NRG ENERGY INC - 10-K Annual Report

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

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

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

As of the last business day of the most recently completed second fiscal quarter, there were 3 shares of Class A Common Stock and 1 share of Common Stock outstanding, all of which were owned by Xcel Energy Wholesale Group, Inc.

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

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

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.

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.

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.

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:


	•	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.


	•	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.

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.

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.

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;


	•	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.

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.

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:


	•	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.

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):


	**	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.

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.

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.”

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

two Devon units. On December 1, 2003, FERC granted us a one day suspension of the rates, subject to refund, set the case for hearing and appointed a settlement judge. On February 25, 2004, a FERC sponsored technical conference occurred to review the costs associated with the two Devon units. In the technical conference, our costs relevant to the RMR agreements were discussed. Also, we expect to file an amended cost of service filing with the FERC relative to Devon units 7 & 8 in order to make the cost assumptions for Devon 7 & 8 similar to that of the RMR agreements. ISO NE has indicated in a letter dated February 27, 2004 that one of the Devon units will no longer be needed for reliability services. Therefore, one of the Devon units 7 & 8 agreements will be terminated effective April 28, 2004.

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.

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

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

Presiding Member’s Proposed Decision issued in January 2004 recommending approval of the redevelopment project will be adopted by the Commission during the first quarter of 2004. However, we would not proceed with the construction of the new project absent a long-term power purchase agreement or tolling arrangement supporting the financial investment necessary for this repowering.

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.

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

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.

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.

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.


*	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).

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.

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, 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

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.

For financial information on our operations on a geographical and on a segment basis, see Item 15 — Note 20 to the Consolidated Financial Statements.

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:

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.

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

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:

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.

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.

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 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,

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

conditions. ISO-NE, together with New England transmission owners, has filed a proposal for an RTO in New England. A number of other entities in various regions of the United States have also requested that FERC approve their organizations as RTOs.

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.

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

regulations is expected to require the addition of pollution control equipment or the imposition of certain restrictions on our operations. We expect that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position.

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 “SO₂,” mercury and, in some instances, carbon dioxide, or “CO₂.”

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

Unit No. 6. We have not completed our evaluation of the impact the proposed nickel emission limit would have on these sources. EPA’s final decision regarding nickel emissions from oil-fired units will be provided on or before December 15, 2004.

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 SO₂ and NO_x in 29 eastern states and the District of Columbia in two phases. SO₂ 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

flexibility in terms of their available compliance options and allow an implementing agency to find that the cost of compliance would be significantly greater than the benefits of complying with a facility’s applicable performance standards. We believe this flexibility will allow the remaining facilities to greatly minimize compliance costs. In general, the cost of a comprehensive demonstration study is expected to total less than $400 thousand; however, in the case of the California facilities El Segundo, Encina and Long Beach, we expect the cost of each such study to be significantly higher, but not exceed $2 million each. We are undertaking to narrow this cost through discussions with contractors having experience in 316(b) demonstrations in California.

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 SO₂ in two steps. The first SO₂ milestone took place on January 1, 2002 and the second SO₂ 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 SO₂ emissions from older power plants. The termination of SO₂ 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, SO₂, mercury and CO₂. 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 SO₂ limits specified in the new rules at our Somerset Generating Station.

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 CO₂ emission standards. Such options include using early reductions of CO₂ 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 CO₂ emissions. If we were required to purchase verifiable CO₂ 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 SO₂ 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 SO₂ 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 SO₂ 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.

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

amounts of ash are landfilled at on and off-site locations. At Indian River, Dunkirk and Huntley, ash is disposed at landfills owned and operated by us. No material liabilities outside the costs associated with closure, post-closure care and monitoring are expected at the Dunkirk and Huntley facilities, currently estimated at approximately $5.8 million. We maintain financial assurance to cover costs associated with closure, post-closure care and monitoring activities by providing cash collateral, corporate guarantees or meeting certain financial ratio tests.

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

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 CO₂ 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 CO₂ 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.

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

likely that over the next several years where there is an oversupply of generation capacity, most of our facilities will operate as “merchant” facilities without long-term agreements. Without the benefit of long-term power purchase agreements, we cannot assure you that we will be able to sell any or all of the power generated by our facilities at commercially attractive rates or that our facilities will be able to operate profitably. This could lead to future impairment of our property, plant and equipment or us closing certain of our facilities resulting in additional economic losses and liabilities.

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

modifications” to our power generation facilities, as defined under the new source review provisions of the Federal Clean Air Act, we would be required to install “best available control technology” or to achieve the “lowest achievable emissions rate.” Any such modifications would likely result in substantial additional capital expenditures. In general, environmental laws, particularly with respect to air emissions, are becoming more stringent, which may require us to install expensive plant upgrades and/or restrict our operations to meet more stringent standards.

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;


	•	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

into these hedging contracts and liquidity requirements may be greater than we anticipate or are able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as cash margin, we may not be able to effectively manage this price volatility. Factors, which could lead to an increase in our required collateral, include adverse changes in our industry, credit rating downgrades or the secured nature of our new credit facility. Under certain unfavorable commodity price scenarios, it is possible that we could experience inadequate liquidity as a result of the posting of additional collateral.

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

We engage in commodity-related marketing and price-risk management activities in order to 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

predict the impact of such changes. Moreover, the business of selling power is fundamentally dependent on the integrity of the electricity transmission system. Large energy blackouts, such as the blackout described above, can occur as a result of failures in the electricity transmission system. Such blackouts have the potential to reduce our revenue collection, increase our costs and engender enhanced federal and state regulatory requirements.

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.

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

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

and regulations may be adopted or become applicable to us or our facilities in a manner that may have a detrimental effect on our business. With the continuing trend toward stricter standards, greater regulation and more extensive permitting requirements, we expect that our environmental expenditures will be substantial in the future. For more information, see “Business — Environmental Matters.”

Our operations are potentially subject to the provisions of various energy laws and regulations, including the PUHCA, the FPA and state and local utility laws and regulations.

Under the FPA, FERC regulates our wholesale sales of electric power (other than sales by our Qualifying Facilities, which are exempt from FERC rate regulation). The ability to sell energy at market-based rates is predicated on the absence of market power in either generation or transmission. The market power analysis includes not only generation and transmission owned by a particular applicant but also assets owned by affiliated companies. FERC has found that we do not possess market power in either generation or transmission outside of the Xcel Energy franchise territories. Once we terminated our Xcel Energy relationship, we were permitted to request FERC to find that we do not possess market power with respect to Xcel Energy franchise territories and request FERC to remove associated restrictions on our ability to make market-based rate sales in such regions. On December 17, 2003, we requested that FERC approve revision to our market based rate tariffs, which in part removed the Xcel Energy sales restrictions. We are waiting for FERC acceptance of the tariff revisions. Holders of market-based rate authority must comply with obligations imposed by FERC and with certain FERC filing requirements such as the requirement to file quarterly reports detailing wholesale sales. Although a number of our direct and indirect subsidiaries have obtained market-based rate authority from FERC, these authorizations could be revoked if we fail in the future to satisfy the applicable criteria, if FERC modifies the criteria, or if FERC eliminates or further restricts the ability of wholesale sellers to make sales at market-based rates. On November 17, 2003, FERC issued an order conditioning all market-based rate sales on behavioral rules intended to prevent market manipulation and other market abuses. All market-based sales will be conditioned on compliance with these behavioral rules and violations of such conditions could result in a seller being subject to refunds, revocation of market-based rate authority and other unspecified remedies for violating the conditions. At this time it is not clear what impact this proposal may have on us.

In addition, under PUHCA, registered holding companies and their subsidiaries (i.e., companies with 10% or more of their voting securities held by registered holding companies) are subject to extensive regulation by the SEC. We were previously a subsidiary of a registered holding company, Xcel Energy. Upon our emergence from bankruptcy, we ceased to be a subsidiary of Xcel Energy and are no longer subject to regulation under PUHCA as a registered holding company or as a subsidiary of such a holding company as long as we do not become a subsidiary of another registered holding company and the projects in which we have an interest (1) qualify as a QF under PURPA, (2) obtain and maintain EWG status under Section 32 of PUHCA, (3) obtain and maintain foreign utility company, (FUCO) status under Section 33 of PUHCA, or (4) are subject to another exemption or waiver. If our projects were to cease to be exempt and we were to become subject to SEC and FERC regulation under PUHCA, it would be difficult for us to comply with PUHCA absent a substantial corporate restructuring.

While we are no longer a subsidiary of a registered holding company after our emergence from bankruptcy, we became an affiliate (as defined by PUHCA, a company with between 5-10% of its voting securities held by a registered holding company) of FirstEnergy, a registered holding company, when FERC approved FirstEnergy’s application to acquire 6.5% of our outstanding common stock upon emergence from bankruptcy as part of a settlement. Although becoming an affiliate of FirstEnergy would have subjected us to certain limitations on our transactions with FirstEnergy and other restrictions, these restrictions are less substantial than those applicable to us when we were a subsidiary of Xcel Energy. On February 2, 2004, FirstEnergy announced that it completed the divestiture of the NRG Energy stock in the secondary market. Based on such disclosure, we believe that we are no longer an affiliate of FirstEnergy.

The Energy Bill currently pending before Congress would repeal PUHCA one year after passage and create new rules for holding companies. At this time, the Energy Bill has stalled in Congress and it is unclear whether it will be passed into law. In addition, if the Energy Bill is passed, it is unclear what impact, if any, the

We face regulatory risk imposed by the various transmission providers, ISOs and RTOs and their corresponding market rules. Transmission providers, ISOs and RTOs have FERC-approved tariffs that govern access to their transmission system. These tariffs may contain provisions that limit access to the transmission grid or allocate scarce transmission capacity in a particular manner.

We presently operate in the following ISO markets: California (through the West Coast Power joint venture and individually), New England, New York and PJM. The chief regulatory risk is the lack of market product that adequately compensates generating units for providing reliability services. The lack of such a properly designed product is one of the reasons we have numerous petitions with the FERC requesting cost based compensation for some of our Connecticut facilities.

Our future success and the successful implementation of new strategies will be highly dependent upon our new President and Chief Executive Officer, and our new Chief Financial Officer, as well as other members of senior management. The loss of the services of any such individuals or other key personnel could have a material adverse effect upon the implementation of new strategies. Further, there can be no assurance that the implementation of new strategies will be successful or that they will not cause substantial disruption to our ongoing business.

The nature of our business subjects us to litigation in the ordinary course of business. In addition, we are from time to time involved in other legal proceedings. Although all claims made against us prior to the date of the bankruptcy filing, except as described in the immediately following paragraph, were satisfied and discharged in accordance with the terms of the NRG plan of reorganization or in connection with settlement agreements that were approved by the bankruptcy court prior to our emergence from bankruptcy, any remaining or future claims may have a material adverse effect on our results of operations and profitability. In addition, claims made against subsidiaries that did not file chapter 11, and claims arising after the date of our bankruptcy filing were not discharged in the bankruptcy proceeding. See Item 3 — Legal Proceedings of this annual report on Form 10-K for a description of the significant legal proceedings and investigations in which we are presently involved.

Claims made against us prior to the date of the bankruptcy filing might not be discharged if the claimant had no notice of the bankruptcy filing. In addition, in other bankruptcy cases, states have challenged whether their claims could be discharged in a federal bankruptcy proceeding if they never made an appearance in the case. The U.S. Supreme Court has not finally settled this issue.

In addition, our West Coast Power subsidiaries are named in a class action suit alleging, among other things, the manipulation of gas price indexes by reporting false and fraudulent trades. We have not been named in this litigation. Dynegy has agreed with us that it will indemnify and hold harmless all of the named defendants in such lawsuit, as well as us. In the event Dynegy is unable or unwilling to satisfy its indemnification obligations, our West Coast Power subsidiaries or we could sustain substantial monetary penalties, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Under the NRG plan of reorganization, we have established disputed claims reserves, which we will utilize to make distributions to holders of disputed claims in our bankruptcy as and when their claims are resolved. If these reserves prove inadequate, we will be required to finance required distributions from other resources, and doing so could have an adverse impact on our financial condition and could require the issuance of new common stock, which would dilute existing shareholders. In particular, the State of California has a disputed claim against us in an amount capped at $1.35 billion. We have made no reserves for this claim because we believe it is without merit; however, if the State of California prevails, then payment of the distributions to which the State of California is entitled under the NRG plan of reorganization could have an adverse impact on our financial condition.

Although we emerged from bankruptcy in December 2003, we cannot assure you that the bankruptcy proceeding will not adversely affect our operations going forward. Having filed for bankruptcy protection may adversely affect our ability to negotiate favorable terms from suppliers, landlords and others and to attract and retain customers. The failure to obtain such favorable terms and retain customers could adversely affect our financial performance.

Under the NRG plan of reorganization, holders of certain claims have received distributions of shares of our common stock. MatlinPatterson Global Opportunities Partners L.P. and one of its affiliates, collectively “MatlinPatterson”, based on its most recent filings with the SEC, own 21.5% of our outstanding common stock. MatlinPatterson could acquire additional claims or shares, or it could divest claims or shares in the future. Our prepetition noteholders and lenders collectively received in excess of 80% of our outstanding common stock.

If any holders of a significant number of the shares of our common stock were to act as a group, such holders could be in a position to control the outcome of actions requiring stockholder approval, such as an amendment to our certificate of incorporation, the authorization of additional shares of capital stock, and any merger, consolidation, or sale of all or substantially all of our assets, and could prevent or cause a change of in our control. Moreover, certain of our prepetition creditors, including MatlinPatterson and lenders under our prepetition credit facility, have designated ten members of our 11-member board of directors.

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

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


	•	fluctuations in currency valuation;

	•	currency inconvertibility;

	•	expropriation and confiscatory taxation;

	•	increased regulation; and

	•	approval requirements and governmental policies limiting returns to foreign investors.

The following subsidiaries are not covered by either of the two plans of reorganization that were confirmed in November 2003, and remain in chapter 11: NRG McClain LLC, NRG Nelson Turbines LLC and LSP-Nelson Energy LLC. In addition, we anticipate that it may be necessary or advisable to put one or more of our other subsidiaries through chapter 11 as part of our overall restructuring effort. The existence of these ongoing chapter 11 proceedings may adversely affect the way we are perceived by investors, financial markets, customers, suppliers and regulatory authorities, which could adversely affect our operations and financial performance.

At a number of our project subsidiaries, our pre-bankruptcy financial distress, the chapter 11 reorganization or the loss of Xcel Energy as a controlling shareholder could constitute a default under certain project loan agreements or shareholders agreements. Absent a waiver of these defaults from the applicable lenders, we may not be able to prevent the acceleration of the project debt and the exercise of remedies against the project subsidiaries. Likewise, absent a waiver from the affected shareholders, those shareholders may be able to enforce buy-out rights or other remedies against our project subsidiaries. As of the date of this annual report, we have not been able to obtain waivers or make other arrangements with certain of these project lenders and shareholders, and there is no assurance that we will be able to in the future. If we are unable to obtain waivers or make other arrangements, our project subsidiaries may be adversely affected, which may cause adverse effects to us as a whole.

This annual report includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). The words “believes,” “projects,” “anticipates,” “plans,” “expects,” “intends,” “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause our actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statement. These factors, risks and uncertainties include, but are not limited to, the following:


	•	Lack of comparable financial data due to adoption of Fresh Start reporting;

	•	Hazards customary to the power production industry and the possibility that we may not have adequate insurance to cover losses as a result of such hazards;

	•	Our inability to enter into intermediate and long-term contracts to sell power and procure fuel on terms and prices acceptable to us;

	•	Increasing competition in wholesale power markets that may require additional liquidity for us to remain competitive;


	•	The present condition of the California energy market which may impact the collectibility of certain amounts owed to our California affiliates by the California Department of Water Resources;

	•	Risks associated with timely completion of capital improvement and re-powering projects, including supply interruptions, work stoppages, labor disputes, social unrest, weather interferences, unforeseen engineering, environmental or geological problems and unanticipated cost overruns;

	•	Volatility of energy and fuel prices and the possibility that we will not have sufficient working capital and collateral to post performance guarantees or margin calls to mitigate such risks or manage such volatility;

	•	Failure of customers and suppliers to perform under agreements, including failure to deliver procured commodities and services and failure to remit payment as required and directed, especially in instances where we are relying on single suppliers or single customers at a particular facility;

	•	Changes in the wholesale power market, including reduced liquidity, which may limit opportunities to capitalize on short-term price volatility;

	•	Large energy blackouts, such as the blackout that impacted parts of the northeastern United States and Canada during the middle of August 2003, which have the potential to reduce our revenue collection, increase our costs and engender enhanced federal and state regulatory requirements;

	•	Limitations on our ability to control projects in which we have less than a majority interest;

	•	The condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions;

	•	Changes in government regulation, including but not limited to the pending changes of market rules, market structures and design, rates, tariffs, environmental regulations and regulatory compliance requirements imposed by the FERC, state commissions, other state regulatory agencies, the EPA, the NERC, transmission providers, RTOs, ISOs, or other regulatory or industry bodies;

	•	Price mitigation strategies employed by ISOs that result in a failure to adequately compensate our generation units for all of their costs;

	•	Employee workforce factors including the hiring and retention of key executives, collective bargaining agreements with union employees and work stoppages;

	•	Cost and other effects of legal and administrative proceedings, settlements, investigations and claims, including claims which are not discharged in the bankruptcy proceedings and claims arising after the date of our bankruptcy filing;

	•	The impact of the bankruptcy proceedings on our operations going forward, including the impact on our ability to negotiate favorable terms with suppliers, customers, landlords and others;

	•	The right of certain of our prepetition creditors who received our common stock upon our emergence from bankruptcy to select our board members and influence certain aspects of our business operations;

	•	Acts of terrorism both in the United States and internationally;

	•	Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where we have a financial interest;

	•	Material developments with respect to and ultimate outcomes of legal proceedings and investigations relating to our past and present activities;

	•	The fact that certain of our subsidiaries will remain in bankruptcy after our emergence, and the potential that additional subsidiaries may file for bankruptcy in the future;

	•	The exposure of certain of our project subsidiaries to the exercise of rights and remedies by project lenders or shareholders as a result of our chapter 11 bankruptcy reorganization;


	•	Factors affecting power generation operations such as unusual weather conditions; catastrophic weather-related or other damage to facilities; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;

	•	Our ability to borrow additional funds and access capital markets;

	•	Our substantial indebtedness and the possibility that we may incur additional indebtedness going forward;

	•	Significant operating and financial restrictions placed on us by the indenture governing our recent note offerings and our new credit facility;

	•	Restrictions on the ability to pay dividends, make distributions or otherwise transfer funds to us contained in the debt and other agreements of certain of our subsidiaries and project affiliates generally; and

	•	Other business or investment considerations that may be disclosed from time to time in our SEC filings or in other publicly disseminated written documents.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause our actual results to differ materially from those contemplated in any forward-looking statements included in this annual report should not be construed as exhaustive.

Listed below are descriptions of our interests in facilities, operations and/or projects owned as of December 31, 2003.

Thermal Energy Production and Transmission Facilities and Resource Recovery Facilities


(1)	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.

(2)	Discontinued Operations. See Disposition of Non-Strategic Assets under Item 1.

In addition to the above, we lease our corporate offices at 901 Marquette, Suite 2300, Minneapolis, Minnesota 55402 and various other office spaces. We also own interests in other construction projects in various states of completion, the development of which has been terminated due to our liquidity situation, as well as other properties not used for operational purposes.

People of the State of California ex. rel. Bill Lockyer, Attorney General, v. Dynegy, Inc. et al., United States District Court, Northern District of California, Case No. C-02-O1854 VRW; United States Court of Appeals for the Ninth Circuit, Case No. 02-16619.

This action was filed in state court on March 11, 2002 against us, Dynegy, Dynegy Power Marketing, Inc., Xcel Energy, West Coast Power and four of West Coast Power’s operating subsidiaries. Through our subsidiary, NRG West Coast LLC, we are a 50 percent beneficial owner with Dynegy of West Coast Power, which owns, operates, and markets the power of four California plants. Dynegy and its affiliates and subsidiaries are responsible for gas procurement and marketing and trading activities on behalf of West Coast Power. It alleges that the defendants violated California Business & Professions Code § 17200 by selling ancillary services to the Cal ISO, and subsequently selling the same capacity into the spot market. The California Attorney General seeks injunctive relief as well as restitution, disgorgement and civil penalties.

On April 17, 2002, the defendants removed the case to the United States District Court in San Francisco. Thereafter, the case was transferred to Judge Vaughn Walker, who is also presiding over various other “ancillary services” cases brought by the California Attorney General against other participants in the California market, as well as other lawsuits brought by the Attorney General against these other market participants. We have tolling agreements in place with the Attorney General with respect to such other proposed claims against us.

The Attorney General filed motions to remand, which the defendants opposed in July of 2002. In an Order filed in early September 2002, Judge Walker denied the remand motions. The Attorney General has appealed that decision to the United States Court of Appeal for the Ninth Circuit, and the appeal is pending. The Attorney General also sought a stay of proceedings in the district court pending the appeal, and this request was also denied. In a lengthy opinion filed March 25, 2003, Judge Walker dismissed the Attorney General’s action against Dynegy and us with prejudice, finding it was barred by the filed-rate doctrine and preempted by federal law. The Attorney General filed a Notice of Appeal, and the appeal was argued in August 2003 and also is pending.

Public Utility District of Snohomish County v. Dynegy Power Marketing, Inc et al., Case No. 02-CV-1993 RHW, United States District Court, Southern District of California (part of MDL 1405).

This action was filed against us, Dynegy, Xcel Energy and several other market participants in the United States District Court in Los Angeles on July 15, 2002. The complaint alleges violations of the California Business & Professions Code § 16720 (the Cartwright Act) and Business & Professions Code § 17200. The basic claims are price fixing and restriction of supply, and other market “gaming” activities.

The action was transferred from Los Angeles to the United States District Court in San Diego and was made a part of the Multi-District Litigation proceeding described below. All defendants filed motions to dismiss and to strike in the fall of 2002. In an Order dated January 6, 2003, Judge Robert Whaley, a federal judge from Spokane sitting in the United States District Court in San Diego, pursuant to the Order of the Multi-District Litigation Panel, granted the motions to dismiss on the grounds of federal preemption and filed-rate doctrine. The plaintiffs have filed a notice of appeal, and the appeal is pending.

In re: Wholesale Electricity Antitrust Litigation, MDL 1405, United States District Court, Southern District of California, pending before Judge Robert H. Whaley. The cases included in this proceeding are as follows:


	Pamela R Gordon, on Behalf of Herself and All Others Similarly Situated v Reliant Energy, Inc. et al., Case No. 758487, Superior Court of the State of California, County of San Diego (filed on November 27, 2000).

	Ruth Hendricks, On Behalf of Herself and All Others Similarly Situated and On Behalf of the General Public v. Dynegy Power Marketing, Inc. et al., Case No. 758565, Superior Court of the State of California, County of San Diego (filed November 29, 2000).

	The People of the State of California, by and through San Francisco City Attorney Louise H. Renne v. Dynegy Power Marketing, Inc. et al., Case No. 318189, Superior Court of California, San Francisco County (filed January 18, 2001).

	Pier 23 Restaurant, A California Partnership, On Behalf of Itself and All Others Similarly Situated v PG&E Energy Trading et al., Case No. 318343, Superior Court of California, San Francisco County (filed January 24, 2001).

	Sweetwater Authority, et al. v. Dynegy, Inc. et al., Case No. 760743, Superior Court of California, County of San Diego (filed January 16, 2001).

	Cruz M Bustamante, individually, and Barbara Matthews, individually, and on behalf of the general public and as a representative taxpayer suit, v. Dynegy Inc. et al., inclusive. Case No. BC249705, Superior Court of California, Los Angeles County (filed May 2, 2001).

All of West Coast Power’s operating subsidiaries are defendants in at least one of these six coordinated cases, which were all filed in late 2000 and 2001 in various state courts throughout California. We are also a defendant in all of them. The cases allege unfair competition, market manipulation and price fixing. All the cases were removed to the appropriate United States District Courts, and were thereafter made the subject of a petition to the Multi-District Litigation Panel (Case No. MDL 1405). The cases were ultimately assigned to Judge Whaley. Judge Whaley entered an order in 2001 remanding the cases to state court, and thereafter the cases were coordinated pursuant to state court coordination proceedings before a single judge in San Diego Superior Court. Thereafter, Reliant Energy and Duke Energy filed cross-complaints naming various Canadian, Mexican and United States government entities. Some of these defendants once again removed the cases to federal court, where they were again assigned to Judge Whaley. The defendants filed motions to dismiss and to strike under the filed-rate and federal preemption theories, and the plaintiffs challenged the district court’s jurisdiction and sought to have the cases remanded to state court. In December 2002, Judge Whaley issued an opinion finding that federal jurisdiction was absent in the district court, and remanding the cases to state court. Duke Energy and Reliant Energy then filed a notice of appeal with the Ninth Circuit, and also sought a stay of the remand pending appeal. The stay request was denied by Judge Whaley. On February 20, 2003, however, the Ninth Circuit stayed the remand order and accepted jurisdiction to hear the appeal of Reliant Energy and Duke Energy on the remand order. We anticipate that filed-rate/federal preemption pleading challenges will be renewed once the remand appeal is decided.

“Northern California” cases against various market participants, not including us (part of MDL 1405). These include the Millar, Pastorino, RDJ Farms, Century Theatres, EI Super Burrito, Leo’s, J&M Karsant, and Bronco Don cases. We were not named in any of these cases, but in virtually all of them, either West Coast Power or one or more of its operating subsidiaries is named as a defendant. These cases all allege violation of Business & Professions Code § 17200, and are similar to the various allegations made by the Attorney General. Dynegy is named as a defendant in all these actions, and Dynegy’s outside counsel is representing both Dynegy and the West Coast Power entities in each of these cases. These cases all were removed to federal court, made part of the Multi-District Litigation, and denied remand to state court. In late August 2003, Judge Whaley granted the defendants’ motions to dismiss in these various cases, which are now the subject of the plaintiff’s appeal to the Ninth Circuit Court of Appeals.

Bustamante v. McGraw-Hill Companies, Inc., et al., No. BC 235598, California Superior Court, Los Angeles County.

This putative class action lawsuit was filed on November 20, 2002. The complaint generally alleges that the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades. Named defendants in the suit include numerous industry participants unrelated to us, as well as the operating subsidiaries established by West Coast Power for each of its four plants: El Segundo Power, LLC; Long Beach Generation, LLC; Cabrillo Power I LLC; and Cabrillo Power II LLC. The complaint seeks restitution and disgorgement of “ill-gotten gains,” civil fines, compensatory and punitive damages, attorneys’ fees and declaratory and injunctive relief. The plaintiff filed an amended complaint in 2003.

Jerry Egger, et al. v. Dynegy, Inc., et al., Case No. 809822, Superior Court of California, San Diego County (filed May 1, 2003). This class action complaint alleges violations of California’s Antitrust Law and Business and Professional Code, as well as unlawful and unfair business practices. The named defendants include “West Coast Power, Cabrillo II, El Segundo Power, Long Beach Generation.” We are not named. This case now has been removed to the United States District Court, and the defendants have moved to have this case included as Multi-District Litigation along with the above referenced cases before Judge Walker. Plaintiffs have filed a motion to remand to state court, which was heard on February 19, 2004. At the hearing, the court decided to stay the case pending a decision from the Ninth Circuit Court of Appeals in the Pastorino appeal, referenced above.

Texas-Ohio Energy, Inc., on behalf of Itself and all others similarly situated v. Dynegy, Inc. Holding Co., West Coast Power, LLC, et al., Case No. CIV.S-03-2346 DFL GGH. This putative class action was filed on November 10, 2003, in the United States District Court for the Eastern District of California. The complaint alleges violations of the federal Sherman and Clayton Acts and California’s Cartwright Act and Business and Professions Code. In addition to naming West Coast Power and Dynegy, Inc. Holding Co., the complaint names numerous industry participants, as well as “unnamed co-conspirators.” The complaint alleges that defendants conspired to manipulate the spot price and basis differential of natural gas with respect to the California market allegedly enabling defendants to reap exorbitant and illicit profits by gouging natural gas purchasers. Specifically, the complaint alleges that defendants and their co-conspirators employed a variety of false reporting techniques to manipulate the published natural gas price indices. The complaint seeks unspecified amounts of damages, including a trebling of plaintiff’s and the putative class’s actual damages. We are unable at this time to predict the outcome of this dispute or the ultimate liability, if any, of West Coast Power.

The FERC has an ongoing “Investigation of Potential Manipulation of Electric and Natural Gas Prices,” which involves hundreds of parties (including our affiliate, West Coast Power) and substantial discovery. In June 2001, FERC initiated proceedings related to California’s demand for $8.9 billion in refunds from power sellers who allegedly inflated wholesale prices during the energy crisis. Hearings have been conducted before an administrative law judge who issued an opinion in late 2002. The administrative law judge stated that after assessing a refund of $1.8 billion for “unjust and unreasonable” power prices between October 2, 2000 and June 20, 2001, power suppliers were owed $1.2 billion because the State was holding funds owed to suppliers.

In August 2002, the United States Circuit Court of Appeals for the Ninth Circuit granted a request by the Electricity Oversight Board, the California Public Utilities Commission and others, to seek out and introduce to FERC additional evidence of market manipulation by wholesale sellers. This decision resulted in FERC ordering an additional 100 days of discovery in the refund proceeding, and also allowing the relevant time period for potential refund liability to extend back an additional nine months, to January 1, 2000.

2003, FERC issued an Order on Proposed Findings on Refund Liability in Docket No. EL00-95-045, or the “Refund Order,” adopting, in part, and modifying, in part, the Proposed Findings issued by Judge Birchman on December 12, 2002. In the Refund Order, FERC adopted the refund methodology in the Staff Final Report on Price Manipulation in Western Markets issued contemporaneously with the Refund Order in Docket No. PA02-2-000. This refund calculation methodology makes certain changes to Judge Birchman’s methodology, because of FERC Staff’s findings of manipulation in gas index prices. This could materially increase the estimated refund liability. The Refund Order directed generators wanting to recover any fuel costs above the mitigated market clearing price during the refund period to submit cost information justifying such recovery within 40 days of the issuance of the Refund Order, which West Coast Power did. Dynegy and the West Coast Power entities are currently engaged in settlement negotiations with FERC Staff, the California Attorney General, the California Public Utility Commission, the California Electricity Oversight Board, PG&E, and Southern California Edison.

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

On December 18, 2002, a Dynegy subsidiary, Dynegy Marketing & Trade, or “DMT,” and West Coast Power, collectively “the Respondents,” entered into a consent Offer of Settlement and Order, “the Consent Order”, with the Commodity Futures and Trading Commission, or “CFTC.” The action is captioned In re Dynegy Marketing & Trade and West Coast Power LLC, CFTC Docket No. 03-03. The CFTC asserted various violations of the Commodity Exchange Act, as well as CFTC regulations.

The CFTC alleged in the Consent Order that DMT natural gas traders reported false natural gas trading information, including price and volume information, to certain industry publications that establish and publish indexes for natural gas prices. The CFTC alleged that DMT submitted the false information in an attempt to manipulate the indexes for DMT’s benefit. The CFTC further alleged that DMT traders directed other Dynegy personnel to report each of the same false trades in the name of West Coast Power, as counterparty, in an effort to lend credence to the trades’ validity. The Respondents to the Consent Order did not admit or deny the allegations or findings made by the CFTC, but agreed to an Offer of Settlement, and agreed to pay a civil monetary fine of $5 million. The Respondents also agreed to undertakings regarding further cooperation with the CFTC and public statements concerning the Consent Order. Dynegy agreed to pay and be entirely responsible for the $5 million fine imposed by the CFTC.

The U.S. Attorney indicted two fired Dynegy traders in connection with the index reporting scheme, and is reportedly investigating other Dynegy activity and employees.

According to press reports, the U.S. Attorney in San Francisco has assembled an “energy crisis” task force. While Dynegy received a grand jury subpoena in November 2002, the scope and targets of this investigation are unknown to us. We did not receive a subpoena.

This Committee, chaired by Senator Dunn, subpoenaed records from us during the Summer of 2001. We produced about 5,000 pages of documents; Dynegy produced a much larger volume of documents. The Committee has apparently concluded its activities without issuing any reports or findings.

The CPUC continues to request data and documents in several settings. First, it is one of the parties in the FERC proceeding mentioned above. Second, inspectors have visited West Coast Power plants, usually unannounced and usually immediately following an unplanned outage. They have demanded documentation concerning the reason for the outage. Third, the CPUC has demanded documents to allow it to prepare “reports,” one of which was issued in the fall of 2002, and another of which was issued January 30, 2003. The FERC’s above-referenced March 26 Refund Order undercut the accuracy and reliability of these CPUC reports. Dynegy has made extensive productions to the CPUC of plant-related materials as well as trading data.

In addition to the litigation it has undertaken described above, the California Attorney General has undertaken an investigation entitled “In the Matter of the Investigation of Possibly Unlawful, Unfair, or Anti-Competitive Behavior Affecting Electricity Prices in California.” In this connection, the Attorney General has issued subpoenas to Dynegy, served interrogatories on Dynegy and us, and informally requested documents and interviews from Dynegy and Dynegy employees as well as us and our employees. We responded to the interrogatories in the summer of 2002, with the final set of responses being served on September 3, 2002. We have also produced a large volume of documentation relating to the West Coast Power plants. In addition, our employees in California have sat for informal interviews with representatives of the Attorney General’s office. Dynegy employees have also been interviewed.

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

Although any evaluation of the likelihood of an unfavorable outcome or an estimate of the amount or range of potential loss in the above-referenced private actions and various investigations cannot be made at this time, we note that the Gordon complaint alleges that the defendants, collectively, overcharged California ratepayers during 2000 by $4.0 billion. We cannot predict the outcome of these cases and investigations at this time.

On December 19, 2003, the Electricity Consumers Resource Council, or “ECRC,” appealed to the United States Court of Appeals for the District of Columbia Circuit a recent decision by FERC approving the implementation of a demand curve for the New York installed capacity, or “ICAP,” market. ECRC claims that the implementation of the ICAP demand curve violates section 205 of the Federal Power Act because it constitutes unreasonable ratemaking. We are a party to this appeal and will contest ECRC’s assertions, but at this time cannot assess the eventual outcome.

This matter involves a claim by CL&P for recovery of amounts it claims are owing for congestion charges under the terms of a SOS contract between the parties, dated October 29, 1999. CL&P has served and filed its motion for summary judgment to which PMI filed a response on March 21, 2003. CL&P has withheld approximately $30 million from amounts owed to PMI, claiming that it has the right to offset those amounts under the contract. PMI has counterclaimed seeking to recover those amounts, arguing among other things that CL&P has no rights under the contract to offset them. By reason of the previous bankruptcy stay, the court has not ruled on the pending motion. On November 6, 2003, the parties filed a joint stipulation for relief from the automatic stay in order to allow the proceeding to go forward. PMI cannot estimate at this time the likelihood of an unfavorable outcome in this matter, or the overall exposure for congestion charges for the full term of the contract.

This matter involves a dispute between CL&P and PMI concerning which of party is responsible, under the terms of the October 29, 1999 SOS contract, for costs related to congestion and losses associated with the implementation of standard market design, or “SMD-Related Costs.” CL&P has withheld, in addition to the $30 million discussed above, approximately $79 million from amounts owed to PMI, claiming that it is entitled under the contract to offset those additional amounts for SMD-Related Costs. The parties have now reached a settlement which was filed with FERC on March 3, 2004, whereby CL&P will pay PMI $38.4 million plus interest, and subject to adjustments and true-ups upon final approval by FERC.

In January 2002, the New York Department of Environmental Conservation, or “DEC,” sued Niagara Mohawk Power Corporation, or “NiMo,” and us in federal court in New York. The complaint asserted that projects undertaken at our Huntley and Dunkirk plants by NiMo, the former owner of the facilities, required preconstruction permits pursuant to the Clean Air Act and that the failure to obtain these permits violated federal and state laws. In July, 2002, we filed a motion to dismiss. On March 27, 2003, the court dismissed the complaint against us with prejudice as to the federal claims and without prejudice as to the state claims. It is possible the state will appeal this dismissal to the Second Circuit Court of Appeals. In the meantime, on December 31, 2003, the trial court granted the state’s motion to amend the complaint to again sue us and various affiliates in this same action in the federal court in New York, asserting against us violations of operating permits and deficient operating permits at the Huntley and Dunkirk plants. If the case ultimately is litigated to an unfavorable outcome that could not be addressed otherwise, we have estimated that the total investment that would be required to install pollution control devices could be as high as $300 million over a ten to twelve-year period. We also could be found responsible for payment of certain penalties and fines.

We have asserted that NiMo is obligated to indemnify it for any related compliance costs associated with resolution of the above enforcement action. NiMo has filed suit in state court in New York seeking a declaratory judgment with respect to its obligations to indemnify us under the asset sales agreement. We have pending a summary judgment motion on its entitlement to be reimbursed by NiMo for the attorneys’ fees we have incurred in the enforcement action.

The DEC has alleged violations by the Huntley Generating Station, the Dunkirk Generating Station and the Oswego Generating Station with respect to opacity exceedances. The above entities have been engaged in consent order negotiations with the DEC relative to such opacity issues affecting all three facilities since the plants were acquired. In late February, 2004 we signed a proposed final version of the consent order, which, if executed and thereby issued by the DEC, would quantify the number of opacity exceedances at the three facilities through the second quarter of 2003 and assess a cumulative penalty of $1 million. In addition, among other provisions, the consent order would establish stipulated penalties for future violations of opacity requirements and of the consent order and would impose a Schedule of Compliance. In the event that the consent order is not issued by DEC in the form to which we agreed to by the six entities and any subsequent negotiations prove unsuccessful, it is not known what relief the DEC will seek through an enforcement action and what the result of such action will be.

On April 30, 2003, the Huntley Station submitted a self-disclosure letter to the DEC reporting violations of applicable sulfur in fuel limits, which had occurred during 6 days in March, 2003 at the chimney stack serving Huntley Units 63-66. The Huntley Station self-disclosed that the average sulfur emissions rates for those days had been 1.8 lbs/mm BTU, rather than the maximum allowance of 1.7 lbs/mm BTU. NRG Huntley Operations discontinued use of Unit 65 (the only unit utilizing the subject stack at the time) and has kept the remaining three units off line until adherence with the applicable standard is assured. On May 19, 2003, the DEC issued Huntley Power LLC a Notice of Violation. Huntley Power LLC has met with the DEC to discuss the circumstances surrounding the event and the appropriate means of resolving the matter. Huntley Power LLC does not know what relief the DEC will seek through an enforcement action. Under applicable provisions of the Environmental Conservation Law, the DEC asserts that it may impose a civil penalty up to $10,000, plus an additional penalty not to exceed $10,000 for each day that a violation continues and may enjoin continuing violations.

On October 2, 2000, plaintiff NiMo commenced this action against us to recover damages plus late fees, less payments received through the date of judgment, as well as any additional amounts due and owing, for electric service provided to the Dunkirk Plant after September 18, 2000. Plaintiff NiMo claims that we have failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999 and continuing to September 18, 2000 and thereafter. Plaintiff has alleged breach of contract, suit on account, violation of statutory duty and unjust enrichment claims. On or about October 23, 2000, we served an answer denying liability and asserting affirmative defenses.

After proceeding through discovery, and prior to trial, the parties and the court entered into a Stipulation and Order filed August 9, 2002 consolidating this action with two other actions against Our Huntley and Oswego subsidiaries, both of which cases assert the same claims and legal theories for failure to pay retail tariffs for utility services at those plants.

On October 8, 2002, a Stipulation and Order was filed in the Erie County Clerk’s Office staying this action pending submission to FERC of some or all of the disputes in the action. We cannot make an evaluation of the likelihood of an unfavorable outcome. The cumulative potential loss could exceed $35 million.

Niagara Mohawk Power Corporation v. Huntley Power LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC, and NRG Oswego

This is the companion action filed by NiMo at FERC, similarly asserting that NiMo is entitled to receive retail tariff amounts for electric service provided to the Huntley, Dunkirk and Oswego plants. On October 31, 2003, the FERC Trial Staff, a party to the proceedings, filed a reply brief in which it supported and agreed with each position taken by our facilities. In short, the staff argued that our facilities: (1) self-supply station power under the NYISO tariff (which took effect on April 1, 2003) in any month during which they produce more energy than they consume and, as such, should not be assessed a retail rate; (2) are connected only to transmission facilities and, as such, at most should only pay NiMo a FERC-approved transmission rate; and (3) should be allowed to net consumption and output even if power is injected into the grid at a different point from which it is drawn off. We are presently awaiting a ruling by FERC. At this stage of the proceedings, we cannot estimate the likelihood of success on this action. As noted above, the cumulative potential loss could exceed $35 million.

During 2000, DEQ issued a Part 70 Air Permit modification to Louisiana Generating to construct and operate two 240 MW natural gas-fired turbines. The Part 70 Air Permit set emissions limits for the criteria air pollutants, including NO_x, based on the application of Best Available Control Technology, or “BACT.” The BACT limitation for NO_x was based on the guarantees of the manufacturer, Siemens-Westinghouse. Louisiana Generating sought an interim emissions limit to allow Siemens-Westinghouse time to install additional control equipment. To establish the interim limit, DEQ issued a Compliance Order and Notice of Potential Penalty, No. AE-CN-02-0022, on September 8, 2002, which is, in part, subject to the referenced administrative hearing. DEQ alleged that Louisiana Generating did not meet its NO_x emissions limit on certain days, did not conduct all opacity monitoring and did not complete all record keeping and certification requirements. Louisiana Generating intends to vigorously defend certain claims and any future penalty assessment, while also seeking an amendment of its limit for NO_x. An initial status conference was held with the Administrative Law Judge and quarterly reports are being submitted to that judge to describe progress, including settlement and amendment of the limit. In late February 2004, we timely submitted to the DEQ an amended BACT analysis and amended Prevention of Significant Deterioration and Title V permit application to amend the NO_x limit. In addition, Louisiana Generating may assert breach of warranty claims against the manufacturer. With respect to the administrative action described above, at this time we are unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which we may be subject.

During 2002, NRG Sterlington conducted a review of the Sterlington Power Facility’s Part 70 Air Permit obtained by the facility’s former owner and operator, Koch Power, Inc. Koch had outlined a plan to install eight 25 MW capacity turbines to reach a 200 MW capacity limit in the permit. Due to the inability of several units to reach their nameplate capacity, Koch determined that it would need additional units to reach the electric output target. In August 2000, NRG Sterlington acquired the remaining interests in the facility not originally held on a passive basis and sought the transfer of the Part 70 Air Permit along with a modification to incorporate two 17.5 MW turbines installed by Koch and to increase the total number of turbines to ten. The permit modification was issued February 13, 2002. During further review, NRG Sterlington determined that a ninth unit had been installed prior to issuance of the permit modification. In keeping with its environmental policy, it disclosed this matter to DEQ in April, 2002. NRG Sterlington provided to DEQ additional information during July 2002. A Consolidated Compliance Order & Notice of Potential Penalty, No. AE-CN-01-0393, was issued by DEQ on September 10, 2003, wherein DEQ formally alleged that NRG Sterlington did not complete all certification requirements, and installed a ninth unit prior to issuance of its permit modification. We met with DEQ on November 19, 2003 to discuss mitigating circumstances and a settlement has been agreed to between the parties. Under the settlement agreement, without admitting any

On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the Clean Air Act from the EPA seeking information primarily relating to physical changes made at Big Cajun II in 1994 and 1995 by the predecessor owner of that facility. Louisiana Generating, LLC and Big Cajun II intend to respond to the EPA request in an appropriate and cooperative manner. At the present time, we cannot predict the probable outcome in this matter.

We and/or our affiliates have entered into several turbine purchase agreements with affiliates of General Electric Company, or “GE,” and Siemens Westinghouse Power Corporation, or “Siemens.” GE and Siemens have notified us that we are in default under certain of those contracts, terminated such contracts, and demanded that we pay the termination fees set forth in such contracts. GE’s claim amounts to approximately $113 million and Siemens’ approximately $45 million in cumulative termination charges. We cannot estimate the likelihood of unfavorable outcomes in these disputes.

Our indirectly controlled Brazilian project company, Itiquira Energetica S.A., the owner of a 156 MW hydro project in Brazil, is currently in arbitration with the former EPC contractor for the project, Inepar Industria e Construcoes, or “Inepar.” The dispute was commenced by Itiquira in September of 2002 and pertains to certain matters arising under the former EPC contract. Itiquira principally asserts that Inepar breached the contract and caused damages to Itiquira by (i) failing to meet milestones for substantial completion; (ii) failing to provide adequate resources to meet such milestones; (iii) failing to pay subcontractors amounts due; and (iv) being insolvent. Itiquira’s arbitration claim is for approximately U.S. $40 million. Inepar has asserted in the arbitration that Itiquira breached the contract and caused damages to Inepar by failing to recognize events of force majeure as grounds for excused delay and extensions of scope of services and material under the contract. Inepar’s damage claim is for approximately U.S. $10 million. The parties submitted their respective statements of claims, counterclaims and responses, and a preliminary arbitration hearing was held on March 21, 2003. In lieu of taking expert testimony at hearing, the court of arbitration ordered an expert investigation process to cover technical and accounting issues. We anticipate that the final report from the expert investigation process will be delivered to the court of arbitration in the last week of March, 2004. After reviewing the final report, the court of arbitration may, if it deems it necessary, require expert testimony on technical and accounting issues, which we anticipate would commence on approximately May 15, 2004. We expect the arbitration panel to issue its decision no later than July 31, 2004. We cannot estimate the likelihood of an unfavorable outcome in this dispute.

On June 17, 2002, the CFTC served Xcel Energy, on behalf of its affiliates, which then included us and PMI, with a subpoena requesting certain information regarding “round trip” or “wash” trading and general trading practices in its investigation of several energy trading companies. The CFTC now appears focused on possible efforts by traders to submit false reports to index publications in an attempt to manipulate the index. In January, 2004, the CFTC and Xcel Energy’s subsidiary, e prime, inc., reached a settlement in connection with this investigation, which included the payment of a $16 million fine and the entry of a cease and desist order. Other industry participants that have settled with the CFTC have paid fines of between $1.5 million and $30 million and have agreed to the terms of cease and desist orders. The CFTC has requested additional related information from us and has subpoenaed to appear for testimony a number of our present and former employees. We have sought to cooperate with the CFTC and have submitted materials responsive to the

In addition to the foregoing, we are parties to other litigation or legal proceedings, which may or may not be material. There can be no assurance that the outcome of such matters will not have a material adverse effect on our business, financial condition or results of operations.

As part of the NRG plan of reorganization, we have funded a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the plan. Under the terms of the plan, to the extent such claims are resolved now that we have emerged from bankruptcy, the claimants will be paid from the reserve on the same basis as if they had been paid out in the bankruptcy. That means that their allowed claims will be reduced to the same recovery percentage as other creditors would have received and will be paid in pro rata distributions of cash and common stock. We believe we have funded the disputed claims reserve at a sufficient level to settle the remaining unresolved proofs of claim we received during the bankruptcy proceedings. However, to the extent the aggregate amount of these payouts of disputed claims ultimately exceeds the amount of the funded claim reserve, we are obligated to provide additional cash and common stock to the claimants. We will continue to monitor our obligation as the disputed claims are settled. However, if excess funds remain in the disputed claims reserve after payment of all obligations, such amounts will be reallocated to the Creditor Pool. We have provided our common stock and cash contribution to an escrow agent to complete the distribution and settlement process. Since we have surrendered control over the common stock and cash provided to the disputed claims reserve, we recognized the issuance of the common stock as of December 5, 2003 and removed the cash amounts from our balance sheet. Similarly, we have moved the obligations relevant to the claims from our balance sheet when the common stock was issued and cash contributed.

In connection with the consummation of the NRG plan of reorganization, on December 5, 2003 all shares of our old common stock were canceled and 100,000,000 shares of new common stock of NRG Energy were distributed pursuant to such plan to the holders of certain classes of claims. A certain number of shares of common stock was issued for distribution to holders of disputed claims as such claims are resolved or settled. In the event our disputed claims reserve is inadequate, it is possible we would have to issue additional shares of our common stock to satisfy such pre-petition claims or contribute additional cash proceeds. See Item 3 — Legal Proceedings — Disputed Claims Reserve. Our authorized capital stock consists of 500,000,000 shares of NRG Energy common stock and 10,000,000 shares of Serial Preferred Stock. Further, a total of 4,000,000 shares of our common stock, representing approximately 4% of our outstanding common stock, are available for issuance under our long-term incentive plan.

Our new common stock currently trades in the over-the-counter market and has been assigned the symbol NRGE.OB. The high and low sales prices for our new common stock since issuance on December 5, 2003 through March 9, 2004, are:

Over-the-counter market quotations reflect inter-dealer prices, without retail markup, mark-down or commission and may not necessarily represent actual transactions.

From June 2, 2002 through December 5, 2003, Xcel Energy Wholesale Group, Inc. held all shares of our old common stock. During the period from May 31, 2000 through June 3, 2002, our then outstanding common stock was traded principally on the New York Stock Exchange.

We have not declared or paid dividends on our new common stock, and the payment of dividends is currently prohibited by our credit agreements.

The NRG Energy, Inc. long-term incentive plan became effective upon our emergence from bankruptcy. The Long-Term Incentive Plan was not approved by security holders as it was adopted in connection with the NRG plan of reorganization. The long-term incentive plan provides for grants of stock options, stock appreciation rights, restricted stock, performance awards, deferred stock units and dividend equivalent rights. Our directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by us, are eligible to receive grants under the long-term incentive plan. A total of 4,000,000 shares of our common stock, representing approximately 4% of our outstanding common stock, are available for issuance under the long-term incentive plan. The purpose of the long-term incentive plan is to promote our long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to our success and to enable us to attract, retain and reward the best available persons for positions of responsibility. The compensation committee of our board of directors will administer the long-term incentive plan.

Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

All of our outstanding common stock was issued pursuant to the NRG plan of reorganization on December 5, 2003 in accordance with Section 1145 of the bankruptcy code. We received no proceeds from such issuance.

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

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

Energy and energy related revenue consists of revenues received upon the physical delivery of electrical energy to a third party at both spot (merchant sales) and contracted rates. In addition, we also generate revenues from the sale of ancillary services and by entering into certain financial transactions. Ancillary revenues are derived from the sale of energy related products associated with the generation of electrical energy such as spinning reserves, reactive power and other similar products. Revenues derived from financial transactions are generally received upon the settlement of transactions relating to the sale of energy or fuel which do not require the physical delivery of the underlying commodity.

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

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

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

Other revenues consist of miscellaneous other revenues derived from the sale of natural gas, recovery of incurred costs under reliability agreements and revenues received under leasing arrangements.

We are 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, which help us mitigate risk. We intend 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 do not anticipate any significant new acquisitions or construction in the near future, and instead will focus on operational performance, asset management and debt reduction. We have already made significant reductions in capital expenditures, business development activities and personnel. Power sales, fuel procure-

Industry Trends. In this “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we discuss our historical results of operations and expected financial condition. During 2002 and 2003, the following factors, among others, have negatively affected our results of operations:


	•	weak markets for electric energy, capacity and ancillary services;

	•	a narrowing of the “spark spread” (the difference between power prices and fuel costs) in most regions of the United States in which we operate power generation facilities;

	•	mild weather during peak seasons in regions where we have significant merchant capacity;

	•	reduced liquidity in the energy trading markets as a result of fewer participants trading lower volumes;

	•	the imposition of price caps and other market mitigation in markets where we have significant merchant capacity;

	•	regulatory and market frameworks in certain regions where we operate that prevent us from charging prices that will enable us to recover our operating costs and to earn acceptable returns on capital;

	•	the obligation to perform under certain long-term contracts that are not profitable;

	•	physical, regulatory and market constraints on transmission facilities in certain regions that limit or prevent us from selling power generated by certain of our facilities; and

	•	limited access to capital due to our financial condition since July 2002 and the resulting contraction of our ability to conduct business in the merchant energy markets.

We expect that these generally weak market conditions will continue for the foreseeable future in some markets. Historically, we have believed that, as supply surpluses begin to tighten and as market rules and regulatory conditions stabilize, prices will improve for energy, capacity and ancillary services. This view is consistent with our belief that in the long run market prices will support an adequate rate of return on the construction of new power generation assets needed to meet increasing demand. This view is currently being challenged in certain markets as regulatory actions and market rules unfold that limit the ability of merchant power companies to earn favorable returns on existing and new investments. To the extent unfavorable regulatory and market conditions exist in the long term, we could have significant impairments of our property, plant and equipment, which, in turn, could have a material adverse effect on our results of operations. Further, this could lead to us closing certain of our facilities resulting in additional economic losses and liabilities.

Asset Sales. As part of our strategy, we plan to continue the selective divestment of certain assets. Since July 2002, we have sold or made arrangements to sell a number of assets and equity investments. In addition, we are currently marketing our interest in certain other non strategic assets.

Discontinued Operations. We have classified certain business operations, and gains/losses recognized on sale, as discontinued operations for projects that were sold or have met the required criteria for such classification pending final disposition. Accounting regulations require that continuing operations are reported separately in the income statement from discontinued operations, and that any gain or loss on the disposition of any such business be reported along with the operating results of such business. Assets classified as “discontinued operations” on our balance sheet as of December 31, 2003 include McClain. For the periods January 1, 2003 through December 5, 2003, discontinued results of operations include our Killingholme, McClain, NEO Landfill Gas, Inc., NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, Timber Energy Resources, Inc., Cahua and Energia Pacasmayo projects. All prior periods presented have been restated accordingly. For the period December 6, 2003 through December 31, 2003, discontinued results of operations included McClain.

New Management. On October 21, 2003, we announced the appointment of David Crane as our new President and Chief Executive Officer, effective December 1, 2003. Before joining us, Mr. Crane served as the Chief Executive Officer of London-based International Power PLC and has over 12 years of energy industry

experience. On March 11, 2004 we announced the appointment of Robert Flexon as Executive Vice President and Chief Financial Officer, effective March 29, 2004. Before joining us Mr. Flexon served as Vice President, Work Processes, Corporate Resources and Development at Hercules, Inc. In addition, we have filled several other senior and middle management positions over the last 12 months. Our board of directors currently is comprised of Mr. Crane and ten other independent individuals, three of whom have been designated by MatlinPatterson.

Independent Public Accountants; Audit Committee. PricewaterhouseCoopers LLP has been our independent auditor since 1995. Our new board of directors has appointed an audit committee consisting entirely of independent directors. Pursuant to the charter, the committee appoints, retains, oversees, evaluates, compensates and terminates on its sole authority our independent auditors and approves all audit engagements, including the scope, fees and terms of each engagement. The audit committee’s oversight process is intended to ensure that we will continue to have high-quality, cost-efficient independent auditing services.

Due to the adoption of Fresh Start as of December 5, 2003, Reorganized NRG’s balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with, and are therefore generally not comparable to those of the Predecessor Company prior to the application of Fresh Start. In accordance with SOP 90-7, Reorganized NRG’s balance sheet, statement of operations and statement of cash flows have been presented separately from those of the Predecessor Company.

Reorganized NRG’s revenues from majority-owned operations, operating costs and expenses, general, administrative and development expenses, write-downs and losses on sales of equity method investments, restructuring and impairment charges and legal settlement costs were not significantly affected by the adoption of Fresh Start. Therefore, the Predecessor Company’s 2003 amounts have been combined with Reorganized NRG’s 2003 amounts for comparison and analysis purposes herein.

Reorganized NRG’s net loss, equity in earnings of unconsolidated affiliates, depreciation and amortization, other income (expense), income taxes and discontinued operations were affected by the adoption of

During the period January 1, 2003 through December 5, 2003, we recorded net income of $2.8 billion. Net income for the period is directly attributable to our emerging from bankruptcy and adopting the Fresh Start provisions of SOP 90-7. Upon the confirmation of our Plan of Reorganization and our emergence from bankruptcy we were able to remove significant amounts of long-term debt and other prepetition obligations from our balance sheet. Accordingly, as part of net income from continuing operations, we recorded a net gain of $3.9 billion as the impact of our adopting Fresh Start in our statement of operations, $6.0 billion of this amount is directly related to the forgiveness of debt and settlement of substantial amounts of our pre-petition obligations upon our emergence from bankruptcy. In addition to the removal of substantial amounts of pre-petition debt and other obligations from our balance sheet, we have also revalued our assets and liabilities to fair value, accordingly we have substantially written down the value of our fixed assets. We have recorded a net $1.7 billion charge related to the revaluation of our assets and liabilities within the Fresh Start Reporting adjustment line of our consolidated statement of operations. In addition to our recording adjustments related to our emergence from bankruptcy, we also recorded substantial charges related to other items such as the settlement of certain outstanding litigation in the amount of $462.6 million, write downs and losses on the sale of equity investments of $147.1 million, advisor cost and legal fees directly attributable to our being in bankruptcy of $197.8 million and $237.6 million of other asset impairment and restructuring costs incurred prior to our filing for bankruptcy. Net income for the period January 1, 2003 through December 5, 2003 was also favorably impacted by our not recording interest expense on substantial amounts of corporate level debt while we were in bankruptcy and by the continued favorable results experienced by our equity investments.

During the year ended December 31, 2002, we recognized a net loss of $3.5 billion. The loss from continuing operations incurred during 2002 primarily consisted of $2.7 billion of other charges consisting primarily of asset impairments.

During the period December 6, 2003 through December 31, 2003, we recognized net income of $11.0 million or $0.11 per share of common stock. Net income was directly attributable to a number of factors some of which are discussed below. From an overall operational perspective our facilities were profitable during this period. Our results were adversely impacted by our having to continue to satisfy the standard offer service contract that we entered into with Connecticut Light & Power, or “CL&P” in 2000. As a result of our inability to terminate this contract during our bankruptcy proceeding we continued to be exposed to losses under this contract. These losses were incurred, as we were unable to satisfy the requirements of this contract

at a price/cost below the contracted sales price. Upon our adoption of Fresh Start, we recorded at fair value, all assets and liabilities on our opening balance sheet and accordingly we recorded as an obligation the fair value of the CL&P contract. During the period December 6, 2003 through December 31, 2003, we recognized as revenues, the entire fair value of this contract effectively offsetting the actual losses incurred under this contract. The CL&P contract terminated on December 31, 2003.

Our operating revenues from majority owned operations were $2.1 billion in 2003, compared to $2.1 billion in the prior year, an increase of $1.3 million or less than 1%.

Revenues from majority owned operations of $2.1 billion for the year 2003, includes $1.1 billion of energy revenues, $649.1 million of capacity revenues, $192.8 million of alternative energy, $15.3 of O&M fees and $153.5 million of other revenues which include financial and physical gas sales, sales from our Schkopau facility and NEPOOL expense reimbursements. The increase of $1.3 million is due to increased capacity revenues resulting from additional projects becoming operational in the later part of 2002, higher sales in New York, and by our recognizing, as additional revenues, the fair value of the out-of-market CL&P contract upon our emergence from bankruptcy. Offsetting these increases, we continued to recognize losses on the CC&P contract throughout 2003 resulting from higher market prices and lower generation.

Our cost of majority owned operations related to continuing operations was $1.6 billion in 2003, compared to $1.4 billion for 2002, an increase of $113.0 million or 7.8%. For 2003 and 2002, cost of majority owned operations represented 73.3% and 68.0% of revenues from majority owned operations, respectively. Cost of majority owned operations, consists primarily of cost of energy (primarily fuel costs), labor, operating and maintenance costs and non income based taxes related to our majority owned operations.

For the year 2003, cost of energy was $956.4 million compared to $965.7 million for 2002, representing a decrease of $9.3 million. As a percent of revenue from majority owned operations, cost of energy was 45.1% and 45.6%, for 2003 and 2002, respectively. This decrease was a result of an overall decrease in the cost of fuel during 2003 and a favorable change in the fair value of our energy related derivatives resulting from contract terminations. Offsetting this decrease are liquidated damages of $72.9 million triggered from our financial condition.

Our depreciation and amortization expense related to continuing operations was $245.9 million for the period January 1, 2003 through December 5, 2003 and $240.7 for the year ended December 31, 2002. Depreciation and amortization consists of the allocation of our historical depreciable fixed asset costs over the remaining lives of such property as well as the amortization of certain contract based intangible assets.

Our depreciation and amortization expense related to continuing operations was $13.0 million for the period December 6, 2003 through December 31, 2003. Depreciation and amortization consists of the allocation of our newly valued basis in our fixed assets over newly determined remaining fixed asset lives. As part of adopting the Fresh Start concepts of SOP 90-7 our tangible fixed assets were recorded at fair value as determined by a third party valuation expert who we also consulted with in determining the appropriate remaining lives for our tangible depreciable property. Depreciation expense for this period was based on preliminary depreciable lives and asset balances.

Our general, administrative and development costs for 2003 were $192.0 million compared to $226.2 million for 2002, a decrease of $34.1 million or 15.1%. For 2003 and 2002, general, administrative and development costs represent 9.1% and 10.7% of revenues from majority owned operations, respectively. This decrease is due to decreased costs related to work force reduction efforts, cost reductions due to the closure of certain international offices and reduced legal costs. Outside services also decreased, due to less non-restructuring legal activities.

During the year 2003, we recorded other credits of $3.0 billion, which consisted primarily of $228.9 million related to asset impairments, $462.6 million related to legal settlements and $197.8 million related to reorganization charges and $8.7 million related to restructuring charges. We also incurred a $3.9 billion credit related to Fresh Start adjustments. During 2002, we recorded other charges of $2.7 billion, which consisted primarily of $2.6 billion related to asset impairments and $111.3 million related to restructuring charges.

We review the recoverability of our long-lived assets on a periodic basis and if we determined that an asset was impaired, we compared asset-carrying values to total future estimated undiscounted cash flows. Separate analyses are completed for assets or groups of assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The estimates of future cash flows included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of our assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service are based on the asset’s existing service potential. The cash flow estimates may include probability weightings to consider possible alternative courses of action and outcomes, given the uncertainty of available information and prospective market conditions.

If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to write down the asset to its fair value. Estimates of fair value were based on prices for similar assets and present value techniques. Fair values determined by similar asset prices reflect our current estimate of recoverability from expected marketing of project assets. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated future project operating costs, and expected plant operation given assumed market conditions.

Impairment charges (credits) included the following for the year ended December 31, 2002 and for the period January 1, 2003 to December 5, 2003 and the period December 6, 2003 through December 31, 2003.

For the period from January 1, 2003 to December 5, 2003, we incurred $197.8 million in reorganization costs and for the period from December 6, 2003 to December 31, 2003 we incurred $2.5 million in reorganization costs. All reorganization costs have been incurred since we filed for bankruptcy in May 2003. The following table provides the detail of the types of costs incurred (in thousands):

We incurred total restructuring charges of approximately $111.3 million for the year ended December 31, 2002. These costs consisted of employee separation costs and advisor fees. We incurred an additional $8.7 million of employee separation costs and advisor fees during 2003 until we filed for bankruptcy in May 2003. Subsequent to that date we recorded all advisor fees as reorganization costs.

During 2003, we recorded $396.0 million in connection with the resolution of the FirstEnergy Arbitration Claim. As a result of this resolution, FirstEnergy retained ownership of the Lake Plant Assets and received an allowed general unsecured claim of $396 million under the NRG plan of reorganization submitted to the bankruptcy court.

In November 2003, we settled various litigation with Fortistar Capital in which Fortistar Capital released us from all litigation claims in exchange for a $60.0 million pre-petition claim and an $8.0 million post-petition claim. We had previously recorded $10.8 million in connection with various legal disputes with Fortistar Capital; accordingly, we recorded an additional $57.2 million during November 2003.

In August of 1995, we entered into a Marketing, Development and Joint Proposing Agreement or “the Marketing Agreement”, with Cambrian Energy Development LLC, or “Cambrian.” Various claims had arisen in connection with this Marketing Agreement. In November 2003, we entered into a Settlement Agreement with Cambrian where we agreed to transfer our 100% interest in three gasco projects (NEO Ft. Smith, NEO Phoenix and NEO Woodville) and our 50% interest in two genco projects (MM Phoenix and MM Woodville) to Cambrian. In addition, we agreed to pay approximately $1.8 million in settlement of royalties incurred in connection with the Marketing Agreement. We had previously recorded a liability for royalties owed to Cambrian, therefore, we recorded an additional $1.4 million during November 2003.

In November 2003, we settled our dispute with Dick Corporation in connection with Meriden Gas Turbines, which resulted in our recording an additional liability of $8.0 million in November, 2003.

During the fourth quarter of 2003, we recorded a credit of $3.9 billion in connection with fresh start adjustments as discussed in Item 15 — Note 3. Following is a summary of the significant effects of the reorganization and Fresh Start:

During the period January 1, 2003 through December 5, 2003, we recorded other expense of $327.4 million. Other expense consisted primarily of $360.4 million of interest expense and $147.1 million of write downs and losses on sales of equity method investments, partially offset by equity in earnings of unconsolidated affiliates of $170.9 million and $11.4 million of other income.

For the year ended December 31, 2002, other expenses was $590.3 million, which consisted primarily of $487.2 million of interest expense and $200.5 million of write downs and losses on sales of equity method investments.

Interest expense for the period January 1, 2003 through December 5, 2003 of $360.4 million consisted of interest expense on both our project and corporate level interest bearing debt. In addition, interest expense includes the amortization of debt issuance costs and any interest rate swap termination costs. Subsequent to our entering into bankruptcy we ceased the recording of interest expense on our corporate level debt as these prepetition claims were deemed to be impaired and subject to compromise. We did not however cease to record interest expense on the project level debt outstanding at our Northeast Generating and South Central Generating facilities even though these entities were also in bankruptcy as these claims were deemed to be most likely not impaired and not subject to compromise. We also recorded substantial amounts of fees and costs related to our acquiring a debtor in possession financing arrangement while we were in bankruptcy. In addition, upon our emergence from bankruptcy we wrote off any remaining deferred finance costs related to our corporate and project level debt including our Northeast and South Central project level debt as it was probable that they would be refinanced upon our emergence from bankruptcy.

As we periodically review our equity method investments for impairments we have taken substantial write-downs and losses on sales of equity method investments during the period January 1, 2003 through December 5, 2003 and for the year 2002. In 2003 we recorded impairments and losses on the sales of investments of $147.1 million compared to $200.5 million in 2002. The $147.1 million recorded in 2003 consists of the write down of our investment in the Loy Yang project of $146.4 million and our investment in the NEO Corporation — Minnesota Methane project of $12.3 million during 2003. These losses were partially

offset by gains on the sale of our investment in the ECKG and Mustang projects. During 2002 we recorded write-downs and losses on sales of equity method investments of $200.5 million. The $200.5 million recorded in 2002 consists of a write down of our investment in the Loy Yang project of $111.4 million, a loss of $48.4 million on the transfer of our interest in the Sabine River Works project to our partner, a $14.2 million write down related to our investment in our EDL project, a write down of our investment in our Kondapalli project of $12.7 million and a write down of our investment in NEO Corporation — Minnesota Methane and MM Biogas of $12.3 million and $3.3 million, respectively among others. See Item 15 — Note 7 to the Consolidated Financial Statements for additional information.

During the period January 1, 2003 through December 5, 2003, minority interest in (earnings)/losses of consolidated subsidiaries was $(2.2) million, compared to $20.3 million, an increase of $22.5 million, as compared to 2002. The increase is primarily due to favorable results at PERC.

Other income (expense) for the period December 6, 2003 through December 31, 2003, was an expense of $6.7 million and consisted primarily of $21.6 million of interest expense, partially offset by $13.5 million of equity earnings from unconsolidated subsidiaries.

Interest expense for the period December 6, 2003 through December 31, 2003 of $21.6 million consists primarily of interest expense at the corporate level, primarily related to the newly issued high yield notes, term loan facility and revolving line of credit used to refinance certain project level financings. In addition, interest expense includes the amortization of deferred financing costs incurred as a result of our refinancing efforts and the amortization of discounts and premiums recorded upon the marking of our debt to fair value upon our adoption of the Fresh Start provision of SOP 90-7.

During the period January 1, 2003 through December 5, 2003, we recorded $170.9 million of equity earnings from investments in unconsolidated affiliates. Our 50% investment in West Coast Power comprised $98.7 million of this amount with our investments in the Mibrag, Loy Yang, Gladstone and Rocky Road projects comprising $21.8 million, $17.9 million, $12.4 million and $6.9 million, respectively, with the remaining amounts attributable to various domestic and international equity investments. Our investment in West Coast Power continues to generate favorable earnings as well as our investments in Mibrag, Loy Yang, Gladstone and Rocky Road. For the year ended December 31, 2002, equity earnings from investments in unconsolidated affiliates was $69.0 million.

Equity in earnings of unconsolidated affiliates of $13.5 million consists primarily of equity earnings from our 50% ownership in West Coast Power of $9.3 million.

As of December 5, 2003, we classified as discontinued operations the operations and gains/losses recognized on the sales of projects that were sold or were deemed to have met the required criteria for such classification pending final disposition. For the period January 1, 2003 through December 5, 2003, discontinued operations consist of the historical operations and net gains/losses related to our Killingholme, McClain, NLGI, NEO Corporation projects, TERI, Cahua and Energia Pacasmayo projects. Discontinued operations for the year ended December 31, 2002 consisted of our Crockett Cogeneration, Entrade, Killingholme, Csepel, Bulo Bulo, McClain, NLGI and TERI, Cahua and Energia Pacasmayo projects.

For the period January 1, 2003 through December 5, 2003, the results of operations related to such discontinued operations was a net gain of $15.7 million. The reason for the gain recognized during the period January 1, 2003 through December 5, 2003, was the completion of the sale of our interest in Killingholme resulting in a net gain of $191.2 million, offset by the loss on the sale of our Peru projects, impairment charges recorded at McClain and NLGI.

During 2002 we recognized a loss on discontinued operations of $500.8 million due to asset impairments recorded at Killingholme, NLGI and TERI projects.

Discontinued operations for the period December 6, 2003 through December 31, 2003 is comprised of a gain of $0.5 million attributable to the on going operations of our McClain project.

Income tax (benefit)/expense for the period January 1, 2003 through December 5, 2003 was a tax expense of $16.6 million as compared to a tax benefit of ($164.4) million for the year ended December 31, 2002. The income tax expense for the period ended December 5, 2003 was primarily due to separate company income tax liabilities and an increase in the valuation allowance against deferred tax assets. An additional valuation allowance of $33 million was recorded against deferred tax assets of NRG West Coast as a result of its conversion from a corporation to a single member limited liability company (a disregarded entity for federal income tax purposes).

The effective income tax rate for the period January 1, 2003 through December 5, 2003 is relatively low since the U.S. net operating loss carryforwards are offset by the cancellation of debt income resulting from the Bankruptcy. The income tax benefit for the year ended December 31, 2002 was primarily due to the increase in deferred tax assets relating to impairments recognized for financial reporting purposes. A valuation allowance was increased limiting the recognition of deferred tax assets to the extent of previously-recorded deferred tax liabilities.

Income taxes have been recorded on the basis that our U.S. subsidiaries and we will file separate federal income tax returns for the period January 1, 2003 through December 5, 2003. Since our U.S. subsidiaries and we will not be included in the Xcel Energy consolidated tax group, each of our U.S. subsidiaries that is classified as a corporation for U.S. income tax purposes must file a separate federal income tax return. It is uncertain if, on a stand-alone basis, we would be able to fully realize deferred tax assets related to net operating losses and other temporary differences, therefore a full valuation allowance has been established.

Income tax (benefit)/expense for the period December 6, 2003 through December 31, 2003 was a tax benefit of ($0.7) million which consists of a U.S. tax benefit of ($1.5) million and foreign tax expense of $0.8 million. The foreign tax expense for the period is due to earnings in the foreign jurisdictions.

Our U.S. subsidiaries and we will file a consolidated federal income tax return for the period December 6, 2003 through December 31, 2003. With the exception of alternative minimum tax, or “AMT”, we anticipate that our cash tax rate for the next 5 years will be relatively low as we realize the cash tax benefits from using our net operating loss carryforwards. For AMT purposes, utilization of net operating losses is limited on an annual basis.

Due to the uncertainty of realization of deferred tax assets related to net operating losses and other temporary differences, the change in U.S. current and deferred income taxes has been fully offset by a change in the valuation allowance and our U.S. net deferred tax assets at December 31, 2003 were offset by a full valuation allowance in accordance with SFAS 109. Regarding the valuation allowance as of December 5, 2003, SOP 90-7 requires any future benefits from reducing the valuation allowance from preconfirmation net

operating loss carryforwards be reported as a direct addition to paid-in-capital versus a benefit on our income statement. Consequently, our effective tax rate in post Bankruptcy emergence years will not benefit from utilization of our net operating loss carryforwards which were fully valued as of the date of our emergence from Bankruptcy.

During the year ended December 31, 2002, we recognized a net loss of $3.5 billion. This loss represented a decrease in earnings of $3.7 billion compared to net income of $265.2 million for the same period in 2001. Our loss from continuing operations was $3.0 billion for the year ended December 31, 2002 compared to net income of $222.0 million from continuing operations for the same period in 2001. The loss from continuing operations incurred during 2002 primarily consists of $2.7 billion of other charges consisting primarily of asset impairments.

During 2002, our continuing operations experienced less favorable results than those experienced during the same period in 2001. Overall, our domestic power generation operations performed poorly compared to the same period in 2001. Our domestic operations experienced reductions in domestic energy and capacity sales and an overall decrease in power pool prices and related spark spreads (the monetary difference between the price of power and fuel cost). During the fourth quarter of 2002, an additional reserve for uncollectible receivables in California was established by West Coast Power, the California joint venture of which we own 50%, which reduced our equity in the earnings of that joint venture by approximately $58.5 million on a pre-tax basis. In addition, West Coast Power’s results were already less than those recorded in 2001 due to less favorable contracts and reductions in sales of energy and capacity. In addition, increased administrative costs, depreciation and interest expense from completed construction costs also contributed to the less than favorable results in 2002. Partially offsetting these earnings reductions was the recognition, in the fourth quarter of 2002, of approximately $51.0 million of additional revenues related to the contractual termination of a power purchase agreement with our Indian River project.

During the third quarter of 2002, we experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. These events led to impairments of a number of our assets, resulting in pre-tax charges related to continuing operations of approximately $2.6 billion during 2002. In addition, approximately $200.5 million of net losses on sales and write-downs of equity method investments were recorded in 2002.

Operating results of majority-owned projects that were sold or have met the criteria to be considered as held-for-sale have been classified as discontinued operations. The period ended December 31, 2002, consisted of the historical operations and net gains/losses related to our Crockett Cogeneration, Entrade, Killingholme, Csepel, Bulo Bulo, McClain, NLGI, NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, TERI, Cahua and Energia Pacasmayo.

During 2002, we expensed approximately $111.3 million for costs related to our financial restructuring. These costs include expenses for financial and legal advisors, contract termination costs, employee separation and other restructuring activities.

Our operating revenues from majority-owned operations were $2.1 billion in 2002 compared to $2.2 billion in the prior year, a decrease of $88.8 million or approximately 4.0%. Revenues from majority-owned operations for the year ended December 31, 2002, consisted primarily of power generation revenues from domestic operations of approximately $1.6 billion in 2002 compared with $1.7 billion in 2001, a decrease

The Northeast region experienced decreased revenues, as they were significantly affected by a combination of lower capacity revenues and a decline in megawatt hour generation compared with 2001. This decline in generation is attributable to an unseasonably warm winter and cooler spring and a slowing economy, which reduced demand for electricity, together with new regulation, which reduced price volatility, particularly in New York City. The South Central region generated increased revenues primarily due to a full year of operations compared to plants acquired and completed in 2001.

Our International revenues from majority-owned operations increased by $36.3 million or 10.9% from 2001 to 2002. The Asia Pacific region reported a reduction in revenues of $9.8 million while increases were reported from Europe of $34.9 million and Latin America of $11.2 million. The reduction in Asia Pacific revenue is primarily due to a decline in energy prices and the loss of a significant contract at Flinders. The increase in Europe and Latin America revenue is primarily due to a full year of operations for acquisitions made in 2001.

For the year ended December 31, 2002, cost of majority-owned operations related to continuing operations was $1.4 billion compared to $1.4 billion for 2001, an increase of $11.2 million or approximately 0.8%. For the years ended December 31, 2002 and 2001, cost of majority-owned operations represented approximately 68.0% and 64.7% of revenues from majority-owned operations, respectively. Cost of majority-owned operations consists primarily of cost of energy (primarily fuel costs), labor, operating and maintenance costs and non-income based taxes related to our majority-owned operations.

For the year ended December 31, 2002, cost of energy was $965.7 million compared to $995.0 million for the year ended December 31, 2001. This represents a decrease of $29.3 million or 2.9%. As a percent of revenue from majority-owned operations cost of energy was 45.1% and 45.1% for the years ended December 31, 2002 and 2001, respectively.

For the year ended December 31, 2002, operating and maintenance costs were $399.0 compared to $347.4 million for the year ended December 31, 2001. This represents an increase of $51.6 million or 14.9%. As a percent of revenue from majority-owned operations, operating and maintenance costs represented 18.8% and 15.7%, for the years ended December 31, 2002 and 2001, respectively. The increase in operating and maintenance expense is primarily due to a full year of expense in 2002 related to assets acquired during 2001.

For the year ended December 31, 2002, depreciation and amortization related to continuing operations was $240.7 million, compared to $163.9 million for the year ended December 31, 2001, an increase of $76.8 million or approximately 46.9%. This increase is primarily due to the addition of property, plant and equipment related to our acquisitions of electric generating facilities completed during 2002.

For the year ended December 31, 2002, general, administrative and development costs were $226.2 million, compared to $192.1 million for the year ended December 31, 2001, an increase of $34.1 million or approximately 17.7%. For the year ended December 31, 2002 and 2001, general, administrative and development costs represent 10.7% and 8.7% of revenues from majority-owned operations, respectively. This increase is primarily due to an increase in bad debt expense. Additionally there was an increase in other general administrative expenses due to 2001 acquisitions and newly constructed facilities coming on line. These increases were partially offset by decreases in business development expenses and other reductions to costs previously incurred to support international and expanded operations.

During the third quarter of 2002, we experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. We applied the provisions of SFAS No. 144 to our construction and operational projects. We completed an analysis of the recoverability of the asset carrying values of our projects factoring in the probability of different courses of action available to us given our financial position and liquidity constraints. As a result, we determined during the third quarter that many of our construction projects and certain operational projects were impaired and should be written down to fair market value. To estimate fair value, our management considered discounted cash flow analyses, bids and offers related to those projects and prices of similar assets. During 2002, we recorded asset impairment and other special charges related to continuing operations of $2.7 billion. See Item 15 — Note 8 to the Consolidated Financial Statements for additional information.

For the year ended December 31, 2002, total other expense was $590.3 million, compared to $161.9 million for the year ended December 31, 2001, an increase of $428.4 million or approximately 264.7%. The increase in total other expense from 2001 consisted primarily of an increase in interest expense and $200.5 million of write downs and losses on sales of equity method investments combined with lower equity earnings of unconsolidated affiliates.

For the year ended December 31, 2002, we had equity in earnings of unconsolidated affiliates of $69.0 million, compared to $210.0 million for 2001, a decrease of $141.0 million or approximately 67.1%. The $141.0 million decrease in equity earnings from unconsolidated affiliates is due primarily to unfavorable results at West Coast Power in 2002 as compared to the same period in 2001. During 2002, West Coast Power had long-term contracts that were less favorable than those held in 2001. In addition during 2002, West Coast Power established reserves for certain receivables not considered recoverable from California PX. Our share of this reserve was approximately $58.5 million on a pre-tax basis.

For the year ended December 31, 2002, interest expense (which includes both corporate and project level interest expense) was $487.2 million, compared to $389.9 million in 2001, an increase of $97.3 million or approximately 25.0%. This increase is due primarily to increased corporate and project level debt. We issued substantial amounts of long-term debt at both the corporate level (recourse debt) and project level (non-recourse debt) to either directly finance the acquisition of electric generating facilities or refinance short-term bridge loans incurred to finance such acquisitions.

For the year ended December 31, 2002, minority interest in (earnings)/ losses of consolidated subsidiaries was $20.3 million, compared to $(0.8) million, a decrease of $21.1 million, as compared to 2001. This decrease is primarily due to increased earnings from COBEE for the year ended December 31, 2002.

Other income was a gain of $8.0 million, as compared to $18.8 million for the year ended December 31, 2001, a decrease of $10.8 million, or approximately 57.4%. Other income consists primarily of interest income on cash balances and realized and unrealized foreign currency exchange gains and losses. Interest income was lower during 2002 due to lower interest from affiliates, primarily related to West Coast Power. In addition, there were significant foreign currency exchange losses during 2002.

For the year ended December 31, 2002, write-downs and losses on equity method investments were $200.5 million. The $200.5 million charge consists primarily of write-downs related to our investment in Loy Yang in the total amount of $111.4 million. In addition, we recorded a loss of $48.4 million upon the transfer of our investment in SRW Cogeneration and recorded write-downs of $14.2 million and $3.6 million of our investments in EDL and Collinsville, respectively.

Income tax (benefit)/expense for the year ended December 31, 2002 was a tax benefit of ($164.4) million as compared to a tax expense of $39.1 million for the year ended December 31, 2001. The income tax benefit for the year ended December 31, 2002 was primarily due to the increase in deferred tax assets relating to impairments recognized for financial reporting purposes. A valuation allowance was increased limiting the recognition of deferred tax assets to the extent of previously recorded deferred tax liabilities. The income tax expense for the year ended December 31, 2001 was primarily due to U.S. and foreign operating earnings reduced by tax credits of $37.2 million.

For 2002, income taxes were recorded on the basis that Xcel Energy would not include us in its consolidated federal income tax return following Xcel Energy’s acquisition of our public shares on June 3, 2002. Since Xcel Energy did not include us in its consolidated federal income tax return, we and each of our U.S. subsidiaries that is classified as a corporation for U.S. income tax purposes must file separate federal income tax returns. It is uncertain if, on a stand-alone basis, we will be able to fully realize deferred tax assets related to net operating losses and other temporary differences, consequently, a valuation allowance of $1.3 billion was recorded as of December 31, 2002.

For 2001, our U.S. subsidiaries and we were included in the Xcel Energy consolidated federal income tax return through March 12, 2001, the date of our secondary public offering. For the remainder of the year, we filed a consolidated federal return with our U.S. subsidiaries. Income tax expense was recorded on current and deferred tax liabilities, partially offset by benefits from tax credits.

As of December 31, 2002, we classified the operations and gains/losses recognized on the sales of certain entities as discontinued operations. Discontinued operations consist of the historical operations and net gains/losses related to our Crockett Cogeneration, Entrade, Killingholme, Csepel, Bulo Bulo, McClain, NLGI, NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, TERI, Cahua and Energia Pacasmayo that were sold in 2002 or were deemed to have met the required criteria for such classification pending final disposition. For 2002, the results of operations related to such discontinued operations was a net loss of $500.8 million as compared to a gain of $43.2 million for the same period in 2001. The primary reason for the loss recognized in 2002 is due to asset impairments recorded at Killingholme, TERI and NLGI.

On May 14, 2003, we and 25 of our U.S. affiliates, filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code, “the Bankruptcy Code” in the United States Bankruptcy Court for the Southern District of New York, or the “bankruptcy court.”

On May 15, 2003, NRG Energy, PMI, NRG Finance Company I LLC, NRGenerating Holdings (No. 23) B.V. and NRG Capital LLC, collectively “the Plan Debtors”, filed the NRG plan of reorganization and the related Disclosure Statement for Reorganizing Debtors’ Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code, as subsequently amended, “the Disclosure Statement.” The Bankruptcy Court held a hearing on the Disclosure Statement on June 30, 2003, and instructed the Plan Debtors to include certain additional disclosures. The Plan Debtors amended the Disclosure Statement and obtained Bankruptcy Court approval for the Third Amended Disclosure Statement for Debtors’ Second Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code.

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. On September 17, 2003, the Northeast/ South Central plan of reorganization was proposed 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.

Between May 14, 2003 and December 5, 2003, we operated as a debtor-in-possession under the supervision of the bankruptcy court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”, or “SOP 90-7.”

For financial reporting purposes, the close of business on December 5, 2003, represents the date of emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:

The implementation of the NRG plan of reorganization resulted in, among other things, a new capital structure, the satisfaction or disposition of various types of claims against the Predecessor Company, the assumption or rejection of certain contracts, and the establishment of a new board of directors.

In connection with the emergence from bankruptcy, we adopted Fresh Start in accordance with the requirements of SOP 90-7. The application of SOP 90-7 resulted in the creation of a new reporting entity. Under Fresh Start, the enterprise value of our company was allocated among our assets and liabilities on a basis substantially consistent with purchase accounting in accordance with SFAS No. 141 “Business Combinations”, or “SFAS No. 141.” Accordingly, we pushed down the effects of this allocation to all of our subsidiaries.

Under the requirements of Fresh Start, we have adjusted our assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking our assets and liabilities to their estimated fair values, we determined that there was no excess reorganization value that was reallocated back to our tangible and intangible assets. Deferred taxes were determined in accordance with SFAS No. 109, “Accounting for Income Taxes.” The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in the Predecessor Company’s results of operations for the period January 1, 2003 through December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

As part of the bankruptcy process we engaged an independent financial advisor to assist in the determination of our reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from our core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, or “DCF”, valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisors prepared a 30 year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted our project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

In constructing our Fresh Start balance sheet upon our emergence from bankruptcy we used a reorganization equity value of approximately $2.4 billion, as we believe this value to be the best indication of the value of the ownership distributed to the new equity owners. Our NRG Plan of reorganization provided for the issuance of 100,000,000 shares of NRG common stock to the various creditors resulting in a calculated price per share of $24.04. Our reorganization value of approximately $9.1 billion was determined by adding our reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and our other liabilities of

$3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and bankruptcy court’s approval of the NRG plan of reorganization.

We recorded approximately $3.9 billion of net reorganization income in the Predecessor Company’s statement of operations for 2003, which includes the gain on the restructuring of equity and the discharge of obligations subject to compromise for less than recorded amounts, as well as adjustments to the historical carrying values of our assets and liabilities to fair market value.

Due to the adoption of Fresh Start as of December 5, 2003, the Reorganized NRG post-Fresh Start balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are therefore not comparable in certain respects to the financial statements prior to the application of Fresh Start. A black line has been drawn on the accompanying Consolidated Financial Statements to separate and distinguish between Reorganized NRG and the Predecessor Company. The effects of the reorganization and Fresh Start on our balance sheet as of December 5, 2003, were as follows (in thousands):

APB No. 18, “The Equity Method of Accounting for Investments in Common Stock,” requires us to effectively push down the effects of Fresh Start reporting to our unconsolidated equity method investments and to recognize an adjustment to our share of the earnings or losses of an investee as if the investee were a consolidated subsidiary. As a result of pushing down the impact of Fresh Start to our West Coast Power affiliate, we determined that a contract based intangible asset with a one year remaining life, consisting of the value of West Coast Power’s California Department of Water Resources energy sales contract, must be established and recognized as a basis adjustment to our share of the future earnings generated by West Coast

In addition to our issuance of new common stock, on December 23, 2003, we completed a note offering consisting of $1.25 billion of 8% Second Priority Senior Secured Notes due 2013, or the “Second Priority Notes”, and we entered into a new credit facility consisting of a $950.0 million term loan facility, a $250.0 million funded letter of credit facility and a $250.0 million revolving credit facility. In January of 2004, we completed a supplementary note offering whereby we issued an additional $475.0 million of the Second Priority Notes at a premium and used the proceeds to repay a portion of the $950.0 million term loan. As of March 1, 2004, we had $1.7 billion in aggregate principal amount of Second Priority Notes outstanding, $446.5 million principal amount outstanding under the term loan and $147.5 million remains available under the funded letter of credit facility. As of March 1, 2004, we had not drawn down on our revolving credit facility. Finally, in connection with the consummation of the NRG plan of reorganization, we issued to Xcel Energy a $10.0 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.

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 through our distribution of new common stock and $1.04 billion in cash among our unsecured creditors. In addition to the debt reduction associated with the restructuring, we used the proceeds of the recent note offering and borrowings under the New Credit Facility to retire approximately $1.7 billion of project-level debt.

For additional information on our short term and long term borrowing arrangements, see Item 15 — Note 17 to the Consolidated Financial Statements.

Historically, we have obtained cash from operations, issuance of debt and equity securities, borrowings under credit facilities, capital contributions from Xcel Energy, reimbursement by Xcel Energy of tax benefits pursuant to a tax sharing agreement and proceeds from non-recourse project financings. We used these funds to finance operations, service debt obligations, fund the acquisition, development and construction of generation facilities, finance capital expenditures and meet other cash and liquidity needs.

We have obtained cash from operations, Xcel Energy’s contribution net of distributions to creditors, proceeds from the sale of certain assets and borrowings under our Second Priority Notes and New Credit Facility.

Net cash provided by operating activities increased during 2002 compared with 2001, primarily due to our efforts to conserve cash by deferring the payment of interest and managing our cash flows more closely. As a result, we increased accounts payable and accrued interest balances and reduced inventory levels.

For the period January 1, 2003 through December 5, 2003 net cash provided by operating activities was $238.5 million. Operating activities consisted of a net loss before Fresh Start adjustments of $1.1 billion, offset by non-cash charges of $567.5 million and cash provided by working capital of $800.1 million. The non-cash charges consisted primarily of the write-down of our investment in Loy Yang, asset impairments and legal settlement charges. The favorable change in working capital was primarily due to reduced cash expenditures throughout the bankruptcy period resulting in increased accounts payable.

For the period December 6, 2003 through December 31, 2003 cash used by operating activities was $588.9 million. This was primarily a result of payments made to creditors upon our emergence from bankruptcy.

Net cash used in investing activities decreased in 2002, compared with 2001, primarily as a result of the termination of our acquisition program due to our financial difficulties and the receipt of cash upon the sale of assets during 2002.

For the period January 1, 2003 through December 5, 2003 cash used in investing activities $185.7 million. This was primarily a result of capital expenditures and an increase in restricted cash, offset by cash proceeds received upon the sale of investments.

For the period December 6, 2003 through December 31, 2003 cash provided by investing activities was $363.4 million. In connection with the refinancing transaction, approximately $375.3 million of restricted cash was released upon payment of the Northeast Generating and South Central Generating note. This increase was offset by funds used for capital expenditures and investments in projects.

Net cash provided by financing activities decreased during 2002 compared to 2001 due to constraints on our ability to access the capital markets and the cancellation and termination of construction projects reducing the need for capital.

For the period January 1, 2003 through December 5, 2003 cash used by financing activities was $29.9 million, which consisted primarily of principal payments offset by the issuance of additional debt.

For the period December 6, 2003 through December 31, 2003 cash provided by financing activities was $393.3 million. We entered into refinancing transactions on December 23, 2003, where we issued $1.25 billion of Second Priority Notes and entered into the New Credit Facility, which consisted of a $950.0 million senior secured term loan facility and a $250.0 million funded letter of credit facility. Upon completion of the refinancing transactions, we repaid the Northeast Generating and South Central Generating notes and the Mid-Atlantic Generating obligations.

The principal sources of liquidity for our future operations, capital expenditures, facility closures and project restructurings are expected to be: (i) existing cash on hand and cash flows from operations, (ii) Xcel Energy’s contribution net of distributions to creditors, (iii) proceeds from the sale of certain assets and businesses and (iv) borrowings under our New Credit Facility, including up to $250.0 million of available borrowings under our new revolving credit facility and up to $250.0 million of a pre-funded letter of credit facility. Additionally, there are approximately $89.5 million of undrawn letters of credit under the pre-petition ANZ LC Facility. The ANZ LC Facility is supported by a cash funded claim reserve to support any letters of credit drawn prior to their expiration. Capacity under the ANZ LC facility will be reduced as the underlying LCs expire or are terminated. All of the LCs will expire or be terminated by the end of 2004, at which time the ANZ LC facility will no longer exist.

As a result of our emergence from bankruptcy, all of our then existing securities, including our old common stock and various issuances of senior notes, were cancelled and approximately $5.2 billion of our existing debt and approximately $1.3 billion of additional claims and disputes were eliminated for a combination of equity and up to $1.04 billion in cash.

On December 23, 2003, we entered into a bank facility for up to $1.45 billion, or the “New Credit Facility”, which included a $950.0 million, six and a half-year senior secured term loan, a $250.0 million funded letter of credit facility, and a four-year $250.0 million revolving line of credit, or the “revolving credit facility.” Portions of the revolving credit facility are available as a swing-line facility and as a revolving letter of credit sub-facility. As of December 31, 2003, the corporate revolver was undrawn. Also on December 23, 2003, we issued $1.25 billion in 8% second priority, senior secured notes, or the “Second Priority Notes”, due and payable on December 15, 2013.

Upon completion of the refinancing transactions, we, among other things: (i) repaid the Northeast Generating LLC Notes, or “Northeast Notes”, the South Central Generating LLC Notes, or “South Central Notes”, and the Mid-Atlantic Generating LLC Obligations; (ii) paid a settlement amount associated with the repayment of the Northeast Notes and the South Central Notes; (iii) paid $500.0 million in lieu of 10% NRG Energy senior notes to former unsecured creditors pursuant to the NRG plan of reorganization, the “POR Notes”, (see the discussion of Senior Securities under Item 15 — Note 17 to the Consolidated Financial Statements) ; (iv) pre-funded a letter of credit sub-facility under the New Credit Facility in the amount of $250.0 million; and (v) paid fees and expenses related to the offering of notes and the New Credit Facility in the amount of $74.8 million.

On January 28, 2004, we issued an additional $475.0 million of the Second Priority Notes, obtaining net proceeds of $501.8 million. With proceeds from this issuance and other funds, we subsequently 1) repaid $503.5 million of the term loan under the New Credit Facility, reducing the principal outstanding from $950.0 million to $446.5 million, 2) made a prepayment premium payment of $15.1 million, and 3) repaid accrued but unpaid interest on the prepayment amount, totaling $0.4 million. On February 25, 2004, we received from our term loan lenders a waiver under the New Credit Facility waiving our obligation to enter into a hedge arrangement on a notional value of $500.0 million, as required by the credit agreement.

Cash Flows. Our operating cash flows are expected to be impacted by, among other things: (i) spark spreads generally; (ii) commodity prices (including demand for natural gas, coal, oil and electricity); (iii) the cost of ordinary course operations and maintenance expenses; (iv) planned and unplanned outages; (v) contraction of terms by trade creditors; (vi) cash requirements for closure and restructuring of certain facilities; (vii) restrictions in the declaration or payments of dividends or similar distributions from our subsidiaries; and (viii) the timing and nature of asset sales.

A principal component of the NRG plan of reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution to us consisting of cash (and, under certain circumstances, its common stock) in an aggregate amount of up to $640.0 million to be paid in three separate installments. Xcel Energy contributed $288.0 million on February 20, 2004. We anticipate receiving an additional installment of up to $352.0 million in cash on April 30, 2004. We will distribute $515.0 million of cash we receive from Xcel Energy to our creditors. In the event we achieve certain liquidity measures in September 2004, an additional $25.0 million may be distributed to creditors, and we may use $100.0 million for any purpose, subject to any restrictions contained in the indenture or the New Credit Facility.

Asset Sales. We received $229.3 million and $196.2 million in net cash proceeds from the sale of certain assets and businesses in the fiscal years ended 2002 and 2003, respectively. The New Credit Facility and the indenture governing the notes place restrictions on the use of any proceeds we may receive from certain asset sales in the future.

Letter of Credit Sub-facility and Revolving Credit Facility. The New Credit Facility includes a letter of credit sub-facility in the amount of $250.0 million. As of December 31, 2003, we had issued $1.7 million in letters of credit under this facility. The New Credit Facility also includes a revolving credit facility in the amount of $250.0 million to be used for general corporate purposes. On December 31, 2003 we had not yet drawn on our revolving credit facility. For additional information regarding our debt see Item 15 — Note 17 to the Consolidated Financial Statements.

Our requirements for liquidity and capital resources, other than for operating our facilities, can generally be categorized by the following: (i) PMI activities; (ii) capital expenditures; and (iii) project finance requirements for cash collateral.

PMI. PMI activities comprise the single largest requirement for liquidity and capital resources. PMI liquidity requirements are primarily driven by: (i) margin and collateral posting requirements with counterparties; (ii) establishment of trading relationships; (iii) disbursement and receipt timing (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. For 2004, we believe that approximately $265 million to $360 million may be required for PMI to meet potential margin requirements and to cover prepayments and fuel inventory builds.

Estimates for liquidity requirements are highly dependent on our hedging activity and then current market conditions, including forward prices for energy and fuel and market volatility. In addition, our estimates are dependent on credit terms with third parties. We do not assume that we will be provided with unsecured credit from third parties in budgeting our working capital requirements.

Capital Expenditures. Capital expenditures were $1.4 billion for the year ended 2002, $113.5 million for the period January 1, 2003 through December 5, 2003 and $10.6 million for the period December 6, 2003 through December 31, 2003. Capital expenditures in 2003 relate primarily to operations and maintenance of

our existing generating facilities whereas capital expenditures in 2002 related primarily to new plant construction. We anticipate that our 2004 capital expenditures will be approximately $113.8 million and will relate primarily to the operation and maintenance of our existing generating facilities.

Project Finance Requirements. We are a holding company and conduct our operations through subsidiaries. Historically, we have utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct our power plants and related assets. Consistent with our strategy, we may seek, where available on commercially reasonable terms, non-recourse debt financing in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. Non-recourse borrowings are substantially non-recourse to other subsidiaries, affiliates and us, and are generally secured by the capital stock, physical assets, contracts and cash flow of the related project subsidiary or affiliate. Some of these project financings require us to post collateral in the form of cash or an acceptable letter of credit.

Principal on short-term debt, long-term debt and capital leases as of December 31, 2003 are due and payable in the following periods (in thousands):

Principal payments for debt that have been deemed current for financial reporting purposes as of December 31, 2003 are reflected as short-term in the table above. Events may have occurred since December 31, 2003 that would allow such debt to be paid on a normal amortizing schedule. Prepayments, or additional borrowing under certain facilities, since December 31, 2003 are not reflected. See Item 15 — Note 17 to the Consolidated Financial Statements for further discussion on events that may affect debt payment schedules.

If we decide not to provide any additional funding or credit support to our subsidiaries, the inability of any of our subsidiaries that are under construction or that have near-term debt payment obligations to obtain non-recourse project financing may result in such subsidiary’s insolvency and the loss of our investment in such subsidiary. Additionally, the loss of a significant customer at any of our subsidiaries may result in the need to restructure the non-recourse project financing at that subsidiary, and the inability to successfully complete a restructuring of the non-recourse project financing may result in a loss of our investment in such subsidiary. Certain of our projects are subject to restrictions regarding the movement of cash. For additional information see Item 15 — Note 17 to the Consolidated Financial Statements.

For 2004, we anticipate utilizing all of our $250.0 million letter of credit sub-facility. In addition, we believe that approximately $265.0 million to $360.0 million of cash may be required for PMI to meet its potential margin requirements and to cover prepayments and fuel inventory builds. As part of our refinancing transactions, we have established a $250.0 million revolving credit facility. The revolving credit facility was established to satisfy short-term working capital requirements, which may arise from time to time. It is not our current intention to draw funds under the revolving credit facility.

We maintain cash deposits in order to assure the continuation of vendor trade terms. As of December 31, 2003, the total amount of cash deposits maintained for these purposes was approximately $48.3 million.

We expect our capital requirements to be met with existing cash balances, cash flows from operations, borrowings under our Second Priority Notes and New Credit Facility, and asset sales. We believe that our current level of cash availability and asset sales, along with our future anticipated cash flows from operations, will be sufficient to meet the existing operational and collateral needs of our business for the next 12 months. Subject to restrictions in our Second Priority Notes and our New Credit Facility, if cash generated from operations is insufficient to satisfy our liquidity requirements, we may seek to sell assets, obtain additional credit facilities or other financings and/or issue additional equity or convertible instruments. We cannot assure you, however, that our business will generate sufficient cash flow from operations, that currently anticipated cost savings and operating improvements will be realized on schedule or that future borrowings will be available to us under our credit facilities in an amount sufficient to enable us to pay our indebtedness, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, on commercially reasonable terms or at all. To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control.

As of December 31, 2003, we do not have any significant relationships with structured finance or special purpose entities that provide liquidity, financing or incremental market risk or credit risk.

We have numerous investments with an ownership interest percentage of 50% or less in energy and energy related entities that are accounted for under the equity method of accounting as disclosed in Item 15 — Note 13 to the Consolidated Financial Statements. Our pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $967.7 million as of December 31, 2003. In the normal course of business we may be asked to loan funds to these entities on both a long and short-term basis. Such transactions are generally accounted for as accounts payables and receivables to/from affiliates and notes payables/receivables to/from affiliates and if appropriate, bear market-based interest rates. See Item 15 — Note 11 to the Consolidated Financial Statements for additional information regarding amounts accounted for as notes receivable — affiliates.

We have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to our capital expenditure programs. The following is a summarized table of contractual obligations. See additional discussion in Item 15 — Notes 17, 24 and 26 to the Consolidated Financial Statements.


*	These amounts represent creditor payments under NRG’s plan of reorganization. Additionally, payments of up to $275 million will be required pursuant to security interests held in certain assets by creditors when the related assets are sold.

We do not have any significant interdependent relationships. Since we formerly were an indirect wholly owned subsidiary of Xcel Energy, there were certain related party transactions that took place in the normal

We may enter into long term power sales contracts, long term gas purchase contracts and other energy related commodities financial instruments to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect fuel inventories.

The tables below disclose the trading activities that include non-exchange traded contracts accounted for at fair value. Specifically, these tables disaggregate realized and unrealized changes in fair value; identify changes in fair value attributable to changes in valuation techniques; disaggregate estimated fair values at December 31, 2003 based on whether fair values are determined by quoted market prices or more subjective means; and indicate the maturities of contracts at December 31, 2003.

We may use a variety of financial instruments to manage our exposure to fluctuations in foreign currency exchange rates on our international project cash flows, interest rates on our cost of borrowing and energy and energy related commodities prices.

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements and related disclosures in compliance with generally accepted accounting principles, or “GAAP”, requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.

On an ongoing basis, we, evaluate our estimates, utilizing historic experience, consultation with experts and other methods we consider reasonable. In any case, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Our significant accounting policies are summarized in Item 15 — Note 2 to the Consolidated Financial Statements. The following table identifies certain of the significant accounting policies listed in Item 15 — Note 2 to the Consolidated Financial Statements. The table also identifies the judgments required, uncertainties involved in the application of each and estimates that may have a material impact on our results of operations and statement of financial position.These policies, along with the underlying assumptions and judgments made by our management in their application, have a significant impact on our consolidated financial statements. We identify our most critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.

Of all of the accounting policies identified in the above table, we believe that the following policies and the application thereof to be those having the most direct impact on our financial position and results of operations.

The bankruptcy court in its confirmation order approved our Plan of reorganization on November 24, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. Our Plan of reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. We believe this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

Under the requirements of Fresh Start, we have adjusted our assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking our assets and liabilities to their estimated fair values, we determined that there was no excess reorganization value to recognize as an intangible asset. Deferred taxes were determined in accordance with SFAS No. 109, “Accounting for Income Taxes.” The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in the Predecessor Company’s results for the period January 1, 2003 through December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

As part of the bankruptcy process we engaged an independent financial advisor to assist in the determination of the fair value of our reorganized enterprise value. The fair value calculation was based on management’s forecast of our core assets. Management’s forecast relied on forward market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, or “DCF”, valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts all expected future economic benefits by a theoretical or observed discount rate determined by calculating the weighted average cost of capital, or “WACC”, of Reorganized NRG. The enterprise calculation was based on management’s forecast of our core assets. Management’s forecast relied on forward market prices obtained from a third party consulting firm. For purposes of our Disclosure statement, the independent financial advisor estimated our reorganization enterprise value of our ongoing projects to range from $5.5 billion to $5.7 billion, less project level debt, and net of cash. Certain other adjustments were made to reflect the values of assets held for sale, excess cash and net of the Xcel Settlement and collateral requirements. These adjustments resulted in a reorganized NRG value, net of project debt, of between $3.1 billion and $3.5 billion. Additional adjustments were made to reflect cash payments expected as part of the implementation of the Plan of Reorganization, resulting in a final range of equity values of between $2.2 billion and $2.6 billion.

In constructing our Fresh Start balance sheet upon our emergence from bankruptcy we used a reorganization equity value of approximately $2.4 billion, as we believe this value to be the best indication of the value of the ownership distributed to the new equity owners. Our reorganization value of approximately $9.1 billion was determined by adding our reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and our other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of the Plan of Reorganization.

Due to the adoption of Fresh Start upon our emergence from bankruptcy, the Reorganized NRG’s post-fresh start balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are therefore not comparable in certain respects to the financial statements prior to the application of Fresh Start.

For those assets that were being constructed by us, the carrying value reflects the application of our property, plant and equipment policies which incorporate estimates, assumptions and judgments by management relative to the capitalized costs and useful lives of our generating facilities. Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the asset under construction is ready for our intended use or when construction is terminated. An insignificant amount of interest was capitalized during 2003. Development costs and capitalized project costs include third party professional services, permits and other costs that are incurred incidental to a particular project. Such costs are expensed as incurred until an acquisition agreement or letter of intent is signed, and our board of directors has approved the project. Additional costs incurred after this point are capitalized.

In connection with the emergence from bankruptcy, we adopted Fresh Start in accordance with the requirements of SOP 90-7. The application of SOP 90-7 resulted in the creation of a new reporting entity. Under Fresh Start, the reorganization value of our company was allocated to our assets and liabilities on a basis substantially consistent with purchase accounting in accordance with SFAS No. 141. We engaged a valuation specialist to help us determine the fair value of our fixed assets. The valuations were based on forecast power prices and operating costs determined by us. The valuation specialist also determined the estimated remaining useful lives of our fixed assets. The capitalization policy will be consistent with the predecessor company policy.

We evaluate property, plant and equipment and intangible assets for impairment whenever indicators of impairment exist. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available to us. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. Assets to be disposed of are reported at the lower of the carrying amount or fair value less the cost to sell. For the period January 1, 2003 through December 5, 2003, net income from continuing operations was reduced by $228.9 million due to asset impairments. Asset impairment evaluations are by nature highly subjective.

We are primarily an electric generation company, operating a portfolio of majority-owned electric generating plants and certain plants in which our ownership is 50% or less which are accounted for under the

equity method of accounting. We also produce thermal energy for sale to customers. Both physical and financial transactions are entered into to optimize the financial performance of our generating facilities. Electric energy revenue is recognized upon transmission to the customer. In certain markets, which are operated/ controlled by an independent system operator and in which we have entered into a netting agreement with the ISO, which results in our receiving a netted invoice, we have recorded purchased energy as an offset against revenues received upon the sale of such energy. Capacity and ancillary revenue is recognized when contractually earned. Revenues from operations and maintenance services are recognized when the services are performed. We continually assess the collectibility of our receivables, and in the event we believe a receivable to be uncollectible, an allowance for doubtful accounts is recorded or, in the event of a contractual dispute, the receivable and corresponding revenue may be considered unlikely of recovery and not recorded in the financial statements until management is satisfied that it will be collected.

In January 2001, we adopted FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or “SFAS No. 133”, 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. In some cases hedge accounting may apply. The criteria used to determine if hedge accounting treatment is appropriate are a) the designation of the hedge to an underlying exposure, b) whether or not the overall risk is being reduced and c) if there is correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as 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. We primarily account for derivatives under SFAS No. 133 such as long-term power sales contracts, long-term gas purchase contracts and other energy related commodities and financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and to protect investments in fuel inventories. SFAS No. 133 also applies to interest rate swaps and foreign currency exchange rate contracts. The application of SFAS No. 133 results in increased volatility in earnings due to the recognition of unrealized gains and losses. In determining the fair value of these derivative/financial instruments we use estimates, various assumptions, judgment of management and when considered appropriate third party experts in determining the fair value of these derivatives.

We classify our results of operations that either have been disposed of or are classified as held for sale as discontinued operations if both of the following conditions are met: (a) the operations and cash flows have been (or will be) eliminated from our ongoing operations as a result of the disposal transaction and (b) we will not have any significant continuing involvement in the operations of the component after the disposal transaction.

The determination of our obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. Our actuarial consultants use assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by us.

Effective January 1, 2003, we adopted the fair value recognition provisions of SFAS Statement No. 123, “Accounting for Stock-Based Compensation,” or “SFAS No. 123.” In accordance with SFAS Statement No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure,” or “SFAS No. 148”, we adopted SFAS No. 123 under the prospective transition method which requires the application of the recognition provisions to all employee awards granted, modified, or settled after the beginning of the fiscal year in which the recognition provisions are first applied.

As part of the provisions of SOP 90-7, we are required to adopt, for the current reporting period, all accounting guidance that is effective within a twelve-month period. As a result, we have adopted all provisions of FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities.”

Historically we have used a variety of financial instruments to manage our exposure to fluctuations in foreign currency exchange rates on our international project cash flows, interest rates on our cost of borrowing and energy and energy related commodities prices.

We expect to continue to be subject to currency risks associated with foreign denominated distributions from our international investments. In the normal course of business, we may receive distributions denominated in the Euro, Australian Dollar, British Pound, New Taiwanese Dollar and the Brazilian Real. We have historically engaged in a strategy of hedging foreign denominated cash flows through a program of matching currency inflows and outflows, and to the extent required, fixing the U.S. Dollar equivalent of net foreign denominated distributions with currency forward and swap agreements with highly credit worthy financial institutions. We would expect to enter into similar transactions in the future if management believes it to be appropriate.

As of December 31, 2003, neither we, nor any of our consolidating subsidiaries, had any outstanding foreign currency exchange contracts.

We are exposed to fluctuations in interest rates when entering into variable rate debt obligations to fund certain power projects. Exposure to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. Our risk management policy allows us to reduce interest rate exposure from variable rate debt obligations.

As of December 31, 2003, we had various interest rate swap agreements with notional amounts totaling approximately $620.5 million. If the swaps had been discontinued on December 31, 2003, we would have owed the counter parties approximately $50.1 million. Based on the investment grade rating of the counter-parties, we believe that our exposure to credit risk due to nonperformance by the counter-parties to our hedging contracts is insignificant.

We have both long and short-term debt instruments that subject us to the risk of loss associated with movements in market interest rates. As of December 31, 2003, a 100 basis point change in the benchmark rate on our variable rate debt would impact net income by approximately $14.5 million.

At December 31, 2003, the fair value of our fixed-rate debt was $1.8 billion, compared with the carrying amount of $1.8 billion. We estimate that a 1% decrease in market interest rates would have increased the fair value of our fixed-rate debt to $1.9 billion, or an increase of $119.2 million.

We are exposed to commodity price variability in electricity. Commodity price risk also impacts emission allowances, natural gas, oil and coal, which are required to generate power. To manage earnings volatility associated with these commodity price risks, we enter into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps.

We utilize an un-diversified “Value-at-Risk”, or “VAR”, model to estimate a maximum potential loss in the fair value of our commodity portfolio including generation assets, load obligations and bilateral physical and financial transactions. The key assumptions for our VAR model include (1) a lognormal distribution of price returns (2) three day holding period and (3) a 95% confidence interval. The volatility estimate is based on the implied volatility for at the money call options. This model encompasses the following generating regions: ENTERGY, NEPOOL, NYPP, PJM, WSCC and MAIN.

The estimated maximum potential three-day loss in fair value of our commodity portfolio, calculated using the VAR model is as follows:

We have risk management policies in place to measure and limit market and credit risk associated with our power marketing activities. These policies do not permit speculative or directional trading. An independent department within our finance organization is responsible for the enforcement of such policies. We are currently in the process of reviewing and revising these policies to reflect changes in best practices and industry.

We are exposed to credit risk in our risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counter party of its contractual obligations. We actively manage our counter-party credit risk. We have an established credit policy in place to minimize overall credit risk. Important elements of this policy include ongoing financial reviews of all counter-parties, established credit limits, as well as monitoring, managing and mitigating credit exposure.

The financial statements and schedules are listed in Part IV, Item 15 of this Form 10-K.

During the fourth quarter of 2003, under the supervision and with the participation of our management, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) or Rule 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended, as of the end of the fiscal year covered by this Form 10-K. Based on their evaluation, our officers concluded that our disclosure controls and procedures are effective.

Our officers are primarily responsible for the accuracy of the financial information that is represented in this report. To meet their responsibility for financial reporting, they have established internal controls and procedures, which they believe, are adequate to provide reasonable assurance that our assets are protected from loss. There have been no significant changes (including corrective actions with regard to significant deficiencies or material weaknesses) in our internal controls or in other factors that could significantly affect these controls subsequent to the date of the evaluation referenced above. We recently hired a new Chief Financial Officer, Robert Flexon, effective March 2004.

During the fourth quarter of 2002, our officers determined that there were certain deficiencies or “reportable conditions” in the internal controls relating to our financial reporting caused by our pending financial restructuring and business realignment. During the second half of 2002, there were material changes and vacancies in our senior management positions and a diversion of our financial and management resources to restructuring efforts. These circumstances detracted from our ability through our internal controls to timely monitor and accurately assess the impact of certain transactions, as would be expected in an effective financial reporting control environment. In addition, during 2003, we operated without an internal audit department, a senior risk manager or a CFO. However, during 2003, we dedicated significant resources to make corrections to those control deficiencies, including hiring several other key senior and middle management personnel, hiring an outside consultant to review, document and suggest improvements to controls, and the implementation of new controls and procedures.

Information required by this Item will be contained in our definitive Proxy Statement for its 2004 Annual Meeting of Stockholders, to be filed on or before April 29, 2004, and such information is incorporated herein by reference.

The following consolidated financial statements of NRG Energy and related notes thereto, together with the reports thereon of PricewaterhouseCoopers LLP are included herein:

The following Consolidated Financial Statement Schedule of NRG Energy is filed as part of Item 15(d) of this report and should be read in conjunction with the Consolidated Financial Statements.

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.

(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report.

(b) Reports on Form 8-K. We filed reports on Form 8-K on the following dates over the last fiscal year:

February 21, 2003, March 6, 2003, May 16, 2003, August 27, 2003, October 22, 2003, November 7, 2003, November 19, 2003, December 9, 2003, December 19, 2003, December 24, 2003, January 7, 2004, January 30, 2004, March 2, 2004, March 11, 2004.

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, cash flows and stockholder’s equity (deficit) present fairly, in all material respects, the financial position of NRG Energy, Inc. and its subsidiaries (Predecessor Company) at December 31, 2002 and the results of their operations and their cash flows for the period from January 1, 2003 to December 5, 2003, and for each of the two years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company filed a petition on May 14, 2003 with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003 and Reorganized NRG emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting.

As discussed in Note 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”, as of January 1, 2002. As discussed in Notes 2 and 8 to the consolidated financial statements, the Company adopted Statements of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, cash flows and stockholders’ equity present fairly, in all material respects, the financial position of NRG Energy, Inc. and its subsidiaries (Reorganized NRG) at December 6, 2003 and December 31, 2003 and the results of their operations and their cash flows for the period from December 6, 2003 to December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of New York confirmed the NRG Energy, Inc. Plan of Reorganization on November 24, 2003. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before May 14, 2003 and substantially alters rights and interests of equity security holders as provided for in the plan. The NRG Energy, Inc. Plan of Reorganization was substantially consummated on December 5, 2003, and NRG Energy, Inc. emerged from bankruptcy. In connection with its emergence from bankruptcy, NRG Energy, Inc. adopted fresh start accounting as of December 5, 2003.

We are 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 on December 23, 2003. In January 2004, we used proceeds of an additional note offering to repay $503.5 million of the outstanding borrowings under our New Credit facility.

As of December 31, 2003, we owned interests in 72 power projects in seven countries having an aggregate generation capacity of approximately 18,200 MW. Approximately 7,900 MW of our capacity consists of merchant power plants in the Northeast region of the United States. Certain of these assets are located in transmission constrained areas, including approximately 1,400 MW of “in-city” New York City generation capacity and approximately 700 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 consisted of a diversified mix of natural gas-, coal- and oil-fired facilities, representing approximately 48%, 26% and 26% of our total domestic generation capacity, respectively. 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.

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 primarily with third party debt. Due to a number of reasons, particularly our aggressive pricing of acquisitions and the overall down-turn 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 assets, declining power prices, increasing fuel prices, the overall down-turn in the power generation industry and the overall down-turn 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.

the bankruptcy court entered an order confirming the Northeast/South Central plan of reorganization and the plan became effective on December 23, 2003.

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.


	•	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 in December 2003, with proceeds of the Refinancing Transactions;


	•	distributing the collateral to the security holder,

	•	selling the collateral and distributing the proceeds to the security holder or

	•	other mutually agreeable treatment; and


	•	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.

Between May 14, 2003 and December 5, 2003, we operated as a debtor-in-possession under the supervision of the bankruptcy Court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code.”

For financial reporting purposes, close of business on December 5, 2003, represents the date of our emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities,” or “FIN No. 46.” FIN No. 46 requires an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling interest. Historically, that requirement has been applied to subsidiaries in which an enterprise has a majority voting interest, but in many circumstances the enterprise’s consolidated financial statements do not include the consolidation of variable interest entities with which it has similar relationships but no majority voting interest. Under FIN No. 46, the voting interest approach is not the approach used to identify the controlling financial interest. The new rule requires that for entities to be consolidated that those assets be initially recorded at their carrying amounts at the date the requirements of the new rule first apply. If determining carrying amounts as required is impractical, then the assets are to be measured at fair value the first date the new rule applies. Any difference between the net amounts of any previously recognized interest in the newly consolidated entity should be recognized as the cumulative effect of an accounting change. In December 2003, the FASB has published a revision to Interpretation 46, or “FIN 46R”, to clarify some of the provisions of FASB Interpretation No. 46, “Consolidation of Variable Interest Entities,” and to exempt certain entities from its requirements. As required by SOP 90-7, we have adopted FIN No. 46R as of the adoption of Fresh Start. In connection with the adoption of FIN No. 46R, we have recorded total assets of $54.4 million and total liabilities of $47.5 million as of December 6, 2003 that were previously recorded through equity method investments. The nature of the operations consolidated consisted of hydro power facilities on the East Coast.

The consolidated financial statements include our accounts and operations and those of our subsidiaries in which we have a controlling interest. We account for the operations of LSP-Nelson Energy LLC and NRG Nelson Turbines LLC under the cost method as they are currently in bankruptcy. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America. As discussed in Note 13, we have investments in partnerships, joint ventures and projects. Earnings from equity in international investments are recorded net of foreign income taxes.

In accordance with Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” certain companies qualify for fresh start reporting in connection with their emergence from bankruptcy. Fresh start reporting is appropriate on the emergence from chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. We met these requirements and adopted Fresh Start reporting resulting in the creation of a new reporting entity designated as Reorganized NRG.

The bankruptcy court issued a confirmation order approving our Plan of reorganization on November 24, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. Our Plan of reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. The Xcel Energy settlement agreement was entered into on December 5, 2003. We believe this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

gain of $3.9 billion, which is reflected in the Predecessor Company’s results for the period January 1, 2003 through December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

As part of the bankruptcy process we engaged an independent financial advisor to assist in the determination of our reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from our core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, or “DCF”, valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30 year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted our project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

In constructing our Fresh Start balance sheet upon our emergence from bankruptcy, we used a reorganization equity value of approximately $2.4 billion, as we believe this value to be the best indication of the value of the ownership distributed to the new equity owners. Our NRG Plan of reorganization provided for the issuance of 100,000,000 shares of NRG common stock to the various creditors resulting in a calculated price per share of $24.04. Our reorganization value of approximately $9.1 billion was determined by adding our reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and our other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of the Plan of Reorganization.

Our Fresh Start adjustments consist primarily of the valuation of our existing fixed assets and liabilities, equity investments and recognition of the value of certain power sales contracts that were deemed to be significantly valuable or burdensome as either intangible assets or liabilities which will be amortized into income over the respective terms of each contract. A description of the adjustments and amounts is provided in Note 3 — Emergence from Bankruptcy and Fresh Start Reporting.

A separate plan of reorganization was filed for our Northeast Generating and South Central Generating entities that was confirmed by the bankruptcy court on November 25, 2003, and became effective on December 23, 2003, when the final conditions of the plan were completed. In connection with Fresh Start on December 5, 2003, we continued to consolidate our Northeast Generating and South Central Generating entities as we believe that we continued to maintain control over the Northeast Generating and South Central Generating facilities through out the bankruptcy process. As previously stated, the Northeast Generating and South Central Generating entities emerged from bankruptcy on December 23, 2003. However, since the creditors received full recovery, the liabilities are not recorded as subject to compromise in the December 6, 2003 balance sheet.

Due to the adoption of the Fresh Start upon our emergence from bankruptcy, the Reorganized NRG balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are therefore not comparable to the financial statements prior to the application of Fresh Start.

internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type, and dispatch levels, which help us mitigate risk. 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.

Cash and cash equivalents include highly liquid investments (primarily commercial paper) with an original maturity of three months or less at the time of purchase.

Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within our projects that are restricted in their use.

Inventory is valued at the lower of weighted average cost or market and consists principally of fuel oil, spare parts, coal, kerosene, emission allowance credits and raw materials used to generate steam.

Property, plant and equipment are stated at cost however impairment adjustments are recorded whenever events or changes in circumstances indicate carrying values may not be recoverable. On December 5, 2003, we recorded adjustments to the property, plant and equipment to reflect such items at fair value in accordance with Fresh Start reporting. A new cost basis was established with these adjustments. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation is computed using the straight-line method over the following estimated useful lives:

The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in operations.

Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Asset.” An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

Investments accounted for by the equity method are reviewed for impairment in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” APB Opinion No. 18 requires that a loss in value of an investment that is other than a temporary decline should be recognized. We identify and measure losses in value of equity investments based upon a comparison of fair value to carrying value.

Long-lived assets are classified as discontinued operations when all of the required criteria specified in SFAS No. 144 are met. These criteria include, among others, existence of a qualified plan to dispose of an asset, an assessment that completion of a sale within one year is probable and approval of the appropriate level of management and board of directors. Discontinued operations are reported at the lower of the asset’s carrying amount or fair value less cost to sell.

Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the asset under construction is ready for its intended use or when a project is terminated or construction ceased. Capitalized interest was approximately $27.2 million, $64.8 million, $15.9 thousand and $1.5 thousand in 2001, 2002, 2003 Predecessor Company and 2003 Reorganized NRG, respectively.

Development costs and capitalized project costs include third party professional services, permits, and other costs that are incurred incidental to a particular project. Such costs are expensed as incurred until an acquisition agreement or letter of intent is signed, and our Board of Directors has approved the project. Additional costs incurred after this point are capitalized. When a project begins operation, previously capitalized project costs are reclassified to equity investments in affiliates or property, plant and equipment and amortized on a straight-line basis over the lesser of the life of the project’s related assets or revenue contract period. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.

Debt issuance costs are capitalized and amortized as interest expense on a basis, which approximates the effective interest method over the terms of the related debt.

Goodwill represents the excess of the purchase price of net tangible and intangible assets acquired in business combinations over their estimated fair value. Effective January 1, 2002, we implemented SFAS No. 142, “Goodwill and Other Intangible Assets” or “SFAS No. 142.” Pursuant to SFAS No. 142, goodwill is not amortized but is subject to periodic impairment testing. Prior to 2002, goodwill was amortized on a straight line basis over 20 to 30 years.

Intangible assets represent contractual rights held by us. Intangible assets are amortized over their economic useful life and reviewed for impairment on a periodic basis. Non-amortized intangible assets, including goodwill, are tested for impairment annually and on an interim basis if an event or circumstance occurs between annual tests that might reduce the fair value of that asset.

The Predecessor Company’s income tax provision for the period January 1, 2003 through December 5, 2003 has been recorded on the basis that separate federal income tax returns will be filed. The Reorganized NRG’s income tax provision for the period December 6, 2003 through December 31, 2003 has been recorded on the basis that we and our U.S. subsidiaries will reconsolidate for federal income tax purposes as of December 6, 2003. The income tax provision for the year ended December 31, 2002 has been recorded on the

basis that we and our U.S. subsidiaries have filed a consolidated federal income tax return for the period January 1, 2002 through June 3, 2002 and filed separate federal income tax returns for the remainder of 2002.

The Predecessor Company’s income taxes have been recorded on the basis that Xcel Energy has not included us in its consolidated federal income tax return following Xcel Energy’s acquisition of our public shares on June 3, 2002. Since we and our U.S. subsidiaries will not be included in the Xcel Energy consolidated tax group, each of our U.S. subsidiaries that is classified as a corporation for U.S. income tax purposes must file a separate federal income tax return for the periods ended December 31, 2002 and December 5, 2003.

The Reorganized NRG is no longer owned by Xcel Energy and thus, no longer included in the Xcel Energy affiliated group. The change in ownership allows us to file a consolidated federal income tax return with our U.S. subsidiaries starting on December 6, 2003.

Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

We are primarily an electric generation company, operating a portfolio of majority-owned electric generating plants and certain plants in which our ownership interest is 50% or less and which are accounted for under the equity method. In connection with our electric generation business, we also produce thermal energy for sale to customers, principally through steam and chilled water facilities. We also collect methane gas from landfill sites, which are used for the generation of electricity. In addition, we sell small amounts of natural gas and oil to third parties.

Electrical energy revenue is recognized upon delivery to the customer. In certain markets, which are operated/controlled by an independent system operator and in which we have entered into a netting agreement with the ISO, which results in our receiving a netted invoice, we have recorded purchased energy as an offset against revenues received upon the sale of such energy. Capacity and ancillary revenue is recognized when contractually earned. Disputed revenues are not recorded in the financial statements until disputes are resolved and collection is assured.

Revenue from long-term power sales contracts that provide for higher pricing in the early years of the contract are recognized in accordance with Emerging Issues Task Force Issue No. 91-6, “Revenue Recognition of Long Term Power Sales Contracts.” This results in revenue deferrals and recognition on a levelized basis over the term of the contract.

We provide contract operations and maintenance services to some of our non-consolidated affiliates. Revenue is recognized as contract services are performed.

We recognize other income for interest income on loans to our non-consolidated affiliates, as the interest is earned and realizable.

The local currencies are generally the functional currency of our foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses and cash flows are translated at weighted-average rates of exchange for the period. The resulting currency translation adjustments are accumulated and reported as a separate component of stockholders’ equity and are

not included in the determination of the results of operations. Foreign currency transaction gains or losses are reported in results of operations. We recognized foreign currency transaction gains (losses) of $1.8 million, $(10.4) million, $(19.8) million and $0.4 million in 2001, 2002, 2003 Predecessor Company and 2003 Reorganized NRG, respectively.

Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of cash, accounts receivable, notes receivable and investments in debt securities. Cash accounts are generally held in Federally insured banks. Accounts receivable, notes receivable and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, we believe the credit risk posed by industry concentration is offset by the diversification and creditworthiness of our customer base.

The carrying amount of cash and cash equivalents, receivables, accounts payables, and accrued liabilities approximate fair value because of the short maturity of these instruments. The carrying amounts of long-term receivables approximate fair value, as the effective rates for these instruments are comparable to market rates at year end, including current portions. The fair value of long-term debt is estimated based on quoted market prices for those instruments which are traded or on a present value method using current interest rates for similar instruments with equivalent credit quality.

During the fourth quarter of 2003, in accordance with SFAS Statement No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” we adopted SFAS No. 123 under the prospective transition method which requires the application of the recognition provisions to all employee awards granted, modified, or settled after the beginning of the fiscal year in which the recognition provisions are first applied. As a result, we applied the fair value recognition provisions of SFAS No. 123 as of January 1, 2003. As discussed in Note 18, we recognized compensation expense for the grants issued under the Long-Term Incentive Plan.

Basic net income per share is calculated based on the weighted average of common shares outstanding during the period. Net income per share, assuming dilution is computed by dividing net income by the weighted average number of common and common equivalent shares outstanding. Our only common equivalent shares are those that result from dilutive common stock options and restricted stock.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

In recording transactions and balances resulting from business operations, we use estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, un-collectible accounts, actuarially determined benefit costs and the valuation of long-term energy commodities contracts, among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Certain prior-year amounts have been reclassified for comparative purposes. These reclassifications had no effect on our net income or total stockholders’ equity as previously reported.

In accordance with the requirements of SOP 90-7, we determined the reorganization value of NRG and subsidiaries emerging from bankruptcy to be approximately $9.1 billion. Reorganization value generally approximates fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring. Several methods are used to determine the reorganization value; however, generally it is determined by discounting future cash flows for the reconstituted business that will emerge from chapter 11 bankruptcy. Our approach was consistent in that our independent financial advisor’s estimated reorganization enterprise value of our ongoing projects using a discounted cash flow approach.

We allocated the reorganization value of $9.1 billion to our assets in conformity with the procedures specified by SFAS No. 141. We used a third party to complete an independent appraisal of our tangible assets, equity investments and intangible assets and contracts. In completing the fair value allocation our assets were calculated to be greater than the reorganization value. As a result, we reallocated the negative reorganization value to our tangible and intangible assets in accordance with SFAS No. 141. In preparing our balance sheet we also recorded each liability existing at the plan confirmation date, other than deferred taxes, at the present value of amounts to be paid determined at appropriate current interest rates. Deferred taxes were reported in conformity with generally accepted accounting principles under SFAS No. 109. Our equity was recorded at approximately $2.4 billion representing a price per share of $24.04 for the issuance of 100,000,000 shares of common stock with bankruptcy emergence. We pushed down the effects of fresh start reporting to all of our subsidiaries.

In constructing our Fresh Start balance sheet using our reorganization value upon our emergence from bankruptcy we used a reorganization equity value of approximately $2.4 billion, as we believe this value to be the best indication of the value of the ownership distributed to the new equity owners. Accordingly, our

reorganization value of $9.1 billion was determined by adding our reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and our other liabilities of $3.0 billion. This value is consistent with the voting creditors and Court’s approval of the Plan of Reorganization.

The determination of the enterprise value and the allocations to the underlying assets and liabilities were based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.

We recorded approximately $3.9 billion of net reorganization income in the Predecessor Company’s statement of operations for 2003, which includes the gain on the restructuring of debt and equity and the discharge of obligations subject to compromise for less than recorded amounts, as well as adjustments to the historical carrying values of our assets and liabilities to fair market value.

Due to the adoption of Fresh Start as of December 5, 2003, the Reorganized NRG balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of Fresh Start. A black line has been drawn on the accompanying Consolidated Financial Statements to separate and distinguish between Reorganized NRG and the Predecessor Company. The effects of the reorganization and Fresh Start on our balance sheet as of December 5, 2003, were as follows (in thousands):

up to $1.04 billion in cash among our unsecured creditors. Upon reorganization we issued 100 million shares of NRG common stock at $24.04 per share.

APB No. 18, “The Equity Method of Accounting for Investments in Common Stock”, requires us to effectively push down the effects of Fresh Start reporting to our unconsolidated equity method investments and to recognize an adjustment to our share of the earnings or losses of an investee as if the investee was a consolidated subsidiary. As a result of pushing down the impact of Fresh Start to our West Coast Power affiliate we determined that a contract based intangible asset with a one year remaining life, consisting of the value of West Coast Power’s California Department of Water Resources energy sales contract, must be established and recognized as a basis adjustment to our share of the future earnings generated by West Coast Power. This adjustment will reduce our equity earnings in the amount of approximately $10.4 million per month during 2004 until the contract expires in December 2004.

The estimated December 31 fair values of our recorded financial instruments are as follows:

For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of notes receivable is based on expected future cash flows discounted at market interest rates. The fair value of long-term debt is estimated based on quoted market prices for those instruments which are traded or on a present value method using current interest rates for similar instruments with equivalent credit quality.

As stated above, we and certain of our subsidiaries filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code during 2003. On December 5, 2003, we and five of our subsidiaries emerged from bankruptcy. As of the respective bankruptcy filing dates, the Debtors’ financial records were closed for the Prepetition Period. As required by SOP 90-7 “Financial Report by Entities in Reorganization under the Bankruptcy Code”, below are the condensed combined financial statements of our remaining Debtors since the date of the bankruptcy filings, “the Debtors’ Statements.”

The Debtors’ Statements consist of the following wholly-owned consolidated entities which remained in bankruptcy as of December 6, 2003: Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Berrians I Gas Turbine Power, LLC, Big Cajun II Unit 4 LLC, Connecticut Jet Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Louisiana Generating LLC, LSP-Nelson Energy LLC, Middletown Power LLC, Montville Power LLC, Northeast Generation Holding LLC, Norwalk Power LLC, NRG Central US LLC, NRG Eastern LLC, NRG McClain LLC, NRG Nelson Energy LLC, NRG New Roads Holdings LLC, NRG Northeast Generating LLC, NRG South Central Generating LLC, Oswego Harbor Power LLC, Somerset Power LLC, and South Central Generation Holding LLC. As of December 31,

2003, three entities remain in bankruptcy. Two entities have been deconsolidated and accounted for under the cost method because we have effectively lost control of those entities including NRG Nelson Turbine, LLC and LSP-Nelson Energy LLC. The other entity NRG McClain LLC is shown as a discontinued operation since it was held for sale prior to filing for bankruptcy.


*	These amounts are listed as liabilities subject to compromise as of December 6, 2003, as these entities remain in bankruptcy.

SFAS No. 144 requires that discontinued operations be valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions our management considered cash flow analyses, bids and offers related to those assets and businesses. This amount is included in (loss)/income on discontinued operations, net of income taxes in the accompanying Statement of Operations. In accordance with the provisions of SFAS No. 144, assets held for sale will not be depreciated commencing with their classification as such.

We have classified certain business operations, and gains/losses recognized on sale, as discontinued operations for projects that were sold or have met the required criteria for such classification.

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

Summarized results of operations of the discontinued operations were as follows. For the years ended December 31, 2001 and December 31, 2002, discontinued results of operations included our Crockett Cogeneration, Bulo Bulo, Csepel, Entrade, Killingholme, NEO Landfill Gas, Inc., or “NLGI”, McClain, Timber Energy Resources, Inc., or “TERI”, three NEO Corporation projects (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC), Cahua and Energia Pacasmayo projects. For the period from January 1, 2003 to December 5, 2003, discontinued results of operations include our Killingholme, McClain, NLGI, NEO Corporation projects, TERI, Cahua and Energia Pacasmayo projects. For the period December 6, 2003 to December 31, 2003, discontinued results of operations include our McClain project.

Operating and other expenses for 2001 and 2002 shown in the table above included asset impairment charges of $0 and approximately $502.0 million, respectively. The 2002 charges are comprised of approximately $477.9 million for the Killingholme project. $12.4 million for the NEO Landfill Gas, Inc. project and $11.7 million for the TERI project. Operating and other expenses for 2003 include asset impairment charges

of approximately $124.3 million, comprised of approximately $100.7 million for McClain, and $23.6 million for NLGI.

The components of income tax benefit attributable to discontinued operations were as follows:

The assets and liabilities of the discontinued operations are reported in the December 31, 2003, December 6, 2003 and December 31, 2002 balance sheets as discontinued operations. The major classes of assets and liabilities are presented by geographic area in the following table. As of December 6, 2003 and December 31, 2003, the North America segment includes the McClain project. As of December 2002, the North America segment includes the McClain project, the Europe segment includes the Killingholme project,

the Other Americas segment includes Cahua and Energia Pacasmayo projects and the Alternative Energy segment includes the NLGI, and TERI projects.

Bulo Bulo — In June 2002, we began negotiations to sell our 60% interest in Compania Electrica Central Bulo Bulo S.A. (Bulo Bulo), a Bolivian corporation. The transaction reached financial close in the fourth quarter of 2002 resulting in cash proceeds of $10.9 million (net of cash transferred of $8.6 million) and a loss of $10.6 million.

Crockett Cogeneration Project — In September 2002, we announced that we had reached an agreement to sell our 57.7% interest in the Crockett Cogeneration Project, a 240 MW natural gas fueled cogeneration plant near San Francisco, California, to Energy Investment Fund Group, an existing LP, and a unit of GE Capital. In November 2002, the sale closed and we realized net cash proceeds of approximately $52.1 million (net of cash transferred of $0.2 million) and a loss on disposal of approximately $11.5 million.

Csepel and Entrade — In September 2002, we announced that we had reached agreements to sell our Csepel power generating facilities (located in Budapest, Hungary) and our interest in Entrade (an electricity trading business headquartered in Prague) to Atel, an independent energy group headquartered in Switzerland. The sales of Csepel and Entrade closed before year-end and resulted in cash proceeds of $92.6 million (net of cash transferred of $44.1 million) and a gain of approximately $24.0 million. We accounted for the results of operations of Csepel and Entrade as part of our power generation segment within Europe.

Killingholme — During third quarter 2002, we recorded an impairment charge of $477.9 million. In January 2003, we completed the sale of our interest in the Killingholme project to our lenders for a nominal value and forgiveness of outstanding debt with a carrying value of approximately $360.1 million at

December 31, 2002. The sale of our interest in the Killingholme project and the release of debt obligations resulted in a gain on sale in the first quarter of 2003 of approximately $191.2 million. The gain results from the write-down of the project’s assets in the third quarter of 2002 below the carrying value of the related debt.

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

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

Peru Projects — In November 2003, we completed the sale of the Cahua and Pacasmayo (Peruvian Assets) resulting in net cash proceeds of approximately $16.2 million and a loss of $36.9 million. In addition, we expect to receive an additional consideration adjustment of approximately $2 million during 2004.

NEO Corporation — In August of 1995, we entered into a Marketing, Development and Joint Proposing Agreement, or “the Marketing Agreement”, with Cambrian Energy Development LLC, or “Cambrian.” Various claims had arisen in connection with this Marketing Agreement. In November 2003, we entered into a Settlement Agreement with Cambrian where we agreed to transfer our 100% interest in three gasco projects (NEO Ft. Smith, NEO Phoenix and NEO Woodville).

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

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

As part of our effort to seek alternative transactions that would provide greater value and in accordance with the bidding procedures approved by the Bankruptcy Court, we conducted an auction for the sale of McClain’s assets, however no bids were submitted for the purchase of the assets. The Bankruptcy Court entered an order approving the terms of the sale with Oklahoma Gas & Electric free and clear of all liens. The closing of the sale is subject to various closing conditions including approval by the Federal Energy Regulatory Commission. Upon consummation of the asset sale, we anticipate that all proceeds from the sale will be used to repay outstanding project debt under the secured term loan and working capital facility.

Note 7 — Write Downs and (Gains)/Losses on Sales of Equity Method Investments

Investments accounted for by the equity method are reviewed for impairment in accordance with APB Opinion No. 18. APB Opinion 18, requires that a loss in value of an investment that is other than a temporary decline should be recognized. Gains are recognized on completion of the sale. Write downs and (gains)/ losses on sales of equity method investments recorded in operating expenses in the consolidated statement of operations includes the following:

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

NEO Corporation — MM Biogas — We recorded an impairment charge of $3.2 million during 2002 to write-down our 50% investment in MM Biogas. This charge was related to revised project outlook and management’s belief that the decline in fair value was other than temporary. In November 2003, we entered into a sales agreement with Cambrian Energy Development to sell our 50% interest in MM Biogas. We recorded an additional impairment charge of $2.6 million during the fourth quarter of 2003 due to developments related to the sale that indicated an impairment of our book value that was considered to be other than temporary.

Kondapalli — In the fourth quarter of 2002, we wrote down our investment in Kondapalli by $12.7 million due to recent estimates of sales value, which indicated an impairment of our book value that was considered to be other than temporary. On January 30, 2003, we signed a sale agreement with the Genting Group of Malaysia, or “Genting”, to sell our 30% interest in Lanco Kondapalli Power Pvt Ltd, or “Kondapalli”, and a 74% interest in Eastern Generation Services (India) Pvt Ltd (the O&M company). Kondapalli is based in Hyderabad, Andhra Pradesh, India, and is the owner of a 368 MW natural gas fired combined cycle gas turbine. In the first quarter of 2003, we wrote down our investment in Kondapalli by $1.3 million based on the final sale agreement. The sale closed on May 30, 2003 resulting in net cash proceeds of approximately $24 million and a gain of approximately $1.8 million. The gain resulted from incurring lower selling costs than estimated as part of the first quarter impairment.

ECKG — In September 2002, we announced that we had reached agreement to sell our 44.5% interest in the ECKG power station in connection with our Csepel power generating facilities, and our interest in Entrade, an electricity trading business, to Atel, an independent energy group headquartered in Switzerland. The transaction closed in January 2003 and resulted in cash proceeds of $65.3 million and a net loss of less than $1.0 million. In accordance with the purchase agreement, we were to receive additional consideration if Atel purchased shares held by our partner. During the second quarter of 2003, we received approximately $3.7 million of additional consideration.

Loy Yang — Based on a third party market valuation and bids received in response to marketing Loy Yang for possible sale, we recorded a write down of our investment of approximately $111.4 million during 2002 ($53.6 million during the third quarter and an additional $57.8 million during the fourth quarter). This write-down reflected management’s belief that the decline in fair value of the investment was other than temporary. Accumulated other comprehensive loss at December 31, 2002 included foreign currency translation losses of approximately $76.7 million related to Loy Yang.

In May 2003, we entered into negotiations that culminated in the completion of a Share Purchase Agreement to sell 100% of the Loy Yang project. Completion of the sale is subject to various conditions. Upon completion, the sale will result in proceeds of approximately $25.0 million to $31.0 million to us; however, the final sale proceeds will vary depending on the foreign exchange rate and purchase price adjustments. Consequently, we recorded an additional impairment charge of approximately $146.4 million during 2003.

Mustang Station — On July 7, 2003, we completed the sale of our 50% interest in Mustang Station, a gas-fired combined cycle power generating plant located in Denver City, Texas, to EIF Mustang Holdings I, LLC. The sale resulted in net cash proceeds of approximately $13.3 million and a net gain of approximately $12.1 million.

Energy Development Limited — On July 25, 2002, we announced that we completed the sale of our ownership interests in an Australian energy company, Energy Development Limited, or “EDL.” EDL is a listed Australian energy company engaged in the development and management of an international portfolio of projects with a particular focus on renewable and waste fuels. In October 2002, we received proceeds of $78.5 million (AUS), or approximately $43.9 million (USD), in exchange for our ownership interest in EDL with the closing of the transaction. During the third quarter of 2002, we recorded a write-down of the investment of approximately $14.2 million to write down the carrying value of our equity investment due to the pending sale.

Sabine River — In September 2002, we agreed to transfer our indirect 50% interest in SRW Cogeneration LP, or “SRW”, to our partner in SRW, Conoco, Inc. in consideration for Conoco’s agreement to terminate or assume all of our obligations, in relation to SRW. SRW owns a cogeneration facility in Orange County, Texas. We recorded a charge of approximately $48.4 million during the quarter ended September 30, 2002 to write down the carrying value of our investment due to the pending sale. The transaction closed on November 5, 2002.

Kingston — In December 2002, we completed the sale of our 25% interest in Kingston Cogeneration LP, based near Toronto, Canada to Northland Power Income Fund. We received net proceeds of $15.0 million resulting in a gain on sale of approximately $9.9 million.

Mt. Poso — In September 2002, we agreed to sell our 39.5% indirect partnership interest in the Mt. Poso Cogeneration Company, a California limited partnership, or “Mt. Poso”, for approximately $10 million to Red Hawk Energy, LLC. Mt. Poso owns a 49.5 MW coal-fired cogeneration power plant and thermally enhanced oil recovery facility located 20 miles north of Bakersfield, California. The sale closed in November 2002 resulting in a loss of approximately $1.0 million.

Powersmith — During the fourth quarter of 2002, we wrote down our investment in Powersmith in the amount of approximately $3.4 million due to recent developments, which indicated impairment of our book value that is considered to be other than temporary.

Collinsville Power Station — Based on third party market valuation and bids received in response to marketing the investment for possible sale, we recorded a write down of our investment of approximately $4.1 million during the second quarter of 2002. In August 2002, we announced that we had completed the sale of our 50% interest in the 192 MW Collinsville Power Station in Australia, to our partner, a subsidiary of Transfield Services Limited for $8.6 million (AUS), or approximately $4.8 million (USD). Our ultimate loss on the sale of Collinsville Power Station was approximately $3.6 million.

Restructuring, impairment charges, legal settlement costs and fresh start adjustments included in operating expenses in the Consolidated Statement of Operations include the following:

We review the recoverability of our long-lived assets in accordance with the guidelines of SFAS No. 144. As a result of this review, we recorded impairment charges of $2.6 billion and $228.9 million for the year ended December 31, 2002 and the period from January 1, 2003 through December 5, 2003 respectively, as shown in the table below.

To determine whether an asset was impaired, we compared asset carrying values to total future estimated undiscounted cash flows. Separate analyses were completed for assets or groups of assets at the lowest level for which identifiable cash flows were largely independent of the cash flows of other assets and liabilities. The estimates of future cash flows included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of our assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service were based on the asset’s existing service potential. The cash

flow estimates may include probability weightings to consider possible alternative courses of action and outcomes, given the uncertainty of available information and prospective market conditions.

Impairment charges (credits) included the following asset impairments (realized gains) for the year ended December 31, 2002 and for the period January 1, 2002 to December 5, 2003:

Credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity experienced during the third quarter of 2002 were “triggering events” which required us to review the recoverability of our long-lived assets. Adverse economic conditions resulted in declining energy prices. Consequently, we determined that many of our construction projects and operational projects were impaired during the third quarter of 2002 and should be written down to fair market value.

Connecticut Facilities — As a result of regulatory developments and changing circumstances in the second quarter of 2003, we updated the facilities’ cash flow models to incorporate changes to reflect the impact of the April 25, 2003 FERC’s orders on regional and locational pricing, and to update the estimated impact of future locational capacity or deliverability requirements. Based on these revised cash flow models, management determined that the new estimates of pricing and cost recovery levels were not projected to return sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown Power LLC. As a consequence, during the second quarter of 2003 we recorded $64.2 million and $157.3 million as impairment charges for Devon Power LLC and Middletown Power LLC, respectively.

Langage (UK) — During the third quarter of 2002, we reviewed the recoverability of our Langage assets pursuant to SFAS No. 144 and recorded a charge of $42.3 million. In August 2003 we closed on the sale of Langage to Carlton Power Limited resulting in net cash proceeds of approximately $1.5 million, of which $1.0 million was received in 2003 and $0.5 million during the first quarter of 2004, and a net gain of approximately $3.1 million.

Arthur Kill Power, LLC — During the third quarter of 2003, we cancelled our plans to re-establish fuel oil capacity at our Arthur Kill plant. This resulted in a charge of approximately $9.0 million to write-off assets under development.

Turbines — In October 2003, we closed on the sale of three turbines and related equipment. The sale resulted in net cash proceeds of $70.7 million and a gain of approximately $21.9 million.

Berrians Project — During the fourth quarter of 2003, we cancelled plans to construct the Berrians peaking facility on the land adjacent to our Astoria facility. Berrians was originally scheduled to commence operations in the summer of 2005; however, based on the remaining costs to complete and the current risk profile of merchant peaking units, the construction project was terminated. This resulted in a charge of approximately $14.3 million to write off the project’s assets.

Termo Rio — Termo Rio is a 1040 green field cogeneration project located in the state of Rio de Janeiro, Brazil. Based on the project’s failure to meet certain key milestones, we exercised our rights under the project agreements to sell our debt and equity interests in the project to our partner. We are in arbitration over the amount of compensation we are to receive for our interests in the project. Based on continued negotiations aimed at settling the case and the positions of the parties in the arbitration we recorded an impairment charge of $6.4 million to reflect our investment interest at the amount expected to be recovered through a sale. On March 8, 2003, the arbitral tribunal decided most, but not all, of the issues in our favor. The final amount of the arbitral award to NRG has not been conclusively determined and the parties may seek to modify or challenge the award. We believe we will recover the amount we have recorded on our balance sheet.

There were no impairment charges for the period December 6, 2003 through December 31, 2003.

For the period from January 1, 2003 to December 5, 2003, we incurred $197.8 million in reorganization costs and for the period from December 6, 2003 to December 31, 2003 we incurred $2.5 million in

reorganization costs. All reorganization costs have been incurred since we filed for bankruptcy in May 2003. The following table provides the detail of the types of costs incurred:

During the third quarter of 2003, we recorded $396.0 million in connection with the resolution of the FirstEnergy Arbitration Claim. As a result of this resolution, FirstEnergy retained ownership of the Lake Plant Assets and received an allowed general unsecured claim of $396.0 million under the NRG plan of reorganization submitted to the Bankruptcy Court.

In August of 1995, we entered into a Marketing, Development and Joint Proposing Agreement, “the Marketing Agreement”, with Cambrian Energy Development LLC, or “Cambrian.” Various claims had arisen in connection with this Marketing Agreement. In November 2003, we entered into a Settlement Agreement with Cambrian where we agreed to transfer our 100% interest in three gasco projects (NEO Ft. Smith, NEO Phoenix and NEO Woodville) and our 50% interest in two genco projects (MM Phoenix and MM Woodville) to Cambrian. In addition, we agreed to pay approximately $1.8 million in settlement of royalties incurred in connection with the Marketing Agreement. We had previously recorded a liability for royalties owed to Cambrian therefore we recorded an additional $1.4 million during November 2003.

In November 2003, we settled our dispute with Dick Corporation in connection with Meriden Gas Turbines, which resulted in our recording an additional liability of $8.0 million in November, 2003.

During the fourth quarter of 2003, we recorded a credit of $3.9 billion in connection with fresh start adjustments as discussed in Note 3. Following is a summary of the significant effects of the reorganization and Fresh Start:

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

We identified certain retirement obligations within our power generation operations related to our North America projects in the South Central region, the Northeast region, Australia, our Alternative Energy projects and our Thermal projects. These asset retirement obligations are related primarily to the future dismantlement of equipment on leased property and environment obligations related to ash disposal site closures. We also identified other asset retirement obligations including plant dismantlement that could not be calculated because the assets associated with the retirement obligations were determined to have an indeterminate life. The adoption of SFAS No. 143 resulted in recording a $2.6 million increase to property, plant and equipment and a $4.2 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was recorded as a $0.6 million increase to depreciation expense and a $1.6 million increase to cost of majority-owned operations in the period from January 1, 2003 to December 5, 2003 as we considered the cumulative effect to be immaterial.

The following represents the balances of the asset retirement obligation as of January 1, 2003 and the additions and accretion of the asset retirement obligation for the periods January 1, 2003 through December 5, 2003 and the period of December 6, 2003 through December 31, 2003, which is included in other long-term obligations in the consolidated balance sheet. Prior to December 5, 2003, we completed our annual review of asset retirement obligations. As part of that review we made revisions to our previously recorded obligation in the amount of $4.0 million. The revisions included identification of new obligations as well as changes in costs or procedures required at retirement date. As a result of adopting Fresh Start we revalued our asset retirement obligations on December 6, 2003. We recorded an additional asset retirement obligation of $7.3 million in connection with fresh start reporting. This amount results from a change in the discount rate used between adoption and fresh starting reporting as of December 5, 2003, equal to 500 to 600 basis points.

The following represents the pro-forma effect on our net income for the twelve months ended December 31, 2001 and 2002, as if we had adopted SFAS No. 143 as of January 1, 2001:

On a pro forma basis an Asset Retirement obligation of $8.4 million and $10.1 million would have been recorded as an other long-term obligation as of January 1, 2002 and December 31, 2002, based on similar assumptions used to determine the amounts on our balance sheet as of December 6, 2003 and December 31, 2003.

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

Notes receivable consists primarily of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. The notes receivable are as follows:

Investment in bonds is comprised of marketable debt securities. These securities consist of municipal bonds of Audrain County, Missouri and Mississippi Industrial Revenue Bonds. The Audrain County bonds mature in 2023 and the Mississippi Industrial bonds mature in 2010. These investments in bonds are classified as held to maturity and are recorded at amortized cost. The carrying value of these bonds approximates fair value. Both the Audrain County bonds and the Mississippi Industrial Revenue Bonds are pledged as collateral for the related debt owed to each county. As further described in Note 17, each of these transactions have offsetting obligations.

Included in construction in progress at December 31, 2002 is approximately $248.9 million related to turbines associated with cancelled projects. As of December 5, 2003 and December 31, 2003, $55.0 million of turbine cost associated with cancelled projects has been reclassified to the other asset line in the accompanying balance sheet.

We had investments in various international and domestic energy projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents us from exercising a controlling influence over operating and financial

policies of the projects. Under this method, equity in pretax income or losses of domestic partnerships and, generally, in the net income or losses of international projects, are reflected as equity in earnings of unconsolidated affiliates.

A summary of certain of our more significant equity-method investments, which were in operation at December 31, 2003, is as follows:

Summarized financial information for investments in unconsolidated affiliates accounted for under the equity method is as follows:

We have a 50% interest in one company (West Coast Power LLC) that was considered significant as of December 31, 2003, as defined by applicable SEC regulations, we account for our investment using the equity method. Upon adoption of Fresh Start we adjusted our investment in West Coast Power to fair value as of December 6, 2003. In accordance with APB Opinion 18, we have reconciled the value of our investment as of December 6, 2003 to our share of West Coast Powers partner’s equity. As a result of pushing down the impact of Fresh Start to the projects balance sheet we determined that a contract based intangible asset with a one year remaining life, consisting of the value of West Coast Power’s CDWR energy sales contract, must be established and recognized as a basis adjustment to our share of the future earnings generated by West Coast Power. This adjustment will reduce our equity earnings in the amount of approximately $10.4 million per month during 2004 until the contract expires in December 2004. Offsetting this reduction in earnings is a favorable adjustment to reflect a lower depreciation expense resulting from the corresponding reduced value of the project’s fixed assets from Fresh Start reporting. During the period December 6, 2003 through December 31, 2003 we recorded equity earnings of $9.4 million for West Coast Power after adjustments for the reversal of $2.6 million project level depreciation expense, offset by a decrease in earnings related to $8.8 million amortization of the intangible asset for the CDWR contract. The following table summarizes financial information for West Coast Power LLC, including interests owned by us and other parties for the periods shown below:

We are required by the State of Louisiana Department of Environmental Quality, or “DEQ”, to rehabilitate our Big Cajun II ash and wastewater impoundment areas, subsequent to the Big Cajun II facilities’ removal from service. On July 1, 1989, a guarantor trust fund, or “the Solid Waste Disposal Trust

Fund”, was established to accumulate the estimated funds necessary for such purpose. Approximately $1.1 million was initially deposited in the Solid Waste Disposal Trust Fund in 1989, and $116,000 has been funded annually thereafter, based upon an estimated future rehabilitation cost (in 1989 dollars) of approximately $3.5 million and the remaining estimated useful life of the Big Cajun II facilities. At December 31, 2002, December 6, 2003 and December 31, 2003, the carrying value of the trust fund investments was approximately $4.6 million, $4.8 million and $4.8 million, respectively. The trust fund investments are comprised of various debt securities of the United States and are carried at amortized cost, which approximates their fair value. The amounts required to be deposited in this trust fund are separate from our calculation of the asset retirement obligation recorded for the Big Cajun II ash and waste water impoundment areas discussed in Note No. 9.

During the first quarter of 2002, we adopted SFAS No. 142 — “Goodwill and Other Intangible Assets” or “SFAS No. 142”, which requires new accounting for intangible assets, including goodwill. Intangible assets with finite lives will be amortized over their economic useful lives and periodically reviewed for impairment. Goodwill will no longer be amortized, but will be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value. Upon the adoption of Fresh Start, we re-evaluated the recoverability of our goodwill and intangibles. As a result, we have written off all goodwill amounts as of December 5, 2003. We have also established certain other contract based intangibles, which will be amortized over their respective contractual lives.

We had intangible assets with a net carrying value of $76.6 million at December 31, 2002. The Aggregate amortization expense recognized for the years ended December 31, 2002 and 2001 was approximately $2.8 million and $4.2 million, respectively. The amortization expense for the period January 1, 2003 through December 5, 2003 was $3.8 million.

We had intangible assets with a net carrying value of $486.7 million and $481.5 million at December 6, 2003 and December 31, 2003. The power purchase agreements will be amortized as a reduction to revenue over the terms and conditions of each contract. The weighted average amortization period is 7 years for the power purchase agreements. Emission allowances will be amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023. The amortization expense for the period December 6, 2003 through December 31, 2003 was $5.2 million related to power purchase agreements. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $57.5 million in year one, $37.4 million in year two, $30.2 million in years three and four, and $23.3 million in

year five for both the power purchase agreements and emission allowances. Intangible assets consisted of the following:


*	Written off as part of Fresh Start since service contracts determined to be at current market rates.


**	No amortization recorded in 2003 as this balance includes only emission allowances for 2004 and beyond. All emission allowances for 2003 were used prior to December 5, 2003.

The following table summarizes the pro forma impact of implementing SFAS No. 142 at January 1, 2001 on net income (loss) for the periods presented.

We have adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” or “SFAS No. 133”, 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. Changes in the fair value of non-hedge derivatives will be immediately recognized in earnings. The criteria used to determine if hedge accounting treatment is appropriate are a) the designation of the hedge to an underlying exposure, b) whether or not the overall risk is being reduced and c) if there is a high degree of correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in fair values of derivatives accounted for as hedges will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income, or “OCI”, until the hedged

transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings. We also formally assess both at inception and at least quarterly thereafter, whether the derivatives that are used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

SFAS No. 133 applies to our long-term power sales contracts, long-term gas purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. SFAS No. 133 also applies to various interest rate swaps used to mitigate the risks associated with movements in interest rates and foreign exchange contracts to reduce the effect of fluctuating foreign currencies on foreign denominated investments and other transactions. At December 31, 2003, we had commodity contracts extending through December 2020.

As of December 6, 2003 and December 31, 2003, neither we nor our consolidating subsidiaries had any outstanding foreign currency exchange contracts. At December 31, 2002, we had various foreign currency exchange instruments with combined notional amounts of $3.0 million. These foreign currency exchange instruments were hedges of expected future cash flows. If the hedges had been terminated at December 31, 2002, we would have owed the counter-parties $0.3 million.

At December 31, 2002, December 6, 2003 and December 31, 2003, our consolidating subsidiaries had various interest-rate swap agreements with combined notional amounts of $1.7 billion, $617.4 million and $620.5 million, respectively. These contracts are used to manage our exposure to changes in interest rates. If these swaps had been terminated at December 31, 2002, December 6, 2003 and December 31, 2003, we would have owed the counter-parties $41.0 million, $53.6 million and $50.2 million, respectively.

At December 31, 2002, December 6, 2003 and December 31, 2003, we had various energy related commodities financial instruments with combined notional amounts of $241.8 million, $519.7 million and $521.1 million, respectively. These financial instruments take the form of fixed price, floating price or indexed sales or purchases, options, such as puts or calls, basis transactions and swaps. These contracts are used to manage our exposure to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. If these contracts were terminated at December 31, 2002, December 6, 2003 and December 31, 2003, we would have received $58.5 million, $46.3 million and $46.0 million, from counter-parties, respectively. As of December 31, 2003, we had various long-term power sales contracts with combined notional amounts of approximately $3.2 billion.

We have an established credit policy in place to minimize our overall credit risk. Important elements of this policy include ongoing financial reviews of all counter-parties, established credit limits, as well as monitoring, managing and mitigating credit exposure.

The following table summarizes the effects of SFAS No. 133 on our other comprehensive income balance as of December 31, 2003:

During the period ended December 31, 2003, we recorded a loss in OCI of approximately $0.5 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of December 31, 2003 was an unrecognized loss of approximately $0.5 million. We expect $2.1 million of deferred net gains on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

The following table summarizes the effects of SFAS No. 133 on our other comprehensive income balance as of December 6, 2003:

During the period ended December 5, 2003, we reclassified losses of $32.0 million from OCI to current-period earnings as a result of the discontinuance of cash flow hedges because it is probable that the original forecasted transactions will not occur by the end of the originally specified time period. Additionally, gains of $114.8 million were reclassified from OCI to current period earnings during the period ended December 5, 2003 due to the unwinding of previously deferred amounts. These amounts are recorded on the same line in the statement of operations in which the hedged items are recorded. Also during the period ended December 5, 2003, we recorded a gain in OCI of approximately $51.4 million related to changes in the fair values of derivatives accounted for as hedges. Our plan of reorganization became effective December 5, 2003

and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net losses recorded in OCI of $5.1 million.

The following table summarizes the effects of SFAS No. 133 on our other comprehensive income balance as of December 31, 2002:

During the year ended December 31, 2002, we reclassified gains of $23.3 million from OCI to current-period earnings as a result of the discontinuance of cash flow hedges because it is probable that the original forecasted transactions will not occur by the end of the originally specified time period. Also, gains of $6.1 million were reclassified from OCI to current period earnings due to the hedge items being terminated by the counterparties. Additionally, gains of $53.2 million were reclassified from OCI to current period earnings during the year ended December 31, 2002 due to the unwinding of previously deferred amounts. These amounts are recorded on the same line in the statement of operations in which the hedged items are recorded. Also during the year ended December 31, 2002, we recorded a gain in OCI of approximately $37.7 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of December 31, 2002 was an unrecognized gain of approximately $26.3 million.

The following tables summarize the effects of SFAS No. 133 on our statement of operations for the period from December 6, 2003 through December 31, 2003:

The following tables summarize the effects of SFAS No. 133 on our statement of operations for the period from January 1, 2003 through December 5, 2003:

The following tables summarize the effects of SFAS No. 133 on our statement of operations for the period ended December 31, 2002:

The following tables summarize the effects of SFAS No. 133 on our statement of operations for the period ended December 31, 2001:

We are exposed to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. In order to manage these commodity price risks, we enter into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. Certain of these transactions have been designated as cash flow hedges. We have accounted for these derivatives by recording the effective portion of the cumulative gain

or loss on the derivative instrument as a component of OCI in shareholders’ equity. We recognize deferred gains and losses into earnings in the same period or periods during which the hedged transaction affects earnings. Such reclassifications are included on the same line of the statement of operations in which the hedged item is recorded.

No ineffectiveness was recognized on commodity cash flow hedges during the years ended December 31, 2001, December 31, 2002 or during the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003.

Our pre-tax earnings for the years ended December 31, 2001, December 31, 2002, the period January 1, 2003 through December 5, 2003 and the period December 6, 2003 through December 31, 2003, were affected by an unrealized gain of $14.1 million, an unrealized gain of $20.0 million, an unrealized gain of $53.7 million and an unrealized loss of $0.7 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

During the year ended December 31, 2002, we reclassified gains of $83.7 million from OCI to current-period earnings. During the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003 gains of $112.5 and $0 million, respectively, were reclassified from OCI to current-period earnings. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net gains recorded in OCI of $61.0 million on energy related derivative instruments accounted for as hedges. We expect to reclassify an additional $1.3 million of deferred gains to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

To manage interest rate risk, we have entered into interest-rate swaps that effectively fix the interest payments of certain floating rate debt instruments. Interest-rate swap agreements are accounted for as cash flow hedges. The effective portion of the cumulative gain or loss on the derivative instrument is reported as a component of OCI in shareholders’ equity and recognized into earnings as the underlying interest expense is incurred. Such reclassifications are included on the same line of the statement of operations in which the hedged item is recorded.

No ineffectiveness was recognized on interest rate cash flow hedges during the year ended December 31, 2002 or during the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003.

Our pre-tax earnings for the years ended December 31, 2001 and 2002 were increased by an unrealized loss of $0 and $32.0 million, respectively, associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

Our pre-tax earnings for the period January 1, 2003 through December 5, 2003 and the period December 6, 2003 through December 31, 2003, were affected by an unrealized loss of $15.1 million and an unrealized gain of $2.0 million, respectively, associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

During the year ended December 31, 2002, we reclassified gains of $0.9 million from OCI to current-period earnings. During the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003 losses of $29.7 and $0 million, respectively, were reclassified from OCI to current-period earnings. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net losses recorded in OCI of $65.9 million on interest rate swaps accounted for as hedges. We

expect to reclassify an additional $0.7 million of deferred gains to earnings during the next twelve months on interest rate swaps accounted for as hedges.

To preserve the U.S. dollar value of projected foreign currency cash flows, we may hedge, or protect those cash flows if appropriate foreign hedging instruments are available.

No ineffectiveness was recognized on foreign currency cash flow hedges during the years ended December 31, 2001, December 31, 2002 or during the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003.

Our pre-tax earnings for the years ended December 31, 2001 and 2002 were increased by an unrealized gain of $0.3 million and $0.3 million, respectively, associated with foreign currency hedging instruments not accounted for as hedges in accordance with SFAS No. 133.

Our pre-tax earnings for the period January 1, 2003 through December 5, 2003 and the period December 6, 2003 through December 31, 2003, were increased by an unrealized gain of $0.1 million and $0, respectively, associated with foreign currency hedging instruments not accounted for as hedges in accordance with SFAS No. 133.

During the year ended December 31, 2002, we reclassified losses of $2.1 million from OCI to current period earnings. During the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003 losses of $0 and $0 million, respectively, were reclassified from OCI to current-period earnings. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net losses recorded in OCI of $0.2 million on foreign currency swaps accounted for as hedges. We do not expect to reclassify any deferred gains or losses to earnings during the next twelve months on foreign currency swaps accounted for as hedges.


(1)	We have reclassified the long-term portions of these debt issuances to current as they were callable within one year from December 31, 2003.

(2)	Distinguishes debt with various interest rates.

(3)	A+2 equals Libor plus 2%

(4)	A+ 3.5 equals Libor plus 3.5%

(5)	We have reclassified the long-term portions of these debt issuances to current, as they were callable within one year from December 6, 2003.

As of December 31, 2003, we have timely made scheduled payments on interest and/or principal on all of our recourse debt and were not in default under any of our related recourse debt instruments. However, a significant amount of our subsidiaries’ debt and other obligations contain terms that require that they be supported with letters of credit or cash collateral following a ratings downgrade or a default on our debt. As of December 31, 2003, as a result of the downgrades and loan defaults that we experienced in 2002, we estimate that we were in default of our obligations to post collateral of approximately $71.4 million, principally to fund contract termination penalties, revenue shortfall guarantees and late completion penalties related to NRG Peaker Finance Company LLC. On January 6, 2004, the debt held at NRG Peaker Finance Company LLC was restructured, and this collateral obligation ceased. As a result, we currently have no unmet cash collateral obligations outstanding.

On December 23, 2003, we entered into a bank facility for up to $1.45 billion, or “New Credit Facility”, which included a $950.0 million, six and a half-year senior secured term loan, a $250.0 million funded letter of credit facility, and a four-year $250.0 million revolving line of credit, or “corporate revolver”. Portions of the corporate revolver are available as a swing-line facility and as a revolving letter of credit sub-facility. As of

December 31, 2003, the corporate revolver was undrawn. The $250 million funded letter of credit is reflected as a funded deposit on the December 31, 2003 balance sheet.

As a result of our bankruptcy filing, we ceased recording accrued interest on the following unsecured facilities, as it was not probable of being paid. On December 5, 2003, concurrent with our emergence from bankruptcy, the following senior unsecured facilities were terminated in conjunction with certain settlement provisions. We have no outstanding obligations with respect to the following terminated debt facilities:


	•	NRG Energy ROARS, due March 15, 2020, 7.97%; $250.0 million in outstanding principal, $25.3 million in accrued interest, and $41.1 million in contractually obligated interest at date of termination;

	•	NRG Energy senior debentures, or “corporate units”, due May 16, 2006, 6.5%; $287.5 million in outstanding principal, $14.2 million in accrued interest, and $26.5 million in contractually obligated interest at date of termination;

	•	NRG Energy senior notes due February 1, 2006, 7.625%; $125.0 million in outstanding principal, $7.7 million in accrued interest, and $14.2 million in contractually obligated interest at date of termination;

	•	NRG Energy senior notes due July 15, 2006, 6.75%; $340.0 million in outstanding principal, $21.9 million in accrued interest, and $34.9 million in contractually obligated interest at date of termination;

	•	NRG Energy senior notes due June 15, 2007, 7.50%; $250.0 million in outstanding principal, $19.4 million in accrued interest, and $30.7 million in contractually obligated interest at date of termination;

	•	NRG Energy senior notes due June 1, 2009, 7.50%; $300.0 million in outstanding principal, $20.4 million in accrued interest, and $37.9 million in contractually obligated interest at date of termination;

	•	NRG Energy senior notes due September 15, 2010, 8.25%; $350.0 million in outstanding principal, $34.5 million in accrued interest, and $56.9 million in contractually obligated interest at date of termination;

	•	NRG Energy senior notes, due April 1, 2011, 7.75%; $350.0 million in outstanding principal, $31.2 million in accrued interest, and $51.5 million in contractually obligated interest at date of termination;

	•	NRG Energy senior notes, due November 1, 2003, 8.00%; $240.0 million in outstanding principal, $17.5 million in accrued interest, and $34.6 million in contractually obligated interest at date of termination;

	•	NRG Energy senior notes, due April 1, 2031, 8.625%; $340.0 million and $160 million in outstanding principal, and $49.7 million in accrued interest, and $83.0 million in contractually obligated interest at date of termination; and

	•	NRG Energy corporate revolver, due March 8, 2003; $930.5 million in outstanding principal, $57.7 million in accrued interest, and $84.8 million in contractually obligated interest at date of termination.

As part of and concurrent with the emergence from bankruptcy, certain unsecured creditors received rights to $500.0 million of 10% NRG Energy senior notes, or “POR Notes” to be issued by us. However, the creditors accepted $500 million in cash in lieu of the POR Notes, on December 23, 2003 in conjunction with the financing described below. Accrued interest of $2.5 million was paid to these creditors based on the notional amount of the POR Notes. As of December 31, 2003, there were no outstanding obligations with respect to the POR Notes.

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

Also on December 23, 2003, concurrently with the offering of the notes, we and PMI entered into the New Credit Facility for up to $1.45 billion with Credit Suisse First Boston, as Administrative Agent, and Lehman Commercial Paper, Inc., as Syndication Agent and a group of lenders. The New Credit Facility consists of a $950 million, six and a half-year senior secured term loan facility, a $250 million, funded letter of credit facility, and a four-year revolving credit facility in an amount of up to $250 million. Portions of the revolving credit facility are available as a swing-line facility and as a revolving letter of credit sub-facility. No borrowings had been made under the revolving credit facility as of December 31, 2003. Under the letter of credit facility, $1.7 million had been issued as of December 31, 2003.

The New Credit Facility is secured by, among other things, first-priority perfected security interests in all of the property and assets owned at any time or acquired by us and our subsidiaries, other than the property and assets of certain excluded project subsidiaries, foreign subsidiaries and certain other subsidiaries, with some exceptions.

Interest on the New Credit Facility consists of a spread of either 3% over prime or 4% over a LIBO rate, to be selected by the borrower. Other expenses associated with the New Credit Facility include commitment fees on the undrawn portion of the letter of credit facility, participation fees for the credit-linked deposit and other fees. As of December 31, 2003, we did not have an interest rate swap in place to hedge against fluctuations in prime or LIBO rates. On February 25, 2004 we amended the new credit facility to remove this requirement.

Proceeds of the December 23, 2003 Second Priority Notes issuance and the New Credit Facility were used for the following purposes:


	•	Repayment of secured debt held by NRG Northeast Generating LLC, including $556.5 million in outstanding principal, $1.1 million in accrued interest, and $8.3 million in a make-whole premium;

	•	Repayment of secured debt held by NRG South Central Generating LLC, including $750.8 million in outstanding principal, $18.7 million in accrued interest, and $11.3 million in a make-whole premium;

	•	Repayment of secured debt held by NRG Mid-Atlantic Generating LLC, including $406.6 million in outstanding principal and $4.1 million in accrued interest;

	•	Funding of the $250 million letter of credit facility under the New Credit Facility;

	•	Payment of cash in lieu of the $500 million, 10% POR Notes to be issued to certain unsecured creditors; and

Significant affirmative covenants of the Second Priority Notes and the New Credit Facility include the provision of financial reports, reports of any events of default or developments that could have a material adverse effect, provision of notice with respect to changes in corporate structure or collateral. In addition, the borrower must maintain segregated cash accounts for certain deposits or settlements. A provision that the borrower enter into an interest-rate swap agreement on a portion of the term loan was waived by the lenders pursuant to an amendment to the New Credit Agreement.

Significant negative covenants of the Second Priority Notes and the New Credit Facility include limitations on permitted indebtedness, including the provision of intercompany loans among certain subsidiaries and affiliates; permitted liens; permitted acquisitions and certain asset dispositions. In addition, certain financial ratio tests must be met.

Events of default under the Second Priority Notes and the New Credit Facility include materially false representation or warranty; payment default on principal or interest; covenant defaults; cross-defaults to material indebtedness; our or a material subsidiary’s bankruptcy and insolvency; material unpaid judgments; ERISA events; failure to be perfected on any material collateral; and a change in control.

On January 28, 2004, we issued an additional $475.0 million in Second Priority Notes, under the same terms and indenture as our December 23, 2003 offering. Proceeds of the offering were used to prepay $503.5 million of the outstanding principal on the term loan under the New Credit Facility, described below, reducing the outstanding principal of the term loan from $950.0 million to $446.5 million.

For discussion of NRG FinCo, the Audrain capital lease and LSP Pike Energy LLC see Note 24.

The LSP Kendall Energy LLC credit facility is non-recourse to us and consists of a construction and term loan, working capital and letter of credit facilities. As of December 31, 2002, December 6, 2003 and December 31, 2003, there were borrowings totaling approximately $495.8 million, $489.2 million and $487.0 million, respectively, outstanding under the facility at a weighted average annual interest rate of 3.15%, 2.58% and 2.58%, respectively. In May 2002, LSP-Kendall Energy, LLC received a notice of default from Societe Generale, the administrative agent under LSP-Kendall’s Credit and Reimbursement Agreement dated November 12, 1999. The notice asserted that an event of default had occurred under the Credit and Reimbursement Agreement as a result of liens filed against the Kendall project by various subcontractors. In consideration of the borrower’s implementation of a plan to remove the liens, and our indemnification pursuant to an Indemnity Agreement dated June 28, 2002, of the lenders to the Kendall project from any claims or damages relating to these liens or any dispute or action involving the project’s EPC contractor, the administrative agent, with the consent of the required lenders under the Credit and Reimbursement Agreement, withdrew the notice of default and conditionally waived any default or event of default described therein. Discussions with the administrative agent regarding the liens continue. On August 25, 2003, LSP-Kendall Energy LLC entered into a Completion Extension and Amendment Agreement with the lenders and Societe Generale whereby certain extensions were granted in respect of project construction, lien removal and other items. The Completion Extension and Amendment Agreement prohibits LSP-Kendall Energy LLC from making any distributions to equity owners until January 1, 2005, and thereafter only when certain conditions are met. LSP-Kendall Energy LLC continues to be in default with respect to certain covenants, however, and is in discussions with the lenders regarding restructuring its indebtedness.

In May 1999, LSP Energy Limited Partnership, or “Partnership” and LSP Batesville Funding Corporation, or “Funding” issued two series of Senior Secured Bonds, or “Bonds” in the following total principal amounts: $150 million 7.16% Series A Senior Secured Bonds due 2014 and $176 million 8.160% Series B Senior Secured Bonds due 2025. Interest is payable semiannually on each January 15 and July 15. In

March 2000, a registration statement was filed by Partnership and Funding and became effective. The registration statement was filed to allow the exchange of the Bonds for two series of debt securities, or “Exchange Bonds”, which are in all material respects substantially identical to the Bonds. The Exchange Bonds are secured by substantially all of the personal property and contract rights of the Partnership and Funding. The Exchange Bonds are redeemable, at the option of Partnership and Funding, at any time in whole or from time to time in part, on not less than 30 nor more than 60 days prior notice to the holders of that series of Exchange Bonds, on any date prior to their maturity at a redemption price equal to 100% of the outstanding principal amount of the Exchange Bonds being redeemed and a make whole premium. In no event will the redemption price ever be less than 100% of the principal amount of the Exchange Bonds being redeemed plus accrued and unpaid interest thereon. Principal payments are payable on each January 15 and July 15 beginning July 15, 2001. Under the credit arrangements, the project is required to maintain minimum cash balances in certain reserve funds. Subject to funding these reserve accounts and anticipated working capital needs, and meeting certain debt coverage tests, the project may distribute any remaining cash to us. As of December 31, 2003, Batesville had sufficiently funded its reserve accounts, but did not meet its debt coverage test.

In June 2002, NRG Peaker Finance Company LLC, or “NRG Peaker”, an indirect wholly owned subsidiary, completed the issuance of $325 million of Series A Floating Rate Senior Secured Bonds due 2019. The bonds bear interest at a floating rate equal to three-month LIBOR plus 1.07%. Interest on the bonds is payable on March 10, June 10, September 10 and December 10 of each year, commencing on September 10, 2002. NRG Peaker subsequently entered into an interest rate swap agreement pursuant to which it agreed to make 6.67% fixed rate interest payments and receive floating rate interest payments. XL Capital Assurance, or “XLCA”, guarantees principal, interest and swap payments, through a financial guaranty insurance policy. Such notes are also secured by substantially all of the assets of and/or membership interests in our subsidiaries: Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG Rockford II LLC and NRG Rockford Equipment LLC. As of December 31, 2003, $311.4 million in aggregate principal remained outstanding on these bonds. XLCA accelerated the bonds due to cross-defaults on our debt and liens placed upon certain assets. On January 6, 2004, we and XLCA consummated a comprehensive restructuring arrangement which provides for, among other things, the provision of a letter of credit by us for the benefit of the secured parties in the NRG Peaker financing, the cure or waiver of all defaults under the original financing agreement and the mutual release of claims by the parties. With the exception of distributions to pay taxes, distributions to equity holders are subject to tests regarding NRG Peaker reserve funding and financial ratios.

In May 2001, our wholly-owned subsidiary, NRG Finance Company I LLC, or “NRG FinCo”, entered into a $2.0 billion revolving credit facility. The facility was established to finance the acquisition, development and construction of power generating plants located in the United States and to finance the acquisition of turbines for such facilities. The facility provided for borrowings of base rate loans and Eurocurrency loans and was secured by mortgages and security agreements in respect of the assets of the projects financed under the facility, pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects, and by guaranties from each such subsidiary or affiliate. The NRG FinCo secured revolver was initially scheduled to mature on May 8, 2006; however, due to defaults hereunder by NRG FinCo and applicable guarantors, the lenders accelerated all outstanding obligations on November 6, 2002. As of our emergence, $1.1 billion was outstanding under the facility, and there was an aggregate of approximately $58 million of accrued but unpaid interest and commitment fees. Of this, $842.0 million was allowed in unsecured claims under NRG plan of reorganization, and was settled at the time of our emergence. The remaining balance will be satisfied when the NRG FinCo lenders exercise their perfected security interests in our Nelson, Audrain and Pike projects (see note 24).

Meriden Gas Turbines LLC, or “MGT” is party to a $0.5 million Promissory Note and Security Agreement with PowerSource LLC, issued and entered into on February 13, 2003. MGT used the proceeds of

the note issuance to allow the release of a lien and claim on certain MGT assets, and for costs associated with the transport of certain equipment to the MGT site. The note became due and payable on May 14, 2003. We expect to repay this note with the proceeds from the sale of the MGT assets in 2004.

In March 2001, we increased our ownership interest in Penobscot Energy Recovery Company, or “PERC”, which resulted in the consolidation of our equity investment in PERC. As a result, the assets and liabilities of PERC became part of our consolidated assets and liabilities. Upon completion of the transaction, we recorded approximately $37.9 million of outstanding Finance Authority of Maine Electric, or “FAME” Rate Stabilization Revenue Refunding Bonds Series 1998, or “FAME bonds” which were issued on PERC’s behalf by FAME in June 1998. The face amount of the bonds that were initially issued was approximately $44.9 million and was used to repay the Floating Rate Demand Resource Revenue Bonds issued by the Town of Orrington, Maine on behalf of PERC. The FAME bonds are fixed rate bonds with yields ranging from 3.75% to 5.2%. The weighted average yield on the FAME bonds is approximately 5.1%. The FAME bonds are subject to mandatory redemption in annual installments of varying amounts through July 1, 2018. Beginning July 1, 2008 the FAME bonds are subject to redemption at the option of PERC at a redemption price equal to 102% through June 30, 2009, 101% for the period July 1, 2009 to June 30, 2010 and 100% thereafter, of the principal amount outstanding, plus accrued interest. The loan agreement with FAME contains certain restrictive covenants relating to the FAME bonds, which restrict PERC’s ability to incur additional indebtedness, and restricts the ability of the general partners to sell, assign or transfer their general partner interests. The bonds are collateralized by liens on substantially all of PERC’s assets. As of December 31, 2003, $26.3 million in principal remains outstanding.

In November 2001, NRG McClain LLC entered into a $181.0 million term loan and $8.0 million working capital facility with Westdeutsche Landesbank Girozentrale, New York branch, as agent to repay an outstanding term loan used to finance the acquisition of the McClain generating facility (non-recourse to us). The final maturity date of the facility is November 30, 2006. As of December 31, 2002 and 2003, the aggregate amount outstanding under this facility was $157.3 million and $156.5 million, respectively. During the period ended December 31, 2002 and 2003, the weighted average interest rate of such outstanding borrowings was 4.51% and 5.89%, respectively. On September 17, 2002, NRG McClain LLC received notice from the agent bank that the project loan was in default as a result of our downgrades and of defaults on material obligations under the Energy Management Services Agreement. On August 19, 2003, NRG McClain signed an asset purchase agreement with Oklahoma Gas and Electric Company for substantially all of the assets of McClain and contemporaneously filed for bankruptcy pursuant to the asset purchase agreement. Upon consummation of the asset sale we anticipate that all proceeds from the sale will be used to repay outstanding project debt under the secured term loan and working capital facility. On December 18, 2003, FERC issued an order setting the application for hearing to determine remedies FERC could impose as a condition of any approval for the transaction. This sale will not be completed until FERC approval is received. NRG McClain is recorded as a discontinued operation in the accompanying balance sheets.

The Camas Power Boiler LP notes are secured principally by its long-term assets. In accordance with the terms of the note agreements, Camas Power Boiler LP is required to maintain compliance with certain financial covenants primarily related to incurring debt, disposing of assets, and affiliate transactions. Camas Power Boiler was in compliance with these covenants at December 31, 2003. Distributions to us from Camas are permitted quarterly, contingent upon the project sufficiently funding debt service accounts, and meeting certain covenants and conditions. As of December 31, 2003, Camas met all requirements for distributions.

In July 2002, NRG Energy Center Minneapolis LLC, or “MEC”, an indirect wholly owned subsidiary, entered into an agreement allowing it to issue senior secured promissory notes in the aggregate principal amount of up to $150 million. In July 2002, under this agreement, MEC issued $75 million of bonds in a private placement. Two series of notes were issued in July 2002, the $55 million Series A-Notes dated July 3, 2002, which matures on August 1, 2017 and bears an interest rate of 7.25% per annum and the $20 million

Series B-Notes dated July 3, 2002, which matures on August 1, 2017 and bears an interest rate of 7.12% per annum. NRG Thermal LLC, a directly-held, wholly-owned subsidiary, which owns 100% of MEC, pledged its interests in all of its district heating and cooling investments throughout the United States as collateral. NRG Thermal and MEC are required to maintain compliance with certain financial covenants primarily related to incurring debt, disposing of assets, and affiliate transactions. In August 1993, MEC issued $84 million of 7.31% senior secured notes, due June 15, 2013. The three MEC notes contain a covenant providing the lender the option to choose prepayment of the notes if, among other things, Xcel Energy no long directly or indirectly owns a controlling interest in NRG Thermal. Xcel Energy no longer owns a controlling interest in NRG Thermal as a result of our emergence from bankruptcy. In anticipation of the change in control, NRG Thermal has entered into a forbearance agreement with the lender to allow time to negotiate a modified loan covenant package that would enable the lender to choose not to exercise its change in control option. Until a new loan covenant package has been developed, terms of the forbearance agreement prevent MEC or its subsidiaries from making distributions to us. The forbearance agreement expires June 1, 2004. As a result of the forbearance agreement, NRG Thermal and MEC were in compliance with their credit covenants at December 31, 2003.

STS Hydropower, LTD, or “STS Hydropower” which is indirectly 50% owned by NEO Corporation, or “NEO”, our wholly-owned subsidiary, entered into a Note Purchase Agreement in March 1995 with Allstate Life Insurance Co., or “Allstate”. Allstate purchased from STS Hydropower $22.1 million of 9.155% senior secured debt due December 30, 2016. The agreement was amended in 1996 to add $0.7 million of 8.24% senior secured debt due March 2011. The debt is secured by substantially all assets of and interest in STS Hydropower. Because of poor hydroelectric output due to drought conditions, no principal or interest payments have been made on this loan facility since October 2001. In May 2003, the facility was restructured and currently has a maturity of March 2023 and an interest rate of 9.133%. As of December 31, 2003, all required covenants under the restructured facility had been met and $25.2 million of principal was outstanding.

In September 1999, Northbrook New York LLC, or “NNY”, which is indirectly owned by NEO, entered into a $17.5 million term loan agreement with Heller Financial. In December 2001, the credit agreement with Heller Financial was amended to include $2.6 million of financing for Northbrook Carolina Hydro, LLC, or “NCH”, which is indirectly 50% owned by NEO, and to cross-collateralize the NNY and NCH notes. Heller Financial was subsequently purchased by GE Capital Services, which assumed the notes. The loan facilities are secured by substantially all hydroelectric assets of and membership interests in NCH and NNY. The NNY facility bears an interest rate of LIBOR plus 3% and matures in December 2018. The NCH facility bears interest at an interest rate of LIBOR plus 4% and matures in December 2016. As of December 31, 2003, the outstanding principal balance on the NNY facility and the NCH facility was $17.2 million and $2.5 million, respectively. On December 2001, NCH purchased a $0.3 million subordinated note from NEO. This subordinated note accrues interest at 11% per annum, and no payment is due until maturity on December 31, 2018.

In September 2000, Flinders Power Finance Pty Ltd, or “Flinders Power”, an Australian wholly owned subsidiary, entered into a twelve year AUD $150 million cash advance facility (US $81.4 million at September 2000). As of December 31, 2002 and 2003, there remains AUD$143.4 million (US$80.5 million) and AUD$135.0 million (US$101.6 million) outstanding under this facility, respectively. The interest has fixed and variable components. At December 31, 2002 and 2003, the interest rate was 6.49% and 7.53%, respectively and is paid semi-annually. Principal payments commence in 2006 and the facility will be fully paid in 2012.

In March 2002, Flinders Power entered into a 10 year AUD$165 million (US$85.4 million at March 2002) floating rate loan facility for the purpose of refurbishing the Flinders Playford generating station. As of December 31, 2002 and 2003, the Company had drawn AUD$33.3 million (US$18.7 million) and

AUD$114.3 million (US$86.0 million), respectively, of this facility. The interest rate has fixed and variable components. The interest rate at December 31, 2002 and 2003 was 6.14% and 7.03%, and is paid semi-annually. Principal payments for the refurbishment facility commence in 2005. Upon our downgrades in 2002, there existed a potential default under these facility agreements related to the funding of reserve accounts. On May 13, 2003, Flinders Power and its lenders entered into a Second Supplemental Deed, which resolved these potential defaults. As part of the terms of that Second Supplemental Deed, part of the refurbishment facility was voluntarily cancelled by Flinders Power so as to reduce the total available commitment from AUD$165 million to AUD$137 million (US$103.1 million).

In connection with our acquisition of a controlling interest in the COBEE facilities, we assumed non-recourse long-term debt that is due in 18 semi-annual installments of varying amounts beginning January 31, 1999 and ending July 31, 2007. The loan agreement provides an A Loan of up to $30 million and a B Loan of up to $45 million. The balance of the A and B loans was $31.8 million as of December 31, 2003. Interest is payable semi-annually in arrears at a rate equal to 6-month LIBOR plus a margin of 4.5% on the A Loan and 6-month LIBOR plus a margin of 4.0% on the B Loan. The A Loan and the B Loan are collateralized by a mortgage on substantially all of COBEE’s assets.

In connection with our purchase of PowerGen’s interest in Saale Energie GmbH, we have recognized a non-recourse capital lease on our balance sheet in the amount of $333.9 million and $342.5 million, as of December 31, 2002 and 2003, respectively. The capital lease obligation is recorded at the net present value of the minimum lease obligation payable over the lease’s remaining period of 19 years. In addition, a direct financing lease was recorded in notes receivable in the amount of approximately $366.4 million, $435.0 million and $451.4 million, as of December 31, 2002, December 6, 2003 and December 31, 2003, respectively.

Hsin Yu, which is approximately 63% indirectly owned by us, entered into a NT$2,700.0 million syndicated loan arrangement to finance construction of what was to be the first phase of a multi-phase cogeneration facility. Chiao Tung Bank led the original financing. Principal covenants of the syndicated facility include maintaining a debt to equity ratio below 250% until 2006, and a ratio below 200% thereafter, and maintaining a debt service coverage ratio above 1.1, starting in 2004. The fair value adjustment reflects the uncertainty of repayment of such obligations from project cash flows.

Annual maturities of long-term debt and capital leases for the years ending after December 31, 2003 are as follows:

Future minimum lease payments for capital leases included above at December 31, 2003 are as follows:

Assets related to our capital leases were revalued as of December 6, 2003, to $171.0 million and remained at $171.0 million with no accumulated amortization at December 31, 2003, as the amounts have been recorded at recoverable values. Total net book value related to these assets at December 31, 2002 was $258.2 million, net of $2.3 million of accumulated amortization.

In connection with the consummation of our plan of reorganization, on December 5, 2003 all shares of our old common stock were canceled and 100,000,000 shares of new common stock of NRG Energy were distributed pursuant to such plan to the holders of certain classes of claims. A certain number of shares of common stock was issued for distribution to holders of disputed claims as such claims are resolved or settled. In the event our disputed claims reserve is inadequate, it is possible we would have to issue additional shares of our common stock to satisfy such pre-petition claims or contribute additional cash proceeds. See Note 24 — Disputed Claims Reserve. Our authorized capital stock consists of 500,000,000 shares of NRG Energy common stock and 10,000,000 shares of Serial Preferred Stock. Further, a total of 4,000,000 shares of our common stock, representing approximately 4% of our outstanding common stock, are available for issuance under our long-term incentive plan.

In addition to our issuance of new common stock, on December 23, 2003, we completed a note offering consisting of $1.25 billion of 8% Second Priority Senior Secured Notes due 2013, and we entered into a new credit facility consisting of a $950.0 term loan facility, a $250.0 million funded letter of credit facility and a $250 million revolving credit facility. We used the proceeds of these offerings to retire certain project level debt, pay certain unsecured creditors and relieve associated cash traps. In January of 2004, we completed a supplementary note offering whereby we issued an additional $475 million of 8% Second Priority Senior Secured Notes due 2013 at a premium and used the proceeds there from to repay a portion of the $950.0 million term loan. As of March 1, 2004, the outstanding principal balance on the notes was $1.725 billion and the principal amount outstanding under the term loan was $446.5 million and $147.5 million remains available under the funded letter of credit facility. As of March 1, 2004, we had not drawn down on our revolving credit facility. Finally, in connection with the consummation of our plan of reorganization, we issued to Xcel Energy a $10.0 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 our plan of reorganization.

As part of our 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 through our distribution of new common stock and $1.04 billion in cash among our unsecured creditors. In addition to the debt reduction associated with the restructuring, we used the proceeds of the recent note offering and borrowings under the New Credit Facility to retire approximately $1.7 billion of project-level debt.

For additional information on our short term and long term borrowing arrangements, see Note 17.

In June 2000, we sold 32.4 million shares of common stock at $15 per share. Net proceeds from the offering were $453.7 million. At that time we were authorized to issue capital stock consisting of 550,000,000 shares of common stock, and 250,000,000 shares of Class A common stock. At December 31, 2000, there were approximately 32,396,000 shares of common stock, and 147,605,000 shares of Class A common stock issued and outstanding.

In March 2001, we completed the sale of 18.4 million shares of common stock for an initial price of $27 per share. The offering was completed with all 18.4 million shares of common stock being sold including the over-allotment shares of 2.4 million. We received gross proceeds from the issuance of $496.6 million. Net proceeds from the issuance were $473.4 million after deducting underwriting discounts, commissions and estimated offering expenses. The net proceeds were used in part to reduce amounts outstanding under our short-term bridge credit agreement, which was used to finance, in part, our acquisition of the LS Power assets.

At December 31, 2001, there were approximately 50,939,875 shares of common stock, and 147,605,000 shares of Class A common stock issued and outstanding.

On June 3, 2002, Xcel Energy completed its exchange offer for the 26% of our common shares that had been previously publicly held. Xcel Energy issued to our shareholders 0.50 shares of Xcel Energy common stock in exchange for each outstanding share of our common stock.

In June 2000, we adopted an incentive compensation plan, or “the Stock Plan”, which was approved by shareholders in June 2001. We accounted for this plan under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. During 2002, the Stock Plan, and all grants under the plan, were adopted by the Xcel Energy Incentive Stock Plan. There were no grants to our employees under the Xcel Energy Incentive Stock Plan. During 2001, we recognized approximately $1.9 million of stock based compensation expense under the New Stock Plan. In 2002, we recognized income due to the net reduction of our compensation expense accrual by approximately $2.3 million for terminated stock options during the period. The amount was reported as a reduction of compensation expense for the year ended December 31, 2002.

Effective January 1, 2003, we adopted the fair value recognition provisions of SFAS Statement No. 123, “Accounting for Stock-Based Compensation” or “SFAS No. 123.” In accordance with SFAS Statement No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” or “SFAS No. 148”, we adopted SFAS No. 123 under the prospective transition method which requires the application of the recognition provisions to all employee awards granted, modified, or settled after the beginning of the fiscal year in which the recognition provisions are first applied. As a result, we recognized compensation expense for any grants issued on or after January 1, 2003. There were no grants issued during the period from January 1, 2003 through December 4, 2003.

During 2003, we recognized approximately $540,000 of stock based compensation expense under the Long-Term Incentive Plan, approximately $424,000 related to stock options and approximately $116,000

related to restricted stock. In December 2003, we adopted a new long-term incentive plan, or “the Long-Term Incentive Plan”, which is described below.

The Long-Term Incentive Plan became effective upon our emergence from bankruptcy. The long-term incentive plan provides for grants of stock options, stock appreciation rights, restricted stock, performance awards, deferred stock units and dividend equivalent rights. Our directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by us, are eligible to receive grants under the long-term incentive plan. The purpose of the long-term inventive plan is to promote our long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to our success and to enable us to attract, retain and reward the best available persons for positions of responsibility.

A total of 4,000,000 shares of our common stock, representing approximately 4% of our outstanding common stock, are available for issuance under the long-term incentive plan, subject to adjustment in the event of a reorganization, recapitalization, stock split, reverse stock split, stock dividend, combination of shares, merger or similar change in our structure or our outstanding shares of common stock.

The compensation committee of our board of directors will administer the long-term incentive plan. If for any reason a compensation committee has not been appointed by our board to administer the long-term incentive plan, our board of directors will have the authority to administer the plan and to take all actions under the plan.

The following is a summary of the material terms of the long-term incentive plan, but does not include all of the provisions of the plan.

Eligibility. Our directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by, us are eligible to receive grants under the long-term incentive plan. In each case, the compensation committee will select the actual grantees.

Stock Options. Under the long-term incentive plan, the compensation committee may award grants of incentive stock options conforming to the requirements of Section 422 of the Internal Revenue Code or non-qualified stock options. The compensation committee may not award to any one person in any calendar year options to purchase more than 1,000,000 shares of common stock. In addition, it may not award incentive stock options first exercisable in any calendar year whose underlying shares have a fair market value greater than $100,000, determined at the time of grant.

The compensation committee will determine the exercise price of any options granted under the long-term incentive plan. However, the exercise price of any option may not be less than 100% of the fair market value of a share of our common stock on the date of grant, and the exercise price of an incentive stock option granted to a person who owns stock constituting more than 10% of the voting power of all classes of our stock may not be less than 110% of the fair market value of a share of our common stock on the date of grant.

Unless the compensation committee determines otherwise, the exercise price of any option may be paid in any of the following ways:


	•	in cash;

	•	by delivery of shares of common stock with a fair market value equal to the exercise price;

	•	by means of any cashless exercise procedure approved by the compensation committee; or

	•	by any combination of the foregoing.

The compensation committee will determine the term of each option in its discretion. However, no term may exceed 10 years from the date of grant or, in the case of an incentive stock option granted to a person who owns stock constituting more than 10% of the voting power of all classes of our stock, five years from the date of grant. In addition, all options under the long-term incentive plan, whether or not then exercisable, generally will cease vesting when a grantee ceases to be a director, officer or employee of, or to otherwise perform services for, us. Vested options will generally expire 90 days after the date of cessation of service.

There will be exceptions depending upon the circumstances of cessation. In the case of a grantee’s death, all options will become fully vested and will remain exercisable for a period of one year after the date of death. In the case of a grantee’s termination due to disability, vested options will remain exercisable for a period of one year after the date of termination due to disability while his or her unvested options will be forfeited. In the event of retirement, a grantee’s vested options will remain exercisable for a period of two years after the date of retirement while his or her unvested options will be forfeited. Upon termination for cause, all options will terminate immediately. Upon a change in control of NRG Energy, all of the options will become fully vested and will remain exercisable until the expiration date of the options. In addition, the compensation committee will have the authority to grant options that will become fully vested and exercisable automatically upon a change in control, whether or not the grantee is subsequently terminated.

Upon a reorganization, merger, consolidation or sale or other disposition of all or substantially all of our assets, the compensation committee may cancel any or all outstanding options under the long-term incentive plan in exchange for payment of an amount equal to the portion of the consideration that would have been payable to the grantees in the transaction if their options had been fully exercised immediately prior to the transaction, less the exercise price that would have been payable, or if the exercise price is greater than the consideration that would have been payable in the transaction, then for no consideration or payment.

Stock Appreciation Rights. Under the long-term incentive plan, the compensation committee may grant stock appreciation rights, or SARs, alone or in tandem with options, subject to terms and conditions as the compensation committee may specify. SARs granted in tandem with options will become exercisable only when, to the extent and on the conditions that the related options are exercisable, and they will expire at the same time the related options expire. The exercise of an option will result in the immediate forfeiture of any related SAR to the extent the option is exercised, and the exercise of a SAR results in the immediate forfeiture of any related option to the extent the SAR is exercised.

Upon exercise of a SAR, the grantee will receive an amount in cash, shares of our common stock or our other securities equal to the difference between the fair market value of a share of common stock on the date of exercise and the exercise price of the SAR or, in the case of a SAR granted in tandem with options, of the option to which the SAR relates, multiplied by the number of shares as to which the SAR is exercised. Unless otherwise provided in the grantee’s grant agreement, each SAR will be subject to the same termination and forfeiture provisions as the stock options described above.

Restricted Stock. Under the long-term incentive plan, the compensation committee may award restricted stock in the amounts that it determines in its discretion. Each grant of restricted stock will be evidenced by a grant agreement, which will specify the applicable restrictions on such shares and the duration of the restrictions (which will generally be at least six months). A grantee will be required to pay us at least the aggregate par value of any shares of restricted stock within ten days of the grant, unless the shares are treasury shares. Unless otherwise provided in the grantee’s grant agreement, each unit or share of restricted stock will be subject to the same termination and forfeiture provisions as the stock options described above.

Performance Awards. Under the long-term incentive plan, the compensation committee may grant performance awards contingent upon achievement by the grantee, us or any of our divisions of specified performance criteria, such as return on equity, over a specified performance cycle, as determined by the compensation committee. Performance awards may include specific dollar-value target awards; performance

units, the value of which will be determined by the compensation committee at the time of issuance; and/or performance shares, the value of which will be equal to the fair market value of common stock. The value of a performance award may be fixed or may fluctuate based on specified performance criteria. A performance award may be paid out in cash, shares of our common stock or our other securities.

A grantee must be a director, officer or employee of, or otherwise perform services for, us at the end of the performance cycle in order to be entitled to payment of a performance award issued in respect of such cycle, provided that unless otherwise provided in the grantee’s grant agreement, each performance award will be subject to the same termination and forfeiture provisions as the stock options described above.

Deferred Stock Units. Under the long-term incentive plan, the compensation committee may grant deferred stock units from time to time in its discretion. A deferred stock unit will entitle the grantee to receive the fair market value of one share of common stock at the end of the deferral period, which will be no less than one year. The payment of the value of deferred stock units may be made by us in shares of our common stock, cash or both. If a grantee ceases to be a director, officer or employee of, or otherwise perform services for, us upon his or her death prior to the end of the deferral period, the grantee will receive payment of his or her deferred stock units which would have matured or been earned at the end of the deferral period as if the deferral period has ended as of the date of his or her death. In the event of a termination due to disability or retirement prior to the end of the deferral period, the grantee will receive payment of his or her deferred stock units at the end of the deferral period. If a grantee ceases to be a director, officer or employee of, or otherwise perform services for, us for any other reason, his or her unvested deferred stock units will immediately be forfeited. Upon a change in control in NRG Energy, a grantee will receive payment of his or her deferred stock units as if the deferral period has ended as of the date of the change in control.

Dividend Equivalent Rights. Under the long-term incentive plan, the compensation committee may grant a dividend equivalent right entitling the grantee to receive amounts equal to all or any portion of the dividends that would be paid on shares of our common stock covered by an award if those shares had been delivered to the grantee pursuant to the award, subject to terms and conditions as the committee may specify.

Vesting, Withholding Taxes and Transferability of All Awards. The terms and conditions of each award made under the long-term incentive plan, including vesting requirements, will be set forth consistent with the plan in a written agreement with the grantee. Except in limited circumstances and unless the compensation committee determines otherwise, no award under the long-term incentive plan may vest and become exercisable within six months of the date of grant.

Unless the compensation committee determines otherwise, a participant may elect to deliver shares of common stock, or to have us withhold shares of common stock otherwise issuable upon exercise of an option or a SAR or deliverable upon grant or vesting of restricted stock or the receipt of common stock, in order to satisfy our tax withholding obligations in connection with any exercise, grant or vesting.

Unless the compensation committee determines otherwise, no award made under the long-term incentive plan will be transferable other than by will or the laws of descent and distribution, and each option, SAR or performance award may be exercised only by the grantee or his or her executor, administrator, guardian or legal representative, or by a family member of the grantee if he or she has acquired the option, SAR or performance award by gift or qualified domestic relations order.

Amendment and Termination of the Long-Term Incentive Plan. The board of directors or the compensation committee may amend or terminate the long-term incentive plan in its discretion, except that no amendment will become effective without prior approval of our stockholders if approval is required by applicable law or regulations, including any NASDAQ or stock exchange listing requirements, if the amendment would remove a provision of the long-term incentive plan which, without giving effect to the amendment, is subject to shareholder approval or if the amendment would directly or indirectly increase the

share limit of 4,000,000 shares. If not otherwise terminated, the long-term incentive plan will terminate on the tenth anniversary of the effective date of our plan of reorganization, which was December 5, 2003.

In December 2003, we issued one stock option grant for a total of 632,751 shares of common stock under the Long-Term Incentive Plan. These options have a three-year graded vesting schedule and become exercisable through the year 2006 at a price of $24.03. Total compensation expense under the stock option grant is approximately $8.3 million. Compensation expense for the year ended December 31, 2003 was approximately $0.4 million. Compensation expense for the years ended December 31, 2004, December 31, 2005 and December 31, 2006 will be approximately $4.9 million, $2.2 million and $0.8 million, respectively. At December 31, 2003, no employee stock options were exercisable. Stock option transactions were:

The following table summarizes information about stock options outstanding at December 31, 2003:

The fair value of the stock option grant was estimated on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions used for grants in 2003.

In December 2003, we issued 173,394 restricted stock units under the Long-Term Incentive Plan. These units will fully vest in December 2006. Total compensation expense under the restricted stock grant is approximately $4.2 million. Compensation expense for the year ended December 31, 2003 was approximately $0.1 million. Compensation expense for the years ended December 31, 2004, December 31, 2005 and

December 31, 2006 will be approximately $1.4 million, $1.4 million and $1.3 million, respectively. The weighted-average fair value of our restricted stock units for 2003 is $24.03.

Basic earnings per common share were computed by dividing net income by the weighted average number of common stock shares outstanding. Shares issued during the year are weighted for the portion of the year that they were outstanding. Shares of common stock granted to our officers and employees are included in the computation only after the shares become fully vested. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table:

The options to purchase 632,751 shares of common stock at a price of $24.03 per share were not included in the computation because the options’ exercise price was greater than the average market price of the common shares and therefore the effect would be anti-dilutive.

NRG Energy conducts its business within six segments: Independent Power Generation in North America, Independent Power Generation outside North America (Europe, Asia Pacific and Other Americas regions), Alternative Energy and Thermal projects. Our revenues from majority owned operations attributable to Europe and Asia Pacific primarily relate to operations in the United Kingdom and Australia, respectively. These segments are distinct components with separate operating results and management structures in place. The “Other” category includes operations that do not meet the threshold for separate disclosure and corporate charges (primarily interest expense) that have not been allocated to the operating segments. All non U.S.A. operations are included in the Europe, Asia Pacific and Other Americas segments.

For the year ended December 31, 2002 and the period January 1, 2003 through December 5, 2003, income taxes have been recorded on the basis that Xcel Energy will not be including us in its consolidated federal income tax return following Xcel Energy’s acquisition of our public shares on June 3, 2002. Since our U.S. subsidiaries and we will not be included in the Xcel Energy consolidated federal income tax return for the period January 1, 2003 through December 5, 2003, we and each of our U.S. subsidiaries that is classified as a corporation for U.S. income tax purposes must file separate federal income tax returns.

Following our emergence from Bankruptcy on December 5, 2003, we and our U.S. subsidiaries will file a consolidated federal income tax return. We have reviewed the requirements for reconsolidation and believe we satisfy them.

As of December 31, 2003, we provided a valuation allowance of approximately $559.7 million to account for potential limitations on utilization of U.S. and foreign net operating loss carryforwards. If unused, the U.S. net operating loss carryforward of $1.0 billion generated in 2002 and 2003 will expire by 2023. Net

operating loss carryforwards for foreign tax purposes have no expiration date. We also have a valuation allowance for other U.S. and foreign deferred income tax assets of approximately $704.7 million as of December 31, 2003.

As of December 5, 2003, we provided a valuation allowance of approximately $545.0 million to account for potential limitations on utilization of U.S. and foreign net operating loss carryforwards compared to a valuation allowance of $494.5 million for the same period in 2002. We also provided a valuation allowance for other U.S. and foreign deferred income tax assets of approximately $720.0 million for the period ended December 5, 2003 compared to $578.7 million for the same period in 2002.

The effective income tax rates of continuing operations for the years ended December 31, 2001, 2002 and 2003 differ from the statutory federal income tax rate of 35% as follows:

Income tax (benefit)/expense for the period December 6, 2003 through December 31, 2003 was a tax benefit of ($0.7) million which includes ($1.5) million benefit and $0.8 million expense of U.S. and foreign taxes, respectively. The U.S. tax benefit recorded for this period is the result of a state tax refund received from Xcel Energy pursuant to the tax matters agreement. The foreign tax expense for the period is due to earnings in the foreign jurisdictions.

The income tax (benefit)/expense for the period January 1, 2003 through December 5, 2003 was a tax expense of $16.6 million compared to a tax benefit of ($164.4) million for the year ended December 31, 2002. During 2003, an additional valuation allowance of $33 million was recorded against the deferred tax assets of NRG West Coast as a result of its conversion from a corporation to a single member limited liability company (a disregarded entity for federal income tax purposes). Subsequent to the conversion, NRG West Coast will no longer be taxed as an entity separate from us.

As of December 31, 2003, our management intends to indefinitely reinvest the earnings from our foreign operations. Accordingly, U.S. income taxes and foreign withholding taxes were not provided on the earnings from our foreign subsidiaries. As of December 31, 2003, December 5, 2003, and December 31, 2002 no U.S. income tax benefit was provided on the cumulative amount of losses from our foreign subsidiaries of $432.5 million, $438.4 million, and $341.7 million, respectively.

While we were an indirect, wholly owned subsidiary of Xcel Energy, 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. Prior to December 5, 2003, we had entered into material transactions and agreements with Xcel Energy. Certain material agreements and transactions existing during 2003 between NRG Energy and Xcel Energy are described below.

We have two agreements with Xcel Energy for the purchase of thermal energy. Under the terms of the agreements, Xcel Energy charges us for certain costs (fuel, labor, plant maintenance, and auxiliary power) incurred by Xcel Energy to produce the thermal energy. We paid Xcel Energy $7.1 million, $8.2 million and $9.6 million in 2001, 2002 and the period January 1, 2003 to December 5, 2003, respectively, under these agreements. One of these agreements expired on December 31, 2002 and the other expires on December 31, 2006.

We have a renewable 10-year agreement with Xcel Energy, expiring on December 31, 2006, whereby Xcel Energy agreed to purchase refuse-derived fuel for use in certain of its boilers and we agree to pay Xcel Energy a burn incentive. Under this agreement, we received $1.6 million, $1.2 million and $1.4 million from Xcel Energy, and paid $2.8 million, $3.3 million and $3.9 million to Xcel Energy in 2001, 2002 and the period January 1, 2003 to December 5, 2003, respectively.

We had an administrative services agreement in place with Xcel Energy. Under this agreement we reimbursed Xcel Energy for certain overhead and administrative costs, including benefits administration, engineering support, accounting, and other shared services as requested by us. In addition, our employees participated in certain employee benefit plans of Xcel Energy as discussed in Note 23. We reimbursed Xcel Energy in the amounts of $12.2 million, $21.2 million and $7.3 million during 2001, 2002 and the period January 1, 2003 to December 5, 2003, respectively, under this agreement. This agreement was terminated December 5, 2003.

We had an agreement with e prime, a wholly owned subsidiary of Xcel Energy, under which e prime provided natural gas marketing and trading from time to time at our request. We paid $19.2 million to e prime in 2002 related to these services. This agreement was terminated by e prime on December 12, 2002 and a termination charge of $0.3 million was paid in the period January 1, 2003 to December 5, 2003.

Included in accounts payable affiliate is approximately $42.9 of amounts owed to Xcel Energy at December 31, 2002. While we were an indirect, wholly owned subsidiary of Xcel Energy, we became an independent public company upon our emergence from bankruptcy on December 5, 2003. As part of our restructuring, amounts owed to Xcel Energy were forgiven and replaced by a $10.0 million promissory note, which was outstanding as of December 6, 2003 and December 31, 2003.

Included in the company’s balance sheet is a $640.0 million receivable from Xcel Energy. Under the terms of the settlement agreement, payments were to be made in three installments. As of December 6, 2003 and December 31, 2003, the balance was $640.0 million.

Substantially all of our employees participate in defined benefit pension plans. We have initiated a new NRG Energy noncontributory, defined benefit pension plan effective January 1, 2004, with credit for service from December 5, 2003. On December 5, 2003, we recorded a liability of approximately $48.0 million to record our accumulated benefit obligations at fair value. As of December 31, 2003, there were no plan assets related to the plans assumed from Xcel Energy. We have chosen the plan Trustee and are in the preliminary stages of defining the investment strategies for this plan.

In addition, we provide postretirement health and welfare benefits (health care and death benefits) for certain groups of our employees. Generally, these are groups that were acquired in recent years and for whom prior benefits are being continued (at least for a certain period of time or as required by union contracts). Cost sharing provisions vary by acquisition group and terms of any applicable collective bargaining agreements.

We expect to contribute approximately $2.0 million to our NRG pension plan and our postretirement health and welfare plan in 2004.

Employees of NRG Flinders, a wholly owned subsidiary of NRG Energy, are members of the multiemployer Electricity Industry Superannuation Schemes, or “EISS.” Members of the EISS make contributions from their salary and the EISS Actuary makes an assessment of our liability. As a result of adopting Fresh Start we recorded a liability of approximately $13.8 million at December 5, 2003, to record our accumulated benefit obligation plan assets on the balance sheet at fair value. The balance sheet includes a liability related to the Flinders retirement plan of $12.3 million, $13.8 million and $13.7 million at December 31, 2002, December 5, 2003 and December 31, 2003, respectively. NRG Flinders contributed $5.8 million, $4.5 million and $0 for the year ended December 31, 2002, the period January 1 through December 5, 2003 and the period December 6 through December 31, 2003, respectively.

The Superannuation Board is responsible for the investment of Scheme assets. The assets may be invested in government securities, shares, property and a variety of other securities and the Board may appoint professional investment managers to invest all or part of the assets on its behalf.

The net annual periodic pension cost related to all of our plans, include the following components:

A comparison of the pension benefit obligation and pension assets at December 6, 2003 and December 31, 2003 for all of our plans on a combined basis is as follows:

A comparison of the pension benefit obligation and pension assets at December 31, 2002 for all of our plans on a combined basis is as follows:


*	We did not determine an expected return on plan assets for the NRG pension plan as there are no plan assets at December 31, 2003.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect (in thousands):

Our employees have also been eligible to participate in defined contribution 401(K) plans. Our contributions to these plans were approximately $3.2 million, $4.6 million and $3.8 million in 2001, 2002 and 2003, respectively.

Prior to December 5, 2003, all eligible employees participated in Xcel Energy’s multiemployer noncontributory, defined benefit pension plan, which was formerly sponsored by NSP. We sponsored two defined benefit plans that were merged into Xcel Energy’s plan as of June 30, 2002. Benefits are generally based on a combination of an employee’s years of service and earnings. Some formulas also take into account Social Security benefits. Plan assets principally consisted of the common stock of public companies, corporate bonds and U.S. government securities.

Prior to December 5, 2003, certain former NRG Energy retirees were covered under the legacy Xcel Energy plan, which was terminated for non-bargaining employees retiring after 1998 and for bargaining employees retiring after 1999.

As a result of our emergence from bankruptcy on December 5, 2003, we are no longer owned by or affiliated with Xcel Energy and our employees are no longer participants of the Xcel Energy plans.

We did not make contributions to the Xcel Energy pension plan and postretirement plan in 2001, 2002 or 2003. The balance sheet includes a liability related to the Xcel Energy Pension Plan of $1.7 million for 2002. The balance sheet also includes a liability related to the Xcel Energy Postretirement Medical Plan of $2.2 million for 2002. As of December 31, 2003, there are no liabilities recorded related to the Xcel Energy plans. The liabilities associated with these plans were settled as part of the NRG plan of reorganization. The net annual periodic cost (credit) related to our portion of the Xcel Energy pension plan and postretirement plans totaled $(8.9) million, $(8.9) million and $0.2 million for 2001, 2002 and 2003, respectively.

Prior to December 5, 2003, certain employees also participated in Xcel Energy’s noncontributory defined benefit supplemental retirement income plan. This plan is for the benefit of certain qualifying executive personnel. Benefits for this unfunded plan are paid out of operating cash flows. The balance sheet includes a liability related to this plan of $3.2 million and $0.4 million as of December 31, 2002 and 2003, respectively.

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug Improvement and Modernization Act of 2003, or “the Act.” The Act expanded Medicare to include, for the first time, coverage for prescription drugs. This coverage is generally effective January 1, 2006. The execution of this new legislation had no significant impact on our statement of financial position or results of operation as of

December 31, 2003 and for the period December 6, 2003 through December 31, 2003. Any future impact will be recognized as incurred.

We lease certain of our facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2023. Rental expense under these operating leases was $10.0 million, and 13.4 million for the years ended December 31, 2001 and 2002, respectively and $12.2 million and $0.7 million for the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003, respectively. Future minimum lease commitments under these leases for the years ending after December 31, 2003 are as follows:

We anticipate funding our ongoing capital requirements through committed debt facilities, operating cash flows, and existing cash. Our capital expenditure program is subject to continuing review and modification. The timing and actual amount of expenditures may differ significantly based upon plant operating history, unexpected plant outages, and changes in the regulatory environment, and the availability of cash.

In May 2001, our wholly-owned subsidiary, NRG FinCo, entered into a $2.0 billion revolving credit facility. The facility was established to finance the acquisition, development and construction of power generating plants located in the United States and to finance the acquisition of turbines for such facilities. The facility provided for borrowings of base rate loans and Eurocurrency loans and was secured by mortgages and security agreements in respect of the assets of the projects financed under the facility, pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects, and by guaranties from each such subsidiary or affiliate. The NRG FinCo secured revolver was initially scheduled to mature on May 8, 2006; however, due to defaults hereunder by NRG FinCo and applicable guarantors, the lenders accelerated all outstanding obligations on November 6, 2002. As of our emergence, $1.1 billion was outstanding under the facility, and there was an aggregate of approximately $58 million of accrued but unpaid interest and commitment fees. Of this, $842.0 million was allowed in unsecured claims under NRG plan of reorganization, and was settled at the time of our emergence. The remaining balance will be satisfied when the NRG FinCo lenders exercise their perfected security interests in our Nelson, Audrain and Pike projects. These project companies hold assets with estimated fair market values of approximately $55.2 million, $172.0 million and $48.0 million, respectively. The amount of $55.2 million for Nelson consists of a partially completed project. Since the Nelson entity is currently in bankruptcy, we are recording the entity as a cost method investment with the fair value of the assets equaling the fair value of the obligation to the NRG FinCo lenders. The Audrain project cost of $172.0 million represents the fair value of the operating assets consisting of property

plant and equipment. An offsetting liability of $172.0 million was recorded as of Fresh Start to the NRG FinCo lenders. The Pike entity holds a turbine with an estimated fair value of approximately $48.0 million. Additionally, we also recorded an equal liability of $48.0 million to the NRG FinCo lenders. The obligations of Audrain and Pike totaling $220.0 million is reflected on the balance sheet as other bankruptcy settlement. We are in the process of marketing for sale each of the Audrain, Pike, and Nelson projects on behalf of the NRG FinCo lenders. The NRG FinCo lenders have authority under their perfected security interest to accept or reject all offers. As a result these entities are not reflected as a discontinued operations. We believe we have no additional risk of loss related to these entities.

In connection with our acquisition of the Audrain facilities, we have recognized a capital lease on its balance sheet within long-term debt in the amount of $239.9 million, as of December 31, 2003 and 2002. The capital lease obligation is recorded at the net present value of the minimum lease obligation payable. The lease terminates in May 2023. During the term of the lease only interest payments are due, no principal is due until the end of the lease. In addition, we have recorded in notes receivable, an amount of approximately $239.9 million, which represents its investment in the bonds that the county of Audrain issued to finance the project. During February 2004, we received a notice of a waiver of a $24.0 million interest payment due on the capital lease obligation. In connection with the transfer of the security in the Audrain projects to NRG FinCo Lenders, the Audrain entity will be liquidated resulting in the termination of the lease obligation and the note receivable.

The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and our facilities are not exempted from coverage, we could be required to make extensive modifications to further reduce potential environmental impacts.

Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at the facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by the party in connection with any releases or threatened releases. These laws, 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.

We strive to exceed the standards of compliance with applicable environmental and safety regulations. Nonetheless, we expect that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position. It is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of possible changes to environmental and safety regulations, regulatory interpretations or enforcement policies. In general, the effect of future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions on our operations.

As part of acquiring existing generating assets, we have inherited certain environmental liabilities associated with regulatory compliance and site contamination. Often potential compliance implementation plans are changed, delayed or abandoned due to one or more of the following conditions: (a) extended

negotiations with regulatory agencies, (b) a delay in promulgating rules critical to dictating the design of expensive control systems, (c) changes in governmental/regulatory personnel, (d) changes in governmental priorities or (e) selection of a less expensive compliance option than originally envisioned.

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, we conducted Phase I and Phase II Environmental Site Assessments at each of these sites for purposes of identifying such existing contamination and provided the results to the sellers. 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. While spills and releases of various substances have occurred at many sites since establishing the historical baseline, all but one has been remediated in accordance with existing laws. An unquantified amount of soil contaminated by lubricating oil that leaked from underground piping at the El Segundo Generating Station has been allowed by the Regional Water Quality Control Board to remain under the foundation of the Unit I powerhouse until the building is demolished.

Our affiliates have incurred capital expenditures at the Encina Generating Station to install Selective Catalytic Reduction, or “SCR” emission control technology on all five generating units. Units 4 & 5 were retrofitted with SCRs during 2002; while Units 1, 2, and 3 were retrofitted with SCRs in 2003. The cost to retrofit all five units totaled approximately $42 million.

Coal ash is produced as a by-product of coal combustion at the Dunkirk, Huntley, and Somerset Generating Stations. We attempt to direct its coal ash to beneficial uses. Even so, significant amounts of ash are landfilled at on and off-site locations. At Dunkirk and Huntley, ash is disposed at landfills owned and operated by us. No material liabilities outside the costs associated with closure, post-closure care and monitoring are expected at these facilities. We maintain financial assurance to cover costs associated with closure, post-closure care and monitoring activities. In the past, we have provided financial assurance via financial test and corporate guarantee. As a result of our debt restructuring process, we were required to re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, such costs currently estimated at approximately $5.9 million. We provided such financial assurance via a trust fund established in this amount on April 30, 2003.

We must also maintain financial assurance for closing interim status RCRA facilities at the Devon, Middletown, Montville and Norwalk Harbor Generating Stations. Previously, we have provided financial assurance via financial test. As a result of our debt restructuring process, we were required to re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, such costs currently estimated at approximately $1.5 million. We provided such financial assurance via a trust fund established in this amount on April 30, 2003.

Historical clean-up liabilities were inherited as a part of acquiring 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 have been identified and 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 cover and monitor ash management areas pursuant to the Connecticut require-

ments. Remedial liabilities at the Arthur Kill Generating Station have been established in discussions between us and the New York State DEC and are expected to cost on the order of $1.0 million. Remedial investigations are on-going at the Astoria Generating Station. At this time, our long-term cleanup liability at this site is not expected to exceed $1.5 million.

We estimate that we will incur total environmental capital expenditures of $79.7 million during 2004 through 2008 for the facilities in New York, Connecticut and Massachusetts. These expenditures will be primarily related to changes required to accommodate Power River Basin coal at selected plants, landfill construction, installation of NO_x controls, installation of the best technology available for minimizing environmental impacts associated with impingement and entrainment of fish and larvae, particulate matter control improvements, spill prevention controls, and undertaking remedial actions. NRG Energy estimates that it will incur in 2004 at all of its plants in the Northeast Region approximately $23 million in capital expenditures for plant modifications and upgrades required to comply with environmental regulations.

As of December 31, 2003, we had recorded an accrual of approximately $2.1 million to cover penalties associated with historical opacity exceedances.

We estimate that we will incur capital expenditures of approximately $14.7 million during the years 2004 through 2008 related to resolving environmental concerns at the Indian River Generating Station. These concerns include the expected closure of the existing ash landfill, the construction of a new ash landfill nearby, the addition of controls to reduce NO_x emissions, fuel yard modifications, and electrostatic precipitator refurbishments to reduce opacity.

Liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated on site at the Big Cajun II Generating Station are addressed through the use of a trust fund maintained by us (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 current value of the trust fund is approximately $4.8 million and we are making annual payments to the fund in the amount of about $116,000. See Note 14.

We estimate approximately $18 million of capital expenditures will be incurred during the period 2004 through 2008 for the addition of NO_x controls on Units 1 and 2 of Big Cajun II. In addition, NRG Energy estimates that it would incur up to $5 million to reduce particulate matter emissions during start-up of Units 1 and 2 at Big Cajun II.

In November 2002, the NYISO notified us of claims related to New York City mitigation adjustments, general NYISO billing adjustments and other miscellaneous charges related to sales between November 2000 and October 2002. The New York City mitigation adjustments totaled $11.5 million. We did not contest that claim and it has been fully reserved. The general NYISO billing adjustment issue totaled $10.2 million and related to NYISO’s concern that NRG would not have sufficient revenue to cover for subsequent revisions to its energy market settlements. As of December 31, 2003, the NYISO held $4.5 million in escrow for such future settlement revisions.

On November 8, 2002 Conectiv provided us with a Notice of Termination of Transaction under the Master Power Purchase and Sale Agreement, or “Master PPA”, dated June 21, 2001. Under the Master PPA, which was assumed by us in our acquisition of various assets from Conectiv, we had been required to deliver 500 MW of electrical energy around the clock at a specified price through 2005. In connection with the Conectiv acquisition, we recorded as an out-of-market contract obligation for this contract. As a result of the cancellation, we will lose approximately $383.1 million in future contracted revenues. Also, in conjunction with the terms of the Master PPA, we received from Conectiv a termination payment in the amount of $955,000. At December 31, 2002, the remaining unamortized balance of the contract obligation was recognized as revenue. As a result, during the fourth quarter approximately $50.7 million was recognized as revenue.

This action was filed in state court on March 11, 2002 against us, Dynegy, Dynegy Power Marketing, Inc., Xcel Energy, West Coast Power and four of West Coast Power’s operating subsidiaries. Through our subsidiary, NRG West Coast LLC, we are a 50 percent beneficial owner with Dynegy of West Coast Power, which owns, operates, and markets the power of California plants. Dynegy and its affiliates and subsidiaries are responsible for gas procurement and marketing and trading activities on behalf of West Coast Power. It alleges that the defendants violated California Business & Professions Code § 17200 by selling ancillary services to the Cal ISO, and subsequently selling the same capacity into the spot market. The California Attorney General seeks injunctive relief as well as restitution, disgorgement and civil penalties.

Public Utility District of Snohomish County v. Dynegy Power Marketing, Inc et al., Case No. 02-CV-1993
RHW, United States District Court, Southern District of California (part of MDL 1405).

Pamela R Gordon, on Behalf of Herself and All Others Similarly Situated v Reliant Energy, Inc. et al., Case No. 758487, Superior Court of the State of California, County of San Diego (filed on November 27, 2000).

Ruth Hendricks, On Behalf of Herself and All Others Similarly Situated and On Behalf of the General Public v. Dynegy Power Marketing, Inc. et al., Case No. 758565, Superior Court of the State of California, County of San Diego (filed November 29, 2000).

The People of the State of California, by and through San Francisco City Attorney Louise H. Renne v. Dynegy Power Marketing, Inc. et al., Case No. 318189, Superior Court of California, San Francisco County (filed January 18, 2001).

Pier 23 Restaurant, A California Partnership, On Behalf of Itself and All Others Similarly Situated v PG&E Energy Trading et al., Case No. 318343, Superior Court of California, San Francisco County (filed January 24, 2001).

Sweetwater Authority, et al. v. Dynegy, Inc. et al., Case No. 760743, Superior Court of California, County of San Diego (filed January 16, 2001).

Cruz M Bustamante, individually, and Barbara Matthews, individually, and on behalf of the general public and as a representative taxpayer suit, v. Dynegy Inc. et al., inclusive. Case No. BC249705, Superior Court of California, Los Angeles County (filed May 2, 2001).

All of West Coast Power’s operating subsidiaries are defendants in at least one of these six consolidated cases, which were all filed in late 2000 and 2001 in various state courts throughout California. They allege unfair competition, market manipulation and price fixing. All the cases were removed to the appropriate United States District Courts, and were thereafter made the subject of a petition to the Multi-District Litigation Panel (Case No. MDL 1405). The cases were ultimately assigned to Judge Whaley. Judge Whaley entered an order in 2001 remanding the cases to state court, and thereafter the cases were coordinated pursuant to state court coordination proceedings before a single judge in San Diego Superior Court. Thereafter, Reliant Energy and Duke Energy filed cross-complaints naming various Canadian, Mexican and United States government entities. Some of these defendants once again removed the cases to federal court, where they were again assigned to Judge Whaley. The defendants filed motions to dismiss and to strike under the filed-rate and federal preemption theories, and the plaintiffs challenged the district court’s jurisdiction and sought to have the cases remanded to state court. In December 2002, Judge Whaley issued an opinion finding that federal jurisdiction was absent in the district court, and remanding the cases to state court. Duke Energy and Reliant Energy then filed a notice of appeal with the Ninth Circuit, and also sought a stay of the remand pending appeal. The stay request was denied by Judge Whaley. On February 20, 2003, however, the Ninth Circuit stayed the remand order and accepted jurisdiction to hear the appeal of Reliant Energy and Duke Energy on the remand order. We anticipate that filed-rate/federal preemption pleading challenges will be renewed once the remand appeal is decided.

Bustamante v. McGraw-Hill Companies, Inc., et al., No. BC 235598, California Superior Court, Los Angeles County.

Jerry Egger, et al. v. Dynegy, Inc., et al., Case No. 809822, Superior Court of California, San Diego County (filed May 1, 2003). This class action complaint alleges violations of California’s Antitrust Law, Business and Professional Code, and unlawful and unfair business practices. The named defendants include “West Coast Power, Cabrillo II, El Segundo Power, Long Beach Generation.” We are not named. This case now has been removed to the United States District Court, and the defendants have moved to have this case included as Multi-District Litigation along with the above referenced cases before Judge Walker. Plaintiffs have filed a motion to remand to state court, which was heard on February 19, 2004. At the hearing, the court decided to stay the case pending a decision from the Ninth Circuit Court of Appeals in the Pastorino appeal, referenced above.

Texas-Ohio Energy, Inc., on behalf of Itself and all others similarly situated v. Dynegy, Inc. Holding Co., West Coast Power, LLC, et al., Case No. CIV.S-03-2346 DFL GGH. This putative class action was filed on November 10, 2003, in the United States District Court for the Eastern District of California. The complaint alleges violations of the federal Sherman and Clayton Acts and California’s Cartwright Act and Business and Professions Code. In addition to naming West Coast Power and Dynegy the complaint names numerous industry participants, as well as “unnamed co-conspirators.” The complaint alleges that defendants conspired to manipulate the spot price and basis differential of natural gas with respect to the California market allegedly enabling defendants to reap exorbitant and illicit profits by gouging natural gas purchasers. Specifically, the complaint alleges that defendants and their co-conspirators employed a variety of false reporting techniques to manipulate the published natural gas price indices. The complaint seeks unspecified amounts of damages, including a trebling of plaintiff’s and the putative class’s actual damages. We are unable at this time to predict the outcome of this dispute or the ultimate liability, if any, of West Coast Power.

The Federal Energy Regulatory Commission has an ongoing “Investigation of Potential Manipulation of Electric and Natural Gas Prices,” which involves hundreds of parties (including our affiliate, West Coast Power) and substantial discovery. In June 2001, FERC initiated proceedings related to California’s demand

for $8.9 billion in refunds from power sellers who allegedly inflated wholesale prices during the energy crisis. Hearings have been conducted before an administrative law judge who issued an opinion in late 2002. The administrative law judge stated that after assessing a refund of $1.8 billion for “unjust and unreasonable” power prices between October 2, 2000 and June 20, 2001, power suppliers were owed $1.2 billion because the State was holding funds owed to suppliers.

On December 12, 2002, FERC Administrative Law Judge Birchman issued a Certification of Proposed Findings on California Refund Liability in Docket No. EL00-95-045 et al., which determined the method for calculating the mitigated energy market clearing price during each hour of the refund period. On March 26, 2003, FERC issued an Order on Proposed Findings on Refund Liability in Docket No. EL00-95-045, or “Refund Order”, adopting, in part, and modifying, in part, the Proposed Findings issued by Judge Birchman on December 12, 2002. In the Refund Order, FERC adopted the refund methodology in the Staff Final Report on Price Manipulation in Western Markets issued contemporaneously with the Refund Order in Docket No. PA02-2-000. This refund calculation methodology makes certain changes to Judge Birchman’s methodology, because of FERC Staff’s findings of manipulation in gas index prices. This could materially increase the estimated refund liability. The Refund Order directed generators wanting to recover any fuel costs above the mitigated market clearing price during the refund period to submit cost information justifying such recovery within 40 days of the issuance of the Refund Order, which West Coast Power did. Dynegy and the West Coast Power entities are currently engaged in settlement negotiations with FERC Staff, the California Attorney General, the California Public Utility Commission, the California Electricity Oversight Board, PG&E, and Southern California Edison.

On December 18, 2002, a Dynegy subsidiary, Dynegy Marketing & Trade, or “DMT”, and West Coast Power, collectively “the Respondents”, entered into a consent Offer of Settlement and Order, “the Consent Order”, with the Commodity Futures and Trading Commission, or “CFTC.” The action is captioned In re Dynegy Marketing & Trade and West Coast Power LLC, CFTC Docket No. 03-03. The CFTC asserted various violations of the Commodity Exchange Act, as well as CFTC regulations.

The U.S. Attorney indicted two fired Dynegy traders in connection with the index reporting scheme, and is reportedly investigating other Dynegy activity and employees.

Although any evaluation of the likelihood of an unfavorable outcome or an estimate of the amount or range of potential loss in the above-referenced private actions and various investigations cannot be made at this time, we note that the Gordon complaint alleges that the defendants, collectively, overcharged California ratepayers during 2000 by $4.0 billion. We know of no evidence implicating us in the various private plaintiffs’ allegations of collusion. We cannot predict the outcome of these cases and investigations at this time.

On December 19, 2003 the Electricity Consumers Resource Council, or “ECRC”, appealed to the United States Court of Appeals for the District of Columbia Circuit a recent decision by FERC approving the

implementation of a demand curve for the New York installed capacity, or “ICAP”, market. ECRC claims that the implementation of the ICAP demand curve violates section 205 of the Federal Power Act because it constitutes unreasonable ratemaking. We are a party to this appeal and will contest ECRC’s assertions, but at this time cannot assess what the eventual outcome will be.

This matter involves a dispute between CL&P and PMI concerning which of party is responsible, under the terms of the October 29, 1999 SOS contract, for costs related to congestion and losses associated with the implementation of standard market design, or “SMD-Related Costs.” CL&P has withheld, in addition to the $30 million discussed above, approximately $79 million from amounts owed to PMI, claiming that it is entitled under the contract to offset those additional amounts for SMD-Related Costs. The parties have now reached a settlement, subject to board approval, whereby CL&P will pay PMI $38.4 million plus interest, and subject to adjustments and true-ups upon final approval by FERC. The settlement agreement was filed with FERC on March 3, 2004.

In January 2002, the New York Department of Environmental Conservation, or “DEC”, sued Niagara Mohawk Power Corporation, or “NiMo”, and us in federal court in New York. The complaint asserted that projects undertaken at our Huntley and Dunkirk plants by NiMo, the former owner of the facilities, required preconstruction permits pursuant to the Clean Air Act and that the failure to obtain these permits violated federal and state laws. In July, 2002, we filed a motion to dismiss. On March 27, 2003, the court dismissed the complaint against us with prejudice as to the federal claims and without prejudice as to the state claims. It is possible the state will appeal this dismissal to the Second Circuit Court of Appeals. In the meantime, on December 31, 2003, the trial court granted the state’s motion to amend the complaint to again sue us and various affiliates in this same action in the federal court in New York, asserting against us violations of operating permits and deficient operating permits at the Huntley and Dunkirk plants. If the case ultimately is litigated to an unfavorable outcome that could not be addressed otherwise, we have estimated that the total investment that would be required to install pollution control devices could be as high as $300 million over a ten to twelve-year period. We also could be found responsible for payment of certain penalties and fines.

The DEC has alleged violations by the Huntley Generating Station, the Dunkirk Generating Station and the Oswego Generating Station with respect to opacity exceedances. The above entities have been engaged in consent order negotiations with the DEC relative to such opacity issues affecting all three facilities since the plants were acquired. In late February, 2004, a representative of each of the six entities signed a proposed final version of the consent order, which, if executed and thereby issued by the DEC, would quantify the number of opacity exceedances at the three facilities through the second quarter of 2003 and assess a cumulative penalty of $1 million. In addition, among other provisions, the consent order would establish stipulated penalties for future violations of opacity requirements and of the consent order and impose a Schedule of Compliance. In the event that the consent order is not issued by DEC in the form in which it was agreed to by the six entities and any subsequent negotiations prove unsuccessful, it is not known what relief the DEC will seek through an enforcement action and what the result of such action will be.

On April 30, 2003, the Huntley Station submitted a self-disclosure letter to the DEC reporting violations of applicable sulfur in fuel limits, which had occurred during 6 days in March 2003 at the chimney stack serving Huntley Units 63-66. The Huntley Station self-disclosed that the average sulfur emissions rates for those days had been 1.8 lbs/mm BTU, rather than the maximum allowance of 1.7 lbs/mm BTU. NRG Huntley Operations discontinued use of Unit 65 (the only unit utilizing the subject stack at the time) and has kept the remaining three units off line until adherence with the applicable standard is assured. On May 19, 2003, the DEC issued Huntley Power LLC a Notice of Violation. Huntley Power LLC has met with the DEC to discuss the circumstances surrounding the event and the appropriate means of resolving the matter. Huntley Power LLC does not know what relief the DEC will seek through an enforcement action. Under applicable provisions of the Environmental Conservation Law, the DEC asserts that it may impose a civil penalty up to $10,000, plus an additional penalty not to exceed $10,000 for each day that a violation continues and may enjoin continuing violations.

Oswego subsidiaries, both of which cases assert the same claims and legal theories for failure to pay retail tariffs for utility services at those plants.

units to reach their nameplate capacity, Koch determined that it would need additional units to reach the electric output target. In August 2000, NRG Sterlington acquired the remaining interests in the facility not originally held on a passive basis and sought the transfer of the Part 70 Air Permit along with a modification to incorporate two 17.5 MW turbines installed by Koch and to increase the total number of turbines to ten. The permit modification was issued February 13, 2002. During further review, NRG Sterlington determined that a ninth unit had been installed prior to issuance of the permit modification. In keeping with its environmental policy, it disclosed this matter to DEQ in April, 2002. NRG Sterlington provided to DEQ additional information during July 2002. A Consolidated Compliance Order & Notice of Potential Penalty, No. AE-CN-01-0393, was issued by DEQ on September 10, 2003, wherein DEQ formally alleged that NRG Sterlington did not complete all certification requirements, and installed a ninth unit prior to issuance of its permit modification. We met with DEQ on November 19, 2003 to discuss mitigating circumstances and a settlement has been agreed to between the parties. Under the settlement agreement, without admitting any liability, NRG Sterlington has agreed to pay DEQ the sum of $4,500. The agreement is subject to a public comment period and review by the Louisiana attorney general.

On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the Clean Air Act from the United States Environmental Protection Agency, or “EPA”, seeking information primarily relating to physical changes made at Big Cajun II in 1994 and 1995 by the predecessor owner of that facility. Louisiana Generating, LLC and Big Cajun II intend to respond to the EPA request in an appropriate and cooperative manner. At the present time, we cannot predict the probable outcome in this matter.

We and/or our affiliates have entered into several turbine purchase agreements with affiliates of General Electric Company, or “GE” and Siemens Westinghouse Power Corporation, or “Siemens.” GE and Siemens have notified us that we are in default under certain of those contracts, terminated such contracts, and demanded that we pay the termination fees set forth in such contracts. GE’s claim amounts to $120 million and Siemens’ approximately $45 million in cumulative termination charges. We cannot estimate the likelihood of unfavorable outcomes in these disputes.

Our indirectly controlled Brazilian project company, Itiquira Energetica S.A., the owner of a 156 MW hydro project in Brazil, is currently in arbitration with the former EPC contractor for the project, Inepar Industria e Construcoes, or “Inepar.” The dispute was commenced by Itiquira in September of 2002 and pertains to certain matters arising under the former EPC contract. Itiquira principally asserts that Inepar breached the contract and caused damages to Itiquira by (i) failing to meet milestones for substantial completion; (ii) failing to provide adequate resources to meet such milestones; (iii) failing to pay subcontractors amounts due; and (iv) being insolvent. Itiquira’s arbitration claim is for approximately U.S. $40 million. Inepar has asserted in the arbitration that Itiquira breached the contact and caused damages to Inepar by failing to recognize events of force majeure as grounds for excused delay and extensions of scope of services and material under the contract. Inepar’s damage claim is for approximately U.S. $10 million. The parties submitted their respective statements of claims, counterclaims and responses, and a preliminary arbitration hearing was held on March 21, 2003. In lieu of taking expert testimony at hearing, the court of arbitration ordered an expert investigation process to cover technical and accounting issues. We anticipate that the final report from the expert investigation process will be delivered to the court of arbitration in the last week of March, 2004. After reviewing the final report, the court of arbitration may, if it deems it necessary,

require expert testimony on technical and accounting issues, which we anticipate would commence on approximately May 15, 2004. We expect the arbitration panel to issue its decision no later than July 31, 2004. We cannot estimate the likelihood of an unfavorable outcome in this dispute.

On June 17, 2002, the CFTC served Xcel Energy, on behalf of its affiliates, which then included us and PMI, with a subpoena requesting certain information regarding “round trip” or “wash” trading and general trading practices in its investigation of several energy trading companies. The CFTC now appears focused on possible efforts by traders to submit false reports to index publications in an attempt to manipulate the index. In January, 2004, the CFTC and Xcel Energy’s subsidiary e prime, inc., reached a settlement in connection with this investigation, which included the payment of a $16 million fine and the entry of a cease and desist order. Other industry participants that have settled with the CFTC have paid fines of between $1 million and $30 million and have agreed to the terms of cease and desist orders. The CFTC has requested additional related information from us and has subpoenaed to appear for testimony a number of our present and former employees. We have sought to cooperate with the CFTC and have submitted materials responsive to the CFTC’s requests, while vigorously denying that we engaged in any improper conduct. We cannot at this time predict the outcome or financial impact of this investigation.

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

In conjunction with confirmation of the NRG plan of reorganization, we reached an agreement with the Attorney General and the State of California that limits the potential maximum amount of its claims, if any. Under the NRG plan of reorganization, the liquidated amount of any allowed claims shall not exceed $1.35 billion in total. The agreement neither affects our right to object to these claims on any grounds nor admits any liability. We further agreed to waive any objection to the liquidation of these claims in a non-bankruptcy forum having proper jurisdiction. Although we cannot make at this time any evaluation of the

likelihood of an unfavorable outcome or an estimate of the amount or range of potential loss in the private actions and various investigations, we know of no evidence implicating us in the various private plaintiffs’ allegations of collusion. We cannot predict the outcome of these cases and investigations at this time.

Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:

During the period May 14, 2003 through December 31, 2003, we received $1.1 million of interest income on cash balances. No such amounts were received during the period December 6, 2003 through December 31, 2003.

During the period May 14, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003, we made cash payments for professional fees to our financial and legal advisors of $33.5 million and $14.4 million, respectively.

We made cash payments of $1.3 billion related to the repayment of NRG Northeast Generating and NRG South Central Generating’s debt, including accrued interest upon their emergence from bankruptcy on December 23, 2003 with proceeds from our recently completed corporate level refinancing. We also made cash payments of $19.6 million for a prepayment settlement upon our early payment of the NRG Northeast Generating and NRG South Central Generating debt.

Upon our emergence from bankruptcy, we made cash payments to our creditors in the amounts of $518.6 million during the period December 6, 2003 through December 31, 2003.

In November 2002, the FASB issued FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly we applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception. As a result, we recorded a $15.0 million liability, which is included in other long-term liabilities.

We are directly liable for the obligations of certain of our project affiliates and other subsidiaries pursuant to guarantees relating to certain of their indebtedness, equity and operating obligations. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of our generation facilities in the United States, we may be required to guarantee a portion of the obligations of certain of our subsidiaries. Additionally, as a result of the downgrades of our unsecured debt ratings, we were required to but failed to post cash collateral in the amount of $71.4 million as of December 31, 2003. At the time of the January 6, 2004 restructuring of the project financing of NRG Peaker Finance Co., LLC, this equity contribution requirement was extinguished and was replaced with a $36.2 million NRG Energy letter of credit, for the benefit of the secured parties in the Peaker financing, as well as other provisions of the restructuring.

As of December 31, 2002, December 6, 2003 and December 31, 2003, our obligations pursuant to our guarantees of the performance, equity and indebtedness obligations of our subsidiaries were as follows:

As of December 6, 2003 and December 31, 2003, the nature and details of our guarantees were as follows:

Recourse provisions for each of the guarantees above are to the extent of their respective liability. Additionally, no assets are held as collateral for any of the above guarantees.

As of December 6, 2003 and December 31, 2003, the nature and details of our unmet cash collateral obligations were as follows:

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%).

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. During 2002, sales to one customer (NYISO) accounted for 23.7% of our total revenues from majority owned operations in 2002. During 2001, sales to two customers accounted for 33.6% (NYISO) and 17.5% (Connecticut Light and Power Co.) of our total revenues from majority owned operations in 2001.

On March 31, 2000, we acquired a 58% interest in the Big Cajun II, Unit 3 generation plant. Entergy Gulf States owns the remaining 42%. Big Cajun II, Unit 3 is operated and maintained by Louisiana Generating pursuant to a joint ownership participation and operating agreement. Under this agreement, Louisiana Generating and Entergy Gulf States are each entitled to their ownership percentage of the hourly net electrical output of Big Cajun II, Unit 3. All fixed costs are shared in proportion to the ownership interests. Fixed costs include the cost of operating common facilities. All variable costs are incurred in proportion to the energy delivered to the owners. Our income statement includes its share of all fixed and variable costs of operating the unit.

Our 58% share of the Property, Plant and Equipment and construction in progress as revalued to fair value upon the adoption of the fresh start provisions of SOP 90-7 at December 6, 2003 and December 31, 2003 was $183.2 million and $183.2 million and corresponding accumulated depreciation and amortization was $0 million and $0.5 million, respectively.

Our 58% share of the original cost included in Property, Plant and Equipment and construction in progress at December 31, 2002 was $189.0 million and corresponding accumulated depreciation and amortization was $12.3 million.

In June 2001, we completed the acquisition of an approximately 3.7% interest in both the Keystone and Conemaugh coal-fired generating facilities. The Keystone and Conemaugh facilities are located near Pittsburgh, Pennsylvania and are jointly owned by a consortium of energy companies. We purchased our interest from Conectiv, Inc. Keystone and Conemaugh are operated by GPU Generation, Inc., which sold its assets and operating responsibilities to Sithe Energies. Keystone and Conemaugh both consist of two operational coal-fired steam power units with a combined net output of 1,700 MW, four diesel units with a combined net output of 11 MW and an on-site landfill. The units are operated pursuant to a joint ownership participation and operating agreement. Under this agreement each joint owner is entitled to its ownership ratio of the net available output of the facility. All fixed costs are shared in proportion to the ownership interests. All variable costs are incurred in proportion to the energy delivered to the owners. Our income statement includes our share of all fixed and variable costs of operating the facilities.

Our 3.70% and 3.72% share of the Keystone and Conemaugh facilities original cost included in Property, Plant and Equipment and construction in progress at December 6, 2003 was $60 million and $63 million, respectively. The corresponding accumulated depreciation and amortization at December 6, 2003 for Keystone and Conemaugh was $0 million and $0 million, respectively.

Our 3.70% and 3.72% share of the Keystone and Conemaugh facilities Property, Plant and Equipment and construction in progress as revalued to fair value upon the adoption of the fresh start provisions of SOP 90-7 at December 31, 2003 was $57.9 million and $69.7 million, respectively. The corresponding accumulated depreciation and amortization at December 31, 2003 for Keystone and Conemaugh was $0.2 million and $0.3 million, respectively.

Our 3.70% and 3.72% share of the Keystone and Conemaugh facilities original cost included in Property, Plant and Equipment and construction in progress at December 31, 2002 was $57.9 million and $62.8 million, respectively. The corresponding accumulated depreciation and amortization at December 31, 2002 for Keystone and Conemaugh was $3.5 million and $4.1 million, respectively.

Our audits of the consolidated financial statements referred to in our report dated March 10, 2004 appearing in this Annual Report on Form 10-K also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Annual Report on Form 10-K. In our opinion, this financial statement schedule for the period from December 6, 2003 to December 31, 2003 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

Our audits of the consolidated financial statements referred to in our report dated March 10, 2004 appearing in this Annual Report on Form 10-K also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Annual Report on Form 10-K. In our opinion, this financial statement schedule for the period from January 1, 2003 to December 5, 2003 and for the two years ended December 31, 2002, present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

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


	NRG ENERGY, INC.
	(Registrant)

	/s/ DAVID CRANE

	David Crane,
	Chief Executive Officer
	(Principal Executive Officer)

	/s/ GEORGE P. SCHAEFER

	George P. Schaefer,
	Vice President and Treasurer
	(Principal Financial Officer)

	/s/ WILLIAM T. PIEPER

	William T. Pieper,
	Vice President and Controller
	(Principal Accounting Officer)

Each person whose signature appears below constitutes and appoints David W. Crane, Scott J. Davido and David T. Quinby, each or any of them, such person’s true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in such person’s name, place and stead, in any and all capacities, to sign any and all amendments to this report on Form 10-K, and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on March 12, 2004.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:


	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b) Omitted pursuant to SEC Release 33-8238;

	(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):


	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


	/s/ DAVID CRANE

	David Crane
	Chief Executive Officer
	(Principal Executive Officer)


	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b) Omitted pursuant to SEC Release 33-8238;

	(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


	/s/ GEORGE P. SCHAEFER

	George P. Schaefer
	Vice President and Treasurer
	(Principal Financial Officer)


	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b) Omitted pursuant to SEC Release 33-8238;

	(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


	/s/ WILLIAM T. PIEPER

	William T. Pieper
	Vice President and Controller
	(Principal Accounting Officer)

In connection with the Annual Report of NRG Energy, Inc. (the Company) on Form 10-K for the year ended December 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:


	(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Form 10-K.


	/s/ DAVID CRANE

	David Crane,
	Chief Executive Officer
	(Principal Executive Officer)

	/s/ GEORGE P. SCHAEFER

	George P. Schaefer,
	Vice President and Treasurer
	(Principal Financial Officer)

	/s/ WILLIAM T. PIEPER

	William T. Pieper,
	Vice President and Controller
	(Principal Accounting Officer)

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NRG Energy, Inc. and will be retained by NRG Energy, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.


	(1)	Filed herewith

	(2)	Incorporated herein by reference to NRG Energy, Inc.’s annual report on Form 10-K filed on March 31, 2003

	(3)	Incorporated herein by reference to NRG Energy’s Registration Statement on Form S-1, as amended, Registration No. 333-33397.

	(4)	Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended June 30, 1999

	(5)	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on November 19, 2003.


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the Fiscal Year ended December 31, 2003.

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the Transition Period from to .


Delaware		41-1724239
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

901 Marquette Avenue Minneapolis, Minnesota		55402
(Address of principal executive offices)		(Zip Code)


Class		Outstanding at March 1, 2004

Common Stock, par value $0.01 per share		100,000,000


		Page No.

PART I
Item 1	Business		2
Item 2	Properties		40
Item 3	Legal Proceedings		43
Item 4	Submission of Matters to a Vote of Security Holders		52

PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		52
Item 6	Selected Financial Data		54
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		55
Item 7A	Quantitative and Qualitative Disclosures About Market Risk		88
Item 8	Financial Statements and Supplementary Data		90
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		90
Item 9A	Controls and Procedures		90

PART III
Item 10	Directors and Executive Officers of the Registrant		90
Item 11	Executive Compensation		90
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		90
Item 13	Certain Relationships and Related Transactions		91
Item 14	Principal Accountants Fees and Services		91

PART IV
Item 15	Exhibits, Financial Statements Schedules and Reports on Form 8-K		91
Signatures			199
Amended and Restated Certificate of Incorporation
Amended and Restated By-Laws
Indenture
Purchase Agreement
Registration Rights Agreement
Purchase Agreement
Registration Rights Agreement
$1,450,000 Credit Agreement
Guarantee and Collateral Agreement
Collateral Trust Agreement
Amended and Restated Common Agreement
Amended and Restated Security Deposit Agreement
NRG Parent Agreement
Employment Agreement - David Crane
Key Executive Retention, Restructing Agreement
Severance Agreement - William Pieper
Severance Agreement - John P. Brewster
Subsidiaries
Rule 13a-14(a)/14d-14(a) Certification - Crane
Rule 13a-14(a)/14d-14(a) Certification - Schaefer
Rule 13a-14(a)/14d-14(a) Certification - Pieper
Section 1350 Certification
Financial Statements of West Coast Power


	Energy		Capacity		Ancillary		Other		Total
Region	Revenues		Revenues		Services		Revenues***		Revenues

Northeast	$	630,808	$	249,211	$	11,624	$	38,313	$	929,956
South Central		211,570		171,264		—		1,019		383,853
West Coast*		5,259		18,505		—		—		23,764
Other		10,372		125,085		4		51,738		187,199

Total North America Power Generation**	$	858,009	$	564,065	$	11,628	$	91,070	$	1,524,772


Title of Each Class		Name of Exchange on Which Registered

None		None


	*Events Leading to the Commencement of the Chapter 11 Filing*


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


			Annual
	Net		Equivalent		Average Heat
	Generation		Availability		Rate		Net Capacity		Net U.S. Owned		In-Market
Region	(MWh)		Factor		Btu/KWh		Factor		Capacity		Availability

Northeast		13,390,887		86.0%		10,763		20.0%		7,657		92.4%
South Central		10,249,518		92.6%		10,695		47.4%		2,469		96.8%
Other		3,676,045		89.8%		8,653		11.9%		3,542		N/A


					NRG’s
			Net Owned		Percentage
	Power		Capacity		Ownership			Fuel
Name and Location of Facility	Market		(MW)		Interest			Type

Oswego, New York		NYISO		1,700		100	%	Oil/Gas
Huntley, New York		NYISO		760		100	%	Coal
Dunkirk, New York		NYISO		600		100	%	Coal
Arthur Kill, New York		NYISO		842		100	%	Gas/Oil
Astoria Gas Turbines, New York		NYISO		600		100	%	Gas/Oil
Somerset, Massachusetts		ISO-NE		136		100	%	Coal/Oil/Jet Fuel
Middletown, Connecticut		ISO-NE		786		100	%	Oil/Gas/Jet Fuel
Montville, Connecticut		ISO-NE		498		100	%	Oil/Gas/Diesel
Devon, Connecticut		ISO-NE		401		100	%	Gas/Oil/Jet
Norwalk Harbor, Connecticut		ISO-NE		353		100	%	Oil
Connecticut Jet Power, Connecticut		ISO-NE		127		100	%	Jet
Indian River, Delaware		PJM		784		100	%	Coal/Oil
Vienna, Maryland		PJM		170		100	%	Oil
Conemaugh, Pennsylvania		PJM		64		4	%	Coal/Oil
Keystone, Pennsylvania		PJM		63		4	%	Coal/Oil


			NRG’s
			Percentage
Name and Location			Ownership		Fuel
of Facility	Purchaser/MSW Supplier	Net Owned Capacity	Interest		Type

Newport, MN*	Ramsey and Washington Counties	MSW: 1,500 tons/day		100%	Refuse Derived Fuel
Elk River, MN**	Anoka, Hennepin and Sherburne Counties; Tri-County Solid Waste Management Commission	MSW: 1,275 tons/day		85%	Refuse Derived Fuel
Penobscot Energy Recovery, ME***	Bangor Hydroelectric Company	MSW: 590 tons/day		50%	Refuse Derived Fuel


Asset (Location)	Transaction Description		Closing Date

Completed Transactions:
ECKG (Czech Republic)		Sale of our 45% interest		1/10/03
Brazos Valley (Texas)		Transfer of our project to project banks		1/31/03
Killingholme (England)(1)		Transfer of our project to project banks		1/31/03
NEO Landfill Gas and Minn. Methane (Various)		Hudson United Bank foreclosure		5/7/03
Kondapalli (India)		Sale of our 30% interest		5/30/03
Mustang (Texas)		Sale of our 25% interest		7/7/03
Langage (England)		Sale of our 100% interest		8/1/03
Timber Energy (Power Plant)(1)		Sale of our 50% interest		9/18/03
Central San Antonio Libertador Turbine Package		Sale of our turbines		10/20/03
Timber Energy (Chip Mill)(1)		Sale of our 50% interest		10/30/03
Cahua and Energia Pacasmayo (Peru)(1)		Sale of our 100% interest		11/21/03
Announced Pending Dispositions:
Loy Yang (Australia)		Sale of our 25% interest		N/A
McClain (Oklahoma)(1)		Asset sale		N/A



		Revenue By Segment


		Predecessor Company															Reorganized NRG

		For the Year					For the Year					For the Period					For the Period
		Ended		Percent of			Ended		Percent of			Ended		Percent of			Ended			Percent of
		December 31,		Total			December 31,		Total			December 5,		Total			December 31,			Total
Segments		2001		Revenue			2002		Revenue			2003		Revenue			2003			Revenue

		(In thousands)					(In thousands)					(In thousands)					(In thousands)
Power Generation
	North America	$	1,697,125		76.9	%	$	1,564,360		73.8	%	$	1,416,743		72.0	%	$	108,029			71.0	%
	Europe		72,540		3.3	%		107,466		5.1	%		118,825		6.0	%		11,278			7.4	%
	Other Americas		21,923		1.0	%		33,084		1.6	%		46,407		2.4	%		4,514			3.0	%
	Asia Pacific		238,375		10.8	%		228,591		10.8	%		211,475		10.7	%		16,294			10.7	%
Thermal			108,319		4.9	%		111,809		5.3	%		108,068		5.5	%		8,632			5.7	%
Alternative Energy			51,423		2.3	%		69,288		3.3	%		61,098		3.1	%		3,870			2.5	%
Other			18,476		0.8	%		4,787		0.1	%		5,963		0.3	%		(509	)		(0.3	)%

Total Revenue		$	2,208,181		100.0	%	$	2,119,385		100.0	%	$	1,968,579		100.0	%	$	152,108			100.0	%


	*Our actual financial results may vary significantly from the projections filed with the bankruptcy court.*


	Because our consolidated financial statements will reflect Fresh Start reporting adjustments made upon our emergence from bankruptcy, financial information reflecting our future results of operations and financial condition will not be comparable to prior periods.


Item 1 —	*Business*


	*NRG Plan of Reorganization*


	*Northeast Region*


	*South Central Region*


	*Our operations are subject to hazards customary to the power generation industry. We may not have adequate insurance to cover all of these hazards.*


	Our revenues are unpredictable because many of our power generation facilities operate, wholly or partially, without long-term power purchase agreements. Further, because wholesale power prices are subject to significant volatility, the revenues that we generate are subject to significant fluctuations.


	A substantial portion of our historical earnings in 2003 have been derived from our California generation assets, and we cannot assure you as to the collectibility of all amounts owed to our California affiliates or that we will be able to enter into comparable agreements beyond 2004.


	Construction, expansion, refurbishment and operation of power generation facilities involve significant risks that cannot always be covered by insurance or contractual protections and could have a material adverse effect on our revenues and results of operations.


	We are exposed to the risk of fuel and fuel transportation cost increases and volatility and interruption in fuel supply because our facilities generally do not have long-term natural gas, coal and liquid fuel supply agreements.


	*The quality of fuel that we rely on at certain of our plants may at times not be available.*


	*Future decreases in gas prices in certain markets may adversely impact our financial performance.*


	We often rely on single suppliers and at times we rely on single customers at our facilities, exposing us to significant financial risks if either should fail to perform their obligations.


	*We may not have sufficient liquidity to effectively hedge market risks.*


	*Our risk management activities may increase the volatility in our quarterly financial results.*


	*Our results are subject to quarterly and seasonal fluctuations.*


	*Large energy blackouts have the potential to reduce our revenue collection, increase our costs and result in increased federal and state regulatory requirements.*


	*Because we own less than a majority of some of our project investments, we cannot exercise complete control over their operations.*


	Our business is subject to substantial governmental regulation and permitting requirements and may be adversely affected by liability under, or any future inability to comply with, existing or future regulations or requirements.


	Our business faces regulatory risks related to the market rules and regulations imposed by transmission providers, ISOs and RTOs particularly with respect to our Connecticut generating assets.


	*Our success will depend on our ability to retain key employees and successfully implement new strategies.*


	We will be subject to claims made after the date that we filed for bankruptcy and other claims that are not discharged in the bankruptcy proceeding, which could have a material adverse effect on our results of operations and profitability.


	*We cannot be certain that the bankruptcy proceeding will not adversely affect our operations going forward.*


	Certain of our prepetition creditors have received NRG Energy common stock pursuant to the NRG plan of reorganization and have the right to select our board members and influence certain aspects of our business operations.


	*Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.*