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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, 2005.	
 	
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	
 	 	 	
5.75% Mandatorily Convertible Preferred Stock	 	New York Stock Exchange	
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01 per share
      Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes  þ           No  o
      Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.     Yes  o           No  þ
      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 (§ 229.405 of this chapter) 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ          Accelerated filer o          Non-accelerated filer o
      Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  o           No  þ
      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 $3,272,968,478 based on the closing sale price of $37.60 as reported on the New York Stock Exchange.
      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 3, 2006	
 	 	 	
Common Stock, par value $0.01 per share	 	136,975,275	
Documents Incorporated by Reference:
Portions of the Proxy Statement for the 2006 Annual Meeting of Stockholders to be held on April 28, 2006

 
NRG ENERGY, INC. AND SUBSIDIARIES
INDEX
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Page No.	 	

Glossary of Terms	 	 	2	 	
 	 Item 1	 	 	—	 	 	 Business	 	 	6	 	
 	 Item 1A	 	 	—	 	 	 Risk Factors Related to NRG Energy, Inc.	 	 	47	 	
 	 Item 1B	 	 	—	 	 	 Unresolved Staff Comments	 	 	60	 	
 	 Item 2	 	 	—	 	 	 Properties	 	 	61	 	
 	 Item 3	 	 	—	 	 	 Legal Proceedings	 	 	64	 	
 	 Item 4	 	 	—	 	 	 Submission of Matters to a Vote of Security Holders	 	 	70	 	
 PART II	 	 	71	 	
 	 Item 5	 	 	—	 	 	 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	 	 	71	 	
 	 Item 6	 	 	—	 	 	 Selected Financial Data	 	 	74	 	
 	 Item 7	 	 	—	 	 	 Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	76	 	
 	 Item 7A	 	 	—	 	 	 Quantitative and Qualitative Disclosures About Market Risk	 	 	124	 	
 	 Item 8	 	 	—	 	 	 Financial Statements and Supplementary Data	 	 	128	 	
 	 Item 9	 	 	—	 	 	 Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	 	 	128	 	
 	 Item 9A	 	 	—	 	 	 Controls and Procedures	 	 	128	 	
 	 Item 9B	 	 	—	 	 	 Other Information	 	 	128	 	
 PART III	 	 	129	 	
 	 Item 10	 	 	—	 	 	 Directors and Executive Officers of the Registrant	 	 	129	 	
 	 Item 11	 	 	—	 	 	 Executive Compensation	 	 	129	 	
 	 Item 12	 	 	—	 	 	 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	 	 	129	 	
 	 Item 13	 	 	—	 	 	 Certain Relationships and Related Transactions	 	 	129	 	
 	 Item 14	 	 	—	 	 	 Principal Accountant Fees and Services	 	 	129	 	
 PART IV	 	 	130	 	
 	 Item 15	 	 	—	 	 	 Exhibits and Financial Statement Schedules	 	 	130	 	
 SIGNATURES	 	 	254	 	
 EXHIBIT INDEX	 	 	 	 	
 EX-10.31: AMENDED MASTER POWER PURCHASE AND SALE AGREEMENT	 	 	 	
 EX-10.32: TERMS AND CONDITIONS OF SALE	 	 	 	
 EX-10.33: EMPLOYMENT AGREEMENT	 	 	 	
 EX-10.34: NEO 2005 AIP PAYOUT AND 2006 BASE SALARY TABLE	 	 	 	
 EX-21: SUBSIDIARIES OF NRG ENERGY, INC.	 	 	 	
 EX-23.1: CONSENT OF KPMG LLP	 	 	 	
 EX-23.2: CONSENT OF PRICEWATERHOUSECOOPERS LLP	 	 	 	
 EX-31.1: CERTIFICATION	 	 	 	
 EX-31.2: CERTIFICATION	 	 	 	
 EX-31.3: CERTIFICATION	 	 	 	
 EX-32: CERTIFICATION	 	 	 	

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Glossary of Terms
      When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
 	 	 	
APB	 	Accounting Principles Board	
APB 18	 	APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”	
Average gross heat rate	 	The product of dividing(a) fuel consumed in BTU’s by(b) KWh generated.	
BART	 	Best Available Retrofit Technology	
Baseload capacity	 	Electric power generation capacity normally expected to serve loads on an around-=the-clock basis throughout the calendar year.	
BTA	 	Best Technology Available	
BTU	 	British Thermal Unit	
CAA	 	Clean Air Act	
CAIR	 	Clean Air Interstate Rule	
Cal ISO	 	California Independent System Operator.	
CAMR	 	Clean Air Mercury Rule	
Capacity factor	 	The ratio of the actual net electricity generated to the energy that could have been generated at continuous full-power operation during the year.	
CDWR	 	California Department of Water Resources	
CERCLA	 	Comprehensive Environmental Response, Compensation and Liability Act	
CL&P	 	Connecticut Light & Power	
CO 2	 	Carbon dioxide	
CPUC	 	California Public Utilities Commission,	
CTDEP	 	Connecticut Department of Environmental Protection	
CWA	 	Clean Water Act	
DNREC	 	Delaware Department of Natural Resources and Environmental Control	
EAF	 	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, expressed as a percent of all hours in the year	
EFOR	 	Equivalent Forced Outage Rates — considers the equivalent impact that forced de-ratings have in addition to full forced outages	
EITF	 	Emerging Issues Task Force	
EITF 91-6	 	EITF No. 91-6, “Revenue Recognition of Long-Term Power Sales Contracts.”	
EITF 02-3	 	EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”	
EITF 03-11	 	EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in EITF Issue No. 02-03. ”	
EPA	 	Environmental Protection Agency	
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ERCOT	 	Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas	
ERISA	 	Employee Retirement Income Security Act	
Expected annual baseload generation	 	The net baseload capacity limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages)	
FASB	 	Financial Accounting Standards Board, the designated organization for establishing standards for financial accounting and reporting	
FERC	 	Federal Energy Regulatory Commission	
FF-ACI	 	Fabric Filter with Activated Carbon Injection	
FGD	 	Flue Gas Desulphurization	
FIN	 	Financial Accounting Standards Board Interpretation	
FIN 45	 	FIN No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”	
FIN 46R	 	FIN No. 46 (Revised 2003), “Consolidation of Variable Interest Entities”	
FIP	 	Federal Implementation Plan	
Fresh Start	 	Reporting requirements as defined by SOP 90-7	
FSP	 	FASB Staff Position (interpretations of standards issued by the staff of the FASB)	
FSP 106-1	 	FSP 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”	
FSP 106-2	 	FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”	
GHG	 	Greenhouse Gases	
IGCC	 	Integrated Gasification Combined Cycle	
IRS	 	Internal Revenue Service	
ISO	 	Independent System Operator, also referred to as regional transmission organizations, or RTO	
ISO-NE	 	ISO New England, Inc.	
KWh	 	kilowatt-hours	
LADEQ	 	Louisiana Department of Environmental Quality	
LIBOR	 	London Inter-Bank Offered Rate	
LNB/OFA	 	Low NO x Burner with Over Fire Air	
MACT	 	Maximum Achievable Control Technology	
MADEP	 	Massachusetts Department of Environmental Protection	
Moody’s	 	Moody’s Investors Services, Inc.	
MISO	 	Midwest Independent Transmission System Operator	
MW	 	Megawatts	
MWh	 	Saleable megawatt hours net of internal/parasitic load megawatt-hours	
NAAQS	 	National Ambient Air Quality Standards	
Net baseload capacity	 	Nominal summer net megawatt capacity of power generation adjusted for ownership and parasitic load, and excluding capacity from mothballed units as of December 31, 2005	
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Net Capacity Factor	 	Net actual generation divided by net maximum capacity for the period hours	
Net Generating Capacity	 	Nominal summer capacity, net of auxiliary power	
NiMo	 	Niagara Mohawk Power Corporation	
NO x	 	Nitrogen oxides	
NOL	 	Net operating loss	
NRC	 	United States Nuclear Regulatory Commission	
NSR	 	New Source Review	
NYISO	 	New York Independent System Operator.	
NYSDEC	 	New York Department of Environmental Conservation	
OCI	 	Other Comprehensive Income	
OTC	 	Ozone Transport Commission	
PJM	 	PJM Interconnection, LLC	
PJM Market	 	The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia.	
PM 2.5	 	Fine particulate matter	
PSD	 	Prevention of Significant Deterioration	
PUCT	 	Public Utility Commission of Texas	
Powder River Basin, or PRB Coal	 	Coal produced in the northeastern Wyoming and southeastern Montana, which coal has low sulfur content	
RCRA	 	Resource Conservation and Recovery Act	
RECLAIM	 	Regional Clean Air Incentives Market	
RGGI	 	Regional Greenhouse Gas Initiative	
RMR	 	Reliability must-run	
RTC	 	RECLAIM Trading Credit	
RTO	 	Regional transmission organization	
S&P	 	Standard & Poor’s, a division of the McGraw Hill Companies	
SARA	 	Superfund Amendments and Reauthorization Act of 1986	
Sarbanes-Oxley	 	Sarbanes — Oxley Act of 2002	
SCAQMD	 	South Coast Air Quality Management District	
SCR	 	Selective Catalytic Reduction	
SDG&E	 	San Diego Gas & Electric	
SEC	 	United States Securities and Exchange Commission	
SERC	 	Southeastern Electric Reliability Council/ Entergy	
SFAS	 	Statement of Financial Accounting Standards issued by the FASB	
SFAS 71	 	SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”	
SFAS 87	 	SFAS No. 87, “Employers’ Accounting for Pensions”	
SFAS 106	 	SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”	
SFAS 109	 	SFAS No. 109, “Accounting for Income Taxes”	
SFAS 123	 	SFAS No. 123, “Accounting for Stock-Based Compensation”	
SFAS 123R	 	SFAS No. 123 (revised 2004), “Share-Based Payment”	
SFAS 133	 	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”	
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SFAS 140	 	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a replacement of FASB Statement 125”	
SFAS 142	 	SFAS No. 142, “Goodwill and Other Intangible Assets”	
SFAS 143	 	SFAS No. 143, “Accounting for Asset Retirement Obligations”	
SFAS 144	 	SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”	
SIP	 	State Implementation Plan	
SO 2	 	Sulfur dioxide	
SOP	 	Statement of Position issued by the American Institute of Certified Public Accountants	
SOP 90-7	 	Statement of Position 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”	
SPP	 	Southwest Power Pool	
STP	 	South Texas Project — Texas Genco’s nuclear generating facility located in Bay City, TX of which we own a 44% interest	
TCEQ	 	Texas Commission on Environmental Quality	
Texas Genco	 	Texas Genco LLC	
US	 	United States of America	
USEPA	 	US Environmental Protection Agency	
US GAAP	 	Accounting principles generally accepted in the US	
WCP	 	WCP (Generation) Holdings, Inc.	
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PART I
Item 1 — Business
      For purposes of discussing our business in this Business Section of our Annual Report, “we,” “our,” “us,” the “combined company” and the “Company” refer to NRG and Texas Genco on a combined basis, together with their consolidated subsidiaries, after giving effect to the completion of the acquisition of Texas Genco, or the Acquisition. The terms “MW” and “MWh” refer to megawatts and megawatt-hours. The megawatt figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the combined company’s ownership position excluding capacity from inactive/mothballed units as of December 31, 2005. NRG has previously shown gross MWs when presenting its operations. Capacity is tested following standard industry practices. The combined company’s numbers denote saleable MWs net of internal/parasitic load. The term “expected annual baseload generation” refers to the net baseload capacity limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages).
General
      We are a leading wholesale power generation company with a significant presence in many of the major competitive power markets in the United States. We are primarily engaged in the ownership and operation of power generation facilities, purchasing fuel and transportation services to support our power plant operations, and marketing and trading energy, capacity and related products in the competitive markets in which we operate.
      On February 2, 2006, NRG acquired Texas Genco LLC by purchasing all of the outstanding equity interests in Texas Genco. The purchase price of approximately $6.1 billion consisted of approximately $4.4 billion in cash and the issuance of approximately 35.4 million shares of NRG’s common stock valued at approximately $1.7 billion, and we assumed a total of approximately $2.7 billion of Texas Genco’s outstanding debt. The purchase price is subject to adjustment due to acquisition costs. Texas Genco is now a wholly-owned subsidiary of NRG, and will be managed and accounted for as a new business segment to be referred to as NRG Texas.
      As of December 31, 2005, the combined company has a total global portfolio of 235 operating generation units at 61 power generation plants, with an aggregate generation capacity of approximately 24,580 MW. Within the United States, the combined company has a large and geographically diversified power generation portfolio with approximately 22,663 MW of generation capacity in 213 generating units at 53 plants. These power generation facilities are primarily located in our core regions in the ERCOT market (approximately 10,658 MW), and in the Northeast (approximately 7,099 MW), South Central (approximately 2,395 MW) and Western (approximately 1,044 MW) regions of the United States. Our facilities consist primarily of baseload, intermediate and peaking power generation facilities, and also include thermal energy production and energy resource recovery plants. The sale of capacity and power from baseload generation facilities accounts for the majority of our revenues and provides a stable source of cash flow. In addition, our diverse generation portfolio provides us with opportunities to capture additional revenues by selling power into our core regions during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.
      On December 27, 2005, we entered into a definitive agreement with Dynegy, Inc., to acquire Dynegy’s 50% of WCP. When completed this acquisition will give NRG sole ownership of WCP’s 1,800 MW of generation capacity in California. Our disclosures as to MWs and financial information do not include the remaining 50% interest in WCP.
Our Strategy
      Our strategy is to optimize the value of our generation assets while using that asset base as a platform for enhanced financial performance which can be sustained and expanded upon in years to come. We plan to maintain and enhance our position as a leading wholesale power generation company in the United States in a

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cost effective and risk-mitigating manner in order to serve the bulk power requirements of our customer base and other entities that offer load, or otherwise consume wholesale electricity products and services in bulk. Our strategy includes the following elements:
      Increase value from our existing assets. We have a highly diversified portfolio of power generation assets in terms of region, fuel type and dispatch levels. We will continue to focus on extracting value from our portfolio by improving plant performance, reducing costs and harnessing our advantages of scale in the procurement of fuels: a strategy that we have branded “ FOR NRG,” or Focus on ROIC@NRG.
      Pursue intrinsic growth opportunities at existing sites in our core regions. We are favorably positioned to pursue growth opportunities through expansion of our existing generating capacity. We intend to invest in our existing assets through plant improvements, repowering and brownfield development to meet anticipated regional requirements for new capacity. We expect that these efforts will provide more efficient energy, lower our delivered cost, expand our electricity production capability and improve our ability to dispatch economically across sectors of the merit order, including baseload, intermediate and peaking generation.
      Maintain financial strength and flexibility. We remain focused on increasing cash flow and maintaining liquidity and balance sheet strength in order to ensure continued access to capital for growth; enhancing risk-adjusted returns; and providing flexibility in executing our business strategy. We will continue our focus on maintaining operational and financial controls designed to ensure that our financial position remains strong.
      Reduce the volatility of our cash flows through asset-based commodity hedging activities. We will continue to execute asset-based risk management, hedging, marketing and trading strategies within well-defined risk and liquidity guidelines in order to manage the value of our physical and contractual assets. Our marketing and hedging philosophy is centered on generating stable returns from our portfolio of power generation assets while preserving the ability to capitalize on strong spot market conditions and to capture the extrinsic value of our portfolio. We believe that we can successfully execute this strategy by taking advantage of our expertise in the trading and marketing of power and ancillary services, our knowledge of markets, our flexible financial structure and our diverse portfolio of power generation assets.
      Participate in continued industry consolidation. We will continue to pursue selective acquisitions, joint ventures and divestitures to enhance our asset mix and competitive position in our core regions to meet the fuel and dispatch requirements in these regions. We intend to concentrate on acquisition and joint venture opportunities that present attractive risk-adjusted returns. We will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures during the consolidation of the power generation industry in the United States.
Our Competitive Strengths
      Scale and diversity of assets. The combined company has one of the largest and most diversified power generation portfolios in the United States with approximately 22,663 MW of generation capacity in 213 generating units at 53 plants as of December 31, 2005. Our power generation assets are diversified by fuel type, dispatch level and region, which helps mitigate the risks associated with fuel price volatility and market demand cycles. The combined company’s U.S. baseload facilities consist of approximately 8,558 MW of generation capacity and provide the combined company with a significant source of stable cash flow, while the combined company’s intermediate and peaking facilities, with approximately 14,105 MW of generation capacity, provide the combined company with opportunities to capture the significant upside potential that can arise from time to time during periods of high demand. In addition, approximately 10% of the combined company’s domestic generation facilities have dual or multiple fuel capability, which allows most of these plants to dispatch with the lowest cost fuel option.

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      The following chart demonstrates the diversification of the combined company’s generation assets:

 	 	
(1) 	Reflects only domestic generation capacity; 19 MW of wood-fired generation capacity not shown.	
     Stability of future cash flows. We have sold forward a significant amount of our expected baseload generation capacity for 2006 and 2007. As of December 31, 2005 the company has sold forward an average of 77% of its baseload generation in the Texas (ERCOT) market for 2006 through 2009. As of the same date, the combined company sold an average of 78% of its expected annual baseload generation in the SERC — Entergy market for 2006 through 2009, and approximately 76% of its expected annual baseload generation in the Northeast region for 2006. In addition, as of December 31, 2005, the combined company purchased forward under fixed price fuel contracts (with contractually-specified price escalators) to provide fuel for approximately 81% of its expected baseload coal generation output from 2006 to 2009.
      Favorable market dynamics for baseload power plants. As of December 31, 2005, approximately 39% of the company’s domestic generation capacity has been fueled by coal or nuclear fuel. In many of the competitive markets where we operate, the price of power typically is set by the marginal costs of natural gas-fired and oil-fired power plants. These oil and gas fired plants currently have substantially higher variable costs than our solid fuel baseload power plants. As a result of our lower marginal cost for baseload coal and nuclear generation assets, we expect such assets to generate power nearly 100% of the time they are available.
      Locational advantages. Many of our generation assets are located within densely populated areas that are characterized by significant constraints on the transmission of power from generators outside the region. Consequently, these assets are able to benefit from the higher prices that prevail for energy in these markets during periods of transmission constraints. The Company has generation assets located within New York City, southwestern Connecticut, Houston and the Los Angeles and San Diego load basins, all areas with constraints on the transmission of electricity. This allows us to capture additional revenues through offering capacity to retail electric providers and other entities serving load within the transmission constrained areas, selling power at prevailing market prices during periods of peak demand and providing ancillary services in support of system reliability.

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Performance Metrics
      The following table contains a summary of NRG’s North American power generation revenues from majority-owned subsidiaries for the year 2005 (figures for our Texas facilities are not included):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Alternative	 	 	 	 	 	 	 	
 	 	Energy	 	 	Capacity	 	 	Energy	 	 	 	 	Other	 	 	Total	 	
Region	 	Revenues	 	 	Revenues	 	 	Revenues	 	 	O&M Fees	 	Revenues***	 	 	Revenues	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Northeast	 	$	1,444	 	 	$	291	 	 	$	—	 	 	$	—	 	 	$	(181	)	 	$	1,554	 	
South Central	 	 	330	 	 	 	186	 	 	 	—	 	 	 	—	 	 	 	36	 	 	 	552	 	
Western*	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	
Other	 	 	11	 	 	 	5	 	 	 	2	 	 	 	—	 	 	 	(3	)	 	 	15	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total North America Power Generation**	 	$	1,786	 	 	$	482	 	 	$	2	 	 	$	—	 	 	$	(148	)	 	$	2,122	 	

 	 	 	
 	* 	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 21 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 tables below present the North American power generation performance metrics for owned assets discussed above for the years ended December 31, 2005 and December 31, 2004 (figures for our Texas facilities are not included):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31, 2005	 	
 	 	 	 	
 	 	 	 	Annual	 	 	 	
 	 	 	 	Net	 	 	Equivalent	 	 	Average Net	 	 	 	
 	 	Net Owned	 	 	Generation	 	 	Availability	 	 	Heat Rate	 	 	Net Capacity	 	
Region	 	Capacity (MW)	 	 	(MWh)	 	 	Factor	 	 	Btu/KWh	 	 	Factor	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Northeast*	 	 	7,099	 	 	 	15,251,449	 	 	 	87.2%	 	 	 	11,146	 	 	 	22.9%	 	
South Central	 	 	2,395	 	 	 	10,116,622	 	 	 	90.9%	 	 	 	10,518	 	 	 	50.6%	 	
Western**	 	 	1,044	 	 	 	1,588,962	 	 	 	86.5%	 	 	 	11,109	 	 	 	18.0%	 	
Other North America	 	 	1,467	 	 	 	247,721	 	 	 	90.6%	 	 	 	14,297	 	 	 	3.4%	 	
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 	 	Year Ended December 31, 2004	 	
 	 	 	 	
 	 	 	 	Annual	 	 	 	
 	 	 	 	Net	 	 	Equivalent	 	 	Average Net	 	 	 	
 	 	Net Owned	 	 	Generation	 	 	Availability	 	 	Heat Rate	 	 	Net Capacity	 	
Region	 	Capacity (MW)	 	 	(MWh)	 	 	Factor	 	 	Btu/KWh	 	 	Factor	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Northeast*	 	 	7,099	 	 	 	13,205,040	 	 	 	85.6%	 	 	 	10,823	 	 	 	19.8%	 	
South Central	 	 	2,395	 	 	 	10,470,786	 	 	 	92.1%	 	 	 	10,494	 	 	 	52.9%	 	
Western**	 	 	1,044	 	 	 	2,291,844	 	 	 	88.4%	 	 	 	10,624	 	 	 	25.6%	 	
Other North America***	 	 	1,467	 	 	 	147,376	 	 	 	97.3%	 	 	 	N/A	 	 	 	2.4%	 	

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

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

*** 	Excludes operations for Kendall, McClain and Batesville which were sold during 2004.	
     The tables below present the Australian power generation performance metrics discussed above for the years ended December 31, 2005 and December 31, 2004:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31, 2005	 	
 	 	 	 	
 	 	 	 	Annual	 	 	 	
 	 	 	 	Net	 	 	Equivalent	 	 	Average Net	 	 	 	
 	 	Net Owned	 	 	Generation	 	 	Availability	 	 	Heat Rate	 	 	Net Capacity	 	
Region	 	Capacity (MW)	 	 	(MWh)	 	 	Factor	 	 	Btu/KWh	 	 	Factor	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Flinders Northern Power Station	 	 	480	 	 	 	3,990,642	 	 	 	95.8%	 	 	 	10,900	 	 	 	94.9%	 	
Flinders Playford Power Station	 	 	220	 	 	 	458,180	 	 	 	57.9%	 	 	 	15,900	 	 	 	23.8%	 	
Gladstone*	 	 	605	 	 	 	2,808,335	 	 	 	93.3%	 	 	 	10,300	 	 	 	53.0%	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31, 2004	 	
 	 	 	 	
 	 	 	 	Annual	 	 	 	
 	 	 	 	Net	 	 	Equivalent	 	 	Average Net	 	 	 	
 	 	Net Owned	 	 	Generation	 	 	Availability	 	 	Heat Rate	 	 	Net Capacity	 	
Region	 	Capacity (MW)	 	 	(MWh)	 	 	Factor	 	 	Btu/KWh	 	 	Factor	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Flinders Northern Power Station	 	 	480	 	 	 	3,924,196	 	 	 	93.2%	 	 	 	11,400	 	 	 	93.1%	 	
Flinders Playford Power Station	 	 	220	 	 	 	365,642	 	 	 	46.0%	 	 	 	16,300	 	 	 	18.9%	 	
Gladstone*	 	 	605	 	 	 	2,879,236	 	 	 	83.2%	 	 	 	10,200	 	 	 	54.2%	 	

* 	Includes 37.5% of the generation owned through our Gladstone Unincorporated Joint Venture.	
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Generation Asset Overview
      We have a significant power generation presence in many of the major competitive power markets of the United States as set out below:

     Texas (ERCOT)
      As of December 31, 2005, Texas Genco’s generation assets in the ERCOT market consisted of approximately 5,178 MW of baseload generation assets and approximately 5,480 MW of intermediate, cyclic and peaking natural gas-fired assets. We expect that the combined company will realize a substantial majority of its revenue and cash flow from the sale of power from its three baseload power plants located in the ERCOT market that use solid fuel: W. A. Parish (coal), Limestone (lignite and PRB coal) and an undivided 44% interest in two nuclear generation units at STP (nuclear fuel). Because plants are generally dispatched in order of lowest operating cost, and approximately 73% of the net generation capacity in the ERCOT market was natural gas-fired, we expect these three baseload plants to operate nearly 100% of the time (subject to planned and forced outages) due to their low marginal costs relative to natural gas-fired plants.
      The following table summarizes the ERCOT baseload forward power sales and natural gas swap agreements that extend beyond December 31, 2005. The amounts summarized below reflect forward sales volumes and average prices as of December 31, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	Annual	 	 	Annual	 	
 	 	 	 	 	 	 	 	 	 	 	 	Average for	 	 	Average for	 	
 	 	2006	 	 	2007	 	 	2008	 	 	2009	 	 	2010	 	 	2006-2007	 	 	2006-2010	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Baseload Capacity (MW)	 	 	5,294	 	 	 	5,340	 	 	 	5,340	 	 	 	5,340	 	 	 	5,340	 	 	 	5,317	 	 	 	5,331	 	
Total Baseload Sales (MW) (1)	 	 	4,375	 	 	 	4,267	 	 	 	4,157	 	 	 	3,449	 	 	 	1,395	 	 	 	4,321	 	 	 	3,529	 	
Percentage Baseload Capacity Sold Forward	 	 	83	%	 	 	80	%	 	 	78	%	 	 	65	%	 	 	26	%	 	 	81	%	 	 	66	%	
Weighted Average Forward Price ($ per MWh) (2)	 	$	44	 	 	$	39	 	 	$	41	 	 	$	47	 	 	$	51	 	 	$	41	 	 	$	43	 	
Total Revenues Sold Forward ($ in millions) (2)	 	$	1,690	 	 	$	1,443	 	 	$	1,505	 	 	$	1,434	 	 	$	621	 	 	$	1,566	 	 	$	1,338	 	

(1) 	Includes amounts under fixed price firm and non-firm power sales contracts and amounts financially hedged under natural gas swap contracts. The forward natural gas swap quantities are reflected in equivalent MW and are derived by first dividing the quantity of MMBtu of natural gas hedged by the forward market heat rate (in MMBtu/ MWh, mid-point of the bid and offer as quoted by	
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 	brokers in the market of the relevant Electric Reliability Council of Texas zones as of December 30, 2005) to arrive at the equivalent MWh hedged which is then divided by 8,760 to arrive at MW hedged.	

(2) 	Includes amounts under fixed price power sales contracts and amounts financially hedged under natural gas swap contracts.	

 	Northeast	
      As of December 31, 2005, approximately 7,099 MW of NRG’s generation capacity consisted of power plants in the Northeast region of the United States, including power plants within the control areas of the New York Independent System Operator, or NYISO, the ISO-New England, Inc., or ISO-NE, and the PJM Interconnection LLC., or PJM. Certain of these assets are located in transmission constrained areas, including approximately 1,394 MW of in-city New York City generation capacity and approximately 538 MW of southwest Connecticut generation capacity. As of December 31, 2005, NRG’s generation assets in the Northeast region consisted of approximately 1,876 MW of baseload generation assets and approximately 5,223 MW of intermediate and peaking assets.
      The following table summarizes Northeast’s baseload forward power sales that extend beyond December 31, 2005. The amounts summarized below reflect forward sales volumes and average prices as of December 31, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	Annual	 	
 	 	 	 	 	 	 	 	 	 	 	 	Average for	 	
 	 	2006	 	 	2007	 	 	2008	 	 	2009	 	 	2010	 	 	2006-2007	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Baseload Capacity (MW)	 	 	1,876	 	 	 	1,876	 	 	 	1,876	 	 	 	1,876	 	 	 	1,876	 	 	 	1,876	 	
Total Baseload Sales (MW)	 	 	1,410	 	 	 	608	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,009	 	
Percentage Baseload Capacity Sold Forward	 	 	75	%	 	 	32	%	 	 	—	%	 	 	—	%	 	 	—	%	 	 	54	%	
Weighted Average Forward Price ($ per MWh)	 	$	72	 	 	$	76	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	74	 	
Total Revenues Sold Forward ($ in millions)	 	$	885	 	 	$	406	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	645	 	

 	South Central	
      As of December 31, 2005, NRG owned approximately 2,395 MW of generation capacity in the South Central region of the United States, making NRG the third largest generator in the Southeastern Electric Reliability Council/ Entergy, or SERC-Entergy, region. NRG’s generation assets in the South Central region consisted of approximately 1,489 MW of baseload generation assets and 906 MW of intermediate and peaking assets. NRG’s primary asset is the Big Cajun II coal-fired plant near Baton Rouge, where NRG has approximately 1,489 MW of generation capacity.
      The following table summarizes South Central’s baseload forward power sales that extend beyond December 31, 2005. The amounts summarized below reflect forward sales volumes and average prices as of December 31, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	Annual	 	 	Annual	 	
 	 	 	 	 	 	 	 	 	 	 	 	Average for	 	 	Average for	 	
 	 	2006	 	 	2007	 	 	2008	 	 	2009	 	 	2010	 	 	2006-2007	 	 	2006-2010	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Baseload Capacity (MW)	 	 	1,489	 	 	 	1,489	 	 	 	1,489	 	 	 	1,489	 	 	 	1,489	 	 	 	1,489	 	 	 	1,489	 	
Total Baseload Sales (MW)(1)	 	 	1,150	 	 	 	1,097	 	 	 	1,088	 	 	 	1,015	 	 	 	1,008	 	 	 	1,124	 	 	 	1,072	 	
Percentage Baseload Capacity Sold Forward	 	 	77	%	 	 	74	%	 	 	73	%	 	 	68	%	 	 	68	%	 	 	75	%	 	 	72	%	
Weighted Average Forward Price ($ per MWh)	 	$	33	 	 	$	32	 	 	$	33	 	 	$	34	 	 	$	36	 	 	$	33	 	 	$	34	 	
Total Revenues Sold Forward ($ in millions)	 	$	307	 	 	$	308	 	 	$	314	 	 	$	303	 	 	$	316	 	 	$	307	 	 	$	310	 	

(1) 	Total Baseload Sales volumes for South Central are estimated volumes using historical load information.	

 	Western	
      As of December 31, 2005, NRG’s assets in the Western Electricity Coordinating Council, or WECC, the power market for the West Coast of the United States, included approximately 1,044 MW of generation

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capacity, most of it in NRG’s 50% interest in WCP Holdings. NRG’s generation assets in the Western region consisted of approximately 1,044 MW of intermediate and peaking assets. As part of NRG’s strategy of optimizing NRG’s asset base, NRG retired approximately 265 MW of additional gross generation capacity at the Long Beach generating facility on January 1, 2005. On December 27, 2005, NRG entered into a purchase and sale agreement to acquire Dynegy’s 50% ownership interest in WCP Holdings to become the sole owner of power plants totaling approximately 1,800 MW of generation capacity in the Western region. On March 1, 2006, FERC issued an order authorizing the transaction, pursuant to section 203 of the Federal Power Act.
 	 	
 	Australia	
      As of December 31, 2005, NRG owned approximately 1,305 MW of coal fired, primarily base load generation plants in the Australian National Electricity Market (NEM) — 700 MW in the South Australian region (NRG Flinders) and 605 MW in the Queensland Region (Gladstone). NRG Flinders is a merchant generation business that derives revenue from bidding its output into the NEM, by trading the plant as a portfolio, selling derivative hedges that are not plant specific and supplying minor retail sales via contract. 180 MW of gas fired power contracted from Osborne under a long-term PPA is also traded as part of the portfolio. A hedge book is maintained such that the short to medium term revenue is secured via hedge levels up to and in the order of 75-80% of the plant output. The current book is underpinned by a medium term hedge with a major South Australian retailer. The Gladstone assets are owned through an unincorporated joint venture with other investors and NRG does not have unilateral control over management of the assets. Gladstone Power Station is fully contracted through 2029 via a PPA and a capacity purchase agreement with Boyne Smelter Limited and Enertrade, respectively. Enertrade is a state owned company that trades the excess power in the NEM.
 	 	
 	Other	
      As of December 31, 2005, NRG had net ownership in approximately 1,467 MW of additional generating capacity in the United States. In addition to these traditional power generation facilities, NRG also owns thermal and chilled water businesses that generate approximately 1,225 MW thermal equivalents, as well as resource recovery facilities, as described below. NRG also owns interests in power plants having a generation capacity of approximately 611 MW from a hydro plant in Brazil and coal plants adjacent to our coal mines in Germany.
Power Marketing and Commercial Operations
      We seek to maximize profitability and manage cash flow volatility through the marketing, trading and sale of energy, capacity and ancillary services into spot, intermediate and long-term markets and through the active management and trading of emissions credits, fuel supplies and transportation-related services. Our principal objectives are the realization of the full market value of our asset base, including the capture of extrinsic value, the management and mitigation of commodity market risk, and the reduction of cash flow volatility over time.
      We enter into power sales and hedging arrangements via a wide range of products and contracts, including power purchase agreements, fuel supply contracts, capacity auctions, natural gas swap agreements and other financial instruments. The power purchase agreements we enter into require us to deliver MWh of power to our counterparties. Natural gas swap agreements and other financial instruments hedge the price we will receive for power to be delivered in the future.
      Before NRG acquired it, Texas Genco’s capital structure permitted the grant of second priority liens on its assets as security for Texas Genco’s obligations under certain long-term power sales agreements and related hedges. The Credit Agreement for NRG’s senior secured debt and the Indentures for NRG’s high yield notes, which became effective as of February 2, 2006, allow these arrangements to remain in place. In addition, the new debt instruments also permit us to grant second priority liens on our other assets in the United States in order to secure obligations under power sales agreements and related hedges, within certain limits. The seven trading counterparties of Texas Genco who held second priority liens on Texas Genco’s assets as of

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February 2, 2006, have been offered a second priority lien on NRG’s other assets under the new structure, as additional collateral. Going forward, NRG anticipates that it will use the second lien structure to reduce the amount of cash collateral and letters of credit that it may otherwise be required to post from time to time to support its obligations under long term power sales and related hedges.
      As of February 28, 2006, our net mark-to-market exposure on the hedges that are subject to the second lien structure was $1.9 billion. The following table summarizes the utilization of the second lien structure as of December 31, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	12 Months Starting	 	
 	 	 	 	
 	 	Jan 1,	 	 	Jan 1,	 	 	Jan 1,	 	 	Jan 1,	 	 	Jan 1,	 	
 	 	2006	 	 	2007	 	 	2008	 	 	2009	 	 	2010	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equivalent Net Sales secured by Second Lien Structure (1)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	In MWh	 	 	2,081	 	 	 	3,067	 	 	 	2,513	 	 	 	2,999	 	 	 	1,395	 	
 	As a percentage of net baseload capacity in collateral pool as of February 2, 2006	 	 	30	%	 	 	44	%	 	 	36	%	 	 	43	%	 	 	20	%	

(1) 	Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.	
     Our largest customer under the second lien structure is J. Aron & Co., or J. Aron. The agreements with J. Aron extend through December 31, 2010, and account for approximately 26% of NRG’s baseload generation in Texas and approximately 16% of our total baseload capacity, as measured in MWh through 2010.
      In addition to the second lien described above, NRG also provides cash collateral and letters of credit to secure its obligations under hedge agreements and other power marketing contracts. As of December 31, 2005, the combined company, after giving effect to the Acquisition, had posted cash collateral (including letters of credit) to support commercial operations totaling $1.2 billion. The following table summarizes, as of December 31, 2005, the combined company collateral posted by credit rating.
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Letters of	 	 	 	 	Collateral	 	
Credit Rating	 	Credit	 	 	Cash	 	 	Posted	 	
 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
A– and above	 	$	616	 	 	$	392	 	 	$	1,008	 	
BBB– through BBB+	 	 	99	 	 	 	39	 	 	 	138	 	
Below BBB-	 	 	7	 	 	 	4	 	 	 	11	 	
Not Rated(1)	 	 	38	 	 	 	3	 	 	 	41	 	
 	 	 	 	 	 	 	 	 	 	
Total	 	$	760	 	 	$	438	 	 	$	1,198	 	

 	 	
(1) 	Not Rated indicates that no rating has been issued, or that an external rating agency (for example, Standard & Poor’s or Moody’s) does not rate a particular obligation as a matter of policy. The Not Rated row above consists of collateral posted to 17 counterparties, mainly gas producers.	
Fuel Supply and Transportation
      Our fuel requirements consist primarily of nuclear fuel and various forms of fossil fuel including oil, natural gas and coal (including lignite). We obtain our oil, natural gas and coal from multiple sources. Although fossil fuels are generally available for purchase, 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. We are largely hedged for our domestic coal consumption over the next few years.
      We arrange for the purchase, transportation and delivery of coal for our coal plants via a range of coal purchase agreements, rail and barge transportation agreements and rail car lease arrangements. Coal consumption in 2006 for NRG is expected to be approximately 36 million tons, which would rank us as one of

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the top five coal purchasers in the United States. In addition, approximately 92% of our coal-fired generation benefits from multiple sourcing and transportation alternatives. The Company has approximately 6,100 privately leased or owned rail cars in its transportation fleet. In addition, we intend to enter into contracts for delivery of approximately 2,700 additional rail cars within the next two years of which approximately 2,200 will replace existing rail cars. NRG has entered into rail transportation agreements that provide for substantially all of its rail transportation requirements through 2009.
      STP satisfies its fuel supply requirements by acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride, for enrichment of uranium hexafluoride and for fabrication of nuclear fuel assemblies. Through our subsidiary Texas Genco, we are party to a number of contracts covering a portion of the fuel requirements of STP for uranium, conversion and enrichment services and fuel fabrication. The table below summarizes the nuclear fuel situation at STP through the major processes:
 	 	 	 	 	 	 	
 	 	Process	 	Supplier(s)	 	Procurement Status	
 	 	 	 	 	 	 	
Step 1	 	Yellow cake U(3)O(8). Conversion to uranium hexafluoride (UF(6))	 	Contracts with Cameco (Canada) and Cogema/Arriba (France) combine these steps.	 	100% covered through mid-2011 and then 25% covered through 2021.	
Step 2	 	Enrichment of U235 content	 	Urenco (Germany), Cogema/ Arriba (France), Louisiana Enrichment Services, or LES  (1)  (joint venture between Westinghouse & Urenco).	 	Urenco and Cogema contracts cover through mid-2008. Contract with Urenco/LES through 2027/2028.	
Step 3	 	Fabrication of fuel rods	 	Westinghouse.	 	Contract covers life of operating license.	

(1) 	Enrichment by LES assumes successful completion of LES licensing and construction of facility in New Mexico.	
Financial Information About Segments and Geographic Areas
      For financial information on NRG’s operations on a geographical and on a segment basis, see Item 15 — Note 21 to the Consolidated Financial Statements.
Dispositions of Non-Strategic Assets
      We continued to market our interest in our remaining non-core assets during 2005. 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 2005 are summarized in the following chart:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Closing	 	 	 	 	Gain/(Loss)	 	 	Debt	 	
Asset (Location)	 	Type	 	 	Segment	 	 	Date	 	 	Proceeds	 	 	on Disposition	 	 	Reduction	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	(In millions)	 	
Enfield, England	 	 	Equity investment	 	 	 	Other International	 	 	 	4/1/2005	 	 	$	65	 	 	$	12	 	 	$	—	 	
Kendall, IL	 	 	Equity investment	 	 	 	Other North America	 	 	 	8/8/2005	 	 	 	5	 	 	 	4	 	 	 	—	 	
Northbrook New York, NY and Northbrook Energy (Multi- state)	 	 	Discontinued operation	 	 	 	Other North America	 	 	 	8/11/2005	 	 	 	36	 	 	 	12	 	 	 	44	 	
Bourbonnais, IL	 	 	Land sale	 	 	 	Other North America	 	 	 	8/31/2005	 	 	 	2	 	 	 	—	 	 	 	—	 	
Kaufman, TX	 	 	Land sale	 	 	 	Other North America	 	 	 	12/22/2005	 	 	 	5	 	 	 	4	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total	 	 	 	 	 	 	 	 	 	 	 	 	 	$	113	 	 	$	32	 	 	$	44	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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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. In 2002, a number of factors including 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. All NRG entities have emerged from chapter 11 as of December 31, 2005. 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.
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.
Significant Customers
 	 	
 	Reorganized NRG (excluding Texas Genco)	
      For the year ended December 31, 2005 we derived approximately 50.2% of total revenues for majority owned operations from two customers: NYISO accounted for 35.6% and ISO-NE accounted for 14.6%. We account for the revenues attributable to these customers as part of our Northeast segment.
      For the year ended December 31, 2004, we derived approximately 37.8% of our total revenues from majority-owned operations from two customers. NYISO accounted for 28.6% and ISO New England accounted for 9.2%. We account for these revenues attributable to NYISO and ISO New England as part of our Northeast segment.
      For the period December 6, 2003 through December 31, 2003, we derived approximately 39.4% of our total revenues from majority-owned operations from two customers: NYISO accounted for 26.8% and ISO New England accounted for 12.6%. Revenues from NYISO and ISO New England are included in our Northeast segment.
 	 	
 	Predecessor Company	
      For the period from January 1, 2003 through December 5, 2003, sales to one customer, NYISO, accounted for 33.4% of our total revenues from majority-owned operations.
Seasonality and Price Volatility
      Annual and quarterly operating results can be significantly affected by weather and energy commodity price volatility. Significant other events, such as the demand for natural gas, interruptions in fuel supply infrastructure 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, power price 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.

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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 suppliers and transportation 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 late 2005 due to infrastructure damage caused by Hurricanes Katrina and Rita. Additionally, throughout 2005, oil prices were extremely volatile due to hurricane damage, geo-political uncertainty in the Middle East and increased global oil demand. Issues related to the sources and availability of raw materials are fairly uniform across our business segments.
Plant Operations
      We provide overall support services to our generation facilities to ensure that high-level performance goals are developed, best practices are shared and resources are appropriately balanced and allocated to get the best results for us. Performance goals are set for equivalent forced outage rates, or EFOR, availability, procurement costs, operating costs and safety.
      The functional areas included in this organization include safety and security, engineering, project management, construction services, and purchasing. These services also include overall facilities management, operations strategic planning and the development and dissemination of consistent policies and practices relating to plant operations.
Environmental Controls
      Between 2002 and 2007, NRG has made, and will continue to make, investments that we believe will total approximately $125 million in its coal-fired plants in the Northeast region of the United States so that they can burn low sulfur coal from the Powder River Basin in Wyoming and Montana. These improvements have not only led to significant reductions in sulfur dioxide emissions, but have also improved the operational flexibility and financial performance of these plants. During the same period, NRG expects to invest approximately $32 million in its coal plants in the South Central region for NO x  burners and over fired air, which have led to reductions in NO x . A significant portion of this investment may be recovered from NRG’s cooperative customers. Texas Genco and its predecessors invested over $700 million in NO x  reduction initiatives since 1999 to ensure both regulatory compliance and continued performance, and we estimate we will invest approximately $70 million in additional capital expenditures in these assets to meet pollution control requirements from 2006 to 2014.

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      The following table summarizes the key existing and current forecasted plans as to environmental controls on our coal-fired units. Also see our discussion on Environmental Matters further within this Business Section:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	SO2	 	 	NOx	 	 	Hg	 	 	Particulate	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Control	 	 	Install	 	 	Control	 	 	Install	 	 	Control	 	 	Install	 	 	Control	 	 	Install	 	
Units	 	Equipment	 	 	Date	 	 	Equipment	 	 	Date	 	 	Equipment	 	 	Date	 	 	Equipment	 	 	Date	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Huntley 67	 	 	Wet FGD(1)	 	 	 	2013	 	 	 	SNCR	 	 	 	2010	 	 	 	FF-ACI(2)	 	 	 	2011	 	 	 	ESP	 	 	 	1973	 	
Huntley 68	 	 	Wet FGD(1)	 	 	 	2013	 	 	 	SNCR	 	 	 	2011	 	 	 	FF-ACI(2)	 	 	 	2009	 	 	 	ESP	 	 	 	1973	 	
Dunkirk 1	 	 	None	 	 	 	—	 	 	 	SNCR	 	 	 	2010	 	 	 	FF-ACI(2)	 	 	 	2010	 	 	 	ESP	 	 	 	1974	 	
Dunkirk 2	 	 	None	 	 	 	—	 	 	 	SNCR	 	 	 	2011	 	 	 	FF-ACI(2)	 	 	 	2011	 	 	 	ESP	 	 	 	1974	 	
Dunkirk 3	 	 	None	 	 	 	—	 	 	 	SNCR	 	 	 	2010	 	 	 	FF-ACI(2)	 	 	 	2011	 	 	 	ESP	 	 	 	1975	 	
Dunkirk 4	 	 	None	 	 	 	—	 	 	 	SNCR	 	 	 	2011	 	 	 	FF-ACI(2)	 	 	 	2010	 	 	 	ESP	 	 	 	1976	 	
Indian River 1	 	 	In-Duct Scrubber	 	 	 	2012	 	 	 	SNCR & LNB (3)	 	 	 	2008	 	 	 	Co-Benefit of Scrubbers	 	 	 	2012	 	 	 	ESP (IR1-3)	 	 	 	1976	 	
Indian River 2	 	 	In-Duct Scrubber	 	 	 	2013	 	 	 	SNCR & LNB (3)	 	 	 	2008	 	 	 	Co-Benefit of Scrubbers	 	 	 	2013	 	 	 	ESP (IR1-3)	 	 	 	1976	 	
Indian River 3	 	 	In-Duct Scrubber	 	 	 	2012	 	 	 	LNB(3) & SNCR	 	 	 	2008	 	 	 	Co-Benefit of Scrubbers	 	 	 	2012	 	 	 	ESP (IR1-3)	 	 	 	1980	 	
 	 	 	 	 	 	 	 	 	 	 	upgrade	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Indian River 4	 	 	Dry Scrubber	 	 	 	2011	 	 	 	LNB(3) & SNCR	 	 	 	2008	 	 	 	Co-Benefit of Scrubbers	 	 	 	2011	 	 	 	ESP (IR1-3)	 	 	 	1980	 	
 	 	 	 	 	 	 	 	 	 	 	upgrade	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Big Cajun II 1	 	 	Dry Scrubber	 	 	 	2011	 	 	 	None	 	 	 	 	 	 	 	ACI(2)	 	 	 	2012	 	 	 	ESP	 	 	 	1981	 	
Big Cajun II 2	 	 	Dry Scrubber	 	 	 	2010	 	 	 	SCR(4)	 	 	 	2010	 	 	 	ACI(2)	 	 	 	2011	 	 	 	ESP	 	 	 	1981	 	
Big Cajun II 3	 	 	Dry Scrubber	 	 	 	2013	 	 	 	SCR(4)	 	 	 	2013	 	 	 	ACI(2)	 	 	 	2014	 	 	 	ESP	 	 	 	1983	 	
Limestone	 	 	FGD	 	 	 	1986-87	 	 	 	LNB/OFA(3)	 	 	 	2000-01	 	 	 	Co-Benefit of Scrubbers	 	 	 	—	 	 	 	ESP	 	 	 	1986-87	 	
WA Parish 5,6,7	 	 	None	 	 	 	NA	 	 	 	SCR & LNB/OFA (3)	 	 	 	2000-04	 	 	 	None	 	 	 	—	 	 	 	FF	 	 	 	1988	 	
WA Parish 8	 	 	FGD	 	 	 	1982	 	 	 	SCR & LNB/OFA (3)	 	 	 	2000-04	 	 	 	Co-Benefit of Scrubber	 	 	 	—	 	 	 	FF	 	 	 	1988	 	

(1) 	FGD stands for Flue Gas Desulfurization	
 	 	
(2) 	FF-ACI stands for Fabric Filter with Activated Carbon Injection	
 	 	
(3) 	LNB/ OFA stands for Low NOx Burner with Over Fire Air	
 	 	
(4) 	SCR stands for Selective Catalytic Reduction	
Performance Improvement and Cost and Process Control Initiatives
      In May 2005, NRG announced FORNRG, a comprehensive cost and margin improvement program, consisting of a large number of asset, portfolio and headquarters-specific targeted initiatives. This effort has been branded as “FORNRG,” or Focus on ROIC@NRG. Projects are focused on improving plant performance, reducing purchasing and other costs and streamlining processes. A large number of initiatives are currently underway in plant operations including forced outage reductions and heat rate improvements at NRG’s major base load facilities. Additional initiatives are underway at our regional and headquarter offices as well. The ultimate objective is to produce $100 million of recurring benefits by 2008.
      There have been a number of parallel improvement programs underway at Texas Genco, which have focused on streamlining processes, right sizing the organization and running efficient operations. As part of the integration of Texas Genco into NRG, we are comparing best practices and results between NRG and Texas Genco, and we are combining purchasing programs and incorporating Texas Genco processes under the  FOR NRG program.
Regional Business Descriptions
      The combined company is organized into business units as described below, with each of our core regions operating as a separate unit.
 	 	
 	TEXAS (ERCOT)	
      NRG’s largest business unit is located in the Texas (ERCOT) region of the United States and is comprised of investments in generation facilities located in the physical control areas of the ERCOT-ISO. These assets were acquired on February 2, 2006 as part of the Texas Genco Acquisition.

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Operating Strategy
      Our business in the ERCOT region is comprised of two fundamental sets of assets: a regionally diverse set of three large solid-fuel baseload plants and a set of generally older gas-fired plants located in and around Houston. Our operating strategy to maximize value and opportunity across these two sets of assets is four pronged: (1) to ensure the availability of the baseload plants to fulfill their commercial obligations under long-term forward sales contracts already in place, (2) to manage the gas assets for profitability while ensuring the reliability and flexibility of power supply to the Houston market, (3) to take advantage of our skill sets and market/regulatory knowledge to grow the business through incremental capacity uprates and brownfield development of solid-fuel baseload units and (4) to play a leading role in the development of the ERCOT market by active membership and participation in market and regulatory issues.
      It is our strategy to sell forward up to 80% of our solid-fuel baseload capacity in ERCOT under long-term contracts. Accordingly, our primary focus will be to keep these solid-fuel baseload units running efficiently. The generation performance by fuel type for the recent three-year period is as shown below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Net Generation (MWh)	 	
 	 	 	 	
 	 	2005	 	 	2004	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	
 	 	(In thousands)	 	
Coal	 	 	31,299	 	 	 	31,222	 	 	 	29,754	 	
Gas	 	 	6,806	 	 	 	7,701	 	 	 	10,701	 	
Nuclear	 	 	6,412	 	 	 	6,580	 	 	 	4,843	 	
 	 	 	 	 	 	 	 	 	 	
 	Total	 	 	44,517	 	 	 	45,503	 	 	 	45,298	 	
 	 	 	 	 	 	 	 	 	 	
      On the gas-fired asset side, we will continue a dual path of contracting forward a significant portion of gas-fired capacity one to two years out while holding a portion for back-up in case there is an operational issue with one of the baseload units. For the gas-fired capacity sold forward, we offer a range of products including “virtual units” where the customer has the right to dispatch capacity as the customer needs in order to meet their physical load requirements. For the gas-fired capacity that we will continue to sell commercially into the market, we will focus on making this capacity available to the market whenever it is economic to run.
      Texas Genco’s growth efforts to date have been focused on adding incremental capacity to existing units — such as the 99 MW uprate at Limestone 2 in the spring of 2006. We will continue this effort with exploration of some additional potential opportunities at W. A. Parish as well as some scheduled uprates at STP. We have also launched a broader brownfield development initiative where we will evaluate opportunities to take advantage of our current power plant sites and other land we own as well as our deep market, regulatory, and environmental knowledge to consider the development of new solid fuel baseload units.

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Facilities
      The following table describes Texas Genco’s electric power generation plants and generation capacity as of December 31, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net Generation	 	 	 	
 	 	 	 	 	 	Capacity	 	 	 	
Generation Sites	 	Location	 	 	% Owned	 	 	(MW)(1)	 	 	Primary Fuel Type(2)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Solid Fuel Baseload Units:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
W. A. Parish(3)	 	 	Thompsons, TX	 	 	 	100	%	 	 	2,463	 	 	Low Sulfur Coal Lignite/Low Sulfur	
Limestone	 	 	Jewett, TX	 	 	 	100	%	 	 	1,614	 	 	 	Coal	 	
South Texas Project(4)	 	 	Bay City, TX	 	 	 	44	%	 	 	1,101	 	 	 	Nuclear	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Solid Fuel Baseload	 	 	 	 	 	 	 	 	 	 	5,178	 	 	 	 	 	
Operating Natural Gas-Fired Units:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cedar Bayou	 	 	Chambers County, TX	 	 	 	100	%	 	 	1,498	 	 	 	Natural Gas	 	
T. H. Wharton	 	 	Houston, TX	 	 	 	100	%	 	 	1,025	 	 	 	Natural Gas	 	
W. A. Parish (Natural gas) (3)	 	 	Thompsons, TX	 	 	 	100	%	 	 	1,191	 	 	 	Natural Gas	 	
S. R. Bertron	 	 	Deer Park, TX	 	 	 	100	%	 	 	844	 	 	 	Natural Gas	 	
Greens Bayou	 	 	Houston, TX	 	 	 	100	%	 	 	760	 	 	 	Natural Gas	 	
San Jacinto	 	 	LaPorte, TX	 	 	 	100	%	 	 	162	 	 	 	Natural Gas	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Operating Natural Gas-Fired	 	 	 	 	 	 	 	 	 	 	5,480	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Texas (ERCOT) Region	 	 	 	 	 	 	 	 	 	 	10,658	 	 	 	 	 	

 	 	
(1) 	Actual capacity can vary depending on factors including weather conditions, operational conditions and other factors. ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time. Excludes 3,378 MW of inactive capacity available for redevelopment of which 174 MW of available capacity was sold on November 14, 2005. An additional 461 MW was moved to inactive status as of December 31, 2005.	
 	 	
(2) 	Low sulfur coal is coal mined from the Powder River Basin, a coal-producing area in northeastern Wyoming and southeastern Montana, which coal has low sulfur content relative to most coal from the eastern United States.	
 	 	
(3) 	W. A. Parish has nine units, four of which are baseload coal-fired units and five of which are natural gas-fired units.	
 	 	
(4) 	Generation capacity figure consists of our 44.0% undivided interest in the two units of STP.	
     W.A. Parish. The W. A. Parish plant is one of the largest fossil-fired plants in the United States based on total MWs of generation capacity. The plant is located in the Houston ERCOT zone and was recognized by Platts’ Power Magazine as one of the top power plants in the United States for 2004. This plant’s power generation units include four coal-fired steam generation units with an aggregate generation capacity of 2,463 MW as of December 31, 2005. Two of these units are 649 MW steam units that were placed in commercial service in December 1977 and December 1978, respectively. The other two units are 555 MW and 610 MW steam units that were placed in commercial service in June 1980 and December 1982, respectively. All four units are serviced by two competing railroads that diversify Texas Genco’s coal transportation options at competitive prices. Texas Genco invested approximately $430 million in nitrogen oxide, or NO x , control systems from 1999 to 2004. Each of the four coal-fired units has low- NO x  burners and selective catalytic reduction, or SCR, installed to reduce NO x  emissions. In addition, W. A. Parish Unit 8 has a scrubber installed to reduce sulfur dioxide, or SO 2 , emissions. Plant efficiency projects to be completed by year end 2007 are expected to uprate the net generation capacity of W.A. Parish by 31 MW.
      Limestone. The Limestone plant is a lignite and coal-fired plant located approximately 140 miles northwest of Houston. This plant includes two steam generation units with an aggregate generation capacity of 1,614 MW as of December 31, 2005. The first unit is an 836 MW steam unit that was placed in commercial service in December 1985. The second unit is a 778 MW steam unit that was placed in commercial service in December 1986. Limestone primarily burns lignite from an on-site mine, but also burns low sulfur coal and petroleum coke. This serves to lower average fuel costs by eliminating fuel transportation costs, which can

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represent up to two-thirds of delivered fuel costs for plants of this type. We own the mining equipment and facilities and a portion of the lignite reserves located at the mine. Mining operations are conducted by Texas Westmoreland Coal Co., a single purpose, wholly-owned subsidiary of Westmoreland Coal Company and the owner of a substantial portion of the remaining lignite reserves. Both units have installed low- NO x  burners to reduce NO x  emissions and scrubbers to reduce SO 2  emissions. In the second quarter of 2006 we plan to replace the high pressure and intermediate pressure turbines at Limestone Unit 2, rewinding the generator and replacing the main generator step-up transformer. This work is expected to cost approximately $33 million and to improve generation capacity by 99 MW.
      South Texas Project Electric Generating Station. STP is one of the newest and largest nuclear-powered generation plants in the United States based on total megawatts of generation capacity. This plant is located approximately 90 miles south of downtown Houston, near Bay City, Texas and consists of two generation units each representing approximately 1,250 MW of generation capacity. Plant efficiency projects to be completed by 2007 are expected to uprate the net generation capacity of STP by 73 MW (32 MW net to NRG). STP’s two generation units commenced operations in August 1988 and June 1989, respectively. For the year ended December 31, 2004, STP had a forced outage rate of 0.4% and a 97% capacity factor.
      STP is currently owned as a tenancy in common among NRG and two other co-owners. NRG owns a 44.0% (1,101 MW) interest in STP, the City of San Antonio owns a 40% interest and the City of Austin owns the remaining 16% interest. Each co-owner retains its undivided ownership interest in the two nuclear-fueled generation units and the electrical output from those units. In the event any owner desires to sell all or part of its ownership interest in STP, such sale is subject to a right of first refusal in favor of the other owners. Except for certain plant shutdown and decommissioning costs and NRC licensing liabilities, NRG is severally liable, but not jointly liable, for the expenses and liabilities of STP. The original co-owners of STP organized South Texas Project Nuclear Operating Company, or STPNOC, to operate and maintain STP. STPNOC is managed by a board of directors composed of one director appointed by each of the three co-owners, along with the chief executive officer of STPNOC. STPNOC is the NRC-licensed operator of STP. No single owner controls STPNOC and all decisions must be approved by two or more owners who collectively control more than 60% of the interests. Due to the fact that NRG owns 44% of STP, NRG effectively holds a veto right.
      In connection with the acquisition by Texas Genco of 13.2% of STP from AEP, Texas Genco, LP agreed with AEP that, for a period of ten years from May 19, 2005, Texas Genco, LP would maintain a minimum partners’ equity, determined in accordance with GAAP, of $300 million. This obligation remains in effect as an obligation of NRG.
      The two STP generation units operate under licenses granted by the NRC that expire in 2027 and 2028, respectively. These licenses may be extended for additional 20-year terms if the project satisfies NRC requirements. Adequate provisions exist for long-term on-site storage of spent nuclear fuel throughout the remaining life of the existing STP plant licenses.
Market Framework
      The ERCOT market is one of the nation’s largest and fastest growing power markets. It represents approximately 85% of the demand for power in Texas and covers the whole state, with the exception of the far west (El Paso), a large part of the Texas Panhandle and two small areas in the eastern part of the state. From 1994 through 2004, peak hourly demand in the ERCOT market grew at a compound annual rate of 3.0%, compared to a compound annual rate of growth of 2.1% in the United States for the same period. For 2004, hourly demand ranged from a low of 20,276 MW to a high of 58,506 MW. ERCOT has limited interconnections — currently limited to 856 MW of generation capacity — to other markets in the United States, and wholesale transactions within ERCOT are not subject to regulation by FERC. Any wholesale producer of power that qualifies as a power generation company under the Texas electric restructuring law and that can access the ERCOT electric power grid is allowed to sell power in the ERCOT market at unregulated rates.
      The ERCOT market has experienced significant construction of new generation plants in recent years, with over 20,000 MW of mostly natural gas-fired combined cycle generation capacity added to the market

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since 2000. As of December 31, 2005, aggregate net generation capacity of approximately 81,000 MW existed in the ERCOT market, of which 73% was natural gas-fired. Approximately 20,000 MW, or 25%, was lower marginal cost generation capacity such as coal, lignite and nuclear plants. NRG’s coal and nuclear fuel baseload plants represent approximately 5,178 MW, or 26%, of the total solid fuel baseload net generation capacity in the ERCOT market. ERCOT has established a target equilibrium reserve margin level of approximately 12.5%; the reserve margin as of the latest known information on December 31, 2005 was 16.9%. Construction of new generation plants has been minimal since 2004, and we expect that reserve margins will decrease as demand gradually grows and surpasses recently added supply.
      In the ERCOT market, buyers and sellers enter into bilateral wholesale capacity, power and ancillary services contracts or may participate in the centralized ancillary services market, including balancing energy, which ERCOT administers. In the ERCOT market, a 2004 report by Henwood found that natural gas-fired plants have set the market price of wholesale power more than 90% of the time. As a result, NRG’s lower marginal cost solid-fuel baseload plants are expected to generate power nearly 100% of the time they are available.
      The ERCOT market is divided into five regions or congestion zones (Northeast, North, Houston, South and West), which reflect transmission constraints that limit the amount of power that can flow across zones. NRG’s W. A. Parish plant and all its natural gas-fired plants are located in the Houston zone, NRG’s Limestone plant is located in the North zone and STP is located in the South zone.
      The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council, or NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’ main interconnected power transmission grid. ERCOT is responsible for facilitating reliable operations of the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that power production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike power pools with independent operators in other regions of the country, the ERCOT market is not a centrally dispatched power pool and ERCOT does not procure power on behalf of its members other than to maintain the reliable operations of the transmission system. The ERCOT-ISO also serves as agent for procuring ancillary services for those who elect not to provide their own ancillary services.
      Power sales or purchases from one location to another may be constrained by the power transfer capability between locations. Under current ERCOT protocol, the commercially significant constraints and the transfer capabilities along these paths are reassessed every year and congestion costs are directly assigned to those parties causing the congestion. This has the potential to increase power generators’ exposure to the congestion costs associated with transferring power between zones.
      The PUCT has adopted a rule directing the ERCOT-ISO to develop and implement a wholesale market design that, among other things, includes a day ahead energy market and replaces the existing zonal wholesale market design with a nodal market design that is based on locational marginal prices for power. See “— Regulatory Developments — Regional Businesses — Market Developments — Texas (ERCOT) Region.” One of the stated purposes of the proposed market restructuring is to reduce local (intra-zonal) transmission congestion costs. The market redesign project is expected to take effect in 2009. We expect that implementation of any new market design will require modifications to our procedures and systems. Although we do not expect the combined company’s competitive position in the ERCOT market will be materially adversely affected by the proposed market restructuring, we do not know for certain how the planned market restructuring will affect our revenues, and some of the combined company’s plants in ERCOT may experience adverse pricing effects due to their location on the transmission grid.
PUCT Mandated Auctions
      PUCT regulation required firm entitlements to 15% of NRG’s operating installed generation capacity to be sold at auction through December 31, 2006, at opening bid prices well below NRG’s cost for 2006. On December 7, 2005, Texas Genco filed an application with the PUCT requesting the PUCT to determine that we were no longer required to conduct mandated auctions because 40% or more of the electric power

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consumed by the residential and small commercial customers within the CenterPoint Energy Houston Electric, LLC certificated service area before the onset of customer choice is now provided by nonaffiliated retail electric providers. On February 6, 2006, the Staff of the PUCT reported that ERCOT had performed the analysis and calculations necessary to demonstrate that we have satisfied the 40% threshold. The Staff recommended that the petition be granted and that we be released from any further capacity auction requirements. The administrative law judge issued her proposal for decision, and a decision by the PUCT is expected in March.
 	 	
 	NORTHEAST REGION	
      NRG’s second largest asset base is located in the Northeast region of the United States and is comprised of investments in generation facilities primarily located in the physical control areas of NYISO, the ISO-NE and PJM.
Operating Strategy
      The Northeast region strategy is focused on optimizing the value of our broad and varied generation portfolio in three interconnected and actively traded competitive markets: the NYISO, the ISO-NE and the PJM. In our Northeast markets, load serving entities generally lack their own generation capacity, much of the generation base is aging, and the current ownership of the generation is highly disaggregated. Thus, commodity prices are more volatile on an as-delivered basis than in other regions due to the distances and occasional physical constraints impacting delivery of fuels into the region. In this environment, we seek both to enhance our ability to be the low cost wholesale generator capable of delivering wholesale power to load centers within the region from multiple locations using multiple fuel sources, and to be properly compensated for delivering such wholesale power and related services. The generation performance by fuel type for the recent three-year period is as shown below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Net Generation (MWh)	 	
 	 	 	 	
 	 	2005	 	 	2004	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	
 	 	(In thousands)	 	
Coal	 	 	10,369	 	 	 	10,664	 	 	 	9,783	 	
Oil	 	 	3,158	 	 	 	1,381	 	 	 	1,471	 	
Gas	 	 	1,724	 	 	 	1,160	 	 	 	1,172	 	
 	 	 	 	 	 	 	 	 	 	
 	Total	 	 	15,251	 	 	 	13,205	 	 	 	12,426	 	
 	 	 	 	 	 	 	 	 	 	
      Several of our Connecticut assets are located in transmission-constrained load pockets and have been designated as required to be available to ISO-NE to ensure reliability. These assets are subject to reliability must-run, or RMR, agreements, which are contracts under which we agree to maintain our facilities to be available to run when needed, and are paid for providing these capability services based on our costs. We are focused on capturing the locational value of our plants that are located in or near load centers and inside chronic transmission constraints, in order to improve the economic rationale for repowering of those sites. We do this principally through the advocacy of capacity market reforms, e.g., locational installed capacity markets that generate adequate returns for wholesale power generators.
      We continue to evaluate opportunities to redevelop our existing sites as well as opportunities for acquisitions in the Northeast region. The redevelopment opportunities for our existing sites include expanding sites with high efficiency, intermediate and peaking units, converting coal or oil sites to cleaner technologies, redeveloping existing sites with projects using IGCC technology, as well as reconfiguring the existing sites to burn renewable fuel sources. Redevelopment opportunities have been identified for each site in the Northeast and we have established priorities based on expected financial returns and probability of success. To facilitate redevelopment opportunities, we are pursuing contractual arrangements to support significant redevelopment capital expenditures via direct negotiations with relevant agencies and potential power purchasers as well as through request for proposal processes. We also continue to pursue contractual arrangements to support the

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construction costs of potential new facilities and acquisition opportunities through public auction processes as well as by initiating discussions with various parties on potential opportunities.
Facilities
      As of December 31, 2005, NRG’s facilities in the Northeast region consisted of approximately 7,099 MW of generation capacity, including assets located in transmission constrained areas, such as in-city New York City (1,394 MW) and southwest Connecticut (538 MW). The Northeast region power generation assets are summarized in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generation	 	 	 	
 	 	 	 	 	 	Capacity	 	 	 	
Plant	 	Location	 	 	% Owned	 	 	(MW)*	 	 	Primary Fuel Type	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Oswego	 	 	Oswego, NY	 	 	 	100.0	%	 	 	1,634	 	 	 	Oil	 	
Arthur Kill	 	 	Staten Island, NY	 	 	 	100.0	%	 	 	841	 	 	 	Natural Gas	 	
Middletown	 	 	Middletown, CT	 	 	 	100.0	%	 	 	770	 	 	 	Oil	 	
Indian River	 	 	Millsboro, DE	 	 	 	100.0	%	 	 	737	 	 	 	Coal	 	
Astoria Gas Turbines	 	 	Queens, NY	 	 	 	100.0	%	 	 	553	 	 	 	Natural Gas	 	
Dunkirk	 	 	Dunkirk, NY	 	 	 	100.0	%	 	 	522	 	 	 	Coal	 	
Huntley	 	 	Tonawanda, NY	 	 	 	100.0	%	 	 	552	 	 	 	Coal	 	
Montville	 	 	Uncasville, CT	 	 	 	100.0	%	 	 	497	 	 	 	Oil	 	
Norwalk Harbor	 	 	So. Norwalk, CT	 	 	 	100.0	%	 	 	342	 	 	 	Oil	 	
Devon	 	 	Milford, CT	 	 	 	100.0	%	 	 	124	 	 	 	Natural Gas	 	
Vienna	 	 	Vienna, MD	 	 	 	100.0	%	 	 	170	 	 	 	Oil	 	
Somerset Power	 	 	Somerset, MA	 	 	 	100.0	%	 	 	127	 	 	 	Coal	 	
Connecticut Remote Turbines	 	 	Various locations in CT	 	 	 	100.0	%	 	 	104	 	 	 	Oil	 	
Conemaugh	 	 	New Florence, PA	 	 	 	3.7	%	 	 	64	 	 	 	Coal	 	
Keystone	 	 	Shelocta, PA	 	 	 	3.7	%	 	 	63	 	 	 	Coal	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Northeast Region	 	 	 	 	 	 	 	 	 	 	7,099	 	 	 	 	 	

 	 	
* 	Excludes 382 MW of inactive capacity.	
     The following are descriptions of our most significant revenue generating plants in the Northeast region:
      Arthur Kill. NRG’s Arthur Kill plant is a natural gas-fired power plant consisting of three units and is located on the west side of Staten Island, New York. The plant produces an aggregate generation capacity of 841 MW from two intermediate load units (Units 20 and 30) and one peak load unit (Unit GT-1). Unit 20 produces an aggregate generation capacity of 335 MW and was installed in 1959. Unit 30 produces an aggregate generation capacity of 491 MW and was installed in 1969, and both Units were converted from steam engines in the early 1990s. We may need to upgrade the plant in the future to comply with environmental regulations. If upgrades are needed it could cost several million dollars.
      Astoria Gas Turbines. Adjacent to LaGuardia airport in Queens, New York, Astoria provides power to the local New York City load pockets. The facility has an aggregate generation capacity of 553 MW from 19 operational combustion turbine engines. The turbine engines are peak gas-fired and/or oil-fired installed in the early 1970s. The engines are classified into three classes, which are then grouped into ten Astoria Gas Turbine units. These units consist of Buildings 2, 3 and 4, which have a total net generation capacity of 431 MW and will be retired in 2022. Units 5, 7 and 8, which are Class 2 turbine engines, have a net generation capacity totaling approximately 42 MW; and will be retired in 2015. Units 10, 11, 12 and 13, which are Class 3 turbine engines have a total net generation capacity of 80 MW, will be retired in 2015 as well.

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      Dunkirk. NRG’s Dunkirk plant is a coal-fired plant located on Lake Erie in Dunkirk, New York. This plant produces an aggregate generation capacity of 522 MW from four baseload units. Units 1 and 2 produce up to 81 MW each and were put in service in 1950. Units 3 and 4 produce approximately 180 MW each and were put in service in 1959 and 1960, respectively. The plant is currently implementing changes to switch from eastern bituminous coal to low sulfur PRB coal in order to comply with various federal and state emissions standards, as well as the NYSDEC settlement referred to in the following paragraph. The conversion will be completed for all units by Spring 2006.
      Huntley. NRG’s Huntley plant is a coal-fired plant consisting of six units and is located in Tonawanda, New York, approximately three miles north of Buffalo. The plant has a generation capacity of 552 MW from two intermediate load units (Units 65 and 66) and two baseload units (Units 67 and 68). Units 67 and 68 generate a net capacity of approximately 190 MW each and were put in service in 1957 and 1958, respectively. Units 65 and 66 generate a net capacity of 86 MW each and were put in service between 1942 and 1954. Units 63 and 64 are currently inactive. At the end of 2005, NRG gave notice to the New York Public Service Commission, or NYPSC, of its intent to retire Units 63 and 64 in early 2006, subject to NYPSC approval. As part of a settlement reached with the New York Department of Environmental Conservation, or NYSDEC, in January 2005, NRG will reduce NOx and SOx emissions from its Huntley and Dunkirk plants through 2013 in the aggregate by over 80% and 86%, respectively. A portion of these reductions has been achieved through the switch to PRB coal and related projects completed at the plant that have already been expended or committed to.
Market Framework
      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, similar market designs. Each ISO dispatches power plants to meet system energy and reliability needs, and settles physical power deliveries at 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 create a reliable and least-cost dispatch. The ISO-sponsored LMP energy markets 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. Prices paid in these LMP energy markets, however, are affected by, among other things, market mitigation measures which can result in lower prices associated with certain generating units that are mitigated because they are deemed to have locational market power, and by $1000/ MWh energy market price caps that are in place in all three northeast ISOs.
      In addition to energy delivery, the ISOs manage secondary markets for installed capacity, ancillary services and financial transmission rights. All of the three northeastern ISOs have realized, however, that they are not capable of supporting needed investment in new generation without well designed capacity and ancillary service markets. NYISO’s capacity market was the first to receive approval of its proposed demand curve and locational capacity reforms (which are intended to better reflect locational values of capacity resources). ISO-NE and PJM have both proposed their respective versions of reformed capacity markets, namely, a locational installed capacity market, or LICAP in ISO-NE, and a reliability pricing model, or RPM proposal in PJM. These proposals are currently pending before FERC. Also see further discussion in Item 15 — Note 26 Regulatory Matters.
 	 	
 	SOUTH CENTRAL REGION	
      As of December 31, 2005, NRG owned approximately 2,395 MW of generating capacity in the South Central region of the United States. The region lacks an ISO and, therefore, remains a bilateral market, making it less transparent than a region with an ISO-administered energy market using large scale economic dispatch (such as the Northeast markets discussed above). Our plants in the South Central region operate as their own control area, the South Central control area. As a result, the South Central control area is capable of providing control area services, in addition to wholesale power, that enables NRG to provide full requirement

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services to load serving utilities, thus making the South Central control area a competitive alternative to the integrated utilities operating in the region.
Operating Strategy
      Our South Central region seeks to capitalize on two factors: our position as a significant coal-fired generator in a market which is highly dependent on natural gas for power generation purposes; and our long-term contractual and historical service relationship with 11 rural cooperatives around Louisiana. We are working with our cooperative customers to improve contract administration, to expand their and our customer base on terms advantageous to all parties and, in some cases, to modify the terms of our contracts with respect to our current or new customers.
      The generation performance by fuel type for the recent three-year period is as shown below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Net Generation (MWh)	 	
 	 	 	 	
 	 	2005	 	 	2004	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	
 	 	(In thousands)	 	
Coal	 	 	10,103	 	 	 	10,469	 	 	 	10,318	 	
Gas	 	 	14	 	 	 	2	 	 	 	27	 	
 	 	 	 	 	 	 	 	 	 	
 	Total	 	 	10,117	 	 	 	10,471	 	 	 	10,345	 	
 	 	 	 	 	 	 	 	 	 	
      As part of our strategy, we are examining all of our sites in the South Central region for possible brownfield development. In particular, we continue the development of the new 675 MW Big Cajun II Unit 4 super critical coal-fired generating unit. On August 22, 2005, NRG received the Title V Air Permit from the Louisiana Department of Environmental Quality. On October 14, 2005, Washington Group International was selected as the owner’s engineer. We continue to aggressively pursue equity partners and off-takers for the output of the unit. We continue to look for opportunities to acquire assets that will enhance our portfolio and long-term strategic goals.
Facilities
      NRG’s generating assets in the South Central region consist primarily of its net ownership of power generation facilities in New Roads, Louisiana, which we refer to as Big Cajun II, and also includes the Sterlington, Bayou Cove and Big Cajun peaking facilities. NRG’s power generation assets in the South Central region as of December 31, 2005 are summarized in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generating	 	 	 	
 	 	 	 	 	 	Capacity	 	 	Primary Fuel	
Plant	 	Location	 	 	% Owned	 	 	(MW)	 	 	Type	
 	 	 	 	 	 	 	 	 	 	 	 	
Big Cajun II(1)	 	 	New Roads, LA	 	 	 	86.0	%	 	 	1,489	 	 	Coal	
Bayou Cove	 	 	Jennings, LA	 	 	 	100.0	%	 	 	300	 	 	Natural Gas	
Big Cajun I — (Peakers) Units 3 & 4	 	 	New Roads, LA	 	 	 	100.0	%	 	 	210	 	 	Natural Gas	
Big Cajun I — Units 1 & 2	 	 	New Roads, LA	 	 	 	100.0	%	 	 	220	 	 	Natural Gas/Oil	
Sterlington	 	 	Sterlington, LA	 	 	 	100.0	%	 	 	176	 	 	Natural Gas	
 	 	 	 	 	 	 	 	 	 	 	 	
Total South Central	 	 	 	 	 	 	 	 	 	 	2,395	 	 	 	

 	 	
(1) 	NRG owns 100% of Units 1 & 2; 58% of Unit 3	
     Big Cajun II. Our most significant revenue generating plant in the South Central region is the Big Cajun II facility. Big Cajun II plant is a coal-fired, sub-critical heat baseload plant located along the banks of the Mississippi River, upstream from Baton Rouge. This plant includes three coal-fired generation units (Units 1, 2 and 3) with an aggregate generation capacity of 1,730 MW as of December 31, 2005, and generation capacity per unit of 580 MW, 575 MW and 575 MW, respectively. The plant uses coal supplied by the Powder River Basin and was commissioned between 1981 and 1983. NRG owns 100% of Units 1 and 2 and 58% of Unit 3 for an aggregate owned capacity of 1,489 MW (86.0%) of the plant. All three units have

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been upgraded with low NOx burners and over fire air. The Unit 1 generator has recently been rewound and was optimized with a modern turbine/exciter control system. Units 2 and 3 are planned for generator rewinds, turbine/exciter control replacements and additional neural net systems in future years. These efficiency improvements are expected to cost approximately $30 million.
Market Framework
      NRG’s assets in the South Central region are located within the franchise territories of vertically integrated utilities, primarily Entergy Corp., or Entergy. Entergy performs the scheduling, reserve and reliability functions that are administered by the ISOs in certain other regions of the United States and Canada. Although the reliability functions performed are essentially the same, the primary differences between these markets lie in the physical delivery and price discovery mechanisms. In the South Central region, all power sales and purchases are consummated bilaterally between individual counterparties. Transacting counterparties are required to reserve and purchase transmission services from the relevant transmission owners at their FERC-approved tariff rates. Included with these transmission services are the reserve and ancillary costs.
      As of December 31, 2005, NRG had long-term all-requirements contracts with 11 Louisiana distribution cooperatives. The agreements are standardized into three types, Forms A, B and C and have the terms, contract loads and customers as shown in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Estimated	 	 	 	
 	 	Expiration	 	 	Contract Load	 	 	Customers	 	
 	 	 	 	 	 	 	 	 	 	
Form A	 	 	March 2025	 	 	 	42	%	 	 	6	 	
Form B	 	 	March 2025	 	 	 	3	%	 	 	1	 	
Form C	 	 	March 2009-2014	 	 	 	42	%	 	 	4	 	
      NRG also has long-term contracts with the Municipal Agency of Mississippi, South Mississippi Electric Power Association, and Southwestern Electric Power Company, which collectively comprise an additional 13% of contract load.
      At peak demand periods, NRG’s Big Cajun II assets are insufficient to serve the requirements of the customers under these contracts, and at such times, NRG typically purchases power from other power producers in the region, frequently at higher prices than can be recovered under our contracts. As the loads of our customers grow, we can expect this imbalance to worsen, unless we are successful in renegotiating the terms of our long-term contracts.
      We are currently in negotiations with these customers to achieve contractual amendments that limit incremental load growth at contract rates for large industrial and municipal loads. To date, we have been successful in achieving such amendments with two of the eleven cooperative contracts.
      As a result of Hurricanes Katrina and Rita in August and September 2005, NRG recognized a loss of approximately $1.3 million for damaged assets. Four of the South Central region’s 11 cooperative customers suffered extensive losses to their distribution systems, and the region suffered a drop in contract sales during the ensuing power outages. By year-end, loads have largely returned to normal for three of the four hard-hit cooperatives, while the fourth cooperative continues to face challenges in rebuilding. The load loss and the transmission constraints had offsetting impacts on the South Central region’s margins resulting in gross margins that were $4 million below expectations. In addition, NRG created a reserve for a receivable from Entergy New Orleans of $1.9 million because of its hurricane-related bankruptcy.
 	 	
 	WESTERN REGION	
      As of December 31, 2005, NRG owned approximately 1,044 MW of generating capacity in the Western region of the United States (California), of which approximately 904 MW is through a 50% interest in WCP Holdings. On December 27, 2005, NRG entered into a purchase and sale agreement to acquire Dynegy’s 50% ownership interest in West Coast Power to become the sole owner of power plants totaling approximately

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1,800 MW of generation capacity in the Western region. The transaction, which is subject to regulatory approval, is expected to close in the first quarter of 2006.
Operating Strategy
      Our Western region strategy is focused on maximizing the cash flow and value associated with our generating plants while protecting and potentially realizing the commercial value of the underlying real estate in case our following initiatives do not generate value. There are three principal components to this strategy. First, we are focused on influencing market reforms in California to provide an energy market environment where our capacity can be offered into centrally administered competitive auctions, such as we see in the Northeast, and also provide for the negotiation of bilateral transactions for both energy and capacity. Second, we are preparing our sites for the construction of new capacity to meet increasing local area requirements. At El Segundo, NRG has a California Energy Commission, or CEC, permit to construct a new combined cycle plant to replace the retired units at the site. At the Long Beach site, NRG has land available to construct new peaking capacity. NRG is developing plans for site remediation and preparation in anticipation of a new request for new capacity from load serving entities. Third, we are engaged in the identification of collaborative value enhancing projects with communities and businesses located near our plants. West Coast Power’s plants are, for example, considered excellent candidates for the co-location of desalination plants. In case the said initiatives fail, we are taking active steps to assess the value of our property for non-power generation purposes. The real estate value from our plant locations is promising as two of West Coast Power’s plants are situated at choice locations on the Pacific coast.
      NRG’s assets in the Western region include three additional power plants, Red Bluff and Chowchilla (94 MW total), located in northern California that have some locational value and one plant in Henderson, Nevada (Saguaro), that is contracted to Nevada Power and two steam hosts. NRG has entered into a resource adequacy agreement with PG&E Corporation, or PG&E, for the capacity of the Red Bluff and Chowchilla units that expires December 31, 2007. The Saguaro plant in Nevada is contracted to Nevada Power through 2022, one steam host (Pioneer) whose contract expires in 2007 (with a negotiated renewal) and a steam off taker (Ocean Spray), whose contract runs through 2015. The Saguaro plant had a long-term gas supply agreement that expired in July 2005 and the plant is now exposed to the monthly spot gas market. At present, Saguaro cannot pass higher natural gas costs through to its customers, and the plant is currently experiencing negative cash flows. Consequently, during 2005, we wrote down our equity investment in Saguaro by approximately $27 million. NRG is currently researching a number of alternatives for its investment in Saguaro.

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Facilities
      NRG’s power generation assets in the Western region as of December 31, 2005 are summarized in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generation	 	 	 	
 	 	 	 	 	 	Capacity	 	 	Primary Fuel	 	
Plant	 	Location	 	 	% Owned	 	 	(MW)	 	 	Type	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
WCP(1)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Encina	 	 	Carlsbad, CA	 	 	 	50.0%	 	 	 	483	 	 	 	Natural Gas	 	
 	El Segundo	 	 	El Segundo, CA	 	 	 	50.0%	 	 	 	335	 	 	 	Natural Gas	 	
 	Cabrillo II	 	 	San Diego, CA	 	 	 	50.0%	 	 	 	86	 	 	 	Natural Gas	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total WCP	 	 	 	 	 	 	 	 	 	 	904	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Western Region Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Saguaro	 	 	Henderson, NV	 	 	 	50.0%	 	 	 	46	 	 	 	Natural Gas	 	
 	Chowchilla	 	 	Northern CA	 	 	 	100.0%	 	 	 	49	 	 	 	Natural Gas	 	
 	Red Bluff	 	 	Northern CA	 	 	 	100.0%	 	 	 	45	 	 	 	Natural Gas	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	140	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Western Region	 	 	 	 	 	 	 	 	 	 	1,044	 	 	 	 	 	

 	 	
(1) 	On December 27, 2005, NRG entered into a purchase and sale agreement to acquire Dynegy’s 50% ownership interest in WCP Holdings to become the sole owner of power plants totaling approximately 1,800 MW of generation capacity in the Western region. The transaction is expected to close in the first quarter of 2006.	
     NRG’s assets in the Western region consist primarily of older, higher heat rate, gas-fired plants in southern California. These plants, while older and less efficient than newer combined cycle plants, possess locational advantages during peak hours when the newer, remotely located plants are unable to get through transmission congestion in southern California. As a result, the Cal ISO designated NRG’s El Segundo, Encina and Cabrillo II plants as RMR qualifying units in 2005, and therefore those plants are entitled to certain fixed-cost payments from the Cal ISO for the right to dispatch those units during periods of locational constraints. Initially, transmission upgrades by Southern California Edison and San Diego Gas and Electric in 2005 caused the Cal ISO to drop the RMR designation for both El Segundo and the Encina Unit 4 for 2006. However, Cal ISO designated Encina Unit 4 as an RMR unit in a letter to Cabrillo Power I dated December 22, 2005, and a filing requesting FERC approval of the requisite changes to Cabrillo Power I’s RMR agreement for 2006 was made on December 29, 2005. This change, if approved, will assure that Encina Units 4 and 5 will receive partial cost recovery under RMR and both units will be available in the market for 2006.
Market Framework
      The majority of NRG’s assets in the Western region are located within the control area of the Cal ISO. The Cal ISO operates a financially settled real time balancing market. There are currently no organized day ahead markets in the Western region and such forward markets in California currently operate similarly to those in the ERCOT market with all power sales and purchases consummated bilaterally between individual counterparties and scheduled for physical delivery with the Cal ISO. All plants are subject to the FERC “must offer” order, an order instituted during the energy crisis of 2000-2001 requiring any generator capable of operating and not subject to a bilateral agreement to make its capacity available to Cal ISO. The compensation paid by the Cal ISO for such service generally covers only variable costs. Additionally, California generators remain subject to a $250 per MWh price cap, another legacy of the energy crisis mentioned above. FERC approved an increase in the “softcap” from $250 per MWh to $400 per MWh, effective January 1, 2006. NRG is working with various industry groups and governmental authorities to put

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market reforms in place in California that will encourage new investment and enable generators to earn acceptable returns on new and existing investments.
      WCP will continue to pursue repowering opportunities at the El Segundo, Encina and Long Beach plants where grid stability and in-load resource adequacy is needed. On December 23, 2004, the CEC approved NRG’s application for a permit to repower the existing El Segundo site and replace retired units 1 and 2 with 630 MW of new combined cycle 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. On August 31, 2005, the California Supreme Court refused to hear the case, making that date the effective date of the permit. The El Segundo permit has as a condition the payment of $5 million by the project to the Santa Monica Bay Restoration Fund with the first $1 million being due in equally quarterly installments beginning 30 days following the disposition of all appeals. The initial quarterly payment has been made. Should we elect to repower the Long Beach site, we will do it outside of the CEC permitting process. We do not believe the CEC can legally assert jurisdiction over a Long Beach repowering project as the total anticipated megawatts added will be less than the number of megawatts retired. The California Court of Appeals, in a case involving the Los Angeles Department of Water and Power, held that the CEC jurisdiction is only required where the total megawatts added exceed the existing megawatts of capacity by over 50 megawatts.
      In California, the 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 MD02. These changes, once implemented, will re-establish a day-ahead time market and allow for multiple settlements. We view this as a vast improvement to the existing structure. In general, the Cal ISO is continuing along a path of small incremental changes rather than significant market restructuring. Although numerous stakeholder meetings have been held, the final market design remains unknown at this time. The effect of the new MRTU changes on us cannot be determined at this time. In addition to that activity, the California Public Utility Commission, or CPUC, recently issued their Resource Adequacy Order, which we believe will ultimately create greater opportunities for merchant generators in California. However, the final order did delay the implementation of local capacity requirements and allowed a liberalized phase out of firm liquidated damages contracts, which may act as a disincentive for load serving entities to contract for our capacity over the next two years. Assembly Bill 1576 which will promote and codify the recovery of costs from repowered facilities — thus making contracting from these sites more attractive to the in-state-utilities, was passed by the Senate on September 8, 2005, and signed by the Governor on September 29, 2005. This provides opportunities for the Western region, as WCP currently holds a permit for repowering up to 630 MW at the El Segundo facility and options for redevelopment at the Long Beach facility. Both facilities are positioned for possible long-term contracts as the market rules and structure fall into place in the near future.
      The CEC recently issued their 2005 Energy Report — Range of Need and Policy Recommendations To the California Public Utilities Commission, or CPUC. That study confirmed that the SCE franchise territory will require over 8,000 MW of new generation capacity by 2009; a dire prediction for a state with limited new resources coming on line and retirement of older facilities accelerating. There is some indication that the various regulatory agencies are responding to these warnings by moving to design a market that will provide the incentives to invest in new generation. The CPUC now requires that load-serving entities meet a 15-17% reserve margin by June 2006. This has prompted RFOs from load-serving entities, with the stated goal of engaging in bilateral contract negotiations with the merchant generators to secure their long-term capacity needs. Load-serving entities must demonstrate, by January 27, 2006 and by September 30 for each year thereafter that they have secured at least 90% of their capacity needs for the following year. The CPUC order requiring a demonstration of adequate capacity should present opportunities to enter into new bilateral agreements pursuant to competitive RFO processes. The Red Bluff and Chowchilla facilities have received capacity contracts for the period April 1, 2006 through December 31, 2007 from a major load serving entity.

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The capacity for El Segundo Units 3 and 4 has been secured under a tolling agreement with a major load serving entity for the period May 2006 through April 2008.
      In September 2004, Governor Schwarzenegger vetoed AB2006, commonly referred to as the “re-regulation” initiative. A proposition (Proposition 80) that would amend legislation forever prohibiting “customer choice” in California was defeated in a November 2005 special election.
 	 	
 	OTHER	

 	Other North American Assets	
      As of December 31, 2005, NRG owned approximately 1,467 MW of generating capacity in other segments of the United States. NRG’s other North American power generation assets are summarized in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generating	 	 	 	
 	 	 	 	 	 	Capacity	 	 	 	
Plant	 	Location	 	% Owned	 	 	MW	 	 	Primary Fuel Type	
 	 	 	 	 	 	 	 	 	 	 	
Audrain*	 	Vandalia, MO	 	 	100.0%	 	 	 	577	 	 	Natural Gas	
Rockford I (Peaker)	 	Rockford, IL	 	 	100.0%	 	 	 	310	 	 	Natural Gas	
Rocky Road Partnership*	 	East Dundee, IL	 	 	50.0%	 	 	 	165	 	 	Natural Gas	
Rockford II (Peaker)	 	Rockford, IL	 	 	100.0%	 	 	 	160	 	 	Natural Gas	
Dover	 	Dover, DE	 	 	100.0%	 	 	 	104	 	 	Natural Gas/Coal	
Power Smith Cogeneration	 	Oklahoma City, OK	 	 	6.25%	 	 	 	7	 	 	Natural Gas	
Ilion Cogeneration*	 	New York	 	 	100.0%	 	 	 	58	 	 	Natural Gas	
James River	 	Virginia	 	 	50.0%	 	 	 	55	 	 	Coal	
Cadillac*	 	Cadillac, MI	 	 	50.0%	 	 	 	19	 	 	Wood	
Paxton Creek	 	Harrisburg, PA	 	 	100.0%	 	 	 	12	 	 	Natural Gas	
 	 	 	 	 	 	 	 	 	 	 	
 	Other North American Assets	 	 	 	 	 	 	 	 	1,467	 	 	 	

 	 	
* 	Certain of the above projects are in transition. The Audrain project is under contract for sale. Closing is expected in 2006. NRG is in advanced discussions regarding the sale of the Cadillac project. NRG is currently performing under an agreement whereby the Ilion project will be disconnected and terminated. On December 27, 2005, NRG entered into a purchase and sale agreement with Dynegy through which NRG will sell to Dynegy its 50% ownership interest in the jointly held entity that owns the Rocky Road power plant. The transaction is conditioned upon NRG’s acquisition of Dynegy’s 50% interest in WCP Holdings and is expected to close in the first quarter of 2006.	
Australia and All Other Generation and Non-Generation Assets
      As of December 31, 2005, NRG, through certain foreign subsidiaries, had investments in power generation projects located in Australia, Germany and Brazil with approximately 1,916 MW of total generating capacity. In addition, NRG owns interests in coal mines located in Australia and Germany.

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      NRG’s international power generation assets as of December 31, 2005 are summarized in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generating	 	 	 	
 	 	 	 	 	 	Capacity	 	 	Primary	 	
Plant	 	Location	 	 	% Owned	 	 	MW	 	 	Fuel Type	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Flinders	 	 	Australia	 	 	 	100.0	%	 	 	700	 	 	 	Coal	 	
Gladstone	 	 	Australia	 	 	 	37.5	%	 	 	605	 	 	 	Coal	 	
Schkopau	 	 	Germany	 	 	 	41.9	%	 	 	400	 	 	 	Coal	 	
MIBRAG(1)	 	 	Germany	 	 	 	50.0	%	 	 	55	 	 	 	Coal	 	
Itiquira	 	 	Brazil	 	 	 	99.2	%	 	 	156	 	 	 	Hydro	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total International Assets	 	 	 	 	 	 	 	 	 	 	1,916	 	 	 	 	 	

 	 	
(1) 	Primarily a coal mining facility. Approximately 90% of MIBRAG’s revenues represent coal sales and 8% represent electricity sales. MIBRAG owns 110 MW of net exportable generation. Approximately two-thirds of that amount is sold to third parties and one-third is used to power mining and other MIBRAG operations. NRG equity in net exportable electricity is 55 MW.	

 	Australia	
      Asset Management Strategy. Our strategy for maximizing our return on investment in our assets concentrates on effective contract management, operating the plant to ensure safe and efficient operations and management of the equity investment, including cash flow and finances. NRG is currently considering strategic alternatives with respect to Australia either to reposition its assets more effectively within the National Electricity Market or to monetize its investment. We will seek to determine the best option to optimize our investment by the end of the second quarter of 2006.
      NRG Flinders Assets. NRG Flinders is a merchant generation business that derives revenue from bidding its generation output into the South Australian region of the National Electricity Market, or NEM, by trading the plant as a portfolio, selling derivative hedges that are not plant specific and supplying minor retail sales via contract. The bidding of the plant as a portfolio supports strategies for maximizing revenue of the entire portfolio both in terms of pool and derivative revenues and the most economic fuel use. A hedge book is maintained such that the short to medium term revenue is secured via hedge levels up to and in the order of 75-80% of the plant output. The current book is underpinned by a medium term hedge with a major South Australian retailer.
      The Gladstone Assets. We are the operators of the Gladstone facility, however, the Gladstone assets are owned in an unincorporated joint venture with other investors and NRG does not have unilateral control over management of the assets. Gladstone Power Station is fully contracted via a power purchase agreement and a capacity purchase agreement with Boyne Smelter Limited and Enertrade through 2029. Enertrade is a state owned company that trades the excess power in the NEM.
 	 	
 	Germany	

 	Asset Management Strategy	
      Our German assets are owned in partnership with other investors and NRG does not have direct control over operations. Our strategy for maximization of return on investment therefore concentrates on the following: contract management, monitoring of our facility operators to ensure safe, profitable and sustainable operations; management of cash flow and finances; and growth of our businesses through investments in projects related to our current businesses.

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 	Thermal and Chilled Water Businesses	
      NRG Thermal’s thermal and chilled water businesses have a steam and chilled water capacity of approximately 1,225 megawatt thermal equivalents, or MWt.
      As of December 31, 2005, NRG Thermal owned heating and cooling systems that provide steam heating to approximately 555 customers and chilled water to 95 customers in five different cities in the United States. In addition, as of that date, NRG Thermal owned and operated three projects that serve industrial/government customers with high-pressure steam and hot water, an 88 MW combustion turbine peaking generation facility and an 16 MW coal-fired cogeneration facility in Dover, Delaware and a 12 MW gas-fired project in Harrisburg, Pennsylvania. Approximately 34% of Thermal’s revenues are derived from its district heating and chilled water business in Minneapolis, Minnesota.
      Both our NRG Energy Center Pittsburgh and our NRG Energy Center Harrisburg anticipate filing rate cases during 2006 seeking increased rates under their tariffs for steam services as well as chilled water for Pittsburgh.
 	 	
 	Resource Recovery Facilities	
      NRG’s Resource Recovery business owns and operates fuel processing projects. The alternative fuel currently processed is municipal solid waste, approximately 85% of which is processed into refuse derived fuel, or RDF. NRG’s Resource Recovery business has municipal solid waste processing capacity of 3,000 tons per day. NRG’s Resource Recovery business owns and operates NRG Processing Solutions, which includes 14 composting and processing sites in Minnesota, of which five sites are permitted to operate as municipal solid waste transfer stations.
Competition
      Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We compete on the basis of the location of our plants and owning multiple plants in our regions, which increases the stability and reliability of our energy supply. Wholesale power generation is fundamentally a local business which, at present, is highly fragmented (relative to other commodity industries) and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies we compete against from market to market.
Employees
      As of December 31, 2005, the combined company has 3,682 employees, approximately 1,694 of whom were covered by U.S. bargaining agreements. During 2005, neither NRG nor Texas Genco experienced any significant labor stoppages or labor disputes at their facilities.
Energy Regulatory Matters
      As operators of power plants and participants in wholesale energy markets, we are subject to regulation by various federal and state government agencies. These include FERC, NRC, PUCT and certain other state public utility commissions in which our generating assets are located. In addition, we are also subject to the market rules, procedures and protocols of the various ISO markets in which we participate.
      The plant operations of, and wholesale electric sales from our Texas assets are not currently subject to regulation by FERC, as they are deemed to operate solely within the ERCOT and not in interstate commerce. As discussed below, these operations are subject to regulations by PUCT as well as to regulation by the NRC with respect to its ownership interest in the STP.
 	 	
 	Federal Energy Regulatory Commission	
      FERC, among other things, regulates the transmission and wholesale sale of electricity in interstate commerce under the authority of the Federal Power Act, or FPA. In addition, under existing regulations,

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FERC determines whether an entity owning a generation facility is an Exempt Wholesale Generator, or EWG, as such was defined in the Public Utility Holding Company Act of 1935, or PUHCA of 1935. 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. Each of NRG’s U.S. generating facilities has either been determined by FERC to qualify as a QF, or the subsidiary owning the facility has been determined to be an EWG.
      The Energy Policy Act of 2005. EPAct 2005 was enacted into law on August 8, 2005. Among other things, EPAct 2005 repealed PUHCA of 1935, amended PURPA to remove statutory restrictions on utility ownership of a QF and to remove a utility’s obligation to buy from a QF under certain circumstances, and enacted the Public Utility Holding Company Act of 2005, or PUHCA of 2005. EPAct 2005’s PUHCA changes became effective February 8, 2006. EPAct 2005’s amendments to PURPA were effective as of August 8, 2005. Though generally supported by the industry and viewed as a positive development, EPAct 2005 remains subject to FERC interpretation, and FERC has issued several rulemakings and rules to implement EPAct, some of which are still ongoing. NRG is currently assessing the effect of EPAct 2005 and these rulemakings issued by FERC to implement it on the company’s regulatory environment and business.
      Federal Power Act. The FPA gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of electricity in interstate commerce. Under the FPA, FERC, with certain exceptions, 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. NRG’s QFs are currently exempt from the FERC’s rate regulation under Sections 205 and 206 of the FPA to the extent that sales are made pursuant to a contract established under PURPA and are not made under a market-based rate authorization from FERC.
      Public utilities under the FPA are required to obtain FERC’s acceptance, pursuant to Section 205 of the FPA, of their rate schedules for wholesale sales of electricity. All of NRG’s non-QF generating companies and power marketing affiliates in the United States make sales of electricity pursuant to market-based rates authorized by FERC. FERC’s orders that grant NRG’s generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. In addition, our market-based sales are subject to certain market behavior rules and, if any of our generating or power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority, as well as criminal and civil penalties. As a condition to the orders granting us market-based rate authority, every three years NRG is required to file a market update to show that it continues to meet FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. NRG is also required to report to FERC any material changes in status that would reflect a departure from the characteristics that FERC relied upon when granting NRG’s various generating and power marketing companies’ market-based rates. If NRG’s generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and would become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.
      Section 204 of the FPA gives FERC jurisdiction over a public utility’s issuance of securities or assumption of liabilities. However, FERC typically grants blanket approval for future securities issuances or assumptions of liabilities to entities with market-based rate authority. In the event that one of NRG’s public utility generating companies were to lose its market-based rate authority, such company’s future securities issuances or assumptions of liabilities could require prior approval from FERC.
      Section 203 of the FPA requires FERC’s prior approval for the transfer of control over assets subject to FERC’s jurisdiction. EPAct 2005 amended this prior approval authority in a number of ways. In particular, transactions involving only generation assets which were previously exempt from FERC review under Section 203 of the FPA will now be subject to such review provided they meet the new $10 million threshold.

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The provisions of EPAct 2005 relating to prior approval of asset acquisitions under the FPA and FERC’s rules promulgated thereafter became effective February 8, 2006.
      PUHCA. As discussed above, EPAct 2005 repealed PUHCA of 1935, effective February 8, 2006, and replaces it with PUHCA of 2005. PUHCA of 2005 provides FERC with certain authority over and access to books and records of public utility holding companies not otherwise exempt by virtue of their ownership of EWGs, QFs and Foreign Utility Companies, or FUCOs. Because all of NRG’s generating facilities have QF status or are owned through EWGs or FUCOs, NRG does not currently qualify as a “holding company” under PUHCA of 2005. As noted above, FERC has a rulemaking ongoing to implement PUHCA 2005, and several companies have sought clarification of FERC’s rules.
      Public Utility Regulatory Policies Act. PURPA was passed in 1978 in large part to promote increased energy efficiency and development of independent power producers. PURPA created QFs to further both goals, and FERC is primarily charged with administering PURPA as it applies to QFs. As discussed above, under current law, some categories of QFs may be exempt from regulation under the FPA as public utilities. PURPA incentives also initially included a requirement that utilities must buy and sell power to QFs. As noted above, EPAct 2005 has amended several provisions of PURPA. Among other things, EPAct of 2005 provides for the elimination of the obligation imposed on certain utilities to purchase power from QFs at an avoided cost rate under certain conditions. However, the purchase obligation is only eliminated if FERC first finds that a QF has non-discriminatory access to wholesale energy markets having certain characteristics (including nondiscriminatory transmission and interconnection services provided by a regional transmission entity in certain circumstances). Existing contacts entered into under PURPA are not expected to be impacted, however, certain of NRG’s QFs currently interconnect into markets that may meet the qualifications for elimination of the PURPA purchase requirement. If the obligation to purchase from some or all of NRG’s QFs is terminated, NRG will need to find alternative purchasers for the output of these QFs once their current contracts expire. Such alternative purchases will be at prevailing market rates, which may not be as favorable as the terms of our PURPA sales arrangements under existing contracts and thus may diminish the value of its QF’s. In addition, under FERC regulations implementing EPAct of 2005, QFs not making sales pursuant to state-approved avoided cost rates will become subject to FERC’s ratemaking authority under the FPA and be required to obtain market rate authority in order to be allowed to sell power at market-based rates.
 	 	
 	Nuclear Regulatory Commission	
      The NRC is authorized under the Atomic Energy Act of 1954, as amended, or the AEA, among other things, to grant licenses for, and regulate the operation of, commercial nuclear power reactors. As a holder of an ownership interest in STP, our subsidiary Texas Genco, LP is an NRC licensee and is subject to NRC regulation. This NRC license gives it the right only to possess an interest in STP but not to operate it. Operating authority under the NRC operating license for STP is held by STPNOC. NRC regulation involves licensing, inspection, enforcement, testing, evaluation and modification of all aspects of plant design and operation (including the right to order a plant shutdown), technical and financial qualifications, and decommissioning funding assurance in light of NRC safety and environmental requirements. In addition, NRC written approval is required prior to a licensee transferring an interest in its license, either directly or indirectly. As a possession-only licensee (i.e., non-operating co-owner), the NRC’s regulation of Texas Genco, LP primarily focuses on its ability to meet its financial and decommissioning funding assurance obligations. In connection with the acquisition by Texas Genco of a 30.8% interest in STP from CenterPoint Energy, the NRC required Texas Genco to enter into a support agreement with Texas Genco, LP to provide up to $120 million to Texas Genco, LP if necessary to support operations at STP. Texas Genco entered into that support agreement on April 13, 2005. The support agreement remains in effect now that the Acquisition has been consummated.
      Decommissioning Trusts. Upon expiration of the operating terms of the operation licenses for the two generating units at STP (currently scheduled for 2027 and 2028), the co-owners of STP are required under federal law to decontaminate and decommission STP. In May 2004, an outside consultant estimated a 44.0% share of the STP decommissioning costs to be approximately $650 million in 2004 dollars.

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      Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioning obligations unless it is a rate regulated utility (or a state or municipal entity that sets its own rates) or has the benefit of a state-mandated non-bypassable charge available to periodically fund the decommissioning trust such that periodic payments to the trust, plus allowable earnings, will equal the estimated decommissioning obligations needed by the time decommissioning is expected to begin. Currently, Texas Genco, LP’s funding against its decommissioning obligation is contained within two separate trusts. PUCT regulations provide for the periodic funding of our decommissioning obligations through non-bypassable charges collected by CenterPoint Energy Houston Electric, LLC and AEP Texas Central Company, or CenterPoint Houston and AEP TCC, from their customers.
      In the event that the funds from the trusts are ultimately determined to be inadequate to decommission the STP facilities, the original owners of our STP interests, CenterPoint Houston and AEP TCC, each will be required to collect, through their PUCT-authorized non-bypassable charges to customers, additional amounts required to fund the decommissioning obligations relating to our 44.0% share, provided that we have complied with the PUCT’s rules and regulations regarding decommissioning trusts. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective rate payers of CenterPoint Houston or AEP TCC (or their successors).
 	 	
 	Public Utility Commission of Texas	
      Our Texas subsidiaries are registered as power generation companies with PUCT. PUCT also has jurisdiction over power generation companies with regard to the administration of nuclear decommissioning trusts, PUCT state-mandated capacity auctions and the implementation of measures to mitigate undue market power that a power generation company may have and to remedy market power abuses in the ERCOT market and, indirectly, through oversight of ERCOT.
Regulatory Developments
      In New England, New York, the Mid-Atlantic region, the Midwest and California, FERC has approved regional transmission organizations, also commonly referred to as independent system operators, or ISOs. Most of these ISOs administer a wholesale centralized bid-based spot market in their regions pursuant to tariffs approved by FERC and associated ISO market rules. These tariffs/market rules dictate how the day ahead and real-time markets operate, how market participants may make bilateral sales to one another, and how entities with market-based rates shall be compensated within those markets. The ISOs in these regions also control access to and the operation of the transmission grid within their regions. In Texas, pursuant to a 1999 restructuring statute, the PUCT has granted similar responsibilities to ERCOT.
      We are affected by rule/tariff changes that occur in the existing ISOs. The ISOs that oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms (in particular, market power mitigation rules) to address some of the volatility in these markets. 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, new approaches to the sale of electric power, in particular capacity, have been proposed, and it is not yet clear how they will operate in times of market stress or whether they will provide adequate compensation to generators over the long term.
 	 	
 	Regional Businesses — Market Developments	

 	Texas (ERCOT) Region	

 	Texas Nodal Protocols	
      At the direction of the PUCT, the ERCOT stakeholder process has developed the “Texas Nodal Protocols” that sets forth a complete and detailed revised wholesale market design based on locational marginal pricing (in place of the current ERCOT zonal market today). The stakeholder process took two years to complete and incorporates a variety of unique characteristics for a nodal market as the result of

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accommodations reached by parties in the stakeholder process. Major elements include bilateral energy and ancillary schedules, day-ahead energy market, resource specific energy and ancillary service bid curves, direct assignment of all congestion rents, nodal energy prices for generators, aggregation of nodal to zonal energy prices for loads, congestion revenue rights (including pre-assignment for public power entities), and pricing safeguards. The PUCT will consider approval of the Texas Nodal Protocols by early 2006 and has indicated January 1, 2009, as the date for full implementation of the new market design. Under the expedited schedule, the evidentiary hearing concluded December 13, 2005, and briefing by parties concluded January 27, 2006.
      For a detailed discussion on market developments for the Northeast, South Central, Western and Other regions, please see Item 15 — Note 26 to the Consolidated Financial Statements.
Environmental Matters
      We are subject to a broad range of environmental and safety laws and regulations (across a broad number of jurisdictions) in the development, ownership, construction and operation of domestic and international projects. These laws and regulations generally require that governmental permits and approvals be obtained before construction or during operation of power plants. Environmental laws have become increasingly stringent over time, particularly the regulation of air emissions from power generators. Such laws generally require regular capital expenditures for power plant upgrades, modifications and the installation of certain pollution control equipment. It is not possible at this time to determine when or to what extent additional facilities, or modifications to existing or planned NRG facilities, will be required due to potential changes to environmental and safety laws and regulations, regulatory interpretations or enforcement policies. In general, future laws and regulations are expected to require the addition of emissions control or other environmental quality equipment or the imposition of certain restrictions on the operations of the combined company. We expect that future liability under, or compliance with, environmental requirements could have a material effect on our operations or competitive position.
 	 	
 	U.S. Federal Environmental Initiatives	

 	Air	
      On May 18, 2005, the US Environmental Protection Authority, or USEPA, published 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). Consistent with the significant debate on whether the USEPA has authority to regulate mercury emissions through a cap-and-trade mechanism (as opposed to a command-and-control requirement to install “maximum achievable control technology”, or MACT, on a unit basis), 14 states, together with five environmental organizations, have filed petitions for reconsideration of CAMR. The states (including California, Connecticut, Delaware, Illinois, Maine, Massachusetts, New Hampshire, New Jersey, New Mexico, New York, Pennsylvania, Rhode Island, Vermont and Wisconsin) allege that the rule violates the Clean Air Act, or CAA, because it fails to treat mercury as a hazardous air pollutant. On August 4, 2005, the U.S. Court of Appeals for the District of Columbia Circuit denied the environmental petitioners’ request for a stay of CAMR. On October 28, 2005, the USEPA published notices of reconsideration of seven specific aspects of CAMR (including state allocations). Each of our coal-fired electric power plants will be subject to mercury regulation. However, since the rule has yet to be implemented by individual states and given the USEPA’s pending reconsideration of the rule, it is difficult to assess with certainty how CAMR will affect our operations. Nevertheless, we continue to actively review emerging mercury monitoring and mitigation strategies and technologies to identify the most cost-effective options for NRG in implementing required mercury emission controls on the stipulated schedule.
      On May 12, 2005, the USEPA published the Clean Air Interstate Rule, or CAIR. This rule applies to 28 Eastern States and the District of Columbia and caps SO 2  and NO X  emissions from power plants in two phases (2010 and 2015 for SO 2  and 2009 and 2015 for NO X ). CAIR will apply to certain of the combined company’s power plants in New York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois, Penn-

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sylvania, Maryland and Texas. States must achieve the required emission reductions through: (a) requiring power plants to participate in a USEPA-administered interstate cap-and-trade system; or (b) measures to be selected by individual states. On August 24, 2005, the USEPA published a proposed Federal Implementation Plan, or FIP, to ensure that generators affected by CAIR reduce emissions on schedule. In addition, on December 20, 2005, the USEPA signed proposed revisions to the National Ambient Air Quality Standards (“NAAQS”) for fine particulates (PM2.5) and inhalable coarse particulates (PM10-PM2.5), that would require affected states to implement further rules to address SO 2  and NO X  emissions (as precursors of fine particulates in the atmosphere). Further, on November 22, 2005, the USEPA granted requests to reconsider four specific aspects of CAIR (including the inclusion of certain states) with final action on reconsideration expected by March 15, 2006. While our current business plans include initiatives to address emissions (for example, the conversion of Huntley and Dunkirk to burn low sulfur coal), until the final CAIR rule and NAAQS for PM2.5, PM10-2.5 and ozone are actually implemented by specific state legislation, it is not possible to identify with greater specificity the effect of CAIR on us. As noted below, certain states in which we operate have already announced plans to implement emissions reductions that go beyond the CAIR requirements. It is possible that investments in additional backend control technologies will be required and we continue to evaluate these issues.
      Although we recognize the uncertainties regarding how CAMR and CAIR will be implemented, we expect to incur a substantial increase in our environmental capital expenditures between 2009 and 2012 in order to ensure compliance with CAMR and CAIR. We have currently estimated expenditures of around $540 million for CAMR and CAIR compliance during this period for the NRG facilities most of which would be incurred at our various coal-fired plants in the Northeast region and South Central region. We have currently estimated our total capital expenditures for compliance with air pollution control regulations from 2006 to 2014 at the NRG facilities at approximately $675 million.
      From 1999 through 2005, Texas Genco invested approximately $700 million for NOX emissions controls at its plants. These emissions controls were installed to comply with regulations adopted by the Texas Commission on Environmental Quality, or TCEQ, to attain the one-hour NAAQS for ozone, as well as provisions of the Texas electric restructuring law. As a result, emissions from our plants in the Houston-Galveston area have been reduced by approximately 88% from 1998 levels and our Texas fleet overall operates at one of the lowest NO X  emissions rates in the country. In aggregate, our Texas plants are in compliance with current NO X  emission limits and are not expected to incur material environmental capital expenditures to ensure NO X  emissions compliance in the next several years. The TCEQ has, however, initiated a rulemaking process for establishing lower NO X  emissions limits to assure compliance with the USEPA 8-hour ozone standard in the Houston-Galveston and Dallas-Fort Worth areas. It is possible that any new regulations implemented may require additional NO X  emission controls on the Texas plants in 2009 or beyond. We have currently estimated approximately $70 million in additional capital expenditures with respect to compliance with air pollution control requirements (primarily replacement of catalyst for NO X  emission controls) between 2006 and 2014.
      The USEPA had also proposed MACT standards for nickel from oil-fired units that would essentially require the installation of electrostatic precipitators on certain oil-fired units. These proposed requirements were originally included in drafts of CAMR. However, reflecting further dialogue with generation industry participants and additional scientific review, the nickel MACT provisions were omitted from CAMR. In fact, the USEPA issued a delisting rule on March 29, 2005 effectively removing the MACT standards for nickel (i.e., specific control technologies to be installed at each affected plant) at oil-fired power plants. A number of environmental groups lodged legal challenges to the USEPA’s delisting rule and the agency has agreed to reconsider this delisting, although it has not specified which issues will be reconsidered. As the delisting challenge relates to both nickel from oil-fired power plants and mercury from coal-fired plants, it is not possible to predict the outcome of the pending legal action.
      NRG’s facilities in the eastern United States are subject to a cap-and-trade program governing NOX emissions during the “ozone season” (May 1 through September 30). These rules essentially require that one NO X  allowance be held for each ton of NO X  emitted from fossil fuel-fired stationary boilers, combustion turbines, or combined cycle systems. Each of NRG’s facilities that is subject to these rules has been allocated

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NOX emissions allowances. NRG currently estimates that the portfolio total is currently sufficient to generally cover operations at these facilities through 2009. However, if at any point allowances are insufficient for the anticipated operation of each of these facilities, NRG must purchase NO X  allowances. Any obligation to purchase a substantial number of additional NO X  allowances could have a material adverse effect on NRG’s operations.
      The Clean Air Visibility Rule (or so-called BART rule) was published by the USEPA on July 6, 2005. This rule is designed to improve air quality in national parks and wilderness areas. The rule requires regional haze controls (by targeting SO 2  and NO X  emissions from sources including power plants of a certain vintage) through the installation of Best Available Retrofit Technology, or BART, in certain cases. States must develop implementation plans by December 2007 which may be satisfied through an emissions trading program for BART sources. Although the BART rule will apply to many of the Company’s facilities, sources that are also subject to CAIR (which include most of our facilities) will likely be able to satisfy their obligations under the BART rule through compliance with the more stringent CAIR. Accordingly, no material additional expenditures are anticipated for compliance with the Clean Air Visibility Rule, beyond those required by CAIR.
      In addition to federal regulation, national legislation has been proposed that would impose annual caps on U.S. power plant emissions of NO X , SO 2 , mercury, and, in some instances, CO 2 . While the Administration’s proposed Clear Skies Act (which would regulate the aforementioned pollutants except for CO 2 ) stalled in Senate Committee on March 9, 2005, the Bush Administration continues to support this legislation. Clear Skies overlaps significantly with CAIR and CAMR, and would likely modify or supersede those rules if enacted as federal legislation as proposed.
      Twelve states and various environmental groups filed suit against the USEPA seeking confirmation that the USEPA has an existing obligation to regulate greenhouse gases, or GHGs, under the CAA. On July 15, 2005, the US Court of Appeals for the District of Columbia Circuit (in  Commonwealth of Massachusetts v. EPA ) supported the USEPA’s refusal to regulate GHG emissions from motor vehicles, although avoiding the broader issue of whether USEPA has authority, or an obligation, to regulate GHGs under the CAA. On September 1, 2005, five states requested reconsideration of this dismissal. While the specific issue under consideration is the USEPA’s obligation to require GHG cuts from mobile sources, any decision implying that the USEPA has an obligation to regulate GHGs nationally has wider implications for the power generation sector. In 2004, eight states and the City of New York filed suit in the U.S. District Court for the Southern District of New York 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 ( Connecticut v. AEP ). An injunction was sought against each defendant to force it to abate its contribution to the “global warming nuisance” by requiring CO 2  emissions caps and annual reductions in those caps for at least a decade. On September 15, 2005, the public nuisance case was dismissed on the basis that the claims made raised “political questions” reserved to the legislative and executive branches of the federal government. On September 20, 2005, plaintiffs filed an appeal of this decision with the US Court of Appeals for the Second Circuit. The initiation of GHG-related litigation and proposed legislation is becoming more frequent, although the outcomes of such suits or proposed litigation cannot be predicted. Although NRG has not been named as a defendant in any related suits to date, the outcome of such suits could affect the overall regulation of GHGs under the CAA. Our compliance costs with any mandated GHG reductions in the future could be material. See also “Regional U.S. Environmental Regulatory Initiatives,” below.
      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 facilities over the years. As a result, the USEPA and several states filed suits against a number of coal-fired power plants in mid-western and southern states alleging violations of the CAA NSR/ Prevention of Significant Deterioration, or PSD, requirements. In one of the more prominent suits of this type, involving Ohio Edison, a subsidiary of First Energy, the USEPA reached settlement on March 18, 2005 for NSR issues with respect to all coal-fired plant located in Ohio, obligating First Energy to spend $1.1 billion to install pollution control equipment through 2010. In another similar suit,

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on June 15, 2005 the USEPA appeal in the Duke Energy case was heard with the U.S. Court of Appeals for the Fourth Circuit holding in favor of Duke’s position as to what type of modification triggers NSR and PSD provisions. Rehearing petitions filed in this matter by the Department of Justice and some environmental groups were denied on August 30, 2005. On December 28, 2005, further petitions were filed by environmental groups requesting Supreme Court review of this decision. On June 3, 2005, the U.S. District Court for the Northern District of Alabama reached conclusions favorable to Alabama Power through the court’s interpretation of NSR rules relating to “routine maintenance, repair and replacement,” or RMRR, and the correct test for determining a significant net emissions increase. However, divergent rulings exist on NSR issues across the country, with courts in Ohio and Indiana providing interpretations of the NSR provisions different from those in the Duke and Alabama cases. For example, on August 29, 2005, U.S. District Court for the Southern District of Indiana ruled in U.S. v. Cinergy  in favor of the USEPA and specifically rejected the conclusion in the Duke case.
      In an effort to revise the legal requirements as to what amounts to a major modification and what emissions tests apply, USEPA issued its NSR Reform Rule on December 31, 2002, although its implementation was stayed by court order on December 24, 2003. There have been a number of legal challenges to different aspects of the proposed rule. On October 13, 2005 USEPA proposed changes to its NSR permitting program to stipulate an emissions test standard based on hourly emission rates, rather than aggregate annual emissions.
      Given the divergent cases and rules in this area (at both the federal and state levels), it is difficult to predict with certainty the parameters of the final NSR/ PSD regime. However, in October 2005, the USEPA announced that due to the promulgation of programs such as CAIR and the Clean Air Visibility Rule, it is placing a lower priority on continued enforcement of suspected NSR/ PSD violations. In the meantime, we continue to analyze all proposed projects at our facilities to ensure ongoing compliance with the applicable legal requirements.
 	 	
 	Water	
      In July 2004, USEPA published rules governing cooling water intake structures at existing power facilities (the Phase II 316(b) Rules). 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 our facilities that withdraw water in amounts greater than 50 million gallons per day (and utilize at least 25% for cooling purposes) to submit certain surveys, plans and operational 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 NRG’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 NRG has conducted a number of the requisite studies, 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 with certainty the capital costs that will be required for compliance with the Phase II 316(b) Rules, although current estimates for the combined company’s facilities involve capital expenditures and related costs of around $80 million between 2006 and 2012. In addition, the Phase II Rules have been challenged by industrial and environmental groups and the outcome of this litigation could affect our obligations pursuant to these rules. Further, Phase III rules, which were proposed in November 2004, may be applicable to some of our smaller power plants when finalized.
 	 	
 	Nuclear Waste	
      Under the U.S. Nuclear Waste Policy Act of 1982, the federal government must remove and ultimately dispose of spent nuclear fuel and high-level radioactive waste from nuclear plants such as STP. Consistent with the Act, owners of nuclear plants, including NRG and the other owners of STP, entered into contracts

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setting out the obligations of the owners and the U.S. Department of Energy, or DOE, including the fees being paid by the owners for DOE’s services. Since 1998, the DOE has been in default on its obligations to begin removing spent nuclear fuel and high-level radioactive waste from reactors. On January 28, 2004, Texas Genco LP and the other owners of STP filed a breach of contract suit against the DOE in order to protect against the running of a statute of limitations.
      Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The state of Texas has agreed to a compact with the states of Maine and Vermont for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by President Clinton in 1998. In 2003, the state of Texas enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal. We intend to continue to ship low-level waste material from STP off-site for as long as an alternative disposal site is available. Should existing off-site disposal become unavailable, the low-level waste material will then be stored on-site. STP’s on-site storage capacity is expected to be adequate for STP’s needs until other off-site facilities become available.
 	 	
 	Regional U.S. Environmental Regulatory Initiatives	
      Texas (ERCOT) Region. The USEPA’s Region VI (which includes Texas, Louisiana, and three other states) indicated in September 2004 that it intends to evaluate 75%-80% of the coal-fired power plants in its region over the next several years for potential violations of the NSR program or PSD. During air emissions inspections of the Limestone plant in November 2004, a USEPA inspector informally advised Texas Genco that the USEPA has drafted, but not yet sent, an information request letter pursuant to Section 114 of the CAA concerning potential NSR or PSD issues at the Limestone plant. As of March 3, 2006, NRG has not received this letter and has not had any further communications on this issue with the USEPA.
      Northeast Region. 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 , SO 2 , mercury, and CO 2 . The state has reserved the issue of control of carbon monoxide and particulate matter emissions for future consideration. Our Somerset plant is subject to these regulations. NRG has installed natural gas re-burn technology to meet the NO X  and SO 2  limits. On June 4, 2004, the Massachusetts Department of Environmental Protection, or 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%. We plan to meet the requirements through the management of our fuels and the use of early and off-site reduction credits. Additionally, NRG has entered into an agreement with MADEP to retire or repower the Somerset station by the end of 2009.
      The Massachusetts carbon regulation 310 CMR 7.29 “Emissions Standards for Power Plants” requires coal-fired generation located within the state to comply with CO 2  emission restrictions. A carbon emissions cap applies beginning January 1, 2006, while a rate requirement will apply in 2008. This regulation means that if CO 2  emissions at our Somerset facility exceed the annual cap from 2006, then the excess must be offset with approved CO 2  credits. However, since there are currently no approved CO 2  credits for use in Massachusetts, MADEP has proposed that generators annually report overages, starting in 2006, and at the time that there is a an established CO 2  market operating in the state, NRG would be required to purchase or generate sufficient CO 2  credits to offset the balance. On December 20, 2005, Massachusetts issued proposed revisions to the CO 2  regulations, including a proposed implementing regime that could allow the use of on-site and off-site generated CO 2  credits, with a price backstop of $10/ton. MADEP expects to finalize these revisions in spring 2006. Massachusetts was involved in the initial negotiations regarding the Regional Greenhouse Gas Initiative, or RGGI, which is discussed below, but did not enter into the Memorandum of Understanding with other northeastern states. Given the regulatory uncertainty surrounding implementation of Massachusetts’s carbon market and the corresponding costs of CO 2  allowances when that market exists, Somerset could be materially affected if it does not retire by the end of 2009.

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      Pursuant to New York State Department of Environmental Conservation, or NYSDEC, rules (the Acid Deposition Reduction Program, ADRP) fossil-fuel-fired combustion units in New York must reduce SO 2  emissions to 25% below the levels allowed in the federal Acid Rain Program starting January 2005 and to 50% below those levels starting in January 2008. In addition, under ADRP generators now also have to meet the ozone season NO X  emissions limit year-round. Our strategy for complying with the ADRP involves the generation of early reductions of SO 2 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, NRG reached an agreement with the State of New York and the NYSDEC in connection with emissions reductions at the Huntley and Dunkirk facilities, as discussed below in Legal Proceedings. The Consent Decree was entered by the U.S. District Court for the Western District of New York on June 3, 2005. NRG does not anticipate that any additional material capital expenditures, beyond those already spent, will be required for our Huntley and Dunkirk plants to meet the current compliance standards under the Consent Decree through 2010, although, this does not reflect any additional capital expenditures that may be required to satisfy other federal and state laws.
      Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC entered into a Consent Order with NYSDEC, effective March 31, 2004, regarding certain alleged opacity exceedances. The Consent Order required the respondents to pay a civil penalty of $1.0 million which was paid in April 2004. The Order also stipulates penalties (payable quarterly) for future violations of opacity requirements and a compliance schedule. NRG recently resolved a dispute with NYSDEC over the method of calculation for stipulated penalties. NRG paid NYSDEC $1.1 million at the end of 2005 to cover the stipulated penalty payments that had been withheld pending resolution of the dispute.
      While no rules affecting NRG’s existing facilities have been formally proposed, Delaware has recently issued a “Start Action Notice” to impose emissions standards for SO 2 , NO X  and mercury. Delaware is pursuing such rule-making based on recent determinations that portions of the state are in non-attainment for NAAQS for fine particulates, and all of the state is in non-attainment for the NAAQS for 8-Hour Ozone. We are evaluating emissions reduction opportunities which may include blending low sulfur western coals. NRG is actively participating in the Delaware rule-making as a stakeholder and will continue to be involved in environmental policy-making efforts in Delaware through the Governor’s Energy Task Force and interactions with legislators, the PSC and the Delaware Department of Natural Resources and Environmental Control, or DNREC.
      The Ozone Transport Commission, or OTC, was established by Congress and governs ozone and the NOX budget program in certain eastern states, including Massachusetts, Connecticut, New York and Delaware. In January 2005, the OTC redoubled its efforts to develop a multi-pollutant regime (SO 2 , NO X  , mercury and CO 2 ) that is expected to be completed by mid-2006 (with individual state implementation to follow). On June 8, 2005, the OTC members unanimously resolved to implement “CAIR-Plus” emissions regulations, based on concerns that the USEPA’s CAIR fails to achieve attainment of 8-hour ozone and fine particulate matter. As a result, the OTC proposes to implement a regional plan containing emissions reduction targets for power plants that exceed those under CAIR. The OTC targets and timelines are as follows: (a) through September 2006: write model rule, with participating states signing a Memorandum of Understanding; (b) by December 2006 states file their implementation plans or reduction regulations; (c) 2008 Phase I reductions of NO X  (to 1.87 million tons) and SO 2  (to 3.0 million tons) apply; (d) 2012 Phase II reductions of NO X  (to 1.28 million tons) and SO 2  (to 2.0 million tons) apply; and (e) 2015 90% mercury removal required. OTC’s proposed CAIR-Plus involves emissions reductions which are both sooner and more aggressive than CAIR (e.g., aggregate NO X  reductions would be 25% greater than CAIR, while SO 2  reductions would be 33% greater than CAIR). NRG 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 is successful in implementing emissions requirements that are more stringent than existing regimes (including the recently reached New York settlement), NRG could be materially impacted.
      On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to create a regional initiative to establish a cap-and-trade GHG program for electric generators, referred to as the

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Regional Greenhouse Gas Initiative, or RGGI. The model RGGI rule is scheduled to be announced within the next few months, with an estimate of two to three years for participating states to finalize implementing regulations. The current proposal is for the program to start in 2009, with a review in 2015 and an assessment of further reductions after 2020. The proposal involves an overall RGGI cap (with state sub-caps) based on CO 2  emissions for the period 2000 to 2004. That cap, referred to as “stabilization,” will remain the same through 2015, with a 10% reduction between 2015 and 2020. Decisions on allowance allocations will be made by each state, although at least 25% of the state allocations will be set aside for public purposes, suggesting that from implementation, generators in the RGGI region may receive an allocation of allowances that is materially less than required to cover existing emissions, potentially having a significant effect on the cost of operations. While the details of the model rule are still under development, when RGGI is implemented, our plants in New York, Delaware and Connecticut may be materially affected. If Massachusetts, which was originally involved in the development of RGGI, decides to participate, NRG’s plant in that state may also be affected.
      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. NRG 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 off-takers), allowing nearly all of the costs of added combustion controls to be passed through to the cooperatives. The combustion controls required at the Big Cajun II Generating Station to meet the state’s NO X  regulations have been installed.
      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 and subsequently received a notice of violation, or NOV, based on alleged NSR violations. See “— Legal Proceedings” for a discussion of this matter. NRG is up-to-date with all USEPA information requests it has received in connection with this matter and has not been contacted by USEPA pursuant to the NOV since May 2005.
      Western 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 for the life of those units.
      On October 6, 2005, the California Public Utilities Commission, or CPUC, adopted a policy statement on GHG Performance Standards as part of a focus on emissions from conventional fossil-fuel resources. The adopted policy statement directs the CPUC to investigate a GHG emissions performance standard for energy procurement by the state’s Investor-Owned Utilities, or IOUs, that is no higher than the GHG emissions levels of a combined-cycle natural gas turbine for all energy procurement contracts longer than three years in length and for all new IOU owned generation. On January 13, 2006, the CPUC issued a draft decision establishing a load-based GHG emission cap that will apply to IOUs. While the decision doesn’t establish specific caps, it does indicate a preference for using 1990 emissions as the preferred baseline year. The decision also restricts IOUs from entering into power purchase agreements with generators unless the generator reports its GHG emissions through the California Climate Action Registry. West Coast Power is a member of the Registry and will be finalizing its 2004 GHG inventory by the end of February 2006. The CPUC is obligated to evaluate and decide on the details of the GHG cap and trading program under the recent draft decision by, ,as part of either an existing or new CPUC rulemaking sometime in 2006.

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      On February 9, 2006, the California State Lands Commission (“CSLC”) postponed an agenda item regarding, “Commission consideration of a resolution supporting the elimination of once through cooling in California power generation facilities.” The draft resolution urges the California State Water Resource Control Board and the California Energy Commission to develop policies that eliminate once through cooling systems at new and existing power plants in California. The draft resolution also requires that the CSLC not approve new or extended leases for power plants utilizing once through cooling systems after 2020. This resolution, if adopted, would affect the long term operation of the once through cooling systems at the El Segundo and Encina power stations as both systems rely on submerged land leases with the CSLC and both of which are currently undergoing lease renewals. Under pressure from power and desalination water industry groups, the CSLC agreed to postpone the agenda item until the April 27, 2006 Commission meeting in order to better understand the costs and impacts associated with the decision.
 	 	
 	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 a 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. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills or other occurrences during our operations.
      On January 18, 2005, NRG Indian River Operations, Inc. received a letter of informal notification from DNREC stating that it may be a potentially responsible party with respect to the Burton Island Landfill, along with Delmarva Power. The letter signals only that an investigation is to be commenced and is not a conclusive determination. Further, the Burton Island Landfill is a site that would potentially qualify for a remedy under a “Voluntary Cleanup Program” or VCP. We have signaled our interest in being considered for a VCP should matters progress. With the exception of the foregoing, neither NRG nor Texas Genco have been named as a potentially responsible party with respect to any off-site waste disposal matter.
      Texas (ERCOT) Region. The lignite used to fuel the Limestone facility is obtained from a surface mine adjacent to the facility under an amended long-term contract with Texas Westmoreland Coal Co., or TWCC, entered into in August 1999. TWCC is responsible for performing ongoing reclamation activities at the mine until all lignite reserves have been produced. When production is completed at the mine, Texas Genco is responsible for final mine reclamation obligations. The Railroad Commission of Texas has imposed a bond obligation of approximately $70 million on TWCC for the reclamation of this lignite mine. Final reclamation activity is expected to commence in 2015. Pursuant to the contract with TWCC, an affiliate of CenterPoint Energy, Inc. has guaranteed $50 million of this obligation until 2010. The remaining sum of approximately $20 million has been bonded by the mine operator, TWCC. Under the terms of Texas Genco’s agreement, Texas Genco is required to post a corporate guarantee in the amount of $50 million of TWCC’s reclamation bond when CenterPoint’s obligation lapses. As of December 31, 2005, Texas Genco had accrued approximately $17 million related to the mine reclamation obligation.
      Further details regarding our Domestic Site Remediation obligations for the Northeast, South Central and Western regions can be found at Item 15 — Note 27 to the Consolidated Financial Statements.
 	 	
 	International Environmental Matters	
      Most of the foreign countries in which NRG owns or may acquire or develop independent power projects have environmental and safety laws or regulations relating to the ownership or operation of electric power

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generation facilities. These laws and regulations, like those in the U.S., are constantly evolving and have a significant impact on international wholesale power producers. In particular, NRG’s 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 or minimal impact on our 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, with the possible exception of an inter-jurisdictional state-led carbon trading proposal (which is not supported by the federal government).
      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 will have an obligation to remediate these ponds in accordance with a plan accepted by the South Australian Environment Protection Agency and confirmed in the Environment Compliance Agreement between the South Australian Minister for Environment and Heritage and NRG Flinders dated September 20, 2000, or the EC Agreement. The estimated cost of remediation including contingencies according to the plan is AUD 2.0 million (approximately $1.5 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.
      MIBRAG/ Schkopau, Germany. While CO2 emissions trading began in Germany in 2005, pursuant to European Union obligations under the Kyoto Protocol, we do not currently expect the CO 2  trading program to be a material constraint on our business in Germany. 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. These plant modifications are proceeding on schedule.
      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 effect such requirements would have on our future coal mining operations in Germany.
      A new law specifically dealing with the relocation of the residents of Heuersdorf from the path of the mining plan was enacted by the legislature of Saxony in 2004. On November 25, 2005, the Saxony Constitutional Court upheld the constitutionality of the Heuersdorf act. This ruling cannot be appealed. Nuisance suits remain a possibility, but the court’s ruling brings the matter closer to final 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 approximately €176 million in the instance of the Schleenhain mine and €132 million for Profen.

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Insurance
 	 	
 	General	
      NRG carries insurance coverage consistent with companies engaged in similar commercial operations with similar properties, including business interruption insurance for the coal and lignite plants. However, NRG’s insurance policies are subject to certain limits and deductibles as well as policy exclusions. Adequate insurance coverage in the future may be more expensive or may not be available on commercially reasonable terms. Also, the insurance proceeds received for any loss of or any damage to any of our generation plants may not be sufficient to restore the loss or damage without negative impact on our financial condition, results of operations or cash flows.
      NRG believes that the insurance program that is presently in effect for NRG after its acquisition of Texas Genco is consistent with prudent industry practice.
 	 	
 	Nuclear	
      NRG and the other owners of STP maintain nuclear property and nuclear liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. The owners of STP currently maintain $2.75 billion in property damage insurance coverage, which is above the legally required minimum. STPNOC currently carries accidental outage coverage with a 17 week deductible and a six week indemnity at a rate of $3.5 million per week. This coverage may not be available on commercially renewable terms or may be more expensive in the future and any proceeds from such insurance may not be sufficient to indemnify the owners of STP for their losses. NRG has also purchased additional accidental outage coverage for its ownership percentage in STP. This coverage will provide maximum weekly indemnity of $1.98 million for 52 weeks and $1.584 million per week for the next 104 weeks after the 17-week waiting period and six-week indemnity period have been met. These figures are per unit and if more than one unit experiences an outage from the same accident, the weekly indemnity is limited to 80% of the single unit recovery when both units are out of service.
      The Price-Anderson Act, as amended by the Energy Policy Act of 2005, requires owners of nuclear power plants in the U.S. to be collectively responsible for retrospective secondary insurance premiums for liability to the public arising from nuclear incidents resulting in claims in excess of the required primary insurance coverage amount of $300 million per reactor. For such claims in excess of $300 million per reactor, NRG and the other owners of STP are liable for any single incident, whether it occurs at STP or at another nuclear power plant not owned by it, up to a cap of $95.8 million per reactor in retrospective premiums for such incident but not to exceed $15 million per year in each case as adjusted for future inflation. These amounts are assessed per each licensed reactor. STP is a two reactor facility and our liability is capped at 44.0% of these amounts due to our 44.0% interest in STP. The Price-Anderson Act only covers nuclear liability associated with any accident in the course of operation of the nuclear reactor, transportation of nuclear fuel to the reactor site, in the storage of nuclear fuel and waste at the reactor site and the transportation of the spent nuclear fuel and nuclear waste from the nuclear reactor. All other non-nuclear liabilities are not covered. Any substantial retrospective premiums imposed under the Price-Anderson Act or losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.

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Item 1A — Risk Factors Related to NRG Energy, Inc.
 	 	
 	Many of our power generation facilities operate, wholly or partially, without long-term power sale agreements.	
      Many of our facilities operate as “merchant” facilities without long-term power sale agreements, and therefore are exposed to market fluctuations. Without the benefit of long-term power purchase agreements for certain assets, we cannot be sure that we will be able to sell any or all of the power generated by these facilities at commercially attractive rates or that these 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, which could have a material adverse effect on our results of operations, financial condition or cash flows.
 	 	
 	Our financial performance may be impacted by future decreases in oil and natural gas prices, significant and unpredictable price fluctuations in the wholesale power markets and other market factors that are beyond our control.	
      A significant percentage of the company’s domestic revenues is derived from baseload power plants that are fueled by coal. In many of the competitive markets where we operate, the price of power typically is set by marginal cost natural gas-fired and oil-fired power plants that currently have substantially higher variable costs than our solid fuel baseload power plants. The current pricing and cost environment allows our baseload coal generation assets to earn attractive operating margins compared to plants fueled by natural gas and oil. A decrease in oil and natural gas prices could be expected to result in a corresponding decrease in the market price of power but would generally not affect the cost of the solid fuels that we use. This could significantly reduce the operating margins of our baseload generation assets and materially and adversely impact our financial performance.
      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, as well as wholesale purchasers. We are generally not entitled to traditional cost-based regulation, therefore we sell electric generation capacity, power and ancillary services to wholesale purchasers at prices determined by the market. As a result, we are not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations depend upon current and forward market prices for power.
      Market prices for power, generation capacity and ancillary services tend to fluctuate substantially. 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, power prices are subject to significant volatility from supply and demand imbalances, especially in the day-ahead and spot markets. Long-term and short-term power prices may also fluctuate substantially due to other factors outside of our control, including:
 	 	 	
 	• 	increases and decreases in generation capacity in our markets, including the addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity;	
 	 	 	
 	• 	changes in power transmission or fuel transportation capacity constraints or inefficiencies;	
 	 	 	
 	• 	electric supply disruptions, including plant outages and transmission disruptions;	
 	 	 	
 	• 	weather conditions;	
 	 	 	
 	• 	changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices;	
 	 	 	
 	• 	availability of competitively priced alternative power sources;	
 	 	 	
 	• 	development of new fuels and new technologies for the production of power;	
 	 	 	
 	• 	natural disasters, wars, embargoes, terrorist attacks and other catastrophic events;	
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 	• 	regulations and actions of the ISOs; and	
 	 	 	
 	• 	federal and state power market and environmental regulation and legislation.	
      These factors have caused our quarterly operating results to fluctuate in the past and will continue to cause them to do so in the future.
 	 	
 	Our costs, results of operations, financial condition and cash flows could be adversely impacted by disruption of our fuel supplies.	
      We rely on coal, oil and natural gas to fuel our power generation facilities. Delivery of these fuels to our facilities is dependent upon the continuing financial viability of contractual counterparties as well as upon the infrastructure (including rail lines, rail cars, barge facilities, roadways, and natural gas pipelines) available to serve each generation facility. As a result, we are subject to the risks of disruptions or curtailments in the production of power at our generation facilities if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.
      The company has sold forward a substantial part of its baseload power in order to lock in long-term prices that it deemed to be favorable at the time it entered into the forward sale contracts. In order to hedge our obligations under these forward power sales contracts, we have entered into long-term and short-term contracts for the purchase and delivery of fuel. Many of our forward power sales contracts do not allow us to pass through changes in fuel costs or discharge the company’s power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Disruptions in our fuel supplies may therefore require us to find alternative fuel sources at higher costs, to find other sources of power to deliver to counterparties at higher cost, or to pay damages to counterparties for failure to deliver power as contracted. Any such event could have a material adverse effect on our financial performance.
      We also buy significant quantities of fuel on a short-term or spot market basis. Prices for all of our fuels fluctuate, sometimes rising or falling significantly over a short period. 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 or delivery costs. This may have a material adverse effect on our financial performance. 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;	
 	 	 	
 	• 	federal, state and foreign governmental regulation and legislation; and	
 	 	 	
 	• 	our creditworthiness and liquidity and willingness of fuel suppliers/transporters to do business with us.	
      Our plant operating characteristics and equipment, particularly at our coal-fired plants, often dictate the specific fuel quality to be combusted. The availability and price of specific fuel qualities may vary due to

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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 facility with lesser quality coal can lead to emission or operating problems. If we had sold forward the power from such a coal 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.
 	 	
 	There may be periods when we will not be able to meet our commitments under our forward sales obligations at a reasonable cost or at all.	
      A substantial portion of the output from NRG’s units is sold forward under fixed price power sales contracts through 2010, and we also sell forward the output from our intermediate and peaking facilities when we deem it commercially advantageous to do so. Because our obligations under most of these agreements are not contingent on a unit being available to generate power, we are generally required to deliver power to the buyer, even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that we do not have sufficient lower cost capacity to meet our commitments under our forward sales obligations, we would be required to supply replacement power either by running our other, higher cost power plants or by obtaining power from third-party sources at market prices that could substantially exceed the contract price. If we failed to deliver the contracted power, then we would be required to pay the difference between the market price at the delivery point and the contract price, and the amount of such payments could be substantial.
      In NRG’s South Central region, NRG has long-term contracts with rural cooperatives that require it to serve all of the cooperatives’ requirements at prices that generally reflect the costs of coal-fired generation. At times, the output from NRG’s coal-fired Big Cajun II facility is inadequate to serve these obligations, and when that happens NRG typically purchases power from other power producers, often at a loss. NRG’s financial returns from its South Central region are likely to deteriorate over time as the rural cooperatives grow their customer bases, unless NRG is able to amend or renegotiate its contracts with the cooperatives or add generating capacity.
 	 	
 	Our trading operations and the use of hedging agreements could result in financial losses that negatively impact our results of operations.	
      We enter into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, in order to manage the commodity price risks inherent in our power generation operations. These activities, although intended to mitigate price volatility, expose us to other risks. When we sell power forward, we give up the opportunity to sell power at higher prices in the future, which not only may result in lost opportunity costs but also may require us to post significant amounts of cash collateral or other credit support to our counterparties. Further, if the values of the financial contracts change in a manner we do not anticipate, or if a counterparty fails to perform under a contract, it could harm our business, operating results or financial position.
      We do not typically hedge the entire exposure of our operations against commodity price volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position may be improved or diminished based upon movement in commodity prices.
      We may engage in trading activities, including the trading of power, fuel and emissions credits that are not directly related to the operation of our generation facilities or the management of related risks. These trading activities take place in volatile markets and some of these trades could be characterized as speculative. We would expect to settle these trades financially rather than through the production of power or the delivery of fuel. This trading activity may expose us to the risk of significant financial losses which could have a material adverse effect on our business and financial condition.

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 	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 the purchase and sale of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into energy and delivering the energy to a buyer.
      We undertake these marketing activities through agreements with various counterparties. Many of our agreements with counterparties include provisions that require us to provide guarantees, offset of netting arrangements, letters of credit, a second lien on assets and/or cash collateral to protect the counterparties against the risk of our default or insolvency. The amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in our being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these 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 manage price volatility effectively or to implement our strategy. An increase in demands from our counterparties to post letters of credit or cash collateral may negatively affect our liquidity position and financial condition.
      Further, if our facilities experience unplanned outages, we may be required to procure replacement power at spot market prices in order to fulfill contractual commitments. Without adequate liquidity to post margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities, and 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:
 	 	 	
 	• 	electricity sales from our generation assets;	
 	 	 	
 	• 	fuel utilized by those assets; and	
 	 	 	
 	• 	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 and annual operating results.
 	 	
 	Competition in wholesale power markets may have a material adverse effect on our results of operations, cash flows and the market value of our assets.	
      We have numerous competitors in all aspects of our business, and additional competitors may enter the industry. Because 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 to the extent

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our competitors are able to consume the same fuel as we consume at those plants. Over time, our plants may be squeezed out of their markets, or may be unable to compete with these more efficient plants.
      In our power marketing and commercial operations, we compete on the basis of our relative skills, financial position and access to capital 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 compete successfully, 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.
      Other companies with which we compete may have greater liquidity, access to credit and other financial resources, lower cost structures, more effective risk management policies and procedures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services or greater flexibility in the timing of their sale of generation capacity and ancillary services than we do.
      Our competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or to devote greater resources to the construction, expansion or refurbishment of their power generation facilities than we can. In addition, current and potential competitors may make strategic acquisitions or establish cooperative relationships among themselves or with third parties. Accordingly, it is possible that new competitors or alliances among current and new competitors may emerge and rapidly gain significant market share. There can be no assurance that we will be able to compete successfully against current and future competitors, and any failure to do so would have a material adverse effect on our business, financial condition, results of operations and cash flow.
 	 	
 	Operation of power generation facilities involves significant risks that could have a material adverse effect on our revenues and results of operations.	
      The ongoing operation of our facilities involves risks that include 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. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWh or require us to incur significant costs as a result of running one of our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. Our inability to operate our plants efficiently, manage capital expenditures and costs, and generate earnings and cash flow from our asset-based businesses in relation to our debt and other obligations could have a material adverse effect on our results of operations, financial condition or cash flows.
      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 or vendors.
 	 	
 	Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material adverse effect on our revenues and results of operations.	
      Many of our facilities are old and are 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.
      We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist attacks). The

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unexpected requirement of large capital expenditures could have a material adverse effect on our financial performance and condition.
      If we make any major modifications to our power generation facilities, we may be required to install the best available control technology or to achieve the lowest achievable emissions rate, as such terms are defined under the new source review provisions of the federal Clean Air Act. Any such modifications would likely result in substantial additional capital expenditures.
      We may also choose to undertake the repowering, refurbishment or upgrade of current facilities based on our assessment that such activity will provide adequate financial returns. Such projects often require several years of development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. The construction, expansion, modification and refurbishment of power generation facilities involve many additional risks, including:
 	 	 	
 	• 	delays in obtaining necessary permits and licenses;	
 	 	 	
 	• 	environmental remediation of soil or groundwater at contaminated sites;	
 	 	 	
 	• 	interruptions to dispatch at our facilities;	
 	 	 	
 	• 	supply interruptions;	
 	 	 	
 	• 	work stoppages;	
 	 	 	
 	• 	labor disputes;	
 	 	 	
 	• 	weather interferences;	
 	 	 	
 	• 	unforeseen engineering, environmental and geological problems; and	
 	 	 	
 	• 	unanticipated cost overruns.	
      Any of these risks could cause our financial returns on new investments to be lower than expected, or could cause us to operate below expected capacity or availability levels, which could result in lost revenues, increased expenses, higher maintenance costs and penalties.
 	 	
 	Supplier and/or customer concentration at certain of our facilities may expose us to significant financial credit or performance risks.	
      We often rely on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of certain of our facilities. If these suppliers cannot perform, we utilize the marketplace to provide these services. There can be no assurance that the marketplace can 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 account for a substantial percentage of the anticipated revenue from a given facility. We have hedged a portion of our exposure to power price fluctuations through forward fixed price power sales and natural gas price swap agreements. Counterparties to these agreements may breach or may be unable to perform their obligations. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements, or at all. If we were unable to enter into replacement power purchase agreements, we would sell our plants’ power at market prices. If we were unable to enter into replacement fuel or fuel transportation purchase agreements, we would seek to purchase our plants’ fuel requirements at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price.
      In the past several years, a substantial number of companies, some of which serve as our counterparties from time to time, have experienced downgrades in their credit ratings. The failure of any supplier or customer to fulfill its contractual obligations to us could have a material adverse effect on our financial results.

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Consequently, the financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.
 	 	
 	We rely on power transmission facilities that we do not own or control and are subject to transmission constraints within a number of our core regions. If these facilities fail to provide us with adequate transmission capacity, we may be restricted in our ability to deliver wholesale electric power to our customers and we may either incur additional costs or forego revenues. Conversely, improvements to certain transmission systems could also reduce revenues.	
      We depend on transmission facilities owned and operated by others to deliver the wholesale power we sell from our power generation plants to our customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be adversely impacted. If a region’s power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure. We also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.
      In addition, in certain of the markets in which we operate, energy transmission congestion may occur and we may be deemed responsible for congestion costs if we schedule delivery of power between congestion zones during times when congestion occurs between the zones. If we are liable for congestion costs, our financial results could be adversely affected.
      In the California ISO, New York ISO and New England ISO markets, the company will have a significant amount of generation located in load pockets making that generation valuable, particularly with respect to maintaining the reliability of the transmission grid. Expansion of transmission systems to reduce or eliminate these load pockets could negatively impact the value or profitability of our existing facilities in these areas.
 	 	
 	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.
 	 	
 	Future acquisition activities may have adverse effects.	
      We may seek to acquire additional companies or assets in our industry. The acquisition of power generation companies and assets is subject to substantial risks, including the failure to identify material problems during due diligence, the risk of over-paying for assets and the inability to arrange financing for an acquisition as may be required or desired. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, our acquisitions may not be successfully integrated. There can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital expenditures needed to develop them.

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 	Our operations are subject to hazards customary to the power generation industry. We may not have adequate insurance to cover all of these hazards.	
      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, other hazards, such as fire, explosion, structural 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. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.
 	 	
 	Our business is subject to substantial governmental regulation 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 laws and regulation. Compliance with the requirements under these various regulatory regimes may cause us to incur significant additional costs and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.
      Public utilities under the Federal Power Act, or FPA, are required to obtain the Federal Energy Regulatory Commission’s, or FERC’s, acceptance of their rate schedules for wholesale sales of electricity. All of NRG’s non-qualifying facility generating companies and power marketing affiliates in the United States make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. FERC has granted each of NRG’s generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant NRG’s generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. In addition, NRG’s market-based sales are subject to certain market behavior rules and, if any of NRG’s generating and power marketing companies were deemed to have violated one of those rules, they are subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. If NRG’s generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and would become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates NRG charges for power from its facilities.
      We are also affected by changes to market rules, tariffs, changes in market structures, changes in administrative fee allocations and changes in market bidding rules that occur in the existing ISOs. The ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, price limitations, offer caps, and other mechanisms to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell energy and capacity into the wholesale power markets. In addition, the regulatory and legislative changes that have recently been enacted at the federal level and 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

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meaningful long-term price history in many of these markets and the imposition of price limitations by independent system operators.
 	 	
 	Our ownership interest in a nuclear power facility subjects us to regulations, costs and liabilities uniquely associated with these types of facilities.	
      Under the Atomic Energy Act of 1954, as amended, or AEA, operation of STP, of which we indirectly own a 44.0% interest, is subject to regulation by the Nuclear Regulatory Commission, or NRC. Such regulation includes licensing, inspection, enforcement, testing, evaluation and modification of all aspects of nuclear reactor power plant design and operation, environmental and safety performance, technical and financial qualifications, decommissioning funding assurance and transfer and foreign ownership restrictions. Our 44.0% share of the output of STP represents approximately 1,101 MW of generation capacity.
      There are unique risks to owning and operating a nuclear power facility. These include liabilities related to the handling, treatment, storage, disposal, transport, release and use of radioactive materials, particularly with respect to spent nuclear fuel, and uncertainties regarding the ultimate, and potential exposure to, technical and financial risks associated with modifying or decommissioning a nuclear facility. The NRC could require the shutdown of the plant for safety reasons or refuse to permit restart of the unit after unplanned or planned outages. New or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. STP may be obligated to continue storing spent nuclear fuel if the Department of Energy continues to fail to meet its contractual obligations to STP made pursuant to the U.S. Nuclear Waste Policy Act of 1982 to accept and dispose of STP’s spent nuclear fuel. See “Business — Environmental Matters — U.S. Federal Environmental Initiatives — Nuclear Waste.” Costs associated with these risks could be substantial and have a material adverse effect on our results of operations, financial condition or cash flow. In addition, to the extent that all or a part of STP is required by the NRC to permanently or temporarily shut down or modify its operations, or is otherwise subject to a forced outage, NRG may incur additional costs to the extent it is obligated to provide power from more expensive alternative sources — either our own plants, third party generators or the ERCOT — to cover our then existing forward sale obligations. Such shutdown or modification could also lead to substantial costs related to the storage and disposal of radioactive materials and spent nuclear fuel.
      NRG and the other owners of STP maintain nuclear property and nuclear liability insurance coverage as required by law. The Price-Anderson Act, as amended by the Energy Policy Act of 2005, requires owners of nuclear power plants in the United States to be collectively responsible for retrospective secondary insurance premiums for liability to the public arising from nuclear incidents resulting in claims in excess of the required primary insurance coverage amount of $300 million per reactor. The Price-Anderson Act only covers nuclear liability associated with any accident in the course of operation of the nuclear reactor, transportation of nuclear fuel to the reactor site, in the storage of nuclear fuel and waste at the reactor site and the transportation of the spent nuclear fuel and nuclear waste from the nuclear reactor. All other non-nuclear liabilities are not covered. Any substantial retrospective premiums imposed under the Price-Anderson Act or losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.
 	 	
 	We are subject to environmental laws and regulations that impose extensive and increasingly stringent requirements on our ongoing operations, as well as potentially substantial liabilities arising out of environmental contamination. These environmental requirements and liabilities could adversely impact our results of operations, financial condition and cash flows.	
      Our business is subject to the environmental laws and regulations of foreign, federal, state and local authorities. We must comply with numerous environmental laws and regulations and obtain numerous governmental permits and approvals to operate our plants. If we fail to comply with any environmental requirements that apply to our operations, we could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions seeking to curtail our operations. In addition, when new requirements take effect or when existing environmental requirements are revised, reinterpreted or subject to changing enforcement policies, our business, results of operations, financial condition and cash flows could be adversely affected.

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      Environmental laws and regulations have generally become more stringent over time, and we expect this trend to continue. In particular, the U.S. Environmental Protection Agency, or USEPA, has recently promulgated regulations requiring additional reductions in nitrogen oxides, or NO X  and sulfur dioxide, or SO 2 , emissions, commencing in 2009 and 2010 respectively, and has also promulgated regulations requiring reductions in mercury emissions from coal-fired electric generating units, commencing in 2010 with more substantial reductions in 2018. These regulatory programs are currently subject to litigation and reconsideration by the USEPA, which could affect the timing of our future capital projects. Moreover, certain of the states in which we operate have promulgated air pollution control regulations which are more stringent than existing and proposed federal regulations. Ongoing public concerns about emissions of SO 2 , NO X , mercury and carbon dioxide and other greenhouse gases from power plants have resulted in proposed laws and regulations at the federal, state and regional levels that, if they were to take effect substantially as proposed, would likely apply to our operations. For example, we could incur substantial costs pursuant to the proposed multi-state carbon cap-and-trade program known as the Regional Greenhouse Gas Initiative, or RGGI, which would apply to the facilities in our Northeast region. A model rule for implementation of RGGI is expected to be released within the next few months.
      Significant capital expenditures may be required to keep our facilities compliant with environmental laws and regulations, and if it is not economical to make those capital expenditures then we may need to retire or mothball facilities, or restrict or modify our operations to comply with more stringent standards.
      Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. We are generally responsible for all liabilities associated with the environmental condition of our power generation plants, including any soil or groundwater contamination that may be present, regardless of when the liabilities arose and whether the liabilities are known or unknown, or arose from the activities of our predecessors or third parties. We are currently subject to remediation obligations at a number of our facilities.
 	 	
 	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. The closure or modification of any of our facilities could lead to substantial liabilities, including related to the cleanup of any contamination that occurred during the facility’s operation. While we believe that we meet, or are performing, all site remediation obligations currently applicable to our assets (including through the provision of various forms of financial assurance at certain facilities at which we are not currently required to perform remediation), more onerous obligations often 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 business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by our unionized employees.	
      As of December 31, 2005, approximately 46.0% of the Company’s employees at its U.S. generation plants would have been covered by collective bargaining agreements. In the event that our union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we would be responsible for procuring replacement labor or we could experience reduced power generation or outages. Our ability to procure such labor is uncertain. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 	Changes in technology may impair the value of our power plants.	
      Research and development activities are ongoing to provide alternative and more efficient technologies to produce power, including fuel cells, clean coal and coal gasification, micro-turbines, photovoltaic (solar) cells and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these or other technologies could reduce the costs of power production to a level below what we have currently forecasted, which could adversely affect our revenue, results of operations or competitive position.
 	 	
 	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 are subject to additional risks that our U.S. investments do not have.	
      We have investments in power projects in Australia, 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;	
 	 	 	
 	• 	restrictions on the repatriation of capital; and	
 	 	 	
 	• 	approval requirements and governmental policies limiting returns to foreign investors.	

 	Our plants are the subject of a number of lawsuits filed by individuals who claim injury due to exposure to asbestos while working at certain of our facilities.	
      Many of our plants have been subject to personal injury claims arising out of alleged exposure to asbestos. Most of the claimants who have brought such claims have been third-party workers who participated in the construction, renovation or repair of various industrial plants, including power plants. While many of the claimants have never worked at or near our plants, some of the claimants have worked at locations owned by us. While we have been dismissed from many of these lawsuits without having to make any payment to claimants, we have incurred and expect to continue to incur costs associated with these claims. We are also subject to claims for asbestos exposure in certain of its facilities, as well as claims for indemnity from previous owners of those facilities. We defend against these claims aggressively, and, thus, we have incurred and expect to continue to incur defense costs as a result of such claims. For further discussion of such claims, see “Business — Legal Proceedings.” If asbestos-related claims against us rise significantly or if insurance currently available for contribution to the payment of asbestos liabilities becomes unavailable (through insurer insolvencies, coverage disputes, changes in law or otherwise), asbestos liabilities could have a material adverse effect on our results of operations, financial condition and cash flows.

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 	Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, expose us to the risk of increased interest rates and limit our ability to react to changes in the economy or our industry.	
      Our substantial debt could have important consequences, including:
 	 	 	
 	• 	increasing our vulnerability to general economic and industry conditions;	
 	 	 	
 	• 	requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our preferred or common stock or to use our cash flow to fund our operations, capital expenditures and future business opportunities;	
 	 	 	
 	• 	limiting our ability to enter into long-term power sales or fuel purchases which require credit support;	
 	 	 	
 	• 	exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under our new senior secured credit facility are at variable rates of interest;	
 	 	 	
 	• 	making it more difficult for us to satisfy our obligations with respect to our notes;	
 	 	 	
 	• 	placing us at a competitive disadvantage compared to our competitors that have less debt;	
 	 	 	
 	• 	limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and	
 	 	 	
 	• 	limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who have less debt.	
      The indentures for the new notes and our new senior secured credit facility contain financial and other restrictive covenants that may limit our ability to engage in activities that may be in our long-term best interests. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of our borrowed indebtedness.
      In addition, our ability to arrange financing, either at the corporate level or at a non-recourse project-level subsidiary, and the costs of such capital are dependent on numerous factors, including:
 	 	 	
 	• 	general economic and capital market conditions;	
 	 	 	
 	• 	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 and compliance with covenants in debt agreements;	
 	 	 	
 	• 	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.
 	 	
 	We may not be able to realize the anticipated benefits from the Texas Genco Acquisition.	
      The success of the Acquisition will depend in part on NRG’s ability to consolidate and effectively integrate the Texas Genco assets, operations and employees into NRG. The integration will require substantial time and attention from our management. If the integration takes longer or is more complex or expensive than anticipated, or if we cannot operate our combined business as effectively as we anticipate, our operating performance and profitability could be materially adversely affected.

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      The Texas Genco power generation assets operate in the ERCOT market, a market in which NRG did not operate before the Acquisition. Accordingly, we are dependent upon the managers and employees who were in place at Texas Genco to manage those assets, and the loss of these key managers or employees could adversely affect our business.
      In addition, as a result of the Acquisition, we have assumed all of Texas Genco’s liabilities. After the Acquisition, we may learn additional information about Texas Genco’s business that adversely affects us, such as unknown or contingent liabilities, issues relating to internal controls over financial reporting and issues relating to compliance with applicable laws.
 	 	
 	Because the historical financial information may not be representative of our results as a combined company or capital structure after the Acquisition, and NRG’s and Texas Genco’s historical financial information are not comparable to their current financial information, you have limited financial information on which to evaluate us, NRG and Texas Genco.	
      NRG’s financial statements prior to December 5, 2003 are not comparable to its financial statements after that date. As a result of NRG’s emergence from bankruptcy, it is operating its business with a new capital structure, and is subject to Fresh Start reporting requirements prescribed by generally accepted accounting principles in the United States. As required by Fresh Start reporting, assets and liabilities as of December 6, 2003 were recorded at fair value, with the enterprise value being determined in connection with the reorganization.
      Texas Genco did not exist prior to July 19, 2004, and Texas Genco and its subsidiaries had no operations and no material activities until December 15, 2004 when Texas Genco acquired its gas and coal-fired assets. Consequently, Texas Genco’s historical financial information is not comparable to its current financial information.
      NRG and Texas Genco have been operating as separate companies prior to the Acquisition. We have had no prior history as a combined entity and our operations have not previously been managed on a combined basis. The historical financial statements may not reflect what our results of operations, financial position and cash flows would have been had we operated on a combined basis and may not be indicative of what our results of operations, financial position and cash flows will be in the future.
 	 	
 	Goodwill and/or other intangible assets that we will record in connection with the Acquisition are subject to mandatory annual impairment evaluations and as a result, the combined company could be required to write off some or all of this goodwill and other intangibles, which may adversely affect its financial condition and results of operations.	
      NRG will account for the Acquisition using the purchase method of accounting. The purchase price for Texas Genco will be allocated to identifiable tangible and intangible assets and assumed liabilities based on estimated fair values at the date of consummation of the Acquisition. Any unallocated portion of the purchase price will be allocated to goodwill. In accordance with Financial Accounting Standard No. 142, “Goodwill and Other Intangible Assets,” goodwill is not amortized but is reviewed annually or more frequently for impairment and other intangibles are also reviewed at least annually or more frequently, if certain conditions exist, and may be amortized. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings which could materially adversely affect our reported results of operations and financial position in future periods.

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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 1A and to the following:
 	 	 	
 	• 	General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel or other raw materials;	
 	 	 	
 	• 	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;	
 	 	 	
 	• 	The effectiveness of NRG’s risk management policies and procedures, and the ability of NRG’s counterparties to satisfy their financial commitments;	
 	 	 	
 	• 	Counterparties’ collateral demands and other factors affecting NRG’s liquidity position and financial condition;	
 	 	 	
 	• 	Our ability to operate its businesses efficiently, manage capital expenditures and costs tightly (including general and administrative expenses), and generate earnings and cash flow from its asset-based businesses in relation to its debt and other obligations; and	
 	 	 	
 	• 	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, 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;	
 	 	 	
 	• 	The success of the business following the acquisition of Texas Genco LLC;	
 	 	 	
 	• 	Operating and financial restrictions placed on us contained in the indentures governing our 7.25% and 7.375% unsecured senior notes due 2014 and 2016, respectively, our new senior secured credit facility and in debt and other agreements of certain of our subsidiaries and project affiliates generally; and	
 	 	 	
 	• 	Lack of comparable financial data due to adoption of Fresh Start reporting.	
      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 1B — Unresolved Staff Comments
      None.

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Item 2 — Properties
      Listed below are descriptions of our interests in facilities, operations and/or projects owned as of December 31, 2005, including such interests owned through Texas Genco. The MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the combined company’s ownership position excluding capacity from inactive/mothballed units as of December 31, 2005. Prior to the Texas Genco acquisition, our documents referenced the capacity of our generating equipment using Nameplate, or gross capacity (netted to reflect ownership position but inclusive of power which was absorbed internally). The MW numbers included units which are inactive but still owned by NRG. However, with the addition of the Texas assets and to provide a consistent measure across the fleet, NRG will now provide summer net MW capacity for active units only which is more representative of capacity available for sale in the marketplace.
Independent Power Production and Cogeneration Facilities
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generation	 	 	 	
 	 	Purchaser/Power	 	 	 	Capacity	 	 	 	
Name and Location of Facility	 	Market	 	% Owned	 	 	(MW)	 	 	Primary Fuel Type	
 	 	 	 	 	 	 	 	 	 	 	
Texas Region:	 	 	 	 	 	 	 	 	 	 	 	 	
W. A. Parish, Thompsons, TX	 	ERCOT	 	 	100.00	%	 	 	2,463	 	 	Low Sulfur Coal	
Limestone, Jewett, TX	 	ERCOT	 	 	100.00	%	 	 	1,614	 	 	Lignite/Low Sulfur Coal	
South Texas Project, Bay City, TX (1)	 	ERCOT	 	 	44.00	%	 	 	1,101	 	 	Nuclear	
Cedar Bayou, TX	 	ERCOT	 	 	100.00	%	 	 	1,498	 	 	Natural Gas	
T. H. Wharton, Houston, TX	 	ERCOT	 	 	100.00	%	 	 	1,025	 	 	Natural Gas	
W. A. Parish (Natural gas), Thompsons, TX	 	ERCOT	 	 	100.00	%	 	 	1,191	 	 	Natural Gas	
S. R. Bertron, Deer Park, TX	 	ERCOT	 	 	100.00	%	 	 	844	 	 	Natural Gas	
Greens Bayou, Houston, TX	 	ERCOT	 	 	100.00	%	 	 	760	 	 	Natural Gas	
San Jacinto, LaPorte, TX	 	ERCOT	 	 	100.00	%	 	 	162	 	 	Natural Gas	
Northeast Region:	 	 	 	 	 	 	 	 	 	 	 	 	
Oswego, New York	 	NYISO	 	 	100.00	%	 	 	1,634	 	 	Oil	
Arthur Kill, New York	 	NYISO	 	 	100.00	%	 	 	841	 	 	Natural Gas	
Middletown, Connecticut	 	ISO-NE	 	 	100.00	%	 	 	770	 	 	Oil	
Indian River, Delaware	 	PJM	 	 	100.00	%	 	 	737	 	 	Coal	
Astoria Gas Turbines, New York	 	NYISO	 	 	100.00	%	 	 	553	 	 	Natural Gas	
Dunkirk, New York	 	NYISO	 	 	100.00	%	 	 	522	 	 	Coal	
Huntley, New York	 	NYISO	 	 	100.00	%	 	 	552	 	 	Coal	
Montville, Connecticut	 	ISO-NE	 	 	100.00	%	 	 	497	 	 	Oil	
Norwalk Harbor, Connecticut	 	ISO-NE	 	 	100.00	%	 	 	342	 	 	Oil	
Devon, Connecticut	 	ISO-NE	 	 	100.00	%	 	 	124	 	 	Natural Gas	
Vienna, Maryland	 	PJM	 	 	100.00	%	 	 	170	 	 	Oil	
Somerset, Massachusetts	 	ISO-NE	 	 	100.00	%	 	 	127	 	 	Coal	
Connecticut Jet Power, Connecticut	 	ISO-NE	 	 	100.00	%	 	 	104	 	 	Oil	
Conemaugh, Pennsylvania	 	PJM	 	 	3.72	%	 	 	64	 	 	Coal	
Keystone, Pennsylvania	 	PJM	 	 	3.72	%	 	 	63	 	 	Coal	
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 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generation	 	 	 	
 	 	Purchaser/Power	 	 	 	Capacity	 	 	 	
Name and Location of Facility	 	Market	 	% Owned	 	 	(MW)	 	 	Primary Fuel Type	
 	 	 	 	 	 	 	 	 	 	 	
South Central Region:	 	 	 	 	 	 	 	 	 	 	 	 	
Big Cajun II, Louisiana(2)	 	SERC-Entergy	 	 	86.00	%	 	 	1,489	 	 	Coal	
Bayou Cove, Louisiana	 	SERC-Entergy	 	 	100.00	%	 	 	300	 	 	Natural Gas	
Big Cajun I, Louisiana	 	SERC-Entergy	 	 	100.00	%	 	 	210	 	 	Natural Gas	
Big Cajun I, Louisiana	 	SERC-Entergy	 	 	100.00	%	 	 	220	 	 	Natural Gas/Oil	
Sterlington, Louisiana	 	SERC-Entergy	 	 	100.00	%	 	 	176	 	 	Natural Gas	
Western Region:	 	 	 	 	 	 	 	 	 	 	 	 	
Encina, California	 	Cal ISO	 	 	50.00	%	 	 	483	 	 	Natural Gas	
El Segundo Power, California	 	Cal ISO	 	 	50.00	%	 	 	335	 	 	Natural Gas	
San Diego Combustion Turbines, California	 	Cal ISO	 	 	50.00	%	 	 	86	 	 	Natural Gas	
Saguaro Power Co., Nevada	 	WECC	 	 	50.00	%	 	 	46	 	 	Natural Gas	
Chowchilla, California	 	Cal ISO	 	 	100.00	%	 	 	49	 	 	Natural Gas	
Red Bluff, California	 	Cal ISO	 	 	100.00	%	 	 	45	 	 	Natural Gas	
Other North America Region:	 	 	 	 	 	 	 	 	 	 	 	 	
Audrain(3)	 	MISO	 	 	100.00	%	 	 	577	 	 	Natural Gas	
Rockford I, Illinois	 	PJM	 	 	100.00	%	 	 	310	 	 	Natural Gas	
Rocky Road Power, Illinois (3)	 	PJM	 	 	50.00	%	 	 	165	 	 	Natural Gas	
Rockford II, Illinois	 	PJM	 	 	100.00	%	 	 	160	 	 	Natural Gas	
Dover, Delaware	 	PJM	 	 	100.00	%	 	 	104	 	 	Natural Gas/Coal	
Power Smith Cogeneration, Oklahoma	 	SPP	 	 	6.25	%	 	 	7	 	 	Natural Gas	
Ilion, New York(3)	 	NYISO	 	 	100.00	%	 	 	58	 	 	Natural Gas	
James River, Virginia	 	SERC — TVA	 	 	50.00	%	 	 	55	 	 	Coal	
Cadillac, Michigan(3)	 	MISO	 	 	50.00	%	 	 	19	 	 	Wood	
Paxton Creek Cogeneration, Pennsylvania	 	PJM	 	 	100.00	%	 	 	12	 	 	Natural Gas	
Australia Region:	 	 	 	 	 	 	 	 	 	 	 	 	
Flinders, South Australia	 	South Australian Pool	 	 	100.00	%	 	 	700	 	 	Coal	
Gladstone Power Station, Queensland	 	Enertrade/Boyne Smelters	 	 	37.50	%	 	 	605	 	 	Coal	
Other International Region:	 	 	 	 	 	 	 	 	 	 	 	 	
Schkopau Power Station, Germany	 	Vattenfall Europe	 	 	41.90	%	 	 	400	 	 	Coal	
MIBRAG mbH, Germany(4)	 	ENVIA/MIBRAG Mines	 	 	50.00	%	 	 	55	 	 	Coal	
Itiquira Energetica, Brazil	 	COPEL	 	 	99.20	%	 	 	156	 	 	Hydro	

(1) 	For the nature of our interest and various limitations on our interest, please read Item 1 — Business — Texas — Facilities section.	
 	 	
(2) 	Units 1 and 2 owned 100%, Unit 3 owned 58%	
 	 	
(3) 	Committed to sell or may sell or dispose of in 2006	
 	 	
(4) 	Primarily a coal mining facility	
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Thermal Energy Production and Transmission Facilities and Resource Recovery Facilities
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	%	 	 	 	
Name and Location of	 	Year of	 	 	 	 	Ownership	 	 	Thermal Energy	
Facility	 	Acquisition	 	 	Generating Capacity(1)	 	Interest	 	 	Purchaser/MSW Supplier	
 	 	 	 	 	 	 	 	 	 	 	
NRG Energy Center
Minneapolis, MN	 	 	1993	 	 	Steam: 1,203 mmBtu/hr., (353 MWt) Chilled Water: 41,630 tons (146 MWt)	 	 	100%	 	 	Approx. 100 steam customers and 47 chilled water customers	
NRG Energy Center San
Francisco, CA	 	 	1999	 	 	Steam: 482 mmBtu/Hr. (141 MWt)	 	 	100%	 	 	Approx. 165 steam customers	
NRG Energy Center
Harrisburg, PA	 	 	2000	 	 	Steam: 440 mmBtu/hr. (129 MWt) Chilled water: 2,400 tons (8 MWt)	 	 	100%	 	 	Approx. 265 steam customers and 3 chilled water customers	
NRG Energy Center	 	 	1999	 	 	Steam: 266 mmBtu/hr. (78 MWt) Chilled water: 12,580 tons (44 MWt)	 	 	100%	 	 	Approx. 25 steam and 25 chilled water customers	
NRG Energy Center San
Diego, CA	 	 	1997	 	 	Chilled water: 7,425 tons (26 MWt)	 	 	100%	 	 	Approx. 20 chilled water customers	
NRG Energy Center St.
Paul, MN 	 	 	1992	 	 	Steam: 430 mmBtu/hr. (126 MWt)	 	 	100%	 	 	Rock-Tenn Company	
Camas Power Boiler,
Washington	 	 	1997	 	 	Steam: 200 mm Btu/hr. (59 MWt)	 	 	100%	 	 	Georgia-Pacific Corp.	
NRG Energy Center
Dover, DE	 	 	2000	 	 	Steam: 190 mmBtu/hr. (56 MWt)	 	 	100%	 	 	Kraft Foods Inc.	
NRG Energy Center Oak
Park Heights, MN	 	 	1992	 	 	Steam: 200 mmBtu/Hr. (59 MWt)	 	 	100%	 	 	Andersen Corp., MN Correctional Facility	

(1) 	Thermal production and transmission capacity is based on 1,000 Btus per pound of steam production or transmission capacity. The unit mmBtu is equal to one million Btus.	
     Listed below are descriptions of our significant resource recovery assets as of December 31, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	%	 	 	 	
 	 	Date of	 	 	 	 	Ownership	 	 	 	
Name and Location of Facility	 	Acquisition	 	 	Processing Capacity(1)	 	 	Interest	 	 	MSW Supplier	
 	 	 	 	 	 	 	 	 	 	 	 	
Newport, MN(1)	 	 	1993	 	 	 	MSW: 1,500 tons/day	 	 	 	100	%	 	Ramsey and Washington Counties	
Elk River, MN(2)	 	 	2001	 	 	 	MSW: 1,500 tons/day	 	 	 	85	%	 	Anoka, Hennepin and Sherburne Counties; Tri- County Solid Waste Management Commissioner	

(1) 	The Newport facilities are strictly related to garbage-sorting facilities.	
 	 	
(2) 	For the Elk River facility, NRG’s 85% interest is related strictly to garbage-sorting facilities.	
Other Properties
      In addition, we own various real property and facilities relating to our generation assets, other vacant real property unrelated to our generation assets, interests in other construction projects in various states of completion and properties not used for operational purposes. We believe we have satisfactory title to our plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in our opinion, would not have a material adverse effect on the use or value of our portfolio.
      We lease our corporate offices at 211 Carnegie Center, Princeton, New Jersey 08540 and various other office spaces.

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Item 3 — Legal Proceedings
California Electricity and Related Litigation
      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 found that federal jurisdiction was absent in the district court, and remanded 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 affirmed the District Court in most respects. On March 5, 2005, the Ninth Circuit denied a petition for rehearing and thereafter remanded the cases to San Diego Superior Court. NRG was dismissed on July 22, 2005. The remaining defendants including the WCP subsidiaries filed a motion to dismiss based on the filed rate doctrine and federal preemption which was granted on October 3, 2005. Although a judgment of dismissal with prejudice was entered on October 5, 2005, the Plaintiffs filed a notice of appeal on December 2, 2005, with the U.S. Court of Appeals for the Ninth Circuit. Where WCP or its subsidiaries are named, Dynegy is defending the named parties pursuant to an indemnification agreement.
      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 an indemnification agreement. The complaint seeks restitution and disgorgement, civil fines, compensatory and punitive damages, attorneys’ fees and declaratory and injunctive relief. Defendants’ 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. On February 19, 2004, the court stayed the case. Dynegy’s counsel is defending Dynegy and WCP and its subsidiaries in this case pursuant to an indemnification agreement. The defendants expect to seek dismissal of this case during 2006.
      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

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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. On April 18, 2005, the court granted defendants motion to dismiss based on the filed rate doctrine and federal preemption. On May 17, 2005, Plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Ninth Circuit. Dynegy is defending WCP pursuant to an 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. After the case was transferred to the U.S. District Court for the Southern District of California on February 11, 2005, the court granted defendants motion to dismiss the case based on the filed rate doctrine and federal preemption. On March 21, 2005, Plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Ninth Circuit. Dynegy is defending WCP and its subsidiaries pursuant to an 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 named WCP and Dynegy Holding Co., Inc. among the numerous defendants. The Complaints alleged violations of the federal Sherman Act, and California’s antitrust and unfair competition law as well as unjust enrichment. The Complaints sought 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. On December 19, 2005, the court granted defendants notice to dismiss based upon the filed rate doctrine and federal preemption. Dynegy is defending WCP pursuant to an indemnification agreement. On February 2, 2006, Dynegy settled the case on behalf of itself and WCP. A motion for approval of this settlement is expected to be filed by the plaintiffs by March 30, 2006.
      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. On September 30, 2005, the court granted Plaintiffs class action certification. On November 2, 2005, Dynegy entered into a settlement agreement with Plaintiffs that also resolves claims against the WCP subsidiaries. The settlement is awaiting court approval. Dynegy Marketing and Trade is defending WCP in these proceedings pursuant to an 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

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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;  Pabco Building Products v. Dynegy et al.,  San Diego Superior Court, Case No. GIC 856187,  filed November 22, 2005;  The Board of Trustees of California State University v. Dynegy et al.,  San Diego Superior Court, Case No. GIC 856188,  filed November 22, 2005.
      The defendants in all of the above referenced cases include WCP and various Dynegy entities. NRG 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, 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. Defendants motion to dismiss was denied by the Court on June 22, 2005, and the cases are in discovery. Dynegy is defending WCP pursuant to an indemnification agreement.
 	 	
 	California Electricity and Related Litigation Indemnification	
      On December 27, 2005, NRG entered into a purchase and sale agreement to acquire Dynegy’s 50% ownership interest in WCP Holdings to become the sole owner of the WCP power plants. The transaction, which is subject to regulatory approval, is expected to close in the first quarter of 2006. Pursuant to the indemnification agreement in the purchase and sale agreement, in the above referenced cases relating to natural gas, Dynegy is defending WCP and/or its subsidiaries and will be the responsible party for any loss. In the above referenced cases relating to electricity, Dynegy’s counsel is representing it and WCP and/or its subsidiaries with Dynegy and WCP each responsible for half of the costs and each party responsible for half of any loss. Where NRG is named as a party in the above referenced electricity cases, it is defending the case, bears its own costs of defense, and is responsible for any loss. Any new cases filed within these three categories of cases would be handled similarly.
 	 	
 	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. On February 1, 2006, NRG filed with the U.S. Bankruptcy Court for the Southern District of New York a Supplement to Objection to Claims filed by Oscars Photolab, claiming on behalf of Itself and All Other Similarly Stated California Business and Residential Ratepayers. Therein, NRG requested an order disallowing and expunging these proofs of claim.

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 	FERC Proceedings	
      There are a number of 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, or CDWR, and the State of California and certain of its agencies and departments. The CDWR claim involves a February 2002 complaint filed by the State of California demanding that FERC abrogate the CDWR contract between the State and subsidiaries of WCP and seeking refunds associated with the revenues collected by WCP from the CDWR. In 2003, FERC rejected the States complaint and subsequently denied rehearing. The State appealed to the U.S. Court of Appeals for the Ninth Circuit where all briefs were filed and oral argument was held on December 8, 2004. Pursuant to the December 27, 2005 purchase and sale agreement between NRG and Dynegy regarding the WCP power plants, we agreed to indemnify Dynegy with respect to the CDWR claim. However, to the effect any loss incurred is found to have resulted from Dynegy’s gross negligence or willful misconduct, then any such loss shall instead be shared evenly between Dynegy and us. The purchase and sale agreement is subject to regulatory approval and is expected to close in the first quarter of 2006.
      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 questioned whether 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. A motion for rehearing of the Order was denied by FERC on November 17, 2005. On January 13, 2006, the petitioners filed an appeal with the U.S. Court of Appeals for the District of Columbia Circuit. Based on the November 17, 2005 denial, we now deem the risk of loss to be remote.
      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

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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 $5 million.
      New York Public Interest Research Group (NYPIRG) v. Stephen L. Johnson, Administrator, U.S. Environmental Protection Agency ,  Case Nos.03-40846(L) and 03-40848 (CON), U.S. Court of Appeals for the Second Circuit.  In 2000, the New York State Department of Environmental Conservation, or NYSDEC, issued a NOV to the prior owner of the Huntley and Dunkirk stations. After an unsuccessful challenge to the stations’ Title V air quality permits by NYPIRG, it appealed. On October 24, 2005, the Second Circuit held that, during the Title V permitting process for the two stations, the 2000 NOV should have been sufficient for the NYSDEC to have made a finding that the stations were out of compliance. Accordingly, the court stated that the EPA should have objected to the Title V permits on that basis and the permits should have included compliance schedules. On June 3, 2005, the consent decree among NYSDEC, Niagara Mohawk Power Corporation and NRG was entered in federal court, settling the substantive issues discussed by the Second Circuit in its decision. NYSDEC is in the process of incorporating the consent decree obligations into the Huntley and Dunkirk Title V permits so as to make them permit conditions, an action we believe is supported by the decision. On January 12, 2006, the NYSDEC, the EPA, and NRG filed individual petitions for rehearing with the Second Circuit. On January 31, 2006, the court denied the petitions for re-hearing filed by the NYSDEC and the EPA. NRG’s petition for review en banc remains pending.
      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 sought to recover damages less payments received through the date of judgment, as well as additional amounts for electric service provided to the Dunkirk Plant. NiMo claimed 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. On October 8, 2002, a Stipulation and Order was entered staying this action pending resolution by FERC of some or all of the disputes in the action. The potential loss inclusive of amounts paid to NiMo and accrued is approximately $26 million.
      Niagara Mohawk Power Corporation v. Huntley Power LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC, and NRG Oswego Operations, Inc. ,  Case Filed November 26, 2002 in Federal Energy Regulatory Commission Docket No. EL 03-27-000.  This is the companion action to the above referenced action filed by NiMo at FERC asserting the same claims and legal theories. On November 19, 2004, FERC denied NiMo’s petition and ruled that the Huntley, Dunkirk and Oswego plants could net their service station obligations over a 30 calendar day period from the day NRG Energy acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities because they are interconnected to transmission and not to distribution. On April 22, 2005, FERC denied NiMo’s motion for rehearing and NiMo appealed to the U.S. Court of Appeals for the District of Columbia Circuit . On May 12, 2005, the court consolidated the appeal with several pending station service disputes involving NiMo.
      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 engineering procurement and construction contract between the parties. Itiquira sought Real 140 million and asserted that Inepar breached the contract. Inepar sought Real 39 million and alleged that Itiquira breached the contract. On September 2, 2005, the arbitration panel ruled in favor of Itiquira, awarding it Real 139 million and Inepar Real 4.7 million. Due to interest accrued from the commencement of the arbitration to the award date, Itiquira’s award is increased to

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approximately Real 227 million (U.S. $97 million, based on conversion rates as of December 31, 2005). On December 21, 2005, Inepar’s request for clarification of the arbitration panels decision was denied. Itiquira has commenced the lengthy process in Brazil to execute on the arbitral award. We are unable to predict the outcome of this execution process.
      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 March 16, 2005, the federal district court in Minnesota adopted the magistrate judge’s December 6, 2004, report and recommendations and dismissed the case. On May 13, 2005, the CFTC filed a notice of appeal with the U.S. Court of Appeals for the Eighth Circuit and its brief on August 9, 2005. On September 29, 2005, NRG replied and on October 28, 2005, the CFTC filed its reply brief. The parties are awaiting an argument date. The Bankruptcy Court has yet to schedule a hearing or rule on the CFTC’s pending motion to reinstate its expunged claim.
      Texas Commercial Energy v. TXU Energy, Inc. et al., Case No. 04-40962 U.S. District Court for the Southern District of Texas — Corpus Christi Division .  This lawsuit was filed against us, CenterPoint Energy, Inc., Reliant Energy, Inc., Reliant Electric Solutions, LLC, several other CenterPoint Energy and Reliant Energy subsidiaries, and a number of other participants in the ERCOT market. The plaintiff, a retail electricity provider in the Texas market served by ERCOT, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws and committed fraud and negligent misrepresentation. The lawsuit sought damages in excess of $500 million, exemplary damages, treble damages, interest, costs of suit and attorneys’ fees. In June 2004, the court dismissed plaintiff’s claims on jurisdictional grounds. In July      , 2004, the plaintiff filed an appeal with the U.S. Court of Appeals for the Fifth Circuit. The Fifth Circuit affirmed the lower court’s decision in June 2005. The plaintiff moved for a rehearing en banc which was subsequently denied. On January 9, 2006, the U.S. Supreme Court denied plaintiff’s petition for certiorari thereby ending recourse.
      Asbestos Litigation. Several of our plants are the subject of a number of lawsuits filed against numerous defendants by a large number of individuals who claim personal injury due to alleged exposure to asbestos while working at plant sites primarily in Texas. The overwhelming majority of these claimants are third party contractor or sub-contractors who participated in the construction, renovation, or repair of various industrial plants, including power plants. As of December 31, 2005, there were 3,803 claims pending in Texas. For the twelve months ended December 31, 2005, there were 268 claims filed, 146 claims settled, 1,261 claims dismissed or otherwise resolved with no payment, and the average settlement amount was approximately $3,600. While ultimate financial responsibility for uninsured losses relating to asbestos claims has been assumed by us, CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense from us. To date, costs of settlement and defense have not been material and a portion of the payments in respect of these claims have been offset by insurance recoveries.
      On May 19, 2005, amendments to the Texas Civil Practice and Remedies Code and other state codes were signed into law by the Governor of Texas. The law will make it more difficult for persons claiming personal injuries due to alleged exposure to asbestos to continue to pursue their claims when there is no medical evidence of an actual physical impairment caused by exposure to asbestos. The law precludes persons whose claims have not been adjudicated by September 1, 2005, from pursuing or advancing their claims until they have produced a report by a board-certified physician of an actual physical impairment caused by exposure to asbestos. In addition, Congress is currently considering the proposed Fairness in Asbestos Injury Resolution Act of 2005, which, if it becomes law, would require asbestos defendants and insurers to make payments into a privately-funded national asbestos compensation fund. Under the bill as currently drafted, any payments made by us would not be offset by any insurance recoveries.

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 	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, as such claims are resolved, the claimants are paid from the reserve on the same basis as if they had been paid out in the bankruptcy. To the extent the aggregate amount required to be paid on the disputed claims exceeds the amount remaining in the funded claims reserve, we will be obligated to provide additional cash and common stock to the satisfy the claims. Any excess funds in the disputed claims reserve will be reallocated to the creditor pool for the pro rata benefit of all allowed claims. The contributed common stock and cash in the reserves is held by 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.
      The face amount of the remaining unresolved claims is approximately $35 million, plus unresolved claims relating to the California power crisis in 2000-2001 and other claims of indefinite amount, but the Company estimates that the actual amount of these claims, once settled, will be less than $35 million. Based on these estimates, the Company believes that in order to assure sufficient funds to satisfy all remaining disputed claims the reserve needs to retain approximately $7 million in cash and approximately 650,000 shares of common stock. The reserve currently holds cash and stock in excess of these amounts, and the Company intends to make a supplemental distribution of the surplus on or about April 1, 2006. The total value of the planned distribution is approximately $137 million, based on the closing stock price on March 3, 2006, consisting of approximately $25 million in cash and 2,541,000 shares of NRG common stock. NRG’s chapter 11 creditors holding allowed claims in Class 5 are expected to receive approximately $22.13 per $1,000.00 of allowed claim, consisting of $4.05 in cash and 0.41 shares of NRG common stock. Creditors holding Class 6 allowed claims are expected to receive approximately $19.97 per $1,000.00 of allowed claim, consisting of $1.89 in cash and 0.41 shares of NRG common stock.
 	 	
Item 4 —	Submission of Matters to a Vote of Security Holders	
      None.

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PART II
 	 	
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	
Market Information and Holders
      In connection with the consummation of our reorganization, on December 5, 2003, all shares of our old common stock were canceled and 100,000,000 shares of new common stock of NRG 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 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 for each of the following shares of preferred stock: (i) our 4% Convertible Perpetual Preferred Stock: (ii) our 3.625% Convertible Perpetual Preferred Stock and (iii) our 5.75% Mandatory Convertible Preferred Stock. We also issued 35,406,292 shares of our common stock in connection with the Texas Genco Acquisition as described below. Also in connection with the Texas Genco Acquisition we issued 20,855,057 shares of common stock in a public offering; 2,000,000 shares of our 5.75% Mandatory Convertible Preferred Stock in a public offering; and $3.6 billion of unsecured high yield notes.
      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 2005 and 2004 are set forth below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Fourth	 	 	Third	 	 	Second	 	 	First	 	 	Fourth	 	 	Third	 	 	Second	 	 	First	 	
 	 	Quarter	 	 	Quarter	 	 	Quarter	 	 	Quarter	 	 	Quarter	 	 	Quarter	 	 	Quarter	 	 	Quarter	 	
Common Stock Price	 	2005	 	 	2005	 	 	2005	 	 	2005	 	 	2004	 	 	2004	 	 	2004	 	 	2004	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
High	 	$	49.44	 	 	$	44.45	 	 	$	37.61	 	 	$	39.10	 	 	$	36.18	 	 	$	28.43	 	 	$	24.80	 	 	$	22.50	 	
Low	 	$	37.60	 	 	$	36.40	 	 	$	30.30	 	 	$	32.79	 	 	$	26.00	 	 	$	24.10	 	 	$	19.17	 	 	$	18.10	 	
Closing	 	$	47.12	 	 	$	42.60	 	 	$	30.70	 	 	$	34.15	 	 	$	36.05	 	 	$	26.94	 	 	$	24.80	 	 	$	22.20	 	
      NRG had 80,701,888 shares outstanding as of December 31, 2005, and as of March 3, 2006, there were 136,975,275 shares outstanding. As of February 10, 2006, there were approximately 27,000 common stockholders of record.
Dividends
      We have not declared or paid dividends on our common stock and the amount available for dividends is currently limited by our senior secured credit agreements and high yield note indentures.
Recent Sale of Unregistered Securities; Repurchase of Common Stock
      On February 2, 2006, NRG acquired Texas Genco LLC, a Delaware limited liability company, by purchasing all of the outstanding equity interests in Texas Genco pursuant to the Acquisition Agreement, dated September 30, 2005, by and among NRG, Texas Genco, and each of the direct and indirect owners of Texas Genco, or the Sellers. A portion of the consideration paid to the Sellers consisted of 35,406,292 shares of our common stock to the Sellers in a private placement in reliance on Section 4(2) of the Securities Act of 1933, as amended.

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      On August 11, 2005, we entered into an Accelerated Share Repurchase Agreement with Credit Suisse First Boston, or CSFB, pursuant to which we repurchased $250 million of our common stock on that date that equaled a total of 6,346,788 shares, which were held in treasury. We funded the repurchase with cash on hand. On March 3, 2006, we paid to CSFB a cash purchase price adjustment of approximately $7 million based upon the weighted average value of NRG’s common stock over a period of approximately six months, subject to a minimum price of 97% and a maximum price of 103% of the closing price per share on August 10, 2005, or $39.39.
      The following table summarizes the stock repurchased by NRG Energy:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Total Number	 	 	Maximum Number	 	
 	 	 	 	 	 	of Shares	 	 	of Shares That	 	
 	 	Total Number	 	 	Average Price	 	 	Purchased as	 	 	May Yet be	 	
 	 	of Shares	 	 	Paid per	 	 	Part of Publicly	 	 	Purchased Under	 	
Period	 	Purchased	 	 	Share	 	 	Announced Plans	 	 	the Plans	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
August 11, 2005	 	 	6,346,788*	 	 	$	39.90	 	 	 	none	 	 	 	N/A	 	

* 	6,346,788 shares were purchased as part of the Accelerated Share Repurchase Agreement with CSFB as described above.	
Redemption and Repurchase of Second Priority Notes
      During 2005 we redeemed and repurchased approximately $645 million of our Second Priority Notes in a number of stages as described in the following table:
 	 	 	 	 	
Date of	 	 	 	 	
Redemption	 	 	 	 	
or Repurchase	 	Amount	 	Source	
 	 	 	 	 	
January 2005	 	$25 million face value repurchased	 	Existing cash	
February 2005	 	$375 million redeemed	 	Proceeds from the sale of the 4% Preferred Stock in December 2004	
March 2005	 	$15.8 million face value repurchased	 	Existing Cash	
September 2005	 	$229 million redeemed	 	Proceeds from the sale of the 3.625% Preferred Stock in August 2005	
      As of December 31, 2005, the outstanding balance of our Second Priority Notes was approximately $1.1 billion. All outstanding Second Priority Notes were tendered, paid off and defeased on February 2-3, 2006, using funds received from a number of financial transactions as described in Item 15 — Note 34 to the Consolidated Financial Statements.

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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	 	 	2,593,179	 	 	$	25.04	 	 	 	1,355,193*	 	
Equity compensation plans not approved by security holders	 	 	—	 	 	 	n/a	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
 	Total	 	 	2,593,179	 	 	$	25.04	 	 	 	1,355,193*	 	

 	 	
* 	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 1,355,193 and 2,053,294 shares of common stock remaining available for grants of stock options under our Long-Term Incentive Plan as of December 31, 2005 and 2004, respectively.	
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Item 6 —	Selected Financial Data	
      The following table presents our historical 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. The historical financial data does not reflect any amounts for the purchase of Texas Genco as the Acquisition closed after December 31, 2005.
      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	 	
 	 	Year Ended December 31,	 	 	December 6 -	 	 	 	January 1 -	 	 	December 31,	 	
 	 	 	 	 	December 31,	 	 	 	December 5,	 	 	 	 	
 	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	 	2002	 	 	2001	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions, except per share amounts)	 	
Revenues from majority-owned operations	 	$	2,708	 	 	$	2,348	 	 	$	137	 	 	 	$	1,798	 	 	$	1,926	 	 	$	2,085	 	
Corporate relocation charges	 	 	6	 	 	 	16	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	—	 	
Reorganization, restructuring and impairment charges	 	 	6	 	 	 	32	 	 	 	2	 	 	 	 	435	 	 	 	2,497	 	 	 	—	 	
Fresh start reporting adjustments	 	 	 —	 	 	 	—	 	 	 	—	 	 	 	 	(4,220	)	 	 	—	 	 	 	—	 	
Legal settlement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	463	 	 	 	—	 	 	 	—	 	
Total operating costs and expenses	 	 	2,470	 	 	 	1,955	 	 	 	122	 	 	 	 	(1,587	)	 	 	4,231	 	 	 	1,704	 	
Write downs and losses on equity method investments	 	 	(31	)	 	 	(16	)	 	 	—	 	 	 	 	(147	)	 	 	(200	)	 	 	—	 	
Income/(loss) from continuing operations	 	 	77	 	 	 	161	 	 	 	11	 	 	 	 	3,082	 	 	 	(2,693	)	 	 	211	 	
Income/(loss) from discontinued operations, net	 	 	7	 	 	 	25	 	 	 	—	 	 	 	 	(316	)	 	 	(771	)	 	 	55	 	
Net income/(loss)	 	 	84	 	 	 	186	 	 	 	11	 	 	 	 	2,766	 	 	 	(3,464	)	 	 	265	 	
Income/(loss) from continuing operations per weighted average share — basic	 	$	0.67	 	 	$	1.61	 	 	$	0.11	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations per weighted average share — diluted	 	$	0.66	 	 	$	1.60	 	 	$	0.11	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total assets	 	 	7,431	 	 	 	7,864	 	 	 	9,315	 	 	 	 	N/A	 	 	 	10,897	 	 	 	12,915	 	
Long-term debt, including current maturities	 	$	2,682	 	 	$	3,484	 	 	$	3,846	 	 	 	 	N/A	 	 	$	7,217	 	 	$	6,291	 	
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      The following table provides the detail of our revenues from majority-owned operations:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	 	 	Predecessor Company	 	
 	 	 	 	 	 	 	 	
 	 	Year Ended	 	 	 	 	 	 	 	Year Ended	 	
 	 	December 31,	 	 	December 6 -	 	 	 	January 1 -	 	 	December 31,	 	
 	 	 	 	 	December 31,	 	 	 	December 5,	 	 	 	 	
 	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	 	2002	 	 	2001	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Energy	 	$	2,014	 	 	$	1,364	 	 	$	64	 	 	 	$	910	 	 	$	1,172	 	 	$	1,376	 	
Capacity	 	 	563	 	 	 	612	 	 	 	37	 	 	 	 	566	 	 	 	553	 	 	 	490	 	
Hedging and risk management activities	 	 	(248	)	 	 	76	 	 	 	2	 	 	 	 	19	 	 	 	7	 	 	 	—	 	
Alternative energy	 	 	191	 	 	 	176	 	 	 	12	 	 	 	 	82	 	 	 	98	 	 	 	162	 	
O&M fees	 	 	20	 	 	 	21	 	 	 	1	 	 	 	 	13	 	 	 	14	 	 	 	16	 	
Other	 	 	168	 	 	 	99	 	 	 	21	 	 	 	 	208	 	 	 	82	 	 	 	41	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues from majority-owned operations	 	$	2,708	 	 	$	2,348	 	 	$	137	 	 	 	$	1,798	 	 	$	1,926	 	 	$	2,085	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      Energy 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.
      Hedging and Risk management activities includes fair value changes of financial instruments (derivatives) that have yet to be settled for the period, as well as, the revenues derived from the settlement of financial transactions relating to the sale of energy or fuel which do not require the physical delivery of the underlying commodity.
      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. 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.

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Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	
Introduction and 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. As of the close of the Acquisition, our principal domestic generation assets consist of a diversified mix of natural gas-, coal-, oil-fired and nuclear facilities, representing approximately 45%, 34%, 16% and 5% of our total domestic generation capacity, respectively. In addition, 10% of our domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option.
      In this discussion and analysis, we will discuss and explain the general financial condition and the results of operations for NRG during 2005 that will include the points below:
 	 	 	
 	• 	Factors which affect our business,	
 	 	 	
 	• 	Our earnings and costs in the periods presented,	
 	 	 	
 	• 	Changes in earnings and costs between periods,	
 	 	 	
 	• 	Sources of earnings,	
 	 	 	
 	• 	Impact of these factors on our overall financial condition,	
 	 	 	
 	• 	A discussion of known trends, including the expected impact of the Texas Genco Acquisition, that will affect our future results of operations and financial condition,	
 	 	 	
 	• 	Expected future expenditures for capital projects, and	
 	 	 	
 	• 	Expected sources of cash for future operations and capital expenditures.	
      As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for the years ended December 31, 2005 and 2004, the period of December 6, 2003 through December 31, 2003 and for the period of January 1, 2003 through December 5, 2003. We analyze and explain the differences between periods in the specific line items of our Consolidated Statements of Income. However, it is important to note that the historical financial information does not include any results of operation or the financial condition of Texas Genco.
      We have organized our discussion and analysis as follows:
 	 	 	
 	• 	First, we discuss our strategy.	
 	 	 	
 	• 	We then describe the business environment in which we operate including how regulation, weather, and other factors affect our business.	
 	 	 	
 	• 	We highlight significant events that are important to understanding our results of operations and financial condition.	
 	 	 	
 	• 	We then review our results of operations discussing:	

 	• 	An overview of our total company results, followed by a more detailed review of those results by operating segment.	
 	 	 	
 	• 	Known trends that will affect our results of operations in the future.	

 	• 	We review our financial condition addressing:	

 	• 	Our sources and uses of cash, credit ratings, capital resources and requirements, commitments, and off-balance sheet arrangements.	
 	 	 	
 	• 	Known trends that will affect our financial condition in the future.	
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 	• 	Next, we discuss our critical accounting policies. These are the accounting policies that are most important to both the portrayal of our financial condition and results of operations and require management’s most difficult, subjective or complex judgment.	
Our Strategy
      Our strategy is to optimize the value of our generation assets while using that asset base as a platform for enhanced financial performance which can be sustained and expanded upon in years to come. We plan to maintain and enhance our position as a leading wholesale power generation company in the United States in a cost effective and risk-mitigating manner in order to serve the bulk power requirements of our customer base and other entities that offer load, or otherwise consume wholesale electricity products and services in bulk. Our strategy includes the following elements:
 	 	
 	      Increase value from our existing assets. We have a highly diversified portfolio of power generation assets in terms of region, fuel type and dispatch levels. We will continue to focus on extracting value from our portfolio by improving plant performance, reducing costs and harnessing our advantages of scale in the procurement of fuels: a strategy that we have branded  “FOR NRG, ”  or Focus on ROIC@NRG.	
 	 	
 	      Pursue intrinsic growth opportunities at existing sites in our core regions. We are favorably positioned to pursue growth opportunities through expansion of our existing generating capacity. We intend to invest in our existing assets through plant improvements, repowering and brownfield development to meet anticipated regional requirements for new capacity. We expect that these efforts will provide more efficient energy, lower our delivered cost, expand our electricity production capability and improve our ability to dispatch economically across all sections of the merit order, including baseload, intermediate and peaking generation.	
 	 	
 	      Maintain financial strength and flexibility. We remain focused on increasing cash flow and maintaining liquidity and balance sheet strength in order to ensure continued access to capital for growth; enhancing risk-adjusted returns; and providing flexibility in executing our business strategy. We will continue our focus on maintaining operational and financial controls designed to ensure that our financial position remains strong.	
 	 	
 	      Reduce the volatility of our cash flows through asset-based commodity hedging activities. We will continue to execute asset-based risk management, hedging, marketing and trading strategies within well-defined risk and liquidity guidelines in order to manage the value of our physical and contractual assets. Our marketing and hedging philosophy is centered on generating stable returns from our portfolio of power generation assets while preserving the ability to capitalize on strong spot market conditions and to capture the extrinsic value of our portfolio. We believe that we can successfully execute this strategy by taking advantage of our expertise in marketing power and ancillary services, our knowledge of markets, our flexible financial structure and our diverse portfolio of power generation assets.	
 	 	
 	      Participate in continued industry consolidation. We will continue to pursue selective acquisitions, joint ventures and divestitures to enhance our asset mix and competitive position in our core regions to meet the fuel and dispatch requirements in these regions. We intend to concentrate on acquisition and joint venture opportunities that present attractive risk-adjusted returns. We will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures during the consolidation of the power generation industry in the United States.	
Business Environment
      General Industry — This past year, the energy and power sector has been shaken by significant events and change. These have shifted the industry’s focus toward more efficient energy and fuel management, infrastructure developmental needs, and scope and scale merits. Those events include:
 	 	 	
 	• 	Hurricanes Katrina and Rita exacerbated an already tight national natural gas production and delivery system during record summer demand. This led to significant price spikes and volatility across all fuel sources, which in turn spurred regulatory concerns over excessive burdens on retail consumers and	
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 	 	renewed interest by incumbent utilities in securing long-term power supplies that are not tied to the price of natural gas.	
 	 	 	
 	• 	The Energy Policy Act of 2005, or EPAct, the most comprehensive energy legislation in more than a decade, was enacted in August 2005. EPAct reinforces FERC oversight and monitoring responsibilities and encourages the development of regulatory framework that provide the appropriate market signals for increased infrastructure investment including generation.	
 	 	 	
 	• 	While financial and strategic buyers continue to participate in energy sector asset sales and acquisitions, there has been renewed interest within the power sector for scope and scale and renewed merger and acquisitions activities by existing owners of power generation. This year has also seen regulated utilities seeking to participate in the competitive markets through outright combinations with deregulated entities.	
 	 	 	
 	• 	The EPA released its CAIR and CAMR guidelines in March. While there continues to be uncertainty as to the implementation standards by certain states, these environmental requirements coupled with potential improved scrubber technologies provide additional clarity with respect to longer term compliance strategies that will drive higher capital expenditure programs towards the end of the decade for many energy providers.	
 	 	 	
 	• 	There has been contentious but continued progress towards capacity markets evolution in order to meet increasing demand and encourage new investment in transmission and generation in load pockets around the country, including New England and California.	
      Competition — Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We compete on the basis of the location of our plants and owning multiple plants in our regions, which increases the stability and reliability of our energy supply. Wholesale power generation is fundamentally a local business which, at present, is highly fragmented (relative to other commodity industries) and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies we compete against from market to market.
      Regulatory Matters — As an operator of power plants and a participant in wholesale energy markets, we are subject to regulation by various federal and state government agencies. These include FERC, NRC, PUCT and certain state public utility commissions in which our generating assets are located. In addition, we are also subject to the market rules, procedures and protocols of the various ISO markets in which we participate. The plant operations of, and wholesale electric sales from our Texas assets are not currently subject to regulation by FERC, as they are deemed to operate solely within the ERCOT and not in interstate commerce. These operations are subject to regulations by PUCT as well as to regulation by the NRC with respect to its ownership interest in the STP.
      Weather — Weather conditions in the different regions of the United States influence the financial results of our business. Weather conditions can affect the supply of and demand for electricity and fuels. Changes in energy supply and demand may impact the price of these energy commodities in both the spot market and the forward market, which may affect our results in any given period. Typically, demand for electricity and its price are higher in the summer and the winter, when temperatures are more extreme. The demand for and price of natural gas and oil are higher in the winter. However, all regions of North America typically do not experience extreme weather conditions at the same time, thus we are not typically exposed to the effects of extreme weather in all parts of our business at once.
      Other Factors — A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for our business. These factors include:
 	 	 	
 	• 	seasonal daily and hourly changes in demand,	
 	 	 	
 	• 	extreme peak demands,	
 	 	 	
 	• 	available supply resources,	
 	 	 	
 	• 	transportation and transmission availability and reliability within and between regions,	
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 	• 	location of our generating facilities relative to the location of our load-serving opportunities,	
 	 	 	
 	• 	procedures used to maintain the integrity of the physical electricity system during extreme conditions, and	
 	 	 	
 	• 	changes in the nature and extent of federal and state regulations	
      These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in:
 	 	 	
 	• 	weather conditions,	
 	 	 	
 	• 	market liquidity,	
 	 	 	
 	• 	capability and reliability of the physical electricity and gas systems,	
 	 	 	
 	• 	local transportation systems, and	
 	 	 	
 	• 	the nature and extent of electricity deregulation.	
      Environmental Matters and Legal Proceedings — We discuss details of our environmental matters in Item 15 — Note 27 to our Consolidated Financial Statements and Item 1 Business — Environmental Matters section. We discuss details of our legal proceedings in Item 15 — Note 25 to our Consolidated Financial Statements. Some of this information is about costs that may be material to our financial results.
      Impact of inflation on our results — Unless discussed specifically in the relevant segment, for the years ended December 31, 2005 and 2004, the period of December 6 through December 31, 2003 and the period January 1, 2003 through December 5, 2003 the impact of inflation and changing prices (due to changes in exchange rates) on our revenue and income from continuing operations was immaterial.
Results of Operations
      Note: These historical results do not include the results of Texas Genco, and therefore represent the results of NRG Energy, Inc.’s consolidated results only for the periods presented.

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      The following table provides operating income by segment for the year ended December 31, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	For the Year Ended December 31, 2005	 	
 	 	 	 	
 	 	 	 	South	 	 	 	 	Other North	 	 	 	
 	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	All Other	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions, except MWh, CDD and HDD data)	 	
Energy revenue	 	$	1,444	 	 	$	330	 	 	$	1	 	 	$	11	 	 	$	144	 	 	$	84	 	 	$	2,014	 	
Capacity revenue	 	 	291	 	 	 	186	 	 	 	—	 	 	 	5	 	 	 	—	 	 	 	81	 	 	 	563	 	
Hedging & risk management activity	 	 	(285	)	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	43	 	 	 	(5	)	 	 	(248	)	
Alternative revenue	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	—	 	 	 	189	 	 	 	191	 	
O&M fees	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	20	 	 	 	20	 	
Other revenue	 	 	104	 	 	 	37	 	 	 	 	 	 	 	(3	)	 	 	25	 	 	 	5	 	 	 	168	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Operating revenues	 	 	1,554	 	 	 	552	 	 	 	1	 	 	 	15	 	 	 	212	 	 	 	374	 	 	 	2,708	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of energy	 	 	871	 	 	 	368	 	 	 	1	 	 	 	14	 	 	 	93	 	 	 	182	 	 	 	1,529	 	
Derivative cost of energy	 	 	(2	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(2	)	
Other operating expenses (1)	 	 	393	 	 	 	104	 	 	 	5	 	 	 	16	 	 	 	99	 	 	 	121	 	 	 	738	 	
Depreciation and amortization	 	 	74	 	 	 	61	 	 	 	1	 	 	 	7	 	 	 	27	 	 	 	24	 	 	 	194	 	
Operating income/ (loss)	 	 	218	 	 	 	20	 	 	 	(6	)	 	 	(28	)	 	 	(7	)	 	 	41	 	 	 	238	 	
MWh sold(2) (in thousands)	 	 	16,128	 	 	 	11,710	 	 	 	6	 	 	 	77	 	 	 	5,495	 	 	 	 	 	 	 	 	 	
Market indicators:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average natural gas price — Henry Hub ($/MMbtu)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	8.89	 	
Average on-peak market power prices ($/MWh)	 	$	91.98	 	 	$	69.96	 	 	$	71.06	 	 	$	63.76	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cooling Degree Days, or CDDs (3)	 	 	1,604	 	 	 	2,825	 	 	 	776	 	 	 	970	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDD’s 30 year rolling average	 	 	1,073	 	 	 	2,449	 	 	 	704	 	 	 	708	 	 	 	 	 	 	 	 	 	 	 	 	 	
Heating Degree Days, or HDDs (3)	 	 	10,449	 	 	 	1,638	 	 	 	2,563	 	 	 	5,095	 	 	 	 	 	 	 	 	 	 	 	 	 	
HDD’s 30 year rolling average	 	 	10,479	 	 	 	1,888	 	 	 	2,790	 	 	 	5,436	 	 	 	 	 	 	 	 	 	 	 	 	 	

(1) 	Other operating expenses include “Cost of majority-owned operations” and “General, administrative and development” expenses, excluding cost of energy.	
 	 	
(2) 	Includes MWhs sold for wholly owned subsidiaries only.	
 	 	
(3) 	National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/ HDDs for a period of time are calculated by adding the CDDs/ HDDs for each day during the period.	
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     The following table provides operating income by segment for the year ended December 31, 2004:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	For the Year Ended December 31, 2004	 	
 	 	 	 	
 	 	 	 	South	 	 	 	 	Other North	 	 	 	
 	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	All Other	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions, except MWh, CDD and HDD data)	 	
Energy revenue	 	$	853	 	 	$	219	 	 	$	10	 	 	$	15	 	 	$	159	 	 	$	109	 	 	$	1,365	 	
Capacity revenue	 	 	265	 	 	 	183	 	 	 	(4	)	 	 	84	 	 	 	—	 	 	 	84	 	 	 	612	 	
Hedging & risk management activity	 	 	58	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	15	 	 	 	2	 	 	 	76	 	
Alternative revenue	 	 	 —	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	—	 	 	 	174	 	 	 	176	 	
O&M fees	 	 	 —	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	21	 	 	 	21	 	
Other revenue	 	 	75	 	 	 	16	 	 	 	(3	)	 	 	(8	)	 	 	7	 	 	 	11	 	 	 	98	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Operating revenues	 	 	1,251	 	 	 	418	 	 	 	3	 	 	 	94	 	 	 	181	 	 	 	401	 	 	 	2,348	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of energy	 	 	521	 	 	 	223	 	 	 	5	 	 	 	10	 	 	 	79	 	 	 	168	 	 	 	1,006	 	
Derivative cost of energy	 	 	 —	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Other operating expenses (1)	 	 	338	 	 	 	71	 	 	 	5	 	 	 	42	 	 	 	83	 	 	 	154	 	 	 	693	 	
Depreciation and amortization	 	 	73	 	 	 	62	 	 	 	1	 	 	 	21	 	 	 	24	 	 	 	27	 	 	 	208	 	
Operating income/(loss)	 	 	318	 	 	 	58	 	 	 	(9	)	 	 	(5	)	 	 	(5	)	 	 	36	 	 	 	393	 	
MWh sold(2) (in thousands)	 	 	14,259	 	 	 	10,569	 	 	 	77	 	 	 	5	 	 	 	5,189	 	 	 	 	 	 	 	 	 	
Market indicators:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average natural gas price — Henry Hub ($/MMbtu)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	5.89	 	
Average on-peak market power prices ($/MWh)	 	$	63.53	 	 	$	45.76	 	 	$	53.16	 	 	$	43.31	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cooling Degree Days, or CDDs (3)	 	 	1,031	 	 	 	2,547	 	 	 	888	 	 	 	590	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDD’s 30 year rolling average	 	 	1,073	 	 	 	2,449	 	 	 	704	 	 	 	708	 	 	 	 	 	 	 	 	 	 	 	 	 	
Heating Degree Days, or HDDs (3)	 	 	10,256	 	 	 	1,557	 	 	 	2,347	 	 	 	4,987	 	 	 	 	 	 	 	 	 	 	 	 	 	
HDD’s 30 year rolling average	 	 	10,479	 	 	 	1,888	 	 	 	2,790	 	 	 	5,436	 	 	 	 	 	 	 	 	 	 	 	 	 	

(1) 	Other operating expenses include “Cost of majority-owned operations” and “General, administrative and development” expenses, excluding cost of energy.	
 	 	
(2) 	Includes MWhs sold for wholly owned subsidiaries only.	
 	 	
(3) 	National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/ HDDs for a period of time are calculated by adding the CDDs/ HDDs for each day during the period.	
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     The following table provides operating income by segment for the period December 6, 2003 through December 31, 2003:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	For the Period from December 6, 2003 through December 31, 2003	 	
 	 	 	 	
 	 	 	 	South	 	 	 	 	Other North	 	 	 	
 	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	All Other	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions, except MWh, CDD and HDD data)	 	
Energy revenue	 	$	49	 	 	$	15	 	 	$	—	 	 	$	—	 	 	$	10	 	 	$	(10	)	 	$	64	 	
Capacity revenue	 	 	14	 	 	 	11	 	 	 	—	 	 	 	5	 	 	 	—	 	 	 	7	 	 	 	37	 	
Hedging & risk management activity	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	—	 	 	 	2	 	
Alternative revenue	 	 	—	 	 	 	—	 	 	 	 	 	 	 	 	 	 	 	—	 	 	 	12	 	 	 	12	 	
O&M fees	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	1	 	
Other revenue	 	 	6	 	 	 	1	 	 	 	—	 	 	 	(1	)	 	 	—	 	 	 	15	 	 	 	21	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Operating revenues	 	 	69	 	 	 	27	 	 	 	 	 	 	 	4	 	 	 	12	 	 	 	25	 	 	 	137	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of energy	 	 	28	 	 	 	15	 	 	 	 	 	 	 	 	 	 	 	6	 	 	 	14	 	 	 	63	 	
Derivative cost of energy	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Other operating expenses (1)	 	 	25	 	 	 	4	 	 	 	—	 	 	 	3	 	 	 	4	 	 	 	9	 	 	 	45	 	
Depreciation and amortization	 	 	5	 	 	 	3	 	 	 	—	 	 	 	2	 	 	 	1	 	 	 	1	 	 	 	12	 	
Operating income/(loss)	 	 	11	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	15	 	
Market indicators:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average natural gas price — Henry Hub ($/MMbtu)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	6.28	 	
Average on-peak market power prices ($/MWh)	 	$	60.75	 	 	$	39.98	 	 	$	49.08	 	 	$	33.09	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cooling Degree Days, or CDDs (3)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDD’s 30 year rolling average	 	 	1,073	 	 	 	2,449	 	 	 	704	 	 	 	708	 	 	 	 	 	 	 	 	 	 	 	 	 	
Heating Degree Days, or HDDs (3)	 	 	1,494	 	 	 	377	 	 	 	427	 	 	 	803	 	 	 	 	 	 	 	 	 	 	 	 	 	
HDD’s 30 year rolling average	 	 	10,479	 	 	 	1,888	 	 	 	2,790	 	 	 	5,436	 	 	 	 	 	 	 	 	 	 	 	 	 	

(1) 	Other operating expenses include “Cost of majority-owned operations” and “General, administrative and development” expenses, excluding cost of energy.	
 	 	
(2) 	Includes MWhs sold for wholly owned subsidiaries only.	
 	 	
(3) 	National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/ HDDs for a period of time are calculated by adding the CDDs/ HDDs for each day during the period.	
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     Upon our emergence from bankruptcy, we adopted the Fresh Start Reporting 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 provides operating income by segment for the period January 1, 2003 through December 5, 2003:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor NRG	 	
 	 	 	 	
 	 	For the Period from January 1, 2003 through December 5, 2003	 	
 	 	 	 	
 	 	 	 	South	 	 	 	 	Other North	 	 	 	
 	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	All Other	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(in millions, except MWh, CDD and HDD data)	 	
Energy revenue	 	$	554	 	 	$	196	 	 	$	5	 	 	$	9	 	 	$	122	 	 	$	24	 	 	$	910	 	
Capacity revenue	 	 	235	 	 	 	160	 	 	 	19	 	 	 	74	 	 	 	—	 	 	 	78	 	 	 	566	 	
Hedging & risk management activity	 	 	19	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	19	 	
Alternative revenue	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	—	 	 	 	80	 	 	 	82	 	
O&M fees	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	—	 	 	 	11	 	 	 	13	 	
Other revenue	 	 	53	 	 	 	1	 	 	 	—	 	 	 	(1	)	 	 	29	 	 	 	126	 	 	 	208	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Operating revenues	 	 	861	 	 	 	357	 	 	 	24	 	 	 	86	 	 	 	151	 	 	 	319	 	 	 	1,798	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of energy	 	 	470	 	 	 	188	 	 	 	4	 	 	 	7	 	 	 	72	 	 	 	104	 	 	 	845	 	
Derivative cost of energy	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(9	)	 	 	—	 	 	 	(5	)	
Other operating expenses (1)	 	 	326	 	 	 	59	 	 	 	4	 	 	 	39	 	 	 	61	 	 	 	195	 	 	 	684	 	
Depreciation and amortization	 	 	90	 	 	 	34	 	 	 	11	 	 	 	30	 	 	 	17	 	 	 	29	 	 	 	211	 	
Operating income/ (loss)	 	 	(1,331	)	 	 	(384	)	 	 	(101	)	 	 	(465	)	 	 	(68	)	 	 	5,734	 	 	 	3,385	 	
Market indicators:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average natural gas price — Henry Hub ($/MMbtu)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	5.43	 	
Average on-peak market power prices ($/MWh)	 	$	61.78	 	 	$	41.53	 	 	$	48.64	 	 	$	37.83	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cooling Degree Days, or CDDs (3)	 	 	1,164	 	 	 	2,583	 	 	 	900	 	 	 	633	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDD’s 30 year rolling average	 	 	1,073	 	 	 	2,449	 	 	 	704	 	 	 	708	 	 	 	 	 	 	 	 	 	 	 	 	 	
Heating Degree Days, or HDDs (3)	 	 	11,404	 	 	 	1,836	 	 	 	2,455	 	 	 	5,586	 	 	 	 	 	 	 	 	 	 	 	 	 	
HDD’s 30 year rolling average	 	 	10,479	 	 	 	1,888	 	 	 	2,790	 	 	 	5,436	 	 	 	 	 	 	 	 	 	 	 	 	 	

(1) 	Other operating expenses include “Cost of majority-owned operations” and “General, administrative and development” expenses, excluding cost of energy.	
 	 	
(2) 	Includes MWhs sold for wholly owned subsidiaries only.	
 	 	
(3) 	National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/ HDDs for a period of time are calculated by adding the CDDs/ HDDs for each day during the period.	
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 	For year ended December 31, 2005 compared to the year ended December 31, 2004	

 	Significant Events Reflected in our Results of Operations During 2005	

 	• 	Extreme weather conditions, including Hurricanes Katrina and Rita, contributed to the increase in the sale price of power. This increase in power prices drove the net mark-to-market losses of $119 million primarily associated with forward financial electric sales in support of our Northeast assets.	
 	 	 	
 	• 	As compared to the year ended December 31, 2004, on-peak electricity prices increased between 43% to 53% in the various markets we operate, whereas our total domestic coal costs, which are largely contracted, increased only 17% increasing our dark spreads. Gas and oil prices increased 50% and 49%, respectively, resulting in higher spark spreads, but compressed oil margins as compared to the same period last year(1)	
 	 	 	
 	• 	Total generation increased for the year ended December 31, 2005 compared to 2004 by 5%.	
 	 	 	
 	• 	We began selling excess emission allowances, and have recognized a net gain of $31 million during 2005.	
 	 	 	
 	• 	Forced outages at our Huntley, Dunkirk, Indian River and Big Cajun II plants during 2005 negatively impacted our generation by 2.4 million MWh.	
 	 	 	
 	• 	We repurchased $645 million in aggregate principal amount of our Second Priority Notes, resulting in $45 million of refinancing charges.	
 	 	 	
 	• 	We sold a number of non-core assets including, Enfield, our Northbrook assets and our remaining Kendall interest for a total of $106 million in proceeds and a net gain of approximately $32 million.	
 	 	 	
 	• 	We announced the signing of a sale agreement for Rocky Road resulting in an impairment charge of $20 million.	
 	 	 	
 	• 	We wrote-down our interest in the Saguaro Power Company by $27 million.	

 	Consolidated Discussion:	

 	Revenues from Majority-Owned Operations	
      Revenues from majority-owned operations were $2,708 million for the year ended December 31, 2005 compared to $2,348 million for the year ended December 31, 2004, an increase of $360 million. Energy revenues for the year ended December 31, 2005 increased $649 million from $1,365 million to $2,014 million. Of the $2,014 million, 87% were merchant as compared to 70% for the year ended December 31, 2004. The increase in energy revenues versus 2004 was driven by both increased prices and the increased merchant generation from our Northeast assets. Energy revenues from our domestic coal assets increased by $314 million, all due to increased power prices, as generation from our domestic coal assets decreased 5% for the year ended December 31, 2005 as compared to the same period in 2004. This decrease in generation was due to both planned and unplanned outages at Huntley, Indian River, and Big Cajun II during the second and fourth quarters, and the time we typically perform outage work. Energy revenue from our gas assets in New York City increased by $176 million, including $23 million in NYISO final settlement payments. Of the remaining $153 million, both price and generation nearly equally contributed to the increase. Energy revenues from our oil-fired assets rose by $211 million, 86% due to higher volumes following an increase in summer demand as the generation from these assets increased by 122% for the year ended December 31, 2005 as compared to the same period in 2004. Additionally, a one-time payment of $39 million from the Connecticut Light and Power settlement contributed to energy revenue during the second quarter of 2004.
      Capacity revenues for the year ended December 31, 2005 were $563 million compared to $612 million for the year ended December 31, 2004, a reduction of $49 million. Capacity revenues were unfavorable versus last year due to the loss of $56 million capacity revenues from the Kendall facility, which was sold in the fourth
 
1 Per the Henry Hub gas price index published by Platts Gas Daily.

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quarter of 2004, and the expiration of the Rockford tolling agreement in May 2005 which reduced year-on-year results by $23 million. Capacity revenues from our western New York plants decreased by $10 million due to the addition of new generation and increased imports in New York, which depressed capacity prices for our assets in the western New York market during the first half of 2005. This loss was offset by a $44 million increase in capacity revenues from our Connecticut assets. This increase is related to the additional $24 million capacity revenues recorded in 2005 related to our Connecticut RMR settlement agreement. Alternative revenues for the year ended December 31, 2005 and 2004 were $191 million and $175 million, respectively. Increased generation due to the hotter weather this summer and an increase in contract rates from our Thermal and Resource Recovery operations positively impacted the alternative revenues results.
      Other revenues include emission allowance sales, natural gas sales, Fresh Start-related contract amortization, and expense recovery revenues. For the year ended December 31, 2005, other revenues totaled a $168 million compared to $98 million of other revenues for the same period in 2004. The increase is due to higher emission allowance revenues, higher physical gas sales and lower contract amortization, offset by lower expense recovery revenues. Please see our discussion below as to our emission allowance position and sales. The increase in other revenues was also attributed to $33 million in higher gas sales. The increase in gas sales is primarily related to a new gas sale agreement entered into in the third quarter of 2005 by the South Central region, where revenues from gas sales increased by $23 million. We entered into this agreement in conjunction with power purchase agreements to minimize our market purchases during peak months. Lower contract amortization of $30 million is related to contracts rolling off over the course of time. Finally, during the year ended December 31, 2005, expense recovery revenues were $29 million lower versus the comparable period in 2004. Expense recovery revenues are associated with our Connecticut RMR agreements and we reached our maximum payment under that agreement during the first quarter of 2005.
      Sale of Excess SO2 Emission Allowances — We actively manage our surplus emission allowance position. During the later half of 2005, we began trading a portion of our excess SO 2  emission allowances to third parties. Revenues from the sale of emission allowances to third parties net of purchases totaled $31 million in 2005, excluding the EPA auction results. The following table provides the sales activity and our balance of emission allowances (excluding Texas Genco) for vintage years, through 2009:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Average	 	 	 	
 	 	Tons	 	 	Sales Price	 	 	Revenue	 	
 	 	 	 	 	 	 	 	 	 	
Balance of NRG SO 2 Emissions Credits Allowances, as of December 31, 2004	 	 	897,653	 	 	 	n/a	 	 	 	n/a	 	
 	Sales during 2005	 	 	35,052	 	 	$	889	 	 	$	31 million	 	
 	Consumed	 	 	(115,810	)	 	 	 	 	 	 	 	 	
Balance of NRG SO 2 Emissions Credits Allowances, as of December 31, 2005	 	 	746,791	 	 	 	n/a	 	 	 	n/a	 	
 	Completed Sales between January 1 and February 28, 2006	 	 	46,077	 	 	$	1,180	 	 	$	54 million	 	
Balance of NRG SO 2 Emissions Credits Allowances, as of February 28, 2006	 	 	700,714	 	 	 	n/a	 	 	 	n/a	 	
      In addition to our SO2 emission allowance balances presented above, after the closing of the acquisition of Texas Genco, the combined NRG balance of excess SO 2  emissions allowances for vintage years through 2009 is 1,329,066 tons on February 28, 2006.
      We expect to continue the active management of our SO2 emission allowances in excess of our forecast generation needs.

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 	Hedging and Risk Management Activity	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	For the Year Ended December 31, 2005	 	
 	 	 	 	
 	 	 	 	South	 	 	 	 	Other North	 	 	
 	 	Northeast	 	 	Central	 	 	Western	 	America	 	Australia	 	 	All Other	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Net gains/ (losses) on settled positions, or financial revenues	 	$	(132	)	 	$	(1	)	 	$	—	 	 	$	—	 	 	$	35	 	 	$	(5	)	 	$	(103	)	
Mark-to-market results	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized (gains)/losses on settled positions	 	 	(59	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	(58	)	
Net unrealized gains/ (losses) on open positions related to economic hedges	 	 	(119	)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	7	 	 	 	 	 	 	 	(112	)	
Net unrealized gains/ (losses) on open positions related to trading activity	 	 	27	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	27	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Subtotal mark-to-market results	 	 	(151	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	8	 	 	 	—	 	 	 	(143	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total derivative gain/ (loss)	 	$	(283	)	 	$	(1	)	 	$	—	 	 	$	—	 	 	$	43	 	 	$	(5	)	 	$	(246	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      Hedging and Risk Management Activity — The total derivative loss for the year was approximately $246 million, comprised of $103 million in financial revenue losses and $143 million of mark-to-market losses. The $103 million loss of financial revenues represent the settled value for the year of all financial instruments including but not limited to financial swaps on power. Of the $143 million of mark-to-market losses, $112 million represents the change in fair value of forward sales of electricity and fuel — $114 million losses associated with electricity sales and $2 million gain associated with cost of fuel, the reversal of $58 million of mark-to-market gains which ultimately settled as financial revenues and $27 million mark-to-market gain related to trading activity. These activities primarily support our Northeast assets. The $112 million domestic loss related to forward sales during 2005 compares to a $59 million gain for the same period during 2004.
      Since our economic hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy sold, the changes in such results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on energy revenues and costs of energy. In the fourth quarter of 2004 and over the course of 2005, we hedged much of our calendar year 2005 and 2006 Northeast generation. Since that time and during the third quarter 2005 in particular, the settled and forward prices of electricity rose, driven by the extreme weather conditions this summer. While this increase in electricity prices benefited our generation portfolio versus last year with higher energy revenues, it is also the reason for the mark-to-market recognition of the forward sales and the settlement of positions as losses.
      In addition to the hedging techniques used until now, we expect to utilize hedging strategies that are option-based with a goal of establishing a floor on earnings, leaving upside market participation, minimizing mark-to-market swings and optimizing collateral support of our hedging program. For 2007, we have already locked in a floor on 30% of our baseload coal generation at current forward prices while preserving our ability to benefit from further upward movement in northeastern electricity prices.
 	 	
 	Cost of Majority-Owned Operations	
      Cost of majority-owned operations for the year ended December 31, 2005 was $2,067 million. Cost of majority-owned operations for the year ended December 31, 2004 was $1,489 million or 63% of revenues from majority-owned operations. The increase is related to the cost of energy, which increased by $521 million, to $1,529 million or 56% of revenues for the year ended December 31, 2005 from $1,008 million or 43% of revenues for the same period in 2004. The increase in the cost of energy as a percentage of revenues is driven by the higher mark to market loss in revenues, by both higher price and generation in the Northeast region and higher purchased energy and gas sales in the South Central region. Total gas costs increased by $163 million, $124 million in the New York City assets alone. Of the increase at our New York City assets, $15 million was due to increased gas purchases for resale, with approximately $67 million due to increased generation. The

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South Central region’s gas costs increased by $25 million due to physical gas purchases related to a new gas sale agreement entered into in the third quarter of 2005 to support certain tolling arrangements. Total oil costs for the company increased by $165 million, 65% due to increased generation from our oil-fired assets, and the remainder due to an increase in price. Total coal costs increased by $71 million. The increase at our domestic coal-fired assets is solely due to price increases, as overall generation from our coal-fired assets decreased for the year ended December 31, 2005 by 5% as compared to the same period in 2004 due to the planned and forced outages at our Huntley, Indian River and Big Cajun II facilities. The increase in coal prices is related to new low-sulfur coal and rail contracts which became effective in April 2005. Additionally, our Indian River plant uses a higher portion of eastern coal that experienced a significant cost increase in 2005. We have increased our percentage blend of low-sulfur coal over the year as compared to the same period last year. This had the effect of mitigating the increase in coal and coal transportation costs as low sulfur coal prices have not increased as much as regular coal prices. Total purchased energy increased by $112 million due to increases at our South Central region. Higher long-term contract load demand due to the extreme weather, a 100-MW around-the-clock sale to Entergy, a tolling agreement, and the forced outages during the second quarter, required South Central to purchase energy to meet its contract load obligations.
      Other Operating Expenses during 2005 totaled $737 million versus $693 million in the comparable period of 2004, an increase of $44 million. This increase is driven by a $51 million, or 11%, increase in operating and maintenance costs. Major maintenance projects and more extensive outages in 2005, as compared to 2004, contributed $33 million to the increase. The low-sulfur coal conversions and turbine overhauls of the western New York plants and Indian River plant was a main focus for many of the major maintenance and outages in 2005. South Central also went through a significant outage to install a low-NOX burner on one of its units and an additional outage was completed this Fall to address reliability issues experienced at the Big Cajun II unit earlier in the year. Normal maintenance increased by $9 million or 9% due to the increased run time at our plants this summer. Additionally, in 2004, a settlement with a third party vendor regarding auxiliary power charges reduced 2004 operating and maintenance expenses by $7 million.
 	 	
 	Depreciation and Amortization	
      Our depreciation and amortization expense for the year ended December 31, 2005 and 2004 was approximately $194 million and $208 million, respectively. The decrease in depreciation and amortization from 2005 to 2004 is due to the 2004 sale of our Kendall plant, which contributed approximately $14 million in depreciation and amortization expense during 2004.
 	 	
 	General, Administrative and Development	
      Our G&A costs for the year ended December 31, 2005 were $197 million compared to $210 million for the same period in 2004, a decrease of $13 million. Corporate costs represent $94 million or 3% of revenues and $113 million or 5% of revenues for the years ended December 31, 2005 and 2004, respectively. G&A costs have been favorably impacted by $11 million in reduced bad debt expense associated with notes receivable from third parties. Additionally, external consulting expenses decreased in 2005 as compared to 2004 by approximately $11 million primarily related to reduced tax and legal consulting. These favorable impacts were offset by a $5 million increase in information technology related expenses primarily associated with increased compliance costs related to Sarbanes Oxley and the relocation from Minneapolis.
 	 	
 	Corporate Relocation Charges	
      During the year ended December 31, 2005, charges related to our corporate relocation activities were approximately $6 million as compared to $16 million in 2004. Included in this year’s charges is approximately $3 million related to the lease abandonment charges associated with our former Minneapolis office with the remainder related to the relocation, recruitment and transition costs. In 2004, we recorded $16 million primarily related to employee severance and termination benefits and employee-related transition costs. We completed the physical move of our relocation in 2004 when the majority of costs were incurred. We do not expect any material relocation charges in 2006.

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 	Equity in Earnings of Unconsolidated Affiliates	
      During the year ended December 31, 2005, equity earnings from our investments in unconsolidated affiliates were $104 million compared to $160 million for the year ended December 31, 2004, a decrease of $56 million. Our earnings in WCP accounted for $22 million and $69 million for the years ended December 31, 2005 and 2004, respectively. The decrease in WCP’s equity earnings is due to the expiration of the CDWR contract in December 2004. Enfield’s equity earnings were $13 million lower for the year ended December 31, 2005 as compared to the same period in 2004. We sold our investment in Enfield on April 1, 2005. For the year ended December 31, 2005 results for Enfield include approximately $12 million of unrealized gains associated with mark-to-market increases in the fair value of energy-related derivative instruments, as compared to $23 million of unrealized gain for the same period of 2004.
      Other equity investments included in the 2005 results include MIBRAG and Gladstone which comprised $26 million and $24 million for the year ended December 31, 2005, respectively. For the comparable period in 2004, MIBRAG and Gladstone earned $21 million and $18 million, respectively. MIBRAG’s equity earnings for 2004 were negatively impacted by an outage at our Schkopau plant; additionally, MIBRAG recorded a lower asset retirement obligation in 2005 as compared to 2004. Gladstone’s earnings in 2005 were greater than 2004 due to lower major maintenance expense and an approximate $1 million recovery in business interruption insurance.
 	 	
 	Write Downs and Gains/(Losses) on Sales of Equity Method Investments	
      During the year ended December 31, 2005, we recorded a $31 million loss due to the sale and impairment of certain equity investments as we continued to divest of non-core assets. On April 1, 2005, we sold our 25% interest in Enfield, resulting in net pre-tax proceeds of $65 million and a pre-tax gain of $12 million, including the post-closing working capital adjustments. In 2005, we also sold our interest in Kendall for $5 million in net pre-tax proceeds and a pre-tax gain of approximately $4 million. These gains on sales were offset by approximately $47 million in impairment charges recorded this year.
      In December 2005, we executed an agreement with Dynegy to sell our 50% interest in Rocky Road LLC in conjunction with our purchase of Dynegy’s 50% interest in WCP. Based on this arms length transaction rendering the fair value of our investment in Rocky Road at $45 million, we subsequently impaired our investment to this fair value by an approximate write down of $20 million. We expect to close the sale of our interest of Rocky Road during the first half of 2006. We also recorded an impairment of $27 million on our investment in Saguaro. With the expiration of its gas supply contract, Saguaro began recording operating losses during the second half of 2005, triggering a permanent write down to NRG’s investment value in Saguaro.
      During the year ended December 31, 2004, we sold our Loy Yang investment which resulted in a $1 million loss, our interest in Commonwealth Atlantic Limited Partnership for a $5 million loss, and several NEO investments for a $4 million loss. These losses were offset by a $1 million gain associated with the sale of Calpine Cogeneration. Also during 2004, we recorded a $7 million impairment charge on our investment in James River LLC based on an estimated sale value from a prospective buyer.
 	 	
 	Other Income, net	
      Other income had a net increase of $35 million during the year ended December 31, 2005 as compared to the same period in 2004. Other income in 2005 was favorably impacted by a $14 million gain from the settlement related to our TermoRio project in Brazil and a gain of approximately $4 million related to the resolution of a contingency from the sale of a former project, the Crockett Cogeneration Facility, which was sold in 2002. Other income was also favorably impacted by $14 million of higher interest income related to more efficient management of our cash balances. These favorable results were offset by a $3 million reserve relating to the ongoing TermoRio litigation.

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 	Refinancing expense	
      Refinancing expenses for the year ended December 31, 2005 and 2004 were $56 million and $72 million, respectively. During 2005, as part of our continuing effort to manage our capital structure, we redeemed and purchased a total of $645 million of our Second Priority Notes. As a result of the redemption and purchases, we incurred $55 million in premiums and write-offs of deferred financing costs. Our Australia region also refinanced its project debt for better terms, resulting in the write-off of approximately $10 million of debt premium, i.e. refinancing income. We also incurred an additional $11 million in refinancing fees during 2005 related to the amortization of a bridge loan commitment fee that we paid related to the Acquisition of Texas Genco.
      As part of our new financing in 2006 in conjunction with the acquisition of Texas Genco, we paid a bridge loan commitment fee of approximately $45 million to ensure that we would have the proper financing in place for the said acquisition. This amount is being amortized over time, and during 2005 we amortized approximately $11 million to refinancing expense. The remaining balance of this amount will be expensed during the first quarter of 2006 as we finalized the new financings related to the acquisition of Texas Genco.
      During the year ended December 31, 2004, we refinanced certain amounts of our term loans with additional corporate level high yield notes for better terms, which resulted in $15 million of prepayment penalties and a $15 million write-off of deferred financing costs. Additionally, we refinanced our senior credit facility in December 2004 and recorded $14 million of prepayment penalties and a $27 million of write-off of deferred financing costs.
 	 	
 	Interest expense	
      Interest expense for the year ended December 31, 2005 was $197 million as compared to $266 million for the same period in 2004, a reduction of $69 million. Interest expense was favorably impacted by the sale of Kendall which incurred $25 million of interest expense year ended December 31, 2004. Additionally, the refinancing of our Senior Credit Facility on December 23, 2004 lowered our interest rate by 212.5 basis points and the $645 million redemption and purchases of our Second Priority Notes during 2005 reduced interest expense on our corporate debt by approximately $50 million.
 	 	
 	Income Tax Expense	
      Income tax expense was approximately $43 million and approximately $65 million for the years ended December 31, 2005 and 2004, respectively. The overall effective tax rate was 35.8% and 28.7% for the years ended December 31, 2005 and 2004, respectively. The effective income tax rate for the year ended December 31, 2005 and 2004 differs from the U.S. statutory rate of 35% due to the earnings in foreign jurisdictions taxed at rates lower than the U.S. statutory rate, rendering an effective tax rate of 17.3% and 9.7%, respectively, on foreign income. Our 2005 domestic income tax effective rate increased due to our gain on the sale of Enfield and the taxable dividend received pursuant to the American Jobs Creation Act of 2004. Also see our tax rate reconciliation disclosure in Note 22,  Income Taxes , to the Condensed Consolidated Financial Statements.
      The effective tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and the adjustment of valuation allowances in accordance with SFAS 109. These factors and others, including our history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.
 	 	
 	Income from Discontinued Operations, net of Income Taxes	
      During the year ended December 31, 2005 and 2004, we recorded a gain from discontinued operations of $7 million and $25 million, respectively, as we continued to divest certain non-core assets. Discontinued operations for the year ended December 31, 2005 consist of Audrain, the Northbrook New York and Northbrook Energy assets and various expenses related to the final settlements of McClain. During the year ended December 31, 2004, discontinued operations consisted of the results of Audrain, the two Northbrook

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entities, McClain, 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 and NEO Tajiguas LLC). With the exception of Audrain, Northbrook New York and Northbrook Energy, all discontinued operations were sold prior to December 31, 2004.
      As of December 31, 2005, the sale of Audrain is still pending and remains subject to regulatory approvals. Ameren’s application to assume certain obligations of Audrain is pending before the Missouri Public Service Commission . The case filed with the FERC seeking authorization for the transaction pursuant to section 203 of the Federal Power Act has been protested by the Missouri Joint Municipal Electric Utility Commission. The pre-merger waiting period under the Hart-Scott-Rodino Antitrust Improvement Act expired January  19, 2006. Despite the above, we still expect to close this sale during the first half of 2006.
 	 	
 	Regional Discussion	

 	Northeast Region Results	

 	Operating Income	
      For the year ended December 31, 2005, operating income for the Northeast region was $218 million, as compared to $318 million for the same period in 2004, a decrease of $100 million. This decrease is due to $119 million net MTM losses reported by the Northeast associated with forward sales of electricity as compared to a $59 million net MTM gain booked in 2004. Excluding net MTM losses or gains, the Northeast operating income increased by $52 million. This increase was largely due to increased power prices, wider dark spread margins, and increased generation from the Northeast gas and oil assets. With higher than average temperatures this summer, on-peak electricity prices increased 43% to 52% as compared to 2004, while gas and oil prices increased 50% and 49%(1) Spark spreads on our gas and coal margins widened, while oil margins were compressed compared to the same period last year. The Northeast’s New York City assets benefited from the increased spark spreads as they increased their generation output by 52% versus last year, from 1.1 million MWh to 1.7 million MWh due to increased summer demand. Generation from our Northeast oil-fired assets increased by 122%, but oil margins decreased by 25% versus 2004, as our cost per MWh increased by 29% in comparison to the same period in 2004 due to an offsetting increase in oil prices.
 	 	
 	Revenues	
      Revenues from our Northeast region totaled $1,554 million for the year ended December 31, 2005 compared to $1,251 million for the same period in 2004, an increase of $303 million. Revenues for the year ended December 31, 2005 included $1,444 million in energy revenues compared to $853 million for the same period in 2004. Of this $591 million increase, $183 million can be attributed to our New York City assets. Due to outages of local competitors and extreme heat this summer, sold generation from our New York City assets’ increased by 52% for the year ended December 31, 2005 as compared to 2004. Excluding the $23 million of final NYISO settlement payments, increased generation accounted for 49% of the increase in NYC energy revenues. Our oil-fired assets earned $211 million more in energy revenues, and increased generation 122% during 2005 as compared to 2004; 86% of the increased energy revenues were due to increased generation. Our coal assets recorded higher energy revenues of $99 million due solely to higher power prices as generation from our coal assets had a minimal decrease for the year ended December 31, 2005.
      Capacity revenues for the year ended December 31, 2005 were $291 million compared to $265 million for the same period in 2004. Capacity revenues were favorable versus the last year due to $24 million additional capacity revenues recorded during the second quarter of 2005 in conjunction with our Connecticut RMR settlement agreement approved by FERC on January 22, 2005. These settlement revenues were offset, however, by lower capacity revenues from our western New York plants. Capacity prices in western New York were negatively impacted by the addition of new capacity supply and increased imports into the state.
 
1Per the Henry Hub gas price index published by Platts Gas Daily.

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      Other revenues include emission credit sales, natural gas sales, Fresh Start-related contract amortization, and expense recovery revenues and totaled $104 million for the year ended December 31, 2005 as compared to $75 million the same period in 2004, an increase of $29 million. This increase is related to the additional $43 million in emission allowance sales to both external parties and inter-company sales. In addition, other revenues increased from $6 million in higher gas sales, and $6 million in lower contract amortization as the contracts have rolled off over time. Other revenues were adversely impacted by $29 million in lower expense recovery revenues related to the Connecticut RMR agreement. We reached our maximum payment under that agreement during the first quarter of 2005.
      Hedging and Risk Management Activity — The total derivative loss for the year was $283 million, comprised of $132 million in financial revenue losses and $151 million of mark-to-market losses. The $132 million loss of financial revenues represent the settled value for the year of all financial instruments including financial swaps and options on power. Of the $151 million of mark-to-market losses, $119 million represents fair value of forward sales of electricity and fuel — $121 million losses associated with electricity sales and $2 million gain associated with cost of fuel, the reversal of $59 million of mark-to-market gains which ultimately settled as financial revenues and $27 million mark-to-market gain related to trading activity. These activities primarily support our Northeast assets.
      Since hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy sold, the changes in such results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on energy revenues and costs of energy. In the fourth quarter of 2004 and over the course of 2005, we hedged much of our calendar year 2005 and 2006 Northeast generation. Since that time and during the third quarter 2005 in particular, the settled and forward prices of electricity rose, driven by the extreme weather conditions this summer. While this increase in electricity prices benefited our generation portfolio versus last year with higher energy revenues, it is also the reason for the mark-to-market recognition of the forward sales and the settlement of positions as losses.
 	 	
 	Cost of energy	
      Cost of energy increased by $350 million for our Northeast region for the year ended December 31, 2005 compared to the same period in 2004. Oil fuel costs in our Northeast region increased by $162 million, where 65% of the increase was due to increased generation. The Northeast’s gas fuel costs increased by $129 million. Higher gas sales from our New York City assets drove $15 million of the increase, with $109 million of the increase related to higher prices and demand for our NYC assets. Coal costs increased by $61 million, due to increased prices, although our coal-fired generation in the Northeast had a minimal decrease during 2005 as compared to 2004, specifically due to scheduled and unplanned outages at our western New York and Indian River facilities during the second and fourth quarters. Of the $61 million increase in coal cost, 71% was due to increases at our Indian River plant. Our Indian River plant uses a higher portion of eastern coal, whose price experienced a significant cost increase during 2005.
 	 	
 	Other Operating Expenses	
      Other operating costs for our Northeast region increased by $55 million for the year ended December 31, 2005 compared to the same period in 2004. This increase was driven by operating and maintenance costs, led by higher major maintenance costs. The low-sulfur conversion projects continued at our Western New York plants and began at our Indian River plant this year and major outages related to turbine overhauls took place at our Western New York and Indian River plants. The increased number and extensiveness of the outages contributed to the $14 million increase in major maintenance expense this year. Additionally, in 2004, a settlement with a third party vendor regarding auxiliary power charges reduced 2004 operating and maintenance expenses by $7 million.
      Other operating expenses for the Northeast region include the administrative regional office costs, other non-income tax expense, insurance and corporate allocations. These costs increased by $30 million in 2005 compared to 2004, $14 million of which was due in non-income tax expense as we recognized property tax credits in 2004. Additionally, regional office and corporate allocations also increased per our new allocation

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methodology as discussed in Item 15 — Note 21, Segment Reporting, to the Consolidated Financial Statements.
 	 	
 	South Central Region Results	

 	Operating Income	
      For the year ended December 31, 2005, the South Central region realized operating income of $20 million, as compared to $58 million for the year ended December 31, 2004. During 2005, our Big Cajun II facility experienced several forced outages during the summer months, at which time contract demand and replacement power costs were at their highest. Generation for 2005 decreased by 6% from 10.6 million MWh to 9.9 million MWh versus the same period in 2004, with 0.2 million MWh lost due to forced outages. These outages contributed to the purchase of $114 million in additional purchased energy required to meet contract load-following obligation in the merchant market at costs higher than our coal-based generating assets. In addition, during 2005, South Central had three planned outages versus one major planned outage during 2004, which increased major maintenance by $16 million as compared to the year ended December 31, 2004.
 	 	
 	Revenues	
      Revenues from our South Central region were $552 million for the year ended December 31, 2005 compared to $418 million for the same period in 2004, an increase of $134 million. Revenues for the year ended December 31, 2005 included $330 million in energy revenues, of which 62% were contracted. This compares to $219 million of energy revenues for the year ended December 31, 2004, 73% of which were contracted. This increase of $111 million in energy revenues and the lower percentage contracted was due to increased merchant energy sales following higher power prices, favorable weather, and nuclear plant outages in the region. Also, a round-the-clock 100 MW sale to Entergy and a tolling agreement which at times provided power that could be resold at a higher price helped to boost merchant revenues. Other revenues include physical gas sales and Fresh Start-related contract amortization. For the year ended December 31, 2005, other revenues totaled $37 million compared to $16 million for the year ended December 31, 2004, with the increase due to $23 million increase in physical gas sales related to a new gas sale agreement entered into in July 2005. We entered into this agreement in conjunction with power purchase agreements to minimize our market purchases during peak months.
 	 	
 	Cost of Energy	
      South Central’s cost of energy increased by $145 million for the year ended December 31, 2005 compared to the same period in 2004. Of this amount, $114 million is due to higher purchased energy costs. During 2005, our Big Cajun II facility experienced a number of forced outages, encountered high demand from the Region’s long-term contracts, and entered into 100-MW around-the-clock sale to Entergy, and a tolling agreement, all of which required the purchase of energy to meet contract load obligations. Purchased energy per MWh increased by 238% versus the same period in 2004. Additionally, due to the extreme weather conditions and increasing gas prices, the average purchased energy price increased $18.20 per MWh for the year ended December 31, 2005 as compared to the same period in 2004.
 	 	
 	Other Operating Expenses	
      Other operating expenses increased by $33 million for the year ended December 31, 2005 compared to the same period in 2004, with $16 million of the increase related to increased planned and unplanned outages at our Big Cajun II facility, and $13 million related to regional office and the new NRG allocation methodology discussed in Item 15 — Note 21,  Segment Reporting , to the Consolidated Financial Statements.
 	 	
 	Western Region Results	
      For the year ended December 31, 2005, the Western region realized an operating loss of $6 million, as compared to an operating loss of $9 million for the same period in 2004, a reduction of $3 million in our loss.

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This reduction is due to the payment of CAISO penalties paid by our Red Bluff and Chowchilla facilities in 2004, offset by the expiration of the Red Bluff RMR contract as of December 31, 2004.
 	 	
 	Other North America Region Results	
      For the year ended December 31, 2005, the Other North America region realized an operating loss of $28 million on revenues of $15 million, as compared to an operating loss of $5 million and revenues of $94 million for the year ended December 31, 2004. This unfavorable variance is primarily related to the sale of Kendall and the expiration of a tolling agreement at our Rockford facility. Both Kendall and Rockford had operating income of $3 million each, for the year ended December 31, 2004 and revenues of $73 million and $15 million, respectively. Other operating expenses and depreciation and amortization for our Other North America region for the year ended December 31, 2005 were $16 million and $7 million, respectively. For the year ended December 31, 2004, other operating expenses and depreciation and amortization were $42 million and $21 million, respectively. The favorable variance in both of these is due to the sale of Kendall.
 	 	
 	Australia Region Results	

 	Operating Income	
      For the year ended December 31, 2005, the Australia region realized an operating loss of $7 million, as compared to an operating loss of $5 million for the same period in 2004. Unseasonably mild weather and weak pool prices in the first quarter drove the unfavorable results as compared to last year. Higher generation for the year ended December 31, 2005 helped to offset weak pool prices, with generation increasing 6% over 2004.
 	 	
 	Revenues	
      Revenues from our Australia region totaled $212 million for the year ended December 31, 2005 compared to $181 million for the year ended December 31, 2004, an increase of approximately $31 million, with $7 million as a result of the strengthening Australian dollar in 2005. Energy revenues decreased by $15 million primarily due to the weak pool prices experienced in the first quarter of the year. An unseasonably mild summer in Australia drove the average annualized pool price down to $23 per MWh from $30 per MWh in 2004, a reduction of 26%. This decrease was offset by $18 million of financial revenues, representing the settled value of financial instruments, including financial swaps on power, and $10 million of higher derivative revenues, representing the change in fair value of forward sales of electricity and fuel. Additionally, 5% higher generation due to fewer planned outage hours at the Osborne Power Station in 2005 and the full commercialization of the Playford station during the fourth quarter of 2004, helped to offset the impact of the lower pool prices. For the year ended December 31, 2005, other revenues totaled $25 million compared to $7 million of other revenues for the same period in 2004. Other revenues were favorably impacted by lower contract amortization of $15 million in 2005 as a significant contract was canceled in 2004.
 	 	
 	Cost of Energy	
      Fuel costs increased by $14 million, with $10 million of this related to an 18% increase in purchased power from Osborne Power Station in 2005 and $3 million due to additional gas expenses to support these higher generation levels. These increased costs are offset by increased revenue from merchant electricity and gas sales in 2005 related to our Osborne plant. Fuel oil costs in 2005 were approximately $1 million higher due to a combination of increased world oil prices and increased starts at Playford.
 	 	
 	Other Operating Expenses	
      Other operating expenses for Australia for the year ended December 31, 2005 increased by $16 million over the same period in 2004. Operating and maintenance expense increased by $10 million in 2005 with $3 million attributable to the strengthening Australian dollar. Increased operational and maintenance costs relating to our Playford power station in addition to higher coal production costs to support the higher generation levels led to a further $2 million increase. Significant increases in world oil prices over the 2005 year resulted in $1 million of additional costs related to coal mining and delivery. Labor costs at Flinders

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were up approximately $1 million, a combination of increasing provision levels for workers compensation claims and increased charges relating to pension charges. Additionally, due to the new NRG allocations methodology as discussed in Item 15 — Note 21,  Segment Reporting , to the Consolidated Financial Statements, the Australia region incurred $6 million in higher corporate allocations as compared to 2004.
 	 	
 	For the Year Ended December 31, 2004 Compared to the Year Ended December 31, 2003	

 	Net Income	

 	Reorganized NRG	
      For the year ended December 31, 2004, we recorded net income of $186 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 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 were 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 million unrealized gain recorded in revenue for the year ended December 31, 2004 and as more fully described in Item 15 — Note 15 to the Consolidated Financial Statements. The majority of the unrealized gains relate to forward sales of electricity which were 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. 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 million in settlement proceeds in July 2004. The 2004 results were also positively impacted by $160 million in equity earnings of unconsolidated affiliates including $69 million from our interest in West Coast Power which benefited from warmer than normal temperatures during the year. Impairment charges of $45 million negatively impacted net income; of which $27 million relates to the Kendall asset.
      During the period December 6, 2003 through December 31, 2003, we recognized net income of $11 million or $0.11 per share of common stock. 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	
      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

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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 $4.2 billion gain from continuing operations and a $0.3 billion loss from discontinued operations) as the impact of our adopting Fresh Start in our statement of operations. $6 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 also revalued our assets and liabilities to fair value. Accordingly, we substantially wrote down the value of our fixed assets. We 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 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 $463 million, write downs and losses on the sale of equity investments of $147 million, advisor costs and legal fees directly attributable to our being in bankruptcy of $198 million and $237 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 $2.3 billion for the year ended December 31, 2004 which included $1.4 billion of energy revenues, $612 million of capacity revenues, $175 million of alternative energy revenues, $21 million of O&M fees, $76 million of hedging and risk management activities and $99 million other revenues.
      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 North America assets generated approximately 29 million MWh during the year 2004 with the Northeast region representing 46% of these MWh’s. 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 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 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 million in unrealized gains. This gain is related to our Northeast assets and is included in the hedging and risk management activities. 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 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.

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      Our revenues from majority-owned operations were $137 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 approximately $910 million of energy revenues, $566 million of capacity revenues, $82 million of alternative energy, $13 million of O&M fees, $19 million of hedging and risk management activities and $208 million other revenues. 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	
      Our cost of majority-owned operations for the year ended December 31, 2004 was $1.5 billion or 63% of revenues from majority-owned operations. Cost of majority-owned operations consist of $1.006 billion of cost of energy (primarily fuel and purchased energy costs), or 43% of revenues from majority-owned operations and $483 million of operating expenses, or 21% of revenues from majority-owned operations. Operating expenses consist of $207 million of labor related costs, $235 million of operating and maintenance costs, $38 million of non-income based taxes and $3 million of asset retirement obligation accretion.
 	 	
 	Cost of Energy	
      Fuel related costs include $476 million in coal costs, $233 million in natural gas costs, $105 million in fuel oil costs, $39 million in transmission and transportation expenses, $100 million of purchased energy costs, $35 million in other costs and $18 million in non-cash SO 2  emission credit amortization resulting from Fresh Start accounting. The Northeast region consumed 50%, 64% and 91% 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	

 	Reorganized NRG	
      Operating expenses related to continuing operations for the year ended December 31, 2004 were $483 million or 21% 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 $207 million. The Northeast region, where the majority of our assets reside, represents 53% of total labor costs; Australia represents 18%, while our South Central region represents 12%. Of the total O&M costs, normal and major maintenance at our plants accounted for $176 million, or 36% 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 $99 million in costs in 2004 while Australia had $40 million in normal and major maintenance, or 23%. Operating expenses were positively impacted by a $7 million favorable settlement with a vendor regarding auxiliary power charges. Non-income based taxes totaled $38 million net of $35 million in property tax credits, primarily associated with an enterprise zone program.
      Cost of majority-owned operations was $95 million, or 69% of revenues from majority-owned operations for the period December 6, 2003 through December 31, 2003. Cost of energy for this period was $63 million or 46% of revenues from majority-owned operations and operating expenses were $32 million, or 23% of revenues from majority-owned operations. Labor during this period totaled $11 million. Normal and major maintenance

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was $12 million with 67% 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% 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 $208 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 $12 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 $211 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 $210 million. Of this total, $111 million or 5% of revenues from majority-owned operations represents our corporate costs, with the remaining $99 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 $41 million. Additionally, we recorded $12 million in bad debt expense related to notes receivable.
      General, administrative and development costs were $13 million, or 10% 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.

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 	Predecessor Company	
      Our general, administrative and development costs related to continuing operations for the period January 1, 2003 to December 5, 2003 were $170 million or 10% 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 $48 million, which consisted of $16 million of corporate relocation charges, $13 million of reorganization credits and $45 million of restructuring and impairment charges.
      For the period December 6, 2003 through December 31, 2003 we recorded $2 million of reorganization charges.
 	 	
 	Predecessor Company	
      During the period January 1, 2003 to December 5, 2003, we recorded other credits of $3.3 billion, which consisted primarily of $229 million related to asset impairments, $463 million related to legal settlements, $198 million related to reorganization charges and $8 million related to restructuring charges. We also incurred a $4.2 billion credit related to Fresh Start adjustments.
      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 millions)	 	
Corporate relocation charges	 	$	16	 	 	$	—	 	 	 	$	—	 	
Reorganization items	 	 	(13	)	 	 	2	 	 	 	 	198	 	
Impairment charges	 	 	45	 	 	 	—	 	 	 	 	229	 	
Restructuring charges	 	 	—	 	 	 	—	 	 	 	 	8	 	
Fresh Start adjustments	 	 	—	 	 	 	—	 	 	 	 	(4,220	)	
Legal settlement	 	 	—	 	 	 	—	 	 	 	 	463	 	
 	 	 	 	 	 	 	 	 	 	 	
 	Total	 	$	48	 	 	$	2	 	 	 	$	(3,322	)	

 	 	
 	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. As of December 31, 2005, the transition of the corporate headquarters is complete. During the year ended December 31, 2004, we recorded $16 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”.  See Item 15 — Note 8 to our consolidated financial statements for more information.
      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 $6 million of

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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 million.
      We recognized a curtailment gain of approximately $1 million 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 million related primarily to the settlement of obligations recorded under Fresh Start. We incurred $7 million of professional fees associated with the bankruptcy which offset $20 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 million and $198 million, respectively, in reorganization costs. All reorganization costs have been incurred since we filed for bankruptcy in May 2003. Also see Item 15 — Note 8 for a tabular description of expenses.
 	 	
 	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 $45 million and $229 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 $45 million total in 2004, Kendall and the Meriden turbine accounted for $27 million and $15 million, respectively. We successfully completed the sale of Kendall in November 2004 and expect to complete the sale of the Meriden turbines in 2006. 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. 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.
      See Item 15 — Note 8 for a list of impairment charges (credits) for the year ended December 31, 2004 and the period January 1, 2003 to December 5, 2003.
 	 	
 	Restructuring Charges	
      We incurred $8 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.

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 	Fresh Start Adjustments	
      During the fourth quarter of 2003, we recorded a net credit of $3.9 billion (comprised of a $4.2 billion gain from continuing operations and a $0.3 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 2 emission 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	 	 	(325	)	
 	 	 	 	
Total Fresh Start adjustments — continuing operations	 	$	4,220	 	

 	 	
 	Legal Settlement Charges	
      During the period January 1, 2003 to December 5, 2003, we recorded $463 million of legal settlement charges which consisted of the following. We recorded $396 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 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 million pre-petition bankruptcy claim and an $8 million post-petition bankruptcy claim. We had previously recorded approximately $11 million in connection with various legal disputes with Fortistar Capital; accordingly, we recorded an additional $57 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 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 $2 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 million during November 2003.
 	 	
 	Other Income (Expense)	

 	Reorganized NRG	
      During the year ended December 31, 2004, we recorded other expense of $167 million. Other expense consisted primarily of $266 million of interest expense, $72 million of refinancing-related expenses, $16 million of write downs and losses on sales of equity method investments, offset by $160 million of equity in

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earnings of unconsolidated affiliates (including $69 million from our investment in West Coast Power LLC) and $27 million of other income, net.
      Other income (expense) for the period December 6, 2003 through December 31, 2003, was an expense of $5 million and consisted primarily of $19 million of interest expense, partially offset by $14 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 $265 million. Other expense consisted primarily of $308 million of interest expense and $147 million of write downs and losses on sales of equity method investments, partially offset by equity in earnings of unconsolidated affiliates of $171 million and $19 million of other income, net.
 	 	
 	Equity in Earnings of Unconsolidated Affiliates	

 	Reorganized NRG	
      For the year ended December 31, 2004, we recorded $160 million of equity earnings from our investments in unconsolidated affiliates. Our equity in earnings of WCP comprised $69 million of this amount with our equity in earnings of Enfield, MIBRAG, and Gladstone comprising $28 million, $21 million, and $17 million, respectively. Our investment in WCP generated favorable results due to the pricing under the CDWR contract. Additionally, revenues from ancillary services revenue and minimum load cost compensation power positively contributed to WCP’s operating results. However, our equity earnings in the project as reported in our results of operations have been reduced by a net $116 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 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 $14 million for the period December 6, 2003 through December 31, 2003 consists primarily of equity earnings from our 50% ownership in WCP of $9 million.
 	 	
 	Predecessor Company	
      During the period January 1, 2003 through December 5, 2003, we recorded $171 million of equity earnings from investments in unconsolidated affiliates. Our 50% investment in WCP comprised $99 million of this amount with our investments in the MIBRAG, Loy Yang, Gladstone and Rocky Road projects comprising $22 million, $18 million, $12 million and $7 million, respectively, with the remaining amounts attributable to various domestic and international equity investments.

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      Equity in earnings of unconsolidated affiliates consists of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	
 	 	Year Ended	 	 	December 6, 2003	 	 	 	January 1, 2003	 	
 	 	December 31,	 	 	Through	 	 	 	Through	 	
 	 	2004	 	 	December 31, 2003	 	 	 	December 5, 2003	 	
 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
WCP	 	$	69	 	 	$	9	 	 	 	$	99	 	
MIBRAG	 	 	21	 	 	 	—	 	 	 	 	22	 	
Enfield	 	 	28	 	 	 	1	 	 	 	 	6	 	
Gladstone	 	 	17	 	 	 	1	 	 	 	 	12	 	
Rocky Road	 	 	7	 	 	 	—	 	 	 	 	7	 	
James River	 	 	8	 	 	 	1	 	 	 	 	(2	)	
NRG Saguaro	 	 	5	 	 	 	1	 	 	 	 	4	 	
Scudder LA Trust	 	 	2	 	 	 	—	 	 	 	 	3	 	
NRG National	 	 	1	 	 	 	—	 	 	 	 	2	 	
Loy Yang	 	 	—	 	 	 	—	 	 	 	 	18	 	
Other	 	 	2	 	 	 	1	 	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	
 	Total Equity in Earnings of Unconsolidated Affiliates	 	$	160	 	 	$	14	 	 	 	$	171	 	

 	 	
 	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 million and $147 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.
      Further details as to write downs and losses (gains) on sales of equity method investments recorded in the consolidated statement of operations are detailed in Item 15 — Note 7 to the Consolidated Financial Statements.
 	 	
 	Other Income, net	

 	Reorganized NRG	
      During the year ended December 31, 2004, we recorded $27 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 an immaterial amount of other income.
 	 	
 	Predecessor Company	
      During the period January 1, 2003 through December 5, 2003, we recorded $19 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.

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 	Interest Expense	

 	Reorganized NRG	
      Interest expense for the year ended December 31, 2004 was $266 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 million related to our corporate level debt and $13 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 $19 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 $308 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 $72 million for the year ended December 31, 2004. This amount includes $15 million of prepayment penalties and a $15 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 $14 million of prepayment penalties and a $27 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 million for the year ended December 31, 2004 and an income tax benefit of ($1) 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

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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 pre-confirmation 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 $38 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 approximately $25 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), four NEO Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha LLC and NEO Tajiguas LLC), Northbrook New York LLC, Northbrook Energy LLC and Audrain Generating LLC. All other discontinued operations were disposed of in prior periods. The $25 million income from discontinued operations includes a gain of $22 million, net of income taxes of $8 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 less than a million dollars attributable to the on going operations of our McClain, PERC, Cobee, LSP Energy, Hsin Yu, four NEO Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha LLC and NEO Tajiguas LLC) and Audrain Generating LLC. The financial results of Northbrook New York LLC and Northbrook Energy LLC have not been reclassified as discontinued operations in the consolidated statement of operations and the consolidated statement of cash flows, for the period December 6, 2003 through December 31, 2003 due to immateriality.
 	 	
 	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

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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, Hsin Yu projects and Audrain Generating LLC. Prior to December 6, 2003, Northbrook New York LLC and Northbrook NewYork LLC were unconsolidated affiliates because the ownership structure prevented us from exercising a controlling influence over operating and financial policies of the 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 $316 million due to a net loss of results of operations from discontinued operations of Audrain Generating LLC of $133 million, loss on the sale of our Peru projects, impairment charges of $101 million and $24 million, respectively, recorded at McClain and NLGI and fresh start adjustments at LSP Energy.
 	 	
 	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 filed the NRG plan of reorganization. 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, we filed the Northeast/ South Central plan of reorganization in connection with our Northeast and South Central subsidiaries in Chapter 11. 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 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 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

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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 109. The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion (comprised of a $4.2 billion gain from continuing operations and a $0.3 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 $4.2 billion gain from continuing operations and a $0.3 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

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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.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Company	 	 	Debt Discharge	 	 	 	 	 	 	NRG	 	
 	 	December 5,	 	 	and Exchange	 	 	Fresh Start	 	 	 	 	December 6,	 	
 	 	2003	 	 	of Stock	 	 	Adjustments	 	 	Consolidation	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Current Assets	 	$	1,718	 	 	$	614	 	 	$	4	 	 	$	6	 	 	$	2,342	 	
Non-current Assets	 	 	8,172	 	 	 	(155	)	 	 	(1,233	)	 	 	41	 	 	 	6,825	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	9,890	 	 	$	459	 	 	$	(1,229	)	 	$	47	 	 	$	9,167	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	2,190	 	 	 	999	 	 	 	1,187	 	 	 	1	 	 	 	4,377	 	
Non-current Liabilities	 	 	9,458	 	 	 	(6,270	)	 	 	(848	)	 	 	46	 	 	 	2,386	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Liabilities	 	 	11,648	 	 	 	(5,271	)	 	 	339	 	 	 	47	 	 	 	6,763	 	
Stockholders Equity	 	 	(1,758	)	 	 	2,404	 	 	 	1,758	 	 	 	—	 	 	 	2,404	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Liabilities and Stockholders Equity	 	$	9,890	 	 	$	(2,867	)	 	$	2,097	 	 	$	47	 	 	$	9,167	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      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 approximate amount of $116 million for the year ended December 31, 2004. This contract expired in December 2004.
 	 	
 	Known trends that will affect our results in the future:	

 	Acquisition of Texas Genco and Financing Transactions	
      On February 2, 2006, NRG acquired Texas Genco LLC by purchasing all of the outstanding equity interests in Texas Genco pursuant to the Acquisition Agreement, dated September 30, 2005, by and among NRG, Texas Genco, and the Sellers. Also see our detailed discussion in our Liquidity and Capital Resources section. Texas Genco is now a wholly-owned subsidiary of NRG, and will be managed and accounted for as a new business segment to be referred to as NRG Texas.
      In order to facilitate the acquisition of Texas Genco, we entered into a series of financing transactions. Also see our detailed discussion in our Liquidity and Capital Resources section:
 	 	
 	Debt instruments:	

 	• 	$3.575 billion Term Loan Facility	
 	 	 	
 	• 	$1.0 billion Revolving Credit Facility	
 	 	 	
 	• 	$1.0 billion Letter of Credit Facility	
 	 	 	
 	• 	$1.2 billion in aggregate principal amount of 7.25% Senior Notes	
 	 	 	
 	• 	$2.4 billion in aggregate principal amount of 7.375% Senior Notes	

 	Equity instruments:	

 	• 	$485 million from the issuance of 2 million shares of 5.75% Preferred Stock, net of issuance costs	
 	 	 	
 	• 	$985 million from the issuance of 20,855,057 shares of our common stock, net of issuance costs	
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      These transactions also facilitated the refinancing of our outstanding debt as well as the debt outstanding for Texas Genco upon acquisition.
      Based on our current projections, our NRG Texas segment will be a profitable segment and will significantly increase our revenue and operating costs going forward. Partially offsetting this additional profit will be the increased interest expense due to the increased debt level as shown above. We have also increased the number of our outstanding shares by issuing approximately 35 million shares from both treasury and newly issued stock to the Sellers, as well as approximately 21 million newly issued shares to the public. This significant increase in outstanding shares will dilute our future earnings per share.
      At this time, we anticipate that the net effect in 2006 will be positive to our future results of operations as well as to our earnings per share.
 	 	
 	Acquisition of Remaining 50% Equity Interest in WCP	
      On December 27, 2005, we entered into purchase and sale agreements for projects co-owned with Dynegy. Under the agreements, we will acquire Dynegy’s 50% ownership interest in WCP (Generation) Holdings, Inc., and become the sole owner of WCP’s 1,808 MW of generation in Southern California. We anticipate that the transaction will close during the first quarter of 2006.
      As of the date of acquisition we will consolidate the results of operations of WCP. When consolidated, the results of WCP will increase our revenues and cost of operations, but it will reduce our equity earnings. We anticipate that the net effect in 2006 will be positive to our results of operations.
Liquidity and Capital Resources
 	 	
 	Significant Events during 2005	

 	• 	The repurchase of $645 million in aggregate principal amount of our Second Priority Notes, resulting in $54 million of refinancing charges	
 	 	 	
 	• 	The issuance of $250 million of 3.625% Preferred Stock	
 	 	 	
 	• 	The execution of the Accelerated Share Repurchase Agreement whereby we repurchased $250 million of common stock	
 	 	 	
 	• 	Repatriation of $298 million of foreign funds utilizing the tax benefits of the American Jobs Creation Act of 2004	
 	 	 	
 	• 	Cash collateral payments of $405 million supporting our hedging activities	
 	 	 	
 	• 	Collection of $71 million in an arbitration award related to TermoRio	
 	 	 	
 	• 	Execution of the Texas Genco Acquisition Agreement and related financing commitments	
 	 	 	
 	• 	Sale of non-core assets resulting in $106 million in proceeds	
 	 	 	
 	• 	The announced signing of sales and purchase agreements for the sale of Audrain resulting in its reclassification as a discontinued operation	
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      The following table summarizes the debt transactions during 2005 and subsequent transactions in 2006:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Balance	 	 	2005 activity and	 	 	2006 activity and	 	
 	 	 	 	 	 	Outstanding at	 	 	Outstanding at	 	 	Outstanding at	 	
 	 	Date of	 	 	Original	 	 	December 31,	 	 	December 31,	 	 	February 25,	 	
 	 	Transaction	 	 	Amount	 	 	2004	 	 	2005	 	 	2006	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Xcel Promissory Note	 	 	Dec. 6, 2003	 	 	$	10	 	 	$	10	 	 	$	10	 	 	$	10	 	
NRG 8% Second Priority Notes	 	Dec. 23, 2003- Jan. 28, 2004	 	 	1,725	 	 	 	1,725	 	 	 	 	 	 	 	 	 	
 	Repurchase of Notes	 	 	Jan-Mar, 2005	 	 	 	 	 	 	 	 	 	 	 	(41	)	 	 	 	 	
 	Early redemption	 	 	Feb-Sep, 2005	 	 	 	 	 	 	 	 	 	 	 	(604	)	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance Dec. 31, 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,080	 	 	 	 	 	
 	Repurchase of Notes	 	 	Feb. 2, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(1,080	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance Feb. 25, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	—	 	
NRG Credit Facility Term loan	 	 	Dec. 23, 2003	 	 	 	950	 	 	 	450	 	 	 	 	 	 	 	 	 	
 	Repayments of Term Loans	 	 	Throughout 2005	 	 	 	 	 	 	 	 	 	 	 	(4	)	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance Dec. 31, 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	446	 	 	 	 	 	
 	Prepayment of Term Loan	 	 	Jan 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(446	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance Feb. 25, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	—	 	
Letter of Credit facility	 	 	Dec. 23, 2003	 	 	 	250	 	 	 	350	 	 	 	350	 	 	 	 	 	
 	Terminating Letter of Credit facility	 	 	Feb. 2, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(350	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance Feb. 25, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	—	 	
Corporate Revolver*	 	 	Dec. 23, 2003	 	 	 	250	 	 	 	150	 	 	 	150	 	 	 	 	 	
 	Terminating Corporate Revolver *	 	 	Feb. 2, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(150	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance Feb. 25, 2006 *	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	—	 	
New Sr. Secured Term loan	 	 	Feb. 2, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	3,575	 	
New Funded LC Facility	 	 	Feb. 2, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,000	 	
New Corporate Revolver*	 	 	Feb. 2, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance Feb. 25, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	5,575	 	
7.25% Senior Notes due 2014	 	 	Feb. 2, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,200	 	
7.375% Senior Notes due 2016	 	 	Feb. 2, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	2,400	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance Feb. 25, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	3,600	 	
Total Corporate Level Debt*	 	 	 	 	 	 	 	 	 	$	2,535	 	 	$	1,886	 	 	$	7,185	 	

 	 	
* 	Amount indicates capacity to borrow under NRG’s revolver facilities only. Un-borrowed capacity is not included in total corporate level debt.	

 	Sources of Funds	
      The principal sources of liquidity for our future operations and capital expenditures are expected to be existing cash on hand, cash flows from operations, and funds raised from new financing arrangements.
      Cash Flows from Operations. Our operating cash flows are expected to be impacted by, among other things: (i) spark spreads generally; (ii) commodity prices (including demand for natural gas, coal, oil and electricity); (iii) the cost of ordinary course operations and maintenance expenses; (iv) planned and unplanned outages; (v) restrictions in the declaration or payments of dividends or similar distributions from our subsidiaries; and (vi) the timing and nature of asset sales. Following are additional sources of cash flows:
      Letter of credit and revolver borrowing capacity. We had approximately $38 million of undrawn letter of credit capacity and $150 million of revolving credit capacity under our Amended Credit Facility as of December 31, 2005. On February 2, 2006 we terminated our Amended Credit Agreement and entered into a new Senior Credit Facility. The new Senior Credit Facility consists of a $3.575 billion term loan, $1.0 billion in a synthetic letter of credit facility and $1.0 billion in a revolver facility. Portions of the revolving credit facility are available as a swing-line facility and as a revolving letter of credit sub-facility. As of March 3, 2006,

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we had approximately $225 million of undrawn letter of credit capacity under our senior credit facility and $845 million of revolving credit capacity under our Senior Credit Facility. The balance of the revolver has been used to issue non-commercial letters of credit. See our discussion below on the Financing Transactions and Texas Genco Acquisition in this discussion and analysis.
      Issuance of $250 million in 3.625% Preferred Stock. On August 11, 2005, we issued 250,000 shares of 3.625% Preferred Stock to Credit Suisse First Boston Capital LLC, or CSFB, in a private placement. As of December 31, 2005, 250,000 shares of the 3.625% Preferred Stock were issued and outstanding at a liquidation value, net of issuance costs of $246 million. Holders of the 3.625% 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 3.625% per annum, payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year, commencing on December 14, 2005. On or after August 11, 2015, we may redeem, subject to certain limitations, some or all of the 3.625% 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 from the sale of the 3.625% preferred securities along with cash on hand were used to redeem $229 million in Second Priority Notes, pay an early redemption penalty of $18 million and pay accrued interest of $4 million on the redeemed notes.
      Settlements and Asset Sales. On February 15, 2005 we received a $71 million settlement payment from Petrobras, our former partner in our TermoRio project in Brazil. During 2005, we received approximately $106 million in proceeds from the sale of our interest in non-core projects, including our interest in Enfield, Northbrook New York and Northbrook Energy and remaining interest in Kendall.
      Repatriation of Foreign Funds. During the third quarter of 2005 we repatriated approximately $298 million of accumulated foreign earnings. Only a portion of this amount represents the cumulative earnings and profits from the foreign entities. Those earnings resulted in approximately $5 million of tax expense. This repatriation was initiated to utilize the tax benefits of the American Jobs Creation Act of 2004 which expired on December 31, 2005.
 	 	
 	Uses of Funds	
      Our requirements for liquidity and capital resources, other than for operating our facilities, can generally be categorized by the following: (i) Commercial Operations (formerly referred to as PMI) activities; (ii) capital expenditures; (iii) corporate financial restructuring and (iv) project finance requirements.
 	 	
 	(i) Commercial Operations	
      Commercial Operations activities comprise the single largest requirement for liquidity and capital resources. These 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, 2005, Commercial Operations had total cash collateral outstanding of $438 million, and $227 million outstanding in letters of credit to third parties primarily to support our economic hedging activities.
      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.
      Following the Acquisition, our debt instruments permit us to grant secured priority liens on our assets to support certain trading activities which will provide an alternative to posting cash deposits and letters of credit. See our discussion below on the Financing Transactions and Texas Genco Acquisition in this discussion and analysis.

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 	(ii) Capital Expenditures	
      Capital expenditures were $106 million for the year ended December 31, 2005, and $119 million for the year ended December 31, 2004. Capital expenditures in 2005 related to the continued PRB conversions, associated conveyor track and emissions compliance upgrades at our Western New York plants. Indian River’s PRB conversion is underway at units 1-3. Unit 4 at Indian River, originally targeted for conversion, was deemed incompatible for PRB coal during 2005. Capital expenditures in 2004 also related primarily to the conversion of our western New York plants to PRB coal, as well as the Playford 2 refurbishment at our Flinders operation in Australia and planned outages across our fleet.
 	 	
 	(iii) Corporate Financial Restructuring	
      Repurchase and redemption of Second Priority Notes during 2005. In conjunction with our goal of improving our credit ratings we manage our capital allocation around a target of 45%-60% debt to capital ratio. As such, we may elect periodically to modify our corporate financial structure. Throughout 2005, we repurchased or redeemed, and subsequently retired, $645 million of our Second Priority Notes. Total costs associated with the repurchase and redemptions was $52 million in early redemption premium, $9 million in accrued but unpaid interest, and $7 million in accrued but unpaid liquidated damages.
      Redemption of Second Priority Notes and Termination of Credit Facility during 2006. On January 31, 2006 we repaid $446 million in outstanding principal plus $3 million in accrued interest and terminated our term loan under our Amended Credit Facility. On February 2, 2006, we repurchased and retired $1.08 billion of our Second Priority Notes, pursuant to a tender offer, paying approximately $138 million in consent premiums and accrued interest. On February 2, 2006 we defeased the remaining un-tendered $0.4 million of our Second Priority Notes, effectively terminating our obligations with respect to such Notes. Also on February 2, 2006 we paid $1 million in accrued fees and terminated our revolving facility and our funded letter of credit facility under our Amended Credit Facility, and simultaneously issued new indebtedness, as described below in  New Financing Structure and Texas Genco Acquisition  in this discussion and analysis.
      Accelerated Share Repurchase Plan. On August 11, 2005, we entered into an Accelerated Share Repurchase Agreement with CSFB, pursuant to which we repurchased $250 million of our common stock on that date that equaled a total of 6,346,788 shares, which were held in treasury. We funded the repurchase with cash on hand. On March 3, 2006, we paid to CSFB a cash purchase price adjustment of approximately $7 million based upon the weighted average value of NRG’s common stock over a period of approximately six months, subject to a minimum price of 97% and a maximum price of 103% of the closing price per share on August 10, 2005, or $39.39.
      Preferred Dividend Payments. During 2005, we paid approximately $17 million in four dividend payments to our holders of our 4% Preferred Stock. On December 15, 2005, we made an approximate $3 million dividend payment to our 3.625% preferred shareholders of record as of December 1, 2005.
 	 	
 	(iv) Project Finance Requirements	
      We are a holding company and conduct our operations primarily 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 of our affiliates, or we may develop, construct or acquire new projects. 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.

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      Principal on short-term debt, long-term debt and capital leases as of December 31, 2005 are due and payable in the following periods (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Subsidiary/Description	 	Total	 	 	2006	 	 	2007	 	 	2008	 	 	2009	 	 	2010	 	 	Thereafter	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Xcel Energy Note	 	$	10	 	 	$	10	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Amended Credit Facility due	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Dec. 2011	 	 	796	 	 	 	796	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
8% Second Priority Notes	 	 	1,080	 	 	 	1,080	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
NRG Energy Center Minneapolis, due 2013 and 2017	 	 	111	 	 	 	8	 	 	 	9	 	 	 	10	 	 	 	11	 	 	 	11	 	 	 	62	 	
NRG Peaker Finance Co LLC	 	 	297	 	 	 	7	 	 	 	11	 	 	 	13	 	 	 	15	 	 	 	20	 	 	 	231	 	
Flinders Power Finance Pty	 	 	177	 	 	 	6	 	 	 	14	 	 	 	4	 	 	 	8	 	 	 	18	 	 	 	127	 	
Camas Pwr BLR LP Bank facility	 	 	4	 	 	 	3	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Camas Pwr BLR LP Bonds	 	 	3	 	 	 	1	 	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Itiquira Energetica S.A., due January 2012	 	 	19	 	 	 	3	 	 	 	3	 	 	 	3	 	 	 	3	 	 	 	3	 	 	 	4	 	
Itiquira Energetica S.A., due December 2013	 	 	30	 	 	 	4	 	 	 	4	 	 	 	4	 	 	 	4	 	 	 	4	 	 	 	10	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Subtotal Debt, Bonds and Notes	 	 	2,527	 	 	 	1,918	 	 	 	44	 	 	 	34	 	 	 	41	 	 	 	56	 	 	 	434	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Saale Energie GmbH, Schkopau (capital lease)	 	 	214	 	 	 	61	 	 	 	34	 	 	 	28	 	 	 	21	 	 	 	10	 	 	 	60	 	
Conemaugh Fuels LLC (capital lease)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Subtotal Capital Leases	 	 	214	 	 	 	61	 	 	 	34	 	 	 	28	 	 	 	21	 	 	 	10	 	 	 	60	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total Debt	 	$	2,741	 	 	$	1,979	 	 	$	78	 	 	$	62	 	 	$	62	 	 	$	66	 	 	$	494	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      These amounts reflect scheduled amortization of principal as of December 31, 2005, with the exception of the 8% Second Priority Notes, and our Credit Facility, for which 2006 amounts reflect early termination. The table below reflects the new short-term and long-term debt amounts and the expected future payments. Also see our discussion below on the Financing Transactions and Texas Genco Acquisition in this discussion and analysis, as well as Item 15 — Note 17 to the Consolidated Financial Statements for further discussion on events that may affect debt payment schedules.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Description	 	Total	 	 	2006	 	 	2007	 	 	2008	 	 	2009	 	 	2010	 	 	Thereafter	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
New Credit Facility due Feb 2013	 	$	3,575	 	 	$	26	 	 	$	36	 	 	$	36	 	 	$	36	 	 	$	36	 	 	$	3,405	 	
7.25% Notes due 2014	 	 	1,200	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,200	 	
7.375% Notes due 2016	 	 	2,400	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,400	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total Debt	 	$	7,175	 	 	$	26	 	 	$	36	 	 	$	36	 	 	$	36	 	 	$	36	 	 	$	7,005	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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 	Historical Cash Flows	
      We have obtained cash from operations, proceeds from repayment of outstanding notes receivable, proceeds from the sale of certain assets and the proceeds from the sale of preferred stock. We have used these funds to finance operations, reduce our outstanding Second Priority Notes, repurchase common stock through an accelerated share repurchase plan, service debt obligations, finance capital expenditures, and meet other cash and liquidity needs. The following table reflects the changes in cash flows for the comparative years and we include a detailed discussion on the changes during the last year. All cash flow categories include the cash flows from continuing operations and discontinued operations:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	Company	 	
 	 	 	 	 	 	 	
 	 	 	 	For the Period	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6-	 	 	January 1-	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Net cash provided (used) by operating activities	 	$	68	 	 	$	645	 	 	$	(589	)	 	$	238	 	
Net cash (used) provided by investing activities	 	 	158	 	 	 	184	 	 	 	363	 	 	 	(186	)	
Net cash provided (used) by financing activities	 	 	(830	)	 	 	(284	)	 	 	393	 	 	 	(30	)	

 	Net Cash Provided (Used) By Operating Activities	
      For the year ended December 31, 2005, net cash provided by operating activities decreased by $580 million compared to the year ended December 31, 2004. This is primarily due to the following reasons:
 	 	 	
 	• 	Net income decreased by $102 million for the year ended December 31, 2005 compared to the year ended December 31, 2004.	
 	 	 	
 	• 	Due to the sharp increase in the sale price per MWh, our derivative contract terms required collateral deposits of $405 million during 2005, compared to $7 million during 2004, a difference of $398 million. As of December 31, 2005 we had collateral deposits of $438 million and we expect $405 of this amount to be refunded during 2006 as the underlying contracts expire.	
 	 	 	
 	• 	A decrease of $60 million in distributions from our equity investments during 2005 compared to 2004. The majority of this decrease is from our WCP investment. Since the expiration of the CDWR contract on December 31, 2004, WCP’s profit has been significantly reduced and has subsequently distributed $59 million less dividends during 2005 compared to 2004.	
 	 	 	
 	• 	Receipt of $100 million in 2004 related to the settlement with Xcel Energy.	

 	Net Cash Provided (Used) By Investing Activities	
      For the year ended December 31, 2005, net cash provided by investing activities was $26 million less than for the year ended December 31, 2004. This decrease is due to the following mix of investment activities:
 	 	 	
 	• 	During 2004, we sold interests in non-core assets for proceeds totaling $304 million. As most of the non-core assets were sold during 2004 and management began focusing on different areas of operation, during 2005 proceeds from the sale of non-core assets fell by $198 million.	
 	 	 	
 	• 	Our capital expenditures were $13 million less during 2005 compared to 2004 due to lower PRB conversion expenditures.	
 	 	 	
 	• 	During 2005, proceeds from payments on our notes receivable increased by $82 million, primarily due to the payment from TermoRio of approximately $71 million as the dispute related to this note was settled.	
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 	• 	In comparison to an increase of $27 million during 2004, restricted cash balances decreased by $46 million, a difference of $72 million. This amount is explained by the release of approximately $38 million of restricted cash at our Flinders facility as a result of our refinancing of Flinders’ debt, as well as the release of accounts from restrictions during post bankruptcy operations.	

 	Net Cash Provided (Used) By Financing Activities	
      For the year ended December 31, 2005, net cash used by financing activities increased by $546 million in comparison to 2004. The activity for 2005 consisted of:
 	 	 	
 	• 	The redemption and repurchase of $645 million of our Second Priority Secured Notes. In order to redeem our Second Priority Notes, we issued $420 million of the 4% Preferred Stock in December 2004, and subsequently, $250 million of the 3.625% Preferred Stock in August of 2005. The timing difference between the receipt of cash from our 4% Preferred Stock in December 2004 and the redemption of debt in 2005 is the primary reason for the increase in cash used for financing activities in 2005 in comparison to 2004.	
 	 	 	
 	• 	Our accelerated share repurchase payment of $250 million.	
 	 	 	
 	• 	Payment of $46 million for financing costs to refinance our Flinders’ debt.	
 	 	 	
 	• 	Payment of $20 million of dividends to holders of our preferred stock.	
      During 2004, the primary use of funds for financing activities was related to the repayment of project level debt at McClain of approximately $157 million and regular debt payments of approximately $135 million.
 	 	
 	Other Liquidity Matters — NOLs and Deferred Tax Assets	
      As of December 31, 2005, we U.S. NOL carryforwards of approximately $93 million. We believe that it is more likely than not that the benefit will not be realized on a substantial portion of the deferred tax assets relating to future tax benefits. This assessment includes consideration of positive and negative factors, including our current financial position, historical results of operations and current results of operations, projected future taxable income, including projected operating and capital gains, and available tax planning strategies. Therefore, as of December 31, 2005, a consolidated valuation allowance of $756 million was recorded against the net deferred tax assets, in accordance with SFAS No. 109. However, we have not provided a valuation allowance for approximately $15 million of net deferred tax assets which consist of mark-to-market adjustments per SFAS 133 and utilization of carryover net operating losses to the extent of taxable income generated for the year ended December 31, 2005.
 	 	
 	Conclusion on Future Liquidity	
      As of December 31, 2005 our liquidity was $758 million and included $570 million of unrestricted and restricted cash. Our liquidity also included $150 million of available capacity under our revolving line of credit and $38 million of availability under our letter of credit facility. As of December 31, 2004 our liquidity was $1.6 billion and included $1.2 billion of unrestricted and restricted cash. Our liquidity also included $150 million of available capacity under our revolving line of credit and $193 million of availability under our letter of credit facility.
      Based on the new financing transactions, but assuming the cash balances as of December 31, 2005 and the outstanding instruments as of March 3, 2006, our liquidity would be $1.6 billion and includes $570 million of unrestricted and restricted cash. Our liquidity include $845 million of available capacity under our new Revolving Credit Facility and $225 million of availability under our new synthetic Letter of Credit Facility, as of March 3, 2006. Please see discussion below for further detail.
      Management believes that these amounts and cash flows from operations will be adequate to finance capital expenditures, to fund dividends to our preferred shareholders and other liquidity commitments for the next 12 months. Management continues to regularly monitor the company’s ability to finance the needs of its

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operating, financing and investing activity in a manner consistent with its intention to maintain a debt to capital ratio within a range of 45%-60%.
 	 	
 	Known Trends and Other Factors Affecting our Liquidity	
     New Financing Structure and Texas Genco Acquisition
      On February 2, 2006, NRG acquired Texas Genco LLC, a Delaware limited liability company, by purchasing all of the outstanding equity interests in Texas Genco pursuant to the Acquisition Agreement, dated September 30, 2005, by and among NRG, Texas Genco, and each of the direct and indirect owners of Texas Genco. The purchase price of approximately $6.1 billion consisted of $4.4 billion in cash and the issuance of approximately 35.4 million shares of NRG’s common stock valued at $1.7 billion. This amount is subject to adjustment due to acquisition costs. The value of our common stock issued to the Sellers was based on our average stock price immediately before and after the closing date of February 2, 2006. The Acquisition includes the assumption of approximately $2.7 billion of Texas Genco debt. Texas Genco is now a wholly-owned subsidiary of NRG, and will be managed and accounted for as a new business segment to be referred to as NRG Texas.
      The Texas Genco acquisition was partially funded at closing with the combination of (i) cash proceeds received upon the issuance and sale in a public offering of 20,855,057 shares of NRG’s common stock at a price of $48.75 per share; (ii) cash proceeds received upon the issuance and sale of $3.6 billion of unsecured high yield notes; (iii) cash proceeds received upon the issuance and sale in a public offering of 2,000,000 shares of mandatory convertible preferred stock at a price of $250 per share; (iv) funds borrowed under a new senior secured credit facility consisting of a $3.575 billion term loan facility, a $1.0 billion revolving credit facility and a $1.0 billion synthetic letter of credit facility; and (v) cash on hand.
      Texas Genco owns approximately 11,000 MW of net operating generation capacity, and sells power and related services in the Texas’ ERCOT market.
 	 	
 	New Senior Credit Facility	
      On February 2, 2006, we also entered into a new senior secured first priority credit facility with a syndicate of financial institutions, including Morgan Stanley Senior Funding, Inc., as administrative agent, Morgan Stanley & Co. Inc., as collateral agent, and Morgan Stanley Senior Funding, Inc. and Citigroup Global Markets Inc. as joint lead book-runners, joint lead arrangers and co-documentation agents providing for up to an aggregate amount of $5.575 billion, or the New Senior Credit Facility. The New Senior Credit Facility consists of a $3.575 billion term loan facility, or the Term Loan Facility, a $1.0 billion revolving credit facility, or the Revolving Credit Facility, and a $1.0 billion synthetic letter of credit facility, or the Letter of Credit Facility. The New Senior Credit Facility replaced our then existing senior secured credit facility. The Term Loan Facility will mature on February 2, 2013 and will amortize in 27 consecutive equal quarterly installments of 0.25% of the original principal amount of the Term Loan Facility with the balance payable on the seventh anniversary thereof. The full amount of the Revolving Credit Facility will mature on February 2, 2011. The Letter of Credit Facility will mature on February 2, 2013 and no amortization will be required in respect thereof.
      The New Senior Credit Facility is guaranteed by substantially all of our existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries and certain other subsidiaries. In addition, the New Senior Credit Facility is secured by liens on substantially all of our assets and the assets of our subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries and certain other subsidiaries. The capital stock of substantially all of our subsidiaries, with certain exceptions for unrestricted subsidiaries, foreign subsidiaries and project subsidiaries, has been pledged for the benefit of the New Senior Credit Facility lenders.
      The New Senior Credit Facility is also secured by a first-priority perfected security interest in all of the property and assets owned at-any time or acquired by us and our subsidiaries, other than certain limited

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exceptions. These exceptions include assets such as the assets of certain unrestricted subsidiaries, equity interests in certain of our project affiliates that have non-recourse debt financing, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of our foreign subsidiaries.
      The New Senior Credit Facility contains customary covenants, which, among other things require us to meet certain financial tests, including a minimum interest coverage ratio and a maximum leverage ratio, each at the corporate level and on a consolidated basis, and further limits our ability to, among other things:
 	 	 	
 	• 	incur indebtedness and liens and enter into sale and lease-back transactions;	
 	 	 	
 	• 	make investments, loans and advances;	
 	 	 	
 	• 	engage in mergers, acquisitions, consolidations and asset sales;	
 	 	 	
 	• 	pay dividends and make other restricted payments;	
 	 	 	
 	• 	enter into transactions with affiliates;	
 	 	 	
 	• 	make capital expenditures;	
 	 	 	
 	• 	make debt payments; and	
 	 	 	
 	• 	make certain changes to the terms of material indebtedness.	

 	Senior Notes	
      On February 2, 2006, we completed the sale of (i) $1.2 billion in aggregate principal amount of 7.25% senior notes due 2014, or 7.25% Senior Notes, and (ii) $2.4 billion in aggregate principal amount of 7.375% senior notes due 2016, or 7.375% Senior Notes, collectively the Senior Notes. The Senior Notes were issued under an Indenture, dated February 2, 2006, between us and Law Debenture Trust Company of New York, as Trustee, as supplemented by a First Supplemental Indenture, dated February 2, 2006, between us, the guarantors named therein and the Trustee, relating to the 7.25% Senior Notes, and as supplemented by a Second Supplemental Indenture, dated February 2, 2006,(together with the Indenture and the First Supplemental Indenture, the Indentures) between us, the guarantors named therein and the Trustee, relating to the 7.375% Senior Notes. The Indentures provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG.
      Interest is payable on the Senior Notes on February 1 and August 1 of each year beginning on August 1, 2006 until their maturity dates — February 1, 2014 for the 7.25% Senior Notes and February 1, 2016 for the 7.375% Senior Notes.
      Prior to February 1, 2010 for the 7.25% Senior Notes and prior to February 1, 2011 for the 7.375% Senior Notes, we may redeem all or a portion of the series of Senior Notes at a price equal to 100% of the principal amount plus a “make whole” premium and accrued interest. On or after February 1, 2010 for the 7.25% Senior Notes and on or after February 1, 2011 for the 7.375% Senior Notes, we may redeem all or a portion of the series of Senior Notes at redemption prices set forth in the Indentures. In addition, at any time prior to February 1, 2009, we may redeem up to 35% of the aggregate principal amount of the series of Senior Notes with the net proceeds of certain equity offerings at the redemption price set forth in the Indentures.
      The terms of the Indentures, among other things, limit our ability and certain of our subsidiaries’ ability to:
 	 	 	
 	• 	make restricted payments;	
 	 	 	
 	• 	restrict dividends or other payments of subsidiaries;	
 	 	 	
 	• 	incur additional debt;	
 	 	 	
 	• 	engage in transactions with affiliates;	
 	 	 	
 	• 	create liens on assets;	
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 	• 	engage in sale and leaseback transactions; and	
 	 	 	
 	• 	consolidate, merge or transfer all or substantially all of its assets and the assets of its subsidiaries.	
      The Indentures provide for customary events of default which include, among others, nonpayment of principal or interest; breach of other agreements in the Indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against us and our subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately.
 	 	
 	Second Lien Structure	
      Before the Acquisition, Texas Genco’s capital structure permitted the grant of second priority liens on its assets as security for their obligations under certain long-term power sales agreements and related hedges. The Credit Agreement for New Senior Credit Facility and the Indentures, which became effective as of February 2, 2006, allow these arrangements to remain in place. In addition, the new debt instruments also permit us to grant second priority liens on our other assets in the United States in order to secure obligations under power sales agreements and related hedges, within certain limits. The seven trading counterparties of Texas Genco who held second priority liens on Texas Genco’s assets as of February 2, 2006, have been offered a second priority lien on NRG’s other assets under the new structure, as additional collateral. Going forward, NRG anticipates that it will use the second lien structure to reduce the amount of cash collateral and letters of credit that it may otherwise be required to post from time to time to support its obligations under long term power sales and related hedges. Also see Item 1 — “Business” section — within the “Power Marketing and Commercial Operations” discussion for quantified utilization as of December 31, 2005.
 	 	
 	Mandatory Convertible Preferred Stock	
      On February 2, 2006, we completed the issuance of 2 million shares of 5.75% mandatory convertible preferred stock, or the 5.75% Preferred Stock, at an offering price of $250 per share for total net proceeds after deducting offering expenses and underwriting discounts of approximately $485 million. Dividends on the 5.75% Preferred Stock are $14.375 per share per year, and are due and payable on a quarterly basis beginning on March 15, 2006. The 5.75% Preferred Stock will automatically convert into common stock on March 16, 2009, or the Conversion Date, at a rate that is dependent upon the applicable market value of our common stock. If the applicable market value of our common stock is $60.45 a share or higher at the Conversion Date, then the 5.75% Preferred Stock is convertible at a rate of 4.1356 shares of our common stock for every share of 5.75% Preferred Stock outstanding. If the applicable market value of our common stock is less than or equal to $48.75 per share at the Conversion Date, then the 5.75% Preferred Stock is convertible at a rate of 5.1282 shares of our common stock for every share of 5.75% Preferred Stock outstanding. If the applicable market value of our common stock is between $48.75 per share and $60.45 per share at the Conversion Date, then the 5.75% Preferred Stock is convertible into common stock at a rate that is between 4.1356 per share and 5.1282 per share of common stock.
 	 	
 	Common Stock	
      On January 31, 2006, we completed the issuance of 20,855,057 shares of our common stock at an offering price of $48.75 per share for total net proceeds after deducting offering expenses and underwriting discounts of approximately $985 million.
 	 	
 	Sale of Audrain	
      Audrain has an approximate total of $355 million in long and short-term debt. We anticipate that the sale of Audrain will close during the first half of 2006 upon which these balances will be eliminated.

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 	Brownfield Developments	
      As part of our strategy to reinvest capital in our existing assets for reason of repowering and expansion of current generation sites, management is evaluating opportunities within our core areas of operations.
      During the third quarter, we received a Title V Air Permit from the Louisiana Department of Environmental Quality to add a fourth unit of generating capacity at our Big Cajun II Generating Station in New Roads, Louisiana. The total capital expenditure expected from the construction of the 675 MW expansion project is approximately $1 billion and would take four years to build. Our Big Cajun II facility serves the electricity needs of Louisiana’s 11 electric cooperatives and we believe that there is additional unmet demand for coal-fired generation in the area. We are currently evaluating potential partners and customers for this project as they are critical to the consideration of when to proceed with this project.
          Operations in Australia
      NRG is currently considering strategic alternatives with respect to Australia either to reposition its assets more effectively within the National Electricity Market or to monetize its investment. We will seek to determine the best option to optimize our investment during 2006.
     Off-Balance Sheet Items
 	 	
 	Obligations Under Certain Guarantee Contracts	
      NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See Note 29, Guarantees and Other Contingent Liabilities for further details of the guarantee arrangements.
 	 	
 	Retained or Contingent Interests	
      NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
 	 	
 	Derivative Instrument obligations	
      On August 11, 2005 NRG issued the 3.625% Preferred Stock which includes a conversion feature which is considered a derivative per FAS 133. Although it is considered a derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of SFA 133. Despite this exclusion, per the guidance of EITF Topic D-98 the conversion feature must be marked-to-market. Currently, the conversion feature is valued at $0 as our stock price is outside the conversion range. See Note 18 Capital Structure for further discussion.
 	 	
 	Obligations Arising Out of a Variable Interest in an Unconsolidated Entity	

 	Variable interest in Equity investments	
      As of December 31, 2005, 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. Our pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $178 million and $252 million as of December 31, 2005 and December 31, 2004, respectively. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to us. In the normal course of business we may be asked to loan funds to 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.

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 	New Synthetic Letter of Credit Facility and Revolver Facility	
      Under the New Senior Credit Facility we entered into on February 2, 2006, we have a $1.0 billion synthetic Letter of Credit Facility that is unfunded directly by NRG, and a $1.0 billion senior Revolving Credit Facility. The synthetic Letter of Credit Facility is secured by a $1.0 billion cash collateral deposit, held by Deutsche Bank AG, New York Branch as the Issuing Bank. Under the synthetic Letter of Credit Facility, we are allowed to issue letters of credit to support our obligations under commodity hedging or power purchase arrangements. We are permitted to issue up to $300 million in unfunded letters of credit under our Revolving Credit Facility for ongoing working capital requirements and for general corporate purposes, including acquisitions that are permitted under the New Senior Credit Facility, or revolver letters of credit.
      As of March 3, 2006, we had issued $775 million in funded letters of credit under the Letter of Credit Facility. Of this amount, a portion was issued to support obligations under terminated NRG and Texas Genco letter of credit facilities. As of March 3, 2006, we had issued $155 million in revolver letters of credit, a portion of which supports non-commercial letter of credit obligations under the terminated NRG and Texas Genco letters of credit facilities.
 	 	
 	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 17 and 25 to the Consolidated Financial Statements.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Payments Due by Period as of December 31, 2005	 	
 	 	 	 	
 	 	 	 	After	 	
Contractual Cash Obligations	 	Total	 	 	Short-term	 	 	2-3 Years	 	 	4-5 Years	 	 	5 Years	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Long-term debt (including estimated interest)	 	$	3,600	 	 	$	201	 	 	$	391	 	 	$	408	 	 	$	2,600	 	
Capital lease obligations (including estimated interest)	 	 	406	 	 	 	77	 	 	 	90	 	 	 	52	 	 	 	187	 	
Operating leases	 	 	150	 	 	 	25	 	 	 	37	 	 	 	27	 	 	 	61	 	
Coal purchase and transportation obligations	 	 	416	 	 	 	192	 	 	 	154	 	 	 	52	 	 	 	18	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total contractual cash obligations	 	$	4,572	 	 	$	495	 	 	$	672	 	 	$	539	 	 	$	2,866	 	

 	 	Amount of Guarantee Liabilities Expiration per Period as of	 	
 	 	December 31, 2005	 	
 	 	 	 	
 	 	Total	 	 	 	
 	 	Amounts	 	 	 	 	After	 	
Guarantee Type	 	Committed	 	 	Short-term	 	 	2-3 Years	 	 	4-5 Years	 	 	5 Years	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Funded standby letters of credit	 	$	312	 	 	$	312	 	 	$	—	 	 	$	—	 	 	$	—	 	
Unfunded standby letters of credit	 	 	9	 	 	 	9	 	 	 	—	 	 	 	—	 	 	 	—	 	
Surety bonds	 	 	4	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	
Asset sales guarantee obligations	 	 	123	 	 	 	—	 	 	 	13	 	 	 	—	 	 	 	110	 	
Commodity sales guarantee obligations	 	 	91	 	 	 	62	 	 	 	12	 	 	 	14	 	 	 	3	 	
Other guarantees	 	 	91	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	90	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total guarantees	 	$	630	 	 	$	387	 	 	$	26	 	 	$	14	 	 	$	203	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      We have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to our capital expenditure programs, as discussed in Item 15 —

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Note 25, Commitments and Contingencies, to the Consolidated Financial Statements for a discussion of commitments and contingencies that also include contractual obligations and commercial commitments that occurred during 2005.
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, to 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, 2005 based on whether fair values are determined by quoted market prices or more subjective means; and indicate the maturities of contracts at December 31, 2005.
 	 	
 	Derivative Activity Gains/(Losses)	
 	 	 	 	 	
 	 	(In millions)	 	
Fair value of contracts at December 31, 2004	 	$	(43	)	
Contracts realized or otherwise settled during the period	 	 	129	 	
Changes in fair value	 	 	(490	)	
 	 	 	 	
Fair value of contracts at December 31, 2005	 	$	(404	)	

 	 	
 	Sources of Fair Value Gains/(Losses)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Fair Value of Contracts as of December 31, 2005	 	
 	 	 	 	
 	 	Maturity	 	 	 	 	Maturity	 	 	 	
 	 	Less Than	 	 	Maturity	 	 	Maturity	 	 	in Excess	 	 	Total Fair	 	
 	 	1 Year	 	 	1-3 Years	 	 	4-5 Years	 	 	of 5 Years	 	 	Value	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Prices actively quoted	 	$	(243	)	 	$	(12	)	 	$	—	 	 	$	—	 	 	$	(255	)	
Prices based on models and other valuation methods	 	 	2	 	 	 	(22	)	 	 	(10	)	 	 	(38	)	 	 	(68	)	
Prices provided by other external sources	 	 	(53	)	 	 	(1	)	 	 	6	 	 	 	(33	)	 	 	(81	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	(294	)	 	$	(35	)	 	$	(4	)	 	$	(71	)	 	$	(404	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      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

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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. 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	
 	 	 	
Revenue Recognition and Derivative Activity	 	• Assumptions used in valuation models	
 	 	• Market maturity and economic conditions	
 	 	• Contract interpretation	
 	 	• Market conditions in the energy industry, especially the effects of price volatility on contractual commitments	
 	 	• Documentation requirements	
 	 	• Market conditions in foreign countries	
 	 	• Regulatory and political environments and requirements	
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.	
Impairment of Long Lived Assets	 	• 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	
Goodwill and Other Intangible Assets	 	• Estimated useful lives for finite-lived intangible assets	
 	 	• Judgment about impairment triggering events	
 	 	• Estimates of reporting unit’s fair value	
 	 	• Fair value estimate of certain power sales and fuel contracts using forward pricing curves as of the closing date over the life of each contract	
Contingencies	 	• Estimated financial impact of event(s)	
 	 	• Judgment about likelihood of event(s) occurring	
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 	Revenue Recognition and Derivative Instruments	
      We record revenues using two methods of accounting: accrual accounting and mark-to-market accounting. We describe our use of accrual accounting, including the application of hedge accounting, in more detail in Note 2 to the Consolidated Financial Statements. In January 2001, we adopted SFAS 133, as amended by SFAS 137, SFAS 138 and SFAS 149. SFAS 133, as amended, requires us to mark-to-market all derivatives on the balance sheet. 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.
      Derivative instruments valuation assets and liabilities consist of a combination of energy and energy-related derivative contracts. While some of these contracts 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 modeling techniques to determine expected future market prices, contract quantities, or both. 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. However, future market prices and actual quantities will vary from those used in recording derivative instruments valuation assets and liabilities, and it is possible that such variations could be material.
 	 	
 	Income Taxes and Valuation Allowance for Deferred Tax Assets	
      At December 31, 2005, we had a valuation allowance of approximately $756 million primarily related to our U.S. net deferred tax assets. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the demonstration of a history of earnings and generation of future income during the periods in which those temporary differences will be deductible.
      As of December 31, 2005, we have approximately $93 million of U.S. federal and state net operating loss (NOLs) carryforwards for financial reporting purposes. The ultimate utilization of our NOLs will depend on several factors, such as our ability to utilize tax benefits through carrybacks to prior periods and carryforwards to future periods, the application of tax statutes and regulations to transactions, the ability of tax authority decisions to withstand legal challenges or appeals, and anticipated future decisions of tax authorities.
      We continue to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. A tax liability has been recorded for certain tax filing positions where our inability to sustain the tax return position is probable and estimable. Such liabilities are based on management’s judgment which considers the best estimate of the amount and probable outcome of the tax position, and it can take several years between the time when a liability is recorded and when the related filing position is resolved with the taxing authority. Management periodically reviews these matters and adjusts the liabilities recorded on the financial statements as appropriate.
 	 	
 	Evaluation of Assets for Impairment and Other Than Temporary Decline in Value	
      In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate property, plant and equipment and intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events are:
 	 	 	
 	• 	Significant decrease in the market price of a long-lived asset;	
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 	• 	Significant adverse change in the manner an asset is being used or its physical condition;	
 	 	 	
 	• 	Adverse business climate;	
 	 	 	
 	• 	Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset,	
 	 	 	
 	• 	Current-period loss combined with a history of losses or the projection of future losses;	
 	 	 	
 	• 	Change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.	
      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. We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
      For assets to be held and used, if we determine that the undiscounted cash flows from the asset are less than the carrying amount of the asset, we must estimate fair value to determine the amount of any impairment loss. Assets held for sale are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value under SFAS No. 144, whether in conjunction with an asset to be held and used or with an asset held for sale, and the evaluation of asset impairment are, by their nature, subjective. We consider quoted market prices in active markets to the extent they are available. In the absence of such information, we may consider prices of similar assets, consult with brokers, or employ other valuation techniques. We also will discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in our estimates, and the impact of such variations could be material.
      We are also required to evaluate our equity-method and cost-method investments to determine whether or not they are impaired. Accounting Principles Board Opinion No. 18,  The Equity Method of Accounting for Investments in Common Stock , or APB18, provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under APB 18 is whether the value that is considered an “other than a temporary” decline in value. The evaluation and measurement of impairments under APB 18 involves the same uncertainties as described for long-lived assets that we own directly and account for in accordance with SFAS 144. Similarly, the estimates that we make with respect to our equity and cost-method investments are subjective, and the impact of variations in these estimates could be material. Additionally, if the projects in which we hold these investments recognize an impairment under the provisions of SFAS 144, we would record our proportionate share of that impairment loss and would evaluate our investment for an other than temporary decline in value under APB 18.
      For the years ended December 31, 2005 and December 31, 2004, the periods December 6, 2003 through December 31, 2003 and January 1, 2003 through December 5, 2003 net income from continuing operations was reduced by $6 million, $45 million, $0 million and $229 million, respectively, due to investment impairments.

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 	Goodwill and Other Intangible Assets	
      As part of the Acquisition we expect to record intangible assets that may include goodwill resulting from the Acquisition and other intangible assets. We will apply SFAS 141, and SFAS 142 Goodwill and Other Intangible Assets, to account for these intangibles. Under these standards we will amortize all finite-lived intangible assets over their respective estimated weighted-average useful life, whereas goodwill and other intangibles that have indefinite lives are not amortized. However, goodwill and all intangible assets will be tested for impairment whenever an event occurs that indicates that an impairment may have occurred, or at a minimum on an annual basis. If necessary, our goodwill and/or intangible asset will be impaired at that time.
      In connection with the Acquisition, we expect to recognize the fair value of certain power sales and fuel contracts acquired. We estimate that the fair value of these contracts using forward pricing curves as of the closing date over the life of each contract. These contracts had negative fair values at the closing date of the acquisition and will be reflected as assumed contracts in the combined balance sheet. Assumed contracts are amortized to revenues and fuel expense as applicable based on the estimated realization of the preliminary fair value established on the closing date over the contractual lives.
 	 	
 	Contingencies	
      We record a loss contingency when management determines it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Gain contingencies are not recorded until management determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. We describe in detail our contingencies in Note 25 to the Consolidated Financial Statements.
 	 	
 	Recent Accounting Developments	
      See Note 2 to the Consolidated Financial Statements as found in Item 15 for a discussion of recent accounting developments.
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	
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 	• 	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 generation assets 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 valuations, 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, 2005	 	$	36.9	 	
 	Average	 	 	27.6	 	
 	High	 	 	45.9	 	
 	Low	 	 	16.0	 	
Year end December 31, 2004	 	 	26.7	 	
 	Average	 	 	40.3	 	
 	High	 	 	53.4	 	
 	Low	 	 	26.7	 	
      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 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, 2005 is approximately $37 million.

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      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.
      In January 2006, we entered into a series of new interest rate swaps. These interest rate swaps became effective on February 15, 2006 and are intended to hedge the risk associated with floating interest rates. For each of the interest rate swaps, we pay our counterparty the equivalent of a fixed interest payment on a predetermined notional value, and we receive quarterly the equivalent of a floating interest payment based on 3-month LIBOR calculated on the same notional value. All payments by us and our counterparties are made quarterly, and the LIBOR is determined in advance of each interest period. While the notional value of each of the swaps does not vary over time, the swaps are designed to mature sequentially. The total notional amount of these swaps as of February 25, 2006 was $2.15 billion. The notional amounts and maturities of each tranche of these swaps are as follows:
 	 	 	 	 	 	 	 	 	
Period of Swap	 	Notional value	 	 	Maturity	 	
 	 	 	 	 	 	 	
1-year	 	$	120 million	 	 	 	March 31, 2007	 	
2-year	 	$	140 million	 	 	 	March 31, 2008	 	
3-year	 	$	150 million	 	 	 	March 31, 2009	 	
4-year	 	$	190 million	 	 	 	March 31, 2010	 	
5-year	 	$	1.55 billion	 	 	 	March 31, 2011	 	
      As of December 31, 2005, we and our consolidating subsidiaries had various interest rate swap agreements with notional amounts totaling approximately $1.2 billion. If the swaps had been discontinued on December 31, 2005, we would have owed the counter-parties approximately $33.1 million. Based on the investment grade rating of the counterparties, we believe that our exposure to credit risk due to nonperformance by the counterparties 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, 2005, a 100 basis point change in interest rates would result in a $8.3 million change in interest expense on a rolling 12 month basis. When our new senior unsecured notes and new credit agreement are included, a 100 basis point change in interest rates would result in a $34 million change in interest expense on a rolling 12 month basis.
      At December 31, 2005, the fair value of our fixed-rate long-term debt was $2.8 billion, compared with the carrying amount of $2.7 billion. We estimate that a 1% decrease in market interest rates would have increased the fair value of our fixed-rate long-term debt by approximately $33 million. When our new senior unsecured notes and new credit agreement are included, we estimate that a 1% decrease in market rates would increase the fair value of our fixed rate long term debt by approximately $456 million.

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 	Liquidity Risk	
      Our collateral posted in support of our management of our electric generation facilities fluctuates based on amount of the portfolio hedged using collateralized contracts and market price movements. Based on a sensitivity analysis a $1 per MWh increase or decrease in electricity prices would cause a change in margin collateral outstanding of approximately $13 million. This sensitivity uses simplified assumptions and may not reflect actual market movements.
 	 	
 	Credit Risk	
      Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. We monitor and manage the credit risk of NRG 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 counterparty. Risks surrounding counterparty 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, 2005, we held collateral support of approximately $205 million from counterparties.
      A portion of our credit risk is related to transactions that are recorded in our Consolidated Balance Sheets. These transactions primarily consist of open positions from our marketing and risk management operation that are accounted for using mark-to-market accounting, as well as amounts owed by counterparties for transactions that settled but have not yet been paid. The following table highlights the credit quality and exposures related to these activities as of December 31, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Exposure	 	 	 	 	 	
 	 	Before	 	 	 	 	Net	 	
 	 	Collateral	 	 	Collateral	 	 	Exposure	 	
 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Investment grade	 	$	518	 	 	$	96	 	 	$	422	 	
Non-investment grade	 	 	24	 	 	 	5	 	 	 	19	 	
Not rated	 	 	164	 	 	 	25	 	 	 	139	 	
 	 	 	 	 	 	 	 	 	 	
 	Total	 	$	706	 	 	$	126	 	 	$	580	 	
Investment grade	 	 	73	%	 	 	76	%	 	 	73	%	
Non-investment grade	 	 	3	%	 	 	4	%	 	 	3	%	
Not rated	 	 	24	%	 	 	20	%	 	 	24	%	
      Additionally, we have concentrations of suppliers and customers among electric utilities, energy marketing and trading companies and regional transmission operators. These concentrations of counterparties may impact NRG’s overall exposure to credit risk, either positively or negatively, in that counterparties may be similarly affected by changes in economic, regulatory and other conditions.
      NRG’s exposure to significant counterparties greater than 10% of the net exposure of approximately $580 million was approximately $386 million as of December 31, 2005. We do not anticipate any material adverse effect on its financial position or results of operations as a result of nonperformance by any of its counterparties.
 	 	
 	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 denominated in the Euro, Australian Dollar and the Brazilian Real. We have historically engaged in a strategy of hedging foreign denominated cash flows through a program of matching currency inflows and outflows, and to

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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, 2005, neither we, nor any of our consolidating subsidiaries, had any material outstanding foreign currency exchange contracts.
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 Rules 13a-15(e) or 15d-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
      Effective March 3, 2006, NRG entered into a restated employment agreement with David Crane, pursuant to which Mr. Crane will continue to serve as the Company’s President and Chief Executive Officer. The initial term of the restated employment agreement will end on December 31, 2008, but the agreement provides for automatic extensions for additional successive one-year terms on the same terms and conditions, unless either party provides the other with notice to the contrary at least 90 days prior to the end of the initial term or any subsequent one-year term. The restated employment agreement provides for an initial annual base salary of $1,000,000. For each one-year period thereafter, Mr. Crane’s base salary will be reviewed and may be increased by the Board. Beginning with the 2006 fiscal year, Mr. Crane is entitled to an annual bonus with a target amount of up to 100 percent of his base salary, based upon the achievement of criteria determined at the beginning of the fiscal year by the Board, with input from Mr. Crane, for that fiscal year. In addition, beginning with the 2006 fiscal year, Mr. Crane is entitled to a maximum annual bonus equal to up to an additional 100 percent of his base salary, based upon the achievement of criteria determined at the beginning of the fiscal year by the Board, with input from Mr. Crane, for that fiscal year. Mr. Crane is also eligible to participate in the Long Term Incentive Plan in accordance with its terms and is entitled to receive other customary fringe benefits generally available to the Company’s executive employees. Mr. Crane is also entitled to certain severance benefits. Further details of Mr. Crane’s employment package are set forth in the restated employment agreement attached as Exhibit 10.33 to this Form 10-K and incorporated herein by reference.
      The Compensation Committee’s and the Board of Director’s approval of the Annual Incentive Plan Payout, or the AIP Payout, for each executive officer of NRG who is expected to be a named executive officer in NRG’s Proxy Statement for the annual meeting of stockholders to be held on April 28, 2006 became final on March 7, 2006. The named executive officers include: David Crane, President and Chief Executive Officer;

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Robert C. Flexon, Executive Vice President and Chief Financial Officer; Kevin Howell, Executive Vice President, Commercial Operations; John P. Brewster, Executive Vice President, International Operations and President, South Central Region; and Christine A. Jacobs, Vice President, Plant Operations. Effective January 3, 2006, the Board of Directors approved the 2006 Base Salary for Mr. Crane (as previously disclosed in a Form 8-K, filed January 5, 2006) and the Compensation Committee approved the 2006 Base Salary for the other named executive officers. The AIP Payout and the base salary for each named executive officer is set forth in the 2005 AIP Payout and 2006 Base Salary Table attached as Exhibit 10.34 to this Form 10-K and incorporated herein by reference.
      On March 1, 2006, the Compensation Committee, duly authorized by the Board of Directors, approved 2006 performance targets for Mr. Crane, President and Chief Executive Officer, Mr. Flexon, Executive Vice President and Chief Financial Officer and the other named executive officers. Performance targets include EBITDA and free cash flow financial goals, as well as non-financial goals in the areas of safety, environmental, strategic development, staff development and individual performance objectives. As noted above, the Chief Executive Officer will have a target opportunity of 100 percent of base salary with an additional maximum opportunity of 100 percent of base salary. The Chief Financial Officer will have a target opportunity of 75 percent of base salary with an additional maximum opportunity of 75 percent of base salary. The remaining named executive officers will have a target opportunity ranging from 50 to 75 percent of base salary with an additional maximum opportunity ranging from 25 to 37.5 percent of base salary.
PART III
Item 10 — Directors and Executive Officers of the Registrant
      NRG 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. It may be accessed through NRG’s website at http://www.nrgenergy.com/investor/corpgov.htm. NRG 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 incorporated by reference to the similarly named section of our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held April 28, 2006.
Item 11 — Executive Compensation
      Other information required by this Item will be incorporated by reference to the similarly named section of our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held April 28, 2006.
 	 	
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	
      Other information required by this Item will be incorporated by reference to the similarly named section of our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held April 28, 2006.
Item 13 — Certain Relationships and Related Transactions
      Other information required by this Item will be incorporated by reference to the similarly named section of our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held April 28, 2006.
Item 14 — Principal Accountant Fees and Services
      Other information required by this Item will be incorporated by reference to the similarly named section of our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held April 28, 2006.

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PART IV
Item 15 — Exhibits and Financial Statement Schedules
(a)(1) Financial Statements
      The following consolidated financial statements of NRG Energy and related notes thereto, together with the reports thereon of KPMG LLP are included herein:
 	 	
 	Consolidated Statement of Operations — Year ended December 31, 2005 and the Year ended December 31, 2004 (Reorganized NRG)	
 	 	
 	Consolidated Balance Sheet — December 31, 2005 and December 31, 2004 (Reorganized NRG)	
 	 	
 	Consolidated Statement of Cash Flows — Year ended December 31, 2005 and the Year ended December 31, 2004 (Reorganized NRG)	
 	 	
 	Consolidated Statement of Stockholders’ Equity/(Deficit) and Comprehensive Income/(Loss) — Year ended December 31, 2005 and the Year ended December 31, 2004 (Reorganized NRG)	
 	 	
 	Notes to Consolidated Financial Statements	
      The following consolidated financial statements of NRG Energy and related notes thereto, together with the reports thereon of PricewaterhouseCoopers LLP are included herein:
 	 	
 	Consolidated Statements of Operations — The period December 6, 2003 to December 31, 2003 (Reorganized NRG) and the period January 1, 2003 to December 5, 2003 (Predecessor Company)	
 	 	
 	Consolidated Statements of Cash Flows — The period December 6, 2003 to December 31, 2003 (Reorganized NRG) and the period January 1, 2003 to December 5, 2003 (Predecessor Company)	
 	 	
 	Consolidated Statements of Stockholders’ Equity/(Deficit) and Comprehensive Income/(Loss) — The period December 6, 2003 to December 31, 2003 (Reorganized NRG) and the period January 1, 2003 to December 5, 2003 (Predecessor Company)	
 	 	
 	Notes to Consolidated Financial Statements	
(a)(2) Financial Statement Schedule
      The following Consolidated Financial Statement Schedule of NRG Energy is filed as part of Item 15(d) of this report and should be read in conjunction with the Consolidated Financial Statements.
&nbsp;     Report of Independent Registered Public Accounting Firm on Financial Statement Schedule.
      Schedule II — Valuation and Qualifying Accounts
      All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.
(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report.
(b) Exhibits
(c) Financial Statement Schedule

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
      Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). 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 the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2005.
      Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in its report which is included in this Form 10-K.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
NRG Energy, Inc.:
      We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that NRG Energy, Inc. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, based on “criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)”. NRG Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
      In our opinion, management’s assessment that NRG Energy, Inc. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on “criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)”. Also, in our opinion, NRG Energy, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on “criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)”.
      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of NRG Energy, Inc. and subsidiaries as of December 31, 2005, and the related consolidated statements of operations, stockholders’ equity/(deficit) and comprehensive income/(loss), and cash flows for the year then ended December 31, 2005, and our report dated March 7, 2006 expressed an unqualified opinion on those consolidated financial statements.
 	 	
 	/s/ KPMG LLP	
 	 	
 	KPMG LLP	
Philadelphia, Pennsylvania
March 7, 2006

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
NRG Energy, Inc.:
      We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity/(deficit) and comprehensive income/(loss), and cash flows for each of the years in the two year period ended December 31, 2005. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule “Schedule II Valuation and Qualifying Accounts.” These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG Energy, Inc. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the two year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of NRG Energy, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2005, based on “criteria established in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)”, and our report dated March 7, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
 	 	
 	/s/ KPMG LLP	
 	 	
 	KPMG LLP	
Philadelphia, Pennsylvania
March 7, 2006

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of NRG Energy, Inc.:
      In our opinion, the accompanying consolidated statements of operations, cash flows and of stockholders’ equity/(deficit) and comprehensive income/(loss) of NRG Energy, Inc. and its subsidiaries (Reorganized NRG) present fairly, in all material respects, the results of their operations and their cash flows for the period from December 6, 2003 to December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
      As discussed in Notes 1 and 2 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of New York confirmed the NRG Energy, Inc. Plan of Reorganization on November 24, 2003. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before May 14, 2003 and substantially alters rights and interests of equity security holders as provided for in the plan. The NRG Energy, Inc. Plan of Reorganization was substantially consummated on December 5, 2003, and NRG Energy, Inc. emerged from bankruptcy. In connection with its emergence from bankruptcy, NRG Energy, Inc. adopted fresh start accounting as of December 5, 2003.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	
 	 	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004, except as to Notes 6, 21, and 33, which are as of December 6, 2004

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of NRG Energy, Inc.:
      In our opinion, the accompanying consolidated statement of operations, cash flows and of stockholders’ equity/(deficit) and comprehensive income/(loss) of NRG Energy, Inc. and its subsidiaries (Predecessor Company) present fairly, in all material respects, the results of their operations and their cash flows for the period from January 1, 2003 to December 5, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      As discussed in Notes 1 and 2 to the consolidated financial statements, the Company filed a petition on May 14, 2003 with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003 and Reorganized NRG emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	
 	 	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004, except as to Notes 6, 21, and 33, which are as of December 6, 2004

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	
 	 	 	 	December 6,	 	 	 	January 1,	 	
 	 	 	 	2003	 	 	 	2003	 	
 	 	Year Ended	 	 	Year Ended	 	 	Through	 	 	 	Through	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions, except per share amounts)	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Revenues from majority-owned operations	 	$	2,708	 	 	$	2,348	 	 	$	137	 	 	 	$	1,798	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cost of majority-owned operations	 	 	2,067	 	 	 	1,489	 	 	 	95	 	 	 	 	1,354	 	
 	Depreciation and amortization	 	 	194	 	 	 	208	 	 	 	12	 	 	 	 	211	 	
 	General, administrative and development	 	 	197	 	 	 	210	 	 	 	13	 	 	 	 	170	 	
 	Other charges (credits)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Corporate relocation charges	 	 	6	 	 	 	16	 	 	 	—	 	 	 	 	—	 	
 	 	Reorganization items	 	 	—	 	 	 	(13	)	 	 	2	 	 	 	 	198	 	
 	 	Restructuring and impairment charges	 	 	6	 	 	 	45	 	 	 	—	 	 	 	 	237	 	
 	 	Fresh start reporting adjustments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	(4,220	)	
 	 	Legal settlement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	463	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Total operating costs and expenses	 	 	2,470	 	 	 	1,955	 	 	 	122	 	 	 	 	(1,587	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	 	238	 	 	 	393	 	 	 	15	 	 	 	 	3,385	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Equity in earnings of unconsolidated affiliates	 	 	104	 	 	 	160	 	 	 	14	 	 	 	 	171	 	
 	Write downs and losses on sales of equity method investments	 	 	(31	)	 	 	(16	)	 	 	—	 	 	 	 	(147	)	
 	Other income, net	 	 	62	 	 	 	27	 	 	 	—	 	 	 	 	19	 	
 	Refinancing expenses	 	 	(56	)	 	 	(72	)	 	 	—	 	 	 	 	—	 	
 	Interest expense	 	 	(197	)	 	 	(266	)	 	 	(19	)	 	 	 	(308	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Total other expense	 	 	(118	)	 	 	(167	)	 	 	(5	)	 	 	 	(265	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income From Continuing Operations Before Income Taxes	 	 	120	 	 	 	226	 	 	 	10	 	 	 	 	3,120	 	
Income Tax Expense/(Benefit)	 	 	43	 	 	 	65	 	 	 	(1	)	 	 	 	38	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income From Continuing Operations	 	 	77	 	 	 	161	 	 	 	11	 	 	 	 	3,082	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	7	 	 	 	25	 	 	 	—	 	 	 	 	(316	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	 	84	 	 	 	186	 	 	 	11	 	 	 	 	2,766	 	
 	 	Preference stock dividends	 	 	20	 	 	 	—	 	 	 	—	 	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Available for Common Stockholders	 	$	64	 	 	$	186	 	 	$	11	 	 	 	$	2,766	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted Average Number of Common Shares Outstanding — Basic	 	 	85	 	 	 	100	 	 	 	100	 	 	 	 	—	 	
Income From Continuing Operations per Weighted Average Common Share — Basic	 	$	0.67	 	 	$	1.61	 	 	$	0.11	 	 	 	 	—	 	
Income From Discontinued Operations per Weighted Average Common Share — Basic	 	 	0.09	 	 	 	0.25	 	 	 	—	 	 	 	 	—	 	
Net Income per Weighted Average Common Share — Basic	 	$	0.76	 	 	$	1.86	 	 	$	0.11	 	 	 	 	—	 	
Weighted Average Number of Common Shares Outstanding — Diluted	 	 	85	 	 	 	100	 	 	 	100	 	 	 	 	—	 	
Income From Continuing Operations per Weighted Average Common Share — Diluted	 	$	0.66	 	 	$	1.60	 	 	$	0.11	 	 	 	 	—	 	
Income From Discontinued Operations per Weighted Average Common Share — Diluted	 	 	0.09	 	 	 	0.25	 	 	 	—	 	 	 	 	—	 	
Net Income per Weighted Average Common Shares — Diluted	 	$	0.75	 	 	$	1.85	 	 	$	0.11	 	 	 	 	—	 	
See notes to consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
 	 	(In millions, except shares	 	
 	 	and par value)	 	
ASSETS	
Current Assets	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	506	 	 	$	1,104	 	
 	Restricted cash	 	 	64	 	 	 	110	 	
 	Accounts receivable-trade, less allowance for
doubtful accounts of $2 and $1	 	 	280	 	 	 	270	 	
 	Accounts receivable-affiliate	 	 	4	 	 	 	—	 	
 	Current portion of notes receivable and capital lease	 	 	25	 	 	 	85	 	
 	Property taxes receivable	 	 	43	 	 	 	37	 	
 	Inventory	 	 	260	 	 	 	247	 	
 	Derivative instruments valuation	 	 	404	 	 	 	80	 	
 	Collateral on deposit in support of energy risk management activities	 	 	438	 	 	 	33	 	
 	Deferred income taxes	 	 	4	 	 	 	—	 	
 	Prepayments and other current assets	 	 	125	 	 	 	136	 	
 	Current assets — held for sale	 	 	43	 	 	 	—	 	
 	Current assets — discontinued operations	 	 	1	 	 	 	17	 	
 	 	 	 	 	 	 	
 	 	Total current assets	 	 	2,197	 	 	 	2,119	 	
 	 	 	 	 	 	 	
Property, Plant and Equipment, net	 	 	3,039	 	 	 	3,158	 	
 	 	 	 	 	 	 	
Other Assets	 	 	 	 	 	 	 	 	
 	Equity investments in affiliates	 	 	603	 	 	 	735	 	
 	Notes receivable, less current portion — affiliates, net	 	 	103	 	 	 	124	 	
 	Notes receivable and capital lease, less current portion, net	 	 	355	 	 	 	440	 	
 	Intangible assets, net of accumulated amortization of $79 and $55	 	 	257	 	 	 	294	 	
 	Derivative instruments valuation	 	 	22	 	 	 	42	 	
 	Funded letter of credit	 	 	350	 	 	 	350	 	
 	Deferred income tax	 	 	26	 	 	 	34	 	
 	Other assets	 	 	125	 	 	 	111	 	
 	Non-current assets — discontinued operations	 	 	354	 	 	 	457	 	
 	 	 	 	 	 	 	
 	 	 	Total other assets	 	 	2,195	 	 	 	2,587	 	
 	 	 	 	 	 	 	
Total Assets	 	$	7,431	 	 	$	7,864	 	
 	 	 	 	 	 	 	
See notes to consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS — (Continued)
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
 	 	(In millions, except shares	 	
 	 	and par value)	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	
Current Liabilities	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt and capital leases	 	$	101	 	 	$	511	 	
 	Accounts payable — trade	 	 	268	 	 	 	209	 	
 	Accounts payable — affiliates	 	 	—	 	 	 	5	 	
 	Derivative instruments valuation	 	 	692	 	 	 	17	 	
 	Other bankruptcy settlement	 	 	3	 	 	 	6	 	
 	Accrued expenses	 	 	82	 	 	 	57	 	
 	Other current liabilities	 	 	95	 	 	 	109	 	
 	Current liabilities — discontinued operations	 	 	115	 	 	 	173	 	
 	 	 	 	 	 	 	
 	 	 	Total current liabilities	 	 	1,356	 	 	 	1,087	 	
Other Liabilities	 	 	 	 	 	 	 	 	
 	Long-term debt and capital leases	 	 	2,581	 	 	 	2,973	 	
 	Deferred income taxes	 	 	135	 	 	 	169	 	
 	Postretirement and other benefit obligations	 	 	125	 	 	 	116	 	
 	Derivative instruments valuation	 	 	137	 	 	 	148	 	
 	Out of market contracts	 	 	298	 	 	 	319	 	
 	Other long-term obligations	 	 	81	 	 	 	71	 	
 	Non-current liabilities — discontinued operations	 	 	240	 	 	 	288	 	
 	 	 	 	 	 	 	
 	 	 	Total non-current liabilities	 	 	3,597	 	 	 	4,084	 	
 	 	 	 	 	 	 	
 	 	 	Total liabilities	 	 	4,953	 	 	 	5,171	 	
 	 	 	 	 	 	 	
Minority interest	 	 	1	 	 	 	1	 	
3.625% Convertible Perpetual Preferred Stock; $.01 par value; 250,000 shares issued and outstanding (at liquidation value of $250, net of issuance costs)	 	 	246	 	 	 	—	 	
Commitments and Contingencies	 	 	 	 	 	 	 	 	
Stockholders’ Equity	 	 	 	 	 	 	 	 	
4% Convertible Perpetual Preferred Stock; $.01 par value; 420,000 shares issued and outstanding at December 31, 2005 and 2004 (at liquidation value of $420, net of issuance costs)	 	 	406	 	 	 	406	 	
Common stock; $.01 par value; 100,048,676 and 100,041,935 shares issued and 80,701,888 and 87,041,935 outstanding at December 31, 2005 and 2004, respectively	 	 	1	 	 	 	1	 	
Additional paid-in capital	 	 	2,431	 	 	 	2,417	 	
Retained earnings	 	 	261	 	 	 	197	 	
Less treasury stock, at cost; 19,346,788 and 13,000,000 shares as of December 31, 2005 and 2004, respectively	 	 	(663	)	 	 	(405	)	
Accumulated other comprehensive income/(loss)	 	 	(205	)	 	 	76	 	
 	 	 	 	 	 	 	
 	 	Total stockholders’ equity	 	 	2,231	 	 	 	2,692	 	
 	 	 	 	 	 	 	
Total Liabilities and Stockholders’ Equity	 	$	7,431	 	 	$	7,864	 	
 	 	 	 	 	 	 	
See notes to consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY/(DEFICIT)
AND COMPREHENSIVE INCOME/(LOSS)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	Accumulated	 	 	Total	 	
 	 	Serial Preferred	 	 	Common	 	 	Additional	 	 	Retained	 	 	 	 	Other	 	 	Stockholders’	 	
 	 	 	 	 	 	 	 	Paid-In	 	 	Earnings/	 	 	Treasury	 	 	Comprehensive	 	 	Equity/	 	
 	 	Stock	 	 	Shares	 	 	Stock	 	 	Shares	 	 	Capital	 	 	(Deficit)	 	 	Stock	 	 	Income/(Loss)	 	 	(Deficit)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Balances at December 31, 2002 (Predecessor Company)	 	$	—	 	 	 	—	 	 	$	—	 	 	 	—	 	 	$	2,228	 	 	$	(2,829	)	 	$	—	 	 	$	(95	)	 	$	(696	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	2,766	 	 	 	 	 	 	 	 	 	 	 	2,766	 	
 	Foreign currency translation adjustments and other	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	128	 	 	 	128	 	
 	Deferred unrealized loss on derivatives, net	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(32	)	 	 	(32	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Comprehensive income for the period from January 1, 2003 through December 5, 2003	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	2,862	 	
 	Effects of reorganization	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(2,228	)	 	 	63	 	 	 	 	 	 	 	(1	)	 	 	(2,166	)	
 	Issuance of common stock	 	 	 	 	 	 	 	 	 	 	1	 	 	 	100	 	 	 	2,403	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	2,404	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balances at December 5, 2003 (Predecessor Company)	 	$	—	 	 	 	—	 	 	$	1	 	 	 	100	 	 	$	2,403	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	2,404	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	11	 	 	 	 	 	 	 	 	 	 	 	11	 	
 	Foreign currency translation adjustments and other	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	23	 	 	 	23	 	
 	Deferred unrealized loss on derivatives, net	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(1	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Comprehensive income for the period from December 6, 2003 through December 31, 2003	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	33	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balances at December 31, 2003 (Reorganized NRG)	 	$	—	 	 	 	—	 	 	$	1	 	 	 	100	 	 	$	2,403	 	 	$	11	 	 	$	—	 	 	$	22	 	 	$	2,437	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	186	 	 	 	 	 	 	 	 	 	 	 	186	 	
 	Foreign currency translation adjustments and other	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	46	 	 	 	46	 	
 	Deferred unrealized gain on derivatives, net	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	8	 	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Comprehensive income for 2004	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	240	 	
 	Equity based compensation	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	14	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	14	 	
 	Issuance of preferred stock	 	 	406	 	 	 	0.4	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	406	 	
 	Purchase of treasury stock	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(13	)	 	 	 	 	 	 	 	 	 	 	(405	)	 	 	 	 	 	 	(405	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balances at December 31, 2004 (Reorganized NRG)	 	$	406	 	 	 	0.4	 	 	$	1	 	 	 	87	 	 	$	2,417	 	 	$	197	 	 	$	(405	)	 	$	76	 	 	$	2,692	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	84	 	 	 	 	 	 	 	 	 	 	 	84	 	
 	Foreign currency translation adjustments and other	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(72	)	 	 	(72	)	
 	Deferred unrealized loss on derivatives, net	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(203	)	 	 	(203	)	
 	Minimum pension liability, net of $3 tax	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(6	)	 	 	(6	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Comprehensive loss for 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(197	)	
 	Equity based compensation	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	14	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	14	 	
 	Preferred stock dividends	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(20	)	 	 	 	 	 	 	 	 	 	 	(20	)	
 	Purchase of treasury stock	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(6	)	 	 	 	 	 	 	 	 	 	 	(258	)	 	 	 	 	 	 	(258	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balances at December 31, 2005 (Reorganized NRG)	 	$	406	 	 	 	0.4	 	 	$	1	 	 	 	81	 	 	$	2,431	 	 	$	261	 	 	$	(663	)	 	$	(205	)	 	$	2,231	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See notes to consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	 	 	Predecessor Company	 	
 	 	 	 	 	 	 	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6, 2003	 	 	 	January 1, 2003	 	
 	 	December 31,	 	 	December 31,	 	 	Through	 	 	 	Through	 	
 	 	2005	 	 	2004	 	 	December 31, 2003	 	 	 	December 5, 2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net income	 	$	84	 	 	$	186	 	 	$	11	 	 	 	$	2,766	 	
 	 	Adjustments to reconcile net income to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Distributions in excess of (less than) equity earnings of unconsolidated affiliates	 	 	(8	)	 	 	(1	)	 	 	2	 	 	 	 	(41	)	
 	 	Depreciation and amortization	 	 	195	 	 	 	215	 	 	 	13	 	 	 	 	257	 	
 	 	Reserve for note and interest receivable	 	 	—	 	 	 	12	 	 	 	—	 	 	 	 	—	 	
 	 	Amortization of financing costs and debt discount/(premium)	 	 	22	 	 	 	28	 	 	 	2	 	 	 	 	18	 	
 	 	Write-off of deferred financing costs due to refinancings	 	 	(8	)	 	 	42	 	 	 	—	 	 	 	 	—	 	
 	 	Write downs and losses on sales of equity method investments	 	 	31	 	 	 	16	 	 	 	—	 	 	 	 	147	 	
 	 	Deferred income taxes and investment tax credits	 	 	2	 	 	 	57	 	 	 	(3	)	 	 	 	(2	)	
 	 	Unrealized (gains)/losses on derivatives	 	 	143	 	 	 	(74	)	 	 	4	 	 	 	 	(35	)	
 	 	Minority interest	 	 	1	 	 	 	1	 	 	 	—	 	 	 	 	2	 	
 	 	Amortization of intangible assets	 	 	17	 	 	 	52	 	 	 	(13	)	 	 	 	—	 	
 	 	Amortization of unearned equity compensations	 	 	12	 	 	 	14	 	 	 	—	 	 	 	 	—	 	
 	 	Restructuring and impairment charges	 	 	6	 	 	 	45	 	 	 	—	 	 	 	 	408	 	
 	 	Fresh start reporting adjustments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	(3,895	)	
 	 	Loss on sale and disposal of assets	 	 	4	 	 	 	1	 	 	 	—	 	 	 	 	—	 	
 	 	Gain on sale of discontinued operations	 	 	(6	)	 	 	(23	)	 	 	—	 	 	 	 	(186	)	
 	 	Gain on TermoRio settlement	 	 	(14	)	 	 	—	 	 	 	—	 	 	 	 	—	 	
 	 	Collateral deposit payments in support of energy risk management activities	 	 	(405	)	 	 	(7	)	 	 	(8	)	 	 	 	—	 	
 	 	Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Accounts receivable, net	 	 	(8	)	 	 	(52	)	 	 	18	 	 	 	 	28	 	
 	 	Xcel Energy settlement receivable	 	 	—	 	 	 	640	 	 	 	—	 	 	 	 	—	 	
 	 	Inventory	 	 	(14	)	 	 	(56	)	 	 	11	 	 	 	 	14	 	
 	 	Prepayments and other current assets	 	 	(35	)	 	 	126	 	 	 	(71	)	 	 	 	(37	)	
 	 	Accounts payable	 	 	57	 	 	 	50	 	 	 	(40	)	 	 	 	649	 	
 	 	Accrued expenses	 	 	(8	)	 	 	(21	)	 	 	(67	)	 	 	 	217	 	
 	 	Creditor pool obligation payments	 	 	—	 	 	 	(540	)	 	 	—	 	 	 	 	—	 	
 	 	Other current liabilities	 	 	(8	)	 	 	(106	)	 	 	(441	)	 	 	 	(23	)	
 	 	Other assets and liabilities	 	 	8	 	 	 	40	 	 	 	(7	)	 	 	 	(49	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Operating Activities	 	 	68	 	 	 	645	 	 	 	(589	)	 	 	 	238	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Proceeds from sale of discontinued operations	 	 	36	 	 	 	253	 	 	 	—	 	 	 	 	19	 	
 	Proceeds from sale of investments	 	 	70	 	 	 	51	 	 	 	—	 	 	 	 	107	 	
 	Proceeds from sale of turbines and other property, plant and equipment	 	 	9	 	 	 	4	 	 	 	—	 	 	 	 	71	 	
 	Decrease/(increase) in restricted cash and trust funds	 	 	45	 	 	 	(27	)	 	 	375	 	 	 	 	(266	)	
 	Decrease/(increase) in notes receivable	 	 	107	 	 	 	25	 	 	 	1	 	 	 	 	(2	)	
 	Deferred acquisition costs	 	 	(5	)	 	 	—	 	 	 	—	 	 	 	 	—	 	
 	Capital expenditures	 	 	(106	)	 	 	(119	)	 	 	(11	)	 	 	 	(114	)	
 	Return of capital/(Investments) in projects	 	 	2	 	 	 	(3	)	 	 	(2	)	 	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Investing Activities	 	 	158	 	 	 	184	 	 	 	363	 	 	 	 	(186	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Payment of dividends to preferred shareholders	 	 	(20	)	 	 	—	 	 	 	—	 	 	 	 	—	 	
 	Repayment of minority interest obligations	 	 	(4	)	 	 	—	 	 	 	—	 	 	 	 	—	 	
 	Accelerated share repurchase payment, net	 	 	(250	)	 	 	—	 	 	 	—	 	 	 	 	—	 	
 	Purchase of treasury stock	 	 	—	 	 	 	(405	)	 	 	—	 	 	 	 	—	 	
 	Issuance of 4% Preferred Stock, net	 	 	—	 	 	 	406	 	 	 	—	 	 	 	 	—	 	
 	Issuance of 3.625% Preferred Stock, net	 	 	246	 	 	 	—	 	 	 	—	 	 	 	 	—	 	
 	Proceeds from issuance of long-term debt, net	 	 	249	 	 	 	1,333	 	 	 	2,450	 	 	 	 	40	 	
 	Deferred debt issuance costs	 	 	(46	)	 	 	(26	)	 	 	(75	)	 	 	 	(19	)	
 	Funded letter of credit	 	 	—	 	 	 	(100	)	 	 	(250	)	 	 	 	—	 	
 	Principal payments on short and long-term debt	 	 	(1,005	)	 	 	(1,492	)	 	 	(1,732	)	 	 	 	(51	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Financing Activities	 	 	(830	)	 	 	(284	)	 	 	393	 	 	 	 	(30	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	(2	)	 	 	3	 	 	 	(14	)	 	 	 	(22	)	
Change in Cash from Discontinued Operations	 	 	8	 	 	 	6	 	 	 	1	 	 	 	 	35	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Increase/(Decrease) in Cash and Cash Equivalents	 	 	(598	)	 	 	554	 	 	 	154	 	 	 	 	35	 	
Cash and Cash Equivalents at Beginning of Period	 	 	1,104	 	 	 	550	 	 	 	396	 	 	 	 	361	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and Cash Equivalents at End of Period	 	$	506	 	 	$	1,104	 	 	$	550	 	 	 	$	396	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See notes to consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 	 	
Note 1 —	Organization	

 	General	
      We are a leading wholesale power generation company with a significant presence in many of the major competitive power markets in the United States. We are primarily engaged in the ownership and operation of power generation facilities, purchasing fuel and transportation services to support our power plant operations, and the marketing and trading of energy, capacity and related products in the competitive markets in which we operate.
      Our facilities consist primarily of baseload, intermediate and peaking power generation facilities, and also include thermal energy production and energy resource recovery plants. The sale of capacity and power from baseload generation facilities accounts for the majority of our revenues and provides a stable source of cash flow. In addition, our diverse generation portfolio provides us with opportunities to capture additional revenues by selling power into our core regions during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.
      On February 2, 2006, NRG completed the acquisition of Texas Genco, or the Acquisition. The purchase price of approximately $6.1 billion consisted of approximately $4.4 billion in cash and the issuance of approximately 35.4 million shares of NRG’s common stock valued at $1.7 billion. This amount is subject to adjustment due to acquisition costs. The value of our common stock issued to the former direct and indirect owners of Texas Genco, or the Sellers, was based on our average stock price immediately before and after the closing date of February 2, 2006. The Acquisition includes the assumption of approximately $2.7 billion of Texas Genco debt. Texas Genco is now a wholly-owned subsidiary of NRG, and will be managed and accounted for as a new business segment to be referred to as NRG Texas.
      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. In 2002, a number of factors including 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.
      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 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.
      We were incorporated as a Delaware corporation on May 29, 1992. Our common stock is 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.
 	 	
Note 2 —	Summary of Significant Accounting Policies	
     Nature of Operations
      We are a wholesale power generation company, primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States and internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type, and dispatch levels, which help mitigate risk. We seek to maximize operating income through the efficient

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procurement and management of fuel supplies and maintenance services, and the sale of energy, capacity and ancillary services into attractive spot, intermediate and long-term markets.
 	 	
 	Principles of Consolidation and Basis of Presentation	
      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 SOP 90-7.
      For financial reporting purposes, close of business on December 5, 2003, represents the date of our emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:
 	 	 	
“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, December 6, 2003-December 31, 2005	
      In January 2003, the FASB issued FIN 46 which requires an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling interest. In December 2003, the FASB published a revision to Interpretation 46, or FIN 46R, to clarify some of the provisions of FIN 46 and to exempt certain entities from its requirements. As required by SOP 90-7, we adopted FIN 46R as of the adoption of Fresh Start and consequently we have consolidated operations of hydropower facilities on the East Coast, Northbrook New York and Northbrook Energy. These operations have been sold during 2005 and classified as discontinued operations. Also see Note 6 for further discussion.
      The consolidated financial statements include our accounts and operations and those of our subsidiaries in which we have a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America. As discussed in Note 13, we have investments in partnerships, joint ventures and projects.
 	 	
 	Fresh Start Reporting	
      In accordance with SOP 90-7, certain companies qualify for fresh start reporting in connection with their emergence from bankruptcy. Fresh start reporting is appropriate on the emergence from chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. We met these requirements and adopted Fresh Start reporting resulting in the creation of a new reporting entity designated as Reorganized NRG.
      The bankruptcy court issued a confirmation order approving our plan of reorganization on November 24, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. Our plan of reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. The Xcel Energy settlement agreement was entered into on December 5, 2003. We believe this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.
      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 a negative reorganization value that was reallocated back to our tangible and intangible assets. Deferred taxes were determined in accordance with SFAS 109. The

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net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion (comprised of a $4.2 billion gain from continuing operations and a $0.3 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 our reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from our core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, or DCF, valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the bankruptcy 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 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 statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s statement of operations and statement of cash flows and are therefore not comparable to these statements prior to the application of Fresh Start.
 	 	
 	Cash and Cash Equivalents	
      Cash and cash equivalents include highly liquid investments (primarily commercial paper and money market accounts) with an original maturity of three months or less at the time of purchase.
 	 	
 	Restricted Cash	
      Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within our projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments, per the restrictions of the debt agreements.

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 	Inventory	
      Inventory is valued at the lower of weighted average cost or market and consists principally of fuel oil, coal, emission allowances and raw materials used to generate steam. Spare parts inventory is valued at weighted average cost, as we expect to recover these costs in the ordinary course of business. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.
 	 	
 	Property, Plant and Equipment	
      Property, plant and equipment are stated at cost however impairment adjustments are recorded whenever events or changes in circumstances indicate carrying values may not be recoverable. On December 5, 2003, we recorded adjustments to the property, plant and equipment to reflect such items at fair value in accordance with Fresh Start reporting. A new cost basis was established with these adjustments. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation will be computed using the straight-line method over the following estimated useful lives:
 	 	 	
Facilities and equipment	 	1-42 years	
Office furnishings and equipment	 	2-10 years	
      The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in operations.
 	 	
 	Asset Impairments	
      Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with SFAS 144. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value and included in operating costs and expenses in the statement of operations. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.
      Investments accounted for by the equity method are reviewed for impairment in accordance with APB 18 which requires that a loss in value of an investment that is other than a temporary decline should be recognized. We identify and measure losses in value of equity investments based upon a comparison of fair value to carrying value.
 	 	
 	Discontinued Operations	
      Long-lived assets are classified as discontinued operations when all of the required criteria specified in SFAS 144 are met. These criteria include, among others, existence of a qualified plan to dispose of an asset, an assessment that completion of a sale within one year is probable and approval of the appropriate level of management. Discontinued operations are reported at the lower of the asset’s carrying amount or fair value less cost to sell.
 	 	
 	Capitalized Interest	
      Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the asset under construction is ready for its intended use or when a project is terminated or construction ceased. Capitalized interest was approximately $0.2 million, $3 million, $1 million, and $5 million for the years ended December 31, 2005 and

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December 31, 2004, and the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, respectively.
 	 	
 	Capitalized Project Costs	
      Development costs and capitalized project costs include third party professional services, permits, and other costs that are incurred incidental to a particular project. Such costs are expensed as incurred until an acquisition agreement or letter of intent is signed, and our Board of Directors has approved the project. Additional costs incurred after this point are capitalized. When a project begins operations, previously capitalized project costs are reclassified to equity investments in affiliates or property, plant and equipment and amortized on a straight-line basis over the lesser of the life of the project’s related assets or revenue contract period. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
 	 	
 	Debt Issuance Costs	
      Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the terms of the related debt.
 	 	
 	Intangible Assets	
      Intangible assets represent contractual rights held by us. Intangible assets are amortized over their economic useful life and reviewed for impairment on a periodic basis.
 	 	
 	Income Taxes	
      The Reorganized NRG’s income tax provision for the years ended December 31, 2005 and December 31, 2004, and for the period December 6, 2003 through December 31, 2003 has been recorded on the basis that we and our U.S. subsidiaries reconsolidated for federal income tax purposes as of December 6, 2003. The Reorganized NRG is no longer owned by Xcel Energy and thus, no longer included in the Xcel Energy affiliated group. The change in ownership allows us to file a consolidated federal income tax return with our U.S. subsidiaries starting on December 6, 2003.
      The Predecessor Company’s income tax provision has been recorded on the basis that Xcel Energy has not included us in its consolidated federal income tax return following Xcel Energy’s acquisition of our public shares on June 3, 2002. Since we and our U.S. subsidiaries will not be included in the Xcel Energy’s 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 for the period ended December 5, 2003.
      Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year-end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.
 	 	
 	Revenue Recognition	
      We are primarily an electric generation company, operating a portfolio of majority-owned electric generating plants and certain plants in which our ownership interest is 50% or less which are accounted for under the equity method of accounting. In connection with our electric generation business, we also produce thermal energy for sale to customers, principally through steam and chilled water facilities. We also collect

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methane gas from landfill sites, which are used for the generation of electricity. In addition, we sell small amounts of natural gas and oil to third parties.
      Energy. 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. We record gross revenues in regions where bilateral markets exist and physical delivery of electricity is common from our plants under the accrual method. In certain markets, which are operated and/or controlled by an ISO 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 from an ISO and not sourced from our facilities are reported net.
      Capacity. Capacity and ancillary revenue is recognized when contractually earned, and 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. We provide contract operations and maintenance services to some of our non-consolidated affiliates. Revenue is recognized as contract services are performed.
      Revenue from Sales of Emission Allowances. During 2005, we began selling our excess SO2 emission allowances. We record the sale of these allowances in Operating Revenues. The cost basis of these allowances, established upon the adoption of Fresh Start, is recorded in Operating Costs and Expenses. Beginning in 2006, we will actively manage our SO 2  emission allowances as well as fuels, and we will account for such asset optimization activity related to emission allowances and other fuel commodities under EITF 02-3,  “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.”  As such, revenues and costs for the asset and optimization activities would be reflected on a net basis in the consolidated statement of operations.
      Contract Amortization. At Fresh Start we recognized liabilities for power sales agreements related to the sale of electric capacity and energy in future periods where the fair value was determined to be significantly out of market as compared to market expectations. The liability is being amortized as an increase to revenue over the term of each underlying contract based on actual generation. The carrying amount of the unfavorable out-of-market power sales agreements at December 31, 2005 and 2004 was $298 million and $319 million, respectively. The estimated annual amortization of the out-of-market power sales agreements for each of the five succeeding years is expected to approximate $37 million in 2006, $28 million in 2007, $24 million in 2008, $24 million in 2009 and $20 million for 2010.
      Disputed Revenues. Disputed revenues are not recorded in the financial statements until disputes are effectively resolved and collection is reasonably assured.
 	 	
 	Derivative Financial Instruments	
      In January 2001, we adopted SFAS 133, as amended by SFAS 137, SFAS 138 and SFAS 149. SFAS 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,

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until the hedged transactions occur and are recognized in earnings. We primarily account for derivatives under SFAS 133, as amended, for 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 133, as amended, also applies to interest rate swaps and foreign currency exchange rate contracts. The application of SFAS 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.
 	 	
 	Foreign Currency Translation and Transaction Gains and Losses	
      The local currencies are generally the functional currency of our foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses and cash flows are translated at weighted-average rates of exchange for the period. The resulting currency translation adjustments are accumulated and reported as a separate component of stockholders’ equity and are not included in the determination of the results of operations. Foreign currency transaction gains or losses are reported in results of operations. We recognized foreign currency transaction gains (losses) of $(1) million, $2 million, $0.4 million, and $(20) million for the years ended December 31, 2005, December 31, 2004, and the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, respectively.
 	 	
 	Concentrations of Credit Risk	
      Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of cash, trust funds, accounts receivable, notes receivable and investments in debt securities. Cash accounts and trust funds are generally held in federally insured banks. Accounts receivable, notes receivable and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, we believe the credit risk posed by industry concentration is offset by the diversification and creditworthiness of our customer base.
 	 	
 	Fair Value of Financial Instruments	
      The carrying amount of cash and cash equivalents, trust funds, receivables, accounts payables, and accrued liabilities approximate fair value because of the short maturity of these instruments. The carrying amounts of long-term receivables usually approximate fair value, as the effective rates for these instruments are comparable to market rates at year-end, including current portions. Any differences are disclosed in Note 5. The fair value of long-term debt is estimated based on quoted market prices for those instruments which are traded or on a present value method using current interest rates for similar instruments with equivalent credit quality.
 	 	
 	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.

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 	Stock Based Compensation	
      During the fourth quarter of 2003, in accordance with SFAS Statement No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure”  we adopted SFAS 123 under the prospective transition method which requires the application of the recognition provisions to all employee awards granted, modified, or settled after the beginning of the fiscal year in which the recognition provisions are first applied. As a result, we applied the fair value recognition provisions of SFAS 123 as of January 1, 2003. We recognize compensation expense on a graded vesting basis for non-qualified stock option grants issued under the Long-Term Incentive Plan. The Black-Scholes option-pricing model is used for all non-qualified stock options. We recognize compensation expense on a straight-line basis over the applicable vesting period for restricted stock units (RSUs) and performance units (PUs). We use our common stock price on the date of grant as the fair value of the RSUs, while the fair value of the PU’s is estimated on the date of grant using the Monte Carlo valuation model. In January 2006, we will adopt SFAS 123(R) under a modified version of prospective application as discussed below in  Recent Accounting Pronouncements.
 	 	
 	Use of Estimates	
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
      In recording transactions and balances resulting from business operations, we use estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, and the valuation of long-term energy commodities contracts and environmental liabilities, and legal costs incurred in connection with recorded loss contingencies, among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
 	 	
 	Reclassifications	
      Certain prior-year amounts have been reclassified for comparative purposes. These reclassifications had no effect on our net income or total stockholders’ equity as previously reported.
 	 	
 	Recent Accounting Developments	
      During the period, the FASB issued FIN 47 to clarify the term “conditional asset retirement obligation” as used in SFAS 143 governing the application of Asset Retirement Obligations. SFAS 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional but there may remain some uncertainty as to the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred — generally upon acquisition, construction, or development and/or through the normal operation of the asset. SFAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 clarifies when the company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is

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effective for fiscal years ending after December 15, 2005. This guidance does not materially affect our consolidated financial position, results of operations or statement of cash flows.
      Also during the period, the SEC issued Staff Accounting Bulletin 107, or SAB 107, which addresses the application of SFAS 123(R). SAB 107 was issued to assist registrants by simplifying some of the implementation challenges of SFAS 123(R) while enhancing the information that investors receive. SAB 107 creates a framework that is premised on two overarching themes — considerable judgment will be required by preparers to successfully implement SFAS 123(R), specifically when valuing employee stock options, and that reasonable individuals, acting in good faith, may conclude differently on the fair value of employee stock options. Accordingly, situations in which there is only one acceptable fair value estimate are expected to be rare. In addition, the SEC extended the adoption date to registrants for the implementation of SFAS 123(R) and SAB 107 so that they may implement this guidance for their fiscal year which begins after September 15, 2005. We will adopt SFAS 123(R) and SAB 107 on January 1, 2006 under a modified version of prospective application, or the modified prospective application. Under modified prospective application, we will apply the provisions of SFAS 123(R) to new awards and to awards modified, repurchased, or cancelled after the required effective date. In addition to applying a forfeiture rate to new awards, we are required to apply a forfeiture rate to existing awards and, if material, eliminate from balance sheet amounts and recognize in income as the cumulative effect of a change in accounting principle as of the required effective date. This guidance will not materially affect our consolidated financial position, results of operations or statement of cash flows.
      Subsequent to release of SFAS 123R, the FASB issued Staff Position No. FAS 123R-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards” , or FSP FAS 123R-3, on November 10, 2005. FSP FAS 123R-3 provides a one-time election related to the accounting for the tax benefits from share-based compensation cost since the adoption of FAS 123, and allows for purposes of calculating current tax expense, the aggregation of tax benefits recognized for share-based compensation in excess of financial statement tax benefits since adoption of FAS 123 in lieu of the award-by-award basis prescribed by SFAS 123R. We are currently evaluating the impact of this election, but do not expect this guidance to materially affect our consolidated financial position, results of operations or statement of cash flows.
      On March 17, 2005, the Emerging Issues Task Force, or EITF, issued EITF No. 04-6 “Accounting for Stripping Costs Incurred during Production in the Mining Industry” , or EITF 04-6. EITF 04-6 provides that costs incurred to remove overburden and waste material to access coal seams, or stripping costs, during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. EITF 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005. Our MIBRAG equity investment is a 50% interest in a mining company, which will be negatively affected by this pronouncement. Currently, MIBRAG has an asset totaling approximately € 157 million, approximately $185 million, representing the stripping costs incurred during production as of December 31, 2005. The adoption of EITF 04-6 will not have a material impact on our consolidated results of operations, but will have a material impact on our consolidated financial position. Following adoption on January 1, 2006, our investment in MIBRAG will be reduced by 50% of the above mentioned asset, approximately $93 million, with an offsetting charge to retained earnings.
      Also during the period, the FASB issued SFAS No. 154 “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3 , or SFAS 154. This Statement replaces APB Opinion No. 20, “Accounting Changes” , or APB 20, and FASB Statement No. 3,  “Reporting Accounting Changes in Interim Financial Statements” , and changes the requirements for the accounting for and reporting of a change in accounting principle. This Statement applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
transition provisions, those provisions should be followed. APB 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle for direct effects of the change, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change, and redefines restatement as the revising of previously issued financial statements to reflect the correction of an error. This Statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
      On July 12, 2005, the FASB issued Staff Position APB 18-1, “Accounting by an Investor for Its Proportionate Share of Accumulated Other Comprehensive Income of an Investee Accounted for under the Equity Method in Accordance with APB Opinion No. 18 upon a Loss of Significant Influence” , or FSP APB 18-1. This guidance clarifies the application of paragraph 121 of SFAS No. 130,  “Reporting Comprehensive Income” , or SFAS 130, and clarifies that the company’s proportionate share of an investee’s equity adjustments for OCI should be offset against the carrying value of the investment at the time significant influence is lost. To the extent that the offset results in a carrying value of the investment that is less than zero, an investor should (a) reduce the carrying value of the investment to zero and (b) record the remaining balance in income. The guidance in FSP APB 18-1 is effective as of the first reporting period after July 12, 2005. Currently, this guidance does not materially affect our consolidated financial position, results of operations or statement of cash flows.
      On June 29, 2005, the EITF issued EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” , or EITF 04-5. EITF 04-5 provides a framework for addressing when a general partner controls a limited partnership when the limited partners have certain rights. EITF 04-5’s scope excludes a number of investment types, including limited partnerships entities that are not variable interest entities under FIN 46R, and investments accounted for under the pro rata method of consolidation. The guidance in EITF 04-5 is effective immediately to general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified. For general partners in all other limited partnerships, the guidance in EITF 04-5 is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. Currently, this guidance will not materially affect our consolidated financial position, results of operations or statement of cash flows.
      On June 16, 2005, the EITF issued EITF Issue No. 05-5, “Accounting for Early Retirement or Postemployment Programs with Specific Features (Such As Terms Specified in Altersteilzeit Early Retirement Arrangements)” , or EITF 05-5. EITF 05-5 provides guidance on the accounting for early retirement or postemployment programs with specific features, and specifically the terms of Altersteilzeit early retirement arrangements. The Altersteilzeit (ATZ) arrangement is a voluntary early retirement program in Germany designed to create an incentive for employees, within a certain age group, to transition from employment into retirement before their legal retirement age. If certain criteria are met by the employer, the German government provides to the employer a subsidy for bonuses paid to the employee and the additional contributions paid by the employer into the German government pension scheme under an ATZ arrangement for a maximum of six years. The Task Force reached a consensus that the employer should recognize the government subsidy when it meets the necessary criteria and is entitled to the subsidy. The Task Force also reached a consensus that payments made by the employer relative to the bonus feature and the additional contributions into the German government pension scheme (collectively, the additional compensation) should be accounted for as a post-employment benefit under SFAS 112,  Employers’ Accounting for Post-employment Benefits , which prescribes than an entity should recognize the additional compensation over the period from the point at which the employee signs the ATZ contract until the end of the active service period. The guidance of EITF 05-5 is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. We are currently evaluating the impact of this election, but do not expect

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this guidance to materially affect our consolidated financial position, results of operations or statement of cash flows.
 	 	
Note 3 —	Emergence from Bankruptcy and Fresh Start Reporting	
      In accordance with the requirements of SOP 90-7, we determined the reorganization value of NRG and subsidiaries emerging from bankruptcy to be approximately $9.1 billion. Reorganization value generally approximates fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring. Several methods are used to determine the reorganization value; however, generally it is determined by discounting future cash flows for the reconstituted business that will emerge from chapter 11 bankruptcy. Our approach was consistent in that our independent financial advisor’s estimated reorganization enterprise value of our ongoing projects used a discounted cash flow approach.
      We allocated the reorganization value of $9.1 billion to our assets in conformity with the procedures specified by SFAS 141. We used a third party to complete an independent appraisal of our tangible assets, equity investments and intangible assets and contracts. In completing the fair value allocation our assets were calculated to be greater than the reorganization value. As a result, we reallocated the negative reorganization value to our tangible and intangible assets in accordance with SFAS 141. In preparing our balance sheet we also recorded each liability existing at the plan confirmation date, other than deferred taxes, at the present value of amounts to be paid determined at appropriate current interest rates. Deferred taxes were reported in conformity with generally accepted accounting principles under SFAS 109. Our equity was recorded at approximately $2.4 billion representing a price per share of $24.04 for the issuance of 100 million shares of common stock upon emergence from bankruptcy. We pushed down the effects of fresh start reporting to all of our subsidiaries.
      In constructing our Fresh Start balance sheet using our reorganization value upon our emergence from bankruptcy, we used a reorganization equity value of approximately $2.4 billion, as we believe this value to be the best indication of the value of the ownership distributed to the new equity owners. Accordingly, our reorganization value of $9.1 billion was determined by adding our reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and our other liabilities of $3.0 billion. This value is consistent with the voting creditors and Court’s approval of the Plan of Reorganization.
      The determination of the enterprise value and the allocations to the underlying assets and liabilities were based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.
      We recorded approximately $3.9 billion of net reorganization income (comprised of a $4.2 billion gain from continuing operations and a $0.3 billion loss from discontinued operations) in the Predecessor Company’s statement of operations for 2003, which includes the gain on the restructuring of debt and equity and the discharge of obligations subject to compromise for less than recorded amounts, as well as adjustments to the historical carrying values of our assets and liabilities to fair market value.
      Due to the adoption of Fresh Start as of December 5, 2003, the Reorganized NRG 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

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the application of Fresh Start. The accompanying Consolidated Financial Statements have been prepared to distinguish between Reorganized NRG and the Predecessor Company.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Company	 	 	 	 	 	 	 	 	NRG	 	
 	 	December 5,	 	 	Debt Discharge and	 	 	Fresh Start	 	 	 	 	December 6,	 	
 	 	2003	 	 	Exchange of Stock	 	 	Adjustments	 	 	Consolidation	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Current Assets	 	$	1,718	 	 	$	614	 	 	$	4	 	 	$	6	 	 	$	2,342	 	
Non-current Assets	 	 	8,172	 	 	 	(155	)	 	 	(1,233	)	 	 	41	 	 	 	6,825	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	9,890	 	 	$	459	 	 	$	(1,229	)	 	$	47	 	 	$	9,167	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	2,190	 	 	 	999	 	 	 	1,187	 	 	 	1	 	 	 	4,377	 	
Non-current Liabilities	 	 	9,458	 	 	 	(6,270	)	 	 	(848	)	 	 	46	 	 	 	2,386	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Liabilities	 	 	11,648	 	 	 	(5,271	)	 	 	339	 	 	 	47	 	 	 	6,763	 	
Stockholders Equity	 	 	(1,758	)	 	 	2,404	 	 	 	1,758	 	 	 	—	 	 	 	2,404	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Liabilities and Stockholders Equity	 	$	9,890	 	 	$	(2,867	)	 	$	2,097	 	 	$	47	 	 	$	9,167	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      APB 18 requires us to effectively push down the effects of Fresh Start reporting to our unconsolidated equity method investments and to recognize an adjustment to our share of the earnings or losses of an investee as if the investee was a consolidated subsidiary. As a result of pushing down the impact of Fresh Start to our West Coast Power affiliate we determined that a contract based intangible asset with a one year remaining life, consisting of the value of West Coast Power’s California Department of Water Resources energy sales contract, must be established and recognized as a basis adjustment to our share of the future earnings generated by West Coast Power. This adjustment reduced our equity earnings in the amount of approximately $10 million per month during 2004 until the contract expired in December 2004.
 	 	
Note 4 —	Debtors’ Statements	
      As stated above, we and certain of our subsidiaries filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code during 2003. On December 5, 2003, we and five of our subsidiaries emerged from bankruptcy. As of the respective bankruptcy filing dates, the debtors’ financial records were closed for the pre-petition period. As required by SOP 90-7, below are the condensed combined financial statements of our remaining debtors since the date of the bankruptcy filings, or the Debtors’ Statements.
      The Debtors’ Statements consist of the following wholly-owned consolidated entities which remained in bankruptcy as of December 6, 2003: Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Berrians I Gas Turbine Power, LLC, Big Cajun II Unit 4 LLC, Connecticut Jet Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Louisiana Generating LLC, LSP-Nelson Energy LLC, Middletown Power LLC, Montville Power LLC, Northeast Generation Holding LLC, Norwalk Power LLC, NRG Central US LLC, NRG Eastern LLC, NRG McClain LLC, NRG Nelson Energy LLC, NRG New Roads Holdings LLC, NRG Northeast Generating LLC, NRG South Central Generating LLC, Oswego Harbor Power LLC, Somerset Power LLC, and South Central Generation Holding LLC. As of December 31, 2005, there were no entities remaining in bankruptcy.

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Debtors’ Condensed Combined Statement of Operations
 	 	 	 	 	 	
 	 	For the Period	 	
 	 	May 15, 2003 –	 	
 	 	December 5,	 	
 	 	2003	 	
 	 	 	 	
 	 	(In millions)	 	
Operating revenue	 	$	731	 	
Operating costs and expenses	 	 	(620	)	
Fresh start reporting adjustments — asset write-downs, net	 	 	(1,244	)	
Reorganization items	 	 	(27	)	
Restructuring and impairment charges	 	 	(23	)	
 	 	 	 	
 	Operating loss	 	 	(1,183	)	
Other expense	 	 	(161	)	
 	 	 	 	
 	Net loss	 	$	(1,344	)	
 	 	 	 	
Debtors’ Condensed Combined Statement of Cash Flows
 	 	 	 	 	
 	 	For the Period	 	
 	 	May 15, 2003	 	
 	 	December 5,	 	
 	 	2003	 	
 	 	 	 	
 	 	(In millions)	 	
Net cash provided by operating activities	 	$	66	 	
Net cash used by investing activities	 	 	(73	)	
Net cash used by financing activities	 	 	—	 	
 	 	 	—	 	
Net increase in cash and cash equivalents	 	 	(7	)	
Cash and cash equivalents at beginning of period	 	 	23	 	
 	 	 	 	
Cash and cash equivalents at end of period	 	$	16	 	

 	 	
Note 5 —	Financial Instruments	
      The estimated fair values of our recorded financial instruments are as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	December 31, 2005	 	 	December 31, 2004	 	
 	 	 	 	 	 	 	
 	 	Carrying	 	 	 	 	Carrying	 	 	 	
 	 	Amount	 	 	Fair Value	 	 	Amount	 	 	Fair Value	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(In millions)	 	 	 	
Cash and cash equivalents	 	$	506	 	 	$	506	 	 	$	1,104	 	 	$	1,104	 	
Restricted cash	 	 	64	 	 	 	64	 	 	 	110	 	 	 	110	 	
Trust fund investments	 	 	20	 	 	 	20	 	 	 	20	 	 	 	20	 	
Unfunded letters of credit and surety bonds	 	 	—	 	 	 	13	 	 	 	—	 	 	 	21	 	
Notes receivable, including current portion	 	 	483	 	 	 	494	 	 	 	649	 	 	 	662	 	
Long-term debt, including current portion	 	 	2,682	 	 	 	2,809	 	 	 	3,484	 	 	 	3,624	 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. Trust funds investments are comprised of various U.S. debt securities carried at fair market value. Unfunded letters of credit and surety bonds are off balance sheet and are short term by nature. Because of their short-term characteristics, their balance approximates fair value.
      The fair value of notes receivable is based on expected future cash flows discounted at market interest rates. The fair value of long-term debt is estimated based on quoted market prices for those instruments which are traded or on a present value method using current interest rates for similar instruments with equivalent credit quality.
 	 	
Note 6 —	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. The financial results for all of these businesses have been accounted for as discontinued operations. Accordingly, current period operating results and prior periods have been restated to report the operations as discontinued. We have also classified certain assets as held for sale as management has committed to selling certain long lived assets within the next year. This classification does not affect prior period operating results.
      SFAS 144 requires that discontinued operations be valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions our management considered cash flow analyses, bids and offers related to those assets and businesses. This amount is included in income/(loss) on discontinued operations, net of income taxes in the accompanying Statement of Operations. In accordance with the provisions of SFAS 144, assets held for sale will not be depreciated commencing with their classification as such.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The assets and liabilities of the discontinued operations are reported in the December 31, 2005 and 2004 balance sheets as discontinued operations. The major classes of assets and liabilities are presented by geographic area in the following table.
 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
 	 	Wholesale	 	 	Wholesale	 	
 	 	Power	 	 	Power	 	
 	 	Generation	 	 	Generation	 	
 	 	 	 	 	 	 	
 	 	Other	 	 	Other	 	
 	 	North	 	 	North	 	
 	 	America	 	 	America	 	
 	 	 	 	 	 	 	
 	 	 	 	Consists of	 	
 	 	 	 	McClain,	 	
 	 	 	 	Northbrook	 	
 	 	 	 	New York,	 	
 	 	 	 	Northbrook	 	
 	 	Consists of	 	 	Energy and	 	
 	 	Audrain	 	 	Audrain	 	
 	 	 	 	 	 	 	
 	 	(In millions)	 	
Cash and cash equivalents	 	$	—	 	 	$	8	 	
Restricted cash	 	 	—	 	 	 	5	 	
Receivables, net	 	 	—	 	 	 	2	 	
Inventory	 	 	1	 	 	 	1	 	
Other current assets	 	 	—	 	 	 	1	 	
 	 	 	—	 	 	 	—	 	
Current assets — discontinued operations	 	 	1	 	 	 	17	 	
Property, plant and equipment, net	 	 	114	 	 	 	217	 	
Notes Receivable	 	 	240	 	 	 	240	 	
 	 	 	 	 	 	 	
Non-current assets — discontinued operations	 	 	354	 	 	 	457	 	
Current portion of long-term debt	 	 	—	 	 	 	1	 	
Accounts payable — trade	 	 	—	 	 	 	1	 	
Other current liabilities	 	 	115	 	 	 	171	 	
 	 	 	 	 	 	 	
Current liabilities — discontinued operations	 	 	115	 	 	 	173	 	
Long-term debt	 	 	240	 	 	 	281	 	
Minority interest	 	 	—	 	 	 	6	 	
Other non-current liabilities	 	 	—	 	 	 	1	 	
 	 	 	 	 	 	 	
Non-current liabilities — discontinued operations	 	 	240	 	 	 	288	 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The following table summarizes our discontinued operations for all periods presented in our consolidated financial statements:
 	 	 	 	 	 	 	
 	 	 	 	Initial Discontinued	 	 	
 	 	 	 	Operations	 	 	
Project	 	Segment	 	Treatment Date	 	Disposal Date	
 	 	 	 	 	 	 	
Killingholme	 	Other International	 	Fourth Quarter 2002	 	First Quarter 2003	
NLGI	 	Alternative Energy	 	Second Quarter 2003	 	Second Quarter 2003	
TERI	 	Non-Generation	 	Third Quarter 2003	 	Third Quarter 2003	
McClain	 	Other North America	 	Third Quarter 2003	 	Third Quarter 2004	
NEO Corporation (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC)	 	Alternative Energy	 	Fourth Quarter 2003	 	Fourth Quarter 2003	
Cahua and Energia Pacasmayo	 	Other International	 	Fourth Quarter 2003	 	Fourth Quarter 2003	
PERC	 	Other North America	 	First Quarter 2004	 	Second Quarter 2004	
Cobee	 	Other International	 	First Quarter 2004	 	Second Quarter 2004	
Hsin Yu	 	Other International	 	Second Quarter 2004	 	Second Quarter 2004	
LSP Energy (Batesville)	 	Other North America	 	Second Quarter 2004	 	Third Quarter 2004	
NEO Corporation (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha LLC and NEO Tajiguas LLC)	 	Alternative Energy	 	Third Quarter 2004	 	Third Quarter 2004	
Northbrook New York and Northbrook Energy	 	Other North America	 	Third Quarter 2005	 	Third Quarter 2005	
Audrain	 	Other North America	 	Fourth Quarter 2005	 	Second Quarter 2006	
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      Summarized results of operations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	
 	 	 	 	For the Period	 	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	 	January 1 -	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
Description	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operating revenues	 	$	15	 	 	$	122	 	 	$	20	 	 	 	$	263	 	
Operating costs and other expenses	 	 	13	 	 	 	119	 	 	 	20	 	 	 	 	753	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pre-tax income/(loss) from operations of discontinued components	 	 	2	 	 	 	3	 	 	 	—	 	 	 	 	(490	)	
Income tax expense/(benefit)	 	 	1	 	 	 	—	 	 	 	—	 	 	 	 	(22	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) from operations of discontinued components	 	 	1	 	 	 	3	 	 	 	—	 	 	 	 	(468	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Disposal of discontinued components — pre-tax gain (net)	 	 	13	 	 	 	30	 	 	 	—	 	 	 	 	152	 	
Income tax expense/(benefit)	 	 	7	 	 	 	8	 	 	 	—	 	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Disposal of discontinued components — gain (net)	 	 	6	 	 	 	22	 	 	 	—	 	 	 	 	152	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) on discontinued operations, net of income taxes	 	$	7	 	 	$	25	 	 	$	—	 	 	 	$	(316	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      Operating costs and other expenses for 2005 shown in the table above include the impairment of Audrain’s fixed assets and consequent reduction in the estimated liability by approximately $57 million, offsetting each other with no impact to Audrain’s results. Due to the sale of our Audrain facility to AmerenUE for $115 million, the fixed asset was impaired to its fair value. Based on the agreement with CSFB, CSFB will receive only $115 million, reducing the corresponding estimated liability.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Operating costs and other expenses for 2004 include asset impairment charges of approximately $0.2 million. Operating costs and other expenses for 2003 include asset impairment charges of approximately $226 million, comprised of approximately $101 million for McClain, $24 million for NLGI and $101 for Audrain. The pre-tax gain or loss on disposals of discontinued components consist of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Predecessor	 	
 	 	 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	For the Period	 	 	 	For the Period	 	
 	 	 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	 	January 1 -	 	
 	 	 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
Project	 	Segment	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(In millions)	 	
Northbrook Energy, Northbrook New York	 	Other North America	 	$	12	 	 	$	—	 	 	$	 —	 	 	 	$	—	 	
McClain	 	Other North America	 	 	—	 	 	 	(3	)	 	 	—	 	 	 	 	—	 	
PERC	 	Other North America	 	 	—	 	 	 	3	 	 	 	—	 	 	 	 	—	 	
Cobee	 	Other International	 	 	—	 	 	 	3	 	 	 	—	 	 	 	 	—	 	
LSP Energy — Batesville	 	Other North America	 	 	—	 	 	 	11	 	 	 	—	 	 	 	 	—	 	
Hsin Yu	 	Other International	 	 	—	 	 	 	10	 	 	 	—	 	 	 	 	—	 	
NEO Nashville, Hackensack, Prima Deshecha, Tajiguas	 	Alternative Energy	 	 	—	 	 	 	6	 	 	 	—	 	 	 	 	—	 	
Killingholme	 	Other International	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	191	 	
TERI	 	Non-Generation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	1	 	
Cahua and Energia Pacasmayo	 	Other International	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	(37	)	
Others	 	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	(3	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total gain on disposal of discontinued components — pre-tax	 	 	 	$	12	 	 	$	30	 	 	$	—	 	 	 	$	152	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      Audrain Generating LLC — On December 8, 2005 NRG entered into an Asset Purchase and Sale Agreement to sell all the assets of NRG Audrain Generating LLC, or Audrain, to AmerenUE, a subsidiary of Ameren Corporation. The purchase price is $115 million, subject to customary purchase price adjustments. The transaction is expected to close during the second quarter of 2006. The sale is subject to customary approvals, including Federal Energy Regulatory Commission, Missouri Public Utilities Commission, Illinois Commerce Commission, and Hart-Scott-Rodino review. We expect to record a gain of approximately $15 million at closing.
      Northbrook New York LLC and Northbrook Energy LLC — On August 11, 2005, we completed the sale of Northbrook New York LLC and Northbrook Energy LLC. In exchange for the sale, we received net cash proceeds of $36 million and paid off Northbrook New York LLC’s third party debt of $17 million. We recognized a net pre-tax gain of $12 million in the third quarter of 2005.
      McClain — We reviewed the recoverability of our McClain assets pursuant to SFAS No. 144 and recorded a charge of $101 million in the second quarter of 2003. On August 14, 2003, NRG’s Board of Directors approved a plan to sell its 77% interest in McClain Generating Station, a 520-MW combined-cycle, natural gas-fired facility located in New Castle, Oklahoma. On July 9, 2004, NRG McClain completed the sale of its 77% interest in the McClain Generating Station to Oklahoma Gas & Electric Company. The Oklahoma Municipal Power Authority will continue to own the remaining 23% interest in the facility. The proceeds of $160 million from the sale were used to repay outstanding project debt under the secured term

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loan and working capital facility. A loss of $3 million was recognized as of June 30, 2004 based upon the final terms of the sale.
      Penobscot Energy Recovery Company (PERC) — During the first quarter of 2004, we received board authorization to proceed with the sale of our interest in PERC to SET PERC Investment LLC which reached financial closing in April 2004. Upon completion of the transaction, we received net proceeds of $18 million, resulting in a gain of approximately $3 million.
      Cobee — During the first quarter of 2004, we entered into an agreement for the sale of our interest in our Cobee project to Globeleq Holdings Limited, which reached financial closing in April 2004. Upon completion of the transaction, we received net proceeds of approximately $50 million, resulting in a gain of $3 million.
      LSP Energy — Batesville — On August 24, 2004, we completed the sale of our 100 percent interest in an 837-megawatt generating plant in Batesville, Mississippi to CEP Batesville Acquisition, LLC. CEP Batesville Acquisition, LLC assumed approximately $300 million of outstanding project debt. The transaction resulted in the elimination of $289 million in consolidated debt from NRG Energy’s balance sheet. In exchange for the sale, we received cash proceeds of $28 million. We recorded a gain of $11 million in 2004.
      Hsin Yu — During the second quarter of 2004, we entered into an agreement for the sale of our interest in our Hsin Yu project to a minority interest shareholder, Asia Pacific Energy Development Company Ltd., which reached financial closing in May 2004. Completion of the transaction resulted in a gain of approximately $10 million, resulting from our negative equity in the project. In addition, although we have no continuing involvement in the project, we retained the prospect of receiving an additional $1 million in additional proceeds upon final closing of Phase II of the project.
      NEO Corporation — 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). During the third quarter of 2004, we completed the sale of four wholly-owned entities — NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha LLC and NEO Tajiguas LLC, as well as 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. Upon completion of the transaction, we received cash proceeds of $6 million, resulting in a $6 million gain associated with the four wholly-owned entities sold and received cash proceeds of $6 million resulting in a loss of approximately $4 million attributable to the equity investments sold. The sale of these equity investments do not qualify for reporting purposes as discontinued operations.
      Killingholme — In January 2003, we completed the sale of our interest in the Killingholme project to our lenders for a nominal value and forgiveness of outstanding debt with a carrying value of approximately $360 million at December 31, 2002. The sale of our interest in the Killingholme project and the release of debt obligations resulted in a gain on sale in the first quarter of 2003 of approximately $191 million. The gain results from the write-down of the project’s assets in the third quarter of 2002 below the carrying value of the related debt.
      NLGI — During the quarter ended March 31, 2003, we recorded impairment charges of $24 million related to subsidiaries of NLGI and a charge of $14 million to write off our 50% investment in Minnesota Methane, LLC. Through April 30, 2003, NRG Energy and NLGI failed to make certain payments causing a default under NLGI’s term loan agreements. In May 2003, the project lenders to the wholly-owned subsidiaries of NLGI and Minnesota Methane LLC foreclosed on our membership interest in the NLGI subsidiaries and our equity interest in Minnesota Methane LLC. There was no material gain or loss recognized as a result of the foreclosure.
      TERI — In September 2003, we completed the sale of TERI, a biomass waste-fuel power plant located in Florida and a wood processing facility located in Georgia, to DG Telogia Power, LLC. The sale resulted in

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net proceeds of approximately $1 million. We entered into an agreement to sell the wood processing facility on behalf of DG Telogia Power, LLC. This sale was completed during fourth quarter 2003 and we received cash consideration of approximately $1 million, resulting in a net gain on sale of approximately $1 million.
      Cahua and Energia Pacasmayo — In November 2003, we completed the sale of Cahua and Energia Pacasmayo resulting in net cash proceeds of approximately $16 million and a loss of $37 million. In addition, we received an additional consideration adjustment of approximately $1 million during 2004.
 	 	
Note 7 —	Write Downs and (Gains)/ Losses on Sales of Equity Method Investments	
      Investments accounted for by the equity method are reviewed for impairment in accordance with APB 18 which requires that a loss in value of an investment that is other than a temporary decline should be recognized. Gains or losses are recognized on completion of the sale. Write downs and (gains)/losses on sales of equity method investments recorded in other income/expense in the consolidated statement of operations includes the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Predecessor	 	
 	 	 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	For the Period	 	 	 	For the Period	 	
 	 	 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	 	January 1 -	 	
 	 	 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
 	 	Segment	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	(In millions)	 	 	 	 	
Saguaro	 	Western	 	$	27	 	 	$	—	 	 	$	 —	 	 	 	$	—	 	
Rocky Road	 	Other North America	 	 	20	 	 	 	—	 	 	 	—	 	 	 	 	—	 	
Kendall	 	Other North America	 	 	(4	)	 	 	—	 	 	 	—	 	 	 	 	—	 	
Enfield	 	Other International	 	 	(12	)	 	 	—	 	 	 	—	 	 	 	 	—	 	
Commonwealth Atlantic Limited Partnership	 	Other North America	 	 	—	 	 	 	5	 	 	 	—	 	 	 	 	—	 	
James River Power LLC	 	Other North America	 	 	—	 	 	 	7	 	 	 	—	 	 	 	 	—	 	
NEO Corporation	 	Alternative Energy	 	 	—	 	 	 	4	 	 	 	—	 	 	 	 	—	 	
Calpine Cogeneration	 	Other North America	 	 	—	 	 	 	(1	)	 	 	—	 	 	 	 	—	 	
NLGI — Minnesota Methane	 	Alternative Energy	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	12	 	
NLGI — MM Biogas	 	Alternative Energy	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	3	 	
ECKG	 	Other International	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	(3	)	
Loy Yang	 	Australia	 	 	—	 	 	 	1	 	 	 	—	 	 	 	 	146	 	
Mustang	 	Other North America	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	(12	)	
Other	 	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total write downs and losses on sales of equity method investments	 	 	 	$	31	 	 	$	16	 	 	$	—	 	 	 	$	147	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      Saguaro — During the fourth quarter of 2005, due to the expiration of its long-term gas supply contract and higher market prices paid for natural gas, NRG determined that a decline in the value of its 50% investment in Saguaro was considered to be permanent and recorded a write down of its investment of approximately $27 million.
      Rocky Road — In December 2005, NRG entered into a purchase and sale agreements (PSA) with Dynegy, Inc. whereby we have agreed to sell to Dynegy our 50% ownership interest in Rocky Road Power LLC for $45 million cash. As a result of the PSA with Dynegy, during December 2005, we recorded an

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impairment charge of approximately $20 million to write down the value of our 50% interest in Rocky Road to the fair value of $45 million.
      Kendall — In December 2004, we sold out interest in Kendall to LS Power Associates, L.P. or LS Power. Under the terms of the December 2004 agreement, we retained the right to acquire a 40% interest in the plant within a 10-year period for a nominal amount, or the Call Option. Therefore, the transaction was treated as a partial sale for accounting purposes. On August 8, 2005, we executed an agreement with LS Power to sell the Call Option for $5 million. A pre-tax gain of $4 million was recognized in the third quarter of 2005.
      Enfield — On April 1, 2005, we completed the sale of our 25% interest in Enfield to Infrastructure Alliance Limited. The sale resulted in net pre-tax proceeds of $65 million. A pre-tax gain of approximately $12 million was recorded in the second quarter of 2005.
      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 $4 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 $15 million. Total impairment charges as a result of the sale were approximately $5 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 at which time we recorded an impairment charge of approximately $6 million to write down the value of our investment in James River to its fair value. During the fourth quarter of 2004, the sales agreement was terminated. Total impairment charges for 2004 were approximately $7 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 Note 6). We received cash proceeds of approximately $6 million. The sale resulted in a loss of approximately $4 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 $3 million. During the second quarter of 2004, we received additional consideration on the sale of $1 million, resulting in an adjusted net gain of $1 million.
      NLGI — Minnesota Methane — . We recorded an impairment charge of $15 million during the first quarter of 2003. This charge was 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 million resulting in a net impairment charge of $12 million. The gain upon completion of the foreclosure resulted from the release of certain obligations upon completion of the foreclosure.
      NLGI — MM Biogas — In November 2003, we entered into a sales agreement with Cambrian Energy Development to sell our 50% interest in MM Biogas. We recorded an impairment charge of $3 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.
      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.

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The transaction closed in January 2003 and resulted in cash proceeds of $65 million and a net loss of less than $1 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 $4 million of additional consideration resulting in a net gain of approximately $3 million.
      Loy Yang — In May 2003, we entered into negotiations that culminated in the completion of a Share Purchase Agreement to sell 100% of the Loy Yang project. Consequently, we recorded an impairment charge of approximately $146 million during 2003. In April 2004 we completed the sale of Loy Yang which resulted in net cash proceeds of approximately $27 million and a loss of approximately $1 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 million and a net gain of approximately $12 million.
Note 8 — Other Charges (Credits)
      Other charges and credits included in operating expenses in the Consolidated Statement of Operations include the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	
 	 	 	 	For the Period	 	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	 	January 1 -	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(In millions)	 	 	 	 	
Corporate relocation charges	 	$	6	 	 	$	16	 	 	$	—	 	 	 	$	—	 	
Reorganization items	 	 	—	 	 	 	(13	)	 	 	2	 	 	 	 	198	 	
Impairment charges	 	 	6	 	 	 	45	 	 	 	—	 	 	 	 	229	 	
Restructuring charges	 	 	—	 	 	 	—	 	 	 	 —	 	 	 	 	8	 	
Fresh Start adjustments	 	 	—	 	 	 	—	 	 	 	 —	 	 	 	 	(4,220	)	
Legal settlement	 	 	—	 	 	 	—	 	 	 	 —	 	 	 	 	463	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total	 	$	12	 	 	$	48	 	 	$	2	 	 	 	$	(3,322	)	

 	 	
 	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. As of December 31, 2004, the transition of our corporate headquarters is substantially complete.
      For the years ended December 31, 2005 and 2004, we recorded $6 million and $16 million, respectively, for total charges of $22 million related to our corporate relocation activities, primarily for employee severance and termination benefits and employee related transition costs and lease abandonment 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” , or SFAS 146. All material expenses related to the corporate relocation have been incurred as of December 31, 2005. Lease termination costs require that cash payments in the amount of $2 million be made through the fourth quarter of 2006.

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      A summary of the SFAS 146-classified expenses is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended	 	 	Year Ended	 	 	 	 	 	
 	 	December 31,	 	 	December 31,	 	 	Yet to be	 	Expected	 	
 	 	2004	 	 	2005	 	 	Incurred	 	Total Charges	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(In millions)	 	 	
Employee related transition costs	 	$	9	 	 	$	2	 	 	$	—	 	 	$	11	 	
Severance and termination benefits	 	 	6	 	 	 	1	 	 	 	—	 	 	 	7	 	
Lease termination costs	 	 	1	 	 	 	3	 	 	 	—	 	 	 	4	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total corporate relocation charges	 	$	16	 	 	$	6	 	 	$	—	 	 	$	22	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
      A summary of the significant components of the restructuring liability is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Balance at	 	 	Relocation	 	 	 	 	Balance at	 	
 	 	December 31,	 	 	Related	 	 	Cash	 	 	December 31,	 	
 	 	2004	 	 	Charges	 	 	Payments	 	 	2005	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(In millions)	 	 	 	
Employee related transition costs	 	$	(1	)	 	$	2	 	 	$	(1	)	 	$	—	 	
Severance and termination benefits	 	 	4	 	 	 	1	 	 	 	(5	)	 	 	—	 	
Lease termination costs	 	 	1	 	 	 	3	 	 	 	(2	)	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total	 	$	4	 	 	$	6	 	 	$	(8	)	 	$	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
      As of December 31, 2005 and 2004, the net restructuring liability was approximately $2 million and $4 million, respectively, the majority of which is included in other current liabilities on the consolidated balance sheet. Charges related to the employee related transition costs, severance and termination benefits and lease termination costs are recorded at our corporate level within our All Other — Other segment, in the corporate relocation charges line on the consolidated statement of operations.
 	 	
 	Reorganization Items	
      For the year ended December 31, 2005 we did not record any reorganization item expense or income. For the year ended December 31, 2004, we recorded a net credit of approximately $13 million related primarily to the settlement of obligations recorded under Fresh Start. For the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, we incurred approximately $2 million and $198 million,

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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	 	Year Ended	 	 	December 6 -	 	 	 	January 1 -	 	
 	 	December 31,	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
 	 	2005	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(In millions)	 	 	 	 	
Reorganization items	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Professional fees	 	$	—	 	 	$	7	 	 	$	2	 	 	 	$	82	 	
 	Deferred financing costs	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	55	 	
 	Pre-payment settlement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	20	 	
 	Interest earned on accumulated cash	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	(1	)	
 	Contingent equity obligation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	42	 	
 	Settlement of obligations and other gains	 	 	—	 	 	 	(20	)	 	 	—	 	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total reorganization items	 	$	—	 	 	$	(13	)	 	$	2	 	 	 	$	198	 	

 	 	
 	Impairment Charges	
      We review the recoverability of our long-lived assets in accordance with the guidelines of SFAS 144. As a result of this review, we recorded impairment charges of approximately $6 million, $45 million and $229 million, for the years ended December 31, 2005 and 2004, and the period January 1, 2003 through December 5, 2003, respectively, as shown in the table below.
      To determine whether an asset was impaired, we compared asset-carrying values to total future estimated undiscounted cash flows. 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.

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      Impairment charges (credits) included the following asset impairments (realized gains) for the years ended December 31, 2005 and 2004, and the period January 1, 2003 to December 5, 2003. There were no impairment charges for the period December 6, 2003 to December 31, 2003.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	Predecessor	 	 	 	
 	 	 	 	 	 	 	Company	 	 	 	
 	 	 	 	Reorganized NRG	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	For the Period	 	 	 	
 	 	 	 	Year Ended	 	 	Year Ended	 	 	 	January 1 —	 	 	 	
 	 	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	 	 	
Project Name	 	Project Status	 	2005	 	 	2004	 	 	 	2003	 	 	Fair Value Basis	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(In millions)	 	 	 	
Berrians I Gas Turbine Power LLC	 	Non-operating asset	 	$	6	 	 	$	—	 	 	 	$	 —	 	 	Sales price	
Meriden (turbine only)	 	Pending sale	 	 	—	 	 	 	15	 	 	 	 	—	 	 	Sales price	
Kendall	 	Sold	 	 	—	 	 	 	27	 	 	 	 	—	 	 	Realized loss	
Louisiana Generating LLC	 	Office building and land being marketed	 	 	—	 	 	 	1	 	 	 	 	—	 	 	Estimated market price	
New Roads Holding LLC (turbine)	 	Non-operating asset — abandoned	 	 	—	 	 	 	2	 	 	 	 	—	 	 	Projected cash flows	
Devon Power LLC	 	Operating at a loss in 2003	 	 	—	 	 	 	—	 	 	 	 	64	 	 	Projected cash flows	
Middletown Power LLC	 	Operating at a loss Terminated	 	 	—	 	 	 	—	 	 	 	 	157	 	 	Projected cash flows	
Arthur Kill Power, LLC	 	construction project	 	 	—	 	 	 	—	 	 	 	 	9	 	 	Projected cash flows	
Langage (UK)	 	Terminated	 	 	—	 	 	 	—	 	 	 	 	(3	)	 	Estimated market price/Realized gain	
Turbines	 	Sold	 	 	—	 	 	 	—	 	 	 	 	(22	)	 	Realized gain	
Berrians Project	 	Terminated	 	 	—	 	 	 	—	 	 	 	 	14	 	 	Realized loss	
TermoRio	 	Terminated	 	 	—	 	 	 	—	 	 	 	 	7	 	 	Realized loss	
Other	 	 	 	 	—	 	 	 	—	 	 	 	 	3	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total impairment charges	 	 	 	$	6	 	 	$	45	 	 	 	$	229	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      Berrians I Gas Turbine Power LLC — During 2005, we determined that an unused turbine previously acquired for a now canceled project would be placed for sale. A letter of intent was entered into for the sale which resulted in an impairment of approximately $6 million, and the sale closed during the first quarter of 2006. Berrians is included within our Other North America segment. The balance of the Berrians turbine is classified as a current asset held for sale on the balance sheet as of December 31, 2005, totaling $8 million.
      Meriden — During the third quarter of 2004, we entered into a purchase and sale agreement to sell unused turbines. As a result, we recorded an impairment charge of $15 million. The sale is expected to close in the first half of 2006. Meriden is included in our All Other segment under the Other category. The balance of the Meriden turbines are classified as current assets held for sale on the balance sheet as of December 31, 2005, totaling $35 million.
      Kendall — In September 2004, we executed an agreement to sell our 1,160 MW generating plant in Minooka, Illinois to an affiliate of LS Power Associates, L.P and recorded a charge of approximately $25 million related to the impairment to realizable value. Under the terms of the agreement, we have the right to acquire a 40% interest in the plant within a 10-year period for a nominal amount. Therefore, the transaction was treated as a partial sale for accounting purposes. In December 2004 we completed the sale and received net proceeds of $1 million, resulting in a loss on sale of approximately $2 million and a total loss of approximately $27 million. Kendall is included in our Other North America segment.
      Louisiana Generating LLC — In January 2004, we closed the South Central regional office in Baton Rouge, Louisiana and offered it for sale. During the fourth quarter of 2004, we recorded a charge of

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approximately $1 million related to the impairment to net realizable value based on two offers received. The sale was finalized during the third quarter of 2005. Louisiana Generating is included in our South Central segment.
      New Roads Holding LLC — During the second quarter of 2004, we reviewed the recoverability of our New Roads assets pursuant to SFAS No. 144 and recorded a charge of approximately $1 million related to the impairment to realizable value of a turbine acquired in March 2000 from Cajun Electric. During the third quarter of 2004, we recorded an additional charge of approximately $1 million to write the turbine’s value down to its scrap value. New Roads Holding is included in our South Central segment.
      Connecticut Facilities (Devon Power LLC and Middletown Power LLC) — As a result of regulatory developments and changing circumstances in the second quarter of 2003, we updated the facilities’ cash flow models to incorporate changes to reflect the impact of the April 25, 2003 FERC’s orders on regional and locational pricing, and to update the estimated impact of future locational capacity or deliverability requirements. Based on these revised cash flow models, management determined that the new estimates of pricing and cost recovery levels were not projected to return sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown Power LLC. As a consequence, during the second quarter of 2003 we recorded approximately $64 million and $157 million as impairment charges for Devon Power LLC and Middletown Power LLC, respectively. In the third quarter of 2004, ISO-NE informed the Company that it would not extend the RMR contract for Devon units 7 and 8. As a result, both units have been placed on deactivated reserve. Devon Power and Middletown Power are included in our Northeast segment.
      Arthur Kill Power, LLC — During the third quarter of 2003, we cancelled our plans to re-establish fuel oil capacity at our Arthur Kill plant. This resulted in a charge of approximately $9.0 million to write-off assets under development. Arthur Kill Power is included in our Northeast segment.
      Langage (UK) — In August 2003 we closed on the sale of Langage to Carlton Power Limited resulting in net cash proceeds of approximately $2 million, of which $1 million was received in 2003 and $1 million was received during the first quarter of 2004, and a net gain of approximately $3 million. Langage is included in our All Other segment under the Other International category.
      Turbines — In October 2003, we closed on the sale of three turbines and related equipment. The sale resulted in net cash proceeds of approximately $71 million and a gain of approximately $22 million. Turbines are included in our All Other segment under the Other category.
      Berrians Project — During the fourth quarter of 2003, we cancelled plans to construct the Berrians peaking facility on the land adjacent to our Astoria facility. Berrians was originally scheduled to commence operations in the summer of 2005; however, based on the remaining costs to complete and the current risk profile of merchant peaking units, the construction project was terminated. This resulted in a charge of approximately $14 million to write off the project’s assets. Berrians is included in our Other North America segment.
      TermoRio — TermoRio was a green field cogeneration project located in the state of Rio de Janeiro, Brazil. Based on the project’s failure to meet certain key milestones, we exercised our rights under the project agreements to sell our debt and equity interests in the project to our partner, Petroleo Brasileiro S.A. Petrobras, or Petrobras. On May 17, 2002, Petrobras commenced an arbitration. On March 8, 2003, the arbitral tribunal decided most, but not all, of the issues in our favor and awarded us approximately US $80 million. On June 4, 2004, NRG Energy commenced a lawsuit in U.S. District Court for the Southern District of New York, seeking to enforce the arbitration award. On February 16, 2005, a conditional settlement agreement was signed with our former partner Petrobras, whereby Petrobras is obligated to pay us $71 million. Such payment was received by us at a closing held on February 25, 2005. We had a note receivable of $57 million related to the arbitration award. The amounts received in excess of approximately $57 million were recorded to other income in the first quarter of 2005. TermoRio is included in our All Other

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segment under the Other International category. A $3 million reserve related to ongoing litigation was recorded in the fourth quarter of 2005.
 	 	
 	Restructuring Charges	
      We incurred $8 million of employee separation costs and advisor fees during 2003 until we filed for bankruptcy in May 2003. Subsequent to that date we recorded all advisor fees as reorganization costs.
 	 	
 	Fresh Start Adjustments	
      During the fourth quarter of 2003, we recorded a net credit of $3.9 billion (comprised of a $4.2 billion gain from continuing operations and a $0.3 billion loss from discontinued operations) in connection with fresh start adjustments as discussed in Note 3.
      Following is a summary of the significant effects of the reorganization and Fresh Start:
 	 	 	 	 	 	
 	 	(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(2) emission 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	 	 	(325	)	
 	 	 	 	
Total Fresh Start adjustments — continuing operations	 	$	4,220	 	

 	 	
 	Legal Settlement Charges	
      During the period January 1, 2003 to December 5, 2003, we recorded $463 million of legal settlement charges which consisted of the following. We recorded $396 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 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 million pre-petition bankruptcy claim and an $8 million post-petition bankruptcy claim. We had previously recorded $11 million in connection with various legal disputes with Fortistar Capital; accordingly, we recorded an additional $57 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 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

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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 $2 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 million during November 2003.
 	 	
Note 9 —	Asset Retirement Obligation	
      Effective January 1, 2003, we adopted SFAS 143 which requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.
      We identified certain retirement obligations within our power generation operations in the Northeast, South Central and Australia regions. We also identified retirement obligations within our All Other segment under the Other International, Alternative Energy category and the Non-Generation category. These asset retirement obligations are related primarily to the future dismantlement of equipment on leased property and environment obligations related to ash disposal site closures and fuel storage facilities.
      We have also identified conditional asset retirement obligations for asbestos removal and disposal which are specific to certain power generation operations. In 2005, we adopted FIN 47 which clarifies the term “conditional asset retirement obligation” as used in SFAS 143. Under FIN 47, a conditional asset retirement obligation is reasonably estimable if (a) it is evident that the fair value of the obligation is embodied in the acquisition price of the asset, (b) an active market exists for the transfer of the obligation, or (c) sufficient information exists to apply an expected present value technique. To estimate the fair value of the conditional asset retirement obligations, we utilize existing information to calculate an expected present value of the future obligations. The existing information includes engineering estimates on the cost of asbestos removal and disposal, the maximum future lives of the plants assuming no major renovations, our weighted average cost of capital and future inflation rates. We also include several probabilities in the expected present value calculation, including major plant renovations or dismantlement. The calculation of the expected present value of the conditional asset retirement obligations indicates an additional asset retirement obligation for asbestos removal and disposal of $4 million which we recorded in the fourth quarter of 2005. The cumulative effect adjustment of the additional asset retirement obligation is not considered to be material.

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      The following represents the balances of the asset retirement obligation as of December 31, 2005, 2004 and 2003,and the additions, accretion, settlements and translation adjustments of the asset retirement obligation for the years ended December 31, 2005 and 2004. The asset retirement obligation is included in other long-term obligations in the consolidated balance sheet.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	 	 	Total	 	
 	 	 	 	Asset	 	
 	 	 	 	South	 	 	 	 	Other	 	 	Alternative	 	 	Non	 	 	 	 	Retirement	 	
 	 	Northeast	 	 	Central	 	 	Australia	 	 	International	 	 	Energy	 	 	Generation	 	 	Other	 	 	Obligation	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Balance as of December 31, 2003	 	$	12	 	 	$	3	 	 	$	9	 	 	$	4	 	 	$	1	 	 	$	1	 	 	$	—	 	 	$	30	 	
Additions	 	 	1	 	 	 	—	 	 	 	3	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4	 	
Accretion	 	 	—	 	 	 	—	 	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2004	 	 	13	 	 	 	3	 	 	 	14	 	 	 	4	 	 	 	1	 	 	 	1	 	 	 	—	 	 	 	36	 	
Additions	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4	 	 	 	5	 	
Accretion	 	 	1	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	
Translation adjustments	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2005	 	$	15	 	 	$	3	 	 	$	14	 	 	$	4	 	 	$	1	 	 	$	1	 	 	$	4	 	 	$	42	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      Prior to December 5, 2003, we completed our annual review of asset retirement obligations. As part of that review we made revisions to our previously recorded obligation in the amount of $4 million. The revisions included identification of new obligations as well as changes in costs required at retirement date. As a result of adopting Fresh Start we revalued our asset retirement obligations on December 6, 2003. We recorded an additional asset retirement obligation of approximately $7 million in connection with Fresh Start reporting. This amount results from a change in the discount rate used between adoption and Fresh Start reporting as of December 5, 2003, equal to 500 to 600 basis points.
 	 	
Note 10 —	Inventory	
      Inventory, which is stated at the lower of weighted average cost or market, consists of:
 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
 	 	(In millions)	 	
Fuel oil	 	$	132	 	 	$	114	 	
Coal	 	 	66	 	 	 	75	 	
Natural gas	 	 	4	 	 	 	—	 	
Spare parts	 	 	54	 	 	 	53	 	
Other	 	 	4	 	 	 	5	 	
 	 	 	 	 	 	 	
 	Total inventory	 	$	260	 	 	$	247	 	
 	 	 	 	 	 	 	
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Note 11 —	Notes Receivable and Capital Lease	
      Notes receivable consist primarily of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. The notes receivable and capital lease are as follows:
 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
 	 	(In millions)	 	
Notes Receivable — non-affiliate	 	 	 	 	 	 	 	 	
Omega Energy, LLC, due 2004, 12.5%	 	$	—	 	 	$	4	 	
Omega Energy II, LLC, due 2009, 11%	 	 	—	 	 	 	1	 	
Elk River — Great River Energy, due December 31, 2008, 4.69%	 	 	1	 	 	 	1	 	
Northbrook Texas LLC, due February 2024, 9.25%	 	 	—	 	 	 	9	 	
Termo Rio (via NRGenerating Luxembourg (No. 2) S.a.r.l), 8.0%	 	 	—	 	 	 	57	 	
Capital Lease	 	 	 	 	 	 	 	 	
VEAG Vereinigte Energiewerke AG, due August 31, 2021, 13.88% (direct financing lease) (1)	 	 	379	 	 	 	461	 	
 	 	 	 	 	 	 	
 	Notes receivable and capital lease — non-affiliates	 	 	380	 	 	 	533	 	
Reserve for uncollectible notes receivable	 	 	—	 	 	 	(8	)	
 	 	 	 	 	 	 	
 	 	Notes receivable non-affiliates and capital lease, net	 	 	380	 	 	 	525	 	
Less current maturities	 	 	25	 	 	 	85	 	
 	 	 	 	 	 	 	
 	 	Total	 	$	355	 	 	$	440	 	
 	 	 	 	 	 	 	
Notes Receivable — affiliates	 	 	 	 	 	 	 	 	
NEO notes to various affiliates due primarily 2012, prime +2%	 	 	—	 	 	 	4	 	
Kraftwerke Schkopau GBR, indefinite maturity date, 4.75%-7.79%(2)	 	 	103	 	 	 	120	 	
 	 	 	 	 	 	 	
 	 	Notes receivable — affiliates	 	$	103	 	 	$	124	 	

 	 	
(1) 	Saale Energie GmbH, or Saale, has sold 100% of its share of capacity from the Schkopau power plant to VEAG Vereinigte Energiewerke AG under a 25-year contract, which is more than 83% of the useful life of the plant. The direct financing lease receivable amount was calculated based on the present value of the income to be received over the life of the contract.	
 	 	
(2) 	Saale entered into a note receivable with Kraftwerke Schkopau GBR, a partnership between Saale and E.On Kraftwerke GmbH. The note was used to fund Saale’s initial capital contribution to the partnership and to cover project liquidity shortfalls during construction of a power plant. The note is subject to repayment upon the disposition of the Schkopau plant.	
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Note 12 —	Property, Plant and Equipment	
      The major classes of property, plant and equipment were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Reorganized NRG	 	 	Average	 	
 	 	 	 	 	 	 	Remaining	 	
 	 	Depreciable	 	December 31,	 	 	December 31,	 	 	Useful	 	
 	 	Lives	 	2005	 	 	2004	 	 	Life	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(In millions)	 	 	 	
Facilities and equipment	 	1-42 Years	 	$	3,223	 	 	$	3,199	 	 	 	14	 	
Land and improvements	 	 	 	 	128	 	 	 	127	 	 	 	 	 	
Office furnishings and equipment	 	2-10 Years	 	 	26	 	 	 	21	 	 	 	3	 	
Construction in progress	 	 	 	 	54	 	 	 	17	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Total property, plant and equipment	 	 	 	 	3,431	 	 	 	3,364	 	 	 	 	 	
Accumulated depreciation	 	 	 	 	(392	)	 	 	(206	)	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Net property, plant and equipment	 	 	 	$	3,039	 	 	$	3,158	 	 	 	 	 	

 	 	
Note 13 —	Investments Accounted for by the Equity Method	
      We have investments in various international and domestic energy projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents us from exercising a controlling influence over operating and financial policies of the projects. Under this method, equity in pretax income or losses of domestic partnerships and, generally, in the net income or losses of international projects, are reflected as equity in earnings of unconsolidated affiliates.
      A summary of certain of our more significant equity-method investments, which were in operation at December 31, 2005, is as follows:
 	 	 	 	 	 	 	
 	 	 	 	Economic	 	
Name	 	Geographic Area	 	Interest	 	
 	 	 	 	 	 	
MIBRAG mbH, or MIBRAG	 	Germany	 	 	50%	 	
Saguaro Power Company, or Saguaro	 	USA	 	 	50%	 	
Rocky Road Power	 	USA	 	 	50%	 	
Enfield Energy Centre Limited, or Enfield — sold on April 1, 2005	 	UK	 	 	25%	 	
West Coast Power, or WCP	 	USA	 	 	50%	 	
James River	 	USA	 	 	50%	 	
Gladstone Power Station, or Gladstone	 	Australia	 	 	37.5%	 	
Central and Eastern European Energy Power Fund	 	Various	 	 	22.2%	 	
Scudder LA Power Fund I	 	Latin America	 	 	25%	 	
      During 2005 we sold our equity investment in Enfield. During 2004, we sold our equity investments in Commonwealth Atlantic Limited Partnership, four NEO investments (Four Hills LLC, Minnesota Methane II LLC, NEO Montauk Genco LLC and NEO Montauk Gasco LLC), Calpine Cogeneration, Loy Yang,

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Kondapalli, and ECKG. Summarized financial information for investments in unconsolidated affiliates accounted for under the equity method is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	
 	 	 	 	For the Period	 	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	 	January 1 -	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(In millions)	 	 	 	 	
Summarized Statements of Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	1,300	 	 	$	2,428	 	 	$	268	 	 	 	$	2,212	 	
Costs and expenses	 	 	1,101	 	 	 	1,966	 	 	 	203	 	 	 	 	2,036	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net income	 	$	199	 	 	$	462	 	 	$	65	 	 	 	$	176	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Summarized Balance Sheets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets	 	$	592	 	 	$	845	 	 	$	830	 	 	 	$	784	 	
Non-current assets	 	 	2,561	 	 	 	2,903	 	 	 	6,541	 	 	 	 	6,452	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total assets	 	$	3,153	 	 	$	3,748	 	 	$	7,371	 	 	 	$	7,236	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities	 	 	133	 	 	 	206	 	 	 	1,276	 	 	 	 	1,216	 	
Non-current liabilities	 	 	1,143	 	 	 	1,740	 	 	 	3,592	 	 	 	 	3,529	 	
Equity	 	 	1,877	 	 	 	1,802	 	 	 	2,503	 	 	 	 	2,491	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total liabilities and equity	 	$	3,153	 	 	$	3,748	 	 	$	7,371	 	 	 	$	7,236	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NRG’s share of equity and net income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NRG’s share of equity	 	$	810	 	 	$	809	 	 	$	1,052	 	 	 	$	1,079	 	
NRG’s share of net income	 	$	104	 	 	$	160	 	 	$	14	 	 	 	$	171	 	
      We have ownership interests in five companies that were considered significant as defined by applicable SEC regulations as of December 31, 2005: MIBRAG, WCP, Saguaro, Gladstone and Enfield. We account for our investments using the equity method. Our carrying value of equity investments is impacted by impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates as well as other adjustments. The financial statements of MIBRAG and WCP will be filed as separate exhibits to this Form 10-K.

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 	MIBRAG Summarized Financial Information	
      The Company owns a 50% interest in MIBRAG. Located near Leipzig, Germany, MIBRAG owns and manages a coal mining operation, three lignite fueled power generation facilities and other related businesses. Approximately 50% of the power generated by MIBRAG is used to support its mining operations, with the remainder sold to a German utility company. A portion of the coal from MIBRAG’s mining operation is used to fuel the power generation facilities, but a majority of the mined coal is sold primarily to two major customers, including Schkopau, an affiliate of the Company. A significant portion of the sales of MIBRAG are made pursuant to long-term coal and energy supply contracts. The following tables summarize financial information for MIBRAG, including interests owned by the Company and other parties for the periods shown below:
Results of Operations
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	For the Year Ended	 	
 	 	 	 	
 	 	2005	 	 	2004	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operating revenues	 	$	432	 	 	$	427	 	 	$	401	 	
Operating income	 	 	72	 	 	 	61	 	 	 	62	 	
Net income (pre-tax)	 	 	51	 	 	 	43	 	 	 	46	 	
Financial Position
 	 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	 	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
 	 	(In millions)	 	
Current assets	 	$	121	 	 	$	179	 	
Other assets	 	 	1,134	 	 	 	1,295	 	
 	 	 	 	 	 	 	
 	Total assets	 	$	1,255	 	 	$	1,474	 	
 	 	 	 	 	 	 	
Current liabilities	 	$	22	 	 	$	21	 	
Other liabilities	 	 	885	 	 	 	1,083	 	
Equity	 	 	348	 	 	 	370	 	
 	 	 	 	 	 	 	
 	Total liabilities and equity	 	$	1,255	 	 	$	1,474	 	
 	 	 	 	 	 	 	
      For the years ended December 31, 2005 and 2004, the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 through December 5, 2003 our equity earnings from MIBRAG were approximately $26 million, $21 million, $0 million and $22 million, respectively.
      As discussed in Note 2, our MIBRAG equity investment will be negatively affected by EITF 04-6. Currently, MIBRAG has an asset totaling € 157 million, approximately $185 million, representing the stripping costs incurred during production as of December 31, 2005. Following adoption in the first quarter of 2006, our investment in MIBRAG will be reduced by 50% of the above mentioned asset, approximately $93 million, with an offsetting charge to retained earnings.
 	 	
 	West Coast Power LLC Summarized Financial Information	
      We have a 50% interest in WCP. Upon adoption of Fresh Start we adjusted our investment in WCP to fair value as of December 6, 2003. In accordance with APB 18, we have reconciled the value of our investment as of December 6, 2003 to our share of WCP’s partner’s equity. As a result of pushing down the impact of Fresh Start to the project’s balance sheet, we determined that a contract based intangible asset with a one year

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
remaining life, consisting of the value of WCP’s CDWR energy sales contract, must be established and recognized as a basis adjustment to our share of the future earnings generated by WCP. This adjustment reduced our equity earnings in the amount of approximately $116 million for the year ended December 31, 2004 until the contract expired in December 2004. Offsetting this reduction in earnings is a favorable adjustment to reflect a lower depreciation expense resulting from the corresponding reduced value of the project’s fixed assets from Fresh Start reporting.
      During the year ended December 31, 2005 we recorded equity earnings of $22 million for WCP after adjustments for the reversal of $12 million project-level depreciation expense. For the year ended December 31, 2004 we recorded equity earnings of approximately $69 million for WCP after adjustments for the reversal of approximately $32 million project-level depreciation expense, offset by a decrease in earnings related to approximately $116 million amortization of the intangible asset for the CDWR contract. During the period December 6, 2003 through December 31, 2003 we recorded equity earnings of approximately $9 million for WCP after adjustments for the reversal of approximately $3 million project-level depreciation expense, offset by a decrease in earnings related to approximately $9 million amortization of the intangible asset for the CDWR contract. The following table summarizes financial information for WCP, including interests owned by us and other parties for the periods shown below:
Results of Operations
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	For the Period	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	January 1 -	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operating revenues	 	$	301	 	 	$	726	 	 	$	53	 	 	$	643	 	
Operating income	 	 	15	 	 	 	303	 	 	 	31	 	 	 	201	 	
Net income (pre-tax)	 	 	21	 	 	 	306	 	 	 	31	 	 	 	202	 	
Financial Position
 	 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
 	 	(In millions)	 	
Current assets	 	$	312	 	 	$	426	 	
Other assets	 	 	376	 	 	 	394	 	
 	 	 	 	 	 	 	
 	Total assets	 	$	688	 	 	$	823	 	
 	 	 	 	 	 	 	
Current liabilities	 	 	43	 	 	 	82	 	
Other liabilities	 	 	6	 	 	 	5	 	
Equity	 	 	639	 	 	 	736	 	
 	 	 	 	 	 	 	
 	Total liabilities and equity	 	$	688	 	 	$	823	 	
 	 	 	 	 	 	 	
      For the years ended December 31, 2005 and 2004, the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 through December 5, 2003 our equity earnings from WCP were approximately $22 million, $69 million, $9 million and $99 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 	 	
 	Acquisition of Remaining 50% in WCP from Dynegy, Inc. and sale of our 50% investment in Rocky Road Power LLC	
      On December 27, 2005, we entered into purchase and sale agreements for projects co-owned with Dynegy, Inc., or Dynegy. Under the agreements, we will acquire Dynegy’s 50% ownership interest in WCP (Generation) Holdings, Inc., and become the sole owner of WCP’s 1,808 MW of generation in Southern California . In addition, we are selling to Dynegy our 50% ownership interest in Rocky Road Power LLC, or Rocky Road, a 330 MW gas-fueled, simple cycle peaking plant located in Dundee, Illinois. Both of these transactions are conditioned upon one another and we will pay Dynegy a net purchase price of $160 million at closing. We will fund the net purchase price with cash held by WCP. We anticipate closing both transactions during the first quarter of 2006.
 	 	
 	Saguaro Power Company	
      NRG purchased 50 percent of Saguaro in September 2001. Located in Henderson, near Las Vegas, Nevada, the Saguaro plant is a cogeneration plant with dual-fuel capability (natural gas and oil) and has contracted its electricity to Nevada Power through 2022, one steam host (Pioneer) whose contract expires in 2007 (with a negotiated renewal) and a steam off taker (Ocean Spray), whose contract runs through 2015. Upon adoption of Fresh Start we created a basis difference as we increased our investment in Saguaro by approximately $31 million to reflect fair value as of December 6, 2003. From Fresh Start we have amortized this amount by approximately $2 million annually based on the plant’s estimated remaining useful life, recorded as a reduction in equity earnings. In accordance with APB 18, we have reconciled the value of our investment as of December 6, 2003 to our share of Saguaro’s partner’s equity.
      The Saguaro plant had a long-term gas supply agreement that expired in July 2005 and the plant is now exposed to the monthly spot gas market. At present, Saguaro cannot pass higher natural gas costs through to its customers, and the plant is currently experiencing negative cash flows. Due to this event and based on forecasted prices and cash flows, we determined that we have a permanent decline in value of our 50% interest and recorded a write down of our equity investment in Saguaro by approximately $27 million (see also Note 7). As such, the remaining basis difference as of December 31, 2005 is immaterial.
      For the years ended December 31, 2005 and 2004, the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 through December 5, 2003 our equity earnings from Saguaro were approximately $0 million, $5 million, $1 million and $4 million, respectively.
 	 	
 	Gladstone	
      We own a 37.5% interest in Gladstone, an unincorporated joint venture, or UJV, which operates a 1,613 megawatt coal-fueled power generation facility in Queensland, Australia. The power generation facility is managed by the joint venture participants and the facility is operated by NRG. Operating expenses incurred in connection with the operation of the facility are funded by each of the participants in proportion to their ownership interests. Coal is sourced from a mining operation owned and operated by certain joint venture partners and other investors under a long term supply agreement. We and the joint venture participants receive a majority of our respective share of revenues directly from customers and are directly responsible and liable for project related debt, all in proportion to the ownership interests in the UJV. Power generated by the facility is primarily sold to an adjacent aluminum smelter, with excess power sold on the national market.
      For the years ended December 31, 2005 and 2004, the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 through December 5, 2003 our equity earnings from Gladstone were approximately $24 million, $18 million, $1 million and $12 million, respectively.

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 	Enfield Energy Centre Limited	
      Until April 1, 2005, we owned a 25% interest in Enfield, located in Enfield, North London, UK. Enfield owns and operates a 396 MW, natural gas-fired combined cycle gas turbine power station. Enfield sells electricity generated from the plant in North London and the gas generated from the plant under a long-term gas supply contract. As of April 1, 2005, Enfield had a long-term agreement that effectively fixed the purchase price of its gas supply. The purpose of the contract, which was executed in August 1997 and extended through October 2014, was to mitigate the risk associated with fluctuations in the price of gas utilized in the generation of electricity at our facility. This contract was considered a derivative as defined by SFAS 133, and was afforded mark-to-market accounting treatment. We were subject to volatility in earnings associated with fluctuations in the market price of gas. Enfield has the ability to consume the gas for generation, and therefore our risk of loss associated with the contract is minimal. Given an increase in the price of natural gas in the UK market during the course of 2004 and 2005, we recorded mark to market gains of approximately $12 million and $23 million for the three months ended March 31, 2005 and for the year ended December 31, 2004, respectively.
      For the three months ended March 31, 2005, the year ended December 31, 2004, the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 through December 5, 2003 our equity earnings from Enfield were approximately $16 million, $29 million, $0 million and $6 million, respectively.
Note 14 — Intangible Assets
 	 	
 	Reorganized NRG	
      Upon the adoption of Fresh Start, we established certain intangible assets for power sales agreements and plant emission allowances. These intangible assets are being amortized over their respective lives based on a straight-line or units of production basis to resemble our realization of such assets. We are also actively selling part of our emission allowances and their respective cost is expensed when sold.
      Power sale agreements are amortized as a reduction to revenue over the terms and conditions of each contract. The weighted average remaining amortization period is two years for the power sale agreements. Emission allowances are amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023. Aggregate amortization recognized for the year ended December 31, 2005, December 31, 2004 and the period December 6, 2003 to December 31, 2003 was approximately $24 million, $50 million and $5 million, respectively. The annual aggregate amortization for each of the five succeeding years, starting with 2006, is expected to approximate $14 million in 2006, $12 million in 2007, $11 million in 2008, $11 million in 2009 and $8 million for 2010 for both the power sale agreements and emission allowances. The expected annual amortization of these amounts is expected to change as we continue to sell part of our emission allowances and as we relieve our tax valuation allowance per the explanation below.
      For the year ended December 31, 2005, we reduced our valuation allowance by approximately $17 million and reduced certain deferred tax assets by $9 million. Both movements were offset to our intangible assets at our wholly-owned subsidiaries, in accordance with SOP 90-7. For the year ended December 31, 2004, we reduced our deferred tax valuation allowance by $64 million and recorded a corresponding reduction of $55 million related to our intangible assets at our wholly-owned subsidiaries. The remaining $9 million was recorded as a reduction to our intangible asset related to our equity investments in West Coast Power. In accordance with SOP 90-7, any future income tax benefits realized from reducing the valuation allowance should first reduce intangible assets until exhausted, and thereafter be recorded as a direct addition to paid-in capital. During 2004, Intangible assets were also reduced by approximately $33 million consisting of an approximate $11 million reduction in connection with the recognition of certain tax credits to be claimed on our New York state franchise tax return and approximately $22 million of adjustments related to a true-up of certain other tax evaluations and the recognition of Itiquira Energetica S.A. preferred stock as debt for U.S. generally accepted accounting purposes.

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      Intangible assets consisted of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Power Sale	 	 	Emission	 	 	 	
 	 	Agreements	 	 	Allowances	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Original balance as of December 6, 2003	 	$	64	 	 	$	373	 	 	$	437	 	
Amortization	 	 	(5	)	 	 	—	 	 	 	(5	)	
 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2003	 	 	59	 	 	 	373	 	 	 	432	 	
Tax valuation adjustments	 	 	(5	)	 	 	(50	)	 	 	(55	)	
Other valuation adjustments	 	 	(2	)	 	 	(31	)	 	 	(33	)	
Amortization	 	 	(32	)	 	 	(18	)	 	 	(50	)	
 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2004	 	 	20	 	 	 	274	 	 	 	294	 	
Tax valuation adjustments	 	 	(1	)	 	 	(16	)	 	 	(17	)	
Other valuation adjustments	 	 	—	 	 	 	9	 	 	 	9	 	
Sale of emission credits to 3rd parties	 	 	—	 	 	 	(5	)	 	 	(5	)	
Amortization	 	 	(12	)	 	 	(12	)	 	 	(24	)	
 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2005	 	$	7	 	 	$	250	 	 	$	257	 	

 	 	
 	Predecessor Company	
      We had intangible assets that were amortized and consisted of service contracts. Aggregate amortization expense for the period January 1, 2003 to December 5, 2003 was approximately $4 million.
Note 15 — Accounting for Derivative Instruments and Hedging Activities
      SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, or SFAS No. 133, as amended, requires us to recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. If certain conditions are met, we may be able to designate our derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives in Accumulated Other Comprehensive Income, or OCI and subsequently recognize in earnings when the hedged items impact income. The ineffective portion of a cash flow hedge is immediately recognized in income.
      For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivatives and the hedged items are recorded in current earnings. The ineffective portion of a hedging derivative instrument’s change in fair values will be immediately recognized in earnings.
      For derivatives that are neither designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Under the guidelines established by SFAS No. 133, as amended, certain derivative instruments may qualify for the normal purchase and sale exception and are therefore exempt from fair value accounting treatment. SFAS No. 133 applies to our energy related commodity contracts, interest rate swaps and foreign exchange contracts.
      As the Company engages principally in the trading and marketing of its generation assets, most of our commercial activities qualify for hedge accounting under the requirements of SFAS No. 133. In order to so qualify, the physical generation and sale of electricity must be highly probable at inception of the trade and throughout the period it is held, as is the case with our base-load coal plants. For this reason, trades in support of the company’s peaking units will not generally qualify for hedge accounting treatment and any changes in fair value are likely to be reflected on a mark-to-market basis in the statement of operations. The majority of trades in support of our base-load coal units will normally qualify for hedge accounting treatment and any fair value movements will be reflected in the balance sheet as part of OCI.

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 	Derivative Financial Instruments	

 	Energy Related Commodities	
      As part of our risk management activities, we manage the commodity price risk associated with our competitive supply activities and the price risk associated with power sales from our electric generation facilities. In doing so, we may enter into a variety of derivative and non-derivative instruments, including but not limited to the following:
 	 	 	
 	• 	Forward contracts, which commit us to purchase or sell energy commodities in the future.	
 	 	 	
 	• 	Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument.	
 	 	 	
 	• 	Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual (notional) quantity.	
 	 	 	
 	• 	Option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price.	
      The objectives for entering into such hedges include:
 	 	 	
 	• 	Fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on our electric generation operations.	
 	 	 	
 	• 	Fixing the price of a portion of anticipated fuel purchases for the operation of our power plants.	
 	 	 	
 	• 	Fixing the price of a portion of anticipated energy purchases to supply our load-serving customers.	
      Ineffectiveness will result from a difference in the relative price movements between a financial transaction and the underlying physical pricing point. If this difference is large enough, it will cause an entity to discontinue the use of hedge accounting.
      At December 31, 2005 we had hedge and non-hedge energy related commodities financial instruments extending through December 2026. At December 31, 2005 our derivative assets and liabilities consisted primarily of the following:
 	 	 	
 	• 	Forward and financial contracts for the sale of electricity and related products economically hedging our generation assets forecasted output through 2008.	
 	 	 	
 	• 	Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of our generation assets into 2006.	
      Also, at December 31, 2005 we had other energy related contracts that did not qualify as derivatives under the guidelines established by SFAS No. 133, or we elected to apply the normal purchase and sale exception as follows:
 	 	 	
 	• 	Coal purchase contracts extending through 2009 designated as normal purchases and disclosed as part of our contractual cash obligations. (See Note 25 Commitments and Contingencies).	
 	 	 	
 	• 	Natural gas transportation and storage agreements these contracts are not derivatives and are disclosed as part of our contractual cash obligations. (See Note 25 Commitments and Contingencies).	
 	 	 	
 	• 	Load-following forward electric sales contracts extending through 2026 (these contracts are not considered derivatives).	
      For the year ended December 31, 2005, the impact of hedge ineffectiveness associated with financial forward contracted electric sales was immaterial. No ineffectiveness was recognized on commodity cash flow

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hedges during the year ended December 31, 2004, the periods December 6, 2003 through December 31, 2003 and January 1, 2003 through December 5, 2003.
      Our pre-tax earnings for the year ended December 31, 2005 and 2004, the period December 6, 2003 through December 31, 2003, and the period January 1, 2003 through December 5, 2003 were affected by an unrealized loss of $143 million, an unrealized gain of $81 million, an unrealized loss of $1 million and an unrealized gain of $54 million respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.
      During the year ended December 31, 2005 and 2004, we reclassified losses of $132 million and $3 million, respectively, from OCI to current period earnings. During the period December 6, 2003 through December 31, 2003 no gains or losses were reclassified from OCI to current-period earnings. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net gains recorded in OCI of $61 million on energy related derivative instruments accounted for as hedges. During the period January 1, 2003 through December 5, 2003, we reclassified gains of $113 million from OCI to current period earnings. We expect to reclassify an additional $208 million of deferred losses to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.
 	 	
 	Interest Rates	
      To manage interest rate risk, we have entered into interest rate swap agreements that fix the interest payments or the fair value of selected debt issuances. The qualifying swap agreements are accounted for as cash flow or fair value hedges. The effective portion of the cash flow hedges’ cumulative gains/losses are reported as a component of OCI in stockholders’ equity. These gains/losses are recognized in earnings as the hedged interest expense is incurred. The reclassification from OCI is included on the same line of the statement of operations in which the hedged item appears. The entire amount of the change in fair value hedges is recorded in the statement of operations along with the change in value of the hedged item. At December 31, 2005 our consolidating subsidiaries had various interest-rate swap agreements extending through June 2019 with combined notional amounts of $1.2 billion. If these swaps had been terminated at December 31, 2005 we would have owed the counter-parties $33 million.
      At December 31, 2005 all of our interest rate swap arrangements have been designated as either cash flow or fair value hedges.
      No ineffectiveness was recognized on interest rate swaps that qualify as hedges during the year ended December 31, 2005 and 2004, the periods December 6, 2003 through December 31, 2003 and January 1, 2003 through December 5, 2003.
      Our pre-tax earnings for the year ended December 31, 2005 were not affected by changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133. Our pre-tax earnings for the year ended December 31, 2004 were increased by an unrealized gain of less than a million dollars associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133. One of these instruments was a $400 million swap to pay fixed, which was not designated as a hedge of the expected cash flows at March 31, 2004. As of April 1, 2004, this instrument was designated as a cash flow hedge under SFAS No. 133. As a result, changes in value subsequent to April 1, 2004 are deferred and recorded as part of OCI.
      Our pre-tax earnings for the period December 6, 2003 through December 31, 2003 and the period January 1, 2003 through December 5, 2003 were increased by an unrealized gain of $2 million and decreased by an unrealized loss of $15 million, respectively, associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      During the year ended December 31, 2005, we reclassified gains of $2 million from OCI to current period earnings. During the year ended December 31, 2004, we reclassified losses of $5 million from OCI to current period earnings. During the periods December 6, 2003 through December 31, 2003 and January 1, 2003 through December 5, 2003, losses of $0 and $30 million, respectively, were reclassified from OCI to current- period earnings. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net losses recorded in OCI of $66 million on interest rate swaps accounted for as hedges. We expect to reclassify $2 million of deferred gains to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.
 	 	
 	Foreign Currency Exchange Rates	
      To preserve the U.S. dollar value of projected foreign currency cash flows, we may hedge, or protect those cash flows if appropriate foreign hedging instruments are available. As of December 31, 2005, the results of any outstanding foreign currency exchange contracts were immaterial to our financial results.
      No ineffectiveness occurred on foreign currency cash flow hedges during the year ended December 31, 2004, the periods December 6, 2003 through December 31, 2003 or January 1, 2003 through December 5, 2003.
      During the year ended December 31, 2005 and 2004 and the period December 6, 2003 to December 31, 2003, our pre-tax earnings were not affected by any gain or loss associated with foreign currency hedging instruments not accounted for as hedges in accordance with SFAS No. 133.
      During the year ended December 31, 2005 and 2004, the periods December 6, 2003 through December 31, 2003 and January 1, 2003 through December 5, 2003, no amounts were reclassified from OCI to current period earnings. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net losses recorded in OCI of less than one million dollars on foreign currency swaps accounted for as hedges. Any amounts we expect to reclassify to earnings during the next twelve months on foreign currency swaps accounted for as hedges are immaterial to our results.
 	 	
 	Accumulated Other Comprehensive Income	
      The following table summarizes the effects of SFAS No. 133, as amended, on our other comprehensive income balance attributable to hedged derivatives for the year ended December 31, 2005 before income taxes:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	Energy	 	 	Interest	 	 	Foreign	 	 	
 	 	Commodities	 	 	Rate	 	 	Currency	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(Gains/(losses) in millions)	 	
Accumulated OCI balance at December 31, 2004	 	$	5	 	 	$	2	 	 	$	—	 	 	$	7	 	
 	Unwound from OCI during period:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	— due to unwinding of previously deferred amounts	 	 	132	 	 	 	(2	)	 	 	—	 	 	 	130	 	
 	Mark to market of hedge contracts	 	 	(341	)	 	 	8	 	 	 	—	 	 	 	(333	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Accumulated OCI balance at December 31, 2005	 	$	(204	)	 	$	8	 	 	$	—	 	 	$	(196	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Gains/(Losses) expected to unwind from OCI during next 12 months	 	$	(208	)	 	$	2	 	 	$	—	 	 	$	(206	)	
      During the year ended December 31, 2005, losses of approximately $130 million were reclassified from OCI to current period earnings due to the unwinding of previously deferred amounts. These amounts are

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
recorded on the same line in the statement of operations in which the hedged items are recorded. Also during the year ended December 31, 2005, we recorded a loss in OCI of $333 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of December 31, 2005 was an unrecognized loss of approximately $196 million. We expect $206 million of deferred net losses on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.
      The following table summarizes the effects of SFAS No. 133, as amended, on our other comprehensive income balance attributable to hedged derivatives for the year ended December 31, 2004 before income taxes
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	Energy	 	 	Interest	 	 	Foreign	 	 	
 	 	Commodities	 	 	Rate	 	 	Currency	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(Gains/(losses) in millions)	 	
Accumulated OCI balance at December 31, 2003	 	$	(2	)	 	$	1	 	 	$	—	 	 	$	(1	)	
 	Unwound from OCI during period:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	— due to unwinding of previously deferred amounts	 	 	3	 	 	 	5	 	 	 	—	 	 	 	8	 	
 	Mark to market of hedge contracts	 	 	4	 	 	 	(4	)	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Accumulated OCI balance at December 31, 2004	 	$	5	 	 	$	2	 	 	$	—	 	 	$	7	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
      During the year ended December 31, 2004, losses of approximately $8 million were reclassified from OCI to current period earnings due to the unwinding of previously deferred amounts. These amounts are recorded on the same line in the statement of operations in which the hedged items are recorded. Also during the year ended December 31, 2004, we recorded a loss in OCI of less than $1 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of December 31, 2004 was an unrecognized gain of approximately $7 million.
      The following table summarizes the effects of SFAS No. 133, as amended, on our other comprehensive income balance attributable to hedged derivatives for the period December 6, 2003 to December 31, 2003 before income taxes:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	Energy	 	 	Interest	 	 	Foreign	 	 	
 	 	Commodities	 	 	Rate	 	 	Currency	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(Gains/(losses) in millions)	 	
Accumulated OCI balance at December 6, 2003	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
 	Unwound from OCI during period:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	— due to unwinding of previously deferred amounts	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Mark to market of hedge contracts	 	 	(2	)	 	 	1	 	 	 	—	 	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Accumulated OCI balance at December 31, 2003	 	$	(2	)	 	$	1	 	 	$	—	 	 	$	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
      During the period ended December 31, 2003, we recorded a loss in OCI of approximately $1 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133, as amended, as of December 31, 2003 was an unrecognized loss of approximately $1 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The following table summarizes the effects of SFAS No. 133, as amended, on our other comprehensive income balance attributable to hedged derivatives for the period January 1, 2003 to December 5, 2003 before income taxes:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company	 	
 	 	 	 	
 	 	Energy	 	 	Interest	 	 	Foreign	 	 	
 	 	Commodities	 	 	Rate	 	 	Currency	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(Gains/(losses) in millions)	 	
Accumulated OCI balance at December 31, 2002	 	$	130	 	 	$	(103	)	 	$	—	 	 	$	27	 	
 	Unwound from OCI during period:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	— due to forecasted transactions probable of no longer occurring	 	 	—	 	 	 	32	 	 	 	—	 	 	 	32	 	
 	 	 — due to unwinding of previously deferred amounts	 	 	(113	)	 	 	(2	)	 	 	—	 	 	 	(115	)	
 	Mark to market of hedge contracts	 	 	44	 	 	 	7	 	 	 	—	 	 	 	51	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Accumulated OCI balance at December 5, 2003	 	 	61	 	 	 	(66	)	 	 	—	 	 	 	(5	)	
 	 	 — due to Fresh Start reporting write-off	 	 	(61	)	 	 	66	 	 	 	—	 	 	 	5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Accumulated OCI balance at December 6, 2003	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
      During the period ended December 5, 2003, we reclassified losses of $32 million from OCI to current-period earnings as a result of the discontinuance of cash flow hedges because it is probable that the original forecasted transactions will not occur by the end of the originally specified time period. Additionally, gains of $115 million were reclassified from OCI to current period earnings during the period ended December 5, 2003 due to the unwinding of previously deferred amounts. These amounts are recorded on the same line in the statement of operations in which the hedged items are recorded. Also during the period ended December 5, 2003, we recorded a gain in OCI of approximately $51 million related to changes in the fair values of derivatives accounted for as hedges. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net losses recorded in OCI of $5 million.
 	 	
     	Statement of Operations	
      The following tables summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the year ended December 31, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	Energy	 	 	Interest	 	Foreign	 	 	
 	 	Commodities	 	 	Rate	 	Currency	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	
 	 	(Gains/(losses) in millions)	 	
Revenue from majority-owned subsidiaries	 	$	(145	)	 	$	—	 	 	$	—	 	 	$	(145	)	
Cost of operations	 	 	2	 	 	 	—	 	 	 	—	 	 	 	2	 	
Other income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings of unconsolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Interest expense	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Statement of Operations impact before tax	 	$	(143	)	 	$	—	 	 	$	—	 	 	$	(143	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The following tables summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the year ended December 31, 2004:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	Energy	 	 	Interest	 	Foreign	 	 	
 	 	Commodities	 	 	Rate	 	Currency	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	
 	 	(Gains/(losses) in millions)	 	
Revenue from majority-owned subsidiaries	 	$	57	 	 	$	—	 	 	$	—	 	 	$	57	 	
Cost of operations	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Other income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings of unconsolidated subsidiaries	 	 	24	 	 	 	—	 	 	 	—	 	 	 	24	 	
Interest expense	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Statement of Operations impact before tax	 	$	81	 	 	$	—	 	 	$	—	 	 	$	81	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
      The following tables summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the period from December 6, 2003 through December 31, 2003:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	Energy	 	 	Interest	 	 	Foreign	 	 	
 	 	Commodities	 	 	Rate	 	 	Currency	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(Gains/(losses) in millions)	 	
Revenue from majority-owned subsidiaries	 	$	(1	)	 	$	—	 	 	$	—	 	 	$	(1	)	
Cost of operations	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
Other income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings of unconsolidated subsidiaries	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	(1	)	
Interest expense	 	 	—	 	 	 	2	 	 	 	—	 	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total Statement of Operations impact before tax	 	$	(1	)	 	$	2	 	 	$	—	 	 	$	1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
      The following tables summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the period from January 1, 2003 through December 5, 2003:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company	 	
 	 	 	 	
 	 	Energy	 	 	Interest	 	 	Foreign	 	 	
 	 	Commodities	 	 	Rate	 	 	Currency	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(Gains/(losses) in millions)	 	
Revenue from majority-owned subsidiaries	 	$	30	 	 	$	—	 	 	$	—	 	 	$	30	 	
Cost of operations	 	 	5	 	 	 	—	 	 	 	—	 	 	 	5	 	
Other income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings of unconsolidated subsidiaries	 	 	19	 	 	 	—	 	 	 	—	 	 	 	19	 	
Interest expense	 	 	—	 	 	 	(15	)	 	 	—	 	 	 	(15	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total Statement of Operations impact before tax	 	$	54	 	 	$	(15	)	 	$	—	 	 	$	39	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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Note 16 — Other Bankruptcy Settlements
      A principal component of our plan of reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of our plan of reorganization, that was received during 2004. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and us and/or our creditors and, in exchange for the Xcel Energy contribution, Xcel Energy received a complete release of claims from us and our creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003. We used the proceeds from the Xcel Energy settlement to pay off our creditor pool obligation as of December 31, 2004.
      In addition, our other bankruptcy settlement obligation as of December 31, 2005 and 2004 was $3 million and $6 million, respectively. This obligation relates to the allowed claims against NRG Energy related to our Pike facilities. See Note 25 — NRG FinCo Settlement. The net change in the balance of $3 million reflects the sale of certain of these assets, the proceeds of which were paid to the FinCo lenders.
Note 17 — Debt and Capital Leases
      Long-term debt and capital leases consist of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Reorganized NRG	 	
 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Fair Value	 	 	 	 	Fair Value	 	
 	 	 	 	 	 	Principal	 	 	Adjustment	 	 	Principal	 	 	Adjustment	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	December 31,	 	 	December 31,	 	
 	 	Stated	 	 	Effective	 	 	 	 	 	 	 	
 	 	Rate	 	 	Rate	 	 	2005	 	 	2005	 	 	2004	 	 	2004	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(Percent)	 	 	(In millions)	 	
NRG Recourse Debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NRG Energy 2nd priority senior notes, due December 15, 2013 (3)(4)	 	 	8.00	%	 	 	n/a	 	 	$	1,080	 	 	$	(6	)	 	$	1,725	 	 	$	10	 	
NRG Amended Credit Facility, due December 24, 2011	 	 	(1	)	 	 	—	 	 	 	795	 	 	 	—	 	 	 	800	 	 	 	—	 	
NRG Promissory Note, Xcel Energy, due June 5, 2006	 	 	3.00	 	 	 	9.00	 	 	 	10	 	 	 	—	 	 	 	10	 	 	 	(1	)	
NRG Project-Level, Non-Recourse Debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NRG Peaker Finance Co. LLC, due June 2019	 	 	(1	)	 	 	L+3.5	(2)	 	 	297	 	 	 	(57	)	 	 	301	 	 	 	(64	)	
Flinders Power Finance Pty, due September 2012	 	 	(1	)	 	 	—	 	 	 	177	 	 	 	—	 	 	 	203	 	 	 	10	 	
NRG Energy Center Minneapolis LLC, Senior secured notes, due 2013 and 2017, 7.12%-7.31%	 	 	(1	)	 	 	L+2	(2)	 	 	111	 	 	 	5	 	 	 	119	 	 	 	6	 	
Camas Power Boiler LP, unsecured term loan, due June 2007	 	 	(1	)	 	 	L+2	(2)	 	 	4	 	 	 	—	 	 	 	6	 	 	 	—	 	
Camas Power Boiler LP, revenue bonds, due August 2007	 	 	3.38	 	 	 	L+2	(2)	 	 	3	 	 	 	—	 	 	 	4	 	 	 	—	 	
Itiquira Energetica S.A., due December 2013	 	 	12.00	 	 	 	—	 	 	 	30	 	 	 	—	 	 	 	31	 	 	 	—	 	
Itiquira Energetica S.A., due January 2012	 	 	(1	)	 	 	—	 	 	 	19	 	 	 	—	 	 	 	20	 	 	 	—	 	
Capital leases:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Saale Energie GmbH, Schkopau capital lease, due 2021	 	 	(1	)	 	 	—	 	 	 	214	 	 	 	—	 	 	 	304	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Subtotal	 	 	 	 	 	 	 	 	 	 	2,740	 	 	 	(58	)	 	 	3,523	 	 	 	(39	)	
Less current maturities	 	 	 	 	 	 	 	 	 	 	108	 	 	 	(7	)	 	 	508	 	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total	 	 	 	 	 	 	 	 	 	$	2,632	 	 	$	(51	)	 	$	3,015	 	 	$	(42	)	

 	 	
(1) 	Distinguishes debt with various interest rates.	
 	 	
(2) 	L+ equals LIBOR plus x%	
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(3) 	Fair value adjustment as of December 31, 2004 and December 31, 2005 reflects $16 million reduction and $20 million reduction, respectively, for an interest rate swap. In addition, the balances as of December 31, 2004 and December 31, 2005 reflect unamortized bond premium of $26 million and $14 million, respectively.	
 	 	
(4) 	$645 million in bonds have been redeemed or repurchased and retired in 2005.	
     As a result of adopting Fresh Start on December 6, 2003, the fair value of long-term debt was calculated using the indicated effective interest rates which approximate market rates. The fair value adjustments for these notes and capital leases are amortized into interest expense using the effective interest rate method. A fair value adjustment was not necessary for the senior notes and the credit facility as both of these obligations were entered into subsequent to Fresh Start. For those notes and capital leases where market pricing was not available, we used carrying amounts, which we believe approximated the market values as of December 6, 2003.
      As of December 31, 2005, we have timely made scheduled payments on interest and/or principal on all of our recourse debt and were not in default under any of our related recourse debt instruments. Additionally, we are not in default on any obligations to post collateral.
 	 	
 	Senior Securities	
      On December 23, 2003, we issued $1.25 billion in 8% Second Priority Notes, due and payable on December 15, 2013. On January 28, 2004, we issued an additional $475.0 million in Second Priority Notes, under the same terms and indenture as our December 23, 2003 offering.
      When we issued the Second Priority Senior Secured Notes in December 2003, we entered into a Registration Rights Agreement with the purchasers of the Notes. Under the Registration Rights Agreement, we were required to file a Registration Statement with the SEC by May 21, 2004 (150 days after the issuance of the Notes) to permit the bonds to be publicly traded. When we did not meet this deadline, we were required to accrue liquidated damages, starting May 22, 2004 until the exchange was executed, which happened on June 14, 2005. In 2005, we made payments for liquidated damages totaling approximately $7 million. Accrued but unpaid liquidated damages were $0 and approximately $1 million as of December 31, 2005 and 2004, respectively.
      During the first quarter of 2005, we used existing cash to purchase, at market prices, approximately $41 million in face value of our Second Priority Notes. These notes were subsequently retired. On February 4, 2005, we redeemed $375 million in Second Priority Notes. At the same time, we paid $30 million for the early redemption premium, approximately $4 million in accrued but unpaid interest and $0.4 million in accrued but unpaid liquidated damages on the redeemed notes. On September 12, 2005, we redeemed approximately $229 million in Second Priority Notes and paid approximately $18 million for the early redemption premium and $4 million in accrued but unpaid interest.
      On December 15, 2005, we commenced a tender offer for all the outstanding Second Priority Notes. On December 30, 2005 we amended the indenture relating to the Second Priority Notes to remove many covenant restrictions, including the incurrence of additional indebtedness, having received the necessary consents from holders of the Second Priority Notes. Those holders who validly tendered their Second Priority Notes by February 2, 2006 were eligible to receive the tender offer consideration. On February 2, 2006 we closed our offer to purchase all outstanding Second Priority Notes. All but approximately $0.4 million aggregate principal amount of Second Priority Notes were tendered in such offer. The same day, we effected a covenant defeasance of our remaining Second Priority Notes by placing approximately $0.5 million in escrow with the trustee of the Second Priority Notes for payment in full on amounts due with respect to the non-tendered notes through the earliest redemption date, December 15, 2008. As a result of the defeasement, liens held by the remaining holders were released and all covenant obligations under these notes were extinguished; however, the subsidiary guarantees supporting our obligations under the Second Priority Notes remain.

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      The Second Priority Notes were refinanced on February 2, 2006 with new Senior Unsecured Notes which are described in Note 34 — Subsequent Events. As of December 31, 2005 and March 3, 2006, we had $1.08 billion and $0 in Second Priority Notes outstanding, respectively.
      The Second Priority Notes were general obligations of ours. They were secured on a second-priority basis by security interests in all assets of ours, with certain exceptions, subject to the liens securing our obligations under the Amended Credit Agreement (described below) and any other priority lien debt. The notes were effectively subordinated to our obligations under the Amended Credit Facility and any other priority lien obligation. The Second Priority Notes were senior in right of payment to any future subordinated indebtedness. Interest on the Second Priority Notes accrued at the rate of 8.0% per annum and was payable semi-annually in arrears on June 15 and December 15, commencing on June 15, 2004. Accrued but unpaid interest was approximately $4 million and $6 million as of December 31, 2005 and 2004, respectively.
      As of December 31, 2005, we had an interest rate swap in place to exchange fixed-rate interest payments for floating-rate interest payments. This swap agreement became effective March 26, 2004 and terminates December 15, 2013. The swap agreement has provisions for early termination that are linked to any prepayment of the Second Priority Notes. As of February 25, 2006, this swap agreement remains outstanding. Under the agreement, we agree to pay semi-annually in arrears, commencing June 15, 2004, a floating interest rate on a notional amount of $400 million, and receive semi-annually in arrears a fixed interest rate payment on the same notional amount. The floating interest rate is based upon six-month LIBOR plus a spread. Depending on market interest rates, we or the swap counter-party may be required to post collateral on a daily basis in support of this swap, to the benefit of the other party. On December 31, 2005 and as of March 3, 2006, we had approximately $5 million and $13 million in collateral posted.
      On December 23, 2003 we and PMI entered into a Credit Facility for up to $1.45 billion with Credit Suisse, as Administrative Agent, Lehman Commercial Paper, Inc., as Syndication Agent and a group of lenders. The Credit Facility was amended on December 24, 2004 to consist of a $450 million senior secured term loan facility maturing December 24, 2011, a $350 million funded letter of credit facility maturing December 24, 2011, and a revolving credit facility in an amount up to $150 million, maturing December 24, 2007 (the “Amended Credit Facility”). The Amended Credit Facility was further amended on August 5 and December 27, 2005 to remove certain covenants restricting the incurrence and repayment of indebtedness. The balance outstanding under this facility was approximately $796 million as of December 31, 2005. 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, 2005, the $350 million letter of credit facility was fully funded and reflected as a funded letter of credit on the December 31, 2005 balance sheet. As of December 31, 2005, approximately $312 million in letters of credit had been issued under this facility, leaving approximately $38 million available for future issuances. Most of these letters of credit are issued in support of our obligations to perform under commodity agreements, financing or other arrangements. These letters of credit expire within one year of issuance, and it is not unusual for us to renew many of them on similar terms.
      On September 22 and 23, 2005, we borrowed $80 million and $40 million, respectively, under our revolving credit facility to support working capital obligations. These borrowings were repaid on September 26 and October 26, 2005. As of December 31, 2005, we had no borrowings outstanding under the revolving credit facility.
      On January 31, 2006, we repaid the outstanding principal balance of approximately $446 million, along with accrued but unpaid interest of approximately $2 million, under the term loan facility and terminated that facility. On February 2, 2006, we paid accrued but unpaid fees on our revolving credit facility and our funded letter of credit facility, and terminated those facilities. The facilities were replaced by new financing arrangements as of February 2, 2006. An interim arrangement has been made with Credit Suisse, such that

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letters of credit issued under the Amended Credit Facility will be retained at Credit Suisse until they are transferred to the letter of credit facility under the New Credit Agreement. In lieu of credit-linked deposits, we have issued to the benefit of Credit Suisse a letter of credit under our new funded letter of credit facility. The new credit facilities are described in Note 34 — Subsequent Events.
      The Amended Credit Facility was secured by, among other things, first-priority perfected security interests in all of the property and assets owned at any time or acquired by us and our subsidiaries, other than the property and assets of certain excluded project subsidiaries, foreign subsidiaries and certain other subsidiaries, with some exceptions. The Amended Credit Facility bore interest at an interest rate of 1.875% over LIBOR, which was 4.39% as of December 31, 2005. As of December 31, 2005, we had an interest rate swap in place to hedge against fluctuations in floating interest rates. The swap agreement became effective March 26, 2004 and terminates March 31, 2006. Under the agreement, we agree to pay quarterly a fixed-rate interest payment on a notional amount of $400 million, commencing on March 31, 2004, and receive quarterly a floating-rate interest rate payment on the same notional amount. The floating rate is based upon three-month LIBOR, subject to a floor.
      On December 5, 2003, we entered into a $10 million promissory note with Xcel Energy. The note accrues interest at a rate of 3% per year, payable quarterly in arrears. All principal is due at maturity on June 5, 2006.
      See Note 34 — Subsequent Events for information related to recent financing activities related to the acquisition of Texas Genco.
      Financing commitments — As discussed in Note 34, we financed the Acquisition through a combination of a senior secured credit facility, unsecured high yield notes and the sale of common and preferred equity securities in the public markets. As of December 31, 2005 we had received a commitment letter from Morgan Stanley Senior Funding, Inc., or Morgan Stanley, and Citigroup Global Markets, Inc., or Citigroup, to provide us with up to $4.8 billion in senior secured debt financing, including up to $3.2 billion under a senior first priority term loan facility, up to $600 million under a senior first priority secured revolving credit facility and up to $1 billion under a senior first priority secured synthetic letter of credit facility. The commitment letter further provided for up to $5.1 billion in bridge financing to fund all necessary amounts not provided for under the senior secured debt financing. This commitment letter was necessary if for some reason any of the planned financings were unavailable at the time of the closing. The commitment letter was subject to customary conditions to consummation, including the absence of any event or circumstance that would have a material adverse effect on the business, assets, properties, liabilities, condition (financial or otherwise) or results of operations, taken as a whole, of Texas Genco, or Texas Genco and NRG combined, since June 30, 2005. During the fourth quarter of 2005 we paid a fee of approximately $45 million for this commitment and were amortizing it over the commitment period. However, as all the financings have been completed without utilizing this commitment letter, we have expensed the remaining amount subsequent to the completion of the financings and Acquisition, during February of 2006.
Project Financings
      The following are descriptions of certain indebtedness of NRG’s project subsidiaries that remain outstanding on December 31, 2005. The indebtedness described below is non-recourse to NRG, unless otherwise described.
 	 	
 	Peakers	
      In June 2002, NRG Peaker Financing LLC, or Peakers, an indirect wholly-owned subsidiary, issued $325 million in floating rate bonds due June 2019. Peakers subsequently swapped such floating rate debt for fixed rate debt at an all-in cost of 6.67% per annum. Principal, interest, and swap payments are guaranteed by XL Capital Assurance, or XLCA, through a financial guaranty insurance policy. Such notes are also secured

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by, among other things, substantially all of the assets of and membership interests in Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG Rockford II LLC and NRG Rockford Equipment LLC (all subsidiaries of NRG). As of December 31, 2005, approximately $297 million in principal remained outstanding on these bonds. In January 2004, terms of the financing arrangement were restructured, at which time we issued approximately $36 million letter of credit, under our corporate funded letter of credit facility to the Peakers’ Collateral Agent. The letter of credit may be drawn if the project is unable to meet principal or interest payments. There are no provisions requiring us to replenish the letter of credit if it is drawn.
 	 	
 	Flinders	
      In February 2005, NRG Flinders amended its debt facility of approximately AUD 279 million (approximately US $219 million) in floating-rate debt. The amendment extended the maturity to February 2017, reduced borrowing costs and reserve requirements, reduced 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 million) working capital and performance bond facility, under which approximately AUD 12 million (approximately US $9 million) in performance bonds and letters of credit have been issued as of December 31, 2005. An interim arrangement to indemnify the Australia New Zealand Bank, or ANZ, of up to approximately AUD 16 million was terminated on May 17, 2005. 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. During the year, Flinders made approximately AUD 61 million optional prepayments, approximately AUD 18 million of mandatory repayments and AUD 61 million of re-borrowings. As of December 31, 2005, AUD 241 million (approximately US $177 million) was outstanding.
 	 	
 	NRG Thermal	
      NRG Thermal LLC, or NRG Thermal, has two subsidiaries with outstanding long-term debt. Such indebtedness is secured principally by the subsidiaries’ long-term assets and is guaranteed by NRG Thermal and “cross-collateralized” by NRG Thermal’s ownership interests in all of its subsidiaries. In July 2002, NRG Energy Center Minneapolis LLC issued $55 million of 7.25% Series A notes due August 2017, of which approximately $48 million remained outstanding as of December 31, 2005; $20 million of 7.12% Series B notes due August 2017, of which approximately $17 million remained outstanding as of December 31, 2005; and in August 1993, NRG Energy Center Minneapolis LLC issued $84 million of 7.31% senior secured notes due June 2013, of which approximately $46 million remained outstanding as of December 31, 2005. NRG Energy Center San Francisco LLC has issued $360 thousand of 7.63% senior secured term notes due September 2008, of which approximately $0.1 million remained outstanding at December 31, 2005.
 	 	
 	Camas	
      In November 1990, Clark County, Washington issued $15 million in aggregate principal amount of 7.2% fixed interest Series A tax-exempt bonds due August 15, 2007 to fund the construction of the Camas project. The bonds were re-marketed with a 4.65% interest rate in August 1997 and again at a 3.375% interest rate in August 2002. This facility, pursuant to the indenture, can no longer be re-marketed. As of December 31, 2005, approximately $3 million remains outstanding. In 1997, Camas also acquired approximately $20 million floating-rate bank loan from Fort James Corporation, maturing in June 2007. The principal outstanding on this facility was approximately $4 million as of December 31, 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 	 	
 	Itiquira Energetica S.A.	
      On July 15, 2004, Itiquira Energetica S. A., a majority-owned subsidiary of ours, executed a long-term financing arrangement with Uniăo de Bancos Brasilieros S.A., or Unibanco, for a 55 million Brazilian Reals term loan maturing in January 2012. The facility bears a floating interest rate and amortizes on a schedule that is indexed to certain foreign exchange rates. The principal obligation as of December 31, 2005 was approximately $19 million. Eletrobrăs owns preferred shares in Itiquira, which for U.S. GAAP purposes are reflected as debt. The preferred shares accrue cumulative dividends of 12% per year, payable only at such time Itiquira has sufficient retained profits or reserves. The balance at December 31, 2005 was approximately $30 million.
 	 	
 	Capital Leases	

 	Saale Energie GmbH	
      Saale Energie GmbH, or SEG, an NRG subsidiary, has a 41.9% participation in the Schkopau Power Plant, or Schkopau, through our interest in the Kraftwerke Schkopau GbR, KSGbR, partnership. Under the terms of a Use and Benefit fee Agreement, SEG and the other partner to the project, E.ON Kraftwerke GmbH, are required to fund debt service and certain other costs resulting from the construction and financing of Schkopau. The Use and Benefit Fee Agreement is treated as a capital lease under US GAAP. Calls for funds are made to the partners based on their participation interest as cash is needed. The KSGbR issued debt to fund Schkopau pursuant to multiple facilities totaling approximately €887 million (approximately US $1.2 billion). As of December 31, 2005, approximately €362 million (approximately US $428 million) remained outstanding at Schkopau. Interest on the individual loans accrues at fixed rates averaging 5.68% per annum, with maturities occurring between years 2006 and 2015. The lenders to the project rely almost exclusively on the creditworthiness of E.ON Kraftwerke GmbH. SEG remains liable to the lenders as a partner in KSGbR, but there is no recourse to NRG. As of December 31, 2005 the capital lease obligation at SEG was approximately $214 million.
Consolidated annual maturities and future minimum lease payments:
      Annual maturities of long-term debt and capital leases for the years ending after December 31, 2005 are as follows:
 	 	 	 	 	 	
 	 	Total	 	
 	 	 	 	
 	 	(In millions)	 	
2006	 	$	108	 	
2007	 	 	82	 	
2008	 	 	66	 	
2009	 	 	65	 	
2010	 	 	71	 	
Thereafter	 	 	2,348	 	
 	 	 	 	
 	Total	 	$	2,740	 	
 	 	 	 	
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      Future minimum lease payments for capital leases included above at December 31, 2005 are as follows:
 	 	 	 	 	 	
 	 	(In millions)	 	
2006	 	$	77	 	
2007	 	 	48	 	
2008	 	 	42	 	
2009	 	 	33	 	
2010	 	 	19	 	
Thereafter	 	 	187	 	
 	 	 	 	
 	Total minimum obligations	 	 	406	 	
Interest	 	 	192	 	
 	 	 	 	
Present value of minimum obligations	 	 	214	 	
Current portion	 	 	61	 	
 	 	 	 	
Long-term obligations	 	$	153	 	
 	 	 	 	
Note 18 — Capital Structure
 	 	
 	Common Stock	
      In connection with the consummation of our reorganization, on December 5, 2003, all shares of our old common stock were canceled and 100 million shares of new common stock of NRG 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. . In the event our disputed claims reserve is inadequate, it is possible we would have to issue additional shares of our common stock to satisfy such pre-petition claims or contribute additional cash proceeds.
      Our authorized common stock consists of 500 million shares of NRG common stock. Common stock shares issued as of December 31, 2005 and 2004 were 100,048,676 and 100,041,935, respectively at a par value of $1 million. Common stock shares outstanding as of December 31, 2005 and 2004 were 80,701,888 and 87,041,935, respectively. A total of 4,000,000 shares of our common stock are available for issuance under our long — term incentive plan.
 	 	
 	Treasury Stock	
      As of December 31, 2005 and 2004, the NRG Energy common stock shares repurchased by the company were 19,346,788 and 13,000,000, respectively, at a cost of $664 million and $405 million, respectively.
      Upon emergence from chapter 11, investment partnerships managed by MatlinPatterson LLC owned approximately 21.5 million (21.5%) of our common shares. In December 2004, we used existing cash to repurchase 13 million shares of common stock from MatlinPatterson at a purchase price of $31.16 per share plus transaction costs of $0.2 million. 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 of NRG Energy 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.
      On August 11, 2005, we entered into an Accelerated Share Repurchase Agreement with CSFB, pursuant to which we repurchased $250 million of our common stock on that date that equaled a total of 6,346,788 shares, which were held in treasury. We funded the repurchase with cash on hand. On March 3,

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2006, we paid to CSFB a cash purchase price adjustment of approximately $7 million based upon the weighted average value of NRG’s common stock over a period of approximately six months, subject to a minimum price of 97% and a maximum price of 103% of the closing price per share on August 10, 2005, or $39.39.
      On February 2, 2006, we delivered to the Sellers all of the shares of common stock held in treasury as part of the consideration for the Texas Genco Acquisition. Also see Note 34 Subsequent Events.
 	 	
 	Preferred Stock	
      At December 31, 2005, our authorized amount of preferred stock is 10,000,000 shares. As of December 31, 2005, our preferred stock consists of two series, the 4% Convertible Perpetual Preferred Stock, or 4% Preferred Stock and the 3.625% Convertible Perpetual Preferred Stock, which is treated as Redeemable Preferred Stock, or 3.625% Preferred Stock.
 	 	
 	4% Preferred Stock	
      As of December 31, 2005 and 2004, 420,000 shares of the 4% Preferred Stock were issued and outstanding at a liquidation value, net of issuance costs of $406 million. The 4% Preferred Stock has a liquidation preference of $1,000 per share of 4% Preferred Stock. Holders of the 4% Preferred Stock are entitled to receive, when declared by our Board of Directors, 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 4% 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 a conversion rate of 25 shares of common stock per share of the 4% Preferred Stock, subject to specified adjustments. On or after December 20, 2009, we may redeem, subject to certain limitations, some or all of the 4% 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.
      If we are subject to a fundamental change, as defined in the Certificate of Designation of the 4% Convertible Perpetual Preferred Stock, each holder of shares of the 4% Preferred Stock has the right, subject to certain limitations, to require us to purchase any or all of its shares of Preferred Stock at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends, including liquidated damages, if any, to the date of purchase. Final determination of a fundamental change must be approved by the Board of Directors.
      Each holder of the 4% Preferred Stock has one vote for each share of the 4% Preferred Stock held by the holder on all matters voted upon by the holders of our common stock, as well as voting rights specifically provided for in our amended and restated certificate of incorporation or as otherwise from time to time required by law. In addition, whenever (1) dividends on the 4% Preferred Stock or any other class or series of stock ranking on a parity with the 4% Preferred Stock with respect to the payment of dividends are in arrears for dividend periods, whether or not consecutive, containing in the aggregate a number of days equivalent to six calendar quarters, or (2) we fail to pay the redemption price on the date shares of the 4% Preferred Stock are called for redemption or the purchase price on the purchase date for shares of the 4% Preferred Stock following a fundamental change, then, in each case, the holders of the 4% Preferred Stock (voting separately as a class with all other series of preferred stock upon which like voting rights have been conferred and are exercisable) are entitled to vote for the election of two of the authorized number of our directors at the next annual meeting of stockholders and at each subsequent meeting until all dividends accumulated or the redemption price on the Preferred Stock have been fully paid or set apart for payment. The term of office of all directors elected by holders of the Preferred Stock terminates immediately upon the termination of the rights of the holders of the 4% Preferred Stock to vote for directors. Upon election of any additional directors, the

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number of directors that comprise our Board of Directors will be increased by the number of such additional directors.
      The 4% Preferred Stock is, with respect to dividend rights and rights upon liquidation, winding up or dissolution: junior to all of our existing and future debt obligations; junior to each other class or series of our capital stock other than (1) our common stock and any other class or series of our capital stock which provides that such class or series will rank junior to the 4% Preferred Stock and (2) any other class or series of our capital stock the terms of which provide that such class or series will rank on a parity with the 4% Preferred Stock; on a parity with any other class or series of our capital stock the terms of which provide that such class or series will rank on parity with the 4% Preferred Stock; senior to our common stock and any other class or series of our capital stock the terms of which provide that such class or series will rank junior to the 4% Preferred Stock; and effectively junior to all of our subsidiaries (1) existing and future liabilities and (2) capital stock held by others.
      The proceeds of $406 million net of issuance costs of approximately $14 million were primarily used to redeem $375 million of Second Priority Notes on February 4, 2005.
      During the year ended December 31, 2005, we made $17 million of dividend payments to our 4% Preferred Stock shareholders.
 	 	
 	Redeemable Preferred Stock	
      On August 11, 2005, we issued 250,000 shares of 3.625% Preferred Stock, which is treated as Redeemable Preferred Stock, to Credit Suisse First Boston Capital LLC, or CSFB, in a private placement. As of December 31, 2005, 250,000 shares of the 3.625% Preferred Stock were issued and outstanding at a liquidation value, net of issuance costs of $246 million. The 3.625% Preferred Stock is recorded based on the proceeds of $250 million net of issuance costs of $4 million. This amount will be accreted over a 10 year period to the redemption value of $250 million. The 3.625% Preferred Stock amount is located after the Liabilities but before the Stockholders’ Equity section on the Balance Sheet as of December 31, 2005, due to the fact that the preferred shares can be redeemed in cash by the shareholder.
      The 3.625% Preferred Stock has a liquidation preference of $1,000 per share. Holders of the 3.625% Preferred Stock are entitled to receive, out of funds legally available, cash dividends at the rate of 3.625% per annum, payable in cash quarterly in arrears commencing on December 15, 2005. Each share of 3.625% Preferred Stock is convertible during the 90-day period beginning August 11, 2015 at the option of NRG or the holder. Holders tendering the 3.625% Preferred Stock for conversion shall be entitled to receive, for each share of 3.625% Preferred Stock converted, $1,000 in cash and a number of shares of Common Stock equal to the product of (x) the greater of (i) the difference between the average of the closing sale price of the Common Stock on each of the 20 consecutive scheduled trading days starting on the date 30 scheduled exchange business days immediately prior to the conversion date, or the Market Price, and $59.085 and (ii) zero, times (y) 25.38715. The number of Common Stock shares to be delivered under the conversion feature is limited to 8,000,000 shares. If upon conversion, the Market Price is less than $39.39, then the Holder will deliver to NRG cash or a number of shares of Common Stock equal in value to the product of (A) $39.39 minus the Market Price, times (B) 25.38715. We may elect to make a cash payment in lieu of delivering shares of common stock in connection with such conversion, and we may elect to receive cash in lieu of shares of common stock, if any, from the Holder in connection with such conversion. If a fundamental change occurs, the holders will have the right to require us to repurchase all or a portion of the 3.625% Preferred Stock for a period of time after the fundamental change at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends. The 3.625% Preferred Stock are senior to all classes of common stock, on a parity with our 4% Preferred Stock and junior to all of our existing and future debt obligations and all of our subsidiaries’ existing and future liabilities and capital stock held by persons other than NRG or our subsidiaries. The proceeds from issuing the 3.625% Preferred Stock were used to

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redeem $229 million of Second Priority Notes on September 12, 2005. During the year ended December 31, 2005, we made $3 million of dividend payments to our 3.625% Preferred Stock shareholders. See Note 34 — Subsequent Events for information related to recent equity transactions related to the acquisition of Texas Genco.
Note 19 — Stock-Based Compensation
 	 	
 	Incentive Compensation Plans	
      Effective January 1, 2003, we adopted the fair value recognition provisions of SFAS 123. In accordance with SFAS 148, we adopted SFAS 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. In December 2004, the FASB issued a revision to SFAS 123, or SFAS 123(R) which requires us to recognize expense for stock — based compensation in the statement of income and is effective for us on January 1, 2006. We do not expect the provisions of SFAS 123(R) to result in a significant change in the compensation expense we currently recognize in our statements of income under SFAS 123.
      During 2005, 2004 and 2003, in accordance with SFAS 123, we recognized approximately $12 million, $14 million and $0, respectively, of stock based compensation expense under the Long-Term Incentive Plan (as described below) as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2005	 	 	2004	 	 	2003	
 	 	 	 	 	 	 	 	 	
 	 	(In millions)	
Non qualified stock options	 	$	     4	 	 	$	     7	 	 	$	     —	 	
Restricted stock units	 	 	7	 	 	 	5	 	 	 	—	 	
Deferred stock units	 	 	1	 	 	 	2	 	 	 	—	 	
Performance units	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
 	Total	 	$	     12	 	 	$	     14	 	 	$	     —	 	
 	 	 	 	 	 	 	 	 	 	
      In December 2003, we adopted a new long-term incentive plan, or the Long-Term Incentive Plan, which is described below.
 	 	
 	Long-Term Incentive Plan	
      The Long-Term Incentive Plan became effective upon our emergence from bankruptcy and was also approved by our stockholders on August 4, 2004. The Long-Term Incentive Plan provides for grants of non-qualified stock options, restricted stock units, performance units, deferred stock units, stock appreciation rights and dividend equivalent rights, collectively referred to as Awards. Our directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by us, are eligible to receive grants under the Long-Term Incentive Plan. The purpose of the Long-Term 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.
      A total of 4,000,000 shares of our common stock are available for issuance under the Long-Term Incentive Plan, subject to adjustment in the event of a reorganization, recapitalization, stock split, reverse stock split, stock dividend, and combination of shares, merger or similar change in our structure or our outstanding shares of common stock. There were 1,355,193 and 2,053,294 shares of common stock remaining available for grants of Awards under our Long-Term Incentive Plan as of December 31, 2005 and 2004, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The Compensation Committee of our Board of Directors administers the Long-Term Incentive Plan. If for any reason a Compensation Committee has not been appointed by our board to administer the Long-Term Incentive Plan, our Board of Directors has the authority to administer the plan and to take all actions under the plan.
      The following is a summary of the material terms of the Long-Term Incentive Plan related to the Awards outstanding as of December 31, 2005. Unless otherwise noted, these terms are applicable to all Awards:
      Eligibility. Our directors, officers and employees, as well as other individuals performing services for us are eligible to receive grants under the Long-Term Incentive Plan.
      Exercise price and payment — The Compensation Committee determines the exercise price of any Award granted, typically the fair market value of a share of our common stock on the date of grant. In general, the exercise price of any NQSO may be paid by the holder, in any of the following ways:
 	 	 	
 	• 	in cash;	
 	 	 	
 	• 	by delivery of shares of common stock with a fair market value equal to the exercise price;	
 	 	 	
 	• 	by means of any cashless exercise procedure approved by the Compensation Committee; or	
 	 	 	
 	• 	by any combination of the foregoing.	
      Term — The Compensation Committee determines the term of each Award, however, no term may exceed 10 years from the date of grant. In addition, all Awards generally cease vesting when a grantee ceases to be a director, officer or employee of, or to otherwise perform services for us. Vested Awards generally expire 90 days after the date of cessation of service. There are exceptions depending upon the circumstances such as the case of a grantee’s death, termination due to disability and retirement, where the grantee’s vested Awards remain exercisable for a period of one to two years
      Change of control — Upon a change in control of NRG, all of the Awards become fully vested and remain exercisable until their expiration date. In addition, the Compensation Committee has the authority to grant Awards that become fully vested and exercisable automatically upon a change in control, whether or not the grantee is subsequently terminated.
 	 	
 	Vesting, Withholding Taxes and Transferability of All Awards —	

 	• 	Awards will vest over a period of not less than six months of the date of grant.	
 	 	 	
 	• 	Participants may elect to deliver shares of common stock, or to have us withhold shares of common stock deliverable upon vesting or exercise, in order to satisfy our tax withholding obligations.	
 	 	 	
 	• 	Awards are not transferable other than by will or the laws of descent and distribution.	
 	 	 	
 	• 	Awards may be exercised only by the grantee or his or her executor, administrator, guardian or legal representative, or by a family member of the grantee if he or she has acquired the award by gift or qualified domestic relations order.	
      Amendment and Termination of the Long-Term Incentive Plan. The Board of Directors or the Compensation Committee may amend or terminate the Long-Term Incentive Plan in its discretion, except that no amendment is effective without prior approval of our stockholders if approval is required by applicable law or regulations, including any NASDAQ or stock exchange listing requirements, if the amendment would remove a provision of the Long-Term Incentive Plan which, without giving effect to the amendment, is subject to shareholder approval or if the amendment would directly or indirectly increase the share limit of 4,000,000 shares. If not otherwise terminated, the Long-Term Incentive Plan terminates on the tenth anniversary of the effective date of our plan of reorganization, which was December 5, 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 	 	
 	The following types of Awards are issued and outstanding as of December 31, 2005:	
      Stock Options. The Compensation Committee may award grants of non-qualified stock options conforming to the requirements of Section 422 of the Internal Revenue Code, or NQSO’s. The Compensation Committee may not award to any one person in any calendar year NQSO’s to purchase more than 1,000,000 shares of common stock. In addition, it may not award NQSO’s first exercisable in any calendar year whose underlying shares have a fair market value greater than $100,000, determined at the time of grant.
      Restricted Stock Units. The Compensation Committee may award restricted stock units, or RSU’s, in the amounts that it determines in its discretion. Each grant of RSU’s is evidenced by a grant agreement, which specifies the applicable restrictions on such shares and the duration of the restrictions (which is generally at least six months). A grantee is required to pay us at least the aggregate par value of any shares of RSU’s within ten days of the grant, unless the shares are treasury shares.
      Performance Units. The Compensation Committee may grant performance units, or PU’s, contingent upon achievement by the grantee, us or any of our divisions of specified performance criteria, such as return on equity over a specified performance cycle, fair market value of common stock at a specified target date, or other criteria as determined by the Compensation Committee. A performance award may be paid out in cash, shares of our common stock or our other securities.
      Deferred Stock Units. The Compensation Committee may grant deferred stock units, or DSU’s, from time to time in its discretion. A DSU entitles the grantee to receive the fair market value of one share of common stock at the end of the deferral period, which is no less than one year. The payment of the value of DSU’s may be made by us in shares of our common stock, cash or both.
 	 	
 	Stock Options	
      In 2005, we issued NQSO’s for a total of 134,000 shares of common stock under the Long-Term Incentive Plan. These NQSO’s have a three-year graded vesting schedule and become exercisable through the year 2008 at an exercise price of $38.80 and an estimated fair value of $13.22. During 2005, 1,500 NQSO’s with an exercise price of $38.80 and an estimated fair value of $13.22 were canceled. Total compensation expense under all NQSO’s grants is approximately $13 million. Compensation expense for the years ended December 31, 2005 and 2004 was approximately $4 million and $7 million, respectively. Compensation expense for the year ended December 31, 2006, will be approximately $2 million. Compensation expense for the years 2007 and 2008 is expected to be immaterial. At December 31, 2005, 531,834 employee NQSO’s were exercisable. The following table summarizes NQSO transactions:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted-	 	
 	 	 	 	 	 	Average	 	
 	 	 	 	Exercise Price Range	 	 	Exercise	 	
 	 	Shares	 	 	per Share	 	 	Price	 	
 	 	 	 	 	 	 	 	 	 	
Outstanding at December 6 and December 31, 2003	 	 	632,751	 	 	$	24.03	 	 	$	24.03	 	
Granted	 	 	330,000	 	 	$	19.90 - $31.48	 	 	$	21.46	 	
 	 	 	 	 	 	 	 	 	 	
Outstanding at December 31, 2004	 	 	962,751	 	 	$	19.90 - $31.48	 	 	$	23.15	 	
Granted	 	 	134,000	 	 	$	38.80	 	 	$	38.80	 	
Canceled or expired	 	 	(1,500	)	 	$	38.80	 	 	$	38.80	 	
 	 	 	 	 	 	 	 	 	 	
Outstanding at December 31, 2005	 	 	1,095,251	 	 	$	19.90-38.80	 	 	$	25.04	 	
 	 	 	 	 	 	 	 	 	 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The following table summarizes information about stock options outstanding at December 31, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Options Outstanding	 	 	 	
 	 	 	 	 	 	 	Options Exercisable	 	
 	 	 	 	Weighted-	 	 	 	 	 	 	
 	 	 	 	Average	 	 	Weighted-	 	 	 	 	Weighted-	 	
 	 	 	 	Remaining	 	 	Average	 	 	 	 	Average	 	
 	 	Total	 	 	Life (In	 	 	Exercise	 	 	Total	 	 	Exercise	 	
Range of exercise prices	 	Outstanding	 	 	Years)	 	 	Price	 	 	Exercisable	 	 	Price	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
$19.90 - $22.24	 	 	307,000	 	 	 	3.2	 	 	$	20.92	 	 	 	102,333	 	 	$	20.92	 	
$24.03 - $31.48	 	 	655,751	 	 	 	7.9	 	 	$	24.20	 	 	 	429,501	 	 	$	24.11	 	
$38.80	 	 	132,500	 	 	 	4.6	 	 	$	38.80	 	 	 	—	 	 	 	—	 	
      The fair value of the stock option grants were estimated on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2005	 	 	2004	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	
Dividends per year	 	 	—	 	 	 	—	 	 	 	—	 	
Expected volatility	 	 	29.75	%	 	 	51.05	%	 	 	35.70	%	
Risk-free interest rate	 	 	4.16	%	 	 	3.06	%	 	 	4.24	%	
Expected life (years)	 	 	5	 	 	 	5	 	 	 	10	 	
Fair value	 	$	13.22	 	 	$	10.20	 	 	$	13.17	 	

 	Restricted Stock Units	
      As of December 31, 2005, RSU’s issued and outstanding totaled 1,285,944. These units fully vest between three and five years from the date of issuance. Total compensation expense attributable to the RSU’s is approximately $35 million. During the year ended December 31, 2005, we issued 473,850 RSU’s at fair values between $33.43 and $38.80 per unit, cancelled 66,250 RSU’s at fair values between $19.90 and $38.80 per unit and issued 1,642 shares of common stock, net of common stock withheld for payroll taxes, due to accelerated vesting on 2,650 RSU’s. Compensation expense for the years ended December 31, 2005 and 2004 was approximately $7 million and $5 million, respectively. Compensation expense for the years ended December 31, 2006, December 31, 2007, and December 31, 2008 will be approximately $12 million, $7 million and $3 million, respectively. The fair value of the RSU’s is based on the closing price of our common stock on the date of grant. The weighted-average fair value of our RSU’s outstanding as of December 31, 2005 is $27.14.
 	 	
 	Deferred Stock Units	
      As of December 31, 2005, DSU’s issued and outstanding totaled 122,184. During 2005, we issued 68,201 DSU’s. The fair values of the DSU’s issued during 2005 were between $34.72 and $41.05 per unit. These units are fully vested at the date of issuance. During the year ended December 31, 2005, we issued 5,099 shares of common stock, net of common stock withheld for payroll taxes, due to the conversion of 6,298 DSU’s at fair values between $19.95 and $37.85 per unit. Total compensation expense attributable to the DSU grants is approximately $3 million. Compensation expense for the years ended December 31, 2005 and 2004 was approximately $1 million and $2 million, respectively. The fair value of the DSU’s is based on the closing price of our common stock on the date of grant. The weighted-average fair value of our DSU’s outstanding as of December 31, 2005 is $29.21

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 	 	
 	Performance Units	
      In August 2005, we issued 45,900 PU’s. Each performance unit will be paid out on August 1, 2008 if the Measurement Price, that is the average closing price of NRG’s common stock for the ten trading days prior to August 1, 2008, is equal to or greater than $54.50. The payout for each performance unit will be equal to: (i) one share of common stock, if the Measurement Price equals the Target Price; (ii) a pro-rated amount in between one and two shares of common stock, if the Measurement Price is greater than the Target Price but less than the Maximum Price of $63.75; and (iii) two shares of common stock, if the Measurement Price is equal to or greater than the Maximum Price.
      The fair value of the PU’s were estimated on the date of grant using the Monte Carlo valuation model, with the following weighted average assumptions:
 	 	 	 	 	
 	 	Performance Units	 	
 	 	 	 	
Dividends per year	 	 	—	 	
Expected volatility	 	 	29.75	%	
Risk free interest rate	 	 	4.09	%	
Expected life of PU’s (in years)	 	 	3	 	
Fair value	 	$	29.87	 	
      As of December 31, 2005, PU’s outstanding totaled 44,900. During 2005, 45,900 PU’s were issued and 1,000 PU’s were canceled. Total compensation expense attributable to the PU’s issued is approximately $1 million.
Note 20 — Earnings Per Share
      Basic earnings per common share were computed by dividing net income less accumulated preferred stock dividends by the weighted average number of common stock shares outstanding. Shares issued during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.
      Dilutive effect for equity compensation — The outstanding non-qualified stock options, non-vested restricted stock units, deferred stock units and performance units are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator for purposes of computing diluted earnings per share under the treasury stock method or the if-converted method. The dilutive effect of the potential exercise of outstanding non-qualified stock options, non-vested restricted stock units and performance units is calculated using the treasury stock method. The dilutive effect of the deferred stock units are included in the denominator for purposes of computing diluted earnings per share under the if-converted method.
      Dilutive effect for other equity instruments — The outstanding 4% Preferred Stock and 3.625% Preferred Stock are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator for purposes of computing diluted earnings per share under the if-converted method.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	
 	 	December 31, 2005	 	 	December 31, 2004	 	 	December 31, 2003	 	
 	 	 	 	 	 	 	 	 	 	
 	 	(In millions, except per share data)	 	
Basic earnings per share	 	 	 	 	 	 	 	 	 	 	 	 	
Numerator:	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	77	 	 	$	161	 	 	$	11	 	
Deduct preferred stock dividends	 	 	(20	)	 	 	(1	)	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Net income available to common stockholders from continuing operations	 	 	57	 	 	 	160	 	 	 	11	 	
Discontinued operations, net of tax	 	 	7	 	 	 	25	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Net income available to common stockholders	 	$	64	 	 	$	185	 	 	$	11	 	
 	 	 	 	 	 	 	 	 	 	
Denominator:	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average number of common shares outstanding	 	 	84.6	 	 	 	99.6	 	 	 	100.0	 	
Basic earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	0.67	 	 	$	1.61	 	 	$	0.11	 	
Discontinued operations, net of tax	 	 	0.09	 	 	 	0.25	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Net income	 	$	0.76	 	 	$	1.86	 	 	$	0.11	 	
 	 	 	 	 	 	 	 	 	 	
Diluted earnings per share	 	 	 	 	 	 	 	 	 	 	 	 	
Numerator	 	 	 	 	 	 	 	 	 	 	 	 	
Net income available to common stockholders from continuing operations	 	$	57	 	 	$	160	 	 	$	11	 	
Add preferred stock dividends for dilutive preferred stock	 	 	—	 	 	 	1	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Adjusted income from continuing operations	 	 	57	 	 	 	161	 	 	 	11	 	
Discontinued operations, net of tax	 	 	7	 	 	 	25	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Net income available to common stockholders	 	$	64	 	 	$	186	 	 	$	11	 	
 	 	 	 	 	 	 	 	 	 	
Denominator:	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average number of common shares outstanding	 	 	84.6	 	 	 	99.6	 	 	 	100.0	 	
Incremental shares attributable to the issuance of non-qualifying stock options (treasury stock method)	 	 	0.2	 	 	 	—	 	 	 	—	 	
Incremental shares attributable to the issuance of non-vested restricted stock units (treasury stock method)	 	 	0.4	 	 	 	0.4	 	 	 	0.1	 	
Incremental shares attributable to the assumed conversion of deferred stock units (if converted method)	 	 	0.1	 	 	 	0.1	 	 	 	—	 	
Incremental shares attributable to the assumed conversion of the 4% preferred stock (if converted method)	 	 	—	 	 	 	0.3	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Total dilutive shares	 	 	85.3	 	 	 	100.4	 	 	 	100.1	 	
 	 	 	 	 	 	 	 	 	 	
Diluted earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	0.66	 	 	$	1.60	 	 	$	0.11	 	
Discontinued operations, net of tax	 	 	0.09	 	 	 	0.25	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Net income	 	$	0.75	 	 	$	1.85	 	 	$	0.11	 	
 	 	 	 	 	 	 	 	 	 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 	 	
 	Anti-dilutive effect of certain equity instruments	
      Non-Qualified Stock Options — For the years ended December 31, 2005 and, 2004 and the period December 6, 2003 to December 31, 2003, options to purchase 132,500, 962,751 and 632,751 shares of common stock at an average price of $38.80, $23.15 and $24.03 per share, respectively, were not included in the earnings per share computation because the effect would be anti-dilutive.
      Restricted Stock Units — For the years ended December 31, 2005 and 2004 , restricted stock units totaling 459,200 and 77,500 shares of common stock at an average price of $38.77 and $28.14 per share, respectively, were not included in the computation because the effect would be anti-dilutive. All the restricted stock units for the period December 6, 2003 to December 31, 2003 were included in the computation because the effect would be dilutive.
      Performance Units — For the year ended December 31, 2005, 44,900 Performance Units which convert into common shares of stock were not included in the earnings per share computation as their effect would be anti-dilutive. There were no outstanding Performance Units as of December 31, 2004.
      4% Preferred Stock — For the year ended December 31, 2005, the outstanding 4% Preferred Stock which are convertible into 10,500,000 shares of common stock were not included in the earnings per share computation because the effect would be anti-dilutive. However, for the year ended December 31, 2004, on a weighted average basis, 343,324 shares of common stock associated with the 4% Preferred Stock were included in the earnings per share computation.
      3.625% Preferred Stock — The conversion feature of the 3.625% Preferred Stock, for the year ended December 31, 2005, is anti-dilutive and thus not included in the earnings per share computation. The conversion feature allows additional cash or common shares to be issued if the closing average stock price for a 20-day period prior to conversion exceeds the $59.08 market price trigger at conversion. The market price trigger was not reached as of December 31, 2005, and consequently, the conversion feature of the 3.625% Preferred Stock is considered anti-dilutive.
Note 21 — Segment Reporting
      Our identified reportable segments are primarily based on geographic areas, both domestically and abroad. In connection with our emergence from bankruptcy and the new management team, we determined that it was necessary to adjust our segment reporting disclosures to more closely align our disclosures with the realignment of our management team. Accordingly, we have expanded our domestic geographical disclosures and collapsed our international geographical disclosures related to our wholesale power generation segment. In addition, our other segments have been further refined. As a result of these changes, we have retroactively recast our prior period disclosures in a consistent manner.
      Beginning January 1, 2005 management changed the allocation criteria of corporate general and administrative expenses to the segments. Prior to 2005, corporate general and administrative expenses were allocated based on an analysis of man hours spent on work for each segment. As of January 1, 2005, corporate general and administrative expenses are allocated based on the forecasted revenue to be generated by each segment. In the following table, we have included a reconciliation of the increase/(decrease) in net income by segment for the year ended December 31, 2005, assuming the prior allocation criteria was still in effect.
      We conduct the majority of our business within five reportable operating segments based on geographic regions. Certain operations consisting of other products and services are presented under the “All Other” category. Our reportable operating segments consist of Wholesale Power Generation — Northeast, Wholesale Power Generation — South Central, Wholesale Power Generation — Western, Wholesale Power Generation — Other North America and Wholesale Power Generation — Australia. These reportable segments are distinct components with separate operating results and management structures in place.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Included in the All Other category are our Wholesale Power Generation — Other International operations, our Alternative Energy operations, our Non-Generation operations (comprised primarily from our operating services, power marketing and thermal operations) and an Other component which includes our corporate charges (primarily interest expense) that have not been allocated to the reportable segments and the remainder of our operations which are not significant. We have presented this detail within the All Other category as we believe that this information is important to a full understanding of our business.
      All material revenues and long-lived assets attributable to foreign countries are presented in Wholesale Power Generation — Australia and All Other — Wholesale Power Generation — Other International reportable segments. Furthermore, the segment information has been reclassified for all discontinued operations.

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 	 	Reorganized NRG	 	
 	 	Year Ended December 31, 2005	 	
 	 	 	 	
 	 	Wholesale Power Generation	 	 	 	 	 	

All Other	 	 	 	
 	 	 	 	Other	 	 	 	 	 	 	 	 	
 	 	 	 	South	 	 	 	 	North	 	 	 	 	Other	 	 	Alternative	 	 	Non-	 	 	 	 	 	
 	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	International	 	 	Energy	 	 	Generation	 	 	Other	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	1,554	 	 	$	552	 	 	$	1	 	 	$	15	 	 	$	212	 	 	$	163	 	 	$	70	 	 	$	158	 	 	$	(17	)	 	$	2,708	 	
Operating expenses	 	 	1,262	 	 	 	471	 	 	 	6	 	 	 	30	 	 	 	192	 	 	 	122	 	 	 	60	 	 	 	124	 	 	 	(3	)	 	 	2,264	 	
Depreciation and amortization	 	 	74	 	 	 	61	 	 	 	1	 	 	 	7	 	 	 	27	 	 	 	4	 	 	 	5	 	 	 	11	 	 	 	4	 	 	 	194	 	
Corporate relocation charges	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	6	 	 	 	6	 	
Reorganization items	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Restructuring and impairment charges	 	 	—	 	 	 	—	 	 	 	—	 	 	 	6	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income/(loss)	 	 	218	 	 	 	20	 	 	 	(6	)	 	 	(28	)	 	 	(7	)	 	 	37	 	 	 	5	 	 	 	23	 	 	 	(24	)	 	 	238	 	
Minority interest in earnings of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings (losses) of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	22	 	 	 	13	 	 	 	24	 	 	 	45	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	104	 	
Write downs and losses on sales of equity method investments	 	 	 	 	 	 	—	 	 	 	(27	)	 	 	(16	)	 	 	 	 	 	 	12	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(31	)	
Other income (expense), net	 	 	4	 	 	 	—	 	 	 	1	 	 	 	13	 	 	 	3	 	 	 	21	 	 	 	2	 	 	 	6	 	 	 	12	 	 	 	62	 	
Refinancing expenses	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	10	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(66	)	 	 	(56	)	
Interest expense	 	 	 	 	 	 	(9	)	 	 	 	 	 	 	(18	)	 	 	(13	)	 	 	(8	)	 	 	 	 	 	 	(9	)	 	 	(140	)	 	 	(197	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations before income taxes	 	 	222	 	 	 	11	 	 	 	(10	)	 	 	(36	)	 	 	17	 	 	 	107	 	 	 	7	 	 	 	20	 	 	 	(218	)	 	 	120	 	
Income tax expense/(benefit)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4	 	 	 	2	 	 	 	18	 	 	 	4	 	 	 	4	 	 	 	11	 	 	 	43	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations	 	 	222	 	 	 	11	 	 	 	(10	)	 	 	(40	)	 	 	15	 	 	 	89	 	 	 	3	 	 	 	16	 	 	 	(229	)	 	 	77	 	
Income/(loss) on discontinued operations, net of income taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	 	 	 	 	6	 	 	 	—	 	 	 	—	 	 	 	7	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss)	 	$	222	 	 	$	11	 	 	$	(10	)	 	$	(39	)	 	$	15	 	 	$	89	 	 	$	9	 	 	$	16	 	 	$	(229	)	 	$	84	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance Sheet	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	1	 	 	 	—	 	 	 	188	 	 	 	56	 	 	 	163	 	 	 	195	 	 	 	 	 	 	 	—	 	 	 	—	 	 	 	603	 	
Capital expenditures	 	 	51	 	 	 	26	 	 	 	—	 	 	 	—	 	 	 	17	 	 	 	—	 	 	 	1	 	 	 	6	 	 	 	5	 	 	 	106	 	
Total assets	 	$	1,810	 	 	$	1,075	 	 	$	200	 	 	$	599	 	 	$	825	 	 	$	679	 	 	$	74	 	 	$	1,446	 	 	$	723	 	 	$	7,431	 	
      If the Company continued using the previous year’s allocation method for corporate general and administrative expenses, the effect to the net income of each segment for the year ended December 31, 2005 would be as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss) as reported	 	$	222	 	 	$	11	 	 	$	(10	)	 	$	(39	)	 	$	15	 	 	$	89	 	 	$	9	 	 	$	16	 	 	$	(229	)	 	$	84	 	
Increase/(decrease) in net income	 	 	25	 	 	 	13	 	 	 	—	 	 	 	(1	)	 	 	6	 	 	 	4	 	 	 	1	 	 	 	5	 	 	 	(53	)	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted net income/(loss)	 	$	247	 	 	$	24	 	 	$	(10	)	 	$	(40	)	 	$	21	 	 	$	93	 	 	$	10	 	 	$	21	 	 	$	(282	)	 	$	84	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	Year Ended December 31, 2004	 	
 	 	 	 	
 	 	Wholesale Power Generation	 	 	 	 	
 	 	 	 	All Other	 	 	 	
 	 	 	 	Other	 	 	 	 	 	 	 	 	
 	 	 	 	South	 	 	 	 	North	 	 	 	 	Other	 	 	Alternative	 	 	Non-	 	 	 	 	 	
 	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	International	 	 	Energy	 	 	Generation	 	 	Other	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	1,251	 	 	$	418	 	 	$	3	 	 	$	94	 	 	$	181	 	 	$	157	 	 	$	65	 	 	$	186	 	 	$	(7	)	 	$	2,348	 	
Operating expenses	 	 	860	 	 	 	294	 	 	 	11	 	 	 	51	 	 	 	162	 	 	 	122	 	 	 	61	 	 	 	101	 	 	 	37	 	 	 	1,699	 	
Depreciation and amortization	 	 	73	 	 	 	62	 	 	 	1	 	 	 	21	 	 	 	24	 	 	 	3	 	 	 	5	 	 	 	11	 	 	 	8	 	 	 	208	 	
Corporate relocation charges	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	16	 	 	 	16	 	
Reorganization items	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	(15	)	 	 	(13	)	
Restructuring and impairment charges	 	 	—	 	 	 	3	 	 	 	—	 	 	 	27	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	15	 	 	 	45	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income/(loss)	 	 	318	 	 	 	58	 	 	 	(9	)	 	 	(5	)	 	 	(5	)	 	 	32	 	 	 	(1	)	 	 	73	 	 	 	(68	)	 	 	393	 	
Minority interest in earnings of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings (losses) of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	74	 	 	 	16	 	 	 	18	 	 	 	51	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	160	 	
Write downs and losses on sales of equity method investments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(11	)	 	 	(1	)	 	 	—	 	 	 	(4	)	 	 	—	 	 	 	—	 	 	 	(16	)	
Other income (expense), net	 	 	5	 	 	 	—	 	 	 	—	 	 	 	3	 	 	 	4	 	 	 	7	 	 	 	1	 	 	 	2	 	 	 	5	 	 	 	27	 	
Refinancing expenses	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(72	)	 	 	(72	)	
Interest expense	 	 	(1	)	 	 	(9	)	 	 	—	 	 	 	(45	)	 	 	(11	)	 	 	(11	)	 	 	—	 	 	 	(8	)	 	 	(181	)	 	 	(266	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations before income taxes	 	 	322	 	 	 	49	 	 	 	65	 	 	 	(42	)	 	 	5	 	 	 	79	 	 	 	(3	)	 	 	67	 	 	 	(316	)	 	 	226	 	
Income tax expense/(benefit)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(10	)	 	 	(5	)	 	 	13	 	 	 	(1	)	 	 	5	 	 	 	63	 	 	 	65	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations	 	 	322	 	 	 	49	 	 	 	65	 	 	 	(32	)	 	 	10	 	 	 	66	 	 	 	(2	)	 	 	62	 	 	 	(379	)	 	 	161	 	
Income/(loss) on discontinued operations, net of income taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	14	 	 	 	—	 	 	 	12	 	 	 	2	 	 	 	—	 	 	 	(3	)	 	 	25	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss)	 	$	322	 	 	$	49	 	 	$	65	 	 	$	(18	)	 	$	10	 	 	$	78	 	 	$	—	 	 	$	62	 	 	$	(382	)	 	$	186	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance Sheet	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	1	 	 	 	—	 	 	 	256	 	 	 	76	 	 	 	156	 	 	 	246	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	735	 	
Capital expenditures	 	 	49	 	 	 	31	 	 	 	—	 	 	 	1	 	 	 	22	 	 	 	2	 	 	 	2	 	 	 	4	 	 	 	8	 	 	 	119	 	
Total assets	 	$	1,932	 	 	$	1,077	 	 	$	279	 	 	$	783	 	 	$	1,008	 	 	$	939	 	 	$	51	 	 	$	512	 	 	$	1,283	 	 	$	7,864	 	
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Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	December 6, 2003 Through December 31, 2003	 	
 	 	 	 	
 	 	Wholesale Power Generation	 	 	 	 	 	

All Other	 	 	 	
 	 	 	 	Other	 	 	 	 	 	 	 	 	
 	 	 	 	South	 	 	 	 	North	 	 	 	 	Other	 	 	Alternative	 	 	Non-	 	 	 	 	 	
 	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	International	 	 	Energy	 	 	Generation	 	 	Other	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	69	 	 	$	27	 	 	$	—	 	 	$	4	 	 	$	12	 	 	$	13	 	 	$	4	 	 	$	10	 	 	$	(2	)	 	$	137	 	
Operating expenses	 	 	53	 	 	 	20	 	 	 	—	 	 	 	2	 	 	 	10	 	 	 	11	 	 	 	4	 	 	 	8	 	 	 	—	 	 	 	108	 	
Depreciation and amortization	 	 	5	 	 	 	3	 	 	 	—	 	 	 	2	 	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	12	 	
Reorganization items	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income/(loss)	 	 	11	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	—	 	 	 	2	 	 	 	(4	)	 	 	15	 	
Minority interest in earnings of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	10	 	 	 	2	 	 	 	1	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	14	 	
Other income (expense), net	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	—	 	
Interest expense	 	 	(3	)	 	 	(4	)	 	 	—	 	 	 	(3	)	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	(7	)	 	 	(19	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations before income taxes	 	 	8	 	 	 	—	 	 	 	10	 	 	 	(1	)	 	 	1	 	 	 	3	 	 	 	—	 	 	 	1	 	 	 	(12	)	 	 	10	 	
Income tax expense/(benefit)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	(2	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations	 	 	8	 	 	 	—	 	 	 	10	 	 	 	(1	)	 	 	1	 	 	 	2	 	 	 	—	 	 	 	1	 	 	 	(10	)	 	 	11	 	
Income/(loss) on discontinued operations, net of income taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss)	 	$	8	 	 	$	—	 	 	$	10	 	 	$	(1	)	 	$	1	 	 	$	2	 	 	$	—	 	 	$	1	 	 	$	(10	)	 	$	11	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company	 	
 	 	January 1, 2003 Through December 5, 2003	 	
 	 	 	 	
 	 	Wholesale Power Generation	 	 	 	 	 	

All Other	 	 	 	
 	 	 	 	Other	 	 	 	 	 	 	 	 	
 	 	 	 	South	 	 	 	 	North	 	 	 	 	Other	 	 	Alternative	 	 	Non-	 	 	 	 	 	
 	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	International	 	 	Energy	 	 	Generation	 	 	Other	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	861	 	 	$	357	 	 	$	24	 	 	$	86	 	 	$	151	 	 	$	137	 	 	$	61	 	 	$	129	 	 	$	(8	)	 	$	1,798	 	
Operating expenses	 	 	800	 	 	 	247	 	 	 	7	 	 	 	45	 	 	 	124	 	 	 	111	 	 	 	52	 	 	 	87	 	 	 	51	 	 	 	1,524	 	
Depreciation and amortization	 	 	90	 	 	 	34	 	 	 	11	 	 	 	29	 	 	 	17	 	 	 	4	 	 	 	5	 	 	 	12	 	 	 	9	 	 	 	211	 	
Reorganization items	 	 	2	 	 	 	29	 	 	 	—	 	 	 	41	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	126	 	 	 	198	 	
Restructuring and impairment charges	 	 	232	 	 	 	2	 	 	 	—	 	 	 	17	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	(15	)	 	 	237	 	
Fresh start reporting adjustments	 	 	1,068	 	 	 	429	 	 	 	107	 	 	 	415	 	 	 	78	 	 	 	(11	)	 	 	50	 	 	 	181	 	 	 	(6,537	)	 	 	(4,220	)	
Legal settlement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	(9	)	 	 	—	 	 	 	468	 	 	 	463	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income/(loss)	 	 	(1,331	)	 	 	(384	)	 	 	(101	)	 	 	(465	)	 	 	(68	)	 	 	33	 	 	 	(38	)	 	 	(151	)	 	 	5,890	 	 	 	3,385	 	
Equity in earnings of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	103	 	 	 	7	 	 	 	30	 	 	 	32	 	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	171	 	
Write downs and losses on sales of equity method investments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	12	 	 	 	(146	)	 	 	3	 	 	 	(16	)	 	 	—	 	 	 	—	 	 	 	(147	)	
Other income (expense), net	 	 	3	 	 	 	1	 	 	 	—	 	 	 	2	 	 	 	(1	)	 	 	13	 	 	 	2	 	 	 	—	 	 	 	(1	)	 	 	19	 	
Interest expense	 	 	(70	)	 	 	(74	)	 	 	—	 	 	 	(70	)	 	 	(4	)	 	 	(8	)	 	 	—	 	 	 	(10	)	 	 	(72	)	 	 	(308	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations before income taxes	 	 	(1,398	)	 	 	(457	)	 	 	2	 	 	 	(514	)	 	 	(189	)	 	 	73	 	 	 	(53	)	 	 	(161	)	 	 	5,817	 	 	 	3,120	 	
Income tax expense/(benefit)	 	 	—	 	 	 	—	 	 	 	36	 	 	 	5	 	 	 	15	 	 	 	17	 	 	 	2	 	 	 	—	 	 	 	(37	)	 	 	38	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations	 	 	(1,398	)	 	 	(457	)	 	 	(34	)	 	 	(519	)	 	 	(204	)	 	 	56	 	 	 	(55	)	 	 	(161	)	 	 	5,854	 	 	 	3,082	 	
Income/(loss) on discontinued operations, net of income taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(414	)	 	 	—	 	 	 	138	 	 	 	(25	)	 	 	—	 	 	 	(15	)	 	 	(316	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss)	 	$	(1,398	)	 	$	(457	)	 	$	(34	)	 	$	(933	)	 	$	(204	)	 	$	194	 	 	$	(80	)	 	$	(161	)	 	$	5,839	 	 	$	2,766	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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Note 22 — Income Taxes
      The income tax provision (benefit) from continuing operations consists of the following amounts:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	
 	 	 	 	For the Period	 	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	 	January 1 -	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	U.S. 	 	$	19	 	 	$	—	 	 	$	(2	)	 	 	$	2	 	
 	Foreign	 	 	16	 	 	 	17	 	 	 	1	 	 	 	 	16	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	35	 	 	 	17	 	 	 	(1	)	 	 	 	18	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	U.S. 	 	 	2	 	 	 	57	 	 	 	—	 	 	 	 	3	 	
 	Foreign	 	 	6	 	 	 	(9	)	 	 	—	 	 	 	 	17	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	8	 	 	 	48	 	 	 	—	 	 	 	 	20	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total income tax (benefit)	 	$	43	 	 	$	65	 	 	$	(1	)	 	 	$	38	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effective tax rate	 	 	35.8	%	 	 	28.7	%	 	 	(6.2	)%	 	 	 	1.3	%	
      The following represents the domestic and foreign income components of income (loss) from continuing operations before income tax expense (benefit):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	Company	 	
 	 	 	 	 	 	 	
 	 	 	 	For the Period	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	January 1 -	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
U.S. 	 	$	(4	)	 	$	138	 	 	$	6	 	 	$	3,236	 	
Foreign	 	 	124	 	 	 	88	 	 	 	4	 	 	 	(116	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	120	 	 	$	226	 	 	$	10	 	 	$	3,120	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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      A reconciliation of the U.S. federal statutory rate of 35% to our effective rate from continuing operations for the year ended December 31, 2005 and 2004 and the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003 is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	
 	 	 	 	For the Period	 	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	 	January 1 -	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	$	120	 	 	$	226	 	 	$	10	 	 	 	$	3,120	 	
Tax at 35%	 	 	42	 	 	 	80	 	 	 	4	 	 	 	 	1,092	 	
State taxes, (net of federal benefit)	 	 	(1	)	 	 	6	 	 	 	(2	)	 	 	 	265	 	
Foreign operations	 	 	(21	)	 	 	(22	)	 	 	(1	)	 	 	 	15	 	
Section 965 Taxable Dividend	 	 	5	 	 	 	—	 	 	 	—	 	 	 	 	—	 	
Subpart F Taxable Income	 	 	19	 	 	 	—	 	 	 	—	 	 	 	 	—	 	
Fresh Start accounting adjustments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	(1,440	)	
Valuation allowance	 	 	(22	)	 	 	—	 	 	 	(1	)	 	 	 	71	 	
Change in state effective tax rate	 	 	22	 	 	 	—	 	 	 	—	 	 	 	 	—	 	
Change in tax rate	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	36	 	
Permanent differences, reserves, other	 	 	(1	)	 	 	1	 	 	 	(1	)	 	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax Expense/(Benefit)	 	$	43	 	 	$	65	 	 	$	(1	)	 	 	$	38	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effective income tax rate	 	 	35.8	%	 	 	28.7	%	 	 	(6.2	)%	 	 	 	1.3	%	
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      The temporary differences, which give rise to our deferred tax assets and liabilities consist of the following:
 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
 	 	(In millions)	 	
Deferred tax liabilities:	 	 	 	 	 	 	 	 	
 	Discount/premium on notes	 	$	23	 	 	$	20	 	
 	Emissions credits	 	 	113	 	 	 	115	 	
 	Difference between book and tax basis of property	 	 	247	 	 	 	246	 	
 	 	 	 	 	 	 	
 	Total deferred tax liabilities	 	 	383	 	 	 	381	 	
Deferred tax assets:	 	 	 	 	 	 	 	 	
 	Deferred compensation, accrued vacation and other reserves	 	 	56	 	 	 	54	 	
 	Development costs	 	 	2	 	 	 	3	 	
 	Net unrealized gains on mark to market transactions	 	 	148	 	 	 	10	 	
 	Foreign net operating loss carryforwards	 	 	46	 	 	 	64	 	
 	Differences between book and tax basis of contracts	 	 	146	 	 	 	162	 	
 	Non-depreciable Property	 	 	197	 	 	 	182	 	
 	Intangibles amortization (other than goodwill)	 	 	12	 	 	 	13	 	
 	Restructuring costs	 	 	80	 	 	 	60	 	
 	U.S. net operating loss carry forwards	 	 	38	 	 	 	40	 	
 	U.S. capital loss carryforwards	 	 	238	 	 	 	280	 	
 	Investments in projects	 	 	63	 	 	 	83	 	
 	Other	 	 	8	 	 	 	3	 	
 	 	 	 	 	 	 	
 	Total deferred tax assets (before valuation allowance)	 	 	1,034	 	 	 	954	 	
 	 	Valuation allowance	 	 	(756	)	 	 	(708	)	
 	 	 	 	 	 	 	
 	Net deferred tax assets	 	 	278	 	 	 	246	 	
 	 	 	 	 	 	 	
Net deferred tax liability	 	$	105	 	 	$	135	 	
 	 	 	 	 	 	 	
      The net deferred tax liability consists of:
 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
 	 	(In millions)	 	
Current deferred tax asset	 	$	(4	)	 	$	—	 	
Non-current deferred tax asset	 	 	(26	)	 	 	(34	)	
Non-current deferred tax liability	 	 	135	 	 	 	169	 	
 	 	 	 	 	 	 	
Net deferred tax liability	 	$	105	 	 	$	135	 	
 	 	 	 	 	 	 	
      The effective income tax rate for the year ended December 31, 2005 differs from the U.S. statutory rate of 35% due to the U.S. income inclusion upon the sale of Enfield (considered subpart F income), the taxable portion of a dividend from foreign operations repatriated pursuant to the American Jobs Creation Act of 2004, or the Jobs Act, and partially offset due to earnings in foreign jurisdictions taxed at rates lower than the U.S. statutory rate.
      For the year ended December 31, 2005 we increased the estimated state effective income tax rate to 9% from the prior year state income tax rate of 7%. This increase is due to management’s best estimate of the effective income tax rates for the various state and local taxing jurisdictions that we expect to be subject to for income tax filing purposes based on our business operations within each state. An increase to the net deferred

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tax asset balance of approximately $22 million has been recorded for which a corresponding valuation allowance as required has been established.
      On February 2, 2006, we acquired Texas Genco for which we will obtain a step up in basis for a large portion of the newly acquired assets, which will generate tax depreciation expense deductions reducing our taxable income in future periods.
 	 	
 	Taxes payable	
      During 2005, we recorded a current tax payable of approximately $22 million that represents a liability due to domestic federal and state tax of approximately $19 million as well as foreign taxes payable of approximately $3 million. During 2004, the Company generated current year domestic net operating losses for federal and state tax purposes, however we had a $5 million foreign current tax payable.
 	 	
 	Deferred tax assets and valuation allowance	
      For U.S. income tax purposes, NRG generated additional net deferred tax assets of $80 million for the year ended December 31, 2005 of which a valuation allowance of $65 million was applied due to the uncertainty of utilization in future periods. As a result of our 2004 income tax filing, for financial reporting purposes we increased our domestic NOL’s by $198 million and utilized $207 million during 2005. As of December 31, 2005 we have an outstanding domestic NOL carryforward of $93 million that will expire through 2025. Cumulative foreign NOL carryforwards of $156 million have no expiration date.
      We believe that it is more likely than not that a benefit will not be realized on a substantial portion of our deferred tax assets. This assessment included consideration of positive and negative evidence, our current financial position and results of historical operations, current operations, projected future taxable income, projected operating and capital gains and our available tax planning strategies. During the year ended December 31, 2005, we reduced the domestic valuation allowance as a result of the utilization of tax assets and generated taxable income during the period. Positive evidence exists that current deferred tax assets when realized during 2006 can be carried back to offset taxable income in 2005. As a result, a corresponding decrease to the valuation allowance was recorded.
      As of December 31, 2005, a consolidated valuation allowance of $756 million was recorded against the net deferred tax assets, of which $741 million is for domestic deferred tax assets and $15 million is for foreign deferred tax assets. Furthermore, the consolidated valuation allowance is comprised of a current and non-current portion of approximately $114 million and $642 million, respectively.
      Under SOP 90-7, any future benefits from reducing a valuation allowance from pre-confirmation deferred tax assets should first reduce intangibles until exhausted and thereafter 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. During 2005 we reduced our valuation allowance by $17 million with a corresponding reduction to our intangibles by the same amount. At December 31, 2005, approximately $674 million of pre-confirmation valuation allowance remained. Upon recognition in future periods, a reduction to this portion of the valuation allowance will be recorded against our intangible assets, and once exhausted, increase our paid-in capital.
 	 	
 	Repatriation of foreign funds pursuant to the American Jobs Creation Act of 2004	
      Pursuant to the Jobs Act, NRG may elect to deduct 85% of certain eligible dividends received from non-U.S. subsidiaries from its taxable income before the end of 2005 if those dividends are reinvested in the U.S. for eligible purposes. During the year ended December 31, 2005, NRG repatriated approximately $298 million of accumulated foreign earnings. Only a portion of this amount represents the cumulative earnings and profits which will result in approximately $4.7 million of tax expense. The remaining amounts transferred are considered a return of capital. To the extent that NRG does not provide deferred income taxes for unremitted earnings, it is management’s intent to permanently reinvest those earnings overseas in

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accordance with APB Opinion No. 23 Accounting for Income Taxes-Special Areas, or APB 23. As of December 31, 2005, there are no cumulative losses from our foreign subsidiaries.
 	 	
 	Tax Holidays	
      During 2005, the “Amazon Development Agency” granted an income tax holiday to our subsidiary Itiquira Energetica SA pertaining to the local tax liability resulting from Itiquira’s operating income for Brazilian tax purposes, applicable retroactively to January 1, 2005. The tax holiday program will reduce the effective income tax rate to 15.25% from a statutory income tax rate of 34% and will expire in December 31, 2013.
Note 23 — Related Party Transactions
 	 	
 	Stock Purchase Agreement	
      Upon emergence from chapter 11, investment partnerships managed by MatlinPatterson LLC owned approximately 21.5 million (21.5%) of our common shares. We used existing cash to repurchase 13 million shares of common stock from MatlinPatterson pursuant to a stock purchase agreement dated December 13, 2004 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 of NRG Energy 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.
 	 	
 	Operating Agreements	
      We entered into operation and maintenance agreements, or O&M agreements, with certain of our equity investments — WCP, Saguaro, Gladstone and MIBRAG. Fees for services under these contracts primarily include recovery of our costs of operating the plant as approved in the annual budget, as well as a base monthly fee. At WCP, we also provide services under Administrative Management Agreements, or AMAs. Services provided under the AMAs include environmental, engineering, legal and public relations services not covered under the O&M agreements. We also entered into long-term coal purchase agreements with MIBRAG to supply coal to Schkopau, a consolidated subsidiary. These fees and expenses are included in our operating revenues and operating costs in the consolidated statements of operations and consisted of the following:

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Related Party Transactions with Equity Investments:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	
 	 	 	 	For the Period	 	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	 	January 1 -	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Revenues from Related Parties Included in Revenues from Majority-Owned Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
WCP	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
O&M fees	 	$	6	 	 	$	4	 	 	$	—	 	 	 	$	6	 	
AMA fees	 	 	2	 	 	 	3	 	 	 	—	 	 	 	 	1	 	
Saguaro	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
O&M fees	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	—	 	
Gladstone	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
O&M fees	 	 	3	 	 	 	2	 	 	 	—	 	 	 	 	1	 	
MIBRAG	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
O&M fees	 	 	4	 	 	 	3	 	 	 	—	 	 	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	15	 	 	$	12	 	 	$	—	 	 	 	$	11	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Expenses from Related Parties Included in Cost of Majority-Owned Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
MIBRAG	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of purchased coal	 	$	41	 	 	$	39	 	 	$	3	 	 	 	$	36	 	

 	Xcel Energy	
      Prior to our emergence from bankruptcy on December 5, 2003, NRG Energy was an indirect, wholly-owned subsidiary of Xcel Energy. Prior to December 5, 2003, we had entered into material transactions and agreements with Xcel Energy which are described below. Upon emergence from bankruptcy, we became an independent public company with no material affiliation or relationship to Xcel Energy. We have included amounts paid to or received from Xcel Energy during the year ended December 31, 2005, December 31, 2004 and for the period December 6, 2003 to December 31, 2003 only for comparative purposes, as these transactions are not considered related party transactions subsequent to December 5, 2003.
 	 	
 	Operating Agreements	
      We have two agreements with Xcel Energy for the purchase of thermal energy. Under the terms of the agreements, Xcel Energy charges us for certain costs (fuel, labor, plant maintenance, and auxiliary power) incurred by Xcel Energy to produce the thermal energy. We paid Xcel Energy $11 million, $11 million, $1 million, and $10 million during the year ended December 31, 2005 and 2004, the period December 6, 2003 to December 31, 2003, and the period January 1, 2003 to December 5, 2003 respectively, under these agreements. These agreements are expected to terminate in 2007.
      We have a renewable 10-year agreement with Xcel Energy, expiring on December 31, 2006, whereby Xcel Energy agreed to purchase refuse-derived fuel for use in certain of its boilers and we agree to pay Xcel Energy a burn incentive. Under this agreement, we received $2 million, $1 million, $0 and $1 million from Xcel Energy and paid $4 million, $4 million, $0 million and $4 million to Xcel Energy during the year

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ended December 31, 2005 and 2004, the period December 6, 2003 to December 31, 2003 and the period January 1, 2003 to December 5, 2003, respectively.
 	 	
 	Administrative Services and Other Costs	
      We had an administrative services agreement in place with Xcel Energy. Under this agreement we reimbursed Xcel Energy for certain overhead and administrative costs, including benefits administration, engineering support, accounting and other shared services as requested by us. In addition, our employees participated in certain employee benefit plans of Xcel Energy as discussed in Note 24. We reimbursed Xcel Energy in the amount of $7.3 million during the period January 1, 2003 to December 5, 2003, under this agreement. This agreement was terminated December 5, 2003.
 	 	
 	Natural Gas Marketing and Trading Agreement	
      We had an agreement with e prime, a wholly-owned subsidiary of Xcel Energy, under which e prime provided natural gas marketing and trading from time to time at our request. This agreement was terminated by e prime on December 12, 2002 and a termination charge of $0.3 million was paid in the period January 1, 2003 to December 5, 2003.
Note 24 — Benefit Plans and Other Postretirement Benefits
 	 	
 	Reorganized NRG	
      Substantially all employees hired prior to December 5, 2003 were eligible to participate in our defined benefit pension plans. We have initiated new NRG Energy noncontributory, defined benefit pension plans effective January 1, 2004, with credit for service from December 5, 2003.
      In addition, we provide postretirement health and welfare benefits (health care and death benefits) for certain groups of our employees. Generally, these are groups that were acquired in recent years and for whom prior benefits are being continued (at least for a certain period of time or as required by union contracts). Cost sharing provisions vary by acquisition group and terms of any applicable collective bargaining agreements. We expect to contribute approximately $18 million to our NRG pension plans in 2006.
 	 	
 	NRG Flinders Retirement Plan	
      Employees of NRG Flinders, a wholly-owned subsidiary of NRG Energy, are members of the multiemployer Electricity Industry Superannuation Schemes, or EISS. Members of the EISS make contributions from their salary and the EISS Actuary makes an assessment of our liability. As a result of adopting Fresh Start we recorded a liability of approximately $14 million at December 5, 2003, to record our accumulated benefit obligation plan assets on the balance sheet at fair value. The balance sheet includes a liability related to the Flinders retirement plan of $15 million and $9 million at December 31, 2005 and 2004, respectively. NRG Flinders contributed approximately $6 million, $10 million, $0 and $5 million for the years ended December 31, 2005 and 2004, the period December 6 through December 31, 2003 and the period January 1 through December 5, 2003, respectively.
      The Superannuation Board is responsible for the investment of EISS assets. The assets may be invested in government securities, shares, property and a variety of other securities and the Board may appoint professional investment managers to invest all or part of the assets on its behalf.

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 	NRG Pension and Postretirement Medical Plans	

 	Components of Net Periodic Benefit Cost	
      The net annual periodic pension cost related to our domestic plans, include the following components:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension Benefits	
 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized NRG	 	 	Company	
 	 	 	 	 	 	
 	 	 	 	For the Period	 	 	For the Period	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	January 1 -	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	December 5,	
 	 	2005	 	 	2004	 	 	2003	 	 	2003	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	
Service cost benefits earned	 	$	11	 	 	$	11	 	 	$	1	 	 	$	—	 	
Interest cost on benefit obligation	 	 	4	 	 	 	3	 	 	 	—	 	 	 	—	 	
Expected return on plan assets	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Curtailment gain	 	 	—	 	 	 	(1	)	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net periodic benefit cost	 	$	15	 	 	$	13	 	 	$	1	 	 	$	—	 	

 	 	Other Benefits	 	
 	 	 	 	
 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	Company	 	
 	 	 	 	 	 	
 	 	 	 	For the Period	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	January 1 -	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Service cost benefits earned	 	$	2	 	 	$	1	 	 	$	—	 	 	$	1	 	
Interest cost on benefit obligation	 	 	3	 	 	 	3	 	 	 	—	 	 	 	2	 	
Amortization of prior service cost	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Recognized actuarial (gain)/loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net periodic benefit cost	 	$	5	 	 	$	4	 	 	$	—	 	 	$	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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 	Reconciliation of Funded Status	
      A comparison of the pension benefit obligation and pension assets at December 31, 2005 and 2004 for all of our plans on a combined basis is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension Benefits	 	 	Other Benefits	 	
 	 	 	 	 	 	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	December 31,	 	
Reorganized NRG	 	2005	 	 	2004	 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Benefit obligation at January 1	 	$	64	 	 	$	49	 	 	$	51	 	 	$	42	 	
Service cost	 	 	11	 	 	 	11	 	 	 	2	 	 	 	1	 	
Interest cost	 	 	4	 	 	 	3	 	 	 	3	 	 	 	3	 	
Plan initiation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Plan amendments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Plan curtailment	 	 	 	 	 	 	(1	)	 	 	—	 	 	 	—	 	
Actuarial (gain)/loss	 	 	5	 	 	 	2	 	 	 	2	 	 	 	6	 	
Benefit payments	 	 	(1	)	 	 	—	 	 	 	(1	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Benefit obligation at December 31	 	$	83	 	 	$	64	 	 	$	57	 	 	$	51	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at January 1	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	
Actual return on plan assets	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Employer contributions	 	 	13	 	 	 	1	 	 	 	1	 	 	 	1	 	
Benefit payments	 	 	(1	)	 	 	—	 	 	 	(1	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Fair value of plan assets at December 31	 	$	13	 	 	$	1	 	 	$	—	 	 	$	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded status at December 31 — excess of obligation over assets	 	 	(70	)	 	 	(63	)	 	 	(57	)	 	 	(51	)	
Unrecognized net (gain) loss	 	 	8	 	 	 	2	 	 	 	8	 	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Accrued benefit liability recognized on the consolidated balance sheet at December 31	 	$	(62	)	 	$	(61	)	 	$	(49	)	 	$	(45	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
      Amounts recognized in the balance sheets consist of:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension Benefits	 	 	Other Benefits	 	
 	 	 	 	 	 	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	December 31,	 	
 	 	2005	 	 	2004	 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Accrued benefit cost	 	$	(62	)	 	$	(61	)	 	$	(49	)	 	$	(45	)	
Unfunded accrued benefit obligation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Intangible assets	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Accumulated other comprehensive income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net amount recognized	 	$	(62	)	 	$	(61	)	 	$	(49	)	 	$	(45	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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      The following table presents the balances of significant components of our domestic pension plans:
 	 	 	 	 	 	 	 	 	
 	 	Pension Benefits	 	
 	 	 	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
 	 	(In millions)	 	
Projected benefit obligation	 	$	83	 	 	$	64	 	
Accumulated benefit obligation	 	 	35	 	 	 	16	 	
Fair value of plan assets	 	 	13	 	 	 	1	 	
      The following table presents the significant assumptions used to calculate the benefit obligations:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension Benefits	 	 	Other Benefits	 	
 	 	 	 	 	 	 	
 	 	2005	 	 	2004	 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted-average assumptions used to determine benefit obligations at December 31	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate	 	 	5.50	%	 	 	5.75	%	 	 	5.50%	 	 	 	5.75%	 	
Rate of compensation increase	 	 	4.00 - 4.50	%	 	 	4.00 - 4.50	%	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	11.5% grading to	 	 	 	9% grading to	 	
Health care trend rate	 	 	—	 	 	 	—	 	 	 	5.5% in 2012	 	 	 	5.5% in 2009	 	
      The following table presents the significant assumptions used to calculate the benefit expense:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension Benefits	 	 	Other Benefits	 	
 	 	 	 	 	 	 	
 	 	2005	 	 	2004	 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate	 	 	5.75	%	 	 	6.00	%	 	 	5.75%	 	 	 	6.00%	 	
Expected return on plan assets	 	 	8.00	%	 	 	8.00	%	 	 	—	 	 	 	—	 	
Rate of compensation increase	 	 	4.00 - 4.50	%	 	 	4.00 - 4.50	%	 	 	—	 	 	 	—	 	
Health care trend rate	 	 	 	 	 	 	 	 	 	 	9% grading to	 	 	 	10% grading to	 	
 	 	 	—	 	 	 	—	 	 	 	5.5% in 2009	 	 	 	5.5% in 2009	 	
      We use December 31 of each respective year as the measurement date for our pension and other benefit plans. We set the discount rate assumptions on an annual basis for each of our retirement related benefit plans at their respective measurement date. This rate is determined by our Investment Committee based on information provided by our actuary whose discount rate assumptions reflect the current rate at which the associated liabilities could be effectively settled at the end of the year. Such assumptions consider high-quality corporate bond indices, such as Moody’s Aa, when selecting the discount rate. Using these methodologies, we determined a discount rate of 5.50% to be appropriate as of December 31, 2005, which is a reduction of 0.25% from the rate used as of December 31, 2004.
      NRG employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The target allocation of plan assets is 60% to 80% invested in equity securities, with the remainder invested in fixed income securities. The Investment Committee will review the asset mix periodically and as the plan assets increase in future years, the Committee may examine other asset classes such as real estate, private equity, etc. NRG employs a building block approach to determining the long-term rate of return for plan assets with proper consideration given to diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current factors such as inflation and interest rates are evaluated before long-term capital market

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assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness.
      Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across US and non-US stocks, as well as growth, value, and small and large capitalizations. The plan assets weighted average allocation was as follows:
 	 	 	 	 	 	 	 	 	
 	 	December 31	 	
 	 	 	 	
 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	
US Equity	 	 	56	%	 	 	N/A	 	
International Equity	 	 	15	%	 	 	N/A	 	
US Fixed Income	 	 	29	%	 	 	N/A	 	
Cash	 	 	—	 	 	 	N/A	 	
      Expected future benefit payments are:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Post Retirement Medical Plans	 	
 	 	Pension Benefits	 	 	 	 	
 	 	 	 	 	 	 	Medicare Prescription	 	
 	 	Benefit Payments	 	 	Benefit Payments	 	 	Drug Reimbursements	 	
 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
2006	 	$	1	 	 	$	1	 	 	$	—	 	
2007	 	 	1	 	 	 	2	 	 	 	—	 	
2008	 	 	3	 	 	 	2	 	 	 	—	 	
2009	 	 	4	 	 	 	3	 	 	 	—	 	
2010	 	 	6	 	 	 	3	 	 	 	—	 	
2011-2015	 	 	50	 	 	 	18	 	 	 	1	 	
      Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:
 	 	 	 	 	 	 	 	 	
 	 	1-Percentage-	 	 	1-Percentage-	 	
 	 	Point Increase	 	 	Point Decrease	 	
 	 	 	 	 	 	 	
 	 	(In millions)	 	
Effect on total service and interest cost components	 	$	1	 	 	$	—	 	
Effect on postretirement benefit obligation	 	 	6	 	 	 	(5	)	

 	Defined Contribution Plans	
      Our employees have also been eligible to participate in defined contribution 401(K) plans. Our contributions to these plans were approximately $5 million, $4 million and $4 million for the years ended December 31, 2005, 2004 and 2003, respectively.
 	 	
 	Predecessor Company	
      Prior to December 5, 2003, all eligible employees participated in Xcel Energy’s noncontributory, defined benefit pension plan, which was formerly sponsored by NSP. We sponsored two defined benefit plans that were merged into Xcel Energy’s plan as of June 30, 2002. Benefits were generally based on a combination of an employee’s years of service and earnings. Some formulas also took into account Social Security benefits. Plan assets principally consisted of the common stock of public companies, corporate bonds and U.S. government securities.
      Prior to December 5, 2003, certain former NRG retirees were covered under the legacy Xcel Energy plan, which was terminated for non-bargaining employees retiring after 1998 and for bargaining employees retiring after 1999.
      As a result of our emergence from bankruptcy on December 5, 2003, we are no longer owned by or affiliated with Xcel Energy and our employees are no longer active participants in the Xcel Energy plans.

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 	Participation in Xcel Energy, Inc. Pension Plan and Postretirement Medical Plan	
      We did not make contributions to the Xcel Energy pension plan and postretirement plan in 2003. As of December 31, 2003, there are no liabilities recorded related to the Xcel Energy plans. The liabilities associated with these plans were settled as part of the NRG plan of reorganization. The net annual periodic cost (credit) related to our portion of the Xcel Energy pension plan and postretirement plans totaled $0.2 million 2003.
      Prior to December 5, 2003, certain employees also participated in Xcel Energy’s noncontributory defined benefit supplemental retirement income plan. This plan was for the benefit of certain qualifying executive personnel. Benefits for this unfunded plan were paid out of operating cash flows. The liability related to this plan was not material as of December 31, 2005 and 2004, respectively.
 	 	
 	2003 Medicare Legislation	
      In May 2004, the FASB issued FSP 106-2 that provides guidance on accounting for the effects of the new Medicare Prescription Drug, Improvement, and Modernization Act of 2003 by employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. FSP 106-2 is effective as of the first interim period beginning after June 15, 2004. NRG Energy adopted FSP 106-2 in the third quarter of 2004 on a retroactive basis. Adoption of FSP 106-2 reduces the annual non-cash postretirement health expense by approximately $0.2 million and reduce the accumulated postretirement benefit obligation by $2.2 million. The change in accumulated postretirement benefit obligation has been reflected as an actuarial gain and will be amortized in future periods.
 	 	
Note 25 —	Commitments and Contingencies	

 	Operating Lease Commitments	
      We lease certain of our facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2023. Certain operating lease agreements over their lease term include provisions such as scheduled rent increases, leasehold incentives and rent concessions. We recognize the effects of those scheduled rent increases, leasehold incentives and rent concessions on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Rental expense under these operating leases was approximately $9 million for the year ended December 31, 2005, $11 million for the year ended December 31, 2004, $1 million for the period December 6, 2003 through December 31, 2003 and $12 million for the period January 1, 2003 through December 5, 2003. Future minimum lease commitments under these leases for the years ending after December 31, 2005 are as follows:
 	 	 	 	 	 	
 	 	Total	 	
 	 	 	 	
 	 	(In millions)	 	
2006	 	$	25	 	
2007	 	 	21	 	
2008	 	 	16	 	
2009	 	 	14	 	
2010	 	 	13	 	
Thereafter	 	 	61	 	
 	 	 	 	
 	Total	 	$	150	 	
 	 	 	 	
      In August 2004, we entered into a contract to purchase 1,540 aluminum railcars from Freight Car America, formerly Johnstown America Corporation, to be used for the transportation of low sulfur coal from Wyoming to NRG’s coal burning generating plants, including our New York and South Central 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. The lease was amended on August 2, 2005 to include an additional 40 railcars, bringing the total number of leased railcars to 1,540. Delivery of the railcars from

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Freight Car America commenced in February 2005 and was completed by August 2005. We have assigned certain of our rights and obligations for the 1,540 railcars under the purchase agreement with Freight Car America to GE. Accordingly, the railcars which we lease from GE under the arrangement described above were purchased by GE from Freight Car America in lieu of our purchase of those railcars.
 	 	
 	Coal Purchase and Transportation Commitments	
      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. Future payments under this agreement and other outstanding agreements for the years ending after December 31, 2005 are estimated as follows:
 	 	 	 	 	 	
 	 	Total	 	
 	 	 	 	
 	 	(In millions)	 	
2006	 	$	192	 	
2007	 	 	106	 	
2008	 	 	48	 	
2009	 	 	49	 	
2010	 	 	3	 	
Thereafter	 	 	18	 	
 	 	 	 	
 	Total	 	$	416	 	

 	 	
 	International	
      Two of our wholly-owned, indirect subsidiaries are severally responsible for the prorate payments of principal, interest and related costs incurred in connection with the financing of our equity investment in the unincorporated joint venture Gladstone Power Station. At December 31, 2005, we were obligated for the loan of AUD 88 million (approximately US $65 million) in principal. This loan is scheduled to be fully repaid on March 31, 2009.
 	 	
 	NRG FinCo Settlement	
      In May 2001, our wholly-owned subsidiary, NRG FinCo, entered into a $2.0 billion revolving credit facility. The facility was established to finance the acquisition, development and construction of certain power generating plants located in the United States and to finance the acquisition of turbines for such facilities. The facility provided for borrowings of base rate loans and Eurocurrency loans and was secured by mortgages and security agreements in respect of the assets of the projects financed under the facility, pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects, and by guaranties from each such subsidiary or affiliate. The NRG FinCo secured revolver was initially scheduled to mature on May 8, 2006; however, due to defaults hereunder by NRG FinCo and applicable guarantors, the lenders accelerated all outstanding obligations on November 6, 2002. As of our emergence from bankruptcy, $1.1 billion was outstanding under the facility, and there was an aggregate of approximately $58 million of accrued but unpaid interest and commitment fees. Of this, $842 million was allowed in unsecured claims under the NRG plan of reorganization, and was settled at the time of our emergence. The remaining balance will be satisfied when the NRG FinCo lenders exercise their perfected security interests in our Nelson, Audrain and Pike projects. During 2004, we sold our Nelson assets for approximately $20 million and certain assets of our Pike project for $17 million. The proceeds from these sales were paid to the lenders. As of December 31, 2005, we hold assets in our Audrain project, principally property, plant and equipment, and some remaining ancillary equipment in our Pike project of approximately $115 million and $3 million, respectively. Proceeds from the sale of these assets are owed to the NRG FinCo lenders, accordingly there are liabilities reflected in other bankruptcy settlement and within discontinued operations for the same amount on our consolidated balance sheet. We are in the process of marketing for sale the remaining Pike equipment on behalf of the NRG FinCo lenders. The

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NRG FinCo lenders have authority under their perfected security interest to accept or reject all offers. On December 8, 2005, we entered into an Asset Purchase and Sale Agreement to sell all of the assets of Audrain to AmerenUE, a subsidiary of Ameren Corporation . Accordingly, we have classified Audrain as discontinued operations. The purchase price is $115 million and is expected to close in the second quarter of 2006. In accordance with a Term Sheet Agreement with the NRG FinCo lenders, we have the right to retain certain proceeds from the sale as a success fee. Accordingly, we expect to record a gain on the sale of $15 million upon closing.
 	 	
 	NYISO Claims	
      In November 2002, NYISO notified us of claims related to New York City mitigation adjustments, general NYISO billing adjustments and other miscellaneous charges related to sales between November 2000 and October 2002. New York City mitigation adjustments totaled approximately $11 million. The issue related to NYISO’s concern that NRG would not have sufficient revenue to cover subsequent revisions to its energy market settlements. As of December 31, 2005, NYISO held approximately $4 million in escrow for such future settlement revisions.
 	 	
 	Legal Issues	
      Set forth below is a description of our material legal proceedings. Pursuant to the requirements of SFAS 5, “Accounting for Contingencies,”  and related guidance, we record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments could occur, there can be no certainty that we may not ultimately incur charges in excess of presently recorded reserves. A future adverse ruling or unfavorable development could result in future charges which could have a material adverse effect on NRG’s consolidated financial position, results of operations or cash flows.
      With respect to a number of the items listed below, management has determined that a loss is not probable or the amount of the loss is not reasonably estimable, or both. In some cases, management is not able to predict with any degree of substantial certainty the range of possible loss that could be incurred. Notwithstanding these facts, management has assessed each of these matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.
      In addition to the legal proceedings noted below, we are parties to other litigation or legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect our consolidated financial position, results of operations or cash flows.
      The Company believes that it has valid defenses to the legal proceedings and investigations described below 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 below, the Company is unable to predict the outcome of 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.

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 	California Electricity and Related Litigation	
      NRG, WCP, WCP’s four operating subsidiaries, Dynegy, Inc. and numerous other unrelated parties are the subject of numerous lawsuits arising based on events occurring in the California power market. The complaints primarily allege that the defendants engaged in unfair business practices, price fixing, antitrust violations, and other market “gaming” activities. Certain of these lawsuits originally commenced in 2000 and 2001, which seek unspecified treble damages and injunctive relief, were consolidated and made a part of a Multi-District Litigation proceeding before the U.S. District Court for the Southern District of California. In December 2002, the district court found that federal jurisdiction was absent and remanded the cases back to state court. On December 8, 2004, the U.S. Court of Appeals for the Ninth Circuit affirmed the district court in most respects. On March 3, 2005, the Ninth Circuit denied a motion for rehearing. On May 5, 2005, the case was remanded to California state court and, under a scheduling order, defendants filed their objections to the pleadings. On July 22, 2005, based upon the filed rate doctrine and federal preemption, the court dismissed NRG Energy, Inc. without prejudice, leaving only subsidiaries of WCP remaining in the case. On October 3, 2005, the court sustained defendants’ demurrer dismissing the case against all remaining defendants. On December 2, 2005, the plaintiffs filed their notice of appeal from the dismissal.
      In addition to the cases discussed above, other cases, including putative class actions, have been filed in state and federal court on behalf of business and residential electricity consumers that name NRG and/or WCP and/or certain subsidiaries of WCP, in addition to numerous other defendants. The complaints allege the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades, and violated California’s antitrust law and unfair business practices law. The complaints seek restitution and disgorgement, civil fines, compensatory and punitive damages, attorneys’ fees and declaratory and injunctive relief. Motion practice is proceeding in these cases and dispositive motions have been filed in several of these proceedings. In the above referenced cases relating to natural gas, Dynegy is defending WCP and/or its subsidiaries pursuant to an indemnification agreement and will be the responsible party for any loss. In cases relating to electricity, Dynegy’s counsel is representing it and WCP and/or its subsidiaries with each party responsible for half of the costs and each party shall be responsible for half of any loss. Where NRG is named as a party in an electricity case, it is defending the case and bears its own costs of defense.
 	 	
 	FERC Proceedings	
      There are proceedings in which WCP and WCP subsidiaries are parties, which either are 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 Cal ISO, the California Department of Water Resources, or CDWR, and the State of California. The CDWR claim involves a February 2002 complaint filed by the State of California demanding that FERC abrogate the CDWR contract between the State and subsidiaries of WCP and seeking refunds associated with revenues collected from CDWR by WCP. In 2003, FERC rejected this demand and subsequently denied rehearing. The case was appealed to the U.S. Court of Appeals for the Ninth Circuit where all briefs were filed and oral argument was held December 8, 2004. Dynegy is indemnified by WCP and WCP is responsible for any loss unless any such loss resulted from Dynegy’s gross negligence or willful misconduct.
 	 	
 	New York Operating Reserve Markets	
      Consolidated Edison and others petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of FERC’s refusal to order a re-determination of prices in the New York Independent System Operator, or NYISO, operating reserve markets for a two month period in 2000. On November 7, 2003, the court found that NYISO’s method of pricing spinning reserves violated the NYISO tariff. On March 4, 2005, FERC issued an order favorable to NRG 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

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NYISO was correct not to use its authority to revise the prices in this market. A motion for rehearing of the order was filed before the April 3, 2005 deadline and on November 17, 2005 FERC denied rehearing.
 	 	
 	Connecticut Congestion Charges	
      On November 28, 2001, CL&P sought recovery in the U.S. District Court for Connecticut for amounts it claimed were owed for congestion charges under the October 29, 1999 Standard Offer Services Contract. CL&P withheld approximately $30 million from amounts owed to PMI under contract and PMI counterclaimed. CL&P’s motion for summary judgment, which PMI opposed, remains pending. We cannot estimate at this time the overall exposure for congestion charges for the term of the contract prior to the implementation of standard market design, which occurred on March 1, 2003; however, such amount has been fully reserved as a reduction to outstanding accounts receivable.
 	 	
 	New York Public Interest Research Group	
      On October 24, 2005, the U.S. Court of Appeals for the Second Circuit issued its opinion in New York Public Interest Research Group (NYPIRG) v. Stephen L. Johnson, Administrator, U.S. Environmental Protection Agency.  In 2000, the NYSDEC issued a NOV to the prior owner of the Huntley and Dunkirk stations. After an unsuccessful challenge to the stations’ Title V air quality permits by NYPIRG, it appealed. The Second Circuit held that, during the Title V permitting process for the two stations, the 2000 NOV should have been sufficient for the NYSDEC to have made a finding that the stations were out of compliance. Accordingly, the court stated that the EPA should have objected to the Title V permits on that basis and the permits should have included compliance schedules. On June 3, 2005, the consent decree among NYSDEC, Niagara Mohawk Power Corporation and NRG was entered in federal court, settling the substantive issues discussed by the Second Circuit in its decision. NYSDEC is in the process of incorporating the consent decree obligations into the Huntley and Dunkirk Title V permits so as to make them permit conditions, an action we believe is supported by the decision. On January 12, 2006, the NYSDEC, the EPA and NRG filed individual petitions for rehearing with the Second Circuit. On January 31, 2006, the court denied the petitions of the NYSDEC and EPA. NRG’s petition for rehearing en banc remains pending.
 	 	
 	Station Service Disputes	
      On October 2, 2000, NiMo commenced an action against NRG in New York state court seeking damages related to NRG’s alleged failure to pay retail tariff amounts for utility services at the Dunkirk Plant between June 1999 and September 2000. The parties agreed to consolidate this action with two other actions against the Huntley and Oswego Plants. On October 8, 2002, by stipulation and order, this action was stayed pending submission to FERC of some or all of the disputes in the action. The contingent loss from this case is approximately $26 million, and at this time we believe we are adequately reserved. In a companion action at FERC, NiMo asserted the same claims and legal theories, and on November 19, 2004, FERC denied NiMo’s petition and ruled that the NRG facilities could net their service obligations over each 30 calendar day period from the day NRG acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities because they are interconnected to transmission and not to distribution. On April 22, 2005, FERC denied NiMo’s motion for rehearing. NiMo appealed to the U.S. Court of Appeals for the D.C. Circuit which, on May 12, 2005, consolidated the appeal with several pending station service disputes involving NiMo. All parties filed their briefs prior to the January 17, 2006 deadline.
      On December 14, 1999, NRG acquired certain generating facilities from CL&P. A dispute arose over station service power and delivery services provided to the facilities. On December 20, 2002, as a result of a petition filed at FERC by Northeast Utilities Services Company on behalf of itself and CL&P, FERC issued an order finding that, at times when NRG 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. In August 2003, the parties agreed to submit the dispute to binding arbitration, however, the parties have yet to agree on a description of the dispute and on the appointment of a neutral arbitrator. The contingent loss from this case could exceed $5 million, and at this time we believe we are adequately reserved.

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 	Itiquira Energetica, S.A.	
      NRG’s Brazilian project company, Itiquira Energetica S.A., or Itiquira, the owner of a 156 MW hydro project in Brazil, is in arbitration with the former Engineering, Procurement and Construction, or EPC, contractor for the project, Inepar Industria e Construcoes, or Inepar. The dispute was commenced in arbitration by Itiquira in September of 2002 and pertains to certain matters arising under the EPC contract between the parties. Itiquira sought Real 140 million and asserted that Inepar breached the contract. Inepar sought Real 39 million and alleged that Itiquira breached the contract. On September 2, 2005, the arbitration panel ruled in favor of Itiquira, awarding it Real 139 million and Inepar Real 4.7 million. Due to interest accrued from the commencement of the arbitration to the award date, Itiquira’s award is increased to approximately Real 227 million (approximately $97 as of December 31, 2005). Itiquira has commenced the lengthy process in Brazil to execute on the arbitral award. We are unable to predict the outcome of this execution process. On October 14, 2005, Inepar filed with the arbitration panel a request for clarifications of the ruling and Itiquira objected. On December 21, 2005, Inepar’s request for clarifications was denied. Due to the uncertainty of the collection process, NRG is accounting for receipt of any amounts as a gain contingency.
 	 	
 	CFTC Trading Litigation	
      On July 1, 2004, the Commodities Futures Trading Commission, or CFTC, filed a civil complaint against NRG 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 November 17, 2004, a bankruptcy court hearing was held on the CFTC’s motion to reinstate its expunged bankruptcy claim, and on NRG’s motion to enforce the provisions of the NRG plan of reorganization, thereby precluding the CFTC from continuing its federal court action. The bankruptcy court has yet to schedule a hearing or rule on the CFTC’s pending motion to reinstate its expunged claim. On December 6, 2004, a federal magistrate judge issued a report and recommendation that NRG’s motion to dismiss be granted. That motion to dismiss was granted by the federal district court in Minnesota on March 16, 2005. On May 13, 2005 the CFTC filed a notice of appeal with the U.S. Court of Appeals for the Eighth Circuit. The CFTC filed its brief on August 9, 2005, and on September 29, 2005 NRG filed its brief. On October 28, 2005, the CFTC filed its reply brief.
 	 	
 	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, as such claims are resolved, the claimants are paid from the reserve on the same basis as if they had been paid out in the bankruptcy. To the extent the aggregate amount required to be paid on the disputed claims exceeds the amount remaining in the funded claims reserve, we will be obligated to provide additional cash and common stock to the satisfy the claims. Any excess funds in the disputed claims reserve will be reallocated to the creditor pool for the pro rata benefit of all allowed claims. The contributed common stock and cash in the reserves is held by 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.
      The face amount of the remaining unresolved claims is approximately $35 million, plus unresolved claims relating to the California power crisis in 2000-2001 and other claims of indefinite amount, but the Company estimates that the actual amount of these claims, once settled, will be less than $35 million. Based on these estimates, the Company believes that in order to assure sufficient funds to satisfy all remaining disputed claims the reserve needs to retain approximately $7 million in cash and approximately 650,000 shares of common stock. The reserve currently holds cash and stock in excess of these amounts, and the Company intends to make a supplemental distribution of the surplus on or about April 1, 2006. The total value of the planned distribution is approximately $137 million, based on the closing stock price on March 3, 2006, consisting of approximately $25 million in cash and 2,541,000 shares of NRG common stock. NRG’s

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chapter 11 creditors holding allowed claims in Class 5 are expected to receive approximately $22.13 per $1,000.00 of allowed claim, consisting of $4.05 in cash and 0.41 shares of NRG common stock. Creditors holding Class 6 allowed claims are expected to receive approximately $19.97 per $1,000.00 of allowed claim, consisting of $1.89 in cash and 0.41 shares of NRG common stock.
 	 	
Note 26 —	Regulatory Matters	
      With the exception of NRG’s Thermal and Chilled Water business, NRG’s operations are not regulated operations subject to SFAS 71 and NRG does not record assets and liabilities that result from the regulated ratemaking processes in the same manner as do regulated public utilities. NRG does operate, however, in a highly regulated industry and we are subject to regulation by various federal and state agencies. As such we are affected by regulatory developments in the regions in which we operate.
 	 	
 	Northeast Region	

 	RMR Agreements	
      During 2005, NRG’s Devon, Middleton and Montville stations operated under RMR agreements with ISO-NE that expired at the end of 2005. On November 1, 2005, NRG filed new RMR agreements with FERC in order provide for the continued provision of reliability services from these resources. Following the filing of interventions and protests challenging the proposed rates and provisions of the filed RMR agreements, NRG entered into a settlement agreement with the Connecticut Department of Public Utility Control, the Connecticut Office of Consumer Counsel, and ISO-NE that was filed with FERC on December 20, 2005, and that provided for the acceptance of new RMR agreements as described below, or Settlement RMR Agreements. The Commission accepted the Settlement RMR Agreements on February 1, 2006, establishing rates effective January 1, 2006 and effect immediately upon the expiration of the existing RMR agreements.
      Under the Settlement RMR Agreements, NRG is entitled to annual fixed revenue requirement of $98 million, allocated among the stations, subject to NRG meeting the availability requirements specified therein. In addition, NRG is also entitled to retain 35% of its market revenues from the subject stations, while crediting 65% of such revenues against the monthly availability payments there under. The Settlement RMR Agreements specify that they remain in effect until a Location Installed Capacity market, or LICAP, or other similar capacity payment mechanism, is fully implemented or as FERC may otherwise determine if it approves a transition program for LICAP. In addition, the Settlement RMR Agreements contain some new termination provisions. For example, the Devon RMR agreement will terminate ninety days after the commencement of Locational Forward Reserve Market, but no earlier than January 1, 2007. In certain circumstances, after January 1, 2007, the Connecticut entities will be allowed to seek termination by filing a Section 206 complaint at FERC.
      On February 15, 2006, we reported to FERC and to ISO-NE that for two days in January 2006, after unit 12 at Devon had been removed from service for needed maintenance, the unit was erroneously reported to ISO-NE as available. We further reported that when ISO-NE dispatched the Devon units on January 25, 2006, and unit 12 was unable to respond, inaccurate information was provided to ISO-NE. We are investigating the matter and are cooperating with FERC and ISO-NE.
 	 	
 	LICAP Market Developments	
      On August 31, 2004, ISO-NE filed its proposal for designing and implementing a Location Installed Capacity market, or LICAP, with FERC. On June 15, 2005, the FERC administrative law judge assigned to the proceeding issued her decision, recommending that FERC approve ISO-NE’s proposed LICAP design with a few modifications. On August 10, 2005, FERC issued an order delaying the implementation of a LICAP market from January 1, 2006 until October 1, 2006, and, in subsequent orders, assigned the proceeding to a settlement judge and required the commencement of settlement negotiations.
      On January 31, 2006, the settlement judge reported to FERC that an agreement had been reached that provides for interim capacity payments for all generators in New England and the establishment of a forward

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procurement market design. The settlement includes over 100 parties, including suppliers, load-serving entities, state regulators, and ISO-NE. The settlement is not final and, moreover, it is not unanimous, and thus there is some possibility of continued litigation regarding LICAP and/or the settlement proposal. NRG supports the settlement in principle, and will continue to work to finalize the settlement. For our Connecticut units subject to the Settlement RMR Agreements, any transition payment will be credited against the monthly availability payment for those units, resulting in no additional revenues for those units. Our other New England generation units are expected to be eligible for the transition payments, and thus we expect the transition period to be net positive as compared to the status quo. The forward procurement market concept, when implemented, should provide a competitive market price for all our capacity, while enhancing opportunities for NRG to competitively repower its New England facilities.
 	 	
 	Connecticut	
      On September 12, 2005, Richard Blumenthal, Attorney General for the state of Connecticut, the Connecticut Office of Consumer Counsel, the Connecticut Municipal Electric Energy Cooperative and the Connecticut Industrial Energy Consumers filed a complaint against ISO-NE pursuant to sections 206 and 212 of the Federal Power Act, seeking to amend the ISO-NE’s Market Rule 1 to require all electric generation facilities not currently operating under an RMR agreement in Connecticut to be placed under cost-of-service rates. On October 20, 2005, NRG, among others, filed an answer requesting that the Commission dismiss the complaint. NRG’s Connecticut Jet Power and Norwalk facilities are not currently operating pursuant to an RMR agreement.
 	 	
 	New York	
      NRG’s New York City generation is presently subject to price mitigation in the installed capacity market. When the capacity market is tight, the price NRG receives is capped 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 revenues from capacity sales over revenues obtained in previous capacity markets. On January 7, 2005, NYISO filed its proposed installed capacity, or ICAP, demand curves for the following capacity years: 2005-06, 2006-07 and 2007-08. On April 21, 2005, FERC accepted the NYISO’s proposed demand curves, with certain minor revisions. Based upon NYISO’s May 20, 2005 compliance filing, the monthly reference point for the demand curve is $14.34 per KW/month of ICAP for the 2006-207 capacity year. Following the New York State Reliability Council’s, or NYSRC, report on the ICAP requirement for 2006-2007, on February 9, 2006, NYISO raised the New York City location capacity requirement to 83% from 80%. The existing in-city mitigation measures, however, will continue to apply to us when the capacity market is tight, preventing us from obtaining these higher prices.
      On October 6, 2005, NiMo filed a complaint against NYISO and the NYSRC requesting that FERC direct the NYSRC to modify its methodology for calculating the statewide installed reserve margin. NiMo’s complaint also alleges that the NYISO incorrectly calculates the installed capacity requirement. FERC issued an order on February 2, 2006, denying NiMo’s complaint and directing that the NiMO work with NYISO and NYSRC to modify its methodology for calculating the statewide Installed Reserve Margin.
      The dispute is continuing with respect to high prices for spinning reserves, or SRs, and non-spinning reserves, or NSR, in the NYISO-administered markets during the period from January 29 to March 27, 2000. Certain entities have argued that the NYISO acted unreasonably is declining to invoke Temporary Extraordinary Operating Procedures, or TEPs, to recalculate prices and the markets should be resettled for various reasons. In a series of orders, FERC declined to grant the requested relief. On appeal, the U.S. Court of Appeals for the D.C. Circuit, or DC Circuit, remanded the case to FERC to further explain its decision not to utilize TEP to remedy certain market issues. On March 4, 2005, FERC issued an order reaffirming that (i) the NYISO acted reasonably in not invoking its TEP, (ii) NYISO did not violate its tariff, and (3) refunds should not be granted, and this order was reaffirmed on rehearing on November 17, 2005. These orders have been appealed to the D.C. Circuit.

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      A similar dispute remains with respect to high prices in the NYISO energy market on May 8 and 9, 2000 Those high prices resulted from bids submitted by the New York Power Authority for its Blenheim-Gilboa facility, a pumped storage unit. Certain parties have challenged NYISO’s issuance of an Energy Limited Resources Extraordinary Corrective Action utilizing its TEP authority to reduce the prices and complained to FERC requesting NYISO restore the original real-time market prices. The Commission denied the complaints. On appeal, the D.C. Circuit found that FERC had not adequately addressed the complainants’ contention that there was no Market Design Flaw that forced NYPA to submit high bids for Blenheim-Gilboa facility and remanded the case to FERC. In its March 4, 2005 order on remand, FERC found that NYISO’s tariff did not contain a market design flaw, a necessary prerequisite to invoking TEP. FERC therefore ordered NYISO to pay refunds and collect surcharges designed to reinstate the original market clearing prices for energy for the real-time market determined on May 8 and 9, 2000, and to file a refund report; this order was reaffirmed on rehearing. These orders have been appealed to the D.C. Circuit. Also on rehearing, the Commission set for settlement and hearing proceedings the issues raised as to the amount of refunds and the means by which NYISO may determine them (i.e., the calculation of the refund amount), the determination of opportunity costs, and the determination and treatment of amounts that the NYISO may be unable to collect from its customers,
      On December 9, 2005, NYISO submitted proposed revisions to its tariff to include negotiated compensation provisions for existing generators providing “Black Start and System Restoration Services” (Black Start and System Restoration Services) in the Consolidated Edison Company of New York, Inc.’s, or ConEd, transmission district. NRG’s Arthur Kill and Astoria Gas Turbine facilities provide such blackstart services and NRG supports NYISO’s filing. On January 27, 2006, FERC issued a deficiency letter requiring NYISO to provide additional cost support for its filing.
      The rate that the NRG generation facilities in New York are currently paid for voltage support service, or VSS, was scheduled to expire on December 31, 2005. On December 5, 2005, the NYISO filed for an extension of the VSS rate for a period of 120 days (from January 1 to April 4, 2006). On December 30, 2005, FERC issued an order accepting the NYISO’s proposed extension, subject to refund, and referring the proceeding to the FERC’s Dispute Resolution Service. Settlement discussions are ongoing.
 	 	
 	Mid Atlantic	
      On August 31, 2005, PJM filed a proposed reliability pricing model, or RPM, that, if accepted by FERC, would modify the capacity obligations imposed on load, and related market mechanisms within PJM. The primary features of the RPM proposal are the establishment of locational capacity markets using a downward-sloping demand curve similar to the demand curve model adopted in New York; a four-year-forward commitment of capacity resources; establishing separate obligations and auction procurement mechanisms for quick start and load following resources; allowing certain planned resources, transmission upgrades and demand resources to compete with existing generation resources to satisfy capacity requirements; and market power mitigation rules (which are primarily applied to existing generation resources, such as NRG’s). On October 19, 2005, NRG filed an intervention and protest in response to the PJM RPM proposal. On December 8, 2005, FERC issued a notice establishing a technical conference on the issues raised by PJM’s RPM filing which was conducted on February 2, 2006. The outcome of this proceeding is not possible to predict with certainty, nor is the timing of any implementation of PJM’s proposed RPM model.
      On November 16, 2005, PJM filed a comprehensive settlement agreement establishing new scarcity pricing rules for the PJM markets, as well as clarifying the circumstances of when suppliers will be subject to offer caps with respect to transmission constraints. The settlement agreement addresses certain issues involving the mitigation of market power that may result from congestion in PJM’s service territory, provisions for scarcity pricing, increased payments to frequently mitigated units, and competitive issues surrounding certain of PJM’s internal interfaces. NRG’s facilities may be located in the scarcity pricing regions, and furthermore, are mitigated a high percentage of the time and thus may be impacted by these changes. The settlement agreement and related tariff provisions were accepted by FERC effective January 26, 2006.

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 	South Central Region	
      On January 3, 2005, Entergy submitted a petition for declaratory order requesting guidance on issues associated with its proposal to establish an independent coordinator of transmission, or ICT. Entergy requested FERC’s guidance on whether the functions to be performed by the ICT will cause it to become a public utility under the Federal Power Act or the transmission provider under Entergy’s Open Access Transmission Tariff, or OATT, and whether Entergy’s transmission pricing proposal satisfies FERC’s transmission pricing policy.
      On March 22, 2005, FERC granted Entergy’s Petition for declaratory order, stating that the implementation of the ICT proposal on an experimental basis will permit a transmission decision-making process that is independent of control by any market participant or class of participants. On May 23, 2005, FERC issued an order granting rehearing for further consideration but has not yet acted on rehearing. On May 27, 2005, Entergy submitted a Section 205 filing detailing the enhanced functions that the ICT will perform. Numerous interventions and protests were filed in response, a technical conference has been held and the proceeding is ongoing.
 	 	
 	Western Region	
      NRG has negotiated RMR agreements with the Cal ISO for one-year terms for all of the WCP capacity. NRG has filed these RMR agreements with FERC, with an effective date of January 1, 2006, for each of our Encina and Cabrillo II plants, and these RMR agreements have been accepted by FERC. Unit 4 was not designated by Cal ISO as RMR unit for 2006 until December 22, 2005, and its RMR agreement was accepted separately by FERC on February 14, 2006. MML Energy North America, LLC protested the RMR agreement for Unit 4 by Cal ISO and has requested rehearing of the order. Cal ISO did not designate the El Segundo plant as an RMR for 2006. A tolling agreement for the total capacity of the El Segundo plant has been executed with a major load serving entity for the period May 2006 through April 2008.
      All of our California plants are subject to FERC’s “must-offer” requirements requiring any generator capable of operating and not subject to a bilateral agreement to make its capacity available to Cal ISO. On January 13, 2006, FERC accepted Cal ISO’s proposal to increase the “softcap” from $250 to $400 per MWh effective January 1, 2006, and declined to convert the softcap to a firm price-cap.
 	 	
Note 27 —	Environmental Matters	
      The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and our facilities are not exempted from coverage, we could be required to make extensive modifications to further reduce potential environmental impacts. In general, the effect of future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions on our operations.
      Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at the facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by the party in connection with any releases or threatened releases. These laws impose strict (without fault) and joint and several liability. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. On January 18, 2006, NRG Indian River Operations, Inc. received a letter of informal notification from DNREC stating that it may be a potentially responsible party with respect to the Burton Island Landfill, along with Delmarva Power. The letter signals only that an investigation is to be commenced and is not a conclusive determination. Further, the Burton Island Landfill is a site that would potentially qualify for a remedy under a “Voluntary Cleanup Program” or VCP. We have signaled our interest in being considered for a VCP should matters progress. With the exception of the foregoing, NRG has not been named as a potentially responsible party with respect to any off-site waste disposal matter.

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      As part of acquiring existing generating assets, we have inherited certain environmental liabilities associated with regulatory compliance and site contamination. Often potential compliance implementation plans are changed, delayed or abandoned due to one or more of the following conditions: (a) extended negotiations with regulatory agencies, (b) a delay in promulgating rules critical to dictating the design of expensive control systems, (c) changes in governmental/regulatory personnel, (d) changes in the interpretation and enforcement of existing laws and regulations, (e) changes in governmental priorities or (f) selection of a less expensive compliance option than originally envisioned.
      Trust funds — during our period of bankruptcy as well as inherited circumstances in our South Central region, we deposited approximately $20 million in trust funds to maintain financial assurance to cover costs associated with a number of future remediation items. Our Northeast region has a total of approximately $15 million in trust funds and our South Central has approximately $5 million in trust funds as described in the discussions below.
      Northeast Region. Significant amounts of ash are contained in landfills at on and off-site locations. At Dunkirk, Huntley, Somerset and Indian River, ash is disposed of at landfills owned and operated by NRG. NRG maintains financial assurance to cover costs associated with landfill closure, post-closure care and monitoring activities. NRG has funded a trust in the amount of approximately $6 million to provide such financial assurance in New York and approximately $7 million in Delaware. NRG must also maintain financial assurance for closing interim status “RCRA (Resource Conservation and Recovery Act) facilities” at the Devon, Middletown, Montville and Norwalk Harbor Generating Stations and has funded a trust in the amount of approximately $2 million accordingly.
      NRG 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. NRG 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. NRG has proposed a remedial action plan to be implemented over the next two to eight years (depending on the station) to address historical ash contamination at the facilities. The total estimated cost is not expected to exceed $1.4 million. Remedial obligations at the Arthur Kill generating station have been established in discussions between NRG and the NYSDEC and are estimated to be approximately $1 million. Remedial investigations continue at the Astoria generating station with long-term clean-up liability expected to be approximately $3 million. While installing groundwater-monitoring wells at Astoria to track our remediation of an historical fuel oil spill, the drilling contractor encountered deposits of coal tar in two borings. NRG reported the coal tar discovery to the NYSDEC in 2003 and delineated the extent of this contamination. NRG 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.
      In September 2001, we experienced an underground fuel line leak at our Vienna Generating Station, resulting in a small release of oil free product, which was contained. NRG promptly reported the event to the relevant state agencies and continues to work with the Maryland Department of the Environment, or DEP, to develop any remediation requirements. Ongoing monitoring has indicated that the product is stable. NRG submitted a site assessment report and proposed remediation plan to Maryland DEP but the agency has not formally responded to those documents. Based upon work completed by a remediation contractor retained by NRG, long-term clean up liability in connection with this matter is not expected to exceed $1 million.
      We currently estimate that we will incur total environmental capital expenditures of approximately $367 million during 2006 through 2011 for the facilities in New York, Connecticut, Delaware and Massachusetts. These expenditures will be primarily related to installation of particulate, SO 2  and NOX controls, as well as installation of BTA under the Phase II 316(b) Rule.

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 	South Central Region	
      South Central Region. Liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated on site at the Big Cajun II Generating Station are addressed through the use of a trust fund maintained by NRG in the amount of approximately $5 million. Annual payments are made to the fund in the amount of approximately $0.1 million.
      We currently estimate approximately $252 million of capital expenditures will be incurred during the period 2006 through 2011 for our South Central facilities, primarily related to installation of particulate, SO 2  and NOx controls, as well as studies for installation of BTA under the Phase II 316(b) Rule.
 	 	
 	Western Region	
      Western Region. The Asset Purchase Agreements for the Long Beach, El Segundo, Encina, and San Diego gas turbine generating facilities provide that SCE and San Diego Gas & Electric or SDG&E, as sellers retain liability, and indemnify NRG, for existing soil and groundwater contamination that exceeds remedial thresholds in place at the time of closing. NRG and its business partner identified existing contamination and provided the results to the sellers. SCE and SDG&E agreed to address this identified contamination and are undertaking corrective action at the Encina and San Diego gas turbine generating sites. NRG could incur related costs if SCE and SDG&E did not complete their corrective action responsibilities. Spills and releases of various substances have occurred at these sites since NRG 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. NRG excavated and disposed of contaminated soils to the greatest extent permitted by existing laws. Following NRG’s formal request, the Los Angeles Regional Water Quality Control Board agreed to allow the remaining contaminated soils to stay 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 un-quantified remediation in inaccessible areas may be required in the future. Given the current uncertainties at this facility, it is difficult to accurately estimate the resultant clean up liability.
 	 	
 	Other North America	
      Resource Recovery. Liabilities associated with closure, post-closure care and monitoring of the Becker refuse derived fuel ash landfill are addressed through the use of a letter of credit maintained by NRG in the amount of approximately $3 million.

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Note 28 —	Cash Flow Information	
      Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Predecessor	 	
 	 	Reorganized NRG	 	 	 	Company	 	
 	 	 	 	 	 	 	 	
 	 	 	 	For the Period	 	 	 	For the Period	 	
 	 	Year Ended	 	 	Year Ended	 	 	December 6 -	 	 	 	January 1 -	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	 	December 5,	 	
 	 	2005	 	 	2004	 	 	2003	 	 	 	2003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Interest paid (net of amount capitalized)	 	$	257	 	 	$	295	 	 	$	87	 	 	 	$	182	 	
Income taxes paid	 	 	21	 	 	 	34	 	 	 	2	 	 	 	 	27	 	
Non-cash investing and financing activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Investment in WCP by contributing fixed assets	 	 	—	 	 	 	2	 	 	 	—	 	 	 	 	—	 	
 	Reduction to fixed assets due to liquidated damages	 	 	—	 	 	 	15	 	 	 	—	 	 	 	 	—	 	
 	Addition to fixed assets due to conditional asset retirement obligations	 	 	4	 	 	 	—	 	 	 	—	 	 	 	 	—	 	
 	Conversion of accrued salaries to stockholders’ equity	 	 	2	 	 	 	—	 	 	 	—	 	 	 	 	—	 	
 	Addition to treasury stock for the maximum purchase price adjustment	 	 	8	 	 	 	—	 	 	 	—	 	 	 	 	—	 	
 	Accrued deferred acquisition costs	 	 	2	 	 	 	—	 	 	 	—	 	 	 	 	—	 	

Note 29 —	Guarantees and Other Contingent Liabilities	
      In November 2002, the FASB issued FIN 45. In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly, we applied the provisions of FIN 45 to all of the guarantees.
      We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchase and sale agreements, commodity sale and purchase agreements, joint venture agreements, operations and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties. These contracts generally indemnify the counter-party for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. In many cases, our maximum potential liability cannot be estimated, since some of the underlying agreements contain no limits on potential liability. In accordance with FIN 45, we estimated that the current fair value for issuing these guarantees is approximately $15 million as of December 31, 2005 and the liability in this amount is included in our other long term obligations.
      The material guarantees, within the scope of FIN 45, are as follows:
 	 	 	
 	• 	Standby letters of credit and surety bonds — At December 31, 2005, we and our consolidated subsidiaries were contingently obligated for a total of approximately $321 million under standby letters of credit. Most of these letters of credit are issued in support of our obligations to perform under commodity agreements, financing or other arrangements. These letters of credit expire within one year of issuance, and it is typical for us to renew many of them on similar terms.	

 	As of December 31, 2005, standby letters of credit in amounts totaling approximately $312 million were issued under our $350.0 million corporate funded letter of credit facility, which is reflected in our financial statements. Of this amount, approximately $3 million was issued to support performance obligations of an unconsolidated affiliate of ours. Our Flinders subsidiary had issued approximately	
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 	AUD 12 million (approximately US $9 million) in unfunded letters of credit under an AUD 20 million (approximately US $15 million) working capital and letter of credit facility, described in Note 17 — Debt and Capital Leases.	
 	 	
 	At December 31, 2005, we were also contingently obligated for approximately $4 million under surety bonds to support our prepayment, completion, license, tax or performance bonding requirements. Most of the bonds are supported by a letter of credit under our funded letter of credit facility, which is reflected in our financial statements. All of the bonds expire within one year; however, we expect to renew many of these bonds on a rolling twelve-month basis.	

 	• 	Asset purchases and divestitures — In the normal course of business, we may be asked to provide certain assurances to the counter-parties of our asset sale and purchase agreements. Such assurances may take the form of a guarantee issued by us on behalf of a directly or indirectly held majority-owned subsidiary who included certain indemnifications to a third party (usually the buyer) as described below. Due to the inter-company nature of such arrangements (NRG Energy is essentially guaranteeing its own performance) and the nature of the guarantee being provided (usually the typical representations and warranties that are provided in any asset sales agreement), it is not our policy to recognize the value of such an obligation in our consolidated financial statements. Most of these guarantees provide an explicit cap on our maximum liability, as well as an expiration period, exclusive of breach of representations and warranties.	

 	On April 1, 2005, in conjunction with the sale of our interest in the Enfield Energy Center Ltd, a minority-owned, indirectly held affiliate of ours, we issued a guarantee of the obligations of a subsidiary of ours under the sale and purchase agreement, to the buyers of our interest. The maximum liability for this guarantee was approximately $56 million as of December 31, 2005.	
 	 	
 	At December 31, 2005, our maximum known exposure under asset purchase or sales guarantees was approximately $123 million. On January 1, 2006, we executed a guarantee to a prospective buyer of one of our unconsolidated affiliates. This guarantees the payment of claims related to tax obligations, late payments, and indemnifications, and the maximum liability we estimate under this guarantee is approximately $5 million. This guarantee expires on October 1, 2016. Upon the defeasance of $0.4 million of our Second Priority Notes on February 2, 2006, we retained guarantee obligations related to this indebtedness. For further information, see Note 17 — Debt and Capital Leases.	

 	• 	Commercial sales arrangements — In connection with the purchase and sale of fuel, emission allowances and power generation products to and from third parties with respect to the operation of some of our generation facilities in the U.S., we may be required to guarantee a portion of the obligations of certain of our subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments. As of December 31, 2005, we estimate the maximum liability for this category of guarantee was approximately $91 million. We have subsequently issued additional guarantees or increased existing guarantees of the performance of NRG PMI, with increasing the maximum liability by approximately $19 million. These additional guarantees terminate between December 31, 2006 and December 31, 2008.	
 	 	 	
 	• 	Other types of guarantees — We have issued guarantees of obligations our subsidiaries may incur in provision of environmental site remediation, payment of debt obligations, rail car leases and performance under operating and maintenance agreements. Maximum quantifiable liability under the environmental guarantees is approximately $64 million, most of which is a guarantee for plant removal and site remediation obligations at our Flinders facilities. The maximum quantifiable exposure under the operational guarantees is $25 million, primarily related to our role as operator at the Gladstone power plant. In addition, we have a maximum liability exposure of approximately $1 million under a tax indemnity guarantee to a third party and third-party debt guarantee exposure of approximately $1 million.	
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 	On February 18, 2005 we executed a guarantee to the benefit of our counter-party under a railcar lease. We guarantee the performance and payment obligations of NRG PMI under the railcar lease. Payment obligations include future rental and termination payments, which are estimated to total approximately $48 million over the next five years of the lease, and approximately $46 million over the remainder of the lease, should we elect not to exercise our termination rights. If we do elect to terminate the lease, we will be required to pay $8 million in termination fees, but we will have no obligation to make future lease payments. However, our obligations under this guarantee include additional requirements that would be difficult to quantify until such time as a claim were made. As a result, our maximum potential obligation under this guarantee is of indeterminate exposure, and therefore is not included in the table of maximum exposure maturities in this note.	
      The following table outlines the scheduled expiration of our guarantees, indemnity and other contingent liability obligations, to the extent the maximum liabilities can be quantified and scheduled.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Amount of Guarantee Liabilities Expiration per Period as of	 	
 	 	December 31, 2005 (in millions)	 	
 	 	 	 	
 	 	Total Amounts	 	 	 	 	After 5 Years or	 	
Guarantee Type	 	Committed	 	 	Short-term	 	 	2-3 Years	 	 	4-5 Years	 	 	Indeterminate	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded standby letters of credit	 	$	312	 	 	$	312	 	 	$	—	 	 	$	—	 	 	$	—	 	
Unfunded standby letters of credit	 	 	9	 	 	 	9	 	 	 	—	 	 	 	—	 	 	 	—	 	
Surety bonds	 	 	4	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	
Asset sales guarantee obligations	 	 	123	 	 	 	—	 	 	 	13	 	 	 	—	 	 	 	110	 	
Commodity sales guarantee obligations	 	 	91	 	 	 	62	 	 	 	12	 	 	 	14	 	 	 	3	 	
Other guarantees	 	 	91	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	90	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total guarantees	 	$	630	 	 	$	387	 	 	$	26	 	 	$	14	 	 	$	203	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
      The material indemnities, within the scope of FIN 45, are as follows:
 	 	 	
 	• 	Asset purchases and divestitures — The purchase and sale agreements which govern our asset or share investments and divestitures customarily contain indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a change in tax laws. These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or quantify at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. For those indemnities in which liability is capped, the exposure ranges from $250 thousand up to $50 million. We have no reason to believe that we currently have any material liability relating to such routine indemnification obligations.	
 	 	 	
 	• 	Other indemnities — Other indemnifications we have provided cover operational, tax, litigation and breaches of representations, warranties and covenants. We have also indemnified, on a routine basis in the ordinary course of business, consultants or other vendors who have provided services to us. Our maximum potential exposure under these indemnifications can range from a specified dollar amount to an unlimited amount, depending on the nature of the transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be made or how they will be resolved. We do not have any reason to believe that we will be required to make any material payments under these indemnity provisions.	
      Because many of the guarantees and indemnities we issue to third parties do not limit the amount or duration of our obligations to perform under them, there exists a risk that we may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit our liability exposure, we may not be able to estimate what our liability would be, until a claim was made for payment or performance, due to the contingent nature of these contracts.

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Note 30 —	Sales to Significant Customers	

 	Reorganized NRG	
      For the year ended December 31, 2005 we derived approximately 50.2% of total revenues for majority owned operations from two customers: NYISO accounted for 35.6% and ISO-NE accounted for 14.6%. We account for the revenues attributable to these customers as part of our Northeast segment.
      For the year ended December 31, 2004, we derived approximately 37.8% of our total revenues from majority-owned operations from two customers. NYISO accounted for 28.6% and ISO New England accounted for 9.2%. We account for these revenues attributable to NYISO and ISO New England as part of our Northeast segment.
      For the period December 6, 2003 through December 31, 2003, we derived approximately 39.4% of our total revenues from majority-owned operations from two customers: NYISO accounted for 26.8% and ISO New England accounted for 12.6%. Revenues from NYISO and ISO New England are included in our Northeast segment.
 	 	
 	Predecessor Company	
      For the period from January 1, 2003 through December 5, 2003, sales to one customer, NYISO, accounted for 33.4% of our total revenues from majority-owned operations.
Note 31 — Jointly Owned Plants
 	 	
 	Big Cajun II Unit 3	
      On March 31, 2000, we acquired a 58% interest in the Big Cajun II, Unit 3 generation plant. Entergy Gulf States owns the remaining 42%. Big Cajun II, Unit 3 is operated and maintained by Louisiana Generating pursuant to a joint ownership participation and operating agreement. Under this agreement, Louisiana Generating and Entergy Gulf States are each entitled to their ownership percentage of the hourly net electrical output of Big Cajun II, Unit 3. All fixed costs are shared in proportion to the ownership interests. All variable costs are incurred in proportion to the energy delivered to the owners. Our income statement includes its share of all fixed and variable costs of operating the unit.
 	 	
 	Reorganized NRG	
      Our 58% share of the property, plant and equipment at December 31, 2005 and 2004 was approximately $186 million and $185 million, respectively (included in this amount is construction in progress was $3 million and $2 million, respectively), and the corresponding accumulated depreciation and amortization was approximately $22 million and $12 million, respectively.
 	 	
 	Keystone and Conemaugh	
      In June 2001, we completed the acquisition of an approximately 3.7% interest in both the Keystone and Conemaugh coal-fired generating facilities. The Keystone and Conemaugh facilities are located near Pittsburgh, Pennsylvania and are jointly owned by a consortium of energy companies. We purchased our interest from Conectiv, Inc. Keystone and Conemaugh are operated by GPU Generation, Inc., which sold its assets and operating responsibilities to Sithe Energies. Keystone and Conemaugh both consist of two operational coal-fired steam power units with a combined net output of 1,700 MW, four diesel units with a combined net output of 11 MW and an on-site landfill. The units are operated pursuant to a joint ownership participation and operating agreement. Under this agreement each joint owner is entitled to its ownership ratio of the net available output of the facility. All fixed costs are shared in proportion to the ownership interests. All variable costs are incurred in proportion to the energy delivered to the owners. Our income statement includes our share of all fixed and variable costs of operating the facilities.

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 	Reorganized NRG	
      Our 3.70% and 3.72% share of the Keystone and Conemaugh facilities original cost included in property, plant and equipment at December 31, 2005 was approximately $59 million and $71 million, respectively (included in this amount is construction in progress in the amount of $1 million and $0 million, respectively). The corresponding accumulated depreciation and amortization at December 31, 2005 for Keystone and Conemaugh was approximately $6 million and $8 million, respectively.
      Our 3.70% and 3.72% share of the Keystone and Conemaugh facilities property, plant and equipment at December 31, 2004 was approximately $59 million and $71 million, respectively. The corresponding accumulated depreciation and amortization at December 31, 2004 for Keystone and Conemaugh was approximately $3 million and $4 million, respectively.
Note 32 — Unaudited Quarterly Financial Data
      Summarized quarterly unaudited financial data is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	
 	 	 	 	
 	 	Quarters Ended 2005	 	 	 	
 	 	 	 	 	 	
 	 	March 31	 	 	June 30	 	 	September 30	 	 	December 31	 	 	Total Year	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions, except per share data)	 	
Operating Revenues	 	$	597	 	 	$	579	 	 	$	762	 	 	$	770	 	 	$	2,708	 	
Operating Income/(Loss)	 	 	44	 	 	 	44	 	 	 	(7	)	 	 	157	 	 	 	238	 	
Income From Continuing Operations	 	 	22	 	 	 	22	 	 	 	(37	)	 	 	70	 	 	 	77	 	
Income/(Loss) on Discontinued Operations net of Income Taxes	 	 	1	 	 	 	2	 	 	 	10	 	 	 	(6	)	 	 	7	 	
Net Income/(Loss)	 	$	23	 	 	$	24	 	 	$	(27	)	 	$	64	 	 	$	84	 	
Weighted Average Number of Common Shares Outstanding — Basic	 	 	87	 	 	 	87	 	 	 	84	 	 	 	81	 	 	 	85	 	
Income From Continuing Operations per Weighted Average Common Share — Basic	 	$	0.20	 	 	$	0.21	 	 	$	(0.51	)	 	$	0.79	 	 	$	0.67	 	
Income/(Loss) From Discontinued Operations per Weighted Average Common Share — Basic	 	 	0.01	 	 	 	0.02	 	 	 	0.12	 	 	 	(0.07	)	 	 	0.09	 	
Net Income per Weighted Average Common Share — Basic	 	$	0.21	 	 	$	0.23	 	 	$	(0.39	)	 	$	0.72	 	 	$	0.76	 	
Weighted Average Number of Common Shares Outstanding — Diluted	 	 	88	 	 	 	88	 	 	 	84	 	 	 	92	 	 	 	85	 	
Income From Continuing Operations per Weighted Average Common Share — Diluted	 	$	0.20	 	 	$	0.20	 	 	$	(0.51	)	 	$	0.74	 	 	$	0.66	 	
Income From Discontinued Operations per Weighted Average Common Share — Diluted	 	 	0.01	 	 	 	0.02	 	 	 	0.12	 	 	 	(0.06	)	 	 	0.09	 	
Net Income per Weighted Average Common Share — Diluted	 	$	0.21	 	 	$	0.22	 	 	$	(0.39	)	 	$	0.68	 	 	$	0.75	 	
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 	 	Reorganized NRG	 	
 	 	 	 	
 	 	Quarters Ended 2004	 	 	 	
 	 	 	 	 	 	
 	 	March 31	 	 	June 30	 	 	September 30	 	 	December 31	 	 	Total Year	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions, except per share data)	 	
Operating Revenues	 	$	596	 	 	$	570	 	 	$	605	 	 	$	577	 	 	$	2,348	 	
Operating Income	 	 	118	 	 	 	115	 	 	 	79	 	 	 	81	 	 	 	393	 	
Income From Continuing Operations	 	 	31	 	 	 	69	 	 	 	44	 	 	 	17	 	 	 	161	 	
Income/(Loss) on Discontinued Operations net of Income Taxes	 	 	(1	)	 	 	14	 	 	 	10	 	 	 	2	 	 	 	25	 	
Net Income	 	$	30	 	 	$	83	 	 	$	54	 	 	$	19	 	 	$	186	 	
Weighted Average Number of Common Shares Outstanding — Basic	 	 	100	 	 	 	100	 	 	 	100	 	 	 	99	 	 	 	100	 	
Income From Continuing Operations per Weighted Average Common Share — Basic	 	$	0.31	 	 	$	0.69	 	 	$	0.44	 	 	$	0.17	 	 	$	1.61	 	
Income/(Loss) From Discontinued Operations per Weighted Average Common Share — Basic	 	 	(0.01	)	 	 	0.14	 	 	 	0.10	 	 	 	0.01	 	 	 	0.25	 	
Net Income per Weighted Average Common Share — Basic	 	$	0.30	 	 	$	0.83	 	 	$	0.54	 	 	$	0.18	 	 	$	1.86	 	
Weighted Average Number of Common Shares Outstanding — Diluted	 	 	100	 	 	 	100	 	 	 	101	 	 	 	99	 	 	 	100	 	
Income From Continuing Operations per Weighted Average Common Share — Diluted	 	$	0.31	 	 	$	0.69	 	 	$	0.44	 	 	$	0.17	 	 	$	1.60	 	
Income From Discontinued Operations per Weighted Average Common Share — Diluted	 	 	(0.01	)	 	 	0.14	 	 	 	0.10	 	 	 	0.01	 	 	 	0.25	 	
Net Income per Weighted Average Common Share — Diluted	 	$	0.30	 	 	$	0.83	 	 	$	0.54	 	 	$	0.18	 	 	$	1.85	 	
      For 2005 and for 2004, we have reclassified the financial results of Northbrook New York LLC, Northbrook Energy LLC and Audrain as discontinued operations. Accordingly, 2005 and 2004 quarterly results have been restated to report the results as discontinued.

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Note 33 — Condensed Consolidating Financial Information
      As of December 31, 2005, we have $1.08 billion of Second Priority Notes outstanding. The Second Priority Notes are guaranteed by each of current and future wholly-owned domestic subsidiaries, or Guarantor Subsidiaries. Each of the following Guarantor Subsidiaries fully and unconditionally guarantee the Second Priority Notes.
 	 	 	
Arthur Kill Power LLC	 	NRG Cabrillo Power Operations Inc.	
Astoria Gas Turbine Power LLC	 	NRG Cadillac Operations Inc.	
Berrians I Gas Turbine Power LLC	 	NRG California Peaker Operations LLC	
Big Cajun II Unit 4 LLC	 	NRG Connecticut Affiliate Services Inc.	
Capistrano Cogeneration Company	 	NRG Devon Operations Inc.	
Chickahominy River Energy Corp. 	 	NRG Dunkirk Operations Inc.	
Commonwealth Atlantic Power LLC	 	NRG El Segundo Operations Inc.	
Conemaugh Power LLC	 	NRG Huntley Operations Inc.	
Connecticut Jet Power LLC	 	NRG International LLC	
Devon Power LLC	 	NRG Kaufman LLC	
Dunkirk Power LLC	 	NRG Mesquite LLC	
Eastern Sierra Energy Company	 	NRG MidAtlantic Affiliate Services Inc.	
El Segundo Power II LLC	 	NRG Middletown Operations Inc.	
Hanover Energy Company	 	NRG Montville Operations Inc.	
Huntley Power LLC	 	NRG New Jersey Energy Sales LLC	
Indian River Operations Inc. 	 	NRG New Roads Holdings LLC	
Indian River Power LLC	 	NRG North Central Operations Inc.	
James River Power LLC	 	NRG Northeast Affiliate Services Inc.	
Kaufman Cogen LP	 	NRG Norwalk Harbor Operations Inc.	
Keystone Power LLC	 	NRG Operating Services, Inc.	
Louisiana Generating LLC	 	NRG Oswego Harbor Power Operations Inc.	
Middletown Power LLC	 	NRG Power Marketing Inc.	
Montville Power LLC	 	NRG Rocky Road LLC	
NEO California Power LLC	 	NRG Saguaro Operations Inc.	
NEO Chester-Gen LLC	 	NRG South Central Affiliate Services Inc.	
NEO Corporation	 	NRG South Central Generating LLC	
NEO Freehold-Gen LLC	 	NRG South Central Operations Inc.	
NEO Landfill Gas Holdings Inc. 	 	NRG West Coast LLC	
NEO Power Services Inc. 	 	NRG Western Affiliate Services Inc.	
Norwalk Power LLC	 	Oswego Harbor Power LLC	
NRG Affiliate Services Inc. 	 	Saguaro Power LLC	
NRG Arthur Kill Operations Inc. 	 	Somerset Operations Inc.	
NRG Asia-Pacific, Ltd. 	 	Somerset Power LLC	
NRG Astoria Gas Turbine Operations, Inc. 	 	Vienna Operations Inc.	
NRG Bayou Cove LLC	 	Vienna Power LLC	
      The Second Priority Notes noted above were replaced on February 2, 2006 with new Senior Unsecured Notes which are described in Note 34–Subsequent Events. All of the Guarantor Subsidiaries listed above except for El Segundo Power II LLC, fully and unconditionally guarantee the new Senior Unsecured Notes.
      The non-guarantor subsidiaries, or Non-Guarantor Subsidiaries, include all of our foreign subsidiaries and certain domestic subsidiaries. We conduct much of our business through and derive much of our income

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from our subsidiaries. Therefore, our ability to make required payments with respect to our indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under our Peaker financing agreements, there are no restrictions on the ability of any of the Guarantor Subsidiaries to transfer funds to us. In addition, there may be restrictions for certain Non-Guarantor Subsidiaries.
      The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries in accordance with Rule 3-10 under the Securities and Exchange Commission’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries or Non-Guarantor Subsidiaries operated as independent entities.
      In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor Subsidiaries and Non-Guarantor Subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a “push-down” accounting basis.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2005
Reorganized NRG
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	NRG Energy, Inc.	 	 	 	 	Consolidated	 	
 	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Revenues from majority-owned operations	 	$	2,095	 	 	$	564	 	 	$	54	 	 	$	(5	)	 	$	2,708	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cost of majority-owned operations	 	 	1,600	 	 	 	435	 	 	 	37	 	 	 	(5	)	 	 	2,067	 	
 	Depreciation and amortization	 	 	133	 	 	 	51	 	 	 	10	 	 	 	—	 	 	 	194	 	
 	General, administrative and development	 	 	39	 	 	 	31	 	 	 	127	 	 	 	—	 	 	 	197	 	
 	Other charges	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Corporate relocation charges	 	 	—	 	 	 	—	 	 	 	6	 	 	 	—	 	 	 	6	 	
 	 	Reorganization items	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	Impairment charges	 	 	6	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total operating costs and expenses	 	 	1,778	 	 	 	517	 	 	 	180	 	 	 	(5	)	 	 	2,470	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income/(Loss)	 	 	317	 	 	 	47	 	 	 	(126	)	 	 	—	 	 	 	238	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Minority interest in earnings of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Equity in earnings of consolidated subsidiaries	 	 	101	 	 	 	—	 	 	 	274	 	 	 	(375	)	 	 	—	 	
 	Equity in earnings of unconsolidated affiliates	 	 	35	 	 	 	69	 	 	 	—	 	 	 	—	 	 	 	104	 	
 	Write downs and gains/(losses) on sales of equity method investments	 	 	(47	)	 	 	16	 	 	 	—	 	 	 	—	 	 	 	(31	)	
 	Other income, net	 	 	16	 	 	 	54	 	 	 	13	 	 	 	(21	)	 	 	62	 	
 	Refinancing expenses	 	 	—	 	 	 	10	 	 	 	(66	)	 	 	—	 	 	 	(56	)	
 	Interest expense	 	 	(1	)	 	 	(76	)	 	 	(141	)	 	 	21	 	 	 	(197	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total other income/(expense)	 	 	104	 	 	 	73	 	 	 	80	 	 	 	(375	)	 	 	(118	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	421	 	 	 	120	 	 	 	(46	)	 	 	(375	)	 	 	120	 	
Income Tax Expense	 	 	155	 	 	 	18	 	 	 	(130	)	 	 	—	 	 	 	43	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income From Continuing Operations	 	 	266	 	 	 	102	 	 	 	84	 	 	 	(375	)	 	 	77	 	
Income on Discontinued Operations, net of Income Taxes	 	 	5	 	 	 	2	 	 	 	—	 	 	 	—	 	 	 	7	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	$	271	 	 	$	104	 	 	$	84	 	 	$	(375	)	 	$	84	 	

 	 	
(1) 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING BALANCE SHEETS
December 31, 2005
Reorganized NRG
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	NRG Energy, Inc.	 	 	 	 	Consolidated	 	
 	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
ASSETS	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	(7	)	 	$	91	 	 	$	422	 	 	$	—	 	 	$	506	 	
 	Restricted cash	 	 	3	 	 	 	61	 	 	 	—	 	 	 	—	 	 	 	64	 	
 	Accounts receivable-trade, net	 	 	214	 	 	 	275	 	 	 	(205	)	 	 	—	 	 	 	284	 	
 	Current portion of notes receivable	 	 	—	 	 	 	25	 	 	 	468	 	 	 	(468	)	 	 	25	 	
 	Taxes receivable	 	 	(2	)	 	 	—	 	 	 	45	 	 	 	—	 	 	 	43	 	
 	Inventory	 	 	232	 	 	 	27	 	 	 	1	 	 	 	—	 	 	 	260	 	
 	Derivative instruments valuation	 	 	385	 	 	 	16	 	 	 	3	 	 	 	—	 	 	 	404	 	
 	Collateral on deposit in support of energy risk management activities	 	 	438	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	438	 	
 	Deferred income taxes	 	 	6	 	 	 	3	 	 	 	(5	)	 	 	—	 	 	 	4	 	
 	Prepayments and other current assets	 	 	65	 	 	 	22	 	 	 	38	 	 	 	—	 	 	 	125	 	
 	Assets held for sale	 	 	8	 	 	 	—	 	 	 	35	 	 	 	—	 	 	 	43	 	
 	Current assets — discontinued operations	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current assets	 	 	1,342	 	 	 	521	 	 	 	802	 	 	 	(468	)	 	 	2,197	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net property, plant and equipment	 	 	2,176	 	 	 	832	 	 	 	31	 	 	 	—	 	 	 	3,039	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Investment in subsidiaries	 	 	787	 	 	 	—	 	 	 	1,774	 	 	 	(2,561	)	 	 	—	 	
 	Equity investments in affiliates	 	 	243	 	 	 	360	 	 	 	—	 	 	 	—	 	 	 	603	 	
 	Notes receivable	 	 	76	 	 	 	457	 	 	 	1,398	 	 	 	(1,473	)	 	 	458	 	
 	Intangible assets, net	 	 	238	 	 	 	19	 	 	 	—	 	 	 	—	 	 	 	257	 	
 	Derivative instruments valuation	 	 	18	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	22	 	
 	Funded letter of credit	 	 	—	 	 	 	—	 	 	 	350	 	 	 	—	 	 	 	350	 	
 	Deferred income taxes	 	 	—	 	 	 	26	 	 	 	—	 	 	 	—	 	 	 	26	 	
 	Other assets	 	 	22	 	 	 	20	 	 	 	83	 	 	 	—	 	 	 	125	 	
 	Non–current assets — discontinued operations	 	 	—	 	 	 	354	 	 	 	—	 	 	 	—	 	 	 	354	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total other assets	 	 	1,384	 	 	 	1,240	 	 	 	3,605	 	 	 	(4,034	)	 	 	2,195	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	4,902	 	 	$	2,593	 	 	$	4,438	 	 	$	(4,502	)	 	$	7,431	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
LIABILITIES AND STOCK HOLDERS’ EQUITY	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	459	 	 	$	96	 	 	$	14	 	 	$	(468	)	 	$	101	 	
 	Accounts Payable	 	 	158	 	 	 	89	 	 	 	21	 	 	 	—	 	 	 	268	 	
 	Derivative instruments valuation	 	 	678	 	 	 	14	 	 	 	—	 	 	 	—	 	 	 	692	 	
 	Other bankruptcy settlement	 	 	—	 	 	 	3	 	 	 	—	 	 	 	—	 	 	 	3	 	
 	Accrued expenses and other current liabilities	 	 	60	 	 	 	48	 	 	 	69	 	 	 	—	 	 	 	177	 	
 	Current liabilities — discontinued operations	 	 	—	 	 	 	115	 	 	 	—	 	 	 	—	 	 	 	115	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total current liabilities	 	 	1,355	 	 	 	365	 	 	 	104	 	 	 	(468	)	 	 	1,356	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Long-term debt	 	 	1,397	 	 	 	791	 	 	 	1,866	 	 	 	(1,473	)	 	 	2,581	 	
 	Deferred income taxes	 	 	37	 	 	 	149	 	 	 	(51	)	 	 	—	 	 	 	135	 	
 	Derivative instruments valuation	 	 	25	 	 	 	92	 	 	 	20	 	 	 	—	 	 	 	137	 	
 	Out-of-market contracts	 	 	298	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	298	 	
 	Other long-term obligations	 	 	126	 	 	 	58	 	 	 	22	 	 	 	—	 	 	 	206	 	
 	Non-current liabilities — discontinued operations	 	 	—	 	 	 	240	 	 	 	—	 	 	 	—	 	 	 	240	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total non-current liabilities	 	 	1,883	 	 	 	1,330	 	 	 	1,857	 	 	 	(1,473	)	 	 	3,597	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total liabilities	 	 	3,238	 	 	 	1,695	 	 	 	1,961	 	 	 	(1,941	)	 	 	4,953	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Minority interest	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
3.625% Preferred Stock	 	 	—	 	 	 	—	 	 	 	246	 	 	 	—	 	 	 	246	 	
Stockholders’ Equity	 	 	1,664	 	 	 	897	 	 	 	2,231	 	 	 	(2,561	)	 	 	2,231	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total Liabilities and Stockholders’ Equity	 	$	4,902	 	 	$	2,593	 	 	$	4,438	 	 	$	(4,502	)	 	$	7,431	 	

 	 	
(1) 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2005
Reorganized NRG
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Non-	 	 	NRG Energy,	 	 	 	 	 	
 	 	Guarantor	 	 	Guarantor	 	 	Inc.	 	 	 	 	Consolidated	 	
 	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net income	 	$	271	 	 	$	104	 	 	$	84	 	 	$	(375	)	 	$	84	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Adjustments to reconcile net income to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Distributions in excess of (less than) equity earnings of unconsolidated affiliates and consolidated subsidiaries	 	 	(64	)	 	 	(45	)	 	 	453	 	 	 	(352	)	 	 	(8	)	
 	 	Depreciation and amortization	 	 	133	 	 	 	52	 	 	 	10	 	 	 	—	 	 	 	195	 	
 	 	Amortization of deferred financing costs and debt discount/(premium)	 	 	—	 	 	 	6	 	 	 	16	 	 	 	—	 	 	 	22	 	
 	 	Write-off of deferred financing costs due to refinancing	 	 	—	 	 	 	(10	)	 	 	2	 	 	 	—	 	 	 	(8	)	
 	 	Write downs and losses on sales of equity method investments	 	 	47	 	 	 	(16	)	 	 	—	 	 	 	—	 	 	 	31	 	
 	 	Deferred income taxes and investment tax credits	 	 	71	 	 	 	13	 	 	 	(82	)	 	 	—	 	 	 	2	 	
 	 	Unrealized (gains)/losses on derivatives	 	 	150	 	 	 	(10	)	 	 	3	 	 	 	—	 	 	 	143	 	
 	 	Minority interest	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
 	 	Amortization of intangible assets	 	 	(2	)	 	 	19	 	 	 	—	 	 	 	—	 	 	 	17	 	
 	 	Amortization of unearned equity compensation	 	 	3	 	 	 	1	 	 	 	8	 	 	 	—	 	 	 	12	 	
 	 	Restructuring and impairment charges	 	 	6	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	6	 	
 	 	Loss on sale and disposal of property, plant and equipment	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4	 	
 	 	Gain on sale of discontinued operations	 	 	(6	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(6	)	
 	 	Gain on TermRio settlement	 	 	—	 	 	 	(14	)	 	 	—	 	 	 	—	 	 	 	(14	)	
 	 	Collateral deposit payments in support of energy risk management	 	 	(405	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(405	)	
 	 	Cash provided by(used by) changes in other working capital, net of dispositions affects	 	 	(421	)	 	 	9	 	 	 	404	 	 	 	—	 	 	 	(8	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Operating Activities	 	 	(213	)	 	 	110	 	 	 	898	 	 	 	(727	)	 	 	68	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Return of Capital from Subsidiaries	 	 	—	 	 	 	—	 	 	 	1,398	 	 	 	(1,398	)	 	 	—	 	
 	Inter-company Loans (I/ C) to Subsidiaries	 	 	—	 	 	 	—	 	 	 	(2,181	)	 	 	2,181	 	 	 	—	 	
 	Proceeds from I/ C loans with parent and subsidiaries	 	 	327	 	 	 	—	 	 	 	325	 	 	 	(652	)	 	 	—	 	
 	Proceeds from sale of discontinued operations	 	 	36	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	36	 	
 	Proceeds from sale of investments	 	 	—	 	 	 	70	 	 	 	—	 	 	 	—	 	 	 	70	 	
 	Proceeds from sale of property, plant and equipment	 	 	9	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	9	 	
 	Return of capital/ (Investments) in projects	 	 	—	 	 	 	2	 	 	 	—	 	 	 	—	 	 	 	2	 	
 	Decrease/(increase) in restricted cash	 	 	1	 	 	 	44	 	 	 	—	 	 	 	—	 	 	 	45	 	
 	Deferred acquisition costs	 	 	—	 	 	 	—	 	 	 	(5	)	 	 	—	 	 	 	(5	)	
 	Decrease/(increase) in notes receivable	 	 	5	 	 	 	102	 	 	 	—	 	 	 	—	 	 	 	107	 	
 	Capital expenditures	 	 	(78	)	 	 	(22	)	 	 	(6	)	 	 	—	 	 	 	(106	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Investing Activities	 	 	300	 	 	 	196	 	 	 	(469	)	 	 	131	 	 	 	158	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Return of Capital Payments to Parent	 	 	(1,398	)	 	 	—	 	 	 	—	 	 	 	1,398	 	 	 	—	 	
 	Proceeds from Parent Inter-company Loans	 	 	2,181	 	 	 	—	 	 	 	—	 	 	 	(2,181	)	 	 	—	 	
 	Payments for Parent Inter-company Loans	 	 	(325	)	 	 	(327	)	 	 	—	 	 	 	652	 	 	 	—	 	
 	Payments of dividends	 	 	(704	)	 	 	(23	)	 	 	(20	)	 	 	727	 	 	 	(20	)	
 	Repayment of minority interest obligations	 	 	—	 	 	 	(4	)	 	 	—	 	 	 	—	 	 	 	(4	)	
 	Accelerated share repurchase payment, net	 	 	—	 	 	 	—	 	 	 	(250	)	 	 	—	 	 	 	(250	)	
 	Issuance of 3.625% Preferred Stock, net	 	 	—	 	 	 	—	 	 	 	246	 	 	 	—	 	 	 	246	 	
 	Proceeds from issuance of long-term debt	 	 	—	 	 	 	249	 	 	 	—	 	 	 	—	 	 	 	249	 	
 	Deferred debt issuance costs	 	 	—	 	 	 	—	 	 	 	(46	)	 	 	—	 	 	 	(46	)	
 	Principal payments on long-term debt	 	 	(4	)	 	 	(352	)	 	 	(649	)	 	 	—	 	 	 	(1,005	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Financing Activities	 	 	(250	)	 	 	(457	)	 	 	(719	)	 	 	596	 	 	 	(830	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	—	 	 	 	(2	)	 	 	—	 	 	 	—	 	 	 	(2	)	
Change in Cash from Discontinued Operations	 	 	—	 	 	 	8	 	 	 	—	 	 	 	—	 	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	(163	)	 	 	(145	)	 	 	(290	)	 	 	—	 	 	 	(598	)	
Cash and Cash Equivalents at Beginning of Period	 	 	156	 	 	 	236	 	 	 	712	 	 	 	—	 	 	 	1,104	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and Cash Equivalents at End of Period	 	$	(7	)	 	$	91	 	 	$	422	 	 	$	—	 	 	$	506	 	

 	 	
(1) 	All significant intercompany transactions have been eliminated in consolidation	
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2004
Reorganized NRG
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	NRG Energy, Inc.	 	 	 	 	Consolidated	 	
 	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Revenues from majority-owned operations	 	$	1,722	 	 	$	582	 	 	$	51	 	 	$	(7	)	 	$	2,348	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cost of majority-owned operations	 	 	1,060	 	 	 	405	 	 	 	31	 	 	 	(7	)	 	 	1,489	 	
 	Depreciation and amortization	 	 	133	 	 	 	62	 	 	 	13	 	 	 	—	 	 	 	208	 	
 	General, administrative and development	 	 	118	 	 	 	30	 	 	 	62	 	 	 	—	 	 	 	210	 	
 	Other charges	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Corporate relocation charges	 	 	—	 	 	 	—	 	 	 	16	 	 	 	—	 	 	 	16	 	
 	 	Reorganization items	 	 	2	 	 	 	—	 	 	 	(15	)	 	 	—	 	 	 	(13	)	
 	 	Impairment charges	 	 	3	 	 	 	27	 	 	 	15	 	 	 	—	 	 	 	45	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total operating costs and expenses	 	 	1,316	 	 	 	524	 	 	 	122	 	 	 	(7	)	 	 	1,955	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income/(Loss)	 	 	406	 	 	 	58	 	 	 	(71	)	 	 	—	 	 	 	393	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Minority interest in earnings of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Equity in earnings of consolidated subsidiaries	 	 	89	 	 	 	—	 	 	 	293	 	 	 	(382	)	 	 	—	 	
 	Equity in earnings of unconsolidated affiliates	 	 	92	 	 	 	69	 	 	 	(1	)	 	 	—	 	 	 	160	 	
 	Write downs and gains/(losses) on sales of equity method investments	 	 	(16	)	 	 	(1	)	 	 	1	 	 	 	—	 	 	 	(16	)	
 	Other income, net	 	 	7	 	 	 	35	 	 	 	5	 	 	 	(20	)	 	 	27	 	
 	Refinancing expenses	 	 	—	 	 	 	—	 	 	 	(72	)	 	 	—	 	 	 	(72	)	
 	Interest expense	 	 	—	 	 	 	(104	)	 	 	(182	)	 	 	20	 	 	 	(266	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total other income/(expense)	 	 	172	 	 	 	(1	)	 	 	44	 	 	 	(382	)	 	 	(167	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	578	 	 	 	57	 	 	 	(27	)	 	 	(382	)	 	 	226	 	
Income Tax Expense/(Benefit)	 	 	238	 	 	 	44	 	 	 	(217	)	 	 	—	 	 	 	65	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(Loss) From Continuing Operations	 	 	340	 	 	 	13	 	 	 	190	 	 	 	(382	)	 	 	161	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	3	 	 	 	26	 	 	 	(4	)	 	 	—	 	 	 	25	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	$	343	 	 	$	39	 	 	$	186	 	 	$	(382	)	 	$	186	 	

 	 	
(1) 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING BALANCE SHEETS
December 31, 2004
Reorganized NRG
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	NRG Energy,Inc.	 	 	 	 	Consolidated	 	
 	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
ASSETS	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	156	 	 	$	236	 	 	$	712	 	 	$	—	 	 	$	1,104	 	
 	Restricted cash	 	 	4	 	 	 	106	 	 	 	—	 	 	 	—	 	 	 	110	 	
 	Accounts receivable-trade, net	 	 	183	 	 	 	80	 	 	 	7	 	 	 	—	 	 	 	270	 	
 	Current portion of notes receivable	 	 	—	 	 	 	82	 	 	 	6	 	 	 	(3	)	 	 	85	 	
 	Income taxes receivable	 	 	—	 	 	 	(5	)	 	 	42	 	 	 	—	 	 	 	37	 	
 	Inventory	 	 	216	 	 	 	29	 	 	 	2	 	 	 	—	 	 	 	247	 	
 	Derivative instruments valuation	 	 	80	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	80	 	
 	Prepayments and other current assets	 	 	71	 	 	 	25	 	 	 	43	 	 	 	(3	)	 	 	136	 	
 	Collateral on deposit in support of energy risk management activities	 	 	33	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	33	 	
 	Current assets — discontinued operations	 	 	—	 	 	 	17	 	 	 	—	 	 	 	—	 	 	 	17	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current assets	 	 	743	 	 	 	570	 	 	 	812	 	 	 	(6	)	 	 	2,119	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net property, plant and equipment	 	 	2,244	 	 	 	883	 	 	 	31	 	 	 	—	 	 	 	3,158	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Investment in subsidiaries	 	 	777	 	 	 	—	 	 	 	3,916	 	 	 	(4,693	)	 	 	—	 	
 	Equity investments in affiliates	 	 	327	 	 	 	408	 	 	 	—	 	 	 	—	 	 	 	735	 	
 	Notes receivable, less current portion, less reserve	 	 	408	 	 	 	797	 	 	 	1	 	 	 	(642	)	 	 	564	 	
 	Intangible assets, net	 	 	256	 	 	 	38	 	 	 	—	 	 	 	—	 	 	 	294	 	
 	Derivative instruments valuation	 	 	2	 	 	 	35	 	 	 	5	 	 	 	—	 	 	 	42	 	
 	Funded letter of credit	 	 	—	 	 	 	—	 	 	 	350	 	 	 	—	 	 	 	350	 	
 	Deferred income taxes	 	 	—	 	 	 	34	 	 	 	—	 	 	 	—	 	 	 	34	 	
 	Other non- current assets	 	 	36	 	 	 	21	 	 	 	54	 	 	 	—	 	 	 	111	 	
 	Non-current assets — discontinued operations	 	 	—	 	 	 	457	 	 	 	—	 	 	 	—	 	 	 	457	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total other assets	 	 	1,806	 	 	 	1,790	 	 	 	4,326	 	 	 	(5,335	)	 	 	2,587	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	4,793	 	 	$	3,243	 	 	$	5,169	 	 	$	(5,341	)	 	$	7,864	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
LIABILITIES AND STOCK HOLDERS’ EQUITY	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt and capital leases	 	$	—	 	 	$	98	 	 	$	416	 	 	$	(3	)	 	$	511	 	
 	Accounts payable	 	 	427	 	 	 	(33	)	 	 	(181	)	 	 	1	 	 	 	214	 	
 	Derivative instruments valuation	 	 	17	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	17	 	
 	Other bankruptcy settlement	 	 	—	 	 	 	6	 	 	 	—	 	 	 	—	 	 	 	6	 	
 	Accrued expenses and other current liabilities	 	 	101	 	 	 	31	 	 	 	37	 	 	 	(3	)	 	 	166	 	
 	Current liabilities — discontinued operations	 	 	—	 	 	 	173	 	 	 	—	 	 	 	—	 	 	 	173	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total current liabilities	 	 	545	 	 	 	275	 	 	 	272	 	 	 	(5	)	 	 	1,087	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Long-term debt	 	 	—	 	 	 	1,487	 	 	 	2,128	 	 	 	(642	)	 	 	2,973	 	
 	Deferred income taxes	 	 	(32	)	 	 	165	 	 	 	36	 	 	 	—	 	 	 	169	 	
 	Derivative instruments valuation	 	 	—	 	 	 	132	 	 	 	16	 	 	 	—	 	 	 	148	 	
 	Out-of-market contracts	 	 	319	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	319	 	
 	Other non-current liabilities	 	 	122	 	 	 	40	 	 	 	25	 	 	 	—	 	 	 	187	 	
 	Non-current liabilities — discontinued operations	 	 	—	 	 	 	288	 	 	 	—	 	 	 	—	 	 	 	288	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total non-current liabilities	 	 	409	 	 	 	2,112	 	 	 	2,205	 	 	 	(642	)	 	 	4,084	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total liabilities	 	 	954	 	 	 	2,387	 	 	 	2,477	 	 	 	(647	)	 	 	5,171	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Minority interest	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
Stockholders’ Equity	 	 	3,839	 	 	 	855	 	 	 	2,692	 	 	 	(4,694	)	 	 	2,692	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Liabilities and Stockholders’ Equity	 	$	4,793	 	 	$	3,243	 	 	$	5,169	 	 	$	(5,341	)	 	$	7,864	 	

 	 	
(1) 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2004
Reorganized NRG
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	NRG Energy, Inc.	 	 	 	 	Consolidated	 	
 	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	(In millions)	 	 	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net income	 	$	343	 	 	$	39	 	 	$	186	 	 	$	(382	)	 	$	186	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Adjustments to reconcile net income to net cash provided (used) by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Distributions in excess of (less than) equity earnings of unconsolidated affiliates and consolidated subsidiaries	 	 	(53	)	 	 	(38	)	 	 	—	 	 	 	90	 	 	 	(1	)	
 	 	Depreciation and amortization	 	 	133	 	 	 	69	 	 	 	13	 	 	 	—	 	 	 	215	 	
 	 	Reserve for note and interest receivable	 	 	7	 	 	 	5	 	 	 	—	 	 	 	—	 	 	 	12	 	
 	 	Amortization of financing costs and debt discount/(premium)	 	 	—	 	 	 	21	 	 	 	7	 	 	 	—	 	 	 	28	 	
 	 	Write-off of deferred financing costs and debt premium	 	 	—	 	 	 	—	 	 	 	42	 	 	 	—	 	 	 	42	 	
 	 	Deferred income taxes and investment tax credits	 	 	26	 	 	 	(8	)	 	 	118	 	 	 	(79	)	 	 	57	 	
 	 	Minority interest	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
 	 	Unrealized (gains)/losses on derivatives	 	 	(71	)	 	 	(9	)	 	 	6	 	 	 	—	 	 	 	(74	)	
 	 	Write downs and losses on sales of equity method investments	 	 	16	 	 	 	1	 	 	 	(1	)	 	 	—	 	 	 	16	 	
 	 	Amortization of intangibles	 	 	14	 	 	 	38	 	 	 	—	 	 	 	—	 	 	 	52	 	
 	 	Amortization of unearned equity compensation	 	 	2	 	 	 	1	 	 	 	11	 	 	 	—	 	 	 	14	 	
 	 	Collateral deposit payments in support of energy risk management	 	 	(7	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(7	)	
 	 	Restructuring and impairment charges	 	 	3	 	 	 	27	 	 	 	15	 	 	 	—	 	 	 	45	 	
 	 	Loss from sale and disposal of property, plant and equipment	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	
 	 	(Gain)/loss on sale of discontinued operations	 	 	(2	)	 	 	(26	)	 	 	5	 	 	 	—	 	 	 	(23	)	
 	 	Cash provided by provided (used) by changes in certain working capital items, net of effects from acquisitions and dispositions	 	 	(41	)	 	 	1	 	 	 	126	 	 	 	(5	)	 	 	81	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Operating Activities	 	 	371	 	 	 	122	 	 	 	528	 	 	 	(376	)	 	 	645	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Proceeds from sale of discontinued operations	 	 	2	 	 	 	251	 	 	 	—	 	 	 	—	 	 	 	253	 	
 	Proceeds from sale of investments	 	 	21	 	 	 	27	 	 	 	3	 	 	 	—	 	 	 	51	 	
 	Proceeds from sale of property, plant and equipment	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4	 	
 	Decrease/(increase) in restricted cash	 	 	1	 	 	 	(28	)	 	 	—	 	 	 	—	 	 	 	(27	)	
 	Decrease/(increase) in notes receivable	 	 	(23	)	 	 	16	 	 	 	25	 	 	 	7	 	 	 	25	 	
 	Capital expenditures	 	 	(82	)	 	 	(28	)	 	 	(9	)	 	 	—	 	 	 	(119	)	
 	Investments in projects	 	 	4	 	 	 	(16	)	 	 	9	 	 	 	—	 	 	 	(3	)	
 	Distributions/(investments) in subsidiaries	 	 	—	 	 	 	—	 	 	 	82	 	 	 	(82	)	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Investing Activities	 	 	(73	)	 	 	222	 	 	 	110	 	 	 	(75	)	 	 	184	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net borrowings under line of credit agreement	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Proceeds from issuance of preferred shares	 	 	—	 	 	 	—	 	 	 	406	 	 	 	—	 	 	 	406	 	
 	Payment for treasury stock	 	 	—	 	 	 	—	 	 	 	(405	)	 	 	—	 	 	 	(405	)	
 	Capital contributions from parent	 	 	10	 	 	 	33	 	 	 	—	 	 	 	(43	)	 	 	—	 	
 	Dividends and return of investment to NRG Energy, Inc. 	 	 	(407	)	 	 	(10	)	 	 	—	 	 	 	417	 	 	 	—	 	
 	Proceeds from issuance of long-term debt	 	 	—	 	 	 	(7	)	 	 	1,304	 	 	 	36	 	 	 	1,333	 	
 	Deferred debt issuance costs	 	 	—	 	 	 	—	 	 	 	(26	)	 	 	—	 	 	 	(26	)	
 	Funded letter of credit	 	 	—	 	 	 	—	 	 	 	(100	)	 	 	—	 	 	 	(100	)	
 	Principal payments on long-term debt	 	 	(41	)	 	 	(292	)	 	 	(1,200	)	 	 	41	 	 	 	(1,492	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Financing Activities	 	 	(438	)	 	 	(276	)	 	 	(21	)	 	 	451	 	 	 	(284	)	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	—	 	 	 	3	 	 	 	—	 	 	 	—	 	 	 	3	 	
Change in Cash from Discontinued Operations	 	 	—	 	 	 	6	 	 	 	—	 	 	 	—	 	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	(140	)	 	 	77	 	 	 	617	 	 	 	—	 	 	 	554	 	
Cash and Cash Equivalents at Beginning of Period	 	 	296	 	 	 	159	 	 	 	95	 	 	 	—	 	 	 	550	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and Cash Equivalents at End of Period	 	$	156	 	 	$	236	 	 	$	712	 	 	$	—	 	 	$	1,104	 	

 	 	
(1) 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS
For the Period December 6, 2003 Through December 31, 2003
Reorganized NRG
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	NRG Energy, Inc.	 	 	 	 	Consolidated	 	
 	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Revenues from majority-owned operations	 	$	94	 	 	$	40	 	 	$	3	 	 	$	—	 	 	$	137	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cost of majority-owned operations	 	 	64	 	 	 	29	 	 	 	2	 	 	 	—	 	 	 	95	 	
 	Depreciation and amortization	 	 	7	 	 	 	4	 	 	 	1	 	 	 	—	 	 	 	12	 	
 	General, administrative and development	 	 	7	 	 	 	3	 	 	 	3	 	 	 	—	 	 	 	13	 	
 	Other Charges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganization items	 	 	—	 	 	 	—	 	 	 	2	 	 	 	—	 	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating costs and expenses	 	 	78	 	 	 	36	 	 	 	8	 	 	 	—	 	 	 	122	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income/(Loss)	 	 	16	 	 	 	4	 	 	 	(5	)	 	 	—	 	 	 	15	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Equity in earnings of consolidated subsidiaries	 	 	3	 	 	 	—	 	 	 	17	 	 	 	(20	)	 	 	—	 	
 	Equity in earnings of unconsolidated affiliates	 	 	11	 	 	 	2	 	 	 	1	 	 	 	—	 	 	 	14	 	
 	Interest expense	 	 	(6	)	 	 	(5	)	 	 	(8	)	 	 	—	 	 	 	(19	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total other income/(expense)	 	 	8	 	 	 	(3	)	 	 	10	 	 	 	(20	)	 	 	(5	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	24	 	 	 	1	 	 	 	5	 	 	 	(20	)	 	 	10	 	
Income Tax Expense/(Benefit)	 	 	4	 	 	 	1	 	 	 	(6	)	 	 	—	 	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(Loss) From Continuing Operations	 	 	20	 	 	 	—	 	 	 	11	 	 	 	(20	)	 	 	11	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Net Income	 	$	20	 	 	$	—	 	 	$	11	 	 	$	(20	)	 	$	11	 	

 	 	
(1) 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Period December 6, 2003 Through December 31, 2003
Reorganized NRG
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	NRG Energy, Inc.	 	 	 	 	Consolidated	 	
 	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net income	 	$	20	 	 	$	—	 	 	$	11	 	 	$	(20	)	 	$	11	 	
 	Adjustments to reconcile net income to net cash provided by operating activities Distributions in excess of (less than) equity earnings of unconsolidated affiliates	 	 	2	 	 	 	(2	)	 	 	(18	)	 	 	20	 	 	 	2	 	
 	 	Depreciation and amortization	 	 	8	 	 	 	4	 	 	 	1	 	 	 	—	 	 	 	13	 	
 	 	Amortization of deferred financing costs	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	1	 	
 	 	Amortization of debt discount/(premium)	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
 	 	Deferred income taxes and investment tax credits	 	 	—	 	 	 	—	 	 	 	(4	)	 	 	1	 	 	 	(3	)	
 	 	Current tax expense — non cash contribution from members	 	 	4	 	 	 	(3	)	 	 	—	 	 	 	(1	)	 	 	—	 	
 	 	Unrealized (gains)/losses on derivatives	 	 	—	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	4	 	
 	 	Minority interest	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	Amortization of intangibles	 	 	(16	)	 	 	3	 	 	 	—	 	 	 	—	 	 	 	(13	)	
 	 	Collateral deposit payments in support of energy risk management	 	 	(8	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(8	)	
 	 	Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions	 	 	(64	)	 	 	—	 	 	 	(533	)	 	 	 	 	 	 	(597	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Operating Activities	 	 	(54	)	 	 	7	 	 	 	(542	)	 	 	—	 	 	 	(589	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Investments in subsidiaries	 	 	—	 	 	 	—	 	 	 	(1,531	)	 	 	1,531	 	 	 	—	 	
 	Decrease/(increase) in restricted cash	 	 	343	 	 	 	32	 	 	 	—	 	 	 	—	 	 	 	375	 	
 	Decrease/(increase) in notes receivable	 	 	1	 	 	 	(11	)	 	 	(1	)	 	 	12	 	 	 	1	 	
 	Capital expenditures	 	 	(3	)	 	 	(8	)	 	 	—	 	 	 	—	 	 	 	(11	)	
 	Investments in projects	 	 	(2	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(2	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Investing Activities	 	 	339	 	 	 	13	 	 	 	(1,532	)	 	 	1,543	 	 	 	363	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Capital contributions from parent	 	 	1,531	 	 	 	—	 	 	 	—	 	 	 	(1,531	)	 	 	—	 	
 	Proceeds from issuance of long-term debt	 	 	—	 	 	 	—	 	 	 	2,450	 	 	 	—	 	 	 	2,450	 	
 	Deferred debt issuance costs	 	 	—	 	 	 	—	 	 	 	(75	)	 	 	—	 	 	 	(75	)	
 	Funded letter of credit	 	 	—	 	 	 	—	 	 	 	(250	)	 	 	—	 	 	 	(250	)	
 	Principal payments on long-term debt	 	 	(1,714	)	 	 	(6	)	 	 	—	 	 	 	(12	)	 	 	(1,732	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Financing Activities	 	 	(183	)	 	 	(6	)	 	 	2,125	 	 	 	(1,543	)	 	 	393	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	—	 	 	 	(14	)	 	 	—	 	 	 	—	 	 	 	(14	)	
Change in Cash from Discontinued Operations	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Increase in Cash and Cash Equivalents	 	 	102	 	 	 	1	 	 	 	51	 	 	 	—	 	 	 	154	 	
Cash and Cash Equivalents at Beginning of Period	 	 	194	 	 	 	158	 	 	 	44	 	 	 	—	 	 	 	396	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and Cash Equivalents at End of Period	 	$	296	 	 	$	159	 	 	$	95	 	 	$	—	 	 	$	550	 	

 	 	
(1) 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS
For the Period January 1, 2003 Through December 5, 2003
Predecessor Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	NRG Energy, Inc.	 	 	 	 	Consolidated	 	
 	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Revenues from majority-owned operations	 	$	1,230	 	 	$	522	 	 	$	47	 	 	$	(1	)	 	$	1,798	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cost of majority-owned operations	 	 	991	 	 	 	331	 	 	 	33	 	 	 	(1	)	 	 	1,354	 	
 	Depreciation and amortization	 	 	130	 	 	 	67	 	 	 	14	 	 	 	—	 	 	 	211	 	
 	General, administrative and development	 	 	65	 	 	 	29	 	 	 	76	 	 	 	—	 	 	 	170	 	
 	Other Charges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganization charges	 	 	30	 	 	 	17	 	 	 	151	 	 	 	—	 	 	 	198	 	
 	 	Impairment charges	 	 	248	 	 	 	(123	)	 	 	112	 	 	 	—	 	 	 	237	 	
 	 	Fresh start reporting adjustments	 	 	—	 	 	 	(101	)	 	 	(6,571	)	 	 	2,452	 	 	 	(4,220	)	
 	 	Fresh start reporting adjustments — subsidiaries	 	 	—	 	 	 	—	 	 	 	2,452	 	 	 	(2,452	)	 	 	—	 	
 	 	Legal settlement	 	 	(9	)	 	 	4	 	 	 	468	 	 	 	—	 	 	 	463	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total operating costs and expenses	 	 	1,455	 	 	 	224	 	 	 	(3,265	)	 	 	(1	)	 	 	(1,587	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income/(Loss)	 	 	(225	)	 	 	298	 	 	 	3,312	 	 	 	—	 	 	 	3,385	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Equity in earnings of consolidated subsidiaries	 	 	105	 	 	 	—	 	 	 	(18	)	 	 	(87	)	 	 	—	 	
 	Equity in earnings of unconsolidated affiliates	 	 	107	 	 	 	65	 	 	 	(1	)	 	 	—	 	 	 	171	 	
 	Write downs and losses on sales of equity method investments	 	 	(16	)	 	 	(126	)	 	 	(5	)	 	 	—	 	 	 	(147	)	
 	Other income, net	 	 	5	 	 	 	30	 	 	 	(15	)	 	 	(1	)	 	 	19	 	
 	Interest expense	 	 	(136	)	 	 	(61	)	 	 	(112	)	 	 	1	 	 	 	(308	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total other income/(expense)	 	 	65	 	 	 	(92	)	 	 	(151	)	 	 	(87	)	 	 	(265	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	(160	)	 	 	206	 	 	 	3,161	 	 	 	(87	)	 	 	3,120	 	
Income Tax Expense/(Benefit)	 	 	(107	)	 	 	(11	)	 	 	156	 	 	 	—	 	 	 	38	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income/(Loss) From Continuing Operations	 	 	(53	)	 	 	217	 	 	 	3,005	 	 	 	(87	)	 	 	3,082	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	(26	)	 	 	(51	)	 	 	(239	)	 	 	—	 	 	 	(316	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income/(Loss)	 	$	(79	)	 	$	166	 	 	$	2,766	 	 	$	(87	)	 	$	2,766	 	

 	 	
(1) 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOW
For the Period January 1, 2003 through December 5, 2003
Predecessor Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	NRG Energy, Inc.	 	 	 	 	Consolidated	 	
 	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss)	 	$	(79	)	 	$	166	 	 	$	2,766	 	 	$	(87	)	 	$	2,766	 	
Adjustments to reconcile net income/(loss) to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Distributions in excess of (less than) equity earnings of unconsolidated affiliates	 	 	(95	)	 	 	(54	)	 	 	21	 	 	 	87	 	 	 	(41	)	
 	 	Depreciation and amortization	 	 	131	 	 	 	112	 	 	 	14	 	 	 	—	 	 	 	257	 	
 	 	Amortization of deferred financing costs	 	 	7	 	 	 	7	 	 	 	4	 	 	 	—	 	 	 	18	 	
 	 	Write downs and losses on sales of equity method investments	 	 	16	 	 	 	131	 	 	 	—	 	 	 	—	 	 	 	147	 	
 	 	Deferred income taxes and investment tax credits	 	 	(123	)	 	 	(36	)	 	 	181	 	 	 	(24	)	 	 	(2	)	
 	 	Current tax expense — non cash contribution from members	 	 	(17	)	 	 	(54	)	 	 	—	 	 	 	71	 	 	 	—	 	
 	 	Unrealized (gains)/losses on derivatives	 	 	(13	)	 	 	(75	)	 	 	29	 	 	 	24	 	 	 	(35	)	
 	 	Minority interest	 	 	—	 	 	 	2	 	 	 	—	 	 	 	—	 	 	 	2	 	
 	 	Restructuring and impairment charges	 	 	273	 	 	 	94	 	 	 	41	 	 	 	—	 	 	 	408	 	
 	 	Fresh start reporting adjustments	 	 	—	 	 	 	—	 	 	 	(3,895	)	 	 	—	 	 	 	(3,895	)	
 	 	Gain on sale of discontinued operations	 	 	3	 	 	 	(198	)	 	 	9	 	 	 	—	 	 	 	(186	)	
 	 	Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions	 	 	348	 	 	 	2	 	 	 	658	 	 	 	(209	)	 	 	799	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Operating Activities	 	 	451	 	 	 	97	 	 	 	(172	)	 	 	(138	)	 	 	238	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Investment in subsidiaries	 	 	—	 	 	 	—	 	 	 	129	 	 	 	(129	)	 	 	—	 	
 	Proceeds from sale of discontinued operations	 	 	—	 	 	 	19	 	 	 	—	 	 	 	—	 	 	 	19	 	
 	Proceeds from sale of investments	 	 	—	 	 	 	107	 	 	 	—	 	 	 	—	 	 	 	107	 	
 	Proceeds from sale of turbines	 	 	—	 	 	 	—	 	 	 	71	 	 	 	—	 	 	 	71	 	
 	(Increase) in trust funds	 	 	(14	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(14	)	
 	Decrease/(increase) in restricted cash	 	 	(198	)	 	 	(54	)	 	 	—	 	 	 	—	 	 	 	(252	)	
 	Decrease/(increase) in notes receivable	 	 	98	 	 	 	42	 	 	 	—	 	 	 	(142	)	 	 	(2	)	
 	Capital expenditures	 	 	(56	)	 	 	(7	)	 	 	(51	)	 	 	—	 	 	 	(114	)	
 	Investments in projects	 	 	(4	)	 	 	(5	)	 	 	8	 	 	 	—	 	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Investing Activities	 	 	(174	)	 	 	102	 	 	 	157	 	 	 	(271	)	 	 	(186	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Capital contributions from parent	 	 	(135	)	 	 	(132	)	 	 	—	 	 	 	267	 	 	 	—	 	
 	Proceeds from issuance of long-term debt	 	 	—	 	 	 	40	 	 	 	—	 	 	 	—	 	 	 	40	 	
 	Deferred debt issuance costs	 	 	(8	)	 	 	(1	)	 	 	(10	)	 	 	—	 	 	 	(19	)	
 	Principal payments on long-term debt	 	 	(4	)	 	 	(189	)	 	 	—	 	 	 	142	 	 	 	(51	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided (Used) by Financing Activities	 	 	(147	)	 	 	(282	)	 	 	(10	)	 	 	409	 	 	 	(30	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	—	 	 	 	(22	)	 	 	—	 	 	 	—	 	 	 	(22	)	
Change in Cash from Discontinued Operations	 	 	—	 	 	 	35	 	 	 	—	 	 	 	—	 	 	 	35	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Increase in Cash and Cash Equivalents	 	 	130	 	 	 	(70	)	 	 	(25	)	 	 	—	 	 	 	35	 	
Cash and Cash Equivalents at Beginning of Period	 	 	64	 	 	 	228	 	 	 	69	 	 	 	—	 	 	 	361	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and Cash Equivalents at End of Period	 	$	194	 	 	$	158	 	 	$	44	 	 	$	—	 	 	$	396	 	

 	 	
(1) 	All significant intercompany transactions have been eliminated in consolidation.	
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Note 34 — Subsequent Events
 	 	
 	Texas Genco Acquisition	
      On February 2, 2006, NRG acquired Texas Genco LLC, a Delaware limited liability company, by purchasing all of the outstanding equity interests in Texas Genco pursuant to the Acquisition Agreement, dated September 30, 2005, by and among NRG, Texas Genco and the Sellers. The purchase price of approximately $6.1 billion consisted of approximately $4.4 billion in cash and the issuance of approximately 35.4 million shares of NRG’s common stock valued at $1.7 billion. This amount is subject to adjustment due to acquisition costs. The value of our common stock issued to the Sellers was based on our average stock price immediately before and after the closing date of February 2, 2006. The Acquisition includes the assumption of approximately $2.7 billion of Texas Genco debt. Texas Genco is now a wholly-owned subsidiary of NRG, and will be managed and accounted for as a new business segment to be referred to as NRG Texas.
      The acquisition of Texas Genco was partially funded at closing with the combination of (i) cash proceeds received upon the issuance and sale in a public offering of 20,855,057 shares of our common stock at a price of $48.75 per share; (ii) cash proceeds received upon the issuance and sale of $1.2 billion aggregate principal amount of 7.25% Senior Notes due 2014 and $2.4 billion aggregate principal amount of 7.375% Senior Notes due 2016, as described below; (iii) cash proceeds received upon the issuance and sale in a public offering of 2 million shares of mandatory convertible preferred stock at a price of $250 per share, as described below; (iv) funds borrowed under a new senior secured credit facility consisting of a $3.575 billion term loan facility, a $1.0 billion revolving credit facility and a $1.0 billion synthetic letter of credit facility, as described below; and (v) cash on hand.
      Texas Genco owns approximately 11,000 MW of net operating generation capacity, and sells power and related services in ERCOT.
      The acquisition of Texas Genco will be accounted for using the purchase method of accounting and, accordingly, the purchase price will be allocated to the assets acquired and liabilities assumed based on the estimated fair value of such assets and liabilities as of February 2, 2006. As it is difficult to estimate an allocation of purchase price without completed asset appraisals, we have made a preliminary allocation estimate. Ultimately, the excess of the purchase price over the fair value of the net tangible and identified intangible assets acquired will be recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on known contingencies existing at the date of acquisition becomes available within one year after the acquisition, and longer for certain income tax items.

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      The following table summarizes the estimated unaudited fair value of the assets acquired and liabilities assumed at the date of acquisition. For purposes of acquisition costs, we have estimated such costs at approximately $126 million, increasing the total purchase price to approximately $6.2 billion We are in the process of obtaining appraisals of the fixed assets, intangibles and certain liabilities acquired; thus, the allocation of the purchase price is subject to refinement.
 	 	 	 	 	 	
 	 	February 2, 2006	 	
 	 	 	 	
 	 	(Unaudited)	 	
 	 	(In millions)	 	
Current and non-current assets	 	$	1,408	 	
Property, Plant and equipment	 	 	7,745	 	
Intangibles	 	 	1,160	 	
Goodwill	 	 	2,664	 	
 	 	 	 	
 	Total assets acquired	 	 	12,977	 	
Current and non-current liabilities	 	 	1,004	 	
Out of market contracts	 	 	3,048	 	
Long term debt	 	 	2,735	 	
 	 	 	 	
 	Total liabilities acquired	 	 	6,787	 	
 	 	 	 	
Net assets acquired	 	$	6,190	 	
 	 	 	 	
      Based on our preliminary allocation of the purchase price, the purchase price will include an allocation to certain intangibles as well as goodwill. The known intangibles include emission allowances and the fair value for positive power contracts totaling $1,140 million and $20 million, respectively. The weighted average amortization period for the emission allowances and the positive power contracts is approximately 26 years and one year, respectively — a weighted average of approximately 26 years for total intangible assets.
      The allocation also includes a material value for out-of-market contracts assumed at the closing of the acquisition which will be amortized over the next four years on a weighted average basis. When amortized, this balance will be reflected as an increase to our revenue.
 	 	
 	Cash Tender Offer and Consent Solicitation	
      On December 15, 2005, we commenced a cash tender offer and consent solicitation for any and all outstanding $1.1 billion aggregate principal amount of our 8% Second Priority Notes. On such date, we also commenced a cash tender offer and consent solicitation for any and all outstanding $1.1 billion aggregate principal amount of Texas Genco LLC’s and Texas Genco Financing Corp.’s 6.875% senior notes due 2014, or the Texas Genco Notes. The offer to purchase the Second Priority Notes and the Texas Genco Notes was part of our previously announced financing plan in connection with our acquisition of Texas Genco. As of February 2, 2006, NRG had received valid tenders from holders in aggregate principal amount of the NRG Notes, representing approximately 99.96% of the outstanding Second Priority Notes, and had received valid tenders from holders of the $1.1 billion in aggregate principal amount of the Texas Genco Notes, representing 100% of the outstanding Texas Genco Notes. The purchase price for the Second Priority Notes totaling approximately $1.2 billion was paid by NRG on February 2, 2006 and the purchase price for the Texas Genco Notes totaling approximately $1.2 billion was paid by NRG on February 3, 2006.
 	 	
 	New Financings	

 	New Senior Credit Facility	
      On February 2, 2006, we also entered into a new senior secured credit facility with a syndicate of financial institutions, including Morgan Stanley Senior Funding, Inc., as administrative agent, Morgan Stanley & Co. Inc., as collateral agent, and Morgan Stanley Senior Funding, Inc. and Citigroup Global Markets Inc. as joint lead book-runners, joint lead arrangers and co-documentation agents providing for up to an aggregate

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amount of $5.575 billion, or the New Senior Credit Facility, consisting of a $3.575 billion senior first priority secured term loan facility, or the Term Loan Facility, a $1.0 billion senior first priority secured revolving credit facility, or the Revolving Credit Facility, and a $1.0 billion senior first priority secured synthetic letter of credit facility, or the Letter of Credit Facility. The New Senior Credit Facility replaced our then existing senior secured credit facility. The Term Loan Facility will mature on February 1, 2013 and will amortize in 27 consecutive equal quarterly installments of 0.25% of the original principal amount of the Term Loan Facility during the first six and 3 / 4  years thereof with the balance payable on the seventh anniversary thereof. The full amount of the Revolving Credit Facility will mature on February 2, 2011. The Letter of Credit Facility will mature on February 1, 2013 and no amortization will be required in respect thereof.
      The New Senior Credit Facility is guaranteed by substantially all of our existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries and certain other subsidiaries. In addition, the New Senior Credit Facility is secured by liens on substantially all of our assets and the assets of our subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries and certain other subsidiaries. The capital stock of substantially all of our subsidiaries, with certain exceptions for unrestricted subsidiaries, foreign subsidiaries and project subsidiaries, has been pledged for the benefit of the New Senior Credit Facility lenders.
      The New Senior Credit Facility is also secured by a first-priority perfected security interest in all of the property and assets owned at-any time or acquired by us and our subsidiaries, other than certain other limited exceptions. These exceptions include assets such as the assets of certain unrestricted subsidiaries, equity interests in certain of our project affiliates that have non-recourse debt financing, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of our foreign subsidiaries.
      The New Senior Credit Facility contains customary covenants, which, among other things require us to meet certain financial tests, including a minimum interest coverage ratio and a maximum leverage ratio, each at the corporate level and on a consolidated basis, and limit’s our ability to:
 	 	 	
 	• 	incur indebtedness and liens and enter into sale and lease-back transactions;	
 	 	 	
 	• 	make investments,	
 	 	 	
 	• 	loans and advances;	
 	 	 	
 	• 	engage in mergers, acquisitions consolidations and asset sales;	
 	 	 	
 	• 	pay dividends and other restricted payments;	
 	 	 	
 	• 	enter into transactions with affiliates;	
 	 	 	
 	• 	engage in business activities and hedging transactions;	
 	 	 	
 	• 	make capital expenditures;	
 	 	 	
 	• 	make debt payments;	
 	 	 	
 	• 	make certain changes to the terms of material indebtedness;	
 	 	 	
 	• 	and other covenants customary for such facilities.	
      In anticipation of the New Senior Credit Facility, in January 2006, we entered into a series of new interest rate swaps. These interest rate swaps became effective on February 15, 2006 and are intended to hedge the risk associated with floating interest rates. For each of the interest rate swaps, we pay our counterparty the equivalent of a fixed interest payment on a predetermined notional value, and we receive quarterly the equivalent of a floating interest payment based on 3-month LIBOR calculated on the same notional value. All payments by us and our counterparties are made quarterly, and the LIBOR is determined in advance of each interest period. While the notional value of each of the swaps does not vary over time, the swaps are designed

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to mature sequentially. The total notional amount of these swaps as of February 25, 2006 was $2.15 billion. The notional amounts and maturities of each tranche of these swaps are as follows:
 	 	 	 	 	 	 	 	 	
Period of swap	 	Notional Value	 	 	Maturity	 	
 	 	 	 	 	 	 	
1-year	 	$	120 million	 	 	 	March 31, 2007	 	
2-year	 	$	140 million	 	 	 	March 31, 2008	 	
3-year	 	$	150 million	 	 	 	March 31, 2009	 	
4-year	 	$	190 million	 	 	 	March 31, 2010	 	
5-year	 	$	1.55 billion	 	 	 	March 31, 2011	 	

 	Senior Notes	
      On February 2, 2006, we completed the sale of (i) $1.2 billion aggregate principal amount of 7.25% senior notes due 2014, or 7.25% Senior Notes, and (ii) $2.4 billion aggregate principal amount of 7.375% senior notes due 2016, or 7.375% Senior Notes, collectively the Senior Notes. The Senior Notes were issued under an Indenture, dated February 2, 2006, or the Indenture, between us and Law Debenture Trust Company of New York, as trustee, or the Trustee, as supplemented by a First Supplemental Indenture, dated February 2, 2006, or the First Supplemental Indenture, between us, the guarantors named therein and the Trustee, relating to the 7.25% Senior Notes, and as supplemented by a Second Supplemental Indenture, dated February 2, 2006, or the Second Supplemental Indenture (together with the Indenture and the First Supplemental Indenture, the Indentures) between us, the guarantors named therein and the Trustee, relating to the 7.375% Senior Notes. The Indentures and the form of notes, provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG.
      Interest is payable on the Senior Notes on February 1 and August 1 of each year beginning on August 1, 2006 until their maturity dates — February 1, 2014 for the 7.25% Senior Notes and February 1, 2016 for the 7.375% Senior Notes.
      Prior to February 1, 2010 for the 7.25% Senior Notes and prior to February 1, 2011 for the 7.375% Senior Notes, we may redeem all or a portion of the series of Senior Notes at a price equal to 100% of the principal amount plus a “make whole” premium and accrued interest. On or after February 1, 2010 for the 7.25% Senior Notes and on or after February 1, 2011 for the 7.375% Senior Notes, we may redeem all or a portion of the series of Senior Notes at redemption prices set forth in the Indentures. In addition, at any time prior to February 1, 2009, we may redeem up to 35% of the aggregate principal amount of the series of Senior Notes with the net proceeds of certain equity offerings at the redemption price set forth in the Indentures.
      The terms of the Indentures, among other things, limit our ability and certain of our subsidiaries’ ability to:
 	 	 	
 	• 	make restricted payments;	
 	 	 	
 	• 	restrict dividends or other payments of subsidiaries;	
 	 	 	
 	• 	incur additional debt;	
 	 	 	
 	• 	engage in transactions with affiliates;	
 	 	 	
 	• 	create liens on assets;	
 	 	 	
 	• 	engage in sale and leaseback transactions;	
 	 	 	
 	• 	and consolidate, merge or transfer all or substantially all of its assets and the assets of its subsidiaries.	
      The Indentures provide for customary events of default which include, among others, nonpayment of principal or interest; breach of other agreements in the Indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against us and our subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all the Senior Notes of such series to be due and payable immediately.

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 	5.75% Preferred Stock	
      On February 2, 2006, we completed the issuance of 2 million shares of 5.75% mandatory convertible preferred stock, or the 5.75% Preferred Stock, at an offering price of $250 per share for total net proceeds after deducting offering expenses and underwriting discounts of approximately $486 million. Dividends on the 5.75% Preferred Stock are $14.375 per share per year, and are due and payable on a quarterly basis beginning on March 15, 2006. The 5.75% Preferred Stock will automatically convert into common stock on March 16, 2009, or the Conversion Date, at a rate that is dependent upon the applicable market value of our common stock. If the applicable market value of our common stock is $60.45 a share or higher at the Conversion Date, then the 5.75% Preferred Stock is convertible at a rate of 4.1356 shares of our common stock for every share of 5.75% Preferred Stock outstanding. If the applicable market value of our common stock is less than or equal to $48.75 per share at the Conversion Date, then the 5.75% Preferred Stock is convertible at a rate of 5.1282 shares of our common stock for every share of 5.75% Preferred Stock outstanding. If the applicable market value of our common stock is between $48.75 per share and $60.45 per share at the Conversion Date, then the Mandatory Convertible Preferred Stock is convertible into common stock at a rate that is between 4.1356 per share and 5.1282 per share of common stock.
 	 	
 	Common Stock	
      On January 31, 2006, we completed the issuance of 20,855,057 shares of our common stock, or the Common Stock, at an offering price of $48.75 per share for total net proceeds after deducting offering expenses and underwriting discounts of approximately $986 million.
 	 	
 	Second Lien Structure	
      Before the Acquisition, Texas Genco’s capital structure permitted the grant of second priority liens on its assets as security for their obligations under certain long-term power sales agreements and related hedges. The Credit Agreement for the New Senior Credit Facility and the Indentures, which became effective as of February 2, 2006, allow these arrangements to remain in place. In addition, the new debt instruments also permit us to grant second priority liens on our other assets in the United States in order to secure obligations under power sales agreements and related hedges, within certain limits. The seven trading counterparties of Texas Genco who held second priority liens on Texas Genco’s assets as of February 2, 2006 have been offered a second priority lien on NRG’s other assets under the new structure as additional collateral. Going forward, NRG anticipates that it will use the second lien structure to reduce the amount of cash collateral and letters of credit that it may otherwise be required to post from time to time to support its obligations under long term power sales and related hedges.
 	 	
 	Bourbonnais Settlement	
      On January 31, 2006, we finalized a settlement agreement and stipulation, or the Agreements, with an equipment manufacturer related to turbine purchase agreements entered into in 2001 by NRG Bourbonnais and in 1999 by an undeveloped project. The Agreements provide for the payment of the equipment manufacturer’s proof of claim previously filed in NRG’s bankruptcy proceeding, a separate $6 million payment to the equipment manufacturer, and the release of all remaining claims the parties have against each other under the contracts. Additionally, NRG will receive certain equipment as well as a one year option to purchase new-build equipment for a fixed price. As a result of the Agreements, during the first quarter of 2006, NRG will reverse into income accounts payable totaling $35 million resulting from the discharge of the previously recorded liability. In addition, upon the transfer of title for the equipment noted above, NRG will record an adjustment to write up the value of the equipment received to fair value. We expect title to transfer in April 2006 at which time we will record a credit to income for the difference between our current book value and fair value received.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
FINANCIAL STATEMENT SCHEDULE
To the Board of Directors and Stockholders of NRG Energy, Inc.:
      Our audit of the consolidated financial statements referred to in our report dated March 10, 2004, except as to Notes 6, 21, and 33, which are as of December 6, 2004, appearing in this Annual Report on Form 10-K also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Annual Report on Form 10-K. In our opinion, this financial statement schedule for the period from December 6, 2003 to December 31, 2003 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	
 	 	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004, except as to
Notes 6, 21, and 33,
which are as of December 6, 2004.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
FINANCIAL STATEMENT SCHEDULE
To the Board of Directors and Stockholders of NRG Energy, Inc.:
      Our audits of the consolidated financial statements referred to in our report dated March 10, 2004, except as to Notes 6, 21, and 33, which are as of December 6, 2004, appearing in this Annual Report on Form 10-K also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Annual Report on Form 10-K. In our opinion, this financial statement schedule for the period from January 1, 2003 to December 5, 2003 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	
 	 	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004, except as to
Notes 6, 21, and 33,
which are as of December 6, 2004.

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NRG ENERGY, INC.
SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2005, 2004, and 2003
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Column A	 	Column B	 	 	Column C	 	 	Column D	 	 	Column E	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Additions	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	
 	 	Balance at	 	 	Charged to	 	 	Charged to	 	 	 	 	 	
 	 	Beginning of	 	 	Costs and	 	 	Other	 	 	 	 	Balance at	 	
Description	 	Period	 	 	Expenses	 	 	Accounts	 	 	Deductions	 	 	End of Period	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(In millions)	 	
Allowance for doubtful accounts, deducted from accounts receivable in the balance sheet:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reorganized NRG	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year ended December 31, 2005	 	$	1	 	 	$	2	 	 	$	—	 	 	$	(1	)	 	$	2	 	
Year ended December 31, 2004	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
December 6 - December 31, 2003	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Predecessor Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January 1 - December 5, 2003	 	 	18	 	 	 	16	 	 	 	—	 	 	 	(34	)	 	 	—	*	
Income tax valuation allowance, deducted from deferred tax assets in the balance sheet:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reorganized NRG	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year ended December 31, 2005	 	$	708	 	 	$	22	 	 	$	85	 	 	$	(59	)	 	$	756	 	
Year ended December 31, 2004	 	 	1,241	 	 	 	—	 	 	 	(277	)	 	 	(256	)	 	 	708	 	
December 6 - December 31, 2003	 	 	1,242	 	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	1,241	 	
Predecessor Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January 1 - December 5, 2003	 	 	1,171	 	 	 	71	 	 	 	—	 	 	 	—	 	 	 	1,242	*	

* 	December 6, 2003 - Fresh Start Balance	
253

Table of Contents
SIGNATURES
      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 	 	
 	NRG ENERGY, INC.	
 	(Registrant)	
 	 	
 	/s/ DAVID W. CRANE	
 	 	
 	David W. Crane,	
 	Chief Executive Officer	
 	(Principal Executive Officer)	
 	 	
 	/s/ ROBERT C. FLEXON	
 	 	
 	Robert C. Flexon,	
 	Chief Financial Officer	
 	(Principal Financial Officer)	
 	 	
 	/s/ JAMES J. INGOLDSBY	
 	 	
 	James J. Ingoldsby,	
 	Controller	
 	(Principal Accounting Officer)	
Date: March 7, 2006

254

Table of Contents
POWER OF ATTORNEY:
      Each person whose signature appears below constitutes and appoints David W. Crane, Timothy W. J. O’Brien and Tanuja M. Dehne, each or any of them, such person’s true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in such person’s name, place and stead, in any and all capacities, to sign any and all amendments to this report on Form 10-K, and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
      In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on March 7, 2006.
 	 	 	 	 	 	 	
Signature	 	Title	 	Date	

/s/ DAVID W. CRANE

David W. Crane	 	President and Chief Executive Officer	 	March 7, 2006	
 	
/s/ HOWARD E. COSGROVE

Howard E. Cosgrove	 	Chairman of the Board	 	March 7, 2006	
 	
/s/ JOHN F. CHLEBOWSKI

John F. Chlebowski	 	Director	 	March 7, 2006	
 	
/s/ LAWRENCE S. COBEN

Lawrence S. Coben	 	Director	 	March 7, 2006	
 	
/s/ STEPHEN L. CROPPER

Stephen L. Cropper	 	Director	 	March 7, 2006	
 	
/s/ MAUREEN MISKOVIC

Maureen Miskovic	 	Director	 	March 7, 2006	
 	
/s/ ANNE C. SCHAUMBURG

Anne C. Schaumburg	 	Director	 	March 7, 2006	
 	
/s/ HERBERT H. TATE

Herbert H. Tate	 	Director	 	March 7, 2006	
 	
/s/ THOMAS H. WEIDEMEYER

Thomas H. Weidemeyer	 	Director	 	March 7, 2006	
 	
/s/ WALTER R. YOUNG

Walter R. Young	 	Director	 	March 7, 2006	
255

Table of Contents
EXHIBIT INDEX
 	 	 	 	 	
 	2	.1	 	Third Amended Joint Plan of Reorganization of NRG Energy, Inc., NRG Power Marketing, Inc., NRG Capital LLC, NRG Finance Company I LLC, and NRGenerating Holdings (No. 23) B.V.(7)	
 	
 	2	.2	 	First Amended Joint Plan of Reorganization of NRG Northeast Generating LLC (and certain of its subsidiaries), NRG South Central Generating (and certain of its subsidiaries) and Berrians I Gas Turbine Power LLC.(7)	
 	
 	2	.3	 	Acquisition Agreement, dated as of September 30, 2005, by and among NRG Energy, Inc., Texas Genco LLC and the Direct and Indirect Owners of Texas Genco LLC.(16)	
 	
 	3	.1	 	Amended and Restated Certificate of Incorporation.(21)	
 	
 	3	.2	 	Amended and Restated By-Laws.(8)	
 	
 	3	.3	 	Certificate of Designation of 4.0% Convertible Perpetual Preferred Stock, as filed with the Secretary of State of the State of Delaware on December 20, 2004.(10)	
 	
 	3	.4	 	Certificate of Designations of 3.625% Convertible Perpetual Preferred Stock, as filed with the Secretary of State of the State of Delaware on August 11, 2005. (22)	
 	
 	3	.5	 	Certificate of Designations of 5.75% Mandatory Convertible Preferred Stock, as filed with the Secretary of State of the State of Delaware on January 27, 2006. (24)	
 	
 	4	.1	 	Supplemental Indenture dated as of December 30, 2005, among NRG Energy, Inc., the subsidiary guarantors named on Schedule A thereto and Law Debenture Trust Company of New York, as trustee. (18)	
 	
 	4	.2	 	Amended and Restated Common Agreement among XL Capital Assurance Inc., Goldman Sachs Mitsui Marine Derivative Products, L.P., Law Debenture Trust Company of New York, as Trustee, The Bank of New York, as Collateral Agent, NRG Peaker Finance Company LLC and each Project Company Party thereto dated as of January 6, 2004, together with Annex A to the Common Agreement.(2)	
 	
 	4	.3	 	Amended and Restated Security Deposit Agreement among NRG Peaker Finance Company, LLC and each Project Company party thereto, and the Bank of New York, as Collateral Agent and Depositary Agent, dated as of January 6, 2004.(2)	
 	
 	4	.4	 	NRG Parent Agreement by NRG Energy, Inc. in favor of the Bank of New York, as Collateral Agent, dated as of January 6, 2004.(2)	
 	
 	4	.5	 	Indenture dated June 18, 2002, between NRG Peaker Finance Company LLC, as Issuer, Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC and Sterlington Power LLC, as Guarantors, XL Capital Assurance Inc., as Insurer, and Law Debenture Trust Company, as Successor Trustee to the Bank of New York.(4)	
 	
 	4	.6	 	Registration Rights Agreement, dated December 21, 2004, by and among NRG Energy, Inc., Citigroup Global Markets Inc. and Deutsche Bank Securities Inc.(9)	
 	
 	4	.7	 	Specimen of Certificate representing common stock of NRG Energy, Inc.(25)	
 	
 	4	.8	 	Indenture, dated February 2, 2006, among NRG Energy, Inc. and Law Debenture Trust Company of New York.(26)	
 	
 	4	.9	 	First Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014. (26)	
 	
 	4	.10	 	Second Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016. (26)	
 	
 	4	.11	 	Form of 7.250% Senior Note due 2014.(26)	
 	
 	4	.12	 	Form of 7.375% Senior Note due 2016.(26)	
 	
 	10	.1*	 	Employment Agreement, dated November 10, 2003, between NRG Energy, Inc. and David Crane.(2)	
 	
 	10	.2	 	Note Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc. and each of the purchasers named therein.(5)	

Table of Contents
 	 	 	 	 	
 	10	.3	 	Master Shelf and Revolving Credit Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc., The Prudential Insurance Registrants of America and each Prudential Affiliate, which becomes party thereto.(5)	
 	
 	10	.4	 	Asset Sales Agreement, dated December 23, 1998, between NRG Energy, Inc., and Niagara Mohawk Power Corporation.(6)	
 	
 	10	.5	 	Amendment to the Asset Sales Agreement, dated June 11, 1999, between NRG Energy, Inc., and Niagara Mohawk Power Corporation.(6)	
 	
 	10	.6*	 	Severance Agreement between NRG Energy, Inc. and George Schaefer dated December 18, 2002.(4)	
 	
 	10	.7*	 	Severance Agreement between NRG Energy, Inc. and John P. Brewster dated July 23, 2003.(2)	
 	
 	10	.8	 	Stock Purchase Agreement dated December 13, 2004, by and among NRG Energy, Inc. and MatlinPatterson Global Advisers LLC, MatlinPatterson Global Opportunities Partners, L.P. and MatlinPatterson Global Opportunities Partners (Bermuda) L.P.(11)	
 	
 	10	.9*	 	NEO 2004 AIP Payout and 2005 Base Salary Table.(8)	
 	
 	10	.10*	 	Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Officers and Key Management.(20)	
 	
 	10	.11*	 	Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Directors.(20)	
 	
 	10	.12*	 	NRG Energy, Inc. Long-Term Incentive Plan.(15)	
 	
 	10	.13*	 	Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified Stock Option Agreement.(12)	
 	
 	10	.14*	 	Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock Unit Agreement.(12)	
 	
 	10	.15*	 	Form of NRG Energy, Inc. Long Term Incentive Plan Performance Unit Agreement. (17)	
 	
 	10	.16*	 	Annual Incentive Plan for Designated Corporate Officers.(13)	
 	
 	10	.17*	 	Letter Agreement, dated March 5, 2004, between NRG Energy, Inc. and John P. Brewster.(14)	
 	
 	10	.18*	 	Letter Agreement, dated March 5, 2004, between NRG Energy, Inc. and Timothy W. O’Brien.(14)	
 	
 	10	.19*	 	Letter Agreement, dated February 19, 2004, between NRG Energy, Inc. and Robert C. Flexon.(14)	
 	
 	10	.20	 	Railroad Car Full Service Master Leasing Agreement, dated as of February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(20)	
 	
 	10	.21	 	Commitment Letter, dated February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(20)	
 	
 	10	.22*	 	Summary of Director Compensation.(20)	
 	
 	10	.23	 	Purchase Agreement (West Coast Power) dated as of December 27, 2005, by and among NRG Energy, Inc., NRG West Coast LLC (Buyer), DPC II Inc. (Seller) and Dynegy, Inc.(19)	
 	
 	10	.24	 	Purchase Agreement (Rocky Road Power), dated as of December 27, 2005, by and among Termo Santander Holding, L.L.C. (Buyer), Dynegy, Inc., NRG Rocky Road LLC (Seller) and NRG Energy, Inc.(19)	
 	
 	10	.25*	 	August 1, 2005 Executive Officer Grant Table.(23)	
 	
 	10	.26*	 	Letter Agreement, dated June 21, 2005, between NRG Energy, Inc. and Kevin T. Howell. (23)	
 	
 	10	.27	 	Stock Purchase Agreement, dated as of August 10, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(22)	
 	
 	10	.28	 	Accelerated Share Repurchase Agreement, dated as of August 11, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(22)	
 	
 	10	.29	 	Credit Agreement, dated February 2, 2006, among NRG, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, Morgan Stanley Senior Funding, Inc. and Citigroup Global Markets Inc., as joint lead Book Runners, Joint Lead Arrangers and Co-Documentation Agents, Morgan Stanley & Co. Incorporated, as Collateral Agent, and Citigroup Global Markets Inc., as Syndication Agent.(26)	

Table of Contents
 	 	 	 	 	
 	10	.30	 	Investor Rights Agreement, dated as of February 2, 2006, by and among NRG Energy, Inc. and Certain Stockholders of NRG Energy, Inc. set forth therein.(27)	
 	10	.31	 	Amended and Restated Master Power Purchase and Sale Agreement, dated February 2, 2006, by and between J. Aron & Company and Texas Genco II, LP (including the cover sheet and confirmation letter thereto) (portions of this document have been omitted pursuant to a request for confidential treatment and filed separately with the SEC).(1)	
 	10	.32	 	Terms and Conditions of Sale, dated as of October 5, 2005, between Texas Genco II LP and FreightCar America, Inc., (including the Proposal Letter and Amendment thereto) (portions of this document have been omitted pursuant to a request for confidential treatment and filed separately with the SEC).(1)	
 	10	.33*	 	Employment Agreement, dated March 3, 2006, between NRG Energy, Inc. and David Crane.(1)	
 	10	.34*	 	NEO 2005 AIP Payout and 2006 Base Salary Table.(1)	
 	21	 	 	Subsidiaries of NRG Energy. Inc.(1)	
 	
 	23	.1	 	Consent of KPMG LLP.(1)	
 	
 	23	.2	 	Consent of PricewaterhouseCoopers LLP.(1)	
 	
 	31	.1	 	Rule 13a-14(a)/15d-14(a) certification of David W. Crane.(1)	
 	
 	31	.2	 	Rule 13a-14(a)/15d-14(a) certification of Robert C. Flexon.(1)	
 	
 	31	.3	 	Rule 13a-14(a)/15d-14(a) certification of James J. Ingoldsby.(1)	
 	
 	32	 	 	Section 1350 Certification.(1)	

 	*	Exhibit relates to compensation arrangements.	

 	(1) 	Filed herewith.	
 	 	 	
 	(2) 	Incorporated herein by reference to NRG Energy, Inc.’s annual report on Form 10-K filed on March 16, 2004.	
 	 	 	
 	(3) 	Incorporated herein by reference to NRG Energy Inc.’s Amendment No. 2 to its annual report on Form 10-K filed on November 3, 2004.	
 	 	 	
 	(4) 	Incorporated herein by reference to NRG Energy, Inc.’s annual report on Form 10-K filed on March 31, 2003.	
 	 	 	
 	(5) 	Incorporated herein by reference to NRG Energy Inc.’s Registration Statement on Form S-1, as amended, Registration No. 333-33397.	
 	 	 	
 	(6) 	Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended June 30, 1999.	
 	 	 	
 	(7) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on November 19, 2003.	
 	 	 	
 	(8) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on March 3, 2005.	
 	 	 	
 	(9) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on December 27, 2004.	

(10) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on December 27, 2004.	
 	 	
(11) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K/ A filed on December 14, 2004.	
 	 	
(12) 	Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended September 30, 2004.	
 	 	
(13) 	Incorporated herein by reference to NRG Energy, Inc.’s 2004 proxy statement on Schedule 14A filed on July 12, 2004.	
 	 	
(14) 	Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended March 31, 2004.	

Table of Contents
 	 	
(15) 	Incorporated herein by reference to NRG Energy Inc.’s Registration Statement on Form S-8, Registration No. 333-114007.	
 	 	
(16) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on October 3, 2005.	
 	 	
(17) 	Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended June 30, 2005.	
 	 	
(18) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on January 4, 2006.	
 	 	
(19) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on December 28, 2005.	
 	 	
(20) 	Incorporated herein by reference to NRG Energy, Inc.’s annual report on Form 10-K filed on March 30, 2005.	
 	 	
(21) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on May 24, 2005.	
 	 	
(22) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on August 11, 2005.	
 	 	
(23) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on August 3, 2005.	
 	 	
(24) 	Incorporated herein by reference to NRG Energy, Inc.’s Form 8-A filed on January 27, 2006.	
 	 	
(25) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on January 27, 2006.	
 	 	
(26) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on February 6, 2006.	
 	 	
(27) 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on February 8, 2006.	

Exhibit 10.31
***	 	Indicates materials have been omitted pursuant to a Confidential Treatment Request filed with the Securities and Exchange Commission. A complete copy of this Agreement has been filed with the Securities and Exchange Commission.	

 
EXECUTION COPY
MASTER POWER PURCHASE AND SALE AGREEMENT
COVER SHEET
This Master Power Purchase and Sale Agreement (“Master Agreement”) first was entered into as of July 21, 2004 (“Effective Date”) and was amended and restated in its entirety on February 2, 2006 (“Restatement Date”). The  Master Agreement,  together with the exhibits, schedules and any written supplements hereto, the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any confirmations accepted in accordance with Section 2.3 hereto) shall be referred to as the “Agreement.” The Parties to this  Master Agreement  are the following:
 	 	 	
Name (“J. ARON & COMPANY” or “Party A”)
All Notices: J. ARON & COMPANY
Street:          85 Broad Street
City:             New York, N.Y. Zip: 10004
Attn: Commodity Operations
Phone: (212) 902-8986
Facsimile: (212) 344-3457
Duns: 06-698-0312
Federal Tax ID Number: 133092284
Invoices: J. Aron & Company
      Attn: Contract Execution Dept.
      Phone: (212) 357-5110
      Facsimile: (212) 428-1991
Scheduling: J. Aron & Company
      Attn: Power Scheduling
      Phone: (212) 902-1454
      Facsimile: (917) 454-2595
Payments: J. Aron & Company
      Attn: Contract Execution Dept.
      Phone: (212) 357-5110
      Facsimile: (212) 428-9571
Wire Transfer: J. Aron & Company
      BNK: CITIBANK, NA
           399 Park Avenue
           New York, N.Y.
           A/C J. ARON & CO.
           NEW YORK
           ABA: 021000089
           ACCT: 09292521
Credit and Collections: J. Aron & Company
      Attn: Credit Risk Management — Power
      Phone: (212) 855-0990
      Facsimile: (212) 493-0821	 	Name (“Texas Genco II, LP, “Counterparty” or “Party B”)
All Notices: Texas Genco II, LP
Street:          1301 McKinney, Suite 2300
City:             Houston, TX  Zip: 77010
Attn: Contract Administration
Phone: (713) 795-6074
Facsimile: (713) 795-7482
Duns: 16-845-6049
Federal Tax ID Number: 34-2019301
Invoices: Texas Genco II, LP
      Attn: Settlements
      Phone: (713) 795-6144
      Facsimile: (713) 795-7482
Scheduling: Texas Genco II, LP
      Attn: Day Ahead Desk
      Phone: (713) 795-6314
      Facsimile: (713) 795-7488
Payments: Texas Genco II, LP
      Attn: Settlements
      Phone: (713) 795-6144
      Facsimile: (713) 795-7482
Wire Transfer: Texas Genco II, LP
      BNK: JP Morgan Chase
      ABA: 113 000 609
      ACCT: 000 000 113 290 523
Credit and Collections: Texas Genco II, LP
      Attn: Credit Department
      Phone: (713) 795-6200
      Facsimile: (713) 795-7441	
 	 	 	
With additional Notices of an Event of Default or	 	With additional Notices of an Event of Default or	

 

2
* * *
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Potential Event of Default to:	 	 	 	Potential Event of Default to:	 	 	
 	 	Attn: Credit Department	 	 	 	 	 	Attn: Credit Department	
 	 	Phone: (212) 902-1800	 	 	 	 	 	Phone: (212) 902-1800	
 	 	Facsimile:	 	 	 	 	 	 	 	Facsimile:	 	 	 	 	

 	 	and to:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	J. Aron & Company	 	 	 	 	 	 	 	 	 	 	
 	 	One New York Plaza	 	 	 	 	 	 	 	 	 	 	
 	 	New York, NY 10004	 	 	 	 	 	 	 	 	 	 	
 	 	Attn: Steven M. Bunkin, Esq.	 	 	 	 	 	 	 	 	 	 	
 	 	Phone: (212) 902-0952	 	 	 	 	 	 	 	 	 	 	
 	 	Facsimile: (212) 428-3675	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Confirmations:	 	 	 	Confirmations:	 	 	
 	 	Attn:	 	 	 	 	 	Attn:	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Phone:	 	 	 	 	 	Phone:	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Facsimile:	 	 	 	 	 	Facsimile:	

 

3
* * *
The Parties hereby agree that the General Terms and Conditions are incorporated herein, and to the following provisions as provided for in the General Terms and Conditions:
Party A Tariff                Tariff: None                Dated   Docket Number
Party B Tariff                Tariff: None                Dated    Number
 
Article Two	 	 	
 	 	 	
Transaction Terms and Conditions 	 	[ ]      Optional provision in Section 2.4. If not checked, inapplicable.	

Article Four	 	 	
 	 	 	
Remedies for Failure
to Deliver or Receive 	 	[ ]      Accelerated Payment of Damages. If not checked, inapplicable.	

Article Five	 	[ ] Cross Default for Party A:	
 	 	 	
Events of Default; Remedies	 	 	
 	 	 	
 	 	[ ] Party A: Applicable            Cross Default Amount	
 	 	 	
 	 	[ ] Other Entity:                       Cross Default Amount	
 	 	 	
 	 	[ ] Cross Default for Party B:	
 	 	 	
 	 	[ ] Party B: ____________Cross Default Amount $ ____________	
 	 	 	
 	 	[ ] Other Entity: ____________ Cross Default Amount $ _________________	
 	 	 	
 	 	5.6 Closeout Setoff	

 	 	 	[ ] Option A (Applicable if no other selection is made.)	
 	 	 	 	
 	 	 	[ ] Option B — Affiliates shall have the meaning set forth in the Agreement unless otherwise specified as follows: ____________________________	
 	 	 	 	
 	 	 	[ ] Option C (No Setoff)	

Article 8 	 	8.1 Party A Credit Protection:	

Credit and Collateral Requirements 	(a) 	 	Financial Information:	

 	 	 	[ ] Option A	
 	 	 	 	
 	 	 	[ ] Option B            Specify:	
 	 	 	 	
 	 	 	[ ] Option C            Specify: _________	
 	 	 	 	
 	(b)	 	Credit Assurances:	
 	 	 	 	
 	 	 	[ ] Not Applicable	
 	 	 	 	
 	 	 	[ ] Applicable	
 	 	 	 	
 	(c)	 	Collateral Threshold:	
 	 	 	 	
 	 	 	[ ] Not Applicable	
 	 	 	 	
 	 	 	[ ] Applicable	

 

4
* * *
 	(d)	 	Downgrade Event:	
 	 	 	 	
 	 	 	[ ] Not Applicable	
 	 	 	 	
 	 	 	[ ] Applicable	
 	 	 	 	
 	(e)	 	Guarantor for Party B:	
 	 	 	 	
 	 	 	Guarantee Amount:	

 	 	8.2 Party B Credit Protection:	

 	(a)	 	Financial Information:	
 	 	 	 	
 	 	 	[ ] Option A	
 	 	 	 	
 	 	 	[ ] Option B Specify: _________	
 	 	 	 	
 	 	 	[ ] Option C Specify: _________	
 	 	 	 	
 	(b)	 	Credit Assurances:	
 	 	 	 	
 	 	 	[ ] Not Applicable	
 	 	 	 	
 	 	 	[ ] Applicable	
 	 	 	 	
 	(c)	 	Collateral Threshold:	
 	 	 	 	
 	 	 	[ ] Not Applicable	
 	 	 	 	
 	 	 	[ ] Applicable	
 	 	 	 	
 	(d)	 	Downgrade Event:	
 	 	 	 	
 	 	 	[ ] Not Applicable	
 	 	 	 	
 	 	 	[ ] Applicable	
 	 	 	 	
 	(e)	 	Guarantor for Party A:	
 	 	 	 	
 	 	 	Guarantee Amount:	

Article 10
Confidentiality  	 	[x] Confidentiality Applicable   If not checked, inapplicable.	

Schedule M 	 	[ ] Party A is a Governmental Entity or Public Power System	
 	 	 	
 	 	[ ] Party B is a Governmental Entity or Public Power System	
 	 	 	
 	 	[ ] Add Section 3.6. If not checked, inapplicable	
 	 	 	
 	 	[ ] Add Section 8.6. If not checked, inapplicable	
 	 	 	
Other Changes  	 	Specify, if any: See Part 1 below	

 

5
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Part 1. General Terms and Conditions
(1) Article One shall be amended as follows:
(i) The following definitions shall be revised or inserted in alphabetical order:
          “Baseload Capacity” means electric power generation capacity of NRG Energy and its Subsidiaries (including NRG Energy’s and its Subsidiaries’ pro rata share of the capacity represented by minority investments in units) normally operated by NRG Energy and/or any of its Subsidiaries to serve loads on an around-the-clock basis.
          “Capacity Commodity Hedging Agreement” has the meaning specified in the NRG Collateral Trust Agreement.
          “Collateral” has the meaning specified in the NRG Collateral Trust Agreement.
          “Credit Agreement” has the meaning specified in the NRG Collateral Trust Agreement.
          “Definitions” means the 1993 ISDA Commodity Derivatives Definitions as supplemented by the 2000 Supplement to the 1993 ISDA Commodity Derivatives Definitions, each as published by the International Swaps and Derivatives Association, Inc.
          “Derivative Transaction” means (i) any transaction that provides solely for cash settlement and not physical settlement and (ii) that is (a) a commodity swap transaction, cross-commodity swap transaction, commodity cap transaction, commodity floor transaction, commodity collar transaction, commodity option transaction or any other similar transaction (including any Option with respect to any of these transactions), (b) any combination of these transactions or (c) any other transaction identified as a Derivative Transaction in the related Confirmation.
          “ERCOT” means the Electric Reliability Council of Texas, Inc.
          “ERCOT Protocols” means the document adopted, published and amended from time to time by ERCOT, and approved by the PUCT, to govern electric transmission in ERCOT, including any attachments, exhibits or publications referenced in the document, that contains the scheduling, operating, planning, reliability, and settlement policies, rules, guidelines, procedures, standards, and criteria of ERCOT.
          “Fixed LOC” has the meaning ascribed thereto in Section 8.1(c)(I).
          “Guarantee and Collateral Agreement” has the meaning specified in the NRG Collateral Trust Agreement.
          ***
          ***

 

6
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          ***
          “Measurement Date” means, in the case of a Sale, the date of the closing of such Sale and, in the case of a Forecast Loss, the date on which such Forecast Loss is first forecast.
          “MW” has the meaning specified in the NRG Collateral Trust Agreement.
          “Non-Baseload Capacity” means an amount of electric power generation capacity equal to (i) all electric power generation capacity of NRG Energy and its Subsidiaries (including NRG Energy’s and its Subsidiaries’ pro rata share of the capacity represented by minority investments in units) minus (ii) all Baseload Capacity.
          “NRG Collateral Trust Agreement” means the Collateral Trust Agreement dated as of February 2, 2006 (as amended, restated, supplemented, replaced or otherwise modified from time to time), by and among NRG Energy, Inc., the guarantors from time to time party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, J. Aron & Company, as counterparty under the GS Commodity Hedging Agreement (as defined therein), and Morgan Stanley & Co. Inc., as collateral trustee.
          “Obligations” has the meaning specified in the NRG Collateral Trust Agreement.
          ***
          ***
          “Party” means each of Party A and Party B and “Parties” means Party A and Party B collectively.
          ***
          ***
          “PUCT” means the Public Utility Commission of Texas.
          ***
          “Specified Transaction” means any transaction (other than a Transaction) now existing or hereafter entered into between one Party to this Agreement and the other Party to this Agreement that is a spot, forward, option or swap transaction in or with respect to one or more currencies, commodities, securities, rates, indices or other measures of financial or economic risk or any other similar transaction (or any combination thereof).
          “Subsidiary” has the meaning specified in the NRG Collateral Trust Agreement.
          “Texas Genco Collateral Trust Agreement” has the meaning specified in the NRG Collateral Trust Agreement.

 

7
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(ii) Section 1.11 is amended by adding the following to the end thereof: “and in entering into new arrangements which replace a Terminated Transaction.”
(iii) Section 1.50 is amended to delete the reference to section “2.4” and replacing it with “2.5”.
(iv) Section 1.51 is amended by (a) adding the phrase “for delivery” immediately before the phrase “at the Delivery Point” in the second line thereof and (b) deleting the phrase “at Buyer’s option” from the fifth line thereof and replacing it with the following: “absent a purchase”.
(v) Section 1.53 is amended by (a) deleting the phrase “at the Delivery Point” from the second line thereof and (b) deleting the phrase “at Seller’s option” from the fifth line thereof and replacing it with the following: “absent a sale.”
(vi) The definition of “Transaction” in Section 1.60 is hereby deleted in its entirety and replaced with the following new definition:
          “Transaction” means (a) a particular transaction agreed to by the Parties relating to the sale and purchase of a Product pursuant to this Master Agreement or (b) a particular Derivative Transaction agreed to by the Parties pursuant to this Master Agreement.
(2) Article Two shall be amended as follows:
(i) In Section 2.2, insert “The Definitions are hereby incorporated by reference with respect to any Transaction entered into by the Parties pursuant to this Master Agreement that is a Derivative Transaction, except as otherwise provided in any Confirmation or as agreed to by the Parties. In the event of any inconsistency between the provisions of the Master Agreement and the Definitions, the Master Agreement will prevail. In the event of any inconsistency between the terms of any Transaction that is a Derivative Transaction and the Definitions, the terms of such Transaction will prevail.” after the last sentence.
(ii) In Section 2.3, insert “or any other means of electronic messaging for which a written record can be retrieved” after “facsimile” in the first sentence.
(iii) Article Two shall be amended to add a new Section 2.6 as follows:
     2.6 Existing Transactions and Confirmations. For the avoidance of doubt, all Transactions and Confirmations outstanding under the Master Agreement on or prior to the Restatement Date shall remain in effect under the Master Agreement following the Restatement Date;  provided ,  however , that if the terms set forth in such prior Transactions and Confirmations are inconsistent with the terms set forth in the Master Agreement (as restated on the Restatement Date), then the terms in the Master Agreement shall govern.
(3) Article Three shall be amended as follows:
(i) In Section 3.1, insert “set forth in (a) of the definition thereof,” after “Transaction” in the first sentence.

 

8
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(ii) In Section 3.1, insert “With respect to each Derivative Transaction, the Fixed Price Payer (as specified in the related Confirmation) or the Floating Price Payer (as specified in the related Confirmation), as applicable shall pay to the other party any amounts due in accordance with the section entitled “Settlements” in the related Confirmation.” as a new paragraph.
(iii) Section 3.2 is hereby deemed inoperative with respect to all Derivative Transactions.
(iv) Section 3.3 is hereby deemed inoperative with respect to all Derivative
Transactions.
(4) Article Four shall be amended as follows:
(i) Section 4.1 is hereby deemed inoperative with respect to all Derivative Transactions.
(ii) Section 4.2 is hereby deemed inoperative with respect to all Derivative Transactions.
(5) Article Five shall be amended as follows:
(i) In Section 5.1(c), add “, in the case of Transaction set forth in (a) of the definition thereof,” after “except” the second time it appears in such Section and before “for” the first time it appears in such Section.
(ii) In Section 5.1(e), delete “agreed to pursuant to” and add “as and when due as specified in” in its place.
(iii) Section 5.1(g) is amended as follows: in clause (i), delete “, or becoming capable at such time of being declared,”.
(iv) Section 5.1 shall be amended to add a new Section 5.1(i) and Section 5.1(j) as follows:
 	(i)	 	with respect to Party B only, the acceleration of any Specified Indebtedness. ***. For purposes hereof, “acceleration” means the occurrence and continuation of a default, event of default or other similar condition or event relating to the relevant indebtedness, which results in such indebtedness becoming immediately due and payable, or the failure to pay any such indebtedness at maturity.	
 	 	 	 	
 	(j)	 	either Party (i) defaults under a Specified Transaction and, after giving effect to any applicable notice requirement or grace period, such default results in a liquidation of, an acceleration of obligations under, or an early termination of, that Specified Transaction, (ii) defaults, after giving effect to any applicable notice requirement or grace period, in making any payment or delivery due on the last payment date or delivery date of a Specified Transaction; or (iii) disaffirms, disclaims or repudiates any Specified Transaction.	

 

9
* * *
(v) Section 5.2 is amended to delete the following phrase from the last two lines thereof: “under applicable law on the Early Termination Date, as soon as thereafter as is reasonably practicable)” and to add the following to the end of Section 5.2:
“under applicable law on the Early Termination Date, then each such Transaction (individually, an “Excluded Transaction” and collectively, the “Excluded Transactions”) shall be terminated as soon thereafter as reasonably practicable, and upon termination shall be deemed to be a Terminated Transaction and the Termination Payment payable in connection with all such Transactions shall be calculated in accordance with Section 5.3 below). The Non-Defaulting Party (or its agent) may determine its Gains and Losses by reference to information either available to it internally or supplied by one or more third parties including, without limitation, quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets. Third parties supplying such information may include, without limitation, dealers in the relevant markets, end-users of the relevant product, information vendors and other sources of market information.”
(vi)	 	In Section 5.3(a), insert the word “liquid” immediately after the phrase “any cash or other form of” in the third line thereof.	
 	 	 	
(vii)	 	In Section 5.3(b), insert “plus, at the option of the Non-Defaulting Party, any cash or other form of liquid security then available to the Defaulting Party or its agent pursuant to Article Eight,” after the phrase “Non-Defaulting Party,” in the sixth line thereof.	
 	 	 	
(viii)	 	The following is added to the end of Section 5.4:	

 	 	 	Notwithstanding any provision to the contrary contained in this Agreement, the Non-Defaulting Party shall not be required to pay to the Defaulting Party any amount under Article 5 until the Non-Defaulting Party receives confirmation satisfactory to it in its reasonable discretion (which may include an opinion of its counsel) that all other obligations of any kind whatsoever of the Defaulting Party to make any payments to the Non-Defaulting Party under this Agreement or otherwise have been fully and finally performed.	

(ix)	 	Option A of Section 5.6 shall be deleted in its entirety and replaced with the following provision:	

 	 	 	“Option A: After calculation of a Termination Payment in accordance with Section 5.3, if the Defaulting Party would be owed the Termination Payment, the Non-Defaulting Party shall be entitled, at its option and in its discretion, to (i) set off against such Termination Payment any amounts payable (whether or not then due) by the Defaulting Party to the Non-Defaulting Party under any other agreements, instruments or undertakings between the Defaulting Party and the Non-Defaulting Party and/or (ii) to the extent the Transactions are not yet liquidated in accordance with Section 5.2, withhold payment of the Termination Payment to the Defaulting Party. The remedy provided for in this	

 

10
* * *
 	 	 	Section shall be without prejudice and in addition to any right of setoff, combination of accounts, lien or other right to which any Party is at any time otherwise entitled (whether by operation of law, contract or otherwise).	
 	 	 	 	
 	 	 	If any obligation is unascertained, the Non-Defaulting Party may in good faith estimate that obligation and set-off in respect of the estimate, subject to the Non-Defaulting Party accounting to the other when the obligation is ascertained.”	

(x)	 	Section 5.7 is amended as follows:	

 	(a)	 	after “(i)” insert the following words: “to withhold any payment due to the Defaulting Party under this Agreement and/or”; and	
 	 	 	 	
 	(b)	 	insert the words “withholding or” after “any such”.	
 	 	 	 	
 	(c)	 	at the end of Section 5.7, insert “The proviso in subsection (i) of this Section is inoperative with respect to all Derivative Transactions.”	

(xi)	 	The following shall be added as new Sections 5.8 and 5.9:	
               5.8 Certain Regulatory Matters.
               (a) In the event Buyer is regulated by a federal, state or local regulatory body, and such body shall disallow all or any portion of any costs incurred or yet to be incurred by Buyer under any provision of this Agreement or in respect of any Transaction, such action shall not operate to excuse Buyer from performance of any obligation hereunder nor shall such action give rise to any right of Buyer to any refund or retroactive adjustment of the price of any Transaction.
               (b) If, after giving effect to any applicable provision or remedy specified in, or pursuant to, this Agreement, due to an event or circumstance (other than any action taken or omission by a Party) occurring after a Transaction is entered into, it becomes unlawful under any applicable law for a Party (an “Affected Party”) to perform any material obligation to make a payment or delivery in respect of such Transaction (an “Affected Transaction”), to receive a payment or take delivery in respect of such Transaction or to comply with any other material provision of this Agreement relating to such Transaction (in each case, other than as a result of a breach by such Party of Section 5.8(c)), then either Party may, by notice to the other Party, terminate and liquidate all Affected Transactions in the manner contemplated by Section 5.2, which notice shall specify the basis for declaring such Early Termination Date and identify which Transactions are Affected Transactions. If the Affected Transactions constitute all Transactions then in effect under this Agreement, both Parties shall calculate their respective Gains, Losses or Costs in respect of Terminated Transactions as provided in Sections 5.2, 5.3 and 5.4, and endeavor in good faith to agree upon the Termination Payment payable by either Party. If the Affected Transactions constitute some but less than all of the Transactions then in effect under this Agreement, only the Party that is not the Affected Party shall calculate its Gains, Losses and Costs in respect of all Affected Transactions and notify the Affected Party

 

11
* * *
of the Termination Payment, as provided in Sections 5.2, 5.3 and 5.4. Only the Affected Transactions shall be terminated on the Early Termination Date under the circumstances described in the preceding sentence and all other Transactions shall remain unaffected as if no Early Termination Date had been declared.
          (c) Each Party agrees that it will use all reasonable efforts to maintain in full force and effect all consents, approvals, permits or other authorizations of any governmental or other authority (including ERCOT) that are required to be obtained by it with respect to this Agreement and will use all reasonable efforts to obtain any that may become necessary in the future.
          5.9 ***
(6) Article Six shall be amended as follows:
(i) In Section 6.7, the second sentence is hereby deemed inoperative with respect to all Derivative Transactions.
(7) Article Seven shall be amended as follows:
 	(i)	 	Section 7.1 is amended by: (a) deleting “EXCEPT AS SET FORTH HEREIN” from the first sentence thereof, (b) deleting “UNLESS EXPRESSLY HEREIN PROVIDED” from the fifth sentence thereof and substituting in lieu thereof, “NOTWITHSTANDING ANYTHING IN THIS AGREEMENT TO THE CONTRARY” and (c) adding “SET FORTH IN THIS AGREEMENT” after the phrase “INDEMNITY PROVISION” in the fifth sentence thereof.	
(8) ***
(9) Article Nine shall be amended as follows:
(i) Section 9.2 is hereby deemed inoperative with respect to all Derivative Transactions.
(10) Article Ten shall be amended as follows:
(i) Section 10.2 (viii) is amended by adding at the end thereof: “, and acknowledges that the other Party is not acting as a fiduciary for or advisor to it in respect of any Transaction.”
(ii) The reference to “forward contract merchant” in Section 10.2 (ix) is hereby replaced with “swap participant” with respect to all Derivative Transactions.
(iii) Section 10.3 is hereby deemed inoperative with respect to all Derivative Transactions.
(iv) Section 10.4 is hereby deemed inoperative with respect to all Derivative Transactions.
(v) Section 10.5 is amended as follows:

 

12
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 	(a)	 	in the second and third lines thereof, delete the words “may be withheld in the exercise of its sole discretion” and replace them with the following: “will not be arbitrarily withheld or delayed”;	
 	 	 	 	
 	(b)	 	in the fourth line thereof, delete “(and without relieving itself from liability hereunder)”;	
 	 	 	 	
 	(c)	 	in Clause (iii) delete “whose creditworthiness is equal or higher than that” and insert “or pursuant to any consolidation or amalgamation with, or merger with or into another entity or the reorganization, incorporation, reincorporation or reconstitution into or as another entity” after “such Party”;	
 	 	 	 	
 	(d)	 	insert the following at the end of Section 10.5:	
 	 	 	 	
 	 	 	“No transfer or assignment by either Party shall affect the non-transferring Party’s rights and obligations or the transferring Party’s obligations hereunder, including the obligation to provide and maintain Performance Assurance (including any liens) or a guaranty required to be provided under this Agreement. Notwithstanding the foregoing, Party B shall have the right to assign, with full novation and release, pursuant to Section 10.16.”	

(vi)	 	In Section 10.6:	

 	(a)	 	designate the existing text of the Section as Clause (a) and delete the words “AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER” and replace them with “, EACH TRANSACTION ENTERED INTO HEREUNDER, AND ALL MATTERS ARISING IN CONNECTION WITH THIS AGREEMENT”, and	
 	 	 	 	
 	(b)	 	insert the following new Clauses (b) and (c):	

 	(b)	 	With respect to any suit, action or proceedings relating to this Agreement (“Proceedings”), each Party irrevocably:	

 	(i)	 	submits to the non-exclusive jurisdiction of the courts of the State of New York and the United States District Court located in the Borough of Manhattan in New York City; and	
 	 	 	 	
 	(ii)	 	waives any objection which it may have at any time to the laying of venue of any Proceedings brought in any such court, waives any claim that such Proceedings have been brought in an inconvenient forum and further waives the right to object, with respect to such Proceedings, that such court does not have any jurisdiction over such party.	

 	 	 	Nothing in this Agreement precludes either Party from bringing Proceedings in any other jurisdiction in order to enforce any judgment	

 

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 	 	 	obtained in any Proceedings referred to in the preceding sentence, nor will the bringing of such enforcement Proceedings in any one or more jurisdictions preclude the bringing of enforcement Proceedings in any other jurisdiction.	

 	(c)	 	Each Party hereby irrevocably waives any and all right to trial by jury in any Proceeding.”;	

(vii)	 	The third and fourth sentences of Section 10.7 are replaced with the following:	
 	 	 	
 	 	“Notices shall be effective upon receipt by the Party to which it was addressed, which in the case of a facsimile shall be deemed to occur by the close of business on the Business Day on which the same is transmitted (or if not transmitted on a Business Day, then the next Business Day) or such earlier time as is confirmed by the receiving Party.”	
(viii) The second sentence of Section 10.9 is hereby deemed inoperative with respect to all Derivative Transactions.
(ix) The reference to “forward contracts” in Section 10.10 is hereby replaced with “swap agreements” with respect to all Derivative Transactions.
(x)	 	Section 10.11 shall be deleted in its entirety and replaced with the following:	
 	 	 	
 	 	“10.11 Confidentiality. If the Parties have elected on the Cover Sheet to make this Section 10.11 applicable to this Agreement, neither Party shall disclose the terms or conditions of a Transaction under this Agreement, during the term of such Transaction, to a third party (other than the Party’s and the Party’s Affiliates’ employees, rating agencies, lenders, potential investors or buyers, counsel, accountants or advisors who have agreed to keep such terms confidential) except (i) in order to comply with any applicable law (including the rules and regulations of the Securities and Exchange Commission), regulation, or any exchange, control area or independent system operator rule or in connection with any court, regulatory or self-regulatory proceeding or request, (ii) to the extent such information is delivered to such third party for the sole purpose of calculating a published index or other published price source, and (iii) as may be required to be disclosed to the PUCT or in any proceedings of such commission or of any other governmental or regulatory agency having jurisdiction over any Party or such Party’s Affiliates. Each Party shall notify the other Party of any proceeding of which it is aware which may result in disclosure of the terms of any transaction (other than as permitted hereunder) and use reasonable efforts to prevent or limit the disclosure,  provided ,  however , that such reasonable efforts do not cause a Party to be in violation of any law, regulation, subpoena, order or request. The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, this confidentiality obligation.”	
 	 	 	
(xi)	 	The following will be added as a new Section 10.12, 10.13, 10.14, 10.15 and 10.16, respectively:	

 

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          10.12 Scope of Agreement. Notwithstanding anything contained in this Agreement to the contrary, any transaction for the purchase and sale of electric capacity, energy or other products related thereto which has been or will be entered into between Party A and Party B shall constitute a “Transaction” which is subject to, governed by, and construed in accordance with the terms of this Agreement. This Section is inoperative with respect to all Derivative Transactions.
          10.13 Binding Rates and Terms.
 	(a)	 	Each Party irrevocably waives its rights, including its rights under §§ 205-206 of the Federal Power Act, unilaterally to seek or support a change in the rate(s), charges, classifications, terms or conditions of this Agreement or any other agreements entered into in connection with this Agreement or any Transaction thereunder, including any credit, security, margin, guaranty or similar agreement (collectively with this Agreement, the “ Covered Agreements ”). By this provision, each Party expressly waives its right to seek or support: (i) an order from FERC finding that the market-based rate(s), charges, classifications, terms or conditions agreed to by the Parties in the Covered Agreements are unjust and unreasonable; or (ii) any refund with respect thereto. Each Party agrees not to make or support such a filing or request, and that these covenants and waivers shall be binding notwithstanding any regulatory or market changes that may occur hereafter.	
 	 	 	 	
 	(b)	 	Absent the agreement of all parties to the proposed change, the standard of review for changes to any section of any Covered Agreement proposed by a Party (to the extent that any waiver in Section 10.13(a) above is unenforceable or ineffective as to such Party), a non-Party or FERC acting  sua sponte , shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the “ Mobile-Sierra ” doctrine).	
 	 	 	 	
 	(c)	 	The Parties agree that, if and to the extent that FERC adopts a final Mobile-Sierra policy statement in Docket No. PL02-7-000 (“ Policy Statement ”) or issues a final rule (“ Final Rule ”) that requires that, in order to exclude application of the just and reasonable standard under the Mobile-Sierra doctrine, the Parties must agree to language which varies from that set forth in Section 10.13(a) or (b) above, then, without further action of either Party (unless the Parties mutually agree otherwise), such Section(s) shall be deemed amended to incorporate the specific language in the Policy Statement or the Final Rule (as applicable) that requires the public interest standard of review.	
 	 	 	 	
 	(d)	 	The foregoing is not intended to subject this Agreement or either Party to the jurisdiction of FERC.	

 

15
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          10.14 ERCOT Protocols. The Parties shall comply with the ERCOT Protocols and shall reasonably cooperate with each other in their efforts to comply with the ERCOT Protocols;  provided ,  however , this Section 10.14 is not intended to impose liability on either Party for the failure to do so.
Section 10.15 ***
(11) Additional Provisions. The following provisions shall be added to Schedule P: Products and Related Definitions:
(i)	 	Other Products and Service Levels. If the Parties agree to a service level defined by a different agreement (i.e., the WSPP agreement, the ERCOT agreement, etc.) for a particular Transaction, then, unless the Parties expressly state and agree that all the terms and conditions of such other agreement will apply, such reference to a service level/product defined by such other agreement means that the service level for that Transaction is subject to the applicable regional reliability requirements and guidelines as well as the excuses for performance, Force Majeure, Uncontrollable Forces, or other such excuses applicable to performance under such other agreement, to the extent inconsistent with the terms of this Agreement, but all other terms and conditions of this Agreement remain applicable including, without limitation, Section 2.2.	
 	 	 	
(ii)	 	Index Transactions. The terms and provisions of this Section shall be applicable only to transactions which stipulate prices that must be determined by reference to a published index or other publicly available price reference:	

 	(a)	 	Market Disruption. If a Market Disruption Event has occurred and is continuing during the Determination Period, the Floating Price for the affected Trading Day shall be determined pursuant to the index specified in the Transaction for the first Trading Day thereafter on which no Market Disruption Event exists;  provided ,  however , if the Floating Price is not so determined within three (3) Business Days after the first Trading Day on which the Market Disruption Event occurred or existed, then the Parties shall negotiate in good faith to agree on a Floating Price (or a method for determining a Floating Price), and if the Parties have not so agreed on or before the twelfth (12th) Business Day following the first Trading Day on which the Market Disruption Event occurred or existed, then the Floating Price shall be determined with each party obtaining in good faith a quote from a leading dealer in the relevant market and averaging the two quotes.	
 	 	 	 	
 	 	 	“Determination Period” means each calendar month during the term of the relevant Transaction, provided that if the term of the Transaction is less than one calendar month the Determination Period shall be the term of the Transaction.	

 

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 	 	 	“Floating Price” means the price specified in the Transaction as being based upon a specified index or other publicly available price reference (“index”).	
 	 	 	 	
 	 	 	“Market Disruption Event” means, with respect to an index, any of the following events: (a) the failure of the index to announce or publish information necessary for determining the Floating Price; (b) the failure of trading to commence or the permanent discontinuation or material suspension of trading in the relevant options contract or commodity on the exchange or market acting as the index; (c) the temporary (for a period in excess of three (3) business days) or permanent discontinuance or unavailability of the index; (d) the temporary (for a period in excess of three (3) business days) or permanent closing of any exchange acting as the index; or (e) a material change in the formula for or the method of determining the Floating Price.	
 	 	 	 	
 	 	 	“Trading Day” means a day in respect of which the relevant price source published the relevant price.	
 	 	 	 	
 	(b)	 	Corrections to Published Prices. For purposes of determining the relevant prices for any day, if the price published or announced on a given day and used or to be used to determine a relevant price is subsequently corrected and the correction is published or announced by the person responsible for that publication or announcement, either Party may notify the other Party of (i) that correction and (ii) the amount (if any) that is payable as a result of that correction. If a Party gives notice that an amount is so payable, the Party that originally either received or retained such amount will, not later than three (3) Business Days after the effectiveness of that notice, pay, subject to any applicable conditions precedent, to the other Party that amount, together with interest at the Interest Rate for the period from and including the day on which payment originally was (or was not) made to but excluding the day of payment of the refund or payment resulting from that correction.	
 	 	 	 	
 	(c)	 	Calculation of Floating Price. For the purposes of the calculation of a Floating Price, all numbers shall be rounded to three (3) decimal places. If the fourth (4th) decimal number is five (5) or greater, then the third (3rd) decimal number shall be increased by one (1), and if the fourth (4th) decimal number is less than five (5), then the third (3rd) decimal number shall remain unchanged.	
               10.16. Assignment and Release. (a) At any time, so long as no Early Termination Date has occurred or been designated as a result of an Event of Default with respect to Texas Genco II, LP (“TGN”), (i) TGN shall be permitted to assign (the “ Assignment ”) all of its rights and obligations under this Agreement to NRG Power Marketing, Inc. (“NRG Power”) pursuant to a written instrument in which NRG Power agrees to assume such rights and obligations and (ii) Party A shall consent to Assignment, provided that NRG

 

17
* * *
Power has provided Party A with a new or amended Fixed LOC having a face value in the amount required under Section 8.1(c)(I) on the date of the Assignment and any new or amended Additional LOCs required under then outstanding Transactions, each such Additional LOC having a face amount in the amount required under the terms of the relevant Transaction and Section 8.1(c)(III) on the date of the Assignment. Upon the effectiveness of the Assignment all the rights, liabilities, duties and obligations of TGN under and in respect of one or more Transactions entered into between Party A and TGN (each, an “ Old Transaction ”) as evidenced by a confirmation (each, an “ Old Confirmation ”) shall be assigned to NRG Power, with the effect that Party A and NRG Power will be deemed to have entered into a new transaction (each, a “ New Transaction ”) between them having terms identical to those of each Old Transaction, with the understanding that Party A and NRG Power shall each undertake liabilities and obligations towards the other and acquire rights against each other identical in their terms to each corresponding Old Transaction (and, for the avoidance of doubt, as if NRG Power were TGN and with Party A remaining Party A, save for any rights, liabilities or obligations of Party A or TGN with respect to payments or other obligations due and payable or due to be performed on or prior to date of the Assignment). Upon the effectiveness of the Assignment, the guarantee provided by the Goldman Group to TGN (the “ Guarantee ”) will be terminated, and Party A shall cause such Guarantee to be replaced by a guarantee by Goldman Group (which guarantee shall be identical in all material respects to the Guarantee) in favor of NRG Power.
(b) Subject to the occurrence of the events detailed in Section 10.16(a) and upon written notice to Party A, and following (i) the consolidation of the Texas Genco Collateral Trust Agreement and the NRG Collateral Trust Agreement into a single collateral trust agreement and (ii) NRG Power performing such other actions as Party A may reasonably request, Party A and TGN each shall be released and discharged from further obligations to the other party with respect to each Old Transaction and their respective rights against each other thereunder shall be canceled (the “ Release ”), provided that such release and discharge shall not affect any rights, liabilities or obligations of Party A or TGN with respect to payments or other obligations due and payable or due to be performed on or prior to the date of the Release, and all such payments and obligations shall be paid or performed by Party A or TGN in accordance with the terms of the Old Transaction. Nothing contained herein shall affect TGN’s obligations as a Guarantor of the obligations arising under this Agreement so long as TGN is required to be a Guarantor hereunder.
Schedule P is hereby deemed inoperative with respect to all Derivative Transactions.

 

18
* * *
IN WITNESS WHEREOF, the Parties have caused this Master Agreement to be duly executed in one or more counterparts (each of which shall be deemed an original, and all of which, taken together, shall constitute one and the same agreement) as of the date first above written. The Parties expressly acknowledge the validity of facsimile counterparts of the executed Master Agreement, if any, which may be transmitted in advance of, or in lieu of, executed original documents.
J. ARON & COMPANY
 	 	 	 	 	
By:	 	 	 	 	
 	 	 	 	 	
 	 	Name:	 	 	
 	 	Title:	 	 	
TEXAS GENCO II, LP
 	 	 	
By:	New Genco GP, LLC,	
 	its general partner	
Name:	 	 	
Title:	 	 	
DISCLAIMER: This Master Power Purchase and Sale Agreement was prepared by a committee of representatives of Edison Electric Institute (“EEI”) and National Energy marketers Association (“NEM”) member companies to facilitate orderly trading in and development of wholesale power markets. Neither EEI nor NEM nor any member company nor any of their agents, representatives or attorneys shall be responsible for its use, or any damages resulting therefrom. By providing this Agreement, EEI and NEM do not offer legal advice and all users are urged to consult their own legal counsel to ensure that their commercial objectives will be achieved and their legal interests are adequately protected.

 
Schedule B to Master Power Purchase
and Sale Agreement Cover Sheet
Form of Letter of Credit
WE HEREBY ESTABLISH OUR IRREVOCABLE STAND-BY LETTER OF CREDIT
NO. _______________
IN FAVOR OF:
[BENEFICIARY]
[ADDRESS]
[ADDRESS]
Attn : [ _________ ]
Telex : [ _________ ]
BY ORDER AND FOR THE ACCOUNT OF:
(insert full style and address)
FOR AN AMOUNT OF:
US DOLLARS _________
(UNITED STATES DOLLARS _________)
AVAILABLE FOR PAYMENT AT SIGHT UPON PRESENTATION AT OUR COUNTERS IN (insert city and country where documents are to be presented) OF THE FOLLOWING DOCUMENT:
STATEMENT SIGNED BY A PURPORTEDLY AUTHORIZED REPRESENTATIVE OF [BENEFICIARY] CERTIFYING THAT (insert your company name) HAS NOT PERFORMED IN ACCORDANCE WITH THE TERMS OF THE MASTER POWER PURCHASE & SALE AGREEMENT, DATED AS OF JULY 21, 2004, AS AMENDED AND RESTATED AS OF FEBRUARY 2, 2006, BETWEEN  [BENEFICIARY]  AND (insert your company name), AND THE AMOUNT BEING DRAWN OF USD _________ DOES NOT EXCEED THAT AMOUNT WHICH  [BENEFICIARY]  IS ENTITLED TO DRAW PURSUANT TO THE TERMS AND CONDITIONS OF SUCH AGREEMENT.
SPECIAL CONDITIONS:
1. PARTIAL AND MULTIPLE DRAWINGS ARE PERMITTED.
2. ALL CHARGES RELATED TO THIS LETTER OF CREDIT ARE FOR THE ACCOUNT PARTY’S ACCOUNT.
3. DOCUMENTS MUST BE PRESENTED NOT LATER THAN (insert expiry date) OR IN THE EVENT OF FORCE MAJEURE INTERRUPTING OUR BUSINESS, WITHIN THIRTY (30) DAYS AFTER RESUMPTION OF OUR BUSINESS, WHICHEVER IS LATER.

 
UPON RECEIPT OF DOCUMENTS ISSUED IN COMPLIANCE WITH THE TERMS OF THIS CREDIT, WE HEREBY IRREVOCABLY UNDERTAKE TO COVER YOU AS PER YOUR INSTRUCTIONS WITH VALUE ONE BANK WORKING DAY.
      THIS STANDBY CREDIT IS SUBJECT TO THE UNIFORM CUSTOMS AND PRACTICE FOR DOCUMENTARY CREDITS 1993 REVISION), I.C.C. PUBLICATION 500.

 
TABLE OF CONTENTS
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Page	 	
ARTICLE ONE GENERAL DEFINITIONS	 	 	1	 	
 	 	 	 	 	 	 	 	 	
ARTICLE TWO TRANSACTION TERMS AND CONDITIONS	 	 	6	 	
 	 	 	 	 	 	 	 	 	
 	2.1	 	 	Transactions	 	 	6	 	
 	2.2	 	 	Governing Terms	 	 	6	 	
 	2.3	 	 	Confirmation	 	 	6	 	
 	2.4	 	 	Additional Confirmation Terms	 	 	7	 	
 	2.5	 	 	Recording	 	 	7	 	
 	 	 	 	 	 	 	 	 	
ARTICLE THREE OBLIGATIONS AND DELIVERIES	 	 	7	 	
 	 	 	 	 	 	 	 	 	
 	3.1	 	 	Seller’s and Buyer’s Obligations	 	 	7	 	
 	3.2	 	 	Transmission and Scheduling	 	 	8	 	
 	3.3	 	 	Force Majeure	 	 	8	 	
 	 	 	 	 	 	 	 	 	
ARTICLE FOUR REMEDIES FOR FAILURE TO DELIVER/RECEIVE	 	 	8	 	
 	 	 	 	 	 	 	 	 	
 	4.1	 	 	Seller Failure	 	 	8	 	
 	4.2	 	 	Buyer Failure	 	 	8	 	
 	 	 	 	 	 	 	 	 	
ARTICLE FIVE EVENTS OF DEFAULT; REMEDIES	 	 	8	 	
 	 	 	 	 	 	 	 	 	
 	5.1	 	 	Events of Default	 	 	8	 	
 	5.2	 	 	Declaration of an Early Termination Date and Calculation of Settlement Amounts	 	 	10	 	
 	5.3	 	 	Net Out of Settlement Amounts	 	 	10	 	
 	5.4	 	 	Notice of Payment of Termination Payment	 	 	10	 	
 	5.5	 	 	Disputes With Respect to Termination Payment	 	 	11	 	
 	5.6	 	 	Closeout Setoffs	 	 	11	 	
 	5.7	 	 	Suspension of Performance	 	 	11	 	
 	 	 	 	 	 	 	 	 	
ARTICLE SIX PAYMENT AND NETTING	 	 	12	 	
 	 	 	 	 	 	 	 	 	
 	6.1	 	 	Billing Period	 	 	12	 	
 	6.2	 	 	Timeliness of Payment	 	 	12	 	
 	6.3	 	 	Disputes and Adjustments of Invoices	 	 	12	 	
 	6.4	 	 	Netting of Payments	 	 	12	 	
 	6.5	 	 	Payment Obligation Absent Netting	 	 	13	 	
 	6.6	 	 	Security	 	 	13	 	
 	6.7	 	 	Payment for Options	 	 	13	 	
 	6.8	 	 	Transaction Netting	 	 	13	 	
i

 
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Page	 	
ARTICLE SEVEN LIMITATIONS	 	 	13	 	
 	 	 	 	 	 	 	 	 	
 	7.1	 	 	Limitation of Remedies, Liability and Damages	 	 	13	 	
 	 	 	 	 	 	 	 	 	
ARTICLE EIGHT CREDIT AND COLLATERAL REQUIREMENTS	 	 	14	 	
 	 	 	 	 	 	 	 	 	
 	8.1	 	 	Party A Credit Protection	 	 	14	 	
 	8.2	 	 	Party B Credit Protection	 	 	16	 	
 	8.3	 	 	Grant of Security Interest/Remedies	 	 	18	 	
 	 	 	 	 	 	 	 	 	
ARTICLE NINE GOVERNMENTAL CHARGES	 	 	19	 	
 	 	 	 	 	 	 	 	 	
 	9.1	 	 	Cooperation	 	 	19	 	
 	9.2	 	 	Governmental Charges	 	 	19	 	
 	 	 	 	 	 	 	 	 	
ARTICLE TEN MISCELLANEOUS	 	 	19	 	
 	 	 	 	 	 	 	 	 	
 	10.1	 	 	Term of Master Agreement	 	 	19	 	
 	10.2	 	 	Representations and Warranties	 	 	19	 	
 	10.3	 	 	Title and Risk of Loss	 	 	21	 	
 	10.4	 	 	Indemnity	 	 	21	 	
 	10.5	 	 	Assignment	 	 	21	 	
 	10.6	 	 	Governing Law	 	 	21	 	
 	10.7	 	 	Notices	 	 	21	 	
 	10.8	 	 	General	 	 	22	 	
 	10.9	 	 	Audit	 	 	22	 	
 	10.10	 	Forward Contract	 	 	22	 	
 	10.11	 	Confidentiality	 	 	23	 	
ii

 
GENERAL TERMS AND CONDITIONS
ARTICLE ONE
GENERAL DEFINITIONS
     1.1 “Affiliate” means, with respect to any person, any other person (other than an individual) that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with, such person. For this purpose, “control” means the direct or indirect ownership of fifty percent (50%) or more of the outstanding capital stock or other equity interests having ordinary voting power.
     1.2 “Agreement” has the meaning set forth in the Cover Sheet.
     1.3 “Bankrupt” means with respect to any entity, such entity (i) files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar law, or has any such petition filed or commenced against it, (ii) makes an assignment or any general arrangement for the benefit of creditors, (iii) otherwise becomes bankrupt or insolvent (however evidenced), (iv) has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with respect to it or any substantial portion of its property or assets, or (v) is generally unable to pay its debts as they fall due.
     1.4 “Business Day” means any day except a Saturday, Sunday, or a Federal Reserve Bank holiday. A Business Day shall open at 8:00 a.m. and close at 5:00 p.m. local time for the relevant Party’s principal place of business. The relevant Party, in each instance unless otherwise specified, shall be the Party from whom the notice, payment or delivery is being sent and by whom the notice or payment or delivery is to be received.
     1.5 “Buyer” means the Party to a Transaction that is obligated to purchase and receive, or cause to be received, the Product, as specified in the Transaction.
     1.6 “Call Option” means an Option entitling, but not obligating, the Option Buyer to purchase and receive the Product from the Option Seller at a price equal to the Strike Price for the Delivery Period for which the Option may be exercised, all as specified in the Transaction. Upon proper exercise of the Option by the Option Buyer, the Option Seller will be obligated to sell and deliver the Product for the Delivery Period for which the Option has been exercised.
     1.7 “Claiming Party” has the meaning set forth in Section 3.3.
     1.8 “Claims” means all third party claims or actions, threatened or filed and, whether groundless, false, fraudulent or otherwise, that directly or indirectly relate to the subject matter of an indemnity, and the resulting losses, damages, expenses, attorneys’ fees and court costs, whether incurred by settlement or otherwise, and whether such claims or actions are threatened or filed prior to or after the termination of this Agreement.
     1.9 “Confirmation” has the meaning set forth in Section 2.3.
1

 
     1.10 “Contract Price” means the price in $U.S. (unless otherwise provided for) to be paid by Buyer to Seller for the purchase of the Product, as specified in the Transaction.
     1.11 “Costs” means, with respect to the Non-Defaulting Party, brokerage fees, commissions and other similar third party transaction costs and expenses reasonably incurred by such Party either in terminating any arrangement pursuant to which it has hedged its obligations or entering into new arrangements which replace a Terminated Transaction; and all reasonable attorneys’ fees and expenses incurred by the Non-Defaulting Party in connection with the termination of a Transaction.
     1.12 “Credit Rating” means, with respect to any entity, the rating then assigned to such entity’s unsecured, senior long-term debt obligations (not supported by third party credit enhancements) or if such entity does not have a rating for its senior unsecured long-term debt, then the rating then assigned to such entity as an issues rating by S&P, Moody’s or any other rating agency agreed by the Parties as set forth in the Cover Sheet.
     1.13 “Cross Default Amount” means the cross default amount, if any, set forth in the Cover Sheet for a Party.
     1.14 “Defaulting Party” has the meaning set forth in Section 5.1.
     1.15 “Delivery Period” means the period of delivery for a Transaction, as specified in the Transaction.
     1.16 “Delivery Point” means the point at which the Product will be delivered and received, as specified in the Transaction.
     1.17 “Downgrade Event” has the meaning set forth on the Cover Sheet.
     1.18 “Early Termination Date” has the meaning set forth in Section 5.2.
     1.19 “Effective Date” has the meaning set forth on the Cover Sheet.
     1.20 “Equitable Defenses” means any bankruptcy, insolvency, reorganization and other laws affecting creditors’ rights generally, and with regard to equitable remedies, the discretion of the court before which proceedings to obtain same may be pending.
     1.21 “Event of Default” has the meaning set forth in Section 5.1.
     1.22 “FERC” means the Federal Energy Regulatory Commission or any successor government agency.
     1.23 “Force Majeure” means an event or circumstance which prevents one Party from performing its obligations under one or more Transactions, which event or circumstance was not anticipated as of the date the Transaction was agreed to, which is not within the reasonable control of, or the result of the negligence of, the Claiming Party, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided. Force Majeure shall not be based on (i) the loss of Buyer’s markets; (ii) Buyer’s inability economically
2

 
to use or resell the Product purchased hereunder; (iii) the loss or failure of Seller’s supply; or (iv) Seller’s ability to sell the Product at a price greater than the Contract Price. Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Product to be delivered to or received at the Delivery Point and (ii) such curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the Transmission Provider’s tariff; provided, however, that existence of the foregoing factors shall not be sufficient to conclusively or presumptively prove the existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in the first sentence hereof has occurred. The applicability of Force Majeure to the Transaction is governed by the terms of the Products and Related Definitions contained in Schedule P.
     1.24 “Gains” means, with respect to any Party, an amount equal to the present value of the economic benefit to it, if any (exclusive of Costs), resulting from the termination of a Terminated Transaction, determined in a commercially reasonable manner.
     1.25 “Guarantor” means, with respect to a Party, the guarantor, if any, specified for such Party on the Cover Sheet.
     1.26 “Interest Rate” means, for any date, the lesser of (a) the per annum rate of interest equal to the prime lending rate as may from time to time be published in  The Wall Street Journal  under “Money Rates” on such day (or if not published on such day on the most recent preceding day on which published), plus two percent (2%) and (b) the maximum rate permitted by applicable law.
     1.27 “Letter(s) of Credit” means one or more irrevocable, transferable standby letters of credit issued by a U.S. commercial bank or a foreign bank with a U.S. branch with such bank having a credit rating of at least A- from S&P or A3 from Moody’s, in a form acceptable to the Party in whose favor the letter of credit is issued. Costs of a Letter of Credit shall be borne by the applicant for such Letter of Credit.
     1.28 “Losses” means, with respect to any Party, an amount equal to the present value of the economic loss to it, if any (exclusive of Costs), resulting from termination of a Terminated Transaction, determined in a commercially reasonable manner.
     1.29 “Master Agreement” has the meaning set forth on the Cover Sheet.
     1.30 “Moody’s” means Moody’s Investor Services, Inc. or its successor.
     1.31 “NERC Business Day” means any day except a Saturday, Sunday or a holiday as defined by the North American Electric Reliability Council or any successor organization thereto. A NERC Business Day shall open at 8:00 a.m. and close at 5:00 p.m. local time for the relevant Party’s principal place of business. The relevant Party, in each instance unless otherwise specified, shall be the Party from whom the notice, payment or delivery is being sent and by whom the notice or payment or delivery is to be received.
     1.32 “Non-Defaulting Party” has the meaning set forth in Section 5.2.
3

 
     1.33 “Offsetting Transactions” mean any two or more outstanding Transactions, having the same or overlapping Delivery Period(s), Delivery Point and payment date, where under one or more of such Transactions, one Party is the Seller, and under the other such Transaction(s), the same Party is the Buyer.
     1.34 “Option” means the right but not the obligation to purchase or sell a Product as specified in a Transaction.
     1.35 “Option Buyer” means the Party specified in a Transaction as the purchaser of an option, as defined in Schedule P.
     1.36 “Option Seller” means the Party specified in a Transaction as the seller of an option , as defined in Schedule P.
     1.37 “Party A Collateral Threshold” means the collateral threshold, if any, set forth in the Cover Sheet for Party A.
     1.38 “Party B Collateral Threshold” means the collateral threshold, if any, set forth in the Cover Sheet for Party B.
     1.39 “Party A Independent Amount” means the amount , if any, set forth in the Cover Sheet for Party A.
     1.40 “Party B Independent Amount” means the amount , if any, set forth in the Cover Sheet for Party B.
     1.41 “Party A Rounding Amount” means the amount, if any, set forth in the Cover Sheet for Party A.
     1.42 “Party B Rounding Amount” means the amount, if any, set forth in the Cover Sheet for Party B.
     1.43 “Party A Tariff” means the tariff, if any, specified in the Cover Sheet for Party A.
     1.44 “Party B Tariff” means the tariff, if any, specified in the Cover Sheet for Party B.
     1.45 “Performance Assurance” means collateral in the form of either cash, Letter(s) of Credit, or other security acceptable to the Requesting Party.
     1.46 “Potential Event of Default” means an event which, with notice or passage of time or both, would constitute an Event of Default.
     1.47 “Product” means electric capacity, energy or other product(s) related thereto as specified in a Transaction by reference to a Product listed in Schedule P hereto or as otherwise specified by the Parties in the Transaction.
     1.48 “Put Option” means an Option entitling, but not obligating, the Option Buyer to sell and deliver the Product to the Option Seller at a price equal to the Strike Price for the
4

 
Delivery Period for which the option may be exercised, all as specified in a Transaction. Upon proper exercise of the Option by the Option Buyer, the Option Seller will be obligated to purchase and receive the Product.
     1.49 “Quantity” means that quantity of the Product that Seller agrees to make available or sell and deliver, or cause to be delivered, to Buyer, and that Buyer agrees to purchase and receive, or cause to be received, from Seller as specified in the Transaction.
     1.50 “Recording” has the meaning set forth in Section 2.4.
     1.51 “Replacement Price” means the price at which Buyer, acting in a commercially reasonable manner, purchases at the Delivery Point a replacement for any Product specified in a Transaction but not delivered by Seller, plus (i) costs reasonably incurred by Buyer in purchasing such substitute Product and (ii) additional transmission charges, if any, reasonably incurred by Buyer to the Delivery Point, or at Buyer’s option, the market price at the Delivery Point for such Product not delivered as determined by Buyer in a commercially reasonable manner; provided, however, in no event shall such price include any penalties, ratcheted demand or similar charges, nor shall Buyer be required to utilize or change its utilization of its owned or controlled assets or market positions to minimize Seller’s liability. For the purposes of this definition, Buyer shall be considered to have purchased replacement Product to the extent Buyer shall have entered into one or more arrangements in a commercially reasonable manner whereby Buyer repurchases its obligation to sell and deliver the Product to another party at the Delivery Point.
     1.52 “S&P” means the Standard & Poor’s Rating Group (a division of McGraw-Hill, Inc.) or its successor.
     1.53 “Sales Price” means the price at which Seller, acting in a commercially reasonable manner, resells at the Delivery Point any Product not received by Buyer, deducting from such proceeds any (i) costs reasonably incurred by Seller in reselling such Product and (ii) additional transmission charges, if any, reasonably incurred by Seller in delivering such Product to the third party purchasers, or at Seller’s option, the market price at the Delivery Point for such Product not received as determined by Seller in a commercially reasonable manner; provided, however, in no event shall such price include any penalties, ratcheted demand or similar charges, nor shall Seller be required to utilize or change its utilization of its owned or controlled assets, including contractual assets, or market positions to minimize Buyer’s liability. For purposes of this definition, Seller shall be considered to have resold such Product to the extent Seller shall have entered into one or more arrangements in a commercially reasonable manner whereby Seller repurchases its obligation to purchase and receive the Product from another party at the Delivery Point.
     1.54 “Schedule” or “Scheduling” means the actions of Seller, Buyer and/or their designated representatives, including each Party’s Transmission Providers, if applicable, of notifying, requesting and confirming to each other the quantity and type of Product to be delivered on any given day or days during the Delivery Period at a specified Delivery Point.
     1.55 “Seller” means the Party to a Transaction that is obligated to sell and deliver, or cause to be delivered, the Product, as specified in the Transaction.
5

 
     1.56 “Settlement Amount” means, with respect to a Transaction and the Non-Defaulting Party, the Losses or Gains, and Costs, expressed in U.S. Dollars, which such party incurs as a result of the liquidation of a Terminated Transaction pursuant to Section 5.2.
     1.57 “Strike Price” means the price to be paid for the purchase of the Product pursuant to an Option.
     1.58 “Terminated Transaction” has the meaning set forth in Section 5.2.
     1.59 “Termination Payment” has the meaning set forth in Section 5.3.
     1.60 “Transaction” means a particular transaction agreed to by the Parties relating to the sale and purchase of a Product pursuant to this Master Agreement.
     1.61 “Transmission Provider” means any entity or entities transmitting or transporting the Product on behalf of Seller or Buyer to or from the Delivery Point in a particular Transaction.
ARTICLE TWO
TRANSACTION TERMS AND CONDITIONS
     2.1 Transactions. A Transaction shall be entered into upon agreement of the Parties orally or, if expressly required by either Party with respect to a particular Transaction, in writing, including an electronic means of communication. Each Party agrees not to contest, or assert any defense to, the validity or enforceability of the Transaction entered into in accordance with this Master Agreement (i) based on any law requiring agreements to be in writing or to be signed by the parties, or (ii) based on any lack of authority of the Party or any lack of authority of any employee of the Party to enter into a Transaction.
     2.2 Governing Terms. Unless otherwise specifically agreed, each Transaction between the Parties shall be governed by this Master Agreement. This Master Agreement (including all exhibits, schedules and any written supplements hereto), , the Party A Tariff, if any, and the Party B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any Confirmations accepted in accordance with Section 2.3) shall form a single integrated agreement between the Parties. Any inconsistency between any terms of this Master Agreement and any terms of the Transaction shall be resolved in favor of the terms of such Transaction.
     2.3 Confirmation. Seller may confirm a Transaction by forwarding to Buyer by facsimile within three (3) Business Days after the Transaction is entered into a confirmation (“Confirmation”) substantially in the form of Exhibit A. If Buyer objects to any term(s) of such Confirmation, Buyer shall notify Seller in writing of such objections within two (2) Business Days of Buyer’s receipt thereof, failing which Buyer shall be deemed to have accepted the terms as sent. If Seller fails to send a Confirmation within three (3) Business Days after the Transaction is entered into, a Confirmation substantially in the form of Exhibit A, may be forwarded by Buyer to Seller. If Seller objects to any term(s) of such Confirmation, Seller shall notify Buyer of such objections within two (2) Business Days of Seller’s receipt thereof, failing which Seller shall be deemed to have accepted the terms as sent. If Seller and Buyer each send a
6

 
Confirmation and neither Party objects to the other Party’s Confirmation within two (2) Business Days of receipt, Seller’s Confirmation shall be deemed to be accepted and shall be the controlling Confirmation, unless (i) Seller’s Confirmation was sent more than three (3) Business Days after the Transaction was entered into and (ii) Buyer’s Confirmation was sent prior to Seller’s Confirmation, in which case Buyer’s Confirmation shall be deemed to be accepted and shall be the controlling Confirmation. Failure by either Party to send or either Party to return an executed Confirmation or any objection by either Party shall not invalidate the Transaction agreed to by the Parties.
     2.4 Additional Confirmation Terms. If the Parties have elected on the Cover Sheet to make this Section 2.4 applicable to this Master Agreement, when a Confirmation contains provisions, other than those provisions relating to the commercial terms of the Transaction (e.g., price or special transmission conditions), which modify or supplement the general terms and conditions of this Master Agreement (e.g., arbitration provisions or additional representations and warranties), such provisions shall not be deemed to be accepted pursuant to Section 2.3 unless agreed to either orally or in writing by the Parties; provided that the foregoing shall not invalidate any Transaction agreed to by the Parties.
     2.5 Recording. Unless a Party expressly objects to a Recording (defined below) at the beginning of a telephone conversation, each Party consents to the creation of a tape or electronic recording (“Recording”) of all telephone conversations between the Parties to this Master Agreement, and that any such Recordings will be retained in confidence, secured from improper access, and may be submitted in evidence in any proceeding or action relating to this Agreement. Each Party waives any further notice of such monitoring or recording, and agrees to notify its officers and employees of such monitoring or recording and to obtain any necessary consent of such officers and employees. The Recording, and the terms and conditions described therein, if admissible, shall be the controlling evidence for the Parties’ agreement with respect to a particular Transaction in the event a Confirmation is not fully executed (or deemed accepted) by both Parties. Upon full execution (or deemed acceptance) of a Confirmation, such Confirmation shall control in the event of any conflict with the terms of a Recording, or in the event of any conflict with the terms of this Master Agreement.
ARTICLE THREE
OBLIGATIONS AND DELIVERIES
     3.1 Seller’s and Buyer’s Obligations. With respect to each Transaction, Seller shall sell and deliver, or cause to be delivered, and Buyer shall purchase and receive, or cause to be received, the Quantity of the Product at the Delivery Point, and Buyer shall pay Seller the Contract Price; provided, however, with respect to Options, the obligations set forth in the preceding sentence shall only arise if the Option Buyer exercises its Option in accordance with its terms. Seller shall be responsible for any costs or charges imposed on or associated with the Product or its delivery of the Product up to the Delivery Point. Buyer shall be responsible for any costs or charges imposed on or associated with the Product or its receipt at and from the Delivery Point.
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     3.2 Transmission and Scheduling. Seller shall arrange and be responsible for transmission service to the Delivery Point and shall Schedule or arrange for Scheduling services with its Transmission Providers, as specified by the Parties in the Transaction, or in the absence thereof, in accordance with the practice of the Transmission Providers, to deliver the Product to the Delivery Point. Buyer shall arrange and be responsible for transmission service at and from the Delivery Point and shall Schedule or arrange for Scheduling services with its Transmission Providers to receive the Product at the Delivery Point.
     3.3 Force Majeure. To the extent either Party is prevented by Force Majeure from carrying out, in whole or part, its obligations under the Transaction and such Party (the “Claiming Party”) gives notice and details of the Force Majeure to the other Party as soon as practicable, then, unless the terms of the Product specify otherwise, the Claiming Party shall be excused from the performance of its obligations with respect to such Transaction (other than the obligation to make payments then due or becoming due with respect to performance prior to the Force Majeure). The Claiming Party shall remedy the Force Majeure with all reasonable dispatch. The non-Claiming Party shall not be required to perform or resume performance of its obligations to the Claiming Party corresponding to the obligations of the Claiming Party excused by Force Majeure.
ARTICLE FOUR
REMEDIES FOR FAILURE TO DELIVER/RECEIVE
     4.1 Seller Failure. If Seller fails to schedule and/or deliver all or part of the Product pursuant to a Transaction, and such failure is not excused under the terms of the Product or by Buyer’s failure to perform, then Seller shall pay Buyer, on the date payment would otherwise be due in respect of the month in which the failure occurred or, if “Accelerated Payment of Damages” is specified on the Cover Sheet, within five (5) Business Days of invoice receipt, an amount for such deficiency equal to the positive difference, if any, obtained by subtracting the Contract Price from the Replacement Price. The invoice for such amount shall include a written statement explaining in reasonable detail the calculation of such amount.
     4.2 Buyer Failure. If Buyer fails to schedule and/or receive all or part of the Product pursuant to a Transaction and such failure is not excused under the terms of the Product or by Seller’s failure to perform, then Buyer shall pay Seller, on the date payment would otherwise be due in respect of the month in which the failure occurred or, if “Accelerated Payment of Damages” is specified on the Cover Sheet, within five (5) Business Days of invoice receipt, an amount for such deficiency equal to the positive difference, if any, obtained by subtracting the Sales Price from the Contract Price. The invoice for such amount shall include a written statement explaining in reasonable detail the calculation of such amount.
ARTICLE FIVE
EVENTS OF DEFAULT; REMEDIES
     5.1 Events of Default. An “Event of Default” shall mean, with respect to a Party (a “Defaulting Party”), the occurrence of any of the following:
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 	(a)	 	the failure to make, when due, any payment required pursuant to this Agreement if such failure is not remedied within three (3) Business Days after written notice;	
 	 	 	 	
 	(b)	 	any representation or warranty made by such Party herein is false or misleading in any material respect when made or when deemed made or repeated;	
 	 	 	 	
 	(c)	 	the failure to perform any material covenant or obligation set forth in this Agreement (except to the extent constituting a separate Event of Default, and except for such Party’s obligations to deliver or receive the Product, the exclusive remedy for which is provided in Article Four) if such failure is not remedied within three (3) Business Days after written notice;	
 	 	 	 	
 	(d)	 	such Party becomes Bankrupt;	
 	 	 	 	
 	(e)	 	the failure of such Party to satisfy the creditworthiness/collateral requirements agreed to pursuant to Article Eight hereof;	
 	 	 	 	
 	(f)	 	such Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all the obligations of such Party under this Agreement to which it or its predecessor was a party by operation of law or pursuant to an agreement reasonably satisfactory to the other Party;	
 	 	 	 	
 	(g)	 	if the applicable cross default section in the Cover Sheet is indicated for such Party, the occurrence and continuation of (i) a default, event of default or other similar condition or event in respect of such Party or any other party specified in the Cover Sheet for such Party under one or more agreements or instruments, individually or collectively, relating to indebtedness for borrowed money in an aggregate amount of not less than the applicable Cross Default Amount (as specified in the Cover Sheet), which results in such indebtedness becoming, or becoming capable at such time of being declared, immediately due and payable or (ii) a default by such Party or any other party specified in the Cover Sheet for such Party in making on the due date therefor one or more payments, individually or collectively, in an aggregate amount of not less than the applicable Cross Default Amount (as specified in the Cover Sheet);	
 	 	 	 	
 	(h)	 	with respect to such Party’s Guarantor, if any:	

 	(i)	 	if any representation or warranty made by a Guarantor in connection with this Agreement is false or misleading in any material respect when made or when deemed made or repeated;	
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 	(ii)	 	the failure of a Guarantor to make any payment required or to perform any other material covenant or obligation in any guaranty made in connection with this Agreement and such failure shall not be remedied within three (3) Business Days after written notice;	
 	 	 	 	
 	(iii)	 	a Guarantor becomes Bankrupt;	
 	 	 	 	
 	(iv)	 	the failure of a Guarantor’s guaranty to be in full force and effect for purposes of this Agreement (other than in accordance with its terms) prior to the satisfaction of all obligations of such Party under each Transaction to which such guaranty shall relate without the written consent of the other Party; or	
 	 	 	 	
 	(v)	 	a Guarantor shall repudiate, disaffirm, disclaim, or reject, in whole or in part, or challenge the validity of any guaranty.	
     5.2 Declaration of an Early Termination Date and Calculation of Settlement Amounts. If an Event of Default with respect to a Defaulting Party shall have occurred and be continuing, the other Party (the “Non-Defaulting Party”) shall have the right (i) to designate a day, no earlier than the day such notice is effective and no later than 20 days after such notice is effective, as an early termination date (“Early Termination Date”) to accelerate all amounts owing between the Parties and to liquidate and terminate all, but not less than all, Transactions (each referred to as a “Terminated Transaction”) between the Parties, (ii) withhold any payments due to the Defaulting Party under this Agreement and (iii) suspend performance. The Non-Defaulting Party shall calculate, in a commercially reasonable manner, a Settlement Amount for each such Terminated Transaction as of the Early Termination Date (or, to the extent that in the reasonable opinion of the Non-Defaulting Party certain of such Terminated Transactions are commercially impracticable to liquidate and terminate or may not be liquidated and terminated under applicable law on the Early Termination Date, as soon thereafter as is reasonably practicable).
     5.3 Net Out of Settlement Amounts. The Non-Defaulting Party shall aggregate all Settlement Amounts into a single amount by: netting out (a) all Settlement Amounts that are due to the Defaulting Party, plus, at the option of the Non-Defaulting Party, any cash or other form of security then available to the Non-Defaulting Party pursuant to Article Eight, plus any or all other amounts due to the Defaulting Party under this Agreement against (b) all Settlement Amounts that are due to the Non-Defaulting Party, plus any or all other amounts due to the Non-Defaulting Party under this Agreement, so that all such amounts shall be netted out to a single liquidated amount (the “Termination Payment”) payable by one Party to the other. The Termination Payment shall be due to or due from the Non-Defaulting Party as appropriate.
     5.4 Notice of Payment of Termination Payment. As soon as practicable after a liquidation, notice shall be given by the Non-Defaulting Party to the Defaulting Party of the amount of the Termination Payment and whether the Termination Payment is due to or due from the Non-Defaulting Party. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. The Termination Payment shall be made by the Party that owes it within two (2) Business Days after such notice is effective.
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     5.5 Disputes With Respect to Termination Payment. If the Defaulting Party disputes the Non-Defaulting Party’s calculation of the Termination Payment, in whole or in part, the Defaulting Party shall, within two (2) Business Days of receipt of Non-Defaulting Party’s calculation of the Termination Payment, provide to the Non-Defaulting Party a detailed written explanation of the basis for such dispute; provided, however, that if the Termination Payment is due from the Defaulting Party, the Defaulting Party shall first transfer Performance Assurance to the Non-Defaulting Party in an amount equal to the Termination Payment.
     5.6 Closeout Setoffs.
     Option A: After calculation of a Termination Payment in accordance with Section 5.3, if the Defaulting Party would be owed the Termination Payment, the Non-Defaulting Party shall be entitled, at its option and in its discretion, to (i) set off against such Termination Payment any amounts due and owing by the Defaulting Party to the Non-Defaulting Party under any other agreements, instruments or undertakings between the Defaulting Party and the Non-Defaulting Party and/or (ii) to the extent the Transactions are not yet liquidated in accordance with Section 5.2, withhold payment of the Termination Payment to the Defaulting Party. The remedy provided for in this Section shall be without prejudice and in addition to any right of setoff, combination of accounts, lien or other right to which any Party is at any time otherwise entitled (whether by operation of law, contract or otherwise).
     Option B: After calculation of a Termination Payment in accordance with Section 5.3, if the Defaulting Party would be owed the Termination Payment, the Non-Defaulting Party shall be entitled, at its option and in its discretion, to (i) set off against such Termination Payment any amounts due and owing by the Defaulting Party or any of its Affiliates to the Non-Defaulting Party or any of its Affiliates under any other agreements, instruments or undertakings between the Defaulting Party or any of its Affiliates and the Non-Defaulting Party or any of its Affiliates and/or (ii) to the extent the Transactions are not yet liquidated in accordance with Section 5.2, withhold payment of the Termination Payment to the Defaulting Party. The remedy provided for in this Section shall be without prejudice and in addition to any right of setoff, combination of accounts, lien or other right to which any Party is at any time otherwise entitled (whether by operation of law, contract or otherwise).
     Option C: Neither Option A nor B shall apply.
     5.7 Suspension of Performance. Notwithstanding any other provision of this Master Agreement, if (a) an Event of Default or (b) a Potential Event of Default shall have occurred and be continuing, the Non-Defaulting Party, upon written notice to the Defaulting Party, shall have the right (i) to suspend performance under any or all Transactions; provided, however, in no event shall any such suspension continue for longer than ten (10) NERC Business Days with respect to any single Transaction unless an early Termination Date shall have been declared and notice thereof pursuant to Section 5.2 given, and (ii) to the extent an Event of Default shall have occurred and be continuing to exercise any remedy available at law or in equity.
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ARTICLE SIX
PAYMENT AND NETTING
     6.1 Billing Period. Unless otherwise specifically agreed upon by the Parties in a Transaction, the calendar month shall be the standard period for all payments under this Agreement (other than Termination Payments and, if “Accelerated Payment of Damages” is specified by the Parties in the Cover Sheet, payments pursuant to Section 4.1 or 4.2 and Option premium payments pursuant to Section 6.7). As soon as practicable after the end of each month, each Party will render to the other Party an invoice for the payment obligations, if any, incurred hereunder during the preceding month.
     6.2 Timeliness of Payment. Unless otherwise agreed by the Parties in a Transaction, all invoices under this Master Agreement shall be due and payable in accordance with each Party’s invoice instructions on or before the later of the twentieth (20th) day of each month, or tenth (10th) day after receipt of the invoice or, if such day is not a Business Day, then on the next Business Day. Each Party will make payments by electronic funds transfer, or by other mutually agreeable method(s), to the account designated by the other Party. Any amounts not paid by the due date will be deemed delinquent and will accrue interest at the Interest Rate, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full.
     6.3 Disputes and Adjustments of Invoices. A Party may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice, rendered under this Agreement or adjust any invoice for any arithmetic or computational error within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, payment of the undisputed portion of the invoice shall be required to be made when due, with notice of the objection given to the other Party. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within two (2) Business Days of such resolution along with interest accrued at the Interest Rate from and including the due date to but excluding the date paid. Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment. Any dispute with respect to an invoice is waived unless the other Party is notified in accordance with this Section 6.3 within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the month during which performance of a Transaction occurred, the right to payment for such performance is waived.
     6.4 Netting of Payments. The Parties hereby agree that they shall discharge mutual debts and payment obligations due and owing to each other on the same date pursuant to all Transactions through netting, in which case all amounts owed by each Party to the other Party for the purchase and sale of Products during the monthly billing period under this Master Agreement, including any related damages calculated pursuant to Article Four (unless one of the
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Parties elects to accelerate payment of such amounts as permitted by Article Four), interest, and payments or credits, shall be netted so that only the excess amount remaining due shall be paid by the Party who owes it.
     6.5 Payment Obligation Absent Netting. If no mutual debts or payment obligations exist and only one Party owes a debt or obligation to the other during the monthly billing period, including, but not limited to, any related damage amounts calculated pursuant to Article Four, interest, and payments or credits, that Party shall pay such sum in full when due.
     6.6 Security. Unless the Party benefiting from Performance Assurance or a guaranty notifies the other Party in writing, and except in connection with a liquidation and termination in accordance with Article Five, all amounts netted pursuant to this Article Six shall not take into account or include any Performance Assurance or guaranty which may be in effect to secure a Party’s performance under this Agreement.
     6.7 Payment for Options. The premium amount for the purchase of an Option shall be paid within two (2) Business Days of receipt of an invoice from the Option Seller. Upon exercise of an Option, payment for the Product underlying such Option shall be due in accordance with Section 6.1.
     6.8 Transaction Netting. If the Parties enter into one or more Transactions, which in conjunction with one or more other outstanding Transactions, constitute Offsetting Transactions, then all such Offsetting Transactions may by agreement of the Parties, be netted into a single Transaction under which:
 	(a)	 	the Party obligated to deliver the greater amount of Energy will deliver the difference between the total amount it is obligated to deliver and the total amount to be delivered to it under the Offsetting Transactions, and	
 	 	 	 	
 	(b)	 	the Party owing the greater aggregate payment will pay the net difference owed between the Parties.	
Each single Transaction resulting under this Section shall be deemed part of the single, indivisible contractual arrangement between the parties, and once such resulting Transaction occurs, outstanding obligations under the Offsetting Transactions which are satisfied by such offset shall terminate.
ARTICLE SEVEN
LIMITATIONS
     7.1 Limitation of Remedies, Liability and Damages. EXCEPT AS SET FORTH HEREIN, THERE IS NO WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE
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REMEDY, THE OBLIGOR’S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN OR IN A TRANSACTION, THE OBLIGOR’S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.
ARTICLE EIGHT
CREDIT AND COLLATERAL REQUIREMENTS
     8.1 Party A Credit Protection. The applicable credit and collateral requirements shall be as specified on the Cover Sheet. If no option in Section 8.1(a) is specified on the Cover Sheet, Section 8.l(a) Option C shall apply exclusively. If none of Sections 8.1(b), 8.1(c) or 8.1(d) are specified on the Cover Sheet, Section 8.1(b) shall apply exclusively.
 	(a)	 	Financial Information. Option A: If requested by Party A, Party B shall deliver (i) within 120 days following the end of each fiscal year, a copy of Party B’s annual report containing audited consolidated financial statements for such fiscal year and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of Party B’s quarterly report containing unaudited consolidated financial statements for such fiscal quarter. In all cases the statements shall be for the most recent accounting period and prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as Party B diligently pursues the preparation, certification and delivery of the statements.	
     Option B: If requested by Party A, Party B shall deliver (i) within 120 days following the end of each fiscal year, a copy of the annual report containing audited consolidated financial
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statements for such fiscal year for the party(s) specified on the Cover Sheet and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of quarterly report containing unaudited consolidated financial statements for such fiscal quarter for the party(s) specified on the Cover Sheet. In all cases the statements shall be for the most recent accounting period and shall be prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as the relevant entity diligently pursues the preparation, certification and delivery of the statements.
     Option C: Party A may request from Party B the information specified in the Cover Sheet.
 	(b)	 	Credit Assurances. If Party A has reasonable grounds to believe that Party B’s creditworthiness or performance under this Agreement has become unsatisfactory, Party A will provide Party B with written notice requesting Performance Assurance in an amount determined by Party A in a commercially reasonable manner. Upon receipt of such notice Party B shall have three (3) Business Days to remedy the situation by providing such Performance Assurance to Party A. In the event that Party B fails to provide such Performance Assurance, or a guaranty or other credit assurance acceptable to Party A within three (3) Business Days of receipt of notice, then an Event of Default under Article Five will be deemed to have occurred and Party A will be entitled to the remedies set forth in Article Five of this Master Agreement.	
 	 	 	 	
 	(c)	 	Collateral Threshold. If at any time and from time to time during the term of this Agreement (and notwithstanding whether an Event of Default has occurred), the Termination Payment that would be owed to Party A plus Party B’s Independent Amount, if any, exceeds the Party B Collateral Threshold, then Party A, on any Business Day, may request that Party B provide Performance Assurance in an amount equal to the amount by which the Termination Payment plus Party B’s Independent Amount, if any, exceeds the Party B Collateral Threshold (rounding upwards for any fractional amount to the next Party B Rounding Amount) (“Party B Performance Assurance”), less any Party B Performance Assurance already posted with Party A. Such Party B Performance Assurance shall be delivered to Party A within three (3) Business Days of the date of such request. On any Business Day (but no more frequently than weekly with respect to Letters of Credit and daily with respect to cash), Party B, at its sole cost, may request that such Party B Performance Assurance be reduced correspondingly to the amount of such excess Termination Payment plus Party B’s Independent Amount, if any, (rounding upwards for any fractional amount to the next Party B Rounding Amount). In the event that Party B fails to provide Party B Performance Assurance pursuant to the terms of this Article Eight within three (3) Business Days, then an Event of Default under Article Five shall be deemed to have	
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 	 	 	occurred and Party A will be entitled to the remedies set forth in Article Five of this Master Agreement.	
     For purposes of this Section 8.1(c), the calculation of the Termination Payment shall be calculated pursuant to Section 5.3 by Party A as if all outstanding Transactions had been liquidated, and in addition thereto, shall include all amounts owed but not yet paid by Party B to Party A, whether or not such amounts are due, for performance already provided pursuant to any and all Transactions.
 	(d)	 	Downgrade Event. If at any time there shall occur a Downgrade Event in respect of Party B, then Party A may require Party B to provide Performance Assurance in an amount determined by Party A in a commercially reasonable manner. In the event Party B shall fail to provide such Performance Assurance or a guaranty or other credit assurance acceptable to Party A within three (3) Business Days of receipt of notice, then an Event of Default shall be deemed to have occurred and Party A will be entitled to the remedies set forth in Article Five of this Master Agreement.	
 	 	 	 	
 	(e)	 	If specified on the Cover Sheet, Party B shall deliver to Party A, prior to or concurrently with the execution and delivery of this Master Agreement a guarantee in an amount not less than the Guarantee Amount specified on the Cover Sheet and in a form reasonably acceptable to Party A.	
     8.2 Party B Credit Protection. The applicable credit and collateral requirements shall be as specified on the Cover Sheet. If no option in Section 8.2(a) is specified on the Cover Sheet, Section 8.2(a) Option C shall apply exclusively. If none of Sections 8.2(b), 8.2(c) or 8.2(d) are specified on the Cover Sheet, Section 8.2(b) shall apply exclusively.
 	(a)	 	Financial Information. Option A: If requested by Party B, Party A shall deliver (i) within 120 days following the end of each fiscal year, a copy of Party A’s annual report containing audited consolidated financial statements for such fiscal year and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of such Party’s quarterly report containing unaudited consolidated financial statements for such fiscal quarter. In all cases the statements shall be for the most recent accounting period and prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as such Party diligently pursues the preparation, certification and delivery of the statements.	
     Option B: If requested by Party B, Party A shall deliver (i) within 120 days following the end of each fiscal year, a copy of the annual report containing audited consolidated financial statements for such fiscal year for the party(s) specified on the Cover Sheet and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of quarterly
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report containing unaudited consolidated financial statements for such fiscal quarter for the party(s) specified on the Cover Sheet. In all cases the statements shall be for the most recent accounting period and shall be prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as the relevant entity diligently pursues the preparation, certification and delivery of the statements.
     Option C: Party B may request from Party A the information specified in the Cover Sheet.
 	(b)	 	Credit Assurances. If Party B has reasonable grounds to believe that Party A’s creditworthiness or performance under this Agreement has become unsatisfactory, Party B will provide Party A with written notice requesting Performance Assurance in an amount determined by Party B in a commercially reasonable manner. Upon receipt of such notice Party A shall have three (3) Business Days to remedy the situation by providing such Performance Assurance to Party B. In the event that Party A fails to provide such Performance Assurance, or a guaranty or other credit assurance acceptable to Party B within three (3) Business Days of receipt of notice, then an Event of Default under Article Five will be deemed to have occurred and Party B will be entitled to the remedies set forth in Article Five of this Master Agreement.	
 	 	 	 	
 	(c)	 	Collateral Threshold. If at any time and from time to time during the term of this Agreement (and notwithstanding whether an Event of Default has occurred), the Termination Payment that would be owed to Party B plus Party A’s Independent Amount, if any, exceeds the Party A Collateral Threshold, then Party B, on any Business Day, may request that Party A provide Performance Assurance in an amount equal to the amount by which the Termination Payment plus Party A’s Independent Amount, if any, exceeds the Party A Collateral Threshold (rounding upwards for any fractional amount to the next Party A Rounding Amount) (“Party A Performance Assurance”), less any Party A Performance Assurance already posted with Party B. Such Party A Performance Assurance shall be delivered to Party B within three (3) Business Days of the date of such request. On any Business Day (but no more frequently than weekly with respect to Letters of Credit and daily with respect to cash), Party A, at its sole cost, may request that such Party A Performance Assurance be reduced correspondingly to the amount of such excess Termination Payment plus Party A’s Independent Amount, if any, (rounding upwards for any fractional amount to the next Party A Rounding Amount). In the event that Party A fails to provide Party A Performance Assurance pursuant to the terms of this Article Eight within three (3) Business Days, then an Event of Default under Article Five shall be deemed to have occurred and Party B will be entitled to the remedies set forth in Article Five of this Master Agreement.	
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     For purposes of this Section 8.2(c), the calculation of the Termination Payment shall be calculated pursuant to Section 5.3 by Party B as if all outstanding Transactions had been liquidated, and in addition thereto, shall include all amounts owed but not yet paid by Party A to Party B, whether or not such amounts are due, for performance already provided pursuant to any and all Transactions.
 	(d)	 	Downgrade Event. If at any time there shall occur a Downgrade Event in respect of Party A, then Party B may require Party A to provide Performance Assurance in an amount determined by Party B in a commercially reasonable manner. In the event Party A shall fail to provide such Performance Assurance or a guaranty or other credit assurance acceptable to Party B within three (3) Business Days of receipt of notice, then an Event of Default shall be deemed to have occurred and Party B will be entitled to the remedies set forth in Article Five of this Master Agreement.	
 	 	 	 	
 	(e)	 	If specified on the Cover Sheet, Party A shall deliver to Party B, prior to or concurrently with the execution and delivery of this Master Agreement a guarantee in an amount not less than the Guarantee Amount specified on the Cover Sheet and in a form reasonably acceptable to Party B.	
     8.3 Grant of Security Interest/Remedies. To secure its obligations under this Agreement and to the extent either or both Parties deliver Performance Assurance hereunder, each Party (a “Pledgor”) hereby grants to the other Party (the “Secured Party”) a present and continuing security interest in, and lien on (and right of setoff against), and assignment of, all cash collateral and cash equivalent collateral and any and all proceeds resulting therefrom or the liquidation thereof, whether now or hereafter held by, on behalf of, or for the benefit of, such Secured Party, and each Party agrees to take such action as the other Party reasonably requires in order to perfect the Secured Party’s first-priority security interest in, and lien on (and right of setoff against), such collateral and any and all proceeds resulting therefrom or from the liquidation thereof. Upon or any time after the occurrence or deemed occurrence and during the continuation of an Event of Default or an Early Termination Date, the Non-Defaulting Party may do any one or more of the following: (i) exercise any of the rights and remedies of a Secured Party with respect to all Performance Assurance, including any such rights and remedies under law then in effect; (ii) exercise its rights of setoff against any and all property of the Defaulting Party in the possession of the Non-Defaulting Party or its agent; (iii) draw on any outstanding Letter of Credit issued for its benefit; and (iv) liquidate all Performance Assurance then held by or for the benefit of the Secured Party free from any claim or right of any nature whatsoever of the Defaulting Party, including any equity or right of purchase or redemption by the Defaulting Party. The Secured Party shall apply the proceeds of the collateral realized upon the exercise of any such rights or remedies to reduce the Pledgor’s obligations under the Agreement (the Pledgor remaining liable for any amounts owing to the Secured Party after such application), subject to the Secured Party’s obligation to return any surplus proceeds remaining after such obligations are satisfied in full.
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ARTICLE NINE
GOVERNMENTAL CHARGES
     9.1 Cooperation. Each Party shall use reasonable efforts to implement the provisions of and to administer this Master Agreement in accordance with the intent of the parties to minimize all taxes, so long as neither Party is materially adversely affected by such efforts.
     9.2 Governmental Charges. Seller shall pay or cause to be paid all taxes imposed by any government authority(“Governmental Charges”) on or with respect to the Product or a Transaction arising prior to the Delivery Point. Buyer shall pay or cause to be paid all Governmental Charges on or with respect to the Product or a Transaction at and from the Delivery Point (other than ad valorem, franchise or income taxes which are related to the sale of the Product and are, therefore, the responsibility of the Seller). In the event Seller is required by law or regulation to remit or pay Governmental Charges which are Buyer’s responsibility hereunder, Buyer shall promptly reimburse Seller for such Governmental Charges. If Buyer is required by law or regulation to remit or pay Governmental Charges which are Seller’s responsibility hereunder, Buyer may deduct the amount of any such Governmental Charges from the sums due to Seller under Article 6 of this Agreement. Nothing shall obligate or cause a Party to pay or be liable to pay any Governmental Charges for which it is exempt under the law.
ARTICLE TEN
MISCELLANEOUS
     10.1 Term of Master Agreement. The term of this Master Agreement shall commence on the Effective Date and shall remain in effect until terminated by either Party upon (thirty) 30 days’ prior written notice; provided, however, that such termination shall not affect or excuse the performance of either Party under any provision of this Master Agreement that by its terms survives any such termination and, provided further, that this Master Agreement and any other documents executed and delivered hereunder shall remain in effect with respect to the Transaction(s) entered into prior to the effective date of such termination until both Parties have fulfilled all of their obligations with respect to such Transaction(s), or such Transaction(s) that have been terminated under Section 5.2 of this Agreement.
     10.2 Representations and Warranties. On the Effective Date and the date of entering into each Transaction, each Party represents and warrants to the other Party that:
 	(a)	 	it is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation;	
 	 	 	 	
 	(b)	 	it has all regulatory authorizations necessary for it to legally perform its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);	
 	 	 	 	
 	(c)	 	the execution, delivery and performance of this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) are within its powers, have been duly authorized by all	
19

 
 	 	 	necessary action and do not violate any of the terms and conditions in its governing documents, any contracts to which it is a party or any law, rule, regulation, order or the like applicable to it;	

 	(d)	 	this Master Agreement, each Transaction (including any Confirmation accepted in accordance with Section 2.3), and each other document executed and delivered in accordance with this Master Agreement constitutes its legally valid and binding obligation enforceable against it in accordance with its terms; subject to any Equitable Defenses.	
 	 	 	 	
 	(e)	 	it is not Bankrupt and there are no proceedings pending or being contemplated by it or, to its knowledge, threatened against it which would result in it being or becoming Bankrupt;	
 	 	 	 	
 	(f)	 	there is not pending or, to its knowledge, threatened against it or any of its Affiliates any legal proceedings that could materially adversely affect its ability to perform its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);	
 	 	 	 	
 	(g)	 	no Event of Default or Potential Event of Default with respect to it has occurred and is continuing and no such event or circumstance would occur as a result of its entering into or performing its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);	
 	 	 	 	
 	(h)	 	it is acting for its own account, has made its own independent decision to enter into this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) and as to whether this Master Agreement and each such Transaction (including any Confirmation accepted in accordance with Section 2.3) is appropriate or proper for it based upon its own judgment, is not relying upon the advice or recommendations of the other Party in so doing, and is capable of assessing the merits of and understanding, and understands and accepts, the terms, conditions and risks of this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);	
 	 	 	 	
 	(i)	 	it is a “forward contract merchant” within the meaning of the United States Bankruptcy Code;	
 	 	 	 	
 	(j)	 	it has entered into this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) in connection with the conduct of its business and it has the capacity or ability to make or take delivery of all Products referred to in the Transaction to which it is a Party;	
20

 

 	(k)	 	with respect to each Transaction (including any Confirmation accepted in accordance with Section 2.3) involving the purchase or sale of a Product or an Option, it is a producer, processor, commercial user or merchant handling the Product, and it is entering into such Transaction for purposes related to its business as such; and	
 	 	 	 	
 	(l)	 	the material economic terms of each Transaction are subject to individual negotiation by the Parties.	
     10.3 Title and Risk of Loss. Title to and risk of loss related to the Product shall transfer from Seller to Buyer at the Delivery Point. Seller warrants that it will deliver to Buyer the Quantity of the Product free and clear of all liens, security interests, claims and encumbrances or any interest therein or thereto by any person arising prior to the Delivery Point.
     10.4 Indemnity. Each Party shall indemnify, defend and hold harmless the other Party from and against any Claims arising from or out of any event, circumstance, act or incident first occurring or existing during the period when control and title to Product is vested in such Party as provided in Section 10.3. Each Party shall indemnify, defend and hold harmless the other Party against any Governmental Charges for which such Party is responsible under Article Nine.
     10.5 Assignment. Neither Party shall assign this Agreement or its rights hereunder without the prior written consent of the other Party, which consent may be withheld in the exercise of its sole discretion; provided, however, either Party may, without the consent of the other Party (and without relieving itself from liability hereunder), (i) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements, (ii) transfer or assign this Agreement to an affiliate of such Party which affiliate’s creditworthiness is equal to or higher than that of such Party, or (iii) transfer or assign this Agreement to any person or entity succeeding to all or substantially all of the assets whose creditworthiness is equal to or higher than that of such Party; provided, however, that in each such case, any such assignee shall agree in writing to be bound by the terms and conditions hereof and so long as the transferring Party delivers such tax and enforceability assurance as the non-transferring Party may reasonably request.
     10.6 Governing Law. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY LITIGATION ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT.
     10.7 Notices. All notices, requests, statements or payments shall be made as specified in the Cover Sheet. Notices (other than scheduling requests) shall, unless otherwise specified herein, be in writing and may be delivered by hand delivery, United States mail, overnight courier service or facsimile. Notice by facsimile or hand delivery shall be effective at the close of business on the day actually received, if received during business hours on a Business Day, and otherwise shall be effective at the close of business on the next Business Day. Notice by
21

 
overnight United States mail or courier shall be effective on the next Business Day after it was sent. A Party may change its addresses by providing notice of same in accordance herewith.
     10.8 General. This Master Agreement (including the exhibits, schedules and any written supplements hereto), the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any Confirmation accepted in accordance with Section 2.3) constitute the entire agreement between the Parties relating to the subject matter. Notwithstanding the foregoing, any collateral, credit support or margin agreement or similar arrangement between the Parties shall, upon designation by the Parties, be deemed part of this Agreement and shall be incorporated herein by reference. This Agreement shall be considered for all purposes as prepared through the joint efforts of the parties and shall not be construed against one party or the other as a result of the preparation, substitution, submission or other event of negotiation, drafting or execution hereof. Except to the extent herein provided for, no amendment or modification to this Master Agreement shall be enforceable unless reduced to writing and executed by both Parties. Each Party agrees if it seeks to amend any applicable wholesale power sales tariff during the term of this Agreement, such amendment will not in any way affect outstanding Transactions under this Agreement without the prior written consent of the other Party. Each Party further agrees that it will not assert, or defend itself, on the basis that any applicable tariff is inconsistent with this Agreement. This Agreement shall not impart any rights enforceable by any third party (other than a permitted successor or assignee bound to this Agreement). Waiver by a Party of any default by the other Party shall not be construed as a waiver of any other default. Any provision declared or rendered unlawful by any applicable court of law or regulatory agency or deemed unlawful because of a statutory change (individually or collectively, such events referred to as “Regulatory Event”) will not otherwise affect the remaining lawful obligations that arise under this Agreement; and provided, further, that if a Regulatory Event occurs, the Parties shall use their best efforts to reform this Agreement in order to give effect to the original intention of the Parties. The term “including” when used in this Agreement shall be by way of example only and shall not be considered in any way to be in limitation. The headings used herein are for convenience and reference purposes only. All indemnity and audit rights shall survive the termination of this Agreement for twelve (12) months. This Agreement shall be binding on each Party’s successors and permitted assigns.
     10.9 Audit. Each Party has the right, at its sole expense and during normal working hours, to examine the records of the other Party to the extent reasonably necessary to verify the accuracy of any statement, charge or computation made pursuant to this Master Agreement. If requested, a Party shall provide to the other Party statements evidencing the Quantity delivered at the Delivery Point. If any such examination reveals any inaccuracy in any statement, the necessary adjustments in such statement and the payments thereof will be made promptly and shall bear interest calculated at the Interest Rate from the date the overpayment or underpayment was made until paid; provided, however, that no adjustment for any statement or payment will be made unless objection to the accuracy thereof was made prior to the lapse of twelve (12) months from the rendition thereof, and thereafter any objection shall be deemed waived.
     10.10 Forward Contract. The Parties acknowledge and agree that all Transactions constitute “forward contracts” within the meaning of the United States Bankruptcy Code.
22

 
     10.11 Confidentiality. If the Parties have elected on the Cover Sheet to make this Section 10.11 applicable to this Master Agreement, neither Party shall disclose the terms or conditions of a Transaction under this Master Agreement to a third party (other than the Party’s employees, lenders, counsel, accountants or advisors who have a need to know such information and have agreed to keep such terms confidential) except in order to comply with any applicable law, regulation, or any exchange, control area or independent system operator rule or in connection with any court or regulatory proceeding; provided, however, each Party shall, to the extent practicable, use reasonable efforts to prevent or limit the disclosure. The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, this confidentiality obligation.
23

 
CONFIRMATION LETTER
 	 	 	
From:	 	J. Aron & Company	
 	 	85 Broad Street	
 	 	New York, NY 10004	
 	 	 	
To:	 	Texas Genco, LP	
 	 	1111 Louisiana Street, 10th Floor	
 	 	P.O. Box 2846, 20th Floor	
 	 	Houston, TX 77002 (77252-2846)	
 	 	 	
Attention:	 	David G. Tees	
The purpose of this letter agreement (this “Confirmation”) is to confirm the terms and conditions of the following transaction (the “ Transaction ”) entered into on the Trade Date specified below between J. Aron & Company (“ Buyer ”) and Texas Genco, LP (“Seller”).
This confirmation letter is being provided pursuant to and in accordance with the Master Power Purchase and Sale Agreement dated as of July 21, 2004 (the “ Master Agreement ”) between Buyer and Seller and constitutes part of and is subject to the terms and provisions of such Master Agreement. Terms used but not defined herein shall have the meanings ascribed to them in the Master Agreement.
The commercial terms of this Transaction are as follows:
 	 	 	
Trade Date:	 	July 21, 2004	
 	 	 	
Contract Reference:	 	To be advised by Buyer	
 	 	 	
Buyer:	 	J. Aron & Company	
 	 	 	
Seller:	 	Texas Genco, LP	
 	 	 	
Scheduling:	 	Buyer must Schedule the Product at the contracted quantity with ERCOT by 11:00 Central prevailing time each day.	
 	 	 	
Product:	 	Firm (LD) Energy	
 	 	 	
Delivery Period:	 	From hour ending 0100 on January 1, 2005 to hour ending 2400 on December 31, 2008, including North American Electricity Reliability Council (“NERC”) holidays	
 	 	 	
Monthly Quantities:	 	See Schedule 1 to this Confirmation.	

 
 	 	 	
Contract Prices:	 	See Schedule 1 to this Confirmation.	
 	 	 	
Delivery Points:	 	Subject to the section entitled “Alternate Delivery Points” below, (i) while ERCOT operates on a zonal congestion basis, the “Primary Delivery Point” for each ERCOT zone specified in Schedule 1 shall be any delivery point in such ERCOT zone, and (ii) if and when ERCOT switches to a nodal congestion methodology, the “Primary Delivery Point” for each of the Parish facility, the South Texas Project facility and the Limestone facility, as specified in Schedule 1, shall be the node that consists of the 345 kV interconnection at the busbar for such facility.	
 	 	 	
Alternate Delivery Points:	 	Seller may specify an alternate delivery point (an “Alternate Delivery Point”) in accordance with the following for any Product delivered under this Transaction:	
 	 	 	
 	 	(1) If and when ERCOT switches to a nodal congestion methodology, upon notice by Seller to Buyer delivered no later than 08:30 Central prevailing time of the Day prior to the Day on which a Product is to be delivered, Seller may specify any other delivery point in the ERCOT zone (or equivalent designation) in which the Primary Delivery Point for such Product is located as the Delivery Point for such Product. In the event Seller elects an Alternate Delivery Point pursuant to this clause (1), (a) Seller shall pay Buyer the amount by which the market price at the Primary Delivery Point exceeded the market price at the Alternate Delivery Point, and (b) Buyer shall pay to Seller the amount by which the market price at the Alternate Delivery Point exceeded the market price at the Primary Delivery Point, in each case with respect to the Product delivered at such Alternate Delivery Point.	
 	 	 	
 	 	(2) In the event of an Unplanned (Forced) Outage or an Unplanned (Forced) Derating at either the Limestone facility or the South Texas Project facility (each, an  “Affected Facility”),  Seller may, upon notice by Seller to Buyer delivered no later than 08:30 Central prevailing time of the Day prior to the Day on which a Product is to be delivered, elect a Parish Zone Delivery Point as the delivery point for the Product that would otherwise have been delivered at the Primary Delivery Point associated with such Affected Facility. Seller shall not reduce	

 
 	 	 	
 	 	Buyer’s receipts at the Primary Delivery Point at either Affected Facility more than pro rata with other parties buying power at such facilities for which Seller has the right to designate an alternate delivery point.	
 	 	 	
 	 	For purposes of the foregoing, (i) a “Parish Zone Delivery Point” is any delivery point in the ERCOT zone (or equivalent designation) in which the Primary Delivery Point for the Parish facility is located and (ii)  “Unplanned (Forced) Outage” and  “Unplanned (Forced) Derating”  each have the meanings specified in the NERC Generating Unit Availability Data System (GADS) event reporting guidelines.	
 	 	 	
 	 	The provisions related to Alternate Delivery Points shall not affect Seller’s obligation to deliver Firm (LD) Energy.	
 	 	 	
Force Majeure	 	Revise the third sentence of Section 1.23 of the Master Agreement to read as follows:	
 	 	 	
 	 	Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has either (A) contracted for firm transmission with a Transmission Provider for the Product to be delivered to or received at the Delivery Point or (B) scheduled such Product into (in the case of Seller) or out of (in the case of Buyer) a Delivery Point and (ii) such curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the ERCOT Protocols. For the avoidance of doubt, Seller is not a Transmission Provider for purposes of this provision.	
 	 	 	
Buyer Operations Contacts:	 	Fintan Whitty — Operations Manager: (212) 902-7311 Kathy Benini — Scheduling Manager (212) 902-1454	
[SIGNATURE PAGE FOLLOWS]

 
Please confirm that the terms stated herein accurately reflect the agreement reached between
Texas Genco, LP and J. Aron & Company by executing where indicated below.
Signed on behalf of J. Aron & Company
 	 	 	 	 	
By:	 	/s/ Peter O’Hagan	 	 	
 	 	 	 	 	
 	 	Peter O’Hagan	 	 	
 	 	Managing Director J. Aron & Company	 	 	
 	 	 	 	 	
Signed on behalf of Texas Genco, LP
By Texas Genco GP, LLC, its general partner	 	 	
 	 	 	 	 	
By:	 	/s/ David G. Tees	 	 	
 	 	 	 	 	
 	 	Name: David G. Tees	 	 	
 	 	Title: President	 	 	

 
Schedule 1 to Confirmation Letter
CONTRACT PRICES, MONTHLY VOLUMES AND DELIVERY POINTS
***

 
Exhibit 10.32
*** Indicates materials have been omitted pursuant to a Confidential Treatment Request filed with the Securities and Exchange Commission. A complete copy of this Agreement has been filed with the Securities and Exchange Commission.

 
March 4, 2005
Mr. Paul R. Brown, CPM
Staff Sourcing Specialist
Texas Genco, LP
12301 Kurland Drive
Houston, TX 77034
 	 	 	
Subject:	 	*** Aluminum BethGon® II Railcars for Texas Genco, LP.	
 	 	FreightCar America Inc. Proposal No. 04153 Revision A	
Dear Mr. Brown:
In response to your inquiry, FreightCar America, Inc. (“FreightCar”) would be pleased to sell *** new Aluminum BethGon ®  II Railcars (the “Railcars”) to Texas Genco, LP (“Purchaser”), per the details listed below:
 	 	 	 	 	 	 	
Quantity	 	Car Type	 	Specification / Date	 	Price Per Railcar	
***	 	Aluminum BethGon® II
Railcars	 	X-04153 / February 14, 2005	 	$***	
***	 	Aluminum BethGon® II
Railcars	 	X-04153 / February 14, 2005	 	$***	
***	 	Aluminum BethGon® II
Railcars	 	X-04153 / February 14, 2005	 	$***	
***	 	Aluminum BethGon® II
Railcars	 	X-04153 / February 14, 2005	 	$***	
The above price is FOB FreightCar’s Plant. Switching and transportation charges are not included in the price, but can be prepaid by FreightCar and added to your invoice at your request.
The requirements of the Association of American Railroads (AAR) and the United States Department of Transportation (DOT) are incorporated in the Specification for the Railcars. Should these requirements be changed, or should any other regulatory requirements be imposed prior to delivery of the Railcars, the above price will be adjusted upward or downward accordingly.
FRA 49 CFR 224 Reflectorization of Rail Freight Rolling Stock is scheduled to go into effect for all Railcars delivered after May 31, 2005. As of the date of this letter, the Railcar design offered herein complies with 49 CFR 224 as currently defined by the FRA. Any additional costs associated with the ongoing interpretation of 49 CFR 224 are for the account of the Purchaser.
The above proposal price is based upon our ability to obtain certain aluminum, steel, specialties and other components used in the construction of the Railcars at the costs included in our estimate. In the unforeseen instance that a supplier is unable to provide the specified material, specialties and other components at the costs included in our estimate, and substitute material, specialties and other

 
Mr. Paul R. Brown, CPM
March 4, 2005
Page 2
components are supplied the Price per Railcar will be adjusted accordingly. The material, and casting and steel surcharge costs shown on Exhibit A are included in the Price per Railcar and reflect our current estimate of the cost of these items. The Price per Railcar will be adjusted upward or downward to reflect the actual cost of the items shown on Exhibit A used to manufacture the Railcars. Texas Genco, LP will be provided the documentation necessary to verify the actual cost of these items.
DELIVERY: Subject to receipt of prior orders FreightCar can begin delivery of the first *** Aluminum BethGon® II Railcars during the first week of  ***  2006. Subject to receipt of prior orders FreightCar can begin delivery of the remaining  *** Aluminum BethGon ®  II Railcars during the last week of  ***  2006. The cars are scheduled to be produced at  ***  .
This schedule is subject to the availability of castings and other components. Given the tightness in the availability of castings and other components, there is reason to be concerned that suppliers may not be able to maintain delivery schedules.
TERMS: Net due upon receipt of invoice.
This proposal is valid for 70 calendar days and is subject to all respects to the attached Terms and Conditions of Sale.
Please confirm your acceptance of this proposal by having an authorized officer of Texas Genco, LP execute this letter agreement and the attached Terms and Conditions of Sale and returning a copy to my attention within 70 calendar days from the date of this letter.
FreightCar America, Inc. very much appreciates the opportunity to build these Railcars for Texas Genco, LP. Should you have any questions concerning this transaction, please contact me at 312-928-0874.
Very truly yours,
JOHNSTOWN AMERICA CORPORATION
/s/   Tim Johnson
By: Tim Johnson
Its: Vice President Sales — Western Region

 
ACCEPTANCE BY PURCHASER:
Texas Genco, LP hereby acknowledges its acceptance of the offer to acquire the Railcars described above, at the price and upon the terms and conditions set forth herein and in the attached Terms and Conditions of Sale.
Texas Genco, LP
 	 	 	 	 	
By:	 	 	 	 	

Its:	 	 	 	 	

Date:	 	 	 	 	
 	 	 	 	 	
Quantity of Railcars:
 	 	 	
Attachments:	 	EXHIBIT A	
 	 	Texas Genco, LP RFQ	
 	 	Specification X-04153	
 	 	Terms and Conditions	
 	 	Specialty Component List	
 	 	Colin Gibb	
 	 	EJW, WCH, plm, file	

 
EXHIBIT A
BethGon ®  II
Material Cost Subject to Adjustment Included in Per Car Price
 	 	 	 	 	 	 	 	 	 	 	
Item	 	Weight/lbs.	 	$/lbs.	 	 	Cost	 	
COST OF RAW MATERIALS	 	 	 	 	
Steel	 	***	 	$	***	 	 	$	***	 	
Aluminum	 	***	 	$	***	 	 	$	***	 	
 	 	 	 	 	 	 	 	 	 	
Estimated Cost of Raw Materials at Time of Delivery	 	$	***	 	
 	 	 	 	 	 	 	 	 	 	 	
MAJOR SPECIALTIES	 	 	 	 	
Castings	 	 	 	 	 	 	 	$	***	 	
Forgings	 	 	 	 	 	 	 	$	***	 	
Airbrake (Includes Hoses)	 	$	***	 	
Miscellaneous Specialties	 	$	***	 	
Polymers	 	 	 	 	 	 	 	$	***	 	
Coatings	 	 	 	 	 	 	 	$	***	 	
Fasteners	 	 	 	 	 	 	 	$	***	 	
*Wheel Sets	 	 	 	 	 	 	 	$	***	 	
 	 	 	 	 	 	 	 	 	 	
Estimated Cost of Major Specialties on Date of Proposal	 	$	***	 	
 	 	 	 	 	 	 	 	 	 	 	
SURCHARGES ON RAW MATERIALS	 	 	 	 	
Steel	 	 	 	 	 	 	 	$	***	 	
Aluminum	 	 	 	 	 	 	 	$	***	 	
Estimated Surcharges on Raw Material at Time of Delivery	 	$	 	 	
 	 	 	 	 	 	 	 	 	 	 	
SURCHARGES ON MAJOR SPECIALTIES	 	 	 	 	
Castings	 	 	 	 	 	 	 	$	***	 	
Wheels	 	 	 	 	 	 	 	$	***	 	
Axles	 	 	 	 	 	 	 	$	***	 	
Roller Bearings	 	$	***	 	
Springs	 	 	 	 	 	 	 	$	***	 	
Brake System	 	 	 	 	 	 	 	$	***	 	
Forgings	 	 	 	 	 	 	 	$	***	 	
Brake Beams	 	 	 	 	 	 	 	$	***	 	
Fasteners	 	 	 	 	 	 	 	$	***	 	
Miscellaneous	 	 	 	 	
Estimated Surcharges on Major Specialties at Time of Delivery	 	$	***	 	
Estimated Component and Surcharge Cost Included in Per Car Price	 	$	***	 	

 	 	 	
*	 	Wheel Set Complete Includes Wheels, Axle, Bearings & Mounting	
***

 
FREIGHTCAR AMERICA, INC.
TERMS AND CONDITIONS OF SALE
FOR PROPOSAL NO.: 04153 Revision A
These Terms and Conditions of Sale are incorporated into and made a part of the Proposal Letter dated March 4, 2005 (the “Proposal Letter”) from FreightCar America, Inc. (“FreightCar”) to Texas Genco II, LP (“Purchaser”). These Terms and Conditions of Sale, the Proposal Letter and the Specifications and Specialty Component List (such Specifications and Specialty Component List being collectively referred to as the “Specifications”) described therein are hereinafter referred to as this “Agreement.”
Inspection and Acceptance: FreightCar shall give Purchaser, and/or its designated agent, reasonable opportunity to inspect FreightCar’s manufacturing procedures prior to commencement of the start of production of the first Railcar and during production and the Railcars during the construction process at FreightCar’s manufacturing facility in Danville, Illinois ( “FreightCar’s Plant”) during normal operating hours or at such other time as may be mutually agreed. Purchaser shall have its representative present for inspection of the Railcars at FreightCar’s Plant prior to the start of production of the first Railcar. Upon completion of each Railcar, Purchaser shall use its best efforts to arrange to conduct a final inspection of such Railcar prior to the time such Railcar is removed from the Final QA Acceptance Building at FreightCar’s Plant. Such inspection will comply with the safety and inspection procedures specified by FreightCar and will be conducted so as not to interfere unreasonably with FreightCar’s operations, and acceptance of the Railcars by Purchaser will be made before removal of such Railcars from the Final QA Acceptance Building at FreightCar’s Plant. All storage, transportation and other costs incurred by FreightCar as a result of any delay by Purchaser in inspecting or accepting the Railcars shall be for Purchaser’s account. Purchaser, or its designated agent, shall execute a certificate of inspection and acceptance (“Certificate of Acceptance”) in the form of  Exhibit A  hereto covering all Railcars found to be completed in accordance with the Specifications and shall deliver the executed Certificate(s) of Acceptance to FreightCar. If, upon inspection of the Railcars by Purchaser, the Railcars appear not to conform to the Specifications, Purchaser will immediately notify FreightCar in writing of the condition and give FreightCar a reasonable opportunity to correct the condition. Such correction shall not relieve FreightCar of its obligation to adhere to the production schedule agreed upon by the parties. Each designated agent and representative selected by Purchaser to inspect the Railcars must be reasonably acceptable to FreightCar. Prior to the inspection described herein, Purchaser shall notify FreightCar of the name and company of the designated agent and representative selected by Purchaser, and if such person(s) are not reasonably acceptable to FreightCar, FreightCar shall promptly notify Purchaser. FreightCar shall pre-register the Railcars in UMLER and shall, at the reasonable request of Purchaser (and at no cost to FreightCar), make any other required initial filings and registrations of the Railcars.
Price: The purchase price to be paid by Purchaser to FreightCar for each Railcar purchased by Purchaser pursuant to this Agreement is set forth in the Proposal Letter and is based upon FreightCar’s ability to obtain certain aluminum, steel, specialties and other components used in the construction of the Railcars. In the unforeseen instance that a supplier is unable to provide the specified material, specialties and other components and substitute material, specialties and other components are supplied the price per Railcar will be adjusted accordingly. The material and casting and steel surcharge costs shown on Exhibit A to the Proposal Letter are included in the price per Railcar and reflect FreightCar’s current estimate of these items. The price per Railcar will be adjusted upward or downward to reflect the actual cost of the items shown on Exhibit A to the Proposal Letter used to manufacture the Railcar. Upon Purchaser’s request from time to time, FreightCar shall provide to Purchaser any updated price information relating to the Railcars. If the purchase price of the Railcars exceeds by more than ***% the purchase price for such Railcars contained in the Proposal Letter, Purchaser shall, upon

 
notice to FreightCar, within ten (10) days of being notified of such purchase price increase, have the right to cancel this Agreement with respect to the Railcars subject to such price adjustment, without cost or penalty to Purchaser or FreightCar.
If the final purchase price (after application of the aforementioned adjustment) is different than the price set forth in the Proposal Letter, upon Purchaser’s request, the final purchase price is subject to confirmation by an independent auditor acceptable to both parties (“Auditor”). Such confirmation will take place at a mutually acceptable time. The parties agree that information used to determine the final purchase price (“Information”) is the confidential and proprietary property of FreightCar and such Information shall be made available only to the Auditor, subject to the Auditor’s execution of a confidentiality agreement acceptable to FreightCar, solely for the purpose of confirming such final purchase price. The Auditor shall not disclose any Information to Purchaser, but shall confirm its agreement with FreightCar’s calculation of the final purchase price, or in the event it disagrees with such calculation, shall provide to both parties a revised final purchase price with such revised final purchase price being binding on both parties. The cost of the Auditor shall be borne by Purchaser unless the final purchase price is more than  ***  lower than the adjusted purchase price originally submitted by FreightCar, in which case the cost of the Auditor will be borne by FreightCar.
Payment: Following delivery by Purchaser to FreightCar of a Certificate of Acceptance for a Railcar, title to such Railcar shall pass to Purchaser, and FreightCar shall deliver to Purchaser a bill of sale for such Railcar which shall retain for FreightCar a security interest in such Railcar as further described in the following sentence. FreightCar shall retain, and Purchaser does hereby grant to FreightCar, as security for payment of such accepted Railcars and fulfillment of its obligations to FreightCar hereunder, a purchase money security interest in such Railcars and the rentals, earnings, products, proceeds and accessions of and to any of such Railcars, together with all right, title and interest of Purchaser therein and all rights and remedies which Purchaser might exercise with respect thereto but for the execution of this Agreement. Purchaser acknowledges that this Agreement shall constitute a security agreement between the parties and that FreightCar shall be vested with all of the rights and remedies available to a secured party under the Uniform Commercial Code in effect in the State in which FreightCar’s Plant is located upon a default by Purchaser hereunder, including, without limitation, the right to foreclose upon and take possession of the Railcars pursuant to public or private sale. Prior to delivery of any of such Railcars to Purchaser, Purchaser will execute and return to FreightCar a Memorandum of Railcar Security Agreement (“Memorandum”) covering the Railcars in form satisfactory to FreightCar and suitable for filing with the Surface Transportation Board (“STB”). Following receipt by FreightCar of payment for a Railcar, FreightCar will file with the STB a termination of the Memorandum with respect to such Railcar and deliver such other evidence of clear title as Purchaser shall reasonably request. Not less than five (5) days prior to the completion of the final Railcar in a trainset, FreightCar shall invoice Purchaser for the Railcars in such trainset and Purchaser shall pay the purchase price for the Railcars in such trainset, as hereinafter provided, upon acceptance, by Purchaser at FreightCar’s Plant, of the final Railcar in such trainset. Purchaser shall make such payment of the purchase price for such Railcars in the form of a wire transfer of immediately available U.S. funds, in accordance with the instructions from FreightCar, provided that Purchaser shall make such wire transfer no later than (i) the business day following the day on which Purchaser receives, before 2:00 p.m. Central Time, the Certificate of Acceptance for the final Railcar in such trainset (the “Final Certificate”) or (ii) the second business day following the day on which Purchaser receives, after 2:00 p.m. Central Time, the Final Certificate; provided further that FreightCar shall have no obligation to deliver such Railcars to the Connection Point (as hereinafter defined) until FreightCar has confirmed receipt of such wire payment. If all or any portion of the purchase price for the Railcars is not paid to FreightCar when due, such nonpayment shall result in the additional obligation on the part of Purchaser to pay interest to FreightCar on the unpaid amount, on demand, at the applicable Prime Rate, as reported by  The Wall Street Journal.  If Purchaser shall not make payment as aforesaid, Purchaser agrees to execute such instruments and to take such other action as shall be reasonably requested by FreightCar to vest in FreightCar or its designee good and

 
marketable title to such Railcars, free and clear of all liens, claims and encumbrances arising by, through or under Purchaser, and, at FreightCar’s option, possession and control of the Railcars, whereupon FreightCar may, at its election, terminate this Agreement and sell, lease, retain or otherwise dispose of such Railcars.
Credit Approval: If, subsequent to the date hereof, a material adverse change in Purchaser’s creditworthiness, financial condition or prospects occurs, as reasonably determined by FreightCar, FreightCar may cease the ordering or accepting of materials to build the Railcars and cease the manufacture of the Railcars until FreightCar has received from Purchaser a monetary deposit of up to  *** , as requested by FreightCar, or other assurances of payment satisfactory to FreightCar.
Delivery: Following Purchaser’s delivery of a Certificate of Acceptance, at the request of Purchaser, FreightCar shall arrange to deliver such accepted Railcars from FreightCar’s Plant to the railroad connection contiguous to FreightCar’s Plant (the “Connection Point”). The purchase price set forth in this Agreement is FOB FreightCar’s Plant. All movement of the Railcars, following their initial delivery by FreightCar to the Connection Point, shall be at the cost and risk of Purchaser. Delayed delivery of the Railcars due to an event of Force Majeure (as defined below) shall be without penalty or cost to FreightCar. Notwithstanding any other provision to the contrary, FreightCar acknowledges that Purchaser is purchasing the Railcars to replace certain railcars that Purchaser currently leases, and that said lease, and Purchaser’s right to use the railcars pursuant thereto expires in conjunction with Purchaser’s purchase of the Railcars from FreightCar. Should FreightCar fail to deliver any Railcar by the thirtieth (30) day after the date shown on Exhibit B , and such failure is not excused by an event of Force Majeure, FreightCar shall, at its option, (i) pay any reasonable costs associated with Purchaser securing temporary replacement railcars or (ii) supply Purchaser with replacement railcars at FreightCar’s sole expense.
Specifications and Changes: The Railcars shall be constructed in accordance with the Specifications. The Specifications shall comply with the applicable published requirements of the Federal Railroad Administration (“FRA”) and the Association of American Railroads (“AAR”) in effect on the date of manufacture of the Railcars. If it shall become impossible or impracticable for FreightCar to secure the materials required for the manufacture of the Railcars in exact accordance with the Specifications, including without limitation by reason of any subsequent interpretation of or changes to such FRA or AAR requirements, FreightCar may, upon notice to Purchaser, make changes in the Specifications not materially affecting the strength, size, capacity or efficiency of the Railcars for railroad use and interchange, provided that FreightCar shall not substitute any of the materials identified in FreightCar’s Specialty Component List without Purchaser’s consent. If such change will result in an increase in the cost to FreightCar over the anticipated cost to produce the Railcar without giving effect to such change, the purchase price for the Railcars shall be adjusted to reflect such increased cost, provided that FreightCar shall obtain the prior written consent of Purchaser to such adjustment. If Purchaser fails to consent to such adjustment, FreightCar shall have the right to cancel this Agreement without penalty to either party. Any other changes in the Specifications desired by either party must be requested in writing and specify the amount of any adjustment in the purchase price (as determined by FreightCar), and must be approved in writing by the other party. Each party agrees that it will not unreasonably withhold its consent to any requested change by the other. FreightCar is under no obligation to arrange for shipment and acceptance of any required materials in advance of FreightCar’s needs.
Permissible Tolerances: Except in the particulars specified by Purchaser and expressly agreed to in writing by FreightCar, all Railcars will be manufactured in accordance with FreightCar’s standard practices and will be subject to tolerances and variations consistent with usages of the trade and regular practices including deviations from tolerances and variations consistent with practical testing and inspection methods.

 
Force Majeure: An event of “Force Majeure” shall include extraordinary and unforeseeable occurrences such as strikes, lockouts or other labor disturbances, shortages or late delivery of material (due to no fault of FreightCar); unavailability, interruptions or inadequacy of fuel supplies; acts of God; war, preparation for war or other acts or interventions of naval or military personnel or other agencies of government; governmental rules or regulations (or interpretation of or changes to the existing rules or regulations); priorities given to defense orders; riot, embargoes, sabotage, act of terrorism, vandalism, malicious mischief, landslides, floods, hurricanes, earthquakes, collisions, fires or other calamities; delays of carriers (due to no fault of FreightCar); shortages of labor, non-delivery and/or late delivery of any Purchaser-furnished supplies, material, equipment or labor, including plans, drawings or engineering; delays due to changes by Purchaser in drawings or specifications or any circumstance or cause beyond the reasonable control of FreightCar in the conduct of its business. Notwithstanding the foregoing, FreightCar shall, during any period of Force Majeure, exercise such diligence as the circumstances reasonably require.
Risk of Loss: FreightCar shall bear all risks of physical loss of the Railcars at FreightCar’s Plant and until receipt by FreightCar of the Certificate of Acceptance from Purchaser for such Railcars (such date of receipt being hereinafter referred to as the “Transfer Date”) and delivery of Railcars to the Connection Point. From and after the Transfer Date for a Railcar, and after delivery of a Railcar to the Connection Point, Purchaser shall bear all risk of loss of such Railcar. Notwithstanding the foregoing, FreightCar shall not be responsible for any loss or damages to property (including the Railcars) or injury to or death of any person arising out of or in connection with any Railcar (including, without limitation, any inspection of such Railcar) prior to the Transfer Date when such loss, damage or death is caused by the actions of Purchaser’s or any of Purchaser’s affiliated corporation’s officers, managers, directors, employees, inspectors, representatives or agents. If, for any reason, FreightCar does not receive a Certificate of Acceptance for a Railcar, then the Transfer Date for such Railcar shall mean the date on which such Railcar is first delivered by FreightCar to the Connection Point.
Warranty:
     (a) FreightCar warrants that all goods and services sold hereunder or pursuant hereto will be free of any claims of any nature by any third person (other than claims, liens, security interests and encumbrances arising by, through or under Purchaser) and that, upon delivery of the Bill of Sale with respect to a Railcar, FreightCar will convey to Purchaser good and marketable title to such Railcar, free and clear of all claims, liens, security interests, encumbrances and rights of others of any nature whatsoever (other than claims, liens, security interests and encumbrances arising by, through or under Purchaser).
     (b) FreightCar warrants that each Railcar will be free from defects in material and workmanship under normal use and service for a period of  ***  from the Transfer Date of such Railcar by Purchaser. With respect to parts and materials manufactured by others and incorporated by FreightCar in the Railcars, such parts and material shall be covered only by the warranty, if any, of the manufacturer thereof, and FreightCar shall assign to Purchaser any such warranty, to the extent assignable by FreightCar, and FreightCar will cooperate with Purchaser to assist in enforcing any such warranty not so assigned at its own expense. FreightCar shall not provide any other relief or warranty with respect to such parts and materials. FreightCar’s obligations with respect to any Railcar for breach of this warranty, whether or not due to FreightCar’s negligent acts or omissions, is limited to either replacement or repair, which option shall be mutually agreed upon by the parties and which Purchaser shall not unreasonably withhold agreement, of such non-conforming or defective component (or Railcar) on Purchaser’s normal route of railcar movement, but at all time subject to FreightCar’s prior approval of the respective repair shop or facility. FreightCar’s agreement set forth above to repair or replace defective parts and materials (other than with respect to parts and materials manufactured by others and incorporated by FreightCar in the Railcars, the remedy for which is provided for above in this Warranty section) shall be Purchaser’s sole and exclusive remedy with respect to the Railcars that are defective in any respect or

 
that fail to conform to the Specifications or to any express or implied warranty, and FreightCar will not in any event be liable for the cost of any transportation charges expended on or in connection with the repair, replacement or return of any component (or Railcar) or for any special, indirect, incidental or consequential damages. FreightCar’s warranty set forth in this Warranty section shall be void and of no force and effect if repairs made to the Railcar are not made in conformity with FreightCar’s Specifications or, if in the process of making repairs to the Railcar, parts originally manufactured by FreightCar (including, without limitation, all car body components, such as side stakes, top chords, side sills, end posts, tubs, gate systems, etc.) are removed and not replaced with like parts manufactured by FreightCar. FreightCar shall provide to Purchaser copies of the warranties received by FreightCar on parts and materials purchased by FreightCar from the manufacturers and suppliers listed on  Exhibit C  hereto and any manufacturers or suppliers substituted therefore after the date of this Agreement.
THIS WARRANTY IS EXPRESSLY IN LIEU OF ALL OTHER WARRANTIES EXPRESS OR IMPLIED, INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE. PURCHASER ACKNOWLEDGES THAT ITS SOLE REMEDY FOR BREACH OF THIS WARRANTY BY FREIGHTCAR IS AS PROVIDED ABOVE AND FREIGHTCAR SHALL NOT BE LIABLE IN TORT, FOR NEGLIGENCE OR STRICT LIABILITY OR FOR LOSS OR INTERRUPTION OF USE, PROFIT OR BUSINESS OR ANY OTHER INCIDENTAL OR CONSEQUENTIAL INJURY OR DAMAGE, ALL OF WHICH ARE EXPRESSLY WAIVED AND RELEASED BY PURCHASER.
FREIGHTCAR’S OBLIGATIONS UNDER THIS WARRANTY ARE CONDITIONED UPON COMPLIANCE BY PURCHASER AND ALL OTHER USERS OF THE RAILCARS WITH OPERATION, LOADING, USE, HANDLING, MAINTENANCE AND STORAGE IN ACCORDANCE WITH GOOD COMMERCIAL PRACTICES OF THE RAILROAD INDUSTRY. FREIGHTCAR SHALL NOT BE RESPONSIBLE FOR FAILURES CAUSED BY MISLOADING, OVERLOADING, OVERHEATING, IMPROPER CLEANING, PHYSICAL ABUSE, ACCIDENT, DERAILMENT OR FOR OTHER DAMAGE CAUSED BY FIRE, FLOOD OR OTHER EXTERNAL CONDITIONS UNRELATED TO THE MANUFACTURE OF THE RAILCAR OR FOR NORMAL WEAR AND TEAR.
Representations and Warranties:
          (a) FreightCar represents and warrants that the Railcars manufactured pursuant to this Agreement will meet all published U.S. laws, rules and regulations governing the manufacture of railcars in effect on the date of manufacture of the Railcars, including, but not limited to, the applicable published requirements of the Federal Railway Administration and the Association of American Railroads. FreightCar represents that it is in material compliance with all such laws, regulations and orders applicable to FreightCar.
          (b) FreightCar and Purchaser each hereby represent and warrant to the other that: (a) it is incorporated or registered and existing in good standing as a corporation or limited partnership, as the case may be, under the laws of the state in which it is organized and all states in which it is authorized to do business, with full corporate power and authority to execute and deliver this Agreement and to perform its obligations hereunder; (b) neither the execution and delivery of this Agreement by it, nor the performance of its obligations hereunder, will result in any violation of its certificate of incorporation or bylaws, or its Certification of Formation on limited partnership agreement, as applicable; and (c) this Agreement constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms, subject to applicable bankruptcy, insolvency and other similar laws affecting creditors’ rights generally, and to equitable principals of general applicability.

 
          (c) The representations and warranties contained in this Agreement shall survive the execution, delivery and performance of this Agreement, subject to the applicable statute of limitations period.
Non-Disclosure: The parties each agree that the provisions of this Agreement shall not be disclosed to any person other than the parties’ directors, managers, officers, employees, affiliates, agents (including consultants, auditors and accountants, but excluding any manufacturer of railcars or components or affiliate thereof) or legal counsel (herein “Purchaser’s or FreightCar’s representatives”), who shall be subject to the non-disclosure provisions contained herein; except (i) upon the written consent of the other party, (ii) to any federal, state or local governmental agency to whose jurisdiction a party is subject pursuant to regulation, regulatory body policy, order of court or order of administrative judge or hearing examiner (provided, however, that unless specifically required by law, neither party shall provide the Price for the Railcars or any other terms of conditions of sale to the STB, including without limitation in any filing made with the STB), (iii) in response to warrant, subpoena, interrogatory, investigative demand or other legal process in any legal proceeding, including a proceeding for enforcement of this Agreement, (iv) to any third party or parties for the purpose of financing the Railcars or the debt of the Purchaser, provided, that, prior to such disclosure each such party agrees to be bound by the terms of this agreement of non-disclosure, and provided, further, that any breach by such third party shall be deemed to be a breach by Purchaser of this Agreement, or (v) in connection with any filings made to the Securities and Exchange Commission .  In situations (ii), (iii) or (v) above, when disclosure is to be made to any person other than Purchaser’s or FreightCar’s representatives, the disclosing party shall use reasonable efforts to notify the other party of its intent to disclose such information so that the other party may, if it so elects, seek an appropriate protective order or other appropriate relief to avoid or limit such disclosure. In situation (iv) above, no disclosure by Purchaser shall be made to any manufacturer of railcars or components or affiliate thereof.
Drawings: All drawings and technical material, including specifications, descriptions and tolerances relating to the Railcars or any components thereof supplied by FreightCar to Purchaser pursuant to the Specifications (the “Drawings”) are the exclusive property of FreightCar and contain confidential and proprietary information. By accepting the Drawings from FreightCar, Purchaser agrees to limit its use of the Drawings solely to matters relating to Purchaser’s use of the Railcars, including the repair and maintenance of the Railcars. Purchaser further agrees not to disclose the Drawings, or to disclose any information contained in or derived from the Drawings, to any person, including, but not limited to, any other manufacturer of railcars or components or affiliate thereof; provided, however, that Purchaser may provide the Drawings to a car repair shop for the sole purpose of maintaining and repairing the Railcars, provided that such car repair shop agrees in advance in writing to be bound by the terms of the confidentiality provisions contained herein and, provided further, that any breach of such agreement by such car repair shop shall be deemed a breach by Purchaser of this Agreement.
Sales Tax: Notwithstanding anything herein this Agreement to the contrary, Purchaser shall pay, and shall indemnify and hold FreightCar harmless against, all state or local sales, use or related taxes arising out of this transaction which FreightCar may be required to pay or collect with respect to this Agreement.
Order Cancellation: The Railcars to be manufactured by FreightCar for Purchaser pursuant to this Agreement are to be built to order and Purchaser’s purchase commitment contained herein is non-cancellable. Notwithstanding the foregoing, if Purchaser, for whatever reason, cancels its order, it shall upon demand pay to FreightCar, as liquidated damages and not as a penalty, all costs theretofore incurred by FreightCar in the manufacture of the Railcars, including, without limitation, labor costs, and the costs of material, components and supplies ordered by FreightCar to fulfill this Agreement (net of the fair market salvage value of such material, components or partially manufactured Railcars), together with FreightCar’s lost profits, if any, attributable to the cancellation of Purchaser’s purchase commitment (provided, however, that FreightCar shall not be entitled to any such lost profits if FreightCar sells the Cars to a third party for a purchase price which

 
equals or exceeds the purchase price for the Cars which would have been paid by Purchaser had Purchaser not cancelled this Agreement), all as reasonably calculated by FreightCar.
Patents: FreightCar will indemnify Purchaser against any judgment for damages and costs which may be rendered against Purchaser in any suit brought as a result of the alleged infringement of any United States patent by any Railcar supplied by FreightCar, unless made in accordance with materials, designs or specifications furnished or designated by Purchaser, in which case Purchaser will indemnify FreightCar against any judgment for damages and costs which may be rendered against FreightCar in any suit brought as a result of the alleged infringement of any United States patent by such Railcar as a consequence of such materials, designs or specifications; provided that prompt written notice be given to the party from whom indemnity is sought and that an opportunity be given to that party to settle or defend such action as that party may see fit and that each party render to the other party every reasonable assistance in settling or defending such action. Neither party will be liable to the other for special, indirect, incidental or consequential damages arising out of or resulting from infringement of patents. In the event the Railcars are held to constitute infringement for which FreightCar has agreed to indemnify Purchaser hereunder and the use of the Railcars, or any part thereof, is enjoined, FreightCar shall, at its option and expense, either procure for Purchaser the right to continue using said Railcar, replace same with non-infringing equipment of like kind and quality, modify said Railcar so that it becomes non-infringing or refund the purchase price of said Railcar (following the return of such Railcar by Purchaser to FreightCar’s Plant).
Assignment: Neither FreightCar nor Purchaser may assign all or any portion of its rights or obligations under this Agreement without the prior written approval of the other party, which shall not be unreasonably withheld; provided, however, that notwithstanding the foregoing, FreightCar may assign its right to receive any or all payments due hereunder to a third party without the approval of Purchaser. In connection with Purchaser’s financing of the Railcars, Purchaser shall provide to FreightCar sufficient opportunity to review and approve any assignment documents which the financing source requests be executed by FreightCar. Such assignment documents shall provide that (i) Purchaser shall remain liable to FreightCar in accordance with this Agreement (including, without limitation, the obligation to pay the purchase price for the Railcars) to the extent such obligations are not fully and timely performed by such assignee, and (ii) nothing contained in such assignment shall be deemed to modify FreightCar’s rights or obligations under this Agreement.
Binding Effect: This Agreement shall be binding upon and inure to the benefit of FreightCar and Purchaser and to their respective successors and permitted assigns.
Notices: All notices, demands, requests and other communications required or permitted under this Agreement shall be in writing or by a telecommunications device capable of creating a written record, and shall become effective :  (a) upon personal delivery thereof, including, without limitation, by overnight mail and courier service, (b) five (5) days after the date on which it shall have been mailed by United States mail (certified mail, postage prepaid, return receipt requested), or (c) in the case of a communication by a telecommunications device, when properly transmitted during normal business hours (or if not, then on the following business day) addressed to each party at its address or facsimile number set forth on the signature page of the body of this Agreement or at such other address or facsimile number as such party may have specified previously by notice delivered in accordance with this section.
Entire Agreement; No Third Party Beneficiaries: This Agreement (which includes these Terms and Conditions of Sale, the Proposal Letter and the Specifications and the exhibits and attachments hereto and thereto) contains the entire agreement of FreightCar and Purchaser with respect to the subject matter hereof and supersedes all prior written or oral agreements of the parties. This Agreement is not intended to confer upon

 
any person other than the parties hereto, any rights or remedies, and shall not be enforceable by any person or entity who or which is not a party hereto.
Professional Fees and Brokerage Fees: Each party to this Agreement shall be responsible for all professional fees and brokerage fees, if any, incurred by such party in connection with the transaction evidenced by this Agreement.
Disclaimer of Special or Punitive Damages: Notwithstanding anything in this Agreement to the contrary, in no event shall any party to this Agreement be obligated to any other party for any punitive or special damages arising from any breach or violation of this Agreement.
Severability: Any provision of this Agreement that is inoperative, unenforceable or invalid in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of the operation, unenforceability or invalidity without affecting the remaining provisions of this Agreement or affecting the operation, enforceability or validity of that provision in any other jurisdiction.
Amendments, Waiver: None of the terms of this Agreement may be waived or modified except in writing signed by both FreightCar and Purchaser. Any additional or different terms or conditions proposed by Purchaser are rejected unless expressly assented to in writing by FreightCar. No waiver of any of the provisions of this Agreement by either party shall constitute a waiver of any other provision nor shall any such waiver constitute a continuing waiver.
Miscellaneous: The section headings contained in this Agreement are intended solely for convenience of reference and shall be given no effect in the construction or interpretation of this Agreement. This Agreement may be executed in multiple counterpart copies, all of which taken together shall be deemed one original for all purposes.
Governing Law and Jurisdiction: This Agreement shall be governed by, and construed according to, the laws of the State of Illinois, without regard to its conflict of laws doctrine. FreightCar and Purchaser hereby submit to the jurisdiction of, and waive any venue objections against, the United States District Court for the Northern District of Illinois (or any court of the State of Illinois located in such district) in any litigation arising out of this Agreement.
Interpretation: To the extent there is a conflict between the provisions of the Proposal Letter and these Terms and Conditions of Sale, the provisions of the Proposal Letter shall govern.
[SIGNATURE PAGE TO FOLLOW]

 
ACCEPTANCE:
FreightCar and Purchaser hereby acknowledge their acceptance of the above described Terms and Conditions of Sale.
 	 	 	 	 	 	 	 	 	 	 	
FREIGHTCAR AMERICA, INC.	 	TEXAS GENCO II, LP	 	 	
 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	By:	 	New Genco GP, LLC, its general partner	 	 	
 	 	 	 	 	 	 	 	 	 	 	
By:	 	/s/ Sean Hankinson	 	 	 	By:	 	/s/ Jack Fusco	 	 	
Its:	 	  Product Line Manager	 	 	 	Its:	 	  Jack Fusco, President	 	 	
 	 	 	 	 	 	 	 	 	 	 	
Date:	 	October 5, 2005	 	 	 	Date:	 	September 30, 2005	 	 	

 	 	 	
Address:	 	Address:	
FreightCar America, Inc.	 	Texas Genco II, LP	
17 Johns Street	 	1301 McKinney, Suite 2300	
Johnstown, PA 15901	 	Houston, TX 77010	
Attention: Sean Hankinson, Product Line Manager	 	Attention: Colin Gibb, Transportation Specialist	
Fax: 814/533-5010	 	Fax: 713/795-7441	

 
EXHIBIT A
CERTIFICATE OF ACCEPTANCE
 	 	 	 	 	
Type of Railcars:	 	 	 	 	
 	 	 	 	
Place Accepted:	 	 	 	 	
 	 	 	 	
Date Accepted:	 	 	 	 	
 	 	 	 	
Number of Railcars:	 	 	 	 	
 	 	 	 	
Reporting Marks:	 	 	 	 	

 	 	 	 	 	 	 	
Car Numbers	 	Car Weights	 	Car Numbers	 	Car Weights	

 	 	 	 	 	 	 	

 	 	 	 	 	 	 	

 	 	 	 	 	 	 	
I have been appointed as the duly authorized representative of TEXAS GENCO II, LP (“Purchaser”) for the purpose of inspecting and accepting the units of railroad equipment described above (the “Railcars”), which are referred to in the agreement dated as of ___, 2005 (the “Agreement”), between FREIGHTCAR AMERICA, INC. (“Builder”) and Purchaser.
I hereby certify that with respect to the Railcars:
 	A.	 	Each Railcar has been inspected and is in good order.	
 	 	 	 	
 	B.	 	Based on my determination that each Railcar is in compliance with all applicable Specifications (as defined in the Agreement), each Railcar is hereby accepted for all purposes of the Agreement.	

 	 	 	 	 	
 	 	Authorized Representative of Purchaser	 	 	

 
EXHIBIT B
FINAL DELIVERY DATE FOR THE RAILCARS
***

 
EXHIBIT C
COMPONENT WARRANTIES
Attached are copies of warranties from the following manufacturers and suppliers:
ASF-Keystone, Inc.
ZefTek, Inc.
Cardwell Westinghouse Co./Universal Railway Devices Co.
A. Stucki Company
New York Air Brake Corporation
Miner Enterprises Inc.
Schaefer Equipment, Inc.
Strato
Klasing Industries, Inc. d/b/a Klasing Hand Brake Company
Union Spring & Manufacturing Corp.
Holland
Brenco
Standard Forged Products, Inc.
Additional warranties may be added from time to time.

 
August 31, 2005
FreightCar America Inc.
17 Johns Street
Johnstown, PA 15901
 	 	 	
Re:	 	Aluminum BethGon® II Railcars for Texas Genco II, LP.,	
 	 	FreightCar America Inc. Proposal No. 04153 Revision A	
Gentlemen:
     Texas Genco II, LP (“Texas Genco”) hereby confirms that it intends to purchase (the “Transaction”) from FreightCar America Inc. (“FreightCar America”, and together with Texas Genco, the “Parties”, and each, a “Party”) an additional  ***  Aluminum Outside Stake BethGon II ®  open top coal railcars conforming to Specification X-04153 dated February 14, 2005 (“Specification”), and provided by FreightCar America (f/k/a Johnstown America Corporation) to Texas Genco, for a total of  ***  railcars. The price per railcar shall be as outlined in your proposal dated March 4, 2005, FOB FreightCar America’s plant in  ***  . Delivery shall begin no later than the first week of  ***  2006 for the first  ***  railcars. An additional delivery of  ***  railcars shall occur in  ***  and ***  2006. An additional delivery of  ***  railcars and a final delivery of  ***  railcars shall be completed by  ***  2006 and ***  2007, respectively.
     The Transaction is subject to mutual agreement between Texas Genco and FreightCar America on the terms and conditions of the Transaction, including pricing on, and changes to, the Specialty Component List. Accordingly, the Parties intend that no legally binding obligations shall arise between them under this letter. Such obligations shall arise only to the extent set forth in a purchase agreement duly executed and delivered by each Party. Notwithstanding the foregoing, unless and until the negotiations required by the following sentence have been had and discontinued, FreightCar America shall not enter into any agreement that would require it to deliver railcars to any third party on a schedule that would prevent it from delivering the railcars contemplated by this letter to Texas Genco on the schedule set forth above. Notwithstanding the aforementioned required board approval, Texas Genco and FreightCar America shall use commercially reasonable efforts to negotiate and agree on the terms and conditions within 30 days of the date of this letter. Should the Parties fail to enter into such terms and conditions within 30 days of the date of this letter, FreightCar America shall not be barred from entering into an agreement that would require it to deliver railcars to a third party on a schedule that would prevent it from delivering the railcars according to the schedule contemplated by the Parties.
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     Please confirm by signing a copy of this letter in the space provided below and returning it to the undersigned that this letter of intent is sufficient to allow FreightCar America to take all action required to assure that the railcars that are the subject of the Transaction can be delivered on the schedule set forth above.
     Please call if you have any questions or would like to discuss the matter.
 	 	 	 	 	 	 	 	 	 	 	
FREIGHTCAR AMERICA INC.	 	 	 	TEXAS GENCO II, LP	 	 	
 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	By: New Genco GP, LLC, its general partner	 	 	
 	 	 	 	 	 	 	 	 	 	 	
By:	 	/s/Tim Johnson	 	 	 	By:	 	/s/Tyler Reeder	 	 	
 	 	 	 	 	 	 	 	 	 	 	
Name: Tim Johnson	 	 	 	Name: Tyler Reeder	 	 	
Title: VP — Sales, Western Region	 	 	 	Title: 8/31/05	 	 	
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Exhibit 10.33
EMPLOYMENT AGREEMENT
Between
NRG Energy, Inc.
and
David W. Crane
     THIS AGREEMENT is made as of March 3, 2006, between NRG Energy, Inc. (the “Company”), and David W. Crane (“Executive”).
     WHEREAS, the Company has employed the Executive as its President and Chief Executive Officer since December 1, 2003, pursuant to the terms of an Employment Agreement (“Original Agreement”), scheduled to expire by its terms on December 1, 2006; and
     WHEREAS, the parties wish to extend and modify the Original Agreement to more accurately reflect current circumstances.
     NOW, THEREFORE, in consideration of the mutual covenants contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
     1. Employment. The Company shall continue to employ Executive, and Executive hereby agrees to continue in employment with the Company, upon the terms and conditions set forth in this Agreement for the period beginning on March 3, 2006 (the “Effective Date”) and ending as provided in Section 5 hereof (the “Employment Period”).

 
     2. Position and Duties.
     (a) During the Employment Period, Executive shall serve as the President and Chief Executive Officer (“CEO”) of the Company and shall have the normal duties, responsibilities, functions and authorities customarily exercised by the President and CEO of a company of similar size and nature as the Company. During the Employment Period, Executive shall render such administrative, financial and other executive and managerial services to the Company and its affiliates which are consistent with Executive’s position, as the Board of Directors of the Company (the “Board”) may from time to time direct.
     (b) During the Employment Period, Executive shall report to the Board and shall devote his best efforts and his full business time and attention (except for permitted vacation periods and reasonable periods of illness or other incapacity) to the business and affairs of the Company. Executive shall perform his duties, responsibilities and functions to the Company hereunder to the best of his abilities in a diligent, trustworthy, professional and efficient manner and shall comply with the Company’s policies and procedures in all material respects. In performing his duties and exercising his authority under this Agreement, Executive shall support and implement the business and strategic plans approved from time to time by the Board. During the Employment Period, Executive shall not serve as an officer or director of, or otherwise perform services for compensation for, any other entity without the prior written consent of the Board. Executive may serve as an officer or director of, or otherwise participate in, purely educational, welfare, social, religious and civic organizations so long as such activities do not interfere with Executive’s employment. Nothing contained herein shall preclude Executive from (i) engaging in charitable and community activities; (ii) participating in industry and trade organization activities; (iii) managing his and his family’s personal investments and
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affairs; and (iv) delivering lectures, fulfilling speaking engagements or teaching at educational institutions; provided, that such activities do not materially interfere with the regular performance of his duties and responsibilities under this Agreement.
          3. Compensation and Benefits.
          (a) Beginning on the Effective Date, and ending on December 31, 2006, Executive’s annual base salary shall be One Million Dollars ($1,000,000.00). For each subsequent annual period thereafter, the Executive’s annual base salary shall be reviewed by the Board, which shall determine whether to grant an increase (such initial annual base salary and the annual base salary as determined and adjusted upward from time to time by the Board are referred to herein as the “Base Salary”). The Base Salary shall be payable by the Company in regular installments in accordance with the Company’s general payroll practices (in effect from time to time) but in any event no less frequently than monthly. For purposes of this Agreement, the Base Salary shall not include any other type of compensation or benefit paid or payable to the Executive.
          (b) Bonuses and Incentive Compensation.
          (i) Annual Bonus. Beginning for fiscal year 2006 and for each fiscal year thereafter during the Employment Period, based on achievement of criteria determined by the Board as soon as administratively practicable following the beginning of each such fiscal year with input from Executive, Executive will be entitled to an annual bonus with a target amount equal to 100% of the Executive’s then Base Salary (the “Annual Bonus”). The Company shall pay the Annual Bonus in a single cash lump-sum after the end of the Company’s fiscal year in accordance with procedures established
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by the Board, but in no event later than two and one-half months after the end of such fiscal year.
          (ii) Maximum Bonus. In addition to the Annual Bonus referenced in paragraph 3(b)(i), beginning for fiscal year 2006 and for each fiscal year thereafter during the Employment Period, based on achievement of criteria determined by the Board as soon as administratively practicable following the beginning of each such fiscal year with input from Executive, Executive shall be eligible to receive a “maximum bonus” in an amount up to, but not exceeding, 100% of Executive’s then Base Salary (the “Maximum Bonus”). The Company shall pay the Maximum Bonus in a single cash lump-sum following the end of the Company’s fiscal year in accordance with procedures established by the Board, but in no event later than two and one-half months after the end of such fiscal year.
          (iii) Long Term Incentive. The Company has previously provided Executive with a combination of restricted stock or units (“restricted stock”) and stock options (the “Executive LTIP”), pursuant to paragraph 3(b)(iv) of the Original Agreement, which is incorporated herein by reference. The Executive LTIP shall be governed by the terms of paragraph 3(b)(iv) of the Original Agreement and the applicable award agreements entered into by the Company and the Executive. In addition, Executive shall be eligible to participate in the NRG Energy, Inc. Long-Term Incentive Plan, on such terms and conditions as are stated therein.
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          (c) During the Employment Period, the Company shall promptly reimburse Executive for all reasonable business expenses incurred by him in the course of performing his duties and responsibilities under this Agreement which are consistent with the Company’s policies in effect from time to time with respect to travel, entertainment and other business expenses, subject to the Company’s requirements with respect to reporting and documentation of such expenses. The Company will promptly reimburse Executive for reasonable expenses incurred for annual tax return preparation, and ongoing tax advice and financial planning, and for reasonable legal expenses incurred in connection with negotiating this Agreement and the other agreements referred to herein.
          (d) In addition to the Base Salary and any bonuses and incentives payable to Executive pursuant to this Section 3, Executive shall also be entitled to the following benefits during the Employment Period, unless otherwise modified by the Board:
          (i) participation in the Company’s retirement plans, health and welfare plans and disability insurance plans, under the terms of such plans and to the same extent and under the same conditions such participation and coverages are provided to other senior management of the Company;
          (ii) term life insurance with a death benefit of $7.75 million through the continuation of the term life insurance provided to Executive by his former employer (other than adjustable rate life insurance) immediately prior to the Executive’s employment with the Company;
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          (iii) prompt reimbursement of the costs, not to exceed $10,000 per year, Executive incurs in obtaining additional disability insurance coverage with a monthly disability benefit of up to $30,000;
          (iv) five weeks paid vacation each calendar year; and
          (v) coverage under the Company’s director and officer liability insurance policy.
          4. Board Membership. With respect to all regular elections of directors during the Employment Period, the Company shall nominate, and use its reasonable efforts to cause the election of, Executive to serve as a member of the Board. Effective upon the termination or expiration of the Employment Period, Executive shall resign as a director of the Company and its affiliates, as the case may be.
          5. Termination.
          (a) The Employment Period shall end on December 31, 2008, provided, however, that the Employment Period shall be automatically renewed for successive one-year terms thereafter on the same terms and conditions set forth herein unless either party provides the other party with notice that it has elected not to renew the Employment Period at least 90 days prior to the end of the initial Employment Period or any subsequent extension thereof. Notwithstanding the foregoing, (i) the Employment Period shall terminate immediately upon Executive’s resignation (with or without “Good Reason,” as defined in the Company’s Executive Change in Control and General Severance Plan, as in effect from time to time (the “Severance Plan”)), death or Disability (as defined herein) or (ii) the Employment Period may be terminated by the
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Company at any time prior to such date for “Cause” (as defined in the Severance Plan) or without Cause. Except as otherwise provided herein, any termination of the Employment Period by the Company shall be effective as specified in a written notice from the Company to Executive, but in no event more than 30 days from the date of such notice.
          (b) For purposes of this Agreement, the definition of Good Reason shall also include the following:
          (i) any failure by the Company to comply with any of the provisions of this Agreement, other than any isolated, insubstantial and inadvertent failure not occurring in bad faith and which is remedied by the Company promptly after receipt of written notice thereof given by the Executive; or
          (ii) any failure to elect Executive to the Board at any regular election of directors during the Employment Period, or any removal of Executive from the Board, for any reason, during the Employment Period; or
          (iii) a change in reporting structure of the Company where Executive is required to report to someone other than the Board.
          6. Severance.
          (a) Termination without Cause or for Good Reason.
          (i) In the event of Executive’s termination of employment with the Company (i) by the Company without Cause, (ii) by Executive for Good Reason or (iii) if the Company notifies Executive pursuant to Section 5 that it has elected not to renew this Agreement after the initial term or any subsequent one-year term, Executive shall be
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entitled to the severance benefits set forth below in Section 6(a)(ii); provided, however, if such termination of employment or election of non-renewal occurs within twenty-four (24) months immediately following a “Change in Control” (as defined in the Severance Plan) of the Company, Executive shall in lieu of the severance benefits provided under Section 6(a)(ii) hereof become entitled to the severance benefits set forth below in Section 6(a)(iii).
          (ii) As a condition to the payment of the following severance benefits, the Executive shall execute and deliver the “Release” in the form attached hereto as Exhibit A, in consideration for which the Company agrees to the following:
 	(A)	 	The Company shall pay Executive, within 45 days after termination of employment, a lump-sum cash payment in an amount equal to two times the Executive’s annual Base Salary (as in effect at the date of Executive’s termination determined without regard to any reduction in such Base Salary constituting Good Reason).	
 	 	 	 	
 	(B)	 	The Company shall pay Executive, within 45 days after termination of employment, a lump-sum payment in an amount equal to 50% of his target Annual Bonus then in effect (excluding the Maximum Bonus but determined without regard to any reduction in such target Annual Bonus constituting Good Reason) pro-rated for the number of days during such year that Executive was employed by the Company.	
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 	(C)	 	All restricted stock, stock options and other equity awards granted under the Executive LTIP, described in paragraph 3(b)(iv) of the Original Agreement, shall vest in full on the date of such termination of employment, and all stock options shall continue to be exercisable for the remainder of their stated terms.	
 	 	 	 	
 	(D)	 	For eighteen (18) months from the date of termination (the “Benefits Continuation Period”), the Company shall arrange to provide Executive and his dependents, at the Company’s cost, medical and dental coverage providing substantially similar benefits to those which Executive and his dependents were receiving immediately prior to such date. Notwithstanding the foregoing, the period for which Executive’s eligibility for COBRA benefits continuation coverage is measured shall commence upon Executive’s termination of employment and shall run concurrently with the Benefits Continuation Period.	
 	 	 	 	
 	(E)	 	The Company shall pay Executive the amounts described in Section 6(d).	
           (iii)   As a condition to the payment of the following severance benefits, the Executive shall execute and deliver the “Release” in the form attached hereto as Exhibit A, in consideration for which the Company agrees to the following:
 	(A)	 	The Company shall pay Executive, within 45 days after termination of employment, a lump-sum cash payment in an	
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 	 	 	amount equal to two and ninety-nine one-hundredths (2.99) times the sum of the following: (x) Executive’s annual Base Salary (as in effect at the date of Executive’s termination determined without regard to any reduction in such Base Salary constituting Good Reason) and (y) Executive’s target Annual Bonus (excluding the Maximum Bonus but determined without regard to any reduction in such target Annual Bonus constituting Good Reason) for the year in which the termination of employment occurs.	
 	 	 	 	
 	(B)	 	The Company shall pay Executive, within 45 days after termination of employment, a lump-sum cash payment in an amount equal to Executive’s then current target Annual Bonus (excluding the Maximum Bonus but determined without regard to any reduction in such target Annual Bonus constituting Good Reason) for the year in which the termination of employment occurs, adjusted on a pro rata basis based on the number of days Executive was actually employed during the year in which the termination of employment occurs.	
 	 	 	 	
 	(C)	 	All restricted stock, stock options and other equity awards granted under the Executive LTIP, described in paragraph 3(b)(iv) of the Original Agreement, shall vest in full on the date of such termination of employment, and all stock options shall continue to be exercisable for the remainder of their stated terms.	
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 	(D)	 	For eighteen (18) months from the date of termination (the “Change in Control Benefits Continuation Period”), the Company shall arrange to provide Executive and his dependents, at the Company’s cost, medical and dental coverage providing substantially similar benefits to those which Executive and his dependents were receiving immediately prior to such date. Notwithstanding the foregoing, the period for which Executive’s eligibility for COBRA benefits continuation coverage is measured shall commence upon Executive’s termination of employment and shall run concurrently with the Change in Control Benefits Continuation Period.	
 	 	 	 	
 	(E)	 	The Company shall pay Executive the amounts described in Section 6(d).	
          (iv) Notwithstanding anything in this Section 6(a) to the contrary, the benefits provided pursuant to Section 6(a)(ii)(D) and Section 6(a)(iii)(D) shall be discontinued prior to the end of the Benefits Continuation Period or Change in Control Benefits Continuation Period, as applicable, in the event Executive receives substantially similar benefits from a subsequent employer, as determined by the Company in good faith. Executive shall be deemed to have a duty to inform the Company as to the terms and conditions of any subsequent employment and the corresponding benefits earned from such employment, and shall provide, or cause to be provided, to the Company in writing correct, complete and timely information concerning the same.
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          (v) Notwithstanding anything herein to the contrary, if Executive is a “specified employee” (within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”)) as of his termination of employment, then to the extent necessary to comply with the requirements of Section 409A of the Code, no payment due Executive under this Section 6(a) shall be made earlier than the date that is six months following Executive’s termination of employment, at which time all payments that would otherwise have been made within that six month period shall be paid to Executive in a lump sum.
          (b) Termination for Cause or Voluntary Resignation. In the event Executive’s employment with the Company is terminated (i) by the Board for Cause (as defined herein), or (ii) by Executive’s resignation from the Company for any reason other than Good Reason or Disability the Company agrees to the following:
 	(A)	 	The Company shall pay Executive the amounts described in Section 6(d).	
 	 	 	 	
 	(B)	 	The Company shall treat all restricted stock, stock options and other equity awards outstanding under the Executive LTIP or any other Company equity plans in accordance with the terms of the plans or agreements under which such awards were created or maintained. If Executive resigns from the Company for any reason on or after November 10, 2006, all stock options granted under the Executive LTIP will remain exercisable for the remainder of their stated terms.	
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          (c) Death or Disability. In the event that Executive’s employment with the Company is terminated as a result of Executive’s death or Disability, the Company agrees to the following:
 	(A)	 	The Company shall pay Executive, or his estate or legal representative, within fifteen (15) days after such termination, a lump-sum payment in an amount equal to 50% of the target Annual Bonus then in effect (excluding the Maximum Bonus but determined without regard to any reduction in such target Annual Bonus constituting Good Reason) pro-rated for the number of days during such year that Executive was employed by the Company. Any stock options granted under the Executive LTIP that have vested will remain exercisable for the remainder of their stated terms.	
 	 	 	 	
 	(B)	 	If the Executive is terminated as a result of his death or Disability prior to December 1, 2006, his “restricted stock” (as defined above) shall vest on a pro rata basis (based on the ratio of (x) the number of complete months beginning on the Commencement Date (as such term is defined in the Original Agreement) and ending on the date of Executive’s termination of employment to (y) thirty-six (36)).	
 	 	 	 	
 	(C)	 	The Company shall treat all stock options under the Executive LTIP or other equity under any other Company plans in	
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 	 	 	accordance with the terms of the plans or agreements under which such awards were created or maintained.	
 	 	 	 	
 	(D)	 	The Company shall pay Executive the amounts described in Section 6(d).	
For purposes of this Section 6(c), “Disability” shall mean “disabled” as defined in Section 409A(a)(2)(C) of the Code and the regulations promulgated thereunder. Executive shall cooperate in all respects with the Company if a question arises as to whether he has become disabled (including, without limitation, submitting to an examination by a medical doctor or other health care specialists selected by the Company and reasonably acceptable to Executive and authorizing such medical doctor or such other health care specialist to discuss Executive’s condition with the Company).
          (d) In the case of any termination of Executive’s employment with the Company, Executive or his estate or legal representative shall be entitled to receive from the Company (i) Executive’s Base Salary through the date of termination to the extent not theretofore paid, (ii) to the extent not theretofore paid and not otherwise addressed in this Section 6, the amount of any bonus, incentive compensation, deferred compensation and other compensation earned or accrued by Executive as of the date of termination under any compensation and benefit plans, programs or arrangements maintained in force by the Company (for this purpose, Executive’s Annual Bonus, if any, for any fiscal year shall be deemed to have accrued on the last day of such fiscal year), (iii) any vacation pay, expense reimbursements and other cash entitlements accrued by Executive, in accordance with Company policy, as of the date of termination to the extent not theretofore paid, and (iv) all benefits accrued by Executive under all benefit plans and qualified and nonqualified retirement, pension, 401(k) and similar plans and arrangements of the
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Company, in such manner and at such time as are provided under the terms of such plans and arrangements. In the event Executive becomes entitled to receive the benefits described in Section 6(a) hereof, such benefits shall be in lieu of other compensation to which Executive may have been entitled pursuant to all other agreements and plans, including without limitation, the Severance Plan.
          (e) No Other Payments. Except as provided in (a), (b), (c) or (d) above, all of Executive’s rights to salary, bonuses, employee benefits and other compensation hereunder which would have accrued or become payable after the termination or expiration of the Employment Period shall cease upon such termination or expiration, other than those expressly required under applicable law.
          (f) No Mitigation, Et Cetera. In the event of Executive’s termination of employment for whatever reason or in the event of breach of this Agreement by the Company, Executive shall be under no obligation to seek other employment or to otherwise mitigate his damages.
          (g) Offset. The Company may offset, to the fullest extent of the law, any amounts due to the Company from the Executive, or advanced or loaned to the Executive by the Company, from any monies owed to Executive or Executive’s estate by reason of his termination of employment.
          7. Indemnification.
          (a) The Company agrees that (i) if Executive is made a party, or is threatened to be made a party, to any threatened or actual action, suit or proceeding, whether civil, criminal,
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administrative, investigative, appellate or other (each, a “Proceeding”) by reason of the fact that he is or was a director, officer, employee, agent, manager, consultant or representative of the Company or is or was serving at the, request of the Company as a director, officer, member, employee, agent, manager, consultant or representative of another entity or (ii) if any claim, demand, request, investigation, dispute, controversy, threat, discovery request or request for testimony or information (each, a “Claim”) is made, or threatened to be made, that arises out of or relates to Executive’s service in any of the foregoing capacities, then Executive shall promptly be indemnified and held harmless by the Company to the fullest extent legally permitted or authorized by the Company’s certificate of incorporation, bylaws or Board resolutions or, if greater, by the laws of the State of Delaware, against any and all costs, expenses, liabilities and losses (including, without limitation, attorney’s fees, judgments, interest, expenses of investigation, penalties, fines, ERISA excise taxes or penalties and amounts paid or to be paid in settlement) incurred or suffered by the Executive in connection therewith, and such indemnification shall continue as to Executive even if he has ceased to be a director, member, employee, agent, manager, consultant or representative of the Company or other entity and shall inure to the benefit of Executive’s heirs, executors and administrators. The Company shall advance to Executive all costs and expenses incurred by him in connection with any such Proceeding or Claim within 15 days after receiving written notice requesting such an advance. Such notice shall include, to the extent required by applicable law, an undertaking by Executive to repay the amount advanced if he is ultimately determined not to be entitled to indemnification against such costs and expenses.
          (b) Neither the failure of the Company (including the Board, independent legal counsel or stockholders) to have made a determination in connection with any request for
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indemnification or advancement under Section 7(a) that Executive has satisfied any applicable standard of conduct nor a determination by the Company (including the Board, independent legal counsel or stockholders) that Executive has not met any applicable standard of conduct, shall create a presumption that Executive has or has not met an applicable standard of conduct.
          8. Gross-up. In the event that any payment or benefit made or provided to or for the benefit of Executive in connection with this Agreement or his employment with the Company or the termination thereof (a “Payment”) is determined to be subject to any excise tax (“Excise Tax”) imposed by Section 4999 of the Code (or any successor to such Section), the Company shall pay to Executive, prior to the time any Excise Tax is payable with respect to such Payment (through withholding or otherwise), an additional amount (a “Gross-Up Payment”) which, after the imposition of all income, employment, excise and other taxes, penalties and interest thereon, is equal to the sum of (i) the Excise Tax on such Payment plus (ii) any penalty and interest assessments associated with such Excise Tax. The determination of whether any Payment is subject to an Excise Tax and, if so, the amount and time of any Gross-Up Payment pursuant to this Section 8 shall be made by an independent auditor (the “Auditor”) jointly selected by the parties and paid by the Company. Unless Executive agrees otherwise in writing, the Auditor shall be a nationally recognized United States public accounting firm that has not, during the two years preceding the date of its selection, acted in any way on behalf of the Company or any of its affiliates. If the parties cannot agree on the firm to serve as the Auditor, then the parties shall each select one accounting firm and those two firms shall jointly select the accounting firm to serve as the Auditor. The parties shall cooperate with each other in connection with any Proceeding or Claim relating to the existence or amount of any liability for Excise Tax. All expenses relating to any such Proceeding or Claim (including attorneys’ fees
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and other expenses incurred by Executive in connection therewith) shall be paid by the Company promptly upon demand by Executive, and any such payment shall be subject to a Gross-Up Payment under this Section 8 in the event that Executive is subject to Excise Tax on such payment. This Section 8 shall apply irrespective of whether a Change of Control has occurred.
          9. Confidential Information.
          (a) Executive acknowledges that the information, observations and data (including trade secrets) obtained by him while employed by the Company concerning the business or affairs of the Company or any of its affiliates (“Confidential Information”) are the property of the Company or such affiliate. Therefore, except in the course of Executive’s duties to the Company or as may be compelled by law or appropriate legal process, Executive agrees that he shall not disclose to any person or entity or use for his own purposes any Confidential Information or any confidential or proprietary information of other persons or entities in the possession of the Company and its affiliates (“Third Party Information”), without the prior written consent of the Board, unless and to the extent that the Confidential Information or Third Parry Information becomes generally known to and available for use by the public other than as a result of Executive’s acts or omissions. Except in the course of Executive’s duties to the Company or as may be compelled by law or appropriate legal process, Executive will not, during his employment by the Company, or permanently thereafter, directly or indirectly use, divulge, disseminate, disclose, lecture upon, or publish any Confidential Information, without having first obtained written permission from the Board to do so. Executive shall deliver to the Company at the termination or expiration of the Employment Period, or at any other time the Company may reasonably request, all memoranda, notes, plans, records, reports, computer files, disks and tapes, printouts and software and other documents and data (and copies thereof) embodying or relating
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to Third Party Information, Confidential Information or the business of the Company, or its affiliates which he may then possess or have under his control. Notwithstanding the foregoing, the Company hereby waives the right to assert an “inevitable disclosure” argument in any legal proceeding against Employee after the termination of his employment.
          (b) Executive shall be prohibited from using or disclosing any confidential information or trade secrets that Executive may have learned through any prior employment. If at any time during his employment with the Company or any of its affiliates, Executive believes he is being asked to engage in work that will, or will be likely to, jeopardize any confidentiality, or other obligations Executive may have to former employers, Executive shall immediately advise the Board so that Executive’s duties can be modified appropriately. Executive represents and warrants to the Company that Executive took nothing with him which belonged to any former employer when Executive left his prior position and that Executive has nothing that contains any information which belongs to any former employer. If at any time Executive discovers this is incorrect, Executive shall promptly return any such materials to Executive’s former employer. The Company does not want any such materials, and Executive shall not be permitted to use or refer to any such materials in the performance of Executive’s duties hereunder.
          10. Intellectual Property, Inventions and Patents. Executive acknowledges that all discoveries, concepts, ideas, inventions, innovations, improvements, developments, methods, trade secrets, designs, analyses, drawings, reports, patent applications, copyrightable work and mask work (whether or not including any confidential information) and all registrations or applications related thereto, all other proprietary information and all similar or related information (whether or not patentable) which may relate to the Company’s or any of its
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affiliates’ actual or anticipated business, research and development or existing or future products or services and which are conceived, developed or made by Executive (whether alone or jointly with others) while employed by the Company and its affiliates (“Work Product”), belong to the Company or such affiliate. Executive shall promptly disclose such Work Product to the Board and, at the Company’s expense, perform all actions reasonably requested by the Board (whether during or after the Employment Period) to establish and confirm such ownership (including, without limitation, assignments, consents, powers of attorney and other instruments). Executive acknowledges that all applicable Work Product shall be deemed to constitute “works made for hire” under the U.S. Copyright Act of 1976, as amended. To the extent any Work Product is not deemed a work made for hire, then Executive hereby assigns to the Company or such affiliate all right, title and interest in and to such Work Product, including all related intellectual property rights.
          11. Non-Compete, Non-Solicitation.
          (a) In further consideration of the compensation to be paid to Executive hereunder, Executive acknowledges that during the course of his employment with the Company and its affiliates he shall become familiar with the Company’s trade secrets and with other Confidential Information concerning the Company and its affiliates and that his services shall be of special, unique and extraordinary value to the Company and its affiliates, and therefore, Executive agrees that, during the Employment Period and for one (1) year thereafter (the “Noncompete Period”), he shall not directly or indirectly own any interest in, manage, control, participate in, consult with, render services for, be employed in an executive, managerial or administrative capacity by, or in any manner engage in any company engaged in a business that competes with any businesses of the Company or its affiliates, as such businesses exist or are in
20

 
process during the Employment Period or on the date of the termination or expiration of the Employment Period, within any geographical area in which the Company or its affiliates engage or have definitive plans to engage in such businesses. Nothing herein shall prohibit Executive from being a passive owner of not more than 2% of the outstanding stock of any class of a corporation which is publicly traded, so long as Executive has no active participation in the business of such corporation. Notwithstanding the foregoing, the provisions of this Section 11(a) shall not apply in the case of any material breach of the Company’s obligations under Section 6 or Section 7 which remains uncured for more than twenty (20) days after notice is received from Executive of such breach, which such notice shall include a detailed description of the grounds constituting such breach.
          (b) During the Noncompete Period, Executive shall not directly or indirectly through another person or entity (i) induce or attempt to induce any employee of the Company or any of its affiliates to leave the employ of the Company or such affiliate, or in any way interfere with the relationship between the Company or any affiliate and any employee thereof, (ii) hire any person who was an employee of the Company or any affiliate during the last six months of the Employment Period; or (iii) induce or attempt to induce any customer, supplier, licensee, licensor, franchisee or other business relation of the Company or any affiliate to cease doing business with the Company or such affiliate, or in any way interfere with the relationship between any such customer, supplier, licensee or business relation and the Company or any affiliate (including, without limitation, making any negative or disparaging statements or communications regarding the Company or its affiliates).
          (c) If, at the time of enforcement of this Section 11, a court shall hold that the duration, scope or area restrictions stated herein are unreasonable under circumstances then
21

 
existing, the parties agree that the maximum duration, scope or area reasonable under such circumstances shall be substituted for the stated duration, scope or area and that the court shall be allowed to revise the restrictions contained herein to cover the maximum period, scope and area permitted by law. Executive acknowledges that the restrictions contained in this Section 11 are reasonable and that he has reviewed the provisions of this Agreement with his legal counsel.
          (d) In the event of the breach or a threatened breath by Executive of any of the provisions of this Section 11, the Company would suffer irreparable harm, and in addition and supplementary to other rights and remedies existing in its favor, the Company shall be entitled to specific performance and/or injunctive or other equitable relief from a court of competent jurisdiction in order to enforce or prevent any violations of the provisions hereof (without posting a bond or other security). In addition, in the event of a breach or violation by Executive of Section 11(a), the Noncompete Period shall be automatically extended by the amount of time between the initial occurrence of the breach or violation and when such breach or violation has been duly cured.
          12. Executive’s Representations. Executive hereby represents and warrants to the Company that (i) the execution, delivery and performance of this Agreement by Executive do not and shall not conflict with, breach, violate or cause a default under any contract, agreement, instrument, order, judgment or decree to which Executive is a party or by which he is bound which has not been waived, (ii) Executive is not a party to or bound by any employment agreement, noncompete agreement or confidentiality agreement with any other person or entity which has not been waived, and (iii) on the Effective Date, this Agreement shall be the valid and binding obligation of Executive, enforceable in accordance with its terms. Executive hereby acknowledges and represents that he has consulted with independent legal counsel regarding his
22

 
rights and obligations under this Agreement and that he fully understands the terms and conditions contained herein.
          13. Survival. Sections 5 through 28, inclusive, shall survive and continue in full force in accordance with their terms notwithstanding the expiration or termination of the Employment Period.
          14. Notices. Any notice, communication or request provided for in this Agreement shall be in writing and shall be either personally delivered (with a written acknowledgement of receipt), sent by nationally recognized overnight courier service (with a written acknowledgement of receipt by the overnight courier) or mailed by certified or registered mail, return receipt requested, to the recipient at the address below indicated:
 	 	 	
 	 	Notices to Executive:	
 	 	 	
 	 	David Crane	
 	 	Orchard Hill	
 	 	3071 Lawrenceville Road	
 	 	Lawrenceville, NJ 08648	
 	 	 	
 	 	Notices to the Company:	
 	 	 	
 	 	Denise Wilson	
 	 	VP, Human Resources	
 	 	NRG Energy, Inc.
211 Carnegie Center	
 	 	Princeton, NJ 08540	
 	 	 	
 	 	Timothy O’Brien	
 	 	VP, General Counsel	
 	 	NRG Energy, Inc.	
 	 	211 Carnegie Center	
 	 	Princeton, NJ 08540	
23

 
or such other address or to the attention of such other person as the recipient party shall have specified by ten (10) days prior written notice to the sending party. Any notice under this Agreement shall be deemed to have been given when (i) when personally delivered, (ii) two (2) days after being sent by overnight courier or (iii) three (3) days after mailing by certified or registered mail.
          15. Severability. Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement is held to be invalid, illegal or unenforceable in any respect under any applicable law or rule in any jurisdiction, such invalidity, illegality or unenforceability shall not affect any other provision of this Agreement or any action in any other jurisdiction, but this Agreement shall be reformed, construed and enforced in such jurisdiction as if such, invalid, illegal or unenforceable provision had never been contained herein.
          16. Complete Agreement. This Agreement, those documents expressly referred to herein and other documents of even date herewith embody the complete agreement and understanding among the parties and supersede and preempt any prior understandings, agreements or representations by or among the parties, written or oral, which may have related to the subject matter hereof in any way. For the sake of clarity, except as otherwise specifically provided herein, this Agreement supersedes the Original Agreement.
          17. No Strict Construction. The language used in this Agreement shall be deemed to be the language chosen by the parties hereto to express their mutual intent, and no rule of strict construction shall be applied against any party.
24

 
          18. Counterparts. This Agreement may be executed in separate counterparts, each of which is deemed to be an original and all of which taken together constitute one and the same agreement.
          19. Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the beneficiaries, heirs and representatives of Executive and the successors and assigns of the Company. The Company shall require any successor (whether direct or indirect, by purchase, merger, reorganization, consolidation, acquisition of property or stock, liquidation, or otherwise) to all or a majority of its assets, by agreement in form and substance satisfactory to Executive, expressly to assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform this Agreement if no such succession had taken place. Regardless whether such agreement is executed, this Agreement shall be binding upon any successor of the Company in accordance with the operation of law and such successor shall be deemed the “Company” for purposes of this Agreement. Executive may not assign his rights (except by will or the laws of descent and distribution) or delegate his duties or obligations hereunder. Except as provided by this Section 19, this Agreement is not assignable by any party and no payment to be made hereunder shall be subject to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance or other charge.
          20. Choice of Law. All issues and questions concerning the construction, validity, enforcement and interpretation of this Agreement and the exhibits and schedules hereto shall be governed by, and construed in accordance with, the laws of the State of Delaware, without giving effect to any choice of law or conflict of law rules or provisions (whether of the State of Delaware or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of Delaware.
25

 
          21. Amendment and Waiver. The provisions of this Agreement may be amended, modified or waived only with the prior written consent of the Company and Executive, and no course of conduct or course of dealing or failure or delay by any party hereto in enforcing or exercising any of the provisions of this Agreement (including, without limitation, the Company’s right to terminate the Employment Period for Cause) shall affect the validity, binding effect or enforceability of this Agreement or be deemed to be an implied waiver of any provision of this Agreement.
          22. Insurance. The Company may, at its discretion, apply for and procure in its own name and for its own benefit life and/or disability insurance on Executive in any amount or amounts considered advisable. Executive agrees to cooperate in any medical or other examination, supply any information and execute and deliver any applications or other instruments in writing as may be reasonably necessary to obtain and constitute such insurance. Executive hereby represents that he has no reason to believe that his life is not insurable at rates now prevailing for healthy men of his age.
          23. Indemnification and Reimbursement of Payments on Behalf of Executive. The Company and its affiliates shall be entitled to deduct or withhold from any amounts owing from the Company or any of its affiliates to Executive any federal, state, local or foreign withholding taxes, excise tax, or employment taxes (“Taxes”) imposed with respect to Executive’s compensation or other payments from the Company or any of its affiliates or Executive’s ownership interest in the Company (including, without limitation, wages, bonuses, dividends, the receipt or exercise of equity options and/or the receipt or vesting of restricted equity). In the event the Company or any of its affiliates does not make such deductions or withholdings at the written request of the Executive, Executive shall indemnify the Company and
26

 
its affiliates for any amounts paid with respect to any such Taxes, together with any interest, penalties and related expenses thereto.
          24. Consent to Jurisdiction. EACH OF THE PARTIES IRREVOCABLY SUBMITS TO THE EXCLUSIVE JURISDICTION OF THE UNITED STATES DISTRICT COURT FOR THE DISTRICT OF DELAWARE, FOR THE PURPOSES OF ANY SUIT, ACTION OR OTHER PROCEEDING ARISING OUT OF THIS AGREEMENT, ANY RELATED AGREEMENT OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY. EACH OF THE PARTIES HERETO FURTHER AGREES THAT SERVICE OF ANY PROCESS, SUMMONS, NOTICE OR DOCUMENT IN COMPLIANCE WITH THE PROVISIONS OF PARAGRAPH 14 (NOTICE) SHALL BE EFFECTIVE SERVICE OF PROCESS FOR ANY ACTION, SUIT OR PROCEEDING WITH RESPECT TO ANY MATTERS TO WHICH IT HAS SUBMITTED TO JURISDICTION IN THIS SECTION 24. EACH OF THE PARTIES HERETO IRREVOCABLY AND UNCONDITIONALLY WAIVES ANY OBJECTION TO THE LAYING OF VENUE OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF THIS AGREEMENT, ANY RELATED DOCUMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY AND THEREBY IN THE UNITED STATES DISTRICT COURT FOR THE DISTRICT OF DELAWARE, AND HEREBY AND THEREBY FURTHER IRREVOCABLY AND UNCONDITIONALLY WAIVES AND AGREES NOT TO PLEAD OR CLAIM IN ANY SUCH COURT THAT ANY SUCH ACTION, SUIT OR PROCEEDING BROUGHT IN ANY SUCH COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM.
          25. Waiver of Jury Trial. AS A SPECIFICALLY BARGAINED FOR INDUCEMENT FOR EACH OF THE PARTIES HERETO TO ENTER INTO THIS
27

 
AGREEMENT (AFTER HAVING THE OPPORTUNITY TO CONSULT WITH COUNSEL), EACH PARTY HERETO EXPRESSLY WAIVES THE RIGHT TO TRIAL BY JURY IN ANY LAWSUIT OR PROCEEDING RELATING TO OR ARISING IN ANY WAY FROM THIS AGREEMENT OR THE MATTERS CONTEMPLATED HEREBY.
          26. Corporate Opportunity. During the Employment Period, Executive shall submit to the Board all business, commercial and investment opportunities or offers presented to Executive that relate to the business of the Company or its affiliates (“Corporate Opportunities”), if Executive wishes to accept or pursue, directly or indirectly, such Corporate Opportunities on Executive’s own behalf. This Section 26 shall not apply to purchases of publicly traded stock by Executive.
          27. Legal Costs. Except as otherwise agreed to by the parties, the Company shall pay the Executive for costs of litigation or other disputes including, without limitation, reasonable attorneys’ fees incurred by Executive in asserting any claims or defenses under this Agreement, except that Executive shall bear his own costs of such litigation or disputes (including, without limitation attorneys’ fees) if the court finds in favor of the Company with respect to any claims or defenses asserted by the Executive.
          28. Executive’s Cooperation. During the Employment Period and thereafter, Executive shall cooperate with the Company and its affiliates, upon the Company’s reasonable request, with respect to any internal, investigation or administrative, regulatory or judicial proceeding involving matters within the scope of Executive’s duties and responsibilities to the Company during the Employment Period (including, without limitation, Executive being available to the Company upon reasonable notice for interviews and factual investigations,
28

 
appearing at the Company’s reasonable request to give testimony without requiring service of a subpoena or other legal process, and turning over to the Company all relevant Company documents which are or may come into Executive’s possession during the Employment Period); provided, however, that any such request by the Company shall not be unduly burdensome or interfere with Executive’s personal schedule or ability to engage in gainful employment. In the event the Company requires Executive’s cooperation in accordance with this Section 28, the Company shall reimburse Executive for reasonable out-of-pocket expenses (including travel, lodging and meals) incurred by Executive in connection with such cooperation, subject to reasonable documentation. In addition, the Company shall compensate Executive at a rate of $500 per hour for the time in excess of one business day, per occurrence or event, that Executive reasonably spends complying with his obligations under this Section after the expiration of the Employment Period.
     IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.
 	 	 	 	 	 	
 	 	NRG ENERGY, INC.	 	
 	 	 	 	 	 	
 	 	By:	 	/s/ Howard Cosgrove	 	
 	 	 	 	 	 	
 	 	 	 	Howard Cosgrove	 	
 	 	 	 	Board Chairman	 	
 	 	 	 	 	 	
 	 	 	 	/s/ David W. Crane	 	
 	 	 	 	 	 	
 	 	 	 	David W. Crane	 	
 	 	 	 	President & CEO	 	
29

 
EXHIBIT A
GENERAL RELEASE
     In consideration of the payments and benefits (the “Severance Payment”) paid or to be paid to me pursuant to and in accordance with the terms of my Employment Agreement with NRG Energy, Inc. dated March 3, 2006 (the “Agreement”), on behalf of myself, my heirs, executors, administrators, successors, and assigns, I hereby fully and forever RELEASE and DISCHARGE NRG ENERGY, INC., its affiliates and their officers, directors, agents, employees, representatives, successors and assigns (hereinafter, collectively called the “Company”), from any and all claims and causes of action arising out of or relating in any way to my employment with the Company, including, but not limited to, the offer of employment and termination of my employment, and I agree that I will not in any manner institute, prosecute or pursue any complaints, claims, charges, liabilities, claims for relief, demands, suits, actions or causes of action against the Company that are covered by this RELEASE.
     Notwithstanding the foregoing, expressly excluded from this RELEASE are any claims or causes of action which I may have (i) seeking enforcement of my rights under the Agreement, including, without limitation, Sections 6, 7, 8 and 27 thereof, or any other plan, policy or arrangement of the Company, (ii) seeking to obtain contribution as permitted by applicable law in the event of the entry of judgment against me as a result of any act or failure to act for which

 
both I and the Company are held to be jointly liable, (iii) arising out of or relating in any way to acts or omissions after the date of this RELEASE or otherwise not covered by this RELEASE, and (iv) which cannot be waived by law. I shall also retain the right to seek indemnification from the Company, to the extent permitted under applicable law and Section 7 of the Agreement.
1. I understand and agree that, except as specifically provided above, this RELEASE is a full and complete waiver of all claims relating to my employment with the Company, including, but not limited to, claims of wrongful discharge, breach of contract, breach of the covenant of good faith and fair dealing, violation of public policy, defamation, personal injury and emotional distress, claims under Title VII of the Civil Rights Act of 1964, as amended, the Civil Rights Act of 1991, the Age Discrimination in Employment Act of 1967, as amended by the Older Workers Benefit Protection Act of 1990, the Americans With Disabilities Act, the Rehabilitation Act of 1973, as amended, the Equal Pay Act of 1963, Section 1981 of the Civil Rights Act of 1866, any of the Delaware State employment, discrimination or wage payment laws, the Fair Labor Standards Act of 1938, as amended, the Family and Medical Leave Act of 1993, and the Employee Retirement Income Security Act of 1974, as amended, claims arising from any legal restrictions on the Company’s right to terminate employees (including, without limitation, claims arising under various contract, tort, public policy or wrongful discharge theories under any federal, state or local law, or under the federal Worker Adjustment and Retraining Notification Act of 1988, as amended, or any similar state or local law), and any claims for attorney’s fees or costs.
2

 
2. I understand that I have received or will receive, regardless of the execution of this RELEASE, all amounts due to me pursuant to Sections 6(d), 7 and 8 of the Agreement. I further understand and agree that the Company will not provide me with any additional payments or benefits under the Agreement (including, without limitation, payments under Section 6(a) of the Agreement) unless I execute this RELEASE. In consideration of the execution of this RELEASE, I will receive additional payments and benefits specified in Section 6(a) of the Agreement.
3. In addition, and in further consideration of the foregoing, I acknowledge and agree that if I hereafter discover facts different from or in addition to those which I now know or believe to be true that this RELEASE shall be and remain effective in all respects notwithstanding such different or additional facts or the discovery thereof. I understand that this RELEASE does not waive or release any rights or claims that I may have under the Age Discrimination in Employment Act of 1967, as amended, which arise after the date I sign this RELEASE.
4. As part of my existing and continuing obligation to the Company, I have returned or, within seven (7) days of my termination will return to the Company all Confidential Information and Third Party Information (as such terms are defined in the Agreement) in accordance with the terms of the Agreement. I affirm my obligation to keep all Confidential Information confidential and not to disclose it to any third party as required by Section 9 of the Agreement.
5. I agree not to disclose, either directly or indirectly, any information whatsoever regarding (i) any of the terms or the existence of this RELEASE and my benefits under the Agreement or
3

 
(ii) any other claim I may have against the Company, to any person or organization, including but not limited to members of the press and media, present and former employees of the Company, companies who do business with the Company; or other members of the public. Notwithstanding the preceding sentence, I may reveal such terms of this RELEASE and the Severance Payment to my spouse, accountants or attorneys or as are necessary to comply with a request made by the Internal Revenue Service, as otherwise compelled by a court or agency of competent jurisdiction, as allowed and/or required by law.
6. This RELEASE shall be governed by the laws of the State of Delaware.
7. This RELEASE contains the entire agreement between the Company and me with respect to any matters referred to in the RELEASE and shall supersede any all other agreements, whether written or oral, with respect to such matters. I understand and agree that this RELEASE shall not be deemed or construed at any time as an admission of liability or wrongdoing by either myself or the Company. Notwithstanding the foregoing, it is understood and agreed that my termination will be treated for all purposes as a termination without Cause or for Good Reason under Section 6(a) of the Agreement and that I shall be entitled to all payments and benefits under the Agreement consistent with such a termination.
8. If any one or more of the provisions contained in this RELEASE is, for any reason, held to be unenforceable, that holding will not affect any other provision of this RELEASE, but, with respect only to the jurisdiction holding the provision to be unenforceable, this RELEASE shall
4

 
then be construed as if such unenforceable provision or provisions had never been contained therein.
9. Before executing this RELEASE, I obtained sufficient information to intelligently exercise my own judgment about the terms of the RELEASE. The Company has informed me in writing to consult an attorney before signing this RELEASE, if I wish.
I also understand for a period of fifteen (15) days after I sign this RELEASE, I may revoke this RELEASE and that the RELEASE will not become effective until fifteen (15) days after I sign it, and only then if I do not revoke it. In order to revoke this RELEASE, I must deliver, or cause to be delivered, to Denise Wilson; VP, Human Resources by First Class mail or facsimile 609-524-4530, by no later than fifteen (15) days after I execute this RELEASE, a letter stating that I am revoking it.
10. My severance and other termination benefits under the Agreement will be paid in accordance with the terms of the Agreement. If I choose to revoke this RELEASE within fifteen (15) days after I sign it, such benefits will not be due and payable, and the RELEASE will have no effect.
11. If I fail to comply with my agreement not to institute, prosecute or pursue any complaints, claims, charges, liabilities, claims for relief, demands suits or causes of actions against the Company (except as set forth in the second unnumbered paragraph at the beginning of this Release above, including, without limitation, any claims or causes of actions I may have
5

 
as a result of any acts or omissions that occur after the date of this Release), or if I materially and willfully fail to comply with the terms of Section 4 and 5 of this RELEASE, I will forfeit the additional payments and benefits due under the Agreement.
6

 
EMPLOYEE’S ACCEPTANCE OF RELEASE
BEFORE SIGNING MY NAME TO THIS RELEASE, I STATE THAT: I HAVE READ IT; UNDERSTAND IT AND KNOW THAT I AM GIVING UP IMPORTANT RIGHTS; I AM AWARE OF MY RIGHT TO CONSULT WITH AN ATTORNEY BEFORE SIGNING IT; AND I HAVE SIGNED IT KNOWINGLY AND VOLUNTARILY. EXCEPT FOR THE MATTERS EXPRESSLY STATED IN THIS RELEASE, THE COMPANY HAS NEITHER MADE ANY REPRESENTATION NOR OFFERED ME ANY INDUCEMENT TO SIGN THIS RELEASE.
 	 	 	 	 	 	
 	 	By:	 	 	 	
 	 	 	 	 	 	
 	 	 	 	David W. Crane	 	
 	 	 	 	 	 	
 	 	Date:	 	 	 	

Agreed to and accepted:	
 	
NRG ENERGY, INC.	
 	
By:	
 	
Name:	
 	
Title:	

 
Exhibit 10.34
NRG Energy, Inc.
Named Executive Officer 2005 AIP Payout and 2006 Base Salary Table
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	2005 Annual Incentive	 	 	
Name	 	Title	 	Plan Payout	 	2006 Base Salary	
David Crane	 	President, Chief Executive Officer and Director	 	$	1,252,435	 	 	$	1,000,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Robert C. Flexon	 	Executive Vice President and Chief Financial Officer	 	$	488,000	 	 	$	475,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Kevin T. Howell	 	Executive Vice President, Commercial Operations	 	$	250,000	 	 	$	380,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
John P. Brewster	 	Executive Vice President, International Operations and President, South Central Region	 	$	225,000	 	 	$	320,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Christine A. Jacobs	 	Vice President, Plant Operations	 	$	210,000	 	 	$	310,000	 	

 
EXHIBIT 21
Subsidiary Information for NRG Energy, Inc.
 	 	 	
Subsidiary Name	 	State of Incorporation	
Arthur Kill Power LLC	 	Delaware	
Astoria Gas Turbine Power LLC	 	Delaware	
Bayou Cove Peaking Power, LLC	 	Delaware	
Berrians I Gas Turbine Power LLC	 	Delaware	
Big Cajun I Peaking Power LLC	 	Delaware	
Big Cajun II Unit 4 LLC	 	Delaware	
Blackstone TG Feeder IV A L.P.	 	Delaware	
Blackstone TG Feeder IV L.P.	 	Delaware	
Brimsdown Power Limited	 	United Kingdom	
Cabrillo Power I LLC	 	Delaware	
Cabrillo Power II LLC	 	Delaware	
Cadillac Renewable Energy LLC	 	Delaware	
Camas Power Boiler Limited Partnership	 	Oregon	
Camas Power Boiler, Inc.	 	Oregon	
Capistrano Cogeneration Company	 	California	
Central and Eastern Europe Power Fund, Ltd.	 	Bermuda	
Chickahominy River Energy Corp.	 	Virginia	
Commonwealth Atlantic Power LLC	 	Delaware	
Conemaugh Fuels, LLC	 	Delaware	
Conemaugh Power LLC	 	Delaware	
Connecticut Jet Power LLC	 	Delaware	
Croatia Power Group	 	Cayman Islands	
Devon Power LLC	 	Delaware	
Dunkirk Power LLC	 	Delaware	
Eastern Sierra Energy Company	 	California	
El Segundo Power II LLC	 	Delaware	
El Segundo Power, LLC	 	Delaware	
Energy Investors Fund, L.P.	 	Delaware	
Energy National, Inc.	 	Utah	
Enfield Holdings B.V.	 	Netherlands	

 
EXHIBIT 21
Subsidiary Information for NRG Energy, Inc.
 	 	 	
Subsidiary Name	 	State of Incorporation	
Enfield Operations, L.L.C.	 	Delaware	
Enifund, Inc.	 	Utah	
Enigen, Inc.	 	Utah	
ESOCO Molokai, Inc.	 	Utah	
ESOCO, Inc.	 	Utah	
Fernwärme GmbH Hohenmölsen-Webau	 	Germany	
Flinders Coal Pty Ltd	 	Australia	
Flinders Labuan (No. 1) Ltd.	 	Labuan	
Flinders Labuan (No.2) Ltd.	 	Labuan	
Flinders Osborne Trading Pty Ltd	 	Australia	
Flinders Power Finance Pty Ltd	 	Australia	
Flinders Power Partnership	 	Australia	
GALA-MIBRAG-Service GmbH	 	Germany	
GCP Funding Company, LLC	 	Delaware	
Gladstone Power Station Joint Venture	 	Australia	
Granite II Holding, LLC	 	Delaware	
Granite Power Partners II, L.P.	 	Delaware	
Gröbener Logistick GmbH — Spedition, Handel und Transport	 	Germany	
Hanover Energy Company	 	California	
HFCP IV TGN Corporation	 	Delaware	
HFCP IV-A TGN Corporation	 	Delaware	
Huntley Power LLC	 	Delaware	
Indian River Operations Inc.	 	Delaware	
Indian River Power LLC	 	Delaware	
Ingenieurbüro für Grundwasser GmbH	 	Germany	
Itiquira Energetica S.A.	 	Brazil	
Jackson Valley Energy Partners, L.P.	 	California	
James River Cogeneration Company	 	North Carolina	
James River Power LLC	 	Delaware	
Kaufman Cogen LP	 	Delaware	
Keystone Fuels, LLC	 	Delaware	

 
EXHIBIT 21
Subsidiary Information for NRG Energy, Inc.
 	 	 	
Subsidiary Name	 	State of Incorporation	
Keystone Power LLC	 	Delaware	
Kladno Power (No. 1) B.V.	 	Netherlands	
Kladno Power (No. 2) B.V.	 	Netherlands	
Kraftwerk Schkopau Betriebsgesellschaft mbH	 	Germany	
Kraftwerk Schkopau GbR	 	Germany	
Lambique Beheer B.V.	 	Netherlands	
Long Beach Generation LLC	 	Delaware	
Louisiana Generating LLC	 	Delaware	
LS Power Management, LLC	 	Delaware	
LSP-Nelson Energy, LLC	 	Delaware	
LSP-Pike Energy, LLC	 	Delaware	
Meriden Gas Turbines LLC	 	Delaware	
Meridian International Investments III-C Inc.	 	Delaware	
MIBRAG B.V.	 	Netherlands	
MIBRAG Industriekraftwerke Betriebs GmbH	 	Germany	
MIBRAG Industriekraftwerke GmbH & Co. KG	 	Germany	
MIBRAG Industriekraftwerke Vermogensverwaltungs-und Beteiligungs GmbH	 	Germany	
MIBRAG Industriekraftwerke Vertriebs GmbH	 	Germany	
Middletown Power LLC	 	Delaware	
Minnesota Waste Processing Company, L.L.C.	 	Delaware	
Mitteldeutsche Braunkohlengesellschaft mbH	 	Germany	
Montan Bildungs- und Entwicklungsgesellschaft mbH	 	Germany	
Montville Power LLC	 	Delaware	
MUEG Mitteldeutsche Umwelt- und Entsorgung GmbH	 	Germany	
NEO California Power LLC	 	Delaware	
NEO Chester-Gen LLC	 	Delaware	
NEO Corporation	 	Minnesota	
NEO Freehold-Gen LLC	 	Delaware	
NEO Landfill Gas Holdings Inc.	 	Delaware	
NEO Power Services Inc.	 	Delaware	
NEO-Montauk Genco Management LLC	 	Delaware	

 
EXHIBIT 21
Subsidiary Information for NRG Energy, Inc.
 	 	 	
Subsidiary Name	 	State of Incorporation	
New Genco GP, LLC	 	Delaware	
New Genco LP, LLC	 	Delaware	
Norwalk Power LLC	 	Delaware	
NRG Affiliate Services Inc.	 	Delaware	
NRG Andean Development Ltda.	 	Bolivia	
NRG Arthur Kill Operations Inc.	 	Delaware	
NRG Asia-Pacific, Ltd.	 	Delaware	
NRG Astoria Gas Turbine Operations Inc.	 	Delaware	
NRG Audrain Generating LLC	 	Delaware	
NRG Audrain Holding LLC	 	Delaware	
NRG Bayou Cove LLC	 	Delaware	
NRG Bourbonnais Equipment LLC	 	Delaware	
NRG Bourbonnais LLC	 	Illinois	
NRG Brazos Valley GP LLC	 	Delaware	
NRG Brazos Valley LP LLC	 	Delaware	
NRG Cabrillo Power Operations Inc.	 	Delaware	
NRG Cadillac Inc.	 	Delaware	
NRG Cadillac Operations Inc.	 	Delaware	
NRG California Peaker Operations LLC	 	Delaware	
NRG Capital II LLC	 	Delaware	
NRG Caymans Company	 	Cayman Islands	
NRG Caymans-C	 	Cayman Islands	
NRG Caymans-P	 	Cayman Islands	
NRG Collinsville Operating Services Pty Ltd	 	Australia	
NRG ComLease LLC	 	Delaware	
NRG Connecticut Affiliate Services Inc.	 	Delaware	
NRG Development Company Inc.	 	Delaware	
NRG Devon Operations Inc.	 	Delaware	
NRG do Brasil Ltda.	 	Brazil	
NRG Dunkirk Operations Inc.	 	Delaware	
NRG El Segundo Operations Inc.	 	Delaware	

 
EXHIBIT 21
Subsidiary Information for NRG Energy, Inc.
 	 	 	
Subsidiary Name	 	State of Incorporation	
NRG Energy Center Dover LLC	 	Delaware	
NRG Energy Center Harrisburg LLC	 	Delaware	
NRG Energy Center Minneapolis LLC	 	Delaware	
NRG Energy Center Paxton LLC	 	Delaware	
NRG Energy Center Pittsburgh LLC	 	Delaware	
NRG Energy Center Rock Tenn LLC	 	Delaware	
NRG Energy Center San Diego LLC	 	Delaware	
NRG Energy Center San Francisco LLC	 	Delaware	
NRG Energy Center Smyrna LLC	 	Delaware	
NRG Energy Center Washco LLC	 	Delaware	
NRG Energy Development GmbH	 	Germany	
NRG Energy Insurance, Ltd.	 	Cayman Islands	
NRG Energy Jackson Valley I, Inc.	 	California	
NRG Energy Jackson Valley II, Inc.	 	California	
NRG Energy Ltd.	 	United Kingdom	
NRG Energy, Inc.	 	Delaware	
NRG Flinders Operating Services Pty Ltd	 	Australia	
NRG Gladstone Operating Services Pty Ltd	 	Australia	
NRG Gladstone Superannuation Pty Ltd	 	Australia	
NRG Granite Acquisition LLC	 	Delaware	
NRG Huntley Operations Inc.	 	Delaware	
NRG Ilion Limited Partnership	 	Delaware	
NRG Ilion LP LLC	 	Delaware	
NRG International Holdings (No. 2) GmbH	 	Switzerland	
NRG International Holdings GmbH	 	Switzerland	
NRG International II Inc.	 	Delaware	
NRG International III Inc.	 	Delaware	
NRG International LLC	 	Delaware	
NRG Kaufman LLC	 	Delaware	
NRG Latin America Inc.	 	Delaware	
NRG Marketing Services LLC	 	Delaware	

 
EXHIBIT 21
Subsidiary Information for NRG Energy, Inc.
 	 	 	
Subsidiary Name	 	State of Incorporation	
NRG McClain LLC	 	Delaware	
NRG Mesquite LLC	 	Delaware	
NRG Mextrans Inc.	 	Delaware	
NRG MidAtlantic Affiliate Services Inc.	 	Delaware	
NRG Middletown Operations Inc.	 	Delaware	
NRG Montville Operations Inc.	 	Delaware	
NRG Nelson Turbines LLC	 	Delaware	
NRG New Jersey Energy Sales LLC	 	Delaware	
NRG New Roads Holdings LLC	 	Delaware	
NRG North Central Operations Inc.	 	Delaware	
NRG Northeast Affiliate Services Inc.	 	Delaware	
NRG Norwalk Harbor Operations Inc.	 	Delaware	
NRG Operating Services, Inc.	 	Delaware	
NRG Oswego Harbor Power Operations Inc.	 	Delaware	
NRG PacGen Inc.	 	Delaware	
NRG Pacific Corporate Services Pty Ltd	 	Australia	
NRG Peaker Finance Company LLC	 	Delaware	
NRG Power Marketing Inc.	 	Delaware	
NRG Processing Solutions LLC	 	Delaware	
NRG Rockford Acquisition LLC	 	Delaware	
NRG Rockford Equipment II LLC	 	Illinois	
NRG Rockford Equipment LLC	 	Illinois	
NRG Rockford II LLC	 	Illinois	
NRG Rockford LLC	 	Illinois	
NRG Rocky Road LLC	 	Delaware	
NRG Saguaro Operations Inc.	 	Delaware	
NRG Services Corporation	 	Delaware	
NRG South Central Affiliate Services Inc.	 	Delaware	
NRG South Central Generating LLC	 	Delaware	
NRG South Central Operations Inc.	 	Delaware	
NRG Sterlington Power LLC	 	Delaware	

 
EXHIBIT 21
Subsidiary Information for NRG Energy, Inc.
 	 	 	
Subsidiary Name	 	State of Incorporation	
NRG Telogia Power LLC	 	Delaware	
NRG Thermal LLC	 	Delaware	
NRG Thermal Services LLC	 	Delaware	
NRG Victoria I Pty Ltd	 	Australia	
NRG Victoria II Pty Ltd	 	Australia	
NRG Victoria III Pty Ltd	 	Australia	
NRG West Coast LLC	 	Delaware	
NRG Western Affiliate Services Inc.	 	Delaware	
NRGenerating (Gibraltar)	 	Gibraltar	
NRGenerating Energy Trading Ltd.	 	United Kingdom	
NRGenerating German Holdings GmbH	 	Switzerland	
NRGenerating Holdings (No. 2) GmbH	 	Switzerland	
NRGenerating Holdings (No. 21) B.V.	 	Netherlands	
NRGenerating Holdings (No. 24) B.V.	 	Netherlands	
NRGenerating Holdings (No. 5) B.V.	 	Netherlands	
NRGenerating Holdings GmbH	 	Switzerland	
NRGenerating II (Gibraltar)	 	Gibraltar	
NRGenerating III (Gibraltar)	 	Gibraltar	
NRGenerating International B.V.	 	Netherlands	
NRGenerating IV (Gibraltar)	 	Gibraltar	
NRGenerating Luxembourg (No. 1) S.a.r.l.	 	Luxembourg	
NRGenerating Luxembourg (No. 2) S.a.r.l.	 	Luxembourg	
NRGenerating Luxembourg (No. 6) S.a.r.l.	 	Luxembourg	
NRGenerating, Ltd.	 	United Kingdom	
O Brien Cogeneration, Inc. II	 	Delaware	
ONSITE Energy, Inc.	 	Oregon	
Oswego Harbor Power LLC	 	Delaware	
P.T. Dayalistrik Pratama	 	Indonesia	
Pacific Crockett Holdings, Inc.	 	Oregon	
Pacific Generation Company	 	Oregon	
Pacific Generation Holdings Company	 	Oregon	

 
EXHIBIT 21
Subsidiary Information for NRG Energy, Inc.
 	 	 	
Subsidiary Name	 	State of Incorporation	
Pacific-Mt. Poso Corporation	 	Oregon	
Project Finance Fund III, L.P.	 	Delaware	
Rocky Road Power, LLC	 	Delaware	
RWE Umwelt Westsachsen GmbH	 	Germany	
Saale Energie GmbH	 	Germany	
Saale Energie Services GmbH	 	Germany	
Sachsen Holding B.V.	 	Netherlands	
Saguaro Power Company, a Limited Partnership	 	California	
Saguaro Power LLC	 	Delaware	
San Joaquin Valley Energy I, Inc.	 	California	
San Joaquin Valley Energy IV, Inc.	 	California	
San Joaquin Valley Energy Partners I, L.P	 	California	
Somerset Operations Inc.	 	Delaware	
Somerset Power LLC	 	Delaware	
Statoil Energy Power/Pennsylvania, Inc.	 	Pennsylvania	
Sterling (Gibraltar)	 	Gibraltar	
Sterling Luxembourg (No. 4) s.a.r.l.	 	Luxembourg	
Sunshine State Power (No. 2) B.V.	 	Netherlands	
Sunshine State Power B.V.	 	Netherlands	
Tacoma Energy Recovery Company	 	Delaware	
Telogia Power Inc.	 	Delaware	
Termo Santander Holding (Alpha), L.L.C.	 	Delaware	
TermoRio S.A.	 	Brazil	
Texas Genco Financing Corp.	 	Delaware	
Texas Genco GP, LLC	 	Texas	
Texas Genco Holdings, Inc.	 	Texas	
Texas Genco II, LP	 	Texas	
Texas Genco LLC	 	Delaware	
Texas Genco LP	 	Texas	
Texas Genco LP, LLC	 	Delaware	
Texas Genco Operating Services, LLC	 	Delaware	

 
EXHIBIT 21
Subsidiary Information for NRG Energy, Inc.
 	 	 	
Subsidiary Name	 	State of Incorporation	
Texas Genco Services LP	 	Texas	
The PowerSmith Cogeneration Project, Limited Partnership	 	Delaware	
Tosli Acquisition B.V.	 	Netherlands	
TPG Genco III, Inc.	 	Delaware	
TPG Genco IV, Inc.	 	Delaware	
Turners Falls Limited Partnership	 	Delaware	
Vienna Operations Inc.	 	Delaware	
Vienna Power LLC	 	Delaware	
WCP (Generation) Holdings LLC	 	Delaware	
West Coast Power LLC	 	Delaware	

 
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
The Board of Directors
NRG Energy, Inc.:
We consent to the incorporation by reference in the registration statements on Form S-8 (No. 333-114007) and Form S-3 (No. 333-130549) and Form S-3 (No. 333-123677) of NRG Energy, Inc. of our reports dated March 7, 2006, with respect to the consolidated balance sheets of NRG Energy, Inc. as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity/(deficit) and comprehensive income/(loss) and cash flows for each of the years in the two year period ended December 31, 2005, and the related financial statement schedule, management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005 and the effectiveness of internal control over financial reporting as of December 31, 2005, which reports appear in the December 31, 2005, annual report on Form 10-K of NRG Energy, Inc.
 	 	
 	/s/ KPMG LLP	
 	KPMG LLP	

Philadelphia, Pennsylvania
March 7, 2006

 
Exhibit 23.2
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-114007) and Forms S-3 (No. 333-130549 and No. 333-123677) of NRG Energy, Inc. of our reports dated March 10, 2004, except as to Notes 6, 21 and 33 which are as of December 6, 2004, relating to the NRG Energy, Inc. consolidated financial statements and financial statement schedule, which appear in this Form 10-K.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Minneapolis, Minnesota
March 7, 2006

 
EXHIBIT 31.1
CERTIFICATION
I, David W. Crane, certify that:
      1. I have reviewed this annual report on Form 10-K of NRG Energy, Inc.;
      2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
      3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
 	 	
 	      (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	
 	      (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	
 	      (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	
 	      (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	
      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
 	 	
 	      (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 	 	
 	      (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

 	/s/ DAVID W. CRANE	
 	 	
 	David W. Crane	
 	Chief Executive Officer	
 	(Principal Executive Officer)	
Date: March 7, 2006

EXHIBIT 31.2
CERTIFICATION
I, Robert C. Flexon, certify that:
      1. I have reviewed this annual report on Form 10-K of NRG Energy, Inc.;
      2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
      3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
 	 	
 	      (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	
 	      (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	
 	      (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	
 	      (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	
      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
 	 	
 	      (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 	 	
 	      (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

 	/s/ ROBERT C. FLEXON	
 	 	
 	Robert C. Flexon	
 	Chief Financial Officer	
 	(Principal Financial Officer)	
Date: March 7, 2006

EXHIBIT 31.3
CERTIFICATION
I, James J. Ingoldsby, certify that:
      1. I have reviewed this annual report on Form 10-K of NRG Energy, Inc.;
      2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
      3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
 	 	
 	      (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	
 	      (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	
 	      (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	
 	      (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	
      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
 	 	
 	      (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 	 	
 	      (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

 	/s/ JAMES J. INGOLDSBY	
 	 	
 	James J. Ingoldsby	
 	Controller	
 	(Principal Accounting Officer)	
Date: March 7, 2006

EXHIBIT 32
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
      In connection with the Annual Report of NRG Energy, Inc. (the Company) on Form 10-K for the year ended December 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:
 	 	
 	      (1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 	 	
 	      (2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Form 10-K.	
Date: March 7, 2006
 	 	
 	/s/ DAVID W. CRANE	
 	 	
 	David W. Crane,	
 	Chief Executive Officer	
 	(Principal Executive Officer)	
 	 	
 	/s/ ROBERT C. FLEXON	
 	 	
 	Robert C. Flexon	
 	Chief Financial Officer	
 	(Principal Financial Officer)	
 	 	
 	/s/ JAMES J. INGOLDSBY	
 	 	
 	James J. Ingoldsby	
 	Controller	
 	(Principal Accounting Officer)	
      The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.
      A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NRG Energy, Inc. and will be retained by NRG Energy, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.