UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

NRG Energy, Inc.

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

(Former name, former address and former fiscal year, if changed since last report)

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such 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 o

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

Yes x No o

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

Yes x No o

     As of May 10, 2004, there were 100,004,612 shares of common stock outstanding.

TABLE OF CONTENTS

Index

2

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

See notes to consolidated financial statements.

3

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (REORGANIZED COMPANY)

See notes to consolidated financial statements.

4

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (REORGANIZED COMPANY)
(Unaudited)

See notes to consolidated financial statements.

5

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/(DEFICIT)

See notes to consolidated financial statements.

6

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

See notes to consolidated financial statements.

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NRG ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization

General

     NRG Energy, Inc., or “NRG Energy”, “we”, “our”, or “us” is 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. We seek 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.

     We were formed in 1992 as the non-regulated subsidiary of Northern States Power, or “NSP”, which was itself merged into New Century Energies, Inc. to form Xcel Energy, Inc., or “Xcel Energy” in 2000. While owned by NSP and later by Xcel Energy, we pursued a high growth strategy focused on power plant acquisitions, high leverage and aggressive development, including site development and turbine orders. In 2002, a number of factors, most notably the prices paid by us for our acquisitions of turbines, development projects and plants, combined with the overall downturn in the power generation industry, triggered a credit rating downgrade (below investment grade), which in turn, precipitated a severe liquidity situation. On May 14, 2003, we and 25 of our direct and indirect wholly owned subsidiaries commenced voluntary petitions under chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. On November 24, 2003, the bankruptcy court entered an order confirming a plan of reorganization, for NRG Energy and four of our subsidiaries, and the plan became effective on December 5, 2003. On November 25, 2003, the bankruptcy court entered an order confirming the plan of reorganization for 21 of our subsidiaries, and the plan became effective on December 23, 2003. As of March 31, 2004, three entities remain in bankruptcy. Two entities have been deconsolidated and are accounted for under the cost method as we have effectively ceased control of the entities. Those entities are NRG Nelson Turbine, LLC and LSP-Nelson Energy LLC. The other entity, NRG McClain LLC, is shown as a discontinued operation since it was held for sale prior to filing for bankruptcy.

     As part of the NRG plan of reorganization, Xcel Energy relinquished its ownership interest in us and we became an independent public company upon our emergence from bankruptcy on December 5, 2003. We no longer have any material affiliation or relationship with Xcel Energy. As part of that reorganization, we eliminated approximately $5.2 billion of corporate level bank and bond debt and approximately $1.3 billion of additional claims and disputes by distributing a combination of equity and up to $1.04 billion in cash among our unsecured creditors. In addition to the debt reduction associated with the restructuring, we used a substantial portion of the proceeds of a recent note offering and borrowings under a new credit facility, the “Refinancing Transactions,” to retire approximately $1.7 billion of project-level debt on December 23, 2003. In January 2004, we used proceeds of an additional note offering to repay $503.5 million of the outstanding borrowings under our new credit facility.

     As of March 31, 2004, we owned interests in 72 power projects in seven countries having an aggregate net generation capacity of approximately 18,200 MW. Approximately 7,900 MW of our capacity consists of merchant power plants in the Northeast region of the United States. Certain of these assets are located in transmission constrained areas, including approximately 1,400 MW of “in-city” New York City generation capacity and approximately 750 MW of southwest Connecticut generation capacity. We also own approximately 2,500 MW of capacity in the South Central region of the United States, with approximately 1,900 MW of that capacity supported by long-term power purchase agreements. Our assets in the West Coast region of the United States consist of approximately 1,300 MW of capacity with the majority of such capacity owned via our 50% interest in West Coast Power, LLC, or “West Coast Power.” Our assets in the West Coast region are supported by a power purchase agreement with the California Department of Water Resources that runs through December 2004.

     Our principal domestic generation assets consisted of a diversified mix of natural gas-, coal- and oil-fired facilities, representing approximately 48%, 26% and 26% of our total domestic generation capacity, respectively. In addition, 45% of our generating facilities have some capability to combust duel fuels. We also own interests in plants having a net generation capacity of approximately 3,000 MW in various international markets, including Australia, Europe and Latin America. We perform our own power marketing through our energy marketing subsidiary, NRG Power Marketing, Inc., or “PMI” which, is focused on maximizing the value of our North American assets by providing centralized contract origination and management services, and through the efficient procurement and management of fuel and the sale of energy and related products in the spot, intermediate and long-term markets.

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     We were incorporated as a Delaware corporation on May 29, 1992. Our headquarters and principal executive offices are located at 901 Marquette Avenue, Suite 2300, Minneapolis, Minnesota, 55402. Our telephone number is (612) 373-5300. Our Internet website is http://www.nrgenergy.com. Our recent annual reports, quarterly reports, current reports and other periodic filings are available free of charge through our Internet website.

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation

     As used in this Quarterly Report, “Predecessor Company” refers to the Company prior to its emergence from bankruptcy. “Reorganized NRG” refers to the Company after its emergence from bankruptcy.

     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”.

     The accompanying unaudited interim consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission’s or “SEC” regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. The accounting policies we follow are set forth in Note 2 to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2003, or “Form 10-K”. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K. Interim results are not necessarily indicative of results for a full year.

     In the opinion of management, the accompanying unaudited interim consolidated financial statements contain all material adjustments necessary to present fairly our consolidated financial position as of March 31, 2004 and December 31, 2003, the results of its operations and stockholders’ equity/(deficit) for the three months ended March 31, 2004 and 2003, and its cash flows for the three months ended March 31, 2004 and 2003. Certain prior-year amounts have been reclassified for comparative purposes.

     In connection with our emergence from bankruptcy, we adopted Fresh Start Reporting, or “Fresh Start” on December 5, 2003, 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, our reorganization value was allocated to our assets and liabilities on a basis substantially consistent with purchase accounting in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations.”

Comparability of Financial Information

     Due to the adoption of Fresh Start as of December 5, 2003, the Reorganized NRG 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 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.

Note 3 — Discontinued Operations

     SFAS No. 144 requires that discontinued operations 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 our management considered cash flow analyses and offers related to the assets and businesses. This amount is included in income on discontinued operations, net of income taxes in the accompanying Consolidated Statements of Operations. In accordance with SFAS No. 144, assets held for sale will not be depreciated commencing with their classification as such.

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

     For the three months ended March 31, 2004 discontinued operations included our McClain, Penobscot Energy Recovery Company (PERC) and Compania Boliviana De Energia

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Electrica S.A. Bolivian Power Company Limited, or “Cobee” projects. For the three months ended March 31, 2003 discontinued operations included 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 and Energia Pacasmayo projects. Summarized results of operations of discontinued operations were as follows:

     The assets and liabilities of the discontinued operations are reported in the balance sheets as of March 31, 2004 and December 31, 2003 as discontinued operations. The major classes of assets and liabilities are presented by geographic area in the following table. As of March 31, 2004, within our Power Generation Segment, the PERC and McClain projects are included in the Other North America classification and the Cobee project is included in the Other International classification.

     As of December 31, 2003, within our Power Generation Segment, the PERC and McClain projects are included in the Other North America classification and the Cobee project is included in the Other International classification.

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     Killingholme — During third quarter 2002, we recorded an impairment charge of $477.9 million. In January 2003, we completed the sale of our interest in the Killingholme project to our 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 our interest in the Killingholme project and the release of debt obligations resulted in a gain on sale in the first quarter of 2003 of approximately $191.2 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.

     NLGI — During 2002, we recorded an impairment charge of $12.4 million related to subsidiaries of NLGI, an indirect wholly owned subsidiary of NRG Energy. The charge was related largely to asset impairments based on a revised project outlook. During the quarter ended March 31, 2003, we recorded impairment charges of $23.6 million related to subsidiaries of NLGI and a charge of $14.5 million to write off our 50% investment in Minnesota Methane, LLC. Through April 30, 2003, NRG Energy and NLGI failed to make certain payments causing a default under NLGI’s term loan agreements. In May 2003, the project lenders to the wholly-owned subsidiaries of NLGI and Minnesota Methane LLC foreclosed on our membership interest in the NLGI subsidiaries and our equity interest in Minnesota Methane LLC. There was no material gain or loss recognized as a result of the foreclosure.

     TERI — During 2002, we recorded an impairment charge of $11.7 million based on a revised project outlook. In September 2003, we completed the sale of TERI, a biomass waste-fuel power plant located in Florida and a wood processing facility located in Georgia, to DG Telogia Power, LLC. The sale resulted in net proceeds of approximately $1.0 million. We entered into an agreement to sell the wood processing facility on behalf of DG Telogia Power, LLC. This sale was completed during fourth quarter 2003 and we received cash consideration of approximately $1.0 million, resulting in a net gain on sale of approximately $1.0 million.

     Peru Projects — In November 2003, we completed the sale of the Cahua and Pacasmayo (Peruvian Assets) resulting in net cash proceeds of approximately $16.2 million and a loss of $36.9 million. In addition, we expect to receive an additional consideration adjustment of approximately $0.6 million during 2004.

     NEO Corporation — 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).

     McClain — We reviewed the recoverability of our McClain assets pursuant to SFAS No. 144 and recorded a charge of $100.7 million in the second quarter of 2003. On August 14, 2003, NRG’s Board of Directors approved a plan to sell its 77% interest in McClain Generating Station, a 520 MW combined-cycle, natural gas-fired facility located in New Castle, Oklahoma. On August 18, 2003, we entered into an Asset Purchase Agreement with Oklahoma Gas & Electric Company pursuant to which we would, subject to the satisfaction of certain conditions, sell all of the McClain assets in a sale pursuant to Section 363 of the Bankruptcy Codes as part of McClain’s Chapter 11 proceeding that was subsequently filed on August 19, 2003.

     As a result of the formalization of the plan to sell the McClain assets and the filing of petition under the Bankruptcy Code by McClain, McClain is being accounted for as a discontinued operation.

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     As part of our effort to seek alternative transactions that would provide greater value and in accordance with the bidding procedures approved by the Bankruptcy Court, we conducted an auction for the sale of McClain’s assets, however no bids were submitted for the purchase of the assets. The Bankruptcy Court entered an order approving the terms of the sale with Oklahoma Gas & Electric or “OG&E” free and clear of all liens. The closing of the sale is subject to various closing conditions including approval by the Federal Energy Regulatory Commission. OG&E and McClain filed a joint application requesting that FERC approve the transaction on August 26, 2003. FERC issued an order on December 18, 2003 setting the matter for hearings. The hearings will specifically address the adequacy of transmission system improvements proposed by OG&E as mitigation for OG&E’s increased market concentration in generation as a result of the transaction. Hearings are scheduled to start on August 3, 2004. Upon consummation of the asset sale, the proceeds from the sale will be used to repay outstanding project debt under the secured term loan and working capital facility.

     Penobscot Energy Recovery Company (PERC) — During the first quarter of 2004, we received board authorization to proceed with the sale of our interest in PERC to SET PERC Investment, LLC which reached financial closing in April 2004. Upon completion of the transaction, we received net proceeds of $17.4 million, resulting in an immaterial gain.

     Cobee — During the first quarter of 2004, we entered into an agreement for the sale of our interest in our Cobee project to Globeleq Holdings Limited, which reached financial closing in April 2004. Upon completion of the transaction, we received net proceeds of approximately $50.0 million, resulting in an immaterial gain.

     Batesville — In May, 2004 we reached an agreement to sell our 100 percent interest in an 837 megawatt generating plant in Batesville, Mississippi to Complete Energy Partners, LLC. We expect to realize cash proceeds of $26.5 million, subject to certain purchase price adjustments and transaction costs. No material gain or loss is expected upon the completion of the sale. Our Batesville facilities operations were not treated as discontinued operations during the first quarter of 2003 as they did not meet the appropriate criteria as of March 31, 2004.

Note 4 — Write Downs and Losses on Sales of Equity Method Investments

     Write downs and (gains)/losses on sales of equity method investments recorded in the consolidated statement of operations includes the following:

     Calpine Cogeneration — In January 2004, we executed an agreement to sell our 20% interest in Calpine Cogeneration Corporation to Calpine Power Company. The transaction closed in March 2004 and resulted in net cash proceeds of $2.5 million and a net gain of $0.2 million.

     Loy Yang — During first quarter of 2004, we wrote down our investment in Loy Yang by $2.0 million due to recent estimates of the expected sales proceeds. In April 2004, we completed the sale of our 25.4% interest in Loy Yang to Great Energy Alliance Corporation, which resulted in net cash proceeds of $26.7 million. No material gain or loss is expected upon completion of the sale.

     NEO Corporation — Minnesota Methane — We recorded an impairment charge of $12.3 million during 2002 to write-down our 50% investment in Minnesota Methane. We recorded an additional impairment charge of $14.5 million during the first quarter of 2003. These charges were related to a revised project outlook and management’s belief that the decline in fair value was other than temporary. In May 2003, the project lenders to the wholly-owned subsidiaries of NEO Landfill Gas, Inc. and Minnesota Methane LLC foreclosed on our membership interest in the NEO Landfill Gas, Inc. subsidiaries and our equity interest in Minnesota Methane LLC. Upon completion of the foreclosure, we recorded a gain of $2.2 million. This gain resulted from the release of certain obligations.

     Kondapalli — In the fourth quarter of 2002, we wrote down our investment in Kondapalli by $12.7 million due to recent estimates of sales value, which indicated an impairment of our book value that was considered to be other than temporary. On January 30, 2003, we signed a sales agreement with the Genting Group of Malaysia, or “Genting”, to sell our 30% interest in Lanco Kondapalli Power Pvt

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     Ltd, or “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. In the first quarter of 2003, we wrote down our investment in Kondapalli by $1.3 million based on the final sales agreement. The sale closed on May 30, 2003 resulting in net cash proceeds of approximately $24 million and a gain of approximately $1.8 million.

     ECKG — In September 2002, we announced that we had reached agreement to sell our 44.5% interest in the ECKG power station in connection with our Csepel power generating facilities, and our 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 $65.3 million and a net loss of less than $1.0 million

Note 5 — Reorganization, Restructuring and Impairment Charges

     Reorganization, restructuring and impairment charges included in operating expenses in the Consolidated Statements of Operations include the following:

     We reviewed the recoverability of our long-lived assets in accordance with the guidelines of SFAS No. 144. As a result of this review, we recorded no impairment charges for the three months ended March 31, 2004 and $0.7 million for the three months ended March 31, 2003.

     We incurred total reorganization charges of approximately $6.3 million for the three months ended March 31, 2004. All reorganization costs have been incurred since we filed for bankruptcy in May 2003. These costs consist of bankruptcy related charges primarily related to professional fees.

     We incurred total restructuring charges of approximately $21.5 million for the three months ended March 31, 2003. These costs consist of employee separation costs and advisor fees. All amounts were paid during the first half of 2003.

Note 6 — Asset Retirement Obligation

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

     We identified certain retirement obligations within our power generation segments related to our North America projects in the South Central region, the Northeast region, Australia, and our non-generation operations. These asset retirement obligations are related primarily to the future dismantlement of equipment on leased property and environment obligations related to ash disposal site closures. We also identified other asset retirement obligations that could not be calculated because the assets associated with the retirement obligations were determined to have an indeterminate life. The adoption of SFAS No. 143 resulted in recording a $2.6 million increase to property, plant and equipment and a $4.2 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was a $0.6 million increase to depreciation expense and a $1.6 million increase to cost of majority-owned operations, as we considered the cumulative effect to be immaterial.

     The following represents the balances of the asset retirement obligation as of January 1, 2004 and the additions and accretion of the asset retirement obligation for the three months ended March 31, 2004, which is included in other long-term obligations in the consolidated balance sheet.

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Note 7 — Inventory

     Inventory, which is stated at the lower of weighted average cost or market, consisted of:

Note 8 — Property, Plant and Equipment

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

Note 9 — Summarized Financial Information of Affiliates

     We have a 50% interest in one company (West Coast Power LLC) that was considered significant, as defined by applicable SEC regulations, which is accounted for as an equity method investment.

West Coast Power LLC Summarized Financial Information

     For the three months ended March 31, 2004, we recorded equity earnings of $6.0 million for West Coast Power after adjustments for the reversal of $2.0 million project level depreciation expense, offset by a decrease in earnings related to $31.0 million amortization of the intangible asset for the California Department of Water Resources, or “CDWR” contract. As a result of pushing down the impact of Fresh Start to the projects balance sheet we established a contract based intangible asset with a one year remaining life, consisting of the value of West Coast Power’s CDWR energy sales contract. In accordance with SOP 90-7, the carrying value of this intangible asset was reduced by $1.0 million, as a result of allocating the reduction of our tax valuation allowance to our intangible assets (see Notes 10 and 16). The following table summarizes financial information for West Coast Power LLC, including interests owned by us and other parties for the periods shown below:

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Results of Operations

Financial Position

     In April 2004, NRG Energy, West Coast Power, and Dynegy, reached a settlement agreement relating to FERC claims regarding market behavior in 2000 and 2001. The parties, who will enter into a definitive settlement, include FERC, Pacific Gas and Electric Company, Southern California Edison, The California Department of Water Resources, the California Electricity Oversight Board and the California Public Utilities Commission, or “CPUC.”

     Under the terms of the settlement, which must be approved by FERC and the CPUC, West Coast Power will not collect past due receivables from the California Independent System Operator and the California Power Exchange for power provided during the settlement period of June 2000 through January 2001. In addition, West Coast Power will make a cash payment of approximately $22.5 million to escrow accounts for ultimate distribution to purchasers in the California energy markets. In return, the parties to this settlement will drop their claim for any additional refunds from West Coast Power and all FERC investigations in this matter will be dismissed.

     West Coast Power and NRG Energy are fully reserved for both the past due receivables and the cash settlement as of March 31, 2004.

Note 10 — Intangible Assets

Reorganized NRG

     Upon the adoption of Fresh Start, we established certain intangible assets for power sales agreements and plant emission allowances. These intangible assets will be amortized over their respective lives based on a straight-line or units of production basis to resemble our realization of such assets.

     Power sale agreements will be amortized as a reduction to revenue over the terms and conditions of each contract. The weighted average remaining amortization period is 3 years for the power sale agreements. Emission allowances will be amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023. Aggregate amortization recognized for the three months ended March 31, 2004 was approximately $16.8 million. The annual aggregate amortization for each of the five succeeding years is expected to approximate $54.6 million in year one, $35.9 million in year two, $29.2 million in years three and four, and $22.3 million in year five for both the power sale agreements and emission allowances. The expected annual amortization of these amounts is expected to change as we relieve our tax valuation allowance, as explained below.

     For the three months ended March 31, 2004, we reduced our tax valuation allowance by $5.5 million (see Note 16) and recorded a corresponding reduction of $4.5 million related to our intangible assets at our wholly-owned subsidiaries. The remaining $1.0 million was recorded as a reduction to our intangible asset related to our equity investments (see Note 9). In accordance with SOP 90-7, any future benefits from reducing the valuation allowance should first reduce intangible assets until exhausted, and thereafter be recorded as a direct addition to paid-in-capital.

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Intangible assets consisted of the following:

Predecessor Company

     We had intangible assets of $27 million at March 31, 2003, which were not amortized and consisted of goodwill. We had intangible assets of $48.8 million at March 31, 2003, which were amortized and consisted of service contracts. Aggregate amortization expense recognized for the three months ended March 31, 2003 was approximately $1.1 million.

Note 11 — Derivative Instruments and Hedging Activities

     SFAS No. 133 requires us to record all derivatives on the balance sheet as assets or liabilities at fair value. For derivatives designated as cash flow hedges, the effective portion of the changes in fair value of the derivatives are recorded in Accumulated Other Comprehensive Income (OCI) and subsequently recognized in earnings when the hedged items impact income. For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivatives and the hedged items are recorded in current earnings. Changes in the fair value of non-hedge derivatives will be immediately recognized in earnings.

     SFAS No. 133 applies to our 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 financial instruments used to mitigate the risks associated with movements in interest rates, foreign exchange contracts used to reduce the effect of fluctuating foreign currencies on foreign denominated investments and other transactions.

Accumulated Other Comprehensive Income

     The following table summarizes the effects of SFAS No. 133 on our OCI balance for the three months ended March 31, 2004:

     Losses of $0.6 million were reclassified from OCI to current period earnings during the three months ended March 31, 2004, 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 three months ended March 31, 2004, we recorded losses in OCI of approximately $23.1 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 March 31, 2004 was an unrecognized loss of approximately $23.1 million. We expect $15.3 million of deferred net losses on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

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     The following table summarizes the effects of SFAS No. 133 on NRG Energy’s OCI balance as of March 31, 2003:

     Gains of $18.2 million were reclassified from OCI to current period earnings during the three months ended March 31, 2003 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 three months ended March 31, 2003 we recorded losses in OCI of approximately $39.0 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 March 31, 2003 was an unrecognized loss of approximately $30.9 million.

Statement of Operations

     The following tables summarize the pre-tax effects of non-hedge derivatives on our statement of operations for the three months ended March 31, 2004:

     The following tables summarize the pre-tax effects of non-hedge derivatives on our statement of operations for the three months ended March 31, 2003:

Energy Related Commodities

     We are 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, we entered 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. We have 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 stockholders’ deficit. We recognize 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 three months ended March 31, 2004 or March 31, 2003.

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     Our pre-tax earnings for the three months ended March 31, 2004 and 2003 were affected by an unrealized loss of $0.8 million and $12.7 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 three months ended March 31, 2004 and 2003, we reclassified losses of $0.4 million and gains of $18.4 million, respectively, from OCI to current-period earnings and expect to reclassify an additional $15.3 million of deferred losses to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

     At March 31, 2004, we had hedge and non-hedge energy related commodities financial instruments extending through May 2005.

Interest Rates

     To manage interest rate risk, we have entered into interest-rate swap agreements that fix the interest payments or the fair value of selected debt issuances. The qualifying swap agreements are accounted for as cash flow or fair value hedges. The effective portion of the cash flow hedges’ cumulative gains/losses are reported as a component of OCI in stockholders’ equity. These gains/losses are recognized in earnings as the hedged interest expense is incurred. The reclassification from OCI is included on the same line of the statement of operations in which the hedged item appears. The entire amount of the change in fair value hedges is recorded in the statement of operations along with the change in value of the hedged item.

     No ineffectiveness was recognized on interest rate swaps that qualify as hedges during the three months ended March 31, 2004.

     During the three months ended March 31, 2004, pre-tax earnings were increased by an unrealized gain of $0.4 million related to the change in fair value of one interest rate related derivative instrument. This instrument is a $400 million floating to fixed interest rate swap, which was not designated as an effective hedge of the expected cash flows at March 31, 2004. As of April 1, 2004, this instrument was designated as a cash flow hedge under SFAS No. 133. As a result, subsequent changes to its fair value will be deferred and recorded as part of other comprehensive income. Our pre-tax earnings for the three months ended March 31, 2003 were decreased by an unrealized loss of $12.5 million, 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 three months ended March 31, 2004 and March 31, 2003, we reclassified gains of $4,000 and $0.1 million, respectively, from OCI to current- period earnings and expect to reclassify approximately $0.1 million of deferred losses to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.

     At March 31, 2004, we had interest rate derivatives instruments extending through June 2019.

Foreign Currency Exchange Rates

     To preserve the U.S. dollar value of projected foreign currency cash flows, we 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 three months ended March 31, 2004 or March 31, 2003.

     Our pre-tax earnings for the three months ended March 31, 2003 were increased by an unrealized gain of $0.1 million, associated with foreign currency hedging instruments not accounted for as hedges in accordance with SFAS No. 133. There was no impact for the three months ended March 31, 2004.

     During the three months ended March 31,2004 and March 31, 2003, we reclassified losses of $0.2 million and $0.3 million, respectively from OCI to current period earnings and we do not expect to reclassify any deferred gains/losses to earnings during the next twelve months on foreign currency swaps accounted for as hedges.

Note 12 — Short Term Debt and Long Term Debt

     As part of and concurrent with our emergence from bankruptcy on December 5, 2003, certain senior unsecured credit facilities were terminated and defaults related to those facilities were eliminated.

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     As of March 31, 2004, we have made timely scheduled payments on interest and/or principal on all of our recourse debt and were not in default under any of our related recourse debt instruments. Additionally, we are not in default of any obligations to post collateral. As discussed below, our NRG McClain LLC Project debt is in default. However, a significant amount of our subsidiaries’ debt and other obligations contain terms that require that they be supported with letters of credit or cash collateral.

NRG Energy Corporate Debt

     On December 5, 2003 we entered into a $10.0 million promissory note with Xcel Energy. The note accrues interest at a rate of 3% per year, payable quarterly in arrears. All principal is due at maturity on June 5, 2006.

     On December 23, 2003, we and PMI entered into a Senior Secured Credit Facility for up to $1.45 billion, which is comprised of both long-term and short-term debt. Long-term debt included a $950.0 million, six and a half-year senior secured term loan and a $250.0 million letter of credit facility, funded with proceeds from the senior secured lenders. Principal and interest on the term loan is payable quarterly on March 31, June 30, September 30 and December 31 of each year. As of March 31, 2004, the interest rate on the term loan was 5.5%, based on LIBOR plus a credit spread. The LIBOR portion is subject to a floor of 1.5%.

     The $250.0 million funded letter of credit is reflected as a funded deposit on the March 31, 2004 balance sheet. As of March 31, 2004, $113.2 million in letters of credit had been issued under this facility, leaving $136.8 million available for future issuances. Expenses associated with the funded letter of credit include commitment fees on the undrawn portion of the letter of credit facility, participation fees for the credit-linked deposit and other fees.

     The short-term debt component of the Senior Secured Credit Facility is a four-year, $250.0 million revolving line of credit (the Corporate Revolver). Portions of the Corporate Revolver are available as a swing-line facility and as a revolving letter of credit sub-facility. As of March 31, 2004, the corporate revolver was undrawn. We pay a commitment fee of 1% on any undrawn portion of the Corporate Revolver, and interest on any borrowed amounts.

     On December 23, 2003, we issued $1.25 billion in 8% Second Priority Notes, due and payable on December 15, 2013. The 8% Second Priority Notes are general obligations of ours. They are secured on a second-priority basis by security interests in all of our assets. Subject to the liens securing our obligations under the Senior Secured Credit Facility and any other priority lien obligations, which will be secured on a first-priority basis by the same assets that secure the 8% Second Priority Notes. The 8% Second Priority Notes will be senior in right of payment to any future subordinated indebtedness. Interest on the 8% Second Priority Notes accrues at the rate of 8.0% per annum and is payable semi-annually in arrears on June 15 and December 15, commencing June 15, 2004.

     On January 28, 2004, we issued, at a premium, an additional $475.0 million in 8% Second Priority Notes under the same terms and indenture as the December 23, 2003 offering. Proceeds of the additional offering were used to prepay $503.5 million of the term loan under the Senior Secured Credit Facility, reducing the outstanding principal of the term loan from $950.0 million to $446.5 million. A scheduled principal payment on March 31, 2004 further reduced the outstanding principal of the term loan to $444.8 million. In January, 2004 we wrote-off $15.0 million of deferred financing costs (included in interest expense) related to the term loans which were repaid. In addition, we deferred an additional $7.2 million of financing costs related to the newly issued notes.

     On February 25, 2004, we amended our Senior Secured Credit Facility to remove an interest rate hedge mandate. The amendment provides us with additional flexibility in how we choose to mitigate interest-rate risk.

     On March 24, 2004, we executed an interest rate swap agreement to mitigate our floating-rate interest exposure associated with our Senior Secured Credit Facility. The swap agreement became effective March 26, 2004 and terminates March 31, 2006. Under the agreement, we agree to pay quarterly a fixed interest rate on a notional amount of $400.0 million, commencing on March 31, 2004, and receive quarterly a floating-rate interest rate payment on the same notional amount. The floating rate is based upon three-month LIBOR, subject to a floor.

     On March 24, 2004, we executed a second interest rate swap agreement to mitigate our fixed-rate interest exposure associated with our 8% Second Priority Notes. This swap agreement became effective March 26, 2004 and terminates December 15, 2013. The swap agreement has provisions for early termination that are linked to any prepayment of the 8% Second Priority Notes. Under the agreement, we agree to pay semi-annually in arrears, commencing June 15, 2004, a floating interest rate on a notional amount of $400.0 million, and receive semi-annually in arrears a fixed interest rate payment on the same notional amount. The floating interest rate is based upon six-month LIBOR plus a spread. Depending on market interest rates, we or the swap counterparty may be required to post collateral on a daily basis in support of both of these swaps, to the benefit of the other party.

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     On April 29, 2004, we amended our Senior Secured Credit Facility to give us the flexibility to enter into joint ventures from time to time with affiliates of our 21.5% stockholder, MatlinPatterson Global Opportunities Partners, L.P. (“MatlinPatterson”). Three representatives of MatlinPatterson are members of our board of directors. We paid the lenders and agent under our senior secured credit agreement a fee equal to 12.5 basis points, or approximately $1.2 million, for the amendment.

Project Debt Defaults

LSP Kendall Energy, LLC

     As part of our acquisition of the LS Power assets in January 2001, NRG Energy, through its indirect wholly owned subsidiary, LSP Kendall Energy, LLC (Kendall), acquired a $554.2 million credit facility. The facility is non-recourse to us and consists of a construction and term loan, working capital and letter of credit facility. Kendall is a party to four interest rate swaps intended to mitigate much of the interest rate risk associated with the Kendall debt. As of December 31, 2003 and March 31, 2004, there were borrowings totaling approximately $487.0 million and $484.5 million, respectively, outstanding. The facility’s interest rate was 2.46% as of March 31, 2004, excluding interest rate hedges. Kendall has timely met all principal and interest obligations under the credit facility.

     In May 2002, Kendall received a notice of default from Société Generale, 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 our indemnification pursuant to an Indemnity Agreement dated June 28, 2002, indemnifying the lenders to the Kendall project from any claims or damages relating to these liens or any dispute or action involving the project’s contractors, 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.

     On August 25, 2003, Kendall entered into a Completion Extension and Amendment Agreement with the lenders and Société Generale whereby certain extensions were granted in respect of project construction, lien removal and other items. The Completion Extension and Amendment Agreement prohibits Kendall from making any distributions to equity owners until January 1, 2005, and thereafter only when certain conditions are met. Subsequent to execution of the Completion Extension and Amendment Agreement, the project defaulted under provisions requiring project completion. As of March 31, 2004, the Kendall debt was classified as current, due to the creditors’ ability to accelerate the debt based on the abovementioned default.

     In April 2004, Kendall executed an agreement with its lenders resolving the defaults under its credit facility. As required by this settlement agreement, Kendall prepaid $10.5 million in principal on its credit facility on April 21, 2004. Also in April, Kendall executed agreements with certain of its contractors, which resulted in these contractors receiving unsecured claims pursuant to the NRG Plan of Reorganization. Effective with the execution of those agreements, Kendall will no longer be in default with respect to the credit facility and the debt will no longer be classified as current.

NRG McClain LLC

     On November 28, 2001, NRG McClain LLC entered into a credit agreement with Westdeutsche Landesbank Girozentrale, New York Branch and various other lending institutions for a $181.0 million secured term loan (the McClain Secured Term Loan) and an $8.0 million working capital facility. As of December 31, 2003 and March 31, 2004, the outstanding amount under this facility was $156.5 million and $156.5 million, respectively. As of March 31, 2004, the interest rate on such outstanding borrowings was 4.625%.

     On September 17, 2002, NRG McClain LLC received notice from the agent bank that the project loan was in default as a result of our downgrades and of defaults on material obligations under the Energy Management Services Agreement. On August 19, 2003, NRG McClain signed an asset purchase agreement with Oklahoma Gas and Electric Company for substantially all of the assets of McClain and contemporaneously filed for bankruptcy pursuant to the asset purchase agreement. Upon consummation of the asset sale, the proceeds from the sale will be used to repay outstanding project debt under the secured term loan and working capital facility.

     OG&E and McClain filed a joint application requesting that FERC approve the transaction on August 26, 2003. FERC issued an order on December 18, 2003 setting the matter for hearings. The hearings will specifically address the adequacy of transmission system improvements proposed by OG&E as mitigation for OG&E’s increased market concentration in generation as a result of the transaction.

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Hearings are scheduled to start on August 3, 2004. Approval of the transaction is not expected prior to the end of 2004. NRG McClain is recorded as a discontinued operation in the accompanying balance sheets.

NRG Peaker Finance Company LLC

     In June 2002, NRG Peaker Finance Company LLC, or “NRG Peakers,” 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-month LIBOR plus 1.07% (average of 2.20% for the quarter ending March 31, 2004) NRG Peaker entered into an interest rate swap by which NRG Peaker pays a fixed rate of 6.667% through the final maturity of the bonds. As of March 31, 2004, the outstanding amount on this facility was $311.4 million, unchanged from December 31, 2003.

     On May 13, 2003, XL Capital Assurance, or “XLCA,” as controlling party, accelerated the debt issued by NRG Peaker, rendering the debt immediately due and payable. On January 6, 2004, we and XLCA consummated a comprehensive restructuring arrangement which provides for, among other things, the provision of a letter of credit by us for the benefit of the secured parties in the NRG Peaker financing, the cure or waiver of all defaults under the original financing agreement and the mutual release of claims by the parties. As of March 31, 2004, NRG Peaker was not in default under its financing agreements.

Meriden Gas Turbines LLC

Meriden Gas Turbines LLC, or “MGT,” is a party to a $0.5 million Promissory Note and Security Agreement with PowerSource LLC, issued and entered into on February 13, 2003. MGT used the proceeds of the note issuance to allow the release of a lien and claim on certain MGT assets, and for costs associated with the transport of certain equipment to the MGT site. The note became due and payable on May 14, 2003. We expect to repay this note with the proceeds from the sale of the MGT assets in 2004.

Note 13 — Corporate Relocation Charges

     On March 16, 2004, we announced plans to implement a new regional business strategy and structure. The new structure calls for a reorganized leadership team and a corporate headquarters relocation to West Windsor, New Jersey. The corporate relocation is intended to increase our effectiveness in serving our plants and employees as well as our external stakeholders such as regulators, customers and investors. The corporate headquarters staff will be streamlined as part of the relocation, as functions are shifted to the regions. A reduction in the corporate staff of approximately 100 employees is expected. We currently have approximately 240 individuals at our Minneapolis headquarters. The transition of corporate headquarters is expected to begin in September 2004 and run through March 2005.

     We expect to incur $34.0 million of expenses in connection with corporate relocation charges. Relocating, recruiting and other employee-related transition costs are expected to be approximately $17.0 million. These costs and cash payments are expected to be incurred through first quarter of 2005. Severance and termination benefits of $9.1 million are expected to be incurred through first quarter of 2005 with cash payments being made through fourth quarter of 2005. Building lease termination costs and write-offs of fixed assets are expected to be $7.9 million. These costs are expected to be incurred through first quarter of 2005 with cash payments being made through fourth quarter of 2006. The restructuring liability is recorded at fair market value. A summary of the significant components of the restructuring liability is as follows:

     As of March 31, 2004, the restructuring liability was $1.1 million and is included in other current liabilities on the consolidated balance sheet. Charges related to the employee related transition costs are recorded at our corporate level within our Other segment, in the corporate relocation charges line on the consolidated statement of operations.

Note 14 — Earnings Per Share

     Basic earnings per common share were computed by dividing net income by the weighted average number of common stock shares outstanding. Shares issued during the year are weighted for the portion of the year that they were outstanding. Shares of common stock granted to our officers and employees are included in the computation only after the shares become fully vested. Diluted earnings per

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share are computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table:

     For the three months ended March 31, 2004, 727,751 options have been excluded from the dilutive calculation as their exercise price exceeded the average market price of the common shares and therefore the effect would be anti-dilutive.

     Stock options: During March 2004, we issued stock option grants for 232,000 shares of common stock under the Long-Term Incentive Plan. 137,000 options were issued at a fair value of $19.90 per share and 95,000 options were issued at a fair value of $21.85 per share. These options have a three-year graded vesting schedule. Compensation expense recorded under the stock option grants for the three months ended March 31, 2004 was approximately $1.3 million.

     Restricted stock units: During March 2004, we issued 624,400 Restricted Stock Units or “RSUs” under the Long-Term Incentive Plan. 598,400 RSUs were issued at a fair value of $19.90 per unit. 26,000 RSUs were issued at a fair value of $21.85 per unit. These units cliff vest in three years. Compensation expense recorded under the RSUs for the three months ended March 31, 2004 was approximately $0.7 million. For purposes of computing earnings per share, nonvested RSUs are not considered outstanding for purposes of computing basic earnings per share; however, these units are included in the denominator for purposes of computing diluted earnings per share under the treasury stock method.

     Deferred stock units: During March 2004, we issued 63,422 Deferred Stock Units or “DSU” under the Long-Term Incentive Plan at a fair value of $19.95 per unit. A DSU will entitle the grantee to receive either one share of common stock or RSU at the end of the deferral period of not less than one year. Compensation expense recorded under the DSUs for the three months ended March 31, 2004 was approximately $1.3 million. For the purposes of computing basic earnings per share, the DSU’s are considered outstanding upon grant on a weighted average basis.

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Note 15 — Segment Reporting

     In connection with our emergence from bankruptcy and the new management team, we determined that it was necessary to adjust our segment reporting disclosures to more closely align our disclosures with the realignment of our management team. Accordingly, we have expanded our domestic geographical disclosures and collapsed our international geographical disclosures related to our wholesale power generation segment. In addition, our other segments have been further refined. As a result of these changes, we have retroactively recast our prior period disclosures in a consistent manner.

     We conducted our business within five operating segments: Wholesale Power Generation, Alternative Energy, Thermal, Energy Marketing, and Operating Services. These segments are distinct components with separate operating results and management structures in place. The Thermal, Energy Marketing and Operating Services operating segments are aggregated into one reportable segment under the heading “Other Non-Generation” as they do not meet the threshold for separate disclosure. The Wholesale Power Generation operating segment is further disclosed within six significant domestic and foreign geographic areas: Northeast, South Central, West Coast, Other North America, Australia, and Other International. The “Other” category includes operations that do not meet the definition of an operating segment and corporate charges (primarily interest expense) that have not been allocated to the operating segments. Segment information for the three months ended March 31, 2004 and 2003 is as follows: