UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

Commission File No. 001-15891

NRG Energy, Inc.

(612) 373-5300

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01 per share

     Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [   ]

     Indicate by check mark 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. [   ]

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

     As of the last business day of the most recently completed second fiscal quarter, the aggregate market value of the common stock of the registrant held by non-affiliates was approximately $1,943,806,466.

     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 [X] No [   ]

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

Documents Incorporated by Reference:
None

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NRG ENERGY, INC. AND SUBSIDIARIES

INDEX

In connection with the upcoming registration of our 8% Second Priority Senior Notes due December 15, 2013 issued on December 17, 2003 and January 28, 2004, we are reissuing our audited financial statements for the year ended December 31, 2003 as Amendment No. 2 on Form 10-K/A. The updated information includes 2004 discontinued operations as described in Note 6 and consolidating financial statements as required by Rule 3-10 of Regulation S-X as described in Note 30. Discontinued operations have been updated to include the addition of entities related to the sale of our interests in Penobscot Energy Recovery Company, Compania Boliviana De Energia Electrica S.A. – Bolivian Power Company Limited, LSP Energy and Hsin Yu. Our segment reporting disclosures, as shown in Note 20, have been restated to be consistent with the realignment of our management team and our segment disclosures included in our quarterly financials included in our Form 10-Q for the quarter ended June 30, 2004, filed on August 9, 2004. In addition, we have attached to this Form 10-K/A exhibits 99.2 through 99.9, the audited financial statements of eight significant guarantor subsidiaries as required by Rule 3-16 of Regulation S-X.

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Item 6 — Selected Financial Data

     The following table presents our selected financial data. 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 as discontinued operations. For additional information refer to Item 15 — Note 6 to the Consolidated 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 adoption of Fresh Start reporting as of December 5, 2003, the Successor Company’s post Fresh Start balance sheet and statement of operations have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of Fresh Start reporting. A black line has been drawn to separate and distinguish between Reorganized NRG and the Predecessor Company.

N/A — Not Applicable.

     The following table provides the detail of our revenues from majority-owned operations:

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     Energy and energy related revenue consists of revenues received upon the physical delivery of electrical energy to a third party at both spot (merchant sales) and contracted rates. In addition, we also generate revenues from the sale of ancillary services and by entering into certain financial transactions. Ancillary revenues are derived from the sale of energy related products associated with the generation of electrical energy such as spinning reserves, reactive power and other similar products. Revenues derived from financial transactions are generally received upon the settlement of transactions relating to the sale of energy or fuel which do not require the physical delivery of the underlying commodity.

     Capacity revenue consists of revenues received from a third party at either spot (merchant sales) or negotiated contract rates for making installed generation capacity available upon demand in order to satisfy system integrity and reliability requirements. In addition, capacity revenues includes revenues received under tolling arrangements which entitle third parties to dispatch our facilities and assume title to the electrical generation produced from that facility.

     Alternative energy revenue consists of revenues received from the sale of steam, hot and chilled water generally produced at a central district energy plant and sold to commercial, governmental and residential buildings for space heating, domestic hot water heating and air conditioning. Alternative energy revenue includes the sale of high-pressure steam produced and delivered to industrial customers that is used as part of an industrial process. In addition, alternative revenue includes revenues received from the processing of municipal solid waste into refuse derived fuel that is sold to a third party to be used as fuel in the generation of electricity.

     O&M fees consist of revenues received from providing certain unconsolidated affiliates with management and operational services generally under long-term operating agreements.

     Other revenues consist of miscellaneous other revenues derived from the sale of natural gas, recovery of incurred costs under reliability agreements and revenues received under leasing arrangements.

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

Overview

     We are a wholesale power generation 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. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type and dispatch levels, which help us, mitigate risk. We intend to maximize operating income through the efficient procurement and management of fuel supplies and maintenance services, and the sale of energy, capacity and ancillary services into attractive spot, intermediate and long-term markets.

     Our focus will continue to be on the operating performance of our entire portfolio and, in particular, on developing the assets in our core regions into integrated businesses well-suited to serving the requirements of the load-serving entities in our core markets. Power sales, fuel procurement and risk management will remain a key strategic element of these regional businesses contributing to our overall objective to optimize the operating income generated by all of our facilities within an appropriate risk and liquidity profile. Our business will involve the reinvestment of capital in our existing assets for reasons of life extension, repowering, expansion, environmental remediation, operating efficiency, greater fuel optionality or for alternative use, among other reasons. Our business also may involve select acquisitions intended to complement and enhance the commercial performance of the asset portfolios in our core regions.

     Industry Trends. In this “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we discuss our historical results of operations and expected financial condition. During 2002 and 2003, the following factors, among others, have negatively affected our results of operations:

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     We expect that these generally weak market conditions will continue for the foreseeable future in some markets. Historically, we have believed that, as supply surpluses begin to tighten and as market rules and regulatory conditions stabilize, prices will improve for energy, capacity and ancillary services. This view is consistent with our belief that in the long run market prices will support an adequate rate of return on the construction of new power generation assets needed to meet increasing demand. This view is currently being challenged in certain markets as regulatory actions and market rules unfold that limit the ability of merchant power companies to earn favorable returns on existing and new investments. To the extent unfavorable regulatory and market conditions exist in the long term; we could have significant impairments of our property, plant and equipment, which, in turn, could have a material adverse effect on our results of operations. Further, this could lead to us closing certain of our facilities resulting in additional economic losses and liabilities.

     Asset Sales. As part of our strategy, we plan to continue the selective divestment of certain assets. Since July 2002, we have sold or made arrangements to sell a number of assets and equity investments. In addition, we are currently marketing our interest in certain other non-strategic assets.

     Discontinued Operations. We have classified certain business operations, and gains/losses recognized on sale, as discontinued operations for projects that were sold or have met the required criteria for such classification pending final disposition. Accounting regulations require that continuing operations are reported separately in the income statement from discontinued operations, and that any gain or loss on the disposition of any such business be reported along with the operating results of such business. Assets classified as “discontinued operations” on our balance sheet as of December 31, 2003 include McClain, Penobscot Energy Recovery Company (PERC), Compania Boliviana De Energia Electrica S.A. Bolivian Power Company Limited, or “Cobee”, LSP Energy and Hsin Yu projects. For the periods January 1, 2003 through December 5, 2003, discontinued results of operations include our McClain, PERC, Cobee, Killingholme, NEO Landfill Gas, Inc., or “NLGI”, three NEO Corporation projects (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC), Timber Energy Resources, Inc., or “TERI”, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu projects. For the period December 6, 2003 through December 31, 2003, discontinued results of operations included McClain, PERC, Cobee, LSP Energy and Hsin Yu. All prior periods presented have been restated accordingly.

     New Management. On October 21, 2003, we announced the appointment of David Crane as our President and Chief Executive Officer, effective December 1, 2003. Before joining us, Mr. Crane served as the Chief Executive Officer of London-based International Power PLC and has over 12 years of energy industry experience. On March 11, 2004 we announced the appointment of Robert Flexon as Executive Vice President and Chief Financial Officer, effective March 29, 2004. Before joining us Mr. Flexon served as Vice President, Work Processes, Corporate Resources and Development at Hercules, Inc. In addition, we have filled several other senior and middle management positions over the last 12 months. Our board of directors currently is comprised of Mr. Crane and ten independent individuals, three of whom have been designated by MatlinPatterson, a significant holder of NRG common stock.

     Independent Registered Public Accounting Firm; Audit Committee. On May 3, 2004, we announced that we had initiated a search for a new independent auditor because PricewaterhouseCoopers LLP, our previous auditor, informed us that they would not be standing for re-election as our independent auditor for the year ended December 31, 2004. For each of the two fiscal years ended December 31, 2002 and 2003 and for the period from January 1, 2004 through April 27, 2004, there had been no disagreements with

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PricewaterhouseCoopers on any matters of accounting principles or practices, financial statement disclosure or auditing scope or procedure.

     On May 25, 2004, we announced that the audit committee of our board of directors had engaged KPMG LLP to serve as our independent auditor, effective immediately. On August 4, 2004, our stockholders ratified the appointment of KPMG LLP as our independent registered public accounting firm at our 2004 annual meeting of stockholders. KPMG’s engagement with us commenced with its review of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004.

     Our new board of directors appointed an audit committee consisting entirely of independent directors in January 2004. Pursuant to its charter, the committee appoints, retains, oversees, evaluates, compensates and terminates on its sole authority our independent auditors and approves all audit engagements, including the scope, fees, and terms of each engagement. The audit committee’s oversight process is intended to ensure that we will continue to have high-quality, cost efficient independent auditing services.

Results of Operations

     Due to the adoption of Fresh Start as of December 5, 2003, Reorganized NRG’s balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with, and are therefore generally not comparable to those of the Predecessor Company prior to the application of Fresh Start. In accordance with SOP 90-7, Reorganized NRG’s balance sheet, statement of operations and statement of cash flows have been presented separately from those of the Predecessor Company.

     Reorganized NRG’s revenues from majority-owned operations, operating costs and expenses and general, administrative and development expenses, were not significantly affected by the adoption of Fresh Start. Therefore, the Predecessor Company’s 2003 amounts have been combined with Reorganized NRG’s 2003 amounts for comparison and analysis purposes herein.

     Reorganized NRG’s net loss, equity in earnings of unconsolidated affiliates, depreciation and amortization, other income (expense), other charges, income taxes and discontinued operations were affected by the adoption of Fresh Start. Therefore, the Predecessor Company’s 2003 and the Reorganized NRG’s 2003 amounts are discussed separately for comparison and analysis purposes herein.

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For the Year Ended December 31, 2003 Compared to the Year Ended December 31, 2002

     Net Income

     Predecessor Company

     During the period January 1, 2003 through December 5, 2003, we recorded net income of $2.8 billion. Net income for the period is directly attributable to our emerging from bankruptcy and adopting the Fresh Start provisions of SOP 90-7. Upon the confirmation of our Plan of Reorganization and our emergence from bankruptcy we were able to remove significant amounts of long-term debt and other prepetition obligations from our balance sheet. Accordingly, as part of net income from continuing operations, we recorded a net gain of $4.1 billion as the impact of our adopting Fresh Start in our statement of operations, $6.0 billion of this amount is directly related to the forgiveness of debt and settlement of substantial amounts of our pre-petition obligations upon our emergence from bankruptcy. In addition to the removal of substantial amounts of pre-petition debt and other obligations from our balance sheet, we have also revalued our assets and liabilities to fair value, accordingly we have substantially written down the value of our fixed assets. We have recorded a net $1.7 billion charge related to the revaluation of our assets and liabilities within the Fresh Start Reporting adjustment line of our consolidated statement of operations. In addition to our recording adjustments related to our emergence from bankruptcy, we also recorded substantial charges related to other items such as the settlement of certain outstanding litigation in the amount of $462.6 million, write downs and losses on the sale of equity investments of $147.1 million, advisor cost and legal fees directly attributable to our being in bankruptcy of $197.8 million and $237.6 million of other asset impairment and restructuring costs incurred prior to our filing for bankruptcy. Net income for the period January 1, 2003 through December 5, 2003 was also favorably impacted by our not recording interest expense on substantial amounts of corporate level debt while we were in bankruptcy and by the continued favorable results experienced by our equity investments.

     During the year ended December 31, 2002, we recognized a net loss of $3.5 billion. The loss from continuing operations incurred during 2002 primarily consisted of $2.6 billion of other charges consisting primarily of asset impairments.

     Reorganized NRG

     During the period December 6, 2003 through December 31, 2003, we recognized net income of $11.0 million or $0.11 per share of common stock. Net income was directly attributable to a number of factors some of which are discussed below. From an overall operational perspective our facilities were profitable during this period. Our results were adversely impacted by our having to continue to satisfy the standard offer service contract that we entered into with Connecticut Light & Power, or “CL&P” in 2000. As a result of our inability to terminate this contract during our bankruptcy proceeding we continued to be exposed to losses under this contract. These losses were incurred, as we were unable to satisfy the requirements of this contract at a price/cost below the contracted sales price. Upon our adoption of Fresh Start, we recorded at fair value, all assets and liabilities on our opening balance sheet and accordingly we recorded as an obligation the fair value of the CL&P contract. During the period December 6, 2003 through December 31, 2003, we recognized as revenues, the entire fair value of this contract effectively offsetting the actual losses incurred under this contract. The CL&P contract terminated on December 31, 2003.

     Revenues from Majority Owned Operations

     Our operating revenues from majority owned operations were $1.9 billion in 2003, compared to $1.9 billion in the prior year, a decrease of $1.4 million or less than 1%.

     Revenues from majority owned operations of $1.9 billion for the year 2003, includes $1.1 billion of energy revenues, $605.9 million of capacity revenues, $128.0 million of alternative energy, $14.1 million of O&M fees and $118.5 million of other revenues which include financial and physical gas sales, sales from our Schkopau facility and NEPOOL expense reimbursements. The decrease of $1.4 million is due to increased capacity revenues resulting from additional projects becoming operational in the later part of 2002, higher sales in New York, and by our recognizing, as additional revenues, the fair value of the out-of-market CL&P contract upon our emergence from bankruptcy. Offsetting these increases, we continued to recognize losses on the CL&P contract throughout 2003 resulting from higher market prices and lower generation.

     Cost of Majority-Owned Operations

     Our cost of majority owned operations related to continuing operations was $1.5 billion in 2003, compared to $1.3 billion for 2002, an increase of $118.9 million or 8.9%. For 2003 and 2002, cost of majority owned operations represented 75.0% and 68.8% 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 our majority owned operations.

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     For the year 2003, cost of energy was $902.4 million compared to $900.9 million for 2002, representing an increase of $1.5 million. As a percent of revenue from majority owned operations, cost of energy was 46.6% and 46.5%, for 2003 and 2002, respectively. Cost of energy was directly affected by an overall decrease in the cost of fuel during 2003 and a favorable change in the fair value of our energy related derivatives resulting from contract terminations. Offsetting this decrease are liquidated damages of $72.9 million triggered from our financial condition.

     Depreciation and Amortization

     Predecessor Company

     Our depreciation and amortization expense related to continuing operations was $219.2 million for the period January 1, 2003 through December 5, 2003 and $208.1 million for the year ended December 31, 2002. Depreciation and amortization consists of the allocation of our historical depreciable fixed asset costs over the remaining lives of such property as well as the amortization of certain contract based intangible assets.

     Reorganized NRG

     Our depreciation and amortization expense related to continuing operations was $11.8 million for the period December 6, 2003 through December 31, 2003. Depreciation and amortization consists of the allocation of our newly valued basis in our fixed assets over newly determined remaining fixed asset lives. As part of adopting the Fresh Start concepts of SOP 90-7 our tangible fixed assets were recorded at fair value as determined by a third party valuation expert who we also consulted with in determining the appropriate remaining lives for our tangible depreciable property. Depreciation expense for this period was based on preliminary depreciable lives and asset balances.

     General, Administrative and Development

     Our general, administrative and development costs for 2003 were $182.9 million compared to $218.9 million for 2002, a decrease of $36.0 million or 16.4%. For 2003 and 2002, general, administrative and development costs represent 9.4% and 11.3% of revenues from majority owned operations, respectively. This decrease is due to decreased costs related to work force reduction efforts, cost reductions due to the closure of certain international offices and reduced legal costs. Outside services also decreased, due to less non-restructuring legal activities.

     Other Charges (Credits)

     During the period January 1, 2003 to December 5, 2003, we recorded other credits of $3.2 billion, which consisted primarily of $228.9 million related to asset impairments, $462.6 million related to legal settlements and $197.8 million related to reorganization charges and $8.7 million related to restructuring charges. We also incurred a $4.1 billion credit related to Fresh Start adjustments. During 2002, we recorded other charges of $2.6 billion, which consisted primarily of $2.5 billion related to asset impairments and $111.3 million related to restructuring charges.

     We review the recoverability of our long-lived assets on a periodic basis and if we determined that an asset was impaired, we compared asset-carrying values to total future estimated undiscounted cash flows. Separate analyses are completed for assets or groups of assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The estimates of future cash flows included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of our assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service are based on the asset’s existing service potential. The cash flow estimates may include probability weightings to consider possible alternative courses of action and outcomes, given the uncertainty of available information and prospective market conditions.

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

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     Impairment charges (credits) included the following for the year ended December 31, 2002 and for the period January 1, 2003 to December 5, 2003 and the period December 6, 2003 through December 31, 2003.

     Reorganization Items

     For the period from January 1, 2003 to December 5, 2003, we incurred $197.8 million in reorganization costs and for the period from December 6, 2003 to December 31, 2003 we incurred $2.5 million in reorganization costs. All reorganization costs have been incurred since we filed for bankruptcy in May 2003. The following table provides the detail of the types of costs incurred (in thousands):

     Restructuring Charges

     We incurred total restructuring charges of approximately $111.3 million for the year ended December 31, 2002. These costs consisted of employee separation costs and advisor fees. We incurred an additional $8.7 million of employee separation costs and advisor fees during 2003 until we filed for bankruptcy in May 2003. Subsequent to that date we recorded all advisor fees as reorganization costs.

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     Legal Settlement Costs

     During 2003, we recorded $396.0 million in connection with the resolution of the FirstEnergy Arbitration Claim. As a result of this resolution, FirstEnergy retained ownership of the Lake Plant Assets and received an allowed general unsecured claim of $396.0 million under the NRG plan of reorganization submitted to the bankruptcy court.

     In November 2003, we settled various litigation with Fortistar Capital in which Fortistar Capital released us from all litigation claims in exchange for a $60.0 million pre-petition claim and an $8.0 million post-petition claim. We had previously recorded $10.8 million in connection with various legal disputes with Fortistar Capital; accordingly, we recorded an additional $57.2 million during November 2003.

     In August of 1995, we entered into a Marketing, Development and Joint Proposing Agreement or “the Marketing Agreement”, with Cambrian Energy Development LLC, or “Cambrian.” Various claims had arisen in connection with this Marketing Agreement. In November 2003, we entered into a Settlement Agreement with Cambrian where we agreed to transfer our 100% interest in three gasco projects (NEO Ft. Smith, NEO Phoenix and NEO Woodville) and our 50% interest in two genco projects (MM Phoenix and MM Woodville) to Cambrian. In addition, we agreed to pay approximately $1.8 million in settlement of royalties incurred in connection with the Marketing Agreement. We had previously recorded a liability for royalties owed to Cambrian; therefore, we recorded an additional $1.4 million during November 2003.

     In November 2003, we settled our dispute with Dick Corporation in connection with Meriden Gas Turbines, which resulted in our recording an additional liability of $8.0 million in November 2003.

     Fresh Start Adjustments

     During the fourth quarter of 2003, we recorded a credit of $4.1 billion in connection with fresh start adjustments as discussed in Item 15 — Note 3. Following is a summary of the significant effects of the reorganization and Fresh Start:

     Other Income (Expense)

     Predecessor Company

     During the period January 1, 2003 through December 5, 2003, we recorded other expense of $286.9 million. Other expense consisted primarily of $329.9 million of interest expense and $147.1 million of write downs and losses on sales of equity method investments, partially offset by equity in earnings of unconsolidated affiliates of $170.9 million and $19.2 million of other income.

     For the year ended December 31, 2002, other expenses was $572.2 million, which consisted primarily of $452.2 million of interest expense and $200.5 million of write downs and losses on sales of equity method investments.

     Interest expense for the period January 1, 2003 through December 5, 2003 of $329.9 million consisted of interest expense on both our project and corporate level interest bearing debt. In addition, interest expense includes the amortization of debt issuance costs and

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any interest rate swap termination costs. Subsequent to our entering into bankruptcy we ceased the recording of interest expense on our corporate level debt as these prepetition claims were deemed to be impaired and subject to compromise. We did not however cease to record interest expense on the project level debt outstanding at our Northeast Generating and South Central Generating facilities even though these entities were also in bankruptcy as these claims were deemed to be most likely not impaired and not subject to compromise. We also recorded substantial amounts of fees and costs related to our acquiring a debtor in possession financing arrangement while we were in bankruptcy. In addition, upon our emergence from bankruptcy we wrote off any remaining deferred finance costs related to our corporate and project level debt including our Northeast and South Central project level debt as it was probable that they would be refinanced upon our emergence from bankruptcy.

     Reorganized NRG

     Other income (expense) for the period December 6, 2003 through December 31, 2003, was an expense of $5.4 million and consisted primarily of $18.9 million of interest expense, partially offset by $13.5 million of equity earnings from unconsolidated subsidiaries.

     Interest expense for the period December 6, 2003 through December 31, 2003 of $18.9 million consists primarily of interest expense at the corporate level, primarily related to the newly issued high yield notes, term loan facility and revolving line of credit used to refinance certain project level financings. In addition, interest expense includes the amortization of deferred financing costs incurred as a result of our refinancing efforts and the amortization of discounts and premiums recorded upon the marking of our debt to fair value upon our adoption of the Fresh Start provision of SOP 90-7.

     Minority Interest in Earnings of Consolidated Subsidiaries

     For the period December 6, 2003 through December 31, 2003, minority interest in earnings of consolidated subsidiaries was $134,000 and relates primarily to Northbrook New York and Northbrook Energy.

     Write-Downs and Losses on Sales of Equity Method Investments

     As we periodically review our equity method investments for impairments we have taken substantial write-downs and losses on sales of equity method investments during the period January 1, 2003 through December 5, 2003 and for the year 2002. In 2003 we recorded impairments and losses on the sales of investments of $147.1 million compared to $200.5 million in 2002. The $147.1 million recorded in 2003 consists of the write down of our investment in the Loy Yang project of $146.4 million and our investment in the NEO Corporation — Minnesota Methane project of $12.3 million during 2003. These losses were partially offset by gains on the sale of our investment in the ECKG and Mustang projects. During 2002 we recorded write-downs and losses on sales of equity method investments of $200.5 million. The $200.5 million recorded in 2002 consists of a write down of our investment in the Loy Yang project of $111.4 million, a loss of $48.4 million on the transfer of our interest in the Sabine River Works project to our partner, a $14.2 million write down related to our investment in our EDL project, a write down of our investment in our Kondapalli project of $12.7 million and a write down of our investment in NEO Corporation — Minnesota Methane and MM Biogas of $12.3 million and $3.3 million, respectively among others. See Item 15 — Note 7 to the Consolidated Financial Statements for additional information.

     Equity Earnings from Unconsolidated Affiliates

     Predecessor Company

     During the period January 1, 2003 through December 5, 2003, we recorded $170.9 million of equity earnings from investments in unconsolidated affiliates. Our 50% investment in West Coast Power comprised $98.7 million of this amount with our investments in the Mibrag, Loy Yang, Gladstone and Rocky Road projects comprising $21.8 million, $17.9 million, $12.4 million and $6.9 million, respectively, with the remaining amounts attributable to various domestic and international equity investments. Our investment in West Coast Power continues to generate favorable earnings as well as our investments in Mibrag, Loy Yang, Gladstone and Rocky Road. For the year ended December 31, 2002, equity earnings from investments in unconsolidated affiliates was $69.0 million.

     Reorganized NRG

     Equity in earnings of unconsolidated affiliates of $13.5 million consists primarily of equity earnings from our 50% ownership in West Coast Power of $9.3 million.

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     Discontinued Operations

      During the first quarter of 2004, we determined that two additional projects had met the necessary criteria for discontinued operations treatment, Penobscot Energy Recovery Company , or “PERC ” and Compania Boliviana De Energia Electrica S.A. Bolivian Power Company Limited, or “Cobee” accordingly, all periods presented have been restated to reflect the addition of these projects as discontinued operations.

      During the second quarter of 2004, we determined that two more projects had met the necessary criteria for discontinued operations treatment, LSP Energy and Hsin Yu. Accordingly, all periods presented have been restated to reflect the addition of these projects as discontinued operations.

     Predecessor Company

     As of December 5, 2003, we classified as discontinued operations the operations and gains/losses recognized on the sales of projects that were sold or were deemed to have met the required criteria for such classification pending final disposition. For the period January 1, 2003 through December 5, 2003, discontinued operations consist of the historical operations and net gains/losses related to our Killingholme, McClain, PERC, Cobee, NLGI, NEO Corporation projects, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu projects. Discontinued operations for the year ended December 31, 2002 consisted of our Crockett Cogeneration, Entrade, Killingholme, Csepel, Bulo Bulo, McClain, PERC, Cobee, NLGI, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu projects.

     For the period January 1, 2003 through December 5, 2003, the results of operations related to such discontinued operations was a net loss of $180.8 million due to a loss on the sale of our Peru projects, impairment charges recorded at McClain and NLGI and fresh start adjustment at LSP Energy.

     During 2002 we recognized a loss on discontinued operations of $673.1 million due to asset impairments recorded at Killingholme, NLGI, TERI, LSP Energy and Hsin Yu projects.

     Reorganized NRG

     Discontinued operations for the period December 6, 2003 through December 31, 2003 is comprised of a loss of $0.3 million attributable to the on going operations of our McClain, PERC, Cobee, LSP Energy and Hsin Yu projects.

     Income Tax

     Predecessor Company

     Income tax benefit/expense for the period January 1, 2003 through December 5, 2003 was a tax expense of $37.9 million as compared to a tax benefit of $166.9 million for the year ended December 31, 2002. The income tax expense for the period ended December 5, 2003 was primarily due to separate company income tax liabilities and an increase in the valuation allowance against deferred tax assets. An additional valuation allowance of $33 million was recorded against deferred tax assets of NRG West Coast as a result of its conversion from a corporation to a single member limited liability company (a disregarded entity for federal income tax purposes).

     The effective income tax rate for the period January 1, 2003 through December 5, 2003 is relatively low since the U.S. net operating loss carryforwards are offset by the cancellation of debt income resulting from the Bankruptcy. The income tax benefit for the year ended December 31, 2002 was primarily due to the increase in deferred tax assets relating to impairments recognized for financial reporting purposes. A valuation allowance was increased limiting the recognition of deferred tax assets to the extent of previously recorded deferred tax liabilities.

     Income taxes have been recorded on the basis that our U.S. subsidiaries and we will file separate federal income tax returns for the period January 1, 2003 through December 5, 2003. Since our U.S. subsidiaries and we will not be included in the Xcel Energy consolidated tax group, each of our U.S. subsidiaries that is classified, as a corporation for U.S. income tax purposes must file a separate federal income tax return. It is uncertain if, on a stand-alone basis, we would be able to fully realize deferred tax assets related to net operating losses and other temporary differences, therefore a full valuation allowance has been established.

     Reorganized NRG

     Income tax benefit/expense for the period December 6, 2003 through December 31, 2003 was a tax benefit of $0.7 million which consists of a U.S. tax benefit of $1.5 million and foreign tax expense of $0.8 million. The foreign tax expense for the period is due to earnings in the foreign jurisdictions.

     Our U.S. subsidiaries and we will file a consolidated federal income tax return for the period December 6, 2003 through December 31, 2003. With the exception of alternative minimum tax, or “AMT”, we anticipate that our cash tax rate for the next 5 years will be relatively low as we realize the cash tax benefits from using our net operating loss carryforwards. For AMT purposes, utilization of net operating losses is limited on an annual basis.

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     Due to the uncertainty of realization of deferred tax assets related to net operating losses and other temporary differences, the change in U.S. current and deferred income taxes has been fully offset by a change in the valuation allowance and our U.S. net deferred tax assets at December 31, 2003 were offset by a full valuation allowance in accordance with SFAS 109. Regarding the valuation allowance as of December 5, 2003, SOP 90-7 requires any future benefits from reducing the valuation allowance from preconfirmation net operating loss carryforwards be reported as a direct addition to paid-in-capital versus a benefit on our income statement. Consequently, our effective tax rate in post Bankruptcy emergence years will not benefit from utilization of our net operating loss carryforwards which were fully valued as of the date of our emergence from Bankruptcy.

     As of December 31, 2003, our management intends to indefinitely reinvest the earnings from our foreign operations. Accordingly, U.S. income taxes and foreign withholding taxes were not provided on the earnings of our foreign subsidiaries.

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

     Net Income/(Loss)

     During the year ended December 31, 2002, we recognized a net loss of $3.5 billion. This loss represented a decrease in earnings of $3.7 billion compared to net income of $265.2 million for the same period in 2001. Our loss from continuing operations was $2.8 billion for the year ended December 31, 2002 compared to net income of $210.0 million from continuing operations for the same period in 2001. The loss from continuing operations incurred during 2002 primarily consists of $2.6 billion of other charges consisting primarily of asset impairments.

     During 2002, our continuing operations experienced less favorable results than those experienced during the same period in 2001. Overall, our domestic power generation operations performed poorly compared to the same period in 2001. Our 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, the California joint venture of which we own 50%, which reduced our equity in the earnings of that joint venture 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 offsetting these earnings reductions was the recognition, in the fourth quarter of 2002, of approximately $51.0 million of additional revenues related to the contractual termination of a power purchase agreement with our Indian River project.

     During the third quarter of 2002, we experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. These events led to impairments of a number of our assets, resulting in pre-tax charges related to continuing operations of approximately $2.5 billion during 2002. In addition, approximately $200.5 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. The period ended December 31, 2002, consisted of the historical operations and net gains/losses related to our Crockett Cogeneration, Entrade, Killingholme, Csepel, Bulo Bulo, McClain, PERC, Cobee, NLGI, NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu Projects.

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

     Revenues from Majority-Owned Operations

     Our operating revenues from majority-owned operations were $1.9 billion in 2002 compared to $2.1 billion in the prior year, a decrease of $147.0 million or approximately 7.1%. Revenues from majority-owned operations for the year ended December 31, 2002, consisted primarily of power generation revenues from domestic operations of approximately $1.5 billion in 2002 compared with $1.6 billion in 2001, a decrease of $158.1 million. This decrease in domestic generation revenue is due to reductions in energy and capacity sales and an overall decrease in power pool prices.

     The Northeast region experienced decreased revenues, as they 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

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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.

     Our International revenues from majority-owned operations decreased by $6.9 million or 2.4% from 2001 to 2002. The Australia region reported a reduction in revenues of $42.5 million while increases were reported from the Other International region of $35.6 million. The reduction in Australia revenue is primarily due to a decline in energy prices and the loss of a significant contract at Flinders. The increase in Other International revenue is primarily due to a full year of operations for acquisitions made in 2001.

     Operating Costs and Expenses

     For the year ended December 31, 2002, cost of majority-owned operations related to continuing operations was $1.3 billion compared to $1.4 billion for 2001, a decrease of $42.8 million or approximately 3.1%. For the years ended December 31, 2002 and 2001, cost of majority-owned operations represented approximately 68.8% and 66.0% 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 our majority-owned operations.

     For the year ended December 31, 2002, cost of energy was $900.9 million compared to $971.4 million for the year ended December 31, 2001. This represents a decrease of $70.5 million or 7.3%. As a percent of revenue from majority-owned operations cost of energy was 46.5% and 46.6% for the years ended December 31, 2002 and 2001, respectively.

     For the year ended December 31, 2002, operating and maintenance costs were $361.4 million compared to $321.1 million for the year ended December 31, 2001. This represents an increase of $40.3 million or 12.6%. As a percent of revenue from majority-owned operations, operating and maintenance costs represented 18.6% and 15.4%, for the years ended December 31, 2002 and 2001, respectively. The increase in operating and maintenance expense is primarily due to a full year of expense in 2002 related to assets acquired during 2001.

     Depreciation and Amortization

     For the year ended December 31, 2002, depreciation and amortization related to continuing operations was $208.1 million, compared to $142.1 million for the year ended December 31, 2001, an increase of $66.0 million or approximately 46.5%. This increase is primarily due to the addition of property, plant and equipment related to our acquisitions of electric generating facilities completed during 2002.

     General, Administrative and Development

     For the year ended December 31, 2002, general, administrative and development costs were $218.9 million, compared to $187.3 million for the year ended December 31, 2001, an increase of $31.6 million or approximately 16.9%. For the year ended December 31, 2002 and 2001, general, administrative and development costs represent 11.3% and 9.0% of revenues from majority-owned operations, respectively. This increase is primarily due to an increase in bad debt expense. Additionally there was an increase in other general administrative expenses due to 2001 acquisitions and 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.

     Other Charges

     During the third quarter of 2002, we experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. We applied the provisions of SFAS No. 144 to our construction and operational projects. We completed an analysis of the recoverability of the asset carrying values of our projects factoring in the probability of different courses of action available to us given our financial position and liquidity constraints. As a result, we determined during the third quarter that many of our construction projects and certain operational projects were impaired and should be written down to fair market value. To estimate fair value, our management considered discounted cash flow analyses, bids and offers related to those projects and prices of similar assets. During 2002, we recorded asset impairment and other special charges related to continuing operations of $2.6 billion. See Item 15 — Note 8 to the Consolidated Financial Statements for additional information.

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     Other Income (Expense)

     For the year ended December 31, 2002, total other expense was $572.2 million, compared to $131.1 million for the year ended December 31, 2001, an increase of $441.1 million or approximately 336.5%. The increase in total other expense from 2001 consisted primarily of an increase in interest expense and $200.5 million of write downs and losses on sales of equity method investments combined with lower equity earnings of unconsolidated affiliates.

     For the year ended December 31, 2002, we 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 $141.0 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 from California PX. Our share of this reserve was approximately $58.5 million on a pre-tax basis.

     For the year ended December 31, 2002, interest expense (which includes both corporate and project level interest expense) was $452.2 million, compared to $364.1 million in 2001, an increase of $88.1 million or approximately 24.2%. This increase is due primarily to increased corporate and project level debt. We 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.

     Other income was a gain of $11.4 million, as compared to $23.0 million for the year ended December 31, 2001, a decrease of $11.6 million, or approximately 50.3%. Other income consists primarily of interest income on cash balances and realized and unrealized foreign currency exchange gains and losses. Interest income was lower during 2002 due to lower interest from affiliates, primarily related to West Coast Power. In addition, there were significant foreign currency exchange losses during 2002.

     Write-Downs and Losses on Sales of Equity Method Investments

     For the year ended December 31, 2002, write-downs and losses on equity method investments were $200.5 million. The $200.5 million charge consists primarily of write-downs related to our investment in Loy Yang in the total amount of $111.4 million. In addition, we recorded a loss of $48.4 million upon the transfer of our investment in SRW Cogeneration and recorded write-downs of $14.2 million and $3.6 million of our investments in EDL and Collinsville, respectively.

     Income Tax

     Income tax benefit/expense for the year ended December 31, 2002 was a tax benefit of $166.9 million as compared to a tax expense of $38.0 million for the year ended December 31, 2001. The income tax benefit for the year ended December 31, 2002 was primarily due to the increase in deferred tax assets relating to impairments recognized for financial reporting purposes. A valuation allowance was increased limiting the recognition of deferred tax assets to the extent of previously recorded deferred tax liabilities. The income tax expense for the year ended December 31, 2001 was primarily due to U.S. and foreign operating earnings reduced by tax credits of $37.2 million.

     For 2002, income taxes were recorded on the basis that Xcel Energy would not include us in its consolidated federal income tax return following Xcel Energy’s acquisition of our public shares on June 3, 2002. Since Xcel Energy did not include us in its consolidated federal income tax return, we and each of our U.S. subsidiaries that is classified as a corporation for U.S. income tax purposes must file separate federal income tax returns. It is uncertain if, on a stand-alone basis, we will be able to fully realize deferred tax assets related to net operating losses and other temporary differences, consequently, a valuation allowance of $1.1 billion was recorded as of December 31, 2002.

     For 2001, our U.S. subsidiaries and we were included in the Xcel Energy consolidated federal income tax return through March 12, 2001, the date of our secondary public offering. For the remainder of the year, we filed a consolidated federal return with our U.S. subsidiaries. Income tax expense was recorded on current and deferred tax liabilities, partially offset by benefits from tax credits.

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     Discontinued Operations

     Subsequent to December 31, 2002, we determined that additional projects had met the necessary criteria for discontinued operations treatment, McClain, PERC, Cobee, NLGI, NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu, accordingly, we have restated all periods presented to reflect the addition of these projects as discontinued operations.

     As of December 31, 2002, we 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 our Crockett Cogeneration, Entrade, Killingholme, Csepel, Bulo Bulo, McClain, PERC, Cobee, NLGI, NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu that were sold in 2002 or were deemed to have met the required criteria for such classification pending final disposition. For 2002, the results of operations related to such discontinued operations was a net loss of $673.1 million as compared to a gain of $55.2 million for the same period in 2001. The primary reason for the loss recognized in 2002 is due to asset impairments recorded at Killingholme, TERI, NLGI, LSP Energy and Hsin Yu.

Reorganization and Emergence from Bankruptcy

     On May 14, 2003, we and 25 of our U.S. affiliates, filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code, “the Bankruptcy Code” in the United States Bankruptcy Court for the Southern District of New York, or the “bankruptcy court.”

     On May 15, 2003, NRG Energy, PMI, NRG Finance Company I LLC, NRGenerating Holdings (No. 23) B.V. and NRG Capital LLC, collectively “the Plan Debtors”, filed the NRG plan of reorganization and the related Disclosure Statement for Reorganizing Debtors’ Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code, as subsequently amended, “the Disclosure Statement.” The Bankruptcy Court held a hearing on the Disclosure Statement on June 30, 2003, and instructed the Plan Debtors to include certain additional disclosures. The Plan Debtors amended the Disclosure Statement and obtained Bankruptcy Court approval for the Third Amended Disclosure Statement for Debtors’ Second Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code.

     On November 24, 2003, the bankruptcy court issued an order confirming the NRG plan of reorganization, and the plan became effective on December 5, 2003. On September 17, 2003, the Northeast/South Central plan of reorganization was proposed after we secured the necessary financing commitments. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/South Central plan of reorganization and the plan became effective on December 23, 2003.

Financial Reporting by Entities in Reorganization under the Bankruptcy Code and Fresh Start

     Between May 14, 2003 and December 5, 2003, we operated as a debtor-in-possession under the supervision of the bankruptcy court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”, or “SOP 90-7.”

     For financial reporting purposes, the close of business on December 5, 2003, represents the date of emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:

     The implementation of the NRG plan of reorganization resulted in, among other things, a new capital structure, the satisfaction or disposition of various types of claims against the Predecessor Company, the assumption or rejection of certain contracts, and the establishment of a new board of directors.

     In connection with the emergence from bankruptcy, we adopted Fresh Start in accordance with the requirements of SOP 90-7. The application of SOP 90-7 resulted in the creation of a new reporting entity. Under Fresh Start, the enterprise value of our company was allocated among our assets and liabilities on a basis substantially consistent with purchase accounting in accordance with SFAS No. 141 “Business Combinations”, or “SFAS No. 141.” Accordingly, we pushed down the effects of this allocation to all of our subsidiaries.

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     Under the requirements of Fresh Start, we have adjusted our assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking our assets and liabilities to their estimated fair values, we determined that there was no excess reorganization value that was reallocated back to our tangible and intangible assets. Deferred taxes were determined in accordance with SFAS No. 109, “Accounting for Income Taxes.” The net effect of all Fresh Start adjustments resulted in a gain of $4.1 billion, which is reflected in the Predecessor Company’s results of operations for the period January 1, 2003 through December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

     As part of the bankruptcy process we engaged an independent financial advisor to assist in the determination of our reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from our core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, or “DCF”, valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisors prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted our project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

     In constructing our Fresh Start balance sheet upon our emergence from bankruptcy we used a reorganization equity value of approximately $2.4 billion, as we believe this value to be the best indication of the value of the ownership distributed to the new equity owners. Our NRG Plan of reorganization provided for the issuance of 100,000,000 shares of NRG common stock to the various creditors resulting in a calculated price per share of $24.04. Our reorganization value of approximately $9.1 billion was determined by adding our reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and our other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and bankruptcy court’s approval of the NRG plan of reorganization.

     We recorded approximately $4.1 billion of net reorganization income in the Predecessor Company’s statement of operations for 2003, which includes the gain on the restructuring of equity and the discharge of obligations subject to compromise for less than recorded amounts, as well as adjustments to the historical carrying values of our assets and liabilities to fair market value.

     Due to the adoption of Fresh Start as of December 5, 2003, the Reorganized NRG post-Fresh Start balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are therefore not comparable in certain respects to the financial statements prior to the application of Fresh Start. A black line has been drawn on the accompanying Consolidated Financial Statements to separate and distinguish between Reorganized NRG and the Predecessor Company. The effects of the reorganization and Fresh Start on our balance sheet as of December 5, 2003, were as follows (in thousands):

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19

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     APB No. 18, “The Equity Method of Accounting for Investments in Common Stock,” requires us to effectively push down the effects of Fresh Start reporting to our unconsolidated equity method investments and to recognize an adjustment to our share of the earnings or losses of an investee as if the investee were a consolidated subsidiary. As a result of pushing down the impact of Fresh Start to our West Coast Power affiliate, we determined that a contract based intangible asset with a one year remaining life, consisting of the value of West Coast Power’s California Department of Water Resources energy sales contract, must be established and recognized as a basis adjustment to our share of the future earnings generated by West Coast Power. This adjustment will reduce our equity earnings in the amount of approximately $10.4 million per month until the contract expires in December 2004.

Liquidity and Capital Resources

     Reorganized Capital Structure

     In connection with the consummation of the NRG plan of reorganization, on December 5, 2003 all shares of our old common stock were canceled and 100,000,000 shares of new common stock of NRG Energy were distributed pursuant to such plan to the holders of certain classes of claims. A certain number of shares of common stock were issued for distribution to holders of disputed claims as such claims are resolved or settled. In the event our disputed claims reserve is inadequate, it is possible we would have to issue additional shares of our common stock to satisfy such pre-petition claims or contribute additional cash proceeds. See Item 3 — Legal

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Proceedings — Disputed Claims Reserve. Our authorized capital stock consists of 500,000,000 shares of NRG Energy common stock and 10,000,000 shares of Serial Preferred Stock. Further, a total of 4,000,000 shares of our common stock, representing approximately 4% of our outstanding common stock, are available for issuance under our long-term incentive plan.

     In addition to our issuance of new common stock, on December 23, 2003, we completed a note offering consisting of $1.25 billion of 8% Second Priority Senior Secured Notes due 2013, or the “Second Priority Notes”, and we entered into a new credit facility consisting of a $950.0 million term loan facility, a $250.0 million funded letter of credit facility and a $250.0 million revolving credit facility. In January of 2004, we completed a supplementary note offering whereby we issued an additional $475.0 million of the Second Priority Notes at a premium and used the proceeds to repay a portion of the $950.0 million term loan. As of March 1, 2004, we had $1.7 billion in aggregate principal amount of Second Priority Notes outstanding, $446.5 million principal amount outstanding under the term loan and $147.5 million remains available under the funded letter of credit facility. As of March 1, 2004, we had not drawn down on our revolving credit facility. Finally, in connection with the consummation of the NRG plan of reorganization, we issued to Xcel Energy a $10.0 million non-amortizing promissory note, which will accrue interest at a rate of 3% per annum and mature 2.5 years after the effective date of the NRG plan of reorganization.

     As part of the NRG plan of reorganization, we eliminated approximately $5.2 billion of corporate level bank and bond debt and approximately $1.3 billion of additional claims and disputes through our distribution of new common stock and $1.04 billion in cash among our unsecured creditors. In addition to the debt reduction associated with the restructuring, we used the proceeds of the recent note offering and borrowings under the New Credit Facility to retire approximately $1.7 billion of project-level debt.

     For additional information on our short term and long term borrowing arrangements, see Item 15 — Note 17 to the Consolidated Financial Statements.

     Historical Cash Flows

     Predecessor Company

     Historically, we 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. We 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.

Reorganized NRG

     We have obtained cash from operations, Xcel Energy’s contribution net of distributions to creditors, proceeds from the sale of certain assets and borrowings under our Second Priority Notes and New Credit Facility.

     Net Cash Provided (Used) By Operating Activities

     Predecessor Company

     Net cash provided by operating activities increased during 2002 compared with 2001, primarily due to our efforts to conserve cash by deferring the payment of interest and managing our cash flows more closely. As a result, we increased accounts payable and accrued interest balances and reduced inventory levels.

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     For the period January 1, 2003 through December 5, 2003 net cash provided by operating activities was $238.5 million. Operating activities consisted of a net loss before Fresh Start adjustments of $1.1 billion, offset by non-cash charges of $567.5 million and cash provided by working capital of $800.1 million. The non-cash charges consisted primarily of the write-down of our investment in Loy Yang, asset impairments and legal settlement charges. The favorable change in working capital was primarily due to reduced cash expenditures throughout the bankruptcy period resulting in increased accounts payable.

     Reorganized NRG

     For the period December 6, 2003 through December 31, 2003 cash used by operating activities was $588.9 million. This was primarily a result of payments made to creditors upon our emergence from bankruptcy.

     Net Cash Provided (Used) By Investing Activities

     Predecessor Company

     Net cash used in investing activities decreased in 2002, compared with 2001, primarily as a result of the termination of our acquisition program due to our financial difficulties and the receipt of cash upon the sale of assets during 2002.

     For the period January 1, 2003 through December 5, 2003 cash used in investing activities $185.7 million. This was primarily a result of capital expenditures and an increase in restricted cash, offset by cash proceeds received upon the sale of investments.

     Reorganized NRG

     For the period December 6, 2003 through December 31, 2003 cash provided by investing activities was $363.4 million. In connection with the refinancing transaction, approximately $375.3 million of restricted cash was released upon payment of the Northeast Generating and South Central Generating note. This increase was offset by funds used for capital expenditures and investments in projects.

     Net Cash Provided (Used) By Financing Activities

     Predecessor Company

     Net cash provided by financing activities decreased during 2002 compared to 2001 due to constraints on our ability to access the capital markets and the cancellation and termination of construction projects reducing the need for capital.

     For the period January 1, 2003 through December 5, 2003 cash used by financing activities was $29.9 million, which consisted primarily of principal payments offset by the issuance of additional debt.

     Reorganized NRG

     For the period December 6, 2003 through December 31, 2003 cash provided by financing activities was $393.3 million. We entered into refinancing transactions on December 23, 2003, where we issued $1.25 billion of Second Priority Notes and entered into the New Credit Facility, which consisted of a $950.0 million senior secured term loan facility and a $250.0 million funded letter of credit facility. Upon completion of the refinancing transactions, we repaid the Northeast Generating and South Central Generating notes and the Mid-Atlantic Generating obligations.

     Sources of Funds

     The principal sources of liquidity for our future operations, capital expenditures, facility closures and project restructurings are expected to be: (i) existing cash on hand and cash flows from operations, (ii) Xcel Energy’s contribution net of distributions to creditors, (iii) proceeds from the sale of certain assets and businesses and (iv) borrowings under our New Credit Facility, including up to $250.0 million of available borrowings under our new revolving credit facility and up to $250.0 million of a pre-funded letter of credit facility. Additionally, there are approximately $89.5 million of undrawn letters of credit under the pre-petition ANZ LC Facility. The ANZ LC Facility is supported by a cash funded claim reserve to support any letters of credit drawn prior to their expiration.

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Capacity under the ANZ LC facility will be reduced as the underlying LCs expire or are terminated. All of the LCs will expire or be terminated by the end of 2004, at which time the ANZ LC facility will no longer exist.

     As a result of our emergence from bankruptcy, all of our then existing securities, including our old common stock and various issuances of senior notes, were cancelled and approximately $5.2 billion of our existing debt and approximately $1.3 billion of additional claims and disputes were eliminated for a combination of equity and up to $1.04 billion in cash.

     On December 23, 2003, we entered into a bank facility for up to $1.45 billion, or the “New Credit Facility”, which included a $950.0 million, six and a half-year senior secured term loan, a $250.0 million funded letter of credit facility, and a four-year $250.0 million revolving line of credit, or the “revolving credit facility.” Portions of the revolving credit facility are available as a swing-line facility and as a revolving letter of credit sub-facility. As of December 31, 2003, the corporate revolver was undrawn. Also on December 23, 2003, we issued $1.25 billion in 8% second priority, senior secured notes, or the “Second Priority Notes”, due and payable on December 15, 2013.

     Upon completion of the refinancing transactions, we, among other things: (i) repaid the Northeast Generating LLC Notes, or “Northeast Notes”, the South Central Generating LLC Notes, or “South Central Notes”, and the Mid-Atlantic Generating LLC Obligations; (ii) paid a settlement amount associated with the repayment of the Northeast Notes and the South Central Notes; (iii) paid $500.0 million in lieu of 10% NRG Energy senior notes to former unsecured creditors pursuant to the NRG plan of reorganization, the “POR Notes”, (see the discussion of Senior Securities under Item 15 — Note 17 to the Consolidated Financial Statements) ; (iv) pre-funded a letter of credit sub-facility under the New Credit Facility in the amount of $250.0 million; and (v) paid fees and expenses related to the offering of notes and the New Credit Facility in the amount of $74.8 million.

     On January 28, 2004, we issued an additional $475.0 million of the Second Priority Notes, obtaining net proceeds of $501.8 million. With proceeds from this issuance and other funds, we subsequently 1) repaid $503.5 million of the term loan under the New Credit Facility, reducing the principal outstanding from $950.0 million to $446.5 million, 2) made a prepayment premium payment of $15.1 million, and 3) repaid accrued but unpaid interest on the prepayment amount, totaling $0.4 million. On February 25, 2004, we received from our term loan lenders a waiver under the New Credit Facility waiving our obligation to enter into a hedge arrangement on a notional value of $500.0 million, as required by the credit agreement.

     Cash Flows. Our operating cash flows are expected to be impacted by, among other things: (i) spark spreads generally; (ii) commodity prices (including demand for natural gas, coal, oil and electricity); (iii) the cost of ordinary course operations and maintenance expenses; (iv) planned and unplanned outages; (v) contraction of terms by trade creditors; (vi) cash requirements for closure and restructuring of certain facilities; (vii) restrictions in the declaration or payments of dividends or similar distributions from our subsidiaries; and (viii) the timing and nature of asset sales.

     A principal component of the NRG plan of reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution to us consisting of cash (and, under certain circumstances, its common stock) in an aggregate amount of up to $640.0 million to be paid in three separate installments. Xcel Energy contributed $288.0 million on February 20, 2004. We anticipate receiving an additional installment of up to $352.0 million in cash on April 30, 2004. We will distribute $515.0 million of cash we receive from Xcel Energy to our creditors. In the event we achieve certain liquidity measures in September 2004, an additional $25.0 million may be distributed to creditors, and we may use $100.0 million for any purpose, subject to any restrictions contained in the indenture or the New Credit Facility.

     Asset Sales. We received $229.3 million and $196.2 million in net cash proceeds from the sale of certain assets and businesses in the fiscal years ended 2002 and 2003, respectively. The New Credit Facility and the indenture governing the notes place restrictions on the use of any proceeds we may receive from certain asset sales in the future.

     Letter of Credit Sub-facility and Revolving Credit Facility. The New Credit Facility includes a letter of credit sub-facility in the amount of $250.0 million. As of December 31, 2003, we had issued $1.7 million in letters of credit under this facility. The New Credit Facility also includes a revolving credit facility in the amount of $250.0 million to be used for general corporate purposes. On December 31, 2003 we had not yet drawn on our revolving credit facility. For additional information regarding our debt see Item 15 — Note 17 to the Consolidated Financial Statements.

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     Uses of Funds

     Our requirements for liquidity and capital resources, other than for operating our facilities, can generally be categorized by the following: (i) PMI activities; (ii) capital expenditures; and (iii) project finance requirements for cash collateral.

     PMI. PMI activities comprise the single largest requirement for liquidity and capital resources. PMI liquidity requirements are primarily driven by: (i) margin and collateral posting requirements with counterparties; (ii) establishment of trading relationships; (iii) disbursement and receipt timing (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. For 2004, we believe that approximately $265 million to $360 million may be required for PMI to meet potential margin requirements and to cover prepayments and fuel inventory builds.

     Estimates for liquidity requirements are highly dependent on our hedging activity and then current market conditions, including forward prices for energy and fuel and market volatility. In addition, our estimates are dependent on credit terms with third parties. We do not assume that we will be provided with unsecured credit from third parties in budgeting our working capital requirements.

     Capital Expenditures. Capital expenditures were $1.4 billion for the year ended 2002, $113.5 million for the period January 1, 2003 through December 5, 2003 and $10.6 million for the period December 6, 2003 through December 31, 2003. Capital expenditures in 2003 relate primarily to operations and maintenance of our existing generating facilities whereas capital expenditures in 2002 related primarily to new plant construction. We anticipate that our 2004 capital expenditures will be approximately $113.8 million and will relate primarily to the operation and maintenance of our existing generating facilities.

     Project Finance Requirements. We are a holding company and conduct our operations through subsidiaries. Historically, we have utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct our power plants and related assets. Consistent with our strategy, we may seek, where available on commercially reasonable terms, non-recourse debt financing in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. Non- recourse borrowings are substantially non-recourse to other subsidiaries, affiliates and us, and are generally secured by the capital stock, physical assets, contracts and cash flow of the related project subsidiary or affiliate. Some of these project financings require us to post collateral in the form of cash or an acceptable letter of credit.

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     Principal on short-term debt, long-term debt and capital leases as of December 31, 2003 are due and payable in the following periods (in thousands):

     Other Liquidity Matters

     We maintain cash deposits in order to assure the continuation of vendor trade terms. As of December 31, 2003, the total amount of cash deposits maintained for these purposes was approximately $48.3 million.

     We expect our capital requirements to be met with existing cash balances, cash flows from operations, borrowings under our Second Priority Notes and New Credit Facility, and asset sales. We believe that our current level of cash availability and asset sales, along with our future anticipated cash flows from operations, will be sufficient to meet the existing operational and collateral needs of our business for the next 12 months. Subject to restrictions in our Second Priority Notes and our New Credit Facility, if cash generated from operations is insufficient to satisfy our liquidity requirements, we may seek to sell assets, obtain additional credit facilities or other financings and/or issue additional equity or convertible instruments. We cannot assure you, however, that our business will generate sufficient cash flow from operations, that currently anticipated cost savings and operating improvements will be realized on schedule or that future borrowings will be available to us under our credit facilities in an amount sufficient to enable us to pay our indebtedness, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, on commercially reasonable terms or at all. To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control.

Net Operating Loss Carryforwards

     During 2002 and 2003 we generated a net operating loss carryforward of $1.0 billion which will expire in 2023. We have assessed the likelihood that a substantial portion of the deferred tax assets relating to the net operating loss carryforwards would not be realized. This assessment included consideration of positive and negative factors, including our current financial position and results of operations, projected future taxable income, including projected operating and capital gains, and available tax planning strategies. As a result of such assessment, we determined that it was more likely than not that the deferred tax assets related to our domestic net operating loss carryforwards would not be realized. Accordingly, a full valuation allowance was recorded against the net deferred tax assets including net operating loss carryforwards. We also determined that it is more likely than not that a substantial portion of the net operating loss generated in 2002 and 2003 could be determined to be capital in nature. Given that capital losses are of a different character than ordinary losses the likelihood of capital losses expiring unutilized is greater than that of ordinary net operating losses.

     In addition, the conversion of ordinary losses to capital losses, to the extent that the amount exceeds our existing net operating loss, results in a corresponding reduction to the tax basis of our fixed assets. The consequence of which is a reduction to expected depreciation in future years.

Off Balance-Sheet Items

     As of December 31, 2003, we do not have any significant relationships with structured finance or special purpose entities that provide liquidity, financing or incremental market risk or credit risk.

     We have numerous investments with an ownership interest percentage of 50% or less in energy and energy related entities that are accounted for under the equity method of accounting as disclosed in Item 15 — Note 13 to the Consolidated Financial Statements. Our pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $967.7 million as of December 31, 2003. In the normal course of business we 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 payables/receivables to/from affiliates and if appropriate, bear market-based interest rates. See Item 15 — Note 11 to the Consolidated Financial Statements for additional information regarding amounts accounted for as notes receivable — affiliates.

Contractual Obligations and Commercial Commitments

     We have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to our capital expenditure programs. The following is a summarized table of contractual obligations. See additional discussion in Item 15 — Notes 17, 24 and 26 to the Consolidated Financial Statements.

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