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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           .

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)

Title of Each Class		Name of Exchange on Which Registered
5.75% Mandatorily Convertible Preferred Stock		New York Stock Exchange

Class		Outstanding at March 3, 2006
Common Stock, par value $0.01 per share		136,975,275

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									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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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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(1)	Reflects only domestic generation capacity; 19 MW of wood-fired generation capacity not shown.

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										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.

		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.

		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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																						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

																						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

																						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

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	Australia

	Other

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			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.

		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.

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		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.

											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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	Reorganized NRG (excluding Texas Genco)

	Predecessor Company

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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

	TEXAS (ERCOT)

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			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

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										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.

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	NORTHEAST REGION

			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

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										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.

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	SOUTH CENTRAL REGION

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			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

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

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						Estimated
		Expiration				Contract Load				Customers
Form A			March 2025				42	%			6
Form B			March 2025				3	%			1
Form C			March 2009-2014				42	%			4

	WESTERN REGION

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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.

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	OTHER

	Other North American Assets

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.

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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

	Germany

	Asset Management Strategy

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	Thermal and Chilled Water Businesses

	Resource Recovery Facilities

	Federal Energy Regulatory Commission

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	Nuclear Regulatory Commission

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	Public Utility Commission of Texas

	Regional Businesses — Market Developments

	Texas (ERCOT) Region

	Texas Nodal Protocols

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	U.S. Federal Environmental Initiatives

	Air

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	Water

	Nuclear Waste

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	Regional U.S. Environmental Regulatory Initiatives

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	Domestic Site Remediation Matters

	International Environmental Matters

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	General

	Nuclear

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	Many of our power generation facilities operate, wholly or partially, without long-term power sale agreements.

	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.

	•	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.

	Our costs, results of operations, financial condition and cash flows could be adversely impacted by disruption of our fuel supplies.

	•	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.

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	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.

	Our trading operations and the use of hedging agreements could result in financial losses that negatively impact our results of operations.

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

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

	•	electricity sales from our generation assets;
	•	fuel utilized by those assets; and
	•	emission allowances.

	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.

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	Operation of power generation facilities involves significant risks that could have a material adverse effect on our revenues and results of operations.

	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.

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	•	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.

	Supplier and/or customer concentration at certain of our facilities may expose us to significant financial credit or performance risks.

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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.

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

	Future acquisition activities may have adverse effects.

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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.

	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.

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	Our ownership interest in a nuclear power facility subjects us to regulations, costs and liabilities uniquely associated with these types of facilities.

	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.

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

	Our business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by our unionized employees.

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	Changes in technology may impair the value of our power plants.

	Acts of terrorism 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.

	•	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.

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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.

	•	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.

	•	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 able to realize the anticipated benefits from the Texas Genco Acquisition.

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	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.

	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.

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	•	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.

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								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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%

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.

%

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.

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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).

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	California Electricity and Related Litigation Indemnification

	NRG Bankruptcy Cap on California Claims

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	FERC Proceedings

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	Additional Litigation

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

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

		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

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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.

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

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(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

		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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		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

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

	•	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.

	•	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.

	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 “FORNRG,” 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.

	•	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.

	•	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

	•	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.

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			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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			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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			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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			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

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							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

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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	)

	Cost of Majority-Owned Operations

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	Depreciation and Amortization

	General, Administrative and Development

	Corporate Relocation Charges

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	Equity in Earnings of Unconsolidated Affiliates

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

	Other Income, net

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	Refinancing expense

	Interest expense

	Income Tax Expense

	Income from Discontinued Operations, net of Income Taxes

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	Regional Discussion

	Northeast Region Results

	Operating Income

	Revenues

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	Cost of energy

	Other Operating Expenses

91

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Table of Contents

	South Central Region Results

	Operating Income

	Revenues

	Cost of Energy

	Other Operating Expenses

	Western Region Results

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	Other North America Region Results

	Australia Region Results

	Operating Income

	Revenues

	Cost of Energy

	Other Operating Expenses

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

	Net Income

	Reorganized NRG

	Predecessor Company

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	Revenues from Majority-Owned Operations

	Reorganized NRG

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	Predecessor Company

	Cost of Majority-Owned Operations

	Cost of Energy

	Operating Expenses

	Reorganized NRG

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	Predecessor Company

	Depreciation and Amortization

	Reorganized NRG

	Predecessor Company

	General, Administrative and Development

	Reorganized NRG

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	Predecessor Company

	Other Charges (Credits)

	Reorganized NRG

	Predecessor Company

			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

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	Reorganization Items

	Impairment Charges

	Restructuring Charges

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	Fresh Start Adjustments

			(In millions)
Discharge of corporate level debt			$	5,162
Discharge of other liabilities				811
Establishment of creditor pool				(1,040	)
Receivable from Xcel				640
Revaluation of fixed assets				(1,392	)
Revaluation of equity investments				(207	)
Valuation of SO 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

	Other Income (Expense)

	Reorganized NRG

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	Predecessor Company

	Equity in Earnings of Unconsolidated Affiliates

	Reorganized NRG

	Predecessor Company

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												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

	Other Income, net

	Reorganized NRG

	Predecessor Company

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	Interest Expense

	Reorganized NRG

	Predecessor Company

	Refinancing Expense

	Income Tax Expense

	Reorganized NRG

103

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	Predecessor Company

	Income From Discontinued Operations, net of Income Taxes

	Reorganized NRG

	Predecessor Company

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	Reorganization and Emergence from Bankruptcy

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

“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

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		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

	Known trends that will affect our results in the future:

	Acquisition of Texas Genco and Financing Transactions

	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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	Acquisition of Remaining 50% Equity Interest in WCP

	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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											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

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	Uses of Funds

	(i) Commercial Operations

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	(ii) Capital Expenditures

	(iii) Corporate Financial Restructuring

	(iv) Project Finance Requirements

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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

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

														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

	•	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

	•	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

	•	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.

	Other Liquidity Matters — NOLs and Deferred Tax Assets

	Conclusion on Future Liquidity

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	Known Trends and Other Factors Affecting our Liquidity

	New Senior Credit Facility

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	•	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

	•	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.

	Second Lien Structure

	Mandatory Convertible Preferred Stock

	Common Stock

	Sale of Audrain

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	Brownfield Developments

	Obligations Under Certain Guarantee Contracts

	Retained or Contingent Interests

	Derivative Instrument obligations

	Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

	Variable interest in Equity investments

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	New Synthetic Letter of Credit Facility and Revolver Facility

	Contractual Obligations and Commercial Commitments

			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

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	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	)

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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

	Income Taxes and Valuation Allowance for Deferred Tax Assets

	Evaluation of Assets for Impairment and Other Than Temporary Decline in Value

	•	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.

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	Goodwill and Other Intangible Assets

	Contingencies

	Recent Accounting Developments

	•	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.

	•	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

			(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

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	Interest Rate Risk

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

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	Liquidity Risk

	Credit Risk

			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	%

	Currency Exchange Risk

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

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	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

	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

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	/s/ KPMG LLP
	KPMG LLP

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	/s/ KPMG LLP
	KPMG LLP

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	/s/ PricewaterhouseCoopers LLP
	PricewaterhouseCoopers LLP

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	/s/ PricewaterhouseCoopers LLP
	PricewaterhouseCoopers LLP

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																		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					—

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					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

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					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

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																															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

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				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

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Note 1 —	Organization

	General

Note 2 —	Summary of Significant Accounting Policies

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	Principles of Consolidation and Basis of Presentation

“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

	Fresh Start Reporting

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	Cash and Cash Equivalents

	Restricted Cash

143

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	Inventory

	Property, Plant and Equipment

Facilities and equipment		1-42 years
Office furnishings and equipment		2-10 years

	Asset Impairments

	Discontinued Operations

	Capitalized Interest

144

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	Capitalized Project Costs

	Debt Issuance Costs

	Intangible Assets

	Income Taxes

	Revenue Recognition

145

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	Derivative Financial Instruments

146

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	Foreign Currency Translation and Transaction Gains and Losses

	Concentrations of Credit Risk

	Fair Value of Financial Instruments

	Pensions

147

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	Stock Based Compensation

	Use of Estimates

	Reclassifications

	Recent Accounting Developments

148

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149

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150

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Note 3 —	Emergence from Bankruptcy and Fresh Start Reporting

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		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

Note 4 —	Debtors’ Statements

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			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	)

		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

		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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Note 6 —	Discontinued Operations

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		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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				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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															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	)

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																	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

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

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																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

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			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

			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

	Reorganization Items

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																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

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														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

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	Restructuring Charges

	Fresh Start Adjustments

			(In millions)
Discharge of corporate level debt			$	5,162
Discharge of other liabilities				811
Establishment of creditor pool				(1,040	)
Receivable from Xcel				640
Revaluation of fixed assets				(1,392	)
Revaluation of equity investments				(207	)
Valuation of SO(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

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Note 9 —	Asset Retirement Obligation

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		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

Note 10 —	Inventory

			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

				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

					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

				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%

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																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

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	MIBRAG Summarized Financial Information

		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

			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

	West Coast Power LLC Summarized Financial Information

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										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

			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

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	Acquisition of Remaining 50% in WCP from Dynegy, Inc. and sale of our 50% investment in Rocky Road Power LLC

	Saguaro Power Company

	Gladstone

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	Enfield Energy Centre Limited

	Reorganized NRG

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		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

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	Derivative Financial Instruments

	Energy Related Commodities

	•	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.

	•	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.

	•	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.

	•	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).

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	Interest Rates

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	Foreign Currency Exchange Rates

	Accumulated Other Comprehensive Income

				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	)

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				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

				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	)

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				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				$	—			$	—			$	—			$	—

	Statement of Operations

		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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		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

			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

			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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											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.

	Senior Securities

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	Peakers

187

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	Flinders

	NRG Thermal

	Camas

188

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	Itiquira Energetica S.A.

	Capital Leases

	Saale Energie GmbH

			Total
			(In millions)
2006			$	108
2007				82
2008				66
2009				65
2010				71
Thereafter				2,348
	Total		$	2,740

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			(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

	Common Stock

	Treasury Stock

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	Preferred Stock

	4% Preferred Stock

191

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	Redeemable Preferred Stock

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	Incentive Compensation Plans

			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			$	—

	Long-Term Incentive Plan

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	•	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.

	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.

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	The following types of Awards are issued and outstanding as of December 31, 2005:

	Stock Options

										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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						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				—				—

		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

	Deferred Stock Units

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	Performance Units

		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

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		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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	Anti-dilutive effect of certain equity instruments

199

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200

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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

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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		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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		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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		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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																	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	%

														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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															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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				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

		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

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	Taxes payable

	Deferred tax assets and valuation allowance

	Repatriation of foreign funds pursuant to the American Jobs Creation Act of 2004

208

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	Tax Holidays

	Stock Purchase Agreement

	Operating Agreements

209

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															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

	Operating Agreements

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	Administrative Services and Other Costs

	Natural Gas Marketing and Trading Agreement

	Reorganized NRG

	NRG Flinders Retirement Plan

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	NRG Pension and Postretirement Medical Plans

	Components of Net Periodic Benefit Cost

			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

			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	)

		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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		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

		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

		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

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		December 31
		2005				2004
US Equity			56	%			N/A
International Equity			15	%			N/A
US Fixed Income			29	%			N/A
Cash			—				N/A

						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

		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

	Predecessor Company

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	Participation in Xcel Energy, Inc. Pension Plan and Postretirement Medical Plan

	2003 Medicare Legislation

Note 25 —	Commitments and Contingencies

	Operating Lease Commitments

			Total
			(In millions)
2006			$	25
2007				21
2008				16
2009				14
2010				13
Thereafter				61
	Total		$	150

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	Coal Purchase and Transportation Commitments

			Total
			(In millions)
2006			$	192
2007				106
2008				48
2009				49
2010				3
Thereafter				18
	Total		$	416

	International

	NRG FinCo Settlement

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	NYISO Claims

	Legal Issues

218

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	California Electricity and Related Litigation

	FERC Proceedings

	New York Operating Reserve Markets

219

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	Connecticut Congestion Charges

	New York Public Interest Research Group

	Station Service Disputes

220

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	Itiquira Energetica, S.A.

	CFTC Trading Litigation

	Disputed Claims Reserve

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Note 26 —	Regulatory Matters

	Northeast Region

	RMR Agreements

	LICAP Market Developments

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	Connecticut

	New York

223

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	Mid Atlantic

224

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	South Central Region

	Western Region

Note 27 —	Environmental Matters

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	South Central Region

	Western Region

	Other North America

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Note 28 —	Cash Flow Information

																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

	•	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.

		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

	•	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.

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Note 30 —	Sales to Significant Customers

	Reorganized NRG

	Predecessor Company

	Big Cajun II Unit 3

	Reorganized NRG

	Keystone and Conemaugh

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	Reorganized NRG

		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

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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

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				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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			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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								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

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				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

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			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

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				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

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				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

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				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

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				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

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				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.

245

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	Texas Genco Acquisition

246

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			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

	Cash Tender Offer and Consent Solicitation

	New Financings

	New Senior Credit Facility

247

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	•	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.

248

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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

	•	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.

249

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	5.75% Preferred Stock

	Common Stock

	Second Lien Structure

	Bourbonnais Settlement

250

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	/s/ PricewaterhouseCoopers LLP
	PricewaterhouseCoopers LLP

251

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	/s/ PricewaterhouseCoopers LLP
	PricewaterhouseCoopers LLP

252

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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

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	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)

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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

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	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)

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	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)

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	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.

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(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.

 

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	(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

	(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)

 

	(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

	(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)

 

	(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

	(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)

 

	(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
	(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Form 10-K.

	/s/ David 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)