UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

NRG Energy, Inc.

(609) 524-4500
(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 þ 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 þ 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 þ No o

     As of May 3, 2005, there were 87,045,501 shares of common stock outstanding.

TABLE OF CONTENTS

Index

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NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

See notes to consolidated financial statements.

3

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

See notes to consolidated financial statements.

4

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

See notes to consolidated financial statements.

5

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

See notes to consolidated financial statements.

6

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME/(LOSS)
Three Months Ended March 31, 2005 and 2004
(Unaudited)

See notes to consolidated financial statements.

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NRG ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — General

     NRG Energy, Inc., or “NRG Energy”, the “Company”, “we”, “our”, or “us”, is a wholesale power generation company, primarily engaged in the ownership and operation of power generation facilities, the transacting in and trading of fuel and transportation services and the marketing and trading of energy, capacity and related products in the United States and internationally.

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation

     The accompanying unaudited interim consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission’s regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes 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 our Annual Report on Form 10-K for the year ended December 31, 2004. 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 (consisting of normal, recurring accruals) necessary to present fairly our consolidated financial position as of March 31, 2005, the results of our operations and stockholders’ equity for the three months ended March 31, 2005 and 2004, and our cash flows for the three months ended March 31, 2005 and 2004. Certain prior-year amounts have been reclassified for comparative purposes.

Restricted Cash

     Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within our projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments, per the restrictions of the debt agreements.

Accounting Estimates

     Management of the Company is required to make certain estimates and assumptions during the preparation of the consolidated financial statements in accordance with generally accepted accounting principles. These estimates and assumptions impact the reported amount of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the consolidated financial statements. They also impact the reported amount of net earnings during any period. Actual results could differ from those estimates.

Note 3 — 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. 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.

     Statement of Financial Accounting Standards, or SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” 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/(loss) from 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.

     The assets and liabilities reported in the balance sheets as of March 31, 2005 and December 31, 2004 as discontinued operations

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represent those of NRG McClain. The assets of NRG McClain were sold in July 2004 however certain assets and liabilities remained to effect its liquidation and on April 29, 2005, we settled all outstanding obligations of NRG McClain. All other projects were sold as of December 31, 2004.

     For the three months ended March 31, 2005, discontinued operations consisted of various expenses related to NRG McClain as noted above. For the three months ended March 31, 2004, discontinued operations included our NRG McClain LLC; Penobscot Energy Recovery Company, or PERC; Compania Boliviana De Energia Electrica S.A. Bolivian Power Company Limited, or Cobee; Hsin Yu, LSP Energy (Batesville) and four NEO Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha and NEO Tajiguas LLC). McClain, PERC and LSP Energy (Batesville) are included in our Wholesale Power Generation — Other North America segment. Cobee and Hsin Yu are included in the All Other — Other International segment and the four NEO projects are included in the All Other - Alternative Energy segment.

     Summarized results of operations of discontinued operations were as follows:

Note 4 —Corporate Relocation Charges

     On March 16, 2004, we announced plans to implement a new regional business strategy and structure. The new plan called for a reorganized management structure and corporate headquarters relocation to Princeton, New Jersey. The transition of our corporate headquarters was completed in December 2004.

     For the three months ended March 31, 2005 and 2004, we recorded $3.5 million and $1.1 million, respectively, for charges related to our corporate relocation activities, primarily for employee severance and termination benefits, employee related transition costs and lease termination costs. These charges are classified separately in our statement of operations, in accordance with SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities”. Relocation charges for the year ended December 31, 2004 were $16.2 million. We expect to incur an additional $1.8 million in the second and third quarters of 2005 of SFAS No. 146-classified expenses in connection with corporate relocation charges for a total of $21.4 million.

A summary of the SFAS No. 146-classified expenses is as follows:

A summary of the significant components of the restructuring liability is as follows:

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     As of March 31, 2005, the restructuring liability was $4.7 million the majority of which is included in other current liabilities on the consolidated balance sheet. All restructuring costs are recorded at our corporate level within our All Other — Other segment, in the corporate relocation charges line on the consolidated statement of operations. Severance and termination benefits will require that cash payments be made through the fourth quarter of 2005. Lease termination costs will require that cash payments be made through the fourth quarter of 2006.

Note 5 — Investments Accounted for by the Equity Method

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

     We have ownership interests in two companies that were considered significant as defined by applicable SEC regulations as of March 31, 2005: West Coast Power LLC and Enfield Energy Centre Limited. We account for our ownership share of these investments using the equity method. On April 1, 2005, we completed the sale of our 25% interest in Enfield to Infrastructure Alliance Limited. The sale resulted in net pretax proceeds of $59.5 million. A pre-tax gain of approximately $6.0 million will be recorded in the second quarter of 2005 upon completion of the sale. Additionally, we expect to receive an additional amount of approximately $4.0 million based upon the post-closing working capital adjustment, which will also be recorded as a pre-tax gain on sale when determinable.

West Coast Power LLC Summarized Financial Information

     For the three months ended March 31, 2005, we recorded equity earnings of $4.1 million for West Coast Power after adjustments for the reversal of $3.2 million of project level depreciation expense. 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 of project level depreciation expense, offset by a decrease in earnings related to $31.0 million of amortization of the intangible asset for the California Department of Water Resources, or CDWR contract. This contract terminated on December 31, 2004. The following table summarizes financial information for West Coast Power, including interests owned by us and other parties for the periods shown below:

Summarized Results of Operations

Note 6 — Accounting for Derivative Instruments and Hedging Activities

     SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, requires us to recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. If certain conditions are met, we may be able to designate our derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives in Accumulated Other Comprehensive Income (OCI) and subsequently recognize in earnings when the hedged items impact income. The ineffective portion of a cash flow hedge is immediately recognized in 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. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings.

     For derivatives that are neither designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings.

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     Under the guidelines established by SFAS No. 133, as amended, certain derivative instruments may qualify for the normal purchase and sale exception and are therefore exempt from fair value accounting treatment.

     SFAS No. 133 applies to our energy related commodity contracts, interest rate swaps and foreign exchange contracts.

Accumulated Other Comprehensive Income (OCI)

     The following table summarizes the effects of SFAS No. 133 on our OCI balance attributable to hedged derivatives for the three months ended March 31, 2005 before income taxes:

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

     Gains of $2.2 million and losses of $0.6 million were reclassified from OCI to current period earnings during the three months ended March 31, 2005 and 2004, respectively, 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, 2005 and 2004, we recorded losses in OCI of $79.7 million and $23.1 million, respectively, related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of March 31, 2005 was an unrecognized loss of approximately $74.4 million. We expect $69.8 million of deferred net losses on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

Statement of Operations

     The following table summarizes the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the three months ended March 31, 2005:

     The following table summarizes the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the three months ended March 31, 2004:

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Energy Related Commodities

     As part of our risk management activities, we manage the commodity price risk associated with our competitive supply activities and the price risk associated with power sales from our electric generation facilities. In doing so, we may enter into a variety of derivative and non-derivative instruments, including the following:

     The objectives for entering into such hedges include:

          Any ineffectiveness on commodity cash flow hedges during the three months ended March 31, 2005 and 2004 was immaterial to our financial results.

     During the three months ended March 31, 2005 and 2004, our pre-tax earnings were affected by an unrealized loss of $82.8 million and an unrealized gain of $0.4 million $0, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133. These amounts exclude the affect of unrealized gains and losses recorded by equity investee’s.

     During the three months ended March 31, 2005 and 2004, we reclassified gains of $2.8 million and losses of $0.4 million, respectively, from OCI to current period earnings and expect to reclassify approximately $76.3 million of deferred losses to earnings during the next twelve months on energy related derivative instruments accounted for as hedges. At March 31, 2005, we had hedge and non-hedge energy related commodities financial instruments extending through March 2025.

Interest Rates

     We are exposed to changes in interest rates through our issuance of variable rate and fixed rate debt. In order to manage this interest rate risk, we have entered into interest-rate swap agreements. At March 31, 2005, all of our interest rate swap arrangements have been designated as either cash flow or fair value hedges. No ineffectiveness was recognized on interest rate swaps that qualify as hedges during the three months ended March 31, 2005 and 2004.

     During the three months ended March 31, 2005 and 2004, our pre-tax earnings were not impacted and increased by an unrealized gain of $0.4 million, respectively, associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133. One of these instruments is a $400 million swap to pay fixed for floating, which was not designated as a 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, changes in value subsequent to April 1, 2004 are deferred and recorded as part of OCI.

     During the three months ended March 31, 2005 and 2004, we reclassified losses of $0.6 million and $4,000, respectively, from OCI to current period earnings and expect to reclassify approximately $6.5 million of deferred gains to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.

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     At March 31, 2005, we had various interest-rate swap agreements 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. As of March 31, 2005, the results of any outstanding foreign currency exchange contracts were immaterial to our financial results.

Note 7 —Long-term Debt and Capital Leases

     NRG Energy Corporate Debt

     In January 2005 and March 2005, we used existing cash to purchase, at market prices, $25 million and $15.8 million, respectively, in face value of our Second Priority Notes. We paid $3.4 million in fees and market premiums on the repurchased notes which were recorded to refinancing expense, and an additional $0.7 million of accrued interest.

     On February 4, 2005, we redeemed $375.0 million in Second Priority Notes and paid $30.0 million for the early redemption premium on the redeemed notes which was recorded to refinancing expense. In addition, we paid $4.1 million in accrued but unpaid interest on the redeemed notes and $0.4 million in accrued but unpaid liquidated damages on the redeemed notes.

     As of May 3, 2005, our $150.0 million corporate revolving credit facility remained undrawn.

     Certain Events Related to Project-Level Debt

     In February 2005, NRG Flinders amended its debt facility of AUD 279.4 million (approximately US $218.5 million) in floating-rate debt. The amendment extended the maturity to February 2017, reduced borrowing costs and reserve requirements, reduced debt service coverage ratios, removed mandatory cash sharing arrangements, and made other minor modifications to terms and conditions. The facility includes an AUD 20.0 million (US $15.7 million) working capital and performance bond facility, under which an AUD 15.5 million (US $12.0 million) indemnity has been issued as of March 31, 2005. NRG Flinders is required to maintain interest-rate hedging contracts on a rolling 5-year basis at a minimum level of 60% of principal outstanding. Upon execution of the amendment, a voluntary principal prepayment of AUD 50 million (US $39.1 million) was made. On March 31, 2005, Flinders made another voluntary prepayment of AUD 10.5 million (US $8.1 million), reducing the outstanding amount to AUD 198.9 million (US $153.9 million). NRG Flinders retains the right to redraw these amounts at any time.

Note 8 — Earnings Per Share

     Basic earnings per common share were computed by dividing net income less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per 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 nonvested restricted stock units 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. The deferred stock units 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 if-converted method. The reconciliation of basic earnings per common share to diluted earnings per common share is shown in the following table:

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     For the three months ended March 31, 2005, outstanding preferred shares which are convertible into 10,500,000 shares of common stock were not included in the computation because the effect would be anti-dilutive. For the three months ended March 31, 2004, options to purchase 727,751 shares of common stock at an average price of $23.14 per share were not included in the computation because the effect would be anti-dilutive.

Note 9 — Segment Reporting

     We conduct the majority of our business within five reportable operating segments. All of our other operations are presented under the “All Other” category. Our reportable operating segments consist of Wholesale Power Generation – Northeast, Wholesale Power Generation – South Central, Wholesale Power Generation – West Coast, Wholesale Power Generation – Other North America and Wholesale Power Generation – Australia. These reportable segments are distinct components with separate operating results and management structures in place. Included in the All Other category are our Wholesale Power Generation – Other International operations, our Alternative Energy operations, our Non – Generation operations and an Other component which includes primarily our corporate charges (primarily interest expense) that have not been allocated to the reportable segments and the remainder of our operations which are not significant. We have presented this detail within the All Other category, as we believe that this information is important to a full understanding of our business.

     Beginning January 1, 2005 management decided to change the allocation criteria of corporate general and administrative expenses to the segments. Prior to 2005, corporate general and administrative expenses were allocated based on an analysis of man hours spent on work for each segment. As of January 1, 2005, corporate general and administrative expenses are allocated based on the forecasted revenue to be generated by each segment. In the following table, we have included a reconciliation of the increase/(decrease) in net income by segment for the three month period ended March 31, 2005, assuming the prior allocation criteria was still in effect.

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Note 10 — Income Taxes

     Income tax expense was $4.8 million and $14.3 million for the three months ended March 31, 2005 and 2004, respectively. The income tax expense for the three months ended March 31, 2005 and 2004 includes domestic tax expense of $0 million and $6.7 million, respectively, and foreign tax expense of $4.8 million and $7.6 million, respectively.

     A reconciliation of the U.S. statutory rate to our effective tax rate from continuing operations for the three months ended March 31, 2005 and March 31, 2004 are as follows:

     For U.S. income tax purposes, the Company generated additional net deferred tax assets for the three months ended March 31, 2005 of which a full valuation allowance was applied due to the uncertainty of utilization in future periods.

     No U.S. income tax expense is realized for the three months ended March 31, 2005.

     The effective income tax rate for the three months ended March 31, 2005 differs from the U.S. statutory rate of 35% due to the appropriation of a full valuation allowance and due to earnings in foreign jurisdictions taxed at rates lower than the U.S. statutory rate.

     We believe that it is more likely than not that a benefit will not be realized on a substantial portion of our deferred tax assets. This assessment included consideration of positive and negative evidence, including our current financial position and results of current operations, projected future taxable income, including projected operating and capital gains and our available tax planning strategies. Therefore, as of March 31, 2005, a valuation allowance of $736 million was recorded against the net deferred tax assets, including net operating loss carryforwards.

Note 11 — Benefit Plans and Other Postretirement Benefits

     Substantially all employees hired prior to December 5, 2003 were eligible to participate in our defined benefit pension plans. We have initiated an NRG Energy noncontributory, defined benefit pension plan effective January 1, 2004, with credit for service from December 5, 2003. In addition, we provide postretirement health and welfare benefits (health care and death benefits) for certain groups of our employees. Generally, these are groups that were acquired in recent years and for whom prior benefits are being continued (at least for a certain period of time or as required by union contracts). Cost sharing provisions vary by acquisition group and terms of any applicable collective bargaining agreements.

NRG Energy Pension and Postretirement Medical Plans

Components of Net Periodic Benefit Cost

     The net annual periodic pension cost for the three months ended March 31, 2005 and 2004 related to all of our plans, include the following components:

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Note 12 — Commitments and Contingencies

Legal Issues

     Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect our financial condition, results of operations or cash flows.

     Pursuant to the requirements of SFAS No. 5, “Accounting for Contingencies,” and related guidance, we record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments could occur, there can be no certainty that we may not ultimately incur charges in excess of presently recorded reserves. A future adverse ruling or unfavorable development could result in future charges which could have a material adverse effect on NRG Energy’s consolidated financial position, results of operations or cash flows.

     With respect to a number of the items listed below, management has determined that a loss is not probable or the amount of the loss is not reasonably estimable, or both. In some cases, management is not able to predict with any degree of substantial certainty the range of possible loss that could be incurred. Notwithstanding these facts, management has assessed each of these matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

     The descriptions below update, and should be read in conjunction with, the complete descriptions under “Note 27 Commitments and Contingencies” in NRG Energy’s Form 10-K for the year ended December 31, 2004.

California Wholesale Electricity Litigation and Related Investigations

     We, West Coast Power, LLC, or WCP, WCP’s four operating subsidiaries, Dynegy, Inc. and numerous other unrelated parties are the subject of numerous lawsuits arising based on events occurring in the California power market. Through our subsidiary, NRG West Coast Power LLC, we are a 50 percent beneficial owner with Dynegy of WCP, which owns, operates and markets the power of four California plants. Dynegy and its affiliates and subsidiaries are responsible for gas procurement and marketing and trading activities on behalf of WCP. The complaints primarily allege that the defendants engaged in unfair business practices, price fixing, antitrust violations, and other market “gaming” activities. Certain of these lawsuits, which seek unspecified treble damages and injunctive relief, were consolidated and made a part of a Multi-District Litigation proceeding before the U.S. District Court for the Middle District of California. Defendants filed dispositive motions in the fall of 2002. In the first quarter of 2003 the judge granted motions to dismiss in certain of these cases based on federal preemption and the filed rate doctrine. On September 10, 2004, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court’s dismissal. On November 5, 2004, the plaintiffs filed a petition for writ of certiorari with the U.S. Supreme Court and on February 22, 2005, the Supreme Court ordered the U.S. Solicitor General to submit its views on the petition.

     In the lawsuit brought by the California Attorney General, after removal to federal court, on March 25, 2003, the U.S. District Court for the Northern District of California dismissed the case based upon federal preemption and the filed rate doctrine. On July 6, 2004, the Ninth Circuit affirmed that dismissal and later rejected rehearing. On April 18, 2005, the U.S. Supreme Court denied the Attorney General’s petition for writ of certiorari.

     Regarding the remaining cases, in December 2002, the U.S. District Court for the Southern District of California found that federal jurisdiction was absent and remanded the cases back to state court. On December 8, 2004, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court in most respects. On March 3, 2005, the Ninth Circuit denied a motion for rehearing. We anticipate that the cases will be remanded to state court in 2005 at which time the defendants will again raise filed rate and federal preemption challenges. In the Northern California cases, on February 25, 2005, the Ninth Circuit affirmed the district court’s decision to dismiss all of the defendants’ cases.

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     In addition to the Multi-District Litigation discussed above, numerous other cases, including putative class actions, have been filed in state and federal court on behalf of business and residential electricity consumers which name us and/or WCP and/or certain subsidiaries of WCP, in addition to numerous other defendants. The complaints allege the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades, and violated California’s antitrust law and unfair business practices law. The complaints seek restitution and disgorgement, civil fines, compensatory and punitive damages, attorneys’ fees and declaratory and injunctive relief. Motion practice is proceeding in these cases and dispositive motions have been filed in several.

     In certain of the above referenced cases, Dynegy is defending WCP and/or its subsidiaries pursuant to a limited indemnification agreement while in the others, Dynegy’s counsel is representing it and WCP and/or its subsidiaries with each party responsible for half of the costs. Where NRG Energy is named, we are defending the case and bear our own costs of defense.

FERC Proceedings

     There are a number of proceedings in which WCP and WCP subsidiaries are parties, which are either pending before FERC or on appeal from FERC to various U.S. Courts of Appeal. These cases involve, among other things, allegations of physical withholding, a FERC-established price mitigation plan determining maximum rates for wholesale power transactions in certain spot markets, and the enforceability of, and obligations under, various contracts with, among others, the California Independent System Operator, the CDWR and the State of California. Among these is a demand by the State of California for FERC to abrogate the CDWR contract between the State and subsidiaries of WCP. In 2003, FERC rejected this demand and denied rehearing. The case was appealed to the Ninth Circuit where oral argument was held December 8, 2004.

California Attorney General

     The California Attorney General has undertaken an investigation entitled “In the Matter of the Investigation of Possibly Unlawful, Unfair, or Anti-Competitive Behavior Affecting Electricity Prices in California.” As has Dynegy, we and subsidiaries of WCP have responded to interrogatories, document requests, and to requests for interviews.

NRG Bankruptcy Cap on California Claims

     On November 21, 2003, in conjunction with confirmation of the NRG plan of reorganization, we reached an agreement with the Attorney General and the State of California, generally, whereby for purposes of distributions, if any, to be made to the State of California under the NRG plan of reorganization, the liquidated amount of any and all allowed claims shall not exceed $1.35 billion in the aggregate. The agreement neither affects our right to object to these claims on any and all grounds nor admits any liability whatsoever. We further agreed to waive any objection to the liquidation of these claims in a non-bankruptcy forum having proper jurisdiction.

New York Operating Reserve Markets

     Consolidated Edison and others petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of FERC’s refusal to order a re-determination of prices in the New York Independent System Operator, or NYISO, operating reserve markets for a two month period in 2000. On November 7, 2003, the court found that NYISO’s method of pricing spinning reserves violated the NYISO tariff. On March 4, 2005, FERC issued an order stating that no refunds would be required for the tariff violation associated with the pricing of spinning reserves. In the order, FERC also stated that the exclusion of the Blenheim-Gilboa facility and western reserves from the non-spinning market was not a market flaw and NYISO was correct not to use its TEP authority to revise the prices in this market. A motion for rehearing of the Order was filed before the April 3, 2005 deadline. If the March 4, 2005 order is reversed and refunds are required, NRG entities which may be affected include NRG Power Marketing, Inc., Astoria Gas Turbine Power LLC and Arthur Kill Power LLC. Although non-NRG-related entities would share responsibility for payment of any such refunds, under the petitioners’ theory the cumulative exposure to our above-listed entities could exceed $23 million.

Connecticut Congestion Charges

     On November 28, 2001, CL&P sought recovery of amounts it claimed was owed for congestion charges. CL&P withheld approximately $30 million from amounts owed to NRG Power Marketing, Inc., or PMI under an October 29, 1999, contract and PMI counterclaimed. CL&P’s motion for summary judgment, which PMI opposed, remains pending. We cannot estimate at this time the overall exposure for congestion charges for the term of the contract prior to the implementation of standard market design which occurred on March 1, 2003, however, such amount has been fully reserved as a reduction to outstanding accounts receivable.

New York Environmental Settlement

     In January 2002, the New York Department of Environmental Conservation, or NYSDEC, sued Niagara Mohawk Power Corporation, or NiMo, and us in federal court in New York asserting that projects undertaken at our Huntley and Dunkirk plants by

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NiMo, the former owner of the facilities, violated federal and state laws. On January 11, 2005, we reached an agreement to settle this matter whereby we will reduce levels of sulfur dioxide by over 86 percent and nitrogen oxide by over 80 percent in aggregate at the Huntley and Dunkirk plants. We are not subject to any penalty as a result of the settlement. Through the end of the decade, we expect that our ongoing compliance with the emissions limits set out in the settlement will be achieved through capital expenditures already planned. This includes our conversion to low sulfur western coal at the Huntley and Dunkirk plants that will be completed by spring 2006. On April 6, 2005, NYSDEC filed a motion with the court to enter the Consent Decree and on April 19, 2005, we filed a supporting motion. In a related case, on October 18, 2004, the parties reached a confidential settlement with respect to NiMo’s obligation to indemnify us for any related compliance costs associated with resolution of the NYSDEC action.

Station Service Disputes

     On October 2, 2000, NiMo commenced an action against us in New York state court seeking damages related to our alleged failure to pay retail tariff amounts for utility services at the Dunkirk Plant between June 1999 and September 2000. The parties agreed to consolidate this action with two other actions against the Huntley and Oswego Plants. On October 8, 2002, by Stipulation and Order, this action was stayed pending submission to FERC of some or all of the disputes in the action. The potential loss inclusive of amounts paid to NiMo and accrued is approximately $23.2 million. In a companion action at FERC, NiMo asserted the same claims and legal theories and on November 19, 2004, FERC denied NiMo’s petition and ruled that the NRG facilities could net their service station obligations over a 30 calendar day period from the day NRG acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities, because they are interconnected to transmission and not to distribution. On April 22, 2005, FERC denied NiMo’s motion for rehearing. As NiMo has the right to appeal the FERC’s denial, we will not reverse any amounts accrued until such time as it is assured that our risk of loss has ceased. At this time, we cannot predict the outcome of this matter.

     On December 14, 1999, NRG Energy acquired certain generating facilities from CL&P. A dispute arose over station service power and delivery services provided to the facilities. On December 20, 2002, as a result of a petition filed at FERC by Northeast Utilities Services Company on behalf of itself and CL&P, FERC issued an Order finding that at times when NRG Energy is not able to self-supply its station power needs, there is a sale of station power from a third-party and retail charges apply. In August 2003, the parties agreed to submit the dispute to binding arbitration, however, the parties have yet to agree on a description of the dispute and on the appointment of a neutral arbitrator. The potential loss inclusive of amounts paid to CL&P and accrued could exceed $6 million.

U.S. Environmental Protection Agency

     On January 27, 2004, our subsidiaries, Louisiana Generating, LLC and Big Cajun II, received an initial and, thereafter, subsequent requests under Section 114 of the federal Clean Air Act from EPA Region 6 seeking information primarily relating to physical changes made at Big Cajun II. Louisiana Generating, LLC and Big Cajun II submitted several responses to the USEPA. On February 15, 2005, Louisiana Generating, LLC received a Notice of Violation alleging violations of the New Source Review provisions of the Clean Air Act at Big Cajun II Units 1 and 2 from 1998 through the Notice of Violation date. On April 7, 2005, a meeting was held with USEPA and the Department of Justice and additional information was provided to the agency. Given the preliminary stage of this NOV process, the Company cannot predict the outcome of this matter at this time, but it is actively engaged with USEPA to address the issues.

TermoRio Litigation

     TermoRio was a green field cogeneration project located in the state of Rio de Janeiro, Brazil. Based on the project’s failure to meet certain key milestones, we exercised our rights under the project agreements to sell our debt and equity interests in the project to our partner Petroleo Brasileiro S.A.–Petrobras, or Petrobras. On March 8, 2003, the arbitral tribunal decided most, but not all, of the issues in our favor and awarded us approximately US$80 million. On June 4, 2004, NRG Energy commenced a lawsuit in the U.S. District Court for the Southern District of New York seeking to enforce the arbitration award. On February 16, 2005, a conditional settlement agreement was signed with our former partner Petrobras, whereby Petrobras is obligated to pay us US$70.825 million. Such payment was received by us at a closing held on February 25, 2005. As of December 31, 2004, we had a note receivable from Petrobras of $57.3 million related to the arbitral award. The amounts paid in excess of the $57.3 million were recognized in earnings within other income in the first quarter of 2005 as the settlement was accounted for as a gain contingency. In addition to the settlement figure, we have the right to continue to seek recovery of US$12.3 million that is currently being held by Petrobras pending a ruling in a related dispute with a third-party. This related dispute is also being accounted for as a gain contingency.

Itiquira Energetica, S.A.

     Our Brazilian project company, Itiquira Energetica S.A., the owner of a 156 MW hydro project in Brazil, is in arbitration with the former EPC contractor for the project, Inepar Industria e Construcoes, or Inepar. The dispute was commenced by Itiquira in September

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of 2002 and pertains to certain matters arising under the former EPC contract. Itiquira seeks $40 million and asserts that Inepar breached the contract. Inepar seeks $10 million and alleges that Itiquira breached the contract. Final written arguments were submitted on January 28, 2005, to the court of arbitration and a decision is expected by the close of the second quarter of 2005.

CFTC Trading Litigation

     On July 1, 2004, the CFTC filed a civil complaint against us in Minnesota federal district court, alleging false reporting of natural gas trades from August 2001 to May 2002, and seeking an injunction against future violations of the Commodity Exchange Act. On November 17, 2004, a Bankruptcy Court hearing was held on the CFTC’s motion to reinstate its expunged bankruptcy claim, and on our motion to enforce the provisions of the NRG plan of reorganization thereby precluding the CFTC from continuing its federal court action. The bankruptcy court has not yet ruled on those motions. On December 6, 2004, a federal magistrate judge issued a report and recommendation that our motion to dismiss be granted. That motion to dismiss was granted by the federal district court in Minnesota on March 16, 2005. The Bankruptcy Court has yet to schedule a hearing or rule on the CFTC’s pending motion to reinstate its expunged claim.

Additional Litigation

     In addition to the foregoing, we are parties to other litigation or legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect our financial condition, results of operations or cash flows.

     The Company believes that it has valid defenses to the legal proceedings and investigations described above and intends to defend them vigorously. However, litigation is inherently subject to many uncertainties. There can be no assurance that additional litigation will not be filed against the Company or its subsidiaries in the future asserting similar or different legal theories and seeking similar or different types of damages and relief. Unless specified above, the Company is unable to predict the outcome these legal proceedings and investigations may have or reasonably estimate the scope or amount of any associated costs and potential liabilities. An unfavorable outcome in one or more of these proceedings could have a material impact on the Company’s consolidated financial position, results of operations or cash flows. The Company also has indemnity rights for some of these proceedings to reimburse the Company for certain legal expenses and to offset certain amounts deemed to be owed in the event of an unfavorable litigation outcome.

     Pursuant to the requirements of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” and related guidance, we record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. Management has assessed each of these matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

Disputed Claims Reserve

     As part of the NRG plan of reorganization confirmed on November 24, 2003, we have funded a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the plan. Under the terms of the plan, to the extent such claims are resolved now that we have emerged from bankruptcy; the claimants will be paid from the reserve on the same basis as if they had been paid out in the bankruptcy. That means that their allowed claims will be reduced to the same recovery percentage as other creditors would have received and will be paid in pro rata distributions of cash and common stock. We believe we have funded the disputed claims reserve at a sufficient level to settle the remaining unresolved proofs of claim we received during the bankruptcy proceedings. However, to the extent the aggregate amount of these payouts of disputed claims ultimately exceeds the amount of the funded claims reserve, we are obligated to provide additional cash, notes and common stock to the claimants. We will continue to monitor our obligation as the disputed claims are settled. If excess funds remain in the disputed claims reserve after payment of all obligations, such amounts will be reallocated to the creditor pool. We have contributed common stock and cash to an escrow agent to complete the distribution and settlement process. Since we have surrendered control over the common stock and cash provided to the disputed claims reserve, we recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from our balance sheet. Similarly, we removed the obligations relevant to the claims from our balance sheet when the common stock was issued and cash contributed.

Environmental Matters

     We are subject to a broad range of foreign, federal, state and local environmental and safety laws and regulations in the development, ownership, construction and operation of our domestic and international projects. These laws and regulations impose requirements on discharges of substances to the air, water and land, the handling, storage and disposal of, and exposure to, hazardous

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substances and wastes and the cleanup of properties affected by pollutants. These laws and regulations generally require that we obtain governmental permits and approvals before construction or operation of a power plant commences, and after completion, that our facilities operate in compliance with those permits and applicable legal requirements. We could also be held responsible under these laws for the cleanup of pollutants released at our facilities or at off-site locations where we may have sent wastes, even if the release or off-site disposal was conducted in compliance with the law.

Northeast Region

     Significant amounts of ash are contained in landfills at on and off-site locations. At Dunkirk, Huntley, Somerset and Indian River, ash is disposed at landfills owned and operated by the Company. The Company maintains financial assurance to cover costs associated with closure, post-closure care and monitoring activities. The Company has funded a trust in the amount of approximately $5.9 million to provide such financial assurance in New York and $6.8 million in Delaware. The Company must also maintain financial assurance for closing interim status “RCRA facilities” at the Devon, Middletown, Montville and Norwalk Harbor Generating Stations and has funded a trust in the amount of $1.5 million accordingly.

     The Company inherited historical clean-up liabilities when it acquired the Somerset, Devon, Middletown, Montville, Norwalk Harbor, Arthur Kill and Astoria Generating Stations. During installation of a sound wall at Somerset Station in 2003, oil contaminated soil was encountered. The Company has delineated the general extent of contamination, determined it to be minimal, and has placed an activity use limitation on that section of the property. Site contamination liabilities arising under the Connecticut Transfer Act at the Devon, Middletown, Montville and Norwalk Harbor Stations have been identified. The Company has proposed a remedial action plan to be implemented over the next two to eight years (depending on the station) to address historical ash contamination at the facilities. The total estimated cost is not expected to exceed $1.5 million. Remedial obligations at the Arthur Kill generating station have been established in discussions between the Company and the NYSDEC and are estimated to cost between $1 million and $2 million. Remedial investigations continue at the Astoria generating station with long-term clean-up liability expected to be within the range of $2.5 million to $4.3 million. While installing groundwater-monitoring wells at Astoria to track our remediation of a historical fuel oil spill, the drilling contractor encountered deposits of coal tar in two borings. The Company reported the coal tar discovery to the NYSDEC in 2003 and delineated the extent of this contamination. The Company may also be required to remediate the coal tar contamination and/or record a deed restriction on the property if significant contamination is to remain in place.

     We estimate that we will incur total environmental capital expenditures of $197.6 million during 2005 through 2010 for the facilities in New York, Connecticut, Delaware and Massachusetts. These expenditures will be primarily related to installation of particulate, SO₂ and NO_X controls, as well as installation of BTA under the Phase II 316(b) Rule.

     Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC were issued Notices of Violation for opacity exceedances and entered into a Consent Order with NYSDEC, effective March 31, 2004. The Consent Order required the respondents to pay a civil penalty of $1.0 million which was paid in April 2004. The Order also establishes stipulated penalties (payable quarterly) for future violations of opacity requirements and a compliance schedule. The Company is currently in dispute with NYSDEC over the method of calculation for stipulated penalties. The Company has placed $1.3 million in a reserve account as of March 31, 2005, and does not believe that the final resolution will involve a material larger amount.

South Central Region

     Liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated on site at the Big Cajun II Generating Station are addressed through the use of a trust fund maintained by the Company in the amount of approximately $5.0 million. Annual payments are made to the fund in the amount of approximately $116,000.

     We estimate approximately $271 million of capital expenditures will be incurred during the period 2005 through 2010 for our South Central facilities, primarily related to installation of particulate, SO₂ and NO_X controls, as well as studies for installation of BTA under the Phase II 316(b) Rule.

West Coast Region

     The Asset Purchase Agreements for the Long Beach, El Segundo, Encina, and San Diego gas turbine generating facilities provide that SCE and SDG&E retain liability, and indemnify the Company, for existing soil and groundwater contamination that exceeds remedial thresholds in place at the time of closing. The Company and its business partner conducted Phase I and Phase II Environmental Site Assessments at each of these sites for purposes of identifying such existing contamination and provided the results to the sellers. SCE and SDG&E have agreed to address contamination identified by these studies and are undertaking corrective action at the Encina and San Diego gas turbine generating sites. Spills and releases of various substances have occurred at these sites since the Company established the historical baseline, all of which have been, or will be, completely remediated. An oil leak in 2002

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from underground piping at the El Segundo Generating Station contaminated soils adjacent to and underneath the Unit 1 and 2 powerhouse. The Company excavated and disposed of contaminated soils that could be removed in accordance with existing laws. Following the Company’s formal request, the LARWQCB will allow contaminated soils to remain underneath the building foundation until the building is demolished.

Regulatory Matters

NYISO Claims

     In November 2002, NYISO notified us of claims related to New York City mitigation adjustments, general NYISO billing adjustments and other miscellaneous charges related to sales between November 2000 and October 2002. New York City mitigation adjustments totaled $11.4 million. The issue related to NYISO’s concern that NRG would not have sufficient revenue to cover subsequent revisions to its energy market settlements. As of December 31, 2004, NYISO held $3.9 million in escrow for such future settlement revisions.

Commitments

     We have a number of commercial commitments as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2004. During the current period we have increased our commitments as described below.

     In August 2004, we entered into a contract to purchase 1,540 aluminum railcars from Johnston America Corporation to be used for the transportation of low sulfur coal from Wyoming to NRG Energy’s coal burning generating plants, including our New York and South Central facilities. On February 18, 2005, we entered into a ten-year operating lease agreement with GE Railcar Services Corporation, or GE, for the lease of 1,500 railcars. Delivery of the railcars from Johnston commenced in February 2005 and is expected to be completed by August 2005. We have assigned certain of our rights and obligations for 1,500 railcars under the purchase agreement with Johnston America to GE. Accordingly, the railcars which we lease from GE under the arrangement described above will be purchased by GE from Johnston America in lieu of our purchase of those railcars.

     In December 2004, we entered into a long-term coal transport agreement with the Burlington Northern and Santa Fe Railway Company and affiliates of American Commercial Lines LLC to deliver low sulfur coal to our Big Cajun II facility in New Roads, Louisiana beginning April 1, 2005. In March 2005, we entered into an agreement to purchase coal over a period of four years and nine months from Buckskin Mining Company, or Buckskin. The coal will be sourced from Buckskin’s mine in the Powder River Basin, Wyoming, and will be used primarily in NRG Energy’s coal-burning generation plants in the South Central region of the United States. Including this contract and other contracts, total coal purchase obligations increased by $160.1 million.

     In April 2005, we amended our contract for a five-year coal rail transportation agreement with CSX Transportation, Inc. and Union Pacific Railroad Company, to deliver low sulfur coal to our Dunkirk and Huntley facilities in Buffalo, New York, beginning April 1, 2005. Although the amendment does not change our minimum financial commitments, we are now obligated to transport at least 95% of our coal supplies for our Dunkirk and Huntley facilities with CSX Transportation, Inc. and Union Pacific Railroad Company.

Note 13 — Guarantees

     In November 2002, the FASB issued FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly, we applied the provisions of FIN 45 to all of the guarantees.

     We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchase and sale agreements, commodity sale and purchase agreements, joint venture agreements, operations and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties. These contracts generally indemnify the counter-party for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. In many cases, our maximum potential liability cannot be estimated, since some of the underlying agreements contain no limits on potential liability.

     The descriptions below update, and should be read in conjunction with, the complete descriptions under “Note 29 Guarantees and Other Contingent Liabilities” in NRG Energy’s Form 10-K for the year ended December 31, 2004.

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     On February 28, 2005, concurrent with the amendment of its debt facility, our Flinders subsidiary issued, under its amended AUD 20.0 million (US $15.5 million) working capital and performance bond facility sponsored by National Australia Bank Limited, an AUD 15.5 million (US $12.0 million) indemnity to the Australia and New Zealand Banking Group Limited (ANZ), the previous sponsor of the facility. The indemnity expires on October 31, 2006 and indemnifies ANZ against potential claims for guarantees or letters of credit issued under the facility prior to February 28, 2005.

     On February 18, 2005, we issued a guarantee to the benefit of General Electric Railcar Service Corporation. We guarantee the performance and payment obligations of NRG PMI under the railcar lease described in Item 2. - Contractual Obligations and Commercial Commitments. Payment obligations include future rental and termination payments, which are estimated to total $58.6 million over the first five years of the lease, and $49.9 million over the last 5 years of the lease, should we elect not to exercise our termination rights. However, our obligations under this guarantee include additional requirements that would be difficult to quantify until such time as a claim was made. As a result, our maximum potential obligation under this guarantee is indeterminate. At this time, we do not anticipate that we will be required to perform under this guarantee.

     Also during the quarter ended March 31, 2005, we issued guarantees of the performance of NRG PMI under various agreements with counter-parties for the purchase and sale of fuel, emission credits and power generation products. These new guarantees total $17.8 million. At this time, we do not believe we will be obligated to perform under these guarantees.

     At March 31, 2005, we were contingently obligated for approximately $173.2 million under our funded standby letters of credit facility, and we had $16.1 million issued under an unfunded standby letter of credit facility. Obligations of the unfunded letter of credit facility were reserved through our bankruptcy restructuring. Most of these standby letters of credit are issued in support of our obligations to perform under commodity agreements, financing or other arrangements. These letters of credit expire within one year of issuance, and it is typical for us to renew many of them on similar terms.

     On April 1, 2005, in conjunction with the sale of our interest in the Enfield Energy Center Ltd, a minority-owned, indirectly held affiliate of ours, we issued a guarantee of the obligations of a subsidiary of ours under the sale and purchase agreement, to the buyers of our interest. The maximum liability for this guarantee is estimated to be approximately $55.4 million, subject to adjustments. We do not anticipate that we will be required to perform under this guarantee.

     Because many of the guarantees and indemnities we issue to third parties do not limit the amount or duration of our obligations to perform under them, there exists a risk that we may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit our liability exposure, we may not be able to estimate what our liability would be, until a claim was made for payment or performance, due to the contingent nature of these contracts.

Note 14 — Condensed Consolidating Financial Information

     As of March 31, 2005, we have $1.35 billion of 8% Second Priority Senior Secured Notes outstanding. These notes are guaranteed by each of our current and future wholly-owned domestic subsidiaries, or Guarantor Subsidiaries. Each of the following Guarantor Subsidiaries fully and unconditionally guarantee the Notes.

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