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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

NRG Northeast Generating LLC

(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]

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TABLE OF CONTENTS

INDEX

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

See accompanying notes to consolidated financial statements.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

See accompanying notes to consolidated financial statements.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
(UNAUDITED)

For the three months ended September 30, 2002 and 2001

For the nine months ended September 30, 2002 and 2001

See accompanying notes to consolidated financial statements.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

See accompanying notes to consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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 Harbor Power LLC, Oswego Harbor Power LLC and Somerset Power LLC.

     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 8 — Note 2 to the Company’s financial statements in its annual report on Form 10-K for the year ended December 31, 2001 (Form 10-K). The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K. Interim results are not necessarily indicative of results for a full year.

     In the opinion of management, the accompanying unaudited interim consolidated financial statements contain all material adjustments necessary to present fairly the consolidated financial position of the Company as of September 30, 2002 and December 31, 2001, the results of its operations and member’s equity for the three and nine months ended September 30, 2002 and 2001, and its cash flows for the nine months ended September 30, 2002 and 2001.

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

1. RECENT DEVELOPMENTS

     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 to this threat to NRG Energy’s investment grade rating, on February 17, 2002, Xcel Energy announced a financial improvement plan for NRG Energy, which included an initial step of acquiring 100% of NRG Energy through a tender offer to exchange all of the outstanding shares of NRG Energy common stock for Xcel Energy common shares. In addition, the plan included financial support to NRG Energy from Xcel Energy; marketing certain NRG Energy generating assets for possible sale; canceling and deferring capital spending for NRG Energy projects; and combining certain of NRG Energy’s functions with Xcel Energy’s system and organization. On June 3, 2002, Xcel Energy completed its exchange offer for the 26% of NRG Energy’s shares that had been previously publicly held. Xcel Energy offered NRG Energy shareholders 0.50 shares of Xcel Energy common stock for each outstanding share of NRG Energy common stock, representing a $650 million purchase price. During 2002, Xcel Energy provided NRG Energy with $500 million of cash infusions. Throughout this period of time, Xcel Energy was in discussions with credit agencies and believed that its actions would be sufficient to avoid a downgrade of NRG Energy’s credit rating.

     However, even with NRG Energy’s efforts to avoid a downgrade, unexpectedly on July 26, 2002, Standard & Poors’ (S&P) downgraded NRG Energy’s senior unsecured bonds below investment grade, and three days later Moody’s also downgraded NRG Energy’s senior unsecured debt rating below investment grade. Over the next few months NRG senior unsecured debt, as well as the secured NRG Northeast Generating LLC bonds and the secured NRG South Central Generating LLC bonds, were downgraded multiple times. After NRG Energy failed to make the payment obligations due under certain unsecured bond obligations on September 16, 2002, both Moody’s and S&P lowered their ratings on NRG Energy’s unsecured bonds once again. Currently, unsecured bond obligations of NRG Energy carry a rating of between CCC and D, depending on both the specific debt issue and the rating agency rating system. NRG Northeast Generating LLC bonds currently carry a rating of Ca with S&P and Caa1 with Moody’s.

    Many of the corporate guarantees and commitments of NRG Energy and its subsidiaries require 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 and July 29, NRG Energy estimated that it would be required to post collateral ranging from $1.1 billion to $1.3 billion. Although the credit rating downgrades were not expected to occur, NRG Energy believed that it could meet the collateral requirements that would result from such an occurrence with available cash, operating cash flows, equity contributions from Xcel Energy, proceeds from asset sales and the issuance of bonds into the capital markets or as a private placement.

    On August 19, 2002, NRG Energy executed a Collateral Call Extension Letter (CCEL) with various secured project lender groups in which the banks agreed to extend until September 13, 2002, the deadline by which NRG Energy was to post its approximately $1.0 billion of cash collateral in connection with certain bank loan agreements.

     Subsequently, and effective as of September 13, 2002, NRG Energy and these various secured project lenders entered into a Second Collateral Call Extension Letter (Second CCEL) that extended until November 15, 2002, the deadline for NRG Energy to post such collateral. Under the Second CCEL, NRG Energy agreed to submit to the lenders a comprehensive restructuring plan. NRG Energy submitted this plan on November 4, 2002 and is working with the lenders on an overall restructuring of its debt (see further discussion below). The extension agreements did not, however, waive other events of default, including failure to make principal and/or interest payments when due or failure to comply with financial covenants. Nor did the extension agreements waive the rights of the bank groups or bondholders to pursue any rights and remedies in respect of such other defaults. The November 15, 2002, deadline of the second CCEL has passed and NRG Energy has not posted the required collateral. Because NRG Energy has failed to make principal and interest payments when due, and is in breach of other covenants in various financing agreements, NRG Energy is in default of various debt instruments. By reason of these defaults, the lenders are able, if they so choose, to seek to enforce their remedies, which would likely lead to a bankruptcy filing by NRG Energy.

    Starting in August 2002, NRG Energy engaged in the preparation of a comprehensive business plan and forecast. The business plan detailed the strategic merits and financial value of NRG Energy’s projects and operations. It also anticipates that NRG Energy will function independently from Xcel Energy and thus all plans and efforts to combine certain functions of the companies were terminated. NRG Energy utilized independent electric revenue forecasts from an outside energy markets consulting firm to develop forecasted cash flow information included in the business plan. Management concluded that the forecasted free cash flow available to NRG Energy after servicing project-level obligations will be insufficient to service recourse debt obligations. Based on this information and in consultation with Xcel Energy and its financial advisor, NRG Energy prepared and submitted a restructuring plan on November 4, 2002 to various lenders, bondholders and other creditor groups (collectively, “NRG Energy’s Creditors”) of NRG Energy and its subsidiaries. The restructuring plan is expected to serve as a basis for negotiations with NRG Energy’s Creditors in a financially-restructured NRG Energy and, among other things, proposes (i) holders of secured (project-level) debt would either (a) have their debt reinstated with agreed modifications or (b) receive the collateral securing such debt and a claim or claims to the extent such debt is under-secured; (ii) holders of unsecured debt, holders of secured recourse claims against NRG Energy, and holders of other general unsecured claims against NRG Energy would receive a pro rata share of (a) an aggregate of $500 million of junior secured debt of reorganized NRG Energy and (b) 95% of the common equity of reorganized NRG Energy; and (iii) holders of project-level general unsecured claims that are non-recourse to NRG Energy would receive a pro rata share of the remaining 5% of the common equity of a reorganized NRG Energy.

     On November 6, 2002, lenders to NRG Energy accelerated approximately $1.1 billion of NRG Energy’s debt under a construction revolver financing facility, rendering the debt immediately due and payable. This action terminated the Second CCEL in effect between NRG Energy and its major lenders. The extension letter was previously scheduled to expire November 15, 2002. Based on discussions with the construction revolver lenders it is NRG Energy’s understanding that the administrative agent, Credit Suisse First Boston, issued the acceleration notice to preserve certain rights under the construction revolver financing agreements. NRG Energy believes that the administrative agent intends to forbear in the immediate exercise of any rights and remedies against the Company.

     The restructuring plan also includes a proposal by Xcel Energy that in return for a release of any and all claims against Xcel Energy, upon consummation of the restructuring, Xcel Energy would pay $300 million to NRG Energy and surrender its equity ownership of NRG Energy.

     If an agreement were reached with NRG Energy’s Creditors on a restructuring plan, it would most likely lead to NRG Energy commencing a Chapter 11 bankruptcy case and immediately seeking approval of a prenegotiated plan of reorganization. The absence of an agreement will increase the possibility of NRG Energy seeking protection under the bankruptcy laws.

     Throughout the restructuring process, NRG Energy seeks to operate the business in a manner that management believes will offer to creditors similar protection as would be offered by a bankruptcy court. NRG Energy attempts to preserve the enterprise value of the business and to treat creditors within each creditor class without preference, unless otherwise agreed to by advisors to all potentially affected creditors. By operating the Company within this framework, NRG Energy desires to mitigate the risk that creditors will pursue involuntary bankruptcy proceedings against NRG Energy or its material subsidiaries, including NRG Northeast Generating LLC and its subsidiaries.

     The bonds and working capital facility agreements of the Company generally restrict its ability to pay dividends, make distributions or otherwise transfer funds to NRG Energy under certain circumstances. As of September 30, 2002, the Company did not meet the required minimum debt service coverage ratios, and therefore is restricted from making payments to NRG Energy.

     Prior to the NRG Energy downgrades, the debt service reserve account of the Company was funded with a letter of guarantee from the parent company. Following the downgrade, the Company received notice from the trustee on September 9 requesting the cash funding of the debt service reserve account within 30 days. On October 9 NRG Energy failed to fund the debt service reserve account, which created an event of default that, if not cured within 60 days, gives the bond holders rights of acceleration. The project is precluded from making payments to NRG Energy. As a result of this impending default, the long-term portion of the debt has been reclassified to a current liability, as it is potentially callable within the next twelve months.

     The credit rating downgrades, defaults under certain agreements, increased collateral requirements, creditor’s actions and reduced liquidity that have occurred during the quarter ended September 30, 2002 have created substantial doubt as to NRG Energy’s and NRG Northeast Generating LLC ability to continue as a going concern. The absence of a restructuring agreement will increase the possibility of NRG Energy and certain of its subsidiaries, including the Company, seeking protection under the bankruptcy laws. Such action would have a material affect on the Company and its subsidiaries.

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2. LONG-TERM DEBT AND NOTE PAYABLE — AFFILIATE

     On February 22, 2000, the Company issued $750 million of senior secured bonds to refinance short-term project borrowings and for certain other purposes. The bond offering included three tranches: $320 million with an interest rate of 8.065% due in 2004; $130 million with an interest rate of 8.842% due in 2015; and $300 million with an interest rate of 9.292% due in 2024. Principal payments are made semi-annually. The bonds are jointly and severally guaranteed by each of the Company's existing and future subsidiaries. The bonds are secured by a security interest in the Company's membership or other ownership interests in the guarantors and its rights under all intercompany notes between the Company and the guarantors. At September 30, 2002, $556.5 million of bonds remain outstanding and are classified as current. On October 9, 2002, NRG Energy failed to fund the debt service reserve account which created an event of default that, if not cured within 60 days, gives the Bondholders rights of acceleration. See Footnote 1 for more information.

     On June 15, 2002, NRG Energy loaned the Company $30 million to fund capital expenditures. The debt bears interest at the 3 month London Interbank Offered Rate plus 0.5%. The debt is subordinate to the other long-term debt of the Company and is subject to the terms and conditions of the senior secured bonds’ indenture. The Company has recorded this loan as a long-term affiliated note payable.

3. INVENTORY

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

4. PROPERTY, PLANT AND EQUIPMENT

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

Facilities, machinery and equipment		25 to 30 years
Office furnishings and equipment		3 to 10 years

     Property, plant and equipment consisted of:

5. 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 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

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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 September 30, 2002, the Company had derivative contracts extending through December 2006.

Accumulated Other Comprehensive Income

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

     During the three and nine months ended September 30, 2002, the Company recorded a gain of approximately $19 million and a loss of approximately $22 million in OCI respectively, 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 September 30, 2002 was a gain of approximately $85.8 million. The Company expects $85.8 million of the 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 nine months ended September 30, 2002 and 2001, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges.

     The Company’s earnings for the three months ended September 30, 2002 and 2001 were decreased by unrealized losses of $52.8 million and $17.4 million, respectively. For the nine months ended September 30, 2002 and 2001 the Company’s earnings were decreased by unrealized losses of $8.6 million and $55.1 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.

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6. REGULATORY ISSUES

New England

     On April 26, 2001 the Federal Energy Regulatory Commission (FERC) approved, with a July 2001 implementation date, a change in the energy market bidding structure in New England from a one part bidding structure with hourly uplift compensation to a three part bidding system with Net Commitment Period Compensation (NCPC). Under this three part bidding system, a supplier submits separate bids for energy, start up costs and no load. Also under this revised bidding structure, a supplier is guaranteed of receiving an amount at least equal to the combination of its start up, no load and accepted energy bids over the course of the day when it is dispatched to run in the energy market. The impact of this change is that payments for operations dispatched out-of-merit, or from operations required to relieve transmission congestion are evaluated over a twenty four hour period and compensation is paid if the monies received from the energy market are insufficient to cover the as-bid offer. Previously, payments for out-of-merit energy was awarded on an hourly basis and therefore payments received for out-of-merit energy under three part bidding with NCPC are expected to be lower than under previously single part bid market.

     On August 28, 2001, the FERC ruled that a capacity deficiency of $4.87 per kilowatt (KW) per month was appropriate. The deficiency charge acts as a price cap for the Installed Capacity (ICAP) market because load-serving entities (LSE) that do not satisfy their ICAP purchase obligation must pay the deficiency charge. Previous to this ruling, a temporary deficiency charge of $0.17 per KW per month existed. In the same order, the FERC rejected ISO-NE’s proposed after-the-fact cure period for LSE’s ICAP purchase obligation.

     Effective May 1, 2002 certain rule changes went into effect which reflect in part the recommendations made by ISO-NE’s market advisor. Rule changes that are intended to improve the efficiency of the price signal for energy during high load periods include amending eligibility requirements for resources eligible to set the clearing prices, changes to reserve markets including the inclusion of Replacement Reserves in the Thirty Minute Operating Reserve Markets and rules on transaction across the tie lines to New York.

New York

     On October 31, 2001, the extension of the New York City mitigation measures to the real time market and out-of-merit dispatches expired. Consolidated Edison Company of New York (ConEd) has requested an extension of the expanded mitigation measures. On November 27, 2001, the FERC denied this request and directed the NYISO to address the concerns of ConEd in a comprehensive mitigation filing, which is referenced below. On March 20, 2002, the NYISO filed its comprehensive mitigation proposal with the FERC. Under the proposal, the Day-Ahead energy market (DAM) bids of New York City suppliers would continue to be mitigated under the existing ConEd mitigation rules with the following changes. Specifically, the DAM bid for each hour would be compared to the energy price at the Indian Point 2 bus and if the In-City bid exceeded the Indian Point 2 price by more than 107%, all of the DAM energy bids of the supplier would be mitigated to a reference price. The reference price represents either an average of accepted energy bids in the DAM over the last thirty days or a level negotiated with the NYISO. Regarding the real-time energy market (RTM), the NYISO proposal for New York City restricts the ability of a facility to bid above its reference price according to the level of congestion In-City. If congestion prohibits energy from being imported into the City and is also present within the New York City load pockets, the NYISO proposal would restrict the ability to bid above the reference price by approximately 2%. If there is no congestion found in New York City, the facilities can bid approximately one hundred dollars above its referenced price. Currently, the New York City mitigation measures only apply in the day-ahead market. The effect of the expiration of part of these mitigation measures means that in the real time market and out-of-merit dispatches, the Company’s generating assets in New York City are subject only to the NYISO’s New York state mitigation measures.

     On April 30, 2002, the automatic mitigation measure for the entire New York State DAM expired. On May 1, 2002, the FERC approved a NYISO request for extension of the automatic mitigation procedures until May 31, 2002. The extension was granted to permit the FERC to consider the NYISO’s comprehensive mitigation proposal noted above. The automatic mitigation measures evaluate a suppliers’ bids to determine if (1) the bid exceeds the suppliers’ historically accepted bids (over the past 90 days) by more than $100 and (2) that there is an impact on the state-wide or a portion of the state’s energy price by more than $100. If both of these occur, the supplier’s energy bid is reduced to the facility’s historically accepted bids. The impact of the expiration of the automatic mitigation measures means that the Company and other market participants have greater flexibility in submitting bids in the DAM.

     The New York energy markets are subject to a price cap of $1,000 per megawatt hour (MWh). This cap will continue indefinitely.

     On September 4, 2001, the FERC approved the request of the NYISO to revise the ICAP market to one based on unforced capacity

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similar to the capacity market in the Pennsylvania New Jersey Maryland Interconnection. The change from a capacity market that is based on ICAP to one based on unforced capacity requires that certain New York City Capacity requirements be revised to reflect the change. Under ICAP methodology, ICAP sold by the Company and other New York City generators was capped at $105 per KW year. In the September 4th order, the FERC increased the price cap to approximately $112 per KW year. Also in the order the FERC reduced the amount of In-City Capacity an LSE must purchase by 8.6%. The amount of New York City capacity that can be sold as unforced capacity is dependent on the availability of the generating assets to NYISO dispatch instructions. Initially, the FERC reduced the amount of capacity available from New York City generation by approximately 7.1%. The effect of these changes is that the capacity price cap is higher while the amount of capacity an LSE must purchase from New York City generation and the amount of available New York City generating capacity is reduced.

7. COMMITMENTS AND CONTINGENCIES

Contractual Commitments

     During 1999, the Company acquired the Huntley and Dunkirk generating facilities from Niagara Mohawk Power Corporation (NiMo). In connection with this acquisition, the Company entered into a four-year agreement with NiMo that requires the Company to provide to NiMo, pursuant to a predetermined schedule, fixed quantities of energy and capacity at a fixed price.

     During 1999, the Company acquired certain generating facilities from Connecticut Light and Power Corporation (CL&P). The Company also entered into a four-year standard offer agreement that requires the Company to provide to CL&P a portion of its load requirements through the year 2003 at a substantially fixed rate.

     During 1999, the Company acquired the Oswego generating facilities from NiMo and entered into a 4 year transition power sales contract with NiMo in order to hedge NiMo’s transition to market rates. Under the agreement, NiMo will pay to Oswego Power a fixed monthly price plus start up fees for the right to claim, at a specified delivery point(s), the installed capacity of unit 5 and for the right to exercise an option for an additional 350 MW of installed capacity.

     NRG Power Marketing, Inc. (NRG Power Marketing), an affiliate of the Company, has entered into a wholesale standard offer service agreement with Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation (collectively the EUA Companies). Under the agreement, NRG Power Marketing is obligated to provide each of the EUA Companies with firm all-requirements electric service, including capacity, energy, reserves, line losses and related services necessary to serve the aggregate load attributable to retail customers taking standard offer service. The price the EUA Companies pay to NRG Power Marketing for each unit of electricity is a fixed price plus a fuel cost adjustment factor.

Conectiv Agreement Termination

     On November 8, 2002 Conectiv provided NRG Energy with a Notice of Termination of Transaction under the Master Power Purchase and Sale Agreement (Master PPA) dated June 21, 2001. Under the Master PPA, which was assumed by NRG Energy in its acquisition of various assets from Conectiv, NRG Energy had been required to deliver 500 MW of electrical energy around the clock at a specified price through 2005. In connection with the Conectiv acquisition, NRG Energy recorded as an out-of-market contract obligation for this contract. As a result of the cancellation, NRG Energy will lose approximately $402 million in future contracted revenues. Also, in conjunction with the terms of the Master PPA, NRG Energy will receive from Conectiv a termination payment in the amount of $955,000. At September 30, 2002, the balance of the contract obligation was approximately $54 million. Management is currently evaluating the impact of the Notice of Termination of the Master PPA.

NYISO Claims

     In November 2002, the NYISO notified NRG Energy of claims related to New York City mitigation adjustments, general NYISO billing adjustments and other miscellaneous charges related to sales between November 2000 and October 2002. NRG Energy strenuously disagrees with both the validity and calculation of the claims and is currently negotiating with the NYISO over the ultimate disposition. Due to the uncertainty of the final adjustment, an estimate of the final amount has not been recorded in the results for the quarter ended September 30, 2002.

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 September 30, 2002, the Company’s obligations pursuant to its guarantees of the performance of its subsidiaries totaled approximately $184.8 million.

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

     NRG Northeast was formed for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries and affiliates, competitive electric generating facilities in the northeastern region of the United States.

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2002 COMPARED TO THE THREE MONTHS ENDED SEPTEMBER 30, 2001

     Net income for the three months ended September 30, 2002 was $19.8 million, a decrease of $95.0 million compared to the same period in 2001. This change represents a decrease of 82.8%. This change was due to the factors described below.

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Operating Revenues

     For the three months ended September 30, 2002, the Company had total revenues of $233.6 million, compared to $352.2 million for the same period in 2001, a decrease of $118.6 million or 33.7%. The decrease in revenues is due to a combination of lower capacity revenues and a 3% decline in megawatt hour generation compared with the same period in 2001. This decline in generation is attributable to reduced demand for electricity, together with new regulation which reduced price volatility, particularly in New York City, where the Company’s plants sell into the merchant energy market. Additionally, unrealized losses associated with changes in the fair value of non-hedge energy related derivative instruments recorded in revenues were $35.3 million and $0 for the three months ended September 30, 2002 and 2001, respectively.

Operating Costs

     Operating costs were $182.1 million for the three months ended September 30, 2002 compared to $204.9 million for the same period in 2001, a decrease of $22.8 million, or 11.2%. Operating costs primarily consist of expenses for fuel, plant operations and maintenance and unrealized gains or losses associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133. The decrease in operating costs is primarily due to a reduction in fuel cost due to a decline in power generation, a general decline in the price of fuel, and lower expenditures on plant maintenance and operations.

     Fuel expense for the three months ended September 30, 2002 was $119.5 million compared to $136.6 million for the same period in 2001, a decrease of $17.1 million or 12.5%. This decrease is due to a decline in power generation and a general decline in the price of fuel. Fuel expense for the three months ended September 30, 2002 represented 51.2% of revenues compared to 38.8% for the same period in 2001. This increase is the result of a sharper decline in electricity prices than the rate of decline in fuel prices during the three months ended September 30, 2002 as compared to the same period in 2001. Fuel expense included $31.8 million of coal, $51.3 million of natural gas, and $36.4 million of fuel oil, diesel and other related costs. For the three months ended September 30, 2001, fuel expense included $28.7 million of coal, $61.7 million of natural gas, and $46.2 million of fuel oil, diesel and other related costs.

     Plant operations and maintenance expense for the three months ended September 30, 2002 was $45.2 million compared to $50.9 million for the same period in 2001, a decrease of $5.7 million or 11.2%. Plant operations and maintenance expense for the three months ended September 30, 2002 represented 19.3% of revenue, and included labor and benefits under operating service agreements of $16.8 million, maintenance parts, supplies and services of $14.6 million and property taxes and other expense of $13.8 million. Plant operations and maintenance expense for the three months ended September 30, 2001 represented 14.5% of revenue, and included labor and benefits under operating service agreements of $11.5 million, maintenance parts, supplies and services of $22.2 million and property taxes and other expenses of $17.2 million.

     Unrealized losses associated with changes in fair value of non-hedge energy related derivative instruments recorded in operating costs were $17.4 million for each of the three month periods ended September 30, 2002 and 2001.

Depreciation

     Depreciation costs were $13.6 million for the three months ended September 30, 2002, which is an increase of $1.4 million, or 11.5% from the same period in 2001. Depreciation expense was primarily related to the acquisition costs of the facilities, which are being depreciated over twenty-five to thirty years. The increase in depreciation expense is attributable to higher depreciable costs resulting from routine capital additions.

General and Administrative Expenses

     General and administrative expenses were $5.3 million for the three months ended September 30, 2002, compared to $5.5 million for the same period in 2001, a decrease of $0.2 million or 3.6%. General and administrative expenses include costs for outside legal and other contract services, payments to NRG Energy for corporate services, expenses related to office administration, as well as costs for certain employee benefits incurred under operating service agreements.

Interest Expense

     Interest expense for the three months ended September 30, 2002 was $12.9 million compared to $15.2 million for the three months ended September 30, 2001, a decrease of $2.3 million or 15.1%. Interest expense primarily relates to the amortization of deferred finance costs and interest on the senior secured bonds issued on February 22, 2000 and the affiliated note payable issued on June 15, 2002. The decrease in interest expense is attributable to a decline in the average principle amounts outstanding on the senior secured indebtedness.

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Other Income

     Other income for the three months ended September 30, 2002 was $0.1 million compared to $0.6 million for the same period in 2001, a decrease of $0.5 million or 83.3%.

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002 COMPARED TO THE NINE MONTHS ENDED
SEPTEMBER 30, 2001

     Net income for the nine months ended September 30, 2002 was $68.7 million, a decrease of $113.3 million compared to the same period in 2001. This change represents a decrease of 62.3%. This change was due to the factors described below.

Operating Revenues

     For the nine months ended September 30, 2002, the Company had total revenues of $550.3 million, compared to $898.7 million for the same period in 2001, a decrease of $348.4 million or 38.8%. The decrease in revenues for the nine months ended September 30, 2002 versus the same period in 2001 is due to a combination of lower capacity revenues realized of approximately $27.8 million and a 26% decline in megawatt hour generation compared with the same period in 2001. This decline in generation is attributable to an unseasonably warm winter and cooler spring which reduced demand for electricity, together with new regulation which reduced price volatility, particularly in New York City, where the Company’s plants sell into the merchant energy market.

Operating Costs

     For the nine months ended September 30, 2002, operating costs were $390.7 million compared to $621.8 million for the same period in 2001, a decrease of $231.1 million or 37.2%. Operating costs, as a percentage of operating revenues were 71.0% for the nine months ended September 30, 2002 compared to 69.2% for the same period in 2001. Operating costs primarily consist of expenses for fuel, plant operations and maintenance and unrealized gains or losses associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133. The decrease in operating costs is primarily due to a reduction in fuel cost due to a decline in power generation, a general decline in the price of fuel, lower expenditures on plant maintenance and operations and a $47.3 million favorable swing in unrealized losses associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

     Fuel expense for the nine months ended September 30, 2002 was $234.5 million compared to $393.5 million for same period in 2001, a decrease of $159.0 or 40.4%. Fuel expense for the nine months ended September 30, 2002, was 42.6% of revenues compared to 43.6% for the same period in 2001. Fuel expense included $79.7 million of coal, $92.4 million of natural gas, and $62.4 million of fuel oil, diesel and other related costs, for the nine months ended September 30, 2002. For the nine months ended September 30, 2001, fuel expense included $93.5 million of coal $135.6 million of natural gas, and $164.4 million of fuel oil, diesel and other related costs.

     Plant operations and maintenance expense for the nine months ended September 30, 2002 was $148.4 million compared to $173.2 million for the same period in 2001, a decrease of $24.8 million or 14.3%. Plant operations and maintenance expense for the nine months ended September 30, 2002 represented 27.0% of revenue, and included labor and benefits under operating service agreements of $49.4 million, maintenance parts, supplies and services of $54.9 million and property taxes and other expenses of $44.1 million. Plant operations and maintenance expense for the nine months ended September 30, 2001 represented 19.3% of revenue, and included labor and benefits under operating service agreements of $47.3 million, maintenance parts, supplies and services of $73.6 million and property taxes and other expenses of $52.3 million.

     Unrealized losses associated with changes in fair value of non-hedge energy related derivative instruments recorded in operating costs were $7.8 million for the nine months ended September 30, 2002 compared to $55.1 million for the same period in 2001.

Depreciation

     Depreciation costs were $39.8 million for the nine months ended September 30, 2002, which is an increase of $3.2 million, or 9% from the same period in 2001. Depreciation expense was primarily related to the acquisition costs of the facilities, which are being depreciated over twenty-five to thirty years. The increase in depreciation expense is attributable to higher depreciable costs resulting from routine capital additions.

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General and Administrative Expenses

     General and administrative expenses were $16.7 million for the nine months ended September 30, 2002, compared to $14.7 million for the same period in 2001, an increase of $2.0 million or 14%. General and administrative expenses include costs for outside legal and other contract services, payments to NRG Energy for corporate services, expenses related to office administration, as well as costs for certain employee benefits incurred under operating service agreements.

Interest Expense

     Interest expense for the nine months ended September 30, 2002 was $39.6 million compared to $45.6 million for the same period in 2001, a decrease of $6.0 million or 13%. Interest expense primarily relates to the amortization of deferred finance costs and interest on the senior secured bonds issued on February 22, 2000 and the affiliated note payable issued on June 15, 2002. The decrease in interest expense is attributable to a decline in the average principle amounts outstanding on the senior secured indebtedness.

Other Income

     Other income for the nine months ended September 30, 2002 was $5.2 million compared to $1.9 million for the same period in 2001, an increase of $3.3 million or 174%. The increase in other income is primarily attributable to of an insurance settlement for $1.5 million and a refund of transfer tax of $2.9 million related to the acquisition of the Company’s Connecticut assets, offset in part by other expenses of $1.1 million.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     The Company 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 8 Note 2 of the consolidated financial statements of the Company’s Form 10-K for the year ended December 31, 2001 for additional discussion regarding the Company’s accounting policies and estimates.

LIQUIDITY AND CAPITAL RESOURCES

     The Company and its majority-owned subsidiaries have historically obtained cash from operations, issuance of debt securities, and borrowings under credit facilities or affiliated loans. The Company has used these funds to finance operations, service debt obligations, fund the acquisition, development, and construction of generation facilities, finance capital expenditures and meet other cash and liquidity needs.

     The bonds and working capital facility agreements of the Company generally restrict its ability to pay dividends, make distributions or otherwise transfer funds to NRG Energy under certain circumstances. As of September 30, 2002, the Company did not meet the required minimum debt service coverage ratios, and therefore is restricted from making payments to NRG Energy.

     On February 22, 2000, the Company issued $750 million of senior secured bonds to refinance short-term project borrowings and for certain other purposes. The bond offering included three tranches: $320 million with an interest rate of 8.065% due in 2004; $130 million with an interest rate of 8.842% due in 2015; and $300 million with an interest rate of 9.292% due in 2024. Principal payments are made semi-annually. The bonds are jointly and severally guaranteed by each of the Company's existing and future subsidiaries. The bonds are secured by a security interest in the Company's membership or other ownership interests in the guarantors and its rights under all intercompany notes between the Company and the guarantors. At September 30, 2002, $556.5 million of bonds remain outstanding and are classified as current.

     Prior to the NRG Energy downgrades, the debt service reserve account of the Company was funded with a letter of guarantee from the parent company. Following the downgrade, the Company received notice from the trustee on September 9 requesting the cash funding of the debt service reserve account within 30 days. On October 9 NRG Energy failed to fund the debt service reserve account, which created an event of default that, if not cured within 60 days, gives the bond holders rights of acceleration. The project is precluded from making payments to NRG Energy. As a result of this impending default, the long-term portion of the debt has been reclassified to a current liability, as it is potentially callable within the next twelve months.

     As of October 31, 2002, the Company had cash and cash equivalents of approximately $100 million.

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     On August 19, 2002, NRG Energy executed a Collateral Call Extension Letter (CCEL) with various secured project lender groups in which the banks agreed to extend, until September 13, 2002, the deadline by which NRG Energy must post its approximately $1.0 billion of cash collateral in connection with certain bank loan agreements. Subsequently, NRG Energy and these various secured project lenders entered into a Second Collateral Call Extension Letter (Second CCEL) extending, until November 15, 2002, the deadline by which NRG Energy must post such collateral.

     On November 6, 2002, lenders to NRG Energy accelerated approximately $1.1 billion of NRG Energy’s debt under a construction revolver financing facility, rendering the debt immediately due and payable. This action terminated the Second CCEL in effect between NRG Energy and its major lenders. The extension letter was previously scheduled to expire November 15, 2002. Based on discussions with the construction revolver lenders it is NRG Energy’s understanding that the administrative agent, Credit Suisse First Boston, issued the acceleration notice to preserve certain rights under the construction revolver financing agreements. NRG Energy believes that the administrative agent intends to forbear in the immediate exercise of any rights and remedies against the Company.

     Starting in August 2002, NRG Energy engaged in the preparation of a comprehensive business plan and forecast. The business plan detailed the strategic merits and financial value of NRG Energy’s projects and operations. It also anticipates that NRG Energy will function independently from Xcel Energy and thus all plans and efforts to combine certain functions of the companies were terminated. NRG Energy utilized independent electric revenue forecasts from an outside energy markets consulting firm to develop forecasted cash flow information included in the business plan. Management concluded that the forecasted free cash flow available to NRG Energy after servicing project-level obligations will be insufficient to service recourse debt obligations. Based on this information and in consultation with Xcel Energy and its financial advisor, NRG Energy prepared and submitted a restructuring plan on November 4, 2002 to various lenders, bondholders and other creditor groups (collectively, “NRG Energy’s Creditors”) of NRG Energy and its subsidiaries. The restructuring plan is expected to serve as a basis for negotiations with NRG Energy’s Creditors in a financially-restructured NRG Energy and, among other things, proposes (i) holders of secured (project-level) debt would either (a) have their debt reinstated with agreed modifications or (b) receive the collateral securing such debt and a claim or claims to the extent such debt is under-secured; (ii) holders of unsecured debt, holders of secured recourse claims against NRG Energy, and holders of other general unsecured claims against NRG Energy would receive a pro rata share of (a) an aggregate of $500 million of junior secured debt of reorganized NRG Energy and (b) 95% of the common equity of reorganized NRG Energy; and (iii) holders of project-level general unsecured claims that are non-recourse to NRG Energy would receive a pro rata share of the remaining 5% of the common equity of a reorganized NRG Energy.

     The restructuring plan also includes a proposal by Xcel Energy that in return for a release of any and all claims against Xcel Energy, upon consummation of the restructuring, Xcel Energy would pay $300 million to NRG Energy and surrender its equity ownership of NRG Energy.

     If an agreement were reached with NRG Energy’s Creditors on a restructuring plan, it would most likely lead to NRG Energy commencing a Chapter 11 bankruptcy case and immediately seeking approval of a prenegotiated plan of reorganization. The absence of an agreement will increase the possibility of NRG Energy seeking protection under the bankruptcy laws.

     If NRG Energy files under Chapter 11, it is likely that NRG Energy would also file certain wholly-owned subsidiaries, which may include the Company.

     Throughout the restructuring process, NRG Energy seeks to operate the business in a manner that management believes will offer to creditors similar protection as would be offered by a bankruptcy court. NRG Energy attempts to preserve the enterprise value of the business and to treat creditors within each creditor class without preference, unless otherwise agreed to by advisors to all potentially affected creditors. By operating the Company within this framework, NRG Energy desires to mitigate the risk that creditors will pursue involuntary bankruptcy proceedings against NRG Energy or its material subsidiaries.

     The credit rating downgrades, defaults under certain agreements, increased collateral requirements, creditor’s actions and reduced liquidity that have occurred during the quarter ended September 30, 2002 have created substantial doubt as to NRG Energy’s ability to continue as a going concern. The absence of a restructuring agreement will increase the possibility of NRG Energy and certain of its subsidiaries, including the Company, seeking protection under the bankruptcy laws.

Cash Flows

     Net cash provided by operations decreased during the nine months ended September 30, 2002 compared to the same period in 2001. The most significant changes in working capital items related to the decrease in Inventory and the increases in Accounts Receivable and Accounts Receivable — Affiliate during 2002.

     Net cash used in investing activities for the nine months ended September 30, 2002 increased in comparison to the same period in 2001. The increase is due to the increase in capital expenditures in the current period.

     Net cash used in financing activities for the nine months ended September 30, 2002 decreased from the same period in 2001. The decrease is primarily due to significant capital distributions in 2001 and no capital distributions in 2002.

     The debt agreements of NRG Energy’s subsidiaries and project affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to NRG Energy. As of September 30, 2002, the Company is restricted from making cash payments to NRG Energy. On October 31, 2002, the Company had approximately $100 million of cash on hand.

Capital Commitments

Prospective Capital Requirements

     The Company estimates $25 million and $35 million in capital spending for the period from October 21 through December 31, 2002, and for calendar year 2003, respectively. These amounts include the cost of capital improvements, minor refurbishments, and expansions of projects in operation. The Company plans to fund these liquidity needs with cash on hand and operating cash from generating assets. Current financial plans estimate cash from operations of $125 million to $150 million for 2003.

     The Company’s capital expenditure program is subject to continuing review and modification. Actual expenditures may differ from these estimates.

Contractual obligations and commercial commitments

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Other Contingencies

Contract Negotiation

     In July 2002, NRG Energy reached a tentative agreement with Connecticut Light & Power (CL&P) that would result in increased compensation to NRG Energy, a supplier of CL&P’s wholesale supply agreement. CL&P filed an emergency petition with the Connecticut Department of Public Utility Control (DPUC) asking for approval of a shift of wholesale supply agreement revenues, effective August 1, 2002, through December 31, 2003, that would reallocate 0.7 cents per kilowatt-hour in the wholesale price paid to existing suppliers. On July 26, 2002, the DPUC denied the request of CL&P for an emergency letter ruling. On August 9, 2002, NRG Energy announced that it had reached an agreement with ISO-New England to keep three units at its Devon station in service. The agreement expires on September 30, 2003.

Derivative Instruments

     The tables below disclose the Company's derivative activities that include non-exchange traded contracts accounted for at fair value. Specifically, these tables disaggregate realized and unrealized changes in fair value; identifies changes in fair value attributable to changes in valuation techniques; disaggregates estimated fair values at September 30, 2002 based on whether fair values are determined by quoted market prices or more subjective means; and indicates the maturities of contracts at September 30, 2002.

Derivative Activity

Sources of Fair Value Gains/(Losses)

NEW ACCOUNTING PRONOUNCEMENTS

     In June 2001, the Financial Accounting Standards Board (the FASB) issued Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (SFAS No. 142). SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized but instead be tested for impairment in accordance with SFAS No. 121, Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of (SFAS No. 121). Goodwill will no longer be amortized to comply with the provisions of SFAS No. 142. Instead, goodwill and intangible assets that will not be amortized should be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value. An impairment test is required to be performed within nine months of the date of adoption, and the first annual impairment test must be performed in the year the statement is initially adopted. The Company and its subsidiaries have adopted the provisions of SFAS No. 142 effective January 1, 2002. No impairments on assets were recorded upon adopting SFAS 142 on January 1, 2002.

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     In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). This statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. 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. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. The Company has not completed its analysis of SFAS No. 143.

     In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144). This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 retains and expands upon the fundamental provisions of existing guidance related to the recognition and measurement of the impairment of long-lived assets to be held and used and the measurement of long-lived assets to be disposed of by sale. Generally, the provisions of SFAS No. 144 are effective for financial statements issued for fiscal years beginning after December 15, 2001. The Company and its subsidiaries have adopted SFAS No. 144 effective January 1, 2002. No asset impairments have been recognized as a result of adopting SFAS No. 144 through the first three quarters of 2002.

     In April 2002, FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections (SFAS No. 145), that supercedes 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 for prior periods required. In addition, SFAS No. 145 amends SFAS No. 13, Accounting for Leases (SFAS No. 13), 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 are effective for transaction occurring after May 15, 2002. SFAS No. 145 will be applied as required. Adoption of SFAS No. 145 is not expected to have a material impact on the Company.

     In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 addresses financial reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force 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, with early application encouraged. The Company has not completed its analysis of SFAS No. 146.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The Company is exposed to market risks, including changes in commodity prices and interest rates, and credit risk as disclosed in Management’s Discussion and Analysis in its annual report on Form 10-K for the year ended December 31, 2001. There have been no material changes as of September 30, 2002 to the market risk disclosures presented as of December 31, 2001.

Item 4. Controls and Procedures

     NRG’s Chief Operating Officer and Chief Financial Officer have evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-14(c ) and 15d-14(c )) under the Securities Exchange Act of 1934, as amended (Exchange Act) as of a date within 90 days prior to the filing date of this quarterly report (Evaluation Date). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the Company’s disclosure controls and procedures

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are effective in alerting them on a timely basis to material information relating to the Company including its consolidated subsidiaries) required to be included in the Company’s periodic filings under the Act.

     Since the Evaluation Date, there have not been any significant changes in the Company’s internal controls or in other factors that could significantly affect such controls.

Part II — OTHER INFORMATION

Item 1. Legal Proceedings

Fortistar Capital v. NRG Energy

     In July 1999, Fortistar Capital Inc., a Delaware corporation, filed a complaint in District Court (Fourth Judicial District, Hennepin County) in Minnesota against NRG Energy asserting claims for injunctive relief and for damages as a result of NRG Energy’s alleged breach of a confidentiality letter agreement with Fortistar relating to the Oswego facility in New York. NRG Energy disputed Fortistar’s allegations and asserted numerous counterclaims. In October 1999, the Company closed on the acquisition of the Oswego facility. In April and December 2000, NRG Energy filed summary judgment motions to dispose of the litigation. A hearing on these motions was held in February 2001 and certain of Fortistar’s claims were dismissed. On May 8, 2002 the parties entered into a binding, conditional settlement of the litigation, pending certain approvals and final agreement on the terms of the settlement. The settlement also encompassed litigation between the parties with respect to Minnesota Methane LLC. At the end of August, 2002, NRG Energy asserted that conditions for consummation of the settlement had not been met, while Fortistar moved the Court to enter judgement against NRG Energy to enforce the settlement. At the Court’s encouragement, the parties are now engaged in further settlement efforts to resolve all outstanding issues between them.

New York Environmental Litigation

     In January 2002 the New York Attorney General and the New York Department of Environmental Conservation filed suit in the United States District Court, Western District of New York against, NRG Energy and Niagara Mohawk Power Corporation (NiMo), the prior owner of the Huntley and Dunkirk facilities in New York. The lawsuit relates to physical changes made at those facilities prior to NRG Energy’s assumption of ownership. The complaint alleges that these changes represent major modifications undertaken without the required permits having been obtained and seeks a judgement requiring NRG Energy and/or NiMo to install emissions control equipment to reduce emissions of nitrogen oxides and sulfur dioxides. Although NRG Energy has a right to indemnification by the previous owner for fines, penalties, assessments and related losses resulting from the previous owner’s failure to comply with environmental laws and regulations, NRG Energy could be enjoined from operating the facilities if the facilities are found not to comply with applicable permit requirements and it could be required to bear the costs of installing emissions controls. NRG Energy has filed a motion to dismiss the claims against it which was heard in July 2002. The Court’s ruling on that motion is still pending.

     In July 2001, NiMo filed a declaratory judgment action in the Supreme Court for the State of New York, County of Onondaga, against NRG Energy and its wholly-owned subsidiaries, Huntley Power LLC and Dunkirk Power LLC. NiMo requests a declaration by the Court that, pursuant to the terms of the Assets Sales Agreement under which NRG Energy purchased the Huntley and Dunkirk generating facilities from NiMo (the ASA), defendants have assumed liability for any costs for the installation of emissions controls or other modifications to or related to the Huntley or Dunkirk plants imposed as a result of violations or alleged violations of environmental law. NiMo also requests a declaration by the Court that, pursuant to the ASA, defendants have assumed all liabilities, including liabilities for natural resource damages, arising from emissions or releases of pollutants from the Huntley and Dunkirk plants, without regard to whether such emissions or releases occurred before, on or after the closing date for the purchase of the Huntley and Dunkirk plants. NRG Energy has counterclaimed against NiMo, and the parties have exchanged materials.

NYDEC Opacity Notice of Violation

     NRG Energy became part of an opacity consent order negotiation as a result of acquiring its Huntley, Dunkirk and Oswego plants from NiMo. At the time of financial close on these assets, a consent order was being negotiated between NiMo and the NYDEC; it required NiMo to pay a stipulated penalty for each opacity event at these facilities. On January 14, 2002, the NYDEC issued NRG Energy Notices of Violations (NOV) for opacity events, which had occurred since the time NRG Energy assumed ownership of the Huntley, Dunkirk and Oswego generating stations. The NOVs allege that a total of 7,231 events had occurred where the average opacity during a six-minute block of time had exceeded 20%. The NYDEC proposed a penalty associated with the NOVs of $900,000. NRG Energy is in negotiations with the NYDEC to settle the dispute.

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Constellation Power Source Inc. Agreement

     On August 2, 2002, the Company received payment under a net settlement agreement, of approximately $20 million from Constellation Power Source, Inc., through their affiliate, NRG Power Marketing. The agreement provides for the termination of a long-term power purchase contract dated February 25, 2002 between Constellation and NRG Power Marketing on the Company’s behalf.

Item 3. Defaults Upon Senior Securities

     NRG Northeast has identified the following material defaults with respect to the indebtedness of the Company and its significant subsidiaries:

     $320 million of 8.065% Series A Senior Secured Bonds due 2004 by NRG Northeast Generating LLC

•

Failure to fund debt service reserve account

     $130 million of 8.824% Series B Senior Secured Bonds due 2015 by NRG Northeast Generating LLC

•

Failure to fund debt service reserve account

     $300 million of 9.29% Series C Senior Secured Bonds due 2024 by NRG Northeast Generating LLC

•

Failure to fund debt service reserve account

Item 6. Exhibits and Reports on Form 8-K

	(A)		Exhibits
			99.1 Officers’ Certification
	(B)		Reports on Form 8-K
			On October 24, 2002, the Company filed a Form 8-K reporting under Item 5 — Other Events.

On October 18, 2002, NRG Energy announced that it had reached an agreement with certain of its bank lenders to extend until November 15, the deadline by which it must post approximately $1 billion of cash collateral in connection with certain bank loan agreements. NRG Energy also announced the filing by The Shaw Group Inc. of an involuntary petition for liquidation of LSP-Pike Energy, LLC under Chapter 7 of the U.S. Bankruptcy Code. Shaw, the contractor for NRG Energy’s Pike power plant construction project in Holmesville, Mississippi, also filed suit against NRG Energy and Xcel Energy alleging claims connected with the Pike project.

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Cautionary Statement Regarding Forward-Looking Statements

     The information presented in this Form 10-Q includes forward-looking statements in addition to historical information. These statements involve known and unknown risks and relate to future events, or projected business results. In some cases forward-looking statements may be identified by their use of such words as “may,” “expects,” “plans,” “anticipates,” “believes,” and similar terms. Forward-looking statements are only predications, and actual results may differ materially from the expectations expressed in any forward-looking statement. While the Company believes that the expectations expressed in such forward-looking statements are reasonable, we can give no assurances that these expectations will prove to have been correct. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

	•		NRG Energy’s ability to reach agreements with its lenders and creditors to restructure debt and delay the funding of collateral required following NRG Energy’s, and the Company’s, ratings downgrades by Moody’s and Standard & Poor’s;
	•		NRG Energy’s ability to sell assets in the amounts and on the time table assumed;
	•		General economic conditions including inflation rates and monetary exchange rate fluctuations; the risk of a significant slowdown in growth in the U.S. economy or risk of delay in growth recovery in the U.S. as a consequence of the September 11, 2001 terrorist attacks and other factors;
	•		Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where the Company has a financial interest;
	•		Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services;
	•		Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;
	•		Factors affecting the availability or cost of capital such as changes in: interest rates; market perceptions of the power generation industry, the Company or any of its subsidiaries; or credit ratings;
	•		Factors affecting power generation operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;
	•		Employee workforce factors including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;
	•		Volatility of energy prices in a deregulated market environment:
	•		Increased competition in the power generation industry;
	•		Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;
	•		Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;
	•		Factors associated with various investments including competition, operating risks, dependence on certain suppliers and customers, and environmental and energy regulations;
	•		Other business or investment considerations that may be disclosed from time to time in the Company’s Securities and Exchange Commission filings or in other publicly disseminated written documents including the Company’s Registration Statement No. 333-42638, as amended.