SEC Filing | NRG Energy, Inc.

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


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

		For the Fiscal Year ended December 31, 2004.

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

Commission file No. 001-15891

NRG Energy, Inc.

(Exact name of Registrant as specified in its charter)


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

211 Carnegie Center Princeton, New Jersey		08540
(Address of principal executive offices)		(Zip Code)

(609) 524-4500

(Registrant’s telephone number, including area code)

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


Title of Each Class		Name of Exchange on Which Registered

None		None

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

Common Stock, par value $0.01 per share

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

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

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

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

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

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


Class		Outstanding at March 28, 2005

Common Stock, par value $0.01 per share		87,045,104

Documents Incorporated by Reference:

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

NRG ENERGY, INC. AND SUBSIDIARIES

INDEX


		Page No.

PART I
Item 1	Business		2
Item 2	Properties		37
Item 3	Legal Proceedings		40
Item 4	Submission of Matters to a Vote of Security Holders		47
PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		47
Item 6	Selected Financial Data		50
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		51
Item 7A	Quantitative and Qualitative Disclosures About Market Risk		93
Item 8	Financial Statements and Supplementary Data		96
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		96
Item 9A	Controls and Procedures		96
Item 9B	Other Information		96
PART III
Item 10	Directors and Executive Officers of the Registrant		97
Item 11	Executive Compensation		97
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		97
Item 13	Certain Relationships and Related Transactions		97
Item 14	Principal Accountants Fees and Services		97
PART IV
Item 15	Exhibits and Financial Statement Schedules		97
Signatures			213
Form of Long-Term Incentive Plan Deferred Stock Unit Agreement
Form of Long-Term Incentive Plan Deferred Stock Unit Agreement
Credit Agreement
Guarantee and Collateral Agreement
Collateral Trust Agreement
Railroad Car Full Service Master Lease Agreement
Commitment Letter
Summary of Director Compensation
Subsidiaries
Consent of KPMG LLP
Consent of PricewaterhouseCoopers LLP
Consent of PricewaterhouseCoopers LLP
Rule 13a-14(a)/15d-14(a) Certification of David W. Crane
Rule 13a-14(a)/15d-14(a) Certification of Robert C. Flexon
Rule 13a-14(a)/15d-14(a) Certification of James J. Ingoldsby
Section 1350 Certification
Financial Statements of West Coast Power LLC

PART I

Item 1 — Business

General

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

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

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

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

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

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

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

Strategy

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

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


	•	Develop the assets in our core regions into integrated businesses well suited to serve the requirements of the load-serving entities in our core markets;

	•	Reinvest our capital in our existing assets for reasons of repowering, expansion, environmental remediation, operating efficiency, reliability programs, greater fuel optionality, greater merit order diversity, enhanced portfolio effect or alternative use, among others; and

	•	Where consistent with our “core region” strategy, pursue selective acquisitions to complement the assets and portfolios in our core regions.

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

Competition

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

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

Competitive Strengths

We believe that we benefit from the following competitive strengths:

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

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

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

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

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

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

Reorganization

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

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

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

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

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

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

Fresh Start Reporting

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

Performance Metrics

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


						Alternative
	Energy		Capacity			Energy					Other			Total
Region	Revenues		Revenues			Revenues		O&M Fees			Revenues***			Revenues

	(In thousands)
Northeast	$	853,454	$	264,624		$	49	$	—		$	133,026		$	1,251,153
South Central		219,112		183,483			—		—			15,550			418,145
West Coast*		9,276		(3,709	)		—		(2	)		(3,096	)		2,469
Other		27,816		84,097			1,748		186			(8,203	)		105,644

Total North America Power Generation**	$	1,109,658	$	528,495		$	1,797	$	184		$	137,277		$	1,777,411


	*	Consists of our wholly-owned subsidiary, NEO California LLC. Does not include revenues which were produced by assets in which we have a 50% equity interest, primarily West Coast Power, and are reported under the equity method of accounting.


	**	For additional information — see Item 15 — Note 23 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 must- run agreements, revenues received under leasing arrangements, revenues from maintenance, revenues from the sale of ancillary services and revenues from entering into certain financial transactions, offset by contract amortization.

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

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

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

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

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


					Annual
			Net		Equivalent			Average Gross
	Net Owned		Generation		Availability			Heat Rate		Net Capacity
Region	Capacity (MW)		(MWh)		Factor			Btu/KWh		Factor

Northeast*		7,884		13,205,017		85.6	%		10,174		19.8	%
South Central		2,469		10,470,786		92.1	%		9,965		52.9	%
West Coast**		1,315		2,354,668		80.0	%		10,121		20.4	%
Other North America		1,591		2,925,653		96.3	%		N/A		12.0	%


	*	Net Generation and the other metrics do not include Keystone and Conemaugh.


**	Includes 50% of the generation owned through our West Coast Power partnership.

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


					Annual
			Net		Equivalent			Average Gross
	Net Owned		Generation		Availability			Heat Rate		Net Capacity
Region	Capacity (MW)		(MWh)		Factor			Btu/KWh		Factor

Flinders Northern Power Station		520		3,924,196		93.2	%		11,400		93.1	%
Flinders Playford Power Station		240		365,642		46.0	%		16,300		18.9	%
Gladstone*		630		3,065,044		83.2	%		9,600		55.4	%


*	Includes 37.5% of the generation owned through our Gladstone partnership.

Power Generation


	*Northeast Region*

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

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


					NRG’s
			Net Owned		Percentage
	Power		Capacity		Ownership
Name and Location of Facility	Market		(MW)		Interest			Fuel 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
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 Fuel
Norwalk Harbor, Connecticut		ISO-NE		353		100	%		Oil
Connecticut Jet Power, Connecticut		ISO-NE		127		100	%		Jet Fuel
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

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

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

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

Market Developments. ISO-NE and NEPOOL operate a centralized energy market with “Day-Ahead” and “Real-time” energy markets. On August 23, 2004, ISO-NE filed its proposal for locational installed capacity, or LICAP, with FERC, which will decide the issue in a litigated proceeding before an administrative law judge. Under the proposal, separate capacity markets would be created for distinct areas of New England, including southwest Connecticut. While we view this proposal as a positive development, as it is currently proposed it would not permit us to recover all of our fixed costs. In response, we have submitted testimony which includes an alternative proposal. FERC’s goal is to make a decision on the precise terms of the NEPOOL LICAP market in the fall of 2005, to be effective January 1, 2006.

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

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

On January 7, 2005, NYISO filed proposed LICAP demand curves for the following capacity years: 2005-06, 2006-07 and 2007-08. Under the NYISO proposal, the LICAP price for New York City generation would be $126 per KW-year for the capacity year 2006-07. On January 28, 2005, we filed a protest at FERC asserting the LICAP price for this period should be at least $140 per KW-year.

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

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


	*South Central Region*

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

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

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

NRG’s

Net Owned

Percentage

Power

Capacity

Ownership

Fuel

Name and Location of Facility

Market

(MW)

Interest

Type

Big Cajun II, Louisiana*

SERC-Entergy

1,489

Coal

Big Cajun I, Louisiana

SERC-Entergy

458

100

Gas/Oil

Bayou Cove, Louisiana

SERC-Entergy

320

100

Gas

Sterlington, Louisiana

SERC-Entergy

202

100

Gas


*	We own 100% of Units 1 and 2 and 58% of Unit 3.

Market Framework. Our South Central region’s assets are located within the franchise territory of Entergy, a vertically-integrated utility. Entergy performs the scheduling, reserve and reliability functions that are administered by ISOs in certain other regions of the United States and Canada. We operate a North American Electric Reliability Council, or NERC, certified-control area within the Entergy franchise territory, which is comprised of our generating assets and our cooperatives’ customer loads. In the South Central region, including Entergy’s franchise territory, the energy market is not a centralized market and it does not have an independent system operator as is found in the northeast markets. All power sales and purchases are consummated bilaterally between individual counter-parties, and physically delivered either within or across the physical control areas of the transmission owners. Transacting counter-parties are required to reserve and purchase transmission services from the intervening transmission owners at their FERC-approved tariff rates. Included with these transmission services are the reserve and ancillary costs. Energy prices in the South Central region are determined and agreed to in bilateral negotiations between representatives of the transacting counter-parties, using market information gleaned by the individual marketing agents arranging the transactions.

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

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

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

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

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

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


	*West Coast Region*

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

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

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

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

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

NRG’s

Net Owned

Percentage

Power

Capacity

Ownership

Fuel

Name and Location of Facility

Market

(MW)

Interest

Type

Encina, California

Cal ISO

483

Gas/Oil

El Segundo Power, California

Cal ISO

335

Gas

Long Beach Generating, California*

Cal ISO

265

Gas

San Diego Combustion Turbines, California

Cal ISO

Gas/Oil

Saguaro Power Co., Nevada

WECC

Gas/Oil

Chowchilla, California

Cal ISO

100

Gas

Red Bluff, California

Cal ISO

100

Gas


*	Retired effective January 1, 2005

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

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

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

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


	*Other North America*

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

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

NRG’s

Net Owned

Percentage

Capacity

Ownership

Fuel

Name and Location of Facility

Power Market

(MW)

Interest

Type

Audrain, Missouri*

MAIN

640

100%

Gas

Rockford I, Illinois

MAIN

342

100%

Gas

Rockford II, Illinois

MAIN

171

100%

Gas

Rocky Road Power, Illinois

PJM

175

50%

Gas

Ilion, New York

NYISO

100%

Gas/Oil

Dover, Delaware

PJM

106

100%

Gas/Oil

James River, Virginia*

SERC-TVA

50%

Coal

Paxton Creek Cogeneration

PJM

100%

Gas

Other — 3 projects*

Various


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


	*Australia*

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

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

NRG’s

Net Owned

Percentage

Capacity

Ownership

Fuel

Name and Location of Facility

Purchaser/ Power Market

(MW)

Interest

Type

Flinders, South Australia

National Electricity Market

760

100%

Coal

Gladstone Power Station, Queensland

Enertrade/Boyne Smelters

630

37.5%

Coal


	Market Framework

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

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

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


	Market Development

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

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

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


	*Other International*

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

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

NRG’s

Net Owned

Percentage

Capacity

Ownership

Fuel

Name and Location of Facility

Purchaser/ Power Market

(MW)

Interest

Type

Europe:

Enfield Energy Centre, UK*

UK Electricity Grid

Gas

Schkopau Power Station, Germany

Vattenfall Europe

400

Coal

MIBRAG mbH, Germany**

ENVIA/MIBRAG Mines

119

Coal

Brazil:

Itiquira Energetica, Brazil*

COPEL

154

Hydro


	*	NRG may sell or dispose of in the next 12 months.


**	Primarily a coal mining facility.


	*Alternative Energy and Services*

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

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

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

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


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

Newport, MN*	Ramsey and Washington Counties	1,500 tons/day		100%	Refuse Derived Fuel
Elk River, MN**	Anoka, Hennepin and Sherburne Counties; Tri- County Solid Waste Management Commission	1,275 tons/day		85%	Refuse Derived Fuel


	*	The Newport facilities are related strictly to municipal solid waste processing (MSW).


**	Our 85% interest in the Elk River facility is related strictly to municipal solid waste processing.


	*Non-Generation*

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

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

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

NRG’s

Percentage

Net Owned

Ownership

Name and Location of Facility

Customers

Capacity*

Interest

Fuel Type

NRG Energy Center Minneapolis, Minnesota

Approx. 100 steam customers and 45 chilled water customers

Steam: 1,203 mm Btu/hr. (353 MWt)
Chilled water: 41,630 tons (146 MWt)

100%

Gas/Oil

NRG Energy Center San Francisco, California

Approx. 170 steam customers

Steam: 482 mm Btu/hr. (141 MWt)

100%

Gas

NRG Energy Center Harrisburg, Pennsylvania

Approx. 270 steam customers and 3 chilled water customers

Steam: 440 mm Btu/hr. (129 MWt)
Chilled water: 2,400 tons (8 MWt)

100%

Gas/Oil

NRG Energy Center Pittsburgh, Pennsylvania

Approx. 25 steam and 25 chilled water customers

Steam: 266 mm Btu/hr. (78 MWt)
Chilled water: 12,580 tons (44 MWt)

100%

Gas/Oil

NRG Energy Center San Diego, California

Approx. 20 chilled water customers

Chilled water: 7,425 tons (26 MWt)

100%

Gas

NRG Energy Center
St. Paul, Minnesota

Rock-Tenn Company

Steam: 430 mm Btu/hr. (126 MWt)

100%

Coal/Gas/Oil

Camas Power Boiler Washington

Georgia-Pacific Corp.

Steam: 200 mm Btu/hr. (59 MWt)

100%

Biomass

NRG Energy Center
Dover, Delaware

Kraft Foods, Inc.

Steam: 190 mm Btu/hr. (56 MWt)

100%

Coal

NRG Energy Center
Bayport, Minnesota

Andersen Corporation and Minnesota Correctional Facility

Steam: 200 mm Btu/hr. (59 MWt)

100%

Coal/Gas/Propane


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

Energy Marketing

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

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

NRG Worldwide Operations

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

Financial Information About Segments and Geographic Areas

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

Dispositions of Non-Strategic Assets

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


							Gain/(Loss) on			Debt
Asset (Location)		Segment	Closing Date		Proceeds		Disposition			Reduction

					(In thousands)
Calpine Cogeneration		Other North America		3/07/2004	$	3.0	$	0.7		$	—
Loy Yang (Australia)		Australia		4/08/2004		26.7		(1.3	)		—
PERC (Maine)		Other North America		4/16/2004		18.4		3.2			25.2
Cobee (Bolivia)		Other International		4/27/2004		50.0		2.8			24.1
Hsin Yu (Taiwan)		Other International		5/13/2004		1.0		10.3			46.4
McClain (Oklahoma)		Other North America		7/09/2004		160.2		(3.0	)		156.5
Batesville (Mississippi)		Other North America		7/24/2004		27.6		11.0			289.3
NEO projects		Alternative Energy		9/30/2004		5.8		6.0			—
NEO equity projects		Alternative Energy		9/30/2004		6.1		(3.8	)		—
CALP, Virginia		Other North America		11/30/2004		14.9		(4.6	)		—
Kendall, Illinois		Other North America		12/01/2004		1.0		(26.5	)		448.4

	Total				$	314.7	$	(5.2	)	$	989.9

Significant Customers


	*Reorganized NRG*

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

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


	*Predecessor Company*

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

Seasonality and Price Volatility

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

Sources and Availability of Raw Materials

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

Employees

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

Federal Energy Regulation

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

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

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

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

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

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

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

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

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

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

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

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

Environmental Matters

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

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

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

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


	*Domestic Environmental Regulatory Matters*

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

We establish accruals where it is probable that we will incur environmental costs under applicable law or contract and it is possible to reasonably estimate those costs. We adjust the accruals when new remediation or other environmental liability responsibilities are discovered and probable costs become estimable, or when current liability estimates are adjusted to reflect new information or a change in the law.


	*U.S. Federal Environmental Initiatives*

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

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

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

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

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

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

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

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

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

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

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

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


	*Regional U.S. Regulatory Initiatives*

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

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

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

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

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

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

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

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

South Central Region. The Louisiana Department of Environmental Quality, or LADEQ, has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone non-attainment area into compliance with applicable NAAQS. The Company participated in development of the revisions, which require the reduction of NO_X emissions at the gas-fired Big Cajun I Power Station and coal-fired Big Cajun II Power Station to 0.1 lbs/ MMBtu and 0.21 lbs/ MMBtu NO_X, respectively (both based on heat input). This revision of the Louisiana air rules would constitute a change-in-law covered by agreement between Louisiana Generating LLC and the electric cooperatives (power offtakers) allowing the costs of added combustion controls to be passed through to the cooperatives. The capital cost of combustion controls required at the Big Cajun II Generating Station to meet the state’s NO_X regulations will total about $10.0 million for Unit 1 and will be undertaken in 2005. Units 2 and 3 have already made such changes.

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

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

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


	*Domestic Site Remediation Matters*

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

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

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

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

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

South Central Region. Liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated at the Big Cajun II Generating Station are addressed through the use of a trust fund maintained by the Company. The value of the trust fund is approximately $5.0 million and the Company is making annual payments to the fund in the amount of approximately $116,000.

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

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


	*International Environmental Matters*

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

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

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

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

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

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

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

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

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

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

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

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

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

Risks Related to NRG Energy, Inc.


	*Future decreases in gas prices may adversely impact our financial performance.*

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


	Our revenues are unpredictable because most 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.

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

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


	*Competition in wholesale power markets may have a material adverse effect on our results of operations and cash flows.*

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

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

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

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


	*A substantial portion of our historical cash flow has been derived from a CDWR contract in California and we do not expect to be able to enter into comparable agreements beyond 2004.*

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


	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.

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

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

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


	•	interruptions to dispatch at our facilities;

	•	supply interruptions;

	•	work stoppages;

	•	labor disputes;

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


	We are exposed to the risk of fuel and fuel transportation cost increases and volatility and interruption in fuel supply because some of our facilities do not have long-term natural gas, coal or liquid fuel supply agreements.

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


	•	weather conditions;

	•	seasonality;

	•	demand for energy commodities and general economic conditions;


	•	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, 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 materially and adversely affect our financial results and operations.


	*The quality of fuel that we rely on at certain of our coal plants may not be available at times.*

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


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


	*Our operations are subject to hazards customary to the power generation industry. We may not have adequate insurance to cover all of these hazards.*

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

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


	*We may not have sufficient liquidity to hedge market risks effectively.*

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

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


	*The accounting for our hedging activities may increase the volatility in our quarterly and annual financial results.*

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


	*The value of our assets is subject to the nature and extent of decommissioning and remediation obligations applicable to us.*

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


	*Our results are subject to quarterly and seasonal fluctuations.*

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


	*Because we own less than a majority of some of our project investments, we cannot exercise complete control over their operations.*

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


	*Our access to the capital markets may be limited.*

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;

	•	cash flow; and

	•	provisions of tax and securities laws that may impact raising capital.

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

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

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


	*Our business faces regulatory risks related to the market rules and regulations imposed by transmission providers, independent system operators and regional transmission organizations.*

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

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


	*Restrictions in transmission access and expansions in the transmission system could reduce revenues.*

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

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


	We are subject to claims made after the date that we filed for bankruptcy and other claims that were not discharged in the bankruptcy cases, which could have a material adverse effect on our results of operations and profitability.

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

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


	*Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.*

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.


	*Our international investments face uncertainties.*

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

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


	•	fluctuations in currency valuation;

	•	currency inconvertibility;

	•	expropriation and confiscatory taxation;

	•	increased regulation; and

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

Cautionary Statement Regarding Forward Looking Information

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


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

	•	Our ability to successfully and timely close transactions to sell certain of our assets;

	•	The potential impact of our corporate relocation on workforce requirements including the loss of institutional knowledge and the inability to maintain existing processes;

	•	Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, 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 and the possibility that we may not have adequate insurance to cover losses as a result of such hazards;

	•	Our potential inability to enter into contracts to sell power and procure fuel on terms and prices acceptable to us;

	•	The liquidity and competitiveness of wholesale markets for energy commodities;

	•	Changes in government regulation, including but not limited to the pending changes of market rules, market structures and design, rates, tariffs, environmental laws and regulations and regulatory compliance requirements;

	•	Price mitigation strategies and other market structures employed by independent system operators, or ISOs, or regional transmission organizations, or RTOs, that result in a failure to adequately compensate our generation units for all of their costs;

	•	Our ability to borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness going forward; and

	•	Significant operating and financial restrictions placed on us contained in the indenture governing our 8% second priority senior secured notes due 2013, our amended and restated credit facility as well as in debt and other agreements of certain of our subsidiaries and project affiliates generally.

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

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

Item 2 — Properties

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

Independent Power Production and Cogeneration Facilities

Net

NRG’S

Owned

Percentage

Capacity

Ownership

Name and Location of Facility

Purchaser/Power Market

(MW)

Interest

Fuel Type

Northeast Region:

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

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 Fuel

Norwalk Harbor, Connecticut

ISO-NE

353

100%

Oil

Connecticut Jet Power, Connecticut

ISO-NE

127

100%

Jet Fuel

Indian River, Delaware

PJM

784

100%

Coal/Oil

Vienna, Maryland

PJM

170

100%

Oil

Conemaugh, Pennsylvania

PJM

Coal/Oil

Keystone, Pennsylvania

PJM

Coal/Oil

South Central Region:

Big Cajun II, Louisiana*

SERC-Entergy

1,489

86%

Coal

Big Cajun I, Louisiana

SERC-Entergy

458

100%

Gas/Oil

Bayou Cove, Louisiana

SERC-Entergy

320

100%

Gas

Sterlington, Louisiana

SERC-Entergy

202

100%

Gas

West Coast Region:

El Segundo Power, California

Cal ISO

335

50%

Gas

Encina, California

Cal ISO

483

50%

Gas/Oil

Long Beach Generating, California**

Cal ISO

265

50%

Gas

San Diego Combustion Turbines, CA

Cal ISO

50%

Gas/Oil

Saguaro Power Co., Nevada***

WECC

50%

Gas/Oil

Chowchilla, California

Cal ISO

100%

Gas

Red Bluff, California

Cal ISO

100%

Gas

Other North America:

Audrain***

MAIN

640

100%

Gas

Rockford I, Illinois

MAIN

342

100%

Gas

Net

NRG’S

Owned

Percentage

Capacity

Ownership

Name and Location of Facility

Purchaser/Power Market

(MW)

Interest

Fuel Type

Rockford II, Illinois

MAIN

171

100%

Gas

Rocky Road Power, Illinois

PJM

175

50%

Gas

Ilion, New York

NYISO

100%

Gas/Oil

Dover, Delaware

PJM

106

100%

Gas/Coal/Oil

James River***

SERC — TVA

50%

Coal

Paxton Creek Cogeneration

PJM

100%

Gas

Other — 3 projects***

Various

Australia:

Flinders, South Australia

South Australian Pool

760

100%

Coal

Gladstone Power Station, Queensland

Enertrade/Boyne Smelters

630

38%

Coal

Other International:

Europe:

Enfield Energy Centre, UK***

UK Electricity Grid

25%

Gas

Schkopau Power Station, Germany

Vattenfall Europe

400

42%

Coal

MIBRAG mbH, Germany****

ENVIA/MIBRAG Mines

119

50%

Coal

Brazil:

Itiquira Energetica, Brazil***

COPEL

154

99%

Hydro

NEO Corporation, Various

Various


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

**	Retired effective January 1, 2005

***	May sell or dispose of in 2005

****	Primarily a coal mining facility

Thermal Energy Production and Transmission Facilities and Resource Recovery Facilities

NRG’s

Percentage

Name and Location of

Ownership

Facility

Customers

Net Owned Capacity*

Interest

Fuel Type

Non-Generation Facilities:

NRG Energy Center Minneapolis, Minnesota

Approx. 100 steam customers and 45 chilled water customers

Steam: 1,203 mm Btu/hr. (353 MWt)
Chilled water: 41,630 tons (146 MWt)

100%

Gas/Oil

NRG Energy Center San Francisco, California

Approx. 170 steam customers

Steam: 482 mm Btu/hr. (141 MWt)

100%

Gas

NRG Energy Center Harrisburg, Pennsylvania

Approx. 270 steam customers and 3 chilled water customers

Steam: 440 mm Btu/hr. (129 MWt)
Chilled water: 2,400 tons (8 MWt)

100%

Gas/Oil

NRG Energy Center Pittsburgh, Pennsylvania

Approx. 25 steam and 25 chilled water customers

Steam: 266 mm Btu/hr. (78 MWt)
Chilled water: 12,580 tons (44 MWt)

100%

Gas/Oil

NRG Energy Center San Diego, California

Approx. 20 chilled water customers

Chilled water: 7,425 tons (26 MWt)

100%

Gas

NRG Energy Center St. Paul, Minnesota

Rock-Tenn Company

Steam: 430 mm Btu/hr. (126 MWt)

100%

Coal/Gas/Oil

Camas Power Boiler Washington

Georgia-Pacific Corp.

Steam: 200 mm Btu/hr. (59 MWt)

100%

Biomass

NRG Energy Center Dover, Delaware

Kraft Foods, Inc.

Steam: 190 mm Btu/hr. (56 MWt)

100%

Coal

NRG Energy Center Bayport, Minnesota

Andersen Corporation and Minnesota Correctional Facility

Steam: 200 mm Btu/hr. (59 MWt)

100%

Coal/Gas/Propane


*	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.


			NRG’S
			Percentage
			Ownership
Name and Location of Facility	Customers	Net Owned Capacity	Interest

Alternative Energy:
Resource Recovery Facilities
Newport, Minnesota	Ramsey and Washington Counties	MSW: 1,500 tons/day		100%
Elk River, Minnesota	Anoka, Hennepin, and Sherburne Counties; Tri- County Solid Waste Management Commission	MSW: 1,275 tons/day		85%

Other Properties

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


Item 3 —	*Legal Proceedings*

California Wholesale Electricity Litigation and Related Investigations

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

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

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

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).

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

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

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

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

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

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

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

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

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

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

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

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


	NRG Bankruptcy Cap on California Claims

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


	*Investigations*


	FERC — California Market Manipulation

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

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

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

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


	Other FERC Proceedings

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


	California Attorney General

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

Electricity Consumers Resource Council v. Federal Energy Regulatory Commission, Docket No. 03-1449. On December 19, 2003, the Electricity Consumers Resource Council, or ECRC, appealed to the U.S. Court of Appeals for the District of Columbia Circuit a 2003 FERC decision approving the implementation of a demand curve for the New York installed capacity, or ICAP, market. ECRC claims that the implementation of the ICAP demand curve violates section 205 of the Federal Power Act because it constitutes unreasonable ratemaking. On December 3, 2004, the Company filed a brief opposing the ECRC request.

Consolidated Edison Co. of New York v. Federal Energy Regulatory Commission, Docket No. 01-1503. Consolidated Edison and others petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of certain FERC orders in which FERC refused to order a re-determination of prices in the New York Independent System Operator, or NYISO, operating reserve markets for the period January 29, 2000, to March 27, 2000. On November 7, 2003, the Court issued a decision which found that the NYISO’s method of pricing spinning reserves violated the NYISO tariff. The Court also required FERC to determine whether the exclusion from the non-spinning market of a generating facility known as Blenheim-Gilboa and resources located in western New York also constituted a tariff violation and/or whether these exclusions enabled NYISO to use its Temporary Extraordinary Procedure, or TEP, authority to require refunds. On March 4, 2005, FERC issued an order stating that no refunds would be required for the tariff violation associated with the pricing of spinning reserves. In the order, FERC also stated that the exclusion of the Blenheim-Gilboa facility and western reserves from the non-spinning market was not a market flaw and NYISO was correct not to use its TEP authority to revise the prices in this market. Motions for rehearing of the Order must be filed by April 3, 2005. If the March 4, 2005 order is reversed and refunds are required, NRG entities which may be affected include NRG Power Marketing, Inc., Astoria Gas Turbine Power LLC and Arthur Kill Power LLC.

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

Connecticut Light & Power Company v. NRG Power Marketing, Inc., Docket No. 3:01-CV-2373 (AWT), U.S. District Court, District of Connecticut (filed on November 28, 2001). Connecticut Light & Power Company, or CL&P, sought recovery of amounts it claimed it was owed for congestion charges under the terms of an October 29, 1999, contract between the parties. CL&P withheld approximately $30 million from amounts owed to NRG Power Marketing, Inc., or PMI, and PMI counterclaimed. CL&P filed its motion for summary judgment to which PMI filed a response on March 21, 2003. By reason of the stay issued by the bankruptcy court, the court has not ruled on the pending motion. On November 6, 2003, the parties filed a joint stipulation for relief from the stay in order to allow the proceeding to go forward that was promptly granted. PMI cannot estimate at this time the overall exposure for congestion charges for the full term of the contract.

Connecticut Light & Power Company v. NRG Energy, Inc., Federal Energy Regulatory Commission Docket No. EL03-10-000-Station Service Dispute (filed October 9, 2002); Binding Arbitration. On July 1, 1999, Connecticut Light & Power Company, or CL&P, and the Company agreed that we would purchase certain CL&P generating facilities. The transaction closed on December 14, 1999, whereupon NRG Energy took ownership of the facilities. CL&P began billing NRG Energy for station service power and delivery services provided to the facilities and NRG Energy refused to pay asserting that the facilities self-supplied their station service needs. On October 9, 2002, Northeast Utilities Services Company, on behalf of itself and CL&P, filed a complaint at FERC seeking an order requiring NRG Energy to pay for station service and delivery services. On December 20, 2002, FERC issued an Order finding that at times when NRG Energy is not able to self-supply its station power needs, there is a sale of station power from a third-party and retail charges apply. CL&P renewed its demand for payment which was again refused by NRG Energy. In August 2003, the parties agreed to submit the dispute to binding arbitration. The parties each selected one respective arbitrator. A neutral arbitrator cannot be selected until the party-appointed arbitrators have been given a mutually agreed upon description of the dispute, which has yet to occur. Once the neutral arbitrator is selected, a decision is required within 90 days unless otherwise agreed by the parties. The potential loss inclusive of amounts paid to CL&P and accrued could exceed $6 million.

The State of New York and Erin M. Crotty, as Commissioner of the New York State Department of Environmental Conservation v. Niagara Mohawk Power Corporation et al., U.S. District Court for the Western District of New York, Civil Action No. 02-CV-002S. In January 2002, the New York State Department of Environmental Conservation, or NYSDEC, sued Niagara Mohawk Power Corporation, or NiMo, and us in federal court in New York. The complaint asserted that projects undertaken at our Huntley and Dunkirk plants by NiMo, the former owner of the facilities, required preconstruction permits pursuant to the Clean Air Act and that the failure to obtain these permits violated federal and state laws. On January 11, 2005, we reached agreement with the State of New York and the NYSDEC to settle this matter. The settlement requires the reduction of sulfur dioxide (SO₂) by over 86 percent and nitrogen oxide by over 80 percent in aggregate at the Huntley and Dunkirk plants. To do so, units 63 and 64 at Huntley will be retired after receiving the appropriate regulatory approvals. Units 65 and 66 will be retired eighteen months later. We also agreed to limits on the transfer of certain federal SO₂ allowances. We are not subject to any penalty as a result of the settlement. Through the end of the decade, we expect that our ongoing compliance with the emissions limits set out in the settlement will be achieved through capital expenditures already planned. This includes conversion to low sulfur western coal at the Huntley and Dunkirk plants that will be completed by spring 2006.

Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power, LLC, and Dunkirk Power, LLC, Supreme Court, State of New York, County of Onondaga, Case No. 2001-4372 (filed on July 13, 2001). NiMo filed suit in state court in New York seeking a declaratory judgment with respect to its obligations to indemnify us under the asset sales agreement. We asserted that NiMo is obligated to indemnify us for any related compliance costs associated with resolution of the above referenced NYSDEC enforcement action. On October 18, 2004, the parties reached a confidential settlement.

Niagara Mohawk Power Corporation v. Dunkirk Power LLC, NRG Dunkirk Operations, Inc., Huntley Power LLC, NRG Huntley Operations, Inc., Oswego Power LLC and NRG Oswego Operations, Inc., Supreme Court, Erie County, Index No. 1-2000-8681 — Station Service Dispute (filed October 2, 2000). NiMo seeks to recover damages less payments received through the date of judgment, as well as any additional amounts due and owing, for electric service provided to the Dunkirk Plant after September 18, 2000. NiMo claims that we failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999, and continuing to September 18, 2000, and thereafter. NiMo alleged breach of contract, suit on account, violation of statutory duty and unjust enrichment claims. Prior to trial, the parties entered into a Stipulation and Order filed August 9, 2002, consolidating this action with two other actions against the Huntley and Oswego subsidiaries, both of which cases assert the same claims and legal theories. On October 8, 2002, a Stipulation and Order was filed staying this action pending submission to FERC of some or all of the disputes in the action. The potential loss inclusive of amounts paid to NiMo and accrued is approximately $23.2 million.

Niagara Mohawk Power Corporation v. Huntley Power LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC, and NRG Oswego Operations, Inc., Case Filed November 26, 2002 in Federal Energy Regulatory Commission Docket No. EL 03-27-000. This is the companion action to the above referenced action filed by NiMo at FERC asserting the same claims and legal theories. On November 19, 2004, FERC denied NiMo’s petition and ruled that the Huntley, Dunkirk and Oswego plants could net their service station obligations over a 30 calendar day period from the day NRG Energy acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities because they are interconnected to transmission and not to distribution. NiMo filed a motion for rehearing, on which FERC has not ruled.

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

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

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

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


	*Additional Litigation*

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

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

Disputed Claims Reserve

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


Item 4 —	*Submission of Matters to a Vote of Security Holders*

No matters were considered during the fourth quarter of 2004.

PART II


Item 5 —	*Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities*

Market Information and Holders

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

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


									For the Period
	Fourth		Third		Second		First		December 6 -
	Quarter		Quarter		Quarter		Quarter		December 31,
Common Stock Price	2004		2004		2004		2004		2003

High	$	36.18	$	28.43	$	24.80	$	22.50	$	23.05
Low	$	26.00	$	24.10	$	19.17	$	18.10	$	18.10
Closing	$	36.05	$	26.94	$	24.80	$	22.20	$	21.90

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

Dividends

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

Recent Sale of Unregistered Securities; Repurchase of Common Stock

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

The following table summarizes the stock repurchased by NRG Energy.

Total Number of Shares

Purchased as Part of

Maximum Number of

Total Number of

Average Price

Publicly Announced

Shares that May Yet Be

Period

Shares Purchased

Paid Per Share

Plans

Purchased Under the Plans

December 27, 2004

13,000,000*

31.16

none

N/A


*	13,000,000 shares were purchased other than through a publicly announced plan. The purchase was made in a negotiated transaction.

Redemption and Repurchase of Second Priority Notes

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

Securities Authorized for Issuance Under Equity Compensation Plans

(a)

(b)

(c)

Number of Securities

Remaining Available

Number of Securities

for Future Issuance

to be Issued Upon

Weighted-Average Exercise

Under Compensation

Exercise of

Price of Outstanding

Plans (Excluding

Outstanding Options,

Options, Warrants and

Securities Reflected

Plan Category

Warrants and Rights

Rights

in Column (a))

Equity compensation plans approved by security holders

1,904,026

22.34

2,053,294*

Equity compensation plans not approved by security holders

—

n/a

—

Total

1,904,026

22.34

2,053,294*

The NRG Energy, Inc. Long-Term Incentive Plan became effective upon our emergence from bankruptcy. The Long-Term Incentive Plan, which was adopted in connection with the NRG plan of reorganization, was approved by our stockholders on August 4, 2004. 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 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 administers the Long-Term Incentive Plan. There were 2,053,294 and 3,367,249 shares of common stock remaining available for grants of stock options under our Long-Term Incentive Plan as of December 31, 2004 and 2003, respectively.


Item 6 —	*Selected Financial Data*

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.


	Reorganized NRG						Predecessor Company

	Year Ended			December 6 -			January 1 -			Year Ended December 31,
	December 31,			December 31,			December 5,
	2004			2003			2003			2002			2001		2000

	(In thousands, except per share amounts)
Revenues from majority-owned operations	$	2,361,424		$	138,490		$	1,798,387		$	1,938,293		$	2,085,350	$	1,664,980
Corporate relocation charges		16,167			—			—			—			—		—
Reorganization, restructuring and impairment charges		31,271			2,461			435,400			2,563,060			—		—
Fresh start reporting adjustments		—			—			(4,118,636	)		—			—		—
Legal settlement		—			—			462,631			—			—		—
Total operating costs and expenses		1,962,309			122,328			(1,475,523	)		4,321,385			1,703,531		1,308,589
Write downs and losses on equity method investments		(16,270	)		—			(147,124	)		(200,472	)		—		—
Income/(loss) from continuing operations		162,145			11,405			2,949,078			(2,788,452	)		210,502		149,729
Income/(loss) from discontinued operations, net		23,472			(380	)		(182,633	)		(675,830	)		54,702		33,206
Net income/(loss)		185,617			11,025			2,766,445			(3,464,282	)		265,204		182,935
Income/(loss) from continuing operations per weighted average share — basic and diluted	$	1.62		$	.11
Total assets		7,830,028			9,244,987			N/A			10,896,851			12,915,222		5,986,289
Long-term debt, including current maturities	$	3,766,118		$	4,129,011			N/A		$	7,782,648		$	6,857,055	$	3,194,340

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


	Reorganized NRG				Predecessor Company

	Year Ended		December 6 -		January 1 -		Year Ended December 31,
	December 31,		December 31,		December 5,
	2004		2003		2003		2002		2001		2000

	(In thousands)
Energy and energy-related	$	1,378,490	$	78,018	$	992,626	$	1,183,514	$	1,376,044	$	1,091,115
Capacity		612,294		39,955		565,965		553,321		490,315		405,697
Alternative energy		175,715		12,064		115,911		97,712		161,845		92,671
O & M fees		20,852		1,135		12,942		14,413		15,789		10,073
Other		174,073		7,318		110,943		89,333		41,357		65,424

Total revenues from majority-owned operations	$	2,361,424	$	138,490	$	1,798,387	$	1,938,293	$	2,085,350	$	1,664,980

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

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

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

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

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


Item 7 —	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

Overview

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

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

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

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

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

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

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

Results of Operations

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

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


		Reorganized NRG												Predecessor Company

		For the Year						For the Period						For the Period						For the Year
		Ended			Percent of			December 6-			Percent of			January 1-			Percent of			Ended			Percent of
		December 31,			Total			December 31,			Total			December 5,			Total			December 31,			Total
Segments		2004			Revenue			2003			Revenue			2003			Revenue			2002			Revenue

		(In thousands)						(In thousands)						(In thousands)						(In thousands)
Wholesale Power Generation
	Northeast	$	1,251,153			53.0	%	$	69,191			50.0	%	$	861,452			47.9	%	$	964,196			49.7	%
	South Central		418,145			17.6	%		26,609			19.2	%		356,534			19.8	%		388,023			20.0	%
	West Coast		2,469			0.1	%		(268	)		(0.2	)%		23,956			1.3	%		30,796			1.6	%
	Other North America		105,644			4.5	%		5,377			3.9	%		85,388			4.8	%		81,521			4.2	%
	Australia		181,065			7.7	%		11,947			8.6	%		151,494			8.4	%		170,761			8.8	%
All Other
	Other International		157,220			6.7	%		13,082			9.4	%		137,384			7.6	%		108,379			5.6	%
	Alternative Energy		65,872			2.8	%		3,852			2.8	%		60,871			3.4	%		69,030			3.6	%
	Non-Generation		186,425			7.9	%		9,860			7.1	%		129,063			7.2	%		135,403			7.0	%
	Other		(6,569	)		(0.3	)%		(1,160	)		(0.8	)%		(7,755	)		(0.4	)%		(9,816	)		(0.5	)%

Total Revenue		$	2,361,424			100.0	%	$	138,490			100.0	%	$	1,798,387			100.0	%	$	1,938,293			100.0	%

The following table provides operating income by segment for the year ended December 31, 2004.


				South		West			Other North
		Northeast		Central		Coast			America			Australia			All Other			Total

		(In thousands)
Energy revenue		$	853,454	$	219,112	$	9,276		$	27,816		$	159,381		$	109,451		$	1,378,490
Capacity revenue			264,624		183,483		(3,709	)		84,097			—			83,799			612,294
Alternative revenue			49		—		—			1,748			—			173,918			175,715
O & M fees			—		—		(2	)		186			—			20,668			20,852
Other revenue			133,026		15,550		(3,096	)		(8,203	)		21,684			15,112			174,073

Operating revenues			1,251,153		418,145		2,469			105,644			181,065			402,948			2,361,424

Operating expenses			859,769		294,215		10,842			57,686			161,960			321,104			1,705,576
Depreciation and amortization			72,665		62,458		800			21,842			24,027			27,503			209,295
Corporate relocation charges			11		1		—			—			—			16,155			16,167
Reorganization items			180		976		—			142			—			(14,688	)		(13,390	)
Restructuring and impairment charges			247		2,909		—			26,505			—			15,000			44,661

	Operating income/(loss)	$	318,281	$	57,586	$	(9,173	)	$	(531	)	$	(4,922	)	$	37,874		$	399,115


	*For the Year Ended December 31, 2004 Compared to the Year Ended December 31, 2003*


	Net Income/(Loss)


	*Reorganized NRG*

For the year ended December 31, 2004, we recorded net income of $185.6 million, or $1.85 per weighted average share of diluted common stock. These favorable results occurred despite a challenging market environment in 2004. Unseasonably mild weather, high volatility on forward markets and disappointing spot power prices summarize 2004’s events. The year started with colder than normal weather arriving in January but unseasonably mild weather characterized the period from March thru December which dampened energy prices in North America. The National Oceanic Atmospheric Agency, or NOAA, has ranked the mean average temperatures over the past 110 years by season for each of the lower 48 states. The year 2004 started

with the winter being colder than normal in the east coast followed by a spring, summer and fall which were among the mildest in the last 110 years throughout most of the United States. Although mild weather in the North America market kept spot market on-peak power prices low throughout most of the year, relatively high gas and oil prices kept spark spreads on coal-based assets positive.

The overall perception that there would be significant production losses due to Hurricane Ivan ignited a strong pre-heating season rally in natural gas futures during the early fourth quarter. While power prices tracked changes in natural gas prices, this movement was not one for one. As a result, our spark spreads on coal-based generation increased dramatically with the fall 2004 changes in gas prices. During this period we sold forward 2005 power locking in these spark spreads. Forward power prices have fallen considerably from the highs set in October, and many of those forward sales, which were marked-to-market through earnings, significantly contributed to the $57.3 million unrealized gain recorded in revenue for the year ended December 31, 2004 and as more fully described in Note 16 to the financial statements.

As indicated above, our 2004 results were favorably impacted by the cold weather in January. Additionally, the Northeast’s income results for the year were positively impacted by the $57.3 million of unrealized gains associated with forward sale transactions supporting our Northeast assets. The majority of the unrealized gains relate to forward sales of electricity which will be realized in 2005. These gains were offset by our South Central region’s results, which were negatively impacted by an unplanned outage in the fourth quarter forcing us to purchase power to meet our contract supply obligations. Impairment charges of $44.7 million negatively impacted net income; of which $26.5 million relates to the Kendall asset. Our results were also favorably impacted by the FERC-approved settlement agreement between NRG Energy and Connecticut Light & Power, or CL&P, and others concerning the congestion and losses obligation associated with a prior standard offer service contract, whereby we received $38.4 million in settlement proceeds in July 2004. The 2004 results were also positively impacted by $159.8 million in equity earnings of unconsolidated affiliates including $68.9 million from our interest in West Coast Power which benefited from warmer than normal temperatures during the year.

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 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.


	*Predecessor Company*

statement of operations. In addition to our 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 costs 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 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.


	Revenues from Majority-Owned Operations


	*Reorganized NRG*

Our revenues from majority-owned operations were $2.4 billion for the year ended December 31, 2004 which included $1.4 billion of energy revenues, $612.3 million of capacity revenues, $175.7 million of alternative energy revenues, $20.8 million of O&M fees and $174.1 million of other revenues, which include $57.3 million of unrealized gains associated with financial sales transactions of electricity, which are marked to market, $22.4 million from ancillary service revenues and the remainder related to financial and physical gas sales and non-cash contract amortization resulting from fresh start accounting and other miscellaneous revenue items.

Revenues from majority-owned operations for the year ended December 31, 2004, were driven primarily by our North American operations, primarily our Northeast facilities. Our wholly-owned domestic Northeast power generation operations significantly contributed to our energy revenues. Our wholly-owned North America assets generated approximately 29.0 million megawatt hours during the year 2004 with the Northeast region representing 45.6% of these megawatt hours. Of the total $1.4 billion in energy revenues, the Northeast region represented 62%. Our energy revenues were favorably impacted by the FERC-approved settlement agreement between us and CL&P and others, whereby we received $38.4 million in settlement proceeds in July 2004. These settlement proceeds are included in the All Other segment in the energy revenue category. South Central’s energy revenues are driven by our ability to sell merchant energy, which is dependent upon available generation from our coal-based Louisiana Generating company after serving our co-op customer and long-term customer load obligations. Since our load obligation is primarily residential load, our merchant opportunities are largely available in the off-peak hours of the day. Our Australian operations were favorably impacted by strong market prices driven by gas restrictions in January, record high temperatures in February and March, and favorable foreign exchange movements. Our capacity revenues are largely driven by our Northeast and South Central facilities. Our South Central and New York City assets earned 30% and 26% of our total capacity revenues, respectively. In the Northeast, our Connecticut facilities continue to benefit from the cost-based reliability must-run, or RMR agreements, which were authorized by FERC as of January 17, 2004 and approved by FERC on January 27, 2005. The agreements entitle us to approximately $7.1 million of capacity revenues per month until January 1, 2006, the LICAP implementation date. In the South Central region, our long-term contracts provide for capacity payments. Other North American capacity revenues were generated by our Kendall operation, which had a long-term tolling agreement. During this period we also experienced a favorable impact on our revenues due to the mark-to-market on certain of our derivative contracts wherein we have recognized $57.3 million in unrealized gains. This gain is related to our Northeast assets and is included in Other Revenue. Also included in Other Revenue in the Northeast are the cost reimbursement funds under the RMR agreement for our Connecticut assets. Our revenues during this period include net charges of $35.3 million of non-cash amortization of the fair values of various executory contracts recorded on our balance sheet upon our adoption of the Fresh Start provisions of SOP 90-7 in December 2003.

Our revenues from majority-owned operations were $138.5 million for the period December 6, 2003 through December 31, 2003.


	*Predecessor Company*

Revenues from majority-owned operations were $1.8 billion for the period January 1, 2003 through December 5, 2003 and include $992.6 million of energy revenues, $566.0 million of capacity revenues, $115.9 million of alternative energy, $12.9 million of O&M fees and $110.9 million of other revenues which include financial and physical gas sales, sales from our Schkopau facility and NEPOOL expense reimbursements. Revenues from majority-owned operations during the period ended December 5, 2003, were driven primarily by our North American operations and to a lesser degree by our international operations, primarily Australia. Our domestic Northeast and South Central power generation operations significantly contributed to our revenues due primarily to favorable market prices resulting from strong fuel and electricity prices. Our Australian operations were favorably impacted by foreign exchange rates. During this period we also experienced an unfavorable impact on our revenues due to continued losses on our CL&P standard offer contract and the mark-to-market on certain of our derivatives.


	Cost of Majority-Owned Operations


	*Reorganized NRG*

Our cost of majority-owned operations for the year ended December 31, 2004 was $1.5 billion or 63.3% of revenues from majority-owned operations. Cost of majority-owned operations consist of $1.008 billion of cost of energy (primarily fuel and purchased energy costs), or 42.7% of revenues from majority-owned operations and $486.1 million of operating expenses, or 20.6% of revenues from majority-owned operations. Operating expenses consist of $208.5 million of labor related costs, $236.7 million of operating and maintenance costs, $38.2 million of non-income based taxes and $2.9 million of asset retirement obligation accretion.


	Cost of Energy

Fuel related costs include $478.3 million in coal costs, $233.0 million in natural gas costs, $104.7 million in fuel oil costs, $38.8 million in transmission and transportation expenses, $100.4 million of purchased energy costs, $35.0 million in other costs and $17.8 million in non-cash SO₂ emission credit amortization resulting from Fresh Start accounting. The Northeast region consumed 50%, 64% and 92% of total coal, natural gas and oil expenditures, respectively. The South Central region, which is comprised mainly of our Louisiana base-loaded coal plant, consumed 32% of our total coal expenditures.


	Operating Expenses

Operating expenses related to continuing operations for the year ended December 31, 2004 were $486.1 million or 20.6% of revenues from majority-owned operations. Operating expenses include labor, normal and major maintenance costs, environmental and safety costs, utilities costs, and non-income based taxes. Labor costs include regular, overtime and contract costs at our plants and totaled $208.5 million. The Northeast region, where the majority of our assets reside, represents 52% of total labor costs; Australia represents 18%, while our South Central region represents 11%. Of the total O&M costs, normal and major maintenance at our plants accounted for $176.7 million, or 36.3% of total operating costs. Maintenance costs were largely driven by planned outages across our fleet, and the low-sulfur coal conversion in western New York. The Northeast region represented over half of the normal and major maintenance, with a total of $98.6 million in costs in 2004 while Australia had $38.8 million in normal and major maintenance, or 22%. Operating expenses were positively impacted by a $7 million favorable settlement with a vendor regarding auxiliary power charges. Non-income based taxes totaled $38.2 million net of $34.6 million in property tax credits, primarily associated with an enterprise zone program.

Cost of majority-owned operations was $95.5 million, or 69.0% of revenues from majority-owned operations for the period December 6, 2003 through December 31, 2003. Cost of energy for this period was $62.3 million or 45.0% of revenues from majority-owned operations and operating expenses were $33.2 million, or 24.0% of revenues from majority-owned operations. Labor during this period totaled $11.1 million. Normal and major maintenance was $12 million with 70% of the total normal and major maintenance for this time period coming from our Northeast region.


	*Predecessor Company*

Cost of majority-owned operations was $1.4 billion, or 75.4% of revenues from majority-owned operations for the period January 1, 2003 through December 5, 2003. Cost of majority-owned operations was unfavorably impacted by increased generation in the Northeast region, partially offset by a reduction in trading and hedging activity resulting from a reduction in our power marketing activities. Our international operations were impacted by an unfavorable movement in foreign exchange rates and continued mark-to-market of the Osborne contract at Flinders resulting from lower pool prices.


	Depreciation and Amortization


	*Reorganized NRG*

Our depreciation and amortization expense related to continuing operations for the year ended December 31, 2004 was $209.3 million. Depreciation and amortization consists primarily of the allocation of our historical depreciable fixed asset costs over the remaining lives of such property. Upon adoption of Fresh Start, we were required to revalue our fixed assets to fair value and determine new remaining lives for such assets. Our fixed assets were written down substantially upon our emergence from bankruptcy. We also determined new remaining depreciable lives, which are, on average, shorter than what we had previously used primarily due to the age and condition of our fixed assets.

Depreciation and amortization expense for the period December 6, 2003 through December 31, 2003 was $11.8 million. Depreciation and amortization expense consists of the allocation of our newly valued basis in our fixed assets over newly determined remaining fixed asset lives.


	*Predecessor Company*

Our depreciation and amortization expense related to continuing operations for the period January 1, 2003 through December 5, 2003 was $218.8 million. During this period, depreciation expense was unfavorably impacted by the shortening of the depreciable lives of certain of our domestic power generation facilities located in the Northeast region and the impact of recently completed construction projects. The depreciable lives of certain of our Northeast facilities, primarily our Connecticut facilities, were shortened to reflect economic developments in that region. Certain capitalized development costs were written-off in connection with the Loy Yang project resulting in increased expense. Amortization expense increased due to reducing the life of certain software costs.


	General, Administrative and Development


	*Reorganized NRG*

Our general, administrative and development costs related to continuing operations for the year ended December 31, 2004 were $211.2 million. Of this total, $111.1 million or 4.7% of revenues from majority-owned operations represents our corporate costs, with the remaining $100.1 million representing costs at our plant operations. Corporate costs are primarily comprised of corporate labor, external professional support, such as legal, accounting and audit fees, and office expenses. Corporate general, administrative and development expenses were negatively impacted this year by increased legal fees, increased audit costs and increased consulting costs due to our Sarbanes Oxley testing and implementation. Plant general, administrative and development costs primarily include insurance and external consulting costs. Plant insurance costs were $40.6 million. Additionally, we recorded $11.7 million in bad debt expense related to notes receivable.

General, administrative and development costs were $12.5 million, or 9.0% of revenues from continuing operations for the period December 6, 2003 to December 31, 2003. These costs are primarily comprised of corporate labor, insurance and external professional support, such as legal, accounting and audit fees.


	*Predecessor Company*

Our general, administrative and development costs related to continuing operations for the period January 1, 2003 to December 5, 2003 were $170.3 million or 9.5% of revenues from majority-owned operations. These costs are primarily comprised of corporate labor, insurance and external professional support, such as legal, accounting and audit fees.


	Other Charges (Credits)


	*Reorganized NRG*

For the year ended December 31, 2004, we recorded other charges of $47.4 million, which consisted of $16.2 million of corporate relocation charges, $13.4 million of reorganization credits and $44.6 million of restructuring and impairment charges.

For the period December 6, 2003 through December 31, 2003 we recorded $2.5 million of reorganization charges.


	*Predecessor Company*

Other charges (credits) consist of the following:


		Reorganized NRG					Predecessor Company

					For the Period		For the Period
		Year Ended			December 6 -		January 1 -
		December 31,			December 31,		December 5,
		2004			2003		2003

		(In thousands)
Corporate relocation charges		$	16,167		$	—	$	—
Reorganization items			(13,390	)		2,461		197,825
Impairment charges			44,661			—		228,896
Restructuring charges			—			—		8,679
Fresh Start adjustments			—			—		(4,118,636	)
Legal settlement			—			—		462,631

	Total	$	47,438		$	2,461	$	(3,220,605	)


	Corporate Relocation Charges

On March 16, 2004, we announced plans to implement a new regional business strategy and structure. The new structure called for a reorganized leadership team and a corporate headquarters relocation to Princeton, New Jersey. The corporate headquarters staff were streamlined as part of the relocation, as functions were either reduced or shifted to the regions. The transition of the corporate headquarters is substantially complete. During the year ended December 31, 2004, we recorded $16.2 million for charges related to our corporate relocation activities, primarily for employee severance and termination benefits and employee related transition costs. These charges are classified separately in our statement of operations, in accordance with SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities”. We expect to incur an additional $7.7 million of SFAS No. 146-classified expenses in connection with corporate relocation charges for a total of $23.9 million. Of this total, relocating, recruiting and other employee-related transition costs are expected to be approximately $11.9 million and have been and will continue to be expensed as incurred. These costs and cash payments are expected to be incurred through the second quarter of 2005. Severance and termination benefits of $7.2 million are expected to be incurred through the second quarter of

2005 with cash payments being made through the fourth quarter of 2005. Building lease termination costs are expected to be $4.8 million. These costs are expected to be incurred through the first quarter of 2005 with cash payments being made through the fourth quarter of 2006. Costs not classified separately as relocation charges include rent expense of our temporary office in Princeton, construction costs of our new office and certain labor costs. All costs relating to the corporate relocation that are not classified separately as relocation charges, except for approximately $5.7 million of related capital expenditures will be expensed as incurred and included in general, administrative and development expenses. Cash expenditures for 2004, including capital expenditures, were $22.4 million. We currently estimate total costs associated with the corporate relocation to be approximately $40.0 million.

We recognized a curtailment gain of $750,000 on our defined benefit pension plan in the fourth quarter of 2004, as a substantial number of our current headquarters staff left the Company in this period.


	Reorganization Items

For the year ended December 31, 2004, we recorded a net credit of $13.4 million related primarily to the settlement of obligations recorded under Fresh Start. We incurred $7.4 million of professional fees associated with the bankruptcy which offset $20.8 million of credits associated with creditor settlements. For the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, we incurred $2.5 million and $197.8 million, respectively, 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.


							Predecessor
		Reorganized NRG					Company

					For the period		For the period
		Year Ended			December 6 -		January 1 -
		December 31,			December 31,		December 5,
		2004			2003		2003

		(In thousands)
Reorganization items
	Professional fees	$	7,383		$	2,461	$	82,186
	Deferred financing costs		—			—		55,374
	Pre-payment settlement		—			—		19,609
	Interest earned on accumulated cash		—			—		(1,059	)
	Contingent equity obligation		—			—		41,715
	Settlement of obligations		(20,773	)		—		—

	Total reorganization items	$	(13,390	)	$	2,461	$	197,825


	Impairment Charges

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 $44.7 million and $228.9 million for the year ended December 31, 2004 and the period January 1, 2003 through December 5, 2003, respectively, as shown in the table below. Of the $44.7 million total in 2004, Kendall and the Meriden turbine accounted for $26.5 million and $15.0 million, respectively. Both of these charges were based on indicative market valuations. We successfully completed the sale of Kendall in November 2004 and expect to complete the sale of the Meriden turbine in the first quarter of 2005. There were no impairment charges for the period December 6, 2003 through December 31, 2003.

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.

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 asset impairments (realized gains) for the year ended December 31, 2004 and the period January 1, 2003 to December 5, 2003.

Predecessor

Reorganized

Company

NRG

For the Period

Year Ended

January 1 -

December 31,

December 5,

Basis of Impairment

Project Name

Project Status

2004

2003

Charge

(In thousands)

Louisiana Generating LLC

Office building and land being marketed

493

—

Estimated market price

New Roads Holding LLC (turbine)

Non-operating asset — abandoned

2,416

—

Projected cash flows

Devon Power LLC

Operating at a loss in 2003

247

64,198

Projected cash flows

Middletown Power LLC

Operating at a loss

—

157,323

Projected cash flows

Arthur Kill Power, LLC

Terminated construction project

—

9,049

Projected cash flows

Langage (UK)

Terminated

—

(3,091

)

Estimated market price

Turbines

Sold

—

(21,910

)

Realized gain

Berrians Project

Terminated

—

14,310

Realized loss

TermoRio

Terminated

—

6,400

Realized loss

Meriden

Sold

15,000

—

Similar asset prices

Kendall and other expansion projects

Sold

26,505

—

Projected cash flows, sales contracts

Other

—

2,617

Total impairment charges

44,661

228,896


	Restructuring Charges


	Fresh Start Adjustments

During the fourth quarter of 2003, we recorded a net credit of $3.9 billion (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations) in connection with fresh start adjustments. Following is a summary of the significant effects of the reorganization and Fresh Start:


		(In millions)

Discharge of corporate level debt		$	5,162
Discharge of other liabilities			811
Establishment of creditor pool			(1,040	)
Receivable from Xcel			640
Revaluation of fixed assets			(1,392	)
Revaluation of equity investments			(207	)
Valuation of SO ₂emission credits			374
Valuation of out of market contracts, net			(400	)
Fair market valuation of debt			108
Valuation of pension liabilities			(61	)
Other valuation adjustments			(100	)

Total Fresh Start adjustments			3,895
	Less discontinued operations		(224	)

Total Fresh Start adjustments — continuing operations		$	4,119


	Legal Settlement Charges

During the period January 1, 2003 to December 5, 2003, we recorded $462.6 million of legal settlement charges which consisted of the following. We recorded $396.0 million in connection with the resolution of an arbitration claim asserted by FirstEnergy Corp. 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 NRG Energy’s Plan of Reorganization. In November 2003, we settled litigation with Fortistar Capital in which Fortistar Capital released us from all litigation claims in exchange for a $60.0 million pre-petition bankruptcy claim and an $8.0 million post-petition bankruptcy 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 November 2003, we settled our dispute with Dick Corporation in connection with Meriden Gas Turbines LLC through the payment of a general unsecured claim and a post-petition pre-confirmation payment. This settlement resulted in our recording an additional liability of $8.0 million in November 2003.

In August 1995, we entered into a Marketing, Development and Joint Proposing Agreement, or the Marketing Agreement, with Cambrian Energy Development LLC, or Cambrian. Various claims arose in connection with the 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 paid 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.


	Other Income (Expense)


	*Reorganized NRG*

During the year ended December 31, 2004, we recorded other expense of $171.9 million. Other expense consisted primarily of $269.4 million of interest expense, $71.6 million of refinancing-related expenses, $1.0 million of minority interest in earnings of consolidated subsidiaries and $16.3 million of write downs and losses on sales of equity method investments, offset by $159.8 million of equity in earnings of unconsolidated affiliates (including $68.9 million from our investment in West Coast Power LLC) and $26.6 million of other income, net.

Other income (expense) for the period December 6, 2003 through December 31, 2003, was an expense of $5.4 million and consisted primarily of $18.9 million of interest expense, partially offset by $13.5 million of equity in earnings of unconsolidated affiliates.


	*Predecessor Company*

During the period January 1, 2003 through December 5, 2003, we recorded other expense of $286.9 million. Other expense consisted primarily of $329.9 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 $19.2 million of other income, net.


	Minority Interest in Earnings of Consolidated Subsidiaries

For the year ended December 31, 2004, minority interest in earnings of consolidated subsidiaries was $1.0 million which relates primarily to our ownership interests in Northbrook Energy, LLC and Northbrook New York, LLC, partnerships which hold a portfolio of small hydro projects. For the period December 6, 2003 through December 31, 2003, minority interest in earnings of consolidated subsidiaries was $134,000 and relates primarily to Northbrook New York and Northbrook Energy.


	Equity in Earnings of Unconsolidated Affiliates


	*Reorganized NRG*

For the year ended December 31, 2004, we recorded $159.8 million of equity earnings from our investments in unconsolidated affiliates. Our equity in earnings of West Coast Power comprised $68.9 million of this amount with our equity in earnings of Enfield, Mibrag, and Gladstone comprising $28.5 million, $20.9 million, and $17.5 million, respectively. Our investment in West Coast Power generated favorable results due to the pricing under the California Department of Water Resources contract. Additionally, revenues from ancillary services revenue and minimum load cost compensation power positively contributed to West Coast Power’s operating results. However, our equity earnings in the project as reported in our results of operations have been reduced by a net $115.8 million to reflect a non-cash basis adjustment for in the money contracts resulting from adoption of Fresh Start.

NRG Energy’s equity earnings were also favorably impacted by $23.3 million of unrealized gain related to our Enfield investment. This gain is associated with changes in the fair value of energy-related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

Equity in earnings of unconsolidated affiliates of $13.5 million for the period December 6, 2003 through December 31, 2003 consists primarily of equity earnings from our 50% ownership in West Coast Power of $9.4 million.


	*Predecessor Company*

Equity in earnings of unconsolidated affiliates consists of the following:


		Reorganized NRG						Predecessor Company

		Year Ended			December 6, 2003			January 1, 2003			Year Ended
		December 31,			Through			Through			December 31,
		2004			December 31, 2003			December 5, 2003			2002

		(In thousands)
West Coast Power		$	68,895		$	9,362		$	98,741		$	19,044
MIBRAG			20,938			102			21,818			28,750
Enfield			28,505			481			5,975			(6,017	)
Gladstone			17,528			997			12,440			7,237
Rocky Road			6,904			305			6,864			6,868
James River			7,750			543			(1,893	)		9,713
NRG Saguaro			5,480			617			3,940			4,968
Scudder LA Trust			1,521			150			2,653			1,043
NRG National			846			190			2,010			1,695
MWPC — RDF			200			8			123			259
NRG Cadillac			(421	)		(2	)		280			195
Central and Eastern European Energy Power Fund			(47	)		(22	)		(260	)		(331	)
Loy Yang			—			—			17,924			8,443
Other			1,726			790			286			(12,871	)

	Total Equity in Earnings of Unconsolidated Affiliates	$	159,825		$	13,521		$	170,901		$	68,996


	Write Downs and Losses on Sales of Equity Method Investments

As part of our periodic review of our equity method investments for impairments, we have taken write downs and losses on sales of equity method investments during the year ended December 31, 2004 of $16.3 million and $147.1 million for the period January 1, 2003 through December 5, 2003. Our Commonwealth Atlantic Limited Partnership (CALP) and James River investments were written down based on indicative market bids. The sale of CALP closed in the fourth quarter of 2004, while the sale agreement for James River has been terminated. There were no write downs and losses on sales of equity method investments for the period December 6, 2003 through December 31, 2003.

Write downs and losses (gains) on sales of equity method investments recorded in the consolidated statement of operations include the following:


	Reorganized			Predecessor
	NRG			Company

				For the Period
	Year Ended			January 1 -
	December 31,			December 5,
	2004			2003

	(In thousands)
Commonwealth Atlantic Limited Partnership	$	4,614		$	—
James River Power LLC		7,293			—
NEO Corporation		3,830			—
Calpine Cogeneration		(735	)		—
NLGI — Minnesota Methane		—			12,257
NLGI — MM Biogas		—			2,613
Kondapalli		—			(519	)
ECKG		—			(2,871	)
Loy Yang		1,268			146,354
Mustang		—			(12,124	)
Other		—			1,414

Total write downs and losses of equity method investments	$	16,270		$	147,124

Commonwealth Atlantic Limited Partnership (CALP) — In June 2004, we executed an agreement to sell our 50% interest in CALP. During the third quarter of 2004, we recorded an impairment charge of approximately $3.7 million to write down the value of our investment in CALP to its fair value. The sale closed in November 2004, resulting in net cash proceeds of $14.9 million. Total impairment charges as a result of the sale were $4.6 million.

James River Power LLC — In September 2004, we executed an agreement with Colonial Power Company LLC to sell all of our outstanding shares of stock in Capistrano Cogeneration Company, a wholly-owned subsidiary of NRG Energy which owns a 50% interest in James River Cogeneration Company. During the third quarter of 2004, we recorded an impairment charge of approximately $6.0 million to write down the value of our investment in James River to its fair value. During the fourth quarter of 2004, the sale agreement was terminated. We continue to impair any additional equity earnings based on its fair value. Total impairment charges for 2004 were $7.3 million.

NEO Corporation — On September 30, 2004, we completed the sale of several NEO investments — Four Hills LLC, Minnesota Methane II LLC, NEO Montauk Genco LLC and NEO Montauk Gasco LLC to Algonquin Power of Canada. The sale also included four wholly-owned NEO subsidiaries (see Item 15 — Note 6). We received cash proceeds of $6.1 million. The sale resulted in a loss of approximately $3.8 million attributable to the equity investment entities sold.

Calpine Cogeneration — In January 2004, we executed an agreement to sell our 20% interest in Calpine Cogeneration Corporation to Calpine Power Company. The transaction closed in March 2004 and resulted in net cash proceeds of $2.5 million and a net gain of $0.2 million. During the second quarter of 2004, we received additional consideration on the sale of $0.5 million, resulting in an adjusted net gain of $0.7 million.

NLGI — 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, resulting in a net impairment

charge of $12.3 million for the period January 1, 2003 to December 5, 2003. This gain resulted from the release of certain obligations.

NLGI — 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 a 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, resulting in a net gain of $0.5 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, resulting in a net gain of $2.9 million.

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. This write-down reflected management’s belief that the decline in fair value of the investment was other than temporary. 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. Consequently, we recorded an additional impairment charge of approximately $146.4 million during 2003. In April 2004, we completed the sale of Loy Yang which resulted in net cash proceeds of $26.7 million and a loss of $1.3 million.

Mustang Station — On July 7, 2003, we completed the sale of our 25% 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.


	Other Income, net


	*Reorganized NRG*

During the year ended December 31, 2004, we recorded $26.6 million of other income, net, consisting primarily of interest income earned on notes receivable and cash balances. For the period December 6, 2003 through December 31, 2003 we recorded other income of $97,000.


	*Predecessor Company*

During the period January 1, 2003 through December 5, 2003, we recorded $19.2 million of other income, net. During this period other income, net consisted primarily of interest income earned on notes receivable and cash balances, offset in part by the unfavorable mark-to-market on our corporate level £160 million note that was cancelled in connection with our bankruptcy proceedings.


	Interest Expense


	*Reorganized NRG*

Interest expense for the year ended December 31, 2004 was $269.4 million, consisting of interest expense on both our project- and corporate-level interest-bearing debt. Significant amounts of our corporate-level debt were forgiven upon our emergence from bankruptcy and we refinanced significant amounts of our project-level debt with corporate level high yield notes and term loans in December 2003. Also included in interest expense is the amortization of debt financing costs of $9.2 million related to our corporate level debt and $13.3 million of amortization expense related primarily to debt discounts and premiums recorded as part of Fresh Start. Interest expense also includes the impact of any interest rate swaps that we have entered in order to manage our exposure to changes in interest rates.

Interest expense for the period December 6, 2003 through December 31, 2003 of $18.9 million consists primarily of interest expense at the corporate level, primarily related to the Second Priority 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.


	*Predecessor Company*

Interest expense for the period January 1, 2003 through December 5, 2003 of $329.9 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. Interest expense during this period was favorably impacted by our ceasing to record interest expense on debt where it was probable that such interest would not be paid, such as the NRG Energy corporate level debt (primarily bonds) and the NRG Finance Company debt (construction revolver) due to our entering into bankruptcy in May 2003. 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. Interest expense was unfavorably impacted by an adverse mark-to-market on certain interest rate swaps that we have entered in order to manage our exposure to changes in interest rates. Due to our deteriorating financial condition during such period, hedge accounting treatment was ceased for certain of our interest rate swaps, causing changes in fair value to be recorded as interest expense.


	Refinancing Expense

Refinancing expense was $71.6 million for the year ended December 31, 2004. This amount includes $15.1 million of prepayment penalties and a $15.3 million write-off of deferred financing costs related to refinancing certain amounts of our term loans with additional corporate level high yield notes in January 2004 and $13.8 million of prepayment penalties and a $26.8 million write-off of deferred financing costs related to refinancing the senior credit facility in December 2004.


	Income Tax Expense


	*Reorganized NRG*

Our income tax provision from continuing operations was $65.1 million for the year ended December 31, 2004 and an income tax benefit of ($0.7) million for the period December 6, 2003 through December 31, 2003. The overall effective tax rate in 2004 and the short period in 2003 was 28.7% and (6.2%), respectively.

The change in our effective tax rate was primarily due to a state tax refund received from Xcel Energy in 2003 and foreign income taxed in jurisdictions with tax rates different from the U.S. statutory rate.

Our net deferred tax assets at December 31, 2004 were offset by a full valuation allowance in accordance with SFAS No. 109. Under SOP 90-7, any future benefits from reducing a valuation allowance from preconfirmation deferred tax assets are required to be reported first as an adjustment of identifiable intangible assets and then as a direct addition to paid in capital versus a benefit on our statement of operations.

The effective tax rate may vary from year to year depending on, among other factors, the geographic and business mix of earnings and losses. These same and other factors, including history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.


	*Predecessor Company*

Income tax expense for the period January 1, 2003 through December 5, 2003 was $37.9 million. The overall effective tax rate for the period ended December 5, 2003 was 1.3%. The rate is lower than the U.S. statutory rate primarily due to a release in valuation allowance for net operating loss carryforwards that were utilized following our emergence from bankruptcy to offset the current tax on cancellation of debt income.

Income taxes have been recorded on the basis that our U.S. subsidiaries and we would file separate federal income tax returns for the period January 1, 2003 through December 5, 2003. Since our U.S. subsidiaries and we were not 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 filed 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 From Discontinued Operations, net of Income Taxes


	*Reorganized NRG*

We classified as discontinued operations the operations and gains/losses recognized on the sale of projects that were sold or were deemed to have met the required criteria for such classification pending final disposition. During the year ended December 31, 2004, we recorded income from discontinued operations, net of income taxes, of $23.5 million. During the year ended December 31, 2004 and for the period December 6, 2003 to December 31, 2003, discontinued operations consisted of the results of our NRG McClain LLC, Penobscot Energy Recovery Company, or PERC, Compania Boliviana De Energia Electrica S.A. Bolivian Power Company Limited, or Cobee, Hsin Yu, LSP Energy (Batesville) and four NEO Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha LLC and NEO Tajiguas LLC). All other discontinued operations were disposed of in prior periods. The $23.5 million income from discontinued operations includes a gain of $22.4 million, net of income taxes of $7.9 million, related primarily to the dispositions of Batesville, Cobee and Hsin Yu.

Discontinued operations for the period December 6, 2003 through December 31, 2003 is comprised of a loss of $0.4 million attributable to the on going operations of our McClain, PERC, Cobee, LSP Energy, Hsin Yu and four NEO Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha LLC and NEO Tajiguas LLC).


	*Predecessor Company*

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, PERC, Cobee, NEO Landfill Gas, Inc., or NLGI, seven NEO Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha LLC, NEO Tajiguas LLC, NEO Ft. Smith LLC, NEO

Woodville LLC and NEO Phoenix LLC), Timber Energy Resources, Inc., or TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu projects.

For the period January 1, 2003 through December 5, 2003, the results of operations related to such discontinued operations was a net loss of $182.6 million due to a loss on the sale of our Peru projects, impairment charges of $100.7 million and $23.6 million, respectively, recorded at McClain and NLGI and fresh start adjustments at LSP Energy.


	*For the Year Ended December 31, 2003 Compared to the Year Ended December 31, 2002*


	Net Income


	*Reorganized NRG*

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.


	*Predecessor Company*

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 pre-petition obligations from our balance sheet. Accordingly, as part of net income, we recorded a net gain of $3.9 billion (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations) 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 $1.6 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 costs 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 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 $2.6 billion of other charges consisting primarily of asset impairments.


	Revenues from Majority-Owned Operations


	*Reorganized NRG*

Our operating revenues from majority-owned operations were $138.5 million for the period December 6, 2003 through December 31, 2003.


	*Predecessor Company*

Revenues from majority-owned operations were $1.8 billion for the period January 1, 2003 through December 5, 2003 and include $992.6 million of energy revenues, $566.0 million of capacity revenues, $115.9 million of alternative energy, $12.9 million of O&M fees and $110.9 million of other revenues which include financial and physical gas sales, sales from our Schkopau facility and NEPOOL expense reimbursements. Revenues from majority-owned operations during the period year ended December 5, 2003, were driven primarily by our North American operations and to a lesser degree by our international operations, primarily Australia. Our domestic Northeast and South Central power generation operations significantly contributed to our revenues due primarily to favorable market prices resulting from strong fuel and electricity prices. Our Australian operations were favorably impacted by favorable foreign exchange rates. During this period we also experienced an unfavorable impact on our revenues due to continued losses on our CL&P standard offer contract and the mark-to-market on certain of our derivatives.

Revenues from majority-owned operations were $1.9 billion for the year ended December 31, 2002.


	Cost of Majority-Owned Operations


	*Reorganized NRG*

Our cost of majority-owned operations for the period December 6, 2003 through December 31, 2003 was $95.5 million or 69.0% of revenues from majority-owned operations.


	*Predecessor Company*

Cost of majority-owned operations was $1.4 billion, or 75.4% of revenues from majority-owned operations for the period January 1, 2003 through December 5, 2003. Cost of majority-owned operations was unfavorably impacted by increased generation in the Northeast region, partially offset by a reduction in trading and hedging activity resulting from a reduction in our power marketing activities. Our international operations were unfavorably impacted due to an unfavorable movement in foreign exchange rates and continued mark-to-market of the Osborne contract at Flinders resulting from lower pool prices.

Our cost of majority-owned operations related to continuing operations was $1.3 billion for 2002, or 68.7% of revenues from majority-owned operations. 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. Cost of energy for the year ended December 31, 2002 was $900.9 million or 46.5% of revenue from majority-owned operations.


	Depreciation and Amortization


	*Reorganized NRG*

Our depreciation and amortization expense related to continuing operations was $11.8 million for the period December 6, 2003 through December 31, 2003. Depreciation and amortization expense 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.


	*Predecessor Company*

Our depreciation and amortization expense related to continuing operations was $218.8 million for the period January 1, 2003 through December 5, 2003 and $207.0 million for the year ended December 31, 2002. During the period January 1, 2003 to December 5, 2003, depreciation expense was unfavorably impacted by the shortening of the depreciable lives of certain of our domestic power generation facilities located in the Northeast region and the impact of completed construction projects. 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.


	General, Administrative and Development


	*Reorganized NRG*

Our general, administrative and development costs for the period December 6, 2003 through December 31, 2003 was $12.5 million or 9.0% of revenues from majority-owned operations. These costs are primarily comprised of corporate labor, insurance and external professional support, such as legal, accounting and audit fees.


	*Predecessor Company*

Our general, administrative and development costs for the period January 1, 2003 through December 5, 2003 were $170.3 million, or 9.5% of revenues from majority-owned operations. Our general, administrative and development costs for 2002 were $218.9 million, or 11.3% of revenues from majority-owned operations. General, administrative and development costs for the period January 1, 2003 through December 5, 2003 were favorably impacted by 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.


	Other Charges (Credits)


	*Reorganized NRG*

During the period December 6, 2003 through December 31, 2003 we recorded $2.5 million of other charges related to reorganization items.


	*Predecessor Company*

During the period January 1, 2003 to December 5, 2003, we recorded other credits of $3.2 billion, which consisted primarily of $228.9 million related to asset impairments, $462.6 million related to legal settlements, $197.8 million related to reorganization charges and $8.7 million related to restructuring charges. We also incurred a $4.1 billion credit related to Fresh Start adjustments. During 2002, we recorded other charges of $2.6 billion, which consisted primarily of $2.5 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.

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 period January 1, 2003 to December 5, 2003 and the year ended December 31, 2002. There were no impairment charges for the period December 6, 2003 through December 31, 2003.


		Predecessor Company

		For the Period
		January 1 -			Year Ended
		December 5,			December 31,
Project Name	Project Status	2003			2002		Fair Value Basis

		(In thousands)
Devon Power LLC	Operating at a loss	$	64,198		$	—	Projected cash flows
Middletown Power LLC	Operating at a loss		157,323			—	Projected cash flows
Arthur Kill Power, LLC	Terminated construction project		9,049			—	Projected cash flows
Langage (UK)	Terminated		(3,091	)		42,333	Estimated market price/Realized gain
Turbine	Sold		(21,910	)		—	Realized gain
Berrians Project	Terminated		14,310			—	Realized loss
Termo Rio	Terminated		6,400			—	Realized loss
Nelson	Terminated		—			467,523	Similar asset prices
Pike	Terminated		—			402,355	Similar asset prices
Bourbonnais	Terminated		—			264,640	Similar asset prices
Meriden	Terminated		—			144,431	Similar asset prices
Brazos Valley	Foreclosure completed in January 2003		—			102,900	Projected cash flows
Kendall and other expansion projects	Terminated		—			55,300	Projected cash flows
Turbines & other costs	Equipment being marketed		—			701,573	Similar asset prices
Audrain	Operating at a loss		—			66,022	Projected cash flows
Somerset	Operating at a loss		—			49,289	Projected cash flows
Bayou Cove	Operating at a loss		—			126,528	Projected cash flows
Other			2,617			28,851

Total impairment charges (credits)		$	228,896		$	2,451,745


	Reorganization Items

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


		Reorganized		Predecessor
		NRG		Company

		For the Period		For the Period
		December 6 -		January 1 -
		December 31,		December 5,
		2003		2003

		(In thousands)
Reorganization items
	Professional fees	$	2,461	$	82,186
	Deferred financing costs		—		55,374
	Pre-payment settlement		—		19,609
	Interest earned on accumulated cash		—		(1,059	)
	Contingent equity obligation		—		41,715

	Total reorganization items	$	2,461	$	197,825


	Restructuring Charges

We incurred $8.7 million of employee separation costs and advisor fees during the period January 1, 2003 until we filed for bankruptcy in May 2003. Subsequent to that date we recorded all advisor fees as reorganization costs. 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.


	Legal Settlement Charges

During the period January 1, 2003 to December 5, 2003, we recorded $462.6 million of legal settlement charges which consisted of the following. We recorded $396.0 million in connection with the resolution of an arbitration claim asserted by FirstEnergy Corp. 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 NRG Energy’s plan of reorganization. In November 2003, we settled litigation with Fortistar Capital in which Fortistar Capital released us from all litigation claims in exchange for a $60.0 million pre-petition bankruptcy claim and an $8.0 million post-petition bankruptcy 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 November 2003, we settled our dispute with Dick Corporation in connection with Meriden Gas Turbines LLC through the payment of a general unsecured claim and a post-petition pre-confirmation payment. This settlement resulted in our recording an additional liability of $8.0 million in November 2003.


	Fresh Start Adjustments


		(In millions)
Discharge of corporate level debt		$	5,162
Discharge of other liabilities			811
Establishment of creditor pool			(1,040	)
Receivable from Xcel			640
Revaluation of fixed assets			(1,392	)
Revaluation of equity investments			(207	)
Valuation of SO ₂emission credits			374
Valuation of out of market contracts, net			(400	)
Fair market valuation of debt			108
Valuation of pension liabilities			(61	)
Other valuation adjustments			(100	)

Total Fresh Start adjustments			3,895
	Less discontinued operations		(224	)

Total Fresh Start adjustments — continuing operations		$	4,119


	Other Income (Expense)


	*Reorganized NRG*


	*Predecessor Company*

For the year ended December 31, 2002, other expenses were $572.2 million, which consisted primarily of $452.2 million of interest expense and $200.5 million of write downs and losses on sales of equity method investments, partially offset by equity in earnings of unconsolidated affiliates of $69.0 million and other income, net of $11.5 million.


	Minority Interest in Earnings of Consolidated Subsidiaries

For the period December 6, 2003 through December 31, 2003, minority interest in earnings of consolidated subsidiaries was $134,000 and relates primarily to Northbrook New York and Northbrook Energy.


	Equity in Earnings of Unconsolidated Affiliates


	*Reorganized NRG*


	*Predecessor Company*

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.


	Write-Downs and Losses on Sales of Equity Method Investments

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. During the period January 1, 2003 to December 5, 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 primarily of the write down of our investment in the Loy Yang project of $146.4 million, our investment in the NEO Corporation — Minnesota Methane project of $12.3 million and our investment in NEO Corporation — MM Biogas of $2.6 million. These losses were partially offset by gains on the sale of our investment in the ECKG and Mustang projects of $2.9 million and $12.1 million, respectively. 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 primarily 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 $3.2 million, respectively among others, offset by a $9.9 million gain on sale of our Kingston project.


	Other income, net

Other income, net consists primarily of interest income earned on notes receivable and cash balances. We recorded $97,000, $19.2 million and $11.4 million of other income, net for the periods December 6, 2003 through December 31, 2003 and January 1, 2003 through December 5, 2003 and for the year ended December 31, 2002, respectively.


	Interest expense


	*Reorganized NRG*


	*Predecessor Company*

Interest expense for the period January 1, 2003 through December 5, 2003 of $329.9 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 pre-petition 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.

Interest expense was $452.2 million for the year ended December 31, 2002.


	Income Tax


	*Reorganized NRG*

Income tax benefit for the period December 6, 2003 through December 31, 2003 was ($0.7) million and the overall effective tax rate was (6.2%). The rate is lower than the U.S. statutory rate primarily due to a state tax refund received from Xcel Energy in 2003, foreign income taxed in jurisdictions with tax rates different from the U.S. statutory rate and a decrease in unfavorable permanent differences.

Our deferred tax assets at December 31, 2003 were offset by a full valuation allowance in accordance with SFAS No. 109. Under SOP 90-7, any future benefits from reducing a valuation allowance from preconfirmation deferred tax assets are required to 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 the realization of our deferred tax assets, which were fully valued as of the date of our emergence from bankruptcy. The adoption of this Statement of Position will result in a disallowance of a future income statement benefit of $1.3 billion as a result of a reduction to the intangible asset for realization of benefits of fully valued deferred tax assets as of December 5, 2003 (date of emergence from bankruptcy).


	*Predecessor Company*

Income tax expense (benefit) for the period January 1, 2003 through December 5, 2003 was a tax expense of $37.9 million and a tax benefit of ($166.9) million for the year ended December 31, 2002. The overall effective tax rate for the short period ended December 5, 2003 and the year ended December 31, 2002 was 1.3% and 5.6%, respectively. The change in our effective tax rate was primarily due to a release in valuation allowance for net operating loss carryforwards that were utilized following our emergence from bankruptcy to offset the current tax on cancellation of debt income.


	Discontinued Operations


	*Reorganized NRG*


	*Predecessor Company*

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, PERC, Cobee, NLGI, seven NEO Corporation projects, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu projects. Discontinued operations for the year ended December 31, 2002 consisted of our Crockett Cogeneration, Entrade, Killingholme, Csepel, Bulo Bulo, McClain, PERC, Cobee, NLGI, seven NEO Corporation projects, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu projects.

During 2002, we recognized a loss on discontinued operations of $675.8 million due primarily to asset impairments recorded at Killingholme, NLGI, TERI, LSP Energy and Hsin Yu projects.

Reorganization and Emergence from Bankruptcy

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, or 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, or 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.


	*Financial Reporting by Entities in Reorganization under the Bankruptcy Code and Fresh Start*

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:


“Predecessor Company”		The Company, pre-emergence from bankruptcy The Company’s operations prior to December 6, 2003
“Reorganized NRG”		The Company, post-emergence from bankruptcy The Company’s operations from December 6, 2003- December 31, 2004

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 (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations), 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 (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations) 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 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. The accompanying Consolidated Financial Statements have been prepared to distinguish between Reorganized NRG and the Predecessor Company.

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 Power. This adjustment reduced our equity earnings in the amount of $115.8 million for the year ended December 31, 2004. This contract expired in December 2004.

Liquidity and Capital Resources


	*Reorganized Capital Structure*

In connection with the consummation of our reorganization, on December 5, 2003, all shares of our old common stock were canceled and 100,000,000 shares of new common stock of NRG Energy were distributed pursuant to such plan in accordance with Section 1145 of the bankruptcy code to the holders of certain classes of claims. We received no proceeds from such issuance. A certain number of shares of common stock were issued and placed in the Disputed Claims Reserve for distribution to holders of disputed claims as such claims are resolved or settled. See Item 3 — Legal Proceedings — Disputed Claims Reserve. In the event our disputed claims reserve is inadequate, it is possible we will have to issue additional shares of our common stock to satisfy such pre-petition claims or contribute additional cash proceeds. Our authorized capital stock consists of 500,000,000 shares of NRG Energy common stock and 10,000,000 shares of preferred stock. A total of 4,000,000 shares of our common stock are available for issuance under our long-term incentive plan.

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 $1.45 billion 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 connection with the consummation of the NRG plan of reorganization, we issued to Xcel Energy a $10.0 million non-amortizing promissory note, which accrues interest at a rate of 3% per annum and matures 2.5 years after the effective date of the NRG plan of reorganization. In January 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. On December 24, 2004, we amended and restated our existing $1.45 billion credit facility, recasting it as a $950 million secured credit facility made up of a $450.0 million seven-year senior secured term loan, a $350.0 million funded letter of credit facility and a three-year $150.0 million revolving line of credit. In December 2004, we also issued $420 million of convertible preferred stock and used the proceeds from such issuance to redeem $375 million of the Second Priority Notes in February 2005. Also in January 2005 and in March 2005, we used existing cash to purchase, at market prices, $25 million and $15.8 million, respectively, in face value of our Second Priority Notes. These notes were assumed by NRG Energy and therefore remain outstanding. As of March 21, 2005, we had $1.35 billion in aggregate principal amount of Second Priority Notes outstanding, $450.0 million principal amount outstanding under the term loan and $350 million of the funded letter of credit facility outstanding. $178.3 million of undrawn letters of credit remain available under the funded letter of credit facility. As of March 21, 2005, we had not drawn down on our revolving credit facility.

The following table summarizes the debt transactions:


							Outstanding at				Outstanding at					Outstanding at
			Date of		Original		December 31,				December 31,					March 21,
			Transaction		Amount		2003		Activity		2004		Activity			2005

					(In thousands)
Xcel Promissory Note				Dec. 6, 2003	$	10,000	$	10,000			$	10,000				$	10,000
NRG 8% Senior Secured Notes				Dec. 23, 2003	$	1,250,000	$	1,250,000			$	1,250,000
	Tack-on offering			Jan. 28, 2004					$	475,000	$	475,000

											$	1,725,000				$	1,725,000
	Repurchase of Notes*			Jan. 21-27, 2005									$	(25,000	)
	Early Redemption			Feb. 4, 2005									$	(375,000	)		(375,000	)
	Repurchase of Notes*			March 28, 2005									$	(15,838	)

																$	1,350,000
NRG Credit Facility Term loan				Dec. 23, 2003	$	950,000	$	950,000
	Letter of Credit facility			Dec. 23, 2003		250,000	$	250,000
	Corporate Revolver			Dec. 23, 2003		250,000		—

		NRG New Credit Facility			$	1,450,000	$	1,200,000
Refinancing of the Credit Facility
Amended Credit Facility
	Term loan			Dec. 24, 2004	$	450,000					$	450,000				$	450,000
	Letter of Credit facility			Dec. 24, 2004		350,000						350,000					350,000
	Corporate Revolver			Dec. 24, 2004		150,000						—					—

		NRG Amended Credit Facility			$	950,000					$	800,000				$	800,000

Total Corporate Level Debt							$	2,460,000			$	2,535,000				$	2,160,000


*	The notes were assumed by NRG Energy and remain outstanding.

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 Second Priority Notes and borrowings under our 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 18 to the Consolidated Financial Statements.


	*Historical Cash Flows*


	Reorganized NRG

We have obtained cash from operations, Xcel Energy’s contribution net of distributions to creditors, proceeds from the sale of certain assets, borrowings under our Second Priority Notes and credit facilities and the proceeds from the sale of preferred stock. We have used these funds to finance operations, service debt obligations, finance capital expenditures, repurchase common stock and meet other cash and liquidity needs.


	Predecessor Company

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.


	Reorganized NRG						Predecessor Company

				For the Period			For the Period
	Year Ended			December 6-			January 1-			Year Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002

	(In thousands)
Net cash provided (used) by operating activities	$	643,993		$	(588,875	)	$	238,509		$	430,042
Net cash (used) provided by investing activities		184,685			363,372			(185,679	)		(1,681,467	)
Net cash provided (used) by financing activities		(283,734	)		393,273			(29,944	)		1,449,330


	*Net Cash Provided (Used) By Operating Activities*


	Reorganized NRG

For the year ended December 31, 2004, net cash provided by operating activities was $644.0 million. Net income of $185.6 million and adjustments of $383.3 million accounted for $568.9 million of the total cash provided by operating activities. Non-cash adjustments consist primarily of depreciation, amortization and impairment charges offset by unrealized gains on derivatives. Cash provided by working capital of $75.0 million reflects a $100 million net resolution of a bankruptcy-related receivable and payable offset by other working capital changes of $25.0 million.

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


	Predecessor Company

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 year ended December 31, 2002, net cash provided by operating activities was $430.0 million. Operating activities consisted of a net loss before restructuring and impairment charges of $319.8 million offset by non-cash charges of $144.5 million and cash provided by working capital of $605.3 million.


	*Net Cash Provided (Used) By Investing Activities*


	Reorganized NRG

For the year ended December 31, 2004, net cash provided by investing activities was $184.7 million due primarily to sales proceeds, net of cash on hand, of $252.7 million on the sale of discontinued operations and sale proceeds of $50.7 million from the sale of investments, offset by capital expenditures of $114.4 million.

For the period December 6, 2003 through December 31, 2003, net 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.


	Predecessor Company

For the period January 1, 2003 through December 5, 2003, net cash used in investing activities was $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 year ended December 31, 2002, net cash used by investing activities was $1.7 billion due primarily to $1.4 billion of capital expenditures.


	*Net Cash Provided (Used) By Financing Activities*


	Reorganized NRG

For the year ended December 31, 2004, net cash used by financing activities was $283.7 million primarily due to reduction of long-term debt by $159.3 million, which was primarily related to the McClain sale. Financing activities were also driven by an increase in the funded letter of credit asset balance of $100.0 million. In December 2004, the Company issued preferred stock for net proceeds of $406.4 million which enabled us to redeem $375.0 million of senior secured notes in 2005. Available cash balances were used to purchase 13 million shares of common stock owned by MatlinPatterson for a price of $405.3 million.

For the period December 6, 2003 through December 31, 2003, net 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, a $250.0 million funded letter of credit facility and a $250.0 million unfunded revolving line of credit. Upon completion of the refinancing transactions, we repaid the Northeast Generating and South Central Generating notes and the Mid-Atlantic Generating obligations.


	Predecessor Company

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

For the year ended December 31, 2002, net cash provided by financing activities was $1.4 billion which consisted primarily of increased debt of $945.3 and a capital contribution from Xcel Energy in the amount of $500.0 million.


	*Sources of Funds*

The principal sources of liquidity for our future operations and capital expenditures are expected to be: (i) existing cash on hand and cash flows from operations and (ii) proceeds from the sale of certain assets and businesses. Additionally, we have approximately $192.9 million of undrawn letter of credit capacity under our senior credit facility as of December 31, 2004.

On December 24, 2004, we amended our corporate bank facility, which at December 31, 2004 consists of a $450.0 million, seven-year senior secured term loan, a $350.0 million funded letter of credit facility, and a three-year $150.0 million revolving line of credit, or the revolving credit facility. With the refinancing, we lowered the interest rate on the term loan to LIBOR plus 1.875% from LIBOR plus 4.0%. 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, 2004, the corporate revolver was undrawn.

On December 27, 2004, we completed the sale of $420 million of convertible perpetual preferred stock with a dividend coupon rate of 4%. The Preferred Stock has a liquidation preference of $1,000 per share of Preferred Stock. Holders of Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available therefore, cash dividends at the rate of 4% per annum, payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year, commencing on March 15, 2005. The Preferred Stock is convertible, at the option of the holder, at any time into shares of our common stock at an initial conversion price of $40.00 per share, which is equal to an approximate conversion rate of 25 shares of common stock per share of Preferred Stock, subject to specified adjustments. On or after

December 20, 2009, we may redeem, subject to certain limitations, some or all of the Preferred Stock with cash at a redemption price equal to 100% of the liquidation preference, plus accumulated but unpaid dividends, including liquidated damages, if any, to the redemption date.

Proceeds of $406.4 million from the sale of the preferred securities are net of securities issuance costs of approximately $13.6 million, and on February 4, 2005, these proceeds along with cash on hand were used to redeem $375.0 million in Second Priority Notes, pay an early redemption penalty of $30.0 million and pay accrued interest of $4.1 million on the redeemed notes.

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 including margin and collateral calls for our trading operation; (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, $328.5 million on April 30, 2004 and $23.5 million on May 28, 2004. We distributed $540.0 million of cash we received from Xcel Energy to our creditors pursuant to our plan of reorganization. We retained the remaining $100.0 million, which we used for general corporate purposes.

Asset Sales. We received $303.4 million, $196.5 million and $229.3 million in cash proceeds from the sale of certain assets and businesses in the fiscal years ended 2004, 2003 and 2002, respectively. The Amended 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 Amended Credit Facility includes a letter of credit sub-facility in the amount of $350.0 million. As of December 31, 2004, we had issued $157.1 million in letters of credit under this facility, leaving $192.9 million available for future issuance. The Amended Credit Facility also includes a revolving credit facility in the amount of $150.0 million to be used for general corporate purposes. On December 31, 2004 our revolving credit facility was undrawn. For additional information regarding our debt see Item 15 — Note 18 to the Consolidated Financial Statements.


	*Uses of Funds*

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; (iii) corporate financial restructuring and (iv) 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 posted with counter-parties; (ii) initial collateral required to establish trading relationships; (iii) timing of disbursements and receipts (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of December 31, 2004, PMI had total collateral outstanding of $47.8 million in margin, prepayments and cash deposits and $83.1 million outstanding in letters of credit to third parties.

Future liquidity requirements may change based on our hedging activity, fuel purchases, future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on our credit ratings and general perception of creditworthiness. We do not assume that we will be given unsecured credit from third parties in budgeting our working capital requirements.

Capital Expenditures. Capital expenditures were $114.4 million for the year ended December 31, 2004, $10.6 million for the period December 6, 2003 through December 31, 2003, $113.5 million for the period

January 1, 2003 through December 5, 2003 and $1.4 billion for the year ended 2002. Capital expenditures in 2004 relate primarily to the conversion of our western New York plants to low-sulfur coal, the Playford 2 refurbishment at our Flinders operation in Australia and planned outages across our fleet. 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. In 2005, we anticipate we will spend approximately $133.3 million in capital expenditures and an additional $109.5 million in major maintenance expense related primarily to the operation and maintenance of our existing generating facilities.

Corporate Financial Restructuring. We may elect periodically to modify our corporate financial structure in order to increase near-term or long-term cash flows or to reduce exposure to financial risks. On December 21, 2004, we purchased 13 million shares of common equity interest in NRG Energy from investment partnerships managed by MatlinPatterson. Total costs associated with the repurchase, including fees and expenses, was $405.3 million. On February 4, 2005, we used proceeds from our Preferred Stock issuance to redeem early $375.0 million of our Second Priority Notes at par value plus 8%. We also paid outstanding accrued interest and liquidated damage penalties attributable to the redeemed notes. In January 2005 and March 2005, we repurchased $25.0 million and $15.8 million, respectively, of our notes, which remain outstanding. As of March 21, 2005, $1.35 billion in Second Priority Notes remain outstanding.

Preferred Dividend Payment. On March 15, 2005, we made a $3.9 million dividend payment to our preferred shareholders of record as of March 1, 2005. This represents the first quarterly dividend payment we anticipate making to our preferred shareholders.

Project Finance Requirements. We are a holding company and conduct our operations through subsidiaries. Historically, we have utilized project-level 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, project-level debt in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. Project-level 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 being financed. Some of these project financings may require us to post collateral in the form of cash or an acceptable letter of credit.

In February 2005, Flinders amended its debt facility of AUD 279.4 million (approximately US $218.5 million) in floating-rate debt. The amendment extended the maturity to February 2017, reduced borrowing costs and reserve requirements, minimized debt service coverage ratios, removed mandatory cash sharing arrangements, and made other minor modifications to terms and conditions. The facility includes an AUD 20 million (approximately US $15.7 million) working capital and performance bond facility. NRG Flinders is required to maintain interest-rate hedging contracts on a rolling 5-year basis at a minimum level of 60% of principal outstanding. Upon execution of the amendment, a voluntary principal prepayment of AUD 50 million (approximately US $39.1 million) was made, reducing the principal balance to AUD 229.2 million (approximately $179.4 million).

Principal on short-term debt, long-term debt and capital leases as of December 31, 2004 are due and payable in the following periods (in thousands):


Subsidiary/Description			Total		2005		2006		2007		2008		2009		Thereafter

Xcel Energy Note			$	10,000	$	—	$	10,000	$	—	$	—	$	—	$	—
Credit Facility Due Dec. 2011				800,000		8,000		8,000		8,000		8,000		8,000		760,000
8% Second Priority Notes due Dec. 2013				1,725,000		400,000		—		—		—		—		1,325,000
NRG Energy Center Minneapolis, due 2013 and 2017				118,950		7,877		8,465		9,097		9,776		10,507		73,228
NRG Peaker Finance Co LLC				300,876		4,312		6,768		11,164		12,903		14,758		250,971
Flinders Power Finance Pty				202,856		11,564		13,443		14,633		15,931		14,083		133,202
NRG Energy Center San Francisco				129		32		31		37		29		—		—
Camas Pwr BLR LP Bank facility				6,275		2,442		2,533		1,300		—		—		—
Camas Pwr BLR LP Bonds				4,475		1,385		1,485		1,605		—		—		—
Itiquira Energetica S.A., due January 2012				20,078		2,845		2,845		2,845		2,845		2,845		5,853
Itiquira Energetica S.A., due April 2011				31,002		—		3,875		3,875		3,875		3,875		15,502
Northbrook New York				16,900		500		600		700		800		850		13,450
Northbrook Carolina				2,375		100		100		150		150		150		1,725
Northbrook STS HydroPower				24,329		477		523		572		627		807		21,323

	Subtotal Debt, Bonds and Notes			3,263,245		439,534		58,668		53,978		54,936		55,875		2,600,254

Saale Energie GmbH, Schkopau (capital lease)				303,803		69,904		51,785		38,612		31,693		23,786		88,023
Audrain Generating (capital lease)				239,930		—		—		—		—		—		239,930
Conemaugh Fuels LLC (capital lease)				218		16		18		19		20		22		123

	Subtotal Capital Leases			543,951		69,920		51,803		38,631		31,713		23,808		328,076

		Total Debt	$	3,807,196	$	509,454	$	110,471	$	92,609	$	86,649	$	79,683	$	2,928,330

These amounts reflect scheduled amortization of principal as of December 31, 2004, with the exception of the 8% Senior Secured Notes, for which 2005 amounts reflect early redemption and repurchases made through March 21, 2005. See Item 15 — Note 18 to the Consolidated Financial Statements for further discussion on events that may affect debt payment schedules.

On December 24, 2004, we amended and restated our senior credit facility, which now consists of a $450.0 million, seven-year senior secured term loan facility, a $350.0 million funded letter of credit facility, and a three-year revolving credit facility in an amount up to $150.0 million. At that time, we paid $13.8 million in prepayment breakage costs, $3.2 million in accrued but unpaid interest and fees, and $16.7 million in other costs associated with the amendment. The balance outstanding under this facility was $800.0 million as of December 31, 2004. Other expenses include commitment fees on the undrawn portion of the revolving credit facility, participation fees for the credit-linked deposit and other fees.

As of December 31, 2004, the $350.0 million letter of credit facility was fully funded and reflected as a funded letter of credit on the December 31, 2004 balance sheet. As of December 31, 2004, $157.1 million in letters of credit had been issued under this facility, leaving $192.9 million available for future issuances.

If we decide not to provide any additional funding or credit support to our subsidiaries, the inability of any of our subsidiaries 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 could 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 18 to the Consolidated Financial Statements.


	*Liquidity Estimates*

For 2005, we anticipate utilizing $300 million of our letter of credit facility. In addition, PMI may require additional capital resources depending upon our hedging activity, fuel purchases and future market conditions. As part of our refinancing transactions, we have a $150.0 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.

On February 4, 2005, utilizing net proceeds of $406.4 million from the sale of preferred securities in December 2004, we redeemed $375.0 million in Second Priority Notes. At the same time, we paid $30.0 million for the early redemption premium on the redeemed notes, $4.1 million in accrued but unpaid interest on the redeemed notes and $0.4 million in accrued but unpaid liquidated damages on the redeemed notes.

On March 15, 2005, we made a $3.9 million dividend payment to our preferred shareholders of record as of March 1, 2005. This represents the first quarterly dividend payment we anticipate making to our preferred shareholders.


	*Other Liquidity Matters*

We expect our capital requirements to be met with existing cash balances, cash flows from operations, borrowings under our Second Priority Notes and Amended 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 Amended 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, such 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.


	Net Operating Loss Carryforwards

For the year ended December 31, 2004, we generated a net operating loss carryforward of $102.1 million which will expire through 2024. We believe that it is more likely than not that no benefit will be realized on the deferred tax assets relating to the net operating loss carryforwards. This assessment included consideration of positive and negative factors, including our current financial position and results of operations, projected future taxable income, including projected operating and capital gains, and available tax planning strategies. Therefore, as of December 31, 2004, a valuation allowance of $707.9 million was recorded against the net deferred tax assets, including net operating loss carryforwards in accordance with SFAS No. 109.

Off-Balance Sheet Items

As of December 31, 2004, we have not entered into any financing structure that is designed to be off-balance sheet that would create liquidity, financing or incremental market risk or credit risk to us. However, 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 $251.7 million as of December 31, 2004. The decline was largely a result of sales of our interest in Calpine Cogeneration, Loy Yang and Commonwealth Atlantic. In the normal course of business we may be asked to loan funds to the unconsolidated affiliates on both a long and short-term basis. Such transactions are generally accounted for as accounts payable and receivable to/from affiliates and notes payable/receivable 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.

Contractual Obligations and Commercial Commitments

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 18, 27 and 29 to the Consolidated Financial Statements.


	Payments Due by Period as of December 31, 2004

									After
Contractual Cash Obligations	Total		Short-term		2-3 Years		4-5 Years		5 Years

	(In thousands)
Long-term debt	$	4,783,626	$	614,573	$	461,833	$	460,372	$	3,246,848
Capital lease obligations (including estimated interest)		1,263,658		115,558		177,436		136,940		833,724
Operating leases		140,324		16,176		32,383		28,822		62,943
Coal purchase and transportation obligations		351,182		118,679		135,176		75,628		21,699

Total contractual cash obligations	$	6,538,790	$	864,986	$	806,828	$	701,762	$	4,165,214


	Amount of Commitment Expiration per Period as of December 31,
	2004

	Total
	Amounts								After
Other Commercial Commitments	Committed		Short-term		2-3 Years		4-5 Years		5 Years

	(In thousands)
Funded standby letters of credit	$	157,144	$	157,144	$	—	$	—	$	—
Unfunded standby letters of credit		16,103		16,103		—		—		—
Surety bonds		4,467		4,467		—		—		—
Asset sales guarantee obligations		73,515		1,000		250		12,500		59,765
Commodity sales guarantee obligations		57,600		24,100		—		—		33,500
Other guarantees		94,126		—		778		—		93,348

Total commercial commitments	$	402,955	$	202,814	$	1,028	$	12,500	$	186,613

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

commenced in February 2005. We have assigned certain of our rights and obligations for 1,500 railcars under the purchase agreement with Johnston America to GE. Accordingly, the railcars which we lease from GE under the arrangement described above will be purchased by GE from Johnston America in lieu of our purchase of those railcars.

Interdependent Relationships

We do not have any significant interdependent relationships.

Derivative Instruments

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. In addition, in order to mitigate interest rate risk associated with the issuance of our variable rate and fixed rate debt, we enter into interest rate swap agreements.

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, 2004 based on whether fair values are determined by quoted market prices or more subjective means; and indicate the maturities of contracts at December 31, 2004.


	*Derivative Activity Gains/(Losses)*


	Reorganized
	NRG

	(In thousands)
Fair value of contracts at December 31, 2003	$	(93,253	)
Contracts realized or otherwise settled during the period		17,298
Changes in fair value		32,284

Fair value of contracts at December 31, 2004	$	(43,671	)


	Sources of Fair Value Gains/(Losses)


	Reorganized NRG
	Fair Value of Contracts at Period End as of December 31, 2004

	Maturity								Maturity
	Less than		Maturity			Maturity			in excess			Total Fair
	1 Year		1-3 Years			4-5 Years			of 5 Years			Value

	(In thousands)
Prices actively quoted	$	47,131	$	1,296		$	—		$	—		$	48,427
Prices based on models and other valuation methods		1,371		(19,451	)		(16,354	)		(37,913	)		(72,347	)
Prices provided by other external sources		13,245		(1,643	)		(6,500	)		(24,853	)		(19,751	)

Total	$	61,747	$	(19,798	)	$	(22,854	)	$	(62,766	)	$	(43,671	)

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.

Critical Accounting Policies and Estimates

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.


Accounting Policy		Judgments/Uncertainties Affecting Application

Fresh Start Reporting		• The determination of the enterprise value and the allocation to the underlying assets and liabilities are based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies
		• Determination at Fresh Start date
		• Consolidation of entities remaining in bankruptcy
		• Valuation of emission credit allowances and power sales contracts
		• Valuation of debt instruments
		• Valuation of equity investments
Capitalization Practices		• Determination of beginning and ending of capitalization periods
		• Allocation of purchase prices to identified assets
Asset Valuation and Impairment		• Recoverability of investment through future operations
		• Regulatory and political environments and requirements
		• Estimated useful lives of assets
		• Environmental obligations and operational limitations
		• Estimates of future cash flows
		• Estimates of fair value (fresh start)
		• Judgment about triggering events
Revenue Recognition		• Customer/counter-party dispute resolution practices


Accounting Policy		Judgments/Uncertainties Affecting Application

		• Market maturity and economic conditions
		• Contract interpretation
Uncollectible Receivables		• Economic conditions affecting customers, counter-parties, suppliers and market prices
		• Regulatory environment and impact on customer financial condition
		• Outcome of litigation and bankruptcy proceedings
Derivative Financial Instruments		• Market conditions in the energy industry, especially the effects of price volatility on contractual commitments
		• Assumptions used in valuation models
		• Documentation requirements
		• Counter-party credit risk
		• Market conditions in foreign countries
		• Regulatory and political environments and requirements
Litigation Claims and Assessments		• Impacts of court decisions
		• Estimates of ultimate liabilities arising from legal claims
Income Taxes and Valuation Allowance for Deferred Tax Assets		• Ability of tax authority decisions to withstand legal challenges or appeals
		• Anticipated future decisions of tax authorities
		• Application of tax statutes and regulations to transactions.
		• Ability to utilize tax benefits through carrybacks to prior periods and carryforwards to future periods.
Discontinued Operations		• Consistent application
		• Determination of fair value (recoverability)
		• Recognition of expected gain or loss prior to disposition
Pension		• Accuracy of management assumptions
		• Accuracy of actuarial consultant assumptions
Stock-Based Compensation		• Accuracy of management assumptions used to determine the fair value of the stock options

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.

Fresh Start Reporting

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 among our assets and liabilities on a basis substantially consistent with purchase accounting in accordance with SFAS No. 141, “Business Combinations.”

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 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 (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations), 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 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 all 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 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 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.

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 have accounted for these entities as if they had emerged from bankruptcy at the same time that we emerged, as we believe that we continued to maintain control over the Northeast Generating and South Central Generating facilities throughout the bankruptcy process.

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.


	*Capitalization Practices*


	Reorganized NRG

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.


	Predecessor Company

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.


	*Impairment of Long Lived Assets*

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 year ended December 31, 2004, the periods December 6, 2003 through December 31, 2003 and January 1, 2003 through December 5, 2003 and for the year ended December 31, 2002, net income from continuing operations was reduced by $44.7 million, $0 million, $228.9 million and $2.5 billion, respectively, due to asset impairments. Asset impairment evaluations are by nature highly subjective.


	*Revenue Recognition and Uncollectible Receivables*

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 regions where bilateral markets exist and physical delivery of electricity is common from our plants, we record revenue on a gross basis. 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. Revenues derived from the buying and selling of electricity not sourced from our facilities are reported net. 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.


	*Derivative Financial Instruments*

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, as amended, 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, as amended, 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, as amended, also applies to interest rate swaps and foreign currency exchange rate contracts. The application of SFAS No. 133, as amended, 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.


	*Discontinued Operations*

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. Prior periods are restated to report the operations as discontinued.


	*Pensions*

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.


	*Stock-Based Compensation*

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. The Black-Scholes option-pricing model is used for all non-qualified stock options.


	*Recent Accounting Developments*

In November 2004, the Emerging Issue Task Force, or EITF, issued EITF No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”. EITF 03-13 clarifies the

definition of cash flows of a component in which the seller engages in activities with the component after disposal, and significant continuing involvement in the operations of the component after the disposal transaction, and is effective for fiscal periods beginning after December 15, 2004. The adoption of this standard will not have a material effect on our consolidated financial position and results of operations.

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs — an amendment of ARB No. 43, Chapter 4”. This statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing”, and requires that idle facility expense, excessive spoilage, double freight, and rehandling costs be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal” established by ARB No. 43. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The adoption of this statement will not have a material effect on our consolidated financial position and results of operations.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment”, a revision to SFAS No. 123, “Accounting for Stock-Based Compensation”, which supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees” and its related implementation guidance. SFAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services, including obtaining employee services in share-based payment transactions. SFAS 123R applies to all awards granted after the required effective date and to awards modified, repurchased, or cancelled after that date. Adoption of the provisions of SFAS 123R is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. We have previously adopted SFAS No. 123, and we are currently in the process of evaluating the potential impact that the adoption of SFAS 123R will have on our consolidated financial position and results of operations.

In December 2004, the FASB issued two FASB Staff Positions, or FSPs, regarding the accounting implications of the American Jobs Creation Act of 2004 related to (1) the deduction for qualified domestic production activities (FSP FAS 109-1) and (2) the one-time tax benefit for the repatriation of foreign earnings (FSP FAS 109-2). In FSP FAS 109-1, “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”, the Board decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under FASB Statement No. 109, “Accounting for Income Taxes” and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004”, addresses the appropriate point at which a company should reflect in its financial statements the effects of the one-time tax benefit on the repatriation of foreign earnings. Because of the proximity of the Act’s enactment date to many companies’ year-ends, its temporary nature, and the fact that numerous provisions of the Act are sufficiently complex and ambiguous, the Board decided that absent additional clarifying regulations, companies may not be in a position to assess the impact of the Act on their plans for repatriation or reinvestment of foreign earnings. Therefore, the Board provided companies with a practical exception to FAS 109’s requirements by providing them additional time to determine the amount of earnings, if any, that they intend to repatriate under the Act’s beneficial provisions. The Board confirmed, however, that upon deciding that some amount of earnings will be repatriated, a company must record in that period the associated tax liability, thereby making it clear that a company cannot avoid recognizing a tax liability when it has decided that some portion of its foreign earnings will be repatriated. We are currently in the process of evaluating the potential impact that the adoption of FSP FAS 109-1 and FSP FAS 109-2 will have on our consolidated financial position and results of operations.


Item 7A —	*Quantitative and Qualitative Disclosures About Market Risk*

We are exposed to several market risks in our normal business activities. Market risk is the potential loss that may result from market changes associated with our “merchant” power generation or with an existing or forecasted financial or commodity transaction. The types of market risks we are exposed to are commodity price risk, interest rate risk and currency exchange risk. In order to manage these risks we utilize various fixed-

price forward purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange, and swaps and options traded in the over-the-counter financial markets to:


	•	Manage and hedge our fixed-price purchase and sales commitments;

	•	Manage and hedge our exposure to variable rate debt obligations,

	•	Reduce our exposure to the volatility of cash market prices; and

	•	Hedge our fuel requirements for our generating facilities.

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities in commodities, and correlations between various commodities, such as natural gas, electricity, coal and oil. A number of factors influence the level and volatility of prices for energy commodities and related derivative products. These factors include:


	•	Seasonal daily and hourly changes in demand,

	•	Extreme peak demands due to weather conditions,

	•	Available supply resources,

	•	Transportation availability and reliability within and between regions,

	•	Changes in the nature and extent of federal and state regulations.

As part of our overall portfolio, we manage the commodity price risk of our “merchant” generation by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel. These instruments include forward purchase and sale contracts, futures and option contracts traded on the New York Mercantile Exchange, and swaps and options traded in the over-the-counter financial markets. The portion of forecasted transactions hedged may vary based upon management’s assessment of market, weather, operational, and other factors.

While some of the contracts we use to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. We use our best estimates to determine the fair value of commodity and derivative contracts we hold and sell. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. However, it is likely that future market prices could vary from those used in recording mark-to-market derivative instrument valuation, and such variations could be material.

We measure the sensitivity of our portfolio to potential changes in market prices using value at risk. Value at risk is a statistical model that attempts to predict risk of loss based on market price volatility. We calculate value at risk using a variance/covariance technique that models positions using a linear approximation of their value. Our value at risk calculation includes mark-to-market and non mark-to-market energy assets and liabilities.

We utilize a diversified value at risk model to calculate the estimate of potential loss in the fair value of our energy assets and liabilities including generation assets, load obligations and bilateral physical and financial transactions. The key assumptions for our diversified model include (1) a lognormal distribution of price returns, (2) one-day holding period, (3) a 95% confidence interval, (4) a rolling 24-month forward looking period and (5) market implied price volatilities and historical price correlations.

This model encompasses the following generating regions: ENTERGY, NEPOOL, NYPP, PJM, WSCC and MAIN. The estimated maximum potential loss in fair value of our commodity portfolio, including generation assets, load obligations and bilateral physical and financial transaction, calculated using the diversified VAR model is as follows:


		(In millions)
Year end December 31, 2004		$	26.7
	Average		40.3
	High		53.4
	Low		26.7
Year end December 31, 2003			37.1
	Average		45.7
	High		53.0
	Low		37.1

In order to provide additional information for comparative purposes to our peers we also utilize value at risk to model the estimate of potential loss of financial derivative instruments included in derivative instruments valuation assets and liabilities. This estimation includes those energy contracts accounted for as a hedge under SFAS No. 133, as amended. The estimated maximum potential loss in fair value of the financial derivative instruments calculated using the diversified VAR model as of December 31, 2004 is $17.6 million.

Due to the inherent limitations of statistical measures such as value at risk, the relative immaturity of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the value at risk calculation may not capture the full extent of commodity price exposure. Additionally, actual changes in the value of options may differ from the value at risk calculated using a linear approximation inherent in our calculation method. As a result, actual changes in the fair value of mark-to market energy assets and liabilities could differ from the calculated value at risk, and such changes could have a material impact on our financial results.


	*Interest Rate Risk*

We are exposed to fluctuations in interest rates through our issuance of fixed rate and variable rate debt. Exposures 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, 2004, we had various interest rate swap agreements with notional amounts totaling approximately $1.3 billion. If the swaps had been discontinued on December 31, 2004, we would have owed the counter-parties approximately $35.6 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, 2004, a 100 basis point change in interest rates would result in a $5.7 million change in interest expense.

At December 31, 2004, the fair value of our long-term debt was $3.9 billion, compared with the carrying amount of $3.8 billion. We estimate that a 1% decrease in market interest rates would have increased the fair value of our long-term debt by $76.3 million.


	*Currency Exchange Risk*

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 denomi-

nated in the Euro, Australian Dollar, British Pound 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, 2004, neither we, nor any of our consolidating subsidiaries, had any outstanding foreign currency exchange contracts.


	*Credit Risk*

Credit risk relates to the risk of loss resulting from non-performance or non-payment by counter-parties pursuant to the terms of their contractual obligations. We monitor and manage the credit risk of NRG Energy, Inc. and its subsidiaries through credit policies which include an (i) established credit approval process, (ii) daily monitoring of counter-party credit limits, (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements, (iv) the use of payment netting agreements and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counter-party. Risks surrounding counter-party performance and credit could ultimately impact the amount and timing of expected cash flows. We have credit protection within various agreements to call on additional collateral support if necessary. As of December 31, 2004, we held collateral support of $155.5 million from counterparties.

Additionally NRG has concentrations of suppliers and customers among electric utilities, energy marketing and trading companies and regional transmission operators. These concentrations of counter-parties may impact NRG’s overall exposure to credit risk, either positively or negatively, in that counter-parties may be similarly affected by changes in economic, regulatory and other conditions.


Item 8 —	*Financial Statements and Supplementary Data*

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


Item 9 —	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosures*

None.


Item 9A —	*Controls and Procedures*

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer, principal financial officer and principal accounting officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based on this evaluation, our principal executive officer, principal financial officer and principal accounting officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this annual report on Form 10-K.

There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter that have materially affected, or are reasonably likely to materially affected, or are reasonably likely to materially affect our internal control over financial reporting.


Item 9B —	*Other Information*

The following disclosure would otherwise have been filed on Form 8-K under the caption “Item 1.01. Entry into a Material Definitive Agreement.” On December 7, 2004, the Board of Directors approved the following additional director compensation: an additional $10,000 for members of the Audit Committee due to the extraordinary number of meetings (19) held in 2004 and an additional $5,000 for members of the Board of

Directors who served on a special committee in connection with the sale of shares by MatlinPatterson Global Opportunities Partners L.P. and one of its affiliates to NRG Energy.

PART III


Item 10 —	*Directors and Executive Officers of the Registrant*

NRG Energy has adopted a code of ethics entitled “NRG Code of Conduct” that applies to directors, officers and employees, including the chief executive officer and senior financial officers of NRG Energy, which may be viewed through NRG Energy’s website at http://www.nrgenergy.com/investor/corpgov/.htm. NRG Energy also elects to disclose the information required by Form 8-K, Item 5.05, “Amendments to the registrant’s code of ethics, or waiver of a provision of the code of ethics,” through this website and such information will remain available on this website for at least a 12-month period. A copy of the “NRG Code of Conduct” is available in print to any shareholder who requests it.

Other information required by this Item will be contained in our definitive Proxy Statement for our 2005 Annual Meeting of Stockholders, to be filed on or before May 1, 2005, and such information is incorporated herein by reference.


Item 11 —	*Executive Compensation*

Information required by this Item will be contained in our definitive Proxy Statement for our 2005 Annual Meeting of Stockholders, to be filed on or before May 1, 2005, and such information is incorporated herein by reference.


Item 12 —	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*


Item 13 —	*Certain Relationships and Related Transactions*

Information required by this I