald Letendre None NU Common Gary A. Long 13,078 (10) NU Common Hugh C. MacKenzie 18,360 (11) NU Common Paul J. McDonald 500 NU Common Michael G. Morris 621,767 (12) NU Common Jane E. Newman None NU Common Melinda M. Phelps None NU Common Rodney O. Powell 8,288 (13) Amount beneficially owned by Directors and Executive Officers as a group: Amount and Nature of Company Number of Persons Beneficial Ownership CL&P 8 969,352 (14) PSNH 11 974,142 (14) WMECO 22 976,073 (14) NAEC 7 948,054 (1) As of February 28, 2001, there were 148,780,800 common shares of NU outstanding. The percentage of such shares beneficially owned by any Director or Executive Officer, and by all Directors and Executive Officers of CL&P, PSNH, WMECO, and NAEC as a group, does not exceed one percent. (2) Includes 730 restricted shares, as to which Mr. Boguslawski has sole voting power but no dispositive power. Includes 15,512 shares that could be acquired by Mr. Boguslawski pursuant to currently exercisable options. (3) Mr. DiProfio retired effective February 1, 2001. Beneficial ownership is given as of January 31, 2001, and includes 879 shares that could be acquired by Mr. DiProfio pursuant to then exercisable options. 1,295 unvested options vested upon Mr. DiProfio's retirement. (4) Includes 639 restricted shares, as to which Mr. Feigenbaum has sole voting power but no dispositive power. Includes 19,153 shares that could be acquired by Mr. Feigenbaum pursuant to currently exercisable options. (5) Includes 2,738 restricted shares, as to which Mr. Forsgren has sole voting power but no dispositive power. Includes 107,087 shares that could be acquired by Mr. Forsgren pursuant to currently exercisable options. (6) Includes 5,283 shares that could be acquired by Mr. Gram pursuant to currently exercisable options. (7) Includes 1,643 restricted shares, as to which Mrs. Grise has sole voting power, but no dispositive power. Includes 33,724 shares that could be acquired by Mrs. Grise pursuant to currently exercisable options. Includes 265 shares held by Mrs. Grise's husband as custodian for her children, with whom she shares voting and dispositive power. (8) Includes 1,734 restricted shares, as to which Mr. Kenyon has sole voting power but no dispositive power. Includes 41,772 shares that could be acquired by Mr. Kenyon pursuant to currently exercisable options. (9) Includes 342 restricted shares, as to which Ms. Kuhlman has sole voting power but no dispositive power. Includes 8,395 shares that could be acquired by Ms. Kuhlman pursuant to currently exercisable options. (10) Includes 319 restricted shares, as to which Mr. Long has sole voting power but no dispositive power. Includes 7,590 shares that could be acquired by Mr. Long pursuant to currently exercisable options. (11) Mr. MacKenzie retired effective January 1, 2001. Beneficial ownership is given as of December 31, 2000, and includes 3,285 restricted shares, as to which Mr. MacKenzie had sole voting power but no dispositive power, and 22,067 shares that could be acquired by Mr. MacKenzie pursuant to then exercisable options. Mr. MacKenzie's restricted stock and 28,141 unvested options vested upon his retirement. (12) Includes 7,779 restricted shares, as to which Mr. Morris has sole voting power but no dispositive power. Includes 573,476 shares that could be acquired by Mr. Morris pursuant to currently exercisable options. Includes 13,499 shares held jointly by Mr. Morris and his wife, who share voting and investment power. (13) Includes 249 restricted shares, as to which Mr. Powell has sole voting power but no dispositive power. Includes 6,750 shares that could be acquired by Mr. Powell pursuant to currently exercisable options. (14) Includes 684 restricted shares held by an executive officer other than those named in the table above as to which such officer has sole voting power but no dispositive power. Includes 16,174 shares that could be acquired by such officer pursuant to currently exercisable options. CHANGES IN CONTROL See Item 1 - Business - Mergers and Acquisitions - Consolidated Edison, Inc. Merger on pages 3-4. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The law firm of Sulloway and Hollis provided legal services to NU, PSNH and NAEC during 2000. John B. Garvey, who is the husband of Cotton M. Cleveland, a Trustee of NU, is a member of the firm. ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. Financial Statements: The Report of Independent Public Accountants and financial statements of CL&P, PSNH, WMECO, and NAEC are hereby incorporated by reference and made a part of this report (see "Item 8. Financial Statements and Supplementary Data"). Report of Independent Public Accountants on Schedules S-1 Consent of Independent Public Accountants S-2 2. Schedules: Financial Statement Schedules for NU (Parent), NU and Subsidiaries, CL&P and Subsidiaries, PSNH, and WMECO and Subsidiary are listed in the Index to Financial Statements Schedules S-3 3. Exhibits Index E-1 (b) Reports on Form 8-K: NU filed a current report on Form 8-K dated February 29, 2000, disclosing: o The 1999 financial statements for NU consolidated and notes thereto and management's discussion and analysis of financial condition and results of operations relating to the 1999 financial statements. NU filed a current report on Form 8-K dated March 1, 2000, disclosing: o The completion of the merger with Yankee. NU, CL&P and WMECO filed current reports on Form 8-K dated March 14, 2000, disclosing: o The transfer of approximately 1,289 MW of hydroelectric and pumped storage generation assets in Connecticut and Massachusetts to NGC. NU filed a current report on Form 8-K dated March 29, 2000, disclosing: o The supplement to the joint proxy statement/prospectus for the special meeting of shareholders related to the Con Edison merger. NU filed a current report on Form 8-K dated September 27, 2000, disclosing: o The Utility Operations Management Analysis Unit of the DPUC recommended that the DPUC approve the results of the recently completed auction of the Millstone nuclear units. NU filed a current report on Form 8-K dated October 24, 2000, disclosing: o Con Edison issued a press release on October 23, 2000, regarding the DPUC's decision on October 19, 2000, which approved the proposed merger between NU and Con Edison, subject to a number of conditions. NU filed a current report on Form 8-K dated October 24, 2000, disclosing: o NU's earnings press release for the third quarter of 2000. NU filed a current report on Form 8-K dated October 31, 2000, disclosing: o NU's and Con Edison's presentation dated October 31, 2000, entitled "The Northeast's Energy Company." NU filed a current report on Form 8-K dated January 23, 2001, disclosing: o NU's earnings press release for the fourth quarter and full year 2000. NU filed a current report on Form 8-K dated February 28, 2001, disclosing: o NU's news release formally seeking Con Edison's assurance of intent to close merger. NU filed a current report on Form 8-K dated March 5, 2001, disclosing: o NU declares Con Edison in breach of merger agreement. NU to sue Con Edison to recover value of merger for NU shareholders. NU filed a current report on Form 8-K dated March 12, 2001, disclosing: o NU filed suit in the U.S. District Court for the Southern District seeking for itself and its shareholders in excess of $1 billion in damages arising from Con Edison's breach of the merger agreement. NU filed a current report on Form 8-K dated March 22, 2001, disclosing: o NU's news release announcing revised 2000 earnings and confirming 2001 projected earnings. NORTHEAST UTILITIES 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. NORTHEAST UTILITIES ------------------- (Registrant) Date: March 16, 2001 By /s/ Michael G. Morris ---------------------------- Michael G. Morris Chairman of the Board, President and Chief Executive Officer 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 dates indicated. Date Title Signature - ---- ----- --------- March 16, 2001 Chairman of the Board, /s/ Michael G. Morris President and -------------------------- Chief Executive Officer Michael G. Morris and a Trustee March 16, 2001 Executive Vice /s/ John H. Forsgren President and Chief -------------------------- Financial Officer John H. Forsgren and a Trustee March 16, 2001 Vice President and /s/ John J. Roman Controller -------------------------- John J. Roman March 16, 2001 Trustee /s/ Cotton M. Cleveland -------------------------- Cotton M. Cleveland March 16, 2001 Trustee /s/ Sanford Cloud, Jr. -------------------------- Sanford Cloud, Jr. March 16, 2001 Trustee /s/ William F. Conway -------------------------- William F. Conway March 16, 2001 Trustee /s/ E. Gail de Planque -------------------------- E. Gail de Planque March 16, 2001 Trustee /s/ Raymond L. Golden -------------------------- Raymond L. Golden March 16, 2001 Trustee /s/ Elizabeth T. Kennan -------------------------- Elizabeth T. Kennan March 16, 2001 Trustee /s/ Emery G. Olcott -------------------------- Emery G. Olcott March 16, 2001 Trustee /s/ William J. Pape II -------------------------- William J. Pape II March 16, 2001 Trustee /s/ Robert E. Patricelli -------------------------- Robert E. Patricelli March 16, 2001 Trustee /s/ John F. Swope -------------------------- John F. Swope March 16, 2001 Trustee /s/ John F. Turner -------------------------- John F. Turner THE CONNECTICUT LIGHT AND 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 CONNECTICUT LIGHT AND POWER COMPANY --------------------------------------- (Registrant) Date: March 16, 2001 By /s/ Michael G. Morris ------------------------------------ Michael G. Morris Chief Executive Officer 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 dates indicated. Date Title Signature - ---- ----- --------- March 16, 2001 Treasurer /s/ Randy A. Shoop ----------------------------- Randy A. Shoop March 16, 2001 Controller /s/ John P. Stack ----------------------------- John P. Stack March 16, 2001 Director /s/ David H. Boguslawski ----------------------------- David H. Boguslawski March 16, 2001 Director /s/ Rodney O. Powell ----------------------------- Rodney O. Powell PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 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. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE --------------------------------------- (Registrant) Date: March 16, 2001 By /s/ Michael G. Morris ------------------------------------ Michael G. Morris Chairman and Chief Executive Officer 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 dates indicated. Date Title Signature - ---- ----- --------- March 16, 2001 Chairman and Chief /s/ Michael G. Morris Executive Officer ----------------------------- and a Director Michael G. Morris March 16, 2001 President and Chief /s/ Gary A. Long Operating Officer and ----------------------------- a Director Gary A. Long March 16, 2001 Vice President and /s/ David R. McHale Treasurer ----------------------------- David R. McHale March 16, 2001 Vice President /s/ John J. Roman and Controller ----------------------------- John J. Roman March 16, 2001 Director /s/ David H. Boguslawski ----------------------------- David H. Boguslawski March 16, 2001 Director /s/ John C. Collins ----------------------------- John C. Collins March 16, 2001 Director /s/ John H. Forsgren ----------------------------- John H. Forsgren March 16, 2001 Director /s/ Gerald Letendre ----------------------------- Gerald Letendre March 16, 2001 Director /s/ Jane E. Newman ----------------------------- Jane E. Newman WESTERN MASSACHUSETTS ELECTRIC 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. WESTERN MASSACHUSETTS ELECTRIC COMPANY -------------------------------------- (Registrant) Date: March 16, 2001 By /s/ Michael G. Morris ---------------------------------- Michael G. Morris Chairman and Chief Executive Officer 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 dates indicated. Date Title Signature - ---- ----- --------- March 16, 2001 Chairman and Chief /s/ Michael G. Morris Executive Officer ----------------------------- and a Director Michael G. Morris March 16, 2001 President and /s/ Kerry J. Kuhlman Chief Operating ----------------------------- Officer and a Director Kerry J. Kuhlman March 16, 2001 Vice President /s/ David R. McHale and Treasurer ----------------------------- David R. McHale March 16, 2001 Vice President /s/ John J. Roman and Controller ----------------------------- John J. Roman March 16, 2001 Director /s/ David H. Boguslawski ----------------------------- David H. Boguslawski March 16, 2001 Director /s/ James E. Byrne ----------------------------- James E. Byrne March 16, 2001 Director /s/ John H. Forsgren ----------------------------- John H. Forsgren March 16, 2001 Director /s/ Paul J. McDonald ----------------------------- Paul J. McDonald March 16, 2001 Director /s/ Melinda M. Phelps ----------------------------- Melinda M. Phelps NORTH ATLANTIC ENERGY CORPORATION 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. NORTH ATLANTIC ENERGY CORPORATION --------------------------------- (Registrant) Date: March 16, 2001 By /s/ Bruce D. Kenyon ------------------------------------ Bruce D. Kenyon President and Chief Executive Officer 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 dates indicated. Date Title Signature - ---- ----- --------- March 16, 2001 President and Chief /s/ Bruce D. Kenyon Executive Officer ------------------------------ and a Director Bruce D. Kenyon March 16, 2001 Vice President and /s/ David R. McHale Treasurer of Northeast ----------------------------- Utilities Service David R. McHale Company as Agent for North Atlantic Energy Corporation March 16, 2001 Vice President and /s/ John J. Roman and Controller of ----------------------------- Northeast Utilities John J. Roman Service Company as Agent for North Atlantic Energy Corporation March 16, 2001 Director /s/ Ted C. Feigenbaum ----------------------------- Ted C. Feigenbaum March 16, 2001 Director /s/ George R. Gram ---------------------------- George R. Gram REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES ----------------------------------------------------- We have audited in accordance with auditing standards generally accepted in the United States, the financial statements included in Northeast Utilities' annual report on Form 10-K and The Connecticut Light and Power Company's, Western Massachusetts Electric Company's, Public Service Company of New Hampshire's, and North Atlantic Energy Corporation's annual reports, incorporated by reference in this Form 10-K, and have issued our reports thereon dated January 23, 2001 (except with respect to the matters discussed in Note 15, Note 15, Note 14, Note 14, and Note 11 for Northeast Utilities, The Connecticut Light and Power Company, Western Massachusetts Electric Company, Public Service Company of New Hampshire, and North Atlantic Energy Corporation, respectively, as to which the date is March 13, 2001). Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the accompanying Index to Financial Statements Schedules are the responsibility of the companies' management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not a part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/ Arthur Andersen LLP Arthur Andersen LLP Hartford, Connecticut January 23, 2001 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS ----------------------------------------- As independent public accountants, we hereby consent to the incorporation of our reports dated January 23, 2001 (except with respect to the matters discussed in Note 15 for Northeast Utilities and The Connecticut Light and Power Company, Note 14 for Western Massachusetts Electric Company and Public Service Company of New Hampshire, and Note 11 for North Atlantic Energy Corporation, as to which the date is March 13, 2001), included (or incorporated by reference) in this Form 10-K into the Company's previously filed Registration Statements No. 33-55279 of The Connecticut Light and Power Company, No. 33-56537 of CL&P Capital, LP and No. 33-34622, No. 33-44814, No. 33-63023, No. 33-40156, No. 333-52413, No. 333-52415, and No. 333-85613 of Northeast Utilities. It should be noted that we have not audited any financial statements of the Company subsequent to December 31, 2000 or performed any audit procedures subsequent to the date of our report. /s/ Arthur Andersen LLP Arthur Andersen LLP Hartford, Connecticut March 27, 2001 INDEX TO FINANCIAL STATEMENTS SCHEDULES Schedule I. Financial Information of Registrant: Northeast Utilities (Parent) Balance Sheets 2000 and 1999 S-4 Northeast Utilities (Parent) Statements of Income 2000, 1999, and 1998 S-5 Northeast Utilities (Parent) Statements of Cash Flows 2000, 1999, and 1998 S-6 II. Valuation and Qualifying Accounts and Reserves 2000, 1999, and 1998: Northeast Utilities and Subsidiaries S-7 - S-9 The Connecticut Light and Power Company and Subsidiaries S-10 - S-12 Public Service Company of New Hampshire S-13 - S-15 Western Massachusetts Electric Company and Subsidiary S-16 - S-18 All other schedules of the companies' for which provision is made in the applicable regulations of the SEC are not required under the related instructions or are not applicable, and therefore have been omitted. SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT BALANCE SHEETS AT DECEMBER 31, 2000 AND 1999 (Thousands of Dollars)
2000 1999 ---------- ---------- ASSETS - ------ Other Property and Investments: Investments in subsidiary companies, at equity............ $2,687,804 $2,252,175 Investments in transmission companies, at equity.......... 15,011 16,460 Other, at cost............................................ 14 54 ----------- ----------- 2,702,829 2,268,689 ----------- ----------- Current Assets: Cash...................................................... 1,058 - Notes receivable from affiliated companies................ 94,400 45,300 Notes and accounts receivable............................. 868 625 Receivables from affiliated companies..................... 3,908 8,351 Taxes receivable.......................................... - 418 Prepayments............................................... 3,744 1,192 ----------- ----------- 103,978 55,886 ----------- ----------- Deferred Charges: Unamortized debt expense.................................. 13 6 Other..................................................... 321 122 Deferred Yankee Energy System, Inc. acquisition expenses.. - 3,427 ----------- ----------- 334 3,555 ----------- ----------- Total Assets......................................... $2,807,141 $2,328,130 =========== =========== CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common Shareholders' Equity: Common shares, $5 par value - authorized 225,000,000 shares; 148,781,861 shares issued and 143,820,405 shares outstanding in 2000 and 137,393,829 shares issued and 131,870,284 outstanding in 1999......................... $ 693,345 $ 636,405 Capital surplus, paid in.................................. 927,059 776,290 Temporary equity from stock forward....................... 215,000 215,000 Deferred contribution plan - employee stock ownership plan (114,463) (127,725) Retained earnings......................................... 495,873 581,817 Accumulated other comprehensive income.................... 1,769 1,524 ----------- ----------- Total common shareholders' equity....................... 2,218,583 2,083,311 Long-term debt............................................ 117,000 138,000 ----------- ----------- Total capitalization.................................... 2,335,583 2,221,311 ----------- ----------- Current Liabilities: Long-term debt - current portion.......................... 21,000 20,000 Notes payable to banks.................................... 436,000 65,000 Accounts payable.......................................... 966 7,258 Accounts payable to affiliated companies.................. 18 1,201 Accrued taxes............................................. 1,135 - Accrued interest.......................................... 6,961 1,705 Accrued Con Edison/Northeast Utilities merger fees........ 20 6,143 ----------- ----------- 466,100 101,307 ----------- ----------- Accumulated deferred income taxes........................... 5,026 5,302 Other deferred credits...................................... 432 210 ----------- ----------- 5,458 5,512 ----------- ----------- Total Capitalization and Liabilities $2,807,141 $2,328,130 =========== ===========
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 2000, 1999, AND 1998 (Thousands of Dollars Except Share Information) 2000 1999 1998 ------------- ------------- ------------- Operating Revenues................ $ - $ - $ - ------------- ------------- ------------- Operating Expenses: Other........................... 15,335 19,126 7,674 Federal income taxes............ 2,708 (4,849) 1,569 ------------- ------------- ------------- Total operating expenses....... 18,043 14,277 9,243 ------------- ------------- ------------- Operating Loss.................... (18,043) (14,277) (9,243) ------------- ------------- ------------- Other Income/(Loss): Equity in earnings/(loss) of subsidiaries................ 23,553 56,812 (145,874) Equity in earnings of transmission companies......... 2,553 2,608 2,903 Other, net...................... 9,134 2,628 21,995 Income taxes.................... 2,036 2,057 - ------------- ------------- ------------- Other income/(loss), net...... 37,276 64,105 (120,976) ------------- ------------- ------------- Income/(loss) before interest charges...................... 19,233 49,828 (130,219) ------------- ------------- ------------- Interest Charges.................. 47,819 15,612 16,534 ------------- ------------- ------------- (Loss)/Earnings for Common Shares. $ (28,586) $ 34,216 $ (146,753) ============= ============= ============= Basic and Fully Diluted (Loss)/ Earnings Per Common Share....... $ (0.20) $ 0.26 $ (1.12) ============= ============= ============= Basic Common Shares Outstanding (average)............ 141,549,860 131,415,126 130,549,760 ============= ============= ============= Fully Diluted Common Shares Outstanding (average)............ 141,967,216 132,031,573 130,549,760 ============= ============= ============= SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Thousands of Dollars)
2000 1999 1998 ------------ -------------- -------------- Operating Activities: Net (loss)/income........................................ $ (28,586) $ 34,216 $ (146,753) Adjustments to reconcile to net cash provided by operating activities: Equity in earnings of subsidiary companies............. (23,553) (56,812) 145,874 Cash dividends received from subsidiary companies...... 183,016 66,000 47,000 Deferred income taxes.................................. (276) 74 777 Other sources of cash.................................. 3,276 16,655 20,926 Changes in working capital: Receivables.......................................... 4,200 (7,220) (84) Accounts payable..................................... (7,475) 5,863 523 Other working capital (excludes cash)................ (1,866) 12,191 (15,981) ------------ -------------- -------------- Net cash flows provided by operating activities............ 128,736 70,967 52,282 ------------ -------------- -------------- Investing Activities: NU system Money Pool..................................... (49,100) (10,900) (200) Investment in subsidiaries............................... (117,631) (99,462) (40,029) Other investment activities, net......................... 1,489 1,245 2,278 Payment for the purchase of Yankee Energy System, Inc.... (260,347) - - ------------ -------------- -------------- Net cash flows used in investing activities................ (425,589) (109,117) (37,951) ------------ -------------- -------------- Financing Activities: Issuance of common shares................................ 4,269 5,318 2,659 Net increase in short-term debt.......................... 371,000 65,000 - Reacquisitions and retirements of long-term debt......... (20,000) (19,000) (17,000) Cash dividends on common shares.......................... (57,358) (13,168) - ------------ -------------- -------------- Net cash flows provided by/(used in) financing activities.. 297,911 38,150 (14,341) ------------ -------------- -------------- Net increase/(decrease) in cash for the period............. 1,058 - (10) Cash - beginning of period................................. - - 10 ------------ -------------- -------------- Cash - end of period....................................... $ 1,058 $ - $ - ============ ============== ============== Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized..................... $ 39,099 $ 15,724 $ 16,610 ============ ============== ============== Income taxes............................................. $ 1,430 $ 28,982 $ 16,929 ============ ============== ==============
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 2000 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 4,895 $26,740 $ 130 (c) $19,265 (a) $12,500 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $44,995 $22,573 $37,680 (c) $25,967 (b) $79,281 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith. (c) Amounts represent activity related to the acquisition of Yankee on March 1, 2000.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1999 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,417 $ 8,026 $ - $ 5,548 (a) $ 4,895 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $40,438 $18,597 $ - $14,040 (b) $44,995 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1998 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,052 $ 3,042 $ - $ 2,677 (a) $ 2,417 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $34,437 $12,427 $ - $ 6,426 (b) $40,438 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 2000 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 300 $ 9,270 $ - $ 9,270 (a) $ 300 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $16,069 $ 7,488 $ - $ 9,897 (b) $13,660 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1999 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 300 $ 290 $ - $ 290 (a) $ 300 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $16,656 $ 5,422 $ - $ 6,009 (b) $16,069 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1998 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 300 $ 183 $ - $ 183 (a) $ 300 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $14,962 $ 5,612 $ - $ 3,918 (b) $16,656 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 2000 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 1,359 $ 2,220 $ - $ 1,710 (a) $ 1,869 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $11,405 $ 9,855 $ - $ 9,610 (b) $11,650 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1999 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,041 $ 1,590 $ - $ 2,272 (a) $ 1,359 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 9,906 $ 7,268 $ - $ 5,769 (b) $11,405 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1998 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 1,702 $ 2,726 $ - $ 2,387 (a) $ 2,041 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 7,788 $ 4,136 $ - $ 2,018 (b) $ 9,906 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 2000 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 1,640 $ 2,416 $ - $ 2,170 (a) $ 1,886 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 7,188 $ 1,130 $ - $ 1,558 (b) $ 6,760 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1999 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 50 $ 4,564 $ - $ 2,974 (a) $ 1,640 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 5,960 $ 3,085 $ - $ 1,857 (b) $ 7,188 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1998 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions ---------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 50 $ 106 $ - $ 106 (a) $ 50 ======= ======= ======= ======= ======= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 5,503 $ 816 $ - $ 359 (b) $ 5,960 ======= ======= ======= ======= ======= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
EXHIBIT INDEX Each document described below is incorporated by reference to the files of the SEC, unless the reference to the document is marked as follows: * - Filed with the 2000 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324 into the 2000 Annual Reports on Form 10-K for CL&P, PSNH, WMECO, and NAEC. # - Filed with the 2000 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324 into the 2000 Annual Report on Form 10-K for CL&P. @ - Filed with the 2000 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324 into the 2000 Annual Report on Form 10-K for PSNH. ** - Filed with the 2000 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324 into the 2000 Annual Report on Form 10-K for WMECO. ## - Filed with the 2000 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2000 Form 10-K, File No. 1-5324 into the 2000 Annual Report on Form 10-K for NAEC. Exhibit Number Description 2 Plan of acquisition, reorganization, arrangement, liquidation or succession 2.1 Agreement and Plan of Merger (Exhibit 1 in NU's Current Report on Form 8-K dated June 14, 1999, File No. 1-5324) 2.2 Agreement and Plan of Merger (Exhibit 1 to NU's Current Report on Form 8-K dated October 13, 1999, File No. 1-5324) 3 Articles of Incorporation and By-Laws 3.1 Northeast Utilities 3.1.1 Declaration of Trust of NU, as amended through May 24, 1988. (Exhibit 3.1.1, 1988 NU Form 10-K, File No. 1-5324) 3.2 The Connecticut Light and Power Company 3.2.1 Certificate of Incorporation of CL&P, restated to March 22, 1994. (Exhibit 3.2.1, 1993 NU Form 10-K, File No. 1-5324) 3.2.2 Certificate of Amendment to Certificate of Incorporation of CL&P, dated December 26, 1996. (Exhibit 3.2.2, 1996 NU Form 10-K, File No. 1-5324) 3.2.3 Certificate of Amendment to Certificate of Incorporation of CL&P, dated April 27, 1998. (Exhibit 3.2.3, 1998 NU Form 10-K, File No. 1-5324) 3.2.4 By-laws of CL&P, as amended to January 1, 1997. (Exhibit 3.2.3, 1996 NU Form 10-K, File No. 1-5324) 3.3 Public Service Company of New Hampshire 3.3.1 Articles of Incorporation, as amended to May 16, 1991. (Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324) 3.3.2 By-laws of PSNH, as amended to November 1, 1993. (Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324) 3.4 Western Massachusetts Electric Company 3.4.1 Articles of Organization of WMECO, restated to February 23, 1995. (Exhibit 3.4.1, 1994 NU Form 10-K, File No. 1-5324) 3.4.2 By-laws of WMECO, as amended to April 1, 1999. (Exhibit 3.1, 1999 NU Form 10-Q for the Quarter Ended June 30, 1999, File No. 1-5324) 3.4.3 By-laws of WMECO, as further amended to May 1, 2000. (Exhibit 3.1, 2000 NU Form 10-Q for the Quarter Ended June 30, 2000, File No. 1-5324) 3.5 North Atlantic Energy Corporation 3.5.1 Articles of Incorporation of NAEC dated September 20, 1991. (Exhibit 3.5.1, 1993 NU Form 10-K, File No. 1-5324) 3.5.2 Articles of Amendment dated October 16, 1991 and June 2, 1992, to Articles of Incorporation of NAEC. (Exhibit 3.5.2, 1993 NU Form 10-K, File No. 1-5324) 3.5.3 By-laws of NAEC, as amended to November 8, 1993. (Exhibit 3.5.3, 1993 NU Form 10-K, File No. 1-5324) 3.5.4 By-laws of NAEC, as amended to June 1, 2000. (Exhibit 3.1, 2000 NU Form 10-Q for the Quarter Ended September 30, 2000, File No. 1-5324) 4 Instruments defining the rights of security holders, including indentures 4.1 Northeast Utilities 4.1.1 Indenture dated as of December 1, 1991, between Northeast Utilities and IBJ Schroder Bank & Trust Company, with respect to the issuance of Debt Securities. (Exhibit 4.1.1, 1991 NU Form 10-K, File No. 1-5324) 4.1.2 First Supplemental Indenture dated as of December 1, 1991, between Northeast Utilities and IBJ Schroder Bank & Trust Company, with respect to the issuance of Series A Notes. (Exhibit 4.1.2, 1991 NU Form 10-K, File No. 1-5324) 4.1.3 Second Supplemental Indenture dated as of March 1, 1992, between Northeast Utilities and IBJ Schroder Bank & Trust Company with respect to the issuance of 8.38% Amortizing Notes. (Exhibit 4.1.3, 1992 NU Form 10-K, File No. 1-5324) 4.1.4 Credit Agreement among NU, CL&P, WMECO and the Co-Agents and Banks named therein, dated as of November 17, 2000, (includes Open End Mortgages), (Exhibit No. 2 on 35-CERT filed November 27, 2000, File No. 70-8875) *4.1.5 Term Loan Agreement among NU and the Banks named therein, dated as of March 1, 2000. *4.1.5.1 First Amendment to Term Loan Agreement dated as of December 15, 2000. 4.1.6 Indenture between NU and The Bank of New York, as Trustee, dated as of February 28, 2001, relating to Senior Notes (Exhibit A-1 to 35-CERT filed March 9, 2001, File No. 70-9535) 4.1.6.1 First Supplemental Indenture to the Indenture, dated as of February 28, 2001, between NU and The Bank of New York, as Trustee, relating to Floating Rate Notes Due 2003 (Exhibit A-2 to 35-CERT filed March 9, 2001, File No. 70-9535) 4.2 The Connecticut Light and Power Company 4.2.1 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921. (Composite including all twenty-four amendments to May 1, 1967.) (Exhibit 4.1.1, 1989 NU Form 10-K, File No. 1-5324) Supplemental Indentures to the Composite May 1, 1921, Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of: 4.2.2 December 1, 1969. (Exhibit 4.2.2, 1998 NU Form 10-K, File No. 1-5324) 4.2.3 June 30, 1982. (Exhibit 4.33, File No. 2-79235) 4.2.4 December 1, 1989. (Exhibit 4.1.26, 1989 NU Form 10-K, File No. 1-5324) 4.2.5 July 1, 1992. (Exhibit 4.31, File No. 33-59430) 4.2.6 July 1, 1993. (Exhibit A.10(b), File No. 70-8249) 4.2.7 July 1, 1993. (Exhibit A.10(b), File No. 70-8249) 4.2.8 December 1, 1993. (Exhibit 4.2.14, 1993 NU Form 10-K, File No. 1-5324) 4.2.9 February 1, 1994. (Exhibit 4.2.16, 1993 NU Form 10-K, File No. 1-5324) 4.2.10 June 1, 1994. (Exhibit 4.2.15, 1994 NU Form 10-K, File No. 1-5324) 4.2.11 October 1, 1994. (Exhibit 4.2.16, 1994 NU Form 10-K, File No. 1-5324) 4.2.12 June 1, 1996. (Exhibit 4.2.16, 1996 NU Form 10-K, File No. 1-5324) 4.2.13 January 1, 1997. (Exhibit 4.2.17, 1996 NU Form 10-K, File No. 1-5324) 4.2.14 May 1, 1997. (Exhibit 4.19, File No. 333-30911) 4.2.15 June 1, 1997. (Exhibit 4.20, File No. 333-30911) 4.2.16 June 1, 1997. (Exhibit 4.2.17, 1997 NU Form 10-K, File No. 1-5324) 4.2.17 May 1, 1998. (Exhibit 4.2.17, 1998 NU Form 10-K, File No. 1-5324) 4.2.18 May 1, 1998. (Exhibit 4.2.18, 1998 NU Form 10-K, File No. 1-5324) 4.2.19 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1986 Series) dated as of December 1, 1986. (Exhibit C.1.47, 1986 NU Form U5S, File No. 30-246) 4.2.20 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1988 Series) dated as of October 1, 1988. (Exhibit C.1.55, 1988 NU Form U5S, File No. 30-246) 4.2.21 Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire, CL&P and the Trustee (Pollution Control Bonds, 1992 Series A) dated as of December 1, 1992. (Exhibit C.2.33, 1992 NU Form U5S, File No. 30-246) 4.2.22 Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.21, 1993 NU Form 10-K, File No. 1-5324) 4.2.23 Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series B, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.22, 1993 NU Form 10-K, File No. 1-5324) 4.2.24 Amended and Restated Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Bond - 1996A Series) dated as of May 1, 1996, and Amended and Restated as of January 1, 1997. (Exhibit 4.2.24, 1996 NU Form 10-K, File No. 1-5324) 4.2.24.1 Amended and Restated Indenture of Trust between Connecticut Development Authority and the Trustee (CL&P Pollution Control Revenue Bond- 1996A Series), dated as of May 1, 1996, and Amended and Restated as of January 1, 1997. (Exhibit 4.2.24.1, 1996 NU Form 10-K, File No. 1-5324) #4.2.24.2 Standby Bond Purchase Agreement among CL&P, Bank of New York as Purchasing Agent and the Banks Named therein, dated October 24, 2000. 4.2.24.3 AMBAC Municipal Bond Insurance Policy issued by the Connecticut Development Authority (CL&P Pollution Control Revenue Bond-1996A Series), effective January 23, 1997. (Exhibit 4.2.24.3, 1996 NU Form 10-K, File No. 1-5324) 4.2.25 Amended and Restated Limited Partnership Agreement (CL&P LP) among CL&P, NUSCO, and the persons who became limited partners of CL&P LP in accordance with the provisions thereof dated as of January 23, 1995 (MIPS). (Exhibit A.1 (Execution Copy), File No. 70-8451) 4.2.26 Indenture between CL&P and Bankers Trust Company, Trustee (Series A Subordinated Debentures), dated as of January 1, 1995 (MIPS). (Exhibit B.1 (Execution Copy), File No. 70-8451) 4.2.27 Payment and Guaranty Agreement of CL&P dated as of January 23, 1995 (MIPS). (Exhibit B.3 (Execution Copy), File No. 70-8451) 4.3 Public Service Company of New Hampshire 4.3.1 First Mortgage Indenture dated as of August 15, 1978, between PSNH and First Fidelity Bank, National Association, New Jersey, now First Union National Bank, Trustee, (Composite including all amendments to May 16, 1991). (Exhibit 4.4.1, 1992 NU Form 10-K, File No. 1-5324) 4.3.1.1 Tenth Supplemental Indenture dated as of May 1, 1991, between PSNH and First Fidelity Bank, National Association, now First Union National Bank. (Exhibit 4.1, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.3 Series A (Tax Exempt New Issue) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.2, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.4 Series B (Tax Exempt Refunding) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.3, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.5 Series C (Tax Exempt Refunding) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.4, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.6 Series D (Tax Exempt Refunding) Amended and Restated PCRB Loan and Trust Agreement dated as of April 1, 1999. (Exhibit 4.3.6, 1999 NU Form 10-K, File No. 1-5324) 4.3.7 Series E (Tax Exempt Refunding) Amended and Restated PCRB Loan and Trust Agreement dated as of April 14, 1999. (Exhibit 4.3.7, 1999 NU Form 10-K, File No. 1-5324) 4.4 Western Massachusetts Electric Company 4.4.1 First Mortgage Indenture and Deed of Trust between WMECO and Old Colony Trust Company, Trustee, dated as of August 1, 1954. (Exhibit 4.4.1, 1993 NU Form 10-K, File No. 1-5324) Supplemental Indentures thereto dated as of: 4.4.2 October 1, 1954. (Exhibit 4.4.2, 1998 NU Form 10-K, File No. 1-5324) 4.4.3 March 1, 1967. (Exhibit 4.4.3, 1997 NU Form 10-K, File No. 1-5324) 4.4.4 July 1, 1973. (Exhibit 2.10, File No. 2-68808) 4.4.5 December 1, 1992. (Exhibit 4.15, File No. 33-55772) 4.4.6 January 1, 1993. (Exhibit 4.5.13, 1992 NU Form 10-K, File No. 1-5324) 4.4.7 March 1, 1994. (Exhibit 4.4.12, 1993 NU Form 10-K, File No. 1-5324) 4.4.8 May 1, 1997. (Exhibit 4.11, File No. 33-51185) 4.4.9 July 1, 1997. (Exhibit 4.4.10, 1997 NU Form 10-K, File No. 1-5324) 4.4.10 May 1, 1998. (Exhibit 4.4.10, 1998 NU Form 10-K, File No. 1-5324) 4.4.11 May 1, 1998. (Exhibit 4.4.11, 1998 NU Form 10-K, File No. 1-5324) 4.4.12 Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.4.13, 1993 NU Form 10-K, File No. 1-5324) 4.5 North Atlantic Energy Corporation 4.5.1 First Mortgage Indenture and Deed of Trust between NAEC and United States Trust Company of New York, Trustee, dated as of June 1, 1992. (Exhibit 4.6.1, 1992 NU Form 10-K, File No. 1-5324) 4.5.2 Term Credit Agreement dated as of November 9, 1995. (Exhibit 4.5.2, 1995 NU Form 10-K, File No. 1-5324) 10 Material Contracts 10.1 Stockholder Agreement dated as of July 1, 1964, among the stockholders of CYAPC. (Exhibit 10.1, 1994 NU Form 10-K, File No. 1-5324) 10.2 Form of Power Contract dated as of July 1, 1964, between CYAPC and each of CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.2, 1994 NU Form 10-K, File No. 1-5324) 10.2.1 Form of Additional Power Contract dated as of April 30, 1984, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324) 10.2.2 Form of 1987 Supplementary Power Contract dated as of April 1, 1987, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.6, 1987 NU Form 10-K, File No. 1-5324) 10.3 Capital Funds Agreement dated as of September 1, 1964, between CYAPC and CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.3, 1994 NU Form 10-K, File No. 1-5324) 10.4 Stockholder Agreement dated December 10, 1958, between YAEC and CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.4, 1993 NU Form 10-K, File No. 1-5324) 10.5 Form of Amendment No. 3, dated as of April 1, 1985, to Power Contract between YAEC and each of CL&P, PSNH and WMECO, including a composite restatement of original Power Contract dated June 30, 1959, and Amendment No. 1 dated April 1, 1975, and Amendment No. 2 dated October 1, 1980. (Exhibit 10.5, 1988 NU Form 10-K, File No. 1-5324.) 10.5.1 Form of Amendment No. 4 to Power Contract, dated May 6, 1988, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324) 10.5.2 Form of Amendment No. 5 to Power Contract, dated June 26, 1989, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324) 10.5.3 Form of Amendment No. 6 to Power Contract, dated July 1, 1989, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324) 10.5.4 Form of Amendment No. 7 to Power Contract, dated February 1, 1992, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.4, 1993 NU Form 10-K, File No. 1-5324) 10.6 Stockholder Agreement dated as of May 20, 1968, among stockholders of MYAPC. (Exhibit 10.6, 1997 NU Form 10-K, File No. 1-5324) 10.7 Form of Power Contract dated as of May 20, 1968, between MYAPC and each of CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.7, 1997 Form 10-K, File No. 1-5324) 10.7.1 Form of Amendment No. 1 to Power Contract dated as of March 1, 1983, between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.1, 1993 NU Form 10-K, File No. 1-5324) 10.7.2 Form of Amendment No. 2 to Power Contract dated as of January 1, 1984, between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.2, 1993 NU Form 10-K, File No. 1-5324) 10.7.3 Form of Amendment No. 3 to Power Contract dated as of October 1, 1984, between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.7.3, 1994 NU Form 10-K, File No. 1-5324) 10.7.4 Form of Additional Power Contract dated as of February 1, 1984, between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324) 10.8 Capital Funds Agreement dated as of May 20, 1968, between MYAPC and CL&P, PSNH, HELCO, and WMECO. (Exhibit 10.8, 1997 NU Form 10-K, File No. 1-5324) 10.8.1 Amendment No. 1 to Capital Funds Agreement, dated as of August 1, 1985, between MYAPC, CL&P, PSNH and WMECO. (Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324) 10.9 Sponsor Agreement dated as of August 1, 1968, among the sponsors of VYNPC. (Exhibit 10.9, 1997 NU Form 10-K, File No. 1-5324) 10.10 Form of Power Contract dated as of February 1, 1968, between VYNPC and each of CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.10, 1997 NU Form 10-K, File No. 1-5324) 10.10.1 Form of Amendment to Power Contract dated as of June 1, 1972, between VYNPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 5.22, File No. 2-47038) 10.10.2 Form of Second Amendment to Power Contract dated as of April 15, 1983, between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.2, 1993 NU Form 10-K, File No. 1-5324) 10.10.3 Form of Third Amendment to Power Contract dated as of April 24, 1985, between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.10.3, 1994 NU Form 10-K, File No. 1-5324) 10.10.4 Form of Fourth Amendment to Power Contract dated as of June 1, 1985, between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.10.4, 1996 NU Form 10-K, File No. 1-5324) 10.10.5 Form of Fifth Amendment to Power Contract dated as of May 6, 1988, between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.5, 1990 NU Form 10-K, File No. 1-5324) 10.10.6 Form of Sixth Amendment to Power Contract dated as of May 6, 1988, between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.6, 1990 NU Form 10-K, File No. 1-5324) 10.10.7 Form of Seventh Amendment to Power Contract dated as of June 15, 1989, between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.7, 1990 NU Form 10-K, File No. 1-5324) 10.10.8 Form of Eighth Amendment to Power Contract dated as of December 1, 1989, between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.8, 1990 NU Form 10-K, File No. 1-5324) 10.10.9 Form of Additional Power Contract dated as of February 1, 1984, between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.9, 1993 NU Form 10-K, File No. 1-5324) 10.11 Capital Funds Agreement dated as of February 1, 1968, between VYNPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.11, 1997 NU Form 10-K, File No. 1-5324) 10.11.1 Form of First Amendment to Capital Funds Agreement dated as of March 12, 1968, between VYNPC and CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.11.1, 1997 NU Form 10-K, File No. 1-5324) 10.11.2 Form of Second Amendment to Capital Funds Agreement dated as of September 1, 1993, between VYNPC and CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.11.2, 1993 NU Form 10-K, File No. 1-5324) 10.12 PSA for the Millstone Power Station dated as of August 7, 2000, by and among CL&P and WMECO as Sellers and Dominion as Buyer. (Exhibit 10.1, 2000 NU Form 10-Q for the Quarter ended June 30, 2000, File No. 1-5324) 10.13 Amended and Restated Millstone Plant Agreement dated as of December 1, 1984, by and among CL&P, WMECO and NNECO. (Exhibit 10.12, 1994 NU Form 10-K, File No. 1-5324) 10.14 Sharing Agreement dated as of September 1, 1973, with respect to 1979 Connecticut nuclear generating unit (Millstone 3). (Exhibit 6.43, File No. 2-50142) 10.14.1 Amendment dated August 1, 1974, to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 5.45, File No. 2-52392) 10.14.2 Amendment dated December 15, 1975, to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 7.47, File No. 2-60806) 10.14.3 Amendment dated April 1, 1986, to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 10.17.3, 1990 NU Form 10-K, File No. 1-5324) 10.15 Agreement dated July 19, 1990, among NAESCO and Seabrook Joint owners with respect to operation of Seabrook. (Exhibit 10.53, 1990 NU Form 10-K, File No. 1-5324) 10.16 Sharing Agreement between CL&P, WMECO, HP&E, HWP, and PSNH dated as of June 1, 1992. (Exhibit 10.17, 1992 NU Form 10-K, File No. 1-5324) 10.17 Rate Agreement by and between NUSCO, on behalf of NU, and the Governor of the State of New Hampshire and the New Hampshire Attorney General dated as of November 22, 1989. (Exhibit 10.44, 1989 NU Form 10-K, File No. 1-5324) 10.17.1 First Amendment to Rate Agreement dated as of December 5, 1989. (Exhibit 10.16.1, 1995 NU Form 10-K, File No. 1-5324) 10.17.2 Second Amendment to Rate Agreement dated as of December 12, 1989. (Exhibit 10.16.2, 1995 NU Form 10-K, File No. 1-5324) 10.17.3 Third Amendment to Rate Agreement dated as of December 3, 1993. (Exhibit 10.16.3, 1995 NU Form 10-K, File No. 1-5324) 10.17.4 Fourth Amendment to Rate Agreement dated as of September 21, 1994. (Exhibit 10.16.4, 1995 NU Form 10-K, File No. 1-5324) 10.17.5 Fifth Amendment to Rate Agreement dated as of September 9, 1994. (Exhibit 10.16.5, 1995 NU Form 10-K, File No. 1-5324) 10.18 Agreement to Settle PSNH Restructuring (Exhibit 10.2, 1999 NU Form 10-Q for the Quarter Ended June 30, 1999, File No. 1-5324) 10.19 Merger Settlement Agreement between NU, Con Edison and NHPUC dated as of December 6, 2000. (Exhibit O.1, to NU's U-1 Application, File No. 70-9711) 10.20 Form of Seabrook Power Contract between PSNH and NAEC, as amended and restated. (Exhibit 10.45, 1992 NU Form 10-K, File No. 1-5324) 10.21 Agreement (composite) for joint ownership, construction and operation of New Hampshire nuclear unit, as amended through the November 1, 1990 twenty-third amendment. (Exhibit No. 10.17, 1994 NU Form 10-K, File No. 1-5324) 10.21.1 Memorandum of Understanding dated November 7, 1988, between PSNH and Massachusetts Municipal Wholesale Electric Company (Exhibit 10.17, PSNH 1989 Form 10-K, File No. 1-6392) 10.21.2 Agreement of Settlement among Joint Owners dated as of January 13, 1989. (Exhibit 10.13.21, 1988 NU Form 10-K, File No. 1-5324) 10.21.2.1 Supplement to Settlement Agreement, dated as of February 7, 1989, between PSNH and CMP. (Exhibit 10.18.1, PSNH 1989 Form 10-K, File No. 1-6392) 10.22 Amended and Restated Agreement for Seabrook Project Disbursing Agent dated as of November 1, 1990. (Exhibit 10.4.7, File No. 33-35312) 10.22.1 Form of First Amendment to Exhibit 10.22. (Exhibit 10.4.8, File No. 33-35312) 10.22.2 Form (Composite) of Second Amendment to Exhibit 10.22. (Exhibit 10.18.2, 1993 NU Form 10-K, File No. 1-5324) 10.23 Agreement dated November 1, 1974, for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 among PSNH, CMP and other utilities. (Exhibit 5.16, File No. 2-52900) 10.23.1 Amendment to Exhibit 10.23 dated June 30, 1975. (Exhibit 5.48, File No. 2-55458) 10.23.2 Amendment to Exhibit 10.23 dated as of August 16, 1976. (Exhibit 5.19, File No. 2-58251) 10.23.3 Amendment to Exhibit 10.23 dated as of December 31, 1978. (Exhibit 5.10.3, File No. 2-64294) 10.24 Form of Service Contract dated as of July 1, 1966, between each of NU, CL&P and WMECO and the Service Company. (Exhibit 10.20, 1993 NU Form 10-K, File No. 1-5324) 10.24.1 Service Contract dated as of June 5, 1992, between PSNH and the Service Company. (Exhibit 10.12.4, 1992 NU Form 10-K, File No. 1-5324) 10.24.2 Service Contract dated as of June 5, 1992, between NAEC and the Service Company. (Exhibit 10.12.5, 1992 NU Form 10-K, File No. 1-5324) 10.24.3 Form of Service Agreement dated as of June 29, 1992, between PSNH and NAESCO, and the First Amendment thereto. (Exhibits B.7 and B.7.1, File No. 70-7787) 10.24.4 Form of Annual Renewal of Service Contract. (Exhibit 10.20.3, 1993 NU Form 10-K, File No. 1-5324) 10.25 Memorandum of Understanding between CL&P, HELCO, HP&E, HWP, and WMECO dated as of June 1, 1970, with respect to pooling of generation and transmission. (Exhibit 13.32, File No. 2-38177) 10.25.1 Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP, and WMECO dated as of February 2, 1982, with respect to pooling of generation and transmission. (Exhibit 10.21.1, 1993 NU Form 10-K, File No. 1-5324) 10.25.2 Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP, and WMECO dated as of January 1, 1984, with respect to pooling of generation and transmission. (Exhibit 10.21.2, 1994 NU Form 10-K, File No. 1-5324) 10.25.3 Second Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP, and WMECO dated as of June 8, 1999, with respect to pooling of generation and transmission. (Exhibit 10.23.3, 1999 NU Form 10-K, File No. 1-5324) *10.26 Restated NEPOOL Power Pool Agreement (restated by the sixty-ninth Agreement dated as of December 31, 2000, and includes the Restated NEPOOL Open Access Transmission Tariff 10.26.1 Form of Interim ISO Agreement (Attachment to Thirty- third Amendment to Exhibit 10.26 dated as of December 31, 1996). (Exhibit 10.23.6, 1996 NU Form 10-K, File No. 1-5324) 10.27 Agreements among New England Utilities with respect to the Hydro- Quebec interconnection projects. (See Exhibits 10(u) and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of New England Electric System, File No. 1-3446.) 10.28 Trust Agreement dated February 11, 1992, between State Street Bank and Trust Company of Connecticut, as Trustor, and Bankers Trust Company, as Trustee, and CL&P and WMECO, with respect to Niantic Bay Fuel Trust. (Exhibit 10.23, 1991 NU Form 10-K, File No. 1-5324) 10.28.1 Nuclear Fuel Lease Agreement dated as of February 11, 1992, between Bankers Trust Company, Trustee, as Lessor, and CL&P and WMECO, as Lessees. (Exhibit 10.23.1, 1991 NU Form 10-K, File No. 1-5324) 10.28.2 Modification and Amendment to Nuclear Fuel Lease Agreement dated as of May 17, 1999, between Bankers Trust Company, Trustee, as Lessor, and CL&P and WMECO, as Lessees. (Exhibit 10.26.2, 1999 NU Form 10-K, File No. 1-5324) 10.29 Simulator Financing Lease Agreement, dated as of May 2, 1985, by and between The Prudential Insurance Company of America and NNECO. (Exhibit No. 10.26, 1994 NU Form 10-K, File No. 1-5324) 10.30 Lease dated as of April 14, 1992, between The Rocky River Realty Company (RRR) and NUSCO with respect to the Berlin, Connecticut headquarters (office lease). (Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324) 10.30.1 Lease dated as of April 14, 1992, between RRR and NUSCO with respect to the Berlin, Connecticut headquarters (project lease). (Exhibit 10.29.1, 1992 NU Form 10-K, File No. 1-5324) 10.31 Lease and Agreement, dated as of December 15, 1988, by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina. (Exhibit 10.63, 1988 NU Form 10-K, File No. 1-5324.) 10.32 Note Agreement dated April 14, 1992, by and between RRR and Purchasers named therein (Connecticut General Life Insurance Company, Life Insurance Company of North America, INA Life Insurance Company of New York, Life Insurance Company of Georgia), with respect to RRR's sale of $15 million of guaranteed senior secured notes due 2007 and $28 million of guaranteed senior secured notes due 2017. (Exhibit 10.52, 1992 NU Form 10-K, File No. 1-5324) 10.32.1 Amendment to Note Agreement, dated September 26, 1997. (Exhibit 10.31.1, 1997 NU Form 10-K, File No. 1-5324) 10.32.2 Note Guaranty dated April 14, 1992, by Northeast Utilities pursuant to Note Agreement dated April 14, 1992, between RRR and Note Purchasers, for the benefit of The Connecticut National Bank as Trustee, the Purchasers and the owners of the notes. (Exhibit 10.52.1, 1992 NU Form 10-K, File No. 1-5324) 10.32.2.1 Extension of Note Guaranty, dated September 26, 1997. (Exhibit 10.31.2.1, 1997 NU Form 10-K, File No. 1-5324) 10.32.3 Assignment of Leases, Rents and Profits, Security Agreement and Negative Pledge, dated as of April 14, 1992, among RRR, NUSCO and The Connecticut National Bank as Trustee, securing notes sold by RRR pursuant to April 14, 1992, Note Agreement. (Exhibit 10.52.2, 1997 NU Form 10-K, File No. 1-5324) 10.32.3.1 Modification of and Confirmation of Assignment of Leases, Rents and Profits, Security Agreement and Negative Pledge, dated as of September 26, 1997. (Exhibit 10.31.3.1, 1997 NU Form 10-K, File No. 1-5324) 10.32.4 Purchase and Sale Agreement, dated July 28, 1997, by and between RRR and the Sellers and Purchasers named therein. (Exhibit 10.31.4, 1997 NU Form 10-K, File No. 1-5324) 10.32.5 Purchase and Sale Agreement, dated September 26, 1997, by and between RRR and the Purchaser named therein. (Exhibit 10.31.5, 1992 NU Form 10-K, File No. 1-5324) 10.33 Master Trust Agreement dated as of September 2, 1986, between CL&P and WMECO and Colonial Bank as Trustee, with respect to reserve funds for Millstone 1 decommissioning costs. (Exhibit No. 10.32, 1996 NU Form 10-K, File No. 1-5324) 10.33.1 Notice of Appointment of Mellon Bank, N.A. as Successor Trustee, dated November 20, 1990, and Acceptance of Appointment. (Exhibit 10.41.1, 1992 NU Form 10-K, File No. 1-5324) 10.34 Master Trust Agreement dated as of September 2, 1986, between CL&P and WMECO and Colonial Bank as Trustee, with respect to reserve funds for Millstone 2 decommissioning costs. (Exhibit No. 10.33, 1996 NU Form 10-K, File No. 1-5324) 10.34.1 Notice of Appointment of Mellon Bank, N.A. as Successor Trustee, dated November 20, 1990, and Acceptance of Appointment. (Exhibit 10.42.1, 1992 NU Form 10-K, File No. 1-5324) 10.35 Master Trust Agreement dated as of April 23, 1986, between CL&P and WMECO and Colonial Bank as Trustee, with respect to reserve funds for Millstone 3 decommissioning costs. (Exhibit No. 10.34, 1996 NU Form 10-K, File No. 1-5324) 10.35.1 Notice of Appointment of Mellon Bank, N.A. as Successor Trustee, dated November 20, 1990, and Acceptance of Appointment. (Exhibit 10.43.1, 1992 NU Form 10-K, File No. 1-5324) 10.36 Rights Agreement dated as of February 23, 1999, between Northeast Utilities and NUSCO, as Rights Agent (Exhibit 1 to NU's Registration Statement on Form 8-A, filed on 4/12/99, File No. 001-05324). 10.36.1 Amendment to Rights Agreement (Exhibit 3 to NU's Current Report on Form 8-K dated October 13, 1999, File No. 1-5324). 10.37 NU Executive Incentive Plan, effective as of January 1, 1991. (Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324) 10.37.1 NU Incentive Plan, effective as of January 1, 1998. (Exhibit 10.35.1, 1998 NU Form 10-K, File No. 1-5324) 10.37.1.1 Amendment to Exhibit 10.37.1, effective as of February 23, 1999. (Exhibit 10.35.1.1, 1998 NU Form 10-K, File No. 1-5324) 10.38 Supplemental Executive Retirement Plan for Officers of NU system companies, Amended and Restated effective as of January 1, 1992. (Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30, 1992, File No. 1-5324) 10.38.1 Amendment 1 to Exhibit 10.38, effective as of August 1, 1993. (Exhibit 10.35.1, 1993 NU Form 10-K, File No. 1-5324) 10.38.2 Amendment 2 to Exhibit 10.38, effective as of January 1, 1994. (Exhibit 10.35.2, 1993 NU Form 10-K, File No. 1-5324) 10.38.3 Amendment 3 to Exhibit 10.38, effective as of January 1, 1996. (Exhibit 10.36.3, 1995 NU Form 10-K, File No. 1-5324) 10.39 Special Severance Program for Officers of NU system companies, as adopted on July 15, 1998. (Exhibit 10.37, 1998 NU Form 10-K, File No. 1-5324) 10.39.1 Amendment to Exhibit 10.39, effective as of February 23, 1999. (Exhibit 10.37.1, 1998 NU Form 10-K, File No. 1-5324) 10.39.2 Amendment to Exhibit 10.39, effective as of September 14, 1999. (Exhibit 10.3, 1999 NU Form 10-Q for the Quarter Ended September 30, 1999, File No. 1-5324) 10.40 Loan Agreement dated as of December 2, 1991, by and between NU and Mellon Bank, N.A., as Trustee, with respect to NU's loan of $175 million to an ESOP Trust. (Exhibit 10.46, 1991 NU Form 10-K, File No. 1-5324) 10.40.1 First Amendment to Exhibit 10.40 dated February 7, 1992. (Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324) 10.40.2 Loan Agreement dated as of March 19, 1992 by and between NU and Mellon Bank, N.A., as Trustee, with respect to NU's loan of $75 million to the ESOP Trust. (Exhibit 10.49.1, 1992 NU Form 10-K, File No. 1-5324) 10.40.3 Second Amendment to Exhibit 10.40 dated April 9, 1992. (Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324) 10.41 Employment Agreement with Michael G. Morris. (Exhibit 10.39, 1997 NU Form 10-K, File No. 1-5324) 10.40.1 Amendment to Exhibit 10.41, dated as of February 23, 1999. (Exhibit 10.39.1, 1998 NU Form 10-K, File No. 1-5324) 10.42 Transition and Retirement Agreement with Bernard M. Fox. (Exhibit 10.39, 1996 NU Form 10-K, File No. 1-5324) 10.43 Employment Agreement with Bruce D. Kenyon. (Exhibit 10.40, 1996 NU Form 10-K, File No. 1-5324) 10.43.1 Amendment to Exhibit 10.43, dated as of January 13, 1998. (Exhibit 10.41.1, 1998 NU Form 10-K, File No. 1-5324) 10.43.2 Amendment to Exhibit 10.43, dated as of February 23, 1999. (Exhibit 10.41.2, 1998 NU Form 10-K, File No. 1-5324) 10.43.3 Amendment to Exhibit 10.43, dated as of March 21, 1999. (Exhibit 10.1, 1999 NU Form 10-Q for the Quarter Ended March 31,1999, File No. 1-5324) 10.43.4 Amendment to Exhibit 10.43, dated as of May 14, 2000. (Exhibit 10.3, 2000 NU Form 10-Q for the Quarter Ended June 30, 2000, File No. 1-5324) 10.44 Employment Agreement with John H. Forsgren. (Exhibit 10.41, 1996 NU Form 10-K, File No. 1-5324) 10.44.1 Amendment to Exhibit 10.44, dated as of January 13, 1998. (Exhibit 10.42.1, 1998 NU Form 10-K, File No. 1-5324) 10.44.2 Amendment to Exhibit 10.44, dated as of February 23, 1999. (Exhibit 10.42.2, 1998 NU Form 10-K, File No. 1-5324) 10.44.3 Amendment to Exhibit 10.44, dated as of May 10, 1999. (Exhibit 10.1, 1999 NU Form 10-Q for the Quarter Ended March 31, 1999, File No. 1-5324) 10.44.4 Amendment to Exhibit 10.44, dated as of September 14, 1999. (Exhibit 10.4, 1999 NU Form 10-Q for the Quarter Ended September 30, 1999, File No. 1-5324) 10.45 Employment Agreement with Hugh C. MacKenzie. (Exhibit 10.42, 1996 NU Form 10-K, File No. 1-5324) 10.45.1 Amendment to Exhibit 10.45, dated as of January 13, 1998. (Exhibit 10.43.1, 1998 NU Form 10-K, File No. 1-5324) 10.45.2 Amendment to Exhibit 10.45, dated as of February 23, 1999. (Exhibit 10.43.2, 1998 NU Form 10-K, File No. 1-5324) #@**10.45.3 Separation Agreement with Hugh C. MacKenzie, dated as of December 20, 2000. 10.46 Employment Agreement with Cheryl W. Grise. (Exhibit 10.44, 1998 NU Form 10-K, File No. 1-5324) 10.46.1 Amendment to Exhibit 10.46, dated as of January 13, 1998. (Exhibit 10.44.1, 1998 NU Form 10-K, File No. 1-5324) 10.46.2 Amendment to Exhibit 10.46, dated as of February 23, 1999. (Exhibit 10.44.2, 1998 NU Form 10-K, File No. 1-5324) 10.46.3 Amendment to Exhibit 10.46, dated as of September 14, 1999. (Exhibit 10.5, 1999 NU Form 10-Q for the Quarter Ended September 30, 1999, File No. 1-5324) 10.47 Northeast Utilities Deferred Compensation Plan for Trustees, Amended and Restated December 13, 1994. (Exhibit 10.39, 1995 NU Form 10-K, File No. 1-5324) 10.48 Deferred Compensation Plan for Officers of Northeast Utilities System Companies adopted September 23, 1986. (Exhibit 10.40, 1995 NU Form 10-K, File No. 1-5324) 10.49 Northeast Utilities Deferred Compensation Plan for Executives, adopted January 13, 1998. (Exhibit A.5, File No. 70-09185) 10.50 Reciprocal Support Agreement Among NNECO, NAESCO, CYAPC, YAEC, and NUSCO dated January 1, 1996. (Exhibit 10.41, 1995 NU Form 10-K, File No. 1-5324) 10.51 Receivables Purchase and Sale Agreement (CL&P and CL&P Receivables Corporation [CRC]), dated as of September 30, 1997. (Exhibit 10.49, 1997 NU Form 10-K, File No. 1-5324) 10.51.1 Amendment to Exhibit 10.51 dated September 29, 1998. (Exhibit 10.49.1, 1998 NU Form 10-K, File No. 1-5324) 10.51.2 Amendment to Exhibit 10.51 dated September 28, 1999. (Exhibit C.10.3, 1999 NU Form U5S, File No. 30-246) #10.51.3 Amendment to Exhibit 10.51 dated September 27, 2000. 10.51.4 Purchase and Contribution Agreement (CL&P and CRC), dated as of September 30, 1997. (Exhibit 10.49.1, 1997 NU Form 10-K, File No. 1-5324) *10.52 Confirmation Agreement between Credit Suisse First Boston and NU, dated as of January 2, 2001. 10.53 Confirmation Agreement between Bank One and NU, dated as of December 9, 1999. (Exhibit 10.56, 1999 NU Form 10-K, File No. 1-5324) *10.53.1 First Amendment to Confirmation Agreement, dated as of January 1, 2001. *10.54 Credit Agreement dated as of March 9, 2000, among NGC as Borrower and the Initial Lenders Named Therein as Initial Lenders and Citibank, N.A. as Administrative and Collateral Agent and Depository Bank. *10.54.1 Amendment No. 1 to Exhibit 10.54, dated as of July 27, 2000. *10.54.2 Amendment No. 2 to Exhibit 10.54, dated as of November 22, 2000. *10.55 Tranche B Mortgage dated as of March 9, 2000, among NGC and Citibank, N.A. 10.56 Indenture of Mortgage and Deed of Trust dated July 1, 1989, between Yankee and the Connecticut National Bank, as Trustee (Exhibit 4.7, 1990 Yankee Form 10-K, File No. 0-10721) 10.57 Credit Agreement dated as of February 2, 1995, by and among Yankee and the Bank of New York as Agent (Exhibit 10.18, 1995 Yankee Form 10-K, File No. 0-10721) 13 Annual Report to Security Holders (Each of the Annual Reports is filed only with the Form 10-K of that respective registrant.) 13.1 Annual Report of CL&P. 13.2 Annual Report of WMECO. 13.3 Annual Report of PSNH. 13.4 Annual Report of NAEC. *21 Subsidiaries of the Registrant. MANAGEMENT'S DISCUSSION AND ANALYSIS FINANCIAL CONDITION OVERVIEW Northeast Utilities (NU or the company) reported year end 2000 earnings before extraordinary items of $205.3 million, or $1.45 per share on a fully diluted basis, compared with earnings of $34.2 million, or $0.26 per share, in 1999 and a loss of $146.8 million, or $1.12 per share in 1998. Because of extraordinary charges totaling $233.9 million after-tax, NU reported a net loss of $28.6 million, or $0.20 per share, on a fully diluted basis, for the year. These extraordinary charges are associated with the impacts of industry restructuring and the discontinuation of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." The most significant write-off occurred at Public Service Company of New Hampshire (PSNH) during the fourth quarter as a result of the "Agreement to Settle PSNH Restructuring" (Settlement Agreement) with the State of New Hampshire. Increases in competitive energy subsidiaries' sales pushed total NU revenues to a record $5.9 billion in 2000, up 31 percent from $4.47 billion in 1999. Revenues were $3.77 billion in 1998. The growth in competitive energy subsidiaries' revenues more than offset a 5 percent retail rate decrease on January 1, 2000, for customers of The Connecticut Light and Power Company (CL&P) and a 5 percent rate reduction on October 1, 2000, for PSNH retail customers. Regulated retail electric sales increased by 0.8 percent in 2000, as compared to 1999, primarily due to economic growth in NU's service territories. However, retail electric sales would have increased 1.9 percent had it not been for mild summer temperatures. Many areas of the Northeast Utilities system (NU system) contributed to the better operating performance in 2000. The most significant improvement occurred at CL&P, NU's largest operating subsidiary. CL&P's earnings totaled $148.1 million in 2000, compared with a loss of $13.6 million in 1999 and $195.7 million in 1998. The 2000 results represented CL&P's first annual profit since 1995. CL&P benefited from the return to service of the Millstone 2 unit in May 1999 and the strong performance of the Millstone 2 and 3 units in 2000. Millstone 2 operated at a capacity factor of 82 percent in 2000, while Millstone 3 operated at a capacity factor of virtually 100 percent in 2000. However, management projects that CL&P's earnings will decline in 2001 as a result of the expected sale of CL&P's share of the Millstone units, other rate adjustments and the pending resolution of the over-earnings docket. Although CL&P's earnings are expected to decline, its return on equity is not expected to be compromised. NU's competitive energy subsidiaries achieved a significant improvement in operating results in 2000 over 1999. The competitive energy subsidiaries contributed $13.6 million before extraordinary charges in 2000 toward NU's consolidated earnings, compared with a net loss of $37 million in 1999. During 2000, the Holyoke Water Power Company (HWP) recorded an extraordinary charge of $19.7 million after-tax, or $0.14 per share, as a result of the discontinuation of SFAS No. 71 for certain hydroelectric generation assets. Absent the extraordinary charge, PSNH earned $67.6 million in 2000, compared with $84.2 million in 1999 and $91.7 million in 1998. North Atlantic Energy Corporation (NAEC) earned $32.5 million in 2000, compared with $29.6 million in 1999 and $29.5 million in 1998. Operating earnings at PSNH and NAEC are expected to decline significantly after the first quarter of 2001, as a result of the retail rate reductions and capital redeployment that will accompany the introduction of industry restructuring in New Hampshire. Similar to CL&P, Western Massachusetts Electric Company (WMECO) also experienced a significant improvement in operating results in 2000, primarily as a result of the return to service of Millstone 2 and the absence of restructuring charges. In 2000, WMECO earned $35.3 million, compared with $2.9 million in 1999 and a loss of $9.6 million in 1998. NU projects earnings will be between $1.40 per share and $1.60 per share during 2001, not including significant nonrecurring gains and losses. CONSOLIDATED EDISON, INC. MERGER In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the approvals needed to complete the merger announced in October 1999. Shareholders from both companies approved the merger in April 2000, and all state regulatory approvals were granted by the end of the year. Additionally, the Federal Energy Regulatory Commission (FERC) approved the merger in May 2000, the Nuclear Regulatory Commission approved the transaction in August 2000, and the United States Department of Justice approved the merger in February 2001. Necessary approval from the Securities and Exchange Commission (SEC) was expected to be received in mid-March 2001. On February 28, 2001, NU's Board of Trustees requested that Con Edison provide reasonable assurance, in writing, that it intended to comply with the terms of the definitive merger agreement between the two companies. This included assurances that Con Edison would consummate the pending merger at the price set forth in the agreement promptly following the receipt of SEC approval. The original request for assurance was to be received by March 2, 2001, however that date was later extended to March 5, 2001. On March 5, 2001, Con Edison advised NU that it was not willing to close the merger on the agreed terms. NU notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that NU would file suit to obtain the benefits of the transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District of New York (Southern District), seeking declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement. On March 12, 2001, NU filed suit against Con Edison in the Southern District seeking damages in excess of $1 billion arising from Con Edison's breach of the merger agreement. NU cannot predict the outcome of this matter nor its effect on NU. Under the terms of the proposed transaction, had it proceeded to closing, NU shareholders would have received a base price of $25 per share, in a combination of cash and Con Edison common stock, plus $0.0034 per share per day, or approximately $0.10 per share per month, for each day that the merger did not close after August 5, 2000. Additionally, NU shareholders would have received another $1 per share as a result of a recommendation by the Connecticut Department of Public Utility Control's (DPUC) Utility Operations Management Analysis Unit that the DPUC accept the results of the Millstone auction that were announced on August 7, 2000. The DPUC approved the sale in January 2001. The $25 per share base price, the $0.0034 per share per day compensation and the additional $1 per share resulting from the Millstone auction would have been subject to the collar mechanism described in the merger proxy statement dated February 29, 2000, to the extent NU shareholders received Con Edison stock. Assuming that Con Edison's stock price had averaged between $36 and $46 per share during the applicable pricing period, as defined, NU shareholders would have received approximately $26.84 per share, were the merger to have closed on April 10, 2001. YANKEE ENERGY SYSTEM, INC. MERGER On March 1, 2000, NU completed its acquisition of Yankee Energy System, Inc. (Yankee), the parent company of Connecticut's largest natural gas distribution company. Under the terms of the merger, NU issued approximately 11.1 million NU common shares and paid $261.4 million of cash to Yankee's shareholders. As expected, the transaction was dilutive for NU earnings per share in 2000, in part because the merger was closed at the end of the winter heating season and near the end of Yankee's strongest earnings period. Yankee lost $0.7 million during the 10 months of 2000 it has been part of the NU system. Substantially better financial results are anticipated in 2001 during which Yankee's operations will include the months of January and February. Yankee anticipates filing a rate case in the second quarter of 2001. On August 9, 2000, Yankee Gas Services Company (Yankee Gas) was ordered by the DPUC to file a rate application. This review of Yankee Gas' rates is required under Connecticut law because four years have passed since its last rate review. In accordance with the most recent schedule approved by the DPUC, Yankee Gas filed a cost of service study on February 14, 2001, which reflected a historical test year ending September 30, 2000. Yankee Gas has asked the DPUC to approve a schedule that would call for Yankee Gas to file a letter of intent in May 2001, and its full filing in July 2001. LIQUIDITY NU's net cash flows provided by operating activities declined slightly to $578.4 million in 2000 compared with $614.2 million in 1999 and $663.3 million in 1998. Industry restructuring in Connecticut which required retail rate cuts reduced cash flows from operating activities. Industry restructuring resulted in a reduction of depreciation and amortization expense of $382.8 million for the year, as compared to 1999. Changes in working capital, primarily a decrease in accrued taxes and an increase in prepayments and other, also decreased cash flows from operating activities. The increase in prepayments and other is primarily due to increases in prepaid property taxes. In addition, an increase in prepaid pension, which is a component of other sources and uses, contributed to the decrease in cash flows from operating activities. Those factors were partially offset by a $162.5 million increase in income after interest charges for the year ended December 31, 2000, compared with the same period in 1999. Cash flows from operations, however, was more than adequate to meet the payment of the NU system's common and preferred dividends ($71.6 million) and investments in electric and other utility plant, nuclear fuel and nuclear decommissioning trusts ($453.6 million). The level of common dividends totaled $57.4 million in 2000, as compared to $13.2 million paid in 1999 and no cash dividends in 1998. This increase was a result of NU paying a $0.10 per share quarterly common dividend for all of 2000, as compared to only the fourth quarter of 1999. The level of preferred dividends decreased to $14.2 million in 2000, compared with $22.8 million in 1999 and $26.4 million in 1998, reflecting NU's ongoing effort to reduce preferred stock outstanding. The NU system companies currently forecast construction expenditures ranging from $395 million to $420 million for the year 2001. The transfer of 1,289 megawatts (MW) of hydroelectric generation assets to Northeast Generation Company (NGC), an affiliated company, from CL&P and WMECO in March 2000, produced a significant source of cash for CL&P and WMECO. NGC financed the transfer with a short-term credit agreement collateralized by the generation assets transferred and an equity infusion from NU. CL&P and WMECO used this cash to retire long-term debt, preferred stock and to return equity capital to the parent company. Consolidated financing activities for 2000 included $812.3 million for the retirement of long-term debt and preferred stock, compared with $864 million for 1999. Aside from the NGC borrowings, the largest new financing for the NU system in 2000 was the borrowing of $263 million to finance the cash portion of the Yankee acquisition. NU refinanced that borrowing on February 28, 2001, when it issued $263 million of two-year variable-rate notes. Based on the initial rate of those notes, NU expects to save more than $1 million annually as a result of the refinancing. The NU system also renewed a series of other borrowing facilities over the course of 2000. In November 2000, NU parent increased its revolving credit agreement to $400 million from $350 million, primarily to meet Select Energy Inc.'s (Select Energy) increased working capital needs to support a rapidly growing level of business. NU parent provides credit assurance in the form of guarantees, letters of credit, performance guarantees, and other assurances for the financial performance obligations of certain of its competitive energy subsidiaries, particularly Select Energy. Also in November 2000, CL&P and WMECO reduced their revolving credit agreement to $350 million from $500 million to reflect lower borrowing needs post-restructuring, NAEC renewed its $200 million term credit agreement for 364 days, and Yankee Gas renewed a $60 million revolving credit agreement. All of those facilities were renewed with more favorable terms as a result of the NU system's improving credit profile. In April 2000, Moody's Investors Service (Moody's) upgraded its credit ratings for NU, PSNH and NAEC, and in October 2000, Fitch IBCA (Fitch) upgraded its credit ratings for PSNH and NAEC. In January 2001, Moody's and Standard and Poor's upgraded their credit ratings for NU, CL&P, PSNH, WMECO, and NAEC, primarily as a result of the New Hampshire Supreme Court's decision to uphold that state's restructuring plan, the anticipated sale of the Millstone units and NU's general financial recovery. In February 2001, Fitch upgraded its credit ratings for NU, CL&P and WMECO. These upgrades return NU's unsecured debt to investment grade ratings for the first time in five years and will save the NU system in excess of $4.7 million annually in financing costs. For further information regarding the NU system's borrowing facilities, see Note 2, "Short-Term Debt," to the consolidated financial statements. PSNH terminated its $75 million revolving credit agreement in April 1999 and continues to fund its operations and capital program with cash on hand and operating cash flows. In August and September 2000, PSNH repaid $109.2 million of variable-rate taxable pollution control bonds from cash on hand. PSNH also paid a $50 million common dividend to NU on October 2, 2000, PSNH's first common dividend to NU since February 1997. Despite those cash outflows, PSNH maintained $115.1 million of cash on hand as of December 31, 2000. On January 2, 2001, NU modified its forward share purchase arrangements for approximately 10 million NU common shares. To initially effect these arrangements, the financial institutions (counterparties) purchased approximately 10 million NU common shares on the open market in December 1999 and January 2000, in a total aggregate amount of $215 million at an average price of $21.26. The counterparties maintain ownership of the shares until the transactions are settled. NU will continue to accrue charges on the total aggregate amount at LIBOR plus an agreed upon percentage per annum until the transactions are settled. These transactions can be settled in cash or NU common shares at the company's discretion. NU expects to repurchase the shares from the counterparties in the first half of 2001 with proceeds from restructuring. However, if prior to the settlement date, NU's share price falls below $18.06 per share, NU may be required to provide the counterparties with additional collateral. This amount has been classified as temporary equity from stock forward on NU's consolidated balance sheets at December 31, 2000 and 1999. For further information regarding the forward share purchase arrangements, see Note 1C, "Summary of Significant Accounting Policies - New Accounting Standards," to the consolidated financial statements. In 2001, NU expects to reduce the capitalization of its regulated electric operating companies significantly as a result of continued asset sales and securitization of stranded costs. CL&P, PSNH and WMECO expect to receive gross proceeds of $843.2 million, $26 million and $196.2 million, respectively, as a result of the sale of their ownership interests in the Millstone units to Dominion Resources, Inc. (Dominion). This sale is expected to close as early as the end of March 2001. The cash proceeds are expected to be used to repay subsidiary debt and capital lease obligations and to return equity capital to the parent company. By the end of 2002, PSNH expects to complete the auction of approximately 1,200 MW of fossil and hydroelectric generation assets, as well as CL&P's and NAEC's share of the Seabrook Station nuclear unit (Seabrook). PSNH's restructuring settlement was predicated upon receiving approximately $400 million of net proceeds from those sales. Cash proceeds will be used to retire debt and to return equity capital to the parent company. In November 2000, the DPUC approved CL&P's request to securitize an amount not to exceed $1.55 billion of approved, eligible stranded costs, primarily related to above-market purchased-power contracts and generation-related regulatory assets. CL&P plans to use approximately $400 million of those proceeds to reduce debt with the remaining proceeds to be used to buydown and buyout above-market purchased-power contracts and to return equity capital to the parent company. However, the Office of Consumer Counsel (OCC) has appealed the securitization order to the Connecticut Superior Court. On March 1, 2001, CL&P and the OCC entered into an agreement to settle this issue. Under the agreement, pending DPUC approval, the OCC agreed to withdraw its appeal of the securitization order and not take any action that would affect the timing and amount of securitization financing to be undertaken. The DPUC approved the agreement on March 12, 2001. The OCC withdrew is appeal on March 16, 2001. Securitization for CL&P is expected to take place by the end of the first quarter 2001. In September 2000, the New Hampshire Public Utilities Commission (NHPUC) approved a comprehensive restructuring settlement that allows PSNH to securitize up to $670 million of stranded costs. In January 2001, the New Hampshire Supreme Court upheld this restructuring order on appeal. However, one of the appellants indicated publicly it would request a review of the New Hampshire Supreme Court decision by the United States Supreme Court. Such a request must be filed by May 1, 2001. Management believes that such an appeal would have a low probability of success, but cannot determine what effect it might have on the timing of the issuance of securitization bonds and the implementation of customer choice in New Hampshire. PSNH currently expects to work with the State of New Hampshire to issue securitization bonds early in the second quarter of 2001. Cash proceeds would be combined with cash on hand and used primarily to buydown the power contract between PSNH and NAEC, retire debt at the two companies of approximately $300 million and to return equity capital to the parent company from PSNH and NAEC of another $375 million. During February 2001, the Massachusetts Department of Telecommunications and Energy (DTE) approved the securitization of $155 million of stranded costs by WMECO. A significant portion of those proceeds will be used to buyout a purchased-power contract with the remainder used to retire WMECO's debt and to return equity capital to the parent company. Securitization for WMECO is expected to take place early in the second quarter of 2001. Should NU's regulated companies successfully complete the aforementioned asset sales and securitization transactions, between 1999 and 2002, these regulated companies would receive in excess of $5 billion of cash, including approximately $1.4 billion previously received related to the sale and transfer of CL&P's and WMECO's fossil and hydroelectric generation assets during 1999 and 2000. In total, management currently expects these operating subsidiaries to use these proceeds in four primary ways. More than $2 billion would be used to repay debt and preferred stock; more than $1 billion to buyout and buydown high-cost purchased-power contracts; approximately $600 million to pay taxes on gains from the sales of generation assets, and; approximately $1.2 billion would be returned to NU from these operating companies. Of that $1.2 billion, CL&P and WMECO repurchased $390 million of their common stock from NU in March 2000, the proceeds of which were immediately invested in NGC. NU will also use another $215 million of these proceeds to settle the aforementioned forward share purchase arrangement. RESTRUCTURING As a result of industry restructuring, CL&P and WMECO stopped supplying power directly to customers in 2000. Instead, CL&P and WMECO became energy delivery companies, delivering electricity to customers that is produced by other companies and sometimes bought by customers through intermediaries. In 2000, customers in both states had the option of choosing alternative power suppliers or relying on CL&P and WMECO to acquire the power for them through standard offer service. In 1999, under the oversight of the DPUC, CL&P secured four-year fixed-price contracts with three suppliers to provide power to customers who choose standard offer service. CL&P is fully recovering from retail customers the cost of buying power from these three standard offer suppliers and expects to continue recovery through the expiration of the contracts on December 31, 2003. As of January 1, 2000, Select Energy, an affiliated company, became responsible for 50 percent of CL&P's standard offer load for the entire standard offer period, or approximately 2,000 MW annually at peak. Two other unaffiliated suppliers became responsible for the balance of CL&P's standard offer load also for the entire standard offer period. CL&P and WMECO continue to generate power through either direct ownership of generating plants, such as Millstone 2 and 3 and Seabrook, or through purchased-power contracts. CL&P and WMECO sold the capacity associated with Millstone 2 and 3 and Seabrook to Select Energy and five unaffiliated companies. These contracts will expire on December 31, 2001. The revenues generated from these contracts are expected to recover CL&P's and WMECO's share of the nuclear operating costs through the divestiture of the Millstone units. In 2000, WMECO supplied power to standard offer customers at a rate of slightly more than $0.045 per kilowatt-hour. As a result of new one-year standard offer supply contracts signed in December 2000, that rate will increase significantly in 2001 to approximately $0.073 per kilowatt-hour. In January 2001, the DTE approved an average overall rate increase of approximately 17.4 percent for WMECO standard offer customers, allowing WMECO to fully recover these increased power procurement costs. A higher rate was also approved for customers who take default service from WMECO. Under the new standard offer contracts, three unaffiliated companies provide up to 630 MW of power to WMECO's standard offer customers and one unaffiliated company serves WMECO's default load of up to 70 MW through December 31, 2001. WMECO renegotiates its standard offer supply contracts on an annual basis. Because of delays in implementing restructuring in New Hampshire, PSNH remained a vertically integrated utility in 2000 with a fuel and purchased-power adjustment charge. For the first nine months following restructuring, PSNH will meet the load requirements of those customers who do not choose an alternative supplier (Transition Service or standard offer service) through its own generation assets and purchased-power obligations. Because PSNH's generation assets are heavily weighted toward coal and nuclear generation, PSNH is somewhat insulated from rising oil and natural gas prices. Following that initial nine-month period, PSNH expects to sell its generation assets and acquire power for up to two years from third-party suppliers for customers who remain on transition service. Under the restructuring statute and the conforming Settlement Agreement, PSNH will utilize its own generation capability to provide Transition Service and Default Service for the Initial Transition Service Period (ITSP, the first nine months after competition day). At the conclusion of the ITSP, PSNH will be required to contract for Transition Service for the remaining 24-month Transition Service period with third party suppliers through a competitive bidding process administered by the NHPUC. As part of its negotiation with state legislature, PSNH has agreed to expense the first $7 million of costs for the first 12-month period following the ITSP, if the cost of acquiring Transition Service exceeds the rate charged to customers. PSNH will be permitted to defer and recover, as unsecuritized stranded costs, all Transition Service costs in excess of the initial $7 million. Provisions for Transition Service are but one element of Settlement Agreement which during 2000 was approved by the New Hampshire House and Senate, signed into law by the Governor of New Hampshire and approved by the NHPUC. Other provisions allow for issuing rate reduction bonds to securitize stranded costs; implementing a rate decrease of approximately 15.5 percent, 5 percent of which was implemented on a temporary basis on October 1, 2000; an after-tax write-off of stranded costs in excess of $200 million, which was recorded in the fourth quarter; selling NAEC's share of Seabrook no later than December 31, 2003, and; fixing PSNH's delivery rates at $0.028 per kilowatt-hour for the first 33 months after the Settlement Agreement takes effect. PSNH and NAEC will also terminate the Seabrook Power Contracts upon the sale of Seabrook. Restructuring is expected to take effect the first day of the month after PSNH issues rate reduction bonds, which is anticipated to be May 1, 2001. For further information regarding commitments and contingencies related to restructuring, see Note 6A, "Commitments and Contingencies - Restructuring," to the consolidated financial statements. REGIONAL TRANSMISSION ORGANIZATION Pursuant to FERC Order 888 (issued in April 1996), the NU system companies operate their transmission system under an open access, nondiscriminatory transmission tariff. In December 1999, the FERC issued an order calling on all transmission owners to voluntarily join Regional Transmission Organizations (RTOs) in order to boost competition in electric markets. In general, each of these organizations would be an independent operator over all transmission facilities, and would perform, among other functions, tariff administration, construction planning and reliability management for the particular regional transmission system. NU's active voting interest in such an organization would be limited to 5 percent under the proposal. The NU system companies and other parties have appealed this order. Of primary concern to NU is the ratemaking authority granted to RTOs and its impact on the ability of transmission owners to earn appropriate returns on their transmission investment under the organizational structure and the minimum functions proposed in the order. The NU system companies were required to participate in a collaborative process established by the FERC beginning in March of 2000. On January 16, 2001, NU along with the Independent System Operator and five other New England transmission owning utilities filed a proposal to establish a New England RTO. COMPETITIVE ENERGY SUBSIDIARIES NU's competitive energy subsidiaries engage in a variety of energy-related activities, primarily in the competitive energy retail and wholesale commodity, marketing and services fields. In addition, these subsidiaries own and manage 1,521 MW of capacity, as well as provide services to the electric generation market and large commercial and industrial customers in the Northeast. NU's competitive energy subsidiaries contributed $13.6 million before extraordinary items in 2000 towards NU's consolidated earnings, compared with a net loss of $37 million in 1999. In July 1999, NGC was announced as one of the winning bidders of certain CL&P and WMECO hydroelectric generation assets. Management expected this transaction to close by January 1, 2000. The transaction actually closed on March 14, 2000. This transaction has allowed the competitive energy subsidiaries to better balance their energy purchase and supply commitments, improving profitability. Since January 1, 2000, these assets have been managed by the competitive energy subsidiaries and earnings of $6.9 million have been included in the contributed earnings reported above of $13.6 million. As a result of the delayed closing, however, the $6.9 million was recorded by CL&P and WMECO for the period from January 1, 2000 to March 14, 2000. Unconsolidated revenues for the competitive energy subsidiaries were $1.9 billion in 2000, compared with $648.9 million in 1999. CL&P's standard offer purchases from Select Energy, represented $651.9 million of total competitive energy subsidiaries' revenues in 2000, which is eliminated in consolidation. NUCLEAR PLANT PERFORMANCE AND DIVESTITURE Millstone: The Millstone units completed one of their best years ever in 2000. Millstone 2 operated at a capacity factor of 82 percent in 2000 and completed a refueling outage in early June more than four days ahead of schedule. The 40-day, 21-hour outage set a world record for a refueling that included a full generator rewind. Millstone 3 operated at virtually a 100 percent capacity factor in 2000 and ran for 585 consecutive days before beginning a scheduled refueling outage on February 3, 2001. Millstone 3 is expected to return to service by the end of the first quarter of 2001. Along with the higher output, NU benefited from lower costs. NU's share of the nonfuel operation and maintenance (O&M) expenses associated with Millstone 2 and 3 totaled $193.6 million in 2000, compared with $269.4 million in 1999. On August 7, 2000, CL&P, WMECO and certain other joint owners reached an agreement to sell substantially all of the Millstone units, located in Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including approximately $105 million for nuclear fuel. Dominion has also agreed to assume responsibility for decommissioning the three units and NU will transfer to Dominion all funds in the Millstone decommissioning trust. Additionally, NU is obligated to top-off the decommissioning trust if its value does not equal an agreed upon amount at closing. That amount is pursuant to the purchase and sale agreement (PSA) with Dominion, subject to adjustment for delays in the closing of the sale and Millstone 1 not meeting the "cold and dark" condition specified in the PSA. If the transaction is consummated as proposed, CL&P and WMECO would receive gross proceeds of approximately $843.2 million and $196.2 million on a pretax basis for their respective ownership interests. The proceeds from the sale of these interests will be used to reduce the companies' stranded costs under restructuring and the cash proceeds will be used to repay subsidiary debt and capital lease obligations and to return equity capital to the parent company. PSNH will receive $26 million on a pretax basis, which will be reflected as a gain in accordance with the Settlement Agreement. In preparation for the divestiture of the Millstone units, it was discovered that two full-length irradiated fuel rods are missing. The company believes that the two rods remain stored in the Millstone 1 spent fuel pool or were shipped in a shielded cask to a facility licensed to accept radioactive material. The company's investigation into the location of the two rods is ongoing. NU is responsible for any potential liabilities, which are not determinable at this time, related to these missing fuel rods. In connection with the prior settlement of Millstone 3 joint owner claims, if the aforementioned transaction is consummated as proposed, the NU system will record a pretax gain in excess of $150 million. NU currently expects to close on the sale of Millstone as early as the end of March 2001. In anticipation of the sale of Millstone, in December 2000, NU announced a voluntary separation program designed to reduce generation-related support staff in 2001. NU will reflect this program's cost in the first quarter of 2001. Seabrook: Seabrook operated at a capacity factor of 78 percent in 2000. The unit began a scheduled refueling outage on October 21, 2000. The outage was extended by approximately two months as a result of the need to repair extensive problems with a back-up diesel generator. Seabrook returned to service on January 29, 2001. On December 15, 2000, NU filed its divestiture plan for Seabrook with the NHPUC and the DPUC. NU hopes to complete the sale in 2002. In October 2000, NU reached an agreement with an unaffiliated joint owner, who owns approximately 15 percent of Seabrook, to auction its share of the plant with NU's share. As part of the agreement, if the unaffiliated joint owner's share of the proceeds from the sale of Seabrook is less than $87.2 million, NU will provide up to $17.4 million to compensate for any shortfall. NU also will share in the benefits if the proceeds from the sale of that share of Seabrook exceeds $87.2 million. Additionally, under the agreement, NU will top-off certain decommissioning obligations above a defined level. Yankee Companies: In 1999, the Vermont Yankee Nuclear Power Corporation (VYNPC) agreed to sell its nuclear generating unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the obligation to decommission the unit after it is taken out of service, and the owners of VYNPC (including CL&P, WMECO and PSNH) agreed to fund their shares of the decommissioning costs up to a negotiated amount. Subsequent to the time that the agreement was executed, the original proposed acquiring company increased its purchase price and three other unaffiliated companies have indicated their interest in buying VYNPC's generating unit on terms that have not been disclosed. On February 14, 2001, the Vermont Public Service Board dismissed the acquiring company's petition for approval and VYNPC agreed to work with the Vermont regulators to develop an auction process for the sale of the unit. At present, CL&P, WMECO and PSNH expect that the unit will be sold, but the identity of the owner and the terms of sale, including price, future decommissioning obligations and future power purchase obligations, are not known. NUCLEAR DECOMMISSIONING In connection with the aforementioned sale of the Millstone units, Dominion has agreed to assume responsibility for decommissioning the Millstone units. For further information regarding nuclear decommissioning, see Note 7, "Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. SPENT NUCLEAR FUEL DISPOSAL COSTS The United States Department of Energy (DOE) originally was scheduled to begin accepting delivery of spent nuclear fuel in 1998. However, delays in confirming the suitability of a permanent storage site continually have postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. NU has the primary responsibility for the interim storage of its spent nuclear fuel prior to divestiture of its nuclear units. For further information regarding spent nuclear fuel disposal costs, see Note 6D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements. COMPETITIVE ENERGY SUBSIDIARIES' MARKET AND OTHER RISKS NU's competitive energy subsidiaries, as major providers of electricity and natural gas, have certain market risks inherent in their business activities. The competitive energy subsidiaries enter into contracts of varying length of time to buy and sell energy commodities, primarily electricity, natural gas and oil. Market risk represents the risk of loss that may impact the companies' financial statements due to adverse changes in commodity market prices. Through December 31, 2000, the competitive energy subsidiaries increased their volume of electricity and gas marketing activities, increasing these risks. The competitive energy subsidiaries manage its portfolio of contracts and assets to maximize value and minimize associated risks. The length of contracts to buy and sell energy vary in duration from daily/hourly to several years. At any point in time, the portfolio may be long (purchases exceeds sales) or short (sales exceeds purchases). Portfolio and risk management disciplines are used to manage exposures to market risks. Policies and procedures have been established to manage these risks. At market spot prices in effect at December 31, 2000, the portfolio had a negative mark to market. There is significant volatility in the energy commodities market and for certain of the energy products and contracts there has been limited liquidity. Management does not believe the ultimate settlement through physical delivery of its energy portfolio will result in realization of this negative mark to market. The servicing of CL&P's standard offer load is a significant risk for Select Energy, as this contract is for a 4-year period, ending December 31, 2003, at fixed prices. Approximately 26 percent of the 2000 competitive energy revenues came from this contract. This risk is partially mitigated by Select Energy entering into purchase contracts with other energy providers to supply a portion of the standard offer requirement, including its contracts with NGC, the purchase of 850 MW of output from the Millstone and Seabrook units through 2001 and other resources in the energy marketplace. Although there can be no assurance that it will be able to do so, management believes that Select Energy will be able to source its remaining load requirement at reasonable prices. If Select Energy is unable to source its remaining load requirement at prices below the standard offer contract price as a result of energy price increases, Select Energy's earnings would be adversely impacted. For further information see Note 8, "Market Risk and Risk Management Instruments," to the consolidated financial statements. OTHER MATTERS Derivative Instruments and Market Risk: Select Energy engages in the trading of commodity derivatives which are accounted for using the mark-to-market method under Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities." All other nontrading transactions are recognized where settled. For further information regarding these topics, see Note 8, "Market Risk and Risk Management Instruments," to the consolidated financial statements. Environmental Matters: NU is subject to environmental laws and regulations structured to mitigate or remove the effect of past operations and to improve or maintain the quality of the environment. For further information regarding environmental matters, see Note 6C, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements. Other Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 6, "Commitments and Contingencies," to the consolidated financial statements. Forward Looking Statements: This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in historical weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, and other presently unknown or unforeseen factors. RESULTS OF OPERATIONS The components of significant income statement variances for the past two years are provided in the table below. Income Statement Variances (Millions of Dollars) 2000 over/(under) 1999 1999 over/(under) 1998 ----------------------------------------------- Amount Percent Amount Percent ------ ------- ------ ------- Operating Revenues $1,405 31% $704 19% Operating Expenses: Fuel, purchased and net interchange power 1,423 75 428 29 Other operation (6) (1) 53 7 Maintenance (85) (25) (58) (15) Depreciation (62) (21) (31) (9) Amortization of regulatory assets, net (321) (54) 393 (a) Federal and state income taxes 49 27 99 (a) Taxes other than income taxes (22) (9) 9 4 Gain on sale of utility plant 309 100 (309) - ------ --- ---- --- Total operating expenses 1,285 31 584 16 ------ --- ---- --- Operating income 120 35 120 53 ------ --- ---- --- Other Income: Equity in earnings of regional nuclear generating and transmission companies 10 (a) (7) (59) Nuclear related costs 53 75 72 50 Other, net 29 95 (19) (a) Other income taxes (14) (17) 6 8 ------ --- ---- --- Net other income 78 (a) 52 69 Interest charges, net 36 14 (5) (2) Preferred dividends of subsidiaries (9) (38) (4) (14) ------ --- ---- --- Income before extraordinary line 171 (a) 181 (a) ------ --- ---- --- Extraordinary loss (234) (a) - - ------ --- ---- --- Net (loss)/income $ (63) (a) $181 (a) ====== === ==== === (a) Percent greater than 100. OPERATING REVENUES Total revenues increased by $1,405 million or 31 percent in 2000, primarily due to higher revenues from the competitive energy subsidiaries ($1,246 million of which $669 million represents sales to other NU affiliates which are eliminated in consolidation), the acquisition of Yankee ($262 million) and higher regulated wholesale revenues ($727 million of which $281 million represents sales to other NU affiliates which are eliminated in consolidation), partially offset by lower regulated retail revenues ($26 million). The competitive energy companies' increase is primarily due to higher revenues from Select Energy as a result of new contracts for energy sales and services. The regulated wholesale revenue increase is primarily due to higher PSNH energy sales and higher CL&P and WMECO revenue from the sale of the output from Millstone 2 and 3. The regulated retail decrease is primarily due to retail rate reductions for CL&P and PSNH ($108 and $8 million, respectively), partially offset by the impact of Millstone 2 being returned to CL&P's rate base ($33 million), higher retail sales ($18 million), higher fuel revenues for PSNH ($15 million) and higher retail revenue attributed to lower price discounts in 2000 and changing customer mix ($24 million). Regulated retail kilowatt-hour sales increased by 0.8 percent in 2000. Total revenues increased by $704 million or 19 percent in 1999, primarily due to higher revenues from the competitive energy subsidiaries ($552 million), higher regulated wholesale revenue ($107 million) and higher regulated retail revenue ($45 million). The competitive energy companies' increase is primarily due to higher revenues from Select Energy as a result of new contracts for energy sales. The regulated wholesale revenue increase is primarily due to higher energy sales and related capacity and transmission revenues. The regulated retail increase is primarily due to higher retail sales ($99 million) and the impact of Millstone 2 and 3 being returned to CL&P's rate base ($13 million). These retail increases were partially offset by retail rate reductions for CL&P and WMECO ($55 and $12 million, respectively). Regulated retail kilowatt-hour sales increased by 3.8 percent. FUEL, PURCHASED AND NET INTERCHANGE POWER Fuel, purchased and net interchange power expense increased in 2000, primarily due to higher purchased energy and capacity costs as a result of higher sales for Select Energy ($1,053 million of which $660 million represents purchases from NU other affiliates which are eliminated in consolidation), Yankee expenses ($135 million) and higher purchased power for regulated subsidiaries ($235 million). Fuel, purchased and net interchange power expense increased in 1999, primarily due to higher purchased energy and capacity costs as a result of higher sales for Select Energy ($521 million), regulated wholesale ($86 million) and regulated retail ($36 million), partially offset by lower replacement power costs due to the return to service of Millstone 2 and 3 ($215 million). OTHER OPERATION AND MAINTENANCE Other O&M expenses decreased $91 million in 2000, primarily due to lower spending at the nuclear units due to better performance ($75 million), lower expenses due to the sale of certain CL&P and WMECO fossil generation assets ($74 million), lower corporate support ($38 million), the decommissioning status of Millstone 1 ($17 million), lower environmental-related costs ($12 million), and higher 1999 expenses associated with the Con Edison merger ($12 million), partially offset by the addition of Yankee ($60 million), higher O&M expenses for the competitive energy businesses ($54 million), primarily due to the business expansion, and higher distribution expenses ($29 million), including increased conservation program expenses. Other O&M expenses decreased in 1999, primarily due to lower costs at the Millstone units ($125 million), partially offset by the recognition of environmental insurance proceeds in 1998 and additional environmental reserves in 1999 ($30 million), higher transmission and power exchange expenses ($35 million), higher spending at Seabrook ($10 million) as a result of the refueling outage, higher expenditures for HEC Inc. and the competitive energy businesses ($32 million), and expenses associated with the Con Edison merger ($12 million) in 1999. DEPRECIATION Depreciation decreased in 2000, primarily due to the effect of discontinuing SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," for the portion of the generation business for CL&P and WMECO and the resulting reclassification of depreciable nuclear plant balances to regulatory assets ($84 million) and the sale of certain CL&P and WMECO fossil and hydroelectric generation assets, partially offset by the addition of Yankee ($23 million). Depreciation decreased in 1999, primarily due to the retirement of Millstone 1. AMORTIZATION OF REGULATORY ASSETS, NET Amortization of regulatory assets, net decreased in 2000, primarily due to the amortization in 1999 as a result of the gain on the sale of fossil and hydroelectric generation assets for CL&P and WMECO ($309 million) and changes in amortization levels as a result of industry restructuring ($95 million). These decreases were partially offset by higher amortization associated with the reclassified nuclear plant balances ($84 million). Amortization of regulatory assets, net increased in 1999, primarily due to the increased amortization associated with the gain on the sale of CL&P's and WMECO's fossil and hydroelectric generation assets ($309 million), the amortization of CL&P's and WMECO's Millstone 1 remaining investment ($56 million) and the amortization of stranded nuclear plant balances reclassified as regulatory assets ($23 million). FEDERAL AND STATE INCOME TAXES The consolidated statement of income taxes provides a reconciliation of actual and expected tax expense. The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commission. In past years, this rate-making treatment has required the company to provide the customers with a portion of the tax benefits associated with accelerated tax depreciation in the year it is generated (flow-through depreciation). As these flow-through differences turn around, higher tax expense is recorded. Federal and state income tax expense increased approximately $63 million in 2000. Significant variances responsible for this increase include higher pretax earnings ($90 million) and lower adjustments to the tax valuation allowance ($21 million). Reduction in flow-through depreciation and amortization ($51 million) partially offset the overall change. Federal and state income tax expense increased approximately $93 million in 1999, primarily due to the significant increase in book pretax earnings. Significant variances of other items include a $10 million increase in flow-through depreciation turnaround and $4.6 million of nontax deductible merger-related expenditures, offset by the elimination of a $23 million deferred tax asset valuation reserve. TAXES OTHER THAN INCOME TAXES Taxes other than income taxes decreased in 2000, primarily due to lower Connecticut gross earnings taxes ($12 million) and lower payroll taxes ($7 million). Other income taxes increased in 1999, primarily due to higher local property taxes ($3 million) and higher gross earnings taxes ($2 million). GAIN ON SALE OF UTILITY PLANT CL&P and WMECO recorded gains on the sale of their fossil and hydroelectric generation assets in 1999. A corresponding amount of amortization expense was recorded. EQUITY IN EARNINGS OF REGIONAL NUCLEAR GENERATING AND TRANSMISSION COMPANIES Equity in earnings of regional nuclear generating and transmission companies increased in 2000, primarily due to higher earnings from the Connecticut Yankee Atomic Power Company (CYAPC) as a result of a rate settlement. Equity in earnings of regional nuclear generating and transmission companies decreased in 1999, primarily due to lower earnings from CYAPC. NUCLEAR RELATED COSTS Nuclear related costs in 2000 are comprised of a CL&P/WMECO settlement of Millstone 3 joint owner litigation, net of insurance proceeds ($11 million), and CL&P/WMECO regulatory settlements ($6 million). In comparison, 1999 is comprised of one-time charges related to the CL&P write-off of Connecticut Municipal Electric Energy Cooperative (CMEEC) nuclear costs ($20 million), the CL&P write-off of capital projects as a result of the Connecticut standard offer decision ($11 million), the CL&P/WMECO settlement of Millstone 3 joint owner litigation, net of insurance proceeds ($27 million), and WMECO return disallowances on Millstone 1 plant ($13 million). Recoverable costs in 1998 are comprised of the write-off of the Millstone 1 entitlement formerly held by CMEEC ($28 million) and the write-off of unrecoverable Millstone 1 costs as a result of the February 1999 CL&P rate decision ($115 million). OTHER, NET Other, net increased in 2000, primarily due to a one-time gain related to Mode 1 Communications, Inc.'s investment in NEON Communications, Inc. ($17 million) and the loss in 1999 on the CL&P assignment of market-based contracts to Select Energy ($15 million). Other income/(loss), net decreased in 1999, primarily due to the PSNH settlement with the New Hampshire Electric Cooperative ($6 million) and the loss on the CL&P assignment of market-based contracts to Select Energy ($15 million). INTEREST CHARGES, NET Interest charges, net increased in 2000, primarily due to higher short-term borrowings associated with the NGC asset transfer and the Yankee merger, partially offset by lower long-term debt as a result of reacquisitions and retirements. Interest charges, net decreased in 1999, primarily due to lower long-term debt as a result of reacquisitions and retirements. PREFERRED DIVIDENDS Preferred dividends decreased in 1999 and 2000, primarily due to lower preferred stock outstanding. EXTRAORDINARY LOSS The extraordinary loss is primarily due to an after-tax write-off by PSNH of approximately $225 million of stranded costs under an industry restructuring settlement with the state of New Hampshire, combined with other positive effects on PSNH from the discontinuance of SFAS No. 71 ($11 million) and a loss associated with the pending sale of certain HWP assets ($20 million). COMPANY REPORT The accompanying consolidated financial statements of Northeast Utilities and subsidiaries and other sections of this annual report were prepared by the company. These financial statements, which were audited by Arthur Andersen LLP, were prepared in accordance with accounting principles generally accepted in the United States using estimates and judgments, where required, and giving consideration to materiality. The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities. The company maintains a system of internal controls over financial reporting, which is designed to provide reasonable assurance to the company's management and Board of Trustees regarding the preparation of reliable, published financial statements. The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits. Through established programs, the company regularly communicates to its management employees their internal control responsibilities and policies prohibiting conflicts of interest. The Audit Committee of the Board of Trustees is composed entirely of independent trustees. The Audit Committee meets periodically with management, the internal auditors and the independent auditors to review the activities of each and to discuss audit matters, financial reporting and the adequacy of internal controls. Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected. The company believes, however, that its system of internal accounting controls and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ---------------------------------------- To the Board of Trustees and Shareholders of Northeast Utilities: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northeast Utilities (a Massachusetts trust) and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, comprehensive income, shareholders' equity, cash flows, and income taxes for each of the three years in the period ended December 31, 2000. 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 in accordance with auditing standards generally accepted in the United States. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut January 23, 2001 (except with respect to the matters discussed in Note 15, as to which the date is March 13, 2001) NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
- --------------------------------------------------------------------------------------------- For the Years Ended December 31, - --------------------------------------------------------------------------------------------- (Thousands of Dollars, except share information) 2000 1999 1998 - --------------------------------------------------------------------------------------------- Operating Revenues................................. $ 5,876,620 $ 4,471,251 $ 3,767,714 ------------- ------------- ------------- Operating Expenses: Operation - Fuel, purchased and net interchange power...... 3,321,226 1,898,314 1,470,200 Other.......................................... 850,192 855,917 803,419 Maintenance........................................ 255,884 340,419 399,165 Depreciation....................................... 239,798 302,305 332,807 Amortization of regulatory assets, net............. 276,139 596,437 203,132 Federal and state income taxes..................... 230,031 180,883 82,332 Taxes other than income taxes...................... 238,587 261,353 251,932 Gain on sale of utility plant...................... - (308,914) - ------------- ------------- ------------- Total operating expenses..................... 5,411,857 4,126,714 3,542,987 ------------- ------------- ------------- Operating Income................................... 464,763 344,537 224,727 ------------- ------------- ------------- Other Income/(Loss): Equity in earnings of regional nuclear generating and transmission companies......... 14,586 5,034 12,420 Nuclear related costs ............................. (17,907) (71,066) (143,239) Other, net......................................... (1,689) (30,855) (12,225) Minority interest in loss of subsidiary............ (9,300) (9,300) (9,300) Income taxes....................................... 68,306 82,272 76,393 ------------- ------------- ------------- Other income/(loss), net..................... 53,996 (23,915) (75,951) ------------- ------------- ------------- Income before interest charges............... 518,759 320,622 148,776 ------------- ------------- ------------- Interest Charges: Interest on long-term debt......................... 200,697 258,093 273,824 Other interest, net................................ 98,605 5,558 (4,735) ------------- ------------- ------------- Interest charges, net........................ 299,302 263,651 269,089 ------------- ------------- ------------- Income/(loss) after interest charges......... 219,457 56,971 (120,313) Preferred Dividends of Subsidiaries................ 14,162 22,755 26,440 ------------- ------------- ------------- Income/(Loss) before extraordinary loss............ 205,295 34,216 (146,753) Extraordinary loss, net of tax benefit of $169,562..................................... (233,881) - - ------------- ------------- ------------- Net (Loss)/Income.................................. $ (28,586) $ 34,216 $ (146,753) ============= ============= ============= Basic and Fully Diluted (Loss)/Earnings Per Common Share: Income/(loss) before extraordinary loss......... $ 1.45 $ 0.26 $ (1.12) Extraordinary loss, net of tax benefit.......... (1.65) - - ------------- ------------- ------------- Basic (Loss)/Earnings Per Common Share............. $ (0.20) $ 0.26 $ (1.12) ============= ============= ============= Basic Common Shares Outstanding (average).......... 141,549,860 131,415,126 130,549,760 ============= ============= ============= Fully Diluted Common Shares Outstanding (average).. 141,967,216 132,031,573 130,549,760 ============= ============= =============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
- --------------------------------------------------------------------------------------------- For the Years Ended December 31, - --------------------------------------------------------------------------------------------- (Thousands of Dollars) 2000 1999 1998 - --------------------------------------------------------------------------------------------- Net (Loss)/Income.................................. $ (28,586) $ 34,216 $ (146,753) ------------- ------------- ------------- Other comprehensive income, net of tax: Foreign currency translation adjustments........... - 1 - Unrealized gains on securities..................... 245 118 2,019 Minimum pension liability adjustments.............. - - (613) ------------- ------------- ------------- Other comprehensive income, net of tax......... 245 119 1,406 ------------- ------------- ------------- Comprehensive (Loss)/Income........................ $ (28,341) $ 34,335 $ (145,347) ============= ============= =============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------- At December 31, - ---------------------------------------------------------------------------------------- (Thousands of Dollars) 2000 1999 - ---------------------------------------------------------------------------------------- ASSETS - ------ Utility Plant, at cost: Electric................................................ $ 9,370,176 $ 9,185,272 Gas and other........................................... 861,727 226,002 ------------- ------------- 10,231,903 9,411,274 Less: Accumulated provision for depreciation......... 7,041,279 6,088,310 ------------- ------------- 3,190,624 3,322,964 Unamortized PSNH acquisition costs...................... - 324,437 Construction work in progress........................... 228,330 177,504 Nuclear fuel, net....................................... 128,261 122,529 ------------- ------------- Total net utility plant.............................. 3,547,215 3,947,434 ------------- ------------- Other Property and Investments: Nuclear decommissioning trusts, at market............... 740,058 711,910 Investments in regional nuclear generating companies, at equity.................................. 62,477 81,503 Other, at cost.......................................... 137,291 94,768 ------------- ------------- 939,826 888,181 ------------- ------------- Current Assets: Cash and cash equivalents............................... 200,017 255,154 Investments in securitizable assets..................... 98,146 107,620 Receivables, less accumulated provision for uncollectible accounts of $12,500 in 2000 and $4,895 in 1999........................................ 472,863 310,190 Unbilled revenues....................................... 121,090 75,728 Fuel, materials and supplies, at average cost........... 163,711 172,973 Recoverable energy costs, net - current portion......... - 73,721 Prepayments and other................................... 94,528 75,225 ------------- ------------- 1,150,355 1,070,611 ------------- ------------- Deferred Charges: Regulatory assets....................................... 3,910,801 3,642,439 Unamortized debt expense................................ 33,475 39,192 Goodwill and other purchased intangible assets.......... 324,389 23,542 Prepaid pensions........................................ 139,546 669 Other .................................................. 171,542 75,984 ------------- ------------- 4,579,753 3,781,826 ------------- ------------- Total Assets.............................................. $ 10,217,149 $ 9,688,052 ============= =============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------- At December 31, - ---------------------------------------------------------------------------------------- (Thousands of Dollars) 2000 1999 - ---------------------------------------------------------------------------------------- CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common shares, $5 par value - authorized 225,000,000 shares; 148,781,861 shares issued and 143,820,405 shares outstanding in 2000 and 137,393,829 shares issued and 131,870,284 shares outstanding in 1999..... $ 693,345 $ 636,405 Capital surplus, paid in................................ 927,059 776,290 Temporary equity from stock forward..................... 215,000 215,000 Deferred contribution plan - employee stock ownership plan........................................ (114,463) (127,725) Retained earnings....................................... 495,873 581,817 Accumulated other comprehensive income.................. 1,769 1,524 ------------- ------------- Total common shareholders' equity.................... 2,218,583 2,083,311 Preferred stock not subject to mandatory redemption....... 136,200 136,200 Preferred stock subject to mandatory redemption........... 15,000 121,289 Long-term debt............................................ 2,029,593 2,372,341 ------------- ------------- Total capitalization................................. 4,399,376 4,713,141 ------------- ------------- Minority Interest in Consolidated Subsidiary.............. 100,000 100,000 ------------- ------------- Obligations Under Capital Leases.......................... 47,234 62,824 ------------- ------------- Current Liabilities: Notes payable to banks.................................. 1,309,977 278,000 Long-term debt and preferred stock - current portion.... 340,041 503,315 Obligations under capital leases - current portion...... 112,645 118,469 Accounts payable........................................ 538,983 347,321 Accrued taxes........................................... 54,088 158,684 Accrued interest........................................ 41,131 37,904 Other................................................... 144,931 126,768 ------------- ------------- 2,541,796 1,570,461 ------------- ------------- Deferred Credits and Other Long-term Liabilities: Accumulated deferred income taxes....................... 1,585,494 1,688,114 Accumulated deferred investment tax credits............. 153,155 140,407 Decommissioning obligation - Millstone 1................ 692,560 702,351 Deferred contractual obligations........................ 244,608 358,387 Other................................................... 452,926 352,367 ------------- ------------- 3,128,743 3,241,626 ------------- ------------- Commitments and Contingencies (Note 6) Total Capitalization and Liabilities...................... $ 10,217,149 $ 9,688,052 ============= =============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
- ------------------------------------------------------------------------------------------ Accum- Deferred ulated Capital Contribu- Other Common Surplus, tion Retained Compre- Shares Paid In Plan- Earnings hensive (Thousands of Dollars) (a) (a) ESOP (b) Income Total - ------------------------------------------------------------------------------------------ Balance as of January 1, 1998................$684,211 $ 932,494 $(154,141)$ 707,522 $ (1)$2,170,085 - ------------------------------------------------------------------------------------------ Net loss for 1998............. (146,753) (146,753) Issuance of 189,094 common shares, $5 par value........ 945 1,714 2,659 Allocation of benefits-ESOP... (4,769) 13,522 8,753 Unearned stock compensation... (537) (537) Capital stock expenses, net... 3,560 3,560 Gain on equity investment..... 8,140 8,140 Gain on repurchase of preferred stock............. 59 59 Other comprehensive income.... 1,406 1,406 - ------------------------------------------------------------------------------------------ Balance as of December 31, 1998............. 685,156 940,661 (140,619) 560,769 1,405 2,047,372 - ------------------------------------------------------------------------------------------ Net income for 1999........... 34,216 34,216 Cash dividends on common shares-$0.10 per share...... (13,168) (13,168) Issuance of 362,565 common shares, $5 par value........ 1,813 3,505 5,318 Allocation of benefits-ESOP... (3,053) 12,894 9,841 Unearned stock compensation... (1,194) (1,194) Capital stock expenses, net... 807 807 Other comprehensive income.... 119 119 - ------------------------------------------------------------------------------------------ Balance as of December 31, 1999............. 686,969 940,726 (127,725) 581,817 1,524 2,083,311 - ------------------------------------------------------------------------------------------ Net loss for 2000............. (28,586) (28,586) Cash dividends on common shares-$0.40 per share...... (57,358) (57,358) Issuance of 11,388,032 common shares, $5 par value........ 56,940 164,443 221,383 Common share repurchase transaction fee............. (13,786) (13,786) Allocation of benefits-ESOP... (1,617) 13,262 11,645 Redemption of preferred stock............. (749) (749) Capital stock expenses, net... 2,478 2,478 Other comprehensive income.... 245 245 - ------------------------------------------------------------------------------------------ Balance as of December 31, 2000.............$743,909 $1,091,495 $(114,463)$ 495,873 $1,769 $2,218,583 - ------------------------------------------------------------------------------------------ (a) In conjunction with NU's forward share purchase arrangement, 10,112,879 shares or $50.6 million and $164.4 million, respectively, have been reclassified from Common Shares and Capital Surplus, Paid In, at December 31, 2000 and 1999, to Temporary Equity from Stock Forward. (b) Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt agreements. These restrictions also limit the amount of retained earnings available for NU common dividends. At December 31, 2000, retained earnings available for payment of dividends totaled $180.1 million. Pursuant to certain credit agreements, NU may not declare or make distributions in an amount not to exceed $60 million for any twelve month period.
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
- ------------------------------------------------------------------------------------------------ For the Years Ended December 31, - ------------------------------------------------------------------------------------------------ (Thousands of Dollars) 2000 1999 1998 - ------------------------------------------------------------------------------------------------ Operating Activities: Income/(loss) after interest charges......................... $ 219,457 $ 56,971 $(120,313) Adjustments to reconcile to net cash provided by operating activities: Depreciation............................................... 239,798 302,305 332,807 Deferred income taxes and investment tax credits, net...... (16,117) (183,356) 23,502 Amortization of regulatory assets, net..................... 276,139 596,437 203,132 Net (deferral)/amortization of recoverable energy costs.... (30,603) 44,526 38,356 Nuclear related costs...................................... 17,907 71,066 143,239 Gain on sale of utility plant.............................. - (308,914) - Net other sources/(uses) of cash........................... (88,549) (79,232) 53,346 Changes in working capital: Receivables and unbilled revenues, net..................... (104,868) (106,566) (27,553) Fuel, materials and supplies............................... 12,450 29,688 10,060 Accounts payable........................................... 171,148 8,709 (64,258) Accrued taxes.............................................. (128,107) 107,929 4,739 Investments in securitizable assets........................ 9,474 74,498 48,787 Other working capital (excludes cash)...................... 254 157 17,424 ---------- ---------- ---------- Net cash flows provided by operating activities................ 578,383 614,218 663,268 ---------- ---------- ---------- Investing Activities: Investments in plant: Electric, gas and other utility plant...................... (352,736) (287,081) (217,009) Nuclear fuel............................................... (61,286) (42,471) (17,026) ---------- ---------- ---------- Net cash flows used for investments in plant................. (414,022) (329,552) (234,035) Investments in nuclear decommissioning trusts................ (39,550) (74,231) (75,551) Investment in competitive energy assets...................... - (23,542) - Net proceeds from the sale of utility plant.................. - 565,436 - Other investment activities, net............................. (28,478) 13,084 14,342 Payment for the purchase of Yankee, net of cash acquired..... (260,347) - - ---------- ---------- ---------- Net cash flows (used in)/provided by investing activities...... (742,397) 151,195 (295,244) ---------- ---------- ---------- Financing Activities: Issuance of common shares.................................... 4,269 5,318 2,659 Issuance of long-term debt................................... 26,477 200 275 Net increase/(decrease) in short-term debt................... 961,977 248,000 (20,000) Reacquisitions and retirements of long-term debt............. (685,555) (817,759) (269,555) Reacquisitions and retirements of preferred stock............ (126,771) (46,250) (62,211) Cash dividends on preferred stock............................ (14,162) (22,755) (26,440) Cash dividends on common shares.............................. (57,358) (13,168) - ---------- ---------- ---------- Net cash flows provided by/(used in) financing activities...... 108,877 (646,414) (375,272) ---------- ---------- ---------- Net (decrease)/increase in cash and cash equivalents........... (55,137) 118,999 (7,248) Cash and cash equivalents - beginning of period................ 255,154 136,155 143,403 ---------- ---------- ---------- Cash and cash equivalents - end of period...................... $ 200,017 $ 255,154 $ 136,155 ========== ========== ========== Supplemental schedule of noncash investing and financing activities: In conjuction with the Yankee acquisition on March 1, 2000, common stock was issued and debt was assumed as follows: Fair value of assets acquired, net of liabilites assumed $ 712,484 Cash paid (261,370) NU common stock issued (217,114) ---------- $ 234,000 ========== Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized......................... $ 269,735 $ 266,823 $ 238,990 ========== ========== ========== Income taxes................................................. $ 253,383 $ 86,183 $ 19,454 ========== ========== ========== Increase in obligations: Niantic Bay Fuel Trust and other capital leases.............. $ 8,067 $ 5,865 $ 12,583 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CAPITALIZATION
- ---------------------------------------------------------------------------------------------------------------- At December 31, - ---------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2000 1999 - ---------------------------------------------------------------------------------------------------------------- Common Shareholders' Equity (a) $2,218,583 $2,083,311 Cumulative Preferred Stock of Subsidiaries: $25 par value - authorized 36,600,000 shares at December 31, 2000 and 1999; 1,630,722 shares outstanding in 2000 and 2,720,000 shares outstanding in 1999 $50 par value - authorized 9,000,000 shares at December 31, 2000 and 1999; 2,324,000 shares outstanding in 2000 and 4,314,774 shares outstanding in 1999 $100 par value - authorized 1,000,000 shares at December 31, 2000 and 1999; 200,000 shares outstanding in 2000 and 1999
- ---------------------------------------------------------------------------------------------------------------- Current Current Redemption Shares Dividend Rates Prices (b) Outstanding - ---------------------------------------------------------------------------------------------------------------- Not Subject to Mandatory Redemption: $50 par value - $1.90 to $3.28 $50.50 to $54.00 2,234,000 116,200 116,200 $100 par value - $7.72 $103.51 200,000 20,000 20,000 --------- --------- Total Preferred Stock Not Subject to Mandatory Redemption 136,200 136,200 --------- --------- Subject to Mandatory Redemption: (c) $25 par value - $1.90 to $2.65 $25.00 to $25.26 1,630,722 40,768 68,000 $50 par value - $2.65 to $3.615 - - - 99,539 --------- --------- Total Preferred Stock Subject to Mandatory Redemption 40,768 167,539 Less: Preferred Stock to be Redeemed Within One Year 25,768 46,250 --------- --------- Preferred Stock Subject to Mandatory Redemption, Net 15,000 121,289 --------- ---------
Long-Term Debt: (d)
First Mortgage Bonds - Maturity Interest Rates - ---------------------------------------------------------------------------------------------------------------- 2000 5.75% to 6.875%................................... - 159,000 2001 7.375% to 7.875%.................................. 220,000 220,000 2002 7.75% to 9.05%.................................... 375,000 489,150 2005 6.75%............................................. 20,000 - 2009-2012 6.20% to 7.19%.................................... 80,000 - 2019-2024 7.375% to 10.07%.................................. 313,050 325,000 ----------- ---------- Total First Mortgage Bonds......................................... 1,008,050 1,193,150 ----------- ---------- Other Long-Term Debt - Pollution Control Notes and Other Notes - (e) 2000 Adjustable Rate and 7.67%......................... - 206,011 2003-2006 6.24% to 8.58%.................................... 139,600 158,000 2013-2018 Adjustable Rate and 5.90%......................... 33,400 33,400 2020 Adjustable Rate................................... 15,300 15,300 2021-2022 Adjustable Rate and 5.85% to 7.65%................ 443,285 552,485 2028 5.85% to 5.95%.................................... 369,300 369,300 2031 Adjustable Rate................................... 62,000 62,000 ---------- ---------- Total Pollution Control Notes and Other Notes...................... 1,062,885 1,396,496 Fees and interest due for spent nuclear fuel disposal costs............... 240,303 226,463 Other..................................................................... 38,978 15,346 ---------- ---------- Total Other Long-Term Debt................................................ 1,342,166 1,638,305 ---------- ---------- Unamortized premium and discount, net..................................... (6,350) (2,049) ---------- ---------- Total Long-Term Debt...................................................... 2,343,866 2,829,406 Less: Amounts due within one year........................................ 314,273 457,065 ---------- ---------- Long-Term Debt, Net....................................................... 2,029,593 2,372,341 ---------- ---------- Total Capitalization...................................................... $4,399,376 $4,713,141 ========== ==========
The accompanying notes are an integral part of these financial statements. NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION (a) On January 2, 2001, NU modified its forward share purchase arrangements for approximately 10 million NU common shares. To initially effect these arrangements, the financial institutions (counterparties) purchased approximately 10 million NU common shares on the open market in December 1999 and January 2000, in a total aggregate amount of $215 million, at an average price of $21.26. The counterparties maintain ownership of the shares until the transactions are settled. NU will continue to accrue charges on the total aggregate amount at LIBOR plus an agreed upon percentage per annum, until the transactions are settled. These transactions can be settled in cash or NU common shares at the company's discretion. NU expects to repurchase the shares from the counterparties in the first half of 2001 with the proceeds from restructuring. This amount has been classified as temporary equity from stock forward on NU's consolidated balance sheets at December 31, 2000 and 1999. (b) Each of these series is subject to certain refunding limitations for the first five years after issuance. For preferred stock subject to mandatory redemption, redemption prices reduce in future years. (c) The minimum sinking fund requirements of the series subject each year to mandatory redemption aggregate $25.8 million in 2001 and $1.5 million in 2002, 2003, 2004, and 2005. In case of default on sinking fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If a subsidiary is in arrears in the payment of dividends on any outstanding shares of preferred stock, the subsidiary is prohibited from redeeming or purchasing less than all of the outstanding preferred stock. (d) Long-term debt maturities and cash sinking fund requirements, excluding fees and interest due for spent nuclear fuel disposal costs, on debt outstanding at December 31, 2000, for the years 2001 through 2005 are $314.3 million, $331.5 million, $26.6 million, $26.4 million, and $48.5 million, respectively. Essentially all utility plant of CL&P, PSNH, WMECO, and NAEC, is subject to the liens of each company's respective first mortgage bond indenture. NAEC's first mortgage bonds are also secured by payments made to NAEC by PSNH under the terms of two life-of-unit, full cost recovery contracts. CL&P and WMECO have secured $369.3 million of pollution control notes with second mortgage liens on Millstone 1, junior to the liens of their respective first mortgage bond indentures. CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with bond insurance secured by the first mortgage bonds and a liquidity facility. Concurrent with the issuance of PSNH's Series A and B first mortgage bonds, PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire. Pursuant to these arrangements, the BFA issued five series of PCRBs and loaned the proceeds to PSNH. At December 31, 2000 and 1999, $407.3 million and $516.5 million, respectively, of the PCRBs were outstanding. PSNH's obligation to repay each series of PCRBs is secured by the first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. For financial reporting purposes, these bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs. (e) The average effective interest rates on the variable-rate pollution control notes ranged from 3.2 percent to 6.8 percent for 2000 and 2.2 percent to 6.1 percent for 1999. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME TAXES
- ---------------------------------------------------------------------------------------------------------------- For the Years Ended December 31, - ---------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2000 1999 1998 - ---------------------------------------------------------------------------------------------------------------- The components of the federal and state income tax provisions charged to operations are: Current income taxes: Federal...................................................... $ 154,790 $ 248,012 $ (13,660) State........................................................ 23,052 33,955 (3,903) --------- --------- --------- Total current................................................... 177,842 281,967 (17,563) --------- --------- --------- Deferred income taxes, net: Federal....................................................... 7,297 (134,773) 51,913 State......................................................... (5,529) (28,789) (12,948) --------- --------- --------- Total deferred.................................................. 1,768 (163,562) 38,965 --------- --------- --------- Investment tax credits, net..................................... (17,885) (19,794) (15,463) --------- --------- --------- Total income tax expense........................................ $ 161,725 $ 98,611 $ 5,939 ========= ========= ========= The components of total income tax expense are classified as follows: Income taxes charged to operating expenses.................. $ 230,031 $ 180,883 $ 82,332 Other income taxes.......................................... (68,306) (82,272) (76,393) --------- --------- --------- Total income tax expense........................................ $ 161,725 $ 98,611 $ 5,939 ========= ========= ========= Deferred income taxes are comprised of the tax effects of temporary differences as follows: Deferred tax asset associated with net operating losses...... $ 1,563 $ 14,801 $ 69,212 Depreciation, leased nuclear fuel, settlement credits and disposal costs.................................. 9,514 (4,580) 16,217 Regulatory deferral.......................................... (34,486) (27,297) (38,287) Regulatory disallowance...................................... - (30,719) (18,080) Sale of fossil and hydroelectric generation assets........... - (125,807) - Pension...................................................... 25,751 8,936 10,950 Other........................................................ (574) 1,104 (1,047) --------- --------- --------- Deferred income taxes, net...................................... $ 1,768 $(163,562) $ 38,965 ========= ========= ========= A reconciliation between income tax expense and the expected tax expense at 35 percent of pretax income: Expected federal income tax..................................... $ 133,413 $ 54,454 $ (40,031) Tax effect of differences: Depreciation................................................. 7,775 24,583 25,793 Amortization of regulatory assets............................ 11,942 45,825 30,740 Amortization of PSNH acquisition costs....................... 9,946 9,946 17,301 Investment tax credit amortization........................... (17,885) (19,794) (15,463) State income taxes, net of federal benefit................... 11,390 3,358 (10,953) Nondeductible penalties...................................... 38 17 3,589 Adjustment for prior years' taxes............................ - (2,796) (7,338) Employee stock ownership plan................................ (999) 1,166 (1,670) Dividends received deduction................................. (8,618) (1,314) (3,218) Adjustment to tax asset valuation allowance.................. (2,136) (23,129) 7,000 Merger-related expenditures.................................. 5,829 4,597 - Deferred intercompany gain................................... 5,038 786 630 Other, net................................................... 5,992 912 (441) --------- --------- --------- Total income tax expense $ 161,725 $ 98,611 $ 5,939 ========= ========= =========
The accompanying notes are in integral part of these financial statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. ABOUT NORTHEAST UTILITIES Northeast Utilities (NU or the company) is the parent company of the Northeast Utilities system (NU system). Through its regulated utilities and competitive energy subsidiaries, the NU system serves in excess of 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues. The NU system's regulated utilities furnish franchised retail electric service in Connecticut, New Hampshire and western Massachusetts through three wholly owned subsidiaries: The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO). Another wholly owned subsidiary, North Atlantic Energy Corporation (NAEC), sells all of its entitlement to the capacity and output of the Seabrook Station nuclear unit (Seabrook) to PSNH under the terms of two life-of-unit, full cost recovery contracts (Seabrook Power Contracts). A fifth wholly owned subsidiary, Holyoke Water Power Company (HWP), also is engaged in the production and distribution of electric power. On March 1, 2000, NU completed its acquisition of Yankee Energy System, Inc. (Yankee), the parent company of Yankee Gas Services Company (Yankee Gas), Connecticut's largest natural gas distribution system. NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and the NU system is subject to the provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering inter- connections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. The operating subsidiaries are subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions. NU Enterprises, Inc. is a wholly owned subsidiary of NU and acts as the holding company for certain of NU's competitive energy subsidiaries. Northeast Generation Company (NGC) was formed to acquire and manage generation facilities. Northeast Generation Services Company and its subsidiaries (NGS) was formed to maintain and service any fossil or hydroelectric facility that is acquired or contracted with for these services. HEC Inc. and its subsidiaries (HEC), Mode 1 Communications, Inc. (Mode 1), Select Energy, Inc. (Select Energy), and Select Energy Portland Pipeline, Inc. engage in a variety of energy-related and telecommunications activities, as applicable, primarily in the competitive energy retail and wholesale commodity, marketing and services fields. Several wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing, and other services to the NU system companies. Northeast Nuclear Energy Company acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear units. North Atlantic Energy Service Corporation has operational responsibility for Seabrook. Three other subsidiaries construct, acquire or lease some of the property and facilities used by the NU system companies. B. PRESENTATION The consolidated financial statements of the NU system include the accounts of all subsidiaries. Intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. C. NEW ACCOUNTING STANDARDS Derivative Instruments: Effective January 1, 2001, NU adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS No. 133 requires that derivative instruments be recorded as an asset or liability measured at its fair value and that changes in the fair value of derivative instruments be recognized currently in earnings unless specific hedge accounting criteria are met. In order to implement SFAS No. 133 by January 1, 2001, NU established a cross- functional project team to identify all derivative instruments, measure the fair value of those derivative instruments, designate and document various hedge relationships, and evaluate the effectiveness of those hedge relationships. NU has completed the process of identifying all derivative instruments and has established appropriate fair value measurements of those derivative instruments in place at January 1, 2001. In addition, for those derivative instruments which are hedging an identified risk, NU has designated and documented all hedging relationships anew. NU believes that the majority of its nontrading energy and capacity contracts, purchased-power agreements, power sale agreements, and gas and electric retail contracts, qualify for the "normal purchases and sales" exception of the new standard, and therefore are not required to be recognized at fair value. However, NU believes that its electric, oil and gas swap contracts, interest rate swap agreements, and gas and oil futures are derivatives and will be recorded on its consolidated balance sheets at fair value on January 1, 2001. NU believes that certain of these contracts meet specific hedge accounting criteria; accordingly, changes in the fair value of these contracts will be recorded in other comprehensive income on the consolidated balance sheets. For those contracts that do not meet the hedging requirements, the changes in fair value of those contracts will be recognized currently in earnings. As explained within Note 8 commodity derivatives that are utilized for trading purposes, are accounted for using the mark-to-market method, under Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities." Management will record the effects of SFAS No. 133 in the first quarter of 2001 through a cumulative effect of a change in accounting principle and estimates that the effect will be to reduce pretax earnings by approximately $37.4 million and increase shareholders' equity by $21.7 million. These estimates do not include certain long-term energy and capacity contracts which management believes represent "normal purchases and sales." The accounting for these types of contracts is currently being evaluated by the Financial Accounting Standards Board (FASB). Further guidance from the FASB may change management's conclusions regarding these contracts and require them to be accounted for as derivatives. Transfers of Financial Assets: In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities - a Replacement of FASB Statement No. 125." SFAS No. 140 revises the criteria for accounting for securitizations, other financial asset transfers and collateral and introduces new disclosures, but otherwise carries forward most of the provisions of SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," without amendment. SFAS No. 140 is effective for transfers and servicing of financial assets and extinguishments of liabilities occurring after March 31, 2001, and is effective for recognition and reclassification of collateral and for disclosures relating to securitization transactions and collateral for fiscal years ending after December 15, 2000. The adoption of the disclosure requirements under SFAS No. 140 did not have a material impact on NU's consolidated financial statements. Revenue Recognition: In December 1999, the SEC issued Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition." The adoption of SAB No. 101, as amended, did not have a material impact on NU's consolidated financial statements. Forward Share Purchase Arrangement: EITF Issue No. 00-19, "Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company's Own Stock," requires that all contracts be initially measured at fair value and subsequently accounted for based on the current classification and the assumed or required settlement method. As NU's forward share purchase arrangements can be settled in cash or NU common shares at the company's discretion, this amount was classified as temporary equity from stock forward on the consolidated balance sheets at December 31, 2000 and 1999. On January 2, 2001, these arrangements were modified. As a result of applying the revised guidance under EITF Issue No. 00-19, the aforementioned forward share purchase transactions no longer meet the temporary equity criteria and will be classified as an asset or liability in the first quarter of 2001. The difference between the fair value and contract value will be included in earnings. NU expects to repurchase the shares from the counterparties in the first half of 2001 with the proceeds from restructuring. D. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock in four regional nuclear companies (Yankee Companies). The NU system's ownership interests in the Yankee Companies at December 31, 2000 and 1999, which are accounted for on the equity method due to the NU system companies' ability to exercise significant influence over their operating and financial policies are 49 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 38.5 percent of the Yankee Atomic Electric Company (YAEC), 20 percent of the Maine Yankee Atomic Power Company (MYAPC), and 16 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC). The NU system's total equity investment in the Yankee Companies at December 31, 2000 and 1999, is $62.5 million and $81.5 million, respectively. Each Yankee Company owns a single nuclear generating unit. However, VYNPC is the only unit still in operation at December 31, 2000. Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a 660 megawatt (MW) nuclear unit, which is currently in decommissioning status, and Millstone 2, an 870 MW nuclear generating unit. CL&P, PSNH and WMECO together have a 68.02 percent joint ownership interest in Millstone 3, a 1,154 MW nuclear generating unit. On August 7, 2000, CL&P, WMECO and certain other joint owners reached an agreement to sell substantially all of the Millstone units to Dominion Resources, Inc. (Dominion) for approximately $1.3 billion, including approximately $105 million for nuclear fuel. NU currently expects to close on the sale of Millstone as early as the end of March 2001. Seabrook: CL&P and NAEC together have a 40.04 percent joint ownership interest in Seabrook, a 1,148 MW nuclear generating unit. NAEC sells all of its share of the power generated by Seabrook to PSNH under the Seabrook Power Contracts. CL&P and NAEC expect to auction their joint ownership interests in Seabrook in 2001 with a closing on the sale expected in 2002. Plant-in-service and the accumulated provision for depreciation for the NU system's share of Millstone 2 and 3 and Seabrook are as follows: - ------------------------------------------------------------------------------- At December 31, - ------------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 - ------------------------------------------------------------------------------- Plant-in-service Millstone 2 $ 962.0 $ 952.1 Millstone 3 2,427.2 2,414.9 Seabrook 909.3 901.9 Accumulated provision for depreciation Millstone 2 $ 953.6 $ 910.0 Millstone 3 2,214.3 2,220.5 Seabrook 821.3 318.8 - ------------------------------------------------------------------------------- Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling $15 million and $16.5 million at December 31, 2000 and 1999, respectively, in two companies that transmit electricity imported from the Hydro-Quebec system in Canada. E. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on the estimated remaining useful lives of depreciable utility plant- in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. The costs of closure and removal of nonnuclear facilities are accrued over the life of the plant as a component of depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.1 percent in 2000 and 3.3 percent in 1999 and 1998. As a result of discontinuing the application of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," for CL&P's and WMECO's generation businesses in 1999, including CL&P's ownership interest in Seabrook, NU recorded a charge to accumulated depreciation for the nuclear plant in excess of the estimated fair market value at the time in the amount of $2 billion and a corresponding regulatory asset was created. Also, in 2000, HWP discontinued SFAS No. 71 and recorded a charge to accumulated depreciation for the plant in excess of fair value for certain hydroelectric generation assets, which was recorded as an extraordinary loss. F. REVENUES Regulated utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. Regulatory commissions also have authority over the terms and conditions of nontraditional rate-making arrangements. At the end of each accounting period, CL&P, PSNH, WMECO, Select Energy, and Yankee Gas accrue a revenue estimate for the amount of energy delivered but unbilled. Revenues for NU's competitive energy subsidiaries, primarily Select Energy, are recognized when the energy is delivered. G. PSNH ACQUISITION COSTS PSNH acquisition costs represent the aggregate value placed by the 1989 rate agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in excess of the net book value of PSNH's non-Seabrook assets, plus the $700 million value assigned to Seabrook by the Rate Agreement as part of the bankruptcy resolution on June 5, 1992. The Rate Agreement provided for the recovery through rates, with a return, of the PSNH acquisition costs. In connection with the "Agreement to Settle PSNH Restructuring" (Settlement Agreement) approximately $219.4 million was written off and the balance of $76.6 million has been reclassified as a regulatory asset. H. REGULATORY ACCOUNTING AND ASSETS The accounting policies of the NU system operating companies and the accompanying consolidated financial statements conform to accounting principles generally accepted in the United States applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71. As a result of final restructuring orders issued in 1999, CL&P and WMECO discontinued the application of SFAS No. 71 for the generation portion of their businesses. During the fourth quarter of 2000, the Settlement Agreement became probable of implementation, therefore, PSNH discontinued the application of SFAS No. 71 for the generation portion of its business. CL&P's, WMECO's and PSNH's transmission and distribution business will continue to be cost-based and management believes the application of SFAS No. 71 continues to be appropriate. Management continues to believe it is probable that the NU system operating companies will recover their investments in long- lived assets, including regulatory assets through charges to their transmission and distribution customers generally over periods of 7 to 26 years, subject to certain adjustments. The majority for CL&P and WMECO will be recovered through a transition charge over a 12-year period. PSNH will recover securitized assets over a 12-year period. Nuclear decommissioning and IPP costs will be recovered over the period PSNH is responsible for those costs. The third type of PSNH stranded costs are nonsecuritized regulatory assets (type three regulatory assets). Any type three regulatory assets not collected by the recovery end date will be written off. Based on current projections, PSNH expects to fully recovery all of its type three regulatory assets by the recovery end date stipulated in the Settlement Agreement. In addition, all material regulatory assets are earning a return. The components of the NU system companies' regulatory assets are as follows: - ------------------------------------------------------------------------------- At December 31, - ------------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 - ------------------------------------------------------------------------------- Recoverable nuclear costs $2,565.8 $2,210.8 Income taxes, net 504.7 636.6 Unrecovered contractual obligations 255.8 349.2 Recoverable energy costs, net 332.5 228.2 Other 252.0 217.6 - ------------------------------------------------------------------------------- Totals $3,910.8 $3,642.4 - ------------------------------------------------------------------------------- As a result of discontinuing the application of SFAS No. 71 in 1999 for CL&P's and WMECO's generation businesses, CL&P and WMECO reclassified nuclear plant in excess of its estimated fair market value from plant to regulatory assets. As of December 31, 2000 and 1999, both the CL&P unamortized balance ($1.35 billion and $1.38 billion, respectively) and the WMECO unamortized balance ($286.9 million and $316.1 million, respectively) are classified as recoverable nuclear costs. Also included in that regulatory asset component for 2000 and 1999 are $449.2 million and $514.7 million, respectively, which includes Millstone 1 recoverable nuclear costs relating to the recoverable portion of the undepreciated plant and related assets ($90.8 million and $145.7 million, respectively) and the decommissioning and closure obligation ($358.4 million and $369 million, respectively). As a result of discontinuing the application of SFAS No. 71 in 2000 for PSNH's generation business, PSNH recorded an after-tax charge of $214.2 million in the fourth quarter of 2000. In addition, a regulatory asset was created for the Seabrook over market generation in the amount of $484.7 million, which is classified as recoverable nuclear costs. It is anticipated this regulatory asset will be securitized. I. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows: - ------------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 - ------------------------------------------------------------------------------- Accelerated depreciation and other plant-related differences $1,364.9 $1,388.0 Regulatory assets - income tax gross-up 189.1 241.2 Other 31.5 58.9 - ------------------------------------------------------------------------------- Totals $1,585.5 $1,688.1 - ------------------------------------------------------------------------------- J. UNRECOVERED CONTRACTUAL OBLIGATIONS Under the terms of contracts with the Yankee Companies, the shareholder- sponsored companies are responsible for their proportionate share of the remaining costs of the units, including decommissioning. As management expects that the NU system companies will be allowed to recover these costs from their customers, the NU system companies have recorded regulatory assets, with corresponding obligations, on their respective balance sheets. K. RECOVERABLE ENERGY COSTS Energy Policy Act of 1992: Under the Energy Policy Act of 1992 (Energy Act), CL&P, PSNH, WMECO, and NAEC are assessed for their proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P, PSNH, WMECO, and NAEC are currently recovering these costs through rates. As of December 31, 2000 and 1999, the NU system's total D&D Assessment deferrals were $34.5 million and $38.4 million, respectively. CL&P: Through December 31, 1999, CL&P had an energy adjustment clause under which fuel prices above or below base-rate levels were charged to or credited to customers. Coincident with the start of restructuring, the energy adjustment clause was terminated. Energy costs deferred and not yet collected under the energy adjustment clause amounted to $61.1 million and $62.6 million at December 31, 2000 and 1999, respectively. This balance is recorded as a generation-related stranded cost and will be recovered through a transition charge mechanism pending final Connecticut Department of Public Utility Control (DPUC) approval. PSNH: The Rate Agreement includes a fuel and purchased-power adjustment clause (FPPAC) permitting PSNH to pass through to retail customers, for a 10-year period that began in May 1991, the retail portion of differences between the fuel and purchased-power costs assumed in the Rate Agreement and PSNH's actual costs, which include the costs related to the Seabrook Power Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are subject to a prudence review by the New Hampshire Public Utilities Commission (NHPUC). At December 31, 2000 and 1999, PSNH had $230.1 million and $120.5 million, respectively, of recoverable energy costs deferred under the FPPAC. Under the Settlement Agreement, the FPPAC will be recovered as a type three regulatory asset through a transition charge. L. CASH AND CASH EQUIVALENTS Cash and cash equivalents includes cash on hand and short-term cash investments which are highly liquid in nature and have original maturities of three months or less. 2. SHORT-TERM DEBT Limits: The amount of short-term borrowings that may be incurred by NU and the NU system operating companies is subject to periodic approval by either the SEC under the 1935 Act or by the respective state regulators. Currently, SEC authorization allows NU, CL&P, WMECO, and Yankee Gas to incur total short-term borrowings up to a maximum of $400 million, $375 million, $250 million, and $100 million, respectively. In addition, the charters of CL&P and WMECO contain preferred stock provisions restricting the amount of unsecured debt those companies may incur. As of December 31, 2000, CL&P's and WMECO's charters permit CL&P and WMECO to incur $245 million and $94 million, respectively, of additional unsecured debt. PSNH and NAEC are authorized by the NHPUC to incur short-term borrowings up to a maximum of $71.3 million and $260 million, respectively. Credit Agreements: NGC: In March 2000, CL&P and WMECO transferred 1,289 MW of hydroelectric generation assets in Connecticut and Massachusetts to NGC, an affiliated company, for approximately $865.5 million. To finance the transfer, on March 9, 2000, NGC entered into a new short-term credit agreement with a total commitment amount of $865.5 million, collateralized by the generation assets transferred. Under the short-term credit agreement, $435.5 million of the commitment matured on March 14, 2000, and was repaid. This credit agreement, with an original maturity date of December 29, 2000, was extended for a minimum of six months. NGC expects to replace the short-term credit agreement with up to $440 million of permanent financing in the first half of 2001. At December 31, 2000, there were $402.4 million in borrowings under the credit agreement. Yankee Merger: To finance the cash portion of the Yankee merger, on March 1, 2000, NU entered into an unsecured term loan agreement for $266 million. The term loan agreement will expire on February 28, 2001. NU expects to replace this financing with permanent, long-term financing prior to its maturity date. At December 31, 2000, there were $263 million in borrowings under the term loan agreement. CL&P and WMECO: On November 17, 2000, CL&P and WMECO entered into a 364-day revolving credit facility for $350 million, replacing the previous $500 million facility which was to expire on November 17, 2000. CL&P and WMECO may draw up to $200 million and $150 million, respectively, under the facility which, until the nuclear divestiture, is secured by second mortgages on Millstone 2 and 3. Once CL&P and WMECO receive the proceeds from securitization, the $350 million revolving credit facility will be reduced to $250 million, with a $150 million limit for CL&P and a $100 million limit for WMECO. Unless extended, the credit facility will expire on November 16, 2001. At December 31, 2000 and 1999, there were $225 million and $213 million, respectively, in borrowings under these facilities. NAEC: On November 9, 2000, NAEC entered into an unsecured 364-day term credit agreement for $200 million, replacing a $225 million term loan which was to expire on November 9, 2000. The proceeds from the term credit agreement were used to repay the $200 million outstanding under the previous term loan. Additionally, the interest rate swaps and collar related to the previous term loan expired and were not replaced. The term credit agreement also contains two mandatory prepayment provisions; the first is a 50 percent mandatory principal repayment of amounts outstanding to $100 million within two days of the buydown of the Seabrook Power Contracts and the second is 100 percent prepayment within two days of the sale of Seabrook. Any amounts prepaid can not be reborrowed. Unless extended, the term credit agreement will expire on November 8, 2001. At December 31, 2000 and 1999, there were $200 million in borrowings under the credit agreement and previous term loan. NU Parent: To continue to support the working capital needs of NU and its competitive energy subsidiaries, NU replaced its $350 million 364-day unsecured revolving credit facility which was to expire on November 17, 2000, with a 364-day unsecured revolving credit facility on November 17, 2000. This facility provides a total commitment of $400 million which is available subject to two overlapping sub-limits. First, subject to the notional amount of any letters of credit outstanding, amounts up to $300 million are available for advances. Second, subject to the advances outstanding, letters of credit may be issued in notional amounts up to $200 million. Unless extended, this credit facility will expire on November 16, 2001. At December 31, 2000 and 1999, there were $173 million and $65 million, respectively, in borrowings under the new and previous facilities. With regard to credit support, NU had $40 million and $29 million, respectively, in letters of credit issued under the new and previous agreements at December 31, 2000 and 1999. Yankee Gas: Yankee Gas has arranged a $60 million unsecured revolving credit facility. On November 17, 2000, the expiration date of this facility was extended to November 16, 2001. At December 31, 2000, there were $46.6 million in borrowings under this credit facility. NU provides credit assurance in the form of guarantees, letters of credit and other assurances for the financial performance obligations of certain of its competitive energy subsidiaries. NU currently has authorization from the SEC to provide up to $500 million of such assurances. As of December 31, 2000 and 1999, NU had provided approximately $284 million and $190 million, respectively, of such credit assurances. Under the aforementioned credit agreements, the respective borrowers may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service. The weighted average interest rate on the NU system companies' notes payable to banks outstanding on December 31, 2000 and 1999, was 8.85 percent and 7.93 percent, respectively. Maturities of short-term debt obligations were for periods of three months or less. These credit agreements provide that the parties to these agreements must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, common equity ratios, interest coverage ratios, cash flow ratios, and dividend payment restrictions. The parties to the credit agreements currently are and expect to remain in compliance with these covenants. 3. LEASES CL&P and WMECO finance their nuclear fuel for Millstone 2 and their respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement. This capital lease agreement has an expiration date of June 1, 2040. At December 31, 2000 and 1999, the present value of the capital lease obligation to the NBFT was $139.2 million and $157 million, respectively. In connection with the planned nuclear divestiture the NBFT capital lease agreement will be terminated, the nuclear fuel will be transferred to Dominion and the related $180 million Series G Intermediate Term Note Agreement will be extinguished with the divestiture proceeds. CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel consumed in the reactors based on a units-of-production method at rates which reflect estimated kilowatt-hours of energy provided plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, ownership of the nuclear fuel transfers to CL&P and WMECO. The NU system companies also have entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, nuclear control room simulators, and office space. The provisions of these lease agreements generally provide for renewal options. Capital lease rental payments charged to operating expense were $50.1 million in 2000, $20.8 million in 1999 and $31 million in 1998. Interest included in capital lease rental payments was $11.6 million in 2000, $13.7 million in 1999 and $18.3 million in 1998. Operating lease rental payments charged to expense were $10.1 million in 2000, $7.5 million in 1999 and $15.7 million in 1998. Future minimum rental payments, excluding annual nuclear fuel lease payments and executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 2000 are as follows: - ------------------------------------------------------------------------------ (Millions of Dollars) - ------------------------------------------------------------------------------ Year Capital Leases Operating Leases - ------------------------------------------------------------------------------ 2001 $ 4.9 $ 25.0 2002 3.2 20.0 2003 3.2 15.0 2004 3.0 11.5 2005 2.8 9.4 After 2005 27.7 23.2 - ------------------------------------------------------------------------------ Future minimum lease payments 44.8 Less amount representing interest 24.1 104.1 - ------------------------------------------------------------------------------ Present value of future minimum lease payments for other than nuclear fuel 20.7 Present value of future nuclear fuel lease payments 139.2 - ------------------------------------------------------------------------------ Present value of future minimum lease payments $159.9 - ------------------------------------------------------------------------------ 4. EMPLOYEE BENEFITS A. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS The NU system companies, participate in a uniform noncontributory defined benefit retirement plan covering substantially all regular NU system employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. The total pension credit, part of which was credited to utility plant, was $97.9 million in 2000, $33.7 million in 1999 and $44.1 million in 1998. Currently, the NU system companies' policy is to annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code. The NU system companies also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. These benefits are available for employees retiring from the NU system who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. The NU system companies annually fund postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible. Pension and trust assets are invested primarily in domestic and international equity securities and bonds. In December 2000, NU announced the details of a voluntary separation program designed to reduce NU's generation-related support staff in 2001. NU will reflect the program's costs in first quarter 2001 results. The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' funded status: - ------------------------------------------------------------------------------- At December 31, - ------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits - ------------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 2000 1999 - ------------------------------------------------------------------------------- Change in benefit obligation Benefit obligation at beginning of year......... $(1,516.6) $(1,479.2) $(306.8) $(305.2) Yankee merger.................. (66.7) - (26.9) - Service cost................... (41.2) (43.7) (7.6) (7.6) Interest cost.................. (118.5) (106.3) (25.5) (21.8) Employee contribution.......... - - (0.1) - Plan amendment................. - (79.6) - - Actuarial (loss)/gain.......... (39.4) 133.8 (13.6) (1.3) Benefits paid.................. 109.5 78.3 27.5 28.9 Settlements and other.......... 2.0 (19.9) 0.7 0.2 - ------------------------------------------------------------------------------- Benefit obligation at end of year............... $(1,670.9) $(1,516.6) $(352.3) $(306.8) - ------------------------------------------------------------------------------- Change in plan assets Fair value of plan assets at beginning of year......... $ 2,330.2 $ 2,098.0 $ 170.7 $ 151.2 Yankee merger.................. 107.5 - 16.1 - Actual return on plan assets... (8.8) 310.5 8.6 18.7 Employer contribution.......... - - 29.6 29.7 Employee contribution.......... - - 0.1 - Benefits paid.................. (109.5) (78.3) (27.5) (28.9) - ------------------------------------------------------------------------------- Fair value of plan assets at end of year............... $ 2,319.4 $ 2,330.2 $ 197.6 $ 170.7 - ------------------------------------------------------------------------------- Funded status at December 31... $ 648.5 $ 813.6 $(154.7) $(136.1) Unrecognized transition (asset)/obligation........... (5.8) (7.4) 180.9 196.6 Unrecognized prior service cost................. 90.9 99.2 - - Unrecognized net gain.......... (594.1) (904.7) (35.5) (60.4) - ------------------------------------------------------------------------------- Prepaid/(accrued) benefit cost. $ 139.5 $ 0.7 $ (9.3) $ 0.1 - ------------------------------------------------------------------------------- The following actuarial assumptions were used in calculating the plans' year end funded status: - ------------------------------------------------------------------------------- At December 31, - ------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits - ------------------------------------------------------------------------------- 2000 1999 2000 1999 - ------------------------------------------------------------------------------- Discount rate..................... 7.50% 7.75% 7.50% 7.75% Compensation/progression rate..... 4.50 4.75 4.50 4.75 Health care cost trend rate (a)... N/A N/A 5.26 5.57 - ------------------------------------------------------------------------------- (a) The annual per capita cost of covered health care benefits was assumed to decrease to 4.91 percent by 2001. The components of net periodic benefit (credit)/cost are: - ------------------------------------------------------------------------------- For the Years Ended December 31, - ------------------------------------------------------------------------------- Postretirement Pension Benefits Benefits - ------------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 1998 2000 1999 1998 - ------------------------------------------------------------------------------- Service cost......... $ 41.2 $ 43.7 $ 37.4 $ 7.6 $ 7.6 $ 6.6 Interest cost........ 118.5 106.3 96.8 25.5 21.8 20.9 Expected return on plan assets..... (205.1) (175.5) (153.2) (15.3) (11.7) (9.9) Amortization of unrecognized net transition (asset)/ obligation......... (1.4) (1.5) (1.5) 15.1 15.1 15.1 Amortization of prior service cost....... 7.9 7.9 2.1 - - - Amortization of actuarial gain..... (52.4) (33.5) (25.7) - - - Other amortization, net................ - - - (4.3) (3.1) (3.8) Settlements and other.............. (6.6) 18.9 - - - - - ------------------------------------------------------------------------------- Net periodic benefit (credit)/cost....... $(97.9) $(33.7) $(44.1) $28.6 $29.7 $28.9 - ------------------------------------------------------------------------------- For calculating pension and postretirement benefit costs, the following assumptions were used: - ------------------------------------------------------------------------------- For the Years Ended December 31, - ------------------------------------------------------------------------------- Postretirement Pension Benefits Benefits - ------------------------------------------------------------------------------- 2000 1999 1998 2000 1999 1998 - ------------------------------------------------------------------------------- Discount rate........ 7.75% 7.00% 7.25% 7.75% 7.00% 7.25% Expected long-term rate of return..... 9.50 9.50 9.50 N/A N/A N/A Compensation/ progression rate.... 4.75 4.25 4.25 4.75 4.25 4.25 Long-term rate of return - Health assets, net of tax....... N/A N/A N/A 7.50 7.50 7.75 Life assets........ N/A N/A N/A 9.50 9.50 9.50 - ------------------------------------------------------------------------------- Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects: - ------------------------------------------------------------------------------- One Percentage One Percentage (Millions of Dollars) Point Increase Point Decrease - ------------------------------------------------------------------------------- Effect on total service and interest cost components $ 1.6 $ (1.6) Effect on postretirement benefit obligation $17.9 $(16.6) - ------------------------------------------------------------------------------- The trust holding the health plan assets is subject to federal income taxes. B. 401(k) SAVINGS PLAN NU maintains a 401(k) Savings Plan for substantially all NU system employees. This savings plan provides for employee contributions up to specified limits. NU matches employee contributions up to a maximum of 3 percent of eligible compensation with cash and NU stock. The matching contributions made by NU were $13.6 million in 2000, $13.8 million in 1999 and $13.2 million in 1998. C. ESOP NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating shares to employees participating in the NU system's 401(k) Savings Plan. Under this arrangement, NU issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of which were lent to the ESOP trust for the purchase of 10.8 million newly issued NU common shares (ESOP Shares). The ESOP trust is obligated to make principal and interest payments on the ESOP notes at the same rate that ESOP Shares are allocated to employees. NU makes annual contributions to the ESOP equal to the ESOP's debt service, less dividends received by the ESOP. All dividends received by the ESOP on unallocated shares are used to pay debt service and are not considered dividends for financial reporting purposes. During the fourth quarter of 1999 through December 31, 2000, NU paid a 10 cent per share quarterly dividend. In 2000 and 1999, the ESOP trust issued 572,863 and 556,978 of NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to employees. As of December 31, 2000 and 1999, the total allocated ESOP shares were 5,854,699 and 5,281,836, respectively, and total unallocated ESOP shares were 4,945,486 and 5,518,349, respectively. The fair market value of unallocated ESOP shares as of December 31, 2000 and 1999, was $119.9 million and $113.5 million, respectively. D. STOCK-BASED COMPENSATION Employee Stock Purchase Plan (ESPP): Since July 1998, the NU system maintained an ESPP for all eligible employees. Under the ESPP, shares of NU common stock were purchased at 6-month intervals at 85 percent of the lower of the price on the first or last day of each 6-month period. Employees purchased shares having a value not exceeding 25 percent of their compensation at the beginning of the purchase period. During 2000 and 1999, employees purchased 199,520 and 253,853 shares, respectively, at discounted prices ranging from $17.48 to $18.49 in 2000, and $13.76 to $14.93 per share in 1999. At December 31, 2000 and 1999, 1,417,156 and 1,616,676 shares remained reserved for future issuance under the ESPP, respectively. Effective January 1, 2001, the ESPP was terminated. Incentive Plans: The NU system has long-term incentive plans authorizing various types of share-based awards, including stock options, to be made to eligible employees and board members. The exercise price of stock options, as set at the time of grant, is generally equal to the fair market value per share at the date of grant. Under the Northeast Utilities Incentive Plan (Incentive Plan), the number of shares which may be utilized for awards granted during a given calendar year may not exceed one percent of the total number of shares of NU common stock outstanding as of the first day of that calendar year. Stock option transactions for 1998, 1999 and 2000, including those options acquired in connection with the Yankee merger, are as follows: - ------------------------------------------------------------------------------- Exercise Price Per Share ------------------------ Options Range Weighted ------- ----- Average - ------------------------------------------------------------------------------- Outstanding December 31, 1997 500,000 $ 9.6250 $ 9.6250 Granted 741,273 $14.8750 - $16.8125 $16.1780 Forfeited (7,595) $16.3125 $16.3125 - ------------------------------------------------------------------------------- Outstanding December 31, 1998 1,233,678 $ 9.6250 - $16.8125 $13.5213 Granted 644,123 $14.9375 - $21.1250 $15.2514 Exercised (19,368) $16.3125 - $16.8125 $16.3986 Forfeited (32,177) $14.9375 - $16.3125 $15.8714 - ------------------------------------------------------------------------------- Outstanding December 31, 1999 1,826,256 $ 9.6250 - $21.1250 $14.0585 Granted 669,470 $18.4375 - $22.2500 $18.7029 Yankee merger 10,167 $ 9.3640 - $12.6888 $10.7653 Exercised (43,750) $14.9375 - $19.5000 $16.0658 Forfeited (28,281) $14.9375 - $19.5000 $16.6515 - ------------------------------------------------------------------------------- Outstanding December 31, 2000 2,433,862 $ 9.3640 - $22.2500 $15.2569 - ------------------------------------------------------------------------------- Exercisable December 31, 1998 232,936 $14.8750 - $16.8125 $16.2972 Exercisable December 31, 1999 711,787 $ 9.6250 - $21.1250 $14.0102 Exercisable December 31, 2000 1,298,339 $ 9.3640 - $22.2500 $14.2021 - ------------------------------------------------------------------------------- The vesting schedule for the options granted in 1998 is one-third upon grant, two-thirds after one year and the total award after two years. For the options that were granted in 1999 and for certain options that were granted in 2000, the vesting schedule for these options is ratably over three years from the date of grant. Other options granted in 2000 vest 50 percent at the date of grant and 50 percent one year from the date of grant. Also under the Incentive Plan, the NU system awarded 91,120 of restricted shares in 1999. These shares have the same vesting schedule as the options granted under the Incentive Plan. The NU system has also made several small grants of restricted stock and other incentive-based stock compensation. During 2000, 1999 and 1998, $1.9 million, $2.2 million and $0.8 million, respectively, was expensed for stock-based compensation. Had compensation cost been determined for the ESPP and the incentive plan stock options under the fair value method as opposed to the intrinsic value method followed by the NU system, net (loss)/income and net (loss)/income per share would have been as follows: - ------------------------------------------------------------------------------- (Millions of Dollars, except per share amounts) 2000 1999 1998 - ------------------------------------------------------------------------------- Net (loss)/income $(33.9) $29.6 $(149.1) Basic (loss)/income per common share $(0.24) $0.23 $ (1.14) Diluted (loss)/income per common share $(0.24) $0.22 $ (1.14) - ------------------------------------------------------------------------------- The fair value of each stock option grant has been estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions: - ------------------------------------------------------------------------------- 2000 1999 1998 - ------------------------------------------------------------------------------- Risk-free interest rate 6.56% 5.69% 5.82% Expected life 10 years 10 years 10 years Expected volatility 26.15% 36.21% 35.05% Expected dividend yield 1.82% 1.89% 5.46% - ------------------------------------------------------------------------------- The weighted average grant date fair values of options granted during 2000, 1999 and 1998 were $7.50, $6.79 and $3.98, respectively. As of December 31, 2000 and 1999, the weighted average remaining contractual lives for those options outstanding are 7.92 years and 8.47 years, respectively. 5. SALE OF CUSTOMER RECEIVABLES As of December 31, 2000 and 1999, CL&P had sold accounts receivable of $170 million to a third-party purchaser with limited recourse through the CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. In addition, at December 31, 2000 and 1999, $18.9 million and $22.5 million, respectively, of accounts receivable were designated as collateral under the agreement with the CRC. Concentrations of credit risk to the purchaser under the company's agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. 6. COMMITMENTS AND CONTINGENCIES A. RESTRUCTURING Connecticut: The 1999 restructuring orders allowed for securitization of CL&P's nonnuclear regulatory assets and the costs to buyout or buydown the various purchased-power contracts. On November 8, 2000, the DPUC approved CL&P's request to securitize an amount not to exceed $1.55 billion of approved, eligible stranded costs, primarily related to above-market purchased-power contracts and generation related regulatory assets. However, the Office of Consumer Counsel (OCC) appealed the securitization order to the Connecticut Superior Court and it remains unclear when securitization financing can be undertaken. New Hampshire: In September 2000, the NHPUC approved a comprehensive restructuring order that would allow PSNH to securitize up to $670 million of stranded costs. In January 2001, the New Hampshire Supreme Court upheld this restructuring order on appeal. However, one of the appellants indicated publicly it would request a review of the New Hampshire Supreme Court decision by the United States Supreme Court. Such a request must be filed by May 1, 2001. Management believes that such an appeal would have a low probability of success, but cannot determine what effect it might have on the timing of the issuance of securitization bonds and the implementation of customer choice in New Hampshire. PSNH currently expects to work with the State of New Hampshire to issue securitization bonds early in the second quarter of 2001. In October 2000, NU reached an agreement with an unaffiliated joint owner, who owns approximately 15 percent of Seabrook, to auction its share of the plant with NU's share. As part of the agreement, if the unaffiliated joint owner's share of Seabrook sells for less than $87.2 million, NU will provide up to $17.4 million to compensate for any shortfall. NU also will share in the benefits if that share of Seabrook exceeds $87.2 million. Additionally, under the agreement, NU will top-off certain decommissioning obligations above a defined level. Massachusetts: A settlement has been reached with the Massachusetts Attorney General finalizing a $155 million securitization plan. WMECO expects to receive approval of its securitization plan in February 2001. B. NUCLEAR GENERATION ASSETS DIVESTITURE On August 7, 2000, CL&P, WMECO and certain other joint owners reached an agreement to sell substantially all of the Millstone units, located in Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including approximately $105 million for nuclear fuel. Dominion has also agreed to assume responsibility for decommissioning the three units and NU will transfer to Dominion all funds in the Millstone decommissioning trust. Additionally, NU is obligated to top-off the decommissioning trust if its value does not equal a previously agreed upon level as defined. NU expects to close on the sale of Millstone as early as the end of March 2001. If the transaction is consummated as proposed, CL&P and WMECO would receive gross proceeds of approximately $843.2 million and $196.2 million on a pretax basis for their respective ownership interests. The proceeds from the sale of these interests will be used to reduce the companies' stranded costs under restructuring and the cash proceeds will be used to repay subsidiary debt and capital lease obligations and to return equity capital to the parent company. The DPUC approved the recovery of Millstone-related stranded costs not offset by asset divestiture proceeds. Pursuant to the DPUC order, CL&P will seek recovery of Millstone post-1997 capital additions totaling $50 million. The OCC has appealed CL&P's ability to recover these costs. PSNH will receive $26 million on a pretax basis, which will be reflected as a gain in accordance with the Settlement Agreement. In connection with the prior settlement of Millstone 3 joint owner claims, if the aforementioned transaction is consummated as proposed, the NU system will record a pretax gain in excess of $150 million. These settlements included clauses which allowed NU to retain sale proceeds for the joint owners interests in the units in excess of certain agreed upon amounts. By the end of 2002, PSNH expects to complete the sale of its fossil and hydroelectric generation assets, as well as NAEC's ownership share of Seabrook. CL&P intends to sell its interest in Seabrook, when NAEC sells theirs. C. ENVIRONMENTAL MATTERS The NU system is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of our environment. As such, the NU system has an active environmental auditing and training program and believes it is substantially in compliance with the current laws and regulations. However, the normal course of operations may involve activities and substances that expose the NU system to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on the NU system's financial statements. Based upon currently available information for the estimated remediation costs as of December 31, 2000 and 1999, including Yankee in 2000, the liability recorded by the NU system for its estimated environmental remediation costs amounted to $58.2 million and $24.8 million, respectively. D. SPENT NUCLEAR FUEL DISPOSAL COSTS Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. As of December 31, 2000 and 1999, fees due to the DOE for the disposal of Prior Period Fuel were $240.3 million and $226.5 million, respectively, including interest costs of $158.2 million and $144.3 million, respectively. Fees for nuclear fuel burned on or after April 7, 1983, are billed currently to customers and paid to the DOE on a quarterly basis. NU is responsible for fees to be paid for fuel burned until the divestiture of the Millstone and Seabrook nuclear units. E. NUCLEAR INSURANCE CONTINGENCIES Insurance policies covering the NU system's nuclear facilities have been purchased for the primary cost of repair, replacement or decontamination of utility property, certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement or decontamination or premature decommissioning of utility property. The NU system is subject to retroactive assessments if losses under those policies exceed the accumulated funds available to the insurer. The maximum potential assessments with respect to losses arising during the current policy year for the primary property insurance program, the replacement power policies and the excess property damage policies are $8.2 million, $4.1 million and $10.2 million, respectively. In addition, insurance has been purchased in the aggregate amount of $200 million on an industry basis for coverage of worker claims. Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third-party liability indemnification program, the NU system could be assessed liabilities in proportion to its ownership interest in each of its nuclear units up to $83.9 million. The NU system's payment of this assessment would be limited to, in proportion to its ownership interest in each of its nuclear units, $10 million in any one year per nuclear unit. In addition, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection, the NU system would be subject to an additional 5 percent, or $4.2 million, liability, in proportion to its ownership interests in each of its nuclear units. Based upon its ownership interests in the Millstone units and in Seabrook, the NU system's maximum liability, including any additional assessments, would be $271 million per incident, of which payments would be limited to $30.8 million per year. In addition, through purchased-power contracts with VYNPC, the NU system would be responsible for up to an additional assessment of $14.1 million per incident, of which payments would be limited to $1.6 million per year. NU expects to terminate its nuclear insurance upon the divestiture of its nuclear units. F. LONG-TERM CONTRACTUAL ARRANGEMENTS Yankee Companies: Under the terms of their agreements, the NU system companies paid their ownership (or entitlement) shares of costs, which included depreciation, operation and maintenance (O&M) expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs were recorded as purchased-power expenses. The total cost of purchases under contracts with VYNPC amounted to $24.9 million in 2000, $29.2 million in 1999 and $27.3 million in 1998. VYNPC is in the process of selling its nuclear unit. Upon completion of the sale, these long-term contracts will be terminated. Nonutility Generators (NUGs): CL&P, PSNH and WMECO have entered into various arrangements for the purchase of capacity and energy from NUGs. The total cost of purchases under these arrangements amounted to $482.1 million in 2000, $461.8 million in 1999 and $459.7 million in 1998. The companies are in the process of renegotiating the terms of these contracts through either a contract buydown or buyout. The companies expect any payments to the NUGs as result of these renegotiations to be recovered from the companies' customers. Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO, and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO, and HWP are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual O&M expenses and capital costs of those facilities. Estimated Annual Costs: The estimated annual costs of the NU system's significant long-term contractual arrangements, absent the effects of any contract terminations, buydowns or buyouts are as follows: - ------------------------------------------------------------------------------ 2001 2002 2003 2004 2005 - ------------------------------------------------------------------------------ (Millions of Dollars) VYNPC............. $ 28.5 $ 28.9 $ 29.1 $ 32.0 $ 30.1 NUGs.............. 480.2 489.2 500.6 487.3 496.8 Hydro-Quebec...... 27.9 27.0 26.0 25.0 24.1 - ------------------------------------------------------------------------------ Select Energy: Select Energy maintains long-term agreements to purchase energy in the normal course of business as part of its portfolio of resources to meet its actual or expected sales commitments. The aggregate amount of these purchase contracts was $1.94 billion at December 31, 2000. These contracts extend through 2004 as follows: - ------------------------------------------------------------------------------- (Millions of Dollars) - ------------------------------------------------------------------------------- Year - ------------------------------------------------------------------------------- 2001 $1,418.3 2002 266.2 2003 228.5 2004 28.0 - ------------------------------------------------------------------------------- Total $1,941.0 - ------------------------------------------------------------------------------- 7. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS Millstone and Seabrook: The NU system operating nuclear power plants, Millstone 2 and 3 and Seabrook, have service lives that are expected to end during the years 2015 through 2026, and upon retirement, must be decommissioned. Millstone 1's expected service life was to end in 2010, however, in July 1998, restart activities were discontinued and decommissioning of the unit began. In connection with the sale of the Millstone units, Dominion has agreed to assume responsibility for decommissioning. Until the divestiture, CL&P, PSNH and WMECO recover sufficient amounts through their allowed rates related to decommissioning costs. The estimated cost of decommissioning Millstone 2, in year end 2000 dollars, is $430.6 million. The NU system's ownership share of the estimated cost of decommissioning Millstone 3 and Seabrook, in year end 2000 dollars, is $440.8 million and $234.6 million, respectively. Nuclear decommissioning costs are accrued over the expected service lives of the units and are included in depreciation expense and the accumulated provision for depreciation. Nuclear decommissioning expenses for these units amounted to $35.5 million in 2000, $30.6 million in 1999 and $27.9 million in 1998. Nuclear decommissioning expenses for Millstone 1 were $23.1 million in 2000, $25.7 million in 1999 and $19.8 million in 1998. Through December 31, 2000 and 1999, total decommissioning expenses of $304.4 million and $260.6 million, respectively, have been collected from customers and are reflected in the accumulated provision for depreciation. External decommissioning trusts have been established for the costs of decommissioning the Millstone units. Payments for the NU system's ownership share of the cost of decommissioning Seabrook are paid to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assumes after-tax earnings on the Millstone and Seabrook decommissioning funds of 5.5 percent and 6.5 percent, respectively. As of December 31, 2000 and 1999, $278.5 million and $239.7 million, respectively, have been transferred to external decommissioning trusts. Earnings on the decommissioning trusts increase the decommissioning trust balances and the accumulated provisions for depreciation. Unrealized gains and losses associated with the decommissioning trusts also impact the balance of the trusts and the accumulated provisions for depreciation. The fair values of the amounts in the external decommissioning trusts were $450.8 million and $410.2 million at December 31, 2000 and 1999, respectively. Upon divestiture, balances in the decommissioning trusts will be transferred to the buyer. NU is obligated to top-off the Millstone decommissioning trust if its value does not equal an agreed upon amount at closing, pursuant to the conditions set forth in the purchase and sale agreement. Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. The NU system's ownership share of estimated costs, in year end 2000 dollars, of decommissioning this unit is $72.3 million. In 1999, VYNPC agreed to sell its nuclear generating unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the obligation to decommission the unit after it is taken out of service, and the owners of VYNPC (including CL&P, WMECO and PSNH) agreed to fund their shares of the decommissioning costs up to a negotiated amount. Subsequent to the time that agreement was executed, the original proposed acquiring company has increased the price it agreed to pay and three other unaffiliated companies have indicated their interest in buying VYNPC's generating unit on terms that have not been disclosed. At present, CL&P, WMECO and PSNH expect that the unit will be sold, but the identity of the owner and the terms of sale, including price, future decommissioning obligations and future power purchase obligations, are not known. As of December 31, 2000 and 1999, NU's remaining estimated obligation, including decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down was $244.6 million and $358.4 million, respectively. 8. MARKET RISK AND RISK MANAGEMENT INSTRUMENTS Competitive Energy Subsidiaries: Select Energy provides both firm requirement energy services to its customers and performs energy trading and marketing activities. Select Energy manages its exposure to risk from existing contractual commitments and provides risk management services to its customers through forward contracts, futures, over-the-counter swap agreements, and options (commodity derivatives). Select Energy has utilized the sensitivity analysis methodology to disclose the quantitative information for the commodity price risks. Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity prices, or other similar price changes. Commodity Price Risk - Trading Activities: As a market participant in the Northeast area of the United States, Select Energy conducts commodity-trading activities in electricity and its related products, oil and natural gas and therefore experiences net open positions. Select Energy manages these open positions with strict policies which limit its exposure to market risk and require daily reporting to management of potential financial exposure. Commodity derivatives utilized for trading purposes are accounted for using the mark-to-market method, under EITF Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities." Under this methodology, these instruments are adjusted to market value, and the unrealized gains and losses are recognized in income in the current period in the consolidated statements of income as operating expenses - other and in the consolidated balance sheets as prepayments and other. The mark-to-market position at December 31, 2000, was a positive $13.8 million. Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity, contract prices and market prices represented by each derivative commodity contract. For swaps, forward contracts and options, market value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are subject to market, based on closing exchange prices. As of December 31, 2000, Select Energy has calculated the market price resulting from a 10 percent unfavorable change in forward market prices. That 10 percent change would result in approximately a $1 million decline in the fair value of the Select Energy trading portfolio. In the normal course of business, Select Energy also faces risks that are either nonfinancial or nonquantifiable. Such risks principally include credit risk, which is not reflected in the sensitivity analysis above. Commodity Price Risk - Nontrading Activities: Select Energy utilizes derivative financial and commodity instruments (derivatives), including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas sold under firm commitments with certain customers. Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts, to manage the market risk associated with a portion of its anticipated supply requirements. Gains or losses on derivatives associated with firm commitments are recognized as adjustments to cost of sales or revenues when the associated transactions affect earnings. Gains and losses on derivatives associated with forecasted transactions are recognized when such forecasted transactions affect earnings. If a derivative instrument is terminated early because it is probable that a transaction or forecasted transaction will not occur, any gain or loss as of such date is immediately recognized in earnings. When conducting sensitivity analysis of the change in the fair value of Select Energy's electricity, oil and natural gas portfolio, which would result from a hypothetical change in the future market price of electricity, oil and natural gas, the fair value of the contracts are determined from models which take into account estimated future market prices of electricity, oil and natural gas, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments. In most instances, market prices and volatility are determined from quoted prices on the futures exchange. Select Energy has determined a hypothetical change in the fair value for its nontrading electricity, natural gas and oil contracts, assuming a 10 percent unfavorable change in forward market prices. As of December 31, 2000, an unfavorable 10 percent change in forward market price would have resulted in a decrease in fair value of approximately $52 million. The impact of a change in electricity, natural gas and oil prices on Select Energy's nontrading contracts on December 31, 2000, is not necessarily representative of the results that will be realized when these contracts go to eventual physical delivery. Select Energy also maintains natural gas service agreements with certain customers to supply gas at fixed prices for terms extending through 2003. Select Energy has hedged its gas supply risk under these agreements through NYMEX contracts. Under these contracts, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements, which extend through 2002. As of December 31, 2000, the NYMEX contracts had a notional value of $18.8 million and a positive mark-to- market position of $14.9 million. Regulated Entities: Interest Rate Risk - Nontrading Activities: The company manages its interest rate risk exposure by maintaining a mix of fixed and variable rate debt. In addition, Yankee has entered into an interest rate sensitive derivative. Yankee uses swap instruments with financial institutions to exchange fixed-rate interest obligations to a blend between fixed and variable-rate obligations without exchanging the underlying notional amounts. These instruments convert fixed interest rate obligations to variable rates. The notional amounts parallel the underlying debt levels and are used to measure interest to be paid or received and do not represent the exposure to credit loss. As of December 31, 2000, Yankee had outstanding agreements with a total notional value of $48 million and a negative mark-to-market position of $0.8 million. For the fair value, see Note 10 for the disclosure of NU's debt. Commodity Price Risk - Nontrading Activities: Yankee Gas maintains a master swap agreement with a certain customer to supply gas at fixed prices for a 10-year term extending through 2005. Under this master swap agreement, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreement, which extends through 2005. As of December 31, 2000, the commodity swap agreement had a notional value of $17.1 million and a positive mark-to-market position of $5.4 million. 9. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY CL&P Capital LP (CL&P LP), a subsidiary of CL&P, previously had issued $100 million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS), Series A. CL&P has the sole ownership in CL&P LP, as a general partner, and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million capital contribution, back to CL&P in the form of an unsecured debenture. CL&P consolidates CL&P LP for financial reporting purposes. Upon consolidation, the unsecured debenture is eliminated, and the MIPS securities are accounted for as a minority interest. 10. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and cash equivalents: The carrying amounts approximate fair value due to the short-term nature of cash and cash equivalents. Supplemental Executive Retirement Plan (SERP) Investments: Investments held for the benefit of the SERP are recorded at fair market value. The investments having a cost basis of $6.5 million and $5.8 million held for benefit of the SERP were recorded at their fair market values at December 31, 2000 and 1999, of $10.1 million and $9.2 million, respectively. Nuclear decommissioning trusts: The investments held in the NU system companies' nuclear decommissioning trusts were marked-to-market by $117.6 million as of December 31, 2000, and $129 million as of December 31, 1999, with corresponding offsets to the accumulated provision for depreciation. The amounts adjusted in 2000 and in 1999 represent cumulative net unrealized gains. Cumulative gross unrealized holding losses were immaterial for both 2000 and 1999. Preferred stock and long-term debt: The fair value of the NU system's fixed- rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of the NU system's financial instruments and the estimated fair values are as follows: - ------------------------------------------------------------------------------- At December 31, 2000 - ------------------------------------------------------------------------------- Carrying Fair (Millions of Dollars) Amount Value - ------------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption............... $ 136.2 $ 159.9 Preferred stock subject to mandatory redemption............... 40.8 42.0 Long-term debt - First mortgage bonds............... 1,008.1 1,012.5 Other long-term debt............... 1,342.2 1,290.6 MIPS.................................. 100.0 100.5 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- At December 31, 1999 - ------------------------------------------------------------------------------- Carrying Fair (Millions of Dollars) Amount Value - ------------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption............... $ 136.2 $ 164.0 Preferred stock subject to mandatory redemption............... 167.5 166.8 Long-term debt - First mortgage bonds............... 1,193.2 1,209.5 Other long-term debt............... 1,638.3 1,593.1 MIPS.................................. 100.0 97.3 - ------------------------------------------------------------------------------- 11. OTHER COMPREHENSIVE INCOME The accumulated balance for each other comprehensive income item is as follows: - ------------------------------------------------------------------------------- Current December 31, Period December 31, (Thousands of Dollars) 1999 Change 2000 - ------------------------------------------------------------------------------- Foreign currency translation adjustments....................... $ - $ - $ - Unrealized gains on securities...... 2,137 245 2,382 Minimum pension liability adjustments....................... (613) - (613) - ------------------------------------------------------------------------------- Accumulated other comprehensive income............ $1,524 $245 $1,769 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- Current December 31, Period December 31, (Thousands of Dollars) 1998 Change 1999 - ------------------------------------------------------------------------------- Foreign currency translation adjustments....................... $ (1) $ 1 $ - Unrealized gains on securities...... 2,019 118 2,137 Minimum pension liability adjustments....................... (613) - (613) - ------------------------------------------------------------------------------- Accumulated other comprehensive income............ $1,405 $119 $1,524 - ------------------------------------------------------------------------------- The changes in the components of other comprehensive income are reported net of the following income tax effects: - ------------------------------------------------------------------------------- (Thousands of Dollars) 2000 1999 1998 - ------------------------------------------------------------------------------- Foreign currency translation adjustments $ - $ - $ - Unrealized gains on securities (147) (71) (1,222) Minimum pension liability adjustments - - 398 - ------------------------------------------------------------------------------- Other comprehensive income $(147) $(71) $ (824) - ------------------------------------------------------------------------------- 12. EARNINGS PER SHARE Earnings per share (EPS) is computed based upon the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock. The following table sets forth the components of basic and diluted EPS: - ------------------------------------------------------------------------------- (Millions of Dollars, except share information) 2000 1999 1998 - ------------------------------------------------------------------------------- Income/(loss) after interest charges $219.5 $57.0 $ (120.4) Preferred dividends of subsidiaries 14.2 22.8 26.4 - ------------------------------------------------------------------------------- Income/(loss) before extraordinary loss 205.3 34.2 (146.8) Extraordinary loss, net of tax benefit (233.9) - - - ------------------------------------------------------------------------------- Net (loss)/income $(28.6) $34.2 $(146.8) - ------------------------------------------------------------------------------- Basic EPS common shares outstanding (average) 141,549,860 131,415,126 130,549,760 Dilutive effect of employee stock options 417,356 616,447 - (a) - ------------------------------------------------------------------------------- Diluted EPS common shares outstanding (average) 141,967,216 132,031,573 130,549,760 - ------------------------------------------------------------------------------- Basic earnings/(loss) per common share: Income/(loss) before extraordinary loss $ 1.45 $0.26 $(1.12) Extraordinary loss, net of tax benefit (1.65) - - - ------------------------------------------------------------------------------- Net (loss)/income $(0.20) $0.26 $(1.12) - ------------------------------------------------------------------------------- Diluted earnings/(loss) per common share: Income/(loss) before extraordinary loss $ 1.45 $0.26 $(1.12) Extraordinary loss, net of tax benefit (1.65) - - - ------------------------------------------------------------------------------- Net (loss)/income $(0.20) $0.26 $(1.12) - ------------------------------------------------------------------------------- (a) The addition of dilutive potential common shares would be anti-dilutive for 1998 and was not included. 13. MODE 1 On November 23, 1999, NEON Communications, Inc. (NEON) entered into agreements with two unaffiliated companies. Under the terms of the agreements, NEON will provide network transport and carrier services in its service areas and that of the two unaffiliated companies and each company will provide connectivity from the backbone system to their respective local loops. Additionally, each company will manage their local distribution into their respective end-users' locations. NEON will also develop, operate and market the combined telecommunications infrastructure created under the two agreements. As the agreements are implemented, the two unaffiliated companies will ultimately obtain a total of approximately 4.6 million shares of NEON common stock, or approximately 12 percent and 10 percent ownership interests, respectively. Each unaffiliated company will also nominate one member to the NEON Board of Directors. Prior to the implementation of these agreements, Mode 1 had approximately a 29 percent ownership interest in the common shares of NEON. In conjunction with the consummation of the agreements on September 14, 2000, a portion of the total common shares to be issued were issued to the two unaffiliated companies. The remainder of these shares will be issued as the two unaffiliated companies complete certain milestones, as defined in their respective agreements. The issuance of these shares had the effect of decreasing Mode 1's ownership interest in NEON's outstanding common shares to approximately 25 percent. However, these shares were issued at an amount greater than Mode 1's investment, resulting in a $19.8 million pretax increase to Mode 1's equity. NU's accounting policy is to recognize the gain or loss from this type of change in ownership interest in net income. 14. SEGMENT INFORMATION The NU system is organized between regulated utilities (electric and gas for the 12 months and 10 months, respectively, ended December 31, 2000, and electric only for the year ended December 31, 1999) and competitive energy subsidiaries. The regulated utilities segment represents approximately 85 percent and 86 percent of the NU system's total revenues for the year ended December 31, 2000 and 1999, respectively, and is comprised of several business units. Regulated utilities revenues primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The competitive energy subsidiaries segment has two major customers, one unaffiliated company and CL&P. Their purchases represented approximately 15 percent and 34 percent, respectively, of total competitive energy subsidiaries' revenues for the year ended December 31, 2000. Purchases from the unaffiliated company represented approximately 43 percent of total competitive energy subsidiaries' revenues for the year ended December 31, 1999. There were no purchases from CL&P in 1999. The competitive energy subsidiaries segment in the following table includes HEC, a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional electric companies and electric utility companies; HWP, a company engaged in the production and distribution of electric power; NGC, a corporation that acquires and manages generation facilities; NGS, a corporation that maintains and services any fossil or hydroelectric facility that is acquired or contracted with for fossil or hydroelectric generation services, and; Select Energy, a corporation engaged in the marketing, transportation, storage, and sale of energy commodities, at wholesale, in designated geographical areas and in the marketing of electricity to retail customers. Other in the following table includes the results for Mode 1, an investor in a fiber-optic communications network. Mode 1 had earnings of $3.8 million and a net loss of $4.3 million for years ended December 31, 2000 and 1999, respectively. See Note 13 for further information related to Mode 1's earnings for the year ended December 31, 2000. Other also includes the results of the nonenergy related subsidiaries of Yankee. Interest expense included in Other primarily relates to the debt of NU parent. Inter-segment eliminations of revenues and expenses are also included in Other. - -------------------------------------------------------------------------------------------- For the Year Ended December 31, 2000 - -------------------------------------------------------------------------------------------- Regulated Utilities Competitive Eliminations (Millions of ------------------- Energy and Dollars) Electric Gas Subsidiaries Other Total - -------------------------------------------------------------------------------------------- Operating revenues $4,738.5 $251.2 $1,894.9 $(1,008.0) $ 5,876.6 Operating expenses (4,311.3) (233.7) (1,831.7) 964.9 (5,411.8) - -------------------------------------------------------------------------------------------- Operating income/(loss) 427.2 17.5 63.2 (43.1) 464.8 Other income/(loss) 48.2 (4.1) (3.1) 13.0 54.0 Interest expense (191.9) (12.2) (53.4) (41.8) (299.3) Preferred dividends (14.2) - - - (14.2) - -------------------------------------------------------------------------------------------- Income/(loss) before extraordinary loss 269.3 1.2 6.7 (71.9) 205.3 Extraordinary loss, net of tax benefit (214.2) - (19.7) - (233.9) - -------------------------------------------------------------------------------------------- Net income/(loss) $ 55.1 $ 1.2 $ (13.0) $ (71.9) $ (28.6) - -------------------------------------------------------------------------------------------- Total assets $9,620.0 $912.6 $ 684.1 $ (999.6) $10,217.1 - --------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------- For the Year Ended December 31, 1999 - ------------------------------------------------------------------------------- Regulated Competitive Eliminations Electric Energy and (Millions of Dollars) Utilities Subsidiaries Other Total - ------------------------------------------------------------------------------- Operating revenues $3,846.1 $648.8 $(23.7) $4,471.2 Operating expenses (3,454.3) (688.2) 15.8 (4,126.7) - ------------------------------------------------------------------------------- Operating income/(loss) 391.8 (39.4) (7.9) 344.5 Other (loss)/income (43.2) 5.6 13.7 (23.9) Interest expense (245.5) (3.2) (14.9) (263.6) Preferred dividends (22.8) - - (22.8) - ------------------------------------------------------------------------------- Net income/(loss) $ 80.3 $(37.0) $ (9.1) $ 34.2 - ------------------------------------------------------------------------------- Total assets $9,302.6 $308.2 $ 77.3 $9,688.1 - ------------------------------------------------------------------------------- 15. SUBSEQUENT EVENTS A. MERGER AGREEMENT WITH CONSOLIDATED EDISON, INC. In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the approvals needed to complete the merger announced in October 1999. Shareholders from both companies approved the merger in April 2000, and all state regulatory approvals were granted by the end of the year. Additionally, the FERC approved the merger in May 2000, the Nuclear Regulatory Commission approved the transaction in August 2000, and the United States Department of Justice approved the merger in February 2001. Necessary approval from the SEC was expected to be received in mid-March 2001. On February 28, 2001, NU's Board of Trustees requested that Con Edison provide reasonable assurance, in writing, that it intended to comply with the terms of the definitive merger agreement between the two companies. This included assurances that Con Edison would consummate the pending merger at the price set forth in the agreement promptly following the receipt of SEC approval. The original request for assurance was to be received by March 2, 2001, however that date was later extended to March 5, 2001. On March 5, 2001, Con Edison advised NU that it was not willing to close the merger on the agreed terms. NU notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that NU would file suit to obtain the benefits of the transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District of New York (Southern District), seeking declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement. On March 12, 2001, NU filed suit against Con Edison in the Southern District seeking damages in excess of $1 billion arising from Con Edison's breach of the merger agreement. Under the terms of the proposed transaction, had it proceeded to closing, NU shareholders would have received a base price of $25 per share, in a combination of cash and Con Edison common stock, plus $0.0034 per share per day, or approximately $0.10 per share per month, for each day that the merger did not close after August 5, 2000. Additionally, NU shareholders would have received another $1 per share as a result of a recommendation by the DPUC's Utility Operations Management Analysis Unit that the DPUC accept the results of the Millstone auction that were announced on August 7, 2000. The DPUC approved the sale in January 2001. The $25 per share base price, the $0.0034 per share per day compensation and the additional $1 per share resulting from the Millstone auction would have been subject to the collar mechanism described in the merger proxy statement dated February 29, 2000, to the extent NU shareholders received Con Edison stock. Assuming that Con Edison's stock price had averaged between $36 and $46 per share during the applicable pricing period, as defined, NU shareholders would have received approximately $26.84 per share, were the merger to have closed on April 10, 2001. B. FERC DECISION On March 6, 2001, the FERC issued an order on rehearing related to the price for installed capacity (ICAP) in New England. The FERC reinstituted the previously approved $8.75 per kilowatt-month charge for installed capacity, but made the price effective April 1, 2001. In an earlier decision in December 2000, the FERC had made the charge effective as of August 1, 2000, but in its revised decision, the FERC substituted a $0.17 per kilowatt-month charge for the period of August 2000 through March 2001. Because NU was a major seller of installed generating capacity during the last five months of 2000, the FERC's revised decision with respect to the August through March time period reduced NU's fourth quarter revenues by $24.6 million and lowered earnings by $14.8 million, or $0.10 per share. Although it is important that FERC understood the going forward need for a capacity charge that approximates the cost of installing new generation in New England, management currently plans on requesting that FERC review the inconsistency of their decision with regard to the change in the effective date of the $8.75 charge. CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarter Ended (a) (b) --------------------- (Thousands of Dollars, except per share information) March 31 June 30 September 30 December 31 -------- ------- ------------ ----------- 2000 Operating Revenues $1,382,321 $1,414,973 $1,581,947 $1,497,379 Operating Income $ 135,409 $ 99,092 $ 115,761 $ 114,501 Income Before Extraordinary Loss $ 74,587 $ 12,206 $ 65,543 $ 52,959 Extraordinary Loss, Net of Tax Benefit - - - (233,881) ---------- ---------- ---------- ---------- Net Income/(Loss) $ 74,587 $ 12,206 $ 65,543 $ (180,922) ========== ========== ========== ========== Basic Earnings/(Loss) Per Common Share: Income Before Extraordinary Loss $ 0.55 $ 0.09 $ 0.46 $ 0.37 Extraordinary Loss, Net of Tax Benefit $ - $ - $ - $ (1.63) ---------- ---------- ---------- ---------- Net Income/(Loss) $ 0.55 $ 0.09 $ 0.46 $ (1.26) ========== ========== ========== ========== Diluted Earnings/(Loss) Per Common Share: Income Before Extraordinary Loss $ 0.55 $ 0.08 $ 0.45 $ 0.37 Extraordinary Loss, Net of Tax Benefit $ - $ - $ - $ (1.63) ---------- ---------- ---------- ---------- Net Income/(Loss) $ 0.55 $ 0.08 $ 0.45 $ (1.26) ========== ========== ========== ========== 1999 Operating Revenues $1,043,407 $1,038,569 $1,240,539 $1,148,736 Operating Income $ 89,638 $ 56,492 $ 110,544 $ 87,863 Net Income/(Loss) $ 18,444 $ 228 $ 31,218 $ (15,674) Basic and Diluted Earnings/(Loss) Per Common Share $ 0.14 $ - $ 0.24 $ (0.12)
(a) Certain reclassifications of prior years' data have been made to conform with the current year's presentation. (b) Summation of quarterly data may not equal annual data due to rounding. CONSOLIDATED GENERATION STATISTICS (UNAUDITED)
Source of Electric Energy: (kWh-millions) 2000 1999 1998 1997 1996 ------ ------ ------ ------ ------ Nuclear - Steam (a) 16,306 13,558 5,679 3,778 9,405 Fossil - Steam 5,584 10,959 12,505 13,155 9,188 Hydro - Conventional 686 1,206 1,510 1,260 1,544 Hydro - Pumped Storage 240 944 819 959 1,217 Internal Combustion 7 262 80 184 206 Energy Used for Pumping (343) (1,318) (1,130) (1,327) (1,668) ------ ------ ------ ------ ------ Net Generation 22,480 25,611 19,463 18,009 19,892 Purchased and Net Interchange 56,280 43,849 24,945 24,377 22,111 Company Use and Unaccounted For (3,100) (2,612) (2,566) (2,802) (2,473) ------ ------ ------ ------ ------ Net Energy Sold 75,660 66,848 41,842 39,584 39,530 ====== ====== ====== ====== ======
(a) Includes the NU system's entitlements in regional nuclear generating companies, net of capacity sales and purchases. SELECTED CONSOLIDATED FINANCIAL DATA (UNAUDITED)
(Thousands of Dollars, except percentages and share information) 2000 1999 1998 1997 1996 ----------- ----------- ----------- ----------- ----------- Balance Sheet Data: Net Utility Plant $ 3,547,215 $ 3,947,434 $ 6,170,881 $ 6,463,158 $ 6,732,165 Total Assets 10,217,149 9,688,052 10,387,381 10,414,412 10,741,748 Total Capitalization (a) 4,739,417 5,216,456 6,030,402 6,472,504 6,659,617 Obligations Under Capital Leases (a) 159,879 181,293 209,279 207,731 206,165 Income Data: Operating Revenues $ 5,876,620 $ 4,471,251 $ 3,767,714 $ 3,834,806 $ 3,792,148 Income/(Loss) Before Extraordinary Loss $ 205,295 $ 34,216 $ (146,753) $ (129,962) $ 38,929 Extraordinary Loss, Net of Tax Benefit (233,881) - - - - ----------- ----------- ----------- ----------- ----------- Net (Loss)/Income $ (28,586) $ 34,216 $ (146,753) $ (129,962) $ 38,929 =========== =========== =========== =========== =========== Common Share Data: Basic and Diluted Earnings/(Loss) Per Common Share: Income/(Loss) Before Extraordinary Loss $ 1.45 $ 0.26 $(1.12) $(1.01) $ 0.30 Extraordinary Loss, Net of Tax Benefit (1.65) - - - - ------ ------ ------ ------ ------ Net (Loss)/Income $(0.20) $ 0.26 $(1.12) $(1.01) $ 0.30 ====== ====== ====== ====== ====== Basic Common Shares Outstanding (Average) 141,549,860 131,415,216 130,549,760 129,567,708 127,960,382 Fully Diluted Common Shares Outstanding (Average) 141,967,216 132,031,573 130,549,760 129,567,708 128,073,261 Dividends Per Share $ 0.40 $ 0.10 $ - $ 0.25 $ 1.38 Market Price - Closing (high) $24.25 $22.00 $17.25 $14.25 $25.25 Market Price - Closing (low) $18.25 $13.56 $11.69 $ 7.63 $ 9.50 Market Price - Closing (end of year) $24.25 $20.56 $16.00 $11.81 $13.13 Book Value Per Share (end of year) $15.43 $15.80 $15.63 $16.67 $18.02 Rate of Return Earned on Average Common Equity (%) (1.3) 1.6 (7.0) (5.8) 1.6 Market-to-Book Ratio (end of year) 1.6 1.3 1.0 0.7 0.7 Capitalization: Common Shareholders' Equity 47% 40% 34% 34% 35% Preferred Stock (a) (b) 4 5 5 6 6 Long-Term Debt (a) 49 55 61 60 59 ------- ------- ------- ------- ------- 100% 100% 100% 100% 100% ======= ======= ======= ======= =======
(a) Includes portions due within one year. (b) Excludes $100 million of MIPS. CONSOLIDATED ELECTRIC SALES STATISTICS (UNAUDITED)
2000 1999 1998 1997 1996 ---------- ---------- ---------- ---------- ---------- Revenues: (Thousands) Residential $1,469,439 $1,517,913 $1,475,363 $1,499,394 $1,501,465 Commercial 1,256,126 1,272,969 1,273,146 1,266,449 1,246,822 Industrial 566,625 560,801 568,913 560,782 565,900 Other Utilities 1,884,082 926,056 336,623 329,764 315,577 Streetlighting and Railroads 45,998 45,564 47,682 48,867 48,053 Non-Franchised Sales 16,932 24,659 22,479 21,476 8,360 Miscellaneous 96,666 52,357 16,429 47,446 23,513 ---------- ---------- ---------- ---------- ---------- Total Electric 5,335,868 4,400,319 3,740,635 3,774,178 3,709,690 Gas 461,716 - - - - Other 79,036 70,932 27,079 60,628 82,458 ---------- ---------- ---------- ---------- ---------- Total $5,876,620 $4,471,251 $3,767,714 $3,834,806 $3,792,148 ========== ========== ========== ========== ========== Sales: (kWh - Millions) Residential 12,940 12,912 12,162 12,099 12,241 Commercial 13,023 12,850 12,477 12,091 12,012 Industrial 7,130 7,050 6,948 6,801 6,820 Other Utilities 42,127 33,575 9,742 8,034 8,032 Streetlighting and Railroads 333 314 320 318 319 Non-Franchised Sales 107 147 193 241 50 ---------- ---------- ---------- ---------- ---------- Total 75,660 66,848 41,842 39,584 39,474 ========== ========== ========== ========== ========== Customers: (average) Residential 1,576,068 1,569,932 1,555,013 1,535,134 1,532,015 Commercial 166,114 164,932 162,500 159,350 157,347 Industrial 7,701 7,721 7,847 7,804 7,792 Other 3,917 3,908 3,890 3,929 3,916 ---------- ---------- ---------- ---------- ---------- Total Electric 1,753,800 1,746,493 1,729,250 1,706,217 1,701,070 Gas 187,000 - - - - ---------- ---------- ---------- ---------- ---------- Total 1,940,800 1,746,493 1,729,250 1,706,217 1,701,070 ========== ========== ========== ========== ========== Average Annual Use Per Residential Customer (kWh) 8,233 8,243 7,799 7,898 8,005 ========== ========== ========== ========== ========== Average Annual Bill Per Residential Customer $ 934.94 $ 969.38 $ 946.80 $ 978.72 $ 980.19 ========== ========== ========== ========== ========== Average Revenue per kWh: Residential 11.36 cents 11.76 cents 12.14 cents 12.39 cents 12.27 cents Commercial 9.65 9.91 10.20 10.47 10.38 Industrial 7.95 7.95 8.19 8.25 8.30
EX-4.1.5 2 0002.txt EXHIBIT 4.1.5 EXECUTION COPY TERM LOAN AGREEMENT Dated as of March 1, 2000 Among NORTHEAST UTILITIES as Borrower THE BANKS NAMED HEREIN FLEET NATIONAL BANK as Syndication Agent THE BANK OF NEW YORK as Documentation Agent and CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY as Administrative Agent TABLE OF CONTENTS Page ARTICLE I DEFINITIONS AND ACCOUNTING TERMS SECTION 1.01. Certain Defined Terms 1 SECTION 1.02. Computation of Time Periods 14 SECTION 1.03. Accounting Terms; Financial Statements 14 SECTION 1.04. Computations of Outstandings 14 ARTICLE II COMMITMENTS SECTION 2.01. The Commitments 15 SECTION 2.02. Fees 15 ARTICLE III CONTRACT ADVANCES SECTION 3.01. Contract Advances 15 SECTION 3.02. Terms Relating to the Making of Contract Advances 15 SECTION 3.03. Making of Advances 16 SECTION 3.04. Repayment of Advances 16 SECTION 3.05. Interest 17 i TABLE OF CONTENTS (continued) Page ARTICLE IV PAYMENTS SECTION 4.01. Payments and Computations 19 SECTION 4.02. Prepayments 20 SECTION 4.03. Yield Protection 21 SECTION 4.04. Sharing of Payments, Etc. 24 SECTION 4.05. Taxes 25 ARTICLE V CONDITIONS PRECEDENT SECTION 5.01. Conditions Precedent to Effectiveness 26 SECTION 5.02. Conditions Precedent to Advances on Funding Date. 28 SECTION 5.03. Reliance on Certificates 29 ARTICLE VI REPRESENTATIONS AND WARRANTIES SECTION 6.01. Representations and Warranties of the Borrower 29 ARTICLE VII COVENANTS SECTION 7.01. Affirmative Covenants 33 SECTION 7.02. Negative Covenants 36 SECTION 7.03. Financial Covenants 41 SECTION 7.04. Reporting Obligations 41 ii TABLE OF CONTENTS (continued) Page ARTICLE VIII DEFAULTS SECTION 8.01. Events of Default 44 SECTION 8.02. Remedies Upon Events of Default 46 ARTICLE IX THE ADMINISTRATIVE AGENT SECTION 9.01. Authorization and Action 46 SECTION 9.02. Administrative Agent's Reliance, Etc. 47 SECTION 9.03. CIBC and its Affiliates. 47 SECTION 9.04. Lender Credit Decision 48 SECTION 9.05. Indemnification 48 SECTION 9.06. Successor Administrative Agent 48 SECTION 9.07. Other Agents 49 ARTICLE X MISCELLANEOUS SECTION 10.01. Amendments, Etc. 49 SECTION 10.02. Notices, Etc. 49 SECTION 10.03. No Waiver of Remedies 50 SECTION 10.04. Costs, Expenses and Indemnification 50 SECTION 10.05. Right of Set-off 51 SECTION 10.06. Binding Effect 52 SECTION 10.07. Assignments and Participation 52 SECTION 10.08. Confidentiality 55 SECTION 10.09. Waiver of Jury Trial 55 SECTION 10.10. Governing Law 55 SECTION 10.11. Relation of the Parties; No Beneficiary 56 SECTION 10.12. Execution in Counterparts 56 SECTION 10.13. Limitation of Liability 56 iii TABLE OF CONTENTS (continued) Page SCHEDULES Schedule I - Applicable Lending Offices Schedule II - Pending Actions EXHIBITS Exhibit 1.01A - Form of Contract Note Exhibit 3.01 - Form of Notice of Contract Borrowing Exhibit 5.01A - Form of Opinion of Day, Berry and Howard, Counsel to the Borrower Exhibit 5.01B - Form of Opinion of Jeffrey C. Miller, Assistant General Counsel of NUSCO Exhibit 5.01C - Form of Opinion of King and Spalding, Special New York Counsel to the Administrative Agent Exhibit 10.07 - Form of Lender Assignment iv TERM LOAN AGREEMENT Dated as of March 1, 2000 THIS TERM LOAN AGREEMENT is made by and among: (i) Northeast Utilities, an unincorporated voluntary business association organized under the laws of the Commonwealth of Massachusetts ("NU" or the "Borrower"); (ii) The financial institutions (the "Banks") listed on the signature pages hereof and the other Lenders (as hereinafter defined) from time to time party hereto; (iii) Fleet National Bank, as Syndication Agent hereunder; (iv) The Bank of New York, as Documentation Agent hereunder; and (v) Canadian Imperial Bank of Commerce, a Canadian chartered bank ("CIBC") acting through its New York Agency, as Administrative Agent for the Lenders hereunder. PRELIMINARY STATEMENT The Borrower has requested the Banks to provide the credit facility hereinafter described in the amounts and on the terms and conditions set forth herein. The Banks have so agreed on the terms and conditions set forth herein, and the Administrative Agent has agreed to act as agent for the Lenders on such terms and conditions. Based upon the foregoing and subject to the terms and conditions set forth in this Agreement, the parties hereto hereby agree as follows: ARTICLE I DEFINITIONS AND ACCOUNTING TERMS SECTION 1.01. CERTAIN DEFINED TERMS. As used in this Agreement, the following terms shall have the following meanings (such meanings to be applicable to the singular and plural forms of the terms defined): "ADMINISTRATIVE AGENT" means CIBC, in its capacity as administrative agent hereunder, or any successor thereto as provided herein. "ADVANCE" means a Contract Advance. "AFFILIATE" means, with respect to any Person, any other Person directly or indirectly controlling (including, but not limited to, all directors and officers of such Person), controlled by, or under direct or indirect common control with such Person. A Person shall be deemed to control another entity if such Person possesses, directly or indirectly, the power to direct or cause the direction of the management and policies of such entity, whether through the ownership of voting securities, by contract or otherwise. "AGREEMENT" means this Term Loan Agreement, as the same may be modified, amended and/or supplemented pursuant to the terms hereof. "APPLICABLE LENDING OFFICE" means, with respect to each Lender: (i) in the case of any Contract Advance, (A) such Lender's "Eurodollar Lending Office" in the case of a Eurodollar Rate Advance or (B) such Lender's "Domestic Lending Office" in the case of a Base Rate Advance, in each case as specified opposite such Lender's name on Schedule I hereto or in the Lender Assignment pursuant to which it became a Lender; or (ii) in each case, such other office of such Lender as such Lender may from time to time specify in writing to the Borrower and the Administrative Agent. "APPLICABLE MARGIN" means, for any day during the relevant period indicated below for any outstanding Contract Advance, the percentage per annum set forth below in effect on such day during such period, determined on the basis of the Applicable Rating Level for the Borrower: APPLICABLE MARGIN (PERCENTAGE %) APPLICABLE EURODOLLAR BASE RATE RATING LEVEL RATE ADVANCES ADVANCES FUNDING FUNDING DATE 8-1-00 11-1-00 AND DATE 8-1-00 11-1-00 AND 7-31-00 10-31-00 7-31-00 10-31-00 THEREAFTER THEREAFTER 2 Level I 2.00 1.375 1.625 1.00 .375 .625 Level II 2.00 1.625 1.875 1.00 .625 .875 Level III 2.00 1.875 2.125 1.00 .875 1.125 Level IV 2.00 2.125 2.375 1.00 1.12 1.375 Level V 2.00 2.375 2.625 1.00 1.375 1.625 Level VI 2.00 2.625 2.875 1.00 1.625 1.875 Any change in the Applicable Margin caused by a change in the Applicable Rating Level shall take effect at the time such change in the Applicable Rating Level shall occur. "APPLICABLE RATE" means, with respect to any Advance made to the Borrower, either of (i) the Base Rate from time to time applicable to such Advance plus the Applicable Margin, or (ii) the Eurodollar Rate from time to time applicable to such Advance plus the Applicable Margin. "APPLICABLE RATING LEVEL" shall be determined at any time and from time to time on the basis of the ratings assigned by S and P and Moody's to the senior, unsecured, non-credit enhanced long-term Debt of the Borrower (the "RATED DEBT") in accordance with the following: APPLICABLE RATING LEVEL S & P MOODY'S Level I BBB+ or higher Baa3 or higher Level II BBB Ba1 Level III BBB- Ba2 Level IV BB+ Ba3 Level V BB B1 Level VI BB- or lower B2 or lower In the event that the rating assigned by S and P to the Rated Debt and the rating assigned by Moody's to the Rated Debt do not correspond to the same Applicable Rating Level, then the lower of the two ratings shall determine the Applicable Rating Level. The Applicable Rating Level shall be redetermined as and when any change in the ratings used in the determination thereof shall be announced by S and P or Moody's, as the case may be. If either Moody's or S and P shall cease to issue or maintain a rating on the Rated Debt, then the Applicable Rating Level shall be Level VI. "BANKS" has the meaning assigned to that term in the caption to this Agreement. "BASE RATE" means, for any period, a fluctuating interest rate per annum as shall be in effect from time to time which rate per annum shall at all times be equal to the higher of: (a) the rate of interest announced publicly by CIBC in its principal place of business in the United States from time to time as CIBC's base rate for loans made in United States Dollars; and (b) half of one percent per annum above the Federal Funds Rate in effect from time to time. 3 If the Administrative Agent shall have determined (which determination shall be conclusive absent manifest error) that it is unable to ascertain the Federal Funds Rate for any reason, including the inability or failure of the Administrative Agent to obtain sufficient quotations in accordance with the terms thereof, the Base Rate shall be determined without regard to clause (b) of the first sentence of this definition until the circumstances giving rise to such inability no longer exist. Any change in the Base Rate due to a change in the Administrative Agent's base rate or the Federal Funds Rate shall be effective on the effective date of such change in the Administrative Agent's base rate or the Federal Funds Rate, respectively. "BASE RATE ADVANCE" means a Contract Advance in respect of which the Borrower has selected in accordance with Article III hereof, or this Agreement provides for, interest to be computed on the basis of the Base Rate. "BORROWER" has the meaning assigned to that term in the caption to this Agreement. "BORROWING" means a Contract Borrowing. "BUSINESS DAY" means a day of the year on which banks are not required or authorized to close in New York City and, if the applicable Business Day relates to any Eurodollar Rate Advances, on which dealings are carried on in the London interbank market. "CHANGE OF CONTROL" means (a) any Person or "group" (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended), other than Consolidated Edison, Inc., shall either (1) acquire beneficial ownership of more than 50 percent of any outstanding class of common stock of NU having ordinary voting power in the election of directors of NU or (2) obtain the power (whether or not exercised) to elect a majority of NU's directors or (b) except as a result of the acquisition of NU by Consolidated Edison, Inc., the Board of Directors of NU shall not consist of a majority of Continuing Directors. For purposes of this definition, the term "Continuing Directors" means directors of NU on the Closing Date and each other director of NU, if such other director's nomination for election to the Board of Directors of NU is recommended by a majority of the then Continuing Directors. "CIBC" means Canadian Imperial Bank of Commerce, a Canadian chartered bank, acting through its New York Agency. "CL & P" means The Connecticut Light and Power Company, a corporation organized under the laws of the State of Connecticut. "CL & P INDENTURE" has the meaning assigned to that term in Section 7.02(a)(ii) hereof. "CLOSING DATE" has the meaning assigned to that term in Section 5.01 hereof. "COMMITMENT" means, for each Lender, the aggregate amount set forth opposite such Lender's name on the signature pages hereof or, if such Lender has entered into one or more Lender Assignments, set forth for such Lender in the Register maintained by the Administrative Agent pursuant to Section 10.07(c). "COMMITMENTS" shall refer to the aggregate of the Lenders' Commitments hereunder. "COMMITMENT FEE" has the meaning assigned to that term in Section 2.02(a) hereof. 4 "COMMON EQUITY" means, at any date for the Borrower, an amount equal to the sum of the aggregate of the par value of, or stated capital represented by, the outstanding common shares of the Borrower and its Subsidiaries and the surplus, paid-in, earned and other capital, if any, of the Borrower and its Subsidiaries, in each case as determined on a consolidated basis in accordance with generally accepted accounting principles. "CONFIDENTIAL INFORMATION" has the meaning assigned to that term in Section 10.08 hereof. "CONSOLIDATED INTEREST EXPENSE" means, for any period, the aggregate amount of any interest required to be paid during such period by the Borrower and its Subsidiaries on Debt (including the current portion thereof) (as determined on a consolidated basis in accordance with generally accepted accounting principles), excluding interest required to be paid on the stranded cost recovery bonds of any Subsidiary of the Borrower. "CONSOLIDATED OPERATING INCOME" means, for any period (as determined on a consolidated basis in accordance with generally accepted accounting principles), the Borrower's and its Subsidiaries' operating income for such period, adjusted as follows: (i) increased by the amount of income taxes accrued less the amount of income taxes paid by the Borrower and its Subsidiaries during such period, if and to the extent deducted in the computation of the Borrower's and/or its Subsidiaries' consolidated operating income for such period; (ii) increased by the amount of any depreciation and amortization deducted in the computation of the Borrower's and/or its Subsidiaries' consolidated operating income for such period; (iii) decreased by the amount of any capital expenditures paid by the Borrower and/or its Subsidiaries to the extent not deducted in the computation of the Borrower's and its Subsidiaries' consolidated operating income for such period; (iv) decreased by the amount of revenues accrued by the Borrower and/or its Subsidiaries related to the interest and principal on stranded cost recovery bonds issued by Subsidiaries of the Borrower, and increased by the amount of operating expenses accrued by the Borrower and/or its Subsidiaries related to the interest and principal on stranded cost recovery bonds issued by Subsidiaries of the Borrower, in each case to the extent included in the computation of the Borrower's and/or its Subsidiaries' consolidated operating income for such period; (v) decreased by the proceeds of stranded cost recovery bonds issued by Subsidiaries of the Borrower to the extent included in the computation of the Borrower's and/or its Subsidiaries' consolidated operating income for such period; and 5 (vi) decreased by the proceeds (including Extraordinary Proceeds of the Borrower and/or its Subsidiaries) of asset sales done outside the ordinary course of business to the extent included in the computation of the Borrower's and/or its Subsidiaries' consolidated operating income for such period; and (vii) increased or decreased, as the case may be, by the amount of income taxes paid or refunded on gains or losses related to the sale of assets or purchased power contracts done outside the ordinary course of business to the extent included in the computation of the Borrower's and/or its Subsidiaries consolidated operating income for such period. "CONTRACT ADVANCE" means an advance by a Lender to the Borrower pursuant to Article III hereof, and refers to a Eurodollar Rate Advance or a Base Rate Advance (each of which shall be a "TYPE" of Contract Advance). For purposes of this Agreement, all Contract Advances of a Lender (or portions thereof) of the same Type and Interest Period, if any, made or converted on the same day to the Borrower shall be deemed to be a single Advance by such Lender until repaid. "CONTRACT BORROWING" means a borrowing consisting of one or more Contract Advances of the same Type and Interest Period, if any, made, continued or converted on the same Business Day. A Contract Borrowing may be referred to herein as being a "TYPE" of Contract Borrowing, corresponding to the Type of Contract Advances comprising such Borrowing, whether such Advances were made on the Funding Date or were continued or converted as Advances of a certain Type and for a certain Interest Period. For purposes of this Agreement, all Contract Advances of the same Type and Interest Period, if any, made, continued or converted on the same day to the Borrower shall be deemed a single Contract Borrowing hereunder until repaid. "CONTRACT NOTE" means a promissory note of the Borrower payable to the order of a Lender, in substantially the form of Exhibit 1.01A hereto, evidencing the aggregate indebtedness of the Borrower to such Lender resulting from the Contract Advances made by such Lender to the Borrower. "DEBT" means, for any Person, without duplication, (i) indebtedness of such Person for borrowed money, including but not limited to obligations of such Person evidenced by bonds, debentures, notes or other similar instruments (excluding stranded cost recovery bonds which are non-recourse to such Person), (ii) obligations of such Person to pay the deferred purchase price of property or services (excluding any obligation of such Person to the United States Department of Energy or its successor with respect to disposition of spent nuclear fuel burned prior to April 3, 1983), (iii) obligations of such Person as lessee under leases which shall have been or should be, in accordance with generally accepted accounting principles, recorded as capital leases, (iv) obligations under direct or indirect guaranties in respect of, and obligations (contingent or otherwise) to purchase or otherwise acquire, or otherwise to assure a creditor against loss in respect of, indebtedness or obligations of others of the kinds referred to in clauses (i) through (iii), above, including 6 all Parent Support Obligations, (v) letters of credit, guaranties and other forms of credit enhancement issued to support power sales and trading activities, and (vi) liabilities in respect of unfunded vested benefits under ERISA Plans. "DISCLOSURE DOCUMENTS" means for the Borrower and each Principal Subsidiary: (i) such Person's Annual Report on Form 10-K for the fiscal year ended December 31, 1998; (ii) its Quarterly Reports on Form 10-Q for the fiscal quarters ended March 31, June 30, and September 30, 1999; and (iii) each Current Report on Form 8-K of such Person filed after September 30, 1999 and on or prior to February 29, 2000. "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time. "ERISA AFFILIATE" means, with respect to any Person, any trade or business (whether or not incorporated) which is a "commonly controlled entity" of such Person within the meaning of the regulations under Section 414 of the Internal Revenue Code of 1986, as amended from time to time. "ERISA MULTIEMPLOYER PLAN" means a "multiemployer plan" subject to Title IV of ERISA. "ERISA PLAN" means an employee benefit plan (other than a ERISA Multiemployer Plan) maintained for employees of the Borrower or any ERISA Affiliate of the Borrower and covered by Title IV of ERISA. "ERISA PLAN TERMINATION EVENT" means (i) a Reportable Event described in Section 4043 of ERISA and the regulations issued thereunder (other than a Reportable Event not subject to the provision for 30-day notice to the PBGC under such regulations) with respect to an ERISA Plan or an ERISA Multiemployer Plan, or (ii) the withdrawal of the Borrower or any of its ERISA Affiliates from an ERISA Plan or an ERISA Multiemployer Plan during a plan year in which it was a "substantial employer" as defined in Section 4001(a)(2) of ERISA, or (iii) the filing of a notice of intent to terminate an ERISA Plan or an ERISA Multiemployer Plan or the treatment of an ERISA Plan or an ERISA Multiemployer Plan under Section 4041 of ERISA, or (iv) the institution of proceedings to terminate an ERISA Plan or an ERISA Multiemployer Plan by the PBGC, or (v) any other event or condition which might constitute grounds under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any ERISA Plan or ERISA Multiemployer Plan. "EUROCURRENCY LIABILITIES" has the meaning assigned to that term in Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time. "EURODOLLAR RATE" means, for each Interest Period for each Eurodollar Rate Advance comprising part of the same Borrowing, an interest rate per annum equal to (i) the rate for deposits in U.S. Dollars for a period equal to such Interest Period appearing on Page 3750 of the Telerate Service at approximately 11:00 a.m. (London time) two 7 Business Days before the first day of such Interest Period, or (ii) if for any reason such rate is not available, the average (rounded upward to the nearest whole multiple of 1 dash 16 of 1 percent per annum, if such average is not such a multiple) of the rates per annum at which deposits in U.S. dollars are offered by the principal office of each of the Reference Banks in London, England to prime banks in the London inter-bank market at 11:00 a.m. (London time) two Business Days before the first day of such Interest Period in the amount of 1,000,000 dollars and for a period equal to such Interest Period. If determined pursuant to clause (ii), above, the Eurodollar Rate for the Interest Period for each Eurodollar Rate Advance comprising part of the same Borrowing shall be determined by the Administrative Agent on the basis of applicable rates furnished to and received by the Administrative Agent from the Reference Banks two Business Days before the first day of such Interest Period, subject, however, to the provisions of Sections 3.05(d) and 4.03(g). "EURODOLLAR RATE ADVANCE" means a Contract Advance in respect of which the Borrower has selected in accordance with Article III hereof, or this Agreement provides for, interest to be computed on the basis of the Eurodollar Rate. "EURODOLLAR RESERVE PERCENTAGE" of any Lender or its subparticipant, for each Interest Period for each Eurodollar Rate Advance, means the reserve percentage applicable during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during which any such percentage shall be so applicable) under Regulation D or other regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, without limitation, any emergency, supplemental or other marginal reserve requirement, without benefit of or credit for proration, exemptions or offsets) for such Lender or its subparticipant with respect to liabilities or assets consisting of or including Eurocurrency Liabilities having a term equal to such Interest Period. "EVENT OF DEFAULT" has the meaning specified in Section 8.01 hereof. "EXTRAORDINARY PROCEEDS" shall mean, for any Person for any period, net proceeds received by such Person during such period from (i) issuances of securitization bonds sold by such Person or any of its Subsidiaries plus (ii) sales of assets by such Person or any of its Subsidiaries not in the ordinary course of business plus (iii) the sale or disposition (by way of merger, sale of capital stock, sale of assets or otherwise) of any Subsidiary of such Person. For purposes of the foregoing, all cash received by such Person from, or as a result of the sale or disposition of, a Subsidiary shall be deemed to constitute "Extraordinary Proceeds" up to the amount of proceeds received by, or as a result of the sale or disposition of, such Subsidiary from such issuances and sales during the relevant period, net of underwriting discounts and commissions, costs of sale and other, similar transaction costs. "FEDERAL FUNDS RATE" means, for any period, a fluctuating interest rate per annum equal to, for each day during such period, the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by 8 Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day which is a Business Day, the average of the quotations for such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it. "FEE LETTER" means that certain Fee Letter dated February 18, 2000 between NU and CIBC. "FERC" means the Federal Energy Regulatory Commission. "FINANCIAL STATEMENTS" means, with respect to the Borrower and each Principal Subsidiary, (i) the audited consolidated balance sheet of such Person as at December 31, 1998, (ii) the unaudited consolidated balance sheet of such Person as at September 30, 1999, (iii) the audited consolidated statements of income and cash flows of such Person for the Fiscal Year ended December 31, 1998 and (iv) the unaudited consolidated statements of income and cash flows of such Person for the 9-month period ended September 30, 1999, in each case as included in such Person's Annual Report on Form 10-K for the Fiscal Year ended December 31, 1998 or Quarterly Report on Form 10-Q for the Fiscal Quarter ended September 30, 1999. "FIRST MORTGAGE BONDS" means any bond, however designated, entitled to the benefits of a First Mortgage Indenture. "FIRST MORTGAGE INDENTURE" means, with respect to CL and P, the CL and P Indenture or any successor thereto or replacement thereof; and with respect to WMECO, the WMECO Indenture or any successor thereto or replacement thereof. "FISCAL QUARTER" means a period of three calendar months ending on the last day of March, June, September or December, as the case may be. "FISCAL YEAR" means a period of twelve calendar months ending on the last day of December. "FIXED CHARGES" shall mean, for any period, the sum of the following amounts: (a) dividends paid by NU to common and preferred stockholders during such period; (b) interest expense for NU for such period; and (c) income taxes paid by NU during such period. "FUNDING DATE" has the meaning assigned to that term in Section 2.01 hereof. "GOVERNMENTAL APPROVAL" means any authorization, consent, approval, license, permit, certificate, exemption of, or filing or registration with, any governmental authority or other legal or regulatory body (including, without limitation, the Securities and Exchange Commission, the FERC, the Nuclear Regulatory Commission, the Connecticut Department of Public Utility Control and the Massachusetts Department of Telecommunications and Energy, required in connection with either (i) the execution, 9 delivery or performance of any Loan Document, (ii) the nature of the Borrower's or any Subsidiary's business as conducted or the nature of the property owned or leased by it or (iii) the acquisition by the Borrower of YES. "HAZARDOUS SUBSTANCE" means any waste, substance or material identified as hazardous, dangerous or toxic by any office, agency, department, commission, board, bureau or instrumentality of the United States of America or of the State or locality in which the same is located having or exercising jurisdiction over such waste, substance or material. "HWP" means Holyoke Water Power Company, a corporation organized under the laws of the Commonwealth of Massachusetts. "INDEMNIFIED PERSON" has the meaning assigned to that term in Section 10.04(b) hereof. "INTEREST PERIOD" has the meaning assigned to that term in Section 3.05(a) hereof. "LENDER ASSIGNMENT" means an assignment and acceptance entered into by a Lender and an assignee, and accepted by the Administrative Agent, in substantially the form of Exhibit 10.07 hereto. "LENDERS" means the financial institutions listed on the signature pages hereof, and each assignee that shall become a party hereto pursuant to Section 10.07. "LIEN" means, with respect to any asset or property, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset or property. For the purposes of this Agreement, a Person or any of its Subsidiaries shall be deemed to own subject to a Lien any asset which it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such asset. "LOAN DOCUMENTS" means this Agreement and the Notes. "MAJORITY LENDERS" means on any date of determination, Lenders who, collectively, on such date (i) have Percentages in the aggregate of at least 66-2/3 percent and (ii) if the Advances shall have been made on the Funding Date, hold at least 66-2/3 percent of the then aggregate Outstanding Credits of the Lenders. Determination of those Lenders satisfying the criteria specified above for action by the Majority Lenders shall be made by the Administrative Agent and shall be conclusive and binding on all parties absent manifest error. "MOODY'S" means Moody's Investors Service, Inc., or any successor thereto. "NAEC" means North Atlantic Energy Corporation, a corporation organized under the laws of the State of New Hampshire. 10 "NAMED DEBT" means Debt of HWP under (i) the Reimbursement and Security Agreement (1988 Series), dated as of November 3, 1999, between HWP and The Toronto-Dominion Bank and (ii) the Reimbursement and Security Agreement (1990 Series), dated as of November 3, 1999, between HWP and The Toronto-Dominion Bank. "NGC EQUITY CONTRIBUTION" shall mean the proposed equity investment by the Borrower of up to $475,000,000 in Northeast Generation Company. "NOTE" means a Contract Note, as may be amended, supplemented or otherwise modified from time to time. "NOTICE OF CONTRACT BORROWING" has the meaning assigned to that term in Section 3.01 hereof. "NU" has the meaning assigned to that term in the caption to this Agreement. "NU SYSTEM MONEY POOL" means the money pool described in the application/declaration, as amended, of NU and certain of its Subsidiaries, filed with the Securities and Exchange Commission in File No. 70-8875, as amended from time to time. "NUSCO" means Northeast Utilities Service Company, a Connecticut corporation. "OPERATING CASH FLOW" shall mean, for any period, the sum of the following amounts: (1) dividends paid to the Borrower by a Subsidiary thereof during such period; (2) consulting and management fees paid to the Borrower for such period; (3) tax sharing payments made to the Borrower during such period; (4) interest and other distributions paid to the Borrower during such period with respect to cash (e.g., NU System Money Pool) and other permitted investments of the Borrower; and (5) other cash payments made to the Borrower by its Subsidiaries other than (A) returns of invested capital, (B) payments of the principal on Debt of any such Subsidiary to the Borrower (to the extent permitted hereunder) and (C) Extraordinary Proceeds. If at any time there shall exist an event or condition which permits any holder to accelerate the maturity date of any Debt of, or terminate its commitment to extend credit to any Subsidiary, then the contributions of such Subsidiary to Operating Cash Flow for any period ending at or prior to such time shall be eliminated and Operating Cash Flow shall be calculated after giving effect to such elimination. "OUTSTANDING CREDITS" mean, on any date of determination, an amount equal to the aggregate principal amount of all Contract Advances outstanding on such date. The "Outstanding Credits" of a Lender on any date of determination shall be an amount equal to the outstanding Advances made by such Lender. "PARENT SUPPORT OBLIGATION" means, without duplication, any obligation of the Borrower under direct or indirect guaranties in respect of, and obligations (contingent or otherwise) to purchase or otherwise acquire, or otherwise to assure a creditor against loss in respect of, indebtedness or obligations of others of the kinds referred to in clauses (i) 11 through (iii) of the definition of "Debt", including any reimbursement obligation in respect of a letter of credit, any recourse obligation in respect of a surety or similar bond or other, similar obligation of the Borrower other than a construction completion or similar performance guaranty as permitted hereunder issued on behalf of HEC Inc. The amount of each Parent Support Obligation shall be computed in good faith in accordance with the Borrower's then applicable mark-to-market and other risk management methods. "PBGC" means the Pension Benefit Guaranty Corporation (or any successor entity) established under ERISA. "PERCENTAGE" means, in respect of any Lender on any date of determination, the percentage obtained by dividing such Lender's Commitment on such day (or, if the Commitments shall have been terminated, the aggregate principal amount of outstanding Advances held by such Lender on such day) by the total of the Commitments (or outstanding Advances, as applicable) on such day, and multiplying the quotient so obtained by 100%. "PERMITTED INVESTMENTS" means (i) securities issued or directly and fully guaranteed or insured by the United States or any agency or instrumentality thereof (provided that the full faith and credit of the United States is pledged in support thereof) having maturities of not more than six (6) months from the date of acquisition by such Person; (ii) time deposits and certificates of deposit, with maturities of not more than six (6) months from the date of acquisition by such Person, of any international commercial bank of recognized standing having capital and surplus in excess of $500,000,000 and having a rating on its commercial paper of at least A-1 or the equivalent thereof by S&P or at least P-1 or the equivalent thereof by Moody's; (iii) commercial paper issued by any Person, which commercial paper is rated at least A-1 or the equivalent thereof by S&P or at least P-1 or the equivalent thereof by Moody's and matures not more than six (6) months after the date of acquisition by such Person; (iv) investments in money market funds substantially all the assets of which are comprised of securities of the types described in clauses (i) and (ii) above and (v) United States Securities and Exchange Commission registered money market mutual funds conforming to Rule 2a-7 of the Investment Company Act of 1940 in effect in the United States, that invest primarily in direct obligations issued by the United States Treasury and repurchase obligations backed by those obligations, and rated in the highest category by S&P and Moody's. "PERSON" means an individual, partnership, corporation (including a business trust), limited liability company, joint stock company, trust, unincorporated association, joint venture or other entity, or a government or any political subdivision or agency thereof. "PRINCIPAL SUBSIDIARY" shall mean YES, CL&P, WMECO, PSNH, HWP, NAEC, Select Energy, Inc., HEC Inc., Northeast Generation Company, Mode One Communications, Inc., and any other Subsidiary, whether owned directly or indirectly by the Borrower, which, with respect to the Borrower and its Subsidiaries taken as a whole, 12 represents at least ten percent (10%) of such Borrower's consolidated assets or such Borrower's consolidated net income (or loss). "PSNH" means Public Service Company of New Hampshire, a corporation duly organized under the laws of the State of New Hampshire. "RECIPIENT" has the meaning assigned to that term in Section 10.08 hereof. "REFERENCE BANKS" means CIBC, Fleet Bank, N.A. and The Bank of New York, and any other bank or financial institution designated by the Borrower and the Administrative Agent with the approval of the Majority Lenders to act as a Reference Bank hereunder. "REGULATORY ASSET" means, with respect to CL&P or WMECO, an intangible asset established by statute, regulation or regulatory order or similar action of a utility regulatory agency having jurisdiction over CL&P or WMECO, as the case may be, and included in the rate base of CL&P or WMECO, as the case may be, with the intention that such asset be amortized by rates over time. "RESTRICTED PAYMENT" shall mean any dividend, payment or other distribution of assets, properties, cash, rights, obligations or securities on account of any share of any class of capital stock of NU (other than as a result of a stock split and dividends payable solely in equity securities of NU), or the purchase, redemption, retirement or other acquisition for value of any shares of any class of capital stock of NU or any warrants, rights, or options to acquire any such shares, now or hereafter outstanding. "REVOLVING CREDIT AGREEMENT" means the Credit Agreement, dated as of November 19, 1999, among the Borrower, the lenders from time to time parties thereto and Union Bank of California, N.A., as Administrative Agent. "S&P" means Standard and Poor's Ratings Services, a division of The McGraw-Hill Companies, Inc., or any successor thereto. "SUBSIDIARY" shall mean, with respect to any Person (the "PARENT"), any corporation, association or other business entity of which securities or other ownership interests representing 50% or more of the ordinary voting power are, at the time as of which any determination is being made, owned or controlled by the Parent or one or more Subsidiaries of the Parent or by the Parent and one or more Subsidiaries of the Parent. "TERMINATION DATE" means the earliest to occur of (i) February 28, 2001, (ii) the date of termination of the Commitments pursuant to Section 8.02 or (iii) the date of acceleration of all amounts payable hereunder and under the Notes pursuant to Section 8.02. "TOTAL CAPITALIZATION" means, at any date, the sum of (i) the aggregate principal amount of all long-term and short-term Debt (including the current portion thereof) of the Borrower and its Subsidiaries, (ii) the aggregate of the par value of, or stated capital 13 represented by, the outstanding shares of all classes of common and preferred shares of the Borrower and its Subsidiaries and (iii) the consolidated surplus of the Borrower and its Subsidiaries, paid-in, earned and other capital, if any, in each case as determined on a consolidated basis in accordance with generally accepted accounting principles consistent with those applied in the preparation of the Borrower's Financial Statements. "TOTAL COMMITMENT" means $266,000,000, or such lesser amount from time to time as shall equal the sum of the Commitments. "TYPE" has the meaning assigned to such term (i) in the definition of "Contract Advance" when used in such context and (ii) in the definition of "Contract Borrowing" when used in such context. "UNMATURED DEFAULT" means the occurrence and continuance of an event which, with the giving of notice or lapse of time or both, would constitute an Event of Default. "WMECO" means Western Massachusetts Electric Company, a corporation organized under the laws of the Commonwealth of Massachusetts. "WMECO INDENTURE" has the meaning assigned to that term in Section 7.02(a)(iii) hereof. "YEAR 2000 ISSUE" means the failure of computer software, hardware and firmware systems and equipment containing computer chips to properly receive, transmit, process, manipulate, store, retrieve, re-transmit or in any other way utilize data and information due to the occurrence of the year 2000 or the inclusion of dates on or after January 1, 2000. "YES" means Yankee Energy System Inc. SECTION 1.02. COMPUTATION OF TIME PERIODS. In the computation of periods of time under this Agreement, any period of a specified number of days or months shall be computed by including the first day or month occurring during such period and excluding the last such day or month. In the case of a period of time "from" a specified date "to" or "until" a later specified date, the word "from" means "from and including" and the words "to" and "until" each means "to but excluding". SECTION 1.03. ACCOUNTING TERMS; FINANCIAL STATEMENTS. All accounting terms not specifically defined herein shall be construed in accordance with generally accepted accounting principles applied on a basis consistent with the application employed in the preparation of the Financial Statements. All references contained herein to the Borrower's or a Principal Subsidiary's Annual Report on Form 10-K in respect of a Fiscal Year or Quarterly Report on Form 10-Q in respect of a Fiscal Quarter shall be deemed to include any exhibits and schedules thereto, including without limitation in the case of any Annual Report on Form 10-K, any "Annual Report" of the Borrower or such Principal Subsidiary referred to therein. 14 SECTION 1.04. COMPUTATIONS OF OUTSTANDINGS. Whenever reference is made in this Agreement to the principal amount of Outstanding Credits under this Agreement on any date, such reference shall refer to the aggregate principal amount of all Outstanding Credits on such date after giving effect to (i) all Advances to be made on such date and the application of the proceeds thereof and (ii) any repayment or prepayment of Advances on such date by the Borrower. ARTICLE II COMMITMENTS SECTION 2.01. THE COMMITMENTS. Each Lender severally agrees, on the terms and conditions hereinafter set forth, to make a single Advance to the Borrower on any Business Day (the "FUNDING DATE") during the period from the Closing Date until March 15, 2000, in an amount not to exceed such Lender's Commitment. If the Funding Date shall not have occurred on or prior to March 15, 2000, the Commitments shall terminate. SECTION 2.02. FEES. The Borrower agrees to pay to the Administrative Agent for the account of each Bank a commitment fee (the "COMMITMENT FEE") on the amount of such Bank's Commitment at a rate per annum equal to one-half of one percent (0.5%) for the period from the date of this Agreement to (but excluding) the Funding Date or the earlier termination of the Commitments. The Commitment Fee payable by the Borrower shall be calculated and accrued daily and shall be payable on the Funding Date, or, if earlier, the date on which the Commitments are terminated. (b) The Borrower further agrees to pay the fees specified in the Fee Letter to the parties entitled thereto. ARTICLE III CONTRACT ADVANCES SECTION 3.01. CONTRACT ADVANCES. Subject to Section 2.01, more than one Contract Borrowing may be made on the same Business Day. Each Contract Borrowing shall consist of Contract Advances of the same Type and Interest Period made to the Borrower on the Funding Date, or thereafter continued or converted as Advances of the same Type and for the same Interest Period on the same Business Day, by the Lenders ratably according to their respective Commitments. The Contract Borrowing to be made on the Funding Date shall be made on notice in substantially the form of Exhibit 3.01 hereto (the "NOTICE OF CONTRACT BORROWING"), delivered by the Borrower to the Administrative Agent, by hand or facsimile, not later than 11:00 a.m. (New York City time) (i) in the case of Eurodollar Rate Advances, on the third Business Day 15 prior to the Funding Date and (ii) in the case of Base Rate Advances, on the Funding Date. Upon receipt of the Notice of Contract Borrowing, the Administrative Agent shall notify the Lenders thereof promptly on the day so received. The Notice of Contract Borrowing shall specify therein the requested (A) Funding Date, (B) principal amount and Type of Advances comprising such Borrowing and (C) initial Interest Period for such Advances. The Borrowing to be made on the Funding Date shall be subject to the satisfaction of the conditions precedent thereto as set forth in Article V hereof. SECTION 3.02. TERMS RELATING TO THE MAKING OF CONTRACT ADVANCES. (a) Notwithstanding anything in Section 3.01 above to the contrary: (i) at no time shall more than six different Contract Borrowings be outstanding hereunder; and (ii) each Contract Borrowing hereunder which is to be comprised of Base Rate or Eurodollar Rate Advances shall be in an aggregate principal amount of not less than $5,000,000 or an integral multiple of $1,000,000 in excess thereof. (b) The Notice of Borrowing shall be irrevocable and binding on the Borrower. SECTION 3.03. MAKING OF ADVANCES. (a) Each Lender shall, before 1:00 p.m. (New York City time) on the Funding Date, make available for the account of its Applicable Lending Office to the Administrative Agent at the Administrative Agent's address referred to in Section 10.02, in same day funds, such Lender's portion of the Borrowing to be made on such date. Contract Advances shall be made by the Lenders ratably in accordance with their several Commitments. After the Administrative Agent's receipt of such funds and upon fulfillment of the applicable conditions set forth in Article V, the Administrative Agent will make such funds available to the Borrower at the Administrative Agent's aforesaid address. (b) Unless the Administrative Agent shall have received notice from a Lender prior to the time of the Borrowing to be made on the Funding Date that such Lender will not make available to the Administrative Agent such Lender's ratable portion of such Borrowing, the Administrative Agent may assume that such Lender has made such portion available to the Administrative Agent on the Funding Date in accordance with subsection (a) of this Section 3.03, and the Administrative Agent may, in reliance upon such assumption, make available to the Borrower a corresponding amount on such date. If and to the extent that any such Lender (a "NON-PERFORMING LENDER") shall not have so made such ratable portion available to the Administrative Agent, the non-performing Lender and the Borrower severally agree to repay to the Administrative Agent forthwith on demand such corresponding amount together with interest thereon, for each day from the date such amount is made available to the Borrower until the date such amount is repaid to the Administrative Agent, at (i) in the case of the Borrower, the interest rate applicable at the time to Advances comprising such Borrowing and (ii) in the case of such 16 Lender, the Federal Funds Rate. Nothing herein shall in any way limit, waive or otherwise reduce any claims that any party hereto may have against any non-performing Lender. (c) The failure of any Lender to make the Advance to be made by it as part of the Borrowing on the Funding Date shall not relieve any other Lender of its obligation, if any, hereunder to make its Advance on the Funding Date, but no Lender shall be responsible for the failure of any other Lender to make the Advance to be made by such other Lender on the Funding Date. SECTION 3.04. REPAYMENT OF ADVANCES. The Borrower shall repay the principal amount of each Advance made to it hereunder on the Termination Date. SECTION 3.05. INTEREST. (a) INTEREST PERIODS. (i) The period commencing on the date of each Advance and ending on the last day of the period selected by the Borrower with respect to such Advance pursuant to the provisions of this Section 3.05 is referred to herein as an "INTEREST PERIOD". The duration of each Interest Period shall be (i) in the case of any Eurodollar Rate Advance, one, two, three or (subject to availability) more months, and (ii) in the case of any Base Rate Advance, the period of time beginning on the date of the making of, or the conversion of an outstanding Advance into, such Advance and ending on the last day of March, June, September or December next following the date on which such Advance was made; provided, however, that no Interest Period may be selected by the Borrower if such Interest Period would end after the Termination Date. (ii) Subject to the terms and conditions of this Agreement, the initial Interest Period for the Advances made to the Borrower on the Funding Date shall be determined by the Borrower as set forth in its Notice of Contract Borrowing. The Borrower may elect to continue or convert (A) the Advances made on the Funding Date and (B) thereafter, one or more Advances of any Type and having the same Interest Period, to one or more Advances of the same or any other Type and having the same or a different Interest Period, on the following terms and subject to the following conditions: (A) Each continuation or conversion shall be made as to all Advances comprising a single Borrowing upon written notice given by the Borrower to the Administrative Agent not later than 11:00 a.m. (New York City time) on the third Business Day prior to the date of the proposed continuation of or conversion, in the case of a continuation or conversion to a Eurodollar Rate Advance, or on the day of the proposed continuation of or conversion to a Base Rate Advance. The Administrative Agent shall notify each Lender of the contents of such notice promptly after receipt thereof. Each such notice shall specify therein the following information: (1) the date of such proposed continuation or conversion (which in the case of Eurodollar Rate Advances shall be the last day of the Interest Period then applicable to such Advances to be continued or converted), (2) the Type of, 17 and Interest Period applicable to the Advances proposed to be continued or converted, (3) the aggregate principal amount of Advances proposed to be continued or converted, and (4) the Type of Advances to which such Advances are proposed to be continued or converted and the Interest Period to be applicable thereto. (B) During the continuance of an Unmatured Default, the right of the Borrower to continue or convert Advances to Eurodollar Rate Advances shall be suspended, and all Eurodollar Rate Advances then outstanding shall be converted to Base Rate Advances on the last day of the Interest Period then in effect, if, on such day, an Unmatured Default shall be continuing. (C) During the continuance of an Event of Default, the right of the Borrower to continue or convert Advances to Eurodollar Rate Advances shall be suspended, and upon the occurrence of an Event of Default, all Eurodollar Rate Advances then outstanding shall immediately, without further act by the Borrower, be converted to Base Rate Advances. (D) If no notice of continuation or conversion is received by the Administrative Agent as provided in paragraph (A), above, with respect to any outstanding Advances on or before the third Business Day prior to the last day of the Interest Period then in effect for such Advances, the Administrative Agent shall treat such absence of notice as a deemed notice of continuation or conversion providing for such Advances to be continued as or converted to Base Rate Advances with an Interest Period of three months commencing on the last day of such Interest Period. (b) INTEREST RATES. The Borrower shall pay interest on the unpaid principal amount of each Advance owing by the Borrower from the date of such Advance until such principal amount shall be paid in full, at the Applicable Rate for such Advance (except as otherwise provided in this subsection (b)), payable as follows: (i) EURODOLLAR RATE ADVANCES. If such Advance is a Eurodollar Rate Advance, interest thereon shall be payable on the last day of the Interest Period applicable thereto and on the Termination Date; provided that during the continuance of any Event of Default, such Advance shall bear interest at a rate per annum equal at all times to 2% per annum above the Applicable Rate for such Advance for such Interest Period. (ii) BASE RATE ADVANCES. If such Advance is a Base Rate Advance, interest thereon shall be payable quarterly on the last day of each March, June, September and December and on the date such Base Rate Advance shall be paid in full; provided that during the continuance of any Event of Default, such Advance shall bear interest at a rate per annum equal at all times to 2% per annum above the Applicable Rate for such Advance for such Interest Period. 18 (c) OTHER AMOUNTS. Any other amounts payable hereunder that are not paid when due shall (to the fullest extent permitted by law) bear interest, from the date when due until paid in full, at a rate per annum equal at all times to 2.0% per annum above the Applicable Rate in effect from time to time for Base Rate Advances, payable on demand. (d) INTEREST RATE DETERMINATIONS. The Administrative Agent shall give prompt notice to the Borrower and the Lenders of the Applicable Rate determined from time to time by the Administrative Agent for each Contract Advance. Each Reference Bank agrees to furnish to the Administrative Agent timely information for the purpose of determining the Eurodollar Rate for any Interest Period. If any one Reference Bank shall not furnish such timely information, the Administrative Agent shall determine such interest rate on the basis of the timely information furnished by the other two Reference Banks. (e) MAXIMUM INTEREST RATE. Notwithstanding anything herein to the contrary: (i) If at any time the effective interest rate on any Eurodollar Rate Advance or Base Rate Advance for any Interest Period (including any additional interest payable upon the occurrence of an Event of Default) exceeds 4.00% plus the Eurodollar Rate as determined (or as it would have been determined) as of the first day of the then applicable Interest Period for such Eurodollar Rate Advance or Base Rate Advance (the "MAXIMUM RATE"), such rate of interest shall be reduced to the Maximum Rate. (ii) If the amount of interest payable for the account of any Lender in respect of any Interest Period is reduced pursuant to subparagraph (i), above, and the amount of interest payable for such Lender's account in respect of any subsequent Interest Period would be less than the amount of interest computed at the Maximum Rate, then the amount of interest payable for such Lender's account in respect of such subsequent Interest Period shall, to the extent permitted by applicable law, be automatically increased to the amount of interest that would be payable for such Interest Period if such interest were computed at the Maximum Rate; provided that at no time shall the aggregate amount by which interest paid for the account of any Lender is increased pursuant to this subparagraph (ii) exceed the aggregate amount by which interest paid for its account has theretofore been reduced pursuant to subparagraph (i), above. 19 ARTICLE IV PAYMENTS SECTION 4.01. PAYMENTS AND COMPUTATIONS. (a) The Borrower shall make each payment hereunder and under the Notes not later than 12:00 noon (New York City time) on the day when due in U.S. Dollars to the Administrative Agent at its address referred to in Section 10.02 hereof, in same day funds. The Administrative Agent will promptly thereafter cause to be distributed like funds relating to the payment of principal, interest, fees or other amounts payable to the Lenders, to the respective Lenders to whom the same are payable, for the account of their respective Applicable Lending Offices, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of a Lender Assignment and recording of the information contained therein in the Register pursuant to Section 10.07, from and after the effective date specified in such Lender Assignment, the Administrative Agent shall make all payments hereunder and under the Notes in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Lender Assignment shall make all appropriate adjustments in such payments for periods prior to such effective date directly between themselves. (b) The Borrower hereby authorizes the Administrative Agent and each Lender, if and to the extent payment owed by the Borrower to the Administrative Agent or such Lender, as the case may be, is not made when due hereunder (or, in the case of a Lender, under the Note held by such Lender), to charge from time to time against any or all of the Borrower's accounts with the Administrative Agent or such Lender, as the case may be, any amount so due. (c) All computations of interest based on the Base Rate (except when determined on the basis of the Federal Funds Rate) shall be made on the basis of a year of 365 or 366 days, as the case may be. All computations of interest and other amounts payable pursuant to Section 4.03 shall be made by the Lender claiming such interest or other amount on the basis of a year of 360 days. All other computations of interest, including computations of interest based on the Eurodollar Rate, the Base Rate (when and if determined on the basis of the Federal Funds Rate), and all computations of fees and other amounts payable hereunder, shall be made on the basis of a year of 360 days. In each such case, such computation shall be made for the actual number of days (including the first day but excluding the last day) occurring in the period for which such interest, fees or other amounts are payable. Each such determination by the Administrative Agent or a Lender shall be conclusive and binding for all purposes, absent manifest error. (d) Whenever any payment under any Loan Document shall be stated to be due, or the last day of an Interest Period hereunder shall be stated to occur, on a day other than a Business Day, such payment shall be made, and the last day of such Interest Period shall occur, on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest and fees hereunder; provided, however, that if such extension would cause payment of interest on or principal of Eurodollar Rate Advances to be made, or the last day of an Interest Period for a Eurodollar Rate Advance to occur, in the next following 20 calendar month, such payment shall be made on the next preceding Business Day and such reduction of time shall in such case be included in the computation of payment of interest hereunder. (e) Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Lenders hereunder that the Borrower will not make such payment in full, the Administrative Agent may assume that the Borrower has made such payment in full to the Administrative Agent on such date and the Administrative Agent may, in reliance upon such assumption, cause to be distributed to each Lender on such due date an amount equal to the amount then due such Lender. If and to the extent the Borrower shall not have so made such payment in full to the Administrative Agent, such Lender shall repay to the Administrative Agent forthwith on demand such amount distributed to such Lender, together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Administrative Agent, at the Federal Funds Rate. SECTION 4.02. PREPAYMENTS. (a) The Borrower shall not have any right to prepay any Contract Advances except in accordance with subsection (b) below. (b) The Borrower may, (i) in the case of Eurodollar Rate Advances, upon at least three Business Day's written notice to the Administrative Agent (such notice being irrevocable) and (ii) in the case of Base Rate Advances, upon notice not later than 11:00 a.m. on the date of the proposed prepayment to the Administrative Agent (such notice being irrevocable), stating the proposed date and aggregate principal amount of the prepayment, and if such notice is given, the Borrower shall, prepay Contract Advances comprising part of the same Borrowing, in whole or ratably in part, together with accrued interest to the date of such prepayment on the principal amount prepaid and any amounts owing in connection therewith pursuant to Section 4.03(d); provided, however, that each partial prepayment shall be in an aggregate principal amount not less than $5,000,000 or an integral multiple of $1,000,000 in excess thereof. Once prepaid, Advances may not be reborrowed. SECTION 4.03. YIELD PROTECTION. (a) CHANGE IN CIRCUMSTANCES. Notwithstanding any other provision herein, if after the date hereof; the adoption of or any change in applicable law or regulation or in the interpretation or administration thereof by any governmental authority charged with the interpretation or administration thereof (whether or not having the force of law) shall (i) change the basis of taxation of payments to any Lender of the principal of or interest on any Eurodollar Rate Advance made by such Lender or any fees or other amounts payable hereunder (other than changes in respect of taxes imposed on the overall net income of such Lender, or its Applicable Lending Office, by the jurisdiction in which such Lender has its principal office or in which such Applicable Lending Office is located or by any political subdivision or taxing authority therein), or (ii) shall impose, modify or deem applicable any reserve, special deposit or similar requirement against commitments or assets of, deposits with or for the account of, or credit extended by, such Lender, or (iii) shall impose on such Lender any other condition affecting this Agreement or Eurodollar 21 Rate Advances, and the result of any of the foregoing shall be (A) to increase the cost to such Lender of issuing, maintaining or participating in this Agreement or of agreeing to make, making or maintaining any Advance or (B) to reduce the amount of any sum received or receivable by such Lender hereunder (whether of principal, interest or otherwise), then the Borrower will pay to such Lender, upon demand, such additional amount or amounts as will compensate such Lender for such additional costs incurred or reduction suffered. (b) CAPITAL. If any Lender shall have determined that any change after the date hereof in any law, rule, regulation or guideline adopted pursuant to or arising out of the July 1988 report of the Basle Committee on Banking Regulations and Supervisory Practices entitled "International Convergence of Capital Measurement and Capital Standards", or the adoption after the date hereof of any law, rule, regulation or guideline regarding capital adequacy, or any change in any of the foregoing or in the interpretation or administration of any of the foregoing by any governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any Lender (or any Applicable Lending Office of such Lender), or any holding company of any such entity, with any request or directive regarding capital adequacy (whether or not having the force of law) of any such authority, central bank or comparable agency, has or would have the effect (i) of reducing the rate of return on such entity's capital or on the capital of such entity's holding company, if any, as a consequence of this Agreement, any Commitment hereunder or the portion of the Advances made by such entity pursuant hereto to a level below that which such entity or such entity's holding company could have achieved, but for such applicability, adoption, change or compliance (taking into consideration such entity's policies and the policies of such entity's holding company with respect to capital adequacy), or (ii) of increasing or otherwise determining the amount of capital required or expected to be maintained by such entity or such entity's holding company based upon the existence of this Agreement, any Commitment hereunder, the portion of the Advance made by such entity pursuant hereto and other similar such credits, participations, commitments, agreements or assets, then from time to time the Borrower shall pay to such Lender, upon demand, such additional amount or amounts as will compensate such entity or such entity's holding company for any such reduction or allocable capital cost suffered. (c) EURODOLLAR RESERVES. The Borrower shall pay to each Lender upon demand, so long as such Lender shall be required under regulations of the Board of Governors of the Federal Reserve System to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency Liabilities, additional interest on the unpaid principal amount of each Eurodollar Rate Advance of such Lender to the Borrower, from the date of such Advance until such principal amount is paid in full, at an interest rate per annum equal at all times to the remainder obtained by subtracting (i) the Eurodollar Rate for the Interest Period for such Advance from (ii) the rate obtained by dividing such Eurodollar Rate by a percentage equal to 100% minus the Eurodollar Reserve Percentage of such Lender for such Interest Period. Such additional interest shall be determined by such Lender and notified to the Borrower and the Administrative Agent. (d) BREAKAGE INDEMNITY. The Borrower shall indemnify each Lender against any loss, cost or reasonable expense which such Lender may sustain or incur as a consequence of (i) any failure by the Borrower to fulfill on the Funding Date or the date of any continuation or conversion of Advances hereunder the applicable conditions precedent set forth in Articles III and 22 V, (ii) any failure by the Borrower to borrow or continue any, or convert any outstanding Advance into a, Eurodollar Rate Advance hereunder after the Notice of Contract Borrowing has been delivered pursuant to Section 3.01 hereof or after delivery of a notice of continuation or conversion pursuant to Section 3.05(a)(ii) hereof, (iii) any payment, prepayment, continuation or conversion of a Eurodollar Rate Advance required or permitted by any other provision of this Agreement or otherwise made or deemed made on a date other than the last day of the Interest Period applicable thereto, (iv) any default in payment or prepayment of the principal amount of any Eurodollar Rate Advance made to the Borrower or any part thereof or interest accrued thereon, as and when due and payable (at the due date thereof, by irrevocable notice of prepayment or otherwise) or (v) the occurrence of any Event of Default, including, in each such case, any loss or reasonable expense sustained or incurred or to be sustained or incurred in liquidating or employing deposits from third parties acquired to effect or maintain such Advance or any part thereof as a Eurodollar Rate Advance. Such loss, cost or reasonable expense shall include an amount equal to the excess, if any, as reasonably determined by such Lender, of (A) its cost of obtaining the funds for the Eurodollar Rate Advance being paid, prepaid, converted, continued or not borrowed or continued for the period from the date of such payment, prepayment, conversion, continuation or failure to borrow or continue to the last day of the Interest Period for such Advance (or, in the case of a failure to borrow or continue, the Interest Period for such Advance which would have commenced on the date of such failure) over (B) the amount of interest (as reasonably determined by such Lender) that would be realized by such Lender in reemploying the funds so paid, prepaid, converted, continued or not borrowed or continued for such period or Interest Period, as the case may be. For purposes of this subsection (d), it shall be presumed that in the case of any Eurodollar Rate Advance, each Lender shall have funded each such Advance with a fixed-rate instrument bearing the rates and maturities designated in the determination of the Applicable Rate for such Advance. (e) NOTICES. A certificate of any Lender setting forth such entity's claim for compensation hereunder and the amount necessary to compensate such entity or its holding company pursuant to subsections (a) through (d) of this Section 4.03 shall be submitted to the Borrower and the Administrative Agent and shall be conclusive and binding for all purposes, absent manifest error. The Borrower shall pay such Lender directly the amount shown as due on any such certificate within 10 days after its receipt of the same. The failure of any entity to provide such notice or to make demand for payment under this Section 4.03 shall not constitute a waiver of such entity's rights hereunder; provided that such entity shall not be entitled to demand payment pursuant to subsections (a) through (d) of this Section 4.03 in respect of any loss, cost, expense, reduction or reserve, if such demand is made more than one year following the later of such entity's incurrence or sufferance thereof or such entity's actual knowledge of the event giving rise to such entity's rights pursuant to such subsections. Each Lender shall use reasonable efforts to ensure the accuracy and validity of any claim made by it hereunder, but the foregoing shall not obligate any such entity to assert any possible invalidity or inapplicability of the law, rule, regulation, guideline or other change or condition which shall have occurred or been imposed. (f) CHANGE IN LEGALITY. Notwithstanding any other provision herein, if the adoption of or any change in any law or regulation or in the interpretation or administration thereof by any governmental authority charged with the administration or interpretation thereof shall make it unlawful for any Lender to make or maintain any Eurodollar Rate Advance or to give effect to its 23 obligations as contemplated hereby with respect to any Eurodollar Rate Advance, then, by written notice to the Borrower and the Administrative Agent, such Lender may: (i) declare that Eurodollar Rate Advances will not thereafter be made by such Lender hereunder, whereupon the right of the Borrower to select Eurodollar Rate Advances for any Borrowing or conversion shall be forthwith suspended until such Lender shall withdraw such notice as provided hereinbelow or shall cease to be a Lender hereunder pursuant to Section 10.07(g) hereof; and (ii) require that all outstanding Eurodollar Rate Advances be converted to Base Rate Advances, in which event all Eurodollar Rate Advances shall be automatically converted to Base Rate Advances as of the effective date of such notice as provided herein below. Upon receipt of any such notice, the Administrative Agent shall promptly notify the other Lenders. Promptly upon becoming aware that the circumstances that caused such Lender to deliver such notice no longer exist, such Lender shall deliver notice thereof to the Borrower and the Administrative Agent withdrawing such prior notice (but the failure to do so shall impose no liability upon such Lender). Promptly upon receipt of such withdrawing notice from such Lender (or upon such Lender assigning all of its Commitments, Advances and other rights and obligations under the Loan Documents in accordance with Section 10.07(g)), the Administrative Agent shall deliver notice thereof to the Borrower and the Lenders and such suspension shall terminate. Prior to any Lender giving notice to the Borrower under this subsection (f), such Lender shall use reasonable efforts to change the jurisdiction of its Applicable Lending Office, if such change would avoid such unlawfulness and would not, in the sole determination of such Lender, be otherwise disadvantageous to such Lender. Any notice to the Borrower by any Lender shall be effective as to each Eurodollar Rate Advance on the last day of the Interest Period currently applicable to such Eurodollar Rate Advance; provided that if such notice shall state that the maintenance of such Advance until such last day would be unlawful, such notice shall be effective on the date of receipt by the Borrower and the Administrative Agent. (g) MARKET RATE DISRUPTIONS. If (i) fewer than two Reference Banks furnish timely information to the Administrative Agent for determining the Eurodollar Rate for Eurodollar Rate Advances in connection with any proposed Borrowing or (ii) if the Majority Lenders shall notify the Administrative Agent that the Eurodollar Rate will not adequately reflect the cost to such Majority Lenders of making, funding or maintaining their respective Eurodollar Rate Advances, the right of the Borrower to select or receive Eurodollar Rate Advances for any Borrowing shall be forthwith suspended until the Administrative Agent shall notify the Borrower and the Lenders that the circumstances causing such suspension no longer exist, and until such notification from the Administrative Agent, each requested Borrowing of Eurodollar Rate Advances hereunder shall be deemed to be a request for Base Rate Advances. (h) RIGHTS OF PARTICIPANTS. Any participant in a Lender's interests hereunder may assert any claim for yield protection under Section 4.03 that it could have asserted if it were a Lender hereunder. If such a claim is asserted by any such participant, it shall be entitled to receive such compensation from the Borrower as a Lender would receive in like circumstances; provided, 24 however, that with respect to any such claim, the Borrower shall have no greater liability to the Lender and its participant, in the aggregate, than it would have had to the Lender alone had no such participation interest been created. SECTION 4.04. SHARING OF PAYMENTS, ETC. If any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise, but excluding any proceeds received by assignments or sales of participation in accordance with Section 10.07 hereof to a Person that is not an Affiliate of the Borrower) on account of the Advances owing to it (other than pursuant to Section 4.03 hereof) in excess of its ratable share of payments on account of the Advances obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders such participation in the Advances owing to them as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them; provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each Lender shall be rescinded and such Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such Lender's ratable share (according to the proportion of (i) the amount of such Lender's required repayment to (ii) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 4.04 may, to the fullest extent permitted by law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of the Borrower in the amount of such participation. Notwithstanding the foregoing, if any Lender shall obtain any such excess payment involuntarily, such Lender may, in lieu of purchasing participation from the other Lenders in accordance with this Section 4.04, on the date of receipt of such excess payment, return such excess payment to the Administrative Agent for distribution in accordance with Section 4.01(a). SECTION 4.05. TAXES. (a) All payments by or on behalf of the Borrower under any Loan Document shall be made in accordance with Section 4.01, free and clear of and without deduction for all present or future taxes, levies, imposts, deductions, charges or withholdings, and all liabilities with respect thereto, excluding, in the case of each Lender and the Administrative Agent, taxes imposed on its overall net income, and franchise taxes imposed on it, by the jurisdiction under the laws of which such Lender or the Administrative Agent (as the case may be) is organized or any political subdivision thereof and, in the case of each Lender, taxes imposed on its overall net income, and franchise taxes imposed on it, by the jurisdiction of such Lender's Applicable Lending Office or any political subdivision thereof (all such non-excluded taxes, levies, imposts, deductions, charges, withholdings and liabilities being hereinafter referred to as "TAXES"). If the Borrower shall be required by law to deduct any Taxes from or in respect of any sum payable under any Loan Document to any Lender or the Administrative Agent, (i) the sum payable shall be increased as may be necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 4.05) such Lender or the Administrative Agent (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower shall make such deductions and (iii) the Borrower shall 25 pay the full amount deducted to the relevant taxation authority or other authority in accordance with applicable law. (b) In addition, the Borrower agrees to pay any present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies that arise from any payment made by the Borrower under any Loan Document or from the execution, delivery or registration of, or otherwise with respect to, any Loan Document (hereinafter referred to as "OTHER TAXES"). (c) The Borrower hereby indemnifies each Lender and the Administrative Agent for the full amount of Taxes and Other Taxes (including, without limitation, any Taxes and any Other Taxes imposed by any jurisdiction on amounts payable under this Section 4.05) paid by such Lender or the Administrative Agent (as the case may be) and any liability (including penalties, interest and expenses) arising therefrom or with respect thereto, whether or not such Taxes or Other Taxes were correctly or legally asserted. A claim for such indemnification shall be set forth in a certificate of such Lender or the Administrative Agent (as the case may be) setting forth in reasonable detail the amount necessary to indemnify such Person pursuant to this subsection (c) and shall be submitted to the Borrower and the Administrative Agent and shall be conclusive and binding for all purposes, absent manifest error. The Borrower shall pay such Lender or the Administrative Agent (as the case may be) directly the amount shown as due on any such certificate within 30 days after the receipt of same. If any Taxes or Other Taxes for which a Lender or the Administrative Agent has received payments from the Borrower hereunder shall be finally determined to have been incorrectly or illegally asserted and are refunded to such Lender or the Administrative Agent, such Lender or the Administrative Agent, as the case may be, shall promptly forward to the Borrower any such refunded amount. The Borrower's, the Administrative Agent's and each Lender's obligations under this Section 4.05 shall survive the payment in full of the Outstanding Credits. (d) Within 30 days after the date of any payment of Taxes, the Borrower will furnish to the Administrative Agent, at its address referred to in Section 10.02, the original or a certified copy of a receipt evidencing payment thereof. (e) Each Lender that is not incorporated under the laws of the United States of America or any state thereof shall, on or prior to the date it becomes a Lender hereunder, deliver to the Borrower and the Administrative Agent such certificates, documents or other evidence, as required by the Internal Revenue Code of 1986, as amended from time to time (the "CODE"), or treasury regulations issued pursuant thereto, including Internal Revenue Service Form 4224, Form 1001, Form W-8 BEN or Form W-8 ECI and any other certificate or statement of exemption required by Treasury Regulation Section 1.1441-1(a) or Section 1.1441-6(c) or any subsequent version thereof, properly completed and duly executed by such Lender establishing that it is (i) not subject to withholding under the Code or (ii) totally exempt from United States of America tax under a provision of an applicable tax treaty. Each Lender shall promptly notify the Borrower and the Administrative Agent of any change in its Applicable Lending Office and shall deliver to the Borrower and the Administrative Agent together with such notice such certificates, documents or other evidence referred to in the immediately preceding sentence. Each Lender will use good faith efforts to apprise the Borrower and the Administrative Agent as promptly as practicable of any impending change in its tax status that would give rise to any obligation by the 26 Borrower to pay any additional amounts pursuant to this Section 4.05. Unless the Borrower and the Administrative Agent have received forms or other documents satisfactory to them indicating that payments under the Loan Documents are not subject to United States of America withholding tax or are subject to such tax at a rate reduced by an applicable tax treaty, the Borrower or the Administrative Agent shall withhold taxes from such payments at the applicable statutory rate in the case of payments to or for any Lender organized under the laws of a jurisdiction outside the United States of America. Each Lender represents and warrants that each such form supplied by it to the Administrative Agent and the Borrower pursuant to this Section 4.05, and not superseded by another form supplied by it, is or will be, as the case may be, complete and accurate. (f) Any Lender claiming any additional amounts payable pursuant to this Section 4.05 shall use reasonable efforts (consistent with legal and regulatory restrictions) to file any certificate or document requested by the Borrower or to change the jurisdiction of its Applicable Lending Office if the making of such a filing or change would avoid the need for or reduce the amount of any such additional amounts which may thereafter accrue and would not, in the sole determination of such Lender, be otherwise disadvantageous to such Lender. ARTICLE V CONDITIONS PRECEDENT SECTION 5.01. CONDITIONS PRECEDENT TO EFFECTIVENESS. The obligations of the Lenders to make Advances to the Borrower on the Funding Date shall not become effective until the date (the "CLOSING DATE") on which each of the following conditions is satisfied: (a) The Administrative Agent shall have received on or before the Closing Date the following, each dated the Closing Date, in form and substance satisfactory to the Administrative Agent and in sufficient copies for each Lender (except for the Notes): (i) Counterparts of this Agreement, duly executed by the Borrower. (ii) Contract Notes of the Borrower, duly made to the order of each Lender in the amount of such Lender's Commitment. (iii) A certificate of the Secretary or Assistant Secretary of the Borrower certifying: (A) the names and true signatures of the officers of the Borrower authorized to sign the Loan Documents; (B) that attached thereto are true and correct copies of: (1) the Declaration of Trust of the Borrower, together with all amendments thereto, as in effect on such date; (2) the resolutions of the Borrower's Board of Trustees 27 approving the execution, delivery and performance by the Borrower of the Loan Documents, the Borrowings hereunder and the consummation by the Borrower of the acquisition of YES; (3) all documents evidencing other necessary corporate or other similar action, if any, with respect to the execution, delivery and performance of the Loan Documents by the Borrower and the consummation by the Borrower of the acquisition of YES; and (4) true and correct copies of all Governmental Approvals referred to in clauses (i) and (iii) of the definition of "Governmental Approval" required to be obtained by the Borrower in connection with the execution, delivery and performance by the Borrower of the Loan Documents (including the order of the Securities and Exchange Commission) and the acquisition by the Borrower of YES; and (C) that the resolutions referred to in the foregoing clause (B)(2) have not been modified, revoked or rescinded and are in full force and effect on such date. (iv) A certificate signed by the Treasurer or Assistant Treasurer of the Borrower, certifying as to: (A) the delivery to each of the Lenders, prior to the Closing Date, of true, correct and complete copies (other than exhibits thereto) of all of the Disclosure Documents; and (B) the absence of any material adverse change in the financial condition, operations, properties or prospects of the Borrower or the Borrower and its Principal Subsidiaries, taken as a whole, since September 30, 1999, except as disclosed in the Disclosure Documents. (v) A certificate of a duly authorized officer of the Borrower certifying that (i) the representations and warranties of the Borrower contained in Section 6.01 are correct, in all material respects, on and as of the Closing Date, (ii) no event has occurred and is continuing which constitutes an Event of Default or Unmatured Default, and (iii) attached thereto is the merger agreement with respect to the acquisition of YES and all amendments and supplements, if any, thereto. (vi) Such financial, business and other information regarding the Borrower and its Principal Subsidiaries, as any Lender shall have reasonably requested. (vii) Favorable opinions of: (A) Day, Berry & Howard, counsel to the Borrower, in substantially the form of Exhibit 5.01A hereto and as to such other matters as any Lender may reasonably request; (B) Jeffrey C. Miller, Assistant General Counsel of NUSCO, in substantially the form of Exhibit 5.01B hereto; and as to such other matters as any Lender may reasonably request; and 28 (C) King & Spalding, special New York counsel to the Administrative Agent, in substantially the form of Exhibit 5.01C hereto and as to such other matters as any Lender may reasonably request. (b) The representations and warranties of the Borrower contained in Section 6.01 shall be correct in all material respects on and as of the Closing Date, and no event shall have occurred and be continuing which constitutes an Event of Default or Unmatured Default. (c) All fees and other amounts payable pursuant to the Fee Letter shall have been paid (to the extent then due and payable). (d) The Borrower shall have entered into a definitive merger agreement with respect to the acquisition of YES; the Administrative Agent shall have reviewed and shall be satisfied with all of the material terms thereof; no default or failure in the satisfaction of a condition shall have occurred and be continuing under such agreement that could reasonably be expected to threaten or materially delay the consummation of such acquisition; and, from and after the date hereof, the Borrower shall not have agreed to any modification of such material terms if the effect thereof would be to increase the purchase price of the shares of YES to be acquired thereunder or, without the consent of the Administrative Agent, if the effect of such modification would be to decrease the aggregate value of such shares. (e) The Administrative Agent shall have received such other approvals, opinions and documents as the Majority Lenders, through the Administrative Agent, shall have reasonably requested as to the legality, validity, binding effect or enforceability of this Agreement and the Notes or the financial condition, operations, properties or prospects of the Borrower and its Principal Subsidiaries. SECTION 5.02. CONDITIONS PRECEDENT TO ADVANCES ON FUNDING DATE. The obligation of any Lender to make an Advance on the Funding Date shall be subject to the conditions precedent that, on such date and after giving effect to the Advances to be made thereon: (a) the following statements shall be true (and each of the giving of the Notice of Contract Borrowing with respect to such Advances and the acceptance of the proceeds of such Advances by the Borrower shall constitute a representation and warranty by the Borrower that on the Funding Date such statements are true): (i) the representations and warranties of the Borrower contained in Section 6.01 of this Agreement are correct, in all material respects, on and as of the Funding Date, before and after giving effect to the Advances to be made thereon and to the application of the proceeds therefrom, as though made on and as of such date; and (ii) no Event of Default or Unmatured Default has occurred and is continuing on or as of the Funding Date or would result from the Advances to be made thereon or from the application of the proceeds thereof; and 29 (b) the Borrower shall have furnished to the Administrative Agent such other approvals, opinions or documents as any Lender may reasonably request through the Administrative Agent as to the legality, validity, binding effect or enforceability of any Loan Document. SECTION 5.03. RELIANCE ON CERTIFICATES. The Lenders and the Administrative Agent shall be entitled to rely conclusively upon the certificates delivered from time to time by officers of the Borrower as to the names, incumbency, authority and signatures of the respective persons named therein until such time as the Administrative Agent may receive a replacement certificate, in form acceptable to the Administrative Agent, from an officer of the Borrower identified to the Administrative Agent as having authority to deliver such certificate, setting forth the names and true signatures of the officers and other representatives of the Borrower thereafter authorized to act on behalf of the Borrower and, in all cases, the Lenders and the Administrative Agent may rely on the information set forth in any such certificate. ARTICLE VI REPRESENTATIONS AND WARRANTIES SECTION 6.01. REPRESENTATIONS AND WARRANTIES OF THE BORROWER. The Borrower represents and warrants as follows: (a) The Borrower is a voluntary association organized under a Declaration of Trust, and each of its Principal Subsidiaries is a corporation, in each case duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, has the requisite corporate power (or in the case of the Borrower, power under its Declaration of Trust) and authority to own its property and assets and to carry on its business as now conducted and is qualified to do business in every jurisdiction where, because of the nature of its business or property, such qualification is required, except where the failure so to qualify would not have a material adverse effect on the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries taken as a whole. The Borrower has the requisite power to execute, deliver and perform its obligations under the Loan Documents, to borrow hereunder and to execute and deliver its respective Notes, and to consummate the acquisition of YES. (b) The execution, delivery and performance of the Loan Documents by the Borrower, and the consummation by the Borrower of the acquisition of YES, are within the Borrower's powers under its Declaration or Trust, have been duly authorized by all necessary action under its Declaration of Trust and applicable law, and do not and will not contravene (i) the Borrower's Declaration of Trust or any law or legal restriction or (ii) any contractual restriction binding on or affecting the Borrower or its properties or its Principal Subsidiaries or their respective properties. (c) Except as disclosed in the Disclosure Documents, none of the Borrower or any of its Principal Subsidiaries is in violation of any law or in default with respect to any 30 judgment, writ, injunction, decree, rule or regulation (including any of the foregoing relating to environmental laws and regulations) of any court or governmental agency or instrumentality where such violation or default would reasonably be expected to have a material adverse effect on the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole. (d) There has been no material adverse development with respect to (i) the proceedings of CL&P or WMECO to divest its generating assets, or (ii) any orders, plans or authorizations for recovery of the stranded assets of CL&P or WMECO, where any such development results, or would reasonably be expected to result, in a material adverse effect on the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole, other than as described in the Disclosure Documents. (e) All Governmental Approvals referred to in clauses (i) and (iii) of the definition of "Governmental Approvals" have been duly obtained or made, and all applicable periods of time for review, rehearing or appeal with respect thereto have expired, except as described below. If the period for appeal of the order of the Securities and Exchange Commission approving the transactions contemplated hereby (including the acquisition by the Borrower of YES) has not expired, the filing of an appeal of such order will not affect the validity of said transactions, unless such order has been otherwise stayed or any of the parties hereto has actual knowledge that any of such transactions constitutes a violation of the Public Utility Holding Company Act of 1935 or any rule or regulation thereunder. No such stay exists and the Borrower has no reason to believe that any of such transactions constitutes any such violation. The Borrower and each Subsidiary thereof has obtained or made all Governmental Approvals referred to in clause (ii) of the definition of "Governmental Approvals", except (A) those which are not yet required but which are obtainable in the ordinary course of business as and when required, (B) those the absence of which would not materially adversely affect the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole, and (C) those which the Borrower or any such Subsidiary, as the case may be, is diligently attempting in good faith to obtain, renew or extend, or the requirement for which the Borrower or any such Subsidiary, as the case may be, is contesting in good faith by appropriate proceedings or by other appropriate means, in each case described in the foregoing clause (C), except as is disclosed in the Disclosure Documents, such attempt or contest, and any delay resulting therefrom, is not reasonably expected to have a material adverse effect on the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole, or to magnify to any significant degree any such material adverse effect that would reasonably be expected to result from the absence of such Governmental Approval. (f) The Loan Documents are legal, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their respective terms; subject to the qualification, however, that the enforcement of the rights and remedies herein and therein is subject to bankruptcy and other similar laws of general application affecting rights and 31 remedies of creditors and the application of general principles of equity (regardless of whether considered in a proceeding in equity or at law). (g) The Financial Statements, copies of which have been provided to the Administrative Agent and each of the Lenders, fairly present in all material respects the consolidated financial condition and results of operations of the Borrower and each of its Principal Subsidiaries at and for the period ended on the dates thereof, and have been prepared in accordance with generally accepted accounting principles consistently applied. Since September 30, 1999, there has been no material adverse change in the consolidated financial condition, operations, properties or prospects of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole, except as disclosed in the Disclosure Documents. (h) There is no pending or known threatened action or proceeding (including, without limitation, any action or proceeding relating to any environmental protection laws or regulations) affecting the Borrower, any Principal Subsidiary thereof or any of their respective properties, before any court, governmental agency or arbitrator (i) which affects or purports to affect the legality, validity or enforceability of any Loan Document or of the consummation by the Borrower of the acquisition of YES or (ii) as to which there is a reasonable possibility of an adverse determination and which, if adversely determined, would materially adversely affect (A) the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole, or (B) the timing, cost or worth to the Borrower of the consummation of the acquisition of YES, except, for purposes of this clause (ii) only, such as is described in the Disclosure Documents or in Schedule II hereto. (i) No ERISA Plan Termination Event has occurred nor is reasonably expected to occur with respect to any ERISA Plan which would materially adversely affect the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole, except as disclosed to the Lenders and consented to by the Majority Lenders in writing. Since the date of the most recent Schedule B (Actuarial Information) to the annual report of each such ERISA Plan (Form 5500 Series), there has been no material adverse change in the funding status of the ERISA Plans referred to therein, and no "prohibited transaction" has occurred with respect thereto that, singly or in the aggregate with all other "prohibited transactions" and after giving effect to all likely consequences thereof, would be reasonably expected to have a material adverse effect on the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole. Neither the Borrower nor any of its ERISA Affiliates has incurred nor reasonably expects to incur any material withdrawal liability under ERISA to any ERISA Multiemployer Plan, except as disclosed to and consented by the Majority Lenders in writing. (j) The Borrower and each Principal Subsidiary thereof has good and marketable title (or, in the case of personal property, valid title) or valid leasehold interests in its assets, except for (i) minor defects in title that do not materially interfere with the ability of 32 the Borrower or such Principal Subsidiary to conduct its business as now conducted and (ii) other defects that, either individually or in the aggregate, do not materially adversely affect the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole. All such assets and properties are free and clear of any Lien, other than Liens permitted under Section 7.02(a) hereof. No Liens exist on the stock of CL&P, WMECO or PSNH. (k) All outstanding shares of capital stock having ordinary voting power for the election of directors of each Principal Subsidiary have been validly issued and are fully paid and nonassessable and are owned beneficially by NU, free and clear of any Lien. NU is a "holding company" (as defined in the Public Utility Holding Company Act of 1935, as amended). (l) The Borrower and each of its Principal Subsidiaries has filed all tax returns (Federal, state and local) required to be filed and paid taxes shown thereon to be due, including interest and penalties, or, to the extent the Borrower or such Principal Subsidiary is contesting in good faith an assertion of liability based on such returns, has provided adequate reserves in accordance with generally accepted accounting principles for payment thereof. (m) No exhibit, schedule, report or other written information provided by or on behalf of the Borrower or its agents to the Administrative Agent or the Lenders in connection with the negotiation, execution and closing of the Loan Documents (including, without limitation, the Financial Statements) knowingly contained when made any material misstatement of fact or knowingly omitted to state any material fact necessary to make the statements contained therein not misleading in light of the circumstances under which they were made. Except as has been disclosed to the Administrative Agent and each Lender, nothing has come to the attention of the responsible officers of the Borrower that would indicate that any of such assumptions, to the extent material to such projections, has ceased to be reasonable in light of subsequent developments or events. (n) All proceeds of the Advances shall be used to finance the acquisition by the Borrower of YES. No proceeds of any Advance will be used in violation of, or in any manner that would result in a violation by any party hereto of, Regulation T, U or X promulgated by the Board of Governors of the Federal Reserve System or any successor regulations. After giving effect to the acquisition of YES, the aggregate value of all of the shares of YES acquired by the Borrower, together with the aggregate value of all other Margin Stock (as defined in Regulation U) owned of record or beneficially by the Borrower and its consolidated subsidiaries will not exceed 25% of the total consolidated assets of the Borrower and its consolidated Subsidiaries. Neither the Borrower nor any Subsidiary thereof (A) is an "investment company" within the meaning ascribed to that term in the Investment Company Act of 1940 or (B) is engaged in the business of extending credit for the purpose of buying or carrying Margin Stock. (o) The Borrower and each Principal Subsidiary thereof has obtained the insurance specified in Section 7.01(c) hereof and the same is in full force and effect. 33 (p) The Borrower and each Principal Subsidiary thereof has substantially completed reprogramming and/or remediation required as a result of the potential Year 2000 Issue to permit the proper functioning in all material respects of its computer software, hardware and firmware systems and equipment containing computer chips and the proper processing in all material respects of data, and the testing of such reprogramming or remediation (as the case may be). The Borrower has completed review of the reasonably foreseeable consequences of the potential Year 2000 Issue to the Borrower and each of its Principal Subsidiaries (including, without limitation, reprogramming errors and the failure of systems or equipment supplied by others) and such consequences are not reasonably expected to result in an Event of Default, an Unmatured Default or a material adverse effect on the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole. ARTICLE VII COVENANTS SECTION 7.01. AFFIRMATIVE COVENANTS. On and after the Closing Date, so long as any Note shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower shall, unless the Majority Lenders shall otherwise consent in writing: (a) USE OF PROCEEDS. Apply the proceeds of each Advance solely as specified in Section 6.01(n) hereof. (b) PAYMENT OF TAXES, ETC. Pay and discharge, and cause each of its Principal Subsidiaries to pay and discharge, before the same shall become delinquent, all taxes, assessments and governmental charges, royalties or levies imposed upon it or upon its property except to the extent the Borrower or such Principal Subsidiary is contesting the same in good faith by appropriate proceedings and has set aside adequate reserves in accordance with generally accepted accounting principles for the payment thereof. (c) MAINTENANCE OF INSURANCE. Maintain or cause to be maintained, and cause each of its Principal Subsidiaries to maintain or cause to be maintained, insurance (including appropriate plans of self-insurance) covering the Borrower, the Principal Subsidiaries and their respective properties, in effect at all times in such amounts and covering such risks as may be required by law and, in addition, as is usually carried by companies engaged in similar businesses and owning similar properties as the Borrower and such Principal Subsidiaries. (d) PRESERVATION OF EXISTENCE, ETC.; DISAGGREGATION. (i) Except as permitted by Section 7.02(b) hereof, preserve and maintain, and cause each of its Principal Subsidiaries to preserve and maintain, its existence, 34 corporate or otherwise, material rights (statutory and otherwise) and franchises except where the failure to maintain and preserve such rights and franchises would not materially adversely affect the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole. (ii) In furtherance of the foregoing, and notwithstanding Section 7.02(b), the Borrower agrees that it will not, and will cause each of its Principal Subsidiaries not to, except in accordance with one or more restructuring plans approved by the appropriate regulatory authorities, sell, transfer or otherwise dispose of (by lease or otherwise, and whether in one or a series of related transactions) any portion of its generation, transmission or distribution assets in excess of 10% of the net utility plant assets of the Borrower and its Principal Subsidiaries, taken as a whole, in each case as determined on a cumulative basis from the date of this Agreement through the Termination Date by reference to the published balance sheets of the Borrower and its Principal Subsidiaries. (e) COMPLIANCE WITH LAWS, ETC. Comply, and cause each of its Principal Subsidiaries to comply, in all material respects with the requirements of all applicable laws, rules, regulations and orders of any governmental authority, including, without limitation, any such laws, rules, regulations and orders issued by the Securities and Exchange Commission or relating to zoning, environmental protection, use and disposal of Hazardous Substances, land use, construction and building restrictions, ERISA and employee safety and health matters relating to business operations, except to the extent (i) that the Borrower or any such Principal Subsidiary is contesting the same in good faith by appropriate proceedings or (ii) that any such non-compliance, and the enforcement or correction thereof, would not materially adversely affect the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole. (f) INSPECTION RIGHTS. At any time and from time to time upon reasonable notice, permit, and cause each of its Principal Subsidiaries to permit, the Administrative Agent, the Lenders and their respective agents and representatives to examine and make copies of and abstracts from the records and books of account of, and the properties of, the Borrower and each Principal Subsidiary and to discuss the affairs, finances and accounts of the Borrower and each Principal Subsidiary (i) with the Borrower, each Principal Subsidiary and their respective officers and directors and (ii) with the consent of the Borrower and/or its Principal Subsidiaries, as the case may be (which consent shall not be unreasonably withheld or delayed), with the accountants of the Borrower or any such Principal Subsidiary. (g) KEEPING OF BOOKS. Keep, and cause each Principal Subsidiary to keep, proper records and books of account, in which full and correct entries shall be made of all financial transactions of the Borrower and each Principal Subsidiary and the assets and business of the Borrower and each Principal Subsidiary, in accordance with generally accepted accounting practices consistently applied. 35 (h) CONDUCT OF BUSINESS. Except as permitted by Section 7.02(b) but subject in all respects to Section 7.01(d)(ii), conduct, and cause each Principal Subsidiary to conduct, its primary business in substantially the same manner and in substantially the same fields as such business is conducted on the Closing Date. (i) MAINTENANCE OF PROPERTIES, ETC. (i) As to properties of the type described in Section 6.01(j) hereof, maintain, and cause each Principal Subsidiary to maintain, title of the quality described therein and preserve, maintain, develop, and operate, and cause each Principal Subsidiary to preserve, maintain, develop and operate, in substantial conformity with all laws, material contractual obligations and prudent practices prevailing in the industry, all of its properties which are used or useful in the conduct of its businesses in good working order and condition, ordinary wear and tear excepted, except (A) as permitted by Section 7.02(b), but subject nevertheless to Section 7.01(d)(ii), (B) as disclosed in the Disclosure Documents or otherwise in writing to the Administrative Agent and the Lenders on or prior to the date hereof, and (C) to the extent such non-conformity would not materially adversely affect the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole; provided, however, that neither the Borrower nor any Principal Subsidiary will be prevented from discontinuing the operation and maintenance of any such properties if such discontinuance is, in the judgment of the Borrower or such Principal Subsidiary, desirable in the operation or maintenance of its business and would not materially adversely affect the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole. (j) GOVERNMENTAL APPROVALS. Duly obtain, and cause each Principal Subsidiary to duly obtain, on or prior to such date as the same may become legally required, and thereafter maintain, and cause each Principal Subsidiary to maintain, in effect at all times, all Governmental Approvals on its part to be obtained, except in the case of those Governmental Approvals referred to in clause (ii) of the definition of "Governmental Approvals", (i) those the absence of which would not materially adversely affect the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole, and (ii) those which the Borrower or such Principal Subsidiary is diligently attempting in good faith to obtain, renew or extend, or the requirement for which the Borrower or such Principal Subsidiary is contesting in good faith by appropriate proceedings or by other appropriate means; provided, however, that the exception afforded by clause (ii), above, shall be available only if and for so long as such attempt or contest, and any delay resulting therefrom, does not have a material adverse effect on the financial condition, properties, prospects or operations of the Borrower or of the Borrower and its Principal Subsidiaries, taken as a whole, and does not magnify to any significant degree any such material adverse effect that would reasonably be expected to result from the absence of such Governmental Approval. (k) FURTHER ASSURANCES. Promptly execute and deliver all further instruments and documents, and take all further action, that may be necessary or that any Lender 36 through the Administrative Agent may reasonably request in order to fully give effect to the interests and properties purported to be covered by the Loan Documents. SECTION 7.02. NEGATIVE COVENANTS. On and after the Closing Date, and so long as any Note shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower shall not, or permit any Principal Subsidiary to, without the written consent of the Majority Lenders: (a) LIENS, ETC. Create incur, assume or suffer to exist any Lien upon any of its properties or assets (including the stock of its Subsidiaries), whether now owned or hereafter acquired, except: (i) any Liens existing on the Closing Date; (ii) in the case of CL&P, Liens created by the Indenture of Mortgage and Deed of Trust dated as of May 1, 1921, from CL&P to Bankers Trust Company, as trustee, as previously and hereafter amended and supplemented (the "CL&P INDENTURE"); (iii) in the case of WMECO, Liens created by the First Mortgage Indenture and Deed of Trust dated as of August 1, 1954, from WMECO to State Street Bank and Trust Company, as successor trustee, as previously and hereafter amended and supplemented (the "WMECO INDENTURE"); (iv) in the case of PSNH, Liens created by the General and Refunding Mortgage Indenture, dated as of August 15, 1978, between PSNH and New England Merchants National Bank, as trustee, and to which First Union National Bank is successor trustee, as previously and hereafter amended and supplemented (the "PSNH INDENTURE"); (v) in the case of NAEC, Liens created by the First Mortgage Indenture and Deed of Trust, dated as of June 1, 1992, between NAEC and United States Trust Company of New York, as trustee, as previously and hereafter amended and supplemented (the "NAEC INDENTURE"); (vi) Liens on the interests of CL&P and WMECO in (A) the Millstone Unit No. 1 created by (1) the Open-End Mortgage and Trust Agreement dated as of October 1, 1986, as previously and hereafter amended, made by CL&P in favor of State Street Bank and Trust Company, as successor trustee, and (2) the Open-End Mortgage and Trust Agreement dated as of October 1, 1986, as previously and hereafter amended, made by WMECO in favor of State Street Bank and Trust Company, as successor trustee, to the extent of the Debt from time to time secured by such Open-End Mortgages and Trust Agreements, and (B) Millstone Unit No. 2 and Millstone Unit No. 3 created by (1) the Open-End Mortgage, dated as of November 19, 1999, made by CL&P in favor of Citibank, N.A., as collateral agent, and (2) the Open-End Mortgage, dated as of November 19, 1999, made by WMECO in favor of Citibank, N.A., as collateral agent, to the extent of the Debt secured by such Open-End Mortgages; 37 (vii) "Permitted Liens" or "Permitted Encumbrances" under the CL&P Indenture (in the case of CL&P), the WMECO Indenture (in the case of WMECO), the PSNH Indenture (in the case of PSNH) or the NAEC Indenture (in the case of NAEC), in each case as such terms are defined on the date hereof, to the extent such Liens do not secure Debt of the Borrower or any Principal Subsidiary; (viii) any purchase money Lien or construction mortgage on assets hereafter acquired or constructed by the Borrower or any Principal Subsidiary and any Lien on any assets existing at the time of acquisition thereof by the Borrower or such Principal Subsidiary or created within 180 days from the date of completion of such acquisition or construction; provided that such Lien shall at all times be confined solely to the assets so acquired or constructed and any additions thereto; (ix) any existing Liens on assets now owned by the Borrower or any Principal Subsidiary and Liens existing on assets of a corporation or other going concern when it is merged into or with the Borrower or such Principal Subsidiary or when substantially all of its assets are acquired by the Borrower or such Principal Subsidiary; provided that such Liens shall at all times be confined solely to such assets, or if such assets constitute a utility system, additions to or substitutions for such assets; (x) Liens resulting from legal proceedings being contested in good faith by appropriate legal or administrative proceedings by the Borrower or any Principal Subsidiary, and as to which the Borrower or such Principal Subsidiary, to the extent required by generally accepted accounting principles applied on a consistent basis, shall have set aside on its books adequate reserves; (xi) Liens created in favor of the other contracting party in connection with advance or progress payments; (xii) any Liens in favor of any state of the United States or any political subdivision of any such state, or any agency of any such state or political subdivisions, or trustee acting on behalf of holders of obligations issued by any of the foregoing or any financial institutions lending to or purchasing obligations of any of the foregoing, which Lien is created or assumed for the purpose of financing all or part of the cost of acquiring or constructing the property subject thereto; (xiii) Liens resulting from conditional sale agreements, capital leases or other title retention agreements including, without limitation, Liens arising under leases of nuclear fuel from the Niantic Bay Fuel Trust; (xiv) with respect to pollution control bond financings, Liens on funds, accounts and other similar intangibles of the Borrower or any Principal Subsidiary created or arising under the relevant indenture, pledges of the related loan agreement with the relevant issuing authority and pledges of the Borrower's or such Principal Subsidiary's interest, if any, in any bonds issued pursuant to such financings to a letter of credit bank or bond issuer or similar credit enhancer; 38 (xv) Liens granted on accounts receivable and Regulatory Assets in connection with financing transactions, whether denominated as sales or borrowings; (xvi) Liens on the assets of, or the stock issued by, Northeast Generation Company or any other Subsidiary of the Borrower created to hold generating assets if such Liens are created to secure nonrecourse Debt incurred to acquire, construct or otherwise develop such generating assets; (xvii) Liens on assets of HWP permitted to exist by the terms of agreements governing the Named Debt; (xviii) any other Liens incurred in the ordinary course of business otherwise than to secure Debt; and (xix) any extension, renewal or replacement of Liens permitted by clauses (i), (vi) through (ix) and (xi) through (xvi); provided, however, that the principal amount of Debt secured thereby shall not, at the time of such extension, renewal or replacement, exceed the principal amount of Debt so secured and that such extension, renewal or replacement shall be limited to all or a part of the property which secured the Lien so extended, renewed or replaced. (b) MERGERS, ACQUISITIONS, SALES OF ASSETS, ETC. Merge with or into or consolidate with or into, any Person, or purchase or otherwise acquire (whether directly or indirectly) all or substantially all of the assets or stock of any class of, or any partnership or joint venture interest in, any other Person, or sell, transfer, convey, lease or otherwise dispose of all or any substantial part of its assets; except for the following, and then only after receipt of all necessary corporate and governmental or regulatory approvals and provided that, before and after giving effect to any such merger, consolidation, purchase, acquisition, sale, transfer, conveyance, lease or other disposition, no Event of Default or Unmatured Default shall have occurred and be continuing: (A) NU may merge with or into Consolidated Edison, Inc. or a wholly owned Subsidiary thereof; (B) any purchase or acquisition of a joint venture interest in a mutual insurance company providing nuclear liability or nuclear property or replacement power insurance; (C) any sale of accounts receivable on reasonable commercial terms (including a commercially reasonable discount) to obtain funding for CL&P and WMECO, as the case may be; (D) any sale or purchase of generating assets or Regulatory Assets on an arms-length basis, subject to approval by the appropriate regulatory authorities; (E) the sale of the Borrower's or any Principal Subsidiary's assets in the ordinary course of business on customary terms and conditions; 39 (F) the acquisition of YES for consideration in an amount not to exceed $495,000,000 (excluding the assumption of Debt); and (G) the acquisition of substantially all of the assets of, or substantially all of the ownership interests in, any other Person or Persons, which acquisition or acquisitions are not otherwise permitted by this subsection (b), so long as the aggregate consideration for all such acquisitions (including the acquisition by HEC Inc. of the assets of Energy Applications Inc.) does not exceed $5,000,000. For purposes of this subsection (b), any sale of assets by the Borrower or any Principal Subsidiary (in one or a series of transactions) will be deemed to be a "substantial part" of its assets if (i) the book value of such assets exceeds 7.5% of the total book value of the assets (net of Regulatory Assets) of such Person, as reflected in the most recent financial statements of the Borrower or such Principal Subsidiary delivered to the Administrative Agent pursuant to Section 7.04 hereof (or, if no such financial statements have been delivered to the Administrative Agent as of the relevant date of determination, the Financial Statements of such Person), or (ii) the gross revenue associated with such assets accounts for more than 7.5% of the total gross revenue of the Borrower or such Principal Subsidiary for the four proceeding fiscal quarters, as reflected in the most recent financial statements of the Borrower or such Principal Subsidiary delivered to the Administrative Agent pursuant to Section 7.04 hereof (or, if no such financial statements have been delivered to the Administrative Agent as of the relevant date of determination, the Financial Statements of such Person). (c) COMPLIANCE WITH ERISA. (i) Terminate, or permit any of its ERISA Affiliates to terminate, any ERISA Plan so as to result in any liability of the Borrower or any Principal Subsidiary to the PBGC in an amount greater than $1,000,000, or (ii) permit to exist any occurrence of any Reportable Event (as defined in Title IV of ERISA) which, alone or together with any other Reportable Event with respect to the same or another ERISA Plan, has a reasonable possibility of resulting in liability of the Borrower or any Principal Subsidiary to the PBGC in an aggregate amount exceeding $1,000,000, or any other event or condition which presents a material risk of such a termination by the PBGC of any ERISA Plan or has a reasonable possibility of resulting in a liability of the Borrower or any Principal Subsidiary to the PBGC or any withdrawal liability to an ERISA Multiemployer Plan in an aggregate amount exceeding $1,000,000. (c) ACCOUNTING CHANGES. Make any change in its accounting policies or reporting practices except as required or permitted by the Securities and Exchange Commission, the Financial Accounting Standards Board or any other generally recognized accounting authority. (e) TRANSACTIONS WITH AFFILIATES. Engage in any transaction with any Affiliate except (i) in accordance with the Public Utility Holding Company Act of 1935, to the extent applicable thereto or (ii) on terms no less favorable to the Borrower or the Principal Subsidiary party thereto than if the transaction had been negotiated in good faith on an arms-length basis with a non-Affiliate and on commercially reasonable terms or pursuant to a binding agreement in effect on the Closing Date. 40 (f) ISSUANCE OF FIRST MORTGAGE BONDS. In the case of CL&P and WMECO only, issue any First Mortgage Bonds on or after the Closing Date, whether in addition to First Mortgage Bonds outstanding on the Closing Date or in replacement of First Mortgage Bonds redeemed, retired, defeased, repaid or prepaid on or after the Closing Date. (g) INTERESTS IN NUCLEAR PLANTS. Acquire any nuclear plant or any interest therein not held on the Closing Date, other than so-called "power entitlements" acquired for use in the ordinary course of business. (h) DEBT. Create, incur, assume or suffer to exist, any Debt of NU, NU Enterprises, Inc. or any Subsidiary of NU Enterprises, Inc., other than (i) Debt under the Loan Documents; (ii) other Debt in existence on the Closing Date, excluding any extension, renewal or replacement thereof; (iii) Debt arising under the Revolving Credit Agreement, (iv) Debt resulting from the issuance of debt-like instruments by NU for stock redemptions and repurchases in connection with the acquisition of YES in an amount not to exceed $215,000,000; (v) non-recourse Debt of the Northeast Generation Company; (vi) Parent Support Obligations in an amount not to exceed $350,000,000 at any one time outstanding; (vii) Debt incurred by HEC Inc. in connection with the Portsmouth Naval Shipyard Project, and other Debt of HEC Inc. in an aggregate principal amount not to exceed $25,000,000; and (viii) in the case of NU Enterprises, Inc. and its Subsidiaries, Debt owing to NU, NU Enterprises, Inc. or the NU System Money Pool. (i) INVESTMENTS. With respect to the Borrower only, purchase, hold or acquire any capital stock, evidences of indebtedness or other securities (including any option, warrant or other right to acquire any of the foregoing) of, make or permit to exist any loans or advances to, guarantee any obligations of, or make or permit to exist any investment or any other interest in, any other Person, or purchase or otherwise acquire (in one transaction or a series of transactions) any assets of any other Person constituting a business unit (each of the foregoing, an "INVESTMENT"), except (i) the NGC Equity Contribution; (ii) equity and debt investments in (including NU System Money Pool advances to) Select Energy Inc. in an aggregate amount not to exceed $100,000,000; (iii) NU System Money Pool advances (other than to Select Energy Inc.) in an aggregate amount not to exceed $50,000,000 at any one time outstanding; (iv) other debt and equity investments in Subsidiaries of the Borrower (other than NU System Money Pool advances and other than in Select Energy Inc.) in an aggregate amount not to exceed $50,000,000 from and after the Closing Date; (v) the issuance of up to $25,000,000 in construction completion and similar performance guaranties on behalf of HEC Inc. from and after the Closing Date; (vi) Investments permitted by subsections (b) and (h) above; (vii) Investments other than (A) those enumerated in clauses (i) through (vi) above and (B) NU System Money Pool Advances, in each case, made prior to the Closing Date; and (viii) Permitted Investments. (j) RESTRICTED PAYMENTS. With respect to the Borrower only, declare or make, or agree to pay or make, directly or indirectly, any Restricted Payment, except that the Borrower may (i) pay dividends to its common stockholders in an aggregate amount not to exceed $53,000,000 during any 12-month period beginning or ending on the Closing Date or any day thereafter until and including the Termination Date, and (ii) redeem or repurchase capital stock for an aggregate amount not in excess of $215,000,000 in connection with the acquisition of YES 41 (k) FINANCING AGREEMENTS. With respect to the Borrower only, permit any Principal Subsidiary to enter into any agreement, contract, indenture or similar obligation, or issue any security (all of the foregoing being referred to as "FINANCING AGREEMENTS"), that is not in effect on the Closing Date, or amend or modify any existing Financing Agreement, if the effect of such Financing Agreement (or amendment or modification thereof) is to impose any additional restriction not in effect on the Closing Date on the ability of such Principal Subsidiary to pay dividends to the Borrower; provided, that the foregoing shall not restrict the right of Northeast Generation Company, or any other Subsidiary of the Borrower created to hold generating assets, to enter into any such Financing Agreement in connection with the incurrence of nonrecourse Debt to acquire, construct or otherwise develop generating assets. SECTION 7.03. FINANCIAL COVENANTS. On and after the Closing Date, so long as any Note shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower shall, unless the Majority Lenders shall otherwise consent in writing: (a) COMMON EQUITY RATIO. Maintain at all times a ratio of Common Equity to Total Capitalization of at least 0.30:1:00. (b) INTEREST COVERAGE RATIO. Maintain, as of the end of each Fiscal Quarter, with respect to the four Fiscal Quarters then ended, a ratio of Consolidated Operating Income to Consolidated Interest Expense of at least 2.00:1:00. (c) CASH FLOW RATIO. Maintain, as of the end of each Fiscal Quarter commencing with the Fiscal Quarter ending March 31, 2000, with respect to the four Fiscal Quarters then ended (or such fewer number of quarterly periods that shall have ended on or after March 31, 2000), a ratio of Operating Cash Flow to Fixed Charges of at least 1.50:1.00. SECTION 7.04. REPORTING OBLIGATIONS. So long as any Note shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower shall, unless the Majority Lenders shall otherwise consent in writing, furnish or cause to be furnished to the Administrative Agent in sufficient copies for each Lender, the following: (i) as soon as possible and in any event within ten days after the occurrence of each Event of Default or Unmatured Default continuing on the date of such statement, a statement of the Chief Financial Officer, Treasurer or Assistant Treasurer of the Borrower setting forth details of such Event of Default or Unmatured Default and the action which the Borrower proposes to take with respect thereto; (ii) (A) as soon as available, and in any event within fifty (50) days after the end of each of the first three Fiscal Quarters of each Fiscal Year of the Borrower, a copy of the Borrower's and each of its Principal Subsidiary's Quarterly Reports on Form 10-Q submitted to the Securities and Exchange Commission with respect to such quarter, or, if the Borrower or Select Energy, Inc. ceases to be required to submit such report, consolidated and unconsolidated balance sheets of the Borrower or Select Energy, Inc., as the case may be, as of the end of such Fiscal Quarter and consolidated and unconsolidated statements of income and retained earnings and of cash flows of the Borrower or Select 42 Energy, Inc., as the case may be, for the period commencing at the end of the previous Fiscal Year and ending with the end of such Fiscal Quarter, all in reasonable detail and duly certified (subject to year-end audit adjustments) by the Chief Financial Officer, Treasurer, Assistant Treasurer or Comptroller of the Borrower or Select Energy, Inc., as the case may be, as having been prepared in accordance with generally accepted accounting principles consistent with those applied in the preparation of the Financial Statements; and (B) concurrently with the delivery of the financial statements described in the foregoing clause (a), a certificate of the Chief Financial Officer, Treasurer, Assistant Treasurer or Comptroller of the Borrower: (1) to the effect that such financial statements were prepared in accordance with generally accepted accounting principles consistent with those applied in the preparation of the Financial Statements, (2) stating that no Event of Default or Unmatured Default has occurred and is continuing or, if an Event of Default or Unmatured Default has occurred and is continuing, describing the nature thereof and the action which the Borrower proposes to take with respect thereto, and (3) demonstrating the Borrower's compliance with the covenants set forth in Section 7.03 hereof, for and as of the end of such Fiscal Quarter, in each case such demonstrations to be in form satisfactory to the Administrative Agent and to set forth in reasonable detail the computations used in determining such compliance; (iii) (A) as soon as available, and in any event within 105 days after the end of each Fiscal Year of the Borrower, a copy of the Borrower's and each of its Principal Subsidiary's Annual Reports on Form 10-K submitted to the Securities and Exchange Commission with respect to such Fiscal Year, or, if the Borrower or Select Energy, Inc. ceases to be required to submit such report, a copy of the annual audit report for such year for the Borrower or Select Energy, Inc., as the case may be, including therein consolidated and unconsolidated balance sheets of the Borrower or Select Energy, Inc., as the case may be, as of the end of such Fiscal Year and consolidated and unconsolidated statements of income and retained earnings and of cash flows of the Borrower or Select Energy, Inc., as the case may be, for such Fiscal Year, all in reasonable detail and certified by a nationally-recognized independent public accountant; and (B) concurrently with the delivery of the financial statements described in the foregoing clause (A), a certificate of the Chief Financial Officer, Treasurer, Assistant Treasurer or Comptroller of the Borrower: (1) to the effect that such financial statements were prepared in accordance with generally accepted accounting principles consistent with those applied in the preparation of the Financial Statements, and 43 (2) stating that no Event of Default or Unmatured Default has occurred and is continuing, or if an Event of Default or Unmatured Default has occurred and is continuing, describing the nature thereof and the action which the Borrower proposes to take with respect thereto, and (3) demonstrating the Borrower's compliance with the covenants set forth in Section 7.03 hereof, for and as of the end of such Fiscal Year, in each case such demonstrations to be in form satisfactory to the Administrative Agent and to set forth in reasonable detail the computations used in determining such compliance; (iv) upon the reasonable request of the Administrative Agent, but not more than once per Fiscal Quarter, copies of any or all filings or registrations with, or notices or reports to, any regulatory authority by the Borrower or any Principal Subsidiary; (v) promptly upon becoming aware that any of its or any of its Principal Subsidiaries' material businesses and operations is reasonably likely be affected by the Year 2000 Issue, a detailed description of the nature of such circumstances and the actions which the Borrower proposes to take with respect thereto, except where the effect of the Year 2000 Issue would not be reasonably likely to have a material adverse effect on the financial condition, properties, prospects or operations of the Borrower or of the Borrower and the Principal Subsidiaries, taken as a whole; (vi) as soon as possible and in any event (A) within 30 days after the Chief Financial Officer, Treasurer or any Assistant Treasurer of the Borrower knows or has reason to know that any ERISA Plan Termination Event described in clause (i) of the definition of ERISA Plan Termination Event with respect to any ERISA Plan or ERISA Multiemployer Plan has occurred and (B) within 10 days after the Borrower knows or has reason to know that any other ERISA Plan Termination Event with respect to any ERISA Plan or ERISA Multiemployer Plan has occurred, a statement of the Chief Financial Officer, Treasurer or Assistant Treasurer of the Borrower describing such ERISA Plan Termination Event and the action, if any, which the Borrower proposes to take with respect thereto; (vii) promptly after receipt thereof by the Borrower or any of its ERISA Affiliates from the PBGC, copies of each notice received by the Borrower or any such ERISA Affiliate of the PBGC's intention to terminate any ERISA Plan or ERISA Multiemployer Plan or to have a trustee appointed to administer any ERISA Plan or ERISA Multiemployer Plan; (viii) promptly after receipt thereof by the Borrower or any of its ERISA Affiliates from an ERISA Multiemployer Plan sponsor, a copy of each notice received by the Borrower or any of its ERISA Affiliates concerning the imposition or amount of withdrawal liability in an aggregate principal amount of at least $10,000,000 pursuant to Section 4202 of ERISA in respect of which the Borrower may be liable; 44 (ix) promptly after the Borrower becomes aware of the commencement thereof, notice of all actions, suits, proceedings or other events of the type described in Section 6.01(h) hereof (including, without limitation, any action or proceeding relating to any environmental protection laws or regulations); (x) promptly after the filing thereof, copies of each prospectus (excluding any prospectus contained in any Form S-8) and Current Report on Form 8-K, if any, which the Borrower or any Principal Subsidiary files with the Securities and Exchange Commission or any successor governmental authority; and (xi) promptly after requested, such other information respecting the financial condition, operations, properties or prospects of the Borrower or its Subsidiaries as the Administrative Agent, or the Majority Lenders through the Administrative Agent, may from time to time reasonably request in writing. ARTICLE VIII DEFAULTS SECTION 8.01. EVENTS OF DEFAULT. The following events shall each constitute an "EVENT OF Default": (a) The Borrower shall fail to pay any principal of any Note when due or shall fail to pay any interest on any Note or fees or other amounts payable under the Loan Documents within two days after the same becomes due; or (c) Any representation or warranty made by the Borrower (or any of its officers or agents) in any Loan Document, any certificate or other writing delivered pursuant hereto or thereto shall prove to have been incorrect in any material respect when made or deemed made; or (c) The Borrower shall fail to perform or observe any term or covenant on its part to be performed or observed contained in Section 7.01(d), Section 7.02, Section 7.03 or Section 7.04(i) hereof; or (d) The Borrower shall fail to perform or observe any other term or covenant on its part to be performed or observed contained in any Loan Document and any such failure shall remain unremedied for a period of 30 days after the earlier of (i) written notice of such failure having been given to the Borrower by the Administrative Agent or (ii) the Borrower having obtained actual knowledge of such failure; or (e) The Borrower or any Principal Subsidiary shall fail to pay any of its Debt when due (including any interest or premium thereon but excluding Debt evidenced by the Notes and excluding other Debt (except for Named Debt) aggregating in no event more 45 than $10,000,000 in principal amount at any one time) whether by scheduled maturity, required prepayment, acceleration, demand or otherwise, and such failure shall continue after the applicable grace period, if any, specified in any agreement or instrument relating to such Debt; or any other default under any agreement or instrument relating to any such Debt, or any other event, shall occur and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such default or event is to accelerate, or to permit the acceleration of, the maturity of such Debt; or any such Debt shall be declared to be due and payable, or required to be prepaid (other than by a regularly scheduled required prepayment or as a result of the Borrower's or such Principal Subsidiary's exercise of a prepayment option) prior to the stated maturity thereof; or (f) The Borrower or any Principal Subsidiary shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make an assignment for the benefit of creditors; or any proceeding shall be instituted by or against the Borrower or any Principal Subsidiary seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of its debts under any law relating to bankruptcy, insolvency, or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, or other similar official for it or for any substantial part of its property and, in the case of a proceeding instituted against the Borrower or any Principal Subsidiary, the Borrower or such Principal Subsidiary shall consent thereto or such proceeding shall remain undismissed or unstayed for a period of 90 days or any of the actions sought in such proceeding (including without limitation the entry of an order for relief against the Borrower or such Principal Subsidiary or the appointment of a receiver, trustee, custodian or other similar official for the Borrower or such Principal Subsidiary or any of its property) shall occur; or the Borrower or any Principal Subsidiary shall take any corporate or other action to authorize any of the actions set forth above in this subsection (f); or (g) Any judgments or orders for the payment of money in excess of $10,000,000 (or aggregating more than $10,000,000 at any one time) shall be rendered against the Borrower or its properties or any Principal Subsidiary or its properties, and either (A) enforcement proceedings shall have been commenced by any creditor upon such judgment or order and shall not have been stayed or (B) there shall be any period of 15 consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or (h) Any material provision of any Loan Document shall at any time for any reason cease to be valid and binding on the Borrower, or shall be determined to be invalid or unenforceable by any court, governmental agency or authority having jurisdiction over the Borrower, or the Borrower shall deny that it has any further liability or obligation under any Loan Document; or (i) A Change of Control shall have occurred; or 46 (j) The Borrower shall cease to own at least 85% of the outstanding common stock of any Principal Subsidiary, free and clear of all Liens except for Liens permitted by Section 7.02(a) hereof; or (k) Any legal restriction that is not in existence on the Closing Date shall materially adversely affect the ability of any Principal Subsidiary to pay dividends or make other distributions to the Borrower. SECTION 8.02. REMEDIES UPON EVENTS OF DEFAULT. Upon the occurrence and during the continuance of any Event of Default, the Administrative Agent shall at the request, or may with the consent, of the Lenders entitled to make such request, upon notice to the Borrower (i) declare the obligation of each Lender to make Advances to the Borrower to be terminated, whereupon such obligations of the Lenders shall forthwith terminate, provided, that any such request or consent pursuant to this clause (i) shall be made solely by Lenders having Percentages in the aggregate of not less 66-2/3%; (ii) declare the Notes of the Borrower, all interest thereon and all other amounts payable by the Borrower under this Agreement and the other Loan Documents to be forthwith due and payable, whereupon such Notes, all such interest and all such amounts shall become and be forthwith due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Borrower, provided, that any such request or consent pursuant to this clause (ii) shall be made solely by the Lenders holding at least 66-2/3% of the then aggregate Outstanding Credits; provided, however, that if such Event of Default is an Event of Default pursuant to subsection (f) of Section 8.01, then (A) the obligation of each Lender to make Advances to the Borrower shall automatically be terminated and (B) the Notes of the Borrower, all interest thereon and all other amounts payable by the Borrower under this Agreement and the other Loan Documents shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by the Borrower. ARTICLE IX THE ADMINISTRATIVE AGENT SECTION 9.01. AUTHORIZATION AND ACTION. Each Lender hereby appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under this Agreement as are delegated to the Administrative Agent by the terms hereof, together with such powers as are reasonably incidental thereto. As to any matters not expressly provided for by the Loan Documents (including, without limitation, enforcement or collection thereof), the Administrative Agent shall not be required to exercise any discretion or take any action, but shall be required to act or to refrain from acting (and shall be fully protected in so acting or refraining from acting) upon the instructions of the Majority Lenders, and such instructions shall be binding upon all Lenders; provided, however, that the Administrative Agent shall not be required to take any action which exposes the Administrative Agent to personal liability or which is contrary to the Loan Documents or applicable law. The Administrative Agent 47 agrees to deliver promptly to each Lender notice of each notice given to it by the Borrower pursuant to the terms of this Agreement. SECTION 9.02. ADMINISTRATIVE AGENT'S RELIANCE, ETC. Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be liable for any action taken or omitted to be taken by it or them under or in connection with any Loan Document, except for its or their own gross negligence or willful misconduct. Without limitation of the generality of the foregoing, the Administrative Agent: (i) may treat the payee of any Note as the holder thereof until the Administrative Agent receives and accepts a Lender Assignment entered into by the Lender which is the payee of such Note, as assignor, and an assignee, as provided in Section 10.07; (ii) may consult with legal counsel (including counsel for the Borrower), independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by it in accordance with the advice of such counsel, accountants or experts; (iii) makes no warranty or representation to any Lender and shall not be responsible to any Lender for any statements, warranties or representations made in or in connection with any Loan Document; (iv) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of any Loan Document on the part of the Borrower to be performed or observed, or to inspect any property (including the books and records) of the Borrower; (v) shall not be responsible to any Lender for the due execution, legality, validity, enforceability, genuineness, sufficiency or value of any Loan Document or any other instrument or document furnished pursuant hereto; and (vi) shall incur no liability under or in respect of any Loan Document by acting upon any notice, consent, certificate or other instrument or writing (which may be by facsimile) believed by it to be genuine and signed or sent by the proper party or parties. SECTION 9.03. CIBC AND ITS AFFILIATES. With respect to its Commitment and the Note issued to it, CIBC shall have the same rights and powers under the Loan Documents as any other Lender and may exercise the same as though it were not the Administrative Agent, and the term "Lender" or "Lenders" shall, unless otherwise expressly indicated, include CIBC in its individual capacity. CIBC and its Affiliates may accept deposits from, lend money to, act as trustee under indentures of, and generally engage in any kind of business with, the Borrower, any of its Subsidiaries and any Person who may do business with or own securities of the Borrower or any such Subsidiary, all as if CIBC were not the Administrative Agent and without any duty to account therefore to the Lenders. SECTION 9.04. LENDER CREDIT DECISION. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender and based on the Financial Statements and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement. SECTION 9.05. INDEMNIFICATION. The Lenders agree to indemnify the Administrative Agent (to the extent not reimbursed by the Borrower), ratably according to the respective 48 principal amounts of the Notes then held by each of them (or if no Notes are at the time outstanding, ratably according to the respective Commitments of the Lenders; if any Notes or Commitments are held by the Borrower or any Affiliate thereof, any ratable apportionment hereunder shall exclude the principal amount of the Notes held by the Borrower or such Affiliate or their respective Commitments (if any) hereunder), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever which may be imposed on, incurred by, or asserted against the Administrative Agent in its capacity as such in any way relating to or arising out of any Loan Document or any action taken or omitted by the Administrative Agent in its capacity as such under any Loan Document, provided that no Lender shall be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Administrative Agent's gross negligence or willful misconduct. Without limitation of the foregoing, each Lender agrees to reimburse the Administrative Agent promptly upon demand for such Lender's ratable share of any out-of-pocket expenses (including counsel fees) incurred by the Administrative Agent in connection with the preparation, execution, delivery, administration, modification, amendment or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice in respect of rights or responsibilities under, the Loan Documents to the extent that the Administrative Agent is entitled to reimbursement for such expenses pursuant to Section 10.04 but is not reimbursed for such expenses by the Borrower. SECTION 9.06. SUCCESSOR ADMINISTRATIVE AGENT. The Administrative Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower, with any such resignation to become effective only upon the appointment of a successor Administrative Agent pursuant to this Section 9.06. Upon any such resignation, the Majority Lenders shall have the right to appoint a successor Administrative Agent, which shall be a Lender or another commercial bank or trust company reasonably acceptable to the Borrower organized or licensed under the laws of the United States, or of any State thereof. If no successor Administrative Agent shall have been so appointed by the Majority Lenders, and shall have accepted such appointment, within 30 days after the retiring Administrative Agent's giving of notice of resignation, then the retiring Administrative Agent may, on behalf of the Lenders, appoint a successor Administrative Agent, which shall be Lender or shall be another commercial bank or trust company organized or licensed under the laws of the United States or of any State thereof reasonably acceptable to the Borrower. In addition to the foregoing right of the Administrative Agent to resign, the Majority Lenders may remove the Administrative Agent at any time, with or without cause, concurrently with the appointment by the Majority Lenders of a successor Administrative Agent. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor Administrative Agent, such successor Administrative Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations under this Agreement. After any retiring Administrative Agent's resignation or removal hereunder as Administrative Agent, the provisions of this Article IX shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent under the Loan Documents. SECTION 9.07. OTHER AGENTS. Neither The Bank of New York, by virtue of its designation as "Documentation Agent", nor Fleet National Bank, by virtue of its designation as 49 "Syndication Agent", shall have any duties, liabilities, obligations or responsibilities under this Agreement other than as a Lender hereunder. ARTICLE X MISCELLANEOUS SECTION 10.01. AMENDMENTS, ETC. No amendment or waiver of any provision of any Loan Document, nor consent to any departure by the Borrower therefrom, shall in any event be effective unless the same shall be in writing and signed by the Majority Lenders, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no amendment, waiver or consent shall, unless in writing and signed by all the Lenders, do any of the following: (a) waive, modify or eliminate any of the conditions specified in Article V, (b) increase the Commitment of any Lender hereunder or increase the Commitments of the Lenders that may be maintained hereunder or subject the Lenders to any additional obligations, (c) reduce the principal of, or interest on, the Notes, any Applicable Margin or any fees or other amounts payable hereunder, (d) postpone any date fixed for any payment of principal of, or interest on, the Notes or any fees or other amounts payable under the Loan Documents, (e) change the percentage of the Commitments or of the aggregate unpaid principal amount of the Notes, or the number of Lenders which shall be required for the Lenders or any of them to take any action under the Loan Documents, (f) amend any Loan Document in a manner intended to prefer one or more Lenders over any other Lenders, or (g) amend this Section 10.01; provided, that no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent, in addition to the Lenders required above to take such action, affect the rights or duties of the Administrative Agent under any Loan Document. SECTION 10.02. NOTICES, ETC. Except as otherwise expressly provided herein, all notices and other communications provided for under the Loan Documents shall be in writing (including facsimile communication) and mailed, sent by facsimile or hand delivered: (i) if to the Borrower, to it in care of NUSCO at 107 Selden Street, Berlin, Connecticut 06037, Attention: Assistant Treasurer, facsimile number: (860) 665-5457, confirm number: (860) 665-3258; (ii) if to any Bank, at its Domestic Lending Office specified opposite its name on Schedule I hereto; (iii) if to any Lender other than a Bank, at its Domestic Lending Office specified in the Lender Assignment pursuant to which it became a Lender; and 50 (iv) if to the Administrative Agent, at its address at 425 Lexington Avenue, New York, New York 10017, Attention: Agency Services, facsimile number: (212) 856-3691, confirm number: (212) 856-3763. or, as to each party, at such other address as shall be designated by such party in a written notice to the other parties. All such notices and communications shall, when mailed, sent by facsimile or hand delivered, be effective five days after when deposited in the mails, or when sent by facsimile, or when delivered, respectively, except that notices and communications to the Administrative Agent pursuant to Article II, III, IV or IX shall not be effective until received by the Administrative Agent. With respect to any telephone notice given or received by the Administrative Agent pursuant to Section 3.03 hereof, the records of the Administrative Agent shall be conclusive for all purposes. SECTION 10.03. NO WAIVER OF REMEDIES. No failure on the part of the Administrative Agent or any Lender to exercise, and no delay in exercising, any right under any Loan Document shall operate as a waiver thereof; nor shall any single or partial exercise of any such right preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law. SECTION 10.04. COSTS, EXPENSES AND INDEMNIFICATION. (a) The Borrower agrees to pay when due, in accordance with the terms hereof: (i) all costs and expenses of the Administrative Agent in connection with the preparation, negotiation, execution and delivery of the Loan Documents, the administration of the Loan Documents, and any proposed modification, amendment, or consent relating thereto (including, in each case, the reasonable fees and expenses of counsel to the Administrative Agent); and (ii) all costs and expenses of the Administrative Agent and each Lender (including all fees and expenses of counsel) in connection with the enforcement, whether through negotiations, legal proceedings or otherwise, of the Loan Documents. (b) The Borrower hereby agrees to indemnify and hold the Administrative Agent and each Lender, and its officers, directors, employees, professional advisors and affiliates (each, an "INDEMNIFIED PERSON") harmless from and against any and all claims, damages, losses, liabilities, costs or expenses (including reasonable attorney's fees and expenses, whether or not such Indemnified Person is named as a party to any proceeding or investigation or is otherwise subjected to judicial or legal process arising from any such proceeding or investigation) which any of them may incur or which may be claimed against any of them by any person or entity (except to the extent such claims, damages, losses, liabilities, costs or expenses arise from the gross negligence or willful misconduct of the Indemnified Person): (i) by reason of or in connection with the execution, delivery or performance of the Loan Documents or any transaction contemplated thereby, or the use by the Borrower of the proceeds of any Advance; (ii) in connection with or resulting from the utilization, storage, disposal, treatment, generation, transportation, release or ownership of any Hazardous Substance 51 (A) at, upon or under any property of the Borrower or any of its Affiliates or (B) by or on behalf of the Borrower or any of its Affiliates at any time and in any place; or (iii) in connection with any documentary taxes, assessments or charges made by any governmental authority by reason of the execution and delivery of the Loan Documents. (c) The Borrower's obligations under this Section 10.04 shall survive the assignment by any Lender pursuant to Section 10.07 hereof and shall survive as well the repayment of all amounts owing to the Lenders under the Loan Documents and the termination of the Commitments. If and to the extent that the obligations of the Borrower under this Section 10.04 are unenforceable for any reason, the Borrower agrees to make the maximum contribution to the payment and satisfaction thereof which is permissible under applicable law. (d) The Borrower's obligations under this Section 10.04 are in addition to and shall not be deemed to supersede its indemnification and similar obligations set forth in that certain Commitment Letter dated as of February 15, 2000 between the Borrower and CIBC. SECTION 10.05. RIGHT OF SET-OFF. (a) Upon (i) the occurrence and during the continuance of any Event of Default, and (ii) the making of the request or the granting of the consent specified by Section 8.02 to authorize the Administrative Agent to declare the Notes due and payable pursuant to the provisions of Section 8.02, each Lender is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Lender to or for the credit or the account of the Borrower against any and all of the obligations of the Borrower now or hereafter existing under the Loan Documents held by such Lender, irrespective of whether or not such Lender shall have made any demand under the Loan Documents or such Notes and although such obligations may be Unmatured. Each Lender agrees promptly to notify the Borrower after any such set-off and application made by such Lender, provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of each Lender under this Section are in addition to other rights and remedies (including, without limitation, other rights of set-off) which such Lender may have. (b) The Borrower agrees that it shall have no right of off-set, deduction or counterclaim in respect of its obligations under the Loan Documents, and that the obligations of the Lenders hereunder are several and not joint. Nothing contained herein shall constitute a relinquishment or waiver of the Borrower's rights to any independent claim that the Borrower may have against the Administrative Agent or any Lender, but no Lender shall be liable for the conduct of the Administrative Agent or any other Lender, and the Administrative Agent shall not be liable for the conduct of the other or any Lender. SECTION 10.06. BINDING EFFECT. This Agreement shall become effective when it shall have been executed by the Borrower and the Administrative Agent and when the Administrative Agent shall have been notified by each Bank that such Bank has executed it and 52 thereafter shall be binding upon and inure to the benefit of the Borrower, the Administrative Agent and each Lender and their respective successors and assigns, except that the Borrower shall not have the right to assign its rights under the Loan Documents or any interest herein without the prior written consent of the Lenders. SECTION 10.07. ASSIGNMENTS AND PARTICIPATION. (a) Each Lender may assign to one or more banks or other entities all or a portion of its rights and obligations under the Loan Documents, including, without limitation, all or a portion of its Commitment, the Advances owing to it, and the Note or Notes held by it (with the prior written consent of the Borrower and the Administrative Agent if the assignee thereunder is not then a Lender or an Affiliate of a Lender, which consent shall not be unreasonably withheld); provided, however, that (i) each such assignment shall be of a constant, and not a varying, percentage of all of the assigning Lender's rights and obligations under the Loan Documents, (ii) if the assignee thereunder is not then a Lender or an Affiliate of a Lender, the amount of the Commitment, Advance or Note being assigned pursuant to each such assignment shall in no event be less than the lesser of the amount of the assigning Lender's Commitment and $5,000,000, and (iii) the parties to each such assignment shall execute and deliver to the Administrative Agent, for its acceptance and recording in the Register, an assignment and acceptance in substantially the form of Exhibit 10.07 hereto (the "LENDER ASSIGNMENT"), together with any Note or Notes subject to such assignment and a processing and recordation fee of $3,500. Upon such execution, delivery, acceptance and recording, from and after the effective date specified in each Lender Assignment, which effective date shall be at least five Business Days after the execution thereof, (x) the assignee thereunder shall be a party hereto and, to the extent that rights and obligations under the Loan Documents have been assigned to it pursuant to such Lender Assignment, have the rights and obligations of a Lender under the Loan Documents and (y) the Lender assignor thereunder shall, to the extent that rights and obligations under the Loan Documents have been assigned by it to an assignee pursuant to such Lender Assignment, relinquish its rights and be released from its obligations under the Loan Documents (and, in the case of a Lender Assignment covering all or the remaining portion of an assigning Lender's rights and obligations under the Loan Documents, such Lender shall cease to be a party to the Loan Documents); provided, however, if an Event of Default shall have occurred and be continuing a Lender may assign all or a portion of its rights and obligations without the prior written consent of the Borrower but otherwise in accordance with this Section. (b) By executing and delivering a Lender Assignment, the Lender assignor thereunder and the assignee thereunder confirm to and agree with each other and the other parties hereto as follows: (i) other than as provided in such Lender Assignment, such assigning Lender makes no representation or warranty and assumes no responsibility with respect to any statements, warranties or representations made in or in connection with the Loan Documents or the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any other instrument or document furnished pursuant thereto; (ii) such assigning Lender makes no representation or warranty and assumes no responsibility with respect to the financial condition of the Borrower or the performance or observance by the Borrower of any of its obligations under the Loan Documents or any other instrument or document furnished pursuant thereto; (iii) such assignee confirms that it has received a copy of the Loan Documents, 53 together with copies of the Financial Statements, or the latest financial statements delivered by the Borrower to the Administrative Agent pursuant to Section 7.04 hereof, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into such Lender Assignment; (iv) such assignee will, independently and without reliance upon the Administrative Agent, such assigning Lender or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents; (v) such assignee appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under the Loan Documents as are delegated to the Administrative Agent by the terms thereof, together with such powers as are reasonably incidental thereto; and (vi) such assignee agrees that it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender. (c) The Administrative Agent shall maintain at its address referred to in Section 10.02 a copy of each Lender Assignment delivered to and accepted by it and a register for the recordation of the names and addresses of the Lenders and the Commitment of, and principal amount of the Advances owing to, each Lender from time to time (the "REGISTER"). The entries in the Register shall be conclusive and binding for all purposes, absent manifest error, and the Borrower, the Administrative Agent and the Lenders may treat each Person whose name is recorded in the Register as a Lender hereunder for all purposes of the Loan Documents. The Register shall be available for inspection by the Borrower or any Lender at any reasonable time and from time to time upon reasonable prior notice. (d) Upon its receipt of a Lender Assignment executed by an assigning Lender and an assignee, together with any Note or Notes subject to such assignment, the Administrative Agent shall, if such Lender Assignment has been completed and is in substantially the form of Exhibit 10.07 hereto, (i) accept such Lender Assignment, (ii) record the information contained therein in the Register and (iii) give prompt notice thereof to the Borrower. Within five Business Days after its receipt of such notice, the Borrower, at its own expense, shall execute and deliver to the Administrative Agent in exchange for the surrendered Note or Notes a new Note or Notes to the order of such assignee in an amount equal to the Commitment and/or Advances assumed by it pursuant to such Lender Assignment and, if the assigning Lender has retained a Commitment and/or Advances hereunder, a new Note or Notes to the order of the assigning Lender in an amount equal to the Commitment and/or Advances retained by it hereunder. Such new Note or Notes shall be in an aggregate principal amount equal to the aggregate principal amount of such surrendered Note or Notes, shall be dated the effective date of such Lender Assignment and shall otherwise be in substantially the form of Exhibit 1.01A hereto. (e) Each Lender may sell Participations to one or more banks or other entities in or to all or a portion of its rights and obligations under the Loan Documents (including, without limitation, all or a portion of its Commitment, the Advances owing to it or the Note or Notes held by it); provided, however, that (i) such Lender's obligations under the Loan Documents (including, without limitation, its Commitment hereunder) shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, (iii) such Lender shall remain the holder of any such Note for all purposes of the Loan Documents, (iv) the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely 54 and directly with such Lender in connection with such Lender's rights and obligations under the Loan Documents, and (v) the holder of any such participation, other than an Affiliate of such Lender, shall not be entitled to require such Lender to take or omit to take any action under the Loan Documents, except action (A) reducing the principal of, or interest on, the Notes, any Applicable Margin or any fees or other amounts payable under the Loan Documents, or (B) postponing any date fixed for any payment of principal of, or interest on, the Notes or any fees or other amounts payable under the Loan Documents. (f) Any Lender may, in connection with any assignment or participation or proposed assignment or proposed participation pursuant to this Section 10.07, disclose to the assignee or participant or proposed assignee or proposed participant, any information relating to the Borrower furnished to such Lender by or on behalf of the Borrower; provided that, prior to any such disclosure, the assignee or participant or proposed assignee or participant shall agree, in accordance with the terms of Section 10.08, to preserve the confidentiality of any Confidential Information received by it from such Lender. (g) If any Lender shall have delivered a notice to the Administrative Agent described in Section 4.03(a), (b), (c) or (f) hereof, or shall become a non-performing Lender under Section 3.03(b) hereof, and if and so long as such Lender shall not have withdrawn such notice or corrected such non-performance in accordance with Section 3.03(b), the Borrower may demand that such Lender assign, in accordance with Section 10.07 hereof, to one or more assignees designated by the Borrower or the Administrative Agent (and reasonably acceptable to the other), all (but not less than all) of such Lender's Commitment, Advances, participatory and other rights and obligations under the Loan Documents; provided that any such demand by the Borrower during the continuance of an Event of Default or an Unmatured Default shall be ineffective without the consent of the Majority Lenders. If, within 30 days following any such demand by the Borrower, any such assignee so designated shall fail to tender such assignment on terms reasonably satisfactory to the Borrower and the Borrower and the Administrative Agent shall have failed to designate any such assignee, then such demand by the Borrower shall become ineffective, it being understood for purposes of this provision that such assignment shall be conclusively deemed to be on terms reasonably satisfactory to such Lender, and such Lender shall be compelled to tender such assignment forthwith, if (i) such assignee (A) shall agree to such assignment in substantially the form of the Lender Assignment and (B) shall tender payment to such Lender in an amount equal to the full outstanding dollar amount accrued in favor of such Lender hereunder (as computed in accordance with the records of the Administrative Agent) and (ii) in the event the Borrower demanded such assignment, the Borrower shall tender payment to the Administrative Agent of the processing and recording fee specified in Section 10.07(a) for such assignment. (h) Anything in this Section 10.07 to the contrary notwithstanding, any Lender may assign and pledge all or any portion of its Commitment and the Advances owing to it to any Federal Reserve Bank (and its transferees) as collateral security pursuant to Regulation A of the Board of Governors of the Federal Reserve System and any Operating Circular issued by such Federal Reserve Bank. No such assignment shall release the assigning Lender from its obligations hereunder. 55 SECTION 10.08. CONFIDENTIALITY. In connection with the negotiation and administration of the Loan Documents, the Borrower has furnished or caused to have furnished and will from time to time furnish or cause to be furnished to the Administrative Agent and the Lenders (each, a "RECIPIENT") written information which when delivered to the Recipient will be deemed to be confidential (such information, other than any such information which (i) was publicly available, or otherwise known to the Recipient, at the time of disclosure, (ii) subsequently becomes publicly available other than through any act or omission by the Recipient or (iii) otherwise subsequently becomes known to the Recipient other than through a Person whom the Recipient knows to be acting in violation of his or its obligations to the Borrower, being hereinafter referred to as "CONFIDENTIAL INFORMATION"). The Recipient will not knowingly disclose any such Confidential Information to any third party (other than to those Persons who have a confidential relationship with the Recipient), and will take all reasonable steps to restrict access to such information in a manner designed to maintain the confidential nature of such information, in each case until such time as the same ceases to be Confidential Information or as the Borrower may otherwise instruct. It is understood, however, that the foregoing will not restrict the Recipient's ability to freely exchange such Confidential Information with prospective participants in or assignees of the Recipient's position herein, but the Recipient's ability to so exchange Confidential Information shall be conditioned upon any such prospective participant's entering into an understanding as to confidentiality similar to this provision. It is further understood that the foregoing will not prohibit the disclosure of any or all Confidential Information if and to the extent that such disclosure may be required (i) by a regulatory agency or otherwise in connection with an examination of the Recipient's records by appropriate authorities, (ii) pursuant to court order, subpoena or other legal process or (iii) otherwise, as required by law; in the event of any required disclosure under clause (ii) or (iii), above, the Recipient agrees to use reasonable efforts to inform the Borrower as promptly as practicable unless the Lender is prohibited from doing so by court order, subpoena or other legal process. SECTION 10.09. WAIVER OF JURY TRIAL. THE BORROWER, THE ADMINISTRATIVE AGENT AND EACH OF THE LENDERS HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR RELATING TO THE LOAN DOCUMENTS, OR ANY OTHER INSTRUMENT OR DOCUMENT DELIVERED HEREUNDER OR THEREUNDER. SECTION 10.10. GOVERNING LAW. THE LOAN DOCUMENTS SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK. The Borrower, each of the Lenders and the Administrative Agent: (i) irrevocably submits to the jurisdiction of any New York State Court or Federal court sitting in New York City in any action arising out of or relating to the Loan Documents, (ii) agrees that all claims in such action may be decided in such court, (iii) waives, to the fullest extent it may effectively do so, the defense of an inconvenient forum and (iv) consents to the service of process by mail. A final judgment in any such action shall be conclusive and may be enforced in other jurisdictions. Nothing herein shall affect the right of any party to serve legal process in any manner permitted by law or affect its right to bring any action in any other court. SECTION 10.11. RELATION OF THE PARTIES; NO BENEFICIARY. No term, provision or requirement, whether express or implied, of any Loan Document, or actions taken or to be taken by any party thereunder, shall be construed to create a partnership, association, or joint venture 56 between such parties or any of them. No term or provision of any Loan Document shall be construed to confer a benefit upon, or grant a right or privilege to, any Person other than the parties hereto. SECTION 10.12. EXECUTION IN COUNTERPARTS. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. SECTION 10.13. LIMITATION OF LIABILITY. No shareholder or trustee of NU shall be held to any liability whatever for the payment of any sum of money or for damages or otherwise under any Loan Document, and such Loan Documents shall not be enforceable against any such trustee in their or his or her individual capacities or capacity and such Loan Documents shall be enforceable against the trustees of NU only as such, and every person, firm, association, trust or corporation having any claim or demand arising under such Loan Documents and relating to NU, its shareholders or trustees shall look solely to the trust estate of NU for the payment or satisfaction thereof. S-1 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written. NORTHEAST UTILITIES By: /s/ RANDY A. SHOOP ----------------------------------- Name: Randy A. Shoop Title: Assistant Treasurer-Finance 57 S-2 Commitment: $66,500,000 CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY, as Bank and as Administrative Agent By: /s/ DENIS P. O'MEARA ----------------------------------- Name: Denis P. O'Meara Title: Executive Director CIBC World Markets Corp. As Agent S-3 Commitment: $66,500,000 BARCLAYS BANK PLC By /s/ SYDNEY G. DENNIS ------------------------------------ Name: Sydney G. Dennis Title: Director S-4 Commitment: $66,500,000 THE BANK OF NEW YORK, as Bank and as Documentation Agent By: /s/ JOHN W. HALL ----------------------------------- Name: John W. Hall Title: Vice President S-5 FLEET NATIONAL BANK, as Syndication Agent Commitment: $66,500,000 FLEET NATIONAL BANK, as Trust Administrator for LongLane Master Trust IV, as Bank By: /s/ ----------------------------------- Name: Title: 58 SCHEDULE I APPLICABLE LENDING OFFICES
NAME OF BANK DOMESTIC LENDING OFFICE EURODOLLAR LENDING OFFICE ------------ ----------------------- ------------------------- Barclays Bank PLC 75 Wall Street, 11th Floor 75 Wall Street, 11th Floor New York, NY 10265 New York, NY 10265 The Bank of New York One Wall Street One Wall Street New York, NY 10286 New York, NY 10286 Fleet National Bank, 100 Federal Street 100 Federal Street as Trust Administrator for Boston, MA 02110 Boston, MA 02110 LongLane Master Trust IV Canadian Imperial Bank of 425 Lexington Avenue 425 Lexington Avenue Commerce New York, NY 10017 New York, NY 10017
59 SCHEDULE II PENDING ACTIONS None. 60 EXHIBIT 1.01A FORM OF CONTRACT NOTE $ New York, New York March 1, 2000 FOR VALUE RECEIVED, the undersigned, NORTHEAST UTILITIES, an unincorporated voluntary business association organized under the laws of the Commonwealth of Massachusetts (the "BORROWER"), hereby promises to pay to the order of [___________] (the "LENDER"), on the Termination Date (as defined in the Credit Agreement referred to below), the lesser of the principal sum of [_____________________] DOLLARS ($___________) and the aggregate unpaid principal amount of all Contract Advances made by the Lender to the Borrower pursuant to the Credit Agreement, in lawful money of the United States of America in immediately available funds, and to pay interest on such principal amount from time to time outstanding, in like funds, at a rate or rates per annum and payable with respect to such periods and on such dates as determined pursuant to the Credit Agreement. The Borrower promises to pay interest, on demand, on any overdue principal and overdue interest from their due dates at a rate or rates determined as set forth in the Credit Agreement. The Borrower hereby waives diligence, presentment, demand, protest and notice of any kind whatsoever. The nonexercise by the holder of any of its rights hereunder in any particular instance shall not constitute a waiver thereof in that or any subsequent instance. All borrowings evidenced by this Contract Note and all payments and prepayments of the principal hereof and interest hereon and the respective dates thereof shall be endorsed by the holder hereof on the schedule attached hereto and made a part hereof, or on a continuation thereof which shall be attached hereto and made a part hereof, or otherwise recorded by such holder in its internal records; provided, however, that any failure of the holder hereof to make such a notation or any error in such notation shall not in any manner affect the obligation of the 61 Borrower to make payments of principal and interest in accordance with the terms of this Contract Note and the Credit Agreement. This Contract Note is one of the Contract Notes referred to in the Term Loan Agreement, dated as of March 1, 2000 among the Borrower, the Lenders party thereto, Canadian Imperial Bank of Commerce, New York Agency, as Administrative Agent, The Bank of New York, as Documentation Agent, and Fleet National Bank, as Syndication Agent (as amended from time to time in accordance with its terms, the "CREDIT AGREEMENT") and is subject to the terms and conditions contained in the Credit Agreement and is entitled to the benefits thereof. The Credit Agreement, among other things, contains provisions for the acceleration of the maturity hereof upon the happening of certain events, for prepayment of the principal hereof prior to the maturity thereof and for the amendment or waiver of certain provisions of the Credit Agreement, all upon the terms and conditions therein specified. This Contract Note shall be construed in accordance with and governed by the laws of the State of New York and any applicable laws of the United States of America. No shareholder or trustee of the Borrower shall be held to any liability whatever for the payment of any sum of money or for damages or otherwise under this Contract Note, and this Contract Note shall not be enforceable against any such trustee in their or his or her individual capacities or capacity; this Contract Note shall be enforceable against the trustees of the Borrower only as such, and every, person, firm, association, trust or corporation having any claim or demand arising under this Contract Note relating to the Borrower, its shareholders or trustees shall look solely to the trust estate of the Borrower for payment or satisfaction thereof. NORTHEAST UTILITIES By /s/ ------------------------------------ Name: Title: GRID NOTE SCHEDULE - -------------------------------------------------------------------------------- DATE OF AMOUNT OF INTEREST INTEREST NUMBER INTEREST AMOUNT NOTED ADVANCE PRINCIPAL RATE PERIOD OF DAYS DUE PAID BY PAID DATE - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 62 EXHIBIT 3.01 (NU) FORM OF NOTICE OF CONTRACT BORROWING [Date]1 1 The Notice of Contract Borrowing must be received by the Administrative Agent (i) in the case of a proposed Contract Borrowing to consist of Eurodollar Rate Advances, by hand or facsimile not later than 11:00 a.m. (New York City time), three Business Days prior to the Funding Date and (ii) in the case of a proposed Contract Borrowing to consist of Base Rate Advances, by hand or facsimile not later than 11:00 a.m. (New York City time), on the Funding Date. Canadian Imperial Bank of Commerce, New York Agency as Administrative Agent for the Lenders party to the Credit Agreement referred to below 425 Lexington Avenue New York, NY 10017 Attention: ____________________ Ladies and Gentlemen: The undersigned, Northeast Utilities (the "BORROWER"), refers to the Term Loan Agreement, dated as of March 1, 2000 (as amended from time to time in accordance with its terms, the "CREDIT AGREEMENT"), among the Borrower, the Lenders party thereto, Canadian Imperial Bank of Commerce, New York Agency, as Administrative Agent, The Bank of New York, as Documentation Agent, and Fleet National Bank, as Syndication Agent. Capitalized terms used herein and not otherwise defined herein shall have the meanings assigned to such terms in the Credit Agreement. The undersigned hereby gives you notice pursuant to Section 3.01 of the Credit Agreement that it requests a Contract Borrowing under the Credit Agreement, and in that connection sets forth below the terms on which such Borrowing is requested to be made: (A) Date of proposed Contract Borrowing _____________________ (which is a Business Day) (B) Principal Amount _____________________ of Contract Borrowing Not less than $5,000,000 and in integral multiples of $1,000,000. (C) Type of Advance Eurodollar Rate Advance or Base Rate Advance. ---------------------- (D) Initial Interest Period _____________________ Upon acceptance of any or all of the Contract Advances requested in this Notice of Contract Borrowing, the undersigned shall be deemed to have represented and warranted that the conditions precedent to each Contract Advance applicable to it specified in Section 5.02(a) of the Credit Agreement have been satisfied. Very truly yours, NORTHEAST UTILITIES By________________________________ Name: Title: EXHIBIT 10.07 ASSIGNMENT AND ACCEPTANCE Dated , Reference is made to the Term Loan Agreement, dated as of March 1, 2000 (as amended from time to time in accordance with its terms, the "CREDIT AGREEMENT"), among Northeast Utilities (the "BORROWER"), the Lenders party thereto, Canadian Imperial Bank of Commerce, New York Agency, as Administrative Agent, The Bank of New York, as Documentation Agent, and Fleet National Bank, as Syndication Agent. Capitalized terms used herein and not defined shall have the meaning assigned to such terms in the Credit Agreement. Pursuant to the Credit Agreement, ________________ (the "ASSIGNOR") has committed to make advances ("ADVANCES") to the Borrower, which Advances are evidenced by the Contract Note issued by the Borrower to the Assignor. The Assignor and (the "ASSIGNEE") agree as follows: ----------------- 1. The Assignor hereby sells and assigns, without recourse, to the Assignee, and the Assignee hereby purchases and assumes from the Assignor, without recourse to the Assignor, a portion of the Assignor's rights and obligations under the Loan Documents as of the Effective Date (as defined below) which represents the percentage interest specified on Schedule 1 of all outstanding rights and obligations of the Lenders under the Loan Documents (the "ASSIGNED INTEREST"), including, without limitation, such percentage interest in the Commitment as in effect on the Effective Date, the Advances outstanding on the Effective Date and the Notes. After giving effect to such sale and assignment, the Assignee's Commitment will be as set forth in Section 2 of Schedule 1. The effective date of this sale and assignment shall be the date specified on Schedule 1 hereto, which shall be no fewer than five Business Days following the date first set forth above (the "EFFECTIVE DATE"). 2. On the Effective Date, the Assignee will pay to the Assignor, in same day funds, at such address and account as the Assignor shall advise the Assignee, the principal amount of the Advances outstanding under the Loan Documents which are being assigned hereunder, and the sale and assignment contemplated hereby shall thereupon become effective. From and after the Effective Date, the Assignor agrees that the Assignee shall be entitled to all rights, powers and privileges of the Assignor under the Loan Documents to the extent of the Assigned Interest, including without limitation (i) the right to receive all payments in respect of the Assigned Interest for the period from and after the Effective Date, whether on account of principal, interest, fees, indemnities in respect of claims arising after the Effective Date (subject to Section 10.04 of the Credit Agreement), increased costs, additional amounts or otherwise; (ii) the right to vote and to instruct the Administrative Agent under the Credit Agreement based on the Assigned Interest; (iii) the right to set-off and to appropriate and apply deposits of the Borrower as set forth in the Credit Agreement; and (iv) the right to receive notices, requests, demands and other communications. The Assignor agrees that it will promptly remit to the Assignee any amount received by it in respect of the Assigned Interest (whether from the Borrower, the Administrative Agent or otherwise) in the same funds in which such amount is received by the Assignor. 3. The Assignor (i) represents and warrants that it is the legal and beneficial owner of the interest being assigned by it hereunder and that such interest is free and clear of any adverse claim; (ii) other than as provided in this Assignment and Acceptance, makes no representation or warranty and assumes no responsibility with respect to any statements, warranties or representations made in or in connection with the Loan Documents or the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any other instrument or document furnished pursuant thereto; (iii) makes no representation or warranty and assumes no responsibility with respect to the financial condition of the Borrower or the performance or observance by the Borrower of any of its obligations under the Loan Documents or any other instrument or document furnished pursuant thereto; (iv) makes no other representation or warranty with respect to the Borrower, the Loan Documents or any other instrument or document furnished pursuant thereto, except as expressly set forth in clause (i) of this Section 3; and (v) attaches its Notes which are subject to the assignment being made hereby and requests that the Administrative Agent obtain new Notes from the Borrower in accordance with the terms of subsection 10.07(d) of the Credit Agreement. 4. The Assignee (i) confirms that it has received a copy of the Credit Agreement, together with copies of the Financial Statements, or the latest financial statements delivered by the Borrower to the Administrative Agent pursuant to Section 7.04 of the Credit Agreement, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment and Acceptance; (ii) agrees that it will, independently and without reliance upon the Administrative Agent, the Assignor or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents; (iii) appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under the Loan Documents as are delegated to the Administrative Agent by the terms thereof, together with such powers as are reasonably incidental thereto; (iv) agrees that it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender; (v) specifies as its Domestic Lending Office (and address for notices) and Eurodollar Lending Office the offices set forth beneath its name on the signature pages hereof; and (vi) attaches the forms prescribed by the Internal Revenue Service of the United States certifying as to the Assignee's status for purposes of determining exemption from United States withholding taxes with respect to all payments to be made to the Assignee under the Loan Documents or such other documents as are necessary to indicate that all such payments are subject to such rates at a rate reduced by an applicable tax treaty. 5. Following the execution of this Assignment and Acceptance, it will be delivered to the Administrative Agent for acceptance and recording by the Administrative Agent. Upon such acceptance and recording and receipt of any consent of the Borrower and the Administrative Agent required pursuant to Section 10.07(a) of the Credit Agreement, as of the Effective Date, the Assignee shall be a party to the Credit Agreement and, to the extent provided in this Assignment and Acceptance, have the rights and obligations of a Lender thereunder and under the Notes and the Assignor shall, to the extent provided in this Assignment and Acceptance, relinquish its rights and be released from its obligations under the Credit Agreement and the Notes. 6. Upon such acceptance, recording and consent, from and after the Effective Date, the Administrative Agent shall make all payments under the Credit Agreement and the Notes in respect of the interest assigned hereby (including, without limitation, all payments of principal, interest and fees with respect thereto) to the Assignee. The Assignor and Assignee shall make all appropriate adjustments in payments under the Credit Agreement and the Notes for periods prior to the Effective Date directly between themselves. 7. This Assignment and Acceptance shall be governed by, and construed in accordance with, the laws of the State of New York. 8. This Assignment and Acceptance may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of Schedule 1 to this Assignment and Acceptance by telecopier shall be effective as delivery of a manually executed counterpart of this Assignment and Acceptance. IN WITNESS WHEREOF, the parties hereto have caused this Assignment and Acceptance to be executed by their respective officers thereunto duly authorized, as of the date first above written, such execution being made on Schedule 1 hereto. 2 Schedule 1 to Lender Assignment Dated , SECTION 1. --------- (a) Total Credit Agreement Commitments:$________ (b) Percentage Interest: Specify percentage to no more than 8 decimal points. ---------% (c) Amount of Assigned Share: $________ SECTION 2. --------- Assignee's Commitment: $________ SECTION 3. --------- Effective Date: Such date shall be at least 5 Business Days after the execution of this Lender Assignment. __________, ____ [NAME OF ASSIGNOR], as Assignor By ______________________________ Name: Title: [NAME OF ASSIGNEE], as Assignee By ______________________________ Name: Title: Domestic Lending Office (and address for notices): [Address] Eurodollar Lending Office: [Address] Accepted and Consented to this day ---- of : ------------ - CANADIAN IMPERIAL BANK OF COMMERCE, as Administrative Agent By ____________________________ Name: Title: Consented tothis day ---- of : ------------ NORTHEAST UTILITIES By: ----------------------------------------- Name: Title: EX-4.1.5.1 3 0003.txt EXHIBIT 4.1.5.1 Final FIRST AMENDMENT TO TERM LOAN Agreement This FIRST AMENDMENT, dated as of December 15, 2000 (this "Amendment"), to that certain TERM LOAN AGREEMENT, dated as of March 1, 2000 (the "Existing Agreement"; as amended by this Amendment, the "Amended Agreement"), among NORTHEAST UTILITIES, an unincorporated voluntary business association organized under the laws of the Commonwealth of Massachusetts (the "Borrower"), the Lenders parties thereto, Fleet National Bank, as Syndication Agent thereunder, The Bank of New York, as Documentation Agent thereunder and CANADIAN IMPERIAL BANK OF COMMERCE, a Canadian chartered bank ("CIBC") acting through its New York Agency, as Administrative Agent for such Lenders. WHEREAS, the parties have previously entered into the Existing Agreement; and WHEREAS, the parties now wish to amend the Existing Agreement as herein set forth; NOW THEREFORE, the Borrower, the Lenders, such Syndication Agent, such Documentation Agent and the Administrative Agent hereby agree as follows: ARTICLE I Definitions SECTION 2.01. Definitions. Terms used but not otherwise defined in this Amendment shall have the meanings assigned them in the Existing Agreement. ARTICLE III AMENDMENT OF EXISTING AGREEMENT SECTION 4.01. Amendments to Section 1.01 (Definitions). (a) The following definitions are hereby added to Section 1.01 of the Existing Agreement: "Consolidated EBIT" means, for any period (as determined on a consolidated basis in accordance with generally accepted accounting principles), the Borrower's and its Subsidiaries' net income for such period, adjusted as follows: (i) increased by the amount of federal and state income taxes to the extent deducted in the computation of such Borrower's and/or its Subsidiaries' consolidated net income for such period; (ii) increased by the amount of Consolidated Interest Expense deducted in the computation of the Borrower's and/or its Subsidiaries' consolidated net income for such period; (iii) increased by the amount of dividends on preferred stock deducted in the computation of the Borrower's and/or its Subsidiaries' consolidated net income for such period; (iv) decreased (increased) by the gain (loss) on asset sales done outside the ordinary course of business by the Borrower and/or its Subsidiaries to the extent such gains (losses) are not offset by increases (decreases) in amortization of regulatory assets, and to the extent such gain (loss) is included in the computation of the Borrower's and/or its Subsidiaries' consolidated net income for such period; (v) decreased by the amount of revenues accrued by the Borrower and/or its Subsidiaries related to interest on Stranded Cost Recovery Obligations of Subsidiaries of the Borrower, and increased by the amount of operating expenses accrued by the Borrower and/or its Subsidiaries related to interest on Stranded Cost Recovery Obligations of Subsidiaries of the Borrower, in each case to the extent included in the computation of the Borrower's and/or its Subsidiaries' consolidated net income for such period; and (vi) increased by the amount of the non-cash write-offs associated with the September 8, 2000 PSNH restructuring settlement (PUC order no. 23,549) to the extent included in the computation of the Borrower's and/or its Subsidiaries' consolidated net income for such period. "Stranded Cost Recovery Obligations" means, with respect to any Person, such Person's obligations to make principal, interest or other payments to the issuer of stranded cost recovery bonds pursuant to a loan agreement or similar arrangement whereby the issuer has loaned the proceeds of such bonds to such Person. (b) The following definitions set forth in the Section 1.01 of the Existing Agreement are hereby amended and restated to read in their entirety as follows: "Consolidated Interest Expense" means, for any period, the aggregate amount of any interest required to be paid during such period by the Borrower and its Subsidiaries on Debt (including the current portion thereof) (as determined on a consolidated basis in accordance with generally accepted accounting principles), excluding interest required to be paid on the Stranded Cost Recovery Obligations of any Subsidiary of the Borrower. "Debt" means, for any Person, without duplication, (i) indebtedness of such Person for borrowed money, including but not limited to obligations of such Person evidenced by bonds, debentures, notes or other similar instruments (excluding Stranded Cost Recovery Obligations which are non-recourse to such Person), (ii) obligations of such Person to pay the deferred purchase price of property or services (excluding any obligation of such Person to the United States Department of Energy or its successor with respect to disposition of spent nuclear fuel burned prior to April 3, 1983), (iii) obligations of such Person as lessee under leases which shall have been or should be, in accordance with generally accepted accounting principles, recorded as capital leases, (iv) obligations under direct or indirect guaranties in respect of, and obligations (contingent or otherwise) to purchase or otherwise acquire, or otherwise to assure a creditor against loss in respect of, indebtedness or obligations of others of the kinds referred to in clauses (i) through (iii), above, including all Parent Support Obligations, (v) letters of credit, guaranties and other forms of credit enhancement issued to support power sales and trading activities, and (vi) liabilities in respect of unfunded vested benefits under ERISA Plans. "ERISA Plan Termination Event" means (i) a Reportable Event described in Section 4043 of ERISA and the regulations issued thereunder (other than a Reportable Event not subject to the provision for 30-day notice to the PBGC under such regulations) with respect to an ERISA Plan or an ERISA Multi- employer Plan, or (ii) the withdrawal of the Borrower or any of its ERISA Affiliates from an ERISA Plan or an ERISA Multi-employer Plan during a plan year in which it was a "substantial employer" as defined in Section 4001(a)(2) of ERISA, or (iii) the filing of a notice of intent to terminate an ERISA Plan or an ERISA Multi-employer Plan or the treatment of an ERISA Plan amendment as a termination or of an ERISA Multi-employer Plan amendment as a termination under Section 4041 of ERISA, or (iv) the institution of proceedings to terminate an ERISA Plan or an ERISA Multi-employer Plan by the PBGC, or (v) any other event or condition which might constitute grounds under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any ERISA Plan or ERISA Multi-employer Plan. "Extraordinary Proceeds" shall mean, for any Person for any period, net proceeds received by such Person during such period from (i) issuances of stranded cost recovery bonds plus (ii) sales of assets by such Person or any of its Subsidiaries not in the ordinary course of business plus (iii) the sale or disposition (by way of merger, sale of capital stock, sale of assets or otherwise) of any Subsidiary of such Person. For purposes of the foregoing, all cash received by such Person from, or as a result of the sale or disposition of, a Subsidiary shall be deemed to constitute "Extraordinary Proceeds" up to the amount of proceeds received by, or as a result of the sale or disposition of, such Subsidiary from such issuances and sales during the relevant period, net of underwriting discounts and commissions, costs of sale and other, similar transaction costs. "First Mortgage Indenture" means, with respect to CL&P, the CL&P Indenture or any successor thereto or replacement thereof; with respect to WMECO, the WMECO Indenture or any successor thereto or replacement thereof; and with respect to any other Person, an indenture or similar instrument pursuant to which such Person may issue bonds, notes or similar instruments secured by a lien on all or substantially all of such Person's fixed assets. "Named Debt" means Debt of HWP under (i) the Reimbursement and Security Agreement (1988 Series), dated as of November 3, 1999, as amended or extended from time to time, between HWP and The Toronto-Dominion Bank and (ii) the Reimbursement and Security Agreement (1990 Series), dated as of November 3, 1999, as amended or extended from time to time, between HWP and The Toronto- Dominion Bank. "Operating Cash Flow" shall mean, for any period, the sum of the following amounts: (1) dividends paid to the Borrower by a Subsidiary thereof during such period; (2) consulting and management fees paid to the Borrower for such period; (3) tax sharing payments made to the Borrower during such period; (4) interest and other distributions paid to the Borrower during such period with respect to cash (e.g., NU System Money Pool) and other Permitted Investments of the Borrower; and (5) other cash payments made to the Borrower by its Subsidiaries other than (A) returns of invested capital, (B) payments of the principal on Debt of any such Subsidiary to the Borrower (to the extent permitted hereunder) and (C) Extraordinary Proceeds. If at any time there shall exist an event or condition which permits any holder to accelerate the maturity date of any Debt of, or terminate its commitment to extend credit to any Subsidiary, then the contributions of such Subsidiary to Operating Cash Flow for any period ending at or prior to such time shall be eliminated and Operating Cash Flow shall be calculated after giving effect to such elimination. "Principal Subsidiary" shall mean CL&P, WMECO, PSNH, HWP, NAEC, Select Energy, Inc., HEC Inc., Northeast Generation Company, Mode One Communications, Inc., Yankee Gas Services Company, and any other Subsidiary, whether owned directly or indirectly by the Borrower, which, with respect to the Borrower and its Subsidiaries taken as a whole, represents at least ten percent (10%) of such Borrower's consolidated assets or such Borrower's consolidated net income (or loss). (c) The definition of "Consolidated Operating Income" is hereby deleted from Section 1.01 of the Existing Agreement. SECTION 4.02. Amendments to Section 7.02 (Negative Covenants). Section 7.02 of the Existing Credit Agreement is hereby amended and restated to read in its entirety as follows: SECTION 7.02. Negative Covenants. On and after the Closing Date, and so long as any Note shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower shall not, or permit any Principal Subsidiary to, without the written consent of the Majority Lenders: (a) Liens, Etc. Create incur, assume or suffer to exist any Lien upon any of its properties or assets (including the stock of its Subsidiaries), whether now owned or hereafter acquired, except: (i) any Liens existing on the Closing Date; (ii) in the case of CL&P, Liens created by the Indenture of Mortgage and Deed of Trust dated as of May 1, 1921, from CL&P to Bankers Trust Company, as trustee, as previously and hereafter amended and supplemented (the "CL&P Indenture"); (iii) in the case of WMECO, Liens created by the First Mortgage Indenture and Deed of Trust dated as of August 1, 1954, from WMECO to State Street Bank and Trust Company, as successor trustee, as previously and hereafter amended and supplemented (the "WMECO Indenture"); (iv) in the case of PSNH, Liens created by the General and Refunding Mortgage Indenture, dated as of August 15, 1978, between PSNH and New England Merchants National Bank, as trustee, and to which First Union National Bank is successor trustee, as previously and hereafter amended and supplemented (the "PSNH Indenture"); (v) in the case of NAEC, Liens created by the First Mortgage Indenture and Deed of Trust, dated as of June 1, 1992, between NAEC and United States Trust Company of New York, as trustee, as previously and hereafter amended and supplemented (the "NAEC Indenture"); (vi) as permitted by Section 7.02(f) hereof; (vii) Liens on the interests of CL&P and WMECO in (A) the Millstone Unit No. 1 created by (1) the Open-End Mortgage and Trust Agreement dated as of October 1, 1986, as previously and hereafter amended, made by CL&P in favor of State Street Bank and Trust Company, as successor trustee, and (2) the Open-End Mortgage and Trust Agreement dated as of October 1, 1986, as previously and hereafter amended, made by WMECO in favor of State Street Bank and Trust Company, as successor trustee, to the extent of the Debt from time to time secured by such Open-End Mortgages and Trust Agreements, and (B) Millstone Unit No. 2 and Millstone Unit No. 3 created by (1) the Open-End Mortgage, dated as of November 17, 2000, made by CL&P in favor of Citibank, N.A., as collateral agent, and (2) the Open-End Mortgage, dated as of November 17, 2000, made by WMECO in favor of Citibank, N.A., as collateral agent, to the extent of the Debt secured by such Open-End Mortgages; (viii) "Permitted Liens" or "Permitted Encumbrances" under the CL&P Indenture (in the case of CL&P), the WMECO Indenture (in the case of WMECO), the PSNH Indenture (in the case of PSNH) or the NAEC Indenture (in the case of NAEC), in each case as such terms are defined on the date hereof, to the extent such Liens do not secure Debt of the Borrower or any Principal Subsidiary; (ix) any purchase money Lien or construction mortgage on assets hereafter acquired or constructed by the Borrower or any Principal Subsidiary and any Lien on any assets existing at the time of acquisition thereof by the Borrower or such Principal Subsidiary or created within 180 days from the date of completion of such acquisition or construction; provided that such Lien shall at all times be confined solely to the assets so acquired or constructed and any additions thereto; (x) any existing Liens on assets now owned by the Borrower or any Principal Subsidiary and Liens existing on assets of a corporation or other going concern when it is merged into or with the Borrower or such Principal Subsidiary or when substantially all of its assets are acquired by the Borrower or such Principal Subsidiary; provided that such Liens shall at all times be confined solely to such assets, or if such assets constitute a utility system, additions to or substitutions for such assets; (xi) Liens resulting from legal proceedings being contested in good faith by appropriate legal or administrative proceedings by the Borrower or any Principal Subsidiary, and as to which the Borrower or such Principal Subsidiary, to the extent required by generally accepted accounting principles applied on a consistent basis, shall have set aside on its books adequate reserves; (xii) Liens created in favor of the other contracting party in connection with advance or progress payments; (xiii) any Liens in favor of any state of the United States or any political subdivision of any such state, or any agency of any such state or political subdivisions, or trustee acting on behalf of holders of obligations issued by any of the foregoing or any financial institutions lending to or purchasing obligations of any of the foregoing, which Lien is created or assumed for the purpose of financing all or part of the cost of acquiring or constructing the property subject thereto; (xiv) Liens resulting from conditional sale agreements, capital leases or other title retention agreements including, without limitation, Liens arising under leases of nuclear fuel from the Niantic Bay Fuel Trust; (xv) with respect to pollution control bond financings, Liens on funds, accounts and other similar intangibles of the Borrower or any Principal Subsidiary created or arising under the relevant indenture, pledges of the related loan agreement with the relevant issuing authority and pledges of the Borrower's or such Principal Subsidiary's interest, if any, in any bonds issued pursuant to such financings to a letter of credit bank or bond issuer or similar credit enhancer; (xvi) Liens granted on accounts receivable and Regulatory Assets in connection with financing transactions, whether denominated as sales or borrowings; (xvii) Liens on the assets of, or the stock issued by, Northeast Generation Company or any other Subsidiary of the Borrower created to hold generating assets if such Liens are created to secure nonrecourse Debt incurred to acquire, construct or otherwise develop such generating assets; (xviii) Liens on assets of HWP permitted to exist by the terms of agreements governing the Named Debt; (xix) any other Liens incurred in the ordinary course of business otherwise than to secure Debt; and (xx) any extension, renewal or replacement of Liens permitted by clauses (i), (vii) through (x) and (xii) through (xvii); provided, however, that the principal amount of Debt secured thereby shall not, at the time of such extension, renewal or replacement, exceed the principal amount of Debt so secured and that such extension, renewal or replacement shall be limited to all or a part of the property which secured the Lien so extended, renewed or replaced or to other property of no greater value than the property which secured the Lien so extended, renewed or replaced. (b) Mergers, Acquisitions, Sales of Assets, Etc. Merge with or into or consolidate with or into, any Person, or purchase or otherwise acquire (whether directly or indirectly) all or substantially all of the assets or stock of any class of, or any partnership or joint venture interest in, any other Person, or sell, transfer, convey, lease or otherwise dispose of all or any substantial part of its assets; except for the following, and then only after receipt of all necessary corporate and governmental or regulatory approvals and provided that, before and after giving effect to any such merger, consolidation, purchase, acquisition, sale, transfer, conveyance, lease or other disposition, no Event of Default or Unmatured Default shall have occurred and be continuing: (A) NU may merge with or into Consolidated Edison, Inc. or a wholly owned Subsidiary thereof; (B) NU or any Subsidiary thereof may enter into such transactions with third parties if the aggregate consideration involved in all such transactions does not exceed $25,000,000 and if NU or such Subsidiary is the surviving legal entity of any such transaction; (C) any purchase or acquisition of a joint venture interest in a mutual insurance company providing nuclear liability or nuclear property or replacement power insurance; (D) any sale of accounts receivable on reasonable commercial terms (including a commercially reasonable discount) to obtain funding for CL&P and WMECO, as the case may be; (E) any sale or purchase of generating assets or Regulatory Assets on an arms-length basis, subject to approval by the appropriate regulatory authorities; (F) any sale of transmission assets on an arms-length basis as required by the appropriate regulatory authorities; and (G) the sale of the Borrower's or any Principal Subsidiary's assets in the ordinary course of business on customary terms and conditions. For purposes of this subsection (b), any sale of assets by the Borrower or any Principal Subsidiary (in one or a series of transactions) will be deemed to be a "substantial part" of its assets if (i) the book value of such assets exceeds 7.5% of the total book value of the assets (net of Regulatory Assets) of such Person, as reflected in the most recent financial statements of the Borrower or such Principal Subsidiary delivered to the Administrative Agent pursuant to Section 7.04 hereof (or, if no such financial statements have been delivered to the Administrative Agent as of the relevant date of determination, the Financial Statements of such Person), or (ii) the gross revenue associated with such assets accounts for more than 7.5% of the total gross revenue of the Borrower or such Principal Subsidiary for the four proceeding fiscal quarters, as reflected in the most recent financial statements of the Borrower or such Principal Subsidiary delivered to the Administrative Agent pursuant to Section 7.04 hereof (or, if no such financial statements have been delivered to the Administrative Agent as of the relevant date of determination, the Financial Statements of such Person). (c) Compliance with ERISA. (i) Terminate, or permit any of its ERISA Affiliates to terminate, any ERISA Plan so as to result in any liability of the Borrower or any Principal Subsidiary to the PBGC in an amount greater than $1,000,000, or (ii) permit to exist any occurrence of any Reportable Event (as defined in Title IV of ERISA) which, alone or together with any other Reportable Event with respect to the same or another ERISA Plan, has a reasonable possibility of resulting in liability of the Borrower or any Principal Subsidiary to the PBGC in an aggregate amount exceeding $1,000,000, or any other event or condition which presents a material risk of such a termination by the PBGC of any ERISA Plan or has a reasonable possibility of resulting in a liability of the Borrower or any Principal Subsidiary to the PBGC in an aggregate amount exceeding $1,000,000. (d) Accounting Changes. Make any change in its accounting policies or reporting practices except as required or permitted by the Securities and Exchange Commission, the Financial Accounting Standards Board or any other generally recognized accounting authority. (e) Transactions with Affiliates. Engage in any transaction with any Affiliate except (i) in accordance with the Public Utility Holding Company Act of 1935, to the extent applicable thereto or (ii) on terms no less favorable to the Borrower or the Principal Subsidiary party thereto than if the transaction had been negotiated in good faith on an arms-length basis with a non-Affiliate and on commercially reasonable terms or pursuant to a binding agreement in effect on the Closing Date. (f) Issuance of First Mortgage Bonds. In the case of Principal Subsidiaries only, issue any First Mortgage Bonds on or after the Closing Date, whether in addition to First Mortgage Bonds outstanding on the Closing Date or in replacement of First Mortgage Bonds redeemed, retired, defeased, repaid or prepaid on or after the Closing Date; provided, that (i) Yankee Gas Services Company may issue First Mortgage Bonds, the proceeds of which are used to refinance not more than $200,000,000 of Debt incurred by NU in connection with the acquisition by NU of Yankee Energy System Inc., and (ii) Northeast Generation Company may issue First Mortgage Bonds for the purpose of refinancing up to $416,000,000 of its secured Debt outstanding on the Closing Date, to the extent that the principal amount of any such First Mortgage Bonds is less than or equal to the principal amount of the Debt so refinanced plus up to six months of accrued interest on such Debt, determined at the time of the refinancing; provided, that in no event shall the amount of First Mortgage Bonds issued by Northeast Generation Company exceed $440,000,000. (g) Interests in Nuclear Plants. Acquire any nuclear plant or any interest therein not held on the Closing Date, other than so-called "power entitlements" acquired for use in the ordinary course of business. (h) Debt. Create, incur, assume or suffer to exist, any Debt of NU, NU Enterprises, Inc. or any Subsidiary of NU Enterprises, Inc., other than (i) Debt under the Loan Documents; (ii) other Debt in existence on the Closing Date, and any renewal or replacement thereof by the debtor thereunder so long as such renewal or replacement does not result in an increase in the amount of such Debt or require, when compared to the Debt being renewed or replaced, additional credit support or credit support of a different character (including, without limitation, any collateral) that has not been first offered to the Lenders; (iii) Parent Support Obligations in an amount not to exceed $500,000,000 at any one time outstanding; (iv) Debt incurred by HEC Inc. in an aggregate principal amount not to exceed $35,000,000; (v) in the case of NU Enterprises, Inc. and its Subsidiaries, Debt owing to NU, NU Enterprises, Inc. or the NU System Money Pool; and (vi) as permitted by Section 7.02(f) above. (i) Investments. With respect to the Borrower only, purchase, hold or acquire any capital stock, evidences of indebtedness or other securities (including any option, warrant or other right to acquire any of the foregoing) of, make or permit to exist any loans or advances to, guarantee any obligations of, or make or permit to exist any investment or any other interest in, any other Person, or purchase or otherwise acquire (in one transaction or a series of transactions) any assets of any other Person constituting a business unit (each of the foregoing, an "Investment"), except (i) equity and debt investments in (including NU System Money Pool advances to) Select Energy Inc. in an aggregate amount not to exceed $200,000,000; (ii) NU System Money Pool advances (other than to Select Energy Inc.) in an aggregate amount not to exceed $100,000,000 at any one time outstanding; (iii) other debt and equity investments in Subsidiaries of the Borrower (other than NU System Money Pool advances and other than in Select Energy Inc.) in an aggregate amount not to exceed $100,000,000 from and after the Closing Date; (iv) the issuance of up to $35,000,000 in construction completion and similar performance guaranties on behalf of HEC Inc. from and after the Closing Date; (v) Investments permitted by subsections (b) and (h) above; (vi) Investments other than (A) those enumerated in clauses (i) through (v) above and (B) NU System Money Pool Advances, in each case, made prior to the Closing Date; and (vii) Permitted Investments. (j) Restricted Payments. With respect to the Borrower only, declare or make, or agree to pay or make, directly or indirectly, any Restricted Payment, except that the Borrower may (i) pay dividends to its common stockholders in an aggregate amount not to exceed $60,000,000 during any 12- month period beginning or ending on the Closing Date or any day thereafter until and including the Termination Date, and (ii) redeem or repurchase capital stock for an aggregate amount not in excess of $215,000,000 in connection with the acquisition of Yankee Energy System Inc.. (k) Financing Agreements. With respect to the Borrower only, permit any Principal Subsidiary to enter into any agreement, contract, indenture or similar obligation, or issue any security (all of the foregoing being referred to as "Financing Agreements"), that is not in effect on the Closing Date, or amend or modify any existing Financing Agreement, if the effect of such Financing Agreement (or amendment or modification thereof) is to impose any additional restriction not in effect on the Closing Date on the ability of such Principal Subsidiary to pay dividends to the Borrower; provided, that the foregoing shall not restrict the right of Northeast Generation Company, or any other Subsidiary of the Borrower created to hold generating assets, to enter into any such Financing Agreement in connection with the incurrence of nonrecourse Debt to acquire, construct or otherwise develop generating assets. SECTION 4.03. Amendments to Section 7.03 (Financial Covenants). Section 7.03 of the Existing Credit Agreement is hereby amended and restated to read in its entirety as follows: SECTION 7.03. Financial Covenants. On and after the Closing Date, so long as any Note shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower shall, unless the Majority Lenders shall otherwise consent in writing: (a) Common Equity Ratio. Maintain at all times a ratio of Common Equity to Total Capitalization of at least 0.30:1:00. (b) Interest Coverage Ratio. Maintain, as of the end of each Fiscal Quarter, with respect to the four Fiscal Quarters then ended, a ratio of Consolidated EBIT to Consolidated Interest Expense of at least (i) 2.00:1:00 with respect to the four Fiscal Quarters ending December 31, 2000 and March 31, 2001, and (ii) 2.20:1.00 with respect to any period of four Fiscal Quarters ending after March 31, 2001. (c) Cash Flow Ratio. Maintain, as of the end of each Fiscal Quarter, with respect to the four Fiscal Quarters then ended, a ratio of Operating Cash Flow to Fixed Charges of at least 1.50:1.00. SECTION 4.04. Reference to and Effect on Other Documents. (a) On and after the date this Amendment becomes effective in accordance with Article III, below, each reference in the Existing Agreement to "this Agreement", "hereunder", "hereof" or words of like import referring to the Existing Agreement, and each reference in the Notes to "the Credit Agreement", "thereunder", "thereof" or words of like import referring to the Existing Agreement, shall mean and be a reference to the Amended Agreement. (b) Except as specifically amended above, the Existing Agreement is and shall continue to be in full force and effect and is hereby in all respects ratified and confirmed. (c) The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of the Lenders or of the Administrative Agent under the Existing Agreement, nor constitute a waiver of any provision of any of the foregoing. ARTICLE V Conditions Precedent to EFFECTIVENESS SECTION 7.01. Conditions Precedent to Effectiveness. This Amendment shall not become effective unless and until all of the following conditions precedent shall have been satisfied: (a) The Administrative Agent shall have received the following, each dated the date of this Amendment, in form and substance reasonably satisfactory to the Administrative Agent and its counsel: (i) counterparts of this Amendment duly executed by the Borrower and the Majority Lenders; (ii) an opinion of Jeffrey C. Miller, Associate General Counsel to the Borrower, in form and substance satisfactory to the Administrative Agent and its counsel; (iii) copies of all approvals, authorizations or consents of, or notices to or registrations with, any governmental body or agency required for the Borrower to enter into this Amendment, and of all such approvals, authorizations, notices or registrations required to be obtained or made by the Borrower in connection with the transactions contemplated by this Amendment, other than, in each case, those previously delivered to the Administrative Agent pursuant to the Existing Agreement; (iv) a certificate of the Borrower certifying the names and true signatures of the individuals authorized to sign this Amendment and the other documents to be delivered by the Borrower hereunder; and (v) such other documents, instruments, approvals (and, if requested by the Administrative Agent, certified duplicates of executed copies thereof) or opinions as the Administrative Agent may reasonably request. (b) No Default or Event of Default shall have occurred and be continuing or would result from the issuance of this Amendment, and the Administrative Agent shall have received a certificate to such effect signed by a senior officer of the Borrower and dated such date. ARTICLE VIII Representations and Warranties SECTION 8.01. Representations and Warranties of the Borrower. The Borrower represents and warrants to the Lenders as follows: (a) Organization. The Borrower is a voluntary association organized under a Declaration of Trust, duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, has the requisite power under its Declaration of Trust and authority to own its property and assets and to carry on its business as now conducted. Commonwealth of Massachusetts. (b) Authorization; No Conflict. The execution and delivery of this Amendment, and the performance by the Borrower of its obligations under this Amendment and the Amended Agreement are within the Borrower's powers under its Declaration or Trust, have been duly authorized by all necessary action under its Declaration of Trust and applicable law, and do not and will not contravene (i) the Borrower's Declaration of Trust or any law or legal restriction or (ii) any contractual restriction binding on or affecting the Borrower or its properties. (c) Governmental Approvals. No authorization or approval or other action by, and no notice to or filing with, any governmental authority or regulatory body is required for the due execution and delivery by the Borrower of this Amendment and the performance by the Borrower of this Amendment and the Amended Agreement except for the approval, which has already been obtained and is in full force and effect, of the United States Securities and Exchange Commission. (d) Validity and Binding Nature. This Amendment and the Amended Agreement are legal, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their respective terms. (e) Information. No exhibit, schedule, report or other written information provided by the Borrower or its agents to the Administrative Agent or the Lenders in connection with the negotiation, execution and closing of this Amendment knowingly contained when made any material misstatement of fact or knowingly omitted to state any material fact necessary to make the statements contained therein not misleading in light of the circumstances under which they were made. ARTICLE IX MISCELLANEOUS SECTION 9.01. Costs, Expenses and Taxes. The Borrower agrees to pay on demand all reasonable costs and expenses in connection with the preparation, execution, delivery, filing, administration and enforcement of this Amendment and any other documents delivered in connection with or related to this Amendment, including the reasonable fees and expenses of counsel for the Bank with respect thereto. SECTION 9.02. Governing Law. This Amendment shall be governed by, and construed and interpreted in accordance with, the laws of the State of New York. SECTION 9.03. Headings. Section headings in this Amendment are included herein for convenience of reference only and shall not constitute a part of this Amendment for any other purpose. SECTION 9.04. Limitation of Liability. The Declaration of Trust of Northeast Utilities provides that no shareholder shall be held to any liability whatever for the payment of any sum of money or for damages or otherwise under any contract, obligation, or undertaking made, entered into or issued by the trustees of Northeast Utilities or by any officer, agent or representative elected or appointed by the trustees, and no such contract, obligation or undertaking shall be enforceable against the trustees or any of them in their individual capacities or capacity and all such contracts, obligations and undertakings shall be enforceable only against the trustees as such, and every person, firm, association, trust and corporation having any claim or demand arising out of any such contract, obligation or undertaking shall look only to the trust estate for the payment or satisfaction thereof. S - 2 Signature Page to First Amendment S - 1 Signature Page to First Amendment IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their respective officers hereunto duly authorized as of the date first above written. NORTHEAST UTILITIES By: Title: CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY, as Bank and as Administrative Agent By Name: Title: BARCLAYS BANK PLC By Name: Title: THE BANK OF NEW YORK, as Bank and as Documentation Agent By Name: Title: FLEET NATIONAL BANK, as Syndication Agent By Name: Title: FLEET NATIONAL BANK, as Trust Administrator for LongLane Master Trust IV, as Bank By Name: Title: COMMERZBANK AG By Name: Title: By Name: Title: HEWLETT-PACKARD MASTER TRUST By Name: Title: IBM RETIREMENT PLAN By Name: Title: LUCENT TECHNOLOGIES INC. MASTER PENSION TRUST By Name: Title: KZH LANGDALE LLC By Name: Title: VAN KAMPEN MERRITT PRIME RATE INCOME TRUST By Name: Title: EX-4.2.24.2 4 0004.txt EXHIBIT 4.2.24.2 STANDBY BOND PURCHASE AGREEMENT Dated as of October 24, 2000 among THE CONNECTICUT LIGHT AND POWER COMPANY, THE PARTICIPATING BANKS and THE BANK OF NEW YORK, as Purchasing Bank THE BANK OF NEW YORK Administrative Agent BNY CAPITAL MARKETS, INC. Lead Arranger and Book Manager TABLE OF CONTENTS ARTICLE I DEFINITIONS Section 1.01 Certain Defined Terms. Section 1.02 Accounting Terms and Determinations. Section 1.03 Basis for Ratings. Section 1.04 Interpretation. ARTICLE II standby bond purchase facility Section 2.01 Purchase of Unremarketed Bonds. (a) Commitment to Purchase Unremarketed Bonds. (b) Manner of Purchase. Section 2.02 Purchased Bonds as Bank Bonds; Bank Rate. Section 2.03 Redemption of Bank Bonds. Section 2.04 Remarketing of Bank Bonds. Section 2.05 Application of Payments on Bank Bonds. Section 2.06 Repayment and Prepayment of Disbursements. (a) Scheduled Repayments. (b) Optional Prepayments. (c) Mandatory Prepayments. (d) Transfer of Excess Bank Bonds. Section 2.07 Interest on Disbursements and Other Amounts. (a) Interest Rate Options. (b) Applicable Rates. (c) Overdue Amounts. (d) Payment Dates. Section 2.08 Commitment Fee. Section 2.09 Computation of Interest and Fees; Maximum Interest Rate. Section 2.10 Reduction or Termination of Commitment. (a) Reduction upon Retirement of Bank Bonds. (b) Reduction upon Conversion of Bank Bonds. (c) Optional Termination by the Company. (d) Reduction or Termination of Participation Amounts. Section 2.11 Basis for Determining Interest Rate Inadequate or Unfair. Section 2.12 Illegality. Section 2.13 Increased Costs. Section 2.14 Capital Adequacy. Section 2.15 Funding Losses. Section 2.16 Payments. Section 2.17 Distribution of Payments by the Purchasing Bank. Section 2.18 Sharing of Recoveries. ARTICLE III CONDITIONS PRECEDENT Section 3.01 Conditions Precedent Subject to Fulfillment on the Closing Date. Section 3.02 Additional Conditions Precedent Subject to Fulfillment on the Closing Date. Section 3.03 Conditions Subject to Fulfillment on Each Purchase Date. ARTICLE IV REPRESENTATIONS AND WARRANTIES29 Section 4.01 Organization. Section 4.02 Authorization. Section 4.03.Enforceability. Section 4.04 Approvals. Section 4.05 Financial Information. Section 4.06 Litigation. Section 4.07 Reoffering Circular. Section 4.08 Environmental Matters. Section 4.09 Investment Company Act. Section 4.10 Public Utility. Section 4.11 All Other Representations and Warranties Accurate. ARTICLE V COVENANTS Section 5.01 Further Assurances. Section 5.02 Maintenance of Remarketing Agent. Section 5.03 Amendments to Related Documents. Section 5.04 Offering Circular. Section 5.05 Remarketing. Section 5.06 Substitute Liquidity Facility. Section 5.07 Remarketing Agent. Section 5.08 Entry into Conflicting Agreements; Performance of Related Documents. Section 5.09 Financial Statements. Section 5.10 Certificates; Other Information. Section 5.11 Payment of Obligations. Section 5.12 Conduct of Business; Maintenance of Existence; Compliance with Obligations and Laws; Merger. Section 5.13 Maintenance of Property; Insurance. Section 5.14 Inspection; Books and Records; Discussions. Section 5.15 Notices. ARTICLE VI EVENTS OF DEFAULT; REMEDIES Section 6.01 Events of Default. Section 6.02 Remedies. (a) Events of Suspension. (b) Events of Termination. (c) Other Remedies. (d) Direction by Required Banks. ARTICLE VII MISCELLANEOUS Section 7.01 Amendments, Etc. Section 7.02 Notices, Etc. Section 7.03 No Implied Waiver: Remedies Cumulative. Section 7.04 Indemnification. Section 7.05 Limitation of Liability. Section 7.06 Costs, Expenses and Taxes. Section 7.07 Binding Effect; Assignment; Participations. Section 7.08 Set-Off. Section 7.09 Severability. Section 7.10 Governing Law. Section 7.11 Jurisdiction; Service of Process; Waiver of Jury Trial. Section 7.12 Survival of Representations and Warranties. Section 7.13 Entirety. Section 7.14 Execution in Counterparts. Section 7.15 Headings. Section 7.16 Effectiveness. Section 7.17 Confidentiality. Section 7.18 Purchasing Bank's Rights and Responsibilities. Section 7.19 Reimbursement and Indemnification by Participating Banks. Section 7.20 Participating Banks' Obligations Absolute. Section 7.21 Beneficiaries. ANNEX A - Participating Banks, Lending Offices and Notice Addresses EXHIBIT 2.01 - - Form of Purchase Certificate EXHIBIT 2.06 - Form of Notice of Prepayment EXHIBIT 2.07 - Form of Notice of Interest Rate Election EXHIBIT 2.16 - Form of Non-US Bank Certificate EXHIBIT 7.07(b) - Form of Joinder Agreement EXHIBIT 7.07(c) - Form of Assignment and Acceptance STANDBY BOND PURCHASE AGREEMENT This STANDBY BOND PURCHASE AGREEMENT, dated as of October 24, 2000, among THE CONNECTICUT LIGHT AND POWER COMPANY, a Connecticut corporation, the PARTICIPATING BANKS and THE BANK OF NEW YORK, as Purchasing Bank. W I T N E S S E T H : WHEREAS, pursuant to the Indenture (such term and all other capitalized terms used in these recitals having the meanings set forth or referred to in Section 1.01), the Issuer has issued the Bonds; WHEREAS, the payment of the principal of and interest (at a rate per annum not in excess of 18 percent) on the Bonds (including Unremarketed Bonds purchased by the Purchasing Bank pursuant to this Agreement) is insured by the Bond Insurance Policy issued by the Bond Insurer for the benefit of the holders from time to time of the Bonds (including the Purchasing Bank); WHEREAS, in order to provide liquidity support for the Bonds, the Company has requested the Purchasing Bank to agree to purchase Unremarketed Bonds from time to time and has requested the Participating Banks to participate in the Purchasing Bank's obligation to make such purchases, all in accordance with the terms and conditions hereof; and WHEREAS, the Purchasing Bank is willing to agree to so purchase Unremarketed Bonds and the Participating Banks are willing to agree to so participate in such purchase obligation, all in accordance with the terms and conditions hereof; NOW, THEREFORE, the parties hereto agree as follows: ARTICLE I DEFINITIONS Section 1.01 Certain Defined Terms. The following terms, as used herein, have the following meanings: "Adjusted London Interbank Offered Rate" means, in regards to any Interest Period, a rate per annum equal to the quotient (rounded upward, if necessary, to the next higher 1/100 of 1 percent) obtained by dividing (a) the applicable London Interbank Offered Rate by (b) 1.00 minus the Euro-Dollar Reserve Percentage. The Adjusted London Interbank Offered Rate shall be adjusted automatically on and as of the effective date of any change in the Euro-Dollar Reserve Percentage. "Affiliate" means, with respect to any Person, any other Person directly or indirectly controlling (including all directors and officers of such Person), controlled by, or under direct or indirect common control with, such Person. A Person shall be deemed to control another entity if such Person possesses, directly or indirectly, the power to direct or cause the direction of the management and policies of such entity, whether through the ownership of voting securities, by contract or otherwise. "Agreement" means this Standby Bond Purchase Agreement. "Applicable Law" means (a) all applicable common law and principles of equity and (b) all applicable provisions of all (i) constitutions, statutes, rules, regulations and orders of governmental bodies, (ii) Governmental Approvals and Governmental Registrations and (iii) orders, decisions, judgments and decrees. "Applicable Lending Office" means, with respect to a Bank, (a) in the case of its Domestic Disbursement Participations, its Domestic Lending Office and (b) in the case of its Euro-Dollar Disbursement Participations, its Euro-Dollar Lending Office. "Applicable Margin" means, with respect to any Euro-Dollar Disbursement on any date, (a) for any date occurring prior to the Stated Expiration Date: (i) if either the Company's senior secured debt or the Bond Insurer's long- term debt or claims paying ability is rated either A- or higher by S and P or A3 or higher by Moody's, 0.350 percent per annum; (ii) if clause (i) does not apply but either the Company's senior secured debt or the Bond Insurer's long-term debt or claims paying ability is rated either BBB+ or higher by S and P or Baa1 or higher by Moody's, 0.500 percent per annum; and (iii) if neither clause (i) nor clause (ii) applies, 0.875 percent per annum; and (b) for any date occurring on or after the Stated Expiration Date, the rate per annum that would otherwise be applicable pursuant to clause (a) above plus 0.50 percent. "Approved Fund" means any Fund that is administered or managed by (a) a Bank, (b) an Affiliate of a Bank or (c) an entity or an Affiliate of an entity that administers or manages a Bank. "Assignment and Acceptance" means an assignment and acceptance agreement in the form of Exhibit 7.07(c) with such variations as shall be acceptable to the Persons whose consent is required therefor under Section 7.07(c). "Available Interest Commitment" means, at any time, (a) the amount of the Interest Commitment at such time less (b) the aggregate principal amount of Interest Disbursements outstanding at such time. "Available Principal Commitment" means, at any time, (a) the amount of the Principal Commitment at such time less (b) the aggregate principal amount of Principal Disbursements outstanding at such time. "Bank Bond" means any Unremarketed Bond or portion thereof purchased by the Purchasing Bank pursuant to Section 2.01 that has not been (a) resold by the Purchasing Bank pursuant to Section 2.04, (b) transferred to the Company pursuant to Section 2.06(d), or (c) redeemed, cancelled, defeased or otherwise retired in accordance with the Indenture. "Bank Information" has the meaning assigned to that term in Section 7.04(a). "Bank Rate" means, for any day, with respect to any Bank Bond, the rate per annum necessary to produce an interest accrual on such Bank Bond for such day equal to daily interest at a rate per annum equal to the Base Rate for such day (or with respect to any overdue amount, the Base Rate for such day plus 2 percent per annum) on an amount equal to the sum of (a) the principal amount of such Bank Bond as of such date plus (b) the unpaid principal amount as of such date of any Interest Disbursement made as part of the Purchase Price for such Bank Bond. "Banks" means each of the Participating Banks and the Purchasing Bank. "Base Rate" means, for any day, an interest rate per annum equal to the greater of (a) the Prime Rate in effect for such day or (b) the sum of the Federal Funds Rate in effect for such day plus 0.50 percent. "Bond Documents" means the Bonds, the Indenture, the Loan Agreement and the Mortgage Bond Documents. "Bond Insurance Policy" means the municipal bond insurance policy issued by the Bond Insurer (including any riders and endorsements thereto) with respect to the Bonds, as such insurance policy may be amended, modified or supplemented from time to time. "Bond Insurer" means (a) AMBAC Assurance Corporation, a Wisconsin stock insurance company, and (b) any other insurance or indemnity company or other type of financial institution that either replaces AMBAC Assurance Corporation as "Bond Insurer" under and as defined in the Indenture or is provided as an additional "Bond Insurer" under and as defined in the Indenture. "Bond Insurer Event of Insolvency" means the occurrence of one or more of the following events: (a) the issuance of an order of rehabilitation, liquidation or dissolution of the Bond Insurer; (b) the commencement by the Bond Insurer of a voluntary case or other proceeding seeking rehabilitation, dissolution, liquidation, reorganization or other relief with respect to itself or its debts under any bankruptcy, insolvency or other similar law now or hereafter in effect, including the appointment of a trustee, receiver, liquidator, custodian or other similar official for itself or any substantial part of its property; (c) the consent of the Bond Insurer to, or the acquiescence by the Bond Insurer in, any case or proceeding described in the preceding clause (b) that is commenced against it; (d) the making by the Bond Insurer of a general assignment for the benefit of creditors; (e) the failure of the Bond Insurer, or the admission by the Bond Insurer in writing of its inability, generally to pay its debts or claims as they become due; (f) the initiation by the Bond Insurer of any action to authorize any of the foregoing; (g) the commencement of an involuntary case or other proceeding against the Bond Insurer seeking liquidation, reorganization or other relief with respect to it or its debts under any bankruptcy, insolvency or other similar law now or hereafter in effect or seeking the appointment of a trustee, receiver, liquidator, custodian or other similar official of it or any substantial part of its property, and such involuntary case remaining undismissed and unstayed for a period of 60 days; or (h) the entering of an order for relief against the Bond Insurer under the federal bankruptcy laws as now or hereafter in effect. "Bond Insurer Potential Insolvency" means any event or condition that would become a Bond Insurer Event of Insolvency under clause (g) of the definition thereof after the lapse of the 60-day period referred to in such clause (g). "Bonds" means the 62,000,000 dollars Pollution Control Revenue Bonds (The Connecticut Light and Power Company Project - 1996A Series) authorized and issued pursuant to Section 2.3 of the Indenture. The term "Bonds" includes Unremarketed Bonds and Bank Bonds. "Closing Date" means October 24, 2000. "Code" means the Internal Revenue Code of 1986, as amended. "Combined Available Commitment" means, on any date, an amount equal to the sum of (a) the Available Principal Commitment as in effect on such date and (b) the Available Interest Commitment as in effect on such date. "Commitment" means, as the context may require, (a) the Principal Commitment and the Interest Commitment or (b) the Purchasing Bank's obligation to purchase Unremarketed Bonds pursuant Section 2.01 in amounts limited thereby. "Commitment Fee Rate" means, for any day: (a) if either the Company's senior secured debt or the Bond Insurer's long- term debt or claims paying ability is rated either A- or higher by S and P or A3 or higher by Moody's, 0.150 percent per annum; (b) if clause (a) does not apply but either the Company's senior secured debt or the Bond Insurer's long-term debt or claims paying ability is rated either BBB+ or higher by S and P or Baa1 or higher by Moody's, 0.175 percent per annum; and (c) if neither clause (a) nor clause (b) applies, 0.225 percent per annum. "Commitment Fees" means fees payable pursuant to Section 2.08. "Commitment Termination Date" means the earliest to occur of the following dates: (a) the Stated Expiration Date, (b) the date on which the Commitment is reduced to zero or terminated in accordance with Section 2.10, or (c) the date on which the Commitment is terminated in accordance with Section 6.02(b). "Company" means The Connecticut Light and Power Company, a Connecticut corporation. "Company Disclosure Documents" means the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999, the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2000, and the Company's Current Reports on Form 8-K dated December 2, 1999 and March 14, 2000. "Contaminant" means any waste, pollutant, hazardous substance, toxic substance, hazardous waste, special waste, industrial substance or waste, petroleum or petroleum-derived substance or waste, or any constituent of any such substance or waste, including any such substance regulated under any Environmental Law. "Daily Mode" has the meaning ascribed to such term in the Indenture. "Default" means any condition or event that constitutes an Event of Default or that, with the giving of notice or lapse of time or both would, unless cured or waived, become an Event of Default. "Disbursement" means an amount transferred by the Purchasing Bank to the Paying Agent pursuant to Section 2.01(b)(i) for the purpose of paying the Purchase Price of Unremarketed Bonds. Any amount so transferred shall constitute a Disbursement regardless of whether such amount is used by the Paying Agent to purchase Unremarketed Bonds on the specified Purchase Date. "Disbursement Group" means at any time a group of Disbursements consisting of (a) all Disbursements that are Domestic Disbursements at such time or (b) all Disbursements that are Euro-Dollar Disbursements having the same Interest Period at such time. "Disbursement Participation" means (a) with respect to the Purchasing Bank, such Bank's retained interest in a Disbursement and (b) with respect to a Participating Bank, such Bank's participation interest in such Disbursement. "Domestic Business Day" means any day except a Saturday, Sunday or other day on which commercial banks in New York, New York are authorized or required by law to close. "Domestic Disbursement" means a Disbursement that bears interest on the basis of the Base Rate in accordance with Section 2.07(b). "Domestic Disbursement Participation" means a Disbursement Participation in a Domestic Disbursement. "Domestic Lending Office" of any Bank means (a) (i) in the case of the Purchasing Bank, the Purchasing Bank's office located at One Wall Street, New York, New York and (ii) in the case of a Participating Bank, the branch or office of such Bank set forth below such Bank's name under the heading "Domestic Lending Office" on Annex A or, in the case of a Participating Bank that became a Participating Bank pursuant to Section 7.07(b) or (c), the branch or office of such Bank designated as its "Domestic Lending Office" in the Joinder Agreement or Assignment and Acceptance pursuant to which such Bank became a Participating Bank or (b) in the case of any Bank, such other branch or office of such Bank designated by such Bank from time to time as the branch or office at which its Domestic Disbursement Participations are to be made or maintained. "Enacted", as applied to a Regulatory Change, means the date such Regulatory Change first becomes effective or is implemented or first required or expected to be complied with, whether the same is (a) the result of an enactment by a government or any agency or political subdivision thereof, a determination of a court or regulatory authority, a request or directive of a regulatory authority, or otherwise or (b) enacted, adopted, issued or proposed before or after the Closing Date. "Environmental Laws" means any and all Applicable Laws relating to the environment or to emissions, discharges or releases of Contaminants into the environment including, ambient air, surface water, ground water or land, or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of Contaminants or the clean-up or other remediation thereof. "Environmental Liabilities and Costs" means all liabilities, obligations, responsibilities, obligations to conduct Remedial Actions, losses, damages, punitive damages, consequential damages, treble damages, costs and expenses (including all reasonable fees, disbursements and expenses of counsel, expert and consulting fees and costs of investigations and feasibility studies), fines, penalties, and monetary sanctions, interest, direct or indirect, known or unknown, absolute or contingent, past, present or future, resulting from any claim or demand, by any Person, whether based in contract, tort, implied or express warranty, strict liability, criminal or civil statute, including any Environmental Law, arising from on-site environmental, health or safety conditions, or the Release or threatened Release of a Contaminant into the environment, as a result of past, present or future operations of the Company or any previous owners or lessees of any of its properties. "ERISA" means the Employee Retirement Income Security Act of 1974 and the rules and regulations issued thereunder, as from time to time in effect. "ERISA Affiliate" means any trade or business (whether or not incorporated) that is a member of a group of (a) organizations described in Section 414(b) or (c) of the Code and (b) solely for purposes of potential liability under Section 302(c)(11) of ERISA and Section 412(c)(ii) of the Code and the Lien created under Section 302(f) of ERISA and under Section 412(n) of the Code, organizations described in Section 414(m) or (o) of the Code of which the Company is a member. "ERISA Termination Event" means, with respect to any Plan, (a) any Reportable Event with respect to such Plan, (b) the termination of such Plan, or the filing of notice of intent to terminate such Plan, or the treatment of any amendment to such Plan as a termination under ERISA Section 4041, (c) the institution of proceedings to terminate such Plan under ERISA Section 4042 or (d) the appointment of a trustee to administer such Plan under ERISA Section 4042. "Euro-Dollar Business Day" means any Domestic Business Day on which commercial banks are open for international business (including dealings in dollar deposits) in the London interbank market. "Euro-Dollar Disbursement" means a Disbursement that bears interest on the basis of an Adjusted London Interbank Offered Rate in accordance with Section 2.07(b). "Euro-Dollar Disbursement Participation" means a Disbursement Participation in a Euro-Dollar Disbursement. "Euro-Dollar Lending Office" of any Bank means (a) (i) in the case of the Purchasing Bank, the Purchasing Bank's office located at One Wall Street, New York, New York and (ii) in the case of a Participating Bank, the branch or office of such Bank set forth below such Bank's name under the heading "Euro- Dollar Lending Office" on Annex A or, in the case of a Participating Bank that became a Participating Bank pursuant to Section 7.07(b) or (c), the branch or office of such Bank designated as its "Euro-Dollar Lending Office" in the Joinder Agreement or Assignment and Acceptance pursuant to which such Bank became a Participating Bank or (b) in the case of any Bank, such other branch or office of such Bank designated by such Bank from time to time as the branch or office at which its Euro-Dollar Participations are to be made or maintained. "Euro-Dollar Reserve Percentage" means for any day that percentage (expressed as a decimal) which is in effect on such day, as prescribed by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement for a member bank of the Federal Reserve System in New York City with deposits exceeding five billion dollars in respect of "Eurocurrency liabilities" (or in respect of any other category of liabilities that includes deposits by reference to which the interest rate on Euro-Dollar Disbursements is determined or any category of extensions of credit or other assets that includes loans by a non-United States office of the Purchasing Bank to United States residents). "Event of Default" has the meaning set forth in Section 6.01. "Event of Suspension" has the meaning set forth in Section 6.02(a). "Event of Termination" or "event of termination" has the meaning set forth in Section 6.02(b). "Federal Funds Rate" means, for any day, the rate per annum (rounded upwards, if necessary, to the nearest 1/100th of 1 percent) equal to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers on such day, as published by the Federal Reserve Bank of New York on the Domestic Business Day next succeeding such day; provided that (a) if such day is not a Domestic Business Day, the Federal Funds Rate for such day shall be such rate on such transactions on the next preceding Domestic Business Day as so published on the next succeeding Domestic Business Day, and (b) if no such rate is so published on such next succeeding Domestic Business Day, the Federal Funds Rate for such day shall be the average rate quoted to the Purchasing Bank on such day on such transactions as determined by the Purchasing Bank. "First Mortgage Bonds" means the 1996 Series B First Mortgage Bonds issued by the Company and delivered to the Trustee. "First Mortgage Indenture" means the Indenture of Mortgage and Deed of Trust, dated as of May 1, 1921, between the Company and Bankers Trust Company, as trustee. "Fixed Rate Mode" has the meaning ascribed to such term in the Indenture. "Flexible Mode" has the meaning ascribed to such term in the Indenture. "Fund" means any Person (other than a natural Person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary of its business. "GAAP" means generally accepted accounting principles in the United States in effect from time to time, as applied to a regulated utility. "Governmental Approval" means any authorization, consent, approval, license (or the like) or exemption (or the like) of any Governmental Authority. "Governmental Authority" means any Federal, state, local or foreign court or governmental agency, authority, instrumentality or regulatory body. "Governmental Registration" means any registration or filing (or the like) with, or report or notice (or the like) to, any Governmental Authority. "Indenture" means the Amended and Restated Indenture of Trust, dated as of May 1, 1996, as amended and restated as of January 1, 1997, between the Issuer and State Street Bank and Trust Company (successor to Fleet National Bank), as trustee. "Interest Commitment" means 918,000 dollars (calculated on the basis of an assumed rate of 12 percent per annum for 45 days on the initial Principal Commitment), as such amount may be reduced from time to time pursuant to Section 2.10. Any termination of the Commitment shall be deemed to reduce the Interest Commitment to zero. "Interest Disbursement" means a Disbursement made for the purpose of paying that portion of the Purchase Price for Unremarketed Bonds corresponding to accrued and unpaid interest thereon. "Interest Payment Date" means the first day of each month. "Interest Period" means, with respect to each Euro-Dollar Disbursement, a period commencing on the date specified in the applicable Notice of Interest Rate Election and ending one, two, three or six months thereafter, as the Company may elect in such Notice of Interest Rate Election; provided that (a) any Interest Period that would otherwise end on a day that is not a Euro- Dollar Business Day shall be extended to the next succeeding Euro-Dollar Business Day unless such day falls in another calendar month, in which case such Interest Period shall end on the next preceding Euro-Dollar Business Day; and (b) any Interest Period that begins on the last Euro-Dollar Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Euro-Dollar Business Day of a calendar month. "Issuer" means the Connecticut Development Authority. "Joinder Agreement" means a joinder agreement in the form of Exhibit 7.07(b) with such variations as shall be acceptable to the Persons whose consent is required therefor under Section 7.07(b). "Lead Arranger" means BNY Capital Markets, Inc. "Lien" means any mortgage, pledge, title retention agreement, lien, claim, charge, encumbrance or security interest. "Loan Agreement" means the Amended and Restated Loan Agreement, dated as of May 1, 1996, as amended and restated as of January 1, 1997, between the Issuer and the Company. "London Interbank Offered Rate" means, in regards to any Interest Period, the rate per annum (rounded upward, if necessary, to the next higher 1/16 of 1 percent) at which deposits in U.S. dollars are offered to the Purchasing Bank in the London interbank market at approximately 11:00 a.m. (London time) two Euro-Dollar Business Days before the first day of such Interest Period in an amount approximately equal to the principal amount of the Euro-Dollar Disbursement to which such Interest Period is to apply and for a period of time comparable to such Interest Period. "Materially Adverse Effect" means, relative to any occurrence of whatever nature (including any adverse determination in any litigation, arbitration, or governmental investigation or proceeding), a materially adverse effect on (a) the consolidated business, assets, revenues, financial condition, results of operations, operations, or prospects of the Company and its Subsidiaries; (b) the ability of the Company to make any payment when due under this Agreement or to perform any of its other obligations hereunder or under the Related Documents; or (c) the legality, validity, binding nature or enforceability of this Agreement or any of the Related Documents. "Maximum Interest Rate" means, with respect to interest payable on any amount, the rate of interest on such amount that, if exceeded, could, under Applicable Law, result in (a) civil or criminal penalties being imposed upon the payee or (b) the payee's being unable to enforce payment of (or, if collected, retain) all or any part of such amount or the interest payable thereon. "Moody's" means Moody's Investors Service, Inc. "Mortgage Bond Documents" means the First Mortgage Bonds, the First Mortgage Indenture (to the extent relating to the issuance of the First Mortgage Bonds) and any supplemental indenture or indentures pursuant to which the Company creates, issues and delivers to the Trustee its First Mortgage Bonds. "Multiannual Mode" has the meaning ascribed to such term in the Indenture. "Multiemployer Plan" means a multiemployer plan as defined in Section 4001(a)(3) of ERISA to which the Company or any ERISA Affiliate is making or accruing an obligation to make contributions, or has within any of the preceding five plan years made or accrued an obligation to make contributions. "Non-US Bank" means a Person that is not a United States Person and that is not described in Section 881(c)(3) of the Code. "Non-US Bank Certificate" means a certificate in the form of Exhibit 2.16. "Notice of Interest Rate Election" means a notice in the form of Exhibit 2.07. "Notice of Prepayment" means a notice in the form of Exhibit 2.06. "NU" means Northeast Utilities. "Offering Circular" means any offering circular or other document (whether preliminary or final) used in connection with the offering and sale or the re-offering and re-sale or remarketing of the Bonds, including the Reoffering Circular. "Parent" means, with respect to a Bank, any Person controlling such Bank. "Participating Bank" means (a) any Person listed on Annex A and (b) any Person that is granted a Participation Interest by the Purchasing Bank pursuant to Section 7.07(b) or is assigned a Participation Interest by a Participating Bank pursuant to Section 7.07(c). "Participation Amount" of any Participating Bank means the amount set forth opposite such Participating Bank's name under the heading "Participation Amount" on Annex A or, in the case of a Participating Bank that became a Participating Bank pursuant to Section 7.07(b) or (c), the Participation Amount granted or assigned to such Participating Bank, in any case, as the same may be reduced from time to time pursuant to Section 2.10(d) or reduced or increased from time to time pursuant to assignments in accordance with Section 7.07(c). "Participation Interests" means, with respect to a Participating Bank, such Participating Bank's participation interests in the Commitment and outstanding Disbursements. "Participation Share" means, at any time, (a) so long as the Commitment has not expired or been terminated, (i) with respect to the Purchasing Bank, the percentage equivalent of a fraction, the numerator of which shall be the amount of the Commitment at such time reduced by the sum of all of the Participating Banks' Participation Amounts at such time and the denominator of which shall be the amount of the Commitment at such time, and (ii) with respect to a Participating Bank, the percentage equivalent of a fraction, the numerator of which shall be such Participating Bank's Participation Amount at such time and the denominator of which shall be the amount of the Commitment at such time, and (b) at any time after the Commitment has expired or been terminated, (i) with respect to the Purchasing Bank, the percentage equivalent of a fraction, the numerator of which shall be the amount of the aggregate principal amount of outstanding Disbursements at such time reduced by the sum of all of the Participating Banks' Participation Interests in the principal of outstanding Disbursements at such time and the denominator of which shall be the aggregate principal amount of outstanding Disbursements at such time, and (ii) with respect to a Participating Bank, the percentage equivalent of a fraction, the numerator of which shall be the aggregate amount of such Participating Bank's Participation Interests in the principal of outstanding Disbursements at such time and the denominator of which shall be the amount of the aggregate principal amount of Disbursements at such time. "Paying Agent" has the meaning ascribed to such term in the Indenture. "PBGC" means the Pension Benefit Guaranty Corporation or any Person succeeding to any or all of its functions under ERISA. "Person" means an individual, a corporation, a partnership, a limited liability company, an association, a trust or any other entity or organization, including a government or political subdivision or an agency or instrumentality thereof. "Plan" means any employee pension benefit plan (other than a Multiemployer Plan) subject to the provisions of Title IV of ERISA that is maintained for current or former employees, or any beneficiaries thereof, of the Company or any ERISA Affiliate. "Prime Rate" means the rate of interest publicly announced by The Bank of New York in New York City from time to time as its prime commercial lending rate (which rate is a reference rate and not necessarily the lowest rate of interest charged by The Bank of New York to its prime customers). "Principal Commitment" means 62,000,000 dollars, as such amount may be reduced from time to time pursuant to Section 2.10. Any termination of the Commitment shall be deemed to reduce the Principal Commitment to zero. "Principal Disbursement" means a Disbursement made for the purpose of paying that portion of the Purchase Price for Unremarketed Bonds corresponding to the principal amount thereof. "Purchase Certificate" means a certificate in the form of Exhibit 2.01. "Purchase Date" means each date fixed for the purchase of Bonds by the Purchasing Bank in accordance with the terms of the Indenture. "Purchase Price" has the meaning assigned to that term in Section 2.01(a)(i). "Purchasing Bank" means The Bank of New York. "Register" has the meaning assigned to that term in Section 7.07(d). "Regulatory Change" means any Applicable Law, interpretation, directive, determination, request or guideline (whether or not having the force of law), or any change therein or in the administration or enforcement thereof, that is Enacted after the Closing Date, including any such that imposes, increases or modifies any Tax, reserve requirement, insurance charge, special deposit requirement, assessment or capital adequacy requirement, or determines that the Commitment does not constitute commitments with an original maturity of one year or less, but excluding any such that imposes, increases or modifies any Tax on the overall net income of a Bank. "Related Documents" means the Bond Documents, the Bond Insurance Policy, the Remarketing Agreement and the Tax Regulatory Agreement. "Release" means any release, spill, emission, leaking, pumping, injection, deposit, disposal, discharge, disbursal, leeching or migration into the indoor or outdoor environment or into or out of any property owned by the Company or any of its Subsidiaries, including the movement of Contaminants through or in the air, soil, surface water, ground water or property. "Remarketing Agent" has the meaning ascribed to such term in the Indenture. "Remarketing Agreement" means the Remarketing Agent's Agreement, dated as of May 1, 1996, among the Issuer, the Company and the Lead Arranger (as successor Remarketing Agent to Goldman, Sachs and Co.) or any successor remarketing agreement or agreements entered into in connection with the Bonds in accordance herewith and with the Indenture. "Remedial Action" means all actions required to (a) clean up, remove, treat or in any other way adjust Contaminants in the indoor or outdoor environment; (b) prevent the Release or threat of Release or minimize the further Release of Contaminants so that they do not migrate or endanger or threaten to endanger public health or welfare or the indoor or outdoor environment; or (c) perform pre-remedial studies and investigations and post-remedial monitoring and care. "Reoffering Circular" means the Reoffering Circular of the Company, dated January 20, 1997, including documents incorporated therein by reference, used in connection with the reoffering of the Bonds, and any supplement thereto used with respect to the Bonds. "Reportable Event" means any reportable event as defined in Section 4043(c) of ERISA or the regulations issued thereunder with respect to a Plan (other than a Plan maintained by an ERISA Affiliate that is considered an ERISA Affiliate only pursuant to subsection (m) or (o) of Code Section 414) requiring notice to PBGC under applicable regulations. "Required Banks" means, at any time, Banks the aggregate of whose Participation Shares at such time exceeds 50 percent. "S and P" means Standard and Poor's Ratings Services (a division of The McGraw-Hill Companies, Inc.). "SG Bond Purchase Agreement" means that Standby Bond Purchase Agreement, dated January 23, 1997, among The Connecticut Light and Power Company, Societe Generale, New York Branch, as bank, and Fleet National Bank, as trustee. "Stated Expiration Date" means October 23, 2001. "Subparticipant" has the meaning assigned to that term in Section 7.07(c) "Subsidiary" means, as to any Person, any corporation, association, partnership, joint venture or other business entity of which such Person or any Subsidiary of such Person, directly or indirectly, either (a) in respect of a corporation, owns or controls more than 50 percent of the outstanding stock having ordinary voting power to elect a majority of the board of directors or similar managing body of such corporation, irrespective of whether a class or classes shall or might have voting power by reason of the happening of any contingency, or (b) in respect of an association, partnership, joint venture or other business entity, is entitled to share in more than 50 percent of the profits and losses, however determined of such entity. "Tax" means any Federal, State or foreign tax, assessment, or other charge imposed by a Governmental Authority upon a Person or upon its assets, revenues, income or profits. "Tax Regulatory Agreement" means the Tax Regulatory Agreement, dated as of the date of initial issuance and delivery of the Bonds, among the Issuer, the Company and the Trustee. "Trustee" has the meaning ascribed to such term in the Indenture. "United States" means the United States of America, including the States and the District of Columbia, but excluding its territories and possessions. "United States Person" means a corporation, partnership or other entity created, organized or incorporated under the laws of the United States of America or a State thereof (including the District of Columbia). "Unremarketed Bonds" means Bonds in Daily, Weekly or Flexible Mode that are tendered or deemed tendered for purchase pursuant to the provisions of the Indenture and for which remarketing proceeds have not been received by the Remarketing Agent. "Weekly Mode" has the meaning ascribed to such term in the Indenture. "Welfare Plan" means a "welfare plan", as such term is defined in Section 3(1) of ERISA. "Withdrawal Liability" means liability to a Multiemployer Plan as a result of a complete or partial withdrawal from such Multiemployer Plan, as such terms are defined in Part I of Subtitle E of Title IV of ERISA. Section 1.02 Accounting Terms and Determinations. Except as otherwise expressly provided herein, all terms of an accounting or financial nature shall be construed in accordance with GAAP. Section 1.03 Basis for Ratings. Except with respect to the ratings assigned to the Bonds, the Company's senior secured debt or the Bond Insurer's claims-paying ability, references herein to credit ratings are to ratings assigned to unsecured obligations without third party credit support. Except as aforesaid, ratings assigned to any obligation that is secured or that has the benefit of third party credit support shall be disregarded. For purposes hereof, the rating in effect on any date is that in effect on the close of business on such date. Section 1.04 Interpretation. (a) Except as otherwise specified herein, all references herein (i) to any Person shall be deemed to include such Person's successors and assigns, (ii) to any Applicable Law defined or referred to herein shall be deemed references to such Applicable Law or any successor Applicable Law as the same may have been or may be amended or supplemented from time to time and (iii) to any agreement or contract defined or referred to herein shall be deemed references to such agreement or contract (and, in the case of any instrument, any instrument issued in substitution therefor) as the terms thereof may have been or may be amended, supplemented, waived or otherwise modified from time to time. (b) When used in this Agreement, the words "herein", "hereof" and "hereunder" and words of similar import shall refer to this Agreement as a whole and not to any provision of this Agreement, and the words "Article", "Section", "Annex", "Schedule" and "Exhibit" shall refer to Articles and Sections of, and Annexes, Schedules and Exhibits to, this Agreement unless otherwise specified. (c) Whenever the context so requires, the neuter gender includes the masculine or feminine, the masculine gender includes the feminine, and the singular number includes the plural, and vice versa. (d) Any item or list of items set forth following the word "including", "include" or "includes" is set forth only for the purpose of indicating that, regardless of whatever other items are in the category in which such item or items are "included", such item or items are in such category, and shall not be construed as indicating that the items in the category in which such item or items are "included" are limited to such items or to items similar to such items. (e) Each authorization in favor of a Bank or any other Person granted by or pursuant to this Agreement shall be deemed to be irrevocable and coupled with an interest. (f) Except as otherwise specified herein, all references to the time of day shall be deemed to be to New York City time as then in effect. ARTICLE II standby bond purchase facility Section 2.01 Purchase of Unremarketed Bonds. (a) Commitment to Purchase Unremarketed Bonds. (i) Subject to the terms and conditions of this Agreement, the Purchasing Bank agrees to purchase Unremarketed Bonds on any Domestic Business Day prior to the Commitment Termination Date at a price (the "Purchase Price") equal to 100 percent of the principal amount thereof plus (if such Purchase Date is not a day on which interest is payable on such Unremarketed Bonds) accrued interest, if any, to such Purchase Date; provided, however, that (A) the aggregate Purchase Price payable by the Purchasing Bank on any Purchase Date shall not exceed (x) with respect to the portion of such aggregate Purchase Price corresponding to principal of the Unremarketed Bonds to be purchased, the Available Principal Commitment as in effect on such Purchase Date and (y) with respect to the portion of such aggregate Purchase Price corresponding to accrued interest on the Unremarketed Bonds to be purchased, the Available Interest Commitment as in effect on such Purchase Date; and (B) Unremarketed Bonds that are held by or for the account of the Company, any Affiliate of the Company or any broker-dealer holding Unremarketed Bonds pursuant to an arrangement with the Company or any Affiliate of the Company shall not be purchased by the Purchasing Bank hereunder. (ii) Each Participating Bank shall have a participation interest in the Commitment and each Disbursement made pursuant thereto, to the extent of such Bank's Participation Share thereof. The Purchasing Bank shall remain solely responsible to the Company, the Paying Agent, the Trustee and the holders of the Bonds for the performance of the entire Commitment notwithstanding such grant of participation interests to the Participating Banks, and its obligations to such Persons hereunder shall be undiminished thereby. (b) Manner of Purchase. (i) If the Purchasing Bank receives a Purchase Certificate from the Paying Agent no later than (x) 12:30 p.m. on the specified Purchase Date, in the case of Unremarketed Bonds that are in the Weekly Mode, or (y) 1:00 p.m. on the specified Purchase Date, in the case of Unremarketed Bonds that are in the Daily Mode or in the Flexible Mode, the Purchasing Bank will, subject to satisfaction of the other terms and conditions set forth in this Agreement, transfer not later than 3:00 p.m. on such Purchase Date to the Paying Agent, in funds to be available as specified in such Purchase Certificate, an amount equal to the aggregate Purchase Price for such Unremarketed Bonds. The Purchasing Bank agrees to use its own funds to purchase Unremarketed Bonds. (ii) Upon receiving a Purchase Certificate from the Paying Agent, the Purchasing Bank shall promptly give each Participating Bank telephonic notice (confirmed in writing) of (A) the applicable Purchase Date, (B) the aggregate amount of Disbursements to be made on such date and (C) such Participating Bank's Participation Share of such aggregate amount of Disbursements. Each Participating Bank shall pay to the Purchasing Bank such Participating Bank's Participation Share of the Disbursements to be made on the specified Purchase Date no later than (A) 3:00 p.m. on the date such notice is given to such Bank (or, if later, the specified Purchase Date) if such notice is given by 1:30 p.m. on any Domestic Business Day, or (B) 12:00 p.m. on the Domestic Business Day following the date such notice is given to such Bank if such notice is given after 1:30 p.m. on any Domestic Business Day on or after the specified Purchase Date. If a Participating Bank should for any reason not make any payment to the Purchasing Bank hereunder on the date such payment is due, the Purchasing Bank shall be entitled to recover from such Participating Bank such amounts, plus interest thereon from and including the date such payment was due to but excluding the day such amounts are recovered by the Purchasing Bank at the Federal Funds Rate until (and including) the third Domestic Business Day after the date due and thereafter at the Base Rate plus 2 percent. Section 2.02 Purchased Bonds as Bank Bonds; Bank Rate. Pursuant to Section 2.3(G)(9) of the Indenture, Unremarketed Bonds purchased by the Purchasing Bank pursuant to Section 2.01 shall constitute Bank Bonds and shall bear interest on the unpaid principal amount thereof at the Bank Rate. Interest on Bank Bonds shall be payable monthly in arrears on each Interest Payment Date (or, in the event that the maturity of the Bonds shall have been accelerated in accordance with the terms of the Bond Documents, payable on demand by the Purchasing Bank). As provided in Sections 2.3(G)(9) and 9.10(4) of the Indenture, Bank Bonds shall be held in trust by the Paying Agent for the benefit of the Purchasing Bank. Section 2.03 Redemption of Bank Bonds. (a) Bank Bonds shall be subject to mandatory and optional redemption as provided in Sections 2.4(A), (C), (D) and (G)(ii) of the Indenture and, as permitted by Section 2.4(G)(i) of the Indenture, shall also be subject to mandatory redemption as provided in Section 2.03(b) and (c). (b) The Bank Bonds outstanding on the Stated Expiration Date shall be redeemed in ten consecutive semi-annual installments of equal principal amount, commencing on the date six months after the Stated Expiration Date, at a price equal to the principal amount thereof plus accrued and unpaid interest at the Bank Rate to but excluding the date of redemption. If, after the Stated Expiration Date, any Bank Bonds are otherwise redeemed or cease to be Bank Bonds as a result of being remarketed or purchased by the Company, the remaining redemption installments shall be reduced in inverse order of their maturity. (c) Upon receipt by the Trustee of a demand by the Purchasing Bank in accordance with clause (iii) of the second sentence of Section 6.02(b), all outstanding Bank Bonds shall be immediately redeemed at a price equal to the principal amount thereof plus accrued and unpaid interest at the Bank Rate to but excluding the date of redemption. Section 2.04 Remarketing of Bank Bonds. (a) In accordance with Section 9.19 of the Indenture, the Remarketing Agent shall solicit offers to purchase and use its best efforts to find a purchaser for Bank Bonds; provided, however, that Bank Bonds shall not be released by the Paying Agent unless and until the Purchasing Bank has been paid the principal of and interest accrued on such Bonds at the Bank Rate. (b) Notwithstanding the foregoing, no Bank Bonds shall be remarketed after the Commitment Termination Date or the date, if any, on which the maturity of the Bonds shall have been accelerated in accordance with the terms of the Bond Documents, unless the purchaser of such Bonds shall have acknowledged, in a manner reasonably satisfactory to the Purchasing Bank, that such Bonds shall not be entitled to the benefits of this Agreement. Section 2.05 Application of Payments on Bank Bonds. Payments received by the Purchasing Bank in respect of the principal of or interest on Bank Bonds (whether pursuant to a scheduled payment thereof, upon redemption or acceleration, upon purchase of Bank Bonds pursuant to a remarketing thereof or substitution of another liquidity facility, or otherwise) shall be applied as follows: (a) Payments in respect of principal of Bank Bonds shall be applied to the payment of the Principal Disbursements. (b) Payments in respect of interest accrued on Bank Bonds at the time of their purchase by the Purchasing Bank shall be applied to the payment of Interest Disbursements. (c) Payments in respect of interest accruing on Bank Bonds after their purchase by the Purchasing Bank shall be applied in the following order of priorities: first to the payment of accrued and unpaid interest on the Disbursements, second, to the payment of accrued and unpaid fees and expenses payable to the Banks hereunder, and third, to the Company (or if such payment shall have been made by the Bond Insurer pursuant to the Bond Insurance Policy, to the Bond Insurer). Section 2.06 Repayment and Prepayment of Disbursements. (a) Scheduled Repayments. (i) Interest Disbursements. The Company shall repay in full the Interest Disbursements made on any Purchase Date on the first Interest Payment Date following such Purchase Date. (ii) Principal Disbursements. The Company shall repay the aggregate amount of Principal Disbursements remaining outstanding on the Stated Expiration Date in ten equal consecutive semi-annual installments commencing on the date six months after such date. Additional amounts of Principal Disbursements paid or prepaid after the Stated Expiration Date shall be applied to the remaining installments in inverse order of maturity. (b) Optional Prepayments. The Company may, at any time and from time to time, prepay the Disbursements in whole or in part, without premium or penalty, except that any optional partial prepayment shall be in an aggregate principal amount of 1,000,000 dollars or any multiple of 100,000 dollars in excess thereof. Any prepayment of Euro-Dollar Disbursements made on a day other than the last day of the applicable Interest Periods therefor shall be accompanied by the amount, if any, required to be paid in respect thereof pursuant to Section 2.15. The Company shall give the Purchasing Bank a Notice of Prepayment no later than 11:00 a.m. on, in the case of a prepayment of Domestic Disbursements, the Domestic Business Day before the date of such prepayment and, in the case of a prepayment of Euro-Dollar Disbursements, the third Euro-Dollar Business Day before the date of such prepayment. Each Notice of Prepayment shall specify (i) the date such prepayment is to be made, (ii) the Disbursements to be prepaid (whether Domestic Disbursements or Euro-Dollar Disbursements and, in the case of Euro-Dollar Disbursements, the last day of the applicable Interest Periods for such Disbursements) and (iii) for each such Disbursement, the amount thereof to be prepaid. Amounts to be so prepaid shall irrevocably be due and payable on the date specified in the applicable Notice of Prepayment, together with interest accrued thereon to but excluding the date of prepayment. The Purchasing Bank shall give each Participating Bank prompt notice of each Notice of Prepayment that it receives and the amounts of such Participating Bank's Participation Interests in Disbursements affected thereby. (c) Mandatory Prepayments. (i) If at any time the aggregate principal amount of outstanding Principal Disbursements shall exceed the aggregate principal amount of Bank Bonds, the Company shall, upon demand by the Purchasing Bank, immediately prepay Principal Disbursements to such extent. If at any time the amount of any outstanding Interest Disbursement made in connection with the purchase of an Unremarketed Bond shall exceed the amount of interest accrued on such Bank Bond at the time of its purchase that then remains unpaid, the Company shall, upon demand by the Purchasing Bank, immediately prepay such Interest Disbursement to such extent. (ii) On each date that Bank Bonds are required to be redeemed pursuant to Section 2.03(A), (C), (D) or G(ii) of the Indenture or Section 2.03(c), the Company shall prepay (A) Principal Disbursements in an aggregate principal amount equal to the aggregate amount of Bank Bonds required to be redeemed and (B) to the extent not previously paid, the full amount of all Interest Disbursements, if any, made by the Purchasing Bank as part of the Purchase Price for such Bonds. (iii) Without duplication of other payments or prepayments required under this Section 2.06, on each date that any payments are received by the Purchasing Bank in respect of principal of Bank Bonds or interest accrued on Bank Bonds at the time of their purchase by the Purchasing Bank, Disbursements shall be prepaid through the application of such payments as provided in Section 2.05. (d) Transfer of Excess Bank Bonds. If at any time the aggregate principal amount of Bank Bonds shall exceed the aggregate principal amount of outstanding Principal Disbursements (as a result of a prepayment pursuant to Section 2.06(b) or otherwise), the Bank shall, upon request of the Company, transfer to the Company Bank Bonds in an aggregate principal amount equal to such excess. Section 2.07 Interest on Disbursements and Other Amounts. (a) Interest Rate Options. (i) All Disbursements made by the Purchasing Bank on any Purchase Date shall initially be Domestic Disbursements. Thereafter, the Company may from time to time elect to change or continue the type of interest rate borne by each Disbursement Group (subject in each case to the provisions of Sections 2.11 and 2.12), as follows: (A) if such Disbursements are Domestic Disbursements, the Company may elect to convert such Disbursements to Euro-Dollar Disbursements as of any Euro-Dollar Business Day; and (B) if such Disbursements are Euro-Dollar Disbursements, the Company may elect to convert such Disbursements to Domestic Disbursements or elect to continue such Disbursements as Euro-Dollar Disbursements for an additional Interest Period, in each case effective on the last day of the then current Interest Period applicable to such Disbursements. (ii) Each such election shall be made by delivering a Notice of Interest Rate Election to the Purchasing Bank no later than 11:00 a.m. on the third Euro- Dollar Business Day before the conversion or continuation selected in such notice is to be effective. A Notice of Interest Rate Election may, if it so specifies, apply to only a portion of the aggregate principal amount of the relevant Disbursement Group; provided that the portion to which such Notice of Interest Rate Election applies, and the remaining portion to which it does not apply, are each at least 3,000,000 dollars. (iii) Each Notice of Interest Rate Election shall specify (A) the Disbursement Group (or portion thereof) to which such notice applies; (B) the date on which the conversion or continuation selected in such notice is to be effective, which shall comply with the applicable clause of subsection (i) above; (C) if the Disbursements comprising such Disbursement Group are to be converted, the new type of Disbursements (i.e. Domestic or Euro-Dollar) and, if such new Disbursements are Euro-Dollar Disbursements, the duration of the initial Interest Period applicable thereto; and (D) if such Disbursements are to be continued as Euro-Dollar Disbursements for an additional Interest Period, the duration of such additional Interest Period. Each Interest Period specified in a Notice of Interest Rate Election shall comply with the provisions of the definition of Interest Period. (iv) A Notice of Interest Rate Election is nonrevocable by the Company. If the Company fails to deliver a timely Notice of Interest Rate Election to the Purchasing Bank for any Disbursement Group of Euro-Dollar Disbursements, such Disbursements shall be converted into Domestic Disbursements on the last day of the then current Interest Period applicable thereto. (v) The Purchasing Bank shall give each Participating Bank prompt notice of each Notice of Interest Rate Election that it receives and the amounts of such Participating Bank's Participation Interests in Disbursements affected thereby. (vi) Notwithstanding anything herein to the contrary, (A) the Company may not elect to convert a Domestic Disbursement to a Euro-Dollar Disbursement or continue a Euro-Dollar Disbursement as a Euro-Dollar Disbursement for another Interest Period at any time that a Default shall have occurred and be continuing, and (B) the Company shall convert and continue Disbursements in a manner such that no payment of Euro-Dollar Disbursements will have to be made prior to the last day of an applicable Interest Period in order to repay the Disbursements in the amounts and on the dates specified in Section 2.06(a). (b) Applicable Rates. (i) Subject to Section 2.07(c), each Domestic Disbursement shall bear interest on the outstanding principal amount thereof, for each day from and including the date such Disbursement is made to but excluding the date such Disbursement is required to be repaid hereunder, at a rate per annum equal to the Base Rate for such day. (ii) Subject to Section 2.07(c), each Euro-Dollar Disbursement shall bear interest on the outstanding principal amount thereof, for each day during each Interest Period applicable thereto, at a rate per annum equal to the sum of the Applicable Margin for such day plus the Adjusted London Interbank Offered Rate applicable to such Interest Period. (c) Overdue Amounts. Any overdue principal of, or interest on, any Disbursement and any other amount payable hereunder that is not paid when due, whether at stated maturity or otherwise, shall bear interest, from the date the same becomes due until such amount is paid in full, at a rate per annum equal to 2 percent over the Base Rate as in effect from time to time (except that an overdue amount of principal of a Euro-Dollar Disbursement that becomes due prior to the last day of an applicable Interest Period shall bear interest at a rate per annum equal to 2 percent above the rate that would otherwise be applicable to such Disbursement until the last day of such Interest Period and at a rate per annum equal to 2 percent over the Base Rate in effect from time to time thereafter). (d) Payment Dates. Interest on Disbursements shall be payable (i) on each Interest Payment Date, (ii) at the time of any payment or prepayment of Disbursements to the extent accrued on the amount paid or prepaid and (iii) at such other times as required by Section 2.05(c). Notwithstanding the foregoing, interest on overdue amounts (including overdue amounts of Disbursements) shall be payable on demand. Section 2.08 Commitment Fee. The Company shall pay to the Purchasing Bank a commitment fee at a per annum rate for each day equal to the Commitment Fee Rate for such day on the Combined Available Commitment at the close of business on such day. Such commitment fee shall accrue from and including the Closing Date to but excluding the Commitment Termination Date. Fees accrued under this Section shall be payable (i) quarterly in arrears on each March 31, June 30, September 30 and December 31 (commencing on December 31, 2000) and (ii) on the Commitment Termination Date. If the Commitment is reduced pursuant to Section 2.10, all fees accrued under this Section to but excluding the effective date of such reduction with respect to portion of the Combined Available Commitment eliminated by such reduction shall be payable on such date. Section 2.09 Computation of Interest and Fees; Maximum Interest Rate. (a) Interest based on the Prime Rate shall be computed on the basis of a year of 365 days (or 366 days in a leap year) and paid for the actual number of days elapsed (including the first day but excluding the last day). All other interest and all fees shall be computed on the basis of a year of 360 days and paid for the actual number of days elapsed (including the first day but excluding the last day). (b) The Purchasing Bank shall determine each interest rate applicable hereunder. The Purchasing Bank shall give prompt notice to the Company and the Participating Banks of each rate of interest so determined, and its determination thereof shall be conclusive in the absence of manifest error. (c) Nothing contained herein shall require the payment of interest on Bank Bonds or Disbursements at a rate exceeding the Maximum Interest Rate. If interest payable on any Bank Bond or Disbursement for any period would otherwise exceed the maximum amount permitted by the Maximum Interest Rate, such interest payment shall automatically be reduced to such maximum permitted amount, and interest on other Bank Bonds or Disbursements (as the case may be) for such period and/or interest on all Bank Bonds or Disbursements (as the case may be) for subsequent periods, to the extent less than the maximum amount permitted by the Maximum Interest Rate, shall be increased to permit payment of such reduction at the earliest possible date. Section 2.10 Reduction or Termination of Commitment. (a) Reduction upon Retirement of Bank Bonds. In the event of any redemption, cancellation, defeasance, or any other retirement of any Bonds, the Company shall have the right to reduce the Principal Commitment by an amount equal to the principal amount of Bonds so redeemed, canceled, defeased, or otherwise retired, by giving to the Purchasing Bank written notice of such reduction (which notice shall state the amount of such reduction and the date or dates of such redemption, purchase and cancellation, defeasance, or other retirement). (b) Reduction upon Conversion of Bank Bonds. Any time after the close of business on the fifth Domestic Business Day following the date on which Bonds are converted to Fixed Rate Mode or Multiannual Mode (but prior, in the case of Bonds converted to Multiannual Mode, to any date on which the Company gives notice of its intent to convert such Bonds to Daily, Weekly or Flexible Mode), the Company shall have the right to reduce the Principal Commitment by an amount equal to the principal amount of Bonds so converted, by giving to the Purchasing Bank written notice of such reduction (which notice shall state the amount of such reduction and the date or dates of such conversion). (c) Optional Termination by the Company. (i) The Company shall have the right to terminate the Commitment at any time upon 30 days' written notice to the Purchasing Bank, the Bond Insurer, the Trustee, the Paying Agent and the Remarketing Agent; provided, however, that in connection with any such termination the Company shall pay to the Banks any and all amounts then accrued or owing to the Banks under this Agreement and there shall be purchased from the Purchasing Bank all Bank Bonds, together with accrued interest thereon. (ii) In the event that (A) the Purchasing Bank shall fail to purchase Unremarketed Bonds when required under the terms or conditions of this Agreement or (B) bankruptcy, insolvency, receivership, liquidation or other similar proceedings are instituted against the Purchasing Bank, the Company shall have the right to immediately terminate the Commitment upon written notice to the Purchasing Bank, the Bond Insurer, the Trustee, the Paying Agent and the Remarketing Agent; provided, however, that in connection with any such termination the Company shall pay to the Banks any and all amounts then accrued or owing to the Banks under this Agreement and there shall be purchased from the Purchasing Bank all Bank Bonds, together with accrued interest thereon. (d) Reduction or Termination of Participation Amounts. Upon any reduction or termination of the Commitment, the Participation Amounts of all Participating Banks shall automatically be reduce proportionately or terminated, as the case may be. The Purchasing Bank shall give each Participating Bank prompt notice of any notice of Commitment reduction or termination that it receives pursuant to this Section 2.10 and, in the case of a reduction, the amount of the reduction of such Participating Bank's Participation Amount. Section 2.11 Basis for Determining Interest Rate Inadequate or Unfair. If prior to the first day of any Interest Period for any Disbursement Group of Euro-Dollar Disbursements, (a) the Purchasing Bank determines that for any reason appropriate information is not available to it for purposes of determining the Adjusted London Interbank Rate for such Interest Period or (b) the Required Banks determine that the Adjusted London Interbank Offered Rate will not adequately and fairly reflect the cost to them of funding their Euro-Dollar Disbursement Participations for such Interest Period, the Purchasing Bank shall forthwith give notice thereof to the Company, whereupon until the Purchasing Bank notifies the Company that the circumstances giving rise to such suspension no longer exist, the obligations of the Purchasing Bank to make or continue Euro-Dollar Disbursements or to convert outstanding Domestic Disbursements into Euro-Dollar Disbursements shall be suspended and each outstanding Euro-Dollar Disbursement shall be converted into a Domestic Disbursement on the last day of the then current Interest Period applicable thereto. Section 2.12 Illegality. If, on or after the date of this Agreement, the adoption of any Applicable Law, or any change in any Applicable Law, or any change in the interpretation or administration thereof by any Governmental Authority charged with the interpretation or administration thereof, or compliance by a Bank (or its Euro-Dollar Lending Office) with any request or directive (whether or not having the force of law) of any such Governmental Authority, shall restrict the ability of such Bank (or its Euro-Dollar Lending Office) to make, maintain or fund its Euro-Dollar Disbursement Participations (or, in the case of the Purchasing Bank, the Euro-Dollar Disbursements), such Bank shall forthwith give notice thereof to the Company and the Purchasing Bank, whereupon until such Bank notifies the Company and the Purchasing Bank that the circumstances giving rise to such suspension no longer exist, the obligation of the Purchasing Bank to continue Euro-Dollar Disbursements as Euro-Dollar Disbursements for additional Interest Periods or to convert outstanding Domestic Disbursements into Euro-Dollar Disbursements shall be suspended. Before giving any notice pursuant to this Section 2.12, the affected Bank shall designate a different Euro-Dollar Lending Office if such designation will avoid the need for giving such notice and will not, in the judgment of such Bank, be otherwise disadvantageous to such Bank. If such notice is given, each Euro-Dollar Disbursement then outstanding shall be converted to a Domestic Disbursement either (a) on the last day of the then current Interest Period applicable to each Euro-Dollar Disbursement Participation if the affected Bank may lawfully continue to maintain and fund Euro-Dollar Disbursement Participations to such day or (b) immediately if the affected Bank shall determine that it may not lawfully continue to maintain and fund Euro-Dollar Disbursement Participations to such day. Section 2.13 Increased Costs. If, in the determination of any Bank, an Regulatory Change Enacted on or after the date of this Agreement: (a) shall subject such Bank (or its Applicable Lending Office) to any tax, duty or other charge with respect to Bank Bonds, Disbursements or Disbursement Participations or its obligation to purchase and hold Bank Bonds or make or maintain Disbursements or Disbursement Participations or shall change the basis of taxation of payments to such Bank (or its Applicable Lending Office) of the principal of or interest on Disbursements or Disbursement Participations or any other amounts due under this Agreement in respect of Disbursements or Disbursement Participations or its obligation to purchase and hold Bank Bonds or make or maintain Disbursements or Disbursement Participations (except for changes in the rate of tax on the overall net income of such Bank or its Applicable Lending Office imposed by the jurisdiction in which such Bank's principal executive office or Applicable Lending Office is located, including under United States federal, home state and home locality income tax laws); or (b) shall impose, modify or deem applicable any reserve (including any such requirement imposed by the Board of Governors of the Federal Reserve System, but excluding any such requirement included in an applicable Euro-Dollar Reserve Percentage), special deposit, insurance assessment or similar requirement against assets of, deposits with or for the account of, or credit extended by, such Bank (or its Applicable Lending Office) or shall impose on such Bank (or its Applicable Lending Office) or on the London interbank market any other condition affecting Bank Bonds, Disbursements or Disbursement Participations or its obligation to purchase and hold Bank Bonds or make or maintain Disbursements or Disbursement Participations, as the case may be; and the result of any of the foregoing is to increase the cost to such Bank (or its Applicable Lending Office) of purchasing or holding Bank Bonds or making or maintaining any Disbursements or Disbursement Participations or to reduce the amount of any sum received or receivable by such Bank (or its Applicable Lending Office) under this Agreement, by an amount deemed by such Bank to be material, then, within 30 days after demand by such Bank, the Company shall pay to such Bank such additional amount or amounts as will compensate such Bank for such increased cost or reduction. Such Bank will promptly notify the Company of any event of which it has knowledge, occurring after the date hereof, which will entitle such Bank to compensation pursuant to this Section 2.13 and will designate a different Applicable Lending Office if such designation will avoid the need for, or reduce the amount of, such compensation and will not, in the judgment of such Bank, be otherwise disadvantageous to such Bank. A certificate of such Bank claiming compensation under this Section 2.13 and setting forth in reasonable detail the additional amount or amounts to be paid to it hereunder, which shall be based on such estimates, assumptions, allocations and the like that such Bank shall in good faith determine to be appropriate, shall be conclusive in the absence of manifest error. In determining such amount, such Bank may use any reasonable averaging and attribution methods. Section 2.14 Capital Adequacy. If, in the determination of any Bank, an Regulatory Change Enacted on or after the date of this Agreement has or would have the effect of reducing the rate of return on capital of such Bank (or its Parent) as a consequence of such Bank's obligations hereunder to a level below that which such Bank (or its Parent) could have achieved but for such Regulatory Change (taking into consideration its policies with respect to capital adequacy) by an amount deemed by such Bank to be material, then from time to time, within 30 days after demand by such Bank, the Company shall pay to such Bank such additional amount or amounts as will compensate such Bank (or its Parent) for such reduction. Such Bank will promptly notify the Company of any event of which it has knowledge, occurring after the date hereof, which will entitle such Bank to compensation pursuant to this Section 2.14 and will designate a different Applicable Lending Office if such designation will avoid the need for, or reduce the amount of, such compensation and will not, in the judgment of such Bank, be otherwise disadvantageous to such Bank. A certificate of such Bank claiming compensation under this Section 2.14 and setting forth in reasonable detail the additional amount or amounts to be paid to it hereunder, which shall be based on such estimates, assumptions, allocations and the like that such Bank shall in good faith determine to be appropriate, shall be conclusive in the absence of manifest error. In determining such amount, such Bank may use any reasonable averaging and attribution methods. Section 2.15 Funding Losses. If any payment of principal with respect to any Euro-Dollar Disbursement is made or any Euro-Dollar Disbursement is converted to a Domestic Disbursement on any day other than the last day of the Interest Period applicable to such Euro-Dollar Disbursement (pursuant to Section 2.06(a), (b) or (c), Section 2.12, or otherwise), the Company shall reimburse each Bank within 15 days after demand for any resulting loss or expense incurred by such Bank, including any loss incurred as a result of a decline in the London Interbank Offered Rate since the rate for such Euro-Dollar Disbursement was set for such Interest Period, but excluding loss of margin for the period after any such payment or conversion; provided that such Bank shall have delivered to the Company a certificate setting forth in reasonable detail the amount of such loss or expense, which shall be based on such estimates, assumptions, allocations and the like that such Bank shall in good faith determine to be appropriate, which certificate shall be conclusive in the absence of manifest error. Section 2.16 Payments. (a) All amounts payable to a Bank hereunder shall be paid, in Federal or other immediately available funds, to such Bank at its Domestic Lending Office or at such other address as such Bank may designate by notice to the Company. Amounts payable to a Bank in respect of Euro-Dollar Disbursement Participations (or, the case of the Purchasing Bank, Euro-Dollar Disbursements) shall be payable for the account of such Bank's Eurodollar Lending Office; amounts payable to a Bank in respect of Domestic Disbursement Participations (or, the case of the Purchasing Bank, Domestic Disbursements) shall be payable for the account of such Bank's Domestic Lending Office. (b) All amounts payable by the Company to a Bank hereunder shall be paid not later than 3:00 p.m. on the date when due. Any payment by the Company received by a Bank after 3:00 p.m. shall be deemed to be received on the following Domestic Business Day. (c) Whenever any amount payable to a Bank hereunder is due on a day that is not a Domestic Business Day, the date for payment thereof shall be extended to the next succeeding Domestic Business Day. If the date for any payment is extended by operation of law or otherwise, such payment shall bear interest for such extended time at the rate of interest applicable hereunder. (d) (i) All amounts payable by the Company to a Bank hereunder shall be paid without any reduction or deduction whatsoever, including any reduction or deduction for any set-off, recoupment, counterclaim or Tax, except for Taxes required by Applicable Law to be withheld or deducted. If any Taxes are required to be withheld or deducted from any such payment, the Company shall pay to the applicable Bank the amount that, after deduction from such increased amount of all Taxes required to be withheld or deducted therefrom, will yield to such Bank the amount stated to be payable hereunder. Notwithstanding the foregoing, the Company shall not be required to pay any increased amounts pursuant to this Section 2.16(d) on account of Taxes measured by or based upon the overall net income of a Bank. The Company will execute and deliver to the affected Bank at its request such further instruments as may be necessary or desirable to give full force and effect to any such increase. The Company will, upon the request of an affected Bank, provide such Bank with evidence satisfactory to it of the payment of any Taxes. If any Taxes required to be borne by the Company pursuant to this Section 2.16(d) are paid by a Bank, the Company will, upon demand of such Bank, reimburse such Bank for such payments, together with any interest, penalties and expenses in connection therewith. (ii) Notwithstanding anything to the contrary contained herein, the Company shall not be required to pay any additional amount in respect of withholding of United States Federal income taxes pursuant to Section 2.16(d)(i) to any Bank except (A) in the case of a Person that is a Bank on the Closing Date, to the extent such Taxes are required to be withheld as a result of a Regulatory Change Enacted after the Closing Date and (B) in the case of a Person that becomes a Bank after the Closing Date, to the extent (1) such Taxes are required to be withheld as a result of a Regulatory Change Enacted after the date such Person becomes a Bank or (2) such additional amount would have been payable had such Person not become a Bank; provided, however, that the Company shall not be required to pay any additional amount in respect of withholding of United States Federal income taxes pursuant to Section 2.16(d)(i) to the extent such withholding is required because such Bank has failed to submit any form or certificate that it is entitled to so submit under Applicable Law. (iii) There shall be submitted to the Company and the Purchasing Bank, (A) on or before the first date that interest or fees are payable to the such Participating Bank hereunder, (1) if at the time the same are applicable, (aa) by each Participating Bank that is not a United States Person, two duly completed and signed copies of Internal Revenue Service Form W-8BEN or W-8ECI (or successor forms), in either case entitling such Participating Bank to a complete exemption from withholding of any United States federal income taxes on all amounts to be received by such Participating Bank hereunder, or (bb) by each Participating Bank that is a Non-US Bank and the Issuing Bank if it is a Non-US Bank, (x) a duly completed Internal Revenue Service Form W-8BEN (or successor form) and (y) a Non-US Bank Certificate or (2) if at the time any of the foregoing are inapplicable, duly completed and signed copies of such form, if any, as entitles such Participating Bank to exemption from withholding of United States federal income taxes to the maximum extent to which such Participating Bank is then entitled under Applicable Law, and (B) from time to time thereafter, prior to the expiration or obsolescence of any previously delivered form or upon any previously delivered form becoming inaccurate or inapplicable, such further duly completed and signed copies of such form, if any, as entitles such Participating Bank to exemption from withholding of United States Federal income taxes to the maximum extent to which such Person is then entitled under Applicable Law. Each Participating Bank shall promptly notify the Company and the Purchasing Bank if (A) it is required to withdraw or cancel any form or certificate previously submitted by it or any such form or certificate has otherwise become ineffective or inaccurate or (B) payments to it are or will be subject to withholding of United States Federal income taxes to a greater extent than the extent to which payments to it were previously subject. Upon the request of the Company or the Purchasing Bank, each Participating Bank that is a United States Person shall from time to time submit to the Company and the Purchasing Bank a certificate to the effect that it is such a United States Person and a duly completed Internal Revenue Service Form W-9 (or successor form). Section 2.17 Distribution of Payments by the Purchasing Bank. (a) When, if and to the extent that the Purchasing Bank receives (from the Company, the Bond Insurer, the Paying Agent, the Trustee or any other Person obligated with respect to the Disbursements, by exercise of any right of set- off, counterclaim or banker's lien, or otherwise) a payment or prepayment in respect of (i) the principal of or interest on the Disbursements or interest on overdue amounts thereof or (ii) Commitment Fees or interest on overdue amounts thereof, the Purchasing Bank shall promptly pay to each Participating Bank such Participating Bank's Participation Share of such payment; provided, however, that a Bank to which the Purchasing Bank grants a participation in the Commitment and any outstanding Disbursements after the Closing Date shall not be entitled to any payment on account of Commitment Fees or interest on Disbursements with respect to such participation to the extent such amounts are payable for any period prior to the date such participation was granted. Except for amounts explicitly set forth herein, no Participating Bank shall be entitled to share in or receive any fee or other payment to which the Purchasing Bank may be entitled, or which it has received or may receive, in respect of this Agreement. (b) If the Purchasing Bank should for any reason make any payment to a Participating Bank in anticipation of the receipt of funds from the Company, the Bond Insurer, any other Person obligated with respect to the Disbursements and such funds are not received by the Purchasing Bank from the Company, the Bond Insurer or such Person on the date payment is due, or such payment is in excess of the amount due such Participating Bank hereunder, then such Participating Bank shall, upon request by the Purchasing Bank, forthwith return to the Purchasing Bank any such amounts transferred to such Participating Bank by the Purchasing Bank, plus interest thereon from and including the day such amounts were transferred by the Purchasing Bank to such Participating Bank to but excluding the day such amounts are returned by such Participating Bank at a per annum rate (calculated on the basis of a 360 day year) equal to the Federal Funds Rate. (c) If the Purchasing Bank is required at any time to return pursuant to any bankruptcy, insolvency, liquidation or reorganization law, or any sharing clause herein or in any of the Related Documents or otherwise, any portion of the payments made by the Company, the Bond Insurer or any other Person obligated with respect to any of the Disbursements or otherwise received by the Purchasing Bank and paid to the Participating Banks, each Participating Bank shall, on demand of the Purchasing Bank, forthwith return to the Purchasing Bank any such amounts received by such Participating Bank, but without interest thereon unless the Purchasing Bank is required to pay interest on such amounts to the person recovering such payment, in which case with interest thereon, computed at the same rate, and on the same basis, as the interest that the Purchasing Bank is required to pay. Section 2.18 Sharing of Recoveries. If a Participating Bank receives (from the Company, the Bond Insurer, the Paying Agent, the Trustee or any other Person obligated with respect to the Disbursements, by exercise of any right of set-off, counterclaim or banker's lien, or otherwise) any payment on account of its Participation Interests in excess of such Participating Bank's Participation Share of such amount, such Participating Bank shall promptly deliver such excess to the Purchasing Bank. If such Participating Bank is required at any time to return, pursuant to any bankruptcy, insolvency, liquidation or reorganization law or otherwise, any portion of the amounts referred to in the preceding sentence, the Purchasing Bank shall, on demand of such Participating Bank, return to such Participating Bank such excess (or the appropriate portion of such excess) received by the Purchasing Bank (and, to the extent paid by the Purchasing Bank to other Participating Banks, as received from such other Participating Banks), but without interest thereon unless such Participating Bank is required to pay interest on such excess (or such portion) to the Person recovering such payment, in which case with interest thereon, computed at the same rate, and on the same basis, as the interest that such Participating Bank is required to pay. ARTICLE III CONDITIONS PRECEDENT Section 3.01 Conditions Precedent Subject to Fulfillment on the Closing Date. The obligation of the Purchasing Bank to purchase Unremarketed Bonds pursuant to this Agreement is subject to the condition precedent that the Banks shall have received on or before the Closing Date the following, each in form and substance satisfactory to the Banks and counsel for the Purchasing Bank: (a) This Agreement, duly executed on behalf of the Company. (b) (i) Counterparts (or certified copies thereof) of each of the Related Documents (other than the Bonds and the First Mortgage Bonds) that, when taken together, bear the signatures of all of the respective parties thereto and that are in full force and effect in accordance with their respective terms and are satisfactory to the Purchasing Bank in form and substance and (ii) a specimen of each Bond and First Mortgage Bond. (c) A copy of the Reoffering Circular, certified to be a true copy by an officer of the Company. (d) A certificate of the secretary or an assistant secretary of the Company, certifying the names and true signatures of the officers of the Company authorized to execute on behalf of the Company this Agreement and the Related Documents to which the Company is a party. (e) Evidence that all necessary action required to be taken by (i) the Issuer (including the adoption or enactment by the Issuer of all necessary resolutions and ordinances) and (ii) any Governmental Authority, in connection with the authorization, execution, issuance, delivery and performance of this Agreement and the Related Documents, and any other document or instrument required to be delivered pursuant hereto or thereto or in connection with the transactions contemplated hereby or thereby, has been taken. (f) Evidence that, as of the Closing Date, all conditions contained in the Indenture and the Loan Agreement for the replacement of the SG Bond Purchase Agreement with this Agreement have been satisfied. (g) A copy of the Bond Insurance Policy which shall provide that it insures all principal of and interest (at a rate per annum not in excess of 18 percent per annum) when due on the Bonds (including payment of interest on Bank Bonds at the Bank Rate and payment of principal of and accrued interest on Bank Bonds upon any redemption provided for herein or in the Indenture), executed by the Bond Insurer, together with evidence satisfactory to the Purchasing Bank that such Bond Insurance Policy is in full force and effect and is non-cancelable and that all premiums required to be paid thereunder have been paid in full. (h) Legal opinions of (i) Day, Berry and Howard LLP, as special counsel to the Company, (ii) Jeffrey C. Miller, Assistant General Counsel of Northeast Utilities Service Company, (iii) counsel to the Bond Insurer satisfactory to the Purchasing Bank, and (iv) Winthrop, Stimson, Putnam and Roberts, counsel to the Purchasing Bank, in each case, as to such matters incident to this Agreement, the Related Documents and the transactions contemplated hereby and thereby as the Purchasing Bank shall have reasonably requested. (i) Evidence of the power and authority of the Trustee and the Paying Agent to accept and execute their respective responsibilities under the Indenture. (j) An executed copy of each document, instrument, certificate and opinion delivered pursuant to the Indenture. (k) Such other documents, instruments, opinions and approvals (and, if requested by any Bank, certified duplicates or executed copies thereof) as any Bank shall have reasonably requested. Section 3.02 Additional Conditions Precedent Subject to Fulfillment on the Closing Date. The obligation of the Purchasing Bank to purchase Unremarketed Bonds pursuant to this Agreement is subject to the further conditions precedent that on the Closing Date: (a) The following statements shall be true and shall be deemed to have been represented by the Company as being true on and as of the Closing Date, and each Bank shall have received a certificate of the Company signed by an authorized officer dated the Closing Date, stating that, to the best of such authorized officer's knowledge after due inquiry: (i) The representations and warranties of the Company contained in Article IV are true and correct in all material respects on and as of the Closing Date as though made on and as of the Closing Date; and (ii) No event has occurred and is continuing, or would result from the effectiveness of this Agreement, that constitutes a Default. (b) Each Bank shall have received payment in full of all fees and other sums required to be paid to or for the account of such Bank on or prior to the Closing Date. Section 3.03 Conditions Subject to Fulfillment on Each Purchase Date. The obligation of the Purchasing Bank to purchase Unremarketed Bonds pursuant to this Agreement on each Purchase Date shall be subject to the fulfillment of the following conditions precedent on and as of such Purchase Date: (a) The Purchasing Bank shall have received a duly completed Purchase Certificate for the purchase of such Unremarketed Bonds on such Purchase Date in accordance with Section 2.01(b)(i). (b) The Unremarketed Bonds to be so purchased are not held by or for the account of the Company, any Affiliate of the Company or any broker-dealer holding Unremarketed Bonds pursuant to an arrangement with the Company or any Affiliate of the Company. (c) No Event of Suspension shall have occurred and be continuing. (d) The amount being demanded for payment by the Purchasing Bank under Section 2.01 does not exceed the Combined Available Commitment on such Purchase Date (prior to giving effect to such payment). (e) The Commitment Termination Date shall not have occurred. Notwithstanding the foregoing, if the condition set forth in clause (b) above is satisfied for some but not all of the Unremarketed Bonds covered by a Purchase Certificate, then, provided that all of the other conditions to purchase have been satisfied, the Purchasing Bank shall be obligated to purchase so much of such Unremarketed Bonds for which the condition set forth in clause (b) is satisfied. ARTICLE IV REPRESENTATIONS AND WARRANTIES In order to induce each Bank to enter into and perform its obligations under this Agreement, the Company hereby represents and warrants as follows: Section 4.01 Organization. The Company is duly organized, validly existing and in good standing under the laws of the State of Connecticut, and has all requisite corporate power and authority to own or lease its properties and to conduct its business as now conducted and as proposed to be conducted, and is duly qualified and authorized to engage in business as a public utility in the State of Connecticut. Section 4.02 Authorization. The execution, delivery and performance by the Company of this Agreement and the Related Documents to which it is a party are within the Company's corporate powers, have been duly authorized by all necessary corporate action, and (a) do not contravene, violate or breach: (i) Applicable Law; (ii) the Certificate of Incorporation or By-laws of the Company; or (iii) any indenture, mortgage, loan agreement or other contract or instrument to which the Company is a party or by which it or its assets are bound; and (b) do not result in or require the creation of any Lien except as provided in or contemplated by this Agreement or the Related Documents upon or with respect to any of the Company's properties. Section 4.03 Enforceability. This Agreement is, and the Related Documents to which the Company is a party are, legal, valid and binding obligations of the Company, enforceable against the Company in accordance with their respective terms, except as enforceability may be limited by applicable bankruptcy, insolvency, reorganization, moratorium or similar Applicable Laws affecting the enforcement of creditors' rights generally and by general equitable principles (whether enforcement is sought by proceedings in equity or at law). Section 4.04 Approvals. No authorization of, approval or other action by, and no notice to or filing with, any Governmental Authority is required for the due execution, delivery and performance by the Company of this Agreement or any Related Document, except those that have been, or will be simultaneously with the execution hereof, duly obtained or made and are in full force and effect. Section 4.05 Financial Information. (a) The audited balance sheet of the Company as at December 31, 1999, and the audited statements of income and cash flows of the Company for the fiscal year then ended as set forth in the Company's Annual Report on Form 10-K for such fiscal year and (b) the unaudited balance sheet of the Company as at June 30, 2000 and the unaudited statements of income and cash flows of the Company for the six-month period then ended as set forth in the Company's Quarterly Report on Form 10-Q for the period then ended, fairly present in all material respects the financial condition and results of operations of the Company at and for the respective periods ended on such dates, and have been prepared in accordance with GAAP, consistently applied. Since December 31, 1999, there has been no material adverse change in the financial condition, operations, properties or prospects of the Company and its Subsidiaries, taken as a whole, except to the extent, if any, described in the Company Disclosure Documents. Section 4.06 Litigation. Except for any pending or threatened action, suit, investigation or proceeding as disclosed in the Company Disclosure Documents or otherwise disclosed to the Banks in writing prior to the date hereof (as to which no representation or warranty is being made), there is no action, suit or proceeding (or to the best knowledge of the Company, investigation) pending or, to the best knowledge of the Company, threatened (a) in connection with this Agreement or any of the transactions contemplated by this Agreement or the Related Documents, or (b) against or affecting the Company, the result of which is reasonably likely to have a Materially Adverse Effect. Section 4.07 Reoffering Circular. Except for information contained in the Reoffering Circular describing any Bank, the Issuer, the Bond Insurer or The Depository Trust Company, as to which no representation or warranty is made, (a) the Reoffering Circular as of its issue date was, and any supplement or amendment thereto will be, accurate in all material respects for the purposes for which their use is or shall be authorized, and (b) the Reoffering Circular as of its issue date did not, and any such supplement or amendment will not, contain any untrue statement of a material fact or omit to state any material fact necessary to make the statements made therein, in the light of the circumstances under which they are or were made, not misleading. Section 4.08 Environmental Matters. Except as disclosed or for matters identified in the Company Disclosure Documents (as to which no representation or warranty is made): (a) The operations of the Company comply in all respects with all applicable Environmental Laws concerning environmental health and safety except where the failure to comply would not have a Materially Adverse Effect; (b) The Company has obtained or made timely application for all environmental, health and safety permits necessary for its operation. All such permits previously obtained are in effect or timely application for renewal thereof is pending, and no action to revoke the same is pending and the period to appeal such permits have expired, and the Company is in compliance with all terms and conditions of such permits except where the failure to comply would not have a Materially Adverse Effect; (c) With respect to property currently or formerly owned or operated by it, the Company is not (at the time of ownership or operation) subject to any outstanding written notice or order from, or agreement with, any Governmental Authority or other Person in respect to which the Company (i) is required to take any Remedial Action that would or might reasonably be expected to have a Materially Adverse Effect or (ii) would be reasonably likely to be required to incur any Environmental Liabilities and Costs arising from the Release or threatened Release of a Contaminant into the environment that would or might reasonably be expected to result in a Materially Adverse Effect; (d) The Company has not received written notification pursuant to Environmental Laws that any of its current or past operations, or any by- product thereof, is related to or subject to any investigation by any Governmental Authority evaluating whether any Remedial Action is needed to respond to a Release or threatened Release of a Contaminant into the environment, which investigation is reasonably likely to lead to the Company having to take Remedial Action, or having to incur Environmental Liabilities and Costs, in each case which would have a Materially Adverse Effect; and (e) The Company has not filed any notice under any applicable Environmental Law reporting a Release of a Contaminant into the environment that is reasonably likely to lead to any Governmental Authority or any other Person having to take Remedial Action or having to incur Environmental Liabilities and Costs, that would have a Materially Adverse Effect. Section 4.09 Investment Company Act. The Company is not an "investment company", or a company "controlled by an investment company" within the meaning of the Investment Company Act of 1940. Section 4.10 Public Utility. All outstanding shares of capital stock having ordinary voting power for the election of directors of the Company have been validly issued, are fully paid and nonassessable, and are owned beneficially by NU, free and clear of any Lien. NU is a "holding company" (as defined in the Public Utility Holding Company Act of 1935, as amended (the "1935 Act")). Except for the post- closing filing on Form U-6B-2 required to be made with the Securities and Exchange Commission pursuant to the 1935 Act, the Company is not required to obtain any consents or make any filings pursuant to the 1935 Act in order to execute, deliver and perform this Agreement or any of the Related Documents to which it is a party. Section 4.11 All Other Representations and Warranties Accurate. All representations and warranties made by the Company in any of the Related Documents are true and correct in all material respects at and as of the date hereof, except that any such representations and warranties that expressly speak of a particular date were true and correct in all material respects as of such date. ARTICLE V COVENANTS So long as the Purchasing Bank has any Commitment hereunder, any Disbursements shall remain outstanding, or any other amount shall be accrued or owing to the Banks hereunder: Section 5.01 Further Assurances. The Company will, to the extent permitted by Applicable Law, execute, acknowledge where appropriate, and deliver or file, and cause to be executed, acknowledged where appropriate, and delivered or filed, from time to time promptly at the request of the Purchasing Bank or the Required Banks, all such instruments and documents as are reasonably necessary or advisable to carry out the intent and purpose of this Agreement and the Related Documents. Section 5.02 Maintenance of Remarketing Agent. The Company will maintain in place a Remarketing Agent in accordance with the provisions of the Indenture. Section 5.03 Amendments to Related Documents. Without the prior written consent of the Purchasing Bank and the Required Banks, the Company shall not enter into or consent to any amendment, modification or termination of any Related Document, except (a) as may be required to comply with applicable law, (b) as necessary to obtain a credit rating on the Bonds by S and P, Moody's or any other rating agency then rating the Bonds, or (c) for amendments that would not affect the rights and obligations of the Banks under such Related Document. With respect to any amendment to any Related Document of the type described in clause (a), (b) or (c) of the preceding sentence, each Bank hereby agrees that it shall cooperate with the Company in delivering its consent which may nevertheless be required under such Related Document; provided that no Bank shall be required to deliver any such consent with respect to any amendment that it determines would be materially adverse to its interests. Notwithstanding anything to the contrary contained herein or in the Related Documents, the Company shall not agree to surrender, amend or modify the Bond Insurance Policy or to release or substitute the Bond Insurer thereunder. Section 5.04 Offering Circular. The Company will not include, or permit to be included, any information, material or reference relating to any Bank in any Offering Circular or any tombstone advertisement, unless such information, material or reference is approved in writing by such Bank prior to its inclusion therein, and the Company will not distribute or use, or permit to be distributed or used, any Offering Circular unless copies of such Offering Circular are furnished to such Bank prior to the distribution or use thereof. The Banks will use all reasonable efforts to respond to any request for such approval in a timely fashion. Section 5.05 Remarketing. The Company will not permit the Remarketing Agent to remarket any Bonds at a price less than the principal amount thereof plus accrued interest, if any, thereon to the respective dates of remarketing. Section 5.06 Substitute Liquidity Facility. The Company will not substitute another liquidity facility for the obligations of the Purchasing Bank to purchase Unremarketed Bonds pursuant to this Agreement unless prior to or simultaneously with such substitution, there shall be purchased from the Purchasing Bank, at a price not less than the principal amount thereof plus accrued interest, if any, thereon to the date of purchase, all Bank Bonds purchased pursuant to this Agreement and the Company shall have paid to the Banks any and all amounts accrued or owing to the Banks under this Agreement (after giving effect to the application of the proceeds of the Bank Bonds in accordance with Section 2.05 of this Agreement). Section 5.07 Remarketing Agent. Without the prior written approval of the Purchasing Bank and the Required Banks (which approval shall not be unreasonably withheld), the Company will not (a) appoint or permit or suffer to be appointed any successor Remarketing Agent unless the successor Remarketing Agent is a nationally recognized remarketing agent for municipal obligations, or (b) enter into any successor Remarketing Agreement that contains provisions (including provisions that protect the rights and interests of the Banks) that are not substantially (other than the identity of the successor Remarketing Agent and fees payable thereunder) the same in all respects material, in the judgment of the Purchasing Bank and the Required Banks, to the interests of the Banks as those contained in the predecessor Remarketing Agreement. The Company shall provide to the Banks a copy of such successor Remarketing Agreement promptly upon execution and delivery thereof. Section 5.08 Entry into Conflicting Agreements; Performance of Related Documents. (a) The Company will not enter into any agreement containing any provision that would be violated or breached by the performance by the Company of its obligations hereunder or under the Related Documents. (b) The Company will punctually pay or cause to be paid when due all amounts payable by it under the Loan Agreement, the First Mortgage Bonds and the other Related Documents and observe and perform all of the conditions, covenants and requirements of the Loan Agreement, the First Mortgage Bonds and the other Related Documents applicable to it. Section 5.09 Financial Statements. The Company will furnish to the Banks: (a) as soon as available and in any event within 105 days after the end of each fiscal year of the Company, a copy of the Company's report on Form 10-K submitted to the Securities and Exchange Commission with respect to such fiscal year, or, if the Company ceases to be required to submit such report, a copy of the annual audit report for such year for the Company including therein a consolidated balance sheet of the Company as of the end of such fiscal year and consolidated statements of income and retained earnings and of cash flows of the Company for such fiscal year, all in reasonable detail and certified by (i) a nationally-recognized independent public accountant and (ii) by the Chief Financial Officer, Treasurer, Assistant Treasurer or Comptroller of the Company as having been prepared in accordance with GAAP applied consistently with those financial statements referred to in Section 4.05; and (b) as soon as available and in any event within 60 days after the end of each of the first three fiscal quarters of each fiscal year of the Company, a copy of the Company's Quarterly Report on Form 10-Q submitted to the Securities and Exchange Commission with respect to such quarter, or if the Company ceases to be required to submit such report, a consolidated balance sheet of the Company as of the end of such fiscal quarter and consolidated statements of income and retained earnings and of cash flows of the Company for the period commencing at the end of the previous fiscal year and ending with the end of such fiscal quarter, all in reasonable detail and duly certified (subject to year-end audit adjustments) by the Chief Financial Officer, Treasurer, Assistant Treasurer or Comptroller of the Company as having been prepared in accordance with GAAP applied consistently with those financial statements referred to in Section 4.05. Section 5.10 Certificates; Other Information. The Company will furnish to the Banks: (a) concurrently with the delivery of the financial statements referred to in Section 5.09(a) above, a certificate of the independent certified public accountants reporting on such financial statements stating that in making the examination necessary therefor no knowledge was obtained of any Default, except as specified in such certificate; (b) concurrently with the delivery of the financial statements referred to in Sections 5.09(a) and (b), a certificate of an authorized officer stating that, to the best of such officer's knowledge, the Company during such period has in all material respects observed or performed all of its covenants and other agreements, and satisfied every condition, contained in this Agreement and the Related Documents to be observed, performed or satisfied by it, and that such officer has obtained no knowledge of any Default, in each case except as specified in such certificate; (c) promptly after the filing thereof, copies of each prospectus (excluding any prospectus contained in any Form S-8), and Current Report on Form 8-K, if any, that the Company files with, the Securities and Exchange Commission or any governmental authority which may be substituted therefor; and (d) promptly, such additional financial and other information as any Bank may from time to time reasonably request. Section 5.11 Payment of Obligations. The Company shall pay, discharge or otherwise satisfy at or before maturity or before they become delinquent, as the case may be, all Taxes imposed on it or its income, profits or revenues or any of its properties, except when the amount or validity thereof is currently being contested in good faith by appropriate proceedings and reserves in conformity with GAAP with respect thereto have been provided on the books of the Company. Section 5.12 Conduct of Business; Maintenance of Existence; Compliance with Obligations and Laws; Merger. (a) The Company shall, except to the extent such failure would not, in the aggregate, have a Materially Adverse Effect, (i) continue to engage in business as a public utility under the laws of the State of Connecticut, (ii) preserve, renew and keep in full force and effect its corporate existence and take all reasonable action to maintain all rights, licenses, approvals, privileges and franchises necessary or desirable in the normal conduct of its business, except as otherwise permitted by Section 5.12(b) or 5.13, and (iii) comply with all of its contractual obligations and all Applicable Law. (b) Nothing contained in this Agreement shall prevent any lawful consolidation or merger of the Company with or into any other corporation or corporations lawfully authorized to acquire and operate the properties of the Company, or a series of consolidations or mergers, in which the Company or its successor or successors shall be a party, or any sale of all or substantially all of the properties of the Company as an entirety to a corporation lawfully authorized to acquire and operate the same; provided that (i) upon any such consolidation, merger or sale, the corporation formed by such consolidation, or into which such merger may be made, or making such purchase shall execute and deliver to the Banks an instrument, in form and substance reasonably satisfactory to the Purchasing Bank and the Required Banks, whereby such corporation shall effectively assume the due and punctual payment of any amounts due hereunder and the due and punctual performance and observance of all covenants and agreements to be performed by the Company pursuant to this Agreement; and (ii) immediately after such consolidation, merger or sale no Event of Default shall have occurred and be continuing. Upon any such consolidation or merger or sale, the succesor corporation shall succeed to and be substituted for the Company hereunder with the same effect as if such successor corporation had been named herein. Every such successor corporation shall possess, and may exercise, from time to time, each and every right and power hereunder of the Company, in its name or otherwise; and any act, proceeding, resolution or certificate by any of the terms of this Agreement, required or provided to be done, taken and performed or made, executed or verified by any board or officer of the Company shall and may be done, taken and performed or made, executed or verified with like force and effect by the corresponding board or officer of any such successor corporation. If consolidation, merger or sale or other transfer is made as permitted by this Section, the provisions of this Section shall continue in full force and effect and no further consolidation, merger or sale or other transfer shall be made except in compliance with the provisions of this Section 5.12(b). Section 5.13 Maintenance of Property; Insurance. The Company shall (a) keep all property useful and necessary in its business in good working order and condition, except where the failure to do so would not have a Materially Adverse Effect, and (b)(i) maintain with financially sound and reputable insurance companies insurance on all its property in at least such amounts and against at least such risks as are usually insured against in the same general area by companies engaged in the same or a similar business, and (ii) furnish to any Bank, upon written request, full information as to the insurance carried. Section 5.14 Inspection; Books and Records; Discussions. The Company shall keep proper books of records and account in conformity with GAAP and Applicable Law in which entries shall be made of all dealings and transactions in relation to its business and activities; and permit representatives of any Bank to visit and inspect any of its properties and examine and make abstracts from any of its books and records at any reasonable time and as often as may reasonably be desired, and to discuss the business, operations, properties and financial and other condition of the Company with officers and employees of the Company and with its independent certified public accountants; provided that the foregoing shall not require the Company to waive any attorney-client privilege or violate any confidentiality agreements to which it is a party. Section 5.15 Notices. The Company shall give notice to the Banks of each of the following promptly after the Company has knowledge thereof: (a) the occurrence of any Default; (b) (i) the occurrence or expected occurrence of any ERISA Termination Event that could have a Materially Adverse Effect; and (c) any notices received from the Bond Insurer. Each notice pursuant to this section shall be accompanied by a statement of a senior officer of the Company setting forth details of the occurrence referred to therein and stating what action the Company proposes to take with respect thereto, it being understood and agreed that delivery of reports required by Section 5.10(c) will fulfill the notice requirements of this Section 5.15 with respect to the information contained in such reports; provided that such reports are delivered promptly after the Company gains knowledge of the information that it is required to provide the Banks under this Section 5.15. ARTICLE VI EVENTS OF DEFAULT; REMEDIES Section 6.01 Events of Default. Each of the following shall constitute an "Event of Default": (a) The Company shall fail to pay when due, or to cause to be paid when due, any principal of any Disbursement or shall fail to pay, within five days of the due date thereof, any interest or fees payable hereunder; or (b) Any representation or warranty of the Company made in, or deemed to have been made by the Company pursuant to, this Agreement or any of the Related Documents to which the Company is a party, or by any of its officials in any certificate, agreement, instrument or statement contemplated by or made or delivered pursuant to or in connection herewith or therewith (including the Reoffering Circular), shall prove to have been incorrect in any material respect when made or when deemed made; or (c) Any "Event of Default" under the Indenture or any "event of default" under the Loan Agreement shall have occurred and be continuing; or (d) The Company shall fail to perform or observe any covenant or agreement set forth in Section 5.03; or (e) The Company shall fail to perform or observe any other term, covenant or agreement (other than one described in any other paragraph of this Section 6.01) contained in this Agreement or the Related Documents on its part to be performed or observed, and any such failure shall remain unremedied for 30 days after written notice thereof shall have been given to the Company by the Purchasing Bank or the Required Banks; (f) Any default or similar event shall occur with respect to any indebtedness having an aggregate principal amount in excess of 10,000,000 dollars with respect to which the Company is an obligor, the effect of which is to permit the holder or holders of such indebtedness, or a trustee or agent on behalf of such holder or holders, to cause any such indebtedness to become due prior to its stated maturity, or any such indebtedness shall be declared to be due and payable prior to its stated maturity or shall not be paid when due; (g) The Company shall make a general assignment for the benefit of creditors, file a petition in bankruptcy, be unable generally to pay its debts as they become due, or be adjudicated insolvent or bankrupt or there shall be entered any order or decree granting relief in any voluntary or involuntary case commenced by or against the Company under any applicable bankruptcy, insolvency or other similar law now or hereafter in effect, or the Company shall petition or apply to any court or administrative body for the appointment of any receiver, trustee, liquidator, assignee, custodian, sequestrator (or other similar official) of the Company or of any substantial part of the Company's properties, or shall commence any proceeding in a court of law for a reorganization, readjustment of debt, dissolution, liquidation, assignment or other similar procedure under the laws or statutes of any jurisdiction, whether now or hereafter in effect, or there shall be commenced against the Company any such proceeding in a court of law that remains undismissed or not discharged, vacated or stayed within 90 days after commencement, or the Company by any act shall indicate its consent to, approval of or acquiescence in any of the foregoing or take any action for the purpose of effecting any of the foregoing; or (h) The Company shall commence proceedings seeking to limit its liability under this Agreement or the Bank Bonds. (i) The ratings assigned to the Bond Insurer's long-term debt or claims paying ability are withdrawn, suspended and/or reduced to below BBB- (or its equivalent rating) by S and P and are withdrawn, suspended and/or reduced to below Baa3 (or its equivalent rating) by Moody's; or (j) A Bond Insurer Event of Insolvency shall have occurred; or (k) The Bond Insurer shall fail, wholly or partially, to make a payment when and as required under the provisions of any Bond Insurance Policy (including principal of, and interest at the Bank Rate on, Bank Bonds); or (l) The Bond Insurer or any other Person shall claim or assert in writing that any Bond Insurance Policy is invalid or unenforceable against the Bond Insurer, or the Bond Insurer shall repudiate its obligations or deny that it has any further liability under any Bond Insurance Policy or the validity or enforceability of any Bond Insurance Policy shall be contested in any contest or proceeding (including an appellate proceeding) directly or indirectly by the Bond Insurer or any other Person and, in the case of a Person other than the Bond Insurer, the Bond Insurer shall fail to defend or assert such validity or enforceability or to appeal such contest or proceeding pursuant to appropriate proceedings or actions; or (m) Any Governmental Authority with competent jurisdiction shall announce, find or rule that any Bond Insurance Policy is null and void or otherwise invalid or unenforceable against the Bond Insurer; or (n) Any Bond Insurance Policy is surrendered, canceled or terminated, or amended or modified in any material respect; or (o) A court of competent jurisdiction enters a final nonappealable judgment that any Bond Insurance Policy is not valid and binding on or enforceable against the Bond Insurer. Section 6.02 Remedies. (a) Events of Suspension. (i) Each of the following shall constitute an "Event of Suspension": (A) the occurrence of any Event of Default set forth in Section 6.01(i)-(o) or (B) a Bond Insurer Potential Insolvency. During the continuance of any Event of Suspension, the Commitment shall be suspended and the Purchasing Bank shall be under no obligation to purchase any Unremarketed Bonds. The Purchasing Bank shall give written notice of any Event of Suspension to the Company, the Trustee, the Paying Agent and the Remarketing Agent promptly after it becomes aware thereof; provided, however, that the Purchasing Bank shall not incur any liability or responsibility whatsoever by reason of the Purchasing Bank's failure to give such notice and such failure shall in no way affect the suspension of the Commitment. The suspension of the Commitment shall not extend the Stated Expiration Date or affect any other remedy provided under this Section 6.02, and no cure of an Event of Suspension shall reinstate the Commitment if the Commitment shall have expired or been terminated prior thereto. (ii) For the purposes of Section 6.02(a)(i), (A) an Event of Suspension resulting from an Event of Default under Section 6.01(l) or (m) shall be deemed to cease to exist if and only if a court of competent jurisdiction shall find or rule that such Bond Insurance Policy is valid and binding on the Bond Insurer in accordance with its terms, (B) an Event of Suspension resulting from a Bond Insurer Potential Insolvency shall be deemed to cease to exist if and only if such Bond Insurer Potential Insolvency shall cease to exist and no Bond Insurer Event of Insolvency shall have occurred and (C) any other Event of Suspension shall be deemed to cease to exist if and only if the Event of Default from which such Event of Suspension resulted shall cease to exist. (b) Events of Termination. Each of the following shall constitute an "Event of Termination" or an "event of termination": (i) the occurrence of an Event of Default under Section 6.01(j), (k), (n) or (o), (ii) the occurrence of an Event of Default under Section 6.01(i) and the continuance of such Event of Default for a period of 30 consecutive days, or (iii) the occurrence of an Event of Default under Section 6.01(l) or (m) and the entry by a court of competent jurisdiction of a final nonappealable judgment that the Bond Insurance Policy is not valid and binding on the Bond Insurer. During the continuance of an Event of Termination, the Purchasing Bank may do any or all of the following: (i) by notice to the Company, declare all Disbursements to be, and all Disbursements shall thereupon become, immediately due and payable, (ii) by notice to the Trustee declare that, on the fifth Domestic Business Day after the 45th day after notice of such Event of Termination is received by the Trustee, the Commitment shall terminate, in which event the Commitment shall so terminate on such day (if not previously expired or terminated), and (iii) by notice to the Trustee, demand the immediate redemption of all Bank Bonds in accordance with Section 2.4(G)(ii) of the Indenture and Section 2.03(c) hereof. The Purchasing Bank shall promptly give the Company, the Paying Agent and the Remarketing Agent a copy of any notice given to the Trustee pursuant to clause (ii) or (iii) of the preceding sentence; provided, however, that the Purchasing Bank shall not incur any liability or responsibility whatsoever by reason of the Purchasing Bank's failure to give a copy of such notice and such failure shall in no way affect the effectiveness of any remedies elected by the Banks. (c) Other Remedies. During the continuance of any Event of Default, the Banks, in addition, shall have all remedies provided at law or equity, including the right to demand and receive specific performance; provided, however, that, except as otherwise provided in subsection (a) or (b) of this Section 6.02, the Purchasing Bank shall not have the right to suspend, terminate or otherwise reduce the Commitment. (d) Direction by Required Banks. The Purchasing Bank shall (i) in the case of an Event of Termination, take any or all of the actions referred to in clause (i)-(iii) of Section 6.02(b) if so directed by the Required Banks and (ii) in the case of any Event of Default or Event of Termination, take such other action with respect thereto as shall be reasonably directed by the Required Banks. ARTICLE VII MISCELLANEOUS Section 7.01 Amendments, Etc. (a) No amendment or waiver of any provision of this Agreement, nor consent to any departure by the Company therefrom, shall in any event be effective unless the same shall be in writing and signed by the Purchasing Bank and the Required Banks and, in the case of an amendment, the Company; provided, however, that no amendment or waiver shall be effective, unless in writing and signed by each Participating Bank affected thereby, to the extent it (i) extends the Stated Expiration Date, (ii) increases the amount of the Commitment or such Bank's Participation Amount, (iii) reduces or postpones any payment of any principal of or interest on any Disbursement or any Commitment Fees, (iv) waives or changes any condition precedent set forth in Article III, (v) changes Section 5.03, (vi) changes Section 2.13, 2.14, 2.15, 7.04 or 7.06, (vii) modifies Section 2.17(a) or 2.18 or any other provision providing for the equal or ratable treatment of the Banks or (viii) modifies the definition of "Required Banks" or this Section 7.01(a) or any other provision requiring the consent of all of the Banks. (b) Without the prior written consent of the Required Banks, the Purchasing Bank shall not give or withhold its agreement to any waiver, modification or amendment of any term, provision or covenant of any of the Related Documents; provided, however, that, without the prior written consent of each Participating Bank, the Purchasing Bank (i) shall not consent to any modification of the Bond Insurance Policy or (ii) agree to purchase Unremarketed Bonds at a time when the Purchasing Bank's obligation to do so has been suspended or terminated pursuant to the terms hereof. Section 7.02 Notices, Etc. Except as otherwise expressly provided herein, all notices and other communications provided for hereunder shall be in writing (including telecopier communication) and shall be given to such party (a) in the case of the Company or the Purchasing Bank, at its address or telecopier number set forth on the signature pages hereof, (b) in the case of the Participating Banks, at its address or telecopier number set forth below such Bank's name under the heading "Notice Address" on Annex A or, in the case of a Participating Bank that became a Participating Bank pursuant to Section 7.07(b) or (c), the address for notices to such Bank set forth in the Joinder Agreement or Assignment and Acceptance pursuant to which such Bank became a Participating Bank, (c) in the case of the Trustee, the Paying Agent and the Remarketing Agent, to their respective addresses or telecopier numbers set forth in the Indenture and/or the other Related Documents, or (d) as to each of the foregoing, at such other address as shall be designated by such Person in a written notice to the others. All such notices and communications shall be effective (x) if given by telecopier, when transmitted to the telecopier number specified as aforesaid, (y) if given by mail, 72 hours after such communication is deposited in the mails with first class postage prepaid, addressed as aforesaid, and (z) if given by other means, when delivered at the address specified as aforesaid, except that written notices to any Bank pursuant to the provisions of Article II shall not be effective until received. Section 7.03 No Implied Waiver: Remedies Cumulative. No failure on the part of the Banks to exercise, and no delay in exercising, any right under this Agreement shall operate as a waiver thereof; nor shall any single or partial exercise of any right under this Agreement preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law. Section 7.04 Indemnification. The Company agrees to indemnify the Banks, the Lead Arranger, the Trustee, their respective Affiliates and the respective directors, officers, agents and employees of the foregoing (each an "Indemnitee") for, and to hold harmless each Indemnitee from and against any and all liabilities, losses, damages, costs and reasonable expenses of any kind (including the reasonable fees and disbursements of counsel) that may be incurred by such Indemnitee in connection with any investigative, administrative or judicial proceeding (whether or not such Indemnitee shall be designated a party thereto) in any way relating to or arising out of: (a) any alleged inaccuracy of, or any alleged untrue statement contained in, any Offering Circular or any amendment or supplement thereto, or by reason of the alleged omission to state therein a material fact necessary to make the statements contained in any Offering Circular or any amendment or supplement thereto, in the light of the circumstances under which they were made, not misleading, other than any action or proceeding alleging any inaccuracy in a material respect, or an untrue statement of a material fact, with respect to information supplied by and describing a Bank in any Offering Circular or any amendment or supplement thereto (the "Bank Information"), or alleging any omission to state therein a material fact necessary to make the statements in the Bank Information, in the light of the circumstances under which they were made, not misleading; or (b) the execution, delivery or performance of this Agreement, any Related Document or any transaction contemplated hereby or thereby (including, without limitation, by reason of or in connection with the purchase by the Purchasing Bank of Unremarketed Bonds); provided, however, that the Company shall not be required to indemnify any Indemnitee pursuant to this Section 7.04(a)(ii) for any claims, damages, losses, liabilities, costs or expenses to the extent, but only to the extent, caused by the willful misconduct or gross negligence of such Indemnitee as determined by a court of competent jurisdiction or arising from any litigation brought by such Indemnitee against the Company in which a final, nonappealable judgment has been rendered against such Indemnitee. Section 7.05 Limitation of Liability. The Company assumes all risks of the acts or omissions of the Trustee, the Paying Agent, the Remarketing Agent and the Bond Insurer with respect to the use of the Disbursements under this Agreement. None of the Banks nor any of their respective officers, directors, agents or employees shall be liable or responsible for, and none of the Company's obligations under this Agreement shall be affected by, (a) any mechanical error, omission, interruption or delay in the transmission, dispatch or delivery of any message or advice, however transmitted, in connection with this Agreement; (b) the use that may be made of the Commitment or any acts or omissions of the Trustee, the Paying Agent or the Remarketing Agent in connection therewith; (c) the validity, sufficiency or genuineness of documents, or of any endorsement thereon, even if such documents should prove to be in any or all respects invalid, insufficient, fraudulent or forged; (d) payment by the Purchasing Bank against presentation of a Purchase Certificate that does not comply with the terms of this Agreement; (e) any act, or any failure to act, by the Trustee or the Paying Agent that results in the failure of the Paying Agent (i) to credit the appropriate account with funds made available by the Purchasing Bank pursuant to this Agreement or (ii) to effect the purchase for the account of the Purchasing Bank of Unremarketed Bonds with such funds pursuant to this Agreement; (f) any other circumstances whatsoever in making or failing to make payment under this Agreement or (g) any other action, inaction or omission that may be taken by it in good faith in connection with this Agreement; provided that the Company shall have a claim against any Bank, and such Bank shall be liable to the Company, to the extent of any direct, as opposed to consequential, damages suffered by the Company that the Company proves were caused by such Bank's willful misconduct or gross negligence. Section 7.06 Costs, Expenses and Taxes. The Company shall pay (a) all reasonable out-of-pocket expenses of the Purchasing Bank and the Lead Arranger, including the reasonable fees and disbursements of special counsel for the Purchasing Bank, in connection with the preparation, negotiation and closing of this Agreement, any waiver or consent hereunder or any amendment hereof or in connection with any Default or alleged Default, and (b) if an Event of Default occurs, all reasonable out-of-pocket expenses incurred by the Banks, including (without duplication) the reasonable fees and disbursements of outside counsel, in connection with such Event of Default and any collection, bankruptcy, insolvency and other enforcement proceedings resulting therefrom. In addition, the Company shall pay any and all costs and expenses of the Banks (including reasonable counsel fees and expenses) in connection with the transfer, exchange and registration of Bank Bonds and any and all recording, stamp and other taxes and fees payable or determined to be payable in connection with the execution, delivery, filing and recording of this Agreement, any Related Document and such other documents, and agrees to save the Banks harmless from and against any and all liabilities with respect to or resulting from any delay in paying or omission to pay such taxes or fees. Section 7.07 Binding Effect; Assignment; Participations. (a) This Agreement shall be binding upon and inure to the benefit of the Company and the Banks and their respective successors and assigns, except that the Company shall not have the right to assign any of its rights or obligations hereunder or any interest herein without the prior written consent of each of the Banks. (b) The Purchasing Bank may grant one or more Persons additional participations in the Commitment and Disbursements; provided that (i) so long as no Event of Default pursuant to Section 6.01(g) has occurred and is continuing, the Company has consented to such grant of a participation (each such consent not to be unreasonably withheld or delayed), (ii) the Person to which such participation is granted shall have executed and delivered to the Purchasing Bank a Joinder Agreement and (iii) after giving effect to the grant of such participation, the aggregate amount of the Participation Amounts does not exceed the Commitment. From and after the effective date of a Joinder Agreement, the Person granted Participation Interests thereunder shall be a party hereto and, to the extent of the Participation Interests granted by such Joinder Agreement, have the rights and obligations of a Participating Bank under this Agreement. (c) Any Participating Bank may assign to one or more Persons all or a portion of its rights and obligations under this Agreement (including all or a portion of its Participation Amount and Participation Interests); provided that (i) each of the Purchasing Bank and, so long as no Event of Default pursuant to Section 6.01(g) has occurred and is continuing, the Company has consented to such assignment (each such consent not to be unreasonably withheld or delayed), (ii) each partial assignment shall not be of less than 5,000,000 dollars of the assigning Participating Bank's Participation Amount and shall be made as an assignment of a proportionate part of all the assigning Participating Bank's rights and obligations under this Agreement (including Participation Interests in outstanding Disbursements) with respect to the Participation Amount assigned and (iii) the parties to each assignment shall execute and deliver to the Purchasing Bank a Assignment and Acceptance, together with a processing and recordation fee of 3,500 dollars. From and after the effective date of an Assignment and Acceptance, the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Acceptance, shall have the rights and obligations of a Participating Bank under this Agreement, and the assigning Participating Bank thereunder shall, to the extent of the interest assigned by such Assignment and Acceptance, be released from its obligations under this Agreement (and, in the case of a Assignment and Acceptance covering all of the assigning Participating Bank's rights and obligations under this Agreement, such Participating Bank shall cease to be a party hereto). Any assignment or transfer by a Participating Bank of rights or obligations under this Agreement that does not comply with this paragraph shall be treated for purposes of this Agreement as a sale by such Participating Bank of a participation in such rights and obligations in accordance with paragraph (e) of this Section 7.07. (d) The Purchasing Bank, acting solely for this purpose as an agent of the Company, shall maintain at one of its offices in New York City a copy of each Joinder Agreement and Assignment and Acceptance delivered to it and a register for the recordation of the names and addresses of the Participating Banks, and the Participation Amounts of, and Participation Interests held by, each Participating Bank pursuant to the terms hereof from time to time (the "Register"). The entries in the Register shall be conclusive, and the Company, the Purchasing Bank and the Participating Banks may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Participating Bank hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Company and any Participating Bank, at any reasonable time and from time to time upon reasonable prior notice. (e) Any Participating Bank may, without the consent of, or notice to, the Company or the Purchasing Bank, sell subparticipations to one or more banks or other entities (a "Subparticipant") in all or a portion of such Participating Bank's rights and/or obligations under this Agreement (including all or a portion of its Participation Amount and Participation Interests); provided that (i) such Participating Bank's obligations under this Agreement shall remain unchanged, (ii) such Participating Bank shall remain solely responsible to the other parties hereto for the performance of such obligations and (iii) the Company, the Purchasing Bank and the other Participating Banks shall continue to deal solely and directly with such Participating Bank in connection with such Participating Bank's rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Participating Bank sells such a participation shall provide that such Participating Bank shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Participating Bank will not, without the consent of the Subparticipant, agree to any amendment, modification or waiver described in clauses (i)-(iii) of Section 7.01(a) that affects such Subparticipant. Subject to paragraph (f) of this Section 7.07, the Company agrees that each Subparticipant shall be entitled to the benefits of Sections 2.13, 2.14 and 2.15 to the same extent as if it were a Participating Bank and had acquired its interest by assignment pursuant to paragraph (c) of this Section 7.07. To the extent permitted by law, each Subparticipant also shall be entitled to the benefits of Section 7.08 as though it were a Participating Bank, provided such Subparticipant agrees to be subject to Section 2.18 as though it were a Participating Bank. (f) A Subparticipant shall not be entitled to receive any greater payment under Sections 2.13, 2.14 or 2.15 than the applicable Participating Bank would have been entitled to receive with respect to the participation sold to such Subparticipant, unless the sale of the participation to such Subparticipant is made with the Company's prior written consent. A Subparticipant that would be a Non-US Bank if it were a Participating Bank shall not be entitled to the benefits of Section 2.16(d) unless the Company is notified of the participation sold to such Subparticipant and such Subparticipant agrees, for the benefit of the Company, to comply with Section 2.16(d)(iii) as though it were a Participating Bank. (g) Any Bank may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Bank, including without limitation any pledge or assignment to secure obligations to a Federal Reserve Bank; provided that no such pledge or assignment of a security interest shall release a Bank from any of its obligations hereunder or substitute any such pledgee or assignee for such Bank as a party hereto. Section 7.08 Set-Off. The Purchasing Bank and each Participating Bank is hereby authorized by the Company, at any time and from time to time, without notice, (a) during any Event of Default, to set off against, and to appropriate and apply to the payment of, the liabilities of the Company under this Agreement (whether owing to such Person or to any other Person that is the Purchasing Bank or a Participating Bank and whether matured or unmatured, fixed or contingent or liquidated or unliquidated and including the amounts to which a Participating Bank is entitled with respect to its Participation Interests) any and all liabilities owing by such Person or any of its Affiliates to the Company (whether payable in U.S. dollars or any other currency, whether matured or unmatured and, in the case of liabilities that are deposits, whether general or special, time or demand and however evidenced and whether maintained at a branch or office located within or without the United States) and (b) during any Default, to suspend the payment and performance of such liabilities owing by such Person or its Affiliates in an amount equal to the amount then due and payable under this Agreement and, in the case of liabilities that are deposits, to return as unpaid for insufficient funds any and all checks and other items drawn against such deposits. Section 7.09 Severability. Any provision of this Agreement that is prohibited, unenforceable, or not authorized in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition, unenforceability or non-authorization without invalidating the remaining provisions hereof or affecting the validity, enforceability or legality of such provision in any other jurisdiction. Section 7.10 Governing Law. PURSUANT TO SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW, This Agreement shall be governed by, and construed in accordance with, the law of the State of New York. Section 7.11 Jurisdiction; Service of Process; Waiver of Jury Trial. (a) In connection with any civil action or proceeding arising out of, based upon or in any way connected to this Agreement, each of the Company and the Participating Bank submits to the non-exclusive jurisdiction of state and federal courts located in the City and State of New York in personam and agrees that such courts are convenient forums. Each of the Company and the Participating Banks waives personal service upon it and consents to service of process by mailing a copy thereof to it by registered or certified mail. (b) EACH OF THE BANKS AND THE COMPANY WAIVE THE RIGHT TO TRIAL BY JURY IN ANY CIVIL ACTION OR PROCEEDING ARISING OUT OF, OR BASED UPON, OR IN ANY WAY CONNECTED WITH THIS AGREEMENT. Section 7.12 Survival of Representations and Warranties. All agreements, representations and warranties made in this Agreement and in any certificates delivered pursuant hereto shall survive the execution and delivery of this Agreement, and the agreements contained in Sections 2.11, 2.12, 2.13, 2.14, 2.15, 7.04, 7.06 and 7.19 shall survive the termination of this Agreement and payment of all other amounts payable hereunder. Section 7.13 Entirety. This Agreement embodies the entire agreement and understanding between the Banks and the Company with respect to the subject matter hereof and supersedes all other prior discussions, negotiations, arrangements and understandings relating to the subject matter hereof. Section 7.14 Execution in Counterparts. This Agreement may be executed in any number of counterparts and by different parties hereto on separate counterparts, each of which counterparts, when so executed and delivered, shall be deemed to be an original and all of which counterparts, taken together, shall constitute but one and the same agreement. Section 7.15 Headings. Section headings and the table of contents in this Agreement are included herein for convenience of reference only and shall not constitute a part of this Agreement for any other purpose. Section 7.16 Effectiveness. This Agreement shall become effective upon receipt by each Bank of counterparts hereof signed by each of the parties hereto (or, in the case of any party as to which an executed counterpart shall not have been received, receipt by each Bank in form satisfactory to it of telegraphic, telex, facsimile or other written confirmation from such party of execution of a counterpart hereof by such party). Section 7.17 Confidentiality. Each Bank agrees to take normal and reasonable precautions and exercise due care to maintain the confidentiality of all non-public information provided to it by the Company or any Subsidiary in connection with this Agreement and the Related Documents; provided that such Bank may disclose to, and exchange and discuss with, any other Person (such Bank and each such other Person being hereby authorized to do so), any information concerning the Company or any Subsidiary (whether received by such Bank or such other Person in connection with or pursuant to this Agreement or otherwise) (a) to independent auditors or bank examiners or other governmental authorities, (b) to any Affiliate of the Bank, (c) to any participant or proposed participant pursuant to Section 7.07 that has agreed to be bound by the provisions of this Section 7.17 and (d) for the purpose of (i) complying with Applicable Law, (ii) protecting, preserving, exercising or enforcing any of their rights under or related to this Agreement or the Related Documents, (iii) performing any of their obligations under or related to this Agreement or the Related Documents or (iv) consulting with its legal counsel other advisors with respect to any of the foregoing. Each Bank shall, and shall cause any Affiliate to which it provides such non-public information to, use such non- public information only in connection with this Agreement and other existing or prospective credit arrangements with the Company not involving the purchase or sale of the securities. Section 7.18 Purchasing Bank's Rights and Responsibilities. (a) Except as otherwise expressly provided in this Agreement, the Purchasing Bank (i) shall have the sole right to exercise or refrain from exercising any rights or remedies it may have, or to take or refrain from taking any other action, with respect to the Disbursements or under this Agreement or any of the Related Documents or otherwise available to it, and (ii) shall not be required to obtain the consent of or consult with the Purchasing Banks with respect thereto. (b) The Purchasing Bank shall administer this Agreement in accordance with its customary practices with respect to similar credit facilities with respect to which it has not granted participations. The Purchasing Bank shall not, however, have any liability to the Participating Bank with respect to the exercise of its discretionary powers over the administration of this Agreement except to the extent such exercise constitutes a grossly negligent or willful failure to comply with such customary practices. The Purchasing Bank (i) shall be entitled to rely upon any writing, statement, consent, certificate or notice or any fax or telex message reasonably believed by it to be signed and sent by the proper person, (ii) may consult with counsel, independent public accountants, appraisers and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith in reliance on the advice of any such expert, and (iii) may employ agents or attorneys-in-fact and shall not be liable for the default or misconduct of any such person unless the Purchasing Bank was grossly negligent in selecting such person. (c) The Purchasing Bank shall have no duties or responsibilities, and makes no representations or warranties, to the Participating Banks except as expressly set forth in this Agreement. Without limiting the generality of the foregoing, neither the Participating Bank nor any of its officers, directors or employees shall be responsible to the Participant for, or shall be deemed to have made any representation or warranty with respect to, (i) the accuracy of any statement, representation or warranty made by any other person in or in connection with this Agreement or the Related Documents, (ii) the validity, enforceability, collectability or sufficiency of this Agreement or the Related Documents, (iii) the past, present or future financial condition of the Company, the Bond Insurer or any other Person or (iv) the performance of any of the terms, provisions or conditions of this Agreement or the Related Documents on the part of the Company, the Trustee, the Paying Agent, the Bond Insurer, the Remarketing Agent or any other Person. (d) Each Participating Bank acknowledges that (i) it has reviewed and is familiar with this Agreement and the Related Documents, (ii) it has made its own independent investigation of the financial condition and financial prospects of the Company, the Bond Insurer and all other obligors under the Related Documents, (iii) in entering into this Agreement, it has made its own credit analysis and decision and is not relying on the investigation of the Purchasing Bank or any of its directors, officers or employees or upon any financial projections, estimates, appraisals, financial summaries or credit memoranda prepared by or on behalf of the Purchasing Bank and given directly or indirectly to such Participating to assist such Participating in making its own independent evaluation and (iv) it will, independently and without reliance upon the Purchasing Bank and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decision in taking or not taking action under this Agreement and (v) no fiduciary relationship exists between such Participating Bank and the Purchasing Bank with respect to its Participation Interests. Section 7.19 Reimbursement and Indemnification by Participating Banks. To the extent the Purchasing Bank is not reimbursed and indemnified by the Company pursuant to Section 7.04(a) or 7.06, each Participating Bank agrees to indemnify the Purchasing Bank for such Participating Bank's Participation Share of any and all losses, liabilities, obligations, damages, penalties, actions, judgments, suits, costs, expenses (including, without limitation, fees and expenses of counsel) or disbursements of any kind or nature whatsoever which may be imposed on, incurred by or asserted against the Purchasing Bank in any way relating to or arising out of (i) the Disbursements, this Agreement or any of the Related Documents or any other document delivered in connection with the Disbursements or the transactions contemplated hereby or the enforcement of any of the terms hereof (provided that such Participating Bank shall not be liable for any of the foregoing to the extent they arise from the Purchasing Bank's gross negligence or willful misconduct) or (ii) without limiting the generality of the foregoing, the failure of such Participating Bank to comply with the provisions of Section 2.16(d)(iii) or any inaccuracy in any document delivered pursuant thereto. Section 7.20 Participating Banks' Obligations Absolute. Each Participating Bank's obligations under this Agreement shall constitute absolute, unconditional and continuing obligations and are irrespective of (i) any invalidity, unenforceability or insufficiency of any of the Related Documents, (ii) any default by or insolvency of the Company, the Bond Insurer or any other Person obligated with respect to any of the Disbursements, (iii) any act or omission (other than acts or omissions arising out of or relating to gross negligence or willful misconduct by the Purchasing Bank) on the part of the Purchasing Bank, any other bank, the Issuer, the Bond Insurer or any other Person hereunder or under the Related Documents, (iv) the absence of notice to such Participating Bank with respect to any of the foregoing, and (v) any requirement that the Purchasing Bank, any other bank, the Issuer, the Bond Insurer or any other Person take any action against the Company, the Bond Insurer or any other Person obligated with respect to the Disbursements. Section 7.21 Beneficiaries. This Agreement shall be for the benefit of the parties hereto, the Trustee, the Paying Agent and the holders of the Bonds, and nothing contained herein, express or implied, is intended to give any Person other than the parties hereto, the Trustee, the Paying Agent and the holders of the Bonds any right, remedy, or claim hereunder or by reason hereof. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and delivered by their respective officers thereunto duly authorized as of the date set forth below. THE CONNECTICUT LIGHT AND POWER COMPANY By: Name: Randy A. Shoop Title: Treasurer Address: The Connecticut Light and Power Company if by mail: P.O. Box 270 Hartford, CT 06141-0270 if by delivery: 107 Selden Street Berlin, CT 06037 Attention: Treasurer Telephone: 860-665-3258; Telecopy: 860-665-5457 THE BANK OF NEW YORK, as Purchasing Bank By: Name: Title: Address: One Wall Street, 18th Floor New York, NY 10286 Attention: Lawrence Berger Telephone: 212-635-8403; Telecopy: 212-635-8059 with a copy to: BNY Capital Markets, Inc. One Wall Street, 18th Floor New York, NY 10286 Attention: Lawrence Berger Telephone: 212-635-8403; Telecopy: 212-635-8059 BANK HAPOALIM, B.M., as Participating Bank By: Name: Title: Den Danske Bank A/S, as Participating Bank By: Name: Title: CITIC KA WAH BANK LIMITED, as Participating Bank By: Name: Title: Citizens BANK OF MASSACHUSETTS, as Participating Bank By: Name: Title: EX-10.26 5 0005.txt EXHIBIT 10.26 NEW ENGLAND POWER POOL RESTATED NEW ENGLAND POWER POOL AGREEMENT FERC ELECTRIC THIRD REVISED RATE SCHEDULE NO. 5 (As amended through the Sixty-Ninth Agreement Amending New England Power Pool Agreement) TABLE OF CONTENTS SHEET NO. PART ONE INTRODUCTION SECTION 1 DEFINITIONS 1.1 Accepted Electric Industry Practice 1.2 Adjusted Load 1.3 Adjusted Monthly Peak 1.4 Adjusted Net Interchange 1.5 Administrative Procedures 1.6 AGC Capability 1.7 AGC Entitlement 1.8 Agreement 1.9 Annual Transmission Revenue Requirements 1.10 Automatic Generation Control or AGC 1.11 Balloting Agent 1.12 Bid Price 1.13 Bilateral Transaction 1.14 Clearing Price 1.15 CMS 1.16 CMS/MSS Effective Date 1.17 Commission 1.18 Congestion 1.19 Congestion Component 1.20 Congestion Cost 1.21 Congestion Revenue 1.22 Congestion Revenue Fund 1.23 Control Area 1.24 Curtailment 1.25 Day-Ahead 1.26 Day-Ahead Market 1.27 Demand Bid 1.28 Demand Bid Price 1.29 Direct Assignment Facilities 1.30 Dispatch Day 1.31 Dispatchable Load 1.32 Dispatch Price 1.33 Distribution Company 1.34 Distribution Company Load Zone 1.35 EHV PTF 1.36 Electrical Load 1.37 Eligible Customer 1.38 End User Behind-the-Meter Generation 1.39 End User Organization 1.40 End User Participant 1.41 Energy 1.42 Energy Entitlement 1.43 Entitlement 1.44 Entity 1.45 Excepted Transaction 1.46 External Node 1.47 Facilities Study 1.48 FCR 1.49 Financial Congestion Right 1.50 Firm Contract 1.51 First Effective Date 1.52 Governance Only Member 1.53 HQ Contracts 1.54 HQ Energy Banking Agreement 1.55 HQ Interconnection 1.56 HQ Interconnection Agreement 1.57 HQ Interconnection Capability Credit 1.58 HQ Interconnection Transfer Capability 1.59 HQ Net Interconnection Capability Credit 1.60 HQ Phase I Energy Contract 1.61 HQ Phase I Percentage 1.62 HQ Phase I Transfer Credit 1.63 HQ Phase II Firm Energy Contract 1.64 HQ Phase II Gross Transfer Responsibility 1.65 HQ Phase II Net Transfer Responsibility 1.66 HQ Phase II Percentage 1.67 HQ Phase II Transfer Credit 1.68 HQ Use Agreement 1.69 Hub 1.70 Hub Price 1.71 Installed Capability 1.72 Installed Capability Entitlement 1.73 Installed Capability Responsibility 1.74 Installed System Capability 1.75 Interchange Transactions 1.76 Internal Point-to-Point Service 1.77 Interruption 1.78 ISO 1.79 Kilowatt 1.80 Large End User 1.81 Liaison Committee 1.82 Load 1.83 Load Asset Contract 1.84 Load Zone 1.85 Local Network 1.86 Local Network Service 1.87 Location 1.88 Locational Price 1.89 Lost Opportunity Cost 1.90 Lower Voltage PTF 1.91 Marginal Loss 1.92 Marginal Loss Component 1.93 Marginal Loss Revenue 1.94 Marginal Loss Revenue Fund 1.95 Market Products 1.96 Market Rules 1.97 Markets Committee 1.98 Megawatt 1.99 Monthly 1.100 MSS 1.101 NEPOOL 1.102 NEPOOL Control Area 1.103 NEPOOL Installed Capability 1.104 NEPOOL Installed Capability Responsibility 1.105 NEPOOL Objective Capability 1.106 NEPOOL Market 1.107 NEPOOL System Rules 1.108 NEPOOL Transmission System 1.109 NERC 1.110 {Net Hourly Load Obligation for Energy 1.111 New Unit 1.112 No-Load Price 1.113 Nodal Price 1.114 Node 1.115 Non-Participant 1.116 NPCC 1.117 OASIS 1.118 Operable Capability 1.119 Operating Reserve 1.120 Operating Reserve Entitlement 1.121 Other HQ Energy 1.122 Participant 1.123 Participants Committee 1.124 Pool-Planned Facility 1.125 Pool-Planned Unit 1.126 Power Year 1.127 Prior NEPOOL Agreement 1.128 Proxy Unit 1.129 PTF 1.130 Publicly Owned Entity 1.131 Real-Time 1.132 Real-Time Market 1.133 Reference Node 1.134 Regional Network Service 1.135 Related Person 1.136 Reliability Committee 1.137 Reliability Standards 1.138 Reliability Must Run 1.139 Reliability Region 1.140 {Reserve Contract 1.141 {Reserve Price 1.142 Resource 1.143 Review Board43 1.144 RMR 1.145 RMR Charge 1.146 RMR Uplift 1.147 Scheduled Dispatch Period 1.148 Second Effective Date 1.149 Sector 1.149A Self-Schedule 1.149B Self-Supply 1.150 Service Agreement 1.151 Settlement Obligation 1.152 Shift Factor 1.153 Small End User 1.154 Standard Offer Obligation 1.155 Start-Up Price 1.156 Summer Capability 1.157 Summer Period 1.158 Supply Obligation 1.159 Supply Offer 1.160 Supply Offer Price 1.161 System Contract 1.162 System Impact Study 1.163 System Operator 1.164 Target Availability Rate 1.165 Tariff 1.166 Tariff Committee 1.167 Technical Committees 1.168 Third Effective Date 1.169 Through or Out Service 1.170 Transition Period 1.171 Transmission Customer 1.172 Transmission Owner 1.173 Transmission Owners Committee 1.174 Transmission Provider 1.175 Unit Contract 1.176 Withdrawal Factor 1.177 Winter Capability 1.178 Winter Period 1.179 Zonal Price 1.180 4-Hour Reserve 1.181 4-Hour Reserve Entitlement 1.182 10-Minute Spinning Reserve 1.183 10-Minute Non-Spinning Reserve 1.184 30-Minute Operating Reserve 1.185 Modification of Certain Definitions When a Participant Purchases a Portion of Its Requirements from Another Participant Pursuant to Firm Contract SECTION 2 PURPOSE; EFFECTIVE DATES 2.1 Purpose 2.2 Effective Dates; Transitional Provisions SECTION 3 MEMBERSHIP 3.1 Membership 3.2 Operations Outside the Control Area 3.3 Lack of Place of Business in New England 3.4 Obligation for Deferred Expenses 3.5 Financial Security SECTION 4 STATUS OF PARTICIPANTS 4.1 Treatment of Certain Entities as Single Participant 4.2 Participants to Retain Separate Identities SECTION 5 NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS 5.1 NEPOOL Objectives 5.2 Cooperation by Participants PART TWO GOVERNANCE SECTION 6 COMMITTEE ORGANIZATION AND VOTING 6.1 Principal Committees 6.2 Sector Representation 6.3 Appointment of Members and Alternates 6.4 Term of Members 6.5 Regular and Special Meetings 6.6 Notice of Meetings 6.7 Attendance 6.8 Quorum 6.9 Voting Definitions 6.10 Voting On Proposed Actions 6.11 Voting On Amendments 6.12 Designated Representatives and Proxies 6.13 Limits on Representatives 6.14 Adoption of Bylaws 6.15 Joint Meetings of Technical Committees SECTION 7 PARTICIPANTS COMMITTEE 7.1 Officers 7.2 Adoption of Budgets 7.3 Establishing Reliability Standards 7.4 Appointment and Compensation of NEPOOL Personnel 7.5 Duties and Authority 7.6 Attendance of Participants at Committee Meeting 7.7 Appeal of Actions to Review Board SECTION 8 RELIABILITY COMMITTEE 8.1 Officers 8.2 Notice to Members and Alternates of Participants Committee 8.3 Voting; Appeal of Actions 8.4 Responsibilities 8.5 Establishment of Subcommittees and Task Forces 8.6 Further Powers and Duties SECTION 9 TARIFF COMMITTEE 9.1 Officers 9.2 Notice to Members and Alternates of Participants Committee 9.3 Voting; Appeal of Actions 9.4 Responsibilities 9.5 Establishment of Subcommittees and Task Forces 9.6 Further Powers and Duties SECTION 10 MARKETS COMMITTEE 10.1 Officers 10.2 Notice to Members and Alternates of Participants Committee 10.3 Voting; Appeal of Actions 10.4 Responsibilities 10.5 Establishment of Subcommittees and Task Forces 10.6 Further Powers and Duties 10.7 Development of Rules Relating to Non-Participant Supply and Demand-side Resources SECTION 11 FURTHER RESTRUCTURING SECTION 11A REVIEW BOARD 11A.1 Organization 11A.2 Composition 11A.3 Qualifications 11A.4 Term 11A.5 Meetings 11A.6 Bylaws 11A.7 Procedure on Appeal of Participant Committee Action or Failure to Take Action 11A.8 Effect of a Review Board Decision 11A.9 11A.10 11A.11 SECTION 11B TRANSMISSION OWNERS COMMITTEE 11B.1 Organization 11B.2 Membership 11B.3 Appointment of Members and Alternates 11B.4 Term of Members 11B.5 Regular and Special Meetings 11B.6 Notice of Meetings 11B.7 Attendance 11B.8 Votes 11B.9 Appointment of Task Forces or Working Groups 11B.10 Officers 11B.11 Adoption of Bylaws 11B.12 Review of Committee Actions SECTION 11C LIAISON COMMITTEE 11C.1 Organization; Duties 11C.2 Membership 11C.3 Regular and Special Meetings 11C.4 Notice of Meetings 11C.5 Attendance 11C.6 Officers PART THREE MARKET PROVISIONS SECTION 12 INSTALLED CAPABILITY OBLIGATIONS AND PAYMENTS 12.0 Continuing Reliability Measures 12.1 Obligations to Provide Installed Capability 12.2 Computation of Installed Capability Responsibilities 12.3 [Deleted.] 12.4 [Deleted.] 12.5 Consequences of Deficiencies in Installed Capability Responsibility 12.6 [Deleted] 12.7 Payments to Participants Furnishing Installed Capability SECTION 13 OPERATION, GENERATION, OTHER RESOURCES, AND INTERRUPTIBLE CONTRACTS 13.1 Maintenance and Operation in Accordance with Accepted Electric Industry Practice 13.2 Central Dispatch 13.3 Maintenance and Repair 13.4 Objectives of Day-to-Day System Operation 13.5 Satellite Membership SECTION 14 INTERCHANGE TRANSACTIONS 14.1 Obligation for Energy, Operating Reserve and Automatic Generation Control 14.2 Obligation to Bid or Schedule, and Right to Receive Energy, Operating Reserve and Automatic Generation Control 14.3 Amount of Energy, Operating Reserve and Automatic Generation Control Received or Furnished 14.4 Payments by Participants Receiving Energy Service, Operating Reserve and Automatic Generation Control 14.5 Payments to Participants Furnishing Energy Service, Operating Reserve, and Automatic Generation Control 14.6 Energy Transactions with Non-Participants 14.7 Participant Purchases Pursuant to Firm Contracts and System Contracts 14.8 Determination of Energy Clearing Price 14.9 Determination of Operating Reserve Clearing Price 14.10 Determination of AGC Clearing Price 14.11 Funds to or from which Payments are to be Made 14.12 Development of Rules Relating to Nuclear and Hydroelectric Generating Facilities, Limited-Fuel Generating Facilities, and Interruptible Loads 14.13 Dispatch and Billing Rules During Energy Shortages 14.14 Congestion Uplift 14.14A CMS/MSS Implementation Studies Related to Congestion 14.15 Additional Uplift Charges SECTION 14A PARTICIPANT MARKET TRANSACTIONS ON AND AFTER THE CMS/MSS EFFECTIVE DATE 14A.1 Supply Obligations and Settlement Obligations for Energy, Operating Reserve, 4-Hour Reserve and Automatic Generation Control 14A.2 Right to Receive Service 14A.3 Participation in the Day-Ahead Market 14A.4 Nature of Demand Bids and Supply Offers; Limitations; Self-Schedules and Self-Supplies 14A.5 Scheduling Procedures in the Day-Ahead Market 14A.6 Participation in the Real-Time Market 14A.7 Scheduling Procedures in the Real-Time Market 14A.8 Settlement Obligation Payments for Energy, Operating Reserves, 4-Hour Reserves and Automatic Generation Control 14A.9 Supply Obligation Payments For Energy, Operating Reserves, 4-Hour Reserves and Automatic Generation Control 14A.10 Contract and Scheduling Authority 14A.11 Bilateral Transactions and Participant Transactions with Non- Participants 14A.12 Determination of Locational Prices 14A.13 Determination of Operating Reserve and 4-Hour Reserve Clearing Prices 14A.14 Determination of AGC Clearing Price 14A.15 Funds to or from which Payments are to Be Made 198WW14A.16 Marginal Losses 14A.17 Congestion Cost and Revenues 14A.18 Market Monitoring and Reports 14A.19 Additional Uplift ChargesPART FOUR TRANSMISSION PROVISIONS SECTION 15 OPERATION OF TRANSMISSION FACILITIES 15.1 Definition of PTF 15.2 Maintenance and Operation in Accordance with Accepted Electric Industry Practice 15.3 Central Dispatch 15.4 Maintenance and Repair 15.5 Additions to or Upgrades of PTF SECTION 16 SERVICE UNDER TARIFF 16.1 Effect of Tariff 16.2 Obligation to Provide Regional Service 16.3 Obligation to Provide Local Network Service 16.4 Transmission Service Availability 16.5 Transmission Information 16.6 Distribution of Transmission Revenues SECTION 17 POOL-PLANNED UNIT SERVICE 17.1 Effective Period 17.2 Obligation to Provide Service 17.3 Rules for Determination of Facilities Covered by Particular Transactions 17.4 Payments for Uses of EHV PTF During the Transition Period 17.5 Payments for Uses of Lower Voltage PTF 17.6 Use of Other Transmission Facilities by Participants 17.7 Limits on Individual Transmission Charges SECTION 17A TRANSMISSION OWNERS RESERVED RIGHTS 17A.1 17A.2 17A.3 17A.4 17A.5 17A.6 17A.7 17A.8 PART FIVE GENERAL SECTION 18 GENERATION AND TRANSMISSION FACILITIES 18.1 Designation of Pool-Planned Facilities 18.2 Construction of Facilities 18.3 Protective Devices for Transmission Facilities and Automatic Generation Control Equipment 18.4 Review of Participant's Proposed Plans 18.5 Participant to Avoid Adverse Effect SECTION 19 EXPENSES 19.1 Annual Fee 19.2 NEPOOL Expenses 19.3 Restructuring Costs SECTION 20 INDEPENDENT SYSTEM OPERATOR SECTION 21 MISCELLANEOUS PROVISIONS 21.1 Alternative Dispute Resolution 21.2 Payment of Pool Charges; Termination of Status as Participant 21.3 Assignment 21.4 Force Majeure 21.5 Waiver of Defaults 21.6 Other Contracts 21.7 Liability and Insurance 21.8 Records and Information 21.9 Consistency with NPCC and NERC Standards 21.10 Construction 21.11 Amendment 21.12 Termination 21.13 Notices to Participants, Committees, Committee Members, or the System Operator 21.14 Severability and Renegotiation 21.15 No Third-Party Beneficiaries 21.16 Counterparts ATTACHMENT A METHODOLOGY FOR DETERMINATION OF TRANSMISSION FLOWS ATTACHMENT B NEPOOL OPEN ACCESS TRANSMISSION TARIFF ATTACHMENT C RELIABILITY REGIONS 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 Percentageis 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 (a) 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. (b) 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 (a) 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 (b) kilowatthours delivered by such Participant pursuant to Firm Contracts to its wholesale customers for resale, plus (c) kilowatthours of use by such Participant, exclusive of use by such Participant for the operation and maintenance of its generating unit or units, plus (d) 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 NERCis 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. 1.120 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. 1.122 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 Serviceis the transmission service by that name provided pursuant to Section 14 of the Tariff. 1.135 Related Personof a Participant is: (a) 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 (b) 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. (c) 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 Boardis 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. 1.149A 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. 1.149B 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. 1.150 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. 1.151 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. 1.152 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. 1.153 Small End User is a End User Participant which does not otherwise meet the definition of Large End User or End User Organization. 1.154 Standard Offer Obligation has the meaning specified in Section 14A.12(b)(ii) of the Agreement and Schedule 13 of the Tariff. 1.155 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. 1.156 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). 1.157 Summer Period in each Power Year is the four-month period from June through September. 1.158 Supply Obligation is an obligation as defined in Section 14A.1(a) for Energy, Operating Reserve, 4-Hour Reserve, and/or AGC. 1.159 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. 1.160 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. 1.161 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. 1.162 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. 1.163 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. 1.164 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. 1.165 Tariff is the NEPOOL Open Access Transmission Tariff set out in Attachment B to the Agreement, as modified and amended from time to time. 1.166 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. 1.167 Technical Committees are the Reliability Committee, the Tariff Committee and the Markets Committee. 1.168 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. 1.169 Through or Out Service is the transmission service by that name provided pursuant to Section 18 of the Tariff. 1.170 Transition Period is the six- year period commencing on March 1, 1997. 1.171 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. 1.172 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. 1.173 Transmission Owners Committee is the committee whose responsibilities are specified in Section 11B. 1.174 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. 1.175 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. 1.176 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. 1.177 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). 1.178 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. 1.179 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. 1.180 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. 1.181 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. 1.182 10-Minute Spinning Reserve (a) 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. (b) 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. 1.183 10-Minute Non-Spinning Reserve (a) 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. (b) 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. 1.184 30-Minute Operating Reserve (a) 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. (b) 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. 1.185 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: (a) 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): (1) 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 (2) 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. (b) 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): (1) the Installed Capability Responsibility of the purchasing Participant shall be equal to the amount of its Installed Capability Entitlements; (2) 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 (3) 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 (EQUATION) 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 Error! Reference source not found. of 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 6.3 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. 6.4 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) 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. (b) 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. (c) 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. (d) 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. (e) 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. 6.5 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. 6.6 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. 6.7 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. 6.8 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. 6.9 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. 6.10 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. 6.11 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: (a) 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%). (b) 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. (c) 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. (d) 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". (e) 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. (f) 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. 6.12 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. 6.13 Voting On Amendments. Subject to Section 21.11 and Section 17A, amendments to the NEPOOL Agreement or Tariff shall be accomplished as follows: (a) Amendments shall be drafted by a standing or ad hoc NEPOOL committee or a Participant and sent to the Participants Committee for its consideration. (b) 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. (c) 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. (d) 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. (e) 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. 6.14 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. 6.15 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. 6.16 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. 6.17 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. (i) 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; (j) 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.); (k) 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.); (l) 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; (m) 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 (n) 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. (g) develop operating procedures relating to the administration of the NEPOOL Markets and periodically review and recommend changes thereto as appropriate; and (h) 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. (e) Hearing: A hearing (if any) will be held as soon as is reasonably practicable. (f) 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. (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. (b) 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 prior 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 12.1 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)c2) + K6(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. (b) 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. (c) 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. (d) 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. (c) 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. (d) 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 the Energy 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: (EQUATION) where: (EQUATION) the Nodal Price at Node i in $/megawatthour; (EQUATION) the marginal cost in $/megawatthour, based on Demand Bids and Supply Offers, to serve additional load at the Reference Node; (EQUATION) the Marginal Loss Component of the Nodal Price at Node i in $/megawatthour; and (EQUATION) 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 (EQUATION) in which WFi, the Withdrawal Factor at Node i relative to the system Reference Node, is calculated using the following equation: (EQUATION) where: L = NEPOOL Transmission System losses; Pi = the net amount of Energy injected into the NEPOOL Transmission System at Node i; and (EQUATION) = 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: (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 (EQUATION) = 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 and into the equation for calculating the Nodal Price for a given Node i yields: (EQUATION) (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: (EQUATION), where: (EQUATION) = Zonal Price for Reliability Region j in $/megawatthour; (EQUATION) is as defined in Section 14A.12(a); (EQUATION) is the Marginal Loss Component of the Zonal Price for Reliability Region j in $/megawatthour; (EQUATION) 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: (EQUATION) where: (EQUATION) = Hub Price for Hub j in $/megawatthour; (EQUATION) is as defined in Section 14A.12(a); (EQUATION) is the Marginal Loss Component of the Hub Price for Hub j in $/megawatthour; (EQUATION) is the Congestion Component of the Hub Price for Hub j in $/megawatthour; Hj = the set of Nodes in Hub j; and WijH = 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: (EQUATION) where: (EQUATION) = 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; GFin = Shift Factor at External Node i for the interconnection line that passes through Node n; and (WFn - 1) (EQUATION) = the Marginal Loss Component of the Nodal Price at Node n in $/megawatthour, where WFn is the withdrawal factor at Node n and (EQUATION) 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. (c) 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. (d) 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: (i) (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 (ii) 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.18 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. (b) 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. (c) 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. (d) 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. (e) 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. (i) 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. (ii) 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 Settlemen 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: (EQUATION) 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. (iii) 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: (EQUATION) 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. (iv) 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. (v) 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: (EQUATION) 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 15.16 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. 15.17 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. 15.18 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. 15.19 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. 15.20 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 One Year Two Year Three Year Four Years Five and Six % of charge to be paid 100% 80% 60% 40% 20% (iv) 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 (v) 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 One Year Two Year Three Year Four Year Five Year Six Allocated Flows: 25% 20% 15% 10% 5% 2.5% Annual Transmission Revenue Requirements: 75% 80% 85% 90% 95% 97.5% 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. B. 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. C. 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. D. 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. E. 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. (a) 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. (b) 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. (c) 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 18.8 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. 18.9 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. 18.10 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. 18.11 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. 18.12 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 or funded separately by the ISO) 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 of 10.78% per annum. 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: (EQUATION) 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. (EQUATION) 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. Each month commencing on or after January 1, 2001 and continuing until the Early Restructuring Expense has been fully amortized and repaid (including the payment of all interest thereon), each Participant shall pay its percentage "W", 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 in accordance with the formula set forth therefor in this Section 19.3(b), of the aggregate of the amount paid for the month, including accumulated interest. "W" shall be determined in accordance with the following formula: (EQUATION) W is the percentage to be paid for the month by a Participant of the aggregate amount payable pursuant to this subsection (b) by all Participants for the month. EL is the Participant's total Electrical Load, expressed in total kilowatthours, for the month. G is the sum, expressed in total kilowatthours, of (i) the Participant's share of the amount of energy that is generated in the month by generating units in which the Participant has a direct ownership interest as a sole or joint owner and which is subject to NEPOOL central dispatch, (ii) the Participant's share of the amount of energy generated in the month by generating units in which the Participant has an indirect ownership interest as a shareholder, as a general or limited partner or as a member of a limited liability company and which is subject to NEPOOL central dispatch, provided that the corporation, partnership or limited liability company is not itself a Participant, (iii) the Participant's share of the amount of energy generated in the month by any other generating unit in which the Participant has an interest under a lease or other contractual arrangement, provided that the other party to the arrangement is itself not a Participant, (iv) the share of any Related Person of the Participant of the amount of energy generated in the month by any other generating unit which is subject to NEPOOL central dispatch in which such Related Person has one of the interests described in clauses (i), (ii) and (iii) above, provided that such Related Person is not itself a Participant, and (v) the amount of energy imported into the NEPOOL Control Area in the month by the Participant or any Related Person of the Participant, provided that the Related Person is not itself a Participant (the items described in this subparagraph are collectively referred to as a Participant's "Generating Shares"); provided, however, that if two or more Participants have entered into a Unit Contract for Energy, the purchasing Participant(s), and not the selling Participant(s), thereunder shall be credited with the amount of energy to which the purchasing Participant(s) are entitled under that Unit Contract for purposes of calculating the Generating Shares of each such Participant. PEL is the maximum Electrical Load, expressed in total kilowatts, of the Participant during any hour in the month (the "Peak Electrical Load"). GP is the maximum Generating Shares, expressed in total kilowatts, of the Participant during any hour in the month (the "Generating Peak"). EL1 is the aggregate Electrical Load, expressed in total kilowatts, of all Participants for the month. G1 is the aggregate Generating Shares, expressed in total kilowatthours, of all Participants for the month. PEL1 is the aggregate Peak Electrical Load, expressed in total kilowatts, of all Participants for the month. GP1 is the aggregate Generating Peak, expressed in total kilowatts, of all Participants for the month. [Next Sheet is 241 (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 be funded for each month, on an as incurred basis, by the Participants to the extent that the ISO does not obtain an alternative source of funds for certain portions of the Late Restructuring Expense. In 2000, such Late Restructuring Expense shall initially be funded for each month by the Participants in proportion to their charges under the ISO Tariff for the prior month. In 2001 and thereafter, on an as-incurred basis, the ISO shall allocate the incrementally incurred Late Restructuring Expense among the various schedules to the ISO Tariff that is in effect at that time in a manner that best matches the elements comprising the incrementally incurred Late Restructuring Costs to the types of service to be covered by each schedule to the ISO Tariff, and the portion of the Late Restructuring Expense to be funded by the Participants that has been allocated to each such schedule to the ISO Tariff for such year shall be funded in each month by the Participants in proportion to their charges under such schedule for the prior month; provided, however, that in the event that the Commission accepts (i) an amendment to the ISO Agreement (as defined in Section 20(a) hereof) providing that in the event of a termination or resignation of the ISO, all assets purchased by the ISO with funds provided by the Participants for which the Participants have not been reimbursed shall be transferred without further consideration to the Participants or their designee (which amendment shall be mutually acceptable to the ISO and the Participants Committee) and (ii) an amendment to the ISO Tariff or a separate tariff for the ISO pursuant to which the ISO collects certain portions of the Late Restructuring Expense thereunder, such portions of the Late Restructuring Expense shall be funded directly under the ISO Tariff or such separate tariff for the ISO and shall not be initially collected hereunder. Each item of the Late Restructuring Expense funded by the Participants in each calendar year (either hereunder, under the ISO Tariff or under a separate tariff for the ISO) shall be amortized in equal monthly amounts and repaid over a period of time determined by the ISO in accordance with generally accepted accounting principles in effect at the time of determination and taking into consideration the depreciation period, if any, of the particular asset giving rise to such item of the Late Restructuring Expense, such repayment to include interest thereon from the date of payment at the rate of 10.78% per annum. For each item of the Late Restructuring Expense funded by the Participants (regardless of whether it was incurred before, on or after January 1, 2001 and whether it was funded hereunder, under the ISO Tariff or under a separate tariff for the ISO) and during the time in which amounts are being amortized and repaid for such item, the ISO shall determine to which schedule or schedules of the then effective ISO Tariff such item relates, and the ISO, acting as agent for the Participants initially providing the funding for such item, shall recover the amounts being repaid that are associated with such item plus accrued interest from the Participants using the allocation methodology set forth in such schedule or schedules to the ISO Tariff. The ISO shall provide the amounts recovered to the applicable Participants according to which Participants funded the item of the Late Restructuring Expense for which the subject amounts have been recovered. (e) 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 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, but only to the extent that the ISO does not obtain such funding from other sources. 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 with funding provided by the Participants pursuant to this Agreement 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, any funding by the Participants 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 ISO Tariff or a separate tariff for the ISO. 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 an 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. B. 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. (i) 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. C. 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. D. 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 NEW ENGLAND POWER POOL RESTATED NEPOOL OPEN ACCESS TRANSMISSION TARIFF FERC ELECTRIC TARIFF, FOURTH REVISED VOLUME NO. 1 (As amended through the Sixty-Ninth Agreement Amending New England Power Pool Agreement) I. COMMON SERVICE PROVISIONS 1 Definitions 1.1 Administrative Costs 1.2 Agreement 1.3 Ancillary Services 1.4 Annual Transmission Revenue Requirements 1.5 Application 1.6 ARR 1.7 ARR Allocation 1.8 Auction Revenue Right 1.9 Auction Revenue Right Holder 1.10 Backyard Generation 1.11 Business Day 1.12 CMS 1.13 CMS/MSS Effective Date 1.14 Commission 1.15 Completed Application 1.16 Compliance Effective Date 1.17 Congestion 1.18 Congestion Component 1.19 Congestion Cost 1.20 Congestion Paying Entity 1.21 Congestion Revenue 1.22 Congestion Revenue Fund 1.23 Congestion Revenue Shortfall 1.24 Congestion Revenue Surplus 1.25 Control Area 1.26 Curtailment 1.27 Day-Ahead 1.28 Day-Ahead Market 1.29 Delivering Party 1.30 Demand Bid 1.31 Demand Bid Price 1.32 Designated Agent 1.33 Direct Assignment Facilities 1.34 Direct Interconnection Transmission Costs 1.35 Dispatch Day 1.36 Distribution Company 1.37 Distribution Company Load Zone 1.38 Economic Upgrade 1.39 Elective Transmission Upgrade 1.40 Eligible Customer 1.41 Energy 1.42 Energy Imbalance Service 1.43 Entitlement 1.44 Excepted Transaction 1.45 External Node 1.46 Facilities Study 1.47 FCR 1.48 FCR Auction 1.49 FCR Auction Revenue 1.50 FCR Auction Revenue Fund 1.51 FCR Holder 1.52 FCR Payment 1.53 Financial Congestion Right 1.54 Firm Contract 1.55 Firm Point-To-Point Transmission Service 1.56 Firm Transmission Service 1.57 Generator Interconnection Related Upgrade 1.58 Generator Owner 1.59 Good Utility Practice 1.60 Hub 1.61 Hub Price 1.62 HQ Interconnection 1.63 HQ Phase II Firm Energy Contract 1.64 Import Transaction 1.65 Interchange Transactions 1.66 Interest 1.67 Internal Point-to-Point Service 1.68 Internal Point-to-Point Service Rate 1.69 Interruption 1.70 ISO 1.71 Load Asset Contract 1.72 Load Ratio Share 1.73 Load Shedding 1.74 Load Zone 1.75 Local Network 1.76 Local Network Service 1.77 Local Point-To-Point Service 1.78 Location 1.79 Locational Price 1.80 Long-Term Firm Service 1.81 Marginal Loss 1.82 Marginal Loss Component 1.83 Marginal Loss Revenue 1.84 Marginal Loss Revenue Fund 1.85 Market Rules 1.85 A Merchant Transmission Facility 1.86 Minimum Interconnection Standard 1.87 Monthly Network Load 1.88 Monthly Peak 1.89 Monthly Peak Load 1.90 Native Load Customers 1.91 NEMA 1.92 NEMA ARRs 1.93 NEMA Contract 1.94 NEMA LSE 1.95 NEMA or "Northeast Massachusetts" Upgrade 1.96 NEPOOL 1.97 NEPOOL Control Area 1.98 NEPOOL System Rules 1.99 NEPOOL Transmission Plan 1.100 NEPOOL Transmission System 1.101 NERC 1.102 Network Customer 1.103 Network Integration Transmission Service 1.104 Network Load 1.105 Network Operating Agreement 1.106 Network Operating Committee 1.107 Network Resource 1.108 Network Upgrades 1.109 Nodal Price 1.110 Node 1.111 Non-Firm Point-To-Point Transmission Service 1.112 Non-Participant 1.113 Non-PTF 1.114 Northeast Massachusetts Upgrade 1.115 NPCC 1.116 Open Access Same-Time Information System (OASIS) 1.117 Operating Reserve - 10-Minute Non-Spinning Reserve Service 1.118 Operating Reserve - 10-Minute Spinning Reserve Service 1.119 Operating Reserve - 30-Minute Reserve Service 1.120 Participant 1.121 Participant RNS Rate 1.122 Participants Committee 1.123 Point(s) of Delivery 1.124 Point(s) of Receipt 1.125 Point-To-Point Transmission Service 1.126 Pool-Planned Unit 1.127 Pool PTF Rate 1.128 Pool RNS Rate 1.129 Pool-Supported PTF 1.130 Power Purchaser 1.131 Prior NEPOOL Agreement 1.132 PTF or Pool Transmission Facilities 1.133 Pre-1997 PTF Rate 1.134 Publicly Owned Entity 1.135 Quick Fix Upgrade 1.136 Reactive Supply and Voltage Control From Generation Sources Service 1.137 Real-Time 1.138 Real-Time Market 1.139 Receiving Party 1.140 Reference Node 1.141 Regional Network Service 1.142 Regulation and Frequency Response Service 1.143 Reliability Region 1.144 Reliability Upgrade 1.145 Reserved Capacity 1.146 Scheduling, System Control and Dispatch Service 1.147 Second Effective Date 1.148 Service Agreement 1.149 Service Commencement Date 1.150 Settlement Obligation 1.151 Shift Factor 1.152 Short-Term Firm Service 1.153 Standard Offer Obligation 1.154 Supply Obligation 1.155 Supply Offer 1.156 System Contract 1.157 System Impact Study 1.158 System Operator 1.159 Target FCR Payment 1.160 Tariff 1.161 Third-Party Sale 1.162 Through or Out Service 1.163 Third Effective Date 1.164 Ties 1.165 Transition Period 1.166 Transmission Customer 1.167 Transmission Owner 1.168 Transmission Owners Committee 1.169 Transmission Provider 1.170 Transmission System Upgrade 1.171 Unit Contract 1.172 Use 1.173 Withdrawal Factor 1.174 Year 1.175 Zonal Price 2 Purpose of This Tariff 3 Initial Allocation and Renewal Procedures 3.1 Initial Allocation of Available Transmission Capability 3.2 Reservation Priority for Existing Firm Service Customers 3.3 Initial Election of Optional Internal Point-to-Point Service 4 Ancillary Services 4.1 Scheduling, System Control and Dispatch Service 4.2 Reactive Supply and Voltage Control from Generation Sources Service 4.3 Regulation and Frequency Response Service 4.4 Energy Imbalance Service 4.5 Operating Reserve - 10-Minute Spinning Reserve Service 4.6 Operating Reserve - 10-Minute Non-Spinning Reserve Service 4.7 Operating Reserve - 30-Minute Reserve Service 4.8 System Restoration and Planning Service 5 Open Access Same-Time Information System (OASIS) 6 Local Furnishing and Other Tax-Exempt Bonds 6.1 Participants That Own Facilities Financed by Local Furnishing or Other Tax-Exempt Bonds 6.2 Alternative Procedures for Requesting Transmission Service - Local Furnishing Bonds 6.3 Alternative Procedures for Requesting Transmission Service - Other Tax-Exempt Bonds 7 Reciprocity 8 Billing and Payment; Accounting 8.1 Participant Billing Procedure 8.2 Non-Participant Billing Procedure 8.3 Interest on Unpaid Balances 8.4 Customer Default 8.5 Study Costs and Revenues 9 Regulatory Filings 10 Force Majeure and Indemnification 10.1 Force Majeure 10.2 Indemnification 11 Creditworthiness 12 Dispute Resolution Procedures 12.1 Internal Dispute Resolution Procedures 12.2 Rights Under The Federal Power Act 13 Stranded Costs 13.1 General 13.2 Commission Requirements 13.3 Wholesale Contracts 13.4 Right to Seek or Contest Recovery Unimpaired II. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION SERVICE) 14 Nature of Regional Network Service 14.1 Rules for Import Transactions Conducted in Conjunction with Regional Network Service: 15 Availability of Regional Network Service 15.1 Provision of Regional Network Service 15.2 Eligibility to Receive Regional Network Service 16 Payment for Regional Network Service 17 Procedure for Obtaining Regional Network Service III. THROUGH OR OUT SERVICE; INTERNAL POINT-TO-POINT SERVICE 18 Through or Out Service 18.1 Provision of Through or Out Service 18.2 Use of Through or Out Service 19 Internal Point-to-Point Service 19.1 Provision of Internal Point-to-Point Service 19.2 Use of Internal Point-to-Point Service 19.3 Use by a Transmission Customer 20 Payment for Through or Out Service 21 Payment for Internal Point-to-Point Service 22 Reservation of Capacity for Point-to-Point Transmission Service IV. SERVICE DURING THE TRANSITION PERIOD; CONGESTION COSTS; EXCEPTED TRANSACTIONS 23 Transition Arrangements 24 Congestion Costs and Congestion Revenue 25 Excepted Transactions 25A Phase I Credit and Uplift Charge With Respect to Excepted Transactions 25B Phase II Credit and Uplift Charge With Respect to Certain Excepted Transactions V. POINT-TO-POINT TRANSMISSION SERVICE Preamble 26 Scope of Application of Part V 27 Nature of Firm Point-To-Point Transmission Service 27.1 Term 27.2 Reservation Priority 27.3 Use of Firm Point-To-Point Transmission Service by the Participants That Own PTF 27.4 Service Agreements 27.5 Transmission Customer Obligations for Facility Additions or Redispatch Costs 27.6 Curtailment of Firm Transmission Service 27.7 Classification of Firm Point-To-Point Transmission Service 27.8 Scheduling of Firm Point-To-Point Transmission Service 28 Nature of Non-Firm Point-To-Point Transmission Service 28.1 Term 28.2 Reservation Priority 28.3 Use of Non-Firm Point-To-Point Transmission Service by the Transmission Provider 28.4 Service Agreements 28.5 Classification of Non-Firm Point-To-Point Transmission Service 28.6 Scheduling of Non-Firm Point-To-Point Transmission Service 28.7 Curtailment or Interruption of Service 29 Service Availability 29.1 General Conditions 29.2 Determination of Available Transmission Capability 29.3 Initiating Service in the Absence of an Executed Service Agreement 29.4 Obligation to Provide Transmission Service that Requires Expansion or Modification of the Transmission System 29.5 Deferral of Service 29.6 Real Power Losses 29.7 Load Shedding 30 Transmission Customer Responsibilities 30.1 Conditions Required of Transmission Customers 30.2 Transmission Customer Responsibility for Third-Party Arrangements 31 Procedures for Arranging Firm Point-To-Point Transmission Service 31.1 Application 31.2 Completed Application 31.3 Deposit 31.4 Notice of Deficient Application 31.5 Response to a Completed Application 31.6 Execution of Service Agreement 31.7 Extensions for Commencement of Service 32 Procedures for Arranging Non-Firm Point-To-Point Transmission Service 32.1 Application 32.2 Completed Application 32.3 Reservation of Non-Firm Point-To-Point Transmission Service 32.4 Determination of Available Transmission Capability 33 Additional Study Procedures For Firm Point-To-Point Transmission Service Requests 33.1 Notice of Need for System Impact Study 33.2 System Impact Study Agreement and Cost Reimbursement 33.3 System Impact Study Procedures 33.4 Facilities Study Procedures 33.5 Facilities Study Modifications 33.6 Due Diligence in Completing New Facilities 33.7 Partial Interim Service 33.8 Expedited Procedures for New Facilities 34 Procedures if New Transmission Facilities for Firm Point-To-Point Transmission Service Cannot be Completed 34.1 Delays in Construction of New Facilities 34.2 Alternatives to the Original Facility Additions 34.3 Refund Obligation for Unfinished Facility Additions 35 Provisions Relating to Transmission Construction and Services on the Systems of Other Utilities 35.1 Responsibility for Third-Party System Additions 35.2 Coordination of Third-Party System Additions 36 Changes in Service Specifications 36.1 Modifications on a Non-Firm Basis 36.2 Modification on a Firm Basis 37 Sale, Assignment or Transfer of Transmission Service 37.1 Procedures for Sale, Assignment or Transfer of Service 37.2 Limitations on Assignment or Transfer of Service 37.3 Information on Assignment or Transfer of Service 38 Metering and Power Factor Correction at Receipt and Delivery Points(s) 38.1 Transmission Customer Obligations 38.2 NEPOOL Access to Metering Data 38.3 Power Factor 39 Compensation for New Facilities and Redispatch Costs VI. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION SERVICE) 40 Nature of Regional Network Service 40.1 Scope of Service 40.2 Transmission Provider Responsibilities 40.3 Network Integration Transmission Service 40.4 Secondary Service 40.5 Real Power Losses 40.6 Restrictions on Use of Service 41 Initiating Service 41.1 Condition Precedent for Receiving Service 41.2 Application Procedures 41.3 Technical Arrangements to be Completed Prior to Commencement of Service 41.4 Network Customer Facilities 41.5 Filing of Service Agreement 42 Network Resources 42.1 Designation of Network Resources 42.2 Designation of New Network Resources 42.3 Termination of Network Resources 42.4 Network Customer Redispatch Obligation 42.5 Transmission Arrangements for Network Resources Not Physically Interconnected With The NEPOOL Transmission System 42.6 Limitation on Designation of Resources 42.7 Use of Interface Capacity by the Network Customer 43 Designation of Network Load 43.1 Network Load 43.2 New Network Loads Connected With the NEPOOL Transmission System 43.3 Network Load Not Physically Interconnected with the NEPOOL Transmission System 43.4 New Interconnection Points 43.5 Changes in Service Requests 43.6 Annual Load and Resource Information Updates 44 Additional Study Procedures For Network Integration Transmission Service Requests 44.1 Notice of Need for System Impact Study 44.2 System Impact Study Agreement and Cost Reimbursement 44.3 System Impact Study Procedures 44.4 Facilities Study Procedures 45 Load Shedding and Curtailments 45.1 Procedures 45.2 Transmission Constraints 45.3 Cost Responsibility for Relieving Transmission Constraints 45.4 Curtailments of Scheduled Deliveries 45.5 Allocation of Curtailments 45.6 Load Shedding 45.7 System Reliability 46 Rates and Charges 46.1 Determination of Network Customer's Monthly Network Load 47 Operating Arrangements 47.1 Operation under The Network Operating Agreement 47.2 Network Operating Agreement 47.3 Network Operating Committee 48 Scope of Application of Part VI to Participants VII. TRANSMISSION PLANNING, ADDITIONS AND MODIFICATIONS 49 General 50 Interconnection Procedures and Requirements 50.1 Interconnection of Generating Unit Under the Minimum Interconnection Standard 50.2 Interconnection of Elective Transmission Upgrades 51 Regional Transmission Planning and Expansion 51.1 General 51.2 Responsibilities of the Transmission Expansion Advisory Committee, Transmission Planning Committee and System Operator 51.3 NEPOOL Transmission Plan: Principles, Scope, and Contents 51.4 Procedures for Developing a NEPOOL Transmission Plan 51.5 Procedures for the Conduct of Enhancement and Expansion Studies 51.6 Request for Proposals ("RFP") Process For Upgrades 51.7 Obligations of Transmission Owners to Build 51.8 Merchant Transmission Facilities; Compliance 51.9 Alternative Remedies 52 "Quick Fix" Measures SCHEDULE 1 Scheduling, System Control and Dispatch Service SCHEDULE 2 Reactive Supply and Voltage Control from Generation Sources Service SCHEDULE 3 Regulation and Frequency Response Service (Automatic Generation Control) SCHEDULE 4 Energy Imbalance Service SCHEDULE 5 Operating Reserve - 10-Minute Spinning Reserve Service SCHEDULE 6 Operating Reserve - 10-Minute Non-Spinning Reserve Service SCHEDULE 7 Operating Reserve - 30-Minute Reserve Service SCHEDULE 8 Through or Out Service - The Pool PTF Rate SCHEDULE 9 Regional Network Service SCHEDULE 10 Internal Point-to-Point Service SCHEDULE 11 Generator Interconnection Related Upgrade Costs SCHEDULE 12 Reliability Upgrade, Economic Upgrade and Elective Transmission Upgrade Costs SCHEDULE 13 Locational Prices; Congestion Cost; Congestion Revenue; Marginal Loss Cost; Marginal Loss Revenue A. Calculation of Locational Prices B. Congestion Cost C. Congestion Revenue D. Marginal Loss Cost and Marginal Loss Revenue E. Additional Rules and Procedures SCHEDULE 14 Financial Congestion Rights ("FCRs") A. FCR Holder Status and Transfer of FCRs B. FCR Designation and Simultaneous Feasibility C. FCR Payments D. FCR Settlements E. Congestion Revenue Shortfalls or Surpluses F. FCR Auctions G. FCRs as Options H. Additional Rules and Procedures SCHEDULE 15 Auction Revenue Rights A. First Stage of ARR Allocation B. Second Stage of ARR Allocation C. Third Stage of ARR Allocation D. Fourth Stage of ARR Allocation E. Payments to ARR Holders F. Annual and Monthly ARR Adjustments G. Incremental ARRs H Additional Rules and Procedures SCHEDULE 16 System Restoration and Planning Service from Generators ATTACHMENT A Form of Service Agreement for Through or Out Service or Internal Point-To-Point Service ATTACHMENT B Form Of Service Agreement For Regional Network Service ATTACHMENT C Methodology To Assess Available Transmission Capability ATTACHMENT D Methodology for Completing a System Impact Study ATTACHMENT E Local Networks ATTACHMENT F Annual Transmission Revenue Requirements ATTACHMENT G: List of Excepted Transaction Agreements ATTACHMENT G-1: List of Excepted Agreements ATTACHMENT G-2: List of Certain Arrangements over External Ties ATTACHMENT H Form of Network Operating Agreement ATTACHMENT I Form of System Impact Study Agreement ATTACHMENT J Form of Facilities Study Agreement ATTACHMENT K 1997 Twelve CP Network Load Data NEPOOL 1997 12 CP Network Load ATTACHMENT L Financial Assurance Policy for NEPOOL Members ATTACHMENT M Financial Assurance Policy for NEPOOL Non-Participant Transmission Customers ATTACHMENT N New England Power Pool Billing Policy IMPLEMENTATION RULE - SCHEDULE 1 Scheduling, System Control and Dispatch Service IMPLEMENTATION RULE - SCHEDULE 2 Reactive Supply and Voltage Control from Generation Sources Service IMPLEMENTATION RULE - ATTACHMENT F Annual Transmission Revenue Requirements I. COMMON SERVICE PROVISIONS 1 Definitions Whenever used in this Tariff, in either the singular or the plural number, the terms contained in this Section shall have the meanings set forth herein. If a term includes language in brackets ([ ]), such language shall become effective automatically on the CMS/MSS Effective Date. Certain definitions and language within definitions are included in braces ({ }). Such definitions and language 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 Tariff may remove brackets ([ ]), braces ({ }) and text included therein, and this explanatory introductory language, and may renumber the definitions, without further specific amendment to or restatement of this Tariff. Terms used in this Tariff that are not defined in this Tariff shall have the meanings customarily attributed to such terms by the electric utility industry in New England. 1.1 Administrative Costs: Those costs incurred in connection with the review of Applications for transmission service and the carrying out of System Impact Studies and Facilities Studies. 1.2 Agreement: The Restated New England Power Pool Agreement dated as of September 1, 1971, as amended and restated from time to time, of which this Tariff forms a part. 1.3 Ancillary Services: Those services that are necessary to support the transmission of electric capacity and energy from resources to loads while maintaining reliable operation of the NEPOOL Transmission System in accordance with Good Utility Practice. 1.4 Annual Transmission Revenue Requirements: The annual revenue requirements of a Participant's PTF or of all Participants' PTF for purposes of this Tariff shall be the amount determined in accordance with Attachment F to this Tariff. 1.5 Application: A written request by an Eligible Customer for transmission service pursuant to the provisions of this Tariff. 1.6 ARR: An Auction Revenue Right. 1.7 ARR Allocation: The allocation of ARRs described in Schedule 15. 1.8 Auction Revenue Right: The right to receive FCR Auction Revenues in accordance with Schedule 15 and Section 49 of the Tariff. 1.9 Auction Revenue Right Holder: An entity which is the record holder of an Auction Revenue Right in the register maintained by the System Operator. 1.10 Backyard Generation: Generation which interconnects directly with distribution facilities dedicated solely to load not designated as Network Load. Any distribution facilities which are shared with Network Load will not qualify. 1.11 Business Day: Any day other than a Saturday or Sunday or a national or Massachusetts holiday. 1.12 CMS: The Congestion management system under the NEPOOL arrangements, including Locational Prices for Energy and Financial Congestion Rights. 1.13 CMS/MSS Effective Date: The date on which the provisions of Section 14A of the Agreement shall become fully effective and supersede the provisions of Section 14 of the Agreement. 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. 1.14 Commission: The Federal Energy Regulatory Commission. 1.15 Completed Application: An Application that satisfies all of the information and other requirements of this Tariff, including any required deposit. 1.16 Compliance Effective Date: October 1, 1998. 1.17 Congestion: 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. 1.18 Congestion Component: 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. 1.19 Congestion Cost: 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. 1.20 Congestion Paying Entity: For the purpose of the allocation of FCR Auction Revenues to ARR Holders as provided for in Schedule 15, a Participant, other than a Transmission Customer, that is responsible for paying for both (i) the Congestion Cost associated with supplying Energy to serve load, and (ii) the RMR Charge for RMR Uplift (as defined in Section 14A.19 of the Agreement) associated with serving load. The term Congestion Paying Entity shall be deemed to include, but not be limited to, the Load Asset Contract purchaser. 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: 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 Congestion Revenue Shortfall: The amount, if any, by which Congestion Revenues collected by the System Operator in a month are less than the sum of the Target FCR Payments for that month. A Congestion Revenue Shortfall is managed in accordance with Schedule 14. 1.24 Congestion Revenue Surplus: The amount, if any, by which Congestion Revenues collected by the System Operator in a month exceed the sum of the Target FCR Payments for that month. A Congestion Revenue Surplus is managed in accordance with Schedule 14. 1.25 Control Area: An electric power system or combination of electric power systems to which a common automatic generation control scheme is applied in order to: (1) 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); (2) maintain scheduled interchange with other Control Areas, within the limits of Good Utility Practice; (3) maintain the frequency of the electric power system(s) within reasonable limits in accordance with Good Utility Practice and the criteria of the applicable regional reliability council or the North American Electric Reliability Council; and (4) provide sufficient generating capacity to maintain operating reserves in accordance with Good Utility Practice. 1.26 Curtailment: A reduction in firm or non-firm transmission service in response to a transmission capacity shortage as a result of system reliability conditions. 1.27 Day-Ahead: The calendar day immediately preceding a Dispatch Day for which Participants submit Demand Bids and Supply Offers in accordance with applicable NEPOOL System Rules and the System Operator schedules Resources for Energy, Operating Reserve, 4-Hour Reserve and AGC (as defined in the Agreement) in accordance with applicable NEPOOL System Rules. 1.28 Day-Ahead Market: The market provided for in Section 14A of the Agreement and conducted in the calendar day immediately preceding a Dispatch Day in which Energy, Operating Reserve, 4-Hour Reserve and AGC (as defined in the Agreement) are scheduled for a Dispatch Day, based on the Day-Ahead Demand Bids and Supply Offers and applicable NEPOOL System Rules. 1.29 Delivering Party: The entity supplying capacity and/or energy to be transmitted at Point(s) of Receipt under this Tariff. 1.30 Demand Bid: 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. 1.31 Demand Bid Price: The price specified by a Participant to the System Operator in a Demand Bid for Energy at a specified Location. 1.32 Designated Agent: Any entity that performs actions or functions required under the Tariff on behalf of NEPOOL, an Eligible Customer, or a Transmission Customer. 1.33 Direct Assignment Facilities: 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 this Tariff or a 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 or in accordance with the separate agreement and not under this Tariff. 1.34 Direct Interconnection Transmission Costs: Has the meaning specified in Section 2 of Schedule 11 of the Tariff. 1.35 Dispatch Day: The period beginning at the minute ending 0001 and ending at 2400 each day. 1.36 Distribution Company: Has the meaning specified in Section (A)(2) of Schedule 13. 1.37 Distribution Company Load Zone: Has the meaning specified in Section (A)(2) of Schedule 13. 1.38 Economic Upgrade: Those additions and upgrades that are not related to the interconnection of a generator, and are designed to reduce or eliminate Congestion Cost, where the net present values of the reduction in, or elimination of, Congestion Cost exceeds the net present value of the cost of the transmission addition or upgrade. 1.39 Elective Transmission Upgrade: An addition to or modification of the NEPOOL Transmission System that is not: (i) a Generator Interconnection Related Upgrade; (ii) a Reliability Upgrade (including a NEMA Upgrade, as appropriate); (iii) an Economic Upgrade (including a NEMA Upgrade, as appropriate); (iv) a Quick Fix Upgrade; or (v) initially proposed in an Elective Transmission Upgrade Application filed with the System Operator in accordance with Section 50.2 on a date after the addition or modification already has been otherwise identified in the current NEPOOL Transmission Plan (other than as an Elective Transmission Upgrade) in publication as of the date of that application. An Elective Transmission Upgrade may increase transfer capability of the NEPOOL Transmission System, may increase the reliability or stability of the NEPOOL Transmission System above the requirements and criteria established by NERC, NPCC or the NEPOOL Reliability Committee, or may reduce Congestion Costs into Load Zones or at Nodes into or within the NEPOOL Control Area. 1.40 Eligible Customer: (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. 1.41 Energy: Is electrical energy measured in kilowatthours or megawatthours. 1.42 Energy Imbalance Service: This service is the form of Ancillary Service described in Schedule 4. 1.43 Entitlement: An Installed Capability Entitlement, Energy Entitlement, Operating Reserve Entitlement[, 4-Hour Reserve Entitlement], or AGC Entitlement, in each case as defined in the Agreement. When used in the plural form, it may be any or all such Entitlements or combinations thereof, as the context requires. 1.44 Excepted Transaction: A transaction specified in Section 25 for the applicable period specified in that Section, or in Sections 25A and 25B. 1.45 External Node: 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. 1.46 Facilities Study: An engineering study conducted pursuant to the Agreement or this 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. 1.47 FCR: A Financial Congestion Right. 1.48 FCR Auction: The periodic auction of FCRs conducted by the System Operator or another authorized agent of the NEPOOL Participants in accordance with Schedule 14. 1.49: The revenue collected from the sale of FCRs in FCR Auctions. FCR Auction Revenue is payable to FCR Holders who submit their FCRs for sale in the FCR Auction in accordance with Schedule 14 and to ARR Holders in accordance with Schedule 15. 1.50 FCR Auction Revenue Fund: The fund containing the FCR Auction Revenue. 1.51 FCR Holder: An entity that acquires an FCR through the FCR Auction or a subsequent bilateral arrangement pursuant to Schedule 14 of the Tariff and registers with the System Operator as the holder of the FCR in accordance with Schedule 14 of the Tariff and applicable NEPOOL System Rules. 1.52 FCR Payment: The payment made either from the Congestion Revenue Fund to an FCR Holder or to the Congestion Revenue Fund by an FCR Holder in accordance with Schedule 14 of the Tariff and applicable NEPOOL System Rules. 1.53 Financial Congestion Right: A financial instrument that evidences the rights and obligations specified in Schedule 14 of the Tariff. 1.54 Firm Contract: 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 (as defined in the Agreement) 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 make deliveries thereunder as the result of events beyond the supplier's reasonable control. 1.55 Firm Point-To-Point Transmission Service: Point-To-Point Transmission Service which is reserved and/or scheduled between specified Points of Receipt and Delivery in accordance with the applicable procedure specified in Part V of this Tariff. 1.56 Firm Transmission Service: Service for Native Load Customers, firm Regional Network Service (Network Integration Transmission Service), service for Excepted Transactions, Firm Internal Point-To-Point Transmission Service, or Firm Through or Out Service. 1.57 Generator Interconnection Related Upgrade: An addition to or modification of the NEPOOL Transmission System pursuant to Section 50.1 to effect the interconnection of a new generating unit or an existing generating unit whose capacity is being materially changed and increased, whether or not the interconnection is being effected to meet the Minimum Interconnection Standard. As to Category A Projects (as defined in Schedule 11), a Generator Interconnection Related Upgrade also includes an upgrade beyond that required to satisfy the Minimum Interconnection Standard for which the Generator Owner has committed to pay prior to October 29, 1998. 1.58 Generator Owner: Any Participant or Non-Participant that owns, in whole or part, a generating unit whether located within or outside the NEPOOL Control Area. As used in Section 50 and Schedules 11 and 12 of this Tariff, Generator Owner also includes any Participant or Non-Participant that proposes to site a new generating unit at a site owned or controlled by it, or which it has the right to acquire or control, located in the NEPOOL Control Area. 1.59 Good Utility Practice: 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 judgment 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. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather includes all acceptable practices, methods, or acts generally accepted in the region. 1.60 Hub: 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 Energy Settlement Obligations and for the designation of FCRs in accordance with Schedule 14. 1.61 Hub Price: In each hour of the Dispatch Day in the Day-Ahead Market and the Real-Time Market is the price used for 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. 1.62 HQ Interconnection: 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. 1.63 HQ Phase II Firm Energy Contract: 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. 1.64 Import Transaction: An energy delivery originating outside the NEPOOL Control Area that uses the PTF to deliver energy to Network Load within the NEPOOL Control Area, except for a delivery that uses a direct interconnection between the NEPOOL Control Area and the Hydro-Quebec transmission system that existed as of January 1, 2000. 1.65 Interchange Transactions: Are transactions deemed to be effected under Section 14 of the Agreement prior to the CMS/MSS Effective Date, and under Section 14A on and after the CMS/MSS Effective Date. 1.66 Interest: Interest calculated in the manner specified in Section 8.3. 1.67 Internal Point-to-Point Service: (1) Until the CMS/MSS Effective Date, Point-to-Point Transmission Service with respect to a transaction where the Point of Receipt is at the boundary of or within the NEPOOL Transmission System and the Point of Delivery is within the NEPOOL Transmission System. (2) On and after the CMS/MSS Effective Date, Internal Point-to-Point Service is Point-to-Point Transmission Service with respect to a transaction where the Point of Receipt is within the NEPOOL Transmission System and the Point of Delivery is within the NEPOOL Transmission System. 1.68 Internal Point-to-Point Service Rate: The rate applicable to Internal Point-to-Point Service, which shall be equal for each delivery to the Participant RNS Rate per Kilowatt for the current Year for the Participant which owns the Local Network from which the Customer's load is served. 1.69 Interruption: A reduction in non-firm transmission service due to economic reasons pursuant to Section 28.7. 1.70 ISO: 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 this Tariff, subject to regulation by the Commission. 1.71 Load Asset Contract: 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. 1.72 Load Ratio Share: Ratio of a Transmission Customer's most recently reported Monthly Network Load in the case of Network Customers and including where applicable Point-to-Point Customers' Reserved Capacity, to the total load of Network Customers and Point-to-Point customers, computed in accordance with Part VI of the Tariff. 1.73 Load Shedding: The systematic reduction of system demand by temporarily decreasing load in response to transmission system or area capacity shortages, system instability, or for voltage control considerations under Part VI of the Tariff. 1.74 Load Zone: A Reliability Region, except as otherwise provided in Section 14A.12(b) of the Agreement and Schedule 13 of the Tariff. 1.75 Local Network: The transmission facilities constituting a local network identified on Attachment E, and any other local network or change in the designation of a Local Network as a Local Network which the Management Committee may designate or approve from time to time. The Management Committee may not unreasonably withhold approval of a request by a Participant that it effect such a change or designation. 1.76 Local Network Service: 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. 1.77 Local Point-To-Point Service: Local Point-To-Point service is Point- to-Point Transmission Service provided, under a separate tariff or contract, by a Participant that is a Transmission Provider over Non-PTF or distribution facilities to permit deliveries to or from an interconnection point on the NEPOOL Transmission System. 1.78 Location: A Node, External Node, Load Zone, or Hub. 1.79 Locational Price: 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. 1.80 Long-Term Firm Service: Firm Transmission Service with a term of one year or more. 1.81 Marginal Loss: 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. 1.82 Marginal Loss Component: 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. 1.83 Marginal Loss Revenue: For each hour is the surplus revenue, if any, after netting the revenues paid and collected for the Marginal Loss Components of Locational Prices for all Energy transactions on the NEPOOL Transmission System, including Energy deliveries by Non-Participant Transmission Customers taking service under this Tariff, as settled in accordance with the Market Rules. 1.84 Marginal Loss Revenue Fund: 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. 1.85 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. 1.85A Merchant Transmission Facility: Has the meaning specified in Section 51.8. 1.86 Minimum Interconnection Standard: Has the meaning specified in Section 50.1. 1.87 Monthly Network Load: Has the meaning specified in Section 46.1. 1.88 Monthly Peak: Has the meaning specified in Section 46.1. 1.89 Monthly Peak Load: For purposes of Schedule 15, the Monthly Peak Load of the Transmission Customer is the Transmission Customer's Monthly Peak less any portion of such Monthly Peak served by a Congestion Paying Entity. For purposes of Schedule 15, the Monthly Peak Load of a Congestion Paying Entity includes the portion of any Transmission Customer's Monthly Peak served by the Congestion Paying Entity. 1.90 Native Load Customers: The wholesale and retail power customers of a Participant or other entity which is a Transmission Provider on whose behalf the Participant or other entity, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate its system to meet the reliable electric needs of such customers. 1.91 NEMA: The Northeast Massachusetts Reliability Region. 1.92 NEMA ARRs: The ARRs allocated in accordance with Schedule 15 to certain entities serving load in NEMA. 1.93 NEMA Contract: A contract described in Section C of Schedule 15 and listed in Attachment 1 to Schedule 15. 1.94 NEMA LSE: A NEMA LSE is a Transmission Customer or Congestion Paying Entity that serves load within NEMA. 1.95 NEMA or "Northeast Massachusetts" Upgrade: Is an addition to or modification of the NEPOOL Transmission System into or within the Northeast Massachusetts Reliability Region that is not, as of December 31, 1999, the subject of a System Impact Study or application filed pursuant to Section 18.4 of the Restated NEPOOL Agreement; that is not related to generation interconnections; and that will be completed and placed in service by June 30, 2004. Such upgrades include, but are not limited to, new transmission facilities and related equipment and/or modifications to existing transmission facilities and related equipment. 1.96 NEPOOL: The New England Power Pool, the power pool created under and governed by the Agreement, and the entities collectively participating in the New England Power Pool. 1.97 NEPOOL Control Area: The Control Area (as defined in Section 1.25) for NEPOOL. 1.98 NEPOOL System Rules: 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. 1.99 NEPOOL Transmission Plan: A five-year plan for the expansion or modification of the NEPOOL Transmission System which has been developed pursuant to Section 51. 1.100 NEPOOL Transmission System: The PTF transmission facilities. 1.101 NERC: The North American Electric Reliability Council. 1.102 Network Customer: A Participant or Non-Participant receiving transmission service pursuant to the terms of the Network Integration Transmission Service under Part II and Part VI of the Tariff. 1.103 Network Integration Transmission Service: Regional Network Service, which may be used with respect to Network Resources or Network Load not physically interconnected with the NEPOOL Transmission System. 1.104 Network Load: The load that a Network Customer designates for Network Integration Transmission Service under Part II and Part VI of the Tariff. The Network Customer's Network Load shall include all load designated by the Network Customer (including losses) and shall not be credited or reduced for any behind-the-meter generation. A Network Customer may elect to designate less than its total load as Network Load but may not designate only part of the load at a discrete Point of Delivery. Where an Eligible Customer has elected not to designate a particular load at discrete Points of Delivery as Network Load, the Eligible Customer is responsible for making separate arrangements under Part III and Part V of the Tariff for any Point-to-Point Transmission Service that may be necessary for such non-designated load. 1.105 Network Operating Agreement: An executed agreement in the form of Attachment H, or any other form that is mutually agreed to, that contains the terms and conditions under which the Network Customer shall operate its facilities and the technical and operational matters associated with the implementation of Network Integration Transmission Service under Part II and Part VI of this Tariff. The Agreement and the rules adopted thereunder shall constitute the Network Operating Agreement for Participants. 1.106 Network Operating Committee: A group made up of representatives from the Network Customer(s) and the System Operator established to coordinate operating criteria and other technical considerations required for implementation of Network Integration Transmission Service under Part II and Part VI of this Tariff. The Network Operating Committee for Network Customers that are Participants shall be the NEPOOL Regional Transmission Operations Committee and the NEPOOL Regional Transmission Planning Committee, meeting jointly in a meeting designated as the annual Network Operating Committee meeting. Notice of each meeting of the Committee pursuant to Section 47.3 shall be given to each Non-Participant receiving Regional Network Service under this Tariff and the Non-Participant shall have the right to be represented at each of such meetings. 1.107 Network Resource: (a) With respect to Participants, (i) any generating resource located in the NEPOOL Control Area which has been placed in service prior to the Compliance Effective Date (including a unit that has lost its capacity value when its capacity value is restored and a deactivated unit which may be reactivated without satisfying the requirements of Section 49 of this Tariff in accordance with the provisions thereof) until retired; (ii) any generating resource located in the NEPOOL Control Area which is placed in service after the Compliance Effective Date until retired, provided that (1) the Generator Owner has complied with the requirements of Section 49 of the Tariff, and (2) the output of the unit shall be limited in accordance with Section 49, if required; and (iii) any generating resource or combination of resources (including bilateral purchases) located outside the NEPOOL Control Area for so long as any Participant has an Entitlement in the resource or resources which is being delivered to it in the NEPOOL Control Area to serve Network Load located in the NEPOOL Control Area or other designated Network Loads contemplated by Section 43.3 of this Tariff taking Regional Network Service. (b) With respect to Non-Participant Network Customers, any generating resource owned, purchased or leased by the Network Customer which it designates to serve Network Load. 1.108 Network Upgrades: Modifications or additions to transmission-related facilities that are integrated with and support the overall NEPOOL Transmission System for the general benefit of all users of such Transmission System. 1.109 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. 1.110 Node: A point on the NEPOOL Transmission System where Energy is received or furnished, and for which Nodal Prices are calculated. 1.111 Non-Firm Point-To-Point Transmission Service: Point-To-Point Transmission Service under this Tariff that is subject to Curtailment or Interruption under the circumstances specified in Section 28.7 of this Tariff. 1.112 Non-Participant: Any entity that is not a Participant. 1.113 Non-PTF: The transmission facilities owned by the Participants that do not constitute PTF. 1.114 Northeast Massachusetts Upgrade: Has the meaning specified in Schedule 12. 1.115 NPCC: The Northeast Power Coordinating Council. 1.116 Open Access Same-Time Information System (OASIS): The NEPOOL information system and standards of conduct responding to requirements of 18 C.F.R. 37 of the Commission's regulations and all additional requirements implemented by subsequent Commission orders dealing with OASIS. 1.117 Operating Reserve - 10-Minute Non-Spinning Reserve Service: This service is the form of Ancillary Service described in Schedule 6. 1.118 Operating Reserve - 10-Minute Spinning Reserve Service: This service is the form of Ancillary Service described in Schedule 5. 1.119 Operating Reserve - 30-Minute Reserve Service: This service is the form of Ancillary Service described in Schedule 7. 1.120 Participant: A participant in NEPOOL under the Agreement. 1.121 Participant RNS Rate: The rate applicable to Regional Network Service to effect a delivery to load in a particular Local Network, as determined in accordance with Schedule 9 to this Tariff. 1.122 Participants Committee: The committee whose responsibilities are specified in Section 7 of the Agreement. To the extent applicable, references in the Tariff to the Participants Committee shall include the prior Management Committee or Executive Committee as the predecessor of the Participants Committee if not inconsistent with Section 17A of the Agreement. 1.123 Point(s) of Delivery: Point(s) where capacity and/or energy transmitted by the Participants will be made available to the Receiving Party under this Tariff. Until the CMS/MSS Effective Date, but not thereafter, the Point of Delivery may be designated as the NEPOOL power exchange. The Point(s) of Delivery shall be specified in the Service Agreement, if applicable, for Long-Term Firm Point-to-Point Transmission Service. 1.124 Point(s) of Receipt: Point(s) of interconnection where capacity and/or energy to be transmitted by the Participants will be made available to NEPOOL by the Delivering Party under this Tariff. Until the CMS/MSS Effective Date, but not thereafter, the Point of Receipt may be designated as the NEPOOL power exchange in circumstances where the System Operator does not require greater specificity. The Point(s) of Receipt shall be specified in the Service Agreement, if applicable, for Long-Term Firm Point-To-Point Transmission Service. 1.125 Point-To-Point Transmission Service: The transmission of capacity and/or energy on either a firm or non-firm basis from the Point(s) of Receipt to the Point(s) of Delivery under this Tariff. NEPOOL Point-to-Point Transmission Service includes both Internal Point-to-Point Service and Through or Out Service. 1.126 Pool-Planned Unit: 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). 1.127 Pool PTF Rate: The transmission rate determined in accordance with Schedule 8 to this Tariff. 1.128 Pool RNS Rate: The transmission rate determined in accordance with paragraph (2) of Schedule 9 to this Tariff. 1.129 Pool-Supported PTF: (i) PTF first placed in service prior to January 1, 2000; (ii) Generator Interconnection Related Upgrades with respect to Category A and B Projects (as defined in Schedule 11), but only to the extent not paid for by the interconnecting Generator Owner; (iii) Quick Fix Upgrades, in accordance with Section 52; and (iv) other PTF upgrades, but only to the extent the costs therefor are determined to be Pool-Supported PTF in accordance with Schedule 12. 1.130 Power Purchaser: The entity that is purchasing the capacity and/or energy to be transmitted under the Tariff. 1.131 Prior NEPOOL Agreement: The NEPOOL Agreement as in effect on December 1, 1996. 1.132 PTF or Pool Transmission Facilities: (i) The transmission facilities owned by the Participants and their Related Persons which constitute PTF pursuant to the Agreement, and (ii) the static VAR compensator installed at Chester, Maine at the request of the Participants. 1.133 Pre-1997 PTF Rate: The transmission rate of a Participant determined in accordance with paragraph (5) of Schedule 9 to this Tariff. 1.134 Publicly Owned Entity: 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. 1.135 Quick Fix Upgrade: Has the meaning specified in Section 52. 1.136 Reactive Supply and Voltage Control From Generation Sources Service: This service is the form of Ancillary Service described in Schedule 2. 1.137 Real-Time: 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. 1.138 Real-Time Market: The market provided for in Section 14A of the Agreement 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. 1.139 Receiving Party: The entity receiving the capacity and/or energy transmitted to Point(s) of Delivery under this Tariff. 1.140 Reference Node: 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. 1.141 Regional Network Service: The transmission service described in Part II and Part VI of this Tariff. 1.142 Regulation and Frequency Response Service: This service is the form of Ancillary Service described in Schedule 3. 1.143 Reliability Region: 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 NEPOOL 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. 1.144 Reliability Upgrade: Those additions and upgrades not required by the interconnection of a generator that are nonetheless necessary to ensure the continued reliability of the NEPOOL system, taking into account load growth and known resource changes, and include those upgrades necessary to provide acceptable stability response, short circuit capability and system voltage levels, and those facilities required to provide adequate thermal capability and local voltage levels that cannot otherwise be achieved with reasonable assumptions for certain amounts of generation being unavailable (due to maintenance or forced outages) for purposes of long-term planning studies. Good Utility Practice, applicable reliability principles, guidelines, criteria, rules, procedures and standards of NERC and NPCC and any of their successors, applicable publicly available local reliability criteria, and the NEPOOL System Rules, as they may be amended from time to time, will be used to define the system facilities required to maintain reliability in evaluating proposed Reliability Upgrades. 1.145 Reserved Capacity: The maximum amount of capacity and energy that is committed to the Transmission Customer for transmission over the NEPOOL Transmission System between the Point(s) of Receipt and the Point(s) of Delivery under Part V of this Tariff. Reserved Capacity shall be expressed in terms of whole kilowatts on a sixty-minute interval (commencing on the clock hour) basis. 1.146 Scheduling, System Control and Dispatch Service: This service is the form of Ancillary Service described in Schedule 1. 1.147 Second Effective Date: May 1, 1999. 1.148 Service Agreement: The initial agreement and any amendments or supplements thereto entered into by the Transmission Customer and the System Operator for service under this Tariff. 1.149 Service Commencement Date: The date service is to begin pursuant to the terms of an executed Service Agreement, or the date service begins in accordance with Section 29.3 or Section 41.1 under this Tariff, or in the case of Regional Network Service which is not required to be furnished under a Service Agreement pursuant to Section 48 of this Tariff, the date service actually commences. 1.150 Settlement Obligation Prior to the CMS/MSS Effective Date, an obligation as defined in Section 14.1(a) of the Agreement for Energy, Section 14.1(b) of the Agreement for Operating Reserve and Section 14.1(c) of the Agreement for AGC, and all applicable Market Rules and, on and after the CMS/MSS Effective Date, an obligation as defined in Section 14A.1(b) of the Agreement for Energy, Section 14A.1(c) of the Agreement for Operating Reserve, Section 14A.1(d) of the Agreement for 4-Hour Reserve and Section 14A.1(e) of the Agreement for AGC, and all applicable Market Rules. 1.151 Shift Factor: 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. 1.152 Short-Term Firm Service: Firm Transmission Service with a term of less than one year. 1.153 Standard Offer Obligation: Has the meaning specified in Section 14A.12(b)(ii) of the Agreement and Schedule 13 of the Tariff. 1.154 Supply Obligation: Is an obligation as defined in Section 14A.1(a) of the Agreement for Energy, Operating Reserve, 4-Hour Reserve, and/or AGC. 1.155 Supply Offer: A proposal to furnish Energy at a Node or External Node, Operating Reserve, 4-Hour Reserve and/or AGC (as defined in the Agreement) 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 price for the Supply Offer and information with respect to the quantity proposed to be furnished, technical parameters for the Resource, timing and other matters. 1.156 System Contract: Any Contract for the purchase of Installed Capability, Energy [at a Location], Operating Reserves[, 4-Hour Reserves] and/or AGC (as defined in the Agreement), 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. 1.157 System Impact Study: An assessment pursuant to Part V, VI or VII of this 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. 1.158 System Operator: The central dispatching agency provided for in the Agreement which has responsibility for the operation of the NEPOOL Control Area from the control center and the administration of this Tariff. The System Operator is the ISO. 1.159 Target FCR Payment: The amount of an FCR Payment that an FCR Holder is entitled to in the absence of a Congestion Revenue Shortfall when the Congestion Component of the Locational Price at the Location and/or Reliability Region of a given FCR's Point of Delivery is higher than the Congestion Component of the Locational Price at the Location and/or Reliability Region of the given FCR's Point of Receipt. Target FCR Payments are calculated and Congestion Revenue Shortfalls are managed in accordance with Schedule 14. 1.160 Tariff: This NEPOOL Open Access Transmission Tariff and accompanying schedules and attachments, as modified and amended from time to time. 1.161 Third-Party Sale: Any sale for resale in interstate commerce to a Power Purchaser that is not designated as part of Network Load under the Regional Network Service. 1.162 Through or Out Service: Point-to-Point Transmission Service provided by NEPOOL with respect to a transaction which requires the use of PTF and which goes through the NEPOOL Control Area, as, for example, from the Maine Electric Power Company line or New Brunswick to New York, or from one point on the NEPOOL Control Area boundary with New York to another point on the Control Area boundary with New York, or with respect to a transaction which goes out of the NEPOOL Control Area from a point in the NEPOOL Control Area, as, for example, from Boston to New York. 1.163 Third Effective Date: 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 Management 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 Management Committee. 1.164 Ties: (i) The PTF lines and facilities which connect the NEPOOL Transmission System to the transmission line owned by Maine Electric Power Company, which is in turn connected to the transmission system in New Brunswick, (ii) the PTF lines and facilities which connect the NEPOOL Transmission System to the transmission system in New York and (iii) any new PTF lines and facilities which connect the NEPOOL Transmission System to the transmission system in another Control Area. 1.165 Transition Period: The six-year period commencing on March 1, 1997. 1.166 Transmission Customer: 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 this 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 this Tariff. This term is used in Part I to include customers receiving transmission service under this Tariff. 1.167 Transmission Owner: A Transmission Provider that 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 and includes 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 (1) own, or lease with rights equivalent to ownership, PTF with an original capital investment in its PTF of at least $30,000,000, and (2) provide transmission service to non- affiliated customers pursuant to an open access transmission tariff on file with the Commission. 1.168 Transmission Owners Committee: The committee established pursuant to Section 11B of the Agreement. 1.169 Transmission Provider: 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. 1.170 Transmission System Upgrade: Has the meaning specified in Section 51. 1.171 Unit Contract: 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 capacity of a specific electric generating unit or units, or (ii) to a specifically determined or determinable amount of Installed Capability, Energy, Operating Reserves and/or AGC (as defined in the Agreement) if, or to the extent that, a specific electric generating unit or units is or can be operated. 1.172 Use: For a Transmission Customer which has exercised its option to take Internal Point-to-Point Service to serve all or a portion of its load at any Point of Delivery, the greater for the hour of (i) the maximum amount of Energy that it will receive in any hour, as determined from meters and adjusted for losses, plus, in the case of a Participant, the maximum amount of Operating Reserve assigned to the Participant by the System Operator in any hour during the month, at that Point of Delivery from the resources covered by its Completed Applications and from Interchange Transactions, or (ii) the portion of its Installed Capability Responsibility which must be satisfied with the resources covered by its Completed Applications and from Interchange Transactions. Use shall be expressed in terms of whole Kilowatts on a sixty-minute interval (commencing on the clock hour) basis. 1.173 Withdrawal Factor: 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. 1.174 Year: A period of 365 or 366 days, whichever is appropriate, commencing on, or on the anniversary of March 1, 1997. Year One is the Year commencing on March 1, 1997, and Years Two and higher follow it in sequence. 1.175 Zonal Price: In each hour of the Dispatch Day in the Day-Ahead Market and the Real-Time Market, 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. 3 Purpose of This Tariff This Tariff, together with the transmission provisions in Part Four of the Agreement, is intended to provide a regional arrangement which will cover new uses of the NEPOOL Transmission System. The arrangement is designed and shall be operated in such a manner as to encourage and promote competition in the electric market to the benefit of ultimate users of electric energy. New uses of transmission facilities which require the use of a single Participant Local Network will continue to be provided in part under that Participant's filed tariff. Any new regional use of the NEPOOL Transmission System must be obtained from NEPOOL pursuant to this Tariff and not from individual Participants. Ancillary Services will be supplied in accordance with Section 4 of this Tariff. A five-year transitional arrangement, which is described in Part IV of this Tariff, and continuing service for Excepted Transactions, have been negotiated to phase in the financial impacts of the change from the historic regime in which uses of the NEPOOL Transmission System had to be obtained and paid for under the individual tariffs of the Participants to a regime in which the service will be obtained from the Participants through NEPOOL at a rate which will not vary with distance. This Tariff is intended to provide for comparable, non-discriminatory treatment of all similarly situated Transmission Providers and all Participants and Non-Participants that are transmission users, and it shall be construed in the manner which best achieves this objective. This Tariff, and the provisions of Part Four of the Agreement, provide for a two-tier transmission arrangement integrating regional service which is provided under this Tariff, and local service which is provided under the Participants' individual system tariffs. This Tariff is also intended to provide a system of Congestion management. 4 Initial Allocation and Renewal Procedures 4.1 Initial Allocation of Available Transmission Capability: For purposes of determining whether existing capability on the NEPOOL Transmission System is adequate to accommodate a request for new Through or Out Service under Part V of this Tariff, all Completed Applications for new service received during the initial sixty-day period of the Transition Period will be deemed to have been filed simultaneously. A lottery system conducted by an independent accounting firm shall be used to assign priorities for Completed Applications filed simultaneously. All Completed Applications for Through or Out Service received after the initial sixty-day period shall be assigned a priority pursuant to Section 27.2. 4.2 Reservation Priority for Existing Firm Service Customers: Existing firm service customers receiving service with respect to Excepted Transactions and any other existing firm service customers of the Participants (wholesale requirements customers and transmission-only customers) with a contract term of one year or more have the right to continue to take transmission service at the same or a reduced level under this Tariff at the time when the existing contract terminates during or after the Transition Period. This transmission reservation priority is independent of whether the existing customer continues to purchase capacity and energy from its existing supplier or elects to purchase capacity and energy from another supplier. If, at the end of the contract term, the NEPOOL Transmission System cannot accommodate all of the requests for transmission service, the existing firm service customer must agree to accept a contract term at least equal to a competing request by any new Eligible Customer and to pay the current just and reasonable rate, filed with the Commission, for such service. This transmission reservation priority for existing firm service customers is an ongoing right that may be exercised as to any firm contract with a term of one year or longer by filing an Application in accordance with this Tariff at least sixty days in advance of the first day of the calendar month in which the existing contract term is to terminate. 4.3 Initial Election of Optional Internal Point-to-Point Service: Participants and Non-Participants receiving Regional Network Service under the Tariff on the Compliance Effective Date shall have sixty days to make an initial election to receive Internal Point-to-Point Service in lieu of, in whole or part, Regional Network Service. The election shall take effect as to such service at the end of such sixty-day period and shall be made by delivering an application to the System Operator, together with a deposit, if required, pursuant to Part V of this Tariff. Participants and Non-Participants receiving Regional Network Service which do not make such an initial election within such sixty-day period shall continue to receive Regional Network Service, subject to their right to elect at any time later to receive Internal Point-to-Point Service. 5 Ancillary Services Ancillary Services are needed with transmission service to maintain reliability within the NEPOOL Control Area. The Participants are required to provide through NEPOOL, and the Transmission Customer is required to purchase from NEPOOL, Scheduling, System Control and Dispatch Service, and Reactive Supply and Voltage Control from Generation Sources Service. The Participants offer to provide or arrange for, through NEPOOL, the following Ancillary Services, but only to a Transmission Customer serving load within the NEPOOL Control Area (i) Regulation and Frequency Response (Automatic Generator Control), (ii) Energy Imbalance, (iii) Operating Reserve - 10-Minute Spinning, (iv) Operating Reserve - 10-Minute Non-Spinning and (v) Operating Reserve - 30-Minute. A Participant or other Transmission Customer serving load within the NEPOOL Control Area is required to provide these Ancillary Services, whether from the System Operator, from a third party, or by self- supply. A Transmission Customer may not decline NEPOOL's offer of these Ancillary Services unless the Transmission Customer demonstrates to the System Operator that the Transmission Customer has acquired Ancillary Services of equal quality from another source. The Transmission Customer that is not a Participant must list in its Application which Ancillary Services it will purchase through NEPOOL. In the event of an unauthorized use of any Ancillary Service by the Transmission Customer, the Transmission Customer will be required to pay 200% of the charge which would otherwise be applicable. The specific Ancillary Services, prices and/or compensation methods are described on the Schedules that are attached to and made a part of this Tariff. Three principal requirements apply to discounts for Ancillary Services provided by NEPOOL in conjunction with its provision of transmission service as follows: (1) any offer of a discount made by NEPOOL must be announced to all Eligible Customers solely by posting on the OASIS, (2) any customer-initiated requests for discounts (including requests for use by one's wholesale merchant or an affiliate's use) must occur solely by posting on the OASIS, and (3) once a discount is negotiated, details must be immediately posted on the OASIS. A discount agreed upon for an Ancillary Service must be offered for the same period to all Eligible Customers on the NEPOOL Transmission System. Sections 4.1 through 4.7 below list the seven Ancillary Services. 5.1 Scheduling, System Control and Dispatch Service: The rates and/or methodology are described in Schedule 1. 5.2 Reactive Supply and Voltage Control from Generation Sources Service: The rates and/or methodology are described in Schedule 2. 5.3 Regulation and Frequency Response Service: Where applicable, the rates and/or methodology are described in Schedule 3. 5.4 Energy Imbalance Service: Where applicable, the rates and/or methodology are described in Schedule 4. 5.5 Operating Reserve - 10-Minute Spinning Reserve Service: Where applicable, the rates and/or methodology for this service are described in Schedule 5. 5.6 Operating Reserve - 10-Minute Non-Spinning Reserve Service: Where applicable, the rates and/or methodology for this service are described in Schedule 6. 5.7 Operating Reserve - 30-Minute Reserve Service: Where applicable, the rates and/or methodology for this service are described in Schedule 7. 5.8 System Restoration and Planning Service: Where applicable, the rates and/or methodology for this service are described in Schedule 16. 6 Open Access Same-Time Information System (OASIS) Terms and conditions regarding the NEPOOL Open Access Same-Time Information System and standards of conduct are set forth in 18 C.F.R. 37 of the Commission's regulations (Open Access Same-Time Information System and Standards of Conduct for Public Utilities). In the event available transmission capability, as posted on OASIS, is insufficient to accommodate a request for firm transmission service, additional studies may be required as provided by this Tariff pursuant to Sections 33 and 44. 7 Local Furnishing and Other Tax-Exempt Bonds 7.1 Participants That Own Facilities Financed by Local Furnishing or Other Tax-Exempt Bonds: This provision is applicable only to Participants that have financed facilities for the local furnishing of electric energy with tax-exempt bonds, as described in Section 142(f) of the Internal Revenue Code ("local furnishing bonds") or other tax-exempt bonds, as described in Section 103(b) of the Internal Revenue Code ("other tax-exempt bonds"). Notwithstanding any other provision of this Tariff, a Participant shall not be required to provide service to any Eligible Customer pursuant to this Tariff if the provision of such transmission service would jeopardize the tax-exempt status of any local furnishing bond(s) or other tax-exempt bonds used to finance the Participant's facilities that would be used in providing such Transmission Service. 7.2 Alternative Procedures for Requesting Transmission Service - Local Furnishing Bonds: (i) If a Participant determines that the provision of transmission service to be provided under this Tariff would jeopardize the tax-exempt status of any local furnishing bond(s) used to finance the Participant's facilities that would be used in providing such transmission service, the Management Committee shall be advised within thirty days of receipt of a Completed Application by an Eligible Customer requesting such service, or the date on which this Tariff becomes effective, whichever is applicable. (ii) If an Eligible Customer thereafter renews its request for the same transmission service referred to in (i) by tendering an application under Section 211 of the Federal Power Act, or the Management Committee tenders such an application requesting that service be provided under this Tariff, the Participant, within ten days of receiving a copy of the Section 211 application, will waive its rights to receive a request for service under Section 213(a) of the Federal Power Act and to the issuance of a proposed order under Section 212(c) of the Federal Power Act. The Commission, upon receipt of the Transmission Provider's waiver of its rights to a request for service under Section 213(a) of the Federal Power Act and to the issuance of a proposed order under Section 212(c) of the Federal Power Act, shall issue an order under Section 211 of the Federal Power Act. Upon issuance of the order under Section 211 of the Federal Power Act, the Transmission Provider shall be required to provide the requested transmission service in accordance with the terms and conditions of this Tariff. 7.3 Alternative Procedures for Requesting Transmission Service - Other Tax- Exempt Bonds: If a Participant determines that the provision of transmission service to be provided under the Tariff would jeopardize the tax-exempt status of any other tax-exempt bonds used to finance the Participant's facilities that would be used in furnishing such transmission service, it shall notify the Management Committee within thirty days of the date on which this Tariff becomes effective, and shall elect in its notice either to comply with the procedure specified in Section 6.2(ii) or to make its facilities unavailable under the Tariff and thereby waive its right to share in the distribution of revenues received under the Tariff derived from such facilities. Any such election may be changed at any time. 8 Reciprocity A Transmission Customer receiving transmission service under this Tariff, whether a Participant or a Non-Participant, agrees to provide comparable transmission service that it is capable of providing to the Participants on similar terms and conditions over facilities used for the transmission of electric energy in Canada or used for such transmission in the United States and that are owned, controlled or operated by, or on behalf of the Transmission Customer and over facilities used for the transmission of electric energy owned, controlled or operated by the Transmission Customer's corporate affiliates. Transmission of power on the Transmission Customer's system to the border of the NEPOOL Control Area and transfer of ownership at that point shall not satisfy, or relieve the Transmission Customer of, the obligation to provide reciprocal service. This reciprocity requirement applies not only to the Transmission Customer that obtains transmission service under the Tariff, but also to all parties to a transaction that involves the use of transmission service under the Tariff, including the power seller, buyer and any intermediary, such as a power marketer. This reciprocity requirement also applies to any Eligible Customer that owns, controls or operates transmission facilities that uses an intermediary, such as a power marketer, to request transmission service under the Tariff. If the Transmission Customer does not own, control or operate transmission facilities, the Transmission Customer must include in its Application a sworn statement of one of its duly authorized officers or other representatives that the purpose of its Application is not to assist an Eligible Customer to avoid the requirements of this provision. 9 Billing and Payment; Accounting 9.1 Participant Billing Procedure: Billings to Transmission Customers shall be made in accordance with this Section 8 and the NEPOOL Billing Policy set forth in Attachment N hereto, as such Billing Policy with respect to Participants may be amended, modified or supplemented by other billing procedures established pursuant to the Agreement. 9.2 Non-Participant Billing Procedure: Within a reasonable time after the first day of each month, the System Operator will submit on behalf of the Participants an invoice to each Non-Participant Transmission Customer for the charges for all services furnished under this Tariff during the preceding month. The invoice shall be paid by the Non-Participant Transmission Customer to the System Operator for NEPOOL within ten days of receipt. All payments shall be made, in accordance with the procedure specified by the System Operator, in immediately available funds payable to the System Operator or by wire transfer to a bank account designated by the System Operator. 9.3 Interest on Unpaid Balances: Interest on any unpaid amounts (including amounts placed in escrow) will be calculated in accordance with the methodology specified for interest on refunds in 18 C.F.R. 35.19a(a)(2)(iii) of the Commission's regulations. Interest on delinquent amounts will be calculated from the due date of the bill to the date of payment. When payments are made by mail, bills will be considered as having been paid on the date of receipt of payment by the System Operator or by the bank designated by the System Operator. 9.4 Customer Default: In the event a Non-Participant Transmission Customer fails to make payment to the ISO on or before the due date as described above, and such failure of payment is not corrected within thirty calendar days after the ISO notifies the Transmission Customer to cure such failure, a default by the Transmission Customer will be deemed to exist. Upon the occurrence of a default, NEPOOL may initiate a proceeding with the Commission to terminate service but shall not terminate service until the Commission approves such termination. In the event of a billing dispute between NEPOOL and the Transmission Customer, service will continue to be provided under the Service Agreement and service termination proceedings will not be initiated as long as the Transmission Customer continues to make all payments invoiced by NEPOOL, including any disputed amounts, subject to resolution of such dispute in favor of such Transmission Customer. If the Transmission Customer fails to meet this requirement for continuation of service, then the ISO may provide notice to the Transmission Customer of NEPOOL's intention to suspend service in sixty days, in accordance with applicable Commission rules and regulations, and may proceed with such suspension. In the event a Transmission Customer that is a Participant fails to perform its obligations under the Tariff, Section 21.2 of the Agreement shall be applicable to that failure. That section of the Agreement addresses defaults under both the Tariff and the Agreement and also addresses termination of an entity's status as a Participant. 9.5 Study Costs and Revenues: A Participant which is a Transmission Provider shall (i) include in a separate operating revenue account or subaccount the revenues, if any, it receives from transmission service when making Third-Party Sales under Part V of this Tariff, and (ii) include in a separate transmission operating expense account or subaccount, costs properly chargeable to expense that are incurred to perform any System Impact Studies or Facilities Studies which the Transmission Provider conducts to determine if it must construct new transmission facilities or upgrades necessary for its own uses, including Third-Party Sales, if any, under this Tariff; and include in a separate operating revenue account or subaccount the revenues received for System Impact Studies or Facilities Studies performed when such amounts are separately stated and identified in a billing under the Tariff. 10 Regulatory Filings Nothing contained in this Tariff or any Service Agreement shall be construed as affecting in any way the right of the Participants to file with the Commission under Section 205 of the Federal Power Act and pursuant to the Commission's rules and regulations promulgated thereunder for a change in any rates, terms and conditions, charges, classification of service, Service Agreement, rule or regulation. Nothing contained in this Tariff or any Service Agreement shall be construed as affecting in any way the ability of any Transmission Customer receiving service under this Tariff or for an Excepted Transaction to exercise its rights under the Federal Power Act and pursuant to the Commission's rules and regulations promulgated thereunder. 11 Force Majeure and Indemnification 11.1 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 party's control. A Force Majeure event does not include an act of negligence or intentional wrongdoing. Neither the Participants, NEPOOL, the System Operator nor the Transmission Customer will be considered in default as to any obligation under this Tariff if prevented from fulfilling the obligation due to an event of Force Majeure; provided that no event of Force Majeure affecting any entity shall excuse that entity from making any payment that it is obligated to make hereunder or under a Service Agreement. However, an entity whose performance under this Tariff is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations under this Tariff, and shall promptly notify the System Operator or the Transmission Customer, whichever is appropriate, of the commencement and end of each event of Force Majeure. 11.2 Indemnification: The Transmission Customer shall at all times indemnify, defend, and save harmless the System Operator, NEPOOL and each Participant from any and all damages, losses, claims, including claims and actions relating to injury to or death of any person or damage to property, demands, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting from the performance by the System Operator, NEPOOL or any Participant of their obligations under this Tariff on behalf of the Transmission Customer, except in cases of negligence or intentional wrongdoing by the System Operator, NEPOOL or a Participant, as the case may be. 12 Creditworthiness For the purpose of determining the ability of a Transmission Customer which is a Non-Participant to meet its obligations related to service hereunder, NEPOOL may require reasonable credit review procedures. This review shall be made in accordance with standard commercial practices. In addition, NEPOOL may require the Transmission Customer to provide and maintain in effect during the term of the Service Agreement an irrevocable letter of credit as security to meet its responsibilities and obligations under this Tariff, or an alternative form of security proposed by the Transmission Customer and acceptable to NEPOOL and consistent with commercial practices established by the Uniform Commercial Code that protects the Participants against the risk of non-payment. The Financial Assurance Policy for NEPOOL Non-Participant Transmission Customers set forth in Attachment M hereto provides in greater detail NEPOOL's credit review procedures and the types of security that are acceptable to NEPOOL to protect against the risk of non-payment. 13 Dispute Resolution Procedures 13.1 Internal Dispute Resolution Procedures: Any dispute between an Eligible Customer or Transmission Customer which is a Participant and NEPOOL involving transmission service under the Tariff may be submitted to mediation and/or arbitration and resolved in accordance with the alternate dispute resolution procedures set forth in Section 21.1 of the Agreement. Any dispute between a Non-Participant Eligible Customer or Transmission Customer and NEPOOL involving this Tariff (excluding applications for rate changes or other changes to this Tariff, or to any Service Agreement entered into under this Tariff, which shall be presented directly to the Commission for resolution) shall be referred to a designated senior representative of the Eligible Customer or Transmission Customer and a representative of the Management Committee for resolution on an informal basis as promptly as practicable. In the event the designated representatives are unable to resolve the dispute within thirty days or such other period as the parties may fix by mutual agreement, such dispute may be submitted to mediation and/or arbitration and resolved in accordance with the alternate dispute resolution procedures set forth in Section 21.1 of the Agreement, with any Non-Participant being treated as if it were a Participant for purposes of such procedures. 13.2 Rights Under The Federal Power Act: Nothing in this section shall restrict the rights of any party to file a complaint with the Commission, or seek any other available remedy, under relevant provisions of the Federal Power Act. 14 Stranded Costs 14.1 General: This Tariff shall not be used to evade or enhance in whole or in part the stranded cost policies or charges established by law or by the regulatory commission with jurisdiction. 14.2 Commission Requirements: A Participant which seeks to recover stranded costs from a Transmission Customer pursuant to this Tariff may do so in accordance with the terms, conditions and procedures in the Commission's Order No. 888 or other relevant Commission orders. However, the Participant must separately file any specific proposed stranded cost charge under Section 205 of the Federal Power Act. 14.3 Wholesale Contracts: Nothing in this Section 13 is intended to affect or alter the rights or obligations of parties under wholesale requirements contracts. 14.4 Right to Seek or Contest Recovery Unimpaired: No provision in this Tariff shall impair a Participant's right to seek stranded cost relief from the appropriate regulatory body or court or the right of any Participant or other entity to contest such relief. II. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION SERVICE) Regional Network Service or Network Integration Transmission Service will be provided by the Participants through NEPOOL during and after the Transition Period to Transmission Customers pursuant to the applicable terms and conditions of this Tariff. Local Network Service will be provided during and after the Transition Period pursuant to the applicable terms and conditions of tariffs filed by an individual Participant that is a Transmission Provider and/or pursuant to an agreement between a Participant that is a Transmission Provider and a Transmission Customer. This Tariff does not prescribe the methodology to be used by the individual Participant in developing its Local Network Service rate, but the Agreement prescribes certain requirements with respect thereto. 15 Nature of Regional Network Service Regional Network Service or Network Integration Transmission Service is the service provided under Parts II and VI of this Tariff over the NEPOOL Transmission System which is provided to Network Customers to serve their loads. It includes firm transmission service for the delivery to a Network Customer of its energy and capacity in Network Resources and secondary service for the delivery to or by Network Customers of energy and capacity in Interchange Transactions. 1.1 Rules for Import Transactions Conducted in Conjunction with Regional Network Service: For purposes of scheduling and curtailment of Import Transactions over interconnections between the NEPOOL Control Areas and neighboring Control Areas, the following rules shall apply: (a) Excepted Transactions, and those service agreements covering the importation over the PTF of the allocation of New York Power Authority power and energy that were in effect as of the date that the NEPOOL Tariff became effective, shall have highest priority, and shall be scheduled first and curtailed last; (b) other than as provided in 14.1(a), Import Transactions shall, to the maximum extent practicable, be scheduled and curtailed on the basis of economic merit order and in accordance with NEPOOL System Rules, except that Short Notice External Transactions (as defined in the Market Rules) shall be scheduled and curtailed in accordance with the Market Rules governing such transactions; (c) other than as provided in 14.1(a), to the extent that Import Transactions cannot be scheduled and curtailed on the basis of economic merit order, such transactions shall be scheduled in order of submittal time (first submitted, first served) and curtailed in reverse order of submittal time (last submitted, first curtailed); (d) to the extent that multiple schedules for Import Transactions submitted at the same time have the same economic merit order, the System Operator shall curtail the schedules on a non-discriminatory basis in accordance with NEPOOL System Rules; and (e) market participants wishing to schedule Import Transactions shall comply with applicable NEPOOL System Rules. The System Operator shall apply the above-listed rules consistent with maintaining the reliability of the NEPOOL Transmission System. The System Operator shall develop and post procedures on its Internet website reflecting the above-listed Import Transaction rules. 16 Availability of Regional Network Service 16.1 Provision of Regional Network Service: Regional Network Service shall be provided by the Participants through NEPOOL, and shall be available to each Eligible Customer. 16.2 Eligibility to Receive Regional Network Service: Regional Network Service shall be taken and paid for by (i) each Eligible Customer which has a load within the NEPOOL Control Area and has not elected to take Internal Point-to-Point Service at all of its Point(s) of Delivery, and (ii) each Non- Participant which is an Eligible Customer and has a load within the NEPOOL Control Area unless such Non-Participant operates its own Control Area or has elected to take Internal Point-to-Point Service at all of its Point(s) of Delivery. Participants and Non-Participants which take Regional Network Service must also take Local Network Service except as otherwise provided in Section 25. 17 Payment for Regional Network Service Each Participant or Non-Participant which has a load in the NEPOOL Control Area and takes Regional Network Service for a month shall pay to NEPOOL for such month an amount equal to its Monthly Network Load for the month times the applicable Participant RNS Rate, and shall pay in addition any amount which it is required to pay for the service pursuant to Section 43.3 of this Tariff. It shall also be obligated to pay any ancillary service charges and any applicable congestion or other uplift charge required to be paid pursuant to Sections 24, 25A and 25B of this Tariff. The applicable Participant RNS Rate shall be the rate, determined in accordance with Schedule 9, which is applicable to a delivery to load in the particular Local Network in which the load served by the Participant or Non-Participant is located. In the event the Participant or Non-Participant serves Network Load located on more than one Local Network, the amount to be paid by it shall be separately computed for the Network Load located on each Local Network. 18 Procedure for Obtaining Regional Network Service A Participant or Non-Participant which takes Regional Network Service shall be subject to the applicable provisions of Part II and Part VI of this Tariff, except to the extent otherwise specifically provided in Section 48 of this Tariff III. THROUGH OR OUT SERVICE; INTERNAL POINT-TO-POINT SERVICE Point-to-Point Transmission Service as Through or Out Service or Internal Point-to-Point Service will be provided during and after the Transition Period pursuant to the applicable terms and conditions of this Tariff. 19 Through or Out Service 19.1 Provision of Through or Out Service: Through or Out Service shall be provided by the Participants through NEPOOL, and shall be available to any Participant and to any Non-Participant which is an Eligible Customer. 19.2 Use of Through or Out Service: A Participant or Non-Participant shall take Through or Out Service as Firm or Non-Firm Point-To-Point Transmission Service for the transmission of any Unit Contract Entitlement or System Contract transaction with respect to a transaction which requires the use of PTF if either (i) the transaction goes through the NEPOOL Control Area and the Point(s) of Receipt for NEPOOL are at one point on the NEPOOL Control Area boundary and the Point(s) of Delivery for NEPOOL are at another point on the NEPOOL Control Area boundary, as, for example, from the Maine Electric Power Company line or New Brunswick to New York or from one point on the NEPOOL Control Area boundary with New York to another point on the Control Area boundary with New York, or (ii) the transaction goes out of the NEPOOL Control Area and the Point(s) of Receipt are within the NEPOOL Control Area and the Point(s) of Delivery for NEPOOL are at a NEPOOL Control Area boundary, as, for example, from Boston to New York. 20 Internal Point-to-Point Service 20.1 Provision of Internal Point-to-Point Service: Internal Point-to-Point Service shall be provided by the Participants through NEPOOL, and shall be available to any Participant and to any Non-Participant which is an Eligible Customer. 20.2 Use of Internal Point-to-Point Service: A Participant or Non-Participant which is an Eligible Customer may take Internal Point-to-Point Service as Firm or Non-Firm Point-to-Point Transmission Service with respect to any transaction if the Point(s) of Receipt are at the NEPOOL Control Area boundary or within the NEPOOL Control Area, and the Point(s) of Delivery are within the NEPOOL Control Area, including Interchange Transactions meeting these requirements. Non-Firm Internal Point-to-Point Service shall be available to an entity to serve its load only if the entity (i) demonstrates to the satisfaction of the System Operator a physical ability to interrupt its receipt of energy and/or capacity and (ii) gives the System Operator physical control over such an interruption. 20.3 Use by a Transmission Customer: If a Transmission Customer elects to take Internal Point-to-Point Service with respect to any Points of Delivery, it may reserve transmission capacity for the service to cover both the delivery to it of Energy and capacity covered by the Entitlements or System Contracts designated by it in Completed Applications and the delivery to or from it in Interchange Transactions of Energy and/or capacity. A transmission Customer which takes Internal Point-to-Point Service to serve its load must also take point-to-point service under the applicable Local Network Service tariff. A load-serving Participant or Non-Participant which takes Internal Point-to-Point Service in this manner must reserve each month sufficient Reserved Capacity, after adjusting for any Backyard Generation, at a Point of Delivery to cover (i) the maximum amount of Energy that it will receive in any hour, as determined from meters and adjusted for losses, plus, in the case of a Participant, the maximum amount of Operating Reserve assigned to that Participant by the System Operator in any hour during the month, or (ii) the portion of its Installed Capability Responsibility which must be satisfied with the resources covered by its Completed Applications and from Interchange Transactions if such portion exceeds the amount determined in accordance with clause (i) of this sentence. Any load-serving entity may use Internal Point-to-Point Service to effect sales in bilateral arrangements, whether or not it elects to take Point-to-Point Service to serve its load. 21 Payment for Through or Out Service Each Participant or Non-Participant which takes Firm or Non-Firm Through or Out Service shall pay to NEPOOL a charge per Kilowatt of Reserved Capacity based on an annual rate (the "T or O Rate") which shall be the highest of (i) the Pool PTF Rate, or (ii) a rate which is derived from the annual incremental cost, not otherwise borne by the Transmission Customer or a Generation Owner, of any new facilities or upgrades that would not be required but for the need to provide the requested service or (iii) a rate which is equal to the Pool's opportunity cost (if and when available) capped at the cost of expansion. If at any time NEPOOL proposes to charge a rate based on opportunity cost, it shall first file with the Commission procedures for computing opportunity cost pricing for all Transmission Customers. The Transmission Customer shall also be obligated to pay any ancillary service charge and any applicable congestion or other uplift charge required to be paid pursuant to Section 24 of this Tariff. The rate for Firm Through or Out Service shall be as follows: Per year - the T or O Rate Per month - the T or O Rate divided by 12 Per week - the T or O Rate divided by 52 Per day - the T or O Rate "per week" divided by 5; provided that the rate for 5 to 7 consecutive days may not exceed the "per week" rate. The rate for Non-Firm Through or Out Service shall be as follows: Per year - the T or O Rate Per month - the T or O Rate divided by 12 Per week - the T or O Rate divided by 52 Per day - the T or O Rate "per week" divided by 7; Per hour - the Non-Firm T or O Rate "per day" divided by 24. The Pool PTF Rate shall be the Rate determined annually in accordance with paragraph (2) of Schedule 8. 22 Payment for Internal Point-to-Point Service Each Participant or Non-Participant which takes firm or non-firm Internal Point-to-Point Service shall pay to NEPOOL a charge per Kilowatt of Reserved Capacity based on an annual rate (the "IPTP Charge") which shall be the Internal Point-to-Point Service Rate; provided that if either or both (i) a rate which is derived from the annual incremental cost, not otherwise borne by the Transmission Customer or a Generator Owner, of any new facilities or upgrades that would not be required but for the need to provide the requested service, or (ii) a rate which is equal to the Pool's opportunity cost (if and when available) capped at the cost of expansion is greater than the Pool PTF Rate, the IPTP Charge shall be the higher of such amounts; provided further that no such charge shall be payable with respect to the use of Internal Point-to-Point Service to effect a delivery to the NEPOOL power exchange in an Interchange Transaction. If at any time NEPOOL proposes to charge a rate based on opportunity cost, it shall first file with the Commission procedures for computing opportunity cost pricing for all Transmission Customers. The Transmission Customer shall also be obligated to pay any ancillary service charges and any applicable congestion or other uplift charge required to be paid pursuant to Sections 24, 25A and 25B of this Tariff. The charge for firm Internal Point-to-Point Service shall be as follows: Per year - the IPTP Charge Per month - the IPTP Charge divided by 12 Per week - the IPTP Charge divided by 52 Per day - the IPTP Charge "per week" divided by 5; provided that the rate for 5 to 7 consecutive days may not exceed the "per week" rate. The rate for non-firm Internal Point-to-Point Service shall be as follows: Per year - the IPTP Charge Per month - the IPTP Charge divided by 12 Per week - the IPTP Charge divided by 52 Per day - the IPTP Charge "per week" divided by 7; Per hour - the non-firm IPTP Charge "per day" divided by 24. If several power marketers or other entities are involved in a series of sales of the same energy and/or capacity, transmission service shall be required only with respect to the delivery to the ultimate wholesale buyer, and if an Internal Point-to-Point Service charge is payable with respect to the transaction, the charge shall be paid only with respect to the delivery to, and absent other arrangements the charge shall be paid by, the ultimate wholesale buyer. 23 Reservation of Capacity for Point-to-Point Transmission Service Compliance with the applicable requirements of Part V of this Tariff is required for the initiation of Through or Out Service or Internal Point-to- Point Service. IV. SERVICE DURING THE TRANSITION PERIOD; CONGESTION COSTS; EXCEPTED TRANSACTIONS The six-year Transition Period, and additional arrangements to be in effect during the succeeding five-year period, will permit the phase-in on a negotiated basis of the Tariff rates. 24 Transition Arrangements The transition arrangements include (i) the treatment provided for certain Excepted Transactions in Section 25, (ii) the provisions in Schedule 9 for the phase-in of the rates for Regional Network Service, and (iii) the rules provided in Sections 16.3 and 16.6 of the Agreement for the distribution and application of revenues received by NEPOOL on behalf of the Participants from the payment of the Tariff rates. 25 Congestion Costs and Congestion Revenue (1) Until the earlier of the CMS/MSS Effective Date or the implementation effective date of an order issued by the Commission directing a different allocation of Congestion Costs, if limitations in available transmission capacity over any interface within the NEPOOL Control Area in any hour require that the System Operator dispatch resources out-of-merit, the System Operator shall determine for the affected area or areas the aggregate of the Congestion Costs for all such out-of-merit resources for the hour. The Congestion Costs for each hour in any month shall be paid as a transmission charge and included in the charge for Regional Network Service or Internal Point-to-Point Service or Through or Out Service, whichever is applicable, by those Participants and Non-Participants which are obligated to pay a Regional Network Service, Internal Point-to-Point Service or Through or Out Service charge for the month, in accordance with the following formula: (EQUATION) in which CH = the amount to be paid by a Participant or Non-Participant for the hour; CC = the Congestion Costs for the hour to be allocated and paid pursuant to this Section 24(a); HLi = the Network Load of the Participant or Non-Participant for the hour, if it is obligated to pay a Regional Network Service charge for the month; HL = the aggregate of the Network Loads for the hour of all Participants and Non-Participants which are obligated to pay a Regional Network Service charge for the month; RCi = the Reserved Capacity, if any, for Internal Point-to-Point Service or Through or Out Service of the Participant or Non-Participant for the hour; and RC = the aggregate Reserved Capacity, if any, for Internal Point-to-Point Service or Through or Out Service of all Participants and Non-Participants for the hour. This Section 24(a) shall terminate on the implementation effective date of an order issued by the Commission directing a different allocation of Congestion Costs. As used in this Section 24(a), 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. The "Dispatch Price" of an out-of-merit resource for an hour is the price to provide energy from the resource, as determined pursuant to market operation rules approved by the NEPOOL Regional Market Operations Committee to incorporate the Bid Price for such energy and any loss adjustments, if and as appropriate under such market operation rules. The "Energy Clearing Price" for an hour is the price determined for the hour in accordance with Section 14.8 of the Agreement. 26 (b) On and after the CMS/MSS Effective Date, when Congestion exists, the Congestion Cost shall be reflected in Locational Prices calculated in accordance with Section 14A.12 of the Agreement and Schedule 13 of the Tariff. Congestion Cost shall be recovered from Non-Participant Transmission Customers taking service under the Tariff in accordance with Schedule 13 of the Tariff. Congestion Cost shall be recovered from Participants in accordance with Section 14A.17 of the Agreement. Congestion Revenue shall be collected and maintained in a Congestion Revenue Fund in accordance with Section E of Schedule 14 of the Tariff. A system of Financial Congestion Rights shall be implemented and administered in accordance with Schedule 14 of the Tariff. A system of Auction Revenue Rights shall be implemented and administered in accordance with Schedule 15 of the Tariff. 27 Excepted Transactions Notwithstanding any other section of the Tariff but except as otherwise provided in Section 25A or 25B of this Tariff, the power transfers and other uses of the NEPOOL Transmission System effected under the transmission agreements in effect on November 1, 1996 specified below ("Excepted Transactions") will continue to be effected under such agreements for the respective periods specified below rather than under this Tariff, but not thereafter, and such transfers and other uses will continue to be effected after such period, if still occurring, under this Tariff. Participants receiving service under the agreements listed in Attachment G-1 shall not be required to take Local Network Service for such transfers and other uses. The period for which each Excepted Transaction will continue to be effected under such existing transmission agreements shall be: (1) for the period to and including February 28, 2001, the following transfers pursuant to Section 17 of the Agreement: (a) the transfer to a Participant's system within the NEPOOL Control Area of its ownership interest in a Pool-Planned Unit which is off its system; (b) the transfer to a Participant's system within the NEPOOL Control Area of its Unit Contract Entitlement, under a contract entered into by it on or before November 1, 1996, in a Pool-Planned Unit which is off its system; and (c) the transfer to a Participant's system within the NEPOOL Control Area of its Entitlement in a purchase (including a purchase under the HQ Phase II Firm Energy Contract) from Hydro-Quebec under a contract entered into by it on or before November 1, 1996, where the line over which the transfer is made into New England is the HQ Interconnection; (2) for the period to and including February 28, 2001, the transfer to a Participant's system within the NEPOOL Control Area of its Unit Contract Entitlement in the Vermont Yankee Nuclear Power Corporation unit or the Pilgrim 1 unit; provided the transfer is pursuant to a transmission agreement in effect on November 1, 1996 and is to the entity which was receiving the service on November 1, 1996; and (3) for the period from the effective date of the Tariff until the termination of the transmission agreement: (a) transfers and other uses within the NEPOOL Control Area, as of November 1, 1996, of the NEPOOL Transmission System under the support or exchange agreements specified in Attachment G; (b) transfers and other uses within the NEPOOL Control Area, as of November 1, 1996, of the NEPOOL Transmission System under the comprehensive network service agreements specified in Attachment G-1; and (c) transfers and other uses within the NEPOOL Control Area, as of November 1, 1996, of the NEPOOL Transmission System under the other transmission agreements or tariff service agreements specified in Attachment G. The Management Committee is authorized to add additional agreements to Attachment G if they have been inadvertently omitted. Except as otherwise provided in Sections 25A or 25B below, the transfers or other uses under any of the transmission agreements covering the transfers referred to in paragraphs (1), (2) and (3) above shall be in accordance with the terms of the transmission agreement as in effect on November 1, 1996, or a modification of the terms which is expressly provided for in the agreement as in effect on November 1, 1996 and is accomplished without amendment of the agreement or by an amendment entered into after November 1, 1996 that does not extend the term of the agreement or increase the amount of the service. Further, except as otherwise provided in Sections 25A or 25B below, and notwithstanding the foregoing restriction on the amendment after November 1, 1996 of transmission agreements with respect to Excepted Transactions, the transmission arrangements for the Masspower and Altresco facilities may continue as Excepted Transactions in accordance with transmission agreement amendments or memoranda of understanding entered into as of December, 1996 which do not extend the term of the agreements. For the purpose of determining priorities under this Tariff, Excepted Transactions shall have the same priority as Firm Point-To-Point Transmission Service transactions for resources in existence on the effective date of this Tariff which are effected as Regional Network Service or as Internal Point- to-Point Service or as Through or Out Service. When the transfers and other uses effected under the transmission agreements that are Excepted Transactions cease to be Excepted Transactions before the end of their term, except as therein provided in Sections 25A or 25B below the transactions shall be effected under this Tariff and under any applicable Local Network Service Tariff, to the extent appropriate, but the transactions shall continue to have a priority not less than the priority that they would have had if Regional Network Service had been used for the transactions from the effective date of this Tariff. New transactions entered into after November 1, 1996 under umbrella tariff agreements then in effect will not be Excepted Transactions. Notwithstanding the foregoing or any other section of the Tariff, existing agreements which provide for the support of the costs of transmission facilities or for the interconnection of transmission facilities shall continue in effect until the termination of the agreement to provide for such support or for the rights and obligations of the parties with respect to the interconnection arrangements. Attachment G-2 lists certain additional agreements covering transactions, the status of which is described in the Attachment. 25A Phase I Credit and Uplift Charge With Respect to Excepted Transactions Notwithstanding the provisions of any other Section of this Tariff, the following Participants will receive a total credit of $12,012,000 to settle certain disputes regarding Excepted Transactions, allocated as set forth below (defined for purposes of this Section 25A only as the Participant's "Phase I Credit"): Bangor Hydro-Electric Company $ 896,000 Massachusetts Municipal Wholesale Electric Company clients $ 6,182,400 Braintree Electric Light Department $ 666,400 Reading Municipal Light Department $ 1,430,240 Taunton Municipal Lighting Plant $ 479,360 United Illuminating Company $ 280,000 Fitchburg Gas and Electric Light Company $ 117,600 Unitil Power Corporation $ 1,960,000 The Phase I Credit for each of the Participants identified above shall be provided as reductions in each entity's NEPOOL bill equal to one-twelfth (1/12) of the amount identified above commencing with and including the bill covering the period June 1 - 30, 1999 and ending with the bill covering the period May 1 - - May 31, 2000. The total $12,012,000 Phase I Credit shall be funded with twelve equal monthly uplift charges (the "Phase I Uplift") which will be in effect for the twelve month period beginning June 1, 1999 and continuing through May 31, 2000, and which will be included in the bills corresponding to this time period. Each RNS and Internal Point-to-Point Transmission Customer under the NEPOOL Tariff shall pay the monthly Phase I Uplift charge determined as follows: 1) A Transmission Customer's monthly share of the Phase I Uplift charge shall be determined in accordance with the following formula: PIU = $998,387 x [(ULi + URCi + UAUi) / (UL + URC + UAU)] Where: PIU = The Phase I Uplift Charge for the Participant or Non-Participant per month. $998,387 = The total monthly Phase I Uplift charge, exclusive of Taunton's portion of the charge, calculated as follows: ($12,012,000 / 12) - $2,613. ULi = Monthly Uplift Network Load of a Participant or Non-Participant for the month UL = Aggregate of the Uplift Network Loads of all Participants or Non-Participants for the month URCi = The sum of a Participant's or Non-Participant's Maximum Reserved Capacity for Internal Point-to-Point Service for each load served within a Local Network or Network(s) during the month URC = Aggregate of URCi for all Participants and Non-Participants UAUi = The sum of a Participant's or Non-Participant's Maximum Unauthorized Use associated with Internal Point-to-Point Service for each load served within a Local Network or Network(s) during the month UAU = Aggregate of UAUi for all Participants and Non-Participants The monthly Uplift Network Load (ULi) for each Non-Participant shall be its Network Load for the month.The monthly Uplift Network Load (ULi) for each Participant shall be the "1998 12 CP Network Load" identified in connection with the determination of the Pool PTF Rate to become effective June 1, 1999, on a basis comparable to the "1997 12 CP Network Load" reflected in Attachment K of this Tariff, except as follows: 1) The total Uplift Load (ULi + URCi + UAUi) for the Vermont Electric Power Company shall be zero. 2) The total Uplift Load (ULi + URCi + UAUi) for Bangor Hydro-Electric Company shall be 50 MW. 3) The monthly Uplift Network Load (ULi) for Commonwealth Electric Company and Cambridge Electric Light Company shall be one half of the value reflected in the "1998 12 CP Network Load" for such companies (excluding the load for Nantucket). 4) The monthly Uplift Network Load (ULi) for Montaup Electric Company and the affiliated Eastern Utilities Associates Operating Companies shall be one half of the value reflected in the "1998 12 CP Network Load" for "Eastern Utilities Associates." 5) The Taunton Municipal Lighting Plant's monthly payment for the Phase I Uplift shall be limited to $2,613. 25B Phase II Credit and Uplift Charge With Respect to Certain Excepted Transactions Notwithstanding the provisions of any other Section of this Tariff, the Participants identified in Section 25A of this Tariff receiving a Phase I Credit as set forth in that Section, so long as they remain RNS Transmission Customers under the Tariff, shall receive a credit (defined for purposes of this Section 25B only as a "Phase II Credit") to their NEPOOL transmission bills equal to the amounts they are assessed under the contracts and arrangements for the month within the scope of Sections 25(1) and 25(2) of the NEPOOL Tariff (specifically PPU, Yankee, Pilgrim and HQ II), for all charges assessed during the period March 1, 1999 through and including February 28, 2001 (defined for purposes of this Section 25B only as "Phase II"). The Phase II Credit for each of the Participants that are to receive the Phase II Credit shall be provided as reductions in that Participant's NEPOOL bill commencing with and including the bill covering the period beginning March 1, 1999 and terminating with the bill for the period through February 28, 2001. The total Phase II Credit shall be funded with a monthly uplift charge (the "Phase II Uplift") which will be in effect for the twenty-four-month period beginning June 1, 1999 and continuing through May 31, 2001, and which will be included in the bills corresponding to this time period. Each RNS and Internal Point-to-Point Transmission Customer under the NEPOOL Tariff shall pay a share of the monthly Phase II Uplift charge, determined as follows: PIIUi = $Y x [(PIILi + URCi + UAUi) / (PIIL + URC + UAU)] Where: PIIUi = The Phase II Uplift charge for the Participant or Non-Participant for the month $Y = Sum of the EHV PTF, Vermont Yankee and Pilgrim transmission charges for the month for Bangor Hydro-Electric Company, Massachusetts Municipal Wholesale Electric Company, Braintree Electric Light Department, Reading Municipal Light Department and Taunton Municipal Lighting Plant, the United Illuminating Company and Unitil Power Corp. PIILi = Phase II Uplift Network Load of a Participant or Non-Participant for the month UL = Aggregate of the Phase II Uplift Network Loads of all Participants or Non-Participants for the month URCi = The sum of a Participant's or Non-Participant's maximum Reserved Capacity for Internal Point-to-Point Service for each load served within a Local Network or Network(s) during the month URC = Aggregate of URCi for all Participants and Non-Participants UAUi = The sum of a Participant's or Non-Participant's Maximum Unauthorized Use associated with Internal Point-to-Point Service for each load served within a Local Network or Network(s) during the month UAU = Aggregate of UAUi for all Participants and Non-Participants The Phase II Uplift Network Load (PIIli) of a Transmission Customer in a month shall be its Network Load in that month, except as follows: 1) The Phase II Uplift Network Load (PIILi) for the Vermont Electric Power Company shall be zero. 2) The Phase II Uplift Network Load (PIILi) for Central Maine Power Company shall be zero. 3) The Phase II Uplift Network Load (PIIli) for Bangor Hydro-Electric Company shall be 50 MW. 4) The total Phase II Uplift Load (PIILi) and URCi) shall be one half of the sum of the Network Load and Reserved Capacity for Internal Point-to-Point Service for the following Transmission Customers: Commonwealth Electric Company Cambridge Electric Company Canal Electric Company Montaup Electric Company on its own behalf and on behalf of the operating affiliates of Eastern Utilities Associates All Internal Point-to-Point Service shall be deemed to be under the NEPOOL and LNS Tariffs rather than under an Excepted Transaction. V. POINT-TO-POINT TRANSMISSION SERVICE Preamble Firm or Non-Firm Point-to-Point Transmission Service shall be reserved by all Transmission Customers, whether Participants or Non-Participants, for all new transfers to be effected as Internal Point-to-Point Service or as Through or Out Service, pursuant to the applicable terms and conditions of Part III and this Part V of the Tariff. Point-to-Point Transmission Service is the service required for the receipt of capacity and/or energy at designated Point(s) of Receipt and the transmission of such capacity and/or energy to designated Point(s) of Delivery. 28 Scope of Application of Part V Except for the deposit and creditworthiness requirement of Section 31.3, which will apply only to Non-Participants, all of the requirements of this Part V shall be fully applicable to both Participants and Non-Participants requesting Internal Point-to-Point Service or Through or Out Service. Alternative deposit and creditworthiness requirements are applicable to Participants under the Financial Assurance Policy for NEPOOL Members which is set forth in Attachment L hereto. Reservations under the Tariff shall not be required for the use of Internal Point-to-Point Service for deliveries to the NEPOOL power exchange in Interchange Transactions from a Point of Receipt within the NEPOOL Control Area, but are required for the use of In Service for such deliveries from a Point of Receipt at the NEPOOL Control Area boundary. 29 Nature of Firm Point-To-Point Transmission Service 29.1 Term: The minimum term of Firm Point-To-Point Transmission Service shall be one day and the maximum term shall be that specified in the Service Agreement. 29.2 Reservation Priority: Long-Term Firm Point-To-Point Transmission Service shall be available to Participants and Non-Participants on a first-come, first-served basis, i.e., in the chronological sequence in which each Transmission Customer's application for reserved service is received by the System Operator pursuant to Section 31. Reservations for Short-Term Firm Point-To-Point Transmission Service will be conditional based upon the length of the requested transaction. If the NEPOOL Transmission System becomes oversubscribed, requests for longer term service may preempt requests for shorter term service up to the following deadlines: one day before the commencement of daily service, one week before the commencement of weekly service, and one month before the commencement of monthly service. Before the conditional reservation deadline, if available transmission capability is insufficient to satisfy all Applications, an Eligible Customer with a reservation for shorter term service has the right of first refusal to match any longer term reservation before losing its reservation priority. A longer term competing request for Short-Term Firm Point-To-Point Transmission Service will be granted if the Eligible Customer with the right of first refusal does not agree to match the competing request within 24 hours (or earlier if necessary to comply with the scheduling deadlines provided in Section 27.8) from being notified by the System Operator of a longer-term competing request for Short-Term Firm Point-To-Point Transmission Service. After the conditional reservation deadline, service will commence pursuant to the terms of Part III of this Tariff. Firm Point-To-Point Transmission Service will always have a reservation priority over non-firm Point-To-Point Transmission Service under the Tariff. All Long-Term Firm Point-To-Point Transmission Service will have reservation priority equal to Native Load Customers, Network Customers and customers for Excepted Transactions. Reservation priorities for existing firm service customers, including customers receiving service with respect to Excepted Transactions, are provided in Section 3.2. 29.3 Use of Firm Point-To-Point Transmission Service by the Participants That Own PTF: A Transmission Provider that owns PTF will be subject to the rates, terms and conditions of this Tariff when making Third-Party Sales to be transmitted as Point-to-Point Transmission Service under (i) agreements executed after November 1, 1996 or (ii) agreements executed on or before November 1, 1996 to the extent that the Commission requires them to be unbundled, by the date specified by the Commission. A Transmission Provider that owns PTF will maintain separate accounting, pursuant to Section 8, for any use of Firm Point-To-Point Transmission Service to make Third-Party Sales to the extent not paid for under this Tariff. 29.4 Service Agreements: A standard form Firm Point-To-Point Transmission Service Agreement (Attachment A) will be offered to an Eligible Customer when it submits a Completed Application for Long-Term or Short-Term Firm Point-To- Point Transmission Service to be transmitted pursuant to this Tariff. Executed Service Agreements that contain the information required under this Tariff will be filed with the Commission in compliance with applicable Commission regulations. 29.5 Transmission Customer Obligations for Facility Additions or Redispatch Costs: In cases where it is determined that the NEPOOL Transmission System is not capable of providing new Firm Point-To-Point Transmission Service without (1) degrading or impairing the reliability of service to Native Load Customers, Network Customers, customers taking service for Excepted Transactions and other Transmission Customers taking Firm Point-To-Point Transmission Service, or (2) interfering with a Participant's ability to meet prior firm contractual commitments to others, the Transmission Providers will be obligated to arrange to expand or upgrade PTF for Long-Term Firm Service pursuant to the terms of Section 33. The Transmission Customer must agree to compensate the Transmission Providers or any other entity designated to effect construction through the System Operator for any necessary transmission facility additions or upgrades pursuant to the terms of Section 39. To the extent the System Operator can relieve any system constraint more economically by redispatching the Participants' resources, rather than through construction of additions or upgrades, it shall do so, provided that the Eligible Customer agrees to compensate the Participants pursuant to the terms of Section 39. Any redispatch, addition or upgrade or Direct Assignment Facilities costs to be charged to the Transmission Customer on an incremental basis under this Tariff will be specified in the Service Agreement prior to initiating service. 29.6 Curtailment of Firm Transmission Service: In the event that a Curtailment on the NEPOOL Transmission System, or a portion thereof, is required to maintain reliable operation of the system, the Curtailment will be made on a non-discriminatory basis to the transaction(s) that effectively relieve the constraint. If multiple transactions require Curtailment, to the extent practicable and consistent with Good Utility Practice, the System Operator will curtail service to Network Customers and Transmission Customers taking Firm Point- To-Point Transmission Service on a non-discriminatory basis. All Curtailments will be made on a non-discriminatory basis; however, Non-Firm Point-To-Point Transmission Service shall be subordinate to Firm Transmission Service. When the System Operator determines that an electrical emergency exists on the NEPOOL Transmission System and implements emergency procedures to effect a Curtailment of Firm Transmission Service, the Transmission Customer shall make the required reductions upon the System Operator's request. However, NEPOOL reserves the right to effect a Curtailment, in whole or in part, of any Firm Transmission Service provided under this Tariff when, in the System Operator's sole discretion, an emergency or other unforeseen condition impairs or degrades the reliability of the NEPOOL Transmission System. The System Operator will notify all affected Transmission Customers in a timely manner of any scheduled Curtailments. In the event the System Operator exercises its right to effect a Curtailment, in whole or part, of Firm Point-to-Point Transmission Service, no credit or other adjustment shall be provided as a result of the Curtailment with respect to the charge payable by the Customer. 29.7 Classification of Firm Point-To-Point Transmission Service: (a) A Transmission Customer taking Firm Point-To-Point Transmission Service may (1) change its Points of Receipt and Delivery to obtain service on a non- firm basis consistent with the terms of Section 36.1 or (2) request a modification of the Points of Receipt or Delivery on a firm basis pursuant to the terms of Section 36.2; provided that if any Transmission Provider or its designee constructed new facilities or upgraded facilities to accommodate the original firm service, such Transmission Provider or its designee shall continue to be compensated for its facility costs by the Transmission Customer. (b) A Transmission Customer may purchase transmission service to make sales from multiple generating units or contracts that are on the NEPOOL Transmission System. For such purchase of transmission service the Transmission Customer shall specify a Location for each generating unit or contract. (c) Deliveries will be provided from the Point(s) of Receipt to the Point(s) of Delivery. Each Point of Receipt and Point of Delivery at which firm transmission capacity is reserved for Long-Term Firm Point-to-Point Transmission Service by the Transmission Customer shall be set forth in the Service Agreement for such Service along with a corresponding capacity reservation. The greater of either (1) the sum of the capacity reservations at the Point(s) of Receipt, or (2) the sum of the capacity reservations at the Point(s) of Delivery shall be the Transmission Customer's Reserved Capacity. The Transmission Customer will be billed for its Reserved Capacity under the terms of Section 20 or Section 21, whichever is applicable. The Transmission Customer's Use may not exceed its firm capacity reserved at each Point of Receipt and each Point of Delivery except as otherwise specified in Section 36. In the event that the Use by a Transmission Customer (including Third-Party Sales by the Participants) exceeds that Transmission Customer's Reserved Capacity at any Point of Receipt or Point of Delivery in any hour, it shall pay 200% of the charge which is otherwise applicable for each Kilowatt of the excess. In addition, the System Operator will record all instances in which a Transmission Customer's Use exceeds that Transmission Customer's firm Reserved Capacity, and if in any calendar year more than 10 such instances occur with respect to any single Transmission Customer, then the System Operator may require such Transmission Customer to apply for additional Firm Point-to-Point Transmission Service under the Tariff in an amount equal to the greatest amount of the excess of such Transmission Customer's Use over its firm Reserved Capacity for the remainder of that calendar year. Charges for such additional Firm Point-to-Point Transmission Service will relate back to the first day of the month following the month in which the System Operator notifies such Transmission Customer that it is subject to the provisions of this paragraph. 29.8 Scheduling of Firm Point-To-Point Transmission Service: (a) Until the CMS/MSS Effective Date, unless other schedules are permitted pursuant to NEPOOL System Rules, schedules for the Transmission Customer's Firm Point-To-Point Transmission Service (including schedules for resources to be self scheduled) must be submitted to the System Operator no later than noon of the day prior to commencement of such service. In the cases which are bid into the power exchange, the Energy bid price must be submitted to the System Operator by the noon deadline. Hour-to-hour schedules of any capacity and energy that is to be delivered must be stated in increments of 1000 kW per hour. Transmission Customers with multiple requests for Firm Point-To-Point Transmission Service at a Point of Receipt, each of which request is under 1000 kW per hour, may consolidate their service requests at a common Point of Receipt into units of 1000 kW per hour for scheduling and billing purposes. Scheduling changes will be permitted up to thirty-five minutes before the start of the next clock hour, provided that the Delivering Party and Receiving Party also agree to the schedule modification. The System Operator will furnish to the Delivering Party's system operator hour-to-hour schedules equal to those furnished by the Receiving Party (unless reduced for losses) and will deliver the capacity and energy provided by such schedules. Should the Transmission Customer, Delivering Party or Receiving Party revise or terminate any schedule, such party shall immediately notify the System Operator, and the System Operator will have the right to adjust accordingly the schedule for capacity and energy to be received and to be delivered. (b) On and after the CMS/MSS Effective Date, unless other schedules are permitted pursuant to the NEPOOL System Rules, Day-Ahead Market schedules for the Transmission Customer's Firm Point-To-Point transmission service must be submitted to the System Operator no later than noon of the day prior to the Dispatch Day. The Supply Offers and Demand Bids must be submitted to the System Operator by the noon deadline. The System Operator will furnish to the Delivering Party's system operator hour-to-hour schedules equal to those furnished by the Receiving Party and will deliver the capacity and Energy provided by such schedules. Should the Transmission Customer, Delivering Party or Receiving Party revise or terminate any schedule, such party shall immediately notify the System Operator, and the System Operator will have the right to adjust accordingly the schedule for capacity and Energy to be received and to be delivered. On and after the CMS/MSS Effective Date, unless other schedules are permitted pursuant to the NEPOOL System Rules, Real-Time Market schedules for the Transmission Customer's Firm Point-To-Point transmission service must be submitted to the System Operator in accordance with the NEPOOL System Rules. The Supply Offers and Demand Bids must be submitted to the System Operator in accordance with the NEPOOL System Rules. Scheduling changes will be permitted up to thirty-five minutes before the start of the next clock hour, provided that the Delivering Party and Receiving Party also agree to the schedule modification. The System Operator will furnish to the Delivering Party's system operator hour-to-hour schedules equal to those furnished by the Receiving Party and will deliver the capacity and Energy provided by such schedules. Should the Transmission Customer, Delivering Party or Receiving Party revise or terminate any schedule, such party shall immediately notify the System Operator, and the System Operator will have the right to adjust accordingly the schedule for capacity and Energy to be received and to be delivered. 30 Nature of Non-Firm Point-To-Point Transmission Service 30.1 Term: Non-Firm Point-To-Point Transmission Service will be available for periods ranging from one hour to one month. However, a Purchaser of Non-Firm Point-To-Point Transmission Service will be entitled to reserve a sequential term of service (such as a sequential monthly term without having to wait for the initial term to expire before requesting another monthly term) so that the total time period for which the reservation applies is greater than one month, subject to the requirements of Section 32.3. 30.3 Reservation Priority: Non-Firm Point-To-Point Transmission Service shall be available from transmission capability in excess of that needed for reliable service to Native Load Customers, Network Customers, customers for Excepted Transactions and other Transmission Customers taking Long-Term and Short-Term Firm Point-To-Point Transmission Service. A higher priority will be assigned to reservations with a longer duration of service. In the event the NEPOOL Transmission System is constrained, competing requests of equal duration will be prioritized based on the highest price offered by the Eligible Customer for the Transmission Service, or in the event the price for all Eligible Customers is the same, will be prioritized on a first-come, first-served basis i.e., in the chronological sequence in which each Customer has reserved service. Eligible Customers that have already reserved shorter term service have the right of first refusal to match any longer term reservation before being preempted. A longer term competing request for Non- Firm Point-To-Point Transmission Service will be granted if the Eligible Customer with the right of first refusal does not agree to match the competing request: (a) immediately for hourly Non-Firm Point-To-Point Transmission Service after notification by the System Operator; and (b) within 24 hours (or earlier if necessary to comply with the scheduling deadlines provided in Section 28.6) for Non-Firm Point-To-Point Transmission Service other than hourly transactions after notification by the System Operator. Secondary transmission service for Network Customers pursuant to Section 40.4 will have a higher priority than any Non-Firm Point-To-Point Transmission Service. Non-Firm Point-To-Point Transmission Service over secondary Point(s) of Receipt and Point(s) of Delivery will have the lowest reservation priority under this Tariff. 30.4 Use of Non-Firm Point-To-Point Transmission Service by the Transmission Provider: A Transmission Provider will be subject to the rates, terms and conditions of this Tariff when making Third-Party Sales to be transmitted as Non-Firm Point-to-Point Transmission Service under (i) agreements executed after November 1, 1996 or (ii) agreements executed on or before November 1, 1996 to the extent that the Commission requires them to be unbundled, by the date specified by the Commission. A Transmission Provider will maintain separate accounting, pursuant to Section 8, for any use of Non-Firm Point-To- Point Transmission Service to make Third-Party Sales, to the extent not paid for under this Tariff. 30.5 Service Agreements: The System Operator shall offer a standard form Point-To-Point Transmission Service Agreement (Attachment A, modified to cover non-firm service) to an Eligible Customer when the Eligible Customer first submits a Completed Application for Non-Firm Point-To-Point Transmission Service pursuant to the Tariff. Executed Service Agreements that contain the information required under this Tariff shall be filed with the Commission in compliance with applicable Commission regulations. 30.6 Classification of Non-Firm Point-To-Point Transmission Service: Non-Firm Point-To-Point Transmission Service shall be offered under applicable terms and conditions contained in Part III of this Tariff. The NEPOOL Participants undertake no obligation under this Tariff to plan the NEPOOL Transmission System in order to have sufficient capacity for Non-Firm Point-To-Point Transmission Service. Parties requesting Non-Firm Point-To-Point Transmission Service for the transmission of firm power do so with the full realization that such service is subject to availability and to Curtailment or Interruption under the terms of this Tariff. In the event that the Use by a Transmission Customer (including Third-Party Sales by a Participant) exceeds that Transmission Customer's non-firm Reserved Capacity at any Point of Receipt or Point of Delivery, it shall pay 200% of the charge which is otherwise applicable for each Kilowatt of the excess. In addition, the System Operator will record all instances in which a Transmission Customer's Use exceeds that Transmission Customer's non-firm Reserved Capacity, and if in any calendar year more than 10 such instances occur with respect to any single Transmission Customer, then the System Operator may require such Transmission Customer to apply for additional Non-Firm Point-to-Point Transmission Service under the Tariff in an amount equal to the greatest amount of the excess of such Transmission Customer's Use over its non-firm Reserved Capacity for the remainder of that calendar year. Charges for such additional Non-Firm Point-to-Point Transmission Service will relate back to the first day of the month following the month in which the System Operator notifies such Transmission Customer that it is subject to the provisions of this paragraph. (a) Non-Firm Point-To-Point Transmission Service shall include transmission of energy on an hourly basis and transmission of scheduled short-term capacity and energy on a daily, weekly or monthly basis, but not to exceed one month's reservation for any one Application. (b) Each Point of Receipt at which non-firm transmission capacity is reserved by the Transmission Customer shall be set forth in the Application along with a corresponding capacity reservation associated with each Point of Receipt. 30.7 Scheduling of Non-Firm Point-To-Point Transmission Service: (a) Until the CMS/MSS Effective Date, unless other schedules are permitted pursuant to NEPOOL System Rules, schedules for Non-Firm Point-To-Point Transmission Service must be submitted to the Transmission Provider no later than noon of the day prior to commencement of such service. Schedules submitted after noon will be accommodated, if practicable. Hour-to-hour schedules of energy that is to be delivered must be stated in increments of 1,000 kW per hour. Transmission Customers within the NEPOOL Control Area with multiple requests for Transmission Service at a Point of Receipt, each of which is under 1,000 kW per hour, may consolidate their schedules at a common Point of Receipt into units of 1,000 kW per hour. Scheduling changes will be permitted up to thirty-five minutes before the start of the next clock hour provided that the Delivering Party and Receiving Party also agree to the schedule modification. The System Operator will furnish to the Delivering Party's system operator, hour-to-hour schedules equal to those furnished by the Receiving Party (unless reduced for losses) and shall deliver the capacity and energy provided by such schedules. Should the Transmission Customer, Delivering Party or Receiving Party revise or terminate any schedule, such party shall immediately notify the System Operator, and the System Operator shall have the right to adjust accordingly the schedule for capacity and energy to be received and to be delivered. (b) On and after the CMS/MSS Effective Date, unless other schedules are permitted pursuant to the NEPOOL System Rules, Day-Ahead Market schedules for Non-Firm Point-To-Point Transmission Service must be submitted to the Transmission Provider no later than noon of the day prior to the Dispatch Day. The Supply Offers and Demand Bids must be submitted to the System Operator by the noon deadline. The System Operator will furnish to the Delivering Party's system operator hour-to-hour schedules equal to those furnished by the Receiving Party and shall deliver the capacity and Energy provided by such schedules. Should the Transmission Customer, Delivering Party or Receiving Party revise or terminate any schedule, such party shall immediately notify the System Operator, and the System Operator shall have the right to adjust accordingly the schedule for capacity and Energy to be received and to be delivered. On and after the CMS/MSS Effective Date, unless other schedules are permitted pursuant to the NEPOOL System Rules, Real-Time Market schedules for Non-Firm Point-To-Point Transmission Service must be submitted to the Transmission Provider in accordance with the NEPOOL System Rules. The Supply Offers and Demand Bids must be submitted to the System Operator in accordance with the Market Rules. Scheduling changes will be permitted up to thirty-five minutes before the start of the next clock hour provided that the Delivering Party and Receiving Party also agree to the schedule modification. The System Operator will furnish to the Delivering Party's system operator hour-to-hour schedules equal to those furnished by the Receiving Party and shall deliver the capacity and Energy provided by such schedules. Should the Transmission Customer, Delivering Party or Receiving Party revise or terminate any schedule, such party shall immediately notify the System Operator, and the System Operator shall have the right to adjust accordingly the schedule for capacity and Energy to be received and to be delivered. 30.8 Curtailment or Interruption of Service: The System Operator reserves the right to effect a Curtailment, in whole or in part, of Non-Firm Point-To-Point Transmission Service provided under this Tariff for reliability reasons when an emergency or other unforeseen condition threatens to impair or degrade the reliability of the NEPOOL Transmission System. The System Operator reserves the right to effect an Interruption, in whole or in part, of Non-Firm Point-To-Point Transmission Service provided under this Tariff for economic reasons in order to accommodate (1) a request for Firm Transmission Service, (2) a request for Non-Firm Point-To-Point Transmission Service of greater duration, or (3) transmission service for Network Customers. The System Operator also will discontinue or reduce service to the Transmission Customer to the extent that deliveries for transmission are discontinued or reduced at the Point(s) of Receipt. Where required, Curtailments or Interruptions will be made on a non-discriminatory basis to the transaction(s) that effectively relieve the constraint; however, Non-Firm Point-To-Point Transmission Service shall be subordinate to Firm Transmission Service. If multiple transactions require Curtailment or Interruption, to the extent practicable and consistent with Good Utility Practice, Curtailments or Interruptions will be made to transactions of the shortest term (e.g., hourly non-firm transactions will be Curtailed or Interrupted before daily non-firm transactions and daily non-firm transactions will be Curtailed or Interrupted before weekly non-firm transactions). Transmission service for Network Customers will have a higher priority than any Non-Firm Point-To-Point Transmission Service under this Tariff. Non-Firm Point-To- Point Transmission Service furnished over secondary Point(s) of Receipt and Point(s) of Delivery will have a lower priority than any other Non-Firm Point-To-Point Transmission Service under this Tariff. The System Operator will provide advance notice of Curtailment or Interruption where such notice can be provided consistent with Good Utility Practice. In the event the System Operator exercises its right to effect a Curtailment, in whole or part, of Non-Firm Point-to-Point Transmission Service, no credit or other adjustment shall be provided as a result of the Curtailment with respect to the charge payable by the Customer. In the event the System Operator exercises its right to effect an Interruption, in whole or part, of Non-Firm Point-to-Point Transmission Service, the charge payable by the Customer shall be computed as if the term of service actually rendered were the term of service reserved; provided that an adjustment of the charge shall be made only when the Interruption is initiated by the System Operator, not when the Customer fails to deliver energy to NEPOOL. 31 Service Availability 31.1 General Conditions: Firm Point-To-Point Transmission Service over, on or across the NEPOOL Transmission System is available to any Transmission Customer that has met the applicable requirements of Section 31. 31.2 Determination of Available Transmission Capability: A description of NEPOOL's specific methodology for assessing available transmission capability posted on the NEPOOL OASIS(Section 5) is contained in Attachment C of this Tariff. In the event sufficient transmission capability may not exist to accommodate a service request, a System Impact Study will be performed. 31.3 Initiating Service in the Absence of an Executed Service Agreement: If the System Operator and the Transmission Customer requesting Firm Point-To- Point Transmission Service cannot agree on all the terms and conditions of the applicable Service Agreement, the System Operator will file with the Commission, within thirty days after the date the Transmission Customer provides written notification directing the System Operator to file, an unexecuted Service Agreement containing terms and conditions deemed appropriate by the System Operator for such requested transmission service. The service will be commenced subject to the Transmission Customer agreeing to (i) pay whatever rate the Commission ultimately determines to be just and reasonable, and (ii) comply with the terms and conditions of this Tariff including providing appropriate security deposits in accordance with the terms of Section 31.3. 31.4 Obligation to Provide Transmission Service that Requires Expansion or Modification of the Transmission System: If it is determined that the service requested in a Completed Application for Long-Term Firm Point-To- Point Transmission Service cannot be provided because of insufficient capability on the NEPOOL Transmission System, one or more Transmission Providers or other entities will be designated to use due diligence to expand or modify the NEPOOL Transmission System to provide the requested Long-Term Firm Point-To-Point Transmission Service, provided that the Transmission Customer agrees to compensate the Transmission Providers or other entities that will be responsible for the construction of any new facilities or upgrades for the costs of such new facilities or upgrades pursuant to the terms of Section 39. The System Operator and the designated Transmission Providers or other entities will conform to Good Utility Practice in determining the need for new transmission facilities or upgrades and in coordinating the design and construction of such facilities. This obligation applies only to those facilities that the designated Transmission Providers or other entities have the right to expand or modify. 31.5 Deferral of Service: Long-Term Firm Point-To-Point Transmission Service may be deferred until the designated Transmission Providers or other entities complete construction of new transmission facilities or upgrades needed to provide such service whenever it is determined that providing the requested service would, without such new facilities or upgrades, impair or degrade reliability to any existing Firm Transmission Service. 31.6 Real Power Losses: Real power losses are associated with all transmission service. The Transmission Provider is not obligated to provide real power losses. Until the CMS/MSS Effective Date, to the extent PTF losses are not specifically allocated through the market procedures provided for in Section 14 of the Agreement, point-to-point losses will be allocated on the basis of PTF average losses as established by the System Operator. The System Operator shall post on the OASIS the PTF average loss, which is initially set at 1.13% but shall be adjusted by the System Operator from time to time. The applicable real power loss factor shall be determined on the basis of PTF average losses. Average PTF losses shall be determined initially on an estimated basis, pending the accumulation of metered data needed to determine actual average PTF losses. On and after the CMS/MSS Effective Date, the cost of PTF losses shall be recovered through the Marginal Loss cost recovery mechanisms provided for in Section 14A.16 of the Agreement and Schedule 13 of the Tariff. 31.7 Load Shedding: To the extent that a system contingency exists on the NEPOOL Transmission System and the System Operator determines that it is necessary for the Participants and the Transmission Customer to shed load, the Parties shall shed load in accordance with the procedures under the Agreement and the rules adopted thereunder, or in accordance with other mutually agreed-to provisions. 32 Transmission Customer Responsibilities 32.2 Conditions Required of Transmission Customers: Firm Point-To-Point Transmission Service will be provided only if the following conditions are satisfied by the Transmission Customer: a. The Transmission Customer has pending a Completed Application for service; b. In the case of a Non-Participant, the Transmission Customer meets the creditworthiness criteria set forth in Section 11; c. The Transmission Customer will have arrangements in place for any other transmission service necessary to effect the delivery from the generating source to the Point of Receipt prior to the time service under the Tariff commences; d. The Transmission Customer agrees to pay for any facilities or upgrades constructed or any redispatch costs chargeable to such Transmission Customer under this Tariff, whether or not the Transmission Customer takes service for the full term of its reservation; and e. The Transmission Customer has executed a Service Agreement or has agreed to receive service pursuant to Section 29.3. 32.3 Transmission Customer Responsibility for Third-Party Arrangements: Any scheduling arrangements that may be required by other electric systems shall be the responsibility of the Transmission Customer requesting service. (If Local Network Service will be required, the System Operator shall notify the Transmission Customer and the affected Participants.) The Transmission Customer shall provide, unless waived by the System Operator, notification to the System Operator identifying such other electric systems and authorizing them to schedule the capacity and energy to be transmitted pursuant to this Tariff on behalf of the Receiving Party at the Point of Delivery or the Delivering Party at the Point of Receipt. The System Operator will undertake reasonable efforts to assist the Transmission Customer in making such arrangements, including without limitation, providing any information or data required by such other electric system pursuant to Good Utility Practice. 33 Procedures for Arranging Firm Point-To-Point Transmission Service 33.1 Application: A request for Firm Point-To-Point Transmission Service for periods of one year or longer must be made in an Application, delivered to ISO New England Inc., One Sullivan Road, Holyoke, MA 01040-2841 or such other address as may be specified from time to time. The request should be delivered at least sixty days in advance of the calendar month in which service is requested to commence. The System Operator will consider requests for such firm service on shorter notice when practicable. Requests for firm service for periods of less than one year will be subject to expedited procedures that will be negotiated between the System Operator and the party requesting service within the time constraints provided in Section 27.8. All Firm Point-To-Point Transmission Service requests should be submitted by transmitting the Completed Application to NEPOOL by mail or telefax. Each of these methods will provide a time-stamped record for establishing the priority of the Application. 33.2 Completed Application: A Completed Application for Firm Point-To-Point Transmission Service shall provide all of the information included at 18 C.F.R. 2.20 of the Commission's regulations, including but not limited to the following: (i) The identity, address, telephone number and facsimile number of the entity requesting service; (ii) A statement that the entity requesting service is, or will be upon commencement of service, an Eligible Customer under this Tariff; (iii) The location of the Point(s) of Receipt and Point(s) of Delivery and the identities of the Delivering Parties and the Receiving Parties; (iv) The location of the generating facility(ies) supplying the capacity and energy, and the location of the load ultimately served by the capacity and energy transmitted. The System Operator will treat this information as confidential in accordance with the NEPOOL information policy except to the extent that disclosure of this information is required by this Tariff, by regulatory or judicial order, or for reliability purposes pursuant to Good Utility Practice. The System Operator will treat this information consistent with the standards of conduct contained in 18 C.F.R. Part 37 of the Commission's regulations; (v) A description of the supply characteristics of the capacity and energy to be delivered; (vi) An estimate of the capacity and energy expected to be delivered to the Receiving Party; (vii) The Service Commencement Date and the term of the requested transmission service; and (viii) The transmission capacity requested for each Point of Receipt and each Point of Delivery on the NEPOOL Transmission System; customers may combine their requests for service in order to satisfy the minimum transmission capacity requirement. The System Operator will treat this information consistent with the standards of conduct contained in 18 C.F.R. Part 37 of the Commission's regulations. 33.3 Deposit: A Completed Application for Firm Point-To-Point Transmission Service by a Non-Participant shall also include a deposit of either one month's charge for Reserved Capacity or the full charge for Reserved Capacity for service requests of less than one month. If the Application is rejected by the System Operator because it does not meet the conditions for service as set forth herein, or in the case of requests for service arising in connection with losing bidders in a request for proposals (RFP), the deposit will be returned with Interest, less any reasonable Administrative Costs incurred by the System Operator or any affected Participants in connection with the review of the Application. The deposit also will be returned with Interest less any reasonable Administrative Costs incurred by the System Operator or any affected Participants if the new facilities or upgrades needed to provide the service cannot be completed. If an Application is withdrawn or the Eligible Customer decides not to enter into a Service Agreement for the Service, the deposit will be refunded in full, with Interest, less reasonable Administrative Costs incurred by the System Operator or any affected Participants to the extent such costs have not already been recovered from the Eligible Customer. The System Operator will provide to the Eligible Customer a complete accounting of all costs deducted from the refunded deposit, which the Eligible Customer may contest if there is a dispute concerning the deducted costs. Deposits associated with construction of new facilities or upgrades are subject to the provisions of Section 33. If a Service Agreement for Firm Point-To-Point Transmission Service is executed, the deposit, with interest, will be returned to the Transmission Customer upon expiration or termination of the Service Agreement. Applicable Interest will be calculated from the day the deposit is credited to the System Operator's account. 33.4 Notice of Deficient Application: If an Application fails to meet the requirements of this Tariff, the System Operator will notify the entity requesting service within fifteen days of the System Operator's receipt of the Application of the reasons for such failure. The System Operator will attempt to remedy minor deficiencies in the Application through informal communications with the Eligible Customer. If such efforts are unsuccessful, the System Operator will return the Application, along with any deposit (less the reasonable Administrative Costs incurred by the System Operator or any affected Participants in connection with the Application), with Interest. Upon receipt of a new or revised Application that fully complies with the requirements of this Tariff, the Eligible Customer will be assigned a new priority based upon the date of receipt by the System Operator of the new or revised Application. 33.5 Response to a Completed Application: Following receipt of a Completed Application for Firm Point-To-Point Transmission Service, a determination of available transmission capability will be made pursuant to Section 29.2. The Eligible Customer will be notified as soon as practicable, but not later than thirty days after the date of receipt of a Completed Application, if required, that either (i) service will be provided without performing a System Impact Study, or (ii) such a study is needed to evaluate the impact of the Application pursuant to Section 33.1. Responses by the System Operator must be made as soon as practicable to all Completed Applications and the timing of such responses must be made on a non-discriminatory basis. 33.6 Execution of Service Agreement: Whenever the System Operator determines that a System Impact Study is not required and that the requested service can be provided, it will notify the Eligible Customer as soon as practicable but no later than thirty days after receipt of the Completed Application, and will tender a Service Agreement to the Eligible Customer. Failure of an Eligible Customer to execute and return the Service Agreement or request the filing of an unexecuted Service Agreement pursuant to Section 29.3, within fifteen days after it is tendered by the System Operator shall be deemed a withdrawal and termination of the Application and any deposit (less the reasonable Administrative Costs incurred by the System Operator and any affected Participants in connection with the Application) submitted will be refunded with Interest. Nothing herein limits the right of an Eligible Customer to file another Application after such withdrawal and termination. Where a System Impact Study is required, the provisions of Section 33 will govern the execution of a Service Agreement. 33.7 Extensions for Commencement of Service: The Transmission Customer can obtain up to five one-year extensions for the commencement of service. The Transmission Customer may postpone service by paying a non-refundable annual reservation fee equal to one-month's charge for Firm Point-To-Point Transmission Service for each year or fraction thereof. If during any extension for the commencement of service an Eligible Customer submits a Completed Application for Firm Point-To-Point Transmission Service, and such request can be satisfied only by releasing all or part of the Transmission Customer's Reserved Capacity, the original Reserved Capacity will be released unless the following condition is satisfied: within thirty days, the original Transmission Customer agrees to pay the applicable rate for Firm Point-To- Point Transmission Service for its Reserved Capacity for the period that its reservation overlaps the period covered by such Eligible Customer's Completed Application. In the event the Transmission Customer elects to release the Reserved Capacity, the reservation fees or portions thereof previously paid will be forfeited. 34 Procedures for Arranging Non-Firm Point-To-Point Transmission Service 34.1 Application: Eligible Customers seeking Non-Firm Point-To-Point Transmission Service must submit a Completed Application to the System Operator. Applications should be submitted by entering the information listed below on the NEPOOL OASIS. 34.2 Completed Application: A Completed Application shall provide all of the information included in 18 C.F.R. 2.20 including but not limited to the following: (i) The identity, address, telephone number and facsimile number of the entity requesting service; (ii) A statement that the entity requesting service is, or will be upon commencement of service, an Eligible Customer under this Tariff; (iii) The Point(s) of Receipt and the Point(s) of Delivery; (iv) The maximum amount of capacity requested at each Point of Receipt and Point of Delivery; and (v) The proposed dates and hours for initiating and terminating transmission service hereunder. In addition to the information specified above, when required to properly evaluate system conditions, the System Operator also may ask the Transmission Customer to provide the following: (vi) The electrical location of the initial source of the power to be transmitted pursuant to the Transmission Customer's request for service; and (vii) The electrical location of the ultimate load. The System Operator will treat this information in (vi) and (vii) as confidential at the request of the Transmission Customer except to the extent that disclosure of this information is required by this Tariff, by regulatory or judicial order, or for reliability purposes pursuant to Good Utility Practice. The System Operator shall treat this information consistent with the standards of conduct contained in Part 37 of the Commission's regulations. 34.3 Reservation of Non-Firm Point-To-Point Transmission Service: Requests for monthly service shall be submitted no earlier than sixty days before service is to commence; requests for weekly service shall be submitted no earlier than fourteen days before service is to commence; requests for daily service shall be submitted no earlier than five days before service is to commence; and requests for hourly service shall be submitted no earlier than 9:00 a.m. the second day before service is to commence. Requests for service received later than noon of the day prior to the day service is scheduled to commence will be accommodated if practicable. 34.4 Determination of Available Transmission Capability: Following receipt of a tendered schedule the System Operator will make a determination on a non-discriminatory basis of available transmission capability pursuant to Section 29.2. Such determination shall be made as soon as reasonably practicable after receipt, but not later than the following time periods for the following terms of service (i) thirty-five minutes for hourly service, (ii) thirty-five minutes for daily service, (iii) four hours for weekly service, and (iv) two days for monthly service. 35 Additional Study Procedures For Firm Point-To-Point Transmission Service Requests 35.1 Notice of Need for System Impact Study: After receiving a request for Firm Point-To-Point Transmission Service, the System Operator will review the effect of the proposed service on the reliability requirements to meet existing and pending obligations of the Participants and Non-Participants, and the obligations of the particular Participants whose PTF facilities will be impacted by the proposed service and determine on a non-discriminatory basis whether a System Impact Study is needed. A description of the methodology for completing a System Impact Study is provided in Attachment D. If the System Operator determines that a System Impact Study is necessary to accommodate the requested service, as soon as practicable thereafter the System Operator will so inform the Eligible Customer and any affected Participants if the System Impact Study is to be performed by the Participants. If the likely result of the study is that a Direct Assignment Facility will be required, the study shall be performed by the affected Participants, subject to review by the System Operator. In such cases, the System Operator will within thirty days of receipt of a Completed Application, tender a System Impact Study agreement in the form of Exhibit I to this Tariff, or in any other form that is mutually agreed to, pursuant to which the Eligible Customer shall agree to reimburse the System Operator and any affected Participants for performing the required System Impact Study. For a service request to remain a Completed Application, the Eligible Customer shall execute the System Impact Study agreement and return it to the System Operator within fifteen days. If the Eligible Customer elects not to execute a System Impact Study agreement, its application shall be deemed withdrawn and its deposit (less the reasonable Administrative Costs incurred by the System Operator and any affected Participants in connection with the Application), will be returned with Interest. 35.2 System Impact Study Agreement and Cost Reimbursement: (i) The System Impact Study agreement shall clearly specify the System Operator's estimate of the actual cost, and time for completion of the System Impact Study. The charge shall not exceed the actual cost of the study. In performing the System Impact Study, the System Operator and any affected Participants will rely, to the extent reasonably practicable, on existing transmission planning studies. The Eligible Customer shall not be assessed a charge for such existing studies; however, the Eligible Customer shall be responsible for charges associated with any modifications to existing planning studies that are reasonably necessary to evaluate the impact of the Eligible Customer's request for service on the NEPOOL Transmission System. (ii) If in response to multiple Eligible Customers requesting service in relation to the same competitive solicitation, a single System Impact Study is sufficient for the System Operator to accommodate the requests for service, the costs of that study will be equitably prorated among the Eligible Customers. (iii) For System Impact Studies that the System Operator and any affected Participants conduct on behalf of the Transmission Providers, the Participants will record the cost of the System Impact Studies pursuant to Section 8.5. 35.3 System Impact Study Procedures: Upon receipt of an executed System Impact Study agreement, the System Operator and any affected Participants will use due diligence to complete the required System Impact Study within a sixty-day period. The System Impact Study, if required, shall identify any system constraints and redispatch options and the need for additional Direct Assignment Facilities or facility additions or upgrades required to provide the requested service. In the event that the required System Impact Study cannot be completed within such time period, the System Operator will so notify the Eligible Customer and provide an estimated completion date along with an explanation of the reasons why additional time is required to complete the required study and an estimate of any increase in cost which will result from the delay. A copy of the completed System Impact Study and related work papers shall be made available to the Eligible Customer. The System Operator will use the same due diligence in completing the System Impact Study for an Eligible Customer that is a Non-Participant as it uses when completing studies for the Participants. The System Operator will notify the Eligible Customer immediately upon completion of the System Impact Study if the NEPOOL Transmission System will be adequate to accommodate all or part of a request for service or that no costs are likely to be incurred for new transmission facilities or upgrades. Within fifteen days of completion of the System Impact Study, the Eligible Customer must execute a Service Agreement or request the filing of an unexecuted Service Agreement pursuant to Section 29.3, or the Application shall be deemed terminated and withdrawn. 35.4 Facilities Study Procedures: If a System Impact Study indicates that additions or upgrades to the NEPOOL Transmission System are needed to supply the Eligible Customer's service request, the System Operator, within thirty days of the completion of the System Impact Study, will tender to the Eligible Customer a Facilities Study agreement in the form of Attachment J to this Tariff, or in any other form that is mutually agreed to, which is to be entered into by the Eligible Customer and the System Operator and, if deemed necessary by the System Operator, by one or more affected Transmission Provider(s) and pursuant to which the Eligible Customer shall agree to reimburse the System Operator and any affected Transmission Providers or other entity designated by the System Operator for performing any required Facilities Study. For a service request to remain a Completed Application, the Eligible Customer shall execute the Facilities Study agreement and return it to the System Operator within fifteen days. If the Eligible Customer elects not to execute the Facilities Study agreement, its application shall be deemed withdrawn and its deposit, if any (less the reasonable Administrative Costs incurred by the System Operator and any affected Participants in connection with the Application), will be returned with Interest. Upon receipt of an executed Facilities Study agreement, the System Operator and any affected Transmission Provider(s) or other designated entity will use due diligence to cause the required Facilities Study to be completed within a sixty-day period. If a Facilities Study cannot be completed in the allotted time period, the System Operator will notify the Transmission Customer and provide an estimate of the time needed to reach a final determination and any resulting increase in the cost, along with an explanation of the reasons that additional time is required to complete the study. When completed, the Facilities Study shall include a good faith estimate of (i) the cost of Direct Assignment Facilities to be charged to the Transmission Customer, or (ii) the Transmission Customer's appropriate share of the cost of any required additions or upgrades, and (iii) the time required to complete such construction and initiate the requested service. The Transmission Customer shall provide a letter of credit or other reasonable form of security acceptable to the Transmission Providers or other entities that will be responsible for the construction of the new facilities or upgrades equivalent to the costs of the new facilities or upgrades and consistent with relevant commercial practices, as established by the Uniform Commercial Code. The Transmission Customer shall have thirty days to execute a Service Agreement, if required, or request the filing of an unexecuted Service Agreement with the Commission and provide the required letter of credit or other form of security or the request will no longer be a Completed Application and shall be deemed terminated and withdrawn. In addition to the foregoing, each Facilities Study shall contain a non- binding estimate from the System Operator of the incremental FCRs and associated ARRs, if any, resulting from the construction of the new facilities. After completion of the transmission upgrade or expansion, the System Operator shall determine the incremental FCRs and associated ARRs, if any, resulting from the upgrade or expansion. 35.5 Facilities Study Modifications: Any change in design arising from inability to site or construct proposed facilities will require development of a revised good faith estimate. New good faith estimates also will be required in the event of new statutory or regulatory requirements that are effective before the completion of construction or other circumstances beyond the control of the Transmission Providers or other entities that are responsible for the construction of the new facilities or upgrades and that significantly affect the final cost of the new facilities or upgrades to be charged to the Transmission Customer pursuant to the provisions of this Tariff. 35.6 Due Diligence in Completing New Facilities: The System Operator will use due diligence to designate Transmission Providers or other entities to add necessary facilities or upgrade the NEPOOL Transmission System within a reasonable time. A Transmission Provider or other entity will have no obligation to upgrade its existing or planned transmission system in order to provide the requested Firm Point-To-Point Transmission Service if doing so would impair system reliability or otherwise impair or degrade existing firm service. 35.7 Partial Interim Service: If the System Operator determines that there will not be adequate transmission capability to satisfy the full amount of a Completed Application for Long-Term Firm Point-To-Point Transmission Service, the portion of the requested Service that can be accommodated without addition of any facilities or upgrades and through redispatch will be offered and provided. However, there shall be no obligation to provide the incremental amount of requested Long-Term Firm Point-To-Point Transmission Service that requires the addition of facilities or upgrades to the NEPOOL Transmission System until such facilities or upgrades have been placed in service. 35.8 Expedited Procedures for New Facilities: In lieu of the procedures set forth above, the Eligible Customer shall have the option to expedite the process by requesting the System Operator to tender at one time, together with the results of required studies, an "Expedited Service Agreement" pursuant to which the Eligible Customer would agree to pay for all costs incurred pursuant to the terms of this Tariff. In order to exercise this option, the Eligible Customer shall request in writing an Expedited Service Agreement covering all of the above-specified items within thirty days of receiving the results of the System Impact Study identifying the need for facility additions or upgrades and costs to be incurred in providing the requested service. While the System Operator, on behalf of the Transmission Providers or other entities that will be responsible for constructing the new facilities or upgrades, agrees to provide the Eligible Customer with its best estimate of the new facility costs and other charges that may be incurred, such estimate shall not be binding and the Eligible Customer shall agree in writing to pay for all costs incurred pursuant to the provisions of this Tariff. The Eligible Customer shall execute and return such an Expedited Service Agreement within fifteen days of its receipt or the Eligible Customer's request for service will cease to be a Completed Application and will be deemed terminated and withdrawn. 36 Procedures if New Transmission Facilities for Firm Point-To-Point Transmission Service Cannot be Completed 36.1 Delays in Construction of New Facilities: If any event occurs that will materially affect the time for completion of new facilities for Firm Point-To-Point Service, or the ability to complete such facilities, the System Operator will promptly notify the Transmission Customer. In such circumstances, the System Operator will within thirty days of notifying the Transmission Customer of such delays, convene a technical meeting with the Transmission Customer and any affected Transmission Providers or other entities responsible for construction to evaluate the alternatives available to the Transmission Customer. The System Operator and the affected Transmission Providers or other entities will make available to the Transmission Customer studies and work papers related to the delay, including all information that is in the possession of the System Operator or the Transmission Providers or other entities that are responsible for the construction of the new facilities or upgrades that is reasonably needed by the Transmission Customer to evaluate any alternatives. 36.2 Alternatives to the Original Facility Additions: When the review process of Section 34.1 determines that one or more alternatives exist to the originally planned construction project, the System Operator will present such alternatives for consideration by the Transmission Customer. If, upon review of any alternatives, the Transmission Customer desires to proceed with its Completed Application subject to construction of the alternative facilities, it may request the System Operator to submit a revised Service Agreement. If the alternative approach solely involves Non-Firm Point-To-Point Transmission Service, the System Operator will promptly tender a Service Agreement for Non-Firm Point-To-Point Transmission Service providing for such service. In the event the System Operator and the affected Participants or other entities responsible for construction conclude that no reasonable alternative exists and the Transmission Customer disagrees, the Transmission Customer may seek relief under the dispute resolution procedures pursuant to Section 12 or it may refer the dispute to the Commission for resolution. 36.3 Refund Obligation for Unfinished Facility Additions: If the System Operator, the affected Transmission Providers or other entities responsible for construction and the Transmission Customer mutually agree that no other reasonable alternatives exist and the requested service cannot be provided out of existing capability under the conditions of this Tariff, the obligation to provide the requested Firm Point-To-Point Transmission Service shall terminate and any deposit made by the Transmission Customer shall be returned, with Interest. The Transmission Customer shall be responsible for all costs prudently incurred by the System Operator and by the Transmission Providers or other entities that have been responsible for the construction of the new facilities or upgrades through the date that any required regulatory approval is denied or construction is suspended and for cost of removal, if necessary, of facilities constructed prior to suspension. 37 Provisions Relating to Transmission Construction and Services on the Systems of Other Utilities 37.1 Responsibility for Third-Party System Additions: Neither the System Operator nor any Participant which is not the Transmission Customer will be responsible for making arrangements for any necessary engineering, permitting, and construction of transmission or distribution facilities on the system(s) of any other entity or for obtaining any regulatory approval for such facilities. The System Operator will undertake reasonable efforts to assist the Transmission Customer in obtaining such arrangements, including without limitation, providing any information or data required by such other electric system pursuant to Good Utility Practice. 37.2 Coordination of Third-Party System Additions: In circumstances where the need for transmission facilities or upgrades is identified pursuant to the provisions of this Tariff, and if such upgrades further require the addition of transmission facilities on third-party systems, the System Operator and the Transmission Providers or other entities that are responsible for the construction of any new facilities or upgrades on the NEPOOL Transmission System will have the right to coordinate construction on the NEPOOL Transmission System with the construction required by the third parties. The System Operator and the Transmission Providers or other entities that are responsible for the construction of any new facilities or upgrades on the NEPOOL Transmission System may, after consultation with the Transmission Customer and representatives of such other systems, defer construction of new transmission facilities or upgrades on the NEPOOL Transmission System if the new transmission facilities on another system cannot be completed in a timely manner. The System Operator will notify the Transmission Customer in writing of the basis for any decision to defer construction and the specific problems that must be resolved before the construction of new facilities will be initiated or resumed. Within sixty days of receiving written notification by the System Operator of a decision to defer construction pursuant to this section, the Transmission Customer may challenge the decision in accordance with the dispute resolution procedures contained in Section 12 or it may refer the dispute to the Commission for resolution. 38 Changes in Service Specifications 38.1 Modifications on a Non-Firm Basis: The Transmission Customer taking Firm Point-To-Point Transmission Service may submit a request to the System Operator for transmission service on a non-firm basis over Point(s) of Receipt and Point(s) of Delivery other than those specified in the Service Agreement ("Secondary Receipt and Delivery Points"), in amounts not to exceed the Transmission Customer's firm capacity reservation, without incurring an additional Non-Firm Point-to-Point Transmission Service charge or executing a new Service Agreement, subject to the following conditions: (a) service provided over Secondary Receipt and Delivery Points will be non-firm only, on an as-available basis, and will not displace any firm or non-firm service reserved or scheduled by Participants or Non-Participants under this Tariff or by the Participants on behalf of their Native Load Customers or Excepted Transactions; (b) the sum of all Firm Point-To-Point Transmission Service and Non-Firm Point-To-Point Transmission Service provided to the Transmission Customer at any time pursuant to this section shall not exceed the Reserved Capacity specified in the relevant Service Agreement under which such services are provided; (c) the Transmission Customer shall retain its right to schedule Firm Point-To-Point Transmission Service at the Point(s) of Receipt and Point(s) of Delivery specified in the relevant Service Agreement in the amount of the Transmission Customer's original capacity reservation; and (d) service over Secondary Receipt and Delivery Points on a non-firm basis shall not require the filing of an Application for Non-Firm Point-to-Point Transmission Service under the Tariff. However, all other requirements of this Tariff (except as to transmission rates) shall apply to transmission service on a non-firm basis over Secondary Receipt and Delivery Points. 38.2 Modification on a Firm Basis: Any request by a Transmission Customer to modify Point(s) of Receipt and Point(s) of Delivery on a firm basis shall be treated as a new request for service in accordance with Section 31, except that such Transmission Customer shall not be obligated to pay any additional deposit if the capacity reservation does not exceed the amount reserved in the existing Service Agreement. While such new request is pending, the Transmission Customer shall retain its priority for service at the firm Receipt Point(s) and Delivery Point(s) specified in the Transmission Customer's Service Agreement. 39 Sale, Assignment or Transfer of Transmission Service 39.1 Procedures for Sale, Assignment or Transfer of Service: Subject to Commission action on any necessary filings, a Transmission Customer may sell, assign, or transfer all or a portion of its rights under its Service Agreement, but only to another Eligible Customer (the "Assignee"). The Transmission Customer that sells, assigns or transfers its rights under its Service Agreement is hereafter referred to as the "Reseller." Compensation to the Reseller shall not exceed the higher of (i) the original rate paid by the Reseller, (ii) the maximum applicable rate on file under this Tariff at the time of the assignment, or (iii) the Reseller's opportunity cost capped at the Participants' cost of expansion. If the Assignee does not request any change in the Point(s) of Receipt or the Point(s) of Delivery, or a change in any other term or condition set forth in the original Service Agreement, the Assignee shall receive the same services as did the Reseller and the priority of service for the Assignee shall be the same as that of the Reseller. A Reseller shall notify the System Operator as soon as possible after any sale, assignment or transfer of service occurs, but in any event, notification must be provided prior to any provision of service to the Assignee. The Assignee shall be subject to all terms and conditions of this Tariff. If the Assignee requests a change in service, the reservation priority of service will be determined by the System Operator pursuant to Section 27.2. The sale, resale or assignment of FCRs is governed by Schedule 14 of the Tariff, and this Section 37.1 is not applicable to such sales, resales and assignments. 39.2 Limitations on Assignment or Transfer of Service: If the Assignee requests a change in the Point(s) of Receipt or Point(s) of Delivery, or a change in any other specifications set forth in the original Service Agreement, the System Operator will consent to such change subject to the provisions of this Tariff, provided that the change will not impair the operation and reliability of the Participants' generation, transmission, or distribution systems. The Assignee shall compensate the System Operator and any affected Participants for performing any System Impact Study needed to evaluate the capability of the NEPOOL Transmission System to accommodate the proposed change and any additional costs resulting from such change. The Reseller shall remain liable for the performance of all obligations under the Service Agreement, except as specifically agreed to by the System Operator, the Reseller and the Assignee through an amendment to the Service Agreement. 39.3 Information on Assignment or Transfer of Service: In accordance with Section 5, Transmission Customers may use the NEPOOL OASIS to post information regarding transmission capacity available for resale. 40 Metering and Power Factor Correction at Receipt and Delivery Points(s) 40.1 Transmission Customer Obligations: Unless the System Operator otherwise agrees, the Transmission Customer shall be responsible for installing and maintaining compatible metering and communications equipment to accurately account for the capacity and energy being transmitted under this Tariff and to communicate the information to the System Operator. Unless otherwise agreed, such equipment shall remain the property of the Transmission Provider. 40.2 NEPOOL Access to Metering Data: The System Operator will have access to such metering data as may reasonably be required to facilitate measurements and billing under the Service Agreement. 40.3 Power Factor: Unless otherwise agreed, the Transmission Customer is required to maintain a power factor within the same range as the Participants maintain pursuant to Good Utility Practice and applicable NEPOOL requirements. The power factor requirements are specified in the Service Agreement, where applicable. 41 Compensation for New Facilities and Redispatch Costs Whenever a System Impact Study performed in connection with the provision of Firm Point-To-Point Transmission Service identifies the need for new facilities or upgrades, the Transmission Customer shall be responsible for such costs to the extent they are consistent with Commission policy. Whenever a System Impact Study identifies capacity constraints that may be relieved more economically by redispatching the Participants' resources than by building new facilities or upgrading existing facilities to eliminate such constraints, the Transmission Customer shall be responsible for the redispatch costs to the extent consistent with applicable Commission policy. VI. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION SERVICE) The Participants will provide NEPOOL Regional Network Service (Network Integration Transmission Service), as described in Part II of this Tariff to Participants and Non-Participants pursuant to the applicable terms and conditions contained in this Tariff. Part II of this Tariff specifies certain terms and conditions which are generally applicable to the receipt of Regional Network Service by both Participants and Non-Participants. This Part VI specifies additional provisions with respect to the provision of Regional Network Service. 42 Nature of Regional Network Service 42.1 Scope of Service: Regional Network Service (Network Integration Transmission Service) is the transmission service described in Section 14 that allows Network Customers to efficiently and economically utilize their resources and Interchange Transactions to serve their Network Load located in the NEPOOL Control Area and any additional load that may be designated pursuant to Section 43.3 of this Tariff. The Network Customer taking Regional Network Service must obtain or provide Ancillary Services pursuant to Section 4. 42.2 Transmission Provider Responsibilities: The NEPOOL Participants will plan, construct, operate and maintain the NEPOOL Transmission System in accordance with Good Utility Practice in order to provide the Network Customer with Regional Network Service over the NEPOOL Transmission System. Subject to Section 48, each Participant which is individually a Transmission Provider, on behalf of its Native Load Customers, shall be required to designate resources and loads in the same manner as any Network Customer under Part VI of this Tariff. This information must be consistent with the information used by the Transmission Provider to calculate available transmission capacity. The Participants shall include the Network Customer's Network Load in NEPOOL Transmission System planning and shall, consistent with Good Utility Practice, endeavor to construct and place into service sufficient transmission capacity to deliver Network Resources to serve the Network Customer's Network Load on a basis comparable to the Participants' delivery of their own generating and purchased resources to their Native Load Customers. 42.3 Network Integration Transmission Service: The Participants that are individually Transmission Providers will provide firm transmission service over the NEPOOL Transmission System to the Network Customer for the delivery of energy and/or capacity from its resources to service its Network Loads on a basis that is comparable to the Participants' use of the NEPOOL Transmission System to reliably serve their Native Load Customers. 42.4 Secondary Service: The Network Customer may use the NEPOOL Transmission System to deliver energy and/or capacity to its Network Loads from resources that have not been designated as Network Resources. Such energy and capacity shall be transmitted, on an as-available basis, at no additional charge, except for any applicable charges for Congestion Cost and/or Marginal Loss cost recovery, which are recovered from Non-Participants as part of Regional Network Service and from Participants under the Agreement. Deliveries from resources other than Network Resources will have a higher priority than any Non-Firm Point-to-Point Transmission Service under this Tariff. 42.5 Real Power Losses: Real Power Losses are associated with all transmission service. The Transmission Provider is not obligated to provide Real Power Losses. To the extent PTF losses are not specifically allocated through the market procedures provided for in Section 14 of the Agreement, total remaining PTF losses, minus point-to-point losses, shall be allocated to all load on a load ratio basis. 42.6 Restrictions on Use of Service: The Network Customer is entitled to use Regional Network Service for any of the uses specified in Part II of this Tariff. 43 Initiating Service 43.1 Condition Precedent for Receiving Service: Subject to the terms and conditions of Parts II and VI of this Tariff, the Participants will provide Regional Network Service to any Eligible Customer, provided that, except as otherwise provided in Section 48, (i) the Eligible Customer completes an Application for service as provided under Part VI of this Tariff, (ii) the Eligible Customer and the System Operator complete the technical arrangements set forth in Sections 41.3 and 41.4, (iii) the Eligible Customer executes a Service Agreement in the form of Attachment B for service under Part VI of this Tariff or requests in writing that the Transmission Provider file a proposed unexecuted Service Agreement with the Commission, and (iv) the Eligible Customer executes a Network Operating Agreement in the form of Exhibit H to this Tariff, or in any other form that is mutually agreed to, with the Transmission Provider. 43.2 Application Procedures: Except as otherwise provided in Section 48, an Eligible Customer requesting Network Integration Transmission Service under this Tariff must submit an Application, with a deposit approximating the charge for one month of service, to the System Operator as far as possible in advance of the month in which service is to commence. Completed Applications for Network Integration Transmission Service will be assigned a priority according to the date and time the Application is received, with the earliest Application receiving the highest priority. Applications should be submitted by entering the information listed below on the NEPOOL OASIS to the extent feasible. A Completed Application shall provide all of the information included in 18 CFR 2.20 including but not limited to the following: (i) The identity, address, telephone number and facsimile number of the party requesting service; (ii) A statement that the party requesting service is, or will be upon commencement of service, an Eligible Customer under this Tariff; (iii) A description of the Network Load at each delivery point. This description should separately identify and provide the Eligible Customer's best estimate of the total loads to be served at each transmission voltage level, and the loads to be served from each Transmission Provider substation at the same transmission voltage level. The description should include a ten-year forecast of summer and winter load resource requirements beginning with the first year after the service is scheduled to commence; (iv) The amount and location of any interruptible loads included in the Network Load. This shall include the summer and winter capacity requirements for each interruptible load (had such load not been interruptible), that portion of the load subject to Interruption, the conditions under which an Interruption can be implemented and any limitations on the amount and frequency of Interruptions. An Eligible Customer should identify the amount of interruptible customer load (if any) included in the ten-year load forecast provided in response to (iii) above; (v) A description of Network Resources (current and ten-year projection), which shall include, for each Network Resource, if not otherwise available to the System Operator: - - Unit size and amount of capacity from that unit to be designated as Network Resource - - VAR capability (both leading and lagging) of all generators - - Operating restrictions - - Any periods of restricted operations throughout the year - - Maintenance schedules - - Minimum loading level of unit - - Normal operating level of unit - - Any must-run unit designations required for system reliability or contract reasons - - Approximate variable dispatch price ($/MWH) for redispatch computations - - Arrangements governing sale and delivery of power to third parties from generating facilities located in the NEPOOL Control Area, where only a portion of unit output is designated as a Network Resource - - Description of external purchased power designated as a Network Resource including source of supply, Control Area location, transmission arrangements and delivery point(s) to the Transmission Provider's Transmission System; (vi) Description of Eligible Customer's transmission system: - - Load flow and stability data, such as real and reactive parts of the load, lines, transformers, reactive devices and load type, including normal and emergency ratings of all transmission equipment in a load flow format compatible with that used by the Participants - - Operating restrictions needed for reliability - - Operating guides employed by system operators - - Contractual restrictions or committed uses of the Eligible Customer's transmission system, other than the Eligible Customer's Network Loads and Resources - - Location of Network Resources described in subsection (v) above - - ten-year projection of system expansions or upgrades - - Transmission System maps that include any proposed expansions or upgrades - - Thermal ratings of Eligible Customer's Control Area ties with other Control Areas; and (vii) Service Commencement Date and the term of the requested Network Integration Transmission Service. The minimum term for Network Integration Transmission Service is one year. Unless the Eligible Customer and the System Operator agree to a different time frame, the System Operator must acknowledge the request within ten days of receipt. The acknowledgment must include a date by which a response, including a Service Agreement, will be sent to the Eligible Customer. If an Application fails to meet the requirements of this section, the System Operator shall notify the Eligible Customer requesting service within fifteen days of receipt and specify the reasons for such failure. Wherever possible, the System Operator will attempt to remedy deficiencies in the Application through informal communications with the Eligible Customer. If such efforts are unsuccessful, the System Operator shall return the Application without prejudice to the Eligible Customer, who may thereafter file a new or revised Application that fully complies with the requirements of this section. The Eligible Customer will be assigned a new priority consistent with the date of the new or revised Application. The System Operator shall treat this information consistent with the standards of conduct contained in Part 37 of the Commission's regulations. 43.3 Technical Arrangements to be Completed Prior to Commencement of Service: Except as otherwise provided in Section 48, Regional Network Service shall not commence until the Participants and the Network Customer, or a third party, have completed installation of all equipment specified under a Network Operating Agreement consistent with Good Utility Practice and any additional requirements reasonably and consistently imposed to ensure the reliable operation of the NEPOOL Transmission System. The Participants shall exercise reasonable efforts, in coordination with the Network Customer, to complete such arrangements as soon as practicable taking into consideration the Service Commencement Date. 43.4 Network Customer Facilities: The provision of Regional Network Service shall be conditioned upon the Network Customer's constructing, maintaining and operating the facilities on its side of each delivery point or interconnection necessary to reliably deliver capacity and energy from the NEPOOL Transmission System to the Network Customer. The Network Customer shall be solely responsible for constructing or installing and operating and maintaining all facilities on the Network Customer's side of each such delivery point or interconnection. 43.5 Filing of Service Agreement: The System Operator will file Service Agreements with the Commission in compliance with applicable Commission regulations. 44 Network Resources 44.1 Designation of Network Resources: The designation of generation resources as Network Resources shall be effected automatically in accordance with the definition thereof for Participant Network Customers. A Network Customer shall designate to the System Operator those Network Resources which are owned, purchased or leased by it. The Network Resources so designated may not include resources, or any portion thereof, that are committed for sale to non-designated third party load or otherwise cannot be called upon to meet the Network Customer's Network Load on a non-interruptible basis, or to the extent that the resource is being delivered directly to a load being served with Internal Point-to-Point Service. Any owned, purchased or leased resources that were serving the Network Customer's loads under firm agreements entered into on or before the Compliance Effective Date shall be deemed to continue to be so owned, purchased or leased by it until the Network Customer informs the System Operator of a change. Nothing in this Section is intended to relieve any customer of its obligation to pay the charge for Internal Point-to-Point Service deliveries of Network Resources to it. 44.2 Designation of New Network Resources: The Network Customer shall identify the Network Resources which are owned, purchased or leased by it to the System Operator with as much advance notice as practicable. A designation of a Network Resource as owned, purchased or leased by the Customer must be made by a notice to the System Operator. 44.3 Termination of Network Resources: The Network Customer may terminate the designation of all or part of a Network Resource as owned, purchased or leased by it at any time but should provide notification to the System Operator as soon as reasonably practicable. 44.4 Network Customer Redispatch Obligation: As a condition to receiving Network Integration Transmission Service, the Network Customer agrees to redispatch its Network Resources as requested by the System Operator pursuant to Section 45.2. To the extent practical, the redispatch of resources pursuant to this section shall be on a least cost, non-discriminatory basis between all Network Customers and the Participants. 44.5 Transmission Arrangements for Network Resources Not Physically Interconnected With The NEPOOL Transmission System: The Network Customer shall be responsible for any arrangements necessary to deliver capacity and energy from a Network Resource not physically interconnected with the NEPOOL Transmission System. The System Operator will undertake reasonable efforts to assist the Network Customer in obtaining such arrangements, including without limitation, providing any information or data required by such other entity pursuant to Good Utility Practice. 44.6 Limitation on Designation of Resources: The Network Customer must demonstrate that it owns, leases or has committed to purchase an Entitlement in a generation resource pursuant to an executed contract in order to designate the generating resource to serve its Network Load. Alternatively, the Network Customer may establish that execution of a contract is contingent upon the availability of transmission service under Part II of this Tariff. 44.7 Use of Interface Capacity by the Network Customer: There is no limitation upon a Network Customer's use of the NEPOOL Transmission System at any particular interface to integrate the Network Customer's resources (or substitute purchases in Interchange Transactions) with its Network Loads. However, a Network Customer's use of the NEPOOL total interface capacity with other transmission systems to serve its Network Load may not exceed the Network Customer's load. 45 Designation of Network Load 45.1 Network Load: Except as otherwise provided in Section 48, the Network Customer must designate the individual Network Loads on whose behalf the Participants will provide through NEPOOL Network Integration Transmission Service. The Network Loads shall be specified in the Service Agreement. 45.2 New Network Loads Connected With the NEPOOL Transmission System: The Network Customer shall provide the System Operator with as much advance notice as reasonably practicable of the designation of new Network Load that will be added to the NEPOOL Transmission System. A designation of new Network Load must be made through a modification of service pursuant to a new Application. The Participants will use due diligence to install or cause to be installed any transmission facilities required to interconnect a new Network Load designated by the Network Customer. The costs of new facilities required to interconnect a new Network Load shall be determined in accordance with the procedures provided in Section 44.4 and shall be charged to the Network Customer in accordance with Commission policy and Schedule 11. 45.3 Network Load Not Physically Interconnected with the NEPOOL Transmission System: This section applies to both initial designation pursuant to Section 43.1 and the subsequent addition of new Network Load not physically interconnected with the NEPOOL Transmission System. To the extent that the Network Customer desires to obtain transmission service for a load outside the NEPOOL Control Area, the Network Customer shall have the option of (1) electing to include the entire load as Network Load for all purposes under Part VI of this Tariff and designating resources to serve such additional Network Load, or (2) excluding that entire load from its Network Load. To the extent that the Network Customer gives notice of its intent to add a new Network Load as part of its Network Load pursuant to this section the request must be made through a modification of service pursuant to a new Application, and shall be available only so long as a scheduling and interconnection agreement acceptable to the System Operator shall be required to be in effect with the Control Area in which the load is located. Charges for such portion of the service shall be based on the Through or Out Service rate applied to the amount reserved for the Network Load which is not physically interconnected with the NEPOOL Transmission System. 45.4 New Interconnection Points: To the extent the Network Customer desires to add a new Delivery Point or interconnection point between the NEPOOL Transmission System and a Network Load, the Network Customer shall provide the System Operator with as much advance notice as reasonably practicable. 45.5 Changes in Service Requests: Under no circumstances shall the Network Customer's decision to cancel or delay a requested change in Network Integration Transmission Service (the addition of a new Network Resource, if any, or designation of a new Network Load) in any way relieve the Network Customer of its obligation to pay the costs of transmission facilities constructed by the Participants and charged to the Network Customer as reflected in the Service Agreement or other appropriate agreement. However, the System Operator must treat any requested change in Network Integration Transmission Service in a non-discriminatory manner. 45.6 Annual Load and Resource Information Updates: The Network Customer shall provide the System Operator with annual updates of Network Load and Network Resource forecasts consistent with those included in its Application under Part VI of this Tariff. The Network Customer also shall provide the System Operator with timely written notice of material changes in any other information provided in its Application relating to the Network Customer's Network Load, Network Resources, its transmission system or other aspects of its facilities or operations affecting the Participants' ability to provide reliable service. 46 Additional Study Procedures For Network Integration Transmission Service Requests 46.1 Notice of Need for System Impact Study: After receiving a request for service, the System Operator shall review the effect of the requested service on the reliability requirements to meet existing and pending obligations of the Participant(s) and on the obligations of the particular Participant(s) whose PTF facilities will be impacted by the proposed service and shall determine on a non-discriminatory basis whether a System Impact Study is needed. A description of the methodology for completing a System Impact Study is provided in Attachment D. If the System Operator determines that a System Impact Study is necessary to accommodate the requested service, it shall as soon as practicable inform the Eligible Customer and any affected Participant(s) if the System Impact Study is to be performed by the Participant(s). If the likely result of the study is that a Direct Assignment Facility will be required, the study shall be performed by the affected Participant(s), subject to review by the System Operator. In such cases, the System Operator shall within thirty days of receipt of a Completed Application, tender a System Impact Study agreement in the form of Attachment I to this Tariff, or in any other form that is mutually agreed to, pursuant to which the Eligible Customer shall agree to reimburse the System Operator and any affected Participant for performing the required System Impact Study. For a service request to remain a Completed Application, the Eligible Customer shall execute a System Impact Study agreement and return it to the System Operator within fifteen days. If the Eligible Customer elects not to execute a System Impact Study agreement, its Application shall be deemed withdrawn and its deposit (less the reasonable Administrative Costs incurred by the System Operator and any affected Participant(s)) shall be returned with Interest. 46.2 System Impact Study Agreement and Cost Reimbursement: (i) The System Impact Study agreement, whether in the form detailed in Attachment I or in any other form that is mutually agreed to, will clearly specify the System Operator's actual estimate of the actual cost, and time for completion of the System Impact Study. The actual charge shall not exceed the actual cost of the study. In performing the System Impact Study, the System Operator and the affected Participants shall rely, to the extent reasonably practicable, on existing transmission planning studies. The Eligible Customer will not be assessed a charge for such existing studies; however, the Eligible Customer will be responsible for charges associated with any modifications to existing planning studies that are reasonably necessary to evaluate the impact of the Eligible Customer's request for service on the NEPOOL Transmission System. (ii) If in response to multiple Eligible Customers requesting service in relation to the same competitive solicitation, a single System Impact Study is sufficient for the System Operator and the affected Participants to accommodate the service requests, the costs of that study shall be prorated among the Eligible Customers. (iii) For System Impact Studies that the System Operator and any affected Participants conduct on behalf of a Participant which is a Transmission Provider, the Participant will record the cost of the System Impact Studies pursuant to Section 8.5. 46.3 System Impact Study Procedures: Upon receipt of an executed System Impact Study agreement, the System Operator and any affected Participants will use due diligence to complete the required System Impact Study within a 60-day period. The System Impact Study, if required, shall identify any system constraints, redispatch options, or the need for additional Direct Assignment Facilities or other facility additions or upgrades to provide the requested service. In the event that the System Operator and any affected Participants are unable to complete the required System Impact Study within such time period, the System Operator shall so notify the Eligible Customer and provide an estimated completion date along with an explanation of the reasons why additional time is required to complete the required studies and an estimate of any increase in cost which will result from the delay. A copy of the completed System Impact Study and related work papers shall be made available to the Eligible Customer. The System Operator will use the same due diligence in completing the System Impact Study for an Eligible Customer as it uses when completing studies for the Participants. The System Operator shall notify the Eligible Customer immediately upon completion of the System Impact Study if the NEPOOL Transmission System will be adequate to accommodate all or part of a request for service or that no costs are likely to be incurred for new transmission facilities or upgrades. In order for a request to remain a Completed Application, within fifteen days of completion of the System Impact Study the Eligible Customer must execute a Service Agreement or request the filing of an unexecuted Service Agreement, or the Application shall be deemed terminated and withdrawn. 46.4 Facilities Study Procedures: If a System Impact Study indicates that additions or upgrades to the NEPOOL Transmission System are needed to supply the Eligible Customer's service request, the System Operator, within thirty days of the completion of the System Impact Study, shall tender to the Eligible Customer a Facilities Study agreement in the form of Attachment J to this Tariff, or in any other form that is mutually agreed to, which is to be entered into by the Eligible Customer and the System Operator and, if deemed necessary by the System Operator, by one or more affected Transmission Provider(s) and pursuant to which the Eligible Customer shall agree to reimburse the System Operator and any affected Transmission Provider(s) for performing the required Facilities Study. For a service request to remain a Completed Application, the Eligible Customer shall execute the Facilities Study agreement and return it to the System Operator within fifteen days. If the Eligible Customer elects not to execute a Facilities Study agreement, its Application shall be deemed withdrawn and its deposit, if any (less the reasonable Administrative Costs incurred by the System Operator and any affected Transmission Provider(s)), shall be returned with Interest. Upon receipt of an executed Facilities Study agreement, the System Operator and any affected Transmission Provider(s), will use due diligence to complete the required Facilities Study within a sixty-day period. If the System Operator and any affected Transmission Provider(s) are unable to complete the Facilities Study in the allotted time period, the System Operator shall notify the Eligible Customer and provide an estimate of the time needed to reach a final determination and any resulting increase in the cost, along with an explanation of the reasons that additional time is required to complete the study. When completed, the Facilities Study will include a good faith estimate of (i) the cost of Direct Assignment Facilities to be charged to the Eligible Customer, (ii) the Eligible Customer's appropriate share of the cost of any required Network Upgrades, and (iii) the time required to complete such construction and initiate the requested service. The Eligible Customer shall provide a letter of credit or other reasonable form of security acceptable to the affected Transmission Provider(s) or other entities that will be responsible for the construction of the new facilities or upgrades equivalent to the costs of new facilities or upgrades consistent with commercial practices as established by the Uniform Commercial Code. The Eligible Customer shall have thirty days to execute a Service Agreement or request the filing of an unexecuted Service Agreement and provide the required letter of credit or other form of security or the request no longer will be a Completed Application and shall be deemed terminated and withdrawn. In addition to the foregoing, each Facilities Study shall contain a non- binding estimate from the System Operator of the incremental FCRs and associated ARRs, if any, resulting from the construction of the new facilities. After completion of the transmission upgrade or expansion, the System Operator shall determine the incremental FCRs and associated ARRs, if any, resulting from the upgrade or expansion. 47 Load Shedding and Curtailments 47.1 Procedures: Prior to the Service Commencement Date, the System Operator and the Network Customer shall establish Load Shedding and Curtailment procedures pursuant to the Network Operating Agreement with the objective of responding to contingencies on the NEPOOL Transmission System. The parties will implement such programs during any period when the System Operator determines that a system contingency exists and such procedures are necessary to alleviate such contingency. The System Operator will notify all affected Network Customers in a timely manner of any scheduled Curtailment. 47.2 Transmission Constraints: During any period when the System Operator determines that a transmission constraint exists on the NEPOOL Transmission System, and such constraint may impair the reliability of the NEPOOL Transmission System, the System Operator will take whatever actions, consistent with Good Utility Practice, that are reasonably necessary to maintain the reliability of the system. To the extent the System Operator determines that the reliability of the System can be maintained by redispatching resources, the System Operator will initiate procedures pursuant to a Network Operating Agreement to redispatch all the Network Customer's resources and the Participants' own resources on a least-cost basis without regard to the ownership of such resources. Any redispatch under this section may not unduly discriminate between the Participants' use of the NEPOOL Transmission System on behalf of their Native Load Customers and any Network Customer's use of the Transmission System to serve its designated Network Load. 47.3 Cost Responsibility for Relieving Transmission Constraints: (a) Until the earlier of the CMS/MSS Effective Date or the implementation effective date of an order issued by the Commission directing a different allocation of Congestion Costs, to the extent not otherwise covered under the Network Operating Agreement, whenever the System Operator implements least- cost redispatch procedures in response to a transmission constraint, the customers taking Internal Point-to-Point Service and/or Through or Out Service and Network Customers will each bear a proportionate share of the total redispatch cost. (b) On and after the CMS/MSS Effective Date, to the extent not otherwise covered under the Network Operating Agreement, whenever the System Operator implements least-cost redispatch procedures in response to a transmission constraint, the customers taking Internal Point-to-Point Service and/or Through or Out Service and Network Customers will each bear a share of the total redispatch cost in accordance with Section 14A.12 and 14A.17 of the Agreement and Schedule 13 of the Tariff. 47.4 Curtailments of Scheduled Deliveries: If a transmission constraint on the NEPOOL Transmission System cannot be relieved through the implementation of least-cost redispatch procedures and the System Operator determines that it is necessary to effect a Curtailment of scheduled deliveries, such schedule shall be curtailed in accordance with the Network Operating Agreement. 47.5 Allocation of Curtailments: The System Operator shall on a non- discriminatory basis, effect a Curtailment of the transaction(s) that effectively relieve the constraint. However, to the extent practicable and consistent with Good Utility Practice, any Curtailment will be shared by the customers taking Internal Point-to-Point Service and/or Through or Out Service and Network Customers on a non-discriminatory basis. The System Operator shall not direct the Network Customer to effect a Curtailment of schedules to an extent greater than the System Operator would effect a Curtailment of the Participants' schedules under similar circumstances. Notwithstanding the preceding provisions of this Section, Import Transactions shall be scheduled and curtailed in accordance with Section 14.1. 47.6 Load Shedding: To the extent that a system contingency exists on the NEPOOL Transmission System and the System Operator determines that it is necessary for the customers taking Internal Point-to-Point Service and/or Through or Out Service and Network Customers to shed load, the Parties shall shed load in accordance with previously established procedures under the Network Operating Agreement, or in accordance with other mutually agreed-to provisions. 47.7 System Reliability: Notwithstanding any other provisions of this Tariff, the System Operator reserves the right, consistent with Good Utility Practice and on a not unduly discriminatory basis, to effect a Curtailment of Network Integration Transmission Service without liability on the part of the System Operator or the Participants for the purpose of making necessary adjustments to, changes in, or repairs on the Participants' lines, substations and facilities, and in cases where the continuance of Network Integration Transmission Service would endanger persons or property. In the event of any adverse condition(s) or disturbance(s) on the NEPOOL Transmission System or on any other system(s) directly or indirectly interconnected with the NEPOOL Transmission System, the System Operator, consistent with Good Utility Practice, also may effect a Curtailment of Network Integration Transmission Service in order to (i) limit the extent or damage of the adverse condition(s) or disturbance(s), (ii) prevent damage to generating or transmission facilities, or (iii) expedite restoration of service. The System Operator will give the Network Customer as much advance notice as is practicable in the event of such Curtailment. Any Curtailment of Network Integration Transmission Service will be not unduly discriminatory relative to the Participants' use of the Transmission System on behalf of their Native Load Customers. The Network Operating Agreement shall specify the rate treatment and all related terms and conditions applicable in the event that the Network Customer fails to respond to established Load Shedding and Curtailment procedures. 48 Rates and Charges The Network Customer shall pay Transmission Providers for any Direct Assignment Facilities and its share of the cost of any required Network Upgrades and applicable study costs consistent with Commission policy, along with the payment to the System Operator of the charges for Ancillary Services and the charge for Regional Network Service provided under this Tariff. 48.1 Determination of Network Customer's Monthly Network Load: The Network Customer's "Monthly Network Load" is its hourly load (including its designated Network Load not physically interconnected with the Transmission Provider under Section 43.3) coincident with the coincident aggregate load of the Participants and other Network Customers served in each Local Network in the hour in which the coincident load is at its maximum for the month ("Monthly Peak"). 49 Operating Arrangements 49.1 Operation under The Network Operating Agreement: The Network Customer shall plan, construct, operate and maintain its facilities in accordance with Good Utility Practice and in conformance with the Network Operating Agreement which shall be in the form of Exhibit H to this Tariff, or in any other form that is mutually agreed to. 49.2 Network Operating Agreement: The terms and conditions under which the Network Customer shall operate its facilities and the technical and operational matters associated with the implementation of Part VI of the Tariff shall be specified in the Network Operating Agreement. The Network Operating Agreement shall provide for the Parties to (i) operate and maintain equipment necessary for integrating the Network Customer within the NEPOOL Transmission System (including, but not limited to, remote terminal units, metering, communications equipment and relaying equipment), (ii) transfer data between the System Operator and the Network Customer (including, but not limited to, heat rates and operational characteristics of Network Resources, generation schedules for units outside the NEPOOL Transmission System, interchange schedules, unit outputs for redispatch required under Section 45, voltage schedules, loss factors and other real time data), (iii) use software programs required for data links and constraint dispatching, (iv) exchange data on forecasted loads and resources necessary for long-term planning, and (v) address any other technical and operational considerations required for implementation of Part VI of this Tariff, including scheduling protocols. The Network Operating Agreement will recognize that the Network Customer shall either (i) operate as a Control Area under applicable guidelines of the North American Electric Reliability Council (NERC) and the Northeast Power Coordinating Council (NPCC), (ii) satisfy its Control Area requirements, including all necessary Ancillary Services, by contracting with the System Operator and the Participants, or (iii) satisfy its Control Area requirements, including all necessary Ancillary Services, by contracting with another entity, consistent with Good Utility Practice, which satisfies NERC and NPCC requirements. The System Operator shall not unreasonably refuse to accept contractual arrangements with another entity for Ancillary Services. 49.3 Network Operating Committee: A Network Operating Committee (Committee) shall be established to coordinate operating criteria for the Parties' respective responsibilities under the Network Operating Agreement, where the Network Customer is not a Participant. Each Network Customer shall be entitled to have at least one representative on the Committee. The Committee shall meet from time to time as need requires, but no less than once each calendar year. 50 Scope of Application of Part VI to Participants (a) All Participants which are receiving Regional Network Service on the Compliance Effective Date shall be deemed to have requested to continue Regional Network Service and to have identified as their Network Resources and Network Load all of their resources and load as of the Compliance Effective Date, unless they elect in accordance with Section 3.3 of this Tariff to receive Internal Point-to-Point Service at one or more Point(s) of Delivery from one or more Point(s) of Receipt. (b) In view of the operational, informational and financial obligations imposed on Participants by the Agreement, the NEPOOL Financial Assurance Policy (which is set forth in Attachment L hereto) and NEPOOL rules, the following requirements shall not be applicable to Participants: (1) the Application requirement specified in Sections 41.1(i) and 42 of this Tariff; (2) the deposit requirement specified in Section 41.2 of this Tariff; (3) the requirement that a Network Customer execute a Service Agreement, as specified in Section 41.1 (iii) of this Tariff; provided that a Service Agreement shall be required (i) for any Participant initially taking Regional Network Service after the Compliance Effective Date, (ii) if a Participant serves load not physically interconnected with the NEPOOL Transmission System pursuant to Section 43.3 of this Tariff or (iii) if a new facility or upgrade is to be constructed pursuant to Section 44.4 of this Tariff; (4) the requirement that a Network Customer execute a Network Operating Agreement, as specified in Section 41.1(iv) of this Tariff; provided that a Network Operating Agreement shall be required if a Participant serves load not physically interconnected with the NEPOOL Transmission System pursuant to Section 43.3 of this Tariff; and (5) the requirement that a Network Customer provide an annual update of Network Load and Network Resource forecasts, as specified in Section 43.6 of the Tariff. Notwithstanding the foregoing, if the System Operator determines at any time that it requires information from a Participant which would be contained in an Application submitted pursuant to Section 41.2 or an annual update of Network Load and Network Resource forecasts provided pursuant to Section 43.6, it has the right to require that the Customer provide the information. VII. TRANSMISSION PLANNING, ADDITIONS AND MODIFICATIONS 51 General Additions to or modifications of the NEPOOL Transmission System may be required or permitted under this Tariff, and be subject to related rights, obligations and procedures, in any of the following circumstances: (a) An addition or modification may be required under Part V or Part VI of the Tariff in order to meet a new request for Point-to-Point Service or Regional Network Service. Where such an addition or modification is to be effected, the rights and obligations of the System Operator, the Transmission Providers and Transmission Customers shall be determined in accordance with the applicable provisions of Parts V and VI. (b) An addition or modification may be required to permit the interconnection of a new or modified generating unit or the interconnection of an Elective Transmission Upgrade. Where such an addition or modification is to be effected, the rights and obligations of the System Operator, the Transmission Owners, and the Generator Owner or applicant for an Elective Transmission Upgrade, shall be determined in accordance with Section 50 and Schedules 11 and 12. (c) A Reliability Upgrade, an Economic Upgrade or a NEMA Upgrade may be required or proposed pursuant to a NEPOOL Transmission Plan. Where a Reliability Upgrade, an Economic Upgrade, or a NEMA Upgrade is to be effected, the rights and obligations of the System Operator, the Transmission Owners and other Participants shall be determined in accordance with Schedule 12. (d) A Quick Fix Upgrade may be identified for implementation in 2000 or 2001. Where a Quick Fix Upgrade is to be effected, the rights and obligations of the System Operator, the Transmission Owners and other Participants shall be determined in accordance with Section 52. (e) Consistent with reliability and safety standards, Transmission Owners, the operators of affected satellites in the NEPOOL Control Area and the System Operator will coordinate scheduled generation and transmission facility outages so as to minimize, to the extent practicable, Congestion and RMR-related costs. The System Operator shall provide Transmission Owners and the operators of the affected satellites with such information as is necessary to enable them to perform this function. Any information provided to Transmission Owners and the operators of the affected satellites pursuant to this provision will be subject to all the applicable requirements of the Commission's Order 889. These provisions for PTF additions and modifications are not intended to be exclusive. Nothing in this Tariff is intended to preclude any entity from identifying and constructing Elective Transmission Upgrades on a merchant or other basis, so long as it obtains all required legal rights and approvals and satisfies applicable System Operator, NEPOOL, and Transmission Owner requirements relating to such facilities. An addition or modification which constitutes PTF under the Agreement and the Tariff shall become part of the NEPOOL Transmission System and shall be fully subject to this Tariff, whether or not all or any part of the costs of the addition or modification are included in Pool-Supported PTF costs. The priorities, if any, with respect to the use of the addition or modification as among the owner and supporters of the addition or modification and other Transmission Customers shall be determined under Parts I to VI, inclusive, of this Tariff. To the extent that a Generator Owner is responsible for the costs of a Generator Interconnection Related Upgrade or Elective Transmission Upgrade, or an entity other than a Generator Owner is responsible for costs of any other system upgrade, the Generator Owner or entity which supports part or all of the costs of the addition or modification shall be entitled to a share of any associated ARRs equivalent to the share of the total costs of such upgrade which it supports, as assigned and allocated in accordance with Schedules 14 and 15. Any incremental FCRs resulting from Generator Interconnection Related Upgrades or other upgrades shall be auctioned along with other FCRs in accordance with Schedule 14. Nothing in this Tariff is intended to waive the legal rights of any person or the rights of the Transmission Owners under Section 17A of the Agreement. If issues of cost allocation arise with respect to the recovery of any of the costs provided for in this Part VII, or in Schedules 11 or 12, such issues shall be subject to determination by the Commission in the appropriate proceeding. 52 Interconnection Procedures and Requirements 52.1 Interconnection of Generating Unit Under the Minimum Interconnection Standard: Any Generator Owner that proposes after the Compliance Effective Date (i) to place in service a new generating unit at a site which the Generator Owner owns or controls, or which it has the right to acquire or control, and that will interconnect to the NEPOOL Transmission System, or (ii) to materially change and increase the capacity of an existing generating unit located in the NEPOOL Control Area shall be obligated to: (a) complete and submit to the System Operator a standard application, which is available from the System Operator ("Interconnection Application"), along with the administrative fee and description of its proposal and site information required by the Interconnection Application, as well as any additional information that may be reasonably required by the System Operator; (b) within fifteen (15) days of its tender by the System Operator (which tender shall occur no later than thirty (30) days following System Operator's receipt of a complete Interconnection Application), enter into an agreement with the System Operator and, if deemed necessary by the System Operator, one or more affected Transmission Owners to provide for the conduct of a System Impact Study to determine what additions or modifications to the NEPOOL Transmission System and to the Non-PTF system are required in order to permit its generating unit to interconnect in a manner that avoids any significant adverse effect on system reliability, stability, and operability, including protecting against the degradation of transfer capability for interfaces affected by the unit ("Minimum Interconnection Standard"). If the Generator Owner does not enter into the System Impact Study agreement within the above time period, its Interconnection Application shall be deemed terminated and withdrawn. The System Impact Study shall be conducted in accordance with the procedures, and subject to the obligations, specified in Sections 33.2 and 33.3 and Attachment D of this Tariff and using the form of agreement specified in Attachment I of this Tariff, except that: (1) references therein to transmission service shall be deemed to refer to interconnection; (2) references therein to Eligible Customer or Transmission Customer shall be deemed to refer to the Generator Owner; (3) Attachment D shall be applied so that the interconnection is studied on a Minimum Interconnection Standard basis; and (4) any references to, or requirements for, a Service Agreement in Section 33.3 shall be inapplicable; (c) if a System Impact Study indicates that additions or modifications to the NEPOOL Transmission System are required in order to permit the Generator Owner's generating unit to be interconnected with the NEPOOL Transmission System on a basis satisfying the Minimum Interconnection Standard, within fifteen (15) days of its tender by the System Operator (which tender shall occur no later than thirty (30) days following the completion of the System Impact Study), enter into an agreement with the System Operator and, if deemed necessary by the System Operator, one or more affected Transmission Owners to provide for the conduct of a Facilities Study. The Facilities Study shall be conducted in accordance with the procedures, and subject to the obligations, specified in Sections 33.4 and 33.5 of this Tariff, and using the form of agreement specified in Attachment J of this Tariff, except that: (1) references therein to transmission service shall be deemed to refer to interconnection; (2) references therein to Eligible Customer or Transmission Customer shall be deemed to refer to the Generator Owner; and (3) any references to, or requirements for, a Service Agreement in Section 33.4 shall be inapplicable. In lieu of a Facilities Study, if transmission system additions or modifications are required, within forty-five (45) days of submission of the final System Impact Study report to the Generator Owner, the Generator Owner, the affected Transmission Owner(s) and, when necessary, the System Operator may establish an agreement for expedited interconnection. While the Transmission Owner(s) or other entities that will be responsible for constructing the new facilities or modifications pursuant to an expedited interconnection agreement will provide the Generator Owner with its best estimate of the new facility costs and other charges that may be incurred, such estimate shall not be binding and the Generator Owner shall agree in writing to pay for all applicable costs ultimately incurred. If the Generator Owner does not enter into the Facilities Study or expedited interconnection agreement within the above time periods, its Interconnection Application shall be deemed terminated and withdrawn; (d) if the System Impact Study indicates that no additions or modifications are required, work with the interconnecting Transmission Owner(s) to establish appropriate interconnection agreements and provide the security, credit assurances and/or deposits that the Transmission Owner determines is necessary to ensure payment within ninety (90) days following issuance of a final System Impact Study report. If the studies conducted pursuant to this Section indicate that additions or modifications to PTF or Non-PTF are required: (i) the Generator Owner and the interconnecting Transmission Owner(s) shall enter into appropriate interconnection agreements, including security and deposit provisions, or the Generator Owner may request, upon providing the security, credit assurances, and/or deposits required by the Transmission Owner, the filing with the Commission by the Transmission Owner of an unexecuted agreement; and (ii) within ninety (90) days following issuance of the final Facilities Study report, or within ninety (90) days following execution of an agreement for expedited interconnection, the Generator Owner shall provide the security, credit assurances, and/or deposits that the Transmission Owner determines is necessary to ensure payment to the extent not already provided under (i) above; and (iii) the Transmission Owner or its designee designated to perform the construction of the additions or modifications shall, in accordance with the terms of the arrangements described in this paragraph and subject to Sections 18.4 and 18.5 of the Agreement, use due diligence to design and effect the proposed construction. If the Generator Owner fails to enter into an interconnection agreement or to request the filing of an unexecuted agreement within ninety (90) days following issuance of the final Facilities Study report, or if it fails to provide the security, credit assurances and/or deposits required by the Transmission Owner, its Interconnection Application shall be deemed terminated and withdrawn. Sections 34.1, 34.2 (other than those sentences referring to Service Agreements), 34.3 and 35 of the Tariff shall be applicable to the facilities construction or modification, except that: (1) references therein to transmission service shall be deemed to refer to interconnection; and (2) references therein to Eligible Customer or Transmission Customer shall be deemed to refer to the Generator Owner. (e) satisfy any applicable requirements under the applicable tariff of the relevant Transmission Owner on file with the Commission (except for those relating to System Impact Studies and Facilities Studies, which will be performed on a unified basis by the System Operator in accordance with this Section) in the event that transmission service will be needed across Non-PTF of the Transmission Owner; and (f) submit its proposal for review in accordance with Section 18.4 of the Agreement and related NEPOOL System Rules and thereafter take any action required pursuant to Section 18.5 of the Agreement as a result of such Section 18.4 review. Upon the satisfaction of the obligations described in (a), (b), (c), (d), (e), and (f) above, and subject to all necessary legal rights and approvals being obtained, the Generator Owner's unit shall have the right to be interconnected with the NEPOOL Transmission System. A Generator Owner proposing the interconnection of a new or materially changed generating unit shall be responsible for the costs of any required Generator Interconnection Related Upgrades which do not constitute costs of Pool-Supported PTF in accordance with Schedule 11, and shall comply with the Transmission Owner's requirements with respect to security, credit assurances and/or deposits in accordance with Schedule 11. With respect to upgrades required to meet the Minimum Interconnection Standard, and consistent with reliability and safety standards, Transmission Owners, the interconnecting Generator Owner and the System Operator shall jointly use their best reasonable efforts to develop Congestion and RMR- related cost estimates and construction schedules designed to minimize, to the extent practicable, the financial impact of the upgrade-related transmission outages on all affected parties. The development of the aforementioned construction schedule shall include consultation with any affected existing Generator Owner. To the extent it is possible to implement a procedure that facilitates the ability of interconnecting Generator Owners and Transmission Owners to minimize, to the extent reasonably practicable, the associated RMR and Congestion cost exposure prior to implementation of CMS, the parties agree to continue the use of the procedure after the implementation of CMS to the extent that such procedures are consistent with CMS. There shall be no payment under this Tariff of lost opportunity costs to Generator Owners for generating units that are dispatched down or dispatched off. In connection with the consultation required by this paragraph, the affected parties shall, as necessary, enter into non- disclosure agreements protecting commercially sensitive information from unlimited disclosure in order to facilitate the development of construction schedules designed to minimize the financial impact on the affected parties. For purposes of determining whether a generating unit is to be deemed a new generating unit placed in service after the Compliance Effective Date so that it is obligated to satisfy the requirements of this Section, any unit which, on January 1, 1999, was in active or deactivated status, as classified in the April 1998 NEPOOL Capacity, Energy, Loads and Transmission Report and any other generating unit in active status on that date which may receive deactivated status after that date, subject to criteria developed by the appropriate NEPOOL committee, may retain this status for a period not to exceed three (3) years from the date the unit receives deactivated status and shall not be obligated to comply with this Section if it is reactivated during such period, but if not reactivated during such period shall be deemed retired at the end of such period for purposes of this Section. Notwithstanding the foregoing, if a proposal is submitted and approved under Section 18.4 of the Agreement during the three-year period to 1) reactivate, 2) materially modify and reactivate or 3) replace the deactivated unit, the unit may be reactivated without material modification without compliance with this Section. Further, notwithstanding the foregoing, any unit in deactivated status prior to January 1, 1999 shall be entitled to retain such status through December 31, 2001 whether or not a submission is made under Section 18.4 during such period. 52.2 Interconnection of Elective Transmission Upgrades: Any Participant or Non-Participant may undertake the design, construction and interconnection of an Elective Transmission Upgrade ("Elective Transmission Upgrade Applicant"). In undertaking the design, construction and interconnection of an Elective Transmission Upgrade, the Elective Transmission Upgrade Applicant shall undertake, as a condition to its right to place the Elective Transmission Upgrade in service, the following procedures and otherwise comply with the relevant NEPOOL System Rules: (a) complete and submit to the System Operator a standard application, which is available from the System Operator, along with the administrative fee, that describes the Elective Transmission Upgrade in sufficient detail to enable the System Operator to identify the location of the upgrade, affected Transmission Owners, and the purpose of the Elective Transmission Upgrade; (b) if required by the System Operator, enter into a System Impact Study Agreement with the System Operator and, if deemed necessary by the System Operator, one or more affected Transmission Owners to determine the effects, if any, of the upgrade on the NEPOOL Transmission System and Non-PTF. The System Operator may permit the Elective Transmission Upgrade Applicant to undertake on its own a System Impact Study in consultation with the System Operator and affected Transmission Owner(s). (c) upon receipt of the completed System Impact Study, notify the System Operator whether it will seek approval of the Elective Transmission Upgrade pursuant to Section 18.4 of the Agreement and, if so, submit its proposal for review in accordance with Section 18.4 of the Agreement and relevant rules and procedures of NEPOOL and the System Operator; and (d) after obtaining approval for the Elective Transmission Upgrade, or after the time periods set forth in Section 18.4 of the Agreement have passed without the Elective Transmission Upgrade Transmission Applicant receiving notice in writing that its proposed upgrade will have a significant adverse effect upon the reliability or operating characteristics of its system or the system of one or more Participants, the Elective Transmission Upgrade Applicant shall enter into an interconnection agreement with the affected Transmission Owners. To the extent necessary and appropriate, the Elective Transmission Upgrade Applicant shall also enter into support agreements with the affected Transmission Owners. The Elective Transmission Upgrade Applicant also may request, upon providing the security, credit assurances, and/or deposits required by the affected Transmission Owners, the filing with the Commission by the Transmission Owner of unexecuted interconnection and support agreements. The Elective Transmission Upgrade Applicant shall obtain all necessary legal rights and approvals for the construction and maintenance of the upgrade and shall cooperate with Transmission Owners in obtaining all necessary legal rights and approvals for the construction and maintenance of additions or modifications, if any, required in conjunction with the upgrade. Upon satisfaction of the obligations described in (a), (b), (c), and (d) above, subject to all necessary legal rights and approvals being obtained, and upon satisfaction of any conditions placed on the Elective Transmission Upgrade Applicant pursuant to Sections 18.4 and 18.5 of the Agreement, the Elective Transmission Upgrade shall have the right to be interconnected with the NEPOOL Transmission System. The Participant or Non-Participant that constructs and/or maintains the Elective Transmission Upgrade shall be responsible for 100% of all of the costs of said upgrade and of any additions to or modifications of the NEPOOL Transmission System and Non-PTF that are required to accommodate the Elective Transmission Upgrade. A request for rate treatment of an Elective Transmission Upgrade, if any, shall be determined by the Commission in the appropriate proceeding. The completion of a System Impact Study for an Elective Transmission Upgrade and the construction of an Elective Transmission Upgrade shall not delay the completion of a System Impact Study or Facilities Study for a Generator Owner applying to interconnect under the Minimum Interconnection Standard and shall not delay the construction of upgrades for a generating unit interconnecting under the Minimum Interconnection Standard. 53 Regional Transmission Planning and Expansion 53.1 General: Commencing with the NEPOOL Transmission Plan that will be effective for the period 2001 and beyond, and subject to the final outcome of rehearing requests and any appeals with respect to the Commission's June 28, 2000 CMS/MSS Order issued in Docket Nos. EL00-62-000 et al., and subject to any changes resulting from compliance with the requirements of Commission Order No. 2000, the process defined in this Section 51, as amended from time to time, shall be utilized for regional transmission planning. No provisions of this Section 51 reflect or are intended to reflect agreement among the Participants as to the ownership of any Upgrades to the NEPOOL Transmission System built pursuant to an RFP under Section 51.6. The NEPOOL Transmission Plan and transmission enhancement and expansion studies shall be completed with the involvement of the Transmission Expansion Advisory Committee and the Transmission Planning Committee. These two committees shall be established in accordance with the provisions of Section 51.2, and shall be responsible for the functions identified in that Section. 53.2 Responsibilities of the Transmission Expansion Advisory Committee, Transmission Planning Committee and System Operator: (a) A Transmission Expansion Advisory Committee shall be established to perform the functions set forth in subsection (b) below. This Committee shall not be subject to the governance provisions of the Agreement nor shall it have any of the authority conferred by those provisions. It shall have a Chair and Secretary, who shall be appointed by the chief executive officer of the System Operator after consultation with the Participant members of the Liaison Committee established pursuant to Section 11C of the Agreement. Before appointing an individual to the position of the Chair or Secretary, the System Operator shall notify the Committee of the proposed assignment and, consistent with its personnel practices, provide any other information about the individual reasonably requested by the Committee. The chief executive officer of the System Operator shall consider the input of the members of the Committee in selecting, removing or replacing such officers. If members of the Committee representing five or more entities conclude that the performance of the Chair or Secretary is not satisfactory, they may identify their concerns to the System Operator. If after 30 days their concerns have not been reasonably addressed, they may request that the Participants Committee consider a resolution to remove the officer. A vote of the Participants Committee to remove an officer of the Transmission Expansion Advisory Committee shall be immediately effective and binding on the System Operator and not subject to any appeal. If the Participants Committee votes to remove an officer of the Transmission Expansion Advisory Committee, the System Operator shall appoint a replacement officer in accordance with this subsection. (b) The Transmission Expansion Advisory Committee shall be responsible for providing input to and feedback for both the development of the NEPOOL Transmission Plan and the conduct of enhancement and expansion studies. Such input and feedback may include comment on policy issues, objectives, study scope, and solutions and alternatives for consideration in the development of the NEPOOL Transmission Plan. Any entity may designate a member to the Transmission Expansion Advisory Committee by providing written notice to the Secretary of that Committee identifying the name of the entity represented by the member and the member's name, address, telephone number, facsimile number and electronic mail address. The entity may remove or replace such member at any time by written notice to the Secretary of the Transmission Expansion Advisory Committee. (c) A Transmission Planning Committee shall be established to perform the functions set forth in subsection (d) below. This Committee shall not be subject to the governance provisions of the Agreement nor shall it have any of the authority conferred by those provisions. It shall have a Chair and Secretary, who shall be appointed by the chief executive officer of the System Operator after consultation with the members of the Committee. The Chair shall be an employee of the System Operator. Before an individual is appointed to the position of the Chair or Secretary, the System Operator shall, consistent with its personnel practices, provide any information about the individual reasonably requested by members of the Transmission Planning Committee. The chief executive officer of the System Operator shall consider the input of the members of this Committee in selecting, removing or replacing such officers. (d) The Transmission Planning Committee shall be responsible for providing the data, information and analytical support necessary to perform studies as required, and shall identify engineering and technical issues and engineering and technical solutions and alternatives with respect to the work within the scope of the NEPOOL Transmission Plan. The Transmission Planning Committee shall be comprised of at least one representative from the System Operator and from each of the Transmission Owners. The Transmission Owners' representatives must be "transmission function employees" subject to the code of conduct requirements of 18 C.F.R. 37.4, as such requirements may be amended or superseded from time to time. The System Operator may, after notice to the Transmission Planning Committee, invite representatives of other entities to attend a discussion by the Transmission Planning Committee of an Upgrade proposed by such entities, provided such representatives either are by confidentiality agreement or otherwise, subject to the same limitations on the use and disclosure of information as, "transmission function employees" subject to the standards of conduct requirements of 18 C.F.R. 37.4, as such requirements may be amended or superseded from time to time. The Transmission Planning Committee shall not be subject to the requirements of Section 7.6 of the Agreement and, except as provided above, attendance at any meeting shall be restricted solely to members of that Committee. (e) In addition to the responsibilities specifically assigned to the System Operator in other Sections of this Section 51, those NEPOOL Transmission System planning functions required by this Section 51 that are not functions of the Transmission Expansion Advisory Committee, the Transmission Planning Committee or another NEPOOL Committee or entity under other provisions of the Agreement or this Tariff, shall be the sole responsibility of the System Operator; provided, that the assignment of any technical, engineering or analytical planning function to the Transmission Planning Committee is not intended to preclude the performance of any technical, engineering or analytical planning function by the System Operator. For Upgrades proposed to reduce Congestion Costs, the System Operator also shall perform and publish analysis that identifies the costs and benefits of the Upgrade and, to the extent feasible, the distribution of such benefits in the region. 53.3 NEPOOL Transmission Plan: Principles, Scope, and Contents: (a) The NEPOOL Transmission Plan shall conform to Good Utility Practice, applicable reliability principles, guidelines, criteria, rules, procedures and standards of NERC and NPCC and any of their successors, applicable publicly available local reliability criteria, and the NEPOOL System Rules, as they may be amended from time to time. (b) The NEPOOL Transmission Plan shall consolidate regional transmission needs into a single plan which is assessed on the basis of maintaining the NEPOOL Control Area's reliability while accounting for economic and environmental considerations. The NEPOOL Transmission Plan shall be based on the results of a comprehensive transmission expansion and enhancement study conducted at least once every three years in accordance with Section 51.5. The NEPOOL Transmission Plan shall also account for at least the ensuing five year load and capacity forecasts, proposed generation additions and retirements, proposed Merchant Transmission Facility additions, and the requirements for system restoration services (but will not include development of a system restoration plan). Based on the foregoing requirements and considerations, the NEPOOL Transmission Plan shall identify for at least each of the ensuing five years a list of proposed enhancements and expansions to the NEPOOL Transmission System not otherwise proposed as Merchant Transmission Facilities that are determined to be appropriate at the time of the issuance of the Plan (collectively referred to as "Upgrades"). That list of Upgrades is subject to adjustment in accordance with subsection (c) of Section 51.4 and, accordingly, an Upgrade included in a Plan may subsequently be removed from the Plan and not be constructed. The NEPOOL Transmission Plan shall also identify any projected need for Transfer Capability during or before the five-year period, based on information at that time, for which Upgrades have not been identified. (c) The NEPOOL Transmission Plan shall be designed (i) to avoid unnecessary duplication of facilities; (ii) to avoid the imposition of unreasonable costs upon any Transmission Owner, Transmission Customer or other user of a transmission facility; (iii) to take into account the legal and contractual rights and obligations of the Transmission Owners and the transmission-related legal and contractual rights and obligations of any other entity; and (iv) to provide for coordination with existing transmission systems and with appropriate interregional and local expansion plans. 53.4 Procedures for Developing a NEPOOL Transmission Plan: (a) An initial draft of a five-year NEPOOL Transmission Plan for the years 2001-2005 (the "2000 Plan") shall be assembled and provided to Participants as soon as reasonably practicable. The 2000 Plan shall reflect the list of additions and modifications to the NEPOOL Transmission System that have been identified by the System Operator and by Transmission Owners for their individual systems or that have been jointly planned by Transmission Owners by December 31, 2000. The 2000 Plan shall reflect the results of reliability-related studies including those already identified in Form 715 filings with the Commission as of March 31, 2000; provided that the 2000 Plan may also reflect studies completed after March 31, 2000 and prior to December 31, 2000. The 2000 Plan shall be issued by December 31, 2000 and shall be deemed to be the NEPOOL Transmission Plan referred to in Section (3) of Schedule 12. (b) The starting point for the NEPOOL Transmission Plan for the years 2002-2006 (the "2001 Plan") and each subsequent NEPOOL Transmission Plan shall be the list of Upgrades included in the prior Plan, as updated, that have not been completed at that time. The 2001 Plan and each subsequent Plan shall include for each year covered by that Plan on a coordinated regional basis a list of additional Upgrades identified in enhancement and expansion studies performed pursuant to Section 51.5. That list shall identify separately (i) Reliability Upgrades, (ii) Economic Upgrades, (iii) Generator Interconnection Related Upgrades to be effected pursuant to Section 50 to accommodate new generation interconnections that have satisfied the requirements under Sections 18.4 and 18.5 of the Agreement, and (iv) NEMA Upgrades as appropriate. The Plan shall also include a description of the reasons for any new Upgrades proposed in the Plan, including the information identified in subsection (g) below, or for any removal of Upgrades from the Plan pursuant to subsection (c) below. (c) An Upgrade may be added to the NEPOOL Transmission Plan at any time in a given year, provided there has been consultation with and consideration of input from the Transmission Expansion Advisory Committee and the Transmission Planning Committee, within the scope of their respective functions as specified in subsections (b) and (d) of Section 51.2. Similarly, provided there has been consultation with and consideration of input from the Transmission Expansion Advisory Committee and the Transmission Planning Committee, within the scope of their functions as specified in subsections (b) and (d) of Section 51.2, the NEPOOL Transmission Plan may be revised to remove a proposed Upgrade if the market responds by proposing alternative generation projects, Merchant Transmission Facilities in accordance with Section 51.8, or demand-side projects, or other circumstances arise such that the need for the Upgrade no longer exists; provided that the entity responsible for the construction of the Upgrade is reimbursed for any costs prudently incurred or prudently committed to be incurred in connection with the planning, preparation for construction, and/or construction of the Upgrades proposed for removal from the Plan. All Upgrades proposed to be added or removed during this planning process must meet the requirements of subsection (a) of Section 51.3. (d) The Transmission Owners, those entities requesting transmission service or interconnection, and any other entities proposing to provide facilities to be integrated into the NEPOOL Control Area or alternatives to such facilities shall supply upon request and subject to applicable confidentiality requirements of the NEPOOL Information Policy any information and data reasonably required to prepare a NEPOOL Transmission Plan or to perform a transmission enhancement and expansion study. Any confidential cost estimate for a proposed Upgrade to the NEPOOL Transmission System that is or may be subject to subsection (a) of Section 51.6 shall be considered by the System Operator to be competitively sensitive, confidential information and shall be considered the estimator's confidential information under the NEPOOL Information Policy, and shall not be disclosed by the System Operator to other entities that may be eligible to submit a proposal in accordance with Section 51.6, including, without limitation, other Transmission Owners. Any other information or data provided shall be subject to the rights and obligations of the NEPOOL Information Policy. (e) The NEPOOL Transmission Plan shall be developed in coordination with the transmission systems of the surrounding Control Areas and the regional reliability councils, as appropriate. (f) At the initiation of an effort to update a Plan or develop a new Plan, the System Operator shall solicit input for the updated or new Plan from members of the Transmission Expansion Advisory Committee and Transmission Planning Committee. These Committees shall meet to perform their respective functions in connection with the preparation of the NEPOOL Transmission Plan, as specified in subsections (b) and (d) of Section 51.2. Thereafter, drafts of the NEPOOL Transmission Plan shall be provided to the Transmission Expansion Advisory Committee and input from that Committee shall be received and considered in preparing and revising subsequent drafts. Before a final draft of any proposed NEPOOL Transmission Plan is presented to the System Operator's Board of Directors for approval, a subcommittee of that Board shall hold a public meeting to receive input directly and to discuss any proposed revisions to the draft. (g) For potential Upgrades proposed to be included in the NEPOOL Transmission Plan, the System Operator (in connection with the preparation of the NEPOOL Transmission Plan) shall identify, to the extent practicable, the anticipated benefits of the proposed Upgrade. To the extent an Upgrade is proposed to reduce Congestion Costs, the System Operator shall publish data and information, in a manner that does not violate the Information Policy, that would reasonably permit entities to calculate the costs and economic benefits of such an Upgrade and, to the extent feasible, the distribution of such benefits within the region. Such information shall be published so as to permit analysis for a reasonably limited period of time (generally ten years or less), and shall include the effects of (i) all projects for which applications have been received for approval under Section 18.4 of the Restated NEPOOL Agreement, including but not limited to proposed generation projects and Merchant Transmission Facilities and (ii) demand-side projects planned within the NEPOOL Control Area and identified to the System Operator. (h) Any entity with a representative on the Transmission Expansion Advisory Committee may request that specific proposals for alternative solutions or facilities, including but not limited to generation projects, transmission projects, and/or demand-side projects, be accounted for in the development of the NEPOOL Transmission Plan. The recommended draft of a NEPOOL Transmission Plan shall account for such proposals where appropriate provided that the recommended Plan shall not include in the list of Upgrades any proposed resource participating in competitive electricity markets or Merchant Transmission Facilities. If a proposal is not accounted for in the draft Plan to be recommended to the System Operator's Board of Directors, the recommendation to the Board shall include a written explanation of why such proposal(s) were not accounted for in the recommended Plan, which shall be made public. (i) A draft of a recommended NEPOOL Transmission Plan shall be presented at least annually to the System Operator's Board of Directors for approval. At least every three years, a draft shall reflect the results of a new comprehensive transmission planning and expansion study conducted pursuant to Section 51.5. In other years, the draft may be only an update to a prior approved Plan. The draft shall be presented to the System Operator's Board of Directors no later than September 30 of each year and shall be acted on by the Board within 60 days of receipt. The Board of Directors may approve the recommended Plan as submitted, modify the Plan or remand all or any portion of it back with guidance for development of a revised recommendation in accordance with this Section 51.4. The Board of Directors may consider the Plan in executive session, and shall consider in its deliberations the views of the subcommittee of the Board reflecting the public meeting held pursuant to subsection (f) of Section 51.4. (j) The cost responsibility for each Upgrade that is listed in the NEPOOL Transmission Plan shall be determined in accordance with this Tariff, including Schedule 11 or 12 of this Tariff, as applicable. 53.5 Procedures for the Conduct of Enhancement and Expansion Studies: From time to time in connection with the development of a NEPOOL Transmission Plan or any updates thereto, transmission enhancement and expansion studies may be desired or necessary. Such studies shall be conducted in accordance with the following procedures: (a) The System Operator shall initiate a comprehensive transmission enhancement and expansion study at least once every three years. A more limited study shall be conducted if (i) a need for additional transfer capability is identified by the System Operator in its evaluation of requests for firm transmission service with a term of one year or more or as a result of the System Operator's on-going evaluation of the bulk power supply system's adequacy and performance; (ii) a need for additional transfer capability is identified as a result of the NERC and/or NPCC reliability assessment or more stringent publicly available local reliability criteria, if any; or (iii) constraints or available transfer capability limitations are identified as a result of generation additions or retirements, evaluation of load forecasts or proposals for the addition of transmission facilities in the NEPOOL Control Area. A transmission enhancement and expansion study may also be initiated for any other circumstances which may warrant such a study. (b) Written notice of the initiation of a transmission enhancement and expansion study shall be provided to all members of the Transmission Expansion Advisory Committee and Transmission Planning Committee. That notice shall identify the needs supporting the initiation of the study. Meetings of these two Committees shall be convened thereafter to identify additional considerations relating to such a transmission enhancement and expansion study that were not identified in support of initiating the study, and to provide input on the study's scope, assumptions and procedures, consistent with the respective responsibilities of these Committees as set forth in Section 51.2. (c) The results of the enhancement and expansion study, along with a discussion of the study assumptions and input, shall be made public. 53.6 Request for Proposals ("RFP") Process For Upgrades: (a) Except as otherwise provided in subsections (e) or (f) of this Section 51.6 below, the System Operator shall circulate a request for proposals ("RFP") inviting any entity or entities to build an Upgrade included in the NEPOOL Transmission Plan. The RFP shall be prepared by the System Operator which shall, to the extent necessary, consult with the Transmission Owner(s) to obtain necessary data, information and technical specifications that the System Operator requires to prepare the RFP. The RFP shall include appropriate requirements to safeguard the confidential nature of information provided by a Transmission Owner in accordance with applicable commercial practices, the requirements of the NEPOOL Information Policy and the requirements of any applicable Commission order. Each such RFP shall require that respondents meet specified technical and financial qualifications and submit proposals (i) that conform with all the requirements of subsection (a) of Section 51.3 and reasonable Transmission Owner requirements and specifications identified in the RFP which are not inconsistent with Commission policy, (ii) that are consistent with other applicable accepted engineering practices, governmental, technical, and financial requirements, and (iii) that do not use a Transmission Owner's facilities, rights-of-way or other property, provided that the affected Transmission Owner may voluntarily agree, in its own discretion, to the use of its property in connection with a proposal. (b) The System Operator shall develop selection criteria in consultation with the Transmission Expansion Advisory Committee and post the criteria on the System Operator's website before it issues the RFP. The evaluation criteria may consider any or all of the following non-exclusive factors: (i) the qualifications of the entity that would be responsible for implementing the proposal to build the proposed Upgrade; (ii) the estimated financial and reliability impacts on Transmission Customers and load during and after construction and installation of the proposed Upgrade if the proposal is accepted and implemented; (iii) the timing for completion of the proposal; (iv) the assurance that the entity responsible for implementing the proposal is able to perform; and (v) the mobilization or demobilization of facilities affected by the building of the proposed Upgrade during construction and installation. (c) The issuance of an RFP for an Upgrade shall not preclude the modification of a NEPOOL Transmission Plan in accordance with Section 51.4(c), including, without limitation, a modification that eliminates such Upgrade from the recommended plan. (d) Any entity whose proposal is accepted by the System Operator in accordance with subsection (b) shall be compensated in accordance with the terms of its accepted proposal. (e) An RFP shall not be required for an Upgrade under this Section 51.6 if the Upgrade is initially included in the 2000 Plan or its estimated cost is less than $10 million. In such circumstances, the Transmission Owner or Owners on whose system(s) the proposed Upgrade in the Plan is located, or its/their designee(s), shall be designated as the appropriate entity responsible for completion of that Upgrade, in accordance with the requirements of Section 51.7. (f) No proposed Merchant Transmission Facility and no Upgrade that uses the facilities, rights-of-way or other property of a Transmission Owner, except as the affected Transmission Owner may voluntarily agree, in its own discretion, to such use, shall be the subject of the RFP process of this Section 51.6. No provision of Section 51 affects any obligations to interconnect new customers to the NEPOOL Transmission System imposed by other provisions of this Tariff or the Federal Power Act. 53.7 Obligations of Transmission Owners to Build: (a) If a Transmission Owner is responsible for completion of an Upgrade identified in a NEPOOL Transmission Plan in accordance with subsection (e) of Section 51.6, or the Upgrade is a Reliability Upgrade and construction is not being accomplished in accordance with a proposal accepted by the System Operator in accordance with subsection (b) of Section 51.6, or if the Transmission Owner is otherwise required to complete an Upgrade in accordance with provisions of Part III, V or VI of the Tariff or applicable regulations or statutes, the Transmission Owner shall use its reasonable efforts to design, construct and place the proposed Upgrade into service or enter into appropriate contracts to fulfill such obligations, subject to a Transmission Owner's ability to: (i) satisfy the requirements of applicable law, government regulations and approvals, including, without limitation, requirements to obtain any necessary state or local siting, construction and operating permits; (ii) obtain required financing; (iii) acquire necessary rights-of-way; (iv) recover, pursuant to appropriate financial arrangements and tariffs or contracts, all reasonably incurred costs, plus a reasonable return on investment; and (v) comply with Sections 18.4 and 18.5 of the Agreement. (b) Any Transmission Owner may seek recovery for the costs of an Upgrade for which it is responsible under this Section 51.7 on any basis it determines appropriate, including on an incremental cost basis; provided that rates, charges and terms and conditions for such recovery are accepted or approved by the Commission. Nothing herein shall prohibit or otherwise restrict the ability of affected entities to protest, challenge, comment upon or object to efforts by any Transmission Owner to obtain regulatory approval of any proposed mechanism for recovery by such Owner of the costs of such Upgrade. 53.8 Merchant Transmission Facilities; Compliance: (a) Subject to compliance with the requirements of Section 18.4 and 18.5 of the Agreement and any other applicable requirements with respect to the interconnection of bulk power facilities with the NEPOOL Transmission System, any entity shall have the right to propose and construct the addition of transmission facilities outside the Plan, none of the costs of which shall be Pool-Supported PTF or covered under Schedule 11 or 12 of this Tariff ("Merchant Transmission Facilities"). Any such Merchant Transmission Facilities shall be subject to the requirements of subsection (b) below. In performing studies in connection with the NEPOOL Transmission Plan, the prospect that proposed Merchant Transmission Facilities will be completed shall be accounted for on the same basis as the prospect that proposed generating units will be completed. (b) All Merchant Transmission Facilities shall comply with Sections 18.4 and 18.5 of the Agreement and shall be subject to: (i) agreements between the proposed owner of such Merchant Transmission Facilities and the affected Transmission Owners covering the interconnection of the Merchant Transmission Facilities, said agreement not to be unreasonably withheld; (ii) agreements with one or more Transmission Owners or the System Operator establishing responsibility for the operation and maintenance of the Merchant Transmission Facilities; (iii) agreements with any affected Transmission Owner or other entity for access to and/or use of the property of such entity, as may be necessary for the completion and operation of the Merchant Transmission Facilities; (iv) if any such owner of the Merchant Transmission Facilities is not a Participant, an agreement (A) to transfer to the System Operator operational authority of any facilities rated 69 kV or above which constitute part of the Merchant Transmission Facilities that are to be integrated with, or that will affect, the NEPOOL Transmission System and (B) that comply with the requirements of Sections 13, 21.3 and 21.7 of the Agreement, to the same extent if such owner were a Participant; and (v) taking such other action as may be required to make the facility available for use as part of the NEPOOL Transmission System. A Transmission Owner shall have the right to require that any agreement providing for the interconnection of any Merchant Transmission Facilities with its own facilities includes requirements that the Merchant Transmission Facilities' owner provide security, credit assurances and/or deposits deemed necessary by the Transmission Owner, subject to Commission acceptance or approval. 53.9 Alternative Remedies: Nothing herein shall limit in any way the right of any entity to seek any available relief pursuant to the provisions of the Federal Power Act. 1 "Quick Fix" Measures Commencing as promptly as possible in 2000, and to the extent practicable, Transmission Owners and the System Operator shall recommend cost effective "quick fix" measures that they reasonably believe can be constructed/installed in less than thirty (30) days and that reduce the likelihood of Congestion or the running of generation resources out of merit order. These measures shall include, but are not limited to, resagging transmission lines, relay changes or additions, raising transmission structures, better coordination of maintenance outages between the System Operator, Transmission Owners and the Satellites, using temperature sensitive ratings, replacing limiting equipment such as wavetraps and disconnect switches, transferring load, installing reactors and capacitors, and sectionalizing lines. The Transmission Owners and the System Operator shall recommend cost effective "quick fix" measures during 2000 and 2001. All expenses and capital investments incurred during 2000 and 2001 that are related to these measures shall constitute Pool-Supported PTF costs and shall be recovered through NEPOOL transmission charges, including the Post-1996 Pool PTF Rate. The System Operator and Transmission Owners will report to the Participant Committee quarterly beginning in March 2000 as to which measures have been completed or if any difficulties are occurring that prevent the identification or implementation of such measures. SCHEDULE 1 Scheduling, System Control and Dispatch Service Scheduling, System Control and Dispatch Service is the service required to schedule at the pool level the movement of power through, out of, within, or into the NEPOOL Control Area. Local level service is provided under the Local Network Service tariffs of the Participants which are the individual Transmission Providers. For transmission service under this Tariff, this Ancillary Service can be provided only by the System Operator and the Transmission Customer must purchase this service from the System Operator. Charges for Scheduling, System Control and Dispatch Service are to be based on the expenses incurred by the System Operator, and by the individual Transmission Providers in the operation of satellite dispatch centers or otherwise, to provide these services. Effective as of January 1, 1999, or such other date as the Commission may determine, the expenses incurred by the System Operator in providing these services are to be recovered under its Tariff for Transmission Dispatch and Power Administration Services, which has been filed in Docket No. ER98-3554-000. A surcharge for the expenses incurred by Participants in the provision of these services will be added to the Internal Point-to-Point Service rate, to the Through or Out Service rate and to the Regional Network Service rate. The expenses incurred in providing Scheduling, System Control and Dispatch Service for each Participant will be determined by an annual calculation based on the previous calendar year's data as shown, in the case of Transmission Providers which are subject to the Commission's jurisdiction, in the Participants' FERC Form 1 report for that year, and shall be based on actual data in lieu of allocated data if specifically identified in the Form 1 report. This amended Schedule 1 shall be effective as of January 1, 1999, or such other date as the Commission may determine. The surcharge shall be redetermined annually as of June 1 in each year and shall be in effect for the succeeding twelve months. The rate surcharge per kilowatt for each month is one-twelfth of the amount derived by dividing the total annual Participant expenses for providing the service by the sum of the average of the coincident Monthly Peaks (as defined in Section 46.1) of all Local Networks for the prior calendar year. Each Participant or Non-Participant which is obligated to pay the rate for Regional Network Service for a month shall pay the surcharge on the basis of the number of kilowatts of its Monthly Network Load (as defined in Section 46.1) for the month. Each Participant or Non-Participant which is obligated to pay the rate for Internal Point-to-Point Service or Through or Out Service for the applicable period shall pay the surcharge on the basis of the highest amount of its Reserved Capacity for each transaction scheduled as Internal Point-to-Point Service and/or Through or Out Service for such period. The revenues received under this Schedule 1 to cover the expenses incurred by Participants for providing Scheduling, System Control and Dispatch Service shall be allocated each month among the Participants whose satellite or other costs are reflected in the computation of the surcharge for the service in proportion to the costs for each which are reflected in the computation of the surcharge. The details for implementation of Schedule 1 shall be established in accordance with a rule approved by the Regional Transmission Operations Committee which shall be filed with the Commission and considered a supplement to this Tariff. SCHEDULE 2 Reactive Supply and Voltage Control from Generation Sources Service In order to maintain transmission voltages on the NEPOOL Transmission System within acceptable limits, generation facilities are operated to produce (or absorb) reactive power. Thus, Reactive Supply and Voltage Control from Generation Sources Service must be provided for each transaction on the NEPOOL Transmission System. The amount of Reactive Supply and Voltage Control from Generation Sources Service that must be supplied with respect to a Transmission Customer's transaction will be determined based on the reactive power support necessary to maintain transmission voltages within limits that are generally accepted in the region and consistently adhered to by the Participants. Reactive Supply and Voltage Control from Generation Sources Service is to be provided through the Participants and the System Operator and the Transmission Customer must purchase this service from the Participants through the System Operator when the System Operator (or applicable satellite dispatching center) determines, in the exercise of its discretion, that it is necessary to direct a generating unit to alter its operations in an hour in order to provide such service. The charge for each hour for such service, when required by the System Operator (or satellite dispatching center) as set forth above, shall be paid by each Participant or Non-Participant which receives either Regional Network Service or Internal Point-to-Point Service or Through or Out Service and shall be determined in accordance with the following formula: The formula in Schedule 2 is amended to read as follows: (EQUATION) in which CH = the amount to be paid by the Participant or Non-Participant for the hour; CC = the capacity costs for the hour, which shall be stated in an informational filing with the Commission; LOC = the lost opportunity costs for the hour to be paid to Participants who provide VAR support; PC = the portion of the amount paid to Participants for the hour for Energy produced by a generating unit that is considered under the applicable Implementation Rule to be paid for VAR support; SCL = the cost of energy used in the hour by generating facilities, synchronous condensers or static controlled VAR regulators in order to provide VAR support to the transmission system; HL1 = the Network Load of the Participant or Non-Participant for the hour; HL = the aggregate of the Network Loads of all Participants and Non- Participants for the hour; RC1 = the Reserved Capacity for Internal Point-to-Point Service and/or Through or Out Service of the Participant or Non-Participant for the hour; and RC = the aggregate Reserved Capacity for Internal Point-to-Point Service and/or Through or Out Service of all Participants and Non-Participants for the hour. SCHEDULE 3 Regulation and Frequency Response Service (Automatic Generation Control) Regulation and Frequency Response Service (Automatic Generation Control or AGC) is necessary to provide for continuous balancing of resources (generation and interchange) with load, and for maintaining scheduled interconnection frequency at sixty cycles per second (60 Hz). Regulation and Frequency Response Service (Automatic Generation Control) is accomplished by dispatching on-line resources whose output is raised or lowered (predominantly through the use of automatic generating control equipment) as necessary to follow the moment-by-moment changes in load. The obligation to maintain this balance between resources and load lies with the System Operator and this service will be available to all Participants and other entities that serve load within the NEPOOL Control Area either under the Agreement for Participants or pursuant to Service Agreements with Non- Participants entered into under the Tariff. The Transmission Customer must either take this service from the System Operator pursuant to the Tariff or under the Agreement or make alternative comparable arrangements to satisfy its Regulation and Frequency Response Service (Automatic Generation Control) obligation. Until the CMS/MSS Effective Date, charges for this Service will be determined on the basis of bids submitted by Participants in accordance with Section 14 of the Agreement and applicable Market Rules. After the CMS/MSS Effective Date, charges for this Service will be determined on the basis of Supply Offer Prices submitted by Participants in accordance with Section 14A of the Agreement and applicable Market Rules. In either case, the per unit charge for this service to Non-Participants shall be the same as determined for Participants under Section 14.10 of the Agreement prior to the CMS/MSS Effective Date, and under Section 14A.8(c) of the Agreement and applicable Market Rules on and after the CMS/MSS Effective Date. The transmission service required with respect to Regulation and Frequency Response Service (Automatic Generation Control) will be paid for as part of Regional Network Service or Internal Point-to-Point Service by all Participants and other entities serving load in the NEPOOL Control Area. The charge for Regional Network Service is determined in accordance with Schedule 9 of the Tariff. The charge for Internal Point-to-Point Service is determined in accordance with Schedule 10 of the Tariff. Sheet No. 204 is intentionally blank. SCHEDULE 4 Energy Imbalance Service Energy Imbalance Service is the service provided when a difference occurs between the scheduled and the actual delivery of energy to a load located within the NEPOOL Control Area during a single hour. The Transmission Customer may either supply its load from its own resources or through bilateral arrangements or obtain the service under the Agreement. This service will be available to all Participants and other entities that serve load within the NEPOOL Control Area either under the Agreement for Participants or pursuant to Service Agreements with Non-Participants entered into under the Tariff. The prices for such service will be determined in accordance with Section 14 of the Agreement and applicable Market Rules until the CMS/MSS Effective Date, and will be the applicable Locational Prices determined pursuant to Section 14A.12 of the Agreement and applicable Market Rules on and after the CMS/MSS Effective Date. The transmission service required with respect to Energy Imbalance Service under the Agreement will be furnished as part of Regional Network Service or Internal Point-to-Point Service to all Participants and other entities serving load in the NEPOOL Control Area. The charges for Regional Network Service are determined in accordance with Schedule 9 of the Tariff. The charges for Internal Point-to-Point Service are determined in accordance with Schedule 10 of the Tariff. SCHEDULE 5 Operating Reserve - 10-Minute Spinning Reserve Service 10-Minute Spinning Reserve Service is a service needed to serve load immediately in the event of a system contingency. This service will be available to all Participants and other entities that serve load within the NEPOOL Control Area. The Transmission Customer may either supply this service with its own resources or through bilateral arrangements, or obtain the service either under the Agreement for Participants or pursuant to Service Agreements with Non-Participants entered into under the Tariff. The total of each category of Operating Reserve requirements for the NEPOOL Control Area in each hour is determined by the System Operator in accordance with applicable NEPOOL System Rules. The currently applicable NEPOOL System Rule, Operating Procedure No. 8, is on file with the Commission as a supplement to the Tariff. Under Section 14 of the Agreement, until the CMS/MSS Effective Date, the price to be paid for Operating Reserve Service received in any hour will be the Operating Reserve Clearing Price for the hour for that category of reserve service, as determined on the basis of bids to provide the service plus any applicable uplift charge. On and after the CMS/MSS Effective Date, the price to be paid for Operating Reserve Service shall be determined in accordance with Section 14A.8(b) of the Agreement. In accordance with Section 14A.1(c) of the Agreement, Participants and Non-Participant Transmission Customers shall be assigned Settlement Obligations by the System Operator, which are used to allocate among the Participants and Non-Participant Transmission Customers cost responsibility for each category of Operating Reserve that is not self- supplied. The allocated costs that must be paid for each category of Operating Reserve following the CMS/MSS Effective Date are determined in accordance with Sections 14A.1(c) and 14A.8(c) of the Agreement. The transmission service required with respect to Operating Reserve will be paid for as part of Regional Network Service or Internal Point-to-Point Service by all Participants and other entities serving load in the NEPOOL Control Area. The charge for Regional Network Service is determined in accordance with Schedule 9 of the Tariff. The charge for Internal Point-to- Point Service is determined in accordance with Schedule 10 of the Tariff. SCHEDULE 6 Operating Reserve - 10-Minute Non-Spinning Reserve Service 10-Minute Non-Spinning Reserve Service is a service needed to serve load in the event of a system contingency. This service will be available to all Participants and other entities that serve load within the NEPOOL Control Area. The Transmission Customer may either supply this service with its own resources or through bilateral arrangements, or obtain the service either under the Agreement for Participants or pursuant to Service Agreement with Non-Participants entered into under the Tariff. The total of each category of Operating Reserve requirements for the NEPOOL Control Area in each hour is determined by the System Operator in accordance with applicable NEPOOL System Rules. The currently applicable NEPOOL System Rule, Operating Procedure No. 8, is on file with the Commission as a supplement to the Tariff. Under Section 14 of the Agreement, until the CMS/MSS Effective Date, the price to be paid for Operating Reserve Service received in any hour will be the Operating Reserve Clearing Price for the hour for that category of reserve service, as determined on the basis of bids to provide the service plus any applicable uplift charge. On and after the CMS/MSS Effective Date, the price to be paid for Operating Reserve Services shall be determined in accordance with Section 14A.8(b) of the Agreement. In accordance with Section 14A.1(c) of the Agreement, Participants and Non-Participant Transmission Customers shall be assigned Settlement Obligations by the System Operator, which are used to allocate among the Participants and Non-Participant Transmission Customers cost responsibility for each category of Operating Reserve that is not self- supplied. The allocated costs that must be paid for each category of Operating Reserve following the CMS/MSS Effective Date are determined in accordance with Sections 14A.1(c) and 14A.8(c) of the Agreement. The transmission service required with respect to Operating Reserve will be furnished as part of Regional Network Service or Internal Point-to-Point Service to all Participants and other entities serving load in the NEPOOL Control Area. The charge for Regional Network Service is determined in accordance with Schedule 9 of the Tariff. The charge for Internal Point-to- Point Service is determined in accordance with Schedule 10 of the Tariff. SCHEDULE 7 Operating Reserve - 30-Minute Reserve Service 30-Minute Reserve Service is a service needed to serve load in the event of a system contingency. This service will be available to all Participants and other entities that serve load within the NEPOOL Control Area. The Transmission Customer may either supply this service with its own resources or through bilateral arrangements, or obtain the service either under the Agreement for Participants or pursuant to Service Agreements with Non- Participants entered into under the Tariff. The total of each category of Operating Reserve requirements for the NEPOOL Control Area in each hour is determined by the System Operator in accordance with applicable NEPOOL System Rules. The currently applicable NEPOOL System Rule, Operating Procedure No. 8, is on file with the Commission as a supplement to the Tariff. Under Section 14 of the Agreement, until the CMS/MSS Effective Date, the price to be paid for Operating Reserve Service received in any hour will be the Operating Reserve Clearing Price for the hour for that category of reserve service, as determined on the basis of bids to provide the service plus any applicable uplift charge. On and after the CMS/MSS Effective Date, the price to be paid for Operating Reserve Service shall be determined in accordance with Section 14A.8(b) of the Agreement. In accordance with Section 14A.1(c) of the Agreement, Participants and Non-Participant Transmission Customers shall be assigned Settlement Obligations by the System Operator, which are used to allocate among the Participants and Non-Participant Transmission Customers cost responsibility for each category of Operating Reserve that is not self- supplied. The allocated costs that must be paid for each category of Operating Reserve following the CMS/MSS Effective Date are determined in accordance with Sections 14A.1(c) and 14A.8(c) of the Agreement. The transmission service required with respect to Operating Reserve will be furnished as part of Regional Network Service or Internal Point-to-Point Service to all Participants and other entities serving load in the NEPOOL Control Area. The charge for Regional Network Service is determined in accordance with Schedule 9 of the Tariff. The charge for Internal Point-to- Point Service is determined in accordance with Schedule 10 of the Tariff. SCHEDULE 8 Through or Out Service - The Pool PTF Rate (1) A Transmission Customer shall pay to NEPOOL for firm or non-firm Through or Out Service reserved for it in accordance with Section 19 of the Tariff the highest of (a) the Pool PTF Rate or (b)a rate which is derived from the annual incremental cost, not otherwise borne by the Transmission Customer or a Generator Owner, of any new facilities or upgrades that would not be required but for the need to provide the requested service or (c) a rate which is equal to NEPOOL's opportunity cost (if and when available) capped at the cost of expansion, as determined for the period of service in accordance with Section 20 of this Tariff. If at any time NEPOOL proposes to charge a rate based on opportunity cost, it shall first file with the Commission procedures for computing opportunity cost pricing for all Transmission Customers. The Transmission Customer shall also be obligated to pay any applicable ancillary service charges and any congestion or other uplift charge required to be paid pursuant to Section 24 of this Tariff. (2) The Pool PTF Rate in effect at any time shall be determined annually on the basis of the information for the most recent calendar year contained in Form 1 filings (or similar information on the books of Transmission Providers that are not required to submit a Form 1 filing) and shall be changed annually effective as of June 1 in each year. The Pool PTF rate shall be equal to (i) the sum for all Participants of Annual Transmission Revenue Requirements determined in accordance with Attachment F divided by (ii) the sum of the coincident Monthly Peaks (as defined in Section 46.1) of all Local Networks, excluding from the Monthly Peak for each Local Network as applicable the loads at each applicable Point of Delivery of each Participant or Non-Participant which has elected to take Internal Point-to-Point Service in lieu of Regional Network Service at one or more Points of Delivery; plus the Long-Term Firm Reserved Capacity amount for each such Participant or Non- Participant which has elected to take Firm Internal Point-to-Point Service in lieu of Regional Network Service at one or more Points of Delivery plus the Long-Term Reserved Capacity amount for each Participant or Non-Participant for Firm Through or Out Service. Revenues associated with Short-Term Point- to-Point reservations will be credited to the sum of all Participants' Annual Transmission Revenue Requirements referred to in (i) above. (3) Discounts: Three principal requirements apply to discounts for Through or Out Service as follows (1) any offer of a discount made by the Participants must be announced to all Eligible Customers solely by posting on the OASIS, (2) any customer-initiated requests for discounts (including requests for use by one's wholesale merchant or an affiliate's use) must occur solely by posting on the OASIS, and (3) once a discount is negotiated, details must be immediately posted on the OASIS. For any discount agreed upon for service on a path, from Point(s) of Receipt to Point(s) of Delivery, the Participants must offer the same discounted transmission service rate for the same time period to all Eligible Customers on all unconstrained transmission paths that go to the same Point(s) of Delivery on the NEPOOL Transmission System. SCHEDULE 9 Regional Network Service (1) A Transmission Customer which serves a Network Load in the NEPOOL Control Area shall pay to NEPOOL each month for Regional Network Service the amount determined in accordance with the following formula: A = 1/12 (R . L) in which A = the amount to be paid R = the Participant RNS Rate per Kilowatt for the current Year for the Participant which owns the Local Network from which the Customer's load is served L = the Customer's Monthly Network Load for the month It shall also be obligated to pay any ancillary charges and any applicable congestion or other uplift charge required to be paid pursuant to Sections 24, 25A and 25B of this Tariff. Each Participant RNS Rate is to be determined in accordance with the remaining provisions of this Schedule 9. The Participants intend that the rate will be determined by looking separately at the costs associated with facilities which are in service at December 31, 1996, and the costs associated with new facilities which are placed in service after December 31, 1996. Costs of new facilities are to be shared regionally on a per Kilowatt basis in determining the rates of each of the Participants with a Local Network, unless otherwise allocated to a particular entity pursuant to this Tariff. Costs of existing facilities are to be determined separately for each Participant and reflected in the rate for service to Transmission Customers serving load in the Participant's Local Network. This is initially subject to a band width which limits the variation of the Participant per Kilowatt cost from the average per Kilowatt cost for all Participants to not less than 70%, or more than 130%, of the average cost. (2) The Pool RNS Rate per Kilowatt is $1 in Year One, $4 in Year Two, $7 in Year Three, $10 in Year Four and $13 in Years Five and Six and the period from the end of Year Six to the next succeeding June 1, and is equal to the Pool PTF Rate for each Year thereafter. (3) The Participant RNS Rate for a Participant for a Year shall be a percentage of the Pool RNS Rate for the year and shall be equal to the Pool RNS Rate after the end of the transitional period described in paragraph (4) of this Schedule. The percentage for each Participant for each Year shall equal the percentage which the sum of (i) the Participant's pre-1997 Participant RNS Rate and (ii) the post-1996 Pool PTF Rate represents of (iii) the Pool PTF Rate for the Year. (4) The pre-1997 Participant RNS Rate for each Participant shall be determined by comparing its individual pre-1997 PTF Rate, for the most recent calendar year for which information is available from Form 1 filings or otherwise to the pre-1997 Pool PTF Rate for the same calendar year. If the Participant's individual pre-1997 PTF Rate for a Year is less than the pre- 1997 Pool PTF Rate, its pre-1997 Participant RNS Rate for the Year shall be the rate determined by reducing the pre-1997 Pool PTF Rate by the percentage which the Participant's pre-1997 PTF Rate is less than the pre-1997 Pool PTF Rate; provided that in no event shall its pre-1997 Participant RNS Rate be less than 70% of the pre-1997 Pool PTF Rate, until the end of Year Five, and thereafter shall be no less than 50% of the pre-1997 Pool PTF Rate for Year Six through Year Eleven, and shall be equal to the pre-1997 Pool PTF Rate for Year Twelve and thereafter. If the Participant's individual pre-1997 PTF Rate is greater than the pre-1997 Pool PTF Rate, its pre-1997 Participant RNS Rate shall be the rate determined by increasing the pre-1997 Pool PTF Rate by the percentage which its pre-1997 Participant PTF Rate is greater than the pre-1997 Pool PTF Rate; provided that in no event shall its pre-1997 Participant RNS Rate be greater than 130% of the pre-1997 Pool PTF Rate until the end of Year Six, and thereafter shall be no greater than 127% of the pre- 1997 Pool PTF Rate for Year Six, 123% of the pre-1997 Pool PTF Rate for Year Eight, 118% of the pre-1997 Pool PTF Rate for Year Nine, 112% of the pre-1997 Pool PTF Rate for Year Ten, 105% of the pre-1997 Pool PTF Rate for Year Eleven, and shall be equal to the pre-1997 Pool PTF Rate for Year Twelve and thereafter. If for any Year the revenues to be received from the payment by Participants or other Transmission Customers of their respective applicable Participant RNS Rates will average more or less than the Pool PTF Rate per Kilowatt for the Year, each Participant RNS Rate will be increased or decreased, as appropriate, so that the revenues to be received per Kilowatt per Year will equal the Pool PTF Rate per Kilowatt for the Year. (5) The individual pre-1997 PTF Rate of a Participant which owns a Local Network for a year is the amount derived annually by dividing its Annual Transmission Revenue Requirements for the most recent calendar year for which information is available from Form 1 filings (or similar information on the books of Transmission Providers that are not required to submit a Form 1 filing) with respect to PTF placed in service before January 1, 1997, as determined in accordance with Attachment F to this Tariff, by the average for the twelve months of the calendar year on which the rate is based of the sum of the coincident Monthly Peaks for the Local Network, as adjusted each month for losses, excluding from the Monthly Peak the load at each applicable Point of Delivery of each Participant or Non-Participant which has elected to take Internal Point-to-Point Service in lieu of Regional Network Service at one or more Points of Delivery; plus the Long-Term Firm Reserved Capacity amount for each such Participant or Non-Participant which has elected to take Firm Internal Point-to-Point Service in lieu of Regional Network Service at one or more Points of Delivery. (6) The pre-1997 Pool PTF Rate shall be determined in accordance with the following formula: (EQUATION) and the post-1996 Pool PTF Rate shall be determined in accordance with the following formula: (EQUATION) in which R = the pre-1997 Pool PTF Rate R' = the post-1996 Pool PTF Rate ATRR = the aggregate of the Annual Transmission Revenue Requirements of the Participants with respect to PTF placed in service before January 1, 1997, as determined in accordance with Attachment F to this Tariff. ATRR' = the aggregate of the Annual Transmission Revenue Requirements of the Participants with respect to PTF placed in service on or after January 1, 1997, including upgrades, modifications or additions to PTF placed in service before January 1, 1997, as determined in accordance with Attachment F to this Tariff. ARNL = the average for the twelve months of the calendar year on which the rate is based of the sum of the coincident Monthly Peaks for all Local Networks, as adjusted each month for NEPOOL losses, excluding from the Monthly Peak for each Local Network as applicable the load at each applicable Point of Delivery of each Participant or Non-Participant which has elected to take Internal Point-to-Point Service in lieu of Regional Network Service at one or more Points of Delivery; plus the Long-Term Firm Reserved Capacity amount for each such Participant or Non-Participant which has elected to take Firm Internal Point-to-Point Service in lieu of Regional Network Service at one or more Points of Delivery plus the Long-Term Reserved Capacity amount for each Participant or Non-Participant for Firm Through or Out Service. (7) As used in this Schedule, "Monthly Peak" and "Monthly Network Load" each has the meaning specified in Section 46.1 of this Tariff. (8) With the exception of any provision of this Schedule relating to the determination or application of the post-1996 Pool PTF Rate and technical changes to the last sentence of paragraph (4) of this Schedule 9 to allocate costs as necessary to keep Participants within the band widths identified in that paragraph, the provisions of this Schedule 9 shall not be amended for service rendered under the NEPOOL Tariff through December 31, 2003, except by agreement in writing of the parties executing the Settlement Agreement in FERC Docket Nos. OA97-237-000 et al. and compliance with the applicable requirements of the Restated NEPOOL Agreement. SCHEDULE 10 Internal Point-to-Point Service (1) A Transmission Customer shall pay to NEPOOL for firm or non-firm Internal Point-to-Point Service reserved for it in accordance with Section 19 of the Tariff a charge per Kilowatt, as determined for the period of the service in accordance with Section 21 of this Tariff, equal to the Internal Point-to-Point Service Rate; provided if either or both (i) a rate which is derived from the annual incremental cost not otherwise borne by the Transmission Customer or a Generator Owner, of any new facilities or upgrades that would not be required but for the need to provide the requested service or (ii) a rate which is equal to NEPOOL's opportunity cost (if and when available) capped at the cost of expansion, is greater than the Pool PTF Rate the charge shall be the higher of such amounts; provided further that no such charge shall be payable with respect to the use of Internal Point-to-Point Service to effect a delivery to the NEPOOL power exchange in an Interchange Transaction. If at any time NEPOOL proposes to charge a rate based on opportunity cost, it shall first file with the Commission procedures for computing opportunity cost pricing for all Transmission Customers. The Customer shall also be obligated to pay any applicable ancillary service charge and any applicable congestion or other uplift charge required to be paid pursuant to Sections 24, 25A and 25B of this Tariff. (2) Discounts: Three principal requirements apply to discounts for Internal Point-to-Point Service as follows (1) any offer of a discount made by the Participants must be announced to all Eligible Customers solely by posting on the OASIS, (2) any customer-initiated requests for discounts (including requests for use by one's wholesale merchant or an affiliate's use) must occur solely by posting on the OASIS, and (3) once a discount is negotiated, details must be immediately posted on the OASIS. For any discount agreed upon for service on a path, from Point(s) of Receipt to Point(s) of Delivery, the Participants must offer the same discounted transmission service rate for the same time period to all Eligible Customers on all unconstrained transmission paths that go to the same Point(s) of Delivery on the NEPOOL Transmission System. SCHEDULE 11 Generator Interconnection Related Upgrade Costs (1) Classification of Generating Projects. The treatment for purposes of this Tariff of the Generator Interconnection Related Upgrade costs with respect to the facilities needed for the interconnection of a particular new or modified generating unit project in accordance with Section 50 of the Tariff depends on whether the project is a Category A Project, a Category B Project or a Category C Project, as follows: (a) A Category A Project is one whose Generator Owner committed to pay for upgrade costs prior to October 29, 1998 and has filed a petition with the Commission requesting that the costs associated with the interconnection of its generation project be determined in accordance with Schedule 11 of the Tariff, as filed with the Thirty-Sixth Agreement Amending the Restated NEPOOL Agreement. Subject to the outcome of proceedings pending before the Commission in Docket No. ER98-3853, including all appeals, and consistent with the Commission's June 28, 2000 order in Docket Nos. EL00-62-000, et al., and further Commission orders with respect thereto, the following projects have been identified as potentially being Category A Projects: EMI Dighton EMI Tiverton EMI Rumford Polsky AEC Millennium Power Partners, L.P. PDC Berkshire Duke, Bridgeport Energy Duke, Maine Independence (b) A Category B Project is any one, other than a Category A Project, on which the Generator Owner had expended at least $5,000,000, including amounts due under irrevocable commitments, as of June 22, 1999 with respect to the project. The Category B Projects are: Sithe, Mystic Station Expansion Sithe Edgar Station Expansion, Fore River Sithe, West Medway PG&E, Generating Lake Road Generating PDC, Milford Power PDC, Meriden Power Reliant Energy, Hope Rhode Island IDC FPL, Bellingham Constellation, Merrimack (Nickel Hill) Energy Project SEI, Canal Re-powering ANP, Bellingham ANP, Blackstone Cabot, Island End Calpine, Westbrook Power HQ, Bucksport AES, Londonderry ConEd, Newington (c) A Category C Project is any project which is not a Category A Project or a Category B Project. (2) Direct Interconnection Transmission Costs. Direct Interconnection Transmission Costs shall mean the cost of facilities constructed for sole use of the Generator Owner that are not PTF. One hundred percent of Direct Interconnection Transmission Costs shall be the responsibility of the Generator Owner whether the Generator Owner's project is a Category A Project, a Category B Project or a Category C Project. (3) Treatment of Category A Project Transmission Costs. The allocation of costs of Generator Interconnection Related Upgrades for Category A Projects will be determined as follows: (a) One-half of the Shared Amount (as defined below) of the capital cost of the PTF upgrade shall constitute Pool-Supported PTF and be included in Annual Transmission Revenue Requirements under Attachment F. The Generator Owner shall be obligated to pay, in addition to the Direct Interconnection Transmission Costs, the other half of the Shared Amount of the capital cost of the PTF upgrade and all of the capital costs in excess of the Shared Amount, and any applicable tax gross-up amounts, and such amounts to be paid by the Generator Owner shall not be included in Annual Transmission Revenue Requirements under Attachment F. Following completion of the construction or modification of the Generator Interconnection Related Upgrade, the Generator Owner shall be obligated to pay its pro rata share of all of the annual costs (including cost of capital, federal and state income taxes, O&M and A&G expenses, annual property taxes and other related costs) which are allocable to such upgrade, pursuant to the interconnection agreement with the individual Transmission Owner or its designee which is responsible for the construction or modification, which agreement may be filed with the Commission by the Transmission Owner unsigned either on its own or at the request of the Generator Owner. (b) In determining the cost responsibilities related to a Generator Interconnection Related Upgrade to PTF, the Participants Committee may determine that all or a portion of the proposed facilities exceed regional system, regulatory or other public requirements. In such a case, the Participants Committee shall determine the amount of the excess costs of the Generator Interconnection Related Upgrade which shall be borne by the entity which is responsible for requiring such excess costs, and the excess costs shall not be included in the calculation of the Shared Amount. (c) The Shared Amount of the capital cost of the Generator Interconnection Related Upgrade of PTF shall be initially determined as of the time that the System Impact Study agreement is executed by all parties and the Generator Owner has paid the cost of the study (such initial determination to be based on the estimated cost of the Generator Interconnection Related Upgrade, subject to later adjustment as set forth below) subject to truing up the KW element of the following formula upon completion of the Generator Interconnection Upgrade, and shall be the lesser of (1) the full actual capital cost of the Generator Interconnection Related Upgrade of PTF (excluding any costs which are determined to be excess costs in accordance with paragraph (b) above) or (2) the amount determined in accordance with the following formula: (EQUATION) in which: P is the maximum amount to be shared; KW in the case of a generating unit, is the actual demonstrated net capability of the new generating unit or increase in the capacity of an existing generating unit corrected to 50*F in kilowatts. If winter operating conditions are shown in the System Impact Study and/or application under Section 18.4 of the Agreement to require additional transmission reinforcements beyond those reinforcements required for summer operating conditions, the net capability of the unit will be corrected to an ambient air temperature of 0*F; R is the Pool PTF Rate in effect on the Compliance Effective Date, which is $15.57 per kilowatt year, adjusted to reflect compliance with the April 5, 1999 Settlement Agreement, approved by the Commission by order dated July 30, 1999 in Docket Nos. OA97-237-000, et al.; and C is the weighted average carrying charge factor of all of the Transmission Providers which own PTF, determined, as of the Compliance Effective Date, in accordance with Attachment F to the Tariff, which is 15.87 percent, adjusted to reflect compliance with the April 5, 1999 Settlement Agreement, approved by the Commission by order dated July 30, 1999 in Docket Nos. OA97-237-000, et al. (d) All payments required hereunder shall be determined initially on an estimated basis, and then adjusted after the appropriate portion of the construction or modification costs has been reflected in Tariff rates in the first adjustment of Tariff rates after the upgrade has been placed in commercial operation. (e) The provisions in this Section (3) with respect to allocation of costs for Generator Interconnection Related Upgrades of PTF for Category A projects are subject to further clarifications and/or modifications to reflect the outcome of proceedings in Commission Docket Nos. ER98-3853 (including any court appeals) and EL00-62-000, et al., and further Commission orders with respect thereto. (4) Treatment of Category B Project Transmission Costs. If, and to the extent capital costs for, a Generator Interconnection Related Upgrade are required to be incurred in order to satisfy the Minimum Interconnection Standard in connection with a Category B Project, and would not have been required but for the interconnection of the generator, one-half of such capital cost of the Generator Interconnection Related Upgrade, other than Direct Interconnection Transmission Costs and any excess costs as described below, up to a maximum of two million dollars ($2,000,000) (or one-half of $4,000,000), shall constitute Pool-Supported PTF costs and shall be included in Annual Transmission Revenue Requirements under Attachment F of the Tariff. The Generator Owner shall be obligated to pay the remaining costs of the Generation Interconnection Related Upgrade required to be incurred to meet the Minimum Interconnection Standard for the Category B Project that would not be needed but for the interconnection of that Generator (including all Direct Interconnection Transmission Costs, any excess costs as described below, and any applicable tax gross-up amounts) and to pay the entire costs of any Elective Transmission Upgrade requested by such Generator Owner (including all Direct Interconnection Transmission Costs, any excess costs as described below, and any applicable tax gross-up amounts); and such amounts to be paid by the Generator Owner shall not be included in Annual Transmission Revenue Requirements under Attachment F. Following completion of the construction or modification of the Generator Interconnection Related Upgrade, the Generator Owner shall be obligated to pay its pro rata share of all of the annual costs (including cost of capital, federal and state income taxes, O&M and A&G expenses, annual property taxes and other related costs) which are allocable to such upgrade, pursuant to the interconnection agreement with the individual Transmission Owner or its designee which is responsible for the construction or modification, which agreement may be filed with the Commission by the Transmission Owner unsigned either on its own or at the request of the Generator Owner. In determining the cost responsibilities related to a Generator Interconnection Related Upgrade for a particular Category B Project, the Participants Committee may determine that all or a portion of the proposed facilities exceed regional system, regulatory or other public requirements. In such a case, the Participants Committee shall determine the amount of the excess costs of the Generator Interconnection Related Upgrade which shall be borne by the entity which is responsible for requiring such excess costs, and the excess costs shall not be included in the calculation of the amount of the capital costs to be shared as discussed above. All payments required hereunder shall be determined initially on an estimated basis, and then adjusted after the appropriate portion of the construction or modification costs has been reflected in Tariff rates in the first adjustment of Tariff rates after the upgrade has been placed in commercial operation. (5) Treatment of Category C Project Transmission Costs. If a Generator Interconnection Related Upgrade is required in order to satisfy the Minimum Interconnection Standard in connection with a Category C Project, the Generator Owner shall be obligated to pay all of the cost of such upgrade, including all Direct Interconnection Transmission Costs and any applicable tax gross-up amounts, to the extent such costs would not have been incurred but for the interconnection. Following completion of the construction or modification, the Generator Owner shall be obligated to pay all of the annual costs (including federal and state income taxes, O&M and A&G expenses, annual property taxes and other related costs) which are allocable to the Generator Interconnection Related Upgrade, pursuant to the interconnection agreement (or support agreement) with the individual Transmission Owner or its designee which is responsible for the construction or modification, which agreement may be filed with the Commission by the Transmission Owner either signed by both parties or unsigned at the request of the Generator Owner. (6) Treatment of Elective Transmission Upgrades for Generating Units. If a Generator Owner has requested an Elective Transmission Upgrade pursuant to Section 50.2 of this Tariff in connection with a new or materially changed generation unit, the Generator Owner shall be subject to the cost, credit assurance and contract obligations set forth in Section 50.2 and Schedule 12 for Elective Transmission Upgrades. (7) Contract and Credit Requirements. If a Generator Interconnection Related Upgrade is required, the Generator Owner requesting such upgrade, at the request of the Transmission Owner or its designee responsible for effecting the construction or modification, shall be obligated to pay to the Transmission Owner or its designee responsible for effecting the Generator Interconnection Related Upgrade an amount equal to its share of the estimated cost of the construction at one time or in monthly or other periodic installments, including, without limitation, all costs associated with acquiring land, rights of way easements, purchasing equipment and materials, installing, constructing, interconnecting, and testing the facilities; O&M and engineering costs; all related overheads; and any and all associated taxes and government fees. In addition to, or in lieu of said payment, the affected Transmission Owner or its designee may require the Generator Owner to provide, as security for its obligation to pay any unfunded balance of the construction costs, a letter of credit or other reasonable form of security acceptable to the Transmission Owner or its designee that will be responsible for the construction equivalent to the cost of the upgrade including taxes and consistent with relevant commercial practices, as established by the Uniform Commercial Code. As soon as reasonably practical, but in any event within 180 days after completion of the construction or modifications, or as otherwise mutually agreed, the Transmission Owner or its designee responsible for the construction or modification will determine the difference, if any, between the estimated cost already paid by the Generator Owner to the Transmission Owner or its designee responsible for the construction or modification and its share of the actual cost of the construction or modification, and will either receive from the Generator Owner, with Interest (if the sum paid is insufficient) or pay to the Generator Owner, with Interest (if the sum paid is surplus) the difference; provided that if, at the time such determination is made, items of construction that remain to be completed and/or some construction costs have not been invoiced and paid, the Transmission Owner or its designee responsible for the construction or modification shall continue to be entitled to recover from the Generator Owner the Generator Owner's share of the costs of such remaining items and may retain a reserve to cover such items. Furthermore, the Transmission Owner shall release any letter of credit or other security instrument received by the Transmission Owner, up to the amount allowed to be recovered through the Transmission Owner's Annual Transmission Revenue Requirement for Category A and B Projects, no later than sixty (60) days after the later of the reflection of such costs in the Pool rates and the commercial operation of the generation addition or modification. To the extent Generator Interconnection Related Upgrades, or any portion thereof, are completed in a calendar year, Transmission Owners will use their best efforts to reflect such facilities in their Annual Transmission Revenue Requirements calculated on the basis of that year. That portion of the construction or modification costs or deposit paid by the Generator Owner may, by mutual agreement of the Transmission Owner and the Generator Owner, either be retained by the Transmission Owner, or be refunded to the Generator Owner upon the Generator Owner executing a contract with the Transmission Owner obligating the Generator Owner to pay the Transmission Owner the ongoing transmission revenue requirement associated with its share of the Generator Interconnection Related Upgrade, including but not limited to cost of capital, federal and state income taxes, O&M and A&G costs, annual property taxes and all other related costs, and providing the Transmission Owner with an irrevocable letter of credit or other form of security acceptable to the Transmission Owner. In the event the Generator Owner's portion of the construction or modification costs is retained by the Transmission Owner or its designee in accordance with the preceding sentence, the Generator Owner will be obligated (i) to pay the federal and state income taxes required to be paid by the Transmission Owner with respect to the retained amount, and (ii) to pay annually its percentage of the O&M and A&G costs, annual property taxes and all other related costs, except for those costs required to be paid under (i) or any costs that are retained by the Transmission Owner in accordance with the interconnection agreement. If the Generator Owner for whatever reason goes out of business, or otherwise abandons its generation project and the Generator Interconnection Related Upgrade has already been partially or completely constructed, the Generator Owner shall be responsible for all of the unrecovered ongoing costs of the upgrade that would not have been incurred but for the proposed generation project. Nothing contained herein shall prevent the Transmission Owner or its designee responsible for the construction or modification and the Generator Owner from negotiating other methods for providing financial security associated with the cost of an upgrade deemed acceptable to the Transmission Owner or other entity. Subject to the foregoing, the interconnection and support agreements for a Generation Interconnection Related Upgrade may specify the basis for continued support of such upgrade in the event of a termination of NEPOOL, the cancellation of the project due to a failure to obtain regulatory approvals or permits or required rights of way or other property, or action to terminate the project before its completion for whatever reason and any other matters. Interest payable hereunder shall be calculated in accordance with Section 8.3 of the Tariff. SCHEDULE 12 Reliability Upgrade, Economic Upgrade and Elective Transmission Upgrade Costs (1) Allocation and Recovery of Costs for Reliability Upgrades and Economic Upgrades Associated with the NEPOOL Transmission Plan. All costs of Merchant Transmission Facilities shall be recovered in accordance with the recovery mechanism for those facilities that is filed with and accepted by the Commission. All costs associated with Upgrades for the interconnection of Merchant Transmission Facilities shall be treated in the same fashion and subject to the same rights and obligations as Generator Interconnection Related Upgrade Costs for Category C Projects under Schedule 11 of this Tariff, including the provisions of Sections (5), (6) and (7) of that Schedule. To the extent not otherwise covered above or by Part III or Schedule 11 of the Tariff or Sections (2) or (3) of this Schedule 12 below, the costs of a Reliability Upgrade and Economic Upgrade shall be allocated as follows: (a) If entities have agreed to bear some or all of the cost responsibility for an Upgrade, the Upgrade costs shall be allocated to such entities in accordance with that agreement. (b) To the extent there are Reliability Upgrade or Economic Upgrade costs that are not allocated in accordance with other arrangements as identified in the introductory language of this Section (1) or subparagraph (a) above, such costs shall be allocated utilizing an appropriate cost causation and cost benefit methodology to be specified in NEPOOL System Rules, which are to be a supplement to the Tariff and are filed with, and accepted by, the Commission. Any allocation to a specific entity or entities or a Reliability Region or Region(s) pursuant to such Rules over which there is a dispute shall be filed with the Commission and shall become effective on the date specified by the Commission. (c) To the extent there still remain Reliability Upgrade or Economic Upgrade costs that are not allocated in accordance with other arrangements as identified in the introductory language of this Section (1) or subparagraphs (a) or (b) above, or the cost allocation determined in accordance with subparagraph (b) has not yet become effective, such costs shall be treated as Pool-Supported PTF costs recoverable under Attachment F to this Tariff. (2) Elective Transmission Upgrade Costs. The capital and annual costs of Elective Transmission Upgrades and of any additions to or modifications of the NEPOOL Transmission System that are required to accommodate the Elective Transmission Upgrades shall not constitute Pool-Supported PTF costs and shall not be included in Annual Transmission Revenue Requirements under Attachment F, except to the extent approved pursuant to the Agreement. Until further review by the NEPOOL Reliability Committee and amendment of this Tariff, contract and credit requirements for an Elective Transmission Upgrade shall be governed by the provisions of Section 50.2 of this Tariff. (3) Northeast Massachusetts Upgrade Costs. In recognition of the unique Congestion situation in the Northeast Massachusetts Reliability Region, as identified in Attachment B to the Agreement, up to thirty-five million dollars ($35,000,000) of the capital costs of Northeast Massachusetts Upgrades shall constitute Pool-Supported PTF costs and shall be included in Annual Transmission Revenue Requirements under Attachment F. A "Northeast Massachusetts Upgrade" is an addition to or modification of the NEPOOL Transmission System into or within the Northeast Massachusetts Reliability Region that is not, as of December 31, 1999, the subject of a System Impact Study or application filed pursuant to Section 18.4 of the Restated NEPOOL Agreement; that is not related to generation interconnections; and that will be completed and placed in service by June 30, 2004. Such upgrades include, but are not limited to, new transmission facilities and related equipment and/or modifications to existing transmission facilities and related equipment. Any Northeast Massachusetts Upgrade will be identified within a reasonable period of time and included in the NEPOOL Transmission Plan to be completed on or about September 1, 2000. A Northeast Massachusetts Upgrade also must satisfy one of the following three criteria: (a) The addition or modification qualifies as an Economic Upgrade. If an addition or modification meets these requirements, the full estimated capital cost of the upgrade shall be taken into account for purposes of the $35,000,000 aggregate limit specified above. (b) The addition or modification qualifies as a Reliability Upgrade meet a future reliability need within the five years covered by the NEPOOL Transmission Plan, and the net present value of the expected benefit advancing the construction of the addition or modification exceeds the incremental cost of advancing the in-service date of the addition or modification. The incremental cost of the advancement shall qualify as a cost of Pool-Supported PTF pursuant to this Section and only the incremental cost shall be taken into account for purposes of the $35,000,000 aggregate limit specified above. The remaining cost of the addition or modification shall qualify as the Pool-Supported PTF cost of a Reliability Upgrade. (c) The addition or modification is in construction as of January 1, 2000 or planned for construction in 2000 and would qualify as an Economic Upgrade except for the fact that it has not yet been included in a NEPOOL Transmission Plan. If an addition or modification meets this requirement, the full estimated capital cost of the addition or modification shall be taken into account for purposes of the $35,000,000 aggregate limit specified above. The aggregate capital costs of the Northeast Massachusetts Upgrades which qualify as Pool-Supported PTF costs shall not exceed $35,000,000. If there are multiple proposed additions or modifications which satisfy the criteria specified in paragraphs (a), (b), or (c) above, and the aggregate cost of such proposed additions or modifications to be taken into account for purposes of the $35,000,000 limit specified above exceeds $35,000,000, the proposed additions or modifications meeting the criteria specified in paragraph (a) or (b) above with the highest benefit/cost ratios shall be given priority. For this purpose, the benefit/cost ratio of an addition or modification is the net present value of the benefit of the addition or modification divided by the net present value of the cost of the addition or modification. In considering whether to undertake a proposed addition or modification which might otherwise qualify under this Subsection (3), the Transmission Owners and the System Operator shall not limit their consideration of alternative means of Congestion relief to transmission additions or modifications. SCHEDULE 13 Locational Prices; Congestion Cost; Congestion Revenue; Marginal Loss Cost; Marginal Loss Revenue A. Calculation of Locational Prices: When Congestion exists on the NEPOOL Transmission System, Congestion Cost and Marginal Loss cost shall be recovered, pursuant to Section B below, from Non-Participant Transmission Customers taking service under the Tariff. Congestion Cost and Marginal Loss Cost are derived from the Congestion Components and Marginal Loss Components of Locational Prices calculated as described below. (1) Nodal Prices for Nodes and External Nodes. 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 of the Agreement. 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 Section A(4) 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: (EQUATION) where: (EQUATION) the Nodal Price at Node i in $/megawatthour; (EQUATION) the marginal cost in $/megawatthour, based on Demand Bids and Supply Offers, to serve additional load at the Reference Node; (EQUATION) the Marginal Loss Component of the Nodal Price at Node i in $/megawatthour; and (EQUATION) 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 (EQUATION) in which WFi, the Withdrawal Factor at Node i relative to the system Reference Node, is calculated using the following equation: where: (EQUATION) L = NEPOOL Transmission System losses; Pi = the net amount of Energy injected into the NEPOOL Transmission System at Node i; and (EQUATION) = 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: (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 (EQUATION) 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 and into the equation for calculating the Nodal Price for a given Node i yields: (2) 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 certain time period ("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 a Zonal Price 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 calculated 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: (EQUATION) where: (EQUATION) = Zonal Price for Reliability Region j in $/megawatthour; (EQUATION) is the Marginal Loss Component of the Zonal Price for Reliability Region j in $/megawatthour; (EQUATION) 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. (3) 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: (EQUATION) where: (EQUATION) = Hub Price for Hub j in $/megawatthour; (EQUATION) is as defined in Section A(1); (EQUATION) is the Marginal Loss Component of the Hub Price for Hub j in $/megawatthour; (EQUATION) is the Congestion Component of the Hub Price for Hub j in $/megawatthour; Hj = the set of Nodes in Hub j; and WijH = 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 acquire FCRs to and from the Hub in accordance with Schedule 14 of the Tariff. (4) 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 that is received from or delivered 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 Nodes 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: (EQUATION) where: (EQUATION) = 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; GFin = Shift Factor at External Node i for the interconnection line that passes through Node n; and (WFn - 1) = the Marginal Loss Component of the Nodal Price at Node n in $/megawatthour, where WFn is the withdrawal factor at Node n and (EQUATION) is as defined in Section A(1). 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. B. Congestion Cost: (1) Congestion Cost. Congestion Cost shall be recovered under this Section B from each Non-Participant Transmission Customer taking service under the Tariff when the Congestion Component of the Locational Price at the Point of Delivery's Location exceeds the Congestion Component of the Locational Price at the Point of Receipt's Location for the transaction. In accordance with NEPOOL System Rules, each Transmission Customer may elect to specify a maximum Congestion Cost that it is willing to pay to have its transaction scheduled or to keep its transaction from being wholly or partially curtailed. The System Operator shall calculate Congestion Cost to be recovered from such customers for each hour of the Dispatch Day in which Congestion exists in the Day-Ahead and the Real-Time Markets. Such Congestion Cost recovered with respect to Day-Ahead transmission service scheduling shall equal (1) the amount (in $/megawatthour) by which the Congestion Component of the Day-Ahead Locational Price at the Point of Delivery's Location exceeds the Congestion Component of the Day-Ahead Locational Price at the Point of Receipt's Location; multiplied by (2) the quantity of Energy scheduled by the Transmission Customer for that hour. Such Congestion Cost recovered with respect to Real-Time transmission service scheduling shall equal (1) the amount (in $/megawatthour) by which the Congestion Component of the Real-Time Locational Price at the Point of Delivery's Location exceeds the Congestion Component of the Real-Time Locational Price at the Point of Receipt's Location; multiplied by (2) the quantity of Energy scheduled by the Transmission Customer for that hour, minus the quantity of Energy that Transmission Customer scheduled for that hour in its Day-Ahead transmission service scheduling. (2) Congestion Cost Relief. Each Non-Participant Transmission Customer taking Through or Out or Point-to-Point Service shall be paid or be credited for Congestion relief when the Congestion Component of the Locational Price at the Point of Receipt's Location exceeds the Congestion Component of the Locational Price at the Point of Delivery's Location for the transaction. The System Operator shall calculate and allocate such payments or credits to such customers for each hour of the Dispatch Day in which Congestion exists in the Day-Ahead and the Real-Time Markets. Such payments or credits made with respect to the Day-Ahead transmission service scheduling shall equal (i) the amount (in $/megawatthour) by which the Congestion Component of the Day- Ahead Locational Price at the Point of Receipt's Location exceeds the Congestion Component of the Day-Ahead Locational Price at the Point of Delivery's Location; multiplied by (ii) the quantity of Energy scheduled by the Transmission Customer for that hour. Such payments or credits made with respect to the Real-Time Market shall equal (i) the amount (in $/megawatthour) by which the Congestion Component of the Real-Time Locational Price at the Point of Receipt's Location exceeds the Congestion Component of the Real-Time Locational Price at the Point of Delivery's Location; multiplied by (ii) the quantity of Energy scheduled by the Transmission Customer for that hour, minus the quantity of Energy that Transmission Customer scheduled for that hour in its Day-Ahead transmission service scheduling. C. Congestion Revenue: For each hour the System Operator shall calculate and collect Congestion Revenue and maintain a Congestion Revenue Fund in accordance with Section E of Schedule 14. D. Marginal Loss Cost and Marginal Loss Revenue: (1) Marginal Loss Cost. Marginal Loss cost shall be recovered under this Section D from each Non-Participant Transmission Customer taking service under the Tariff when the Marginal Loss Component of the Locational Price at the Point of Delivery's Location exceeds the Marginal Loss Component of the Locational Price at the Point of Receipt's Location for the transaction. The System Operator shall calculate Marginal Loss cost to be recovered from such customers for each hour of the Dispatch Day. Such costs shall equal the amount (in $/megawatthour) of the Marginal Loss Component of the Real-Time Locational Price at the Point of Delivery's Location minus the Marginal Loss Component of the Real-Time Locational Price at the Point of Receipt's Location, multiplied by the amount of Energy scheduled for the transaction in that hour. Each Non-Participant Transmission shall be paid or credited when the Marginal Loss Component of the Real-Time Locational Price at the Point of Receipt's Location exceeds the Marginal Loss Component of the Real-Time Locational Price at the Point of Delivery's Location for the transaction. Such Marginal Loss payment or credit shall equal the amount (in $/megawatthour) of the Marginal Loss Component of the Real-Time Locational Price at the Point of Receipt's Location minus the Marginal Loss Component of the Real-Time Locational Price at the Point of Delivery's Location, multiplied by the amount of Energy scheduled for the transaction in that hour. (2) 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 in accordance with the Market Rules to load serving entities paying for Energy during such settlement period. E. Additional Rules and Procedures: Consistent with this Schedule 13, the implementation of its provisions shall further be detailed, defined and carried out pursuant to the Agreement and Market Rules. SCHEDULE 14 Financial Congestion Rights ("FCRs") The System Operator shall implement and administer a system of Financial Congestion Rights ("FCRs") as provided for below. A. FCR Holder Status and Transfer of FCRs: FCRs shall be awarded to winning bidders in the mandatory FCR Auctions pursuant to Section F below and may be acquired in the subsequent bilateral market from FCR Holders. An entity that acquires an FCR through the FCR Auction shall automatically be recognized by the System Operator as the registered FCR Holder of that FCR, subject to having already met the eligibility criteria for bidding in the FCR Auction. The registered FCR Holder shall be entitled to receive or be obligated to make FCR Payments arising from such FCR in accordance with Section C. An entity that acquires an FCR through the FCR Auction or through a subsequent bilateral transaction may elect to hold it, sell it in the FCR Auction or sell it bilaterally. The registered FCR Holder of an FCR sold in a bilateral transaction will continue to be the FCR Holder for that FCR unless it submits a confirmation of the sale to the System Operator in accordance with the Market Rules. The System Operator upon receipt of such a confirmation will transfer record ownership on its register. The purchaser of an FCR in a bilateral transaction that is not recorded on the System Operator's register receives only a contractual right against the seller of the FCR and has no rights or obligations in settlement or in the Energy market. An entity who subsequently acquires an FCR from an FCR Holder through a bilateral transaction must meet applicable criteria established by the Participants Committee, including creditworthiness criteria, to be the FCR Holder of that FCR and secure the associated rights and obligations. The System Operator shall settle FCRs only with the registered FCR Holders. At any given time, each FCR shall have only one registered FCR Holder. B. FCR Designation and Simultaneous Feasibility: FCRs shall be unidirectional, financial transmission rights based on the transfer capability of the NEPOOL Transmission System, denominated in Megawatts, designated to and from specified Locations and/or Reliability Regions, and lasting for a certain term. To the extent feasible, FCRs valid for on-peak and/or off-peak periods shall be available in the FCR Auctions and shall be accommodated in the FCR settlement process by the System Operator. Each FCR shall be designated to and from specified Locations and/or Reliability Regions for the purpose of determining FCR Payments. Each FCR shall also have a specified origin and destination Node that shall be used to determine to which new Load Zone and/or Reliability Region an existing FCR would be assigned if and when a Load Zone and/or Reliability Region were reconfigured. The System Operator shall determine, initially and periodically thereafter in conjunction with the FCR Auctions, the FCRs that can be made available based on a simultaneous feasibility test. The purpose of the test shall be to determine whether the NEPOOL Transmission System, under security constrained conditions, could accommodate all the potential transactions represented by a defined set of FCRs. The System Operator shall maintain a record of the FCRs, containing such information as is necessary to administer the system of FCRs including, but not limited to, each FCR's designated origin and destination Nodes and settlement Locations and/or Reliability Regions, Megawatt amount, registered Holder, and the period during which the FCR is valid. FCR Holders shall provide the System Operator with such information regarding the FCRs as is reasonably requested by the System Operator for the administration of the system of FCRs. An FCR Holder may, to the extent permitted by the Market Rules, subdivide FCRs into individually transferable components representing the intermediate points of injection and withdrawal contained within the FCR's path, such that an FCR from point A to point C, for example, may be subdivided prior to transfer based on the intermediate point B, resulting in two individually transferable FCRs, one from point A to point B, and one from point B to point C. Likewise, the Holder of an FCR that is valid for more than one hour may, to the extent permitted by the Market Rules, subdivide that FCR into individually transferable components representing subsets of those hours. For example, an FCR valid during January and February may be subdivided into an FCR valid during January and an FCR valid during February, each of which would be individually transferable. FCRs awarded in the FCR Auction or acquired through subsequent bilateral transactions may be reconfigured, but only through the System Operator. The System Operator shall facilitate the transfer and reconfiguration of FCRs, ensure their simultaneous feasibility, and register the FCR Holders of the reconfigured FCRs. In effecting the award or transfer of any FCR that can be subdivided into any of the following general and specific components, the System Operator shall subdivide the FCR into its general and specific components and record the FCR as having such components. The general components are Load Zone and/or Reliability Region to Load Zone and/or Reliability Region, Hub to Load Zone and/or Reliability Region, Load Zone and/or Reliability Region to Hub. The specific components are Node or External Node to Load Zone and/or Reliability Region in which the Node or External Node is located, Load Zone and/or Reliability Region to Node or External Node contained in the Load Zone and/or Reliability Region, and Node or External Node to Node or External Node contained in the same Load Zone and/or Reliability Region. Each FCR shall be designated to and from specified Locations and/or Reliability Regions for the purpose of determining FCR Payments. Each FCR shall also have a specified origin and destination Node that shall be used to determine to which new Load Zone and/or Reliability Region an existing FCR would be assigned if and when a Load Zone and/or Reliability Region were reconfigured. The System Operator shall determine, initially and periodically thereafter in conjunction with the FCR Auctions, the FCRs that can be made available based on a simultaneous feasibility test. The purpose of the test shall be to determine whether the NEPOOL Transmission System, under security constrained conditions, could accommodate all the potential transactions represented by a defined set of FCRs. The System Operator shall maintain a record of the FCRs, containing such information as is necessary to administer the system of FCRs including, but not limited to, each FCR's designated origin and destination Nodes and settlement Locations and/or Reliability Regions, Megawatt amount, registered Holder, and the period during which the FCR is valid. FCR Holders shall provide the System Operator with such information regarding the FCRs as is reasonably requested by the System Operator for the administration of the system of FCRs. An FCR Holder may, to the extent permitted by the Market Rules, subdivide FCRs into individually transferable components representing the intermediate points of injection and withdrawal contained within the FCR's path, such that an FCR from point A to point C, for example, may be subdivided prior to transfer based on the intermediate point B, resulting in two individually transferable FCRs, one from point A to point B, and one from point B to point C. Likewise, the Holder of an FCR that is valid for more than one hour may, to the extent permitted by the Market Rules, subdivide that FCR into individually transferable components representing subsets of those hours. For example, an FCR valid during January and February may be subdivided into an FCR valid during January and an FCR valid during February, each of which would be individually transferable. FCRs awarded in the FCR Auction or acquired through subsequent bilateral transactions may be reconfigured, but only through the System Operator. The System Operator shall facilitate the transfer and reconfiguration of FCRs, ensure their simultaneous feasibility, and register the FCR Holders of the reconfigured FCRs. In effecting the award or transfer of any FCR that can be subdivided into any of the following general and specific components, the System Operator shall subdivide the FCR into its general and specific components and record the FCR as having such components. The general components are Load Zone and/or Reliability Region to Load Zone and/or Reliability Region, Hub to Load Zone and/or Reliability Region, Load Zone and/or Reliability Region to Hub. The specific components are Node or External Node to Load Zone and/or Reliability Region in which the Node or External Node is located, Load Zone and/or Reliability Region to Node or External Node contained in the Load Zone and/or Reliability Region, and Node or External Node to Node or External Node contained in the same Load Zone and/or Reliability Region. C. FCR Payments: Except as provided in Section E below, each FCR Holder shall be entitled to receive for each hour of the Dispatch Day for which that FCR is valid an FCR Payment for an FCR when the Congestion Component of the Locational Price at the FCR's specified destination Location and/or Reliability Region exceeds the Congestion Component of the Locational Price at the FCR's specified origin Location and/or Reliability Region. Such FCR Payment shall equal the amount (in $/megawatthour) by which the Congestion Component of the Locational Price at the FCR's specified destination Location and/or Reliability Region exceeds the Congestion Component of the Locational Price at the FCR's specified origin Location and/or Reliability Region, multiplied by the Megawatt designation of the FCR for that hour. The FCR Holder shall be entitled to receive such FCR Payments independent of the FCR Holder's actual use of the NEPOOL Transmission System. In the event that in any hour of the Dispatch Day in which an FCR is valid the Congestion Component of the Locational Price at an FCR's specified origin Location and/or Reliability Region exceeds the Congestion Component of the Locational Price at the FCR's specified destination Location and/or Reliability Region, the FCR Holder of that FCR shall be obligated to make an FCR Payment. Such FCR Payment shall equal the amount (in $/megawatthour) by which the Congestion Component of the Locational Price at the FCR's specified origin Location exceeds the Locational Price at the FCR's specified destination Location, multiplied by the Megawatt designation of the FCR, for that hour. The FCR Holder shall be obligated to make such FCR Payments independent of the FCR Holder's actual use of the NEPOOL Transmission System. D. FCR Settlements: FCRs may be acquired from: Node to Node, Node to External Node, Node to Hub, Node to Load Zone, Node to Reliability Region; External Node to Node, External Node to External Node, External Node to Hub, External Node to Load Zone, External Node to Reliability Region; Hub to Node, Hub to External Node, Hub to Hub (if multiple Hubs are established), Hub to Load Zone, Hub to Reliability Region; Load Zone to Hub, Load Zone to Node, Load Zone to External Node, Load Zone to Load Zone, Load Zone to Reliability Region; Reliability Region to Node, Reliability Region to External Node, Reliability Region to Hub, Reliability Region to Load Zone, and Reliability Region to Reliability Region. Each FCR shall be settled based on its designated settlement Locations and/or Reliability Regions. FCRs shall be settled for the Day-Ahead Market not the Real-Time Market. FCRs shall be settled based on the difference between the Congestion Components of the relevant Locational Prices at the origin and destination Locations and/or Reliability Regions. E. Congestion Revenue Shortfalls or Surpluses: There may be instances (resulting from physical conditions on the NEPOOL Transmission System or other reasons) in which the total Congestion Revenue collected by the System Operator will be less or more than the sum of all Target FCR Payments, creating Congestion Revenue Shortfalls or Surpluses. A cash reserve in the Congestion Revenue Fund shall be established and maintained by the System Operator so as to minimize the impact on FCR Holders of Congestion Revenue Shortfalls. During each month, a Congestion Revenue Surplus would increase the cash reserve, and a Congestion Revenue Shortfall would decrease the cash reserve. The System Operator shall calculate the Congestion Revenue collected and the total Target FCR Payments on an hourly basis. The System Operator shall determine total Target FCR Payments by summing the Target FCR Payments in a given hour over all FCRs. The actual Congestion Revenue collections in each hour shall be calculated through the following steps: (1) multiplying the withdrawals at each Location and/or Reliability Regions by the Congestion Component of the Locational Price applying to that withdrawal; (2) summing the calculation in Step 1 over all withdrawals; (3) multiplying the injections at each Node by the Congestion Component of the Nodal Price applying to that injection; (4) summing the calculation in Step 3 over all injections; and (5) subtracting the total calculated in Step 4 from the total calculated in Step 2. If the actual Congestion Revenue collected in each hour, summed over all hours in a billing month, exceeds the total Target FCR Payments for each hour, summed over all hours in that billing month, then the difference will constitute a Congestion Revenue Surplus for that billing month. All Congestion Revenue Surpluses will be added to the Congestion Revenue Fund, and all FCR Payments made from the Congestion Revenue Fund to FCR Holders for that billing month shall be equal to the Target FCR Payments to those FCR Holders. If the actual Congestion Revenue collected in each hour, summed over all hours in a billing month, is less than the total Target FCR Payments for each hour, summed over all hours in that billing month, then the difference will constitute a Congestion Revenue Shortfall for that billing month. If there is a Congestion Revenue Shortfall for that billing month, but that Congestion Revenue Shortfall is not greater than the balance of the Congestion Revenue Fund cash reserve entering the month, then the Congestion Revenue Shortfall shall be deducted from the Congestion Revenue Fund, and all FCR Payments made from the Congestion Revenue Fund to FCR Holders for that billing month shall be equal to the Target FCR Payments to those FCR Holders. If the Congestion Revenue Shortfall for a month is greater than the balance of the Congestion Revenue Fund cash reserve entering the month, then that balance as of the conclusion of that month shall be set to zero, and the funds in the Congestion Revenue Fund will be used to make FCR Payments to FCR Holders. However, these funds, in combination with the Congestion Revenue collected in that billing month, will not be sufficient to permit the FCR Payment to each FCR Holder to be equal to the Target FCR Payment to that FCR Holder for every hour in that billing month. Consequently, each FCR Payment made by the Congestion Revenue Fund to an FCR Holder for an hour in that month shall be set equal to the Target FCR Payment that would have been payable to that FCR Holder for that hour multiplied by a proportionality factor. This proportionality factor (which shall be the same for all hours and all FCRs) shall be the number that makes the sum of all FCR Payments made by the Congestion Revenue Fund for that billing month equal to the sum of: (1) the balance of the Congestion Revenue Fund at the beginning of that billing month; (2) the Congestion Revenue collected for that billing month; (3) the FCR Payments made by FCR Holders to the Congestion Revenue Fund for that billing month; and (4) the amount paid, if any and to the extent provided for in the Market Rules, by generators interconnecting with the NEPOOL Transmission System for redispatch caused by interconnecting such generators. When an FCR Holder is obligated to make an FCR Payment in accordance with Section C above, the FCR Holder shall be obligated to make a payment to the Congestion Revenue Fund equal to the Target FCR Payment. This obligation shall not be affected by the existence of a Congestion Revenue Shortfall or Surplus. At the end of each calendar year, the balance of the Congestion Revenue fund will first be used to pay the holder of any FCR who received less than the Target FCR Payment with respect to that FCR in a month during the calendar year. To the extent that the balance is not sufficient to pay all such Target FCR Payment shortfalls, the shortfalls will be multiplied by a proportionality factor that makes the sum of all shortfalls equal to the balance in the Congestion Revenue fund. To the extent that the balance exceeds the amount required to pay all shortfalls, any remaining balance, with the exception of any amount that is retained in the Congestion Revenue Fund pursuant to the Market Rules, shall be allocated to those entities who paid for Congestion Cost either under the Agreement or the Tariff. Such allocation shall be in accordance with the Market Rules. F. FCR Auctions: Prior to the implementation of CMS, and on an annual and monthly basis following the CMS/MSS Effective Date, the System Operator shall perform a simultaneous feasibility test using appropriate power flow models of security-constrained dispatch to determine the feasible set of simultaneous FCRs that can be offered in the annual and monthly FCR Auctions. Such test shall take into account already awarded FCRs (following the first FCR Auction), and outages of both individual generation units and transmission facilities. Such tests shall be based on reasonable assumptions about the configuration and availability of transmission capability during the period covered by the FCR Auction. The System Operator shall perform the simultaneous feasibility test with the purpose of ensuring that there will be adequate Congestion Revenue under expected conditions to fund FCR Payments made to the purchasers of FCRs sold in the FCR Auction. FCRs shall be reconfigured and awarded in the FCR Auction to maximize the valuation of the awarded FCRs (based on buyers' bids) net of the value of the offered FCRs (based on sellers' reservation prices in the case of previously awarded FCRs offered for sale, or based on a zero price in the case of FCRs supporting payments to ARR Holders), subject to the constraint that the awarded FCRs must be simultaneously feasible in a security constrained dispatch in conjunction with all FCRs already awarded in the FCR Auction or acquired through subsequent bilateral transactions and held by FCR Holders and not offered into the auction. Based on the outcome of the System Operator's simultaneous feasibility tests, FCRs shall be made available to Eligible FCR Bidders through periodic FCR Auctions conducted by the System Operator or another authorized agent of the NEPOOL Participants. An "Eligible FCR Bidder" is an entity that has satisfied the reasonable creditworthiness criteria set by the Participants Committee, and shall not include the Auctioneer, its affiliates, and their officers, directors, employees, consultants and other representatives. FCR Auctions shall initially be held on both a biannual and a monthly basis. In the initial biannual FCR Auction, the maximum term of the awarded FCRs shall be six months. Ten percent of the transfer capacity of the NEPOOL Transmission System will be made available to support the sale in this initial auction of FCRs with a term of six months. During the second biannual FCR Auction, twenty-five percent of the transfer capacity of the NEPOOL Transmission System will be made available to support FCRs with a term of six months. During this initial twelve-month period, following each biannual FCR Auction, the remaining transfer capability of the NEPOOL Transmission System will be made available to support the sale of FCRs with a term of one month in the monthly FCR Auctions. Following the initial auctions, FCR Auctions shall be held on both an annual and a monthly basis. Fifty percent of the feasible FCRs that can be made available with a term of one (1) year to five (5) years (in one-year increments for the five calendar years immediately subsequent to the FCR Auction) shall be made available in the annual FCR Auction conducted in accordance with the Market Rules. Each Eligible FCR Bidder may submit bids in the annual FCR Auction for FCRs for a single year or for multiple years in the five-year period covered by the auction. Each Eligible FCR Bidder in the annual FCR Auction shall specify the year or years for which it wishes to purchase a specified FCR. After the annual FCR Auction has been conducted, the remaining feasible FCRs, each having a term of one month, shall be made available in monthly FCR Auctions conducted in accordance with the Market Rules. After each auction of monthly FCRs is complete, a residual FCR sale mechanism shall be established pursuant to the Market Rules, in which any FCR that is simultaneously feasible in conjunction with all outstanding FCRs may be purchased on a daily, peak and off-peak basis for any day of the next month. Each offer to sell a previously awarded FCR shall identify the FCR by Megawatt quantity and the FCR's origin and destination Locations and/or Reliability Regions and other pertinent information as required by the Market Rules. An offer to sell a specified Megawatt quantity of FCRs shall be deemed an offer to sell a quantity of FCRs equal to or less than the specified quantity. An offer to sell may not specify a minimum quantity being offered. Each offer to sell a previously awarded FCR may specify a reservation price, below which the offeror will not sell the FCR. Each bid to buy an FCR shall specify the Megawatt quantity, price per Megawatt, and specific origin and destination Locations and/or Reliability Regions of the FCR and other pertinent information as required by the Market Rules. A bid to purchase a specified Megawatt quantity of FCRs shall be deemed a bid to purchase a quantity of FCRs equal to or less than the specified quantity. A bid to purchase may not specify a minimum quantity that the bidder wishes to purchase. A bid to purchase may specify any origin and destination Locations and/or Reliability Regions for which the System Operator calculates Locational Prices. Offers and bids in the FCR Auction may specify on-peak and off-peak time periods of the Dispatch Day for which an FCR will be valid. The System Operator shall model all existing FCRs not offered into the FCR Auction in the simultaneous feasibility test as fixed injections and withdrawals on the NEPOOL Transmission System for their remaining term, thereby in effect reserving the transfer capability required to honor the existing FCR. FCRs to and from a Hub shall be treated in the simultaneous feasibility test as injections and withdrawals at each Node comprising that Hub, with the amount injected or withdrawn at each such Node corresponding to the weight assigned by the System Operator to that Node when calculating the Hub Price at that Hub in the Day-Ahead Market. FCRs to and from Load Zones and/or Reliability Regions shall be treated in the simultaneous feasibility test as injections and withdrawals at each Node in that Load Zone and/or Reliability Regions, with the amount injected or withdrawn at each such Node corresponding to the weights assigned by the System Operator to that Node when calculating the Zonal Price for that Load Zone and/or Reliability Regions in the Day-Ahead Market. The System Operator's simultaneous feasibility test shall also test for revenue adequacy under future Load Zone and/or Reliability Regions definitions through a second test in which FCRs with a term of one year or more to and from Load Zones and/or Reliability Regions would be treated as injections and withdrawals at the designated origin and destination Locations and/or Reliability Regions for each FCR. Each winning bidder for an FCR in an FCR Auction shall pay the market- clearing price as determined by the FCR Auction, for the awarded FCR when that price is positive. If the market-clearing price for the awarded FCR is negative, the winning bidder for that FCR shall receive a payment equal to the absolute value of the market-clearing price for that FCR. Each seller of an FCR in the FCR Auction shall be paid the market-clearing price, as determined by the FCR Auction, for the FCR sold when that price is positive. If the market-clearing price for the FCR sold is negative, the seller of that FCR shall make a payment equal to the absolute value of the market-clearing price for that FCR. As soon as feasible and in accordance with the Market Rules, the System Operator shall post on its Internet website the market- clearing price of each FCR sold in the FCR Auction. Revenues from the FCR Auctions shall be collected by the System Operator or another authorized agent of the NEPOOL Participants and held in the Auction Revenue Fund. FCR Auction Revenue shall be allocated to FCR Holders who sell their FCRs in the FCR Auction and to Auction Revenue Rights Holders as described in Schedule 15 and Section 49. G. FCRs as Options: To the extent feasible, as determined by the Participants Committee and the System Operator, FCRs in the form of financial options shall be available through the FCR Auctions. The rules governing such option type FCRs, if such FCRs have been determined feasible, shall be stated in the Tariff and detailed in the NEPOOL System Rules. H. Additional Rules and Procedures: Consistent with this Schedule 14, the implementation of its provisions shall further be detailed, defined and carried out pursuant to the Market Rules. SCHEDULE 15 Auction Revenue Rights Auction Revenue Rights ("ARRs") are rights to receive FCR Auction Revenues from the sale of FCRs other than FCRs sold by FCR Holders. ARRs shall be determined and allocated to Congestion Paying Entities, Transmission Customers and NEMA LSEs (including any of the foregoing that are parties to Excepted Transactions that are included in the list of transactions in Attachments G and G-2 of the Tariff), using a four-stage process as described below (the "ARR Allocation"). A. First Stage of ARR Allocation (1) Excepted Transactions. In the first stage of each ARR Allocation, each entity serving load to which Energy is delivered pursuant to an Excepted Transaction included in the list of transactions in Attachments G and G-2 of the Tariff, and which is the party responsible for paying Congestion Cost associated with Energy purchased under the Excepted Transaction shall have the option to be allocated ARRs from the generator to the location of the load. Alternatively, each seller delivering Energy pursuant to an Excepted Transaction to an entity serving load and which seller is the party responsible for paying Congestion Cost associated with Energy purchased under the Excepted Transaction shall have the option to be allocated ARRs from the generation source to the load. In order to be eligible to receive ARRs in association with an Excepted Transaction, each entity to which Energy is delivered pursuant to an Excepted Transaction or which delivers Energy pursuant to an Excepted Transaction must request that it be allocated ARRs pursuant to this section prior to the second stage of the ARR Allocation. The first-stage ARR Allocation to an entity serving load to which Energy is delivered pursuant to an Excepted Transaction who makes such a request shall be equal to the number of Megawatts of Energy to be delivered to that customer under the Excepted Transaction. The origin Node or External Node for those ARRs shall match the generation source for any such Excepted Transaction and the destination Locations and/or Reliability Regions for those ARRs shall match the location of the load served by those Excepted Transactions. The first-stage ARR Allocation to an entity selling Energy to an entity serving load to which Energy is delivered pursuant to an Excepted Transaction who makes such a request shall be equal to the number of Megawatts of Energy to be delivered by that selling entity under the Excepted Transaction. The origin Node or External Node for those ARRs shall match the generation source for any such Excepted Transaction and the destination Locations and/or Reliability Regions for those ARRs shall match the Locations and/or Reliability Regions of the load served by those Excepted Transactions. Each entity shall be entitled to make requests for ARRs under the terms of this section until the Excepted Transaction has terminated, or ten years from the CMS/MSS Effective Date, whichever is earlier. (2) Transmission Customers and Congestion Paying Entities. ARRs shall be allocated to each Congestion Paying Entity and Transmission Customer from each NEPOOL generator and tie line source in proportion to the capacity of the generator and tie line source and in proportion to the Monthly Peak Load served by that Congestion Paying Entity or Transmission Customer, provided, however, that the allocation of first-stage ARRs to Transmission Customers under this Section A(2) shall be in proportion to: (i) the Transmission Customer's Monthly Peak Load not served by a Congestion Paying Entity, less (ii) any portion of the Transmission Customer's or Congestion Paying Entity's load for which ARRs have been allocated pursuant to the Excepted Transaction election described above. The determination of the first-stage ARR Allocation to Transmission Customers and Congestion Paying Entities shall be performed using the following formula: Nijkt = Git * (Ljkt/Lt), where: Nijkt = the amount of ARRs from Node or External Node i to Reliability Region j awarded to Transmission Customer or Congestion Paying Entity k for month t; Git = the total rated capacity for month t of generators or the capacity during month t-1 of tie line capacity located at node i; Ljkt= the Monthly Peak Load of Transmission Customer or Congestion Paying Entity k calculated on the basis of its Monthly Peak Load during the same month t of the prior year in Reliability Region j, less any portion of that Monthly Peak Load (up to a maximum of the total Monthly Peak Load) for which ARRs have been allocated in association with Excepted Transactions as described above; and Lt = total Monthly Peak Load during month t of the prior year. The total quantity of ARRs assigned pursuant to this Section A(2) to Transmission Customer or Congestion Paying Entity k in month t shall be: (EQUATION) B. Second Stage of ARR Allocation: The amount of ARRs allocated to each entity in the first stage of each ARR Allocation may be modified in the second stage of that ARR Allocation. The second stage of each ARR Allocation shall determine the final allocation of ARRs to all ARR Holders for that FCR Auction, except for NEMA LSEs. Allocations of ARRs to NEMA LSEs may be modified in the third and fourth stages of the ARR Allocation for each FCR Auction. The second stage of each ARR Allocation shall be performed using the following procedure, which will be adjusted on an annual and monthly basis to account for changes in available transmission capacity, load ratio shares, transfer of load obligations and the termination or expiration of Excepted Transactions. The System Operator shall make such adjustments in accordance with the allocation methodology described below, the Agreement, and NEPOOL System Rules. Step 1: Begin with the combination of all ARRs included in the first-stage ARR Allocation described in Section A above. This set of ARRs almost certainly will not be simultaneously feasible. Step 2: Hold the FCR Auction as described in Section F of Schedule 14. Step 3: Through the following steps, eliminate ARRs having a negative value in the FCR Auction and then reduce the set of remaining ARRs defined in Step 1 proportionately on a per Megawatt of constraint impact basis as necessary to arrive at a set of ARRs that is simultaneously feasible in a contingency constrained dispatch. 3(a): Identify all ARRs determined in Step 1 that receive a positive value (in $/Megawatt) in the FCR Auction. 3(b): Test whether the ARRs identified in Step 3(a) are simultaneously feasible. 3(c): If the ARRs identified in Step 3(a) are simultaneously feasible, go to Step 4. 3(d): If the ARRs identified in Step 3(a) are not simultaneously feasible, calculate the pre- and post-contingency power flows associated with dispatching the system to honor the ARRs defined in Step 3(a). 3(e): Identify the constraint whose relief would require the largest proportionate reduction in all of the ARRs defined in Step 3(a) that increase flows over that constraint. Reduce proportionately on a per Megawatt of constraint impact basis all ARRs defined in Step 3(a) that increase flows over this constraint until the constraint is relieved. 3(f): Test whether the ARRs identified in Step 3(e) are simultaneously feasible. If the set of ARRs defined in Step 3(e) is simultaneously feasible, proceed to Step 4. 3(g): Otherwise, calculate the pre- and post-contingency power flows associated with dispatching the system to honor the ARRs defined in Step 3(e). 3(h): Identify the constraint whose relief would require the largest proportionate reduction in all of the ARRs defined in Step 3(e) that increase flows over that constraint. Reduce proportionately on a per Megawatt of constraint impact basis all ARRs defined in Step 3(e) that increase flows over this constraint until the constraint is relieved. 3(i) Repeat Steps 3(f) through 3(h) as necessary until a simultaneously feasible set of ARRs is obtained. 3(j) If as a result of the application of Steps 3(e) through 3(i) any of the constraints over which ARRs were reduced in Steps 3(e) through 3(i) is no longer binding, ARRs defined in Step 3(a) that have been reduced in Steps 3(e) through 3(i) and do not exacerbate any binding transmission constraint would be proportionately scaled up until a transmission constraint becomes binding. The allocation process ends here if NEMA is not significantly constrained and the ARRs allocated at the conclusion of Step 3(j) constitute the final allocation of ARRs. Step 4. The ARR Allocation determined in the preceding steps shall be divided into two sets: ARRs allocated to entities that are not NEMA LSEs, and ARRs allocated to NEMA LSEs. NEMA LSEs are Transmission Customers and Congestion Paying Entities that serve load within NEMA. C. Third Stage of ARR Allocation. The ARRs allocated to NEMA LSEs, as determined in the first two stages of each ARR Allocation, may be modified further in the third and fourth stages of the ARR Allocation. The third and fourth stages of any ARR Allocation shall not change the amount or origin Nodes or External Nodes or destination Locations and/or Reliability Regions of any ARRs allocated to entities that are not NEMA LSEs as of the conclusion of the second stage of that ARR Allocation. For the purposes of this stage, a set of "Stage 3 ARRs" shall be defined as follows: Certain NEMA LSEs which have long-term purchase contracts in effect as of November 1, 1999 for generation resources with delivery points in NEMA, excluding long-term purchase contracts covered by Excepted Transactions, ("NEMA Contracts") shall be allocated Stage 3 ARRs. The NEMA Contracts for these NEMA LSEs' respective generation resources and entitlements, which entitle them to Stage 3 ARRs subject to verification that the NEMA Contracts meet the criteria specified in the preceding sentence, are listed in Attachment 1 to this Schedule 15. Each NEMA LSE listed in Attachment 1 shall provide by October 1, 2000 to the System Operator and shall make available upon request to each NEMA LSE, copies of its NEMA Contract(s) in the form that such contracts existed as of November 1, 1999, together with copies of any subsequent modifications or amendments, any notices of termination, and any notices or elections shortening the term or reducing the amount of power to be purchased under its NEMA Contract(s). For as long as a NEMA LSE listed in Attachment 1 has a right to request Stage 3 ARRs, it shall have an ongoing obligation to provide, in a timely manner, each NEMA LSE and the System Operator with copies of any further modifications or amendments, any notices of termination, and any notices or elections shortening the term or reducing the amount of power to be purchased under its NEMA Contract. The amount of Stage 3 ARRs that will be allocated to each NEMA LSE shall be equal to the sum of the Megawatts of entitlement specified in each NEMA LSE's NEMA Contract(s) calculated based on the winter capability period (the period from the beginning of October through the end of May) capacity during months of the winter capability period and the summer capability period (the period from the beginning of June through the end of September) capacity during the months of the summer capability period subject to the limitation that the Stage 3 ARRs allocated to each NEMA LSE shall not exceed that NEMA LSE's Monthly Peak Load during that month of the prior year, as defined in the NEPOOL Tariff. The origin Node or External Node for the Stage 3 ARRs allocated to NEMA LSEs shall match the Node or External Node where Energy was purchased in association with the NEMA Contracts listed in Attachment 1, and the destination Location for the Stage 3 ARRs allocated to NEMA LSEs shall match the Location of the load served by that NEMA LSE in association with that contract. The NEMA LSEs identified in Attachment 1 to this Schedule 15 shall be entitled to make requests for Stage 3 ARRs under the terms of this section until the earlier of the expiration of the term of each of its NEMA Contract(s) in effect as of November 1, 1999, but excluding any optional extensions which had not been exercised as of November 1, 1999, or until NEMA is no longer significantly constrained. To the extent that such a NEMA LSE transfers to other another entity the responsibility under the Agreement or the Tariff for paying for the Congestion Cost and RMR Charge, resulting from the NEMA LSE's NEMA Contract, the entity assuming such responsibility shall receive the entitlement to the NEMA LSE's Stage 3 ARRs in lieu of the NEMA LSE receiving that entitlement. The third stage of each ARR Allocation shall be performed using the following procedure, which will be adjusted on an annual and monthly basis to account for changes in available transmission capacity, load ratio shares, transfer of load obligations, reductions in or resale of purchase amounts under NEMA Contracts, and the termination of the NEMA Contract(s) or expiration of the term of the NEMA Contract(s) in effect as of November 1, 1999, but excluding any optional extensions which had not been exercised as of November 1, 1999. The System Operator shall make such adjustments in accordance with the allocation methodology described below, the Agreement, and the NEPOOL System Rules: Step 1: Begin with the set of all Stage 3 ARRs. Step 2: Through the following steps, eliminate Stage 3 ARRs having a negative value in the FCR Auction and then reduce the set of remaining Stage 3 ARRs proportionately on a per Megawatt of constraint impact basis as necessary to arrive at a set of ARRs that is simultaneously feasible in a contingency constrained dispatch. 2(a): Identify all ARRs determined in Step 1 that receive a positive value (in $/Megawatt) in the FCR Auction. Then add the set of all non-NEMA ARRs as determined in Step 4 of Stage 2 to the remaining Stage 3 ARRs. 2(b): Test whether the ARRs identified in Step 2(a) are simultaneously feasible. 2(c): If the ARRs identified in Step 2(a) are simultaneously feasible, go to Step 3. 2(d): If the ARRs identified in Step 2(a) are not simultaneously feasible, calculate the pre- and post-contingency power flows associated with dispatching the system to honor the ARRs defined in Step 2(a). 2(e): Identify the constraint whose relief would require the largest proportionate reduction in all of the Stage 3 ARRs defined in Step 2(a) that increase flows over that constraint. Reduce proportionately on a per Megawatt of constraint impact basis all Stage 3 ARRs defined in Step 2(a) that increase flows over this constraint until the constraint is relieved. 2(f): Test whether the ARRs identified in Step 2(e) are simultaneously feasible. If the set of ARRs defined in Step 2(e) is simultaneously feasible, proceed to Step 3. 2(g): Otherwise, calculate the pre- and post-contingency power flows associated with dispatching the system to honor the ARRs defined in Step 2(e). 2(h): Identify the constraint whose relief would require the largest proportionate reduction in all of the Stage 3 ARRs defined in Step 2(e) that increase flows over that constraint. Reduce proportionately on a per Megawatt of constraint impact basis all Stage 3 ARRs defined in Step 2(e) that increase flows over this constraint until the constraint is relieved. 2(i) Repeat Steps 2(f) through 2(h) as necessary until a simultaneously feasible set of ARRs is obtained. 2(j) If as a result of the application of Steps 2(e) through 2(i) any of the constraints over which ARRs were reduced in Steps 2(e) through 2(i) is no longer binding, ARRs defined in Step 2(a) that have been reduced in Steps 2(e) through 2(i) and do not exacerbate any binding transmission constraint would be proportionately scaled up until a transmission constraint becomes binding. Step 3. Remove the non-NEMA ARRs. The remaining ARRs will be the ARRs for the NEMA Contracts. D. Fourth Stage of ARR Allocation. The fourth stage of the ARR Allocation shall determine the final allocation of ARRs for a given FCR Auction. The fourth stage shall only affect the allocation of ARRs to NEMA LSEs. For the purposes of this step, a set of "Stage 4 ARRs" shall be defined. Each NEMA LSE shall be allocated Stage 4 ARRs, using the following formula: Nikt = Aikt * Xkt where: Nikt = the amount of Stage 4 ARRs from Node or External Node i to the Locations within NEMA allocated to NEMA LSE k for month t; Aikt = the amount of ARRs from Node i to NEMA that had been allocated to NEMA LSE k for month t as of the conclusion of the second stage of the ARR Allocation; and Xkt = the ratio of (the Monthly Peak Load of NEMA LSE k calculated on the basis of its Monthly Peak Load during the same month t of the prior year less the allocation of ARRs for NEMA Contracts to NEMA LSE k for month t) to the Monthly Peak Load of NEMA LSE k in month t of the prior year. The fourth stage of each ARR Allocation shall be performed using the following procedure, which will be adjusted on an annual and monthly basis to account for changes in available transmission capacity, load ratio shares, transfer of load obligations, reductions in purchase amounts under NEMA Contracts, and the termination of the NEMA Contract(s) or expiration of the term of the NEMA Contract(s) in effect as of November 1, 1999, but excluding any optional extensions which had not been exercised as of November 1, 1999. The System Operator shall make such adjustments in accordance with the allocation methodology described below, the Agreement, and NEPOOL System Rules: Step 1: Begin with the set of all Stage 4 ARRs. Step 2: Through the following steps, eliminate negatively-valued Stage 4 ARRs and then reduce the set of remaining Stage 4 ARRs proportionately on a per Megawatt of constraint impact basis as necessary to arrive at a set of ARRs that is simultaneously feasible in a contingency constrained dispatch. 2(a): Identify all ARRs determined in Step 1 that receive a positive value (in $/Megawatt) in the FCR Auction. Then add the set of all non-NEMA ARRs and all ARRs for NEMA Contracts to the remaining Stage 4 ARRs. 2(b): Test whether the ARRs identified in Step 2(a) are simultaneously feasible. 2(c): If the ARRs identified in Step 2(a) are simultaneously feasible, go to Step 3. 2(d): If the ARRs identified in Step 2(a) are not simultaneously feasible, calculate the pre- and post-contingency power flows associated with dispatching the system to honor the ARRs defined in Step 2(a). 2(e): Identify the constraint whose relief would require the largest proportionate reduction in all of the Stage 4 ARRs defined in Step 2(a) that increase flows over that constraint. Reduce proportionately on a per Megawatt of constraint impact basis all Stage 4 ARRs defined in Step 2(a) that increase flows over this constraint until the constraint is relieved. 2(f): Test whether the ARRs identified in Step 2(e) are simultaneously feasible. If the set of ARRs defined in Step 2(e) is simultaneously feasible, proceed to Step 3. 2(g): Otherwise, calculate the pre- and post-contingency power flows associated with dispatching the system to honor the ARRs defined in Step 2(e). 2(h): Identify the constraint whose relief would require the largest proportionate reduction in all of the Stage 4 ARRs defined in Step 2(e) that increase flows over that constraint. Reduce proportionately on a per Megawatt of constraint impact basis all Stage 4 ARRs defined in Step 2(e) that increase flows over this constraint until the constraint is relieved. 2(i) Repeat Steps 2(f) through 2(h) as necessary until a simultaneously feasible set of ARRs is obtained. 2(j) If as a result of the application of Steps 2(e) through 2(i) any of the constraints over which ARRs were reduced in Steps 2(e) through 2(i) is no longer binding, ARRs defined in Step 2(a) that have been reduced in Steps 2(e) through 2(i) and do not exacerbate any binding transmission constraint would be proportionately scaled up until a transmission constraint becomes binding. Step 3. The remaining ARRs constitute the final allocation of ARRs. Holders of ARRs in this allocation shall be deemed ARR Holders. E. Payments to ARR Holders. Each ARR Holder shall be entitled to receive a share of the Auction Revenues from each annual or monthly FCR Auction reflecting the value in that auction of FCRs, other than those sold by FCR Holders, corresponding to its ARRs, whether or not such specific FCRs are actually sold. This share shall equal the amount of ARRs (quantified in Megawatts) received in the final allocation of ARRs with specified origin Nodes or External Nodes and destination Locations and/or Reliability Regions that it holds which cover the period for which FCRs were sold in that auction, multiplied by the value determined in that FCR Auction for FCRs with the same origin Nodes or External Nodes and destination Locations and/or Reliability Regions as the ARRs. The determination of the FCRs awarded in each FCR Auction shall be subject to a simultaneous feasibility test in accordance with Schedule 14. The amount of feasible FCRs available in the FCR Auction (and the corresponding Auction Revenues and payments to ARR Holders) will vary depending on transmission system conditions. F. Annual and Monthly ARR Adjustments. ARR Holders who receive a share of the Auction Revenues from FCRs sold in the annual FCR Auction and whose load serving responsibility (as reflected in the NEPOOL market settlement system) decreases in subsequent months in the same year shall retain the annual ARR payments, but shall be allocated a smaller share of ARRs, in proportion to their decrease in load ratio share, to the monthly Auction Revenues. G. Incremental ARRs. An entity who pays for new transmission upgrades which increase transfer capability on the NEPOOL Transmission System, making it possible for the System Operator to award additional FCRs in the FCR Auction, shall be awarded ARRs. The amount of ARRs awarded to such an entity, and the origin and destination Locations and/or Hubs for those ARRs, shall be consistent with the FCRs that were made possible by the transmission upgrade, as determined by the System Operator and the FCRs awarded in the auction. The award shall be in direct proportion to the percentage of the costs of the upgrade paid by such entity, and shall continue for so long as the entity supports the costs of the upgrade. ARRs awarded to an entity who pays for transmission upgrades will not be subject to reduction in Stages 2, 3 and 4 of the ARR Allocation process described above. To the extent that transmission upgrades resulting in new transfer capability are paid for through the Pool RNS Rate, any Auction Revenue Rights associated with the sale of FCRs made possible by such upgrades, other than FCRs sold by FCR Holders, shall be allocated to Transmission Customers and Congestion Paying Entities on a Monthly Peak Load basis. H. Additional Rules and Procedures. Consistent with this Schedule 15, the implementation of its provisions shall further be detailed, defined and carried out pursuant to Market Rules. ATTACHMENT 1 TO SCHEDULE 15 TABLE 1 NEMA CONTRACTS NEMA Load-Serving Entity NEMA Contract Entitlements(FN1) Danvers 1. Millstone 3 (.263%) 2. Seabrook (1.12%) 3. Stony Brook Combined Cycle (8.457%) 4. Stony Brook 2A (11.555%) 5. Stony Brook 2B (11.555%) 6. Vermont Yankee (1.08 MW) 7. Hydro Quebec (2.93 MW (winter)) 8. NYPA (2.44 MW) Georgetown 1. Millstone 3 (.021%) 2. Seabrook (.096%) 3. Stony Brook Combined Cycle (.736%) - ------ (FN1) NEMA Contract entitlements are stated by percentage in case of unit entitlements held on percentage basis, and by megawatts (MW) where contract states entitlement in MW. 4. Stony Brook 2A (1.014%) 5. Stony Brook 2B (1.014%) 6. Vermont Yankee (.144 MW) 7. System Power (Select Energy) (2.0 MW) 8. Hydro Quebec (.280 MW (winter)) 9. NYPA (.620 MW) Ipswich 1. Millstone 3 (.061%) 2. Seabrook (.107%) 3. Stony Brook Combined Cycle (.293%) 4. Vermont Yankee (.522 MW) 5. NYPA (1.35 MW) Marblehead 1. Millstone 3 (.154%) 2. Seabrook (.135%) 3. Stony Brook Combined Cycle (2.64%) 4. Stony Brook 2A (1.598%) 5. Stony Brook 2B (1.598%) 6. Wyman 4 (.279%) 7. Vermont Yankee (.655 MW) 8. Hydro Quebec (1.040 MW (winter)) 9. NYPA (2.140 MW) Middleton 1. Millstone 3 (.044%) 2. Seabrook (.328%) 3. Stony Brook Combined Cycle (.878%) 4. Stony Brook 2A (1.892%) 5. Stony Brook 2B (1.892%) 6. Wyman 4 (.101%) 7. Vermont Yankee (.213%) 8. System Power (NU) (10.5 MW) 9. Hydro Quebec (.580 MW (winter)) 10. NYPA (.6 MW) Peabody 1. Millstone 3 (.297%) 2. Seabrook (1.13%) 3. Stony Brook Combined Cycle (13.052%) 4. Vermont Yankee (1.693 MW) 5. Hydro Quebec (3.480 MW (winter)) 6. NYPA (4.860 MW) Reading 1. Millstone 3 (.404%) 2. Seabrook (.635%) 3. Stony Brook Combined Cycle (14.453%) 4. Stony Brook 2A (19.516%) 5. Stony Brook 2B (19.516%) 6. System Power (NU) 15 MW (out of a total of 30 - remaining 15 MW are Excepted Transactions) 7. Hydro Quebec (5.710 MW (winter)) Wakefield 1. Millstone 3 (.206%) 2. Seabrook (.387%) 3. Stony Brook (3.993%) 4. Stony Brook 2A (6.379%) 5. Stony Brook 2B (6.379%) 6. Wyman 4 (.440%) 7. Vermont Yankee (.885 MW) 8. Hydro Quebec (1.520 MW (winter)) 9. NYPA (2.230 MW) Concord 1. Hydro Quebec (.890 MW (winter)) Groveland 1. System Power (NU) (6.1 MW) 2. NYPA (.510 MW) Merrimac 1. System Power (NU) (4.9 MW) 2. NYPA (.520 MW) Rowley 1. System Power (NU) (6.7 MW) 2. Hydro Quebec (.2 MW (winter)) 3. NYPA (.510) SCHEDULE 16 System Restoration and Planning Service from Generators System Restoration and Planning Service is necessary to ensure the continued reliable operation of the New England Transmission System. System Restoration and Planning Service enables the System Operator to designate specific generators interconnected to the transmission or distribution system at strategic locations capable of supplying load to re-energize the transmission system following a system-wide blackout. These designated generators are able to start without an outside electrical supply and are otherwise known as "Black Start Capable." The planning and maintenance of adequate capability for restoration of the NEPOOL Control Area following a blackout represents a benefit to all entities using the power system. Therefore, this service must be taken from the System Operator. In contrast to the System Restoration and Planning Service described herein, the actual supply of power that would allow a power producer to restart its own generating units may itself be self-supplied or purchased from another power producer independent of the NEPOOL Control Area arrangements formulated by the System Operator. The Black Start Capability intrinsic of System Restoration and Planning Service is to be provided by designated Participants through the System Operator. I. Rate Formulas A Transmission Customer Purchasing either Regional Network Service under Schedule 9 of this Agreement or Internal Point to Point Service under Schedule 10 of this Agreement, or a Transmission Customer making Unauthorized Use shall be required to pay NEPOOL for its share of Black Start Restoration and Planning Service ("Black Start Responsibility") as determined in accordance with the following formulas: MRSR = (EQUATION) Where: MRSR = The Transmission Customers' Monthly Restoration Service Rate. NL = The aggregate of the individual sums of each Participant's or Non- Participant's Network Load for the billing month. IPP = The aggregate of the individual sums of each Participant's or Non- Participant's maximum Reserved Capacity for Internal Point-to-Point Service for each load served within a Local Network or Network(s) during the billing month. UAU = The aggregate of the individual sums of each Participant's or Non- Participant's Maximum Unauthorized Use associated with Internal Point-to- Point Service for each load served within a Local Network or Network(s) during the month. C = The annual cost of Service as determined from Supplement 1. Each individual Participant's or Non-Participant's charge in any billing month would be calculated by the following formula: MC = (MRSR)(NLi + IPPi + UAUi) Where MC = The Monthly Charge. NLi = The sum of a Participant's or Non-Participant's Network Load for the billing month. IPPi = The sum of a Participant's or Non-Participant's maximum Reserved Capacity for Internal Point-to-Point Service for each load served within a Local Network or Network(s) during the billing month. UAUi = The sum of a Participant's or Non-Participant's Maximum Unauthorized Use associated with Internal Point-to-Point Service for each load served within a Local Network or Network(s) during the month. A separate charge for this service based upon the above rates will be added to the Transmission Customer's monthly bill. The above rates are based upon generator expense as determined by Supplement 1. II. III. Compensation to Generators A. Eligibility. In order to be designated as a "Black Start Generator" providing System Restoration Service and to be eligible for compensation under this Schedule 16 of the NEPOOL Open Access Transmission Tariff, a generator must meet the following criteria: 1. The unit is "Black Start Capable" in that it has the ability of being started without energy from other NEPOOL generating units in such a way that it meets all of the requirements stated in Operating Procedure 11 (Black Start Capability Eligibility & Testing Requirements); and 2. The unit owner, NEPOOL, and the System Operator agree that the unit should be designated Black Start Capable and accordingly is listed as a Black Start unit in Operating Procedure 11. Each generator which is eligible for and seeks compensation under the NEPOOL Open Access Transmission Tariff for providing System Restoration Service shall execute an agreement with NEPOOL. III. Effective Date. This Schedule 16 shall be effective as of September 1, 1998. Supplement 1 To Schedule 16 System Restoration and Planning Service Revenue Requirement The annual Revenue Requirement for System Restoration and Planning Service will be the sum of the annual revenue requirements for each generator which is designated in NEPOOL Operating Procedure 11 as providing Black Start Service and which has provided to the System Operator, along with work papers and supporting documents, a calculation of its annual Revenue Requirement, determined in accordance with this Supplement 1. Each Black Start Generator's Revenue Requirement will reflect the generator's costs for its Black Start equipment as listed in Exhibit 1. Each Generator's Revenue Requirement will be an annual calculation based on the previous calendar year's data and supplied to the ISO in time for a June 1 informational filing. The calculation is set forth below: The Generator's Revenue Requirement shall equal the sum of generator's (A) Return and Associated Income Taxes, (B) Black Start Plant Depreciation Expense, (C) Black Start Related Amortization of Loss on Reacquired Debt, (D) Black Start Related Amortization of Investment Tax Credits, (E) Black Start Related Municipal Tax Expense, (F) Black Start Operation and Maintenance Expense, and (G) Black Start Related Administrative and General Expense. A. Return and Associated Income Taxes shall equal the product of the Black Start Plant Investment Base and the Cost of Capital Rate. 1. The Black Start Plant Investment Base will consist of (a) Black Start Plant in FERC 345 or equivalent accounts, plus (b) Related General Plant in FERC 244 or equivalent accounts, less (c) Related Depreciation Reserve, less (d) Related Accumulated Deferred Taxes, plus (e) Related Loss on Reacquired Debt, plus (f) other regulatory assets, plus (g) Prepayments, plus (h) Materials and Supplies, plus (i) Related Cash Working Capital. a. Black Start Plant will equal the calculated average balance of generator's investment in the Exhibit 1 facilities based upon GAAP records and engineering studies and evaluations categorized similar in principal to FERC 345 or equivalent accounts. b. Black Start Related General Plant shall equal generator's calculated average balance of investment in general plant based upon GAAP records and engineering studies and evaluations categorized similar in principal to FERC 244 or equivalent accounts multiplied by the ratio of Black Start related wages and salaries utilizing a standard labor rate to the generator's total wages and salaries of the black start facilities, and excluding administrative and general wages and salaries ("Black Start Allocation Factor"). c. Black Start Related Depreciation Reserve shall equal the average balance of total Black Start depreciation reserve for the Black Start Plant plus the average balance of Black Start Related General Plant depreciation reserve. The Black Start Plant depreciation reserve shall be the average balance of the total Black Start Plant depreciation recovered by the generator for providing system restoration services. Black Start Related General Plant depreciation reserve shall equal the product of the Black Start General Plant reserve and the Black Start Allocation Factor. d. Black Start Related Accumulated Deferred Taxes shall equal generator's average balance of total accumulated deferred income taxes, multiplied by the ratio of total investment in Black Start Plant plus Black Start Related General Plant to total plant in service excluding general plant ("Plant Allocation Factor"). e. Black Start Related Loss on Reacquired Debt shall equal generator's average balance of total loss on reacquired debt multiplied by the Plant Allocation Factor described in Section (A) (1) (d). f. Other Regulatory Assets shall equal generator's average balance of FAS 106 multiplied by the Black Start Allocation Factor described in Section (A) (1) (b) above and the balance of FAS 109, net of FAS 109 liability multiplied by the Plant Allocation Factor described in Section (A) (1) (d) above. g. Black Start Prepayments shall equal generator's average balance of prepayments multiplied by the Black Start Allocation Factor described in Section (A) (1) (b) above. h. Black Start Materials and Supplies shall equal generator's average balance of plant materials and supplies multiplied by the Plant Allocation Factor described in Section (A) (1) (d) above or the actual materials and supplies utilized in the operation and maintenance of Black Start equipment. i. Black Start Related Cash Working Capital shall be a 12.5% allowance (45 days / 360 days) of Black Start operation and maintenance expense and related administrative and general expense. 2. The Cost of Capital Rate shall equal (a) the Weighted Cost of Capital, plus (b) Federal Income Taxes, plus (c) State Income Taxes. a. The Weighted Cost of Capital will be the weighted average cost of debt and common equity, using a proxy capital structure based upon a 50% debt and 50% equity split. i) The Return on Equity Component shall be the average of the NEPOOL Transmission Providers' return on equity pursuant to the NEPOOL Tariff. ii) The Cost of Debt component shall equal the current interest rate of a 30-year U.S. Treasury Bond. b. Federal Income Taxes shall equal (EQUATION) where FT is the federal income tax rate (35%) and A is the Return on Equity Component, as determined in Section (A) (2) (a) (i). c. State Income Taxes shall equal (A + Federal Income Tax)(ST) 1 - ST Where ST is the state income tax rate for the applicable state and A is the Return on Equity Component, as determined in Section (A) (2) (a) (i), and Federal Income Tax is the rate determined in Section (A) (2) (b) above. B. Black Start Depreciation Expense shall equal the sum of depreciation expense for Black Start Plant plus an allocation of general plant depreciation expense calculated by multiplying general plant depreciation expense by the Black Start Allocation Factor, described in Section (A) (1) (b) above. C. Black Start Related Amortization of Loss on Reacquired Debt shall equal generator's amortization of loss on reacquired debt multiplied by the Plant Allocation Factor described in Section (A) (1) (d) above. D. Black Start Related Amortization of Investment Tax Credits shall equal generator's amortization of investment tax credits multiplied by the Plant Allocation Factor described in Section (A) (1) (d) above. E. Black Start Related Municipal Tax Expense shall equal generator's total municipal tax expense multiplied by the Plant Allocation Factor described in Section (A) (1) (d) above. F. Black Start Operation and Maintenance Expense shall equal all expenses charged directly to Black Start equipment. G. Black Start Related Administrative and General Expenses shall equal generator's administrative and general expenses, plus payroll taxes, multiplied by the Black Start Allocation Factor described in Section (A) (1) (b) above. Exhibit 1 to Supplement 1 Additional Black Start Cost of Service Methodology Details The objective of this methodology is to apply cost of service principles to determine the amount of compensation providers of black start service receive. Black Start Generators are only compensated for the incremental costs that are incurred in making and maintaining a unit black start capable and do not include any other costs. Generators shall not recover those black start costs for which they are otherwise compensated through other rate schedules or divestiture contracts. O&M includes equipment wear and tear, training, black start labor costs associated with testing, and periodic maintenance. It is assumed that there are 25 worker-hours per black start unit per year of training. Wear and tear associated with testing black start units will be prorated based on number of hours between maintenance activities. For example, if a maintenance activity occurs every 1,000 hours, and black start testing lasts 1 hour per year, than 0.1% of the costs associated with that maintenance activity will be recovered through black start charges. Fuel costs are those actual, average in tank fuel costs including emission allowances/credits used in testing Black Start Generators and their actual use in system restoration. Fuel costs include fuel consumed due to minimum run requirements. Cash and Working Capital include spare parts associated with the equipment that makes a generating unit black start capable. The list of equipment below is equipment commonly associated with making generating units Black Start Capable. The exact equipment varies depending on the specific generator. In addition, some generating units are made Black Start Capable by having a stand alone generating unit that is not connected to the bulk power system (and therefore cannot participate in any of the NEPOOL markets). This stand-alone generating unit provides the means by which the black start generating unit is Black Start Capable. (FN1) The following equipment is assumed to be depreciated over the following number of years (unless a different depreciation is required by FERC): Air compressors 10 years Air tanks 30 years Batteries/Chargers 10 years DC motors 25 years DC Controllers 25 years DC/AC Inverters 10 years - ---- (FN 1) These depreciation times are intended to be consistent with FERC policy and need to be verified as such. If they are not consistent, they will be made so. Supplement 2 To Schedule 16 Black Start System Restoration and Planning Service Terms and Conditions 1. Definition of System Restoration and Planning Service. A unit is defined to provide "System Restoration and Planning Service" if both of the following conditions are met: A. The unit is "Black Start Capable" in that it has the ability of being started without energy from other NEPOOL generating units in such a way that it meets all of the requirements stated in Operating Procedure 11 (Black Start Capability Eligibility & Testing Requirements); and B. The unit owner, NEPOOL, and the System Operator agree that the unit should be designated Black Start Capable. 2. Generator Owner's commitment to provide System Restoration and Planning Service: A. Generators need to commit initially for at least three years to provide System Restoration and Planning Service from the date of the last black-start/system restoration study. The most recent study was conducted in October 1998. B. All succeeding commitments must be at least for three years. C. Generators may, and are encouraged to, commit to provide System Restoration and Planning Service for periods greater than three years with System Operator and NEPOOL concurrence. D. Generators need to give at least one-year notice that they will no longer be able to provide System Restoration and Planning Service. This one-year notice cannot truncate the generator's commitment to provide System Restoration and Planning Service except as noted in item 2(E) or 2(F) below. E. If due to an event of Force Majeure a Generator Owner cannot provide System Restoration and Planning Service, the above notification requirements stated in items 2(A) and 2(B) are not binding. F. If an owner of a generation unit that is designated Black Start Capable decides to retire that unit, then the three year requirement to provide System Restoration and Planning Service from that unit is not binding. The one-year notice, however, is binding. 3. Performance obligations of generators that are providing System Restoration and Planning Service: A. Generators that are providing System Restoration and Planning Service will be tested in accordance with Operating Procedure 11 or its successor, which may be revised from time to time. B. Units that are providing System Restoration and Planning Service must start- up within the prescribed time stipulated in Operating Procedure 11 (Black Start Capability Eligibility & Testing Requirements). Not all unmanned units that are providing System Restoration and Planning Service will be asked to start-up at the same time. C. If a unit fails a System Restoration and Planning Service test, the owner must incur the necessary costs to make that unit capable of passing the test within a reasonable amount of time. Until the unit passes another System Restoration and Planning Service test, it would not be compensated for providing System Restoration and Planning Service. All costs associated with System Restoration and Planning Service unit re-tests are at the owner's expense. 4. Obligations by System Operator and NEPOOL to generators that are providing System Restoration and Planning Service: A. Generators that commit to provide System Restoration and Planning Service will not have their Black Start Capable designation terminated within the time period of their commitment. B. The System Operator and NEPOOL must provide at least one-year notice to the owner or owners of generation units that are providing System Restoration and Planning Service prior to terminating that unit's designation as Black Start Capable. C. There are no additional restrictions on generation maintenance of designated Black Start Capable units beyond what exists for non-Black Start units except that designated Black Start generation units cannot take seasonal outages. If a Generator Owner makes System Operator and NEPOOL approved capital investments necessary to System Restoration and Planning Service, then that owner will recover all of the associated costs of that investment, including on and of capital, unless the owner voluntary removes that unit from providing System Restoration and Planning Service prior to the recovery of its investment costs in accordance with the cost-of-service methodology approved for the recovery of System Restoration and Planning Service costs. If a Generator Owner voluntary removes a unit from providing System Restoration and Planning Service prior to the recovery of all of its investment costs, then that owner only receives that portion of its investment cost that was recovered during the period that its unit was providing System Restoration and Planning Service. The System Operator or its designated agent shall have the right to independently audit the accounts and records of each generator receiving payments under this rate schedule. The generator shall make its accounts and records available at its offices at a mutually agreeable time for this audit. Such audit shall extend only to those areas relating specifically to this rate schedule. Any errors identified as a result of such audit shall be corrected with interest in accordance with FERC policy with refunds and surcharges, as appropriate, for any amounts previously over- or under-charged due to such errors. ATTACHMENT A Form of Service Agreement for Through or Out Service or Internal Point-To-Point Service 1.0 This Service Agreement, dated as of , is entered into, by and between the NEPOOL Participants acting through (the "System Operator") and ("Transmission Customer"). 2.0 The Transmission Customer has been determined by the System Operator to have a Completed Application for Firm [Non-Firm] Transmission Service under this Tariff. 3.0 If required, the Transmission Customer has provided to the System Operator an Application deposit in accordance with the provisions of this Tariff. 4.0 Service under this Service Agreement shall commence on the later of (1) the requested service commencement date, or (2) the date on which construction or any Direct Assignment Facilities and/or facility additions or upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this Service Agreement shall terminate on such date as is mutually agreed upon by the parties. [The Service Agreement may be a blanket agreement for non-firm service.] 5.0 The Participants agree to provide, and the Transmission Customer agrees to take and pay for, Transmission Service in accordance with the provisions of the Tariff and this Service Agreement. 6.0 Any notice or request made to or by either party regarding this Service Agreement shall be made to the representative of the other party as indicated below. NEPOOL Participants: New England Power Pool One Sullivan Road Holyoke, MA 01040-2841 Transmission Customer: 7.0 The Tariff is incorporated in this Service Agreement and made a part hereof. IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials. NEPOOL Participants: By [System Operator] By: Name Title Date Transmission Customer: By: Name Title Date Specifications For Through or Out Service or Internal Point-to-Point Service 1.0 Term of Transaction: Start Date: Termination Date: 2.0 Description of capacity and energy to be transmitted by Participants including the electric Control Area in which the transaction originates. 3.0 Point(s) of Receipt: Delivering party: 4.0 Point(s) of Delivery: Receiving party: 5.0 Maximum amount of capacity and energy to be transmitted (Reserved Capacity): 6.0 Designation of party(ies) or other entity(ies) subject to reciprocal service obligation: 7.0 Name(s) of any intervening systems providing transmission service: 8.0 Service under this Service Agreement may be subject to some combination of the charges detailed below. (The appropriate charges for individual transactions will be determined in accordance with the terms and conditions of this Tariff.) 8.1 Transmission Charge: 8.2 System Impact Study and/or Facilities Study Charge(s): 8.3 direct assignment expansion charge [Need to define or reference upgrade costs]: ATTACHMENT B Form Of Service Agreement For Regional Network Service 1.0 This Service Agreement, dated as of , is entered into, by and between the NEPOOL Participants acting through (the "System Operator"), and ("Transmission Customer"). 2.0 The Transmission Customer has been determined by the System Operator to be a Transmission Customer under the Tariff and has requested Regional Network Service under the Tariff. 3.0 Regional Network Service (including, if requested, Network Integration Transmission Service) under this Agreement shall be provided by the NEPOOL Participants upon request by an authorized representative of the Transmission Customer. 4.0 The Transmission Customer agrees to supply information the System Operator deems reasonably necessary in accordance with Good Utility Practice in order for it to provide the requested service. 5.0 The Participants agree to provide and the Transmission Customer agrees to take and pay for Regional Network Service in accordance with the provisions of the Tariff and this Service Agreement. 6.0 Any notice or request made to or by either party regarding this Service Agreement shall be made to the representative of the other party as indicated below. NEPOOL Participants: New England Power Pool One Sullivan Road Holyoke, MA 01040-2841 Transmission Customer: 7.0 The Tariff is incorporated herein and made a part hereof. IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials. Transmission Customer: By: Name Title Date NEPOOL Participants: By: [System Operator] By: Name Title Date ATTACHMENT C Methodology To Assess Available Transmission Capability Available Transmission Capability (ATC) will be assessed based on industry- accepted standards; currently, ATC will be established by reducing the determined Total Transfer Capability (TTC) by the Transmission Reliability Margin (TRM) and by transmission commitments. Total Transfer Capability (TTC) is the determined amount of electric power that can be reliably transferred over the network consistent with the following: Good utility practice NERC standards, guides, and procedures; NPCC criteria and guidelines; New England criteria, rules, procedures, and reliability standards; Applicable guides, standards, and criteria of the affected Transmission Owner(s), whether Participant or Non-Participant; Other applicable guidelines and standards which may need to be established from time to time. As such, TTC will be determined at a level which maintains all of the following: All equipment within its applicable capabilities; Voltages and reactive reserves within acceptable levels; Stability maintained with adequate levels of damping; Frequency (Hz) within acceptable levels. TTC will be evaluated using appropriate and suitable tools, data, and information, considering the physical impacts of electric power transfers on the interconnected transmission network. It will reflect anticipated system conditions and equipment status to the degree practicable. The Transmission Reliability Margin (TRM) will be established at a level which incorporates the uncertainties and continued variability of system conditions and the practical limitations of system control. Transmission commitments include existing and pending requests for transmission service and obligations of other existing contracts under which transmission service is provided. ATTACHMENT D Methodology for Completing a System Impact Study The system impact study will be performed to evaluate the impact of the requested service on the reliability and operating characteristics of the bulk power system, consistent with: Good utility practice NERC standards, guides, and procedures; NPCC criteria and guidelines; New England criteria, rules, procedures, and reliability standards; Applicable guides, standards, and criteria of the impacted Transmission Owner(s), whether Participant or Non-Participant; Other applicable guidelines and standards which may need to be established from time to time. As such, the study will examine the impact on the New England regional bulk power system and its component systems and neighboring and external systems. Consistent with the aforementioned, the ability to operate the system subject to the following will be considered: All equipment within its applicable capabilities; Voltages and reactive reserves within acceptable levels; Stability maintained with adequate levels of damping; Frequency (Hz) within acceptable levels. The study will consider the reliability requirements to meet existing and pending obligations of the Participants and the obligations of the impacted Transmission Owner(s). The study will be performed using appropriate and suitable analysis tools and modeling data consistent with the nature and duration of the requested service. It is expected that the Eligible Customer will provide the information as prescribed in Exhibit 1 of Attachment I, and such other information as may be reasonably required and associated with the requested service and necessary for its study. It is also recognized that it may be determined that additional or specialized analysis tools or computer software are necessary for the study. The responsibility for the provision of these items will be subject to the System Impact Study Agreement. The study will identify if the requested service or a portion of it can be provided without adverse impact on the reliability and operating characteristics of the system. The study will also identify if it appears that modification of the system is necessary to provide the service. ATTACHMENT E Local Networks The Local Networks, as of the effective date of this Tariff, are those of the following: 1. Bangor Hydro-Electric Company 2. Boston Edison Company 3. Central Maine Power Company 4. the Commonwealth Energy System companies 5. the Eastern Utility Associates companies 6. the New England Electric System companies 7. the Northeast Utilities companies 8. The United Illuminating Company 9. Vermont Electric Power Company and the entities which are grouped with it as a single Participant. ATTACHMENT F Annual Transmission Revenue Requirements The Transmission Revenue Requirements for each Participant will reflect the Participant's costs with respect to Pool-Supported PTF. The Transmission Revenue Requirements will be an annual calculation based on the previous year's calendar data as shown, in the case of Transmission Providers which are subject to the Commission's jurisdiction, in the Participants' FERC Form 1 report for that year, and shall be based on actual data in lieu of allocated data if specifically identified in the Form 1 report in accordance with the following formula: I. The Transmission Revenue Requirement shall equal the sum of the Transmission Provider's (A) Return and Associated Income Taxes, (B) Transmission Depreciation Expense, (C) Transmission Related Amortization of Loss on Reacquired Debt, (D) Transmission Related Amortization of Investment Tax Credits, (E) Transmission Related Municipal Tax Expense, (F) Transmission Related Payroll Tax Expense, (G) Transmission Operation and Maintenance Expense, (H) Transmission Related Administrative and General Expense, (I) Transmission Related Integrated Facilities Charges, minus (J) Transmission Support Revenue, plus (K) Transmission Support Expense, plus (L) Transmission Related Expense from Generators, plus (M) Transmission Related Taxes and Fees Charge, minus (N) Revenue for Short-Term Transmission Service under the NEPOOL Tariff and (O) Transmission Rents Received from Electric Property. The details for implementation of Attachment F, as well as the definitions of the terms used in the Attachment F formula, shall be established in accordance with the applicable rule set forth in the Settlement Agreement entered into in FERC Dockets OA97-237-000, et al. Any changes to that rule must be approved by the Regional Transmission Operations Committee. The rule and any changes thereto shall be filed with the Commission and considered a supplement to this Tariff. ATTACHMENT G: List of Excepted Transaction Agreements (Table) Attachment G is a listing of transmission agreements pertaining to certain point-to-point wheeling transactions across or out of a Local Network. In accordance with Sections 25, 25A and 25B of the Tariff, these agreements will continue to be in effect at the rates and terms thereunder rather than under the Tariff. Notes to Attachments G, G-1 and G-2 1. NEP's long-term Point-to-Point transmission services will be grandfathered at a fixed rate of $17.00/kW-yr. Distribution, transformation, and metering surcharges when applicable, will be subject to NEP's applicable point-to-point tariffs. 2. See FERC Contract for specific details of agreement. In general, 100MW's until transmission upgrades are complete. This item is still under review and is subject to further review dependent upon outcome of Congestion Pricing. 3. Excepted status applies to transmission by CMP. Transmission by others (MEPCO, NBP, MPS) remains under the rates, terms and conditions of applicable agreements. 4. This Transmission Service Agreement is governed in part by a memorandum of understanding, filed 6/13/97 in Docket nos. EC90-10-007, ER93-294-000, ER95-1686-000, ER96-496-000, OA97-237-000, and ER97-1079-000. ADDENDUM TO ATTACHMENTS G, G-1 AND G-2 Pursuant to the terms of a settlement agreement (the "Settlement Agreement") reached in FERC Dockets OA97-237-000, et al., the parties to the Excepted Transaction Agreements specifically identified below have reached the following agreements with respect to those Excepted Transaction Agreements. In addition to the items specifically identified below, other Excepted Transaction Agreements listed in Attachment G, G-1 and G-2 to this Tariff may also be affected more generally by the terms of that Settlement Agreement. NEPOOL Tariff Attachment G, Item 1 If the Settlement Agreement is approved in its entirety and takes effect as to all signatories, Unitil and CMP agree as follows: This Transmission Service Agreement between Unitil and CMP (the "Unitil/CMP Agreement") will continue in effect without modification until that date on which the revenues received by CMP, pursuant to the terms and conditions of the Unitil/CMP Agreement, as calculated prospectively from March 1, 1999, equals Three Hundred Thousand Dollars ($300,000.00). Such date is anticipated to be December 13, 1999. On that date, the said Unitil/CMP Agreement will terminate, and any rights and obligations enjoyed by CMP and Unitil under the terms of the Unitil/CMP Agreement will cease. Any issues involving the revenues received prior to March 1, 1999 by CMP from Unitil pursuant to the Unitil/CMP Agreement have been resolved in accordance with the terms of the Settlement Agreement, Section G. Unitil and CMP each agree to waive any claims against the other arising prior to March 1, 1999, whether identified previously or not, that are based on or in any way relate to the terms and conditions of the Unitil/CMP Agreement. NEPOOL Tariff Attachment G, Item 4 Phase I payments will be made according to the Settlement Agreement, Section G. This Excepted Transaction will be terminated effective March 1, 1999. NEPOOL Tariff Attachment G, Items 7 and 8 From March 1, 1999 forward the service under the Excepted Transaction will be terminated and will be subject to NEPOOL Tariff and, if applicable, the NEP LNS Tariff. NEPOOL Tariff Attachment G, Item 10 Phase I payments will be made according to the Settlement Agreement, Section G. This Excepted Transaction will be terminated effective March 1, 1999. NEPOOL Tariff Attachment G, Item 11 Phase I payments will be made according to the Settlement Agreement, Section G. This Excepted Transaction will be terminated effective March 1, 1999. NEPOOL Tariff Attachment G, Item 12 Phase I payments will be made according to the Settlement Agreement, Section G. This Excepted Transaction will be terminated effective March 1, 1999. NEPOOL Tariff Attachment G, Item 13 Phase I payments will be made according to the Settlement Agreement, Section G. This Excepted Transaction will be terminated effective March 1, 1999. As a clarification, Maine Yankee has been retired and swapped for Vermont Yankee. Therefore, retroactively, the refunds apply to both Maine and Vermont Yankee and prospectively the transmission of Vermont Yankee is terminated. NEPOOL Tariff Attachment G, Item 15 This contract has been terminated and Holyoke is receiving service under NU's Open Access Tariff. NEPOOL Tariff Attachment G, Items 17, 19 and 46 These arrangements will continue for the life of the Unit Contract at a rate of $6.50 per kw-year. NEPOOL Tariff Attachment G, Item 18 NU, UI and Unitil agree that Item 19, which is a contract for corridor transmission service between NU and UI (the "NU-UI Agreement") that was entered into as a settlement of prior disputes, will remain in effect in accordance with its terms. The parties further agree that the Purchased Power Agreement between UI and Unitil for power from Bridgeport Harbor Station Unit No. 3 (the "UI-UNITIL Agreement") shall remain in effect subject to the terms of that agreement for its full term at the rate stated therein. NU shall pay Unitil an amount equal to one-third of the transmission charges Unitil pays to reimburse UI for the costs UI incurs for the transmission of Unitil's power in connection with the UI-UNITIL agreement for the period between March 1, 1999 and October 31, 2003. From November 1, 2003 to October 31, 2005, NU shall pay Unitil an amount equal to 100% of the transmission charges Unitil pays UI to reimburse UI for the costs UI incurs for the transmission of Unitil's power in connection with the UI-UNITIL Agreement. NU, UI and Unitil agree that the foregoing arrangements satisfy any claims of double charges under the NU-UI Agreement and the UI-UNITIL Agreement. NEPOOL Tariff Attachment G, Item 20 This contract will remain in force according to its terms at a rate of $6.50 per kw-year. NEPOOL Tariff Attachment G, Item 21 and 23 The transmission contract between NUSCO and MASSPOWER will remain in effect for its full term. The MASSPOWER transmission contract (and the contract between NUSCO and Pittsfield) will remain under the NU System Companies' Tariff No. 9, subject to the settlement among MASSPOWER, Pittsfield and the NU System Companies that is currently pending the Commission in Dockets ER93- 545-000 and ER93-219-000. The parties in those dockets who are also signatories to this Settlement Agreement will withdraw their opposition to the settlement pending in those dockets. NEPOOL Tariff, Attachment G, Items 24 and 25 The parties to these Excepted Transactions, which are contracts for transmission service by NU over the New York tie, have agreed that these contracts for transmission service will remain in effect for their full term at a rate of $6.50 per kw-year. NEPOOL Tariff Attachment G, Item 32 NU and Reading have agreed that the transmission rate applicable to this Attachment G contract will be one-half of the current transmission charge paid by Reading under such contract from March 1, 1999 through the remainder of its term. This Attachment G contract will remain in effect in accordance with its current terms. Reading will continue to be billed and pay for service in accordance with the pre-existing negotiated rates in this Attachment G contract and such bills will include a line item reflecting the cost of transmission based on the NU Tariff 9 rate in effect for the applicable billing period. Monthly adjustments in the transmission portion of the bill will be made separately by NU's transmission group to account for the difference between the Tariff 9 rate used for billing purposes and the settlement rate of one-half the current transmission charge paid by Reading under this contract such that Reading will pay a net transmission charge of one-half the current transmission charge paid by Reading under this contract. NEPOOL Tariff Attachment G, Items 33, 34, 35, 39, 40, 41, 42, 43 and 45 NU and the MMWEC parties have agreed that the transmission rate applicable to these Attachment G contracts will be $6.50/kw-year from March 1, 1999 through the remainder of their terms. These Attachment G contracts will remain in effect in accordance with their current terms. The customers will continue to be billed and pay for service in accordance with the pre-existing negotiated rates in those contracts and such bills will include a line item reflecting the cost of transmission based on the NU Tariff 9 rate in effect for the applicable billing period. Monthly adjustments in the transmission portion of the bill will be made separately by NU's transmission group to account for the difference between the Tariff 9 rate used for billing purposes and the settlement rate of $6.50/kw-year such that the MMWEC parties will pay a net transmission charge of $6.50/kw-year. NEPOOL Tariff Attachment G, Item 38 This contract ended by its terms in 1998. NEPOOL Tariff Attachment G, Items 55 and 56 Montaup, as Transmission Provider, and MASSPOWER and Pittsfield, as Transmission Customers, and all other Parties agree that these Excepted Transactions shall not be affected by this Settlement Agreement and shall remain in full force and effect in accordance with their terms. NEPOOL Tariff Attachment G, Items 57, 58, 60 and 61 Non-firm wheeling of Cleary 9 power by Montaup to North Attleboro, Hudson Light & Power and Hingham will continue at 50% of the current contract transmission rate until February 28, 2001, after which date it will terminate. Non-firm wheeling of Cleary 9 power by Montaup to Braintree terminated as of February 28, 1999. NEPOOL Tariff Attachment G, Item 59 Firm wheeling of NYPA power by Montaup for Braintree and Reading will continue at 50% of the current contract transmission rate until the expiration of the existing contract. Firm wheeling by Montaup for Hingham, Hull, Wellesley, Belmont and Concord under the same transaction will continue at 50% of the current transmission rate until February 28, 2001 after which date it terminates subject to extension upon agreement of the parties. NEPOOL Tariff Attachment G, Item 63 Firm wheeling of NYPA power by Montaup for Pascoag Fire District will continue at 50% of the current transmission rate until February 28, 2001 after which date it terminates, subject to extension upon agreement of the parties. NEPOOL Tariff Attachment G, Item 68 From March 1, 1999 to the expiration of the contract, BECO will not bill Braintree, Reading, Hingham and Hull, and BECO will bill Concord, Wellesley and Belmont at 50% of the contract rate. NEPOOL Tariff Attachment G, Item 69 CVPS and Unitil are currently engaged in an arbitration with respect to this Excepted Transaction. This Settlement Agreement has no impact on arbitration findings for payments due prior to March 1, 1997. For purposes of this Settlement Agreement, CVPS and Unitil agree as follows: If Unitil prevails at the arbitration, Unitil will owe nothing to CVPS. If CVPS prevails, then Unitil will pay 75% of the amount of the award related to the period March 1, 1997 through February 28, 1999, plus 100% of any interest. The transmission component of this contract shall be null and void going forward from February 28, 1999. Unitil shall continue to take and pay for capacity and energy for the term of the contract, consistent with the existing terms of the agreement. Neither CVPS nor Unitil shall communicate any aspect of this Settlement Agreement, or side agreement between them, to the arbitrator prior to the rendering of his decision. NEPOOL Tariff Attachment G-1, Items 1 and 2 NEP and NU will terminate items 1 and 2 in Attachment G-1 to the NEPOOL Tariff and both services will transfer to the respective LNS Tariffs as of April 1, 1999. NEPOOL Tariff Attachment G-1, Item 10 This contract has been terminated. ATTACHMENT H Form of Network Operating Agreement 1.0 Preamble This Network Operating Agreement is entered into by and between the NEPOOL Participants (the "Transmission Provider") acting through (the "System Operator") and (the "Transmission Customer") as an implementing agreement for the NEPOOL Open Access Transmission Tariff and is subject to and in accordance with the NEPOOL Open Access Transmission Tariff. All definitions and other terms and conditions of the NEPOOL Open Access Transmission Tariff are incorporated herein by reference. The Transmission Provider may designate a satellite dispatch center and/or one or more Participants to act for it under this Agreement. 2.0 General Terms and Conditions The Transmission Provider agrees to provide transmission service to the Transmission Customer's equipment or facilities, etc., subject to the Transmission Customer operating its facilities in accordance with applicable NEPOOL and NPCC criteria, rules, standards, procedures, or guidelines as they may be adopted and/or amended from time to time. In addition to the provisions defined in those documents, service to the Transmission Customer's equipment or facilities, etc. is provided subject to the following specified terms and conditions. 2.1 Electrical Supply: The electrical supply to the Point(s) of Delivery shall be in the form of three-phase sixty-hertz alternating current at a voltage class determined by mutual agreement of the parties. 2.2 Coordination of Operations: The Transmission Provider shall consult the Transmission Customer and/or its Designated Agent regarding timing of scheduled maintenance of the Transmission System and the Transmission Provider shall schedule any shutdown or withdrawal of facilities to coincide with the Transmission Customer's equipment or facilities, etc. scheduled outages of the Transmission Customer's resources, to the extent practicable. In the event the Transmission Provider is unable to schedule the shutdown of its facilities to coincide with Transmission Customer's schedule, the Transmission Provider shall notify the Transmission Customer and/or its Designated Agent, in advance if feasible, of reasons for the shutdown, the time scheduled for it to take place, and its expected duration. The Transmission Provider shall use due diligence to resume delivery of electric power as quickly as possible. 2.3 Reporting Obligations: The Transmission Customer shall be responsible for all information required by NPCC or NEPOOL. The Transmission Customer shall respond promptly and completely to the Transmission Provider's reasonable requests for information, including but not limited to, data necessary for operations, maintenance, regulatory requirements and analysis. In particular, that information may include: For Network Loads: - - 10-year coincident, seasonal (summer, winter) Annual Peak Load forecast, aggregated by geographic distribution area - - Load Power Factor performance by geographic distribution area - - Underfrequency load shedding capability aggregated by geographic distribution area - - Block load shedding capability aggregated by geographic distribution area - - Disturbance/interruption reports - - Protection system setting conformance - - Protection system testing and maintenance conformance - - Planned changes to protection systems - - Metering testing and maintenance conformance - - Planned changes in transformation capability - - Conformance to harmonic and voltage fluctuation limits - - Dead station tripping conformance - - Voltage reduction capability conformance For Network Resources and interconnected generators: - - 10-year forecast of generation capacity retirements and additions, if applicable - - Generator reactive capability verification - - Generator underfrequency relaying conformance - - Protection system testing and maintenance conformance - - Planned changes to protection system - - Planned changes to generation parameters - - Metering testing and maintenance conformance Failure by the Transmission Customer to do so may constitute default. Delinquency in responding by the Transmission Customer will result in a fine as described in 5.0 below. The Transmission Customer shall supply accurate and reliable information to the system operators regarding metered values for MW, MVAR, volt, amp, frequency, breaker status indication, and all other information deemed necessary by the Transmission Provider for reliable operation. Information shall be gathered for electronic communication using one or more of the following: supervisory control and data acquisition (SCADA), remote terminal unit (RTU) equipment, and remote access pulse recorders (RAPR). All equipment used for metering, SCADA, RTU, RAPR, and communications must be approved by the Transmission Provider. 2.4 Operational Obligations: The Transmission Customer shall request permission from the system operators prior to opening and/or closing circuit breakers per applicable switching and operating procedures. The Transmission Customer shall carry out all switching orders from the Transmission Provider, the System Operator or the Transmission Provider's designee in a timely manner. The Transmission Customer shall balance the load at the Point(s) of Delivery such that the difference in the individual phase currents are acceptable to the Transmission Provider. The Transmission Customer's equipment shall conform with harmonic distortion and voltage fluctuation standards of the Transmission Provider. The Transmission Customer's equipment must comply with all environmental requirements to the extent they impact the operation of the Transmission Provider's system. The Transmission Customer shall operate all of its equipment and facilities connected to the Transmission Provider's system in a safe and efficient manner and in accordance with manufacturers' recommendations, Good Utility Practice, applicable regulations, and requirements of the Transmission Provider, the System Operator, and NPCC. 2.5 Notice of Transmission Service Interruptions: If at any time, in the reasonable exercise of the system operator's judgement, operation of the Transmission Customer's equipment adversely affects the quality of service or interferes with the safe and reliable operation of the system, the Transmission Provider may discontinue transmission service until the condition has been corrected. Unless the system operators perceive that an emergency exists or the risk of one is imminent, the system operators shall give the Transmission Customer and/or its Designated Agent reasonable notice of its intention to discontinue transmission service and, where practical, allow suitable time for the Transmission Customer to remove the interfering condition. The Transmission Provider's judgement with regard to the discontinuance of service under this paragraph shall be made in accordance with Good Utility Practice. In the case of such discontinuance, the Transmission Provider shall immediately confer with the Transmission Customer regarding the conditions causing such discontinuance and its recommendation concerning timely correction thereof. Failure by a Customer to shed load would be subject to an additional charge of 10/kWh for every kWh the Customer failed to shed. 2.6 Access and Control: Properly accredited representatives of the Transmission Provider shall at all reasonable times have access to the Transmission Customer's facilities to make reasonable inspections and obtain information required in connection with this Tariff. Such representatives shall make themselves known to the Transmission Customer's personnel, state the object of their visit, and conduct themselves in a manner that will not interfere with the construction or operation of the Transmission Customer's facilities. The Transmission Provider or its designee will have control such that it may open or close the circuit breaker or disconnect and place safety grounds at the Point(s) of Delivery, or at the station, if the Point(s) of Delivery is remote from the station. 2.7 Point(s) of Delivery: Network Integration Transmission Service will be delivered by the Transmission Provider at the Point(s) of Delivery as specified in the customer's Service Agreement, and as amended from time to time. Each Point of Delivery shall have a unique identifier, meter location, meter number, metered voltage, terms on meter compensation and, the actual, or if not currently in service, the projected in-service year. 2.8 Maintenance of Equipment: The Transmission Customer shall maintain all of its equipment and facilities connected to the Transmission Provider's system in a safe and efficient manner and in accordance with manufacturers' recommendations, Good Utility Practice, applicable regulations, and requirements of NEPOOL, and NPCC. The Transmission Provider may request that the Transmission Customer test, calibrate, verify or validate the data link, metering, data acquisition, transmission, protective, or other equipment or software consistent with the Transmission Customer's routine obligation to maintain its equipment and facilities or for the purposes of trouble shooting problems on the network facilities. The Transmission Customer will be responsible for the cost to test, calibrate, verify or validate the equipment or software. The Transmission Provider shall have the right to inspect the tests, calibrations, verifications and validations of the data link, metering, data acquisition, transmission, protective, or other equipment or other software connected to the Transmission Provider's system. The Transmission Customer, at the Transmission Provider's request, shall supply the Transmission Provider with a copy of the installation, test, and calibration records of the data link, metering, data acquisition, transmission, protective or other equipment or software connected to the Transmission Provider's system. The Transmission Provider shall have the right, at the Transmission Customer's expense, to monitor the factory acceptance test, the field acceptance test, and the installation of any metering, data acquisition, transmission, protective or other equipment or software connected to the Transmission Provider's system. 2.9 Emergency System Operations: The Transmission Customer's equipment and facilities, etc. shall be subject to all applicable emergency operation standards required of and by the Transmission Provider to operate in an interconnected transmission network. The Transmission Provider reserves the right to have the system operators take whatever actions or inactions they deem necessary during emergency operating conditions to: (i) preserve the integrity of the Transmission System, (ii) limit or prevent damage, (iii) expedite restoration of service, or (iv) preserve public safety. 2.10 Cost Responsibility: The Transmission Customer shall be responsible for all costs incurred by the Transmission Provider relative to the Transmission Customer's facilities. Some costs may be allocated to several Transmission Customers. If the method for allocating costs is not clearly defined, then the method for allocation will be at the Transmission Provider's discretion. 3.0 Service For a Network Resource The following Terms and Conditions are specific to Service for a generator Network Resource. 3.1 Voltage or Reactive Control Requirements: Unless directed otherwise, the Transmission Customer will operate its existing interconnected generation facility(ies) with an automatic voltage regulator(s). The voltage regulator will control voltage at the Point(s) of Receipt consistent with the range of voltage scheduled by the System Operator. At the discretion of the Transmission Provider, the Transmission Customer may be directed to deactivate the automatic voltage regulator and to supply reactive power per a schedule provided by the Transmission Provider. If the Transmission Customer has not installed capacity sufficient to operate its generation facility consistent with recommendations of the Transmission Provider resulting from the System Impact and Facilities Studies or fails to operate at such capacity, the Transmission Provider may install, at the Transmission Customer's expense, reactive compensation equipment necessary to ensure the proper voltage or reactive supply at the Point(s) of Receipt. 3.2 Station Service: When the Transmission Customer's generation facility is producing electricity, the Customer must supply its own station service power. If and when the Transmission Customer's generation facility is not producing electricity, the Customer must obtain station service capacity and energy from another supplier or another of its resources. 3.3 Protection Requirements: Protection requirements are defined in NEPOOL and NPCC documents as may be adopted or amended from time to time. 3.4 Operational Obligations: The Transmission Provider may require the generator to be equipped for Automatic Generation Control (AGC). The Transmission Customer will be responsible for all costs associated with installing and maintaining an AGC system on the generator(s). The Transmission Provider retains the right to require reduced generation at times when system conditions present transmission restrictions or otherwise adversely affect the Transmission Provider's other customers. The Transmission Provider will use due diligence to resolve the problems to allow the generator to return to the operating level prior to the Transmission Provider's notice to reduce generation. All operations (including start-up, shutdown and determination of hourly generation) will be coordinated by the Transmission Provider. 3.5 Coordination of Operations: The Transmission Customer shall furnish the Transmission Provider with generator annual maintenance schedules, advise the Transmission Provider if its Network Resource is capable of participation in system restoration and/or if it has black start capability. The Transmission Provider reserves the right to specify turbine and/or generator control (e.g., droop) settings as determined by the System Impact or Facilities Study or subsequent studies. The Transmission Customer agrees to comply with such specifications by the Transmission Provider at the Transmission Customer's expense. If the generator is not dispatchable by the Transmission Provider, the Transmission Customer shall notify the Transmission Provider at least 48 hours in advance of its intent to take its resource temporarily off-line and its intent to resume generation. In circumstances such as forced outages, the Transmission Customer shall notify the Transmission Provider as promptly as possible of the Network Resource's temporary interruption of generation and/or transmission. 4.0 Service for Delivery to Load The following Terms and Conditions are specific to Service for Delivery to Load. 4.1 Power Factor Requirement: The Transmission Customer agrees to maintain an overall Load Power Factor and reactive power supply within predefined sub-areas as measured at the Point(s) of Delivery within ranges specified by the Transmission Provider or NEPOOL criteria, rules and standards which identify the power factor levels that must be maintained throughout the applicable sub-area for each anticipated level of total NEPOOL load. The Transmission Customer agrees to maintain Load Power Factor and reactive power requirements within the range specified by the Transmission Provider for the sub-area based on total NEPOOL load during that hour. NEPOOL may revise the power factor limits required from time to time. If the Transmission Customer lacks the capability to maintain the Load Power Factor within the ranges specified, the Transmission Provider may: a) install, at the Transmission Customer's expense, reactive compensation equipment necessary to ensure proper load power factor at the Point(s) of Delivery; b) charge the Transmission Customer per the Tariff. 4.2 Protection Requirements: The Transmission Customer's relay and protection systems must comply with all applicable NEPOOL and NPCC criteria, rules, procedures, guidelines, standards or requirements as may be adopted or amended from time to time. 4.3 Operational Obligations: The Transmission Customer shall be responsible for operating and maintaining security of its electric system in a manner that avoids adverse impact to the Transmission Provider's or others' interconnected systems and complies with all applicable NEPOOL, and NPCC operating criteria, rules, procedures, guidelines and interconnection standards as may be amended or adopted from time to time. These actions include, but are not limited to: - - Voltage Reduction Load Shedding - - Underfrequency Load Shedding - - Block Load Shedding - - Dead Station Tripping - - Transferring Load Between Point(s) of Delivery - - Implementing Voluntary Load Reductions Including Interruptible Customers - - Starting Stand-by Generation - - Permitting Transmission Provider Controlled Service Restoration Following Supply Delivery Contingencies on Transmission Provider Facilities 5.0 Default If the Transmission Customer's equipment fails to perform consistent with the Terms and Conditions of this agreement, then the Transmission Customer will be deemed to be in default and service may be suspended immediately and subject to a termination through a FERC filing. If the Transmission Customer fails to provide the information required in Section 2.3 in a timely manner, the Transmission Provider shall be permitted to assess a penalty of $100 per day until such information is provided in its entirety to the Transmission Provider. The Parties whose authorizing signatures appear below warrant that they will abide by the foregoing terms and conditions. NEPOOL Participants By (System Operator) (Transmission Customers) By: By: Title: Title: Date: Date: ATTACHMENT I Form of System Impact Study Agreement This Agreement dated , is entered into by (the "Transmission Customer") and the NEPOOL Participants (the "Transmission Provider") acting through (the "System Operator"), for the purpose of setting forth the terms, conditions and costs for conducting a System Impact Study relative to ,in accordance with the NEPOOL Open Access Transmission Tariff ("Tariff"). All definitions and other terms and conditions of that Tariff are incorporated herein by reference. The Transmission Provider may designate one or more Participants or the System Operator to act for it under this Agreement. 1. The Transmission Customer agrees to provide, in a timely and complete manner, the information and technical data specified in Exhibit 1 to this Agreement and reasonably necessary for the Transmission Provider to conduct the System Impact study. The Transmission Customer understands that it must provide all such information and data prior to the Transmission Provider's commencement of the Study. Such information and technical data is specified in Exhibit 1 to this Agreement. 2. All work pertaining to the System Impact Study that is the subject of this Agreement will be approved and coordinated only through designated and authorized representatives of the Transmission Provider and the Transmission Customer. Each party shall inform the other in writing of its designated and authorized representative. 3. The Transmission Provider will advise the Transmission Customer of any additional information as it may in its sole reasonable discretion deem necessary to complete the study. Any such additional information shall be obtained only if required by Good Utility Practice and shall be subject to the Transmission Customer's consent to proceed, such consent not to be unreasonably withheld. 4. The Transmission Provider contemplates that it will require to complete the System Impact Study. Upon completion of the Study by the Transmission Provider, the Transmission Provider will provide a report to the Transmission Customer based on the information provided and developed as a result of this effort. If, upon review of the Study results, the Transmission Customer decides to pursue , the Transmission Provider will, at the Transmission Customer's direction, tender a Facilities Study Agreement within thirty (30) days. The System Impact and Facilities Studies, together with any additional studies contemplated in Paragraph 3, shall form the basis for the Transmission Customer's proposed use of the Transmission Provider's transmission system and shall be furthermore utilized in obtaining necessary third-party approvals of any interconnection facilities and requested transmission services. The Transmission Customer understands and acknowledges that any use of study results by the Transmission Customer or its agents, whether in preliminary or final form, prior to NEPOOL l8.4 approval, is completely at the Transmission Customer's risk and that the Transmission Provider will not guarantee or warrant the completeness, validity or utility of study results prior to NEPOOL 18.4 approval. 5. The estimated costs contained within this Agreement are the Transmission Provider's good faith estimate of its costs to perform the System Impact Study contemplated by this Agreement. The Transmission Provider's estimates do not include any estimates for wheeling charges that may be associated with the transmission of facility output to third parties or with rates for station service. The actual costs charged to the Transmission Customer by the Transmission Provider may change as set forth in this Agreement. Prepayment will be required for all study, analysis, and review work performed by the Transmission Provider or its Designated Agent, all of which will be billed by the Transmission provider to the Transmission Customer in accordance with Paragraph 6 of this Agreement. 6. The payment required is $ from the Transmission Customer to the Transmission Provider for the primary system analysis, coordination, and monitoring of the System Impact Study. The Transmission Provider will, in writing, advise the Transmission Customer in advance of any cost increases for work to be performed if total amount increases by 10% or more. Any such changes to the Transmission Provider's costs for the study work shall be subject to the Transmission Customer's consent, such consent not to be unreasonably withheld. The Transmission Customer shall, within thirty (30) days of the Transmission Provider's notice of increase, either authorize such increases and make payment in the amount set forth in such notice, or the Transmission Provider will suspend the System Impact Study and this Agreement will terminate if so permitted by the Federal Energy Regulatory Commission. In the event this Agreement is terminated for any reason, the Transmission Provider shall refund to the Transmission Customer the portion of the above credit or any subsequent payment to the Transmission Provider by the Transmission Customer that the Transmission provider did not expend in performing its obligations under this Agreement. Any additional billings under this Agreement shall be subject to an interest charge computed in accordance with the provisions of the Tariff. Payments for work performed shall not be subject to refunding except in accordance with Paragraph 7 below. 7. If the actual costs for the work exceed prepaid estimated costs, the Transmission Customer shall make payment to the Transmission Provider for such actual costs within thirty (30) days of the date of the Transmission Provider's invoice for such costs. If the actual costs for the work are less than those prepaid, the Transmission Provider will credit such difference toward Transmission Provider costs unbilled, or in the event there will be no additional billed expenses, the amount of the overpayment will be returned to the Transmission Customer with interest computed as stated in Paragraph 6 of this Agreement, from the date of reconciliation. 8. Nothing in this Agreement shall be interpreted to give the Transmission Customer immediate rights to wheel over or interconnect with the Transmission Provider's transmission or distribution system. Such rights shall be provided for under separate agreement and in accordance with the Transmission Provider's open access tariff. 9. Within one (1) year following the Transmission Provider's issuance of a final bill under this Agreement, the Transmission Customer shall have the right to audit the Transmission Provider's accounts and records at the offices where such accounts and records are maintained, during normal business hours; provided that appropriate notice shall have been given prior to any audit and provided that the audit shall be limited to those portions of such accounts and records that relate to service under this Agreement. The Transmission Provider reserves the right to assess a reasonable fee to compensate for the use of its personnel time in assisting any inspection or audit of its books, records or accounts by the Transmission Customer or its Designated Agent. 10. Each party agrees to indemnify and hold the other party and its Related Persons of each of them (collectively "Affiliates") harmless from and against any and all damages, costs (including attorney's fees), fines, penalties and liabilities, in tort, contract, or otherwise (collectively "Liabilities") resulting from claims of third parties arising, or claimed to have arisen as a result of any acts or omissions of either party under this Agreement. Each party hereby waives recourse against the other party and its Related Persons for, and releases the other party and its Related Persons from, any and all Liabilities for or arising from damage to its property due to a performance under this Agreement by such other party except in cases of negligence or intentional wrongdoing by either party. 11. If either party materially breaches any of its covenants hereunder, the other party may terminate this Agreement by filing a notice of intent to terminate with the Federal Energy Regulatory Commission and serving notice of same on the other party to this Agreement. This remedy is in addition to any other remedies available to the injured party. 12. This Agreement shall be construed and governed in accordance with the laws of the State of Connecticut and with Part II of the Federal Power Act, 16 U.S.C. 824d et seq., and with Part 35 of Title 18 of the Code of Federal Regulations, 18 C.F.R. 35 et seq. 13. All amendments to this Agreement shall be in written form executed by both parties. 14. The terms and conditions of this Agreement shall be binding on the successors and assigns of either party. 15. This Agreement will remain in effect for a period of up to two years from its effective date as permitted by the Federal Energy Regulatory Commission, and is subject to extension by mutual agreement. Either party may terminate this Agreement by thirty (30) days' notice except as is otherwise provided herein. If this Agreement expires by its own terms, it shall be the Transmission Provider's responsibility to make such filing. Transmission Customer: Name: Title: Date: NEPOOL Participants By (System Operator) Name: Title: Date: EXHIBIT 1 Information to be Provided to the Transmission Provider by the Transmission Customer for System Impact Study 1.0 Facilities Identification 1.1 Requested capability in MW and MVA; summer and winter 1.2 Site location and plot plan with clear geographical references 1.3 Preliminary one-line diagram showing major equipment and extent of Transmission Customer ownership 1.4 Auxiliary power system requirements 1.5 Back-up facilities such as standby generation or alternate supply sources 2.0 Major Equipment 2.1 Power transformer(s): rated voltage, MVA and BIL of each winding, LTC and or NLTC taps and range, Z1 (positive sequence) and Zo (zero sequence) impedances, and winding connections. Provide normal, long-time emergency and short-time emergency thermal ratings. 2.2 Generator(s): rated MVA, speed and maximum and minimum MW output, reactive capability curves, open circuit saturation curve, power factor (V) curve, response (ramp) rates, H (inertia), D (speed damping), short circuit ratio, X1 (leakage), X2:(negative sequence), and Xo (zero sequence) reactances and other data: Direct Quadrature Axis Axis Saturated synchronous reactance Xdv Xqv unsaturated synchronous reactance Xdi Xqt saturated transient reactance X'dv X'qv unsaturated transient reactance X'di X'qi saturated subtransient reactance X"dv X"qv unsaturated subtransient reactance X"di X"qi transient open-circuit time constant T'do T'qo transient short-circuit time constant T"d T"q subtransient open-circuit time constant T"do T"qo subtransient short-circuit time constant T"d T"q 2.3 Excitation system, power system stabilizer and governor: manufacturer's data in sufficient detail to allow modeling in transient stability simulations. 2.4 Prime mover: manufacturer's data in sufficient detail to allow modeling in transient stability simulations, if determined necessary. 2.5 Busses: rated voltage and ampacity (normal, long-time emergency and short-time emergency thermal ratings), conductor type and configuration. 2.6 Transmission lines: overhead line or underground cable rated voltage and ampacity (normal, long-time emergency and short-time emergency thermal ratings), Z1 (positive sequence) and Zo (zero sequence) impedances, conductor type, configuration, length and termination points. 2.7 Motors greater than 150 kW 3-phase or 50 kW single-phase: type (induction or synchronous), rated hp, speed, voltage and current, efficiency and power factor at 1/2, 3/4 and full load, stator resistance and reactance, rotor resistance and reactance, magnetizing reactance. 2.8 Circuit breakers and switches: rated voltage, interrupting time and continuous, interrupting and momentary currents. Provide normal, long-time emergency and short-time emergency thermal ratings. 2.9 Protective relays and systems: ANSI function number, quantity manufacturer's catalog number, range, descriptive bulletin, tripping diagram and three-line diagram showing AC connections to all relaying and metering. 2.10 CT's and VT's: location, quantity, rated voltage, current and ratio. 2.11 Surge protective devices: location, quantity, rated voltage and energy capability. 3.0 Other 3.1 Additional data reasonably necessary to perform the System Impact Study will be provided by the Transmission Customer as requested by the Transmission Provider. 3.2 The Transmission Provider reserves the right to require that the Transmission Customer accept the use in the study of specific equipment settings or characteristics necessary to meet NEPOOL and NPCC criteria and standards. ATTACHMENT J Form of Facilities Study Agreement This agreement dated , is entered into by (the Transmission Customer) and the NEPOOL Participants (the "Transmission Operator") acting through the ("System Provider"), for the purpose of setting forth the terms, conditions and costs for conducting a Facilities Study relative to , in accordance with the NEPOOL Open Access Transmission Tariff ("Tariff"). All definitions and other terms and conditions of that Tariff are incorporated herein by reference. The Transmission Provider may designate one or more Participants or the System Operator to act for it under this Agreement. The Facilities Study will determine the detailed engineering, design and cost of the facilities necessary to satisfy the Transmission Customer's request for service over the NEPOOL Transmission System. 1. The Transmission customer agrees to provide, in a timely complete manner, the information and technical data specified in Exhibit 1 to this Agreement and reasonably necessary for the Transmission Provider to conduct the Facilities Study. Where such information and technical data was provided for the System Impact Study, it should be reviewed and updated with current information, as required. 2. All work pertaining to the Facilities Study that is the subject of this Agreement will be approved and coordinated only through designated and authorized representatives of the Transmission Provider and the Transmission Customer. Each party shall inform the other in writing of its designated and authorized representative. 3. The Transmission Provider will advise the Transmission Customer of additional information as may be reasonably deemed necessary to complete the study by the Transmission Provider. Any such additional information shall be obtained only if required by Good Utility Practice and shall be subject to the Transmission Customer's consent to proceed, such consent not to be unreasonably withheld. 4. The Transmission Provider contemplates that it will require ____ days to complete the Facilities Study. Upon completion of the study by the Transmission Provider, the Transmission Provider will provide a report to the Transmission Customer based on the information provided and developed as a result of this effort. If, upon review of the study results, the Transmission Customer decides to pursue its transmission service request, the Transmission Customer must sign a supplemental Service Agreement with the Transmission Provider under the Tariff. The System Impact and Facilities Studies, together with any additional studies contemplated in Paragraph 3, shall form the basis for the Transmission Customer's proposed use of the Transmission Provider's Transmission System and shall be furthermore utilized in obtaining necessary third-party approvals of any facilities and requested transmission services. The Transmission Customer understands and acknowledges that any use of the study results by the Transmission Customer or its agents whether in preliminary or final form, prior to approval under Section 18.4 of the Restated NEPOOL Agreement, is completely at the Transmission Customer's risk and that the Transmission Provider will not guarantee or warrant the completeness, validity or utility of the study results prior to NEPOOL 18.4 approval. 5. The estimated costs contained within this Agreement are the Transmission Provider's good faith estimate of its costs to perform the Facilities Study contemplated by this Agreement. The Transmission Provider's estimates do not include any estimates for wheeling charges that may be associated with the transmission of facility output to third parties or with rates for station service. The actual costs charged to the Transmission Customer by the Transmission Provider may change as set forth in this Agreement. Prepayment will be required for all study, analysis, and review work performed by the Transmission Provider's or its Designated Agent's personnel, all of which will be billed by the Transmission Provider to the Transmission Customer in accordance with Paragraph 6 of this Agreement. 6. The payment required is $ from the Transmission Customer to the Transmission Provider for the primary system analysis, coordination, and monitoring of the Facilities Study to be performed by the Transmission Provider for the Transmission Customer's requested service. The Transmission Provider will, in writing, advise the Transmission Customer in advance of any cost increases for work to be performed if the total amount increases by 10% or more. Any such changes to the Transmission Provider's costs for the study work to be performed shall be subject to the Transmission Customer's consent, such consent not to be unreasonably withheld. The Transmission Customer shall, within thirty (30) days of the Transmission Provider's notice of increase, either authorize such increases and make payment in the amount set forth in such notice, or the Transmission Provider will suspend the study and this Agreement will terminate if so permitted by the Federal Energy Regulatory Commission. In the event this Agreement is terminated for any reason, the Transmission Provider shall refund to the Transmission Customer the portion of the above credit or any subsequent payment to the Transmission Provider by the Transmission Customer that the Transmission Provider did not expend in performing its obligations under this Agreement. Any additional billings under this Agreement shall be subject to an interest charge computed in accordance with the provisions of the Tariff. Payments for work performed shall not be subject to refunding except in accordance with Paragraph 7 below. 7. If the actual costs for the work exceed prepaid estimated costs, the Transmission Customer shall make payment to the Transmission Provider for such actual costs within thirty (30) days of the date of the Transmission Provider's invoice for such costs. If the actual costs for the work are less than that prepaid, the Transmission Provider will credit such difference toward Transmission Provider's costs unbilled, or in the event there will be no additional billed expenses, the amount of the overpayment will be returned to the Transmission Customer with interest computed in accordance with the provisions of the Tariff. 8. Nothing in this Agreement shall be interpreted to give the Transmission Customer immediate rights to interconnect to or wheel over the NEPOOL Transmission System. Such rights shall be provided for under separate agreement. 9. Within one (1) year following the Transmission Provider's issuance of a final bill under this Agreement, the Transmission Customer shall have the right to audit the Transmission Provider's accounts and records at the offices where such accounts and records are maintained during normal business hours; provided that appropriate notice shall have been given prior to any audit and provided that the audit shall be limited to those portions of such accounts and records that relate to service under this Agreement. The Transmission Provider reserves the right to assess a reasonable fee to compensate for the use of its personnel time in assisting any inspection or audit of its books, records or accounts by the Transmission Customer or its Designated Agent. 10. Each party agrees to indemnify and hold the other party and its Related Persons harmless from and against any and all damages, costs (including attorney's fees), fines, penalties and liabilities, in tort, contract, or otherwise (collectively "Liabilities") resulting from claims of third parties arising, or claimed to have arisen as a result of any acts or omissions of either party under this Agreement. Each party hereby waives recourse against the other party and its Related Persons for, and releases the other party and its Related Persons from, any and all Liabilities for or arising from damage to its property due to performance under this Agreement by such other party except in cases of negligence or intentional wrongdoing by either party. 11. If any party materially breaches any of its covenants hereunder, the other party may terminate this Agreement by filing a notice of intent to terminate with the Federal Energy Regulatory Commission and serving notice of same on the other party to this Agreement. This remedy is in addition to any other remedies available for the injured party. 12. This agreement shall be construed and governed in accordance with the laws of the State of Connecticut and with Part II of the Federal Power Act, 16 U.S.C. Sections 824d et seq., and with Part 35 of Title 18 of the Code of Federal Regulations, 18 C.F.R. Sections 35 et seq. 13. All amendments to this Agreement shall be in written form executed by both parties. 14. The terms and conditions of this Agreement shall be binding on the successors and assigns of either party. 15. This Agreement will remain in effect for a period of two years from its effective date as permitted by the Federal Energy Regulatory Commission, and is subject to extension by mutual agreement. Either party may terminate this Agreement by thirty (30) days' notice except as is otherwise provided herein. If this Agreement expires by its own terms, it shall be the Transmission Provider's responsibility to make such filing. Transmission Customer: Name: Title: Date: NEPOOL Participants By (System Operator) Name: Title: Date: ATTACHMENT K 1997 Twelve CP Network Load Data NEPOOL 1997 12 CP Network Load NEPOOL 1997 12CP Network Loads NEPOOL Local Networks - 1997 1997 12CP Network Load (MW) Boston Edison Co. 3,023.024 Bangor Hydro Electric 255.589 Commonwealth Energy Systems 601.023 Central Maine Power 1,464.781 Eastern Utilities Associates 885.357 New England Electric System 3,957.775 Northeast Utilities 6,332.724 United Illuminating 677.367 Vermont Electric Light Co. 796.881 TOTAL 17,994.521 Boston Edison Company Network Load Customer 1997 12CP Network Load (MW) Boston Edison Co.** 2,383.727 Braintree 58.395 Cambridge*** 216.966 Concord (PASNY) 1.690 Hingham 25.083 Hull 6.139 MBTA 7.283 Norwood (NYPA) 2.635 Norwood (NEP Tariff 1) 48.448 Quincy/Weymouth (Retail Wheeling-MECO) 0.000 Quincy/Weymouth (NEP Tariff 1) 185.693 Reading 82.333 Wellseley (PASNY) 2.335 Belmont (PASNY) 2.297 Total 3,023.024 Bangor Hydro Electric Company Network Load Customer 1997 12CP Network Load (NW) Bangor Hydro Electric 255.589 Total 255.589 Commonwealth Electric Company Network Load Customer 1997 12CP Network Loan (MW) Commonwealth Electric Company 585.283 Nantucket (NEP Tariff 1) 15.740 Nantucket (Retail Wheeling) 0.000 Total 601.023 Central Maine Power Network Load Customer 1997 12CP Network Loan (MW) Central Maine Power 1,407.939 Fox Island 1.491 Kennebunk 15.024 Madison 40.327 Total 1,464.781 Eastern Utilities Associates Network Load Customer 1997 12CP Network Loan (MW) Eastern Utilities Associates** 756.175 Middleborough 22.967 Pascoag, RI 1.592 Taunton 90.940 Tiverton (Retail Wheeling - NECO) 0.000 Tiverton (NEP Tariff 1) 13.683 Total 885.357 New England Power Network Load Customer 1997 12CP Network Loan (MW) New England Power** 3,287.945 Granite State Electric (Retail Wheeling) 2.307 Massachusetts Electric (Retail Wheeling) 43.397 Narragansett Electric (Retail Wheeling) 2.750 Ashburnham 4.540 Boylston 3.930 Central Vermont Public Service 8.234 Danvers 52.435 Fitchburg Gas & Electric 72.331 French King 11.341 Georgetown 6.805 Green Mountain Power (Except Stamford) 59.480 Groton, MA 8.281 Groveland (NYPA Load) 0.510 Holden 15.199 Hudson 47.500 Ispwich 14.670 Littleton, MA 26.751 Mansfield 31.725 MBTA 5.851 Marblehead 17.121 Massachusetts Governors Land Bank 2.127 Merrimac (NYPA) 0.525 Middleton 14.928 N. Attleboro 36.158 Paxton 3.069 Network Load Customer 1997 12CP Network Loan (MW) Peabody 73.540 Princeton 2.388 Rowley 5.305 Shrewsbury 43.113 Sterling 6.673 Templeton 8.902 Wakefield 28.317 W. Boylston 9.627 Total 3,957.775 Northeast Utilities Network Load Customer 1997 12CP Network Loan (MW) Northeast Utilities** 5,377.920 Bolt Hill 34.630 Chicopee 64.539 Conn. Municipal Electric Energy Co-op 268.199 Holyoke Gas & Electric 48.541 SBNG (Retail Wheeling - MECO)*** 0.000 SBNG (NEP Tariff 1)*** 84.184 S. Hadley 21.182 The Six United Illuminating Substations 218.535 UNITIL 164.297 Westfield 50.697 Total 6,332.724 United Illuminating Company Network Load Customer 1997 12CP Network Loan (MW) United Illuminating 677.367 Total 677.367 Vermont Electric Power Co. Network Load Customer 1997 12CP Network Loan (MW) Vermont Electric Light Co. 796.881 Total 796.881 Total of all Transmission Providers 12CP = 17,994.521 ATTACHMENT L Financial Assurance Policy for NEPOOL Members This Financial Assurance Policy for NEPOOL Members ("Policy") shall become effective January 1, 1999 (the "Policy Effective Date"). (FN1) The purpose of this Policy is (i) to establish a financial assurance policy for NEPOOL members ("Participants") that includes commercially reasonable credit review procedures to assess the financial ability of an applicant for membership in NEPOOL ("Applicant") or of a Participant to pay for service transactions under the Restated NEPOOL Agreement and the NEPOOL Open Access Transmission Tariff (the "Tariff") and to pay its share of NEPOOL expenses, including amounts owed to the ISO under its tariff, (ii) to set forth requirements for alternative forms of security that will be deemed acceptable to NEPOOL and consistent with commercial practices established by the Uniform Commercial Code that protects the Participants against the risk of non- payment by other, defaulting Participants, (iii) to set forth the conditions under which NEPOOL will conduct business so as to avoid the possibility of failure of payment for services rendered under the Tariff or the Restated NEPOOL Agreement, and (iv) to collect amounts past due, collect amounts payable upon billing adjustments, make up shortfalls in payments, and terminate membership of defaulting Participants. In accordance with Sections 3.5 and 7.5 of the Restated NEPOOL Agreement, NEPOOL requires the following procedures and requirements to apply to all Applicants and Participants. Generally, any Applicant or Participant that does not have an investment grade rating by either Standard & Poor's, Moody's, Duff & Phelps, or Fitch (or in the case of Applicants or Participants that are not rated themselves, any Applicant or Participant that does not have outstanding debt with such a rating) will be required to provide financial assurances, as described in detail below. - --------- (FN1) Capitalized terms used but not defined in this Policy are intended to have the meanings given to such terms in Section 1 of the Restated NEPOOL Agreement or Section 1 of the Restated NEPOOL Open Access Transmission Tariff (the "Tariff"), as amended. GENERAL REQUIREMENTS Each Applicant or Participant must comply with the following general requirements. In the case of a group of members that are treated as a single Participant pursuant to Section 4.1 of the Restated NEPOOL Agreement, the group members shall be deemed to have elected to be jointly and severally liable for all debts to NEPOOL of any of the group members unless (i) charges of an individual member can be tracked and allocated to the member incurring such charges by the System Operator (FN1) utilizing all information available to the System Operator determined by it to be reliable, including information from Participants or from a single Participant's representative, (ii) an alternate form of financial assurance is provided as set forth below, (iii) the group members agree to allocate amongst themselves responsibility for payment of group member charges on a percentage basis in a manner acceptable to NEPOOL, with additional financial assurance to be provided by those members, if any, that do not satisfy the minimum corporate debt rating, or (iv) the group members when evaluated as a whole (at their expense by one of the above rating agencies) satisfy the minimum corporate debt rating requirement set forth above and, in addition, provide a corporate guaranty from a parent or other responsible affiliate, which parent or affiliate satisfies the minimum corporate debt rating. For the fourth type of consolidated Participant, NEPOOL will conduct a financial assurances review based on the credit rating of only the rated members of the group. For the purposes of these financial assurance provisions, the term "Participant" shall, in the case of a group of members that are treated as a single Participant pursuant to Section 4.1 of the Restated NEPOOL Agreement, be deemed to refer to the group of members as a whole unless the group members have affirmatively indicated to NEPOOL, and NEPOOL has agreed, that they are to be treated pursuant to options (i) or (iii) above, in which case the term "Participant" shall be deemed to refer to each individual group member and not to the aggregate of such group; and the terms "charges" and fees" shall, likewise, be deemed to refer to the charges and fees allocable to the individual group member as opposed to the aggregate of such group. - -------- (FN1) The System Operator will act as NEPOOL's agent in managing and enforcing this Policy with the exception of termination of membership issues, which are specifically reserved to the NEPOOL Participants and will be addressed by the NEPOOL Executive Committee Membership Subcommittee, subject to appeal to the Management Committee. Accordingly, all financial information required pursuant to this Policy is to be provided to the System Operator, which will keep all such information confidential in accordance with the provisions of Section 2 of NEPOOL Criteria, Rules and Standards No. 45. Proof of Financial Viability Each Applicant must with its application submit proof of financial viability, as described below, satisfying NEPOOL requirements to demonstrate the Applicant's ability to meet its obligations, or must provide prior to its membership becoming effective financial assurance in the form of a cash deposit, letter of credit or performance bond as set forth below. An Applicant that chooses to provide a cash deposit, letter of credit or performance bond will not be required to provide financial information to NEPOOL. Generally, each Applicant must submit a current rating agency report, which report must indicate an investment grade rating by either Standard & Poor's, Moody's, Duff & Phelps, or Fitch for the Applicant or, if the Applicant itself is not rated, for the Applicant's outstanding rated debt, in order for the Applicant to be considered as a candidate for NEPOOL membership without furnishing additional financial assurances as described below. Current Participants must also provide a current rating agency report by the Policy Effective Date, as well as any of the financial statements and information set forth below if and as requested by NEPOOL within ten (10) days of such request. Those Participants that do not satisfy the rating requirement as set forth above must provide instead on the Policy Effective Date one form of the financial assurances set forth below. A Participant's failure to meet these requirements may result in termination proceedings by NEPOOL. Financial Statements Each Applicant must submit, if and as requested by NEPOOL and within ten (10) days of such request, audited financial statements for at least the immediately preceding three years, or the period of its existence, if shorter, including, but not limited to, the following information: Balance Sheets Income Statements Statements of Cash Flows Notes to Financial Statements Additionally, the following information for at least the immediately preceding three years, if available, must be submitted if and as requested by NEPOOL and within ten (10) days of such request: Annual and Quarterly Reports 10-K, 10-Q and 8-K Reports Where the above financial statements are available on the Internet, the Applicant may provide instead a letter to NEPOOL stating where such statements may be located and retrieved by NEPOOL. Each Applicant may also be required to provide at least one bank reference and three (3) Utility credit references. In those cases where an Applicant does not have three (3) Utility credit references, three (3) trade payable vendor references may be substituted. Each Applicant may also be required to include information as to any known or anticipated material lawsuits, as well as any prior bankruptcy declarations by the Applicant, or by its predecessor(s), if any. In the case of certain Applicants, some of the above financial submittals may not be applicable, and alternate requirements may be specified by NEPOOL. Ongoing Financial Review Each Participant that has not provided a cash deposit, letter of credit, performance bond, or corporate guaranty must submit its current rating agency report promptly upon the request of NEPOOL, and 8-K Reports promptly upon their issuance. In addition, each Participant is responsible for informing NEPOOL in writing within ten (10) business days of any material change in its financial status. A material change in financial status includes, but is not limited to, the following: a downgrade to a below investment grade rating of senior long term debt by a major rating agency, being placed on credit watch with negative implication by a major rating agency if senior long term debt does not have an investment grade rating, a bankruptcy filing, insolvency, a report of a significant quarterly loss or decline of earnings, the resignation of key officer(s), and/or the filing of a material lawsuit that could materially adversely impact current or future financial results. A Participant's failure to provide this information may result in termination proceedings by NEPOOL. If there is a material adverse change in the financial condition of the Participant, NEPOOL may require the Participant to provide one of the forms of other financial assurances set forth below. If the Participant fails to do so, NEPOOL may initiate termination proceedings in accordance with the procedure set forth in Section 21.2(d) of the Restated NEPOOL Agreement. OTHER FINANCIAL ASSURANCES Applicants or Participants that do not satisfy the rating requirement or NEPOOL's credit review process must submit instead one of the following additional financial assurances, depending on the type of transactions they anticipate engaging in as Participants. Each financial assurance for monthly charges, unless replaced in accordance with the terms hereof or no longer required pursuant to the terms hereof, shall remain in effect for one hundred twenty days after termination of the Participant's membership, provided, however that financial assurances required by this Financial Assurance Policy related to potential billing adjustments chargeable to a terminated Participant shall remain in effect until such billing adjustment request is finally resolved in accordance with the provisions of the NEPOOL Billing Policy. In general, Participants must provide additional financial assurance in the following amounts, based on their average or expected monthly charges for interchange and transmission service under the Tariff (which would include charges for Regional Network Service or Through or Out Service) and the Restated NEPOOL Agreement (which would include energy and other services received through NEPOOL) and NEPOOL expenses for services, including amounts owed to ISO New England Inc. under its tariff (collectively the "NEPOOL Charges"): Monthly NEPOOL Charges Financial Assurance Requirement $0 - $15,000 0 months' NEPOOL Charges $15,001 - $30,000 1 month's NEPOOL Charges $30,001 - $50,000 2 months' NEPOOL Charges $50,001 or more 3 1/2 months' NEPOOL Charges The three and one-half months is based on the time required for a FERC filing made by NEPOOL to suspend service to be effective. Therefore, a Participant with $32,000 in monthly NEPOOL Charges that does not satisfy the rating requirement or NEPOOL credit review process must provide additional financial assurances in the amount of $64,000 to NEPOOL. In the case of new Participants, the additional financial assurance requirement will be based on estimated monthly NEPOOL Charges, which estimate NEPOOL has the right to adjust in light of subsequent experience as to actual monthly NEPOOL Charges. Furthermore and without limiting the generality of the foregoing, if a Participant that has received from one or more other Participants or Non- Participant Transmission Customers an amount the payment of which is the subject of a dispute, an amount equal to 100% of such amount in dispute shall be included in determining that Participant's overall financial assurance requirement. Any additional financial assurance provided under this paragraph shall not be terminated or returned prior to the resolution of the dispute requiring such additional financial assurance, even if the Participant providing such additional financial assurance is terminated or withdraws from NEPOOL and otherwise satisfies all of its obligations to NEPOOL. As used herein, the term "Financial Assurance Requirement" shall include 100% of such amount in dispute, in addition to the other amounts included in such Financial Assurance Requirement for the relevant Participant. In addition, and without limiting the foregoing, any Participant that does not satisfy the rating requirement or NEPOOL's credit review process and that has monthly NEPOOL Charges (determined as set forth above) in excess of $15,000 shall not at any time have net NEPOOL Charges (regardless of whether such charges have actually become due and owing or not) in excess of the amount of the additional financial assurance provided by such Participant. Any Participant that does not satisfy the rating requirement or NEPOOL's credit review process but is exempt from providing additional financial assurance by virtue of having monthly NEPOOL charges of $15,000 or less shall not at any time have net NEPOOL Charges (regardless of whether such charges have actually become due and owing or not) in excess of $15,000 unless such Participant provides the additional financial assurance described herein in an amount not less than such net NEPOOL Charges. If a Participant that does not satisfy the rating requirement or NEPOOL's credit review process exceeds the limits for net NEPOOL Charges set forth for it in this paragraph, NEPOOL may initiate termination proceedings. A Participant that does not satisfy the rating requirement or NEPOOL's credit review process and knows or reasonably should know that it has exceeded the limits for net NEPOOL Charges set forth for it in this paragraph shall notify the ISO immediately that it has exceeded such limits. Cash Deposit A cash deposit for the full value of the Financial Assurance Requirement, as determined by NEPOOL, provides an acceptable form of financial assurance to NEPOOL. If the amount of the deposit is below the required level, the Participant shall immediately replenish or increase the deposit to the required level; otherwise, NEPOOL may initiate termination proceedings. In the event that actual NEPOOL Charges exceed those anticipated, the anticipated charges will be increased accordingly and the Participant must augment its cash deposit to reach the required level. The cash deposit will be invested by NEPOOL in investments as may be designated by the Participant in direct obligations of the United States or its agencies and interest earned will be paid to the Participant. NEPOOL may sell or otherwise liquidate such investments at its discretion to meet the Participant's obligations to NEPOOL. The requirement to continue the deposit may be reviewed by NEPOOL after one year. Consideration will be given to replacing the cash deposit with a corporate guaranty if certain conditions are met, as discussed below in the Corporate Guaranty section. Letter of Credit An irrevocable standby letter of credit for the full value of the Financial Assurance Requirement, as determined by NEPOOL, provides an acceptable form of financial assurance to NEPOOL. The letter of credit will renew automatically unless the issuing bank provides notice to NEPOOL at least ninety (90) days prior to the letter of credit's expiration of the bank's decision not to renew the letter of credit. If the letter of credit amount is below the required level, the Participant shall immediately replenish or increase the letter of credit amount; otherwise, NEPOOL may initiate termination proceedings. If actual NEPOOL Charges exceed those anticipated, the Participant must obtain a substitute letter of credit that equals the actual NEPOOL Charges. The form, substance, and provider of the letter of credit must all be acceptable to NEPOOL. The letter of credit should clearly state the full names of the "Issuer," "Account Party" and "Beneficiary" (NEPOOL), the dollar amount available for drawings, and should include a statement required on the drawing certificate and other terms and conditions that should apply. It should also specify that funds will be disbursed, in accordance with the instructions, within one (1) business day after due presentation of the drawing certificate. The bank issuing the letter of credit must have a minimum corporate debt rating of an "A-" by Standard & Poor's, or "A3" by Moody's, or "A-" by Duff & Phelps, or "A-" by Fitch, or an equivalent short term debt rating by one of these agencies. Please refer to Attachment 1, which provides an example of a generally acceptable sample "clean" letter of credit. All costs associated with obtaining financial security and meeting the Policy provisions are the responsibility of the Applicant or Participant. The requirement to continue to provide a letter of credit may be reviewed by NEPOOL after one year. Consideration will be given to replacing the letter of credit with a corporate guaranty if certain conditions are met, as discussed below in the Corporate Guaranty section. Performance Bond A performance bond complying with the requirements set forth herein provides an acceptable form of financial assurance to NEPOOL. The penal sum of such performance bond shall be in an amount equal to the full value of the Financial Assurance Requirement, as determined by NEPOOL, and shall automatically be adjusted to reflect any adjustment in such Financial Assurance Requirement. The bond shall permit suit thereunder until two years after the date that all of the Applicant's or Participant's obligations to NEPOOL expire. If the amount of the penal sum of the performance bond available to NEPOOL is below the required level, the Participant shall immediately replenish or increase the amount of the penal sum; otherwise, NEPOOL may initiate termination proceedings. If actual NEPOOL Charges exceed those anticipated, the Participant must either cause the penal sum of such performance bond to be increased accordingly or must obtain a substitute performance bond in the appropriate amount. The form, substance and provider of the performance bond must be acceptable to NEPOOL. The performance bond should clearly state the full names of the "Principal," the "Surety" and the "Obligee" (NEPOOL) and the penal sum and should include a clear statement that the surety will promptly and faithfully perform the Participant's obligations to NEPOOL if the Participant fails to do so. The insurance company issuing the performance bond must be rated "A" or better by A.M. Best & Co. Please refer to Attachment 2, which provides an example of a generally acceptable sample performance bond. All costs associated with obtaining financial security and meeting the Policy provisions, including without limitation the cost of the premiums for such performance bond, are the responsibility of the Applicant or Participant. The requirement to continue to provide a performance bond may be reviewed by NEPOOL after one year. Consideration will given to replacing the performance bond with a corporate guaranty if certain conditions are met, as discussed below in the Corporate Guaranty section. Weekly Payments A Participant that does not satisfy the rating requirement may request that, in lieu of providing one of the additional financial assurances set forth above, a weekly billing schedule be implemented for it. NEPOOL may, in its discretion, agree to such a request; provided, however, that any weekly billing arrangement will terminate no more than six months after the date on which such arrangement begins unless the Participant requests an extension of such arrangement and demonstrates to NEPOOL's satisfaction in its sole discretion that the termination of such arrangement and compliance with the other provisions of this Policy (including providing another form of financial assurance, if required) will impose a substantial hardship on the Participant. Such demonstration of a substantial hardship shall be made every six months after the initial demonstration, and a Participant's weekly billing arrangement will be terminated if it fails to demonstrate to NEPOOL's satisfaction in its sole discretion at any such six month interval that compliance with the other provisions of this Policy will impose a substantial hardship on it. If NEPOOL agrees to implement a weekly billing schedule for a Participant, the Participant shall be billed weekly in arrears on an estimated basis for all amounts owed to NEPOOL and the System Operator for the week, with an adjustment for each month as part of the regular NEPOOL monthly billing to reflect any under or over collection for the month. The Participant shall be obligated to pay each such weekly bill within five business days after it is received. The Participant shall pay with respect to each weekly bill an administrative fee, determined by the System Operator, to reimburse the System Operator for the costs it incurs as a result of that Participant's weekly billing arrangement. If a weekly billing schedule is implemented for a Participant in lieu of requiring the Participant to provide an additional financial assurance, the Participant may be required to provide an additional financial assurance at any time if the Participant fails to pay when due any weekly bill. In addition, upon the termination of a Participant's weekly billing arrangement, the Participant shall either satisfy the rating requirement set forth herein or provide one of the other forms of financial assurance set forth herein. Use of Transaction Setoffs Under certain conditions, NEPOOL may be obligated to make payments to a Participant. In this event, the amount of the cash deposit, letter of credit or performance bond required for financial assurance for the contemplated transactions may be reduced ("setoff") by an amount equal to NEPOOL's unpaid balance or expected billing under the other transactions. The terms and the amount of the setoff must be approved by NEPOOL. Corporate Guaranty An irrevocable corporate guaranty obtained from a Participant's affiliated company ("Guarantor") for the full value of the Financial Assurance Requirement, as determined by NEPOOL, may provide an acceptable form of financial assurance to NEPOOL. If actual NEPOOL Charges exceed those anticipated, the Participant must provide a substitute corporate guaranty that equals the actual NEPOOL Charges. A Participant for which a letter of credit, performance bond or cash deposit was initially required may have the opportunity to substitute a corporate guaranty if the following conditions are met: 1. NEPOOL determines that the Participant has satisfactorily met its payment obligations in NEPOOL for at least one-year, which one-year period may in whole or in part pre-date the Policy Effective Date; 2. NEPOOL determines that the financial condition of the Guarantor meets the requirements of this Policy; and 3. 3. The form and substance of the corporate guaranty are acceptable to NEPOOL. Upon NEPOOL's written authorization, the Participant may substitute a corporate guaranty that is issued by the Guarantor for a cash deposit, bank letter of credit or performance bond when it has satisfied the conditions stipulated above. The corporate guaranty is considered to be a lesser form of financial assurance than a cash deposit, letter of credit or performance bond, and therefore is allowed as an acceptable form of financial assurance only to those Participants that have satisfied their payment obligations to NEPOOL in a timely manner for at least one year. The corporate guaranty may only be used if the Participant is affiliated with a Guarantor that has greater financial assets, a strong balance sheet and income statements, and at minimum an investment grade rating by either Standard & Poor's, Moody's, Duff & Phelps, or Fitch. The corporate guaranty should clearly state the identities of the "Guarantor," "Beneficiary" and "Obligor," and the relationship between the Guarantor and the Participant Obligor. The corporate guaranty must be duly authorized by the Guarantor, must be signed by an officer of the Guarantor, and must be furnished with either an opinion satisfactory to NEPOOL of the Guarantor's counsel with respect to the enforceability of the guaranty or accompanied by a certificate of corporate guarantee that includes a seal of the corporation with the signature of the corporate secretary. Additionally, adequate documentation regarding the signature authority of the person signing the corporate guaranty must be provided with the corporate guaranty. A corporate guaranty must also obligate the Guarantor to submit a current rating agency report promptly upon the request of NEPOOL, to submit 8-K Reports promptly upon their issuance, to submit financial reports if and as requested by NEPOOL within ten (10) days of such request, and to inform NEPOOL in writing within ten (10) business days of any material change in its financial status. A material change in financial status includes, but is not limited to, the following: a downgrade to a below investment grade rating of senior long term debt by a major rating agency, being placed on credit watch with negative implication by a major rating agency if senior long term debt does not have an investment grade rating, a bankruptcy filing, insolvency, a report of a significant quarterly loss or decline of earnings, the resignation of key officer(s), and/or the filing of a material lawsuit that could materially adversely impact current or future financial results. A Guarantor's failure to provide this information may result in proceedings by NEPOOL to terminate the Participant Obligor. If there is a material adverse change in the financial condition of the Guarantor, NEPOOL may require the Participant Obligor to provide another form of financial assurance, either a cash deposit or a letter of credit or a performance bond. Non-payment of Amounts Due If a Participant does not pay amounts billed when due and as a result a letter of credit or cash deposit is drawn down or a performance bond is paid on, then the Participant must immediately replenish the letter of credit or cash deposit to the required amount or cause the penal sum of the performance bond to be increased to equal the required amount plus all amounts paid thereunder. If a Participant fails to do so, NEPOOL may initiate termination proceedings against the Participant in accordance with the procedure set forth in Section 21.2(d) of the Restated NEPOOL Agreement. In order to encourage prompt payment by Participants of amounts owed to NEPOOL and the ISO, if a Participant is delinquent two or more times within any period of twelve months in paying on time its NEPOOL Charges, the Participant shall pay, in addition to interest on each late payment, a late payment charge for its second failure to pay on time, and for each subsequent failure to pay on time, within the same twelve-month period, in an amount equal to the greater of (i) two percent (2%) of the total amount of such late payment or (ii) $250.00. In the case of a former Participant that applies again for membership in NEPOOL, a determination of delinquency shall be based on the Participant's history of payment of its NEPOOL Charges in its last twelve (12) months of membership. Financial Assurance upon Termination of Membership Upon termination of membership in NEPOOL, a Participant must provide financial assurance in the amount of all potential billing adjustments chargeable to such Participant for all unresolved billing disputes in existence on the date of termination of such Participant's membership. Such financial assurance must be in the form of a cash deposit, a letter of credit, an affiliate guaranty, or a performance bond meeting the requirements of this policy. The amount of such financial assurance shall be reduced to the extent any billing dispute is resolved and the former Participant pays the billing adjustments or no billing adjustment is chargeable to the former Participant. Notification of Default In the event that a Participant fails to comply with this Financial Assurance Policy (including, without limitation, a failure by such Participant (i) to provide NEPOOL with the required information, (ii) to maintain its additional financial assurance at the required level, (iii) to notify NEPOOL of a material adverse change in the financial condition of such Participant or its Guarantor, or (iv) to notify NEPOOL of such Participant's net Monthly Charges exceeding the limits set forth above) (a "Financial Assurance Default") and such failure continues for at least ten days, 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 NEPOOL Participants Committee or billing contact (it being understood that NEPOOL will use reasonable efforts to contact all three), of such Financial Assurance Default. Either simultaneously with the giving of the notice described in the preceding sentence or within the ten days thereafter (unless the Financial Assurance Default is cured during such period), NEPOOL shall notify each other member and alternate on the NEPOOL Participants Committee and each Participant's billing contact of the identity of the Participant receiving such notice, whether such notice relates to a Financial Assurance Default, and the actions NEPOOL plans to take and/or has taken in response to such Financial Assurance Default. No remedy for a Financial Assurance Default is or shall be deemed to be exclusive of any other available remedy or remedies. Each such remedy shall be distinct, separate and cumulative, shall not be deemed inconsistent with or in exclusion of any other available remedy, and shall be in addition to and separate and distinct from every other remedy. ATTACHMENT 1 SAMPLE LETTER OF CREDIT [DATE PROVIDED] IRREVOCABLE STANDBY LETTER OF CREDIT NO. [EXPIRATION DATE] AT OUR COUNTERS [unless an evergreen l/c is obtained] WE DO HEREBY ISSUE AN IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT BY ORDER OF AND FOR THE ACCOUNT OF ON BEHALF OF [PARTICIPANT] ("ACCOUNT PARTY") IN FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") IN AN AMOUNT NOT EXCEEDING US$ .00 (UNITED STATES DOLLARS AND 00/100) AGAINST PRESENTATION TO US OF A DRAWING CERTIFICATE SIGNED BY A PURPORTED OFFICER OR AUTHORIZED AGENT OF NEPOOL AND DATED THE DATE OF PRESENTATION CONTAINING THE FOLLOWING STATEMENT: "THE UNDERSIGNED HEREBY CERTIFIES TO [BANK] ("BANK"), WITH REFERENCE TO IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT NO. ISSUED BY [BANK] IN FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") THAT [PARTICIPANT] HAS FAILED TO PAY NEPOOL IN ACCORDANCE WITH THE TERMS AND PROVISIONS OF THE RESTATED NEPOOL AGREEMENT BETWEEN [PARTICIPANT] AND THE OTHER NEPOOL MEMBERS , AND THUS NEPOOL IS DRAWING UPON THE LETTER OF CREDIT IN AN AMOUNT EQUAL TO $ ." IF PRESENTATION OF ANY DRAWING CERTIFICATE IS MADE ON A BUSINESS DAY AND SUCH PRESENTATION IS MADE AT OUR COUNTERS ON OR BEFORE 10:00 A.M. TIME, WE SHALL SATISFY SUCH DRAWING REQUEST ON THE SAME BUSINESS DAY. IF THE DRAWING CERTIFICATE IS RECEIVED AT OUR COUNTERS AFTER 10:00 A.M. TIME, WE WILL SATISFY SUCH DRAWING REQUEST ON THE NEXT BUSINESS DAY, FOR THE PURPOSES OF THIS SECTION, A BUSINESS DAY MEANS A DAY, OTHER THAN A SATURDAY OR SUNDAY, ON WHICH COMMERCIAL BANKS ARE NOT AUTHORIZED OR REQUIRED TO BE CLOSED IN NEW YORK, NEW YORK. DISBURSEMENTS SHALL BE IN ACCORDANCE WITH THE INSTRUCTIONS OF NEPOOL. THE FOLLOWING TERMS AND CONDITIONS APPLY: THIS LETTER OF CREDIT SHALL EXPIRE AT THE CLOSE OF BUSINESS [DATE]. WE WILL PROVIDE NOTICE TO NEPOOL AT LEAST 90 DAYS PRIOR TO SUCH DATE IF THIS LETTER OF CREDIT WILL NOT BE RENEWED AS OF SUCH DATE [or: THIS LETTER OF CREDIT SHALL EXPIRE ONLY UPON THE FOLLOWING CONDITIONS: (1) WHEN FULL PAYMENT HAS BEEN RECEIVED BY NEPOOL FROM [PARTICIPANT] AND (2) NEPOOL HAS PROVIDED A WRITTEN RELEASE TO THIS BANK .] THE AMOUNT WHICH MAY BE DRAWN BY YOU UNDER THIS LETTER OF CREDIT SHALL BE AUTOMATICALLY REDUCED BY THE AMOUNT OF ANY UNREIMBURSED DRAWINGS HEREUNDER AT OUR COUNTERS. ANY NUMBER OF PARTIAL DRAWINGS ARE PERMITTED FROM TIME TO TIME HEREUNDER. ALL COMMISSIONS AND CHARGES WILL BE BORNE BY THE ACCOUNT PARTY. THIS LETTER OF CREDIT IS NOT TRANSFERABLE OR ASSIGNABLE. THIS LETTER OF CREDIT DOES NOT INCORPORATE AND SHALL NOT BE DEEMED MODIFIED, AMENDED OR AMPLIFIED BY REFERENCE TO ANY DOCUMENT, INSTRUMENT OR AGREEMENT (A) THAT IS REFERRED TO HEREIN (EXCEPT FOR THE UCP, AS DEFINED BELOW) OR (B) IN WHICH THIS LETTER OF CREDIT IS REFERRED TO OR TO WHICH THIS LETTER OF CREDIT RELATES. THIS LETTER OF CREDIT SHALL BE GOVERNED BY THE UNIFORM CUSTOMS AND PRACTICE FOR DOCUMENTARY CREDITS, 1993 REVISION, INTERNATIONAL CHAMBER OF COMMERCE PUBLICATION NO. 500 (THE "UCP"), EXCEPT TO THE EXTENT THAT TERMS HEREOF ARE INCONSISTENT WITH THE PROVISIONS OF THE UCP, INCLUDING BUT NOT LIMITED TO ARTICLES 13(b) AND 17 OF THE UCP, IN WHICH CASE THE TERMS OF THE LETTER OF CREDIT SHALL GOVERN. THIS LETTER OF CREDIT MAY NOT BE AMENDED, CHANGED OR MODIFIED WITHOUT THE EXPRESS WRITTEN CONSENT OF NEPOOL AND US. WE HEREBY ENGAGE WITH YOU THAT DOCUMENTS DRAWN UNDER AND IN COMPLIANCE WITH THE TERMS OF THIS LETTER OF CREDIT SHALL BE DULY HONORED UPON PRESENTATION AS SPECIFIED. PRESENTATION OF ANY DRAWING CERTIFICATE UNDER THIS STANDBY LETTER OF CREDIT MAY BE SENT TO US BY COURIER, CERTIFIED MAIL, REGISTERED MAIL, TELEGRAM, TELEX TO THE ADDRESS SET FORTH BELOW, OR SUCH OTHER ADDRESS AS MAY HEREAFTER BE FURNISHED BY US. OTHER NOTICES CONCERNING THIS STANDBY LETTER OF CREDIT MAY BE SENT BY FACSIMILE OR SIMILAR COMMUNICATIONS FACILITY TO THE RESPECTIVE ADDRESSES SET FORTH BELOW. ALL SUCH NOTICES AND COMMUNICATIONS SHALL BE EFFECTIVE WHEN ACTUALLY RECEIVED BY THE INTENDED RECIPIENT PARTY. IF TO THE BENEFICIARY OF THIS LETTER OF CREDIT: IF TO THE ACCOUNT PARTY: IF TO US: [signature] [signature] ATTACHMENT 2 SAMPLE PERFORMANCE BOND [Insurance Company] Bond No. KNOW ALL MEN BY THESE PRESENTS, That the undersigned [participant], of [participant's address] hereinafter referred to as the Principal, and [insurance company], a corporation organized and existing under the laws of the State of [insurance company's state of incorporation], as Surety, are held and firmly bound unto the Participants in the New England Power Pool as obligees, hereinafter referred to collectively as the Obligee, in the sum of , lawful money of the United States of America (which sum shall automatically be adjusted to reflect any adjustment in the Financial Assurance Requirement applicable to the Principal under the New England Power Pool's Financial Assurance Policy for NEPOOL Members, as in effect from time to time) for the payment of which sum, well and truly to be made, we bind ourselves, our executors, administrators, successors, and assigns, jointly and severally, firmly by these presents. WHEREAS, the Principal has entered into agreements for the purchase and sale of electric services and the payment of amounts owed to ISO New England Inc. and its share of the expenses of the New England Power Pool under the Restated NEPOOL Agreement, the Restated NEPOOL Open Access Transmission Tariff and the ISO New England Inc. Tariff for Transmission Dispatch and Power Administration Services, each as amended from time to time (collectively referred to as the "Agreements"), and in strict accordance with their respective terms. NOW, THEREFORE, the condition of this obligation is such, that if the Principal shall promptly and faithfully make the payments required by, and comply with terms of, the Agreements which have been or may hereafter be in force and shall save and keep harmless the Obligee from all loss or damage which it may sustain or for which it may become liable on account of the issuance of said Agreements to the Principal, then this obligation shall be void; otherwise, it shall remain in full force and effect. Upon notice from ISO New England Inc. of nonpayment by the Principal, Surety will pay to ISO New England Inc., as agent for the Obligee, the amounts owed by the Principal under the Agreements. The Surety hereby waives notice of any alteration or extension of time made by the Obligee. Any suit on this bond must be instituted before the expiration of two (2) years from the date on which the Principal's obligations under the Agreements expires. SIGNED, SEALED AND DATED this day of , 19 . [Seal] [Participant] Principal By: [Seal] [Insurance Company] Surety By: ATTACHMENT 3 CORPORATE GUARANTY For and in consideration of the credit advance or sale of products on open account by the New England Power Pool Participants from time to time ("Participants") to [Participant] ("Company"), the undersigned guarantor, ("Guarantor"), the [subsidiary/affiliate] of Company, hereby unconditionally and irrevocably guarantees the prompt and complete payment of all amounts that Company now or hereafter owes to Participants under the Restated NEPOOL Agreement and Restated NEPOOL Open Access Transmission Tariff, [and performance by Company of any other agreements, whether now existing or hereafter arising, between Company and Participants], as amended from time to time (collectively referred to as the "Agreements"), in strict accordance with their respective terms. 1. If Company does not perform its obligations in strict accordance with the Agreements, Guarantor shall immediately pay all amounts now or hereafter due thereunder (including, without limitation, all principal, interest, and fees) and otherwise proceed to complete the same and satisfy all of Company's obligations under the Agreements. This Guaranty may be satisfied by Guarantor paying and/or performing (as appropriate) Company's obligations or by Guarantor causing Company's obligations to be paid or performed; provided, however, that Guarantor shall at all times remain fully responsible and liable for its obligations hereunder notwithstanding any such payment or performance (or failure thereof) by any third party. Participants will undertake commercially reasonable efforts to notify Guarantor of a failure by Company to make a payment or perform its obligations under the Agreements; provided, however, that failure by Participants to so notify Guarantor shall not defeat, limit or otherwise affect the rights and obligations of Participants, Company or Guarantor. Subject to the terms and conditions set forth herein, Guarantor's obligations hereunder shall not exceed the complete payment of all amounts that Company now or hereafter owes to Participants under the Restated NEPOOL Agreement and NEPOOL Open Access Transmission Tariff and performance by Company of the Agreements in strict accordance with their respective terms. 2. This Guaranty is an absolute, unconditional and continuing guaranty of the full and punctual payment and performance by Company of each of its obligations under the Agreements, and not of collectibility only, and is in no way conditioned upon any requirement that Participants first attempt to collect payment from Company or any other guarantor or surety or resort to any security or other means of obtaining payment of all or any part of Company's obligations or upon any other contingency. This is a continuing guaranty and shall be binding upon Guarantor until the full, final and irrevocable payment and performance of all of Company's obligations under the Agreements, regardless of (i) how long after the date hereof any part of the obligations under the Agreements is incurred by Company and (ii) the amount of the obligations under the Agreements at any time outstanding. This Guaranty may be enforced by Participants from time to time and as often as occasion for such enforcement may arise. 3. The obligations hereunder are independent of the obligations of Company, and a separate action or actions may be brought and prosecuted against Guarantor whether action is brought against Company or whether Company be joined in any such action or actions. Guarantor's liability under this Guaranty is not conditioned or contingent upon genuineness, validity, regularity or enforceability of the Agreements. 4. Guarantor authorizes Participants, without notice or demand and without affecting its liability hereunder, from time to time to (a) renew, extend, or otherwise change the terms of the Agreements or any part thereof, (b) take and hold security for the payment of the Agreements, and exchange, enforce, waive and release any such security; and (c) apply such security and direct the order or manner of sale thereof as Participants in their sole discretion may determine. The obligations and liabilities of Guarantor hereunder shall be absolute and unconditional, shall not be subject to any counterclaim, set- off, deduction or defense based upon any claim Guarantor may have against Company, any other guarantor, or any other person or entity, and shall remain in full force and effect until all of the obligations hereunder and under the Agreements have been fully satisfied, without regard to, or release or discharge by, any event, circumstance or condition (whether or not Guarantor shall have knowledge or notice thereof) which but for the provisions of this Section might constitute a legal or equitable defense or discharge of a guarantor or surety or which might in any way limit recourse against Guarantor, including without limitation: (a) any amendment or modification of, or supplement to, the terms of the Agreements; (b) any waiver, consent or indulgence by Participants, or any exercise or non-exercise by Participants of any right, power or remedy, under or in respect of this Guaranty or the Agreements (whether or not Guarantor or Company has or have notice or knowledge of any such action or inaction); (c) the invalidity or unenforceability, in whole or in part, of the Agreements, or the termination (except pursuant to its terms or by written agreement between Participants and Company), cancellation or frustration of any thereof, or any limitation or cessation of Company's liability under any thereof (other than any limitation or cessation expressly provided for therein), including without limitation any invalidity, unenforceability or impaired liability resulting from Company's lack of capacity, power and/or authority to enter into the Agreements and/or to incur any or all of the obligations thereunder, or from the execution and delivery of any Agreement by any person acting for Company without or in excess of authority (except to the extent the same would limit or cease Company's liability under the Agreements); (d) any actual, purported or attempted sale, assignment or other transfer by Participants of any Agreement or of any of its rights, interests or obligations thereunder; (e) the taking or holding by Participants of a security interest, lien or other encumbrance in or on any property as security for any or all of the obligations of Company under the Agreements or any exchange, release, non- perfection, loss or alteration of, or any other dealing with, any such security; (f) the addition of any party as a guarantor or surety of all or any part of the obligations of Company under the Agreements; (g) any merger, amalgamation or consolidation of Company into or with any other entity, or any sale, lease, transfer or other disposition of any or all of Company's assets or any sale, transfer or other disposition of any or all of the shares of capital stock or other securities of Company to any other person or entity; (h) any change in the financial condition of Company or (as applicable) of any subsidiary, affiliate, partner or controlling shareholder thereof, or Company's entry into an assignment for the benefit of creditors, an arrangement or any other agreement or procedure for the restructuring of its liabilities, or Company's insolvency, bankruptcy, reorganization, dissolution, liquidation or any similar action by or occurrence with respect to Company. 5. Guarantor unconditionally waives, to the fullest extent permitted by law: (a) notice of any of the matters referred to in Section 4 hereof; (b) any right to the enforcement, assertion or exercise by Participants of any of their rights, powers or remedies under, against or with respect to (i) any of the Agreements, (ii) any other guarantor or surety, or (iii) any security for all or any part of the obligations of Company under the Agreements or obligations of Guarantor hereunder; (c) any requirement of diligence and any defense based on a claim of laches; (d) all defenses which may now or hereafter exist by virtue of any statute of limitations, or of any stay, valuation, exemption, moratorium or similar law, except the sole defense of full and indefeasible payment; (e) any requirement that Guarantor be joined as a party in any action or proceeding against Company to enforce any of the provisions of the Agreements; (f) any requirement that Participants mitigate or attempt to mitigate damages resulting from a default by Guarantor hereunder or from a default by Company under any of the Agreements; (g) acceptance of this Guaranty by Participants; and (h) all presentments, protests, notices of dishonor, demands for performance and any and all other demands upon and notices to Company, and any and all other formalities of any kind, the omission of or delay in performance of which might but for the provisions of this Section constitute legal or equitable grounds for relieving or discharging Guarantor in whole or in part from its irrevocable, absolute and continuing obligations hereunder, it being the intention of Guarantor that its obligations hereunder shall not be discharged except by payment and performance and then only to the extent thereof. 6. Guarantor waives any right to require Participants to (a) proceed against Company; (b) proceed against or exhaust any security held from Company; or (c) pursue any other remedy in Participants' power whatsoever. So long as any obligations remain outstanding under this Guaranty or the Agreements, Guarantor shall not exercise any rights against Company arising as a result of payment by Guarantor hereunder, by way of subrogation or otherwise, and will not prove any claim in competition with Participants or their affiliates in respect of any payment under the Agreements in bankruptcy or insolvency proceedings of any nature; Guarantor will not claim any set-off or counterclaim against Company in respect of any liability of Guarantor to Company and Guarantor waives any benefit of any right to participate in any collateral which may be held by Participants or any of their affiliates. Guarantor shall have no right of subrogation or reimbursement, contribution or other rights against Company. 7. If after receipt of any payment of, or the proceeds of any collateral for, all or any part of the obligations of Company under the Agreements, Participants are compelled to surrender or voluntarily surrender such payment or proceeds to any person because such payment or application of proceeds is or may be avoided, invalidated, recaptured, or set aside as a preference, fraudulent conveyance, impermissible setoff or for any other reason, whether or not such surrender is the result of (i) any judgment, decree or order of any court or administrative body having jurisdiction over Participants, or (ii) any settlement or compromise by Participants of any claim as to any of the foregoing with any person (including Company), then the obligations of Company under the Agreements, or part thereof affected, shall be reinstated and continue and this Guaranty shall be reinstated and continue in full force as to such obligations or part thereof as if such payment or proceeds had not been received, notwithstanding any previous cancellation of any instrument evidencing any such obligation or any previous instrument delivered to evidence the satisfaction thereof. The provisions of this Section shall survive the termination of this Guaranty and any satisfaction and discharge of Company by virtue of any payment, court order or any federal or state law until the full, final and irrevocable satisfaction of all of Company's obligations under the Agreements. 8. Any indebtedness of Company now or hereafter held by Guarantor is hereby subordinated to any indebtedness of Company to Participants; and such indebtedness of Company to Guarantor shall be collected, enforced and received by Guarantor as trustee for Participants and be paid over to Participants on account of the indebtedness of Company due and owing at any time to Participants but without reducing or affecting in any manner the liability of Guarantor under the other provisions of this Guaranty. 9. Guarantor represents and warrants to Participants, as an inducement to Participants to make the credit advances or sales of products on open account to Company, that: a. the execution, delivery and performance by Guarantor of this Guaranty (i) are within Guarantor's powers and have been duly authorized by all necessary action; (ii) do not contravene Guarantor's charter documents or any law or any material contractual restrictions binding on or affecting Guarantor or by which Guarantor's property may be affected; and (iii) do not require any authorization or approval or other action by, or any notice to or filing with, any public authority or any other person except such as have been obtained or made; b. this Guaranty constitutes the legal, valid and binding obligation of Guarantor, enforceable in accordance with its terms, except as the enforceability thereof may be subject to or limited by bankruptcy, insolvency, reorganization, arrangement, moratorium or other similar laws relating to or affecting the rights of creditors generally and by general principles of equity; and c. there is no action, suit or proceeding affecting Guarantor pending or threatened before any court, arbitrator, or public authority that may materially adversely affect Guarantor's ability to perform its obligations under this Guaranty, except as set forth in writing to the Participants and ISO New England Inc. prior to Participants' written authorization of this Guaranty. 10. Guarantor shall submit to Participants (i) a current credit rating agency report regarding Guarantor promptly upon the request of Participants, (ii) a copy of any Report on Form 8-K promptly after the filing by Guarantor of such report with the Securities and Exchange Commission, and (iii) a balance sheet, statement of income and such other financial statements of Guarantor as Participants shall reasonably request within ten (10) days after such statements are requested by Participants. Guarantor shall notify Participants in writing within ten (10) days after a material change in the financial status of Guarantor. For purposes of this section, a material change in financial status includes, but is not limited to, the following: (a) a downgrade to a below investment grade rating in the rating of Guarantor's senior long-term debt by a major rating agency; (b) the placement of Guarantor on credit watch with negative implication by a major credit rating agency if Guarantor's senior long-term debt does not have an investment grade rating; (c) Guarantor's bankruptcy or insolvency; (d) a report by Guarantor of a significant quarterly loss or decline in earnings; (e) the resignation of a key officer of Guarantor; and (e) the filing of a lawsuit that could materially adversely impact Guarantor's current or future financial results. Guarantor acknowledges that failure by it to provide the information required hereunder may result in Participants bringing proceedings to terminate Company from the New England Power Pool. 11. Guarantor agrees to pay on demand all reasonable attorneys' fees and all other costs and expenses which may be incurred by Participants in the enforcement of this Guaranty. No terms or provisions of this Guaranty may be changed, waived, revoked or amended without Participants' prior written consent. Should any provision of this Guaranty be determined by a court of competent jurisdiction to be unenforceable, all of the other provisions shall remain effective. This Guaranty embodies the entire agreement among the parties hereto with respect to the matters set forth herein, and supersedes all prior agreements among the parties with respect to the matters set forth herein. No course of prior dealing among the parties, no usage of trade, and no parol or extrinsic evidence of any nature shall be used to supplement, modify or vary any of the terms hereof. There are no conditions to the full effectiveness of this Guaranty. Participants may assign this Guaranty without in any way affecting Guarantor's liability under it, except that Guarantor shall be provided reasonable notice of any such assignment. This Guaranty shall inure to the benefit of Participants and their successors and assigns. This Guaranty is in addition to the guaranties of any other guarantors and any and all other guaranties of Company's indebtedness or liabilities to Participants. 12. This Guaranty shall be governed by the laws of the State of Connecticut, without regard to conflicts of laws principles. Guarantor hereby irrevocably submits to the jurisdiction of any Connecticut State or United States Federal court sitting in Connecticut over any action or proceeding arising out of or relating to this Guaranty or any of the Agreements, and Guarantor hereby irrevocably agrees that all claims in respect of such action or proceeding may be heard and determined in such Connecticut State or Federal court. Guarantor irrevocably consents to the service of any and all process in any such action or proceeding by the mailing of copies of such process to Guarantor at its address set forth below its signature. Guarantor agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Guarantor further waives any objection to venue in such State and any objection to an action or proceeding in such State on the basis of forum non conveniens. Guarantor further agrees that any action or proceeding brought against Participants shall be brought only in Connecticut State or United States Federal courts sitting in Connecticut. Nothing herein shall affect the right of Participants to bring any action or proceeding against the Guarantor or its property in the courts of any other jurisdictions. 13. GUARANTOR ACKNOWLEDGES THAT IT HAS BEEN ADVISED BY COUNSEL OF ITS CHOICE WITH RESPECT TO THIS GUARANTY AND THAT IT MAKES THE FOLLOWING WAIVERS KNOWINGLY AND VOLUNTARILY: a. IRREVOCABLY WAIVES TRIAL BY JURY IN ANY COURT AND IN ANY SUIT, ACTION OR PROCEEDING OR ANY MATTER ARISING IN CONNECTION WITH OR IN ANY WAY RELATED TO THE TRANSACTIONS CONTEMPLATED BY THIS GUARANTY, THE AGREEMENTS OR ANY DOCUMENTS RELATED THERETO (INCLUDING CONTRACT CLAIMS, TORT CLAIMS, BREACH OF DUTY CLAIMS, AND ALL OTHER COMMON LAW OR STATUTORY CLAIMS) AND THE ENFORCEMENT OF ANY OF PARTICIPANTS' RIGHTS AND REMEDIES; AND b. GUARANTOR EXPRESSLY ACKNOWLEDGES THAT THE OBLIGATIONS GUARANTEED HEREBY ARE PART OF A COMMERCIAL TRANSACTION AS SUCH TERM IS USED AND DEFINED IN CHAPTER 903a OF THE CONNECTICUT GENERAL STATUTES AND VOLUNTARILY AND KNOWINGLY WAIVES ANY AND ALL RIGHTS WHICH ARE OR MAY BE CONFERRED UPON IT UNDER CHAPTER 903a OF SAID STATUTES (OR ANY OTHER STATUTE AFFECTING PREJUDGMENT REMEDIES) TO ANY NOTICE OR HEARING OR PRIOR COURT ORDER OR THE POSTING OF ANY BOND PRIOR TO ANY PREJUDGMENT REMEDY WHICH PARTICIPANTS MAY USE. 14. Any demand, notice, request, instruction or other communication to be given hereunder by any party to another party shall be in writing and delivered personally, by nationally recognized overnight courier, by certified mail, postage prepaid and return receipt requested, by telegram, or by telecopier, as follows: If to Guarantor, at: If to Participants, at: Communications given by personal delivery or mail shall be effective upon actual receipt. Communications given by telegram or telecopier shall be effective upon actual receipt during the recipient's normal business hours, or at the beginning of the next business day after receipt if not received during the recipient's normal business hours. All communications by telegram or telecopier shall be confirmed promptly in writing by certified mail or personal delivery. Any party may change any address to which communications are to be given by giving notice as provided above of such change of address. IN WITNESS WHEREOF, the undersigned Guarantor has executed this Guaranty as of this day of [month], 199_. [GUARANTOR] By: Title: Corporate Officer Address: ATTACHMENT M Financial Assurance Policy for NEPOOL Non-Participant Transmission Customers This Financial Assurance Policy for Transmission Customers (FN1) that are Non-Participants ("Policy") shall become effective on January 1, 1999 (the "Policy Effective Date"). The purpose of this Policy is (i) to establish a financial assurance policy for Non-Participant Transmission Customers pursuant to Section 11 of the Restated NEPOOL Open Access Transmission Tariff (the "Tariff") that includes commercially reasonable credit review procedures to assess the financial ability of each Non-Participant applicant for service ("Applicant") under the Tariff to pay for service transactions under the Tariff and under the ISO New England Inc. Tariff for Transmission Dispatch and Power Administration Services (the "ISO Tariff"), (ii) to set forth requirements for alternative forms of security that will be deemed acceptable to NEPOOL and consistent with commercial practices established by the Uniform Commercial Code that protects the Participants against the risk of non-payment by Non-Participant Transmission Customers, (iii) to set forth the conditions under which NEPOOL will conduct business so as to avoid the possibility of failure of payment for services rendered to Non-Participant Transmission Customers under the Tariff and the ISO Tariff, and (iv) to collect amounts past due, make up shortfalls in payments, and terminate service to defaulting Non-Participant Transmission Customers. - ------- (FN1) Capitalized terms used but not defined in this Policy are intended to have the meanings given to such terms in Section 1 of the Restated NEPOOL Agreement or Section 1 of the Restated NEPOOL Open Access Transmission Tariff (the "Tariff"), as amended. In accordance with Section 11 of the Tariff, NEPOOL requires the following procedures and requirements to apply to all Applicants and Non-Participant Transmission Customers. Generally, any Applicant or Non-Participant Transmission Customer that does not have an investment grade rating by either Standard & Poor's, Moody's, Duff & Phelps, or Fitch (or in the case of Applicants and Non-Participant Transmission Customers that are not rated themselves, any Applicant or Non-Participant Transmission Customer that does not have outstanding debt with such a rating) will be required to provide financial assurances, as described in detail below. (FN2) - ------ (FN2) The System Operator will act as NEPOOL's agent in managing and enforcing this Policy with the exception of termination of membership issues, which are specifically reserved to the NEPOOL Participants and will be addressed by the NEPOOL Executive Committee Membership Subcommittee, subject to appeal to the Management Committee. Accordingly, all financial information required pursuant to this Policy is to be provided to the System Operator, which will keep all such information confidential in accordance with the provisions of Section 2 of NEPOOL Criteria, Rules and Standards No. 45. GENERAL REQUIREMENTS Each Applicant or Non-Participant Transmission Customer must comply with the following general requirements. Proof of Financial Viability Each Applicant must with its application for service submit proof of financial viability, as described below, satisfying NEPOOL requirements to demonstrate the Applicant's ability to meet its obligations, or must provide, prior to NEPOOL's filing of a Service Agreement for the Applicant and provision of service to the Applicant under the Tariff, financial assurance in the form of a cash deposit, letter of credit or performance bond as set forth below. An Applicant that chooses to provide a cash deposit, letter of credit or performance bond will not be required to provide financial information to NEPOOL. Generally, each Applicant must submit a current rating agency report, which report must indicate an investment grade rating by either Standard & Poor's, Moody's, Duff & Phelps, or Fitch for the Applicant or, if the Applicant itself is not rated, for the Applicant's outstanding rated debt, in order for NEPOOL to file a Service Agreement for the Applicant and provide service to the Applicant under the Tariff without the Applicant being required to furnish additional financial assurances as described below. Current Non-Participant Transmission Customers that have not already provided to NEPOOL financial assurances consistent with the requirements of this Policy must also provide a current rating agency report by the Policy Effective Date, as well as any of the financial statements and information set forth below if and as requested by NEPOOL within ten (10) days of such request. Those Non-Participant Transmission Customers that do not satisfy the rating requirement as set forth above must provide instead on the Policy Effective Date one form of the financial assurances set forth below. A Non- Participant Transmission Customer's failure to meet these requirements may result in termination of service by NEPOOL in accordance with the procedure set forth for payment defaults in Section 8.4 of the Tariff. Financial Statements Each Applicant must submit, if and as requested by NEPOOL and within ten (10) days of such request, audited financial statements for at least the immediately preceding three years, or the period of its existence, if shorter, including, but not limited to, the following information: Balance Sheets Income Statements Statements of Cash Flows Notes to Financial Statements Additionally, the following information for at least the immediately preceding three years, if available, must be submitted if and as requested by NEPOOL and within ten (10) days of such request: Annual and Quarterly Reports 10-K, 10-Q and 8-K Reports Where the above financial statements are available on the Internet, the Applicant may provide instead a letter to NEPOOL stating where such statements may be located and retrieved by NEPOOL. Each Applicant may also be required to provide at least one bank reference and three (3) utility credit references. In those cases where an Applicant does not have three (3) utility credit references, three (3) trade payable vendor references may be substituted. Each Applicant may also be required to include information as to any known or anticipated material lawsuits, as well as any prior bankruptcy declarations by the Applicant, or by its predecessor(s), if any. In the case of certain Applicants, some of the above financial submittals may not be applicable, and alternate requirements may be specified by NEPOOL. Ongoing Financial Review Each Non-Participant Transmission Customer that has not provided a cash deposit, letter of credit, performance bond, or corporate guaranty must submit its current rating agency report promptly upon the request of NEPOOL, and 8-K Reports promptly upon their issuance. In addition, each Non-Participant Transmission Customer that has not provided a cash deposit, letter of credit, performance bond or corporate guaranty is responsible for informing NEPOOL in writing within ten (10) business days of any material change in its financial status. A material change in financial status includes, but is not limited to, the following: a downgrade to a below investment grade rating of senior long term debt by a major rating agency, being placed on credit watch with negative implication by a major rating agency if senior long term debt does not have an investment grade rating, a bankruptcy filing, insolvency, a report of a significant quarterly loss or decline of earnings, the resignation of key officer(s), and/or the filing of a material lawsuit that could materially adversely impact current or future financial results. A Non-Participant Transmission Customer's failure to provide this information as required may result in termination of service by NEPOOL in accordance with the procedure set forth in Section 8.4 of the Tariff. If there is a material adverse change in the financial condition of the Non- Participant Transmission Customer that has not provided a cash deposit, letter of credit, performance bond or corporate guaranty, NEPOOL may require such Non-Participant Transmission Customer to provide one of the forms of other financial assurances set forth below. If the Non-Participant Transmission Customer fails to do so, NEPOOL may terminate service in accordance with the procedure set forth for payment defaults in Section 8.4 of the Tariff. OTHER FINANCIAL ASSURANCES Applicants or Non-Participant Transmission Customers that do not satisfy the rating requirement or NEPOOL's credit review process must submit instead one of the following additional financial assurances, depending on the specific aspects of the transactions they anticipate engaging in as Non-Participant Transmission Customers. In general, Non-Participant Transmission Customers must provide additional financial assurance in the following amounts, based on their average or expected monthly charges for service under the Tariff, including amounts owed to ISO New England Inc. under the ISO Tariff (collectively the "NEPOOL Charges"): Monthly NEPOOL Charges Financial Assurance Requirement $0 - $15,000 0 months' NEPOOL Charges $15,001 - $30,000 1 month's NEPOOL Charges $30,001 - $50,000 2 months' NEPOOL Charges $50,001 or more 31/2 months' NEPOOL Charges The three and one-half months is based on the time required for a FERC filing made by NEPOOL to suspend service to be effective. Therefore, a Non-Participant Transmission Customer with $32,000 in monthly NEPOOL Charges that does not satisfy the rating requirement or NEPOOL credit review process must provide additional financial assurances in the amount of $64,000 to NEPOOL. In the case of new Non-Participant Transmission Customers, the Financial Assurance Requirement will be based on estimated monthly NEPOOL Charges, which estimate NEPOOL has the right to adjust in light of subsequent experience as to actual monthly NEPOOL Charges. In no event will the Financial Assurance Requirement exceed the anticipated charge for the service requested by the Non-Participant Transmission Customer. Cash Deposit A cash deposit for the full value of the Financial Assurance Requirement based on actual or anticipated NEPOOL Charges, as determined by NEPOOL, provides an acceptable form of financial assurance to NEPOOL. A cash deposit greater than or equal to one month's NEPOOL Charges of a Non-Participant Transmission Customer shall also serve as that Non-Participant Transmission Customer's deposit under Sections 31.3 and 41.2 of the Tariff. If it is necessary to use all or a portion of the deposit to pay the Non- Participant Transmission Customer's obligation, the deposit must be promptly replenished to the required level; otherwise, termination of service proceedings may be initiated. In the event that actual NEPOOL Charges exceed those anticipated, the anticipated charges will be increased accordingly and the Non-Participant Transmission Customer must augment its cash deposit to reach the required level. The cash deposit will be invested by NEPOOL in investments as may be designated by the Non-Participant Transmission Customer in direct obligations of the United States or its agencies and interest earned will be paid to the Non-Participant Transmission Customer. NEPOOL may sell or otherwise liquidate such investments at its discretion to meet the Non-Participant Transmission Customer's obligations to NEPOOL. The requirement to continue the deposit may be reviewed by NEPOOL after one year. Consideration will be given to replacing the cash deposit with a corporate guaranty if certain conditions are met, as discussed below in the Corporate Guaranty section. Letter of Credit An irrevocable standby letter of credit for the full value of the Financial Assurance Requirement based on actual or anticipated NEPOOL Charges, as determined by NEPOOL, provides an acceptable form of financial assurance to NEPOOL. The letter of credit will renew automatically unless the issuing bank provides notice to NEPOOL at least ninety (90) days prior to the letter of credit's expiration of the bank's decision not to renew the letter of credit. If the letter of credit amount falls below the required level because of a drawing, it must be replenished immediately; otherwise, termination of service proceedings may be initiated by NEPOOL. If actual NEPOOL Charges exceed those anticipated, the Non-Participant Transmission Customer must obtain a substitute letter of credit that equals the actual NEPOOL Charges. The form, substance, and provider of the letter of credit must all be acceptable to NEPOOL. The letter of credit should clearly state the full names of the "Issuer," "Account Party" and "Beneficiary" (NEPOOL), the dollar amount available for drawings, and should include a statement required on the drawing certificate and other terms and conditions that should apply. It should also specify that funds will be disbursed, in accordance with the instructions, within one (1) business day after due presentation of the drawing certificate. The bank issuing the letter of credit must have a minimum corporate debt rating of an "A-" by Standard & Poor's, or "A3" by Moody's, or "A-" by Duff & Phelps, or "A-" by Fitch, or an equivalent short term debt rating by one of these agencies. Please refer to Attachment 1, which provides an example of a generally acceptable sample "clean" letter of credit. All costs associated with obtaining financial security and meeting the Policy provisions are the responsibility of the Applicant or Non-Participant Transmission Customer. The requirement to continue to provide a letter of credit may be reviewed by NEPOOL after one year. Consideration will be given to replacing the letter of credit with a corporate guaranty if certain conditions are met, as discussed below in the Corporate Guaranty section. Performance Bond A performance bond complying with the requirements set forth herein provides an acceptable form of financial assurance to NEPOOL. The penal sum of such performance bond shall be in an amount equal to the full value of the Financial Assurance Requirement based on actual or anticipated NEPOOL Charges, as determined by NEPOOL, and shall automatically be adjusted to reflect any adjustment in such Financial Assurance Requirement. The bond shall permit suit thereunder until two years after the last date that service is provided to the Non-Participant Transmission Customer under the Tariff. If the amount of penal sum of the performance bond available to NEPOOL falls below the required level because of a payment thereon, it must be increased to the required level immediately; otherwise, termination of service proceedings may be initiated by NEPOOL. If actual NEPOOL Charges exceed those anticipated, the Non-Participant Transmission Customer must either cause the penal sum of such performance bond to be increased accordingly or must obtain a substitute performance bond in the appropriate amount. The form, substance and provider of the performance bond must be acceptable to NEPOOL. The performance bond should clearly state the full names of the "Principal," the "Surety" and the "Obligee" (NEPOOL) and the penal sum and should include a clear statement that the surety will promptly and faithfully perform the Non-Participant Transmission Customer's obligations to NEPOOL if the Non-Participant Transmission Customer fails to do so. The insurance company issuing the performance bond must be rated "A" or better by A.M. Best & Co. Please refer to Attachment 2, which provides an example of a generally acceptable sample performance bond. All costs associated with obtaining financial security and meeting the Policy provisions, including without limitation the cost of the premiums for such performance bond, are the responsibility of the Applicant or Non-Participant Transmission Customer. The requirement to continue to provide a performance bond may be reviewed by NEPOOL after one year. Consideration will given to replacing the performance bond with a corporate guaranty if certain conditions are met, as discussed below in the Corporate Guaranty section. Weekly Payments A Non-Participant Transmission Customer that does not satisfy the rating requirement may request that, in lieu of providing one of the additional financial assurances set forth above, a weekly billing schedule be implemented for it. NEPOOL may, in its discretion, agree to such a request; provided, however, that any weekly billing arrangement will terminate no more than six months after the date on which such arrangement begins unless the Non-Participant Transmission Customer requests an extension of such arrangement and demonstrates to NEPOOL's satisfaction in its sole discretion that the termination of such arrangement and compliance with the other provisions of this Policy (including providing another form of financial assurance, if required) will impose a substantial hardship on the Non- Participant Transmission Customer. Such demonstration of a substantial hardship shall be made every six months after the initial demonstration, and a Non-Participant Transmission Customer's weekly billing arrangement will be terminated if it fails to demonstrate to NEPOOL's satisfaction in its sole discretion at any such six month interval that compliance with the other provisions of this Policy will impose a substantial hardship on it. If NEPOOL agrees to implement a weekly billing schedule for a Non-Participant Transmission Customer, the Non-Participant Transmission Customer shall be billed weekly in arrears on an estimated basis for all amounts owed to NEPOOL and the System Operator for the week, with an adjustment for each month as part of the regular NEPOOL monthly billing to reflect any under or over collection for the month. The Non-Participant Transmission Customer shall be obligated to pay each such weekly bill within five business days after it is received. The Non-Participant Transmission Customer shall pay with respect to each weekly bill an administrative fee, determined by the System Operator, to reimburse the System Operator for the costs it incurs as a result of that Non-Participant Transmission Customer's weekly billing arrangement. If a weekly billing schedule is implemented for a Non-Participant Transmission Customer in lieu of requiring the Non-Participant Transmission Customer to provide an additional financial assurance, the Non-Participant Transmission Customer may be required to provide an additional financial assurance at any time if the Non-Participant Transmission Customer fails to pay when due any weekly bill or, in its sole discretion, termination of service proceedings may be initiated by NEPOOL. In addition, upon the termination of a Non-Participant Transmission Customer's weekly billing arrangement, the Non-Participant Transmission Customer shall either satisfy the rating requirement set forth herein or provide one of the other forms of financial assurance set forth herein. Use of Transaction Setoffs Under certain conditions, NEPOOL may be involved in other transactions with a Non-Participant Transmission Customer in which NEPOOL is the buyer. In this event, the amount of the prepayment, cash deposit, performance bond or letter of credit required hereunder may be reduced ("setoff") by an amount equal to NEPOOL's unpaid balance or expected billing under the other transaction. The terms and the amount of the setoff must be approved by the System Operator. The System Operator is responsible for monitoring the status of the setoff and ensuring that an adequate financial assurance balance is maintained at all times until the transaction is settled. Corporate Guaranty An irrevocable corporate guaranty obtained from a Non-Participant Transmission Customer's affiliated company ("Guarantor") for the full value of the Financial Assurance Requirement based on actual or anticipated NEPOOL Charges, as determined by NEPOOL, may provide an acceptable form of financial assurance to NEPOOL. If actual NEPOOL Charges exceed those anticipated, the Non-Participant Transmission Customer must provide a substitute corporate guaranty that equals the actual NEPOOL Charges. A Non-Participant Transmission Customer for which a letter of credit, performance bond or cash deposit was initially required may have the opportunity to substitute a corporate guaranty if the following conditions are met: 1. NEPOOL determines that the Non-Participant Transmission Customer has satisfactorily met its payment obligations in NEPOOL for at least one year, which one-year period may in whole or in part pre-date the Policy Effective Date; 2. NEPOOL determines that the financial condition of the Guarantor meets the requirements of this Policy; and 3. The form and substance of the corporate guaranty are acceptable to NEPOOL. Upon NEPOOL's written authorization, the Non-Participant Transmission Customer may substitute a corporate guaranty that is issued by the Guarantor for a cash deposit, bank letter of credit or performance bond when it has satisfied the conditions stipulated above. The corporate guaranty is considered to be a lesser form of financial assurance than a cash deposit, letter of credit or performance bond, and therefore is allowed as an acceptable form of financial assurance only to those Non-Participant Transmission Customers that have satisfied their payment obligations to NEPOOL in a timely manner for at least one year. The corporate guaranty may only be used if the Non-Participant Transmission Customer is affiliated with a Guarantor that has greater financial assets, a strong balance sheet and income statements, and at minimum an investment grade rating by either Standard & Poor's, Moody's, Duff & Phelps, or Fitch. The corporate guaranty should clearly state the identities of the "Guarantor," "Beneficiary" and "Obligor," and the relationship between the Guarantor and the Non-Participant Transmission Customer Obligor. The corporate guaranty must be duly authorized by the Guarantor, must be signed by an officer of the Guarantor, and must be furnished with either an opinion satisfactory to NEPOOL of the Guarantor's counsel with respect to the enforceability of the guaranty or accompanied by a certificate of corporate guarantee that includes a seal of the corporation with the signature of the corporate secretary. Additionally, adequate documentation regarding the signature authority of the person signing the corporate guaranty must be provided with the corporate guaranty. A corporate guaranty must also obligate the Guarantor to submit a current rating agency report promptly upon the request of NEPOOL, to submit 8-K Reports promptly upon their issuance, to submit financial reports if and as requested by NEPOOL within ten (10) days of such request, and to inform NEPOOL in writing within ten (10) business days of any material change in its financial status. A material change in financial status includes, but is not limited to, the following: a downgrade to a below investment grade rating of senior long term debt by a major rating agency, being placed on credit watch with negative implication by a major rating agency if senior long term debt does not have an investment grade rating, a bankruptcy filing, insolvency, a report of a significant quarterly loss or decline of earnings, the resignation of key officer(s), and/or the filing of a material lawsuit that could materially adversely impact current or future financial results. A Guarantor's failure to provide this information may result in proceedings by NEPOOL to terminate service to the Non-Participant Transmission Customer Obligor. If there is a material adverse change in the financial condition of the Guarantor, NEPOOL may require the Non-Participant Transmission Customer Obligor to provide another form of financial assurance, either a cash deposit or a letter of credit or a performance bond. Non-payment of Amounts Due If a Non-Participant Transmission Customer does not pay amounts billed when due and as a result a letter of credit or cash deposit is drawn down or a performance bond is paid on, then the Non-Participant Transmission Customer must immediately replenish the letter of credit or cash deposit to the required amount or cause the penal sum of the performance bond to be increased to equal the required amount plus all amounts paid thereunder. If a Non-Participant Transmission Customer fails to do so, NEPOOL may initiate termination of service proceedings against the Non-Participant Transmission Customer in accordance with the procedure for payment defaults set forth in Section 8.4 of the Tariff. In order to encourage prompt payment of NEPOOL Charges by Non-Participant Transmission Customers, if a Non-Participant Transmission Customer is delinquent in paying on time its NEPOOL Charges, the Non-Participant Transmission Customer shall pay interest on any unpaid amount as provided in Section 8.3 of the Tariff. ATTACHMENT 1 SAMPLE LETTER OF CREDIT [DATE PROVIDED] IRREVOCABLE STANDBY LETTER OF CREDIT NO. [EXPIRATION DATE] AT OUR COUNTERS [unless an evergreen l/c is obtained] WE DO HEREBY ISSUE AN IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT BY ORDER OF AND FOR THE ACCOUNT OF ON BEHALF OF [NON- PARTICIPANT TRANSMISSION CUSTOMER] ("ACCOUNT PARTY") IN FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") IN AN AMOUNT NOT EXCEEDING US$ .00 (UNITED STATES DOLLARS AND 00/100) AGAINST PRESENTATION TO US OF A DRAWING CERTIFICATE SIGNED BY A PURPORTED OFFICER OR AUTHORIZED AGENT OF NEPOOL AND DATED THE DATE OF PRESENTATION CONTAINING THE FOLLOWING STATEMENT: "THE UNDERSIGNED HEREBY CERTIFIES TO [BANK] ("BANK"), WITH REFERENCE TO IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT NO. ISSUED BY [BANK] IN FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") THAT [NON-PARTICIPANT TRANSMISSION CUSTOMER] HAS FAILED TO PAY AMOUNTS DUE UNDER THE RESTATED NEPOOL OPEN ACCESS TRANSMISSION TARIFF OR THE ISO NEW ENGLAND INC. TARIFF FOR TRANSMISSION DISPATCH AND POWER ADMINISTRATION SERVICES, AND THUS NEPOOL IS DRAWING UPON THE LETTER OF CREDIT IN AN AMOUNT EQUAL TO $ ." IF PRESENTATION OF ANY DRAWING CERTIFICATE IS MADE ON A BUSINESS DAY AND SUCH PRESENTATION IS MADE AT OUR COUNTERS ON OR BEFORE 10:00 A.M. TIME, WE SHALL SATISFY SUCH DRAWING REQUEST ON THE SAME BUSINESS DAY. IF THE DRAWING CERTIFICATE IS RECEIVED AT OUR COUNTERS AFTER 10:00 A.M. TIME, WE WILL SATISFY SUCH DRAWING REQUEST ON THE NEXT BUSINESS DAY, FOR THE PURPOSES OF THIS SECTION, A BUSINESS DAY MEANS A DAY, OTHER THAN A SATURDAY OR SUNDAY, ON WHICH COMMERCIAL BANKS ARE NOT AUTHORIZED OR REQUIRED TO BE CLOSED IN NEW YORK, NEW YORK. DISBURSEMENTS SHALL BE IN ACCORDANCE WITH THE INSTRUCTIONS OF NEPOOL. THE FOLLOWING TERMS AND CONDITIONS APPLY: THIS LETTER OF CREDIT SHALL EXPIRE AT THE CLOSE OF BUSINESS [DATE]. WE WILL PROVIDE NOTICE TO NEPOOL AT LEAST 90 DAYS PRIOR TO SUCH DATE IF THIS LETTER OF CREDIT WILL NOT BE RENEWED AS OF SUCH DATE [or: THIS LETTER OF CREDIT SHALL EXPIRE ONLY UPON THE FOLLOWING CONDITIONS: (1) WHEN FULL PAYMENT HAS BEEN RECEIVED BY NEPOOL FROM [NON-PARTICIPANT TRANSMISSION CUSTOMER] AND (2) NEPOOL HAS PROVIDED A WRITTEN RELEASE TO THIS BANK .] THE AMOUNT WHICH MAY BE DRAWN BY YOU UNDER THIS LETTER OF CREDIT SHALL BE AUTOMATICALLY REDUCED BY THE AMOUNT OF ANY UNREIMBURSED DRAWINGS HEREUNDER AT OUR COUNTERS. ANY NUMBER OF PARTIAL DRAWINGS ARE PERMITTED FROM TIME TO TIME HEREUNDER. ALL COMMISSIONS AND CHARGES WILL BE BORNE BY THE ACCOUNT PARTY. THIS LETTER OF CREDIT IS NOT TRANSFERABLE OR ASSIGNABLE. THIS LETTER OF CREDIT DOES NOT INCORPORATE AND SHALL NOT BE DEEMED MODIFIED, AMENDED OR AMPLIFIED BY REFERENCE TO ANY DOCUMENT, INSTRUMENT OR AGREEMENT (A) THAT IS REFERRED TO HEREIN (EXCEPT FOR THE UCP, AS DEFINED BELOW) OR (B) IN WHICH THIS LETTER OF CREDIT IS REFERRED TO OR TO WHICH THIS LETTER OF CREDIT RELATES. THIS LETTER OF CREDIT SHALL BE GOVERNED BY THE UNIFORM CUSTOMS AND PRACTICE FOR DOCUMENTARY CREDITS, 1993 REVISION, INTERNATIONAL CHAMBER OF COMMERCE PUBLICATION NO. 500 (THE "UCP"), EXCEPT TO THE EXTENT THAT TERMS HEREOF ARE INCONSISTENT WITH THE PROVISIONS OF THE UCP, INCLUDING BUT NOT LIMITED TO ARTICLES 13(b) AND 17 OF THE UCP, IN WHICH CASE THE TERMS OF THE LETTER OF CREDIT SHALL GOVERN. THIS LETTER OF CREDIT MAY NOT BE AMENDED, CHANGED OR MODIFIED WITHOUT THE EXPRESS WRITTEN CONSENT OF NEPOOL AND US. WE HEREBY ENGAGE WITH YOU THAT DOCUMENTS DRAWN UNDER AND IN COMPLIANCE WITH THE TERMS OF THIS LETTER OF CREDIT SHALL BE DULY HONORED UPON PRESENTATION AS SPECIFIED. PRESENTATION OF ANY DRAWING CERTIFICATE UNDER THIS STANDBY LETTER OF CREDIT MAY BE SENT TO US BY COURIER, CERTIFIED MAIL, REGISTERED MAIL, TELEGRAM, TELEX TO THE ADDRESS SET FORTH BELOW, OR SUCH OTHER ADDRESS AS MAY HEREAFTER BE FURNISHED BY US. OTHER NOTICES CONCERNING THIS STANDBY LETTER OF CREDIT MAY BE SENT BY FACSIMILE OR SIMILAR COMMUNICATIONS FACILITY TO THE RESPECTIVE ADDRESSES SET FORTH BELOW. ALL SUCH NOTICES AND COMMUNICATIONS SHALL BE EFFECTIVE WHEN ACTUALLY RECEIVED BY THE INTENDED RECIPIENT PARTY. IF TO THE BENEFICIARY OF THIS LETTER OF CREDIT: IF TO THE ACCOUNT PARTY: IF TO US: [signature] [signature] ATTACHMENT 2 SAMPLE PERFORMANCE BOND [Insurance Company] Bond No. KNOW ALL MEN BY THESE PRESENTS, That the undersigned [Non-Participant Transmission Customer], of [Non-Participant Transmission Customer's address] hereinafter referred to as the Principal, and [insurance company], a corporation organized and existing under the laws of the State of [insurance company's state of incorporation], as Surety, are held and firmly bound unto the Participants in the New England Power Pool as obligees, hereinafter referred to collectively as the Obligee, in the sum of , lawful money of the United States of America (which sum shall automatically be adjusted to reflect any adjustment in the Financial Assurance Requirement applicable to the Principal under the New England Power Pool's Financial Assurance Policy for NEPOOL Non-Participant Transmission Customers, as in effect from time to time) for the payment of which sum, well and truly to be made, we bind ourselves, our executors, administrators, successors, and assigns, jointly and severally, firmly by these presents. WHEREAS, the Principal has entered into agreements for the purchase and sale of electric services under the Restated NEPOOL Open Access Transmission Tariff and the ISO New England Inc. Tariff for Transmission Dispatch and Power Administration Services, each as amended from time to time (collectively referred to as the "Agreements"), and in strict accordance with their respective terms. NOW, THEREFORE, the condition of this obligation is such, that if the Principal shall promptly and faithfully make the payments required by, and comply with terms of, the Agreements which have been or may hereafter be in force and shall save and keep harmless the Obligee from all loss or damage which it may sustain or for which it may become liable on account of the issuance of said Agreements to the Principal, then this obligation shall be void; otherwise, it shall remain in full force and effect. Upon notice from ISO New England Inc. of nonpayment by the Principal, Surety will pay to ISO New England Inc., as agent for the Obligee, the amounts owed by the Principal under the Agreements. The Surety hereby waives notice of any alteration or extension of time made by the Obligee. Any suit on this bond must be instituted before the expiration of two (2) years from the date on which the Principal's obligations under the Agreements expires. SIGNED, SEALED AND DATED this day of , 19 . [Seal] [Non-Participant Transmission Customer] Principal By: [Seal] [Insurance Company] Surety By: ATTACHMENT 3 CORPORATE GUARANTY For and in consideration of the credit advance or sale of products on open account by the New England Power Pool Participants from time to time ("Participants") to [Non-Participant Transmission Customer] ("Company"), the undersigned guarantor, ("Guarantor"), the [subsidiary/affiliate] of Company, hereby unconditionally and irrevocably guarantees the prompt and complete payment of all amounts that Company now or hereafter owes to Participants under the Restated NEPOOL Open Access Transmission Tariff (the "Tariff") and the ISO New England Inc. Tariff for Transmission Dispatch and Power Administration Services (the "ISO Tariff"), and performance by Company of any other agreements, whether now existing or hereafter arising, between Company and Participants, as amended from time to time (collectively referred to as the "Agreements"), in strict accordance with their respective terms. 1. If Company does not perform its obligations in strict accordance with the Agreements, Guarantor shall immediately pay all amounts now or hereafter due thereunder (including, without limitation, all principal, interest, and fees) and otherwise proceed to complete the same and satisfy all of Company's obligations under the Agreements. This Guaranty may be satisfied by Guarantor paying and/or performing (as appropriate) Company's obligations or by Guarantor causing Company's obligations to be paid or performed; provided, however, that Guarantor shall at all times remain fully responsible and liable for its obligations hereunder notwithstanding any such payment or performance (or failure thereof) by any third party. Participants will undertake commercially reasonable efforts to notify Guarantor of a failure by Company to make a payment or perform its obligations under the Agreements; provided, however, that failure by Participants to so notify Guarantor shall not defeat, limit or otherwise affect the rights and obligations of Participants, Company or Guarantor. Subject to the terms and conditions set forth herein, Guarantor's obligations hereunder shall not exceed the complete payment of all amounts that Company now or hereafter owes to Participants under the Agreements and performance by Company of the Agreements in strict accordance with their respective terms. 2. This Guaranty is an absolute, unconditional and continuing guaranty of the full and punctual payment and performance by Company of each of its obligations under the Agreements, and not of collectibility only, and is in no way conditioned upon any requirement that Participants first attempt to collect payment from Company or any other guarantor or surety or resort to any security or other means of obtaining payment of all or any part of Company's obligations or upon any other contingency. This is a continuing guaranty and shall be binding upon Guarantor until the full, final and irrevocable payment and performance of all of Company's obligations under the Agreements, regardless of (i) how long after the date hereof any part of the obligations under the Agreements is incurred by Company and (ii) the amount of the obligations under the Agreements at any time outstanding. This Guaranty may be enforced by Participants from time to time and as often as occasion for such enforcement may arise. 3. The obligations hereunder are independent of the obligations of Company, and a separate action or actions may be brought and prosecuted against Guarantor whether action is brought against Company or whether Company be joined in any such action or actions. Guarantor's liability under this Guaranty is not conditioned or contingent upon genuineness, validity, regularity or enforceability of the Agreements. 4. Guarantor authorizes Participants, without notice or demand and without affecting its liability hereunder, from time to time to (a) renew, extend, or otherwise change the terms of the Agreements or any part thereof, (b) take and hold security for the payment of the Agreements, and exchange, enforce, waive and release any such security; and (c) apply such security and direct the order or manner of sale thereof as Participants in their sole discretion may determine. The obligations and liabilities of Guarantor hereunder shall be absolute and unconditional, shall not be subject to any counterclaim, set-off, deduction or defense based upon any claim Guarantor may have against Company, any other guarantor, or any other person or entity, and shall remain in full force and effect until all of the obligations hereunder and under the Agreements have been fully satisfied, without regard to, or release or discharge by, any event, circumstance or condition (whether or not Guarantor shall have knowledge or notice thereof) which but for the provisions of this Section might constitute a legal or equitable defense or discharge of a guarantor or surety or which might in any way limit recourse against Guarantor, including without limitation: (a) any amendment or modification of, or supplement to, the terms of the Agreements; (b) any waiver, consent or indulgence by Participants, or any exercise or non-exercise by Participants of any right, power or remedy, under or in respect of this Guaranty or the Agreements (whether or not Guarantor or Company has or have notice or knowledge of any such action or inaction); (c) the invalidity or unenforceability, in whole or in part, of the Agreements, or the termination (except pursuant to its terms or by written agreement between Participants and Company), cancellation or frustration of any thereof, or any limitation or cessation of Company's liability under any thereof (other than any limitation or cessation expressly provided for therein), including without limitation any invalidity, unenforceability or impaired liability resulting from Company's lack of capacity, power and/or authority to enter into the Agreements and/or to incur any or all of the obligations thereunder, or from the execution and delivery of any Agreement by any person acting for Company without or in excess of authority (except to the extent the same would limit or cease Company's liability under the Agreements); (d) any actual, purported or attempted sale, assignment or other transfer by Participants of any Agreement or of any of its rights, interests or obligations thereunder; (e) the taking or holding by Participants of a security interest, lien or other encumbrance in or on any property as security for any or all of the obligations of Company under the Agreements or any exchange, release, non-perfection, loss or alteration of, or any other dealing with, any such security; (f) the addition of any party as a guarantor or surety of all or any part of the obligations of Company under the Agreements; (g) any merger, amalgamation or consolidation of Company into or with any other entity, or any sale, lease, transfer or other disposition of any or all of Company's assets or any sale, transfer or other disposition of any or all of the shares of capital stock or other securities of Company to any other person or entity; (h) any change in the financial condition of Company or (as applicable) of any subsidiary, affiliate, partner or controlling shareholder thereof, or Company's entry into an assignment for the benefit of creditors, an arrangement or any other agreement or procedure for the restructuring of its liabilities, or Company's insolvency, bankruptcy, reorganization, dissolution, liquidation or any similar action by or occurrence with respect to Company. 5. Guarantor unconditionally waives, to the fullest extent permitted by law: (a) notice of any of the matters referred to in Section 4 hereof; (b) any right to the enforcement, assertion or exercise by Participants of any of their rights, powers or remedies under, against or with respect to (i) any of the Agreements, (ii) any other guarantor or surety, or (iii) any security for all or any part of the obligations of Company under the Agreements or obligations of Guarantor hereunder; (c) any requirement of diligence and any defense based on a claim of laches; (d) all defenses which may now or hereafter exist by virtue of any statute of limitations, or of any stay, valuation, exemption, moratorium or similar law, except the sole defense of full and indefeasible payment; (e) any requirement that Guarantor be joined as a party in any action or proceeding against Company to enforce any of the provisions of the Agreements; (f) any requirement that Participants mitigate or attempt to mitigate damages resulting from a default by Guarantor hereunder or from a default by Company under any of the Agreements; (g) acceptance of this Guaranty by Participants; and (h) all presentments, protests, notices of dishonor, demands for performance and any and all other demands upon and notices to Company, and any and all other formalities of any kind, the omission of or delay in performance of which might but for the provisions of this Section constitute legal or equitable grounds for relieving or discharging Guarantor in whole or in part from its irrevocable, absolute and continuing obligations hereunder, it being the intention of Guarantor that its obligations hereunder shall not be discharged except by payment and performance and then only to the extent thereof. 6. Guarantor waives any right to require Participants to (a) proceed against Company; (b) proceed against or exhaust any security held from Company; or (c) pursue any other remedy in Participants' power whatsoever. So long as any obligations remain outstanding under this Guaranty or the Agreements, Guarantor shall not exercise any rights against Company arising as a result of payment by Guarantor hereunder, by way of subrogation or otherwise, and will not prove any claim in competition with Participants or their affiliates in respect of any payment under the Agreements in bankruptcy or insolvency proceedings of any nature; Guarantor will not claim any set-off or counterclaim against Company in respect of any liability of Guarantor to Company and Guarantor waives any benefit of any right to participate in any collateral which may be held by Participants or any of their affiliates. Guarantor shall have no right of subrogation or reimbursement, contribution or other rights against Company. 7. If after receipt of any payment of, or the proceeds of any collateral for, all or any part of the obligations of Company under the Agreements, Participants are compelled to surrender or voluntarily surrender such payment or proceeds to any person because such payment or application of proceeds is or may be avoided, invalidated, recaptured, or set aside as a preference, fraudulent conveyance, impermissible setoff or for any other reason, whether or not such surrender is the result of (i) any judgment, decree or order of any court or administrative body having jurisdiction over Participants, or (ii) any settlement or compromise by Participants of any claim as to any of the foregoing with any person (including Company), then the obligations of Company under the Agreements, or part thereof affected, shall be reinstated and continue and this Guaranty shall be reinstated and continue in full force as to such obligations or part thereof as if such payment or proceeds had not been received, notwithstanding any previous cancellation of any instrument evidencing any such obligation or any previous instrument delivered to evidence the satisfaction thereof. The provisions of this Section shall survive the termination of this Guaranty and any satisfaction and discharge of Company by virtue of any payment, court order or any federal or state law until the full, final and irrevocable satisfaction of all of Company's obligations under the Agreements. 8. Any indebtedness of Company now or hereafter held by Guarantor is hereby subordinated to any indebtedness of Company to Participants; and such indebtedness of Company to Guarantor shall be collected, enforced and received by Guarantor as trustee for Participants and be paid over to Participants on account of the indebtedness of Company due and owing at any time to Participants but without reducing or affecting in any manner the liability of Guarantor under the other provisions of this Guaranty. 9. Guarantor represents and warrants to Participants, as an inducement to Participants to make the credit advances or sales of products on open account to Company, that: a. the execution, delivery and performance by Guarantor of this Guaranty (i) are within Guarantor's powers and have been duly authorized by all necessary action; (ii) do not contravene Guarantor's charter documents or any law or any material contractual restrictions binding on or affecting Guarantor or by which Guarantor's property may be affected; and (iii) do not require any authorization or approval or other action by, or any notice to or filing with, any public authority or any other person except such as have been obtained or made; b. this Guaranty constitutes the legal, valid and binding obligation of Guarantor, enforceable in accordance with its terms, except as the enforceability thereof may be subject to or limited by bankruptcy, insolvency, reorganization, arrangement, moratorium or other similar laws relating to or affecting the rights of creditors generally and by general principles of equity; and c. there is no action, suit or proceeding affecting Guarantor pending or threatened before any court, arbitrator, or public authority that may materially adversely affect Guarantor's ability to perform its obligations under this Guaranty, except as set forth in writing to the Participants and ISO New England Inc. prior to Participants' written authorization of this Guaranty. 10. Guarantor shall submit to Participants (i) a current credit rating agency report regarding Guarantor promptly upon the request of Participants, (ii) a copy of any Report on Form 8-K promptly after the filing by Guarantor of such report with the Securities and Exchange Commission, and (iii) a balance sheet, statement of income and such other financial statements of Guarantor as Participants shall reasonably request within ten (10) days after such statements are requested by Participants. Guarantor shall notify Participants in writing within ten (10) days after a material change in the financial status of Guarantor. For purposes of this section, a material change in financial status includes, but is not limited to, the following: (a) a downgrade to a below investment grade rating in the rating of Guarantor's senior long-term debt by a major rating agency; (b) the placement of Guarantor on credit watch with negative implication by a major credit rating agency if Guarantor's senior long-term debt does not have an investment grade rating; (c) Guarantor's bankruptcy or insolvency; (d) a report by Guarantor of a significant quarterly loss or decline in earnings; (e) the resignation of a key officer of Guarantor; and (e) the filing of a lawsuit that could materially adversely impact Guarantor's current or future financial results. Guarantor acknowledges that failure by it to provide the information required hereunder may result in Participants bringing proceedings to terminate service to Company in accordance with the procedure set forth for payment defaults in Section 8.4 of the Tariff. 11. Guarantor agrees to pay on demand all reasonable attorneys' fees and all other costs and expenses which may be incurred by Participants in the enforcement of this Guaranty. No terms or provisions of this Guaranty may be changed, waived, revoked or amended without Participants' prior written consent. Should any provision of this Guaranty be determined by a court of competent jurisdiction to be unenforceable, all of the other provisions shall remain effective. This Guaranty embodies the entire agreement among the parties hereto with respect to the matters set forth herein, and supersedes all prior agreements among the parties with respect to the matters set forth herein. No course of prior dealing among the parties, no usage of trade, and no parol or extrinsic evidence of any nature shall be used to supplement, modify or vary any of the terms hereof. There are no conditions to the full effectiveness of this Guaranty. Participants may assign this Guaranty without in any way affecting Guarantor's liability under it, except that Guarantor shall be provided reasonable notice of any such assignment. This Guaranty shall inure to the benefit of Participants and their successors and assigns. This Guaranty is in addition to the guaranties of any other guarantors and any and all other guaranties of Company's indebtedness or liabilities to Participants. 12. This Guaranty shall be governed by the laws of the State of Connecticut, without regard to conflicts of laws principles. Guarantor hereby irrevocably submits to the jurisdiction of any Connecticut State or United States Federal court sitting in Connecticut over any action or proceeding arising out of or relating to this Guaranty or any of the Agreements, and Guarantor hereby irrevocably agrees that all claims in respect of such action or proceeding may be heard and determined in such Connecticut State or Federal court. Guarantor irrevocably consents to the service of any and all process in any such action or proceeding by the mailing of copies of such process to Guarantor at its address set forth below its signature. Guarantor agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Guarantor further waives any objection to venue in such State and any objection to an action or proceeding in such State on the basis of forum non conveniens. Guarantor further agrees that any action or proceeding brought against Participants shall be brought only in Connecticut State or United States Federal courts sitting in Connecticut. Nothing herein shall affect the right of Participants to bring any action or proceeding against the Guarantor or its property in the courts of any other jurisdictions. 13. GUARANTOR ACKNOWLEDGES THAT IT HAS BEEN ADVISED BY COUNSEL OF ITS CHOICE WITH RESPECT TO THIS GUARANTY AND THAT IT MAKES THE FOLLOWING WAIVERS KNOWINGLY AND VOLUNTARILY: a. GUARANTOR IRREVOCABLY WAIVES TRIAL BY JURY IN ANY COURT AND IN ANY SUIT, ACTION OR PROCEEDING OR ANY MATTER ARISING IN CONNECTION WITH OR IN ANY WAY RELATED TO THE TRANSACTIONS CONTEMPLATED BY THIS GUARANTY, THE AGREEMENTS OR ANY DOCUMENTS RELATED THERETO (INCLUDING CONTRACT CLAIMS, TORT CLAIMS, BREACH OF DUTY CLAIMS, AND ALL OTHER COMMON LAW OR STATUTORY CLAIMS) AND THE ENFORCEMENT OF ANY OF PARTICIPANTS' RIGHTS AND REMEDIES; AND b. GUARANTOR EXPRESSLY ACKNOWLEDGES THAT THE OBLIGATIONS GUARANTEED HEREBY ARE PART OF A COMMERCIAL TRANSACTION AS SUCH TERM IS USED AND DEFINED IN CHAPTER 903a OF THE CONNECTICUT GENERAL STATUTES AND VOLUNTARILY AND KNOWINGLY WAIVES ANY AND ALL RIGHTS WHICH ARE OR MAY BE CONFERRED UPON IT UNDER CHAPTER 903a OF SAID STATUTES (OR ANY OTHER STATUTE AFFECTING PREJUDGMENT REMEDIES) TO ANY NOTICE OR HEARING OR PRIOR COURT ORDER OR THE POSTING OF ANY BOND PRIOR TO ANY PREJUDGMENT REMEDY WHICH PARTICIPANTS MAY USE. 14. Any demand, notice, request, instruction or other communication to be given hereunder by any party to another party shall be in writing and delivered personally, by nationally recognized overnight courier, by certified mail, postage prepaid and return receipt requested, by telegram, or by telecopier, as follows: If to Guarantor, at: If to Participants, at: Communications given by personal delivery or mail shall be effective upon actual receipt. Communications given by telegram or telecopier shall be effective upon actual receipt during the recipient's normal business hours, or at the beginning of the next business day after receipt if not received during the recipient's normal business hours. All communications by telegram or telecopier shall be confirmed promptly in writing by certified mail or personal delivery. Any party may change any address to which communications are to be given by giving notice as provided above of such change of address. IN WITNESS WHEREOF, the undersigned Guarantor has executed this Guaranty as of this day of [month], 199_. [GUARANTOR] By: Title: Corporate Officer Address: ATTACHMENT N New England Power Pool Billing Policy This New England Power Pool ("NEPOOL") Billing Policy (the "Policy") shall become effective on the later of (i) the Second Effective Date or (ii) the date that is sixty (60) days after the filing of this Policy with the Federal Energy Regulatory Commission. (FN1) SECTION 1 - OVERVIEW Section 1.1 - Scope. The objective of this Policy is to define the billing and payment procedures to be utilized in administering charges and payments due under the NEPOOL Agreement, the NEPOOL Tariff, the Interim Independent System Operator Agreement (the "Interim ISO Agreement") between NEPOOL and ISO New England Inc. (the "ISO"), the Amended and Restated Independent System Operator Agreement between NEPOOL and the ISO, when such agreement becomes effective (the "Amended ISO Agreement" and together with the Interim ISO Agreement, the "ISO Agreement"), and the ISO's Tariff for Transmission Dispatch and Power Administration Services (the "ISO Tariff"), in each case as amended, modified, supplemented and restated from time to time (collectively, the "Documents").(FN2) This Policy applies to the ISO, the NEPOOL Participants and Non-Participant Transmission Customers for billing and payments procedures for amounts due under the Documents, including without limitation those procedures related to the seven markets administered by the ISO. - ------ (FN1) Capitalized terms used but not defined in this Policy are intended to have the meanings given to such terms in Section 1 of the Restated NEPOOL Agreement (the "NEPOOL Agreement") or Section 1 of the Restated NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff"), in each case as amended from time to time. (FN2) Unless otherwise stated herein, the ISO will act as NEPOOL's agent in administering, managing and enforcing this Policy. Section 1.2 - Financial Transaction Conventions. The following conventions have been adopted in defining sums of money to be paid or received under this Policy: a) The term "Charge" refers to a sum of money due from a Participant or a Non-Participant Transmission Customer to the ISO, either in its individual capacity or as billing agent for the Participants. b) The term "Payment" refers to a sum of money due to a Participant or Non-Participant Transmission Customer from the ISO, as remitting agent for the Participants. Amounts due to and from the ISO include amounts collected and paid by the ISO as billing agent for the Participants. c) Where a Participant's or a Non-Participant Transmission Customer's total Charges exceed its total Payments in a month, the ISO shall issue an "Invoice" for the net Charge owed by such Participant or Non-Participant Transmission Customer. d) Where a Participant's or a Non-Participant Transmission Customer's total Payments exceed its total Charges in a month, the ISO shall issue a "Remittance Advice" for the net Payment owed to the Participant or Non- Participant Transmission Customer. Invoices and Remittance Advices are collectively referred to herein as "Statements." Section 1.3 - General Process. The billing process is performed monthly, except in the case of (i) Participants and Non-Participant Transmission Customers who have requested and received a weekly billing schedule in accordance with the Financial Assurance Policy for NEPOOL Members or the Financial Assurance Policy for NEPOOL Non-Participant Transmission Customers (collectively, the "Financial Assurance Policies") and (ii) special billings, as described below. There are two major steps in the billing process: a) Statement Issuance. The ISO will issue an Invoice or Remittance Advice showing the net amounts due from or owed to a Participant or a Non- Participant Transmission Customer for the preceding calendar month. This Statement is determined from the preliminary statements of the seven markets, applicable Charges due under the Documents (including amounts due under the Financial Assurance Policies), as well as any monthly adjustments. This Statement is normally issued not earlier than the fifth (5th) Business Day nor later than the fifteenth (15th) day after the end of the calendar month to which such Statement relates. b) Electronic Funds Transfer ("EFT"). EFTs related to Invoices and Remittance Advices are performed in a two-step process, as described below, in which all Invoices are paid first and all Remittance Advices are paid within two Business Days later. Section 1.4 - Special Billings. In addition to the regular monthly billing, the ISO will issue special, extraordinary Statements as and when required under the Documents or in order to adjust for special circumstances. Such Statements shall be payable in accordance with the instructions set forth therein. Section 1.5 - Conflicts with Documents. To the extent any provision hereof conflicts with any provision of any Document, the provision in the Document shall govern. SECTION 2 - TIMING AND CONTENT OF STATEMENTS. Section 2.1 - Normal Billing Cycle. The ISO shall provide to each Participant and Non-Participant Transmission Customer on a monthly basis one Statement for the previous calendar month or the portion thereof capable of being settled. The ISO shall issue the Statement typically not earlier than the fifth (5th) Business Day nor later than the fifteenth (15th) day following the end of the calendar month to which such Statement relates (although nothing set forth herein shall prohibit the ISO from issuing Statements between the first and fifth Business Days of a month). If the Statement is not issued by the 15th day of a month, the ISO shall delay the relevant funds transfer dates as described below. Section 2.2 - Provisions for Weekly Billing. The ISO shall implement any weekly billing arrangements effected under the Financial Assurance Policies in accordance therewith and with the procedures set forth below. Section 2.3 - Contents of Statements. Each Statement will include all of the following line items that are applicable to the Participant or Non- Participant Transmission Customer receiving such Statement for the month to which such Statement relates: a) Invoice or Remittance Advice Amount. The net amount of all Charges and Payments owed by or due to a Participant or a Non-Participant Transmission Customer for the relevant Statement. The ISO shall issue an Invoice where the Participant or Non-Participant Transmission Customer owes monies. The ISO shall issue a Remittance Advice where the Participant or Non-Participant Transmission Customer is owed monies. b) NEPOOL Tariff Charges and Payments. The Charges owed by and the Payments owed to the Participant or Non-Participant Transmission Customer under the NEPOOL Tariff. c) ISO Tariff Charges. The Charges owed by the Participant or Non-Participant Transmission Customer under the ISO Tariff, categorized by the section or schedule under which such Charges arise. d) Markets Charges and Payments. The Charges owed by and the Payments owed to the Participant as a result of transactions in each of the seven markets administered by the ISO. e) NEPOOL Expenses. The Participant's pro-rata share of Pool fees and expenses as set forth in Section 19 of the NEPOOL Agreement. f) Sanctions Charges. Any Charges assessed on the Participant pursuant to Market Rule 13, the so-called Sanctions Rule. g) Other Amounts due under the NEPOOL Agreement and the ISO Agreement. The Charges owed by or the Payments owed to the Participant under the NEPOOL Agreement and the ISO Agreement to the extent that those amounts are not included in items (b) - (f) above. h) Other Charges, Payments or Adjustments. Any other Charges, Payments, or adjustments owed by or to the Participant or Non-Participant Transmission Customer that are not included in items (b) - (g) above. These items may be due to retroactive billing adjustments, late payment fees, penalties or other items collectible under the Documents. i) Billing Periods. The billing period (from and to dates) covered for each line item on the Statement. The billing periods for the various line items are not necessarily the same because of differences in timing of settlements (e.g. the ICAP market may be two months in arrears while hourly markets may be one month in arrears) and because of retroactive adjustments. j) Payment Due Date and Time. If the Statement is an Invoice, the date and time on which the net amount due is to be received by the ISO. k) Wire Transfer Instructions. Details including the account number, bank name, routing number and electronic transfer instructions which, in the case of an Invoice, will be for the ISO account to which Charges owed by the Participant or Non-Participant Transmission Customer are to be paid or, in the case of a Remittance Advice, will be for the Participant's or Non- Participant Transmission Customer's account to which the ISO shall remit Payments owed to that Participant or Non-Participant Transmission Customer (as previously provided to the ISO by such Participant or Non-Participant Transmission Customer). A sample Invoice is attached hereto as Attachment 1. A sample Remittance Advice is attached hereto as Attachment 2. Section 2.4 - Subsequent Adjustments to Previously Issued Statements. a) Adjustments Requested by Participants. Participants supplying Network Load and other input data to the ISO for use by the ISO in developing Statements shall use reasonable care to assure that the data supplied is complete and accurate. Should a Participant supplying input data subsequently determine that the data supplied was incorrect, that Participant shall notify the ISO promptly of the error and submit corrected data as soon as practicable. If the error is detected and corrected data is provided within the time frames set forth below, the ISO will issue corrected Statements to reflect the newly supplied data. Type of Adjustment Corrected Data Must be Submitted Within Adjustments to Monthly Three (3) months from the Network Load Submissions date the subject Statement for that calendar month is issued Adjustments to EHV Three (3) months from the and LV PTF Percentages for effective date of the PTF Billing of Excepted modification to an Transactions Submissions entitlement receiving EHV and LV PTF billing Adjustments to Three (3) months after the Annual Average annual average Network Load Network Load for the current NEPOOL Tariff (12CP) Submissions year has been developed Adjustments to Annual Revenue Three (3) months after the Requirement Submissions applicable RNS rate has been established Adjustments to Three (3) months after the Annual NEPOOL Schedule 1 applicable annual Schedule 1 Submissions rate has been established If the data correction is not submitted within the applicable time frame set forth above, the obligation of the ISO to issue corrected Statements reflecting that adjustment shall be as set forth in a written re-billing protocol approved by the Transmission Settlement Sub-committee (or such other NEPOOL committee as the NEPOOL Participants Committee may determine) and posted on the ISO web-site. The re-billing protocol shall provide, for each category of adjustment listed above, whether and to what extent the adjustment shall be prospective or retroactive and the timing of the adjustment. If the corrected data is not submitted within the applicable time frame, the ISO may assess each Participant submitting corrected data on an untimely basis its costs in generating and issuing the corrected Statement. The written re-billing protocol shall include a fee schedule for this purpose. b) Adjustments Triggered by ISO Audit. The ISO will review the results of internal and outsourced audits with the Transmission Settlement Subcommittee, or such other NEPOOL committee as the NEPOOL Participants Committee may determine. That Subcommittee, or other designated committee, will determine whether any errors found are sufficiently significant to require a re- billing. The reasonable costs to the ISO of the re-billing shall be allocated to Schedule 1 of the ISO Tariff. c) Adjustments Reflecting Compliance with an Order of the Commission or other Regulatory or Judicial Authority With Jurisdiction. Adjustments required to effect compliance with an order of the Commission (or any other regulatory or judicial authority with jurisdiction to interpret and/or enforce the provisions of the Documents) shall be completed by the ISO in compliance with such order. The costs of any such re-billing to the ISO shall be allocated among the NEPOOL Participants in accordance with the provisions of Section 19.2 of the Restated NEPOOL Agreement. SECTION 3 - PAYMENT PROCEDURES. All Payments made by the ISO will in all instances be made by EFT or in immediately available funds payable to the account designated to the ISO by the Participant or Non-Participant Transmission Customer to which such Payment is due. Payments made by Participants or Non-Participant Transmission Customers shall be made by EFT to the account designated by the ISO. Section 3.1 - Invoice Payments. a) Payment Date. Except in the case of weekly billings and special billings, all Charges due shall be paid to and received by the ISO not later than the first (1st) Business Day after the nineteenth (19th) day of the calendar month in which the subject invoice was issued; provided, however, that if the Invoice is issued on or after the sixteenth (16th) day of the calendar month, the payment on that Invoice shall be due on the fourth (4th) Business Day after the Invoice is issued; and provided further that a Non- Participant Transmission Customer will in no event be required to make a payment on an Invoice any sooner than provided in Section 8.2 of the NEPOOL Tariff. b) Right to Alter Payment Date. The ISO may alter the dates on which payments are due in the case of special billings and Participants and Non-Participant Transmission Customers that are on weekly billing schedules in accordance with the Financial Assurance Policies; provided, however, that (i) payment on any Invoice shall not be due prior to the fourth (4th) Business Day after the Invoice is issued, and (ii) a Non-Participant Transmission Customer shall not be required to make a payment on an Invoice any sooner than provided in Section 8.2 of the NEPOOL Tariff. c) Payments Received by ISO. Each Participant or Non-Participant Transmission Customer owing monies shall remit the amount shown on its Invoice no later than the date such payment is due. Disputed amounts shall be paid in accordance with clause (d) below. d) Payments Pending Resolution of a Dispute. Any Participant or Non- Participant Transmission Customer that disputes the amount due on any Invoice for service other than transmission service under the NEPOOL Tariff shall pay to the ISO all amounts due on such Invoice, including those in dispute. Such payment shall in no way prejudice the right of such Participant or Non- Participant Transmission Customer to seek reimbursement of such disputed amounts, including accrued interest on such amounts at the Commission's standard rate, set forth in 18 C.F.R. Section 35.19, pursuant to the Billing Dispute Resolution Procedures provided in Section 5 below. Any Participant or Non-Participant Transmission Customer that disputes the amount due on any Invoice for transmission service under the NEPOOL Tariff shall pay to the ISO all amounts not in dispute and shall pay the amount in dispute into an independent escrow account designated by the ISO, which account shall be established at a banking institution acceptable to the ISO and the Participant or Non-Participant Transmission Customer challenging the amount due and shall accrue interest at a prevailing market rate. Such amount in dispute shall be held in escrow pending the resolution of such dispute in accordance with the applicable Document(s). To the extent that the amount in dispute would be payable to one or more identifiable Participants (but not to the ISO), then the amount due to each such Participant in the billing period to which such dispute relates shall be reduced by the portion of the total amount in dispute that would be payable to such Participant, subject to payment with interest accrued thereon if and when the dispute is resolved in favor of such Participant(s). To the extent that the amount in dispute would be payable to the ISO, or the specific Participant(s) to which such amount would be payable cannot be identified, then the shortfall of funds available to pay Remittance Advices resulting from the amount in dispute being held in an escrow account shall be allocated among the Participants according to the two-step allocation process described in Section 3.3(e) below, subject to payment to all such Participants being allocated a portion of the shortfall, with applicable interest (if any), once the dispute is resolved with the funds in such escrow account or with other amounts provided by the Participant or Non-Participant Transmission Customer losing such dispute. Section 3.2 - ISO Payment of Remittance Advice Amounts. The Payment Date for Remittance Advices shall be the second (2nd) Business Day after the date on which Invoices are due in such month. Section 3.3 - Payment Default. If the ISO, in its reasonable opinion, believes that all or any part of any amount due to be paid by any Participant or Non-Participant Transmission Customer will not or has not been paid when due (other than in the case of a payment dispute) (the "Default Amount"), then the following procedures shall apply: a) ISO Charges Paid First. The ISO shall use monies received by it from Participants and Non-Participant Transmission Customers to pay all amounts due to the ISO under the ISO Tariff and ISO Agreement before making any payments to any Participants or Non-Participant Transmission Customers. b) Use of Set-Offs. The ISO shall use any and all rights of set-off it has under the Documents and this Policy against a defaulting Participant or a Non-Participant Transmission Customer to the extent necessary to pay the Default Amount, together with any interest accrued thereon and any late charges assessed under the Documents and the Financial Assurance Policies, due from such Participant or Non-Participant Transmission Customer. c) Enforcing the Security of a Defaulting Party. If and to the extent that the procedure described in clause (b) above is insufficient to effect payment of the Default Amount and all interest accrued thereon and late charges assessed under the Documents and the Financial Assurance Policies, the ISO shall use the financial assurance(s) provided by the Participant or Non- Participant Transmission Customer under the Financial Assurance Policies to the extent necessary to pay the Default Amount and such interest and late charges. Any use of financial assurance(s) shall be undertaken in compliance with the Financial Assurance Policies. d) Action Against a Defaulting Party. If and to the extent that the procedures described in clauses (b) and (c) above are insufficient to effect payment of the Default Amount and all interest accrued thereon and late charges assessed under the Documents and the Financial Assurance Policies, the ISO shall take appropriate actions to recover the Default Amount and such accrued interest and late charges, which actions may include, without limitation, initiating proceedings in accordance with the appropriate dispute resolution mechanisms or actions with NEPOOL or before the Federal Energy Regulatory Commission or a court of competent jurisdiction against the defaulting Participant or Non-Participant Transmission Customer. Prior to the commencement of any such action or proceeding with respect to amounts due to Participants, the ISO shall obtain the approval of the NEPOOL Executive Committee or its designee and shall offer to the NEPOOL Executive Committee or its designee an opportunity to be involved in such action or proceeding. Any amounts incurred by the ISO or any Participant in connection with any such action or proceeding shall be paid by the defaulting Participant or Non- Participant Transmission Customer. e) Reduction of Payments and Increases in Charges. (i) If and to the extent that the procedures described in clauses (b), (c) and (d) above do not yield sufficient funds to pay all Remittance Advice amounts in full (after payment of amounts due to the ISO in accordance with clause (a) above) on the date such Payments are due, the ISO shall reduce Payments to those Participants owed monies for that billing period (the "Default Period"), pro rata based on the amounts owed to such Participants, to the extent necessary to clear its accounts by the close of banking business on the date such Payments are due. As funds attributable to a Default Amount are received by the ISO (including amounts received through financial assurances provided under the Financial Assurance Policies or through actions or proceedings commenced against the defaulting Participant or Non-Participant Transmission Customer) prior to the next billing period's Statements being distributed, such funds, together with any interest and late charges collected on the applicable Default Amount, shall be distributed pro rata to the Participants that did not receive the full amount of their Payments as a result of such Default Amount not being paid. (ii) To the extent that any amount remains unpaid to Participants on the date that Statements are distributed to Participants in the billing period immediately following the Default Period, the Default Amount remaining unpaid shall be reallocated among all of the Participants receiving Statements for the Default Period (other than the Participant or Non-Participant Transmission Customer defaulting on its payment obligations), pro rata based, for each Participant being allocated a share of the Default Amount remaining unpaid, on the sum of (i) all Charges due from such Participant that are reflected on its Statement for the Default Period and (ii) all Payments due to such Participant that are reflected on its Statement for the Default Period, without giving any effect to the process of netting Charges against Payments on each Statement that is the result of the ISO's single billing system. Thus, by way of example, a Participant with $2,000 of Charges and no Payments on its Statement for the Default Period and a Participant with $1,000 of Charges and $1,000 of Payments on its Statement for the Default Period would be allocated an equal share of the unpaid Default Amount under this clause (e)(ii). Each Participant that received a Statement for the Default Period shall have the amount of its Invoice or Remittance Advice in the billing period immediately following the Default Period adjusted as necessary to reflect its obligation for the Default Amount remaining unpaid under this clause (e)(ii). As funds attributable to a Default Amount are received by the ISO (including amounts received through financial assurances provided under the Financial Assurance Policies or through actions or proceedings commenced against the defaulting Participant or Non-Participant Transmission Customer) after such adjusted Statements are distributed, such funds, together with any interest and late charges collected on the applicable Default Amount, shall be distributed to the Participants pro rata based on their allocation of the Default Amount under this clause (e)(ii). f) Other Rights Against Defaulting Parties. Nothing set forth in this Policy shall nullify, restrict or otherwise limit the rights and remedies of the ISO and the Participants against a defaulting Participant or Non-Participant Transmission Customer that are set forth in the Documents, the Financial Assurance Policies or otherwise, including without limitation any late payment charges or rights to terminate or limit trading rights of the defaulting Participant, to the extent such rights and remedies otherwise exist. g) Set-Off. The ISO shall apply any amount to which any defaulting Participant or Non-Participant Transmission Customer is or will be entitled toward the satisfaction of any of that defaulting Participant's or Non- Participant Transmission Customer's debts to the ISO or the Participants which are incurred under the Documents or the Financial Assurance Policies. h) Order of Settlement. As amounts on Default Amounts are received by the ISO, the oldest outstanding amount will be settled first in the order of the creation of such debts. i) Notification of Payment Default. Without limiting any of the other remedies described above, in the event that the ISO, in its reasonable opinion, believes that all or any part of any amount due to be paid by any Participant or any Non-Participant Transmission Customer will not be or has not been paid within 10 days of when due (a "Payment Default"), the ISO (on its own behalf or on behalf of NEPOOL) may (but shall not be required to) notify such Participant or Non-Participant Transmission Customer 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 (it being understood that the ISO will use reasonable efforts to contact all three) or such Non-Participant Transmission Customer's billing contact, of such Payment Default. Either simultaneously with the giving of the notice described in the preceding sentence or within ten days thereafter (unless the Payment Default giving rise to such notice is cured during such period), the ISO shall notify each other member and alternate on the NEPOOL Participants Committee and each Participant's billing contact of the identity of the Participant or Non-Participant Transmission Customer receiving such notice, whether such notice relates to a Payment Default and the actions the ISO plans to take and/or has taken in response to such Payment Default. Section 3.4 - Bankruptcy Filings. In the event any Participant or Non- Participant Transmission Customer files a voluntary or involuntary petition in bankruptcy or commences a proceeding under the United States Bankruptcy Code or any other applicable law concerning insolvency, reorganization or bankruptcy by or against such Participant or Non-Participant Transmission Customer as debtor (the "Bankruptcy Event") and the ISO is required to return any payments made by such Participant or Non-Participant Transmission Customer to the bankruptcy court having jurisdiction over such Bankruptcy Event, the ISO may avail itself of any emergency funding provisions in the ISO Agreement to collect the amounts returned by the ISO. SECTION 4 - WEEKLY BILLING PRINCIPLES. The ISO shall administer weekly billing arrangements according to the following principles: Section 4.1 - Weekly Invoices. The ISO shall issue an Invoice each Friday to each Participant and Non-Participant Transmission Customer for which a weekly billing arrangement has been established to the extent such Participant's or Non-Participant Transmission Customer's Charges exceed the Payments due to it for the current calendar week. Remittance Advices for such Participants will still be issued monthly, in accordance with the procedures set forth above. Section 4.2 - Basis for Billing. The amounts for each market (except the Installed Capability market), and all other amounts due from such Participant or Non-Participant Transmission Customer shall be based on estimates derived by pro-rating the most recent final monthly Statements issued for such Participant or Non-Participant Transmission Customer. For the Installed Capability market, the weekly amount billed for Capability Responsibility shall be based on estimates derived by pro-rating the most recent preliminary report of the Participant's position in the Installed Capability market. Section 4.3 - Payment Date and Time. Each Participant or Non-Participant Transmission Customer receiving such a weekly Invoice shall remit the amount shown on its Invoice no later than five (5) Business Days after the date the Invoice is issued. Section 4.4 - Monthly Reconciliation. In connection with each monthly billing cycle, the ISO shall reconcile the sum of the weekly Invoices issued with the normal monthly billing quantities calculated for the Participant or Non-Participant Transmission Customer. The ISO shall perform a true-up of any amounts owed or due on the following weekly Statements. SECTION 5 - BILLING DISPUTE PROCEDURES. Section 5.1 - Requested Billing Adjustments Eligible for Resolution under Billing Dispute Procedures. Any Participant or Non-Participant Transmission Customer may dispute the amount due on any fully paid monthly Invoice and/or any amount believed to be due or owed on a Remittance Advice (a "Disputed Amount"). Such party (a "Disputing Party") shall seek to recover such Disputed Amount, including accrued interest, pursuant to this Section 5, by first submitting a request for billing adjustment to the ISO (a "Requested Billing Adjustment" or "RBA") in accordance with the procedures provided in this Section 5 and Market Rule 18. A Disputing Party may seek resolution of a Requested Billing Adjustment under this Section 5 concerning any Disputed Amount resulting from the determination of a market clearing price, NEPOOL Tariff and/or ISO Tariff rate by the ISO that allegedly either violates or is otherwise inconsistent with the NEPOOL Tariff, ISO Tariff or the Market Rules, or results from error by the ISO. Notwithstanding the foregoing, a Requested Billing Adjustment must involve a requested change in an amount owed or believed to be owed in a Remittance Advice that is not covered by another alternative dispute resolution procedure under the NEPOOL Tariff, the ISO Tariff, the Interim ISO Agreement or the Market Rules. Furthermore, a Requested Billing Adjustment must not involve Disputed Amounts paid on a weekly Invoice pursuant to the Financial Assurance Policies, provided, however, that this provision shall not preclude a Disputing Party from submitting a Requested Billing Adjustment for a Disputed Amount on a fully paid monthly Invoice which has been paid pursuant to a weekly Invoice in that month. Section 5.2 - Effect of this Policy on Rights of Participant or Non- Participant Transmission Customer with Respect to a Disputed Amount. Except as otherwise set forth in this Section 5.2, nothing in this Section 5 shall in any way abridge the right of any Participant or Non-Participant Transmission Customer to seek legal or equitable relief under the Federal Power Act and/or any other applicable laws with respect to any Disputed Amount. Prior to commencing a proceeding before the Commission or other regulatory or judicial authority with jurisdiction to resolve the dispute which is the subject of the Requested Billing Adjustment, the Disputing Party must first submit the Requested Billing Adjustment to the ISO for review pursuant to Section 5.3 of this Policy. Section 5.3 - ISO Review of Requested Billing Adjustment. Section 5.3.1 - Submission of Requested Billing Adjustment to ISO; Required Contents of Requested Billing Adjustment. A Disputing Party shall submit a Requested Billing Adjustment in writing to the chief financial officer of the ISO. In its Requested Billing Adjustment, the Disputing Party must specify the Disputed Amount at issue and specify the instance of alleged error at issue, including a statement detailing the specific provisions of all applicable governing documents that support the Requested Billing Adjustment. The Disputing Party also must state the relief being requested and identify a specific person or persons to whom all communications to the Disputing Party regarding the Requested Billing Adjustment are to be addressed. A Disputing Party must submit its Requested Billing Adjustment within 3 months of the date that the Invoice or Remittance Advice containing the Disputed Amount was issued by the ISO unless the Disputing Party could not have reasonably known of the existence of the alleged error within such time. Section 5.3.2 - Notice of ISO Review of Requested Billing Adjustment. Within three (3) Business Days of the receipt by the ISO's Chief Financial Officer of a Requested Billing Adjustment, the ISO shall prepare and submit to the Secretary of the Participants Committee for distribution by the Secretary to all Participants and Non-Participant Transmission Customers a notice of the Requested Billing Adjustment ("Notice of RBA"), including, subject to the protection of Confidential Information, the specifics of the Requested Billing Adjustment. The Notice of RBA shall identify a specific representative of the ISO to whom all communications regarding the Requested Billing Adjustment are to be sent. The Secretary of the Participants Committee shall distribute the Notice of RBA to all Participants and Non- Participant Transmission Customers by no later than 5:00 p.m. on the next business day after receiving the Notice of RBA from the ISO. Section 5.3.3 - ISO Review of Requested Billing Adjustments. The ISO shall complete its review of a Requested Billing Adjustment received pursuant to Section 5.3 within twenty (20) business days of the date the Secretary of the Participants Committee distributes the Notice of RBA. To the extent that either party makes such a request and both parties agree to such request, the ISO and Disputing Party may meet or otherwise confer during this period in an effort to resolve the Requested Billing Adjustment. Section 5.3.4 - Comment Period. Any Participant or Non-Participant Transmission Customer, which desires to do so may submit to the ISO's designated representative, on or before the tenth (10th) Business Day following the date the Secretary of the Participants Committee distributes the Notice of RBA, written comments to the ISO with respect to the Requested Billing Adjustment. Any such comments are to be transmitted simultaneously to the Disputing Party. The Disputing Party may respond to any such comments by submitting a written response to the ISO's designated representative and to the commenting party on or before the fifteenth (15th) Business Day following the date the Secretary of the Participants Committee distributes the Notice of RBA. In determining the action it will take with respect to the Requested Billing Adjustment, the ISO shall consider the written response filed by the Disputing Party. The ISO may but is not required to consider any written comments that are filed by any other interested party. Section 5.3.5 - ISO Action on Requested Billing Adjustment. The ISO shall provide to the Disputing Party a written decision (the "RBA Decision") accepting or denying a Requested Billing Adjustment received pursuant to Section 5.3 within twenty (20) Business Days of the date the Secretary of the Participants Committee distributes the Notice of RBA, unless some later date is agreed upon by the Disputing Party and the ISO. The ISO shall provide written notice and a copy of each RBA Decision to each Participant or Non- Participant Transmission Customer either eligible for reimbursement, denied reimbursement of a Disputed Amount or required to provide reimbursement of a Disputed Amount because of an RBA Decision (hereafter referred to as an "Affected Party" or the "Affected Parties") within five (5) business days of the date the RBA Decision is rendered. In providing such notice to any Affected Party required to provide reimbursement of a Disputed Amount, the ISO shall specify the amount to be reimbursed by such Affected Party and the calculations supporting the determination of such reimbursement amount. Subsequent to the provision of the written notice of the RBA Decision as set forth above, the ISO shall provide each Affected Party with respect to that RBA Decision a monthly report of the status of such RBA Decision within the dispute resolution process set forth in this Section 5 of the Billing Policy, including a statement of the accounting treatment of the disputed amount owed by or to that Affected Party with respect to that RBA Decision in accordance with the most recent decision issued pursuant to Sections 5.3.6 or 5.4 of this Billing Policy, whichever applies, with respect to that RBA Decision. For purposes of Section 5 of this Policy, the term "Affected Parties" shall also include the Disputing Party. Section 5.3.6 - Finality of ISO Action on Requested Billing Adjustment. Except as otherwise provided in this Section 5.3.6, the RBA Decision shall become final and binding on the Affected Parties and shall not be appealable in any forum on the twenty-first (21st) Business Day after the notice of the specific RBA Decision at issue was provided to the Affected Parties as set forth in Section 5.3.5 above. The RBA Decision shall not become final or binding if, on or before the twentieth (20th) Business Day after the notice of the specific RBA Decision at issue was provided to the Affected Parties as set forth in Section 5.3.5 above, an Affected Party or Parties has appealed the RBA Decision by commencing a proceeding before the Commission or other regulatory or judicial authority with jurisdiction over the dispute, or has filed an appeal pursuant to Section 5.4 of this Policy. If a proceeding is commenced before the Commission or other regulatory or judicial authority with jurisdiction over the dispute, the Affected Party commencing that proceeding shall simultaneously transmit a copy of their initial pleading in that proceeding to the ISO's designated representative for that particular RBA Decision, and shall also submit to the ISO's designated representative for that particular RBA a copy of the final order or decision in that proceeding resolving the dispute. If any such appeal is filed pursuant to Section 5.4 of this Policy, the RBA Decision shall have no force or effect unless or until it is affirmed or upheld upon completion of the appeal process selected by the Affected Party and as provided for in this Policy. Section 5.4 - Right of Affected Party to Review of ISO RBA Decision by AAA. Section 5.4.1 - Right to Further Review. Any Affected Party may seek review of an RBA Decision by an independent third party neutral by submitting, on or before the twentieth (20th) Business Day after the notice of the specific RBA Decision at issue was provided to the Affected Parties as set forth in Section 5.3.5 above, a request for arbitration of the Requested Billing Adjustment with the American Arbitration Association ("AAA"). At the same time that it submits its request to the AAA, the Affected Party commencing any such review of an RBA Decision shall transmit its request for arbitration: (i) to the ISO's designated representative for that particular RBA Decision; (ii) to each of the Affected Parties; and, (iii) to the Secretary of the Participants Committee. The ISO and any Affected Party shall be joined as parties to the arbitration. NEPOOL shall be permitted to intervene in the arbitration if it desires to do so. Section 5.4.2 - Finality of the AAA Neutral's Decision. Except as otherwise provided in this Section 5.4.2, the written, final decision of the AAA neutral (the "Neutral's Decision") shall become final and binding on the Affected Parties, including the ISO, and shall not be appealable in any forum on the twenty-first (21st) Business Day after the date on which the Neutral's Decision was issued. The Neutral's Decision shall not become final or binding if on or before the twentieth (20th) business day after the date on which the Neutral's Decision was issued, an Affected Party or Parties or the ISO has appealed the Neutral's Decision by commencing a proceeding before the Commission or other regulatory or judicial authority with jurisdiction over the dispute. If any such appeal is filed, the Neutral's Decision shall have no force or effect unless or until it is affirmed or upheld upon completion of the appeal process. Section 5.5 - Access to Confidential Information. Information that is deemed confidential pursuant to the NEPOOL Information Policy in the possession, custody or control of the ISO concerning the dollar amount in Invoices or Remittance Advices issued by the ISO ("Confidential Information") shall be made available under these Billing Dispute Procedures only to "Dispute Representatives" as defined herein who have executed a confidentiality agreement in accordance both with this Section 5.5 and the NEPOOL Information Policy ("Confidentiality Agreement"). A copy of the executed Confidentiality Agreement for a Dispute Representative shall be provided to the ISO prior to the disclosure of any Confidential Information to said Dispute Representative. Confidential Information shall not be disclosed to anyone other than in accordance with this Section 5.5, and shall be used only in connection with the Billing Dispute Procedures provided under Section 5. a) Potential Disputing Parties' Right of Access to Confidential Information. A Participant or Non-Participant Transmission Customer that is a potential Disputing Party is entitled to obtain access to Confidential Information for its Dispute Representative, if and only if, it can demonstrate to the ISO that such access is required to determine if it has a substantive basis for filing a Requested Billing Adjustment with the ISO. Such demonstration by a potential Disputing Party, at a minimum, shall include: the information submitted to the chief financial officer of the ISO required in Section 5.3.1; and, why lack of access to Confidential Information prevents the potential Disputing Party from determining if it has a substantive basis for filing such a Requested Billing Adjustment. A potential Disputing Party shall submit a request for access to Confidential Information in writing to the ISO (an "Information Request"). The ISO shall evaluate and respond to such an Information Request within ten (10) days of the receipt of the Information Request, and where the need for access to Confidential Information is demonstrated in accordance with the above, shall provide access to such Confidential Information within fifteen (15) days of the receipt of the Information Request. b) Affected Parties Right of Access to Confidential Information. If the RBA Decision is submitted to the AAA for resolution pursuant to Section 5.4, then for purposes of that AAA proceeding a Participant or Non-Participant Transmission Customer that is an Affected Party is entitled to obtain access to Confidential Information for its Dispute Representative if, and only if, it can demonstrate to the AAA Neutral that such access is required to protect its financial interests with respect to review of an RBA Decision pending before the Neutral. An Affected Party shall submit a request for access to Confidential Information concerning an RBA Decision within the timeframes established by the Neutral. The Neutral shall have the authority to enter such orders as may be necessary to protect the Confidential Information, in accordance with applicable NEPOOL policies including but not limited to the NEPOOL Information Policy. c) Dispute Representatives. Dispute Representatives shall be limited to the AAA Neutral(s), Participants, Non-Participant Transmission Customers, and third parties retained by and/or in-house legal counsel of the AAA, Participants or Non-Participant Transmission Customers, provided, however, that Confidential Information may not be disclosed to a Dispute Representative to the extent the disclosure is prohibited by Order 889. A Dispute Representative may disclose Confidential Information to any other Dispute Representative as long as the disclosing Dispute Representative and the receiving Dispute Representative each have executed a Confidentiality Agreement. In the event that any Dispute Representative to whom Confidential Information is disclosed ceases to be engaged in a matter under these Billing Dispute Procedures, or is no longer qualified to be a Dispute Representative under this Section, access to Confidential Information by that person, or persons, shall be terminated and all such Confidential Information received by that party shall be returned to the ISO or destroyed to the satisfaction of the ISO. Even if no longer engaged as a Dispute Representative under this Section, every person who has executed the Confidentiality Agreement set forth below shall continue to be bound by the provisions of this Section and such Confidentiality Agreement. All Dispute Representatives are responsible for ensuring that persons under their supervision or control comply with this Section and the Confidentiality Agreement. Re: Requested Billing Adjustment ______________ CONFIDENTIALITY AND NONDISCLOSURE AGREEMENT The ISO ("Provider") agrees to make available, pursuant to Section 5 of the NEPOOL Billing Policy, to ("Recipient") confidential and proprietary information ("Confidential Information") relevant to resolution of Requested Billing Adjustment and any appeals thereof as provided for in said Section 5. 1. Any information provided to Recipient and labeled "Confidential Information" by Provider shall be Confidential Information subject to this Agreement. 2. The Confidential Information is received by Recipient in confidence. 3. The Confidential Information shall not be used or disclosed by the Recipient except in accordance with the terms contained herein, with Section 5 of the NEPOOL Billing Policy and with the NEPOOL Information Policy. 4. Only individuals who are Dispute Representatives as that term is defined in Section 5 of the NEPOOL Billing Policy, and not entities, may be Recipients of Confidential Information under this paragraph. By executing this Agreement, each Recipient certifies that he/she meets the requirements of this Agreement. 5. The following conditions shall apply to each Recipient: a. Each Recipient will receive one (1) numbered, controlled copy of the Confidential Information. The Recipient shall not make any copies thereof or provide the Confidential Information to any individual or entity except one who has executed and delivered an Agreement identical to this Agreement to the Provider. b. The Recipient shall maintain a log of all persons granted access to the Confidential Information. c. The Recipient, by signing this Agreement acknowledges that he/she may not in any manner disclose the Confidential Information to any person, and that he/she may not use the Confidential Information for the benefit of any person except in this proceeding and in accordance with the terms of this Agreement, Section 5 of the NEPOOL Billing Policy and the NEPOOL Information Policy. d. The Recipient acknowledges that any violation of this Agreement may subject the Recipient to civil actions for violation hereof. e. Within thirty (30) days of the final decision issued with respect to the Requested Billing Adjustment terminating all appeals with respect to this Requested Billing Adjustment, Recipient shall return the Confidential Information to Provider. PROVIDER: RECIPIENT: By: By: Dated: Dated: d) Maintenance of Confidential Information. All copies of all documents and materials containing Confidential Information shall be maintained by Dispute Representatives at all times in a secure place in sealed envelopes or other appropriate containers endorsed to the effect that they are sealed pursuant to this Section. Such documents and material shall be marked PROTECTED CONFIDENTIAL INFORMATION and shall be maintained under seal and provided only to Dispute Representatives as are authorized to examine and inspect such Confidential Informational. Dispute Representatives shall provide to the ISO a list of those persons under the supervision and/or control of the Dispute Representative who are entitled to receive Confidential Information. Dispute Representatives shall take all reasonable precautions to ensure that Confidential Information is not distributed to unauthorized persons. e) ISO Right to Object to Access to Confidential Information. Nothing in this Section shall be construed as precluding the ISO from objecting to providing any party access to Confidential Information on any legal grounds other than those provided under the NEPOOL Information Policy, the NEPOOL Agreement, and/or the Interim ISO Agreement, as they may be amended time to time. Section 5.6 - Transition Rules. Any Disputed Amount raised with the ISO between the Second Effective Date and the effective date of these Billing Dispute Procedures that is unresolved as of the effective date of these Billing Dispute Procedures as determined by the Commission shall be submitted for resolution under these Billing Dispute Procedures as specified below. Disputed Amounts so referred shall be termed "Pre-Existing Disputes". a) Review of Pre-Existing Disputes. On or before the thirtieth (30th) calendar day after the date of the Commission's order accepting this Section 5 of the Billing Policy, the Disputing Party in a Pre-Existing Dispute shall submit to the ISO a Request for Billing Adjustment. All parties to Pre- Existing Disputes shall be entitled to access to Confidential Information subject to the rights and obligations provided with respect to Confidential Information in Section 5.5 above. If a Request for Billing Adjustment with respect to a Pre-Existing Dispute is not submitted in accordance with this Section 5.6(a), the Pre-Existing Dispute shall be deemed resolved for purposes of this Billing Policy and Section 21.2 of the Restated NEPOOL Agreement . b) Release of Amounts in Escrow for Pre-Existing Disputes Other than Disputes Involving Transmission Service Under the Tariff. All amounts at issue in a Pre-Existing Dispute held in escrow, except for amounts at issue in a Pre-Existing Dispute concerning amounts due with respect to transmission service under the NEPOOL Tariff, pursuant to the provisions of Section 3.1(d) of the NEPOOL Billing Policy and Section 21.2(c) of the NEPOOL Agreement in effect immediately prior to the effective date of this Section 5 of the NEPOOL Billing Policy (together, the "Former Escrow Provisions") shall be released from escrow to the payee upon satisfaction of the following two conditions: (1) thirty (30) calendar days have elapsed since the date of the Commission's Order accepting this Billing Policy; and, (2) the ISO has determined that the required Financial Assurances under this Section 5 of the Billing Policy and the relevant provisions of Attachment L to the NEPOOL Tariff have been satisfied with respect to the amount at issue in the Dispute. If a Participant that has received from one or more other Participants or Non-Participant Transmission Customers an amount the payment of which is the subject of a dispute, an amount equal to 100% of such amount in dispute shall be included in determining that Participant's overall financial assurance requirement and the relevant provisions of Attachment L to the NEPOOL Tariff shall apply. c) Release of Amounts in Escrow With Respect to Disputes Concerning Transmission Service Under the Tariff. If the Pre-Existing Dispute concerns amounts due on any Invoice for transmission service under the NEPOOL Tariff, any amounts held in escrow with respect to such Pre-Existing Dispute shall remain in escrow and shall accrue interest at a prevailing market rate. Such amount in dispute shall be held in escrow pending the resolution of such dispute in accordance with the applicable Document(s). To the extent that the amount in dispute would be payable to one or more identifiable Participants (but not to the ISO), then the amount due to each such Participant in the billing period to which such dispute relates shall be reduced by the portion of the total amount in dispute that would be payable to such Participant, subject to payment with interest accrued thereon if and when the dispute is resolved in favor of such Participant(s). To the extent that the amount in dispute would be payable to the ISO, or the specific Participant(s) to which such amount would be payable cannot be identified, then the shortfall of funds available to pay Remittance Advices resulting from the amount in dispute being held in an escrow account shall be allocated among the Participants according to the two-step allocation process described in Section 3.3(e) below, subject to payment to all such Participants being allocated a portion of the shortfall, with applicable interest (if any), once the dispute is resolved with the funds in such escrow account or with other amounts provided by the Participant or Non-Participant Transmission Customer losing such dispute. Attachment 1 SAMPLE INVOICE See attached pages [Form of Sample Invoice] Attachment 2 SAMPLE REMITTANCE ADVICE See attached pages [Form of Sample Remittance Advice] Sheet Nos. 457-500 are reserved for future use. ANCILLARY SERVICE SCHEDULE 1 SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE IMPLEMENTATION RULE This rule provides detail with respect to the calculation of the rate surcharge each year for Scheduling, System Control and Dispatch Service, which is defined in the Tariff as the service required to schedule the movement of power through, out of, within, or into the NEPOOL Control Area over Pool Transmission Facilities ("PTF"). This service also includes the dispatch and security analysis of the system. Scheduling, System Control and Dispatch Service for transmission service over transmission facilities other than PTF is provided under the Local Network Service Tariffs of the individual Transmission Providers. For transmission service under the NEPOOL Tariff, this Ancillary Service will be provided by the Independent System Operator (ISO), satellites, and the Transmission Providers. All of the costs of the ISO will be recovered directly by the ISO under its own tariff once that tariff becomes effective (a January 1, 1999 effective date has been requested) and Schedule 1 of the NEPOOL Tariff is for collection only of the revenue requirements for satellites and Transmission Providers for System Control and Dispatch Service. Any Transmission Customer taking Regional Network Service, Through or Out Service, or Internal Point-to-Point Service shall be subject to the rate surcharge calculated under Schedule 1 of the NEPOOL Tariff as described in more detail in this rule below. NEPOOL shall make an annual informational filing on or before July 31 of each year showing the Schedule 1 rate surcharge in effect for the period beginning June 1 of that year through May 31 of the subsequent year. If there are any corrections made to the information reflected in the informational filing after it has been submitted, NEPOOL would file corrections to the informational filing. At least thirty days before the informational filing is made with the Commission, NEPOOL shall make available to Participants and any other interested parties a draft of the proposed filing for review and comment prior to the filing. The filing of the informational filing does not re-open the formula rate set forth below for review, but rather is contestable only with respect to the accuracy of the information contained in the informational filing. The System Operator shall independently audit the charges in effect for the period June 1997 through May 2000 for charges under this Attachment, or direct that an audit[s] be conducted under its supervision by an independent third party, and shall have the discretion to conduct such audits of charges in effect beyond May 2000. I. DEFINITIONS Capitalized terms used in this rule that are not defined in the NEPOOL Tariff have the following definitions: Scheduling and Dispatch Surcharge Rate shall equal the rate surcharge that is determined for the applicable period beginning on June 1, 1999, in accordance with Section II of this rule below. PTF Transmission-Related Satellite Scheduling and Dispatch Expense shall equal the PTF transmission related expenses incurred by the Participant from REMVEC II, CONVEX/ESCC, and the Maine Satellite as recorded in each Participant's FERC Form 1, Account No. 561, excluding any charges recorded in this account that were incurred under the NEPOOL Tariff or the Local Network Service Tariffs of each Transmission Provider as a Transmission Customer. The expenses shall be net of any revenues, as reflected in FERC Account No. 456, received by the Participant for providing scheduling and dispatch services, excluding any revenues recorded in this account that where received as a result of charges under the NEPOOL Tariff or the LNS Tariffs of each Transmission Provider. REMVEC II is a satellite of the ISO-NE providing security analysis of PTF. Local PTF Transmission-Related Scheduling and Dispatch Expense shall equal the sum of (1) each Participant's expenses as recorded in FERC Account No. 561, excluding any ISO and satellite related expenses and any expenses recorded in this Account, that were incurred under this Tariff or the LNS Tariffs of each Transmission Provider as a Transmission Customer, multiplied by the PTF Transmission Plant Allocator, (2) SCADA-related expenses as calculated in accordance with Appendix A to this Rule, and (3) the Maine Satellite revenue requirements as calculated in accordance with Appendix A to this Rule. PTF Transmission Plant Allocation Factor is the factor for allocating transmission costs and expenses between PTF and non-PTF as determined for the applicable period pursuant to Attachment F of the NEPOOL Tariff. II. CALCULATION OF THE SCHEDULING AND DISPATCH SURCHARGE A. Surcharge for Regional Network Service Customers For Network Customers, the scheduling and dispatch surcharge shall equal the Network Customer's Monthly Network Load, as defined in Section 46.1 of the NEPOOL Tariff, multiplied by the Monthly Scheduling and Dispatch Surcharge Rate as determined in accordance with Section II.C below. B. Surcharge for Point-to-Point Customers For Point to Point and Through or Out Service Customers, the Scheduling and Dispatch Surcharge shall equal the Transmission Customer's Reserved Capacity for each transaction scheduled for the month multiplied by the applicable Monthly, Weekly, or Hourly Scheduling and Dispatch Surcharge Rate, as determined in accordance with Section II.C below. C. Scheduling and Dispatch Surcharge Rate The Scheduling and Dispatch Surcharge Rate will be the surcharge rate in effect from time to time for the applicable period, determined pursuant to the formula described below based on the prior calendar year's data. The Scheduling and Dispatch Surcharge Rate shall be redetermined each year, with the new Surcharge Rate going into effect on June 1 of each year, and be effective for the succeeding twelve months. In the case of Transmission Providers which are subject to the Commission's jurisdiction, the data used shall be as identified in the Participant's FERC Form 1 report for that year, and shall be based on actual data in lieu of allocated data if specifically identified in the FERC Form 1. When FERC Form 1 data is not the direct source of the data used in the formula, the worksheets used to develop the inputs will be as reflected in Appendix A of this Rule. The Scheduling and Dispatch Surcharge Rate shall be equal to the sum of (1) PTF Transmission-Related Satellite Scheduling and Dispatch Expense, (2) Local PTF Transmission Related Scheduling and Dispatch Expense, (3) less Schedule 1 revenues from the prior year surcharges for Short-Term Point-to-Point Transactions, and divided by the annual average of the sum of all Network Customers Monthly Peak Load, as defined in Section 46.1 of the NEPOOL Tariff, from the prior calendar year plus the Long-Term Firm Point-to-Point Reserved Capacity, from the prior calendar year. The Monthly Scheduling and Dispatch Surcharge Rate shall equal one-twelfth of the Scheduling and Dispatch Surcharge Rate. The Weekly Scheduling and Dispatch Surcharge Rate shall equal one-fifty- second of the Scheduling and Dispatch Surcharge Rate. The Daily Firm Scheduling and Dispatch Surcharge Rate shall equal one-fifth of the Weekly Scheduling and Dispatch Surcharge Rate. The Daily Non-Firm Scheduling and Dispatch Surcharge Rate shall equal one- seventh of the Weekly Scheduling and Dispatch Surcharge Rate. The Hourly Non-Firm Scheduling and Dispatch Surcharge Rate shall equal one- twenty-fourth of the Daily Non-Firm Scheduling and Dispatch Surcharge Rate. APPENDIX A-1 NEPOOL Tariff Schedule 1 Implementation Rule Scheduling, System Control and Dispatch Service Boston Edison Company SCADA This service is required to schedule the movement of power through, out of, within, or into the NEPOOL Control Area over Pool Transmission Facilities (PTF). Service under this schedule represents the contribution to that service provided by The Transmission Provider's own Dispatch Center, commonly referred to as SCADA. These costs are excluded from costs in Attachment F. Definitions: Dispatch Center Wages and Salaries Allocation Factor: Ratio of Dispatch Center Related Direct Wages and Salaries to Boston Edison's total Direct Wages and Salaries excluding Administrative and General Wages and Salaries. Dispatch Center Plant Allocation Factor: Ratio of Total Investment in Dispatch Center Plant plus Dispatch Center Related General Plant, to Total Plant in service. The PTF Revenue Requirement for the Scheduling System Control and Dispatch Service shall equal the sum of The Transmission Provider's: (A) Return and Associated Income Taxes, (B) Dispatch Center Depreciation Expense, (C) Dispatch Center Related Amortization of Investment Tax Credits, (D) Dispatch Center Related Municipal Tax Expense, (E) Dispatch Center Related Payroll Tax Expense (F) Dispatch Center Operation and Maintenance Expense, and (G) Dispatch Center Related Administrative and General Expense; multiplied by the PTF Transmission Plant Allocation Factor. A. Return and Associated Income Taxes shall equal the product of the Dispatch Center Investment Base and the Cost of Capital Rate. 1. The Dispatch Center Investment Base will consist of (a) Dispatch Center Plant in FERC accounts 350-359, plus (b) Dispatch Center Related General Plant, plus (c) Dispatch Center Plant Held for Future Use, less (d) Dispatch Center Related Depreciation Reserve, less (e) Dispatch Center Related Accumulated Deferred Taxes, plus (f) Other Regulatory Assets, plus (g) Dispatch Center Prepayments, plus (h) Dispatch Center Materials and Supplies, plus (i) Dispatch Center Related Cash Working Capital. a. Dispatch Center Plant will equal the year-end balance of the Transmission Provider's Investment in Dispatch Center per FERC accounts 350 through 359.Dispatch Center Plant Investment is not included in PTF investment in the Attachment F revenue requirement. b. Dispatch Center Related General Plant shall equal the Transmission Provider's year-end balance of Investment in General Plant multiplied by the Dispatch Center Wages and Salaries Allocation Factor described above. c. Dispatch Center Plant Held for Future Use shall equal the year-end balance of Transmission related Dispatch Center Investment in FERC account 105. d. Dispatch Center Related Depreciation Reserve shall equal the year-end balance of Transmission Dispatch Center Depreciation Reserve, plus the year- end balance of Dispatch Center Related General Depreciation Reserve. Dispatch Center Related General Plant Depreciation Reserve shall equal the product of General Plant Depreciation Reserve and the Dispatch Center Wages and Salaries Allocation Factor described above. e. Dispatch Center Related Accumulated Deferred Taxes shall equal the year- end balance of Total Accumulated Deferred Income Taxes, multiplied by the Dispatch Center Plant Allocation Factor described above. f. Other Regulatory Assets shall equal the year-end balance of FAS 106 multiplied by the Dispatch Center Wages and Salaries Allocation Factor described in Section (A) (2) (b) above and the year-end balance of FAS 109, net of FAS 109 liability, multiplied by the Dispatch Center Plant Allocation Factor described in above. g. Dispatch Center Prepayments shall equal the year-end balance of Prepayments multiplied by the Dispatch Center Wages and Salaries Allocation Factor described above. h. Dispatch Center Materials and Supplies shall equal the year-end balance of Transmission Plant Materials and Supplies multiplied times the Dispatch Center Plant Allocation Factor described above. i. Dispatch Center Related Cash Working Capital shall be a 12.5% allowance (45 days/360 days) of Dispatch Center Transmission Related Operation and Maintenance Expense and Dispatch Center Transmission Related Administrative and General Expense. 2. The Cost of Capital Rate shall equal (a) the Weighted Cost of Capital, plus (b) Federal Income Taxes, plus (c) State Income Taxes. a. the Weighted Cost of Capital will be calculated based upon the Transmission Provider's capital structure at the end of each year and will equal the sum of i. the Long Term Debt Component, which equals the product of the actual weighted average embedded cost to maturity of Long Term Debt then outstanding and the ratio that Long-Term Debt is to Total Capital. ii. the Preferred Stock Component, which equals the product of the actual weighted average embedded cost to maturity of Preferred Stock then outstanding and the ratio that Preferred Stock is to Total Capital. iii. the Return on Equity Component, which equals the product of The Transmission Provider's Return on Equity as set in the Transmission Provider's LNS open access tariff rate and the ratio that Common Equity is to Total Capital. b. Federal Income Taxes shall equal A + [(C+B)/D]) x FT 1 - FT Where FT is the Federal Income Tax Rate and A is the sum of the Preferred Stock Component and the Return on Equity Component, as determined in Sections A.2.(a)(ii) and (iii) above, B is Dispatch Center Related Amortization of Investment Tax Credits, as determined in Section II.D. below, C is the Equity AFUDC component of Dispatch Center Depreciation Expense, as defined in Section B., and D is Dispatch Center Investment Base, as determined in A.1., above. c. State Income Taxes shall equal (A + [(C+B)/D] + Federal Income Tax) x ST 1 - ST Where ST is the State Income Tax Rate and A is the sum of the Preferred Stock Component and the Return on Equity Component, as determined in Section A.2.(a)(ii), and Section A.2.(a)(iii) above, and Federal Income Tax is the rate determined in Section A.2.(b) above. B. Dispatch Center Depreciation Expense shall equal the sum of Transmission Depreciation Expense for Dispatch Center Plant, plus an allocation of General Plant Depreciation Expense calculated by multiplying General Plant Depreciation Expense by the Dispatch Center Wages and Salaries Allocation Factor, described in Section (A) (1) (b) above. C. Dispatch Center Related Amortization of Investment Tax Credits shall equal the Transmission Provider's Amortization of Investment Tax Credits multiplied by the Dispatch Center Plant Allocation Factor described above. D. Dispatch Center Related Municipal Tax Expense shall equal the Transmission Provider's total Municipal Tax Expense multiplied by the Dispatch Center Plant Allocation Factor described above. E. Dispatch Center Related Payroll Tax Expense shall equal the Transmission Provider's total electric payroll tax expense, multiplied by the Dispatch Center Wages and Salaries Allocation Factor, described above. F. Dispatch Center Operation and Maintenance Expense shall equal all expenses related to SCADA operation charged to FERC Account Number 561, excluding any ISO and satellite related expenses and any expenses recorded in this Account that were incurred under this Tariff or the LNS tariff of any Transmission Provider as a Transmission Customer. G. Dispatch Center Related Administrative and General Expenses shall equal the sum of (1) Transmission Provider's Administrative and General Expenses, excluding Accounts 924, 928 and 930.1, multiplied by the Dispatch Center Wages and Salaries Allocation Factor, (2) Property Insurance multiplied by the Dispatch Center Plant Allocation Factor, and (3) Expenses included in Account 928 related to FERC Assessments multiplied by Dispatch Center Plant Allocation Factor, plus any other Federal and State Dispatch Center related expenses or assessments, plus specific Dispatch Center related expenses included in Account 930.1. APPENDIX A-2 NEPOOL Tariff Schedule 1 Implementation Rule Scheduling, System Control and Dispatch Service Central Maine Power Company Satellite I. DEFINITIONS Capitalized terms not otherwise defined in Section 1 of the NEPOOL Tariff and as used in this rule have the following definitions: A. ALLOCATION FACTORS 1. Wages and Salaries Allocation Factor shall equal the ratio of the Satellite Direct Wages and Salaries to total direct wages and salaries excluding administrative and general wages and salaries. 2. Satellite Wages and Salaries Allocation Factor shall equal the ratio of the Transmission Satellite Direct Wages and Salaries to total Satellite Direct Wages and Salaries. 3. Satellite PTF Allocation Factor shall equal the ratio of the Satellite PTF Direct Wages and Salaries to the total Satellite Transmission Direct Wages and Salaries. 4. Satellite Plant Allocation Factor shall equal the ratio of the Total Investment in Satellite Plant to Total Plant in service. B. TERMS Administrative and General Expense shall equal the Transmission Provider's expenses as recorded in FERC Account Nos. 920-935, excluding FERC Account Nos. 924, 928, and 930.1. Amortization of Investment Tax Credits shall equal the Transmission Provider's credits as recorded in FERC Account No. 411.4 Amortization of Loss on Reacquired Debt shall equal the Transmission Provider's expenses as recorded in FERC Account No. 428.1 Other Regulatory Assets/Liabilities - FAS 106 shall equal the net of the Transmission Provider's FAS106 balance as recorded in FERC Account 182.3 and any FAS 106 balance as recorded in the Transmission Provider's FERC Account No. 254. Other Regulatory Assets/Liabilities - FAS 109 shall equal the net of the Transmission Provider's FAS 109 balance in FERC Account No. 182.3 and any FAS 109 balance as recorded in the Transmission Provider's FERC Account No. 254. Payroll Taxes shall equal those payroll expenses as recorded in the Transmission Provider's FERC Account Nos. 408.1 and 409.1. Plant Held for Future Use shall equal the Transmission Provider's balance in FERC Account No. 105. Prepayments shall equal the Transmission Provider's prepayment balance as recorded in FERC Account No. 165. Property Insurance shall equal the Transmission Provider's expenses as recorded in FERC Account No. 924. PTF Satellite Direct Wages and Salaries shall equal the Transmission Provider's direct wages and salaries related to providing PTF satellite services as recorded in FERC Account No. 561. Satellite Direct Wages and Salaries shall equal the Transmission Provider's direct wages and salaries related to providing satellite services as recorded in FERC Account Nos. 556, 561, and 581. Satellite Operation and Maintenance Expense shall equal the Transmission Provider's expenses recorded in FERC Account Nos. 556, 561, & 581, less any costs included in FERC Account No. 561 that are otherwise recoverable pursuant to Subpart (1) of the Local PTF Transmission Related Scheduling and Dispatch Expense of the rule implementing the Schedule 1 rate surcharge of the NEPOOL Tariff. Satellite Plant Depreciation Reserve shall equal the Transmission Provider's depreciation reserve balance for Satellite Related Plant as recorded in FERC Account No. 108. Materials and Supplies shall equal the Transmission Provider's balance as recorded in FERC Account No. 154. Satellite Related Depreciation Expense shall equal the Transmission Provider's depreciation expense for Satellite Related Plant as recorded in FERC Account No. 403. Satellite Related Plant shall equal the Transmission Provider's gross plant balances used for system control and dispatch purposes as recorded in FERC Account Nos. 303-399. To the extent that such plant includes any amounts recorded as transmission investment in FERC Account Nos. 350-359, such amounts will be excluded for purposes of determining annual transmission revenue requirements pursuant to the billing rule which implements Attachment F of the NEPOOL Tariff. Satellite Support Revenues shall equal the revenues received from satellite supporters as recorded in FERC Account Nos. 454 and 456, excluding any revenues received under Schedule 1 of the NEPOOL Tariff or the Transmission Provider's Local Tariff. Total Accumulated Deferred Income Taxes shall equal the net of the deferred tax balances as recorded in FERC Account Nos. 281-283 and 190.. Total Loss on Reacquired Debt shall equal the Transmission Provider's balance as recorded in FERC Account No. 189. Total Municipal Tax Expense shall equal the Transmission Provider's municipal tax expenses as recorded in FERC Account Nos. 408.1 and 409.1. Total Plant in Service shall equal the Transmission Provider's total gross plant balance as recorded in FERC Account Nos. 301-399. Transmission Satellite Direct Wages and Salaries shall equal the Transmission Provider's direct wages and salaries related to providing satellite services as recorded in FERC Account No. 561. II. CALCULATION OF TOTAL SATELLITE REVENUE REQUIREMENTS The Satellite Revenue Requirement shall equal the sum of the Satellite related (A) Return and Associated Income Taxes, (B) Depreciation Expense, (C) Amortization of Loss on Reacquired Debt, (D) Amortization of Investment Tax Credits, (E) Municipal Tax Expense, (F) Payroll Tax Expense, (G) Operations and Maintenance Expense, (H) Administrative and General, minus (I) Support Revenues. A. Return and Associated Income Taxes shall equal the product of the Satellite Investment Base and the Cost of Capital Rate reflected in the Transmission Providers' Attachment F formula of the NEPOOL Tariff. 1. Satellite Investment Base The Satellite Investment Base will be the year end balances of Satellite related: (a) Plant, plus (b) Plant Held for Future Use, less (c) Depreciation Reserve, less (d) Accumulated Deferred Taxes, plus (e) Loss on Reacquired Debt, plus (f) Other Regulatory Assets/Liabilities, plus (g) prepayments, plus (h) Materials and Supplies, plus (i) Cash Working Capital. (a) Satellite Related Plant shall equal the balance of the Transmission Provider's Investment in Satellite Plant (b) Satellite Related Plant Held for Future Use shall equal the balance of Plant Held for Future Use multiplied by the Satellite Plant Allocation Factor (c) Satellite Related Depreciation Reserve shall equal the Depreciation Reserve for the Transmission Provider's investment in Satellite plant. (d) Satellite Related Accumulated Deferred Taxes shall equal the Transmission Provider's electric balance of Accumulated Deferred Income Taxes multiplied by the Satellite Plant Allocation Factor. (e) Satellite Related Loss on Reacquired Debt shall equal the Transmission Provider's electric balance of Total Loss on Reacquired Debt multiplied by the Satellite Plant Allocation Factor. (f) Satellite Related Other Regulatory Assets/Liabilities shall equal the Transmission Provider's electric balance of any deferred recovery of FAS 106 expenses multiplied by the Satellite Wages and Salaries Allocation Factor, plus the Transmission Provider's electric balance of FAS 109 multiplied by the Satellite Plant Allocation Factor. (g) Satellite Related Prepayments shall equal the Transmission Provider's electric balance of prepayments multiplied by the Satellite Plant Allocation Factor. (h) Satellite Related Materials and Supplies shall equal the Transmission Provider's electric balance of Plant Materials and Supplies, multiplied by the Satellite Plant Allocation Factor. (i) Satellite Related Cash Working Capital shall be a 12.5% allowance (45 days/360 days) of Satellite Operation and Maintenance Expense, Satellite Related Administrative and General Expense. 2. Cost of Capital Rate The Cost of Capital Rate will equal (a) The Transmission Provider's Weighted Cost of Capital, plus (b) Federal Income Tax plus (c) State Income Tax. (a) The Weighted Cost of Capital will be calculated based upon the capital structure at the end of each year and will equal the sum of: (i) the long-term debt component, which equals the product of the actual weighted average embedded cost to maturity of the Transmission Provider's long-term debt then outstanding and the ratio that long-term debt is to the Transmission Provider's total capital. (ii) the preferred stock component, which equals the product of the actual weighted average embedded cost to maturity of the Transmission Provider's preferred stock then outstanding and the ratio that preferred stock is to the Transmission Provider's total capital. (iii) the return on equity component, which equals the product of the Transmission Provider's Return on Equity as set in the Provider's RNS open access rate and the ratio that common equity is to the Transmission Provider's total capital. (b) Federal Income Tax shall equal (A+[(C+B)/D]) x FT 1 - FT Where FT is the Federal Income Tax Rate and A is the sum of the preferred stock component and the return on equity component, as determined in Sections II.A.2.(a)(ii) and (iii) above, B is the Amortization of Investment Tax Credits as determined in Section II.D. below, C is the equity AFUDC component of Satellite Depreciation Expense, as defined in II.B., and D is Satellite Investment Base, as determined in II.A.1., above. (c) State Income Tax shall equal (A+[(C+B)/D] + Federal Income Tax) x ST 1 - ST Where ST is the State Income Tax Rate, A is the sum of the preferred stock component and return on equity component determined in Sections II.A.2.(a)(ii) and (iii) above, B is the Amortization of Investment Tax Credits as determined in Section II.D. below, C is the equity AFUDC component of Satellite Depreciation Expense, as defined in II.B., D is the Satellite Investment Base, as determined in II.A.1., above and Federal Income Tax is the rate determined in Section II.A.1.(b) above. B. Satellite Depreciation Expense shall equal the Satellite Plant Depreciation Expense and Accumulated Amortization C. Satellite Related Amortization of Loss on Reacquired Debt shall equal the Transmission Provider's electric balance of Loss on Reacquired Debt multiplied by the Satellite Plant Allocation Factor. D. Satellite Related Amortization of Investment Tax Credits shall equal the Transmission Provider's electric Amortization of Investment Tax Credits multiplied by the Satellite Plant Allocation Factor. E. Satellite Related Municipal Tax Expense shall equal the Transmission Provider's total electric municipal tax expense multiplied by the Satellite Plant Allocation Factor. F. Satellite Related Payroll Tax Expense shall equal the Transmission Provider's total electric payroll tax expense, multiplied by the Wages and Salaries Allocation Factor. G. Satellite Operation and Maintenance Expense shall equal the Transmission Provider's Operation and Maintenance Expenses recorded in FERC Account Nos. 556, 561, and 581, less any costs included in FERC Account No. 561 that are otherwise recoverable pursuant to Subpart (1) of Local PTF Transmission Related Scheduling and Dispatch Expense of the rule implementing the Schedule 1 rate surcharge of the NEPOOL Tariff. H. Satellite Related Administrative and General Expenses shall equal the sum of (1) Transmission Provider's Administrative and General Expenses multiplied by the Wages and Salaries Allocation Factor, (2) Property Insurance multiplied by the Satellite Plant Allocation Factor, and (3) Expenses included in Account 928 related to FERC Assessments multiplied by the Satellite Plant Allocation Factor, plus any other Federal and State satellite related expenses or assessments, plus specific satellite related expenses included in Account 930.1. I. Transmission Support Revenues shall equal the Transmission Provider's revenue received for providing system control and dispatch service III. CALCULATION OF SATELLITE TRANSMISSION REVENUE REQUIREMENTS The Total Satellite Revenue Requirements derived in Section II. above are further multiplied by the Satellite Wages and Salaries Allocation Factor defined in Section I. A. 2. above to determine the transmission related revenue requirement, and further multiplied by the Satellite PTF Allocation Factor defined in Section I. A. 3. above, to determine the PTF Transmission related revenue requirements to be included in Schedule I of the NEPOOL Open Access Transmission Tariff. ANCILLARY SERVICE SCHEDULE 2 (Reactive Supply And Voltage Control From Generation Sources Service) IMPLEMENTATION RULE This rule is designed to implement the NEPOOL Open Access Transmission Tariff Ancillary Service Schedule 2 (Reactive Supply and Voltage Control from Generation Sources Service) ("Schedule 2"). As of the Second Effective Date, service within the scope of Schedule 2 shall be paid by Participants and/or Non-Participants in accordance with the formula set forth in Schedule 2. The rule defines how Participants providing Schedule 2 service shall be compensated for providing such service. 1. Capacity Cost (CC) 1.1 The Capacity Cost will be set to zero ($0) until a methodology for cost determination and compensation is developed and approved by the NEPOOL Markets Committee (MC) and the NEPOOL Tariff Committee (TC) and filed and accepted by the Commission. 2. Lost Opportunity Cost (LOC) 2.1 The Lost Opportunity Cost for hydro, pumped storage and thermal generating units that are dispatched down by the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control will be calculated in a manner that is consistent with the rules established in Market Rule and Procedure No. 6-A - Compensation For Resources Postured For OP-4 Conditions (MRP 6-A). 2.2 LOC Data Submission 2.2.1 A NEPOOL satellite or a NEPOOL Participant dispatch center must notify the ISO Control Room staff when a thermal, hydro, or pumped storage generating unit has been dispatched down by the satellite or NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control. 2.2.2 The ISO Control Room staff will log all instances of a thermal, hydro or pumped storage generating unit having been dispatched down by the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control. 2.2.3 The ISO Settlements staff will collect the data required for the determination of LOCSched2 from the ISO Control Room logs, Energy Management System, and Market System. 3. Cost of Energy Consumed (SCL) 3.1 Motoring Hydro or Pumped Storage Generating Units. The SCL associated with hydro and pumped storage generating units that are motoring at the request of the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control will equal the cost of energy to motor and will be calculated in each hour as follows: SCL = (MWhUnit * (ECP or Actual energy cost) + UpliftSched2), where the MwhUnit are calculated pursuant to Section 3.2.4. Actual energy cost applies only if motoring energy is purchased through a bilateral contract. Documentation of actual energy cost is to be provided to the ISO. The UpliftSched2 component of the SCL is related to the increase in the Participant's Electrical Load that was caused by the motoring of a hydro or pumped storage generating unit that was motoring at the request of the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control and any other uplift allocations associated with providing this service and will be calculated in each hour as follows: UpliftSched2 = MWhUnit * ((* AGC, OPCAP, TMNSR, TMOR and TMSR Market Payments + Energy Market Uplift Payment) / * Participants' Electrical Load + applicable ISO Tariff rates + any Emergency Purchase Cost allocation associated with provision of this service). The UpliftSched2 component of the SCL applies only until the changes indicated in Sections 3.5 and 3.6 have been implemented. 3.2 Data submissions associated with Hydro and Pumped Storage Generating Units that motored for the purpose of providing Reactive Supply and Voltage Control 3.2.1 A NEPOOL satellite or a NEPOOL Participant dispatch center must notify the ISO Control Room staff of a generating unit having been instructed by the satellite or NEPOOL Participant dispatch center to motor for the purpose of providing reactive supply and voltage control. 3.2.2 The ISO Control Room staff will log all instances of hydro and pumped storage generating units having been instructed by the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center to motor for the purpose of providing reactive supply and voltage control. 3.2.3 The ISO Settlements staff will collect the flags set by the ISO Control Room and the ISO Control Room logs to determine which hydro or pumped storage generating units had been instructed to motor for the purpose of providing reactive supply and voltage control. 3.2.4 The Lead Participant will need to submit to the ISO Settlements staff the following data for each hour that the hydro or pumped storage generating units was motoring for the purpose of providing reactive supply and voltage control: * The hourly incremental MWh reflecting the energy in each hour required to support reactive supply and voltage control while motoring above that which is required when not providing reactive supply and voltage control, * If the energy to supply the motoring hydro or pumped storage generating unit is being met by the hourly Energy Market, the hourly Energy Clearing Price, plus UpliftSched2 related to the increase in the Participant's Electrical Load that was caused by the motoring of a hydro or pumped storage generating unit that was motoring at the request of the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control (in the hours that the unit was motored, if any) until the changes indicated in Sections 3.5 and 3.6 below are in effect; or If the energy to supply the motoring hydro or pumped storage generating unit is being met by a retail power agreement, the actual cost of energy associated with the wholesale/retail power agreement along with supporting contractual documentation plus UpliftSched2 related to the increase in the Participant's Electrical Load that was caused by the motoring of a hydro or pumped storage generating unit that was motoring at the request of the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control (in the hours that the unit was motored, if any) until the changes indicated in Sections 3.5 and 3.6 below are in effect, and * An invoice for each motoring hydro or pumped storage generating unit that includes a total net cost and an hourly cost detail that includes the hourly data noted in Section 3.1. 3.3 Timing of Data Submissions by Participants for Hydro or Pumped Storage Generating Units that motored for the purpose of providing Reactive Supply and Voltage Control - Participants should submit their SCL data (noted in the above three bullets, Section 3.2.4) related to the motoring of a hydro or pumped storage generating unit for the purpose of providing reactive supply and voltage control to ISO Settlements within fourteen (14) calendar days after the completion of the month in which the unit was called to motor. Under no circumstances will data submissions received three (3) calendar months or more after the completion of the month in which the unit was called to motor be compensated. Submittals received after the 14-day deadline will be reflected in a single billing that will occur after the 3-month submission deadline has passed. 3.4 Data submissions notifying the ISO of Hydro or Pumped Storage Generating Units that have the ability to motor for the purpose of providing Reactive Supply and Voltage Control - Direction as to whether the ECP or the actual energy cost will be applied to the SCL calculation (the ECP is to be selected only if the Participant does not have a wholesale/retail agreement to supply the unit's station service requirements) must be submitted, with supporting contractual documentation, to the ISO Settlements staff prior to the month in which the hydro or pumped storage generating unit is called to motor for reactive supply and voltage control. It is not intended that a Participant would have the option to bounce back and forth between ECP and actual energy cost. 3.5 Power System Modeling of Hydro and Pumped Storage Generating Units that can be motored for the purpose of providing Reactive Supply and Voltage Control - The energy (MWh) required by a hydro or pumped storage generating unit that is motoring for the purpose of providing reactive supply and voltage control should be reported under a distinct and unique Load Asset. The option of reporting the energy required by a hydro or pumped storage generating unit that is motoring for the purpose of providing reactive supply and voltage control under a distinct and unique Load Asset is currently not available. This option will require incorporation within the appropriate Market Rule and Procedures (e.g., MRP 20-H and MRP 20-I) and additional programming within the Market System. Until such a time as that can be accommodated, Participants will submit the appropriate data and be compensated through the mechanism noted in Section 3.1 and 3.2. 3.6 Impact of Hydro or Pumped Storage Generating Units motoring for the purpose of providing Reactive Supply and Voltage Control on the calculation of Electrical Load and Load - The MWh reported under a distinct and unique Load Asset (pursuant to Section 3.5) for the motoring of a hydro or pumped storage generating unit will be excluded from the calculation of Electrical Load and Load. The MWh that have not been reported under a distinct and unique Load Asset (pursuant to Section 3.5) for the motoring of a hydro or pumped storage generating unit will neither be excluded from the calculation of Electrical Load and Load nor be compensated under Schedule 2. 3.7 Synchronous Condensers and Static Controlled VAR Regulators (SC/SCV). The SCL will be set to zero ($0), and the cost of energy to supply reactive supply and voltage control from the Chester SCV will be treated as losses on the NEPOOL bulk transmission system. This treatment will be revisited by the MC and TC on an as needed basis (e.g., upon the addition of a new SC or SCV within the NEPOOL Control Area). 4. Cost of Energy Produced (PC) 4.1 Thermal Generating Units. The PC associated with thermal generating units brought on-line by the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control shall equal 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. The "Dispatch Price" of an out-of-merit resource for an hour is the price to provide energy from the resources, as determined pursuant to Market Rules approved by the NEPOOL Participants Committee, to incorporate the Bid Price for such energy and any loss adjustments, if and as appropriate under such Market Rules. The "Energy Clearing Price" for an hour is the price determined for the hour in accordance with Section 14.8 of the Agreement. 4.2 Hydro and Pumped Storage Generating Units. The PC associated with hydro or pumped storage generating units that are producing real power and that have also been brought on-line by the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center to provide reactive supply and voltage control shall equal 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. The "Dispatch Price" of an out-of-merit resource for an hour is the price to provide energy from the resources, as determined pursuant to Market Rules approved by the NEPOOL Participants Committee, to incorporate the Bid Price for such energy and any loss adjustments, if and as appropriate under such Market Rules. The "Energy Clearing Price" for an hour is the price determined for the hour in accordance with Section 14.8 of the Agreement. 4.3 Data submissions with respect to PC 4.3.1 A NEPOOL satellite or a NEPOOL Participant dispatch center must notify the ISO Control Room staff of a generating unit having been brought on-line by the satellite or NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control. 4.3.2 The ISO Control Room staff will log all instances of a generating unit having been brought on-line by the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control. 4.3.3 The ISO Settlements Hourly Markets staff will collect the flags set by the ISO Control Room and the ISO Control Room logs to determine which generating units have been brought on-line for the purpose of providing reactive supply and voltage control. 4.3.4 The ISO Settlement Staff will collect the appropriate data through the Market System for each hour that the generating unit was brought on-line for the purpose of providing reactive supply and voltage control. Sheet Nos. 530-700 are reserved for future use. NEPOOL TARIFF, ATTACHMENT F IMPLEMENTATION RULE FOR CALCULATING ANNUAL TRANSMISSION REVENUE REQUIREMENTS This rule sets forth details with respect to the determination each year of the Transmission Revenue Requirements for each Participant. Such Transmission Revenue Requirements shall reflect the Participant's costs for Pool Transmission Facilities ("PTF"). The Transmission Revenue Requirements will be an annual formula rate calculation, effective June 1, based on the previous calendar year's data, as shown below, and in the case of each Transmission Provider which is subject to the Commission's jurisdiction, in the Participant's FERC Form 1 report for that year, and shall be based on actual data in lieu of allocated data if specifically identified in the FERC Form 1, using end-of-year balances for each rate base item, as set forth below. NEPOOL shall make an annual informational filing on or before July 31 of each year showing the Pool PTF Rate in effect for the period beginning June 1 of that year through May 31 of the subsequent year. Further, the informational filing with respect to the determination of the Pool PTF rate would include a breakdown by Participant the amount of the change in PTF investment during the prior year and the PTF retirements or additions causing such change to beginning and end-of-year PTF balances (although beginning-of- year PTF balances are not used in the formula itself), and any additions to PTF, retirements of PTF, and reclassifications of PTF during the year for each Transmission Provider. If there are any corrections made to the information reflected in the informational filing after it has been submitted, NEPOOL would file corrections to the informational filing. At least forty-five days before the informational filing is made with the Commission, NEPOOL shall make available to Participants and any other interested parties a draft of the proposed filing for review and comment prior to the filing. The filing of the information filing does not re-open the formula rate set forth below for review, but rather is contestable only with respect to the accuracy of the information contained in the informational filing. The System Operator shall independently audit the charges in effect for the period June 1997 through May 2000 for charges under this Attachment, or direct that an audit[s] be conducted under its supervision by an independent third party, and shall have the discretion to conduct such audits of charges in effect beyond May 2000. I. DEFINITIONS Capitalized terms not otherwise defined in Section 1 of the NEPOOL Tariff and as used in this rule have the following definitions: A. ALLOCATION FACTORS 1. Transmission Wages and Salaries Allocation Factor shall equal the ratio of Transmission-related direct wages and salaries including those of affiliated Companies to the Transmission Provider's total direct wages and salaries including those of the affiliates Companies and excluding administrative and general wages and salaries. 2. PTF Transmission Plant Allocation Factor shall equal the ratio of PTF Transmission Plant to Total Investment in Transmission Plant, excluding capital leases in the Hydro-Quebec DC Facilities (HQ Leases). 3. Plant Allocation Factor shall equal the ratio of the sum of Total Investment in Transmission Plant, excluding HQ leases, and Transmission Related General Plant to Total Plant in service excluding HQ Leases. B. TERMS Administrative and General Expense shall equal the Transmission Provider's expenses as recorded in FERC Account Nos. 920-935, excluding FERC Account Nos. 924, 928 and 930.1. Amortization of Loss on Reacquired Debt shall equal the Transmission Provider's expenses as recorded in FERC Account No. 428.1. Amortization of Investment Tax Credits shall equal the Transmission Provider's credits as recorded in FERC Account No. 411.4. Depreciation Expense for Transmission Plant shall equal the Transmission Provider's transmission expenses as recorded in FERC Account No. 403. General Plant shall equal the Transmission Provider's gross plant balance as recorded in FERC Account Nos. 389-399. General Plant Depreciation Expense shall equal the Transmission Provider's general expenses as recorded in FERC Account No. 403. General Plant Depreciation Reserve shall equal the Transmission Provider's general reserve balance as recorded in FERC Account No. 108. Hydro-Quebec DC Facilities (HQ Leases) shall equal the Transmission Provider's balance in capital leases as recorded in FERC Account Nos. 350-359 and FERC Account Nos. 389-399. Other Regulatory Assets/Liabilities - FAS 106 shall equal the net of the Transmission Provider's FAS106 balance as recorded in FERC Account 182.3 and any FAS 106 balance as recorded in the Transmission Provider's FERC Account No. 254. Other Regulatory Assets/Liabilities - FAS 109 shall equal the net of the Transmission Provider's FAS 109 balance in FERC Account No. 182.3 and any FAS 109 balance as recorded in the Transmission Provider's FERC Account No. 254. Payroll Taxes shall equal those payroll expenses as recorded in the Transmission Provider's FERC Account Nos. 408.1 and 409.1. Plant Held for Future Use shall equal the Transmission Provider's balance in FERC Account No.105. Prepayments shall equal the Transmission Provider's prepayment balance as recorded in FERC Account No. 165. Property Insurance shall equal the Transmission Provider's expenses as recorded in FERC Account No. 924. PTF Transmission Plant Investment shall equal the Transmission Provider's transmission plant as defined in the Section 15.1 of the Restated NEPOOL Agreement and determined in accordance with Attachment 1.5 of this rule, which is entitled "Rules for Determining Investment To be Included in PTF." Total Accumulated Deferred Income Taxes shall equal the net of the deferred tax balance as recorded in FERC Account Nos. 281-283 and the deferred tax balance as recorded in FERC Account No. 190. Total Loss on Reacquired Debt shall equal the Transmission Provider's expenses as recorded in FERC Account 189. Total Municipal Tax Expense shall equal the Transmission Provider's municipal tax expenses as recorded in FERC Account Nos. 408.1, 409.1. Total Plant in Service shall equal the Transmission Provider's total gross plant balance as recorded in FERC Account Nos. 301-399. Total Transmission Depreciation Reserve shall equal the Transmission Provider's transmission reserve balance as recorded in FERC Account 108. Transmission Operation and Maintenance Expense shall equal the Transmission Provider's expenses as recorded in FERC Account Nos. 560, 562-564 and 566- 573, and shall exclude all HQ HVDC expenses booked to accounts 560 through 573 and expenses already included in Transmission Support Expense, as described in Section K which are included in FERC Account Nos. 560-573. Transmission Plant shall equal the Transmission Provider's Gross Plant balance as recorded in FERC Account Nos. 350-359. Transmission Plant Materials and Supplies shall equal the Transmission Provider's balance as assigned to transmission, as recorded in FERC Account No. 154. II. CALCULATION OF TRANSMISSION REVENUE REQUIREMENTS The Transmission Revenue Requirement shall equal the sum of the Transmission Provider's (A) Return and Associated Income Taxes, (B) Transmission Depreciation Expense, (C) Transmission Related Amortization of Loss on Reacquired Debt, (D) Transmission Related Amortization of Investment Tax Credits, (E) Transmission Related Municipal Tax Expense, (F) Transmission Related Payroll Tax Expense, (G) Transmission Operation and Maintenance Expense, (H) Transmission Related Administrative and General Expenses, (I) Transmission Related Integrated Facilities Charges, minus (J) Transmission Support Revenue, plus (K) Transmission Support Expense, plus (L) Transmission-Related Expense from Generators, plus (M) Transmission Related Taxes and Fees Charge, minus (N) Revenue for Short-Term Transmission Service under the NEPOOL Tariff and (O) Transmission Rents Received from Electric Property. A. Return and Associated Income Taxes shall equal the product of the Transmission Investment Base and the Cost of Capital Rate. 1. Transmission Investment Base The Transmission Investment Base will be the year end balances of (a) PTF Transmission Plant, plus (b) Transmission Related General Plant, plus (c) Transmission Plant Held for Future Use, less (d) Transmission Related Depreciation Reserve, less (e) Transmission Related Accumulated Deferred Taxes, plus (f) Transmission Related Loss on Reacquired Debt, plus (g) Other Regulatory Assets/Liabilities, plus (h) Transmission Prepayments, plus (i) Transmission Materials and Supplies, plus (j) Transmission Related Cash Working Capital. (a) PTF Transmission Plant will equal the balance of the Transmission Provider's PTF Investment in Transmission Plant excluding (i) the Transmission Provider's capital leases in the Hydro-Quebec DC Facilities (HQ Leases), (ii) the portion of any facilities, the cost of which is directly assigned under Schedule 11 to the Tariff, to the Transmission Customer or a Generator Owner or Interconnection Requester, (iii) the Pre-1997 PTF gross plant investment associated with leased facilities occupied by the Phase II HVDC facilities. (b) Transmission Related General Plant shall equal the Transmission Provider's balance of investment in General Plant multiplied by the Transmission Wages and Salaries Allocation Factor and the PTF Transmission Plant Allocation Factor. (c) Transmission Plant Held for Future Use shall equal the balance of Transmission-related Plant Held for Future Use multiplied by the PTF Transmission Plant Allocation Factor. (d) Transmission Related Depreciation Reserve shall equal the balance of Total Transmission Depreciation Reserve, plus the balance of Transmission Related General Plant Depreciation Reserve. Transmission Related General Plant Depreciation Reserve shall equal the product General Plant Depreciation Reserve and the Transmission Wages and Salaries Allocation Factor. This sum shall be multiplied by the PTF Transmission Plant Allocation Factor. (e) Transmission Related Accumulated Deferred Taxes shall equal the Transmission Provider's electric balance of Total Accumulated Deferred Income Taxes, multiplied by the Plant Allocation Factor, further multiplied by the PTF Transmission Plant Allocation Factor. (f) Transmission Related Loss on Reacquired Debt shall equal the Transmission Provider's electric balance of Total Loss on Reacquired Debt multiplied by the Plant Allocation Factor, further multiplied by the PTF Transmission Plant Allocation Factor. (g) Other Regulatory Assets/Liabilities shall equal the Transmission Provider's electric balance of any deferred rate recovery of FAS 106 expenses multiplied by the Transmission Wages and Salaries Allocation Factor, plus the Transmission Provider's electric balance of FAS 109 multiplied by the Plant Allocation Factor. This sum shall be multiplied by the PTF Transmission Plant Allocation Factor. (h) Transmission Prepayments shall equal the Transmission Provider's electric balance of prepayments multiplied by the Transmission Wages and Salaries allocator and further multiplied by the PTF Transmission Plant Allocation Factor. (i) Transmission Materials and Supplies shall equal the Transmission Provider's electric balance of Transmission Plant Materials and Supplies, multiplied by the PTF Transmission Plant Allocation Factor. (j) Transmission Related Cash Working Capital shall be a 12.5% allowance (45 days/360 days) of Transmission Operation and Maintenance Expense, Transmission Related Administrative and General Expense and Transmission Support Expense, to the extent that Transmission Support Expense exceeds Transmission Support Revenue included in Paragraph J of the formula. 2. Cost of Capital Rate The Cost of Capital Rate will equal (a) The Transmission Provider's Weighted Cost of Capital, plus (b) Federal Income Tax plus (c) State Income Tax. (a) The Weighted Cost of Capital will be calculated based upon the capital structure at the end of each year and will equal the sum of: (i) the long-term debt component, which equals the product of the actual weighted average embedded cost to maturity of the Transmission Provider's long-term debt then outstanding and the ratio that long-term debt is to the Transmission Provider's total capital. (ii) the preferred stock component, which equals the product of the actual weighted average embedded cost to maturity of the Transmission Provider's preferred stock then outstanding and the ratio that preferred stock is to the Transmission Provider's total capital. (iii) the return on equity component, which shall be determined as follows: (1) For each year during the period March 1, 1997 through May 31, 2000, the return on equity component for each of the Transmission Providers identified below shall be the product of the Transmission Provider's Return on Equity ("ROE") as set forth below and the ratio that common equity is to the Transmission Provider's total capital: Bangor Hydro-Electric Company 11.5% Boston Edison Company 10.65% Central Maine Power Company 11.00% Commonwealth Electric Company 10.75% Eastern Utilities Associates 11.22% (through May 31, 1999) 10.65% (beginning June 1, 1999) New England Electric System 10.65% The United Illuminating Company 11.5% (through May 31, 1999) 10.75% (beginning June 1, 1999) Vermont Electric Company 11.50% Northeast Utilities 11.75% (2) For each year during the period commencing June 1, 2000, the return on equity component shall be determined in the same manner, and the allowed ROE for each Transmission Provider identified above shall remain in effect for purposes of such determination for the Provider until an amendment to its cost of service under the Local Network Service Tariff for the Provider filed after December 31, 1999 results in a different allowed ROE for that Provider, in which case that Provider's ROE shall be set for purposes of such determination at the ROE ultimately determined to be just and reasonable in the proceeding involving the applicable Local Network Service Tariff amendment. (b) Federal Income Tax shall equal (A+[(C+B)/D])(FT) 1 - FT where FT is the Federal Income Tax Rate and A is the sum of the preferred stock component and the return on equity component, as determined in Sections II.A.2.(a)(ii) and (iii) above, B is Transmission Related Amortization of Investment Tax Credits, as determined in Section II.D., below, C is the Equity AFUDC component of Transmission Depreciation Expense , as defined in Section II.B., and D is Transmission Investment Base, as determined in II.A.1., above. (c) State Income Tax shall equal (A+[(C+B)/D] + Federal Income Tax)(ST) 1 - ST where ST is the State Income Tax Rate, A is the sum of the preferred stock component and return on equity component determined in Sections II.A.2.(a)(ii) and (iii) above, B is the Amortization of Investment Tax Credits as determined in Section II.D. below, C is the equity AFUDC component of Transmission Depreciation Expense, as defined in Section II.B., D is the Transmission Investment Base, as determined in II.A.1., above and Federal Income Tax is the rate determined in Section II.A.2.(b) above. B. Transmission Depreciation Expense shall equal the PTF Transmission Plant Allocation Factor, multiplied by the sum of Depreciation Expense for Transmission Plant, plus an allocation of General Plant Depreciation Expense calculated by multiplying General Plant Depreciation Expense by the Transmission Wages and Salaries Allocation Factor. C. Transmission Related Amortization of Loss on Reacquired Debt shall equal the Transmission Provider's electric Amortization of Loss on Reacquired Debt multiplied by the Plant Allocation Factor, and further multiplied by the PTF Transmission Plant Allocation Factor. D. Transmission Related Amortization of Investment Tax Credits shall equal the Transmission Provider's electric Amortization of Investment Tax Credits multiplied by the Plant Allocation Factor, and further multiplied by the PTF Transmission Plant Allocation Factor. E. Transmission Related Municipal Tax Expense shall equal the Transmission Provider's total electric municipal tax expense multiplied by the Plant Allocation Factor, and further multiplied by the PTF Transmission Plant Allocation Factor. F. Transmission Related Payroll Tax Expense shall equal the Transmission Provider's total electric payroll tax expense, multiplied by the Transmission Wages and Salaries Allocation Factor, further multiplied by the PTF Transmission Plant Allocation Factor. G. Transmission Operation and Maintenance Expense shall equal Transmission Operation and Maintenance Expenses multiplied by the PTF Transmission Plant Allocation Factor. H. Transmission Related Administrative and General Expenses shall equal the sum of (1) Transmission Provider's Administrative and General Expenses multiplied by the Transmission Wages and Salaries Allocation Factor, (2) Property Insurance multiplied by the Transmission Plant Allocation Factor, and (3) Expenses included in Account 928 related to FERC Assessments multiplied by Plant Allocation Factor, plus any other Federal and State transmission related expenses or assessments, plus specific transmission related expenses included in Account 930.1. This sum shall be multiplied by the PTF Transmission Plant Allocation Factor. I. Transmission Related Integrated Facilities Charges shall equal the Transmission Provider's transmission payments to affiliates for use of the PTF integrated transmission facilities of those affiliates. J. Transmission Support Revenues shall equal the Transmission Provider's revenue received for PTF transmission support but excluding the support payments to Transmission Providers or their designee pursuant to Schedule 11 and excluding the support payments to Transmission Providers or their designee pursuant to Schedule 12 Part 1(a), Part 1(b), Part 2 and Part 3, and excluding support payments, if any, made to Transmission Owners or their respective designee pursuant to Part III of this Tariff. K. Transmission Support Expense shall equal the expense paid by Transmission Providers or Transmission Customers for PTF transmission support other than expenses for payments made for congestion rights or for transmission facilities or facility upgrades placed in service on or after January 1, 1997, where the support obligation is required to be borne by particular Participants or other entities in accordance with the NEPOOL Tariff. Transmission Support Expenses by any entity other than an LNS Transmission Provider, included in this provision, shall be capped at that entity's annual payment for Regional Network Service or its Point to Point Service for each individual Point to Point transaction from the resource with which the support payment is associated. For the purpose of establishing this cap, for the first five years of the Transition Period the annual payment for RNS and Internal Point-to-Point shall be recalculated at the Pool PTF rate. L. Transmission-Related Expense from Generators shall equal the expenses from generators that both (1) the Management Committee determines should be included as transmission expense as a result of the impact of such generators on reducing transmission costs that would otherwise be required to be paid by Transmission Customers and (2) are reflected in a filing made by NEPOOL with the Commission under Section 205 of the Federal Power Act and accepted by the Commission for recovery under the NEPOOL Tariff. M. Transmission Related Taxes and Fees Charge shall include any fee or assessment imposed by any governmental authority on service provided under this Section which is not specifically identified under any other section of this rule. N. Revenues for Short-term Transmission Service under the NEPOOL Tariff shall be revenues distributed to each Participant, from NEPOOL, for short term service provided under the NEPOOL Tariff, received after March 1, 1999. These revenues will be credited pro-rata between pre-1997 and post-1996 PTF revenue requirements in proportion to pre-1997 and post-1996 PTF Transmission Plant. O. Transmission Rents Received from Electric Property shall equal any Account 454 Rents from electric property, associated with PTF Transmission Plant as defined in Section II.A.1.(a) above but not reflected as a credit in Transmission Support Revenues in paragraph K of this Attachment. EX-10.45.3 6 0006.txt EXHIBIT 10.45.3 CONFIDENTIAL SEPARATION AGREEMENT AND GENERAL RELEASE THIS AGREEMENT, made and entered into as of this 20th day of December, 2000, by and between Northeast Utilities Service Company, a Connecticut corporation, with its principal office in Berlin, Connecticut, (together with each direct and indirect affiliated company that has adopted the Employment Agreement entered into on February 25, 1997 (the "Employment Agreement"), with Northeast Utilities Service Company, hereinafter, the "Company"), and Hugh C. MacKenzie, a resident of Madison, Connecticut ("Executive"). W I T N E S S E T H: WHEREAS, the Company had heretofore employed Executive under the Employment Agreement; and WHEREAS, Executive's employment has been terminated upon a Change in Control, as that phrase is defined in the Employment Agreement, effective December 31, 2000, and the Notice of Termination, required by Section 6.2 of the Employment Agreement, is hereby waived; and WHEREAS, the Company and Executive wish to enter into an agreement to provide for a mutual release as to any claims including, without limitation, claims that might be asserted by Executive under the Employment Agreement and the Age Discrimination in Employment Act, as further described herein, and reaffirm Executive's right to indemnification; NOW, THEREFORE, in consideration of the mutual promises contained herein, the parties hereto, intending to be legally bound, hereby agree as follows: 1. The Company and Executive hereby agree that Executive's termination upon a Change in Control, as that phrase is defined in the Employment Agreement, shall be effective on December 31, 2000 and that the Notice of Termination required by Section 6.2 of the Employment Agreement is hereby waived. The Company and Executive further agree that the Employment Agreement shall continue only to the extent provided therein as to obligations that survive the termination of Executive's employment. 2. Executive agrees and acknowledges that the Company, on a timely basis, has paid, or agreed to pay, to Executive all other amounts due and owing based on Executive's prior services in accordance with the terms of the Employment Agreement or any other contract with Executive, whether express or implied, and that the Company has no obligation, contractual or otherwise to Executive, except as provided herein, in the Employment Agreement or any other such contract with Executive, nor does it have any obligation to hire, rehire or re-employ Executive in the future. Notwithstanding the foregoing, nothing contained in this Agreement -1- shall prevent Executive from requiring the Company to fulfill its obligations under this Agreement, under the Employment Agreement, to the extent of any continuing obligations thereunder, under any employee benefit plan, as defined in Section 3(3) of ERISA, maintained by the Company and in which Executive participated, or any other contract with Executive, whether express or implied. 3. In full and complete settlement of any claims that Executive may have against the Company, including any possible violations of the Age Discrimination in Employment Act ("ADEA"), 29 U.S.C.ss.621, et seq., in connection with Executive's termination of employment, and for and in consideration of the undertakings of the Company described herein, Executive does hereby REMISE, RELEASE, AND FOREVER DISCHARGE the Company, and each of its past, present and future subsidiaries and affiliates, their officers, directors, shareholders, partners, employees and agents, and their respective successors and assigns, heirs, executors and administrators (hereinafter all included within the term "the Company"), of and from any and all manner of actions and causes of actions, suits, debts, claims and demands whatsoever in law or in equity, which Executive ever had, now has, or hereafter may have, or which Executive's heirs, executors or administrators hereafter may have, by reason of any matter, cause or thing whatsoever from the beginning of Executive's employment to the termination of Executive's employment; and particularly, but without limitation of the foregoing general terms, any claims arising from or relating in any way to Executive's employment relationship or the Employment Agreement to the extent of any obligation that does not survive Executive's termination of employment and Executive's termination from that employment relationship, including but not limited to, any claims which have been asserted, could have been asserted, or could be asserted now or in the future under any federal, state or local laws, including any claims under the Age Discrimination in Employment Act ("ADEA"), 29 U.S.C.ss.621, et seq., and the Older Workers' Benefit Protection Act, 29 U.S.C.ss.626(f)(1), and any claims under Section 210 or Section 211 of the Energy Reorganization Act of 1974, 42 U.S.C.ss.5851, the National Energy Policy Act of 1992, Pub. L. No. 102-486, Title VII of the Civil Rights Act of 1964, 42 U.S.C.ss. 2000e, et seq., the Labor Management Relations Act, the Employee Retirement Income Security Act of 1974 ("ERISA"), the Rehabilitation Act of 1973, the Civil Rights Act of 1991, the Americans with Disabilities Act ("ADA"), 42 U.S.C.ss.12101, et seq., the Family and Medical Leave Act of 1993, 29 U.S.C.ss.2601, et seq., the Fair Labor Standards Act, the National Labor Relations Act, the Connecticut Fair Employment Practices Act, Conn. Gen. Stat.ss.ss.46a-60 - 46a-62 (1995), and any other federal, state, or local statute, ordinance, regulation, rule of decision or common law recognized now or in the future and all claims for counsel fees and costs. Notwithstanding the foregoing, nothing contained in this Agreement shall prevent Executive from requiring the Company to fulfill its obligations under this Agreement, under the Employment Agreement, to the extent of any continuing obligations thereunder, under any employee benefit plan, as defined in Section 3(3) of ERISA, maintained by the Company and in which Executive participated, or any other contract with Executive, whether express or implied. 4. Nothing in this Agreement shall be construed to prohibit or otherwise discourage Executive from reporting, providing testimony regarding, cooperating in, or otherwise communicating any suspected instance of illegal activity of any nature, any nuclear -2- safety concern, workplace safety concern, or public safety concern to the U.S. Nuclear Regulatory Commission, the U.S. Department of Labor, or any federal or state government agency, or any matter involving the substantial misfeasance, malfeasance or nonfeasance in the management of the Company to the Connecticut Department of Public Utility Control. The parties further acknowledge, understand, and agree that the provisions of this Agreement are not intended to restrict Executive's communication with, or full cooperation in proceedings or investigations by, any agency relating to nuclear regulatory or safety issues, or any matter involving the substantial misfeasance, malfeasance or nonfeasance in the management of the Company. 5. Nothing in this Agreement shall limit or impair any right Executive may otherwise have to indemnity and defense by the Company, and, notwithstanding any contrary provision of this Agreement, (i) the Company shall indemnify and defend Executive in connection with any action, suit or proceeding in which Executive may be involved or with which Executive may be threatened by reason of Executive's being or having been an officer of the Company or by reason of Executive's being or having been a fiduciary of the Company's employee benefit plans in the same manner contemplated by (including the payment or advancement of any reasonable expenses as incurred) and to the fullest extent permitted by the Declaration of Trust of Northeast Utilities as of the date hereof, unless later limited in accordance with applicable law, or under applicable law, (in which case Executive shall notify the Company within five business days after receiving service of process as to the commencement of the action, suit or proceeding and give the Company the right to control the defense of any such action, suit or proceeding, provided that no delay in giving such notice shall result in a forfeiture of any rights by Executive unless, and then only to the extent that, the Company is actually prejudiced by such delay), and (ii) Executive may join the Company in any action, suit or proceeding, or bring any action, suit or proceeding against the Company, as may be necessary for the protection or enforcement of such rights of indemnification and defense by the Company. 6. Except to the extent permitted by paragraph 3, Executive further agrees and covenants that neither Executive, nor any person, organization or other entity on Executive's behalf, will file, charge, claim, sue or cause or permit to be filed, charged, or claimed, any action for damages, including injunctive, declaratory, monetary or other relief against the Company, involving any matter occurring at any time in the past up to the effective date of this Agreement, or involving any continuing effects of any actions or practices which may have arisen or occurred prior to the date of this Agreement, including any charge of retaliation or discrimination under the ADEA, Title VII, the ADA, the Workers' Compensation Act or federal, state or local laws. In addition, Executive further agrees and covenants that should Executive, or any other person, organization or entity on Executive's behalf, file, charge, claim, sue or cause or permit to be filed, charged, or claimed, any action for damages, including injunctive, declaratory, monetary or other relief, despite Executive's agreement not to do so under this Agreement, or should Executive otherwise fail to abide, in any material respect, by any of the terms of this Agreement, then the Company will be relieved of all further obligations owed under the Employment Agreement and this Agreement, Executive will forfeit all monies paid to Executive under the Employment Agreement following Executive's termination of employment and Executive will -3- pay all of the costs and expenses of the Company (including reasonable attorneys' fees) incurred in the defense of any such action or undertaking. 7. In full and complete settlement of any claims that the Company may have against Executive, other than the fulfillment of Executive's obligations under this Agreement or under the Employment Agreement, and for and in consideration of the undertakings of Executive described herein, the Company does hereby REMISE, RELEASE, AND FOREVER DISCHARGE Executive and Executive's heirs, executors and administrators (hereinafter all included within the term "Executive"), of and from any and all manner of actions and causes of actions, suits, debts, claims and demands whatsoever in law or in equity, which the Company ever had, now has, or hereafter may have, by reason of any civil (but specifically not any criminal act) matter, cause or thing whatsoever by reason of Executive's being or having been an officer of the Company from the beginning of Executive's employment with the Company to the date of termination of employment; and particularly, but without limitation of the foregoing general terms, any claims arising from or relating in any way to actions taken by Executive by reason of Executive's being or having been an officer of the Company and Executive's termination from those relationships with the Company. 8. The Company further agrees and covenants that neither it, nor any person, organization or other entity on its behalf, will file, charge, claim, sue or cause or permit to be filed, charged, or claimed, any action for damages, including injunctive, declaratory, monetary or other relief against Executive, involving any matter occurring at any time in the past up to the date of this Agreement, or involving any continuing effects of any actions or practices which may have arisen or occurred prior to the date of this Agreement, by reason of Executive's being or having been an officer of the Company, so long as Executive meets, in all material respects, Executive's obligations under this Agreement and the Employment Agreement. In addition, the Company further agrees and covenants that should it, or any other person, organization or entity on its behalf, file, charge, claim, sue or cause or permit to be filed, charged, or claimed, any action for damages, including injunctive, declaratory, monetary or other relief, despite its agreement not to do so under this Agreement, then it will pay all of the costs and expenses of Executive (including reasonable attorneys' fees) incurred in the defense of any such action or undertaking. 9. Executive hereby agrees and acknowledges that under this Agreement, the Company has agreed to provide Executive with compensation , benefits, and covenants that are in addition to that which Executive otherwise would have been entitled under the Employment Agreement or otherwise in the absence of this Agreement, and that such additional compensation and covenants are sufficient to support the covenants and agreements by Executive herein. 10. Executive and the Company, its officers and directors, will not, disparage the name, business reputation or business practices of the other. In addition, by signing this Agreement, Executive agrees not to pursue any internal grievance with the Company. 11. Executive hereby certifies that Executive has read the terms of this -4- Agreement, that Executive has been advised by the Company to consult with an attorney and that Executive understands its terms and effects. Executive acknowledges, further, that Executive is executing this Agreement of Executive's own volition, without any threat, duress or coercion and with a full understanding of its terms and effects and with the intention, as expressed in paragraph 3 hereof, of releasing all claims recited herein in exchange for the consideration described herein, which Executive acknowledges is adequate and satisfactory to Executive. The Company has made no representations to Executive concerning the terms or effects of this Agreement other than those contained in this Agreement. 12. Executive hereby acknowledges that Executive was presented with this Agreement on December 20, 2000, and that Executive was informed that Executive had the right to consider this Agreement and the release contained herein for a period of at least twenty-one (21) days prior to execution. Executive also understands that Executive has the right to revoke this Agreement for a period of seven (7) days following execution, by giving written notice to the Senior Vice President, Secretary, and General Counsel for the Company at 107 Selden Street, Berlin, CT 06037, in which event the provisions of this Agreement shall be null and void, and the parties shall have the rights, duties, obligations and remedies afforded by applicable law. 13. This Agreement shall be interpreted and enforced under the laws of the State of Connecticut. IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day and year first above written. ATTEST: NORTHEAST UTILITIES SERVICE COMPANY By: /s/ CHERYL W. GRISE - --------------------------------- ------------------------------------- Witness Cheryl W. Grise Senior Vice President, Secretary and General Counsel /s/ HUGH C. MACKENZIE - --------------------------------- ------------------------------------- Witness Hugh C. MacKenzie -5- EX-10.51.3 7 0007.txt EXHIBIT 10.51.3 As of September 27, 2000 CL&P Receivables Corporation 107 Selden Street Berlin, Connecticut 06037 Re: Fee Agreement Ladies and Gentlemen: This letter agreement will serve to confirm our respective understandings regarding certain of the fees to be paid pursuant to Section 2.05(a) of the Receivables Purchase and Sale Agreement, dated as of the date hereof, as amended (the "Receivables Purchase Agreement"), among The Connecticut Light and Power Company, a Connecticut corpo-ra-tion, as Collection Agent and Originator, CL&P Receivables Corporation, a Connecticut corporation, as Seller, Corporate Asset Funding Company, Inc., a Delaware corporation, Citibank, N.A., and Citicorp North America, Inc., a Delaware corporation, as Agent for the Purchasers and the Banks, as the same may be amended, modified or supple-mented from time to time. Unless otherwise defined herein, capitalized terms used herein shall have the meanings set forth in the Receivables Purchase Agreement. The fees referred to in Section 2.05(a) of the Receivables Purchase Agreement are the following: 1. The Seller shall pay to the Agent a program fee (the "Program Fee") on the unpaid Capital outstanding from time to time at the per annum rate of 0.125 percent. 2. The Seller shall pay to the Agent a purchaser fee (the "Purchaser Fee") on the unpaid Capital outstanding from time to time at the per annum rate of 0.02 percent. 3. The Seller shall pay to the Agent a fee (the "Investor Investment Fee") for the account of the Conduit on the amount of the entire Purchase Limit (whether used or unused) at the per annum rate of 0.01 percent. 4. The Seller shall pay to the Agent a liquidity fee (the "Liquidity Fee") on the entire Purchase Limit (whether used or unused) at a per annum rate equal to the amount set forth below opposite the actual ratings for the Originator's long-term public senior unsecured debt from time to time: Public Debt Rating by Standard and Poor's and Moody's Fee BBB-/Baa3 (or higher) 0.20 percent BB+/Ba1 (or below) 0.325 percent In the event that the Standard & Poor's and Moody's ratings do not correlate as shown above, the lower rating shall be used to determine the Liquidity Fee. All fees are payable in arrears on each Settlement Date during the term of the Receivables Purchase Agreement until the later of the Facility Termination Date or the date on which the Capital and Yield of all Receivable Interests have been paid in full. The Seller shall pay such fees to the Agent by deposit of the appropriate amounts in a special account (account number 4063- 6695) maintained with Citibank at its address specified on the signature page to the Receivables Purchase Agreement. This letter replaces the Fee Agreement between the parties dated as of September 30, 1997, as amended, and applies to fees accruing from and after the date hereof. If the foregoing accurately reflects your under-standing, please sign and return the duplicate copy of this letter. Very truly yours, CITICORP NORTH AMERICA, INC., as Agent By: Name: Title: 450 Mamaroneck Avenue Harrison, NY 10528 Attn: Corporate Asset Funding Facsimile No: 914-899-7890 Agreed and accepted as of the date first above written: CL and P RECEIVABLES CORPORATION By: Name: Title: 107 Selden Street Berlin, Connecticut 06037 Attn: Assistant Treasurer Facsimile No: (860) 665-5457 EX-10.52 8 0008.txt EXHIBIT 10.52 January 2, 2001 Northeast Utilities 107 Selden Street Berlin, CT 06037 Credit Suisse First Boston International One Cabot Square London E14 4QJ Dear Sirs: The purpose of this letter agreement (this "Confirmation") is to confirm the terms and conditions of the Transaction entered into between Party A and Party B through the Arranging Agent on the Trade Date specified below (the "Transaction"). This Confirmation constitutes a "Confirmation" as referred to in the Agreement specified below. This Confirmation amends, restates and supersedes in its entirety the Confirmation dated November 3, 1999 between the parties hereto. 1. The definitions and provisions contained in the 1991 ISDA Definitions (the "1991 Swap Definitions"), as supplemented by the 1998 Supplement to the 1991 Swap Definitions (the "Swap Definitions") and in the 1996 ISDA Equity Derivatives Definitions (the "Equity Definitions", together with the Swap Definitions, the "Definitions") (in each case as published by the International Swaps and Derivatives Association, Inc.) are incorporated into this Confirmation. In the event of any inconsistency between the Swaps Definitions and the Equity Definitions, the Equity Definitions will govern, and between the Definitions and the provisions and this Confirmation, this Confirmation will govern. References herein to a "Transaction" shall be deemed to be references to a "Swap Transaction" for the purposes of the Swap Definitions. If Party A and Party B are parties to the 1992 ISDA Master Agreement (the "Agreement"), this Confirmation supplements, forms a part of, and is subject to such Agreement. If Party A and Party B are not yet parties to the Agreement, they agree to use their best efforts promptly to negotiate, execute, and deliver the Agreement through the Arranging Agent, including Party A's standard form of Schedule and Addendum for Physical Delivery of Shares attached thereto and made a part thereof, with such modifications as Party A and Party B shall in good faith agree. Upon execution and delivery by Party A and Party B of the Agreement, this Confirmation shall supplement, form a part of, and be subject to such Agreement. Until Party A and Party B execute and deliver the Agreement, this Confirmation (together with all other Confirmations of Transactions previously entered into between them, notwithstanding anything to the contrary therein) shall supplement, form a part of, and be subject to the 1992 ISDA Master Agreement, as if, on the Trade Date of the first such Transaction between them, Party A and Party B had executed that agreement (incorporating therein Party A's standard form of Schedule and Addendum for Physical Delivery of Shares) and had specified that the Automatic Early Termination provisions contained in Section 6(a) of such agreement would apply. The Agreement and each Confirmation thereunder will be governed by and construed in accordance with the laws of the State of New York without reference to choice of law doctrine. Party A and Party B expressly acknowledge that, in reliance upon the other party's entering into the Transaction evidenced by this Confirmation, each party has made (or refrained from making) substantial financial commitments and has taken (or refrained from taking) other material actions. All payments in connection with this Transaction shall be made in U.S. Dollars. In this Confirmation, "Party A" means Credit Suisse First Boston International, "Party B" means Northeast Utilities and "Arranging Agent" means Credit Suisse First Boston Corporation, acting solely in its capacity as Arranging Agent for both Party A and Party B. 2. The terms of the Transaction to which this Confirmation relates are as follows: General Terms: Trade Date: November 3, 1999 Effective Date: November 3, 1999 Termination Date: June 29, 2001, subject to adjustment in accordance the Following Business Day Convention, the terms of the Party B Net Settlement Option, the Party A Optional Termination and the Party B Optional Termination. Transaction Type: Equity Forward Seller: Party A Buyer: Party B (sometimes also referred to as the "Issuer"). Shares: Common Shares, par value 5.00 dollars, of Party B. Closing Price on the Exchange As of the Business Day Prior To the Trade Date: 21.0625 dollars Notional Amount: Initially, an amount equal to the Accumulated Adjusted Principal Share Amount, up to an amount equal to the Principal Share Amount, in each case multiplied by the Initial Share Price. Principal Share Amount: The number of Shares that represent purchase prices in an aggregate principal amount of 100,000,000 dollars. Accumulated Adjusted Principal Share Amount: On any Valuation Date during the Initial Pricing Period the aggregate number of Shares purchased by Party A up to the Principal Share Amount, for which full payment has been made by Party A. Initial Share Price: The weighted average of the Average Share Prices for all Valuation Dates occurring during the Initial Pricing Period or, if the last day of a Calculation Period shall occur prior to the completion of the Initial Pricing Period, the weighted average of the Average Share Price for all Valuation Dates occurring to and including the last day of the relevant Calculation Period. Average Share Price: For any Valuation Date, the weighted average price of the Shares purchased by Party A on such Valuation Date (plus a 0.04 per share commission charged by Party A). Initial Pricing Period: The earlier to occur of (i) the Business Day that is 22 trading days prior to the acquisition by Party B of Yankee Energy System, Inc. pursuant to the terms of the Agreement and Plan of Merger dated as of June 14, 1999 between Yankee Energy System, Inc. and Party B (the "Merger Agreement"), which acquisition is currently expected to be April 15, 2000, subject to extension to such later date as is permitted by the Merger Agreement, and for which Party B has provided written notice to Party A through the Arranging Agent and (ii) the Exchange Business Day on which Shares with an aggregate purchase price of 100,000,000 dollars have been purchased. Valuation Date: In respect of the Initial Pricing Period, any Exchange Business Day on which a Market Disruption Event has not occurred. In respect of the Final Pricing Period, any Exchange Business Day on which a Registration Suspension Event or Market Disruption Event has not occurred. Exclusion Period: The first minute of trading and the last one-half hour before the scheduled close of trading on the Exchange. Calculation Period: The period from and including a Calculation Period Interest Reset Date to but excluding the next succeeding Calculation Period Interest Reset Date, provided that, the first Calculation Period Interest Reset Date will commence on the Effective Date and the final Calculation Interest Period will end on and exclude the Termination Date. Calculation Period Interest Reset Dates: The 15th day of each February, May, August and November, commencing on November 15, 1999. Party A Calculation Period Payment Dates: The 15th day of each February, May, August and November, commencing on November 15, 1999. Party A Payment: The Dividend Amount (as defined below). Party B Calculation Period Payment Dates: The 15th day of each February, May, August and November, commencing on November 15, 1999. Party B Payment: An amount in U.S. Dollars equal to the Interest Amount determined as of the relevant Party B Calculation Period Payment Date. Floating Rate Option: USD-LIBOR-BBA Spread: 2.5 percent per annum Designated Maturity: 3 months Interest Amount/Net Interest Amount: The payment obligation of Party A and Party B on such Calculation Period Payment Dates in respect of the Dividend Amount (defined below) and any Interest Amounts shall be netted, such that the party obligated to pay the greater amount shall pay to the other party, through the Agent, an amount equal to the difference between such amounts (the "Net Interest Amount"). For each Calculation Period during the Initial Pricing Period, an amount equal to the product of (i) the weighted average Notional Amount for such Calculation Period and (ii) USD-LIBOR-BBA, plus Spread, and for each Calculation Period thereafter, the product of the Notional Amount and ISD-LIBOR-BBA, plus Spread (subject to adjustment in all cases in accordance with the Following Business Day Convention). In the case either Net Cash Settlement or Net Share Settlement has been designated as the Method of Settlement, the Notional Amount (and the accrued interest attributable thereto) shall be reduced during the Final Reference Share Price Pricing Period by amounts equal to the Net Proceeds (defined below) received by the Selling Agent in respect to sales of the Shares, which reduction shall occur on the Business Day on which such Net Proceeds are received as immediately available funds by the Selling Agent. The Calculation Agent may rely on the information provided pursuant to "(D)-Physical Settlement" hereunder unless the Selling Agent delivers notice of any failure to receive an anticipated payment in respect of the Shares sold or because of any Settlement Disruption Event or an amendment to the time of payment in respect of any Shares sold. Dividend Amount: An amount in USD equal to the sum of: (i) The aggregate amount in respect of all dividends declared by the Issuer to which the record holder of the Principal Share Amount (provided, however, that for purpose of determining the Dividend Amount in the case either Net Cash Settlement or Net Share Settlement has been designated as the Method of Settlement, the Principal Share Amount shall be reduced by the number of Shares sold by the Selling Agent prior to the record date in respect of any dividend declared in respect of the Shares during the Final Reference Share Price Pricing Period) would be entitled by virtue of the occurrence of a dividend record date during the period from the Effective Date to the Settlement Date (other than any Lagging Dividend Payment Amount or any dividends resulting in an Adjustment due to a Potential Adjustment Event); and (ii) An amount representing the interest that could have been earned on such dividends described in (i) at a rate equal to USD-LIBOR-BBA for a designated maturity of one month (any non-conforming period shall be linearly interpolated by the Calculation Agent) for the period from the date that such dividends were or would have been received, for which a Party A Calculation Period Payment Date is a compounding date; the applicable compounding rate for each compounding period is USD-LIBOR-BBA with a designated maturity of one month, for which the Day Count Fraction is Actual/360 and the Following Business Day Convention will apply, and for which compounding is applicable to the Settlement Date Lagging Dividend Payment Amount: In the event that a dividend is declared and payable to a holder of record prior to the Settlement Date of this Transaction but such dividend has not been paid on or before such Settlement Date, Party A agrees to pay to Party B through the Arranging Agent an amount equal to the dividends received by Party A in respect of the Number of Shares on the next succeeding Business Day after the payment is received. Day Count Fraction: Actual/360 Additional Party B Payment: On the Effective Date, Party B shall pay to Party A, through the Arranging Agent, a structuring fee equal to 1,250,000 dollars. Party A and Party B Final Payments Termination Settlement Payment Options: In respect of the Termination Date (including, in case any Event of Default or Termination Event has occurred, the related Early Termination Date) Party B shall elect one of the following Settlement Options (each a "Method of Settlement"): (A) Gross Physical Settlement: Unless Party B has specified Net Cash Settlement or Net Share Settlement in accordance with the terms hereof, on the Settlement Date, Party A will through the Arranging Agent, deliver the Principal Share Amount to Party B, and Party B will pay to Party A an amount equal to the sum of (i) the Notional Amount and (ii) the Net Interest Amount. (B) Net Cash Settlement: If Party B has specified Net Cash Settlement as the Method of Settlement, the Selling Agent will sell a number of Shares equal to the Principal Share Amount, in accordance with the terms hereof. On the related Settlement Date, Party A will pay to Party B, an amount in USD equal to the product of the Principal Share Amount and the Final Reference Share Price, and Party B will pay to Party A, through the Arranging Agent, an amount in USD equal to the sum of (i) the Notional Amount and (ii) the Net Interest Amount (which will reduce the amount due from Party B if the Net Interest Amount is negative). The payment obligations of Party A and Party B on such date in respect of such amounts shall be netted, such that the party obligated to pay the greater amount shall pay to the other party, through the Arranging Agent, an amount equal to the difference between such amounts. If Party A is required to pay such differences on such Settlement Date the Selling Agent, from the aggregate Net Proceeds (defined below) of the sales of Shares, will pay such difference to Party B in accordance with the preceding sentence and pay the remainder of such proceeds to Party A. If Party B is obligated to pay such difference, Party B will pay such amount to Party A through the Arranging Agent and the Selling Agent will pay the aggregate Net Proceeds of the sales of Shares to Party A. (C) Net Share Settlement: If Party B has specified Net Share Settlement as the Method of Settlement, the Selling Agent shall sell, in accordance with the terms hereof, such number of Shares from the Principal Share Amount that will generate aggregate Net Proceeds equal to the sum of (i) the Notional Amount, and (ii) the Net Interest Amount. If during the Final Reference Share Price Pricing Period Party A receives aggregate Net Proceeds equal to the sum of (i) the Notional Amount and (ii) the Net Interest Amount (which will reduce the amount due from Party B if the Net Interest Amount is negative) from the sale of a number of Shares that is less than the Principal Share Amount, on the relevant Settlement Date the Selling Agent shall deliver to Party B, a number of Shares equal to the excess of the Principal Share Amount less such number of Shares sold by the Selling Agent during such period (the "Party A Net Share Settlement Delivery"). If during the Final Reference Share Price Pricing Period the Selling Agent sells a number of Shares equal to the Principal Share Amount and Party A receives aggregate Net Proceeds from such sales in an amount that is less than the sum of (i) the Notional Amount and (ii) the Net Interest Amount, Party A shall notify Party B, through the Arranging Agent, of such fact, and by 4:30 p.m. New York time on the second Exchange Business Day following such notification Party B shall deliver a number of additional Shares (which Party A reasonably estimates is equal in value to the Shortfall (defined below)) (the aggregate number of additional Shares, delivered pursuant to this Net Share Settlement methodology, the "Party B Net Share Settlement Delivery") to the Selling Agent, which will be sold by the Selling Agent using the Offering Method determined pursuant to this Confirmation as described below (to the extent that such sales are required to generate aggregate Net Proceeds equal to the excess of (A) the sum of (i) the Notional Amount and (ii) the Net Interest Amount over (B) the aggregate Net Proceeds received by the Selling Agent from the sale of the Principal Share Amount (for purposes of determining the obligation of Party B in connection with Net Share Settlement, the term "Shortfall" at anytime and from time to time means the US Dollar amount by which the sum of (i) the Notional Amount plus (ii) the Net Interest Amount exceeds the aggregate Net Proceeds, if any, actually received from the sale of (i) all or a portion of the Number of Shares plus (ii) additional Shares delivered pursuant to the Party B Net Share Settlement Delivery)). The Selling Agent shall use its best efforts to sell only such additional Shares as shall generate aggregate Net Proceeds equal to the Shortfall and return the excess Shares, if any, to Party B. In the event the additional Shares delivered by Party B to the Selling Agent are sold for an amount that is less than the Shortfall, the Selling Agent shall notify Party B, through the Arranging Agent, of such fact and by 4:30 p.m. New York time on the second Exchange Business Day following such notification Party B shall deliver additional Shares to Party A, through the Arranging Agent, and, subject to Party B's delivery of a Sale Revocation and Designation Notice (defined below) in connection with Physical Settlement (defined below), Party B shall continue to so deliver additional Shares upon notification until the aggregate Net Proceeds received by the Selling Agent from the sale of all such Shares delivered by Party B to Party A results in a Shortfall equal to zero; provided, however, that notwithstanding Party B's obligations set forth in Appendix A hereto, in the event that Party B is required pursuant to this paragraph to deliver additional Shares and is unable to deliver additional Shares which are at the time of delivery duly authorized, validly issued, fully paid and nonassessable and free of any liens, claims or encumbrances (except liens, claims or encumbrances pursuant to this Transaction), or Party B otherwise fails to deliver such additional Shares and such inability or failure continues for five Exchange Business Days (the "Net Share Settlement Incapacity Event"), such Net Share Settlement shall be deemed terminated and Party B shall be obligated to pay Party A within five Business Days from the date of the Net Share Settlement Incapacity Event an amount in cash equal to the amount of the Shortfall that has not been received from the sale of additional Shares as of the date of the Net Share Settlement Incapacity Event and the Selling Agent shall deliver to Party B any additional Shares received in respect of such Shortfall and not sold by the Selling Agent as of the date of the Net Share Settlement Incapacity Event. The term "Net Proceeds" in respect of a sale of Shares shall mean gross proceeds of such sale less reasonable and customary discounts, fees, commissions and expenses (the "Sale Expenses"), including, but not limited to, reasonable commissions, discounts, fees and expenses customarily payable to underwriter(s) in the case of a Registered Offering (defined below) or to a placement agent in the case of an Exempt Offering (defined below), which may include reasonable amounts customarily payable to the Selling Agent acting as underwriter or placement agent, as well as any additional reasonable fees and expenses of any dealers engaged by any such underwriter or placement agent which are customarily payable. (D) Physical Settlement: In the event Party B elects either Net Cash Settlement or Net Share Settlement, the Selling Agent agrees to provide the Calculation Agent and Party B not later than 5:00 PM on any Business Day on which it has sold Shares a report through the Arranging Agent of the number of Shares sold, the average sale price and the aggregate Net Proceeds received by the Selling Agent from such sales and a reasonable breakdown of the Sales Expenses. At any time after the designation of the Method of Sale, and if applicable, the Offering Method, but prior to the execution and delivery of any underwriting agreement with respect to the Shares, Party B may deliver to the Selling Agent and to Party A through the Arranging Agent a revocation of the Net Cash Settlement or Net Share Settlement Method of Settlement and request the suspension of any further sales of Shares in respect of this Transaction by the Selling Agent (a "Sale Revocation and Designation Notice") on the Business Day immediately following delivery of such Sale Revocation and Designation Notice. Receipt of the Sale Revocation and Designation Notice shall obligate the Selling Agent to suspend any sales and solicitations of orders to buy the Shares but shall not affect Party A's obligations to perform any settlement or delivery of Shares in connection with sales previously agreed and sales which are pending agreement on the date such Sale Revocation and Designation Notice is received and which have been agreed before the close of business on such date. Upon receipt of a Sale Revocation and Designation Notice, the Selling Agent shall report to Party B the number of Shares that remain unsold (which may be some or all of the Principal Share Amount and any additional Shares) as of the Business Day succeeding delivery of the Sale Revocation and Designation Notice (the "Remaining Shares"). In the event of delivery of the Sale Revocation and Designation Notice, Party B shall be required to deliver to Party A through the Arranging Agent a cash amount in respect of the Remaining Shares such that the amount paid by Party B to Party A for the Remaining Shares plus the aggregate Net Proceeds received by the Selling Agent from the sale of other Shares in connection with the Net Cash Settlement or the Net Share Settlement equals (i) the Notional Amount plus (ii) the Net Interest Amount, and Party A shall be required to deliver to Party B the Remaining Shares. Settlement and delivery of the Remaining Shares and payment therefor shall be made to the parties through the Arranging Agent on the second Business Day after the delivery of such Sale Revocation and Designation Notice. (E) Offering Method Upon receipt of notice designating either Net Cash Settlement or Net Share Settlement as the Method of Settlement, Party B may determine the offering method (the "Offering Method") including whether the Shares to be sold will be offered pursuant to a registration statement filed or to be filed (a "Registered Offering") pursuant to the Securities Act of 1933 (the "1933 Act"), subject to Party A's consent to a Registered Offering, which consent shall not be unreasonably withheld. If Party B determines the Shares will be offered in a Registered Offering and Party A consents to a Registered Offering (which consent shall not be unreasonably withheld), Party B (and to the extent required therein, Party A) will use their reasonable efforts to comply in all material respects with the Registration Procedures set forth in Appendix A attached hereto. In the event that Party A, and its underwriter(s), upon advice from their respective counsel, reasonably object to the form or substance of the registration statement, Party A will deliver to Party B through the Arranging Agent a suspension request stating the reason or reasons for such objection ("Suspension Request") and Party B will either (i) modify or amend the registration statement to address such reasonable objection(s) or (ii) suspend the preparation of such registration statement with respect to the offering of the Principal Share Amount. In addition, if such registration statement has been filed and identifies either Party A or the Principal Share Amount and Party B determines not to amend or modify, or that it cannot amend or modify the registration statement to address Party A's or its underwriter(s)' reasonable objections, Party B will withdraw such registration statement pursuant to Rule 259 of the 1933 Act if such registration statement relates solely to the offering of the Principal Share Amount. In the event that no registration statement has been filed identifying Party A or the Principal Share Amount and Party B determines not to amend or modify, or that it cannot amend or modify the registration statement to address Party A's or its underwriter(s)' reasonable objections, Party B may within five Business Days of the delivery of the Suspension Request determine whether the Principal Share Amount will be sold pursuant to an offering that is exempt from the registration requirements of the 1933 Act (an "Exempt Offering") as the means of sale in respect of either a Net Cash Settlement or a Net Share Settlement or designate Gross Physical Settlement as the Method of Settlement. If, however, a registration statement identifying Party A or the Principal Share Amount has been filed and such registration statement is not amended to address Party A's or its underwriter(s) reasonable objections or has been withdrawn, as set forth herein, then not later than the third succeeding Business Day from the receipt of the Suspension Request Party B shall deliver to Party A through the Arranging Agent a notice designating Gross Physical Settlement as the Method of Settlement. In the event Party A delivers to Party B through the Arranging Agent a notice that it will not consent to Party B's determination that the Principal Share Amount are to be sold in a Registered Offering as provided herein, Party B may, within five Business Days from the delivery of such notice, either revoke the Net Cash Settlement or Net Share Settlement Method of Settlement and designate Gross Physical Settlement as the Method of Settlement or elect to have Party A pursue the contemplated sale of Shares in connection with Net Cash Settlement or Net Share Settlement through an Exempt Offering. If an Exempt Offering is pursued and Party B and its counsel object to the exemption to be relied on pursuant to which Shares are to be sold by either Party A or the Selling Agent or the opinion of counsel to Party A or any related documentation to be used in connection with the Exempt Offering, Party B may deliver a notice of suspension to Party A through the Arranging Agent and Party B may either (i) designate Gross Physical Settlement as the Method of Settlement, (ii) renew its solicitation of Party A's consent for a Registered Offering within five Business Days of its delivery of any notice of objection or (iii) subject to the consent of Party A and its counsel (which consent will not be unreasonably withheld), request an alternative Exempt Offering. Notwithstanding the foregoing, if an Event of Default or Termination Event has occurred and is continuing with respect to Party B, Party B will be foreclosed from making any determination as to the Offering Method and, subject to the terms hereof and all applicable regulatory requirements, such determination shall be in Party A's sole discretion. In connection with any Offering Method, Party B shall co-operate with the reasonable requirements of Party A and its underwriter(s) and Party A and its underwriter(s) shall co-operate with the reasonable requests of Party B, including without limitation providing such additional information as may reasonably be required so that any offering document to be used does not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made in such offering document, in light of the circumstances under which they were made, not misleading. Final Reference Share Price: In respect of the number of Shares sold by the Selling Agent in connection with a Net Cash Settlement or a Net Share Settlement, the average Net Proceeds per Share of all sales of the Shares sold by the Selling Agent in (i) transactions on the Exchange at the exchange prices received by the Selling Agent, if any, (ii) a Registered Offering, if any, based on the public offering price and (iii) transactions with recognized dealers or principals in the private placement market which are unaffiliated with Party A pursuant to an Exempt Offering, if any, and with or through which the Selling Agent effects any sales of Shares pursuant to a Net Cash Settlement or Net Share Settlement, which may be shortened by the delivery of a Sale Revocation and Designation Notice by Party B. Final Reference Share Price Pricing Period: The period commencing on the Termination Date, and continuing until the completion of the deliveries and any sales of Shares related thereto required for Net Cash Settlement or Net Share Settlement. Notwithstanding any other provisions set forth herein, in the event that the Settlement Date for this transaction has been delayed to a date that is the one year anniversary of the Termination Date for any reason, including, without limitation, because a Net Share Settlement or a Net Cash Settlement has been designated and the Final Reference Share Price Pricing Period has not been completed, or in the case of any designated Method of Settlement because of any Market Disruption Event or Settlement Disruption Event, then on the Business Day next succeeding such anniversary, Party B shall be deemed to have delivered a Sale Revocation and Designation Notice to Party A through the Arranging Agent suspending any further sales pursuant to the terms and conditions set forth in "(D)- Physical Settlement". Pursuant to such paragraph (D)- Physical Settlement, on the date such Sale and Revocation and Designation Notice is delivered any unsold Shares shall be deemed to be Remaining Shares and the payment and delivery procedures set forth in such paragraph shall govern the payment and delivery obligations of the parties Settlement Dates: To the extent not otherwise provided for hereunder, each of (i) the third Exchange Business Day following the end of the Final Reference Share Price Pricing Period in the case of Net Cash Settlement or Net Share Settlement, and (ii) the next Exchange Business day following (a) the Termination Date that Party B specifies or is deemed to have specified in a Termination Notice hereunder specifying Gross Physical Settlement as the Method of Settlement or (b) the Termination Date that is applicable in the event Party B is deemed to have specified Gross Physical Settlement as the Method of Settlement in the case of Gross Physical Settlement. If a Settlement Disruption Event prevents a Net Share Settlement or a Net Cash Settlement on the day that otherwise would have been the Settlement Date, then the Settlement Date will be the first succeeding day on which settlement can take place through the Clearance System unless a Settlement Disruption Event prevents settlement on each of the ten (10) consecutive Clearance System Business Days immediately following the original date that, but for such Settlement Disruption Event, would have been the Settlement Date. In that case, (a) if the Shares can be delivered in any other commercially reasonable manner, then the Settlement Date will be the first day on which settlement of a sale of Shares executed on that tenth (10th) Clearance System Business Day customarily would take place using such other commercially reasonable manner of delivery (which other manner of delivery will be deemed the Clearance System for purposes of delivery of the relevant Shares), and (b) if the Shares cannot be delivered in any other commercially reasonable manner, then the Settlement Date will be postponed until delivery can be effected through the Clearance System or any other commercially reasonable manner. Settlement Disruption Event: An event beyond the control of the parties as a result of which (i) the Clearance System cannot clear the transfer of the Shares or (ii) in the case of any Shares in physical certificate form, the payment system for bank fund transfers (e.g. the Federal Reserve wire payment system) cannot make electronic funds payments or otherwise transfer funds in the ordinary course. Trading Day: An Exchange Business Day other than an Exchange Business Day on which (i) a Market Disruption Event occurs, or (ii) Party B, by notice to Party A, through the Arranging Agent, by 8:30 a.m., New York time, determines, on the advice of counsel respecting applicable federal securities laws, that such day shall not be a Trading Day for one or more purposes of this Transaction specified by Party B in accordance with such advice. Exchange Business Day: Any day that is (or, but for the occurrence of a Market Disruption Event, would have been) a Trading Day on the Exchange other than a day on which trading on the Exchange is scheduled to close prior to its regular weekday closing time. Market Disruption Event: The occurrence or existence on any Exchange Business Day of any suspension of or material limitation imposed on trading (by reason of movement in price exceeding limits permitted by the relevant exchange or otherwise) on the Exchange in the Shares, if, in the reasonable determination of the Calculation Agent, such suspension or limitation prevents such day from being used as a Trading Day. Exchange: The New York Stock Exchange. Calculation Agent: Party A, whose determinations and calculations hereunder as Calculation Agent will be binding in the absence of manifest error. Subject to the foregoing, the Calculation Agent will have no responsibility for good faith errors or omissions in making any determination or calculation as provided herein. Selling Agent: Credit Suisse First Boston Corporation. When selling any Shares pursuant to this Transaction, the Selling Agent shall determine the number of Shares to be sold on any Trading Day and the price or prices at which such Shares are sold, provided, however, that it shall act in a commercially reasonable manner and on commercially reasonable terms, and shall comply with applicable securities laws, rules and regulations, applicable to it and the Transaction (including sales relating thereto). Party A and Party B hereby acknowledge and agree that the execution and delivery of this Confirmation by the Selling Agent does not constitute a commitment or an obligation of the Selling Agent to purchase or sell any Shares or any other security as principal. Party A Optional Termination: In addition to any other termination rights that Party A may have under the Agreement, in the event of any Merger Event, the terms of which are Share-for-Other or Share-for-Combined, pursuant to which a registered holder of Shares is entitled to receive cash consideration in connection with the Merger Event, Party A shall have the right within three Business Days after the payment of any cash consideration in connection with the Merger Event, to cause the Transaction to terminate in part before the originally scheduled Termination Date by giving a Termination Notice to Party B through the Arranging Agent, designating a Termination Date not earlier than five Business Days after the delivery date of the Termination Notice and making the Partial Termination Payments consisting of (i) a deemed payment by Party B to Party A by means of the Merger Termination Payment (defined below) and (ii) the payment by Party A to Party B of the Premium Cash Merger Payment (defined below) on the date designated as the Termination Date. "Merger Termination Payment" means an amount equal to the product of (i) the Termination Share Amount (defined below) and (ii) the Per Share Cash Component (defined below). "Termination Share Amount" means the number of Shares equal to the product of the Principal Share Amount and a fraction, the numerator of which is equal to the Per Share Cash Component and the denominator if which is equal to the per share total consideration of such offer. "Per Share Cash Component" means the per share cash component of any offer to purchase the Shares underlying the Merger Event. "Premium Cash Merger Payment" means the amount equal to the product of (i) the Termination Share Amount and (ii) the result of the per share total consideration of any offer to purchase the Shares underlying the Merger Event, minus the Initial Share Price, provided, however, that such difference shall not be less than zero. Party B Optional Termination: In addition to any other termination rights that Party B may have under the Agreement, Party B may elect to cause this Transaction to terminate in whole, or in part, before the originally scheduled Termination Date for any reason by giving a Termination Notice to Party A through the Arranging Agent during the last five Business Days prior to any Party B Calculation Period Payment Date and designating a Termination Date. Except for the originally scheduled Termination Date for which no written notice is required, no Termination Date designated hereunder may be set unless Party A has received a written notice not less than 30 Business Days, in the case of either Net Cash Settlement or Net Share Settlement and not less than two Business Days in the case of Gross Physical Settlement in connection with the relevant Method of Settlement. Subject to the terms of this Transaction, Party B shall give Party A written notice, through the Arranging Agent of the Method of Settlement. Registration Notice: Party B agrees that subsequent to the Effective Date it will not file any registration statement, amend a previously filed registration statement or commence any of the procedures set forth in Appendix A attached hereto with respect to any Shares that may be sold in connection with Net Cash Settlement or Net Share Settlement without providing notice to, and receiving the consent of, Party A, which consent shall not be unreasonably withheld. Sale Notification: If the Selling Agent sells any Shares acquired pursuant to this Transaction in the Initial Transaction or in either a Net Cash Settlement or a Net Share Settlement, such sale(s) must be in accordance with the terms and conditions set forth herein and the Selling Agent must notify Party B of such sale(s) as provided herein by telephonic notice, promptly confirmed in writing. Settlement Terms: In respect of the Termination Date Party B shall specify whether Gross Physical Settlement, Net Cash Settlement or Net Share Settlement is to apply. In the event Party B fails to specify the Method of Settlement as provided herein, Party B shall be deemed to have specified Gross Physical Settlement as the Method of Settlement in respect of such Termination Date. Adjustment Events: Method of Adjustment: Calculation Agent Adjustment. Extraordinary Events: Consequences of Merger Events: Following each Merger Event: (a) Share-for-Share: Alternative Obligation (b) Share-for-Other: Alternative Obligation (c) Share-for-Combined: Alternative Obligation Nationalization or Insolvency: Cancellation and Payment 3. Miscellaneous Transfer: Neither the Transaction nor any interest or obligation in or under the Transaction may be transferred (whether by way of security or otherwise) by either party without the prior written consent of the other party, except that a party may make a transfer of the Transaction pursuant to a consolidation or amalgamation with, or merger with or into, or transfer of all or substantially all its assets to, another entity, or upon or after any default of the other party. Any purported transfer that is not in compliance with this paragraph will be void. Party B Representation and Covenants: On each Exchange Business Day during a Final Reference Share Price Pricing Period, Party B hereby represents and warrants to Party A that, unless Party B notifies Party A, through the Arranging Agent, that such day is not a Trading Day, it has publicly disclosed all material information necessary for Party B to be able to purchase or sell Shares in compliance with applicable federal securities laws. Party B hereby represents and warrants to Party A that: (i) it has entered into this Transaction in connection with the Share repurchase program announced publicly on June 3, 1998, and July 13, 1999 for purposes consistent with those stated in such public disclosures and (ii) on the Trade Date and on the Settlement Date, Party B has available to it before and immediately after any purchase of Shares pursuant to this Transaction such orders, consents or other authorities as may be required by the SEC pursuant to rules and regulations of the Public Utility Holding Company Act of 1935 (the "1935 Act"), with respect to the execution, delivery and performance of the forward purchase obligations under this Transaction , and (iii) on the filing date of any registration statement or the commencement of any offer not involving a public offering in the case of any Net Cash Settlement or Net Share Settlement, the offering of Shares (or New Shares as provided herein), on the Settlement Date and on each day during the Final Share Price Pricing Period, will be made pursuant to the orders, consents or other authorizations that may be required under the rules and regulations promulgated under the 1935 Act , which will be in full force and effect and, to Party B's knowledge, will be free of any pending or overtly threatened proceedings contemplating the revocation or modification of such order; provided, however, in lieu of making the representations and warranties and agreeing the covenants set forth in clauses (i) and (ii), delivering an opinion of counsel addressing such matters as Party A may reasonably request and are customarily provided in connection with the purchase and sale of common stock, including, without limitation, that Party B is not subject to the 1935 Act, that no authorisation, consent or notice is required in order for Party B to perform any purchase or sale obligation with respect to the Shares other than any authorisations, consents, filings or notices that may be required under the 1933 Act and any applicable state law that may be required for the authorisation of any purchase of Shares. Party B also represents that it is not subject to regulation by any state, county or municipal agency, authority, board, council or similar body having authority or jurisdiction over Party B within the meaning of any applicable state law, order or regulation or any municipal government or authority with the capacity or power to regulate electric utility or gas utility companies ("Local Regulators") and all approvals and consents from or notices to any Local Regulator required by Party B to execute and deliver the Confirmation and to perform the Transaction and the related transactions contemplated thereby have been received or given and remain in full force and effect. Party B hereby agrees that from the Trade Date through and including the Settlement Date, it will comply in all material respects with all corporate or, if applicable, similar laws affecting its ability to perform its repurchase obligations under this Transaction, including any such requirements of the SEC or any Local Regulator. In the event that Party B reasonably believes that at any time during the term of this Transaction Party B would be prohibited from performing its repurchase obligations under this Transaction as currently contemplated without delivering notice to or obtaining the consent of the SEC or any Local Regulator, Party B will provide notice thereof through the Arranging Agent and designate a date for Settlement, which shall be a date on which Party B still satisfies such requirements and for which no notice or consent is required to perform the repurchase obligations contemplated by this Transaction. Other Provisions: If, notwithstanding any other provision of this Confirmation, this Transaction is terminated at a time when any law, rule or regulation, including without limitation, the 1935 Act or any applicable state law, order or regulation, prevents Party B from repurchasing the Number of Shares, Gross Physical Settlement shall not apply. Each party agrees that if delivery of the Shares on any Settlement Date is subject to any restriction imposed by a regulatory authority (other than the federal securities laws and the rules of the SEC affecting Registered or Exempt Offerings) that materially restricts or prevents delivery of any such Shares, the parties will negotiate in good faith a procedure to effect settlement of such affected Shares in a manner which complies with any relevant rules of such regulatory authority. Party B Undertakings: Party B hereby agrees that if it is the object of any merger, consolidation, amalgamation of Party B with or into another entity (and Party B is not the surviving entity) or a third party acquires such number of Shares or the right to control such number of Shares (or the voting power thereof) and the acquisition of such number of Shares or the voting power with respect thereto results in the transfer of control of Party B (within the meaning of Rule 405 of the 1933 Act), then in the event that (i) Alternative Obligation is elected in respect of Consequences of Merger Event - Share- for-Combined and (ii) a material portion of Shares are exchanged or exchangeable for New Shares (as defined in the Equity Definitions), then Party B shall cause the issuer of such New Shares to undertake and perform each and every obligation and satisfy each and every condition precedent of Party B arising under this Confirmation with respect to any purchase or sale of the Shares, including, but not limited to, the representations, agreements, and covenants that relate to the Shares and any purchase or sale thereof, the exercise or election of any Method of Settlement or Offering Method, the participation and preparation of any materials relating to any registration statement in connection with any Registered Offering of Shares, and the determinations and decisions relating thereto, modified in all cases, mutatis mutandis, to apply to the issuer and to the New Shares. Any failure by Party B to cause the issuer of New Shares to achieve any undertakings, performance or satisfaction of any such obligations to the reasonable satisfaction of Party A shall be deemed an irrevocable exercise of Gross Physical Settlement option as the Method of Settlement that shall be deemed to supersede any prior exercise of any Method of Settlement Option. Cessation and Suspension: If at any time during the Term of the Transaction Party B is subject to any legal or regulatory requirements ("Legal Requirements") or any directly related policies or procedures adopted by Party B with respect to the Legal Requirements, which, in Party B's reasonable judgement requires it, or Party A if acting on behalf of Party B, to refrain from purchasing or selling Shares on any Trading Day, Party B shall give prompt telephonic notice of the cessation of any further purchases or sales of Shares and the suspension of any further purchases or sales of Shares (each, a "Cessation Notice"), which cessation and suspension shall remain in effect until further notice from Party B. Each telephonic notice of a Cessation Notice shall be promptly confirmed in writing. Notwithstanding the foregoing, the delivery of a Cessation Notice shall not affect any obligation of Party A to deliver or receive Shares in settlement of any purchase or sale of Shares agreed prior to the delivery of the Cessation Notice. Issuer Repurchase Safe Harbor: Assuming that Party B's conduct complies with the requirements of rule 10b-18 promulgated under the 1934 Act ("Rule 10b-18"), Party A will use its best efforts to comply with the manner of purchase, time, price and volume requirements of Rule 10b-18 in connection with its purchase of Shares under this Transaction. Limited Liability: No shareholder or trustee of Party B shall be held to any liability whatever for the payment of any sum of money or for damages or otherwise under this Confirmation, and this Confirmation shall not be enforceable against any such trustee in their or his or her individual capacities or capacity and this Confirmation shall be enforceable against the trustees of Party B only as such, and every person, firm, association, trust or corporation having any claim or demand arising under this Confirmation and relating to Party B, its shareholders or trustees shall look solely to the trust estate of Party B for the payment or satisfaction thereof. Securities Contract: Each party hereby represents to the other that it intends this Transaction to be a securities contract within the meaning of Section 741 of Bankruptcy Code, as amended (11 U.S.C. Section 741). 4. Credit Support Documents: Party A: None Party B: Collateral Appendix 5. Account Details: Payments to Party A: Citibank, NY ABA Number: 021-000-089 A/C: Credit Suisse First Boston Corp. A/C: 40804388 FFC: Northeast Utilities A/C Number: 2GA3P0 Payments to Party B: Fleet ABA Number: 011500010 Acct No.: 50252481 Ref.: NU Share Repurchase Delivery of Shares to Party A: To be advised by written notice within 30 days of the Trade Date Delivery of Shares to Party B: To be advised by written notice within 30 days of the Trade Date 6. U.S. Private Placement Representations As this Transaction may constitute the sale by Party A to Party B in the case of this Transaction, and by Party B to Party A in the case of the Number of Shares, in each case, through Arranging Agent, of a Security or Securities (as defined in the 1933 Act), in addition to the representations contained in Section 3 of the Agreement, Party B hereby represents to Party A in respect of this Transaction and Party A represents to Party B in respect of the Number of Shares (for purposes of this Section 6, the representation of Party A with respect to Securities shall be made with respect to the Number of Shares and the representation of Party B shall be made with respect to the Transaction, in accordance with Section 3 of the Agreement), as follows: (a) Each party is acquiring such Securities through the Arranging Agent for its own account as principal, for investment purposes only, and not with a view to, or for, resale, distribution or fractionalization thereof, in whole or in part, and no other person has a direct or indirect beneficial interest in any such Securities acquired by it through the Arranging Agent; (b) Each party understands that the offer and sale by the other party, through the Arranging Agent, of such Securities are intended to be exempt from registration under the 1933 Act, by virtue of Section 4(2) thereof. In furtherance thereof, each Party represents and warrants that (i) it has the financial ability to bear the economic risk of its investment and has adequate means of providing for its current needs and other contingencies, (ii) it is experienced in investing in forward purchase contracts and similar instruments and has determined that such securities are a suitable investment for it, and (iii) it is an institution that qualifies as an "accredited investor" as that term is defined in Regulation D under the 1933 Act; and (c) Each party has been given the opportunity to ask questions of, and receive answers from, the other party through the Arranging Agent concerning the terms and conditions of such Securities and concerning the financial condition and business operations of the other party and has been given the opportunity to obtain such additional information necessary in order for each party to evaluate the merits and risks of purchase of such Securities to the extent the issuer of the Securities possesses such information or can acquire it without unreasonable effort or expense. (d) The Shares shall bear a legend substantially as set forth below: THE SECURITIES REPRESENTED BY THIS CERTIFICATE HAVE NOT BEEN REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933 (THE "ACT") OR ANY STATE SECURITIES LAWS ("BLUE SKY LAW") ANY MAY NOT BE SOLD, TRANSFERRED, PLEDGED OR OTHERWISE DISPOSED OF WITHOUT REGISTRATION UNDER THE ACT AND UNDER APPLICABLE BLUE SKY LAW OR UNLESS SUCH SALE, TRANSFER, PLEDGE OR OTHER DISPOSITION IS EXEMPT FROM REGISTRATION THEREUNDER. THE SALE, TRANSFER, PLEDGE OR OTHER DISPOSTION OF THIS SECURITY IS SUBJECT TO THE AGREEMENT BETWEEN THE ISSUER, CREDIT SUISSE FIRST BOSTON CORPORATION, AS ARRANGING AGENT, AND CREDIT SUISSE FINANCIAL PRODUCTS DATED NOVEMBER 3, 1999 (THE "AGREEMENT"). Each party hereby acknowledges that it understands and agrees that disposition of any such Securities is restricted in the manner set forth under the Agreement, the 1933 Act and state securities laws. For example, such Securities have not been registered under the 1933 Act or under the securities laws of certain states and, therefore, cannot be resold, pledged, assigned or otherwise disposed of unless they have been registered under the 1933 Act and under the applicable laws of such states or an exemption from such registration is available. 9. Matters relating to the Arranging Agent: (a) As a broker-dealer registered with the SEC, Credit Suisse First Boston Corporation in its capacity as Arranging Agent will be responsible for (i) effecting this Transaction, (ii) issuing all required confirmations and statements to Party A and Party B, (iii) maintaining books and records relating to this Transaction as required by Rules 17a-3 and 17a-4 under the Securities Exchange Act of 1934 (the "1934 Act") and (iv) unless otherwise requested by Party B, receiving, delivering, and safeguarding Party B's funds and any securities in connection with this Transaction, in compliance with Rule 15c3-3 under the Exchange Act. (b) Credit Suisse First Boston Corporation is acting in connection with this Transaction solely in its capacity as Arranging Agent for Party A and Party B pursuant to instructions from Party A and Party B. Credit Suisse First Boston Corporation shall have no responsibility or personal liability to Party A or Party B arising from any failure by Party A or Party B to pay or perform any obligations hereunder, or to monitor or enforce compliance by Party A or Party B with any obligation hereunder, including without limitation, any obligations to maintain collateral. Each of Party A and Party B agrees to proceed solely against the other to collect or recover any securities or monies owing to it in connection with or as a result of this Transaction. Credit Suisse First Boston Corporation shall otherwise have no liability in respect of this Transaction, except for its gross negligence or wilful misconduct in performing its duties as Arranging Agent. (c) Any and all notices, demands, or communications of any kind relating to this Transaction, including without limitation, any option exercise notice, between Party A and Party B shall be transmitted exclusively through the Arranging Agent at the following address: Credit Suisse First Boston Corporation 11 Madison Avenue New York, NY 10010 Facsimile No.: (212) 325-8175 Telephone No.: (212) 325-8678 Attention: Ricardo Harewood (d) The date and time of the Transaction evidenced hereby will be furnished by the Arranging Agent to Party A and Party B upon written request. (e) The Arranging Agent will furnish to Party B upon written request a statement as to the source and amount of any remuneration received or to be received by the Arranging Agent in connection with the Transaction evidenced hereby. (f) Party A and Party B each represents and agrees (i) that this Transaction is not unsuitable for it in the light of such party's financial situation, investment objectives and needs and (ii) that it is entering into this Transaction in reliance upon such tax, accounting, regulatory, legal and financial advice as it deems necessary and not upon any view expressed by the other or the Arranging Agent. (g) Party A and Party B each is aware of and agrees to be bound by the rules of the National Association of Securities Dealers, Inc. ("NASD") applicable to the Transaction and is aware of and agrees not to violate, either alone or in concert with others, any applicable position or exercise limits established by the NASD. Credit Suisse Financial Products is regulated by The Securities and Futures Authority and has entered into this transaction as principal. Please confirm that the foregoing correctly sets forth the terms of the agreement by executing the copy of this Confirmation enclosed for that purpose and returning it to us. Yours sincerely, CREDIT SUISSE FIRST BOSTON CORPORATION, solely in its capacities as Arranging Agent and Selling Agent By: Name: Title: CREDIT SUISSE FIRST BOSTON INTERNATIONAL By: Name: Title: Confirmed as of the date first written above: NORTHEAST UTILITIES By: Name: Title: APPENDIX A TO CONFIRMATION OF TRANSACTION BETWEEN CREDIT SUISSE FIRST BOSTON INTERNATIONAL AND NORTHEAST UTILITIES CSFBi REFERENCE NO. 5672645 Unless otherwise agreed in writing by Party A and Party B with respect to specific sales of Shares by the Selling Agent or specific Shares to be delivered to the Selling Agent by Party B, the provisions of this Appendix A shall apply to all Shares in satisfaction of a Party B Net Cash Settlement or Net Share Settlement Delivery including the resale of the Number of Shares which were acquired in a transaction not involving any public offering and, in the case of Net Share Settlement, any additional Shares (collectively, the "Shares"). (a) Party B shall have reserved and have available, out of its authorized but unissued capital stock, for the purpose of effecting the payment of any Party B Net Cash or Net Share Settlement Delivery in Shares as provided in the Confirmation, the full number of shares of capital stock that would then be issuable with respect to such payment. (b) Party B shall have filed with the SEC a registration statement on Form S-3 or such other form as is acceptable to Party A; such registration statement shall have been declared effective with respect to such Shares (the "Registration Statement") and no stop order suspending the effectiveness of the Registration Statement shall be in effect, and no proceedings for such purpose shall be pending before or threatened by the Commission. Party B, at the request of Party A, shall deliver an underwriting agreement naming Party A, or its designee, as underwriter, together with such other agreements, certificates and instruments as Party A may reasonably require either pursuant to such underwriting agreement or as are customarily provided together with such underwriting agreement. (c) Party B shall have registered or qualified such Shares under such securities or "blue sky" laws of such States and other jurisdictions in the United States and Puerto Rico as Party A or any underwriter shall have reasonably requested, and shall have done any and all other acts and things as may be reasonably necessary to be done by Party B to enable Party A or any underwriter to consummate the disposition in such jurisdictions of the Shares covered by the Registration Statement; provided that Party B shall not be required to make any filing or take any action as a result of this paragraph (c) that would required it to qualify as a foreign corporation or file a general consent to service of process in any jurisdiction. (d) Party B shall have caused such Shares and the issuance thereof to be registered with or approved by such other governmental agencies or authorities in the United States as may be reasonably necessary to be done by Party B to enable Party A or any underwriter to consummate the disposition of such Shares. (e) Party B shall have (i) given Party A and its underwriter(s), if any, and their respective counsel and accountants, the opportunity to participate in the preparation of all materials filed with the SEC or any other governmental agency (the "Filed Materials") prior to the first day of such Final Reference Share Price Pricing Period, (ii) furnished to each of them copies of all such Filed Materials (and all documents incorporated therein by reference) sufficiently in advance of filing to provide them with a reasonable opportunity to review such documents and comment thereon, (iii) given each of them such opportunities to discuss the business of Party B with its officers and the independent public accountants who have issued a report on its financial statement as shall be reasonably necessary, in the opinion of Party A and such underwriter(s) or their respective counsel, to conduct a reasonable investigation (within the meaning of the 1933 Act, as amended) with respect to such Filed Materials, (iv) delivered to Party A and its underwriter(s), if any, the financial statements of Party B filed with the SEC, (v) included in such Filed Materials material, furnished to Party B in writing, which in the reasonable judgement of Party A or its underwriter(s), if any, subject to the consent of Party B (which shall not be unreasonably withheld), should be included with respect to Party A, Party A's underwriter(s) and the "Plan of Distribution", including, without limitation, language to the effect that the holding by Party A of the Shares is not to be construed as a recommendation by Party A of the investment quality thereof and (vi) if requested by Party A, deleted from such Filed Materials any reference to Party A if in the written opinion of counsel to Party A, in form and substance to Party B, such reference to Party A by name or otherwise is not required by the 1933 Act or any similar Federal statute then in force. (f) Party B shall have furnished to Party A and any underwriter, addressed to Party A and any such underwriter and dated the first day of the Final Reference Share Price Pricing Period, (i) an opinion of counsel for Party B (which opinion may be from internal counsel for Party B) and (ii) a "cold comfort" letter signed by the independent public accountants who have issued a report on Party B's financial statements included in such Registration Statement, covering substantially the same matters with respect to such Shares and the offering, sale and issuance thereof as are customarily covered in opinions of issuer's counsel and in accountants' letters delivered to underwriter(s) in underwritten public offerings of securities and, in the case of the accountants' letter, such other financial matters as Party A may have reasonably requested. (g) Party B shall have complied with all applicable provisions of the 1933 Act and the 1934 Act and the Public Utility Holding Company Act of 1935, all applicable rules of the SEC and all other applicable laws, rules and regulations of any governmental or regulatory authority with respect to such Filing Materials and such Shares and the offering, sale and issuance thereof. (h) Party B shall have caused all such Shares to be listed on the Exchange and on each securities exchange on which Party B has caused similar securities issued by Party B to be listed. (i) Party B shall have provided a transfer agent and registrar for such Shares. (j) Party B shall have taken such other actions as Party A or any underwriter of such Shares shall have reasonably requested in order to expedite or facilitate the disposition of such Shares. (k) Party B shall provide Party A and its underwriter(s), if any, with indemnity and contribution in form and substance acceptable to Party A covering such matters relating to the Shares, the Filed Materials, and such other matters as Party A shall reasonably request. (l) Party B shall have paid all customary costs and expenses reasonably incurred in connection with the foregoing, provided, that unless otherwise agreed, Party A and its underwriter(s) shall be responsible for the fees and expenses of their respective counsel. (m) Party B shall deliver all such registered Shares through the Clearance System. EX-10.53.1 9 0009.txt EXHIBIT 10.53.1 FIRST AMENDMENT FIRST AMENDMENT, dated as of January 1, 2001 to the equity forward transaction (the "Transaction") between Northeast Utilities ("NU") and Bank One, NA (Illinois) evidenced by the Confirmation dated December 9, 1999 (the "Confirmation"). Capitalized terms used and not defined herein have the meaning given to them in the Confirmation. WHEREAS, the parties hereto desire to amend the Transaction as described herein: NOW THEREFORE, in consideration of the mutual agreements herein, the parties hereto agree as follows: 1. The Termination Date of the Transaction shall be June 29, 2001, subject to adjustment in accordance with the Modified Following Business Day Convention, the terms of the Party B Net Settlement Option, the Party A Optional Termination and the Party B Optional Termination. 2. January 15, 2001, April 15, 2001 and the Termination Date shall be Party A Calculation Period Payment Dates with respect to this Transaction. 3. January 2, 2001, January 15, 2001 and April 15, 2001 shall be Calculation Period Interest Reset Dates with respect to this Transaction. 4. With effect from the Calculation Period commencing January 4, 2001, the Spread shall be 2.00 percent . 5. This First Amendment constitutes the entire Agreement and understanding of the parties with respect to its subject matter and supersedes all oral communications and prior writings with respect thereto. 6. No amendment, modification or waiver in respect of this First Amendment will be effective unless in writing (including a writing evidenced by a facsimile transmission) and executed by each of the parties. 7. This Amendment may be executed in counterparts each of which shall be deemed to be an original. 8. This Amendment will be governed by and construed in accordance with the laws of the State of New York (without reference to choice of law doctrine). 9. Limited Liability. No shareholder or trustee of NU shall be held to any liability whatever for the payment of any sum of money or for damages or otherwise under this Amendment, and this Amendment shall not be enforceable against any such trustee in their or his or her individual capacities or capacity and this Amendment shall be enforceable against the trustees of NU only as such, and every person, firm, association, trust or corporation having any claim or demand arising under this Amendment and relating to NU, its shareholders or trustees shall look solely to the trust estate of NU for the payment or satisfaction thereof. IN WITNESS WHEREOF, the parties have executed this Amendment as of the date first above written. NORTHEAST UTILITIES BANK ONE, NA By: By: Name: Name: Title: Title: EX-10.54 10 0010.txt EXHIBIT 10.54 EXECUTION COPY U.S.$865,500,000 CREDIT AGREEMENT Dated as of March 9, 2000 Among NORTHEAST GENERATION COMPANY AS BORROWER and THE INITIAL LENDERS NAMED HEREIN AS INITIAL LENDERS and CITIBANK, N.A. AS ADMINISTRATIVE AGENT and CITIBANK, N.A. AS COLLATERAL AGENT and CITIBANK, N.A. AS DEPOSITORY BANK TABLE OF CONTENTS SECTION PAGE ARTICLE I DEFINITIONS AND ACCOUNTING TERMS 1.01. Certain Defined Terms 1 1.02. Computation of Time Period 27 1.03. Accounting Terms 27 ARTICLE II AMOUNTS AND TERMS OF THE ADVANCES 2.01. The Advances 28 2.02. Making the Advances 28 2.03. Repayment of Advances 30 2.04. Adjustments of the Commitments 30 2.05. Prepayments 30 2.06. Interest 31 2.07. Fees 32 2.08. Conversion of Advances 32 2.09. Increased Costs, Etc. 33 2.10. Payments and Computations 35 2.11. Taxes 36 2.12. Sharing of Payments, Etc. 38 2.13. Use of Proceeds 39 2.14. Defaulting Lenders 39 2.15. Depository Trust Corporation Eligibility 42 ARTICLE III CONDITIONS OF LENDING 3.01. Conditions Precedent to the Borrowing Date 42 3.02. Determinations Under Section 3.01 51 i ARTICLE IV SPECIAL ACCOUNTS SYSTEM 4.01. Creation of the Collateral Accounts 51 4.02. Revenues Account 53 4.03. Casualty Account 55 4.04. Investment of Funds in Collateral Accounts 57 4.05. Interest 58 4.06. Reports to the Borrower and the Lenders 58 4.07. Books and Records 58 ARTICLE V REPRESENTATIONS AND WARRANTIES 5.01. Representations and Warranties of the Borrower 58 ARTICLE VI COVENANTS OF THE BORROWER 6.01. Affirmative Covenants 65 6.02. Negative Covenants 71 6.03. Reporting Requirements 73 6.04. Financial Covenants 76 ARTICLE VII EVENTS OF DEFAULT 7.01. Events of Default 77 ARTICLE VIII THE AGENTS 8.01. Authorization and Action 81 8.02. Agent's Reliance, Etc. 81 8.03. Citibank and Affiliates 83 8.04. Lender Credit Decision 83 8.05. Indemnification 83 8.06. Successor Agents 84 8.07. Intercreditor Arrangements 85 8.08. Co-Arrangers 86 ii ARTICLE IX MISCELLANEOUS 9.01. Amendments, Etc. 86 9.02. Notices, Etc. 87 9.03. No Waiver; Remedies 87 9.04. Costs, Expenses, Indemnification 88 9.05. Right of Set-off 89 9.06. Binding Effect 90 9.07. Assignments and Participations 90 9.08. Execution in Counterparts 93 9.09. Confidentiality 93 9.10. Jurisdiction, Etc. 93 9.11. Governing Law 94 9.12. Waiver of Jury Trial 94 iii SCHEDULES Schedule I Commitments and Applicable Lending Offices Schedule II Properties Schedule 3.01(e) Information Schedule 5.01(d)(A-1) CL&P Governmental Authorizations Schedule 5.01(d)(A-2) WMECO Governmental Authorizations Schedule 5.01(d)(B) Third Party Consents Schedule 5.01(q) Plans, Multiemployer Plans and Welfare Plans Schedule 5.01(dd) Liens Schedule 5.01(ee) Material Contracts Schedule 5 Insurance EXHIBITS Exhibit A-1 - Form of Tranche A Note Exhibit A-2 - Form of Tranche B Note Exhibit B - Form of Notice of Borrowing Exhibit C - Form of Assignment and Acceptance Exhibit D-1 - Form of Tranche A Borrower Security Agreement Exhibit D-2 - Form of Tranche B Borrower Security Agreement Exhibit E-1 - Form of Tranche A Enterprises Pledge Agreement Exhibit E-2 - Form of Tranche B Enterprises Pledge Agreement Exhibit F-1 - Form of Tranche A Mortgage Exhibit F-2 - Form of Tranche B Mortgage Exhibit G - Form of Flow of Funds Memorandum Exhibit H - Form of Sponsor Agreement Exhibit I - Form of Annual Operating Budget Exhibit J - Form of Solvency Certificates iv EXECUTION COPY CREDIT AGREEMENT CREDIT AGREEMENT dated as of March 9, 2000 among Northeast Generation Company, a Connecticut corporation (the "BORROWER"), the banks, financial institutions and other institutional lenders listed on the signature pages hereof as the Tranche A Initial Lenders (the "TRANCHE A INITIAL LENDERS"), the banks, financial institutions and other institutional lenders listed on the signature pages hereof as the Tranche B Initial Lenders (the "TRANCHE B INITIAL LENDERS"), Citibank, N.A. ("CITIBANK"), as administrative agent (together with any successor appointed pursuant to Article VIII, the "ADMINISTRATIVE AGENT") for the Lenders (as hereinafter defined), Citibank, as Collateral Agent (together with any successor appointed pursuant to Article VIII, the "COLLATERAL AGENT") for the Secured Parties (as hereinafter defined) and Citibank, as the Depositary Bank (the "DEPOSITARY BANK"). PRELIMINARY STATEMENTS: (1) The Borrower intends to acquire the generating assets owned by The Connecticut Light and Power Company, a Connecticut corporation ("CL&P"), and Western Massachusetts Electric Company, a Massachusetts corporation ("WMECO"), that were awarded to the Borrower on July 2, 1999 (the "AWARD DATE") in the auction conducted by The Connecticut Department of Public Utility Control and its agent, J.P. Morgan, in accordance with Public Act 98-28 (of the State of Connecticut), "An Act Concerning Electric Restructuring", on behalf of CL&P. (2) The Borrower has requested that the Lenders make advances to the Borrower in an aggregate amount of $865,500,000 for the purpose of paying the purchase price of such generating assets and otherwise as outlined herein, and the Lenders have indicated their willingness to agree to lend such amount for such purpose and on the terms and conditions of this Agreement. NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements contained herein, the parties hereto hereby agree as follows: ARTICLE I DEFINITIONS AND ACCOUNTING TERMS SECTION 1.01. CERTAIN DEFINED TERMS. As used in this Agreement, the following terms shall have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined): "ACQUISITION" means, collectively, the CL&P Acquisition and the WMECO Acquisition. "ACQUISITION DATE" means the date on which the Acquisition is consummated. 1 "ACQUISITION DOCUMENTS" means the Purchase and Sale Agreements, the Assumption Agreements, the Interconnection Agreements, the Closing Agreement, the Assignment and Assumption Agreements and the Asset Demarcation Agreements. "ADMINISTRATIVE AGENT" has the meaning specified in the recital of parties to this Agreement. "ADMINISTRATIVE AGENT'S ACCOUNT" means the account of the Administrative Agent maintained by the Administrative Agent at its office at 399 Park Avenue, New York, New York Account No. 36852248, Reference: NAIB-Medium Term Finance. "ADVANCE" means either a Tranche A Advance or a Tranche B Advance by a Lender to the Borrower pursuant to Article II, and refers to a Base Rate Advance or a Eurodollar Rate Advance (each of which shall be a "Type" of Advance). "AFFILIATE" means, as to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with such Person or is a director or officer of such Person. For purposes of this definition, the term "control" (including the terms "controlling", "controlled by" and "under common control with") of a Person means the possession, direct or indirect, of the power to vote 5% or more of the Voting Stock of such Person or to direct or cause the direction of the management and policies of such Person, whether through the ownership of Voting Stock, by contract or otherwise. "AGENTS" means, collectively, the Administrative Agent and the Collateral Agent. "AGREEMENT" means this Agreement (including all schedules and exhibits hereto). "ANNUAL OPERATING BUDGET" means the annual budget of the Borrower for Fiscal Year 2000, attached as Exhibit I hereto, which includes all administrative, operating, debt service, Capital Expenditures and other expenses and shall specify the aggregate amount of such expenses of the Borrower that are projected to be required during such Fiscal Year. "APPLICABLE LENDING OFFICE" means, with respect to each Lender, such Lender's Domestic Lending Office in the case of a Base Rate Advance and such Lender's Eurodollar Lending Office in the case of a Eurodollar Rate Advance. 2 "APPLICABLE MARGIN" means: (a) with respect to the Tranche A Advances, 2.00% per annum; and (b) with respect to the Tranche B Advances, a rate per annum equal to (x) for Eurodollar Advances, 2.00% per annum, and (y) for Base Rate Advances, 1.00% per annum. "ARRANGER" means Citibank. "ASSET DEMARCATION AGREEMENTS" means the CL&P Asset Demarcation Agreement and the WMECO Asset Demarcation Agreement. "ASSIGNMENT AND ACCEPTANCE" means an assignment and acceptance entered into by a Lender and an Eligible Assignee, and accepted by the Administrative Agent, in accordance with Section 9.07 and in substantially the form of Exhibit C hereto. "ASSIGNMENT AND ASSUMPTION AGREEMENTS" means the CL&P Assignment and Assumption Agreement and the WMECO Assignment and Assumption Agreement. "ASSUMPTION AGREEMENTS" means the CL&P Assumption Agreement and the WMECO Assumption Agreement. "AVAILABLE EXCESS CASH FLOW" means, for any Excess Cash Flow Payment Date, an amount equal to the Excess Cash Flow for such date MINUS the sum of (i) $4,000,000, (ii) an amount equal to all accrued and unpaid interest on the Advances for each Interest Period then in effect, and (iii) an amount equal to no more than 30 days interest anticipated to accrue on the Advances prior to the expiration of each Interest Period then in effect. "AWARD DATE" has the meaning set forth in the Preliminary Statements to this Agreement. "BASE RATE" means a fluctuating interest rate per annum in effect from time to time, which rate per annum shall at all times be equal to the highest of: (a) the rate of interest announced publicly by Citibank in New York as its Base Rate; (b) 2 of 1% per annum above the latest three-week moving average of secondary market morning offering rates for three-month certificates of deposit of major U.S. money market banks, as determined weekly by Citibank and adjusted for the cost of reserves and estimated insurance assessments from the Federal Deposit Insurance Corporation; and 3 (c) a rate equal to 2 of 1% per annum above the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as determined for any day by Citibank. "BASE RATE ADVANCE" means an Advance that bears interest as provided in Section 2.06(a)(i). "BORROWER" has the meaning specified in the recital of parties to this Agreement. "BORROWER SECURITY AGREEMENT" means, collectively, the Tranche A Borrower Security Agreement and the Tranche B Borrower Security Agreement. "BORROWER'S ACCOUNT" means the account of the Borrower maintained by the Borrower with Citibank at its office at 399 Park Avenue, New York, New York 10043, Account No. 30421332. "BORROWING" means a borrowing consisting of either Tranche A Advances or Tranche B Advances of the same Type made on the same day by the Lenders. "BORROWING DATE" shall mean the date Advances are made to the Borrower for the Acquisition. "BUSINESS DAY" means a day of the year on which banks are not required or authorized by law to close in New York City and, if the applicable Business Day relates to any Eurodollar Rate Advances, on which dealings are carried on in the London interbank market. "CAPITAL EXPENDITURES" means, for any Person for any period, the sum of all expenditures made, directly or indirectly, by such Person during such period for equipment, fixed assets, real property or improvements, or for replacements or substitutions therefor or additions thereto, that have been or should be, in accordance with GAAP, reflected as additions to property, plant or equipment on a Consolidated balance sheet of such Person or have a useful life of more than one year. "CAPITALIZED LEASES" means all leases that have been or should be, in accordance with GAAP, recorded as capitalized leases. "CASUALTY ACCOUNT" means the casualty account of the Borrower maintained pursuant to Article IV hereof by the Collateral Agent with Citibank's office at 111 Wall Street, New York, New York 10043, Account No.36114325, ABA No. 02100008-9, FBO A/C 103561 Northeast, Attention: Olivia Sharp. 4 "CERCLA" means the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended from time to time. "CERCLIS" means the Comprehensive Environmental Response, Compensation and Liability Information System maintained by the U.S. Environmental Protection Agency. "CITIBANK" has the meaning specified in the recital of parties to this Agreement. "CL&P" has the meaning set forth in the Preliminary Statements to this Agreement. "CL&P ACQUISITION" means the acquisition by the Borrower of the CL&P Generating Assets. "CL&P ACQUISITION DOCUMENTS" means the CL&P Asset Demarcation Agreement, the CL&P Assumption Agreement, the CL&P Interconnection Agreement and the CL&P Purchase and Sale Agreement. "CL&P ASSET DEMARCATION AGREEMENT" means the Asset Demarcation Agreement dated as of the date of the Acquisition, between the Borrower and CL&P. "CL&P ASSIGNMENT AND ASSUMPTION AGREEMENT" means the Assignment and Assumption Agreement, dated as of March 14, 2000, between the Borrower and CL&P. "CL&P ASSUMPTION AGREEMENT" means the Assumption Agreement dated July 2, 1999, between Northeast Utilities and CL&P. "CL&P GENERATING ASSETS" means the hydroelectric and pumped storage generating assets and related assets acquired or to be acquired, as the case may be, by the Borrower from CL&P pursuant to the CL&P Purchase and Sale Agreement. "CL&P INDENTURE" means the Indenture of Mortgage and Deed of Trust dated as of May 1, 1921, as amended as of the date hereof, between CL&P and Bankers Trust Company. "CL&P INTERCONNECTION AGREEMENT" means the Interconnection Agreement dated July 2, 1999, between the Borrower and CL&P. "CL&P PURCHASE AND SALE AGREEMENT" means the Purchase and Sale Agreement dated July 2, 1999, between the Borrower and CL&P. "CL&P PURCHASE PRICE" means the amount payable by the Borrower to CL&P for the CL&P Generating Assets pursuant to the CL&P Purchase and Sale Agreements. 5 "CLOSING AGREEMENT" means collectively, (a) the Closing Agreement, dated as of the Acquisition Date between the Borrower and CL&P and (b) the Closing Agreement, dated as of the Acquisition Date between the Borrower and WMECO. "CO-ARRANGERS" means Citibank, Barclays Bank PLC, CIBC Inc. and TD Securities (USA) Inc. "COLLATERAL" means all of the Borrower's present and future property and assets, real and personal, tangible and intangible, including, without limitation, owned real estate, leaseholds, fixtures, accounts, license rights, patents, trademarks, tradenames, copyrights, chattel paper, insurance proceeds, contract rights, cash, bank accounts, tax refunds, documents, instruments, general intangibles, inventory, equipment, vehicles and other goods and all present and future contracts of the Borrower, including the Acquisition Documents, the Project Documents and all service contracts, power purchase and sale contracts, operating leases and labor contracts and all other "Collateral" referred to in the Collateral Documents. "COLLATERAL ACCOUNTS" means the Revenues Account and the Casualty Account. "COLLATERAL AGENT" has the meaning specified in the recital of parties to this Agreement. "COLLATERAL DOCUMENTS" means the Borrower Security Agreement, the Enterprises Pledge Agreement, the Mortgages, the Consents to Assignment and any other agreement that creates or purports to create a Lien in favor of the Collateral Agent for the benefit of the Tranche A Secured Parties or the Tranche B Secured Parties. "COMMITMENT" means a Tranche A Commitment and a Tranche B Commitment. "CONFIDENTIAL INFORMATION" means information that the Borrower furnishes to the Administrative Agent or any Lender in a writing designated as confidential, but does not include any such information that is or becomes generally available to the public or that is or becomes available to the Administrative Agent or such Lender from a source other than the Borrower or the Administrative Agent or any Lender. "CONSENTS TO ASSIGNMENT" means the Consents to Assignment in the forms attached to either of the Borrower Security Agreements and executed by the counterparties to the Assigned Agreements (as defined in the Borrower Security Agreements). 6 "CONSOLIDATED" refers to the consolidation of accounts in accordance with GAAP. "CONVERSION", "CONVERT" and "CONVERTED" each refer to a conversion of Advances of one Type into Advances of the other Type pursuant to Section 2.08 or 2.09. "DEBT" of any Person means, without duplication, (a) all indebtedness of such Person for borrowed money, (b) all obligations of such Person for the purchase price of property or services (other than trade or account payables incurred in the ordinary course of business), (c) all obligations of such Person evidenced by notes, bonds, debentures or other similar instruments, (d) all obligations of such Person created or arising under any conditional sale or other title retention agreement with respect to property acquired by such Person (even though the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), (e) all obligations of such Person as lessee under leases that have been or should be, in accordance with the GAAP applicable to such Person, recorded as capital leases, (f) all obligations, contingent or otherwise, of such Person in respect of acceptances, letters of credit or similar extensions of credit, (g) all obligations of such Person to purchase, redeem, retire, defease or otherwise make any payment in respect of any capital stock of or other ownership or profit interest in such Person or any other Person or any warrants, rights or options to acquire such capital stock, (h) net amounts payable under hedge agreements, (i) all Debt of others referred to in clauses (a) through (h) above or clause (j) below guaranteed directly or indirectly in any manner by such Person, or in effect guaranteed directly or indirectly by such Person through an agreement (1) to pay or purchase such Debt or to advance or supply funds for the payment or purchase of such Indebtedness, (2) to purchase, sell or lease (as lessee or lessor) property, or to purchase or sell services, primarily for the purpose of enabling the debtor to make payment of such Debt or to assure the holder of such Debt against loss, (3) to supply funds to or in any other manner invest in the debtor (including any agreement to pay for property or services irrespective of whether such property is received or such services are rendered) or (4) otherwise to assure a creditor against loss, and (j) all Debt referred to in clauses (a) through (i) above secured by (or for which the holder of such Debt has an existing right, contingent or otherwise, to be secured by) any lien or property (including, without limitation, accounts and contract rights) owned by such Person, even though such Person has not assumed or become liable for the payment of such Indebtedness. 7 "DEFAULT" means any Event of Default or any event that would constitute an Event of Default but for the requirement that notice be given (other than the notice specified in Section 7.01(a)) or time elapse or both. "DEFAULTED ADVANCE" means, with respect to any Lender at any time, the portion of any Advance required to be made by such Lender to the Borrower pursuant to Section 2.01 at or prior to such time which has not been made by such Lender or by the Administrative Agent for the account of such Lender pursuant to Section 2.02(d) as of such time. In the event that a portion of a Defaulted Advance shall be deemed made pursuant to Section 2.14(a), the remaining portion of such Defaulted Advance shall be considered a Defaulted Advance originally required to be made pursuant to Section 2.01 on the same date as the Defaulted Advance so deemed made in part. "DEFAULTED AMOUNT" means, with respect to any Lender at any time, any amount required to be paid by such Lender to the Administrative Agent, the Collateral Agent or any other Lender hereunder or under any other Loan Document at or prior to such time which has not been so paid as of such time, including, without limitation, any amount required to be paid by such Lender to (a) the Administrative Agent pursuant to Section 2.02(d) to reimburse the Administrative Agent for the amount of any Advance made by the Administrative Agent for the account of such Lender, (b) any other Lender pursuant to Section 2.12 to purchase any participation in Advances owing to such other Lender and (c) the Administrative Agent or the Collateral Agent pursuant to Section 8.05 to reimburse the Administrative Agent or the Collateral Agent for such Lender's ratable share of any amount required to be paid by the Lenders to the Administrative Agent or the Collateral Agent as provided therein. In the event that a portion of a Defaulted Amount shall be deemed paid pursuant to Section 2.14(b), the remaining portion of such Defaulted Amount shall be considered a Defaulted Amount originally required to be paid hereunder or under any other Loan Document on the same date as the Defaulted Amount so deemed paid in part. "DEFAULTING LENDER" means, at any time, any Lender that, at such time, (a) owes a Defaulted Advance or a Defaulted Amount or (b) shall take any action or be the subject of any action or proceeding of a type described in Section 7.01(f). "DEPOSITARY BANK" has the meaning specified in the recital of parties to this Agreement or its successor as provided in Section 4.01(b). "DISCLOSURE DOCUMENTS" means the Northeast Utilities 10-K for the year ended 1998 and 10-Q's for 8 the fiscal quarters ended March 30, 1999, June 30, 1999 and September 30, 1999 and Forms 8-K filed on October 19, 1999, October 29, 1999 and January 21, 2000 and filed on and through February 29, 2000. "DOMESTIC LENDING OFFICE" means, with respect to any Lender, the office of such Lender specified as its "Domestic Lending Office" opposite its name on Schedule I hereto or in the Assignment and Acceptance pursuant to which it became a Lender, as the case may be, or such other office of such Lender as such Lender may from time to time specify to the Borrower and the Administrative Agent. "ELIGIBLE ASSIGNEE" means (i) an Initial Lender; (ii) an Affiliate of an Initial Lender; (iii) a commercial bank organized under the laws of the United States, or any State thereof, and having total assets in excess of US$10,000,000,000; (iv) a savings and loan association or savings bank organized under the laws of the United States, or any State thereof, and having total assets in excess of US$10,000,000,000; (v) a commercial bank organized under the laws of any other country that is a member of the OECD or has concluded special lending arrangements with the International Monetary Fund associated with its General Arrangements to borrow, or a political subdivision of any such country, and having total assets in excess of US$10,000,000,000, so long as such bank is acting through a branch or agency located in the country in which it is organized or another country that is described in this clause (v); (vi) a finance company, insurance company or other financial institution or fund (whether a corporation, partnership, trust or other entity) that is engaged in making, purchasing or otherwise investing in commercial loans in the ordinary course of its business and having total assets in excess of US$10,000,000,000; and (vii) any other Person approved by the Administrative Agent and the Borrower, such approval not to be unreasonably withheld or delayed (and, in the case of the Borrower, not to be required if an Event of Default exists); PROVIDED, HOWEVER, that neither any Loan Party nor any Affiliate of any Loan Party shall qualify as an Eligible Assignee hereunder. "ENFORCEMENT ACTION" means any action by the Collateral Agent, the Administrative Agent or any Lender that would have the effect of (a) declaring the Notes, all interest thereon and all other amounts payable under this Agreement and the other Loan Documents to be forthwith due and payable in accordance with Section 7.01 of this Agreement (b) exercising any right of set-off or counterclaim, (b) initiating any judicial or non-judicial proceedings to enforce the payment of any part of the outstanding Obligations or any other amounts owed under any Loan Document, (c) 9 commencing judicial or non-judicial enforcement of any of its rights or remedies under any of the Collateral Documents, or (d) appointing or consenting to the appointment of a receiver or other similar official for the management of the Borrower or for the custody or control of any assets or proceeds of assets of the Borrower. "ENGAGEMENT LETTER" means the Engagement Letter dated June 11, 1999, and as amended on February 9, 2000, among Citibank, the Borrower and Northeast Utilities. "ENTERPRISES PLEDGE AGREEMENT" means, collectively, the Tranche A Enterprises Pledge Agreement and the Tranche B Enterprises Pledge Agreement. "ENVIRONMENTAL ACTION" means any action, suit, demand, demand letter, claim, notice of non-compliance or violation, notice of liability or potential liability, investigation, proceeding, consent order or consent agreement relating in any way to any Environmental Law, any Environmental Permit or Hazardous Material or arising from alleged injury or threat to health, safety or the environment, including, without limitation, (a) by any governmental or regulatory authority for enforcement, cleanup, removal, response, remedial or other actions or damages and (b) by any governmental or regulatory authority or third party for damages, contribution, indemnification, cost recovery, compensation or injunctive relief. "ENVIRONMENTAL LAW" means any federal, state, local or foreign statute, law, ordinance, rule, regulation, code, order, writ, judgment, injunction, decree or judicial or agency interpretation, policy or guidance relating to pollution or protection of the environment, health, safety or natural resources, including, without limitation, those relating to the use, handling, transportation, treatment, storage, disposal, release or discharge of Hazardous Materials. "ENVIRONMENTAL PERMIT" means any permit, approval, identification number, license or other authorization required under any Environmental Law. "EQUITY" means, at any date for the Borrower, an amount equal to the sum of the aggregate of the par value of, or stated capital represented by, the outstanding common shares of the Borrower and the surplus, paid-in, earned and other capital (excluding capital redeemable at the option of the holder), if any, of the Borrower, as determined in accordance with GAAP, as adjusted (without duplication) to add the amount by which the purchase price paid by the Borrower 10 exceeds the book value of the Generating Assets immediately prior to the Acquisition. "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time, and the regulations promulgated and rulings issued thereunder. "ERISA AFFILIATE" means any Person that for purposes of Title IV of ERISA is a member of the controlled group of any Loan Party, or under common control with any Loan Party, within the meaning of Section 414 of the Internal Revenue Code. "ERISA EVENT" means (a) (i) the occurrence of a reportable event, within the meaning of Section 4043 of ERISA, with respect to any Plan unless the 30-day notice requirement with respect to such event has been waived by the PBGC, or (ii) the requirements of subsection (1) of Section 4043(b) of ERISA (without regard to subsection (2) of such Section) are met with respect to a contributing sponsor, as defined in Section 4001(a)(13) of ERISA, of a Plan, and an event described in paragraph (9), (10), (11), (12) or (13) of Section 4043(c) of ERISA is reasonably expected to occur with respect to such Plan within the following 30 days; (b) the application for a minimum funding waiver with respect to a Plan; (c) the provision by the administrator of any Plan of a notice of intent to terminate such Plan, pursuant to Section 4041(a)(2) of ERISA (including any such notice with respect to a plan amendment referred to in Section 4041(e) of ERISA); (d) the cessation of operations at a facility of any Loan Party or any ERISA Affiliate in the circumstances described in Section 4062(e) of ERISA; (e) the withdrawal by any Loan Party or any ERISA Affiliate from a Multiple Employer Plan during a plan year for which it was a substantial employer, as defined in Section 4001(a)(2) of ERISA; (f) the conditions for imposition of a lien under Section 302(f) of ERISA shall have been met with respect to any Plan; (g) the adoption of an amendment to a Plan requiring the provision of security to such Plan pursuant to Section 307 of ERISA; or (h) the institution by the PBGC of proceedings to terminate a Plan pursuant to Section 4042 of ERISA, or the occurrence of any event or condition described in Section 4042 of ERISA that constitutes grounds for the termination of, or the appointment of a trustee to administer, such Plan. "EUROCURRENCY LIABILITIES" has the meaning specified in Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time. "EURODOLLAR LENDING OFFICE" means, with respect to any Lender, the office of such Lender specified as its 11 "Eurodollar Lending Office" opposite its name on Schedule I hereto or in the Assignment and Acceptance pursuant to which it became a Lender (or, if no such office is specified, its Domestic Lending Office), or such other office of such Lender as such Lender may from time to time specify to the Borrower and the Administrative Agent. "EURODOLLAR RATE" means, for any Interest Period for each Eurodollar Rate Advance comprising part of the same Borrowing, an interest rate per annum equal to the rate per annum obtained by dividing (a) the rate that is set forth on Telerate Page Number 3750 (or any other page that may replace such page from time to time) as of 11:00 A.M. (London time) on the second Business Day prior to the first day of any interest period for U.S. Dollar deposits having a tenor equal to the applicable Interest Period or if none of such page 3750 nor any successor or similar service is available, relative to any Eurodollar Rate Advance, the rate of interest per annum determined by the Administrative Agent to be the arithmetic mean (rounded upward to the next 0.01%) of the rates of interest per annum at which dollar deposits in the approximate amount of the amount to be made or continued as, or converted into, a Eurodollar Rate Advance by the Administrative Agent and having a maturity comparable to such Interest Period are offered in immediately available funds to the Administrative Agent in the London interbank market at its request at approximately 11:00 a.m. (London time) two Business Days prior to the commencement of such Interest Period by (b) a percentage equal to 100% minus the Eurodollar Rate Reserve Percentage for such Interest Period. "EURODOLLAR RATE ADVANCE" means an Advance that bears interest as provided in Section 2.06(a)(ii). "EURODOLLAR RATE RESERVE PERCENTAGE" for any Interest Period for all Eurodollar Rate Advances comprising part of the same Borrowing means the reserve percentage applicable two Business Days before the first day of such Interest Period under regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, without limitation, any emergency, supplemental or other marginal reserve requirement) for a member bank of the Federal Reserve System in New York City with respect to liabilities or assets consisting of or including Eurocurrency Liabilities (or with respect to any other category of liabilities that includes deposits by reference to which the interest rate on Eurodollar Rate Advances is determined) having a term equal to such Interest Period. "EVENTS OF DEFAULT" has the meaning specified in Section 7.01. 12 "EXCESS CASH FLOW" shall mean for any Excess Cash Flow Payment Date, the excess of (a) all cash receipts of the Borrower (including, but not limited to, Revenues, but excluding Net Cash Proceeds) actually received by the Borrower during the period from the prior Excess Cash Flow Payment Date (or the Borrowing Date with respect to the first Excess Cash Flow Payment Date) to the date immediately prior to such Excess Cash Flow Payment Date OVER (b) the sum (without duplication) of (i) Operating Costs and Permitted Capital Expenditures paid during such period and (ii) Obligations (other than mandatory prepayments pursuant to Section 2.05(b) hereof and payments of interest in respect thereof pursuant to Section 2.06 hereof) arising under the Loan Documents paid during such period. For purposes of this definition, cash receipts shall exclude, to the extent included, any insurance proceeds deposited into the Casualty Account. "EXCESS CASH FLOW PAYMENT DATE" shall mean May 1, 2000, August 1, 2000 and November 1, 2000. "EXEMPT WHOLESALE GENERATOR" has the meaning specified in Section 32(a)(1) of the Public Utility Holding Company Act of 1935. "EXTRAORDINARY RECEIPT" means any cash received by or paid to or for the account of any Person not in the ordinary course of business, including, without limitation, tax refunds, pension plan reversions, proceeds of insurance (other than proceeds of business interruption insurance to the extent such proceeds constitute compensation for lost earnings), condemnation awards (and payments in lieu thereof) and indemnity payments; PROVIDED, HOWEVER, that an Extraordinary Receipt shall not include cash receipts received from proceeds of insurance, condemnation awards (or payments in lieu thereof) or indemnity payments to the extent that such proceeds, awards or payments (A) in respect of loss or damage to equipment, fixed assets or real property are applied (or in respect of which expenditures were previously incurred) to replace or repair the equipment, fixed assets or real property in accordance with the terms of the Loan Documents, so long as such application is made within six months after the receipt of such proceeds or (B) are received by any Person in respect of any third party claim against such Person and applied to pay (or to reimburse such Person for its prior payment of) such claim and the costs and expenses of such Person with respect thereto. "FEDERAL FUNDS RATE" means, for any period, a fluctuating interest rate per annum equal for each day during such period to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds 13 brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average of the quotations for such day for such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it. "FEE LETTER" means the Fee Letter dated as of February 9, 2000, among the Borrower, Northeast Utilities and the Co-Arrangers. "FERC" means the Federal Energy Regulatory Commission. "FISCAL YEAR" means a fiscal year of the Borrower ending on December 31 in any calendar year. "FLOW OF FUNDS MEMORANDUM" means the memorandum regarding the flow of funds and procedures on the Borrowing Date, attached as Exhibit G hereto. "GAAP" has the meaning specified in Section 1.03. "GENERATING ASSETS" means the CL&P Generating Assets and the WMECO Generating Assets. "GOVERNMENTAL AUTHORITY" means any nation or government, any state, province or other political subdivision thereof, and any governmental, executive, legislative, judicial, administrative or regulatory agency, department, authority, instrumentality, commission, board or similar body, whether federal, state, provincial, territorial, local or foreign. "GOVERNMENTAL AUTHORIZATION" means any authorization, approval, consent, franchise, license, covenant, order, ruling, permit, certification, exemption or similar right or action of or by, or filing or registration with or notice to, any Governmental Authority. "HAZARDOUS MATERIALS" means (a) petroleum or petroleum products, by-products or breakdown products, radioactive materials, asbestos-containing materials, polychlorinated biphenyls and radon gas and (b) any other chemicals, materials or substances designated, classified or regulated as hazardous or toxic or as a pollutant under any Environmental Law. "HOUSATONIC SYSTEM" means the six hydroelectric plants known as Falls Village, Bulls Bridge, Shepaug, Stevenson, Robertsville and Bantam and the one pump storage generating facility known as Rocky River, and the other assets acquired or to be acquired by the 14 Borrower from CL&P pursuant to the CL&P Purchase and Sale Agreement. "INDEMNIFIED PARTY" has the meaning specified in Section 9.04(b). "INDENTURES" shall mean the CL&P Indenture and the WMECO Indenture. "INITIAL LENDERS" means, collectively, the Tranche A Initial Lenders and the Tranche B Initial Lenders. "INSUFFICIENCY" means, with respect to any Plan, the amount, if any, of its unfunded benefit liabilities, as defined in Section 4001(a)(18) of ERISA. "INSURANCE CONSULTANT" means Aon Risk Services or such other insurance consultant selected by the Required Lenders and consented to by the Borrower which shall not be unreasonably withheld or delayed. "INTERCONNECTION AGREEMENTS" means the CL&P Interconnection Agreement and the WMECO Interconnection Agreement. "INTEREST PERIOD" means, for each Eurodollar Rate Advance comprising part of the same Borrowing, the period commencing on the date of such Eurodollar Rate Advance or the date of the Conversion of any Base Rate Advance into such Eurodollar Rate Advance, and ending on the last day of the period selected by the Borrower pursuant to the provisions below and, thereafter, each subsequent period commencing on the last day of the immediately preceding Interest Period and ending on the last day of the period selected by the Borrower pursuant to the provisions below. The duration of each such Interest Period shall be one, two or three months, as the Borrower may, upon notice received by the Administrative Agent not later than 11:00 A.M. (New York City time) on the third Business Day prior to the first day of such Interest Period, select; PROVIDED, HOWEVER, that: (a) no more than five Interest Periods shall be outstanding at any time; (b) the Borrower may not select any Interest Period with respect to any Tranche B Advance that ends after the Tranche B Maturity Date; (c) whenever the last day of any Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur on the next succeeding Business Day, PROVIDED, HOWEVER, that, if such 15 extension would cause the last day of such Interest Period to occur in the next following calendar month, the last day of such Interest Period shall occur on the next preceding Business Day; and (d) whenever the first day of any Interest Period occurs on a day of an initial calendar month for which there is no numerically corresponding day in the calendar month that succeeds such initial calendar month by the number of months equal to the number of months in such Interest Period, such Interest Period shall end on the last Business Day of such succeeding calendar month. "INTERNAL REVENUE CODE" means the Internal Revenue Code of 1986, as amended from time to time, and the regulations promulgated and rulings issued thereunder. "INVESTMENT" in any Person means any loan or advance to such Person, any purchase or other acquisition of any capital stock or other ownership or profit interest, warrants, rights, options, obligations or other securities of such Person, any capital contribution to such Person or any other investment in such Person, including, without limitation, any arrangement pursuant to which the investor incurs Debt of the types referred to in clause (i) or (j) of the definition of "DEBT" in respect of such Person. "LEAD BANK LETTER" means the Lead Bank Letter dated as of June 11, 1999, among the Borrower, Northeast Utilities and the Co-Arrangers. "LENDERS" means the Tranche A Lenders and the Tranche B Lenders. "LIEN" means any lien, security interest or other charge or encumbrance of any kind, or any other type of preferential arrangement, including, without limitation, the lien or retained security title of a conditional vendor and any easement, right of way or other encumbrance on title to real property. "LOAN DOCUMENTS" means this Agreement, the Notes, the Collateral Documents, the Northeast Utilities Guaranties and the Sponsor Agreement, in each case as amended or otherwise modified from time to time. "LOAN PARTIES" means the Borrower, NU Enterprises, Northeast Utilities, Select and NGS. "MARGIN STOCK" has the meaning specified in Regulation U. 16 "MATERIAL ADVERSE EFFECT" means a material adverse effect on (i) the business, financial condition, operations, performance, properties or prospects of any Loan Party, (ii) the rights and remedies of the Administrative Agent, the Collateral Agent or the Lenders under any Loan Document, (iii) the Liens in favor of the Collateral Agent for benefit of the Secured Parties, (iv) the legality, validity or enforceability of any Loan Document, any Project Document, any Material Contract or any Acquisition Document or (v) the ability of the Borrower, NU Enterprises or Northeast Utilities to perform its obligations under any Loan Document to which it is a party. "MATERIAL CONTRACT" means, collectively, the contracts set forth on Schedule 5.01(ee) of this Agreement and each other contract of the Borrower involving aggregate consideration payable to or by the Borrower of $10,000,000 or more in any Fiscal Year or the absence of which would result in a Material Adverse Effect to the Borrower or a material adverse effect on the operations or performance of the Generating Assets taken as a whole. "MATURITY DATE" means the Tranche A Maturity Date and the Tranche B Maturity Date. "METCALF & EDDY" means Metcalf & Eddy, Inc. "MOODY'S" means Moody's Investors Service, Inc. and any successor thereto that is a nationally recognized rating agency. "MORTGAGE POLICIES" has the meaning specified in Section 3.01(m)(ix)(B). "MORTGAGES" means, collectively, the Tranche A Mortgage and the Tranche B Mortgage. "MULTIEMPLOYER PLAN" means a multiemployer plan, as defined in Section 4001(a)(3) of ERISA, to which any Loan Party or any ERISA Affiliate is making or accruing an obligation to make contributions, or has within any of the preceding five plan years made or accrued an obligation to make contributions. "MULTIPLE EMPLOYER PLAN" means a single employer plan, as defined in Section 4001(a)(15) of ERISA, that (a) is maintained for employees of any Loan Party or any ERISA Affiliate and at least one Person other than the Loan Parties and the ERISA Affiliates or (b) was so maintained and in respect of which any Loan Party or any ERISA Affiliate could have liability under Section 4064 or 4069 of ERISA in the event such plan has been or were to be terminated. 17 "NEIGHBORING LANDOWNER AGREEMENTS" means a lease, license or other agreement between the Borrower (or a predecessor in interest of the Borrower) and an owner of real property adjacent to one of the impoundments located on the Borrower=s land, relating to recreational access and/or use by third party users of such impoundment. "NET CASH PROCEEDS" means, with respect to any sale, lease, transfer or other disposition of any asset by the Borrower, or any Extraordinary Receipt received by or paid to or for the account of the Borrower, the aggregate amount of cash received from time to time (whether as initial consideration or through payment or disposition of deferred consideration) by or on behalf of the Borrower in connection with such transaction after deducting therefrom only (without duplication) (a) reasonable and customary brokerage commissions, underwriting fees and discounts, legal fees, finder's fees and other similar fees and commissions and (b) the amount of taxes payable in connection with or as a result of such transaction, in each case to the extent, but only to the extent, that the amounts so deducted are, at the time of receipt of such cash, actually paid to a Person that is not an Affiliate of such Person or any Loan Party and are properly attributable to such transaction or to the asset that is the subject thereof. "NGS" means Northeast Generation Services Company, a Connecticut corporation. "NON-FIRM POINT TO POINT AGREEMENT" refers to the Non-Firm Point to Point Transmission Service Agreement dated as of September 28, 1999, between NUSCO and the Borrower. "NORTHEAST UTILITIES" means Northeast Utilities, a Massachusetts business trust. "NORTHEAST UTILITIES GUARANTIES" means the two guaranties, issued by Northeast Utilities in favor of the Borrower, with respect to the Select Power Purchase Agreement and the O&M Agreement, respectively. "NORTHFIELD MOUNTAIN PROJECT" means the Northfield Mountain Pumped Storage Project that the Borrower is purchasing an 81% ownership interest in from CL&P pursuant to the CL&P Purchase and Sale Agreement and a 19% ownership interest in from WMECO pursuant to the WMECO Purchase and Sale Agreement. "NORTHFIELD OPERATING AGREEMENT" means the Northfield Mountain Project Operating Agreement dated as of February 14, 1968 (as amended by the March 1, 1974 amendment), among CL&P, WMECO and The Hartford Electric Light Company. 18 "NOTE" means either a Tranche A Note or a Tranche B Note. "NOTICE OF BORROWING" has the meaning specified in Section 2.02(a). "NPL" means the National Priorities List under CERCLA. "NU ENTERPRISES" means NU Enterprises, Inc., a Connecticut corporation. "NUSCO" means Northeast Utilities Services Company. "NUSCO SERVICE AGREEMENT" means the Northeast Utilities Service Company Service Contract, dated as of January 1, 1999, as renewed on December 31, 1999, between the Borrower and NUSCO. "OBLIGATION" means, with respect to any Person, any payment, performance or other obligation of such Person of any kind, including, without limitation, any liability of such Person on any claim, whether or not the right of any creditor to payment in respect of such claim is reduced to judgment, liquidated, unliquidated, fixed, contingent, matured, disputed, undisputed, legal, equitable, secured or unsecured, and whether or not such claim is discharged, stayed or otherwise affected by any proceeding referred to in Section 7.01(f). Without limiting the generality of the foregoing, the Obligations of the Loan Parties under the Loan Documents include (a) the obligation to pay principal, interest, charges, expenses, fees, attorneys' fees and disbursements, indemnities and other amounts payable by any Loan Party under any Loan Document and (b) the obligation of any Loan Party to reimburse any amount in respect of any of the foregoing that any Lender, in its sole discretion, may elect to pay or advance on behalf of such Loan Party. "OECD" means the Organization for Economic Cooperation and Development. "O&M AGREEMENT" means the Management and Operation Agreement dated February 1, 2000, as amended on March 1, 2000, between NGS and the Borrower. "OPERATING ACCOUNT" means the operating account of the Borrower maintained by the Borrower with Fleet National Bank at its office at Providence, R.I., Account No. 9417547475, ABA No. 011500010, Ref: Northeast Generation Company, which is in the sole dominion and control of the Borrower. "OPERATING COSTS" shall mean, for any period, the sum, computed without duplication, of all costs and 19 expenses paid by the Borrower during such period (or, in the case of any future period, projected to be paid or payable during such period) in connection with the operation, maintenance and administration of the Generating Assets, including, without limiting the generality of the foregoing, (a) costs of operating and administering the Generating Assets and of maintaining them in good repair and operating condition (including all amounts due and payable under the O&M Agreement), (b) costs of insurance, (c) costs of supplies and other services acquired in connection with the operation and maintenance of the Generating Assets, (d) sales and excise taxes payable by the Borrower, (e) income taxes payable by the Borrower, (f) costs and fees attendant to the obtaining and maintaining in effect the Governmental Authorizations relating to the Generating Assets, (g) legal, accounting and other professional fees attendant to any of the foregoing and (h) payments in respect of Debt permitted under Section 6.02(b)(ii) and Section 6.02(b)(iii); PROVIDED that all of the foregoing costs and expenses shall be determined on a cash basis and shall not include the cost of scheduled Capital Expenditures, depreciation, amortization and other non-cash items. "OTHER TAXES" has the meaning specified in Section 2.11(b). "PBGC" means the Pension Benefit Guaranty Corporation (or any successor). "PERMANENT FINANCING" means the Proposed Permanent Financing or any other capital markets, private placement or other debt issuance (including, without limitation, by entering into a bank credit facility) by the Borrower, the purpose of which is to refinance some or all of the Tranche B Advances. "PERMITTED CAPITAL EXPENDITURES" means, with respect to the Borrower, for any period, all Capital Expenditures contemplated for such period in the Annual Operating Budget or which the Borrower is otherwise permitted to incur pursuant to Section 6.02(n). "PERMITTED ENCUMBRANCES" has the meaning specified in the Mortgages. "PERMITTED HEDGE PROVIDER" means any Lender or its Affiliate providing a Permitted Hedge so long and only so long as such hedge provider remains a Lender or an Affiliate of a Lender. "PERMITTED HEDGES" means any anticipatory hedge product purchased by the Borrower, or Northeast Utilities for the benefit of the Borrower, such as a treasury rate lock, treasury collar or treasury put, for the purpose of hedging the Borrower's anticipated 20 interest rate exposure with respect to the Proposed Permanent Financing, PROVIDED, if the hedge product is provided by (a) a financial institution other than any Permitted Hedge Provider, such hedge provider shall not be entitled to have a lien on any properties or assets of the Borrower as security in respect of the hedge product, or (b) any Permitted Hedge Provider, such hedge provider shall be a Tranche B Secured Party under the Tranche B Collateral Documents entitled to the benefits of the Collateral under the Tranche B Collateral Documents pari passu with the other Tranche B Secured Parties, PROVIDED, FURTHER, HOWEVER, that such hedge provider shall have no voting rights under the Tranche B Collateral Documents. "PERMITTED INVESTMENTS" means any of (a) time deposits of Citibank with such maturities as may be acceptable to the Collateral Agent, (b) commercial paper that is rated at least P-1 by Moody's and at least A-1+ by S&P (provided that the long-term unsecured debt ratings issued by Moody's and S&P for the issuer or the guarantor thereof are at least Aa3 and AA-, respectively), with such maturities and other terms as may be acceptable to the Collateral Agent in its sole discretion, (c) marketable obligations, maturing within 12 months after acquisition thereof, issued or unconditionally guaranteed by the United States of America or an instrumentality or agency thereof and entitled to the full faith and credit of the United States of America, (d) other than with respect to amounts in the Collateral Accounts, the Temp Fund of the Provident Institutional Fund, (e) investments in the Goldman Sachs FS Prime Obligations Fund Administration Class (463) or (f) such other investments as may be requested by the Borrower and acceptable to the Collateral Agent in its reasonable discretion. "PERMITTED LIENS" means such of the following as to which no enforcement, collection, execution, levy or foreclosure proceeding shall have been commenced: (a) Liens for taxes, assessments and governmental charges or levies to the extent not required to be paid under Section 6.01(b) hereof; (b) Liens imposed by law, such as materialmen's, mechanics', carriers', workmen's and repairmen's Liens and other similar Liens arising in the ordinary course of business securing obligations that are not overdue for a period of more than 30 days; (c) pledges or deposits to secure obligations under workers' compensation laws or similar legislation or to secure public or statutory obligations; and (d) easements, rights of way and other encumbrances on title to real property that do not render title to the property encumbered thereby unmarketable or materially adversely affect the use of such property for its present purposes. 21 "PERSON" means an individual, partnership, corporation (including a business trust), limited liability company, joint stock company, trust, unincorporated association, joint venture or other entity, or a government or any political subdivision or agency thereof. "PLACEMENT AGENT" means the placement agent chosen by the Borrower in connection with the Proposed Permanent Financing. "PLAN" means a Single Employer Plan or a Multiple Employer Plan. "PLEDGED SHARES" has the meaning set forth in the Collateral Documents. "PROJECT DOCUMENTS" means the Select Power Purchase Agreement, the O&M Agreement, the Northeast Utilities Guaranties, the NUSCO Service Agreement, any other purchase and sale agreement with respect to sales of the Product (as defined in the O&M Agreement) entered into by the Borrower and any other third party, the Interconnection Agreements, the Asset Demarcation Agreements, the Property Tax Allocation Agreement and the Non-Firm Point to Point Agreement. "PROPERTY TAX ALLOCATION AGREEMENT" means (a) the Real and Personal Property Tax Allocation Agreement, dated as of the Acquisition Date between the Borrower and CL&P and (b) the Real and Personal Property Tax Allocation Agreement, dated as of the Acquisition Date between the Borrower and WMECO. "PROPOSED PERMANENT FINANCING" means the private placement, in accordance with Rule 144A of the Securities Act of 1933, as amended from time to time, of debt securities proposed to be issued by the Borrower in an amount equal to at least the then outstanding amount of the Tranche B Advances hereunder to repay such Advances. "PURCHASE AND SALE AGREEMENTS" means the WMECO Purchase and Sale Agreement and the CL&P Purchase and Sale Agreement. "PURCHASE PRICE" means the aggregate amount payable by the Borrower to CL&P and WMECO as the purchase price for the Generating Assets pursuant to the Purchase and Sale Agreements. "RATING AGENCIES" shall mean S&P and Moody's. "REGISTER" has the meaning specified in Section 9.07(d). 22 "REGULATION U" means Regulation U of the Board of Governors of the Federal Reserve System, as in effect from time to time. "REPLACEMENT LENDER" has the meaning specified in Section 2.09(e). "REQUIRED LENDERS" means at any time Lenders owed at least 66 2/3% of the then aggregate unpaid principal amount of the Advances owing to Lenders, or, if no such principal amount is then outstanding, Lenders having at least 66 2/3% of the Commitments. "REQUIRED RATING" means a rating of at least BBB- (or the then equivalent grade) from S&P and Baa3 (or the then equivalent grade) from Moody's. "REQUIRED TRANCHE A LENDERS" means at any time the Tranche A Lenders owed at least 66 2/3% of the then aggregate unpaid principal amount of the Tranche A Advances owing to the Tranche A Lenders, or, if no such principal amount is then outstanding, Tranche A Lenders having at least 66 2/3% of the Tranche A Commitments. "REQUIRED TRANCHE B LENDERS" means at any time the Tranche B Lenders owed at least 66 2/3% of the then aggregate unpaid principal amount of the Tranche B Advances owing to the Tranche B Lenders, or, if no such principal amount is then outstanding, Tranche B Lenders having at least 66 2/3% of the Tranche B Commitments. "RESPONSIBLE OFFICER" means any of the chief executive officer, the president, the treasurer or any vice president of any Loan Party or any of its Subsidiaries. "REVENUES" shall mean, for any period, the sum, computed without duplication, of all cash receipts received by the Borrower during such period (or, in the case of any future period, projected to be received during such period) pursuant to (a) the Project Documents, including, without limitation, (x) amounts paid by third parties such as guarantors and letter of credit banks, and (y) any and all damages, arbitration awards or other monetary settlements payable to the Borrower, (b) proceeds of any business interruption insurance and other payments received for interruption of operations (excluding proceeds of physical damage or liability insurance), and (c) investment earnings on Permitted Investments held in the Revenues Account. Revenues shall exclude, to the extent included, proceeds of insurance paid in respect of loss or damage of any Generating Asset. "REVENUES ACCOUNT" means the revenues account of the Borrower maintained pursuant to Article IV hereof by the Collateral Agent with Citibank's office at 111 23 Wall Street, New York, New York 10043, Account No.3611-4325, ABA No. 0210-0008-9, FBO A/C 103560 Attention: Olivia Sharp. "S&P" means Standard & Poor's Ratings Services, a division of The McGraw-Hill Companies, Inc., and any successor thereto that is a nationally recognized rating agency. "SECURED OBLIGATIONS" has the meaning specified in the Collateral Documents. "SECURED PARTIES" means the Tranche A Secured Parties and the Tranche B Secured Parties. "SELECT" means Select Energy, Inc., a Connecticut corporation. "SELECT POWER PURCHASE AGREEMENT" means the Power Purchase and Sale Agreement dated December 27, 1999, between Select and the Borrower. "SINGLE EMPLOYER PLAN" means a single employer plan, as defined in Section 4001(a)(15) of ERISA, that (a) is maintained for employees of any Loan Party or any ERISA Affiliate and no Person other than the Loan Parties and the ERISA Affiliates or (b) was so maintained and in respect of which any Loan Party or any ERISA Affiliate could have liability under Section 4069 of ERISA in the event such plan has been or were to be terminated. "SOLVENT" and "SOLVENCY" mean, with respect to any Person on a particular date, that on such date (a) the fair value of the property of such Person is greater than the total amount of liabilities, including, without limitation, contingent liabilities, of such Person, (b) the present fair salable value of the assets of such Person is not less than the amount that will be required to pay the probable liability of such Person on its debts as they become absolute and matured, (c) such Person does not intend to, and does not believe that it will, incur debts or liabilities beyond such Person's ability to pay such debts and liabilities as they mature and (d) such Person is not engaged in business or a transaction, and is not about to engage in business or a transaction, for which such Person's property would constitute an unreasonably small capital. The amount of contingent liabilities at any time shall be computed as the amount that, in the light of all the facts and circumstances existing at such time, represents the amount that can reasonably be expected to become an actual or matured liability. "SPONSOR AGREEMENT" means the sponsor agreement of Northeast Utilities in favor of the Collateral Agent, substantially in the form of Exhibit H attached hereto. 24 "STONE & WEBSTER" means Stone & Webster Management Consultants, Inc. "SUBSIDIARY" of any Person means any corporation, partnership, joint venture, limited liability company, trust or estate of which (or in which) more than 50% of (a) the issued and outstanding capital stock having ordinary voting power to elect a majority of the Board of Directors of such corporation (irrespective of whether at the time capital stock of any other class or classes of such corporation shall or might have voting power upon the occurrence of any contingency), (b) the interest in the capital or profits of such partnership, joint venture or limited liability company or (c) the beneficial interest in such trust or estate is at the time directly or indirectly owned or controlled by such Person, by such Person and one or more of its other Subsidiaries or by one or more of such Person's other Subsidiaries. "TAX CERTIFICATE" has the meaning specified in Section 6.03(m). "TAX SHARING AGREEMENT" means the Amended and Restated Tax Allocation Agreement, dated January 1, 1990 (as amended on October 26, 1998 and on March 1, 2000), to be entered into by the Borrower with NU and various other Subsidiaries of NU (a copy of which was delivered to the Lenders pursuant to Section 3.01(m)(xviii)), together with any other tax sharing agreement entered into by the Borrower in accordance with Section 6.02(o). "TAXES" has the meaning specified in Section 2.11(a). "TERMINATION DATE" means the earlier (x) December 29, 2000 or (y) the date of termination in whole of the Commitments pursuant to Section 2.04 or 7.01. "THIRD PARTY CONSENTS" has the meaning specified in Section 5.01(d). "TOTAL CAPITALIZATION" means, at any date, for the Borrower, the sum of (i) the aggregate principal amount of all long-term and short-term Debt of the Borrower, and (ii) the Equity. "TRANCHE A ADVANCE" has the meaning specified in Section 2.01(a). "TRANCHE A AMOUNTS" has the meaning specified in Section 2.03(a). "TRANCHE A BORROWER SECURITY AGREEMENT" means the agreement by the Borrower in favor of the Collateral 25 Agent for the benefit of the Tranche A Secured Parties, substantially in the form of Exhibit D-1 attached hereto. "TRANCHE A BORROWING" means a borrowing consisting of Tranche A Advances of the same Type made on the same day by the Tranche A Lenders. "TRANCHE A COLLATERAL DOCUMENTS" means the Tranche A Borrower Security Agreement, the Tranche A Enterprises Pledge Agreement, the Tranche A Mortgage and the Tranche A Note. "TRANCHE A COMMITMENT" has the meaning specified in Section 2.01(a). "TRANCHE A ENTERPRISES PLEDGE AGREEMENT" means the agreement by NU Enterprises in favor of the Collateral Agent for the benefit of the Tranche A Secured Parties, substantially in the form of Exhibit E-1 attached hereto. "TRANCHE A INITIAL LENDERS" has the meaning specified in the recital of parties to this Agreement. "TRANCHE A LENDERS" means the Tranche A Initial Lenders and each Person, other than natural persons, that have or shall become and remain a party hereto as a "Tranche A Lender" pursuant to Section 9.07. "TRANCHE A LIEN" has the meaning specified in Section 8.07. "TRANCHE A MATURITY DATE" means the Borrowing Date. "TRANCHE A MORTGAGE" means the mortgage with respect to the Tranche A Advances, substantially in the form of Exhibit F-1. "TRANCHE A NOTE" means a promissory note of the Borrower payable to the order of any Tranche A Lender, in substantially the form of Exhibit A-1 hereto, evidencing the indebtedness of the Borrower to such Tranche A Lender resulting from the Tranche A Advances made by or owed to such Tranche A Lender. "TRANCHE A OBLIGATIONS" means all Tranche A Amounts owed by the Borrower to the Tranche A Secured Parties under the Loan Documents. "TRANCHE A SECURED PARTIES" means (a) the Tranche A Lenders and (b) the Collateral Agent as party to the Tranche A Collateral Documents. "TRANCHE B ADVANCE" has the meaning specified in Section 2.01(b). 26 "TRANCHE B BORROWER SECURITY AGREEMENT" means the agreement by the Borrower in favor of the Collateral Agent for the benefit of the Tranche B Secured Parties, substantially in the form of Exhibit D-2 attached hereto. "TRANCHE B BORROWING" means a borrowing consisting of Tranche B Advances of the same Type made on the same day by the Tranche B Lenders. "TRANCHE B COLLATERAL DOCUMENTS" means the Tranche B Borrower Security Agreement, the Tranche B Enterprises Pledge Agreement, the Tranche B Mortgage and the Tranche B Note. "TRANCHE B COMMITMENT" has the meaning specified in Section 2.01(b). "TRANCHE B ENTERPRISES PLEDGE AGREEMENT" means the agreement by NU Enterprises in favor of the Collateral Agent for the benefit of the Tranche B Secured Parties, substantially in the form of Exhibit E-2 attached hereto. "TRANCHE B INITIAL LENDERS" has the meaning specified in the recital of parties to this Agreement. "TRANCHE B LENDERS" means the Tranche B Initial Lenders and each Person, other than natural persons, that have or shall become and remain a party hereto as a "Tranche B Lender" pursuant to Section 9.07. "TRANCHE B LIEN" has the meaning specified in Section 8.07. "TRANCHE B MATURITY DATE" means December 29, 2000. "TRANCHE B MORTGAGE" means the mortgage with respect to Tranche B Advances, substantially in the form of Exhibit F-2. "TRANCHE B NOTE" means a promissory note of the Borrower payable to the order of any Tranche B Lender, in substantially the form of Exhibit A-2 hereto, evidencing the indebtedness of the Borrower to such Tranche B Lender resulting from the Tranche B Advances made by or owed to such Tranche B Lender. "TRANCHE B OBLIGATIONS" means all amounts owed by the Borrower to the Tranche B Secured Parties under the Loan Documents other than the Tranche A Amounts. "TRANCHE B SECURED PARTIES" means (a) the Tranche B Lenders, (b) each of the Collateral Agent and the Administrative Agent as parties to the Tranche B Collateral Documents and the other Loan Documents to 27 which each is a party, and (c) the Permitted Hedge Providers, if any. "TYPE" has the meaning specified in the definition of "Advance" in this Section 1.01. "UCC" means the Uniform Commercial Code as in effect from time to time in the State of New York. "VOTING STOCK" means capital stock issued by a corporation, or equivalent interests in any other Person, the holders of which are ordinarily, in the absence of contingencies, entitled to vote for the election of directors (or persons performing similar functions) of such Person, even if the right so to vote has been suspended by the happening of such a contingency. "WELFARE PLAN" means a welfare plan, as defined in Section 3(1) of ERISA, that is maintained for employees of any Loan Party or in respect of which any Loan Party could have liability. "WITHDRAWAL LIABILITY" has the meaning specified in Part I of Subtitle E of Title IV of ERISA. "WMECO" has the meaning set forth in the Preliminary Statements to this Agreement. "WMECO ACQUISITION" means the acquisition by the Borrower of the WMECO Generating Assets. "WMECO ACQUISITION DOCUMENTS" means the WMECO Asset Demarcation Agreement, the WMECO Assumption Agreement, the WMECO Interconnection Agreement and the WMECO Purchase and Sale Agreement. "WMECO ASSIGNMENT AND ASSUMPTION AGREEMENT" means the Assignment and Assumption Agreement, dated as of March 14, 2000, between the Borrower and WMECO. "WMECO ASSET DEMARCATION AGREEMENT" means the Asset Demarcation Agreement dated as of the Acquisition Date, between WMECO and the Borrower. "WMECO ASSUMPTION AGREEMENT" means the Assumption Agreement dated July 2, 1999, between Northeast Utilities and WMECO. "WMECO GENERATING ASSETS" means the hydroelectric and pumped storage generating assets and related assets acquired or to be acquired, as the case may be, by the Borrower from WMECO pursuant to the WMECO Purchase and Sale Agreement. "WMECO INDENTURE" means the First Mortgage Indenture and Deed of Trust dated as of August 1, 1954, 28 as amended as of the date hereof, between WMECO and State Street Bank and Trust Company. "WMECO INTERCONNECTION AGREEMENT" means the Interconnection Agreement dated July 2, 1999, between the Borrower and WMECO. "WMECO PURCHASE AND SALE AGREEMENT" means the Purchase and Sale Agreement dated July 2, 1999, between the Borrower and WMECO. "WMECO PURCHASE PRICE" means the aggregate amount payable by the Borrower to WMECO for the WMECO Generating Assets pursuant to the WMECO Purchase and Sale Agreements. SECTION 1.02. COMPUTATION OF TIME PERIODS. In this Agreement in the computation of periods of time from a specified date to a later specified date, the word "from" means "from and including" and the words "to" and "until" each mean "to but excluding". SECTION 1.03. ACCOUNTING TERMS. All accounting terms not specifically defined herein shall be construed in accordance with generally accepted accounting principles consistent with those applied in the preparation of the financial statements referred to in Section 5.01(f) ("GAAP"). SECTION 1.04. REFERENCES TO OTHER AGREEMENTS. Unless otherwise provided herein, references to any other agreement or document shall refer to such agreement or document as amended, supplemented or otherwise modified in accordance with the terms hereof and thereof. ARTICLE II AMOUNTS AND TERMS OF THE ADVANCES SECTION 2.01. THE ADVANCES. (a) Each Tranche A Lender severally agrees, on the terms and conditions hereinafter set forth, to make one advance (the "TRANCHE A ADVANCE") to the Borrower, on the Borrowing Date, which must occur on a Business Day during the period from the date hereof until the Termination Date, in an aggregate amount not to exceed the amount set forth opposite such Tranche A Lender's name on Schedule I attached hereto under the heading "Tranche A Commitment" or, if such Tranche A Lender has entered into any Assignment and Acceptance, set forth for such Tranche A Lender in the Register (under the heading "Tranche A Commitment") maintained by the Administrative Agent pursuant to Section 9.07(d), as such amount may be decreased pursuant to Section 2.04 (such Tranche A Lender's "TRANCHE A COMMITMENT"), PROVIDED, HOWEVER, that (i) each Tranche A Lender shall make no more than one Tranche A 29 Advance and (ii) the Tranche A Advances and the Tranche B Advances shall be made on the same Borrowing Date. The Tranche A Borrowing shall be in an aggregate amount of U.S.$5,000,000 or an integral multiple of U.S.$1,000,000 in excess thereof and shall consist of Tranche A Advances made simultaneously by the Tranche A Lenders ratably according to their respective Tranche A Commitments. Amounts borrowed under this Section 2.01(a) and repaid or prepaid may not be reborrowed. (b) Each Tranche B Lender severally agrees, on the terms and conditions hereinafter set forth, to make one advance (the "TRANCHE B ADVANCE") to the Borrower, on the Borrowing Date, which must occur on a Business Day during the period from the date hereof until the Termination Date, in an aggregate amount not to exceed the amount set forth opposite such Tranche B Lender's name on Schedule I attached hereto (under the heading "Tranche B Commitment") or, if such Tranche B Lender has entered into any Assignment and Acceptance, set forth for such Tranche B Lender in the Register under the heading "Tranche B Commitment" maintained by the Administrative Agent pursuant to Section 9.07(d), as such amount may be decreased pursuant to Section 2.04 (such Tranche B Lender's "TRANCHE B COMMITMENT"), PROVIDED, HOWEVER, that (i) each Tranche B Lender shall make no more than one Tranche B Advance and (ii) the Tranche B Advances and the Tranche A Advances shall be made on the same Borrowing Date. The Tranche B Borrowing shall be in an aggregate amount of U.S.$5,000,000 or an integral multiple of U.S.$1,000,000 in excess thereof and shall consist of Tranche B Advances made simultaneously by the Tranche B Lenders ratably according to their respective Tranche B Commitments. Amounts borrowed under this Section 2.01(b) and repaid or prepaid may not be reborrowed. SECTION 2.02. MAKING THE ADVANCES. (a) The Borrowings of the Tranche A Advances and the Tranche B Advances shall be made on notice, given not later than 11:00 A.M. (New York City time) on the third Business Day prior to the date of the proposed Borrowings by the Borrower to the Administrative Agent, which shall give to each Lender prompt notice thereof by fax. The notice of Borrowings (the "NOTICE OF BORROWING") shall be by telephone, confirmed immediately in a writing, in substantially the form of Exhibit B hereto, sent by fax specifying therein the requested (i) date of the Borrowings, (ii) aggregate amount of the Borrowings, (iii) amount of the Tranche A Borrowing and of the Tranche B Borrowing, (iv) Type of Tranche B Advances comprising the Tranche B Borrowing, and (v) initial Interest Period for each Eurodollar Rate Advance. Each Lender shall, before 10:00 A.M. (New York City time) on the date of the Borrowings, make available for the account of its Applicable Lending Office to the Administrative Agent at the Administrative Agent's Account, in immediately available funds, such Lender's ratable portion of each of the Borrowings. After the Administrative Agent's receipt of such funds and upon fulfillment of the applicable conditions 30 set forth in Article III, the Administrative Agent will make such funds available in accordance with the terms of the Flow of Funds Memorandum. (b) Anything in subsection (a) above to the contrary notwithstanding, the Borrower may not select Eurodollar Rate Advances for (x) any Tranche A Advances or (y) any Borrowing if the obligation of the Lenders to make Eurodollar Rate Advances shall then be suspended pursuant to Section 2.08 or 2.09. (c) The Notice of Borrowing shall be irrevocable and binding on the Borrower. The Borrower shall indemnify each Lender against any loss, cost or expense incurred by such Lender as a result of any failure of the Borrower to fulfill on or before the date specified in such Notice of Borrowing the applicable conditions set forth in Article III, including, without limitation, any loss (including loss of anticipated profits), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by such Lender to fund any Advance to be made by such Lender as part of the Borrowings when such Advance, as a result of such failure, is not made on such date. (d) Unless the Administrative Agent shall have received notice from a Lender prior to the date of the Borrowing that such Lender will not make available to the Administrative Agent such Lender's ratable portion of each Borrowing, the Administrative Agent may assume that such Lender has made such portion available to the Administrative Agent on the date of the Borrowing in accordance with subsection (a) of this Section 2.02 and the Administrative Agent may, in reliance upon such assumption, make available to the Borrower on such date a corresponding amount. If and to the extent that such Lender shall not have so made such ratable portion available to the Administrative Agent, such Lender agrees to pay to the Administrative Agent forthwith on demand such corresponding amount together with interest thereon, for each day from the date such amount is made available to the Borrower until the date such amount is paid to the Administrative Agent, at the Federal Funds Rate. If such Lender shall pay to the Administrative Agent such corresponding amount, such amount so paid shall constitute such Lender's Advance as part of the applicable Borrowing for purposes of this Agreement. (e) The failure of any Lender to make the Advance to be made by it as part of either Borrowing shall not relieve any other Lender of its obligation, if any, hereunder to make its Advance(s) on the date of the Borrowings, but no Lender shall be responsible for the failure of any other Lender to make the Advance(s) to be made by such other Lender on the date of any Borrowings. The rights and obligations of each of the Lenders under the Agreement are several. 31 SECTION 2.03. REPAYMENT OF ADVANCES. (a) TRANCHE A ADVANCES. On the Tranche A Maturity Date, the Borrower shall repay to the Administrative Agent for the ratable account of the Tranche A Secured Parties (i) the aggregate outstanding principal amount of the Tranche A Advances on such date, together with all accrued and unpaid interest on such Advances, and (ii) all fees, expenses and other amounts owing hereunder and under the other Loan Documents in respect of such Advances (all such amounts in clauses (i) and (ii) above, the "TRANCHE A AMOUNTS"). If the Administrative Agent receives the repayment of the Tranche A Amounts on the Tranche A Maturity Date but is unable to distribute the aggregate outstanding Tranche A Amounts to the Tranche A Lenders on the Tranche A Maturity Date, then the Administrative Agent will distribute to the Tranche A Lenders such Tranche A Amounts plus interest thereon at a per annum rate equal to the Federal Funds Rate on the next Business Day after the Tranche A Maturity Date. (b) TRANCHE B ADVANCES. On the Tranche B Maturity Date, the Borrower shall repay to the Administrative Agent for the ratable account of the Tranche B Lenders the aggregate principal amount of the Tranche B Advances outstanding on such date, together with all accrued and unpaid interest on such principal amount and all fees, expenses and other amounts owing hereunder and under the other Loan Documents. SECTION 2.04. ADJUSTMENTS OF THE COMMITMENTS. (a) On the Borrowing Date, after giving effect to the Borrowings on such date, the aggregate Commitments of the Lenders shall be automatically and permanently reduced to zero. (b) The Borrower may not otherwise reduce or terminate any of the Commitments. SECTION 2.05. PREPAYMENTS. (a) OPTIONAL. The Borrower may, upon at least five Business Days' notice to the Administrative Agent stating the proposed date and aggregate principal amount of the prepayment, and if such notice is given the Borrower shall, prepay the outstanding aggregate principal amount of the Tranche B Advances in whole or ratably among the Tranche B Lenders in part, together with accrued interest to the date of such prepayment on the principal amount prepaid; PROVIDED, HOWEVER, that (i) each partial prepayment shall be in an aggregate principal amount of $10,000,000 or an integral multiple of $1,000,000 in excess thereof and (ii) if any prepayment of a Eurodollar Rate Advance is made on a date other than the last day of an Interest Period for such Advance, the Borrower shall also pay any amounts owing pursuant to Section 9.04(c); PROVIDED FURTHER, HOWEVER, the Borrower may not optionally prepay any Tranche B Advances until the Tranche A Advances have been repaid in full and all Tranche A Commitments reduced to zero. 32 (b) MANDATORY. The Borrower shall: (i) on the issuance date of any Permanent Financing, prepay the aggregate outstanding principal amount of the Advances on such date, together with all accrued and unpaid interest on such principal amount and all fees, expenses and other amounts owing hereunder and under the other Loan Documents; (ii) within 30 days from the date of receipt by the Borrower of any Net Cash Proceeds from the sale, lease, transfer or other disposition of any assets of the Borrower (excluding sales of obsolete and worn out equipment, sales of electricity and any other ordinary course of business sales permitted in Section 6.02(e) and sales of any assets, replacements for which are intended to be purchased with such Net Cash Proceeds), prepay an aggregate principal amount of the outstanding Advances together with the accrued and unpaid interest thereon equal to the Net Cash Proceeds from such sale, lease, transfer or other disposition; (iii) within 30 days from the date of receipt by the Borrower of any Net Cash Proceeds from any Extraordinary Receipt, prepay an aggregate principal amount of the outstanding Advances together with the accrued and unpaid interest thereon equal to the Net Cash Proceeds from such Extraordinary Receipt; and (iv) on each Excess Cash Flow Payment Date, prepay an aggregate principal amount of the outstanding Advances together with all accrued and unpaid interest thereon equal to 100% of the Available Excess Cash Flow. Prepayments received pursuant to clauses (ii), (iii) and (iv) of this Section 2.05(b) shall be first applied ratably to reduce the Tranche B Advances outstanding until all such Tranche B Advances are reduced to zero, and then ratably to the Tranche A Advances outstanding, if any. SECTION 2.06. INTEREST. (a) SCHEDULED INTEREST. The Borrower shall pay to the Administrative Agent for the ratable account of the Lenders interest on the unpaid principal amount of each Advance from the date of such Advance until such principal amount shall be paid in full, at the following rates per annum: (i) BASE RATE ADVANCES. During such periods as such Advance is a Base Rate Advance, a rate per annum equal at all times to the sum of (A) the Base Rate in effect from time to time PLUS (B) the Applicable Margin in effect from time to time, payable in arrears monthly on the last day of each month during such periods and on the date such Base Rate Advance shall be Converted or paid in full. 33 (ii) EURODOLLAR RATE ADVANCES. During such periods as such Tranche B Advance is a Eurodollar Rate Advance, a rate per annum equal at all times during each Interest Period for such Tranche B Advance to the sum of (A) the Eurodollar Rate for such Interest Period for such Tranche B Advance PLUS (B) the Applicable Margin in effect from time to time, payable in arrears on the last day of such Interest Period and, if such Interest Period has a duration of more than three months, on each day that occurs during such Interest Period every three months from the first day of such Interest Period and on the date such Eurodollar Rate Advance shall be Converted or paid in full. (b) DEFAULT INTEREST. Upon the occurrence and during the continuance of an Event of Default, the Borrower shall pay to the Administrative Agent for the ratable account of the Lenders interest on (i) the unpaid principal amount of each Advance, payable in arrears on the dates referred to in clause (a)(i) or (a)(ii) above and on demand, at a rate per annum equal at all times to 2% per annum above the rate per annum required to be paid on such Advance pursuant to clause (a)(i) or (a)(ii) above and (ii) to the fullest extent permitted by law, the amount of any interest, fee or other amount payable hereunder that is not paid when due, from the date such amount shall be due until such amount shall be paid in full, payable in arrears on the date such amount shall be paid in full and on demand, at a rate per annum equal at all times to 2% per annum above the rate per annum required to be paid, in the case of interest, on the Type of Advance on which such interest has accrued pursuant to clause (a)(i) or (a)(ii) above, and, in all other cases, on Base Rate Advances pursuant to clause (a)(i) above. (c) NOTICE OF INTEREST RATE. Promptly after receipt of the Notice of Borrowing pursuant to Section 2.02(a), the Administrative Agent shall give notice to the Borrower and each Lender of the applicable interest rate determined by the Administrative Agent for purposes of clause (a)(i) or (ii). SECTION 2.07. FEES. (a) COMMITMENT FEE. The Borrower shall pay to the Administrative Agent for the account of the Lenders a commitment fee, from the date hereof to the Termination Date payable quarterly in arrears and on the Borrowing Date, with the final payment due on the Termination Date, at the rate of 2 of 1% per annum on the average daily unused portion of each Lender's Commitment during such period; PROVIDED, HOWEVER, that no commitment fee shall accrue on any of the Commitments of a Defaulting Lender so long as such Lender shall be a Defaulting Lender. This Section 2.07(a) shall supersede the paragraph entitled "Facility Fee" in the Fee Letter from and after the date hereof. 34 (b) ADMINISTRATIVE AGENT'S FEES. The Borrower shall pay to the Administrative Agent for its own account such fees as may from time to time be agreed between the Borrower and the Administrative Agent. (c) COLLATERAL AGENT'S FEES. The Borrower shall pay to the Collateral Agent for its own account such fees as may from time to time be agreed between the Borrower and the Collateral Agent. SECTION 2.08. CONVERSION OF ADVANCES. (a) OPTIONAL. The Borrower may on any Business Day, upon notice given to the Administrative Agent not later than 11:00 A.M. (New York City time) on the third Business Day prior to the date of the proposed Conversion and subject to the provisions of Sections 2.06 and 2.09, Convert all or any portion of the Tranche B Advances of one Type comprising the same Borrowing into Advances of the other Type; PROVIDED, HOWEVER, that any Conversion of Eurodollar Rate Advances into Base Rate Advances shall be made only on the last day of an Interest Period for such Eurodollar Rate Advances, any Conversion of Base Rate Advances into Eurodollar Rate Advances shall be in an amount not less than the minimum amount of $10,000,000, no Conversion of any Advances shall result in more than five Interest Periods outstanding at any time and each Conversion of Advances comprising part of the same Borrowing shall be made ratably among the Lenders in accordance with their Tranche B Advances. Each such notice of Conversion shall, within the restrictions specified above, specify (i) the date of such Conversion, (ii) the Advances to be Converted and (iii) if such Conversion is into Eurodollar Rate Advances, the duration of the initial Interest Period for such Advances. Each notice of Conversion shall be irrevocable and binding on the Borrower. (b) MANDATORY. (i) On the date on which the aggregate unpaid principal amount of Eurodollar Rate Advances comprising any Borrowing shall be reduced, by payment or prepayment or otherwise, to less than $1,000,000, such Advances shall automatically Convert into Base Rate Advances. (ii) If the Borrower shall fail to select the duration of any Interest Period for any Eurodollar Rate Advances in accordance with the provisions contained in the definition of "Interest Period" in Section 1.01, the Administrative Agent will forthwith so notify the Borrower and the Lenders, whereupon each such Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Advance. (iii) Upon the occurrence and during the continuance of any Event of Default, (x) each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Advance and (y) the obligation of the Lenders to make, or to 35 Convert Advances into, Eurodollar Rate Advances shall be suspended. SECTION 2.09. INCREASED COSTS, ETC. (a) If, due to either (i) the introduction of or any change in or in the interpretation of any law or regulation or (ii) the compliance with any guideline or request from any central bank or other Governmental Authority (whether or not having the force of law), there shall be any increase in the cost to any Lender of agreeing to make or of making, funding or maintaining Eurodollar Rate Advances (excluding for purposes of this Section 2.09 any such increased costs resulting from (A) Taxes or Other Taxes (as to which Section 2.11 shall govern) and (B) changes in the basis of taxation of overall net income or overall gross income by the United States or by the foreign jurisdiction or state under the laws of which such Lender is organized or has its Applicable Lending Office or any political subdivision thereof), then the Borrower shall from time to time, upon demand by such Lender (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender additional amounts sufficient to compensate such Lender for such increased cost; PROVIDED, HOWEVER, that a Lender claiming additional amounts under this Section 2.09(a) agrees to use reasonable efforts (consistent with its internal policy and legal and regulatory restrictions) to designate a different Applicable Lending Office if the making of such a designation would avoid the need for, or reduce the amount of, such increased cost that may thereafter accrue and would not, in the reasonable judgment of such Lender, be otherwise disadvantageous to such Lender. A certificate as to the amount of such increased cost, and the basis therefor, submitted to the Borrower by such Lender, shall be conclusive and binding for all purposes, absent manifest error. (b) If any Lender determines that compliance with any law or regulation or any guideline or request from any central bank or other Governmental Authority (whether or not having the force of law) affects or would affect the amount of capital required or expected to be maintained by such Lender or any corporation controlling such Lender and that the amount of such capital is increased by or based upon the existence of such Lender's commitment to lend hereunder and other commitments of such type, then, upon demand by such Lender (with a copy of such demand to the Administrative Agent), the Borrower shall pay to the Administrative Agent for the account of such Lender, from time to time as specified by such Lender, additional amounts sufficient to compensate such Lender in the light of such circumstances, to the extent that such Lender reasonably determines such increase in capital to be allocable to the existence of such Lender's commitment to lend. A certificate as to such amounts, and the basis therefor, submitted to the Borrower by such Lender shall be conclusive and binding for all purposes, absent manifest error. 36 (c) If, with respect to any Eurodollar Rate Advances the Required Tranche B Lenders notify the Administrative Agent that the Eurodollar Rate for any Interest Period for such Tranche B Advances will not adequately reflect the cost to such Tranche B Lenders of making, funding or maintaining their Eurodollar Rate Advances for such Interest Period, the Administrative Agent shall forthwith so notify the Borrower and the Tranche B Lenders, whereupon (i) each such Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Advance and (ii) the obligation of the Tranche B Lenders to make, or to Convert Tranche B Advances into, Eurodollar Rate Advances shall be suspended until the Administrative Agent shall notify the Borrower that such Tranche B Lenders have determined that the circumstances causing such suspension no longer exist. (d) Notwithstanding any other provision of this Agreement, if the introduction of or any change in or in the interpretation of any law or regulation shall make it unlawful, or any central bank or other Governmental Authority shall assert that it is unlawful, for any Tranche B Lender or its Eurodollar Lending Office to perform its obligations hereunder to make Eurodollar Rate Advances or to continue to fund or maintain Eurodollar Rate Advances hereunder, then, on notice thereof and demand therefor by such Tranche B Lender to the Borrower through the Administrative Agent, (i) each Eurodollar Rate Advance will automatically, upon such demand, Convert into a Base Rate Advance and (ii) the obligation of the Tranche B Lenders to make, or to Convert Tranche B Advances into, Eurodollar Rate Advances shall be suspended until the Administrative Agent shall notify the Borrower that such Tranche B Lender has determined that the circumstances causing such suspension no longer exist; PROVIDED, HOWEVER, that, before making any such demand, such Tranche B Lender agrees to use reasonable efforts (consistent with its internal policy and legal and regulatory restrictions) to designate a different Eurodollar Lending Office if the making of such a designation would allow such Tranche B Lender or its Eurodollar Lending Office to continue to perform its obligations to make Eurodollar Rate Advances or to continue to fund or maintain Eurodollar Rate Advances and would not, in the reasonable judgment of such Tranche B Lender, be otherwise disadvantageous to such Tranche B Lender. (e) If the Borrower becomes obligated to pay additional amounts to any Lender pursuant to this Section 2.09 as a result of any condition which is not generally applicable to all Lenders then, unless the Lender to which such conditions apply has theretofore taken steps to remove or cure, and has removed or cured, the conditions creating the cause for such obligation to pay such additional amounts, the Borrower may, so long as no Event of Default shall have occurred and be continuing, designate another lender which is willing to purchase all rights and 37 obligations of such Lender and which is reasonably acceptable to the Administrative Agent and the Required Lenders (such lender being herein called a "REPLACEMENT LENDER") to purchase for cash all of the rights and obligations of such Lender under this Agreement and all of such Lender=s rights hereunder, without recourse to or warranty (other than title) by, or expense to, such Lender in an amount equal to the outstanding principal amount of the Advances payable to such Lender plus any accrued but unpaid interest on such Advances, expense reimbursements and indemnities (including, without limitation, under Section 9.04(b)) and other amounts in respect of that Lender=s Commitment and Advances hereunder. Such Lender shall consummate such sale in accordance with such terms as promptly as reasonably practicable, and thereafter such Lender shall no longer be a party hereto or have any obligations or rights hereunder (except rights which, pursuant to the provisions of this Agreement, survive the termination of this Agreement and the repayment of the Notes or the Advances), and the Replacement Lender shall succeed to such obligations and rights. SECTION 2.10. PAYMENTS AND COMPUTATIONS. (a) The Borrower shall make each payment hereunder and under the Notes, irrespective of any right of counterclaim or set-off (except as otherwise provided in Section 2.14), not later than 5:00 P.M. (New York City time) for principal on the Tranche A Advances and not later than 11:00 A.M. (New York City time) for all other amounts due hereunder on the day when due in U.S. dollars to the Administrative Agent at the Administrative Agent's Account in immediately available funds. The Administrative Agent will promptly thereafter cause like funds to be distributed (i) if such payment by the Borrower is in respect of principal, interest, commitment fees or any other Obligation then payable hereunder and under the Notes to more than one Lender, to such Lenders for the account of their respective Applicable Lending Offices ratably in accordance with the amounts of such respective Obligations then payable to such Lenders and (ii) if such payment by the Borrower is in respect of any Obligation then payable hereunder to one Lender, to such Lender for the account of its Applicable Lending Office, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of an Assignment and Acceptance and recording of the information contained therein in the Register pursuant to Section 9.07(d), from and after the effective date of such Assignment and Acceptance, the Administrative Agent shall make all payments hereunder and under the Notes in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Assignment and Acceptance shall make all appropriate adjustments in such payments for periods prior to such effective date directly between themselves. (b) The Borrower hereby authorizes each Lender, if and to the extent payment owed to such Lender is not made to the Administrative Agent when due hereunder or 38 under the Note held by such Lender, to charge from time to time against any or all of the Borrower's accounts with such Lender (other than the Collateral Accounts, access to which shall be governed by the Loan Documents) any amount so due. (c) All computations of interest and fees shall be made by the Administrative Agent on the basis of a year of 360 days, in each case for the actual number of days (including the first day but excluding the last day) occurring in the period for which such interest, fees or commissions are payable. Each determination by the Administrative Agent of an interest rate, fee or commission hereunder shall be conclusive and binding for all purposes, absent manifest error. (d) Whenever any payment hereunder or under the Notes shall be stated to be due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest or commitment fee, as the case may be; PROVIDED, HOWEVER, that, if such extension would cause payment of interest on or principal of Eurodollar Rate Advances to be made in the next following calendar month, such payment shall be made on the next preceding Business Day. (e) Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to any Lender hereunder that the Borrower will not make such payment in full, the Administrative Agent may assume that the Borrower has made such payment in full to the Administrative Agent on such date and the Administrative Agent may, in reliance upon such assumption, cause to be distributed to each such Lender on such due date an amount equal to the amount then due such Lender. If and to the extent the Borrower shall not have so made such payment in full to the Administrative Agent, each such Lender shall repay to the Administrative Agent forthwith on demand such amount distributed to such Lender together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Administrative Agent, at the Federal Funds Rate. SECTION 2.11. TAXES. (a) Any and all payments by the Borrower hereunder or under the Notes shall be made, in accordance with Section 2.10, free and clear of and without deduction for any and all present or future taxes, levies, imposts, deductions, charges or withholdings, and all liabilities with respect thereto, EXCLUDING, in the case of each Lender and the Administrative Agent, taxes that are imposed on its overall net income by the United States and taxes that are imposed on its overall net income (and franchise taxes imposed in lieu thereof) by the state or foreign jurisdiction under the laws of which such Lender or the Administrative Agent (as the case may be) is organized or any political subdivision thereof and, in the case of 39 each Lender, taxes that are imposed on its overall net income (and franchise taxes imposed in lieu thereof) by the state or foreign jurisdiction of such Lender's Applicable Lending Office or any political subdivision thereof (all such non-excluded taxes, levies, imposts, deductions, charges, withholdings and liabilities in respect of payments hereunder or under the Notes being hereinafter referred to as "TAXES"). If the Borrower shall be required by law to deduct any Taxes from or in respect of any sum payable hereunder or under any Note to any Lender or the Administrative Agent, (i) the sum payable shall be increased as may be necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 2.11) such Lender or the Administrative Agent (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower shall make such deductions and (iii) the Borrower shall pay the full amount deducted to the relevant taxation authority or other authority in accordance with applicable law. (b) In addition, the Borrower shall pay any present or future stamp, documentary, excise, property or similar taxes, charges or levies that arise from any payment made hereunder or under the Notes or from the execution, delivery or registration of, performing under, or otherwise with respect to, this Agreement or the Notes (hereinafter referred to as "OTHER TAXES"). (c) The Borrower shall indemnify each Lender and the Administrative Agent for and hold it harmless against the full amount of Taxes and Other Taxes, and for the full amount of Taxes of any kind imposed by any jurisdiction on amounts payable under this Section 2.11, imposed on or paid by such Lender or the Administrative Agent (as the case may be) and any liability (including penalties, additions to tax, interest and expenses) arising therefrom or with respect thereto. This indemnification shall be made within 30 days from the date such Lender or the Administrative Agent (as the case may be) makes written demand therefor. (d) Within 30 days after the date of any payment of Taxes, the Borrower shall furnish to the Administrative Agent, at its address referred to in Section 9.02, the original or a certified copy of a receipt evidencing such payment. In the case of any payment hereunder or under the Notes by or on behalf of the Borrower through an account or branch outside the United States or by or on behalf of the Borrower by a payor that is not a United States person, if the Borrower determines that no Taxes are payable in respect thereof, the Borrower shall furnish, or shall cause such payor to furnish, to the Administrative Agent, at such address, an opinion of counsel acceptable to the Administrative Agent stating that such payment is exempt from Taxes. For purposes of this subsection (d) and subsection (e), the terms "UNITED STATES" and "UNITED STATES 40 PERSON" shall have the meanings specified in Section 7701 of the Internal Revenue Code. (e) Each Lender organized under the laws of a jurisdiction outside the United States shall, on or prior to the date of its execution and delivery of this Agreement in the case of each Initial Lender and on the date of the Assignment and Acceptance pursuant to which it becomes a Lender in the case of each other Lender, and from time to time thereafter as requested in writing by the Borrower (but only so long thereafter as such Lender remains lawfully able to do so), provide each of the Administrative Agent and the Borrower with two original Internal Revenue Service forms W-8 ECI or W-8 BEN, as appropriate, or any successor or other form prescribed by the Internal Revenue Service, certifying that such Lender is exempt from or entitled to a reduced rate of United States withholding tax on payments pursuant to this Agreement or the Notes. If the forms provided by a Lender at the time such Lender first becomes a party to this Agreement indicates a United States interest withholding tax rate in excess of zero, withholding tax at such rate shall be considered excluded from Taxes unless and until such Lender provides the appropriate form certifying that a lesser rate applies, whereupon withholding tax at such lesser rate only shall be considered excluded from Taxes for periods governed by such form; PROVIDED, HOWEVER, that, if at the date of the Assignment and Acceptance pursuant to which a Lender becomes a party to this Agreement, the Lender assignor was entitled to payments under subsection (a) in respect of United States withholding tax with respect to interest paid at such date, then, to such extent, the term Taxes shall include (in addition to withholding taxes that may be imposed in the future or other amounts otherwise includable in Taxes) United States withholding tax, if any, applicable with respect to the Lender assignee on such date. If any form or document referred to in this subsection (e) requires the disclosure of information, other than information necessary to compute the tax payable and information required on the date hereof by Internal Revenue Service form W-8 ECI or W-8 BEN, that the Lender reasonably considers to be confidential, the Lender shall give notice thereof to the Borrower and shall not be obligated to include in such form or document such confidential information. (f) For any period with respect to which a Lender has failed to provide the Borrower with the appropriate form described in subsection (e) above (OTHER THAN if such failure is due to a change in law occurring after the date on which a form originally was required to be provided or if such form otherwise is not required under subsection (e) above), such Lender shall not be entitled to indemnification under subsection (a) or (c) with respect to Taxes imposed by the United States by reason of such failure; PROVIDED, HOWEVER, that should a Lender become subject to Taxes because of its failure to deliver a form required hereunder, the Borrower shall take such steps as 41 such Lender shall reasonably request to assist such Lender to recover such Taxes. SECTION 2.12. SHARING OF PAYMENTS, ETC. If any Lender shall obtain at any time any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise) (a) on account of Obligations due and payable to such Lender hereunder and under the Notes at such time in excess of its ratable share (according to the proportion of (i) the amount of such Obligations due and payable to such Lender at such time to (ii) the aggregate amount of the Obligations due and payable to all Lenders hereunder and under the Notes at such time) of payments on account of the Obligations due and payable to all Lenders hereunder and under the Notes at such time obtained by all the Lenders at such time or (b) on account of Obligations owing (but not due and payable) to such Lender hereunder and under the Notes at such time in excess of its ratable share (according to the proportion of (i) the amount of such Obligations owing to such Lender at such time to (ii) the aggregate amount of the Obligations owing (but not due and payable) to all Lenders hereunder and under the Notes at such time) of payments on account of the Obligations owing (but not due and payable) to all Lenders hereunder and under the Notes at such time obtained by all of the Lenders at such time, such Lender shall forthwith purchase from the other Lenders such participations in the Obligations due and payable or owing to them, as the case may be, as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them; PROVIDED, HOWEVER, that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each other Lender shall be rescinded and such other Lender shall repay to the purchasing Lender the purchase price to the extent of such Lender's ratable share (according to the proportion of (i) the purchase price paid to such Lender to (ii) the aggregate purchase price paid to all Lenders) of such recovery together with an amount equal to such Lender's ratable share (according to the proportion of (i) the amount of such other Lender's required repayment to (ii) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 2.12 may, to the fullest extent permitted by law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of the Borrower in the amount of such participation. SECTION 2.13. USE OF PROCEEDS. The proceeds of the Advances shall be available (and the Borrower agrees that it shall use such proceeds) solely to pay the Purchase Price for the Generating Assets and for fees, costs and expenses incurred in connection with the Loan Documents and 42 related to the preparation, execution and delivery of the Loan Documents. SECTION 2.14. DEFAULTING LENDERS. (a) In the event that, at any one time, (i) any Lender shall be a Defaulting Lender, (ii) such Defaulting Lender shall owe a Defaulted Advance to the Borrower and (iii) the Borrower shall be required to make any payment hereunder or under any other Loan Document to or for the account of such Defaulting Lender, then the Borrower may, so long as no Default shall occur or be continuing at such time and to the fullest extent permitted by applicable law, set off and otherwise apply the Obligation of the Borrower to make such payment to or for the account of such Defaulting Lender against the Obligation of such Defaulting Lender to make such Defaulted Advance. In the event that, on any date, the Borrower shall so set off and otherwise apply its obligation to make any such payment against the Obligation of such Defaulting Lender to make any such Defaulted Advance on or prior to such date, the amount so set off and otherwise applied by the Borrower shall constitute for all purposes of this Agreement and the other Loan Documents an Advance by such Defaulting Lender made on the date pursuant to which such Defaulted Advance was originally required to have been made pursuant to Section 2.01. Such Advance shall be a Base Rate Advance and shall be considered, for all purposes of this Agreement, to comprise part of the Borrowing in connection with which such Defaulted Advance was originally required to have been made pursuant to Section 2.01, even if the other Advances comprising such Borrowing shall be Eurodollar Rate Advances on the date such Advance is deemed to be made pursuant to this subsection (a). The Borrower shall notify the Administrative Agent at any time the Borrower exercises its right of set-off pursuant to this subsection (a) and shall set forth in such notice (A) the name of the Defaulting Lender and the Defaulted Advance required to be made by such Defaulting Lender and (B) the amount set off and otherwise applied in respect of such Defaulted Advance pursuant to this subsection (a). Any portion of such payment otherwise required to be made by the Borrower to or for the account of such Defaulting Lender which is paid by the Borrower, after giving effect to the amount set off and otherwise applied by the Borrower pursuant to this subsection (a), shall be applied by the Administrative Agent as specified in subsection (b) or (c) of this Section 2.14. (b) In the event that, at any one time, (i) any Lender shall be a Defaulting Lender, (ii) such Defaulting Lender shall owe a Defaulted Amount to the Administrative Agent or any of the other Lenders and (iii) the Borrower shall make any payment hereunder or under any other Loan Document to the Administrative Agent for the account of such Defaulting Lender, then the Administrative Agent may, on its behalf or on behalf of such other Lenders and to the fullest extent permitted by applicable law, apply at such time the amount so paid by the Borrower to or for the account of such Defaulting Lender to the payment of each 43 such Defaulted Amount to the extent required to pay such Defaulted Amount. In the event that the Administrative Agent shall so apply any such amount to the payment of any such Defaulted Amount on any date, the amount so applied by the Administrative Agent shall constitute for all purposes of this Agreement and the other Loan Documents payment, to such extent, of such Defaulted Amount on such date. Any such amount so applied by the Administrative Agent shall be retained by the Administrative Agent or distributed by the Administrative Agent to such other Lenders, ratably in accordance with the respective portions of such Defaulted Amounts payable at such time to the Administrative Agent and such other Lenders and, if the amount of such payment made by the Borrower shall at such time be insufficient to pay all Defaulted Amounts owing at such time to the Administrative Agent and the other Lenders, in the following order of priority: (i) FIRST, to the Administrative Agent for any Defaulted Amount then owing to the Administrative Agent; and (ii) SECOND, to any other Lenders for any Defaulted Amounts then owing to such other Lenders, ratably in accordance with such respective Defaulted Amounts then owing to such other Lenders. Any portion of such amount paid by the Borrower for the account of such Defaulting Lender remaining, after giving effect to the amount applied by the Administrative Agent pursuant to this subsection (b), shall be applied by the Administrative Agent as specified in subsection (c) of this Section 2.14. (c) In the event that, at any one time, (i) any Lender shall be a Defaulting Lender, (ii) such Defaulting Lender shall not owe a Defaulted Advance or a Defaulted Amount and (iii) the Borrower, the Administrative Agent or any other Lender shall be required to pay or distribute any amount hereunder or under any other Loan Document to or for the account of such Defaulting Lender, then the Borrower or such other Lender shall pay such amount to the Administrative Agent to be held by the Administrative Agent, to the fullest extent permitted by applicable law, in escrow or the Administrative Agent shall, to the fullest extent permitted by applicable law, hold in escrow such amount otherwise held by it. Any funds held by the Administrative Agent in escrow under this subsection (c) shall be deposited by the Administrative Agent in an account with Citibank, in the name and under the control of the Administrative Agent, but subject to the provisions of this subsection (c). The terms applicable to such account, including the rate of interest payable with respect to the credit balance of such account from time to time, shall be Citibank's standard terms applicable to escrow accounts maintained with it. Any interest credited to such account from time to time shall be held by the Administrative Agent 44 in escrow under, and applied by the Administrative Agent from time to time in accordance with the provisions of, this subsection (c). The Administrative Agent shall, to the fullest extent permitted by applicable law, apply all funds so held in escrow from time to time to the extent necessary to make any Advances required to be made by such Defaulting Lender and to pay any amount payable by such Defaulting Lender hereunder and under the other Loan Documents to the Administrative Agent or any other Lender, as and when such Advances or amounts are required to be made or paid and, if the amount so held in escrow shall at any time be insufficient to make and pay all such Advances and amounts required to be made or paid at such time, in the following order of priority: (i) FIRST, to the Administrative Agent for any amount then due and payable by such Defaulting Lender to the Administrative Agent hereunder; (ii) SECOND, to any other Lenders for any amount then due and payable by such Defaulting Lender to such other Lenders hereunder, ratably in accordance with such respective amounts then due and payable to such other Lenders; and (iii) THIRD, to the Borrower for any Advance then required to be made by such Defaulting Lender pursuant to a Commitment of such Defaulting Lender. In the event that any Lender that is a Defaulting Lender shall, at any time, cease to be a Defaulting Lender, any funds held by the Administrative Agent in escrow at such time with respect to such Lender shall be distributed by the Administrative Agent to such Lender and applied by such Lender to the Obligations owing to such Lender at such time under this Agreement and the other Loan Documents ratably in accordance with the respective amounts of such Obligations outstanding at such time. (d) The rights and remedies against a Defaulting Lender under this Section 2.14 are in addition to other rights and remedies that the Borrower may have against such Defaulting Lender with respect to any Defaulted Advance and that the Administrative Agent or any Lender may have against such Defaulting Lender with respect to any Defaulted Amount. SECTION 2.15. DEPOSITORY TRUST CORPORATION ELIGIBILITY. The Borrower agrees to use its reasonable best efforts to cause the Tranche B Notes to be Depository Trust Company eligible promptly after the request of the Required Tranche B Lenders. 45 ARTICLE III CONDITIONS OF LENDING SECTION 3.01. CONDITIONS PRECEDENT TO THE BORROWING DATE. The obligation of each Lender to make any Advance on the occasion of the Borrowing Date is subject to the satisfaction of the following conditions precedent before or concurrently with such Advance: (a) The Acquisition shall be consummated strictly in accordance with the terms of the Purchase and Sale Agreements and in compliance with all applicable laws, without any waiver or amendment not consented to by the Lenders or that would be reasonably likely to have a Material Adverse Effect. (b) The Acquisition Documents shall have been executed by all parties thereto in form and substance satisfactory to the Lenders and no default by any party to any thereof shall have occurred and be continuing that would be reasonably likely to have a Material Adverse Effect. (c) There shall have occurred and be continuing no event which (i) could reasonably be expected to result in a material adverse change in the business, financial condition, operations, performance, properties or prospects of the Borrower, Northeast Utilities or NU Enterprises, individually or taken together as a whole, since December 31, 1999 or (ii) in the reasonable opinion of the Lenders, could reasonably be expected to have a Material Adverse Effect since September 30, 1999 for Northeast Utilities, the Borrower or NU Enterprises. (d) All governmental, shareholder, creditor and other third party consents, approvals and authorizations and all notices to or other such filings with any such entities and all other regulatory requirements applicable to (i) the transfer to the Borrower of the Generating Assets, (ii) the ongoing operation of such assets by the Borrower, (iii) the entry into and performance of the Loan Documents, the Acquisition Documents, the existing Material Contracts and the Project Documents by the Borrower, NU Enterprises, Northeast Utilities, CL&P, WMECO, NGS and Select, (iv) the granting of the Liens contemplated thereby and (v) the other transactions contemplated herein or therein, shall have been satisfied, obtained or made (without the imposition of any conditions that are not customary or otherwise reasonably acceptable to the Lenders) and shall be in full force and effect and all matters relating to such consents, authorizations and approvals including, without limitation, the status thereof shall be reasonably satisfactory to the Lenders and no law or regulation shall be applicable in the reasonable judgment of the Lenders that restrains, prevents or imposes materially adverse conditions on the Generating Assets, the Borrower, NU Enterprises, 46 Northeast Utilities, NGS or Select or the transactions contemplated herein or therein. (e) The written information prepared by or on behalf of the Borrower or Northeast Utilities and delivered to the Lenders listed on Schedule 3.01(e) attached hereto, taken as a whole, shall continue to be true and correct in all material respects, except with respect to forecasts and projections (including, without limitation, the forecasts and projections contained in business plans so updated) which shall have been prepared in good faith and based on reasonable assumptions, which assumptions continue to be fair and reasonable, and such updated information (including, without limitation, such updated forecasts and projections) shall be in form and substance reasonably satisfactory to the Lenders. (f) There shall exist no action, suit, investigation, litigation or proceeding pending or threatened in any court or before any arbitrator or governmental instrumentality that would be reasonably likely to have a Material Adverse Effect other than as set forth in the Disclosure Documents or purports to materially adversely affect the Acquisition, the Acquisition Documents, this Agreement, the existing Material Contracts, the Project Documents or any of the other transactions contemplated hereby or thereby. (g) The Lenders shall have received evidence reasonably satisfactory to them that (x) an amount at least equal to US$45,500,233.35 shall have been deposited in an account to be designated by the Administrative Agent on the date prior to the Borrowing, which shall remain on deposit in such account on the Borrowing Date, and the Administrative Agent shall have received irrevocable instructions to use such funds as provided in the Flow of Funds Memorandum and (y) an amount at least equal to $389,999,766.65 will be available to be released from the lien of the Indentures to be dividended by each of CL&P and WMECO, respectively, to Northeast Utilities or to be used by CL&P or WMECO, respectively, to repurchase stock from Northeast Utilities and that each of CL&P and WMECO shall be capable of satisfying the conditions to such release upon the funding and no limitations (which have not been waived or are not otherwise capable of being satisfied by each of CL&P and WMECO upon the funding) shall exist under the Indentures and the other applicable indentures, credit agreements and other agreements of CL&P and WMECO and no other restrictions shall exist (statutory, corporate, contractual or otherwise) on the declaration and payment of such dividend or such repurchase of stock and on the investment of an amount equal to the Tranche A Borrowing, by Northeast Utilities into NU Enterprises and by NU Enterprises into the Borrower, 47 respectively, and that the mechanics of executing such release, dividend, repurchase of stock and investment are such that the Borrower should be able to repay an amount equal to the Tranche A Borrowing to the Administrative Agent on behalf of the Lenders on the Borrowing Date. (h) Each of CL&P and WMECO shall have taken all necessary corporate action and obtained all necessary governmental, creditor and other third party consents, approvals and authorizations to repurchase stock or dividend an amount equal to US$390,000,000 on such date, from or to Northeast Utilities, and Northeast Utilities and NU Enterprises each shall have taken all necessary corporate action and obtained all necessary governmental and third party consents, approvals and authorizations to invest an amount equal to the Tranche A Borrowing on such date in NU Enterprises (in the case of Northeast Utilities) and in the Borrower (in the case of NU Enterprises) and all such other consents, approvals and authorizations shall be in full force and effect, all matters relating to such consents, approvals and authorizations including, without limitation, the status thereof shall be satisfactory to the Lenders in their sole discretion and no law or regulation shall be applicable in the reasonable judgment of the Lenders that restrains, prevents or imposes materially adverse conditions upon the transactions contemplated thereby. The Administrative Agent shall have received certified copies of all governmental approvals and consents referenced in this clause (h) and any evidence of corporate action requested. (i) To the extent the amount equal to the sum of (1) the Purchase Price, (2) all amounts payable to the Administrative Agent, the Collateral Agent, the Co-Arrangers and the Lenders under the Loan Documents, the Fee Letter, the Lead Bank Letter and the Engagement Letter, and (3) all transaction costs relating to the Loan Documents and the Acquisition, exceeds the Commitments under this Agreement and available on the Borrowing Date, the Borrower shall have received cash capital contributions in an amount sufficient to fund such excess amount prior to the making of the Advances and shall apply such funds to such excess amounts designated above as agreed with the Lenders. (j) The Lenders shall be reasonably satisfied with (i) the Borrower's plan of remediation if required under the Connecticut Transfer Act or, if such plan is required but has not been finalized, with the results of their diligence regarding the anticipated terms of such plan, (ii) the results of their diligence regarding the conditions anticipated to be imposed as part of the FERC re-licensing of the Generating Assets in the Housatonic System, (iii) the conditions 48 disclosed in all Phase II environmental site assessment reports from Metcalf & Eddy with respect to the Generating Assets, (iv) the information disclosed in the final report of Stone & Webster, (v) the results of the final report of the Insurance Consultant with respect to the Generating Assets, and (vi) the results of such other diligence they reasonably determine to undertake in connection with the Acquisition with respect to the Generating Assets. (k) An amount equal to all accrued fees and reasonable expenses of the Administrative Agent, the Collateral Agent, the Co-Arrangers and the Lenders (including the accrued reasonable fees and expenses of counsel to the Administrative Agent, the Collateral Agent and the Depositary Bank) due and payable in accordance with the Loan Documents, the Fee Letter, the Engagement Letter and the Lead Bank Letter shall have been deposited in an account to be designated by the Administrative Agent on the date prior to the Borrowing, which shall remain on deposit in such account on the Borrowing Date, and the Administrative Agent shall have received irrevocable instructions to use such funds to pay such amounts in full. (l) The Lenders shall have received a letter from the Borrower certifying as to the NEPOOL capability rating for each of the Generating Assets. (m) The Administrative Agent shall have received on or before the Borrowing Date the following, each dated such day (unless otherwise specified), in form and substance reasonably satisfactory to the Lenders (unless otherwise specified) and (except for the Notes) in sufficient copies for each Lender: (i) The Notes payable to the order of the Lenders. (ii) Certified copies of the resolutions of the Board of Directors of each Loan Party approving this Agreement, the Notes, each other Loan Document, each Acquisition Document and each Project Document to which it is or is to be a party, and of all documents evidencing other necessary corporate action and governmental and other third party approvals and consents, if any, with respect to this Agreement, the Notes, each other Loan Document, each Acquisition Document and each Project Document. (iii) A copy of the charter of each Loan Party and each amendment thereto, certified (as of a date reasonably near the date of the Borrowing Date) by the Secretary of State of the jurisdiction of its incorporation as being a true and correct copy thereof. 49 (iv) A copy of a certificate of the Secretary of State of the jurisdiction of each Loan Party's organization, dated reasonably near the date of the Borrowing Date, listing the charter of such Loan Party and each amendment thereto on file in his office and certifying that (A) such amendments are the only amendments to such Loan Party's charter on file in his office, (B) each Loan Party has paid all franchise taxes to the date of such certificate and (C) such Loan Party is duly organized and in good standing under the laws of the state of the jurisdiction of its organization. (v) A certificate of each of the Loan Parties, signed on behalf of such Loan Party by a Responsible Officer thereof, dated the Borrowing Date (the statements made in which certificate shall be true on and as of the date of the Borrowing), certifying as to (A) the absence of any amendments to the charter (or the equivalent organizational or constitutive documents) of such Loan Party since the date of the certification referred to in Section 3.01(m)(iv), a copy of which shall be attached to such certificate, (B) a true and correct copy of the bylaws (or the equivalent organizational documents) of such Loan Party as in effect on the Borrowing Date, a copy of which shall be attached to such certificate, and (C) the due organization and good standing of such Loan Party, and the absence of any proceeding for the dissolution, winding-up or liquidation (or any equivalent thereof) of such Loan Party. (vi) A certificate of each of the Loan Parties, signed on behalf of such Loan Party by a Responsible Officer thereof, dated the Borrowing Date (the statements made in such certificate shall be true on and as of the date of the Borrowing), certifying that: (A) all of the representations and warranties of such Loan Party contained in each Loan Document, Acquisition Document or Project Document to which such Loan Party is or is to be a party, or which are contained in any certificate, document or financial or other statement furnished thereunder or in connection therewith, shall be true and correct in all material respects on and as of the Borrowing Date, before and after giving effect to the Borrowing and to the application of the proceeds therefrom, as though made on and as of such date (other than any such representations or warranties that, by their terms, refer to a specific 50 date other than the date of the Borrowing, in which case as of such specific date); and (B) no event has occurred and is continuing, or would result from the Borrowing or from the application of the proceeds therefrom, that constitutes a Default or an Event of Default. (vii) A certificate of the Secretary or an Assistant Secretary of each Loan Party certifying the names and true signatures of the officers of such Loan Party authorized to sign this Agreement, the Notes, the Loan Documents, each Acquisition Document and each Project Document to which they are or are to be parties and the other documents to be delivered hereunder and thereunder. (viii) The Tranche A Borrower Security Agreement, the Tranche B Borrower Security Agreement, the Tranche A Enterprises Pledge Agreement and the Tranche B Enterprises Pledge Agreement, each duly executed by each of the parties thereto, together with: (A) certificates representing the Pledged Shares referred to therein accompanied by undated stock powers executed in blank. (B) acknowledgment copies of proper financing statements, duly filed on or before the Borrowing Date under the Uniform Commercial Code of all jurisdictions that the Collateral Agent may deem necessary or desirable in order to perfect and protect the first priority liens and security interests created under such Collateral Documents, covering the Collateral described in such Collateral Documents. (C) completed requests for information, dated on or before the Borrowing Date, listing the financing statements referred to in clause (B) above and all other effective financing statements filed in the jurisdictions referred to in clause (B) above that name the Borrower or NU Enterprises as debtor, together with copies of such other financing statements. (D) evidence of the completion of all other recordings and filings of or with respect to such Collateral Documents that the Collateral Agent may deem necessary or desirable in order to perfect and protect the Liens created thereby. 51 (E) evidence that all other action that the Collateral Agent may deem necessary or desirable in order to perfect and protect the first priority liens and security interests created under such Collateral Documents has been taken. (ix) The Tranche A Mortgage and the Tranche B Mortgage in respect of the properties listed on Schedule II (in each case as amended, supplemented or otherwise modified from time to time in accordance with their terms, the "MORTGAGES"), duly executed by the Borrower, together with: (A) evidence that (i) counterparts of the Mortgages have been duly recorded on or before the Borrowing Date in all filing or recording offices that the Collateral Agent may deem necessary or desirable in order to create a valid first and subsisting Lien on the property described therein in favor of the Secured Parties and that all filing and recording taxes and fees have been paid, or (ii) the Title Companies (as defined below) have provided gap insurance in respect to the recording of the Mortgages acceptable to the Collateral Agent; (B) fully paid American Land Title Association Lender's Extended Coverage title insurance policies (the "MORTGAGE POLICIES") in form and substance, with endorsements and in amount acceptable to the Collateral Agent, issued, coinsured and reinsured by title insurers acceptable to the Collateral Agent (the "TITLE COMPANIES"), insuring the Tranche B Mortgage to be a valid first and subsisting Lien on the property described therein, free and clear of all defects (including, but not limited to, mechanics' and materialmen's Liens) and encumbrances, excepting only Permitted Encumbrances, and providing for such other affirmative insurance (including endorsements for mechanics' and materialmen's Liens); (C) American Land Title Association form surveys for designated portions of certain properties listed on Schedule II and other site drawings, certified to the Collateral Agent and the issuers of the Mortgage Policy in a manner reasonably satisfactory to the Collateral Agent by a land surveyor duly registered and licensed in the states in which the property described in 52 such surveys is located and acceptable to the Collateral Agent; (D) INTENTIONALLY OMITTED; (E) engineering, soils and other reports as to the properties described in the Mortgages, in form and substance and from professional firms acceptable to the Collateral Agent; (F) such consents and agreements of lessors and other third parties, and such estoppel letters and other confirmations, as the Collateral Agent may reasonably deem necessary; (G) evidence of the insurance required hereunder; (H) evidence that all other action that the Collateral Agent may deem necessary in order to create valid first and subsisting Liens on the property described in the Mortgages has been taken; (I) deeds transferring title to each applicable property described in the Mortgages; (J) evidence of recording of each deed and payment of any recording fees in respect thereof; (K) release of existing mortgages, if any, together with applicable ancillary documentation, including, without limitation, UCC-3 forms; (L) release of other existing encumbrances (other than Permitted Encumbrances) if any, together with applicable ancillary documentation; (M) applicable transfer tax forms; (N) bills of sale related to the transfer of personal property; (O) certified copy of the Northfield Operating Agreement; (P) certified copies of all existing Material Contracts, Project Documents and material operating or regulatory licenses to be assigned; and 53 (Q) assignments of service contracts, permits and warranties. (x) The Sponsor Agreement, duly executed by Northeast Utilities. (xi) Certified copies of the Governmental Authorizations listed on Schedules 5.01(d)(A)(1)-(2) hereof. (xii) Certified copies of each of the Third Party Consents listed on Schedule 5.01(d)(B) hereof, each in form and substance satisfactory to the Lenders. (xiii) Evidence that the Borrower is an Exempt Wholesale Generator. (xiv) A solvency certificate from the chief financial officer of each of CL&P and WMECO, substantially in the form of Exhibit J hereto. (xv) A certified copy of the Annual Operating Budget of the Borrower for the year 2000. (xvi) A copy of the Administrative Agent Fee Letter and the Collateral Agent Fee Letter, each duly executed by each of the parties thereto. (xvii) (a) Written confirmation from Stone & Webster that no material adverse change shall have occurred with respect to the Generating Assets from that indicated in the draft final report of Stone & Webster dated May 28, 1999, (b) written confirmation from the Insurance Consultant that the Borrower's insurance arrangements satisfy the requirements set forth in the Loan Documents and (c) a market study from P.H.B. Hagler Bailly ("HAGLER") which is reasonably satisfactory in form and substance to the Lenders. (xviii) Certified copies of the Acquisition Documents, the O&M Agreement, the Select Power Purchase Agreement, the Northeast Utilities Guaranties and the Tax Sharing Agreement, each of which shall be in form and substance satisfactory to the Lenders. (xix) A favorable opinion of Edwards & Angell, LLP, special counsel for the Borrower, Northeast Utilities, NU Enterprises, CL&P, WMECO, NGS and Select, in form and substance reasonably satisfactory to the Agents and the Initial Lenders. 54 (xx) A favorable opinion of Steptoe and Johnson, special FERC counsel to the Borrower, Northeast Utilities, NU Enterprises, Select, NGS, CL&P and WMECO, in form and substance reasonably satisfactory to the Agents and the Initial Lenders. (xxi) A favorable opinion of Day, Berry & Howard, special Massachusetts and Connecticut energy regulatory counsel and special Securities and Exchange Commission counsel to the Borrower, Northeast Utilities, NU Enterprises, Select, NGS, CL&P and WMECO, in form and substance reasonably satisfactory to the Agents and the Initial Lenders. (xxii) A favorable opinion of Robert Bersak, general counsel to NUSCO in New Hampshire, in form and substance reasonably satisfactory to the Agents and the Initial Lenders. (xxiii) A favorable opinion of Edwards & Angell, LLP, special Massachusetts and Connecticut real estate counsel to the Borrower, Northeast Utilities, NU Enterprises, Select, NGS, CL&P and WMECO, in form and substance reasonably satisfactory to the Agents and the Initial Lenders. (xxiv) A favorable opinion of Nixon Peabody special New Hampshire real estate counsel to the Borrower, Northeast Utilities, NU Enterprises, Select, NGS, CL&P and WMECO, in form and substance reasonably satisfactory to the Agents and the Initial Lenders. (xxv) A favorable opinion of Kristensen, Cummings, Phillips & Carol, special Vermont real estate counsel to the Borrower, Northeast Utilities, Select, NGS, NU Enterprises, CL&P and WMECO, in form and substance reasonably satisfactory to the Agents and the Initial Lenders. (xxvi) A favorable opinion of Shearman & Sterling, counsel for the Administrative Agent, in form and substance reasonably satisfactory to the Lenders. (xxvii) Such other approvals, opinions or documents as any Lender through the Administrative Agent may reasonably request. Section 3.02. DETERMINATIONS UNDER SECTION 3.01. For purposes of determining compliance with the conditions specified in Section 3.01, each Lender shall be deemed to have consented to, approved or accepted or to be satisfied 55 with each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to the Lenders unless an officer of the Administrative Agent responsible for the transactions contemplated by the Loan Documents and the Borrower shall have received written notice of such objection from such Lender prior to the Borrowing specifying its objection thereto, and, in the case of the Borrowing, such Lender shall not have made available to the Administrative Agent such Lender's ratable portion of the Borrowing. ARTICLE IV SPECIAL ACCOUNTS SYSTEM SECTION 4.01. CREATION OF THE COLLATERAL ACCOUNTS. (a) The Collateral Agent and the Borrower shall establish and maintain the Collateral Accounts. (b) THE DEPOSITARY BANK. (i) The Depositary Bank hereby agrees to act as securities intermediary (as defined in the UCC) in respect of the Collateral Accounts established with the Depositary Bank under this Agreement. The Borrower hereby acknowledges that the Depositary Bank shall act as securities intermediary in respect of the Collateral Accounts under this Agreement. The Collateral Agent may, with the consent of the Borrower (which consent shall not be unreasonably withheld), select another financial institution to act as Depositary Bank under this Agreement, subject to the written agreement of the replacement Depositary Bank to be bound by the terms and conditions of this Agreement. (ii) The Depositary Bank acknowledges, confirms and agrees that (A) the Collateral Accounts have been established as set forth in Section 4.01(a), (B) each Collateral Account is a "securities account" (as defined in the UCC), (C) the Borrower is the "entitlement holder" (as defined in the UCC) of the Collateral Accounts, (D) all property delivered to the Depositary Bank pursuant to this Agreement or the Collateral Documents will be promptly credited to a Collateral Account (as specified herein), (E) all "financial assets" (as defined in the UCC) in registered form or payable to or to order and credited to any Collateral Account shall be registered in the name of, payable to or to the order of, or specially endorsed to, the Depositary Bank or in blank, or credited to another securities account maintained in the name of the Depositary Bank, and in no case will any financial asset credited to either Collateral Account be registered in the name of, payable to or to the order of, or specially endorsed to, the Borrower except to the extent the foregoing have been specially endorsed by the Borrower to the Depositary Bank or in blank, (F) the Depositary Bank shall promptly comply with all instructions of the Collateral Agent and, to the limited extent set forth below in this Article IV, the Borrower in 56 connection with the transfer or withdrawal of amounts in the Cash Collateral Accounts and (g) the Depositary Bank shall not change the name or account number of either Collateral Account without the prior written consent of the Collateral Agent. (iii) The Depositary Bank agrees that each item of property (whether cash, a security, an instrument or obligation, share, participation, interest or other property whatsoever) credited to either Collateral Account shall be treated as a "financial asset" under and as defined in Article 8 of the UCC. (iv) The Borrower agrees that the Depositary Bank may, and the Depositary Bank agrees that it shall, comply with "entitlement orders" (as defined in the UCC) originated by the Collateral Agent and relating to either Collateral Account and any "security entitlement" (as defined in the UCC) credited thereto without further consent by the Borrower or any other Person. (v) In the event that the Depositary Bank has obtained or subsequently obtains by agreement, operation of law or otherwise a Lien or security interest in either Collateral Account or any "security entitlement" (as defined in the UCC) credited thereto, the Depositary Bank agrees that such Lien or security interest shall be subordinate to the Lien and security interest of the Secured Parties. The financial assets standing to the credit of the Collateral Accounts will not be subject to deduction, set-off, banker's Lien, or any other right in favor of any Person other than the rights of the Collateral Agent and the other Secured Parties set forth in this Agreement and the other Collateral Documents (except that the face amount of any checks which have been credited to either Collateral Account but are subsequently returned unpaid because of uncollected or insufficient funds). The Depositary Bank hereby waives any right of banker's lien, set-off or counterclaim in respect of any assets contained in either Collateral Account or otherwise that are held by the Depositary Bank hereunder. (vi) The Depositary Bank and the Borrower have not entered into any agreement with respect to the Collateral Accounts or any financial assets credited to either Collateral Account other than this Agreement and the Collateral Documents. The Depositary Bank has not entered into any agreement with the Borrower or any other Person purporting to limit or condition the obligation of the Depositary Bank to comply with entitlement orders originated by the Collateral Agent in accordance with Section 4.01(b)(iv). In the event of any conflict between this Agreement (or any portion thereof) or any other Collateral Document or any other agreement now existing or hereafter entered into, the terms of this Agreement shall prevail. (vii) Except for the claims and interest of the Collateral Agent and the Borrower in each of the Collateral 57 Accounts, the Depositary Bank does not know of any claim to, or interest in, either Collateral Account or in any financial asset credited thereto. If any Person asserts any Lien, encumbrance or adverse claim (including any writ, garnishment, judgment, warrant of attachment, execution or similar process) against either Collateral Account or in any financial asset credited thereto, the Depositary Bank will promptly notify the Collateral Agent and the Borrower thereof. (viii) The rights and powers granted to the Collateral Agent by the Borrower and the Depositary Bank have been granted in order to perfect the Lien and security interests of the Secured Parties in the Collateral Accounts, are powers coupled with an interest and will neither be affected by the bankruptcy of the Borrower nor the lapse of time. (ix) For purposes of the UCC, the Depositary Bank confirms and agrees that the "securities intermediary's jurisdiction" (as defined in the UCC) with respect to the Collateral Accounts is the State of New York. If the "securities intermediary's jurisdiction" shall change from that jurisdiction specified in the previous sentence, the Borrower shall promptly notify the Agent of such change and of such new jurisdiction. (c) LIMITED BORROWER RIGHTS. The Borrower shall not have any rights against or to monies held in the Collateral Accounts, as third party beneficiary or otherwise, except the right to receive or make requisitions of monies held in the Collateral Accounts, as permitted by this Agreement and to direct the investment of monies held in the Collateral Accounts as permitted by Section 4.04. In no event shall any amounts or Permitted Investments be deposited in or credited to either Collateral Account registered in the name of the Borrower, payable to the order of the Borrower or specially endorsed to the Borrower except to the extent that the foregoing have been specially endorsed to the Depositary Bank or in blank. SECTION 4.02. REVENUES ACCOUNT. (a) DEPOSITS INTO THE REVENUES ACCOUNT. The Borrower agrees and confirms that it has irrevocably instructed each party to a Project Document in effect as of the date hereof (and shall instruct each party to any additional Project Documents) and each other Person from whom the Borrower is entitled to receive any: (i) Revenues payable under the Project Documents; (ii) proceeds of any sale (net of the costs and expenses of such sale and any taxes, assessments or prior Liens) of any of the Generating Assets (other than such proceeds constituting Revenues); and 58 (iii) any other cash revenues (other than amounts to be deposited in the Casualty Account pursuant to Section 4.03) to pay the same directly to the Collateral Agent for the account of the Borrower for deposit into the Revenues Account. If, notwithstanding such instructions, the Borrower should receive any such payment, the Borrower shall hold such payment in trust for the Collateral Agent and shall promptly deliver such payment to the Collateral Agent for deposit into the Revenues Account in the exact form received with any necessary endorsement. (b) TRANSFERS FROM THE REVENUES ACCOUNT PRIOR TO AN EVENT OF DEFAULT AND AN ENFORCEMENT ACTION IS COMMENCED. Unless an Event of Default shall have occurred and be continuing, an Enforcement Action shall have been initiated and the Collateral Agent shall have received notice thereof from any Lender, the Collateral Agent shall transfer (or cause to be transferred) from the collected credit balance of the Revenues Account, the following amounts in the following order of priority (and no transfer at any such priority level shall be made on any day if any transfer remains to be made on such day at any higher priority level): FIRST, on the first Business Day of each calender month, for deposit into the Operating Account, an amount equal to (x) the Operating Costs for such month PLUS Capital Expenditures for such month, each as scheduled in the Annual Operating Budget for such month, PLUS an amount equal to any Capital Expenditures, taxes, FERC fees or insurance, each as scheduled in the Annual Operating Budget for future months that the Borrower plans to perform or pay in such month, and that the Borrower certifies in writing to the Collateral Agent that such amount is necessary to perform or pay such Capital Expenditure, taxes, FERC fees or insurance, as the case may be, in such month, (PROVIDED, that an amount equal to any such amount transferred from the Revenues Account to the Operating Account earlier than scheduled in the Annual Operating Budget as provided above shall be subtracted from the aggregate amount to be transferred from the Revenues Account to the Operating Account in the month that such expenditure was scheduled under the Annual Operating Budget so as to avoid duplication of amounts transferred from the Revenues Account to the Operating Account) PLUS (y) an amount not to exceed 10% of such months' scheduled Operating Costs and Capital Expenditures as set forth in the Annual Operating Budget if certified in writing by the Borrower to the Collateral Agent to be necessary; PROVIDED, HOWEVER the Collateral Agent shall not remit funds in excess of the monthly amounts listed in the Annual Operating Budget as requested by the Borrower in accordance with 59 the foregoing more than three times without the prior written consent of the Required Lenders; SECOND, to the Agents and the Depositary Bank, an amount equal to all fees, costs, expenses (including, without limitation, legal fees and expenses), indemnification payments, taxes and other amounts then due and payable by the Borrower to any Agent or the Depositary Bank from time to time as certified to the Collateral Agent by the Agents or the Depositary Bank; THIRD, to the Lenders, an amount equal to the Obligations owed by the Borrower to the Lenders under the Loan Documents then due and payable (excluding mandatory prepayments pursuant to Section 2.05) as certified to the Collateral Agent by the Administrative Agent; FOURTH, to the Lenders, the aggregate amount of any mandatory prepayments then due and payable pursuant to Section 2.05 as certified to the Collateral Agent by the Administrative Agent. (c) TRANSFERS FROM REVENUES ACCOUNT WHEN AN EVENT OF DEFAULT IS CONTINUING AND AN ENFORCEMENT ACTION HAS COMMENCED. At any time that an Event of Default shall have occurred and be continuing and an Enforcement Action has been initiated, upon its receipt of notice thereof from any Lender or the Administrative Agent, the Collateral Agent shall transfer (or caused to be transferred) from the collected credit balance of the Revenues Account only those amounts as directed in writing by the Required Lenders. SECTION 4.03. CASUALTY ACCOUNT. (a) DEPOSITS INTO THE CASUALTY ACCOUNT. The Borrower agrees and confirms that it has irrevocably instructed each insurer from whom the Borrower is entitled to receive any proceeds from any property or casualty insurance policy to pay the same directly to the Collateral Agent for the account of the Borrower for deposit into the Casualty Account. If, notwithstanding such instructions, the Borrower should receive any such payment, the Borrower shall hold such payment in trust for the Collateral Agent and shall promptly deliver such payment to the Collateral Agent for deposit into the Casualty Account in the exact form received with any necessary endorsement. (b) TRANSFERS FROM THE CASUALTY ACCOUNT PRIOR TO AN EVENT OF DEFAULT AND AN ENFORCEMENT ACTION IS COMMENCED. Unless an Event of Default shall have occurred and be continuing and an Enforcement Action shall have been initiated and the Collateral Agent shall have received notice thereof from the Administrative Agent or any Lender, the Collateral Agent shall transfer (or cause to be transferred), from the collected credit balance of the Casualty Account, the following amounts in the following order: 60 (i) if the net proceeds received by the Collateral Agent are less than U.S. $17,500,000 for any single loss or series of losses in the aggregate, the Collateral Agent shall transfer portions of such sum from the Casualty Account to the Operating Account from time to time upon written request from the Borrower for the purpose of making payments required to finance the repair, reconstruction or replacement of the damaged Generating Asset(s) or to reimburse the Borrower for such repair, reconstruction or replacement expenses actually paid by it, against repair, reconstruction or replacement expenses actually paid by it, upon delivery to the Collateral Agent of the Borrower's certification that the funds requested will be applied as provided in this clause 4.03(b)(i); (ii) if the net proceeds received by the Collateral Agent is greater than $17,500,000 for any single loss or series of losses in the aggregate but less than $35,000,000 (and in the case of a series of losses, each additional loss over $17,500,000 shall be a material loss in the reasonable judgment of the Required Lenders), then at any time after such loss or losses and after such time as may be required by the Borrower to assess the extent of such loss or losses and estimate the insurance proceeds to be received in connection therewith, but no later than 45 days after receipt of such proceeds, the Borrower shall deliver to Stone & Webster or another independent engineer reasonably acceptable to the Lenders a plan for the application of such proceeds to repair or replace the damaged property. If, within 30 days from the receipt by the independent engineer of such plan, such independent engineer notifies the Borrower and the Administrative Agent (who shall notify the Lenders in order to vote as provided in this clause (b)(ii)) that, in their reasonable judgment, in light of the nature of the loss or losses and the reasonableness of the plan of the Borrower, it is likely that, after implementation of the Borrower's plan, that (x) such Generating Asset(s) could be repaired in a timely manner and that the insurance proceeds are sufficient to cover the costs of such repair, the amounts on deposit in the Casualty Account shall be transferred to the Operating Account as and when needed for the Borrower to repair, reconstruct or 61 replace the damaged Generating Asset(s), or (y) such Generating Asset(s) could not be repaired or the insurance proceeds are insufficient to cover the costs of such repair, the Required Lenders shall vote within 30 days from such notification from the independent engineer to determine if the amounts on deposit in the Casualty Account shall be applied by the Collateral Agent to prepay the Borrower's Obligations hereunder or if such amounts should be transferred to the Operating Account as and when needed for the Borrower to repair, reconstruct or replace the damaged Generating Asset(s); PROVIDED, if the Required Lenders do not vote to apply the amounts on deposit in the Casualty Account to prepay the Borrower's obligations within such 30 day period, such amounts on deposit in the Casualty Account shall be transferred by the Collateral Agent to the Operating Account as and when needed for the Borrower to repair, reconstruct or replace the damaged Generating Asset(s). If any funds shall be transferred from the Casualty Account to the Operating Account under this subsection (ii), the Borrower must certify to the Lenders that the amounts requested will be applied as provided in this clause 4.03(b)(ii), and that at such time as such repair, reconstruction or replacement is complete, any balance of such sum remaining in the Casualty Account shall be transferred to the Revenues Account at the direction of the Administrative Agent or, if required under the relevant insurance policy or policies, shall, at the direction of the Borrower (with the consent of the Administrative Agent which shall not be unreasonably denied), be paid over to the insurer(s). (iii) if the net proceeds received by the Collateral Agent is greater than or equal to $35,000,000 for any single loss or series of losses in the aggregate, the Collateral Agent shall notify the Lenders thereof, and the Required Lenders shall vote to determine if the amounts on deposit in the Casualty Account shall be applied by the Collateral Agent to prepay the Borrower's Obligations hereunder or if such amounts shall be transferred to the Operating Account for the Borrower to repair, reconstruct or replace the damaged Generating Asset(s); PROVIDED, if the Required Lenders do not vote to apply the amounts on deposit in the Casualty Account to prepay the Borrower's obligations within such 30 day period, such amounts on deposit in the Casualty Account shall be transferred by the Collateral Agent to the Operating Account as and when needed for the Borrower to repair, reconstruct or replace the damaged Generating Asset(s); PROVIDED, FURTHER, that if any funds shall be transferred to the Operating Account under this subsection (iii), the Borrower must certify to the Lenders that the amounts to be transferred from the Casualty Account will be applied as provided in this clause 4.03(b)(iii); and PROVIDED, FURTHER, HOWEVER, that at such time as such repair, reconstruction or replacement is complete, any balance of such sum remaining in the Casualty Account shall be transferred to the Revenues Account at the direction of the Administrative Agent or, if required under the relevant insurance policy or policies, shall, at the direction of the Borrower (with the consent of the Administrative Agent which shall not be unreasonably denied), be paid over to the insurer(s). (c) TRANSFERS FROM CASUALTY ACCOUNT WHEN AN EVENT OF DEFAULT IS CONTINUING AND AN ENFORCEMENT ACTION HAS 62 COMMENCED. At any time that an Event of Default shall have occurred and be continuing and an Enforcement Action has been initiated, upon its receipt of notice thereof from any Lender, the Collateral Agent shall transfer (or caused to be transferred) from the collected credit balance of the Casualty Account only those amounts as directed in writing by the Required Lenders. SECTION 4.04. INVESTMENT OF FUNDS IN COLLATERAL ACCOUNTS. (a) Unless an Event of Default shall have occurred and be continuing, the Collateral Agent shall invest funds (and vary and redeem such investments) in the Collateral Accounts, in the name of the Collateral Agent, as directed by the Borrower, PROVIDED in each case that the designated investment is a Permitted Investment. After the occurrence and during the continuance of an Event of Default, investments in Permitted Investments shall be made as directed by the Administrative Agent. (b) Whenever the Collateral Agent is directed or authorized in accordance with the terms hereof to make a transfer of funds from the Collateral Accounts, if, after application of all other available funds, liquidation of a Permitted Investment is necessary to make any such transfer, the Collateral Agent is authorized to liquidate such Permitted Investment. The Collateral Agent shall liquidate all those Permitted Investments which can be liquidated without interest costs or penalty before it shall liquidate any Permitted Investment the liquidation of which would involve an interest cost or penalty. The Collateral Agent shall have no liability with respect to any interest cost or penalty on the liquidation of any Permitted Investment pursuant to this Section 4.04(b). (c) The Collateral Agent shall have no liability with respect to Permitted Investments (or any losses resulting therefrom) made at the direction of the Borrower or as otherwise provided in Section 4.04(a). (d) All references in this Agreement to the Collateral Accounts and to cash, moneys or funds therein or balances thereof shall include the investments in which such moneys are then invested. All investments shall be under the sole dominion and control of the Collateral Agent, subject to the terms and conditions of this Agreement and the Collateral Documents. SECTION 4.05. INTEREST. Any interest or other earnings accrued on any balances in the Revenues Account, or on any investment thereof, shall be credited to and accumulated in the Revenues Account and thereafter be applied without differentiation from other funds in the Revenues Account. Any interest or other earnings accrued on any balances in the Casualty Account, or on any investment thereof, shall be credited to and accumulated in the Casualty Account and thereafter be applied without differentiation from other funds in the Casualty Account. 63 SECTION 4.06. REPORTS TO THE BORROWER AND THE LENDERS. The Collateral Agent shall deliver, or cause the Depositary Bank to deliver, to the Borrower and each Lender within 15 Business Days after the end of the calendar month in which the first deposit is made into either Collateral Account and each calendar month thereafter, a report with respect to the Collateral Account, setting forth in reasonable detail all deposits to and disbursements from such Collateral Account during such month, including the date on which made, and the balances of and any investments in such Collateral Account at the end of such month. The Collateral Agent shall provide any additional information or reports relating to the Collateral Accounts and the transactions therein reasonably requested from time to time by the Borrower or any Lender. SECTION 4.07. BOOKS AND RECORDS. The Collateral Agent shall, or cause the Depositary Bank to, maintain all books and records with respect to the Collateral Accounts as may be necessary properly to record all transactions carried out by it under this Agreement. The Collateral Agent shall permit the Borrower and each Lender to examine such books and records with respect to the Collateral Accounts, PROVIDED that any such examination shall occur upon reasonable notice and during normal business hours. ARTICLE V REPRESENTATIONS AND WARRANTIES SECTION 5.01. REPRESENTATIONS AND WARRANTIES OF THE BORROWER. The Borrower represents and warrants as follows: (a) The Borrower (i) is a corporation duly organized, validly existing and in good standing under the laws of the jurisdiction of its incorporation, (ii) is duly qualified and in good standing as a foreign corporation in each other jurisdiction in which it owns or leases property or in which the conduct of its business requires it to so qualify or be licensed and (iii) has all requisite corporate power and authority (including, without limitation, all Governmental Authorizations, licenses, permits and other approvals) to own or lease and operate its properties and to carry on its business as now conducted and as proposed to be conducted, except as noted in Section 5.01(d) and except where the failure to so qualify or be licensed would not have a Material Adverse Effect. All of the outstanding capital stock of the Borrower has been validly issued, is fully paid and non-assessable and is owned by NU Enterprises free and clear of all Liens, except those created under the Collateral Documents. 64 (b) The Borrower has no Subsidiaries. (c) The execution, delivery and performance by the Borrower of this Agreement, the Notes, each other Loan Document and the Acquisition Documents to which it is or is to be a party, and the other transactions contemplated hereby and thereby, are within the Borrower's corporate powers, have been duly authorized by all necessary corporate action, and do not (i) contravene the Borrower's charter or bylaws, (ii) violate any law (including, without limitation, the Securities Exchange Act of 1934 and the Racketeer Influenced and Corrupt Organizations Chapter of the Organized Crime Control Act of 1970), rule, regulation (including, without limitation, Regulation X of the Board of Governors of the Federal Reserve System), order, writ, judgment, injunction, decree, determination or award, (iii) conflict with or result in the breach of, or constitute a default under, any Acquisition Document, existing Material Contract, Project Document, loan agreement, indenture, mortgage, deed of trust, material lease or other material instrument binding on or affecting the Borrower or any of its properties or (iv) except for the Liens created under the Collateral Documents, result in or require the creation or imposition of any Lien upon or with respect to any of the properties of the Borrower. The Borrower is not in violation of any such law, rule, regulation, order, writ, judgment, injunction, decree, determination or award or in breach of any such contract, loan agreement, indenture, mortgage, deed of trust, lease or other instrument, the violation or breach of which could have a Material Adverse Effect. (d) No authorization or approval or other action by, and no notice to or filing with, any Governmental Authority or any third party is required for (i) the due execution, delivery, recordation, filing or performance by the Borrower of this Agreement, the Notes, any other Loan Document or the Acquisition Documents or the existing Material Contracts or the Project Documents to which it is or is to be a party or the other transactions contemplated hereby or thereby, (ii) the grant by the Borrower of the Liens granted by it pursuant to the Collateral Documents to which it is a party, (iii) the perfection or maintenance of the Liens created by the Collateral Documents to which it is a party (including the first priority nature thereof), (iv) the ongoing operation of the Generating Assets by the Borrower, except to the extent the absence thereof would not be reasonably likely to have a Material Adverse Effect or (v) the exercise by the Administrative Agent or any Lender of its rights under the Loan Documents or the remedies in respect of the Collateral pursuant to the Collateral Documents to which it is a party except for (A) the Governmental Authorizations listed on Part A-1 of 65 Schedule 5.01(d) hereto with respect to the CL&P Acquisition and the Governmental Authorizations listed on Part A-2 of Schedule 5.01(d) hereto with respect to the WMECO Acquisition and (B) the amendments, waivers and consents listed on Part B of Schedule 5.01(d) hereto with respect to the Acquisition, all of which relating to the Acquisition shall have been duly obtained, taken, given or made and shall be in full force and effect on the Borrowing Date. (e) This Agreement has been, and each of the Notes, each other Loan Document, each Acquisition Document, each existing Material Contract and each Project Document to which it is a party when delivered hereunder will have been, duly executed and delivered by the Borrower. This Agreement is, and each of the Notes, each other Loan Document, each Acquisition Document, each existing Material Document and each other Project Document to which it is a party when delivered hereunder will be, the legal, valid and binding obligation of the Borrower, enforceable against the Borrower in accordance with its terms. (f) The unaudited financial statements of the Borrower for the fiscal year ended December 31, 1999 fairly present the financial condition of the Borrower on such date, in accordance with GAAP, and since December 31, 1999, there has been no material adverse change in the business, condition (financial or otherwise), operations, performance, properties or prospects of the Borrower. (g) (i) All written information that has been or will hereafter be made available by the Borrower or any of its representatives in connection with the transactions contemplated hereby to the Co-Arrangers, to any Lender or to any potential Lender, is and will be true and correct in all material respects and does not and will not contain any misstatement of a material fact or omit to state a material fact necessary in order to make the statements contained therein not misleading in light of the circumstances under which such statements were or are made, and (ii) all financial projections, if any, that have been or will be prepared by the Borrower or any of its representatives in connection with the transactions contemplated hereby have been or will be prepared in good faith based upon reasonable assumptions at the time made. (h) Other than as set forth in the Disclosure Documents, there is no action, suit, investigation, litigation or proceeding affecting the Borrower, including any Environmental Action, pending or, to the best of the Borrower's knowledge, threatened before any court, governmental agency or arbitrator that individually or in the aggregate (i) could have a 66 Material Adverse Effect or (ii) purports to affect the legality, validity or enforceability of this Agreement, any Note, any other Loan Document, any Acquisition Document or any Project Document or the transactions contemplated thereby. (i) Other than as set forth in the Disclosure Documents, the operations and properties of the Borrower, the CL&P Generating Assets and the WMECO Generating Assets comply in all material respects with all applicable Environmental Laws and Environmental Permits (except for any such noncompliance that has been consented to by the appropriate authority), all past material noncompliance with such Environmental Laws and Environmental Permits has been resolved without material ongoing obligations or costs to the Loan Parties, and no circumstances exist that could reasonably be expected to (i) form the basis of an Environmental Action against the Borrower or any of their respective properties or any of the Generating Assets, or (ii) cause any such property to be subject to any restrictions on ownership, occupancy, use or transferability under any Environmental Law that, in the case of either clause (i) or (ii), could reasonably be expected to have a Material Adverse Effect. (j) The execution and delivery of the Loan Documents, the Acquisition Documents and the Project Documents to which the Borrower is a party and the performance by the Borrower of its obligations thereunder are exempt from taxes (other than income taxes), levies, imposts, deductions, charges and withholdings imposed by any Governmental Authority in the United States or any political subdivision or taxing authority thereof or therein, as applicable, except for such transfer or conveyance or mortgage recording taxes as shall have been paid on the Borrowing Date or as otherwise due and such taxes, nominal recording fees, levies, imposts, deductions, charges and withholdings which may have been paid or shall be paid in due course by the Borrower and have been disclosed to the Lenders. (k) The Borrower is an Exempt Wholesale Generator. As an Exempt Wholesale Generator, the Borrower is (a) not subject to or exempt from regulation under the Public Utility Holding Company Act of 1935 and Part II of the Federal Power Act (other than the minimum statutory requirements that apply to Exempt Wholesale Generators generally), (b) not subject to or exempt from any statute or regulation which prohibits or restricts the incurrence of the obligations under the Loan Documents or the granting of the liens contemplated thereby, including, without limitation, statutes or regulations relative to common or contract carriers or to the sale of electricity, gas, steam, water, telephone, telegraph or other public 67 utility services, and (c) not subject to or exempt from regulation as an electric distribution company, a public utility, an electric corporation or any similar type of entity under Connecticut law or Massachusetts law. (l) The Borrower is not engaged in the business of extending credit for the purpose of purchasing or carrying Margin Stock, and no proceeds of any Advance will be used to purchase or carry any Margin Stock or to extend credit to others for the purpose of purchasing or carrying any Margin Stock. (m) The Borrower's obligations under the Loan Documents to which it is a party constitute direct, unconditional and unsubordinated obligations of the Borrower. (n) Both before and after the Acquisition is consummated, except for the liens created or permitted pursuant to the Loan Documents, the Borrower has valid and uncontested legal title to its material properties free and clear of all liens and competing claims. (o) The Borrower is in compliance in all material respects with all applicable laws, ordinances, rules, regulations, and requirements of all Governmental Authorities (including, without limitation, certificates, permits, franchises and other Governmental Authorizations necessary to the ownership of its respective properties or to the conduct of its respective business, environmental laws, and laws with respect to social security and pension fund obligations) except in each case to the extent where such failure to comply could not reasonably be expected to have a Material Adverse Effect. (p) The Borrower is not an "investment company" or an "affiliated person" of, or "promoter" or "principal underwriter" for, an "investment company", as such terms are defined in the Investment Company Act of 1940, as amended. (q) Set forth on Schedule 5.01(q) hereto is a complete and accurate list of all Plans, Multiemployer Plans and Welfare Plans. (r) No ERISA Event has occurred or is reasonably expected to occur with respect to any Plan. (s) Schedule B (Actuarial Information) to the most recent annual report (Form 5500 Series) for each Plan, copies of which have been filed with the Internal Revenue Service and furnished to each Lender, is complete and accurate and fairly presents the funding status of such Plan, and since the date of such 68 Schedule B there has been no material adverse change in such funding status. (t) Neither any Loan Party nor any ERISA Affiliate has incurred or is reasonably expected to incur any Withdrawal Liability to any Multiemployer Plan. (u) Neither the Borrower nor any ERISA Affiliate has been notified by the sponsor of a Multiemployer Plan that such Multiemployer Plan is in reorganization or has been terminated, within the meaning of Title IV of ERISA, and no such Multiemployer Plan is reasonably expected to be in reorganization or to be terminated, within the meaning of Title IV of ERISA. (v) Since December 31, 1999, neither the business nor the properties of the Borrower, the CL&P Generating Assets nor the WMECO Generating Assets are, or have been, affected by any fire, explosion, accident, strike, lockout or other labor dispute, drought, storm, hail, earthquake, embargo, act of God or of the public enemy or other casualty (whether or not covered by insurance) that could reasonably have a Material Adverse Effect. (w) The Borrower is not a party to any indenture, loan or credit agreement or any lease or other agreement or instrument or subject to any charter or corporate restriction that, in each case, could reasonably be expected to have a Material Adverse Effect. (x) The Collateral Documents create a valid and perfected first priority security interest in the Collateral, securing the payment of the Secured Obligations, and all filings and other actions deemed necessary to perfect and protect such security interest have been taken or will be taken as of the Borrowing Date. (y) The Borrower has filed, has caused to be filed or has been included in all tax returns (national, departmental, local, municipal and foreign) required to be filed or has received appropriate filing extensions therefor and has paid or shall pay in due course or caused to be paid all taxes, assessments, fees and other charges shown thereon to be due, together with applicable interest and penalties, other than the payment of any taxes, assessment, fees or other charges (i) the nonpayment of which could not reasonably be expected to have a Material Adverse Effect or (ii) that are being contested in good faith and by proper proceedings and as to which appropriate reserves are being maintained. 69 (z) The Borrower is, and after the consummation of each Acquisition and the transactions contemplated hereby will be, Solvent. (aa) The Borrower has not conducted or engaged in any activities other than (i) the business of, and activities related to, electric power generation and (ii) businesses and activities otherwise permitted under the terms of the Loan Documents, the Acquisition Documents and the Project Documents. (bb) No default or event of default has occurred and is continuing under, and as defined in, any Loan Document, Acquisition Document, Project Document or existing Material Contract to which the Borrower is a party. (cc) For tax purposes, the Borrower's initial basis in the Generating Assets will be equal to the purchase price paid for the Generating Assets. The Borrower is not a party to, and is not bound by, any tax sharing agreement other that the Tax Sharing Agreement. (dd) Set forth on Schedule 5.01(dd) hereto is a complete and accurate list of all Liens on the property or assets of the Borrower (including, without limitation, the Generating Assets), showing as of the date hereof the lienholder thereof, the principal amount of the obligations secured thereby and the property or assets of the Borrower subject thereto. (ee) Set forth on Schedule 5.01(ee) hereto is a complete and accurate list of all existing Material Contracts of the Borrower, showing as of the date hereof the parties, subject matter and term thereof. Each such Material Contract has been duly authorized, executed and delivered by all parties thereto, has not been amended or otherwise modified, is in full force and effect and is binding upon and enforceable against all parties thereto in accordance with its terms, and there exists no event of default under any Material Contract by the Borrower or to the Borrower's knowledge by any other party thereto. (ff) There are no lease or license agreements relating to recreational access and/or use by third party users of the impoundments that either are not terminable for any reason by the owner of the real property in question or are fully subordinated to any mortgage lien (regardless of the date of recording of such mortgage) placed on the real property in question, except for such lease or license agreements that would not materially adversely affect the operation of the Generating Assets. 70 (gg) To the Borrower's knowledge there have been no breaches of the use restrictions encumbering the real property listed in the title commitments provided by the title company and the Borrower has no knowledge that there are any material use restrictions in addition to those listed in the title commitments provided by the title company. (hh) Upon the transfer of the Generating Assets to the Borrower, the Borrower will own outright or be granted the right to access or otherwise use all facilities, improvements and rights to real property it will need to generate electricity as contemplated and as permitted by the applicable FERC licenses. (ii) To the best of the Borrower=s knowledge, there are no Neighboring Landowner Agreements currently in effect that, if the third party holder of such agreement defaulted in its obligations under such Neighboring Landowner Agreement, such default would have a Material Adverse Effect. (jj) To the best of the Borrowers knowledge, there have been no breaches of the use restrictions encumbering the real property listed in the Mortgage Policies and the Borrower has no knowledge that there are any material use restrictions in addition to those listed in the Mortgage Policies. (kk) The Borrower is not aware of any problems relating to the Year 2000 date change that might materially affect its business. ARTICLE VI COVENANTS OF THE BORROWER SECTION 6.01. AFFIRMATIVE COVENANTS. So long as any Advance shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will: (a) COMPLIANCE WITH LAWS, ETC. Comply in all material respects with all applicable laws, rules, regulations and orders, such compliance to include, without limitation, compliance with ERISA and the Racketeer Influenced and Corrupt Organizations Chapter of the Organized Crime Control Act of 1970, except when contested in good faith by appropriate proceedings and for which an adequate reserve has been established or where noncompliance could not reasonably be expected to have a Material Adverse Effect. (b) PAYMENT OF TAXES, ETC. Pay and discharge before the same shall become delinquent, (i) all taxes, 71 assessments and governmental charges or levies imposed upon it or upon its property and (ii) all lawful claims that, if unpaid, might by law become a Lien upon its property; PROVIDED, HOWEVER, that the Borrower shall not be required to pay or discharge any such tax, assessment, charge or claim that is being contested in good faith and by proper proceedings and as to which appropriate reserves are being maintained, unless and until any Lien resulting therefrom (other than Liens for unpaid municipal real property taxes not in excess of $300,000 in the aggregate which have attached solely by operation of law and as to which no Enforcement Action has been taken) attaches to its property and becomes enforceable against its other creditors or where nonpayment could not reasonably be expected to have a Material Adverse Effect. (c) COMPLIANCE WITH ENVIRONMENTAL LAWS. Comply, and cause all lessees and other Persons operating or occupying its properties to comply, with all applicable Environmental Laws and Environmental Permits; obtain and renew all Environmental Permits necessary for its operations and properties; and conduct any investigation, study, sampling and testing, and undertake any cleanup, removal, remedial or other action necessary to remove and clean up all Hazardous Materials from any of its properties, in accordance with the requirements of all Environmental Laws; except where noncompliance could not reasonably be expected to have a Material Adverse Effect; PROVIDED, HOWEVER, that the Borrower shall not be required to undertake any such cleanup, removal, remedial or other action to the extent that its obligation to do so is being contested in good faith and by proper proceedings and appropriate reserves are being maintained with respect to such circumstances. (d) OPERATION OF THE GENERATING ASSETS. Cause the Generating Assets to be operated and maintained and its business to be conducted, (i) in a prudent manner, based on industry standards for comparable facilities or businesses in comparable locations, and (ii) in accordance with applicable laws (including Environmental Laws), except when contested in good faith by appropriate proceedings and for which an adequate reserve has been established or where noncompliance could not reasonably be expected to have a Material Adverse Effect. (e) MAINTENANCE OF INSURANCE. Maintain insurance with responsible and reputable insurance companies or associations of the type indicated on, and in such amounts and covering such risks as is required by law and as set forth on, Schedule 5. (f) PRESERVATION OF CORPORATE EXISTENCE, ETC. Preserve and maintain its existence, legal structure, 72 legal name, rights (charter and statutory), permits, licenses, approvals, privileges and franchises, except for such rights, franchises, permits, licenses and approvals the failure of which to maintain could not reasonably be expected to have a Material Adverse Effect. (g) VISITATION RIGHTS. Subject to Section 9.09, upon reasonable prior notice and during customary business hours, permit the Administrative Agent, the Collateral Agent or any Lender or any agents or representatives thereof, to examine and make copies of and abstracts from the records and books of account of, and visit the properties of the Borrower, and to discuss the affairs, finances and accounts of the Borrower with any of its officers or directors and with its independent certified public accountants. (h) MAINTENANCE OF APPROVALS AND LICENSES. Obtain and maintain in full force and effect all Governmental Authorizations and licenses that may be required for the validity or enforceability of the Loan Documents, the Material Contracts, the Acquisition Documents and the Project Documents and the ongoing operations of the Generating Assets except where the failure to do so could not reasonably be expected to have a Material Adverse Effect. (i) KEEPING OF BOOKS. Keep proper books of record and account, in which full and correct entries shall be made of all financial transactions and the assets and business of the Borrower in accordance with GAAP. (j) MAINTENANCE OF PROPERTIES, ETC. Keep all property useful and necessary to its respective businesses in good working order and condition, wear and tear excepted, and not commit or suffer to exist any waste with respect to any of its properties except where the failure to do so could not reasonably be expected to have a Material Adverse Effect. (k) PERFORMANCE OF MATERIAL CONTRACTS, ACQUISITION DOCUMENTS AND PROJECT Documents. Perform and observe all the material terms and provisions of each Material Contract, each Acquisition Document and each Project Document to be performed or observed by it, enforce each such Material Contract and each such Project Document in accordance with its terms, take all such action to such end and exercise all rights under the Material Contracts, the Acquisition Documents and the Project Documents as may be from time to time requested by the Administrative Agent and, upon request of the Administrative Agent, make to each other party to each such Material Contract, each such Acquisition Document and each such Project Document such demands and requests for information and reports or for action 73 as the Borrower is entitled to make under such Material Contract, such Acquisition Document or such Project Document. (l) TRANSACTIONS WITH AFFILIATES. Conduct all transactions otherwise permitted under the Loan Documents with any of its Affiliates on terms that are fair and reasonable and no less favorable to the Borrower than it would obtain in a comparable arm's-length transaction with a Person not an Affiliate. (m) COVENANT TO GIVE SECURITY. Promptly upon the reasonable request of the Administrative Agent or the Collateral Agent, at the Borrower's expense, execute and deliver, or cause the execution and delivery of, and thereafter register, file or record in each appropriate governmental office, any document or instrument supplemental to or confirmatory of the applicable Loan Documents relating to the Collateral or otherwise reasonably deemed by the Administrative Agent or the Collateral Agent to be necessary for the creation or perfection or priority or continuation of the Liens and security interests purported to be created by any such document; and protect and defend its and the Lenders' interest in the Collateral against Liens (other than Permitted Liens) and immediately discharge any such lien so asserted. (n) MAINTENANCE OF PRIORITY. Take all necessary action so as to ensure that all Obligations of the Loan Parties under the Loan Documents continue to rank senior in right of payment and collateral security to all unsecured or unsubordinated Obligations of the Loan Parties. (o) REGULATORY STATUS. Take all necessary action within its control, and otherwise use its best efforts, to ensure that (i) the Borrower remains exempt from all or is not subject to any regulation as a public utility under the Public Utility Holding Company Act of 1935 and any other applicable federal, state and local laws or regulations regulating public utilities, public utility companies, public utility holding companies, electric utilities, electric companies, electric utility companies, or any similar entity, (ii) the Borrower maintains its status as an Exempt Wholesale Generator and (iii) the Administrative Agent, the Collateral Agent and each Lender will not (i) be subject to regulation as a "public utility" under the Federal Power Act, an electric distribution company, a public utility, an electric corporation or any similar type of entity under Connecticut law or Massachusetts law, or (ii) be subject to regulation by the Securities and Exchange Commission as a "gas utility company," "electric utility company," "public utility company," "holding company," an "affiliate" of a "holding company," a "subsidiary company" of a "holding 74 company," or an "affiliate" of a "subsidiary company" of a "holding company" under the Public Utility Holding Company Act of 1935, or (iii) otherwise be deemed by any federal, state or local Governmental Authority to be a public utility, public utility company, public utility holding company, electric utility, electric company, electric utility company or similar entity or otherwise subject to any regulation relating to any such type of entity (or affiliate thereof). In the event that FERC denies Exempt Wholesale Generator status to the Borrower, the Borrower shall take all necessary actions within its control and without delay, and otherwise use its reasonable best efforts, to comply with the Public Utility Holding Company Act of 1935, including, but not limited to, (y) making any changes necessary to eliminate the basis for denial of the original application for Exempt Wholesale Generator status and preparing and filing a new application in good faith with FERC for a determination of Exempt Wholesale Generator status, or (z) filing an application under the relevant provisions of the Public Utility Holding Company Act of 1935 to qualify Borrower as an operating "public utility company" of Northeast Utilities. (p) USE OF PROCEEDS. Use the proceeds of the Advances solely as provided in Section 2.13. (q) REQUIRED RATING. Actively assist the Placement Agent in obtaining a final rating letter equal to or higher than the Required Rating from each of the Rating Agencies for the Permanent Financing, such assistance to include, without limitation: (A) providing, and causing its respective advisors to provide, the Placement Agent and each of the Rating Agencies upon request with all information reasonably deemed necessary by either of the Rating Agencies or the Placement Agent to acquire the rating letter equal to or higher than the Required Rating, (B) assisting the Placement Agent, upon its reasonable request, in the preparation of all materials presented to the Rating Agencies to be used in connection with obtaining the rating letter equal to or higher than the Required Rating and (C) otherwise assisting the Placement Agent in obtaining a rating equal to or higher than the Required Rating, including by making available officers and advisors of the Borrower and its respective Affiliates from time to time to attend and make presentations regarding the business and prospects of the Borrower, its Affiliates and the Generating Assets, as appropriate, at a meeting or meetings with each of the Rating Agencies. (r) SEPARATE AND DISTINCT. Comply with the following undertakings: 75 (i) It will maintain its books, financial records and accounts, including checking and other bank accounts and custodian and other securities safekeeping accounts, separate and distinct from those of Northeast Utilities and each of the other Subsidiaries of Northeast Utilities. (ii) It will maintain its books, financial records and accounts (including inter-entity transaction accounts) in a manner so that it will not be difficult or costly to segregate, ascertain or otherwise identify its assets and liabilities separate and distinct from the assets and liabilities of Northeast Utilities and each of the other Subsidiaries of Northeast Utilities. (iii) It will not commingle any of its assets, funds, liabilities or business functions with the assets, funds, liabilities or business functions of Northeast Utilities or any of the other Subsidiaries of Northeast Utilities. (iv) It will maintain corporate governance and operating procedures designed to ensure its separate corporate existence from Northeast Utilities and each of the other Subsidiaries of Northeast Utilities, including the holding of periodic and special meetings of shareholders and boards of directors (or other governing body), the recordation and maintenance of minutes of such meetings, and the recordation and maintenance of resolutions adopted at such meetings. (v) It will not be consensually merged or consolidated with Northeast Utilities or any of the other Subsidiaries of Northeast Utilities (other than, with respect to other Subsidiaries of Northeast Utilities, for financial reporting purposes). (vi) It will cause all material transactions, agreements and dealings between it and Northeast Utilities and any of the other Subsidiaries of Northeast Utilities (including transactions, agreements and dealings pursuant to which the assets or property of one is used or to be used by the other) to reflect the separate identity and legal existence of each such entity, to be entered into in the names of the persons that are parties to the transaction or agreement and to be formally documented in writing. (vii) It will ensure that transactions between itself and any third parties will be conducted in its name as an entity separate and distinct from Northeast Utilities and each of the other Subsidiaries of Northeast Utilities. 76 (viii) It will compensate all consultants, independent contractors and agents from its own funds for services provided to it by such consultants, independent contractors and agents. (ix) It will ensure that to the extent that it, on the one hand, and Northeast Utilities or any of the other Subsidiaries of Northeast Utilities, on the other hand, jointly contract or do business with vendors or service providers or share overhead expenses, the costs and expenses incurred in so doing will be fairly and non-arbitrarily allocated between or among such entities, with the result that each such entity bears its fair share of all such costs and expenses. It will ensure that to the extent that it, on the one hand, and Northeast Utilities or any of the other Subsidiaries of Northeast Utilities, on the other hand, contracts or does business with vendors or service providers where the goods or services are wholly or partially for the benefit of the other, then the costs incurred in so doing will be fairly and non-arbitrarily allocated to the entity for whose benefit the goods or services are provided, with the result that each such entity bears its fair share of all such costs. (x) It will have annual financial statements prepared in accordance with GAAP, separate from Northeast Utilities and any of the other Subsidiaries of Northeast Utilities. (xi) It will not make any inter-entity loans, advances, guarantees, extensions of credit or contributions of capital to, from or for the benefit of Northeast Utilities or any of the other Subsidiaries of Northeast Utilities without proper documentation and accounting in accordance with GAAP. (xii) It will cause to be prepared and maintained all legally required tax returns for itself (including federal and state income tax returns) separately from the tax returns of Northeast Utilities and any of the other Subsidiaries of Northeast Utilities, except as otherwise required or permitted by law, and it will cause such tax returns to be prepared in accordance with the Tax Sharing Agreement whether or not it has been entered into by the parties proposed to be party thereto. (xiii) It will identify itself as a separate Connecticut corporation and not as a division or department of Northeast Utilities, any of Northeast Utilities' other Subsidiaries or any 77 other Person and identify Northeast Utilities and its other Subsidiaries as separate entities and not as divisions or departments of Northeast Utilities or any of its other Subsidiaries. (xiv) It will cause its representatives and agents to hold themselves out to third parties as being representatives or agents of the Borrower. (s) It will cause the Incentive Payment (as defined in the Select Power Purchase Agreement) or the equivalent term used therein, if any, to be the identical dollar amount to the Incentive Payment (as defined in the O&M Agreement) or the equivalent term used therein, if any. SECTION 6.02. NEGATIVE COVENANTS. So long as any Advance shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will not, at any time: (a) LIENS, ETC. Create, incur, assume or suffer to exist any Lien on or with respect to any of its properties of any character (including, without limitation, accounts) whether now owned or hereafter acquired, or sign or file or suffer to exist, under the Uniform Commercial Code as in effect from time to time of any jurisdiction, a financing statement that names the Borrower as debtor, or sign or suffer to exist, any security agreement authorizing any secured party thereunder to file such financing statement, or assign any accounts or other right to receive income, EXCLUDING, HOWEVER, from the operation of the foregoing restrictions the Permitted Encumbrances under the Mortgages. (b) DEBT. Create, incur, assume or suffer to exist any Debt other than: (i) Debt under the Loan Documents; (ii) Permitted Hedges; and (iii) Bonds for the conduct of its business in the ordinary course not to exceed $250,000 in the aggregate outstanding at any time. (c) LEASE OBLIGATIONS. Create, incur, assume or suffer to exist any obligations as lessee for the rental or hire of real or personal property of any kind under leases or agreements to lease including Capitalized Leases having an original term of one year or more that would cause the direct and contingent liabilities of the Borrower, in respect of all such obligations to exceed $100,000 payable in any period of 12 consecutive months. 78 (d) MERGERS, ETC. Merge into or consolidate with any Person or permit any Person to merge into it. (e) SALES, ETC., OF ASSETS. Sell, lease, transfer or otherwise dispose of any of its property or assets, or grant any option or other right to purchase, lease or otherwise acquire any of its property or assets, except (i) sales of power in the ordinary course of its business and (ii) sales of damaged, worn-out or obsolete or other property that is not necessary for the proper conduct of the business of the Borrower or the operation of the Generating Assets for fair value in the ordinary course of business. (f) INVESTMENTS IN OTHER PERSONS. Make or hold any Investment in any Person other than Permitted Investments. (g) DIVIDENDS, ETC. Declare or pay any dividends, purchase, redeem, retire, defease or otherwise acquire for value any of its capital stock or any warrants, rights or options to acquire such capital stock, now or hereafter outstanding, return any capital to its stockholders as such, make any distribution of assets, capital stock, warrants, rights, options, obligations or securities to its stockholders as such or issue or sell any capital stock or any warrants, rights or options to acquire such capital stock. (h) CHANGE IN NATURE OF BUSINESS. Engage in any business other than the business of, and activities related and incidental to, electric power generation. (i) CHARTER AMENDMENTS. Amend its certificate of incorporation or bylaws or change its corporate structure if such amendment or change would have a Material Adverse Effect. (j) ACCOUNTING CHANGES. Make or permit any change in (i) accounting policies or reporting practices, except as required by GAAP or (ii) its Fiscal Year. (k) AMENDMENT, ETC., OF PROJECT DOCUMENTS, ACQUISITION DOCUMENTS AND MATERIAL CONTRACTS. With respect to any Material Contract, Acquisition Document or any Project Document to which it is a party, not to cancel or terminate, or accept any cancellation or termination of, or amend, modify or change in any manner (which would result in a Material Adverse Effect) any such Material Contract, Acquisition Document or any Project Document without the prior written approval of the Lenders. (l) NEGATIVE PLEDGE. Enter into or suffer to exist any agreement prohibiting or conditioning the creation or assumption of any Lien upon any of its 79 property or assets other than (i) in favor of the Secured Parties or (ii) in connection with any other Debt permitted by Section 6.02 hereof. (m) PARTNERSHIPS, ETC. Become a general partner in any general or limited partnership or joint venture or similar type of entity. (n) CAPITAL EXPENDITURES. Make any Capital Expenditures in excess of the Capital Expenditures included in the Annual Operating Budget delivered in connection with Section 3.01(m)(xv), other than Capital Expenditures required by a change in law or the order of a competent Governmental Authority, issued after the date hereof or Capital Expenditures requested by Select provided that Select funds the costs for such Capital Expenditures and that (i) if the Capital Expenditure costs less than $500,000 and is not expected to interfere with the operation of any Generating Asset, the Borrower shall deliver a certificate to the Lenders stating that such Capital Expenditure shall not result in a Material Adverse Effect to such Generating Asset or a Material Adverse Effect on the Borrower, and (ii) if the cost of the Capital Expenditure is in excess of $500,000 or would interfere with the operation of a Generating Asset, Stone & Webster or another independent engineer reasonably acceptable to the Lenders shall confirm to the Lenders that such Capital Expenditure would not result in a Material Adverse Effect to such Generating Asset or a Material Adverse Effect to the Borrower; PROVIDED, that Select shall have no claim against the Borrower for the funds advanced for any such Capital Expenditures, that Select shall have no Liens against the Borrower or the Generating Assets arising from such Capital Expenditure and that the title to the assets acquired or financed by such Capital Expenditure shall be in the name of the Borrower. (o) TAX ARRANGEMENTS. Cancel or terminate, or accept any cancellation or termination of, or amend, modify or change in any manner the Tax Sharing Agreement, or enter into any new tax sharing agreement, without the prior written approval of the Lenders; provided, HOWEVER, that no such approval shall be required to the extent that such action or such new tax sharing agreement, as the case may be, can reasonably be expected not to have a Material Adverse Effect. SECTION 6.03. REPORTING REQUIREMENTS. So long as any Advance shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will furnish to the Lenders: (a) DEFAULT NOTICE. As soon as possible and in any event within five Business Days after the occurrence of each Default or any event which would 80 reasonably likely have a Material Adverse Effect continuing on the date of such statement, a statement of the chief financial officer of the Borrower setting forth details of such Default and the action that the Borrower has taken and proposes to take with respect thereto. (b) QUARTERLY FINANCIALS. As soon as available and in any event within 60 days after the end of each of the first three quarters of each Fiscal Year, a balance sheet of the Borrower as of the end of such quarter and statement of income and a statement of cash flows of the Borrower for the period commencing at the end of the previous fiscal quarter and ending with the end of such fiscal quarter and a statement of income and a statement of cash flows of the Borrower for the period commencing at the end of the previous Fiscal Year and ending with the end of such quarter, setting forth in each case in comparative form the corresponding figures for the corresponding period of the preceding Fiscal Year, all in reasonable detail and duly certified (subject to year-end audit adjustments) by the chief financial officer of the Borrower as having been prepared in accordance with GAAP, together with (i) a certificate of said officer stating that no Default has occurred and is continuing or, if a Default has occurred and is continuing, a statement as to the nature thereof and the action that the Borrower has taken and proposes to take with respect thereto, (ii) a certificate of said officer specifically confirming compliance by the Borrower with Section 6.01(r) and (iii) a schedule in form satisfactory to the Administrative Agent of the computations used by the Borrower in determining compliance with the covenant contained in Section 6.04, PROVIDED that in the event of any change in GAAP used in the preparation of such financial statements, the Borrower shall also provide, if necessary for the determination of compliance with Section 6.04, a statement of reconciliation conforming such financial statements to GAAP. (c) ANNUAL FINANCIALS. As soon as available and in any event within 120 days after the end of each Fiscal Year, a copy of the annual audit report for such year for the Borrower, including therein a balance sheet of the Borrower as of the end of such Fiscal Year and a statement of income and a statement of cash flows of the Borrower for such Fiscal Year, in each case accompanied by an opinion reasonably acceptable to the Required Lenders of Arthur Anderson, LLP or other independent public accountants of recognized standing acceptable to the Required Lenders, together with (i) a certificate of such accounting firm to the Lenders stating that in the course of the regular audit of the business of the Borrower, which audit was conducted by such accounting firm in accordance with generally accepted auditing standards, such accounting firm has 81 obtained no knowledge that a Default has occurred and is continuing, or if, in the opinion of such accounting firm, a Default has occurred and is continuing, a statement as to the nature thereof, (ii) a schedule in form satisfactory to the Administrative Agent of the computations used by such accountants in determining, as of the end of such Fiscal Year, compliance with the covenant contained in Section 6.04, PROVIDED that in the event of any change in GAAP used in the preparation of such financial statements, the Borrower shall also provide, if necessary for the determination of compliance with Section 6.04, a statement of reconciliation conforming such financial statements to GAAP, (iii) a certificate of the chief financial officer of the Borrower (or the individual performing such functions) stating that no Default has occurred and is continuing or, if a default has occurred and is continuing, a statement as to the nature thereof and the action that the Borrower has taken and proposes to take with respect thereto and (iv) a certificate of said officer specifically confirming compliance by the Borrower with Section 6.01(r). (d) ERISA EVENTS AND ERISA REPORTS. Promptly and in any event within 10 days after any Loan Party or any ERISA Affiliate knows or has reason to know that any ERISA Event has occurred, a statement of the chief financial officer of the Borrower describing such ERISA Event and the action, if any, that such Loan Party or such ERISA Affiliate has taken and proposes to take with respect thereto and (ii) on the date any records, documents or other information must be furnished to the PBGC with respect to any Plan pursuant to Section 4010 of ERISA, a copy of such records, documents and information. (e) PLAN TERMINATIONS. Promptly and in any event within ten Business Days after receipt thereof by any Loan Party or any ERISA Affiliate, copies of each notice from the PBGC stating its intention to terminate any Plan or to have a trustee appointed to administer any Plan. (f) ACTUARIAL REPORTS. Promptly upon receipt thereof by any Loan Party or any ERISA Affiliate, a copy of the annual actuarial valuation report for each Plan the funded current liability percentage (as defined in Section 302(d)(8) of ERISA) of which is less than 90% or the unfunded current liability of which exceeds $5,000,000. (g) PLAN ANNUAL REPORTS. Promptly and in any event within 30 days after the filing thereof with the Internal Revenue Service, copies of each Schedule B (Actuarial Information) to the annual report (Form 5500 Series) with respect to each Plan. 82 (h) MULTIEMPLOYER PLAN NOTICES. Promptly and in any event within five Business Days after receipt thereof by any Loan Party or any ERISA Affiliate from the sponsor of a Multiemployer Plan, copies of each notice concerning (i) the imposition of Withdrawal Liability by any such Multiemployer Plan, (ii) the reorganization or termination, within the meaning of Title IV of ERISA, of any such Multiemployer Plan or (iii) the amount of liability incurred, or that may be incurred, by such Loan Party or any ERISA Affiliate in connection with any event described in clause (i) or (ii). (i) LITIGATION. Promptly after the commencement thereof, notice of all actions, suits, investigations, litigation and proceedings before any court or governmental department, commission, board, bureau, agency or instrumentality, domestic or foreign, affecting the Borrower of the type described in Section 5.01(h), other than any actions, suits, investigations, litigation and proceedings that could not reasonably be expected to have a Material Adverse Effect. (j) SECURITIES REPORTS. Promptly after the sending or filing thereof, copies of all proxy statements, financial statements and reports that any Loan Party sends to its stockholders, and copies of all regular, periodic and special reports, and all registration statements, that any Loan Party files with the Securities and Exchange Commission or any Governmental Authority that may be substituted therefor, or with any national securities exchange. (k) AGREEMENT NOTICES. (i) Promptly upon receipt thereof, copies of all material notices, requests and other documents received by the Borrower under or pursuant to any Material Contract, Project Document, Acquisition Document or indenture, loan or credit or similar agreement and, from time to time upon request by the Administrative Agent, such information and reports regarding the Material Contracts, the Project Documents and the Acquisition Documents as the Administrative Agent may reasonably request. (ii) Within 30 days from the execution thereof, deliver to the Administrative Agent a certified copy of any modification or amendment to any of the Material Contracts, Project Documents or Acquisition Documents. (l) REVENUE AGENT REPORTS. Within 10 days after receipt, copies of all Revenue Agent Reports (Internal Revenue Service Form 886), or other written proposals of the Internal Revenue Service, that propose, determine or otherwise set forth positive and negative adjustments to the Federal income tax liability of the 83 affiliated group (within the meaning of Section 1504(a)(1) of the Internal Revenue Code) that apply to the Borrower, of which the Borrower is a member aggregating $1,000,000 or more. (m) TAX CERTIFICATES. Promptly, and in any event within five Business Days after the due date (with extensions) for filing the final Federal income tax return in respect of each taxable year, a certificate (a "TAX CERTIFICATE"), signed by the President or the chief financial officer of the Borrower, stating that (i) it has filed, or has had filed on its behalf, all tax returns required to be filed by it, (ii) it, and each other party to the Tax Sharing Agreement, has paid to the Internal Revenue Service or other taxing authority the full amount that it and each such other party is required to pay in respect of Federal income tax for such year and (iii) it has received any amounts payable to it, and has not paid amounts in respect of taxes (Federal, state, local or foreign) in excess of the amount it is required to pay, under any Tax Sharing Agreement in respect of such taxable year. (n) ENVIRONMENTAL CONDITIONS. Promptly after the assertion or occurrence thereof, notice of any Environmental Action against or of any noncompliance by any Loan Party with any Environmental Law or Environmental Permit that (i) could reasonably be expected to have a Material Adverse Effect or (ii) cause any property described in the Mortgages to be subject to any restrictions on ownership, occupancy, use or transferability under any Environmental Law, except to the extent that such restriction could not reasonably be expected to have a Material Adverse Effect. (o) YEAR 2000 COMPLIANCE. Promptly after discovery or determination thereof, notice (in reasonable detail) that any computer application (including those of its suppliers, vendors and customers) that is material to the business and operations of the Borrower will have a problem relating to the Year 2000 date change, except to the extent that such failure could not reasonably be expected to have a Material Adverse Effect. (p) OTHER INFORMATION. Such other information respecting the business, condition (financial or otherwise), operations, performance, properties or prospects of any Loan Party or any of its Subsidiaries as any Lender (through the Administrative Agent) may from time to time reasonably request. SECTION 6.04. FINANCIAL COVENANTS. So long as any Advance shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will maintain an Equity to Total Capitalization ratio of not less than 45%. 84 ARTICLE VII EVENTS OF DEFAULT SECTION 7.01. EVENTS OF DEFAULT. If any of the following events ("EVENTS OF Default") shall occur and be continuing: (a) (i) the Borrower shall fail to pay any principal of or any interest on any Advance when the same shall become due and payable (and, in the case of a non-payment of principal of the Tranche A Advance only, notice of such failure to pay shall have been issued by the Administrative Agent to the Borrower) or (ii) the Borrower or Northeast Utilities shall fail to make any other payment under any Loan Document or any Project Document in each case when the same becomes due and payable and such failure shall continue for 10 days; or (b) any representation or warranty made by any Loan Party (or any of its officers) under or in connection with any Loan Document, any Material Contract or any Project Document shall prove to have been incorrect in any material respect when made or deemed made; or (c) the Borrower shall fail to perform or observe any term, covenant or agreement contained in Section 2.13, 6.01(f), (l), (m), (o) or (p), 6.02, 6.03 or 6.04; or (d) any Loan Party shall fail to perform any other term, covenant or agreement contained in any Loan Document or any Material Contract or any Project Document on its part to be performed or observed if such failure shall remain unremedied for (i) 15 days with respect to the Loan Documents, the Select Power Purchase Agreement and the Northeast Utilities Guaranties, and (ii) 30 days with respect to any Material Contract or any Project Document (other than the Select Power Purchase Agreement and the Northeast Utilities Guaranties), each after the earlier of the date on which (A) a Responsible Officer of any Loan Party becomes aware of such failure or (B) written notice thereof shall have been given to the Borrower by the Administrative Agent or any Lender; or (e) the Borrower, Northeast Utilities or NU Enterprises shall fail to pay any principal of, premium or interest on or any other amount payable in respect of any Debt that is outstanding in a principal amount of at least $10,000,000 either individually or in the aggregate (but excluding Debt outstanding hereunder) of the Borrower, Northeast Utilities or NU Enterprises (as the case may be), when the same becomes due and payable (whether by scheduled maturity, required prepayment, 85 acceleration, demand or otherwise), and such failure shall continue after the applicable grace period, if any, specified in the agreement or instrument relating to such Debt; or any other event shall occur or condition shall exist under any agreement or instrument relating to any such Debt and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such event or condition is to accelerate, or to permit the acceleration of, the maturity of such Debt or otherwise to cause, or to permit the holder thereof to cause, such Debt to mature; or any such Debt shall be declared to be due and payable or required to be prepaid or redeemed (other than by a regularly scheduled required prepayment or redemption), purchased or defeased, or an offer to prepay, redeem, purchase or defease such Debt shall be required to be made, in each case prior to the stated maturity thereof; or (f) the Borrower, Northeast Utilities or NU Enterprises shall generally not pay its debts as such debts become due, shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or any proceeding shall be instituted by or against the Borrower or Northeast Utilities or NU Enterprises seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, or other similar official for it or for any substantial part of its property and, in the case of any such proceeding instituted against it (but not instituted by it) that is being diligently contested by it in good faith, either such proceeding shall remain undismissed or unstayed for a period of 30 days or any of the actions sought in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, custodian or other similar official for, it or any substantial part of its property) shall occur; or the Borrower, Northeast Utilities or NU Enterprises shall take any corporate action to authorize any of the actions set forth above in this subsection (f); or (g) any judgment or order for the payment of money in excess of $10,000,000 either individually or in the aggregate shall be rendered against the Borrower, Northeast Utilities or NU Enterprises and either (i) enforcement proceedings shall have been commenced by any creditor upon such judgment or order or (ii) there shall be any period of 10 consecutive 86 days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or (h) any non-monetary judgment or order shall be rendered against the Borrower, Northeast Utilities or NU Enterprises that could reasonably be expected to have a Material Adverse Effect on the Borrower, Northeast Utilities or NU Enterprises, as the case may be, and either (i) enforcement proceedings shall have been commenced by any creditor upon such judgment or order or (ii) there shall be any period of 10 consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or (i) any provision of any Loan Document, Material Contract or Project Document after delivery thereof pursuant to Section 3.01 or 6.01(n) shall for any reason cease to be valid and binding on or enforceable against any Loan Party which is party to it, or any such Loan Party shall so state in writing; or (j) any Collateral Document after delivery thereof pursuant to Section 3.01 or 6.01(n) shall for any reason (other than pursuant to the terms thereof) cease to create a valid and perfected first priority lien on and security interest in the Collateral purported to be covered thereby; or (k) any material provision of any of the Loan Documents or the Material Contracts or the Project Documents shall be canceled, terminated (other than as contemplated by its terms and the Loan Documents), declared by a competent court having jurisdiction to be null and void or shall otherwise cease to be valid and binding, or any material provision thereof shall be amended or modified in a manner that could reasonably be expected to have a Material Adverse Effect, or any party thereto shall deny any further liability or obligation thereunder; or (l) Northeast Utilities shall cease to own and control directly or indirectly 100% of the capital stock of each of the Borrower, NGS, Select and NU Enterprises, and 80% of the common stock of each of CL&P, WMECO and Public Service Company of New Hampshire, in each case free and clear of all Liens other than Liens in favor of the Secured Parties under the Collateral Documents; or (m) (i) any Person or two or more Persons acting in concert shall have acquired beneficial ownership (within the meaning of Rule 13d-3 of the Securities and Exchange Commission under the Securities Exchange Act of 1934), directly or indirectly, of Voting Stock of Northeast Utilities (or other securities convertible 87 into such Voting Stock) representing 15% or more of the combined voting power of all Voting Stock of Northeast Utilities, other than upon the consummation of the proposed acquisition by Consolidated Edison Inc. (directly or through one of its Subsidiaries) of 100% of the capital stock of Northeast Utilities or (ii) during any period of up to 24 consecutive months, commencing on June 17, 1999, individuals who at the beginning of such 24-month period were directors of Northeast Utilities shall cease for any reason to constitute a majority of the board of directors of Northeast Utilities, other than a change in the board of directors of Northeast Utilities in connection with the proposed acquisition directly or indirectly by Consolidated Edison Inc. of 100% of the capital stock of Northeast Utilities; or (iii) any Person or two or more Persons acting in concert shall have acquired by contract or otherwise, or shall have entered into a contract or arrangement that, upon consummation, will result in its or their acquisition of the power to exercise, directly or indirectly, a controlling influence over the management or policies of Northeast Utilities; or (n) any ERISA Event shall have occurred with respect to a Plan and the sum (determined as of the date of occurrence of such ERISA Event) of the Insufficiency of such Plan and the Insufficiency of any and all other Plans with respect to which an ERISA Event shall have occurred and then exist (or the liability of the Loan Parties and the ERISA Affiliates related to such ERISA Event) exceeds $10,000,000; or (o) any Loan Party or any ERISA Affiliate shall have been notified by the sponsor of a Multiemployer Plan that it has incurred Withdrawal Liability to such Multiemployer Plan in an amount that, when aggregated with all other amounts required to be paid to Multiemployer Plans by the Loan Parties and the ERISA Affiliates as Withdrawal Liability (determined as of the date of such notification), exceeds $10,000,000 or requires payments exceeding $2,500,000 per annum; or (p) any Loan Party or any ERISA Affiliate shall have been notified by the sponsor of a Multiemployer Plan that such Multiemployer Plan is in reorganization or is being terminated, within the meaning of Title IV of ERISA, and as a result of such reorganization or termination the aggregate annual contributions of the Loan Parties and the ERISA Affiliates to all Multiemployer Plans that are then in reorganization or being terminated have been or will be increased over the amounts contributed to such Multiemployer Plans for the plan years of such Multiemployer Plans immediately preceding the plan year in which such reorganization or termination occurs by an amount exceeding $10,000,000; or 88 (q) the Borrower shall cease to be an Exempt Wholesale Generator; then, and in any such event, the Administrative Agent (i) shall at the request, or may with the consent, of the Required Lenders, by notice to the Borrower, declare the obligation of each Lender to make Advances to be terminated, whereupon the same shall forthwith terminate, and (ii) shall at the request, or may with the consent, of the Required Lenders, by notice to the Borrower, declare the Notes, all interest thereon and all other amounts payable under this Agreement and the other Loan Documents to be forthwith due and payable, whereupon the Notes, all such interest and all such amounts shall become and be forthwith due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Borrower; PROVIDED, HOWEVER, that in the event of an actual or deemed entry of an order for relief with respect to the Borrower or NU Enterprises under the Federal Bankruptcy Code, (x) the obligation of each Lender to make Advances shall automatically be terminated and (y) the Notes, all such interest and all such amounts shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by the Borrower. ARTICLE VIII THE AGENTS SECTION 8.01. AUTHORIZATION AND ACTION. (a) Each Lender hereby appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers and discretion under this Agreement and the other Loan Documents as are delegated to the Administrative Agent by the terms hereof and thereof, together with such powers and discretion as are reasonably incidental thereto. As to any matters not expressly provided for by the Loan Documents (including, without limitation, enforcement or collection of the Notes), the Administrative Agent shall not be required to exercise any discretion or take any action, but shall be required to act or to refrain from acting (and shall be fully protected in so acting or refraining from acting) upon the instructions of the Required Lenders, and such instructions shall be binding upon all Lenders and all holders of Notes; PROVIDED, HOWEVER, that the Administrative Agent shall not be required to take any action that exposes the Administrative Agent to personal liability or that is contrary to this Agreement, any other Loan Document or applicable law. The Administrative Agent agrees to give to each Lender prompt notice of each notice given to it by the Borrower pursuant to the terms of this Agreement. 89 (b) Each Lender hereby appoints and authorizes the Collateral Agent to take such action as agent on its behalf and to exercise such powers and discretion under this Agreement and the other Loan Documents as are delegated to the Collateral Agent by the terms hereof and thereof, together with such powers and discretion as are reasonably incidental thereto. As to any matters not expressly provided for by the Loan Documents (including, without limitation, enforcement of any security interest or enforcement or collection of the Notes, giving of any consents, curing of any defaults, requesting any estoppel letters or the determination of any Material Adverse Effect), the Collateral Agent shall not be required to exercise any discretion or take any action, but shall be required to act or to refrain from acting (and shall be fully protected in so acting or refraining from acting) upon the instructions of the Required Lenders, and such instructions shall be binding upon all Lenders and all holders of Notes; PROVIDED, HOWEVER, that the Collateral Agent shall not be required to take any action that exposes the Collateral Agent to personal liability or that is contrary to this Agreement, any other Loan Document or applicable law. The Collateral Agent agrees to give to each Lender prompt notice of each notice given to it by the Borrower pursuant to the terms of this Agreement. The Collateral Agent is hereby directed to execute and deliver the Borrower Security Agreement, the Enterprises Pledge Agreement, the Mortgages and the Consents to Assignment. For purposes of the exculpatory and protective provisions of this Article VIII references to the Collateral Agent shall be deemed to include the Depositary Bank. SECTION 8.02. AGENT'S RELIANCE, ETC. (a) Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be liable for any action taken or omitted to be taken by it or them under or in connection with the Loan Documents, except for its or their own gross negligence or willful misconduct. Without limitation of the generality of the foregoing, the Administrative Agent: (i) may treat the payee of any Note as the holder thereof until the Administrative Agent receives and accepts an Assignment and Acceptance entered into by the Lender that is the payee of such Note, as assignor, and an Eligible Assignee, as assignee, as provided in Section 9.07; (ii) may consult with legal counsel (including counsel for any Loan Party), independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by it in accordance with the advice of such counsel, accountants or experts; (iii) makes no warranty or representation to any Lender and shall not be responsible to any Lender for any statements, warranties or representations (whether written or oral) made in or in connection with the Loan Documents; (iv) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of any Loan Document on the part of any Loan Party or to inspect the property (including the books and records) of any Loan Party; (v) shall not be responsible to any Lender for the due execution, legality, 90 validity, enforceability, genuineness, sufficiency or value of, or the perfection or priority of any lien or security interest created or purported to be created under or in connection with, any Loan Document or any other instrument or document furnished pursuant thereto; (vi) shall incur no liability under or in respect of any Loan Document by acting upon any notice, consent, certificate or other instrument or writing (which may be by telegram, telecopy or telex) believed by it to be genuine and signed or sent by the proper party or parties; and (vii) except with respect to Section 7.01(a), shall not be deemed to have notice of any Default or Event of Default unless and until it shall have received notice thereof from a Lender. The Administrative Agent may fully rely on an incumbency certificate from the Borrower and any other party as to the persons authorized to give directions or otherwise act on behalf of the Borrower or such other party, as the case may be. (b) Neither the Collateral Agent nor any of its directors, officers, agents or employees shall be liable for any action taken or omitted to be taken by it or them under or in connection with the Loan Documents, except for its or their own gross negligence or willful misconduct. Without limitation of the generality of the foregoing, the Collateral Agent: (i) may treat the payee of any Note as the holder thereof until the Collateral Agent receives and accepts an Assignment and Acceptance entered into by the Lender that is the payee of such Note, as assignor, and an Eligible Assignee, as assignee, as provided in Section 9.07; (ii) may consult with legal counsel (including counsel for any Loan Party), independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by it in accordance with the advice of such counsel, accountants or experts; (iii) makes no warranty or representation to any Lender and shall not be responsible to any Lender for any statements, warranties or representations (whether written or oral) made in or in connection with the Loan Documents; (iv) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of any Loan Document on the part of any Loan Party or to inspect the property (including the books and records) of any Loan Party; (v) shall not be responsible to any Lender for the due execution, legality, validity, enforceability, genuineness, sufficiency or value of, or the perfection or priority of any lien or security interest created or purported to be created under or in connection with, any Loan Document or any other instrument or document furnished pursuant thereto; (vi) shall incur no liability under or in respect of any Loan Document by acting upon any notice, consent, certificate or other instrument or writing (which may be by telegram, telecopy or telex) believed by it to be genuine and signed or sent by the proper party or parties, and (vii) shall not be deemed to have notice of any Default or Event of Default unless and until it shall have received notice thereof from a Lender. The Collateral Agent may fully rely on an incumbency 91 certificate from the Borrower and any other party as to the persons authorized to give directions or otherwise act on behalf of the Borrower or such other party, as the case may be. SECTION 8.03. CITIBANK AND AFFILIATES. With respect to its Commitments, the Advances made by it and the Notes issued to it, Citibank shall have the same rights and powers under the Loan Documents as any other Lender and may exercise the same as though it were not the Administrative Agent or the Collateral Agent; and the term "Lender" shall, unless otherwise expressly indicated, include Citibank in its individual capacity. Citibank and its affiliates may accept deposits from, lend money to, act as trustee under indentures of, accept investment banking engagements from and generally engage in any kind of business with, any Loan Party, any of such Loan Party=s Subsidiaries and any Person who may do business with or own securities of any Loan Party or any such Subsidiary, all as if Citibank were not the Administrative Agent or the Collateral Agent and without any duty to account therefor to the Lenders. SECTION 8.04. LENDER CREDIT DECISION. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, the Collateral Agent or any other Lender and based on the financial statements referred to in Section 5.01 and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, the Collateral Agent or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement. SECTION 8.05. INDEMNIFICATION. Each Lender severally agrees to indemnify the Administrative Agent and the Collateral Agent (in each case to the extent not promptly reimbursed by the Borrower) from and against such Lender's ratable share (determined as provided below) of any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on, incurred by, or asserted against the Administrative Agent or the Collateral Agent in any way relating to or arising out of the Loan Documents or any action taken or omitted by the Administrative Agent, the Collateral Agent or the Depositary Bank under the Loan Documents; PROVIDED, HOWEVER, that no Lender shall be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Administrative Agent's or the Collateral Agent's gross negligence or willful misconduct. Without limitation of the foregoing, 92 each Lender agrees to reimburse the Administrative Agent and the Collateral Agent, as the case may be, promptly upon demand for its ratable share of any costs and expenses (including, without limitation, fees and expenses of counsel) payable by the Borrower under Section 9.04, to the extent that the Administrative Agent or the Collateral Agent is not promptly reimbursed for such costs and expenses by the Borrower. For purposes of this Section 8.05, the Lenders' respective ratable shares of any amount shall be determined, at any time, according to the sum of (a) the aggregate principal amount of the Advances outstanding at such time and owing to the respective Lenders, and (b) the aggregate unused portions of their respective Commitments at such time. In the event that any Defaulted Advance shall be owing by any Defaulting Lender at any time, such Lender's Commitment with respect to the Defaulted Advance shall be considered to be unused for purposes of this Section 8.05 to the extent of the amount of such Defaulted Advance. The failure of any Lender to reimburse the Administrative Agent or the Collateral Agent, as the case may be, promptly upon demand for its ratable share of any amount required to be paid by the Lender to the Administrative Agent or the Collateral Agent, as the case may be, as provided herein shall not relieve any other Lender of its obligation hereunder to reimburse the Administrative Agent or the Collateral Agent, as the case may be, for its ratable share of such amount, but no Lender shall be responsible for the failure of any other Lender to reimburse the Administrative Agent or the Collateral Agent, as the case may be, for such other Lender's ratable share of such amount. Without prejudice to the survival of any other agreement of any Lender hereunder, the agreement and obligations of each Lender contained in this Section 8.05 shall survive the payment in full of principal, interest and all other amounts payable hereunder and under the other Loan Documents. SECTION 8.06. SUCCESSOR AGENTS. (a) The Administrative Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower and may be removed at any time with or without cause by the Required Lenders. Upon any such resignation or removal, the Required Lenders shall have the right to appoint a successor Administrative Agent. If no successor Administrative Agent shall have been so appointed by the Required Lenders, and shall have accepted such appointment, within 30 days after the retiring Administrative Agent's giving of notice of resignation or the Required Lenders' removal of the retiring Administrative Agent, then the retiring Administrative Agent may, on behalf of the Lenders, appoint a successor Administrative Agent, which shall be a commercial bank organized under the laws of the United States or of any State thereof and having a combined capital and surplus of at least $1,000,000,000. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor Administrative Agent such successor Administrative Agent shall succeed to and become vested with all the rights, powers, discretion, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations under 93 the Loan Documents. After any retiring Administrative Agent's resignation or removal hereunder as Administrative Agent, the provisions of this Article VII shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent under this Agreement. (b) The Collateral Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower and may be removed at any time with or without cause by the Required Lenders. Upon any such resignation or removal, the Required Lenders shall have the right to appoint a successor Collateral Agent. If no successor Collateral Agent shall have been so appointed by the Required Lenders, and shall have accepted such appointment, within 30 days after the retiring Collateral Agent's giving of notice of resignation or the Required Lenders' removal of the retiring Collateral Agent, then the retiring Collateral Agent may, on behalf of the Lenders, appoint a successor Collateral Agent, which shall be a commercial bank organized under the laws of the United States or of any State thereof and having a combined capital and surplus of at least $1,000,000,000. Upon the acceptance of any appointment as Collateral Agent hereunder by a successor Collateral Agent such successor Collateral Agent shall succeed to and become vested with all the rights, powers, discretion, privileges and duties of the retiring Collateral Agent, and the retiring Collateral Agent shall be discharged from its duties and obligations under the Loan Documents. After any retiring Collateral Agent's resignation or removal hereunder as Collateral Agent, the provisions of this Article VIII shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Collateral Agent under this Agreement. SECTION 8.07. INTERCREDITOR ARRANGEMENTS. (a) The Tranche A Secured Parties and the Tranche B Secured Parties agree that the Collateral shall be held by the Collateral Agent, in its capacity as such, on behalf of the Secured Parties. The Lien of the Tranche A Mortgage, the Liens created under the Tranche A Borrower Security Agreement, the Liens created under the Tranche A Enterprises Pledge Agreement) and all liens and security interests created or evidenced thereby (collectively, the "TRANCHE A LIEN") are hereby made and shall continue to be junior, subject, and subordinate in all respects to, respectively, the Lien of the Tranche B Mortgage, the Liens created under the Tranche B Borrower Security Agreement, the Liens created under the Tranche B Enterprises Pledge Agreement and all Liens and security interests created or evidenced thereby (collectively, the "TRANCHE B LIEN") including, without limitation, after the occurrence and during the continuance of a Default or an Event of Default. So long as any Tranche B Obligations remain outstanding, the Tranche B Secured Parties shall have the right to vote and instruct the Collateral Agent to act with respect to the Collateral secured by the Tranche B Lien and the Tranche A Lien. Once the Tranche B Obligations have been repaid in full in cash, 94 the Tranche A Secured Parties shall have the right to so vote and instruct. Any proceeds received as a result of any sale, lease, transfer or other disposition in respect of the Collateral first shall be applied to repay the Tranche B Obligations in full in cash, and thereafter, shall be applied to repay any outstanding Tranche A Obligations. Each Tranche A Secured Party agrees not to enforce or exercise any right or remedy in respect of the Collateral, or take or receive from the Borrower or the Collateral Agent, directly or indirectly, in cash or other property or by set-off or in any other manner, whether pursuant to any judicial or non-judicial enforcement, collection, execution, levy or foreclosure proceedings or otherwise, including by deed in lieu of foreclosure, any Collateral or any part or proceeds thereof or interest therein, in each case unless and until all Tranche B Obligations have been paid in full in cash. (b) The provisions of Section 8.07(a) shall apply, notwithstanding the availability of other Collateral to the Agents or Lenders or the actual date and time of execution, delivery, recordation, filing or perfection of the Loan Documents, or the Liens created thereby, and notwithstanding the fact that the Tranche B Obligations are or any claim for the Tranche B Obligations is subordinated, avoided, disallowed or otherwise deemed unenforceable, in whole or in part, under the Federal Bankruptcy Code or other applicable federal, state or local law. In the event of a proceeding, whether voluntary or involuntary, for insolvency, liquidation, reorganization, dissolution, bankruptcy or other similar proceeding pursuant to the Federal Bankruptcy Code or other applicable federal or state law, the amounts due under the Tranche B Obligations shall be deemed to include all interest and breakage costs accrued on the Tranche B Obligations, in accordance with and at the rates specified in the Loan Documents, both for periods before and for periods after the commencement of any such proceedings, even if the claim for such interest is not allowed pursuant to applicable law. SECTION 8.08. CO-ARRANGERS. The Co-Arrangers, in their capacity as Co-Arrangers, assume no responsibility or obligation hereunder for servicing, syndication, enforcement or collection of the Debt resulting from the Advances, nor any duties as agent hereunder for the Lenders. The title of "Co-Arranger" is solely honorific and implies no fiduciary responsibility on the part of any Co-Arranger, in its capacity as such, to the Agents or any Lender and the use of such title does not impose on any Co-Arranger any duties or obligations greater than those of any other Lender or entitle any Co-Arranger to any rights other than those to which any other Lender is entitled. 95 ARTICLE IX MISCELLANEOUS SECTION 9.01. AMENDMENTS, ETC. No amendment or waiver of any provision of this Agreement, the Notes or any other Loan Document, nor consent to any departure by the Borrower or any other Loan Party therefrom, shall in any event be effective unless the same shall be in writing and signed (or, in the case of the Collateral Documents, consented to) by (x) with respect to this Agreement, the Sponsor Agreement the Select Power Purchase Agreement and the NU Guaranties, the Required Lenders, (y) with respect to the Tranche A Collateral Documents, the Tranche A Required Lenders, and (z) with respect to the Tranche B Collateral Documents, the Tranche B Required Lenders, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; PROVIDED, HOWEVER, that (a) no amendment, waiver or consent shall, unless in writing and signed by all of the Lenders, do any of the following at any time: (i) waive any of the conditions specified in Section 3.01 or 3.02, (ii) change the number of Lenders or the percentage of (x) the Commitments, or (y) the aggregate unpaid principal amount of the Advances, in each case, required for the Lenders or any of them to take any action hereunder, (iii) limit Northeast Utilities' liability with respect to its Obligations under the Sponsor Agreement or the NU Guaranties or NU Enterprises' liability under the Enterprises Pledge Agreement, (iv) release any material portion of the Collateral in any transaction or series of related transactions or permit the creation, incurrence, assumption or existence of any Lien on any item of Collateral in any transaction or series of related transactions to secure any Obligations other than Obligations owing to the Secured Parties under the Loan Documents, (v) amend this Section 9.01, (vi) increase the Tranche A Commitments of the Tranche A Lenders or the Tranche B Commitments of the Tranche B Lenders, or increase the aggregate Commitments of the Lenders or subject the Lenders to any additional Obligations, (vii) reduce the principal of, or interest on, the Notes or any fees or other amounts payable hereunder, (viii) postpone any date fixed for any payment of principal of, or interest on, the Notes or any fees or other amounts payable hereunder, (ix) reduce the Commitments, (x) limit the liability of any Loan Party under any of the Loan Documents, (xi) modify the second priority status of the Tranche A Collateral Documents or the intercreditor arrangements set forth in Section 9.07 or (xi) modify or extend the payment terms of the Select Power Purchase Agreement; and PROVIDED FURTHER that no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent in addition to the Lenders required above to take such action, affect the rights or duties of the Administrative Agent under this Agreement and that no amendment, waiver or consent shall, unless in writing and signed by the Collateral Agent in addition to the Lenders required above to take such action, affect the rights or duties of the Collateral Agent under this Agreement and that no amendment, waiver or consent shall, unless in writing and 96 signed by the Depositary Bank in addition to the Lenders required above to take such action, affect the rights or duties of the Depositary Bank under this Agreement. SECTION 9.02. NOTICES, ETC. All notices and other communications provided for hereunder shall be in writing (including telegraphic, telecopy or telex communication) and mailed, telegraphed, telecopied, telexed or delivered, if to the Borrower, at its address at 107 Seldon Street, Berlin Ct. 06037, Attention: Treasurer, and with respect to all communications under Article 4 hereof, with copies to (i) Supervisor, Cash Management, and (ii) Emily Campanelli, Corporate Accounting, in both cases at the same address; if to any Initial Lender, at its Domestic Lending Office specified opposite its name on Schedule I hereto; if to any other Lender, at its Domestic Lending Office specified in the Assignment and Acceptance pursuant to which it became a Lender; if to the Administrative Agent, at its address at 399 Park Avenue, New York, New York 10043, Attention: Santiago Pardo with a copy to 2 Penns Way, Newcastle, Delaware 19720, Attention: Bilal Aman; and if to the Collateral Agent and the Depositary Bank, at its address at 111 Wall Street, New York, New York 10043, Attention: Florence Mills; or, as to each party, at such other address as shall be designated by such party in a written notice to the other parties. All such notices and communications shall, when mailed, telegraphed, telecopied or telexed, be effective when deposited in the mails, delivered to the telegraph company, transmitted by telecopier or confirmed by telex answerback, respectively, except that notices and communications to the Administrative Agent pursuant to Article II, III or VII shall not be effective until received by the Administrative Agent. Delivery by telecopier of an executed counterpart of any amendment or waiver of any provision of this Agreement or the Notes or of any Exhibit hereto to be executed and delivered hereunder shall be effective as delivery of a manually executed counterpart thereof. SECTION 9.03. NO WAIVER; REMEDIES. No failure on the part of any Lender, the Administrative Agent, the Collateral Agent or the Depositary Bank to exercise, and no delay in exercising, any right hereunder, under any Note or under any other Loan Document shall operate as a waiver thereof; nor shall any single or partial exercise of any such right preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law. SECTION 9.04. COSTS, EXPENSES, INDEMNIFICATION. (a) The Borrower agrees to pay on demand (i) all reasonable costs and expenses of the Administrative Agent, the Collateral Agent and the Depositary Bank in connection with the preparation, execution, delivery, modification and amendment of the Loan Documents (including, without limitation, (A) all due diligence, collateral review, 97 transportation, computer, duplication, appraisal, audit, insurance, consultant, search, filing and recording fees and expenses and (B) the reasonable fees and expenses of counsel for the Administrative Agent, the Collateral Agent and the Depositary Bank with respect thereto, with respect to advising each of the Administrative Agent, the Collateral Agent or the Depositary Bank, as the case may be, as to its rights and responsibilities, or the perfection, protection or preservation of rights or interests, under the Loan Documents, with respect to negotiations with any Loan Party or with other creditors of any Loan Party, arising out of any Default and with respect to presenting claims in or otherwise participating in or monitoring any bankruptcy, insolvency or other similar proceeding involving creditors' rights generally and any proceeding ancillary thereto) and (ii) all reasonable costs and expenses of the Administrative Agent, the Collateral Agent, the Depositary Bank and the Lenders in connection with the enforcement of the Loan Documents, whether in any action, suit or litigation, any bankruptcy, insolvency or other similar proceeding affecting creditors' rights generally (including, without limitation, the reasonable fees and expenses of counsel for the Administrative Agent, the Collateral Agent, the Depositary Bank and each Lender with respect thereto). (b) The Borrower agrees to indemnify and hold harmless the Administrative Agent, the Collateral Agent, the Depositary Bank, each Lender and each of their Affiliates and their officers, directors, employees, agents and advisors (each, an "INDEMNIFIED PARTY") from and against any and all claims, damages, losses, liabilities and expenses (including, without limitation, reasonable fees and expenses of counsel) that may be incurred by or asserted or awarded against any Indemnified Party, in each case arising out of or in connection with or by reason of (including, without limitation, in connection with any investigation, litigation or proceeding or preparation of a defense in connection therewith) (i) the Notes, this Agreement, the other Loan Documents or any of the transactions contemplated hereby or thereby or (ii) the actual or alleged presence of Hazardous Materials on any property described in the Mortgages or any Environmental Action relating in any way to any Loan Party or any of its Subsidiaries, except to the extent such claim, damage, loss, liability or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted directly or indirectly from such Indemnified Party's gross negligence or willful misconduct. In the case of an investigation, litigation or other proceeding to which the indemnity in this Section 9.04(b) applies, such indemnity shall be effective whether or not such investigation, litigation or proceeding is brought by any Loan Party, its directors, shareholders or creditors or an Indemnified Party or any Indemnified Party is otherwise a party thereto and whether or not the transactions contemplated hereby are consummated. The Borrower also agrees not to assert any claim against the Administrative Agent, the Collateral Agent, the Depositary Bank, any Lender 98 or any of their Affiliates, or any of their respective officers, directors, employees, attorneys and agents, on any theory of liability, for special, indirect, consequential or punitive damages arising out of or otherwise relating to this Agreement, the actual or proposed use of the proceeds of the Advances, the other Loan Documents or any of the transactions contemplated hereby or thereby. (c) If any payment of principal of, or Conversion of, any Eurodollar Rate Advance is made by the Borrower to or for the account of a Lender other than on the last day of the Interest Period for such Advance, as a result of a payment or Conversion pursuant to Section 2.05, 2.08(b)(i) or 2.09(d), acceleration of the maturity of the Notes pursuant to Section 9.01 or for any other reason, the Borrower shall, upon demand by such Lender (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that it may reasonably incur as a result of such payment, including, without limitation, any loss (including loss of anticipated profits), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by any Lender to fund or maintain such Advance. (d) If any Loan Party fails to pay when due any costs, expenses or other amounts payable by it under any Loan Document, including, without limitation, fees and expenses of counsel and indemnities, such amount may be paid on behalf of such Loan Party by the Administrative Agent, the Collateral Agent, the Depositary Bank or any Lender, in its sole discretion; PROVIDED, HOWEVER, that such Loan Party's Obligations to pay such amounts remain unchanged and such payment by any such Lender, the Collateral Agent, the Depositary Bank or the Administrative Agent in no way excuses such Loan Party from such Obligations. (e) Without prejudice to the survival of any other agreement of any Loan Party hereunder or under any other Loan Document, the agreements and obligations of the Borrower contained in Sections 2.09, 2.11 and 9.05 and this Section 9.04 shall survive the payment in full of principal, interest and all other amounts payable hereunder and under any of the other Loan Documents. SECTION 9.05. RIGHT OF SET-OFF. Upon (a) the occurrence and during the continuance of any Event of Default and (b) the making of the request or the granting of the consent specified by Section 7.01 to authorize the Administrative Agent to declare the Notes due and payable pursuant to the provisions of Section 7.01, each Lender and each of its respective Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and otherwise apply any and all deposits (general or special, time or demand, provisional or 99 final) at any time held and other indebtedness at any time owing by such Lender or such Affiliate to or for the credit or the account of the Borrower against any and all of the Obligations of the Borrower now or hereafter existing under this Agreement and the Note or Notes (if any) held by such Lender, irrespective of whether such Lender shall have made any demand under this Agreement or such Note or Notes and although such obligations may be unmatured. Each Lender agrees promptly to notify the Borrower after any such set-off and application; PROVIDED, HOWEVER, that the failure to give such notice shall not affect the validity of such set-off and application. The rights of each Lender and its respective Affiliates under this Section are in addition to other rights and remedies (including, without limitation, other rights of set-off) that such Lender and its respective Affiliates may have. SECTION 9.06. BINDING EFFECT. This Agreement shall become effective when it shall have been executed by the Borrower, the Administrative Agent, the Collateral Agent and the Depositary Bank and when the Administrative Agent shall have been notified by each Initial Lender that such Initial Lender has executed it and thereafter shall be binding upon and inure to the benefit of the Borrower, the Administrative Agent, the Collateral Agent, the Depositary Bank and each Lender and their respective successors and assigns, except that the Borrower shall not have the right to assign its rights hereunder or any interest herein without the prior written consent of the Lenders. SECTION 9.07. ASSIGNMENTS AND PARTICIPATIONS. (a) Each Lender may assign to one or more Eligible Assignees all or a portion of its rights and obligations under this Agreement (including, without limitation, all or a portion of its Commitment or Commitments, the Advances owing to it and the Note or Notes held by it); PROVIDED, HOWEVER, that (i) each such assignment shall be of a uniform, and not a varying, percentage of all rights and obligations under and in respect of the Tranche A Commitment or the Tranche B Commitment, as the case may be, (ii) except in the case of an assignment to a Person that, immediately prior to such assignment, was a Lender or all of a Lender's rights and obligations under this Agreement, the aggregate amount of the Tranche A Commitment and outstanding Tranche A Advances or Tranche B Commitment and outstanding Tranche B Advances of the assigning Lender being assigned pursuant to each such assignment (determined as of the date of the Assignment and Acceptance with respect to such assignment) shall in no event be less than $10,000,000 with respect to such Tranche A Commitment and $10,000,000 with respect to such Tranche B Commitment, (iii) each such assignment shall be to an Eligible Assignee, and (iv) the parties to each such assignment shall execute and deliver to the Administrative Agent, for its acceptance and recording in the Register, an Assignment and Acceptance, together with any Note or Notes subject to such assignment and a processing and recordation fee of $4,000 payable by the Eligible Assignee. 100 (b) Upon such execution, delivery, acceptance and recording, from and after the effective date specified in such Assignment and Acceptance, (i) the assignee thereunder shall be a party hereto and, to the extent that rights and obligations hereunder have been assigned to it pursuant to such Assignment and Acceptance, have the rights and obligations of a Lender hereunder and (ii) the Lender assignor thereunder shall, to the extent that rights and obligations hereunder have been assigned by it pursuant to such Assignment and Acceptance, relinquish its rights, except such rights as survive termination of this Agreement, and be released from its obligations under this Agreement (and, in the case of an Assignment and Acceptance covering all or the remaining portion of an assigning Lender's rights and obligations under this Agreement, such Lender shall cease to be a party hereto). (c) By executing and delivering an Assignment and Acceptance, the Lender assignor thereunder and the assignee thereunder confirm to and agree with each other and the other parties hereto as follows: (i) other than as provided in such Assignment and Acceptance, such assigning Lender makes no representation or warranty and assumes no responsibility with respect to any statements, warranties or representations made in or in connection with this Agreement or any other Loan Document or the execution, legality, validity, enforceability, genuineness, sufficiency or value of, or the perfection or priority of any lien or security interest created or purported to be created under or in connection with, this Agreement or any other Loan Document or any other instrument or document furnished pursuant hereto or thereto; (ii) such assigning Lender makes no representation or warranty and assumes no responsibility with respect to the financial condition of the Borrower or any other Loan Party or the performance or observance by any Loan Party of any of its obligations under any Loan Document or any other instrument or document furnished pursuant thereto; (iii) such assignee confirms that it has received a copy of this Agreement, together with copies of the financial statements referred to in Section 5.01 and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into such Assignment and Acceptance; (iv) such assignee will, independently and without reliance upon the Administrative Agent, the Collateral Agent, such assigning Lender or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement; (v) such assignee confirms that it is an Eligible Assignee; (vi) such assignee appoints and authorizes the Administrative Agent and the Collateral Agent, as the case may be, to take such action as agent on its behalf and to exercise such powers and discretion under the Loan Documents as are delegated to the Administrative 101 Agent and the Collateral Agent, as the case may be, by the terms hereof, together with such powers and discretion as are reasonably incidental thereto; and (vii) such assignee agrees that it will perform in accordance with their terms all of the obligations which by the terms of this Agreement are required to be performed by it as a Lender. (d) The Administrative Agent shall maintain at its address referred to in Section 9.02 a copy of each Assignment and Acceptance delivered to and accepted by it and a register for the recordation of the names and addresses of the Lenders and the Commitment of, and principal amount of the Advances owing to, each Lender from time to time (the "REGISTER"). The entries in the Register shall be conclusive and binding for all purposes, absent manifest error, and the Borrower, the Administrative Agent, the Collateral Agent and the Lenders may treat each Person whose name is recorded in the Register as a Lender hereunder for all purposes of this Agreement. The Register shall be available for inspection by the Collateral Agent, the Borrower or any Lender at any reasonable time and from time to time upon reasonable prior notice. (e) Upon its receipt of an Assignment and Acceptance executed by an assigning Lender and an assignee, together with any Note or Notes subject to such assignment, the Administrative Agent shall, if such Assignment and Acceptance has been completed and is in substantially the form of Exhibit C hereto, (i) accept such Assignment and Acceptance, (ii) record the information contained therein in the Register and (iii) give prompt notice thereof to the Borrower. In the case of any assignment by a Lender, within five Business Days after its receipt of such notice, the Borrower, at its own expense, shall execute and deliver to the Administrative Agent in exchange for the surrendered Note or Notes a new Note or Notes to the order of such Eligible Assignee in an amount equal to the Commitment assumed by it pursuant to such Assignment and Acceptance and, if the assigning Lender has retained a Commitment hereunder, a new Note or Notes to the order of the assigning Lender in an amount equal to the Commitment retained by it hereunder. Such new Tranche A Note or Tranche A Notes shall be in an aggregate principal amount equal to the aggregate principal amount of such surrendered Tranche A Note or Tranche A Notes, shall be dated the effective date of such Assignment and Acceptance and shall otherwise be in substantially the form of Exhibit A-1 hereto. Such new Tranche B Note or Tranche B Notes shall be in an aggregate principal amount equal to the aggregate principal amount of such surrendered Tranche B Note or Tranche B Notes, shall be dated the effective date of such Assignment and Acceptance and shall otherwise be in substantially the form of Exhibit A-2 hereto. (f) Each Lender may sell participations to one or more Persons (other than any Loan Party or any of its Affiliates) in or to all or a portion of its rights and obligations under this Agreement (including, without limitation, all or a portion of its Commitments, the Advances owing to it and the Note or Notes (if any) held by 102 it); PROVIDED, HOWEVER, that (i) such Lender's obligations under this Agreement (including, without limitation, its Commitments) shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, (iii) such Lender shall remain the holder of any such Note for all purposes of this Agreement, (iv) the Borrower, the Administrative Agent, the Collateral Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under this Agreement and (v) no participant under any such participation shall have any right to approve any amendment or waiver of any provision of any Loan Document, or any consent to any departure by any Loan Party therefrom, except to the extent that such amendment, waiver or consent would reduce the principal of, or interest on, the Notes or any fees or other amounts payable hereunder, in each case to the extent subject to such participation, postpone any date fixed for any payment of principal of, or interest on, the Notes or any fees or other amounts payable hereunder, in each case to the extent subject to such participation, or release all or substantially all of the Collateral. (g) Any Lender may, in connection with any assignment or participation or proposed assignment or participation pursuant to this Section 9.07, disclose to the assignee or participant or proposed assignee or participant, any information relating to the Borrower or any other Loan Party furnished to such Lender by or on behalf of the Borrower; PROVIDED, HOWEVER, that, prior to any such disclosure, the assignee or participant or proposed assignee or participant shall agree to preserve the confidentiality of any Confidential Information received by it from such Lender. (h) Notwithstanding any other provision set forth in this Agreement, any Lender may at any time create a security interest in all or any portion of its rights under this Agreement (including, without limitation, the Advances owing to it and the Note or Notes held by it) in favor of any Federal Reserve Bank in accordance with Regulation A of the Board of Governors of the Federal Reserve System. SECTION 9.08. EXECUTION IN COUNTERPARTS. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by telecopier shall be effective as delivery of a manually executed counterpart of this Agreement. SECTION 9.09. CONFIDENTIALITY. Neither the Administrative Agent, the Collateral Agent, the Depositary Bank, any Lender nor any agents or representatives thereof 103 (each, a "DISCLOSING PARTY") shall disclose any Confidential Information to any Person without the consent of the Borrower, other than (a) to the Administrative Agent's, the Collateral Agent's or such Lender's Affiliates and their officers, directors, employees, agents and advisors and to actual or prospective Eligible Assignees and participants, and then only on a confidential basis, (b) as required by any law, rule or regulation or judicial process, (c) as requested or required by any state, federal or foreign authority or examiner regulating banks or banking or (d) if advised by counsel of such Disclosing Party that such disclosure is legally required. SECTION 9.10. JURISDICTION, ETC. (a) Each of the parties hereto hereby irrevocably and unconditionally submits, for itself and its property, to the nonexclusive jurisdiction of any New York State court or federal court of the United States of America sitting in New York City, and any appellate court from any thereof, in any action or proceeding arising out of or relating to this Agreement or any of the other Loan Documents to which it is a party, or for recognition or enforcement of any judgment, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in any such New York State court or, to the extent permitted by law, in such federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement shall affect any right that any party may otherwise have to bring any action or proceeding relating to this Agreement or any of the other Loan Documents in the courts of any jurisdiction. (b) Each of the parties hereto irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection that it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or any of the other Loan Documents to which it is a party in any New York State or federal court. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court. SECTION 9.11. GOVERNING LAW. This Agreement and the Notes shall be governed by, and construed in accordance with, the laws of the State of New York. SECTION 9.12. WAIVER OF JURY TRIAL. Each of the Borrower, the Administrative Agent, the Collateral Agent, the Depositary Bank and the Lenders irrevocably waives all right to trial by jury in any action, proceeding or counterclaim (whether based on contract, tort or otherwise) arising out of or relating to any of the Loan Documents, the 104 Advances or the actions of the Administrative Agent, the Collateral Agent, the Depositary Bank or any Lender in the negotiation, administration, performance or enforcement thereof. 105 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written. BORROWER: --------- NORTHEAST GENERATION COMPANY By ------------------------------ Name: Title: AGENTS: ------- CITIBANK, N.A., as Administrative Agent By ------------------------------ Name: Title: CITIBANK, N.A., as Collateral Agent and as Depositary Bank By ------------------------------ Name: Title: 106 TRANCHE A INITIAL LENDERS: -------------------------- CITIBANK, N.A. By ------------------------------ Name: Title: BARCLAYS BANK PLC By ------------------------------ Name: Title: CANADIAN IMPERIAL BANK OF COMMERCE By ------------------------------ Name: Title: TORONTO DOMINION (TEXAS), INC. By ------------------------------ Name: Title: 107 TRANCHE B INITIAL LENDERS: -------------------------- CITIBANK, N.A. By ------------------------------- Name: Title: BARCLAYS BANK PLC By ------------------------------- Name: Title: CANADIAN IMPERIAL BANK OF COMMERCE By ------------------------------- Name: Title: TORONTO DOMINION (TEXAS), INC. By ------------------------------- Name: Title: MEESPIERSON CAPITAL CORP. By ------------------------------- Name: Title: UNION BANK OF CALIFORNIA, N.A. By ------------------------------- Name: Title: 108 SCHEDULE I COMMITMENTS AND APPLICABLE LENDING OFFICES Name of Initial Lender Citibank, N.A. Tranche A Commitment US$108,875,000.00 Tranche B Commitment US$71,666,666.67 Domestic Lending Office Citibank, N.A. 399 Park Avenue New York, NY 10043 Eurodollar Lending Office Citibank, N.A. 399 Park Avenue New York, NY 10043 Business / Credit Matters: Citibank, N.A. 399 Park Avenue New York, NY 10043 Attn: Santiago Pardo Tel: (212) 559-3623 Fax: (212) 793-0092 email: santiago.pardo@citicorp.com Administrative / Operations Matters: Citibank, N.A. 2 Penns Way Newcastle, Delaware 19720 Attn: Bilal Aman Tel: (302) 894-6013 Fax: (302) 894-6120 email: bilal.aman@citicorp.com Name of Initial Lender Barclays Bank plc Tranche A Commitment US$108,875,000.00 Tranche B Commitment US$71,666,666.67 Domestic Lending Office Barclays Bank PLC 222 Broadway, 11th Floor New York, NY 10038 Attn: Christine Francese Tel: (212) 412-3721 Fax: (212) 412-5306 email: christine.francese@barclayscapital.com Eurodollar Lending Office Barclays Bank PLC 222 Broadway, 11th Floor New York, NY 10038 Attn: Christine Francese Tel: (212) 412-3721 Fax: (212) 412-5306 email: christine.francese@barclayscapital.com Business / Credit Matters: Barclays Bank PLC 222 Broadway, 8th Floor New York, NY 10038 Attn: John Drake Tel: (212) 412-1381 Fax: (212) 412-6709 email: john.drake@barclayscapital.com Administrative / Operations Matters: Barclays Bank PLC 222 Broadway, 11th Floor New York, NY 10038 Attn: Christine Francese Tel: (212) 412-3721 Fax: (212) 412-5306 email: christine.francese@barclayscapital.com with a copy to: Barclays Bank PLC 222 Broadway, 8th Floor New York, NY 10038 Attn: Sydney Dennis Tel: (212) 412-2470 Fax: (212) 412-6709 email: sydney.dennis@barclayscapital.com Name of Initial Lender Canadian Imperial Bank of Commerce Tranche A Commitment US$108,875,000.00 Tranche B Commitment US$71,666,666.67 Domestic Lending Office Canadian Imperial Bank of Commerce Two Paces West 2727 Paces Ferry Road, Suite 1200 Atlanta, GA 30339 Attn: Miriam McCart Tel: (770) 319-4842 Fax: (770) 319-4950 email: mccamiri@us.cibc.com Eurodollar Lending Office Canadian Imperial Bank of Commerce Two Paces West 2727 Paces Ferry Road, Suite 1200 Atlanta, GA 30339 Attn: Miriam McCart Tel: (770) 319-4842 Fax: (770) 319-4950 email: mccamiri@us.cibc.com Business / Credit Matters: CIBC World Markets 425 Lexington Avenue New York, NY 10017 Attn: Eric Klaussmann Tel: (212) 856-3828 Fax: (212) 885-4911 email: klaussma@us.cibc.com with a copy to: CIBC World Markets C/O Utilities Department 425 Lexington Avenue New York, NY 10017 Attn: Jo Manger Tel: (212) 856-3818 Fax: (212) 856-3799 Administrative / Operations Matters: Canadian Imperial Bank of Commerce Two Paces West 2727 Paces Ferry Road, Suite 1200 Atlanta, GA 30339 Attn: Beverly Bowman Tel: (770) 319-4824 Fax: (770) 319-4950 email: bowmanbe@us.cibc.com with a copy to: Canadian Imperial Bank of Commerce Two Paces West 2727 Paces Ferry Road, Suite 1200 Atlanta, GA 30339 Attn: Miriam McCart Tel: (770) 319-4842 Fax: (770) 319-4950 email: mccamiri@us.cibc.com Name of Initial Lender Toronto Dominion (Texas), Inc. Tranche A Commitment US$108,875,000.00 Tranche B Commitment US$71,666,666.67 Domestic Lending Office Toronto Dominion (Texas), Inc. 909 Fannin Street, 17th Floor Houston, TX 77010 Attn: Alva J. Jones Tel: (713) 653-8261 Fax: (713) 951-9921 email: jonesa2@tdusa.com Eurodollar Lending Office Toronto Dominion (Texas), Inc. 909 Fannin Street, 17th Floor Houston, TX 77010 Attn: Alva J. Jones Tel: (713) 653-8261 Fax: (713) 951-9921 email: jonesa2@tdusa.com Business / Credit Matters: Toronto Dominion Securities 31 West 52nd Street New York, NY 10019-6101 Attn: Cori Novellino Tel: (212) 827-7769 Fax: (212) 827-7244 email: novelc@tdusa.com Administrative / Operations Matters: The Toronto-Dominion Bank 909 Fannin Street, 17th Floor Houston, TX 77010 Attn: Alva J. Jones Tel: (713) 653-8261 Fax: (713) 951-9921 email: jonesa2@tdusa.com Name of Initial Lender MeesPierson Capital Corp. Tranche A Commitment US$0US Tranche B Commitment $71,666,666.66 Domestic Lending Office MeesPierson Capital Corp. 3 Stamford Plaza 301 Tresser Boulevard, 9th Floor Stamford, CT 06901-3239 Attn: Marlene Ellis Tel: (203) 705-5753 Fax: (203) 705-5888 email: mpe@meespiersonusa.com Eurodollar Lending Office MeesPierson Capital Corp. 3 Stamford Plaza 301 Tresser Boulevard, 9th Floor Stamford, CT 06901-3239 Attn: Marlene Ellis Tel: (203) 705-5753 Fax: (203) 705-5888 email: mpe@meespiersonusa.com Business / Credit Matters: MeesPierson Capital Corp. 3 Stamford Plaza 301 Tresser Boulevard, 9th Floor Stamford, CT 06901-3239 Attn: Hendrik Vroege Tel: (203) 705-5745 Fax: (203) 705-5890 email: hjv@meespiersonusa.com with a copy to: MeesPierson Capital Corp. 3 Stamford Plaza 301 Tresser Boulevard, 9th Floor Stamford, CT 06901-3239 Attn: Christopher McCall Tel: (203) 705-5729 Fax: (203) 705-7919 email: cjm@meespiersonusa.com Administrative / Operations Matters: MeesPierson Capital Corp. 3 Stamford Plaza 301 Tresser Boulevard, 9th Floor Stamford, CT 06901-3239 Attn: Marlene Ellis Tel: (203) 705-5753 Fax: (203) 705-5888 email: mpe@meespiersonusa.com with a copy to: MeesPierson Capital Corp. 3 Stamford Plaza 301 Tresser Boulevard, 9th Floor Stamford, CT 06901-3239 Attn: Peter Testa Tel: (203) 705-5755 Fax: (203) 705-5888 email: pdt@meespiersonusa.com Name of Initial Lender Union Bank of California, N.A. Tranche A Commitment US$0 Tranche B Commitment US$71,666,666.66 Domestic Lending Office Union Bank of California, N.A. Energy Capital Services 445 S. Figueroa Street, 15th Floor Los Angeles, CA 90071 Attn: Jason DiNapoli Tel: (213) 236-5016 Fax: (213) 236-4096 email: jason.dinapoli@uboc.com Eurodollar Lending Office Union Bank of California, N.A. Energy Capital Services 445 S. Figueroa Street, 15th Floor Los Angeles, CA 90071 Attn: Jason DiNapoli Tel: (213) 236-5016 Fax: (213) 236-4096 email: jason.dinapoli@uboc.com Business / Credit Matters: Union Bank of California, N.A. Energy Capital Services 445 S. Figueroa Street, 15th Floor Los Angeles, CA 90071 Attn: Jason DiNapoli Tel: (213) 236-5016 Fax: (213) 236-4096 email: jason.dinapoli@uboc.com Administrative / Operations Matters: Union Bank of California, N.A. Commercial Loan Operations 1980 Saturn Street Monterey Park, CA 91754 Attn: Gohar Karapetyan Tel: (323) 720-2679 Fax: (323) 724-6198 with a copy to: Union Bank of California, N.A. Commercial Loan Operations 1980 Saturn Street Monterey Park, CA 91754 Attn: Ruby Gonzales Tel: (323) 720-7055 Fax: (323) 724-6198 Total $435,500,000.00 $430,000,000.00 SCHEDULE 5 Insurance (A) Insurance by the Borrower: The Borrower shall procure at its own expense and maintain in full force and effect throughout the term of this Agreement (unless otherwise specified below) insurance policies with responsible insurance companies with (i) a Best Insurance Reports rating of "A-" or better and an financial size category of "IX" or higher, (ii) or a S & P financial strength rating of ABBB+@ or higher, (iii) or other companies acceptable to the Collateral Agent, with limits and coverage provisions sufficient to satisfy the requirements set forth in each of the Project Documents, but in no event less than the limits and coverage provisions set forth below. (1) General Liability Insurance: Liability insurance on an occurrence basis, except for claims made forms issued by the insurers AEGIS or EIM against claims filed anywhere in the world and occurring anywhere in the world for the Borrowers liability arising out of claims for personal injury (including bodily injury and death) and property damage. Such insurance shall provide coverage for products-completed operations, blanket contractual, broad form property damage, personal injury insurance, independent contractors and sudden and accidental pollution liability with a $100,000,000 minimum limit per occurrence for combined bodily injury and property damage. A maximum deductible or self-insured retention of $250,000 per occurrence shall be allowed. (2) Automobile Liability Insurance: Automobile liability insurance for the Borrowers liability arising out of claims for bodily injury and property damage covering all owned (if any), leased, non-owned and hired vehicles of the Borrower, including loading and unloading, with a $10,000,000 minimum limit per accident for combined bodily injury and property damage and containing appropriate no-fault insurance provisions wherever applicable. A maximum deductible or self-insured retention of $125,000 per occurrence shall be allowed. (3) Aircraft Liability Insurance: If the performance of any of the Project Documents requires the use of any aircraft that is owned, leased or chartered by the Borrower, aircraft liability insurance insuring the Borrower with a $25,000,000 minimum limit per occurrence for combined property damage and bodily injury, including passengers and crew. (4) Property Damage Insurance: Property insurance on an "all risk" basis insuring the Borrower and the Secured Parties, as their interests may appear, including coverage against damage or loss caused by earth movement (including but not limited to earthquake, landslide, subsidence and volcanic eruption), flood, turbine and machinery accidents. (a) Property Insured: The property insurance shall provide coverage for (i) the buildings, structures, turbine, machinery, equipment, facilities, fixtures, supplies, fuel and other properties constituting a part of the Generating Assets, (ii) steam and electrical transmission lines along with related equipment for which the Borrower has an insurable interest, (iii) the cost of recreating plans, drawings or any other documents or computer system records, (iv) electronic equipment and (v) foundations and other property below the surface of the ground. (b) Additional Coverages: The property insurance shall insure (i) transit and off-site repair including ocean marine and air transit, if applicable, with sub-limits sufficient to insure the full replacement value of the property or equipment prior to its being moved to or from the Generating Assets sites and while located away from the Generating Assets sites, (ii) attorney's fees, engineering and other consulting costs, and permit fees directly incurred in order to repair or replace damaged insured property in a minimum amount of $2,000,000, (iii) the cost of preventive measures to reduce or prevent a loss (sue & labor) in an amount not less than $2,500,000, (iv) increased cost of construction and loss to undamaged property as the result of enforcement of building laws or ordinances with sub-limits not less than $15,000,000, (v) debris removal with sub-limits not less than $5,000,000, (vi) expediting expenses (defined as extraordinary expenses incurred after an insured loss to make temporary repairs and expedite the permanent repair of the damaged property in excess of the business interruption even if such expense does not reduce the business interruption loss) in an amount not less than $5,000,000 and (vii) the cleaning of civil works, channels, tunnels, equipment or other assets affected by accidental events involving mud or water accumulation, falling rocks, landslides and similar acts of nature that prevent the continuation of normal activities, although no physical damage to the Generating Assets has occurred in an amount not less than $2,000,000. (c) Special Clauses: The property policy shall include a (i) 72 hour clause for flood, windstorm and earthquakes, (ii) unintentional errors and omissions clause, (iii) requirement that the insurer pay losses within 30 days after receipt of an acceptable proof of loss or partial proof of loss and (iv) other insurance clause making this insurance primary over any other insurance. (d) Sum Insured: Losses shall be valued at their repair or replacement cost, without deductible for physical depreciation or obsolescence. The property damage policy shall insure the Generating Assets in an amount not less than $150,000,000 per occurrence. The earth movement and flood coverage may be insured with a sub-limit not less than $150,000,000." (e) Deductibles: The property damage insurance may have deductibles of not greater than $1,000,000 per occurrence. (f) Prohibited Exclusions: The property damage policy shall not contain any (i) coinsurance provision, (ii) exclusion for loss or damage resulting from freezing, mechanical breakdown, (iii) exclusion for loss or damage covered under any guarantee or warranty arising out of an insured peril, (iv) exclusion for resultant damage caused by ordinary wear and tear, gradual deterioration, normal subsidence, settling cracking, expansion or contraction or (v) a faulty workmanship, design or materials exclusion substantially different from the DE-5 or LEG-3 exclusions. (5) Business Interruption Insurance: Business interruption insurance insuring the Borrower and the Secured Parties, as their interests may appear, covering 100% of the Borrowers continuing normal operating expenses including payroll and debt service for a period of 12 months, arising from loss required to be insured by Section(A)(4) above. Such insurance shall (a) have a deductible no greater than 60 days per occurrence, (b) include for a period of 2 months that portion of fixed expenses and debt service not earned arising from an insured loss or occurrence at the premises of any service (electricity, water, gas, etc.) supplier and the premises of any purchaser of electricity, (c) cover loss sustained when access to the Generating Assets sites is prevented due to an insured peril at premises in the vicinity of the Generating Assets sites, (d) cover loss sustained due to the action of a public authority preventing access to the Generating Assets sites due to imminent or actual loss or destruction arising from an insured peril at premises in the vicinity of the Generating Assets sites and (e) include an clause allowing interim payments on account pending finalization of the claim payment. Such insurance shall not contain any coinsurance clause or include a waiver of such clause. (6) Fidelity: Fidelity insurance providing coverage for employee dishonesty including theft, computer funds transfer fraud, alteration and forgery insuring loss of money, securities or other property resulting from any fraudulent or dishonest act committed by the Borrowers employees, whether acting alone or in collusion with others in an amount not less than $5,000,000. (7) Endorsements: All policies of liability insurance required to be maintained by the Borrower shall be endorsed as follows: (a) To name the Secured Parties and their respective officers and employees (and such other Persons as may be required by the Project Documents) as additional insureds; (b) To provide a severability of interests and cross liability clause; (c) That the insurance shall be primary and not excess to or contributing with any insurance or self-insurance maintained by the Secured Parties. (8) Waiver of Subrogation: The Borrower hereby waives any and every claim for recovery from the Secured Parties for any and all loss or damage covered by any of the insurance policies to be maintained under this Agreement to the extent that such loss or damage is recovered under any such policy. Inasmuch as the foregoing waiver will preclude the assignment of any such claim to the extent of such recovery, by subrogation (or otherwise), to an insurance company (or other person), the Borrower shall give written notice of the terms of such waiver to each insurance company which has issued, or which may issue in the future, any such policy of insurance (if such notice is required by the insurance policy) and shall cause each such insurance policy to be properly endorsed by the issuer thereof to, or to otherwise contain one or more provisions that, prevent the invalidation of the insurance coverage provided thereby by reason of such waiver. (B) Amendment of Requirements: (1) Amendment by the Required Lenders: The Required Lenders may at any time amend the requirements of this Schedule 5 due to (i) new information not known by the Lenders as of the date of this Agreement and which poses a material risk to the Generating Assets or (ii) changed circumstances after the date of this Agreement which in the reasonable judgment of the Required Lenders renders such coverage materially inadequate. (2) Amendment Due To Commercial Unfeasibility: In the event any insurance (including the limits or deductibles thereof) hereby required to be maintained shall not be reasonably available and commercially feasible in the commercial insurance market, the Required Lenders shall not unreasonably withhold their agreement to waive such requirement to the extent the maintenance thereof is not so available; provided, however, that (i) the Borrower shall first request any such waiver in writing, which request shall be accompanied by a written report prepared by the Insurance Consultant, certifying that such insurance is not reasonably available and commercially feasible (and, in any case where the required amount is not so available, certifying as to the maximum amount which is so available) and explaining in detail the basis for such conclusions; (ii) at any time after the granting of any such waiver, but not more often than once a year, the Required Lenders may request, and the Borrower shall furnish to the Required Lenders within fifteen (15) days after such request, supplemental reports reasonably acceptable to the Required Lenders from the Insurance Consultant updating their prior report and reaffirming such conclusion; and (iii) any such waiver shall be effective only so long as such insurance shall not be reasonable available and commercially feasible in the commercial insurance market, it being understood that the failure of the Borrower to timely furnish any such supplemental report shall be conclusive evidence that such waiver is no longer effective because such condition no longer exists, but that such failure is not the only way to establish such non-existence. The failure at any time to satisfy the condition to any waiver of an insurance requirement set forth in the proviso to the preceding sentence shall not impair or be construed as a relinquishment of the Borrower's ability to obtain a waiver of an insurance requirement pursuant to the preceding sentence at any other time upon satisfaction of such conditions. For the purposes of this sub-section insurance will be considered not reasonably available and commercially feasible if it is obtainable only at excessive costs which are not justified in terms of the risk to be insured and is generally not being carried by or applicable to independent power producers with operations similar to the Borrower because of such excessive costs. (C) Conditions: (1) Loss Notification: The Borrower shall promptly notify the Collateral Agent of any single loss or event likely to give rise to a claim against an insurer for an amount in excess of $1,000,000 covered by any insurance maintained pursuant to Sections (A)(4) and (5). (2) Payment of Loss Proceeds: All policies of insurance required to be maintained pursuant to Sections (A)(4) and (5), shall provide that the proceeds of such policies shall be payable solely to the Collateral Agent pursuant to a standard first mortgage endorsement substantially equivalent to the Lenders Loss Payable Endorsement 438BFU or ISO endorsement CP12181091 without contribution. (3) Loss Adjustment and Settlement: A loss under any insurance required to be carried under Sections (A)(4) and (5), shall be adjusted with the insurance companies, including the filing in a timely manner of appropriate proceedings, by the Borrower, subject to the approval of the Required Lenders if such loss is in excess of $10,000,000. In addition the Borrower may in its reasonable judgment consent to the settlement of any loss, provided that in the event that the amount of the loss exceeds $10,000,000 the terms of such settlement is concurred with by the Required Lenders. (4) Policy Cancellation and Change: All policies of insurance required to be maintained pursuant to this Schedule 5 shall be endorsed so that if at any time should they be canceled, or coverage be reduced (by any party including the insured) which affects the interests of the Secured Parties, such cancellation or reduction shall not be effective as to the Secured Parties for 60 days, except for non-payment of premium which shall be for 10 days, after receipt by the Collateral Agent of written notice from such insurer of such cancellation or reduction. (5) Miscellaneous Policy Provisions: All policies of insurance required to be maintained pursuant to Sections (A)(4) and (5), shall (i) not include any annual or term aggregate limits of liability or clause requiring the payment of additional premium to reinstate the limits after loss except as regards the insurance applicable to the perils of flood, earth movement, sabotage and terrorism, (ii) shall include the Secured Parties as additional insureds as their interests may appear, and (iii) include a clause requiring the insurer to make final payment on any claim within 30 days after the submission of proof of loss and its acceptance by the insurer. (6) Separation of Interests: All policies (other than in respect to liability or workers compensation insurance) shall insure the interests of the Secured Parties regardless of any breach or violation by the Borrower or any other party of warranties, declarations or conditions contained in such policies, any action or inaction of the Borrower or others, or any foreclosure relating to the Generating Assets or any change in ownership of all or any portion of the Generating Assets. (7) Acceptable Policy Terms and Conditions: All policies of insurance required to be maintained pursuant to this Schedule 5 shall contain terms and conditions reasonably acceptable to the Required Lenders after consultation with the Insurance Consultant. (8) Waiver of Subrogation: All policies of insurance to be maintained by the provisions of this Schedule 5 shall provide for waivers of subrogation in favor of the Secured Parties and their respective officers and employees (and such other Persons as may be required by the Project Documents). (D) Evidence of Insurance: As of the Borrowing Date and on an annual basis at least 10 days prior to each policy anniversary, the Borrower shall furnish the Collateral Agent with (1) certificates of insurance or binders, in a form acceptable to the Collateral Agent, evidencing all of the insurance required by the provisions of this Schedule 5 and (2) a schedule of the insurance policies held by or for the benefit of the Borrower and required to be in force by the provisions of this Schedule 5. Such certificates of insurance/binders shall be executed by each insurer or by an authorized representative of each insurer where it is not practical for such insurer to execute the certificate itself. Such certificates of insurance/binders shall identify underwriters, the type of insurance, the insurance limits and the policy term and shall specifically list the special provisions enumerated for such insurance required by this Schedule 5. Upon request, the Borrower will promptly furnish the Collateral Agent with copies of all insurance policies, binders and cover notes or other evidence of such insurance relating to the insurance required to be maintained by the Borrower. The schedule of insurance shall include the name of the insurance company, policy number, type of insurance, major limits of liability and expiration date of the insurance policies. (E) Reports: Prior to the expiration date of any required insurance policy, the Borrower shall deliver to the Collateral Agent and the Insurance Consultant a certificate of the Borrower stating that all insurance required to be maintained by this Schedule 5 is in full force and effect, accompanied on each Broker Reporting Date (as defined below) by a report or reports from the Borrower's insurance brokers or agents that taken together show with reasonable specificity the existence of all insurance required to be maintained by this Schedule 5 (including the scope and amount of coverage provided by, and the deductibles and exclusions under, each required policy), and that all such insurance is then in full force and effect and all premiums have been paid in full. The Collateral Agent shall have the right to review copies of all policies providing the coverage required by this Schedule 5. For the purposes of this Schedule 5, "Broker Reporting Date" shall mean (i) any date upon which the Borrower has renewed an insurance policy but with a different insurer, and (ii) any date upon which an insurance policy is renewed and incorporates any changes (other than changes of an administrative nature) from the previous corresponding insurance policy. The Borrower shall promptly notify the Collateral Agent of (i) any dispute with an insurer that the Borrower, acting reasonably, considers material and might adversely affect the payment of a claim under any policy of insurance required to be maintained under this Schedule 5 or the ability of the Borrower to maintain in effect any such required policy, (ii) the cancellation (or notification concerning proposed cancellation) of any policy prior to its stated term, (iii) the non-payment of any premium when due, (iv) the failure by the Borrower, for any reason, to maintain in full force and effect any insurance required by this Schedule 5, (v) any material change (other than increases in scope of coverage) in any insurance coverage maintained by the Borrower, (vi) any actual or, upon obtaining knowledge thereof, potential event of loss in excess of $1,000,000 covered by such insurance, and (vii) any other information relating to the insurance required by this Schedule 5 that may be reasonably requested by any Lender or the Collateral Agent. (F) Failure to Maintain Insurance: In the event the Borrower fails to take out or maintain the full insurance coverage required by this Schedule 5, the Collateral Agent, upon 30 days' prior notice (unless the aforementioned insurance would lapse within such period, in which event notice should be given as soon as reasonably possible) to the Borrower of any such failure, may (but shall not be obligated to) take out the required policies of insurance and pay the premiums on the same. All amounts so advanced thereof by the Collateral Agent shall become an additional obligation of the Borrower to the Collateral Agent, and the Borrower shall forthwith pay such amounts to the Collateral Agent, together with interest thereon at the interest rate set forth in Section 2.06(b) of the Agreement from the date so advanced. (G) No Duty of Collateral Agent to Verify or Review: No provision of this Schedule 5 or any provision of this Agreement, any Acquisition Document or any Project Document shall impose on the Collateral Agent any duty or obligation to verify the existence or adequacy of the insurance coverage maintained by the Borrower, nor shall the Collateral Agent be responsible for any representations or warranties made by or on behalf of the Borrower to any insurance company or underwriter. Any failure on the part of the Collateral Agent to pursue or obtain the evidence of insurance required by this Agreement from the Borrower and/or failure of the Collateral Agent to point out any non-compliance of such evidence of insurance shall not constitute a waiver of any of the insurance requirements in this Agreement. (H) Maintenance of Insurance: The Borrower shall at all times maintain the insurance coverage required under the terms of the Project Documents. (I) Liability for Failure to Maintain Insurance: Failure to secure the requisite insurance coverages, to comply fully with any of the provisions of this Schedule 5, or to secure such endorsements on the policies as may be necessary to carry out the terms and provisions of this Schedule 5, shall in no way act to relieve the Borrower from its obligations under this Schedule 5. In the event that liability for loss or damage is denied by the underwriter(s), in full or in part, because of breach of said insurance policies by the Borrower, or if the Borrower fails to maintain any of the insurance herein required, the Borrower shall hold harmless and indemnify the Secured Parties and the Agents against all claims, demands, costs and expenses, including reasonable attorney's fees, which would otherwise be covered by said insurance. The Borrower's indemnification obligations under this Agreement (express or implied) shall not be limited to the amount or scope of coverage provided by insurance which is required under this Schedule 5. (J) Insurance Consultant. The Borrower shall reimburse the Lenders from time to time for the reasonable fees and expenses of the Insurance Consultant appointed by the Required Lenders (a) to advise the Lenders with respect to the initial contents of this Schedule 5, and the compliance by the Borrower on the Borrowing Date with the applicable requirements of this Schedule 5, (b) if requested by the Required Lenders, to review for compliance with the requirements of this Schedule 5 any insurance policies or certificates with respect thereto delivered to or made available by the Borrower pursuant to this Schedule 5, and (c) if requested by the Required Lenders, to advise the Lenders as to whether any change in this Schedule 5 as then in effect requested by the Borrower satisfied the applicable requirements of this Schedule 5. EXHIBIT A-1 TO THE CREDIT AGREEMENT FORM OF TRANCHE A PROMISSORY NOTE $ Dated: , 200 FOR VALUE RECEIVED, the undersigned, Northeast Generation Company, a Connecticut corporation (the "Borrower"), HEREBY PROMISES TO PAY (the "Lender") for the account of its Applicable Lending Office (as defined in the Credit Agreement referred to below) the principal amount of the Tranche A Advance (as defined below) owing to the Lender by the Borrower pursuant to the Credit Agreement dated as of March 9, 2000 (as amended, supplemented or otherwise modified from time to time, the "Credit Agreement"; terms defined therein being used herein as therein defined) among the Borrower, the Lender and certain other Lenders party thereto, and Citibank, N.A. ("Citibank"), as Administrative Agent for the Lender and such other Lenders, as Collateral Agent for the Secured Parties and as Depositary Bank, on the Tranche A Maturity Date. The Borrower promises to pay interest on the unpaid principal amount of the Tranche A Advance from the date of the Tranche A Advance until such principal amount is paid in full, at such interest rates, and payable at such times, as are specified in the Credit Agreement. Both principal and interest are payable in lawful money of the United States of America to Citibank, as Administrative Agent, at the Administrative Agent's Account, in immediately available funds. The Tranche A Advance owing to the Lender by the Borrower and all payments made on account of principal thereof, shall be recorded by the Lender and, prior to any transfer hereof, endorsed on the grid attached hereto, which is part of this Tranche A Promissory Note. This Promissory Note is one of the Notes referred to in, and is entitled to the benefits of, the Credit Agreement. The Credit Agreement, among other things, (i) provides for the making of an advance (the "Tranche A Advance") by the Lender to the Borrower in an amount not to exceed the U.S. dollar amount first above mentioned, the indebtedness of the Borrower resulting from the Tranche A Advance being evidenced by this Promissory Note, and (ii) contains provisions for acceleration of the maturity hereof upon the happening of certain stated events. The obligations of the Borrower under this Promissory Note, and the obligations of the other Loan Parties under the Loan Documents, are secured by the Collateral as provided in the Loan Documents. NORTHEAST GENERATION COMPANY By Name: Title: TRANCHE A ADVANCE AND PAYMENTS OF PRINCIPAL Date Amount of Tranche A Advance Amount of Principal Paid Unpaid Principal Balance Notation Made By EXHIBIT A-2 TO THE CREDIT AGREEMENT FORM OF TRANCHE B PROMISSORY NOTE $ Dated: , 2000 FOR VALUE RECEIVED, the undersigned, Northeast Generation Company, a Connecticut corporation (the "Borrower"), HEREBY PROMISES TO PAY (the "Lender") for the account of its Applicable Lending Office (as defined in the Credit Agreement referred to below) the principal amount of the Tranche B Advance (as defined below) owing to the Lender by the Borrower pursuant to the Credit Agreement dated as of March 9, 2000 (as amended, supplemented or otherwise modified from time to time, the "Credit Agreement"; terms defined therein being used herein as therein defined) among the Borrower, the Lender and certain other Lenders party thereto, and Citibank, N.A. ("Citibank"), as Administrative Agent for the Lender and such other Lenders, as Collateral Agent for the Secured Parties and as Depositary Bank, on the Tranche B Maturity Date. The Borrower promises to pay interest on the unpaid principal amount of the Tranche B Advance from the date of the Tranche B Advance until such principal amount is paid in full, at such interest rates, and payable at such times, as are specified in this Agreement. Both principal and interest are payable in lawful money of the United States of America to Citibank, as Administrative Agent, at the Administrative Agent's Account, in immediately available funds. The Tranche B Advance owing to the Lender by the Borrower, and all payments made on account of principal thereof, shall be recorded by the Lender and, prior to any transfer hereof, endorsed on the grid attached hereto, which is part of this Tranche B Promissory Note. This Promissory Note is one of the Notes referred to in, and is entitled to the benefits of, the Credit Agreement. The Credit Agreement, among other things, (i) provides for the making of an advance (the "Tranche B Advance") by the Lender to the Borrower in an amount not to exceed the U.S. dollar amount first above mentioned, the indebtedness of the Borrower resulting from the Tranche B Advance being evidenced by this Promissory Note, and (ii) contains provisions for acceleration of the maturity hereof upon the happening of certain stated events and also for prepayments on account of principal hereof prior to the maturity hereof upon the terms and conditions therein specified. The obligations of the Borrower under this Promissory Note, and the obligations of the other Loan Parties under the Loan Documents, are secured by the Collateral as provided in the Loan Documents. NORTHEAST GENERATION COMPANY By Name: Title: TRANCHE B ADVANCE AND PAYMENTS OF PRINCIPAL Date Amount of Tranche B Advance Amount of Principal Paid or Prepaid Unpaid Principal Balance Notation Made By EXHIBIT B TO THE CREDIT AGREEMENT FORM OF NOTICE OF BORROWING Citibank, N.A., as Administrative Agent under the Credit Agreement referred to below [Date] Attention: Ladies and Gentlemen: The undersigned, Northeast Generation Company, refers to the Credit Agreement dated as of March 9, 2000 (as amended, supplemented or otherwise modified from time to time, the "Credit Agreement", the terms defined therein being used herein as therein defined), among the undersigned, certain Lenders party thereto, and Citibank, N.A., as Administrative Agent for said Lenders and Collateral Agent for the Secured Parties and Depositary Bank, and hereby gives you notice, irrevocably, pursuant to Section 2.02 of the Credit Agreement that the undersigned hereby requests two Borrowings under the Credit Agreement, and in that connection sets forth below the information relating to such Borrowings (the "Proposed Borrowing") as required by Section 2.02(a) of the Credit Agreement: (i) The Business Day of the Proposed Borrowing is , 2000. (ii) The aggregate amount of the Tranche A Borrowing is $ and of the Tranche B Borrowing is $ . (iii) The Type of Advances comprising the Proposed Tranche B Borrowing is [Base Rate Advances] [Eurodollar Rate Advances]. (iv) The aggregate amount of the Proposed Borrowing is $ . [(v) The initial Interest Period for each Eurodollar Rate Advance made as part of the Proposed Tranche B Borrowing is month[s].] The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing: (A) the representations and warranties contained in each Loan Document are correct on and as of the date of the Proposed Borrowing, before and after giving effect to the Proposed Borrowing and to the application of the proceeds therefrom, as though made on and as of such date; and (B) no event has occurred and is continuing, or would result from such Proposed Borrowing or from the application of the proceeds therefrom, that constitutes a Default. Very truly yours, NORTHEAST GENERATION COMPANY By Name: Title: EXHIBIT C TO THE CREDIT AGREEMENT FORM OF ASSIGNMENT AND ACCEPTANCE Reference is made to the Credit Agreement dated as of March 9, 2000 (as amended, supplemented or otherwise modified from time to time, the "Credit Agreement") among Northeast Generation Company, a Connecticut corporation (the "Borrower"), the Lenders (as defined in the Credit Agreement) and Citibank, N.A., as administrative agent for the Lenders (the "Administrative Agent"), as Collateral Agent for the Secured Parties and as Depositary Bank. Terms defined in the Credit Agreement are used herein with the same meaning. The "Assignor" and the "Assignee" referred to on Schedule 1 hereto agree as follows: 1. The Assignor hereby sells and assigns to the Assignee, and the Assignee hereby purchases and assumes from the Assignor, an interest in and to the Assignor's rights and obligations under the Credit Agreement as of the date hereof equal to the percentage interests specified on Schedule 1 hereto of all outstanding rights and obligations under the Credit Agreement. After giving effect to such sale and assignment, the Assignee's Commitments and the amount of the Advances owing to the Assignee will be as set forth on Schedule 1 hereto. 2. The Assignor (i) represents and warrants that it is the legal and beneficial owner of the interest being assigned by it hereunder and that such interest is free and clear of any adverse claim; (ii) makes no representation or warranty and assumes no responsibility with respect to any statements, warranties or representations made in or in connection with the Loan Documents or the execution, legality, validity, enforceability, genuineness, sufficiency or value of, or the perfection or priority of any lien or security interest created or purported to be created under or in connection with, the Loan Documents or any other instrument or document furnished pursuant thereto; and (iii) makes no representation or warranty and assumes no responsibility with respect to the financial condition of any Loan Party or the performance or observance by any Loan Party of any of its obligations under any Loan Document or any other instrument or document furnished pursuant thereto; and (iv) attaches the Note or Notes held by the Assignor and requests that the Administrative Agent exchange such Note or Notes for a new Note or Notes payable to the order of the Assignee in an amount equal to the Commitments assumed by the Assignee pursuant hereto or new Notes payable to the order of the Assignee in an amount equal to the Commitments assumed by the Assignee pursuant hereto and the Assignor in an amount equal to the Commitments retained by the Assignor under this Agreement, respectively, as specified on Schedule 1 hereto. 3. The Assignee (i) confirms that it has received a copy of the Credit Agreement, together with copies of the financial statements referred to in Section 5.01 thereof and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment and Acceptance; (ii) agrees that it will, independently and without reliance upon the Administrative Agent, the Collateral Agent, the Assignor or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Agreement; (iii) confirms that it is an Eligible Assignee; (iv) appoints and authorizes the Administrative Agent and the Collateral Agent (as the case may be) to take such action as agent on its behalf and to exercise such powers and discretion under the Loan Documents as are delegated to the Administrative Agent and the Collateral Agent, respectively, by the terms thereof, together with such powers and discretion as are reasonably incidental thereto; (v) agrees that it will perform in accordance with their terms all of the obligations that by the terms of the Credit Agreement are required to be performed by it as a Lender; and (vi) attaches any U.S. Internal Revenue Service forms required under Section 2.11 of the Credit Agreement. 4. Following the execution of this Assignment and Acceptance, it will be delivered to the Administrative Agent for acceptance and recording by the Administrative Agent. The effective date for this Assignment and Acceptance (the "Effective Date") shall be the date of acceptance hereof by the Administrative Agent, unless otherwise specified on Schedule 1 hereto. 5. Upon such acceptance and recording by the Administrative Agent, as of the Effective Date, (i) the Assignee shall be a party to the Credit Agreement and, to the extent provided in this Assignment and Acceptance, have the rights and obligations of a Lender thereunder and (ii) the Assignor shall, to the extent provided in this Assignment and Acceptance, relinquish its rights and be released from its obligations under the Credit Agreement. 6. Upon such acceptance and recording by the Administrative Agent, from and after the Effective Date, the Administrative Agent shall make all payments under the Credit Agreement and the Notes in respect of the interest assigned hereby (including, without limitation, all payments of principal, interest and commitment fees with respect thereto) to the Assignee. The Assignor and Assignee shall make all appropriate adjustments in payments under the Credit Agreement and the Notes for periods prior to the Effective Date directly between themselves. 7. This Assignment and Acceptance shall be governed by, and construed in accordance with, the laws of the State of New York. 8. This Assignment and Acceptance may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of Schedule 1 to this Assignment and Acceptance by telecopier shall be effective as delivery of a manually executed counterpart of this Assignment and Acceptance. IN WITNESS WHEREOF, the Assignor and the Assignee have caused Schedule 1 to this Assignment and Acceptance to be executed by their officers thereunto duly authorized as of the date specified thereon. SCHEDULE 1 to ASSIGNMENT AND ACCEPTANCE Percentage interest in Tranche A assigned: % Percentage interest in Tranche B assigned: % Assignee's Tranche A Commitment: $ Assignee's Tranche B Commitment: $ Aggregate outstanding principal amount of Tranche A Advances assigned: $ Aggregate outstanding principal amount of Tranche B Advances assigned: $ Principal amount of Tranche A Note payable to Assignee: $ Principal amount of Tranche B Note payable to Assignee: $ Assignor's Tranche A Commitment: $ Assignor's Tranche B Commitment: $ Principal amount of Tranche A Note payable to Assignor: $__________ Principal amount of Tranche B Note payable to Assignor: $ Effective Date (if other than date of acceptance by Administrative Agent): ** This date should be no earlier than five Business Days after the delivery of this Assignment and Acceptance to the Administrative Agent. , 200 [NAME OF ASSIGNOR], as Assignor By Name: Title: Dated: , 200 [NAME OF ASSIGNEE], as Assignee By Name: Title: Dated: , 200 Domestic Lending Office: Eurodollar Lending Office: Accepted ** Required if the Assignee is an Eligible Assignee solely by reason of clause (vii) the definition of Eligible Assignee.[and Approved] this day of , 200 CITIBANK, N.A. as Administrative Agent By Name Title *[Approved this day of , 200 NORTHEAST GENERATION COMPANY By Name Title:] EXHIBIT J TO THE CREDIT AGREEMENT FORM OF SOLVENCY CERTIFICATE OF [NAME OF COMPANY] I, the undersigned, [Name Officer], in my capacity as Chief Financial Officer of [Name of Company], a corporation (the "Company"), am duly authorized to execute and deliver and make the representations and certifications made in this Certificate and DO HEREBY CERTIFY on behalf of the Company that: 1. This certificate is hereby delivered on behalf of the Company pursuant to Section 3.01(m)(xiv) of the Credit Agreement dated as of March 9, 2000 (as further amended, supplemented or otherwise modified from time to time, the "Credit Agreement") among Northeast Generation Company, certain banks, financial institutions and other institutional lenders from time to time party thereto (the "Lenders") and Citibank, N.A., as Administrative Agent, Collateral Agent and Depositary Bank. Capitalized terms not otherwise defined in this Certificate shall have the same meanings as specified therefor in the Credit Agreement. 2. I am knowledgeable and generally familiar with the properties, businesses, prospects, financial condition and assets of the Company and have carefully reviewed the Loan Documents, the Project Documents and the Acquisition Documents and the contents of this Certificate and, in connection herewith, have reviewed such other documentation and information and have made such investigations and inquiries of the Company and directors and employees of the Company that are necessary and prudent for a proper investigation. 3. The financial information and assumptions that underlie and form the basis for the representations and certifications made in this Certificate were made in good faith and were reasonable when made and continue to be reasonable as of the date of this Certificate. 4. The Company understands that the Agents and the Lenders are relying upon the truth and accuracy of this Certificate in connection with the transactions contemplated by the Loan Documents, the Project Documents and the Acquisition Documents. 5. On the date of this Certificate, immediately before and immediately after giving pro forma effect to the [WMECO/CL&P] Acquisition and the transactions contemplated by the Project Documents and the Acquisition Documents to occur on or prior to the date of this Certificate, the fair value of the property and assets of the Company is greater than the total amount of liabilities (including, without limitation, contingent, subordinated, absolute, fixed, matured or unmatured and liquidated or unliquidated liabilities) of the Company. 6. On the date of this Certificate, immediately before and immediately after giving pro forma effect to the [WMECO/CL&P] Acquisition and the transactions contemplated by the Project Documents and the Acquisition Documents to occur on or prior to the date of this Certificate, the present fair saleable value of the property and assets of the Company is not less than the amount that will be required to pay the probable liability of the Company on its debts as they become absolute and matured. 7. On the date of this Certificate, immediately before and immediately after giving pro forma effect to the [WMECO/CL&P] Acquisition and the transactions contemplated by the Project Documents and the Acquisition Documents to occur on or prior to the date of this Certificate, the Company is not insolvent and the Company will not be rendered insolvent by the transactions contemplated by the Acquisition Documents and the Project Documents. 8. The Company has not incurred, nor does it intend to, and does not believe that it will, incur debts or liabilities beyond its ability to pay such debts and liabilities as they mature. 9. On the date of this Certificate, immediately before and immediately after giving pro forma effect to the [WMECO/CL&P] Acquisition and the transactions contemplated by the Project Documents and the Acquisition Documents to occur on or prior to the date of this Certificate, the Company is not engaged in business or a transaction, and is not about to engage in business or a transaction, for which its property and assets would constitute an unreasonably small capital. 10. The Company does not intend, in consummating the [WMECO/CL&P] Acquisition and the transactions contemplated by the Acquisition Documents and the Project Documents to occur on or prior to the date of this Certificate, to hinder, delay or defraud either present or future creditors or any other Person to which the Company is or, on or after the date of this Certificate, will become indebted. 11. In reaching the conclusions set forth in this Certificate, the Company has considered, among other things: (a) the cash and other current assets of the Company reflected in the Consolidated balance sheet and pro forma statements of income of the Company and its Subsidiaries after giving effect to the [WMECO/CL&P] Acquisition and the transactions contemplated by the Acquisition Documents and the Project Documents [and reflecting the estimated purchase price accounting adjustments prepared by independent public accountants]; (b) all of the unliquidated and contingent liabilities of the Company, including, without limitation, any claims arising out of pending or, to the best knowledge of the undersigned, threatened litigation against the Company or any of its property and assets and, in so doing, the Company has computed the amount of each such unliquidated or contingent liability as the amount that, in light of all of the facts and circumstances existing on the date of this Certificate, represents the amount that can reasonably be expected to become an actual or matured liability; (c) all of the obligations and liabilities of the Company, whether matured or unmatured, liquidated or unliquidated, disputed or undisputed, secured or unsecured, subordinated, absolute, fixed or contingent, including, without limitation, any claims arising out of pending or, to the best knowledge of the undersigned, threatened litigation against the Company or any of its property and assets; (d) historical and anticipated growth in the sales volume of the Company and in the income stream generated by the Company; (e) the customary sales terms and the trade payables and other accounts payable of the Company; (f) the amount of the credit extended to customers and by suppliers of the Company; and (g) the level of capital customarily maintained by the Company and, to the extent that the Company has knowledge thereof, other entities engaged in the same or a similar business as the businesses of the Company. Delivery of an executed signature page to this Certificate by telecopier shall be effective as delivery of a manually executed signature page hereof. IN WITNESS WHEREOF, the Company has caused this Certificate to be executed by its Chief Financial Officer thereunto duly authorized on this March , 2000. [NAME OF COMPANY] By Name: Title: Chief Financial Officer EX-10.54.1 11 0011.txt EXHIBIT 10.54.1 AMENDMENT NO. 1 dated as of July 27, 2000 To CREDIT AGREEMENT dated as of March 9, 2000 Among NORTHEAST GENERATION COMPANY as Borrower and THE LENDERS NAMED HEREIN as Lenders and CITIBANK, N.A. as Administrative Agent and CITIBANK, N.A. as Collateral Agent and CITIBANK, N.A. as Depositary Bank AMENDMENT NO. 1 TO THE CREDIT AGREEMENT Dated as of July 27, 2000 AMENDMENT NO. 1 to the CREDIT AGREEMENT among NORTHEAST GENERATION COMPANY, a Connecticut corporation (the "Borrower"), the banks, financial institutions and other institutional lenders parties to the Credit Agreement referred to below (collectively, the "Lenders") and CITIBANK, N.A., as administratve agent (the "Administrative Agent") for the Lenders, collateral agent for the Secured Parties (the "Collateral Agent") and the depositary bank (the "Depositary Bank"). PRELIMINARY STATEMENTS: (1) The Borrower, the Lenders, the Administrative Agent, the Collateral Agent, and the Depositary Bank have entered into a Credit Agreement dated as of March 9, 2000 (the "Credit Agreement"). Capitalized terms not otherwise defined in this Amendment have the same meanings as specified in the Credit Agreement. (2) The Borrower has requested that the Credit Agreement be amended as hereinafter set forth. (3) The Lenders, the Administrative Agent, the Collateral Agent, and the Depositary Bank are, on the terms and conditions stated below, willing to grant the request of the Borrower. Amendments to Credit Agreement The Credit Agreement is, effective as of the date hereof and subject to the satisfaction of the conditions precedent set forth in Section 2, hereby amended as follows: (a) The definition of "Excess Cash Flow" in Section 1.01 is amended by adding, in the sixth line thereof after the phrase "Cash Flow Payment Date" the following: "(provided, however that in the case of the November 12, 2000 Excess Cash Flow Payment Date, the period used to measure Excess Cash Flow shall be the period from August 1, 2000 to October 31, 2000)". (b) The definition of "Excess Cash Flow Payment Date" in Section 1.01 is amended by deleting the date "November 1, 2000" at the end thereof and substituting the date "November 12, 2000". (c) Section 2.05(iv) is amended by adding at the end thereof before the period, the following: "; provided however that the amount, if any, of Available Excess Cash Flow which is in excess of ten million U.S. dollars (10,000,000 dollars) and which otherwise would be required to be used to prepay Advances together with accrued and unpaid interest under this subsection on the August 1, 2000 Excess Cash Flow Payment Date shall instead be used to prepay Advances together with accrued and unpaid interest on September 12, 2000. Conditions of Effectiveness This Amendment shall become effective as of the date first above written when, and only when the Administrative Agent shall have received counterparts of this Amendment executed by the Borrower, the Lenders, the Collateral Agent, and the Depositary Bank, together with the consent attached hereto executed by the Sponsor. This Amendment is subject to the provisions of Section 9.01 of the Credit Agreement. Reference to and Effect on the Credit Agreement and the Notes (a) On and after the effectiveness of this Amendment, each reference in the Credit Agreement to "this Agreement", "hereunder", "hereof" or words of like import referring to the Credit Agreement, and each reference in the Notes to "the Credit Agreement", "thereunder", "thereof" or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement, as amended by this Amendment. (a) The Credit Agreement and the Notes as specifically amended by this Amendment, are and shall continue to be in full force and effect and are hereby in all respects ratified and confirmed. (a) The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Lender, or the Administrative Agent, the Collateral Agent, or the Depositary Bank under the Credit Agreement, nor constitute a waiver of any provision of the Credit Agreement. Costs. The Borrower agrees to pay on demand all costs and expenses of the Administrative Agent in connection with the preparation, execution and delivery of this Amendment and the other instruments and documents to be delivered hereunder (including, without limitation, the reasonable fees and expenses of counsel for the Administrative Agent) in accordance with the terms of Section 9.04 of the Credit Agreement. Execution in Counterparts This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute but one and the same agreement. Delivery of an executed counterpart of a signature page to this Amendment by telecopier shall be effective as delivery of a manually executed counterpart of this Amendment. Governing Law This Amendment shall be governed by, and construed in accordance with, the laws of the State of New York. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly authorized, as of the date first above written. NORTHEAST GENERATION COMPANY By Title: CITIBANK, N.A., as Administrative Agent By Title: CITIBANK, N.A. As Collateral Agent and as Depositary Bank By Title: Lenders: CITIBANK, N.A. By Name: Title: BARCLAYS BANK PLC By: Name: Title: CANADIAN IMPERIAL BANK OF COMMERCE By Name: Title: TORONTO DOMINION (TEXAS), INC. By: Name: Title: FORTIS CAPITAL CORP. (formerly MeesPierson Capital Corp.) By: Name: Title: UNION BANK OF CALIFORNIA, N.A.. By: Name: Title: BANK ONE, NA By: Name: Title: CONSENT Dated as of July 27, 2000 The undersigned, Northeast Utilities, a Massachusetts voluntary association with reference to the Sponsor Agreement, dated as of March 9, 2000 (the "Sponsor Agreement") in favor of the Administrative Agent and the Lenders parties to the Credit Agreement referred to in the foregoing Amendment, hereby consents to such Amendment and hereby confirms and agrees that (a) notwithstanding the effectiveness of such Amendment, the Sponsor Agreement is, and shall continue to be, in full force and effect and is hereby ratified and confirmed in all respects, except that, on and after the effectiveness of such Amendment, each reference in the Sponsor Agreement to the "Credit Agreement", "thereunder", "thereof" or words of like import and to the Notes "thereunder", "thereof", or words of like import shall mean and be a reference to the Credit Agreement and the Notes respectively, as amended by such Amendment. NORTHEAST UTILITIES By Name: Title: EX-10.54.2 12 0012.txt EXHIBIT 10.54.2 AMENDMENT NO. 2 dated as of November 22, 2000 To CREDIT AGREEMENT dated as of March 9, 2000 Among NORTHEAST GENERATION COMPANY as Borrower and THE LENDERS NAMED HEREIN as Lenders and CITIBANK, N.A. as Administrative Agent and CITIBANK, N.A. as Collateral Agent and CITIBANK, N.A. as Depositary Bank AMENDMENT NO. 2 TO THE CREDIT AGREEMENT Dated as of November 22, 2000 AMENDMENT NO. 2 to the CREDIT AGREEMENT among NORTHEAST GENERATION COMPANY, a Connecticut corporation (the "Borrower"), the banks, financial institutions and other institutional lenders parties to the Credit Agreement referred to below (collectively, the "Lenders") and CITIBANK, N.A., as administrative agent (the "Administrative Agent") for the Lenders, collateral agent for the Secured Parties (the "Collateral Agent") and the depositary bank (the "Depositary Bank"). PRELIMINARY STATEMENTS: (1) The Borrower, the Lenders, the Administrative Agent, the Collateral Agent, and the Depositary Bank have entered into a Credit Agreement dated as of March 9, 2000, as amended by Amendment No 1 dated as of July 27, 2000 (the "Credit Agreement"). Capitalized terms not otherwise defined in this Amendment have the same meanings as specified in the Credit Agreement. (2) The Borrower has requested that the Credit Agreement be amended as hereinafter set forth. (3) The Lenders, the Administrative Agent, the Collateral Agent, and the Depositary Bank are, on the terms and conditions stated below, willing to grant the request of the Borrower. SECTION 1. Amendments to Credit Agreement The Credit Agreement is, effective as of the date hereof and subject to the satisfaction of the conditions precedent set forth in Section 2 of this amendment, hereby amended as follows: (a) The definition of "Annual Operating Budget" in Section 1.01 is amended by adding the following after the words "attached as Exhibit I hereto," in the second line thereof: "or the annual budget for the Borrower for Fiscal Year 2001 delivered pursuant to Section 6.03(q) hereto and reasonably acceptable in form and substance to the Lenders or as provided for in such section if no such budget has been so delivered, as appropriate, in each case (b) The definition of "Excess Cash Flow" in Section 1.01 is deleted in its entirety and replaced with the following: "shall mean for any Excess Cash Flow Payment Date, the excess of (a) all cash receipts of the Borrower (including, but not limited to Revenues, but excluding Net Cash Proceeds) actually received by the Borrower during the period from the prior Excess Cash Flow Payment Date (or the Borrowing Date with respect to the first Excess Cash Flow Payment Date) to the date immediately prior to such Excess Cash Flow Payment Date; provided however that in the case of the November 12, 2000 Excess Cash Flow Payment Date, the period used to measure Excess Cash Flow shall be the period from August 1, 2000 to October 31, 2000, in the case of the February 12, 2001 Excess Cash Flow Payment Date, the period used to measure Excess Cash Flow shall be the period from November 1, 2000 to January 31, 2001, in the case of the May 12, 2001 Excess Cash Flow Payment Date, the period used to measure Excess Cash Flow shall be the period from February 1, 2001 to April 30, 2001, and if the Tranche B Maturity Date is extended to September 28, 2001 as provided in Amendment No. 2 to the Credit Agreement, in the case of the August 12, 2001 Excess Cash Flow Payment Date, the period used to measure Excess Cash Flow shall be the period from May 1, 2001 to July 31, 2001 over (b) the sum (without duplication) of (i) Operating Costs and Permitted Capital Expenditures paid during such period and (ii) Obligations (other than mandatory prepayments pursuant to Section 2.05(b) hereof and payments of interest in respect thereof pursuant to Section 2.06 hereof) arising under the Loan Documents paid during such period. For purposes of this definition, cash receipts shall exclude, to the extent included, any insurance proceeds deposited into the Casualty Account.". (c) The definition of "Excess Cash Flow Payment Date" in Section 1.01 is amended by deleting "and November 12, 2000" at the end thereof and substituting ",November 12, 2000, February 12, 2001, May 12, 2001, and if the Tranche B Maturity Date is extended to September 28, 2001 as provided in Amendment No. 2 to the Credit Agreement herein, August 12, 2001". (d) The definition of "Tranche B Maturity Date" in Section 1.01 is deleted in its entirety and replaced with the following: "means June 29, 2001"; provided however that if and only if the conditions precedent referred to in Section 3 of this Amendment are satisfied; The definition of Tranche B Maturity Date in Section 1.01 shall be deleted in its entirety and replaced with the following: "means September 28, 2001." (e) Section 6.03 is amended by adding at the end thereof a new subsection (q) to read as follows: "Delivery of 2001 Annual Operating Budget. It will deliver to the Administrative Agent, by December 1, 2000, an annual operating budget for Fiscal Year 2001 in the form of the Annual Operating Budget for Fiscal Year 2000 and in substance reasonably acceptable to the Lenders (the "2001 Annual Operating Budget"); provided however that should a 2001 Annual Operating Budget in form and substance reasonably acceptable to the Lenders not be delivered to the Administrative Agent by January 1, 2001, then until it is, for each of January and February, 2001 the Annual Operating Budget for December, 2000 shall be followed, and for each month from March to September, 2001, the Annual Operating Budget for the corresponding month in the budget for Fiscal Year 2000 shall be followed.". SECTION 2. Conditions of Effectiveness This Amendment shall become effective as of the date first above written when, and only when the Administrative Agent shall have received (i) on behalf of each Lender, an amendment fee equal to .15 percent of the outstanding Tranche B Advances owing to such Lender; (ii) copies of an amendment to the Tranche B Mortgage reflecting an extension of the Tranche B Maturity Date until September 28, 2001 duly executed by the Borrower, together with (a) evidence that (1) counterparts of such amendments to the Mortgages have been duly recorded in all filing or recording offices that the Collateral Agent may deem appropriate and (2) all filing and recording taxes and fees in respect thereof have been paid and (b) such confirmation from the Title Companies as shall be satisfactory to the Collateral Agent that the recording of such amendments to the mortgages does not impair the validity, enforceability, or priority of the lien of the mortgages; and (iii) counterparts of this Amendment executed by the Borrower, the Lenders, the Collateral Agent and the Depositary Bank, together with the consent attached hereto executed by the Sponsor provided that no Default or Event of Default shall have occurred and be continuing at such time. This Amendment is subject to the provisions of Section 9.01 of the Credit Agreement. If the aforementioned conditions are not satisfied on or before November 22, 2000, then this amendment shall terminate and have no further effect other than Section 5 and Section 7. SECTION 3. Conditions to Further Extension The Tranche B Maturity Date shall be further extended to September 28, 2001 effective as of June 22, 2001, as set forth in Section 1 above, if and only if (i) no Default or Event of Default shall have occurred and be continuing on June 22, 2001, (ii) prior to June 22, 2001 the Administrative Agent shall have received on behalf of each Lender, an amendment fee equal to .10 percent of the outstanding Tranche B Advances owing to such Lender on the date such fee is paid, and (iii) the Administrative Agent shall have received, by May 30, 2001, notice of the Borrower's intent to extend the Tranche B Maturity Date to September 28, 2001. SECTION 4. Reference to and Effect on the Credit Agreement and the Notes (a) On and after the effectiveness of this Amendment, each reference in the Credit Agreement to "this Agreement", "hereunder", "hereof" or words of like import referring to the Credit Agreement, and each reference in the Notes to "the Credit Agreement", "thereunder", "thereof" or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement, as amended by this Amendment. (b) The Credit Agreement and the Notes as specifically amended by this Amendment, are and shall continue to be in full force and effect and are hereby in all respects ratified and confirmed. (c) The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of any Lender, or the Administrative Agent, the Collateral Agent, or the Depositary Bank under the Credit Agreement, nor constitute a waiver of any provision of the Credit Agreement. SECTION 5. Costs. The Borrower agrees to pay on demand all costs and expenses of the Administrative Agent in connection with the preparation, execution and delivery of this Amendment and the other instruments and documents to be delivered hereunder (including, without limitation, the reasonable fees and expenses of counsel for the Administrative Agent) in accordance with the terms of Section 9.04 of the Credit Agreement. SECTION 6. Execution in Counterparts This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute but one and the same agreement. Delivery of an executed counterpart of a signature page to this Amendment by telecopier shall be effective as delivery of a manually executed counterpart of this Amendment. SECTION 7. Governing Law This Amendment shall be governed by, and construed in accordance with, the laws of the State of New York. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly authorized, as of the date first above written. (Signatures Commence on the Next Page) NORTHEAST GENERATION COMPANY By Title: CITIBANK, N.A., as Administrative Agent By Title: CITIBANK, N.A. As Collateral Agent and as Depositary Bank By Title: Lenders: CITIBANK, N.A. By Name: Title: BARCLAYS BANK PLC By: Name: Title: CANADIAN IMPERIAL BANK OF COMMERCE By Name: Title: TORONTO DOMINION (TEXAS), INC. By: Name: Title: FORTIS CAPITAL CORP. (formerly MeesPierson Capital Corp.) By: Name: Title: UNION BANK OF CALIFORNIA, N.A.. By: Name: Title: BANK ONE, NA By: Name: Title: CONSENT Dated as of November[22], 2000 The undersigned, Northeast Utilities, a Massachusetts voluntary association with reference to the Sponsor Agreement, dated as of March 9, 2000 (the "Sponsor Agreement") in favor of the Administrative Agent and the Lenders parties to the Credit Agreement referred to in the foregoing Amendment, hereby consents to such Amendment and hereby confirms and agrees that (a) notwithstanding the effectiveness of such Amendment, the Sponsor Agreement is, and shall continue to be, in full force and effect and is hereby ratified and confirmed in all respects, except that, on and after the effectiveness of such Amendment, each reference in the Sponsor Agreement to the "Credit Agreement", "thereunder", "thereof" or words of like import and to the Notes "thereunder", "thereof", or words of like import shall mean and be a reference to the Credit Agreement and the Notes respectively, as amended by such Amendment. No Trustee or shareholder of Northeast Utilities shall be held to any liability whatever for any obligations under this Consent or the Sponsor Agreement, and this Consent shall not be enforceable against any such Trustee in their or his or her individual capacities or capacity. This Consent shall be enforceable against the Trustees of Northeast Utilities only as such, and every person, firm, association, trust or corporation having any claim or demand arising under this Consent and relating to Northeast Utilities, its shareholders, or Trustees shall look solely to the trust estate of Northeast Utilities for the payment or satisfaction thereof. NORTHEAST UTILITIES By Name: Title: EX-10.55 13 0013.txt EXHIBIT 10.55 THIS TRANCHE B MORTGAGE, ASSIGNMENT OF LEASES AND RENTS, SECURITY AGREEMENT AND FIXTURE FILING (as the same may from time to time be extended, spread, split, consolidated, amended, modified, supplemented, restated and renewed, this "Mortgage") made as of March , 2000 by NORTHEAST GENERATION COMPANY, a Connecticut corporation ("Mortgagor"), having its principal office at 107 Selden Street, Berlin, Connecticut 06037 to CITIBANK, N.A., a national banking association ("Citibank") having an address at 399 Park Avenue, New York, New York 10005, as collateral agent (Citibank in its capacity as collateral agent and any successor collateral agent appointed in accordance with the Credit Agreement (as hereinafter defined), "Agent") and Depositary Bank for the Lenders (as hereinafter defined), Agent being referred to herein as "Mortgagee". W I T N E S S E T H: WHEREAS, Mortgagor has entered into that certain Credit Agreement (said credit agreement, as it may be amended, modified or supplemented from time to time, being the "Credit Agreement", a copy of which may be examined at reasonable times at the office of Agent by persons who do or will hold an interest in the Land (as hereinafter defined) or the Improvements (as hereinafter defined)), dated as of March , 2000, with the lenders listed on Schedule 1 attached hereto and made a part hereof (said lenders and any lenders that may hereafter become parties to the Credit Agreement, being collectively the "Lenders" and individually a "Lender") and Citibank, N.A., as Collateral Agent, Administrative Agent and Depositary Bank; WHEREAS, pursuant to the Credit Agreement and subject to the terms and conditions therein set forth, the Lenders have agreed to make Advances in the aggregate amount of 865,500,000 dollars, comprised of the Tranche A Advance (as defined in and to be made pursuant to Section 2.01(a) of the Credit Agreement) of up to 435,500,000 dollars and the Tranche B Advance (as defined in and to be made pursuant to Section 2.01(b) of the Credit Agreement) of up to 430,000,000 dollars; WHEREAS, to evidence such indebtedness, Mortgagor has executed and delivered the Credit Agreement and will execute and deliver various promissory notes (each a "Note" and collectively, the "Notes") to the order of each of the Lenders in the amount of its Commitment, and each issued pursuant to the Credit Agreement; WHEREAS, pursuant to the Credit Agreement, Mortgagor may enter into Permitted Hedges with Permitted Hedge Providers (which are also Lenders); WHEREAS, the total indebtedness and liabilities to be secured by this Mortgage are as follows (all such indebtedness and liabilities or the instruments evidencing same, as applicable, being herein collectively called the "Obligations"): (i) the Tranche B Advance in the aggregate principal amount of 430,000,000 dollars, or so much thereof that may be advanced by the Lenders as the Tranche B Advance under the Credit Agreement; plus (ii) interest on the principal amount of the amount so advanced by the Lenders under the Credit Agreement, as provided in the Credit Agreement; plus (iii) all other amounts payable to the Tranche B Secured Parties and all 1 other obligations of Mortgagor, including the obligations of Mortgagor to the Permitted Hedge Providers now or hereafter existing under the Permitted Hedges, under the Credit Agreement and the Notes (but expressly excluding the Tranche A Obligations), this Mortgage and any other document which relates to any of the Credit Agreement or the Notes or any of the security therefor (all of the foregoing documents, as they may be amended, modified, supplemented, extended, restated or renewed from time to time, collectively, the "Loan Documents"); and WHEREAS, it has been agreed that the payment and performance of the Obligations shall be secured by a mortgage, assignment of leases and rents, security agreement and fixture filing, as applicable, of certain property as hereinafter identified. NOW, THEREFORE, in consideration of the premises and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, to secure the punctual payment by Mortgagor when due, whether at stated maturity, by acceleration or otherwise, of the Obligations and the performance and observance of all other covenants, obligations and liabilities of Mortgagor under this Mortgage, Mortgagor does hereby grant, bargain, sell, mortgage, warrant, convey, alien, remise, release, assign, transfer, set over, deliver, confirm and convey unto Mortgagee, upon the terms and conditions of this Mortgage, with power of sale (to the extent permitted by law) and right of entry as provided hereinbelow, each and all of the real and other properties described in the Granting Clauses herein (collectively, the "Mortgaged Property"). GRANTING CLAUSES All the estate, right, title and interest of Mortgagor in, to and under, or derived from, the plots, pieces and parcels of land more particularly described in Exhibit A attached hereto (the "Land"); TOGETHER with the tenements, easements, hereditaments, appurtenances and all the estates and rights of Mortgagor in and to the Land; TOGETHER with all buildings and improvements now or hereafter located on the Land (hereinafter collectively referred to as the "Improvements") and all right, title and interest, if any, of Mortgagor in and to the streets, roads, sidewalks and alleys abutting the Land, and strips and gores within or adjoining the Land, the air space and right to use said air space above the Land and any transferable development or similar rights appurtenant thereto, all rights of ingress and egress by motor vehicles to parking facilities on or within the Land, all easements now or hereafter affecting the Land, royalties and all rights appertaining to the use and enjoyment of the Land, including alley, drainage, flowage, mineral, water, riparian, oil and gas rights; TOGETHER with all property, tangible and intangible, and all additions thereto and substitutions or replacements thereof owned by Mortgagor and now or hereafter contained in, or used in connection with the Premises or placed on any part thereof though not attached thereto, to the extent the same constitutes real property in the state in which the Mortgaged Property is located (all of the foregoing, including the items hereinafter enumerated, collectively referred to as the "Equipment"), including turbines, control machinery and other equipment related to the generation of hydroelectric 2 power, all removable window and floor coverings, furniture and furnishings, heating, lighting, plumbing, ventilating, air conditioning, refrigerating, incinerating and elevator plants, cooking facilities, vacuum cleaning systems, call systems, sprinkler systems and other fire prevention and extinguishing apparatus and materials, motors, machinery, pipes, appliances, equipment, fittings and fixtures (the Land, together with the Improvements and the Equipment, are hereinafter collectively referred to as the "Premises"); TOGETHER with all leases, subleases, lettings, and licenses (including all Neighboring Landowner Agreements) of, and all other contracts, bonds and agreements affecting the Premises or any part thereof now or hereafter entered into, and all amendments, modifications, supplements, additions, extensions and renewals thereof (all of the foregoing hereinafter collectively referred to as the "Leases"), and all right, title and interest of Mortgagor thereunder, including cash and securities deposited thereunder (as down payments, security deposits or otherwise), the right to receive and collect the rents, security deposits, income, proceeds, earnings, royalties, revenues, issues and profits payable thereunder and the rights to enforce, whether at law or in equity or by any other means, all provisions and options thereof or thereunder (all of the foregoing hereinafter collectively referred to as the "Rents") and the right to apply the same to the payment and performance of the Obligations; TOGETHER with all rights, dividends and/or claims of any kind whatsoever relating to the Premises (including damage, secured, unsecured, lien, priority and administration claims); together with the right to take any action or file any papers or process in any court of competent jurisdiction, which may in the opinion of Mortgagee be necessary to preserve, protect, or enforce such rights or claims, including the filing of any proof of claim in any insolvency proceeding under any state, Federal or other laws and any rights, claims or awards accruing to or to be paid to Mortgagor in its capacity as landlord under any Lease; TOGETHER with all unearned premiums, accrued, accruing or to accrue under insurance policies now or hereafter obtained by Mortgagor and relating to the Premises and all proceeds of the conversion, voluntary or involuntary, of the Premises into cash or liquidated claims, including proceeds of hazard and title insurance and all awards and compensation heretofore and hereafter made to the present and all subsequent owners of the Premises by any governmental or other lawful authorities for the taking by eminent domain, condemnation or otherwise, of all or any part of the Premises or any easement therein, including awards for any change of grade of streets; TOGETHER with all right, title and interest of Mortgagor in and to all extensions, improvements, betterments, renewals, substitutes and replacements of, and all additions and appurtenances to, any of the foregoing hereafter acquired by, or released to, Mortgagor or constructed, assembled or placed by Mortgagor on the Premises and all conversions of the security constituted thereby, immediately upon such acquisition, release, construction, assemblage, placement or conversion, as the case may be, and in each such case, without any further mortgage, conveyance, assignment or other act by Mortgagor, shall become subject to the lien of this Mortgage as fully and completely, and with the same effect, as though now owned by Mortgagor and specifically described herein. TO HAVE AND TO HOLD the Mortgaged Property unto Mortgagee, and its respective 3 successors and assigns, forever. This mortgage is granted with MORTGAGE COVENANTS. ARTICLE I Representations, Warranties and Covenants of Mortgagor Representations, Warranties and Covenants of Mortgagor SECTION 1.01. Payment of Obligations. Mortgagor shall punctually pay when due, and timely perform, the Obligations. SECTION 1.02. Warranty of Title. Mortgagor warrants that it has good and marketable title to the Premises, in each case free and clear of all liens, charges and encumbrances of every kind and character, subject only to (i) the encumbrances identified on Exhibit B-2 of each of those certain title insurance policies of Commonwealth Land Title Insurance Company identified as Policy Numbers G32-592535 and G32-7611866 (as endorsed pursuant to endorsement numbers 100183877 and 50570722, respectively, by First American Title Insurance Company), (ii) Liens created under the Loan Documents, (iii) Permitted Liens, (iv) other Liens incurred in the ordinary course of business otherwise than to secure Debt, and (v) any extension, renewal or replacement of the Liens set forth in the foregoing clauses (ii), (iii) and (iv), provided, however, that the principal amount of Debt secured thereby shall not, at the time of such extension, renewal or replacement, exceed the principal amount of Debt so secured and that such extension, renewal, or replacement shall be limited to all or a part of the Mortgaged Property which secured the Lien so extended, renewed or replaced (all of the foregoing, the "Permitted Encumbrances"); has and shall continue to have full power and lawful authority to encumber and convey the Premises as provided herein; owns all other Mortgaged Property free and clear of all liens, charges and encumbrances of every kind and character, subject only to the Permitted Encumbrances; this Mortgage is and shall continue to remain a valid and enforceable first mortgage lien on and security interest in the Mortgaged Property, subject only to the Permitted Encumbrances. Mortgagor further covenants that it shall preserve such title and shall forever warrant and defend the title to the Mortgaged Property unto Mortgagee against all lawful claims whatsoever and shall forever warrant and defend the validity, enforceability and priority of the lien of this Mortgage against the claims of all persons and parties whomsoever. Mortgagor covenants that it shall, at Mortgagor's sole cost and expense and at the request of Mortgagee, (a) promptly correct any defect or error which may be discovered in the Loan Documents, (b) promptly do, execute, acknowledge and deliver, and record and re-record, file and re-file and register and re-register, any and all such instruments as may be necessary from time to time in order to perfect and protect the lien of, and otherwise implement the terms of, this Mortgage and (c) promptly furnish Mortgagee with evidence satisfactory to Mortgagee of every such recording, filing or registration. SECTION 1.03. Operation and Maintenance. (a) Repair and Maintenance. Mortgagor shall operate and maintain the Premises in good order, repair and operating condition, ordinary wear and tear excepted, shall promptly make all necessary repairs, restorations, renewals, replacements, additions and improvements thereto, 4 interior and exterior, structural and nonstructural, foreseen and unforeseen, or otherwise necessary to insure that the same as part of the security under this Mortgage shall not in any way be diminished or impaired, and shall not cause or allow the Premises to be misused, wasted or to deteriorate. No new building, structure, facility or other improvement that would diminish or impair the value of the Premises shall be constructed on the Land without Mortgagee's prior written consent in the case of each such proposed construction. (b) Equipment. Mortgagor shall keep and maintain the Equipment and Inventory (as defined in the Tranche B Borrower Security Agreement) in accordance with Section 10 of the Tranche B Borrower Security Agreement. (c) Zoning; Title Matters. Mortgagor shall not, without the prior written consent of Mortgagee: (i) initiate or support any zoning reclassification of any portion of the Premises upon which an Improvement owned by Mortgagor is located or which is otherwise essential to the generation of electricity on the Mortgaged Property (such portion, a AMaterial Portion"), seek any variance under existing zoning ordinances applicable to any Material Portion of the Premises or use or permit the use of any Material Portion of the Premises in a manner which would result in such use becoming a non-conforming use under applicable zoning ordinances; (ii) modify or amend any of the Permitted Encumbrances in any material respect; (iii) impose any restrictive covenants or encumbrances upon any Material Portion of the Premises, execute or file any subdivision plat affecting any Material Portion of the Premises or consent to the annexation of any Material Portion of the Premises to any municipality; or (iv) permit or suffer any Material Portion of the Premises to be used by the public or any person in such manner as might make reasonably possible a claim of adverse usage or possession or of any implied dedication or easement. (d) Status of the Premises. (i) The Premises is not located in an area identified by the Secretary of Housing and Urban Development or a successor thereto as an area having special flood hazards pursuant to the terms of the National Flood Insurance Act of 1968, or the Flood Disaster Protection Act of 1973, as amended, or any successor law; or if the Premises is located in such an area, Mortgagor shall obtain and maintain insurance against damage or loss by flood on such basis and in such amounts as shall be required by Mortgagee; (ii) the Premises is served by all utilities required for the current use thereof; (iii) Mortgagor has access to the Land and the Improvements by public roads or by irrevocable easement approved by Mortgagee; and (iv) there is no condemnation or similar proceeding pending or, to the best knowledge of Mortgagor, threatened affecting any part of the Premises that might materially adversely affect the Premises. (e) Use. Mortgagor shall use the Premises for substantially the same use as in effect as of the date hereof and for no other use unless consented to in writing by Mortgagee. (f) Compliance with Terms of Leases. Mortgagor shall make all payments and otherwise perform all obligations in respect of all Leases to which it is a party lessee, keep such Leases in full force and effect and not allow such Leases to lapse or be terminated or any rights to renew such leases to be forfeited or canceled, notify the Mortgagee of any default by any party with respect to such Leases and cooperate with the Mortgagee in all respects to cure any such default, except, in any case, where the failure to do so, either individually or in the aggregate, would not reasonably be expected to 5 have a Material Adverse Effect. SECTION 1.04. Insurance. Mortgagor shall maintain in effect insurance in the amounts and otherwise as required pursuant to Section 6.01(e) of the Credit Agreement, which Section 6.01(e) of the Credit Agreement is incorporated herein by reference. SECTION 1.05. Liens and Liabilities. (a) Discharge of Liens. Mortgagor shall pay, bond or otherwise discharge, from time to time when the same shall become due, all claims and demands of mechanics, materialmen, laborers and others which, if unpaid, might result in, or permit the creation of, a lien on the Mortgaged Property. (b) Creation of Liens. Mortgagor shall not, without Mortgagee's consent, create, place or permit to be created or placed or allow to remain, and shall discharge and release within ten (10) days of the placing thereof, any deed of trust, mortgage, trust deed, voluntary or involuntary lien, security interest or other encumbrance against or covering the Mortgaged Property, other than the Permitted Encumbrances, whether or not subordinate hereto. (c) No Consent. Nothing in this Mortgage shall be deemed or construed in any way as constituting the consent or request by Mortgagee, express or implied, to any contractor, subcontractor, laborer, mechanic or materialman for the performance of any labor or the furnishing of any material for any improvement, construction, alteration or repair of the Premises. Mortgagor further agrees that Mortgagee does not stand in any fiduciary relationship to Mortgagor. SECTION 1.06. Taxes and Other Charges. (a) Taxes on the Premises. Mortgagor shall promptly pay when due and before any penalty or interest may be added thereto, all taxes, assessments, vault, water and sewer rents, rates, charges and assessments, levies, permits, inspection and license fees and other governmental and quasi-governmental charges and any penalties or interest for non-payment thereof, heretofore or hereafter imposed, or which may become a lien, upon the Mortgaged Property or arising with respect to the occupancy, use or possession thereof (collectively, "Impositions"). Mortgagor shall also pay any penalty, interest or cost for non-payment of Impositions which may become due and payable. (b) Receipts. Mortgagor shall furnish to Mortgagee upon Mortgagee's request, proof of payment at the time same is made, and thereafter, upon receipt, validated receipts showing payment in full of all Impositions. (c) Increased Costs. In the event of the enactment after the date hereof of any law in the state in which the Mortgaged Property is located or any other governmental entity deducting from the value of the Mortgaged Property for the purpose of taxation any lien or security interest thereon, or changing in any way the laws for the taxation of mortgages, deeds of trust or other liens or debts secured thereby, or the manner of collection of such taxes, so as to affect this Mortgage, the Obligations, Mortgagee or the holders of the Obligations, then, and in such event, Mortgagor shall, on demand, pay to Mortgagee or such holder, or reimburse Mortgagee or such holder for payment of, all taxes, assessments, charges or liens for which Mortgagee or such holder is or may be liable as a result thereof, provided that if any such payment or reimbursement shall be unlawful or would constitute usury or render the Obligations wholly or partially usurious under applicable law, 6 then Mortgagee may, at its option, declare the Obligations immediately due and payable or require Mortgagor to pay or reimburse Mortgagee for payment of the lawful and non-usurious portion thereof. SECTION 1.07. Damage and Destruction. (a) Mortgagor's Obligations. In the event of any damage to or loss or destruction of the Premises, Mortgagor shall (i) promptly notify Mortgagee of such event and take such steps as shall be necessary to preserve any undamaged portion of the Premises and (ii) unless otherwise instructed by Mortgagee and so long as any insurance proceeds paid to Mortgagee hereunder in respect of such damage or destruction are made available by Mortgagee to Mortgagor (but without imposing on Mortgagor any obligation to make such proceeds available to Mortgagor other than as expressly required pursuant to Section 4.03(b) of the Credit Agreement), promptly commence and diligently pursue to completion the restoration, replacement and rebuilding of the Premises to the condition of the Premises affected thereby immediately prior to such damage, loss or destruction in accordance with plans and specifications approved, and with other provisions for the preservation of the security hereunder established, by Mortgagee. (b) Mortgagee's Rights; Application of Proceeds. In the event that (i) any portion of the Premises is so damaged, destroyed or lost, (ii) such damage, destruction or loss is covered, in whole or in part, by insurance required by Section 1.04 hereof, and (iii) a claim is made by Mortgagee or Mortgager against such insurance policy, then the proceeds of such insurance policy shall be applied as provided in Section 4.03(b) of the Credit Agreement. (c) Effect on the Obligations. Notwithstanding any loss, damage or destruction referred to in this Section 1.07, Mortgagor shall continue to pay and perform the Obligations as provided herein. Any reduction in the Obligations resulting from such application shall be deemed to take effect only on the date of receipt by Mortgagee of such insurance proceeds and application against the Obligations, provided that if prior to the receipt by Mortgagee of such insurance proceeds the Mortgaged Property shall have been sold on foreclosure of this Mortgage, or shall have been transferred by deed in lieu of foreclosure of this Mortgage, Mortgagee shall have the right to receive the same to the extent of any deficiency found to be due upon such sale, with interest thereon at the rate and as provided in the Credit Agreement together with attorneys' fees and disbursements incurred by Mortgagee in connection with the collection thereof. SECTION 1.08. Condemnation. (a) Mortgagor's Obligations; Proceedings. Mortgagor, promptly upon obtaining knowledge of any pending or threatened institution of any proceedings for the condemnation of the Premises, or of any right of eminent domain, or of any other proceedings arising out of injury or damage to or decrease in the value of the Premises, including a change in grade of any street, shall notify Mortgagee of the threat or pendency thereof. Mortgagee may participate in any such proceedings, and Mortgagor from time to time shall execute and deliver to Mortgagee all instruments requested by Mortgagee or as may be required to permit such participation. Mortgagor shall, at its expense, diligently prosecute any such proceedings, shall deliver to Mortgagee copies of all papers served in connection therewith and shall consult and cooperate with Mortgagee, its attorneys and agents, in the carrying on and defense of any such proceedings; provided that no settlement of any such proceeding shall be made by Mortgagor without Mortgagee's consent, which consent shall not be unreasonably withheld. 7 (b) Trustee's and Mortgagee's Rights to Proceeds. All proceeds of condemnation awards or proceeds of sale in lieu of condemnation, and all judgments, decrees and awards for injury or damage to the Premises greater than $5,000,000 (collectively, "Awards") are hereby assigned and shall be paid to Mortgagee. Mortgagor authorizes Mortgagee to collect and receive the same, to give receipts and acquittances therefor, and to appeal from any Awards. (c) Application of Proceeds. Mortgagee shall have the right to apply any Awards, first, to reimburse Mortgagee for all reasonable costs and expenses, and, second, the remainder thereof in the manner provided in Section 4.03(b) of the Credit Agreement as if such Awards were insurance proceeds. In the event that Mortgagor shall have received all or any portion of such Awards, Mortgagor, upon demand from Mortgagee, shall pay to Mortgagee an amount equal to the amount so received by Mortgagor, to be applied as Mortgagee shall have the right pursuant to this Section 1.08(c). Notwithstanding anything herein or at law or in equity to the contrary, none of the Awards paid to Mortgagee under this Section 1.08(c) shall be deemed trust funds and Mortgagee shall be entitled to dispose of the same as provided in this Section 1.08(c). (d) Effect on the Obligations. Notwithstanding any condemnation, taking or other proceeding referred to in this Section 1.08, Mortgagor shall continue to pay and perform the Obligations as provided herein. Any reduction in the Obligations resulting from such application shall be deemed to take effect only on the date of receipt by Mortgagee of such Awards and application against the Obligations, provided that if prior to the receipt by Mortgagee of such Awards the Mortgaged Property shall have been sold on foreclosure of this Mortgage, or shall have been transferred by deed in lieu of foreclosure of this Mortgage, Mortgagee shall have the right to receive the same to the extent of any deficiency found to be due upon such sale, with interest thereon at the rate and as provided in the Credit Agreement together with attorneys' fees and disbursements incurred by Mortgagee in connection with the collection thereof. SECTION 1.09. Contest. Notwithstanding anything to the contrary contained in Section 1.03(c), Section 1.05 or Section 1.06 hereof, Mortgagor shall have the right to contest in good faith and at its own expense the validity or applicability of any duty or obligation described in Section 1.03(c) hereof, the validity of any lien, encumbrance, charge or security referred to in Section 1.05 hereof and any Imposition imposed upon the Premises (a "Contest") by an appropriate legal proceeding which proceeding must operate to prevent the collection of such Impositions or other realization thereon and the sale or forfeiture of the Mortgaged Property or any part thereof to satisfy the same; provided that during the pendency of such Contest, Mortgagor shall provide security reasonably satisfactory to Mortgagee (which security may be in the form of a bond or undertaking deposited into a court, in either case sufficient to remove the lien, encumbrance, charge or security in question), assuring the discharge of Mortgagor's obligations that are the subject of such Contest ("Contested Impositions") and of any additional interest, charge, penalty or expense arising from or incurred as a result of such Contest; and provided, further, that if at any time payment of such Contested Impositions shall become necessary to prevent (a) the delivery of a tax deed conveying the Mortgaged Property because of non-payment or (b) the imposition of any civil or criminal penalty or liability on Mortgagee or the holders of the Obligations, Mortgagor shall pay the same in sufficient time to avoid the delivery of such 8 tax deed or the imposition of any such penalty or liability. ARTICLE II Assignment of Leases, Rents and Other Sums SECTION 2.01. Assignment. (a) Mortgagor hereby absolutely and presently bargains, sells, transfers, assigns and sets over to Mortgagee, as further security for the payment of the Obligations, all of its right, title and interest in and to the Leases and the Rents payable thereunder and all rights of Mortgagor thereunder and any and all deposits held as security under the Leases, whether before or after foreclosure or during the full period of redemption, if any, and shall, upon demand, deliver to Mortgagee an executed counterpart of each Lease. The assignment of the Leases and Rents, and of the aforesaid rights with respect thereto, is intended to be and is an absolute present assignment from Mortgagor to Mortgagee and not merely the passing of a security interest. Such assignment and grant shall continue in effect until the Obligations are paid, the execution of this Mortgage constituting and evidencing the irrevocable consent of Mortgagor to the entry upon and taking possession of the Premises by Mortgagee pursuant to such grant, whether foreclosure has been instituted or not and without applying for a receiver. Until the occurrence of an Event of Default hereunder, Mortgagor shall be entitled, subject to any provisions of the Loan Documents and the Permitted Hedges providing otherwise, to collect and receive the Rents and agrees to apply the same in the ordinary course of business. Such right of Mortgagor to collect and receive said Rents shall be automatically revoked upon the occurrence of an Event of Default and thereafter Mortgagee shall have the right and authority to exercise any of the rights or remedies referred to or set forth in Article V hereof. In addition, upon such an Event of Default, Mortgagor shall promptly pay to Mortgagee (i) all rent prepayments and security or other deposits paid to Mortgagor pursuant to any lease assigned hereunder and (ii) all charges for services or facilities or for escalation which were paid pursuant to any such Lease to the extent allocable to any period from and after such Event of Default. Nothing contained in this Section 2.01(a) shall be construed to bind Mortgagee to the performance of any of the covenants, conditions or provisions contained in any Lease or otherwise to impose any obligation on Mortgagee prior to accepting receipt of such Rent (including any liability under the covenant of quiet enjoyment contained in any Lease or under any applicable law in the event that any tenant shall have been joined as a party defendant in any action to foreclose this Mortgage and shall have been barred and foreclosed thereby of all right, title and interest and equity of redemption in the Premises), except that Mortgagee shall be accountable for any money actually received pursuant to such assignment. Mortgagor hereby further grants to Mortgagee the right, after the occurrence of an Event of Default hereunder, to notify the tenant under any Lease of the assignment thereof and (1) to demand that the tenant under any Lease pay all amounts due thereunder directly to Mortgagee, (2) to enter upon and take possession of the Premises for the purpose of collecting the Rents, (3) to dispossess by the usual summary proceedings any tenant defaulting in the payment thereof, (4) to let the Premises, or any part thereof, and (5) to apply the Rents, after payment of all necessary charges and expenses, on account of the Obligations. (b) Mortgagor shall, as and when requested from time to time by Mortgagee, 9 execute, acknowledge and deliver to Mortgagee, in form reasonably acceptable to Mortgagee and Mortgagor, one or more general or specific assignments of the lessor's interest under any Lease. Mortgagor shall, on demand, pay to Mortgagee, or reimburse Mortgagee for the payment of any reasonable costs or expenses incurred in connection with the preparation or recording of any such assignment. SECTION 2.02. Leases and Rents. (a) Mortgagor shall (i) perform or cause to be performed all the lessor's obligations under any Lease, (ii) enforce (including the termination and cancellation of any Lease, so long as the same is a bona fide enforcement of Mortgagor's right as lessor under any such Lease and such termination or cancellation, either by itself or in the aggregate with other terminations and cancellations, shall not diminish or impair the security of this Mortgage) the performance by the lessee under its respective Lease of all of said lessee's obligations thereunder, (iii) give Mortgagee prompt notice and a copy of any notice of default, event of default, termination or cancellation sent or received by Mortgagor in respect of any Lease producing an annual income to Mortgagor of $100,000 or more (such Lease, a AMaterial Lease"); but nothing contained herein shall preclude Mortgagor from modifying, supplementing or amending any existing Lease or preclude Mortgagor from entering, subject to Section 2.02(b) hereof, into additional Leases which may, from time to time, be modified, supplemented, amended, terminated or cancelled by Mortgagor subject to the provisions of this Section 2.02(a). (b) Mortgagor agrees that any Lease, the termination of which could reasonably be expected to have a Material Adverse Effect, shall contain the following provision: A[Tenant] acknowledges and agrees that this [Lease] is subject and subordinate to that certain Tranche B Mortgage, Assignment of Leases and Rents, Security Agreement and Fixture Filing, dated as of March __, 2000, made by [Landlord] in favor of Citibank, N.A. as collateral agent for the lenders listed therein (together with any amendment, assignment or other modification thereof made at any time, the AMortgage"), such subordination being self-operative and requiring no further instrument of subordination. If at any time the mortgagee under the Mortgage (together with successors and assigns of such mortgagee, AMortgagee") or any other person or the successors or assigns of any of the foregoing shall succeed to the rights of [Landlord] (any such successor, a ASuccessor Landlord"), then [Tenant] shall, at the election and upon the request of any Successor Landlord, fully and completely attorn to and recognize such Successor Landlord as the landlord under this [Lease] upon the then executory terms of this [Lease], except that such Successor Landlord shall not be (a) liable for any act or omission of any previous [landlord] under this [Lease], (b) obligated to repair, replace, rebuild or restore any portion of the [premises demised under the Lease] in the event of damage, destruction or taking by eminent domain, (c) subject to any offset or defense which [Tenant] may have against any previous [landlord] under this [Lease], (d) bound by any amendment or modification of the [Lease] unless Mortgagee has approved such amendment or modification in advance, and (e) obligated to perform any work in the [premises demised under the Lease] other than work that is required to be performed under the [Lease]. If any act or omission by [Landlord] shall give [Tenant] the right, immediately or after the lapse of time, to cancel or terminate this [Lease] in whole or in part or to claim such cancellation or termination on the basis of a partial or total eviction, [Tenant] shall not exercise any such right until (1) it shall have given written notice of such act or omission to Mortgagee, and (2) 10 a reasonable period for remedying such act or omission shall have elapsed following such notice and following the time when Mortgagee shall have become entitled under this Mortgage to remedy the same." (c) (i) Except as provided in Section 2.02(a) hereof, Mortgagor shall not, without Mortgagee's consent, (A) assign, mortgage, pledge or otherwise transfer, dispose of or encumber, whether by operation of law or otherwise, any Lease or the Rents, (B) accept or permit the acceptance of a prepayment of any amounts payable under such Lease for more than one month in advance of the due date therefor, (C) enter into, amend, modify, cancel, terminate or accept a surrender of any Lease or (D) enter into any Lease (1) with Mortgagor or any affiliate of Mortgagor or its constituent partners or (2) which would be a "disqualified lease", as defined in Section ' 168(h)(1)(B)(ii) of the Internal Revenue Code of 1986, as amended. (ii) Supplementing the provisions of Section 2.02(c)(i) hereof, if the lessee under any Lease (or any receiver, trustee, custodian or other party who succeeds to the rights of any lessee) rejects or disaffirms such Lease pursuant to any bankruptcy law, Mortgagor hereby assigns to Mortgagee the proceeds of any claims (including the right to retain or apply any security deposits) that Mortgagor may have against the lessee (or receiver, trustee, custodian or other party who succeeds to the rights of any lessee) and any guarantor of any of the Leases, under any one or more of the Leases or any guaranty thereof based upon any breach by such lessee of the terms and provisions of the applicable Lease (including any claim that Mortgagor may have by reason of a termination, rejection or disaffirmance of such Lease pursuant to any bankruptcy law), and the use and occupancy of the premises demised thereby, whether or not pursuant to the applicable Lease (including any claim for use and occupancy arising under any bankruptcy law). Mortgagor, immediately upon obtaining knowledge of any such breach or use by any such lessee, shall notify Mortgagee of any such breach or use. Except in respect of any Lease that is not a Material Lease (in which case Mortgagor shall proceed in Mortgagor's and Mortgagee's behalf pursuant to Section 2.02(c)(ii)(B) hereof), Mortgagee shall have the sole right to elect, either: (A) to proceed against such lessee or guarantor as if it were the named lessor thereunder, in Mortgagor's name or in Mortgagee's name as agent for Mortgagor, and Mortgagor agrees to cooperate with Mortgagee in such action and shall execute any and all documents reasonably required in furtherance of such action; or (B) to have Mortgagor proceed in Mortgagor's and Mortgagee's behalf in which event Mortgagee may participate in any such proceedings, and Mortgagor from time to time shall deliver to Mortgagee all instruments reasonably requested by Mortgagee or as may be required to permit such participation. Mortgagor shall, at its expense, diligently prosecute any such proceedings, shall deliver to Mortgagee copies of all papers served in connection therewith and shall consult and cooperate with Mortgagee, its attorneys and agents, in the carrying on and defense of any such proceedings; provided that no settlement of any such proceeding shall be made by Mortgagor without Mortgagee's consent. ARTICLE III Additional Advances; Expenses; Indemnity 11 SECTION 3.01. Additional Advances and Disbursements. (a) Mortgagor agrees that if an Event of Default occurs hereunder, then Mortgagee shall have the right without notice to Mortgagor to advance all or any part of amounts owing or to perform any or all required actions. No such advance or performance shall be deemed to have cured such default by Mortgagor or any Event of Default with respect thereto. All sums advanced and all expenses incurred by Mortgagee in connection with such advances or actions, and all other sums advanced or expenses incurred by Mortgagee hereunder or under applicable law (whether required or optional and whether indemnified hereunder or not) shall be part of the Obligations, shall bear interest at the rate and as provided in the Credit Agreement and shall be secured by this Mortgage. (b) This Mortgage secures not only existing indebtedness, but also future or additional protective advances made in each case pursuant hereto or to the Credit Agreement, the Permitted Hedges, if any, whether such advances are obligatory or optional. SECTION 3.02. Other Expenses. Mortgagor shall pay or, within ten (10) days of demand therefor, reimburse Mortgagee or any holder of the Obligations for the payment of any and all reasonable costs or expenses (including reasonable attorneys' fees and disbursements) incurred in connection with (a) an Event of Default by Mortgagor hereunder, or (b) the exercise or enforcement by or on behalf of Mortgagee or any holder of the Obligations of any of its rights or of Mortgagor's obligations under the Loan Documents or the Permitted Hedges. SECTION 3.03. Indemnity. Mortgagor shall indemnify and hold harmless Mortgagee, the holders of the Obligations and their respective officers, directors, employees and agents (the "indemnified parties") from and against any and all losses, damages, claims, costs and expenses (including attorneys' fees and disbursements) which may be imposed on, incurred by or asserted against any of the indemnified parties in connection with any transaction in any way connected with the Mortgaged Property, the Loan Documents or the Permitted Hedges, except to the extent any such loss, damage, claim, cost or expense is the result of the willful misconduct or gross negligence of the indemnified party. Any amount payable under this Section 3.03 shall be deemed a demand obligation, shall be added to and become a part of the Obligations, shall bear interest at the rate and as provided in the Credit Agreement if not paid within ten (10) days of demand therefore, and shall be secured by this Mortgage. SECTION 3.04. Interest After Default. If any payment due hereunder, under the other Loan Documents or under a Permitted Hedge is not paid in full when due, whether by acceleration or otherwise, then the same shall bear interest hereunder at the rate and as provided in the Credit Agreement, and such interest shall be added to and become a part of the Obligations and shall be secured hereby. ARTICLE IV Sale or Transfer of the Premises SECTION 4.01. Continuous Ownership. Mortgagor acknowledges that the continuous ownership of the Mortgaged 12 Property by Mortgagor, except as otherwise permitted in the other Loan Documents, is of a material nature to the transaction hereinabove described and Mortgagee's agreement to create the Obligations. Mortgagor=s causing the following activities, whether voluntarily or involuntarily, without Mortgagee=s prior written consent, shall subject Mortgagor to the remedies set forth at Section 5.02 hereof: (a) other than in respect of a parcel of the Mortgaged Property that is not a Material Portion of the Premises transferred in the context of a settlement with an adjoining landowner regarding the ownership or use of such parcel, selling, leasing, granting, conveying, assigning or otherwise transferring, by operation of law or otherwise, or (b) granting an option which or taking any action which pursuant to the terms of any agreement to which Mortgagor is a party may result in any transaction described in clause (a) above of, the Mortgaged Property, or any legal, beneficial or equitable interest (excluding interests in Leases that are not Material Leases) therein (the foregoing, collectively or severally, "Transfer"). For purposes of this Mortgage, but without limiting the foregoing, (i) the issuance of any equity interest in Mortgagor (whether stock, partnership interest or otherwise) not in accordance with and pursuant to the Loan Documents and the Permitted Hedges, shall be deemed a Transfer of the Mortgaged Property, (ii) a Transfer of all or substantially all of the assets of Mortgagor shall be deemed a Transfer of the Mortgaged Property, (iii) subject to Section 1.03(c) hereof, the execution and delivery of any documentation relating to a proposed zoning lot merger or the execution and delivery of any other documentation effecting or purporting to effect, or the taking or suffering of any other action effecting or purporting to effect, a transfer of, or the granting of a right to utilize, any development rights appurtenant to the Mortgaged Property shall be deemed a Transfer of the Mortgaged Property, and (iv) any person or legal representative of Mortgagor to whom Mortgagor's interest in the Mortgaged Property passes by operation of law, or otherwise, shall be bound by the provisions of this Mortgage. The provisions of this Section 4.01 shall apply to each and every such Transfer of all or any portion of the Mortgaged Property or any legal or equitable interest therein, regardless whether or not Mortgagee has consented to, or waived by its action or inaction its rights hereunder with respect to any previous Transfer of all or any portion of the Mortgaged Property or any legal or equitable interest therein. ARTICLE V Defaults and Remedies SECTION 5.01. Events of Default. The term "Event of Default", as used in this Mortgage, shall mean the occurrence of any of the following events: (a) if default shall be made in the payment, after any applicable notice and cure period, of any amounts required to be paid under the Notes, hereunder or under any other Loan Document or under a Permitted Hedge, whether of principal, interest, premium, fee or otherwise, and whether on any stated due date, upon demand, at maturity or upon acceleration; or (b) an Event of Default, as such term is defined in the Credit Agreement; or (c) subject to Mortgagor=s right to contest same set forth in Section 1.09 hereof, if the Mortgaged Property shall be taken, attached or sequestered on execution or other process of law in any action against Mortgagor; or 13 (d) if Mortgagor shall fail at any time to obtain, provide, maintain, keep in force or, within ten (10) days after request therefor, deliver to Mortgagee, the insurance policies required by Section 1.04 hereof; or (e) subject to Mortgagor=s right to contest same set forth in Section 1.09 hereof, if any claim of priority (except a claim based upon a Permitted Encumbrance) to this Mortgage or any other document or instrument securing the Obligations by title, lien or otherwise shall be upheld by any court of competent jurisdiction or shall be consented to by Mortgagor. SECTION 5.02. Remedies. Upon the occurrence of any one or more Events of Default, or any Transfer without the consent of Mortgagee, Mortgagee may, in addition to any rights or remedies available to it hereunder or under the other Loan Documents or the Permitted Hedges and to the extent permitted by applicable law, take such action personally or by its agents or attorneys, with or without entry, and without notice, demand, presentment or protest (each and all of which are hereby waived except as expressly provided otherwise herein), as it deems necessary or advisable to protect and enforce its rights and remedies against Mortgagor and in and to the Mortgaged Property, including the following actions, each of which may be pursued concurrently or otherwise, at such time and in such order as Mortgagee may determine, in its sole discretion, without impairing or otherwise affecting its other rights or remedies: (a) declare the entire balance of the Obligations to be immediately due and payable, and upon any such declaration, the entire unpaid balance of the Obligations shall become and be immediately due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by Mortgagor (except as expressly provided otherwise herein); or (b) institute a proceeding or proceedings, judicial or otherwise, for the complete or partial foreclosure of this Mortgage under any applicable provision of law; or (c) sell the Mortgaged Property, and all estate, right, title, interest, claim and demand of Mortgagor therein, and all rights of redemption thereof, at one or more sales, as an entirety or in parcels, with such elements of real and/or personal property, and at such time and place and upon such terms as it may deem expedient, or as may be required by applicable law, and in the event of a sale, by foreclosure or otherwise, of less than all of the Mortgaged Property, this Mortgage shall continue as a lien and security interest on the remaining portion of the Mortgaged Property; or (d) institute an action, suit or proceeding in equity for the specific performance of any of the provisions contained in the Loan Documents or the Permitted Hedges; or (e) apply for the appointment of a receiver, custodian, trustee, liquidator or conservator of the Mortgaged Property, to be vested with the fullest powers permitted under applicable law, as a matter of right and without regard to, or the necessity to disprove, the adequacy of the security for the Obligations or the solvency of Mortgagor or any other person liable for the payment of the Obligations, and Mortgagor and each other person so liable waives or shall be deemed to have waived such necessity and consents or shall be deemed to have consented to such appointment; or 14 (f) enter upon the Premises, and exclude Mortgagor and its agents and servants wholly therefrom, without liability for trespass, damages or otherwise, and take possession of all books, records and accounts relating thereto and all other Mortgaged Property, and Mortgagor agrees to surrender possession of the Mortgaged Property and of such books, records and accounts to Mortgagee on demand after the happening of any Event of Default; and having and holding the same may use, operate, manage, preserve, control and otherwise deal therewith and conduct the business thereof, either personally or by its superintendents, managers, agents, servants, attorneys or receivers, without interference from Mortgagor; and upon each such entry and from time to time thereafter may, at the expense of Mortgagor and the Mortgaged Property, without interference by Mortgagor and as Mortgagee may deem reasonably advisable, (i) insure or reinsure the Premises, (ii) make all necessary or proper repairs, renewals, replacements, alterations, additions, betterments and improvements thereto and thereon and (iii) in every such case in connection with the foregoing have the right to exercise all rights and powers of Mortgagor with respect to the Mortgaged Property, either in Mortgagor's name or otherwise; or (g) with or without the entrance upon the Premises, collect, receive, sue for and recover in its own name all Rents and cash collateral derived from the Mortgaged Property, and after deducting therefrom all costs, expenses and liabilities of every character reasonably incurred by Mortgagee in collecting the same and in using, operating, managing, preserving and controlling the Mortgaged Property, and otherwise in exercising Mortgagee's rights under subsection (f) of this Section 5.02, including all amounts necessary to pay Impositions, insurance premiums and other charges due and payable in connection with the Premises, as well as compensation for services provided, in respect of the management of the Premises, by Mortgagee or a third party acting on behalf of Mortgagee, to apply the remainder as provided in Section 5.05 hereof; or (h) release any portion of the Mortgaged Property for such consideration as Mortgagee may require without, as to the remainder of the Mortgaged Property, in any way impairing or affecting the lien or priority of this Mortgage, or improving the position of any subordinate lienholder with respect thereto, except to the extent that the Obligations shall have been reduced by the actual monetary consideration, if any, received by Mortgagee for such release and applied to the Obligations, and may accept by assignment, pledge or otherwise any other property in place thereof as Mortgagee may require without being accountable for so doing to any other lienholder; or (i) take all actions permitted under the UCC; or (j) take any other action, or pursue any other right or remedy, as Mortgagee may have under applicable law, and Mortgagor does hereby grant the same to Mortgagee. In the event that Mortgagee shall exercise any of the rights or remedies set forth in subsections (f) and (g) of this Section 5.02, Mortgagee shall not be deemed to have entered upon or taken possession of the Mortgaged Property except upon the exercise of its option to do so, evidenced by its demand and overt act for such purpose, nor shall it be deemed a beneficiary or mortgagee in possession by reason of such entry or taking possession. Mortgagee shall not be liable to account for any action taken pursuant to any such exercise other than for Rents actually received by Mortgagee, nor liable for any loss sustained by Mortgagor resulting from any failure to let the Premises, or 15 from any other act or omission of Mortgagee except to the extent such loss is caused by the willful misconduct or bad faith of Mortgagee or its agents or representatives. SECTION 5.03. Rights Pertaining to Sales. Subject to the provisions or other requirements of law and except as otherwise provided herein, the following provisions shall apply to any sale or sales of all or any portion of the Mortgaged Property under or by virtue of this Article V, whether made under the power of sale herein granted or by virtue of judicial proceedings or of a judgment or decree of foreclosure and sale: (a) Mortgagee may conduct any number of sales from time to time. The power of sale set forth in Section 5.02(c) hereof shall not be exhausted by any one or more such sales as to any part of the Mortgaged Property which shall not have been sold, nor by any sale which is not completed or is defective in Mortgagee's opinion, until the Obligations shall have been paid in full. (b) Any sale may be postponed or adjourned by public announcement at the time and place appointed for such sale or for such postponed or adjourned sale without further notice. Without limiting the foregoing, in case Mortgagee shall have proceeded to enforce any right or remedy under this Mortgage by receiver, entry or otherwise, and such proceedings have been discontinued or abandoned for any such reason or shall have been determined adversely to Mortgagee, then in every such case Mortgagor and Mortgagee shall be restored to their former positions and rights hereunder, and all rights, powers and remedies of Mortgagee shall continue as if no such proceeding had been taken. (c) After each sale, Mortgagee or an officer of any court empowered to do so shall execute and deliver to the purchaser or purchasers at such sale a good and sufficient instrument or instruments granting, conveying, assigning and transferring all right, title and interest of Mortgagor in and to the property and rights sold and shall receive the proceeds of said sale or sales and apply the same as herein provided. Mortgagee is hereby appointed the true and lawful attorney-in-fact of Mortgagor, which appointment is irrevocable and shall be deemed to be coupled with an interest, in Mortgagor's name and stead, to make all necessary conveyances, assignments, transfers and deliveries of the property and rights so sold, and for that purpose Mortgagee may execute all necessary instruments of conveyance, assignment, transfer and delivery, and may substitute one or more persons with like power, Mortgagor hereby ratifying and confirming all that said attorney or such substitute or substitutes shall lawfully do by virtue thereof. Nevertheless, Mortgagor, if requested by Mortgagee, shall ratify and confirm any such sale or sales by executing and delivering to Mortgagee or such purchaser or purchasers all such instruments as may be advisable, in Mortgagee's judgment, for the purposes as may be designated in such request. (d) Any and all statements of fact or other recitals made in any of the instruments referred to in subsection (c) of this Section 5.03 given by Mortgagee as to nonpayment of the Obligations, or as to the occurrence of any Event of Default, or as to Mortgagee having declared all or any of the Obligations to be due and payable, or as to the request to sell, or as to notice of time, place and terms of sale and of the property or rights to be sold having been duly given, or as to any other act or thing having been duly done by Mortgagor or by Mortgagee in connection with the exercise of the remedies described in this Section 5.03(d) shall be taken as conclusive and 16 binding against all persons as to evidence of the truth of the facts so stated and recited absent manifest error. Mortgagee may appoint or delegate any one or more persons as agent to perform any act or acts necessary or incident to any sale so held, including the posting of notices and the conduct of sale. (e) The receipt of Mortgagee for the purchase money paid at any such sale, or the receipt of any other person authorized to receive the same, shall be sufficient discharge therefor to any purchaser of any property or rights sold as aforesaid, and no such purchaser, or its representatives, grantees or assigns, after paying such purchase price and receiving such receipt, shall be bound to see to the application of such purchase price or any part thereof upon or for any trust or purpose of this Mortgage or, in any manner whatsoever, be answerable for any loss, misapplication or nonapplication of any such purchase money, or part thereof, or be bound to inquire as to the authorization, necessity, expediency or regularity of any such sale. (f) Any such sale or sales shall operate to divest all of the estate, right, title, interest, claim and demand whatsoever, whether at law or in equity, of Mortgagor in and to the properties and rights so sold, and shall be a perpetual bar both at law and in equity against Mortgagor and any and all persons claiming or who may claim the same, or any part thereof or any interest therein, by, through or under Mortgagor to the fullest extent permitted by applicable law. (g) Upon any such sale or sales, Mortgagee may bid for and acquire the Mortgaged Property and, in lieu of paying cash therefor, may make settlement for the purchase price by crediting against the Obligations the amount of the bid made therefor, after deducting therefrom the reasonable expenses of the sale, the cost of any enforcement proceeding hereunder, and any other sums which Mortgagee is authorized to deduct under the terms hereof, to the extent necessary to satisfy such bid. (h) In the event that Mortgagor, or any person claiming by, through or under Mortgagor, shall transfer or refuse or fail to surrender possession of the Mortgaged Property after any sale thereof, then Mortgagor, or such person, shall be deemed a tenant at sufferance of the purchaser at such sale, subject to eviction by means of forcible entry and unlawful detainer proceedings, or subject to any other right or remedy available hereunder or under applicable law. (i) Upon any such sale, it shall not be necessary for Mortgagee or any public officer acting under execution or order of court to have present or constructively in its possession any of the Mortgaged Property. (j) In the event a foreclosure hereunder shall be commenced by Mortgagee, Mortgagee may at any time before the sale of the Mortgaged Property abandon the sale, and may institute suit for the collection of the Obligations and for the foreclosure of this Mortgage, or in the event that Mortgagee should institute a suit for collection of the Obligations, and for the foreclosure of this Mortgage, Mortgagee may at any time before the entry of final judgment in said suit dismiss the same and require Mortgagee to sell the Mortgaged Property in accordance with the provisions of this Mortgage. (k) This mortgage is based upon the STATUTORY CONDITION and upon the further condition that all covenants and agreements of Mortgagor in this Mortgage, all other instruments executed in connection therewith and in all other mortgages, debts and obligations of or from Mortgagor to Mortgagee shall be 17 kept and fully performed, and, upon any breach of the same, Mortgagee shall have the STATUTORY POWER OF SALE and any other powers given by statute. SECTION 5.04. Expenses. In any proceeding, judicial or otherwise, to foreclose this Mortgage or enforce any other remedy of Mortgagee under the Loan Documents or under any Permitted Hedge, there shall be allowed and included as an addition to and a part of the Obligations in the decree for sale or other judgment or decree all reasonable expenditures and expenses which may be paid or incurred in connection with the exercise by Mortgagee of any of its rights and remedies provided or referred to in Section 5.02 hereof, or any comparable provision of any other Loan Document or any Permitted Hedge, together with interest thereon at the rate and as provided in the Credit Agreement, and the same shall be part of the Obligations and shall be secured by this Mortgage. SECTION 5.05. Application of Proceeds. The purchase money, proceeds or avails of any sale referred to in Section 5.02 hereof, together with any other sums which may be held by Mortgagee hereunder, whether under the provisions of this Article V or otherwise, shall, except as herein expressly provided to the contrary, be applied as follows: First: To the payment of the reasonable costs and expenses of any such sale, including all amounts due hereunder, and of any judicial proceeding wherein the same may be made, and of all reasonable expenses, liabilities and advances made or incurred by Mortgagee hereunder, together with interest thereon as provided herein, and all Impositions and other charges, except any Impositions or other charges subject to which the Mortgaged Property shall have been sold. Second: To the payment in full of the monetary Obligations (including principal, interest, premium and fees) in such order as Mortgagee may elect. Third: To the payment of any other sums secured hereunder or required to be paid by Mortgagor pursuant to any provision of the Loan Documents or the Permitted Hedges. Fourth: To the extent permitted by applicable law, to be set aside by Mortgagee as adequate security in its judgment for the payment of sums which would have been paid by application under clauses First through Third above to Mortgagee, arising out of an obligation or liability with respect to which Mortgagor has agreed to indemnify Mortgagee, but which sums are not yet due and payable or liquidated. Fifth: To the payment of any withholding tax requirements of the Foreign Investment in Real Property Tax Act of 1980, as amended. Sixth: To the payment of the surplus, if any, to whomsoever may be lawfully entitled to receive the same. SECTION 5.06. Additional Provisions as to Remedies. (a) No delay or omission by Mortgagee to exercise any right or remedy hereunder upon any default or Event of Default shall impair such exercise, or be construed to be a waiver of any such default or Event of Default. (b) The failure, refusal or waiver (by consent, waiver or otherwise) of 18 Mortgagee to assert any right or remedy hereunder upon any default or Event of Default or other occurrence shall not be construed as waiving such right or remedy upon any other or subsequent default or Event of Default or other occurrence. (c) Mortgagee shall not have any obligation to pursue any rights or remedies it may have under any other agreement prior to pursuing its rights or remedies hereunder or under the other Loan Documents or under any Permitted Hedge. (d) Acceptance of any payment after the occurrence of any default or Event of Default shall not be deemed a waiver or a cure of such default or Event of Default, and acceptance of any payment less than any amount then due shall be deemed an acceptance on account only. (e) In the event that Mortgagee shall have proceeded to enforce any right or remedy hereunder by foreclosure, sale, entry or otherwise, and such proceeding shall be discontinued, abandoned or determined adversely for any reason, then Mortgagor and Mortgagee shall be restored to their former positions and rights hereunder with respect to the Mortgaged Property, subject to the lien hereof. (f) Each right of Mortgagee provided for in this Mortgage shall be cumulative and shall be in addition to every other right provided for in this Mortgage or now or hereafter existing at law or in equity, by statute or otherwise, and the exercise by Mortgagee of any one or more of such rights shall not preclude the simultaneous or later exercise by Mortgagee of any other such right. SECTION 5.07. Waiver of Rights and Defenses. To the full extent Mortgagor may lawfully do so, Mortgagor agrees with Mortgagee as follows: (a) Mortgagor shall not claim or take the benefit of any statute or rule of law now or hereafter in force providing for any appraisement, valuation, stay, extension, moratorium or redemption, or of any statute of limitations, and Mortgagor, for itself and its heirs, devisees, representatives, successors and assigns, and for any and all persons ever claiming an interest in the Mortgaged Property (other than Mortgagee), hereby waives and releases all rights of redemption, valuation, appraisement, notice of intention to mature or declare due the whole of the Obligations, and all rights to a marshaling of the assets of Mortgagor, including the Mortgaged Property, or to a sale in inverse order of alienation, in the event of foreclosure of the liens and security interests created hereunder. (b) Mortgagor shall not have or assert and hereby waives any right under any statute or rule of law pertaining to any of the matters set forth in subsection (a) of this Section 5.07(a) hereof, to the administration of estates of decedents or to any other matters whatsoever to defeat, reduce or affect any of the rights or remedies of Mortgagee hereunder. ARTICLE VI Release of Lien SECTION 6.01. Release of Lien. Subject to the 19 full payment of all of the AObligations" defined in the fourth AWhereas" clause of the Tranche A Mortgage, if all of the Obligations shall be fully paid, then and in that event only all rights and obligations hereunder (except for the rights and obligations set forth in Section 3.03 hereof) shall terminate and the Mortgaged Property shall become wholly released and cleared of the liens, security interests, conveyances and assignments evidenced hereby. In such event Mortgagee shall, at the request of Mortgagor, deliver to Mortgagor within ten (10) Business Days, in recordable form, all such documents as shall be necessary to release the Mortgaged Property from the liens, security interests, conveyances and assignments created or evidenced hereby. Moreover, this Mortgage is subject to the provisions of Section 25 of the Borrower Security Agreement, which grants to Mortgagor the right, upon certain terms and conditions, to obtain Mortgagee's consent to release, or cause to be released, from the liens, security interests, conveyances and assignments evidenced by this Mortgage, from time to time, all or any portion of the Mortgaged Property. ARTICLE VII Additional Provisions SECTION 7.01. Provisions as to Payments, Advances. To the extent that any part of the Obligations is used to pay indebtedness secured by any Permitted Encumbrance or other outstanding lien, security interest, charge or prior encumbrance against the Mortgaged Property or to pay in whole or in part the purchase price therefor, Mortgagee shall be subrogated to any and all rights, security interests and liens held by any owner or holder of the same, whether or not the same are released. SECTION 7.02. Separability. If all or any portion of any provision of this Mortgage or any other Loan Document or any Permitted Hedge shall be held to be invalid, illegal or unenforceable in any respect or in any jurisdiction, then such invalidity, illegality or unenforceability shall not affect any other provision hereof or thereof, and such provision shall be limited and construed in such jurisdiction as if such invalid, illegal or unenforceable provision or portion thereof were not contained herein or therein. SECTION 7.03. Notices. Any notice, demand, consent, approval, direction, agreement or other communication (any "Notice") required or permitted hereunder shall be in writing and shall be validly given if mailed by United States mail, certified mail, return receipt requested, postage prepaid, or by a nationally-recognized overnight courier, addressed as follows to the person entitled to receive the same: (a) If to Mortgagor: Northeast Generation Company 107 Selden Street Berlin, Connecticut 06037 Attention: Treasurer and a copy to: Edwards & Angell, LLP 20 90 State House Square Hartford, Connecticut 06103 Attention: Justin M. Sullivan, Esq. (b) If to Mortgagee: Citibank, N.A., as Collateral Agent 111 Wall Street, 5th Floor New York, New York 10005 Attention: Florence Mills, Senior Trust Officer Any Notice shall be deemed to have been validly given hereunder when so mailed or sent by courier. Any person shall have the right to specify, from time to time, as its address or addresses for purposes of this Mortgage, any other address or addresses upon giving three (3) days' notice thereof to each other person then entitled to receive notices or other instruments hereunder. SECTION 7.04. Right to Deal. In the event that ownership of the Mortgaged Property becomes vested in a person other than Mortgagor, Mortgagee may, without notice to Mortgagor, deal with such successor or successors in interest with reference to this Mortgage or the Obligations in the same manner as with Mortgagor, without in any way vitiating or discharging Mortgagor's liability hereunder or for the payment of the Obligations or being deemed a consent to such vesting. SECTION 7.05. Continuation of Lease. (a) Upon the foreclosure of the lien created hereby on the Mortgaged Property, as herein provided, any Leases then existing shall not be destroyed or terminated as a result of such foreclosure unless Mortgagee or any purchaser at a foreclosure sale shall so elect by notice to the lessee in question. (b) If both the lessor's and the lessee's interest under any Lease which constitutes a part of the Premises shall at any time become vested in any one person, this Mortgage and the lien and security interest created hereby shall not be destroyed or terminated by the application of the doctrine of merger and, in such event, Mortgagee shall continue to have and enjoy all of the rights and privileges of Mortgagee hereunder as to each separate estate. SECTION 7.06. Applicable Law. This Mortgage shall be governed by, and construed in accordance with, the internal law of the State in which the Mortgaged Property is located without regard to principles of conflicts of laws, except that the internal laws of the State of New York (without regard to principles of conflicts of laws) shall govern (i) those terms and conditions contained in the Notes and the Credit Agreement which are incorporated by reference herein and (ii) the resolution of issues arising under the Notes and the Credit Agreement to the extent that such resolution is necessary to the interpretation of this Mortgage. SECTION 7.07. Sole Discretion of Mortgagee. Except as expressly provided herein, whenever Mortgagee's judgment, consent or approval is required hereunder for any matter, or shall have an option or election hereunder, such judgment, the decision whether or not to consent to or approve the same or the exercise of such option or election shall be in the sole discretion of Mortgagee. SECTION 7.08. Provisions as to Covenants and 21 Agreements. All of Mortgagor's covenants and agreements hereunder shall run with the land and time is of the essence as to the time periods stated herein in which such covenants and agreements are to be performed. SECTION 7.09. Matters to be in Writing. This Mortgage cannot be altered, amended, modified, terminated, waived, released or discharged except in a writing signed by the party against whom enforcement is sought. SECTION 7.10. Submission to Jurisdiction. Without limiting the right of Mortgagee to bring any action or proceeding against the undersigned or its property arising out of or relating to the Obligations (an "Action") in the courts of other jurisdictions, Mortgagor hereby irrevocably submits to the jurisdiction of the state court or Federal court in each jurisdiction in which the Mortgaged Property is located, and Mortgagor hereby irrevocably agrees that any Action may be heard and determined in such state or federal court. Mortgagor hereby irrevocably waives, to the fullest extent that it may effectively do so, the defense of an inconvenient forum to the maintenance of any Action in the jurisdiction. Mortgagor hereby agrees that the summons and complaint or any other process in any Action may be served in accordance with the rules of the applicable jurisdiction. SECTION 7.11. Construction of Provisions. The following rules of construction shall be applicable for all purposes of this Mortgage and all documents or instruments supplemental hereto, unless the context otherwise requires: (a) All Article, Section and Exhibit captions herein are used for reference only and in no way limit or describe the scope or intent of, or in any way affect, this Mortgage. (b) The terms "include", "including" and similar terms shall be construed as if followed by the phrase "without being limited to". (c) The terms "Land", "Improvements", "Equipment", "Mortgaged Property" and "Premises" shall be construed as if followed by the phrase "or any part thereof". (d) The term "Obligations" shall be construed as if followed by the phrase "or any other sums secured hereby, or any part thereof". (e) Words of masculine, feminine or neuter gender shall mean and include the correlative words of the other genders, and words importing the singular number shall mean and include the plural number, and vice versa. (f) The term "person" shall include natural persons, firms, partnerships, corporations and any other public and private legal entities. (g) The term "provisions", when used with respect hereto or to any other document or instrument, shall be construed as if preceded by the phrase "terms, covenants, agreements, requirements, conditions and/or". (h) The cover page of and all recitals set forth in, and all Exhibits to, this Mortgage are hereby incorporated in this Mortgage. 22 (i) All obligations of Mortgagor hereunder shall be performed and satisfied by or on behalf of Mortgagor at Mortgagor's sole cost and expense. (j) The term "lease" shall mean "tenancy, subtenancy, lease or sublease", the term "lessor" shall mean "landlord, sublandlord, lessor and sublessor" and the term "lessee" shall mean "tenant, subtenant, lessee and sublessee". (k) No inference in favor of or against any party shall be drawn from the fact that such party has drafted any portion hereof. (l) Terms capitalized herein that are not defined herein shall have the meanings set forth for them in the Credit Agreement. (m) In the event that any inconsistencies between the terms of the Credit Agreement and the terms of this Mortgage are discerned, the terms of the Credit Agreement shall govern. SECTION 7.12. Successors and Assigns. The provisions hereof shall be binding upon Mortgagor and the heirs, devisees, representatives, successors and permitted assigns of Mortgagor, including successors in interest of Mortgagor in and to all or any part of the Mortgaged Property, and shall inure to the benefit of Mortgagee, the holders of the Obligations and their respective heirs, successors, legal representatives, substitutes and assigns. Where two or more persons have executed this Mortgage, the obligations of such persons shall be joint and several. SECTION 7.13. Counterparts. This Mortgage may be executed in counterparts, each of which shall be deemed to be an original, but all of which shall constitute one and the same agreement. SECTION 7.14. Agency. Mortgagee may deal with the Mortgaged Property and may issue, as applicable, any release to be given hereunder pursuant to Section 4.02 or Section 6.01 hereof or grant any consent or approval or take any other action, required or permitted hereunder, without reference to or the approval of the holders of the Obligations and any third party (including any title insurance company issuing a title insurance policy, or a commitment to issue a title insurance policy, in connection with the Mortgaged Property) may conclusively rely on the due authority of Mortgagee to do any or all of the foregoing. SECTION 7.15. The Security Agreement. In the event that a valid and enforceable security interest has been created in any of the Mortgaged Property under the terms of the Borrower Security Agreement and the terms of the Borrower Security Agreement are inconsistent with the terms of this Mortgage, then with respect to such Mortgaged Property, the terms of the Borrower Security Agreement shall be controlling in the case of Equipment and the terms of this Mortgage shall be controlling in all other cases. ARTICLE VIII Fixture Filing SECTION 8.01. Fixture Filing. A portion of the Mortgaged Property is or is to become fixtures upon the Premises. To the 23 extent permitted by applicable law, Mortgagor covenants and agrees that the filing of this Mortgage in the real estate records of the county or other municipality in which the Mortgaged Property is located, as applicable, shall also operate from the time of filing as a fixture filing with respect to all goods constituting part of the Mortgaged Property which are or are to become fixtures related to the real estate described herein. For such purpose, the following information is set forth: (a) Name and Address of Debtor: Mortgagor, a Connecticut corporation, having an address at 107 Selden Street, Berlin, Connecticut 06037. (b) Name and Address of Secured Party: Citibank, N.A., as collateral agent for the Lenders listed on Exhibit B hereto, having an address at 111 Wall Street, 5th Floor, New York, New York 10005, Attention: Florence Mills, Senior Trust Officer. (c) This document covers goods which are or are to become fixtures. (d) The name of the record owner is Northeast Generation Company. 24 IN WITNESS WHEREOF, the undersigned has executed under seal this Mortgage the day first set forth above. Signed, sealed and delivered Mortgagor in the presence of the following witnesses: By: Name: Name: Title: Address: Name: Address: By: Name: Name: Title: Address: [Corporate Seal] Name: Address: [Address] 25 ACKNOWLEDGMENT STATE OF ) ) ss.: COUNTY ) On this __ day of March, 2000, before me, the undersigned officer, personally appeared ___________________, personally known and acknowledged [himself][herself] to me to be the ___________________ of Northeast Generation Company, a Connecticut Corporation, that as such officer, being duly authorized to do so pursuant to its bylaws or a resolution of its board of directors, executed and acknowledged the foregoing instrument for the purposes therein contained as [his][her] free and voluntary act and deed. IN WITNESS WHEREOF, I hereunto set my hand and official seal. - ------------------------------ Notary Public [Notary Seal/stamp] My Commission Expires: - ------------------------------ 26 SCHEDULE 1 List of Lenders Lender Address Citibank, N.A. Citibank, N.A. 399 Park Avenue New York, New York 10043 Barclays Bank PLC Barclays Bank PLC 222 Broadway, 11th Floor New York, New York 10038 Attention: Christine Francese Canadian Imperial Bank of Commerce Canadian Imperial Bank of Commerce Two Paces West 2727 Paces Ferry Road, Suite 1200 Atlanta, Georgia 30339 Attention: Miriam McCart Toronto Dominion (Texas), Inc. Toronto Dominion (Texas), Inc. 909 Fannin Street, 17th Floor Houston, Texas 77010 Attention: Alva J. Jones Mees Pierson Capital Corp. Mees Pierson Capital Corp. 3 Stamford Plaza 301 Tresser Boulevard, 9th Floor Stamford, Connecticut 06901-3239 Attention: Marlene Ellis Union Bank of California, N.A. Union Bank of California, N.A. Energy Capital Services 445 S. Figueroa Street, 15th Floor Los Angeles, California 90071 Attention: Jason DiNapoli 27 EXHIBIT A Description of Land 28 EXHIBIT F-2 FORM OF TRANCHE B MORTGAGE This instrument was prepared by the attorney referenced below in consultation with counsel admitted to practice in the state in which the property is located, and when recorded, counterparts should be returned to: Shearman & Sterling 599 Lexington Avenue New York, New York 10022 Attention: John L. Opar, Esq. (60/22) =========================================================== TRANCHE B MORTGAGE, ASSIGNMENT OF LEASES AND RENTS, SECURITY AGREEMENT AND FIXTURE FILING NORTHEAST GENERATION COMPANY, Mortgagor to CITIBANK, N.A., as collateral agent for the Lenders listed on Schedule 1 hereto and as provided herein, Mortgagee Dated: March ___, 2000 This instrument is a mortgage, assignment of leases and rents, security agreement and fixture filing. This instrument encumbers property located in Connecticut, Massachusetts, New Hampshire and Vermont. The total outstanding principal amount of indebtedness secured by this instrument shall not exceed Eight Hundred Sixty-Five Million, Five Hundred Thousand Dollars ($865,500,000). The latest potential date of maturity of the obligations secured hereunder is December 29, 2000. This instrument contains after-acquired property provisions and secures obligations containing provisions for changes in interest rates, extensions of time for payment and other modifications in the terms of the obligations. The mailing address of Mortgagee (as hereinafter defined) is Citibank, N.A., as Collateral Agent 111 Wall Street, 5th Floor New York, New York 10005 Attention: Florence Mills, Senior Trust Officer 29 TABLE OF CONTENTS Page Recitals.................................................................... ARTICLE I Representations, Warranties and Covenants of Mortgagor SECTION 1.01. Payment of Obligations.......................................4 SECTION 1.02. Warranty of Title............................................4 SECTION 1.03. Operation and Maintenance....................................5 SECTION 1.04. Insurance....................................................6 SECTION 1.05. Liens and Liabilities........................................6 SECTION 1.06. Taxes and Other Charges......................................7 SECTION 1.07. Damage and Destruction.......................................8 SECTION 1.08. Condemnation.................................................8 SECTION 1.09. Contest......................................................9 ARTICLE II Assignment of Leases, Rents and Other Sums SECTION 2.01. Assignment..................................................10 SECTION 2.02. Leases and Rents............................................11 ARTICLE III Additional Advances; Expenses; Indemnity SECTION 3.01. Additional Advances and Disbursements.......................13 SECTION 3.02. Other Expenses..............................................14 SECTION 3.03. Indemnity...................................................14 SECTION 3.04. Interest After Default......................................14 ARTICLE IV Sale or Transfer of the Premises SECTION 4.01. Continuous Ownership........................................15 ARTICLE V Defaults and Remedies SECTION 5.01. Events of Default...........................................16 SECTION 5.02. Remedies....................................................16 SECTION 5.03. Rights Pertaining to Sales..................................18 SECTION 5.04. Expenses....................................................21 SECTION 5.05. Application of Proceeds.....................................21 SECTION 5.06. Additional Provisions as to Remedies........................22 SECTION 5.07. Waiver of Rights and Defenses...............................23 ARTICLE VI Release of Lien SECTION 6.01. Release of Lien.............................................23 ARTICLE VII Additional Provisions SECTION 7.01. Provisions as to Payments, Advances.........................24 SECTION 7.02. Separability................................................24 SECTION 7.03. Notices.....................................................24 SECTION 7.04. Right to Deal...............................................25 SECTION 7.05. Continuation of Lease.......................................25 SECTION 7.06. Applicable Law..............................................25 SECTION 7.07. Sole Discretion of Mortgagee................................26 30 SECTION 7.08. Provisions as to Covenants and Agreements...................26 SECTION 7.09. Matters to be in Writing....................................26 SECTION 7.10. Submission to Jurisdiction..................................26 SECTION 7.11. Construction of Provisions..................................26 SECTION 7.12. Successors and Assigns......................................27 SECTION 7.13. Counterparts................................................28 SECTION 7.14. Agency......................................................28 SECTION 7.15. The Security Agreement......................................28 ARTICLE VIII Fixture Filing SECTION 8.01. Fixture Filing..............................................28 31 PAGE Exhibit A Description of Land Exhibit B List of Lenders 32 EX-12 14 0014.txt EXHIBIT 12 NORTHEAST UTILITIES Exhibit 12 Ratio of Earnings to Fixed Charges (Thousands of Dollars)
YEAR YEAR YEAR YEAR YEAR 1996 1997 1998 1999 2000 --------- --------- --------- --------- --------- Earnings, as defined: Net income (loss) before extraordinary item $ 38,929 $(129,962) $(146,753) $ 34,216 $ 205,295 Income taxes 96,110 1,948 5,939 98,611 161,725 Equity in earnings of regional nuclear generating and transmission companies (6,649) (4,653) (1,456) (2,905) (13,667) Minority interest 9,300 9,300 9,300 9,300 9,300 Fixed charges, as below 298,193 291,348 292,622 279,851 311,176 --------- --------- --------- --------- --------- Total earnings, as defined: $ 435,883 $ 167,981 $ 159,652 $ 419,073 $ 673,829 ========= ========= ========= ========= ========= Fixed Charges, as defined: Interest on long-term debt $ 285,463 $ 282,095 $ 273,824 $ 258,093 $ 200,697 Other interest (7,470) (10,114) (4,735) 5,558 98,605 Rental interest factor - capital 14,100 13,600 18,300 13,700 8,657 Rental interest factor - 1/3 operating 6,100 5,767 5,233 2,500 3,217 --------- --------- --------- --------- --------- Total fixed charges, as defined $ 298,193 $ 291,348 $ 292,622 $ 279,851 $ 311,176 ========= ========= ========= ========= ========= Ratio of earnings to fixed charges 1.46 0.58 0.55 1.50 2.17 ========= ========= ========= ========= =========
EX-13.1 15 0015.txt ANNUAL REPORT OF CL&P 2000 Annual Report The Connecticut Light and Power Company and Subsidiaries Index Contents Page - -------- ---- Management's Discussion and Analysis of Financial Condition and Results of Operations............................. 1 Report of Independent Public Accountants.......................... 12 Consolidated Statements of Income................................. 13 Consolidated Statements of Comprehensive Income................... 13 Consolidated Balance Sheets....................................... 14-15 Consolidated Statements of Common Stockholder's Equity............ 16 Consolidated Statements of Cash Flows............................. 17 Notes to Consolidated Financial Statements........................ 18 Selected Consolidated Financial Data.............................. 41 Consolidated Quarterly Financial Data (Unaudited)................. 41 Consolidated Statistics (Unaudited)............................... 42 Preferred Stockholder and Bondholder Information.................. Back Cover The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - ------------------------------------------------------------------------------- FINANCIAL CONDITION - ------------------- Overview - -------- The Connecticut Light and Power Company's (CL&P or the company), the Northeast Utilities (NU) system's (NU system) largest operating subsidiary, earnings totaled $148.1 million in 2000, compared with a loss of $13.6 million in 1999 and $195.7 million in 1998. The 2000 results represented CL&P's first annual profit since 1995. CL&P benefited from the return to service of the Millstone 2 unit in May 1999 and the strong performance of the Millstone 2 and 3 units in 2000. Millstone 2 operated at a capacity factor of 82 percent in 2000, while Millstone 3 operated at a capacity factor of virtually 100 percent in 2000. However, management projects that CL&P's earnings will decline in 2001 as a result of the expected sale of CL&P's share of the Millstone units, other rate adjustments and the pending resolution of the over-earnings docket. Although CL&P's earnings are expected to decline, its return on equity is not expected to be compromised. In 2000, CL&P's revenues increased to $2.94 billion, up 20 percent from $2.45 billion in 1999, primarily due to higher wholesale revenues. Revenues were $2.39 billion in 1998. This growth in revenues was offset by a 5 percent retail rate decrease on January 1, 2000, for customers of CL&P. Consolidated Edison, Inc. Merger - -------------------------------- In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the approvals needed to complete the merger announced in October 1999. Shareholders from both companies approved the merger in April 2000, and all state regulatory approvals were granted by the end of the year. Additionally, the Federal Energy Regulatory Commission (FERC) approved the merger in May 2000, the Nuclear Regulatory Commission approved the transaction in August 2000, and the United States Department of Justice approved the merger in February 2001. Necessary approval from the Securities and Exchange Commission (SEC) was expected to be received in mid-March 2001. On February 28, 2001, NU's Board of Trustees requested that Con Edison provide reasonable assurance, in writing, that it intended to comply with the terms of the definitive merger agreement between the two companies. This included assurances that Con Edison would consummate the pending merger at the price set forth in the agreement promptly following the receipt of SEC approval. The original request for assurance was to be received by March 2, 2001, however that date was later extended to March 5, 2001. On March 5, 2001, Con Edison advised NU that it was not willing to close the merger on the agreed terms. NU notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that NU would file suit to obtain the benefits of the transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District of New York (Southern District), seeking declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement. On March 12, 2001, NU filed suit against Con Edison in the Southern District seeking damages in excess of $1 billion arising from Con Edison's breach of the merger agreement. NU cannot predict the outcome of this matter nor its effect on NU. Liquidity - --------- CL&P's net cash flows provided by operating activities decreased to $259.9 million in 2000 compared to $299.4 million in 1999 and $364.1 million in 1998. Reductions in depreciation and amortization expense, primarily as a result of industry restructuring resulted in a decrease in net cash flows from operations. Industry restructuring in Connecticut required a retail rate reduction of 5 percent on January 1, 2000, further reducing cash flows from operations. These decreases were offset by a $161.7 million increase in net income for the year ended December 31, 2000, compared with the same periods in 1999 and 1998 which increased cash flows from operating activities. Finally, the payment of taxes which occurred in 2000 related to the 1999 sale of generation assets, also decreased cash flows from operations. Cash flows from operations partially met the payment of CL&P's common and preferred dividends ($79.4 million) and investments in electric utility plant, nuclear fuel and nuclear decommissioning trusts ($269.1 million). The level of common dividends totaled $72 million in 2000, as compared to no common dividends paid in 1999 and 1998. The level of preferred dividends decreased to $7.4 million in 2000, compared with $12.8 million in 1999 and $14.1 million in 1998, reflecting CL&P's ongoing effort to reduce preferred stock outstanding. CL&P currently forecasts construction expenditures ranging from $206 million to $231.1 million for the year 2001. The transfer of 1,289 megawatts (MW) of hydroelectric generation assets to Northeast Generation Company, an affiliated company, from CL&P and Western Massachusetts Electric Company (WMECO) in March 2000, produced a significant source of cash for CL&P and WMECO. CL&P used this cash to retire long-term debt, preferred stock and to return equity capital to the parent company. Financing activities for 2000 included $578.6 million for the retirement of long-term debt, preferred stock and common stock, compared with $639.8 million for 1999 and $80.7 million in 1998. In November 2000, CL&P and WMECO reduced their revolving credit agreement to $350 million from $500 million to reflect lower borrowing needs post- restructuring. This agreement was renewed with more favorable terms as a result of the NU system's improving credit profile. In January 2001, Moody's Investors Service and Standard and Poor's upgraded their credit ratings for CL&P primarily as a result of the anticipated sale of the Millstone units and NU's general financial recovery. In February 2001, Fitch IBCA upgraded its credit ratings for CL&P. These upgrades return CL&P's unsecured debt to investment grade ratings for the first time in five years and will save the NU system in excess of $4.7 million annually in financing costs. For further information regarding CL&P's borrowing facilities, see Note 2, "Short-Term Debt," to the consolidated financial statements. In 2001, NU expects to reduce the capitalization of its regulated electric operating companies significantly as a result of continued asset sales and securitization of stranded costs. CL&P expects to receive gross proceeds of $843.2 million as a result of the sale of its ownership interests in the Millstone units to Dominion Resources, Inc. (Dominion). This sale is expected to close as early as the end of March 2001. The cash proceeds are expected to be used to repay subsidiary debt and capital lease obligations and to return equity capital to the parent company. By the end of 2002, CL&P expects to complete the auction of its share of the Seabrook Station nuclear unit (Seabrook). Cash proceeds will be used to retire debt and to return equity capital to the parent company. In November 2000, the Connecticut Department of Public Utility Control (DPUC) approved CL&P's request to securitize an amount not to exceed $1.55 billion of approved, eligible stranded costs, primarily related to above-market purchased-power contracts and generation-related regulatory assets. CL&P plans to use approximately $400 million of those proceeds to reduce debt with the remaining proceeds to be used to buydown and buyout above-market purchased-power contracts and to return equity capital to the parent company. However, the Office of Consumer Counsel (OCC) has appealed the securitization order to the Connecticut Superior Court. On March 1, 2001, CL&P and the OCC entered into an agreement to settle this issue. Under the agreement, pending DPUC approval, the OCC agreed to withdraw its appeal of the securitization order and not take any action that would affect the timing and the amount of securitization financing to be undertaken. The DPUC approved the agreement on March 12, 2001. The OCC withdrew its appeal on March 16, 2001. Securitization for CL&P is expected to take place by the end of the first quarter 2001. Restructuring - ------------- As a result of industry restructuring, CL&P stopped supplying power directly to customers in 2000. Instead, CL&P became an energy delivery company, delivering electricity to customers that is produced by other companies and sometimes bought by customers through intermediaries. In 2000, customers in Connecticut had the option of choosing alternative power suppliers or relying on CL&P to acquire the power for them through standard offer service. To date virtually all customers are receiving power through standard offer service. In 1999, under the oversight of the DPUC, CL&P secured four-year fixed-price contracts with three suppliers to provide power to customers who choose standard offer service. CL&P is fully recovering from retail customers the cost of buying power from these three standard offer suppliers and expects to continue recovery through the expiration of the contracts on December 31, 2003. As of January 1, 2000, Select Energy, Inc. (Select Energy), an affiliated company, became responsible for 50 percent of CL&P's standard offer load for the entire standard offer period, or approximately 2,000 MW annually at peak. Two other unaffiliated suppliers became responsible for the balance of CL&P's standard offer load also for the entire standard offer period. CL&P continues to generate power through either direct ownership of generating plants, such as Millstone 2 and 3 and Seabrook, or through purchased-power contracts. CL&P sold its share of the capacity associated with Millstone 2 and 3 and Seabrook to Select Energy and five unaffiliated companies. These contracts will expire on December 31, 2001. The revenues generated from these contracts are expected to recover CL&P's share of the nuclear operating costs through the divestiture of the Millstone units. For further information regarding commitments and contingencies related to restructuring, see Note 9A, "Commitments and Contingencies - Restructuring," to the consolidated financial statements. Regional Transmission Organization - ---------------------------------- Pursuant to FERC Order 888 (issued in April 1996), the NU system companies, including CL&P, operate their transmission system under an open access, nondiscriminatory transmission tariff. In December 1999, the FERC issued an order calling on all transmission owners to voluntarily join Regional Transmission Organizations (RTOs) in order to boost competition in electric markets. In general, each of these organizations would be an independent operator over all transmission facilities, and would perform, among other functions, tariff administration, construction planning and reliability management for the particular regional transmission system. NU's active voting interest in such an organization would be limited to 5 percent under the proposal. The NU system companies, including CL&P, and other parties have appealed this order. Of primary concern to NU is the ratemaking authority granted to RTOs and its impact on the ability of transmission owners to earn appropriate returns on their transmission investment under the organizational structure and the minimum functions proposed in the order. The NU system companies, including CL&P, were required to participate in a collaborative process established by the FERC beginning in March of 2000. On January 16, 2001, NU along with the Independent System Operator and five other New England transmission owning utilities filed a proposal to establish a New England RTO. Nuclear Plant Performance and Divestiture - ----------------------------------------- Millstone The Millstone units completed one of their best years ever in 2000. Millstone 2 operated at a capacity factor of 82 percent in 2000 and completed a refueling outage in early June more than four days ahead of schedule. The 40-day, 21-hour outage set a world record for a refueling that included a full generator rewind. Millstone 3 operated at virtually a 100 percent capacity factor in 2000 and ran for 585 consecutive days before beginning a scheduled refueling outage on February 3, 2001. Millstone 3 is expected to return to service by the end of the first quarter of 2001. On August 7, 2000, CL&P and certain other joint owners reached an agreement to sell substantially all of the Millstone units, located in Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including approximately $105 million for nuclear fuel. Dominion has also agreed to assume responsibility for decommissioning the three units and NU will transfer to Dominion all funds in the Millstone decommissioning trust. Additionally, NU is obligated to top-off the decommissioning trust if its value does not equal an agreed upon amount at closing. That amount is pursuant to the purchase and sale agreement (PSA) with Dominion, subject to adjustment for delays in the closing of the sale and Millstone 1 not meeting the "cold and dark" condition specified in the PSA. If the transaction is consummated as proposed, CL&P would receive gross proceeds of approximately $843.2 million on a pretax basis for its respective ownership interest. The proceeds from the sale of this interest will be used to reduce the company's stranded costs under restructuring and the cash proceeds will be used to repay subsidiary debt and capital lease obligations and to return equity capital to the parent company. In preparation for the divestiture of the Millstone units, it was discovered that two full-length irradiated fuel rods are missing. NU believes that the two rods remain stored in the Millstone 1 spent fuel pool or were shipped in a shielded cask to a facility licensed to accept radioactive material. NU's investigation into the location of the two rods is ongoing. NU is responsible for any potential liabilities, which are not determinable at this time, related to these missing fuel rods. NU currently expects to close on the sale of Millstone as early as the end of March 2001. Seabrook Seabrook operated at a capacity factor of 78 percent in 2000. The unit began a scheduled refueling outage on October 21, 2000. The outage was extended by approximately two months as a result of the need to repair extensive problems with a back-up diesel generator. Seabrook returned to service on January 29, 2001. On December 15, 2000, NU filed its divestiture plan for Seabrook, including CL&P's 4.06 percent ownership interest, with the New Hampshire Public Utilities Commission and the DPUC. NU hopes to complete the sale in 2002. Yankee Companies In 1999, the Vermont Yankee Nuclear Power Corporation (VYNPC) agreed to sell its nuclear generating unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the obligation to decommission the unit after it is taken out of service, and the owners of VYNPC (including CL&P) agreed to fund their shares of the decommissioning costs up to a negotiated amount. Subsequent to the time that agreement was executed, the original proposed acquiring company increased its purchase price and three other unaffiliated companies have indicated their interest in buying VYNPC's generating unit on terms that have not been disclosed. On February 14, 2001, the Vermont Public Service Board dismissed the acquiring company's petition for approval and VYNPC agreed to work with the Vermont regulators to develop an auction process for the sale of the unit. At present, CL&P expects that the unit will be sold, but the identity of the owner and the terms of sale, including price, future decommissioning obligations and future power purchase obligations, are not known. Nuclear Decommissioning In connection with the aforementioned sale of the Millstone units, Dominion has agreed to assume responsibility for decommissioning the Millstone units. For further information regarding nuclear decommissioning, see Note 10, "Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. Spent Nuclear Fuel Disposal Costs The United States Department of Energy (DOE) originally was scheduled to begin accepting delivery of spent nuclear fuel in 1998. However, delays in confirming the suitability of a permanent storage site continually have postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. CL&P has the primary responsibility for the interim storage of its spent nuclear fuel prior to divestiture of its nuclear units. For further information regarding spent nuclear fuel disposal costs, see Note 9D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements. Other Matters - ------------- Environmental Matters CL&P is subject to environmental laws and regulations structured to mitigate or remove the effect of past operations and to improve or maintain the quality of the environment. For further information regarding environmental matters, see Note 9C, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements. Other Commitments and Contingencies For further information regarding other commitments and contingencies, see Note 9, "Commitments and Contingencies," to the consolidated financial statements. Forward Looking Statements This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in historical weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, and other presently unknown or unforeseen factors. RESULTS OF OPERATIONS - --------------------- The components of significant income statement variances for the past two years are provided in the table below. Income Statement Variances (Millions of Dollars) 2000 over/(under) 1999 1999 over/(under) 1998 ----------------------------------------------- Amount Percent Amount Percent ------ ------- ------ ------- Operating Revenues $483 20% $ 66 3% Operating Expenses: Fuel, purchased and net interchange power 738 80 (143) (13) Other operation (68) (14) (41) (8) Maintenance (82) (38) (53) (20) Depreciation (76) (39) (23) (10) Amortization of regulatory assets, net (350) (78) 327 (a) Federal and state income taxes 9 7 134 (a) Taxes other than income taxes (37) (21) 4 3 Gain on sale of utility plant 286 100 (286) - ---- --- ---- --- Total operating expenses 420 18 (81) (3) ---- --- ---- --- Operating income 63 36 147 (a) ---- --- ---- --- Other Income: Equity in earnings of regional nuclear generating companies 7 (a) (5) (76) Nuclear related costs 39 73 90 63 Other, net 19 73 (20) (a) Other income taxes (6) (16) (30) (45) ---- --- ---- --- Net other income 59 (a) 35 42 Interest charges, net (40) (29) - - ---- --- ---- --- Net income/(loss) $162 (a) $182 93 ==== === ==== === (a) Percent greater than 100. Operating Revenues Operating revenues increased by $483 million or 20 percent in 2000, primarily due to higher wholesale revenues ($510 million), primarily as a result of the sale of the output from Millstone 2 and 3, and the amortization of the gain on the transfer of certain hydroelectric generation assets ($25 million) partially offset by lower retail revenues ($51 million). Retail revenues decreased primarily as a result of a 5 percent retail rate decrease ($108 million), partially offset by higher retail sales ($27 million) and by the impact of Millstone 2 being returned to rate base ($30 million). Retail sales increased by 0.4 percent in 2000. Operating revenues increased by $66 million or 3 percent in 1999, primarily due to higher wholesale revenues ($72 million). The wholesale revenue increase is primarily due to higher energy sales and related capacity and transmission revenues. Retail revenues decreased primarily due to a retail rate reduction ($55 million) and lower fuel clause revenues ($33 million), partially offset by the impact of Millstone 2 and 3 being returned to CL&P's rate base ($13 million) and higher retail sales ($62 million). Retail kilowatt-hour sales increased by 2.9 percent. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in 2000, primarily due to the transition, under industry restructuring, of purchasing full requirements for customers from standard offer suppliers, in addition to the remaining fuel costs of the nuclear units and cogenerators. Fuel, purchased and net interchange power expense decreased in 1999, primarily due to lower replacement power costs due to the return to service of Millstone 2 and 3, partially offset by higher purchased-power costs as a result of a high sales demand. Other Operation and Maintenance Other operation and maintenance (O&M) expenses decreased in 2000, primarily due to lower spending at the nuclear units ($56 million), the decommissioning status of Millstone 1 ($14 million), lower expenses due to the sale of certain fossil generation assets ($65 million), and lower administrative and general expenses ($26 million), partially offset by higher customer service expenses ($39 million). Other O&M expenses decreased in 1999, primarily due to lower costs at the Millstone units ($107 million), lower conservation and load management amortization ($14 million), and lower fossil O&M expenses ($7 million), partially offset by the recognition of environmental insurance proceeds in 1998 ($9 million), higher transmission expenses ($12 million), and higher storm costs ($12 million). Depreciation Depreciation expense decreased in 2000, primarily due to the effect of discontinuing Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," for the generation portion of the business and the resulting reclassification of depreciable nuclear plant balances to regulatory assets ($70 million), the sale of certain fossil generation assets and the transfer of certain hydroelectric generation assets. Depreciation decreased in 1999 primarily due to the retirement of Millstone 1. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased in 2000, primarily due to changes in amortization levels as a result of industry restructuring ($128 million), the amortization in 1999 of the gain on the sale of fossil plants ($286 million), and the completion of the amortization of CL&P's cogeneration deferral in the first quarter of 1999 ($6 million). These decreases were partially offset by higher amortization associated with the reclassified nuclear plant balances ($70 million). Amortization of regulatory assets, net increased in 1999, primarily due to the increased amortization associated with the gain on the sale of fossil generation assets ($286 million), the amortization of CL&P's Millstone 1 remaining investment ($51 million) and the amortization associated with the reclassified nuclear plant balances transferred to regulatory assets ($19 million). These increases were partially offset by the completion of the amortization of the cogeneration deferral in the first quarter of 1999 ($23 million). Federal and State Income Taxes Federal and state income taxes increased in 2000 and 1999, primarily due to higher book taxable income. Taxes Other Than Income Taxes Taxes other than income taxes decreased in 2000, primarily due to lower Connecticut gross earnings tax ($18 million) and lower local property taxes ($7 million). Gain on Sale of Utility Plant CL&P recorded a gain on the sale of its fossil generation assets in 1999. A corresponding amount of amortization expense was recorded. Equity Earnings of Regional Nuclear Generating Companies Equity earnings of regional nuclear generating companies increased in 2000, primarily due to higher earnings from the Connecticut Yankee Atomic Power Company (CYAPC) as a result of a favorable rate settlement. Equity earnings of regional nuclear generating companies decreased in 1999, primarily due to lower earnings from CYAPC. Nuclear Related Costs Nuclear related costs in 2000 are comprised of the settlement of Millstone 3 joint owner litigation, net of insurance proceeds ($9 million) and a settlement with the town of Wallingford ($5 million). In comparison, nuclear related costs in 1999 are comprised of one-time charges related to the write-off of capital projects as a result of the Connecticut standard offer decision ($11 million), the settlement of Millstone 3 joint owner litigation, net of insurance proceeds ($22 million) and the write-off of Connecticut Municipal Electric Energy Cooperative (CMEEC) nuclear costs ($20 million). Nuclear related costs in 1998 are comprised of a write-off of the Millstone 1 entitlement formerly held by CMEEC ($28 million), and the write-off of an unrecoverable Millstone 1 cost as a result of the February 1999 rate decision ($115 million). Other, Net Other, net, increased in 2000, primarily due to the 1999 write-off of stranded costs in relation to the treatment of market-based contracts ($15 million). Other, net, decreased in 1999, primarily due to the 1999 write-off of stranded costs in relation to the treatment of market-based contracts. Interest Charges, Net Interest charges, net, decreased in 2000, primarily due to reacquisitions and retirements of long-term debt in 2000. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - ---------------------------------------- To the Board of Directors of The Connecticut Light and Power Company: We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, comprehensive income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2000. 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 in accordance with auditing standards generally accepted in the United States. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Connecticut Light and Power Company and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut January 23, 2001 (except with respect to the matter discussed in Note 15, as to which the date is March 13, 2001) THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
- ------------------------------------------------------------------------------------------ FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------ (Thousands of Dollars) Operating Revenues................................. $ 2,935,922 $ 2,452,855 $ 2,386,864 ------------ ------------ ------------ Operating Expenses: Operation - Fuel, purchased and net interchange power..... 1,665,806 927,989 1,070,677 Other......................................... 412,230 480,138 520,518 Maintenance...................................... 136,141 217,961 271,317 Depreciation..................................... 117,305 193,776 216,509 Amortization of regulatory assets, net........... 97,315 447,776 120,884 Federal and state income taxes................... 130,994 122,059 (11,642) Taxes other than income taxes.................... 137,846 174,884 170,347 Gain on sale of utility plant.................... - (286,477) - ------------ ------------ ------------ Total operating expenses................... 2,697,637 2,278,106 2,358,610 ------------ ------------ ------------ Operating Income................................... 238,285 174,749 28,254 ------------ ------------ ------------ Other Income/(Loss): Equity in earnings of regional nuclear generating companies........................... 8,246 1,506 6,241 Nuclear related costs............................ (14,099) (53,031) (143,239) Other, net....................................... (7,071) (25,962) (6,075) Minority interest in loss of subsidiary.......... (9,300) (9,300) (9,300) Income taxes..................................... 30,940 36,921 67,127 ------------ ------------ ------------ Other income/(loss), net................... 8,716 (49,866) (85,246) ------------ ------------ ------------ Income/(loss) before interest charges...... 247,001 124,883 (56,992) ------------ ------------ ------------ Interest Charges: Interest on long-term debt....................... 89,841 127,533 133,192 Other interest................................... 9,025 10,918 5,541 ------------ ------------ ------------ Interest charges, net...................... 98,866 138,451 138,733 ------------ ------------ ------------ Net Income/(Loss).................................. $ 148,135 $ (13,568) $ (195,725) ============ ============ ============ CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Net Income/(Loss).................................. $ 148,135 $ (13,568) $ (195,725) ------------ ------------ ------------ Other comprehensive income, net of tax: Unrealized gains on securities................... 90 38 638 Minimum pension liability adjustments............ - - (260) ------------ ------------ ------------ Other comprehensive income, net of tax..... 90 38 378 ------------ ------------ ------------ Comprehensive Income/(Loss) $ 148,225 $ (13,530) $ (195,347) ============ ============ ============
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------- AT DECEMBER 31, 2000 1999 - ---------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS - ------ Utility Plant, at original cost: Electric................................................ $ 5,756,098 $ 5,811,126 Less: Accumulated provision for depreciation......... 4,210,429 4,234,771 ------------- ------------- 1,545,669 1,576,355 Construction work in progress........................... 128,835 115,529 Nuclear fuel, net....................................... 79,672 80,766 ------------- ------------- Total net utility plant.............................. 1,754,176 1,772,650 ------------- ------------- Other Property and Investments: Nuclear decommissioning trusts, at market............... 536,912 516,796 Investments in regional nuclear generating companies, at equity................................... 41,395 54,472 Other, at cost.......................................... 33,708 36,696 ------------- ------------- 612,015 607,964 ------------- ------------- Current Assets: Cash.................................................... 5,461 364 Investment in securitizable assets...................... 98,146 107,620 Notes receivable from affiliated companies.............. 38,000 - Receivables less accumulated provision for uncollectible accounts of $300 in 2000 and 1999........ 29,245 19,680 Accounts receivable from affiliated companies........... 103,763 3,390 Fuel, materials and supplies, at average cost........... 36,332 37,603 Prepayments and other................................... 32,291 35,163 ------------- ------------- 343,238 203,820 ------------- ------------- Deferred Charges: Regulatory assets....................................... 1,835,967 2,564,095 Unamortized debt expense................................ 14,794 16,323 Prepaid pension......................................... 170,672 113,465 Other................................................... 33,336 19,967 ------------- ------------- 2,054,769 2,713,850 ------------- ------------- Total Assets.............................................. $ 4,764,198 $ 5,298,284 ============= =============
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
- ------------------------------------------------------------------------------------------ AT DECEMBER 31, 2000 1999 - ------------------------------------------------------------------------------------------ (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock, $10 par value - authorized 24,500,000 shares; 7,584,884 shares outstanding in 2000 and 12,222,930 shares outstanding in 1999................ $ 75,849 $ 122,229 Capital surplus, paid in.................................. 413,192 665,598 Retained earnings......................................... 243,197 153,254 Accumulated other comprehensive income.................... 506 416 ------------- ------------- Total common stockholder's equity................ 732,744 941,497 Preferred stock not subject to mandatory redemption....... 116,200 116,200 Preferred stock subject to mandatory redemption........... - 79,789 Long-term debt............................................ 1,072,688 1,241,051 ------------- ------------- Total capitalization............................. 1,921,632 2,378,537 ------------- ------------- Minority Interest in Consolidated Subsidiary................ 100,000 100,000 ------------- ------------- Obligations Under Capital Leases............................ 39,910 50,969 ------------- ------------- Current Liabilities: Notes payable to banks.................................... 115,000 90,000 Notes payable to affiliated company....................... - 11,700 Long-term debt and preferred stock - current portion...... 160,000 178,755 Obligations under capital leases - current portion........ 89,959 93,431 Accounts payable.......................................... 153,944 101,106 Accounts payable to affiliated companies.................. 122,106 3,215 Accrued taxes............................................. 32,901 169,214 Accrued interest.......................................... 13,995 18,640 Other..................................................... 31,324 26,347 ------------- ------------- 719,229 692,408 ------------- ------------- Deferred Credits and Other Long-term Liabilities: Accumulated deferred income taxes......................... 977,439 999,473 Accumulated deferred investment tax credits............... 99,771 107,064 Decommissioning obligation - Millstone 1.................. 580,320 580,320 Deferred contractual obligations.......................... 160,590 238,142 Other..................................................... 165,307 151,371 ------------- ------------- 1,983,427 2,076,370 ------------- ------------- Commmitments and Contingencies (Note 9) Total Capitalization and Liabilities........................ $ 4,764,198 $ 5,298,284 ============= =============
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- ------------------------------------------------------------------------------------------------------- Accumulated Capital Retained Other Common Surplus, Earnings Comprehensive Stock Paid In (a) Income Total - ------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1998............ $122,229 $ 641,333 $ 419,972 $ - $1,183,534 Net loss for 1998................. (195,725) (195,725) Cash dividends on preferred stock. (14,139) (14,139) Capital stock expenses, net....... 2,764 2,764 Capital contribution from Northeast Utilities............. 20,000 20,000 Gain on repurchase of preferred stock................. 59 59 Other comprehensive income........ 378 378 --------- ---------- ---------- -------------- ----------- Balance at December 31, 1998.......... 122,229 664,156 210,108 378 996,871 Net loss for 1999................. (13,568) (13,568) Cash dividends on preferred stock. (12,832) (12,832) Capital stock expenses, net....... 1,442 1,442 Allocation of benefits - ESOP..... (30,454) (30,454) Other comprehensive income........ 38 38 --------- ---------- ---------- -------------- ----------- Balance at December 31, 1999.......... 122,229 665,598 153,254 416 941,497 Net income for 2000............... 148,135 148,135 Cash dividends on preferred stock. (7,402) (7,402) Cash dividends on common stock.... (72,014) (72,014) Redemption of preferred stock..... (749) (749) Repurchase of common stock........ (46,380) (253,620) (300,000) Capital stock expenses, net....... 1,963 1,963 Tax benefit for 1993-1999 from reduction of NU parent losses (b)....................... 21,461 21,461 Allocation of benefits - ESOP..... (237) (237) Other comprehensive income........ 90 90 --------- ---------- ---------- -------------- ----------- Balance at December 31, 2000.......... $ 75,849 $ 413,192 $ 243,197 $ 506 $ 732,744 ========= ========== ========== ============== ===========
(a) The company has no dividend restrictions. However, the company has a 30% common equity test to meet and therefore, at December 31, 2000, cannot pay out approximately $152.9 million in equity. (b) In June 1999, CL&P paid NU parent $30.5 million for NU shares issued from 1992 through 1998 on behalf of its employees in accordance with NU's 401(k) plan. This transaction resulted in a reduction of the NU parent loss and a tax benefit to CL&P. The amount in 2000 represents the remaining previously unallocated 1993 through 1999 NU parent losses. The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
- ----------------------------------------------------------------------------------------------- For the Years Ended December 31, - ----------------------------------------------------------------------------------------------- (Thousands of Dollars) 2000 1999 1998 - ----------------------------------------------------------------------------------------------- Operating Activities: Net income/(loss)........................................... $ 148,135 $ (13,568) $(195,725) Adjustments to reconcile to net cash provided by operating activities: Depreciation.............................................. 117,305 193,776 216,509 Deferred income taxes and investment tax credits, net..... 5,672 (140,459) (65,689) Amortization of regulatory assets, net ................... 97,315 447,776 120,884 Amortization of recoverable energy costs.................. 4,155 12,702 30,745 Nuclear related costs..................................... 14,099 53,031 143,239 Tax benefit for 1993-1999 from reduction of NU parent losses........................... 21,461 - - Allocation of ESOP benefits............................... (237) (30,454) - Gain on sale of utility plant............................. 25,444 (286,477) - Net other (uses)/sources of cash.......................... (112,915) (141,675) 43,297 Changes in working capital: Receivables............................................... (109,938) 837 29,914 Fuel, materials and supplies.............................. 1,271 34,379 9,896 Accounts payable.......................................... 171,729 (49,477) (63,592) Accrued taxes............................................. (136,313) 149,818 (13,621) Investments in securitizable assets....................... 9,474 52,633 45,372 Other working capital (excludes cash)..................... 3,204 16,585 62,901 ---------- ---------- ---------- Net cash flows provided by operating activities............... 259,861 299,427 364,130 ---------- ---------- ---------- Investing Activities: Investments in plant: Electric utility plant.................................... (208,249) (180,982) (132,194) Nuclear fuel.............................................. (35,709) (26,198) (8,444) ---------- ---------- ---------- Net cash flows used for investments in plant.............. (243,958) (207,180) (140,638) Investment in NU system Money Pool.......................... (38,000) 6,600 (6,600) Investments in nuclear decommissioning trusts............... (25,133) (54,582) (54,106) Other investment activities, net............................ 10,246 (355) (1,655) Net proceeds from the transfer/sale of utility plant........ 686,807 516,912 - Capital contributions from Northeast Utilities.............. - - 20,000 ---------- ---------- ---------- Net cash flows provided by/(used in) investing activities..... 389,962 261,395 (182,999) ---------- ---------- ---------- Financing Activities: Net increase/(decrease) in short-term debt.................. 13,300 91,700 (86,300) Reacquisitions and retirements of long-term debt............ (179,071) (620,010) (45,006) Reacquisitions and retirements of preferred stock........... (99,539) (19,750) (35,711) Repurchase of common shares................................. (300,000) - - Cash dividends on preferred stock........................... (7,402) (12,832) (14,139) Cash dividends on common stock.............................. (72,014) - - ---------- ---------- ---------- Net cash flows used in financing activities................... (644,726) (560,892) (181,156) ---------- ---------- ---------- Net increase/(decrease) in cash for the period................ 5,097 (70) (25) Cash - beginning of period.................................... 364 434 459 ---------- ---------- ---------- Cash - end of period.......................................... $ 5,461 $ 364 $ 434 ========== ========== ========== Supplemental Cash Flow Information: Cash paid/(refunded) during the year for: Interest, net of amounts capitalized........................ $ 96,735 $ 142,398 $ 110,119 ========== ========== ========== Income taxes................................................ $ 226,380 $ 19,754 $ (46,747) ========== ========== ========== Increase in obligations: Niantic Bay Fuel Trust...................................... $ 6,535 $ 4,752 $ 10,208 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------ 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. About The Connecticut Light and Power Company The Connecticut Light and Power Company (CL&P or the company) along with the Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), North Atlantic Energy Corporation (NAEC), and Holyoke Water Power Company (HWP) are the operating companies comprising the Northeast Utilities system (NU system) and are wholly owned by Northeast Utilities (NU). The NU system serves in excess of 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues. The NU system furnishes franchised retail electric service in Connecticut, New Hampshire and western Massachusetts through CL&P, PSNH and WMECO. NAEC sells all of its entitlement to the capacity and output of the Seabrook Station nuclear unit (Seabrook) to PSNH under the terms of two life-of-unit, full cost recovery contracts. HWP, also is engaged in the production and distribution of electric power. On March 1, 2000, NU completed its acquisition of Yankee Energy System, Inc., the parent company of Yankee Gas Services Company, Connecticut's largest natural gas distribution system. NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act) and the NU system, including CL&P, is subject to provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. CL&P is subject to further regulation for rates, accounting and other matters by the FERC and the Connecticut Department of Public Utility Control (DPUC). Several wholly owned subsidiaries of NU provide support services for the NU system companies, including CL&P, and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing, and other services to the NU system companies, including CL&P. Northeast Nuclear Energy Company acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear units. North Atlantic Energy Service Corporation has operational responsibility for Seabrook. In addition, CL&P has established a special purpose subsidiary whose business consists of the purchase and resale of receivables. B. Presentation The consolidated financial statements of CL&P include the accounts of all subsidiaries. Intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity and are subject to approval by various federal and state regulatory agencies and the DPUC. C. New Accounting Standards Derivative Instruments: Effective January 1, 2001, CL&P adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS No. 133 requires that derivative instruments be recorded as an asset or liability measured at its fair value and that changes in the fair value of derivative instruments be recognized currently in earnings unless specific hedge accounting criteria are met. In order to implement SFAS No. 133 by January 1, 2001, NU established a cross-functional project team to identify all derivative instruments, measure the fair value of those derivative instruments, designate and document various hedge relationships, and evaluate the effectiveness of those hedge relationships. NU has completed the process of identifying all derivative instruments and has established appropriate fair value measurements of those derivative instruments in place at January 1, 2001. In addition, for those derivative instruments which are hedging an identified risk, NU has designated and documented all hedging relationships anew. Management believes the adoption of this new standard will not have a material impact on CL&P's financial position or results of operations. Transfers of Financial Assets: In September 2000, the Financial Accounting Standards Board (FASB) issued SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities - a Replacement of FASB Statement No. 125." SFAS No. 140 revises the criteria for accounting for securitizations, other financial asset transfers and collateral and introduces new disclosures, but otherwise carries forward most of the provisions of SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," without amendment. SFAS No. 140 is effective for transfers and servicing of financial assets and extinguishments of liabilities occurring after March 31, 2001, and is effective for recognition and reclassification of collateral and for disclosures relating to securitization transactions and collateral for fiscal years ending after December 15, 2000. The adoption of the disclosure requirements under SFAS No. 140 did not have a material impact on CL&P's consolidated financial statements. Revenue Recognition: In December 1999, the SEC issued Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition." The adoption of SAB No. 101, as amended, did not have a material impact on CL&P's consolidated financial statements. D. Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: CL&P owns common stock in four regional nuclear companies (Yankee Companies). CL&P's ownership interests in the Yankee Companies at December 31, 2000 and 1999, which are accounted for on the equity method due to CL&P's ability to exercise significant influence over their operating and financial policies are 34.5 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 24.5 percent of the Yankee Atomic Electric Company (YAEC), 12 percent of the Maine Yankee Atomic Power Company (MYAPC), and 9.5 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC). CL&P's total equity investment in the Yankee Companies at December 31, 2000 and 1999, is $41.4 million and $54.5 million, respectively. Each Yankee Company owns a single nuclear generating unit. However, VYNPC is the only unit still in operation at December 31, 2000. Millstone: CL&P has an 81 percent joint ownership interest in both Millstone 1, a 660 megawatt (MW) nuclear unit, which is currently in decommissioning status, and Millstone 2, an 870 MW nuclear generating unit. CL&P has a 52.93 percent joint ownership interest in Millstone 3, a 1,154 MW nuclear generating unit. On August 7, 2000, CL&P and certain other joint owners reached an agreement to sell substantially all of the Millstone units to Dominion Resources, Inc. (Dominion) for approximately $1.3 billion, including approximately $105 million for nuclear fuel. NU currently expects to close on the sale of Millstone as early as the end of March 2001. Seabrook: CL&P has a 4.06 percent joint ownership interest in Seabrook, a 1,148 MW nuclear generating unit. CL&P expects to auction its joint ownership interest in Seabrook, jointly with NAEC, in 2001 with a closing on the sale expected in 2002. Plant-in-service and the accumulated provision for depreciation for CL&P's share of Millstone 2 and 3 and Seabrook are as follows: ---------------------------------------------------------------------- At December 31, 2000 1999 ---------------------------------------------------------------------- (Millions of Dollars) Plant-in-service Millstone 2............................... $ 779.7 $ 771.7 Millstone 3............................... 1,924.7 1,915.1 Seabrook.................................. 174.7 173.9 Accumulated provision for depreciation Millstone 2............................... $ 779.1 $ 743.3 Millstone 3............................... 1,815.0 1,822.8 Seabrook.................................. 164.0 165.7 ---------------------------------------------------------------------- E. Depreciation The provision for depreciation is calculated using the straight-line method based on estimated remaining useful lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. The costs of closure and removal of nonnuclear facilities are accrued over the life of the plant as a component of depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3 percent in 2000, 3.3 percent in 1999 and 3.2 percent in 1998. As a result of discontinuing the application of SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation," for CL&P's generation business in 1999, including CL&P's ownership interest in Seabrook, the company recorded a charge to accumulated depreciation for the nuclear plant in excess of the estimated fair market value at the time in the amount of $1.7 billion and a corresponding regulatory asset was created. F. Revenues Revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the DPUC. Regulatory commissions also have authority over the terms and conditions of nontraditional rate- making arrangements. At the end of each accounting period, CL&P accrues a revenue estimate for the amount of energy delivered but unbilled. G. Regulatory Accounting and Assets The accounting policies of CL&P and the accompanying consolidated financial statements conform to accounting principles generally accepted in the United States applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71. As a result of final restructuring orders issued in 1999, CL&P discontinued the application of SFAS No. 71 for the generation portion of its business. CL&P's transmission and distribution business will continue to be cost-based and management believes the application of SFAS No. 71 continues to be appropriate. Management continues to believe it is probable that CL&P will recover its investments in long-lived assets, including regulatory assets through charges to their transmission and distribution customers generally over periods which end between the years 2015 through 2026, subject to certain adjustments. The majority for CL&P will be recovered through a transition charge over a 12-year period. In addition, all material regulatory assets are earning a return. The components of CL&P's regulatory assets are as follows: ---------------------------------------------------------------------- At December 31, 2000 1999 ---------------------------------------------------------------------- (Millions of Dollars) Recoverable nuclear costs............... $1,122.4 $1,781.9 Income taxes, net....................... 371.9 399.5 Unrecovered contractual obligations..... 171.8 228.9 Recoverable energy costs, net........... 85.2 89.5 Other................................... 84.7 64.3 -------- -------- $1,836.0 $2,564.1 ======== ======== ---------------------------------------------------------------------- As a result of discontinuing the application of SFAS No. 71 in 1999 for CL&P's generation business, the company reclassified nuclear plant in excess of its estimated fair market value from plant to regulatory assets. As of December 31, 2000 and 1999, excluding the impact of the transfer of generation assets to Northeast Generation Company in 2000, the unamortized balance ($1.35 billion and $1.38 billion, respectively) is classified as recoverable nuclear costs. Also included in that regulatory asset component for 2000 and 1999 are $344.3 million and $401.9 million, respectively, which includes Millstone 1 recoverable nuclear costs relating to the recoverable portion of the undepreciated plant and related assets ($51.2 million and $101.9 million, respectively) and the decommissioning and closure obligation ($293.1 million and $300 million, respectively). H. Income Taxes The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows: ---------------------------------------------------------------------- At December 31, 2000 1999 ---------------------------------------------------------------------- (Millions of Dollars) Accelerated depreciation and other plant-related differences....... $800.0 $845.6 Regulatory assets - income tax gross up................... 142.6 153.7 Other................................... 34.8 0.2 ------ ------ $977.4 $999.5 ====== ====== ----------------------------------------------------------------------- I. Unrecovered Contractual Obligations Under the terms of contracts with the Yankee Companies, the shareholder-sponsored companies, including CL&P, are responsible for their proportionate share of the remaining costs of the units, including decommissioning. As management expects that CL&P will be allowed to recover these costs from its customers, CL&P has recorded a regulatory asset, with a corresponding obligation, on its consolidated balance sheet. J. Recoverable Energy Costs Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P is currently recovering these costs through rates. As of December 31, 2000 and 1999, CL&P's total D&D Assessment deferrals were $24.1 million and $26.9 million, respectively. Through December 31, 1999, CL&P had an energy adjustment clause under which fuel prices above or below base-rate levels were charged to or credited to customers. Coincident with the start of restructuring, the energy adjustment clause was terminated. Energy costs deferred and not yet collected under the energy adjustment clause amounted to $61.1 million and $62.6 million at December 31, 2000 and 1999, respectively. This balance is recorded as a generation-related stranded cost and will be recovered through a transition charge mechanism pending final DPUC approval. 2. SHORT-TERM DEBT Limits: The amount of short-term borrowings that may be incurred by CL&P is subject to periodic approval by either the SEC under the 1935 Act or by state regulators. Currently, SEC authorization allows CL&P to incur total short-term borrowings up to a maximum of $375 million. In addition, the charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt the company may incur. As of December 31, 2000, CL&P's charter permits CL&P to incur $245 million of additional unsecured debt. Credit Agreement: On November 17, 2000, CL&P and WMECO entered into a 364-day revolving credit facility for $350 million, replacing the previous $500 million facility which was to expire on November 17, 2000. CL&P may draw up to $200 million under the facility which, until the nuclear divestiture, is secured by second mortgages on Millstone 2 and 3. Once CL&P and WMECO receive the proceeds from securitization, the $350 million revolving credit facility will be reduced to $250 million, with a $150 million limit for CL&P. Unless extended, the credit facility will expire on November 16, 2001. At December 31, 2000 and 1999, there were $115 million and $90 million, respectively, in borrowings under these facilities. Under the aforementioned credit agreement, CL&P may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service. The weighted average interest rate on CL&P's notes payable to banks outstanding on December 31, 2000 and 1999, was 8.41 percent and 7.69 percent, respectively. Maturities of short-term debt obligations were for periods of three months or less. This credit agreement provides that CL&P must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, common equity ratios and interest coverage ratios. CL&P currently is and expects to remain in compliance with these covenants. Money Pool: Certain subsidiaries of NU, including CL&P, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the NU system and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on loans from NU parent, however, bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 2000 and 1999, CL&P had $38 million of lendings to and $11.7 million of borrowings from the Pool, respectively. The interest rate on lendings to and borrowings from the Pool at December 31, 2000 and 1999, was 5.4 percent and 4.9 percent, respectively. 3. LEASES CL&P finances its respective shares of nuclear fuel for Millstone 2 and 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement. This capital lease agreement has an expiration date of June 1, 2040. At December 31, 2000 and 1999, the present value of CL&P's capital lease obligation to the NBFT was $112.6 million and $127.2 million, respectively. In connection with the planned nuclear divestiture, the NBFT capital lease will be terminated, the nuclear fuel will be transferred to Dominion and the related $180 million Series G Intermediate Term Note Agreement will be extinguished with the divestiture proceeds. CL&P makes quarterly lease payments for the cost of nuclear fuel consumed in the reactors based on a units-of-production method at rates which reflect estimated kilowatt-hours of energy provided plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, CL&P's ownership interest in the nuclear fuel transfers to CL&P. CL&P also has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, nuclear control room simulators, and office space. The provisions of these lease agreements generally provide for renewal options. Capital lease rental payments charged to operating expense were $36.3 million in 2000, $10 million in 1999 and $20.5 million in 1998. Interest included in capital lease rental payments was $7.9 million in 2000, $9.4 million in 1999 and $14.1 million in 1998. Operating lease rental payments charged to expense were $9.8 million in 2000, $14.3 million in 1999 and $17.9 million in 1998. Future minimum rental payments, excluding annual nuclear fuel lease payments and executory costs such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 2000, are as follows: ------------------------------------------------------------------------- Year Capital Leases Operating Leases ------------------------------------------------------------------------- (Millions of Dollars) 2001................................ $ 2.4 $11.5 2002................................ 2.4 10.0 2003................................ 2.4 8.1 2004................................ 2.4 6.6 2005................................ 2.4 5.9 After 2005.......................... 27.0 13.4 ------ ----- Future minimum lease payments....... 39.0 $55.5 ===== Less amount representing interest... 21.7 ------ Present value of future minimum lease payments for other than nuclear fuel...................... 17.3 Present value of future nuclear fuel lease payments............... 112.6 ------ Present value of future minimum lease payments.................... $129.9 ====== ------------------------------------------------------------------------- 4. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION Details of preferred stock not subject to mandatory redemption are as follows: -------------------------------------------------------------------------- December 31, Shares 2000 Outstanding December 31, Redemption December 31, --------------- Description Price 2000 2000 1999 -------------------------------------------------------------------------- (Millions of Dollars) $1.90 Series of 1947 $52.50 163,912 $ 8.2 $ 8.2 $2.00 Series of 1947 54.00 336,088 16.8 16.8 $2.04 Series of 1949 52.00 100,000 5.0 5.0 $2.20 Series of 1949 52.50 200,000 10.0 10.0 3.90% Series of 1949 50.50 160,000 8.0 8.0 $2.06 Series E of 1954 51.00 200,000 10.0 10.0 $2.09 Series F of 1955 51.00 100,000 5.0 5.0 4.50% Series of 1956 50.75 104,000 5.2 5.2 4.96% Series of 1958 50.50 100,000 5.0 5.0 4.50% Series of 1963 50.50 160,000 8.0 8.0 5.28% Series of 1967 51.43 200,000 10.0 10.0 $3.24 Series G of 1968 51.84 300,000 15.0 15.0 6.56% Series of 1968 51.44 200,000 10.0 10.0 ------ ------ $116.2 $116.2 ====== ====== -------------------------------------------------------------------------- 5. LONG-TERM DEBT Details of long-term debt outstanding are as follows: -------------------------------------------------------------------------- At December 31, 2000 1999 -------------------------------------------------------------------------- (Millions of Dollars) First Mortgage Bonds: 5 3/4% Series XX due 2000................... $ - $ 159.0 7 7/8% Series A due 2001................... 160.0 160.0 7 3/4% Series C due 2002................... 200.0 200.0 7 3/8% Series TT due 2019................... - 20.0 8 1/2% Series C due 2024................... 115.0 115.0 7 7/8% Series D due 2024................... 140.0 140.0 -------- -------- 615.0 794.0 Pollution Control Notes: Variable rate, due 2016-2022.............. 46.4 46.4 Variable rate, tax exempt, due 2028-2031........................... 377.5 377.5 Fees and interest due for spent nuclear fuel disposal costs....................... 194.7 183.4 Other....................................... - 0.2 Less amounts due within one year............ 160.0 159.0 Unamortized premium and discount, net....... (0.9) (1.4) -------- -------- Long-term debt, net......................... $1,072.7 $1,241.1 ======== ======== -------------------------------------------------------------------------- Long-term debt maturities and cash sinking fund requirements, excluding fees and interest due for spent nuclear fuel disposal costs, on debt outstanding at December 31, 2000, for the years 2001 through 2005 are $160 million, $200 million, and no requirements for 2003, 2004 and 2005, respectively. Essentially all utility plant of CL&P is subject to the liens of the company's first mortgage bond indenture. CL&P has secured $315.5 million of pollution control notes with second mortgage liens on Millstone 1, junior to the liens of its first mortgage bond indenture. CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds with bond insurance secured by first mortgage bonds and a liquidity facility. The average effective interest rates on the variable-rate pollution control notes ranged from 3.2 percent to 4.9 percent for 2000 and from 2.2 percent to 3.9 percent for 1999. 6. INCOME TAX EXPENSE The components of the federal and state income tax provisions were charged/(credited) to operations as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Current income taxes: Federal.................................... $ 77.2 $197.7 $ (9.2) State...................................... 17.2 27.9 (3.9) ------ ------ ------ Total current............................ 94.4 225.6 (13.1) ------ ------ ------ Deferred income taxes, net: Federal.................................... 10.6 (113.0) (34.9) State...................................... 2.4 (20.1) (17.5) ------ ------ ------ Total deferred........................... 13.0 (133.1) (52.4) ------ ------ ------ Investment tax credits, net.................. (7.3) (7.3) (13.3) ------ ------ ------ Total income tax expense/(credit)............ $100.1 $ 85.2 $(78.8) ====== ====== ====== -------------------------------------------------------------------------- The components of total income tax expense/(credit) are classified as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Income taxes charged to operating expenses... $131.0 $122.1 $(11.7) Other income taxes........................... (30.9) (36.9) (67.1) ------ ------ ------ Total income tax expense/(credit)............ $100.1 $ 85.2 $(78.8) ====== ====== ====== -------------------------------------------------------------------------- Deferred income taxes are comprised of the tax effects of temporary differences as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Depreciation, leased nuclear fuel, settlement credits and disposal costs...... $13.8 $ (9.9) $ (5.6) Regulatory deferral.......................... (14.1) 6.2 (36.7) State net operating loss carryforward........ - 7.8 1.1 Regulatory disallowance...................... - (24.2) (18.1) Sale of fossil generation assets............. - (126.1) - Pension accruals............................. 13.6 9.8 8.9 Other........................................ (0.3) 3.3 (2.0) ----- ------- ------ Deferred income taxes, net................... $13.0 $(133.1) $(52.4) ===== ======= ====== -------------------------------------------------------------------------- A reconciliation between income tax expense/(credit) and the expected tax expense/(credit) at 35 percent of pretax income/(loss) is as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Expected federal income tax.................. $ 86.9 $25.0 $(96.1) Tax effect of differences: Depreciation............................... 5.8 27.1 20.9 Amortization of regulatory assets.......... 3.6 31.9 22.7 Investment tax credit amortization......... (7.3) (7.3) (13.3) State income taxes, net of federal benefit.......................... 12.7 5.1 (13.9) Other, net................................. (1.6) 3.4 0.9 ------ ----- ------ Total income tax expense/(credit)............ $100.1 $85.2 $(78.8) ====== ===== ====== -------------------------------------------------------------------------- 7. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS The NU system companies, including CL&P, participate in a uniform noncontributory defined benefit retirement plan covering substantially all regular NU system employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. CL&P's portion of the NU system's total pension credit, part of which was credited to utility plant, was $57.2 million in 2000, $40.3 million in 1999 and $32.6 million in 1998. Currently, CL&P's policy is to annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code. The NU system companies, including CL&P, also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. These benefits are available for employees retiring from CL&P who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. CL&P annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible. Pension and trust assets are invested primarily in domestic and international equity securities and bonds. The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' funded status:
------------------------------------------------------------------------------- At December 31, ------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits ------------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 2000 1999 ------------------------------------------------------------------------------- Benefit obligation at beginning of year......... $ (551.9) $ (562.7) $(131.9) $(133.8) Service cost................... (9.7) (11.0) (1.9) (2.3) Interest cost.................. (42.3) (40.0) (10.1) (9.3) Plan amendment................. - (32.5) - - Transfers...................... (4.9) 1.8 - - Actuarial (loss)/gain.......... (18.9) 58.8 (5.2) (0.6) Benefits paid.................. 40.4 35.5 12.8 14.1 Settlements and other.......... - (1.8) - - ------------------------------------------------------------------------------- Benefit obligation at end of year............... $ (587.3) $ (551.9) $(136.3) $(131.9) ------------------------------------------------------------------------------- Change in plan assets Fair value of plan assets at beginning of year......... $1,037.8 $ 935.7 $ 59.7 $ 53.8 Actual return on plan assets... (3.5) 135.8 3.0 6.6 Employer contribution.......... - - 12.5 13.4 Benefits paid.................. (40.4) (35.5) (12.8) (14.1) Transfers...................... 4.9 1.8 - - ------------------------------------------------------------------------------- Fair value of plan assets at end of year............... $ 998.8 $1,037.8 $ 62.4 $ 59.7 ------------------------------------------------------------------------------- Funded status at December 31... $ 411.5 $ 485.9 $ (73.9) $ (72.2) Unrecognized transition (asset)/obligation........... (3.7) (4.6) 88.2 95.5 Unrecognized prior service cost................. 30.4 33.1 - - Unrecognized net gain.......... (267.5) (400.9) (14.3) (23.3) ------------------------------------------------------------------------------- Prepaid benefit cost........... $ 170.7 $ 113.5 $ - $ - -------------------------------------------------------------------------------
The following actuarial assumptions were used in calculating the plans' year end funded status: ------------------------------------------------------------------------- At December 31, ------------------------------------------------------------------------- Pension Benefits Postretirement Benefits ------------------------------------------------------------------------- 2000 1999 2000 1999 ------------------------------------------------------------------------- Discount rate............. 7.50% 7.75% 7.50% 7.75% Compensation/progression rate.................... 4.50 4.75 4.50 4.75 Health care cost trend rate (a).......... N/A N/A 5.26 5.57 ------------------------------------------------------------------------- (a) The annual per capita cost of covered health care benefits was assumed to decrease to 4.91 percent by 2001. The components of net periodic benefit (credit)/cost are: -------------------------------------------------------------------------- For the Years Ended December 31, -------------------------------------------------------------------------- Postretirement Pension Benefits Benefits -------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 1998 2000 1999 1998 -------------------------------------------------------------------------- Service cost......... $ 9.7 $ 11.0 $ 9.8 $ 1.9 $ 2.3 $ 2.0 Interest cost........ 42.3 40.0 37.5 10.1 9.3 9.2 Expected return on plan assets..... (88.4) (78.1) (68.4) (4.9) (4.2) (3.6) Amortization of unrecognized net transition (asset)/ obligation......... (0.9) (0.9) (0.9) 7.3 7.3 7.4 Amortization of prior service cost....... 2.7 2.7 0.3 - - - Amortization of actuarial gain..... (22.6) (15.0) (10.9) - - - Other amortization, net.. - - - (1.9) (1.3) (1.7) -------------------------------------------------------------------------- Net periodic benefit (credit)/cost....... $(57.2) $(40.3) $(32.6) $12.5 $13.4 $13.3 -------------------------------------------------------------------------- For calculating pension and postretirement benefit costs, the following assumptions were used: -------------------------------------------------------------------------- For the Years Ended December 31, -------------------------------------------------------------------------- Postretirement Pension Benefits Benefits -------------------------------------------------------------------------- 2000 1999 1998 2000 1999 1998 -------------------------------------------------------------------------- Discount rate........ 7.75% 7.00% 7.25% 7.75% 7.00% 7.25% Expected long-term rate of return..... 9.50 9.50 9.50 N/A N/A N/A Compensation/ progression rate.... 4.75 4.25 4.25 4.75 4.25 4.25 Long-term rate of return - Health assets, net of tax....... N/A N/A N/A 7.50 7.50 7.75 Life assets........ N/A N/A N/A 9.50 9.50 9.50 -------------------------------------------------------------------------- Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects: -------------------------------------------------------------------------- One Percentage One Percentage (Millions of Dollars) Point Increase Point Decrease -------------------------------------------------------------------------- Effect on total service and interest cost components $0.5 $(0.5) Effect on postretirement benefit obligation $6.2 $(5.9) -------------------------------------------------------------------------- The trust holding the health plan assets is subject to federal income taxes. 8. SALE OF CUSTOMER RECEIVABLES As of December 31, 2000 and 1999, CL&P had sold accounts receivable of $170 million to a third-party purchaser with limited recourse through the CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. In addition, at December 31, 2000 and 1999, $18.9 million and $22.5 million, respectively, of accounts receivable were designated as collateral under the agreement with the CRC. Concentrations of credit risk to the purchaser under the company's agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. 9. COMMITMENTS AND CONTINGENCIES A. Restructuring The 1999 restructuring orders allowed for securitization of CL&P's nonnuclear regulatory assets and the costs to buyout or buydown the various purchased-power contracts. On November 8, 2000, the DPUC approved CL&P's request to securitize an amount not to exceed $1.55 billion of approved, eligible stranded costs, primarily related to above-market purchased-power contracts and generation related regulatory assets. However, the Office of Consumer Counsel (OCC) appealed the securitization order to the Connecticut Superior Court and it remains unclear when securitization financing can be undertaken. B. Nuclear Generation Assets Divestiture On August 7, 2000, CL&P and certain other joint owners reached an agreement to sell substantially all of the Millstone units, located in Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including approximately $105 million for nuclear fuel. Dominion has also agreed to assume responsibility for decommissioning the three units and NU will transfer to Dominion all funds in the Millstone decommissioning trust. Additionally, NU is obligated to top-off the decommissioning trust if its value does not equal a previously agreed upon level as defined. NU expects to close on the sale of Millstone as early as the end of March 2001. If the transaction is consummated as proposed, CL&P would receive gross proceeds of approximately $843.2 million on a pretax basis for its respective ownership interest. The proceeds from the sale of this interest will be used to reduce the company's stranded costs under restructuring and the cash proceeds will be used to repay subsidiary debt and capital lease obligations and to return equity capital to the parent company. The DPUC approved the recovery of Millstone- related stranded costs not offset by asset divestiture proceeds. Pursuant to the DPUC order, CL&P will seek recovery of Millstone post-1997 capital additions totaling $50 million. The OCC has appealed CL&P's ability to recover these costs. C. Environmental Matters The NU system, including CL&P, is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of our environment. As such, the NU system, including CL&P, have active environmental auditing and training programs and believe they are substantially in compliance with the current laws and regulations. However, the normal course of operations may involve activities and substances that expose CL&P to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on CL&P's consolidated financial statements. Based upon currently available information for the estimated remediation costs as of December 31, 2000 and 1999, the liability recorded by CL&P for its estimated environmental remediation costs amounted to $5.2 million and $6.9 million, respectively. D. Spent Nuclear Fuel Disposal Costs Under the Nuclear Waste Policy Act of 1982, CL&P must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high- level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. As of December 31, 2000 and 1999, fees due to the DOE for the disposal of Prior Period Fuel were $194.7 million and $183.4 million, respectively, including interest costs of $128.1 million and $116.9 million, respectively. Fees for nuclear fuel burned on or after April 7, 1983, are billed currently to customers and paid to the DOE on a quarterly basis. CL&P is responsible for fees to be paid for fuel burned until the divestiture of the Millstone and Seabrook nuclear units. E. Nuclear Insurance Contingencies Insurance policies covering CL&P's ownership share of the NU system's nuclear facilities have been purchased for the primary cost of repair, replacement or decontamination of utility property, certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement or decontamination or premature decommissioning of utility property. CL&P is subject to retroactive assessments if losses under those policies exceed the accumulated funds available to the insurer. The maximum potential assessments with respect to losses arising during the current policy year for the primary property insurance program, the replacement power policies and the excess property damage policies are $5 million, $2.7 million and $6.1 million, respectively. In addition, insurance has been purchased by the NU system in the aggregate amount of $200 million on an industry basis for coverage of worker claims. Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third-party liability indemnification program, the NU system, including CL&P, could be assessed liabilities in proportion to its ownership interest in each of its nuclear units up to $83.9 million. The NU system's payment of this assessment would be limited to, in proportion to its ownership interest in each of its nuclear units, $10 million in any one year per nuclear unit. In addition, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection, the NU system, including CL&P, would be subject to an additional 5 percent, or $4.2 million, liability, in proportion to its ownership interests in each of its nuclear units. Based upon its ownership interests in the Millstone units and in Seabrook, CL&P's maximum liability, including any additional assessments, would be $192.9 million per incident, of which payments would be limited to $21.9 million per year. In addition, through purchased-power contracts with VYNPC, CL&P would be responsible for up to an additional assessment of $8.4 million per incident, of which payments would be limited to $1 million per year. CL&P expects to terminate its nuclear insurance upon the divestiture of its nuclear units. F. Long-Term Contractual Arrangements Yankee Companies: Under the terms of its agreement, CL&P paid its ownership (or entitlement) shares of costs, which included depreciation, operation and maintenance (O&M) expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs were recorded as purchased-power expenses. CL&P's cost of purchases under its contract with VYNPC amounted to $14.5 million in 2000, $17 million in 1999, and $15.9 million in 1998. VYNPC is in the process of selling its nuclear unit. Upon completion of the sale, this long-term contract will be terminated. Nonutility Generators (NUGs): CL&P has entered into various arrangements for the purchase of capacity and energy from NUGs. CL&P's total cost of purchases under these arrangements amounted to $308.6 million in 2000, $293.8 million in 1999 and $290.7 million in 1998. The company is in the process of renegotiating the terms of these contracts through either a contract buydown or buyout. CL&P expects any payments to the NUGs as a result of these renegotiations to be recovered from the company's customers. Hydro-Quebec: Along with other New England utilities, CL&P has entered into an agreement to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M expenses and capital costs of those facilities. Estimated Annual Costs: The estimated annual costs of CL&P's significant long-term contractual arrangements, absent the effects of any contract terminations, buydowns or buyouts, are as follows: --------------------------------------------------------------------- 2001 2002 2003 2004 2005 --------------------------------------------------------------------- (Millions of Dollars) VYNPC............. $ 16.6 $ 16.9 $ 17.0 $ 18.7 $ 17.6 NUGs.............. 292.5 296.2 301.7 283.3 289.2 Hydro-Quebec...... 15.9 15.4 14.8 14.2 13.7 --------------------------------------------------------------------- 10. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS Millstone and Seabrook: CL&P's operating nuclear power plants, Millstone 2 and 3 and Seabrook, have service lives that are expected to end during the years 2015 through 2026, and upon retirement, must be decommissioned. Millstone 1's expected service life was to end in 2010, however, in July 1998, restart activities were discontinued and decommissioning of the unit began. In connection with the sale of the Millstone units, Dominion has agreed to assume responsibility for decommissioning. Until the divestiture, CL&P recovers sufficient amounts through its allowed rates related to decommissioning costs. CL&P's ownership share of the estimated cost of decommissioning Millstone 2 and 3 and Seabrook, in year end 2000 dollars, is $348.8 million, $343.1 million and $23.8 million, respectively. Nuclear decommissioning costs are accrued over the expected service lives of the units and are included in depreciation expense and the accumulated provision for depreciation. Nuclear decommissioning expenses for these units amounted to $24.4 million in 2000, $19.6 million in 1999 and $19.1 million in 1998. Nuclear decommissioning expenses for Millstone 1 were $20.6 million in 2000, $22.8 million in 1999 and $17.3 million in 1998. Through December 31, 2000 and 1999, total decommissioning expenses of $217.8 million and $185.1 million, respectively, have been collected from customers and are reflected in the accumulated provision for depreciation. External decommissioning trusts have been established for the costs of decommissioning the Millstone units. Payments for CL&P's ownership share of the cost of decommissioning Seabrook are paid to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assumes after-tax earnings on the Millstone and Seabrook decommissioning funds of 5.5 percent and 6.5 percent, respectively. As of December 31, 2000 and 1999, $191.9 million and $164.2 million, respectively, have been transferred to external decommissioning trusts. Earnings on the decommissioning trusts increase the decommissioning trust balances and the accumulated provisions for depreciation. Unrealized gains and losses associated with the decommissioning trusts also impact the balance of the trusts and the accumulated provisions for depreciation. The fair values of the amounts in the external decommissioning trusts were $310.1 million and $282.2 million at December 31, 2000 and 1999, respectively. Upon divestiture, balances in the decommissioning trusts will be transferred to the buyer. NU is obligated to top-off the Millstone decommissioning trust if its value does not equal an agreed upon amount at closing, pursuant to the conditions set forth in the purchase and sale agreement. Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. CL&P's ownership share of estimated costs, in year end 2000 dollars, of decommissioning this unit is $42.9 million. In 1999, VYNPC agreed to sell its nuclear generating unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the obligation to decommission the unit after it is taken out of service, and the owners of VYNPC (including CL&P) agreed to fund their shares of the decommissioning costs up to a negotiated amount. Subsequent to the time that agreement was executed, the original proposed acquiring company has increased the price it agreed to pay and three other unaffiliated companies have indicated their interest in buying VYNPC's generating unit on terms that have not been disclosed. At present, CL&P expects that the unit will be sold, but the identity of the owner and the terms of sale, including price, future decommissioning obligations and future power purchase obligations, are not known. As of December 31, 2000 and 1999, CL&P's remaining estimated obligation, including decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down was $160.6 million and $238.1 million, respectively. 11. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY CL&P Capital LP (CL&P LP), a subsidiary of CL&P, previously had issued $100 million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS), Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner, and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million capital contribution, back to CL&P in the form of an unsecured debenture. CL&P consolidates CL&P LP for financial reporting purposes. Upon consolidation, the unsecured debenture is eliminated, and the MIPS securities are accounted for as a minority interest. 12. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Nuclear Decommissioning Trusts: CL&P's portion of the investments held in the NU system companies' nuclear decommissioning trusts were marked- to-market by $83.2 million as of December 31, 2000, and $88.2 million as of December 31, 1999, with corresponding offsets to the accumulated provision for depreciation. The amounts adjusted in 2000 and in 1999 represent cumulative net unrealized gains. Cumulative gross unrealized holding losses were immaterial for both 2000 and 1999. Preferred Stock and Long-Term Debt: The fair value of CL&P's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of CL&P's financial instruments and the estimated fair values are as follows: -------------------------------------------------------------------------- At December 31, 2000 -------------------------------------------------------------------------- Carrying Fair (Millions of Dollars) Amount Value -------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption............... $116.2 $139.7 Long-term debt - First mortgage bonds................. 615.0 621.6 Other long-term debt................. 618.6 576.4 MIPS.................................... 100.0 100.5 -------------------------------------------------------------------------- -------------------------------------------------------------------------- At December 31, 1999 -------------------------------------------------------------------------- Carrying Fair (Millions of Dollars) Amount Value -------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption............... $116.2 $144.9 Preferred stock subject to mandatory redemption.................. 99.6 96.8 Long-term debt - First mortgage bonds................. 794.0 805.4 Other long-term debt................. 607.3 564.5 MIPS.................................... 100.0 97.3 -------------------------------------------------------------------------- 13. OTHER COMPREHENSIVE INCOME The accumulated balance for each other comprehensive income item is as follows: -------------------------------------------------------------------------- Current December 31, Period December 31, 1999 Change 2000 -------------------------------------------------------------------------- (Thousands of Dollars) -------------------------------------------------------------------------- Unrealized gains on securities................... $676 $ 90 $766 Minimum pension liability adjustments........... (260) - (260) -------------------------------------------------------------------------- Accumulated other comprehensive income............ $416 $ 90 $506 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Current December 31, Period December 31, 1998 Change 1999 -------------------------------------------------------------------------- (Thousands of Dollars) -------------------------------------------------------------------------- Unrealized gains on securities................... $638 $ 38 $676 Minimum pension liability adjustments........... (260) - (260) -------------------------------------------------------------------------- Accumulated other comprehensive income............ $378 $ 38 $416 -------------------------------------------------------------------------- The changes in the components of other comprehensive income are reported net of the following income tax effects: -------------------------------------------------------------------------- 2000 1999 1998 -------------------------------------------------------------------------- (Thousands of Dollars) -------------------------------------------------------------------------- Unrealized gains on securities........................ $(59) $(26) $(446) Minimum pension liability adjustments................ - - 182 -------------------------------------------------------------------------- Other comprehensive income............. $(59) $(26) $(264) -------------------------------------------------------------------------- 14. SEGMENT INFORMATION Effective January 1, 1999, the NU system companies, including CL&P, adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." The NU system is organized between regulated utilities and competitive energy subsidiaries. CL&P is included in the regulated utilities segment of the NU system and has no other reportable segments. 15. SUBSEQUENT EVENT Merger Agreement With Consolidated Edison, Inc.: In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the approvals needed to complete the merger announced in October 1999. Shareholders from both companies approved the merger in April 2000, and all state regulatory approvals were granted by the end of the year. Additionally, the FERC approved the merger in May 2000, the Nuclear Regulatory Commission approved the transaction in August 2000, and the United States Department of Justice approved the merger in February 2001. Necessary approval from the SEC was expected to be received in mid-March 2001. On February 28, 2001, NU's Board of Trustees requested that Con Edison provide reasonable assurance, in writing, that it intended to comply with the terms of the definitive merger agreement between the two companies. This included assurances that Con Edison would consummate the pending merger at the price set forth in the agreement promptly following the receipt of SEC approval. The original request for assurance was to be received by March 2, 2001, however that date was later extended to March 5, 2001. On March 5, 2001, Con Edison advised NU that it was not willing to close the merger on the agreed terms. NU notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that NU would file suit to obtain the benefits of the transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District of New York (Southern District), seeking declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement. On March 12, 2001, NU filed suit against Con Edison in the Southern District seeking damages in excess of $1 billion arising from Con Edison's breach of the merger agreement. The Connecticut Light and Power Company and Subsidiaries
- ---------------------------------------------------------------------------------------------------------- SELECTED CONSOLIDATED FINANCIAL DATA 2000 1999 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.................. $2,935,922 $2,452,855 $2,386,864 $2,465,587 $2,397,460 Operating Income/(Loss)............. 238,285 174,749 28,254 (7,619) 59,142 Net Income/(Loss)................... 148,135 (13,568) (195,725) (139,597) (50,868) Cash Dividends on Common Stock...... 72,014 - - 5,989 138,608 Total Assets........................ 4,764,198 5,298,284 6,050,198 6,081,223 6,244,036 Long-Term Debt (a).................. 1,232,688 1,400,056 2,007,957 2,043,327 2,038,521 Preferred Stock Not Subject to Mandatory Redemption........... 116,200 116,200 116,200 116,200 116,200 Preferred Stock Subject to Mandatory Redemption (a).......... - 99,539 119,289 155,000 155,000 Obligations Under Capital Leases (a)........................ 129,869 144,400 162,884 158,118 155,708
- ------------------------------------------------------------------------------------------------ CONSOLIDATED QUARTERLY FINANCIAL DATA (Unaudited) - ------------------------------------------------------------------------------------------------ Quarter Ended - ------------------------------------------------------------------------------------------------ 2000 March 31 June 30 September 30 December 31 - ------------------------------------------------------------------------------------------------ (Thousands of Dollars) - ------------------------------------------------------------------------------------------------ Operating Revenues $747,976 $683,585 $748,143 $756,218 ======== ======== ======== ======== Operating Income $ 76,021 $ 42,723 $ 51,944 $ 67,597 ======== ======== ======== ======== Net Income $ 49,643 $ 19,186 $ 27,908 $ 51,398 ======== ======== ======== ======== - ------------------------------------------------------------------------------------------------ 1999 - ------------------------------------------------------------------------------------------------ Operating Revenues $606,997 $565,069 $667,349 $613,440 ======== ======== ======== ======== Operating Income $ 20,412 $ 24,370 $ 51,969 $ 77,998 ======== ======== ======== ======== Net(Loss)/Income $(13,705) $ (6,814) $ 9,873 $ (2,922) ======== ======== ======== ========
(a) Includes portion due within one year. The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- CONSOLIDATED STATISTICS (Unaudited) - ------------------------------------------------------------------------------- Average Gross Electric Annual Utility Plant Use Per December 31, kWh Residential Electric (Thousands of Sales Customer Customers Employees Dollars) (Millions) (kWh) (Average) December 31, - ------------------------------------------------------------------------------- 2000 $5,964,605 42,179 8,976 1,121,551 2,057 1999 6,007,421 29,317 8,969 1,120,846 2,377 1998 6,345,215 27,356 8,476 1,111,370 2,379 1997 6,639,786 25,766 8,526 1,103,309 2,163 1996 6,512,659 26,043 8,639 1,099,340 2,194 EX-13.2 16 0016.txt ANNUAL REPORT OF WMECO 2000 Annual Report Western Massachusetts Electric Company and Subsidiary Index Contents Page - -------- ---- Management's Discussion and Analysis of Financial Condition and Results of Operations............................. 1 Report of Independent Public Accountants.......................... 10 Consolidated Statements of Income................................. 11 Consolidated Statements of Comprehensive Income................... 11 Consolidated Balance Sheets....................................... 12-13 Consolidated Statements of Common Stockholder's Equity............ 14 Consolidated Statements of Cash Flows............................. 15 Notes to Consolidated Financial Statements........................ 16 Selected Consolidated Financial Data.............................. 38 Consolidated Quarterly Financial Data (Unaudited)................. 38 Consolidated Statistics (Unaudited)............................... 39 Preferred Stockholder and Bondholder Information.................. Back Cover Western Massachusetts Electric Company and Subsidiary - ------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - ------------------------------------------------------------------------------- FINANCIAL CONDITION - ------------------- Overview - -------- The Western Massachusetts Electric Company's (WMECO or the company) earnings totaled $35.3 million in 2000, compared with $2.9 million in 1999 and a loss of $9.6 million in 1998. WMECO is an operating company in the Northeast Utilities system (NU system) and is wholly owned by Northeast Utilities (NU). WMECO benefited from the return to service of the Millstone 2 unit in May 1999, the strong performance of the Millstone 2 and 3 units in 2000 and the absence of restructuring charges in 2000. Millstone 2 operated at a capacity factor of 82 percent in 2000, while Millstone 3 operated at a capacity factor of virtually 100 percent in 2000. In 2000, WMECO's revenues increased to $513.7 million, up 24 percent from $414.2 million in 1999, primarily due to higher wholesale and retail revenues. Revenues were $393.3 million in 1998. Consolidated Edison, Inc. Merger - -------------------------------- In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the approvals needed to complete the merger announced in October 1999. Shareholders from both companies approved the merger in April 2000, and all state regulatory approvals were granted by the end of the year. Additionally, the Federal Energy Regulatory Commission (FERC) approved the merger in May 2000, the Nuclear Regulatory Commission approved the transaction in August 2000, and the United States Department of Justice approved the merger in February 2001. Necessary approval from the Securities and Exchange Commission (SEC) was expected to be received in mid-March 2001. On February 28, 2001, NU's Board of Trustees requested that Con Edison provide reasonable assurance, in writing, that it intended to comply with the terms of the definitive merger agreement between the two companies. This included assurances that Con Edison would consummate the pending merger at the price set forth in the agreement promptly following the receipt of SEC approval. The original request for assurance was to be received by March 2, 2001, however, that date was later extended to March 5, 2001. On March 5, 2001, Con Edison advised NU that it was not willing to close the merger on the agreed terms. NU notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that NU would file suit to obtain the benefits of the transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District of New York (Southern District), seeking declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement. On March 12, 2001, NU filed suit against Con Edison in the Southern District seeking damages in excess of $1 billion arising from Con Edison's breach of the merger agreement. NU cannot predict the outcome of this matter nor its effect on NU. Liquidity - --------- WMECO's net cash flows provided by operating activities from operations increased to $71.5 million in 2000 compared to $2.1 million in 1999 and $27.6 million in 1998. The increase in cash flows from operations is primarily attributable to increased earnings and higher amortization of regulatory assets, a noncash expense. Cash flows from operations were more than adequate to meet the payment of WMECO's common and preferred dividends ($14.8 million) and investments in electric utility plant, nuclear fuel and nuclear decommissioning trusts ($38.6 million). The level of common dividends totaled $12 million in 2000, as compared to no common dividends paid in 1999 and 1998. WMECO currently forecasts construction expenditures of $26.6 million for the year 2001. The transfer of 1,289 megawatts (MW) of hydroelectric generation assets to Northeast Generation Company, an affiliated company, from WMECO and The Connecticut Light and Power Company (CL&P) in March 2000, produced a significant source of cash for WMECO and CL&P. WMECO used this cash primarily to retire long-term debt and to return equity capital to the parent company. During 2000, $94.2 million of long-term debt was retired compared to $100.9 million in 1999 and $9.8 million in 1998. In November 2000, WMECO and CL&P reduced their revolving credit agreement to $350 million from $500 million to reflect lower borrowing needs post- restructuring. This agreement was renewed with more favorable terms as a result of the NU system's improving credit profile. In January 2001, Moody's Investors Service and Standard and Poor's upgraded their credit ratings for WMECO primarily as a result of the anticipated sale of the Millstone units and NU's general financial recovery. In February 2001, Fitch IBCA upgraded its credit ratings for WMECO. These upgrades return WMECO's unsecured debt to investment grade ratings for the first time in five years and will save the NU system in excess of $4.7 million annually in financing costs. For further information regarding the WMECO's borrowing facilities, see Note 2, "Short-Term Debt," to the consolidated financial statements. In 2001, NU expects to reduce the capitalization of its regulated electric operating companies significantly as a result of continued asset sales and securitization of stranded costs. WMECO expects to receive gross proceeds of $196.2 million as a result of the sale of its ownership interest in the Millstone units to Dominion Resources, Inc. (Dominion). This sale is expected to close as early as the end of March 2001. The cash proceeds are expected to be used to repay subsidiary debt and capital lease obligations and to return equity capital to the parent company. During February 2001, the Massachusetts Department of Telecommunications and Energy (DTE) approved the securitization of $155 million of stranded costs by WMECO. A significant portion of those proceeds will be used to buyout a purchased-power contract with the remainder used to retire WMECO's debt and to return equity capital to the parent company. Securitization for WMECO is expected to take place early in the second quarter of 2001. Restructuring - ------------- As a result of industry restructuring, WMECO stopped supplying power directly to customers in 2000. Instead, WMECO became an energy delivery company, delivering electricity to customers that is produced by other companies and sometimes bought by customers through intermediaries. In 2000, customers in Massachusetts had the option of choosing alternative power suppliers or relying on WMECO to acquire the power for them through standard offer service. WMECO continues to generate power through either direct ownership of generating plants, such as Millstone 2 and 3, or through purchased-power contracts. WMECO sold its share of the capacity associated with Millstone 2 and 3 to Select Energy, Inc. and five unaffiliated companies. These contracts will expire on December 31, 2001. The revenues generated from these contracts are expected to recover WMECO's share of the nuclear operating costs through the divestiture of the Millstone units. In 2000, WMECO supplied power to standard offer customers at a rate of slightly more than $0.045 per kilowatt-hour. As a result of new one-year standard offer supply contracts signed in December 2000, that rate will increase significantly in 2001 to approximately $0.073 per kilowatt-hour. In January 2001, the DTE approved an average overall rate increase of approximately 17.4 percent for WMECO standard offer customers, allowing WMECO to fully recover these increased power procurement costs. A higher rate was also approved for customers who take default service from WMECO. Under the new standard offer contracts, three unaffiliated companies provide up to 630 MW of power to WMECO's standard offer customers and one unaffiliated company serves WMECO's default load of up to 70 MW through December 31, 2001. WMECO renegotiates its standard offer supply contracts on an annual basis. For further information regarding commitments and contingencies related to restructuring, see Note 9A, "Commitments and Contingencies - Restructuring," to the consolidated financial statements. Regional Transmission Organization - ---------------------------------- Pursuant to FERC Order 888 (issued in April 1996), the NU system companies, including WMECO, operate their transmission system under an open access, nondiscriminatory transmission tariff. In December 1999, the FERC issued an order calling on all transmission owners to voluntarily join Regional Transmission Organizations (RTOs) in order to boost competition in electric markets. In general, each of these organizations would be an independent operator over all transmission facilities, and would perform, among other functions, tariff administration, construction planning and reliability management for the particular regional transmission system. NU's active voting interest in such an organization would be limited to 5 percent under the proposal. The NU system companies, including WMECO, and other parties have appealed this order. Of primary concern to NU is the ratemaking authority granted to RTOs and its impact on the ability of transmission owners to earn appropriate returns on their transmission investment under the organizational structure and the minimum functions proposed in the order. The NU system companies, including WMECO, were required to participate in a collaborative process established by the FERC beginning in March of 2000. On January 16, 2001, NU along with the Independent System Operator and five other New England transmission owning utilities filed a proposal to establish a New England RTO. Nuclear Plant Performance And Divestiture - ----------------------------------------- Millstone The Millstone units completed one of their best years ever in 2000. Millstone 2 operated at a capacity factor of 82 percent in 2000 and completed a refueling outage in early June more than four days ahead of schedule. The 40-day, 21-hour outage set a world record for a refueling that included a full generator rewind. Millstone 3 operated at virtually a 100 percent capacity factor in 2000 and ran for 585 consecutive days before beginning a scheduled refueling outage on February 3, 2001. Millstone 3 is expected to return to service by the end of the first quarter of 2001. On August 7, 2000, WMECO and certain other joint owners reached an agreement to sell substantially all of the Millstone units, located in Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including approximately $105 million for nuclear fuel. Dominion has also agreed to assume responsibility for decommissioning the three units and NU will transfer to Dominion all funds in the Millstone decommissioning trust. Additionally, NU is obligated to top-off the decommissioning trust if its value does not equal an agreed upon amount at closing. That amount is pursuant to the purchase and sale agreement (PSA) with Dominion, subject to adjustment for delays in the closing of the sale and Millstone 1 not meeting the "cold and dark" condition specified in the PSA. If the transaction is consummated as proposed, WMECO would receive gross proceeds of approximately $196.2 million on a pretax basis for its respective ownership interest. The proceeds from the sale of this interest will be used to reduce the company's stranded costs under restructuring and the cash proceeds will be used to repay subsidiary debt and capital lease obligations and to return equity capital to the parent company. In preparation for the divestiture of the Millstone units, it was discovered that two full-length irradiated fuel rods are missing. NU believes that the two rods remain stored in the Millstone 1 spent fuel pool or were shipped in a shielded cask to a facility licensed to accept radioactive material. NU's investigation into the location of the two rods is ongoing. NU is responsible for any potential liabilities, which are not determinable at this time, related to these missing fuel rods. NU currently expects to close on the sale of Millstone as early as the end of March 2001. Yankee Companies In 1999, the Vermont Yankee Nuclear Power Corporation (VYNPC) agreed to sell its nuclear generating unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the obligation to decommission the unit after it is taken out of service, and the owners of VYNPC (including WMECO) agreed to fund their shares of the decommissioning costs up to a negotiated amount. Subsequent to the time that agreement was executed, the original proposed acquiring company increased its purchase price and three other unaffiliated companies have indicated their interest in buying VYNPC's generating unit on terms that have not been disclosed. On February 14, 2001, the Vermont Public Service Board dismissed the acquiring company's petition for approval and VYNPC agreed to work with the Vermont regulators to develop an auction process for the sale of the unit. At present, WMECO expects that the unit will be sold, but the identity of the owner and the terms of sale, including price, future decommissioning obligations and future power purchase obligations, are not known. Nuclear Decommissioning In connection with the aforementioned sale of the Millstone units, Dominion has agreed to assume responsibility for decommissioning the Millstone units. For further information regarding nuclear decommissioning, see Note 10, "Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. Spent Nuclear Fuel Disposal Costs The United States Department of Energy (DOE) originally was scheduled to begin accepting delivery of spent nuclear fuel in 1998. However, delays in confirming the suitability of a permanent storage site continually have postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. WMECO has the primary responsibility for the interim storage of its spent nuclear fuel prior to divestiture of its nuclear units. For further information regarding spent nuclear fuel disposal costs, see Note 9D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements. Other Matters - ------------- Environmental Matters WMECO is subject to environmental laws and regulations structured to mitigate or remove the effect of past operations and to improve or maintain the quality of the environment. For further information regarding environmental matters, see Note 9C, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements. Other Commitments and Contingencies For further information regarding other commitments and contingencies, see Note 9, "Commitments and Contingencies," to the consolidated financial statements. Forward Looking Statements This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in historical weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, and other presently unknown or unforeseen factors. RESULTS OF OPERATIONS The components of significant income statement variances for the past two years are provided in the table below. Income Statement Variances (Millions of Dollars) 2000 over/(under) 1999 1999 over/(under) 1998 ----------------------------------------------- Amount Percent Amount Percent ------ ------- ------ ------- Operating Revenues $ 99 24% $ 21 5% Operating Expenses: Fuel, purchased and net interchange power 95 62 21 16 Other operation (26) (25) (16) (13) Maintenance (14) (30) (9) (16) Depreciation (10) (36) (13) (32) Amortization of regulatory assets, net 21 80 20 (a) Federal and state income taxes 2 12 17 (a) Taxes other than income taxes (3) (14) 1 5 Gain on sale of utility plant 22 100 (22) - ---- --- ---- --- Total operating expenses 87 23 (1) - ---- --- ---- --- Operating income 12 30 22 (a) ---- --- ---- --- Other Income: Equity in earnings of regional nuclear generating and transmission companies 2 (a) (1) (76) Nuclear related costs 15 84 (18) - Other, net 5 (a) (2) (90) Other income taxes (4) (39) 8 (a) Net other income 18 (a) (13) (a) Interest charges, net (2) (7) (4) (12) ---- --- ---- --- Net income/(loss) $ 32 (a) $ 13 (a) ==== === ==== === (a) Percent greater than 100. Operating Revenues Operating revenues increased by $99 million or 24 percent in 2000, primarily due to higher wholesale and retail revenues. Wholesale revenues increased ($82 million) as a result of the sale of output from Millstone 2 and 3, and the amortization of the gain on the transfer of certain hydroelectric generation assets ($6 million). Retail revenues increased by $11 million due to retail rate increases in late 1999 and early 2000. Retail sales compared to 1999 were flat. Operating revenues increased by $21 million or 5 percent in 1999, primarily due to higher wholesale and retail revenues. Wholesale revenues increased ($17 million) due to higher energy sales and related capacity and transmission revenues. Retail revenues increased by $4 million due to the retail kilowatt- hour sales increase of 3.6 percent which increased revenues by $16 million and was partially offset by the retail rate decrease in 1998 ($12 million). Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in 2000, primarily due to the transition, under industry restructuring, of purchasing full requirements for customers from standard offer suppliers, in addition to the remaining fuel costs of the nuclear units and cogenerators. Fuel, purchased and net interchange power expense increased in 1999, primarily due to a reversal of fuel expense deferrals which were recorded in other operation and maintenance (O&M) expenses as a result of the WMECO restructuring order, partially offset by lower replacement power costs. Other Operation and Maintenance Other O&M expenses decreased in 2000, primarily due to lower spending at the nuclear units ($17 million), the decommissioning status of Millstone 1 ($7 million), lower administrative and general expenses ($14 million), lower fossil and hydroelectric expenses due to the sale of certain fossil generation assets and transfer of certain hydroelectric generation assets ($6 million), partially offset by higher transmission expenses ($4 million). Other O&M expenses decreased in 1999, primarily due to lower costs at the Millstone units ($17 million), deferrals associated with the restructuring order ($5 million), and lower fossil and hydroelectric O&M costs ($4 million), partially offset by higher transmission expenses ($4 million). Depreciation Depreciation decreased in 2000, primarily due to the effect of discontinuing Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," for the generation portion of the business and the resulting reclassification of depreciable nuclear plant balances to regulatory assets ($14 million), the sale of certain fossil generation assets and the transfer of certain hydroelectric generation assets. Depreciation decreased in 1999, primarily due to lower rates utilized in 1999 as a result of the 1999 restructuring orders and the retirement of Millstone 1. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net increased in 2000, primarily due to changes in amortization levels as a result of industry restructuring ($24 million) and higher amortization associated with the reclassified nuclear plant balances ($14 million), partially offset by the amortization in 1999 of the gain on the sale of the fossil plants ($12 million). Amortization of regulatory assets, net increased in 1999, primarily due to increased amortization associated with the gain on the sale of fossil and hydroelectric generation assets ($13 million), the amortization of the Millstone 1 investment ($5 million) and the reclassification of the depreciation on the nuclear plants transferred to regulatory assets ($4 million). Federal and State Income Taxes Federal and state income taxes increased in 2000 and 1999, primarily due to higher book taxable income. Taxes Other Than Income Taxes Taxes other than income taxes decreased in 2000, primarily due to a decrease in local property taxes. Gain on Sale of Utility Plant WMECO recorded a gain on the sale of its fossil and hydroelectric generation assets in 1999. A corresponding amount of amortization expense was recorded. Nuclear Related Costs Nuclear related costs in 2000 are comprised of a settlement of Millstone 3 joint owner litigation, net of insurance proceeds ($2 million), and a regulatory settlement ($1 million). In comparison, costs in 1999 are comprised of one-time charges related to the return disallowed on Millstone 1 unrecovered plant from March 1998 forward ($11 million), the settlement of Millstone 3 owner litigation, net of insurance proceeds ($5 million) and the disallowed Millstone 1 plant per the Massachusetts restructuring order ($2 million). Other, Net Other, net, increased in 2000, primarily due to an environmental reserve recorded in 1999 ($3 million). Interest Charges, Net Interest charges, net, decreased in 2000 and 1999, primarily due to reacquisitions and retirements of long-term debt, partially offset by an increase in interest charges related to short-term borrowings. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - ---------------------------------------- To the Board of Directors of Western Massachusetts Electric Company: We have audited the accompanying consolidated balance sheets of Western Massachusetts Electric Company (a Massachusetts corporation and a wholly owned subsidiary of Northeast Utilities) and subsidiary as of December 31, 2000 and 1999, and the related consolidated statements of income, comprehensive income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2000. 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 in accordance with auditing standards generally accepted in the United States. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Western Massachusetts Electric Company and subsidiary as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut January 23, 2001 (except with respect to the matter discussed in Note 14, as to which the date is March 13, 2001) WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME
- --------------------------------------------------------------------------------- FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 - --------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues............................. $ 513,678 $ 414,231 $ 393,322 ---------- ---------- ---------- Operating Expenses: Operation - Fuel, purchased and net interchange power. 246,130 151,714 130,401 Other..................................... 75,940 101,842 117,663 Maintenance.................................. 33,111 47,586 56,622 Depreciation................................. 17,693 27,771 40,901 Amortization of regulatory assets............ 47,775 26,488 6,016 Federal and state income taxes............... 21,174 18,849 2,109 Taxes other than income taxes................ 17,759 20,677 19,756 Gain on sale of utility plant................ - (22,437) - ---------- ---------- ---------- Total operating expenses............... 459,582 372,490 373,468 ---------- ---------- ---------- Operating Income............................... 54,096 41,741 19,854 ---------- ---------- ---------- Other Income/(Loss): Equity in earnings of regional nuclear generating companies....................... 2,251 407 1,699 Nuclear related costs........................ (2,808) (18,035) - Other, net................................... 1,242 (3,618) (1,905) Income taxes................................. 6,029 9,906 2,198 ---------- ---------- ---------- Other income/(loss), net............... 6,714 (11,340) 1,992 ---------- ---------- ---------- Income before interest charges......... 60,810 30,401 21,846 ---------- ---------- ---------- Interest Charges: Interest on long-term debt................... 14,051 24,255 28,027 Other interest............................... 11,491 3,259 3,398 ---------- ---------- ---------- Interest charges, net.................. 25,542 27,514 31,425 ---------- ---------- ---------- Net Income/(Loss).............................. $ 35,268 $ 2,887 $ (9,579) ========== ========== ========== CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Net Income/(Loss).............................. $ 35,268 $ 2,887 $ (9,579) ---------- ---------- ---------- Other comprehensive income, net of tax: Unrealized gains on securities............... 22 10 183 Minimum pension liability adjustments........ - - (33) ---------- ---------- ---------- Other comprehensive income, net of tax. 22 10 150 ---------- ---------- ---------- Comprehensive Income/(Loss) $ 35,290 $ 2,897 $ (9,429) ========== ========== ==========
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------------- AT DECEMBER 31, 2000 1999 - --------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS - ------ Utility Plant, at original cost: Electric................................................ $ 1,112,405 $ 1,175,954 Less: Accumulated provision for depreciation......... 792,923 813,978 ------------- ------------ 319,482 361,976 Construction work in progress........................... 22,813 21,181 Nuclear fuel, net....................................... 18,296 18,880 ------------- ------------ Total net utility plant.............................. 360,591 402,037 ------------- ------------ Other Property and Investments: Nuclear decommissioning trusts, at market............... 144,921 144,567 Investments in regional nuclear generating companies, at equity................................... 11,117 14,723 Other, at cost.......................................... 6,249 6,232 ------------- ------------ 162,287 165,522 ------------- ------------ Current Assets: Cash.................................................... 985 950 Receivables less the accumulated provision for uncollectible accounts of $1,886 in 2000 and $1,640 in 1999......................................... 36,364 31,692 Accounts receivable from affiliated companies........... 16,146 3,918 Taxes receivable........................................ - 1,912 Accrued utility revenues................................ 21,222 13,485 Fuel, materials and supplies, at average cost........... 1,606 3,097 Prepayments and other................................... 4,817 3,640 ------------- ------------ 81,140 58,694 ------------- ------------ Deferred Charges: Regulatory assets....................................... 392,247 594,800 Unamortized debt expense................................ 1,822 1,926 Prepaid pension......................................... 45,473 26,479 Other................................................... 4,258 4,146 ------------- ------------ 443,800 627,351 ------------- ------------ Total Assets.............................................. $ 1,047,818 $ 1,253,604 ============= ============
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------------- AT DECEMBER 31, 2000 1999 - --------------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock, $25 par value - authorized 1,072,471 shares; 590,093 shares outstanding in 2000 and 1,072,471 shares outstanding in 1999............... $ 14,752 $ 26,812 Capital surplus, paid in................................ 94,010 171,691 Retained earnings....................................... 62,952 38,712 Accumulated other comprehensive income.................. 182 160 ------------- ------------ Total common stockholder's equity.............. 171,896 237,375 Preferred stock not subject to mandatory redemption..... 20,000 20,000 Preferred stock subject to mandatory redemption......... 15,000 16,500 Long-term debt.......................................... 139,425 290,279 ------------- ------------ Total capitalization........................... 346,321 564,154 ------------- ------------ Obligations Under Capital Leases.......................... 5,935 8,106 ------------- ------------ Current Liabilities: Notes payable to banks.................................. 110,000 123,000 Notes payable to affiliated company..................... 600 9,400 Long-term debt and preferred stock - current portion.... 61,500 1,500 Obligations under capital leases - current portion...... 20,986 21,866 Accounts payable........................................ 25,298 12,974 Accounts payable to affiliated companies................ 8,611 3,208 Accrued taxes........................................... 8,471 589 Accrued interest........................................ 4,703 6,046 Other................................................... 7,671 14,384 ------------- ------------ 247,840 192,967 ------------- ------------ Deferred Credits and Other Long-term Liabilities: Accumulated deferred income taxes....................... 224,711 242,942 Accumulated deferred investment tax credits............. 17,580 19,765 Decommissioning obligation - Millstone 1................ 136,130 136,130 Deferred contractual obligations........................ 42,519 63,701 Other................................................... 26,782 25,839 ------------- ------------ 447,722 488,377 ------------- ------------ Commitments and Contingencies (Note 9) Total Capitalization and Liabilities...................... $ 1,047,818 $ 1,253,604 ============= ============
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- --------------------------------------------------------------------------------------------------------- Accumulated Capital Retained Other Common Surplus, Earnings Comprehensive Stock Paid In (a) Income Total - --------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1998............... $ 26,812 $151,171 $ 58,608 $ - $236,591 Net loss for 1998.................... (9,579) (9,579) Cash dividends on preferred stock.... (3,026) (3,026) Capital stock expenses, net.......... 260 260 Other comprehensive income........... 150 150 --------- --------- --------- ------------- --------- Balance at December 31, 1998............. 26,812 151,431 46,003 150 224,396 Net income for 1999.................. 2,887 2,887 Cash dividends on preferred stock.... (3,298) (3,298) Capital stock expenses, net.......... 260 260 Allocation of benefits - ESOP........ (6,880) (6,880) Capital contribution from Northeast Utilities................ 20,000 20,000 Other comprehensive income........... 10 10 --------- --------- --------- ------------- --------- Balance at December 31, 1999............. 26,812 171,691 38,712 160 237,375 Net income for 2000.................. 35,268 35,268 Cash dividends on preferred stock.... (2,798) (2,798) Cash dividends on common stock....... (12,002) (12,002) Repurchase of common stock........... (12,060) (77,940) (90,000) Capital stock expenses, net.......... 259 259 Tax benefit for 1993-1999 from reduction of NU parent losses(b)... 3,824 3,824 Allocation of benefits - ESOP........ (52) (52) Other comprehensive income........... 22 22 --------- --------- --------- ------------- --------- Balance at December 31, 2000............. $ 14,752 $ 94,010 $ 62,952 $ 182 $171,896 ========= ========= ========= ============= =========
(a) The company has no dividend restrictions. However, the company has a 30% common equity test to meet and therefore, at December 31, 2000, cannot pay out approximately $31.5 million in equity. (b) In June 1999, WMECO paid NU parent $6.9 million for NU shares issued from 1992 through 1998 on behalf of its employees in accordance with NU's 401(k) plan. This transaction resulted in a reduction of the NU parent loss and a tax benefit to WMECO. The amount in 2000 represents the remaining previously unallocated 1993 through 1999 NU parent losses. The accompanying notes are an integral part of the financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------------------------- For the Years Ended December 31, - -------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2000 1999 1998 - -------------------------------------------------------------------------------------------------- Operating Activities: Net income/(loss)........................................... $ 35,268 $ 2,887 $ (9,579) Adjustments to reconcile to net cash provided by operating activities: Depreciation.............................................. 17,693 27,771 40,901 Deferred income taxes and investment tax credits, net..... (11,549) (6,544) 7,405 Amortization of recoverable energy costs, net............. 9,386 - - Amortization of regulatory assets, net.................... 47,775 26,488 6,016 Tax benefit for 1993-1999 from reduction of NU parent losses........................... 3,824 - - Nuclear related costs..................................... 2,808 18,035 - Allocation of ESOP benefits............................... (52) (6,880) - Gain on sale of utility plant............................. - (22,437) - Other uses of cash........................................ (28,834) (24,096) (6,553) Changes in working capital: Receivables and accrued utility revenues.................. (24,637) (44,045) 1,622 Fuel, materials and supplies.............................. 1,491 1,956 807 Accounts payable.......................................... 17,727 (14,636) (20,962) Investments in securitizable assets....................... - 21,865 3,415 Accrued taxes............................................. 7,882 (675) 742 Other working capital (excludes cash)..................... (7,321) 22,368 3,748 ----------- ----------- ----------- Net cash flows provided by operating activities............... 71,461 2,057 27,562 ----------- ----------- ----------- Investing Activities: Investments in plant: Electric utility plant.................................... (27,267) (30,192) (19,895) Nuclear fuel.............................................. (7,848) (5,817) (1,801) ----------- ----------- ----------- Net cash flows used for investments in plant.............. (35,115) (36,009) (21,696) Investments in nuclear decommissioning trusts............... (3,437) (11,387) (12,918) Other investment activities, net............................ 3,589 1,807 (171) Net proceeds from the transfer/sale of utility plant........ 185,787 48,524 - Capital contributions from Northeast Utilities.............. - 20,000 - ----------- ----------- ----------- Net cash flows provided by/(used in) investing activities..... 150,824 22,935 (34,785) ----------- ----------- ----------- Financing Activities: Net (decrease)/increase in short-term debt.................. (21,800) 81,500 21,550 Reacquisitions and retirements of long-term debt............ (94,150) (100,850) (9,800) Reacquisitions and retirements of preferred stock........... (1,500) (1,500) (1,500) Repurchase of common shares................................. (90,000) - - Cash dividends on preferred stock........................... (2,798) (3,298) (3,026) Cash dividends on common stock.............................. (12,002) - - ----------- ----------- ----------- Net cash flows (used in)/provided by financing activities..... (222,250) (24,148) 7,224 ----------- ----------- ----------- Net increase in cash for the period........................... 35 844 1 Cash - beginning of period.................................... 950 106 105 ----------- ----------- ----------- Cash - end of period.......................................... $ 985 $ 950 $ 106 =========== =========== =========== Supplemental Cash Flow Information: Cash paid/(refunded) during the year for: Interest, net of amounts capitalized........................ $ 26,055 $ 30,958 $ 22,902 =========== =========== =========== Income taxes................................................ $ 18,554 $ (6,296) $ (2,624) =========== =========== =========== Increase in obligations: Niantic Bay Fuel Trust...................................... $ 1,532 $ 1,112 $ 2,375 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------ 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. About Western Massachusetts Electric Company Western Massachusetts Electric Company (WMECO or the company) along with The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), North Atlantic Energy Corporation (NAEC), and Holyoke Water Power Company (HWP) are the operating companies comprising the Northeast Utilities system (NU system) and are wholly owned by Northeast Utilities (NU). The NU system serves in excess of 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues. The NU system furnishes franchised retail electric service in western Massachusetts, Connecticut and New Hampshire through WMECO, CL&P and PSNH. NAEC sells all of its entitlement to the capacity and output of the Seabrook Station nuclear unit (Seabrook) to PSNH under the terms of two life-of-unit, full cost recovery contracts. HWP, also is engaged in the production and distribution of electric power. On March 1, 2000, NU completed its acquisition of Yankee Energy System, Inc., the parent company of Yankee Gas Services Company, Connecticut's largest natural gas distribution system. NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act) and the NU system, including WMECO, is subject to provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. WMECO is subject to further regulation for rates, accounting and other matters by the FERC and the Massachusetts Department of Telecommunications and Energy (DTE). Several wholly owned subsidiaries of NU provide support services for the NU system companies, including WMECO, and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing, and other services to the NU system companies, including WMECO. Northeast Nuclear Energy Company acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear units. North Atlantic Energy Service Corporation has operational responsibility for Seabrook. B. Presentation The consolidated financial statements of WMECO include the accounts of its subsidiary. Intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity and are subject to approval by various federal and state regulatory agencies and the DTE. C. New Accounting Standards Derivative Instruments: Effective January 1, 2001, WMECO adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS No. 133 requires that derivative instruments be recorded as an asset or liability measured at its fair value and that changes in the fair value of derivative instruments be recognized currently in earnings unless specific hedge accounting criteria are met. In order to implement SFAS No. 133 by January 1, 2001, NU established a cross-functional project team to identify all derivative instruments, measure the fair value of those derivative instruments, designate and document various hedge relationships, and evaluate the effectiveness of those hedge relationships. NU has completed the process of identifying all derivative instruments and has established appropriate fair value measurements of those derivative instruments in place at January 1, 2001. In addition, for those derivative instruments which are hedging an identified risk, NU has designated and documented all hedging relationships anew. Management believes the adoption of this new standard will not have a material impact on WMECO's financial position or results of operations. Revenue Recognition: In December 1999, the SEC issued Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition." The adoption of SAB No. 101, as amended, did not have a material impact on WMECO's consolidated financial statements. D. Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: WMECO owns common stock in four regional nuclear companies (Yankee Companies). WMECO's ownership interests in the Yankee Companies at December 31, 2000 and 1999, which are accounted for on the equity method due to WMECO's ability to exercise significant influence over their operating and financial policies are 9.5 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 7 percent of the Yankee Atomic Electric Company (YAEC), 3 percent of the Maine Yankee Atomic Power Company (MYAPC), and 2.5 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC). WMECO's total equity investment in the Yankee Companies at December 31, 2000 and 1999, is $11.1 million and $14.7 million, respectively. Each Yankee Company owns a single nuclear generating unit. However, VYNPC is the only unit still in operation at December 31, 2000. Millstone: WMECO has a 19 percent joint ownership in both Millstone 1, a 660 megawatt (MW) nuclear unit, which is currently in decommissioning status, and Millstone 2, an 870 MW nuclear generating unit. WMECO has a 12.24 percent joint ownership interest in Millstone 3, a 1,154 MW nuclear generating unit. On August 7, 2000, WMECO and certain other joint owners reached an agreement to sell substantially all of the Millstone units to Dominion Resources, Inc. (Dominion) for approximately $1.3 billion, including approximately $105 million for nuclear fuel. NU currently expects to close on the sale of Millstone as early as the end of March 2001. Plant-in-service and the accumulated provision for depreciation for WMECO's share of Millstone 2 and 3 are as follows: ---------------------------------------------------------------------- At December 31, 2000 1999 ---------------------------------------------------------------------- (Millions of Dollars) Plant-in-service Millstone 2............................. $182.3 $180.4 Millstone 3............................. 382.7 380.5 Accumulated provision for depreciation Millstone 2............................. $174.5 $166.7 Millstone 3............................. 357.3 358.7 ---------------------------------------------------------------------- E. Depreciation The provision for depreciation is calculated using the straight-line method based on estimated remaining useful lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. The costs of closure and removal of nonnuclear facilities are accrued over the life of the plant as a component of depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 2.2 percent in 2000, 2.3 percent in 1999 and 2.9 percent in 1998. As a result of discontinuing the application of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," for WMECO's generation business in 1999, the company recorded a charge to accumulated depreciation for the nuclear plant in excess of the estimated fair market value at the time in the amount of $330 million and a corresponding regulatory asset was created. F. Revenues Revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the DTE. Regulatory commissions also have authority over the terms and conditions of nontraditional rate-making arrangements. At the end of each accounting period, WMECO accrues a revenue estimate for the amount of energy delivered but unbilled. G. Regulatory Accounting and Assets The accounting policies of WMECO and the accompanying consolidated financial statements conform to accounting principles generally accepted in the United States applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71. As a result of final restructuring orders issued in 1999, WMECO discontinued the application of SFAS No. 71 for the generation portion of its business. WMECO's transmission and distribution business will continue to be cost-based and management believes the application of SFAS No. 71 continues to be appropriate. Management continues to believe it is probable that WMECO will recover its investments in long-lived assets, including regulatory assets through charges to their transmission and distribution customers. The majority for WMECO will be recovered through a transition charge over a 12-year period. In addition, all material regulatory assets are earning a return. The components of WMECO's regulatory assets are as follows: ---------------------------------------------------------------------- At December 31, 2000 1999 ---------------------------------------------------------------------- (Millions of Dollars) Recoverable nuclear costs............... $257.7 $428.9 Income taxes, net....................... 50.3 49.0 Unrecovered contractual obligations..... 42.5 63.7 Recoverable energy costs, net........... 6.9 16.3 Other................................... 34.8 36.9 ------ ------ $392.2 $594.8 ====== ====== ---------------------------------------------------------------------- As a result of discontinuing the application of SFAS No. 71 in 1999 for WMECO's generation business, the company reclassified nuclear plant in excess of its estimated fair market value from plant to regulatory assets. As of December 31, 2000 and 1999, excluding the impact of the transfer of generation assets to Northeast Generation Company in 2000, the unamortized balance ($286.9 million and $316.1 million, respectively) is classified as recoverable nuclear costs. Also included in that regulatory asset component for 2000 and 1999 are $104.9 million and $112.8 million, respectively, which includes Millstone 1 recoverable nuclear costs relating to the recoverable portion of the undepreciated plant and related assets ($39.6 million and $43.8 million, respectively) and the decommissioning and closure obligation ($65.3 million and $69 million, respectively). H. Income Taxes The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows: ---------------------------------------------------------------------- At December 31, 2000 1999 ---------------------------------------------------------------------- (Millions of Dollars) Accelerated depreciation and other plant-related differences....... $193.7 $213.4 Regulatory assets - income tax gross up................... 19.5 19.0 Other................................... 11.5 10.5 ------ ------ $224.7 $242.9 ====== ====== ---------------------------------------------------------------------- I. Unrecovered Contractual Obligations Under the terms of contracts with the Yankee Companies, the shareholder-sponsored companies, including WMECO, are responsible for their proportionate share of the remaining costs of the units, including decommissioning. As management expects that WMECO will be allowed to recover these costs from its customers, WMECO has recorded a regulatory asset, with a corresponding obligation, on its consolidated balance sheet. J. Recoverable Energy Costs Under the Energy Policy Act of 1992 (Energy Act), WMECO is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. WMECO is currently recovering these costs through rates. As of December 31, 2000 and 1999, WMECO's total D&D Assessment deferrals were $8.6 million and $9.6 million, respectively. 2. SHORT-TERM DEBT Limits: The amount of short-term borrowings that may be incurred by WMECO is subject to periodic approval by either the SEC under the 1935 Act or by state regulators. Currently, SEC authorization allows WMECO to incur total short-term borrowings up to a maximum of $250 million. In addition, the charter of WMECO contains preferred stock provisions restricting the amount of unsecured debt the company may incur. As of December 31, 2000, WMECO's charter permits WMECO to incur $94 million of additional unsecured debt. Credit Agreement: On November 17, 2000, WMECO and CL&P entered into a 364-day revolving credit facility for $350 million, replacing the previous $500 million facility which was to expire on November 17, 2000. WMECO may draw up to $150 million under the facility which, until the nuclear divestiture, is secured by second mortgages on Millstone 2 and 3. Once WMECO and CL&P receive the proceeds from securitization, the $350 million revolving credit facility will be reduced to $250 million, with a $100 million limit for WMECO. Unless extended, the credit facility will expire on November 16, 2001. At December 31, 2000 and 1999, there were $110 million and $123 million, respectively, in borrowings under these facilities. Under the aforementioned credit agreement, WMECO may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service. The weighted average interest rate on WMECO's notes payable to banks outstanding on December 31, 2000 and 1999, was 8.05 percent and 7.70 percent, respectively. Maturities of short-term debt obligations were for periods of three months or less. This credit agreement provides that WMECO must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, common equity ratios and interest coverage ratios. WMECO currently is and expects to remain in compliance with these covenants. Money Pool: Certain subsidiaries of NU, including WMECO, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the NU system and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on loans from NU parent, however, bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 2000 and 1999, WMECO had $0.6 million and $9.4 million, respectively, of borrowings outstanding from the Pool. The interest rate on borrowings from the Pool at December 31, 2000 and 1999, was 5.4 percent and 4.9 percent, respectively. 3. LEASES WMECO finances its respective shares of the nuclear fuel for Millstone 2 and 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement. This capital lease agreement has an expiration date of June 1, 2040. At December 31, 2000 and 1999, the present value of WMECO's capital lease obligation to the NBFT was $26.6 million and $29.8 million, respectively. In connection with the planned nuclear divestiture, the NBFT capital lease will be terminated, the nuclear fuel will be transferred to Dominion and the related $180 million Series G Intermediate Term Note Agreement will be extinguished with the divestiture proceeds. WMECO makes quarterly lease payments for the cost of nuclear fuel consumed in the reactors based on a units-of-production method at rates which reflect estimated kilowatt-hours of energy provided plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, WMECO's ownership interest in the nuclear fuel transfers to WMECO. WMECO also has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, nuclear control room simulators, and office space. The provisions of these lease agreements generally provide for renewal options. Capital lease rental payments charged to operating expense were $9.6 million in 2000, $2.6 million in 1999 and $4.1 million in 1998. Interest included in capital lease rental payments was $2.8 million in 2000, $3.1 million in 1999 and $2.8 million in 1998. Operating lease rental payments charged to expense were $3.2 million in 2000, $4.8 million in 1999 and $5.8 million in 1998. Future minimum rental payments, excluding annual nuclear fuel lease payments and executory costs such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 2000, are as follows: -------------------------------------------------------------------------- Year Capital Leases Operating Leases -------------------------------------------------------------------------- (Millions of Dollars) 2001................................ $ 0.1 $ 3.5 2002................................ 0.1 3.4 2003................................ 0.1 3.1 2004................................ - 2.8 2005................................ - 2.6 After 2005.......................... - 13.1 ----- ----- Future minimum lease payments....... 0.3 $28.5 ===== Present value of future nuclear fuel lease payments............... 26.6 ----- Present value of future minimum lease payments.................... $26.9 ===== -------------------------------------------------------------------------- 4. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION Details of preferred stock not subject to mandatory redemption are as follows: -------------------------------------------------------------------------- December 31, Shares 2000 Outstanding December 31, Redemption December 31, ------------- Description Price 2000 2000 1999 -------------------------------------------------------------------------- (Millions of Dollars) 7.72% Series B of 1971 $103.51 200,000 $20.0 $20.0 -------------------------------------------------------------------------- 5. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are as follows: -------------------------------------------------------------------------- December 31, Shares 2000 Outstanding December 31, Redemption December 31, ------------- Description Price 2000 2000 1999 -------------------------------------------------------------------------- (Millions of Dollars) 7.60% Series of 1987 $25.26 660,000 $16.5 $18.0 Less preferred stock to be redeemed within one year 60,000 1.5 1.5 ----- ----- $15.0 $16.5 ===== ===== -------------------------------------------------------------------------- This series is subject to certain refunding limitations for the first five years after issuance. The redemption price reduces in future years. The minimum sinking fund requirements of the series subject to mandatory redemption aggregate $1.5 million per year for each year for 2001 through 2005. In case of default on sinking fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If WMECO is in arrears in the payment of dividends on any outstanding shares of preferred stock, WMECO is prohibited from redeeming or purchasing less than all of the outstanding preferred stock. 6. LONG-TERM DEBT Details of long-term debt outstanding are as follows: -------------------------------------------------------------------------- At December 31, 2000 1999 -------------------------------------------------------------------------- (Millions of Dollars) First Mortgage Bonds: 7 3/8% Series B, due 2001................... $ 60.0 $ 60.0 7 3/4% Series V, due 2002................... 40.0 84.2 7 3/4% Series Y, due 2024................... - 50.0 ------ ------ 100.0 194.2 Pollution Control Notes: Tax Exempt 1993 Series A, 5.85% due 2028.. 53.8 53.8 Fees and interest due for spent nuclear fuel disposal costs....................... 45.6 43.0 Less amounts due within one year............ 60.0 - Unamortized premium and discount, net....... - (0.7) ------ ------ Long-term debt, net......................... $139.4 $290.3 ====== ====== -------------------------------------------------------------------------- Long-term debt maturities and cash sinking fund requirements, excluding fees and interest due for spent nuclear fuel disposal costs, on debt outstanding at December 31, 2000, for the years 2001 through 2005 are $60 million, $40 million, and no requirements for 2003, 2004 and 2005. Essentially all utility plant of WMECO is subject to the liens of the company's first mortgage bond indenture. WMECO has secured $53.8 million of pollution control notes with second mortgage liens on Millstone 1, junior to the liens of its first mortgage bond indenture. 7. INCOME TAX EXPENSE The components of the federal and state income tax provisions were charged/(credited) to operations as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Current income taxes: Federal...................................... $ 15.8 $ 13.5 $ (7.4) State........................................ 10.9 2.0 (0.1) ------ ------ ------ Total current.............................. 26.7 15.5 (7.5) ------ ------ ------ Deferred income taxes, net: Federal.................................... (0.8) (3.5) 6.5 State...................................... (8.6) (0.9) 2.4 ------ ------ ------ Total deferred........................... (9.4) (4.4) 8.9 ------ ------ ------ Investment tax credits, net.................. (2.1) (2.2) (1.5) ------ ------ ------ Total income tax expense/(credit)............ $ 15.2 $ 8.9 $ (0.1) ====== ====== ====== -------------------------------------------------------------------------- The components of total income tax expense/(credit) are classified as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Income taxes charged to operating expenses... $21.2 $18.8 $ 2.1 Other income taxes........................... (6.0) (9.9) (2.2) ----- ----- ----- Total income tax expense/(credit)............ $15.2 $ 8.9 $(0.1) ===== ===== ===== -------------------------------------------------------------------------- Deferred income taxes are comprised of the tax effects of temporary differences as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Depreciation, leased nuclear fuel, settlement credits and disposal costs...... $ 0.9 $ (2.3) $ 5.8 Regulatory deferral.......................... (16.4) (1.4) 1.3 Regulatory disallowance...................... - (4.2) - Pension accruals............................. 5.9 4.2 1.0 Other........................................ 0.2 (0.7) 0.8 ----- ----- ----- Deferred income taxes, net................... $(9.4) $(4.4) $ 8.9 ===== ===== ===== -------------------------------------------------------------------------- A reconciliation between income tax expense/(credit) and the expected tax expense/(credit) at 35 percent of pretax income/(loss) is as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Expected federal income tax.................. $17.6 $ 4.1 $(3.4) Tax effect of differences: Depreciation............................... (1.2) 0.2 2.2 Amortization of regulatory assets.......... 1.3 6.2 0.9 Investment tax credit amortization......... (2.1) (2.2) (1.5) State income taxes, net of federal benefit.......................... 1.5 0.7 1.5 Dividends received deduction............... (1.7) (0.4) (0.7) Other, net................................. (0.2) 0.3 0.9 ----- ----- ----- Total income tax expense/(credit)............ $15.2 $ 8.9 $(0.1) ===== ===== ===== -------------------------------------------------------------------------- 8. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS The NU system companies, including WMECO, participate in a uniform noncontributory defined benefit retirement plan covering substantially all regular NU system employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. WMECO's portion of the NU system's total pension credit, part of which was credited to utility plant, was $19 million in 2000, $10.8 million in 1999 and $7.4 million in 1998. Currently, WMECO's policy is to annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code. The NU system companies, including WMECO, also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. These benefits are available for employees retiring from WMECO who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. WMECO annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible. Pension and trust assets are invested primarily in domestic and international equity securities and bonds. The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' 7 funded status: - ------------------------------------------------------------------------------- At December 31, - ------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits - ------------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 2000 1999 - ------------------------------------------------------------------------------- Change in benefit obligation Benefit obligation at beginning of year......... $(118.1) $(118.7) $(29.5) $(30.1) Service cost................... (2.2) (2.4) (0.4) (0.5) Interest cost.................. (8.9) (8.5) (2.2) (2.1) Plan amendment................. - (7.3) - - Transfers...................... 0.5 0.2 - - Actuarial (loss)/gain.......... (3.0) 10.2 (0.5) 0.4 Benefits paid.................. 8.2 7.8 2.6 2.6 Settlements and other.......... 2.4 0.6 0.7 0.2 - ------------------------------------------------------------------------------- Benefit obligation at end of year............... $(121.1) $(118.1) $(29.3) $(29.5) - ------------------------------------------------------------------------------- Change in plan assets Fair value of plan assets at beginning of year......... $ 223.9 $ 201.6 $ 16.6 $ 14.6 Actual return on plan assets... (0.9) 29.9 0.8 1.7 Employer contribution.......... - - 2.5 2.9 Benefits paid.................. (8.2) (7.8) (2.6) (2.6) Transfers...................... (0.5) 0.2 - - - ------------------------------------------------------------------------------- Fair value of plan assets at end of year............... $ 214.3 $ 223.9 $ 17.3 $ 16.6 - ------------------------------------------------------------------------------- Funded status at December 31... $ 93.2 $ 105.8 $(12.0) $(12.9) Unrecognized transition (asset)/obligation........... (0.9) (1.2) 19.1 21.2 Unrecognized prior service cost................. 6.6 7.6 - - Unrecognized net gain.......... (53.4) (85.7) (6.6) (8.2) - ------------------------------------------------------------------------------- Prepaid benefit cost........... $ 45.5 $ 26.5 $ 0.5 $ 0.1 - ------------------------------------------------------------------------------- The following actuarial assumptions were used in calculating the plans' year end funded status: ------------------------------------------------------------------------- At December 31, ------------------------------------------------------------------------- Pension Benefits Postretirement Benefits ------------------------------------------------------------------------- 2000 1999 2000 1999 ------------------------------------------------------------------------- Discount rate............. 7.50% 7.75% 7.50% 7.75% Compensation/progression rate.................... 4.50 4.75 4.50 4.75 Health care cost trend rate (a).......... N/A N/A 5.26 5.57 ------------------------------------------------------------------------- (a) The annual per capita cost of covered health care benefits was assumed to decrease to 4.91 percent by 2001. The components of net periodic benefit (credit)/cost are: -------------------------------------------------------------------------- For the Years Ended December 31, -------------------------------------------------------------------------- Postretirement Pension Benefits Benefits -------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 1998 2000 1999 1998 -------------------------------------------------------------------------- Service cost......... $ 2.2 $ 2.4 $ 2.2 $ 0.4 $ 0.5 $ 0.5 Interest cost........ 8.9 8.5 7.9 2.2 2.1 2.1 Expected return on plan assets..... (19.0) (16.9) (14.8) (1.3) (1.0) (0.9) Amortization of unrecognized net transition (asset)/ obligation......... (0.2) (0.2) (0.2) 1.6 1.6 1.6 Amortization of prior service cost....... 0.6 0.6 0.1 - - - Amortization of actuarial gain..... (4.9) (3.4) (2.6) - - - Other amortization, net.. - - - (0.4) (0.3) (0.4) Settlements and other.............. (6.6) (1.8) - - - - -------------------------------------------------------------------------- Net periodic benefit (credit)/cost....... $(19.0) $(10.8) $ (7.4) $ 2.5 $ 2.9 $ 2.9 -------------------------------------------------------------------------- For calculating pension and postretirement benefit costs, the following assumptions were used: -------------------------------------------------------------------------- For the Years Ended December 31, -------------------------------------------------------------------------- Postretirement Pension Benefits Benefits -------------------------------------------------------------------------- 2000 1999 1998 2000 1999 1998 -------------------------------------------------------------------------- Discount rate........ 7.75% 7.00% 7.25% 7.75% 7.00% 7.25% Expected long-term rate of return..... 9.50 9.50 9.50 N/A N/A N/A Compensation/ progression rate.... 4.75 4.25 4.25 4.75 4.25 4.25 Long-term rate of return - Health assets, net of tax....... N/A N/A N/A 7.50 7.50 7.75 Life assets........ N/A N/A N/A 9.50 9.50 9.50 -------------------------------------------------------------------------- Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects: -------------------------------------------------------------------------- One Percentage One Percentage (Millions of Dollars) Point Increase Point Decrease -------------------------------------------------------------------------- Effect on total service and interest cost components $0.1 $(0.1) Effect on postretirement benefit obligation $1.4 $(1.3) -------------------------------------------------------------------------- The trust holding the health plan assets is subject to federal income taxes. 9. COMMITMENTS AND CONTINGENCIES A. Restructuring A settlement has been reached with the Massachusetts Attorney General finalizing a $155 million securitization plan. WMECO expects to receive approval of its securitization plan in February 2001. B. Nuclear Generation Assets Divestiture On August 7, 2000, WMECO and certain other joint owners reached an agreement to sell substantially all of the Millstone units, located in Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including approximately $105 million for nuclear fuel. Dominion has also agreed to assume responsibility for decommissioning the three units and NU will transfer to Dominion all funds in the Millstone decommissioning trust. Additionally, NU is obligated to top-off the decommissioning trust if its value does not equal a previously agreed upon level as defined. NU expects to close on the sale of Millstone as early as the end of March 2001. If the transaction is consummated as proposed, WMECO would receive gross proceeds of approximately $196.2 million on a pretax basis for its respective ownership interest. The proceeds from the sale of this interest will be used to reduce the company's stranded costs under restructuring and the cash proceeds will be used to repay subsidiary debt and capital lease obligations and to return equity capital to the parent company. C. Environmental Matters The NU system, including WMECO, is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of our environment. As such, the NU system, including WMECO, have active environmental auditing and training programs and believe they are substantially in compliance with the current laws and regulations. However, the normal course of operations may involve activities and substances that expose WMECO to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on WMECO's consolidated financial statements. Based upon currently available information for the estimated remediation costs as of December 31, 2000 and 1999, the liability recorded by WMECO for its estimated environmental remediation costs amounted to $4.6 million and $4.2 million, respectively. D. Spent Nuclear Fuel Disposal Costs Under the Nuclear Waste Policy Act of 1982, WMECO must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high- level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. As of December 31, 2000 and 1999, fees due to the DOE for the disposal of Prior Period Fuel were $45.6 million and $43 million, respectively, including interest costs of $30 million and $27.4 million, respectively. Fees for nuclear fuel burned on or after April 7, 1983, are billed currently to customers and paid to the DOE on a quarterly basis. WMECO is responsible for fees to be paid for fuel burned until the divestiture of the Millstone nuclear units. E. Nuclear Insurance Contingencies Insurance policies covering WMECO's ownership share of the NU system's nuclear facilities have been purchased for the primary cost of repair, replacement or decontamination of utility property, certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement or decontamination or premature decommissioning of utility property. WMECO is subject to retroactive assessments if losses under those policies exceed the accumulated funds available to the insurer. The maximum potential assessments with respect to losses arising during the current policy year for the primary property insurance program, the replacement power policies and the excess property damage policies are $1.1 million, $0.6 million and $1.4 million, respectively. In addition, insurance has been purchased by the NU system in the aggregate amount of $200 million on an industry basis for coverage of worker claims. Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third-party liability indemnification program, the NU system, including WMECO, could be assessed liabilities in proportion to its ownership interest in each of its nuclear units up to $83.9 million. The NU system's payment of this assessment would be limited to, in proportion to its ownership interest in each of its nuclear units, $10 million in any one year per nuclear unit. In addition, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection, the NU system, including WMECO, would be subject to an additional 5 percent, or $4.2 million, liability, in proportion to its ownership interests in each of its nuclear units. Based upon its ownership interests in the Millstone units, WMECO's maximum liability, including any additional assessments, would be $44.3 million per incident, of which payments would be limited to $5 million per year. In addition, through purchased-power contracts with VYNPC, WMECO would be responsible for up to an additional assessment of $2.2 million per incident, of which payments would be limited to $0.3 million per year. WMECO expects to terminate its nuclear insurance upon the divestiture of its nuclear units. F. Long-Term Contractual Arrangements Yankee Companies: Under the terms of its agreement, WMECO paid its ownership (or entitlement) shares of costs, which included depreciation, operation and maintenance (O&M) expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs were recorded as purchased-power expenses. WMECO's cost of purchases under its contract with VYNPC amounted to $4 million in 2000, $4.7 million in 1999 and $4.4 million in 1998. VYNPC is in the process of selling its nuclear unit. Upon completion of the sale, this long-term contract will be terminated. Nonutility Generators (NUGs): WMECO has entered into various arrangements for the purchase of capacity and energy from NUGs. WMECO's total cost of purchases under these arrangements amounted to $28.5 million in 2000, $28.2 million in 1999 and $29.9 million in 1998. The company is in the process of renegotiating the terms of these contracts through either a contract buydown or buyout. WMECO expects any payments to the NUGs as a result of these renegotiations to be recovered from the company's customers. Hydro-Quebec: Along with other New England utilities, WMECO has entered into an agreement to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. WMECO is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M expenses and capital costs of those facilities. Estimated Annual Costs: The estimated annual costs of WMECO's significant long-term contractual arrangements, absent the effects of any contract terminations, buydowns or buyouts are as follows: --------------------------------------------------------------------- 2001 2002 2003 2004 2005 --------------------------------------------------------------------- (Millions of Dollars) VYNPC............. $ 4.8 $ 4.9 $ 5.0 $ 5.4 $ 5.1 NUGs.............. 29.5 30.4 31.2 31.9 32.6 Hydro-Quebec...... 3.2 3.1 3.0 2.9 2.8 --------------------------------------------------------------------- 10. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS Millstone: WMECO's operating nuclear power plants, Millstone 2 and 3, have service lives that are expected to end in 2015 and 2025, respectively, and upon retirement, must be decommissioned. Millstone 1's expected service life was to end in 2010, however, in July 1998, restart activities were discontinued and decommissioning of the unit began. In connection with the sale of the Millstone units, Dominion has agreed to assume responsibility for decommissioning. Until the divestiture, WMECO recovers sufficient amounts through its allowed rates related to decommissioning costs. WMECO's ownership share of the estimated cost of decommissioning Millstone 2 and 3, in year end 2000 dollars, is $81.8 million and $79.3 million, respectively. Nuclear decommissioning costs are accrued over the expected service lives of the units and are included in depreciation expense and the accumulated provision for depreciation. Nuclear decommissioning expenses for these units amounted to $3.7 million in 2000, 1999 and 1998. Nuclear decommissioning expenses for Millstone 1 were $2.5 million in 2000, $2.9 million in 1999 and $2.5 million in 1998. Through December 31, 2000 and 1999, total decommissioning expenses of $43 million and $39.3 million, respectively, have been collected from customers and are reflected in the accumulated provision for depreciation. External decommissioning trusts have been established for the costs of decommissioning the Millstone units. Funding of the estimated decommissioning costs assumes after-tax earnings on the Millstone decommissioning funds of 5.5 percent. As of December 31, 2000 and 1999, $43 million and $39.3 million, respectively, have been transferred to external decommissioning trusts. Earnings on the decommissioning trusts increase the decommissioning trust balances and the accumulated provisions for depreciation. Unrealized gains and losses associated with the decommissioning trusts also impact the balance of the trusts and the accumulated provisions for depreciation. The fair values of the amounts in the external decommissioning trusts were $82.4 million and $77.4 million at December 31, 2000 and 1999, respectively. Upon divestiture, balances in the decommissioning trusts will be transferred to the buyer. NU is obligated to top-off the Millstone decommissioning trust if its value does not equal an agreed upon amount at closing, pursuant to the conditions set forth in the purchase and sale agreement. Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. WMECO's ownership share of estimated costs, in year end 2000 dollars, of decommissioning this unit is $11.3 million. In 1999, VYNPC agreed to sell its nuclear generating unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the obligation to decommission the unit after it is taken out of service, and the owners of VYNPC (including WMECO) agreed to fund their shares of the decommissioning costs up to a negotiated amount. Subsequent to the time that agreement was executed, the original proposed acquiring company has increased the price it agreed to pay and three other unaffiliated companies have indicated their interest in buying VYNPC's generating unit on terms that have not been disclosed. At present, WMECO expects that the unit will be sold, but the identity of the owner and the terms of sale, including price, future decommissioning obligations and future power purchase obligations, are not known. As of December 31, 2000 and 1999, WMECO's remaining estimated obligation, including decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down was $42.5 million and $63.7 million, respectively. 11. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Nuclear Decommissioning Trusts: WMECO's portion of the investments held in the NU system companies' nuclear decommissioning trusts were marked- to-market by $32.3 million as of December 31, 2000, and $35.4 million as of December 31, 1999, with corresponding offsets to the accumulated provision for depreciation. The amounts adjusted in 2000 and in 1999 represent cumulative net unrealized gains. Cumulative gross unrealized holding losses were immaterial for both 2000 and 1999. Preferred stock and long-term debt: The fair value of WMECO's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of WMECO's financial instruments and the estimated fair values are as follows: -------------------------------------------------------------------------- At December 31, 2000 -------------------------------------------------------------------------- Carrying Fair (Millions of Dollars) Amount Value -------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption............... $ 20.0 $ 20.2 Preferred stock subject to mandatory redemption.................. 16.5 16.5 Long-term debt - First mortgage bonds.................. 100.0 100.3 Other long-term debt.................. 99.4 93.7 -------------------------------------------------------------------------- -------------------------------------------------------------------------- At December 31, 1999 -------------------------------------------------------------------------- Carrying Fair (Millions of Dollars) Amount Value -------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption............... $ 20.0 $ 19.1 Preferred stock subject to mandatory redemption.................. 18.0 18.0 Long-term debt - First mortgage bonds.................. 194.2 196.3 Other long-term debt.................. 96.8 89.9 -------------------------------------------------------------------------- 12. OTHER COMPREHENSIVE INCOME The accumulated balance for each other comprehensive income item is as follows: -------------------------------------------------------------------------- Current December 31, Period December 31, 1999 Change 2000 -------------------------------------------------------------------------- (Thousands of Dollars) -------------------------------------------------------------------------- Unrealized gains on securities................ $193 $22 $215 Minimum pension liability adjustments........... (33) - (33) -------------------------------------------------------------------------- Accumulated other comprehensive income............ $160 $22 $182 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Current December 31, Period December 31, 1998 Change 1999 -------------------------------------------------------------------------- (Thousands of Dollars) -------------------------------------------------------------------------- Unrealized gains on securities................... $183 $10 $193 Minimum pension liability adjustments........... (33) - (33) -------------------------------------------------------------------------- Accumulated other comprehensive income............ $150 $10 $160 -------------------------------------------------------------------------- The changes in the components of other comprehensive income are reported net of the following income tax effects: -------------------------------------------------------------------------- 2000 1999 1998 -------------------------------------------------------------------------- (Thousands of Dollars) -------------------------------------------------------------------------- Unrealized gains on securities......... $(14) $(7) $(117) Minimum pension liability adjustments.. - - 21 Other comprehensive income............. $(14) $(7) $ (96) -------------------------------------------------------------------------- 13. SEGMENT INFORMATION Effective January 1, 1999, the NU system companies, including WMECO, adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." The NU system is organized between regulated utilities and competitive energy subsidiaries. WMECO is included in the regulated utilities segment of the NU system and has no other reportable segments. 14. SUBSEQUENT EVENT Merger Agreement With Consolidated Edison, Inc.: In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the approvals needed to complete the merger announced in October 1999. Shareholders from both companies approved the merger in April 2000, and all state regulatory approvals were granted by the end of the year. Additionally, the FERC approved the merger in May 2000, the Nuclear Regulatory Commission approved the transaction in August 2000, and the United States Department of Justice approved the merger in February 2001. Necessary approval from the SEC was expected to be received in mid-March 2001. On February 28, 2001, NU's Board of Trustees requested that Con Edison provide reasonable assurance, in writing, that it intended to comply with the terms of the definitive merger agreement between the two companies. This included assurances that Con Edison would consummate the pending merger at the price set forth in the agreement promptly following the receipt of SEC approval. The original request for assurance was to be received by March 2, 2001, however that date was later extended to March 5, 2001. On March 5, 2001, Con Edison advised NU that it was not willing to close the merger on the agreed terms. NU notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that NU would file suit to obtain the benefits of the transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District of New York (Southern District), seeking declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement. On March 12, 2001, NU filed suit against Con Edison in the Southern District seeking damages in excess of $1 billion arising from Con Edison's breach of the merger agreement. Western Massachusetts Electric Company and Subsidiary
- ---------------------------------------------------------------------------------------------------------- SELECTED CONSOLIDATED FINANCIAL DATA 2000 1999 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.................. $ 513,678 $ 414,231 $ 393,322 $ 426,447 $ 421,337 Operating Income.................... 54,096 41,741 19,854 251 33,190 Net Income/(Loss)................... 35,268 2,887 (9,579) (27,460) 11,089 Cash Dividends on Common Stock...... 12,002 - - 15,004 16,494 Total Assets........................ 1,047,818 1,253,604 1,287,682 1,179,128 1,191,915 Long-Term Debt (a).................. 199,425 290,279 389,314 396,649 349,442 Preferred Stock Not Subject to Mandatory Redemption).......... 20,000 20,000 20,000 20,000 20,000 Preferred Stock Subject to Mandatory Redemption (a).......... 16,500 18,000 19,500 21,000 21,000 Obligations Under Capital Leases (a)........................ 26,921 29,972 34,093 32,887 32,234 - ----------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------ CONSOLIDATED QUARTERLY FINANCIAL DATA (Unaudited) - ------------------------------------------------------------------------------------------------ Quarter Ended - ------------------------------------------------------------------------------------------------ 2000 March 31 June 30 September 30 December 31 - ------------------------------------------------------------------------------------------------ (Thousands of Dollars) Operating Revenues $129,410 $120,090 $130,400 $133,778 ======== ======== ======== ======== Operating Income $ 14,782 $ 9,974 $ 13,940 $ 15,400 ======== ======== ======== ======== Net Income $ 11,053 $ 2,956 $ 9,638 $ 11,621 ======== ======== ======== ======== - ------------------------------------------------------------------------------------------------ 1999 - ------------------------------------------------------------------------------------------------ Operating Revenues $ 97,686 $108,829 $107,776 $ 99,940 ======== ======== ======== ======== Operating Income/(Loss) $ 12,205 $ 8,812 $ 22,821 $ (2,097) ======== ======== ======== ======== Net Income/(Loss) $ 4,852 $ 4,183 $ 11,368 $(17,516) ======== ======== ======== ========
(a) Includes portion due within one year. Western Massachusets Electric Company and Subsidiary - ------------------------------------------------------------------------------- CONSOLIDATED STATISTICS (Unaudited) - ------------------------------------------------------------------------------- Average Gross Electric Annual Utility Plant Use Per December 31, kWh Residential Electric (Thousands of Sales Customer Customers Employees Dollars) (Millions) (kWh) (Average) December 31, - ------------------------------------------------------------------------------- 2000 $1,535,514 7,278 7,371 198,372 406 1999 1,216,015 4,654 7,423 198,012 482 1998 1,256,046 4,091 6,979 196,339 533 1997 1,334,233 4,300 7,121 195,324 507 1996 1,303,361 4,626 7,335 194,705 497 EX-13.3 17 0017.txt ANNUAL REPORT OF PSNH 2000 Annual Report Public Service Company of New Hampshire Index Contents Page - -------- ---- Management's Discussion and Analysis of Financial Condition and Results of Operations............................. 1 Report of Independent Public Accountants.......................... 10 Statements of Income.............................................. 11 Statements of Comprehensive Income................................ 11 Balance Sheets.................................................... 12-13 Statements of Common Stockholder's Equity......................... 14 Statements of Cash Flows.......................................... 15 Notes to Financial Statements..................................... 16-38 Selected Financial Data........................................... 39 Quarterly Financial Data (Unaudited).............................. 39 Statistics (Unaudited)............................................ 40 Preferred Stockholder and Bondholder Information.................. Back Cover Public Service Company of New Hampshire - ------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - ------------------------------------------------------------------------------- Financial Condition - ------------------- Overview - -------- Public Service Company of New Hampshire (PSNH or the company) is a wholly owned operating subsidiary of Northeast Utilities (NU) and is part of the Northeast Utilities system (NU system). PSNH earned $67.6 million before extraordinary charges in 2000. Earnings before extraordinary charges declined $16.6 million from 1999, primarily as a result of a rate decrease on October 1, 2000, and lower wholesale revenues. Because of extraordinary charges totaling $214.2 million, PSNH had a net loss of $146.7 million in 2000, compared with $84.2 million in 1999 and $91.7 million in 1998. These extraordinary charges are a result of the "Agreement to Settle PSNH Restructuring" (Settlement Agreement) with the State of New Hampshire and the discontinuation of Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." During 2000, PSNH and the State of New Hampshire were able to reach a settlement regarding restructuring in the state. This agreement ended several years of uncertainty related to restructuring for PSNH and the State of New Hampshire. PSNH expects to implement the settlement agreement in 2001. Increases in sales pushed total PSNH revenues to $1.29 billion in 2000, up 11.2 percent from $1.16 billion in 1999. The growth in competitive energy revenues more than offset a 5 percent rate reduction on October 1, 2000 for PSNH retail customers. Revenues were $1.09 billion in 1998. Operating earnings at PSNH are expected to decline significantly after the first quarter of 2001, as a result of the retail rate reductions that will accompany the introduction of industry restructuring in New Hampshire. Consolidated Edison, Inc. Merger In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the approvals needed to complete the merger announced in October 1999. Shareholders from both companies approved the merger in April 2000, and all state regulatory approvals were granted by the end of the year. Additionally, the Federal Energy Regulatory Commission (FERC) approved the merger in May 2000, the Nuclear Regulatory Commission approved the transaction in August 2000, and the United States Department of Justice approved the merger in February 2001. Necessary approval from the Securities and Exchange Commission (SEC) was expected to be received in mid-March 2001. On February 28, 2001, NU's Board of Trustees requested that Con Edison provide reasonable assurance, in writing, that it intended to comply with the terms of the definitive merger agreement between the two companies. This included assurances that Con Edison would consummate the pending merger at the price set forth in the agreement promptly following the receipt of SEC approval. The original request for assurance was to be received by March 2, 2001, however that date was later extended to March 5, 2001. On March 5, 2001, Con Edison advised NU that it was not willing to close the merger on the agreed terms. NU notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that NU would file suit to obtain the benefits of the transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District of New York (Southern District), seeking a declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement. On March 12, 2001, NU filed suit against Con Edison in the Southern District seeking damages in excess of $1 billion arising from Con Edison's breach of the merger agreement. NU cannot predict the outcome of this matter nor its effect on NU. Liquidity - --------- During 2000, net cash flows provided by PSNH's operations were $190.3 million, compared to $199.1 million in 1999 and $217.6 million in 1998. The decrease in 2000 is primarily related to a decrease in net income and an increase in amortization of recoverable energy costs. Net cash flows used in financing activities were $188.9 million in 2000, compared to $31.6 million in 1999 and $204.3 million in 1998. This included approximately $135 million paid in 2000 to retire long-term debt and preferred stock, compared to $25 million in 1999 and $195 million in 1998. Payments made for preferred stock dividends were $4 million, $6.6 million and $9.3 million for 2000, 1999 and 1998, respectively. For the first time since March 1997, PSNH paid a cash dividend on common shares. In October 2000, a cash dividend of $50 million was paid in 2000. Including construction expenditures and investments in nuclear decommissioning trusts, net cash flows used in investing activities were $68.9 million in 2000, compared to $45.8 million in 1999 and $46.9 million in 1998. PSNH currently forecasts construction expenditures of $78.7 million for the year 2001. In April 2000, Moody's Investors Service (Moody's) upgraded its credit ratings for PSNH, and in October 2000, Fitch IBCA (Fitch) upgraded its credit ratings for PSNH. In January 2001, Moody's and Standard and Poor's upgraded their credit ratings for PSNH, primarily as a result of the New Hampshire Supreme Court's decision to uphold the state's restructuring plan, the anticipated sale of Millstone and NU's general financial recovery. These upgrades return NU and PSNH to investment grade ratings for the first time in five years and will save the NU system in excess of $4.7 million annually in financing costs. PSNH terminated its $75 million revolving credit agreement in April 1999 and continues to fund its operations and capital program with cash on hand and operating cash flows. In August and September 2000, PSNH repaid $109.2 million of variable-rate taxable pollution control bonds from cash on hand. PSNH also paid a $50 million common dividend to NU on October 2, 2000, PSNH's first common dividend to NU since February 1997. Despite those cash outflows, PSNH maintained $115.1 million of cash on hand as of December 31, 2000. PSNH expects to receive gross proceeds of $26 million as a result of the sale of their ownership interest in the Millstone units to Dominion Resources, Inc. (Dominion). This sale is expected to close as early as the end of March 2001. The cash proceeds, in addition to those anticipated from securitization and the future sale of the Seabrook Station nuclear unit (Seabrook), are expected to be used to repay subsidiary debt and capital lease obligations and to return equity capital to the parent company. By the end of 2002, PSNH expects to complete the auction of approximately 1,200 MW of fossil and hydroelectric generation assets, as well as CL&P's and NAEC's share of Seabrook. PSNH's restructuring settlement was predicated upon receiving approximately $400 million of net proceeds from those sales. Cash proceeds will be used to retire debt and to return equity capital to the parent company. In September 2000, the New Hampshire Public Utilities Commission (NHPUC) approved a comprehensive restructuring settlement that allows PSNH to securitize up to $670 million of stranded costs. In January 2001, the New Hampshire Supreme Court upheld this restructuring order on appeal. However, one of the appellants indicated publicly it would request a review of the New Hampshire Supreme Court decision by the United States Supreme Court. Such a request must be filed by May 1, 2001. Management believes that such an appeal would have a low probability of success, but cannot determine what effect it might have on the timing of the issuance of securitization bonds and the implementation of customer choice in New Hampshire. PSNH currently expects to work with the State of New Hampshire to issue securitization bonds early in the second quarter of 2001. Cash proceeds would be combined with cash on hand and used primarily to buydown the power contract between PSNH and NAEC, retire debt at the two companies of approximately $300 million and to return equity capital to the parent company from PSNH and NAEC of another $375 million. Restructuring - ------------- Because of delays in implementing restructuring, PSNH remained a vertically integrated utility in 2000 with a fuel and purchased-power adjustment charge. For the first nine months following restructuring, PSNH will meet the load requirements of those customers who do not choose an alternative supplier (transition service or standard offer service) through its own generation assets and purchased-power obligations. Because PSNH's generation assets are heavily weighted toward coal and nuclear generation, PSNH is somewhat insulated from rising oil and natural gas prices. Following that initial nine-month period, PSNH expects to sell its generation assets and acquire power for up to two years from third-party suppliers for customers who remain on transition service. Under the restructuring statute and the conforming Settlement Agreement, PSNH will utilize its own generation capability to provide Transition Service and Default Service for the Initial Transition Service Period (ITSP, the first nine months after competition day) as defined in the agreement. At the conclusion of the ITSP, PSNH will be required to contract for Transition Service for the remaining 24-month Transition Service period with third-party suppliers through a competitive bidding process administered by the NHPUC. As part of its negotiation with the state legislature, PSNH has agreed to absorb the first $7 million of costs for the first 12-month period following the ITSP, if the cost of acquiring Transition Service exceeds the rate charged to customers. PSNH will be permitted to defer and recover, as unsecuritized stranded costs, all Transition Service costs in excess of the initial $7 million. Provisions for Transition Service are but one element of the Settlement Agreement which during 2000 was approved by the New Hampshire House and Senate, signed into law by the Governor of New Hampshire and approved by the NHPUC. Other provisions allow for issuing rate reduction bonds to securitize stranded costs; implementing a rate decrease of approximately 15.5 percent, 5 percent of which was implemented on a temporary basis on October 1, 2000; an after-tax write-off of stranded costs in excess of $200 million, which was recorded in the fourth quarter; selling NAEC's share of Seabrook no later than December 31, 2003, and; fixing PSNH's delivery rates at $0.028 per kilowatt-hour for the first 33 months after the Settlement Agreement takes effect. PSNH and NAEC will also terminate the Seabrook Power Contracts upon the sale of Seabrook. Restructuring is expected to take effect the first day of the month after PSNH issues rate reduction bonds, which is anticipated to be May 1, 2001. For further information regarding commitments and contingencies related to restructuring, see Note 9A, "Commitments and Contingencies - Restructuring," to the financial statements. Regional Transmission Organization - ---------------------------------- Pursuant to FERC Order 888 (issued in April 1996), the NU system companies, including PSNH, operate their transmission system under an open access, nondiscriminatory transmission tariff. In December 1999, the FERC issued an order calling on all transmission owners to voluntarily join Regional Transmission Organizations (RTOs) in order to boost competition in electric markets. In general, each of these organizations would be an independent operator over all transmission facilities, and would perform, among other functions, tariff administration, construction planning and reliability management for the particular regional transmission system. NU's active voting interest in such an organization would be limited to 5 percent under the proposal. The NU system companies, including PSNH, and other parties have appealed this order. Of primary concern to NU is the ratemaking authority granted to RTOs and its impact on the ability of transmission owners to earn appropriate returns on their transmission investment under the organizational structure and the minimum functions proposed in the order. The NU system companies were required to participate in a collaborative process established by the FERC beginning in March of 2000. On January 16, 2001, NU along with the Independent System Operator and five other New England transmission owning utilities filed a proposal to establish a New England RTO. Nuclear Plant Performance and Divestiture - ----------------------------------------- Seabrook North Atlantic Energy Corporation (NAEC) is another wholly owned subsidiary of NU. PSNH is obligated to purchase the capacity and output from NAEC's 35.98 percent joint ownership interest in the Seabrook Station nuclear unit (Seabrook) under the terms of two life-of-unit, full cost recovery contracts (Seabrook Power Contracts). Seabrook operated at a capacity factor of 78 percent in 2000. The unit began a scheduled refueling outage on October 21, 2000. The outage was extended by approximately two months as a result of the need to repair extensive problems with a back-up diesel generator. Seabrook returned to service on January 29, 2001. On December 15, 2000, PSNH filed its divestiture plan for Seabrook with the NHPUC and DPUC. PSNH hopes to complete the sale in 2002. Millstone 3 PSNH has a 2.85 percent ownership of the Millstone 3 unit. Millstone 3 operated at virtually a 100 percent capacity factor in 2000 and ran for 585 consecutive days before beginning a scheduled refueling outage on February 3, 2001. Millstone 3 is expected to return to service by the end of the first quarter 2001. On August 7, 2000, CL&P, WMECO and certain other joint owners including PSNH reached an agreement to sell substantially all of the Millstone units, located in Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including approximately $105 million for nuclear fuel. Dominion has also agreed to assume responsibility for decommissioning the three units and NU will transfer to Dominion all funds in the Millstone decommissioning trust. Additionally, NU is obligated to top-off the decommissioning trust if its value does not equal an agreed upon amount at closing. That amount is pursuant to the purchase and sale agreement (PSA) with Dominion, subject to adjustment for delays in the closing of the sale and Millstone 1 not meeting the "cold and dark" condition specified in the PSA. If the transaction is consummated as proposed, PSNH will receive $26 million on a pretax basis, which will be reflected as a gain in accordance with the Settlement Agreement. NU currently expects to close on the sale of Millstone as early as the end of March 2001. Yankee Companies PSNH is a 4 percent shareholder and sponsor company of the Vermont Yankee Nuclear Power Corporation (VYNPC). In 1999, VYNPC agreed to sell its nuclear generating unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the obligation to decommission the unit after it is taken out of service, and the owners of VYNPC (including PSNH) agreed to fund their shares of the decommissioning costs up to a negotiated amount. Subsequent to the time that the agreement was executed, the original proposed acquiring company increased its purchase price and three other unaffiliated companies have indicated their interest in buying VYNPC's generating unit on terms that have not been disclosed. On February 14, 2001, the Vermont Public Service Board dismissed the acquiring company's petition for approval and VYNPC agreed to work with the Vermont regulators to develop an auction process for the sale of the unit. At present, PSNH expects that the unit will be sold, but the identity of the owner and the terms of sale, including price, future decommissioning obligations and future power purchase obligations, are not known. Nuclear Decommissioning In connection with the aforementioned sale of the Millstone units, Dominion has agreed to assume responsibility for decommissioning the Millstone units. For further information regarding nuclear decommissioning, see Note 10, "Nuclear Decommissioning and Plant Closure Costs," to the financial statements. Spent Nuclear Fuel Disposal Costs The United States Department of Energy (DOE) originally was scheduled to begin accepting delivery of spent fuel in 1998. However, delays in confirming the suitability of a permanent storage site continually have postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. PSNH has the primary responsibility for the interim storage of its share of spent nuclear fuel prior to the divestiture of Millstone 3. For further information regarding spent nuclear fuel disposal costs, see Note 9D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the financial statements. Other Matters - ------------- Environmental Matters PSNH is subject to environmental laws and regulations structured to mitigate or remove the effect of past operations and to improve or maintain the quality of the environment. For further information regarding environmental matters, see Note 9C, "Commitments and Contingencies - Environmental Matters," to the financial statements. Other Commitments and Contingencies For further information regarding other commitments and contingencies, see Note 9, "Commitments and Contingencies," to the financial statements. Forward Looking Statements This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancing, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in historical weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, and other presently unknown or unforeseen factors. RESULTS OF OPERATIONS The components of significant income statement variances for the past two years are provided in the table below. Income Statement Variances (Millions of Dollars) 2000 over/(under) 1999 1999 over/(under) 1998 ----------------------------------------------- Amount Percent Amount Percent ------ ------- ------ ------- Operating Revenues $ 131 11% $ 73 7% Operating Expenses: Fuel, purchased and net interchange power 162 23 86 14 Other operation and maintenance (11) (6) 11 7 Depreciation (4) (8) 2 5 Amortization of regulatory assets, net 11 31 8 30 Federal and state income taxes 8 22 (28) (43) Taxes other than income taxes (1) (3) - 1 ----- --- ----- --- Total operating expenses 165 16 80 8 ----- --- ----- --- Operating Income: (35) (28) (7) (5) ----- --- ----- --- Equity in earnings of regional nuclear generating companies 1 71 (2) (58) Other, net 8 (a) (4) (38) Other income taxes 4 (a) 4 (a) ----- --- ----- --- Net other income 12 (a) (2) (35) Interest charges (6) (13) (1) (1) ----- --- ----- --- Income before extraordinary items (17) (20) (7) (8) ----- --- ----- --- Extraordinary loss (214) (a) - - ----- --- ----- --- Net Income/(Loss) $(231) (a) $ (7) (8) (a) Percent greater than 100. Operating Revenues Operating revenues increased by $131 million or 11 percent in 2000, primarily due to higher wholesale and retail revenues. Wholesale revenues increased by $128 million primarily due to higher wholesale energy and capacity sales. Retail revenues were higher primarily due to higher retail sales ($12 million), partially offset by a rate decrease as part of PSNH restructuring ($8 million). Retail kilowatt-hour sales increased by 2.1 percent. Operating revenues increased by $73 million or 7 percent in 1999, primarily due to higher retail revenues ($43 million), higher wholesale energy and capacity sales and transmission revenues ($30 million). Retail kilowatt-hour sales increased by 5.3 percent. Fuel, Purchased and Interchange Power, Net Fuel, purchased and net interchange power expense increased in 2000, primarily due to higher wholesale energy sales. Fuel, purchased and net interchange power expense increased in 1999, primarily due to higher purchased-power expenses ($48 million)and higher deferred expenses ($25 million) associated with the company's fuel clause and higher capacity costs for Seabrook ($8 million). Seabrook's capacity costs are higher due to costs associated with the refueling outage in 1999 and the amortization of the deferred return that was deferred by PSNH through November 1998. Other Operation and Maintenance Expense Other operation and maintenance (O&M) expense increased in 2000, primarily due to lower transmission and distribution expense ($6 million) and lower fossil maintenance expenses($5 million). Other O&M expense increased in 1999, primarily due to the recognition of environmental insurance proceeds which reduced O&M expense in 1998 ($12 million), higher fossil maintenance expenses ($3 million) and higher transmission expense ($2 million), partially offset by lower storm cost in 1999 ($6 million). Amortization of Regulatory Assets Amortization of regulatory assets net increased in 2000, primarily due to the completion of, in 1999, the amortization of regulatory obligations related to net operating loss carryforwards as a result of the Global Settlement. Amortization of regulatory assets, net increased in 1999, primarily due to an increase in the amortization of the Seabrook deferred return which began in June 1998. The reduction of the acquisition premium amortization ($21 million) was offset by the completion in 1999, of the amortization of a regulatory obligation related to net operating loss carryforwards ($21 million) as a result of the Global Settlement. Federal and State Income Taxes Federal and state income taxes increased in 2000, primarily due to the 1999 utilization of net operating loss carryforwards. Federal and state income taxes decreased in 1999, primarily due to the utilization of net operating loss carryforwards. Equity Earnings of Regional Nuclear Generating Companies Equity in earnings of regional nuclear generating and transmission companies was relatively unchanged in 2000. Equity in earnings of regional nuclear generating and transmission companies decreased in 1999, primarily due to lower earnings from Connecticut Yankee. Other, Net Other, net increased in 2000, primarily due to the 1999 settlement with the New Hampshire Electric Cooperative (NHEC) which was recognized in a $6.2 million write-off in 1999. Other, net decreased in 1999, primarily due to the settlement with the NHEC which required a $6.2 million write-off. Interest Charges, Net Interest charges, net decreased in 2000, primarily due to the redemption of long-term debt bonds in 2000. The change in interest charges, net in 1999, was not significant compared to 1998. Extraordinary Loss The extraordinary loss is due to an after-tax write-off by PSNH of approximately $225 million of stranded costs under an industry restructuring settlement with the state of New Hampshire, combined with other positive effects relating to the discontinuation of SFAS 71 ($11 million). REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - ---------------------------------------- To the Board of Directors of Public Service Company of New Hampshire: We have audited the accompanying balance sheets of Public Service Company of New Hampshire (a New Hampshire corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31, 2000 and 1999, and the related statements of income, comprehensive income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2000. 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 in accordance with auditing standards generally accepted in the United States. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Public Service Company of New Hampshire as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut January 23, 2001 (except with respect to the matter discussed in Note 14, as to which the date is March 13, 2001) PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF INCOME
- --------------------------------------------------------------------------------------- FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 - --------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues................................. $1,291,280 $1,160,572 $1,087,247 ----------- ----------- ----------- Operating Expenses: Operation - Fuel, purchased and net interchange power...... 853,563 691,743 605,518 Other.......................................... 123,337 129,041 118,565 Maintenance...................................... 47,429 52,481 51,734 Depreciation..................................... 43,873 47,695 45,342 Amortization of regulatory assets, net........... 45,874 34,915 26,758 Federal and state income taxes................... 45,080 36,810 65,079 Taxes other than income taxes.................... 42,194 43,282 43,052 ----------- ----------- ----------- Total operating expenses................... 1,201,350 1,035,967 956,048 ----------- ----------- ----------- Operating Income................................... 89,930 124,605 131,199 ----------- ----------- ----------- Other Income/(Loss): Equity in earnings of regional nuclear generating companies and subsidiary company.... 1,896 1,112 2,649 Other, net....................................... 13,214 5,681 9,222 Income taxes..................................... 68 (3,914) (7,473) ----------- ----------- ----------- Other income, net.......................... 15,178 2,879 4,398 ----------- ----------- ----------- Income before interest charges............. 105,108 127,484 135,597 ----------- ----------- ----------- Interest Charges: Interest on long-term debt....................... 37,510 42,728 43,317 Other interest................................... 47 547 594 ----------- ----------- ----------- Interest charges, net...................... 37,557 43,275 43,911 ----------- ----------- ----------- Income before extraordinary loss, net of tax benefit............................... 67,551 84,209 91,686 Extraordinary loss, net of tax benefit of $155,783...................................... (214,217) - - ----------- ----------- ----------- Net (Loss)/Income.................................. $ (146,666) $ 84,209 $ 91,686 =========== =========== =========== STATEMENTS OF COMPREHENSIVE INCOME Net (Loss)/Income.................................. $ (146,666) $ 84,209 $ 91,686 ----------- ----------- ----------- Other comprehensive income, net of tax: Unrealized gains on securities..................... 133 70 1,198 Minimum pension liability adjustments.............. - - (194) ----------- ----------- ----------- Other comprehensive income, net of tax........... 133 70 1,004 ----------- ----------- ----------- Comprehensive (Loss)/Income........................ $ (146,533) $ 84,279 $ 92,690 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE BALANCE SHEETS
- ----------------------------------------------------------------------------------------- AT DECEMBER 31, 2000 1999 - ----------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS - ------ Utility Plant, at cost: Electric................................................ $ 1,505,967 $ 1,939,856 Less: Accumulated provision for depreciation......... 711,340 674,155 ------------- ------------- 794,627 1,265,701 Unamortized acquisition costs........................... - 324,437 Construction work in progress........................... 27,251 17,160 Nuclear fuel, net....................................... 1,924 1,734 ------------- ------------- Total net utility plant.............................. 823,802 1,609,032 ------------- ------------- Other Property and Investments: Nuclear decommissioning trusts, at market............... 7,362 6,880 Investments in regional nuclear generating companies and subsidiary company, at equity............ 16,293 18,855 Other, at cost.......................................... 3,225 3,149 ------------- ------------- 26,880 28,884 ------------- ------------- Current Assets: Cash and cash equivalents............................... 115,135 182,588 Receivables, less the accumulated provision for uncollectible accounts of $1,869 in 2000 and $1,359 in 1999......................................... 71,992 79,290 Accounts receivable from affiliated companies........... 2,798 9,091 Taxes receivable from affiliated companies.............. 9,983 11,661 Accrued utility revenues................................ 41,844 48,822 Fuel, materials and supplies, at average cost........... 28,760 38,076 Recoverable energy costs - current portion.............. - 73,721 Prepayments and other................................... 14,750 18,121 ------------- ------------- 285,262 461,370 ------------- ------------- Deferred Charges: Regulatory assets....................................... 924,847 490,921 Deferred receivable from affiliated company............. 3,240 12,984 Unamortized debt expense................................ 9,067 11,896 Other................................................... 9,096 7,346 ------------- ------------- 946,250 523,147 ------------- ------------- Total Assets.............................................. $ 2,082,194 $ 2,622,433 ============= =============
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE BALANCE SHEETS
- ----------------------------------------------------------------------------------------- AT DECEMBER 31, 2000 1999 - ----------------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock, $1 par value - authorized 100,000,000 shares; 1,000 shares outstanding in 2000 and 1999....................................... $ 1 $ 1 Capital surplus, paid in................................ 424,909 424,654 Retained earnings....................................... 123,177 319,938 Accumulated other comprehensive income.................. 1,207 1,074 ------------- ------------- Total common stockholder's equity.............. 549,294 745,667 Preferred stock subject to mandatory redemption......... - 25,000 Long-term debt.......................................... 407,285 516,485 ------------- ------------- Total capitalization........................... 956,579 1,287,152 ------------- ------------- Obligations Under Seabrook Power Contracts and Other Capital Leases................................. 91,702 624,477 ------------- ------------- Current Liabilities: Preferred stock - current portion....................... 24,268 25,000 Obligations under Seabrook Power Contracts and other capital leases - current portion....................... 537,528 101,676 Accounts payable........................................ 45,847 38,685 Accounts payable to affiliated companies................ 54,157 38,229 Accrued taxes........................................... 656 33,443 Accrued interest........................................ 4,962 6,294 Other................................................... 13,112 10,184 ------------- ------------- 680,530 253,511 ------------- ------------- Deferred Credits and Other Long-term Liabilities: Accumulated deferred income taxes....................... 179,723 266,644 Accumulated deferred investment tax credits............. 27,348 12,532 Deferred contractual obligations........................ 41,499 56,544 Deferred revenue from affiliated company................ 3,240 12,984 Deferred pension costs.................................. 41,216 45,504 Other................................................... 60,357 63,085 ------------- ------------- 353,383 457,293 ------------- ------------- Commitments and Contingencies (Note 9) Total Capitalization and Liabilities...................... $ 2,082,194 $ 2,622,433 ============= =============
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- ---------------------------------------------------------------------------------------------------------- Accumulated Capital Other Common Surplus, Retained Comprehensive Stock Paid In Earnings Income Total - ---------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1998............... $ 1 $423,713 $ 170,501 $ - $ 594,215 Net income for 1998.................. 91,686 91,686 Cash dividends on preferred stock.... (9,275) (9,275) Capital stock expenses, net.......... 537 537 Other comprehensive income........... 1,004 1,004 -------- --------- ---------- ------------- ---------- Balance at December 31, 1998............. 1 424,250 252,912 1,004 678,167 Net income for 1999.................. 84,209 84,209 Cash dividends on preferred stock.... (6,625) (6,625) Capital stock expenses, net.......... 404 404 Allocation of benefits - ESOP........ (10,558) (10,558) Other comprehensive income........... 70 70 -------- --------- ---------- ------------- ---------- Balance at December 31, 1999............. 1 424,654 319,938 1,074 745,667 Net loss for 2000.................... (146,666) (146,666) Cash dividends on preferred stock.... (3,962) (3,962) Cash dividends on common stock....... (50,000) (50,000) Capital stock expenses, net.......... 255 255 Tax benefit for 1993-1999 from reduction of NU parent losses (a).. 3,952 3,952 Allocation of benefits - ESOP........ (85) (85) Other comprehensive income........... 133 133 -------- --------- ---------- ------------- ---------- Balance at December 31, 2000............. $ 1 $424,909 $ 123,177 $ 1,207 $ 549,294 ======== ========= ========== ============= ==========
(a) In June 1999, PSNH paid NU parent $10.6 million for NU shares issued from 1992 through 1998 on behalf of its employees in accordance with NU's 401(k) plan. This transaction resulted in a reduction of the NU parent loss and a tax benefit to PSNH. The amount in 2000 represents the remaining previously allocated 1993 through 1999 NU parent losses. The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------------------------- For the Years Ended December 31, - -------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2000 1999 1998 - -------------------------------------------------------------------------------------------------- Operating Activities: Net income before extraordinary loss........................ $ 67,551 $ 84,209 $ 91,686 Adjustments to reconcile to net cash provided by operating activities: Depreciation.............................................. 43,873 47,695 45,342 Deferred income taxes and investment tax credits, net..... (512) (5,297) 78,366 Net (deferral)/amortization of recoverable energy costs... (35,886) 27,065 2,065 Amortization of regulatory assets, net.................... 45,874 34,915 26,758 Tax benefit for 1993-1999 from reduction of NU parent losses........................... 3,952 - - Allocation of ESOP benefits............................... (85) (10,558) - Net other sources/(uses) of cash.......................... 38,694 48,537 (52,004) Changes in working capital: Receivables and accrued utility revenues.................. 20,569 6,004 21,536 Fuel, materials and supplies.............................. 9,316 (1,434) 3,519 Accounts payable.......................................... 23,090 22,277 729 Accrued taxes............................................. (32,787) (49,300) 13,298 Other working capital (excludes cash)..................... 6,645 (4,994) (13,653) ----------- ----------- ----------- Net cash flows provided by operating activities............... 190,294 199,119 217,642 ----------- ----------- ----------- Investing Activities: Investments in plant: Electric utility plant.................................... (69,500) (46,096) (43,780) Nuclear fuel.............................................. (1,153) (1,168) (307) ----------- ----------- ----------- Net cash flows used for investments in plant.............. (70,653) (47,264) (44,087) Investment in nuclear decommissioning trusts................ (686) (678) (641) Other investment activities, net............................ 2,486 2,151 (2,213) ----------- ----------- ----------- Net cash flows used in investing activities................... (68,853) (45,791) (46,941) ----------- ----------- ----------- Financing Activities: Reacquisitions and retirements of long-term debt............ (109,200) - (170,000) Reacquisitions and retirements of preferred stock........... (25,732) (25,000) (25,000) Cash dividends on preferred stock........................... (3,962) (6,625) (9,275) Cash dividends on common stock.............................. (50,000) - - ----------- ----------- ----------- Net cash flows used in financing activities................... (188,894) (31,625) (204,275) ----------- ----------- ----------- Net (decrease)/increase in cash for the period................ (67,453) 121,703 (33,574) Cash and cash equivalents - beginning of period............... 182,588 60,885 94,459 ----------- ----------- ----------- Cash and cash equivalents - end of period..................... $ 115,135 $ 182,588 $ 60,885 =========== =========== =========== Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized........................ $ 38,819 $ 39,895 $ 42,677 =========== =========== =========== Income taxes................................................ $ 22,070 $ 38,511 $ 18,948 =========== =========== =========== (Decrease)/increase in obligations: Seabrook Power Contracts.................................... $ (96,208) $ (115,065) $ (78,939) =========== =========== ===========
The accompanying notes are an integral part of these financial statements. NOTES TO FINANCIAL STATEMENTS - ----------------------------- 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. About Public Service Company of New Hampshire Public Service Company of New Hampshire (PSNH or the company) along with The Connecticut Light and Power Company (CL&P), Western Massachusetts Electric Company (WMECO), North Atlantic Energy Corporation (NAEC), and Holyoke Water Power Company (HWP) are the operating companies comprising the Northeast Utilities system (NU system) and are wholly owned by Northeast Utilities (NU). The NU system serves in excess of 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues. The NU system furnishes franchised retail electric service in New Hampshire, Connecticut, and western Massachusetts through PSNH, CL&P and WMECO. NAEC sells all of its entitlement to the capacity and output of Seabrook Station nuclear unit (Seabrook) to PSNH under the terms of two life-of-unit, full cost recovery contracts (Seabrook Power Contacts). HWP, also is engaged in the production and distribution of electric power. NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act) and the NU system, including PSNH, is subject to provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. PSNH is subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions. Several wholly owned subsidiaries of NU provide support services for the NU system companies including PSNH, and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing, and other services to the NU system companies, including PSNH. Northeast Nuclear Energy Company acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear units. North Atlantic Energy Service Corporation has operational responsibility for Seabrook. B. Presentation The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity and are subject to approval by various federal and state regulatory agencies. C. New Accounting Standards Derivative Instruments: Effective January 1, 2001, PSNH adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS No. 133 requires that derivative instruments be recorded as an asset or liability measured at its fair value and that changes in the fair value of derivative instruments be recognized currently in earnings unless specific hedge accounting criteria be met. In order to implement SFAS No. 133 by January 1, 2001, NU established a cross-functional project team to identify all derivative instruments, measure the fair value of those derivative instruments, designate and document various hedge relationships, and evaluate the effectiveness of those hedge relationships. NU has completed the process of identifying all derivative instruments and has established appropriate fair value measurements of those derivative instruments in place at January 1, 2001. In addition, for those derivative instruments which are hedging an identified risk, NU has designated and documented all hedging relationships anew. Management believes the adoption of this new standard will not have a material impact on PSNH's financial position or results of operations. Revenue Recognition: In December 1999, the SEC issued Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition." The adoption of SAB No. 101, as amended, did not have a material impact on PSNH's financial statements. D. Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: PSNH owns common stock in four regional nuclear companies (Yankee Companies). PSNH's ownership interests in the Yankee Companies at December 31, 2000 and 1999, which are accounted for on the equity method due to PSNH's ability to exercise significant influence over their operating and financial policies are 5 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 7 percent of the Yankee Atomic Electric Company (YAEC), 5 percent of Maine Yankee Atomic Power Company (MYAPC), and 4 percent of Vermont Yankee Nuclear Power Corporation (VYNPC). PSNH's total equity investment in the Yankee Companies at December 31, 2000 and 1999 is $10 million and $12.3 million, respectively. Each Yankee Company owns a single nuclear generating unit. However, VYNPC is the only unit still in operation at December 31, 2000. Millstone: PSNH has a 2.85 percent joint ownership interest in Millstone 3, a 1,154 megawatt (MW) nuclear generating unit. At December 31, 2000 and 1999, plant-in-service included $119.8 million and $119.3 million, respectively, and the accumulated provision for depreciation included $42 million and $39 million, respectively, related to PSNH's share of Millstone 3. Wyman Unit 4: PSNH has a 3.14 percent ownership interest in Wyman Unit 4, a 632 MW oil-fired generating unit. At December 31, 2000 and 1999, plant-in-service included $6.1 million in each year and the accumulated provision for depreciation included $4.3 million and $4.2 million, respectively. E. Depreciation The provision for depreciation is calculated using the straight-line method based on estimated remaining useful lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. The costs of closure and removal of nonnuclear facilities are accrued over the life of the plant as a component of depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.2 percent in 2000, 3.7 percent in 1999 and 3.6 percent in 1998. F. Revenues Revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the New Hampshire Public Utility Commission (NHPUC). Regulatory commissions also have authority over the terms and conditions of nontraditional rate-making arrangements. At the end of each accounting period, PSNH accrues a revenue estimate for the amount of energy delivered but unbilled. G. PSNH Acquisition Costs PSNH acquisition costs represent the aggregate value placed by the 1989 rate agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in excess of the net book value of PSNH's non- Seabrook assets, plus the $700 million value assigned to Seabrook by the Rate Agreement as part of the bankruptcy resolution on June 5, 1992. The Rate Agreement provided for the recovery through rates, with a return, of the PSNH acquisition costs. In connection with the Settlement Agreement approximately $219.4 million was written off and the balance of $76.6 million has been reclassified as a regulatory asset. H. Regulatory Accounting and Assets The accounting policies of PSNH and the accompanying financial statements conform to accounting principles generally accepted in the United States applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of regulation." During the fourth quarter of 2000, the "Agreement to Settle PSNH Restructuring," (Settlement Agreement) became probable of implementation, therefore, PSNH discontinued the application of SFAS No. 71 for the generation portion of its business. PSNH's transmission and distribution business will continue to be cost-based and management believes the application of SFAS No. 71 continues to be appropriate. Management continues to believe it is probable that PSNH will recover their investments in long-lived assets, including regulatory assets through charges to their transmission and distribution customers. PSNH will recover securitized assets over a 12-year period. Nuclear decommissioning and IPP costs will be recovered over the period PSNH is responsible for these costs. The third type of PSNH stranded costs are non- securitized regulatory assets (type three regulatory assets). Any type three regulatory assets not collected by the recovery end date will be written off. Based on current projections, PSNH expects to fully recover all of its type three regulatory assets by the recovery end date stipulated in the Settlement Agreement. In addition, all material regulatory assets are earning a return. The components of PSNH's regulatory assets are as follows: ---------------------------------------------------------------------- At December 31, 2000 1999 ---------------------------------------------------------------------- (Millions of Dollars) Recoverable nuclear costs............... $484.7 $ - Income taxes, net....................... 68.1 166.2 Unrecovered contractual obligations..... 41.5 56.5 Recoverable energy costs, net........... 230.3 120.7 Other................................... 100.2 147.5 ------ ------ $924.8 $490.9 ====== ====== ---------------------------------------------------------------------- As a result of discontinuing the application of SFAS No. 71 in 2000 for PSNH's generation business, PSNH recorded an after-tax charge of $214.2 million in the fourth quarter of 2000. In addition, a regulatory asset was created for the Seabrook over market generation in the amount of $484.7 million, which is classified as recoverable nuclear costs. It is anticipated this regulatory asset will be securitized. I. Income Taxes The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows: ---------------------------------------------------------------------- At December 31, 2000 1999 ---------------------------------------------------------------------- (Millions of Dollars) Accelerated depreciation and other plant-related differences....... $ 93.8 $102.4 Regulatory assets - income tax gross up................... 25.1 62.0 Other................................... 60.8 102.2 ------ ------ $179.7 $266.6 ====== ====== ---------------------------------------------------------------------- PSNH had an Investment Tax Credit (ITC) carryforward of $23 million which expires in 2004. It is anticipated that this carryforward will be fully utilized when filing the 2000 income tax return. J. Recoverable Energy Costs Under the Energy Policy Act of 1992 (Energy Act), PSNH is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. PSNH is currently recovering these costs through rates. As of December 31, 2000 and 1999, PSNH's total D&D deferrals were approximately $.2 million in each year. The Rate Agreement includes a fuel and purchased-power adjustment clause (FPPAC) permitting PSNH to pass through to retail customers, for a 10-year period that began in May 1991, the retail portion of differences between the fuel and purchased-power costs assumed in the Rate Agreement and PSNH's actual costs, which include the costs related to the Seabrook Power Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are subject to a prudence review by the NHPUC. At December 31, 2000 and 1999, PSNH had $230.1 million and $120.5 million, respectively, of recoverable energy costs deferred under the FPPAC. Under the Settlement Agreement, the FPPAC will be recovered as a type three regulatory asset through a transition charge. In addition, under the Rate Agreement, charges made by NAEC through the Seabrook Power Contracts, including the deferred Seabrook capital expenses, are to be collected by PSNH through the FPPAC. Beginning on June 1, 1998, the Seabrook deferred capital expenses began to be recovered over a 36-month period. Included within the restructuring settlement write-off is the write-off of any deferred capital expenses. K. Unrecovered Contractual Obligations Under the terms of contracts with the Yankee companies, the shareholder-sponsor companies, including PSNH, are each responsible for their proportionate share of the remaining costs of the units, including decommissioning. The Settlement Agreement allows for recovery of these costs, therefore, PSNH has recorded a regulatory asset, with a corresponding obligation on its balance sheet. L. Cash and Cash Equivalents Cash and cash equivalents includes cash on hand and short-term cash investments which are highly liquid in nature and have original maturities of three months or less. 2. SEABROOK POWER CONTRACTS PSNH and NAEC have entered into two power contracts that obligate PSNH to purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook for the term of Seabrook's operating license. Under these power contracts, PSNH is obligated to pay NAEC's cost of service during this period, regardless of whether Seabrook is operating. NAEC's cost of service includes all of its Seabrook-related costs, including operation and maintenance (O&M) expenses, fuel expense, income and property tax expense, depreciation expense, certain overhead and other costs, and a return on its allowed investment. With the implementation of the Settlement Agreement, PSNH and NAEC will restructure the power contracts to provide for the buydown of the value of the Seabrook asset to $100 million. The Settlement Agreement also requires NAEC to sell via public auction its share of Seabrook, with the sale to occur no later than December 31, 2003. Upon a successful sale of NAEC's share of Seabrook, the existing Seabrook Power Contracts between PSNH and NAEC will be terminated. PSNH has included its right to buy power from NAEC on its balance sheet as part of utility plant and regulatory assets with a corresponding obligation. At December 31, 2000, this right to buy power was valued at $626.9 million. Under the current Seabrook Power Contracts, if Seabrook is shut down prior to the expiration of its operating license, PSNH will be unconditionally required to pay NAEC termination costs for 39 years, less the period during which Seabrook has operated. These termination costs will reimburse NAEC for its share of Seabrook shut-down and decommissioning costs, and will pay NAEC a return of and on any undepreciated balance of its initial investment over the remaining term of the power contracts, and the return of and on any capital additions to the plant made after the Acquisition Date over a period of five years after shut down (net of any tax benefits to NAEC attributable to the cancellation). Contract payments charged to operating expenses in 2000, 1999 and 1998 were $268 million, $280 million and $272 million, respectively. Interest included in the contract payments in 2000, 1999 and 1998 was $44 million, $49 million and $54 million, respectively. Future minimum payments, excluding executory costs, such as property taxes, state use taxes, insurance and maintenance, under the terms of the contracts, as of December 31, 2000, were approximately: Year Seabrook Power Contracts ---- ------------------------ (Millions of Dollars) 2001........................... $ 116.8 2002........................... 77.5 2003........................... 75.2 2004........................... 72.9 2005........................... 70.5 After 2005..................... 936.2 -------- Future minimum payments........ 1,349.1 Less amount representing interest..................... 722.2 -------- Present value of Seabrook Power Contracts payments..... $ 626.9 ======== -------------------------------------------------------------------------- 3. SHORT-TERM DEBT Limits: The amount of short-term borrowings that may be incurred by NU and the NU system operating companies, including PSNH, is subject to periodic approval by either the SEC under the 1935 Act or by the respective state regulators. PSNH is authorized by the NHPUC to incur short-term borrowings up to a maximum of $71.3 million. Money Pool: Certain subsidiaries of NU, including PSNH, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the NU system and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on loans from NU parent, however, bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 2000 and 1999, PSNH had no outstanding borrowings from the Pool in 2000. Due to the conditions placed on PSNH by the NHPUC during March 2000, PSNH was restricted from lending money to the Pool until the restructuring write-off was recorded. Maturities of short- term debt obligations were for periods of three months or less. 4. LEASES PSNH has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles and office space. The provisions of these lease agreements generally provide for renewal options. Capital lease rental payments charged to operating expense were $1 million in 2000, $1.5 million in 1999 and $1.6 million in 1998. Interest included in capital lease rental payments was $0.3 million in 2000, $0.4 million in 1999 and $0.2 million in 1998. Operating lease rental payments charged to expense were $3.5 million in 2000, $3.1 million in 1999 and $5.4 million in 1998. Future minimum rental payments, excluding executory costs such as property taxes, state use taxes, insurance and maintenance, under long-term noncancelable leases, as of December 31, 2000, are: ------------------------------------------------------------------------- Year Capital Leases Operating Leases ------------------------------------------------------------------------- (Millions of Dollars) 2001................................ $ 1.2 $ 8.3 2002................................ 0.4 5.4 2003................................ 0.4 3.7 2004................................ 0.4 2.9 2005................................ 0.4 2.3 After 2005.......................... 0.7 5.1 ----- ----- Future minimum lease payments....... 3.5 $27.7 ===== Less amount representing interest... 1.2 ----- Present value of future minimum lease payments.................... $ 2.3 ===== ------------------------------------------------------------------------- 5. EMPLOYEE BENEFITS Pension Benefits and Postretirement Benefits Other Than Pensions The NU system's subsidiaries, including PSNH, participate in a uniform noncontributory defined benefit retirement plan covering substantially all regular NU system employees. Benefits are based on years of service and employees' highest eligible compensation during 60 consecutive months of employment. PSNH's portion of the NU system's pension credit, part of which was credited to utility plant, was $4.3 million in 2000, $0.5 million in 1999 and $0.1 million in 1998. Currently, PSNH annually funds an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code. The NU system companies, including PSNH, also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. These benefits are available for employees retiring from PSNH who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. PSNH annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible. Pension and trust assets are invested primarily in domestic and international equity securities and bonds. The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' funded status:
------------------------------------------------------------------------------- At December 31, ------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits ------------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 2000 1999 ------------------------------------------------------------------------------- Change in benefit obligation Benefit obligation at beginning of year......... $ (201.5) $ (201.0) $(51.2) $(50.1) Service cost................... (4.8) (4.9) (0.9) (1.0) Interest cost.................. (15.0) (14.3) (3.9) (3.6) Plan amendment................. - (11.2) - - Transfers...................... 0.1 0.5 - - Actuarial gain/(loss).......... (1.0) 19.1 (1.1) (1.5) Benefits paid.................. 11.1 10.3 4.2 5.0 ------------------------------------------------------------------------------- Benefit obligation at end of year............... $ (211.1) $ (201.5) $(52.9) $(51.2) ------------------------------------------------------------------------------- Change in plan assets Fair value of plan assets at beginning of year......... $ 233.8 $ 213.2 $ 30.6 $ 27.3 Actual return on plan assets... (0.8) 30.4 1.5 3.4 Employer contribution.......... - - 4.5 4.9 Benefits paid.................. (11.1) (10.3) (4.2) (5.0) Transfers...................... (0.1) 0.5 - - ------------------------------------------------------------------------------- Fair value of plan assets at end of year............... $ 221.8 $ 233.8 $ 32.4 $ 30.6 ------------------------------------------------------------------------------- Funded status at December 31... $ 10.7 $ 32.3 $(20.5) $(20.6) Unrecognized transition obligation................... 3.0 3.3 35.3 38.2 Unrecognized prior service cost................. 15.5 16.9 - - Unrecognized net gain.......... (70.4) (98.0) (14.8) (17.6) ------------------------------------------------------------------------------- Deferred benefit cost.......... $ (41.2) $ (45.5) $ - $ - -------------------------------------------------------------------------------
The following actuarial assumptions were used in calculating the plans' year end funded status: ------------------------------------------------------------------------- At December 31, ------------------------------------------------------------------------- Pension Benefits Postretirement Benefits ------------------------------------------------------------------------- 2000 1999 2000 1999 ------------------------------------------------------------------------- Discount rate............. 7.50% 7.75% 7.50% 7.75% Compensation/progression rate.................... 4.50 4.75 4.50 4.75 Health care cost trend rate (a).......... N/A N/A 5.26 5.57 ------------------------------------------------------------------------- (a) The annual per capita cost of covered health care benefits was assumed to decrease to 4.91 percent by 2001. The components of net periodic benefit (credit)/cost are: -------------------------------------------------------------------------- For the Years Ended December 31, -------------------------------------------------------------------------- Postretirement Pension Benefits Benefits -------------------------------------------------------------------------- (Millions of Dollars) 2000 1999 1998 2000 1999 1998 -------------------------------------------------------------------------- Service cost........ $ 4.8 $ 4.9 $ 4.3 $ 0.9 $ 1.0 $ 0.9 Interest cost........ 15.0 14.3 13.2 3.9 3.6 3.4 Expected return on plan assets..... (19.7) (17.7) (15.6) (2.6) (2.1) (1.8) Amortization of unrecognized net transition (asset)/ obligation......... 0.3 0.3 0.3 2.9 2.9 2.9 Amortization of prior service cost....... 1.3 1.3 0.5 - - - Amortization of actuarial gain..... (6.0) (3.6) (2.8) - - - Other amortization, net.. - - - (0.6) (0.5) (0.5) -------------------------------------------------------------------------- Net periodic benefit (credit)/cost....... $(4.3) $(0.5) $(0.1) $ 4.5 $ 4.9 $ 4.9 -------------------------------------------------------------------------- For calculating pension and postretirement benefit costs, the following assumptions were used: -------------------------------------------------------------------------- For the Years Ended December 31, -------------------------------------------------------------------------- Postretirement Pension Benefits Benefits -------------------------------------------------------------------------- 2000 1999 1998 2000 1999 1998 -------------------------------------------------------------------------- Discount rate........ 7.75% 7.00% 7.25% 7.75% 7.00% 7.25% Expected long-term rate of return..... 9.50 9.50 9.50 N/A N/A N/A Compensation/ progression rate.... 4.75 4.25 4.25 4.75 4.25 4.25 Long-term rate of return - Health assets, net of tax....... N/A N/A N/A 7.50 7.50 7.75 Life assets........ N/A N/A N/A 9.50 9.50 9.50 -------------------------------------------------------------------------- Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects: -------------------------------------------------------------------------- One Percentage One Percentage (Millions of Dollars) Point Increase Point Decrease -------------------------------------------------------------------------- Effect on total service and interest cost components ...... $0.2 $(0.2) Effect on postretirement benefit obligation............. $2.9 $(2.6) -------------------------------------------------------------------------- The trust holding the health plan assets is subject to federal income taxes. 6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are: -------------------------------------------------------------------------- Shares Outstanding December 31, Description December 31, 2000 2000 1999 -------------------------------------------------------------------------- (Millions of Dollars) 10.60% Series A of 1991 970,722 $24.3 $50.0 Less preferred stock to be redeemed within one year 970,722 24.3 25.0 ----- ----- $ - $25.0 ===== ===== The Series A preferred stock is not subject to optional redemption by PSNH. It is subject to an annual sinking fund requirement of $25 million each year, which began on June 30, 1997, sufficient to retire annually 1,000,000 shares at $25 per share. In case of default on dividends or sinking fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If PSNH is in arrears in the payment of dividends on any outstanding shares of preferred stock, PSNH would be prohibited from redeeming or purchasing less than all of the outstanding preferred stock. 7. LONG-TERM DEBT Details of long-term debt outstanding are: ------------------------------------------------------------------------- At December 31, 2000 1999 ------------------------------------------------------------------------- (Millions of Dollars) Pollution Control Revenue Bonds: 7.65% Tax-Exempt Series A, due 2021........ $ 66.0 $ 66.0 7.50% Tax-Exempt Series B, due 2021........ 109.0 109.0 7.65% Tax-Exempt Series C, due 2021........ 112.5 112.5 6.00% Tax-Exempt Series D, due 2021........ 75.0 75.0 6.00% Tax-Exempt Series E, due 2021........ 44.8 44.8 Adjustable Rate, Series D, due 2021........ - 39.5 Adjustable Rate, Series E, due 2021........ - 69.7 ------ ------ Long-term debt.............................. $407.3 $516.5 ====== ====== ------------------------------------------------------------------------- There are no cash sinking fund requirements or debt maturities for the years 2001 through 2005. There are annual renewal and replacement fund requirements equal to 2.25 percent of the average of net depreciable utility property owned by PSNH at the reorganization date, plus cumulative gross property additions thereafter. PSNH expects to meet these future fund requirements by certifying property additions. Any deficiency would need to be satisfied by the deposit of cash or bonds. Concurrent with the issuance of PSNH's Series A and B first mortgage bonds, PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the State of New Hampshire. Pursuant to these arrangements, the BFA issued five series of Pollution Control Revenue Bonds (PCRBs) and loaned the proceeds to PSNH. PSNH's obligation to repay each series of PCRBs is secured by the first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. For financial reporting purposes, these bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs. The average effective interest rates on the variable-rate pollution control notes ranged from 5.9 percent to 6.8 percent in 2000 and from 4.9 percent to 6.1 percent in 1999. 8. INCOME TAX EXPENSE The components of the federal and state income tax provisions were charged/(credited) to operations as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Current income taxes: Federal.................................... $ 41.8 $ 41.4 $ (6.6) State...................................... 3.7 4.6 0.8 ------ ------ ------ Total current............................ 45.5 46.0 (5.8) ------ ------ ------ Deferred income taxes, net: Federal.................................... 6.7 4.6 78.0 State...................................... 0.8 (2.2) 0.9 ------ ------ ------ Total deferred........................... 7.5 2.4 78.9 ------ ------ ------ Investment tax credits, net.................. (8.0) (7.7) (0.5) ------ ------ ------ Total income tax expense..................... $ 45.0 $ 40.7 $ 72.6 ====== ====== ====== -------------------------------------------------------------------------- The components of total income tax expense/(credit) are classified as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Income taxes charged to operating expenses... $ 45.1 $ 36.8 $ 65.1 Other income taxes........................... (0.1) 3.9 7.5 ------ ------ ------ Total income tax expense..................... $ 45.0 $ 40.7 $ 72.6 ====== ====== ====== -------------------------------------------------------------------------- Deferred income taxes are comprised of the tax effects of temporary differences as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Depreciation................................. $(1.0) $ (6.5) $(12.1) Regulatory deferral.......................... 6.9 (12.6) 22.6 State net operating loss carryforward........ - 29.5 69.2 Regulatory disallowance...................... - (2.3) - Contractual settlements...................... - (6.7) - Other........................................ 1.6 1.0 (0.8) ----- ------ ------ Deferred income taxes, net................... $ 7.5 $ 2.4 78.9 ===== ====== ====== -------------------------------------------------------------------------- A reconciliation between income tax expense and the expected tax expense at 35 percent of pretax income/(loss) is as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Expected federal income tax $39.4 $43.7 $57.5 Tax effect of differences: Depreciation............................... 0.3 0.9 (2.2) Amortization of regulatory assets.......... 9.9 9.9 17.3 Investment tax credit amortization......... (8.0) (7.7) (0.5) State income taxes, net of federal benefit.......................... 2.9 1.6 1.0 Adjustment to tax asset valuation allowance...................... - (7.4) - Seabrook intercompany gains and losses..... 5.0 0.8 0.6 Allocation of parent company loss.......... (4.2) - - Other, net................................. (0.3) (1.1) (1.1) ----- ----- ----- Total income tax expense..................... $45.0 $40.7 $72.6 ===== ===== ===== -------------------------------------------------------------------------- 9. COMMITMENTS AND CONTINGENCIES A. Restructuring In September 2000, the New Hampshire Public Utilities Commission (NHPUC) approved a comprehensive restructuring order that would allow PSNH to securitize up to $670 million of stranded costs. In January 2001, the New Hampshire Supreme Court upheld this restructuring order on appeal. However, one of the appellants indicated publicly it would request a review of the New Hampshire Supreme Court decision by the United States Supreme Court. Such a request must be filed by May 1, 2001. Management believes that such an appeal would have a low probability of success, but cannot determine what effect it might have on the timing of the issuance of securitization bonds and the implementation of customer choice in New Hampshire. PSNH currently expects to work with the State of New Hampshire to issue securitization bonds early in the second quarter of 2001. B. Nuclear Generation Assets Divestiture On August 7, 2000, PSNH, CL&P, and WMECO and certain other joint owners, including PSNH, reached an agreement to sell substantially all of the Millstone units, located in Waterford, Connecticut, to Dominion Resources, Inc. (Dominion), for approximately $1.3 billion, including approximately $105 million for nuclear fuel. NU expects to close on the sale of Millstone as early as the end of March 2001. If the transaction is consummated as proposed, PSNH will receive $26 million on a pretax basis, which will be reflected as a gain in accordance with the Settlement Agreement. By the end of 2002, PSNH expects to complete the sale of its fossil and hydroelectric generation assets, as well as NAEC's ownership share of Seabrook. C. Environmental Matters The NU system, including PSNH, is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of our environment. As such, the NU system and PSNH have active environmental auditing and training programs and believe they are substantially in compliance with the current laws and regulations. However, the normal course of operations may necessarily involve activities and substances that expose PSNH to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on PSNH's financial statements. Based upon currently available information for the estimated remediation costs as of December 31, 2000 and 1999, the liability recorded by PSNH for its estimated environmental remediation costs amounted to $9.7 million and $9.5 million, respectively. D. Spent Nuclear Fuel Disposal Costs Under the Nuclear Waste Policy Act of 1982, PSNH must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high- level radioactive waste. Fees for nuclear fuel burned are billed currently to customers and paid to the DOE on a quarterly basis. E. Nuclear Insurance Contingencies Insurance policies covering PSNH's ownership share of the NU system's nuclear facilities have been purchased for the primary cost of repair, replacement or decontamination of utility property, certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement or decontamination or premature decommissioning of utility property. PSNH is subject to retroactive assessments if losses under those policies exceed the accumulated funds available to the insurer. The maximum potential assessments, including costs resulting from PSNH's contracts with NAEC, with respect to losses arising during the current policy year for the primary property insurance program, the replacement power policies and the excess property damage policies are $2.1 million, $0.8 million and $2.7 million, respectively. In addition, insurance has been purchased in the aggregate amount of $200 million on an industry basis by the NU system for coverage of worker claims. Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third- party liability indemnification program, the NU system, including PSNH, could be assessed liabilities in proportion to its ownership interest in each of its nuclear units up to $83.9 million. The NU system's payment of this assessment would be limited to, in proportion to its ownership interest in each of its nuclear units, $10 million in any one year per nuclear unit. In addition, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection, the NU system would be subject to an additional 5 percent or $4.2 million liability, in proportion to its ownership interests in each of its nuclear units. Under the terms of the Seabrook Power Contracts, PSNH could be obligated to pay for any assessment charged to NAEC as a cost of service. Based upon its ownership interest in Millstone 3 and NAEC's ownership interest in Seabrook, PSNH's maximum liability, including any additional assessments, would be $33.8 million per incident, of which payments would be limited to $3.9 million per year. In addition, through purchased-power contracts with VYNPC, PSNH would be responsible for up to an additional assessment of $3.5 million per incident, of which payments would be limited to $0.3 million per year. F. Long-Term Contractual Arrangements Yankee Companies: Under the terms of its agreement, PSNH paid its ownership (or entitlement) shares of costs, which included depreciation, operation and maintenance (O&M) expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs were recorded as purchased-power expenses and recovered through PSNH's rates. PSNH's cost of purchases under contracts with VYNPC amounted to $6.4 million in 2000, $7.5 million in 1999 and $7 million in 1998. VYNPC is in the process of selling its nuclear unit. Upon completion of the sale, this long-term contract will be terminated. Nonutility Generators (NUGs): PSNH has entered into various arrangements for the purchase of capacity and energy from NUGs. PSNH's total cost of purchases under these arrangements amounted to $144.9 million in 2000, $139.8 million in 1999 and $139.1 million in 1998. The company is attempting to renegotiate the terms of the largest of these contracts through either a contract buydown or buyout. The company expects any payments to the NUGs as a result of these successful renegotiations to be recovered from the company's customers. Hydro-Quebec: Along with other New England utilities, PSNH has entered into an agreement to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. PSNH is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M expenses and capital costs of those facilities. Estimated Annual Costs: The estimated annual costs of PSNH's significant long-term contractual arrangements, absent the effects of any contract terminations, buydowns or buyouts are as follows: --------------------------------------------------------------------- 2001 2002 2003 2004 2005 --------------------------------------------------------------------- (Millions of Dollars) VYNPC............. $ 7.1 $ 7.1 $ 7.1 $ 7.9 $ 7.4 NUGs.............. 150.0 154.6 159.4 163.7 166.4 Hydro-Quebec...... 8.7 8.4 8.1 7.8 7.5 --------------------------------------------------------------------- G. Deferred Receivable from Affiliated Company At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance with the phase-in under the Rate Agreement, it began to accrue a deferred return on a portion of its Seabrook investment. From May 16, 1991, to the Acquisition Date, PSNH accrued a deferred return of $50.9 million. On the Acquisition Date, PSNH sold the $50.9 million deferred return to NAEC as part of the Seabrook- related assets. At the time PSNH transferred the deferred return to NAEC, it realized, for income tax purposes, a gain that was deferred under the consolidated income tax rules. Beginning December 1, 1997, the gain is being amortized into income for income tax purposes, as the deferred return of $50.9 million, and the associated income taxes of $32.9 million, are being collected by NAEC through the Seabrook Power Contracts. As NAEC recovers the $32.9 million in years eight through ten of the Rate Agreement, corresponding payments are being made to PSNH. The balance of the deferred receivable from NAEC at December 31, 2000 and 1999, was $3.2 million and $13 million, respectively. 10. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS Millstone and Seabrook: PSNH is obligated to pay NAEC's share of Seabrook's decommissioning costs, even if the unit is shut down prior to the expiration of its operating license. Accordingly, NAEC bills PSNH directly for its share of the costs of decommissioning Seabrook. PSNH records its Seabrook decommissioning costs as a component of purchased- power expense. These costs are recovered through base rates. The Seabrook decommissioning costs will continue to be increased annually by its respective escalation rates until the unit is sold. Under New Hampshire law, Seabrook's decommissioning funding requirements are set by the New Hampshire Nuclear Decommissioning Financing Committee (NDFC). During April 1999, the NDFC issued an order that adjusted the decommissioning collection period and funding levels assuming that Seabrook's anticipated energy producing life was 25 years from the date it went into commercial operation. Decommissioning collections are now expected to be completed by October 2015, as opposed to 2026, for the decommissioning collection period only. The cost of funding decommissioning Seabrook is now accrued over the estimated remaining accelerated funding period that was ordered by the NDFC. This is eleven years earlier than the service life established by Seabrook's Nuclear Regulatory Commission's (NRC) operating license. Millstone 3 and Seabrook's service lives are expected to end during the years 2025 through 2026, and upon retirement, must be decommissioned. In connection with the sale of the Millstone nuclear units, Dominion has agreed to assume responsibility for decommissioning. Until the divestiture, PSNH recovers sufficient amounts through their allowed rates related to decommissioning costs. PSNH's ownership share of the estimated cost of decommissioning Millstone 3 and NAEC's ownership share of Seabrook, in year end 2000 dollars, is $18.4 million and $210.8 million, respectively. Nuclear decommissioning costs are accrued over the expected service lives of Millstone 3 and are included in depreciation expense and the accumulated provision for depreciation. Nuclear decommissioning expenses for PSNH's ownership share of Millstone 3 amounted to $.5 million in 2000 and 1999 and $0.4 million in 1998. Through December 31, 2000 and 1999, total decommissioning expenses of $4 million and $3.5 million, respectively, have been collected from customers and are reflected in the accumulated provision for depreciation. External decommissioning trusts have been established for the costs of decommissioning the Millstone units. PSNH payments for NAEC's ownership share of the cost of decommissioning Seabrook are paid by NAEC to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assumes after-tax earnings on the Millstone and Seabrook decommissioning funds of 5.5 percent and 6.5 percent, respectively. As of December 31, 2000 and 1999, NAEC has paid approximately $39.6 million and $32.7 million, respectively, (including payments made prior to the Acquisition Date by PSNH) into Seabrook's decommissioning fund. Earnings on the decommissioning trusts increase the decommissioning trust balances and the accumulated provisions for depreciation. Unrealized gains and losses associated with the decommissioning trusts also impact the balance of the trusts and the accumulated provisions for depreciation. The fair values of the amounts in the external decommissioning trusts for Millstone 3 were $7.4 million and $6.9 million at December 31, 2000 and 1999, respectively. Upon divestiture of Millstone 3, balances in the decommissioning trusts for Millstone 3 will be transferred to the buyer. NU is obligated to top off the decommissioning trust if its value does not equal an agreed upon amount at closing, pursuant to the conditions set forth in the purchase and sale agreement. Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. PSNH's ownership share of estimated costs, in year end 2000 dollars, of decommissioning this unit is $18.1 million. In 1999, VYNPC agreed to sell its nuclear generating unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the obligation to decommission the unit after it is taken out of service, and the owners of VYNPC (including PSNH) agreed to fund their shares of the decommissioning costs up to a negotiated amount. Subsequent to the time that agreement was executed, the original proposed acquiring company has increased the price it agreed to pay and three other unaffiliated companies have indicated their interest in buying VYNPC's generating unit on terms that have not been disclosed. At present, PSNH expects that the unit will be sold, but the identity of the owner and the terms of sale, including price, future decommissioning obligations and future power purchase obligations, are not known. As of December 31, 2000 and 1999, PSNH's remaining estimated obligation, including decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down was $41.5 million and $56.5 million, respectively. 11. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and cash equivalents: The carrying amounts approximate fair value due to the short-term nature of cash and cash equivalents. Nuclear decommissioning trusts: PSNH's portion of the investments held in the NU system companies' nuclear decommissioning trusts were marked- to-market by $2 million as of December 31, 2000, and $2.2 million as of December 31, 1999, with corresponding offsets to the accumulated provision for depreciation. The amounts adjusted in 2000 and 1999 represent cumulative net unrealized gains. Cumulative gross unrealized holding losses were immaterial for both 2000 and 1999. Preferred stock and long-term debt: The fair value of PSNH's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of PSNH's financial instruments and the estimated fair values are as follows: -------------------------------------------------------------------------- At December 31, 2000 -------------------------------------------------------------------------- Carrying Fair (Millions of Dollars) Amount Value -------------------------------------------------------------------------- Preferred stock subject to mandatory redemption............... $ 24.3 $ 25.5 Other long-term debt.................... 407.3 401.9 -------------------------------------------------------------------------- -------------------------------------------------------------------------- At December 31, 1999 -------------------------------------------------------------------------- Carrying Fair (Millions of Dollars) Amount Value -------------------------------------------------------------------------- Preferred stock subject to mandatory redemption............... $ 50.0 $ 52.0 Other long-term debt.................... 516.5 517.4 -------------------------------------------------------------------------- 12. OTHER COMPREHENSIVE INCOME The accumulated balance for each other comprehensive income item is as follows: -------------------------------------------------------------------------- Current December 31, Period December 31, 1999 Change 2000 -------------------------------------------------------------------------- (Thousands of Dollars) -------------------------------------------------------------------------- Unrealized gains on securities................ $1,268 $133 $1,401 Minimum pension liability adjustments........... (194) - (194) -------------------------------------------------------------------------- Accumulated other comprehensive income............ $1,074 $133 $1,207 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Current December 31, Period December 31, 1998 Change 1999 -------------------------------------------------------------------------- (Thousands of Dollars) -------------------------------------------------------------------------- Unrealized gains on securities................... $1,198 $ 70 $1,268 Minimum pension liability adjustments........... (194) - (194) -------------------------------------------------------------------------- Accumulated other comprehensive income............ $1,004 $ 70 $1,074 -------------------------------------------------------------------------- The changes in the components of other comprehensive income are reported net of the following income tax effects: -------------------------------------------------------------------------- 2000 1999 1998 -------------------------------------------------------------------------- (Thousands of Dollars) -------------------------------------------------------------------------- Unrealized gains on securities......... $(74) $(39) $(660) Minimum pension liability adjustments................ - - 107 -------------------------------------------------------------------------- Other comprehensive income............. $(74) $(39) $(553) -------------------------------------------------------------------------- 13. SEGMENT INFORMATION Effective January 1, 1999, the NU system companies, including PSNH, adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." The NU system is organized between regulated utilities and competitive energy subsidiaries. PSNH is included in the regulated utilities segment of the NU system and has no other reportable segments. 14. SUBSEQUENT EVENT Merger Agreement With Consolidated Edison, Inc.: In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the approvals needed to complete the merger announced in October 1999. Shareholders from both companies approved the merger in April 2000, and all state regulatory approvals were granted by the end of the year. Additionally, the FERC approved the merger in May 2000, the NRC approved the transaction in August 2000, and the United States Department of Justice approved the merger in February 2001. Necessary approval from the SEC was expected to be received in mid-March 2001. On February 28, 2001, NU's Board of Trustees requested that Con Edison provide reasonable assurance, in writing, that it intended to comply with the terms of the definitive merger agreement between the two companies. This included assurances that Con Edison would consummate the pending merger at the price set forth in the agreement promptly following the receipt of SEC approval. The original request for assurance was to be received by March 2, 2001, however that date was later extended to March 5, 2001. On March 5, 2001, Con Edison advised NU that it was not willing to close the merger on the agreed terms. NU notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that NU would file suit to obtain the benefits of the transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District of New York (Southern District), seeking a declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement. On March 12, 2001, NU filed suit against Con Edison in the Southern District seeking damages in excess of $1 billion arising from Con Edison's breach of the merger agreement. Public Service Company of New Hampshire
- ---------------------------------------------------------------------------------------------------------- SELECTED FINANCIAL DATA 2000 1999 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.................. $1,291,280 $1,160,572 $1,087,247 $1,108,459 $1,110,169 Operating Income.................... 89,930 124,605 131,199 144,024 155,758 Net Income.......................... (146,666) 84,209 91,686 92,172 97,465 Cash Dividends on Common Stock...... 50,000 - - 85,000 52,000 Total Assets........................ 2,082,194 2,622,433 2,681,595 2,837,159 2,851,212 Long-Term Debt (a).................. 407,285 516,485 516,485 686,485 686,485 Preferred Stock Subject to Mandatory Redemption (a)....... 24,268 50,000 75,000 100,000 125,000 Obligations Under Seabrook Power Contracts and Other Capital Leases (a)........................ 629,230 726,153 842,223 921,813 914,617 - ----------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------ QUARTERLY FINANCIAL DATA (Unaudited) - ------------------------------------------------------------------------------------------------ Quarter Ended - ------------------------------------------------------------------------------------------------ 2000 March 31 June 30 September 30 December 31 - ------------------------------------------------------------------------------------------------ (Thousands of Dollars) - ------------------------------------------------------------------------------------------------ Operating Revenues $328,694 $326,458 $337,865 $ 298,263 ======== ======== ======== ========= Operating Income $ 25,242 $ 24,434 $ 28,180 $ 12,074 ======== ======== ======== ========= Net Income $ 17,431 $ 14,252 $ 28,733 $(207,082) ======== ======== ======== ========= - ------------------------------------------------------------------------------------------------ 1999 - ------------------------------------------------------------------------------------------------ Operating Revenues $286,799 $286,824 $310,739 $ 276,210 ======== ======== ======== ========= Operating Income $ 35,449 $ 29,419 $ 34,666 $ 25,071 ======== ======== ======== ========= Net Income $ 25,281 $ 20,695 $ 25,584 $ 12,649 ======== ======== ======== =========
(a) Includes portion due within one year. Public Service Company of New Hampshire - ------------------------------------------------------------------------------- STATISTICS (Unaudited) - ------------------------------------------------------------------------------- Average Gross Electric Annual Utility Plant Use Per December 31, kWh Residential Electric (Thousands of Sales Customer Customers Employees Dollars) (a) (Millions) (kWh) (Average) December 31, - ------------------------------------------------------------------------------- 2000 $1,535,142 17,143 6,644 433,937 1,227 1999 2,283,187 12,832 6,665 427,694 1,258 1998 2,302,254 12,579 6,347 421,602 1,265 1997 2,312,628 13,340 6,528 407,642 1,254 1996 2,382,009 13,601 6,567 407,082 1,279 (a) Includes unamortized acquisition costs. EX-13.4 18 0018.txt ANNUAL REPORT OF NAEC 2000 Annual Report North Atlantic Energy Corporation Index Contents Page - -------- ---- Management's Discussion and Analysis of Financial Condition and Results of Operations............................. 1 Report of Independent Public Accountants.......................... 8 Statements of Income.............................................. 9 Balance Sheets.................................................... 10-11 Statements of Common Stockholder's Equity......................... 12 Statements of Cash Flows.......................................... 13 Notes to Financial Statements..................................... 14-26 Selected Financial Data........................................... 27 Quarterly Financial Data (Unaudited).............................. 27 Statistics (Unaudited)............................................ 27 Preferred Stockholder and Bondholder Information.................. Back Cover North Atlantic Energy Corporation - ------------------------------------------------------------------------------- Management's Discussion and Analysis of Financial Condition and Results of Operations - ------------------------------------------------------------------------------- Financial Condition - ------------------- Overview North Atlantic Energy Corporation, (NAEC or the company), is a wholly owned operating subsidiary of Northeast Utilities (NU) and is part of the Northeast Utilities system (NU system). Public Service Company of New Hampshire (PSNH), is another wholly owned subsidiary of NU. PSNH is obligated to purchase the capacity and output from NAEC's 35.98 percent joint ownership interest in the Seabrook Station nuclear unit (Seabrook) under the terms of two life-of-unit, full cost recovery contracts (Seabrook Power Contracts). The company's only assets are Seabrook and other Seabrook-related assets and its only source of revenues are the Seabrook Power Contracts. PSNH's obligations under the Seabrook Power Contracts are solely its own and have not been guaranteed by NU. The Seabrook Power Contracts contain no provisions entitling PSNH to terminate its obligations. If, however, PSNH were to fail to perform its obligations under the Seabrook Power Contracts, the company would be required to find other purchasers for Seabrook's power. With the implementation of the "Agreement to Settle PSNH Restructuring" (Settlement Agreement), PSNH and NAEC will restructure the power contracts to provide for the buydown of the value of the Seabrook asset to $100 million. NAEC will use a portion of these cash proceeds to retire its existing long-term debt obligation. NAEC will also return to NU parent another portion of these cash proceeds in the form of a dividend. The Settlement Agreement also requires NAEC to sell via public auction its share of Seabrook, with the sale to occur no later than December 31, 2003. Upon a successful sale of NAEC's share of Seabrook, the existing Seabrook Power Contracts between PSNH and NAEC will be terminated. However, PSNH will continue to be responsible for funding NAEC's ownership share of Seabrook's decommissioning liability. In 2000, NAEC's revenues decreased to $274.3 million, down 4.5 percent from revenues of $287.4 million in 1999. Revenues were $276.7 million in 1998. In 2000, NAEC had net income of $32.5 million, compared to $29.6 million in 1999 and $29.5 million in 1998. Consolidated Edison, Inc. Merger - -------------------------------- In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the approvals needed to complete the merger announced in October 1999. Shareholders from both companies approved the merger in April 2000, and all state regulatory approvals were granted by the end of the year. Additionally, the Federal Energy Regulatory Commission (FERC) approved the merger in May 2000, the Nuclear Regulatory Commission approved the transaction in August 2000, and the United States Department of Justice approved the merger in February 2001. Necessary approval from the Securities and Exchange Commission (SEC) was expected to be received in mid-March 2001. On February 28, 2001, NU's Board of Trustees requested that Con Edison provide reasonable assurance, in writing, that it intended to comply with the terms of the definitive merger agreement between the two companies. This included assurances that Con Edison would consummate the pending merger at the price set forth in the agreement promptly following the receipt of SEC approval. The original request for assurance was to be received by March 2, 2001, however that date was later extended to March 5, 2001. On March 5, 2001, Con Edison advised NU that it was not willing to close the merger on the agreed terms. NU notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that NU would file suit to obtain the benefits of the transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District of New York (Southern District), seeking a declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement. On March 12, 2001, NU filed suit against Con Edison in the Southern District seeking damages in excess of $1 billion arising from Con Edison's breach of the merger agreement. NU cannot predict the outcome of this matter nor its effect on NU. Liquidity - --------- During 2000, net cash flows provided by operations were $117.6 million, compared to $181.4 million in 1999 and $128.7 million in 1998. The decrease in 2000 was primarily due to an increase in receivables and an increase in deferred income tax benefit due to lower tax depreciation. Net cash flows used in financing activities were $112 million in 2000, compared to $130 million in 1999 and $75 million in 1998. This included $270 million to retire long-term debt, compared to $70 million and $20 million in 1999 and 1998, respectively. Cash dividends on common shares paid in 2000 were $42 million, compared to $60 million in 1999 and $45 million in 1998. Including investments made in the NU System Money Pool, construction expenditures and investments in nuclear decommissioning trusts, net cash flows used in investing activities were $5.5 million in 2000, compared to $51.5 million in 1999 and $53.7 million in 1998. NAEC currently forecasts construction expenditures of $6.6 million for the year 2001. In 2000, NAEC renewed its $200 million term credit agreement for 364 days. In April 2000, Moody's Investors Service (Moody's) upgraded its credit ratings for NAEC, and in October 2000, Fitch IBCA (Fitch) upgraded its credit ratings for NAEC. In January 2001, Moody's and Standard and Poor's upgraded their credit ratings for NAEC, primarily as a result of the New Hampshire Supreme Court's decision to uphold that state's restructuring plan and NU's general financial recovery. By the end of 2002, PSNH expects to complete the auction of approximately 1,200 MW of fossil and hydroelectric generation assets, as well NAEC's share of Seabrook. PSNH's restructuring settlement was predicated upon receiving approximately $400 million of net proceeds from those sales. Cash proceeds will be used to retire debt and to return equity capital to the parent company. In September 2000, the New Hampshire Public Utilities Commission (NHPUC) approved a comprehensive restructuring settlement that allows PSNH to securitize up to $670 million of stranded costs. In January 2001, the New Hampshire Supreme Court upheld this restructuring order on appeal. However, one of the appellants indicated publicly it would request a review of the New Hampshire Supreme Court decision by the United States Supreme Court. Such a request must be filed by May 1, 2001. Management believes that such an appeal would have a low probability of success, but cannot determine what effect it might have on the timing of the issuance of securitization bonds and the implementation of customer choice in New Hampshire. PSNH currently expects to work with the State of New Hampshire to issue securitization bonds early in the second quarter of 2001. Cash proceeds would be combined with cash on hand and used primarily to buydown the power contract between PSNH and NAEC, retire debt at the two companies of approximately $300 million and return equity capital to the parent company from PSNH and NAEC of another $375 million. Restructuring - ------------- On September 8, 2000, the NHPUC issued two orders. The first order approved an Amended Settlement Agreement. The Amended Settlement Agreement, as approved by the NHPUC, will resolve 11 NHPUC dockets and PSNH's federal lawsuit which had enjoined the state of New Hampshire from implementing its restructuring legislation, will require PSNH to write off in excess of $200 million after-tax of its stranded costs and allow for the recovery of the remaining amount. The second order issued by the NHPUC was an order addressing financing issues, primarily securitization. The order, among other things, authorizes PSNH to issue up to $670 million of rate reduction bonds (RRB), permits PSNH to establish a RRB charge, and establishes the terms of the RRB charge, including the requirement that it be non-bypassable. The New Hampshire legislature had previously passed legislation, that permitted PSNH to issue up to $670 million in RRBs to securitize certain regulatory assets. The Settlement Agreement also requires NAEC to sell its share of the Seabrook power plant, including Seabrook 2. NAEC will use the proceeds of such a sale to pay off any outstanding obligations. Net proceeds in excess of book value will be transferred to PSNH and applied against PSNH's stranded costs. The sales would be accomplished through an auction process subject to NHPUC administration. Nuclear Plant Performance and Divestiture - ----------------------------------------- Seabrook Seabrook operated at a capacity factor of 78 percent in 2000. The unit began a scheduled refueling outage on October 21, 2000. The outage was extended by approximately two months as a result of the need to repair extensive problems with a back-up diesel generator. Seabrook returned to service on January 29, 2001. On December 15, 2000, NU filed its divestiture plan for Seabrook with the NHPUC and the Connecticut Department of Public Utility Control. NU hopes to complete the sale in 2002. Nuclear Decommissioning For further information regarding nuclear decommissioning, see Note 2, "Nuclear Decommissioning and Plant Closure Costs," to the financial statements. Spent Nuclear Fuel Disposal Costs The United States Department of Energy (DOE) originally was scheduled to begin accepting delivery of spent nuclear fuel in 1998. However, delays in confirming the suitability of a permanent storage site continually have postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. NU has the primary responsibility for the interim storage of its spent nuclear fuel prior to divestiture of its nuclear units. For further information regarding spent nuclear fuel disposal costs, see Note 7C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the financial statements. Other Matters - ------------- Environmental Matters NAEC is subject to environmental laws and regulations structured to mitigate or remove the effect of past operations and to improve or maintain the quality of the environment. For further information regarding environmental matters, see Note 7B, "Commitments and Contingencies - Environmental Matters," to the financial statements. Other Commitments and Contingencies For further information regarding these other commitments and contingencies, see Note 7, "Commitments and Contingencies," to the financial statements. Forward Looking Statements This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancing, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in historical weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, and other presently unknown or unforeseen factors. RESULTS OF OPERATIONS The components of significant income statement variances for the past two years are provided in the table below. Income Statement Variances (Millions of Dollars) 2000 over/(under) 1999 1999 over/(under) 1998 ----------------------------------------------- Amount Percent Amount Percent ------ ------- ------ ------- Operating Revenues $(13) (5)% $ 11 4% Operating Expenses: Fuel, purchased and interchange power, net (3) (17) 2 17 Other operation and maintenance expense - - 10 19 Depreciation - - 2 9 Amortization of regulatory assets - - - - Federal and state income taxes 1 2 (1) (4) Taxes other than income taxes (6) (42) 2 17 ---- --- ---- --- Total operating expenses (7) (3) 15 7 ---- --- ---- --- Operating Income (6) (11) (4) (8) ---- --- ---- --- Other Income: Deferred Seabrook return - other funds (2) (52) (2) (34) Other, net 1 12 1 12 Other income tax 4 19 5 33 ---- --- ---- --- Net other income 2 14 3 27 Interest charges (6) (17) (1) (3) ---- --- ---- --- Net Income/(Loss) $ 3 10 $ - - ==== === ==== === Operating Revenues Total operating revenues decreased by $13 million or 5 percent for 2000, as compared to 1999, primarily due to lower operating costs billed to PSNH through the Seabrook Power Contracts. Operating revenues increased in 1999, primarily due to the higher operating expenses related to the Seabrook refueling and maintenance outage in 1999. Fuel, Purchased and Interchange Power, Net Fuel expense decreased in 2000, as compared to 1999, primarily due to the extended nuclear refueling outage in 2000. Fuel expense increased in 1999, primarily due to a higher fuel amortization rate since the Seabrook refueling outage. Other Operation and Maintenance Expense Other operation and maintenance (O&M) expenses were relatively unchanged in 2000, as compared to 1999. Other O&M expenses increased in 1999, primarily due to higher costs relating to the Seabrook refueling outage. Depreciation Depreciation expense was unchanged in 2000. Depreciation increased in 1999 due to shorter useful lives for 1999 plant asset additions. Federal and State Income Taxes Federal and state income taxes decreased during 2000, due to lower book taxable income. Federal and state income taxes decreased during 1999, due to lower book taxable income. Taxes Other Than Income Taxes Taxes other than income taxes decreased in 2000, primarily due to the tax true-up in the third quarter of 1999 as a result of a change to the statewide utility property tax. Taxes other than income taxes increased in 1999, as the result of the New Hampshire change to a statewide utility property tax in place of the nuclear station tax. Deferred Seabrook Return - Other Funds The deferred Seabrook return income decreased in 2000, as compared to 1999, as NAEC continues to recover the Seabrook deferred return, reducing the outstanding balance. The deferred Seabrook return income decreased in 1999, as compared to 1998, as NAEC continues to recover the Seabrook deferred return, reducing the outstanding balance. Other, Net Other income, net increased in 2000, primarily due to higher interest income on investments in the NU System Money Pool. Other income, net increased in 1999, primarily due to higher interest income on investments in the NU System Money Pool. Interest Charges Interest charges decreased in 2000, primarily due to lower long-term debt outstanding. Interest charges decreased in 1999, primarily due to lower long-term debt outstanding. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of North Atlantic Energy Corporation: We have audited the accompanying balance sheets of North Atlantic Energy Corporation (a New Hampshire corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31, 2000 and 1999, and the related statements of income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2000. 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 in accordance with auditing standards generally accepted in the United States. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of North Atlantic Energy Corporation as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut January 23, 2001 (except with respect to the matter discussed in Note 11, as to which the date is March 13, 2001) NORTH ATLANTIC ENERGY CORPORATION STATEMENTS OF INCOME
- ------------------------------------------------------------------------------------- FOR THE YEAR ENDED DECEMBER 31, 2000 1999 1998 - ------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues................................. $ 274,319 $ 287,369 $ 276,685 ---------- ---------- ---------- Operating Expenses: Operation - Fuel.......................................... 12,923 15,596 13,305 Other......................................... 40,650 41,727 36,763 Maintenance...................................... 20,268 19,030 14,120 Depreciation..................................... 27,823 27,576 25,381 Amortization of regulatory assets, net........... 85,176 85,488 85,464 Federal and state income taxes................... 35,675 34,854 36,194 Taxes other than income taxes.................... 7,727 13,370 11,401 ---------- ---------- ---------- Total operating expenses................... 230,242 237,641 222,628 ---------- ---------- ---------- Operating Income................................... 44,077 49,728 54,057 ---------- ---------- ---------- Other Income/(Loss): Deferred Seabrook return - other funds........... 2,112 4,417 6,731 Other, net....................................... (6,544) (7,432) (8,435) Income taxes..................................... 22,792 19,131 14,378 ---------- ---------- ---------- Other income, net.......................... 18,360 16,116 12,674 ---------- ---------- ---------- Income before interest charges............. 62,437 65,844 66,731 ---------- ---------- ---------- Interest Charges: Interest on long-term debt....................... 32,247 45,297 50,082 Other interest................................... 1,423 (542) (676) Deferred Seabrook return - borrowed funds........ (3,726) (8,467) (12,169) ---------- ---------- ---------- Interest charges, net...................... 29,944 36,288 37,237 ---------- ---------- ---------- Net Income......................................... $ 32,493 $ 29,556 $ 29,494 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION BALANCE SHEETS
- ----------------------------------------------------------------------------------------- AT DECEMBER 31, 2000 1999 - ----------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS - ------ Utility Plant, at original cost: Electric................................................ $ 719,353 $ 736,472 Less: Accumulated provision for depreciation......... 223,465 196,694 ------------- ------------- 495,888 539,778 Construction work in progress........................... 8,710 10,274 Nuclear fuel, net....................................... 28,369 21,149 ------------- ------------- Total net utility plant.............................. 532,967 571,201 ------------- ------------- Other Property and Investments: Nuclear decommissioning trusts, at market............... 50,863 43,667 ------------- ------------- 50,863 43,667 ------------- ------------- Current Assets: Cash.................................................... 118 - Notes receivable from affiliated companies.............. 27,800 56,400 Accounts receivable from affiliated companies........... 50,796 22,840 Taxes receivable........................................ 722 11,717 Materials and supplies, at average cost................. 14,003 13,088 Prepayments and other................................... 2,000 1,773 ------------- ------------- 95,439 105,818 ------------- ------------- Deferred Charges: Regulatory assets....................................... 48,068 129,641 Unamortized debt expense................................ 847 1,780 Prepaid property tax.................................... 630 - Other................................................... 150 - ------------- ------------- 49,695 131,421 ------------- ------------- Total Assets.............................................. $ 728,964 $ 852,107 ============= =============
The accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION BALANCE SHEETS
- ----------------------------------------------------------------------------------------- AT DECEMBER 31, 2000 1999 - ----------------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock, $1 par value - authorized 1,000 shares; 1,000 shares outstanding in 2000 and 1999.............. $ 1 $ 1 Capital surplus, paid in................................ 160,999 160,999 Retained earnings....................................... (41) 12,752 ------------- ------------- Total common stockholder's equity.............. 160,959 173,752 Long-term debt.......................................... 65,000 135,000 ------------- ------------- Total capitalization........................... 225,959 308,752 ------------- ------------- Current Liabilities: Notes payable to banks.................................. 200,000 - Long-term debt - current portion........................ 70,000 270,000 Accounts payable........................................ 16,543 11,694 Accounts payable to affiliated companies................ 1,389 806 Accrued interest........................................ 2,716 2,340 Other................................................... 276 272 ------------- ------------- 290,924 285,112 ------------- ------------- Deferred Credits and Other Long-term Liabilities: Accumulated deferred income taxes....................... 184,763 222,601 Deferred obligation to affiliated company............... 3,240 12,984 Other................................................... 24,078 22,658 ------------- ------------- 212,081 258,243 ------------- ------------- Commitments and Contingencies (Note 7) Total Capitalization and Liabilities...................... $ 728,964 $ 852,107 ============= =============
The accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- ----------------------------------------------------------------------------------- Capital Retained Common Surplus, Earnings Stock Paid In (a) Total - ----------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1998.............. $ 1 $ 160,999 $ 58,702 $ 219,702 Net income for 1998................. 29,494 29,494 Cash dividends on common stock...... (45,000) (45,000) ---------- ---------- --------- ---------- Balance at December 31, 1998............ 1 160,999 43,196 204,196 Net income for 1999................. 29,556 29,556 Cash dividends on common stock...... (60,000) (60,000) ---------- ---------- --------- ---------- Balance at December 31, 1999............ 1 160,999 12,752 173,752 Net income for 2000................. 32,493 32,493 Cash dividends on common stock...... (42,000) (42,000) Tax expense for 1993-1999 from reduction on NU parent company losses (b)......................... (3,286) (3,286) ---------- ---------- --------- ---------- Balance at December 31, 2000............ $ 1 $ 160,999 $ (41) $ 160,959 ========== ========== ========= ==========
(a) The dividend restriction allows all the retained earnings plus an allowance of $10,000,000 to be available. However the company has a 25% common equity ratio test to meet. Since the company's retained earnings are negative, only $9,959,000 of the allowance can be paid. (b) The amount in 2000 represents the tax expense related to the previously unallocated 1993 through 1999 NU parent losses. The accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------------------------- For the Years Ended December 31, - -------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2000 1999 1998 - -------------------------------------------------------------------------------------------------- Operating Activities: Net income.................................................. $ 32,493 $ 29,556 $ 29,494 Adjustments to reconcile to net cash provided by operating activities: Depreciation.............................................. 27,823 27,576 25,381 Amortization of nuclear fuel.............................. 10,221 12,642 10,453 Deferred income taxes and investment tax credits, net..... (25,579) 452 6,010 Deferred return - Seabrook................................ (5,838) (12,884) (18,900) Amortization of regulatory assets, net.................... 85,176 85,488 85,464 Tax expense for 1993-1999 from reduction of NU parent losses.......................... (3,286) - - Deferred obligation to affiliated company................. (9,744) (9,744) (9,744) Net other sources of cash................................. 18,645 35,486 18,214 Changes in working capital: Receivables............................................... (27,956) 964 1,891 Materials and supplies.................................... (915) (276) 191 Accounts payable.......................................... 5,432 5,709 (7,161) Accrued taxes............................................. - (710) 710 Other working capital (excludes cash)..................... 11,148 7,133 (13,258) ----------- ----------- ----------- Net cash flows provided by operating activities............... 117,620 181,392 128,745 ----------- ----------- ----------- Investing Activities: Investments in plant: Electric utility plant.................................... (6,586) (7,895) (9,028) Nuclear fuel.............................................. (17,222) (9,934) (6,474) ----------- ----------- ----------- Net cash flows used for investments in plant.............. (23,808) (17,829) (15,502) Investment in NU system Money Pool.......................... 28,600 (26,050) (30,350) Investments in nuclear decommissioning trusts............... (10,294) (7,584) (7,885) ----------- ----------- ----------- Net cash flows used in investing activities................... (5,502) (51,463) (53,737) ----------- ----------- ----------- Financing Activities: Net increase/(decrease) in short-term debt.................. 200,000 - (9,950) Reacquisitions and retirements of long-term debt............ (270,000) (70,000) (20,000) Cash dividends on common stock.............................. (42,000) (60,000) (45,000) ----------- ----------- ----------- Net cash flows used in financing activities................... (112,000) (130,000) (74,950) ----------- ----------- ----------- Net increase/(decrease) in cash for the period................ 118 (71) 58 Cash - beginning of period.................................... - 71 13 ----------- ----------- ----------- Cash - end of period.......................................... $ 118 $ - $ 71 =========== =========== =========== Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized........................ $ 28,349 $ 38,042 $ 42,498 =========== =========== =========== Income taxes................................................ $ 28,053 $ 3,000 $ 22,136 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. NOTES TO THE FINANCIAL STATEMENTS - --------------------------------- 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. About North Atlantic Energy Corporation North Atlantic Energy Corporation (NAEC or the company) along with The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), and Holyoke Water Power Company (HWP) are the operating companies comprising the Northeast Utilities system (NU system) and are wholly owned by Northeast Utilities (NU). The NU system serves in excess of 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues. The NU system furnishes franchised retail electric service in New Hampshire, Connecticut and western Massachusetts through PSNH, CL&P and WMECO. NAEC owns 35.98 percent of the Seabrook Station nuclear unit (Seabrook) and sells all of its entitlement to the capacity and output of Seabrook to PSNH under the terms of two life- of-unit, full cost recovery contracts (Seabrook Power Contracts). HWP, also is engaged in the production and distribution of electric power. NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act) and the NU system, including NAEC, is subject to provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. NAEC is subject to further regulation for rates, accounting and other matters by the FERC and/or the New Hampshire Public Utilities Commission (NHPUC). Several wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing, and other services to the NU system companies. Northeast Nuclear Energy Company acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear units. North Atlantic Energy Service Corporation (NAESCO) has operational responsibility for Seabrook. B. Presentation The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity and are subject to approval by various federal and state regulatory agencies. C. New Accounting Standards Derivative Instruments: Effective January 1, 2001, NAEC adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS No. 133 requires that derivative instruments be recorded as an asset or liability measured at its fair value and that changes in the fair value of derivative instruments be recognized currently in earnings unless specific hedge accounting criteria are met. In order to implement SFAS No. 133 by January 1, 2001, NU established a cross-functional project team to identify all derivative instruments, measure the fair value of those derivative instruments, designate and document various hedge relationships, and evaluate the effectiveness of those hedge relationships. NU has completed the process of identifying all derivative instruments and has established appropriate fair value measurements of those derivative instruments in place at January 1, 2001. In addition, for those derivative instruments which are hedging an identified risk, NU has designated and documented all hedging relationships anew. Management believes the adoption of this new standard will not have a material impact on NAEC's financial position or results of operations. D. Jointly Owned Electric Utility Plant Seabrook: NAEC has a 35.98 percent ownership interest in Seabrook, a 1,148 megawatt nuclear generating unit. NAEC sells all of its share of the power generated by Seabrook to PSNH under the Seabrook Power Contracts. NAEC expects to auction its investment in Seabrook in 2001 with a closing on the sale expected in 2002. NAEC's share of Seabrook's plant-in-service as of December 31, 2000 and 1999, was $734.6 million and $728 million, respectively, and the accumulated provision for depreciation was $172.6 million and $153 million, respectively. E. Depreciation The provision for depreciation is calculated using the straight-line method based on estimated remaining useful lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency, where applicable. Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. The costs of closure and removal of nonnuclear facilities are accrued over the life of the plant as a component of depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 2.9 percent in 2000, 3.8 percent in 1999 and 3.5 percent in 1998. F. Seabrook Power Contracts NAEC and PSNH have entered into two power contracts that obligate PSNH to purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook for the term of Seabrook's operating license. Under these power contracts, PSNH is obligated to pay NAEC's cost of service during this period, regardless of whether Seabrook is operating. NAEC's cost of service includes all of its Seabrook- related costs, including operation and maintenance (O&M) expenses, fuel expense, income and property tax expense, depreciation expense, certain overhead and other costs, and a return on its allowed investment. The Seabrook Power Contracts established the value of the initial investment in Seabrook at $700 million. As prescribed by the 1989 rate agreement between NU, PSNH, and the state of New Hampshire (Rate Agreement), as of May 1, 1996, NAEC phased into rates 100 percent of the recoverable portion of its investment in Seabrook. From June 5, 1992 (the date NU acquired PSNH and NAEC acquired Seabrook from PSNH - the Acquisition Date) through November 1997, NAEC recorded a $203.9 million deferred return on its investment in Seabrook. At November 30, 1997, NAEC's utility plant included $84.1 million of the deferred return that was transferred as part of the Seabrook plant assets to NAEC on the Acquisition Date. With the implementation of the "Agreement to Settle PSNH Restructuring" (Settlement Agreement), NAEC and PSNH will restructure the power contracts to provide for the buydown of the value of the Seabrook asset to $100 million. The Settlement Agreement also requires NAEC to sell via public auction its share of Seabrook, with the sale to occur no later than December 31, 2003. Upon a successful sale of NAEC's share of Seabrook, the existing Seabrook Power Contracts between NAEC and PSNH will be terminated. Under the current Seabrook Power Contracts, if Seabrook is shut down prior to the expiration of its operating license, PSNH will be unconditionally required to pay NAEC termination costs for 39 years, less the period during which Seabrook has operated. These termination costs will reimburse NAEC for its share of Seabrook shut-down and decommissioning costs, and will pay NAEC a return of and on any undepreciated balance of its initial investment over the remaining term of the power contracts, and the return of and on any capital additions to the plant made after the Acquisition Date over a period of five years after shut down (net of any tax benefits to NAEC attributable to the cancellation). G. Regulatory Accounting and Assets The accounting policies of NAEC and the accompanying financial statements conform to accounting principles generally accepted in the United States applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71. During the fourth quarter of 2000, the Settlement Agreement became probable of implementation, therefore, PSNH discontinued the application of SFAS No. 71 for the generation portion of its business. In accordance with the power contracts, NAEC will be paid for the cost of Seabrook, therefore, PSNH's discontinuation of SFAS No. 71 did not impact NAEC. Management continues to believe it is probable that NAEC will recover their investments in long-lived assets, including regulatory assets. In addition, all material regulatory assets are earning a return. The components of NAEC's regulatory assets are as follows: ---------------------------------------------------------------------- At December 31, 2000 1999 ---------------------------------------------------------------------- (Millions of Dollars) Deferred costs - Seabrook............... $23.2 $ 88.5 Income taxes, net....................... 23.4 35.6 Recoverable energy costs................ 1.5 1.7 Unamortized loss on reacquired debt..... - 3.8 ----- ------ $48.1 $129.6 ===== ====== ---------------------------------------------------------------------- Upon the implementation of the Settlement Agreement, as filed, PSNH will make a payment to NAEC to buydown the Seabrook Power Contracts to $100 million. NAEC will reduce the Seabrook assets to $100 million. Upon the final sale of Seabrook, the Seabrook Power Contract will be terminated and any difference between the net proceeds and the Seabrook book value at the time will be transferred to PSNH and applied against PSNH's stranded costs. H. Income Taxes The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, which give rise to the accumulated deferred tax obligation is as follows: ---------------------------------------------------------------------- At December 31, 2000 1999 ---------------------------------------------------------------------- (Millions of Dollars) Accelerated depreciation and other plant-related differences....... $197.8 $205.1 Regulatory assets - income tax gross up................... 7.6 12.2 Other................................... (20.6) 5.3 ------ ------ $184.8 $222.6 ====== ====== ---------------------------------------------------------------------- I. Recoverable Energy Costs Under the Energy Policy Act of 1992 (Energy Act), NAEC is assessed for its proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. NAEC is currently recovering these costs through the Seabrook Power Contracts. As of December 31, 2000 and 1999, NAEC's total D&D Assessment deferral was $1.5 million and $1.7 million, respectively. 2. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS Seabrook: Under the terms of the Rate Agreement, PSNH is obligated to pay NAEC's share of Seabrook's decommissioning costs, even if the unit is shut down prior to the expiration of its operating license. Accordingly, NAEC bills PSNH directly for its share of the costs of decommissioning Seabrook. PSNH records its Seabrook decommissioning costs as a component of purchased-power expense. Under the Rate Agreement, these costs are recovered through base rates. The Seabrook decommissioning costs will continue to be increased annually by its respective escalation rates until the unit is sold. NAEC's existing decommissioning trusts will be increased at the time of the plant sale, however, PSNH will continue to be responsible for funding NAEC's ownership share of the remainder of Seabrook's decommissioning liability after its share of the unit is sold. PSNH's obligation will be limited to the future funding of the decommissioning cost level in effect at the time of sale. The Settlement Agreement provides PSNH for the recovery of these costs through a stranded cost recovery charge within rates. Under New Hampshire law, Seabrook decommissioning funding requirements are set by the New Hampshire Nuclear Decommissioning Financing Committee (NDFC). During January 2000, the NDFC issued an order that adjusted the decommissioning collection period and funding levels assuming that Seabrook's anticipated energy producing life was 25 years from the date it went into commercial operation. Decommissioning collections are now expected to be completed by October 2015, as opposed to 2026, for the decommissioning collection period only. The cost of funding decommissioning Seabrook is now accrued over the estimated remaining accelerated funding period that was ordered by the NDFC. This is eleven years earlier than the service life established by Seabrook's Nuclear Regulatory Commission's (NRC) operating license. Upon retirement, Seabrook must be decommissioned. Current decommissioning studies conclude that complete and immediate dismantlement as soon as practical after retirement continues to be the most viable and economic method of decommissioning a unit. These studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology, and inflation. Changes in requirements or technology, the timing of funding or dismantling or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. The estimated cost of decommissioning NAEC's share of Seabrook, in year end 2000 dollars is $210.8 million. Nuclear decommissioning costs are accrued over the expected service life of the unit and are included in depreciation expense. Nuclear decommissioning expenses for the unit amounted to $6.9 million in 2000, $6.8 million in 1999 and $4.7 million in 1998. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation. Payments for NAEC's ownership share of the cost of decommissioning Seabrook are paid to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assumes escalated collections and after-tax earnings on the Seabrook decommissioning fund of 6.5 percent. As of December 31, 2000 and 1999, NAEC has paid $39.6 million and $32.7 million (including payments made prior to the Acquisition Date by PSNH), into Seabrook's decommissioning financing fund. Earnings on the decommissioning financing fund increase the decommissioning trust balance and the accumulated reserve for depreciation. Unrealized gains and losses associated with the decommissioning financing fund also impact the balance of the trust and the accumulated reserve for depreciation. The fair values of the amounts in the external decommissioning trust for NAEC were $50.9 million and $43.7 million at December 31, 2000 and 1999, respectively. 3. SHORT-TERM DEBT Limits: The amount of short-term borrowings that may be incurred by NAEC is subject to periodic approval by either the SEC under the 1935 Act or by the NHPUC. As of December 31, 2000, NAEC is authorized by the NHPUC and the SEC to incur short-term borrowings up to a maximum of $260 million. Credit Agreements: On November 9, 2000, NAEC entered into an unsecured 364-day term credit agreement for $200 million, replacing a $225 million term loan which was to expire on November 9, 2000. The proceeds from the term credit agreement were used to repay the $200 million outstanding under the previous term loan. Additionally, the interest rate swaps and collar related to the previous term loan expired and were not replaced. The term credit agreement also contains two mandatory prepayment provisions; the first is a 50 percent mandatory principal repayment of amounts outstanding to $100 million within two days of the buydown of the Seabrook Power Contracts and the second is 100 percent prepayment within two days of the sale of Seabrook. Any amounts prepaid can not be reborrowed. Unless extended, the term credit agreement will expire on November 8, 2001. At December 31, 2000 and 1999, there were $200 million in borrowings under the credit agreement and previous term loan. Under the aforementioned credit agreements, the respective borrowers may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service. The weighted average interest rate on NAEC's notes payable to banks outstanding on December 31, 2000, was 8.3 percent. Maturities of short-term debt obligations were for periods of three months or less. These credit agreements provide that NAEC must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, common equity ratios and interest coverage ratios. NAEC currently is and expects to remain in compliance with these covenants. Money Pool: Certain subsidiaries of NU, including NAEC, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the NU system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on loans from NU parent, however, bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 2000 and 1999, NAEC had no borrowings outstanding from the Pool. 4. LONG-TERM DEBT Details of long-term debt outstanding are: -------------------------------------------------------------------------- At December 31, 2000 1999 -------------------------------------------------------------------------- (Millions of Dollars) First Mortgage Bonds: 9.05% Series A, due 2002................... $135 $205 Notes: Variable - Rate Facility, due 2000......... - 200 Less amounts due within one year 70 270 ---- ---- Long-term debt, net $ 65 $135 ==== ==== -------------------------------------------------------------------------- Long-term debt maturities and cash sinking fund requirements on debt outstanding at December 31, 2000, for the years 2001 and 2002 are $70 million and $65 million, respectively. Essentially all utility plant of NAEC is subject to the liens of the company's first mortgage bond indenture. NAEC's first mortgage bonds are also secured by payments made to NAEC by PSNH under the terms of the Seabrook Power Contracts. In 1999, interest rate swaps effectively fix the interest rate of NAEC's $200 million variable-rate bank note at interest rates ranging from 5.81 percent to 6.07 percent. 5. INCOME TAX EXPENSE The components of the federal and state income tax provisions were charged/(credited) to operations as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Current income taxes: Federal.................................... $37.5 $15.1 $15.2 State...................................... 1.0 0.2 0.6 ----- ----- ----- Total current............................ 38.5 15.3 15.8 ----- ----- ----- Deferred income taxes, net: Federal.................................... (23.6) 0.4 4.0 State...................................... (2.0) - 2.0 ----- ----- ----- Total deferred........................... (25.6) 0.4 6.0 ----- ----- ----- Total income tax expense..................... $12.9 $15.7 $21.8 ===== ===== ===== -------------------------------------------------------------------------- The components of total income tax expense/(credit) are classified as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Income taxes charged to operating expenses... $ 35.7 $ 34.8 $ 36.2 Other income taxes........................... (22.8) (19.1) (14.4) ------ ------ ------ Total income tax expense..................... $ 12.9 $ 15.7 $ 21.8 ====== ====== ====== -------------------------------------------------------------------------- Deferred income taxes are comprised of the tax effects of temporary differences as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Depreciation................................. $ (6.5) $ 19.5 $ 21.8 Bond redemptions............................. (1.4) (2.8) (2.8) Seabrook deferred return..................... (17.3) (15.7) (14.2) Other........................................ (0.4) (0.6) 1.2 ------ ------- ------ Deferred income taxes, net................... $(25.6) $ 0.4 $ 6.0 ====== ======= ====== -------------------------------------------------------------------------- A reconciliation between income tax expense and the expected tax expense at 35 percent of pretax income is as follows: -------------------------------------------------------------------------- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- (Millions of Dollars) Expected federal income tax.................. $15.9 $15.8 $18.0 Tax effect of differences: Amortization of regulatory assets.......... 7.1 7.0 7.1 Depreciation............................... (1.5) (3.2) 1.6 Deferred Seabrook return................... (0.7) (1.5) (2.4) State income taxes, net of federal benefit.......................... (0.7) 0.1 1.7 Allocation of Parent Company's loss........ (6.3) (2.1) (3.9) Other, net................................. (0.9) (0.4) (0.3) ----- ----- ----- Total income tax expense..................... $12.9 $15.7 $21.8 ===== ===== ===== -------------------------------------------------------------------------- 6. DEFERRED OBLIGATION TO AFFILIATED COMPANY At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance with the phase-in under the Rate Agreement, it began to accrue a deferred return on a portion of its Seabrook investment. From May 16, 1991, to the Acquisition Date, PSNH accrued a deferred return of $50.9 million. On the Acquisition Date, PSNH sold the $50.9 million deferred return to NAEC as part of the Seabrook-related assets. At the time PSNH transferred the deferred return to NAEC, it realized, for income tax purposes, a gain that was deferred under the consolidated income tax rules. Beginning December 1, 1997, the gain is being amortized into income for income tax purposes, as the deferred return of $50.9 million, and the associated income taxes of $32.9 million, are being collected by NAEC through the Seabrook Power Contracts. As NAEC recovers the $32.9 million in years eight through ten of the Rate Agreement, corresponding payments are being made to PSNH. The balance of the deferred obligation to PSNH at December 31, 2000 and 1999, was $3.2 million and $13 million, respectively. 7. COMMITMENTS AND CONTINGENCIES A. Restructuring In September 2000, the NHPUC approved a comprehensive restructuring order that would allow PSNH to securitize up to $670 million of stranded costs. In January 2001, the New Hampshire Supreme Court upheld this restructuring order on appeal. However, one of the appellants indicated publicly it would request a review of the New Hampshire Supreme Court decision by the United States Supreme Court. Such a request must be filed by May 1, 2001. Management believes that such an appeal would have a low probability of success, but cannot determine what effect it might have on the timing of the issuance of securitization bonds and the implementation of customer choice in New Hampshire. PSNH currently expects to work with the State of New Hampshire to issue securitization bonds early in the second quarter of 2001. B. Environmental Matters The NU system, including NAESCO on behalf of NAEC, is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of our environment. As such, the NU system and NAESCO, have an active environmental auditing and training program and believe they are substantially in compliance with the current laws and regulations. However, the normal course of operations may involve activities and substances that expose NAEC to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on NAEC's financial statements. C. Spent Nuclear Fuel Disposal Costs Under the Nuclear Waste Policy Act of 1982, NAEC must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high- level radioactive waste. Fees for nuclear fuel burned are billed currently to customers and paid to the DOE on a quarterly basis. D. Nuclear Insurance Contingencies Insurance policies covering NAEC's ownership share of Seabrook have been purchased for the primary cost of repair, replacement or decontamination of utility property and certain extra costs for repair, replacement or decontamination or premature decommissioning of utility property. NAEC is subject to retroactive assessments if losses under those policies exceed the accumulated funds available to the insurer. The maximum potential assessments against NAEC, including costs resulting from PSNH's contracts with NAEC, with respect to losses arising during the current policy year for the primary property insurance program and the excess property damage policies are $2 million and $2.4 million, respectively. In addition, insurance has been purchased by the NU system in the aggregate amount of $200 million on an industry basis for coverage of worker claims. Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third- party liability indemnification program, the NU system, including NAEC, could be assessed liabilities in proportion to its ownership interest in each of its nuclear units up to $83.9 million. The NU system's payment of this assessment would be limited to, in proportion to its ownership interest in each of its nuclear units, $10 million in any one year per nuclear unit. In addition, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection, the NU system would be subject to an additional 5 percent, or $4.2 million, liability, in proportion to its ownership interest in each of its nuclear units. Under the terms of the Seabrook Power Contracts with NAEC, PSNH could be obligated to pay for any assessment charged to NAEC as a cost of service. Based upon NAEC's ownership interest in Seabrook, PSNH's maximum liability, including any additional assessments, would be $31.3 million per incident, of which payments would be limited to $3.6 million per year. 8. MARKET RISK AND MANAGEMENT INSTRUMENTS Interest Rate Risk Management: In 2000 and 1999, NAEC used interest rate collar and swap instruments with financial institutions to hedge against interest rate risk associated with its $200 million variable-rate bank note. On November 9, 2000, this facility was replaced with a fixed-rate bank note. The collar and swap instruments expired and were not replaced. Credit Risk: These agreements have been made with various financial institutions, each of which is rated "A3" or better by Moody's Investors Service rating group. NAEC is exposed to credit risk on its respective market risk management instruments if the counterparties fail to perform their obligations. Management anticipates that the counterparties will fully satisfy their obligations under the agreements. 9. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and Cash Equivalents: The carrying amounts approximate fair value due to the short-term nature of cash and cash equivalents. Nuclear Decommissioning Trust: The investments held in NAEC's nuclear decommissioning trust were marked-to-market by $0.1 million as of December 31, 2000, and by $3.2 million as of December 31, 1999, with corresponding offsets to the accumulated provision for depreciation. The amounts adjusted in 2000 and in 1999 represent cumulative net unrealized gains. Cumulative gross unrealized holding losses were immaterial for both 2000 and 1999. Long-Term Debt: The fair value of NAEC's fixed-rate security is based upon the quoted market price for that issue or similar issues. The adjustable rate security is assumed to have a fair value equal to its carrying value. The carrying amounts of NAEC's financial instruments and the estimated fair values are as follows: -------------------------------------------------------------------------- At December 31, 2000 -------------------------------------------------------------------------- Carrying Fair (Million of Dollars) Amount Value -------------------------------------------------------------------------- First mortgage bonds................. $135.0 $136.8 -------------------------------------------------------------------------- -------------------------------------------------------------------------- At December 31, 1999 -------------------------------------------------------------------------- Carrying Fair (Million of Dollars) Amount Value -------------------------------------------------------------------------- First mortgage bonds................. $205.0 $207.8 Other long-term debt................. $200.0 $200.0 -------------------------------------------------------------------------- 10. SEGMENT INFORMATION Effective January 1, 1999, the NU system companies, including NAEC, adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." The NU system is organized between regulated utilities and competitive energy subsidiaries. NAEC is included in the regulated utilities segment of the NU system and has no other reportable segments. 11. SUBSEQUENT EVENT Merger Agreement with Consolidated Edison, Inc.: In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the approvals needed to complete the merger announced in October 1999. Shareholders from both companies approved the merger in April 2000, and all state regulatory approvals were granted by the end of the year. Additionally, the FERC approved the merger in May 2000, the NRC approved the transaction in August 2000, and the United States Department of Justice approved the merger in February 2001. Necessary approval from the SEC was expected to be received in mid-March 2001. On February 28, 2001, NU's Board of Trustees requested that Con Edison provide reasonable assurance, in writing, that it intended to comply with the terms of the definitive merger agreement between the two companies. This included assurances that Con Edison would consummate the pending merger at the price set forth in the agreement promptly following the receipt of SEC approval. The original request for assurance was to be received by March 2, 2001, however that date was later extended to March 5, 2001. On March 5, 2001, Con Edison advised NU that it was not willing to close the merger on the agreed terms. NU notified Con Edison that it was treating its refusal to proceed on the terms set forth in the merger agreement as a repudiation and breach of the merger agreement, and that NU would file suit to obtain the benefits of the transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison filed suit in the U.S. District Court for the Southern District of New York (Southern District), seeking a declaratory judgment that NU failed to satisfy conditions precedent under the merger agreement. On March 12, 2001, NU filed suit against Con Edison in the Southern District seeking damages in excess of $1 billion arising from Con Edison's breach of the merger agreement. North Atlantic Energy Corporation
- ---------------------------------------------------------------------------------------------------------- SELECTED FINANCIAL DATA 2000 1999 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.................. $274,319 $287,369 $276,685 $ 192,381 $ 162,152 Operating Income.................... 44,077 49,728 54,057 57,061 54,889 Net Income.......................... 32,493 29,556 29,494 29,953 32,072 Cash Dividends on Common Stock...... 42,000 60,000 45,000 25,000 38,000 Total Assets........................ 728,964 852,107 945,153 1,014,639 1,017,388 Long-Term Debt (a).................. 135,000 405,000 475,000 495,000 515,000 - ----------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------ QUARTERLY FINANCIAL DATA (Unaudited) - ------------------------------------------------------------------------------------------------ Quarter Ended - ------------------------------------------------------------------------------------------------ 2000 March 31 June 30 September 30 December 31 - ------------------------------------------------------------------------------------------------ (Thousands of Dollars) Operating Revenues $66,276 $66,106 $66,921 $75,016 ======= ======= ======= ======= Operating Income $11,657 $11,185 $10,470 $10,765 ======= ======= ======= ======= Net Income $ 7,753 $ 8,272 $ 8,063 $ 8,405 ======= ======= ======= ======= - ------------------------------------------------------------------------------------------------ 1999 - ------------------------------------------------------------------------------------------------ Operating Revenues $70,289 $77,203 $69,779 $70,098 ======= ======= ======= ======= Operating Income $12,475 $12,303 $12,122 $12,828 ======= ======= ======= ======= Net Income $ 6,461 $ 6,243 $ 6,442 $10,410 ======= ======= ======= =======
- ----------------------------------------------------------------------------------------- STATISTICS (Unaudited) 2000 1999 1998 1997 1996 - ----------------------------------------------------------------------------------------- Gross Electric Utility Plant at December 31, (Thousands of Dollars) $756,432 $767,895 $784,113 $811,140 $816,446 ======== ======== ======== ======== ======== kWh Sales (Millions) for the year ended December 31, 2,850 3,125 3,018 2,859 3,542 ======== ======== ======== ======== ======== (a) Includes portion due within one year.
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