UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 8-K/A

CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported) March 31, 2005

NRG Energy, Inc.

Delaware

609-524-4500

     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

     o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

     o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

     o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

     o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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Table of Contents

Item 8.01 Other Items

On June 15, 2005, NRG Energy, Inc., or NRG, filed audited financial statements for seven of its significant subsidiaries for the year ended December 31, 2004 pursuant to Rule 3-16 of Regulation S-X, in connection with the filing of a Pre-Effective Amendment No. 1 to the Registration Statement on Form S-4 to register its 8% second priority senior secured notes due in 2013. This Form 8-K is being amended to also file financial statements for the quarter ended March 31, 2005 for those seven significant subsidiaries pursuant to Rule 3-16 of Regulation S-X, which are incorporated herein by reference as Exhibits 99.1 to 99.7.

Item 9.01 Financial Statements and Exhibits

(a) Financial Statements of Business Acquired (not applicable)

(b) Pro Forma Financial Information (not applicable)

(c) Exhibits

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SIGNATURES

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

     Dated: June 14, 2005

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Exhibit Index

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EXHIBIT 99.1

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Consolidated Financial Statements
At March 31, 2005 and December 31, 2004
and for the Three Months Ended March 31, 2005
and for the Three Months Ended March 31, 2004

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INDEX

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY AND COMPREHENSIVE INCOME

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — General

     NRG Northeast Generating LLC, or the Company, or NRG Northeast, a wholly owned subsidiary of NRG Energy, Inc., or NRG Energy, owns electric power generation plants in the northeastern region of the United States. The Company was formed in 1999 for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries and affiliates the power generation facilities owned by Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Connecticut Jet Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC, Oswego Harbor Power LLC and Somerset Power LLC.

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. 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 of the Company’s financial statements for the year ended December 31, 2004, as filed by NRG Energy, Inc. on Form 8-K on June 15, 2005. The following notes should be read in conjunction with such policies and other disclosures in those financial statements. 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 member’s 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 by the Company that are restricted in their use due to contractual arrangements with the New York State Department of Taxation & Finance related to automotive fuel, petroleum business and sales tax.

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 — Accounting for Derivative Instruments and Hedging Activity

     SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 requires the Company 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, the Company may be able to designate 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 values will be immediately recognized in earnings.

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     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.

     SFAS No. 133 applies to the Company’s power sales contracts, oil contracts, long-term gas purchase agreements and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. At March 31, 2005, the Company had various commodity contracts extending through December 2006 .

Energy and Energy Related Commodities

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

     During the three months ended March 31, 2005 and March 31, 2004, any gain or loss the Company recognized due to ineffectiveness of commodity cash flow hedges was immaterial to the financial results.

Accumulated Other Comprehensive Income

     The following table summarizes the effects of SFAS No. 133, as amended, on the Company’s other comprehensive income balance attributable to hedged derivatives for the three months ended March 31, 2005 and March 31, 2004:

     During the three months ended March 31, 2005 and March 31 2004, the Company reclassified gains of approximately $2.7 million and losses of approximately $2.1 million from OCI to current period earnings, respectively. This amount is recorded on the same line in the statement of operations in which the hedged item is recorded. Also during the three months ended March 31, 2005 and March 31 2004, the Company recorded losses in OCI of approximately $69.7 million and approximately $17.4 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 at March 31, 2005 and March 31, 2004 was a loss of approximately $39.8 million and approximately $8.7 million, respectively.

   Statement of Operations

     The following table summarizes the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on the Company’s statement of operations for the three months ended March 31, 2005 and March 31, 2004, respectively:

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

     During the three months ended March 31, 2005 and 2004, our pre-tax earnings were affected by unrealized losses of $47.2 million and $0.8 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.

Note 4 — Commitments and Contingencies

Legal Issues

Consolidated Edison Co. of New York v. Federal Energy Regulatory Commission, Docket No. 01-1503

     Consolidated Edison and others petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of certain FERC orders in which FERC refused to order a re-determination of prices in the NYISO operating reserves markets for the period from January 29, 2000 to March 27, 2000. On November 7, 2003, the Court issued a decision, which found that the NYISO’s method of pricing spinning reserves violated the NYISO tariff. The Court also required FERC to determine whether the exclusion from the non-spinning market of a generating facility known as Blenheim-Gilboa and resources located in western New York also constituted a tariff violation and/or whether these exclusions enabled NYISO to use its Temporary Extraordinary Procedure or TEP authority to require refunds. 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 the 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 by 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.

Electricity Consumers Resource Council v. Federal Energy Regulatory Commission, Docket No. 03-1449

     On December 19, 2003 the Electricity Consumers Resource Council, or ECRC, appealed to the U.S. Court of Appeals for the District of Columbia Circuit a 2003 FERC decision approving the implementation of a demand curve for the New York installed capacity, or ICAP, market. ECRC claims that the implementation of the ICAP demand curve violates section 205 of the Federal Power Act because it constitutes unreasonable ratemaking. On May 13, 2005, the court denied ECRC’s appeal upholding the 2003 FERC decision. A petition for rehearing may be filed within 45 days of the decision.

Connecticut Light & Power Company v. NRG Power Marketing Inc., Docket No. 3:01-CV-2373 (AWT), U.S District Court, District of Connecticut (filed on November 28, 2001)

     Connecticut Light & Power Company, or CL&P, sought recovery of amounts it claimed it was owed for congestion charges under the terms of an October 29, 1999 contract between the parties. CL&P withheld approximately $30 million from amounts owed to NRG Power Marketing, Inc., or PMI, and PMI counterclaimed. CL&P filed its motion for summary judgment to which PMI filed a response on March 21, 2003. By reason of the stay issued by the bankruptcy court, the court has not ruled on the pending motion. On November 6, 2003, the parties filed a joint stipulation for relief from the stay in order to allow the proceeding to go forward that was promptly granted. PMI cannot estimate at this time the overall exposure for congestion charges for the full term of the contract.

The State of New York and Erin M. Crotty, as Commissioner of the New York State Department of Environmental Conservation v. Niagara Mohawk Power Corporation et al., U. S. District Court for the Western District of New York, Civil Action No. 02-CV-002S

     In January 2002, the New York Department of Environmental Conservation, or NYSDEC, sued Niagara Mohawk Power Corporation or NiMo, and NRG Energy and certain of NRG Energy’s affiliates in federal court in New York. The complaint asserted that projects undertaken at NRG Energy’s Huntley and Dunkirk plants by NiMo, the former owner of the facilities, required preconstruction permits pursuant to the Clean Air Act and that the failure to obtain these permits violated federal and state laws. On January 11, 2005, the Company reached agreement with the State of New York and NYDEC to settle this matter. The settlement requires the reduction of sulfur dioxide (SO₂) by over 86 percent and nitrogen oxide by over 80 percent in aggregate at the Huntley and Dunkirk plants. To do so, units 63 and 64 at Huntley will be retired after receiving the appropriate regulatory approvals. Units 65 and 66 will be retired eighteen months later. The Company also agreed to limits on the transfer of certain federal SO₂ allowances. NRG Energy is not subject to any penalty as a result of the settlement. Through the end of the decade, the Company expects ongoing compliance with the emissions limits set out in the settlement will be achieved through capital expenditures already planned. This includes conversion to low sulfur western coal at the Huntley and Dunkirk plants that will be completed by Spring 2006. On April 16, 2005, NYDEC filed a motion with the court to enter the consent decree and on April 19, 2005, we filed a supporting motion. We expect the court to enter the consent decree by the third quarter of 2005.

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Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power, LLC, and Dunkirk Power, LLC, Supreme Court, State of New York, County of Onondaga, Case No. 2001-4372 (filed on July 13, 2001)

     NiMo filed suit in state court in New York seeking a declaratory judgment with respect to its obligations to indemnify NRG Energy under the asset sales agreement. The Company asserted that NiMo is obligated to indemnify it for any related compliance costs associated with resolution of the above referenced NYSDEC enforcement action. On October 18, 2004, the parties reached a confidential settlement, less any related compliance costs associated with resolution of the NYDEC action referenced above.

Connecticut Light & Power v. NRG Energy, Inc., Federal Energy Regulatory Commission Docket No. EL03-10-000-Station Service Dispute (filed October 9, 2002); Binding Arbitration

     On July 1, 1999, Connecticut Light and Power Company, or CL&P and NRG Energy agreed that NRG Energy would purchase certain CL&P generating facilities. The transaction closed on December 14, 1999, whereupon NRG Energy took ownership of the facilities. CL&P began billing NRG Energy for station service power and delivery services provided to the facilities and NRG Energy refused to pay asserting that the facilities self-supplied their station service needs. On October 9, 2002, Northeast Utilities Services Company, on behalf of itself and CL&P, filed a complaint at FERC seeking an order requiring NRG Energy to pay for station service and deliver services. On December 20, 2002, 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. CL&P renewed its demand for payment, which was again refused by NRG Energy. In August 2003, the parties agreed to submit the dispute to binding arbitration. The parties each selected one respective arbitrator. A neutral arbitrator cannot be selected until the party-appointed arbitrators have been given a mutually agreed upon description of the dispute, which has yet to occur. Once the neutral arbitrator is selected, a decision is required within 90 days unless otherwise agreed by the parties. The potential loss inclusive of amounts paid to CL&P and accrued could exceed $6 million.

Niagara Mohawk Power Corporation v. Dunkirk Power LLC, NRG Dunkirk Operations, Inc., Huntley Power LLC, Huntley Power Operations, Inc., Oswego Power LLC and NRG Oswego Operations, Inc., Supreme Court, Erie County, Index No. 1-2000-8681- Station Service Dispute (filed October 2, 2000)

     NiMo seeks to recover damages less payments received through the date of judgment, as well as any additional amounts due and owing, for electric service provided to the Dunkirk Plant after September 18, 2000. NiMo claims that NRG Energy failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999, and continuing to September 18, 2000, and thereafter. NiMo alleged breach of contract, suit on account, violation of statutory duty, and unjust enrichment claims. Prior to trial, the parties entered into a Stipulation and Order filed August 9, 2002, consolidating this action with two other actions against the Company’s Huntley and Oswego subsidiaries, both of which cases assert the same claims and legal theories. On October 8, 2002, a Stipulation and Order was filed staying this action pending submission to FERC of some or all of these disputes in the action. The potential loss inclusive of amounts paid to NiMo and accrued is approximately $23.2 million.

Niagara Mohawk Power Corporation V. Huntley Power LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC, and NRG Oswego Operations, Inc., Case Filed November 26, 2002 in Federal Energy Regulatory Commission Docket No. EL 03-27-000

     This is the companion action to the above referenced action filed by NiMo at FERC asserting the same claims and legal theories. On November 19, 2004, FERC denied NiMo’s petition and ruled that the Huntley, Dunkirk and Oswego plants could net their service station obligations over a 30 calendar day period from the day NRG Energy 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. NiMo appealed to the U.S. Court of Appeals for the D.C. Circuit which, on May 12, 2005, ordered this appeal consolidated with several other pending station service disputes involving NiMo. As NiMo has appealed the FERC’s denial, we will not reverse any amounts accrued until such time as it is assumed that our risk of loss has ceased.

     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 financial position, results of operations or cash flows.

     Pursuant to the requirements of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” and related guidance, the Company record reserves for estimated losses from contingencies when information available indicates that a loss is

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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.

     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 projects. These laws and regulations generally require that we obtain governmental permits and approvals before construction or during operation of our power plants. Environmental laws have become increasingly stringent over time, particularly the regulation of air emissions from power generators. Such laws generally require regular capital expenditures for power plant upgrades, modifications and the installation of certain pollution control equipment. It is not possible at this time to determine when or to what extent additional facilities or modifications to existing or planned facilities will be required due to potential changes to environmental and safety laws and regulations, regulatory interpretations or enforcement policies. In general, future laws and regulations are expected to require the addition of emissions control equipment or the imposition of certain restrictions on the operations of NRG Northeast. We expect that future liability under, or compliance with, environmental and safety requirements could have a material effect on the operations or competitive position of NRG Northeast.

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

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

     In response to liabilities associated with these activities, NRG Northeast establishes accruals where it is probable that it will incur environmental costs under applicable law or contracts and it is possible to reasonably estimate these costs. NRG Northeast adjusts the accruals when new remediation or other environmental liability responsibilities are discovered and probable costs become estimable, or when current liability estimates are adjusted to reflect new information or a change in the law. At March 31, 2005 and December 31, 2004, NRG Northeast has established such accruals in the amount of approximately $4.0 million, primarily related to its Arthur Kill and Astoria projects. In 2004 NRG Northeast also established accruals of $1.5 million related to its Connecticut projects.

     Coal ash is produced as a by-product of coal combustion at the Dunkirk, Huntley, and Somerset Generating Stations. NRG Northeast attempts to direct its coal ash to beneficial uses. Even so, significant amounts of ash are landfilled. At Dunkirk and Huntley, ash is disposed of at landfills owned and operated by NRG Northeast. No material liabilities outside the costs associated with closure, post-closure care and monitoring are expected at these facilities. NRG Northeast maintains financial assurance to cover costs associated with closure, post-closure care and monitoring activities. NRG Northeast has funded a trust to provide such financial assurance in the amount of $5.9 million.

     NRG Northeast must also maintain financial assurance for closing interim status Resource Conservation and Recovery Act facilities at the Devon, Middletown, Montville and Norwalk 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

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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 collective civil penalty of $1 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 any such stipulated penalties. The Company has placed $1.3 million in a reserve as of March 31, 2005, and does not believe that the final resolution will involve a material larger amount.

Note 5 — Guarantees

     In November 2002, the FASB issued FASB Interpretation, or FIN 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, the Company applied the provisions of FIN 45 to all of the guarantees.

     On February 4, 2005, NRG Energy redeemed and retired $375.0 million of Second Priority Notes. As a result of the retirement, the joint and several payment and performance guarantee obligations of the following subsidiaries were reduced from $1,725.0 million to $1,350.0 million.

Note 6 — Regulatory Issues

     On August 23, 2004, ISO-NE filed its proposal for locational installed capacity, or LICAP, with FERC, which will decide the issue in a litigated proceeding before an administrative law judge. Under the proposal, separate capacity markets would be created for distinct areas of New England, including southwest Connecticut. While the Company views this proposal as a positive development, as it is currently proposed it would not permit us to recover all of the Company’s fixed costs. In response, the Company has submitted testimony which includes an alternative proposal. FERC’s goal is to make a decision on the precise terms of the LICAP market in the

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fall of 2005, to be effective January 1, 2006. The hearing is completed and post-trial briefs have been filed. The initial decision by the administrative law judge is scheduled to be issued on June 15, 2005.

     On January 27, 2005, FERC approved the settlement of various reliability must-run, or RMR, agreements between some of our Connecticut generation facilities and ISO-NE. Under the settlement, the Company will receive monthly payments for the Devon 11-14, Montville and Middletown facilities until December 31, 2005, the day before the expected implementation date for LICAP. The settlement also requires the payment of third party maintenance expenses by NEPOOL participants incurred by Devon 11-14, Middletown, Montville, and Norwalk Harbor and are capped at $30 million for the period April 1, 2004 through December 31, 2005. The settlement also approves prior RMR agreements involving Devon 7 and 8, both of which are on deactivated reserves. FERC’s goal is to make a decision on the precise terms of the NEPOOL LICAP market by June 1, 2005, to be effective January 1, 2006.

     On January 7, 2005, NYISO filed proposed LICAP demand curves for the following capability years: 2005-06, 2006-07 and 2007-08. Under the NYISO proposal, the LICAP price for New York City generation would be $126 per KW year for the capacity year 2006-07. In addition, the NYISO requested a rate of $67 per KW year for the capacity year 2006-07 for the rest of New York State excluding Long Island. On January 28, 2005, the Company filed a protest at FERC asserting the LICAP price for New York City for 2006-07 should be at least $140 per KW year. On April 21, 2005, FERC accepted the proposed demand curve with some modifications. It is anticipated that capacity prices for New York state, excluding New York City and Long Island, will probably increase by $1 per KW year. The FERC’s modification should increase the capacity prices in New York City, but the existing in-city mitigation measures will prevent us from obtaining those higher prices.

     Our New York City generation is presently subject to price mitigation in the installed capacity market. When the capacity market is tight, the price we receive is limited by the mitigation price. However when the New York City capacity market is not tight, such as during the winter season, the proposed demand curve price levels should increase our revenues from capacity sales.

     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 March 31, 2005 and December 31, 2004, NYISO held $3.9 million in escrow for such future settlement revisions.

Note 7 — Income Taxes

     The Company is included in the consolidated tax return filings as a wholly owned indirect subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions, as of the earliest period presented, as if the Company had prepared separate filings. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries. Because the Company is not a party to a tax sharing agreement, current tax expense is recorded as a capital contribution from the Company’s parent.

     In assessing the realizabilty of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The realization of deferred tax assets is dependent upon the generation of taxable income in future periods. Management considers both positive and negative evidence, projected operating income and capital gains, and available tax planning strategies in making this assessment. Based upon projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences.

     The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:

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Note 8 — Related Party Transactions

     Effective January 1, 2005, Corporate charges for allocated overhead was discontinued. For fiscal year 2005 and future years, General and administrative expenses will consist of the Company’s expenses only. For the three months ended March 31, 2004, Corporate overhead charges included in General and administrative expenses totaled $5.9 million. The amounts paid during the three months ended March 31, 2004 reflect an overall increase in corporate level general and administrative expenses. Corporate general, administrative and development expense increased during the three months ended March 31, 2004 due to higher legal fees, and increased consulting costs due to NRG Energy’s Sarbanes-Oxley implementation. The method of allocating these costs remained the same from the prior years.

     For the three months ended March 31, 2005 and 2004, the Company recorded operating and maintenance costs billed from NRG Operating Services of $59.7 million and $55.4 million, respectively.

     At March 31, 2005 and December 31, 2004, the Company had an accounts receivable affiliate balance of $72.3 and $33.0 million, respectively. These balances are settled on a periodic basis and are due from multiple entities which are wholly owned subsidiaries of NRG Energy Inc., the parent company of Northeast Generating LLC.

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EXHIBIT 99.2

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

Unaudited Consolidated Financial Statements
At March 31, 2005 and December 31, 2004
and for the Three Months Ended March 31, 2005
and for the Three Months Ended March 31, 2004

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

INDEX

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these consolidated financial statements.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

The accompanying notes are an integral part of these consolidated financial statements.

5

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — General

     NRG South Central Generating LLC, or NRG South Central or the Company, is a wholly owned subsidiary of NRG Energy, Inc., or NRG Energy. NRG South Central owns 100% of Louisiana Generating LLC, or Louisiana Generating; NRG New Roads Holding LLC, or New Roads; NRG Sterlington Power LLC, or Sterlington; Big Cajun I Peaking Power LLC, or Big Cajun Peaking; and NRG Bayou Cove LLC, or Bayou Cove.

     NRG South Central was formed for the purpose of financing, acquiring, owning, operating and maintaining through its subsidiaries and affiliates the facilities owned by Louisiana Generating and any other facilities that it or its subsidiaries may acquire in the future.

Note 2 — Summary of Significant Accounting Policies

     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 annual financial statements for the year ended December 31, 2004, as filed by NRG Energy, Inc. on Form 8-K on June 15, 2005. The following notes should be read in conjunction with such policies and other disclosures in the annual financial statements. 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, cash flows and member’s equity for the three months ended March 31, 2005 and the three months ended March 31, 2004. Certain prior-year amounts have been reclassified for comparative purposes.

     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 — Accounting for Derivative Instruments and Hedging Activity

     SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 requires the Company 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, the Company may be able to designate 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 values 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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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

     SFAS No. 133 applies to the Company’s long-term power sales contracts, long-term gas purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. At March 31, 2005, the Company had various commodity contracts extending through December 2005 .

Energy and Energy Related Commodities

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

     During the three months ended March 31, 2005 and 2004, respectively, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges.

     From time to time, the Company may use interest rate hedging instruments to protect it from an increase in the cost of borrowings. At March 31, 2005 and December 31, 2004, respectively, there were no such instruments outstanding.

     The following table summarizes the effects of SFAS No. 133 on the Company’s statements of operations for the three months ended March 31, 2005, and for the three months ended March 31, 2004, respectively:

     For the three months ended March 31, 2005 and 2004, the Company recognized no gain or loss due to the ineffectiveness of commodity cash flow hedges, and no components of NRG South Central’s derivative instruments gains or losses were excluded from the assessment of effectiveness.

     The Company’s earnings for the three months ended March 31, 2005 and 2004, were increased by $0.9 million and $0.4 million, respectively, associated with the changes in fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

Note 4 — Commitments and Contingencies

     During March 2000, Louisiana Generating entered into certain power supply agreements with eleven distribution cooperatives to provide energy, capacity and transmission services. The agreements are standardized into three types, Form A, B, and C. In connection with push down accounting resulting from NRG Energy’s fresh start accounting, certain of the Company’s long-term power supply agreements were determined to be at above or below market rates. As a result, the Company valued these agreements and recognized the fair value of such contracts on the December 6, 2003 balance sheet. The fair value of these contracts that were deemed to be valuable have been included in intangible assets. The fair value of contracts determined to be significantly out-of-market

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

were recorded as noncurrent liabilities. The favorable and unfavorable contract valuation amounts will be amortized as a net increase to revenues over the terms and conditions of each contract. These contracts consist primarily of the long-term power sale agreements the Company has with its cooperative customers and certain others. The gross carrying amount of the unfavorable out-of-market power sales agreements at March 31, 2005 and December 31, 2004 was $342.2 million and $342.2 million, respectively. During the three months ended March 31, 2005, approximately $4.6 million was amortized as an increase to revenues.

     Six of the distribution cooperatives entered into Form A power supply agreements. The Form A agreement is an all-requirements power supply agreement which has an initial term of 25 years, commencing on March 31, 2000. After the initial term, the agreement continues on a year-to-year basis, unless terminated by either party giving five years advance notice.

     Under the Form A power supply agreement, Louisiana Generating is obligated to supply the distribution cooperative all of the energy and capacity required by the distribution cooperative for service to its retail customers although the distribution cooperative has certain limited rights under which it can purchase energy and capacity from third parties.

     The Company must contract for all transmission service required to serve the distribution cooperative and will pass through the costs of transmission service to the cooperative. The Company is required to supply at its cost, without pass through, control area services and ancillary services which transmission providers are not required to provide.

     The distribution cooperatives have an option to choose one of two fuel options; all six selected the first option which is a fixed fee through 2004 and determined using a formula which is based on gas prices and the cost of delivered coal for the period thereafter. At the end of the fifteenth year of the contract, the cooperatives may switch to the second fuel option. The second fuel option consists of a pass-through of fuel costs, with a guaranteed coal heat rate and purchased energy costs, excluding the demand component in purchased power. From time to time, Louisiana Generating may offer fixed fuel rates which the cooperative may elect to utilize. The variable operation and maintenance charge is fixed through 2004 and escalates at either approximately 3% per annum or in accordance with actual changes in specified indices as selected by the distribution cooperative. Five of the distribution cooperatives elected the fixed escalation provision and one elected the specified indices provision.

     One distribution cooperative selected the Form B Power Supply Agreement. The term of the Form B power supply agreement commences on March 31, 2000, and ends on December 31, 2024. The Form B power supply agreement allows the distribution cooperative the right to elect to limit its purchase obligations to “base supply” or also to purchase “supplemental supply.” Base supply is the distribution cooperative’s ratable share of the generating capacity purchased by Louisiana Generating from Cajun Electric. Supplemental supply is the cooperative’s requirements in excess of the base supply amount. The distribution cooperative, which selected the Form B agreement, also elected to purchase supplemental supply.

     For base supply, Louisiana Generating charges the distribution cooperative a demand charge, an energy charge and a fuel charge. The demand charge for each contract year is set forth in the agreement and is subject to increase for environmental legislation or occupational safety and health laws enacted after the effective date of the agreement. Louisiana Generating can increase the demand

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

charge to the extent its cost of providing supplemental supply exceeds $400/MW. The energy charge is fixed through 2004, and decreased slightly for the remainder of the contract term. The fuel charge is a pass-through of fuel and purchased energy costs. The distribution cooperative may elect to be charged based on a guaranteed coal-fired heat rate of 10,600 Btu/kWh, and it may also select fixed fuel factors as set forth in the agreement for each year through 2008. The one distribution cooperative which selected this form of agreement elected to utilize the fixed fuel factors. For the years after 2008, Louisiana Generating will offer additional fixed fuel factors for five-year periods that may be elected. For the years after 2008, the distribution cooperative may also elect to have its charges computed under the pass-through provisions with or without the guaranteed coal-fired heat rate.

     At the beginning of year six, Louisiana Generating will establish a rate fund equal to the ratable share of $18 million. The amount of the fund will be approximately $720,000. This fund will be used to offset the energy costs of the Form B distribution cooperatives which elected the fuel pass-through provision of the fuel charge, to the extent the cost of power exceeds $0.04/kWh. Any funds remaining at the end of the term of the power supply agreement will be returned to Louisiana Generating.

     Four distribution cooperatives selected the Form C power supply agreement. The Form C power supply agreement is identical to the Form A power supply agreement, except for the following:

     The term of the Form C power supply agreement was for four years following the closing date of the acquisition of the Cajun facilities. In October 2003, the Louisiana Public Service Commission approved contract extensions for all four Form C distribution cooperatives for terms of an additional five or ten years.

     Louisiana Generating will not offer the distribution cooperatives which select the Form C agreement any new incentive rates, but will continue to honor existing incentive rates. At the end of the term of the agreement, the distribution cooperative is obligated to purchase the specific delivery facilities for a purchase price equal to the depreciated book value.

     Louisiana Generating must contract for all transmission services required to serve the distribution cooperative and will pass through the costs of transmission service to the cooperative. Louisiana Generating is required to supply at its cost, without pass-through, control area services and ancillary services which transmission providers are not required to provide.

     Included in the amended and restated Form C agreements is a provision for an annual $250,000 Economic Development Contribution to be shared among the four Form C distribution cooperatives, beginning in April 2004 and extending through the end of the contract terms.

     Louisiana Generating assumed Cajun Electric’s rights and obligations under two consecutive long-term power supply agreements with South Western Electric Power Company, or SWEPCO, one agreement with South Mississippi Electric Power Association, or SMEPA, and one agreement with Municipal Energy Agency of Mississippi, or MEAM.

     The SWEPCO Operating Reserves and Off-Peak Power Sale Agreement, terminates on December 31, 2007. The agreement requires Louisiana Generating to supply 100 MW of off-peak energy during certain hours of the day to a maximum of 292,000 MWh per year and an additional 100 MW of operating reserve capacity and the associated energy within ten minutes of a phone request during certain hours to a maximum of 43,800 MWh of operating reserve energy per year. The obligation to purchase the 100 MW of off-peak energy is contingent on Louisiana Generating’s ability to deliver operating reserve capacity and energy associated with operating reserve capacity. At Louisiana Generating’s request, it will supply up to 100 MW of nonfirm, on peak capacity and associated energy.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

     The SWEPCO Operating Reserves Capacity and Energy Power Sale Agreement is effective January 1, 2008 through December 31, 2026. The agreement requires Louisiana Generating to provide 50 MW of operating reserve capacity within ten minutes of a phone request. In addition, SWEPCO is granted the right to purchase up to 21,900 MWh/year of operating reserve energy.

     The SMEPA Unit Power Sale Agreement is effective through May 31, 2009, unless terminated following certain regulatory changes, changes in fuel costs or destruction of the Cajun facilities. The agreement requires Louisiana Generating to provide 75 MW of capacity and the associated energy from Big Cajun II, Unit 1 and an option for SMEPA to purchase additional capacity and associated energy if Louisiana Generating determines that it is available, in 10 MW increments, up to a total of 200 MW. SMEPA is required to schedule a minimum of 25 MW plus 37% of any additional capacity that is purchased. The capacity charge was fixed through May 31, 2004, and increases for the period from June 1, 2004 to May 31, 2009, including transmission costs to the delivery point and any escalation of expenses. The energy charge is 110% of the incremental fuel cost for Big Cajun II, Unit 1.

     The MEAM Power Sale Agreement is effective through May 31, 2010, with an option for MEAM to extend through September 30, 2015, upon five years advance notice. The agreement requires Louisiana Generating to provide 20 MW of firm capacity and associated energy with an option for MEAM to increase the capacity purchased to a total of 30 MW upon five years advance notice. The capacity charge is fixed. The operation and maintenance charge is a fixed amount which escalates at 3.5% per year. There is a transmission charge which varies depending upon the delivery point. The price for energy associated with the firm capacity is 110% of the incremental generating cost to Louisiana Generating and is adjusted to include transmission losses to the delivery point.

     Louisiana Generating has a coal supply agreement with Triton Coal. The coal is primarily sourced from Triton Coal’s Buckskin and North Rochelle mines located in the Powder River Basin, Wyoming. In December 2004, Louisiana Generating extended the coal purchase contract though 2007. The agreement establishes a base price per ton for coal supplied by Triton Coal. The base price is subject to adjustment for changes in the level of taxes or other government fees and charges, variations in the caloric value and sulfur content of the coal shipped, and changes in the price of SO2 emission allowances. The base price is based on certain annual weighted average quality specifications, subject to suspension and rejection limits.

     In March 2005, NRG Energy entered into an agreement to purchase 23.75 million tons of coal over a period of four years and nine months from Buckskin Mining Company (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.

     Louisiana Generating’s previous coal transportation agreement with DTE Energy expired March 31, 2005. Total payments under this agreement in 2005 are expected to be $1.5 million. The Company has entered into a new coal transportation agreement with Burlington Northern and Santa Fe Railway and an affiliate of ACT for a term of ten years, from April 1, 2005 through March 31, 2015. This agreement provides for the transportation of all of the coal requirements of Big Cajun II from the mines in Wyoming to Big Cajun II. A related agreement between Louisiana Generating and ACT grants Louisiana Generating the option to require ACT to perform the harbor operations related to the unloading of coal at Big Cajun II. Louisiana Generating has given notice to ACT that it will exercise the option and the transition of harbor services operations to ACT is scheduled for April 1, 2005.

     Louisiana Generating assumed Cajun Electric’s existing transmission agreements with Central Louisiana Electric Company, SWEPCO; and Entergy Services, Inc., acting as agent for Entergy Arkansas, Inc., Entergy Gulf States, Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. Louisiana Generating also entered into two interconnection and operating agreements with Entergy Gulf States, Inc. on May 1, 2002 and one interconnection and operating agreement with Entergy Gulf States, Inc. on August 26, 2004. The Cajun facilities are connected to the transmission system of Entergy Gulf States, Inc. and power is delivered to the distribution cooperative at various delivery points on the transmission systems of Entergy Gulf States, Inc., Entergy Louisiana Inc., Central Louisiana Electric Company and SWEPCO. Louisiana Generating also assumed from Cajun Electric 20 interchange and sales agreements with utilities and cooperatives, providing access to a 12 state area.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

     The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and the Company’s facilities are not exempted from coverage, the Company could be required to make extensive modifications to further reduce potential environmental impacts. Also, the Company could be held responsible under environmental and safety laws for the cleanup of pollutants released at its facilities or at off-site locations where it may have sent wastes, even if the release or off-site disposal was conducted in compliance with the law.

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

     The Company establishes accruals where it is probable that it will incur environmental costs under applicable law or contracts and it is possible to reasonably estimate these costs. The Company adjusts the accruals when new remediation or other environmental liability responsibilities are discovered and probable costs become estimable, or when current liability estimates are adjusted to reflect new information or a change in the law.

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

     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. The value of the trust fund is approximately $4.9 million at March 31, 2005.

     The Louisiana Department of Environmental Quality, or LADEQ, has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone nonattainment area into compliance with applicable National Ambient Air Quality Standards. The Company participated in development of the revisions, which require the reduction of NO(x) emissions at the gas-fired Big Cajun I Power Station and coal-fired Big Cajun II Power Station to 0.1 pounds NO(x) per million Btu heat input and 0.21 pounds NO(x) per million Btu heat input, respectively. This revision of the Louisiana air rules would constitute a change-in-law covered by agreement between the Company and the electric cooperatives (power offtakers) allowing the costs of added combustion controls to be passed through to the cooperatives. The capital cost of combustion controls required at the Big Cajun II Generating Station to meet the state’s NOx regulations will total about $10.0 million each for Units 1 & 2. Unit 3 has already made such changes.

U.S. Environmental Protection Agency Request for Information under Section 114 of the Clean Air Act and Notice of Violation

     On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the federal Clean Air Act from the USEPA 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 in response to follow-up requests. On February 15, 2005, Louisiana Generating, LLC received a Notice of Violation, or NOV, 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 NOV date. On April 7, 2005 we met with USEPA and the Department of Justice to discuss the NOV. Given the preliminary stage of this NOV process, the Company cannot predict the outcome of the matter at this time.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

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

     During 2000, the Louisiana Department of Environmental Quality, or DEQ, issued a Part 70 Air Permit modification to the Company to construct and operate two 120 MW natural gas-fired turbines. The Part 70 Air Permit set emissions limits for the criteria air pollutants, including NOx, based on the application of Best Available Control Technology, or BACT. The BACT limitation for NOx was based on the guarantees of the manufacturer, Siemens-Westinghouse. The Company sought an interim emissions limit to allow Siemens-Westinghouse time to install additional control equipment. To establish the interim limit, DEQ issued a Compliance Order and Notice of Potential Penalty on September 8, 2002, which is, in part, subject to the referenced administrative hearing. DEQ alleged violations related to NOx emissions. The Company denied those allegations and will contest any future penalty assessment, while also seeking an amendment of its limit for NOx. Quarterly status reports are being submitted to an Administrative Law Judge. In late February 2004, the Company timely submitted to the DEQ an amended BACT analysis and an amended Prevention of Significant Deterioration and Title V permit application to amend the NOx limit, which application is pending. The Company may also assert breach of warranty claims against the manufacturer.

Travis Ballou, et. al. v. Ralph Mabey, et. al., No. 03-30343 in the United States Court of Appeals for the Fifth Circuit
Kenneth Austin, et.al v. Ralph Mabey, et. al., No. 00-728-D-1 in the United States District Court for the Middle District of Louisiana

     Two lawsuits against the Company are pending in Federal Court involving 39 former employees of Cajun Electric Power Cooperative, Inc. who claim age/race/sex discrimination in failure to hire by the Company. One lawsuit, which included four plaintiffs, was dismissed on summary judgment. The District Court’s summary judgment ruling was affirmed by the U.S. Court of Appeals for the Fifth Circuit on February 10, 2005. On May 9, 2005, the District Court granted six additional motions for summary judgment. In the remaining lawsuit involving 35 plaintiffs, the District Court has now granted the Company’s Motions for Summary Judgment pertaining to nineteen plaintiffs, denied the Company’s Motions for Summary Judgment pertaining to four plaintiffs and is still considering the Company’s Motions for Summary Judgment pertaining to the remaining twelve plaintiffs.

BNSF Railway Company v. Louisiana Generating LLC, Case No. 531992, 19^thJudicial District Court, Parish of East Baton Rouge (filed May 6, 2005)

This lawsuit alleges breach of the coal transportation contract that expired on March 31, 2005. Specifically, the plaintiff alleges the shipment of coal via another carrier in 2004 and the failure to tender a minimum amount of coal during 2003, and further alleges that both actions constituted a breach of the contract. An accrual has been established.

     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 of more of these proceedings could have a material impact on the Company’s financial position, results of operations or cash flows.

     Pursuant to the requirements of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” and related guidance, the Company records 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.

Note 5 — Regulatory Issues

     The Company’s assets are located within the franchise territory of Entergy Corporation, or Entergy, a vertically integrated utility. The utility performs the scheduling, reserve and reliability functions that are administered by the Independent System Operators, or ISOs, or Regional Transmission Organizations, or RTOs, in certain other regions of the United States. The Company operates a National Electric Reliability Council, or NERC, certified control areas within the Entergy franchise territory, which is comprised of the Company’s generating assets and its co-op customer loads. Although the reliability functions performed are essentially the same, the primary differences between these markets lie principally in the physical delivery and price discovery mechanisms. In the South Central region, all power sales and purchases are consummated bilaterally between individual counter-parties, and physically

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

delivered either within or across the physical control areas of the transmission owners from the source generator to the sink load. Transacting counter-parties are required to reserve and purchase transmission services from the intervening transmission owners at their Federal Energy Regulatory Commission, or FERC, approved tariff rates. Included with these transmission services are the reserve and ancillary costs. Energy prices in the South Central region are determining and agreed to in bilateral negotiations between representatives of the transacting counter-parties, using market information gleaned by the individual marketing agents arranging the transactions.

     In the South Central region, including Entergy’s franchise territory, the present energy market is not a centralized market and does not have an ISO or RTO as is found in the Northeast markets. The Company presently has long-term all requirements contracts with 11 Louisiana Distribution Cooperatives, and long-term contracts with the Municipal Energy Agency of Mississippi, South Mississippi Electric Power Association and Southwestern Electric Power Company. The Distribution Cooperatives serve approximately 300,000 to 350,000 retail customers.

     On March 31, 2004, Entergy filed with FERC a proposal to have an independent coordinator of transmission, or ICT, monitor Entergy’s operation of its transmission system, to review the pricing structure for transmission expansion and to oversee a proposed weekly procurement process by which Entergy and other load serving entities could purchase energy. On March 22, 2005, FERC approved the ICT proposal for a two year period, subject to certain conditions. On May 27, 2005 it is expected that Entergy will file its detailed ICT proposal with FERC. On December 17, 2004, FERC ordered that an investigation and evidentiary hearing be held on the issue of whether Entergy is providing access to its transmission system in a just and reasonable manner. On March 22, 2005, FEEC suspended the hearing.

Note 6 — Guarantees

     In November 2002, the FASB issued FASB Interpretation No. 45, or FIN 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, the Company applied the provisions of FIN 45 to all of the guarantees.

     The obligations described below update, and should be read in conjunction with, the complete descriptions under “Note 19 — Guarantees” in NRG South Central LLC’s annual financial statement for the year ended December 31, 2004.

     On February 4, 2005, NRG Energy redeemed and retired $375.0 million of Second Priority Notes. As a result of the retirement, the joint and several payment and performance guarantee obligations of the following subsidiaries were reduced from $1,725.0 million to $1,350.0 million.

Note 7 — Income Taxes

     The Company is included in the consolidated tax return filings as a wholly owned subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions, as of the earliest period presented, as if the Company had prepared separate filings. The Company’s parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries and prior to January 1, 2003, income taxes were not recorded or allocated to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent.

     Management believes that it is more likely than not that no benefit will be realized on a substantial portion of the Company’s deferred tax assets. This assessment included consideration of positive and negative evidence, including the Company’s current financial position and results of current operations, projected future taxable income, including projected operating and capital gains

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

and our available tax planning strategies. Therefore, a valuation allowance of $211.2 million was recorded against the net deferred tax assets, including net operating loss carryforwards.

     Subsequently recognized tax benefits relating to the valuation allowance for deferred tax assets as of March 31, 2005, will be allocated to intangible assets.

     In the first quarter of 2005, the Company utilized $23.6 million of U.S. net operating losses carryforward of $397.4 million which will expire by 2023 if unutilized. There is a net carryforward amount of $373.8 million available at March 31, 2005.

     The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:

Note 8 — Related Party Transactions

     Effective January 1, 2005, Corporate charges for allocated overhead was discontinued. For fiscal year 2005 and future years, General and administrative expenses will consist of the Company’s expenses only. For the three months ended March 31, 2004, Corporate overhead charges included in General and administrative expenses totaled $1.6 million. The amounts paid during the three months ended March 31, 2004 reflect an overall increase in corporate level general and administrative expenses. Corporate general, administrative and development expense increased during the three months ended March 31, 2004 due to higher legal fees and increased consulting costs due to NRG Energy’s Sarbanes-Oxley implementation. The method of allocating these costs remained the same from the prior years.

     At March 31, 2005 and December 31, 2004, the Company had an accounts payable affiliate balance of $10.4 and $17.0 million, respectively. These balances are settled on a periodic basis and are due from multiple entities which are wholly owned subsidiaries of NRG Energy Inc., the parent company of South Central Generating LLC.

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EXHIBIT 99.3

LOUISIANA GENERATING LLC

Unaudited Consolidated Financial Statements
At March 31, 2005 and December 31, 2004
and for the Three Months Ended March 31, 2005
and for the Three Months Ended March 31, 2004

1

LOUISIANA GENERATING LLC

INDEX

2

LOUISIANA GENERATING LLC

BALANCE SHEETS

The accompanying notes are an integral part of these financial statements.

3

LOUISIANA GENERATING LLC

STATEMENTS OF OPERATIONS
(Unaudited)

The accompanying notes are an integral part of these financial statements.

4

LOUISIANA GENERATING LLC

STATEMENTS OF MEMBER’S EQUITY

The accompanying notes are an integral part of these financial statements.

5

LOUISIANA GENERATING LLC

STATEMENTS OF CASH FLOWS
(Unaudited)

The accompanying notes are an integral part of these financial statements.

6

LOUISIANA GENERATING LLC

NOTES TO THE UNAUDITED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — General

     Louisiana Generating LLC, or Louisiana Generating or the Company; is an indirect wholly owned subsidiary of NRG Energy, Inc., or NRG Energy. NRG South Central LLC, or South Central; owns 100% of the Company.

     NRG South Central was formed for the purpose of financing, acquiring, owning, operating and maintaining through its subsidiaries and affiliates the facilities owned by Louisiana Generating and any other facilities that it or its subsidiaries may acquire in the future.

     The Company was formed for the purpose of acquiring, owning, operating and maintaining the electric generating facilities acquired from Cajun Electric Power Cooperative, Inc., or Cajun Electric. Pursuant to a competitive bidding process, as part of the Chapter 11 bankruptcy proceeding of Cajun Electric, Louisiana Generating acquired the non-nuclear electric power generating assets of Cajun Electric.

Note 2 — Summary of Significant Accounting Policies

     The accompanying unaudited interim 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 annual financial statements for the year ended December 31, 2004, as filed by NRG Energy, Inc. on Form 8-K on June 15, 2005. The following notes should be read in conjunction with such policies and other disclosures in the annual financial statements. Interim results are not necessarily indicative of results for a full year.

     In the opinion of management, the accompanying unaudited interim financial statements contain all material adjustments (consisting of normal, recurring accruals) necessary to present fairly our financial position as of March 31, 2005, the results of our operations and member’s 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.

     Management of the Company is required to make certain estimates and assumptions during the preparation of the 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 financial statements. They also impact the reported amount of net earnings during any period. Actual results could differ from those estimates.

Note 3 — Accounting for Derivative Instruments and Hedging Activity

     SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 requires the Company 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, the Company may be able to designate 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 values will be immediately recognized in earnings.

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     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.

     SFAS No. 133 applies to South Central, the Company’s parent, 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. However, the Company does enter into long-term contracts that are exempt from SFAS No. 133. Derivative activities are conducted by an affiliate of South Central and are not recorded by the Company.

Note 4 — Commitments and Contingencies

     During March 2000, the Company entered into certain power supply agreements with eleven distribution cooperatives to provide energy, capacity and transmission services. The agreements are standardized into three types, Form A, B, and C. In connection with push down accounting resulting from NRG Energy’s fresh start accounting, certain of the Company’s long-term power supply agreements were determined to be at above or below market rates. As a result, the Company valued these agreements and recognized the fair value of such contracts on the December 6, 2003 balance sheet. The fair value of these contracts that were deemed to be valuable has been included in intangible assets. The fair value of contracts determined to be significantly out-of-market were recorded as non-current liabilities. The favorable and unfavorable contract valuation amounts will be amortized as a net increase to revenues over the terms and conditions of each contract. These contracts consist primarily of the long-term power sale agreements the Company has with its cooperative customers and certain others. The gross carrying amount of the unfavorable out-of-market power sales agreements at March 31, 2005 and December 31, 2004 was $390.5 million and $390.5 million, respectively. During the three months ended March 31, 2005 and 2004, approximately $8.2 million and $3.0 million, respectively, was amortized as an increase to revenues.

     Six of the distribution cooperatives entered into Form A power supply agreements. The Form A agreement is an all-requirements power supply agreement which has an initial term of 25 years, commencing on March 31, 2000. After the initial term, the agreement continues on a year-to-year basis, unless terminated by either party giving five years advance notice.

     Under the Form A power supply agreement, the Company is obligated to supply the distribution cooperative all of the energy and capacity required by the distribution cooperative for service to its retail customers although the distribution cooperative has certain limited rights under which it can purchase energy and capacity from third parties.

     The Company must contract for all transmission service required to serve the distribution cooperative and will pass through the costs of transmission service to the cooperative. The Company is required to supply at its cost, without pass through, control area services and ancillary services which transmission providers are not required to provide.

     The distribution cooperatives have an option to choose one of two fuel options; all six selected the first option which is a fixed fee through 2004 and determined using a formula which is based on gas prices and the cost of delivered coal for the period thereafter. At the end of the fifteenth year of the contract, the cooperatives may switch to the second fuel option. The second fuel option consists of a pass-through of fuel costs, with a guaranteed coal heat rate and purchased energy costs, excluding the demand component in purchased power. From time to time, the Company may offer fixed fuel rates which the cooperative may elect to utilize. The variable operation and maintenance charge is fixed through 2004 and escalates at either approximately 3% per annum or in accordance with actual changes in

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specified indices as selected by the distribution cooperative. Five of the distribution cooperatives elected the fixed escalation provision and one elected the specified indices provision.

     One distribution cooperative selected the Form B Power Supply Agreement. The term of the Form B power supply agreement commences on March 31, 2000, and ends on December 31, 2024. The Form B power supply agreement allows the distribution cooperative the right to elect to limit its purchase obligations to “base supply” or also to purchase “supplemental supply.” Base supply is the distribution cooperative’s ratable share of the generating capacity purchased by the Company from Cajun Electric. Supplemental supply is the cooperative’s requirements in excess of the base supply amount. The distribution cooperative, which selected the Form B agreement, also elected to purchase supplemental supply.

     For base supply, the Company charges the distribution cooperative a demand charge, an energy charge and a fuel charge. The demand charge for each contract year is set forth in the agreement and is subject to increase for environmental legislation or occupational safety and health laws enacted after the effective date of the agreement. The Company can increase the demand charge to the extent its cost of providing supplemental supply exceeds $400/MW. The energy charge is fixed through 2004, and decreased slightly for the remainder of the contract term. The fuel charge is a pass-through of fuel and purchased energy costs. The distribution cooperative may elect to be charged based on a guaranteed coal-fired heat rate of 10,600 Btu/kWh, and it may also select fixed fuel factors as set forth in the agreement for each year through 2008. The one distribution cooperative which selected this form of agreement elected to utilize the fixed fuel factors. For the years after 2008, the Company will offer additional fixed fuel factors for five-year periods that may be elected. For the years after 2008, the distribution cooperative may also elect to have its charges computed under the pass-through provisions with or without the guaranteed coal-fired heat rate.

     At the beginning of year six, the Company will establish a rate fund equal to the ratable share of $18 million. The amount of the fund will be approximately $720,000. This fund will be used to offset the energy costs of the Form B distribution cooperatives which elected the fuel pass-through provision of the fuel charge, to the extent the cost of power exceeds $0.04/kWh. Any funds remaining at the end of the term of the power supply agreement will be returned to the Company.

     Four distribution cooperatives selected the Form C power supply agreement. The Form C power supply agreement is identical to the Form A power supply agreement, except for the following.

     The term of the Form C power supply agreement was for four years following the closing date of the acquisition of the Cajun facilities. In October 2003, the Louisiana Public Service Commission approved contract extensions for all four Form C distribution cooperatives for terms of an additional five or ten years.

     The Company will not offer the distribution cooperatives which select the Form C agreement any new incentive rates, but will continue to honor existing incentive rates. At the end of the term of the agreement, the distribution cooperative is obligated to purchase the specific delivery facilities for a purchase price equal to the depreciated book value.

     The Company assumed Cajun Electric’s rights and obligations under two consecutive long-term power supply agreements with South Western Electric Power Company, or SWEPCO, one agreement with South Mississippi Electric Power Association, or SMEPA, and one agreement with Municipal Energy Agency of Mississippi, or MEAM.

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     The SWEPCO Operating Reserves and Off-Peak Power Sale Agreement, terminates on December 31, 2007. The agreement requires the Company to supply 100 MW of off-peak energy during certain hours of the day to a maximum of 292,000 MWh per year and an additional 100 MW of operating reserve capacity and the associated energy within ten minutes of a phone request during certain hours to a maximum of 43,800 MWh of operating reserve energy per year. The obligation to purchase the 100 MW of off-peak energy is contingent on the Company’s ability to deliver operating reserve capacity and energy associated with operating reserve capacity. At the Company’s request, it will supply up to 100 MW of nonfirm, on peak capacity and associated energy.

     The SWEPCO Operating Reserves Capacity and Energy Power Sale Agreement is effective January 1, 2008 through December 31, 2026. The agreement requires the Company to provide 50 MW of operating reserve capacity within ten minutes of a phone request. In addition, SWEPCO is granted the right to purchase up to 21,900 MWh/year of operating reserve energy.

     The SMEPA Unit Power Sale Agreement is effective through May 31, 2009, unless terminated following certain regulatory changes, changes in fuel costs or destruction of the Cajun facilities. The agreement requires the Company to provide 75 MW of capacity and the associated energy from Big Cajun II, Unit 1 and an option for SMEPA to purchase additional capacity and associated energy if the Company determines that it is available, in 10 MW increments, up to a total of 200 MW. SMEPA is required to schedule a minimum of 25 MW plus 37% of any additional capacity that is purchased. The capacity charge was fixed through May 31, 2004, and increases for the period from June 1, 2004 to May 31, 2009, including transmission costs to the delivery point and any escalation of expenses. The energy charge is 110% of the incremental fuel cost for Big Cajun II, Unit 1.

     The MEAM Power Sale Agreement is effective through May 31, 2010, with an option for MEAM to extend through September 30, 2015, upon five years advance notice. The agreement requires the Company to provide 20 MW of firm capacity and associated energy with an option for MEAM to increase the capacity purchased to a total of 30 MW upon five years advance notice. The capacity charge is fixed. The operation and maintenance charge is a fixed amount which escalates at 3.5% per year. There is a transmission charge which varies depending upon the delivery point. The price for energy associated with the firm capacity is 110% of the incremental generating cost to the Company and is adjusted to include transmission losses to the delivery point.

     The Company has a coal supply agreement with Triton Coal. The coal is primarily sourced from Triton Coal’s Buckskin and North Rochelle mines located in the Powder River Basin, Wyoming. In December 2004, the Company extended the coal purchase contract though 2007. The agreement establishes a base price per ton for coal supplied by Triton Coal. The base price is subject to adjustment for changes in the level of taxes or other government fees and charges, variations in the caloric value and sulfur content of the coal shipped, and changes in the price of SO2 emission allowances. The base price is based on certain annual weighted average quality specifications, subject to suspension and rejection limits.

     In March 2005, NRG Energy entered into an agreement to purchase 23.75 million tons of coal over a period of four years and nine months from Buckskin Mining Company (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.

     The Company’s previous coal transportation agreement with DTE Energy expired March 31, 2005. Total payments under this agreement in 2005 are expected to be $1.5 million. The Company has entered into a new coal transportation agreement with Burlington Northern and Santa Fe Railway and an affiliate of ACT for a term of ten years, from April 1, 2005 through March 31, 2015. This agreement provides for the transportation of all of the coal requirements of Big Cajun II from the mines in Wyoming to Big Cajun II. A related agreement between the Company and ACT grants the Company the option to require ACT to perform the harbor operations related to the unloading of coal at Big Cajun II. The Company has given notice to ACT that it will exercise the option and the transition of harbor services operations to ACT is scheduled for April 1, 2005.

     The Company assumed Cajun Electric’s existing transmission agreements with Central Louisiana Electric Company, SWEPCO; and Entergy Services, Inc., acting as agent for Entergy Arkansas, Inc., Entergy Gulf States, Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. The Company also entered into two interconnection and operating agreements with Entergy Gulf States, Inc. on May 1, 2002 and one interconnection and operating agreement with Entergy Gulf States, Inc. on August

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26, 2004. The Cajun facilities are connected to the transmission system of Entergy Gulf States, Inc. and power is delivered to the distribution cooperative at various delivery points on the transmission systems of Entergy Gulf States, Inc., Entergy Louisiana Inc., Central Louisiana Electric Company and SWEPCO. Louisiana Generating also assumed from Cajun Electric 20 interchange and sales agreements with utilities and cooperatives, providing access to a 12 state area.

     The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and the Company’s facilities are not exempted from coverage, the Company could be required to make extensive modifications to further reduce potential environmental impacts. Also, the Company could be held responsible under environmental and safety laws for the cleanup of pollutants released at its facilities or at off-site locations where it may have sent wastes, even if the release or off-site disposal was conducted in compliance with the law.

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

     The Company establishes accruals where it is probable that it will incur environmental costs under applicable law or contracts and it is possible to reasonably estimate these costs. The Company adjusts the accruals when new remediation or other environmental liability responsibilities are discovered and probable costs become estimable, or when current liability estimates are adjusted to reflect new information or a change in the law.

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

     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. The value of the trust fund is approximately $4.9 million at March 31, 2005.

     The Louisiana Department of Environmental Quality, or LADEQ, has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone nonattainment area into compliance with applicable National Ambient Air Quality Standards. The Company participated in development of the revisions, which require the reduction of NO(x) emissions at the gas-fired Big Cajun I Power Station and coal-fired Big Cajun II Power Station to 0.1 pounds NO(x) per million Btu heat input and 0.21 pounds NO(x) per million Btu heat input, respectively. This revision of the Louisiana air rules would constitute a change-in-law covered by agreement between the Company and the electric cooperatives (power offtakers) allowing the costs of added combustion controls to be passed through to the cooperatives. The capital cost of combustion controls required at the Big Cajun II Generating Station to meet the state’s NOx regulations will total about $10.0 million each for Units 1 & 2. Unit 3 has already made such changes.

U.S. Environmental Protection Agency Request for Information under Section 114 of the Clean Air Act and Notice of Violation

On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the federal Clean Air Act from the USEPA Region 6 seeking information primarily relating to physical changes made at Big Cajun II. Louisiana

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Generating, LLC and Big Cajun II submitted several responses to the USEPA in response to follow-up requests. On February 15, 2005, Louisiana Generating, LLC received a Notice of Violation, or NOV, 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 NOV date. On April 7, 2005, we met with USEPA and the Department of Justice to discuss the NOV. Given the preliminary stage of this NOV process, the Company cannot predict the outcome of the matter at this time.

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

     During 2000, the Louisiana Department of Environmental Quality, or DEQ, issued a Part 70 Air Permit modification to the Company to construct and operate two 120 MW natural gas-fired turbines. The Part 70 Air Permit set emissions limits for the criteria air pollutants, including NOx, based on the application of Best Available Control Technology, or BACT. The BACT limitation for NOx was based on the guarantees of the manufacturer, Siemens-Westinghouse. The Company sought an interim emissions limit to allow Siemens-Westinghouse time to install additional control equipment. To establish the interim limit, DEQ issued a Compliance Order and Notice of Potential Penalty on September 8, 2002, which is, in part, subject to the referenced administrative hearing. DEQ alleged violations related to NOx emissions. The Company denied those allegations and will contest any future penalty assessment, while also seeking an amendment of its limit for NOx. Quarterly status reports are being submitted to an Administrative Law Judge. In late February 2004, the Company timely submitted to the DEQ an amended BACT analysis and an amended Prevention of Significant Deterioration and Title V permit application to amend the NOx limit, which application is pending. The Company may also assert breach of warranty claims against the manufacturer.

Travis Ballou, et. al. v. Ralph Mabey, et. al., No. 03-30343 in the United States Court of Appeals for the Fifth Circuit
Kenneth Austin, et.al v. Ralph Mabey, et. al., No. 00-728-D-1 in the United States District Court for the Middle District of Louisiana

     Two lawsuits against the Company are pending in Federal Court involving 39 former employees of Cajun Electric Power Cooperative, Inc. who claim age/race/sex discrimination in failure to hire by the Company. One lawsuit, which included four plaintiffs, was dismissed on summary judgment. The District Court’s summary judgment ruling was affirmed by the U.S. Court of Appeals for the Fifth Circuit on February 10, 2005. On May 9, 2005, the District Court granted six additional motions for summary judgment. In the remaining lawsuit involving 35 plaintiffs, the District Court has now granted the Company’s Motions for Summary Judgment pertaining to nineteen plaintiffs, denied the Company’s Motions for Summary Judgment pertaining to four plaintiffs and is still considering the Company’s Motions for Summary Judgment pertaining to the remaining twelve plaintiffs.

BNSF Railway Company v. Louisiana Generating LLC, Case No. 531992, 19^thJudicial District Court, Parish of East Baton Rouge (filed May 6, 2005)

     This lawsuit alleges breach of the coal transportation contract that expired on March 31, 2005. Specifically, the plaintiff alleges the shipment of coal via another carrier in 2004 and the failure to tender a minimum amount of coal during 2003, and further alleges that both actions constituted a breach of the contract. An accrual has been established.

     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 of more of these proceedings could have a material impact on the Company’s financial position, results of operations or cash flows.

     Pursuant to the requirements of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” and related guidance, the Company records 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.

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Note 5 — Regulatory Issues

     The Company’s assets are located within the franchise territory of Entergy Corporation, or Entergy, a vertically integrated utility. The utility performs the scheduling, reserve and reliability functions that are administered by the Independent System Operators, or ISOs, or Regional Transmission Organizations, or RTOs, in certain other regions of the United States. The Company operates a National Electric Reliability Council, or NERC, certified control areas within the Entergy franchise territory, which is comprised of the Company’s generating assets and its co-op customer loads. Although the reliability functions performed are essentially the same, the primary differences between these markets lie principally in the physical delivery and price discovery mechanisms. In the South Central region, all power sales and purchases are consummated bilaterally between individual counter-parties, and physically delivered either within or across the physical control areas of the transmission owners from the source generator to the sink load. Transacting counter-parties are required to reserve and purchase transmission services from the intervening transmission owners at their Federal Energy Regulatory Commission, or FERC, approved tariff rates. Included with these transmission services are the reserve and ancillary costs. Energy prices in the South Central region are determining and agreed to in bilateral negotiations between representatives of the transacting counter-parties, using market information gleaned by the individual marketing agents arranging the transactions.

     In the South Central region, including Entergy’s franchise territory, the present energy market is not a centralized market and does not have an ISO or RTO as is found in the Northeast markets. The Company presently has long-term all requirements contracts with 11 Louisiana Distribution Cooperatives, and long-term contracts with the Municipal Energy Agency of Mississippi, South Mississippi Electric Power Association and Southwestern Electric Power Company. The Distribution Cooperatives serve approximately 300,000 to 350,000 retail customers.

     On March 31, 2004, Entergy filed with FERC a proposal to have an independent coordinator of transmission, or ICT, monitor Entergy’s operation of its transmission system, to review the pricing structure for transmission expansion and to oversee a proposed weekly procurement process by which Entergy and other load serving entities could purchase energy. On March 22, 2005, FERC approved the ICT proposal for a two year period, subject to certain conditions. On May 27, 2005 it is expected that Entergy will file its detailed ICT proposal with FERC. On December 17, 2004, FERC ordered that an investigation and evidentiary hearing be held on the issue of whether Entergy is providing access to its transmission system in a just and reasonable manner. On March 22, 2005, FREC suspended the hearing.

Note 6 — Guarantees

     In November 2002, the FASB issued FASB Interpretation No. 45, or FIN 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, the Company applied the provisions of FIN 45 to all of the guarantees.

     On February 4, 2005, NRG Energy redeemed and retired $375.0 million of Second Priority Notes. As a result of the retirement, the joint and several payment and performance guarantee obligations of the Company was reduced from $1,725.0 million to $1,350.0 million.

Note 7 — Income Taxes

     The Company is included in the tax return filings as a wholly owned subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions, as if the Company had prepared separate filings. The Company’s parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries and prior to January 1, 2003, income taxes were not recorded or allocated to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent.

     In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The realization of deferred tax assets is dependent upon the generation of taxable income in future periods. Management considers both positive and negative evidence, projected operating income and capital gains, and available tax planning strategies in making this assessment. Based upon projections for future taxable income over the periods in

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which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the majority of the benefits of these deductible differences, net of the existing valuation allowances at March 31, 2005.

     Subsequently recognized tax benefits relating to the valuation allowance for deferred tax assets as of March 31, 2005, will be allocated to intangible assets.

     In 2005, we utilized $24.5 million of U.S. net operating loss carryforward of $225.0 million. There is a net carryforward amount of $200.5 million available at March 31, 2005.

     The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% primarily due to the appropriation of state income taxes on earnings taxed at state and local jurisdiction.