General

      NRG Energy, Inc., or “NRG Energy”, “we”, “our”, or “us” is a wholesale power generation company, primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States and internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type, and dispatch levels. We seek to maximize operating income through the efficient procurement and management of fuel supplies and maintenance services, and the sale of energy, capacity and ancillary services into attractive spot, intermediate and long-term markets.

      We were formed in 1992 as the non-regulated subsidiary of Northern States Power, or “NSP”, which was itself merged into New Century Energies, Inc. to form Xcel Energy, Inc., or “Xcel Energy” in 2000. While owned by NSP and later by Xcel Energy, we consistently 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 credit rating downgrade (below investment grade) which, in turn, precipitated a severe liquidity situation. On May 14, 2003, we and 25 of our direct and indirect wholly owned subsidiaries commenced voluntary petitions under chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. On November 24, 2003, the bankruptcy court entered an order confirming our plan of reorganization and the plan became effective on December 5, 2003.

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

      As of December 31, 2003, we owned interests in 72 power projects in seven countries having an aggregate generation capacity of approximately 18,200 megawatts, or “MW.” Approximately 7,900 MW of our capacity consists of merchant power plants in the Northeast region of the United States. Certain of these assets are located in transmission constrained areas, including approximately 1,400 MW of “in-city” New York City generation capacity and approximately 750 MW of southwest Connecticut generation capacity. We also own approximately 2,500 MW of capacity in the South Central region of the United States, with approximately 1,700 MW of that capacity supported by long-term power purchase agreements. Our assets in the West Coast region of the United States consist of approximately 1,300 MW of capacity with the majority of such capacity owned via our 50% interest in West Coast Power, LLC, or “West Coast Power.” Our assets in the West Coast region are supported by a power purchase agreement with the California Department of Water Resources that runs through December 2004. Our principal domestic generation assets consist of a diversified mix of natural gas-, coal- and oil-fired facilities, representing approximately 48%, 26% and 26% of our total domestic generation capacity, respectively. We also own interests in plants having a generation capacity of approximately 3,000 MW in various international markets, including Australia, Europe and Latin America. Our energy marketing subsidiary, NRG Power Marketing, Inc., or “PMI,” began operations in 1998 and is focused on maximizing the value of our North American assets by providing centralized contract origination and management services, and through the efficient procurement and management of fuel and the sale of energy and related products in the spot, intermediate and long-term markets.

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      We were incorporated as a Delaware corporation on May 29, 1992. Our headquarters and principal executive offices are located at 901 Marquette Avenue, Suite 2300, Minneapolis, Minnesota, 55402. Our telephone number is (612) 373-5300. Our Internet website is http://www.nrgenergy.com. Our recent annual reports, quarterly reports, current reports and other periodic filings are available free of charge through our Internet website. The charters of our audit, compensation and nominating committee are also available on our website at http://www.nrgenergy.com/investors/corpgov.htm. These charters are available in print to any shareholder who requests them.

The Bankruptcy Case

      On May 14, 2003, we and 25 of our direct and indirect wholly owned subsidiaries commenced voluntary petitions under chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York, or “the bankruptcy court.” During the bankruptcy proceedings, we continued to conduct our business and manage our properties as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. Our subsidiaries that own our international operations, and certain other subsidiaries, were not part of these chapter 11 cases or any of the subsequent bankruptcy filings. On November 24, 2003, the bankruptcy court entered an order confirming the NRG plan of reorganization, and the plan became effective on December 5, 2003.

      Since the 1990’s, we pursued a strategy of growth through acquisitions and later the development of new construction projects. This strategy required significant capital, much of which was satisfied with third party debt. Due to a number of reasons, particularly our aggressive pricing of acquisitions, and the overall downturn in the power generation industry, our financial condition deteriorated significantly starting in 2001. During 2002, our senior unsecured debt and our project-level secured debt were downgraded multiple times by rating agencies. In September 2002, we failed to make payments due under certain unsecured bond obligations, which resulted in further downgrades.

      As a result of the downgrades, the debt load incurred during the course of acquiring our assets, declining power prices, increasing fuel prices, the overall downturn in the power generation industry and the overall downturn in the economy, we experienced severe financial difficulties. These difficulties caused us to, among other things, miss scheduled principal and interest payments due to our corporate lenders and bondholders, be required to prepay for fuel and other related delivery and transportation services and be required to provide performance collateral in certain instances. We also recorded asset impairment charges of approximately $3.1 billion during 2002, while we were a wholly-owned subsidiary of Xcel Energy, related to various operating projects as well as for projects that were under construction which we had stopped funding and turbines we had purchased for which we no longer had a use.

      In addition, our missed payments resulted in cross-defaults of numerous other non-recourse and limited recourse debt instruments and caused the acceleration of multiple debt instruments, rendering such debt immediately due and payable. In addition, as a result of the downgrades, we received demands under outstanding letters of credit to post collateral aggregating approximately $1.2 billion.

      In August 2002, we retained financial and legal restructuring advisors to assist our management in the preparation of a comprehensive financial and operational restructuring. In March 2003, Xcel Energy announced that its board of directors had approved a tentative settlement agreement with us, the holders of most of our long-term notes and the steering committee representing our bank lenders.

      We filed two plans of reorganization in connection with our restructuring efforts. The first, filed on May 14, 2003, and referred to as the NRG plan of reorganization, relates to us and the other NRG plan debtors. The second plan, relating to our Northeast and South Central subsidiaries, which we refer to as the Northeast/ South Central plan of reorganization, was filed on September 17, 2003. On November 25, 2003, the bankruptcy court entered an order confirming the Northeast/South Central plan of reorganization and the plan became effective on December 23, 2003.

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      On June 6, 2003, LSP-Nelson Energy LLC and NRG Nelson Turbines LLC filed for protection under chapter 11 of the bankruptcy code and on August 19, 2003, NRG McClain LLC filed for protection under chapter 11 of the bankruptcy code. This annual report does not address the plans of reorganization of these subsidiaries because they are not material to our operations and we expect to sell or otherwise dispose of our interest in each subsidiary subsequent to our reorganization.

      The following description of the material terms of the NRG plan of reorganization and the Northeast/ South Central plan of reorganization is subject to, and qualified in its entirety by, reference to the detailed provisions of the NRG plan of reorganization and NRG disclosure statement, and the Northeast/ South Central plan of reorganization and Northeast/ South Central disclosure statement, all of which are available for review upon request.

      The NRG plan of reorganization is the result of several months of intense negotiations, among us, Xcel Energy and the two principal committees representing our creditor groups, which we refer to as the Global Steering Committee and the Noteholder Committee. A principal component of the NRG plan of reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of the NRG plan of reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and us and/or our creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from us and our creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.

      Under the terms of the Xcel Energy settlement agreement, the Xcel Energy contribution will be or has been paid as follows:

	•	An initial installment of $238 million in cash was paid on February 20, 2004.
	•	A second installment of $50 million in cash was paid on February 20, 2004.
	•	A third installment of $352 million in cash, which Xcel Energy is required to pay on April 30, 2004.

      On November 24, 2003, the bankruptcy court issued an order confirming the NRG plan of reorganization, and the plan became effective on December 5, 2003. To consummate the NRG plan of reorganization, we have or will, among other things:

	•	Satisfy general unsecured claims by:

	•	issuing new NRG Energy common stock to holders of certain classes of allowed general unsecured claims; and
	•	making cash payments in the amount of up to $1.04 billion to holders of certain classes of allowed general unsecured claims of which $500 million was paid with proceeds of the Refinancing Transactions.

	•	Satisfy certain secured claims by either:

	•	distributing the collateral to the security holder,
	•	selling the collateral and distributing the proceeds to the security holder or
	•	other mutually agreeable treatment.

	•	Issue to Xcel Energy a $10 million non-amortizing promissory note which will:

	•	accrue interest at a rate of 3% per annum, and
	•	mature 2.5 years after the effective date of the NRG plan of reorganization.

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      The Northeast/ South Central plan of reorganization was proposed on September 17, 2003 after we secured the necessary financing commitments. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central plan of reorganization and the plan became effective on December 23, 2003. In connection with the order confirming the Northeast/ South Central plan of reorganization, the court entered a separate order which provides that the allowed amount of the bondholders’ claims shall equal in the aggregate the sum of (i) $1.3 billion plus (ii) any accrued and unpaid interest at the applicable contract rates through the date of payment to the indenture trustee plus (iii) the reasonable fees, costs or expenses of the collateral agent and indenture trustee (other than reasonable professional fees incurred from October 1, 2003) plus (iv) $19.6 million, ratably, for each holder of bonds based upon the current outstanding principal amount of the bonds and irrespective of (a) the date of maturity of the bonds, (b) the interest rate applicable to such bonds and (c) the issuer of the bonds. The settlement further provides that the Northeast/ South Central debtors shall reimburse the informal committee of secured bondholders, the indenture trustee, the collateral agent, and two additional bondholder groups, for any reasonable professional fees, costs or expenses incurred from October 1, 2003 through January 31, 2004 up to a maximum amount of $2.5 million (including in such amount any post-October 1, 2003 fees already reimbursed), with the exception that the parties to the settlement reserved their respective rights with respect to any additional reasonable fees, costs or expenses incurred subsequent to November 25, 2003 related to matters not reasonably contemplated by the implementation of the settlement of the Northeast/ South Central plan of reorganization.

      The creditors of Northeast and South Central subsidiaries are unimpaired by the Northeast/ South Central plan of reorganization. This means that holders of allowed general unsecured claims were paid in cash, in full on the effective date of the Northeast/ South Central plan of reorganization. Holders of allowed secured claims will receive or have received either (i) cash equal to the unpaid portion of their allowed unsecured claim, (ii) treatment that leaves unaltered the legal, equitable and contractual rights to which such unsecured claim entitles the holder of such claim, (iii) treatment that otherwise renders such unsecured claim unimpaired pursuant to section 1124 of the bankruptcy code or (iv) such other, less favorable treatment that is confirmed in writing as being acceptable to such holder and to the applicable debtor.

Fresh Start Reporting

      As a result of our emergence from bankruptcy, we have adopted Fresh Start reporting, or “Fresh Start.” Under Fresh Start, our confirmed enterprise value has been allocated to our assets and liabilities based on their respective fair values in conformity with the purchase method of accounting for business combinations. See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operation — Reorganization and Emergence from Bankruptcy for additional information.

Strategy

      We own and operate a diverse portfolio of electric generation facilities, which we believe have strategic locational advantages. Through our reorganization, we intend to reposition ourselves in our industry to focus on owning, operating and maximizing the value of our generation assets. We are implementing this strategy through the following key actions:

	•	optimizing the value of our existing assets with a focus on operational reliability and efficiency;
	•	retaining a new management team with proven industry experience;
	•	mitigating risk by pursuing asset-focused power marketing activities through effective procurement of fuel and fuel services and the sale of energy and related products into spot, intermediate and long-term markets;
	•	improving our liquidity position and further deleveraging our balance sheet; and
	•	limiting acquisitions and new project developments in the near term;

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	•	continuing our focus on operating power plants in a safe, secure and environmentally compliant manner, and
	•	to the extent that our locationally-advantaged power plants can no longer be operated profitably, seeking to redevelop those sites for alternative use.

Competition

      The future course of the restructuring of the wholesale power generation industry is difficult to predict, but it is likely to include consolidation within the industry, the sale, bankruptcy or liquidation of certain competitors, the re-regulation of certain markets and the long-term reduction in new investment into the industry. Under any scenario, however, we anticipate that we will continue to face competition from numerous companies in the industry. We anticipate that the Federal Energy Regulatory Commission, or “FERC”, will continue its efforts to facilitate the competitive energy market place throughout the country on several fronts but particularly by encouraging utilities to voluntarily participate in Regional Transmission Organizations, or “RTOs.”

      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 of 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 includes base-load, intermediate and peaking facilities, giving us the opportunity to maximize our profit opportunities along the entire energy dispatch curve. Our generation facilities are likewise diversified by fuel-type, including coal, oil and natural gas. The diversity of technology, fuel type and operational characteristics allows us to participate in most aspects of the electricity demand cycle. By offering what we believe to be an efficient mix of generation, we are able to offer competitive prices to our customers and optimize the revenue potential across the entire fleet. For example, in the current high gas price environment, our coal assets, such as Huntley, Dunkirk, Big Cajun II and Indian River, have a distinct competitive advantage due to the relatively low marginal cost of coal. Peaking assets can provide increased revenue by taking advantage of higher prices in periods of increased demand in the energy markets. Further, peaking and intermediate assets can provide emergency back-up when our base-load plants experience outages.

      Regional Strength. We have a number of power plants in the Northeast, South Central and West Coast regions of the United States, providing a degree of economies of scale throughout the organization, and reducing our dependence on any single market. Owning multiple plants in a particular market provides us greater dispatch flexibility and increases power marketing opportunities.

      Locational Advantages. We own and operate a number of facilities that are strategically located near large urban areas or in certain transmission-constrained areas with locational advantages over our competition. For example, the Astoria and Arthur Kill plants are situated inside the New York City market. Due to transmission constraints and local installed capacity requirements of the New York Independent System Operator, or “NYISO”, competitors outside the city limits are restricted from importing power into New York City, and therefore do not have the advantage of “in city” generation. Certain facilities in California near the Los Angeles and San Diego load centers use ocean water cooling that gives them competitive advantages, especially during water shortages. Additionally, construction of new power plants in areas such as New York City and California is limited because of the difficulty in:

	•	finding sites for new plants;

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	•	overcoming the general public’s “not-in-my-backyard” mentality;
	•	obtaining the necessary permits; and
	•	arranging fuel supplies.

The value of some of our plants is also enhanced by the potential for re-powering or site expansion.

      Risk Mitigation. As a wholesale generator, we are subject to the risks associated with volatility in fuel and power prices. We mitigate these risks by managing a portfolio of contractual assets for both power supply and fuel requirements. In the near term our portfolio will be weighted toward spot market sales and short-term contracts because long-term contracts are not generally available at attractive prices. We expect that these generally weak market conditions will continue for the foreseeable future in some markets. As the markets improve, we will seek opportunities to enter into longer-term agreements in order to capture more stable returns and predictable cash flow. We manage counterparty credit risk by doing our own credit assessment of the companies with which we trade and when necessary by requiring appropriate credit support in the form of cash collateral or letters of credit.

      Improved Financial Position. As part of the NRG plan of reorganization, we eliminated approximately $5.2 billion of corporate level bank and bond debt and approximately $1.3 billion of additional claims and disputes by distributing a combination of equity and up to $1.04 billion in cash among our unsecured creditors.

Performance Metrics

      The following table contains a summary of our North American power generation revenues from majority owned subsidiaries for the year 2003, includes both Predecessor Company and Reorganized NRG revenues (in thousands of dollars):

	*	Consists of our wholly-owned subsidiary, NEO California LLC.

	**	For additional information — see Item 15 — Note 20 of the Consolidated Financial Statements for our consolidated revenues by segment disclosures.

***	Includes miscellaneous revenues from the sale of natural gas, recovery of incurred costs under reliability agreements and revenues received under leasing arrangements.

      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 as more fully described below:

      Annual Equivalent Availability Factor, or “EAF”: is the Total Available Hours a unit is available in a year minus the summation 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 heat rate: We calculate the average heat rate for our fossil-fired power plants (excluding peakers) by dividing (a) fuel consumed in Btu’s 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.

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      In-Market Availability, or “IMA”: IMA is the ratio of the calculated revenue earned compared to an estimation of the potential revenues that would have been earned if the facility had been available 100 percent of the time it was considered to be “in-market”, as determined by NRG Power Marketing, for the period under consideration.

      The table below presents the North America power generation performance metrics discussed above.

      The table below presents the Australian power generation performance metrics discussed above.

Power Generation

      Facilities. As of December 31, 2003, we owned approximately 7,900 MW of net generating 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 power generation assets as of December 31, 2003 are summarized in the table below.

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

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      Although each of the three northeast ISOs are functionally, administratively and operationally independent from one another, they all tend to 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 cost of 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, or “DAM.” The second is a financially settled, security constrained “Real Time” dispatch and balancing market, or “RT.” In addition to energy delivery, the ISOs manage secondary markets for installed capacity, ancillary services and financial transmission rights.

      Market Developments. On March 1, 2003, ISO-NE implemented its version of SMD. This change modified the New England market structure by incorporating LMP, which means pricing by location rather than on a New England wide basis. Even though we view this change as an improvement to the existing market design, we still view the market within New England as incapable of allowing us to recover our costs and earn a reasonable return on our investment.

      On February 26, 2003, we filed a proposed cost of service agreement with FERC for the following Connecticut facilities: Devon station units 11-14, Middletown station, Montville station and Norwalk station (FERC Docket No ER03-563-000). In response, on March 25, 2003, FERC issued an order, “the March 25, 2003 Order”, approving a tracking mechanism for the payment of or recovery of certain maintenance expenses, subject to refund, and authorized an effective date of February 27, 2003. In the March 25, 2003 Order, FERC also permitted ISO-NE, via an escrow account, to start collecting the maintenance expenses from certain NEPOOL participants in order to ensure the availability of our units. In its March 25, 2003 Order, FERC did not rule on the remainder of the issues to allow further time to consider protests it received related to the filing. On February 6, 2004, we filed updated maintenance schedules for the period April 1, 2004 through March 31, 2005.

      On April 25, 2003, FERC issued an order rejecting the remaining part of the proposed cost of service agreements including the monthly cost-based payment, citing certain policy determinations regarding cost of service agreements. Rather, FERC instructed ISO-NE to establish temporary bidding rules that would permit selected units (units with capacity factors of ten percent or less during 2002), operating within designated congestion areas, such as Connecticut, to raise their bids to allow them the opportunity to recover their fixed and variable costs through the market. In May and June 2003, the ISO-NE revised its market rules to facilitate “peaking unit safe harbor”, or “PUSH”, bidding. On July 24, 2003, FERC clarified that the capacity factor of ten percent or less applies to units rather than stations. Therefore, on a unit basis, all of our facilities qualify to bid under the temporary rules, except Middletown units 2 and 3. The PUSH bidding rule will remain in place until ISO-NE implements locational installed capacity payments, which FERC mandated ISO-NE implement no later than June 1, 2004. On March 1, 2004, ISO-NE filed a locational capacity proposal with FERC. Under the proposal, generators that are needed for reliability and have a capacity factor of 15% or less in 2003 are eligible for a monthly capacity payment of $5.38 per KW-month. Most of our generators located in Connecticut satisfy this requirement.

      Consistent with our expectations, PUSH bidding has not yielded sufficient revenues to cover all our costs for most of our affected facilities. We intend to take additional actions with FERC and other Connecticut parties to attempt to address the expected revenue deficiency. On January 16, 2004, we filed proposed reliability-must-run agreements, or “RMR agreements”, with FERC for the following facilities: Devon station units 11-14, Middletown station and Montville station. The RMR agreement filings requested FERC to establish cost of service rates. The FERC has not yet acted on this matter.

      In addition to the facilities noted above, the following of our quick-start facilities in Connecticut have submitted PUSH bids that have been approved by FERC: Cos Cob, Franklin Drive, Branford, and Torrington. The existing RMR agreement between ISO-NE and us covering Devon station units 7 and 8 terminated on September 30, 2003. On October 2, 2003, we filed with FERC to extend the existing RMR agreement for the

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      In April of 2003, the 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. In a complaint filed with FERC on December 15, 2003, Consolidated Edison Company of New York, Inc. and other load-serving entities alleged that NYISO had used the wrong rate setting methodology to establish prices and rebates in the New York City markets for a portion of the summer capacity auction in 2003, and that this action resulted in overcharges to customers and overpayments to suppliers, including us, totaling approximately $21 million, with our share being approximately $5 million. If the complaint were granted, we may be required to refund payments. On December 19, 2003, the Electricity Consumers Resource Council appealed the FERC decision approving the demand curve in the United States Court of Appeals for the District of Columbia Circuit. If the appeal is granted, it could require the elimination of the demand curve for the capacity market. On February 11, 2004, a FERC sponsored settlement conference took place without successful resolution of the issue. The NYISO scarcity pricing improvements have re-introduced some volatility in the New York energy markets when supplies are short.

      The NYISO intends to introduce additional changes to its energy market in early 2004, with the implementation of Standard Market Design 2. Although the exact nature of these changes is not known at this time, we anticipate the changes to be small, targeted improvements to the NYISO’s present market.

      In PJM, we are closely following market power mitigation modifications that may significantly impact the revenues achievable in that market by modifying PJM’s price capping mechanisms. On April 2, 2003, Reliant Resources, Inc., or “Reliant”, filed a complaint against PJM with FERC and suggested specific modifications to PJM’s price mitigation rules. On June 9, 2003, FERC rejected the Reliant modifications but required PJM to file a report to address the concerns of Reliant by September 30, 2003. The PJM market monitoring unit filed its compliance filing with FERC as required, but opted to continue its present mitigation practices. The present mitigation plan permits PJM to “cost-cap” the energy bids of certain generating facilities that were constructed prior to 1996. The cost capping method is based on a facility’s variable costs plus ten percent. In addition, the PJM market monitoring unit filed to eliminate the exemption that units built after 1996 had from PJM’s mitigation measures. This change, if approved by FERC, will impact certain of our facilities within PJM. It will also continue a practice that has depressed prices in PJM. The PJM market monitoring unit’s actions were not endorsed by the requisite number of market participants. It is unclear at this time, what actions FERC will take and how this will impact us.

      Facilities. As of December 31, 2003, we owned approximately 2,500 MW of net generating capacity in the South Central United States. The South Central region generating assets consist primarily of our power generation facilities in New Roads, Louisiana, or “the Cajun Facilities”, and also include the Sterlington and Bayou Cove generating facilities.

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

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      The South Central region power generation assets as of December 31, 2003 are summarized in the table below.

*	Units 1 and 2 owned 100%, Unit 3 owned 58%.

      Market Framework. Our South Central region assets are located within the control areas of the local, regulated, and sometimes vertically integrated, utilities, primarily Entergy Corporation, or “Entergy.” The utility performs the scheduling, reserve and reliability functions that are administered by the ISOs in certain other regions of the United States and Canada. We operate a National Electric Reliability Council, or “NERC”, certified control area within the Entergy control area, which is comprised of our generating assets and our co-op customer loads. Although the reliability functions performed are essentially the same, the primary differences between these markets lie principally in the physical delivery and price discovery mechanisms. In the South Central region, all power sales and purchases are consummated bilaterally between individual counter-parties, and physically delivered either within or across the physical control areas of the transmission owners from the source generator to the sink load. Transacting counter-parties are required to reserve and purchase transmission services from the intervening transmission owners at their 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. In the South Central region, including Entergy’s service territory, the present energy market is not a centralized market and does not have an independent system operator as is found in the Northeast markets. Rather, the energy market is made up of bilateral contractual relations. We presently have long-term all requirements contracts with 11 Louisiana Distribution Cooperatives, and long-term contracts with the Municipal Energy Agency of Mississippi, South Mississippi Electric Power Association and Southwestern Electric Power Company. The Distribution Cooperatives serve approximately 300,000 to 350,000 retail customers.

      In the Southeast portion of the United States, Entergy and Southern Company recently discontinued their RTO initiative, SeTrans. It is unclear at this time how this recent development will impact us, or whether another RTO proposal will replace the SeTrans initiative.

      Facilities. As of December 31, 2003, we owned approximately 1,300 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.

      In May 1999, we formed West Coast Power, along with Dynegy, Inc., or “Dynegy”, 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 Long Beach 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. An application for a permit to repower the existing El Segundo site, replacing the retired unit 1 & 2 with 600 MW of new generation has been filed. The permit is in the California Energy Commission review process, and it is anticipated that the

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      The West Coast region power generation assets as of December 31, 2003 are summarized in the table below.

      Market Framework. Our West Coast region assets are primarily located within the control area of the Cal ISO. The Cal ISO operates a financially settled “Real Time” balancing market. “Day Ahead” energy markets in the west are currently 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 the Cal ISO.

      Market Developments. In California, the Cal ISO continues with its plan to move toward markets similar to PJM, NYISO and ISO-NE with its MDO2 initiative (market design 2002). The Cal ISO intends that MDO2 will establish a standardized day ahead market and real time market that allows for multiple settlements. Presently the Cal ISO market does not include a capacity market. In general, the Cal ISO is continuing along a path of small incremental changes, rather than significant market restructuring. Although numerous stakeholder meetings have been held, the final market design remains unknown at this time. The effect of the MDO2 changes on us 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 maintenance procedures of wholesale power generators. This effort has slowed in recent months, due to an Executive Order issued by Governor Arnold Schwarzenegger that directs all government agencies to evaluate regulations that could harm business and business development in the state. The Executive Order effectively put a nine month hold on all regulations identified, and it is unclear at this time where that process will lead. The CPUC recently issued draft orders directing the utilities to meet a 17% reserve requirement by no later than the beginning of 2008.

      The Cal ISO has protested the timeframe and those discussions may result in changes for procurement by the utilities that may present opportunities to enter into new bilateral agreements. In addition, the CPUC has adopted an order, which allows the load serving investor owned utilities to purchase energy and capacity through contracts with generators for up to a one year term. A longer term procurement proceeding is pending. It is the intention of the West Coast Power LLC entities to arrange for short term and longer term capacity agreements beginning in January 2005 after the current California Department of Water Resources, or “CDWR”, agreement expires.

      Facilities. As of December 31, 2003, we owned approximately 3,500 MW of net generating capacity in our other regions of the United States.

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      Our Other North America power generation assets as of December 31, 2003 are summarized in the table below.

*	May sell or dispose of in the next 12 months.

      Market Developments. In the Midwest, it is anticipated that Exelon Corporation will be partially integrated into PJM by the second quarter of 2004, and will transition to PJM’s LMP market model soon thereafter. Exelon is the parent corporation of PECO Energy Company and Commonwealth Edison, or “ComEd.” On November 25, 2003, FERC issued an order requiring American Electric Power, or “AEP”, to join PJM. In the order the FERC stated that AEP must comply with its prior commitment to join an RTO, namely PJM. Previously, the actions taken by the Virginia legislature had restricted AEP’s ability to join PJM. At this time the effect of the November 25, 2003 order is unclear. Consequently, Exelon, and our Chicago area assets, could be somewhat isolated from the rest of PJM. The impact of the Exelon integration on us is also unclear at this time. Also on December 31, 2003, PJM requested that FERC approve certain changes to the PJM Operating Agreement in order to permit ComEd to join PJM. On December 31, 2003 and February 5, 2004, PJM filed proposed mitigation plans for the ComEd territory. Among the requested changes was the proposed adoption for the PJM energy market mitigation plan of “cost capping” and a new mitigation plan for the capacity market. Under this mitigation plan, bids into the capacity market would be limited to incremental costs. These two mitigation proposals, if approved, could negatively impact our facilities located in ComEd’s territory.

      Facilities. Over the past decade we, through our foreign subsidiaries, invested in international power generation projects in Asia Pacific, Europe and Latin America. During 2002, we sold international generation projects with an aggregate total generating capacity of approximately 600 MW. As of December 31, 2003, we, through certain foreign subsidiaries, had investments in power generation projects located in Australia, the UK, Germany, South America and Taiwan with approximately 3,000 MW of net generating capacity.

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      Our international power generation assets as of December 31, 2003 are summarized in the table below.

*	May sell or dispose of in the next 12 months.
**	May sell or significantly restructure in the next 12 months.
***	Primarily a coal mining facility.
****	Common equity ownership interest.

Alternative Energy and Services

      In addition to our traditional power generation facilities discussed above, we own alternative energy generation facilities through NEO Corporation, or “NEO” and through our NRG Resource Recovery business division, which processes municipal solid waste as fuel to generate power. In addition, we own district heating and cooling and steam transmission operations through NRG Thermal LLC.

      NEO Corporation. NEO is a wholly owned subsidiary that was formed to develop power generation facilities ranging in size from 1 to 33 MW in the United States. As of December 31, 2003, NEO has ownership interests in 9 landfill gas collection systems and had 17 MW of net ownership interests in related electric generation facilities utilizing landfill gas as fuel. NEO also had 42 MW of net ownership interests in 17 hydroelectric facilities and 107 MW of net ownership interests in five distributed generation facilities including 93 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.

      NEO’s power generation assets as of December 31, 2003 are summarized in the table below.

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*	May sell or dispose of in the next 12 months, excluding our Chowchilla or Red Bluff facilities (assets held for use).

      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 3,400 tons per day and generation capacity of 25 MW, of which our net ownership interest is 18 MW. Our Resource Recovery business owns and operates municipal solid waste processing and/or generation facilities in Maine and Minnesota. Our Resource Recovery business also owns and operates NRG Processing Solutions which includes thirteen composting and biomass fuel processing sites in Minnesota, of which three sites are permitted to operate as municipal solid waste transfer stations.

      Our significant Resource Recovery assets as of December 31, 2003 are summarized in the table below.

*	The Newport facilities are related strictly to municipal solid waste processing.
**	For the Elk River facility, our 85% interest is related strictly to municipal solid waste processing.
***	May sell or dispose of in the next 12 months.

      Thermal and Chilled Water Businesses. 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 1,290 megawatt thermal equivalents, or “MWt”.

      As of December 31, 2003, 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 600 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, and 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).

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      Our thermal and chilled water assets as of December 31, 2003 are summarized in the table below.

*	Thermal production and transmission capacity is based on 1,000 Btus per pound of steam production or transmission capacity. The unit mmBtu is equal to one million Btus.

Energy Marketing

      Our energy marketing subsidiary, 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 agency agreements pursuant to which PMI manages the sales and purchases of energy, capacity and ancillary services from the facilities, procures the fuel (coal, oil and natural gas) and associated transportation and manages the emission allowance credits for these facilities. In addition, PMI provides all necessary ISO bidding, dispatch and transmission scheduling for the facilities. PMI utilizes its contractual arrangements with third parties in order to procure fuel and to sell energy, capacity and ancillary services to minimize administrative costs and burdens and reduce the amount of collateral requirements imposed by third party suppliers and purchasers, thereby easing credit and liquidity concerns.

NRG Worldwide Operations

      NRG Worldwide Operations, or “NRG Operations”, provides operating and maintenance services to our generation fleet. 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 ensure the optimum utilization of resources available to the fleet. In addition, NRG Operations provides

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      NRG Operations typically provides services to project entities by entering into a Service Agreement with the project company. Service Agreements provide a contractual basis and definition of the rights and responsibilities of the operating companies and the asset owners for each project that is operated by NRG Operations. NRG Operations’ operating companies provide a uniform suite of services that address management, technical, contractual, commercial and other business issues as well as safety, security and environmental compliance services and strategies.

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 20 to the Consolidated Financial Statements.

Dispositions of Non-Strategic Assets

      Since 2002, we sold or made arrangements to sell a number of consolidated businesses and equity investments in an effort to reduce our debt and improve liquidity. Dispositions completed during 2003 and announced pending dispositions as of February 29, 2004 are summarized in the following chart:

(1)	Discontinued operations.

      In addition to the announced pending dispositions described in the table above, definitive agreements have been executed in connection with the sale of our interests in certain other projects. In addition, we are continuing to market other non-strategic assets.

Significant Customers

      For the period from January 1, 2003 through December 5, 2003, sales to one customer, NYISO, accounted for 30.5% of our total revenues from majority owned operations. Also during 2002, NYISO accounted for 23.7% of our total revenues from majority owned operations. During 2001, we derived approximately 51.1% of our total revenues from majority-owned operations from two customers: NYISO

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      For the period from December 6, 2003 through December 31, 2003, we derived approximately 35.5% of our total revenues from majority-owned operations from two customers: NYISO 24.1% and ISO New England 11.4%. We account for the revenues attributable to the NYISO and ISO New England as part of our North American power generation segment. NYISO is an ISO, which is a FERC-regulated entity that manages the transmission assets that are collectively under the control of the ISO 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.

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

Seasonality and Price Volatility

      Annual and quarterly operating results can be significantly affected by weather and price volatility. Significant other events, such as demand for natural gas for heating and reduced hydroelectric capacity due to drier seasons 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 where volatility and price spikes in underlying fuel prices has tended to drive seasonal electricity prices. Issues related to the 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 energy sources, 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 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 prices of natural gas and oil were particularly high during the winter of 2002-2003 due to weather volatility and geo-political uncertainty in the Middle East. Oil, natural gas and coal represented approximately 37.1% and 38.6% of our cost of operations for the period January 1, 2003 through December 5, 2003 and the period December 6, 2003 through December 31, 2003, respectively. Issues related to the sources and availability of raw materials are fairly uniform across our business segments.

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Employees

      As of December 31, 2003, we had 2,892 employees, approximately 478 of whom are employed directly by us and approximately 2,414 of whom are employed by our wholly owned subsidiaries and affiliates. Approximately 1,020 employees are covered by bargaining agreements. During 2003, we have 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.” The FPA also gives FERC jurisdiction over: a public utility’s issuance of securities or assumption of liabilities; the dispositions of jurisdictional assets; and the licensing and inspecting of private, municipal and state-owned hydroelectric projects. 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 Federal Power Act, or “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 possess excessive market power. 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. In addition, FERC has issued an order in connection with our reorganization that implies that FERC believes that we, even though we are not a public utility under the FPA, may require FERC’s approval before we can issue securities or assume liabilities subsequent to our reorganization.

      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 EWG generating projects with the transmission grid, and over the filed rate schedules and tariffs of our EWG generating projects and power marketer 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 ISOs. Most of these ISOs administer a wholesale centralized bid-based spot market in their regions pursuant to tariffs approved by FERC. These tariffs/market rules dictate how the spot markets operate and how entities with market-based rates shall be compensated within those markets. The ISOs in these regions also control access to and the operation of the transmission grid within their footprint. Outside of ISO-controlled regions, we are allowed to sell at market-based rates as determined by willing buyers and sellers. Access to, pricing for,

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      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 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 not considered “public utility companies” for purposes of 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. However, prior to the effective date of the NRG plan of reorganization, we met the definition of a “Subsidiary” of a registered holding company, Xcel Energy, making us subject to regulation under PUHCA. After the effective date, we ceased to be a Subsidiary of Xcel Energy and, under current law, are no longer subject to regulation as a “registered holding company” or a “Subsidiary” of a registered holding company under PUHCA as long as (i) we do not become a Subsidiary of another registered holding company and (ii) 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.

      On December 18, 2003, FERC approved FirstEnergy Corp’s., or “FirstEnergy”, application to acquire approximately 6.5% of our outstanding shares. We were, therefore, an “Affiliate” of a registered holding company. While an “Affiliate” is subject to substantially less regulation than a “Subsidiary,” being an Affiliate of FirstEnergy Corp. could have limited the transactions that we could enter into with FirstEnergy without notifying the SEC. On February 2, 2004, FirstEnergy announced that it completed the divesture of the NRG Energy stock in the secondary market. Based on such disclosure, we believe that we are no longer an affiliate of FirstEnergy.

      Regulatory Developments. FERC is attempting to deregulate the wholesale market 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, requiring 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. Finally, on July 31, 2002, FERC issued its Notice of Proposed Rulemaking regarding 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. Two of these ISOs, PJM and MISO, have been found to also qualify as RTOs. In February 2004, FERC approved the RTO proposal by Southwest Power Pool, subject to certain

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      We are affected by rule/tariff changes that occur in the existing ISOs and RTOs. The ISOs 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.

      The Energy Bill proposed in Congress 2003 would have repealed PUHCA one year after passage and amended PURPA, and provided FERC with additional jurisdiction over the books and accounts of certain holding companies. If the repeal/amendment of PURPA or PUHCA should occur, either separately or as part of legislation designed to encourage the broader introduction of wholesale and retail competition the ability of regulated utility companies to compete more directly with wholesale power generators could be increased. To the extent competitive pressures increase the economics of domestic wholesale power generation projects may come under increasing pressure. Deregulation may not only continue to fuel the current trend toward consolidation among domestic utilities, but may also encourage the desegregation of vertically-integrated utilities into separate generation, transmission and distribution businesses. At this time, the Energy Bill has stalled in Congress and it is unclear whether it will be passed into law. If the Energy Bill is passed, it is unclear what impact, if any, the new rules would have on us.

Environmental Matters

      We are subject to a broad range of foreign, provincial, federal, state and local environmental and safety laws and regulations applicable to the development, ownership, construction and operation of our domestic and international projects. These laws and regulations impose requirements relating to 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.

      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 addition, environmental laws have become increasingly stringent over time, particularly with regard to the regulation of air emissions from our plants. Such laws generally require regular capital expenditures for power plant upgrades and modifications and for the installation of certain pollution control equipment. Therefore, we seek to integrate the consideration of potential environmental impacts into every business decision we make, and by doing so, strive to improve our competitive advantage by meeting or exceeding environmental and safety requirements pertaining to 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 possible changes to environmental and safety laws and regulations, regulatory interpretations or enforcement policies. In general, the effect of future laws or

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      The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulations in the United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and our facilities are not exempted from coverage, we could be required to make extensive modifications to further reduce potential environmental impacts. Also, we could be held responsible under environmental and safety laws for the cleanup of pollutant releases at our facilities or at off-site locations where we have sent waste.

      We establish accruals where reasonable estimates of probable environmental and safety liabilities are possible. 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 are being undertaken in the U.S. to further limit and control pollutant emissions from fossil-fuel-fired combustion units. Although neither the exact impact of these initiatives nor the final form that these initiatives will take are 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 “SO ₂ ,” mercury and, in some instances, carbon dioxide, or “CO ₂ .”

      The U.S Environmental Protection Agency, or “EPA,” announced in December 2003 its proposed rules regulating mercury emissions from coal-fired electric utility units and emissions of nickel from oil-fired utility units. In its mercury rule proposal, EPA offered three options for controlling mercury emissions. The first option would regulate mercury emissions by setting maximum achievable control technology, or “MACT,” standards on major sources of hazardous air pollutants, or “HAPS.” Existing units would need to comply with new mercury emission limitations within three years following EPA’s publication of the final rule. The other two options are based on capping nationwide emissions of mercury from coal-fired units, allocating mercury allowances to such individual sources, and allowing such sources to trade allowances in order to demonstrate compliance with the rule. Under the EPA proposal, implementation of the cap-and-trade program would be done in two phases; the first phase would cap nationwide mercury emissions beginning in 2010 and the second phase would mandate a further reduction in the cap in 2018. In the preamble to its proposal, EPA indicated that it views the more flexible cap-and-trade approach as the best option for reducing mercury emissions from coal-fired utility units. We expect that each of our coal-fired electric power plants would be subject to mercury regulation under any of EPA’s proposed regulatory options. EPA’s final decision on mercury regulation is expected to be announced on or before December 15, 2004. Since the final rule has not yet been promulgated and we do not know at this time which of the three proposed options EPA will eventually select, it is not possible to determine the extent to which the final mercury rules will affect our domestic operations.

      EPA has also proposed two options for regulations to control nickel emissions from oil-fired electric utility units. The first option is similar to the MACT approach for mercury, i.e., a limit on nickel emissions would apply to oil-fired utility units that constitute major sources of HAPS. The second option would require all oil-fired units to meet the same numerical standard as that proposed under the MACT approach, but would exempt units that fire distillate fuel oil. Under both proposals, EPA is considering establishing a limit on the nickel content of fuel that would be equivalent to the nickel emission limit. In proposing the limits for nickel from oil-fired units, EPA proposed the use of electrostatic precipitators, or “ESPs,” as the control device of choice. Our oil-fired units that lack ESPs include, Vienna, Encina, Middletown Unit No. 4 and Montville

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      EPA has finalized federal rules governing ozone season NO _x emissions across the eastern United States. These ozone season rules are being implemented in two phases. The first phase of restrictions occurred in the Ozone Transport Commission region during the 2003 ozone season; all of our generating units in the northeast and mid-Atlantic regions are included in this part of the program. The second phase of NO _x reductions will extend to states within the Ozone Transport Assessment Group region and restrict 2004 and subsequent ozone season NO _x emissions in most states east of the Mississippi River. These rules, which will continue until further notice, require one NO _x allowance to be held for each ton of NO _x emitted from any fossil fuel-fired stationary boiler, combustion turbine, or combined cycle system that (i) at any time on or after January 1, 1995, served a generator with a nameplate capacity greater than 25 MW and sold any amount of electricity or (ii) has a maximum design heat input greater than 250 mmBtu/hr. Our facilities that are subject to this rule in the South Central and Northeast regions have been allocated NO _x emissions allowances, but we expect that those allowances may not be sufficient for the anticipated operation for all of these facilities. Our facilities in Illinois in the Other North America region are also subject to this program. We expect that our Illinois sources will receive initial allowances out of a new source set aside. The future operating capacity of these Illinois plants will determine whether the initial allowances are sufficient. If our allocation is insufficient, we will be required to purchase NO _x allowances from sources holding excess allowances. The need to purchase these additional NO _x allowances could have a material adverse effect on our operations in these regions.

      On December 17, 2003, EPA announced it was proposing a rule to address the impact of interstate transport of air pollutants on non-attainment of the National Ambient Air Quality Standards for fine particles and 8-hour ozone. EPA dubbed this rule the “Interstate Air Quality Rule.” The proposed Interstate Air Quality Rule would reduce emissions of SO ₂ and NO _x in 29 eastern states and the District of Columbia in two phases. SO ₂ emissions would be reduced by 3.6 million tons in 2010 (approximately 40 percent below current levels) and by another 2 million tons per year when the rules are fully implemented in 2015 (approximately 70 percent below current levels). Emissions of NO _x would be cut by 1.5 million tons in 2010 and 1.8 million tons annually in 2015 (about 65 percent below today’s levels). Each affected state would be required to revise its state implementation plan to include control measures to meet specific statewide emission reduction requirements. To achieve the required reductions in the most cost effective way, the proposal suggests that states regulate power plants under a cap-and-trade program similar to EPA’s Acid Rain Program. Under such a program, total emissions in the affected states would be permanently capped and could not increase. In general, the flexibility provided by such cap-and-trade programs would benefit our operations. However, the cost of obtaining allowances under such programs could still represent a material adverse effect on our operations.

      On February 16, 2004, EPA released for purposes of minimizing adverse environmental impacts on aquatic species regulations governing cooling water intake structures at existing power plants. The new rules will require implementation of the best technology available for minimizing such impacts and require facilities designed to withdraw water in amounts greater than 50 million gallons per day via such structures to include (when such facilities submit applications to renew their National Pollutant Discharge Elimination System permits) a comprehensive demonstration study characterizing impingement mortality and entrainment losses. Further, the facility must confirm that the technologies, operational measures, and/or restoration measures proposed to minimize impacts will meet one of five compliance alternatives. We expect that each of the following NRG facilities that utilize once through cooling systems will be required to conduct such studies and select a compliance alternative: Somerset, Devon, Middletown, Montville, Norwalk Harbor, Indian River, Dunkirk, Huntley, Oswego, Arthur Kill, Big Cajun 2, El Segundo, Encina, and Long Beach. We have already undertaken such demonstration studies at four of these facilities (Somerset, Middletown, Montville, and Norwalk Harbor); we have already decided and budgeted to install best technology available at one of the facilities (Arthur Kill); and we are likely at four facilities to be exempted from critical demonstration study requirements on the basis of either low capacity utilization rates (Montville, Devon and Oswego) or location on a freshwater river with high mean annual flow rate (Big Cajun 2). In general, the new rules provide

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      West Coast Region. The El Segundo and Long Beach Generating Stations are both regulated by the South Coast Air Quality Management District’s, or “SCAQMD’s,” Regional Clean Air Incentives Market, or “RECLAIM,” program. This program, which regulates NO _x emissions in the Los Angeles area, was amended on May 11, 2001, and mandated major changes with respect to air emissions control at power generation facilities in southern California. New RECLAIM Rule 2009 required that all existing power generation facilities meet Best Available Retrofit Control Technology, or “BARCT,” NO _x emissions from all utility boilers by January 1, 2003, and for NO _x emissions from all peaking units by January 1, 2004. Under the new rule, existing power generation facilities were required to submit compliance plans by September 1, 2001, listing how each unit at the stations would meet BARCT by the deadlines. El Segundo’s compliance plan did not propose additional NO _x controls to meet BARCT since Units 3 & 4 are already equipped with acceptable selective catalytic reduction, or “SCR,” technology (first installed on Unit 4 in 1995 and on Unit 3 in 2001). Further, Units 1 & 2 were decommissioned at the end of 2002 so the new requirements did not apply to those two units. SCAQMD approved the El Segundo Rule 2009 Compliance Plan on October 17, 2002, indicating that the SCRs on Units 3 & 4 meet BARCT and requiring that Units 1 & 2 be retired on or before December 31, 2002. SCAQMD approved the Long Beach Generating Station Rule 2009 Compliance Plan on April 25, 2002, which proposed modifications to the Long Beach NO _x control system by December 31, 2002, and specified a new NO _x emission concentration limit of 16.6 parts per million. The Long Beach plant completed all control system modifications and demonstrated compliance with 16.6 parts per million a limit before the December 31, 2002 deadline. We believe all Long Beach and El Segundo units have met the Rule 2009 BARCT requirements.

      Northeast Region. Final rules implementing changes in air regulations in Massachusetts and Connecticut were promulgated in 2000. The Connecticut rules required that existing facilities reduce their emissions of SO ₂ in two steps. The first SO ₂ milestone took place on January 1, 2002 and the second SO ₂ milestone occurred on January 1, 2003. Our plants in Connecticut have operated in compliance with the first phase rules and are now operating in compliance with the second phase rules. Connecticut’s rules governing emissions of NO _x were also modified in 2000 to restrict the average, non-ozone season NO _x emission rate to 0.15 pound per million Btu heat input. We plan to comply with the new NO _x rules, in part, through selective firing of natural gas, use of selective non-catalytic reduction technology presently installed at our 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 in-state emissions credit trading subsequent to January 1, 2005 as a means of meeting Department of Environmental Protection regulatory standards for SO ₂ emissions from older power plants. The termination of SO ₂ emissions trading in Connecticut by 2005 could have a material adverse effect on our operations in that state.

      The new Massachusetts rules set forth schedules under which six existing coal-fired power plants in Massachusetts were required to meet stringent emission limits for NO _x , SO ₂ , mercury and CO ₂ . The state has reserved the issue of credit creation and trading for the control of carbon monoxide and regulations on the control of particulate matter emissions for future consideration. On February 25, 2003, we received from the Massachusetts Department of Environmental Protection, or “MADEP,” a permit to install natural gas reburn technology to meet the NO _x and SO ₂ limits specified in the new rules at our Somerset Generating Station.

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      In September 2003, MADEP proposed mercury regulations that would affect the Somerset Station. The first phase would go into effect on October 1, 2006 and require the Somerset Station to meet a mercury rate of 0.0075 Pounds/ GWh or an 85% reduction inlet-to-outlet. The second phase, which goes into effect on October 1, 2012, would require a rate of 0.0025 Pounds/ GWh, or a 95% reduction inlet-to-outlet. Public hearings on these rules occurred in mid-November. On December 8, 2003, we submitted comments in support of certain provisions of the proposed rule that would allow for affected facilities to submit for MADEP’s approval alternative reduction plans for complying with the rate limitation or percent removal requirement. Such plans would allow for affected facilities to substitute approved off-site reductions for reductions in stack emissions. We believe we can comply with any future mercury reductions required by the rules through achieving early reductions of mercury via early implementation of the natural gas reburn technology and with our January 1, 2010 commitment to shutdown Somerset Station’s existing boiler. We are still considering our options with respect to how we will address MADEP’s CO ₂ emission standards. Such options include using early reductions of CO ₂ achieved through early implementation of the natural gas reburn technology, purchase of creditable greenhouse gas reductions obtained from third parties, or by filing a legal challenge with respect to MADEP’s legal authority to regulate CO ₂ emissions. If we were required to purchase verifiable CO ₂ emission reduction credits, such purchase could have a material adverse impact on Somerset Station.

      New York issued rules on April 17, 2003 that became effective on May 17, 2003 that reduce allowable SO ₂ and NO _x emissions from large, fossil-fuel-fired combustion units in New York State (6 NYCRR Part 237: Acid Deposition Reduction NO _x Budget Trading Program and Part 238: Acid Deposition Reduction SO ₂ Budget Trading Program). These rules affect all of our New York generators except the Astoria Gas Turbines. We filed a petition on August 15, 2003 challenging the final rules. Although, oral arguments have been heard by the judge presiding over this matter, no finding has been issued as of the date hereof. Our strategy for complying with the new rules will be to generate early reductions of SO ₂ and NO _x associated with fuel switching and use such reductions to extend the timeframe for implementing technological controls. Such technological controls could include the addition of flue gas desulphurization, low NO _x combustion technologies and/or SCR equipment. We anticipate that we could incur capital expenditures up to $200 million in the 2010 through 2012 timeframe to implement upgrades and modifications to our plants in New York (other than Astoria) to meet these new state regulatory requirements if we cannot address such requirements through use of compliant fuels and/or plant wide applicability limits. Capital expenditures on this order would be expected to have a material adverse effect on the Company.

      While no material impending rule changes affecting our existing facilities have been formally proposed, Delaware has considered in 2003 whether or not to develop Maximum Achievable Control Technology standards for mercury. In support of this effort, the state is beginning to test large combustion sources for mercury emissions. In addition, the state is considering establishing an emissions reduction rulemaking that could affect our assets in Delaware. We are meeting with the Delaware Department of Natural Resources and Environmental Control, or “DNREC,” to determine whether or nor our reductions and their timing will meet DNREC’s expectations and thereby avoid a rulemaking.

      South Central Region. The Louisiana Department of Environmental Quality has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone non-attainment area into compliance with National Ambient Air Quality Standards. We participated in the development of the revisions, which require the reduction of NO _x emissions at the gas-fired Big Cajun I Power Station and coal-fired Big Cajun II Power Station to 0.1 pounds NO _x per million Btu heat input and 0.21 pounds NO _x per million Btu heat input, respectively. This revision of the Louisiana air rules would appear to constitute a change-in-law covered by the agreement between Louisiana Generating LLC and the electric cooperatives 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 is estimated to total approximately $10.0 million each for Units 1 & 2. Unit 3 has already made such changes.

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      On January 27, 2004, Louisiana Generating LLC received from EPA Region 6 a request for information that would assist in their determination whether projects undertaken at Big Cajun 2 may have triggered any of the Clean Air Act’s requirements under New Source Review and/or New Source Performance Standards. Louisiana Generating LLC has started to assemble the information requested and began submitting documents on February 27, 2004. Given the volume of information requested, Louisiana Generating LLC is not scheduled to complete the information request until the end of March 2004.

      Under certain 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, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault), and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. 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.

      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 and San Diego Gas & Electric retain liability and indemnify us for existing soil and groundwater contamination that exceeds remedial thresholds in place at the time of closing. Along with our business partner for these facilities, we conducted Phase I and Phase II Environmental Site Assessments at each of these sites for the purpose of identifying such existing contamination and provided the results to the sellers. San Diego Gas & Electric has undertaken corrective actions at the Encina and San Diego gas turbine generating sites related to issues identified in these assessments, although final government agency approval to certify completeness of the corrective action has not yet been obtained. Spills and releases of various substances have occurred at these sites since establishing the historical baseline, all of which have been or will be remediated in accordance with existing laws as described further below.

      A lubricating oil leak in November 2002 from underground piping at the El Segundo Generating Station contaminated soils adjacent to and underneath the Unit 1 powerhouse. We excavated and disposed of contaminated soils that could be removed in accordance with existing laws. We filed a request with the Los Angeles Regional Water Quality Control Board to allow contaminated soils to remain underneath the Unit 1 powerhouse building foundation until the building is demolished. In March 2003, the Los Angeles Regional Water Quality Control Board approved the request.

      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 promptly completed. An application for confirmation sampling for the site was submitted to the San Diego County Department of Environmental Health in September 2003. We expect that the Department will authorize the sampling plan and confirmation sampling will be completed in 2004.

      Three San Diego Combustion Turbine facilities, formerly operating pursuant to land leases with the United State 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 United States Navy and the San Diego County Department of Environmental Health. We expect decommissioning and remediation activities to be complete in 2004.

      Northeast Region. Coal ash is produced as a by-product of coal combustion at the Dunkirk, Huntley, Indian River and Somerset Generating Stations. We currently attempt to direct our coal ash to beneficial uses such as road base, cement replacement, cinder blocks and flowable fill materials. Even so, significant

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      We must also maintain financial assurance for closing interim status RCRA facilities at the Devon, Middletown, Montville and Norwalk Harbor Generating Stations. Previously, we satisfied financial assurance requirements by meeting specified financial tests. In April 2003, due to a deterioration of our financial condition, we satisfied financial assurance requirements by depositing $1.5 million in a trust fund instrument requiring complete collateralization of closure and post-closure-related costs.

      We inherited historical clean-up liabilities when we acquired the Somerset, Devon, Middletown, Montville, Norwalk Harbor, Arthur Kill and Astoria Generating Stations. We have recently satisfied clean-up obligations associated with the Ledge Road property (inherited as part of the Somerset acquisition). Site contamination liabilities arising under the Connecticut Transfer Act at the Devon, Middletown, Montville and Norwalk Harbor Stations are currently being refined as part of on-going site investigations. We do not expect to incur material costs associated with completing the investigations at these Stations or future work to close and monitor landfill areas pursuant to the Connecticut requirements. During installation of a sound wall at Somerset Station in 2003, oil contaminated soil was encountered. We have delineated the general extent of contamination, determined it to be minimal, and will place an activity use limitation on that section of the property. Remedial liabilities at the Arthur Kill Generating Station have been established in discussions between the New York State Department of Environmental Conservation, or “NYSDEC,” and us and are expected to cost between approximately $1.0 million and $2.0 million. Remedial investigations are ongoing at the Astoria Generating Station. At this time, we expect our long-term cleanup liability at this site to be approximately $2.5 million to $4.3 million. In the course of installing groundwater monitoring wells on the Astoria site in late 2003 to track our remediation of a historical (pre-NRG Energy) fuel oil spill, the drilling contractor encountered deposits of coal tar in two borings. We reported the coal tar discovery to the NYSDEC. NYSDEC has required us to delineate the extent of this contamination around these borings. We 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. Our estimate of the cost to further delineate the extent of possible coal tar contamination at the Astoria station is approximately $0.2 million. At this time, we do not believe it is necessary to adjust the estimate of our long-term cleanup liability for the Astoria site.

      We are responsible for the costs associated with closure, post-closure care and monitoring of the ash landfill owned and operated by us on the site of the Indian River Generating Station. No material liabilities outside such costs are expected. Financial assurance to provide for closure and post-closure-related costs is currently maintained by a trust fund collateralized in the amount of approximately $6.6 million.

      South Central Region. We maintain a trust fund to address liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated on site at the Big Cajun II Generating Station (one of the instruments allowed by the Louisiana Department of Environmental Quality for providing financial assurance for expenses associated with closure and post-closure care of the ponds). The value of the trust fund is approximately $4.8 million and we are making annual payments to the fund in the amount of approximately $0.1 million.

      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 are still changing and evolving, and have a significant impact on international wholesale power producers. In particular, our international power generation facilities will likely be affected by evolving emissions limitations and operational requirements imposed by the Kyoto

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      We retain appropriate advisors in foreign countries and seek to design our international asset management strategy to comply with and take advantage of opportunities presented by 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. Our Australian power facilities are licensed under the environment protection legislation of the state in which they are located, and are subject to compliance with these state authorizations. The most significant environmental issue for our Australian businesses is the response to global climate change. Climate change issues are 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 our current operations. The Australian government has stated that Australia will achieve its Kyoto Protocol target of 108% of 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. We currently expect that climate change initiatives will not have a material adverse effect on our businesses in Australia.

      MIBRAG/ Schkopau, Germany. We expect CO ₂ emissions trading will begin in Germany in 2005, but we cannot quantify the possible effect of this trading on our operations in Germany at this time because implementation details are still being negotiated among businesses, lobbyists and regulatory authorities. Fundamental issues such as “grandfathering” existing plants or availability of credits for plants previously closed or upgraded are still unsettled. We are working with specialized consultants, the Environmental Ministry of Sachsen Anhalt and MIBRAG to understand developments and minimize any adverse effects. Proposed changes in section 13 of the German Emission Control Directive, is expected to tighten emissions limits for plants firing conventional fuels. As with CO ₂ emissions trading, these changes are currently being debated with issues such as exemptions based on size or purpose of plants and “grandfathering.” Section 17 of this Directive was recently finalized and tightened emission limits for facilities co-firing waste products. Although the new regulations will require the Mumsdorf and Deuben Power Stations to install additional controls to reduce NO _x emissions in 2006, the economic benefits received from co-firing sewage sludge at the facilities provide a business rationale for the investment.

      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 on-going 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 has been introduced in the legislature of Saxony and is expected to be enacted between April and June 2004. There are numerous potential court challenges still to come in the process. We cannot predict the outcome of this process 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, 2029; 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 areas of each mine most recently opened. MIBRAG accrues for these eventual expenses and estimates the cost of final reclamation to approach  € 190 million in the instance of the Schleenhain mine and   € 132 million for Profen.

      UK.  Our Enfield Generating Station uses state-of-the-art combined cycle technology and fires natural gas as its primary fuel. Currently the facility complies with all conditions in its environmental permits and its operation is not under challenge by any governmental or non-governmental parties.

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Risks Related to NRG Energy, Inc.

      In connection with the NRG plan of reorganization, we were required to prepare projected financial information to demonstrate to the bankruptcy court the feasibility of the NRG plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. These projections were based on financial information available to us as of May 1, 2003 and have not been, and will not be, updated on an ongoing basis. The projections were initially filed with the bankruptcy court on May 14, 2003. These projections are not included in this annual report nor are they incorporated by reference and should not be relied upon. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to uncertainties and to a wide variety of significant business, economic and competitive risks. Our actual results will vary from those contemplated by the projections and the variations may be material. As a result, we caution you not to rely upon the projections.

      As a result of adopting Fresh Start reporting, the book value of our long-lived assets and the related depreciation and amortization schedules, among other things, will change from that reflected in our historical consolidated financial statements. Our future results will not be comparable to the historical consolidated statement of operations data included in this annual report. Since we have emerged from bankruptcy, you will not be able to compare certain information reflecting our results of operations and financial condition to those for periods prior to our emergence from bankruptcy without making adjustments for Fresh Start reporting.

      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 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, environmental cleanup costs, personal injury 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 rapidly rising insurance costs, 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.

      Prior to the late 1990’s, substantially all revenues from independent power generation facilities were derived under long-term power purchase agreements, pursuant to which all energy and capacity was generally sold to a single party at fixed prices. Due to changes in the wholesale power markets, the percentage of facilities, including ours, with these types of long-term power purchase agreements has decreased, and it is

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      Further, we sell all or a portion of the energy, capacity and other products from many of our facilities to wholesale power markets. 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 system operators and regulatory regimes in those markets. In addition, unlike most other commodities, 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 price fluctuations over relatively short periods of time and can be unpredictable.

      Our wholesale energy operations compete with other providers of electric energy in the procurement of fuel and the sale of energy and related products. In order to successfully compete, we must have the ability to aggregate fuel supplies at competitive prices from different sources and locations and must be able 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. In addition, our merchant asset business is constrained by our liquidity, our access to credit and the reduction in market liquidity. Other companies with which we compete may not have similar constraints.

      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, or “SCE,” PG&E and San Diego Gas and Electric Company, or “SDG&E.” The ability of the CDWR to make future payments is subject to the CDWR having a continued source of funding, whether from legislative or other emergency appropriations, from a bond issuance or from amounts collected from SCE, PG&E and SDG&E for deliveries to their customers. As a result of the present situation in California, we are exposed to a risk of delayed payments and/or non-payment regardless of whether the sales are made directly to PG&E, SCE or SDG&E or to the California ISO or the CDWR. We are also exposed to the risk of being unable to enter into a contract with similar terms and conditions as the CDWR contract.

      We are exposed to risks relating to the breakdown or failure of equipment or processes, shortages of equipment and supply, material and labor and operating performance below expected levels of output or efficiency. A significant portion of our facilities was constructed many years ago. 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 caused by breakdown, forced outage or any unanticipated capital expenditure, could result in reduced profitability. In addition, if we make any “major

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      We cannot always predict the level of capital expenditures that will be required due to 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, thermal energy production and transmission and resource recovery facilities involve many risks, including:

	•	dispatch at our facilities;
	•	supply interruptions;
	•	work stoppages;
	•	labor disputes;
	•	social unrest;
	•	weather interferences;
	•	unforeseen engineering, environmental and geological problems; and
	•	unanticipated cost overruns.

      The ongoing operation of our facilities involves all of the risks described above, in addition to 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 in 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 lost revenues, increased expenses or liquidated damages payments should we experience equipment breakdown or non-performance of contractors. Any of these risks could cause us to operate below expected capacity 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 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:

	•	weather conditions;
	•	seasonality;
	•	demand for energy commodities and general economic conditions;
	•	forced or unscheduled plant outages;

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	•	disruption of electricity, gas or coal transmission or transportation, infrastructure or other constraints or inefficiencies;
	•	additional generating capacity;
	•	availability of competitively priced alternative energy sources;
	•	availability and levels of storage and inventory for fuel stocks;
	•	natural gas, crude oil and refined products and coal production levels;
	•	the creditworthiness or bankruptcy or other financial distress of market participants;
	•	changes in market liquidity;
	•	natural disasters, wars, embargoes, acts of terrorism and other catastrophic events; and
	•	federal, state and foreign governmental regulation and legislation.

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

      Our plant operating characteristics and equipment often dictate the specific fuel quality to be combusted. The availability of specific fuel qualities may vary due to supplier financial or operational disruptions, and may have a material adverse impact on the financial results of specific plants.

      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. A decrease in gas prices may lead to a corresponding decrease in electricity prices in these markets, which could adversely impact our financial performance.

      We often rely on a single supplier for the provision of fuel, water and other services required for operation of a facility, and 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. During the period January 1, 2003 through December 5, 2003, we derived 30.5% of our revenues from one customer: the NYISO. For the period December 6, 2003 through December 31, 2003 we derived 35.5% of our revenues from two customers: NYISO 24.1% and ISO New England 11.4%. During 2002, we derived approximately 23.7% of our revenues from majority-owned operations from one customer: the NYISO. During 2001, we derived approximately 51.1% of our revenues from majority-owned operations from two customers: the NYISO 33.6% and CL&P 17.5%. The failure of any supplier or customer to fulfill its contractual obligations to the 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 and continued performance by suppliers and customers of their obligations under these long-term agreements.

      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 rights 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 which hedge the amount of exposure for our net transactions. As such, the effectiveness of our hedging strategy may be dependent on the amount of collateral available to enter

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      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 hedge our exposure to market risk with respect to electricity sales from our generation assets, emission allowances and fuel utilized by those assets. 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. Whether a derivative qualifies for hedge accounting or not depends upon it meeting specific criteria used to determine if hedge accounting is appropriate. If a derivative does not qualify or if the company does not elect to designate a derivative as a hedge the changes in fair value of the derivative will be recognized immediately in earnings. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as accounting hedges are either recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments or for forecasted transactions, deferred and recorded as a component of accumulated other comprehensive income, or “OCI,” until the hedged transactions occur and are recognized in earnings. As a result, most derivative contracts are mark-to-market and change in their fair value, brought upon by fluctuations in the underlying commodity prices, flow through the statement of operations. 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 quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including:

	•	seasonal variations in demand and corresponding energy and fuel prices; and
	•	variations in levels of production.

      Additionally, because we receive the majority of capacity payments under some of our power sales agreements during the months of May through October, our revenues and results of operations are subject to seasonal fluctuations.

      On August 14, 2003, the northeastern United States and parts of Canada suffered a massive blackout allegedly stemming from transmission problems originating in Ohio. The Department of Energy, in conjunction with its Canadian counterpart, is actively investigating the cause of the outage. Upon completion, there are likely to be changes to NERC reliability criteria and standards that may impact the operation of power plants owned by us. Other entities such as the New York Public Service Commission are also conducting investigations. Upon completion of these investigations, there may be regulatory changes and we cannot

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      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. 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:

	•	general economic and capital market conditions;
	•	covenants in our existing debt and credit agreements;
	•	credit availability from banks and other financial institutions;
	•	investor confidence in us, our partners and the regional wholesale power markets;
	•	our financial performance and the financial performance of our subsidiaries;
	•	our levels of indebtedness;
	•	maintenance of acceptable credit ratings;
	•	the success of current projects;
	•	provisions of tax and securities laws that may impact raising capital; and
	•	our ability to acquire any necessary regulatory approvals.