UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission file No. 001-15891

NRG Energy, Inc.

(Exact name of Registrant as specified in its charter)

(609) 524-4500

(Registrant’s telephone number, including area code)

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

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

Common Stock, par value $0.01 per share

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

      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     o

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

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

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

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

Documents Incorporated by Reference:

Portions of the Proxy Statement for the 2005 Annual Meeting of Stockholders

NRG ENERGY, INC. AND SUBSIDIARIES

INDEX

PART I

Item 1 — Business

General

      NRG Energy, Inc., or “NRG Energy”, the “Company”, “we”, “our”, or “us” is a wholesale power generation company, primarily engaged in the ownership and operation of power generation facilities, the transacting in and trading of fuel and transportation services and the marketing and trading of energy, capacity and related products in the United States and internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type and dispatch levels. Our principal domestic generation assets consist of a diversified mix of natural gas-, coal- and oil-fired facilities, representing approximately 40%, 31% and 29% of our total domestic generation capacity, respectively. In addition, 23% of our domestic generating facilities have dual- or multiple-fuel capacity, which may allow plants to dispatch with the lowest cost fuel option.

      We seek to maximize operating income through the generation of energy, marketing and trading of energy, capacity and ancillary services into spot, intermediate and long-term markets and the effective transacting in and trading of fuel supplies and transportation-related services. We perform our own power marketing (except with respect to our West Coast Power and Rocky Road affiliates), which is focused on maximizing the value of our North American and Australian assets through the pursuit of asset-focused power and fuel marketing and trading activities in the spot, intermediate and long-term markets. Our principal objectives are the management and mitigation of commodity market risk, the reduction of cash flow volatility over time, the realization of the full market value of the asset base, and adding incremental value by using market knowledge to effectively trade positions associated with our asset portfolio. Additionally, we work with markets, independent system operators and regulators to promote market designs that provide adequate long-term compensation for existing generation assets and to attract the investment required to meet future generation needs.

      As of December 31, 2004, we owned interests in 52 power projects in five countries having an aggregate net generation capacity of approximately 15,400 MW. Approximately 7,900 MW of our capacity consisted of merchant power plants in the Northeast region of the United States. Certain of these assets are located in transmission constrained areas, including approximately 1,400 MW of “in-city” New York City generation capacity and approximately 750 MW of southwest Connecticut generation capacity. We also own approximately 2,500 MW of capacity in the South Central region of the United States, with approximately 1,900 MW of that capacity supported by long-term power purchase agreements.

      As of December 31, 2004, our assets in the West Coast region of the United States consisted of approximately 1,300 MW of capacity with the majority of such capacity owned via our 50% interest in West Coast Power LLC, or West Coast Power. Our assets in the West Coast region were supported by a power purchase agreement with the California Department of Water Resources that expired on December 31, 2004. One-year term reliability must-run, or RMR, agreements with the California Independent System Operator, or Cal ISO, for approximately 568 MW in the San Diego area have been renewed for 2005. On January 1, 2005, a new RMR agreement for the 670 MW gross capacity of the West Coast Power El Segundo generating facility became effective. In January 2005, that generating facility entered into a tolling agreement for its entire gross generating capacity of 670 MW commencing May 1, 2005 and extending through December 31, 2005. During the term of this agreement, the purchaser will be entitled to primary energy dispatch right for the facility’s generating capacity. The agreement is subject to the amendment of the El Segundo RMR agreement to switch to RMR Condition I and to otherwise allow the purchaser to exercise its primary dispatch rights under this agreement while preserving Cal ISO’s ability to call on the El Segundo facility as a reliability resource under the RMR agreement, if necessary. Approximately 265 MW of capacity at the Long Beach generating facility was retired January 1, 2005.

      We own approximately 1,600 MW of net generating capacity in other regions of the U.S. We also own interests in plants having a net generation capacity of approximately 2,100 MW in various international

markets, including Australia, Europe and Brazil. We operate substantially all of our generating assets, including the West Coast Power plants.

      We were incorporated as a Delaware corporation on May 29, 1992. In March 2004, our common stock was listed on the New York Stock Exchange under the symbol “NRG”. Our headquarters and principal executive offices are located at 211 Carnegie Center, Princeton, New Jersey 08540. Our telephone number is (609) 524-4500. The address of our website is www.nrgenergy.com. Our recent annual reports, quarterly reports, current reports and other periodic filings are available free of charge through our website. Our Corporate Governance Guidelines and the charters of our Audit, Compensation and Governance and Nominating Committees are also available on our website at www.nrgenergy.com/investor/corpgov.htm. These charters are available in print to any shareholder who requests them.

Strategy

      We are a significant owner and operator of a diverse portfolio of electric generation facilities. We are focused on owning, operating and maximizing the value of our generation assets in our core regions, which are the Northeast, South Central and West Coast regions of the United States, as well as Australia. Our two principal objectives are: (i) to maximize the operating performance of our entire portfolio, and (ii) to protect and enhance the market value of our physical and contractual assets through the execution of asset-based risk management, marketing and trading strategies within well-defined risk and liquidity guidelines.

      To achieve our principal objectives, we intend to pursue the following strategies, among others:

      From time to time we may also consider and undertake other merger and acquisition transactions that are consistent with our strategy. We continue to market our interest in our remaining non-core assets. Thereafter, we have no current plans to market actively any of our core assets, although our intention to maximize over time the value of all of our assets could lead to additional asset sales.

Competition

      Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. Many of our large competitors are facing restructuring, bankruptcy or liquidation. Many U.S. markets have a glut of generation capacity. New sources of capital have entered the industry, including well-capitalized financial players seeking to acquire assets at distressed prices. Regulatory bodies, including the Federal Energy Regulatory Commission, or FERC, regional independent system operators, state public utility commissions and other regulatory participants are considering significant changes to the structure of certain wholesale utility markets.

      Many companies in the regulated utility industry, with which the wholesale power industry is closely linked, are also restructuring or reviewing their strategies. Several of those companies are discontinuing their unregulated activities, seeking to divest their unregulated subsidiaries or attempting to have their regulated subsidiaries acquire assets out of their or other companies’ unregulated subsidiaries. This may lead to increased competition between the regulated utilities and the unregulated power producers within certain markets.

Competitive Strengths

      We believe that we benefit from the following competitive strengths:

      Plant Diversity. Our generation fleet in core regional markets includes plants dispatched as baseload generation, on an intermediate basis and during peak periods. Approximately 4,300 MWs of domestic baseload capacity provide stability of cash flows, while 5,500 MWs of domestic peaking capacity give us significant upside optionality. Our generation facilities include a diversified fuel mix of natural gas, coal and oil. A significant percentage of our core domestic portfolio, approximately 31%, is fueled by coal, which is a distinct advantage at a time of historically high natural gas prices. We believe that our Huntley, Dunkirk, Big Cajun II and Indian River coal-fired facilities will continue, for the foreseeable future, to have competitive advantages in terms of their marginal cost of production relative to the gas-fired plants with which they compete. In addition, a significant portion of our non-coal domestic generation facilities have dual or multiple fuel capability, which allows most of these plants to dispatch with the lowest cost fuel option. The volatility in oil and gas prices versus the stability of low-sulfur western coal prices creates opportunities for us because of our ability to use low-sulfur coal in certain of our plants.

      Locational Advantages. Owning multiple power plants in a particular market provides greater dispatch flexibility and increases power marketing and trading opportunities. We have achieved this goal to a certain extent in the Northeast (New York, New England Power Pool, or NEPOOL, and Pennsylvania, Jersey, Maryland Interconnection, or PJM) and South Central (Entergy) markets.

      Transmission constraints and other market factors give certain of our power plants locational advantages over the competition. For example, the Astoria and Arthur Kill plants serve the New York City market. Competitors outside the city limits are at a disadvantage because transmission constraints restrict the importation of power into New York City, providing an advantage to “in-city” generation physically located within city limits. Construction of new power plants in New York City is limited because of the difficulties in finding sites for new plants, obtaining the necessary permits and arranging fuel delivery. In California, our facilities are located in the Los Angeles and San Diego load basins where, similar to New York City, transmission constraints restrict the import of power from remotely located plants.

      In some locations, a facility’s advantage is enhanced by the potential for repowering or site expansion or alternative use. Certain Connecticut facilities, for example, have attractive locations in transmission-constrained areas in southern Connecticut. The El Segundo plant located in the west Los Angeles load basin is well positioned to serve the needs of that region well into the future. Our California facilities utilize ocean water cooling, which gives them competitive advantages, especially during water shortages in California, and provides a competitive advantage in the potential siting of desalination projects or for other alternative uses. We are working to preserve our options to expand or repower these facilities when economically justifiable.

      Risk Mitigation. As a wholesale generator, we are subject to the risks associated with volatility in fuel and power prices. We seek to mitigate these risks by managing a portfolio of contractual relationships for power supply, fuel needs and transportation services. We reduce spot price volatility exposure via mid- and long-term contractual arrangements when these markets economically justify such transactions. We plan to trade around the contractual commitments consistent with our market view in an effort to produce enhanced value from market volatility.

      Improved Financial Position. As part of our reorganization (discussed below), we eliminated approximately $5.2 billion of corporate level bank and bond debt and approximately $1.3 billion of additional claims and additional disputes. Since January 1, 2004, we have successfully sold select non-core assets and eliminated approximately $989.9 million of consolidated debt related to those assets. We continued managing our balance sheet throughout 2004 with the tack-on bond offering in January and the refinancing of our credit facility in December.

Reorganization

      We were formed in 1992 as the non-utility subsidiary of Northern States Power Company, or NSP, which was itself merged into New Century Energies, Inc. to form Xcel Energy, Inc., or Xcel Energy, in 2000. While

owned by NSP and later by Xcel Energy, we pursued an aggressive high growth strategy focused on power plant acquisitions, high leverage and aggressive development, including site development and turbine orders. In 2002, a number of factors, most notably the aggressive prices paid by us for our acquisitions of turbines, development projects and plants, combined with the overall downturn in the power generation industry, triggered a series of credit rating downgrades which, in turn, precipitated a severe liquidity crisis at the Company. From May 14 to December 23, 2003, we and a number of our subsidiaries undertook a comprehensive reorganization and restructuring under chapter 11 of the United States Bankruptcy Code. With the exception of one subsidiary that remains in bankruptcy to effect its liquidation, all NRG entities had emerged from chapter 11 as of December 31, 2004.

      As part of our reorganization, Xcel Energy relinquished its ownership interest in us, and we became an independent public company. We no longer have any material affiliation or relationship with Xcel Energy. As part of the reorganization, we eliminated approximately $5.2 billion of corporate level bank and bond debt and approximately $1.3 billion of additional claims and disputes by distributing a combination of equity and $1.04 billion in cash to our unsecured creditors.

      As part of our restructuring, on December 23, 2003, we used the proceeds of a new $1.25 billion offering of 8% second priority senior secured notes due 2013, and borrowings under a new $1.45 billion secured credit facility, to retire approximately $1.7 billion of project-level debt. In January 2004, we used proceeds of a tack-on bond offering of the same notes to repay $503.5 million of the outstanding borrowings under the secured credit facility.

      In 2004, we completed our post-confirmation bankruptcy initiatives, including the liquidation of the chapter 11 subsidiaries deemed to be of no value to NRG Energy (LSP-Nelson Energy LLC and NRG Nelson Turbines LLC); the collection and distribution to creditors of amounts owing by our pre-bankruptcy parent company, Xcel Energy, Inc., under the plan of reorganization and related documents; and the settlement of several large disputed claims. We are still litigating or seeking to settle a number of unresolved disputed claims, for which we believe we have established an adequate disputed claims reserve pursuant to the NRG plan of reorganization. In all other respects, the reorganization process was completed in 2004.

      On December 24, 2004, we entered into an amendment and restatement of our $1.45 billion seven-year secured credit facility, recasting it as a $950 million seven-year secured credit facility with more favorable covenants and interest rates, scheduled to expire in December 2011. On December 27, 2004, we completed the issuance of $420 million of perpetual convertible preferred stock, and used the proceeds to redeem $375 million of our 8% second priority senior secured notes on February 4, 2005. In January 2005 and in March 2005, we purchased $25 million and $15.8 million, respectively, of the notes.

Fresh Start Reporting

      As a result of our emergence from bankruptcy, we adopted Fresh Start Reporting, or Fresh Start. Under Fresh Start, our confirmed enterprise value was allocated to our assets and liabilities based on their respective fair values. See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operation — Reorganization and Emergence from Bankruptcy for additional information. 2004 was our first complete year following the adoption of Fresh Start.

Performance Metrics

      The following table contains a summary of our North American power generation revenues from majority-owned subsidiaries for the year 2004:

      In understanding our business, we believe that certain performance metrics are particularly important. These are industry statistics defined by the North American Electric Reliability Council and are more fully described below:

      Annual Equivalent Availability Factor, or EAF: is the total available hours a unit is available in a year minus the sum of all partial outage events in a year converted to equivalent hours (EH), where EH is partial megawatts lost divided by unit net available capacity times hours of each event, and the net of these hours is divided by hours in a year to achieve EAF in percent.

      Average gross heat rate: We calculate the average heat rate for our fossil-fired power plants by dividing (a) fuel consumed in Btus by (b) KWh generated. The resultant heat rate is a measure of fuel efficiency.

      Net Capacity Factor: Net actual generation divided by net maximum capacity for the period hours.

      The table below presents the North American power generation performance metrics for owned assets discussed above for the year ended December 31, 2004.

      The table below presents the Australian power generation performance metrics discussed above for the year ended December 31, 2004.

Power Generation

      Facilities. As of December 31, 2004, we owned 7,884 MW of net generation capacity in the Northeast region of the United States, primarily in New York, Connecticut and Delaware. These generation facilities are diversified in terms of dispatch level (base-load, intermediate and peaking), fuel type (coal, natural gas and oil) and customers.

      The Northeast region’s power generation assets as of December 31, 2004 are summarized in the table below.

      Market Framework. Our largest asset base is located in the Northeast region. This asset base is comprised of investments in generation facilities primarily located in the physical control areas of the New York Independent System Operator, or NYISO, the ISO New England, Inc., or ISO-NE, and the Pennsylvania, Jersey, Maryland Interconnection, or PJM.

      Although each of the three northeast ISOs and their respective energy markets are functionally, administratively and operationally independent, they all follow, to a certain extent, the FERC-endorsed model for Standard Market Design, or SMD. The physical power deliveries in these markets are financially settled by Locational Marginal Prices, or LMPs, which reflect the value of energy at a specific location at the specific

time it is delivered. This value is determined by an ISO- administered auction process, which evaluates and selects the least costly supplier offers or ‘bids’ to fill the specific locational requirement. The ISO-sponsored LMP energy marketplaces consist of two separate and characteristically distinct settlement time frames. The first is a security-constrained, financially firm, “Day Ahead” unit commitment market. The second is a security-constrained, financially settled, “Real-time” dispatch and balancing market. In addition to energy delivery, the ISOs manage secondary markets for installed capacity, ancillary services and financial transmission rights.

      Market Developments. ISO-NE and NEPOOL operate a centralized energy market with “Day-Ahead” and “Real-time” energy markets. 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 we view this proposal as a positive development, as it is currently proposed it would not permit us to recover all of our fixed costs. In response, we have submitted testimony which includes an alternative proposal. FERC’s goal is to make a decision on the precise terms of the NEPOOL LICAP market in the fall of 2005, to be effective January 1, 2006.

      On January 27, 2005, FERC approved the settlement of various reliability must-run, or RMR, agreements between some of our Connecticut generation and ISO-NE. Under the settlement, we 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.

      The NYISO operates an energy market that is structurally the same as the New England energy markets. In April 2003, NYISO implemented a demand curve in its capacity market and scarcity pricing improvements in its energy market. The New York demand curve eliminated the previous market structure’s tendency to price capacity at either its cap (deficiency rate) or near zero. FERC had previously approved the demand curve, but on December 19, 2003, the Electricity Consumers Resource Council appealed the FERC decision to the United States Court of Appeals for the District of Columbia Circuit. On December 3, 2004, NRG Energy and other suppliers filed a brief in opposition. An adverse decision by the Court of Appeals could require the elimination of the demand curve for the capacity market, and would negatively impact the development of LICAP in New England and PJM in addition to New York.

      On January 7, 2005, NYISO filed proposed LICAP demand curves for the following capacity 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. On January 28, 2005, we filed a protest at FERC asserting the LICAP price for this period should be at least $140 per KW-year.

      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.

      On January 25, 2005, FERC issued an order approving the PJM proposal to increase the compensation for generators which are located in load pockets and are mitigated at least 80% of their running time. Specifically, when a generator would be subject to mitigation, the generator would have the option of recovering its variable cost plus $40 or a negotiated rate with PJM, based on the facility’s going forward costs. If the generator declines both options, it could file for an alternative rate with FERC. FERC also substantially revised the exemption of facilities built after 1996 from the energy price capping mitigation rule. Several of our facilities are presently mitigated 80% of the time and, therefore, are impacted by the change.

      Facilities. As of December 31, 2004, we owned 2,469 MW of net generating capacity in the South Central region of the United States. The South Central region’s generating assets consist primarily of our power generation facilities in New Roads, Louisiana, referred to as the Cajun Facilities, and the Sterlington and Bayou Cove generating facilities.

      Our portfolio of plants in Louisiana comprises the third largest generator in the Southeastern Electric Reliability Council/ Entergy, or SERC-Entergy region. Our primary assets are the Cajun Facilities, which are primarily coal-fired assets supported by long-term power purchase agreements with regional cooperatives.

      The South Central region’s power generation assets as of December 31, 2004 are summarized in the table below.

      Market Framework. Our South Central region’s assets are located within the franchise territory of Entergy, a vertically-integrated utility. Entergy performs the scheduling, reserve and reliability functions that are administered by ISOs in certain other regions of the United States and Canada. We operate a North American Electric Reliability Council, or NERC, certified-control area within the Entergy franchise territory, which is comprised of our generating assets and our cooperatives’ customer loads. In the South Central region, including Entergy’s franchise territory, the energy market is not a centralized market and it does not have an independent system operator as is found in the northeast markets. 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. Transacting counter-parties are required to reserve and purchase transmission services from the intervening transmission owners at their FERC-approved tariff rates. Included with these transmission services are the reserve and ancillary costs. Energy prices in the South Central region are determined 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.

      Market Developments. We have long-term “all requirements” contracts with 11 Louisiana distribution cooperatives, serving approximately 350,000 retail customers, and long-term contracts with the Municipal Energy Agency of Mississippi, South Mississippi Electric Power Association and Southwestern Electric Power Company. With limited exceptions, the all-requirements nature of certain of the power supply agreements between Louisiana Generating and its cooperative customers requires Louisiana Generating to serve future expansion of those cooperative loads at existing contract rates. Additionally, at times of maximum demand, our generating facilities do not produce enough power to serve their customers, and we purchase power in the market to make up the shortfall.

      Entergy has filed an Independent Coordinator of Transmission, or ICT, proposal at FERC and with the public service commissions of the states of Louisiana, Mississippi and Arkansas. Entergy states that this proposal will achieve greater oversight of its transmission system operation and provide greater efficiency for providing and pricing transmission service. On March 22, 2005, FERC approved the ICT proposal for a two-year period, subject to certain conditions.

      On December 17, 2004, FERC ordered that an investigation and evidentiary hearing be held to determine whether Entergy is providing access to its transmission system on a short-term basis and in a just and

reasonable manner. On March 22, 2005, FERC suspended the hearing until Entergy indicates whether it will accept the FERC’s conditional approval of its ICT proposal. On March 25, 2005, FERC permitted Entergy’s proposal regarding reserving 2,900 MWs of import capacity on its transmission system for emergency purposes to go into effect subject to refund. The case was set for hearing, which was then suspended pending settlement discussions.

      In December 2004, we entered into a long-term coal transport agreement with the Burlington Northern and Santa Fe Railway Company and affiliates of American Commercial Lines LLC to deliver low sulfur coal to our Big Cajun II facility in New Roads, Louisiana beginning April 1, 2005. In December 2004, we also entered into coal purchase contracts extending through 2007. In March 2005, we entered into an agreement to purchase 23.75 tons of coal over a period of four years and nine months from Buckskin Mining Company, or Buckskin. The coal will be sourced from Buckskin’s mine in the Powder River Basin, Wyoming, and will be used primarily in NRG Energy’s coal-burning generation plants in the South Central region.

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

      Facilities. As of December 31, 2004, we owned 1,315 MW of net generating capacity in the West Coast region, primarily in California and Nevada. Our West Coast generation assets consist primarily of a 50% interest in West Coast Power LLC, or West Coast Power. Effective January 1, 2005, the Long Beach Generating Station was permanently retired, reducing our net generating capacity by 265 MW, to 1,050 MW. The ultimate disposition of the Long Beach plant and property has yet to be determined. However, site demolition and remediation costs, if required, are expected to approximate the market value of the property. The Company has been negotiating a sale of the Saguaro plant and closing is expected to take place sometime during 2005.

      In May 1999 we formed West Coast Power, along with Dynegy, Inc., to serve as the holding company for a portfolio of operating companies that own generation assets in Southern California in the California Independent System Operator, or Cal ISO, market. This portfolio currently consists of the El Segundo Generating Station, the Encina Generating Station and 13 combustion turbines in the San Diego area. Dynegy provides power marketing and fuel procurement services to West Coast Power, and we provide operations and management services. On December 23, 2004, California Energy Commission, or CEC, approved our application for a permit to repower the existing El Segundo site and replace retired units 1 and 2 with 630 MW of new generation. On January 19, 2005, the CEC voted unanimously to reconsider its December 23, 2004 decision to certify the repowering project. The reconsideration hearing took place on February 2, 2005 and the permit was approved by unanimous vote of the CEC. The reconsideration extended the 30-day period in which parties may petition for rehearing or seek judicial review to March 4, 2005. A petition seeking review of the CEC final order was filed with the California Supreme Court on March 14, 2005. We believe this filing to be untimely.

      Our West Coast Power assets were supported by a power purchase agreement with the California Department of Water Resources that expired on December 31, 2004. We do not anticipate that we can replace that contract with one that has similar or more attractive terms and conditions. One-year term RMR contracts with Cal ISO for 576 MW of net owned capacity in the San Diego area have been renewed for 2005. On January 1, 2005, a new RMR agreement for the 670 MW gross capacity of the West Coast Power El Segundo generating facility became effective. In January 2005, that generating facility entered into a tolling agreement for its entire gross generating capacity of 670 MW commencing May 1, 2005 and extending through

December 31, 2005. During the term of this agreement, the purchaser will be entitled to primary energy dispatch right for the facility’s generating capacity. The agreement is subject to the amendment of the El Segundo RMR agreement to switch to RMR Condition I and to otherwise allow the purchaser to exercise its primary dispatch rights under this agreement while preserving Cal ISO’s ability to call on the El Segundo facility as a reliability resource under the RMR agreement, if necessary. The RMR contract on approximately 45 MW of generating capacity at Red Bluff expired on December 31, 2004 and will not be renewed for 2005.

      The West Coast region’s power generation assets as of December 31, 2004 are summarized in the table below.

      Market Framework. Our West Coast region assets are primarily located within the control area of Cal ISO. Cal ISO operates a financially settled “Real-time” balancing market similar to the regional ISOs in the northeast area of the U.S. Cal ISO’s “Day Ahead” energy markets are similar to those in the South Central region, with all power sales and purchases consummated bilaterally between individual counter-parties and scheduled for physical delivery with Cal ISO.

      Market Developments. In California, Cal ISO continues with its plan to move toward markets similar to PJM, NYISO and ISO-NE, with its Market Redesign & Technology Upgrade, or MRTU, formerly known as MD02 (market design 2002). The proposed changes will re-establish a “real-time” market and allow for multiple settlements. NRG Energy views this as an improvement to the existing structure. In general, Cal ISO is continuing along a path of small incremental changes, rather than implementing a comprehensive market restructuring. The effect of the new MRTU changes on NRG Energy cannot be determined at this time.

      In addition to the Cal ISO’s market changes, numerous legislative initiatives in California create uncertainty and risk for us. Most significantly, SB39XX mandates that the California Public Utilities Commission, or CPUC, exercise jurisdiction over the operating and maintenance procedures of wholesale power generators including the setting of operating, maintenance and logbook standards. On October 28, 2004, the CPUC issued draft orders directing in-state utilities to meet a 15-17% reserve requirement by no later than June 2006, and establishing a requirement that the utilities acquire 90% of their capacity needs a year in advance. This order may present opportunities for West Coast Power to enter into new bilateral agreements.

      In September 2004, Governor Schwarzenegger vetoed AB2006, commonly referred to as the “re-regulation” initiative, with a promise to the people of California to create a competitive energy market in California that will attract the investment capital required to meet growing load obligations.

      Facilities. As of December 31, 2004, we owned approximately 1,591 MW of net generating capacity in other regions of the U.S.

      Our Other North America power generation assets as of December 31, 2004 are summarized in the table below.

      Facilities. As of December 31, 2004, we owned approximately 1,390 MW of net generating capacity in Australia. The Flinders assets are comprised of the Northern Power Station which provides 520 MW, the refurbished Playford Power Station, which provides 240 MW and the Leigh Creek Coal Mine which supplies coal to both plants. The 1,680 MW Gladstone Plant, of which we own 37.5%, is operated by NRG Energy.

      Our Australian power generation assets as of December 31, 2004 are summarized in the table below.

      The National Electricity Market operates across the interconnected states of southern and eastern Australia. The market represents a physical wholesale trading exchange based on merit order generation dispatch and gross pool settlement, within an energy-only market design. The physical market is managed by National Electricity Market Management Co. Ltd., or NEMMCO, as the independent market operator, with spot prices determined on a regional basis in half-hourly trading intervals, capped at a maximum of AUD 10,000/ MWh. The majority of wholesale trading occurs through bilateral financial (hedge) contracts between counter-parties on a regional basis, with some limited financial trading through exchange traded futures.

      The Flinders plant operates within the market as a merchant portfolio. Northern Power Station (520 MW base load) and Playford Power Station (240 MW mid merit) are the only coal-fired units in South Australia. Their output, together with the output of the gas fired Osborne Power Station (output purchased under long-term power purchase agreements, or PPAs) supply over 40% of the state’s electricity. All output is market traded, with revenue streams protected by hedge contracts for a large proportion of forward output.

      The output of Gladstone is fully contracted under long-term PPAs to an adjacent aluminum smelter and a government entity that trades its portion into the market.

      In late 2003, the governments spanning the National Electricity Market embarked upon a series of reforms to address perceived deficiencies in the governance and institutional structure of the market. These reforms are proceeding under cooperative legislation expected to be in operation by mid-2005, and include the creation of a new national energy regulator and the establishment of a more efficient process to change and administer the rules governing the operation of the market.

      These reforms are not intended to alter the operation or fundamental design of the market, but are designed to streamline the administration of the wholesale market, increase regulatory certainty for investors, and improve rule change and decision-making processes in both the electricity and gas sectors.

      Further policy announcements are expected in the near future in relation to electricity transmission planning and regulation, trading region boundary change arrangements, and funding arrangements for the new institutional bodies.

      Facilities. Over the past decade, through our foreign subsidiaries, we invested in international power generation projects in Australia, Europe and Latin America. During 2002, 2003 and 2004, we sold international generation projects with an aggregate total generating capacity of approximately 600 MW, 1,640 MW and 833 MW, respectively. As of December 31, 2004, we had investments in power generation projects located in the United Kingdom, Germany and Brazil with approximately 768 MW of net generating capacity.

      Our Other International power generation assets as of December 31, 2004 are summarized in the table below.

      We own alternative energy generation facilities through NEO Corporation, or NEO, and through our NRG Resource Recovery business division, which converts municipal solid waste, or MSW, into refuse derived fuel suitable to burn in third party power plants.

      NEO Corporation. NEO is a wholly-owned subsidiary that was formed to develop power generation facilities ranging in size from one to 49 MW in the United States. As of December 31, 2004, NEO had 41 MW of net ownership interests in 15 hydroelectric facilities and 98.6 MW of net ownership interests in four distributed generation facilities including 94 MW of gas-fired peaking engines in California (referred to as the Red Bluff and Chowchilla facilities and included in our summary of the West Coast region). Certain of the assets owned by NEO are currently being marketed. See “Significant Dispositions of Non-Strategic Assets” under this Item 1 for more information.

      Resource Recovery Facilities. Our Resource Recovery business is focused on owning and operating alternative fuel/“green power” generation and fuels processing projects. The alternative fuels currently processed and combusted are municipal solid waste, urban wood waste (pallets, clean construction debris, etc.), and non-recyclable waste paper and compost. Our Resource Recovery business has municipal solid waste processing capacity of approximately 2,800 tons per day. Our Resource Recovery business owns and operates municipal solid waste processing facilities in Minnesota, as well as NRG Processing Solutions, including ten composting and biomass fuel processing sites in Minnesota, three of which are permitted to operate as municipal solid waste transfer stations.

      Our significant Resource Recovery assets as of December 31, 2004 are summarized in the table below.

      In addition to our traditional power generation facilities discussed above, we have interests in district heating and cooling systems and steam transmission operations through our subsidiary, NRG Thermal LLC. NRG Thermal’s steam and chilled water businesses have a steam and chilled water capacity of approximately 1,225 megawatt thermal equivalents, or MWt.

      As of December 31, 2004, NRG Thermal owned five district heating and cooling systems in Minneapolis, Minnesota; San Francisco, California; Pittsburgh, Pennsylvania; Harrisburg, Pennsylvania; and San Diego, California. These systems provide steam heating to approximately 565 customers and chilled water to 90 customers. In addition, NRG Thermal owns and operates three projects that serve industrial/government customers with high-pressure steam and hot water, an 88 MW combustion turbine peaking generation facility and an 18 MW coal-fired cogeneration facility in Dover, Delaware (included in the summary of the Other North America region).

      Our thermal and chilled water assets as of December 31, 2004 are summarized in the table below.

Energy Marketing

      Our wholly-owned energy marketing subsidiary, NRG Power Marketing, Inc., or PMI, began operations in 1998. PMI provides a full range of energy management services for our domestic generation facilities. These services are provided under bilateral contracts or agreements pursuant to which PMI engages in the sale,

purchase and trading of energy, capacity and ancillary services from the facilities, transacts in and trades the fuel (coal, oil and natural gas) and associated transportation, and manages and trades the emission allowance credits for these facilities. A significant responsibility of PMI is to recommend to senior management commercial hedge transactions in an effort to manage risk and to maximize earnings and cash flow for NRG Energy. In addition, PMI provides all necessary ISO bidding, dispatch, and transmission scheduling for the facilities. PMI also utilizes its contractual arrangements with third parties to procure fuel, to sell energy, capacity and ancillary services to minimize administrative costs and burdens and reduce the collateral requirements imposed by third party suppliers and purchasers.

NRG Worldwide Operations

      Our wholly-owned subsidiary, NRG Worldwide Operations, or NRG Operations, provides operating and maintenance services to our generation facilities. These services include providing experienced personnel for the operation and administration of each facility and oversight out of the corporate office to balance resources, share expertise and best practices, and to ensure the optimum utilization of resources available to the facilities. In addition, NRG Operations provides overall facilities management, strategic planning, and the development and dissemination of consistent Company policies and practices relating to operations.

Financial Information About Segments and Geographic Areas

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

Dispositions of Non-Strategic Assets

      We continue to market our interest in our remaining non-core assets. Since 2003, we sold or made arrangements to sell a number of consolidated businesses and equity investments in an effort to reduce our debt, improve liquidity and rationalize our investments. Dispositions completed during 2004 are summarized in the following chart:

Significant Customers

      For the year ended December 31, 2004, we derived approximately 49.8% of our total revenues from majority-owned operations from four customers: NYISO accounted for 28.5%, ISO New England accounted for 9.1%, National Electricity Market Management Co. Ltd (Australia) accounted for 6.8% and Vattenfall Europe (Germany) accounted for 5.4%. We account for the revenues attributable to NYISO and ISO-NE as

part of our North American power generation segment. We account for the revenues attributable to National Electricity Market Management and Vattenfall Europe as part of our International segment. For the period December 6, 2003 through December 31, 2003, we derived approximately 39.0% of our total revenues from majority-owned operations from two customers: NYISO accounted for 26.5% and ISO-NE accounted for 12.5%. ISO-NE and NYISO are ISOs or RTOs and are FERC-regulated entities that administer a residual (spot) energy market and manage transmission assets collectively under their respective control to provide non-discriminatory access to the transmission grid. The NYISO exercises operational control over most of New York State’s transmission facilities. We anticipate that NYISO will continue to be a significant customer given the scale of our asset base in the NYISO control area.

      For the period January 1, 2003 through December 5, 2003 and for the year ended December 31, 2002, sales to one customer, NYISO, accounted for 33.4% and 26.0% of our total revenues from majority-owned operations, respectively.

Seasonality and Price Volatility

      Annual and quarterly operating results can be significantly affected by weather and price volatility. Significant other events, such as the demand for natural gas and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility. We derive a majority of our annual revenues in the months of May through September, when demand for electricity is the highest in our North American markets. Further, volatility is generally higher in the summer months due to the effect of temperature variations. Our second most important season is winter when volatility and price spikes in underlying fuel prices have tended to drive seasonal electricity prices. Issues related to seasonality and price volatility are fairly uniform across our business segments.

Sources and Availability of Raw Materials

      Our raw material requirements primarily include various forms of fossil fuel, including oil, natural gas and coal. We obtain our oil, natural gas and coal from multiple sources and availability is generally not an issue, although localized shortages, transportation availability and supplier financial stability issues can and do occur. The prices of oil, natural gas and coal are subject to macro- and micro-economic forces that can change dramatically in both the short-term and the long-term. For example, the price of natural gas was particularly volatile in mid-January 2004 due to the extreme temperatures experienced in the Northeast. Additionally, throughout 2004, oil prices were extremely high due to the geo-political uncertainty in the Middle East and increased demand by China and India. The total cost of oil, natural gas and coal represented approximately 41.6%, 37.5%, 42.4% and 15.1% of our total operating costs and expenses for the year ended December 31, 2004, the periods December 6, 2003 through December 31, 2003 and January 1, 2003 through December 5, 2003, and for the year ended December 31, 2002, respectively. Issues related to the sources and availability of raw materials are fairly uniform across our business segments.

Employees

      As of December 31, 2004, we had 2,644 employees, approximately 555 of whom are employed directly by us and approximately 2,089 of whom are employed by our wholly-owned subsidiaries and affiliates. Approximately 1,011 employees are covered by bargaining agreements. During 2004, we experienced no significant labor stoppages or labor disputes at our facilities.

Federal Energy Regulation

      Federal Energy Regulatory Commission. The FERC is an independent agency that regulates the transmission and wholesale sale of electricity in interstate commerce under the authority of the Federal Power Act, or FPA. In addition, FERC determines whether a generation facility qualifies for Exempt Wholesale Generator, or EWG, status under Public Utility Holding Company Act of 1935, or PUHCA. FERC also

determines whether a generation facility meets the ownership and technical criteria of a Qualifying Facility, or QF, under Public Utility Regulatory Policies Act of 1978, or PURPA.

      Federal Power Act. The FPA gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of electricity in interstate commerce. FERC regulates the owners of facilities used for the wholesale sale of electricity or transmission in interstate commerce as “public utilities.” The FPA also gives FERC jurisdiction to review certain transactions and numerous other activities of public utilities. Our QFs are exempt from the FERC’s FPA rate regulation.

      Public utilities are required to obtain FERC’s acceptance of their rate schedules for wholesale sales of electricity. Because our non-QF generating companies are selling electricity in the wholesale market, such generating companies are deemed to be public utilities for purposes of the FPA. FERC has granted our generating and power marketing companies the authority to sell electricity at market-based rates. Usually, the FERC’s orders that grant our generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that we can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. If our generating and power marketing companies were to lose their market-based rate authority, such companies may be required to obtain FERC’s acceptance of a cost-of-service rate schedule and may become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

      In addition, the FPA gives FERC jurisdiction over a public utility’s issuance of securities or assumption of liabilities. However, FERC usually grants blanket approval for future securities issuances or assumptions of liabilities to entities with market-based rate authority. In the event that one of our public utility generating companies were to lose its market-based rate authority, our future securities issuances or assumptions of liabilities could require prior approval of the FERC.

      The FPA also requires the FERC’s prior approval for the transfer of control over assets subject to FERC’s jurisdiction. FERC has jurisdiction over certain facilities used to interconnect our generating projects to the transmission grid, and over the filed rate schedules and tariffs of our EWG generating projects and power marketing operating companies. Thus, transferring these assets would require FERC approval.

      In New England, New York, the Mid-Atlantic region, the Midwest and California, FERC has approved independent system operators or regional transmission organizations, or ISOs or RTOs. Most of these ISOs or RTOs administer a wholesale centralized bid-based spot market in their regions pursuant to tariffs approved by FERC. These tariffs/market rules dictate how the day-ahead and real-time markets operate and how entities with market-based rates shall be compensated within those markets. The ISOs or RTOs in these regions also control access to and the operation of the transmission grid within their footprint. Outside of ISO or RTO-controlled regions, we are allowed to sell energy at market-based rates as determined by willing buyers and sellers. Access to, pricing for, and operation of the transmission grid in such regions is controlled by the local transmission owning utility according to its Open Access Transmission Tariff approved by FERC.

      Public Utility Holding Company Act. PUHCA defines as a “holding company” any entity that owns, controls or has the power to vote 10% or more of the outstanding voting securities of a “public utility company.” Unless exempt, a holding company is required to register with the Securities and Exchange Commission, or the SEC, and it and its Subsidiaries (i.e., a company with 10% of its voting securities held by the registered holding company) become subject to extensive regulation. Registered holding companies under PUHCA are required to limit their utility operations to a single, integrated utility system and divest any other operations that are not functionally related to the operation of the utility system. In addition, a company that is a Subsidiary of a registered holding company is subject to financial and organizational regulation, including approval by the SEC of certain financings and transactions. Domestic generating facilities that qualify as QFs and/or that have obtained EWG status from FERC are exempt from PUHCA. Each of our domestic generating subsidiaries has been designated by FERC as an EWG or is otherwise exempt from PUHCA because it is a QF under PURPA. Because our generating subsidiaries have EWG or QF status, we do not qualify as a “holding company” under PUHCA. We will not be subject to regulation under PUHCA as long as (a) we do not become a Subsidiary of another registered holding company and (b) the projects in which we

have an interest (1) qualify as QFs under PURPA, (2) obtain and maintain EWG status under Section 32 of PUHCA, (3) obtain and maintain Foreign Utility Company, or FUCO, status under Section 33 of PUHCA, or (4) are subject to another exemption or waiver. If our projects were to cease to be exempt and we were to become subject to SEC regulation under PUHCA, it would be difficult for us to comply with PUHCA absent a substantial corporate restructuring.

      Regulatory Developments. FERC is attempting to spur deregulation of the wholesale markets by requiring transmission owners to provide open, non-discriminatory access to electricity markets and the transmission grid. In April 1996, FERC issued Orders 888 and 889, which required all public utilities to file “open access” transmission tariffs that give wholesale generators, as well as other wholesale sellers and buyers of electricity, access to transmission facilities on a non-discriminatory basis. This led to the formation of the ISOs described above. On December 20, 1999, FERC issued Order 2000, encouraging the creation of RTOs. On July 31, 2002, FERC issued its Notice of Proposed Rulemaking regarding Standard Market Design, or SMD. All three orders were intended to eliminate market discrimination by incumbent vertically integrated utilities and to provide for open access to the transmission grid. The status of FERC’s RTO and SMD initiatives is uncertain. On April 28, 2003, FERC issued a white paper describing proposed changes to the proposed SMD rulemaking that would, among other things, allow for more regional differences. In addition, the Energy Bill pending before Congress could restrict FERC’s ability to implement these initiatives.

      The full effect of these changes on us is uncertain at this time, because in many parts of the United States it has not been determined how entities will attempt to comply with FERC’s initiatives. At this time, five ISOs have been approved and are operational: ISO-NE in New England; the NYISO in New York; PJM in the Mid-Atlantic region; the Midwest Independent System Operation, or MISO, in the Central Midwest region; and the Cal ISO in California. Three of these ISOs: PJM, MISO and ISO-NE, have been found to also qualify as RTOs.

      We are affected by rule/tariff changes that occur in the existing ISOs and RTOs. The ISOs and RTOs that oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address some of the volatility in these markets. For example, ISO-NE, NYISO, PJM and Cal ISO have imposed price limitations. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell energy into the wholesale power markets. In addition, the regulatory and legislative changes that have recently been enacted in a number of states in an effort to promote competition are novel and untested in many respects. These new approaches to the sale of electric power have very short operating histories, and it is not yet clear how they will operate in times of market stress or pressure, given the extreme volatility and lack of meaningful long-term price history in many of these markets and the imposition of price limitations by independent system operators.

Environmental Matters

      We are subject to a broad range of foreign, federal, state and local environmental and safety laws and regulations in the development, ownership, construction and operation of our domestic and international projects. These laws and regulations impose requirements on discharges of substances to the air, water and land, the handling, storage and disposal of, and exposure to, hazardous substances and wastes and the cleanup of properties affected by pollutants. These laws and regulations generally require that we obtain governmental permits and approvals before construction or operation of a power plant commences, and after completion, that our facilities operate in compliance with those permits and applicable legal requirements. We could also be held responsible under these laws for the cleanup of pollutants released at our facilities or at off-site locations where we may have sent wastes, even if the release or off-site disposal was conducted in compliance with the law.

      Environmental laws have become increasingly stringent over time, particularly the regulation of air emissions from our plants. Such laws generally require regular capital expenditures for power plant upgrades, modifications and the installation of certain pollution control equipment. In addition, regulatory compliance for the construction of new facilities is a costly and time-consuming process. Intricate and rapidly changing

environmental regulations may require major capital expenditures for permitting and create a risk of expensive delays or material impairment of project value if projects cannot function as planned due to changing regulatory requirements or local opposition. In all cases, we seek to reflect environmental impacts and mitigants in every business decision we make, and by doing so, strive to improve our competitive advantage by meeting or exceeding environmental and safety requirements in the management and operation of our assets.

      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 as a result of 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 pollution control equipment or the imposition of certain restrictions on our operations. We expect that future liability under, or compliance with, environmental and safety requirements could have a material effect on our operations or competitive position.

      Power projects are subject to stringent environmental and safety protection and land use requirements in the U.S. 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 our facilities are not exempted from coverage, we could be required to make extensive modifications to further reduce potential environmental impacts.

      We establish accruals where it is probable that we will incur environmental costs under applicable law or contract and it is possible to reasonably estimate those costs. We adjust 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.

      Several federal regulatory and legislative initiatives to further limit and control pollutant emissions from fossil fuel-fired combustion units are currently underway. Although neither the exact impact of these initiatives nor their final form is known at this time, all of our power plants will likely be affected in some manner by the expected changes in federal environmental laws and regulations. In Congress, legislation has been proposed that would impose annual caps on U.S. power plant emissions of nitrogen oxides, or NO_X, sulfur dioxide, or SO₂, mercury and, in some instances, carbon dioxide, or CO₂.

      In December 2003, the U.S. Environmental Protection Agency, or USEPA, proposed rules governing mercury emissions from power plants. On March 15, 2005, USEPA issued the Clean Air Mercury Rule, or CAMR, to permanently cap and reduce mercury emissions from coal-fired power plants. CAMR imposes limits on mercury emissions from new and existing coal-fired plants and creates a market-based cap-and-trade program that will reduce nationwide utility emissions of mercury in two phases (2010 and 2018), to achieve an ultimate reduction level of approximately 70%. The cap-and-trade program for mercury is expected to be structured like the federal Acid Rain Program, allowing generators to decide in each particular case the most effective means for their compliance (i.e., install control technologies and/or purchase emissions allowances in the market). As there has been significant debate on whether USEPA has authority to regulate mercury emissions through the proposed cap-and-trade mechanism (as opposed to a command-and-control requirement to install “maximum achievable control technology”, or MACT, on a unit basis), it is reasonable to expect that the new rule may be subject to legal challenge. Each of our coal-fired electric power plants will be subject to mercury regulation. However, since the final rule has yet to be implemented by individual states pursuant to state-specific legislation, it is not possible to identify in detail how the final mercury rules will affect our operations located in those states. Nevertheless, we continue to actively review emerging mercury monitoring and mitigation technologies and assess appropriate options for the Company in future.

      The USEPA has also proposed MACT standards for nickel from oil-fired units. The proposed nickel rule would accept the use of an electrostatic precipitator, or ESP, as the appropriate MACT control, with an implementation date of three years after rule promulgation. Eight of the Company’s oil-fired generating units are not equipped with an ESP: Middletown Unit 4, Montville Unit 6, Vienna and Encina Units 1-5. While

USEPA’s final decision regarding nickel emissions from oil-fired units is still pending, USEPA is reconsidering whether, based on the scientific data, any new controls on nickel emissions from oil-fired generators are in fact needed. Given the current situation, we do not consider any material expenditure for nickel emission mitigation by the Company to be probable at this time.

      The USEPA has finalized federal rules governing ozone season NO_X emissions across the eastern U.S. Current ozone season rules are being implemented within two programs. Restrictions exist in the Ozone Transport Region, or OTR, through annual ozone seasons (May – September) and all of the Company’s generating units located in the OTR are included in this program (which was effective in 2003). NO_X allowance allocations are based on an equivalent emissions rate of 0.15 lbs/MMBtu, with each OTR state managing its own NO_X Budget Program and specific rules for allowance distribution. The second program, in effect from May 2004, is similar to the OTR program, and extends to states within the Ozone Transport Assessment Group, or OTAG, region. This restricts 2004 and subsequent ozone season NO_X emissions in most states east of the Mississippi River. These rules essentially require one NO_X allowance to be held for each ton of NO_X emitted from fossil fuel-fired stationary boilers, combustion turbines, or combined cycle systems. NO_X allowance allocation is similar to the OTR and each of the Company’s facilities that is subject to these rules has been allocated NO_X emissions allowances. While the portfolio total is currently sufficient to cover operations at these facilities, if at any point allowances are insufficient for the anticipated operation of each of these facilities, the Company must purchase NO_X allowances. Any need to purchase additional NO_X allowances could have a material adverse effect on our operations.

      On March 10, 2005, the USEPA announced the Clean Air Interstate Rule, or CAIR, originally proposed in January 2004. The new rule applies to 28 eastern states and the District of Columbia and caps SO₂ and NO_X emissions from power plants in two phases: 2010 and 2015 for SO₂ and 2009 and 2015 for NO_X. CAIR will reduce such emissions in aggregate by just over 70% in the case of SO₂ and just under 70% in the case of NO_X and will apply to certain of the Company’s power plants located in New York, Massachusetts, Connecticut, Delaware (NO_X only) and Louisiana. States must achieve the required emission reductions using one of two compliance options: (a) meet the state’s emission budget by requiring power plants to participate in a USEPA-administered interstate cap-and-trade system; or (b) meet an individual state emissions budget through measures selected by individual states. While the Company’s current business plans include initiatives (for example, the conversion of Huntley and Dunkirk to burn low sulfur coal) in part to address the new emissions caps, until the final rule as issued by USEPA is actually implemented by specific state legislation, it is not possible to identify with greater specificity the effect of CAIR on the Company.

      In 2004, USEPA reproposed the 1999 Regional Haze Rule, designed to improve air quality in national parks and wilderness areas. This rule requires regional haze controls (by targeting SO₂ and NO_X emissions from sources including power plants) through the installation of Best Available Retrofit Technology, or BART, for certain sources put into operation between 1962 and 1977. The so-called BART rule is expected to be finalized in April 2005, with states required to submit their implementation plans by 2008. It is likely that the BART rule, if implemented, will affect many of the Company’s facilities. However, it is also expected that required actions taken for compliance with CAIR (when it is fully implemented) and certain state initiatives will also achieve compliance with the BART rule as currently proposed.

      During the first quarter of 2002, USEPA proposed new rules governing cooling water intake structures at existing power facilities (the Phase II 316(b) Rules). These rules were finalized in February 2004. The Phase II 316(b) Rules specify certain location, design, construction, and capacity standards for cooling water intake structures at existing power plants using the largest amounts of cooling water. These rules will require implementation of the Best Technology Available, or BTA, for minimizing adverse environmental impacts unless a facility shows that such standards would result in very high costs or little environmental benefit. The Phase II 316(b) Rules require the Company’s facilities that withdraw water in amounts greater than 50 million gallons per day to submit certain surveys, plans, operational measures, and restoration measures (with wastewater permit applications or renewal applications) that would minimize certain adverse environmental impacts of impingement or entrainment. The Phase II 316(b) Rules affect a number of the Company’s plants, specifically those with once-through cooling systems. Compliance options include the addition of control technology, modified operations, restoration, or a combination of these, and are subject to a

comparative cost and cost/benefit justification. While we have conducted a number of the requisite studies (and in one case already budgeted to install BTA), until all the needed studies throughout our fleet have been completed and consultations on the results have occurred with USEPA (or its delegated state or regional agencies), it is not possible to estimate the capital costs that will be required for compliance with the Phase II 316(b) Rules.

      Federal legislation, such as the Clear Skies Act, or Clear Skies, has been proposed that would impose annual caps on U.S. power plant emissions of NO_X, SO₂, mercury, and, in some instances, CO₂. Under Clear Skies, these caps would go into effect in two phases: 2010 and 2016 for SO₂; 2008 and 2016 for NO_X; and 2010 and 2016 for mercury, with the proposed final reduction level in 2016 for SO₂, NO_X and mercury being approximately 70%. Clear Skies was first proposed in 2002 and while the bill stalled in Senate Committee on March 9, 2005, the Bush Administration continues to support, and work with Congress to achieve, passage of Clear Skies in 2005. Clear Skies overlaps to a significant degree with the USEPA CAIR and CAMR, and would modify or supersede those rules if enacted as federal legislation.

      While the Bush Administration has publicly stated that it does not support mandatory national restrictions on greenhouse gas, or GHG, emissions, it supports a number of initiatives with respect to voluntary reductions of “carbon intensity” (a measure of carbon emissions per unit of GDP). A number of members of the Senate and Congress continue to call for federal GHG regulation and to propose legislation. Additionally, there have been several petitions from states and other parties to compel USEPA to regulate GHGs under the Clean Air Act, or CAA. On September 3, 2003, USEPA denied a petition by Massachusetts, Maine and Connecticut to require USEPA to establish a National Ambient Air Quality Standard, or NAAQS, for CO₂. Since that time, twelve states and other territorial entities have filed suit against USEPA asking the Court to address whether USEPA has an existing obligation to regulate GHGs under the CAA. Oral arguments in the case are scheduled for April, 2005. Additionally, eight states and the City of New York filed suit on July 21, 2004 against American Electric Power Company, Southern Company, Tennessee Valley Authority, Xcel Energy, Inc. and Cinergy Corporation, alleged to be the nation’s five largest emitters of GHGs and all of which are owners of electric generation. On the same day, a similar complaint was filed in the same court against the same defendants by the Natural Resources Defense Council on behalf of certain special interest groups. In both cases, the complaint seeks an injunction against each defendant forcing it to abate its contribution to the “global warming nuisance” by requiring it to cap its CO₂ emissions and then reduce them by a specified percentage each year for at least a decade. The outcome of this litigation and proposed legislation cannot be predicted. The Company’s compliance costs with any mandated GHG reductions in the future could be material.

      Other federal initiatives that could affect the Company’s generating facilities with respect to fine particulate matter (PM2.5), and ozone are underway, with compliance implementation timeframes expected from 2009.

      Northeast Region. Connecticut rules on air regulation require certain reductions in emissions of SO₂ (in two steps: 2002 and 2003). The Company’s Connecticut plants have operated in compliance with both phases of the rule. The Company also complies with Connecticut’s NO_X emission rules (restricting the average, non-ozone season NO_X emission rate to 0.15 lbs/ MMBtu), through selective firing of natural gas, use of selective non-catalytic reduction, or SNCR, technology presently installed at the Norwalk Harbor and Middletown Power Stations, improved combustion controls, use of emission reduction credits, and purchase of allowances. In 2002, the Connecticut legislature passed a law further tightening air emission standards by eliminating emissions credit purchases after January 1, 2005 as a means of meeting Department of Environmental Protection, or DEP, regulatory standards for SO₂ emissions from older power plants. The Company plans to comply with the legislation through the use of lower sulfur oil.

      Massachusetts air regulations prescribe schedules under which six existing coal-fired power plants in-state are required to meet stringent emission limits for NO_X, SO₂, mercury, and CO₂. The state has reserved the issue of control of carbon monoxide and particulate matter emissions for future consideration. Consistent

with a permit to install natural gas reburn technology to meet the NO_X and SO₂ limits received in early 2003 from the Massachusetts Department of Environmental Protection, or MADEP, the Company has implemented that technology at Somerset station. On June 4, 2004, MADEP issued its regulation on the control of mercury emissions. The effect of this regulation is that starting October 1, 2006, Somerset will be capped at 13.1 lbs/year of mercury and as of January 1, 2008, Somerset must achieve a reduction in its mercury inlet-to-outlet concentration of 85%. The Company plans to meet the requirements through the management of its fuels, and the use of early and off-site reduction credits. Additionally, the Company has entered into an agreement with MADEP to retire or repower the Somerset station by the end of 2009. The Company is currently considering its options with respect to how it will address MADEP’s CO₂ emission standards; part of this analysis depends upon the outcome of the model rule process currently underway for the Regional Greenhouse Gas Initiative, or RGGI, discussed below.

      New York State Department of Environmental Conservation, or NYSDEC, rules reducing allowable SO₂ and NO_X emissions from large, fossil-fuel-fired combustion units in New York State became effective October 2004. The reductions are achieved through an allowance-based cap-and-trade program that affects only New York sources. Specifically, New York electric generators have to reduce SO₂ emissions to 25% below the levels allowed in the federal Acid Rain Program starting January 2005 and 50% below the levels allowed by federal Acid Rain Program starting in January 2008. Under this Acid Rain Deposition Program, or ADRP, electric generators also have to meet the ozone season NO_X emissions limit of 0.15 lbs/MMBtu year-round, starting October 2004. The Company’s strategy for complying with the ADRP is to generate early reductions of SO₂ and NO_X emissions associated with fuel switching and use such reductions to extend the timeframe for implementing technological controls, which could ultimately include the addition of flue gas desulfurization, or FGD, and selective catalytic reduction, or SCR, equipment. On January 11, 2005, the Company reached an agreement with the State of New York and the NYSDEC in connection with voluntary emissions reductions at the Huntley and Dunkirk facilities, as discussed in Item 3 — Legal Proceedings. The Company does not anticipate that any material capital expenditures, beyond those already planned, will be required for our Huntley and Dunkirk plants to meet the current compliance standards in New York (including under the recent settlement) through the end of the decade.

      While no rules affecting the Company’s existing facilities have been formally proposed, Delaware has foreshadowed the development of MACT-comparable standards for SO₂, NO_X and mercury. Delaware is considering such rule-making based on recent determinations that portions of the state are in non-attainment for NAAQS for fine particulates, or PM2.5, and all of the state is in non-attainment for the NAAQS for 8-Hour Ozone. The Company is evaluating voluntary emissions reductions opportunities which may include blending low sulfur western coals. While Delaware has not yet issued a proposed rule, the Company is currently participating as a stakeholder in such policy-making efforts along with the Governor’s Energy Task Force, legislators, the PSC and the Delaware Department of Natural Resources and Environmental Control, or DNREC. Further, Delaware has begun rule-making in regard to developing emissions standards for small combustion turbines and distributive generation sources and implementing USEPA’s New Source Review, or NSR, revisions. In addition to air emission initiatives, Delaware has also established Total Maximum Daily Loading, or TMDL, standards for temperature in its watersheds and intends to establish one for mercury as well. The Company continues to participate in these developments and has filed comments with the relevant agencies.

      In July 2003, nine northeastern states announced a regional initiative to establish a cap-and-trade GHG program for electric generators, referred to as the Regional Greenhouse Gas Initiative, or RGGI. The model RGGI rule is to be announced in 2005, with an estimate of two to three years for participating states to finalize implementing regulations. A proposed level of the RGGI cap has not been determined at this time. If implemented, our plants in New York, Delaware, Massachusetts, and Connecticut may be affected and our compliance costs with any mandated GHG reductions in the future could be material.

      The Ozone Transport Commission, or OTC, was established by Congress and governs ozone and the NO_X budget program in certain eastern states, including Massachusetts, Connecticut, New York and Delaware. In January 2005, the OTC stepped up its efforts to develop a multi-pollutant regime (SO₂, NO_X, mercury and CO₂) that is expected to be completed by mid-2006 (with individual state implementation to

follow), particularly if Clear Skies does not eventuate in 2005 or CAIR is perceived to be lenient. The Company continues to be engaged in the OTC stakeholder process. While it is not possible to predict the outcome of this regional legislative effort, to the extent that the OTC seeks to effect emissions requirements that are more stringent than currently proposed or existing regimes (including the recently reached New York settlement), the Company could be materially impacted.

      South Central Region. The Louisiana Department of Environmental Quality, or LADEQ, has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone non-attainment area into compliance with applicable NAAQS. 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 lbs/ MMBtu and 0.21 lbs/ MMBtu NO_X, respectively (both based on heat input). This revision of the Louisiana air rules would constitute a change-in-law covered by agreement between Louisiana Generating LLC 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 NO_X regulations will total about $10.0 million for Unit 1 and will be undertaken in 2005. Units 2 and 3 have already made such changes.

      In the 1990s, the USEPA commenced an industry-wide investigation of coal-fired electric generators to determine compliance with environmental requirements under the CAA associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. USEPA focused on whether the changes were subject to NSR regulations which require companies to obtain permits before making major modifications to their facilities and if deemed necessary, install control equipment to reduce air emissions. As a result of this ongoing investigation USEPA and several states have filed suits against a number of coal-fired power plants in mid-western and southern states alleging violations of the CAA NSR requirements. The U.S. District Court for the Southern District of Ohio issued a decision in August 2003 finding Ohio Edison Company in violation of the NSR provisions of the CAA. In United States v. Duke Energy Company, however, the U.S. District Court for the Middle District of North Carolina rejected the USEPA’s interpretation, concluding that the exclusion for routine maintenance should be defined relative to what is routine for the particular industry, not what is routine for the particular unit at issue. On October 27, 2003, the USEPA’s NSR rule on routine maintenance was published in the Federal Register. The new regulations, which are not retroactive, would establish an equipment replacement cost threshold of 20% for determining when major NSR requirements are triggered. An appeal opposing the rule was filed with the U.S. Court of Appeals. The effective date of the rule has been delayed pending review. In June 2004, the USEPA filed an appeal with the U.S. Court of Appeals for the Fourth Circuit from the decision in the Duke Energy case which is currently being heard with a ruling expected by summer 2005.

      On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the CAA from USEPA seeking information primarily related to physical changes made at Big Cajun II. Throughout 2004 Louisiana Generating, LLC and Big Cajun II submitted several responses to the USEPA’s follow-up requests. On February 15, 2005, we received a Notice of Violation, or NOV, alleging violations of the NSR provisions of the CAA at Big Cajun 2 Units 1 and 2 from 1998 through the NOV date. Given the preliminary stage of this NOV process, the Company cannot predict the outcome of this matter at this time, but it is actively engaged with USEPA to address these issues.

      West Coast Region. The El Segundo Generating Station is regulated by the South Coast Air Quality Management District, or SCAQMD. Before its retirement as of January 1, 2005, the Long Beach Generating Station was also regulated by SCAQMD. SCAQMD approved amendments to its Regional Clean Air Incentives Market, or RECLAIM, NO_X regulations on January 7, 2005. RECLAIM is a regional emission-trading program targeting NO_X reductions to achieve state and federal ambient air quality standards for ozone. Among other changes, the amendments reduce the NO_X RECLAIM Trading Credit, or RTC, holdings of El Segundo Power, LLC and Long Beach Generation LLC facilities by certain amounts. Notwithstanding these amendments, retained RTCs are expected to be sufficient to operate El Segundo Units 3 and 4 as high as 100% capacity factor.

      Under certain 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 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 hazardous material releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986, or SARA, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault), and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. Although we have been involved in on-site contamination matters, to date, we have not been named as a potentially responsible party with respect to any off-site waste disposal matter.

      Northeast Region. Ash is produced as a by-product of coal combustion at the Dunkirk, Huntley, Indian River and Somerset Generating Stations. The Company 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 the Company and it maintains financial assurance to cover costs associated with landfill closure, post-closure care and monitoring activities. On April 30, 2003, the Company funded a trust in the amount of approximately $5.9 million to provide such financial assurance. The Company is also responsible for the costs associated with closure, post-closure care and monitoring of the ash landfill owned and operated by the Company at the Indian River facility. Financial assurance to provide for closure and post-closure costs at that location is currently maintained by a trust fund collateralized in the amount of approximately $6.7 million. The Company seeks to commence a project to utilize a quarter of its ash production in 2005 for beneficial local use. Additionally, the Company is working with DNREC to modify current landfill slope design to gain significant additional capacity at the existing landfill, thus delaying pending closure and expansion of the landfill. The Company must also maintain financial assurance for closing interim status Resource Conservation and Recovery Act, or RCRA, facilities at the Devon, Middletown, Montville and Norwalk Harbor Generating Stations. On April 30, 2003, the Company funded a trust in the amount of $1.5 million to provide RCRA financial assurance.

      The Company inherited historical clean-up liabilities when it acquired the Somerset, Devon, Middletown, Montville, Norwalk Harbor, Arthur Kill and Astoria Generating Stations. During installation of a sound wall at Somerset Station in 2003, oil contaminated soil was encountered. The Company has delineated the general extent of contamination, determined it to be minimal, and has placed an activity use limitation on that section of the property. Site contamination liabilities arising under the Connecticut Transfer Act at the Devon, Middletown, Montville and Norwalk Harbor Stations have been identified. The Company has proposed a remedial action plan to be implemented over the next two to eight years (depending on the station) to address historical coal ash contamination at the facilities. The total estimated cost of this remedial action plan 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 on the Astoria site to track 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.

      The Company has been put on notice that the prior owner of the Huntley, Dunkirk and Oswego plants is seeking indemnification and defense in connection with several lawsuits alleging liability for damages to persons allegedly exposed to asbestos-containing materials at the plants. The prior owner alleges that the Company is liable by the terms of the Asset Sales Agreements pursuant to which the Company acquired the

plants, which allegations are disputed. To date, the prior owner has not filed suit against the Company with respect to its claim for indemnification with respect to these cases.

      South Central Region. Liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated 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 $5.0 million and the Company is making annual payments to the fund in the amount of approximately $116,000.

      West Coast Region. The Asset Purchase Agreements for the Long Beach, El Segundo, Encina, and San Diego gas turbine generating facilities provide that Southern California Edison, or SCE, and San Diego Gas & Electric, or SDG&E, retain liability, and indemnify the Company, for existing soil and groundwater contamination that exceeds remedial thresholds in place at the time of closing. The Company and its business partner conducted Phase I and Phase II Environmental Site Assessments at each of these sites for purposes of identifying such existing contamination and provided the results to the sellers. SCE and SDG&E have agreed to address contamination identified by these studies and are undertaking corrective action at the Encina and San Diego gas turbine generating sites. Spills and releases of various substances have occurred at these sites since the Company established the historical baseline, all of which have been, or will be, completely remediated. An oil leak in 2002 from underground piping at the El Segundo Generating Station contaminated soils adjacent to and underneath the Unit 1 and 2 powerhouse. The Company excavated and disposed of contaminated soils that could be removed in accordance with existing laws. Following the Company’s formal request, the Los Angeles Regional Water Quality Control Board, or LARWQCB, will allow contaminated soils to remain underneath the building foundation until the building is demolished.

      A diesel fuel spill to on-site surface containment occurred at the Cabrillo Power II LLC Kearny Combustion Turbine facility (San Diego) in February 2003. Emergency response and subsequent remediation activities were completed. Confirmation sampling for the site was completed in 2004 and submitted to the San Diego County Department of Environmental Health. Three San Diego Combustion Turbine facilities, formerly operating pursuant to land leases with the U.S. Navy, are currently being decommissioned with equipment being removed from the sites and remediation activities occurring where necessary. All remedial activities are being completed pursuant to the requirements of the U.S. Navy and the San Diego County Department of Environmental Health. Remediation activities were completed in 2004 at the Naval Training Center and North Island facilities. At the 32nd Street Naval Station facility, additional contamination delineation is necessary and additional unquantified remediation in inaccessible areas may be required in the future.

      Most of the foreign countries in which we own or may acquire or develop independent power projects have environmental and safety laws or regulations relating to the ownership or operation of electric power generation facilities. These laws and regulations, like in the U.S., are constantly evolving, and have a significant impact on international wholesale power producers. In particular, our international power generation facilities will likely be affected by emissions limitations and operational requirements imposed by the Kyoto Protocol, which is an international treaty related to greenhouse gas emissions which entered into force on February 16, 2005, and country-based restrictions pertaining to global climate change concerns.

      We retain appropriate advisors in foreign countries and seek to design our international asset management strategy to comply with each country’s environmental and safety laws and regulations. There can be no assurance that changes in such laws or regulations will not adversely effect our international operations.

      Australia. With respect to Australia, climate change is considered a long-term issue (e.g. 2010 and beyond) and the Australian government’s response to date has included a number of initiatives, all of which have had no impact or minimal impact on the Company’s operations. The Australian government has stated that Australia will achieve its Kyoto Protocol target of 8% below 1990 greenhouse gas emission levels for the 2008 to 2012 reporting period but that Australia will not ratify the Kyoto Protocol. Each Australian state government is considering implementing a number of climate change initiatives that will vary considerably state to state.

      The asset purchase documentation for the NRG Flinders assets in South Australia provides protections to buyer with respect to historical soil and ground water contamination. Although NRG Flinders has some ongoing obligations with respect to historic site contamination management at Augusta Power Station, Clause 5 of the Environment Compliance Agreement between the South Australian Minister for Environment and Heritage and NRG Flinders dated September 20, 2000, referred to as the EC Agreement, removed any obligation for clean-up or remediation of existing contamination.

      While new legislation on contamination is being introduced in South Australia, with particular emphasis on groundwater contamination (regardless of the existing quality of the groundwater), the Company considers it unlikely that any of the proposed amendments will materially negatively impact NRG Flinders’ operations. Specifically, despite the proposed “Soil Contamination Amendments to the Environment Protection Act 1993”, Flinders will not be obligated to take any action to clean up or remediate any historical groundwater contamination caused by disposal of ash as a seawater slurry to the ash ponds by virtue of the EC Agreement (referenced above).

      NRG Flinders disposes of ash to slurry ponds at Port Augusta in South Australia. At the end of life of the power station, NRG Flinders has an obligation to remediate these ponds in accordance with a plan accepted by the South Australian EPA and confirmed in the EC Agreement. The estimated cost of remediation according to the Plan is AUD 1.7 million. There is no timeline associated with the obligation but the EC Agreement extends to 2025. Under these arrangements, required remediation relates to surface remediation and does not entail any groundwater remediation.

      A number of other changes in South Australian legislation are proposed; for example a new Water Quality Policy, which may have some minor implications for the Company’s operations (e.g., especially mine operations). The Company continues to be involved in the legislative stakeholder process and does not expect the proposed amendments to have a materially adverse effect on its assets or operations.

      MIBRAG/ Schkopau, Germany. The Company’s facilities in Germany are likely to be impacted by evolving emissions limitations imposed as a result of the ratification of the Kyoto Protocol. The Company expects that CO₂ emissions trading will begin in Germany in 2005. Allocations of allowances have now been made by the government, but are being challenged by most recipients. Irrespective of the final allocation amounts, the Company does not expect the CO₂ trading program to be a material constraint on its business in Germany. In addition, changes to the German Emission Control Directive will result in lower NO_X emission limits for plants firing conventional fuels (Section 13 of the Directive) and co-firing waste products (Section 17 of the Directive). The new regulations will require the Mumsdorf and Deuben Power stations to install additional controls to reduce NO_X emissions in 2006.

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

      A new law specifically dealing with the relocation of residents of Heuersdorf in the path of the mining plan was enacted by the legislature of Saxony in 2004 and there are numerous potential court challenges still outstanding in this process. We cannot predict the outcome of these actions at this time. MIBRAG continues its political and legal work in an effort to obtain a favorable resolution.

      The supply contracts under which MIBRAG mines lignite from the Profen mine expire on December 31, 2021. The contracts under which MIBRAG mines lignite from the Schleenhain mine expire in 2041. At the end of each mine’s productive lifetime, MIBRAG will be required to reclaim certain areas. MIBRAG accrues for these eventual expenses and estimates the cost of the final reclamation to approach €175 million in the instance of the Schleenhain mine and €132 million for Profen.

      Enfield Energy Centre Limited, United Kingdom. The first phase of Europe’s CO₂ emissions trading scheme, or EU ETS, beginning in 2005, also affects our assets in the U.K. Participants will be required to surrender emissions allowances equal to the amount of CO₂ they have emitted in each year of the scheme. Allowances will be tradable and a market has already developed in this product. For the U.K. it is not yet

possible to quantify the possible effect of this scheme on our operations because final installation level details for the scheme have yet to be released. The second phase of the program will run between 2008 and 2012 and may be extended to cover other GHGs. Additionally, the integrated pollution prevention and control directive, or IPPC, which sets out a framework for the environmental regulation of industrial activities, will be implemented in March 2006. As Enfield Energy Centre is a latest design combined cycle gas turbine, implementing this directive is not expected to require any major changes or expenditures.

Risks Related to NRG Energy, Inc.

      Certain of our facilities, particularly our coal generation assets, are currently benefiting from higher electricity prices in their respective markets as a result of high gas prices compared to historical levels. Gas-fired facilities set the marginal cost of energy in most of our domestic markets. A decrease in gas prices may lead to a corresponding decrease in electricity prices in these markets, which could materially and adversely impact our financial performance.

      Most of our facilities operate as “merchant” facilities without long-term agreements. An oversupply of generating capacity has depressed wholesale power prices in many regions of the country and increased the difficulty of obtaining long-term contracts. Without the benefit of long-term power purchase agreements, we cannot be sure that we will be able to sell any or all of the power generated by our facilities at commercially attractive rates or that our facilities will be able to operate profitably. This could lead to future impairments of our property, plant and equipment or to the closing of certain of our facilities resulting in economic losses and liabilities.

      We sell all or a portion of the energy, capacity and other products from many of our facilities to wholesale power markets, including energy markets operated by independent system operators, or ISOs, or regional transmission organizations, or RTOs. The prices of energy products in those markets are influenced by many factors outside of our control, including fuel prices, transmission constraints, supply and demand, weather, economic conditions and the rules, regulations and actions of the ISOs or RTOs and state and federal regulators. In addition, unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, the wholesale power markets are subject to significant and unpredictable price fluctuations over relatively short periods.

      We have numerous competitors in all aspects of our business, and additional competitors may enter the industry. Our wholesale energy operations compete with other providers of electric energy in the procurement of fuel and transportation services, and the sale of capacity, energy and related products. In order to successfully compete, we seek to aggregate fuel supplies at competitive prices from different sources and locations and to efficiently utilize transportation services from third-party pipelines, railways and other fuel transporters and transmission services from electric utilities.

      We also compete against other energy merchants on the basis of our relative skills, financial position and access to credit sources. Energy customers, wholesale energy suppliers and transporters often seek financial guarantees and other assurances that their energy contracts will be satisfied. As a result, our business is constrained by our liquidity, our access to credit and the reduction in market liquidity. Other companies with which we compete may have greater resources in these areas.

      Other factors may contribute to increased competition in wholesale power markets. The future of the wholesale power generation industry is unpredictable, but may include consolidation within the industry, the

sale, bankruptcy or liquidation of certain competitors, the re-regulation of certain markets or a long-term reduction in new investment into the industry. New capital and competitors have entered the industry in the last three years, including financial investors who perceive that asset values may have bottomed out at levels below their true replacement value. A number of generation facilities in the United States are now in the hands of lenders. Under any scenario, we anticipate that we will continue to face competition from numerous companies in the industry. We anticipate that FERC will continue its efforts to facilitate the competitive energy marketplace throughout the country on several fronts but particularly by encouraging utilities to voluntarily participate in RTOs or ISOs.

      Many companies in the regulated utility industry, with which the wholesale power industry is closely linked, are also restructuring or reviewing their strategies. Several of those companies are discontinuing their unregulated activities, seeking to divest their unregulated subsidiaries or attempting to have their regulated subsidiaries acquire assets out of their or other companies’ unregulated subsidiaries. This may lead to increased competition between the regulated utilities and the unregulated power producers within certain markets.

      In March 2001, certain affiliates of West Coast Power entered into a contract with the California Department of Water Resources, or CDWR, pursuant to which the affiliates agreed to sell up to 2,300 MW from January 1, 2002 through December 31, 2004, any of which may be resold by the CDWR to utilities such as Southern California Edison Company, PG&E Corp. and San Diego Gas and Electric Company. This contract contributed $108.6 million for the year ended December 31, 2004 and $102.6 million for the full year 2003 to our reported equity earnings in West Coast Power, which were decreased by the non-cash impact of fresh start accounting of $115.8 million for the year ended December 31, 2004 and $8.8 million for the period December 6, 2003 through December 31, 2003. West Coast Power made distributions to NRG Energy of $114.2 million for the year ended December 31, 2004 and $122.2 million during calendar year 2003. The contract and the corresponding earnings and cash flow terminated on December 31, 2004. The CDWR contract accounted for a majority of West Coast Power’s revenues during these periods. Beginning January 2005, all of the West Coast Power assets have been negotiated and will operate under reliability must-run, or RMR, agreements. In January 2005, the El Segundo generating facility entered into a tolling arrangement for its entire gross generating capacity of 670 MW commencing May 1, 2005 and extending through December 31, 2005. During the term of this agreement, the purchaser will be entitled to primary energy dispatch rights for the facility’s generating capacity. The agreement is subject to the amendment of the El Segundo RMR agreement to switch to RMR Condition I and to otherwise allow the purchaser to exercise its primary dispatch rights under this agreement while preserving Cal ISO’s ability to call on the El Segundo facility as a reliability resource under the RMR agreement, if necessary.

      Many of our facilities are old. Newer plants owned by our competitors are often more efficient than our aging plants, which may put some of our plants at a competitive disadvantage. Over time, our plants may be squeezed out of their markets, or be unable to compete, because of the construction of new, more efficient plants. Older equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep it operating at optimum efficiency. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability. In addition, if we make any “major modifications” to our power generation facilities, as defined under the new source review provisions of the federal Clean Air Act, we may be required to install “best available control technology” or to achieve the “lowest achievable emissions rate.” Any such modifications would likely result in substantial additional capital expenditures.

      In general, environmental laws and regulations, particularly with respect to air emissions, are becoming more stringent, which may require us to install expensive plant upgrades and/or restrict or modify our operations to meet more stringent standards. An example of this is RGGI, the regional greenhouse gas initiative in the Northeast, discussed previously in the Northeast section under Regional U.S. Regulatory Initiatives. There are many key unknowns with respect to this initiative, including the applicable baseline, initial allocations, required emissions reductions, availability of offsets, the extent to which states will adopt the program, and the timing for implementation. There can be no assurance at this time that a carbon dioxide cap-and-trade program, if implemented by the states in which we operate, would not have a material adverse effect on our operations in this region.

      We cannot predict the level of capital expenditures that will be required due to frequently changing environmental and safety laws and regulations, deteriorating facility conditions and unexpected events (such as natural disasters or terrorist attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on our financial performance and condition. Further, the construction, expansion, modification and refurbishment of power generation facilities involve many risks, including:

      The ongoing operation of our facilities involves all of the risks described above, as well as risks relating to the breakdown or failure of equipment or processes, performance below expected levels of output or efficiency and the inability to transport our product to our customers in an efficient manner due to a lack of transmission capacity. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover our lost revenues, increased expenses or liquidated damages payments should we experience equipment breakdown or non-performance by contractors. Any of these risks could cause us to operate below expected capacity or availability levels, which in turn could result in lost revenues, increased expenses, higher maintenance costs and penalties.

      Most of our domestic natural gas-, coal- and oil-fired power generation facilities purchase their fuel requirements under short-term contracts or on the spot market. Although we attempt to purchase fuel based on our known fuel requirements, we still face the risks of supply interruptions and fuel price volatility as fuel deliveries may not exactly match energy sales due in part to our need to prepurchase fuel inventories for reliability and dispatch requirements. The price we can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel costs. This may have a material adverse effect on our financial performance. Moreover, changes in market prices for natural gas, coal and oil may result from the following:

      The volatility of fuel prices could materially and adversely affect our financial results and operations.

      Our plant operating characteristics and equipment often dictate the specific fuel quality to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, coal of specific quality may not be available at any price, or we may not be able to transport such coal to our facilities on a timely basis. In such case, we may not be able to run a coal facility even if it would be profitable. Operating a coal plant with lesser quality coal can lead to emission problems. If we had contracted the power from the facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of specific plants and on our results of operations.

      We often rely on a single contracted supplier for the provision of transportation of fuel and other services required for the operation of our facilities. If these suppliers cannot perform, we utilize the marketplace to provide these services. At times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility’s output, in some cases under long-term agreements that provide the support for any project debt used to finance the facility. For the year ended December 31, 2004, we derived 49.8% of our revenues from majority-owned operations from four customers: NYISO accounted for 28.5%, ISO New England accounted for 9.1%, National Electricity Market Management Co. Ltd (Australia) accounted for 6.8% and Vattenfall Europe (Germany) accounted for 5.4%. For the period December 6, 2003 through December 31, 2003, we derived 39.0% of our revenues from majority-owned operations from two customers: NYISO accounted for 26.5% and ISO New England accounted for 12.5%. During the period January 1, 2003 through December 5, 2003, we derived 33.4% of our revenues from majority-owned operations from NYISO. During 2002, we derived approximately 26.0% of our revenues from majority-owned operations from NYISO. The failure of any supplier or customer to fulfill its contractual obligations to a facility could have a material adverse effect on such facility’s financial results. Consequently, the financial performance of any such facility is dependent on the credit quality of, and continued performance by, suppliers and customers.

      Our operations are subject to many hazards associated with the power generation industry, which may expose us to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, hazards, such as fire, explosion, collapse and

machinery failure, are inherent risks in our operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. We maintain an amount of insurance protection that we consider adequate, but we cannot assure you that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, we cannot assure you that insurance coverage will continue to be available at all or at rates or on terms similar to those presently available to us.

      We are exposed to market risks through our power marketing business, which involves the sale of energy, capacity and related products and procurement of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from the timing differences associated with buying fuel, converting fuel into energy and delivering the energy to a buyer. We seek to manage this volatility by entering into forward and other contracts that hedge our exposure for our net transactions. The effectiveness of our hedging strategy may be dependent on the amount of collateral available to enter into these hedging contracts, and liquidity requirements may be greater than we anticipate or are able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as cash margin, we may not be able to effectively manage price volatility. Factors which could lead to an increase in our required collateral include volatile commodity prices, adverse changes in our industry, credit rating downgrades and the secured nature of our Amended Credit Facility. Under certain unfavorable commodity price scenarios, it is possible that we could experience inadequate liquidity as a result of the posting of additional collateral.

      Further, if our facilities experience unplanned outages, we may be required to procure replacement power in the open market to minimize our exposure to liquidated damages. Without adequate liquidity to post margin and collateral requirements, we may be exposed to significant losses and may miss significant opportunities, and we may have increased exposure to the volatility of spot markets.

      We engage in commodity-related marketing and price-risk management activities in order to economically hedge our exposure to market risk with respect to (i) electricity sales from our generation assets, (ii) fuel utilized by those assets and (iii) emission allowances. We generally attempt to balance our fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations, through the use of financial and physical derivative contracts. These derivatives are accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires us to record all derivatives on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for hedge accounting treatment. Whether a derivative qualifies for hedge accounting depends upon it meeting specific criteria used to determine if hedge accounting is and will remain appropriate for the term of the derivative. Economic hedges will not necessarily qualify for hedge accounting treatment. As a result, we are unable to predict the impact that our risk management decisions may have on our quarterly operating results or financial position.

      Our facilities and related properties may become subject to decommissioning and/or site remediation obligations that may require material unplanned expenditures or otherwise materially affect the value of those assets. While we meet all site remediation obligations currently applicable to our assets (largely through the provision of various forms of financial assurance. See Item 1 — Environmental Matters — Domestic Site Remediation Matters), more onerous obligations apply to sites where a plant is to be dismantled, which could negatively affect our ability to economically undertake power redevelopments or alternate uses at existing power plant sites. Further, laws and regulations may change to impose material additional decommissioning and remediation obligations on us in the future, negatively impacting the value of our assets and/or our ability to undertake redevelopment projects.

      Our quarterly operating results have fluctuated in the past and will continue to do so in the future as a result of a number of factors, including seasonal variations in demand and corresponding electricity and fuel price volatility and variations in levels of production.

      We have limited control over the operation of some project investments and joint ventures because our investments are in projects where we beneficially own less than a majority of the ownership interests. We seek to exert a degree of influence with respect to the management and operation of projects in which we own less than a majority of the ownership interests by negotiating to obtain positions on management committees or to receive certain limited governance rights such as rights to veto significant actions. However, we may not always succeed in such negotiations. We may be dependent on our co-venturers to operate such projects. Our co-venturers may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these projects optimally. The approval of co-venturers also may be required for us to receive distributions of funds from projects or to transfer our interest in projects.

      We may require additional capital from outside sources from time to time. Our ability to arrange financing, either at the corporate level or on a non-recourse project-level basis, and the costs of such capital are dependent on numerous factors, including:

      We may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital from time to time may have a material adverse effect on our business and operations.

      Our business is subject to extensive foreign, federal, state and local energy, environmental and other laws and regulations. We generally are required to obtain and comply with a wide variety of licenses, permits and other approvals in order to construct, operate or modify our facilities. We may incur significant additional costs because of our need to comply with these requirements. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. We could also be required to shut down any facilities that do not comply with these requirements. In addition, we are at risk for liability for past, current or future contamination at our former and existing facilities or with respect to off-site waste disposal sites that we have used in our operations. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to us or our facilities in a manner that may have a detrimental effect on our business. With the continuing trend toward stricter standards, greater regulation and more extensive permitting requirements, we expect that our environmental expenditures will be substantial in the future.

      Our operations are potentially subject to the provisions of various energy laws and regulations, including the Public Utility Holding Company Act of 1935, or PUHCA, the Federal Power Act or FPA, and state and local utility laws and regulations. Under the FPA, FERC regulates our wholesale sales of electric power (other than sales by our qualifying facilities, which are exempt from FERC rate regulation). The ability to sell energy at market-based rates is predicated on the absence of market power in either generation or transmission, the inability to create barriers to entry and the inability to engage in abusive affiliate transactions and filing of certain reports with FERC. The market power analysis includes not only generation and transmission owned by a particular applicant but also assets owned by affiliated companies. Holders of market-based rate authority must comply with obligations imposed by FERC and with certain FERC filing requirements such as the requirement to file quarterly reports detailing wholesale sales. Although a number of our direct and indirect subsidiaries have obtained market-based rate authority from FERC, these authorizations could be revoked if we fail in the future to satisfy the applicable criteria, if FERC modifies the criteria, or if FERC eliminates or further restricts the ability of wholesale sellers to make sales at market-based rates.

      In addition, under PUHCA, registered holding companies and their subsidiaries (i.e., companies with 10% or more of their voting securities held by registered holding companies) are subject to extensive regulation by the SEC. We will not be considered a holding company or subject to PUHCA as long as we do not become a subsidiary of another registered holding company and the projects in which we have an interest (1) qualify as a qualifying facility, or QF, under the Public Utility Regulatory Policies Act, or PURPA, (2) obtain and maintain exempt wholesale generator, or EWG, status under Section 32 of PUHCA, (3) obtain and maintain foreign utility company, or FUCO, status under Section 33 of PUHCA, or (4) are subject to another exemption or waiver. If our projects were to cease to be exempt and we were to become subject to SEC and FERC regulation under PUHCA, it would be difficult for us to comply with PUHCA absent a substantial corporate restructuring.

      We face regulatory risk imposed by the various transmission providers, ISOs and RTOs and their corresponding market rules. These market rules are subject to revisions, and such revisions may not benefit us. Transmission providers, ISOs and RTOs have FERC-approved tariffs that govern access to their transmission system. These tariffs may contain provisions that limit access to the transmission grid or allocate scarce transmission capacity in a particular manner.

      We presently operate in the following ISO or RTO markets: California (through the West Coast Power joint venture and individually), New England, New York and PJM (the Pennsylvania, Jersey, Maryland Interconnection). The chief regulatory risk is the lack of, or uncertainty regarding, market mechanisms that effectively compensate generating units for providing reliability services and installed capacity.

      We are dependent on access to transmission systems to sell our energy. In the northeastern ISO and RTO markets, we have a significant amount of generation located in load pockets. Expansion of the transmission system to reduce or eliminate these load pockets could negatively impact our existing facilities in these areas.

      Our facilities located in the Entergy franchise territory face a different transmission risk, in that restrictions on transmission access may limit our ability to sell energy or to service new customers.

      The nature of our business frequently subjects us to litigation. Many of the largest claims against us prior to the date of the bankruptcy filing were satisfied and discharged in accordance with the terms of the NRG plan of reorganization or the plan of reorganization for certain subsidiaries or in connection with settlement agreements that were approved by the bankruptcy court prior to our emergence from bankruptcy. Circumstances in which pre-bankruptcy filing claims have not been discharged include, among others, where we have agreed with a given claimant to preserve their claims, as well as, potentially, instances where a claimant had no notice of the bankruptcy filing. The ultimate resolution of certain remaining or future claims may have a material adverse effect on our results of operations and profitability. In addition, claims made against subsidiaries that did not file for chapter 11, and claims arising after the date of our bankruptcy filing, were not discharged in the bankruptcy cases. See Item 15 — Note 27 to the Consolidated Financial Statements included in our Annual Report on Form 10-K for the Year ended December 31, 2004, for a description of the significant legal proceedings and investigations in which we are presently involved.

      Under the NRG plan of reorganization, we have established disputed claims reserves, which we will utilize to make distributions to holders of disputed claims in our bankruptcy cases as and when their claims are resolved. If these reserves prove inadequate, we will be required to finance any further cash distributions from other resources, and doing so could have a material adverse impact on our financial condition, and, in addition, we could be required to issue new common stock, which would dilute existing shareholders. In particular, the State of California’s disputed claims against us are capped at $1.35 billion. There are also a number of private claims springing from the California energy crisis for which there is no cap. We have made no reserves for these claims, because we believe they are without merit; however, if the State of California or these private litigants prevail, then payment of the distributions to which the State of California or these private litigants would be entitled under the NRG plan of reorganization could have a material adverse impact on our financial condition.

      Our generation facilities and the facilities of third parties on which they rely may be targets of terrorist activities, as well as events occurring in response to or in connection with them, that could cause environmental repercussions and/or result in full or partial disruption of their ability to generate, transmit, transport or distribute electricity or natural gas. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. Any such environmental repercussions or disruption could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows.

      We have investments in power projects in Australia, the United Kingdom, Germany and Brazil. International investments are subject to risks and uncertainties relating to the political, social and economic

structures of the countries in which we invest. Risks specifically related to our investments in international projects may include:

Cautionary Statement Regarding Forward Looking Information

      This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The words “believes,” “projects,” “anticipates,” “plans,” “expects,” “intends,” “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause our actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statement. These factors, risks and uncertainties include, but are not limited to, the factors described under “Risks Related to NRG Energy, Inc.” in this Item 1 and to the following:

      Forward-looking statements speak only as of the date they were made, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause our actual results to differ materially from those

contemplated in any forward-looking statements included in this Annual Report on Form 10-K should not be construed as exhaustive.

Item 2 — Properties

      Listed below are descriptions of our interests in facilities, operations and/or projects owned as of December 31, 2004.

Independent Power Production and Cogeneration Facilities

Thermal Energy Production and Transmission Facilities and Resource Recovery Facilities

Other Properties

      In addition to the above, we lease our corporate offices at 211 Carnegie Center, Princeton, New Jersey 08540 and various other office spaces. We also own interests in other construction projects in various states of completion, as well as other properties not used for operational purposes.

California Wholesale Electricity Litigation and Related Investigations

      People of the State of California ex. rel. Bill Lockyer, Attorney General, v. Dynegy, Inc. et al., U.S. District Court, Northern District of California, Case No. C-02-O1854 VRW; U.S. Court of Appeals for the Ninth Circuit, Case No. 02-16619. This action was filed in state court on March 11, 2002, against us, Dynegy, Dynegy Power Marketing, Inc., Xcel Energy, West Coast Power, or WCP, and WCP’s four operating subsidiaries. Through our subsidiary, NRG West Coast LLC, we are a 50 percent beneficial owner with Dynegy of West Coast Power, which owns, operates, and markets the power of four California plants. Dynegy and its affiliates and subsidiaries are responsible for gas procurement and marketing and trading activities on behalf of West Coast Power. The complaint alleges that the defendants violated state unfair competition law by selling ancillary services to the state independent system operator, and subsequently selling the same capacity into the spot market. It seeks injunctive relief as well as restitution, disgorgement and unspecified civil penalties. On April 17, 2002, the defendants removed the case to the U.S. District Court for the Northern District of California in San Francisco. In a March 25, 2003, opinion, the court dismissed the Attorney General’s action against Dynegy and us with prejudice, finding it was barred by the filed-rate doctrine and preempted by federal law. On July 6, 2004, the U.S. Court of Appeals for the Ninth Circuit rejected the Attorney General’s appeal. Rehearing was sought and rejected on October 29, 2004. On January 27, 2005, the Attorney General filed a petition for writ of certiorari to the U.S. Supreme Court.

      Public Utility District of Snohomish County v. Dynegy Power Marketing, Inc et al., Case No. 02-CV-1993 RHW, U.S. District Court, Southern District of California (part of MDL 1405). This action was filed against us, Dynegy, Xcel Energy and several other market participants on July 15, 2002. The complaint alleges violations of state anti-trust and unfair competition laws by means of price fixing, restriction of supply, and other market “gaming” activities. After the action was transferred to the U.S. District Court for the Southern District of California in San Diego and made a part of the Multi-District Litigation, or MDL, proceeding described below, it was dismissed on the grounds of federal preemption and filed-rate doctrine. The plaintiffs filed a notice of appeal and on September 10, 2004, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court’s dismissal on the same legal grounds. On November 5, 2004, the plaintiff filed a petition for writ of certiorari to the U.S. Supreme Court and on February 22, 2005, the Supreme Court issued an order requesting the views of the U.S. Solicitor General on the petition.

      In re: Wholesale Electricity Antitrust Litigation, MDL 1405, U.S. District Court, Southern District of California. The cases included in this proceeding are as follows:

      NRG Energy is a defendant in all of the above referenced cases. Several of WCP’s operating subsidiaries are also defendants in the Bustamante case. The cases allege unfair competition, market manipulation and price fixing and all seek treble damages, restitution and injunctive relief. In December 2002, the U.S. District Court for the Southern District of California issued an opinion finding that federal jurisdiction was absent in the district court, and remanding the cases back to state court. A notice of appeal was filed and on December 8, 2004, the U.S. Court of Appeals for the Ninth Circuit issued its published, unanimous decision affirming the District Court in most respects. On March 5, 2005, the Ninth Circuit denied a petition for rehearing. We anticipate that the cases will be remanded to state court in 2005 at which time the defendants will again raise filed-rate and federal preemption challenges.

      “Northern California” cases against various market participants. T&E Pastorino v. Duke Energy, et al., Case No. 02-CV-2176; RDJ Farms v. Allegheny Energy, et al., Case No. 02-2059; Century Theatres v. Allegheny Energy, et al., Case No. 02-CV-2177; Bronco Don v. Duke Energy, Case No. 02-CV-2178; El Super Burrito v. Allegheny Energy, et al., Case No. 02-CV-2180; Leo’s Day & Night Pharmacy, Case No. 02-CV-2181; J&M Karsant V. Duke Energy, Case No. 02-CV-2182. (Part of MDL 1405). We were not named in any of these cases, but in all of them, either WCP or one or more of its operating subsidiaries as well as Dynegy are named as defendants. These cases all allege violations of state unfair competition law. Dynegy’s counsel is representing both Dynegy and the WCP subsidiaries in these cases with each side responsible for half of the defense costs. These cases all were removed to federal court and denied remand to state court. In late August 2003, the defendants’ motions to dismiss were granted in these various cases. On February 25, 2005, the U.S. Court of Appeals for the Ninth Circuit approved the district court decision to dismiss the case.

      Bustamante v. McGraw-Hill Companies, Inc., et al., No. BC 235598, California Superior Court, Los Angeles County (filed November 20, 2002, and amended in 2003). This putative class action alleges that the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades. Named defendants in the suit include several of WCP’s operating subsidiaries. Dynegy is defending the WCP subsidiaries pursuant to a limited indemnification agreement. The complaint seeks restitution and disgorgement, civil fines, compensatory and punitive damages, attorneys’ fees and declaratory and injunctive relief. Defendant’s motion for summary judgment is pending.

      Jerry Egger, et al. v. Dynegy, Inc., et al., Case No. 809822, Superior Court of California, San Diego County (filed May 1, 2003). This putative class action alleges violations of California’s antitrust law, as well as unlawful and unfair business practices and seeks treble damages, restitution and injunctive relief. The named defendants include WCP and several of its operating subsidiaries. NRG Energy is not named. This case was removed to the U.S. District Court for the Northern District of California, and the defendants have moved to have this case included as Multi-District Litigation along with the above referenced cases. Plaintiffs argued a motion to remand to state court on February 19, 2004, at which time the court stayed the case pending a

decision from the U.S. Court of Appeals for the Ninth Circuit in the Pastorino appeal, referenced above. Dynegy’s counsel is representing Dynegy and WCP and its subsidiaries in this case with each side responsible for half of the defense costs. With the Ninth Circuit’s February 25, 2005, decision in the Northern California cases referenced above, a decision on the stay in this case is expected this year.

      Texas-Ohio Energy, Inc., on behalf of Itself and all others similarly situated v. Dynegy, Inc. Holding Co., West Coast Power, LLC, et al., Case No. CIV.S-03-2346 DFL GGH, U.S. District Court, Eastern District of California (filed November 10, 2003). This putative class action alleges violations of the federal Sherman and Clayton Acts and state antitrust law. In addition to naming WCP and Dynegy, Inc. Holding Co., the complaint names numerous industry participants, as well as “unnamed co-conspirators.” The complaint alleges that defendants conspired to manipulate the spot price and basis differential of natural gas with respect to the California market. The complaint seeks unspecified amounts of damages, including a trebling of plaintiff’s and the putative class’s actual damages. Dynegy is defending WCP pursuant to a limited indemnification agreement.

      City of Tacoma, Department of Public Utilities, Light Division, v. American Electric Power Service Corporation, et al., U.S. District Court, Western District of Washington, Case No. C04-5325 RBL (filed June 16, 2004). The complaint names over 50 defendants, including WCP’s four operating subsidiaries and various Dynegy entities. The complaint also names both us and WCP as “Non-Defendant Co-Conspirators.” Plaintiff alleges a conspiracy to violate the federal Sherman Act by withholding power generation from, and/or inflating the apparent demand for power in markets in California and elsewhere. Plaintiff claims damages in excess of $175 million. Dynegy is defending WCP and its subsidiaries pursuant to a limited indemnification agreement.

      Fairhaven Power Company v. Encana Corporation, et al., Case No. CIV-F-04-6256 (OWW/ LJO), U.S. District Court, Eastern District of California (filed September 22, 2004), Abelman v. Encana, U.S. District Court, Eastern District of California, Case No. 04-CV-6684 (filed December 13, 2004); Utility Savings v. Reliant, et al., U.S. District Court, Eastern District of California, (filed November 29, 2004). These putative class actions name WCP and Dynegy Holding Co., Inc. among the numerous defendants. The Complaints allege violations of the federal Sherman Act, and California’s antitrust and unfair competition law as well as unjust enrichment. The Complaints seek a determination of class action status, a trebling of unspecified damages, statutory, punitive or exemplary damages, restitution, disgorgement, injunctive relief, a constructive trust, and costs and attorneys’ fees. Dynegy is defending WCP pursuant to a limited indemnification agreement.

      In Re: Natural Gas Commodity Litigation, Master File No. 03 CV 6186(VM)(AJP), U.S. District Court, Southern District of New York. West Coast Power, or WCP, and Dynegy Marketing and Trade are among numerous defendants accused of manipulating gas index publications and prices in violation of the federal Commodity Exchange Act, or CEA, in the following consolidated cases: Cornerstone Propane Partners, LP v. Reliant Energy Services, Inc., et al., Case No. 03 CV 6186 (S.D.N.Y. filed August 18, 2003); Calle Gracey v. American Electric Power Co., Inc., et al., Case No. 03 CV 7750 (S.D.N.Y. filed Oct. 1, 2003); Cornerstone Propane Partners, LP v. Coral Energy Resources, LP, et al., Case No. 03 CV 8320 (S.D.N.Y. filed Oct. 21, 2003); and Viola v. Reliant Energy Servs., et al., Case No. 03 CV 9039 (S.D.N.Y. filed Nov. 14, 2003). Plaintiffs, in their Amended Consolidated Class Action Complaint dated October 14, 2004, allege that the defendants engaged in a scheme to manipulate and inflate natural gas prices. The plaintiffs seek class action status for their lawsuit, unspecified actual damages for violations of the CEA and costs and attorneys’ fees. Dynegy Marketing and Trade is defending WCP in these proceedings pursuant to a limited indemnification agreement.

      ABAG Publicly Owned Energy Resources v. Sempra Energy, et al., Alameda County Superior Court, Case No. RG04186098, filed November 10, 2004; Cruz Bustamante v. Williams Energy Services, et al., Los Angeles Superior Court, Case No. BC285598, filed June 28, 2004; City & County of San Francisco, et al. v. Sempra Energy, et al., San Diego County Superior Court, Case No. GIC832539, filed June 8, 2004; City of San Diego v. Sempra Energy, et al., San Diego County Superior Court, Case No. GIC839407, filed December 1, 2004; County of Alameda v. Sempra Energy, Alameda County Superior Court, Case

No. RG041282878, filed October 29, 2004; County of San Diego v. Sempra Energy, et al., San Diego County Superior Court, Case No. GIC833371, filed July 28, 2004; County of San Mateo v. Sempra Energy, et al., San Mateo County Superior Court, Case No. CIV443882, filed December 23, 2004; County of Santa Clara v. Sempra Energy, et al., San Diego County Superior Court, Case No. GIC832538, filed July 8, 2004; Nurserymen’s Exchange, Inc. v. Sempra Energy, et al., San Mateo County Superior Court, Case No. CIV442605, filed October 21, 2004; Older v. Sempra Energy, et al., San Diego Superior Court, Case No. GIC835457, filed December 8, 2004; Owens-Brockway Glass Container, Inc. v. Sempra Energy, et al., Alameda County Superior Court, Case No. RG0412046, filed December 30, 2004; Sacramento Municipal Utility District v. Reliant Energy Services, Inc., Sacramento County Superior Court, Case No. 04AS04689, filed November 19, 2004; School Project for Utility Rate Reduction v. Sempra Energy, et al., Alameda County Superior Court, Case No. RG04180958, filed October 19, 2004; Tamco, et al. v. Dynegy, Inc., et al., San Diego County Superior Court, Case No. GIC840587, filed December 29, 2004; Utility Savings & Refund Services, LLP v. Reliant Energy Services, Inc., et al., U.S. District Court, Eastern District of California, Case No. 04-6626, filed November 30, 2004.

      The defendants in all of the above referenced cases include WCP and various Dynegy entities. NRG Energy is not a defendant. The Complaints allege that defendants attempted to manipulate natural gas prices in California, and allege violations of California’s antitrust law, conspiracy, and unjust enrichment. The relief sought in all of these cases includes treble damages, restitution and injunctive relief. The Complaints assert that WCP is a joint venture between Dynegy and NRG Energy, but that Dynegy Marketing and Trade handled all of the administrative services and commodity related concerns of WCP. The cases are presently being consolidated for coordinated pretrial proceedings in San Diego County Superior Court. Dynegy is defending WCP pursuant to a limited indemnification agreement.

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

      The FERC conducted an “Investigation of Potential Manipulation of Electric and Natural Gas Prices,” which involved hundreds of parties, including our affiliate, West Coast Power, or WCP, and substantial discovery. In June 2001, FERC initiated proceedings related to California’s demand for $8.9 billion in refunds from power sellers who allegedly inflated wholesale prices during the energy crisis. After two administrative law judge opinions and a March 26, 2003, FERC Order adopting in part and modifying in part the last of the two opinions, Dynegy, we and the WCP entities engaged in extensive settlement negotiations with FERC Staff; the People of the State of California ex rel. Bill Lockyer, Attorney General; the California Public Utility Commission, or CPUC staff; the California Department of Water Resources acting through its Electric Power Fund, the California Electricity Oversight Board; PG&E; Southern California Edison Company; and San Diego Gas and Electric Company. The parties entered into a definitive, comprehensive settlement, which FERC approved on October 25, 2004, (the FERC Settlement).

      As part of the FERC Settlement, WCP placed into escrow for distribution to California energy consumers a total of $22.5 million, which includes the $3 million settlement with FERC respecting trading techniques, announced on January 20, 2004. In addition, WCP agreed to forego: (1) past due receivables from the California Independent System Operator and the California Power Exchange related to the settlement period; and (2) natural gas cost recovery claims against the settling parties related to the settlement period. In

exchange, the various California settling parties agreed to forego: (1) all claims relating to refunds or other monetary damages for sales of electricity during the settlement period; (2) claims alleging that WCP received unjust or unreasonable rates for the sale of electricity during the settlement period; and (3) FERC dismissed numerous investigations respecting market transactions. For a two year period following FERC’s acceptance of the settlement agreement, WCP will retain an independent engineering company to perform semi-annual audits of the technical and economic basis, justification and rationale for outages that occurred at its California generating plants during the previous six month period, and to have the results of such audits provided to the FERC Office of Market Oversight and Investigation without any prior review by WCP.

      WCP previously established significant reserves on its balance sheet and will not incur any further loss associated with the FERC Settlement. We will pay no cash from corporate funds, nor will the FERC Settlement have any direct impact on our profit and loss statement.

      There are a number of additional, related proceedings in which WCP subsidiaries are parties, which are either pending before FERC or on appeal from FERC to various U.S. Courts of Appeal. These cases involve, among other things, allegations of physical withholding, a FERC-established price mitigation plan determining maximum rates for wholesale power transactions in certain spot markets, and the enforceability of, and obligations under, various contracts with, among others, the California Independent System Operator and the State of California and certain of its agencies and departments.

      The California Attorney General has undertaken an investigation entitled “In the Matter of the Investigation of Possibly Unlawful, Unfair, or Anti-Competitive Behavior Affecting Electricity Prices in California.” In this connection, the Attorney General has issued subpoenas to Dynegy, served interrogatories on Dynegy and us, and informally requested documents and conducted interviews with Dynegy and Dynegy employees as well as us and our employees. We responded to the interrogatories in the summer of 2002, and again on September 3, 2002. We have also produced a large volume of documentation relating to the West Coast Power subsidiaries.

      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 December 3, 2004, the Company filed a brief opposing the ECRC request.

      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 New York Independent System Operator, or NYISO, operating reserve markets for the period 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 NYISO was correct not to use its TEP authority to revise the prices in this market. Motions for rehearing of the Order must be filed by April 3, 2005. If the March 4, 2005 order is reversed and refunds are required, NRG entities which may be affected include NRG Power Marketing, Inc., Astoria Gas Turbine Power LLC and Arthur Kill Power LLC.

Although non-NRG-related entities would share responsibility for payment of any such refunds under the petitioners’ theory the cumulative exposure to our above-listed entities could exceed $23 million.

      Connecticut 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.

      Connecticut Light & Power Company 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 & Power Company, or CL&P, and the Company agreed that we 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 delivery 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.

      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 State Department of Environmental Conservation, or NYSDEC, sued Niagara Mohawk Power Corporation, or NiMo, and us in federal court in New York. The complaint asserted that projects undertaken at our 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, we reached agreement with the State of New York and the NYSDEC 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. We also agreed to limits on the transfer of certain federal SO₂ allowances. We are not subject to any penalty as a result of the settlement. Through the end of the decade, we expect that our ongoing compliance with the emissions limits set out in the settlement will be achieved through capital expenditures already planned. This includes conversion to low sulfur western coal at the Huntley and Dunkirk plants that will be completed by spring 2006.

      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 us under the asset sales agreement. We asserted that NiMo is obligated to indemnify us 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.

      Niagara Mohawk Power Corporation v. Dunkirk Power LLC, NRG Dunkirk Operations, Inc., Huntley Power LLC, NRG Huntley 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 we 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 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 the 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. NiMo filed a motion for rehearing, on which FERC has not ruled.

      U.S. Environmental Protection Agency Request for Information under Section 114 of the Clean Air Act. On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request under Section 114 of the federal Clean Air Act from U.S. EPA Region 6 seeking information primarily relating to physical changes made at Big Cajun II. Louisiana Generating, LLC and Big Cajun II submitted several responses to the EPA. On February 15, 2005, Louisiana Generating, LLC received a Notice of Violation alleging violations of the New Source Review provisions of the Clean Air Act from 1998 through the Notice of Violation date. We cannot predict the outcome of this matter at this time.

      Itiquira Energetica, S.A. Our Brazilian project company, Itiquira Energetica S.A., the owner of a 156 MW hydro project in Brazil, is in arbitration with the former EPC contractor for the project, Inepar Industria e Construcoes, or “Inepar.” The dispute was commenced by Itiquira in September of 2002 and pertains to certain matters arising under the former EPC contract. Itiquira seeks U.S. $40 million and asserts that Inepar breached the contract and caused damages to Itiquira by (i) failing to meet milestones for substantial completion; (ii) failing to provide adequate resources to meet such milestones; (iii) failing to pay subcontractors amounts due; and (iv) being insolvent. Inepar seeks U.S. $10 million and alleges that Itiquira breached the contract and caused damages to Inepar by failing to recognize events of force majeure as grounds for excused delay and extensions of scope of services and material under the contract. An expert investigation was ordered by an arbitration panel to cover technical and accounting issues and expert testimony was presented at two subsequent hearings. Final written arguments from the parties were submitted on January 28, 2005. The court of arbitration is expected to issue a decision by the close of the second quarter of 2005.

      CFTC Trading Inquiry. On July 1, 2004, the CFTC filed a civil complaint against us in Minnesota federal district court, alleging false reporting of natural gas trades from August 2001 to May 2002, and seeking an injunction against future violations of the Commodity Exchange Act. On July 23, 2004, we filed a motion with the bankruptcy court to enforce the injunction provisions of the NRG plan of reorganization against the CFTC. Thereafter, we filed with the Minnesota federal district court a motion to dismiss. On November 17, 2004, a Bankruptcy Court hearing was held on the CFTC’s motion to reinstate its expunged bankruptcy claim, and on our motion to enforce the injunction contained in our plan of reorganization in order to preclude the CFTC from continuing its Minnesota federal court action. On December 6, 2004, a federal magistrate judge in Minnesota issued a report and recommendation that our motion to dismiss be granted by the district court. On March 16, 2005, the federal district court in Minnesota adopted the magistrate judge’s report and

recommendations and dismissed the case. The Bankruptcy Court has yet to schedule for a hearing or rule on the CFTC’s pending motion to reinstate its expunged claim.

      In addition to the foregoing, we are parties to other litigation or legal proceedings. See “Market Developments” in the various regions in Item 1 — Business — Power Generation for additional discussion on regulatory legal proceedings.

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

Disputed Claims Reserve

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

      No matters were considered during the fourth quarter of 2004.

PART II

Market Information and Holders

      In connection with the consummation of our reorganization, on December 5, 2003, all shares of our old common stock were canceled and 100,000,000 shares of new common stock of NRG Energy were distributed pursuant to such plan in accordance with Section 1145 of the bankruptcy code to the holders of certain classes of claims. We received no proceeds from such issuance. A certain number of shares of common stock were

issued and placed in the Disputed Claims Reserve for distribution to holders of disputed claims as such claims are resolved or settled. See Item 3 — Legal Proceedings — Disputed Claims Reserve. In the event our disputed claims reserve is inadequate, it is possible we will have to issue additional shares of our common stock to satisfy such pre-petition claims or contribute additional cash proceeds. Our authorized capital stock consists of 500,000,000 shares of NRG Energy common stock and 10,000,000 shares of preferred stock. A total of 4,000,000 shares of our common stock are available for issuance under our long-term incentive plan. We have also filed with the Secretary of State of Delaware a Certificate of Designation of our 4% Convertible Perpetual Preferred Stock, or Preferred Stock.

      Our common stock is listed on the New York Stock Exchange and has been assigned the symbol: NRG. We have submitted to the New York Stock Exchange our annual certificate from our Chief Executive Officer certifying that he is not aware of any violation by us of New York Stock Exchange corporate governance listing standards. The high and low sales prices, as well as the closing price for our common stock on a per share basis for 2004 and the period December 6, 2003 to December 31, 2003 are set forth below:

      NRG Energy had 87,041,935 shares outstanding as of December 31, 2004. As of March 10, 2005, there were 11,182 common shareholders of record.

Dividends

      We have not declared or paid dividends on our common stock and the amount of dividends is currently limited by our credit agreements.

Recent Sale of Unregistered Securities; Repurchase of Common Stock

      Upon emergence from chapter 11, investment partnerships managed by MatlinPatterson LLC, or MatlinPatterson, owned approximately 21.5 million (21.5%) of our common shares. On December 21, 2004, using existing cash we purchased 13 million shares of common stock from MatlinPatterson at a purchase price of $31.16 per share. In addition to a reduction in total shares of common stock outstanding by 13 million, the share repurchase resulted in (i) the reduction of MatlinPatterson’s share ownership to less than 10% from the prior 21.5%, (ii) termination of MatlinPatterson’s registration rights, and (iii) resignation from our Board of Directors of three directors affiliated with MatlinPatterson. Our Board’s Governance and Nominating Committee is in the process of identifying appropriate independent directors to fill the vacancies.

      The following table summarizes the stock repurchased by NRG Energy.

Redemption and Repurchase of Second Priority Notes

      Proceeds from the sale of the Preferred Stock were used to redeem $375.0 million of our Second Priority Notes on February 4, 2005. In January 2005 and in March 2005, we used existing cash to purchase, at market prices, $25 million and $15.8 million, respectively, in face value of our Second Priority Notes. These notes were assumed by NRG Energy and therefore remain outstanding.

Securities Authorized for Issuance Under Equity Compensation Plans

      The following table presents our selected financial data. The data included in the following table has been restated to reflect the assets, liabilities and results of operations of certain projects that have met the criteria for treatment as discontinued operations. For additional information refer to Item 15 — Note 6 to the Consolidated Financial Statements. This historical data should be read in conjunction with the Consolidated Financial Statements and the related notes thereto in Item 15 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7. Due to the adoption of Fresh Start reporting as of December 5, 2003, the Successor Company’s post Fresh Start balance sheet and statement of operations have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of Fresh Start reporting.

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

      Energy and energy-related revenue consists of revenues received from third parties for sales in the day-ahead and real-time markets, as well as bilateral sales. In addition, this category includes day-ahead and real-time operating revenues.

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

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

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

      Other revenues consist of miscellaneous other revenues derived from the sale of natural gas, recovery of incurred costs under reliability agreements and revenues received under leasing arrangements. In addition, we also generate revenues from maintenance, the sale of ancillary services excluding day-ahead and real-time operating revenues and by entering into certain financial transactions. Ancillary revenues are derived from the sale of energy related products associated with the generation of electrical energy such as spinning reserves, reactive power and other similar products. Also included in other revenues are revenues derived from financial transactions (derivatives) relating to the sale of energy or fuel which do not require the physical delivery of the underlying commodity.

Overview

      NRG Energy, Inc., or “NRG Energy”, the “Company”, “we”, “our”, or “us” is a wholesale power generation company, primarily engaged in the ownership and operation of power generation facilities, the transacting in and trading of fuel and transportation services and the marketing and trading of energy, capacity and related products in the United States and internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type and dispatch levels. Our principal domestic generation assets consist of a diversified mix of natural gas-, coal- and oil-fired facilities, representing approximately 40%, 31% and 29% of our total domestic generation capacity, respectively. In addition, 23% of our domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option.

      Our two principal objectives are to maximize the operating performance of our entire portfolio, and to protect and enhance the market value of our physical and contractual assets through the execution of asset-based risk management, marketing and trading strategies within well-defined risk and liquidity guidelines. We aggregate the assets in our core regions into integrated businesses to serve the requirements of the load-serving entities in our core markets. Our business involves the reinvestment of capital in our existing assets for reasons of repowering, expansion, environmental remediation, operating efficiency, reliability programs, greater fuel optionality, greater merit order diversity, enhanced portfolio effect or for alternative use, among other reasons. Our business also may involve acquisitions intended to complement the asset portfolios in our core regions, and from time to time we may also consider and undertake other merger and acquisition transactions that are consistent with our strategy.

      The wholesale energy industry entered a prolonged slump in 2001, from which it is only beginning to emerge. We expect that generally weak market conditions will continue for the foreseeable future in many U.S. markets. We further expect that the merchant power industry will continue to see corporate restructuring, debt restructuring, and consolidation over the coming years.

      Asset Sales. We have substantially completed our divestment of major non-core assets; however, as part of our strategy, we plan to continue the selective divestment of certain non-core assets. We have no current plans to market actively any of our core assets, although our intention to maximize over time the value of all of our assets could lead to additional assets sales.

      Discontinued Operations. We have classified certain business operations, and gains/losses recognized on sale, as discontinued operations for projects that were sold or have met the required criteria for such classification pending final disposition. Accounting regulations require that continuing operations be reported separately in the income statement from discontinued operations, and that any gain or loss on the disposition of any such business be reported along with the operating results of such business. Assets classified as discontinued operations on our balance sheet as of December 31, 2004 consist of the McClain project. All other projects have been sold as of December 31, 2004.

      Independent Registered Public Accounting Firm; Audit Committee. PricewaterhouseCoopers LLP served as our independent auditors from 1995 through 2003. On May 3, 2004, we announced that PricewaterhouseCoopers LLP had decided not to stand for re-election as our independent auditor for the year ended December 31, 2004. On May 24, 2004 the Audit Committee of our Board of Directors appointed KPMG LLP as our independent registered public accounting firm going forward, and on August 4, 2004 our stockholders ratified the appointment. PricewaterhouseCoopers LLP has consented to the inclusion of their reports for the periods January 1, 2003 to December 5, 2003 and December 6, 2003 to December 31, 2003 and for the year ended December 31, 2002. The Company intends to continue to request the consent of PricewaterhouseCoopers LLP in future filings with the SEC when deemed necessary.

      Fresh Start Reporting. In connection with our emergence from bankruptcy, we adopted Fresh Start Reporting on December 5, 2003, in accordance with the requirements of Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”, or SOP 90-7. The application of SOP 90-7 resulted in the creation of a new reporting entity. Under Fresh Start, our reorganization value was allocated to our assets and liabilities on a basis substantially consistent with purchase accounting in accordance with SFAS No. 141. Accordingly, our assets’ recorded values were adjusted to reflect their estimated fair values upon adoption of Fresh Start. Any portion of the reorganization value not attributable to specific assets is an indefinite-lived intangible asset referred to as “reorganization value in excess of value of identifiable assets” and reported as goodwill. We did not record any such amounts. As a result of adopting Fresh Start and emerging from bankruptcy, our historical financial information is not comparable to financial information for periods after our emergence from bankruptcy.

Results of Operations

      Upon our emergence from bankruptcy, we adopted the Fresh Start provisions of SOP 90-7. Accordingly, the Reorganized NRG statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of Fresh Start, therefore, the Predecessor Company’s and the Reorganized NRG’s amounts are discussed separately for comparison and analysis purposes, herein.

      The following table shows the percent of total revenue each segment contributes to our total revenue: