SEC Filing | NRG Energy, Inc.

1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) X Quarterly report pursuant to Section 13 or 15(d) of the Securities - --- Exchange Act of 1934 Transition report pursuant to Section 13 or 15(d) of the Securities - --- Exchange Act of 1934 For Quarter Ended September 30, 1999 Commission File Number 333-33397 ------------------- --------- NRG Energy, Inc. - -------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) Delaware 41-1724239 - -------------------------------------------------------------------------------- (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 1221 Nicollet Mall, Minneapolis, Minnesota 55403 - -------------------------------------------------------------------------------- (Address of principal executive officers) (Zip Code) Registrant's telephone number, including area code (612) 373-5300 --------------------------- None - -------------------------------------------------------------------------------- Former name, former address and former fiscal year, if changed since last report Indicated by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Class Outstanding at November 11, 1999 ---------------------- -------------------------------- Common Stock, $1.00 par value 1,000 Shares All outstanding common stock of NRG Energy, Inc., is owned beneficially and of record by Northern States Power Company, a Minnesota corporation. The Registrant meets the conditions set forth in general instruction H (1) (a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.

2 INDEX PAGE NO. -------- PART I ------ Item 1 Consolidated Financial Statements and Notes Consolidated Statements of Income 1 Consolidated Balance Sheets 2-3 Consolidated Statements of Stockholder's Equity 4 Consolidated Statements of Cash Flows 5 Notes to Consolidated Financial Statements 6-9 Item 2 Management's Discussion and Analysis of Financial Condition and Results of Operations 10-12 PART II ------- Item 1 Legal Proceedings 13 Item 6 Exhibits, Financial Statement Schedules, and Reports 14 on Form 8-K SIGNATURES 15

3 CONSOLIDATED STATEMENTS OF INCOME NRG ENERGY, INC. AND SUBSIDIARIES (UNAUDITED) THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, (Thousands of Dollars) 1999 1998 1999 1998 - ---------------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES Revenues from wholly-owned operations $ 139,974 $ 25,047 $ 237,855 $ 74,829 Equity in earnings of unconsolidated affiliates 30,434 29,249 45,726 58,432 - ---------------------------------------------------------------------------------------------------------------------------- Total operating revenues 170,408 54,296 283,581 133,261 - ---------------------------------------------------------------------------------------------------------------------------- OPERATING COSTS AND EXPENSES Cost of wholly-owned operations 79,147 13,079 148,211 39,384 Depreciation and amortization 12,663 4,511 23,688 12,560 General, administrative, and development 20,650 15,201 52,923 39,581 - ---------------------------------------------------------------------------------------------------------------------------- Total operating costs and expenses 112,460 32,791 224,822 91,525 - ---------------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 57,948 21,505 58,759 41,736 - ---------------------------------------------------------------------------------------------------------------------------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated subsidiaries (382) (492) (1,537) (1,652) Write-down of investment in projects - (23,410) - (23,410) Other income, net 2,196 1,206 5,504 3,105 Interest expense (30,760) (13,598) (57,607) (37,849) - ---------------------------------------------------------------------------------------------------------------------------- Total other expense (28,946) (36,294) (53,640) (59,806) - ---------------------------------------------------------------------------------------------------------------------------- INCOME (LOSS) BEFORE INCOME TAXES 29,002 (14,789) 5,119 (18,070) INCOME TAX EXPENSE (BENEFIT) 1,395 (10,014) (23,889) (26,353) - ---------------------------------------------------------------------------------------------------------------------------- NET INCOME $ 27,607 $ (4,775) $ 29,008 $ 8,283 - ---------------------------------------------------------------------------------------------------------------------------- See notes to consolidated financial statements. 1

4 CONSOLIDATED BALANCE SHEETS NRG ENERGY, INC. AND SUBSIDIARIES (UNAUDITED) SEPTEMBER 30, DECEMBER 31, (Thousands of Dollars) 1999 1998 - ------------------------------------------------------------------------------------------------------------------ ASSETS CURRENT ASSETS Cash and cash equivalents $ 25,236 $ 6,381 Restricted cash 2,122 4,021 Accounts receivable-trade, less allowance for doubtful accounts of $110 and $100 84,721 15,223 Accounts receivable-affiliates 33,879 7,324 Current portion of notes receivable - affiliates 11,461 4,460 Current portion of notes receivable - 26,200 Income taxes receivable - 21,169 Inventory 59,535 2,647 Prepayments and other current assets 15,086 4,533 - ------------------------------------------------------------------------------------------------------------------ Total current assets 232,040 91,958 - ------------------------------------------------------------------------------------------------------------------ PROPERTY, PLANT AND EQUIPMENT, AT ORIGINAL COST In service 1,229,082 291,558 Under construction 17,173 5,352 - ------------------------------------------------------------------------------------------------------------------ 1,246,255 296,910 Less accumulated depreciation (116,019) (92,181) - ------------------------------------------------------------------------------------------------------------------ Net property, plant and equipment 1,130,236 204,729 - ------------------------------------------------------------------------------------------------------------------ OTHER ASSETS Investments in projects 894,106 800,924 Capitalized project costs 53,475 13,685 Notes receivable, less current portion - affiliates 96,589 101,887 Notes receivable, less current portion 5,324 3,744 Intangible assets, net of accumulated amortization of $4,292 and $2,984 49,743 22,507 Debt issuance costs, net of accumulated amortization of $4,545 and $1,675 15,543 7,276 Other assets, net of accumulated amortization of $8,395 and $7,350 49,305 46,716 - ------------------------------------------------------------------------------------------------------------------ Total other assets 1,164,085 996,739 - ------------------------------------------------------------------------------------------------------------------ TOTAL ASSETS $ 2,526,361 $ 1,293,426 ================================================================================================================== See notes to consolidated financial statements. 2

5 CONSOLIDATED BALANCE SHEETS NRG ENERGY, INC. AND SUBSIDIARIES (UNAUDITED) SEPTEMBER 30, DECEMBER 31, 1999 1998 - -------------------------------------------------------------------------------------------- LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES Current portion of long-term debt $ 26,707 $ 8,258 Revolving line of credit 208,000 - Consolidated project-level, non-recourse debt 613,890 - Accounts payable-trade 46,094 7,371 Income taxes payable 11,356 - Accrued property and sales taxes 6,006 3,251 Accrued salaries, benefits and related costs 6,836 7,551 Accrued interest 18,202 7,648 Other current liabilities 22,662 8,289 - -------------------------------------------------------------------------------------------- Total current liabilities 959,753 42,368 - -------------------------------------------------------------------------------------------- MINORITY INTEREST 12,998 13,516 CONSOLIDATED PROJECT-LEVEL, LONG TERM, NONRECOURSE DEBT 122,348 113,437 CORPORATE LEVEL LONG-TERM DEBT, LESS CURRENT PORTION 675,000 504,781 DEFERRED INCOME TAXES 6,282 19,841 DEFERRED INVESTMENT TAX CREDITS 1,152 1,343 POSTRETIREMENT AND OTHER BENEFIT OBLIGATIONS 16,078 11,060 DEFERRED INCOME AND OTHER LONG-TERM OBLIGATIONS 10,507 7,748 - -------------------------------------------------------------------------------------------- Total liabilities 1,804,118 714,094 - -------------------------------------------------------------------------------------------- STOCKHOLDER'S EQUITY Common stock; $1 par value; 1,000 shares authorized; 1,000 shares issued and outstanding 1 1 Additional paid-in capital 631,913 531,913 Retained earnings 159,023 130,015 Accumulated other comprehensive income (68,694) (82,597) - -------------------------------------------------------------------------------------------- Total Stockholder's Equity 722,243 579,332 - -------------------------------------------------------------------------------------------- TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 2,526,361 $ 1,293,426 - -------------------------------------------------------------------------------------------- See notes to consolidated financial statements. 3

6 CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY NRG ENERGY, INC. AND SUBSIDIARIES (UNAUDITED) Accumulated Additional Other Total Common Paid-in Retained Comprehensive Stockholder's (Thousands of Dollars) Stock Capital Earnings Income Equity -------------------------------------------------------------------------------------- BALANCES AT JANUARY 1, 1998 $ 1 $ 431,913 $ 88,283 $ (69,499) $ 450,698 Net Income 8,283 8,283 Foreign currency translation adjustments (23,150) (23,150) -------------- Comprehensive income (14,867) -------------------------------------------------------------------------------------- BALANCES AT SEPTEMBER 30, 1998 $ 1 $ 431,913 $ 96,566 $ (92,649) $ 435,831 -------------------------------------------------------------------------------------- BALANCES AT JANUARY 1, 1999 $ 1 $ 531,913 $130,015 $ (82,597) $ 579,332 Net Income 29,008 29,008 Foreign currency translation adjustments 13,903 13,903 -------------- Comprehensive income 42,911 Capital Contribution from parent 100,000 100,000 -------------------------------------------------------------------------------------- BALANCES AT SEPTEMBER 30, 1999 $ 1 $ 631,913 $159,023 $ (68,694) $ 722,243 -------------------------------------------------------------------------------------- See notes to consolidated financial statements. 4

7 CONSOLIDATED STATEMENTS OF CASH FLOWS NRG ENERGY, INC. AND SUBSIDIARIES (UNAUDITED) NINE MONTHS ENDED SEPTEMBER 30, (Thousands of Dollars) 1999 1998 - ---------------------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 29,008 $ 8,283 Adjustments to reconcile net income to net cash provided (used) by operating activities Undistributed equity earnings of unconsolidated affiliates (1,363) (29,873) Depreciation and amortization 23,688 12,560 Deferred income taxes and investment tax credits (13,750) (7,601) Minority interest (518) - Write-down of investment in projects - 23,410 Cash provided (used) by changes in certain working capital items, net of acquisition effects Accounts receivable (67,958) (197) Accounts receivable-affiliates (26,555) 13,934 Income tax receivable 21,169 (3,692) Inventory (16,945) - Prepayments and other current assets (10,553) (3,043) Accounts payable-trade 38,723 (8,636) Income taxes payable 11,356 - Accrued property and sales tax 2,755 (512) Accrued salaries, benefits and related costs (857) 1,274 Accrued interest 10,554 4,430 Other current liabilities 2,260 1,742 Cash used by changes in other assets and liabilities (12,451) 2,808 - ---------------------------------------------------------------------------------------------------------- NET CASH (USED) PROVIDED BY OPERATING ACTIVITIES (11,437) 14,887 - ---------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions, net of liabilities assumed (930,185) - Investments in projects (118,231) (124,903) Divestiture of projects 1,000 9,219 Changes in notes receivable (net) 22,917 20,918 Purchase of plant, property and equipment (62,099) (23,265) Decrease (increase) in restricted cash 1,899 (2,341) - ---------------------------------------------------------------------------------------------------------- NET CASH USED BY INVESTING ACTIVITIES (1,084,699) (120,372) - ---------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Capital contributions from parent 100,000 - Revolving line of credit 84,000 103,000 Proceeds from issuance of note 613,890 - Proceeds from issuance of long-term debt 326,713 22,658 Principal payments on long-term debt (9,612) (18,187) - ---------------------------------------------------------------------------------------------------------- NET CASH PROVIDED BY FINANCING ACTIVITIES 1,114,991 107,471 - ---------------------------------------------------------------------------------------------------------- NET INCREASE IN CASH AND CASH EQUIVALENTS 18,855 1,986 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 6,381 11,986 - ---------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 25,236 $ 13,972 - ---------------------------------------------------------------------------------------------------------- See notes to consolidated financial statements. 5

8 NRG ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The Company is a wholly owned subsidiary of Northern States Power Company (NSP), a Minnesota corporation. Additional information regarding the Company can be found in NSP's Form 10-Q for the nine months ended September 30, 1999. The accompanying unaudited consolidated financial statements have been prepared in accordance with SEC regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. The accounting policies followed by the Company are set forth in Note 1 to the Company's financial statements in its Annual Report on Form 10-K for the year ended December 31, 1998 (Form 10-K). The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K. Interim results are not necessarily indicative of results for a full year. In the opinion of management, the accompanying unaudited interim financial statements contain all material adjustments necessary to present fairly the consolidated financial position of the Company as of September 30, 1999 and December 31, 1998, the results of its operations for the three and nine months ended September 30, 1999 and 1998, and its cash flows and stockholders' equity for the nine months ended September 30, 1999 and 1998. 1. BUSINESS DEVELOPMENTS In February 1999, the Company purchased from Thermal Ventures, Inc. (TVI) the remaining 50.1% limited partnership interests held by TVI in San Francisco Thermal Limited Partnership and Pittsburgh Thermal Limited Partnership for $12.3 million. In April 1999, NRG acquired TVI's 50% member interest in North American Thermal Systems LLC (the entity holding the general partnership interest in the San Francisco and Pittsburgh partnerships) for $500,000. In April 1999, the Company completed the acquisition of the Somerset power station for approximately $55 million from the Eastern Utilities Association (EUA). The Somerset station, located in Somerset, Massachusetts, includes two coal-fired generating facilities and two aeroderivative combustion turbine peaking units with a nominal capacity rating of 160 MW. In May 1999, the Company and Dynegy, through West Coast Power LLC, completed the acquisition of the Encina generating station and 17 combustion turbines for approximately $356 million from San Diego Gas & Electric Company. The facilities, which have a combined nominal capacity rating of 1,218 MW, are located near Carlsbad and San Diego, California. The Company and Dynegy each own a 50% interest in these facilities. In June 1999, the Company completed its acquisition of the Huntley and Dunkirk generating stations from Niagara Mohawk Power Corporation (NIMO) for approximately $355 million. The two coal-fired power generation facilities are located near Buffalo, New York, and have a combined summer capacity rating of 1,360 MW. In June 1999, the Company completed its acquisition of the Arthur Kill generating station and the Astoria gas turbine site from Consolidated Edison Company of New York, Inc. for approximately $505 million. These facilities, which are located in the New York City area, have a combined nominal capacity rating of 1,456 MW. 6

9 The Company, together with its partner and the Creditor's committee, filed a plan with the United States Bankruptcy Court for the Middle District of Louisiana to acquire 1,708 MW of fossil generating assets from Cajun Electric Power Cooperative of Baton Rouge, Louisiana (Cajun) for approximately $1.0 billion. During the third quarter, the U.S. Bankruptcy Judge confirmed the Company's Plan of Reorganization and the Company exercised an option to purchase its partner's 50-percent interest in the project. The Company expects to close the acquisition of the Cajun assets at the end of the first quarter of 2000. In August, the Company agreed to sell all but a 20 percent ownership interest in Cogeneration Corporation of America (CogenAmerica) to Calpine Corporation in connection with Calpine's acquisition of the remaining shares of CogenAmerica. The Company currently owns approximately 45 percent of CogenAmerica and upon the closing of the proposed transaction, all outstanding shares of CogenAmerica common stock (other than those to be retained by the Company) will be acquired by Calpine for a cash purchase price of $25.00 per share. The Company will retain a 20-percent ownership interest in CogenAmerica. The transaction is expected to close during the fourth quarter of 1999. In October 1999, the Company completed its acquisition of the Oswego generating station from NIMO and Rochester Gas and Electric for approximately $85 million. The oil and gas-fired power generating facility, which has a nominal capacity rating of 1,700 MW is located on a 93-acre site in Oswego, New York. In October 1999, the Company entered into a Standard Offer Service Wholesale Sales Agreement with Connecticut Light And Power Company (CL&P) pursuant to which the Company will supply CL&P with 35% of its standard offer service load during 2000, 40% during 2001 and 2002 and 45% during 2003. In July 1999, the Company executed an agreement to acquire four fossil fuel generating stations and numerous remote gas turbines from CL&P for approximately $460 million. These facilities have a combined nominal capacity rating of 2,235 MW. The Company expects the transaction to close during the fourth quarter of 1999. 2. CONTINGENT REVENUES The Company and its partner Dynegy each own a 50% interest in the Long Beach and El Segundo generating stations ("California Projects"). During 1998, the first year of deregulation of the state of California power industry, the California Projects accrued certain receivables related to contingent revenues. These revenues have been deferred pending resolution of the contingency. Such amounts relate to items that are subject to contract interpretations, compliance with processes and filed market disputes. The California Projects are actively pursuing resolution and/or collection of these amounts, which totaled approximately $40 million (the Company's share approximates $20 million) as of September 30, 1999. No assurance can be given that any of these deferred revenues will be collected, however, if collected, such deferred revenues will be recognized in the Company's equity income. 3. SUMMARIZED INCOME STATEMENT INFORMATION OF AFFILIATES The Company has 20-50% investments in four companies that are considered significant subsidiaries, as defined by applicable SEC regulations, and accounts for those investments using the equity method. The following summarizes the income statements of these unconsolidated entities: 7

10 THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, (Thousands of Dollars) 1999 1998 1999 1998 ------------------------ ----------------------- Net sales $ 186,573 $ 209,035 $ 506,994 $ 516,588 Other income (expense) (13,000) 712 - 179 Costs and expenses: Cost of sales 143,674 146,539 381,077 390,340 Depreciation and amortization 7,785 2,049 7,785 4,079 General and administrative (31,745) 5,416 17,827 17,964 ------------------------ ----------------------- 119,714 154,004 406,689 412,383 ------------------------ ----------------------- Income before income taxes 53,859 55,743 100,305 104,384 Income taxes 9,903 19,998 21,739 28,817 ------------------------ ----------------------- Net income $ 43,956 $ 35,745 $ 78,566 $ 75,567 ======================== ======================= Company's share of net income $ 16,572 $ 16,981 $ 31,167 $ 32,648 ======================== ======================= 4. SHORT TERM BORROWINGS At September 30, 1999, the Company had $613.9 million in short-term project level borrowings at an average interest rate of 6.62% used for project acquisitions. The Company has $686.6 million of available borrowing under this credit facility. The Company plans to refinance this short-term project-level borrowing with long-term project-level debt later this year. As of September 30, 1999, the Company had $350 million in revolving credit facilities under a commitment fee arrangement. These facilities provide short-term financing in the form of bank loans and letters of credit. At September 30, 1999, the Company has $208 million outstanding under its revolving credit agreements. 5. LONG TERM DEBT In March 1999, the Company filed a shelf registration statement with the Securities and Exchange Commission for up to $500 million in debt securities. The net proceeds will be used to finance the Company's equity investments in connection with pending acquisitions and for general corporate purposes, which may include financing the development and construction of new facilities, working capital, debt reduction and capital expenditures. In May 1999, the Company issued $300 million of 7.5% senior notes due in 2009 under this registration statement. In September 1999, the Company entered into a $200 million swap agreement effectively converting the 7.5% fixed rate on these senior notes to a variable rate based on LIBOR. In November 1999, the Company issued $240 million of Remarketable or Redeemable Securities (ROARS) with an 8 percent coupon, a re-marketing date of November 2003 and a final maturity of November 2013. During the third quarter of 1999 NRG Northeast Generating LLC (N.E. Generating), a wholly owned subsidiary of the Company, entered into $600 million of treasury locks at various interest rates. These treasury locks, which expire in February of 2000, are an interest rate hedge of N.E. Generating's anticipated bond offering in the first quarter of 2000. The proceeds of any such bond offering will be used to pay off N.E. Generating's currently existing short-term credit facility. 6. SEGMENT REPORTING The Company conducts its business within three segments: Independent Power Generation, Alternative Energy (Resource Recovery and Landfill Gas) and Thermal projects. These segments are distinct components of the Company with separate operating results and management structures in place. The `Other" category includes operations that do not meet the threshold for separate disclosure and corporate charges that have not been allocated to the operating segments. Segment information for the three and nine months ended September 30, 1999 and 1998 are as follows: 8

11 THREE MONTHS ENDED SEPTEMBER 30, 1999 INDEPENDENT (Thousands of Dollars) POWER ALTERNATIVE GENERATION ENERGY THERMAL OTHER TOTAL ---------------------------------------------------------------- OPERATING REVENUES Revenues from wholly-owned operations $ 115,447 $ 5,356 $ 18,450 $ 506 $ 139,759 Intersegment revenues - 215 - - 215 Equity in earnings of unconsolidated affiliates 30,744 (3,365) 588 2,467 30,434 ---------------------------------------------------------------- Total operating revenues 146,191 2,206 19,038 2,973 170,408 ---------------------------------------------------------------- NET INCOME (LOSS) $ 48,272 $ 683 $ 1,498 $ (22,846) $ 27,607 THREE MONTHS ENDED SEPTEMBER 30, 1998 INDEPENDENT (Thousands of Dollars) POWER ALTERNATIVE GENERATION ENERGY THERMAL OTHER TOTAL ----------------------------------------------------------------- OPERATING REVENUES Revenues from wholly-owned operations $ 307 $ 7,642 $ 13,293 $ 3,446 $ 24,688 Intersegment revenues - 359 - - 359 Equity in earnings of unconsolidated affiliates 29,678 (361) 58 (126) 29,249 ----------------------------------------------------------------- Total operating revenues 29,985 7,640 13,351 3,320 54,296 ----------------------------------------------------------------- NET INCOME (LOSS) $ 14,077 $ 3,247 $ 1,553 $(23,653) $ (4,776) NINE MONTHS ENDED SEPTEMBER 30, 1999 INDEPENDENT (Thousands of Dollars) POWER ALTERNATIVE GENERATION ENERGY THERMAL OTHER TOTAL ----------------------------------------------------------------- OPERATING REVENUES Revenues from wholly-owned operations $156,579 $ 20,498 $ 55,005 $ 4,810 $236,892 Intersegment revenues - 963 - - 963 Equity in earnings of unconsolidated affiliates 50,871 (2,029) 1,671 (4,787) 45,726 ----------------------------------------------------------------- Total operating revenues 207,450 19,432 56,676 23 283,581 ----------------------------------------------------------------- NET INCOME (LOSS) $ 55,799 $ 6,847 $ 4,682 $(38,320) $ 29,008 NINE MONTHS ENDED SEPTEMBER 30, 1998 INDEPENDENT (Thousands of Dollars) POWER ALTERNATIVE GENERATION ENERGY THERMAL OTHER TOTAL ----------------------------------------------------------------- OPERATING REVENUES Revenues from wholly-owned operations $ 1,165 $ 22,994 $ 39,946 $ 9,683 $ 73,788 Intersegment revenues - 1,041 - - 1,041 Equity in earnings of unconsolidated affiliates 58,629 13 294 (504) 58,432 ----------------------------------------------------------------- Total operating revenues 59,794 24,048 40,240 9,179 133,261 ----------------------------------------------------------------- NET INCOME (LOSS) $ 35,324 $ 12,095 $ 4,490 $(43,626) $ 8,283 7. FINANCIAL INSTRUMENTS During the first quarter of 1999, the Company entered into a forward contract to exchange approximately $10.5 million of U.S. dollars for British pounds. This foreign exchange contract, which expires in December, 1999 is a hedge of the Company's equity commitment to the Enfield project currently under construction in England. NEW ACCOUNTING PRONOUNCEMENTS In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement requires that all derivatives be recognized at fair value in the Balance Sheet, and that changes in fair value be recognized either currently in earnings or deferred as a component of Other Comprehensive Income, depending on the intended use of the derivative, its resulting designation and its effectiveness. The Company plans to adopt this standard in 2001, as required. The Company has not determined the potential impact of implementing this statement. 9

12 ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Management's Discussion and Analysis of Financial Condition is omitted per conditions as set forth in General Instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management's narrative analysis of the results of operations as permitted by General Instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format). This analysis compares the Company's revenue and expense items for the nine months ended September 30, 1999 with the nine months ended September 30, 1998. RESULTS OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 1998 Net income for the nine months ended September 30, 1999, was $29.0 million compared to $8.3 million for the same period in 1998. The increase in net income of $20.7 million was due to the factors described below. OPERATING REVENUES For the nine months ended September 30, 1999, revenues were $283.6 million, an increase of $150.3 million, or 113%, over the same period in 1998. The operating revenues from wholly owned operations for the nine months ended September 30, 1999 were $237.9 million, an increase of $163.0 million, or 218%, over the same period in 1998. Approximately $115.5 million of the increase relates to the Dunkirk, Huntley, Somerset, Astoria and Arthur Kill facilities that were acquired during the second quarter of 1999. Approximately $41.3 million of the increase is from energy sales to Eastern Utilities Association (EUA) under an agreement that went into effect on January 1, 1999. Under the terms of the power sales agreement, the Company will provide various affiliates of EUA with a fixed percentage of their energy needs for a period of 6.2 to 11 years. In addition, approximately $15.5 million of the increased revenues relates to the Company's increased ownership in the Pittsburgh and San Francisco Thermal operations as a result of the acquisition of the remaining 50% interest in these projects in April, 1999. For the nine months ended September 30, 1999, revenues from wholly owned operations consisted of revenue from electrical generation (77%), heating, cooling and thermal activities (20%) and technical services (3%). Equity in earnings of unconsolidated affiliates was $45.7 million for the nine months ended September 30, 1999, compared to $58.4 million for the nine months ended September 30, 1998, a decrease of $12.7 million, or 22%. The decrease was due to several factors, including a $6.8 million reduction in earnings from the Mt. Poso project primarily due to curtailment revenues that were recorded in 1998, a $3.9 million decrease in earnings from West Coast Power LLC due to cooler weather conditions partially offset by earnings from the Encina facility which was acquired during the second quarter of 1999. In addition, there was a $2.1 million net decrease in equity earnings due to a transaction adjustment related to the Kladno Project. A portion of the Kladno project's debt is denominated in U.S. dollars and German deutsche marks, which strengthened against the Czech koruna in the first six months of 1999. Under SFAS No. 52, Foreign Currency Translation, the Kladno project records foreign currency gains and losses through the income statement. OPERATING COSTS AND EXPENSES Cost of wholly owned operations was $148.2 million for the nine months ended September 30, 1999. This is an increase of $108.8 million, or 276%, over the same period in 1998. The increase is due to increased operating costs from new acquisitions and energy purchases made to satisfy the EUA power sales agreement. 10

13 Depreciation and amortization costs were $23.7 million for the nine months ended September 30, 1999, compared to $12.6 million for the nine months ended September 30, 1998. The depreciation and amortization increase was due primarily to the acquisition of new projects, including the Somerset, Dunkirk, Huntley, Astoria and Arthur Kill facilities and depreciation from the Pittsburgh and San Francisco thermal facilities that were previously recorded on the equity method of accounting. General, administrative and development costs were $52.9 million for the nine months ended September 30, 1999, compared to $39.6 million for the nine months ended September 30, 1998. The $13.3 million increase was due primarily to increased business development activities, associated legal, technical, and accounting expenses, labor and other costs resulting from expanded operations and pending acquisitions. The Company's total assets increased from approximately $1.3 billion to approximately $2.5 billion during the first nine months of 1999. OTHER INCOME (EXPENSE) Other expense for the nine months ended September 30, 1999, was $53.6 million, a decrease of $6.2 million from $59.8 million for the same period in 1998. The decrease was due to a $23.4 million write-down that was recorded in the third quarter of 1998 related to the West Java project in Indonesia and other projects. This amount was partially offset by $19.8 million of additional interest costs in 1999 related to the issuance of $300 million of 7.5% senior notes in May 1999 and approximately $540 million of additional short-term debt. INCOME TAX The Company recognized an income tax benefit due to a pre-tax loss from domestic operations and due to the recognition of certain tax credits. The net income tax benefit for the nine months ended September 30, 1999, decreased by $2.5 million to $23.9 million as compared to $26.4 million for the same period during 1998. The decrease in tax benefits for the nine month period was due primarily to increased earnings from domestic operations. YEAR 2000 (Y2K) READINESS To the extent allowed, the information in the following section is designated as a "Year 2000 Readiness Disclosure." The Company continues to incur costs to modify or replace existing technology, including computer software, for uninterrupted operation in the year 2000 and beyond. A committee made up of senior management is leading the Company's initiatives to identify Y2K related issues and remediate business processes as necessary. The Company is also partnering with its parent, Northern States Power Company, to ensure a consistent overall company process in addressing the Y2K issue, as discussed in the Company's 1998 Form 10-K. The Company is on schedule for completion of its Y2K project based on the following revised timetable. - - Assessment/discovery/analysis - Completed - - Final testing - Completed - - Y2K Ready - November 15, 1999 The Company is currently updating contingency plans for all material Y2K risks and is on track to meet the contingency planning schedule that has been established. In addition to Y2K readiness, the Company's contingency planning addresses the failure of key third party contracts to be Y2K compliant. A Y2K readiness plan is obtained as part of all new acquisitions. FORWARD-LOOKING STATEMENTS This quarterly report on Form 10-Q includes forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "estimate," "expect," "objective," "possible," "potential" and similar expressions. Without limitation, forward-looking statements are contained under the heading "business developments". In addition to any assumptions and other factors referred to specifically in connection with such forward looking statements, factors that could cause the actual results to differ materially from those contemplated in any forward-looking statements include among others the following: the failure to timely satisfy the closing 11

14 conditions contained in definitive agreements for transactions not yet closed, including obtaining all necessary regulatory approvals, many of which are beyond the Company's control; limitations on the Company's ability to control projects or transactions in which the Company has less than 100% interest; and other business or investment considerations that may be disclosed from time to time in the Company's Securities and Exchange Commission filings and in other publicly disseminated written documents, including the Company's registration statement number 333-74519, as amended, and all supplements thereto. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exhaustive. 12

15 PART II ITEM 1. LEGAL PROCEEDINGS On or about July 12, 1999, Fortistar Capital, Inc. ("Fortistar") commenced an action against the Company in Hennepin County (Minnesota) District Court, seeking damages in excess of $100 million and an order restraining the Company from consummating the acquisition of NIMO's Oswego generating station. Fortistar's motion for a temporary restraining order was denied and a temporary injunction hearing was held on September 27, 1999. The acquisition of the Oswego generating station was closed on October 22, 1999 following notification to the Court of the closing date. The Company intends to continue to vigorously defend the suit and believes Fortistar's claims to be without merit. The Company has asserted numerous counterclaims against Fortistar. 13

16 PART II ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (A) EXHIBITS 10.31 First Amendment to the Employment Agreement of David H. Peterson, dated June 27, 1999. 10.32 Second Amendment to the Employment Agreement of David H. Peterson, dated August 26, 1999. 10.33 Third Amendment to the Employment Agreement of David H. Peterson, dated October 20, 1999. 10.34 [Swap] Master Agreement between Niagara Mohawk Power Corporation and NRG Power Marketing, Inc., dated June 11, 1999. 10.35 Standard Offer Service Wholesale Sales Agreement between the Connecticut Light And Power Company and NRG Power Marketing, Inc., dated October 29, 1999. 27 Financial data schedule for the period ended September 30, 1999. (B) REPORTS ON FORM 8-K: On July 8, 1999, NRG filed a Form 8-K reporting under Item 5 - Other Events. NRG announced its acquisition of the Arthur Kill and Astoria generating assets from the Consolidated Edison Company of New York, Inc. On July 16, 1999, NRG filed a Form 8-K reporting under Item 5 - Other Events. NRG announced that earnings for the six months ended June 30, 1999 would be below expectations. On September 14, 1999 NRG filed a Form 8-K reporting under Item 5 - Other Events. NRG announced forecasted earnings for the twelve months ending December 31, 1999 and 2000. On October 14, 1999, NRG filed a Form 8-K reporting under Item 5 - Other Events. NRG announced earnings for the nine months ended September 30, 1999 and reduced its forecast for the twelve months ending December 31, 1999. On November 3, 1999 NRG filed a Form 8-K reporting under Item 5 - Other Events. NRG filed certain exhibits relating to the offering of $240 million principal amount of the Company's 8.0% Remarketable or Redeemable Securities (ROARS) due November 1, 2013 (Remarketing date November 1, 2003). 14

17 SIGNATURES Pursuant to the requirements 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. NRG ENERGY, INC. (Registrant) /s/ Leonard A. Bluhm ---------------------------------- Leonard A. Bluhm Executive Vice President and Chief Financial Officer (Principal Financial Officer) /s/ David E. Ripka ---------------------------------- David E. Ripka Vice President and Controller (Principal Accounting Officer) Date: November 12, 1999 ------------------------ 15

1 EXHIBIT 10.31 FIRST AMENDMENT TO THE EMPLOYMENT AGREEMENT OF DAVID H. PETERSON WHEREAS, David H. Peterson (the "Executive") and NRG Energy Inc. ("NRG") have previously entered into an Employment Agreement (the "Agreement") dated June 28, 1995; and WHEREAS, Section 3(c)(i) of the Agreement provides that Executive may request a lump sum payment option of the benefit described therein provided that Executive requests said lump sum payment not less than twelve (12) months prior to Executive's termination of employment; and WHEREAS, NRG and Executive wish to amend the Agreement to permit the request to be made not less than ten (10) months prior to Executive's termination of employment. RESOLVED, that Section 3(c)(i) of the Agreement is hereby amended to substitute the word "ten" for the word "twelve" in the second sentence thereof. RESOLVED FURTHER, that the Agreement as amended, shall remain in fullforce and effect. /s/ David H. Peterson Date: 6/27/99 - ----------------------------- ------------------------- David H. Peterson NRG Energy Inc. By /s/ Gary R. Johnson Date: 6/25/99 -------------------------- ------------------------- Its Director -------------------------

1 EXHIBIT 10.32 NORTHERN STATES POWER COMPANY 825 Rice Street Cynthia L. Lesher St. Paul, Minnesota 55117-6485 President Telephone (651) 229-2592 NSP Gas August 26, 1999 Dave Peterson NRG Energy, Incorporated VIA FACSIMILE Suite 700 AND U.S. MAIL 1221 Nicollet Mall Minneapolis, Minnesota 55403 Dear Dave: As you know, the period of time during which you may request a lump sum payment under your employment agreement expires tomorrow. Due to the ongoing discussions regarding the extension of your agreement and how to best coordinate the extension with NCE, the NRG Board has approved granting you an additional 30-day period during which you may elect a lump sum. Sincerely, Cyndi

1 EXHIBIT 10.33 THIRD AMENDMENT TO THE EMPLOYMENT AGREEMENT OF DAVID H. PETERSON WHEREAS, David H. Peterson (the "Executive") and NRG Energy Inc. ("NRG") have previously entered into an Employment Agreement (the "Agreement") dated June 28, 1995, amended on June 27, 1999 and further amended on August 26, 1999; and WHEREAS, the parties wish to further amend the agreement to extend its term for four (4) additional years, to provide a minimum severance benefit in the event Executive's employment is terminated in connection with a change in control, and to preserve certain 1999 retirement benefit calculation assumptions if specific performance goals are achieved. RESOLVED, that sections 1, 3(c)(i), and 5(a) of the Agreement are hereby amended to read as follows: 1. Term. NRG shall employ the Executive, and the Executive shall serve NRG, on the terms and conditions set forth in this Agreement, for the period (the "Employment Period") commencing on June 28, 1995 (the "Effective Time") and ending JUNE 27, 2004. 3. Compensation. (c) Additional Benefits. (i) Supplemental Retirement Benefits. During the Employment Period, the Executive shall participate in a supplemental executive retirement plan ("SERP") such that the aggregate value of the retirement benefits that he and his spouse will receive at the end of the Employment Period under all defined benefit plans of NRG, NSP and their affiliates (whether qualified or not) will be not less than the aggregate value of the benefits he would have received had he continued, through the end of the Employment Period to participate in the NSP Deferred Compensation Plan, the NSP Excess Benefit Plan, and the NSP Pension Plan; provided, that benefits under the SERP, shall also include the amount, if any, that the NSP Pension Plan's actuaries reasonably estimate is necessary to compensate Executive for the monthly defined benefit payments the Executive did not receive, but would have received during the term of this Agreement and prior to the date of his actual termination of employment if monthly benefit payments had commenced at the end of the month following the month in which the Executive first became eligible for Early Retirement under the NSP Pension Plan. In addition, the SERP shall offer the Executive the option to receive his benefits thereunder in a single lump sum payment using actuarial assumptions that the NSP Pension Plan's actuaries determine are reasonable in the aggregate; provided, that such lump sum payment option shall be subject to the consent of the Board in its sole discretion and must be requested by the Executive not less than twelve months prior to the Executive's termination of employment. IF THE EXECUTIVE ELECTS A LUMP SUM PAYMENT, THE LUMP SUM SHALL BE CALCULATED USING THE JOINT

2 AND SURVIVOR ANNUITY FACTORS IN EFFECT FOR 1999 UNDER THE NSP PENSION PLAN IF THE FOLLOWING PERFORMANCE GOALS HAVE BEEN ACHIEVED PRIOR TO PAYMENT OF THE LUMP SUM: EARNINGS PER SHARE (EPS) GROWTH OF 20 PERCENT PER YEAR (ASSUMING ADEQUATE EQUITY FUNDING IS PROVIDED) AND NRG RETURN GUIDELINES OF UTILITY (NSP AUTHORIZED RATE OF RETURN) PLUS 1 1/2 PERCENT LONG-TERM RETURN ON EQUITY (ROE), ON AVERAGE, FOR NEW INVESTMENTS. IF THE ROE GOAL IS NOT ACHIEVED, The ADDITIONAL BENEFIT DERIVED FROM THE USE OF THE 1999 JOINT AND SURVIVOR ANNUITY FACTORS WILL BE PRORATED PROVIDED THAT THE EPS GOAL IS MET AND AVERAGE ANNUAL ROE IS AT LEAST 8 PERCENT. FOR EXAMPLE, IF, ON AVERAGE, 20 PERCENT EPS GROWTH AND A ROE OF UTILITY PLUS 1 1/2 PERCENT is ACHIEVED, THE FULL JOINT AND SURVIVOR BENEFIT WILL BE PROVIDED. IF AVERAGE ANNUAL ROE IS 8 PERCENT OR LESS, NO BENEFIT BASED ON THE JOINT AND SURVIVOR ANNUITY FACTORS WILL BE PROVIDED. Finally, if the Executive dies while employed, or deemed pursuant to paragraph (a) of section 5 to be employed by NRG, his surviving spouse (or, if, he has no surviving spouse, his estate) shall be entitled to receive a benefit equal in value to the difference between the pension benefit that the Executive would have received if he had retired (rather than died ) on the date of his death and received a lump sum pension benefit and the lump sum value of the pension payable in the absence of this provision; provided, that in the case where the Executive has no surviving spouse, the benefit pursuant to this sentence shall be paid in a lump sum; and provided, further, that in the case where the Executive has a surviving spouse, the benefit pursuant to this sentence shall be paid in the form of a single life annuity for her life unless she elects a single lump sum payment and the Board, in its sole discretion, consents to the lump sum payment. Notwithstanding anything in the preceding sentence to the contrary, if despite reasonable efforts NRG is unable to obtain insurance on the life of the Executive with a death benefit equal to the anticipated after-tax cost to NRG of the benefit described in the preceding sentence at an average annual premium cost of less than $7,000, then the value of such benefit payable to Executive's surviving spouse or estate shall be reduced so that its after-tax cost to NRG does not exceed the amount of insurance on the life of the Executive that NRG could obtain at such cost. 5. Obligations of NRG upon Termination. (a) By NRG Other Than for Cause or Disability; By the Executive for Good Reason. If, during the Employment Period, NRG terminates the Executive's employment, other than for Cause or Disability, or the Executive terminates employment for Good Reason, NRG shall continue to provide the Executive with the compensation and benefits set forth in Section 3 as if he had remained employed by NRG pursuant to this Agreement through the end of the Employment Period and then retired (at which time he will be treated as eligible for all retiree welfare benefits and other benefits provided to retired senior executives, as set forth in Section 3(b) and (c)); PROVIDED THAT IF THE TERMINATION IS A RESULT OF A CHANGE OF CONTROL, AS THAT TERM IS DEFINED IN THE NRG OFFICER EQUITY PLAN, THE COMPENSATION AND BENEFITS SHALL BE CONTINUED FOR THE LONGER OF THIRTY (30) MONTHS OR THROUGH THE END OF THE EMPLOYMENT PERIOD; provided, that the Incentive 2

3 Compensation for such period shall be equal to the greater of the target Incentive Compensation that the Executive would have been eligible to earn for such period or the Incentive Compensation awarded for the last complete incentive plan year ending prior to Executive's Termination of Employment; provided, further, that in lieu of stock-based or equity-based awards, the Executive shall be paid cash equal to the fair market value at the time of grant, if any, (determined without regard to any restrictions) of the awards that would otherwise have been granted; and provided, finally, that during any period when the Executive is eligible to receive benefits of the type described in paragraph (b) (i) of Section 3 under another employer-provided plan the benefits provided by NRG under this paragraph (a) of Section 5 may be made secondary to those provided under such other plan. The payments and benefits provided pursuant to this paragraph (a) of Section 5 are intended as liquidated damages for a termination of the Executive's employment by NRG other than for Cause or Disability or for the actions of NRG leading to a termination of the Executive's employment by the Executive for Good Reason, and shall be the sole and exclusive remedy therefor. RESOLVED FURTHER, that the Agreement as amended, shall remain in full force and effect. /s/ David H. Peterson Date: 20 Oct. 1999 - --------------------------------- ------------------- David H. Peterson NRG ENERGY, INCORPORATED By /s/ Cynthia L. Lesher Date: 20 Oct. 1999 ------------------------------- ------------------- Its Director ------------------------------ 3

1 EXHIBIT 10.34 DATE: June 11, 1999 TO: NRG POWER MARKETING INC. ATTENTION: FAX NO: FROM: NIAGARA MOHAWK POWER CORPORATION RE: SWAP TRANSACTION - -------------------------------------------------------------------------------- Dear Ladies and Gentlemen: The purpose of this letter agreement (this "Confirmation") is to confirm the terms and conditions of the Transaction entered into between us on the Trade Date specified below (the "Transaction"). This Confirmation constitutes a "Confirmation" as referred to herein, and supplements, forms a part of and is subject to, the ISDA Master Agreement, dated as of June 11, 1999 as amended and supplemented from time to time (the "Agreement"), between NRG Power Marketing Inc. ("PRODUCER") and Niagara Mohawk Power Corporation ("NIAGARA MOHAWK"). All provisions contained in the Agreement govern this Confirmation except as expressly modified below. The terms of the Transaction to which this Confirmation relates are as follows: THE OBLIGATIONS INCURRED PURSUANT TO THIS TRANSACTION SHALL REQUIRE CASH PAYMENTS AND SHALL IN NO EVENT BE INTERPRETED TO REQUIRE THE PURCHASE OR SALE OF ELECTRICITY. 1. General Terms: Trade Date: June 11, 1999 Effective Date: The later of (i) the Closing Date, as such term is defined in the Asset Sales agreement between Niagara Mohawk and NRG Energy, Inc., or (ii) first day of the month following the month in which the later of (i) the NYISO goes into operation, or (ii) Niagara Mohawk's senior notes of the series having the longest maturity then outstanding have been rated investment grade by (a) S&P and Moody's or (b) S&P or Moody's and at least one other rating -1-

2 agency. Termination Date: The fourth anniversary of the Closing Date. Business Day: Any day other than Saturday, Sunday and any day which is a legal holiday or a day on which banking institutions in New York City are authorized by law or other governmental action to close; and a Business Day shall open at 8:00 a.m. and close at 5:00 p.m. Eastern Standard (or Daylight) time. Calculation Agent: NIAGARA MOHAWK. 2. Payments: Settlement Dates: The last day of each calendar month during the Term of this Transaction. Settlement Periods: With respect to each Settlement Date means the period from (but excluding) the immediately preceding Settlement Date (or, in the case of the first Settlement Date, from and including the Effective Date) to (and including) such Settlement Date (or, in the case of the last Settlement Date, to and including the Termination Date). Payment Dates: With respect to each Settlement Date or Settlement Period means the 25th day of the calendar month immediately after such Settlement Date or Settlement Period, as the case may be, subject to adjustment in accordance with the Following Business Day Convention. Payment Calculations: Not less than 5 Business Days prior to each Payment Date, the Calculation Agent shall calculate the amounts payable by each party on such Payment Date and shall notify the other party thereof (including reasonable detail with respect to such calculation). -2-

3 Payment Amounts: On each Payment Date: (i) NIAGARA MOHAWK shall pay to PRODUCER one-twelfth of the Call Fee - Stage 1 for the preceding Settlement Period, and (ii) PRODUCER shall pay to NIAGARA MOHAWK an amount equal to the sum of (A) the aggregate Capacity Payment for each Interval during such Settlement Period and (B) the Ancillary Services Payment for such Settlement Period. In addition to the foregoing, if NIAGARA MOHAWK has exercised the Call Option with respect to any Interval during a Settlement Period, then on the Payment Date immediately after such Settlement Period (i) NIAGARA MOHAWK shall pay to PRODUCER the sum of (A) the aggregate Call Fee-Stage 2 for each such Interval, and (B) the aggregate NIAGARA MOHAWK Call Amount for each such Interval, and (ii) PRODUCER shall pay to NIAGARA MOHAWK the aggregate PRODUCER Call Amount for each such Interval. 3. Call Option Exercise: Call Option: With respect to each Interval, NIAGARA MOHAWK shall have the right, but not the obligation, to specify a quantity of electricity (the "Call Quantity") as to which the PRODUCER Call Amount and the NIAGARA Call Amount will be calculated and will become due in accordance with this Transaction. Notwithstanding the foregoing, PRODUCER shall retain the right to refuse the portion of a Call Quantity for a Unit if the Unit is unexpectedly forced off-line or derated sufficiently to be unable to fulfill the portion of the Call Quantity. Any such refusal with respect to a Call Quantity, for each Settlement Period, shall be limited to the Decline Quantity Cap. In the event the Decline Quantity Cap is reached, the Interval Call Quantity schedule shall immediately become effective in full force, PRODUCER shall immediately notify NIAGARA MOHAWK of any such refusal, the reason for such refusal and the Call Quantity refused. In the event of refusal due to -3-

4 unavailability NIAGARA Mohawk shall not be required to take the Minimum Capacity quantity. At the request of NIAGARA MOHAWK, PRODUCER shall provide evidence of such Unit unavailability or derate. Any exercise which is refused in accordance herewith shall be deemed not to have been exercised to the extent of the Call Quantity so refused. Call Quantities shall be subject to the following limitations: (i) no individual Unit Call Quantity nomination schedule can change by more than its response rate (set forth in Schedule A hereto); (ii) Minimum Capacity and Minimum Down Time Times (set forth in Schedule A hereto), must be adhered to in the nomination for Call Quantities (e.g. to adhere to the Minimum Down Time, if a Call Quantity is scheduled to zero, the Call Quantity cannot exceed zero again until the Minimum Down Time is met, (iii) the Call Quantity for an Interval is limited to the Maximum Capacity set forth in Schedule A hereto, (iv) the aggregate calendar year Call Quantity limit cannot exceed the amount set forth in Schedule B. Call Option Exercise Procedure: Schedule D shall be deemed to be the Call Quantity. For Settlement Periods beyond September 2001, NIAGARA MOHAWK shall have the right to amend Schedule D for each Capability Period with a written notice one month prior to each Capability Period. Such Schedule D amendment shall not change the aggregate Call Quantity for (i) any Capability Period (ii) any calendar year. For any Call Quantity refused by producer NIAGARA MOHAWK shall have the right to make up such quantities by the following procedure. NIAGARA MOHAWK may exercise the Call Option with respect to any Interval by delivery of an exercise notice to PRODUCER (which may be delivered orally, including by telephone). Any such notice shall specify the relevant Interval and Call Quantity (in MWh), and shall be given prior to 5:00 PM (New York time) on the Friday preceding the -4-

5 week in which such Interval occurs. A week shall consist of the period commencing with the hour ending at 0100 on Monday, New York time and ending with the hour ending at 2400 on Sunday, New York time. If any notice is delivered orally, NIAGARA MOHAWK will execute and deliver a written confirmation confirming the substance of that notice within two Business Days of that notice. Failure to provide that written confirmation will not affect the validity of that oral notice. 4. Definitions: "Ancillary Services Payment": For each Settlement Period means an amount equal to a Portion (as defined below) of the payments which NIAGARA MOHAWK makes to the NYISO during such Settlement Period for Ancillary services (including, specifically, reactive supply and voltage support, regulation and frequency response, and operating reserves). The Portion of such payments for each Settlement Period shall be equal to the product of (X) the ratio of the Call Quantity during such Settlement Period divided by the public sales of NIAGARA MOHAWK times (Y) the payments which NIAGARA MOHAWK makes to the NYISO for such ancillary services. "Call Amount": Shall have the meaning defined in PRODUCER Call Amount and NIAGARA Call Amount. "Call Fee - Stage 1": For each Settlement Period means an amount for the applicable Unit and Settlement Period determined by the Calculation Agent based on Schedule C hereto. "Call Fee - Stage 2": For each Interval during which the Call Option is exercised, an amount for the applicable Unit and Interval determined by the Calculation Agent based on Schedule C hereto; provided that (i) a warm start Call Fee - Stage 2 shall apply, and a cold start Call Fee shall not apply, with respect to an Interval if the Call Option has been exercised and the Call Quantity was zero for the preceding Intervals but was greater than zero for any Interval during the preceding 10 Intervals, and (ii) a cold start Call Fee - Stage 2 shall apply, and warm start Call Fee - Stage 2 shall not apply, if the Call Option has been exercised and the Call Quantity was zero for the preceding 10 Intervals. Notwithstanding the above, a Call Fee - Stage 2 shall not apply if the Call Option was exercised in the preceding interval. "Call Quantity": Shall have the meaning described in Article 3 on page 3. -5-

6 "Capability Period": Shall mean each of two six-month intervals whereby the winter capability period includes the calendar months of November through April and the summer capability period includes the calendar months of May through October. "Capacity": For each Interval means the amount of capacity set forth in Schedule A hereto under the column entitled Max Capacity. "Capacity Payment": For each Interval means the Market Capacity Price in $/MW multiplied by the Capacity for such Interval. "Decline Quantity Cap": For each Settlement Period, the PRODUCER's right to decline the Call Quantity due to unexpected forced outage or derate shall be limited on a previous six-Scheduled Quantity Month basis. The Decline Quantity Cap is defined as the Maximum Capacity set forth in Schedule A times the Intervals that make up the previous six Scheduled Quantity Months (adjusted for leap year) times the Equivalent Forced Outage Rate ("EFOR") set forth in Schedule A. The declined quantity shall be calculated on a rolling Interval basis during the previous six-Scheduled Quantity Months (for example, hour ending 1400 on February 15, last year through hour ending 1300 February 15, this year including all of the Scheduled Quantity Months). Furthermore, it is understood that on the Closing Date, it shall be deemed that the previous six-Scheduled Quantity Months have an EFOR as listed in Schedule A. "Interval": one hour. "Market Capacity Price": Shall equal zero at any time when (i) no separate market for capacity exists, or (ii) capacity obligations for load serving entities cease to exist in the NYISO Tariff. Commencing on the first day of the month following the calendar month in which the NYISO is initially established and operating and only if there then exists a separate market for capacity, the Market Capacity Price shall mean the price paid to producers or by load serving entities for capacity at the respective generator plant bus- bar location, established by the most recent NYISO capacity auction. N E [P(i) * V(i))/H(i)] |-| $/MWh(1) = ___________ _________________________ (1) As an example, consider three tranches: (1) 2,100 MW at $1,000/MW per month, (2) 2,000 MW at $2,700/MW per 3-month, (3) 6,000 MW at $6,600/MW per 6-month. The resultant price is equal to the following: $/MWh = { ($1,000/MW*2,100 MW)/720 hr =$1.43/MWh + ($2,700/MW*2,000 MW)/2,160 hr + ($6,600/MW*6,000 MW)/4,380 hr} _________________________ -6-

7 N E [V(i)] |-| where: "N" is the number of individual Capacity Tranches sold at auction; "P(i)", is the sales price (in S/MW) of the ith Capacity Tranche sold at auction; "H(i)", is the capacity entitlement (in hours) corresponding to the ith Capacity Tranche sold at auction; "V(i)", is volume of Capacity (in MW) in the Capacity Tranche sold at auction; and "Capacity Tranche" means an individual block of auction dates and hours of capacity entitlement. Prior to the establishment of the Market Capacity Price, and if capacity obligations for load serving entities exist in the NYISO Tariff then NIAGARA MOHAWK shall retain the right to claim the Capacity, and PRODUCER must provide such Capacity, for NIAGARA MOHAWK's capacity requirements to the NYISO. In the event the PRODUCER is unable to provide Capacity acceptable to the NYISO in the amount claimed by NIAGARA MOHAWK from its own sources, the PRODUCER must procure the CAPACITY from the market and provide it to NIAGARA MOHAWK at no cost to NIAGARA MOHAWK. In the event the PRODUCER fails to provide such Capacity, PRODUCER shall be charged a penalty equivalent to the greater of (i) the penalty rate assessed by the NYISO, or (ii) the capacity rate component of NIAGARA MOHAWK's Service Classification Number 6 Tariff. "Market Price": Means for any Interval commencing on the first day of the month following the calendar month in which the NYISO Establishment Date occurs, the day ahead locational based market price ("LBMP") paid to producers for energy, at the Unit's bus bar or the region in which the Unit's bus bar is located, specified and published by the NYISO. "NIAGARA MOHAWK Call Amount": For each Interval during which the Call Option is exercised, an amount equal to the product of the Call Quantity for such Interval multiplied by the Fixed Price ("P") for such Interval set forth in Schedule C hereto. "NYISO" is the New York Independent System Operator which operates the bulk power electric system pursuant to the FERC approved tariff which was filed by the - -------------------------------------------------------------------------------- (2,100 MW + 2,000 MW + 6,000 MW) -7-

8 members of the New York Power Pool on December 19, 1998. "PRODUCER Call Amount": For any Interval during which the Call Option is exercised, an amount equal to the product of the Call Quantity for such Interval multiplied by the Market Price for such Interval. "PSC": Shall mean the New York Public Service Commission. "Scheduled Quantity Month": Shall mean any calendar month in which a Call Quantity is pre-scheduled pursuant to Schedule D; specifically the calendar months of June, July, August, December, January, February, and the month of March during the year 1999, and 2000 for Huntley, but excluding the month of December during the year 2002 for Dunkirk. "Unit": Shall be PRODUCER's electric generating units as shown in Schedule A. 5. Further Assurances Subject to the terms and conditions contained herein, upon the request from time to time of either party hereto, the other party shall promptly execute and deliver or use its reasonable best efforts to cause to be executed and delivered, such consents, approvals and other instruments, including, without limitation, assignments of this Transaction as collateral, estoppel certificates and utility certificates, in form and substance reasonably satisfactory to both parties and their respective counsel to implement any financing or other material business transaction undertaken by the requesting party. 6. Account Details: Account Details of NIAGARA MOHAWK: Bank name: Citibank Address: 399 Park Avenue New York, New York 10022 ABA #: Account name: Niagara Mohawk Power Corporation Account #: Account Details of PRODUCER: Bank name: LaSalle National Bank Address: Chicago, IL ABA #: Account name: NNRG Power Marketing Inc. Account #: -8-

9 Please confirm that the foregoing correctly sets forth the terms of our agreement by executing the copy of this Confirmation enclosed for that purpose and returning it to us or by sending to us. Yours sincerely, NIAGARA MOHAWK POWER CORPORATION By: Clement Nadeau --------------------------------------- Name: CLEMENT NADEAU Title: Vice President Confirmed as of the date first above written: NRG POWER MARKETING INC. By: James J. Bender --------------------------- Name: James J. Bender Title: Vice President -9-

1 EXHIBIT 10.35 STANDARD OFFER SERVICE WHOLESALE SALES AGREEMENT THIS STANDARD OFFER SERVICE WHOLESALE SALES AGREEMENT ("Agreement") dated as of October 29, 1999, is by and between THE CONNECTICUT LIGHT AND POWER COMPANY ("CL&P" or "Buyer") and NRG POWER MARKETING INC. ("Seller"). The Seller and Buyer together are the Parties and each individually is a Party to this Agreement. WITNESSETH: WHEREAS, pursuant to Section 20(b) of Public Act 98-28, An Act Concerning Electric Restructuring ("Act"), the Buyer must procure generation for the purpose of providing Standard Offer Service to those end use consumers of electricity within its traditional retail service area ("Retail Customers") that do not or are unable to choose an Electric Supplier (as defined in Section 1(30) of the Act); WHEREAS, by Order dated July 7, 1999, in Docket No. 99-03-36, the Connecticut Department of Public Utility Control ("DPUC") approved, with certain modifications, the Buyer's proposal to issue a competitive bid solicitation, or Request For Proposals, for generation service to supply fifty percent of the Buyer's Standard Offer Service Load ("the RFP"); WHEREAS, the DPUC has retained J.P. Morgan Securities, Inc. ("J.P. Morgan") to act as the exclusive agent to the DPUC to conduct the RFP; WHEREAS, J.P. Morgan carefully evaluated the responses to the RFP, including the response submitted by the Seller, and advised that the Seller is a qualified bidder pursuant to the RFP, and that the Seller's offer to supply a portion of the Standard Offer Service Load meets the standards for selection in the RFP, subject to negotiating an acceptable agreement to supply Standard Offer Service; WHEREAS, this Agreement sets forth the rates, terms and conditions under which the Seller will supply firm all-requirements service as necessary to serve a specified share of the Buyer's aggregate retail load that takes Standard Offer Service during the term of this Agreement; NOW, THEREFORE, in consideration of the premises and of the mutual agreements herein contained, the Parties to this Agreement covenant and agree as follows: 1. DEFINITIONS

2 As used throughout this Agreement, the following terms shall have the definitions set forth in this Article 1. 1.1 "BACK-UP SERVICE" means generation services provided to any Retail Customer that has entered into a service contract with an alternative supplier who, in turn, fails to provide generation services to such Retail Customer other than due to the Retail Customer's failure to pay for such services. 1.2 "CONTRACT LOAD QUANTITY" means the portion of the Standard Offer Service Load, defined as a monthly total, for which the Seller is obligated to supply SOS Requirements Power pursuant to Section 3.5 of this Agreement. The Contract Load Quantity shall be calculated in accordance with Appendix A. 1.3 "DELIVERY POINT" means any point on the NEPOOL PTF, or one or more other points of interconnection between the Buyer's transmission or distribution system and generating assets owned or contracted for by the Seller, where Seller delivers SOS Requirements Power to the Buyer, and at which point title to and liability for electricity passes from the Seller to the Buyer; provided, however, that the Seller shall assume all of the risk that it will not obtain NEPOOL credit for power that is not delivered to the NEPOOL PTF; and provided further that, from the standpoint of the rights and benefits received by the Buyer under this Agreement, all power delivered hereunder shall be treated in the same manner as if the power had been delivered to the NEPOOL PTF. 1.4 "DELIVERY SERVICES" means the combination of Regional Network Service ("RNS") over NEPOOL PTF acquired pursuant to the NEPOOL Transmission Tariff, Local Network Service ("LNS") over the Buyer's Non-Pool Transmission Facilities pursuant to the NU Operating Companies open access transmission tariff, and firm distribution services under the Buyer's distribution service tariff that are provided by the Buyer for the delivery of SOS Requirements Power for the Contract Load Quantity. Delivery Services shall not include losses, congestion charges, ancillary services or any ISO charges associated with SOS Requirements Power, all of which shall be the responsibility of the Seller. 1.5 "ISO" means ISO New England, Inc., the Independent System Operator for the NEPOOL Control Area, or any successor thereto. 1.6 "MATERIAL ADVERSE EFFECT" as used in Sections 10.1 and 10.2 means any change in, or effect on the Buyer or Seller after the date of this Agreement and prior to the Effective Date that is materially adverse to any of the transactions contemplated hereby, other than (i) any change or effect resulting from changes in the international, national, regional or local wholesale or retail markets for electric power; (ii) any change or effect -2-

3 resulting from changes in the international, national, regional or local wholesale or retail markets for any fuel used by the Seller; (iii) any change or effect resulting from changes in the North American, national, regional or local electric transmission systems; (iv) any change or effect resulting from any action or inaction by a legislative or regulatory authority, other than failure of any state or federal governmental authority or commission to give any consent or approval. 1.7 "NEPOOL" means the New England Power Pool, the power pool created by and operated pursuant to the provisions of the Restated NEPOOL Agreement, as such agreement may be amended from time to time. 1.8 "NEPOOL CONTROL AREA" means the geographic area in which the ISO is responsible for maintaining transmission lines within established security limits and for balancing the sum of internal generation and net interchange with the control area load at all times in order to maintain system stability, reliability and frequency within acceptable limits. 1.9 "NEPOOL PTF" means the facilities categorized as Pool Transmission Facilities as defined in the Restated NEPOOL Agreement. 1.10 "SOS REQUIREMENTS POWER" means the firm wholesale power that Seller is obligated to deliver as defined in Section 3.1. 1.11 "SOS SUPPLIER BILLING AMOUNT" means the monthly billing quantity as determined in accordance with Appendix A. 1.12 "STANDARD OFFER SERVICE" OR "SOS" means the electric service provided in accordance with Section 20(b) of the Act and the implementing rules and regulations of the DPUC to those Retail Customers of the Buyer that do not purchase electricity from an Electric Supplier. 1.13 "STANDARD OFFER SERVICE LOAD" means the aggregate consumption of all of CL&P's Standard Offer Service customers plus the aggregate electric losses for delivery from a Delivery Point to the end-use meters of all such customers as determined in accordance with Appendix A. 1.14 "TERM" means the period during which the Seller is obligated to supply SOS Requirements Power pursuant to this Agreement. The Term shall be for four (4) calendar years commencing at the hour ending 0100 on January 1, 2000, and terminating at the hour ending at 2400 on December 31, 2003, unless this Agreement is terminated earlier pursuant to its terms. 1.15 "TRANSITION AGREEMENT" means the Agreement for Transition Power Supply between and among The Connecticut Light And Power Company, NRG Energy, Inc., NRG Power Marketing Inc., Montville Power LLC, -3-

4 Middletown Power LLC, Devon Power LLC, Norwalk Power LLC, and Connecticut Jet Power LLC, pursuant to which the parties to such agreement have arranged for the Buyer to acquire rights to power between the date of closing of the sale of certain of the Seller's generating assets to NRG Energy, Inc. and the commencement of SOS, or for the Seller to acquire rights to power from the date of commencement of SOS to the date of closing of the sale of such CL&P generating assets to NRG Energy, Inc. 2. EFFECTIVE DATE AND FILING 2.1 This Agreement shall be binding on the Parties as of the date it is executed by both Parties ("Effective Date"); provided that the provision of SOS Requirements Power by the Seller shall be subject to obtaining necessary regulatory authorizations for providing such service. Promptly after execution hereof, the Seller shall file this Agreement with the Federal Energy Regulatory Commission ("FERC") and shall request that the FERC accept this Agreement for filing without modification or condition, with service hereunder to be effective commencing on January 1, 2000. The Buyer shall support such filing. In addition, the Buyer shall, promptly after execution hereof, submit this Agreement to the DPUC for its approval as set forth in the RFP. The Seller shall bear the cost of the FERC filing described above except for the costs associated with the Buyer's intervention. The Buyer shall bear the cost of the DPUC filing described above except for the cost of the Seller's intervention. In each case, the Party responsible for filing this Agreement shall request that the regulatory agency give confidential treatment to the pricing terms of this Agreement, which are the result of a competitive solicitation held by the Buyer. 2.2 In the event that the FERC or the DPUC grants conditional approval of this Agreement, compliance with which would create a material adverse economic impact on a Party, the adversely affected Party may seek to negotiate such changes to this Agreement as may be necessary to restore the balance of consideration hereunder while simultaneously complying with the FERC and DPUC orders. If the Parties are unable to negotiate such changes that are satisfactory to each Party within five (5) business days after the FERC or DPUC order, either Party shall have the right to terminate this Agreement by giving five (5) days written notice to the other Party, in which event the Agreement shall be null and void and of no further force and effect from and after the date of termination. In the event that the FERC or the DPUC does not accept the changes negotiated by the Parties hereunder, either Party shall have the right to terminate this Agreement upon thirty (30) days' written notice to the other Party, in which event the Agreement shall be null and void and of no further force and effect from and after the date of termination. -4-

5 2.3 The applicable provisions of this Agreement shall continue in effect after expiration of the Term (or earlier termination as provided herein) to the extent necessary to provide for final accounting, final billing, billing adjustments, resolution of any billing dispute, resolution of any court or administrative proceeding and final payments. 3. SALE AND PURCHASE OF SOS REQUIREMENTS POWER 3.1 SOS Requirements Power is the wholesale power delivered at the Delivery Point(s) that is supplied at all times and in quantities reflecting the full requirements for power of Retail Customers purchasing Standard Offer Service from CL&P. SOS Requirements Power shall be firm and shall vary in quantity from minute to minute, hour to hour, day to day and month to month based on the consumption patterns of Retail Customers. SOS Requirements Power includes power supply and ancillary services, in such amounts as are required for the Buyer to serve the Contract Load Quantity plus losses at all times throughout the Term. SOS Requirements Power includes all of the power supply and ancillary services that are or may be necessary to serve electrical load under the Restated NEPOOL Agreement during the Term, including Energy, Installed Capability, Operable Capability, Operating Reserves, Automatic Generation Control, electrical losses, congestion charges imposed under the NEPOOL Transmission Tariff, charges of the ISO associated with NEPOOL membership and with serving the Contract Load Quantity, and any future additions, deletions or changes to the seven NEPOOL products (Energy, Installed Capability, Operable Capability, 30-minute Non-Spinning Operating Reserves, 10-Minute Spinning Reserves, 10-Minute Non-Spinning Reserves, and Automatic Generation Control) that are required for entities serving electrical load in NEPOOL. SOS Requirements Power shall also include such transmission and distribution delivery services as may be required for the Seller to deliver SOS Requirements Power to the Delivery Point(s). SOS Requirements Power shall not include any current or future requirement to meet a renewable energy portfolio standard in the State of Connecticut. 3.2 The Seller shall deliver and sell to Buyer at a Delivery Point the Contract Load Quantity. The billing determinants on which payment to Seller is based shall be determined in accordance with Appendix A. 3.3 The Buyer shall receive and purchase power delivered by Seller in accordance with this Section 3. 3.4 The Seller shall own or procure sufficient firm power supplies and ancillary services to provide SOS Requirements Power throughout the Term, and shall schedule all such power supplies and ancillary services with the ISO -5-

6 for use by the Buyer in accordance with the provisions of the Restated NEPOOL Agreement (including future amendments thereto) and the applicable operating procedures of the ISO. The Seller shall be responsible for all transmission and distribution delivery costs, if any, required to deliver SOS Requirements Power to the Delivery Point(s). 3.5 The Contract Load Quantity shall be equal to thirty-five (35) percent of the Standard Offer Service Load during calendar year 2000, forty (40) percent of the Standard Offer Service Load during calendar years 2001 and 2002, and forty-five (45) percent of the Standard Offer Service Load during calendar year 2003. 3.6 The Buyer shall procure or arrange for Delivery Services in order to accomplish the firm delivery of SOS Requirements Power from the Delivery Point(s) to the Retail Customers taking SOS Requirements Power throughout the Term; provided that the Buyer's obligation to supply Delivery Services at and from the Delivery Point(s) with respect to any particular generating resource of the Seller shall be subject to the availability of transmission service for such delivery under the NEPOOL Transmission Tariff. 3.7 For the entire Term, the Seller shall either (1) be a member of NEPOOL with its own load and settlement account established in accordance with the rules of the ISO, or (2) contract with a NEPOOL member for such member to include the Seller's load in its own load and settlement account. 3.8 The Seller and Buyer shall comply with the procedures, rules and regulations of the ISO and NEPOOL and the requirements of the Restated NEPOOL Agreement as they may apply to the purchase, sale and delivery of SOS Requirements Power. 3.9 The Seller shall be responsible for forecasting the Contract Load Quantity for purposes of meeting its supply obligation hereunder on a monthly, daily and hourly basis, for the full Term of the Agreement. The Buyer's most recent forecasts of energy sales and peak demand for its service area are set forth in Appendix B for informational purposes. The Buyer will supply the Seller with (1) any updates or material changes to such forecasts made during the Term, (2) on a weekly basis, the actual number of customers on Standard Offer Service broken down by customer segment to the extent known, for the previous week, and (3) within 37 hours after the close of the day, the same supplier hourly loads the Buyer submitted to the ISO on behalf of the Seller. 3.10 The Seller shall be responsible for and shall pay all ISO and NEPOOL charges and expenses associated with the provision of SOS Requirements Power, except for any such ISO or NEPOOL charges that -6-

7 are imposed directly on the Buyer in connection with the provision of Delivery Services by the Buyer. 3.11 The Seller shall be responsible for and shall pay all taxes, fees, and levies that may be assessed by any entity in connection with the provision of SOS Requirements Power except for (1) such taxes, fees and levies that Buyer is allowed to collect directly from the Retail Customers, and (2) such taxes, fees and levies that are assessed directly to the Buyer in connection with the provision of Delivery Services. 3.12 If and to the extent that, at any time during the Term, the congestion management scheme in effect under the NEPOOL Transmission Tariff provides for the automatic assignment of rights to rebates of transmission congestion charges to retail loads of the Buyer, the Seller shall be entitled to a portion of such congestion rebate rights based on the ratio between the Contract Load Quantity and the Buyer's retail load that is subject to the automatic assignment of such rights. 4. CHARGE PROVISIONS 4.1 For and in consideration of the sale by the Seller to the Buyer of SOS Requirements Power, the Buyer shall pay the per unit charges set forth in the Table below for all SOS Requirements Power supplied to Retail Customers during the Term of this Agreement. The monthly quantity of SOS Requirements Power to which the unit charges set forth herein shall be applied for billing purposes, shall be the SOS Supplier Billing Amount: NRG POWER MARKETING Table of Load Percentages and Charges - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 5% LOAD 2000 2001 2002 2003 SHARE* (CENTS PER KWH) (CENTS PER KWH) (CENTS PER KWH) (CENTS PER KWH) - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 1ST - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 2ND - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 3RD - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 4TH - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- -7-

8 - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 5TH - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 6TH - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 7TH - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 8TH - - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 9TH - - - - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 10TH - - - - - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- 4.2 The charges set forth in Section 4.1 are the result of a competitive bid solicitation and shall apply for the entire Term unless both Parties agree to a change in charges set forth in a written amendment to the Agreement that is accepted for filing by the FERC. Nothing in this Section 4.2 is intended to modify Sections 2.2, 4.5, or 9.3 of this Agreement. 4.3 It is the intent of the Parties that, except as provided in Sections 4.5 and 9.3, or as the Parties otherwise agree, neither the Seller and its affiliates nor the Buyer and its affiliates shall have the unilateral right to make a filing with the FERC under any Section of the Federal Power Act, or with the DPUC, seeking to change the charges or any other terms or conditions set forth in this Agreement for any reason. 4.4 Neither Party shall instigate or cooperate with any effort of third parties to petition the FERC or the DPUC to change any term of the Agreement (which includes the charges and quantities). If any third party nevertheless petitions the FERC or the DPUC to establish a proceeding under Section 206 of the Federal Power Act, both Parties shall cooperate to seek to dismiss such proceeding and to uphold the Agreement without change. It is the intention of the Parties that any authority of the FERC or the DPUC to change the Agreement be strictly limited to that which applies when the contracting parties have irrevocably waived their right to seek to have the FERC or the DPUC change any term of this Agreement. 4.5 In the event that the DPUC modifies the rules relating to the provision of Standard Offer Service during the Term, or Connecticut enacts legislation that has the affect of modifying the provisions of the Act relating to Standard Offer Service, and such DPUC or legislative modifications would materially adversely affect the rights and responsibilities of either Party under this Agreement, the Party that believes it would be materially adversely affected by such modifications may request that the DPUC take action to protect the interests of such Party. If the DPUC does not provide relief satisfactory to such Party within sixty (60) days from the date of filing of the request, the Parties shall enter into good faith negotiations to amend this Agreement in a manner designed to restore the original -8-

9 balance of consideration set forth herein. In the event that the Parties are unable to reach agreement on such revisions to this Agreement: (1) the Seller, if it is the adversely affected Party, shall have the right unilaterally to make a filing with the FERC pursuant to Section 205 of the Federal Power Act and the FERC's rules and regulations thereunder, and (2) the Buyer, if it is the adversely affected Party, shall have the right to make a filing under Section 206 of the Federal Power Act, seeking such changes to this Agreement, including termination hereof, as such Party deems necessary due solely to the DPUC's change or the new legislation. In the case of any such filing, the other Party shall have the right to intervene in opposition to the filing. 4.6 Upon request of the Buyer, the Seller shall, within three (3) business days, submit a firm price quote for no less than a pro rata share of the Buyer's Back-Up Service requirements, with such pro rata share based on the ratio of the Contract Load Quantity to the Buyer's Standard Offer Service Load, and which quote shall be binding on the Seller for a period of no less than a calendar month. If the Buyer accepts the Seller's price quote during such calendar month period for any portion of the amount of Back-Up Service covered by the quote, the Seller shall supply additional SOS Requirements Power in accordance with its price quote and the remaining terms and conditions of this Agreement. 5. BILLING AND PAYMENT 5.1 As soon as practicable after the end of each month during the Term, the Buyer shall supply the Seller its estimate of the SOS Supplier Billing Amount for purposes of billing hereunder. Within ten (10) days thereafter, the Seller shall submit a bill to the Buyer for all applicable charges hereunder based on such estimates. 5.2 Each bill rendered under this Agreement shall be subject to adjustment in order to true-up charges based on estimated SOS Supplier Billing Amount data to the adjusted SOS Supplier Billing Amount, as defined in Appendix A. Promptly after the adjustment to SOS Supplier Billing Amount has been determined, the Buyer shall supply the adjusted SOS Supplier Billing Amount to the Seller in order to enable the Seller to calculate the final bill for SOS Requirements Power for each month during the Term. The Seller shall prepare and send to the Buyer an adjusted bill within ten (10) days after receiving the adjusted SOS Supplier Billing Amount data from the Buyer. All refunds or surcharges owed to either Party as a result of differences between the estimated and adjusted SOS Supplier Billing Amounts shall include the payment of interest calculated in accordance with the regulations of the FERC applicable to the payment of interest on -9-

10 refunds for the entire period between payment under the original estimated bill and the final bill. 5.3 All bills, including any adjusted bills, shall bear the date of rendering and be due and payable not later than thirty (30) days after the date of rendering. Any amount remaining unpaid after such thirty (30) days shall bear interest at the rate set forth in the regulations of the FERC for interest payments on refunds, from the due date to the date of payment by the Buyer. All payments sent by the Buyer to the Seller shall be by wire transfer or by certified check delivered using overnight mail. 5.4 If the Buyer disputes the amount of any bill, it shall so notify the Seller in writing. The Buyer shall pay to the Seller any undisputed amount of the bill when due. The disputed amount may, at the discretion of the Buyer, be held by the Buyer until the dispute has been resolved; provided that the Buyer shall be responsible to pay interest on any withheld amounts that are determined to have been properly billed, which shall be calculated in the same manner as interest on late payments under Section 5.3. Neither Party shall have the right to challenge any monthly bill or to bring any court or administrative action of any kind questioning the propriety of any bill after a period of twenty four (24) months from the date the bill was due; provided, however, that in the case of a bill based on estimates, such twenty-four month period shall run from the due date of the final adjusted bill. 5.5 In the event that the Buyer fails to pay the amount due by the due date, the Seller may notify the Buyer that, unless payment is received, it will be in default of its obligations under this Agreement. The Buyer shall have thirty (30) days from the date of receipt of such notification from the Seller to cure its default. In the event that the default is not cured within such 30 day period, the Seller, in addition to any other legal or equitable remedies it may have, shall have the right to terminate this Agreement upon five (5) days written notice to the Buyer. 6. BILLING DETERMINANTS/SUPPLY OBLIGATION 6.1 The Buyer shall maintain meters capable of measuring the energy use of Retail Customers taking SOS in accordance with rules prescribed by the DPUC. The accuracy of all metering equipment will be in accordance with the Buyer's normal practices and DPUC requirements applicable to the Buyer's retail distribution loads. The Seller hereby acknowledges and accepts that Buyer does not maintain meters capable of interval measurement for some of its retail load that will be served under the SOS. The price, risk and other terms of this Agreement have been negotiated based upon these conditions and Buyer shall not be obligated to install -10-

11 interval metering equipment as a result of this Agreement. The Parties agree that the obligation of the Buyer to pay for power delivered and the obligation of the Seller to deliver a specified quantity at an authorized Delivery Point shall be determined in accordance with Appendix A. 7. LIABILITY FOR DELIVERY AND FORCE MAJEURE 7.1 The Seller shall be responsible for scheduling with or purchasing from NEPOOL a sufficient amount of SOS Requirements Power to satisfy its service obligations hereunder at all times during the Term. To the extent that the Seller does not own or has not acquired sufficient resources to satisfy this obligation at any time during the Term, the Seller shall purchase any deficiency from NEPOOL. Under no circumstances shall the Buyer be responsible for acquiring power or ancillary services to meet any portion of the Seller's SOS Requirements Power supply obligation hereunder at any time during the Term. 7.2 In the event that the Seller defaults on its material obligations to the Buyer or NEPOOL in connection with this Agreement at any time during the Term, and the Seller does not cure such default within a time period allowed by NEPOOL and ISO-NE (but not to exceed ten (10) days if there is no explicit NEPOOL or ISO-NE period for curing the default), the Buyer shall have the option to terminate or suspend all or a portion of service under this Agreement upon no less than twenty four (24) hours notice and obtain an alternative source of supply of SOS Requirements Power from the open market for the remaining Term. In such event, the Seller shall be liable to the Buyer for the entire difference between the cost of such alternative source of supply obtained in the open market and the cost of purchasing SOS Requirements Power under this Agreement, plus all other costs reasonably incurred by the Buyer to replace the Seller. The Parties hereby stipulate that purchases by the Buyer at the applicable ISO-NE spot market prices will be deemed commercially reasonable open market prices for this purpose. Nothing in this Section 7.2 shall be deemed as a waiver of any other legal or equitable remedies that the Buyer may have against the Seller for breach of this Agreement. 7.3 In the event that the Buyer defaults on its material obligations to the Seller or NEPOOL in connection with this Agreement at any time during the Term, and the Buyer does not cure such default within a time period allowed by NEPOOL and ISO-NE (but not to exceed ten (10) days if there is no explicit NEPOOL or ISO-NE period for curing the default), the Seller shall have the option to terminate or suspend all or a portion of service under this Agreement upon no less than twenty four (24) hours notice and thereafter sell any of the resources it has obtained in order to meet its obligations under this Agreement in the open market. In such event, the -11-

12 Buyer shall be liable to the Seller for the entire difference between the prices obtained by the Seller in the open market and the price the Seller would have obtained for selling SOS Requirements Power under this Agreement. The Parties hereby stipulate that sales by the Seller at the applicable ISO-NE spot market prices will be deemed commercially reasonable open market prices for this purpose. Nothing in this Section 7.3 shall be deemed as a waiver of any other legal or equitable remedies that the Seller may have against the Buyer for breach of this Agreement. 7.4 Notwithstanding any other provision of this Agreement, neither Party shall be liable to the other Party in the event that, due to a cause beyond the reasonable control of, and without the fault or negligence of the Party seeking to limit its liability hereunder ("Force Majeure"), NEPOOL experiences unplanned-for emergency system conditions, including but not limited to a shortage of available electric generating capacity or an insufficiency of transmission or distribution facilities required for the delivery of SOS Requirements Power, such that NEPOOL either must suspend the supply of one or more of the products required to serve load in NEPOOL or must curtail or interrupt all or a portion of the Standard Offer Service Load. 7.5 For purposes of Section 7.4, "Force Majeure" shall include, without limitation, sabotage, strikes, riots or civil disturbance, acts of God, act of a public enemy, drought, earthquake, flood, explosion, fire, lightning, landslide, or any similar cataclysmic occurrence, or the appropriation or diversion of electricity by sale or order of any governmental authority having jurisdiction thereof. Under no circumstances shall Force Majeure include an occurrence or event that merely increases the costs of or causes an economic hardship to a Party, or any occurrence or event that was caused by or contributed to by the Party claiming Force Majeure. 7.6 Except as otherwise specifically provided for herein, neither Party shall be liable to the other Party for any special, indirect, incidental, consequential, or punitive damages of any kind, including but not limited to loss of use, out of pocket expenses and lost profits (past or future). 8. BUYER CREDIT/SECURITY ASSURANCES 8.1 NRG Energy, Inc. has provided the Buyer a certificate executed by an officer of NRG Energy, Inc. certifying that NRG Energy, Inc. has entered into a firm wholesale entitlements contract ("Entitlement Agreement") with the Seller for the full Term of this Agreement, pursuant to which the Seller has acquired from NRG Energy, Inc. firm, first-call entitlement rights to no less than 1,600 MW of generating capacity located in the NEPOOL control area that are owned or controlled by NRG Energy, Inc. and has obtained, or will obtain, any regulatory or other approvals required to put -12-

13 the Entitlement Agreement into effect as of the commencement of the Term. Entitlements in generating units obtained by NRG Energy, Inc. pursuant to the Transition Agreement shall be considered generating capacity owned and controlled by the Seller for purposes of the prior sentence. The Entitlement Agreement shall provide the Seller with all of the rights to capacity, energy and ancillary services available from the generating units such that the Seller can satisfy its obligation to supply SOS Requirements Power for the full Term of this Agreement; provided, however, that the Seller may terminate the Entitlement Agreement if, during the Term, the Seller achieves an Unsecured Investment Grade Rating of "Baa3" or better from Moody's Investors Service or "BBB-" or better from Standard & Poors Corporation, or an equivalent credit rating by another nationally recognized rating service reasonably acceptable to the Buyer; and provided further, if the Seller is unable to maintain such Investment Grade Rating during the Term, it shall either promptly re-instate the Entitlement Agreement or promptly deliver to the Buyer a written parent guarantee, in a form acceptable to the Buyer, by NRG Energy, Inc. of the Seller's performance under this Agreement for the remaining Term hereof. 8.2 The Parties hereby acknowledge that NRG Energy, Inc. or another affiliate of Seller with an Unsecured Investment Grade Rating of "Baa3" or better from Moody's Investors Service or "BBB-" or better from Standard & Poors Corporation, or an equivalent credit rating by another nationally recognized rating service reasonably acceptable to the Buyer, has provided the Buyer a corporate guarantee in the amount of $37 million, which is equal to ten (10) percent of the dollar value for the first year of the awarded bid. The Seller shall cause NRG Energy, Inc. or another qualifying affiliate of Seller (as applicable) to keep such corporate guarantee in place for the full Term. 8.3 By no later than the date of commencement of the Term, the Buyer shall provide the Seller a performance or surety bond or other similar financial instrument in a form and from an issuer reasonably acceptable to the Seller in the amount of $37 million, unless the Buyer shall have obtained an Unsecured Investment Grade Rating of "Baa3" or better from Moody's Investors Service or "BBB-" or better from Standard & Poors Corporation, or an equivalent credit rating by another nationally recognized rating service reasonably acceptable to the Buyer, by such service commencement date. The Buyer shall be entitled to terminate such surety bond or other similar financial instrument immediately upon obtaining a Unsecured Investment Grade Rating of "Baa3" or better from Moody's Investors Service or "BBB-" or better from Standard & Poors Corporation, or an equivalent credit rating by another nationally recognized rating service reasonably acceptable to the Buyer. If the Buyer is unable to maintain such Unsecured Investment Grade Rating during the Term, it -13-

14 shall promptly re-instate such performance or surety bond or other financial instrument. 9. CONDITIONS 9.1 Conditions to Obligation of the Seller. The obligations of the Seller under this Agreement are subject to the fulfillment and satisfaction, on or prior to the Effective Date as defined in Section 2.1, of each of the following conditions, any one or more of which may be waived only in writing, in whole or in part, by the Seller: (a) Representations, Warranties and Covenants True at the Effective Date. (i) All representations and warranties of Buyer contained in this Agreement shall be true and correct in all material respects as of the date when made and at and as of the Effective Date as though such representations and warranties had been made or given on such date (except to the extent such representations and warranties specifically pertain to an earlier date), except (x) for changes contemplated by this Agreement and (y) where the failure to be true and correct will not have a Material Adverse Effect on the business, property, financial condition, results of operations or prospects of Buyer, or on the Seller's rights under this Agreement; (ii) Buyer shall have performed and complied with, in all material respects, its obligations that are to be performed or complied with by it prior to or on the Effective Date; and (b) No Material Adverse Effect. No Material Adverse Effect shall exist. 9.2 Conditions to Obligation of Buyer. The obligations of Buyer under this Agreement are subject to the fulfillment and satisfaction, on or prior to the Effective Date as defined in Section 2.1, of each of the following conditions, any one or more of which may only be waived in writing, in whole or in part, by Buyer: (a) Representations, Warranties and Covenants True at the Effective Date. (i) All representations and warranties of the Seller contained in this Agreement shall be true and correct in all material respects when made and at and as of the Effective Date as though such representations and warranties had been made or given on such date (except to the extent such representations and warranties specifically pertain to an earlier date), except (x) for changes contemplated by this Agreement and (y) where the failure to be true and correct will not have a Material Adverse Effect on the business, property, financial condition, results of operations or prospects of the Seller or Buyer's rights under this Agreement; (ii) the Seller shall have performed and -14-

15 complied with, in all material respects, its obligations that are to be performed or complied with by prior to or on the Effective Date; and (b) Absence of Material Adverse Effect. No Material Adverse Effect shall exist. 9.3 Special Condition Regarding Retail Rates. The DPUC has issued an order stating that it will set the General Services Component ("GSC") rates for Retail Customers taking Standard Offer Service after the negotiation of this Agreement, and that such GSC rates will be established by retail rate class. The Parties have agreed that the level of the GSC rates and distribution to each retail rate class could affect the Seller's expectations in submitting the prices set forth in Section 4.1 in response to the RFP. Accordingly, the Parties agree that, if the DPUC establishes GSC rates at levels which include an adjustment above the weighted average Standard Offer price that are in excess of the maximum rate adjustments set forth in the table below, the Seller shall have the right to seek to renegotiate the prices set forth in Section 4.1, solely as necessary to reflect the GSC rate adjustment exceeding the amounts in the table set forth below. The Parties agree that these adjustments in the table below reflect both a retail adder and a wholesale rate specific adjustment. The Parties further specifically agree that the Seller's right to seek a renegotiation of the prices set forth in Section 4.1 shall apply solely in the circumstance where the DPUC approves GSC rates for any rate class that are in excess of the weighted average Standard Offer price, plus the maximum rate adjustments set forth in the table below, and that this Section 9.3 creates no other right or remedy on behalf of the Seller. In retail restructuring proceedings before the DPUC, CL&P (1) shall not advocate the adoption of GSC rates that include adders above the weighted average Standard Offer price that are not cost-based, and (2) consistent with (1) above, shall request and advocate that the DPUC adopt retail GSC rates that include adders that are below those set forth in this Section 9.3. -15-

16 Table: - ------------------------- ---------------------- CL&P's Rate Proposed GSC Schedule No. Maximum Rate Adjustment - ------------------------- ---------------------- 1 - ------------------------- ---------------------- 5 - ------------------------- ---------------------- 7 - ------------------------- ---------------------- 18 - ------------------------- ---------------------- 27 - ------------------------- ---------------------- 29 - ------------------------- ---------------------- 30 - ------------------------- ---------------------- 35 - ------------------------- ---------------------- 40 - ------------------------- ---------------------- 41 - ------------------------- ---------------------- 55 - ------------------------- ---------------------- 56 - ------------------------- ---------------------- 57 - ------------------------- ---------------------- 58 - ------------------------- ---------------------- 115 - ------------------------- ---------------------- 116 - ------------------------- ---------------------- 117 - ------------------------- ---------------------- 985 - ------------------------- ---------------------- 119 - ------------------------- ---------------------- -16-

17 10. REPRESENTATIONS AND WARRANTIES 10.1 Each Party hereby represents and warrants to the other that: (a) It is duly organized, validly existing and in good standing under the laws of its jurisdiction of organization and is duly qualified to do business in all jurisdictions where such qualification is required. (b) It has full power and authority to enter this Agreement and perform its obligations hereunder. The execution, delivery and performance of this Agreement have been duly authorized by all necessary corporate action and do not and will not contravene its organizational documents or conflict with, result in a breach of, or entitle any Party (with due notice or lapse of time or both) to terminate, accelerate or declare a default under, any agreement or instrument to which it is a party or by which it is bound. The execution, delivery and performance by it of this Agreement will not result in any violation by it of any law, rule or regulation applicable to it. It is not a party to, nor subject to or bound by, any judgment, injunction or decree of any court or other governmental entity which may restrict or interfere with the performance of this Agreement by it. This Agreement is its valid and binding obligation, enforceable against it in accordance with its terms, except as (i) such enforcement may be subject to bankruptcy, insolvency, reorganization, moratorium or other similar laws now or hereafter in effect relating to creditors' rights generally and (ii) the remedy of specific performance and injunctive relief may be subject to equitable defenses and to the discretion of the court before which any proceeding therefor may be brought. (c) Except as otherwise specifically provided in this Agreement, no consent, waiver, order, approval, authorization or order of, or registration, qualification or filing with, any court or other governmental agency or authority is required for the execution, delivery and performance by such Party of this Agreement and the consummation by such Party of the transactions contemplated hereby and no consent or waiver of any party to any contract to which such Party is a party or by which it is bound is required for the execution, delivery and performance by such Party of this Agreement. (d) There is no action, suit, grievance, arbitration or proceeding pending or, to the knowledge of such Party, threatened against or affecting such Party at law or in equity, before any federal, state, municipal or other governmental court, department, commission, board, arbitrator, bureau, agency or instrumentality that prohibits or impairs its ability to execute and deliver this Agreement. Such Party has not received written notice of any such pending or threatened investigation, inquiry or review by any governmental entity. -17-

18 10.2 The Buyer hereby represents that it has not asserted and will not take during the term any position before the DPUC or FERC that is inconsistent with the rights and obligations of the Parties under this Agreement, provided that the foregoing will not prevent the Buyer from asserting or taking any position before such agencies which it reasonably believes is necesarry for it to meet applicable legal requirements. 11. ASSIGNMENT 11.1 Neither Party shall assign, pledge or transfer this Agreement without the prior written consent of the other Party, which consent shall not be unreasonably withheld. When assignable, this Agreement shall be binding upon, shall inure to the benefit of, and may be performed by, the successors and assignees of the Parties, except that no assignment, pledge or other transfer of this Agreement by either Party shall operate to release the assignor, pledgor, or transferor from any of its obligations under this Agreement unless the other Party (or its successors or assigns) consents in writing to the assignment, pledge or other transfer and expressly releases the assignor, pledgor, or transferor from its obligations hereunder. Notwithstanding the foregoing, either Party may transfer or assign its interest hereunder to an affiliate, or to a successor in interest of such Party by virtue of a merger, acquisition or other similar corporate transaction involving all or substantially all of the assets of the assigning Party, without obtaining the consent of the other Party, provided that the assignee has a credit status at the time of such transfer or assignment which, in the non-assigning Party's reasonable opinion, is at least as sound as that of the assignor. Nothing in the foregoing shall be construed as limiting the Seller's right to assign or otherwise transfer a security interest in the revenues generated under this Agreement to a third party, and Buyer expressly consents to such assignment for security interest purposes, provided that such assignment or transfer shall not limit in any way the Seller's obligations to the Buyer hereunder. 12. ACCOUNTS AND RECORDS 12.1 The Seller and Buyer each shall keep complete and accurate accounts and records with respect to its performance under this Agreement and shall maintain such data for a period of at least one (1) year after final billing for audit by the other Party; provided, however, that in the event of any billing dispute or pending accounting, all such accounts and records pertaining to any bill or charge in dispute or pending accounting shall be maintained until such later time as the billing dispute is resolved or the accounting is completed. If an accounting or billing dispute establishes -18-

19 that any bill submitted to and paid by Buyer was for an amount greater than properly chargeable under this Agreement, Seller shall refund to Buyer the excess amount collected together with interest calculated in accordance with the FERC's regulations governing interest on refunds. If such accounting or billing dispute establishes that any bill submitted to and paid by Buyer was for an amount less than properly chargeable under this Agreement, Buyer shall make such additional payment to bring its account into balance, together with interest calculated in accordance with the FERC's regulations governing interest on refunds. The Parties agree to individually and jointly request from NEPOOL or the ISO, or other appropriate source, any data or information which either Party believes is reasonably necessary for purposes of a requested accounting or resolution of a billing dispute. Each Party shall have the right, during normal business hours and at its own expense, to examine, inspect and make copies of all such accounts and records insofar as may be necessary for the purpose of ascertaining the reasonableness and accuracy of all relevant data, estimates or statement of charges submitted hereunder. The records supplied by the Buyer to the Seller for auditing purposes hereunder shall include the Buyer's hourly calculation of its Standard Offer Service Load. 13. INDEMNIFICATION 13.1 Indemnification by Buyer. Buyer shall indemnify, defend and hold harmless the Seller and the Seller's board members, officers, trustees, directors, agents, employees and affiliates from and against any and all claims, demands, liabilities (including reasonable attorney's fees), and judgments, fines, settlements and other amounts ("Damages") arising from any and all civil, criminal, administrative or investigative proceedings ("Claims") relating to or arising out of: (a) any failure of Buyer to observe or perform any material term or provision of this Agreement; (b) any failure of any representation or warranty made by Buyer herein to be true in any material respect; (c) any Claim of any third party to the extent arising from the acts or omissions of Buyer or any of its agents or employees except to the extent such acts or omissions are caused by the Seller or its affiliates; and (d) any bodily injury, death or damage to person or property caused by the Buyer and its affiliates and their respective board members, officers, managers, employees or agents or caused by their facilities, -19-

20 in each case in connection with or resulting from Buyer's performance or non-performance of this Agreement except to the extent caused by an act of negligence or willful misconduct of the Seller. 13.2 Indemnification by Seller. Seller shall indemnify, defend and hold harmless the Buyer and the Buyer's board members, officers, trustees, directors, agents, employees and affiliates from and against any and all claims, demands, liabilities (including reasonable attorney's fees), and judgments, fines, settlements and other amounts ("Damages") arising from any and all civil, criminal, administrative or investigative proceedings ("Claims") relating to or arising out of: (a) any failure of Seller to observe or perform any material term or provision of this Agreement; (b) any failure of any representation or warranty made by Seller herein to be true in any material respect; (c) any Claim of any third party to the extent arising from the acts or omissions of Seller or any of its agents or employees except to the extent such acts or omissions are caused by the Buyer or its affiliates; and (d) any bodily injury, death or damage to person or property caused by the Seller and its affiliates and their respective board members, officers, managers, employees or agents or caused by their facilities, in each case in connection with or resulting from Seller's performance or non-performance of this Agreement except to the extent caused by an act of negligence or willful misconduct of the Buyer. 14. NOTICES 14.1 Any notice, demand, or request permitted or required under this Agreement shall be delivered in person or mailed by certified mail, postage prepaid, return receipt requested, or otherwise confirm receipt to a Party at the applicable address set forth below. To Buyer: Director, Regulatory Policy and Planning Northeast Utilities Service Company P.O. Box 270 Hartford, CT 06141-0270 To Seller: -20-

21 Executive Director, Power Markets NRG Power Marketing Inc. 1221 Nicollet Mall, Suite 700 Minneapolis, MN 55403 Such addresses may be changed from time to time by written notice by either Party to the other Party without a need for an amendment to this Agreement. 15. INTERPRETATION 15.1 The interpretation and performance of this Agreement shall be according to and controlled by the Federal Power Act and regulations and orders of the FERC thereunder and, to the extent not controlled thereby, by the laws of the State of Connecticut. 16. RESOLUTION OF DISPUTES 16.1 Any dispute between the Parties involving service under this Agreement shall be referred to representatives of the Buyer and Seller designated by the Parties for resolution on an informal basis as promptly as practicable. In the event the designated representatives are unable to resolve the dispute within thirty (30) days, or such other period as the Parties may jointly agree upon, such dispute may, by mutual agreement of the Parties, be submitted to arbitration and resolved in accordance with the arbitration procedure set forth in the NEPOOL Transmission Tariff. If they do not agree to arbitration, each Party shall be free to pursue any legal and equitable remedies to which it may be entitled under this Agreement and the applicable law before a court or government agency with jurisdiction over the dispute. 17. MISCELLANEOUS 17.1 Each Party shall prepare, execute, and deliver to the other Party any documents reasonably required to implement any provision hereof. 17.2 Any number of counterparts of this Agreement may be executed and each shall have the same force and effect as the original. -21-

22 17.3 Failure of either Party to enforce any provision of this Agreement or to require performance by the other Party of any of the provisions hereof shall not be construed as a waiver of such provisions or affect the validity of this Agreement, any part hereof, or the right of either Party to thereafter enforce each and every provision. 17.4 This Agreement is made subject to all lawful orders of those state or federal regulatory bodies having jurisdiction hereof. 17.5 Nothing in this Agreement shall be construed as creating any relationship between the Parties other than that of independent contractor for the sale and purchase of electricity. 17.6 The captions to sections throughout this Agreement are intended solely to facilitate reading and reference to all sections and provisions of this Agreement. Such captions shall not affect the meaning or interpretation of this Agreement. 17.7 The invalidity or unenforceability of any provision of this Agreement shall not affect the other provisions hereof. If any provision of this Agreement is held to be invalid, such provision shall not be severed from this Agreement; instead, the scope of the rights and duties created thereby shall be reduced by the smallest extent necessary to conform such provision to the applicable law, preserving to the greatest extent the intent of the Parties to create such rights and duties as set out herein. If necessary to preserve the intent of the Parties hereto, the Parties shall negotiate in good faith to amend this Agreement, adopting a substitute provision for the one deemed invalid or unenforceable that is legally binding and enforceable. 17.8 The Buyer shall use reasonable efforts to supply the Seller with any orders of the DPUC that may affect the Seller's rights and obligations under this Agreement. Such orders shall be provided to the individual designated for receipt of notices pursuant to Section 14.1. 18. AMENDMENT 18.1 This Agreement may be amended only by a written agreement signed by the Parties. 19. COMPLETE AND FULL AGREEMENT -22-

23 19.1 This Agreement constitutes the entire agreement between the Parties and supersedes all previous offers, negotiations, discussions, communications and correspondence. 20. NOTICE OF TERMINATION 20.1 Upon expiration of the Term of this Agreement, Buyer will not oppose and, if Seller requests, Buyer will support, any notice of termination which Seller may be required to file under FERC regulations. 21. EARLY TERMINATION 21.1 In the event that the Transition Agreement terminates pursuant to and in accordance with Section 2.2 thereof prior to the expiration of the Term of this Agreement, this Agreement shall likewise terminate as of the date of termination of the Transition Agreement in accordance with Section 2.2 thereof. IN WITNESS WHEREOF, the undersigned Parties have caused this Agreement to be executed in their names by their respective duly authorized officials, as of the 29th day of October, 1999. The Connecticut Light and Power Company By: /s/ James R. Shuckerow, Jr. ------------------------------------------ James R. Shuckerow, Jr. Director, Wholesale Power Contracts NRG Power Marketing Inc. By: /s/ James J. Bender ------------------------------------------ James J. Bender Vice President -23-

24 APPENDIX A CALCULATION OF THE STANDARD OFFER SUPPLIER'S BILLING DETERMINANTS The Contract Load Quantity will be determined in accordance with the methodology accepted by the DPUC for the calculation of the load responsibilities of competitive retail service suppliers in the competitive retail markets in Connecticut and the settlement rules adopted by NEPOOL and the NEPOOL ISO. The methodology set forth below is based on CL&P's proposed methodology to the DPUC for calculating such retail load responsibilities and current NEPOOL settlement rules, and shall apply unless such methodology is changed pursuant to lawful action of NEPOOL or the DPUC. In the event that the DPUC or NEPOOL implement any such changes, the Buyer shall promptly notify the Seller in writing of such changes. 1. Determination of the System Retail Load. On an hourly basis, the Buyer will calculate the aggregate load of its Retail Customers, ( the "System Retail Load"). The System Retail Load will be computed for each hour based on the total metered output of all generation connected to the Buyer's system below the tie meters at which NEPOOL measures net interchange between the Buyer's system and NEPOOL,and adding to that figure the net imports into the Buyer's system (or subtracting net exports from the system) as measured by the tie meters at or below the NEPOOL PTF, less non-retail loads (e.g. wholesale load served to municipalities). 2. Determination of retail customer Hourly Loads. For each hour, the Buyer will calculate the actual or estimated loads of each of its Retail Customers using one of the following two methods: a) In circumstances where the Customer has an interval recording meter (capable of recording pulses in 15 minute, or other intervals), the retail customer's initial hourly load is determined by these interval pulses translated or -24-

25 aggregated into hourly consumption quantities. The Buyer will use the actual recorded meter readings, increased to account for losses on the Buyer's system between the Delivery Point and end-use meters in accordance with a study entitled, "Determination of Loss Factors for the Northeast Utilities System" conducted by Northeast Utilities' Transmission Planning Department dated October 1, 1989, to determine the hourly loads of the Retail Customers. b) In circumstances where Retail Customers do not have interval meters capable of recording hourly consumption quantities, the Buyer will determine the hourly loads of the Retail Customers using the load estimation technique filed with the DPUC for purposes of calculating retail load responsibilities of competitive suppliers under the Connecticut retail choice program. The load estimation technique will be based on load profile statistics developed for different retail customer classes and segments, and for each calendar month, days and time periods, based on statistical sampling of consumption patterns of Retail Customers with interval recording meters. The average load profiles so developed will be scaled for individual Retail Customers using a usage factor that is calculated based on the relationship between the individual Retail Customer's usage over the prior billing period and the average retail class segment usage estimated over the same time period, and increased to account for losses on the Buyer's system between the Delivery Point and end-use meters in accordance with a study entitled, "Determination of Loss Factors for the Northeast Utilities System" conducted by Northeast Utilities' Transmission Planning Department dated October 1, 1989. 3. Determination of Competitive Supplier Hourly Loads. The hourly loads of each Competitive Supplier serving retail load on the Buyer's system will be estimated using the following two step process: -25-

26 a) Each retail customer will be assigned a Competitive Supplier Code based on the identity of its Competitive Supplier. Those Customers that have not designated a Competitive Supplier will be assigned the Standard Offer Service Supplier Code. The retail customer hourly loads, calculated in accordance with section 2(a) and (b) above, associated with the Retail Customers that have been assigned the same Competitive (or Standard Offer Service) Supplier Code, will be summed for each hour. b) Determination of Residual. The difference between the System Retail Load (as determined in section 1 above) and the sum of the load responsibilities of all Competitive Suppliers (including Standard Offer Service load), determined in accordance with section 3(a), will constitute the "Residual". The Residual will be allocated to each Competitive Supplier (and to the Standard Offer Service load) in proportion to the ratio of the estimated part of the Supplier's assigned retail customer load (as calculated in section 2(b) to the sum of the estimated part of the retail customer loads of all Competitive Suppliers, as calculated in section 2(b), including the Standard Offer Service load. 4. Determination of SOS Total Hourly Loads. The Standard Offer Service hourly load will be determined in accordance with section 3 based on the calculated or estimated hourly loads, including Residual allocations to estimated hourly loads, for all Retail Customers assigned the Standard Offer Service Supplier Code. 5. Allocation of SOS Supplier Hourly Loads. The total Standard Offer Service hourly load will be allocated among each of the Sellers of Standard Offer Service based on the percentage of the total Standard Offer Service Load assigned to that Seller in Section 3.5 of that Seller's Standard Offer Service Agreement with the Buyer. -26-

27 6. Reporting of SOS Supplier Hourly Loads to the ISO. a) In accordance with the rules of NEPOOL, the Buyer will report to the ISO the hourly loads, determined in accordance with section 5 of this Appendix A, for each Seller of Standard Offer Service (or the NEPOOL participant responsible for that Seller's load under NEPOOL rules), within 37 business hours after the close of each day. Each Seller of Standard Offer Service, or the NEPOOL participant designated by such Seller to assume the Seller's load responsibility in NEPOOL, will have sole responsibility for all charges assessed by the ISO based on the hourly loads reported by the Buyer. b) The Contract Load Quantity for each Seller of Standard Offer Service will be equal to the aggregate of the Standard Offer Service hourly loads of such Seller, summed over the calendar month, as reported to NEPOOL in accordance with section 6(a) of Appendix A. 7. Determination of SOS Supplier Billing Amount. The SOS Supplier Billing Amount is equal to the Contract Load Quantity multiplied by a delivery efficiency factor of 0.9238. This amount will be submitted to Seller for purposes of billing hereunder. The delivery efficiency factor set forth above shall not be subject to change during the Term. 8. Determination of adjusted SOS Supplier Billing Amount. In accordance with the requirements of NEPOOL Market Rules & Procedures No. 18, the Buyer will submit to the ISO, within 90 days after the end of each month, revised monthly energy quantities for each NEPOOL participant for such month. The adjusted Contract Load Quantity for each Seller of Standard Offer Service will be based on a 90 day true-up for that month submitted to NEPOOL by the Buyer. The adjusted SOS Supplier Billing Amount will be the adjusted Contract Load Quantity multiplied by a delivery efficiency factor of 0.9238. -27-

5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE SEPTEMBER 30, 1999 FINANCIAL STATEMENTS INCLUDED IN THE COMPANY'S FORM 10-Q AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FORM 10-Q. 1,000 9-MOS DEC-31-1999 JAN-01-1999 SEP-30-1999 25,236 0 84,831 110 59,535 232,040 1,246,255 116,019 2,526,361 959,753 797,348 0 0 1 722,242 2,526,361 237,855 283,581 148,211 224,822 53,640 0 57,607 5,119 (23,889) 29,008 0 0 0 29,008 0 0