NRG ENERGY INC - 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 Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes o No 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, there were 3 shares of Class A Common Stock and 1 share of Common Stock outstanding, all of which were owned by Xcel Energy Wholesale Group Inc.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock as of the latest practicable date.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes þ No o

NRG Energy, Inc. (NRG Energy or the Company) 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.

Since the early 1990’s, NRG Energy pursued a strategy of growth through acquisitions. Starting in 2000, NRG Energy added the development of new construction projects to this strategy. This strategy required significant capital, much of which was satisfied primarily with third party debt. As of December 31, 2002, NRG Energy had approximately $9.4 billion of debt on its balance sheet at the corporate and project levels. 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 in order to become a more stable and conservatively capitalized company. 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 were to file for Chapter 11 bankruptcy protection, Xcel Energy’s equity ownership would most likely be eliminated and a large number of NRG Energy’s creditors’ claims would be impaired.

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.

NRG Energy is restructuring its operations to become a domestic based owner-operator of a fuel-diverse portfolio of electric generation facilities engaged in the sale of energy, capacity and related products. 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. NRG Energy does not anticipate any new significant acquisitions or construction, and instead will focus on operational performance and asset management. NRG Energy has already made significant reductions in expenditures, business development activities and personnel. Power sales, fuel procurement and risk management will remain a key strategic element of NRG Energy’s operations. NRG Energy’s objective will be to optimize the fuel input and the energy output of its facilities within an appropriate risk and liquidity profile.

NRG Energy was incorporated as a Delaware corporation on May 29, 1992. Its headquarters and principal executive offices are located at 901 Marquette Avenue, Suite 2300, Minneapolis, Minnesota 55402. NRG Energy’s telephone number is (612) 373-5300. NRG Energy and Xcel Energy are required to file periodic reports and other documents with the SEC. 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

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 3900 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, 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 projects that were under construction which NRG Energy has stopped funding.

NRG Energy and its subsidiaries have failed to timely make the following interest and/or principal payments on its indebtedness:

These missed payments may have also resulted in cross-defaults of numerous other non-recourse and limited recourse debt instruments of NRG Energy. In addition, the following issues have been accelerated, rendering the debt immediately due and payable: on November 6, 2002, lenders to NRG Energy accelerated the approximately $1.1 billion of debt under the construction revolver facility; on November 21, 2002, the bond trustee, on behalf of bondholders, accelerated the approximately $750 million of debt under the NRG South Central Generating, LLC facility; and on February 27, 2003, ABN Amro, as administrative agent, accelerated the approximately $1.0 billion corporate revolver financing facility.

Since September, the following payments were made: on December 10, 2002, $16.0 million in interest, principal, and swap payments were made from restricted cash accounts in relation to the $325,000,000 Series A Floating Rate Senior Secured Bonds due 2019, issued by NRG Peaker Finance Company LLC (the “Peaker financing facility”); 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; in January 2003, the South Central Generating bondholders unilaterally withdrew $35.6 million from a restricted revenue account relating to the September 15, 2002 interest payment and fees; and on March 17, 2003 South Central bondholders were paid $34.4 million due in relation to the March semi-annual interest payment, but the $12.8 million principal payment was deferred.

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 letters of credit or cash collateral within 5 to 30 days of a ratings downgrade below Baa3 or BBB- by Moody’s or Standard & Poor’s, respectively. As a result of the downgrades on July 26 and July 29, NRG Energy received demands to post collateral aggregating approximately $1.1 billion.

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

Effective as of September 13, 2002, NRG Energy and these various secured project lenders entered into a Second Collateral Call Extension Letter (Second CCEL) that extended the deadline until November 15, 2002. Under the Second CCEL, NRG Energy agreed to submit to the lenders a comprehensive restructuring plan. NRG Energy submitted this plan on November 4, 2002 and continues to work with its lenders and advisors on an overall restructuring of its debt (see further discussion below). The November 15, 2002 deadline of the second CCEL passed without NRG Energy posting the required collateral. NRG Energy and the secured project lenders continue to work toward a plan of restructuring.

In August 2002, NRG Energy retained financial and legal restructuring advisors to assist its management in the preparation of a comprehensive financial and operational restructuring. 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).

To aid in the design and implementation of a restructuring plan, in the fall of 2002, NRG Energy prepared a comprehensive business plan and forecast. Anticipating that NRG Energy’s creditors will own all or substantially all of NRG Energy’s equity interests after implementing the restructuring plan, any plans and efforts to integrate NRG Energy’s business operations with those of Xcel Energy were terminated. Using commodity, emission and capacity prices provided by an independent energy consulting firm to develop forecasted cash flow information, management concluded that the forecasted free cash flow available to NRG Energy after servicing project level obligations will be insufficient to service recourse debt obligations at the NRG Energy corporate level. Based on that forecast, it is anticipated that NRG Energy will remain in default of the various corporate level debt obligations discussed more fully herein.

Based on this information and in consultation with Xcel Energy and its financial and legal restructuring advisors, NRG Energy prepared a comprehensive financial restructuring plan. In November 2002, NRG Energy and Xcel Energy presented the plan 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. Negotiations have progressed substantially since the initial plan was presented in November. If an agreement to a consensual plan of reorganization is negotiated and NRG Energy is unable to effectuate the restructuring through an exchange offer or other non-bankruptcy mechanism, it is highly probable that such plan would be implemented through the commencement of a voluntary Chapter 11 bankruptcy proceeding. There can be no assurance that NRG Energy’s creditors, including, but not limited to the Ad Hoc Committees, will agree to the terms of the consensual plan of reorganization currently being negotiated. In addition, there can be no guarantee that lenders will not seek to enforce their remedies under the various loan agreements, provided that any such attempted enforcement would be subject to the automatic stay and other relevant provisions of the bankruptcy code. The commencement of a voluntary Chapter 11 bankruptcy proceeding without a consensual plan of reorganization would increase the possibility of a prolonged bankruptcy proceeding.

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 consider the settlement and/or 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 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.

The Eastern Region, comprising investments in the New York Independent System Operator (NYISO), New England Power Pool (NEPOOL) and Pennsylvania, New Jersey, Delaware and Maryland (PJM) markets, is NRG Energy’s largest asset base. As of December 31, 2002, NRG Energy owned approximately 7,040 MW of net generating capacity in the Northeast United States and Canada, primarily in New York, Connecticut and Massachusetts. These generation facilities are diversified in terms of dispatch level (base-load, intermediate and peaking), fuel type (coal, natural gas and oil) and customers.

NRG Energy’s Northeast facilities are generally competitively positioned within their respective market dispatch levels with favorable market dynamics and locations close to the major load centers in the NYISO and NEPOOL.

As of December 31, 2002, NRG Energy owned approximately 1,400 MW of net generating capacity in the Mid-Atlantic region of the United States, primarily Delaware, Maryland, Virginia and Pennsylvania. These facilities are primarily coal-type and are diversified in terms of dispatch. These facilities provide interconnect to the PJM market.

As of December 31, 2002, NRG Energy owned approximately 6400 MW of net generating capacity (including projects under construction) in the Central United States, primarily in Louisiana, Illinois, Mississippi, Missouri, Oklahoma and Texas. NRG Energy’s Central generating assets consist primarily of its net ownership of power generation facilities in New Roads, Louisiana (which are referred to as the Cajun facilities) and its net ownership of power generation facilities in Kendall and Rockford, Illinois. The Central region also includes the Sterlington, McClain, Bayou Cove, Batesville, Rocky Road, Audrain and Mustang generating facilities.

NRG Energy’s portfolio of plants in Louisiana and Mississippi comprise the second largest generator in the Southeastern Electric Reliability Counsel/ Entergy (SERC/ETR) region. The core of these assets are the Cajun facilities with capacity over 2000 MW of primarily coal-fired assets supported by long-term power purchase agreements with regional cooperatives.

As of December 31, 2002, NRG Energy owned approximately 1,230 MW of net generating capacity on the West Coast of the United States, primarily California and Nevada. NRG Energy’s West Coast generation assets consist primarily of a 50% interest in West Coast Power LLC (West Coast Power), and a 50% interest in the Saguaro generation facility.

In May 1999, Dynegy Power Corporation (Dynegy) and NRG Energy formed West Coast Power to serve as the holding company for a portfolio of operating companies that own generation assets in Southern California. This portfolio currently is comprised of the El Segundo Generating Station, the Long Beach Generating Station, the Encina Generating Station and 17 combustion turbines in the San Diego area. Dynegy provides power marketing and fuel procurement services to West Coast Power, and NRG Energy provides operations and management services. An application for a permit to repower the existing El Segundo site, replacing the retired unit 1 & 2 with 600 MW of new generation has been filed. The permit is in the CEC (California Energy Commission) review process, and it is anticipated that the approval will be received by third or forth quarter of 2003.

Historically, the majority of power generating capacity outside of the United States has been owned and controlled by governments. During the past decade, however, many foreign governments moved to privatize power generation plant ownership through sales to third parties and by encouraging new capacity development and refurbishment of existing assets by independent power developers.

Over the past decade NRG Energy invested in international power generation projects in three distinct markets, Asia Pacific, Europe and Other Americas. During 2002, NRG Energy sold international generation projects with an aggregate total generating capacity of approximately 600 MW. As of December 31, 2002, NRG Energy has investments in power generation projects located in Australia, UK, Germany, South America, India, Taiwan and the Czech Republic with approximately 4630 MW Total generating capacity. NRG Energy currently anticipates that it will divest its remaining international generating projects over time.

In addition to its traditional power generation facilities discussed above, NRG Energy provides alternative energy through NEO Corporation (NEO), one of the largest landfill gas generation companies in the United States, and through its NRG Resource Recovery business division, which processes municipal solid waste as fuel used to generate power.

NEO Corporation. NEO is a wholly owned subsidiary of NRG Energy that was formed to develop power generation facilities, ranging in size from 1 to 50 MW, in the United States. NEO owns and operates 31 landfill gas collection systems and has 46 MW of net ownership interests in related electric generation facilities utilizing landfill gas as fuel. NEO also has 42 MW of net ownership interests in 18 hydroelectric facilities and 109 MW of net ownership interests in five distributed generation facilities including 90 MW of gas-fired peaking engines in California (referred to as the Red Bluff and Chowchilla facilities).

Resource Recovery Facilities. NRG Energy’s Resource Recovery business is focused on owning and operating alternative fuel/“green power” generation and fuels processing projects. The alternative fuels currently processed and combusted are municipal solid waste (MSW), of which more than 90% is processed into refuse derived fuel (RDF), urban wood waste (pallets, clean construction debris, etc.), forest industry waste wood (bark, sawmill waste, tree trimmings, etc.), agricultural waste (walnut shells, olive pits, peanut shells, etc.), and non-recyclable waste paper and compost. NRG Energy’s Resource Recovery business has MSW processing capacity of over 4,000 tons per day and generation capacity of 35 MW, of which its net ownership interest is 26 MW. NRG Energy’s Resource Recovery business owns and operates MSW processing and/or generation facilities in Florida, Maine and Minnesota. Resource Recovery also owns and operates NRG Processing Solutions that includes thirteen composting and biomass fuel processing sites in Minnesota of which three sites are permitted to operate as MSW transfer stations.

NRG Energy has interests in district heating and cooling systems and steam transmission operations through its subsidiary NRG Thermal LLC. NRG Thermal’s thermal and chilled water businesses have a steam and chilled water capacity of approximately of 1,290 megawatt thermal equivalents (MWt).

NRG Thermal LLC owns five district heating and cooling systems in Minneapolis, Minnesota, San Francisco, California, Pittsburgh, Pennsylvania, Harrisburg, Pennsylvania and San Diego, California. These systems provide steam heating to approximately 600 customers and chilled water to 90 customers. In addition, NRG Thermal LLC owns and operates three projects that serve industrial/ government customers with high-pressure steam and hot water and an 88 MW combustion turbine peaking generation facility and an 18 MW coal-fired cogeneration facility in Dover, Delaware.

NRG Energy’s energy marketing subsidiary, NRG Power Marketing Inc. (NRG Power Marketing), began operations in 1998. 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.

During 2002, NRG Energy (and its subsidiaries) derived approximately 21.1% of its 2002 revenues from majority owned operations from one customer: New York Independent System Operator. During 2001, NRG Energy derived approximately 51.5% of its 2001 revenues from majority owned operations from two customers: New York Independent System Operator (33.9%) and Connecticut Light and Power Company (17.6%). During 2000, NRG Energy derived approximately 41.6% of its 2000 revenues from majority owned operations from two customers: New York Independent System Operator (26.8%) and Connecticut Light and Power Company (14.8%).

Annual and quarterly operating results can be significantly affected by weather and price volatility. Since NRG Energy’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, the precipitous decline in natural gas inventories and productive capacity and reduced hydroelectric capacity due to dry conditions in the Northwest, have all combined to increase fuel and power price volatility.

NRG Energy’s raw material requirements primarily include various forms of fossil fuel energy sources, including oil, natural gas and coal. NRG Energy 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 46% of NRG Energy’s cost of operations during the year ended December 31, 2002.

For financial information on NRG Energy’s operations on a geographical and on a segment basis, see Item 15 — Note 23 to the Consolidated Financial Statements.

Bulo Bulo — In June 2002, NRG Energy began negotiations to sell its 60% interest in Compania Electrica Central Bulo Bulo S.A. (Bulo Bulo), a Bolivian corporation. During the second quarter of 2002, NRG Energy classified the Bulo Bulo project as held-for-sale and recognized a loss on disposal of approximately $9.7 million in discontinued operations. The transaction closed in the fourth quarter of 2002.

Crockett Cogeneration Project — In November 2002, NRG Energy sold its 57.7% interest in the Crockett Cogeneration Project, a 240 MW natural gas fueled cogeneration plant near San Francisco, California, to Energy Investment Fund Group, an existing LP, and a unit of GE Capital. NRG Energy recognized a net loss on sale of $11.5 million (pre-tax) and net proceeds of $52.1 million which was used to reduce debt.

Csepel and Entrade — In September 2002, NRG Energy announced that it had reached agreements to sell its Csepel power generating facilities (located in Budapest, Hungary) and its interest in Entrade (an electricity trading business headquartered in Prague) to Atel, an independent energy group headquartered in Switzerland. The sales of Csepel and Entrade closed before year-end and resulted in cash proceeds of $92.6 million and a gain of approximately $24.0 million.

Brazos Valley — In January 2003, the project lenders foreclosed on NRG Energy’s 100% ownership interests in NRG Brazos Valley, GP LLC, NRG Brazos Valley LP, LLC NRG Brazos Valley Technology LP, LLC and NRG Brazos Valley Energy, LP, and thereby acquired all of the assets of the Brazos Valley project, a 633 MW gas-fired, combined cycle facility under construction in Fort Bend County, Texas — approximately 30 miles west of Houston, Texas. NRG Energy agreed to the consensual foreclosure of the companies to the project lenders. NRG Energy received no cash proceeds upon completion of the foreclosure. As of December 31, 2002, NRG Energy recorded $24.0 million for the potential obligation to infuse additional amounts of capital to fund a debt service reserve account and the potential obligation to satisfy a contingent equity agreement.

Killingholme — In January 2003, NRG Energy completed the sale of its interest in the Killingholme project to its lenders. This transfer of NRG Energy’s interest in the Killingholme project resulted in a gain on sale in the first quarter of 2003 of approximately $182.3 million, primarily due to the removal of the related debt on NRG Energy’s balance sheet. In 2002, NRG Energy recorded an asset impairment charge of $477.9 million related to the Killingholme project. Killingholme is reported as a discontinued operation in NRG Energy’s December 31, 2002 financial statements.

Hsin Yu — During 2002, NRG Energy committed to sell its ownership interest in Hsin Yu. As a result, Hsin Yu meets the criteria for discontinued operations treatment and accordingly the assets and liabilities and results of operations have been reflected as such in the accompanying financial statements. During the third quarter of 2002, NRG Energy recorded an impairment charge of approximately $121.9 million for the Hsin Yu project.

During 2002, NRG Energy sold various equity method investments and others have been approved for sale by the NRG Board of Directors but are still owned as of December 31, 2002. In the accompanying financial statements, the operating results of these projects are classified in revenue as equity in earnings from unconsolidated investments. During 2002, NRG Energy recorded write-downs and losses on disposal of $196.2 million of equity investments.

Energy Development Limited — In August 2002, NRG Energy completed the sale of its ownership interests in an Australian energy company, Energy Development Limited (EDL). NRG Energy received proceeds of $78.5 million (AUS), or approximately $43.9 million (U.S.), in the transaction.

Collinsville Power Station — In August 2002, NRG Energy completed the sale of its 50% interest in the 192 MW Collinsville Power Station in Australia to its partner, a subsidiary of Transfield Services Limited. NRG Energy’s proceeds from the sale amounted to $8.6 million (AUS), or approximately $4.8 million (USD).

Sabine River — In September 2002, NRG Energy agreed to transfer its indirect 50% interest in SRW Cogeneration LP (SRW) to its partner in SRW, Conoco, Inc. in consideration for Conoco’s agreement to terminate or assume all of the obligations of NRG Energy in relation to SRW. SRW owns a cogeneration facility in Orange County, Texas. NRG Energy recorded a charge of approximately $48.4 million during the quarter ended September 30, 2002 to writeoff the carrying value of its investment due to the pending transfer. The transfer closed on November 5, 2002.

Mt. Poso — In November 2002, NRG Energy completed the sale of its 39.5% indirect partnership interest in the Mt. Poso Cogeneration Company, a California limited partnership (Mt. Poso) for approximately $10 million to Red Hawk Energy, LLC. Mt. Poso owns a 49.5 MW coal-fired cogeneration power plant and thermally enhanced oil recovery facility located 20 miles north of Bakersfield, California. NRG Energy recorded a charge of approximately $1.0 million during 2002 to write down the carrying value of its investment.

NEO MESI LLC — On November 26, 2002, NRG Energy, through its indirect wholly-owned subsidiary, NEO MESI LLC, completed the transfer of its 50% interest in MESI Fuel Station No. 1, LLC (MESI) to Power Fuel Partners (PFP) in exchange for the assumption by PFP of all NEO MESI LLC’s obligations under the MESI operating agreement, estimated at the time of closing at $21.6 million, plus a percentage of certain future fuel sales management fees payable to PFP.

Kingston — In December, 2002, NRG Energy completed the sale of its 25% interest in Kingston Cogeneration LP, based near Toronto, Canada to Northland Power Income Fund for approximately $15 million, resulting in a gain on sale of approximately $9.9 million.

ECKG — In January 2003, NRG Energy completed the sale of its 44.5% interest in the ECKG power station, the last transaction in connection with NRG Energy’s sale of its Csepel power generating facilities, its interest in Entrade, an electricity trading business and ECKG, to Atel, an independent energy group headquartered in Switzerland. The transaction resulted in cash proceeds of $67.0 million and a net loss of $2.1 million.

The following investment projects are currently being marketed for sale however, final approval has not been granted by those having such authority as of December 31, 2002. In the accompanying financial statements, the operating results of these projects are classified in revenue as equity in earnings from unconsolidated investments. Write-downs of the carrying amount of the investments and losses on disposal have been classified and reported as a component of write-downs and losses of equity method investments.

Loy Yang — Based on a third party market valuation and bids received in response to marketing the investment for possible sale, NRG Energy recorded a write down of its investment of approximately $53.6 million in the third quarter of 2002. This write-down reflected management’s belief that the decline in fair value of the investment was other than temporary.

During the fourth quarter of 2002, NRG Energy and the other owners of the Loy Yang project engaged in joint marketing of the project for possible sale. In connection with these efforts, a new independent market valuation analysis was completed. Based on the new market valuation and negotiations with a potential purchaser, NRG Energy recorded an additional write-down of its investment in the amount of $57.8 million in the fourth quarter of 2002. At December 31, 2002 the carrying value of the investment in Loy Yang is approximately $72.9 million. Accumulated other comprehensive loss at December 31, 2002 includes foreign

currency translation losses of approximately $76.7 million related to Loy Yang. The foreign currency translation losses will continue to be included as a component of accumulated other comprehensive loss until NRG Energy commits to a plan to dispose of its investment, as required by EITF Issue No. 01-05. NRG Energy accounts for the results of operations of its investment in Loy Yang as part of its power generation segment within the Asia Pacific region.

Kondapalli — On January 30, 2003, NRG Energy signed a sale agreement with the Genting Group of Malaysia to sell NRG’s 30% interest in Lanco Kondapalli Power Pvt Ltd and a 74% interest in Eastern Generation Services (India) Pvt Ltd. Kondapalli is based in Hyderabad, Andhra Pradesh, India, and is the owner of a 368 MW natural gas fired Combined Cycle Gas Turbine. That sale has not yet been completed, although completion is expected before the end of the second quarter of 2003.

Powersmith — During the fourth quarter of 2002, NRG Energy wrote down its investment in Powersmith by approximately $3.4 million due to impairment of its book value. NRG Energy accounts for the results of operations of these investments as part of its power generation segment within the North America region.

Other — During 2002, NRG Energy wrote down other equity investments in the amount of approximately $11.3 million due to impairment of their book value. NRG Energy accounted for the results of operations of these investments as part of its alternative energy segment.

The Federal Energy Regulatory Commission, or 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 hydroelectric projects. FERC determines whether a public utility qualifies for exempt wholesale generator 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.

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 Energy is selling electricity in the wholesale market, NRG Energy is deemed to be a public utility for purposes of the Federal Power Act. In most cases, FERC has granted NRG Energy the authority to sell electricity at market-based rates. 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 Energy 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 Energy market-based rate authority reserve the right to revoke or revise NRG Energy’s market-based rate authority on a prospective basis if FERC subsequently determines that NRG Energy possesses excessive market power. If NRG Energy lost its market-based rate authority, NRG Energy 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

Public Utility Holding Company Act. 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 the Holding Company Act.

Registered holding companies under the Holding Company Act 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 the Holding Company Act 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 “exempt wholesale generator.” Accordingly, it is exempt from the Holding Company Act 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 Energy’s operating subsidiaries has been designated by FERC as an exempt wholesale generator or is otherwise exempt from PUHCA because it is a Qualifying Facility under the Public Utility Regulatory Policy Act of 1978.

NRG Energy does not expect to engage in any activities that will subject it to regulation under PUHCA. If NRG Energy were to lose its exempt wholesale generator status, it would become subject to regulation under the Holding Company Act. It would be difficult for NRG Energy to comply with the Holding Company Act absent a substantial restructuring.

NRG Energy is subject to a broad range of foreign, provincial, federal, state and local environmental and safety laws and regulations applicable to the development, ownership and operation of its United States domestic and international 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 Energy 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 Energy 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 Energy strives at all times to comply with the terms of all environmental and safety laws, regulations, permits and licenses and NRG Energy believes that all of its operating plants are in material compliance with applicable environmental and safety requirements. NRG Energy 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. There can be no assurance, 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 Energy’s plants, which requires regular major capital expenditures for power plant upgrades and modifications. Therefore, it is NRG Energy’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).

The entire independent power industry in the United States is in turmoil. Many of NRG Energy’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 Energy 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 Energy 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 Energy 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 Energy 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 Energy 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 Energy views this change as a significant improvement to the existing market design, NRG Energy still views the market within New England as insufficient to allow for NRG Energy to recover its costs and earn a reasonable return on investment. Consequently, on February 26, 2003, NRG Energy filed and requested a cost of service rate with FERC for most of its Connecticut fleet, requesting a February 27th effective date. NRG Energy remains 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 NRG Energy has the right to file for such rate treatment, there are no assurances that FERC will grant such rates in the form or amount that NRG Energy petitioned for in its filing.

On March 25, 2003, the Federal Energy Regulatory Commission (FERC) issued an order (the Order) in response to Devon Power LLC’s, Middletown Power LLC’s, Montville Power LLC’s, and Norwalk Power LLC’s (collectively, NRG Subsidiaries) 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 Subsidiaries requested that FERC accept the NRG Subsidiaries’ reliability must-run agreements and assure the NRG Subsidiaries’ recovery of maintenance costs for their New England generating facilities prior to the peak summer season. FERC accepted the NRG Subsidiaries’ 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 Subsidiaries 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.

In New York, NRG Energy anticipates that the NYISO will implement a demand curve in its capacity market. 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 Energy.

In the Midwest, it is anticipated that Exelon and AEP will join PJM and will transition to PJM’s market model, although there have been certain regulatory obstacles affecting AEP’s ability to join PJM. This will allow NRG Energy to market capacity and energy from its Chicago area assets more effectively. The other Midwest ISO, MISO, continues its market rule development as it moves toward a PJM styled market. MISO and PJM have signed a Memorandum of Understanding that lays out a common market design that both will employ. It is anticipated that PJM and MISO will operate a common market interface that will allow seamless trading between the two regions. MISO presently has operational control over the transmission facilities located within its footprint.

In the Southeast, Entergy and Southern Company continue to support their RTO, Setrans. The future of Setrans is uncertain given the recent loss of the local municipal Santee Cooper.

Finally, in California, the California Independent System Operator (CA ISO) continues to struggle with market design changes intended to prevent a repeat of past market dis-function. It is unlikely that modification initially coined as Market Design 2002 (MDO2), will be implemented any sooner than 2004. Although numerous stakeholder meetings have been held, the final MDO2 design remains unknown at this time. In addition, numerous legislative initiatives in California create uncertainty and risk for NRG Energy. Most significantly, SB39XX mandates that the California Public Utilities Commission (CPUC) exercise jurisdiction over the maintenance of power producers. It is unclear at this time where that process will lead.

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 limitations 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 limitations. These types of price limitations 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 limitations by independent system operators.

At December 31, 2002, NRG Energy had 3,173 employees, approximately 329 of whom are employed directly by NRG Energy and approximately 2,844 of whom are employed by its wholly owned subsidiaries and affiliates. Approximately 1,757 employees are covered by bargaining agreements. NRG Energy has experienced no significant labor stoppages or labor disputes at its facilities.

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 Energy believes that the expectations expressed in such forward-looking statements are reasonable, NRG Energy 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 Energy or one or more of its subsidiaries, the entry of an order for relief by the Minnesota Bankruptcy Court in respect of the pending involuntary Chapter 11 petition in that court, or the filing of an involuntary bankruptcy petition in another court by a requisite number of creditors of NRG Energy or a 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 timetable assumed;

	•	Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where NRG Energy has a financial interest;

	•	General economic conditions including inflation rates and monetary or currency exchange rate fluctuations;

	•	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;

	•	Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services;

	•	Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

	•	Factors affecting power generation operations such as unusual weather conditions; catastrophic weather-related or other damage to facilities; 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 the hiring and retention 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;

	•	Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

	•	Factors associated with various investments including conditions of final legal closing, partnership actions, competition, operating risks, dependence on certain suppliers and customers and domestic and foreign environmental and energy regulations;

	•	Limitations on NRG Energy’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 Energy’s control;

	•	Failure to timely satisfy the closing conditions contained in the definitive agreements for the sale of projects subject to definitive agreements but not yet closed, many of which are beyond NRG Energy’s control;

	•	Factors challenging the successful integration of projects not previously owned or operated by NRG Energy, including the ability to obtain operating synergies;

	•	Factors associated with operating in foreign countries including: delays in permitting and licensing, construction delays and interruption of business, political instability, taxing regimes, risk of war, expropriation, nationalization, renegotiation, or nullification of existing contracts, changes in law, and the ability to convert foreign currency into United States dollars;

	•	Changes in government regulation or the implementation of new government regulations, including pending changes within or outside of California as a result of the California energy crisis, or the outcome of litigation pending in California and other western states, which could adversely affect the continued deregulation of the electric industry;

	•	Changes in market design or implementation of rules that affect NRG Energy’s ability to transmit or sell power in any market, including, without limitation, the failure of FERC to grant NRG Energy 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.

	•	Other business or investment considerations that may be disclosed from time to time in NRG Energy’s Securities and Exchange Commission filings or in other publicly disseminated written documents, including NRG Energy’s Registration Statement No. 333-62958, as amended, and all supplements therein.

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

Listed below are descriptions of NRG Energy’s interests in facilities, operations and/or projects owned as of December 31, 2002.

Thermal Energy Production and Transmission Facilities and Resource Recovery Facilities


(1)	Thermal production and transmission capacity is based on 1,000 Btus per pound of steam production or transmission capacity. The unit mmBtu is equal to one million Btus.

(2)	Kladno also is included in the Independent Power Production and Cogeneration Facilities table on the preceding page, under the name ECK Generating.

(3)	Held for sale. See “Significant Business and Asset Dispositions” under Item 1.

In addition to the above, NRG Energy leases its corporate offices at 901 Marquette, Suite 2300, Minneapolis, Minnesota 55402 and various other office spaces. NRG Energy also owns interests in other construction projects in various states of completion, the development of which has been terminated due to NRG Energy’s liquidity situation, as well as other properties not used for operational purposes.

Through March 2003, NRG Energy was involved in the following material legal proceedings. NRG Energy is vigorously defending itself in each of these matters.

People of the State of California ex. rel. Bill Lockyer, Attorney General, v. Dynegy, Inc. et al., United States District Court, Northern District of California, Case No. C-02-O1854 VRW; United States Court of Appeals for the Ninth Circuit, Case No. 02-16619.

This action was filed in state court on March 11, 2002. It alleges that the defendants violated California Business & Professions Code § 17200 by selling ancillary services to the California ISO, and subsequently selling the same capacity into the spot market. The Attorney General seeks injunctive relief as well as restitution, disgorgement and civil penalties.

On April 17, 2002, the defendants removed the case to the United States District Court in San Francisco. Thereafter, the case was transferred to Judge Vaughn Walker, who is also presiding over various other “ancillary services” cases brought by the California Attorney General against other participants in the California market, as well as other lawsuits brought by the Attorney General against these other market participants. NRG Energy has tolling agreements in place with the Attorney General with respect to such other proposed claims against it.

The Attorney General filed motions to remand, which the defendants opposed in July of 2002. In an Order filed in early September 2002, Judge Walker denied the remand motions. The Attorney General has appealed that decision to the United States Court of Appeal for the Ninth Circuit, and the appeal remains pending. The Attorney General also sought a stay of proceedings in the district court pending the appeal, and this request was also denied. A “Notice of Bankruptcy Filing” respecting NRG Energy was filed in the Ninth Circuit and in the District Court in mid-December 2002. The Attorney General filed a paper asserting that the “police power” exception to the automatic stay is applicable here. Judge Walker agreed with the Attorney General on this issue. In a lengthy opinion filed March 25, 2003, Judge Walker dismissed the Attorney General’s action against NRG and Dynegy with prejudice, finding it was barred by the filed rate doctrine and preempted by federal law. The Attorney General has announced it will appeal the dismissal. NRG Energy is unable at this time to accurately estimate the damages sought by the Attorney General against NRG Energy and its affiliates, or predict the outcome of the case.

A “Notice of Bankruptcy Filing” respecting NRG Energy was filed in the Ninth Circuit and in the District Court in mid-December, 2002. The Attorney General filed a paper asserting that the “police power” exception to the automatic stay is applicable here.

Public Utility District of Snohomish County v. Dynegy Power Marketing, Inc et al., Case No. 02-CV-1993 RHW, United States District Court, Southern District of California (part of MDL 1405).

This action was filed against Dynegy, NRG Energy, Xcel Energy and several other market participants in the United States District Court in Los Angeles on July 15, 2002. The Complaint alleges violations of the California Business & Professions Code § 16720 (the Cartwright Act) and Business & Professions Code § 17200. The basic claims are price fixing and restriction of supply, and other market “gaming” activities.

The action was transferred from Los Angeles to the United States District Court in San Diego and was made a part of the Multi-District Litigation proceeding described below. All defendants filed motions to dismiss and to strike in the fall of 2002. In an Order dated January 6, 2003, the Honorable Robert Whaley, a federal judge from Spokane sitting in the United States District Court in San Diego, pursuant to the Order of the MDL Panel, granted the motions to dismiss on the grounds of federal preemption and filed-rate doctrine. The plaintiffs have filed a notice of appeal.

In re: Wholesale Electricity Antitrust Litigation, MDL 1405, United States District Court, Southern District of California, pending before Honorable Robert H. Whaley. The cases included in this proceeding are as follows:


	1. Pamela R Gordon, on Behalf of Herself and All Others Similarly Situated v Reliant Energy, Inc. et al., Case No. 758487, Superior Court of the State of California, County of San Diego (filed on November 27, 2000).


	2. Ruth Hendricks, On Behalf of Herself and All Others Similarly Situated and On Behalf of the General Public v. Dynegy Power Marketing, Inc. et al., Case No. 758565, Superior Court of the State of California, County of San Diego (filed November 29,2000).

	3. The People of the State of California, by and through San Francisco City Attorney Louise H. Renne v. Dynegy Power Marketing, Inc. et al., Case No. 318189, Superior Court of California, San Francisco County (filed January 18, 2001).

	4. Pier 23 Restaurant, A California Partnership, On Behalf of Itself and All Others Similarly Situated v. PG&E Energy Trading et al., Case No. 318343, Superior Court of California, San Francisco County (filed January 24,2001).

	5. Sweetwater Authority, et al. v. Dynegy Inc. et al., Case No. 760743, Superior Court of California, San Diego County (filed January 16, 2001).

	6. Cruz M Bustamante, individually, and Barbara Matthews, individually, and on behalf of the general public and as a representative taxpayer suit, v. Dynegy Inc. et al., inclusive. Case No. BC249705, Superior Court of California, Los Angeles County (filed May 2, 2001).

These cases were all filed in late 2000 and 2001 in various state courts throughout California. They allege unfair competition, market manipulation, and price fixing. All the cases were removed to the appropriate United States District Courts, and were thereafter made the subject of a petition to the Multi-District Litigation Panel (Case No. MDL 1405). The cases were ultimately assigned to Judge Whaley. Judge Whaley entered an order in 2001 remanding the cases to state court, and thereafter the cases were coordinated pursuant to state court coordination proceedings before a single judge in San Diego Superior Court. The defendants filed motions to dismiss and to strike under the filed-rate and federal preemption theories, and the plaintiffs challenged the district court’s jurisdiction and sought to have the cases remanded to state court. In December 2002, Judge Whaley issued an opinion finding that federal jurisdiction was absent in the district court, and remanding the cases to state court. Duke and Reliant have filed a notice of appeal with the Ninth Circuit, and also sought a stay of the remand pending appeal. The stay request was denied by Judge Whaley. On February 20, 2003, however, the Ninth Circuit stayed the remand order and accepted jurisdiction to hear the appeal of Reliant and Duke on the remand order. The Company anticipates that filed-rate/federal preemption pleading challenges will once again be filed once the remand appeal is decided. A “Notice of Bankruptcy Filing” respecting NRG Energy has also been filed in this action, providing notice of the involuntary petition.

“Northern California” cases against various market participants, not including NRG Energy (part of MDL 1405). These include the Millar, Pastorino, RDJ Farms, Century Theatres, EI Super Burrito, Leo’s, J&M Karsant, and the Bronco Don cases. NRG Energy, Inc. was not named in any of these cases, but in virtually all of them, either West Coast Power or one or more of the operating LLC’s with which the Company is indirectly affiliated is named as a defendant. These cases all allege violation of Business & Professions Code § 17200, and are similar to the various allegations made by the Attorney General. Dynegy is named as a defendant in all these actions, and Dynegy’s outside counsel is representing both Dynegy and the West Coast Power entities in each of these cases.

“Pacific Northwest” cases: Symonds v. Dynegy Power Marketing et al., United States District Court, Western District of Washington, Case No. CV02-2552; Lodewick v. Dynegy Power Marketing et al., Oregon Circuit Court Case No. 0212-12771. These cases were just recently asserted and contain similar claims to those found in the California cases described above. There has been little activity in either case.

Bustamante v. McGraw-Hill Companies Inc., et al., No. BC 285598, California Superior Court, Los Angeles County

each of its four plants: El Segundo Power, LLC; Long Beach Generation, LLC; Cabrillo Power I LLC; and Cabrillo Power II LLC. NRG Energy is not named as a defendant. The complaint seeks restitution and disgorgement of “ill-gotten gains,” civil fines, compensatory and punitive damages, attorneys’ fees, and declaratory and injunctive relief.

Dynegy has agreed with NRG Energy that it will indemnify and hold harmless the named defendants in the Bustamante lawsuit, as well as NRG Energy, from any civil fines, compensatory damages, punitive damages, costs, and fees that may be entered pursuant to either a final judgment or a settlement of claims. Dynegy has also agreed that it will pay all costs and attorneys’ fees associated with the defense of the named defendants in the Bustamante lawsuit, as well as any defense costs for NRG Energy.

The Federal Energy Regulatory Commission has an ongoing “Investigation of Potential Manipulation of Electric and Natural Gas Prices,” which involves hundreds of parties and substantial discovery. In June, 2001, FERC initiated proceedings related to California’s demand for $8.9 billion in refunds from power sellers who allegedly inflated wholesale prices during the energy crisis. Hearings have been conducted before an administrative law judge who issued an opinion in late 2002. The administrative law judge stated that after assessing a refund of $1.8 billion for “unjust and unreasonable” power prices between October 2, 2000 and June 20, 2001, power suppliers were owed $1.2 billion because the State was holding funds owed to suppliers.

In August, 2002, the 9th U.S. Circuit Court of Appeals granted a request by the Electricity Oversight Board, the California Public Utilities Commission, and others, to seek out and introduce to FERC additional evidence of market manipulation by wholesale sellers. This decision resulted in FERC ordering an additional 100 days of discovery in the refund proceeding, and also allowing the relevant time period for potential refund liability to extend back an additional nine months, to January 1, 2000.

On December 12, 2002, FERC Administrative Law Judge Birchman issued a Certification of Proposed Findings on California Refund Liability in Docket No. EL00-95-045 et al., which determined the method for the mitigated energy market clearing price during each hour of the refund period. On March 26, 2003, FERC issued an Order on Proposed Findings on Refund Liability in Docket No. EL00-95-045 (Refund Order), adopting, in part, and modifying, in part, the Proposed Findings issued by Judge Birchman on December 12, 2002. In the Refund Order, FERC adopted the refund methodology in the Staff Final Report on Price Manipulation in Western Markets issued contemporaneously with the Refund Order in Docket No. PA02-2-000. This refund calculation methodology makes certain changes to Judge Birchman’s methodology, because of FERC Staff’s findings of manipulation in gas index prices. This could materially increase the estimated refund liability. The Refund Order also directs generators that want to recover any fuel costs above the mitigated market clearing price during the refund period to submit cost information justifying such recovery within forty (40) days of the issuance of the Refund Order. FERC announced in the Refund Order that it expects that refunds will be paid by suppliers by the end of summer 2003.

In addition to the litigation it has undertaken described above, the California Attorney General has undertaken an investigation entitled In the Matter of the Investigation of Possibly Unlawful, Unfair, or Anti-Competitive Behavior Affecting Electricity Prices in California. In this connection, the Attorney General has issued subpoenas to Dynegy, served interrogatories on Dynegy and NRG Energy, and informally requested documents and interviews from Dynegy and Dynegy employees as well as NRG Energy and NRG Energy employees. NRG Energy responded to the interrogatories last summer, with the final set of responses being served on September 3, 2002. NRG Energy has also produced a large volume of documentation relating to the West Coast Power plants. In addition, three NRG Energy employees in California have sat for informal interviews with representatives of the Attorney General’s office. Dynegy employees have also been inter-

Although any evaluation of the likelihood of an unfavorable outcome or an estimate of the amount or range of potential loss in the above-referenced private actions and various investigations cannot be made at this time, NRG Energy notes that the Gordon complaint alleges that the defendants, collectively, overcharged California ratepayers during 2000 by $4.0 billion. NRG Energy knows of no evidence implicating NRG Energy in plaintiffs’ allegations of collusion. NRG Energy cannot predict the outcome of these cases and investigations at this time.

On November 22, 2002, a petition commencing an involuntary bankruptcy proceeding pursuant to Chapter 11 of the Bankruptcy Code was filed by five of NRG Energy’s former officers, Brian Bird, Leonard Bluhm, Craig Mataczynski, John Noer and David Peterson in the United States Bankruptcy Court for the District of Minnesota. Roy Hewitt and James Bender subsequently joined in the petition. NRG Energy has subsequently filed an answer and a motion to dismiss the Involuntary Case. The court will consider the motion to dismiss. In their petition filed with the Minnesota Bankruptcy Court, the petitioners sought recovery of severance and other benefits in an aggregate amount of $27.7 million.

Since the commencement of the Minnesota involuntary case, NRG Energy and its counsel have been involved in extensive negotiations with the petitioners and their counsel. As a result of these negotiations, NRG Energy and the petitioners reached an agreement and compromise regarding their respective claims against each other. On February 17, 2003, the Settlement Agreement was executed by the Petitioners and NRG Energy, pursuant to which NRG Energy agreed to pay the Petitioners an aggregate settlement in the amount of $12.2 million.

On February 28, 2003, Stone & Webster, Inc. and Shaw Constructors, Inc. filed a Joinder in Involuntary Petition alleging that they hold unsecured, non-contingent claims against NRG Energy, in a joint amount of $100 million. On March 20, 2003, Connecticut Light & Power Company filed an opposition to the NRG Energy motion to dismiss the Involuntary Case.

The Minnesota Bankruptcy Court has discretion in reviewing and ruling on the motion to dismiss and the review and approval of the settlement agreement. There is a risk that the Minnesota Bankruptcy Court may, among other things, reject the settlement agreement or enter an order for relief under Chapter 11 of the Bankruptcy Code, thus commencing a Chapter 11 case for NRG Energy.

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

On July 12, 1999, Fortistar Capital Inc. sued NRG Energy in Minnesota state court. The complaint sought injunctive relief and damages of over $50 million resulting from NRG Energy’s alleged breach of a letter agreement with Fortistar relating to the Oswego power plant. 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.

Racketeer Influenced and Corrupt Organizations Act (“RICO”) and committed fraud by engaging in a pattern of negotiating and executing agreements “they intended not to comply with” and “made false statements later to conceal their fraudulent promises.” The plaintiffs allege damages of some $350 million and also assert entitlement to a trebling of these damages under the provisions of the RICO Act. The present and former NRG Energy and NEO officers and employees have requested indemnity from NRG Energy, which requests NRG Energy is now examining. NRG Energy cannot at this time estimate the likelihood of an unfavorable outcome to the defendants in this lawsuit.

NEO Corporation, a Minnesota corporation on behalf of Itself and on behalf of Minnesota Methane, LLC, a Delaware limited liability company v. Fortistar Methane, LLC, a Delaware limited liability company, Hennepin County District Court

NEO Corporation, a wholly owned subsidiary of NRG Energy, brought this lawsuit in January of 2001. NEO has asserted claims for breach of contract, breach of the covenant of good faith and fair dealing, fraudulent misrepresentations and omissions, defamation, business disparagement and derivative claims. Fortistar Methane, LLC denied NEO’s claims and counterclaimed alleging breach of contract, fraud, negligent misrepresentation and breach of warranty. NEO has denied Fortistar Methane’s claims and intends to pursue its claims. Discovery has not been conducted. The parties entered into a conditional, confidential settlement of this matter and the Fortistar Capital action, described above. The agreement, however, was subject to necessary board and lender approvals. NEO was unable to obtain necessary approvals. Fortistar Methane has moved to enforce the settlement, seeking damages against NRG Energy in excess of $35 million plus interest and attorneys’ fees. NRG Energy and NEO are opposing Fortistar’s motion on the grounds that conditions to contract performance were not met. No decision has been rendered on the pending motion. NRG Energy cannot predict the likelihood of an unfavorable outcome.

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.

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. The motion is still pending before the judge and there has been no further action taken in connection with the case. On March 27, 2003 the court dismissed the complaint against NRG Energy without prejudice. 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.

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

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

Pointe Coupee Parish Police Jury and Louisiana Generating, LLC v. United States Environmental Protection Agency and Christine Todd Whitman, Administrator, Adversary Proceeding No. 02-61021 on the docket of the United States Court of Appeals for the Fifth Circuit

including Pointe Coupee Parish. The plaintiffs’ challenge is based on DEQ’s failure to comply with Administrative Procedures Act requirements related to rulemaking and EPA’s regulations which prohibit EPA from approving a SIP not prepared in accordance with state law. The court granted a sixty (60) day stay of this proceeding on February 25, 2003 to allow the parties to conduct settlement discussions. At this time, NRG Energy is unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which the Company may be subject.

In the Matter of Louisiana Generating, LLC, Adversary Proceeding No. 2002-1095 1-EQ on the docket of the Louisiana Division of Administrative Law

During 2000, DEQ issued a Part 70 Air Permit modification to Louisiana Generating to construct and operate two 240 MW natural gas-fired turbines. The Part 70 Air Permit set emissions limits for the criteria air pollutants, including NO_x, based on the application of Best Available Control Technology (“BACT”). The BACT limitation for NO_x was based on the guarantees of the manufacturer, Siemens-Westinghouse. Louisiana Generating sought an interim emissions limit to allow Siemens-Westinghouse time to install additional control equipment. To establish the interim limit, DEQ issued a Compliance Order and Notice of Potential Penalty, No. AE-CN-02-0022, on September 8, 2002, which is, in part, subject to the referenced administrative hearing. DEQ alleged that Louisiana Generating did not meet its NO_x emissions limit on certain days, did not conduct all opacity monitoring and did not complete all record keeping and certification requirements. Louisiana Generating intends to vigorously defend certain claims and any future penalty assessment, while also seeking an amendment of its limit for NO_x. An initial status conference has been held with the Administrative Law Judge and quarterly reports will be submitted to describe progress, including settlement and amendment of the limit. In addition, NRG Energy may assert breach of warranty claims against the manufacturer. With respect to the administrative action described above, at this time NRG Energy is unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which the Company may be subject.

During 2002, NRG Sterlington conducted a review of the Sterlington Power Facility’s Part 70 Air Permit obtained by the facility’s former owner and operator, Koch Power, Inc. Koch had outlined a plan to install eight 25 megawatt (MW) turbines to reach a 200 MW limit in the permit. Due to the inability of several units to reach their nameplate capacity, Koch determined that it would need additional units to reach the electric output target. In August 2000, NRG Sterlington acquired the remaining interests in the facility not originally held on a passive basis and sought the transfer of the Part 70 Air Permit along with a modification to incorporate two 17.5 MW turbines installed by Koch and to increase the total number of turbines to ten. The permit modification was issued February 13, 2002. During further review, NRG Sterlington determined that a ninth unit had been installed prior to issuance of the permit modification. In keeping with its environmental policy, it disclosed this matter to DEQ during April, 2002. Additional information was provided during July 2002. As DEQ has not acted to date to institute an enforcement proceeding, NRG Energy suspects that it may not. However, as it is not time barred from doing so, NRG Energy is unable at this time to predict the eventual outcome or potential loss contingencies, if any, to which the Company may be subject.

On February 24, 2003, FERC initiated an investigation into whether Saguaro Power Company satisfied or currently satisfies the statutory and regulatory requirements for a qualifying facility under the Public Utility Regulatory Policies Act of 1978 (“PURPA”). PURPA provides special benefits for qualifying facilities regarding their rights to sell the electrical output of generation projects to electric utilities and exempts qualifying facilities from certain state and federal regulation. NRG Energy’s wholly-owned subsidiary, Eastern Sierra Power Company, owns a 49% general partnership interest and a 1% limited partnership interest in Saguaro. The FERC Order initiating the investigation notes that certain financing arrangements between Enron North America and Boulder Power LLC, an indirect owner of a 14% general partnership interest and a 1% limited partnership interest in Saguaro, may have caused Saguaro not to meet the limitations on electric

utility ownership applicable to qualifying facilities under PURPA and FERC regulations. At this time, NRG Energy is unable to predict the likelihood of an unfavorable outcome of this matter or the remedies that the FERC would impose in the event it found that Sagauro did not or does not satisfy the requirements for a qualifying facility.

Stone & Webster, Inc. and Shaw Constructors, Inc. v. NRG Energy, Inc. et al.

On October 17, 2002, Stone & Webster, Inc. and Shaw Constructors, Inc. filed a lawsuit against NRG Energy, Xcel Energy, Inc., NRG Granite Acquisition LLC, Granite Power Partners II LP and two of Xcel Energy’s executives relating to the construction of a power plant in Pike County, Mississippi. Plaintiffs generally allege that they were not paid for work performed to construct the power plant, and have sued the parent entities of the company with which they contracted to build the plant in order to recover amounts allegedly owing. Plaintiffs assert claims for breach of fiduciary duty, piercing the corporate veil, breach of contract, tortious interference with contract, enforcement of the NRG Energy guaranty, detrimental reliance, negligent or intentional misrepresentation, conspiracy, and aiding and abetting. On December 23, 2002, NRG Energy moved to dismiss the complaint in its entirety for failure to state a claim upon which relief can be granted. NRG Energy is currently awaiting plaintiffs’ response to the motion. No trial date has yet been set in this matter and NRG Energy cannot presently predict the outcome of the dispute.

On October 17, 2002, a petition commencing an involuntary bankruptcy proceeding pursuant to Chapter 7 of the Bankruptcy Code was filed against LSP-Pike Energy, LLC, a subsidiary of NRG Energy, by Stone & Webster, Inc. and Shaw Constructors, Inc. — the joining petitioners in the Minnesota involuntary case described above — in the United States Bankruptcy Court for the Southern District of Mississippi. In their petition filed with the Mississippi Bankruptcy Court, the joining petitioners sought recovery of allegedly unpaid contractual construction-related obligations in an aggregate amount of $73,833,328, which amount LSP-Pike Energy, LLC has disputed. LSP-Pike Energy, LLC filed an answer to the petition in the Mississippi involuntary case and served various interrogatory and deposition discovery requests on the joining petitioners. The Mississippi Bankruptcy Court has not entered any order for relief in the Mississippi involuntary case.

On November 29, 2001, The Cleveland Electric Illuminating Company, The Toledo Edison Company and FirstEnergy Ventures (“Sellers”) entered into Purchase and Sale Agreements with NRG Able Acquisition LLC, which were guaranteed by NRG (collectively, “Purchasers”), for the purchase of certain power plants for approximately $1.5 billion. On August 8, 2002, Sellers terminated the agreements and asserted that Purchasers were liable for anticipatory breach of the Purchase and Sale Agreements on the grounds that they could not finance the purchases. On August 8, 2002, Purchasers provided notice that they disagreed with Sellers’ assertion. After Sellers filed a motion seeking a waiver of the automatic stay of Section 362(a) of the Bankruptcy Code, on February 21, 2003, Sellers, NRG Energy, and NRG Northern Ohio Generating LLC, f/k/a/ NRG Able, stipulated to the United States Bankruptcy Court, District of Minnesota, that they would agree to a waiver of the automatic stay, thereby allowing Sellers to commence arbitration against Purchasers regarding their dispute. The collection of any award, however, would remain fully subject to NRG Energy’s automatic stay. The Bankruptcy Court approved the stipulation. On February 26, 2002, Sellers provided notice of their intent to commence arbitration proceedings against Purchasers. Sellers have yet to quantify their damage claim, though Sellers have stated publicly that they will seek to recover several hundred million dollars. NRG Energy cannot presently predict the outcome of this dispute.

NRG Energy’s indirectly controlled Brazilian project company, Itiquira Energetica S.A., the owner of a 156MW hydro project in Brazil, is currently in arbitration with the former EPC contractor for the project, Inepar Industria e Construcoes (Inepar). The dispute was commenced by Itiquira in September, 2002 and pertains to certain matters arising under the former EPC contract. Itiquira principally asserts that Inepar breached the contract and caused damages to Itiquira by (i) failing to meet milestones for substantial completion; (ii) failing to provide adequate resources to meet such milestones; (iii) failing to pay subcontractors amounts due; and (iv) being insolvent. Itiquira’s arbitration claim is for approximately US$40 million. Inepar has asserted in the arbitration that Itiquira breached the contact and caused damages to Inepar by failing to recognize events of force majeure as grounds for excused delay and extensions of scope of services and material under the contract. Inepar’s damage claim is for approximately US$10 million. On November 12, 2002, Inepar submitted its affirmative statement of claim, and Itiquira submitted its response and statement of counterclaims on December 14, 2002. Inepar replied to Itiquira’s response and counterclaims on January 14, 2003. Itiquira is to submit its reply to Inepar’s January 14 filing on March 14, 2003, and a hearing was held on March 21, 2003. NRG Energy cannot at this time estimate the likelihood of an unfavorable outcome in this dispute.

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.

During the period May 31, 2000 through June 3, 2002, NRG Energy’s common stock was traded principally on the New York Stock Exchange (the Exchange). The common stock was first traded on the Exchange on May 31, 2000, concurrent with the underwritten initial public offering of shares of NRG Energy’s common stock at an initial price to the public of $15.00 per share. In June 2002 following the exchange of all publicly held shares for Xcel Energy stock, trading of NRG Energy common stock was terminated. There is no longer an established public trading market for NRG Energy’s common equity.

All shares of NRG Energy common stock and Class A common stock are owned by Xcel Energy Wholesale Group Inc.

NRG Energy has not paid and does not currently intend to distribute any earnings as dividends.

The following table presents selected financial data of NRG Energy. The data included in the following table has been restated to reflect the assets, liabilities and results of operations of certain projects that have met the criteria for treatment of discontinued operation. For additional information refer to Item 15 — Note 5 of the accompanying financial statements. 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.

Due to the factors discussed below, as well as other matters discussed herein, NRG Energy’s financial condition has deteriorated significantly in the recent past. See “Liquidity” below. As a result, NRG Energy does not contemplate that it will have sufficient funds to make required principal and interest payments on its corporate debt, which means that NRG Energy will remain in default of the various corporate level debt obligations discussed more fully herein. In the absence of a consensual out of court restructuring or a Chapter 11 reorganization, it is highly likely that NRG Energy will be required to commence chapter 11 bankruptcy cases 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. Utilities were 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 market rules. 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.

During the year ended December 31, 2002, NRG Energy recognized a net loss of $3,464.3 million. This loss represented a decrease in earnings of $3,729.5 million compared to net income of $265.2 million for the same period in 2001. NRG Energy’s loss from continuing operations was $2,907.7 million for the year ended December 31, 2002 compared to net income of $218.2 million from continuing operations for the same period

During 2002, NRG Energy’s continuing operations experienced less favorable results than those experienced during the same period 2001. Overall, NRG Energy’s domestic power generation operations were less favorable than compared to the same period in 2001. NRG Energy’s domestic operations experienced reductions in domestic energy and capacity sales and an overall decrease in power pool prices and related spark spreads (the monetary difference between the price of power and fuel cost). During the fourth quarter of 2002, an additional reserve for uncollectible receivables in California was established by West Coast Power, which reduced NRG Energy’s equity earnings by approximately $58.5 million on a pre-tax basis. In addition, West Coast Power’s results were already less than those recorded in 2001 due to less favorable contracts and reductions in sales of energy and capacity. In addition, increased administrative costs, depreciation and interest expense from completed construction costs also contributed to the less than favorable results in 2002. Partially off setting these earnings reductions was the recognition, in the fourth quarter of 2002, of approximately $51 million of additional revenues related to the contractual termination of a power purchase agreement with NRG Energy’s Indian River project.

During the third quarter of 2002, NRG Energy experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. These events led to impairments on a number of NRG Energy assets, resulting in pre-tax charges related to continuing operations of approximately $2,544.8 million during 2002. In addition, approximately $196.2 million of net losses on sales and write-downs of equity method investments were recorded in 2002. Operating results of majority owned projects that were sold or have met the criteria to be considered as held-for-sale have been classified as discontinued operations.

As of December 31, 2002, NRG Energy’s Killingholme project and Hsin Yu project were classified as held for sale. The sales of Bulo Bulo, Csepel, Entrade and Crockett had been completed. In addition, the sale of NRG Energy’s investments in Mt. Poso, Collinsville, EDL, Sabine River Works, Kingston and NEO MESI had also taken place. The sale of NRG Energy’s investment in ECKG was pending at the end of 2002, and was completed in January 2003, along with the transfer of NRG Energy’s ownership interest in the Killingholme and the transfer of the ownership interest in the Brazos Valley project to its lenders.

During 2002, NRG Energy expensed approximately $111.3 million in 2002 for costs related to its financial restructuring. These costs include expenses for financial and legal advisors, contract termination costs, employee separation and other restructuring activities.

During 2002, total operating revenues and equity earnings from continuing operations were $2,281.1 million compared to $2,411.5 million in the prior year, a decrease of $130.4 million, or 5.4%. The primary reason for this decrease was a reduction in Equity earnings from unconsolidated affiliates of $141.0 million. The $141.0 million decrease in equity earnings from unconsolidated affiliates is due primarily to lower results at West Coast Power in 2002 as compared to the same period in 2001. During 2002, West Coast Power had long-term contracts that were less favorable than those held in 2001. In addition during 2002, West Coast Power also established reserves for certain receivables not considered recoverable. NRG Energy’s share of this reserve was approximately $58.5 million on a pre-tax basis.

NRG Energy’s operating revenues from majority-owned operations were $2,212.2 million in 2002 compared to $2,201.4 million in the prior year, an increase of $10.8 million or approximately 0.5%. Revenues from majority-owned operations for the year ended December 31, 2002, consisted primarily of power generation revenues from domestic operations of approximately $1,650.9 million in 2002 compared with $1,679.6 million in 2001, a decrease of $28.7 million. This decrease in domestic generation revenue is due to reductions in energy and capacity sales and an overall decrease in power pool prices.

Within the North American Segment, NRG Energy’s Eastern region revenues decreased by approximately 20.9%. The Eastern region revenues were significantly affected by a combination of lower capacity revenues and a 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 which reduced price volatility, particularly in New York City. The Central region generated increased revenues of 39.9% primarily due to a full year of operations compared to plants acquired and completed in 2001.

NRG Energy’s International revenues from majority owned operations increased by $22.4 million or 7.1% from 2001 to 2002. The Asia Pacific region reported a reduction in revenues of $42.4 million while increases were reported from Europe of $34.9 million and Other Americas of $29.9 million. The reduction in Asia Pacific revenue is primarily due to a decline in energy prices and the loss of a significant contract at Flinders. The increase in Europe and other Americas revenue is primarily due to a full year of operations for acquisitions made in 2001.

For the year ended December 31, 2002, NRG Energy had equity in earnings of unconsolidated affiliates of $69.0 million, compared to $210.0 million for 2001, a decrease of $141.0 million or approximately 67.1%. The $141.1 million decrease in Equity earnings from unconsolidated affiliates is due primarily to unfavorable results at West Coast Power in 2002 as compared to the same period in 2001. During 2002, West Coast Power had long-term contracts that were less favorable than those held in 2001. In addition during 2002, West Coast Power established reserves for certain receivables not considered recoverable. NRG Energy’s share of this reserve was approximately $58.5 million on a pre-tax basis.

For the year ended December 31, 2002, cost of majority-owned operations related to continuing operations was $1,510.6 million compared to $1,430.0 million for 2001, an increase of $80.6 million or approximately 5.6%. For the years ended December 31, 2002 and 2001, cost of majority-owned operations represented approximately 68.3% and 65.0% of revenues from majority-owned operations, respectively. Cost of majority-owned operations consists primarily of cost of energy (primarily fuel costs), labor, operating and maintenance costs and non-income based taxes related to NRG Energy’s majority-owned operations.

Cost of energy increased from $974.7 million for the year ended December 31, 2001 to $1,015.2 million for the year ended December 31, 2002. This represents an increase of $40.5 million or 4.2%. As a percent of revenue from majority owned operations cost of energy was 45.9% and 44.2% for the years ended December 31, 2002 and 2001, respectively.

Operating and maintenance costs increased from $356.9 million for the year ended December 31, 2001 to $415.8 million for the year ended December 31, 2002. This represents an increase of $58.9 million or 16.5%. As a percent of revenue from majority owned operations, operating and maintenance costs represented 18.8% and 16.2%, for the years ended December 31, 2002 and 2001, respectively. The dollar increase in operating and maintenance expense is primarily due to a full year of expense in 2002 related to assets acquired during 2001.

For the year ended December 31, 2002, depreciation and amortization related to continuing operations was $256.2 million, compared to $169.6 million for the year ended December 31, 2001, an increase of $86.6 million or approximately 51.1%. This increase is primarily due to the addition of property, plant and equipment related to NRG Energy’s recently completed acquisitions of electric generating facilities.

For the year ended December 31, 2002, general, administrative and development costs were $250.1 million, compared to $193.9 million, an increase of $56.2 million or approximately 29.0%. For the year ended

December 31, 2002 and 2001, general, administrative and development costs represent 11.3% and 8.8% of revenues from majority-owned operations, respectively. This increase is primarily due to an increase in bad debt expense of approximately $39.2 million over 2001. Additionally there was an increase in other general administrative expenses due to 2001 acquisitions, newly constructed facilities coming on line. These increases were partially offset by decreases in business development expenses and other reductions to costs previously incurred to support international and expanded operations.

For the year ended December 31, 2002, write-downs and losses on equity method investments were $196.2 million. The $196.2 million charge consists primarily of write downs taken related to NRG Energy’s investment in Loy Yang in the total amount of $111.4 million. In addition, NRG Energy recorded a loss of $48.4 million upon the transfer of its investment in SRW Cogeneration and recorded write-downs of $14.2 million and $3.6 million of its investments in EDL and Collinsville, respectively.

During the third quarter of 2002, NRG Energy experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. NRG Energy applied the provisions of SFAS No. 144 to its construction and operational projects. NRG Energy completed an analysis of the recoverability of the asset carrying values of its projects factoring in the probability of different courses of action available to NRG Energy given its financial position and liquidity constraints. As a result, NRG Energy determined during the third quarter that many of its construction projects and certain operational projects were impaired and should be written down to fair market value. To estimate fair value, NRG Energy management considered discounted cash flow analyses, bids and offers related to those projects and prices of similar assets. During 2002, NRG Energy recorded asset impairment and other special charges related to continuing operations of $2,656.1 million. See Item 15 — Note 3 to the Consolidated financial statements and notes of this Form 10-K for additional information.

Additional asset impairments and other charges may be recorded by NRG Energy in periods subsequent to December 31, 2002, given the changing business conditions and the resolution of the pending restructuring plan. Management is unable to determine the possible magnitude of any additional asset impairments.

During 2002, NRG Energy expensed charges of $25.6 million for expected severance costs, primarily related to terminated executives, associated with the restructuring of NRG Energy, and of this amount, $4.7 million of cash was paid as of December 31, 2002.

In addition to asset impairment charges and severance costs, NRG Energy has incurred $85.8 million of restructuring costs consisting of financial and legal advisor fees, contract termination fees and other such costs. NRG Energy expects that costs such as these will continue for the near term as NRG Energy continues to restructure its operations.

NRG Energy 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 Energy views this change as a significant improvement to the existing market design, NRG Energy still views the market within New England as insufficient to allow for NRG Energy to recover its costs and earn a reasonable return on investment. Consequently, on February 26, 2003, NRG Energy filed and requested a cost of service rate with FERC for most of its Connecticut fleet, requesting a February 27th effective date. NRG Energy remains 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 NRG Energy has the right to file for such rate treatment, there are no assurances that FERC will grant such rates in the form or amount that NRG Energy petitioned for in its filing. If FERC declines to grant cost of service based rates in Connecticut, there may be additional impairments related to the Connecticut assets.

On March 25, 2003, the Federal Energy Regulatory Commission (“FERC”) issued an order (the “Order”) in response to Devon Power LLC’s, Middletown Power LLC’s, Montville Power LLC’s, and Norwalk Power LLC’s (collectively, “NRG Subsidiaries”) 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 Subsidiaries requested that FERC accept the NRG Subsidiaries’ reliability must-run agreements and assure the NRG Subsidiaries’ recovery of maintenance costs for their New England generating facilities prior to the peak summer season. FERC accepted the NRG Subsidiaries’ 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 Subsidiaries 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.

For the year ended December 31, 2002, total other expense was $485.0 million, compared to $371.7 million for the year ended December 31, 2001, an increase of $113.3 million or approximately 30.5%. The increase in total other expense from 2001 consisted primarily of an increase in interest expense.

For the year ended December 31, 2002, interest expense (which includes both corporate and project level interest expense) was $494.0 million, compared to $389.3 million in 2001, an increase of $104.7 million or approximately 26.9%. This increase is due primarily to increased corporate and project level debt. NRG Energy issued substantial amounts of long-term debt at both the corporate level (recourse debt) and project level (non-recourse debt) to either directly finance the acquisition of electric generating facilities or refinance short-term bridge loans incurred to finance such acquisitions.

For the year ended December 31, 2002, minority interest in earnings of consolidated subsidiaries was a gain of $4.8 million, compared to a loss of $2.3 million, an increase of $7.1 million, as compared to 2001. The decrease is primarily due to lower earnings from Timber Energy Resources, as compared to 2001.

For the year ended December 31, 2002, other income, net, was a gain of $4.2 million, as compared to $19.9 million for the year ended December 31, 2001, a decrease of $15.7 million, or approximately 78.9%. Other income, net consists primarily of interest income on cash balances and realized and unrealized foreign currency exchange gains and losses.

It is likely that Xcel Energy will not request Internal Revenue Service consent to consolidate NRG Energy for income tax purposes for 2002. Therefore, the income tax provision for NRG Energy is based on a consolidated NRG Energy group through June 3, 2002, and separate income tax returns starting June 4, 2002. On a stand-alone basis, it is uncertain if NRG Energy would be able to fully realize tax benefits on its losses and therefore a valuation allowance has been provided.

For the year ended December 31, 2002, income tax benefit from continuing operations was $165.4 million, compared to an income tax expense of $28.1 million for the year ended December 31, 2001, a decrease of $193.5 million. NRG Energy recorded an income tax benefit in 2002 for operating losses to the extent realization was considered more likely than not. Tax benefits were not recorded for items NRG was uncertain that there would be sufficient operating losses to offset operating income in future periods.

As of December 31, 2002, NRG Energy has classified the operations and gains/losses recognized on the sales of certain entities as discontinued operations. Discontinued operations consist of the historical operations and net gains/losses related to its Crockett Cogeneration, Entrade, Killingholme, Csepel, Hsin Yu and Bulo Bulo projects that were sold in 2002 or were deemed to have met the required criteria for such classification

pending final disposition (the Killingholme and Hsin Yu projects). For 2002, the results of operations related to such discontinued operations was a net loss of $556.6 million as compared to a gain of $47.0 million for the same period in 2001. The primary reason for the loss recognized in 2002 is due to asset impairments recorded at Killingholme and Hsin Yu.

Net income for 2001 was $265.2 million, compared to $182.9 million for 2000, an increase of $82.3 million or approximately 45.0%. Net income for 2001 increased by $82.3 million due to the factors described below.

For the year ended December 31, 2001, NRG Energy had total revenues and equity earnings from continuing operations of $2,411.5 million, compared to $1,810.1 million for 2000, an increase of $601.4 million or approximately 33.2%.

NRG Energy’s operating revenues from majority-owned operations were $2,201.4 million compared to $1,670.8 million, an increase of $530.6 million or approximately 31.8%. Revenues from majority-owned operations for the year ended December 31, 2001 consisted primarily of power generation revenues from domestic operations of approximately $1,679.6 million, operations in Europe of $72.6 million, Asia-Pacific $214.8 million and Other Americas $28.2 million, resulting in increases of $231.3 million, $71.2 million, $120.0 million and $27.9 million compared to 2000, respectively. In addition, NRG Energy recognized revenues from majority-owned operations from its alternative energy, thermal and other operations of approximately $79.5 million, $108.3 million and $18.5 million respectively, resulting in increases of $45.1 million, $23.4 million and $11.7 million compared to 2000, respectively.

The increase of $231.3 million related to NRG Energy’s domestic power generation operations is due primarily to additional sales at NRG Energy’s Eastern region facilities which were acquired in June 2001 from Conectiv and increased sales at NRG Energy’s South Central region facilities which were primarily acquired in March 2000 from Cajun Electric and expanded with the acquisition of the Batesville facility from LS Power in January 2001 and completion of the Sterlington and Big Cajun 1 peaking facilities in 2001.

The increase of $71.2 million related to NRG Energy’s Europe power generation operations is due primarily to operations at Saale Energie in Germany (SEG).

The increase of $120.0 million related to NRG Energy’s Asia-Pacific’s power generation operations is due primarily to a full year of operations at the Flinders Power facilities which was acquired in August 2000.

The increase of $27.9 million related to NRG Energy’s Other America’s power generation operations is due primarily to the consolidation in 2001 of the COBEE facility which was previously accounted for under the equity method.

For the year ended December 31, 2001, NRG Energy had equity in earnings of unconsolidated affiliates of $210.0 million, compared to $139.4 million for 2000, an increase of $70.6 million or approximately 50.6%. The increase of $70.6 million is primarily comprised of favorable results from NRG Energy’s domestic and international power generation equity investments. During 2001, NRG Energy’s domestic power generation investment in West Coast Power contributed $41.0 million of this increase. Additionally, approximately $40.2 million of the increase is from NRG Energy’s international power generation investments. These increases were partially offset by unfavorable results at NRG Energy’s other investments accounted for under

For the year ended December 31, 2001, cost of majority-owned operations was $1,430.0 million compared to $1,060.1 million for 2000, an increase of $369.9 million or approximately 34.9%. For the years ended December 31, 2001 and 2000, cost of majority-owned operations represented approximately 65.0% and 63.4% of revenues from majority-owned operations, respectively. Cost of majority-owned operations consists primarily of cost of energy (primarily fuel costs), labor, operating and maintenance costs and non-income based taxes related to NRG Energy’s majority-owned operations.

Cost of energy increased from $718.4 million for the year ended December 31, 2000 to $974.7 million for the year ended December 31, 2001 primarily due to 2001 domestic and international acquisitions. This represents an increase of $256.3 million or 35.7%. As a percent of revenue from majority owned operations, cost of energy was 44.3% and 43.0% for the years ended December 31, 2001 and 2000, respectively. Approximately 69.3% of the increase in operating costs and expenses for 2001 compared to 2000 of $369.9 million is primarily due to increased cost of energy.

Operating and maintenance costs increased from $259.4 million for the year ended December 31, 2000 to $356.9 million for the year ended December 31, 2001. This represents an increase of $97.5 million or 37.6%. As a percent of revenue from majority owned operations operating and maintenance costs represented 16.2% and 15.5%, for the years ended December 31, 2001 and 2000, respectively. The dollar increase in operating and maintenance expense is primarily due to 2001 domestic and international acquisitions.

For the year ended December 31, 2001, depreciation and amortization from continuing operations was $169.6 million, compared to $97.3 million for the year ended December 31, 2000, an increase of $72.3 million or approximately 74.3%. This increase is primarily due to the addition of property, plant and equipment related to NRG Energy’s recently completed acquisitions of electric generating facilities.

For the year ended December 31, 2001, general, administrative and development costs were $193.9 million, compared to $169.0 million, an increase of $24.9 million or approximately 14.7%. This increase is primarily due to increased business development activities, associated legal, technical and accounting expenses, employees and equipment resulting from expanded operations and pending acquisitions. This also includes a $10.3 million expense related to Enron’s bankruptcy. This amount includes a pre-tax charge of $22.4 million to establish bad debt reserves, which was partially offset by a pre-tax gain of $12.1 million on a credit swap agreement entered into as part of the NRG Energy’s credit risk management program.

For the year ended December 31, 2001, total other expense was $371.7 million, compared to $245.8 million for the year ended December 31, 2000, an increase of $125.9 million or approximately 51.2%. The increase in total other expense of $125.9 million, from 2000, consisted primarily of an increase in interest expense that was partially offset by an increase in other income and a reduction in minority interest in earnings of consolidated subsidiaries.

For the year ended December 31, 2001, interest expense (which includes both corporate and project level interest expense) was $389.3 million, compared to $250.8 million in 2000, an increase of $138.5 million or approximately 55.2%. This increase is due to increased corporate and project level debt issued during 2001. During 2001, NRG Energy issued substantial amounts of long-term debt at both the corporate level (recourse debt) and project level (non-recourse debt) to either directly finance the acquisition of electric generating facilities or refinance short-term bridge loans incurred to finance such acquisitions.

For the year ended December 31, 2001, minority interest in earnings of consolidated subsidiaries was $2.2 million, compared to $0.8 million, an increase of $1.4 million or approximately 175.0%, as compared to 2000.

For the year ended December 31, 2001, other income, net, was $19.9 million, as compared to $5.8 million for the year ended December 31, 2000, an increase of $14.1 million, or approximately 243.1%. Other income, net, consists primarily of interest income on cash balances and loans to affiliates, and miscellaneous other items, including the income statement impact of certain foreign currency translation adjustments and the impact of gains and losses on the dispositions of investments. Approximately $18.0 million of the increase relates to interest on cash balances and loans to affiliates, primarily West Coast Power. The increase also includes gains on foreign currency translation adjustments and miscellaneous asset sales that were partially offset by a $3.8 million charge to write-off capitalized costs associated with the Estonia project.

For the year ended December 31, 2001, income tax expense was $28.1 million, compared to an income tax expense of $86.9 million for the year ended December 31, 2000, a decrease of $58.8 million. Approximately $14.7 million of the decrease is attributed to additional IRC Section 29 energy credits that were recorded in 2001, as compared to the same period in 2000. NRG Energy reported a worldwide effective tax rate of approximately 11.4% for the year ended December 31, 2001, compared to approximately 36.5% for the year ended December 31, 2000. The overall reduction in tax rates was primarily due to the increase in energy credits, the implementation of state tax planning strategies and a higher percentage of NRG Energy’s overall earnings derived from foreign projects in lower tax jurisdictions.

Income from discontinued operations was $47.0 million in 2001 compared to $32.0 million in 2000.

NRG Energy’s discussion and analysis of its financial condition and results of operations are based upon NRG Energy’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 Energy, evaluates its estimates, utilizing historic experience, consultation with experts and other methods NRG Energy considers reasonable. In any case, actual results may differ significantly from NRG Energy’s estimates. Any effects on NRG Energy’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 Energy’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 Energy’s management in their application, have a significant impact on NRG Energy’s consolidated financial statements. NRG Energy identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of NRG Energy’s financial position and

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

As of December 31, 2002, NRG Energy has a carrying value of approximately $6.8 billion of net property, plant and equipment, $623.8 million of which is under construction or turbines being marketed, representing approximately 62.4% and 5.7% of total assets, respectively. The majority of the carrying value of

For those assets that were or are being constructed by NRG Energy the carrying value reflects the application of NRG Energy’s property, plant and equipment policies which incorporate estimates, assumptions and judgments by management relative to the capitalized costs and useful lives of NRG Energy’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. Capitalized interest was approximately $64.8 million 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 Energy’s Board of Directors. 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 Energy 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 Energy. 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 by $2.5 billion due to impairments recorded in 2002. Asset impairment evaluations are, by nature highly subjective.

NRG Energy is primarily an electric generation company, operating a portfolio of majority-owned electric generating plants and certain plants in which its ownership is 50% or less which are accounted for under the equity method of accounting. NRG Energy also produces thermal energy for sale to customers and collects methane gas from landfill sites, which is then used for the generation of electricity. Both physical and financial transactions are entered into to optimize the financial performance of NRG Energy’s generating facilities. Electric energy is recognized upon transmission to the customer. Capacity and ancillary revenue is recognized when contractually earned. Revenues from operations and maintenance services is recognized when the services are performed. NRG Energy uses the equity method of accounting to recognize its pro rata share of the net income or loss of its unconsolidated investments. NRG Energy 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 Energy 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 Energy 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 Energy primarily applies SFAS No. 133 to long-term power sales contracts, long-term gas purchase contracts and other energy related commodities and 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 Energy has entered into. In determining the fair value of these derivative/financial instruments NRG Energy uses estimates, various assumptions, judgment of management and when considered appropriate third party experts in determining the fair value of these derivatives.

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.

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 have failed to timely make the following interest and/or principal payments on its indebtedness:

These missed payments may have also resulted in cross-defaults of numerous other non-recourse and limited recourse debt instruments of NRG Energy. In addition, the following issues have been accelerated, rendering the debt immediately due and payable: on November 6, 2002, lenders to NRG Energy accelerated the approximately $1.1 billion of debt under the construction revolver facility; on November 21, 2002, the bond trustee, on behalf of bondholders, accelerated the approximately $750 million of debt under the NRG South Central Generating, LLC facility; and on February 27, 2003, ABN Amro as administrative agent, accelerated the approximately $1.0 billion corporate revolver financing facility.

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 letters

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.

Historically, NRG Energy and its subsidiaries have obtained cash from operations, issuance of debt and equity securities, borrowings under credit facilities, capital contributions from Xcel Energy, reimbursement by Xcel Energy of tax benefits pursuant to a tax sharing agreement and proceeds from non-recourse project financings. NRG Energy has used these funds to finance operations, service debt obligations, fund the acquisition, development and construction of generation facilities, finance capital expenditures and meet other cash and liquidity needs.

Net cash provided by operating activities increased during 2002 compared with 2001, primarily due to NRG Energy’s efforts to conserve cash by deferring the payment of interest and managing its cash flows more closely. Net cash provided by operating activities decreased during 2001 compared with 2000, primarily due to adverse changes to working capital and increased undistributed equity earnings from unconsolidated affiliates. These decreases to net cash were partially offset by increases in net income after non-cash adjustments for depreciation and amortization in 2001 as compared to 2000. The adverse changes to working capital are primarily due to increases in inventory balances, accrued income taxes receivables and changes in other long term assets and liabilities, partially offset by a favorable change in other current liabilities.

Net cash used in investing activities decreased in 2002, compared with 2001, primarily as a result of NRG Energy terminating its acquisition program due to its financial difficulties and the receipt of cash upon the sale of assets during 2002. Net cash used in investing activities increased in 2001, compared with 2000, primarily due to additional acquisitions of electric generating facilities and increased capital expenditures and project investments.

Net cash provided by financing activities during 2002 decreased, compared to 2001 due to constraints on NRG Energy’s ability to access the capital markets and the cancellation and termination of construction projects reducing the need for capital. Net cash provided by financing activities during 2001 increased compared to 2000 due to the issuance of debt and equity securities to finance asset acquisitions.

Short-term borrowing as a source of short-term funding is affected by access to reasonably priced capital markets. This varies based on financial performance and existing debt levels. If current debt levels are perceived to be at or higher than standard industry levels or those levels that can be sustained by current operating levels, access to reasonable short-term borrowings could be limited. These factors are evaluated by credit rating agencies that review NRG Energy and its subsidiary operations on an ongoing basis. As discussed above, NRG Energy’s credit situation has been adversely affected by its credit ratings and is significantly limited in its access to short-term funding.

NRG Energy’s operating cash flows have been adversely affected by lower operating margins as a result of low power prices since mid-2001. Seasonal variations in demand and market volatility in prices are not unusual in the independent power sector, and NRG Energy does normally experience higher margins in peak summer periods and lower margins in non-peak periods. NRG Energy has also incurred significant amounts of debt to finance its acquisitions in the past several years and the servicing of interest and principal repayments from such financing is largely dependent on domestic project cash flows. NRG Energy’s management has concluded that the forecasted free cash flow available to NRG after servicing project-level obligations will be insufficient to service recourse debt obligations at NRG Energy.

For additional information on NRG Energy’s short term and long term borrowing arrangements, see Item 15 — Note 13 to the Consolidated Financial Statements.

Working Capital. As of February 28, 2003, NRG Energy had cash in the following amounts:

NRG Energy anticipates that these cash resources, in addition to operating cash flows and net proceeds from asset sales, will be adequate to meet its corporate operating and capital expenditure needs going forward. However, NRG Energy does not anticipate having any cash available in 2003 to meet debt service on its corporate-level notes and loans. NRG Energy is in negotiations with certain lenders who are considering making credit available to NRG Energy and/or its subsidiaries through a debtor-in-possession facility in the event NRG Energy and/or its subsidiaries becomes a debtor under Chapter 11 of the United States Bankruptcy Code. Other than a potential debtor-in-possession facility, or entering into a negotiated recapitalization of its debt obligations, NRG Energy does not contemplate access to any new financing in 2003.

Capital Expenditures. NRG Energy’s management forecasts capital expenditures, which includes refurbishments and environmental compliance, to total approximately $475 million to $525 million in the years 2003 through 2007. NRG Energy anticipates funding its ongoing capital requirements through committed debt facilities, operating cash flows, and existing cash. NRG Energy’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.

Project Finance. Substantially all of NRG Energy’s operations are conducted by project subsidiaries and project affiliates. NRG Energy’s cash flow and ability to service corporate-level indebtedness when due is dependent upon receipt of cash dividends and distributions or other transfers from NRG Energy’s projects and other subsidiaries. NRG Energy has generally financed the acquisition and development of its projects under financing arrangements to be repaid solely from each of its project’s cash flows, which are typically secured by the plant’s physical assets and NRG Energy’s equity interests in the project company. In August 2002, NRG Energy suspended substantially all of its acquisition and development activities indefinitely, pending a

comprehensive restructuring of NRG Energy. 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, Loy Yang, Energy Center Kladno, LSP Energy (Batesville), NRG South Central, and NRG Northeast Generating do not currently meet the minimum debt service coverage ratios required for these projects to make payments to NRG Energy. In addition, NRG Energy’s subsidiaries, including LSP Kendall, NRG McClain, NRG Mid-Atlantic, NRG South Central and NRG Northeast Generating are in default on their various debt instruments, resulting in dividend payment restrictions.

As of December 31, 2002, NRG Energy 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 March 2000, an NRG Energy sponsored non-consolidated pass through trust issued $250 million of 8.70% certificates due March 15, 2005. Each certificate represents a fractional undivided beneficial interest in the assets of the trust. Interest is payable on the certificates semi-annually on March 15 and September 15 of each year through 2005. The sole assets of the trust consist of £160 million principal amount 7.97% Reset Senior Notes due March 15, 2020 issued by NRG Energy. Interest is payable semi-annually on the Reset Senior Notes on March 15 and September 15 through March 15, 2005, and then at intervals and interest rates established in a remarketing process. If the Reset Senior Notes are not remarketed on March 15, 2005, they must be mandatorily redeemed by NRG Energy on such date.

NRG Energy has numerous investments of generally less then 50% interests in energy and energy related entities that are accounted for under the equity method of accounting as disclosed in Item 15 — Note 10 to the Consolidated Financial Statements. NRG Energy’s pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $1.0 billion as of December 31, 2002. In the normal course of business NRG Energy may be asked to loan funds to these entities on both a long and short-term basis. Such transactions are generally accounted for as accounts payables and receivables to/from affiliates and notes receivables from affiliates and if appropriate, bear market-based interest rates. For additional information regarding amounts accounted for as notes receivables to affiliates see Item 15 — Note 12 to the Consolidated Financial Statements.

NRG Energy has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to its capital expenditure programs. The following is a summarized table of contractual obligations. See additional discussion in Item 15 — Notes 13, 14 and 22 to the Consolidated Financial Statements.

NRG Energy does not have any significant interdependent relationships. Since it is an indirect wholly owned subsidiary of Xcel Energy there are certain related party transactions that take place in the normal course of business. For additional information regarding NRG Energy’s related party transactions see Item 15 — Note 11 to the Consolidated Financial Statements and Item 13 — Certain Relationships and Related Transactions.

The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation 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 Energy’s facilities are not exempted from coverage, NRG Energy could be required to make extensive modifications to further reduce potential environmental impacts. Also, NRG Energy 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 Energy and its subsidiaries strive to exceed the standards of compliance with applicable environmental and safety regulations. Nonetheless, NRG Energy 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, regulator 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 Energy’s operations.

NRG Energy establishes accruals where reasonable estimates of probable environmental and safety liabilities are possible. NRG Energy 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 22 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 Energy’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 Energy 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 Energy’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 not yet supplanted them, it is not possible for NRG Energy to determine the extent to which the rules will affect its domestic operations.

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 Energy’s existing, wholly owned generating units in the Northeast and Mid-Atlantic regions 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 MWe and sold any amount of electricity or (ii) has a maximum design heat input greater than 250 mmBtu/hr. NRG Energy’s facilities that are subject to this rule in the Northeast and Mid-Atlantic Regions have been allocated NO_x emissions allowances, but NRG Energy expects that those allowances may not be sufficient for the anticipated operation of these facilities. Where insufficient allowances exist, NRG Energy 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 Energy’s operations in these regions.

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 Energy 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 Energy’s operations.

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

The El Segundo and Long Beach Generating Stations are both regulated by the South Coast Air Quality Management District’s (SCAQMD) Regional Clean Air Incentives Market (RECLAIM) program. This program, which regulates NO_x emissions in the Los Angeles area, was amended on May 11, 2001, and mandated major changes with respect to air emissions control at power generation facilities in southern California. New RECLAIM Rule 2009 requires that all existing power generation facilities meet Best Available Retrofit Control Technology (BARCT) for NO_x emissions from all utility boilers by January 1, 2003, and for all peaking units by January 1, 2004. Under the new rule, existing power generation facilities were required to submit compliance plans by September 1, 2001, listing how each unit at the stations would meet BARCT by the deadlines. El Segundo’s compliance plan did not propose additional NO_x controls to meet BARCT since Units 3 & 4 are already equipped with acceptable SCR technology (first installed on Unit 4 in 1995 and on Unit 3 in 2001). Further, NRG Energy is planning to decommission Units 1 & 2 so that it can build a new 621 MW combined cycle plant. SCAQMD approved the El Segundo Rule 2009 Compliance Plan on October 17, 2002, indicating that the SCRs on Units 3 & 4 meet BARCT and requiring

that Units 1 & 2 be retired on or before December 31, 2002. SCAQMD approved the Long Beach Generating Station Rule 2009 Compliance Plan on April 25, 2002, which proposed modifications to the Long Beach NO_x control system by December 31, 2002, and specified a new NO_x emission concentration limit of 16.6 parts per million. The Long Beach plant completed all control system modifications and demonstrated compliance with 16.6 parts per million limit before the December 31, 2002 deadline. Therefore, all Long Beach and El Segundo units have met the Rule 2009 BARCT requirement, and NRG Energy does not at this time anticipate additional material capital expenditures associated with the amended RECLAIM rules.

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 Energy 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 Energy 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 Energy’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 Energy 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 Energy 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 Energy 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 Energy 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 Energy generator in-state. NRG Energy 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 Energy filed written comments on the proposed rules on May 28, 2002. NRG Energy’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 Energy 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 Energy’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 Energy 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 if NRG cannot address such requirements through use of compliant fuels and/or plantwide applicability limits.

While no material impending rule changes affecting NRG Energy’s existing facilities have been formally proposed. Delaware is considering in 2003 whether or not to develop Maximum Achievable Control Technology (MACT) standards for mercury. In support of this effort, the State is beginning to test large combustion sources for mercury emissions. In addition, the State is establishing Total Maximum Daily Loading (TMDL) standards for mercury in its watersheds. NRG is participating as a stakeholder in such policy-making efforts along with the Governor’s Energy Task Force, legislators and the Delaware Department of Natural Resources and Environmental Control (DNREC) to ensure that any rules promulgated adequately consider impacts on NRG’s in-state sources.

The Louisiana Department of Environmental Quality has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone non-attainment area into compliance with National Ambient Air Quality Standards. NRG Energy participated in development of the revisions, which require the reduction of NO_x emissions at the gas-fired Big Cajun I Power Station and coal-fired Big Cajun II Power Station to 0.1 pounds NO_x per million Btu heat input and 0.21 pounds NO_x per million Btu heat input, respectively. This revision of the Louisiana air rules would appear to constitute a change-in-law covered by agreement between Louisiana Generating LLC and the electric cooperatives allowing the costs of added combustion controls to be passed through to the cooperatives. The capital cost of combustion controls required at the Big Cajun II Generating Station to meet the State’s NO_x regulations will total about $10.0 million each for Units 1 & 2. Unit 3 has already made such changes.

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 Energy has been involved in on-site contamination matters, to date, NRG Energy has not been named as a potentially responsible party with respect to any off-site waste disposal matter.

and provided the results to the sellers. Southern California Edison and San Diego Gas & Electric have agreed to address contamination identified by these studies and are undertaking corrective action at the Encina and San Diego gas turbine generating sites. Spills and releases of various substances have occurred at these sites since establishing the historical baseline, all but one of which has been remediated in accordance with existing laws.

A recent oil leak in underground piping at the El Segundo Generating Station contaminated soils adjacent to and underneath the Unit 1 powerhouse. NRG Energy excavated and disposed of contaminated soils that could be removed in accordance with existing laws. NRG Energy filed a request with the Regional Water Quality Control Board to allow contaminated soils to remain underneath the building foundation until the building is demolished.

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

NRG must also maintain financial assurance for closing interim status RCRA facilities at the Devon, Middletown, Montville and Norwalk Harbor Generating Stations. Previously, NRG Energy has provided financial assurance via financial test. NRG Energy must re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs. NRG Energy 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 Energy 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 Harbor Stations have been identified and are currently being refined as part of on-going site investigations. NRG Energy 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 liabilities at the Arthur Kill Generating Station have been established in discussions between NRG Energy and the New York State DEC and are expected to cost on the order of $1.0 million; for contingency purposes, NRG Energy has budgeted $2 million to complete its Arthur Kill remedial obligations. Remedial investigations are on-going at the Astoria Generating Station. At this time, NRG Energy’s long term cleanup liability at this site is not expected to exceed $2.5 million; for contingency purposes, NRG Energy has budgeted $4.3 million to complete its Astoria remedial obligations.

NRG Energy is responsible for the costs associated with closure, post-closure care and monitoring of the ash landfill owned and operated by NRG Energy on the site of the Indian River Generating Station. No material liabilities outside such costs are expected. Financial assurance to provide for closure and post-closure-related costs is currently maintained by a trust fund collateralized in the amount of approximately $6.6 million.

Liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated on site at the Big Cajun II Generating Station are addressed through the use of a trust fund maintained by NRG Energy (one of the instruments allowed by the Louisiana Department of Environmental Quality for providing financial assurance for expenses associated with closure and post-closure care of the ponds). The

Most of the foreign countries in which NRG Energy owns or may acquire or develop independent power projects have environmental and safety laws or regulations relating to the ownership or operation of electric power generation facilities. These laws and regulations are typically significant for independent power producers because they are still changing and evolving. In particular, NRG Energy’s international power generation facilities will likely be affected by evolving emissions limitations and operational requirements imposed by the Kyoto Protocol and country-based restrictions pertaining to global climate change concerns.

NRG Energy retains appropriate advisors in foreign countries and seeks to design its international development and acquisition strategy to comply with and take advantage of opportunities presented by each country’s environmental and safety laws and regulations. There can be no assurance that changes in such laws or regulations will not adversely effect NRG Energy’s international operations.

The most significant environmental issue for the Australian NRG businesses is the response to global climate change. Climate change issues are considered a long-term issue (e.g., 2010 and beyond), and the Federal Government’s response to date has included a number of initiatives, all of which have had no impact or minimal impact on NRG Energy’s current operations. The Australian Government has stated that Australia will achieve its Kyoto target of 108% of 1990 levels for the 2008 to 2012 reporting period but that it will not ratify the Kyoto Protocol. Each Australian State Government is considering implementing a number of climate change initiatives that will vary considerably state to state. NRG Energy currently expects that climate change initiatives will not have a material impact on NRG Energy’s businesses in Australia.

CO₂ emissions trading is supposed to start in 2005, but NRG Energy cannot quantify the possible effect of this trading on its operations in Germany at this time because implementation details are still being negotiated among businesses, lobbyists, and the regulatory authorities. Fundamental issues such as “grandfathering” existing plants or availability of credits for plants previously closed or upgraded are still unsettled. Given the uncertainty regarding the emissions trading program, NRG Energy cannot estimate at this time the possible effect such requirements would have on its future operations.

Proposed changes in sections 13 and 17 of the German Emission Control Directive are expected to tighten emission limits for plants firing conventional fuels, and for those co-firing waste products. As with CO₂ emissions trading, these changes are currently being vigorously debated with issues such as exemptions based on size or purpose of plants and “grandfathering” remaining undecided.

The European Union’s Groundwater Directive and Mine Wastewater Management Directive are in the rule-making stage with the final outcome still under debate. Given the uncertainty regarding the possible outcome of the on-going debate on these directives, NRG Energy cannot quantify at this time the possible effect such requirements would have on its future coal mining operations in Germany.

NRG Energy’s Enfield Generating Station uses state-of-the-art combined cycle technology and is set to fire natural gas as its primary fuel. Currently the facility complies with all conditions in its environmental permits and its operation is not under challenge by any governmental or non-governmental parties.

NRG Energy’s Kondapalli Generating Station is in compliance with its environmental permits, is not being challenged by any parties on environmental grounds, has incurred no fines or penalties associated with

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. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. NRG Energy has not completed its analysis of SFAS No. 143. NRG Energy will complete its analysis in 2003 and in accordance with the accounting guidance, be required to restate prior quarterly statements to the extent the impact of the adoption is material.

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.

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 are effective for transactions occurring after May 15, 2002.

SFAS No. 145 will be applied as required. Adoption of SFAS No. 145 is not expected to have a material impact on NRG Energy.

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, with early application encouraged. SFAS No. 146 will be applied as required.

In December 2002, FASB issued SFAS No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123. This Statement amends FASB Statement No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The provisions of

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. NRG Energy is currently evaluating this standard and is presently unable to determine its impact.

NRG Energy’s California generation assets include a 50% interest in the West Coast Power partnership with Dynegy.

In March 2001, the California Power Exchange (PX) filed for bankruptcy under Chapter 11 of the Bankruptcy Code, and in April 2001, the Pacific Gas & Electric Company (PG&E) also filed for bankruptcy under Chapter 11. PG&E’s filing delayed collection of receivables owed to the Crockett facility. In September 2001, PG&E filed a proposed plan of reorganization. Under the terms of the proposed plan, which is subject to challenge by interested parties, unsecured creditors such as NRG Energy’s California affiliates would receive 60% of the amounts owed upon approval of the plan. The remaining 40% would be paid in negotiable debt with terms from 10 to 30 years. The California PX’s ability to repay its debt is dependent on the extent to which it receives payments from PG&E and Southern California Edison Company (SCE). During the fourth quarter of 2002, West Coast Power recorded an approximately $117.0 million charge to write-off the remaining amounts owed to it by the California PX and ISO. NRG Energy’s share of this charge was approximately $58.5 million (pre-tax).

The tables below disclose the trading 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.

NRG Energy uses a variety of financial instruments to manage its exposure to fluctuations in foreign currency exchange rates on its international project cash flows, interest rates on its cost of borrowing and energy and energy related commodities prices.

NRG Energy is also subject to currency risks associated with foreign denominated distributions from international investments. In the normal course of business, NRG Energy receives distributions denominated in Australian Dollar, British Pound and Euro. Upon completion of the Itiquira plant in Brazil, NRG Energy is also subject to currency risk with the Brazilian Real. NRG Energy engages in a strategy of hedging foreign denominated cash flows through a program of matching currency inflows and outflows, and to the extent required, fixing the U.S. Dollar equivalent of net foreign denominated distributions with currency forward and swap agreements with highly credit worthy financial institutions.

NRG Energy has £160 million in long-term debt due 2020 which is subject to market fluctuations.

As of December 31, 2002, NRG Energy had two foreign currency exchange contracts with notional amounts of $3.0 million. If the contracts had been discontinued on December 31, 2002, NRG Energy would have owed the counter-parties approximately $0.3 million.

NRG Energy and its subsidiaries are exposed to fluctuations in interest rates when entering into variable rate debt obligations to fund certain power projects. Exposure to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG Energy’s risk management policy allows the company to reduce interest rate exposure from variable rate debt obligations.

During 2002, as a result of the various defaults under certain loan agreements, NRG Energy’s counter-parties have terminated interest rate swaps with NRG Energy, Brazos Valley LP and NRG Finance Company I LLC. Until NRG Energy successfully restructures outstanding debt and returns to credit quality, NRG Energy will not seek to manage interest rate risk through the use of financial derivatives.

As of December 31, 2002, NRG Energy had various interest rate swap agreements with notional amounts totaling approximately $1.7 billion. If the swaps had been discontinued on December 31, 2002, NRG Energy would have owed the counter parties approximately $41.0 million. Based on the investment grade rating of the counter parties, NRG Energy believes that its exposure to credit risk due to nonperformance by the counter-parties to its hedging contracts is insignificant.

NRG Energy and its subsidiaries have both long and short-term debt instruments that subject it to the risk of loss associated with movements in market interest rates. As of December 31, 2002, a 100 basis point change in the benchmark rate on NRG Energy’s variable rate debt would impact net income by approximately $39.3 million. As of December 31, 2001, a 100 basis point change in the benchmark rate on NRG Energy’s variable rate debt would have impacted net income by approximately $16.6 million.

NRG Energy 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 Energy enters 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.

NRG Energy utilizes an undiversified “Value-at-Risk” (VAR) model to estimate a maximum potential loss in the fair value of its commodity portfolio including generation assets, load obligations and bilateral physical and financial transactions. The key assumptions for the NRG Energy VAR model include (1) a lognormal distribution of price returns (2) three day holding period and (3) a 95% confidence interval. The volatility estimate is based on the implied volatility for at the money call options. This model encompasses the following generating regions: Entergy, NEPOOL, NYPP, PJM, WSCC, SPP and Main.

The estimated maximum potential three-day loss in fair value of its commodity portfolio, calculated using the VAR model is as follows:

NRG Power Marketing has risk management policies in place to measure and limit market and credit risk associated with NRG’s power marketing activities. These policies do not permit speculative or directional trading. An independent department within NRG Power Marketing is responsible for the enforcement of such policies. NRG Energy is currently in the process of reviewing and revising these policies to reflect changes in industry dynamics and the NRG Energy reorganization.

NRG Energy is exposed to credit risk in its risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counter party of its contractual obligations. NRG Energy actively manages its counter-party credit risk. NRG Energy has an established credit policy in place to minimize

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

The name, age and title of each of the executive officers and directors of NRG Energy as of March 1, 2003 are as set forth below:

Richard C. Kelly has 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.

Wayne H. Brunetti has been a Director of NRG Energy since August 2000. During August 2002, Mr. Brunetti became the acting CEO of NRG Energy. Mr. Brunetti has been President and CEO of Xcel Energy Inc. since August 2000. Prior to assuming his current position in August 2000, Mr. Brunetti was Vice Chairman, President and Chief Executive Officer of New Century Energy. Mr. Brunetti was Vice Chairman, President and Chief Operating Officer of Public Service Company of Colorado before it merged with Southwestern Public Service Company to form New Century Energy. Mr. Brunetti joined Public Service Company of Colorado as President and Director officer in 1994.

Gary R. Johnson has been a Director of NRG Energy since 1993 and has been Vice President and General Counsel of Xcel Energy since August 2000. Mr. Johnson served as Vice President and General Counsel of Northern States Power from November 1991 to August 2000. Prior to November 1991, Mr. Johnson was Vice President-Law of Northern States Power from January 1989, acting Vice President from September 1988 and Director of Law from February 1987, and he has served in various management positions with Northern States Power during the last 20 years.

William T. Pieper has been Vice President and Controller of NRG Energy since June 2001. 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.

Scott J. Davido has 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 & Pogue in Pittsburgh, Pennsylvania from January 1997 to December 1997 and an Associate, Business Practice Group from September 1987 to December 1996.

Ershel C. Redd, Jr. has been Senior Vice President, Commercial Operations at NRG since October 2002 and had been advising NRG Energy’s senior management group with regards to power marketing operations since June 2002. Previously, Mr. Redd served as Vice President of Business Development for Xcel Energy Markets, Xcel Energy from August 2000 to October 2002; Prior to that, he served as Vice President of e Prime, Inc., Xcel Energy from July 1999 to August 15, 2000. Mr. Redd served as President & COO of Texas Ohio Gas, Inc., NCE, from January 1997 to July 1999. He has more than 30 years of management experience in multiple areas of the energy industry.

George P. Schaefer has 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.

John P. Brewster has been Vice President, Worldwide Operations of NRG Energy since June 2002. From July 2001 through June 2002, Mr. Brewster served as Vice President, North American Operations of NRG Energy. From April 2000 through July 2001, he served as Vice President of Production for NRG Louisiana Generating Inc. From April 1995 to April 2000, Mr. Brewster served as Vice President of Production for Cajun Electric Power Cooperative.

There are no family relationships between any of NRG Energy’s officers and directors. Each of NRG Energy’s officers serves at the discretion of the Board of Directors.

Under federal securities laws, NRG Energy’s directors and executive officers are required to report, within specified monthly and annual due dates, their initial ownership in NRG Energy’s securities and subsequent acquisitions, dispositions or other transfers of interest in such securities. NRG Energy is required to disclose whether it has knowledge that any person required to file such a report may have failed to do so in a timely manner. To the knowledge of NRG Energy, all of its directors and officers subject to such reporting obligations have satisfied their reporting obligations in full for 2002 except for Scott J. Davido, Ershel C. Redd Jr., George P. Schaefer and John P. Brewster each of whom was late in satisfying his Form 3 reporting requirements.

The following tables set forth cash and non-cash compensation for each of the last three fiscal years ended December 31, for the individuals who served as NRG Energy’s Chief Executive Officer and Chief Operating Officer during 2002 and each of the four next most highly compensated executive officers (collectively, the “Named Executive Officers”).


	[1]	Mr. Brunetti is Chairman, President and Chief Executive Officer of Xcel Energy, NRG Energy’s parent company. He is not compensated by NRG Energy for service in his capacity as Chairman and Chief Executive Officer.

	[2]	Mr. Peterson’s employment with NRG Energy terminated on May 31, 2002

	[3]	Includes fringe benefits and fringe benefit tax gross-up.

	[4]	Mr. Sass’s employment with NRG Energy terminated on December 18, 2002

	[5]	Includes paid time off (PTO) payout, 401(k) match, fringe benefit tax gross-up, severance payment for two months and pension make-up payment.

	[6]	Represents options to purchase Xcel Energy Common Stock.

	[7]	Includes 401(k) match.

	[8]	Includes severance pay, 401(k) match and PTO payout.

	[9]	Mr. Mataczynski’s employment with NRG Energy terminated on June 28, 2002


[10]	Represents 401(k) match.

[11]	Includes fringe benefits and fringe benefit tax gross-up.

[12]	Includes severance pay, 401(k) match and PTO payout.

NRG Energy did not use stock options and SARs for executive compensation purposes in 2002.

The following table indicates for each of the Named Executive Officers the number and value of all exercisable and unexercisable options and SARs held by the Named Executive Officers as of December 31, 2002.


(1)	Shares acquired on exercise are stated at the Xcel Energy conversion value.

(2)	Option values were calculated based on a $11.00 closing price of Xcel Common Stock at December 31, 2002.

NRG Energy participates in Xcel Energy’s noncontributory, defined benefit pension plan. Such plan covers substantially all of NRG Energy’s employees. As of January 1, 1999, the pension benefit formula that applies to the Named Executive Officers was changed and each Named Executive Officer, together with all other affected nonbargaining employees, was given an opportunity to choose between two retirement programs, the traditional program and the pension equity program. Messrs. Peterson and Mataczynski have selected the traditional program and Messrs. Pieper, Sass and Brewster have selected the pension equity program.

Under the traditional program applicable to certain of the Named Executive Officers, the pension benefit is computed by taking the highest average compensation below the integration level times 1.1333% plus the highest average compensation above the integration level times 1.6333%. The result is multiplied by credited service. The integration level is one-third of the social security wage base. The annual compensation used to calculate average compensation is base salary for the year. After an employee has reached 30 years of service, no additional years of service are used in determining the pension benefit under the traditional program. The benefit amounts under the traditional program are computed in the form of a straight-life annuity.

Under the pension equity program applicable to certain of the Named Executive Officers, the formula for determining the pension benefit is average compensation times credited years of service times 10%. The annual compensation used to calculate average compensation is base salary for the year plus bonus compensation paid in that same year. There is no maximum on the number of years of service used to determine the pension benefit. The benefit amounts under the pension equity program are computed in the form of a lump sum.

Both programs feature a retirement spending account, which credits $1,400 plus interest annually. The opening balance as of January 1, 1999 was $1,400, multiplied by years of service.

The following table illustrates the approximate retirement benefits payable to employees retiring at the normal retirement age of 65 years under the traditional program applicable to certain of the Named Executive Officers:

The following table illustrates the approximate retirement benefits payable to employees retiring at the normal retirement age of 65 years under the pension equity program applicable to certain of the Named Executive Officers if paid in the form of a straight-line annuity:

The approximate credited years of service as of December 31, 2001, for the Named Executive Officers were as follows:

Scott J. Davido is party to a Key Executive Retention, Restructuring Bonus and Severance Agreement with NRG Energy dated as of February 18, 2003. Under the agreement, Mr. Davido is entitled to: (i) a time-vested retention bonus of $150,000 (the “Retention Bonus”) (ii) compensation for participation in the restructuring of NRG Energy (the “Restructuring Bonus”) and (iii) certain severance benefits.

Mr. Davido has been given the entire Retention Bonus and will be entitled to keep the entire Retention Bonus provided he does not voluntarily terminate his employment before July 31, 2003. If Mr. Davido does voluntarily terminate his employment before July 31, 2003, he will be entitled to keep a prorata portion of his bonus based on the number of days remaining until July 31, 2003.

Mr. Davido is entitled to a Restructuring Bonus upon the (i) the consummation of a consensual out of court restructuring of all or substantially all of the debt of NRG Energy, (ii) the confirmation of a plan of reorganization for NRG Energy or (iii) the completion of a sale of all or substantially all of the assets of NRG Energy. Mr. Davido is not entitled to a Restructuring Bonus if he is terminated for cause, his employment ends due to disability or retirement or he voluntarily terminates his employment. The Restructuring Bonus is equal to two times the sum of (i) Mr. Davido’s base salary and (ii) the greater of: (a) Mr. Davido’s average bonus over the last two years or (b) Mr. Davido’s target annual bonus established under a bonus plan for the year in which the restructuring occurs.

Mr. Davido is entitled to certain severance payments in particular situations where Mr. Davido’s employment with NRG Energy is terminated. If Mr. Davido is terminated without cause or resigns for good reason he is entitled to all of the following: (i) two times the sum of (a) Mr. Davido’s base salary and (b) the greater of: (x) Mr. Davido’s average bonus over the last two years or (y) Mr. Davido’s target annual bonus established under a bonus plan for the year in which the termination occurs; (ii) a prorata portion of Mr. Davido’s unpaid target annual incentive; (iii) a payment equivalent to the COBRA premiums in effect as of the termination; and (iv) a cash payment of vacation and/or paid time off earned but not taken by Mr. Davido. If Mr. Davido’s employment is terminated for disability, death or retirement, he (or his estate) is entitled to his base salary and vacation earned but untaken through the termination.

All of the obligations under Mr. Davido’s Key Executive Retention, Restructuring Bonus and Severance Agreement are guaranteed by Xcel Energy. In addition, Mr. Davido has agreed not to compete with NRG Energy for a period of one year after the termination of his employment.

Ershel Redd is party to a severance agreement with NRG Energy dated as of January 30, 2003. Under the agreement, Mr. Redd is entitled to severance benefits equivalent to those under the Xcel Energy Business Unit Vice President Severance Plan. Specifically, if (i) Mr. Redd’s employment is terminated without cause, (ii) his position is eliminated without a comparable position being offered, (iii) his salary is reduced by more than 10% (and he subsequently voluntarily terminates his employment) or (iv) he is required to relocate (and he subsequently voluntarily terminates his employment), then Mr. Redd is entitled to lump-sum and continuing severance benefits during the “severance period” (18 months after employment termination). Further, all of the obligations under Mr. Redd’s severance plan are guaranteed by Xcel Energy.

The lump-sum severance benefit is equal to the aggregate of: (i) unpaid annual salary through the date of termination and a prorata share of Mr. Redd’s target annual incentive; (ii) 1.5 times the sum of Mr. Redd’s salary and target annual incentive; (iii) certain retirement benefits Mr. Redd would have earned had he been employed during the severance period; and (iv) certain contributions the NRG would have made to Mr. Redd’s defined contribution and supplemental executive savings plans. The continuing benefits include: (i) medical, dental vision and life insurance; (ii) outplacement services (up to $15,000); (iii) financial counseling; and (iv) the “flexible prerequisite allowance.”

William Pieper is party to an NRG Executive Officer and Key Personnel Severance Plan with NRG Energy dated as of July 16, 2001 (as modified by a letter agreement between Mr. Pieper, NRG Energy and Xcel Energy dated as of July 16, 2002).

Under the agreement, if Mr. Pieper’s employment is terminated by NRG Energy without cause or Mr. Pieper voluntarily terminates his employment within three months of a material change or reduction in his responsibilities at NRG Energy, then Mr. Pieper is entitled to certain severance benefits. Specifically, Mr. Pieper is entitled to (i) 1.5 times the sum of (a) his base salary and (b) the greater of (x) Mr. Pieper’s average annual bonus over the two years preceding the termination or (y) Mr. Pieper’s target annual bonus for the year of termination, (ii) the unpaid prorata portion of Mr. Pieper’s targeted annual incentive, (iii) a net cash payment equivalent to the COBRA rates of the welfare benefits of medical, dental and term life

In addition, under the agreement, if there is a change of control of NRG Energy and Mr. Pieper’s employment is terminated within 6 months prior to such change of control or 12 months following such change of control, then Mr. Pieper is entitled to certain severance benefits. Specifically, Mr. Pieper is entitled to (i) 2.5 times the sum of (a) his base salary and (b) the greater of (x) Mr. Pieper’s average annual bonus over the two years preceding the termination or (y) Mr. Pieper’s target annual bonus for the year of termination, (ii) the unpaid prorata portion of Mr. Pieper’s targeted annual incentive, (iii) a net cash payment equivalent to the COBRA rates of the welfare benefits of medical, dental and term life insurance for twelve months, (iv) a cash payment for earned and untaken vacation time and (v) all outstanding long-term incentive awards subject to the treatment provided under the long-term incentive plan of NRG Energy.

The letter agreement dated July 16, 2002 provides that rather than immediately terminating his employment and seeking severance benefits due to a material change or reduction in his responsibilities at NRG Energy (after NRG Energy became a wholly-owned subsidiary of Xcel Energy), NRG Energy has instead extended the time frame in which Mr. Pieper may terminate his employment and seek such severance benefits by 15 months, provided Mr. Pieper does not terminate his employment within 12 months of July 16, 2002.

George Schaefer is party to a letter agreement with NRG Energy dated as of December 18, 2002 which provides Mr. Schaefer certain severance benefits in the event his employment with NRG Energy is terminated. Specifically, in the event Mr. Schaefer’s employment is terminated without cause or Mr. Schaefer resigns for good reason, he is entitled to a lump sum payment equal to his base salary and a lump sum payment for all costs associated with health benefits under COBRA for a period of twelve months.

Directors of NRG Energy do not receive compensation for service in such capacity.

NRG Energy was initially incorporated in Minnesota in 1989, and was reincorporated in Delaware in 1992 as a wholly owned subsidiary of NSP. NRG Energy became publicly traded on May 31, 2000. In August 2000, NSP merged with NCE to form Xcel Energy. Following the completion in March 2001 of a public offering by NRG Energy of 18.4 million shares of Common Stock (the March 2001 Offering), Xcel Energy owned an approximate 74% interest in the Common Stock and Class A Common Stock of NRG Energy on a combined basis, representing 96.7% of the total voting power of the Common Stock and Class A Common Stock on a combined basis. On June 3, 2002, Xcel Energy completed its exchange offer for the 26% of NRG Energy’s shares that had been previously publicly held. In addition, 3 directors of NRG Energy are executive officers of Xcel Energy.

NRG Energy has one thermal contract with Xcel Energy in 2002 that expires on December 31, 2006. This contract relates to incremental costs associated with the sale of steam at Xcel Energy’s King plant in Bayport, Minnesota. The NRG Energy Center Rock-Tenn, LLC has two contracts with Xcel Energy in 2002; one is a coal contract that expired December 31, 2002, and the other covers the use and operation of certain facilities at Xcel Energy’s Highbridge plant in St. Paul, Minnesota that expires December 31, 2010. NRG Energy paid $8.2 million in 2002 under these agreements.

NRG Energy has a renewable 10-year agreement with Xcel Energy, expiring on December 31, 2006, under which Xcel Energy agrees to purchase refuse-derived fuel for use in certain of its boilers, and NRG Energy agrees to pay Xcel Energy a burn incentive. Under this agreement, NRG Energy received from Xcel Energy $1.2 million in 2002, and NRG Energy paid to Xcel Energy $3.3 million in 2002.

NRG Energy reimburses Xcel Energy for certain overhead and administrative costs, including benefits administration, engineering support, accounting, and other shared services. Employees of NRG Energy participate in certain employee benefit plans of Xcel Energy. NRG Energy paid Xcel Energy $21.2 million in 2002 as reimbursement for certain overhead costs and the cost of services provided.

NRG Energy has an agreement with Utility Engineering Corporation, a wholly owned subsidiary of Xcel Energy, under which Utility Engineering provides consulting services to NRG Energy. Consulting services are provided from time to time at NRG Energy’s request. NRG Energy paid $698,000 to Utility Engineering for consulting services in 2002.

NRG Energy was formerly a member of Xcel Energy’s consolidated tax group for United States federal income tax purposes. The responsibility for payment of taxes and the allocation between Xcel Energy and NRG Energy of tax benefits and liabilities was previously governed by a tax sharing agreement between NRG Energy and Xcel Energy. Such tax sharing agreement was replaced by a tax allocation agreement, which became effective as of December 2000, that formalized the various practices which arose under the previous tax sharing agreement and reflected the change in NRG Energy’s status from a wholly-owned subsidiary of Xcel Energy to a majority-owned subsidiary. Following the completion of the March 2001 Offering, Xcel Energy owned equity securities representing less than 80% of NRG Energy’s value and, accordingly, NRG Energy was no longer a member of Xcel Energy’s consolidated tax group.

On June 3, 2002 Xcel Energy completed its exchange offer for the 26% of NRG Energy’s shares that had been publicly held. Starting June 4, 2002, NRG Energy and subsidiaries can rejoin Xcel Energy’s consolidated group for federal income tax purposes provided the Internal Revenue Service (IRS) consents to such rejoining. To date, no request has been made to the IRS for consent to permit Xcel Energy to reconsolidate NRG Energy for federal income tax purposes. It is likely that Xcel Energy will not request IRS consent to consolidate NRG Energy for income tax purposes for 2002.

NRG Power Marketing, Inc. has an agreement with e prime, Inc., a wholly-owned subsidiary of Xcel Energy under which e prime, Inc. provides strategic and other business advice relating to origination opportunities with NRG Energy’s plant output. These services are provided from time to time at the request of NRG Power Marketing, Inc.

NRG Energy has agreements with e prime, a wholly owned subsidiary of Xcel Energy, under which e prime provides natural gas and related products from time to time at NRG Energy’s request. NRG Energy paid $19.2 million to e prime in 2002.

The CEO, Vice President and Treasurer and Vice President and Controller (the Certifying Officers) have evaluated NRG Energy’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 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 Energy caused by the NRG’s pending financial restructuring and business realignment. During the second half of 2002, there were material changes and vacancies in senior NRG management positions and a diversion of NRG financial and management resources to restructuring efforts. These circumstances detracted from NRG’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 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 Energy as of, and for the periods presented in this report.

NRG’s Energy’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 assets are protected from loss. There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of the Certifying Officers evaluation.

The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the report thereon of PricewaterhouseCoopers LLP, appearing on pages 68 through 148 are included herein:

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

NRG Energy will supplementally provide the financial statements of West Coast Power LLC as an amendment to this filing when such statements are completed and provided to NRG Energy. All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.

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

(b) Reports on Form 8-K. NRG Energy filed reports on Form 8-K on the following dates over the last fiscal year:

January 31, 2002, February 26, 2002, April 16, 2002, April 25, 2002, June 19, 2002, August 1, 2002, September 16, 2002, September 24, 2002, October 4, 2002, October 24, 2002, October 30, 2002, November 5, 2002, November 19, 2002, November 21, 2002, November 27, 2002, December 23, 2002, December 31, 2002, February 21, 2003, March 6, 2003.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, cash flows and stockholder’s (deficit)/equity present fairly, in all material respects, the financial position of NRG Energy, Inc. 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 our audits provide a reasonable basis for our opinion.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company is experiencing credit and liquidity constraints and has various credit arrangements that are in default. As a direct consequence, during 2002 the Company entered into discussions with its creditors to develop a comprehensive restructuring plan. In connection with its restructuring efforts, it is likely the Company and certain of its subsidiaries 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 19 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 Note 26 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. As discussed in Notes 3 and 5 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002.

NRG Energy, Inc., (NRG Energy or the Company), was incorporated as a Delaware corporation on May 29, 1992. Beginning in 1989, NRG Energy conducted business through its predecessor companies, NRG Energy, Inc. and NRG Group, Inc., Minnesota corporations, which were merged into NRG Energy subsequent to its incorporation. NRG Energy, together with its majority owned subsidiaries and affiliates, is an energy company primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products.

On June 5, 2000, NRG Energy completed its initial public offering. Prior to its initial public offering, NRG Energy was a wholly owned subsidiary of Northern States Power (NSP). In August 2000, NSP merged with New Century Energies, Inc. (NCE), a Colorado-based public utility holding company. The surviving corporation in the merger was renamed Xcel Energy Inc. (Xcel Energy or Parent), Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. Xcel Energy also owns or has interests in a number of non-regulated businesses, the largest of which is NRG Energy. In March 2001, NRG Energy completed a second public offering of 18.4 million shares of its common stock. Following this offering, Xcel Energy indirectly owned a 74% interest in NRG Energy’s common stock and class A common stock, representing 96.7% of the total voting power of NRG Energy’s common stock and class A common stock.

operations. NRG Energy’s objective will be to optimize the fuel input and the energy output of its facilities within an appropriate risk and liquidity profile.

In response to a possible downgrade, during 2002, Xcel Energy contributed $500 million to NRG Energy, and NRG Energy and its subsidiaries sold assets and businesses that provided NRG Energy in excess of $286 million in cash and eliminated approximately $432 million in debt. NRG Energy also cancelled or deferred construction of approximately 3,900 MW of new generation projects. On July 26, 2002, Standard & Poors’ (S&P) downgraded NRG Energy’s senior unsecured bonds to below investment grade, and three days later Moody’s also downgraded NRG Energy’s senior unsecured debt rating to below investment grade. Since July 2002, NRG Energy senior unsecured debt, as well as the secured NRG Northeast Generating LLC bonds, 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.

NRG Energy and its subsidiaries have failed to timely make interest and/or principal payments on substantial amounts of its indebtedness:

In addition, the following issues have been accelerated, rendering the debt immediately due and payable: on November 6, 2002, lenders to NRG Energy accelerated the approximately $1.1 billion of debt under the construction revolver facility; on November 21, 2002, the bond trustee, on behalf of bondholders, accelerated the approximately $750 million of debt under the NRG South Central Generating, LLC facility; and on February 27, 2003, ABN Amro, as administrative agent, accelerated the approximately $1.0 billion corporate revolver financing facility.

In addition to payment defaults, prior to the downgrades, many corporate guarantees and commitments of NRG Energy and its subsidiaries required that they be supported or replaced with letters of credit or cash collateral within 5 to 30 days of a ratings downgrade below Baa3 or BBB- by Moody’s or Standard & Poor’s, respectively. As a result of the downgrades on July 26 and July 29, NRG Energy received demands to post collateral aggregating approximately $1.1 billion.

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 consider the settlement and/or 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 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.

NRG Energy expects to have cash available for operations through 2003. This forecast does not assume further investment by Xcel Energy or modification of NRG Energy’s current debt obligations. In the event that NRG Energy is unable to work through the issues as described above and is unable to obtain adequate financing on terms acceptable to NRG Energy to continue its operations, NRG Energy may have to file bankruptcy. NRG Energy’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 Energy’s ability to continue as a going concern.

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

The consolidated financial statements include NRG Energy’s accounts and those of its subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of NRG Energy’s operations are in accordance with accounting principles generally accepted in the United States of America. As discussed in Note 10, NRG Energy has investments in partnerships, joint ventures and projects. Investments in such businesses in which NRG Energy does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. Earnings from equity in international investments are recorded net of foreign income taxes. The more significant accounting policies are as follows:

The principal business of NRG Energy is the ownership and operation, through its subsidiaries, of power generation facilities and the sale of energy, capacity and related products in the United States and internationally. NRG Energy also has investments in alternative energy, thermal and resource recovery facilities.

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.

Restricted cash consists primarily of cash collateral for letters of credit issued in relation to project development activities, funds held in trust accounts to satisfy the requirements of certain debt agreements and funds held within NRG Energy’s projects that are restricted in their use.

Inventory is valued at the lower of weighted average cost or market and consists principally of fuel oil, spare parts, coal, kerosene, emission allowance credits and raw materials used to generate steam.

Property, plant and equipment are stated at cost or the present value of minimum lease payments for assets under capital leases. 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 using the straight-line method 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 Energy 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.

Investments accounted for by the equity method are reviewed for impairment in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” APB Opinion No. 18 requires that a loss in value of an investment that is other than a temporary decline should be recognized. NRG Energy identifies and measures loss in value of equity investments based upon a comparison of fair value to carrying value.

Long-lived assets are classified as held for sale when all of the required criteria specified in SFAS No. 144 are met. These criteria include, among others, existence of a qualified plan to dispose of an asset, an assessment that completion of a sale within one year is probable and approval of the appropriate level of management and board of directors. Assets held for sale are reported at the lower of the asset’s carrying amount or fair value less cost to sell.

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 a project is terminated or construction ceased. Capitalized interest was approximately $64.8 million, $27.2 million, and $2.7 million in 2002, 2001 and 2000, respectively.

Development costs and capitalized project costs include third party professional services, permits, and other costs that 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 Energy’s Board of Directors. 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. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.

Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the terms of the related debt.

Goodwill represents the excess of the purchase price of net tangible and intangible assets acquired in business combinations over their estimated fair value. 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. Prior to 2002, goodwill was amortized on a straight line basis over 20 to 30 years.

Intangible assets represent contractual rights held by NRG Energy. Intangible assets are amortized over their economic useful life and reviewed for impairment on a periodic basis. Non-amortized intangible assets are tested for impairment annually and on an interim basis if an event or circumstance occurs between annual tests that might reduce the fair value of that asset.

Following the completion of Xcel Energy’s exchange offer on June 3, 2002, NRG and subsidiaries can rejoin the Xcel Energy’s group for federal income tax purposes provided the Internal Revenue Service (IRS) consents. Because it is likely that Xcel Energy will not request IRS consent to consolidate NRG Energy for income tax purposes in 2002, the income tax provision for NRG Energy, is based on a consolidated NRG Energy group through June 3, 2002 and separate corporate tax returns starting June 4, 2002 as discussed in Note 15. On a stand-alone basis, NRG Energy does not have the ability to recognize all tax benefits that may ultimately accrue from losses occurring in 2002. Deferred tax benefits have been recorded only to the extent a valuation allowance was not considered necessary. A current tax benefit has been recorded to the extent the 2002 tax losses can be carried back. Current tax expense has been recorded for those entities generating positive taxable income on a stand-alone basis in 2002.

In March 2001, NRG Energy was deconsolidated from Xcel Energy for federal income tax purposes. Prior to March 13, 2001, NRG Energy was included in the consolidated tax returns of Xcel Energy. NRG Energy calculated its income tax provision on a separate return basis under a tax sharing agreement with Xcel Energy. Current Federal and certain state income taxes were payable to or receivable from Xcel Energy.

Deferred income taxes are recognized for the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts at each year end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

NRG Energy is primarily an electric generation company, operating a portfolio of majority-owned electric generating plants and certain plants in which its ownership interest is 50% or less and which are accounted for under the equity method. In connection with its electric generation business, NRG Energy also produces thermal energy for sale to customers, principally through steam and chilled water facilities. NRG Energy also collects methane gas from landfill sites, which is used for the generation of electricity. In addition, NRG Energy sells small amounts of natural gas and oil to third parties.

Electrical energy revenue is recognized upon delivery to the customer. Capacity and ancillary revenue is recognized when contractually earned. Disputed revenues are not recorded in the financial statements until disputes are resolved and collection is assured.

Revenue from long-term power sales contracts that provide for higher pricing in the early years of the contract are recognized in accordance with Emerging Issues Task Force Issue No. 91-6, “Revenue Recognition of Long Term Power Sales Contracts.” This results in revenue deferrals and recognition on a levelized basis over the term of the contract.

NRG Energy provides contract operations and maintenance services to some of its non-consolidated affiliates. Revenue is recognized as contract services are performed.

NRG Energy uses the equity method of accounting to recognize as revenue its pro rata share of the net income or loss of unconsolidated investments.

NRG Energy recognizes other income for interest income on loans to affiliates as the interest is earned and realizable.

The local currencies are generally the functional currency of NRG Energy’s foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses and cash flows are translated at weighted-average rates of exchange for the period. The resulting currency translation adjustments are accumulated and reported as a separate component of stockholder’s equity and are not included in the determination of the results of operations. Foreign currency transaction gains or losses are reported in results of operations. NRG Energy recognized foreign currency transaction losses of $10.4 million, gains of $1.8 million and losses of $0.6 million in 2002, 2001 and 2000, respectively.

Financial instruments which potentially subject NRG Energy to concentrations of credit risk consist primarily of cash, accounts receivable, notes receivable and investments in debt securities. Cash accounts are generally held in Federally insured banks. Accounts receivable, notes receivable and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact NRG Energy’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 Energy believes the credit risk posed by industry concentration is offset 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. The carrying amounts of long-term receivables approximate fair value as the effective rates for these instruments are comparable to market rates at year end, including current portions. The fair value of long term debt is estimated based on quoted market prices and similar instruments with equivalent credit quality.

In 1995, the Financial Accounting Standard Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 123, “Accounting for Stock Based Compensation.” NRG Energy has elected to continue to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principle Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, NRG Energy records expense, in an amount equal to the excess of the quoted market price on the grant date over the option price. Such expense is recognized at the grant date for options fully vested. For options with a vesting period, the expense is recognized over the vesting period. As of June 3, 2002, all stock options were converted into Xcel Energy stock options.

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 the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

In recording transactions and balances resulting from business operations, NRG Energy uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, un-collectible accounts, and actuarially determined benefit costs 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.

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 Energy is required to adopt SFAS No. 143 on January 1, 2003. NRG Energy 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 Energy 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 the statement.

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 Energy.

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 14.

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 Energy.

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

The credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity experienced by NRG Energy 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 of this review, NRG Energy recorded asset impairment charges during 2002 totaling $2.5 billion for various projects in operation, under construction and in development as shown in the table below.

To determine whether an asset was impaired, NRG Energy 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 Energy’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 Energy’s financial position and liquidity constraints.

If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to write down the asset to its fair value. Estimates of fair value were based on appraisals, prices for similar assets and present value techniques.

Special charges from continuing operations included in Operating Expenses include the following:


(1)	Certain amounts have been combined from impairments disclosed in the September 30, 2002, Form 10-Q for turbines and other items.

All of these impairment charges relate to assets considered held for use under SFAS No. 144. Fair values determined by similar asset prices reflect NRG Energy’s current estimate of recoverability from expected marketing of project assets. Fair values determined by estimated market price represent market bids or appraisals received that NRG Energy believes is best reflective of value. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated future project operating costs, and expected plant operation given assumed market conditions.

Additional asset impairments may be recorded by NRG Energy in periods subsequent to December 31, 2002, given the changing business conditions and the resolution of the pending restructuring plan. Management is unable to determine the possible magnitude of any additional asset impairments, but they could be material.

NRG Energy recorded severance charges of $25.6 million for employees terminated during 2002 and $18.4 million remains accrued. Approximately $2.5 million of the accrual was reported in the December 31,

2002 balance sheet as part of post retirement and other benefit obligations, the remaining amount is recorded as accrued salaries, benefits and related costs.

The following table summarizes the activity related to accrued salaries, benefits and related costs for the twelve months ended December 31, 2002:

In addition, NRG Energy has engaged financial advisors, legal advisors, and other consultants to assist with restructuring NRG Energy’s operations. Costs for these professional services are expensed as incurred.

Pursuant to the requirements of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” NRG Energy has classified and is accounting for certain of its assets as held-for-sale at December 31, 2002. SFAS No. 144 requires that assets held for sale be valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions NRG Energy’s management considered cash flow analyses, bids and offers related to those assets and businesses. This amount is included in loss from discontinued operations in the accompanying Statement of Operations. In accordance with the provisions of SFAS No. 144, assets held for sale will not be depreciated commencing with its classification as such.

During 2002, NRG Energy entered into agreements to dispose of four consolidated international projects and one consolidated domestic project. Sales of four of the projects closed during 2002 (Bulo Bulo, Csepel, Entrade and Crockett Cogeneration) and one project (Killingholme) was sold in January 2003. In addition, NRG Energy has committed to a plan to sell a sixth project (Hsin Yu). Sale of this project is expected to be completed in 2003.

The financial results for all of these businesses have been accounted for as discontinued operations in 2002. Accordingly, operating results of prior periods have been restated to report the operations as discontinued.

Summarized results of operations of the discontinued operations were as follows:

Operating and other expenses for 2002 shown in the table above included asset impairment charges of approximately $599.7 million, comprised of approximately $477.9 million for the Killingholme project and $121.8 million for the Hsin Yu project.

The components of income tax (benefit) expense attributable to discontinued operations were as follows:

The assets and liabilities of the discontinued operations are reported in the December 31, 2002 and 2001 balance sheets as held for sale. The major classes of assets and liabilities held for sale by geographic area are as follows at December 31:

Included in other non-current assets held for sale is approximately $27.0 million (net of $3.6 million of amortization) of goodwill and $11.0 million (net of $1.9 million of amortization) of intangibles as of December 31, 2001. As of December 31, 2002, there are no amounts of goodwill or intangibles included in non-current assets held for sale.

Bulo Bulo — In June 2002, NRG Energy began negotiations to sell its 60% interest in Compania Electrica Central Bulo Bulo S.A. (Bulo Bulo), a Bolivian corporation. The transaction reached financial close in the fourth quarter of 2002 resulting in cash proceeds of $10.9 million (net of cash transferred of $8.6 million) and a loss of $10.6 million. NRG Energy accounted for the results of operations of Bulo Bulo as part of its power generation segment within the Other Americas region.

Crockett Cogeneration Project — In September 2002, NRG Energy announced that it had reached an agreement to sell its 57.7% interest in the Crockett Cogeneration Project, a 240 MW natural gas fueled cogeneration plant near San Francisco, California, to Energy Investment Fund Group, an existing LP, and a unit of GE Capital. In November 2002, the sale closed and NRG Energy realized net cash proceeds of approximately $52.1 million (net of cash transferred of $0.2 million) and a loss on disposal of approximately $11.5 million. NRG Energy accounted for the results of operations of Crockett Cogeneration as part of its power generation segment within North America.

Switzerland. The sales of Csepel and Entrade closed before year-end and resulted in cash proceeds of $92.6 million (net of cash transferred of $44.1 million) and a gain of approximately $24.0 million. NRG Energy accounted for the results of operations of Csepel and Entrade as part of its power generation segment within Europe.

Killingholme — During third quarter 2002 NRG Energy recorded an impairment charge of $477.9 million. In January 2003, NRG Energy completed the sale of its interest in the Killingholme project to its lenders for a nominal value and forgiveness of outstanding debt with a carrying value of approximately $360.1 million at December 31, 2002. The sale of NRG Energy’s interest in the Killingholme project and the release of debt obligations will result in a gain on sale in the first quarter of 2003 of approximately $182.3 million. The gain results from the write-down of the project’s assets in the third quarter of 2002 below the carrying value of the related debt. NRG Energy accounted for the results of operations of Killingholme as part of its power generation segment within Europe

Hsin Yu — During 2002 NRG Energy committed to sell its ownership interest in Hsin Yu located in Taiwan. During the third quarter of 2002, NRG Energy recorded an impairment charge of approximately $121.8 million for the Hsin Yu project. NRG Energy owns 60% with one other party owning the remaining minority interest. At the present time, NRG Energy is negotiating to sell its interest in the project to the minority owner for a nominal value plus assumption of its future funding obligations. No assurance can be provided that the negotiations will be successful and, if not, NRG Energy is committed to pursue other sales alternatives. NRG Energy accounted for the results of operations of Hsin Yu as part of its power generation segment within Asia Pacific.

Write downs and losses on sales of equity method investments recorded in operating expenses in the consolidated statement of operations includes the following:

During the fourth quarter of 2002, NRG Energy and the other owners of the Loy Yang project engaged in a joint marketing of the project for possible sale. In connection with these efforts, a new independent market valuation analysis was completed. Based on the new market valuation and negotiations with a potential purchaser, NRG Energy recorded an additional write-down of its investment in the amount of $57.8 million in the fourth quarter of 2002. At December 31, 2002 the carrying value of the investment in Loy Yang is approximately $72.9 million. Accumulated other comprehensive loss at December 31, 2002 includes a reduction for foreign currency translation losses of approximately $76.7 million related to Loy Yang. The foreign currency translation losses will continue to be included as a component of accumulated other comprehensive (loss) until NRG Energy commits to a plan to dispose of its investment, as required by EITF

Issue No. 01-05. NRG Energy accounts for the results of operations of its investment in Loy Yang as part of its power generation segment within the Asia Pacific region.

Kondapalli — On January 30, 2003, NRG Energy signed a sale agreement with the Genting Group of Malaysia (Genting) to sell NRG’s 30% interest in Lanco Kondapalli Power Pvt Ltd (Kondapalli) and a 74% interest in Eastern Generation Services (India) Pvt Ltd (the O&M company). Kondapalli is based in Hyderabad, Andhra Pradesh, India, and is the owner of a 368 MW natural gas fired combined cycle gas turbine. The sale to Genting has not yet been completed, although completion is expected in early second quarter of 2003. NRG Energy’s equity in the project is $35.2 million, and the proposed transaction will result in an after-tax loss to NRG Energy. In the fourth quarter of 2002, NRG Energy wrote down its investment in Kondapalli by $12.7 million due to recent developments related to the sale which indicate an impairment of its book value that is considered by NRG Energy to be other than temporary. NRG Energy accounts for the results of operations of its investment in Kondapalli as part of its power generation segment within the Asia Pacific region.

Powersmith — During the fourth quarter of 2002, NRG Energy wrote down its investment in Powersmith in the amount of approximately $3.4 million due to recent developments which indicate impairment of its book value that is considered by NRG Energy to be other than temporary. NRG Energy accounts for the results of operations of these investments as part of its power generation segment within the North America region.

Other — During 2002, NRG Energy wrote down other equity investments in the amount of approximately $11.3 million due to recent developments which indicate impairment of their book value that is considered by NRG Energy to be other than temporary. NRG Energy accounted for the results of operations of these investments as part of its alternative energy segment.

During 2002, NRG Energy entered into sales agreements to dispose of its non-controlling interests in seven projects that were accounted for by the equity method. As described below, six of these transactions closed during the year and one closed in January 2003. NRG Energy’s share of each project’s operating results through the respective disposal date is reported as equity in earnings from unconsolidated investments in the consolidated statement of operations. Losses on sales of equity method investments in the aggregate amount of approximately $57.4 million included in operating expenses is comprised of the net losses resulting from the seven disposal transactions.

Energy Development Limited — On July 25, 2002, NRG Energy announced it had signed an agreement for the sale of its ownership interests in an Australian energy company, Energy Development Limited (EDL). EDL is a listed Australian energy company engaged in the development and management of an international portfolio of projects with a particular focus on renewable and waste fuels. In August 2002, NRG Energy received proceeds of $78.5 million (AUS), or approximately $43.9 million (U.S.), in exchange for its ownership interest in EDL with the closing of the transaction. During the second quarter of 2002, NRG Energy recorded a loss of approximately $14.2 million on the sale. NRG Energy accounted for the results of operations of its investment in EDL as part of its power generation segment within the Asia Pacific region.

Collinsville Power Station — In August 2002, NRG Energy announced that it had completed the sale of its 50% interest in the 192 MW Collinsville Power Station in Australia, to its partner, a subsidiary of Transfield Services Limited. NRG Energy’s proceeds from the sale amounted to $8.6 million (AUS), or approximately $4.8 million (USD). NRG Energy recorded a loss of approximately $3.6 million (USD) from the sale during 2002. NRG Energy accounted for the results of operations of its investment in Collinsville Power Station as part of its power generation segment within the Asia Pacific region.

ECKG — In September 2002, NRG Energy announced that it had reached agreement to sell its 44.5% interest in the ECKG power station in connection with its Csepel power generating facilities, and its interest in Entrade, an electricity trading business, to Atel, an independent energy group headquartered in Switzerland. The transaction, closed in January 2003 and resulted in cash proceeds of $67.0 million and a net loss of $2.1 million. NRG Energy accounted for the results of operations of its investment in ECKG as part of its power generation segment within Europe.

Sabine River — In September 2002, NRG Energy agreed to transfer its indirect 50% interest in SRW Cogeneration LP (SRW) to its partner in SRW, Conoco, Inc. in consideration for Conoco’s agreement to terminate or assume all of the obligations of NRG Energy in relation to SRW. SRW is a cogeneration facility in Orange County, Texas. NRG Energy recorded a loss of approximately $48.4 million from the transfer during the quarter ended September 30, 2002. The transaction closed on November 5, 2002. NRG Energy accounted for the results of operations of its investment in SRW as part of its power generation segment within North America.

Mt. Poso — In September 2002, NRG Energy agreed to sell its 39.5% indirect partnership interest in the Mt. Poso Cogeneration Company, a California limited partnership (Mt. Poso) for approximately $10 million to Red Hawk Energy, LLC. Mt. Poso owns a 49.5 MW coal-fired cogeneration power plant and thermally enhanced oil recovery facility located 20 miles north of Bakersfield, California. The sale closed in November 2002 resulting in a loss of approximately $1.0 million. NRG Energy accounted for the results of operations of its investment in Mt. Poso as part of its power generation segment within North America.

Kingston — In December, 2002, NRG Energy completed the sale of its 25% interest in Kingston Cogeneration LP, based near Toronto, Canada to Northland Power Income Fund. NRG Energy received net proceeds of $15.0 million resulting in a gain on sale of approximately $9.9 million. NRG Energy accounted for the results of operations of its investment in Kingston as part of its power generation segment.

NEO MESI LLC — On November 26, 2002, NRG Energy completed the transfer of its 50% interest in MESI Fuel Station No. 1, LLC (“MESI”) to Power Fuel Partners (“PFP”) in exchange for the assumption by PFP of all NEO MESI LLC’s (“NEO MESI”) obligations under the MESI operating agreement, currently estimated at $21.6 million. MESI Fuel Station No. 1 is a facility, which produces and sells synthetic fuel (coal briquettes) from the Ken West terminal in Catlettsburg, Kentucky. The transfer did not result in any significant impact on the results of operations. NRG Energy accounted for the results of operations of its investment in MESI Fuel Station No. 1 as part of the NEO Corporation.

During 2001, NRG Energy completed numerous acquisitions. These acquisitions were recorded using the purchase method of accounting. Accordingly, the purchase prices were allocated to assets acquired and liabilities assumed based on their estimated fair values at the date of acquisition. Operations of the acquired companies have been included in the operations of NRG Energy since the date of the respective acquisitions.

In January 2001, NRG Energy purchased from LS Power, LLC a 5,339 MW portfolio of operating projects and projects in construction and advanced development that are located primarily in the north central and south central United States. Each facility employs natural gas-fired, combined-cycle technology. Through December 31, 2005, NRG Energy also has the opportunity to acquire ownership interests in an additional 3,000 MW of generation projects developed and offered for sale by LS Power and its partners.

In March 2001, NRG Energy purchased from Cogentrix the remaining 430 MW, or 51.37% interest, in an 837 MW natural gas-fired combined-cycle plant in Batesville, Mississippi. NRG Energy acquired a 48.63% interest in the plant in January 2001 from LS Power.

In June 2001, NRG Energy purchased a 640 MW natural gas-fired power plant in Audrain County, Missouri from Duke Energy North America LLC.

In June 2001, NRG Energy closed on the construction financing for the Brazos Valley generating facility, a 633 MW gas-fired power plant in Fort Bend County, Texas that NRG Energy will build, operate and manage. At the time of the closing, NRG Energy also became the 100% owner of the project by purchasing STEAG Power LLC’s 50% interest in the project. During January 2003, NRG Energy transferred its interest in the Brazos Valley project to its creditors.

In June 2001, NRG Energy purchased 1,081 MW of interests in power generation plants from a subsidiary of Conectiv. NRG Energy acquired a 100% interest in the 784 MW coal-fired Indian River Generating Station located near Millsboro, Delaware, and in the 170 MW oil-fired Vienna Generating Station located in Vienna, Maryland. In addition, NRG Energy acquired 64 MW of the 1,711 MW coal-fired Conemaugh Generating Station located approximately 60 miles east of Pittsburgh, Pennsylvania and 63 MW of the 1,711 MW coal-fired Keystone Generating Station located approximately 50 miles east of Pittsburgh, Pennsylvania.

In June 2001, NRG Energy purchased a 389 MW gas-fired power plant and a 116 MW thermal power plant, both of which are located on Csepel Island in Budapest, Hungary, from PowerGen. In April 2001, NRG Energy also purchased from PowerGen its interest in Saale Energie GmbH and its 33.3% interest in MIBRAG BV. By acquiring PowerGen’s interest in Saale Energie, NRG Energy increased its ownership interest in the 960 MW coal-fired Schkopau power station located near Halle, Germany from 200 MW to 400 MW.

By acquiring PowerGen’s interest in MIBRAG, an integrated energy business in eastern Germany consisting primarily of two lignite mines and three power stations, and following MIBRAG’s buy back of the shares NRG Energy acquired from PowerGen, NRG Energy increased its ownership of MIBRAG from 33.3% to 50%. The Washington Group International, Inc., owns the remaining 50% of MIBRAG.

In August 2001, NRG Energy acquired from Indeck Energy Services, Inc. an approximately 2,255 MW portfolio of operating projects and projects in advanced development, that are located in Illinois and upstate New York.

In August 2001, NRG Energy acquired Duke Energy’s 77% interest in the approximately 520 MW natural-gas fired McClain Energy Generating Facility located near Oklahoma City, Oklahoma. The Oklahoma Municipal Power Authority owns the remaining 23% interest. The McClain facility commenced operations in June 2001.

In September 2001, NRG Energy acquired a 50% interest in TermoRio SA, a 1,040 MW gas-fired cogeneration facility currently under construction in Rio de Janeiro State, Brazil, from Petroleos Brasileiros SA (Petrobras). Commercial operation of the facility is expected to begin in March 2004. NRG Energy has the option to put its interest in the project back to Petrobras after March 2002 if by that time certain milestones have not been met, including final agreement on the terms of all project documents.

During fiscal year 2001, NRG Energy also acquired other minor interests in projects in Taiwan, India, Peru and the State of Nevada.

The respective purchase prices have been allocated to the net assets of the acquired entities as follows:

In July 2001, NRG Energy signed agreements to acquire from Edison Mission Energy a 50% interest in the 375 MW Commonwealth Atlantic gas and oil-fired generating station located near Chesapeake, Virginia, and a 50% interest in the 110 MW James River coal-fired generating facility in Hopewell, Virginia. NRG Energy closed the acquisition of the Commonwealth Atlantic and James River generating facilities in January 2002, for $11.2 million and $6.5 million, respectively.

Conectiv — In April 2002, NRG Energy terminated its purchase agreement with a subsidiary of Conectiv to acquire 794 MW of generating capacity and other assets, including an additional 66 MW of the Conemaugh Generating Station and an additional 42 MW of the Keystone Generating Station. The purchase price for these assets was approximately $230 million. No incremental costs were incurred by NRG Energy related to the termination of this agreement.

FirstEnergy — In November 2001, NRG Energy signed purchase agreements to acquire or lease a portfolio of generating assets from FirstEnergy Corporation. Under the terms of the agreements, NRG Energy agreed to pay approximately $1.6 billion for four primarily coal-fueled generating stations.

On July 2, 2002, the Federal Energy Regulatory Commission (FERC) issued an order approving the transfer of FirstEnergy generating assets to NRG Energy; however, the FERC conditioned the approval on NRG Energy’s assumption of FirstEnergy’s obligations under a separate agreement between FirstEnergy and the City of Cleveland. These conditions required FirstEnergy to protect the City of Cleveland in the event the generating assets are taken out of service. On July 16, 2002, FERC clarified that the condition would require NRG Energy to provide notice to the City of Cleveland and FirstEnergy if the generating assets were taken out of service and that other obligations remain with FirstEnergy.

On August 8, 2002, FirstEnergy notified NRG Energy that the agreements regarding the transfer of generating assets from FirstEnergy to NRG Energy had been cancelled. FirstEnergy cited the reason for canceling the agreements as an alleged anticipatory breach of certain obligations in the agreements by NRG Energy. On February 27, 2003, FirstEnergy gave NRG Energy notice that it was commencing arbitration against NRG Energy to determine whether NRG Energy is liable to FirstEnergy for failure to close the transaction. NRG Energy believes it has meritorious defenses against FirstEnergy’s claim and intends to

vigorously defend its position. No amount has been accrued for this contingency. Management is unable to predict the ultimate outcome of this matter, however, an adverse decision could be material to NRG Energy’s financial position and results of operations.

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

Included in construction in progress at December 31, 2002 is approximately $248.9 million related to turbines associated with cancelled projects.

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

NRG Energy has investments in various international and domestic energy projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents NRG Energy from exercising a controlling influence over operating and financial policies of the projects. Under this method, equity in pretax income or losses of domestic partnerships and, generally, in the net income or losses of international projects, are reflected as equity in earnings of unconsolidated affiliates.

A summary of certain of NRG Energy’s equity-method investments which were in operation at December 31, 2002 is as follows:

Summarized financial information for investments in unconsolidated affiliates accounted for under the equity method as of and for the year ended December 31, is as follows:

NRG Energy has a 50% interest in one company (West Coast Power LLC) that was considered significant as of December 31, 2001, as defined by applicable SEC regulations, and accounts for its investment

using the equity method. The following table summarizes financial information for West Coast Power LLC, including interests owned by NRG Energy and other parties for the periods shown below:

NRG Energy and Xcel Energy have entered into material transactions and agreements with one another. Certain material agreements and transactions currently existing between NRG Energy and Xcel Energy are described below.

NRG Energy has two agreements with Xcel Energy for the purchase of thermal energy. Under the terms of the agreements, Xcel Energy charges NRG Energy for certain costs (fuel, labor, plant maintenance, and auxiliary power) incurred by Xcel Energy to produce the thermal energy. NRG Energy paid Xcel Energy $8.2 million, $7.1 million and $5.5 million in 2002, 2001 and 2000, respectively, under these agreements. One of these agreements expired on December 31, 2002 and the other expires on December 31, 2006.

NRG Energy has a renewable 10-year agreement with Xcel Energy, expiring on December 31, 2006, whereby Xcel Energy agreed to purchase refuse-derived fuel for use in certain of its boilers and NRG Energy agrees to pay Xcel Energy a burn incentive. Under this agreement, NRG Energy received $1.2 million, $1.6 million and $1.5 million from Xcel Energy, and paid $3.3 million, $2.8 million and $2.8 million to Xcel Energy in 2002, 2001 and 2000, respectively.

NRG Energy has an administrative services agreement in place with Xcel Energy. Under this agreement NRG Energy reimburses Xcel Energy for certain overhead and administrative costs, including benefits

administration, engineering support, accounting, and other shared services as requested by NRG Energy. In addition, NRG Energy employees participate in certain employee benefit plans of Xcel Energy as discussed in Note 16. NRG Energy reimbursed Xcel Energy in the amounts of $21.2 million, $12.2 million and $5.9 million, during 2002, 2001 and 2000, respectively, under this agreement.

NRG Energy has an agreement with e prime, a wholly owned subsidiary of Xcel Energy, under which e prime provides natural gas marketing and trading from time to time and NRG Energy’s request. NRG Energy paid $19.2 million to e prime in 2002.

Included in accounts payable affiliate is approximately $42.9 of amounts owed to Xcel Energy at December 31, 2002.

Notes receivable consists primarily of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. The notes receivable as of December 31, are as follows:

Saale Energie GmbH (SEG) has a long-term electricity supply contract with its sole customer, VEAG. SEG supplies its total available electricity capacity to VEAG. The contract has a term of 25 years. VEAG is obligated to pay on a monthly basis a price that covers the availability of power supply capacity and the operating costs incurred to produce electricity. During 2002 and the nine months subsequent to NRG Energy’s consolidation of SEG in March 2001, approximately $46.0 million and $56.3 million, respectively, was recognized as revenue under this agreement. NRG Energy expects SEG to recognize revenues of approximately $40 million each year under this agreement.

Investment in bonds is comprised of marketable debt securities. These securities consist of municipal bonds of Audrain County, Missouri and Jackson County, Mississippi. The Audrain County bonds mature in 2023 and the Jackson County bonds mature in 2010. These investments in bonds are classified as held to maturity and are recorded at amortized cost. The carrying value of these bonds approximates fair value. Both the Audrain County bonds Jackson County bonds are pledged as collateral for the related debt owed to each county. As further described in Note 13 each of these transactions have offsetting obligations.


(1)	NRG Energy has not reclassified the long term portions of these debt issuances to current as they are not currently callable within one year from the balance sheet date.

As of December 31, 2002, NRG Energy has failed to make scheduled payments on interest and/or principal on approximately $4.0 billion of its recourse debt and is in default under the related debt instruments. These missed payments also have resulted in cross-defaults of numerous other non-recourse and limited recourse debt instruments of NRG Energy. In addition to the missed debt payments, a significant amount of NRG Energy’s debt and other obligations contain terms, which require that they be supported with letters of credit or cash collateral following a ratings downgrade. As a result of the downgrades that NRG Energy has experienced in 2002, NRG Energy estimates that it is in default of its obligations to post collateral of approximately $1.1 billion, principally to fund equity guarantees associated with its construction revolver

financing facility, to fund debt service reserves and other guarantees related to NRG Energy projects and to fund trading operations. In early November 2002, NRG Energy presented a restructuring plan to its creditors.

In mid-December 2002, the NRG Energy bank steering committee submitted a counter-proposal to the restructuring plan. In January 2003, a new restructuring proposal was presented to the creditors and negotiations are ongoing. On March 26, 2003, Xcel Energy announced that its board of directors had approved a tentative settlement agreement with holders of most of NRG Energy’s long-term notes and the steering committee representing NRG Energy’s bank lenders. The settlement is subject to certain conditions, including the approval of at least a majority in dollar amount of the NRG Energy bank lenders and long-term noteholders and definitive documentation. There can be no assurance that such approvals will be obtained. The terms of the settlement call for Xcel Energy to make payments to NRG Energy over the next 13 months totaling up to $752 million for the benefit of NRG Energy’s creditors in consideration for their waiver of an 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.

Absent an agreement on a comprehensive restructuring plan, NRG Energy will remain in default under its debt and other obligations, because it does not have sufficient funds to meet such requirements and obligations. As a result, the lenders will be able, if they so choose, to seek to enforce their remedies at any time, which would likely lead to a bankruptcy filing by NRG Energy. There can be no assurance that NRG Energy’s creditors ultimately will accept any consensual restructuring plan, or that, in the interim, NRG Energy’s lenders and bondholders will continue to forbear from exercising any or all of the remedies available to them, including acceleration of NRG Energy’s indebtedness, commencement of an involuntary proceeding in bankruptcy and, in the case of certain lenders, realization on the collateral for their indebtedness.

Pending the resolution of NRG Energy’s credit contingencies, NRG Energy has classified as current liabilities those long-term debt obligations that lenders have the ability to accelerate within twelve months of the balance sheet date.

In March 2002, NRG Energy’s $500 million recourse revolving credit facility matured and was replaced with a $1.0 billion 364-day revolving line of credit, which matured on March 7, 2003. The facility is unsecured and provides for borrowings of “Base Rate Loans” and “Eurocurrency Loans”. The Base Rate Loans bear interest at the greater of the Administrative Agent’s prime rate or the sum of the prevailing per annum rates for overnight funds plus 0.5% per annum, plus an additional margin which varies from 0.375% to 0.50% based upon NRG Energy’s utilization of the facility and its then-current senior debt credit rating. The Eurocurrency loans bear interest at an adjusted rate based on LIBOR plus an adjustment percentage, which varies depending on NRG Energy’s senior debt credit rating and the amount outstanding under the facility. The credit agreement for this facility was amended in April 2002 to revise the interest coverage ratio covenant. As amended, the covenant requires NRG Energy to maintain a minimum interest coverage ratio of 1.75 to 1, as determined at the end of each fiscal quarter. The facility contains additional covenants that, among other things, restrict the incurrence of liens and require NRG Energy to maintain a net worth of at least $1.5 billion plus 25% of NRG Energy’s consolidated net income from January 1, 2002 through the determination date. In addition, NRG Energy must maintain a debt to capitalization ratio of not more than 0.68 to 1.00 as defined in the credit agreement. The failure to comply with any of these covenants would be an Event of Default under the terms of the credit agreement. At December 31, 2002, NRG Energy had a $1.0 billion outstanding balance under this credit facility. As of December 31, 2002, the weighted average interest rate of such outstanding advances was 5.14% per year. NRG Energy missed a $7.6 million interest payment due on September 30, 2002, and as of that date, NRG Energy violated both the minimum net worth covenant and the minimum interest coverage ratio. NRG Energy also failed to make a fourth quarter interest payment of approximately

$18.6 million due December 31, 2002. On February 27, 2003, ABN AMRO issued a notice on default on the corporate revolver financing facility, rendering the debt immediately due and payable. The recourse revolving credit facility matured on March 7, 2003 and the $1 billion drawn remains outstanding. Accordingly, the facility is in default.

NRG Energy’s $125 million syndicated letter of credit facility contains terms, conditions and covenants that are substantially the same as those in NRG Energy’s $1.0 billion 364-day revolving line of credit. During the second quarter of 2002, the letter of credit facility agreement was amended to incorporate the same covenant revisions and other amendments that had previously been made to the terms and conditions of NRG Energy’s $1.0 billion revolving credit facility, including the addition of an interest coverage ratio covenant. As of December 31, 2002, NRG Energy violated both the minimum net worth covenant and the minimum interest coverage ratio. Accordingly, the facility is in default. NRG Energy had $110 million and $170 million in outstanding letters of credit as of December 31, 2002 and 2001, respectively.

As of December 31, 2001, NRG Energy, through its wholly owned subsidiary, NRG South Central Generating LLC, had outstanding approximately $40 million under a project level, non-recourse revolving credit agreement which matured in March 2002. During the period ended December 31, 2001, the weighted average interest rate of such outstanding advances was 4.46%. NRG South Central extended this facility in March 2002, for an additional 3 months, on substantially similar terms. NRG South Central paid down the outstanding balance in June 2002. The weighted average interest rate for the three months ended June 30, 2002 was 3.1%. As of December 31, 2002, this facility no longer exists.

In January 2001, NRG Energy entered into a bridge credit agreement with a final maturity date of December 31, 2001. Approximately $600 million was borrowed under this facility to partially finance NRG Energy’s acquisition of the LS Power generation assets. In March 2001, the bridge credit facility was repaid with proceeds from NRG Energy’s offering of common stock and equity units.

In June 2001, NRG Energy entered into a $600 million term loan facility. The facility was unsecured and provided for borrowings of base rate loans and Eurocurrency loans. The facility terminated on June 21, 2002. As of December 31, 2001, the aggregate amount outstanding under this facility was $600 million. During the period ended December 31, 2001 the weighted average interest rate of such outstanding advances was 3.94%. NRG Energy repaid this facility in March 2002, in connection with the closing of its new $1.0 billion unsecured corporate-level revolving line of credit and the receipt of $300 million of cash from Xcel Energy.

On March 13, 2001, NRG Energy completed the sale of 11.5 million equity units for an initial price of $25 per unit. The 11.5 million equity units sold included 1.5 million units sold pursuant to the underwriters’ over-allotment option. NRG Energy received gross proceeds from the issuance of $287.5 million. Net proceeds from this issuance were $278.4 million after deducting underwriting discounts, commissions and estimated offering expenses. Each equity unit initially consists of a corporate unit comprising a $25 principal amount of NRG Energy’s senior debentures and an obligation to acquire shares of NRG Energy common stock no later than May 18, 2004 at a price ranging from between $27.00 and $32.94. Approximately $4.1 million of the gross proceeds have been recorded as additional paid in capital to reflect the value of the obligation to purchase NRG Energy’s common stock. Interest payments will be payable on the debentures quarterly in arrears on each February 16, May 16, August 16 and November 16, commencing May 16, 2001. Interest will be payable initially at an annual rate of 6.50% of the principal amount of $25 per debenture to, but excluding, February 17, 2004, or May 18, 2004. If the interest rate is not reset three business days prior to February 17, 2004 or three business days prior to May 18, 2004, the debentures will bear interest from February 17, 2004, or May 18, 2004, as applicable, at the reset rate to, but excluding, May 16, 2006. In

addition, original issued discount will accrue on the debentures. The net proceeds were used in part to reduce amounts outstanding under NRG Energy’s $600 million short-term bridge credit agreement, which was used to finance in part NRG Energy’s acquisition of LS Power generation assets. As a result of the merger by Xcel Energy of NRG, holders of the NRZ equity units are no longer obligated to purchase shares of NRG common stock under the purchase contracts. Instead, holders of the equity units are now obligated to purchase a number of shares of Xcel Energy common stock upon settlement of the purchase contracts equal to the adjusted “settlement rate” or the adjusted “early settlement rate” as applicable. As a result of the short-form merger, the adjusted settlement rate is 0.4630 and the adjusted early settlement rate is 0.3795, subject to the terms and conditions of the purchase contracts set forth in a purchase contract agreement. On October 29, 2002, NRG Energy announced it would not make the November 16, 2002 quarterly interest payment on the 6.50% senior unsecured debentures due in 2006, which trade with the associated purchase contracts as NRG corporate units (NRZ). The 30-day grace period to make payment ended December 16, 2002, and NRG Energy did not make payment to the NRZ holders and, as a result, this issue is in default. In addition, NRG Energy did not make the February 17, 2003 quarterly interest payment. In the event of an NRG Energy bankruptcy, the obligation to purchase shares of Xcel Energy stock terminates.

In April 2001, NRG Energy issued $690 million of senior notes in two tranches. The first tranche of $350 million matures in April 2011 and bears an interest rate of 7.75%. The second tranche of $340 million matures in April 2031 and bears an interest rate of 8.625%. Interest on the notes is due semi-annually each April and October. The net proceeds of the issuance were used for repayment of short-term indebtedness incurred to fund acquisitions, for investments, general corporate purposes and to provide capital for future planned acquisitions.

In June 2001, NRG filed a shelf registration with the SEC to sell up to $2 billion in debt securities, common and preferred stock, warrants and other securities. Approximately $1.5 billion remains outstanding under this shelf registration filing as of December 31, 2002.

In July 2001, NRG Energy completed the sale of $500 million of unsecured senior notes under this shelf registration. The senior notes were issued in two tranches, the first tranche of $340 million of 6.75% Senior Notes is due July 2006 and the second tranche of $160 million of 8.625% Senior Notes is due April 2031. Interest payments are due semi-annually on January 15 and July 15 until maturity for the Senior Notes due 2006 and April 1 and October 1 until maturity for the Senior Notes due 2031. NRG received net proceeds from the sale of both series of notes of approximately $505.2 million, including interest on the senior notes due 2031, accrued from April 5, 2001. The net proceeds were used to repay all amounts outstanding under NRG’s revolving credit agreement and for investments and other general corporate purposes and to provide capital for planned acquisitions. On October 1, 2002, NRG Energy failed to make a $13.6 million interest payment on the $350 million 7.75% senior unsecured notes due 2011, a $11.5 million interest payment due on the $340 million of 6.75% senior unsecured notes due 2006, and a $21.6 million payment on the combined $500 million of 8.625% senior unsecured notes due 2031. The 30-day grace period to make payment related to these issues has passed and NRG Energy did not make the required payments. NRG Energy is in default on these notes.

In March 2000, an NRG Energy sponsored non-consolidated pass through trust issued $250 million of 8.70% certificates due March 15, 2005. Each certificate represents a fractional undivided beneficial interest in the assets of the trust. Interest is payable on the certificates semi-annually on March 15 and September 15 of each year through 2005. The sole assets of the trust consist of £160 million (approximately $250 million on the date of issuance) principal amount 7.97% Reset Senior Notes due March 15, 2020 issued by NRG Energy. The Reset Senior Notes were used principally to finance NRG Energy’s acquisition of the Killingholme facility. Interest is payable semi-annually on the Reset Senior Notes on March 15 and September 15 through March 15, 2005, and then at intervals and interest rates established in a remarketing process. If the Reset Senior Notes are not remarketed on March 15, 2005, they must be mandatorily redeemed by NRG Energy on

such date. On September 16, 2002, NRG Pass- through Trust I failed to make a $10.9 million interest payment due on the $250 million bonds, as a consequence of NRG Energy failing to pay interest due on £160 million of 7.97% debt. The 30-day grace period to make payment related to this issue has passed and NRG Energy did not make the required payments, NRG Energy is in default on these bonds.

The NRG Energy senior notes are unsecured and are used to support equity requirements for projects acquired and in development. Interest is paid semi-annually.

The NRG Energy $125 million, $250 million, $300 million, $350 million, and $240 million senior notes are unsecured and are used to support equity requirements for projects acquired and in development. The interest is paid semi-annually and mature in February 2006, June 2007, June 2009, September 2010, and November 2013, respectively. On September 16, 2002, NRG Energy failed to make a $14.4 million interest payment due on $350 million of 8.25% senior unsecured notes due in 2010. On November 1, 2002, NRG Energy failed to make a $9.6 million interest payment due on $240 million of 8.0% senior unsecured notes due in 2013. On December 31, 2002, NRG Energy failed to make an $11.3 million interest payment due on $300 million of 7.5% senior unsecured notes due in 2009. On December 15, 2002, NRG Energy failed to make a $9.4 million interest payment due on $250 million of 7.5% senior unsecured notes due in 2007. On February 1, 2003, NRG Energy failed to make a $4.8 million interest payment due on the $125 million of 7.625% senior unsecured notes due 2006. The 30-day grace period to make payment related to these issues has passed and NRG Energy did not make the required payments, and NRG Energy is in default on these notes.

The $240 million NRG Energy Senior notes due November 1, 2013 are ROARS. November 1, 2003 is the first remarketing date for these notes. Interest is payable semi-annually on May 1, and November 1, of each year through 2003, and then at intervals and interest rates as discussed in the indenture. On the remarketing date, the notes must either be mandatorily tendered to and purchased by Credit Suisse Financial Products or mandatorily redeemed by NRG Energy at prices discussed in the indenture. The notes are unsecured debt that rank senior to all of NRG Energy’s existing and future subordinated indebtedness. On October 16, 2002 NRG Energy entered into a Termination Agreement with the agent CSFB that, terminated the Remarketing Agreement. A termination payment of $31.4 million due on October 17, 2002 has not been paid.

In May 2001, NRG Energy’s wholly-owned subsidiary, NRG Finance Company I LLC, entered into a $2 billion revolving credit facility. The facility was established to finance the acquisition, development and construction of power generating plants located in the United States and to finance the acquisition of turbines for such facilities. The facility provides for borrowings of base rate loans and Eurocurrency loans and is secured by mortgages and security agreements in respect of the assets of the projects financed under the facility, pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects, and by guaranties from each such subsidiary or affiliate. Provided that certain conditions are met that assure the lenders that sufficient security remains for the remaining outstanding loans, the borrower may repay loans relating to one project and have the liens relating to that project released. Loans that have been repaid may be re-borrowed, as permitted by the terms of the facility. The facility terminates on May 8, 2006. The facility is non-recourse to NRG Energy other than its obligation to contribute equity at certain times in respect of projects and turbines financed under the facility. NRG Energy estimates the obligation to contribute equity to be approximately $819 million as of December 31, 2002. As of December 31, 2002 and 2001, the aggregate amount outstanding under this facility was $1.08 billion and $697.5 million, respectively. During the period ended December 31, 2002 and 2001, the weighted average interest rate of such outstanding advances was 4.92% and 4.83%, respectively. At December 31, 2002, interest and fees due in September 2002 were not paid

and NRG Energy has suspended required equity contributions to the projects. Supporting construction and other contracts associated with NRG Energy’s Pike and Nelson projects were violated by NRG Energy, in September and October 2002, respectively. NRG Energy is in default of this agreement and on November 6, 2002, lenders to NRG Energy accelerated the approximately $1.08 billion of debt under the construction revolver facility, rendering the debt immediately due and payable.

As part of NRG Energy’s acquisition of the LS Power assets in January 2001, NRG Energy, through its wholly owned subsidiary, LSP Kendall Energy LLC, acquired a $554.2 million credit facility. The facility is non-recourse to NRG Energy and consists of a construction and term loan, working capital and letter of credit facilities. As of December 31, 2002 and 2001, there were borrowings totaling approximately $495.8 million and $499.5 million, respectively, outstanding under the facility at a weighted average annual interest rate of 3.19% and 5.12%, respectively. In May 2002, LSP-Kendall Energy, LLC received a notice of default from Societie General, the administrative agent under LSP-Kendall’s Credit and Reimbursement Agreement dated November 12, 1999. The notice asserted that an event of default had occurred under the Credit and Reimbursement Agreement as a result of liens filed against the Kendall project by various subcontractors. In consideration of the borrower’s implementation of a plan to remove the liens, and NRG Energy’s indemnification pursuant to an Indemnity Agreement dated June 28, 2002, of the lenders to the Kendall project from any claims or damages relating to these liens or any dispute or action involving the projects EPC contractor, the administrative agent, with the consent of the required lenders under the Credit and Reimbursement Agreement, withdrew the notice of default and conditionally waived any default or event of default described therein. Discussions with the administrative agent regarding the liens continue. On January 10, 2003, NRG Energy received a notice of default from LSP Kendall’s lenders indicating that certain events of default have taken place and that by issuing this notice of default the lenders have preserved all of their rights and remedies under the Credit Agreement and other Credit Documents. NRG Energy is negotiating a waiver to this default notice with the creditors to LSP Kendall.

Upon the acquisition of the LS Power assets, a subsidiary of NRG Energy assumed approximately $326 million of bonds outstanding originally issued to finance the construction of the Batesville generation plant. In May 1999, LSP Energy Limited Partnership (Partnership) and LSP Batesville Funding Corporation (Funding) issued two series of Senior Secured Bonds (Bonds) in the following total principle amounts: $150 million 7.16% Series A Senior Secured Bonds due 2014 and $176 million 8.160% Series B Senior Secured Bonds due 2025. Interest is payable semiannually on each January 15 and July 15. In March 2000, a registration statement was filed by Partnership and Funding and became effective. The registration statement was filed to allow the exchange of the Bonds for two series of debt securities (Exchange Bonds), which are in all material respects substantially identical to the Bonds. The Exchange Bonds are secured by substantially all of the personal property and contract rights of the Partnership and Funding. The Exchange Bonds are redeemable, at the option of Partnership and Funding, at any time in whole or from time to time in part, on not less than 30 nor more than 60 days prior notice to the holders of that series of Exchange Bonds, on any date prior to their maturity at a redemption price equal to 100% of the outstanding principal amount of the Exchange Bonds being redeemed and a make whole premium. In no event will the redemption price ever be less than 100% of the principal amount of the Exchange Bonds being redeemed plus accrued and unpaid interest thereon. Principal payments are payable on each January 15 and July 15 beginning July 15, 2001.

In March 2001, NRG Energy increased its ownership interest in Penobscot Energy Recovery Company (PERC), which resulted in the consolidation of its equity investment in PERC. As a result, the assets and liabilities of PERC became part of the assets and liabilities of NRG Energy. Upon completion of the transaction, NRG Energy recorded approximately $37.9 million of outstanding Finance Authority of Maine (FAME) Electric Rate Stabilization Revenue Refunding Bonds Series 1998 (FAME bonds) which were issued on PERC’s behalf by FAME in June 1998. The face amount of the bonds that were initially issued was approximately $44.9 million and was used to repay the Floating Rate Demand Resource Revenue Bonds issued by the Town of Orrington, Maine on behalf of PERC. The FAME bonds are fixed rate bonds with

yields ranging from 3.75% to 5.2%. The weighted average yield on the FAME bonds is approximately 5.1%. The FAME bonds are subject to mandatory redemption in annual installments of varying amounts through July 1, 2018. Beginning July 1, 2008 the FAME bonds are subject to redemption at the option of PERC at a redemption price equal to 102% through June 30, 2009, 101% for the period July 1, 2009 to June 30, 2010 and 100% thereafter, of the principal amount outstanding, plus accrued interest. The loan agreement with FAME contains certain restrictive covenants relating to the FAME bonds, which restrict PERC’s ability to incur additional indebtedness, and restricts the ability of the general partners to sell, assign or transfer their general partner interests. The bonds are collateralized by liens on substantially all of PERC’s assets. As of December 31, 2002, there remains $28.7 million of bonds outstanding.

On June 22, 2001, NRG MidAtlantic Generating LLC (MidAtlantic), a wholly owned subsidiary of NRG Energy, borrowed approximately $420.9 million under a five year term loan agreement (Agreement) to finance, in part, the acquisition of certain generating facilities from Conectiv. The Agreement terminates in November 2005 and provides for a total credit facility of $580 million. Interest is payable quarterly. The debt is guaranteed by MidAtlantic and its wholly owned subsidiaries. The Agreement provides for a variable interest rate at either the higher of the Prime rate or the Federal Funds rate plus 0.50%, or the London Interbank Offered Rate (LIBOR) of interest. During the period ended December 31, 2002 and 2001, the weighted average interest rate for amounts outstanding under the Agreement was 3.30% and 4.56%, respectively. MidAtlantic is obligated to pay a commitment fee of 0.375% of the unused portion of the credit facility. The Agreement requires MidAtlantic to comply with certain covenants concerning limitations on additional borrowings, sales of assets, capital expenditures, and payment of dividends or other distributions to shareholders.

In June 2001, NRG Energy through its wholly owned subsidiaries, Brazos Valley Energy LP and Brazos Valley Technology LP, entered into a $180 million non-recourse construction credit facility to fund the construction of the 600 MW Brazos Valley gas-fired combined cycle merchant generation facility located in Fort Bend County, Texas. On October 8, 2002, bank lenders and the project company executed amendments to the loan documents that provided for additional advances to fund certain construction costs. As of December 31, 2002, there existed an outstanding balance of $194.4 million under this credit agreement. The weighted average interest rate as of December 31, 2002 and 2001 was 4.41% and 4.61%, respectively. Interest is payable quarterly. On January 31, 2003, NRG Energy consented to the foreclosure of its Brazos Valley project by its lenders. As consequence of foreclosure, NRG Energy no longer has any interest in the Brazos Valley project, however, NRG Energy may be obligated to infuse additional amounts of capital to fund a debt service reserve account that had never been funded and may be obligated to make an equity infusion to satisfy a contingent equity agreement.

In connection with NRG Energy’s acquisition of the COBEE facilities, NRG Energy recorded on its balance sheet approximately $56.3 million of non-recourse long-term debt that is due in 18 semi-annual installments of varying amounts beginning January 31, 1999 and ending July 31, 2007. The loan agreement provides an A Loan of up to $30 million and a B Loan of up to $45 million. Interest is payable semi-annual in arrears at a rate equal to 6-month LIBOR plus a margin of 4.5% on the A Loan and 6-month LIBOR plus a margin of 4.0% on the B Loan. The A Loan and the B Loan are collateralized by a mortgage on substantially all of COBEE’s assets.

In August 2001, NRG Energy entered into a 364-day term loan of up to $296 million. The credit facility was structured as a senior unsecured loan and was partially non-recourse to NRG Energy. The proceeds were used to finance the McClain generating facility acquisition. In November 2001, the credit facility was repaid from the proceeds of a $181.0 million term loan and $8.0 million working capital facility entered into by NRG McClain LLC, with Westdeutsche Landesbank Girozentrale, New York branch, as agent (non-recourse to NRG Energy). The final maturity date of the facility is November 30, 2006. As of December 31, 2002 and 2001, the aggregate amount outstanding under this facility was $157.3 million and $159.9 million, respectively.

During the period ended December 31, 2002 and 2001, the weighted average interest rate of such outstanding borrowings was 4.57% and 5.07%, respectively. On September 17, 2002, NRG McClain LLC received notice from the agent bank that the project loan was in default as a result of the downgrade of NRG Energy and of defaults on material obligations under the Energy Management Services Agreement.

In connection with NRG Energy’s acquisition of the Audrain facilities, NRG Energy has recognized a capital lease on its balance sheet within long-term debt in the amount of $239.9 million, as of December 31, 2002 and 2001. The capital lease obligation is recorded at the net present value of the minimum lease obligation payable. The lease terminates in May 2023. During the term of the lease only interest payments are due, no principal is due until the end of the lease. In addition, NRG Energy has recorded in notes receivable, an amount of approximately $239.9 million, which represents its investment in the bonds that the county of Audrain issued to finance the project. During December 2002, NRG Energy received a notice of a waiver of a $24.0 million interest payment due on the capital lease obligation.

In connection with NRG Energy’s purchase of PowerGen’s interest in Saale Energie GmbH, NRG Energy has recognized a non-recourse capital lease on its balance sheet within long-term debt in the amount of $333.9 million and $311.9 million, as of December 31, 2002 and 2001, respectively. The capital lease obligation is recorded at the net present value of the minimum lease obligation payable over the lease’s remaining period of 20 years. In addition, a direct financing lease was recorded in notes receivable in the amount of approximately $366.4 million and $318.9 million, as of December 31, 2002 and 2001, respectively.

In July 2002, NRG Energy Center Minneapolis LLC (ECM), an indirect wholly owned subsidiary of NRG Energy, entered into an agreement allowing it to issue senior secured promissory notes in the aggregate principal amount of up to $150 million. In July 2002, under this agreement, ECM issued $75 million of bonds in a private placement. Two series of notes were issued in July 2002, the $55 million Series A-Notes dated July 3, 2002, which matures on August 1, 2017 and bears an interest rate of 7.25% per annum and the $20 million Series B-Notes dated July 3, 2002, which matures on August 1, 2017 and bears an interest rate of 7.12% per annum. NRG Thermal LLC, a wholly owned subsidiary of NRG Energy, which owns 100% of ECM, pledged its interests in all of its district heating and cooling investments throughout the United States as collateral. NRG Thermal and ECM are required to maintain compliance with certain financial covenants primarily related to incurring debt, disposing of assets, and affiliate transactions. NRG Thermal and ECM were in compliance with these covenants at December 31, 2002.

On October 30, 2002 NRG Energy failed to make $3.1 million in payments under certain Non-Operating Interest Acquisition agreements. As a result, NEO Corporation, a direct wholly-owned subsidiary of NRG Energy and NEO Landfill Gas, Inc., an indirect wholly-owned subsidiary of NRG Energy, failed to make approximately $1.4 million in payments under the Amended and Restated Construction, Acquisition and Term Loan Agreement, dated July 6, 1998. Also, the subsidiaries of NEO Corporation and NEO Landfill Gas, Inc. failed to make approximately $2 million in payments pursuant to various Site Development Operations and Coordination Agreements. NRG Energy received an extension until November 19, 2002 with respect to NEO Landfill Gas, Inc. to make payments under such agreements and such payments were made during the extension period.- The payments relating to NEO Corporation were not made and the loan was due and payable on December 20, 2002. A letter of credit was drawn to pay the NEO Corporation loan in full on December 23, 2002. As of December 31, 2002, NEO Landfill Gas, Inc. was in default under the Amended and Restated Construction, Acquisition and Term Loan Agreement dated July 6, 1998 due to the failure to meet the insurance requirements under the loan document. On January 30, 2003 NRG Energy, Inc. failed to make $2.7 million in payments under certain Non-Operating Interest Acquisition agreements. As a result, NEO Landfill Gas, Inc. failed to make its payment due on January 30, 2003 under the Amended and Restated Construction Acquisition and Term Loan Agreement dated July 6, 1998 and the subsidiaries of NEO Landfill Gas failed to make their payments pursuant to various Site Development and Operations Coordination Agreements.

The Camas Power Boiler LP notes are secured principally by its long-term assets. In accordance with the terms of the note agreements, Camas Power Boiler LP is required to maintain compliance with certain financial covenants primarily related to incurring debt, disposing of assets, and affiliate transactions. Camas Power Boiler was in compliance with these covenants at December 31, 2002.

On February 22, 2000, NRG Northeast Generating LLC (NRG Northeast), an indirect, wholly-owned subsidiary of NRG Energy, 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.

In March 2000, NRG South Central Generating LLC (NRG South Central), an indirect wholly owned subsidiary of NRG Energy, issued $800 million of senior secured bonds in a two-part offering, to finance its acquisition of the Cajun generating facilities. The first tranche was for $500 million with a coupon of 8.962% and a maturity of 2016. The second tranche was for $300 million with a coupon of 9.479% and a maturity of 2024. Interest and principal payments are due semi-annually. The bonds are secured by a security interest in NRG Central U.S. LLC’s and South Central Generating Holding LLC’s membership interests in NRG South Central and NRG South Central’s membership interests in Louisiana Generating and all of the assets related to the Cajun facilities including its rights under a guarantor loan agreement and all inter-company notes between it and Louisiana Generating, and a revenue account and a debt service reserve account. In January 2001, NRG South Central exchanged all of its outstanding bonds for bonds registered under the Securities Act of 1933. As of December 31, 2002 and 2001, there remains $750.8 million and $763.5 million of outstanding bonds, respectively. On September 15, 2002, NRG South Central missed a $47 million principal and interest payment. The 15-day grace period to make payment related to this issue passed and NRG South Central did not make the required payments. In January 2003, the South Central Generating bondholders unilaterally withdrew $35.6 million from the restricted revenue account, relating to the September 15, 2002, interest payment and fees. On March 17th, 2003 South Central bondholders were paid $34.4 million due in relation to the semi-annual interest payment and the $12.8 million principal payment was deferred. NRG South Central remains in default on these notes.

In September 2000, Flinders Power Finance Pty (Flinders Power), an Australian wholly owned subsidiary, entered into a twelve year AUD $150 million promissory note (US $81.4 million at September 2000). As of December 31, 2002 and 2001, there remains $80.5 million and $74.9 million outstanding under this facility, respectively. The interest has fixed and variable components. At December 31, 2002 and 2001, the effective interest rate was 6.49% and 5.89%, respectively and is paid semi annually. Principal payments commence in 2006 and the facility will be fully paid in 2012. In March 2002, Flinders Power entered into a 10 year AUD $165 million (US$85.4 million at March 2002) floating rate promissory note for the purpose of

refurbishing the Flinders Playford generating station. As of December 31, 2002, the Company had drawn $18.7 million (AUD $33 million) of this facility. The interest rate has fixed and variable components. The effective interest rate at December 31 ,2002 was 6.14%, and is paid semi annually. Upon NRG Energy’s credit rating downgrade in 2002, there existed a potential default under these agreements related to the funding of reserve funds. Flinders has worked with the Flinders Banks since the downgrade and has signed a series of consecutive standstill agreements, the last standstill agreement expires in March 2003 unless otherwise agreed or extended.

In June 2002, NRG Peaker Finance Company LLC (NRG Peaker), an indirect wholly owned subsidiary of NRG Energy, completed the issuance of $325 million of Series A Floating Rate Senior Secured Bonds due 2019. The bonds bear interest at a floating rate equal to three-months USD-LIBOR — BBA plus 1.07%. Interest on the bonds is payable on March 10, June 10, September 10 and December 10 of each year, commencing on September 10, 2002. Scheduled principal payments of $8.0 million, $10.5 million, $4.3 million, $6.8 million, $11.2 million and $278.6 million are due on December 10 of 2003, 2004, 2005, 2006, 2007 and thereafter through June 2019, respectively. The final scheduled repayment of principal is due on June 10, 2019. The bonds may be redeemed at any time prior to maturity at a price that, in certain circumstances, will include a redemption premium. The initial bond proceeds of $250 million were used to make loans to affiliates which own natural-gas fired “peaker” electric generating projects located in either Louisiana or Illinois. The project owners used the proceeds of the loans to (1) reimburse NRG Energy for construction and/or acquisition costs for the peaker projects previously paid by NRG Energy, (2) pay to XL Capital Assurance (XLCA) the premium for the Bond Policy, (3) provide funds to NRG Peaker to collateralize a portion of NRG Energy’s contingent guaranty obligations and (4) pay transaction costs incurred in connection with the offering of the bonds (including reimbursement of NRG Energy for the portion of such costs previously paid by NRG Energy). The Bond Policy is a financial guaranty insurance policy that unconditionally and irrevocably guaranties payment of scheduled principal and interest payments on the Bonds. The Bond Policy does not, however, guaranty the payment of principal of or interest on the bonds prior to the applicable scheduled payment dates, unless XLCA elects to make such payments. The bonds are secured by a pledge of membership interests in NRG Peaker and a security interest in all of its assets, which initially consist of notes evidencing loans to the affiliate project owners. The project owners’ jointly and severally guaranty the entire principal amount of the bonds and interest on such principal amount. The project owner guaranties are secured by a pledge of the membership interest in three of five project owners and a security interest in substantially all of the project owners’ assets related to the peaker projects, including equipment, real property rights, contracts and permits. NRG Energy has entered into a contingent guaranty agreement in favor of the collateral agent for the benefit of the secured parties, under which it agreed to make payments to cover scheduled principal and interest payments on the bonds and regularly scheduled payments under the interest rate swap agreement, to the extent that the net revenues from the peaker projects are insufficient to make such payments, in specified circumstances. This financing contains a cross-default provision related to the failure by NRG Energy to make payment of principal, interest or other amounts due on debt for borrowed money in excess of $50 million, a covenant that was violated in October 2002. In addition, in 2002 mechanics liens were placed against the Bayou Cove facility resulting in an additional default. On October 22, 2002, XL Capital issued a notice of default on the Peaker financing facility. On December 10, 2002, $16.0 million in interest, principal, and swap payments were made from restricted cash accounts. As a result, $319.4 million in principal remains outstanding as of December 31, 2002.

NRG Peaker has also entered into an interest rate swap agreement pursuant to which it agreed to make fixed rate interest payments and receive floating rate interest payments. The interest rate swap counter-party will have a security interest in the collateral for the bonds and the collateral for the project owner guaranties. Net payments to be made by NRG Peaker under the interest rate swap agreement will be guaranteed pursuant to a separate financial guaranty insurance policy, the issuer of which will have a security interest in the

collateral for the bonds and the collateral for the project owner guaranties. NRG Peaker was in compliance with this agreement at December 31, 2002.

LSP-Pike Energy LLC received a loan to construct its power generation facility in Pike County, Mississippi, from Mississippi Business Finance Corporation that was financed by the issuance of Industrial Revenue Bonds (Series 2002). NRG Finance Company LLC, an affiliate of LSP-Pike Energy LLC, purchased the Series 2002 bonds. These bonds have been classified as debt on the financial statements. The principal and the interest on these bonds is due and payable as of January 1, 2010 and bears a variable interest rate equivalent to the interest rate payable on the loan funds used to finance the bond purchase by NRG Finance Company I LLC. These bonds are subject to a subordination agreement between NRG Finance Company I LLC, as purchaser, LSP-Pike Energy LLC, and Credit Suisse First Boston, as administrative agent to a senior claim, so that in the case of insolvency or bankruptcy proceedings, or any receivership, liquidation, reorganization or other similar proceedings, and even in the event of any proceedings for voluntary liquidation, dissolutions, or other winding up of the company, then the holders of the senior claims shall be entitled to receive payment in full or cash equivalents of all principal, interest, charges and fees on all senior claims before the purchaser is entitled to receive any payment on account of the principal of or interest on these bonds. As of October 17, 2002, the United States Bankruptcy Court for the Southern District of Mississippi granted an order of relief to the debtor under the US bankruptcy laws, thus, forcing LSP-Pike Energy LLC into default and cessation of all benefits granted under the terms of the loan agreement and issuance of the bonds.

Annual maturities of long-term debt and capital leases for the years ending after December 31, 2002 are as follows:

Future minimum lease payments for capital leases included above at December 31, 2002 are as follows:

Total net book value related to the assets recorded with respect to NRG Energy’s capital leases at December 31, 2002 and 2001 was $258.2 million and $334.6 million, net of $2.3 million and $0 of accumulated amortization, respectively.

NRG Energy is directly liable for the obligations of certain of its project affiliates and other subsidiaries pursuant to guarantees relating to certain of their indebtedness, equity and operating obligations. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of NRG Energy’s generation facilities in the United States, NRG Energy may be required to guarantee a portion of the obligations of certain of its subsidiaries. Additionally, as a result of the downgrades of NRG Energy’s unsecured debt ratings, the Company is required to post cash collateral in the amount of $1.1 billion, however, NRG Energy has been unable to do so.

As of December 31, 2002 and 2001, NRG Energy’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations of its subsidiaries were as follows:

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

Recourse provisions for each of the guarantees above are to the extent of their respective liability. Additionally, no assets are held as collateral for any of the above guarantees.

NRG Energy and its subsidiaries will file a consolidated federal income tax return through June 3, 2002, when Xcel Energy completed its exchange offer for the 26% of NRG Energy’s shares that had been previously publicly held. Starting June 4, 2002, NRG Energy and subsidiaries can rejoin Xcel Energy’s consolidated group for federal income tax purposes provided the Internal Revenue Service (IRS) consents to such rejoining. Without such consent, separate income tax returns will be required for each NRG Energy entity that is treated as a corporation for income tax purposes.

To date, no request has been made to the IRS for consent to permit Xcel Energy to reconsolidate NRG Energy for federal income tax purposes. Because it is likely that Xcel Energy will not request such a consent, the income tax provision for NRG Energy is based on a consolidated NRG Energy group through June 3, 2002, and separate corporate tax returns starting June 4, 2002.

The provision (benefit) for income taxes for the years ended December 31, consists of the following:

The pre-tax (loss) income from U.S. and foreign consolidated entities was as follows:

As of December 31, 2002, NRG Energy provided a valuation allowance to account for potential limitations on utilization of U.S. and Foreign net operating loss carryforwards of approximately $1,143.5 million and $81.9 million, respectively. The net operating loss carryforwards expire between 2003 and 2021. NRG Energy also provided a valuation allowance for other U.S. deferred income tax assets of approximately $513.3 million. The increase in U.S. deferred income tax assets is primarily due to the recognition of impairment charges. During the year ended December 31, 2002, the valuation allowance increased $1,010.4 million due to the increases in net operating loss carryforwards and deferred income tax assets for which NRG Energy is unable to conclude that there will be sufficient taxable earnings in future periods to offset the tax benefits.

As of December 31, 2002, a net deferred tax asset of approximately $33 million was recorded relating to the investment West Coast Power. On a separate company basis, there will be sufficient taxable earnings in future periods for utilization of the tax benefits.

The effective income tax rates of continuing operations for the years ended December 31, 2002 and 2001 differ from the statutory federal income tax rate of 35% as follows:

For the year ended December 31, 2002, the income tax benefit was $165.4 million, compared to an income tax expense of $28.1 million for the year ended December 31, 2001, a decrease of $193.5 million. The decrease in tax expense compared to 2001 was primarily due to the reduction in domestic earnings.

The effective income tax rate for the year ended December 31, 2002 differs from the statutory federal income tax rate of 35% primarily due to limitation on tax benefits. The effective income tax rate for the year ended December 31, 2001 differs from the statutory federal income tax rate of 35% primarily due to state tax, foreign tax and tax credits as shown above.

As of December 31, 2001 NRG Energy management intended to reinvest the earnings of foreign operations to the extent the earnings were subject to current U.S. income taxes. Accordingly, U.S. income taxes and foreign withholding taxes were not provided on a cumulative amount of unremitted earnings of foreign subsidiaries of approximately $345 million December 31, 2001. As of December 31, 2002 NRG Energy management has revised its strategy and no longer intends to indefinitely reinvest the full amount of earnings of foreign operations. However, no U.S. income tax benefit has been provided on the cumulative amount of unremitted losses of $339.7 million at December 31, 2002 due to the uncertainty of realization.

Substantially all of NRG Energy’s employees participate in defined benefit pension plans. All eligible employees participate in Xcel Energy’s noncontributory, defined benefit pension plan which was formerly sponsored by NSP. NRG Energy sponsored two defined benefit plans that were merged into Xcel Energy’s plan as of June 30, 2002. Benefits are generally based on a combination of an employee’s years of service and earnings. Some formulas also take into account Social Security benefits. Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities.

In addition, NRG Energy provides postretirement health and welfare benefits (health care and death benefits) for certain groups of its employees. Generally, these are groups that were acquired in recent years and for whom prior benefits are being continued (at least for a certain period of time or as required by union contracts). Cost sharing provisions vary by acquisition group and terms of any applicable collective bargaining agreements. Certain former NRG Energy retirees are covered under the legacy Xcel Energy plan, which was terminated for non-bargaining employees retiring after 1998 and for bargaining employees retiring after 1999.

The net annual periodic pension cost related to NRG Energy’s plans for the years ended December 31 include the following components:

A comparison of the pension benefit obligation and pension assets at December 31, 2002 and 2001 for all of NRG’s plans on a combined basis is as follows:

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect (in thousands):

Substantially, all eligible employees participate in Xcel Energy’s noncontributory, defined benefit pension plan which was formerly sponsored by NSP. NRG Energy’s contributions to the Xcel Energy pension plan and postretirement plan totaled $0, $0 and $20,000 in 2002, 2001 and 2000. The balance sheet includes a liability related to the Xcel Energy Pension Plan of $1.7 million and $5.0 million for 2002 and 2001, respectively. The balance sheet also includes a liability related to the Xcel Energy Postretirement Medical Plan of $2.2 million and $2.3 million for 2002 and 2001, respectively. The applicable portion of the total plan benefits and net assets of these plans is not separately identifiable. The net annual periodic credit related to NRG’s portion of the Xcel Energy pension plan and postretirement plans totaled $8.9 million, $8.9 million and $1.7 million for 2002, 2001 and 2000, respectively.

Certain NRG employees also participate in Xcel Energy’s noncontributory defined benefit supplemental retirement income plan. This plan is for the benefit of certain qualifying executive personnel. Benefits for this unfunded plan are paid out of operating cash flows. The balance sheet includes a liability related to this plan of $3.2 million and $2.6 million as of December 31, 2002 and 2001, respectively.

Some NRG Energy employees participated in Xcel Energy’s defined contribution 401(K) plan. NRG Energy contributions to the plan were approximately $0.9 million and $0.6 million for the years ended December 31, 2002 and 2001, respectively.

NRG Energy also assumed several contributory, defined contribution employee savings plans as a result of its 2000 and 1999 acquisition activity. These plans comply with Section 401(k) of the Internal Revenue Code and covered substantially all of our employees who were not covered by Xcel Energy’s 401(k) Plan. NRG Energy matched specified amounts of employee contributions to the plan. Employer contributions made to these plans were approximately $2.4 million and $1.6 million in 2002 and 2001, respectively.

The Xcel Energy plan (NRG portion) was rolled into the NRG plans for 2002. Employer contributions made to all plans for 2002 were approximately $4.6 million.

During 1998 and 1999, NRG Energy’s employees were eligible to participate in its Equity Plan (the Plan). The Plan granted, to employees, phantom equity units that were intended to simulate Stock options. Grant size was based on the participant’s position in NRG Energy and base salary. Equity unit valuations were performed annually by an outside valuation firm. The value of an equity unit was the approximate value per share of NRG Energy’s stockholder equity as of the valuation date, less the value of Xcel Energy’s (formerly NSP) equity investments. The units were awarded to employees annually at the respective year’s calculated share price (grant price). The Plan provided employees with a cash pay out for the unit’s appreciation in value over the vesting period. The Plan had a seven year vesting schedule with actual payments beginning after the end of the third year and continuing at 20% each year for the subsequent five years. During 2002, 2001 and

2000, NRG Energy recorded compensation expense of approximately $0, $0, and $6.0 million, respectively, for the Plan.

The Plan included a change of control provision, which allowed all shares to vest if NRG Energy’s ownership were to change. Subsequent to the completion of NRG Energy’s initial public offering in June 2000, the Plan was converted to a new stock option plan (see Note 20).

During 2001, NRG Energy acquired several generating assets and assumed benefit obligations for a number of employees associated with those acquisitions. The plans assumption included noncontributory defined benefit pension plans, and contributory post-retirement welfare plans. Of the 2001 acquisitions where these obligations were assumed, approximately 79% percent of such employees are represented by one local union under collective bargaining agreements, which expire on July 1, 2004. Plan liability and expense amounts for these acquisitions are included in the pension and postretirement health care amounts shown above.

During 2002, sales to one customer (New York Independent System Operator) accounted for 22.1% of total revenues from majority owned operations in 2002. During 2001, sales to two customers accounted for 33.9% (New York Independent System Operator) and 17.6% (Connecticut Light and Power Co.) of total revenues from majority owned operations in 2001. During 2000, sales to two customers accounted for 26.8% (New York Independent System Operator) and 14.8% (Connecticut Light and Power Co.) of total revenues from majority owned operations in 2000.

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

For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of notes receivable is based on expected future cash flows discounted at market interest rates. The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues.

At December 31, 2002, 2001 and 2000, NRG Energy had various foreign currency exchange instruments with combined notional amounts of $3.0 million, $46.3 million and $8.8 million, respectively. These foreign currency exchange instruments were hedges of expected future cash flows. If the hedges had been terminated at December 31, 2002, 2001 and 2000, NRG Energy would have owed the counter-parties $0.3 million, $2.4 million and $0.7 million, respectively.

At December 31, 2002, 2001 and 2000, NRG Energy had various interest-rate swap agreements with combined notional amounts of $1.7 billion, $2.4 billion and $530 million, respectively. These contracts are used to manage NRG Energy’s exposure to changes in interest rates. If these swaps had been terminated at December 31, 2002, 2001 and 2000, NRG Energy would have owed the counter-parties $41.0 million, $81.5 million and $28.9 million, respectively.

At December 31, 2002, 2001 and 2000 NRG Energy had various energy related commodities financial instruments with combined notional amounts of $241.8 million, $1.0 billion and $309.0 million, respectively. These financial instruments take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. These contracts are used to manage NRG Energy’s exposure to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. If these contracts were terminated at December 31, 2002, 2001 and 2000, NRG Energy would have received $58.5 million, $224.1 million and $52.8 million from counter-parties, respectively.

NRG Energy’s counter-parties to its hedging contracts consist principally of financial institutions and major energy companies. NRG Energy actively manages its exposure to counter-party risk. NRG Energy has an established credit policy in place to minimize overall credit risk. Important elements of this policy include ongoing financial reviews of all counter-parties, established credit limits, as well as monitoring, managing and mitigating credit exposure.

During the first quarter of 2002, NRG Energy adopted SFAS No. 142 — “Goodwill and Other Intangible Assets” (SFAS No. 142), which requires new accounting for intangible assets, including goodwill. Intangible assets with finite lives will be amortized over their economic useful lives and periodically reviewed for impairment. Goodwill will no longer be amortized, but will be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value.

NRG Energy had goodwill of $34.2 million at December 31, 2002, which will not be amortized. As of December 31, 2002, NRG Energy performed impairment tests of its goodwill balances. To date, such tests completed have concluded that no write-down of goodwill is necessary primarily because the majority of the goodwill that NRG Energy has recorded relates to its Thermal operations, which have sufficient on going cashflows.

Aggregate amortization expense recognized for the twelve months ended December 31, 2002, 2001 and 2000 was approximately $2.8 million, $4.2 million and $3.1 million, respectively. The annual aggregate

amortization expense for each of the five succeeding years is expected to approximate $2.8 million. Intangible assets consisted of the following:

The following table summarizes the pro forma impact of implementing SFAS No. 142 at January 1, 2000 on net income (loss) for the periods presented.

In June 2000, NRG Energy sold 32.4 million shares of common stock at $15 per share. Net proceeds from the offering were $453.7 million. NRG Energy has authorized capital stock consisting of 550,000,000 shares of common stock, and 250,000,000 shares of Class A common stock. At December 31, 2000, there were approximately 32,396,000 shares of common stock, and 147,605,000 shares of Class A common stock issued and outstanding.

In March 2001, NRG Energy completed the sale of 18.4 million shares of common stock for an initial price of $27 per share. The offering was completed with all 18.4 million shares of common stock being sold including the over-allotment shares of 2.4 million. NRG Energy received gross proceeds from the issuance of $496.6 million. Net proceeds from the issuance were $473.4 million after deducting underwriting discounts, commissions and estimated offering expenses. The net proceeds were used in part to reduce amounts outstanding under NRG Energy’s short-term bridge credit agreement, which was used to finance in part NRG Energy’s acquisition of the LS Power assets. At December 31, 2001, there were approximately 50,939,875 shares of common stock, and 147,605,000 shares of Class A common stock issued and outstanding.

On June 3, 2002, Xcel Energy completed its exchange offer for the 26% of NRG Energy’s shares that had been previously publicly held. Xcel Energy issued NRG Energy shareholders 0.50 shares of Xcel Energy common stock in exchange for each outstanding share of NRG Energy common stock.

In June 2000, NRG Energy adopted a new incentive compensation plan (the New Stock Plan), which was approved by shareholders in June 2001 and which will be administered by a committee appointed by the

Board of Directors. The New Stock Plan provides for awards in the form of stock options, stock appreciation rights, restricted stock, performance units, performance shares, or cash based awards as determined by the Board of Directors. All officers, certain other employees, and non-employee directors are eligible to participate in the plan. Nine million shares of common stock are authorized for issuance under the Stock Plan. Initially, only stock option grants will be made to certain officers, independent directors and employees under the plan.

Each new option granted is valued at the fair market value per share at date of grant. The difference between the option price and the market value of the stock at the date of grant, if any, of each option on the date of grant is recorded as compensation expense over a vesting period. Options granted prior to June 2001 vest over a period of five years, with 25% vesting in each of the years two through five and generally expire ten years from the date of grant. Options granted in June 2001 and subsequently, vest over a four year period, with 25% vesting each year and generally expire ten years from the date of grant. The board’s independent directors’ options vested immediately upon being granted. The average exercise price of vested options at December 31, 2001 and 2000 was $14.39 and $9.51, respectively, all of which were granted in replacement of units previously outstanding under the equity plan. There were no grants in 2002. NRG Energy has recognized approximately $1.9 million and $7.3 million of stock based compensation expense for the periods ended December 31, 2001 and 2000, respectively. In 2002, NRG Energy recognized income due to the net reduction of its compensation expense accrual by approximately $2.3 million for terminated stock options during the period. This amount has been reported as a reduction of compensation expense for the year ended December 31, 2002.

During 2002, the New Stock Plan and all grants under the plan were adopted by the Xcel Energy Incentive Stock Plan. There were no grants to NRG Energy employees under this new plan.

Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:

NRG Energy leases certain of its facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2023. Rental expense under these operating leases was

$12.6 million, $9.7 million and $2.3 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:

NRG Energy anticipates funding its ongoing capital requirements through committed debt facilities, operating cash flows, and existing cash. NRG Energy’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.

NRG Energy’s California generation assets include a 50% interest in the West Coast Power partnership with Dynegy.

In March 2001, the California Power Exchange (PX) filed for bankruptcy under Chapter 11 of the Bankruptcy Code, and in April 2001, the Pacific Gas & Electric Company (PG&E) also filed for bankruptcy under Chapter 11. In September 2001, PG&E filed a proposed plan of reorganization. Under the terms of the proposed plan, which is subject to challenge by interested parties, unsecured creditors such as NRG Energy’s California affiliates would receive 60% of the amounts owed upon approval of the plan. The remaining 40% would be paid in negotiable debt with terms from 10 to 30 years. The California PX’s ability to repay its debt is dependent on the extent to which it receives payments from PG&E and Southern California Edison Company (SCE). During the fourth quarter of 2002, after assuring the collectibility of its California receivables and other recent related developments, West Coast Power recorded an approximate $117.0 million charge to write-off the remaining amounts owed to it by the California PX and ISO. NRG Energy’s share of this charge was approximately $58.5 million (pre-tax).

NRG Energy is 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 Energy views this change as a significant improvement to the existing market design, NRG Energy still views the market within New England as insufficient to allow for NRG Energy to recover its costs and earn a reasonable return on investment. Consequently, on February 26, 2003, NRG Energy filed and requested a cost of service rate with FERC for most of its Connecticut fleet, requesting a February 27th effective date. NRG Energy remains 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 NRG Energy has the right to

file for such rate treatment, there are no assurances that FERC will grant such rates in the form or amount that NRG Energy petitioned for in its filing.

In connection with the acquisition of certain generating facilities NRG Energy entered into various long-term transition agreements and standard offer agreements that obligated NRG Energy 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 Energy acquired the Huntley and Dunkirk generating facilities from Niagara Mohawk Power Corporation (NiMo). In connection with this acquisition, NRG Energy entered into a 4-year agreement with NiMo that requires NRG Energy to provide to NiMo pursuant to a predetermined schedule fixed quantities of energy and capacity at a fixed price.

During 1999, NRG Energy acquired certain generating facilities from Connecticut Light and Power Company (CL&P). NRG also entered into a 4-year standard offer agreement that requires NRG Energy to provide to CL&P a portion of its load requirements through the year 2003 at a substantially fixed rate.

During 2000, NRG Energy acquired the non-nuclear generating assets of Cajun Electric. Upon acquisition of the facilities, NRG Energy entered into various long-term power purchase agreements with the former customers of Cajun Electric, primarily distribution cooperatives and municipalities. These agreements specify that NRG Energy provide these customers with all requirements necessary to satisfy the energy and capacity needs of their retail load.

Also during 2000, NRG Energy acquired the Killingholme generating facilities from National Power plc. In connection with this acquisition, NRG Energy entered into certain agreements to provide the natural gas to operate the facility, which generally sells its power into the spot market. NRG Energy entered into two gas purchase agreements, the first being a 5-year agreement that provides approximately 30% of the generating facilities natural gas requirements and the second agreement being a 10-year agreement that provides approximately 70% of the generating facilities natural gas requirements. NRG Energy also entered into a 5-year fixed price agreement to resell up to 15% of the gas it has contracted for at a slightly higher price. As of December 31, 2002, NRG Energy has entered into an agreement whereby the Killingholme facilities would be turned over to its lenders therefore the assets and liabilities and results of operations have been classified as discontinued operations and held for sale. On January 31, 2003, the Killingholme facilities were sold to its lenders. The obligations under the gas contracts were assumed by the lenders in the sales transaction.

Also during 2000, NRG Energy acquired the Flinders Power operations in South Australia. Upon the closing of the acquisition, NRG Energy assumed a gas purchase and sales agreement relating to the Osborne generating plant with a remaining life of 18-years. These agreements require NRG Energy to purchase a specified quantity of natural gas from a third party supplier at a fixed price for 18-years and resell the natural gas to Osborne at a fixed price for 13-years. The sales price is substantially lower than the purchase price. NRG Energy has recorded the liability associated with this out of the market contract in the amount of approximately $66 million in other long-term obligations and deferred income on its balance sheet. As of December 31, 2002 there remains approximately $73.3 million on NRG Energy’s balance sheet. In addition, NRG Energy has entered into a contract for differences agreement which provides for the sale of energy into the South Australian power pool through the year 2002. The agreement provides for a swap of the variable market price to a fixed price.

During 2001, NRG Energy acquired a portfolio of projects located in Delaware, Maryland and Pennsylvania from Conectiv. Upon closing of the acquisition, NRG Energy assumed a power purchase agreement. This agreement, which is not project specific, requires NRG Energy to deliver and Conectiv to purchase 500 MW of electric energy around the clock at a specified price through 2005. The sales price of the

contracted electricity was substantially lower than the fair value that the electricity on the merchant market at the date of acquisition. During 2001, NRG Energy recorded the liability associated with the out of market contract on the balance sheet in the amount of approximately $89.4 million. Approximately $45.1 million was recorded in other current liabilities and approximately $44.3 million in other long-term obligations and deferred income. The difference was to be amortized into income over the life of the agreement. In the fourth quarter of 2002, Conectiv terminated this agreement and NRG Energy recorded the unamortized balance into income as revenue, see below for additional information.

NRG Energy and its subsidiaries strive to exceed the standards of compliance with applicable environmental and safety regulations. Nonetheless, NRG Energy 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 Energy’s operations.

As part of acquiring existing generating assets, NRG Energy 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 Energy has established accruals where reasonable estimates of probable liabilities are possible. As of December 31, 2002 and 2001, NRG Energy has established such accruals in the amount of approximately $3.8 million and $5.0 million, respectively, primarily related to its Northeast region facilities (Arthur Kill and Astoria projects). NRG Energy 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

Energy’s consolidated financial statements. NRG Energy 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 Energy recorded expenses of approximately $10.9 million, $15.3 million and $3.4 million related to environmental matters, respectively.

The Asset Purchase Agreements for the Long Beach, El Segundo, Encina, and San Diego gas turbine generating facilities provide that Southern California Edison and San Diego Gas & Electric retain liability and indemnify NRG Energy for existing soil and groundwater contamination that exceeds remedial thresholds in place at the time of closing. NRG Energy and its business partner conducted Phase I and Phase II Environmental Site Assessments at each of these sites for purposes of identifying such existing contamination and provided the results to the sellers. San Diego Gas & Electric is proceeding to address contamination identified by these studies by undertaking corrective action at the Encina and San Diego gas turbine generating sites. While spills and releases of various substances have occurred at many sites since establishing the historical baseline, all but one has been remediated in accordance with existing laws. An unquantified amount of soil contaminated by lubricating oil that leaked from underground piping at the El Segundo Generating Station has been allowed by the Regional Water Quality Control Board to remain under the foundation of the Unit I powerhouse until the building is demolished.

NRG Energy’s affiliates have incurred and anticipates further environmental capital expenditures at the Encina Generating Station to install Selective Catalytic Reduction (SCR) emission control technology on all five generating units. Units 4 & 5 were retrofitted with SCRs during 2002; the additional SCR on Unit 3 was completed in February 2003. SCR emission controls on Units 1 and 2 are expected to be completed in 2003. NRG Energy estimates the cost to retrofit all five units to be approximately $42 million.

NRG must also maintain financial assurance for closing interim status RCRA facilities at the Devon, Middletown, Montville and Norwalk Harbor Generating Stations. Previously, NRG Energy has provided financial assurance via financial test. NRG Energy must re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, currently estimated not to exceed $2.4 million. NRG Energy is required to provide an alternative instrument to provide such financial assurance on or before April 30, 2003.

investigations. NRG Energy 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 liabilities at the Arthur Kill Generating Station have been established in discussions between NRG Energy and the New York State DEC and are expected to cost on the order of $1.0 million. Remedial investigations are on-going at the Astoria Generating Station. At this time, NRG Energy’s long-term cleanup liability at this site is not expected to exceed $1.5 million.

NRG Energy estimates that it will incur total environmental capital expenditures of $53 million during 2003 through 2007 for the facilities in New York, Connecticut and Massachusetts. These expenditures will be primarily related to landfill construction, installation of NO_x controls, installation of the best technology available for minimizing environmental impacts associated with impingment and entrainment of fish and larvae, particulate matter control improvements, spill prevention controls, and undertaking remedial actions. NRG Energy estimates that it will incur in 2003 at all of its plants in the Northeast Region about $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.

NRG Energy estimates that it will incur capital expenditures of approximately $25 million during the years 2003 through 2007 related to resolving environmental concerns at the Indian River Generating Station. These concerns include the expected closure of the existing ash landfill, the construction of a new ash landfill nearby, the addition of controls to reduce NO_x emissions, fuel yard modifications, and electrostatic precipitator refurbishments to reduce opacity.

NRG Energy estimates approximately $20 million of capital expenditures will be incurred during the period 2003 and 2007 for the addition of NO_x controls on Units 1 and 2 of Big Cajun II. In addition, NRG Energy estimates that it would incur up to $5 million to reduce particulate matter emissions during start-up of Units 1 and 2 at Big Cajun II.

In November 2002, the NYISO notified NRG Energy of claims related to New York City mitigation adjustments, general NYISO billing adjustments and other miscellaneous charges related to sales between November 2000 and October 2002. NRG Energy contests both the validity and calculation of the claims and is currently negotiating with the NYISO over the ultimate disposition. Accordingly, NRG Energy reduced its revenues by $21.7 million and recorded a corresponding reserve for the receivable.

On November 8, 2002 Conectiv provided NRG Energy with a Notice of Termination of Transaction under the Master Power Purchase and Sale Agreement (Master PPA) dated June 21, 2001. Under the Master PPA, which was assumed by NRG Energy in its acquisition of various assets from Conectiv, NRG Energy had been required to deliver 500 MW of electrical energy around the clock at a specified price through 2005. In connection with the Conectiv acquisition, NRG Energy recorded as an out-of-market contract obligation for this contract. As a result of the cancellation, NRG Energy will lose approximately $383.1 million in future contracted revenues. Also, in conjunction with the terms of the Master PPA, NRG Energy received from Conectiv a termination payment in the amount of $955,000. At December 31, 2002, the remaining unamortized balance of the contract obligation was recognized as revenue. As a result, during the fourth quarter approximately $50.7 million was recognized as revenue.

Public Utility District of Snohomish County v. Dynegy Power Marketing, Inc et al., Case No. 02-CV-1993 RHW, United States District Court, Southern District of California (part of MDL 1405).


	1. Pamela R Gordon, on Behalf of Herself and All Others Similarly Situated v Reliant Energy, Inc. et al., Case No. 758487, Superior Court of the State of California, County of San Diego (filed on November 27, 2000).

	2. Ruth Hendricks, On Behalf of Herself and All Others Similarly Situated and On Behalf of the General Public v. Dynegy Power Marketing, Inc. et al., Case No. 758565, Superior Court of the State of California, County of San Diego (filed November 29, 2000).

	3. The People of the State of California, by and through San Francisco City Attorney Louise H. Renne v. Dynegy Power Marketing, Inc. et al., Case No. 318189, Superior Court of California, San Francisco County (filed January 18, 2001).

	4. Pier 23 Restaurant, A California Partnership, On Behalf of Itself and All Others Similarly Situated v PG&E Energy Trading et al., Case No. 318343, Superior Court of California, San Francisco County (filed January 24, 2001).

	5. Sweetwater Authority, et al. v. Dynegy Inc. et al., Case No. 760743, Superior Court of California, San Diego County (filed January 16, 2001).

	6. Cruz M Bustamante, individually, and Barbara Matthews, individually, and on behalf of the general public and as a representative taxpayer suit, v. Dynegy Inc. et al., inclusive. Case No. BC249705, Superior Court of California, Los Angeles County (filed May 2, 2001).

These cases were all filed in late 2000 and 2001 in various state courts throughout California. They allege unfair competition, market manipulation, and price fixing. All the cases were removed to the appropriate United States District Courts, and were thereafter made the subject of a petition to the Multi-District Litigation Panel (Case No. MDL 1405). The cases were ultimately assigned to Judge Whaley. Judge Whaley entered an order in 2001 remanding the cases to state court, and thereafter the cases were coordinated pursuant to state court coordination proceedings before a single judge in San Diego Superior Court. The defendants filed motions to dismiss and to strike under the filed-rate and federal preemption theories, and the plaintiffs challenged the district court’s jurisdiction and sought to have the cases remanded to state court. In December 2002, Judge Whaley issued an opinion finding that federal jurisdiction was absent in the district court, and remanding the cases to state court. Duke Energy and Reliant Energy have filed a notice of appeal with the Ninth Circuit, and also sought a stay of the remand pending appeal. The stay request was denied by Judge Whaley. On February 20, 2003, however, the Ninth Circuit stayed the remand order and accepted jurisdiction to hear the appeal of Reliant Energy and Duke Energy on the remand order. The Company anticipates that filed-rate/federal preemption pleading challenges will once again be filed once the remand

appeal is decided. A “Notice of Bankruptcy Filing” respecting NRG Energy has also been filed in this action, providing notice of the involuntary petition.

Bustamante v. McGraw-Hill Companies Inc., et al., No. BC 285598, California Superior Court, Los Angeles County

This putative class action lawsuit was filed on November 20, 2002. In addition to naming WCP-related entities as defendants, numerous industry participants are named in this lawsuit that are unrelated to WCP or NRG Energy. The Complaint generally alleges that the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades. Named defendants in the suit are the LLCs established by WCP for each of its four plants: El Segundo Power, LLC; Long Beach Generation, LLC; Cabrillo Power I LLC; and Cabrillo Power II LLC. NRG Energy is not named as a defendant. The complaint seeks restitution and disgorgement of “ill-gotten gains”, civil fines, compensatory and punitive damages, attorneys’ fees, and declaratory and injunctive relief.

On December 12, 2002, FERC Administrative Law Judge Birchman issued a Certification of Proposed Findings on California Refund Liability in Docket No. EL00-95-045 et al., which determined the method for the mitigated energy market clearing price during each hour of the refund period. On March 26, 2003, FERC issued an Order on Proposed Findings on Refund Liability in Docket No. EL00-95-045 (“Refund Order”), adopting, in part, and modifying, in part, the Proposed Findings issued by Judge Birchman on December 12, 2002. In the Refund Order, FERC adopted the refund methodology in the Staff Final Report on Price Manipulation in Western Markets issued contemporaneously with the Refund Order in Docket No. PA02-2-000. This refund calculation methodology makes certain changes to Judge Birchman’s methodology, because of FERC Staff’s findings of manipulation in gas index prices. This could materially increase the estimated refund liability. The Refund Order also directs generators that want to recover any fuel costs above the mitigated market clearing price during the refund period to submit cost information justifying such recovery within forty (40) days of the issuance of the Refund Order. FERC announced in the Refund Order that it expects that refunds will be paid by suppliers by the end of summer 2003.

On Feb. 26, 2003, Fortistar Capital, Inc. and Fortistar Methane, LLC filed a lawsuit in the Federal District Court for the Northern District of New York against Xcel Energy and five present or former NRG Energy or NEO officers and employees. NRG Energy is a wholly owned subsidiary of Xcel Energy, and NEO is a wholly owned subsidiary of NRG Energy. In the lawsuit, Fortistar claims that the defendants violated the Racketeer Influenced and Corrupt Organizations Act (“RICO”) and committed fraud by engaging in a pattern of negotiating and executing agreements “they intended not to comply with” and “made false statements later to conceal their fraudulent promises.” The plaintiffs allege damages of some $350 million and also assert entitlement to a trebling of these damages under the provisions of the RICO Act. The present and former NRG Energy and NEO officers and employees have requested indemnity from NRG Energy, which requests NRG Energy is now examining. NRG Energy cannot at this time estimate the likelihood of an unfavorable outcome to the defendants in this lawsuit.

conditions to contract performance were not met. No decision has been rendered on the pending motion. NRG Energy cannot predict the likelihood of an unfavorable outcome.

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 and to which NRG Power Marketing filed a response in March 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, among other things arguing 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.

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. The motion is still pending before the judge and there has been no further action taken in connection with the case. On March 27, 2003 the court dismissed the complaint against NRG Energy without prejudice. It is possible the State will appeal this dismissal to the Second Circuit Court of Appeals or could 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 maybe responsible for payment of certain penalties and fines.

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.

On December 2, 2002, a Petition for Review was filed to appeal the United States Environmental Protection Agency’s approval of the Louisiana Department of Environmental Quality’s (“DEQ”) revisions to the Baton Rouge State Implementation Plan (“SIP”). Pointe Coupee and NRG Energy’s subsidiary, Louisiana Generating, object to the approval of SIP Section 4.2.1. Permitting NO_x Sources that purports to require DEQ to obtain offsets of major increases in emissions of nitrogen oxides (NO_x) associated with major modifications of existing facilities or construction of new facilities both in the Baton Rouge Ozone Nonattainment Area and in four adjoining attainment parishes referred to as the Region of Influence, including Pointe Coupee Parish. The plaintiffs’ challenge is based on DEQ’s failure to comply with Administrative Procedures Act requirements related to rulemaking and EPA’s regulations which prohibit EPA from approving a SIP not prepared in accordance with state law. The court granted a sixty (60) day stay of this proceeding on February 25, 2003 to allow the parties to conduct settlement discussions. At this time, NRG Energy is unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which the Company may be subject.

Louisiana Generating sought an interim emissions limit to allow Siemens-Westinghouse time to install additional control equipment. To establish the interim limit, DEQ issued a Compliance Order and Notice of Potential Penalty, No. AE-CN-02-0022, on September 8, 2002, which is, in part, subject to the referenced administrative hearing. DEQ alleged that Louisiana Generating did not meet its NO_x emissions limit on certain days, did not conduct all opacity monitoring and did not complete all record keeping and certification requirements. Louisiana Generating intends to vigorously defend certain claims and any future penalty assessment, while also seeking an amendment of its limit for NO_x. An initial status conference has been held with the Administrative Law Judge and quarterly reports will be submitted to describe progress, including settlement and amendment of the limit. In addition, NRG Energy may assert breach of warranty claims against the manufacturer. With respect to the administrative action described above, at this time NRG Energy is unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which the Company may be subject.

parent entities of the company with which they contracted to build the plant in order to recover amounts allegedly owing. Plaintiffs assert claims for breach of fiduciary duty, piercing the corporate veil, breach of contract, tortious interference with contract, enforcement of the NRG Energy guaranty, detrimental reliance, negligent or intentional misrepresentation, conspiracy, and aiding and abetting. On December 23, 2002, NRG Energy moved to dismiss the complaint in its entirety for failure to state a claim upon which relief can be granted. NRG Energy is currently awaiting plaintiffs’ response to the motion. No trial date has yet been set in this matter and NRG Energy cannot presently predict the outcome of the dispute.

NRG Energy and/or its affiliates have entered into several turbine purchase agreements with affiliates of General Electric Company and Siemens Westinghouse Power Corporation. GE and Siemens have notified NRG Energy that it is in default under certain of those contracts, terminated such contracts, and demanded that NRG Energy pay the termination fees set forth in such contracts. GE’s claim amounts to $120 million and Siemens’ approximately $45 million in cumulative termination charges. NRG Energy has recorded a liability for the amounts they believe they owe under the contracts and termination provisions. NRG Energy cannot estimate the likelihood of unfavorable outcomes in these disputes.

NRG Energy’s indirectly controlled Brazilian project company, Itiquira Energetica S.A., the owner of a 156MW hydro project in Brazil, is currently in arbitration with the former EPC contractor for the project, Inepar Industria e Construcoes (Inepar). The dispute was commenced by Itiquira in September, 2002 and pertains to certain matters arising under the former EPC contract. Itiquira principally asserts that Inepar breached the contract and caused damages to Itiquira by (i) failing to meet milestones for substantial completion; (ii) failing to provide adequate resources to meet such milestones; (iii) failing to pay subcontractors amounts due; and (iv) being insolvent. Itiquira’s arbitration claim is for approximately US$40 million. Inepar has asserted in the arbitration that Itiquira breached the contact and caused damages to Inepar by failing to recognize events of force majeure as grounds for excused delay and extensions of scope of services and material under the contract. Inepar’s damage claim is for approximately US$10 million. On November 12, 2002, Inepar submitted its affirmative statement of claim, and Itiquira submitted its response and statement of counterclaims on December 14, 2002. Inepar replied to Itiquira’s response and counterclaims on January 14, 2003. Itiquira is to submit its reply to Inepar’s January 14 filing on March 14, 2003, and a hearing was held on March 21, 2003. NRG Energy cannot estimate the likelihood of an unfavorable outcome in this dispute.

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 predict the outcome or financial impact of these matters.

NRG Energy conducts its business within six segments: Independent Power Generation in North America, Independent Power Generation outside North America (Europe, Asia Pacific and Other Americas regions), Alternative Energy and Thermal projects. NRG Energy’s Revenues from majority owned operations attributable to Europe and Asia Pacific primarily relate to operations in the United Kingdom and Australia, respectively. These segments are distinct components with separate operating results and management structures in place. The “Other” category includes operations that do not meet the threshold for separate disclosure and corporate charges (primarily interest expense) that have not been allocated to the operating segments.

On March 31, 2000, NRG Energy acquired a 58% interest in the Big Cajun II, Unit 3 generation plant. Entergy Gulf States owns the remaining 42%. Big Cajun II, Unit 3 is operated and maintained by Louisiana Generating pursuant to a joint ownership participation and operating agreement. Under this agreement, Louisiana Generating and Entergy Gulf States are each entitled to their ownership percentage of the hourly net electrical output of Big Cajun II, Unit 3. All fixed costs are shared in proportion to the ownership interests. Fixed costs include the cost of operating common facilities. All variable costs are incurred in proportion to the energy delivered to the owners. NRG Energy’s income statement includes its share of all fixed and variable costs of operating the unit. NRG Energy’s 58% share of the original cost included in Property, Plant and Equipment and construction in progress at December 31, 2002 and 2001, was $189.0 million and $179.7 mil-

lion, respectively. The corresponding accumulated depreciation and amortization at December 31, 2002 and 2001, was $12.3 million and $7.8 million, respectively.

In August 2001, NRG Energy completed the acquisition of a 77% interest in the 520 MW gas fired electric generating facility located in McClain County, Oklahoma from Duke Energy North America LLC (McClain generating facility). The remaining 23% of the McClain generating facility is owned and operated by the Oklahoma Municipal Power Authority (OMPA) pursuant to a joint ownership and operating agreement. Under this agreement, NRG McClain LLC operates the facility and NRG Energy and OMPA are entitled to their ownership ratio of the net available output of the McClain facility. All fixed costs are shared in proportion to the ownership interests. All variable costs are incurred in proportion to the energy delivered to the owners. NRG Energy’s income statement includes its share of all fixed and variable costs of operating the facilities. NRG Energy’s 77% share of the original cost included in Property, Plant and Equipment and construction in progress at December 31, 2002 and 2001 was $277.6 million and $277.3 million, respectively. The corresponding accumulated depreciation and amortization at December 31, 2002 and 2001, was $12.3 million and $3.1 million, respectively.

In June 2001, NRG Energy completed the acquisition of an approximately 3.7% interest in both the Keystone and Conemaugh coal-fired generating facilities. The Keystone and Conemaugh facilities are located near Pittsburgh, Pennsylvania and are jointly owned by a consortium of energy companies. NRG Energy purchased its interests from Conectiv, Inc. Keystone and Conemaugh are operated by GPU Generation, Inc. which sold its assets and operating responsibilities to Sithe Energies. Keystone and Conemaugh both consist of two operational coal-fired steam power units with a combined net output of 1,700 MW, four diesel units with a combined net output of 11 MW and an on-site landfill. The units are operated pursuant to a joint ownership participation and operating agreement. Under this agreement each joint owner is entitled to its ownership ratio of the net available output of the facility. All fixed costs are shared in proportion to the ownership interests. All variable costs are incurred in proportion to the energy delivered to the owners. NRG Energy’s income statement includes its share of all fixed and variable costs of operating the facilities. NRG Energy’s 3.70% and 3.72% share of the Keystone and Conemaugh facilities original cost included in Property, Plant and Equipment and construction in progress at December 31, 2002 was $57.9 million and $62.8 million, respectively and for December 31, 2001 $52.9 million and $60.9 million, respectively. The corresponding accumulated depreciation and amortization at December 31, 2002 and 2001, for Keystone and Conemaugh was $3.5 million and $4.1 million, respectively, and for December 31, 2001 $1.3 million and $1.5 million, respectively.

NRG Energy is required by the State of Louisiana Department of Environmental Quality (“DEQ”) to rehabilitate NRG Energy’s Big Cajun II ash and wastewater impoundment areas, subsequent to the Big Cajun II facilities’ removal from service. On July 1, 1989, a guarantor trust fund (the “Solid Waste Disposal Trust Fund”) was established to accumulate the estimated funds necessary for such purpose. Approximately $1.1 million was initially deposited in the Solid Waste Disposal Trust Fund in 1989, and $116,000 has been funded annually thereafter, based upon an estimated future rehabilitation cost (in 1989 dollars) of approximately $3.5 million and the remaining estimated useful life of the Big Cajun II facilities. Cumulative contributions to the Solid Waste Disposal Trust Fund and earnings on the investments therein are accrued as a decommissioning liability. At December 31, 2002 and 2001, the carrying value of the trust fund investments and the related accrued decommissioning liability was approximately $4.6 million and $4.3 million, respectively. The trust fund investments are comprised of various debt securities of the United States and are carried at amortized cost, which approximates their fair value.

On January 1, 2001, NRG Energy 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 Energy to record all derivatives on the balance sheet at fair value. Changes in the fair value of non-hedge derivatives will be immediately recognized in earnings. Changes in fair values of derivatives accounted for as hedges will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income (OCI) until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings. NRG Energy also formally assesses both at inception and at least quarterly thereafter, whether the derivatives that are 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 Energy’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. SFAS No. 133 also applies to various interest rate swaps used to mitigate the risks associated with movements in interest rates and foreign exchange contracts to reduce the effect of fluctuating foreign currencies on foreign denominated investments and other transactions. At December 31, 2002, NRG Energy had various commodity contracts extending through December 2003, and several fixed-price gas and electricity purchase contracts extending through 2018.

The following table summarizes the effects of SFAS No. 133 on NRG Energy’s Other Comprehensive Income balance as of December 31, 2002:

During the year ended December 31, 2002, NRG Energy reclassified losses of $18.8 million from OCI to current-period earnings as a result of the discontinuance of cash flow hedges because it is probable that the original forecasted transactions will not occur by the end of the originally specified time period. Additionally, gains of $84.5 million were reclassified from OCI to current period earnings during the year ended December 31, 2002 due to the unwinding of previously deferred amounts. These amounts are recorded on the

same line in the statement of operations in which the hedged items are recorded. Also during the year ended December 31, 2002, NRG Energy recorded a gain in OCI of approximately $20.9 million 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 was an unrecognized gain of approximately $26.3 million. NRG Energy expects $1.2 million of deferred net losses on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

The following table summarizes the effects of SFAS No. 133 on NRG Energy’s Other Comprehensive Income balance as of December 31, 2001:

The adoption of SFAS No. 133 on January 1, 2001, resulted in an after-tax unrealized loss of $22.6 million recorded to OCI related to previously deferred net losses on derivatives designated as cash flow hedges. During the year ended December 31, 2001, NRG Energy reclassified gains of $25.3 million 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 year ended December 31, 2001, NRG Energy recorded an after-tax gain in OCI of approximately $119.0 million 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, 2001 was an unrecognized gain of approximately $71.1 million.

The following tables summarize the effects of SFAS No. 133 on NRG Energy’s statement of operations for the period ended December 31, 2002:

The following tables summarize the effects of SFAS No. 133 on NRG Energy’s statement of operations for the period ended December 31, 2001:

NRG Energy is exposed to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. In order to manage these commodity price risks, NRG Energy enters 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. Certain of these transactions have been designated as cash flow hedges. NRG Energy has accounted for these derivatives by recording the effective portion of the cumulative gain or loss on the derivative instrument as a component of OCI in shareholders’ equity. NRG Energy recognizes deferred gains and losses into earnings in the same period or periods during which the hedged transaction affects earnings. Such reclassifications are included on the same line of the statement of operations in which the hedged item is recorded.

No ineffectiveness was recognized on commodity cash flow hedges during the periods ended December 31, 2002 and 2001.

NRG Energy’s pre-tax earnings for the years ended December 31, 2002 and 2001 were increased by an unrealized gain of $20.0 million and $14.1 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

During the years ended December 31, 2002 and 2001, NRG Energy reclassified gains of $96.6 million and $25.8 million, respectively, from OCI to current-period earnings and expects to reclassify an additional $8.9 million of deferred gains to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

To manage interest rate risk, NRG Energy has entered into interest-rate swaps that effectively fix the interest payments of certain floating rate debt instruments. Interest-rate swap agreements are accounted for as cash flow hedges. The effective portion of the cumulative gain or loss on the derivative instrument is reported as a component of OCI in shareholders’ equity and recognized into earnings as the underlying interest expense is incurred. Such reclassifications are included on the same line of the statement of operations in which the hedged item is recorded.

No ineffectiveness was recognized on interest rate cash flow hedges during the periods ended December 31, 2002 and 2001.

NRG Energy’s pre-tax earnings for the years ended December 31, 2002 and 2001 were increased by an unrealized loss of $32.0 million and $0, respectively, associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

During the years ended December 31, 2002 and 2001, NRG Energy reclassified losses of $28.8 million and $0.7 million, respectively, from OCI to current-period earnings and expects to reclassify $9.9 million of deferred losses to earnings during the next twelve months on interest rate swaps accounted for as hedges.

To preserve the U.S. dollar value of projected foreign currency cash flows, NRG Energy may hedge, or protect those cash flows if appropriate foreign hedging instruments are available.

No ineffectiveness was recognized on foreign currency cash flow hedges during the periods ended December 31, 2002 and 2001.

NRG Energy’s pre-tax earnings for each of the years ended December 31, 2002 and 2001 were increased by an unrealized gain of $0.3 million associated with foreign currency hedging instruments not accounted for as hedges in accordance with SFAS No. 133.

During the years ended December 31, 2002 and 2001, NRG Energy reclassified losses of $2.1 million and gains of $0.2 million, respectively, from OCI to current period earnings and expects to reclassify $0.3 million of deferred losses to earnings during the next twelve months on foreign currency swaps accounted for as hedges.

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

NRG Energy 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 Energy recalculated the asset impairment tests in accordance with SFAS No. 144 using the appropriate asset groupings for independent cash flows for each generation facility. As a result, NRG Energy concluded that asset impairments should have been recorded for two projects known as Bayou Cove Peaking Power LLC and Somerset Power LLC. Since NRG Energy concluded that the triggering events that led to the impairment charge were experienced in the third quarter of 2002, the asset impairments related to these projects should have been recorded as of September 30, 2002. NRG Energy calculated the asset impairment charges for Bayou Cove Peaking Power LLC and Somerset Power LLC to be $126.5 million and $49.3 million, respectively.

In connection with NRG Energy’s year-end audit, two additional items were found to be inappropriately recorded as of September 30, 2002. These items included the inappropriate treatment of interest rate swap transactions as cash flow hedges and the decrease in the value of a bond remarketing option from the original price paid by NRG Energy. The error correction for the interest rate swaps resulted in the recording of additional income of $61.6 million as of September 30, 2002. The recognition of the decrease in the value of the remarketing option resulted in a charge to income of $15.9 million as of September 30, 2002.

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:

During the fourth quarter of 2002, NRG Energy determined that it had inadvertently offset its investment in Jackson County, MS, bonds in the amount of $155.5 million against long-term debt of the same amount owed to the County. This resulted in an understatement of the Company’s assets by $155.5 million and liabilities by $155.5 million as of September 30, 2002. In addition, the restatement for Bayou Cove Peaking LLC and Somerset Power LLC impairments reduced the previously reported net property, plant and equipment balance by $175.8 million. The restatement for the interest rate swaps had no impact on total shareholder’s equity and the restatement for the remarketing option reduced other assets by $15.9 million.

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

During the fourth quarter of the year ended December 31, 2002, NRG Energy recorded $100.3 million of special charges including additional asset impairments and other restructuring costs. In addition, NRG Energy recorded $74.2 million of write downs and losses on sale of equity investments.

Brazos Valley — In January 2003, the project lenders foreclosed on NRG Energy’s ownership interests in NRG Brazos Valley GP, LLC, NRG Brazos Valley LP, LLC, NRG Brazos Valley Technology LP, LLC and NRG Brazos Valley Energy, LP, and the lenders thereby acquired all of the assets of the Brazos Valley project, a 633 MW project under construction near Houston, TX. NRG Energy agreed to the consensual foreclosure of the companies. NRG Energy received no cash proceeds upon completion of the foreclosure. As of December 31, 2002, NRG Energy recorded $24.0 million for the potential obligation to infuse additional amounts of capital to fund a debt service reserve account and the potential obligation to satisfy a contingent equity agreement.

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.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 31, 2002.


	NRG ENERGY, INC.

	/s/ GEORGE P. SCHAEFER

	George P. Schaefer
	Its Vice President and Treasurer

Each person whose signature appears below constitutes and appoints Richard C. Kelly, 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 March 31, 2003.

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 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 registrant’s board of directors (or persons performing the equivalent functions):


	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 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/ WAYNE H. BRUNETTI

	Wayne H. Brunetti
	Chairman and Chief Executive Officer


	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


	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


	(1)	Incorporated herein by reference to NRG Energy’s Registration Statement on Form S-1, as amended, Registration No. 333-33397.

	(2)	Incorporated herein by reference to NRG Energy’s annual report on Form 10-K for the year ended December 31, 1997.

	(3)	Incorporated herein by reference to NRG Energy’s quarterly report on Form 10-Q for the quarter ended March 31, 1998.

	(4)	Incorporated herein by reference to NRG Energy’s current report on Form 8-K filed on May 27, 1999.

	(5)	Incorporated herein by reference to NRG Energy’s quarterly report on Form 10-Q for the quarter ended June 30, 1999.


	(6)	Incorporated herein by reference to NRG Energy’s quarterly report on Form 10-Q for the quarter ended September 31, 1999.

	(7)	Incorporated herein by reference to NRG Energy’s current report on Form 8-K filed on November 16, 1999.

	(8)	Incorporated herein by reference to NRG Energy’s annual report on Form 10-K for the year ended December 31, 1999.

	(9)	Incorporated herein by reference to NRG Energy’s Registration Statement on Form S-1, as amended, Registration No. 333-35096.


(10)	Incorporated herein by reference to NRG Energy’s current report on Form 8-K filed on September 13, 2000.

(11)	Incorporated herein by reference to NRG Energy’s Registration Statement on Form S-3, as amended, Registration No. 333-52508.

(12)	Incorporated herein by reference to NRG Energy’s current report on Form 8-K filed on March 15, 2001.

(13)	Incorporated herein by reference to NRG Energy’s quarterly report on Form 10-Q for the quarter ended March 31, 2001.

(14)	Incorporated herein by reference to NRG Energy’s quarterly report on Form 10-Q for the quarter ended June 30, 2001.

(15)	Filed herein.

(16)	To be filed by amendment.


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		41-1724239
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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


Title of each class		Name of exchange on which registered

Corporate Units —		(Listed on the New York Stock Exchange)


Class		Outstanding at March 31, 2003

Class A — Common Stock, $0.01 par value		3 shares
Common Stock, $0.01 par value		1 share


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 Price 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
PART III
	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 Stockholders 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
SIGNATURES
CERTIFICATIONS
EXHIBIT INDEX
EX-3.1 Amended/Restated Certificate of Incorp.
EX-3.2 By-Laws
EX-4.23 Indenture
EX-4.24 Common Agreement
EX-4.25 Contingent Guaranty Agreement
EX-10.42 Key Executive Agreement - Scott J. Davido
EX-10.43 Severance Agreement of Ershel Redd
EX-10.44 Executive Officer Severance Plan - Pieper
EX-10.45 Severance Agreement of George Schaefer
EX-21 Subsidiaries of NRG Energy
EX-23.1 Consent of PricewaterhouseCoopers LLP
EX-99.1 Officer Certification


		Page No.

PART I
Item 1	Business		3
Item 2	Properties		18
Item 3	Legal Proceedings		20
Item 4	Submission of Matters to a Vote of Security Holders		29
PART II
Item 5	Market Price for the Registrant’s Common Equity and Related Stockholder Matters		29
Item 6	Selected Financial Data		30
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 7A	Quantitative and Qualitative Disclosures About Market Risk		55
Item 8	Financial Statements and Supplementary Data		57
Item 9	Changes in & Disagreements with Accountants on Accounting and Financial Disclosures		57
PART III
Item 10	Directors and Executive Officers of the Registrant		57
Item 11	Executive Compensation		59
Item 12	Security Ownership of Certain Beneficial Owners and Management		64
Item 13	Certain Relationships and Related Transactions		64
Item 14	Controls and Procedures		65
PART IV
Item 15	Exhibits, Financial Statements Schedules and Reports on Form 8-K		66
Signatures			149


	*Liquidity Issues — Current Status and Chain of Events*


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

Recourse Debt (unsecured)
NRG Energy ROARS	$	250.0		8.700	%		3/15/2005	$	10.9		—		9/16/2002
	$	250.0		8.700	%		3/15/2005	$	10.9		—		3/17/2003
NRG Energy senior notes	$	350.0		8.250	%		9/15/2010	$	14.4		—		9/16/2002
	$	350.0		8.250	%		9/15/2010	$	14.4		—		3/17/2003
NRG Energy senior notes	$	350.0		7.750	%		4/1/2011	$	13.6		—		10/1/2002
NRG Energy senior notes	$	500.0		8.625	%		4/1/2031	$	21.6		—		10/1/2002
NRG Energy senior notes	$	240.0		8.000	%		11/1/2003	$	9.6		—		11/1/2002
NRG Energy senior notes	$	300.0		7.500	%		6/1/2009	$	11.3		—		12/1/2002
NRG Energy senior notes	$	250.0		7.500	%		6/15/2007	$	9.4		—		12/15/2002
NRG Energy senior notes	$	340.0		6.750	%		7/15/2006	$	11.5		—		1/15/2003
NRG Energy senior debentures (NRZ Equity Units)	$	287.5		6.500	%		5/16/2006	$	4.7		—		11/16/2002
	$	287.5		6.500	%		5/16/2006	$	4.7		—		2/17/2003
NRG Energy senior notes	$	125.0		7.625	%		2/1/2006	$	4.8		—		2/1/2003
NRG Energy 364-day corporate revolving facility	$	1,000.0		various			3/7/2003	$	7.6		—		9/30/2002
	$	1,000.0		various			3/7/2003	$	18.6		—		12/31/2002
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
NRG South Central Generating LLC	$	500.0		8.962	%		3/15/2016	$	20.2	$	12.8		9/16/2002
	$	500.0		8.962	%		3/15/2016		—	$	12.8		3/17/2003
NRG South Central Generating LLC	$	300.0		9.479	%		9/15/2024	$	14.2		—		9/16/2002


	*Pending and Completed Consolidated Business Dispositions*


Item 4 —	*Submission of Matters to a Vote of Security Holders*


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



	Year Ended December 31,

	2002			2001		2000		1999			1998


	(In thousands)
Total operating revenues and equity earnings		2,281,149			2,411,459		1,810,138		491,689			173,673
Write downs and losses on equity method investments		196,192			—		—		—			—
Special charges		2,656,093			—		—		—			—
Total operating costs and expenses		4,869,165			1,793,503		1,326,474		384,781			122,206
Income/(loss) from continuing operations		(2,907,661	)		218,212		150,929		57,501			37,858
Income/(loss) from discontinued operations		(556,621	)		46,992		32,006		(306	)		3,874
Net Income/(loss)		(3,464,282	)		265,204		182,935		57,195			41,732
Total assets		10,883,688			12,913,597		5,978,992		3,431,892			1,293,477
Long-term debt, including current maturities		8,385,867			7,492,790		3,205,420		1,716,860			626,476


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


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


	Revenues and Equity in Earnings of Unconsolidated Affiliates


	*Eastern Region*


	*Central Region*


	*West Coast Region*


	*Other Equity Investments*


	Write-Downs and Losses on Sales of Equity Method Investments


	*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 and Impairment		• 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 • Judgment 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 • Market conditions in foreign countries • Regulatory and political environments and requirements
Litigation Claims and Assessments		• Impacts of court decisions • Estimates of ultimate liabilities arising from legal claims
Income Taxes and Valuation Allowance for Deferred Tax Assets		• Ability of tax authority decisions to withstand legal challenges or appeals • Anticipated future decisions of tax authorities • Application of tax statutes and regulations to transactions. • Ability to utilize tax benefits through carrybacks to prior periods and carryforwards to future periods. • Filing elections that may be made by Xcel Energy to include NRG Energy in its consolidated tax return


Location and Availability	Amount

Unrestricted cash at NRG Energy	$	394.3 million
Restricted cash at U.S. subsidiaries	$	249.5 million
Restricted cash at Non-U.S. subsidiaries	$	17.1 million
Cash on deposit with vendors and suppliers	$	40.8 million

Total	$	701.7 million



	Payments Due by Period as of December 31, 2002

									After
Contractual Cash Obligations	Total		Short Term		1-3 Years		4-5 Years		5 Years


	(In thousands)
Long term debt	$	8,385,867	$	7,193,237	$	147,162	$	145,761	$	899,707
Capital lease obligations		574,531		26,855		53,338		53,012		441,326
Operating leases		80,556		11,514		21,067		18,030		29,945

Total contractual cash obligations	$	9,040,954	$	7,231,606	$	221,567	$	216,803	$	1,370,978



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

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


	(In thousands)
Lines of credit	$	1,000,000	$	1,000,000		—		—		—
Stand by letters of credit		110,677		110,677		—		—		—
Guarantees		1,587,022		992,280		94,467		210,941		289,334

Total commercial commitments	$	2,697,699	$	2,102,957	$	94,467	$	210,941	$	289,334


Fair Value of contracts outstanding at the beginning of the period	$	72,236
Contracts realized or otherwise settled during the period		(119,061	)
Other changes in fair values		77,465

Fair value of contracts outstanding at the end of the period	$	30,640



	Fair Value of Contracts at Period-End

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

Prices actively quoted	$	5,825	$	(7,558	)		—		$	(1,908	)	$	(3,641	)
Prices based on models & other valuation methods	$	61,300	$	52,560		$	(22,977	)	$	(56,602	)	$	34,281

	$	67,125	$	45,002		$	(22,977	)	$	(58,510	)	$	30,640


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


	(In millions)

Year end December 31, 2002	$	118.6
Average		76.2
High		124.4
Low		42.0
Year end December 31, 2001		71.7
Average		78.8
High		126.6
Low		58.6
Year end December 31, 2000		116.0
Average		80.0
High		125.0
Low		50.0


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	Director, President-Enterprises Xcel Energy Inc., NRG President and Chief Operating Officer
Wayne H. Brunetti		61	Director, President and CEO Xcel Energy Inc., NRG Chairman and Chief Executive Officer
Gary R. Johnson		56	Director, Vice President and General Counsel Xcel Energy Inc.
William T. Pieper		37	Vice President and Controller
Scott J. Davido		41	Senior Vice President, General Counsel and Corporate Secretary
Ershel C. Redd Jr.		55	Senior Vice President, Commercial Operations
George P. Schaefer		52	Vice President and Treasurer
John P. Brewster		49	Vice President Worldwide Operations



				Annual Compensation							Long-Term Compensation


											Awards				Payouts

													Number of
								Other					Securities
								Annual			Restricted		Underlying
								Compen-			Stock		Options		LTIP		All Other
Name and				Salary		Bonus		sation			Awards		and SARs[6]		Payouts		Compensation
Principal Position		Year		($)		($)		($)			($)		(#)		($)		($)

Wayne Brunetti [1]			2002		—		—		—			—		—		—		—
	Chairman,President and		2001		—		—		—			—		—		—		—
	Chief Executive Officer		2000		—		—		—			—		—		—		—
David H. Peterson [2]			2002		208,334		—		38,647	[3]		—		—		—		1,754,424	[5]
	Former Chairman, President &		2001		491,670		750,000		13,689			—		265,500		—		9,902
	Chief Executive Officer		2000		397,340		474,000		28,678			—		120,000		1,212,067		22,923
John Brewster			2002		189,503		—		—			—		—		—		11,253	[7]
	Vice President — Worldwide		2001		155,317		102,552		5,000			—		7,000		—		4,660
	Operations		2000		91,741		24,343		—			—		800		—		157
William Pieper			2002		158,769		—		—			—		—		—		9,706	[10]
	Vice President & Controller		2001		138,302		153,994		—			—		41,000		—		—
			2000		127,554		74,612		—			—		1,414				2,976
Renee Sass [4]			2002		192,215		—		24,299			—		—		—		51,428	[8]
	Former Vice President Strategic		2001		175,004		203,500		27,270			—		35,000		—		—
	Planning & Asset Mgmt		2000		147,672		79,685		—			—		1,722				2,882
Craig Mataczynski [9]			2002		160,006		—		11,624	[11]		—		—		—		95,386	[12]
	Former Senior Vice President		2001		316,680		321,038		7,752			—		105,000		—		8,125
	North America		2000		278,340		276,500		6,303			—		60,000		186,250		3,059



Average	Estimated Annual Benefits for Years of Service Indicated Years of Service
Compensation
(Last 4 Years)	5		10		15		20		25		30

$ 50,000	$	4,500	$	9,000	$	13,500	$	19,000	$	25,000	$	31,500
100,000		8,500		17,000		25,500		35,000		45,500		56,000
150,000		12,500		25,000		38,000		51,500		66,000		80,500
200,000		16,500		33,500		50,000		68,000		86,500		105,000
250,000		21,000		41,500		62,500		84,000		107,000		129,500
300,000		25,000		49,500		74,500		100,500		127,500		154,000
350,000		29,000		58,000		87,000		117,000		147,500		178,500
400,000		33,000		66,000		99,000		133,000		168,000		203,000
450,000		37,000		74,000		111,500		149,500		188,500		227,500
500,000		41,000		82,500		123,500		166,000		209,000		252,000
550,000		45,500		90,500		136,000		182,000		229,500		276,500
600,000		49,500		98,500		148,000		198,500		250,000		301,000
650,000		53,500		107,000		160,500		215,000		270,000		325,500
700,000		57,500		115,000		172,500		231,000		290,500		350,000
750,000		61,500		123,000		185,000		247,500		311,000		374,500
800,000		65,500		131,500		197,000		264,000		331,500		399,000
850,000		70,000		139,500		209,500		280,000		352,000		423,500
900,000		74,000		147,500		221,500		296,500		372,500		448,000
950,000		78,000		156,000		234,000		313,000		392,500		472,500
1,000,000		82,000		164,000		246,000		329,000		413,000		497,000
1,050,000		86,000		172,000		258,500		345,500		433,500		521,500
1,100,000		90,000		180,500		270,500		362,000		454,000		546,000
1,150,000		94,500		188,500		283,000		378,000		474,500		570,500
1,200,000		98,500		196,500		295,000		394,500		495,000		595,000


Mr. Peterson			38.33
Mr. Mataczynski			20.00
Mr. Pieper			7.67
Mrs. Sass			11.50
Mr. Brewster			2.75


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


Item 13 —	*Certain Relationships and Related Transactions*


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