NRG NORTHEAST GENERATING LLC - 10-K Annual 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 þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is an accelerated filer as defined by Rule 12b-2 of the Act. Yes o No þ

As of the last business day of the most recently completed second fiscal quarter, no voting or non-voting common equity was held by non-affiliates.

As of the latest practicable date, Northeast Generation Holding LLC owned 50% of the outstanding equity interests of NRG Northeast Generating LLC and NRG Eastern LLC owned 50% of the outstanding equity interests of NRG Northeast Generating LLC. Northeast Generation Holding LLC and NRG Eastern LLC are each wholly-owned subsidiaries of NRG Energy, Inc.

NRG Northeast Generating LLC, (NRG Northeast) is a Delaware limited liability company, formed in 1999. NRG Northeast owns electric power generation plants in the northeastern region of the United States through its family of subsidiaries and was formed for the purpose of financing, acquiring, owning, operating and maintaining electric generating facilities. NRG Northeast’s headquarters and principal executive offices are located at 901 Marquette Avenue, Suite 2300, Minneapolis, Minnesota 55402. NRG Northeast’s phone number is (612) 373-5300.

NRG Northeast’s assets represent a diversified regional base of generating facilities in Connecticut, Massachusetts and New York. NRG Northeast’s revenues are derived from base-load, intermediate and peaking facilities. The facilities are diversified in terms of fuel usage and include coal, natural gas and fuel oil plants, or combination thereof.

NRG Northeast is an indirect wholly-owned subsidiary of NRG Energy, Inc. (NRG Energy). NRG Energy is an energy company, primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States and internationally. NRG Energy is a wholly owned subsidiary of Xcel Energy Inc. (Xcel Energy). Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. Xcel Energy also owns or has interest in a number of non-regulated businesses, the largest of which is NRG Energy.

Due to a number of reasons, including the overall down-turn in the energy industry, NRG Energy’s financial condition has deteriorated significantly. As a direct consequence, in 2002 NRG Energy entered into discussions with its creditors in anticipation of a comprehensive restructuring. NRG Energy is working toward this goal by selective divestiture of non-core assets, consolidation of management, reorganization and redirection of power marketing philosophy and activities and an overall financial restructuring that will improve liquidity and reduce debt. In connection with its restructuring efforts, it is likely that NRG Energy (and certain of its subsidiaries) will file for Chapter 11 bankruptcy protection. If NRG Energy seeks protection under Chapter 11 of the Bankruptcy Code, it is likely that NRG Energy would also seek such protection for certain wholly-owned subsidiaries, which would likely include NRG Northeast. For more information about NRG Energy’s restructuring process, refer to the Form 10-K filed by NRG Energy on March 31, 2003.

As a part of the comprehensive restructuring of NRG Energy, NRG Energy’s financial and legal restructuring advisors have been assisting the management of NRG Northeast in the preparation of a comprehensive financial and operational restructuring for NRG Northeast. NRG Northeast and its advisors have been meeting regularly to discuss restructuring issues relating to NRG Northeast with an ad hoc committee of its bondholders (the NRG Northeast Bondholder Committee). NRG Northeast, its management and its financial and legal advisors have engaged in discussions with the NRG Project Bondholder Committee regarding the terms and conditions of a restructuring of the debt of NRG Northeast.

NRG Northeast, NRG Energy and Xcel Energy file periodic reports and other documents with the Securities and Exchange Commission. The public may read and copy the materials filed with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. The public may also obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, electronic copies of these periodic filings are available through the Commission’s web site at www.sec.gov.

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 $432.0 million in debt. NRG Energy also canceled 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 lowered their ratings on NRG Energy’s and its subsidiaries’ unsecured bonds once again. Currently, NRG Energy’s unsecured bonds carry a rating of between CCC and D at S&P and between Ca and C at Moody’s, depending on the specific debt issue.

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, related to various operating projects as well as for projects that were under construction which NRG Energy has stopped funding.

NRG Energy and its subsidiaries (including NRG Northeast) have failed to timely make several interest and/or principal payments on its 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. For more specific information regarding NRG Energy’s liquidity issues, refer to “Liquidity Issues” in Item 1 of Form 10-K filed by NRG Energy on March 31, 2003.

In addition to the payment defaults described above, prior to the downgrades many corporate guarantees and commitments of NRG Energy and its subsidiaries required that they be supported or replaced with letter 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 received demands to post collateral aggregating approximately $1.1 billion. NRG Energy is presently working with various secured project lender groups with respect to the issue of posting collateral and is working toward 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 such comprehensive financial and operational restructuring. NRG Energy and its advisors have been meeting regularly to discuss restructuring issues with an ad hoc committee of its bondholders and a steering committee of its bank lenders (the Ad Hoc Creditors Committees). In November 2002, NRG Energy and Xcel Energy presented a comprehensive plan of restructuring to the Ad Hoc Creditors Committees. The restructuring plan has 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. If a comprehensive plan of restructuring is ultimately agreed to, it is highly probable that such a plan would be implemented through the commencement of a voluntary Chapter 11 bankruptcy proceeding. If NRG Energy seeks protection under Chapter 11 of the Bankruptcy Code, it is likely that NRG Energy would also seek such protection for certain wholly-owned subsidiaries, which would likely include NRG Northeast. For more specific information regarding NRG Energy’s restructuring efforts, refer to “Liquidity Issues” in Item 1 of Form 10-K filed by NRG Energy on March 31, 2003.

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. Under provisions of federal law, NRG Energy has the full authority to continue to operate its business as if the involuntary petition had not been filed unless and until a court hearing on the validity of the involuntary petition is resolved adversely to NRG Energy. On December 16, 2002, NRG Energy responded to the involuntary petition, contesting the petitioners’ claims and filing a motion to dismiss the case. On February 19, 2003, NRG Energy announced that it had reached a settlement with the petitioners. The U.S. Bankruptcy Court for the District of Minnesota will hear NRG Energy’s motion to approve the settlement and dismiss the involuntary petition. Two of NRG Energy’s creditors have objected to the motion to dismiss. There can be no assurance that the court will dismiss the involuntary petition. The Bankruptcy Court has discretion in the review and approval of the settlement agreement. There is a risk that the Bankruptcy Court may, among other things, reject the settlement agreement or enter an order for relief under Chapter 11.

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’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 13 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.

On February 22, 2000, NRG Northeast 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 and interest payments are made semi-annually on each June 15 and December 15. The bonds are jointly and severally guaranteed by each of NRG Northeast’s existing and future subsidiaries. The bonds are secured by a security interest in NRG Northeast’s membership and/or other ownership interests in the guarantors and its rights under all intercompany notes between NRG Northeast and the guarantors. At December 31, 2002, $556.5 million of bonds remain outstanding and are classified as current. NRG Northeast secured bonds currently carry a rating of D at S&P and Caa1 at Moody’s.

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

The debt agreements of NRG Northeast generally restrict its ability to pay dividends, make distributions or otherwise transfer funds to NRG Energy under certain circumstances such as failure to maintain a required minimum debt service ratio. As of December 31, 2002, NRG Northeast did not meet the required minimum debt service coverage ratios, and therefore is restricted from making any payments to NRG Energy.

NRG Northeast is also precluded from making payments to NRG Energy due to an unfunded debt service reserve account. Prior to the NRG Energy downgrades (see above), the debt service reserve account of NRG Northeast was funded with a letter of guarantee from NRG Energy. Following the downgrade, this account was required to be funded with cash from NRG Energy within five to thirty days. The account was not funded with cash from NRG Energy within the respective cure period, and an event of default occurred, thereby giving the lenders the right to accelerate the project financings. As a result of this default, the long-

term portion of the debt has been reclassified as a current liability, as it is potentially callable within the next twelve months. NRG Northeast has approximately $40.1 million of unfunded debt service reserve commitments as of December 31, 2002.

NRG Northeast and its subsidiaries have failed to timely make the following interest and/or principal payments to non-affiliates on its indebtedness:

On December 27, 2002, NRG Northeast made the $24.7 million interest payment due on the NRG Northeast bonds but failed to make the $53.5 million principal payment. As of March 31, 2003, NRG Northeast had cash and cash equivalents of approximately $12 million.

NRG Northeast owns a total of ten fossil fuel-fired and four remote gas turbine electric power generation facilities, as described below. The purchase price set forth below for certain of the facilities is based on an allocation made when more than one facility was purchased pursuant to the same purchase and sale agreement.

Arthur Kill Facility. NRG Northeast acquired the Arthur Kill facility from the Consolidated Edison Company of New York, Inc. (ConEd) in June 1999 for a purchase price of $395.5 million. The Arthur Kill facility, located in Staten Island, New York, is a natural gas/oil-fired intermediate/peaking plant consisting of 3 units and having a capacity of 842 MW (including a black start gas turbine).

Astoria Facility. NRG Northeast acquired the Astoria facility from ConEd in June 1999 for a purchase price of $109.5 million. The Astoria facility, located in Queens, New York, is a gas/liquid fuel-fired peaking plant consisting of 20 units and having a capacity of 614 MW.

Connecticut Jet Facilities. NRG Northeast acquired four unmanned aero derivative combustion turbine facilities (ICU) from Connecticut Light & Power Company (CL&P) in December 1999 for a purchase price of $22.3 million. These ICU facilities, located at local switchyards in Branford, Torrington Terminal, Franklin Drive and Cos Cob, are oil-fired peaking units consisting of 6 units and having an aggregate capacity of 127 MW.

Devon Facility. NRG Northeast acquired the Devon facility from CL&P in December 1999 for a purchase price of $113.3 million. The Devon facility, located in Milford, Connecticut, is a natural gas/oil-fired intermediate/peaking load facility consisting of 7 units and having a capacity of 401 MW.

Dunkirk Facility. NRG Northeast acquired the Dunkirk facility from Niagara Mohawk Power Corporation (NiMo) in June 1999 for a purchase price of $193.3 million. The Dunkirk facility, located in

Dunkirk, New York (near Buffalo), is a coal-fired base-load facility consisting of 4 units and having a capacity of 600 MW. The Dunkirk facility is among the lowest variable cost fossil fuel plants that sell into the New York Independent Operator’s wholesale markets (NYISO).

Huntley Facility. NRG Northeast acquired the Huntley facility from NiMo in June 1999 for a purchase price of $161.7 million. The Huntley facility, located five miles northeast of Buffalo, New York, is a coal-fired base-load facility consisting of 6 units and having a capacity of 760 MW. The Huntley facility is among the lowest cost fossil fuel plants that sell into the NYISO markets.

Middletown Facility. NRG Northeast acquired the Middletown facility from CL&P in December 1999 for a purchase price of $225.8 million. The Middletown facility, located in Middletown, Connecticut, is a natural gas/oil-fired intermediate/peaking plant consisting of 5 units and having a capacity of 856 MW, of which one unit of 70 MW is in deactivated-reserve and has not renewed its air permit.

Montville Facility. NRG Northeast acquired the Montville facility from CL&P in December 1999 for a purchase price of $82.8 million. The Montville facility, located in Uncasville, Connecticut, is a natural gas/oil-fired intermediate/peaking load plant consisting of 4 units and having a capacity of 498 MW.

Norwalk Facility. NRG Northeast acquired the Norwalk facility from CL&P in December 1999 for a purchase price of $75.0 million. The Norwalk facility, located in Norwalk, Connecticut, is an oil-fired intermediate/peaking load plant consisting of 3 units and having a capacity of 353 MW.

Oswego Facility. NRG Northeast acquired the Oswego facility from NiMo and Rochester Gas & Electric Company (RG&E) in October 1999 for a purchase price of $84.9 million. The Oswego facility, located in Oswego, New York, is a natural gas/oil-fired peaking plant consisting of 2 units and having a capacity of 1,700 MW. The Oswego facility has a very low cost capacity factor and is a source of excess emissions allowances that can be utilized at NRG Northeast’s other facilities. NRG Northeast operates the Oswego facility as a peaking facility.

Somerset Facility. NRG Northeast acquired the Somerset facility from Montaup Electric Company (MEC) in April 1999 for a purchase price of $55.2 million. The Somerset facility, located in Somerset, Massachusetts, is a coal-fired base-load facility consisting of 1 unit and having a capacity of 112 MW. The Somerset facility also owns one deactivated coal-fired unit of 69 MW and two oil-fired, peaking units with a combined capacity of 48 MW (of which one is retired). Total operational capacity at Somerset is 136 MW. The Somerset facility is strategically positioned to sell power into the New England Power Pool (ISO-NE). NRG Operating Services, Inc. operates the Somerset facility as a base-load facility, with peaking capacity depending on market conditions.

NRG Northeast is an owner of electric power generation in the northeastern region of the United States. NRG Northeast’s regional base of generating facilities is close to major load centers. NRG Northeast’s regional generating facilities are diverse in terms of operational characteristics, location in and access to multiple power pools and fuel sources.

NRG Energy’s energy marketing subsidiary, NRG Power Marketing Inc. (NRG Power Marketing), provides a full range of energy management services for NRG Energy’s generation facilities in its Eastern and Central regions. These services are provided under bilateral contracts or agency agreements pursuant to which NRG Power Marketing manages the sales and purchases of energy, capacity and ancillary services, procures the fuel (coal, oil and natural gas) and associated transportation and manages the emission allowance credits for these facilities. NRG Power Marketing has continued to provide these services since NRG Energy lost its investment grade ratings in July 2002, and because of NRG Energy’s credit and liquidity limitations, NRG Power Marketing has scaled back its activities. Since July 2002, NRG Power Marketing has focused primarily on procuring fuel for, and marketing the power from, NRG Energy’s North American generation facilities in the spot and short-term markets.

NRG Operating Services, Inc. (NRG Operating Services), a direct wholly-owned subsidiary of NRG Energy, has entered into operation and maintenance agreements with each of the subsidiaries of NRG Northeast. Each agreement has an initial term of five years, with options to extend beyond five years. Under the agreements, the NRG Operating Services company operator is reimbursed for usual and customary costs related to providing operations and maintenance services, including plant labor and other operating costs. The NRG Operating Services subsidiary performs all administrative, operations and maintenance work at each facility.

NRG Northeast is subject to a broad range of federal, state and local environmental and safety laws and regulations applicable to the development, ownership and operation of its projects. These laws and regulations impose requirements relating to discharges of substances to the air, water and land, the handling, storage and disposal of hazardous substances and wastes and the cleanup of properties affected by pollutants. These laws and regulations generally require that NRG Northeast obtain a number of governmental permits and approvals before construction or operation of a power plant commences and, after completion, that its facilities operate in compliance with those permits and applicable legal requirements. NRG Northeast could also be held responsible under these laws for the cleanup of pollutants released at its facilities or at off-site locations where it has sent wastes.

NRG Northeast strives at all times to comply with the terms of all environmental and safety laws, regulations, permits and licenses and NRG Northeast believes that all of its operating plants are in material compliance with applicable environmental and safety requirements. NRG Northeast also does not expect that its liability under environmental laws for the cleanup of contamination at its plants or off-site waste disposal facilities will have a material effect on the results of its operations. NRG Northeast cannot assure you, however, that in the future it will not incur material environmental liabilities, that it will obtain all necessary permits for its operations or that it will operate in full compliance with environmental and safety laws and regulations at all times. In addition, regulatory compliance for the construction of new facilities is a costly and time-consuming process. Intricate and rapidly changing environmental regulations may require major capital expenditures for permitting and create a risk of expensive delays or material impairment of project value if projects cannot function as planned due to changing regulatory requirements or local opposition. Environmental laws have become increasingly stringent over time, particularly with regard to the regulation of air emissions from NRG Northeast’s plants, which requires regular major capital expenditures for power plant upgrades and modifications. Therefore, it is NRG Northeast’s policy to integrate the consideration of potential environmental impacts into every decision it makes, and by doing so, strive to improve its competitive advantage by meeting or exceeding environmental and safety requirements pertaining to the management and operation of its assets. (See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental Matters).

Various federal and state laws pertaining to power generation and sales also affect NRG Northeast. The Federal Power Act regulates the sale of electricity in the wholesale market. The Federal Energy Regulatory Commission (FERC) is an independent agency within The Department of Energy that regulates the transmission and wholesale sale of electricity in interstate commerce under the authority of The Federal Power Act. FERC is also responsible for licensing and inspecting private, municipal and state-owned hydro electric projects. FERC determines whether a public utility qualifies for exempt wholesale generator (EWG) status under The Public Utility Holding Company Act, which was amended by The Energy Policy Act of 1992.

Federal Power Act. The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of electricity in interstate commerce. FERC regulates the owners of facilities used for the wholesale sale of electricity and its transmission in interstate commerce as

“public utilities” under the Federal Power Act. The Federal Power Act also gives FERC jurisdiction to review certain transactions and numerous other activities of public utilities (such as the granting of waivers of certain of the accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules).

Under the Federal Power Act, an entity that sells electricity in the wholesale market is a public utility, subject to FERC’s jurisdiction. Public utilities are required to obtain FERC’s acceptance of their rate schedules for wholesale sales of electricity. Because NRG Northeast’s operating subsidiaries sell energy and capacity in the wholesale market, they are deemed to be public utilities for purposes of the Federal Power Act. In most cases, FERC has granted the NRG Northeast operating companies the authority to sell electricity at market-based rates (Arthur Kill Power, Astoria Power, Dunkirk Power, Huntley Power, Somerset Power, Oswego Power, Connecticut Jet Power, Devon Power, Middletown Power, Montville Power and Norwalk Power applied for and were granted market-based rate authority for the wholesale sales of power by FERC in 1999). In New England, New York, PJM (Pennsylvania, New Jersey, Maryland, Delaware and parts of the Midwest) the Midwest and California, FERC has established Independent System Operators (ISOs) which file market-based rate tariffs, subject to FERC Approval. These tariffs/market rules dictate how the wholesale markets are to operate and how entities with market-based rates shall be compensated within those markets. The ISOs in these regions also control access to, pricing of and the operation of the transmission grid within their footprint. Outside of ISO controlled regions, NRG Northeast is allowed to sell at market-based rates as determined by willing buyers and sellers. Access to, pricing for and operation of the transmission grid in such regions is controlled by the local transmission owning utility according to their Pro Forma Open Access Transmission Tariff (OATT) filed with and approved by FERC.

Usually, FERC’s orders which grant NRG Northeast market-based rate authority reserve the right to revoke or revise the market-based rate authority on a prospective basis if FERC subsequently determines that NRG Northeast possesses excessive market power. If NRG Northeast lost its market-based rate authority, NRG Northeast may be required to obtain FERC’s acceptance of a cost-of-service rate schedule and may become subject to the accounting, record-keeping and reporting requirements that are imposed only on utilities with cost-based rate schedules. It should be noted, however, that NRG Northeast does have the right at any time to petition FERC to grant cost of service based rates pursuant to Section 205 of the Federal Power Act.

Public Utility Holding Company Act (PUHCA). The Public Utility Holding Company Act, known as PUHCA, provides that any entity that owns, controls or has the power to vote 10% or more of the outstanding voting securities of an “electric utility company,” or a holding company for an electric utility company, is subject to regulation under PUHCA.

Registered holding companies under PUHCA are required to limit their utility operations to a single, integrated utility system and divest any other operations that are not functionally related to the operation of the utility system. In addition, a company that is a subsidiary of a holding company registered under PUHCA is subject to financial and organizational regulation, including approval by the SEC of certain financings and transactions. Under the Energy Policy Act of 1992, however, FERC can determine that a company engaged exclusively in the business of owning or operating an eligible facility used for the generation of electric energy for sale at wholesale is an EWG. Accordingly, it is exempt from PUHCA requirements. In the case of facilities previously operated by regulated utilities, FERC can make an exempt wholesale generator determination only after the state utility commission finds that allowing the facility or facilities to be eligible for exempt wholesale generator status will benefit consumers, is in the public interest, and does not violate state law. Each of NRG Northeast’s operating subsidiaries has been designated by FERC as an EWG or is otherwise exempt from PUHCA because it is a Qualifying Facility under the Public Utility Regulatory Policy Act of 1978.

NRG Northeast does not expect to engage in any activities that will subject it to regulation under PUHCA. If NRG Northeast were to lose its EWG status, it would become subject to regulation under PUHCA. It would be difficult for NRG Northeast to comply with PUHCA absent a substantial restructuring.

New York. Pursuant to the New York Public Service Law (the NYPSL), the New York State Public Service Commission (NYPSC) regulates all “public utility companies” or “utility companies” operating in New York. A “public utility company” or “utility company” under the NYPSL includes, among other things, any entity engaged in the production, transmission or distribution of electricity to the public for light, heat or power purposes. The Huntley, Dunkirk, Oswego, Arthur Kill and Astoria facilities (the New York facilities), each considered an EWG, do not provide electricity directly to the public and each sells only at wholesale to power marketers, energy service companies or the New York Independent System Operator (NYISO) wholesale markets. Although the NYPSL is silent with respect to the utility status of electric corporations selling at wholesale within New York, precedent of the NYPSC has applied “lightened regulation” to New York EWGs, which provides for minimal financial and organizational regulation. Each of the New York facilities has been accorded lightened regulatory treatment by the NYPSC. The New York facilities’ rates, however, remain subject to the jurisdiction of the FERC.

Massachusetts. Pursuant to Chapter 164 of the Massachusetts General Laws, a “wholesale generation company” includes any company engaged in the business of producing, manufacturing or generating electricity for sale in the wholesale market only. The Somerset facility, as an EWG, does not provide electricity directly to the public and sells only at wholesale to power marketers and energy service companies and thus is considered a wholesale generation company. Such companies are subject to very limited regulation by the Massachusetts Department of Telecommunications and Energy (MDTE), and management believes the Somerset facility will not likely be subject to regulation as a Massachusetts public utility or electric company. If, however, the Somerset facility were deemed to be an electric company by the MDTE, the MDTE could retroactively apply certain provisions of the statutes to the Somerset facility. The Somerset facility would also be subject to other laws and regulations (other than rate regulation) applicable to Massachusetts electric companies. The Somerset facility’s rates, however, would remain subject to the jurisdiction of the FERC.

Connecticut. Pursuant to Title 16, Chapter 283 of the Connecticut General Statutes, a “foreign electric company” is a corporation organized under the laws of a state other than Connecticut authorized by that state to generate electric energy. A foreign electric company is allowed to acquire and operate electric utility facilities, which include generating stations, in Connecticut. However, any foreign electric company which owns or operates any utility facility in the state is deemed to be an “electric company” and a “public service company” for all purposes of Title 16. Pursuant to Title 16, Chapter 277 of the Connecticut General Statutes, a “public service company” includes electric companies, but does not include EWGs. An “electric company” includes every corporation engaged in generating electricity to be transmitted or distributed within the state, but does not include an EWG. The Connecticut Department of Public Utility Control (DPUC) has authority to adopt rules with respect to rates and charges, services, accounting practices, safety and the conduct of operations generally of public service companies, as it deems reasonable and necessary. The DPUC also must approve the merger or consolidation of any public service company, and the issuance of common stock, notes, bonds, evidence of indebtedness, or securities by any public service company. Since they are EWGs, Middletown Power, Montville Power, Norwalk Power, Devon Power, and Connecticut Jet Power are not likely to be regulated as public service companies or electric companies by the DPUC. If, however, the Connecticut facilities were deemed to be public service companies or electric companies by the DPUC, the DPUC could retroactively apply certain provisions of the statutes to the Connecticut facilities. The Connecticut facilities would also be subject to other laws and regulations (other than rate regulation) applicable to Connecticut public service or electric companies. The rates for each of the Connecticut facilities, however, would remain subject to the jurisdiction of the FERC.

The entire independent power industry in the United States is in turmoil. Many of NRG Northeast’s competitors have announced plans to scale back their growth, sell assets, and restructure their finances. The results of the wholesale restructuring of the independent power industry are impossible to predict, but they may include consolidation within the industry, the sale or liquidation of certain competitors, the re-regulation of certain markets, and the long-term reduction in new investment into the industry. Under any scenario,

however, NRG Northeast anticipates that it will continue to face competition from numerous companies in the industry, some of which may have more extensive operating experience, larger staffs, and greater financial resources than NRG Northeast presently possesses.

Many companies in the regulated utility industry, with which the independent power industry is closely linked, are also restructuring or reviewing their strategies. Several of these companies are discontinuing going forward with unregulated investments, seeking to divest of their unregulated subsidiaries or attempting to have their regulated subsidiaries acquire their unregulated subsidiaries. This may lead to an increased competition between the regulated utilities and the unregulated power producers within certain markets. In such instances, NRG Northeast may compete with regulated utilities in the development of market designs and rulemaking.

FERC, however, is attempting to level the competitive playing field between regulated utilities and unregulated energy suppliers by providing open, non-discriminatory access to electricity markets and the transmission grid. In April 1996, FERC issued Orders 888 and 889 that required all public utilities to file “open access” transmission tariffs that give wholesale generators, as well as other wholesale sellers and buyers of electricity, access to transmission facilities on a non-discriminatory basis. This led to the formation of the ISOs described above. On December 20, 1999, FERC issued Order 2000, encouraging the creation of Regional Transmission Organizations (RTOs). Finally, on July 31, 2002, FERC issued its Notice of Proposed Rulemaking regarding Standard Market Design. All three orders were intended to eliminate market discrimination by incumbent vertically integrated utilities and to provide for open access to the transmission grid.

The full effect of these changes on NRG Northeast is uncertain at this time, because in many parts of the United States, it has not been determined how entities will attempt to comply with FERC’s initiatives. At this time, five ISOs have been approved and are operational; New England (ISO-NE), New York (NYISO), Pennsylvania, NJ, Maryland, DE and parts of the midwest (collectively PJM), Central Midwest (MISO), South Central (SPP) and in California (CA ISO). Two of these ISOs, PJM and MISO, have been found to also qualify as RTOs. Three other entities have also requested that FERC approve their organizations as RTOs; WestConnect (Desert Southwest); RTO West (Pacific Northwest and Rockies) and Setrans (Southeast).

NRG Northeast is also impacted by rule/tariff changes that occur in the existing ISOs. On March 1, 2003, ISO-NE implemented its version of Standard Market Design. This change dramatically modifies the New England market structure by incorporating Locational Marginal Pricing (LMP — pricing by location rather than on a New England wide basis). Even though NRG Northeast views this change as a significant improvement to the existing market design, NRG Northeast still views the market within New England as insufficient to allow for NRG Northeast to recover its costs and earn a reasonable return on investment. Consequently, on February 26, 2003, Devon Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC and NRG Power Marketing (collectively, the NRG Filers) filed and requested a cost of service rate with FERC for most of its Connecticut fleet, requesting a February 27th effective date. The NRG Filers remain committed to working with ISO-NE, FERC and other stakeholders to continue to improve the New England market that will hopefully make further reliance on a cost of service rate unnecessary. While the NRG Filers have the right to file for such rate treatment, there are no assurances that FERC will grant such rates in the form or amount that the NRG Filers petitioned for in their filing. If FERC declines to grant cost of service based rates in Connecticut, there may be additional impairments related to the Connecticut assets. Management is unable to determine the possible magnitude of any such additional asset impairments.

On March 25, 2003, the Federal Energy Regulatory Commission (FERC) issued an order (the Order) in response to the NRG Filers’ Joint Motion for Emergency Expedited Issuance of Order by March 17, 2003 in Docket No. ER03-563-000 (the Emergency Motion). In the Emergency Motion, the NRG Filers requested that FERC accept the NRG Filers’ reliability must-run agreements and assure the NRG Filers’ recovery of deferred maintenance costs for their New England generating facilities prior to the peak summer season. FERC accepted the NRG Filers’ filing as to the recovery of spring 2003 maintenance costs, subject to refund. FERC’s Order authorizes the ISO New England Inc. to begin collecting these maintenance costs in escrow for the benefit of the NRG Filers as of February 27, 2003. Several intervenors protested the Emergency

On March 21, 2003, the NYISO filed tariff revisions at FERC seeking permission to implement a demand curve for ICAP (ICAP Demand Curve) that would allow for ICAP revenues to exceed current levels if capacity shortages exist. The ICAP Demand Curve proposed by the NYISO was proposed by the New York Public Service Commission as an improvement to the ICAP market designed to attract more capacity to New York. The NYISO states that the ICAP Demand Curve proposal will enhance system and resource reliability by valuing capacity in excess of the minimum requirements and promote greater stability in the capacity market resulting in a more effective economic signal for new investment. The NYISO seeks an effective date of May 21, 2003 for the tariff changes. In PJM, NRG Energy is closely following market power mitigation modifications that may significantly impact the revenues achievable in that market by modifying PJM’s price capping mechanisms. The potential modifications are unknown at this time, and it is unclear whether such changes would have a positive or a negative effect on NRG Northeast.

Proposals have been introduced in Congress to repeal PURPA and PUHCA, and FERC has publicly indicated support for the PUHCA repeal effort. If the repeal of PURPA or PUHCA occurs, either separately or as part of legislation designed to encourage the broader introduction of wholesale and retail competition, the significant competitive advantages that independent power producers currently enjoy over certain regulated utility companies would be eliminated or sharply curtailed, and the ability of regulated utility companies to compete more directly with independent power companies would be increased. To the extent competitive pressures increase and the pricing and sale of electricity assumes more characteristics of a commodity business, the economics of domestic independent power generation projects may come under increasing pressure. Deregulation may not only continue to fuel the current trend toward consolidation among domestic utilities, but may also encourage the dis-aggregation of vertically-integrated utilities into separate generation, transmission and distribution businesses.

In addition, the independent system operators who oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price caps and other mechanisms to address some of the volatility in these markets. For example, the independent system operator for the New York power pool and the California independent system operator have imposed price caps. These types of price caps and other mechanisms in New York, California, the New England Power Pool and elsewhere may adversely impact the profitability of NRG Energy’s generation facilities that sell energy into the wholesale power markets. Finally, the regulatory and legislative changes that have recently been enacted in a number of states in an effort to promote competition are novel and untested in many respects. These new approaches to the sale of electric power have very short operating histories, and it is not yet clear how they will operate in times of market stress or pressure, given the extreme volatility and lack of meaningful long-term price history in many of these markets and the imposition of price caps by independent system operators.

The NYISO control area includes 34,000 MW of installed capacity and serves almost all of New York State’s electric power requirements. The NYISO operates competitive, non-discriminatory NYISO bid-based markets for energy, capacity and ancillary services. The NYISO commenced operations in November 1999. Most of New York State’s investor-owned utilities have completed or are in the process of divesting their fossil generation assets as part of the restructuring of the state’s electricity markets. These divested plants compete to varying degrees with new merchant plants in the wholesale markets. The market-clearing price for the NYISO’s day-ahead and real-time energy markets are calculated by determining the market-clearing price for transactions with zonal adjustments to account for transmission constraints. All purchasers of energy from the market pay a transaction charge set by the NYISO to settle system energy balancing and certain ancillary service costs.

In connection with the divestiture by ConEd (the Consolidated Edison Company of New York, Inc.) of certain of its electric generating resources in the New York City in-city market, certain market power mitigation measures are applied to generators located in that area. The intent of these market power mitigation measures is to alleviate concerns that the divested generation resources might be able to exercise localized market power due to the current configuration of New York City in-city market loads, generation, and transmission facilities and related local reliability rules and transmission constraints. The market mitigation measures have been implemented by the NYISO and tracked through its market monitoring process.

NEPOOL was originally formed to capture the benefits of economic dispatch and joint planning between a large number of utilities. NEPOOL is populated with a large number of participants attributed to five sectors: Generators, Suppliers, Transmission Owners, Municipalities and End Users. The region is a high variable cost power market, with oil/gas units operating in the margin. In addition, the region has transmission constraints that limit imports both from neighboring regions and internal to the control area. NEPOOL continues to experience significant transmission constraints in Southwest Connecticut, an area in which NRG Energy owns and operates the Norwalk and Devon Stations and a number of the Connecticut Jets. NEPOOL, is considered a highly divested region with most of the major utilities having divested all of the generating assets. At this time, only New Hampshire and Vermont and the Municipal Utilities Companies remain vertically integrated. NEPOOL redesigned its existing single-settlement market with the implementation of Standard Market Design on March 1, 2003 — a market design substantially identical to the PJM market design.

During 2002, one customer, NYISO, accounted for 72.5% of NRG Northeast’s gross revenues. During 2001, two customers accounted for 72.5% of NRG Northeast’s total revenues, NYISO (58.4%) and Niagara Mohawk Power Corporation (NiMo) (14.1%). During 2000, three customers accounted for 73.1% of NRG Northeast’s total revenues, NYISO (39.9%), CL&P (22.0%) and NiMo (11.2%). Such amounts include revenues from customers under contract with Power Marketing, Inc.

Annual and quarterly operating results can be significantly affected by weather and price volatility. Since NRG Northeast’s peak demand is in the summer months, temperature variations in summer months are generally more significant than variations during winter months. Significant other events, such as the war in Iraq and the precipitous decline in natural gas inventories and productive capacity, have combined to increase fuel and power price volatility.

NRG Northeast’s raw material requirements primarily include various forms of fossil fuel energy sources, including oil, natural gas and coal. NRG Northeast obtains its oil, natural gas and coal from multiple sources and availability is generally not an issue, although localized shortages can and do occur. The prices of oil, natural gas and coal are subject to macro- and micro-economic forces that can change dramatically in both the short term and the long term. For example, the prices of natural gas and oil have been particularly high during the winter of 2002-2003 due to weather volatility and geo-political uncertainty in the Middle East. Oil, natural gas and coal represented approximately 65.4% of NRG Northeast’s cost of operations during the year ended December 31, 2002.

NRG Northeast has no employees. The operating employees at the NRG Northeast facilities are employees of the respective NRG Energy subsidiaries that have contracted to operate each facility. All of the facilities (other than the Middletown facility) are staffed by a combination of union and non-union employees. The Middletown facility is staffed completely by non-union employees. With respect to union employees, all such employees are covered by current labor agreements with the relevant union, which agreements have varying expiration dates. To date there are no significant unresolved arbitrations filed by employees at any of the NRG Northeast’s facilities.

NRG Northeast’s operations are not divided into financial or geographical segments.

The information presented in this annual report 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,” “contemplates,” “believes,” and similar terms. Forward-looking statements are only predictions or expectations and actual results may differ materially from the expectations expressed in any forward-looking statement. While NRG Northeast believes that the expectations expressed in such forward-looking statements are reasonable, NRG Northeast 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:


	•	The possibility of a bankruptcy filing in the near future, either by NRG Northeast, NRG Energy and/or one or more of its other subsidiaries, the entry of an order for relief by the Minnesota Bankruptcy Court in respect of a pending involuntary Chapter 11 petition in that court with respect to NRG Energy, or the filing of an involuntary bankruptcy petition in another court by a requisite number of creditors of NRG Northeast, NRG Energy or any other subsidiary, as the case may be;

	•	NRG Energy’s ability or the ability of any of its subsidiaries to reach agreements with its lenders, creditors and other stakeholders regarding a comprehensive restructuring of NRG Energy;

	•	Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

	•	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;

	•	The effect on the U.S. economy as a consequence of an invasion of Iraq and other potential actions relating to the U.S. government’s efforts to suppress terrorism;

	•	Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where NRG Northeast 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;

	•	Customer financial conditions, including solvency and the ability to pay invoices when due.

	•	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, NRG Northeast or its subsidiary; or credit ratings;

	•	Inability of NRG Northeast to adequately control or hedge against commodity price volatility due to constraints or limitations on available working capital or market credit.

	•	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;

	•	Limitations on NRG Northeast’s ability to control projects in which NRG Energy has less than 100% interest;

	•	Limited operating history at recently acquired or constructed projects provide only a limited basis for management to project the results of future operations;

	•	Risks associated with timely completion of projects under construction, including obtaining competitive commercial agreements, obtaining regulatory and permitting approvals, local opposition, construction delays and other factors beyond NRG Northeast’s control;

	•	Factors associated with various investments including competition, operating risks, dependence on certain suppliers and customers, and environmental and energy regulations;

	•	Changes in government regulation or the implementation of new government regulations, or the outcome of any litigation which could adversely affect the continued deregulation of the electric industry;

	•	Other business or investment considerations that may be disclosed from time to time in NRG Northeast’s Securities and Exchange Commission filings or in other publicly disseminated written documents.

	•	Changes in market design or implementation of rules that affect NRG Northeast’s ability to transmit or sell power in any market, including, without limitation, the failure of FERC to grant the NRG Filers cost of service based rates on certain Connecticut generation facilities in the form and amount petitioned for in the Section 205 filing pursuant to the Federal Power Act.

NRG Northeast undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG Northeast’s actual results to differ materially from those contemplated in any forward-looking statements included in this Form 10-K should not be construed as exhaustive.

Listed below are descriptions of NRG Northeast’s interests in facilities and operations as of December 31, 2002.

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.

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 Connecticut Light & Power Company for recovery of amounts it claims is 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 filed a response on March 21, 2003. CL&P has offset approximately $30 million from amounts owed to NRG Power Marketing claiming that it has the right to offset those amounts under the contract. NRG Power Marketing has counterclaimed seeking to recover those amounts, arguing among other things that CL&P has no rights under the contract to offset them. NRG Power Marketing 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 effect on NRG Northeast, NRG Northeast is not a party to this litigation.

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 asserts that projects undertaken at NRG Energy’s Huntley and Dunkirk plants by NiMo, the former owner of the facilities, should have been permitted pursuant to the Clean Air Act and that the failure to do so 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 or re-file a case against NRG Energy. 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 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.

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 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 us 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.

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 Niagara Mohawk 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.

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.

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

Item 5 — Market for the Registrant’s Common Equity and Related Stockholder Matters

Northeast Generation Holding LLC owns 50% of the outstanding equity interests of NRG Northeast Generating LLC and NRG Eastern LLC owns 50% of the outstanding equity interests of NRG Northeast Generating LLC. Northeast Generation Holding LLC and NRG Eastern LLC are each wholly-owned subsidiaries of NRG Energy, Inc.

During 2002 NRG Northeast did not distribute earnings and does not currently intend to distribute any future earnings as distributions. During 2001 and 2000, NRG Northeast distributed $52.7 million and $422.1 million to its members.

The following table presents selected financial data of NRG Northeast. This historical data should be read in conjunction with the Consolidated Financial Statements and the related notes thereto in Item 15 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7.

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

Due to the factors discussed below, as well as other matters discussed herein, NRG Northeast’s financial condition has deteriorated significantly in the recent past. See “Liquidity” below. As a result, NRG Northeast does not contemplate that it will have sufficient funds to make required principal and interest payments on its corporate debt, which means that NRG Northeast will remain in default of the various corporate level debt obligations discussed more fully herein including the secured NRG Northeast Generating LLC bonds. In the absence of a consensual plan of reorganization, it is highly likely that NRG Northeast, in conjunction with NRG Energy, will be required to commence a voluntary chapter 11 bankruptcy proceeding to allow it to implement its own plan of reorganization. The commencement of a voluntary chapter 11 bankruptcy proceeding without a consensual plan of reorganization will increase the possibility of a prolonged bankruptcy proceeding.

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 are 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, the summer of 2001, the winter of 2001/2002 and the summer of 2002 were mild in the United States. This together with excessive new construction 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 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.

For the Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001

Net income for the year ended December 31, 2002 was $3.9 million, a decrease of $207.4 million or 98.2% compared to 2001. This change was due to the factors described below.

For the year ended December 31, 2002, NRG Northeast had total revenues of $693.9 million compared to $1,050.7 million for the year ended December 31, 2001, a decrease of $356.8 million or 34.0%. The revenues primarily consist of sales under long-term agreements for both years. The decrease in revenues is due to a combination of lower capacity revenues and a 23% decline in megawatt hour generation compared with 2001. This decline in generation is attributable to an unseasonably warm winter and cooler spring and a slowing economy which reduced demand for electricity, together with new regulation (UCAP structure) which reduced price volatility, particularly in New York City, where NRG Northeast’s plants sell into the merchant energy market.

Cost of operations for the year ended December 31, 2002 were $494.4 million compared to $712.1 million for the year ended December 31, 2001. This represents a decrease of $217.7 million or 30.6%. 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, lower expenditures on plant maintenance and operations and a $48.8 million favorable swing in unrealized gains/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 year ended December 31, 2002 was $323.1 million compared to $462.6 million for the year ended December 31, 2001. For the year ended December 31, 2002 fuel expense represented 46.6% of revenue and included $108.9 million of coal, $114.1 million of natural gas, $100.1 million of fuel oil, diesel and other related fuel costs. For the year ended December 31, 2001 fuel expense represented 44.0% of revenue and included $107.3 million of coal, $178.4 million of natural gas, $176.9 million of fuel oil and other related fuel costs.

Plant operations and maintenance expense for the year ended December 31, 2002, was $196.5 million compared to $225.9 million for the year ended December 31, 2001. For the year ended December 31, 2002, plant operations and maintenance expense represented 28.3% of revenue, and includes labor and benefits under operating service agreements of $62.1 million, maintenance parts, supplies and services of $76.4 million, and property taxes and other expenses of $58.0 million. For the year ended December 31, 2001, plant operations and maintenance expense represented 21.5% of revenue, and includes labor and benefits under operating service agreements of $72.4 million, maintenance parts, supplies and services of $84.5 million, and property taxes and other expenses of $69.0 million.

Unrealized gains associated with changes in fair value of non-hedge energy related derivative instruments recorded in operating costs were $25.2 million for 2002 compared to unrealized losses of $23.6 million for 2001.

Depreciation costs were $54.2 million for the year ended December 31, 2002 compared to $48.9 million of the year ended December 31, 2001. Depreciation expense is primarily related to the facilities and related equipment, which are being depreciated over ten to thirty years. The increase in expense is primarily due to the impact of the $34.1 million of capital expenditures made during 2002.

General and administrative expenses were $44.3 million for the year ended December 31, 2002 compared to $24.4 million for the year ended December 31, 2001. These expenses include costs for 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. General and administrative expense represented 6.4% and 2.3% of revenues for the years ended December 31, 2002 and 2001, respectively. The 2002 expense includes $22.3 million related to bad debts. Offsetting the 2001 general and administrative expenses is $8.1 million related to the reversal of the accounts receivable reserve during the fourth quarter due to the collection of previously disputed receivables.

During the third quarter of 2002, NRG Northeast experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. NRG Northeast applied the provisions of SFAS No. 144 to the asset carrying values of its projects factoring in the probability of different courses of action available to NRG Northeast given its financial position and liquidity constraints significantly affected by NRG Northeast’s downgrade at the end of July 2002. In applying those provisions, NRG Northeast’s management primarily considered cash flow analyses related to those projects. As a result, NRG Northeast determined that the Somerset Facility became impaired during the third quarter of 2002 and should be written down to fair market value. The asset impairment was recognized as a special charge in the

In addition to the asset impairment charge, NRG Northeast incurred $1.2 million of expected restructuring costs consisting of advisor and legal fees. These costs were also recorded as special charges.

Additional asset impairment and other related charges may be recorded by NRG Northeast given the changing business conditions and resolution of the pending restructuring plan.

Other income was $5.3 million for the year ended December 31, 2002 compared to $4.6 million for the year ended December 31, 2001. The majority of the increase relates to a property tax refund and an insurance settlement.

Interest expense was $51.8 million for the year ended December 31, 2002 compared to $58.6 million for the year ended December 31, 2001. The interest expense relates to amortization of deferred finance costs and interest on the outstanding balance of the initial $750 million of senior secured bonds issued on February 22, 2000. The decrease in interest expense is due primarily to scheduled debt repayments resulting in a decline in the average outstanding debt balances during the year ended December 31, 2002 versus the year ended December 31, 2001.

Net income for the year ended December 31, 2001 was $211.3 million, a decrease of $72.0 million or 25.4% compared to 2000. This change was due to the factors described below.

For the year ended December 31, 2001, NRG Northeast had total revenues of $1.1 billion compared to $1.1 billion for the year ended December 31, 2000, a decrease of $71.1 million or 6.3%. The revenue amounts consisted primarily of revenue from sales under long-term agreements for both years. The 6.3% decrease in revenue is primarily attributable to an 8% decline in megawatt hour production. Most of that decline occurred in the fourth quarter, as a warmer winter and economic conditions lowered electricity demand.

Cost of operations for the year ended December 31, 2001 were $712.1 million compared to $700.6 million for the year ended December 31, 2000. This represents a increase of $11.5 million or 1.6%.

Fuel expense for the year ended December 31, 2001 was $462.6 million compared to $457.5 million for the year ended December 31, 2000. For the year ended December 31, 2001 fuel expense represented 44.0% of revenue and included $107.3 million of coal, $178.4 million of natural gas, $176.9 million of fuel oil, diesel and other related fuel costs. For the year ended December 31, 2000 fuel expense represented 40.8% of revenue and included $115.5 million of coal, $156.1 million of natural gas, $185.9 million of fuel oil and other related fuel costs. Fuel expense increased 1.1% in 2001 despite an 8% decrease in generation. This is due to a sharp increase in the price of natural gas primarily in the first half of the year as compared with the same period in 2000. The increase in natural gas was partially offset by declines in coal expense driven by lower coal plant generating levels.

Plant operations and maintenance expense for the year ended December 31, 2001, was $225.9 million compared to $243.1 million for the year ended December 31, 2000. For the year ended December 31, 2001, plant operations and maintenance expense represented 21.5% of revenue, and includes labor and benefits under operating service agreements of $72.4 million, maintenance parts, supplies and services of $84.5 million, and property taxes and other expenses of $69.0 million. For the year ended December 31, 2000, plant

operations and maintenance expense represented 21.7% of revenue, and includes labor and benefits under operating service agreements of $64.8 million, maintenance parts, supplies and services of $101.8 million, and property taxes and other expenses of $76.5 million.

Unrealized losses associated with changes in fair value of non-hedge related derivative instruments recorded in operating costs were $23.6 million for 2001.

Depreciation costs were $48.9 million for the year ended December 31, 2001 compared to $47.8 million of the year ended December 31, 2000. Depreciation expense is primarily related to the facilities and related equipment, which are being depreciated over twenty-five to thirty years.

General and administrative expenses were $24.4 million for the year ended December 31, 2001 compared to $27.9 million for the year ended December 31, 2000. These expenses include costs for 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. General and administrative expense represented 2.3% and 2.5% of revenues for the years ended December 31, 2001 and 2000, respectively. Offsetting the 2001 general and administrative expenses is $8.1 million related to the reversal of the accounts receivable reserve during the fourth quarter due to the collection of previously disputed receivables.

Other income was $4.6 million for the year ended December 31, 2001 compared to $0 for the year ended December 31, 2000. The majority of the increase relates to interest income related to prior year disputed revenues.

Interest expense was $58.6 million for the year ended December 31, 2001 compared to $62.3 million for the year ended December 31, 2000. The interest expense relates to amortization of deferred finance costs and interest on the outstanding balance of the initial $750 million of senior secured bonds issued on February 22, 2000. The decrease in interest expense is due primarily to the write-off, in February 2000, of the remaining unamortized deferred finance costs on short-term borrowings coupled with scheduled debt repayments resulting in a decline in the average outstanding debt balances during the twelve months ended December 31, 2001 versus the twelve months ended December 31, 2000.

If FERC declines to grant cost of service-based rates in Connecticut, there may be additional impairments related to the Connecticut assets. Management is unable to determine the possible magnitude of any such additional asset impairments.

NRG Northeast’s discussion and analysis of its financial condition and results of operations are based upon NRG Northeast’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements and related disclosures in compliance with generally accepted accounting principles (GAAP) 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, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges. 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, NRG Northeast evaluates its estimates utilizing historic experience, consultation with experts and other methods NRG Northeast considers reasonable in particular circumstances. In any case, actual results may differ significantly from NRG Northeast’s estimates. Any effects on NRG Northeast’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.

NRG Northeast’s significant accounting policies are summarized in Item 15 — Note 2 of the Consolidated Financial Statements. The following table identifies certain of the significant accounting policies listed in Item 15 — Note 2 of the Consolidated Financial Statements. The table also identifies the judgments required and uncertainties involved in the application of each. These policies, along with the underlying assumptions and judgments made by NRG Northeast’s management in their application, have a significant impact on NRG Northeast’s consolidated financial statements. NRG Northeast identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of NRG Northeast’s

Of all of the accounting policies identified in the above table, NRG Northeast believes that the following policies and the application thereof to be those having the most direct impact on NRG Northeast’s financial position and results of operations.

As of December 31, 2002, NRG Northeast has a carrying value of approximately $1.3 billion of net property, plant and equipment, representing approximately 78.8% total assets. These amounts represent the estimated fair values at the date of acquisition and construction. These estimates may be adjusted based upon completion of certain procedures including third party valuations.

For those assets that were or are being constructed or acquired by NRG Northeast, the carrying value reflects the application of NRG Northeast’s property, plant and equipment policies which incorporate estimates, assumptions and judgments by management relative to the capitalized costs and useful lives of NRG Northeast’s generating facilities. Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the asset under construction is ready for its intended use or when construction is terminated. There was no capitalized interest in 2002. Development costs and capitalized project costs include third party professional services, permits, and other costs which are incurred incidental to a particular project. Such costs are expensed as incurred until an acquisition agreement or letter of intent is signed, and the project has been approved by

NRG Northeast’s Management Committee. Additional costs incurred after this point are capitalized. When a project begins operation, previously capitalized project costs are reclassified to equity investments in affiliates or property plant and equipment and amortized on a straight-line basis over the lesser of the life of the project’s related assets or revenue contract period.

NRG Northeast evaluates property, plant and equipment and intangible assets for impairment whenever indicators of impairment exist. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available to NRG Northeast. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. Assets to be disposed of are reported at the lower of the carrying amount or fair value less the cost to sell. As of December 31, 2002, net income from continuing operations was reduced $49.3 million due to impairments recorded in 2002. Asset impairment evaluations are, by nature highly subjective.

NRG Northeast is primarily an electric generation company, operating a portfolio of majority-owned electric generating plants. Both physical and financial transactions are entered into to optimize the financial performance of NRG Northeast’s generating facilities. Electric energy is recognized upon transmission to the customer. Electric energy is recognized upon transmission to the customer. Capacity and ancillary revenue is recognized when contractually earned. NRG Northeast continually assesses the collectibility of its receivables and in the event it believes a receivable to be uncollectible an allowance for doubtful accounts is recorded or, in the event of a contractual dispute, the receivable and corresponding revenue may be considered unlikely of recovery and not recorded in the financial statements until management is satisfied that it will be collected.

In January 2001, NRG Northeast adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137 and SFAS No. 138. SFAS No. 133 requires NRG Northeast 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. Changes in the fair value of derivatives accounted for as hedges are either recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments or for forecasted transactions, deferred and recorded as a component of accumulated other comprehensive income (OCI) until the hedged transactions occur and are recognized in earnings. NRG Northeast primarily applies SFAS No. 133 to 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. SFAS No. 133 also applies to interest rate swaps and foreign currency exchange rate contracts. The application of SFAS No. 133 results in increased volatility in earnings due to the impact market prices have on the market positions and financial instruments that NRG Northeast has entered into. In determining the fair value of these derivative/financial instruments NRG Northeast uses estimates, various assumptions, judgment of management and when considered appropriate third party experts in determining the fair value of these derivatives.

As of December 31, 2002, NRG Northeast does not have any significant relationships with structured finance or special purpose entities that provide liquidity, financing or incremental market risk or credit risk.

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 $432.0 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 lowered their ratings on NRG Energy’s and its subsidiaries’ unsecured bonds once again. Currently, NRG Energy’s unsecured bonds carry a rating of between CCC and D at S&P and between Ca and C at Moody’s, depending on the specific debt issue.

would be implemented through the commencement of a voluntary Chapter 11 bankruptcy proceeding. If NRG Energy seeks protection under Chapter 11 of the Bankruptcy Code, it is likely that NRG Energy would also seek such protection for certain wholly-owned subsidiaries, which would likely include NRG Northeast. For more specific information regarding NRG Energy’s restructuring efforts, refer to “Liquidity Issues” in Item 1 of Form 10-K filed by NRG Energy on March 31, 2003.

NRG Northeast and its subsidiaries have failed to timely make the following interest and/or principal payments to non-affiliates on its indebtedness:

Net cash provided by operations for the year ended December 31, 2002 decreased in comparison to 2001. The decrease was primarily driven by the decrease in net income and the significant increase in Accounts Receivable, offset in part by the decrease in Inventory. Net cash provided by operations for the year ended December 31, 2001 decreased in comparison to 2000. The decrease was primarily driven by a decrease in net income and adverse changes within working capital.

Net cash used in investing activities for the year ended December 31, 2002 increased in comparison to 2001. The increase is due to higher capital expenditures in 2002. Net cash used in investing activities for the year ended December 31, 2001 increased slightly in comparison to 2000. The increase resulted from a minor increase in capital expenditures.

Net cash used in financing activities for the year ended December 31, 2002 decreased in comparison to 2001. The decrease is primarily due to the suspension of principal payments on the debt during the year, as well as the absence of any equity distributions during the year. Net cash used in financing activities for the year ended December 31, 2001 decreased in comparison to 2000. The decrease was primarily due to a reduction in member distributions.

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 December 31, 2002, NRG Northeast is restricted from making cash payments to NRG Energy. On March 31, 2003, NRG Northeast had approximately $12 million of cash on hand.

Management currently forecasts that cash flow from operations for 2003 will be insufficient to cover capital expenditures, which include minor refurbishments and environmental compliance. Given this shortfall, NRG Northeast anticipates funding its ongoing capital requirements through operating cash flows and existing cash, as well as potential external financing. Management forecasts capital expenditures to total approximately $150 million to $200 million in the period of 2003 through 2007. NRG Northeast’s capital expenditure program is subject to continuing review and modification. The timing and actual amount of expenditures may differ significantly based upon plant operating history, unexpected plant outages, and changes in the regulatory environment, and the availability of cash and restructuring efforts.

NRG Northeast has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to its capital expenditure program. The following is a summarized table of contractual obligations. See additional discussion in Item 15 and Notes 6, 7 and 12 to the Consolidated Financial Statements.

NRG Northeast provides performance guarantees to third parties on behalf of NRG Power Marketing in relation to certain of its sales and supply agreements.

In July 2002, NRG Power Marketing reached a tentative agreement with Connecticut Light & Power (CL&P) that would result in increased compensation to NRG Northeast, a supplier of CL&P’s wholesale supply requirements. 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-NE to keep three units at its Devon station in service in return for a reliability must-run capacity payment. The agreement expires on September 30, 2003.

On February 26, 2003, Devon Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC and NRG Power Marketing (collectively, the NRG Filers) filed and requested a cost of service rate with FERC for most of its Connecticut fleet, requesting a February 27th effective date. The NRG Filers remain committed to working with ISO-NE, FERC and other stakeholders to continue to improve the New England market that will hopefully make further reliance on a cost of service rate unnecessary. While the NRG Filers have the right to file for such rate treatment, there are no assurances that FERC will grant such rates in the form or amount that the NRG Filers petitioned for in their filing. On March 25, 2003, the FERC issued an order (the Order) in response to the NRG Filers’ Joint Motion for Emergency Expedited Issuance of Order by March 17, 2003 in Docket No. ER03-563-000 (the Emergency Motion). In the Emergency Motion, the NRG Filers requested that FERC accept the NRG Filers’ reliability must-run agreements and assure the NRG Filers’ recovery of deferred maintenance costs for their New England generating facilities prior to the peak summer season. FERC accepted the NRG Filers’ filing as to the recovery of spring 2003 maintenance costs, subject to refund. FERC’s Order authorizes the ISO New England Inc. to begin collecting these maintenance costs in escrow for the benefit of the NRG Filers as of February 27, 2003. Several intervenors protested the Emergency Motion. FERC will rule on such protests and other issues raised in the Emergency Motion in a subsequent order.

The tables below disclose NRG Northeast’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 December 31, 2002 based on whether fair values are determined by quoted market prices or more subjective means; and indicates the maturities of contracts at December 31, 2002.

The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulations in the United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and NRG Northeast’s facilities are not exempted from coverage, NRG Northeast could be required to make extensive modifications to further reduce potential environmental impacts. Also, NRG Northeast could be held responsible under environmental and safety laws for the cleanup of pollutant releases at its facilities or at off-site locations where it has sent wastes.

NRG Northeast and its subsidiaries strive to exceed the standards of compliance with applicable environmental and safety regulations. Nonetheless, NRG Northeast expects that future liability under or compliance with environmental and safety requirements could have a material effect on its operations or competitive position. It is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of possible changes to environmental and safety regulations, regulatory interpretations or enforcement policies. In general, the effect of future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions on NRG Northeast’s operations.

NRG Northeast establishes accruals where reasonable estimates of probable environmental and safety liabilities are possible. NRG Northeast adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates are adjusted to reflect new information. For more information on Environmental Matters see Item 15 — Note 12 to the Consolidated Financial Statements.

Several federal regulatory and legislative initiatives are being undertaken in the U.S. to further limit and control pollutant emissions from fossil-fuel-fired combustion units. Although the exact impact of these initiatives is not known at this time, all of NRG Northeast’s power plants will be affected in some manner by the expected changes in federal environmental laws and regulations. In Congress, legislation has been proposed that would impose annual caps on U.S. power plant emissions of nitrogen oxides (NO_X), sulfur dioxide (SO₂), mercury, and, in some instances, carbon dioxide (CO₂). NRG Northeast is currently participating in the debates around such legislative proposals as a member of the Electric Power Supply Association. Federal legislation relating to NO_X, SO₂ and mercury is likely in the next two years. The prospects for passage of the legislation relating to CO₂ is more uncertain. The U.S. Environmental Protection Agency (USEPA) is scheduled to propose in December 2003 and finalize in December 2004 rules governing mercury emissions from power plants. In support of this schedule, USEPA and critical stakeholders, some of which are aligned with NRG Northeast’s interests, are presently conducting a thorough review of existing power plant mercury emissions data. Since these mercury rules have not yet been proposed and legislation has

USEPA has finalized federal rules governing ozone season NO_X emissions across the eastern United States. These ozone season rules will be implemented in two phases. The first phase of restrictions will occur in the Ozone Transport Commission region during the 2003 and subsequent ozone seasons; all of NRG Northeast’s existing, wholly owned generating units are included in this part of the program. The second phase of NO_X reductions will extend to states within the Ozone Transport Assessment Group (OTAG) region and restrict 2004 and subsequent ozone season NO_X emissions in most states east of the Mississippi River. These rules require one NO_X allowance to be held for each ton of NO_X emitted from any fossil fuel-fired stationary boiler, combustion turbine, or combined cycle system that (i) at any time on or after January 1, 1995, served a generator with a nameplate capacity greater than 25 MW and sold any amount of electricity or (ii) has a maximum design heat input greater than 250 MMBtu/hr. NRG Northeast’s facilities that are subject to this rule have been allocated NO_X emissions allowances, but NRG Northeast expects that those allowances may not be sufficient for the anticipated operation of these facilities. Where insufficient allowances exist, NRG Northeast must purchase NO_X allowances from sources holding excess allowances. The need to purchase these additional NO_X allowances could have a material affect on NRG Northeast’s operations.

During the first quarter of 2002, USEPA proposed new rules governing cooling water intake structures at existing power facilities. These rules are scheduled to be finalized by February 16, 2004. The proposed rules specify certain location, design, construction, and capacity standards for cooling water intake structures at existing power plants using the largest amounts of cooling water. These rules will require implementation of the best technology available for minimizing adverse environmental impacts unless a facility shows that such standards would result in very high costs or little environmental benefit. The proposed rules would require NRG Northeast facilities that withdraw water in amounts greater than 50 million gallons per day to submit with wastewater permit applications certain surveys, plans, operational measures, and restoration measures that combined would act to minimize adverse environmental impacts. These anticipated cooling water intake structure rules could have a material effect on NRG Northeast’s operations.

Other Federal initiatives that could affect NRG Northeast and that would govern regional haze, fine particulate matter, and ozone are underway, but under extended compliance implementation timeframes ranging from 2009 and beyond.

Final rules implementing changes in air regulations in the states of Massachusetts and Connecticut were promulgated in 2000. The Connecticut rules required that existing facilities reduce their emissions of SO₂ in two steps, the first of which took place on January 1, 2002. The second SO₂ milestone will occur on January 1, 2003. The NRG Northeast plants in Connecticut have operated in compliance with the first phase rules and are now operating in compliance with the second phase rules. Connecticut’s rules governing emissions of NO_X were also modified in 2000 to restrict the average, non-ozone season NO_X emission rate to 0.15 pound per million Btu heat input. NRG Northeast plans to comply with the new NO_X rules, in part, through selective firing of natural gas, use of selective non-catalytic reduction (SNCR) technology presently installed at its Norwalk Harbor and Middletown Power Stations, improved combustion controls, use of emission reduction credits, and purchase of allowances. In 2002, the Connecticut legislature passed a law further tightening air emission standards by eliminating in-state emissions credit trading subsequent to January 1, 2005 as a means of meeting Department of Environmental Protection (DEP) regulatory standards for SO₂ emissions from older power plants. The termination of SO₂ emissions trading in Connecticut by 2005 could have a material effect on NRG Northeast’s operations in that state.

The new Massachusetts rules set forth schedules under which six existing coal-fired power plants in-state were required to meet stringent emission limits for NO_X, SO₂, mercury, and CO₂. The state has reserved the issue of control of carbon monoxide and particulate matter emissions for future consideration. On February 25th, 2003, NRG Northeast received from the Massachusetts Department of Environmental Protection (MADEP) a permit to install natural gas reburn technology to meet the NO_X and SO₂ limits specified in the

new rule at its Somerset Generating Station. NRG Northeast is projected to incur total capital expenditures of approximately $5.4 million to implement the reburn technology at the Somerset Station, of which about $3.0 million remains to be spent during 2003. MADEP is evaluating the technological and economic feasibility of controlling and eliminating emissions of mercury from the combustion of solid fossil fuel in Massachusetts. Within six months of completing the feasibility evaluation, MADEP must propose emission standards for mercury, with a proposed compliance date of October 1, 2006. NRG Northeast believes it can comply with any future mercury reductions required by the rules through achieving early reductions of mercury via early implementation of the natural gas reburn technology and with its January 1, 2010 commitment to shutdown Somerset Station’s existing boiler. NRG Northeast is still considering its options with respect to how it will address MADEP’s CO₂ emission standards. Such options include using early reductions of CO₂ achieved through early implementation of the natural gas reburn technology or by filing a legal challenge with respect to MADEP’s legal authority to regulate CO₂ emissions.

New York proposed rules reducing allowable SO₂ and NO_X emissions from large, fossil-fuel-fired combustion units in New York State on February 20, 2002 (6NYCRR Part 237: Acid Deposition Reduction NO_X Budget Trading Program and Part 238: Acid Deposition Reduction SO₂ Budget Trading Program). As proposed, these rules would affect every NRG Northeast generator in-state. NRG Northeast provided testimony on the proposed rules in public hearings conducted in Buffalo and Albany on April 4, 2002, and May 20, 2002, respectively. In addition, NRG Northeast filed written comments on the proposed rules on May 28, 2002. NRG Northeast’s comments focused on (i) material changes in electric markets that had occurred since the conduct of studies upon which the Department of Environmental Conservation (DEC) had based their proposal, (ii) the need to increase the quantity of upwind allowances for use in offsetting in-state emissions, and (iii) the disproportionately minimal reduction in in-state acid deposition that could be expected from the significant emissions reductions proposed. NRG Northeast has received a pre-publication version of the rules that will be considered by the New York State DEC’s Environmental Board at the Board’s March 26, 2003 meeting. Indications are that the rules will provide for increased use of upwind SO₂ and NO_X reductions and will continue to allow for the use of early emission reductions. NRG Northeast’s strategy for complying with the new rules will be to generate early reductions of SO₂ and NO_X associated with fuel switching and use such reductions to extend the timeframe for implementing technological controls, which could include the addition of flue gas desulfurization (FGD) and selective catalytic reduction (SCR) equipment. NRG Northeast anticipates that it could incur capital expenditures up to $300 million in the 2008 through 2012 timeframe to implement upgrades and modifications to its plants in New York to meet new state and federal regulatory requirements.

Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at the facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by the party in connection with any releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault) and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. Although NRG Northeast has been involved in on-site contamination matters, to date, NRG Northeast has not been named as a potentially responsible party with respect to any off-site waste disposal matter.

closure, post-closure care and monitoring are expected at these facilities. NRG Northeast maintains financial assurance to cover costs associated with closure, post-closure care and monitoring activities. In the past, NRG Northeast has provided financial assurance via financial test and corporate guarantee. NRG Northeast must re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, currently estimated at approximately $5.8 million. NRG Northeast is required to provide an alternative instrument to provide such financial assurance on or before April 30, 2003.

NRG Northeast must also maintain financial assurance for closing interim status RCRA facilities at the Devon, Middletown, Montville and Norwalk Generating Stations. Previously, NRG Northeast has provided financial assurance via financial test. NRG Northeast must re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs. NRG Northeast is required to provide an alternative instrument to provide such financial assurance on or before April 30, 2003.

Historical clean-up liabilities were inherited as a part of acquiring the Somerset, Devon, Middletown, Montville, Norwalk Harbor, Arthur Kill and Astoria Generating Stations. NRG Northeast has recently satisfied cleanup obligations associated with the Ledge Road property (inherited as part of the Somerset acquisition). Site contamination liabilities arising under the Connecticut Transfer Act at the Devon, Middletown, Montville and Norwalk Stations have been identified and are currently being refined as part of on-going site investigations. NRG Northeast does not expect to incur material costs associated with completing the investigations at these Stations or future work to cover and monitor landfill areas pursuant to the Connecticut requirements. Remedial obligations at the Arthur Kill Generating Station have been established in discussions between NRG Northeast and the New York State DEC and are estimated at $1.0 million. Remedial investigations are on-going at the Astoria Generating Station. At this time, NRG Northeast’s long-term cleanup liability at this site is estimated at $1.5 million. However, the magnitude of cleanup costs for the Astoria Station cannot be estimated with certainty until the results of the remedial investigation are available.

In June 2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” 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. The liability is initially capitalized as part of the cost of the related tangible long-lived asset and thus depreciated over the asset’s useful life. Accretion of the liabilities due to the passage of time will be an operating expense. 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. NRG Northeast is in the process of evaluating the impact of adopting SFAS No. 143 on its financial condition.

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. NRG Northeast has no extraordinary gains or losses resulting from extinguishment of debt during the three years ended December 31, 2002 that will require restatement upon adoption of this part of SFAS No. 145.

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. Adoption of SFAS No. 145 is not expected to have a material impact on NRG Northeast.

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 November 2002, The FASB issued FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

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 NRG Northeast.

NRG Northeast may use interest rate hedging contracts to mitigate the risks associated with movements in interest rates and, when deemed appropriate, may enter into swap agreements effectively converting floating rate obligations into fixed rate obligations. NRG Northeast primarily has fixed rate debt outstanding as of December 31, 2002. As a result, NRG Northeast is not significantly exposed to losses due to fluctuations in interest rates.

NRG Northeast is exposed to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. To manage earnings volatility associated with these commodity price risks, NRG Northeast, through its affiliate NRG Power Marketing, may enter into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps.

Through NRG Power Marketing, NRG Northeast utilizes an undiversified “Value-at-Risk” (VAR) model to determine the maximum potential three-day loss in the fair value of the commodity price related financial instruments for the forward twelve months. The VAR for NRG Northeast assumes a 95% confidence interval and reflects NRG Northeast’s merchant strategy, the generation assets, load obligations and the bilateral physical and financial transactions of NRG Northeast. The volatility estimate is based on the implied volatility for at the money daily call options for forward markets where NRG Northeast has exposure. This model encompasses the ISO-NE and NYISO generating regions.

The estimated maximum potential three-day loss in fair value of the commodity price related financial instruments, calculated using the VAR model, is approximately $81.5 million and $45.4 million as of December 31, 2002 and 2001, respectively. The average, high and low amounts for the year ended December 31, 2002 were $51.5 million, $84.1 million and $26.1 million, respectively.

NRG Northeast is exposed to credit risk in its risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. Through NRG Energy’s Treasury department, NRG Northeast maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes in scope of operations. NRG Northeast conducts standard credit reviews for all of its counterparties. NRG Northeast does not believe its exposure to credit risk is significant.

The consolidated financial statements and schedule are listed in Part IV, Item 15 of this Form 10-K.

Richard C. Kelly has been President and Management Committee Member of NRG Northeast since October 2002. Mr. Kelly has also been a Director of NRG Energy since August 2000. During 2002, Mr. Kelly became the President and Chief Operating Officer of NRG Energy. Mr. Kelly has been President — Enterprises of Xcel Energy since August 2000, and was formerly Executive Vice President of financial and support services and Chief Financial Officer for New Century Energy from 1997 to August 2000. Before that, Mr. Kelly was Senior Vice President of Finance, Treasurer and Chief Financial Officer for Public Service Company of Colorado, which he joined in 1968.

Scott J. Davido has been Vice President, Assistant Secretary and Management Committee Member of NRG Northeast since October 2002. Mr. Davido has also been Senior Vice President, General Counsel at NRG Energy since October 2002. He served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary of The Elder-Beerman Stores Corp. from 1999 to May 2002 and Senior Vice President, General Counsel from 1997 to 1999. Mr. Davido was a Partner, Business Practice Group with Jones, Day, Reavis &

George P. Schaefer has been Treasurer and a Management Committee Member of NRG Northeast since December 2002. Mr. Schaefer has also been Treasurer of NRG Energy since December 2002. Prior to December 2002, Mr. Schaefer served as Senior Vice President, Finance and Treasurer for PSEG Global, Inc. for one year, Vice President of Enron North America from 2000 to 2001 and Vice President and Treasurer of Reliant Energy International from 1995 to 2000. Mr. Schaefer was the Vice President, Business Development for Entergy Power Group from 1993 through 1995 and held the Senior Vice President, Structured Finance Group position with General Electric Capital Corporation from 1982 through 1993.

Andrew T. Panaccione has been a Management Committee Member of NRG Northeast since March 2003. Since 1993 Mr. Panaccione has been employed as President of Entity Services Group, LLC, a company that provides independent director, Delaware Resident Trustee, Passive Investment Company and Offshore services to its clients. NRG Northeast pays Entity Services (SPV), LLC, a wholly-owned subsidiary of Entity Services Group, LLC, an annual fee of $1200 for Mr. Panaccione’s services.

William T. Pieper has been Vice President and Controller of NRG Energy since June 2001. In this capacity, Mr. Pieper has principal responsibility for all accounting matters at NRG Energy and its subsidiaries, including NRG Northeast. He has also held the positions of Controller, Assistant Controller and Manager of International Accounting since joining NRG Energy in March 1995. Prior to joining NRG Energy, Mr. Pieper practiced as a Certified Public Accountant for six years with the firm of KPMG.

All of NRG Northeast’s executive officers are employees of NRG Energy, NRG Northeast’s parent company, or Xcel Energy, NRG Energy’s parent company, and do not receive additional compensation for their service to NRG Northeast. See Form 10-K filed by NRG Energy on March 31, 2003 for information regarding executive compensation at NRG Energy, and Form 10-K filed by Xcel Energy on March 31, 2003 for information regarding executive compensation at Xcel Energy.

NRG Northeast has no employees and has entered into operation and maintenance agreements with subsidiaries of NRG Operating Services, Inc., a wholly-owned subsidiary of NRG. The agreements are effective for five years, with options to extend beyond five years. Under the agreements, the NRG Operating Services company operator operates and maintains its respective facility, including (i) coordinating fuel delivery, unloading and inventory, (ii) managing facility spare parts, (iii) meeting external performance standards for transmission of electricity, (iv) providing operating and maintenance consulting and (v) cooperating with and assisting NRG Northeast in performing NRG Northeast’s obligations under agreements related to its facilities.

Under the agreements, the operator charges an annual fee, and in addition, will be reimbursed for usual and customary costs related to providing the services including plant labor and other operating costs. A demobilization payment will be made if the subsidiary elects not to renew the agreement. There are also incentive fees and penalties based on performance under the approved operating budget, the heat rate and safety.

During 2002 and 2001, NRG Northeast incurred annual operating and maintenance costs billed from NRG Operating Services totaling $4.4 million. In addition, during 2002 and 2001 NRG Northeast incurred $117.9 million and $172.4 million, respectively, for usual and customary costs related to providing the services including plant labor and other operating costs.

NRG Northeast’s subsidiaries have entered into agreements with NRG Energy for corporate support and services. The agreements are perpetual in term, unless terminated in writing by a subsidiary. Under the agreements, NRG will provide services, as requested, in areas such as human resources, accounting, finance, treasury, tax, office administration, information technology, engineering, construction management, environmental, legal and safety. Under the agreements, NRG Energy is paid for personnel time as well as out-of-pocket costs.

During 2002 and 2001, NRG Northeast paid NRG Energy approximately $4.2 million and $5.1 million, respectively, for corporate support and services.

The President and Treasurer (the Certifying Officers) have evaluated NRG Northeast’s disclosure controls and procedures as defined in the rules of the SEC within 90 days of the filing date of this report and have determined that, except to the extent indicated otherwise in this paragraph, disclosure controls and procedures were effective in ensuring that material information required to be disclosed by NRG Northeast in the reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. During the fourth quarter of 2002, the Certifying Officers determined that there were certain deficiencies in the internal controls relating to financial reporting at NRG Northeast caused by NRG Northeast’s pending financial restructuring and business realignment. During the second half of 2002, there were material changes and vacancies in senior NRG Northeast management positions and a diversion of NRG Northeast’s financial and management resources to restructuring efforts. These circumstances detracted from NRG Northeast’s ability through its internal controls to timely monitor and accurately assess the impact of certain transactions, as would be expected in an effective financial reporting control environment. NRG Northeast has dedicated and will continue to dedicate in 2003 resources to make corrections to those control deficiencies. Notwithstanding the foregoing and as indicated in the certification accompanying the signature page to this report, the Certifying Officers have certified that, to the best of their knowledge, the financial statements, and other financial information included in this report on Form 10-K, fairly present in all material respects the financial conditions, results of operations and cash flows of NRG Northeast as of, and for the periods presented in this report.

NRG’s Northeast’s Certifying Officers are primarily responsible for the accuracy of the financial information that is represented in this report. To meet their responsibility for financial reporting, they have established internal controls and procedures which, subject to the disclosure in the foregoing paragraph, they believe are adequate to provide reasonable assurance that NRG Northeast’s assets are protected from loss.

The following consolidated financial statements of Northeast Generating and related notes thereto, together with the report thereon of PricewaterhouseCoopers LLP, appearing on pages 41 through 69 are included herein:

The following Consolidated Financial Statement Schedule of NRG Northeast is filed as part of Item 15(d) of this report and should be read in conjunction with the Consolidated Financial Statements.

All other financial statement schedules have been omitted because either they are not required or the information required to be set forth therein is included in the Consolidated Financial Statements or in the Notes thereto.

(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report.

(b) Reports on Form 8-K. NRG Northeast filed reports on Form 8-K on the following dates over the last fiscal year: August 1, 2002, October 24, 2002, November 27, 2002, December 23, 2002 and December 31, 2002.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of members’ equity and of cash flows present fairly, in all material respects, the financial position of NRG Northeast Generating LLC and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company and its ultimate parent, NRG Energy, Inc., are experiencing credit and liquidity constraints and the Company’s senior secured bonds are in default. As a direct consequence, during 2002 the Company entered into discussion with its creditors to develop a comprehensive restructuring plan. In connection with its restructuring efforts, it is likely that the Company will file for Chapter 11 bankruptcy protection. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”, for the year ended December 31, 2002. As discussed in Notes 2 and 3 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets,” on January 1, 2002. As discussed in Note 8 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” on January 1, 2001.

NRG Northeast Generating LLC (“the Company” or “NRG Northeast”), a wholly-owned indirect subsidiary of NRG Energy, Inc. (“NRG”), 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 the 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 Harbor Power LLC and Somerset Power LLC.

As of December 31, 1999, the Company held a 99% interest in Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Dunkirk Power LLC, Huntley Power LLC, Oswego Harbor Power LLC and Somerset Power LLC. Northeast Generating Holding LLC and NRG Eastern LLC each held a minority interest of 0.5% in Arthur Kill Power LLC (“Arthur Kill Power”), Astoria Gas Turbine Power LLC (“Astoria Gas Turbine Power”), Dunkirk Power LLC, Huntley Power LLC (“Huntley Power”), Oswego Harbor Power LLC (“Oswego Power”) and Somerset Power LLC (“Somerset Power”).

NRG Connecticut Generating LLC, a wholly-owned subsidiary of NRG, owned 100% of Connecticut Jet Power LLC, Devon Power LLC, Middletown Power LLC, Montville Power LLC and Norwalk Power LLC.

Effective January 1, 2000, the minority ownership interests held by Northeast Generating Holding LLC and NRG Eastern LLC as well as the ownership interest held by NRG Connecticut Generating LLC were transferred to the Company.

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 $432.0 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 lowered their ratings on NRG Energy’s and its subsidiaries’ unsecured bonds once again. Currently, NRG Energy’s unsecured bonds carry a rating of between CCC and D at S&P and between Ca and C at Moody’s, depending on the specific debt issue.

various operating projects as well as for projects that were under construction which NRG Energy has stopped funding.

In August 2002, NRG Energy retained financial and legal restructuring advisors to assist its management in the preparation of such comprehensive financial and operational restructuring. NRG Energy and its advisors have been meeting regularly to discuss restructuring issues with an ad hoc committee of its bondholders and a steering committee of its bank lenders (the Ad Hoc Creditors Committees). In November 2002, NRG Energy and Xcel Energy presented a comprehensive plan of restructuring to the Ad Hoc Creditors Committees. The restructuring plan has 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. If a comprehensive plan of restructuring is ultimately agreed to, it is highly probable that such a plan would be implemented through the commencement of a voluntary Chapter 11 bankruptcy proceeding. For more specific information regarding NRG Energy’s restructuring efforts, refer to “Liquidity Issues” in Item 1 of Form 10-K filed by NRG Energy on March 31, 2003.

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.

On December 15, 2002, NRG Northeast failed to make $24.7 million interest and $53.5 million principal payments. NRG Northeast had a 15-day grace period to make payment. On December 27, 2002, NRG Northeast made the $24.7 million interest payment due on the NRG Northeast bonds but failed to make the $53.5 million principal payment

NRG Northeast expects to have cash available for operations through 2003. This forecast does not assume further investment by Xcel Energy in NRG Energy, further contributions to NRG Northeast from NRG Energy, or modification of NRG Northeast’s current debt obligations. In the event that NRG Energy and NRG Northeast are unable to work through the issues as described above and are unable to obtain adequate financing on terms acceptable to NRG Energy and NRG Northeast to continue their operations, NRG Energy and NRG Northeast may have to file bankruptcy. NRG Energy and NRG Northeast’s inability to obtain timely waivers and avoid defaults on their credit obligations could lead to additional involuntary bankruptcy proceedings. In any case, there is substantial doubt as to NRG Northeast’s ability to continue as a going concern.

have been meeting regularly to discuss restructuring issues relating to NRG Northeast with an ad hoc committee of its bondholders (the NRG Northeast Bondholder Committee). NRG Northeast, its management and its financial and legal advisors have engaged in discussions with the NRG Project Bondholder Committee regarding the terms and conditions of a restructuring of the debt of NRG Northeast.

The accompanying consolidated financial statements have been prepared assuming NRG Northeast will continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

The consolidated financial statements include the accounts of NRG Northeast and its subsidiaries (referred to collectively herein as the Company). All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of the Company’s operations are in accordance with accounting principles generally accepted in the United States of America.

The principal business of NRG Northeast is the ownership and operation, through its subsidiaries and affiliates, of power generation facilities and the sale of energy, capacity and related products in the northeastern region of the United States.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results may differ from those estimates.

In recording transactions and balances resulting from business operations, NRG Northeast uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, uncollectible accounts, and the valuation of long-term energy commodities contracts, among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Cash and cash equivalents include highly liquid investments (primarily commercial paper) with an original maturity of three months or less at the time of purchase.

Inventory is valued at the lower of weighted average cost or market and consists principally of fuel oil, spare parts, coal and kerosene.

Property, plant and equipment are stated at cost. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation is computed on a straight-line basis over the following estimated useful lives:

The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in operations. NRG Northeast expenses all repair and maintenance as incurred, including planned major maintenance.

Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews were performed in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (SFAS No. 144) in 2002 and SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of” (SFAS No. 121) in prior years. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset is less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

Deferred financing costs consist of legal and other costs incurred by NRG Northeast to obtain long-term financing. These costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the terms of the related debt.

Other assets represent contractual rights held by NRG Energy. Other assets are amortized over their economic useful life and reviewed for impairment on a periodic basis. Other assets are comprised of prepaid transmission costs pursuant to a long-term contract. These amounts are being amortized over the life of the contract, which is 30 years. At December 31, 2002 and 2001, accumulated amortization of other assets was $2.6 million and $1.7 million, respectively.

Effective January 1, 2002, NRG Energy implemented SFAS No. 142, Goodwill and Other Intangible Assets (SFAS No. 142). Pursuant to SFAS No. 142, goodwill is not amortized but is subject to periodic impairment testing. At December 31, 2002 and 2001, NRG Northeast had no goodwill recorded in the financial statements.

Revenues from the sale of electricity are recorded based upon the output delivered and capacity provided at rates specified under contract terms or prevailing market rates. Revenues and related costs under cost reimbursable contract provisions are recorded as costs are incurred.

NRG Northeast’s subsidiaries have entered into agency agreements with a marketing affiliate for the sale of energy, capacity and ancillary services produced by these subsidiaries, and for the procurement and management of fuel (coal, oil derivatives and natural gas) and emission credit allowances, which enable the affiliate to engage in forward sales and hedging transactions to manage the subsidiaries’ electricity and fuel price exposure. Net gains or losses on hedges by the marketing affiliate, which are physically settled, are recognized in the same manner as the hedged item. NRG Northeast receives the net transaction price on all contracts that are physically settled by its marketing affiliate.

The Company has been organized as a limited liability company. Therefore, federal and state income taxes are assessed at the member level. Accordingly, no provision has been made for federal or state income taxes in the accompanying financial statements.

As of December 31, 2002 and 2001, the accompanying financial statements report a balance of $1.3 billion and $1.4 billion, respectively, for net property, plant and equipment. The tax basis of this property is estimated to be $1.1 billion and $1.2 billion as of December 31, 2002 and 2001, respectively. The primary difference is due to accelerated tax depreciation.

Financial instruments which potentially subject NRG Northeast to concentrations of credit risk consist primarily of cash, accounts receivable and derivative instruments. Cash accounts are generally held in federally insured banks. Accounts receivable and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact NRG Northeast’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, NRG Northeast believes the credit risk posed by industry concentration is mitigated by the diversification and creditworthiness of its customer base.

The carrying amount of cash and cash equivalents, receivables, accounts payables, and accrued liabilities approximate fair value because of the short maturity of these instruments.

In June 2001, the 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. The liability is initially capitalized as part of the cost of the related tangible long-lived asset and thus depreciated over the asset’s useful life. Accretion of the liabilities due to the passage of time will be an operating expense. 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 written or oral contracts, including obligations arising under the doctrine of promissory estoppel. NRG Northeast is required to adopt SFAS No. 143 on January 1, 2003. NRG Northeast is in the process of evaluating the impact of adopting SFAS No. 143 on its financial condition.

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,” (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 Principles 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. NRG Northeast has no extraordinary gains or losses resulting from extinguishment of debt during the three years ended December 31, 2002 that will require restatement upon adoption of this part of SFAS No. 145.

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 were effective for transactions occurring after May 15, 2002. Adoption of SFAS No. 145 is not expected to have a material impact on NRG Northeast.

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 Emerging Issues Task Force (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 November 2002, the FASB issued FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee. See Note 12.

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. Assets of entities consolidated upon adoption of the new standard will 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 NRG Northeast.

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.

The credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity experienced by NRG Northeast during the third quarter of 2002 were “triggering events” which, pursuant to SFAS No. 144, required the Company to review the recoverability of its long-lived

assets. As a result, NRG Northeast determined that Somerset Power became impaired during the third quarter of 2002 and should be written down to fair market value. Accordingly, NRG Northeast recorded asset impairment charges of $49.3 million related to Somerset Power. The impairment charges were recognized as special charges in the third quarter of 2002 statement of operations, as restated during the fourth quarter of 2002 (Note 14).

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 flow included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of NRG Northeast’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, whereas assets under construction or in development were based on expected service potential when complete. The cash flow estimates included probability weightings to consider possible alternative courses of action and outcomes, given NRG Northeast’s financial position and liquidity constraints.

Additional asset impairments may be recorded by NRG Northeast in periods subsequent to December 31, 2002, given the changing business conditions and the resolution of the pending NRG Energy restructuring plan and the FERC filing for cost of service rates for NRG Northeast’s Connecticut assets (see Note 13). Management is unable to determine the possible magnitude of any additional asset impairments, but they could be material.

In addition to asset impairment charges, NRG Northeast incurred $1.2 million of restructuring costs consisting of financial advisor and legal fees. These costs were also recognized as special charges in the statement of operations.

Inventory, which is stated at the lower of weighted average cost or market, at December 31, consists of:

The major classes of property, plant and equipment at December 31, were as follows:

On February 21, 2001, the Company renewed, for 90-days, its $50 million floating rate working capital revolving facility. The proceeds of this facility were used to finance the Company’s working capital needs. In May 2001, the Company allowed its $50 million floating rate working capital revolving facility to expire.

On February 22, 2000, NRG Northeast issued $750 million of project level 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. Interest and principal payments are due semi-annually. The bonds are jointly and severally guaranteed by each of NRG Northeast’s subsidiaries. The bonds are secured by a security interest in NRG Northeast’s membership or other ownership interests in the guarantors and its rights under all inter-company notes between NRG Northeast and the guarantors. In December 2000, NRG Northeast exchanged all of its outstanding bonds for bonds registered under the Securities Act of 1933. As of December 31, 2002 and 2001, there remains $556.5 million and $610 million of outstanding bonds, respectively. On December 15, 2002, NRG Northeast failed to make $24.7 million interest and $53.5 million principal payments. NRG Northeast Generating had a 15-day grace period to make payment. On December 27, 2002, NRG Northeast made the $24.7 million interest payment due on the NRG Northeast bonds but failed to make the $53.5 million principal payment. As a result, the payment default associated with its failure to make principal payments when they come due is currently in effect. NRG Northeast also failed to make a debt service reserve account cash deposit within 30 days of NRG Energy’s credit rating downgrade in July 2002. In addition, NRG Northeast is also in default of its debt covenants because of the lapse of the 60 day grace period regarding the necessary dismissal of an involuntary bankruptcy proceeding. As a result of these events of default, the entire $556.5 million owed on the secured bonds is classified as a current liability at December 31, 2002.

On June 15, 2002, NRG Energy loaned NRG Northeast $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 NRG Northeast and is subject to the terms and conditions of the senior secured bonds’ indenture. Accordingly, NRG Northeast has classified this loan as a short-term affiliated note payable.

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 NRG Northeast 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. NRG Northeast 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 NRG Northeast’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 December 31, 2002, the Company had various commodity contracts extending through 2006.

The following table summarizes the effects of SFAS No. 133 on the Company’s accumulated other comprehensive income balance as of December 31, 2002 and 2001, respectively:

The adoption of SFAS No. 133 on January 1, 2001, resulted in an unrealized gain of $14.1 million recorded to OCI related to previously deferred net gains on derivatives designated as cash flow hedges. During the years ended December 31, 2002 and 2001, the Company reclassified gains of $48.1 million and losses of $14.6 million, respectively, from OCI to current-period earnings. This amount is recorded on the same line in the statement of operations in which the hedged item is recorded. Also during the years ended December 31, 2002 and 2001, the Company recorded losses in OCI of approximately $30.8 million and gains of $79.0 million, 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 December 31, 2002 and 2001 was a gain of approximately $28.8 million and $107.7 million, respectively. The Company expects $28.8 million of the deferred net gains on derivative instruments accumulated in OCI to be recognized as earnings during the next twelve months.

The following tables summarize the effects of SFAS No. 133 on the Company’s statement of operations for the years ended December 31, 2002 and 2001, respectively:

During the years ended December 31, 2002 and 2001, respectively, NRG Northeast recognized no gain or loss due to ineffectiveness of commodity cash flow hedges.

NRG Northeast’s earnings for the years ended December 31, 2002 and 2001 were increased by an unrealized gain of $14.5 million and decreased by an unrealized loss of $31.2 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.

The estimated December 31 fair values of NRG Northeast’s recorded financial instruments are as follows:

For cash and cash equivalents, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of long-term debt is estimated based on the quoted market prices for similar issues.

NRG Northeast is exposed to commodity price variability in electricity, emission allowances, natural gas, oil derivatives and coal used to meet fuel requirements. In order to manage these commodity price risks, NRG Northeast may enter into transactions for physical delivery of particular commodities for a specific period. Financial instruments are used to hedge physical deliveries, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. These transactions are utilized to:


	•	Manage and hedge its fixed-price purchase and sales commitments;

	•	Reduce its exposure to the volatility of spot market prices;

	•	Hedge fuel requirements at its generation facilities; and

	•	Protect its investment in fuel inventories.

From time to time, NRG Northeast may use interest rate hedging instruments to protect it from an increase in the cost of borrowing. As of December 31, 2002 and 2001, there were no such instruments outstanding.

The Company’s subsidiaries have entered into agency agreements with NRG Power Marketing Inc. (“NRG Power Marketing”), a wholly-owned subsidiary of NRG. The agreements are effective until December 31, 2030. Under the agreements, NRG Power Marketing will (i) have the exclusive right to manage, market, hedge and sell all power not otherwise sold or committed to by such subsidiaries, (ii) procure, provide and hedge for such subsidiaries all fuel required to operate their respective facilities and (iii) market, sell and purchase all emission credits owned, earned or acquired by such subsidiaries. In addition, NRG Power Marketing will have the exclusive right and obligation to effect the dispatch of the power output from the facilities.

Under the agreements, NRG Power Marketing pays to the subsidiaries gross receipts generated through sales, less costs incurred by NRG Power Marketing relative to its providing services (e.g. transmission and delivery costs, fuel cost, taxes, labor, contract services, etc.) The Company incurs no fees related to these power sales and agency agreements with NRG Power Marketing.

The Company has no employees and has entered into operation and maintenance agreements with subsidiaries of NRG Operating Services, Inc., a wholly-owned subsidiary of NRG (“NRG Operating Services”). The agreements are effective for five years, with options to extend beyond five years. Under the agreements, the NRG Operating Services company operator operates and maintains its respective facility, including (i) coordinating fuel delivery, unloading and inventory, (ii) managing facility spare parts, (iii) meeting external performance standards for transmission of electricity, (iv) providing operating and maintenance consulting and (v) cooperating with and assisting the Company in performing the Company’s obligations under agreements related to its facilities.

During 2002 and 2001, the Company incurred annual operating and maintenance costs billed from NRG Operating Services totaling $4.4 million. In addition, the Company incurred $117.9 million and $172.4 million, respectively, for usual and customary costs related to providing the services including plant labor and other operating costs.

The Company’s subsidiaries have entered into agreements with NRG for corporate support and services. The agreements are perpetual in term, unless terminated in writing by a subsidiary. Under the agreements, NRG will provide services, as requested, in areas such as human resources, accounting, finance, treasury, tax, office administration, information technology, engineering, construction management, environmental, legal and safety. Under the agreements, NRG is paid for personnel time as well as out-of-pocket costs.

During 2002 and 2001, the Company paid NRG approximately $4.2 million and $5.1 million, respectively, for corporate support and services.

NRG Northeast leases certain of its storage space and equipment under operating leases expiring on various dates through 2018. Rental expense under these operating leases was approximately $0.8 million, $0.9 million, and $0.6 million in 2002, 2001, and 2000, respectively. Future minimum lease commitments under these leases for the years ending after December 31, 2002 are as follows:

Management currently forecasts that cash flow from operations for 2003 will be insufficient to cover capital expenditures, which include minor refurbishments and environmental compliance. Given this shortfall, NRG Northeast anticipates funding its ongoing capital requirements through operating cash flows and existing cash, as well as potential external financing. NRG Northeast’s capital expenditure program is subject to continuing review and modification. The timing and actual amount of expenditures may differ significantly based upon plant operating history, unexpected plant outages, changes in the regulatory environment, the availability of cash and restructuring efforts.

As part of acquiring existing generating assets, NRG Northeast has inherited certain environmental liabilities associated with regulatory compliance and site contamination. Often potential compliance implementation plans are changed, delayed or abandoned due to one or more of the following conditions: (a) extended negotiations with regulatory agencies, (b) a delay in promulgating rules critical to dictating the design of expensive control systems, (c) changes in governmental/regulatory personnel, (d) changes in governmental priorities or (e) selection of a less expensive compliance option than originally envisioned.

In response to liabilities associated with these activities, NRG Northeast has established accruals where reasonable estimates of probable liabilities are possible. As of December 31, 2002 and 2001, NRG Northeast has established such accruals in the amount of approximately $3.8 million and $5.0 million, respectively, primarily related to its Arthur Kill and Astoria projects. NRG Northeast has not used discounting in determining its accrued liabilities for environmental remediation and no claims for possible recovery from third party issuers or other parties related to environmental costs have been recognized in NRG Northeast’s consolidated financial statements. NRG Northeast adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates are adjusted to reflect new information. During the years ended December 31, 2002, 2001 and 2000, NRG Northeast recorded expenses of approximately $5.8 million, $7.2 million and $3.0 million related to environmental matters, respectively.

Coal ash is produced as a by-product of coal combustion at the Dunkirk, Huntley, and Somerset Generating Stations. NRG Northeast attempts to direct its coal ash to beneficial uses. Even so, significant amounts of ash are landfilled at on-site and off-site locations. At Dunkirk and Huntley, ash is disposed at landfills owned and operated by NRG Northeast. No material liabilities outside the costs associated with closure, post-closure care and monitoring are expected at these facilities. NRG Northeast maintains financial assurance to cover costs associated with closure, post-closure care and monitoring activities. In the past, NRG Northeast has provided financial assurance via financial test and corporate guarantee. NRG Northeast must re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, currently estimated at approximately $5.8 million. NRG Northeast is required to provide an alternative instrument to provide such financial assurance on or before April 30, 2003.

Historical clean-up liabilities were inherited as a part of acquiring the Somerset, Devon, Middletown, Montville, Norwalk, Arthur Kill and Astoria Generating Stations. NRG Northeast has recently satisfied clean-up obligations associated with the Ledge Road property (inherited as part of the Somerset acquisition). Site contamination liabilities arising under the Connecticut Transfer Act at the Devon, Middletown, Montville and Norwalk Stations have been identified and are currently being refined as part of on-going site investigations. NRG Northeast does not expect to incur material costs associated with completing the investigations at these Stations or future work to cover and monitor landfill areas pursuant to the Connecticut requirements. Remedial obligations at the Arthur Kill Generating Station have been established in discussions between NRG Northeast and the New York State DEC and are estimated at $1.0 million. Remedial investigations are on-going at the Astoria Generating Station. At this time, NRG Northeast’s long-term cleanup liability at this site is estimated at $1.5 million. However, the magnitude of cleanup costs for the Astoria Station cannot be estimated with certainty until the results of the remedial investigation are available.

NRG Northeast estimates that it will incur total environmental capital expenditures of $53 million during 2003 through 2007. These expenditures will be primarily related to landfill construction, installation of NOx controls, installation of the best technology available for minimizing environmental impacts associated with impingement and entrainment of fish and larvae, particulate matter control improvements, spill prevention controls, and undertaking remedial actions. NRG Northeast estimates that it will incur in 2003 at all of its plants approximately $8 million in capital expenditures for plant modifications and upgrades required to comply with environmental regulations.

As of December 31, 2002, NRG Energy had recorded an accrual in the amount of $1.6 million to cover penalties associated with historical opacity exceedances.

In connection with the acquisition of certain generating facilities NRG Northeast entered into various long-term transition agreements and standard offer agreements that obligated NRG Northeast to provide its customers, primarily the previous owners of the acquired facilities, with a certain portion of the energy and capacity output of the acquired facilities.

During 1999, NRG Northeast acquired the Huntley and Dunkirk generating facilities from Niagara Mohawk Power Corporation (NiMo). In connection with this acquisition, NRG Northeast entered into a 4-year agreement with NiMo that requires NRG Northeast to provide to NiMo pursuant to a predetermined

schedule fixed quantities of energy and capacity at a fixed price. The contract is recorded as a cash flow hedge for financial reporting purposes (see Note 8).

During 1999, NRG Northeast acquired certain generating facilities from Connecticut Light and Power Company (CL&P). NRG Power Marketing also entered into a 4-year standard offer agreement that requires Power Marketing to provide to CL&P a portion of its load requirements through the year 2003 at a fixed rate of $43.83 per mwh. This is a round-the-clock obligation. Through its agency agreement with NRG Northeast, NRG Power Marketing utilizes the capacity available in the Connecticut facilities in order to serve the contract.

During 1999, NRG Northeast 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 has entered into a wholesale standard offer service agreement with Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation (collectively the EUA Company’s). Under the agreement, NRG Power Marketing is obligated to provide each of the EUA Company’s 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 Company’s pay to NRG Power Marketing for each unit of electricity is a fixed price plus a fuel adjustment factor.

In July 2002, NRG Power Marketing reached a tentative agreement with Connecticut Light & Power (CL&P) that would result in increased compensation to NRG Power Marketing, 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 Northeast announced that it had reached an agreement with ISO-NE to keep three units at its Devon station in service in return for a fixed reliability must run (RMR) capacity payment. The agreement expires on September 30, 2003.

In November 2002, the NYISO notified NRG Northeast 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 Northeast strenuously disagrees with both the validity and calculation of the claims and is currently negotiating with the NYISO over the ultimate disposition. NRG Northeast reduced its revenues by $21.7 million and recorded a corresponding reserve for the receivables during 2002.

In November 2002, The FASB issued FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the

requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

NRG Northeast is directly liable for the obligations of certain of its affiliates pursuant to guarantees relating to certain of their performance 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 NRG Northeast’s generation facilities, NRG Northeast may be required to guarantee a portion of the obligations of certain of its subsidiaries.

As of December 31, 2002, NRG Northeast’s obligations pursuant to its guarantees of the performance obligations of its affiliates and subsidiaries totaled approximately $140.8 million.

As of December 31, 2002, the nature and details of NRG Northeast’s guarantees were as follows:

NRG Northeast provides performance guarantees to third parties on behalf of NRG Power Marketing in relation to certain of its sales and supply agreements.

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

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 asserts that projects undertaken at NRG Energy’s Huntley and Dunkirk plants by NiMo, the former owner of the facilities, should have been permitted pursuant to the Clean Air Act and that the failure to do so 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 or re-file a case against NRG Energy. 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 plant wide 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

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 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 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.

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

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 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.

Effective March 1, 2003, ISO-NE implemented its version of standard market design (SMD). This change dramatically modifies the New England market structure by incorporating locational marginal pricing

(LMP — pricing by location rather than on a New England wide basis). Even though NRG Northeast views this change as a significant improvement to the existing market design, NRG Northeast still views the market in New England as incapable of allowing NRG Northeast to recover its costs and provide a reasonable return on investment. Consequently, on February 26, 2003, Devon Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC and NRG Power Marketing (collectively, the NRG Filers) filed and requested a cost of service rate with FERC for most of its Connecticut fleet, requesting a February 27th effective date. The NRG Filers remain committed to working with ISO-NE, FERC and other stakeholders to continue to improve the New England market that will hopefully make further reliance on a cost of service rate unnecessary. While the NRG Filers have the right to file for such rate treatment, there are no assurances that FERC will grant such rates in the form or amount that the NRG Filers petitioned for in their filing. On March 25, 2003, the Federal Energy Regulatory Commission (FERC) issued an order (the Order) in response to the NRG Filers’ Joint Motion for Emergency Expedited Issuance of Order by March 17, 2003 in Docket No. ER03-563-000 (the Emergency Motion). In the Emergency Motion, the NRG Filers requested that FERC accept the NRG Filers’ reliability must-run agreements and assure the NRG Filers’ recovery of deferred maintenance costs for their New England generating facilities prior to the peak summer season. FERC accepted the NRG Filers’ filing as to the recovery of spring 2003 maintenance costs, subject to refund. FERC’s Order authorizes the ISO New England Inc. to begin collecting these maintenance costs in escrow for the benefit of the NRG Filers as of February 27, 2003. Several intervenors protested the Emergency Motion. FERC will rule on such protests and the other issues raised in the Emergency Motion in a subsequent order.

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 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.

In New York, NRG Northeast anticipates that the NYISO will implement a demand curve in its capacity market. In PJM, NRG Northeast is closely following market power mitigation modifications that may significantly impact the revenues achievable in that market by modifying PJM’s price capping mechanisms. The potential modifications are unknown at this time, and it is unclear whether such changes would have a positive or a negative effect on NRG Northeast.

Subsequent to the issuance of NRG Northeast’s financial statements for the quarter ended September 30, 2002, NRG Northeast’s management determined that the accounting for certain transactions required restatement.

NRG Northeast determined that it had misapplied the provisions of SFAS No. 144 related to asset groupings in connection with the review for impairment of its long-lived assets during the quarter ended September 30, 2002. SFAS No. 144 requires that for purposes of testing recoverability, assets be grouped at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets. NRG Northeast recalculated the asset impairment tests in accordance with SFAS No. 144 using the appropriate asset grouping for independent cash flows for each generation facility. As a result, NRG Northeast concluded that an asset impairment should have been recorded for its project known as Somerset Power LLC. Since NRG Northeast concluded that triggering events that led to the impairment charge were experienced in the third quarter of 2002, the asset impairment related to this project should have been recorded as of September 30, 2002. NRG Northeast calculated the asset impairment charge for Somerset Power LLC to be $49.3 million.

A summary of the significant effects of the restatement on our consolidated statements of operations for the three and nine months ended September 30, 2002 is as follows:

A summary of the significant effects of the restatement on our consolidated balance sheet as of September 30, 2002 is as follows:

Our audits of the consolidated financial statements referred to in our report dated March 28, 2003 appearing in this Annual Report on Form 10-K also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Annual Report on Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.


(1)	A total of $28.4 million was recorded as a reduction of revenues in the accompanying financial statements.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	NRG NORTHEAST GENERATING LLC
	(Registrant)

	/s/ RICHARD C. KELLY

	Richard C. Kelly
	President and Management Committee Member

Each person whose signature appears below constitutes and appoints Richard C. Kelly and George Schaefer, each or any of them, such person’s true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in such person’s name, place and stead, in any and all capacities, to sign any and all amendments to this report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on April 14, 2003:

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.

An annual report will not be sent to security holders. No proxy material will be sent to security holders.

1. I have reviewed this annual report on Form 10-K of NRG Northeast Generating LLC;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:


	a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

	b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

	c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):


	a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


	/s/ RICHARD C. KELLY

	Richard C. Kelly
	President and Management Committee Member

1. I have reviewed this annual report on Form 10-Q of NRG Northeast Generating LLC;


	a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

	b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

	c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;


	a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


	/s/ GEORGE SCHAEFER

	George Schaefer
	Treasurer and Management Committee Member


(1)	Previously filed with Report on Form S-4 filed on July 31, 2000 (File No. 333-42638).

(2)	Previously filed with Report on Form S-4/A filed on October 23, 2000 (File No. 333-42638).


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the fiscal year ended December 31, 2002.

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from to .


Delaware		41-1937472
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

901 Marquette Avenue, Suite 2300 Minneapolis, Minnesota (Address of principal executive offices)		55402 (Zip Code)


PART I
	Item 1 -- Business
	Item 2 -- Properties
	Item 3 -- Legal Proceedings
	Item 4 -- Submission of Matters to a Vote of Security Holders
PART II
	Item 5 -- Market for the Registrant’s Common Equity and Related Stockholder Matters
	Item 6 -- Selected Financial Data
	Item 7 -- Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 7A -- Quantitative and Qualitative Disclosures About Market Risk
	Item 8 -- Financial Statements and Supplementary Data
	Item 9 -- Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
	Item 10 -- Directors and Executive Officers of the Registrant
	Item 11 -- Executive Compensation
	Item 12 -- Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
	Item 13 -- Certain Relationships and Related Transactions
	Item 14 -- Controls and Procedures
PART IV
	Item 15 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K
CERTIFICATION
Exhibit Index
Subsidiaries of the NRG Northeast
Officer Certification
Financial Statement of Dunkirk Power LLC
Financial Statements of Huntley Power LLC
Financial Statements of Arthur Kill Power LLC
Financial Statements of Middletown Power LLC
Financial Stmts of Astoria Gas Turbine Power LLC


		Page No.

PART I
Item 1	Business		3
Item 2	Properties		16
Item 3	Legal Proceedings		16
Item 4	Submission of Matters to a Vote of Security Holders		18
PART II
Item 5	Market for Registrants’ Common Equity and Related Stockholder Matters		18
Item 6	Selected Financial Data		19
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 7A	Quantitative and Qualitative Disclosure About Market Risk		36
Item 8	Financial Statements and Supplementary Data		37
Item 9	Changes in & Disagreements With Accountants on Accounting and Financial Disclosure		37
PART III
Item 10	Directors and Executive Officers of the Registrants		37
Item 11	Executive Compensation		38
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		38
Item 13	Certain Relationships and Related Transactions		38
Item 14	Controls and Procedures		39
PART IV
Item 15	Exhibits, Financial Statement Schedules, and Reports on Form 8-K		40
Signatures			70


	Amount							Interest		Principal
Debt ($ in millions)	Issued		Rate			Maturity		Due		Due		Date Due

Non-Recourse Debt (secured)
NRG Northeast Generating LLC	$	320.0		8.065	%		12/15/2004	$	5.1	$	53.5		12/15/2002
NRG Northeast Generating LLC	$	130.0		8.842	%		6/15/2015	$	5.7		—		12/15/2002
NRG Northeast Generating LLC	$	300.0		9.292	%		12/15/2024	$	13.9		—		12/15/2002


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


		Net		NRG’s
		Owned		Percentage
		Capacity		Ownership
Name and Location of Facility	Purchaser/Power Market	(MW)		Interest			Fuel Type

Oswego, New York	Niagara Mohawk/NYISO		1,700		100	%	Oil/Gas
Huntley, New York	Niagara Mohawk/NYISO		760		100	%	Coal
Dunkirk, New York	Niagara Mohawk/NYISO		600		100	%	Coal
Arthur Kill, New York	NYISO		842		100	%	Gas/Oil
Astoria Gas Turbines, New York	NYISO		614		100	%	Gas/Oil
Somerset, Massachusetts	Eastern Utilities Associates		160		100	%	Coal/Oil/Jet
Middletown, Connecticut	ISO-NE		856		100	%	Oil/Gas/Jet
Montville, Connecticut	ISO-NE		498		100	%	Oil/Gas
Devon, Connecticut	ISO-NE		401		100	%	Gas/Oil/Jet
Norwalk, Connecticut	ISO-NE		353		100	%	Oil
Connecticut Jet Power, Connecticut	ISO-NE		127		100	%	Jet


							For the
							period from
	Year Ended December 31,						April 27, 1999
							(inception) to
	2002		2001		2000		December 31, 1999


	(In thousands)
Total operating revenues	$	693,869	$	1,050,688	$	1,121,798	$	258,574
Special charges		50,524		—		—		—
Total operating costs and expenses		643,459		785,420		776,193		177,817
Net income		3,885		211,255		283,309		54,347
Total assets		1,693,737		1,794,730		1,750,484		1,704,638
Long-term debt, including current Maturities		586,500		610,000		700,000		682,330


	*For the Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000*


Accounting Policy		Judgments/Uncertainties Affecting Application

Capitalization Practices/Purchase Accounting		• Determination of beginning and ending of capitalization periods • Allocation of purchase prices to identified assets
Asset Valuation		• Recoverability of investment through future operations • Regulatory and political environments and requirements • Estimated useful lives of assets • Environmental obligations and operational limitations • Estimates of future cash flows • Estimates of fair value • Judgement about triggering events
Revenue Recognition		• Customer/counter-party dispute resolution practices • Market maturity and economic conditions • Contract interpretation
Uncollectible Receivables		• Economic conditions affecting customers, counter parties, suppliers and market prices • Regulatory environment and impact on customer financial condition • Outcome of litigation and bankruptcy proceedings
Derivative Financial Instruments		• Market conditions in the energy industry, especially the effects of price volatility on contractual commitments • Assumptions used in valuation models • Counter party credit risk • Regulatory and political environments and requirements
Litigation Claims and Assessments		• Impacts of court decisions • Estimates of ultimate liabilities arising from legal claims



	For the Year Ended December 31,

	2002		2001		2000


	(In thousands)
Net cash provided by operating activities	$	71,610	$	165,991	$	430,094



	Payments Due by Period Subsequent to December 31, 2002

	Total		Short Term		1-3 Years		4-5 Years		After 5 Years


	(In thousands)
Long term debt	$	556,500	$	556,500	$	—	$	—	$	—
Operating Leases		6,676		780		1,536		1,048		3,312
Note payable — affiliate		30,000				—		—		30,000

Total contractual cash obligations	$	593,176	$	557,280	$	1,536	$	1,048	$	33,312



	Amount of Commitment by Expiration Period as of December 31, 2002

	Total Amounts
	Committed		Short Term		1-3 Years		4-5 Years		After 5 Years


	(In thousands)
Guarantees	$	140,839	$	140,839	$	—	$	—	$	—

Total commercial commitments	$	140,839	$	140,839	$	—	$	—	$	—


Gains/(Losses)	Total

	(Thousands of dollars)
Fair Value of contracts outstanding at the beginning of the period	$	76,513
Contracts realized or otherwise settled during the period		(25,079	)
Fair value of new contract when entered into during the period		—
Changes in fair values attributable to changes in valuation techniques		—
Other changes in fair values		(39,370	)

Fair value of contracts outstanding at the end of the period	$	12,064



	Fair Value of Contracts at Period End

	Maturity							Maturity in
	Less than 1			Maturity		Maturity		excess of		Total Fair
Maturity schedule	Year			1-3 Years		4-5 Years		5 Years		Value


	(Thousands of dollars)
Prices actively quoted	$	(18,813	)	$	2,042	$	—	$	—	$	(16,771	)
Prices provided by other external sources		—			—		—		—		—
Prices based on models & other valuation methods		28,835			—		—		—		28,835

	$	10,022		$	2,042	$	—	$	—	$	12,064


Item 1 —	*Business*


	*NRG Northeast Indebtedness and Liquidity Issues*


	*Environmental and Safety Laws and Regulations*


	*Energy Regulation*


Item 7A —	*Quantitative and Qualitative Disclosures About Market Risk*


Item 8 —	*Financial Statements and Supplementary Data*


Item 9 —	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosures*


Item 10 —	*Directors and Executive Officers of the Registrant*


Name	Age		Title

Richard C. Kelly		57	President and Management Committee Member
Scott J. Davido		41	Vice President, Assistant Secretary and Management Committee Member
George P. Schaefer		52	Treasurer and Management Committee Member
Andrew T. Panaccione		42	Management Committee Member
William T. Pieper		37	Controller


Item 12 —	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*


Item 15 —	*Exhibits, Financial Statement Schedules and Reports on Form 8-K*


Consolidated Balance Sheets — December 31, 2002 and 2001
Consolidated Statements of Operations — Years ended December 31, 2002, 2001 and 2000
Consolidated Statements of Cash Flows — Years ended December 31, 2002, 2001 and 2000
Consolidated Statements of Member’s Equity — Years ended December 31, 2002, 2001 and 2000
Notes to Consolidated Financial Statements — December 31, 2002.



			December 31,

			2002		2001


			(In thousands)
ASSETS
Current Assets:
	Cash and cash equivalents		$	14,354	$	370
	Accounts receivable, net of allowance for doubtful accounts of $50,712 and $0			118,153		56,025
	Inventory			123,963		172,215
	Derivative instruments valuation — at fair value			23,039		—
	Prepaid expenses			38,309		20,116

Total current assets				317,818		248,726
Property, plant & equipment, net of accumulated depreciation of $157,534 and $113,688				1,333,928		1,403,318
Deferred finance costs, net of accumulated amortization of $1,161 and $750				8,995		9,406
Derivative instruments valuation — at fair value				9,601		109,017
Other assets, net of accumulated amortization of $2,605 and $1,737				23,395		24,263

Total assets			$	1,693,737	$	1,794,730

LIABILITIES AND MEMBERS’ EQUITY
Liabilities:
	Current portion of long-term debt		$	556,500	$	107,000
	Note payable — affiliate			30,000		—
	Accounts payable			14,607		2,550
	Accounts payable-affiliates			11,476		—
	Accrued fuel and purchased power expense			37,168		27,049
	Accrued interest			4,198		2,160
	Other accrued liabilities			11,713		41,228
	Derivative instruments valuation — at fair value			13,017		32,504

Total current liabilities				678,679		212,491
Long-term debt				—		503,000
Derivative instruments valuation — at fair value				7,559		—
Other long-term liabilities				27,936		24,655

Total liabilities				714,174		740,146
Commitments and contingencies
Members’ equity				979,563		1,054,584

		Total liabilities and members’ equity	$	1,693,737	$	1,794,730


							Accumulated
	Members’						Other			Total
	Contributions/			Accumulated			Comprehensive			Members’
	Distributions			Net Income			Income			Equity


	(In thousands)
Balances at December 31, 1999	$	872,801		$	54,347		$	—		$	927,148

Net income					283,309			—			283,309
Distributions to members, net		(84,486	)		(337,656	)		—			(422,142	)

Balances at December 31, 2000	$	788,315		$	—			—		$	788,315

Cumulative effect upon adoption of SFAS No 133		—			—			14,100			14,100
Impact of SFAS No. 133 for the year ending December 31, 2001		—			—			93,641			93,641
Net income		—			211,255			—			211,255

Comprehensive income		—									318,996
Distributions to members, net		—			(52,727	)		—			(52,727	)

Balances at December 31, 2001	$	788,315		$	158,528		$	107,741		$	1,054,584

Impact of SFAS No. 133 for the year ending December 31, 2002		—			—			(78,906	)		(78,906	)
Net income		—			3,885			—			3,885

Comprehensive loss		—									(75,021	)

Balances at December 31, 2002	$	788,315		$	162,413		$	28,835		$	979,563


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



		Energy Commodities


		Year Ended December 31,

Gains/(Losses)		2002			2001


		(In thousands)
Beginning balance		$	107,741		$	—
	Initial adoption of SFAS No. 133.		—			14,100
	Unwound from OCI during period:
	— due to forecasted transaction no longer probable		—			—
	— due to unwinding of previously deferred amounts		(48,086	)		14,623
	Mark to market of hedge contracts		(30,820	)		79,018

Ending balance		$	28,835		$	107,741

Gains/(Losses) expected to unwind from OCI during next 12 months		$	28,835



	2002				2001

	Carrying		Fair		Carrying
	Amount		Value		Amount		Fair Value


	(In thousands)
Cash and cash equivalents	$	14,354	$	14,354	$	370	$	370
Long-term debt, including current Portion		556,500		486,250		610,000		590,284


		(Thousands
		of dollars)

2003		$	780
2004			775
2005			761
2006			760
2007			288
Thereafter			3,312

	Total	$	6,676



	Previously Reported				As Restated

	Three Months		Nine Months		Three Months			Nine Months
	Ended		Ended		Ended			Ended


	(In thousands)
Revenue and equity earnings	$	233,604	$	550,252	$	233,064		$	550,252
Operating income/(loss)		32,531		103,134		(16,758	)		53,845
Net income/(loss)		19,787		68,680		(29,502	)		19,391



	As of September 30, 2002

	Previously
	Reported		As Restated


	(In thousands)
Net property, plant and equipment	$	1,385,316	$	1,336,027
Members’ equity		1,101,330		1,052,041



	Quarter Ended 2002


	(Thousands of dollars)
	Mar 31		June 30		Sept 30			Dec 31			Total Year


	Restated
Revenue and equity earnings	$	131,568	$	185,080	$	233,604		$	143,617		$	693,869
Operating income/(loss)		17,550		53,053		(16,758	)		(3,435	)		50,410
Net income/(loss)		2,140		46,753		(29,502	)		(15,506	)		3,885



	Quarter Ended 2001


	(Thousands of dollars)
	Mar 31		June 30		Sept 30		Dec 31		Total Year

Revenue and equity earnings	$	275,732	$	270,819	$	352,158	$	151,979	$	1,050,688
Operating income		64,179		32,029		129,467		39,593		265,268
Net income		49,478		17,685		114,804		29,288		211,255


Column A		Column B		Column C			Column D		Column E

				Additions
		Balance at		Charged to					Balance
		Beginning		Costs and					at End of
Description		of Period		Expenses			Deductions		Period


		(In thousands)
Allowance for doubtful accounts, deducted from accounts receivable in the balance sheet:
	2002	$	—	$	50,712(1	)	$	—	$	50,712
	2001		8,165		(8,165	)		—		—
	2000		—		8,165			—		8,165



Signature				Title

/s/ RICHARD C. KELLY Richard C. Kelly				President (Principal Executive Officer) and Management Committee Member

/s/ GEORGE SCHAEFER George Schaefer				Treasurer (Principal Financial Officer) and Management Committee Member

/s/ SCOTT J. DAVIDO Scott J. Davido				Vice President, Assistant Secretary and Management Committee Member

/s/ ANDREW T. PANACCIONE Andrew T. Panaccione				Management Committee Member

/s/ WILLIAM T. PIEPER William T. Pieper				Controller (Principal Accounting Officer)