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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[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

NRG Northeast Generating LLC
(Exact name of Registrant as specified in its charter)

(612) 373-5300
(Registrant’s telephone number, including area code)

None
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [X]   No [ ]

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)

Yes [ ]   No [X]

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities and Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes [X]   No [ ]

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TABLE OF CONTENTS

INDEX

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Part I — FINANCIAL INFORMATION

Item I — Consolidated Financial Statements and Notes

NRG Northeast Generating LLC and Subsidiaries

See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries

See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries

For the three months ended June 30, 2003 and 2002

For the six months ended June 30, 2003 and 2002

See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries

See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

     NRG Northeast Generating LLC (the Company or NRG Northeast), a wholly-owned indirect subsidiary of NRG Energy, Inc. (NRG Energy), owns electric power generation plants in the northeastern region of the United States. The Company was formed for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries and affiliates; facilities owned by Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Connecticut Jet Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC, Oswego Power LLC and Somerset Power LLC.

     In connection with its restructuring efforts, on May 14, 2003 NRG Energy and 26 of its U.S. affiliates (the Debtors) including the Company and its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of New York (the Bankruptcy Court). It is possible that additional subsidiaries will file petitions for reorganization under Chapter 11. International operations and certain other subsidiaries were not included in the filing. NRG Energy expects operations to continue as normal during the restructuring process, while it operates its business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. For more information about NRG Energy’s restructuring process, refer to the Form 10-K filed by NRG Energy on March 31, 2003 and Form 10-Q filed by NRG Energy on May 20, 2003.

     The accompanying unaudited consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission (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 Item 15 — Note 2 to the Company’s financial statements in its annual report on Form 10-K for the year ended December 31, 2002 (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.

     The Financial Statements have been prepared on a “going concern” basis in accordance with GAAP. The “going concern” basis of presentation assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities in the normal course of business. Because of the Chapter 11 Cases and the circumstances leading to the filing thereof, the Company’s ability to continue as a “going concern” is subject to substantial doubt and is dependent upon, among other things, confirmation of a plan of reorganization, the Company’s ability to comply with the terms of, and if necessary renew at its expiry in May 2004, the Debtor in Possession Credit Facility, and the Company’s ability to generate sufficient cash flows from operations, asset sales and financing arrangements to meet its obligations. There can be no assurances that this can be accomplished and if it were not, the Company’s ability to realize the carrying value of its assets and discharge its liabilities would be subject to substantial uncertainty. Therefore, if the “going concern” basis were not used for the Financial Statements, then significant adjustments could be necessary to the carrying value of assets and liabilities, the revenues and expenses reported, and the balance sheet classifications used.

     The Financial Statements also have been prepared in accordance with The American Institute of Certified Public Accountants Statement of Position 90-7 (SOP 90-7), “Financial Reporting by Entities in Reorganization under the Bankruptcy Code”. Accordingly, all pre-petition liabilities believed to be subject to compromise have been segregated in the Consolidated Balance Sheet and classified as liabilities subject to compromise, at the estimated amount of allowable claims. Liabilities not believed to be subject to compromise are separately classified as current and non-current. Interest expense is reported only to the extent that it will be paid or that it is probable that it will be an allowed claim.

     During the Chapter 11 Cases, the Debtors may, subject to any necessary Bankruptcy Court and lender approvals, sell assets and settle liabilities for amounts other than those reflected in the financial statements. The administrative and reorganization expenses resulting from Chapter 11 Cases will unfavorably affect the Debtors’ results of operations. Future results of operations may also be adversely affected by other factors related to Chapter 11 Cases.

     The Company is in the process of reconciling recorded prepetition liabilities with claims filed by creditors with the Bankruptcy Court. Differences resulting from that reconciliation process will be recorded as adjustments to prepetition liabilities. The Company recently began this process and has not yet determined the reorganization adjustments.

     In the opinion of management, the accompanying unaudited interim consolidated financial statements contain all material adjustments necessary to present fairly the consolidated financial position of the Company as of June 30, 2003 and December 31, 2002, the results of its operations and members’ equity for the three and six months ended June 30, 2003 and 2002, and its cash flows for the six months ended June 30, 2003 and 2002.

     Certain prior year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or total members’ equity as previously reported.

1. Restructuring Activities

     In December 2001, Moody’s Investor Service (Moody’s) placed NRG Energy’s long-term senior unsecured debt rating on review for possible downgrade. In response, Xcel Energy and NRG Energy put into effect a plan to preserve NRG Energy’s investment grade rating and improve its financial condition. This plan included financial support to NRG Energy from Xcel Energy; marketing certain NRG Energy assets for sale; canceling and deferring capital spending; and reducing corporate expenses.

     In response to a possible downgrade during 2002, Xcel Energy contributed $500 million to NRG Energy, and NRG Energy and its subsidiaries sold assets and businesses that provided NRG Energy in excess of $286 million in cash and eliminated approximately $432 million in debt. NRG Energy also cancelled or deferred construction of approximately 3,900 MW of new generation projects. On July 26, 2002, Standard & Poors’ (S&P) downgraded NRG Energy’s senior unsecured bonds to below investment grade, and three days later Moody’s also downgraded NRG Energy’s senior unsecured debt rating to below investment grade. Since July 2002, NRG Energy senior unsecured debt, as well as the secured NRG Northeast Generating LLC bonds and the secured NRG South Central Generating LLC bonds and secured LSP Energy (Batesville) bonds were downgraded multiple times. After NRG Energy failed to make payments due under certain unsecured bond obligations on September 16, 2002, both Moody’s and S&P once again lowered their ratings on NRG Energy’s unsecured bonds and its subsidiaries’ secured bonds. Currently, NRG Energy’s unsecured bonds carry a rating of D at S&P and Ca Moody’s. NRG Northeast secured bonds currently carry a rating of D at S&P and Caa1 at Moody’s.

     As a result of the downgrade of NRG Energy’s credit rating, declining power prices, increasing fuel prices, the overall down-turn in the energy industry, and the overall down-turn in the economy, NRG Energy has experienced severe financial difficulties. These difficulties have caused NRG Energy to, among other things, miss scheduled principal and interest payments due to its corporate lenders and bondholders, prepay for fuel and other related delivery and transportation services and provide performance collateral in certain instances. NRG Energy has also recorded asset impairment charges of approximately $3.1 billion as of December 31, 2002, related to various operating projects as well as for projects that were under construction which NRG Energy has stopped funding.

     NRG Energy and certain wholly owned subsidiaries have failed to timely make several interest and/or principal payments on indebtedness. These missed payments have resulted in cross-defaults of numerous other non-recourse and limited recourse debt instruments of NRG Energy and have caused the acceleration of multiple debt instruments of NRG Energy, rendering such debt immediately due and payable.

     Since March 31, 2003 NRG Energy failed to make a first-quarter payment of $19.1 million due on March 31, 2003 relating to interest and fees on the $1.0 billion unsecured 364-day revolving credit facility; a $13.6 million interest payment due on April 1, 2003 on the $350 million of 7.75% senior unsecured notes maturing 2011; a $21.6 million interest payment due on April 1, 2003 on the $500 million of 8.625% senior unsecured notes maturing 2031; and a $9.6 million interest payment due on May 1, 2003 on the $240 million of 8.0% senior unsecured notes maturing 2013. On May 13, 2003, XL Capital Assurance, as controlling party, accelerated the approximately $319 million

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of debt issued by NRG Peaker Finance Company LLC. Accordingly, these facilities are in default.

     NRG Energy failed to make a second quarter payment of $18 million due on June 30, 2003, relating to interest and fees on the $1.0 billion unsecured, 364-day revolving credit facility; a $11.3 million interest payment due June 1, 2003, on the $300 million of 7.5% senior unsecured notes maturing in 2009; and a $9.4 million interest payment due on June 15, 2003, on the $250 million of 7.5% senior unsecured notes due in 2007.

     Prior to the downgrades, many corporate guarantees and commitments of NRG Energy and its subsidiaries required that they be supported or replaced with letters of credit or cash collateral within 5 to 30 days of a ratings downgrade below Baa3 or BBB- by Moody’s or Standard & Poor’s, respectively. As a result of the downgrades on July 26, 2002 and July 29, 2002, NRG Energy received demands to post collateral aggregating approximately $1.2 billion. NRG Energy is presently working with various secured project lender groups with respect to working towards establishing a comprehensive plan of restructuring.

     In August 2002, NRG Energy retained financial and legal restructuring advisors to assist its management in the preparation of a comprehensive financial and operational restructuring. In November 2002, NRG Energy and Xcel Energy presented a comprehensive plan of restructuring to an ad hoc committee of its bondholders and a steering committee of its bank lenders (the Ad Hoc Creditors Committees). The restructuring plan served as a basis for continuing negotiations between the Ad Hoc Creditors Committees, NRG Energy and Xcel Energy related to a consensual plan of reorganization for NRG Energy.

     On November 22, 2002, five former NRG Energy executives filed an involuntary Chapter 11 petition against NRG Energy in U.S. Bankruptcy Court for the District of Minnesota (the Minnesota Bankruptcy Court). On February 19, 2003, NRG Energy announced that it had reached a settlement with the petitioners. On May 12, 2003, the Minnesota Bankruptcy Court issued an order abstaining from exercising jurisdiction over any aspect of the case and dismissed the case.

     On March 26, 2003, Xcel Energy announced that its board of directors had approved a tentative settlement agreement with holders of most of NRG Energy’s long-term notes and the steering committee representing NRG Energy’s bank lenders. The settlement was subject to certain conditions, including the approval of at least a majority in dollar amount of the NRG Energy bank lenders and long-term noteholders and definitive documentation. There can be no assurance that such approvals will be obtained. The terms of the settlement called for Xcel Energy to make payments to NRG Energy over the next 10 months totaling up to $752 million for the benefit of NRG Energy’s creditors in consideration for their waiver of any existing and potential claims against Xcel Energy. Under the settlement, Xcel Energy would make the following payments: (i) $350 million at or shortly following the consummation of a restructuring of NRG Energy’s debt. It is expected this payment would be made prior to year-end 2003; (ii) $50 million on January 1, 2004. At Xcel Energy’s option, it may fill this requirement with either cash or Xcel Energy common stock or any combination thereof; and (iii) $352 million in April 2004. Since the announcement on March 26, 2003, representatives of NRG Energy, Xcel Energy, the bank lenders and noteholders have continued to meet to draft the definitive documentation necessary to fully implement the terms and conditions of the tentative settlement agreement.

     On May 14, 2003, NRG Energy and certain of its U.S. affiliates (including the Company and its subsidiaries) filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (the Bankruptcy Court), In re: NRG ENERGY, INC., et. al., Case No. 03-13204 (PCB). NRG Energy expects operations to continue as normal during the restructuring process, while it operates its business as a “debtor-in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In connection with its Chapter 11 filing, NRG Energy also announced a $250 million debtor-in-possession (DIP) financing facility from GE Capital Corporation, subject to Bankruptcy Court approval, to be utilized by the Company and some of the Company’s subsidiaries. NRG Energy anticipates that the DIP, together with its cash reserves and its ongoing revenue stream, will be sufficient to fund its operations, including payment of employee wages and benefits, during the reorganization process.

     On May 15, 2003, NRG Energy announced that it had been notified that the New York Stock Exchange (NYSE) has suspended trading in NRG Energy’s corporate units that trade under the ticker symbol NRZ and that an application to the Securities and Exchange Commission to delist the Units is pending the completion of applicable procedures, including appeal by NRG Energy of the NYSE staff’s decision. NRG Energy does not plan to make such an appeal. The NYSE took this action following NRG Energy’s announcement that it and certain of its U.S. affiliates had filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code.

     In addition, on May 15, 2003, NRG Energy, NRG Power Marketing, Inc., NRG Finance Company I, LLC, NRGenerating Holdings (No. 23) B.V. and NRG Capital LLC (collectively, the Plan Debtors), filed their Disclosure Statement for Reorganizing Debtors’ Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code (as subsequently amended, the Disclosure Statement). The Bankruptcy Court held a hearing on the Disclosure Statement on June 30, 2003, and instructed the Plan Debtors to include certain additional disclosure. The Plan Debtors amended the Disclosure Statement and obtained Bankruptcy Court approval for the Third Amended Disclosure Statement for Debtors’ Second Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code (respectively, the Amended Disclosure Statement, the Plan).

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     The Plan must be approved by the SEC prior to its becoming effective. As subsidiaries of a registered holding company (Xcel Energy) under the Public Utility Holding Company Act of 1935 (PUHCA), any reorganization plan for NRG Energy or NRG Energy’s subsidiaries must be approved by the SEC prior to such plan becoming effective. Furthermore, each solicitation of any consent in respect of any reorganization plan must be accompanied or preceded by a copy of a report on the plan made by the SEC, or an abstract thereof made or approved by the SEC. The Plan and Amended Disclosure Statement were submitted to the SEC for review on Monday July 28, 2003. The Plan Debtors will not be able to solicit acceptances or rejections in connection with the Plan prior to obtaining the required SEC approval. As a result, no deadlines or dates have been set regarding voting or confirmation.

     On June 5, 2003, NRG Nelson Turbines LLC and LSP-Nelson Energy LLC (both wholly owned subsidiaries of NRG Energy) filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York.

2. Debtors’ Statements

As stated above, NRG Energy and certain of its subsidiaries (including NRG Northeast and its subsidiaries) filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code on May 14, 2003. As of the bankruptcy filing date, the Debtor’s financial records were closed for the prepetition period. As required by SOP 90-7 “Financial Reporting by Entities in Reorganization under the Bankruptcy Code,” below are the condensed combined financial statements of the Debtors since the date of the bankruptcy filings (the Debtors’ Statements). The Debtors’ Statements have been prepared on the same basis as NRG Northeast’s Consolidated Financial Statements. All entities of NRG Northeast are included in the bankruptcy filing; therefore the condensed combined balance sheet is not required under SOP 90-7.

DEBTORS’ CONDENSED COMBINED STATEMENT OF OPERATIONS

DEBTORS’ CONDENSED COMBINED STATEMENT OF CASH FLOWS

3. Debt

     As of June 30, 2003, NRG Energy has failed to make scheduled payments on interest and/or principal on approximately $4.0 billion of its recourse debt and is in default under the related debt instruments. These missed payments also have resulted in cross-defaults of numerous other non-recourse and limited recourse debt instruments of NRG Energy. In addition to the missed debt payments, a significant amount of NRG Energy’s debt and other obligations contain terms, which require that they be supported with letters of credit or cash collateral following a ratings downgrade. As a result of the downgrades that NRG Energy experienced in 2002, NRG Energy estimates that it is in default of its obligations to post collateral of approximately $1.2 billion, principally to fund a $842.5 million equity guarantee associated with its construction revolver financing facility, to fund debt service reserves and other guarantees related to NRG Energy projects and to fund trading operations.

     Absent an agreement on a comprehensive restructuring plan, NRG Energy will remain in default under its debt and other obligations, because it does not have sufficient funds to meet such requirements and obligations. There can be no assurance that NRG Energy’s creditors ultimately will accept any consensual restructuring plan under the bankruptcy process. For discussion of NRG Energy’s restructuring activities, refer to Note 1 in the Form 10-Q filed by NRG Energy for the six months ended June 30, 2003 and Form 8-K filed by NRG Energy on May 16, 2003.

     As a result of NRG Energy’s bankruptcy filing, NRG Energy has classified its corporate level debt as a prepetition obligation subject to compromise and has ceased recording accrued interest as it is not probable of being paid. The contractual interest requirements for such corporate debt is $40.0 million for the period May 14, 2003 (date of the bankruptcy petition) to June 30, 2003.

     As a result of NRG Energy’s bankruptcy filing, the Company has classified its debt as a prepetition obligation subject to compromise. Accrued interest continues to be recorded as the debt is fully secured.

Debtor-in-Possession Loan

     NRG Energy and certain of its subsidiaries have negotiated a Senior Secured, Super-Priority Debtor-in-Possession Credit Agreement ( the DIP Agreement) with General Electric Capital Corporation (GECC), which was executed following the filing of the petition in NRG Energy’s Chapter 11 bankruptcy case. Under the DIP Agreement, GECC will make up to $250 million (the DIP Facility) available for working capital and general corporate needs of the Debtors that comprise NRG’s Northeast generating facilities (the DIP Borrowers). The DIP Facility will be secured by a first priority lien on substantially all of the assets of and equity interest in the DIP Borrowers, plus the assets of Power Marketing, Inc. that relate to the revenues of the DIP Borrowers.

     The DIP Facility bears an interest rate of 2.00% over the prime rate or 3.50% over the LIBOR rate and is currently set to expire on May 13, 2004. NRG does not currently anticipate the DIP Facility to be outstanding for one year. However, should the DIP Facility extend for more than one year, approval of such financing by the New York Public Service Commission will be required as certain NRG Energy assets securing the loan are located in New York. Should such approval be necessary, NRG Energy intends to make a timely application for the approval.

     The amount available under the DIP Facility may vary from time to time, depending on valuations of the collateral securing the DIP Facility and GECC’s right to set aside certain reserves. The DIP Facility permits the DIP Borrowers to borrow up to $210 million upon entry of a final order approving the DIP Facility. The total availability may increase to $250 million upon the occurrence of certain subsequent events. A final order approving the DIP Facility was entered by the Bankruptcy Court on July 24, 2003. Such order provides, among other things, that the borrowers may not use DIP funds or cash collateral to make disbursements to, or for the benefit of the Connecticut Light and Power Company, unless further agreed to by GECC, the DIP lender, the Official Committee of Unsecured Creditors of NRG Energy, Inc. et al. and the informal committee of holders of the three series of Senior Secured Bonds issued by NRG Northeast Generating LLC, or further order of the Bankruptcy Court.

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     As of June 30, 2003, NRG Energy had not drawn down any funds from the DIP Facility.

4. Inventory

     Inventory consists of spare parts, coal, fuel oil and kerosene and is stated at the lower of weighted average cost or market value:

5. Property, Plant and Equipment

     Property, plant and equipment are stated at cost or recoverable value. Depreciation is computed on a straight-line basis over the following estimated useful lives:

     Property, plant and equipment consisted of:

     In light of economic developments related to the Connecticut assets and NRG Energy’s application for cost of service reimbursements, The Company reassessed the asset lives for the Connecticut facilities. The shorter depreciable lives resulted in an increase in depreciation of approximately $6.3 million and $13.2 million for the three and six months ended June 30, 2003. In accordance with SFAS No. 144, the Company has reclassified the accumulated depreciation recorded on those facilities that were impaired during the six months ended June 30, 2003.

6. Accounting for Long-Term Contracts

     On June 18, 2003, the Company terminated an indemnity agreement between itself and NRG Power Marketing, Inc. (NRG PMI) a wholly owned subsidiary of NRG Energy and an affiliate of the Company, effective to May 14, 2003. Upon the effective termination of this agreement, certain outstanding trade receivables were transferred from the Company to NRG PMI. This transfer resulted in a balance sheet reclass of approximately $67.4 million on the Company’s financials from accounts receivable – trade to accounts receivable – affiliate. These receivables relate to three long-term contracts that were directly affected by the termination of this indemnity agreement termination. As a result, the Company will no longer recognize any revenues or expenses related to these contracts. The affected contracts were the Standard Offer Service contract with CL&P, a long- term contract with Ashland and a long- term contract with EUA. Effective May 14, 2003, NRG PMI will bear the benefits and burdens of these contracts. During the six months ended June 30, 2003, the provisions of the standard offer contracts resulted in an actual operating loss for the Company’s Connecticut facilities of approximately $118.7 million.

     In addition, effective with the indemnity agreement termination, the Company has reclassified certain other accounts receivable – trade balances to accounts receivable – affiliate to recognize the related party relationship between NRG PMI and the Company and its subsidiaries. As of June 30, 2003, approximately $1.7 million of accounts receivable – trade was reclassified to accounts receivable – affiliate. The ongoing expense and revenue recognition related to these transactions will remain consistent with the Company’s past policies and procedures. Included in operating revenue is approximately $57.3 million of related party revenue for the three and six month periods ending June 30, 2003.

7. Derivative Instruments and Hedging Activity

     On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), as amended by SFAS No. 137 and SFAS No. 138. SFAS No. 133 requires the

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Company to record all derivatives on the balance sheet at fair value. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Derivatives that have been designated as hedges of assets, liabilities or firm commitments, are accounted for using the fair value method. Changes in the fair value of these instruments are recognized in earnings as offsets to the changes in the fair value of the related hedged assets, liabilities and firm commitments. Derivatives that have been designated as hedges of forecasted transactions are accounted for using the cash flow method. Changes in the fair value of these instruments are deferred and recorded as a component of accumulated other comprehensive income (OCI) until the hedged transactions occur and are recognized in earnings. Reclassifications of the deferred gains and losses are included on the same line of the statement of operations in which the hedged item is recorded. The ineffective portion of the change in fair value of a derivative instrument designated as a cash flow hedge is immediately recognized in earnings. The Company formally assesses both at inception and at least quarterly thereafter, whether the derivatives used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

     SFAS No. 133 applies to the Company’s long-term power sales contracts, long-term gas purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. At June 30, 2003, the Company had derivative contracts extending through June 2004.

Accumulated Other Comprehensive Income

     The following table summarizes the effects of SFAS No. 133 on the Company’s OCI balance:

     Gains of $12.3 million and $28.8 million were reclassified from OCI to current period earnings during the three and six months ended June 30, 2003 due to the unwinding of previously deferred amounts. In comparison for the three and six months ended June 30, 2002 gains of approximately $0 and $3.9 million were reclassified. These amounts are recorded on the same line item in the statement of operations in which the hedged items are recorded. During the three and six months ended June 30, 2003, the Company recorded no amounts and gains for the three and six months ended June 30, 2002 of $21.0 million and $37.0 million respectively in OCI, related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of June 30, 2003 was $0. The Company expects no deferred net gains on derivative instruments accumulated in OCI to be recognized as earnings during the next twelve months.

Statement of Operations

     The following table summarizes the effects of SFAS No. 133 on the Company’s statement of operations:

     During the three and six months ended June 30, 2003 and 2002, the Company recognized no gain or loss due to ineffectiveness of

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commodity cash flow hedges.

     The Company’s earnings for the three months ended June 30, 2003 and 2002 were increased by an unrealized gain of $23.8 million and a $34.2 million, respectively. For the six months ended June 30, 2003 and 2002 the company’s earnings increased by an unrealized gain of $19.7 million and $44.2 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

8. Regulatory Issues

     NRG Energy is impacted by market rule and tariff changes in the existing Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs), On March 1, 2003, ISO-New England implemented its version of Standard Market Design. This change dramatically modifies the New England market structure by incorporating Locational Marginal Pricing (pricing by location rather than on a New England wide basis). On February 26, 2003, NRG Energy filed a proposed cost of service agreement with the Federal Energy Regulatory Commission (FERC) for the following Connecticut facilities: Middletown Power LLC, Montville Power LLC, Norwalk Power LLC and Devon Power LLC units 11-14 (collectively the NRG Subsidiaries). In the filing, NRG Energy requested that major and minor maintenance expenses of the NRG Subsidiaries be paid for through a tracking mechanism that would insure that NRG Energy receives compensation only for actual maintenance expenses. Under the proposed cost of service agreement, the other NRG Energy costs would be paid through a monthly cost-based payment. NRG Energy requested an effective date of February 27, 2003. The cost of service filing was made notwithstanding the impending implementation of Standard Market Design in New England, including the adoption of Locational Marginal Pricing. While the Standard Market Design represents a significant improvement to the existing market design, NRG Energy still considered the market insufficient to allow NRG Energy to recover its reasonable costs and earn a reasonable return on investment.

     On March 25, 2003, FERC issued an order (the March Order) approving the NRG Subsidiaries’ spring 2003 maintenance expenses, subject to refund and authorized an effective date of February 27, 2003. In the March Order, FERC also permitted ISO New England, via an escrow account, to start collecting the amount of the maintenance expenses in order to ensure the availability of the NRG Energy units for the summer 2003 peak season. To the extent that the Company incurs maintenance related expenses and submitted such expenses to the ISO for reimbursement, the Company will recognize the expense in the period incurred. Upon reimbursement from the ISO for maintenance related expenses, the Company will recognize revenue. FERC did not rule on the remainder of the issues to allow further time to consider protests.

     On April 25, 2003, the FERC issued an order (the April Order) rejecting the remaining part of the proposed cost of service agreements including the monthly cost-based payment. Rather, FERC instructed ISO New England to establish temporary bidding rules that would permit selected peaking units (units with capacity factors of 10 percent or less during 2002), operating within “designated congestion areas” (such as Connecticut) to raise their bids to allow them the opportunity to recover their fixed and variable costs through the market. This temporary bidding rule would remain in place until ISO New England implements locational installed capacity requirements, which should be no later than June 1, 2004. In the July 24 Order on Rehearing (the July Order), FERC clarified that the capacity factor of 10 percent or less applies to units rather than complexes. On a unit basis, all the NRG Energy facilities qualify to bid under the temporary rules except Middletown 2 and 3. For additional information regarding the impact that the FERC’s Order had on NRG Energy’s financial position and results of operations, see Note 10.

9. Commitments and Contingencies

Litigation

The New York Voluntary Bankruptcy Case

     On May 14, 2003 NRG Energy and certain of its U.S. affiliates (including the Company and its subsidiaries) filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of New York (the Bankruptcy Court), In re: NRG ENERGY, INC., et. al., Case No. 03-13024 (PCB). NRG Energy expects operations to continue as normal during the restructuring process, while it operates its business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Fortistar Capital Inc. v. NRG Energy, Inc., Hennepin County District Court

     On July 12, 1999, Fortistar Capital Inc. sued NRG Energy in Minnesota state court. The complaint sought injunctive relief and damages of over $50 million resulting from NRG Energy’s alleged breach of a letter agreement with Fortistar relating to the Oswego Steam Station. NRG Energy asserted counterclaims. After considerable litigation, the parties entered into a conditional, confidential settlement agreement, which was subject to necessary board and lender approvals. NRG Energy was unable to obtain necessary approvals. Fortistar has moved the court to enforce the settlement, seeking damages in excess of $35 million plus interest and attorneys’ fees. NRG Energy is opposing Fortistar’s motion on the grounds that conditions to contract performance have not been satisfied. No decision has been made on the pending motion, and NRG Energy cannot predict the outcome of this dispute.

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Connecticut Light & Power Company v. NRG Power Marketing Inc., Docket No. 3:01-CV-2373 (A WT), pending in the United States District Court, District of Connecticut

     This matter involves a claim by The Connecticut Light & Power Company (CL&P) for recovery of amounts it claims are owing for congestion charges under the terms of a Standard Offer Services contract between the parties, dated October 29, 1999. CL&P has served and filed its motion for summary judgment to which NRG Power Marketing Inc. (NRG PMI) filed a response on March 21, 2003. CL&P has offset approximately $30 million from amounts owed to NRG PMI, claiming that it has the right to offset those amounts under the contract. NRG PMI has counterclaimed seeking to recover those amounts, arguing among other things that CL&P has no rights under the contract to offset them. On May 14, 2003, NRG PMI provided notice to CL&P of termination of the contract effective May 19, 2003. Pursuant to the request of the Attorney General of Connecticut and the Connecticut Department of Public Utility Control (DPUC), on May 16, 2003, the FERC issued an Order directing NRG PMI to continue to provide service to CL&P under the contract, pending further order by FERC. On May 19, 2003, NRG PMI withdrew its notice of termination of the contract. On June 25, 2003, FERC issued an Order directing NRG PMI to continue to provide service to CL&P under the contract, pending further notice by FERC. NRG PMI cannot estimate at this time the likelihood of an unfavorable outcome in this matter, or the overall exposure for congestion charges for the full term of the contract. Although the outcome of this litigation may have an affect on NRG Northeast, NRG Northeast is not a party to this litigation.

Connecticut Light & Power – Related Proceedings at the Federal Energy Regulatory Commission, the United States District Court for the Southern District of New York, and the United States Court of Appeals for the D.C. Circuit and the Second Circuit.

     In May, 2003, when NRG PMI took steps to terminate or reject in bankruptcy the subject Standard Offer Services contract with CL&P (CL&P Contract), the Connecticut Attorney General and the (DPUC) sought and obtained from FERC its above-referenced May 16, 2003 Order temporarily requiring NRG PMI to continue to comply with the terms of the CL&P Contract, pending further notice from FERC. Thereafter, On June 2, 2003, the United States Bankruptcy Court for the Southern District of New York issued its Order specifically authorizing NRG PMI’s rejection of the CL&P Contract, and by Order dated June 12, 2003, the United States District Court for the Southern District of New York granted NRG PMI’s motion for a temporary restraining order staying all actions by CL&P, the Connecticut Attorney General and the DPUC to enforce or apply the above-referenced FERC Order and affording NRG PMI leave to cease its performance under the CL&P Contract, effective retroactive to June 2, 2003. FERC then issued an order on June 25, 2003, that again commanded NRG PMI’s continued performance regardless of any contrary ruling by the Bankruptcy Court and the District Court’s temporary restraining order. By order dated June 30, 2003, the District Court dismissed NRG PMI’s motion for preliminary injunction for lack of subject matter jurisdiction. On July 1, 2003, PMI resumed performance under the CL&P Contract. On July 3, 2003, NRG PMI requested of FERC a stay of the June 25 order which request was denied. On July 8, 2003, PMI requested an emergency stay of FERC’s June 25 order pending petition for review from the United States Court of Appeals for the District of Columbia Circuit. On July 16, 2003, the D.C. Circuit denied NRG PMI’s request for a stay of the June 25 order. On July 17, 2003, NRG PMI appealed to the Second Circuit respecting the District Court’s refusal to enjoin FERC and maintain the restraining order. On July 18, 2003, NRG PMI requested emergency injunctive relief with respect to performance under the CL&P Contract and an expedited briefing schedule on the appeal. NRG Energy awaits the Second Circuit’s decision on the above appeal as well as a permanent order by FERC with respect to NRG PMI’s continued performance under the CL&P Contract. Should NRG PMI have to perform for the duration of the CL&P Contract, this could have an adverse financial consequence approaching $100 million.

The State of New York and Erin M. Crotty, as Commissioner of the New York State Department of Environmental Conservation v. Niagara Mohawk Power Corporation et al., United States District Court for the Western District of New York, Civil Action No. 02-CV-002S

     In January, 2002, NRG Energy and Niagara Mohawk Power Corporation (NiMo) were sued by the New York Department of Environmental Conservation in federal court in New York. The complaint asserted that projects undertaken at NRG Energy’s Huntley and Dunkirk plants by NiMo, the former owner of the facilities, required preconstruction permits pursuant to the Clean Air Act and that the failure to obtain these permits violated federal and state laws. In July, 2002, NRG Energy filed a motion to dismiss. On March 27, 2003 the court dismissed the complaint against NRG Energy with prejudice as to the federal claims and without prejudice as to the state claims. It is possible the state will appeal this dismissal to the Second Circuit Court of Appeals. In the meantime, on April 25, 2003, the state provided to NRG Energy notice of intent to again sue the Company and various affiliates by filing a second amended complaint in this same action in the federal court in New York, asserting against the NRG Defendants violations of operating permits and deficient operating permits at the Huntley and Dunkirk plants. If the case ultimately is litigated to a judgment and there is an unfavorable outcome that could not be addressed through use of compliant fuels and/or a plantwide applicability limit, NRG Energy has estimated that the total investment that would be required to install pollution control devices could be as high as $300 million over a ten to twelve-year period, and NRG Energy may be responsible for payment of certain penalties and fines.

Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power, LLC, and Dunkirk Power, LLC, Supreme Court, State of New York, County of Onondaga, Case No. 2001-4372

     NRG Energy has asserted that NiMo is obligated to indemnify it for any related compliance costs associated with resolution of the

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enforcement action. NiMo has filed suit in state court in New York seeking a declaratory judgment with respect to its obligations to indemnify NRG Energy under the asset sales agreement. NRG Energy has pending a summary judgment motion on its entitlement to be reimbursed by NiMo for the attorneys’ fees NRG Energy has incurred in the enforcement action, and that motion should be heard within the next 60 days.

Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC

     All three of these facilities have been issued Notices of Violation with respect to opacity exceedances. NRG Energy has been engaged in consent order negotiations with the New York State Department of Environmental Conservation (DEC) relative to opacity issues affecting all three facilities periodically since 1999. One proposed consent order was forwarded by DEC under cover of a letter dated January 22, 2002, which makes reference to 7,890 violations at the three facilities and contains a proposed payable penalty for such violations of $900,000. On February 5, 2003, DEC sent to NRG Energy a proposed Schedule of Compliance and asserted that it is to be used in conjunction with newly-drafted consent orders. NRG Energy has not yet received the consent orders although NRG Energy has been told by DEC that DEC is now seeking a penalty in excess of that cited in its January 22, 2002 letter. NRG Energy expects to continue negotiations with DEC regarding the proposed consent orders, including the Schedule of Compliance and the penalty amount. NRG Energy cannot predict whether those discussions with the DEC will result in a settlement and, if they do, what sanctions will be imposed. In the event that the consent order negotiations are unsuccessful, NRG Energy does not know what relief DEC will seek through an enforcement action and what the result of such action will be.

Huntley Power LLC

     On April 30, 2003, the Huntley Station submitted a self-disclosure letter to the (DEC) reporting violations of applicable sulfur in fuel limits which had occurred during 6 days in March, 2003 at the chimney stack serving Huntley Units 63-66. The Huntley Station self-disclosed that the average sulfur emissions rates for those days had been 1.8 lbs/mm BTU, rather than the maximum allowance of 1.7 lbs/mm BTU. NRG Huntley Operations discontinued use of Unit 65 (the only unit utilizing the subject stack at the time) and has kept the remaining 3 units off line until adherence with the applicable standard is assured. On May 19, 2003, the DEC issued Huntley Power LLC a Notice of Violation. NRG Energy has met with the DEC to discuss the circumstances surrounding the event and the appropriate means of resolving the matter. NRG Energy does not know what relief the DEC will seek through an enforcement action. Under applicable provisions of the Environmental Conservation Law, the DEC asserts that it may impose a civil penalty up to $10,000, plus an additional penalty not to exceed $10,000 for each day that a violation continues and may enjoin continuing violations.

Niagara Mohawk Power Corporation v. Dunkirk Power LLC, et al., Supreme Court, Erie County, Index No. 1-2000-8681

     On October 2, 2000, plaintiff Niagara Mohawk Power Corporation commenced this action against NRG Energy to recover damages plus late fees, less payments received through the date of judgment, as well as any additional amounts due and owing, for electric service provided to the Dunkirk Plant after September 18, 2000. Plaintiff NiMo claims that NRG Energy has failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999 and continuing to September 18, 2000 and thereafter. Plaintiff has alleged breach of contract, suit on account, violation of statutory duty, and unjust enrichment claims. On or about October 23, 2000, NRG Energy served an answer denying liability and asserting affirmative defenses.

     After proceeding through discovery, and prior to trial, the parties and the court entered into a stipulation and order filed August 9, 2002 consolidating this action with two other actions against The Company’s Huntley and Oswego subsidiaries, both of which cases assert the same claims and legal theories for failure to pay retail tariffs for utility services.

     On October 8, 2002, a Stipulation and Order was filed in the Erie County Clerk’s Office staying this action pending submission of some or all of the disputes in the action to the FERC. NRG Energy cannot make an evaluation of the likelihood of an unfavorable outcome. The cumulative potential loss could exceed $35 million.

Niagara Mohawk Power Corporation v. Huntley Power LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC, and NRG Oswego Operations, Inc., Case Filed November 26, 2002 in Federal Energy Regulatory Commission Docket No. EL 03-27-000.

     This is the companion action filed by NiMo at FERC, similarly asserting that NiMo is entitled to receive retail tariff amounts for electric service provided to the Huntley, Dunkirk and Oswego plants. The parties are currently engaged in settlement negotiations in an attempt to resolve both this FERC action and the above-referenced state court proceedings respecting amounts owing for electrical service provided to these three plants. At this stage of the proceedings, NRG Energy cannot estimate the likelihood of an adverse determination. As noted above, the cumulative potential loss could exceed $35 million.

NRG Energy Credit Defaults

     NRG Energy and various of its subsidiaries are in default under various of their credit facilities, financial instruments, construction

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agreements and other contracts, which have given rise to liens, claims and contingencies against them and may in the future give rise to additional liens, claims and contingencies against them. In addition, NRG Energy and various of its subsidiaries have entered into various guarantees, equity contribution agreements, and other financial support agreements with respect to the obligations of their affiliates, which have given rise to liens, claims and contingencies against them and may in the future give rise to additional liens, claims and contingencies against the party or parties providing the financial support. NRG Energy cannot at this time predict the outcome or financial impact of these matters.

Guarantees

     The Company is directly liable for the obligations of certain of its subsidiaries pursuant to guarantees relating to certain of their operating obligations. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of the Company’s generation facilities in the United States, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. As of June 30, 2003, the Company’s obligations pursuant to its guarantees of the performance of its subsidiaries totaled approximately $42.3 million.

10. Asset Impairments and Restructuring Charges

     As a result of the changing operational, regulatory and financial conditions impacting the Company on an ongoing basis, the Company reviews the recoverability of its long-lived assets in accordance with the guidelines of SFAS No. 144. As a result of this review, the Company recorded asset impairment charges of $221.5 million for the three and six months ended June 30, 2003, as shown in the table below.

     To determine whether an asset was impaired, NRG Northeast compared asset carrying values to total future estimated undiscounted cash flows. Separate analyses were completed for assets or groups of assets at the lowest level for which identifiable cash flows were largely independent of the cash flows of other assets and liabilities. The estimates of future cash flows included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of the Company’s assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service were based on the asset’s existing service potential. The cash flow estimates may include probability weightings to consider possible alternative courses of action and outcomes, given the uncertainty of available information and prospective market conditions.

     If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to write down the asset to its fair value. Estimates of fair value were based on prices for similar assets and present value techniques. Fair values determined by similar asset prices reflect the Company’s current estimate of recoverability from expected marketing of project assets. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated future project operating costs, and expected plant operation given assumed market conditions.

     Asset impairments and restructuring charges from continuing operations included in operating expenses in the Consolidated Statements of Operations include the following:

     Asset impairments for the three and six months ended June 30, 2003:

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     Connecticut Facilities – NRG Energy reviewed cash flow models for its Connecticut generating facilities at December 31, 2002. No impairment was required based on the pricing and cost recovery assumptions at December 31, 2002. On February 26, 2003 NRG Energy filed a proposed cost of service agreement for the following Connecticut facilities with the Federal Energy Regulatory Commission (FERC) Devon 11-14, Middletown station, Montville station, Norwalk Harbor station. On April 25, 2003, the FERC issued an order that rejected NRG Energy’s proposed fixed monthly charges, citing certain policy determinations regarding cost-of-service agreements. FERC instead directed NRG Energy to recover its fixed and variable costs under interim bidding rules for generators located in constrained areas, the so-called Peaking Unit Safe Harbor (PUSH) mechanism. The PUSH bidding rules would apply to all of NRG Energy’s Connecticut facilities that filed the proposed cost of service agreements, with the exception of Middletown Units 2 and 3, until June 1, 2004. The following quick start facilities, located in Connecticut also have the option of submitting PUSH bids: Cos Cob, Franklin Drive and Torrington. FERC also ordered that the regional power agencies overseeing the energy markets in Connecticut, the Independent System Operator for New England (ISO-NE) and the New England Power Pool (NEPOOL), modify the New England market rules to establish and implement locational capacity or deliverability requirements no later than June 1, 2004. In late May and June 2003, ISO-NE revised its market pricing rules to facilitate FERC’s mandated PUSH mechanism, but has not yet proposed the market modifications required to implement locational capacity or deliverability requirements. In June 2003 NRG Energy filed for rehearing of several elements of FERC’s April 25, 2003 order. In response, on July 25, 2003, FERC re-affirmed the PUSH interim pricing mechanism.

     The existing reliability must run agreement (RMR) between ISO-NE and NRG Energy covering Devon 7 and 8 will terminate on September 30, 2003. At this point it is not clear what mechanism will replace the RMR after September 30, 2003. Several parties have filed rehearing requests concerning the existing RMR and FERC has not yet issued an order covering these rehearing requests.

     As a result of these regulatory developments and changing circumstances in the second quarter, NRG Energy deemed it necessary to review the Connecticut facilities’ cash flow models incorporate changes to reflect the impact of the April 25, 2003 FERC’s orders on PUSH pricing, the pending termination of the RMR, and update the estimated impact of future locational capacity or deliverability requirements. These revised cash flow models determined that the new estimates of pricing and cost recovery levels were not projected to return sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown Power LLC. As a consequence, during the second quarter of 2003 NRG Energy recorded a $64.2 million and $157.3 million impairment at Devon Power LLC and Middletown Power LLC, respectively. NRG Energy accounts for the results of operations of the Connecticut facilities as part of its power generation segment within North America.

     During the three and six month period ended June 30, 2003, the Company incurred $1.7 million and $2.3 million, respectively, of restructuring costs consisting of advisor fees, which includes $0.6 million of restructuring costs for the period May 14, 2003 (the date of the bankruptcy petition) to June 30, 2003. These costs consist of employee separation costs and advisor fees.

11. Asset Retirement Obligation

     Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

     The Company has identified certain retirement obligations at Somerset Power LLC, a wholly owned subsidiary of the Company, related primarily to future environmental obligations. The Company has also identified other asset retirement obligations that could not be calculated because the assets associated with the retirement obligations were determined to have an indeterminate life. The adoption of SFAS No. 143 resulted in recording a $0.2 million increase to property, plant and equipment and a $0.3 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was approximately a $0.1 million increase to depreciation expense and approximately a $0.1 million increase to operating expenses.

     The following represents the balances of the asset retirement obligation as of January 1, 2003 and the additions and accretion of the asset retirement obligation for the six months ended June 30, 2003:

      The following represents the pro-forma effect on the Company’s net income for the three and six months ended June 30, 2002, as if the Company had adopted SFAS No. 143 as of January 1, 2002:

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12. Recent Accounting Pronouncements

     In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections”, that supersedes previous guidance for the reporting of gains and losses from extinguishment of debt and accounting for leases, among other things. SFAS No. 145 requires that only gains and losses from the extinguishment of debt that meet the requirements for classification as “Extraordinary Items,” as prescribed in Accounting Practices Board Opinion No. 30, should be disclosed as such in the financial statements. Previous guidance required all gains and losses from the extinguishment of debt to be classified as “Extraordinary Items.” This portion of SFAS No. 145 is effective for fiscal years beginning after May 15, 2002, with restatement of prior periods required. The Company adopted this standard as of January 1, 2003 and has no extraordinary gains or losses that will require restatement.

     In addition, SFAS No. 145 amends SFAS No. 13, “Accounting for Leases”, as it relates to accounting by a lessee for certain lease modifications. Under SFAS No. 13, if a capital lease is modified in such a way that the change gives rise to a new agreement classified as an operating lease, the assets and obligation are removed, a gain or loss is recognized and the new lease is accounted for as an operating lease. Under SFAS No. 145, capital leases that are modified so the resulting lease agreement is classified as an operating lease are to be accounted for under the sale-leaseback provisions of SFAS No. 98, “Accounting for Leases”. These provisions of SFAS No. 145 were effective for transactions occurring after May 15, 2002.

     In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” (SFAS No. 146). SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 applies to costs associated with an exit activity that does not involve an entity newly acquired in a business combination or with a disposal activity covered by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002.

     In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities (FIN No. 46). FIN No. 46 requires an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling interest. Historically, that requirement has been applied to subsidiaries in which an enterprise has a majority voting interest, but in many circumstances the enterprise’s consolidated financial statements do not include the consolidation of variable interest entities with which it has similar relationships but no majority voting interest. Under FIN No. 46 the voting interest approach is not effective in identifying controlling financial interest. The new rule requires that for entities to be consolidated that those assets be initially recorded at their carrying amounts at the date the requirements of the new rule first apply. If determining carrying amounts as required is impractical, then the assets are to be measured at fair value the first date the new rule applies. Any difference between the net amount of any previously recognized interest in the newly consolidated entity should be recognized as the cumulative effect of an accounting change. FIN No. 46 becomes effective in the third quarter of 2003. FIN No. 46 is not expected to have a significant impact on the Company.

     In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, (SFAS No. 149). SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. The provisions of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2002. In addition, provisions of SFAS 149 that relate to SFAS Statement No. 133 Implementation Issues that have been effective for fiscal quarters that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates. SFAS No. 149 is not expected to have an impact on the Company.

     In May 2003, the FASB issues SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”, (SFAS No. 150). SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. The provisions of SFAS 150 are effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. SFAS No. 150 is not expected to have an impact on the Company.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

     Due to the factors discussed below, as well as other matters discussed herein, NRG Energy’s financial condition has deteriorated significantly in the recent past. See “Liquidity” below. As a result, NRG Energy does not contemplate that it will have sufficient funds to make required principal and interest payments on its corporate debt, which means that NRG Energy will remain in default of the various corporate level debt obligations.

     On May 14, 2003, NRG Energy and certain of its U.S. affiliates (including the Company and its subsidiaries) filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of New York (the Bankruptcy Court). On June 5, 2003 NRG Nelson Turbines LLC and LSP-Nelson Energy LLC filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York.

Industry Dynamics

     An unregulated merchant power company in the United States can be characterized in two ways, as a generator or as an energy merchant, with some companies having characteristics of both. In the United States, generators are either outgrowths of regulated utilities, developers or independent aggregators of plants divested by utilities. Generators have grown through acquisitions or the construction of new power plants. Energy merchants have emphasized risk management and trading skills over the ownership of physical assets. Energy deregulation paved the way for development of these companies, with utilities in some regions forced to sell off some of their generating capacity and buy electricity on the wholesale market or through power procurement agreements.

     Both generators and energy merchants prospered in the late 1990’s. Starting in 1999, however, a number of factors began to arise which had a negative effect on the business model for merchant power companies. These factors included:

     California - When California restructured its electricity industry in the mid-1990’s, it required utilities to sell generation assets and buy electricity on the wholesale spot market, without the stability of long-term contracts. At the time, California had adequate supplies of power, but the State of California was experiencing unusually high electricity demand growth while new capacity additions were not keeping pace. Supply began to lag behind demand, and previously moderate weather gave way to dryer conditions, reducing hydroelectric supply. Shortages and blackouts ensued in 1999 and 2000. Meanwhile, as wholesale electricity prices moved higher, utilities were not allowed to pass higher costs on to consumers under California’s regulatory regime. Unable to bear the financial burden, PG&E sought Chapter 11 protection and California took over the role of procuring electricity for the utilities. Politicians have criticized the electricity generators and the energy merchants, accusing them of improperly manipulating supply, demand and prices. Merchant power companies in California are now embroiled in protracted litigation with California and private parties, which is discouraging new investment.

     Economy - The United States economy, already headed towards a recession by mid-2001, suffered a heavy blow on September 11, 2001. This, along with a decrease in economically driven electricity demand, exacerbated the drop in stock valuations of the energy merchants. Other regions of the world economy have suffered problems as well, which has exposed companies with international assets to losses based on severe currency fluctuations.

     Weather - On the whole, both the summer and winter seasons have been mild in the United States. This together with an oversupply of new generation in many markets has driven down energy prices significantly.

     Enron - The bankruptcy of Enron has devastated the merchant power industry. The public and political perception created by Enron put a stigma on the industry, drove investors away and increased scrutiny of the industry. Enron also played a key role in the energy trading markets, providing a widely used electronic trading platform that accounted for an enormous amount of trading volume. No other company has stepped in to fill this role, and as a result the electricity markets have become far less efficient and liquid.

     Credit ratings - The credit rating agencies were sharply criticized for not foreseeing Enron’s problems. As a result, the agencies have been quick to scrutinize the rest of the industry, and have tightened their criteria for creditworthiness. The agencies have

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downgraded most, if not all, of the industry participants. Many of these downgrades were severe — ratings at times were dropped several notches at once, or dropped more than once in a span of weeks. This has resulted in most of the energy companies, generators and merchants having non-investment grade credit ratings at this time.

     Oversupply - As wholesale electricity prices and market liquidity increased in the late 1990’s the industry went on a building boom. Through 2001 capital was readily available for the industry, encouraging companies to build new generation facilities. The years 2000 and 2001 saw record megawatt capacity additions in the United States, and record years were on the horizon for 2002 and 2003. Even with steady economic growth this would have created an oversupply of generation. Limited economic growth and recession have exacerbated the oversupply situation.

Results of Operations

For the three and six months ended June 30, 2003 compared to the three and six months ended June 30, 2002

Operating Revenues

     Total operating revenues were $163.2 million and $185.1 million for the three months ended June 30, 2003 and 2002, respectively, a decrease of $21.9 million or 11.8%. This decrease is primarily due to the termination of an indemnity agreement between the Company and NRG PMI a wholly owned subsidiary of NRG Energy and an affiliate of the Company, effective to May 14, 2003. As a result, subsequent to May 14, 2003 the Company ceased to recognize any revenues or expenses related to certain contracts. The affected contracts were the Standard Offer Service contract with CL&P, a long term contract with Ashland and a long term contract with EUA. Effective May 14, 2003, NRG PMI will bear the benefits and burdens of these contracts. During the six months ended June 30, 2003, the standard offer contracts resulted in a net loss recorded at the Company’s Connecticut facilities of approximately $118.7 million. In addition, the Company experienced decreased energy revenues due to decreased generation during the period.

     Total operating revenues were $343.4 million and $316.7 million for the six months ended June 30, 2003 and 2002, respectively, an increase of $26.7 million or 8.4%. This increase is primarily due to increases in generation revenues. The average price of natural gas more than doubled in the first six months of 2003 compared to 2002. This resulted in higher power prices overall, but also resulted in lower generation at the Company’s gas fired plants. Although the MW hours generated decreased, the substantial increase in power prices increased the price per MW hour generated. As a result of the increased power prices, there was increased generation at the coal fired plants. This increase was offset by losses incurred on the Connecticut Standard Offer and other contract obligations due to increased market prices, which increased the cost of purchased power used to service the contract load obligations.

Operating Costs

     Operating costs primarily consist of expenses for fuel, plant operations and maintenance, property and other non-income related taxes and unrealized gains or losses associated with changes in the fair value of energy related derivative instruments not accounted for as hedges.

     Cost of operations was $186.1 million and $355.2 million for the three and six months ended June 30, 2003 compared to $110.5 million and $208.6 million for the three and six months ended June 30, 2003. This represents an increase of $75.6 million and $146.6 million or 68.4% and 70.3% for the three and six months ended June 30, 2003 compared to the same periods in 2002. This increase is primarily due to the Company’s financial condition, which resulted in several contract terminations. During the three and six months ended June 30, 2003 various parties have exercised their rights to terminate certain commodity purchase and sale contracts. As a result contract termination expense of approximately $63 million was recorded during 2003. In addition, although generation declined for the three and six month periods ended June 30, 2003 compared to the same periods in 2002, the cost of generation increased substantially due to increased fuel oil and natural gas prices.

Depreciation

     Depreciation expense was $20.4 million and $13.8 million for the three months ended June 30, 2003 and 2002, respectively, an increase of $6.6 million or 47.6%. In light of economic developments related to the Connecticut assets and the FERC recently issued order regarding cost of service reimbursements, The Company reassessed the asset lives for the Connecticut facilities. The shorter depreciable lives resulted in an increase in depreciation of approximately $6.3 million for the three months ended June 30, 2003.

     Depreciation expense was $36.8 million and $26.2 million for the six months ended June 30, 2003 and 2002, respectively, an increase of $10.6 million or 40.6%. The increase in depreciation expense is attributable to shorter depreciable lives on the Connecticut facilities, of approximately $13.2 million for the six months ended June 30, 2003. Depreciation expense decreased due to

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the reduced asset values based on the impairment analysis for the Somerset Facility, which was written down to fair market value during the third quarter of 2002.

General and Administrative Expenses

     General and administrative expense was $6.5 million and $7.7 million for the three months ended June 30, 2003 and 2002, respectively, a decrease of $1.2 million or 15.6%. General and Administrative costs include non-operation labor and other employee related costs, as well as outside services, insurance, office expenses and administrative support. This decrease is due to a one time charge in 2002 related to tax matters totaling about $1.6 million which is offset by additional expenditures in 2003 for increased insurance premiums and costs related generally to legal and technical consulting.

     General and administrative expense was $17.3 million and $11.3 million for the six months ended June 30, 2003 and 2002, respectively, an increase of $6.0 million or 52.9%. This increase is due to several factors including costs related to additional legal and technical consulting, increased insurance premiums which are running approximately 50% higher than last year and $6.2 million of bad debt expense recorded in the first three months of 2003 for collectibility issues primarily related to one contract. As offsets to these increases the Company incurred one time costs in 2002 of approximately $1.6 million and decreased costs related to work force reduction efforts.

Asset Impairments and Restructuring Charges

     Asset impairment and restructuring charges were $222.5 million and $223.3 for the three and six months ended June 30, 2003, respectively. There were no charges for the same periods in 2002. Asset impairment charges were $221.5 million for the three and six months ended June 30, 2003. Restructuring costs were $1.0 million and $1.7 million for the three and six months ended June 30, 2003, respectively.

     Asset impairments for the three and six month periods ended June 30, 2003 consisted of Devon Power LLC and Middletown Power LLC. On February 26, 2003 NRG Energy filed a proposed cost of service agreement with the Federal Energy Regulatory Commission (FERC). On April 25, 2003, the FERC issued an order that rejected the proposed fixed monthly charges, citing certain policy determinations regarding cost-of-service agreements. Considering those policy concerns, the FERC instead directed NRG Energy to recover its fixed and variable costs under a new Peaking Unit Safe Harbor (PUSH) mechanism, rather than through a fixed monthly charge, for the remainder of 2003 through June 2004. Under the PUSH rules proscribed by FERC, Middletown 2 and 3 could not submit PUSH bids. FERC also ordered that the regional power agencies overseeing the energy markets in Connecticut file with FERC locational capacity or deliverability requirements by March 2004 for implementation by June 1, 2004. Such agencies have not yet formally responded to FERC with a recommended locational capacity or deliverability proposal for use after the PUSH mechanism expires on May 31, 2004.

     The existing reliability must run agreement (RMR) between ISO-NE and NRG Energy covering Devon 7 and 8 will terminate on September 30, 2003. At this point it is not clear what mechanism will replace the RMR after September 30, 2003. Several parties have filed rehearing requests concerning the existing RMR and FERC has not yet issued an order covering these rehearing requests.

     As a result of these and other regulatory developments and changing circumstances in the second quarter, as discussed further in Note 4 to the financial statements, NRG Energy deemed it necessary to review the Connecticut facilities' cash flow models to incorporate changes to reflect the impact of the April 25, 2003 FERC's orders on PUSH pricing and update the estimated impact of future locational pricing. These revised cash flow models determined that the new estimates of pricing and cost recovery levels were not projected to provide sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown Power LLC. As a consequence, during the second quarter, NRG Energy recorded a $221.5 million impairment charge for Devon and Middletown.

     During the three and six month periods ended June 30, 2003, the Company incurred $1.7 million and $2.3 million, respectively, of restructuring costs consisting of advisor fees, which includes $0.6 million of restructuring costs for the period May 14, 2003 (the date of the bankruptcy petition) to June 30, 2003. These costs consist of employee separation costs and advisor fees.

Regulatory Issues

     NRG Energy is impacted by market rule and tariff changes in the existing Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs), On March 1, 2003, ISO-New England implemented its version of Standard Market Design. This change dramatically modifies the New England market structure by incorporating Locational Marginal Pricing (pricing by location rather than on a New England wide basis). On February 26, 2003, NRG Energy filed a proposed cost of service agreement with the Federal Energy Regulatory Commission (FERC) for the following Connecticut facilities: Middletown Power LLC, Montville Power LLC, Norwalk Power LLC and Devon Power LLC units 11-14 (collectively the NRG Subsidiaries). In the filing, NRG Energy requested that major and minor maintenance expenses of the NRG Subsidiaries be paid for through a tracking mechanism that would insure that NRG Energy receives compensation only for actual maintenance expenses. Under the proposed cost of service agreement, the other NRG Energy costs would be paid through a monthly cost-based payment. NRG Energy requested an effective date of February 27, 2003. The cost of service filing was made notwithstanding the impending implementation of Standard Market Design in New England, including the adoption of Locational Marginal Pricing. While the Standard Market Design represents a significant improvement to the existing market design, NRG Energy still considered the market insufficient to allow NRG Energy to recover its reasonable costs and earn a reasonable return on investment.

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     On March 25, 2003, FERC issued an order (the March Order) approving the NRG Subsidiaries’ spring 2003 maintenance expenses, subject to refund and authorized an effective date of February 27, 2003. In the March Order, FERC also permitted ISO New England, via an escrow account, to start collecting the amount of the maintenance expenses in order to ensure the availability of the NRG Energy units for the summer 2003 peak season. To the extent that NRG Energy incurs maintenance related expenses and submitted such expenses to the ISO for reimbursement, NRG Energy will recognize the expenses in the period incurred. Upon reimbursement from the ISO for maintenance related expenses, NRG Energy will recognize revenue. FERC did not rule on the remainder of the issues to allow further time to consider protests.

     On April 25, 2003, the FERC issued an order (the April Order) rejecting the remaining part of the proposed cost of service agreements including the monthly cost-based payment. Rather, FERC instructed ISO New England to establish temporary bidding rules that would permit selected peaking units (units with capacity factors of 10 percent or less during 2002), operating within “designated congestion areas” (such as Connecticut) to raise their bids to allow them the opportunity to recover their fixed and variable costs through the market. This temporary bidding rule would remain in place until ISO New England implements locational installed capacity requirements, which should be no later than June 1, 2004. In the July 24 Order on Rehearing (the July Order), FERC clarified that the capacity factor of 10 percent or less applies to units rather than complexes. On a unit basis, all the NRG Energy facilities qualify to bid under the temporary rules except Middletown 2 and 3. For additional information regarding the impact that the April 25, 2003 FERC order and other regulatory developments had on NRG Energy’s results of operations, see Note 10.

Interest Expense

     Interest expense was $13.1 million and $11.1 million for the three months ended June 30, 2003 and 2002, respectively, an increase of $2.0 million or 18.0%. Interest expense relates to the amortization of deferred finance costs, interest on the senior secured bonds issued on February 22, 2000 and an affiliated note payable issued on June 15, 2002. After the bankruptcy filing the Company entered into a Senior Secured, Super-Priority (Debtor-in-Possession Credit Agreement) which costs are being amortized starting May 14, 2003. In addition, the affiliated note was only in effect a part of 2002 and is being accrued for the full quarter in 2003.

     Interest expense was $25.7 million and $26.7 million for the six months ended June 30, 2003 and 2002, respectively, a decrease of $1.0 million or 3.9%. This decrease is due to the decline in the average principle amounts outstanding on the senior secured indebtedness during the first quarter of approximately $3.0 million and the offset by additional costs related to the affiliated note payable and amortization of deferred finance costs related to the Debtor-in Possession Agreement.

Accounting Policies and Estimates

     Management’s discussion and analysis of its financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.

     On an ongoing basis, the Company evaluates its estimates utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any case, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

     Refer to Item 15 Note 2 of the consolidated financial statements of the Company’s Form 10-K for the year ended December 31, 2002 for additional discussion regarding the Company’s accounting policies and estimates.

Liquidity and Capital Resources

     Liquidity Issues of NRG Energy and it Subsidiaries — Current Status and Chain of Events

     In December 2001, Moody’s Investor Service (Moody’s) placed NRG Energy’s long-term senior unsecured debt rating on review for possible downgrade. In response, Xcel Energy and NRG Energy put into effect a plan to preserve NRG Energy’s investment grade rating and improve its financial condition. This plan included financial support to NRG Energy from Xcel Energy; marketing certain

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NRG Energy assets for sale; canceling and deferring capital spending; and reducing corporate expenses.

     In response to a possible downgrade during 2002, Xcel Energy contributed $500 million to NRG Energy, and NRG Energy and its subsidiaries sold assets and businesses that provided NRG Energy in excess of $286 million in cash and eliminated approximately $432 million in debt. NRG Energy also cancelled or deferred construction of approximately 3,900 MW of new generation projects. On July 26, 2002, Standard & Poors’ (S&P) downgraded NRG Energy’s senior unsecured bonds to below investment grade, and three days later Moody’s also downgraded NRG Energy’s senior unsecured debt rating to below investment grade. Since July 2002, NRG Energy senior unsecured debt, as well as the secured NRG Northeast Generating LLC bonds and the secured NRG South Central Generating LLC bonds and secured LSP Energy (Batesville) bonds were downgraded multiple times. After NRG Energy failed to make payments due under certain unsecured bond obligations on September 16, 2002, both Moody’s and S&P once again lowered their ratings on NRG Energy’s unsecured bonds and its subsidiaries’ secured bonds. Currently, NRG Energy’s unsecured bonds carry a rating of D at S&P and between Ca and C at Moody’s, depending on the specific debt issue. NRG Northeast Generating LLC secured bonds currently carry a rating of D at S&P and B1 at Moody’s.

     As a result of the downgrade of NRG Energy’s credit rating, declining power prices, increasing fuel prices, the overall down-turn in the energy industry, and the overall down-turn in the economy, NRG Energy has experienced severe financial difficulties. These difficulties have caused NRG Energy to, among other things, miss scheduled principal and interest payments due to its corporate lenders and bondholders, prepay for fuel and other related delivery and transportation services and provide performance collateral in certain instances. NRG Energy has also recorded asset impairment charges of approximately $3.1 billion as of December 31, 2002, related to various operating projects as well as for projects that were under construction which NRG Energy has stopped funding.

     NRG Energy and certain wholly owned subsidiaries have failed to timely make several interest and/or principal payments on indebtedness. These missed payments have resulted in cross-defaults of numerous other non-recourse and limited recourse debt instruments of NRG Energy and have caused the acceleration of multiple debt instruments of NRG Energy, rendering such debt immediately due and payable.

     Since March 31, 2003 NRG Energy failed to make a first-quarter payment of $19.1 million due on March 31, 2003 relating to interest and fees on the $1.0 billion unsecured 364-day revolving credit facility; a $13.6 million interest payment due on April 1, 2003 on the $350 million of 7.75% senior unsecured notes maturing 2011; a $21.6 million interest payment due on April 1, 2003 on the $500 million of 8.625% senior unsecured notes maturing 2031; and a $9.6 million interest payment due on May 1, 2003 on the $240 million of 8.0% senior unsecured notes maturing 2013. On May 13, 2003, XL Capital Assurance, as controlling party, accelerated the approximately $319 million of debt issued by NRG Peaker Finance Company LLC. These facilities are in default.

     NRG Energy failed to make a second quarter payment of $18 million due on June 30, 2003, relating to interest and fees on the $1.0 billion unsecured, 364-day revolving credit facility; a $11.3 million interest payment due June 1, 2003, on the $300 million of 7.5% senior unsecured notes maturing in 2009; and a $9.4 million interest payment due on June 15, 2003, on the $250 million of 7.5% senior unsecured notes due in 2007.

     Prior to the downgrades, many corporate guarantees and commitments of NRG Energy and its subsidiaries required that they be supported or replaced with letters of credit or cash collateral within 5 to 30 days of a ratings downgrade below Baa3 or BBB- by Moody’s or Standard & Poor’s, respectively. As a result of the downgrades on July 26, 2002 and July 29, 2002, NRG Energy received demands to post collateral aggregating approximately $1.2 billion. NRG Energy is presently working with various secured project lender groups with respect to the issue of posting collateral and is working towards establishing a comprehensive plan of restructuring.

     In August 2002, NRG Energy retained financial and legal restructuring advisors to assist its management in the preparation of a comprehensive financial and operational restructuring. In November 2002, NRG Energy and Xcel Energy presented a comprehensive plan of restructuring to an ad hoc committee of its bondholders and a steering committee of its bank lenders (the Ad Hoc Creditors Committees). The restructuring plan served as a basis for continuing negotiations between the Ad Hoc Creditors Committees, NRG Energy and Xcel Energy related to a consensual plan of reorganization for NRG Energy.

     On November 22, 2002, five former NRG Energy executives filed an involuntary Chapter 11 petition against NRG Energy in U.S. Bankruptcy Court for the District of Minnesota (the Minnesota Bankruptcy Court). On February 19, 2003, NRG Energy announced that it had reached a settlement with the petitioners. On May 12, 2003, the Minnesota Bankruptcy Court issued an order abstaining from exercising jurisdiction over any aspect of the case and dismissed the case.

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     On March 26, 2003, Xcel Energy announced that its board of directors had approved a tentative settlement agreement with holders of most of NRG Energy’s long-term notes and the steering committee representing NRG Energy’s bank lenders. The settlement is subject to certain conditions, including the approval of at least a majority in dollar amount of the NRG Energy bank lenders and long-term noteholders and definitive documentation. There can be no assurance that such approvals will be obtained. The terms of the settlement call for Xcel Energy to make payments to NRG Energy over the next 10 months totaling up to $752 million for the benefit of NRG Energy’s creditors in consideration for their waiver of any existing and potential claims against Xcel Energy. Under the settlement, Xcel Energy will make the following payments: (i) $350 million at or shortly following the consummation of a restructuring of NRG Energy’s debt. It is expected this payment would be made prior to year-end 2003; (ii) $50 million on January 1, 2004. At Xcel Energy’s option, it may fill this requirement with either cash or Xcel Energy common stock or any combination thereof; and (iii) $352 million in April 2004. Since the announcement on March 26, 2003, representatives of NRG Energy, Xcel Energy, the bank lenders and noteholders have continued to meet to draft the definitive documentation necessary to fully implement the terms and conditions of the tentative settlement agreement.

     On May 14, 2003 NRG Energy and certain of its U.S. affiliates (including NRG Northeast and its subsidiaries) filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (the Bankruptcy Court), In re: NRG ENERGY, INC., et. al., Case No. 03-13204 (PCB). NRG Energy expects operations to continue as normal during the restructuring process, while it operates its business as a “debtor-in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In connection with its Chapter 11 filing, NRG Energy also announced that a $250 million debtor-in-possession (DIP) financing facility from GE Capital Corporation, subject to Bankruptcy Court approval, to be utilized by the Company and some of the Company’s subsidiaries. NRG Energy anticipates that the DIP, together with its cash reserves and its ongoing revenue stream, will be sufficient to fund its operations, including payment of employee wages and benefits, during the reorganization process.

     On May 15, 2003, NRG Energy announced that it has been notified that the New York Stock Exchange (NYSE) has suspended trading in NRG Energy’s corporate units that trade under the ticker symbol NRZ and that an application to the Securities and Exchange Commission to delist the Units is pending the completion of applicable procedures, including appeal by NRG Energy of the NYSE staff’s decision. NRG Energy does not plan to make such an appeal. The NYSE took this action following NRG Energy’s announcement that it and certain of its U.S. affiliates had filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code.

     In addition, on May 15, 2003, NRG Energy, NRG Power Marketing, Inc., NRG Finance Company I, LLC, NRGenerating Holdings (No. 23) B.V. and NRG Capital LLC (collectively, the Plan Debtors) filed their Disclosure Statement for Reorganizing Debtors’ Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code (as subsequently amended, the Disclosure Statement). The Bankruptcy Court held a hearing on the Disclosure Statement on June 30, 2003, and instructed the Plan Debtors to include certain additional disclosure. The Plan Debtors amended the Disclosure Statement and obtained Bankruptcy Court approval for the Third Amended Disclosure Statement for Debtors’ Second Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code (respectively, the Amended Disclosure Statement, the Plan).

     The Plan must be approved by the SEC prior to its becoming effective. As subsidiaries of a registered holding company (Xcel Energy) under PUHCA, any reorganization plan for NRG Energy or NRG Energy’s subsidiaries must be approved by the SEC prior to such plan becoming effective. Furthermore, each solicitation of any consent in respect of any reorganization plan must be accompanied or preceded by a copy of a report on the plan made by the SEC, or an abstract thereof made or approved by the SEC. The Plan and Amended Disclosure Statement were submitted to the SEC for review on Monday July 28, 2003. The Plan Debtors will not be able to solicit acceptances or rejections in connection with the Plan prior to obtaining the required SEC approval. As a result, no deadlines or dates have been set regarding voting or confirmation.

     On June 5, 2003, NRG Nelson Turbines LLC and LSP-Nelson Energy LLC (both wholly owned subsidiaries of NRG Energy) filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York.

Cash Flows

     Net cash provided by operating activities was adversely impacted during the six months ended June 30, 2003 as compared to the same period in 2002 due primarily to unfavorable operating results offset by favorable changes in working capital.

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     Net cash used by investing activities for the six months ended June 30, 2003, was favorably impacted as compared to the same period in 2002 due to a reduction in capital expenditures offset by cash proceeds received upon sale of property during 2003.